10-K

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, 2011

or

¨ 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 of 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

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  ¨

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  ¨    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  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  þ    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer þ             Accelerated filer ¨            Non-accelerated filer ¨             Smaller reporting company ¨

                            (Do not check if a smaller reporting company)

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

The aggregate market value of the voting common stock held by non-affiliates of the registrant as of June 30, 2011, was approximately $32.7 billion, based upon the closing price of $78.81 per share as reported by the New York Stock Exchange on such date. On February 9, 2012, 404.1 million shares of common stock were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Proxy statement for the 2012 annual meeting of stockholders — Part III

DEVON ENERGY CORPORATION

FORM 10-K

TABLE OF CONTENTS

PART I
Items 1 and 2. Business and Properties		3
Item 1A.	Risk Factors	15
Item 1B.	Unresolved Staff Comments	19
Item 3.	Legal Proceedings	19
Item 4.	Mine Safety Disclosures	19
PART II
Item 5.	Market for Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	20
Item 6.	Selected Financial Data	23
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	45
Item 8.	Financial Statements and Supplementary Data	47
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	101
Item 9A.	Controls and Procedures	101
Item 9B.	Other Information	101
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	102
Item 11.	Executive Compensation	102
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	102
Item 13.	Certain Relationships and Related Transactions, and Director Independence	102
Item 14.	Principal Accountant Fees and Services	102
PART IV
Item 15.	Exhibits and Financial Statement Schedules	103
SIGNATURES		109

INFORMATION REGARDING FORWARD-LOOKING STATEMENTS

This report includes forward-looking statements regarding our expectations and plans, as well as future events or conditions. Such forward-looking statements are based on our examination of historical operating trends, the information used to prepare our December 31, 2011 reserve reports and other data in our possession or available from third parties. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond our control. Consequently, actual future results could differ materially from our expectations due to a number of factors, such as changes in the supply of and demand for oil, natural gas and NGLs and related products and services; exploration or drilling programs; political or regulatory events; general economic and financial market conditions; and other factors discussed 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 above. We assume no duty to update or revise our forward-looking statements based on new information, future events or otherwise.

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PART I

Item 1 and 2. Business and Properties

General

Devon Energy Corporation (“Devon”) is a leading independent energy company engaged primarily in the exploration, development and production of oil, natural gas and NGLs. Our operations are concentrated in various North American onshore areas in the U.S. and Canada. We also own natural gas pipelines, plants and treatment facilities in many of our producing areas, making us one of North America’s larger processors of natural gas.

Devon pioneered the commercial development of natural gas from shale and coalbed formations, and we are a proven leader in using steam to produce oil from the Canadian oil sands. A Delaware corporation formed in 1971, we have been publicly held since 1988, and our common stock is listed on 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). As of December 31, 2011, we had approximately 5,200 employees.

Devon files or furnishes annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K as well as any amendments to these reports with the U.S. Securities and Exchange Commission (“SEC”). Through our website, http://www.devonenergy.com, we make available electronic copies of the documents we file or furnish to the SEC, the charters of the committees of our Board of Directors and other documents related to our corporate governance (including our Code of Ethics for the Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer). Access to these electronic filings is available free of charge as soon as reasonably practicable after filing or furnishing them to the SEC. Printed copies of our committee charters or other governance documents and filings can be requested by writing to our corporate secretary at the address on the cover of this report.

In addition, the public may read and copy any materials Devon files with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington D.C. 20549. The public may also obtain information about the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Reports filed with the SEC are also made available on its website at www.sec.gov.

Strategy

We aspire to be the premier independent oil and natural gas company in North America and to provide our shareholders with top-quartile returns over the long-term. To achieve this, we strive to optimize our capital investments to maximize growth in cash flows, earnings, production and reserves, all on a per debt-adjusted share basis. We do this by:

• exercising capital discipline,

• maintaining superior financial strength,

• investing in oil and gas properties with strong full-cycle margins, and

• balancing our production and resource mix between natural gas and liquids.

Growth in cash flow per debt-adjusted share has the greatest long-term correlation to share price appreciation. As a result, we focus on capital investments that sustain and accelerate growth per debt-adjusted share. In an environment that involves challenged natural gas prices and more robust liquids prices, our capital allocation is focused on liquids-based resource capture and development. Our portfolio strikes a good balance between oil, NGLs and natural gas with a cost structure that generates highly competitive full-cycle returns. Within our portfolio, we have a deep inventory of repeatable opportunities diversified across several key resource plays. We also have significant exposure to several emerging plays and new venture opportunities. Finally, the recent divestiture of our offshore operations generated about $8 billion in after-tax proceeds. We used a portion of these proceeds to repurchase $3.5 billion of our common stock and repay debt, giving us one of the strongest balance sheets in our peer group.

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Oil and Gas Properties

Property Profiles

The locations of our key properties are presented on the following map. These properties include those that currently have significant proved reserves and production, as well as properties that do not currently have significant levels of proved reserves or production but are expected to be the source of significant future growth in proved reserves and production.

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The following table outlines a summary of key data in each of our operating areas for 2011. Notes 21 and 22 to the financial statements included in “Item 8. Financial Statements and Supplementary Data” of this report contain additional information on our segments and geographical areas.

	Proved Reserves December 31, 2011								Production Year Ended  December 31, 2011								Total		Gross		Average
	MMBoe(1)		% of Total			% Liquids			MMBoe(1)		% of Total			% Liquids			Net Acres		Wells Drilled		Working Interest
																	(in thousands)
U.S.
Barnett		1,151		38.3	%		22.1	%		78		32.4	%		21.3	%		625		309		89.0	%
Cana-Woodford		327		10.9	%		36.4	%		12		5.1	%		26.0	%		244		207		51.4	%
Permian		189		6.3	%		77.8	%		18		7.5	%		74.5	%		1,070		284		80.0	%
Carthage		172		5.7	%		29.7	%		15		6.2	%		26.0	%		309		31		88.1	%
Washakie		98		3.3	%		35.9	%		8		3.5	%		37.5	%		157		57		76.0	%
Granite Wash		46		1.5	%		35.7	%		6		2.5	%		43.2	%		63		59		48.7	%
Arkoma-Woodford		37		1.2	%		20.0	%		5		1.9	%		21.6	%		42		29		31.3	%
New Ventures		—		—	%		—	%		—		—	%		—	%		1,370		—		N/M
Other		258		8.6	%		24.4	%		31		13.0	%		19.5	%		2,664		113		N/M
Total U.S.		2,278		75.8	%		30.4	%		173		72.1	%		28.8	%		6,544		1,089		N/M
Canada
Jackfish		457		15.2	%		100.0	%		13		5.3	%		100.0	%		34		21		100.0	%
Northwest		95		3.2	%		41.0	%		15		6.2	%		24.5	%		1,829		42		74.0	%
Deep Basin		65		2.2	%		14.6	%		15		6.1	%		10.5	%		727		29		45.0	%
Lloydminster		54		1.8	%		78.6	%		14		6.0	%		81.6	%		2,677		197		87.0	%
Pike		—		—	%		—	%		—		—	%		—	%		59		—		50.0	%
Other		56		1.8	%		29.3	%		10		4.3	%		19.1	%		1,501		27		N/M
Total Canada		727		24.2	%		77.6	%		67		27.9	%		47.1	%		6,827		316		N/M
Devon		3,005		100.0	%		41.9	%		240		100.0	%		33.9	%		13,371		1,405		N/M

(1) Gas proved reserves and production are converted to Boe at the rate of six Mcf of gas per Bbl of oil, based upon the approximate relative energy content of gas and oil. NGL reserves and production are converted to Boe on a one-to-one basis with oil.

N/M Not meaningful.

U.S.

Barnett Shale — This is our largest property both in terms of production and proved reserves. Our leases are located primarily in Denton, Johnson, Parker, Tarrant and Wise counties in north Texas. The Barnett Shale is a non-conventional reservoir, producing natural gas and NGLs.

We are the largest producer in the Barnett Shale. Since acquiring a substantial position in this field in 2002, we continue to introduce technology and new innovations to enhance production and have transformed this into one of the top producing gas fields in North America. We have drilled nearly 5,000 wells in the Barnett Shale since 2002, yet we still have several thousand remaining drilling locations. In 2012, we plan to drill approximately 300 wells.

In addition, we have a significant processing plant and gathering system in North Texas to service these properties. Currently, these midstream assets include over 3,000 miles of pipeline, two natural gas processing plants with 750 MMcf per day of total capacity and a 15 MBbls per day NGL fractionator. To meet increasing demand from our liquids-rich development drilling, we intend to increase the size of our inlet processing capacity to 890 MMcf per day by early 2013.

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Cana-Woodford Shale — Our acreage is located primarily in Oklahoma’s Canadian, Blaine, Caddo, and Dewey counties. The Cana-Woodford Shale is a non-conventional reservoir and produces natural gas, NGLs and condensate.

The Cana-Woodford is a leading growth area for Devon and has rapidly emerged as one of the most economic shale plays in North America. We are the largest leaseholder and the largest producer in the Cana-Woodford. During 2011, we increased our production by 85%. We have several thousand remaining drilling locations. In 2012, we plan to drill approximately 200 wells.

In addition, we have constructed a gas processing plant with 200 MMcf per day of total capacity. To meet increasing demand from our development drilling, we intend to increase the size of our plant to 350 MMcf per day by mid-2013.

Permian Basin — These properties have been a legacy asset for us and continue to offer both exploration and low-risk development opportunities. Our acreage is located in various counties in west Texas and southeast New Mexico. Our current drilling activity is targeting conventional and non-conventional liquids-rich targets within the Conventional Delaware, Bone Spring, Wolfcamp, Wolfberry and Avalon Shale plays. In 2012, we plan to drill more than 300 wells.

Carthage — Our acreage is located primarily in Harrison, Marion, Panola and Shelby counties in east Texas. These wells produce natural gas and NGLs from conventional reservoirs. In 2012, we plan to drill approximately 35 wells.

Washakie — These leases are concentrated in Wyoming’s Carbon and Sweetwater counties. The Washakie wells produce natural gas and NGLs from conventional reservoirs. Targeting the Almond and Lewis formations, we have been among the most active drillers in the Washakie basin for many years.

Granite Wash — Our acreage is concentrated in the Texas Panhandle and western Oklahoma. These properties produce liquids and natural gas from conventional reservoirs. Our legacy land position in the Granite Wash is held by production and provides some of the best economics in our portfolio. High initial production rates and strong liquids yields contribute to the superior full-cycle rates of return. In 2012, we plan to drill approximately 65 wells.

Arkoma-Woodford Shale — Our acreage is located primarily in Coal and Hughes counties in southeastern Oklahoma. These properties produce natural gas and NGLs from a non-conventional reservoir. Our acreage in this play is held by production. In 2012, we do not plan to drill additional wells.

New Ventures — During 2010 and 2011, we made significant acreage acquisitions targeting liquids rich production, including the following five exploration opportunities that we have publicly disclosed.

• Michigan Basin — Our 340,000 acres are located in central Michigan and target oil and gas in the A1 Carbonate and Utica shale.

• Mississippian — Our 230,000 acres are located in northern Oklahoma and target oil in the Mississippian Lime and Woodford shale.

• Niobrara — Our 300,000 acres are located primarily in eastern Wyoming and target oil in the Niobrara, Turner, Cordell, Mowry, Frontier and Parkman plays. Currently, we are using 3D seismic to identify appropriate drilling zones.

• Ohio Utica — Our 235,000 acres are located in Ohio and targets oil in the Utica shale.

• Tuscaloosa — Our 265,000 acres are located in Louisiana and Mississippi and target oil and gas in the silica rich shale zone.

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Additionally, in the first quarter of 2012, we expect to close our recently announced transaction in which our new partner will obtain a 33.3% interest in these new ventures properties for approximately $2.5 billion, including a $900 million payment at closing and $1.6 billion toward our share of future drilling costs. We will continue to de-risk the development of these properties with our partner by drilling approximately 125 wells in 2012.

Canada

Jackfish — Jackfish is our thermal heavy oil project in the non-conventional oil sands of east central Alberta. We are the first and only U.S.-based independent energy company to develop and operate an oil sands project in Canada. We are employing steam-assisted gravity drainage at Jackfish. The first phase of Jackfish is fully operational with a gross facility capacity of 35 MBbls per day. The second phase of Jackfish began production in the second quarter of 2011 and will continue to increase production throughout 2012. Also, in 2011 we received regulatory approval for the construction of a third phase and will begin construction in 2012. We expect each phase to maintain a flat production profile for greater than 20 years at an average net production rate of approximately 25-30 MBbls per day.

To facilitate the delivery of our heavy oil production, we have a 50% interest in the Access Pipeline transportation system in Canada. This pipeline system allows us to blend our Jackfish heavy oil production with condensate or other blend-stock and transport the combined product to the Edmonton area for sale.

Northwest — This region includes acreage in west central Alberta and northeast British Columbia. These properties produce liquids-rich natural gas and light gravity oil from conventional reservoirs. In 2012, we plan to drill approximately 25 wells.

The region includes both winter-only and all season access areas. Multi-zone drilling opportunities are common. Since initial exploration in the 1970s, the region has seen significant infrastructure expansion. We own and operate gas gathering and processing facilities in the area, enabling projects to be brought on-stream quickly.

Deep Basin — Our properties in Canada’s Deep Basin include portions of west central Alberta and east central British Columbia. The area produces natural gas and liquids from conventional reservoirs. In 2012, we plan to drill approximately 15 wells.

We are one of the major producers in the Deep Basin. We have used our large proprietary two-dimensional and three-dimensional seismic databases to build an extensive inventory of deep to mid-range drilling targets in this area. Most recently, we have been testing light oil targets in the Cardium formation and liquids-rich opportunities in the lower Cretaceous zones, including the Cadomin. The region has winter-only access restrictions in many areas, but offers year-round access in others. We control significant gas processing and transportation infrastructure throughout the region and hold interests in the only major gas facilities in the Wapiti area.

Lloydminster — Our Lloydminster properties are located to the south and east of Jackfish in eastern Alberta and western Saskatchewan. Lloydminster produces heavy oil by conventional means, without the need for steam injection. In 2012, we plan to drill approximately 150 wells.

The region is well-developed with significant infrastructure and is primarily accessible year-round for drilling. Lloydminster is a low-risk, high margin oil development play. We have drilled over 2,300 wells in the area since 2003.

Pike — Our Pike oil sands acreage is situated directly to the south of our Jackfish acreage in east central Alberta and has similar reservoir characteristics to Jackfish. The Pike leasehold is currently undeveloped and has no proved reserves or production as of December 31, 2011. We continued appraisal drilling in 2011 and will carry forward these activities into 2012. The results will help us determine the optimal configuration for the initial phase of development.

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Proved Reserves

For estimates of our proved, proved developed and proved undeveloped reserves and the discussion of the contribution by each key property, see Note 22 to the financial statements included in “Item 8. Financial Statements and Supplementary Data” of this report.

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 2011 except in filings with the SEC and 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.

Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from known reservoirs under existing economic conditions, operating methods and government regulations. To be considered proved, oil and gas reserves must be economically producible before contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Also, the project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

The process of estimating oil, gas and NGL reserves is complex and requires significant judgment as discussed in “Item 1A. Risk Factors” of this report. As a result, we have developed internal policies for estimating and recording reserves. Such policies require proved reserves to be in compliance with the SEC definitions and guidance. Our policies assign responsibilities for compliance in reserves bookings to our Reserve Evaluation Group (the “Group”). These same policies also require that reserve estimates be made by professionally qualified reserves estimators (“Qualified Estimators”), as defined by the Society of Petroleum Engineers’ standards.

The Group, which is led by Devon’s Director of Reserves and Economics, is responsible for the internal review and certification of reserves estimates. We ensure the Group’s Director and key members of the Group have appropriate technical qualifications to oversee the preparation of reserves estimates, including any or all of the following:

• an undergraduate degree in petroleum engineering from an accredited university, or equivalent;

• a petroleum engineering license, or similar certification;

• memberships in oil and gas industry or trade groups; and

• relevant experience estimating reserves.

The current Director of the Group has all of the qualifications listed above. The current Director has been involved with reserves estimation in accordance with SEC definitions and guidance since 1987. He has experience in reserves estimation for projects in the U.S. (both onshore and offshore), as well as in Canada, Asia, the Middle East and South America. He has been employed by Devon for the past eleven years, including the past four in his current position. During his career with Devon and others, he was responsible for reserves estimation as the primary reservoir engineer for projects including, but not limited to:

• Hugoton Gas Field (Kansas),

• Sho-Vel-Tum CO₂ Flood (Oklahoma),

• West Loco Hills Unit Waterflood and CO₂ Flood (New Mexico),

• Dagger Draw Oil Field (New Mexico),

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• Clarke Lake Gas Field (Alberta, Canada),

• Panyu 4-2 and 5-1 Joint Development (Offshore South China Sea), and

• ACG Unit (Caspian Sea).

From 2003 to 2010, he served as the reservoir engineering representative on our internal peer review team. In this role, he reviewed reserves and resource estimates for projects including, but not limited to the Mobile Bay Norphlet Discoveries (Gulf of Mexico Shelf), Cascade Lower Tertiary Development (Gulf of Mexico Deepwater) and Polvo Development (Campos Basin, Brazil).

The Group reports independently of any of our operating divisions. The Group’s Director reports to our Vice President of Budget and Reserves, who reports to our Chief Financial Officer. No portion of the Group’s compensation is directly 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 additions and revisions to reserves. In addition, the Group reviews reserve estimates with each of the third-party petroleum consultants discussed below. The Group also ensures our Qualified Estimators obtain continuing education related to the fundamentals of SEC proved reserves assignments.

The Group also oversees audits and reserves estimates performed by third-party consulting firms. During 2011, we engaged two such firms to audit 95% of our proved reserves. LaRoche Petroleum Consultants, Ltd. audited the 2011 reserve estimates for 97% of our U.S. onshore properties. AJM Deloitte audited 89% of our Canadian reserves.

“Audited” reserves are those quantities of reserves that were estimated by our employees and audited by an independent petroleum consultant. The Society of Petroleum Engineers’ definition of 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 methods and procedures.

In addition to conducting these internal and external reviews, we also have a Reserves Committee that consists of three independent members of our Board of Directors. This committee provides additional oversight of our reserves estimation and certification process. The Reserves Committee assists the Board of Directors with its duties and responsibilities in evaluating and reporting our proved reserves, much like our Audit Committee assists the Board of Directors in supervising our audit and financial reporting requirements. Besides being independent, the members of our Reserves Committee also have educational backgrounds in geology or petroleum engineering, as well as experience relevant to the reserves estimation process.

The Reserves Committee meets a minimum of twice a year to discuss reserves issues and policies, and meets separately with our senior reserves engineering personnel and our independent petroleum consultants at those meetings. The responsibilities of the Reserves Committee include the following:

• approve the scope of and oversee an annual review and evaluation of our oil, gas and NGL reserves;

• oversee the integrity of our reserves evaluation and reporting system;

• oversee and evaluate our compliance with legal and regulatory requirements related to our reserves;

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

• monitor the performance of our independent engineering consultants.

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Production, Production Prices and Production Costs

The following table presents production, price and cost information for each significant field, country and continent.

	Production								Average Sales Price						Production Cost (Per Boe)
Year Ended December 31,	Oil (MMBbls)		Gas (Bcf)		NGLs (MMBbls)		Total (MMBoe)(1)		Oil (Per Bbl)		Gas (Per Mcf)		NGLs (Per Bbl)
2011
Barnett Shale		1		367		16		78	$	94.23	$	3.30	$	39.00	$	3.97
Jackfish		13		—		—		13	$	58.16	$	—	$	—	$	17.28
U.S.		17		740		33		173	$	91.19	$	3.50	$	39.47	$	5.35
Canada		28		213		4		67	$	66.97	$	3.87	$	55.99	$	13.82
North America		45		953		37		240	$	76.06	$	3.58	$	41.10	$	7.71
2010
Barnett Shale		1		335		13		70	$	77.40	$	3.55	$	29.97	$	3.87
Jackfish		9		—		—		9	$	52.51	$	—	$	—	$	16.81
U.S.		16		716		28		163	$	75.81	$	3.76	$	30.86	$	5.47
Canada		25		214		4		65	$	58.60	$	4.11	$	46.60	$	12.37
North America		41		930		32		228	$	65.14	$	3.84	$	32.61	$	7.42
2009
Barnett Shale		—		331		13		69	$	58.78	$	2.99	$	22.36	$	3.96
Jackfish		8		—		—		8	$	41.07	$	—	$	—	$	12.75
U.S.		17		743		26		167	$	57.56	$	3.20	$	23.51	$	5.97
Canada		25		223		4		66	$	47.35	$	3.66	$	33.09	$	10.15
North America		42		966		30		233	$	51.39	$	3.31	$	24.71	$	7.16

(1) Gas production is converted to Boe at the rate of six Mcf per Bbl of oil, based upon the approximate relative energy content of gas and oil. NGL production is converted to Boe on a one-to-one basis with oil.

Drilling Statistics

The following table summarizes our development and exploratory drilling results.

	Development Wells(1)				Exploratory Wells(1)				Total Wells(1)
Year Ended December 31,	Productive		Dry		Productive		Dry		Productive		Dry		Total
2011
U.S.		721.2		5.5		18.8		4.0		740.0		9.5		749.5
Canada		247.6		1.5		19.1		1.0		266.7		2.5		269.2
Total North America		968.8		7.0		37.9		5.0		1,006.7		12.0		1,018.7
2010
U.S.		855.7		5.3		23.4		1.5		879.1		6.8		885.9
Canada		267.8		—		41.9		1.0		309.7		1.0		310.7
Total North America		1,123.5		5.3		65.3		2.5		1,188.8		7.8		1,196.6
2009
U.S.		508.0		3.8		6.8		2.0		514.8		5.8		520.6
Canada		307.2		—		28.2		—		335.4		—		335.4
Total North America		815.2		3.8		35.0		2.0		850.2		5.8		856.0

(1) These well counts represent net wells completed during each year. Net wells are gross wells multiplied by our fractional working interests on the well.

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The following table presents the February 1, 2012, results of our wells that were in progress on December 31, 2011.

	Productive				Dry				Still in Progress				Total
	Gross(1)		Net(2)		Gross(1)		Net(2)		Gross(1)		Net(2)		Gross(1)		Net(2)
U.S.		221		150.7		—		—		43		22.5		264		173.2
Canada		6		5.5		—		—		1		1.0		7		6.5
Total North America		227		156.2		—		—		44		23.5		271		179.7

(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 on the well.

Productive Wells

The following table sets forth our producing wells as of December 31, 2011.

	Oil Wells				Natural Gas Wells				Total Wells
	Gross(1)		Net(2)		Gross(1)		Net(2)		Gross(1)		Net(2)
U.S.		8,319		3,003		20,762		13,613		29,081		16,616
Canada		5,150		3,958		5,584		3,322		10,734		7,280
Total North America		13,469		6,961		26,346		16,935		39,815		23,896

(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 on the well.

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 approximately 24,000 of our wells. As operator, we receive reimbursement for direct expenses incurred to perform 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.

Acreage Statistics

The following table sets forth our developed and undeveloped lease and mineral acreage as of December 31, 2011. The acreage in the table includes 0.6 million, 1.2 million and 0.5 million net acres subject to leases that are scheduled to expire during 2012, 2013 and 2014, respectively.

	Developed				Undeveloped				Total
	Gross(1)		Net(2)		Gross(1)		Net(2)		Gross(1)		Net(2)
	(In thousands)
U.S.		3,366		2,263		7,105		4,281		10,471		6,544
Canada		3,699		2,286		6,450		4,541		10,149		6,827
Total North America		7,065		4,549		13,555		8,822		20,620		13,371

(1) Gross acres are the sum of all acres in which we own an interest.

(2) Net acres are gross acres multiplied by our fractional working interests on the acreage.

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Title to Properties

Title to properties is subject to contractual arrangements customary in the oil and gas industry, liens for taxes not yet due and, in some instances, other encumbrances. We believe that such burdens do not materially detract from the value of 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, which generally include 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.

Marketing and Midstream Activities

The primary objective of our marketing and midstream operations is to add value to us and other producers to whom we provide such services by gathering, processing and marketing oil, gas and NGL production timely and efficiently.

Our marketing and midstream revenues 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.

Oil, Gas and NGL Marketing

The spot markets for oil, gas and NGLs are subject to volatility as supply and demand factors fluctuate. As detailed below, we sell our production under both long-term (one year or more) and short-term (less than one year) agreements at prices negotiated with third parties. Regardless of the term of the contract, the vast majority of our production is sold at variable, or market-sensitive, prices.

Additionally, we may periodically enter into financial hedging arrangements or fixed-price contracts associated 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 Note 2 to the financial statements included in “Item 8. Financial Statements and Supplementary Data” of this report for further information.

As of January 2012, our production was sold under the following contracts.

	Short-Tem						Long-Tem
	Variable			Fixed			Variable			Fixed
Oil		77	%		—			23	%		—
Natural gas		84	%		—			16	%		—
NGLs		69	%		10	%		21	%		—

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Delivery Commitments

A portion of our production is sold under certain contractual arrangements that specify the delivery of a fixed and determinable quantity. As of January 2012, we were committed to deliver the following fixed quantities of production.

	Total		Less Than 1 Year		1-3 Years		3-5 Years		More Than 5 Years
Oil (MMBbls)		126		14		27		27		58
Natural gas (Bcf)		1,077		341		284		109		343
NGLs (MMBbls)		3		2		1		—		—
Total (MMBoe)(1)		308		73		75		45		115

(1) Gas volumes are converted to Boe at the rate of six Mcf of gas per Bbl of oil, based upon the approximate relative energy content of gas and oil. NGLs are converted to Boe on a one-to-one basis with oil.

We expect to fulfill our delivery commitments over the next three years with production from our proved developed reserves. We expect to fulfill our longer-term delivery commitments beyond three years primarily with our proved developed reserves. In certain regions, we expect to fulfill these longer-term delivery commitments with our proved undeveloped reserves.

Our proved reserves have been sufficient to satisfy our delivery commitments during the three most recent years, and we expect such reserves will continue to satisfy our future commitments. However, should our proved reserves not be sufficient to satisfy our delivery commitments, we can and may use spot market purchases to fulfill the commitments.

Customers

During 2011, 2010 and 2009, no purchaser accounted for over 10% of our revenues.

Competition

See “Item 1A. Risk Factors.”

Public Policy and Government Regulation

The oil and natural gas industry is subject to various types of regulation throughout the world. Laws, rules, regulations and other policy implementations affecting the oil and natural gas industry have been pervasive and are under constant review for amendment or expansion. Pursuant to public policy changes, numerous government agencies have issued extensive laws and regulations binding on the oil and natural 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, marketing and midstream activities. These laws and regulations increase the cost of doing business and, consequently, affect profitability. Because public policy changes affecting the oil and natural gas industry are commonplace and because 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 natural gas companies of similar size and financial strength. The following are significant areas of government control and regulation affecting our operations.

Exploration and Production Regulation

Our oil and gas operations are subject to various federal, state, provincial, tribal and local laws and regulations. These laws and regulations relate to matters that include, but are not limited to:

• acquisition of seismic data;

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• location, drilling and casing of wells;

• hydraulic fracturing;

• well production;

• spill prevention plans;

• emissions and discharge permitting;

• use, transportation, storage and disposal of fluids and materials incidental to oil and gas operations;

• surface usage and the restoration of properties upon which wells have been drilled;

• calculation and disbursement of royalty payments and production taxes;

• plugging and abandoning of wells; and

• transportation of production.

Our operations also are subject to conservation regulations, including the regulation of the size of drilling and spacing units or proration units; the number of wells that may be drilled in a unit; the rate of production allowable from oil and gas wells; and the unitization or pooling of oil and gas properties. In the U.S., 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 generally limit the venting or flaring of natural 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 of our U.S. natural gas and oil leases are granted by the federal government and administered by the Bureau of Land Management of the Department of the Interior. Such leases require compliance with detailed federal regulations and orders that 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 federal government 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.

Royalties and Incentives in Canada

The royalty system in Canada is a significant factor in the profitability of oil and 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 and the type and quality of the petroleum product produced. From time to time, the federal and provincial governments of Canada also have established incentive programs such as royalty rate reductions, royalty holidays, tax credits and fixed rate and profit-sharing royalties for the purpose of encouraging oil and gas exploration or enhanced recovery projects. These incentives generally have the effect of increasing our revenues, earnings and cash flow.

Pricing and Marketing in Canada

Any oil or gas export to be made pursuant to an export contract that exceeds a certain duration or a certain quantity requires an exporter to obtain export authorizations from Canada’s National Energy Board (“NEB”). The governments of Alberta, British Columbia and Saskatchewan also regulate the volume of natural gas that may be removed from those provinces for consumption elsewhere.

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Environmental and Occupational Regulations

We are subject to various federal, state, provincial, tribal and local laws and regulations concerning occupational safety and health as well as the discharge of materials into, and the protection of, the environment. Environmental laws and regulations relate to, among other things:

• assessing the environmental impact of seismic acquisition, drilling or construction activities;

• the generation, storage, transportation and disposal of waste materials;

• the emission of certain gases into the atmosphere;

• the monitoring, abandonment, reclamation and remediation of well and other sites, including sites of former operations; and

• the development of emergency response and spill contingency plans.

We consider the costs of environmental protection and safety and health compliance necessary and manageable parts of our business. We have been able to plan for and comply with environmental, safety and health initiatives without materially altering our operating strategy or incurring significant unreimbursed expenditures. However, based on regulatory trends and increasingly stringent laws, our capital expenditures and operating expenses related to the protection of the environment and safety and health compliance have increased over the years and will likely continue to increase. We cannot predict with any reasonable degree of certainty our future exposure concerning such matters.

Item 1A. Risk Factors

Our business activities, and the oil and gas industry in general, are subject to a variety of risks. If any of the following risk factors should occur, our profitability, financial condition or liquidity could be materially impacted. As a result, holders of our securities could lose part or all of their investment in Devon.

Oil, Gas and NGL Prices are Volatile

Our financial results are highly dependent on the general supply and demand for oil, gas and NGLs, which impact the prices we ultimately realize on our sales of these commodities. A significant downward movement of the prices for these commodities could have a material adverse effect on our revenues, operating cash flows and profitability. Such a downward price movement could also have a material adverse effect on our estimated proved reserves, the carrying value of our oil and gas properties, the level of planned drilling activities and future growth. Historically, market prices and our realized 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, gas and NGLs;

• conservation efforts;

• OPEC production levels;

• weather;

• regional pricing differentials;

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

• differing quality and NGL content of gas produced;

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

• the price and availability of alternative fuels;

• the overall economic environment; and

• governmental regulations and taxes.

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Estimates of Oil, 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. Our policies and internal controls related to estimating and recording reserves are included in “Items 1 and 2. Business and Properties” of this report.

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

The production rates from oil and gas properties generally decline 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 or tertiary recovery techniques, 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, blowouts and surface cratering;

• adverse weather conditions;

• lack of access to pipelines or other transportation methods;

• environmental hazards or liabilities; and

• shortages or delays in the availability of services or 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.

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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. Typically, during times of high or rising commodity prices, drilling and operating costs will also increase. Higher prices will also generally increase the cost to acquire properties. Certain of our competitors have financial and other resources substantially larger than ours. They also may have established strategic long-term positions and relationships in areas 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 gas production, such as changing worldwide price and production levels, the cost and availability of alternative fuels, and the application of government regulations.

Midstream Capacity Constraints and Interruptions Impact Commodity Sales

We rely on midstream facilities and systems to process our natural gas production and to transport our production to downstream markets. Such midstream systems include the systems we operate, as well as systems operated by third parties. When possible, we gain access to midstream systems that provide the most advantageous downstream market prices available to us. Regardless of who operates the midstream systems we rely upon, a portion of our production in any region may be interrupted or shut in from time to time due to loss of access to plants, pipelines or gathering systems. Such access could be lost due to a number of factors, including, but not limited to, weather conditions, accidents, field labor issues or strikes. Additionally, we and third-parties may be subject to constraints that limit our ability to construct, maintain or repair midstream facilities needed to process and transport our production. Such interruptions or constraints could negatively impact our production and associated profitability.

Hedging Limits Participation in Commodity Price Increases and Increases Counterparty Credit Risk Exposure

We periodically enter into hedging activities with respect to a portion of our production to manage our exposure to oil, gas and NGL price volatility. To the extent that we engage in price risk management activities to protect ourselves from commodity price declines, we may be prevented from fully realizing the benefits of commodity price increases above the prices established by our hedging contracts. In addition, our hedging arrangements may expose us to the risk of financial loss in certain circumstances, including instances in which the contract counterparties fail to perform under the contracts.

Public Policy, Which Includes Laws, Rules and Regulations, Can Change

Our operations are generally subject to federal laws, rules and regulations in the U.S. and Canada. In addition, we are also subject to the laws and regulations of various states, provinces, tribal and local governments. Pursuant to public policy changes, 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 public policy have affected, and at times in the future could affect, our 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. Existing laws and regulations can also require us to incur substantial costs to maintain regulatory compliance. Our operating and other compliance costs could increase further if existing laws and regulations are revised or reinterpreted or if new laws and regulations become applicable to our operations. Although we are unable to predict changes to existing laws and regulations, such changes could significantly impact our profitability, financial condition and liquidity, particularly changes related to hydraulic fracturing, income taxes and climate change as discussed below.

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Hydraulic Fracturing — The U.S. Department of the Interior is considering the possibility of additional regulation of hydraulic fracturing on federal lands. Currently, regulation of hydraulic fracturing is conducted primarily at the state level through permitting and other compliance requirements. We lease federal lands and would be affected by the Interior Department proposal if it were to become law.

Income Taxes — We are subject to federal, state, provincial and local income taxes and our operating cash flow is sensitive to the amount of income taxes we must pay. In the jurisdictions in which we operate, income taxes are assessed on our earnings after consideration of all allowable deductions and credits. Changes in the types of earnings that are subject to income tax, the types costs that are considered allowable deductions or the rates assessed on our taxable earnings would all impact our income taxes and resulting operating cash flow. The U.S. President’s budget proposals include provisions that would, if enacted, make significant changes to U.S. tax laws. The most significant change to our business would eliminate the immediate deduction for intangible drilling and development costs.

Climate Change — Policy makers in the U.S. are increasingly focusing on whether the emissions of greenhouse gases, such as carbon dioxide and methane, are contributing to harmful climatic changes. Policy makers at both the U.S. federal and state level have introduced legislation and proposed new regulations that are designed to quantify and limit the emission of greenhouse gases through inventories and limitations on greenhouse gas emissions. Legislative initiatives to date have focused on the development of cap-and-trade programs. These programs generally would cap overall greenhouse gas emissions on an economy-wide basis and require major sources of greenhouse gas emissions or major fuel producers to acquire and surrender emission allowances. Cap-and-trade programs would be relevant to our operations because the equipment we use to explore for, develop, produce and process oil and natural gas emits greenhouse gases. Additionally, the combustion of carbon-based fuels, such as the oil, gas and NGLs we sell, emits carbon dioxide and other greenhouse gases.

Environmental Matters and Costs Can Be Significant

As an owner, lessee or operator of oil and gas properties, we are subject to various federal, state, provincial, tribal and local 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. Any future environmental costs of fulfilling our commitments to the environment are uncertain and will be governed by several factors, including future changes to regulatory requirements. There is no assurance that changes in or additions to public policy regarding the protection of the environment will not have a significant impact on our operations and profitability.

Insurance Does Not Cover All Risks

Our business is hazardous and is subject to all of the operating risks normally associated with the exploration, development, production, processing and transportation of oil, natural gas and NGLs. Such risks include potential blowouts, cratering, fires, loss of well control, mishandling of fluids and chemicals and possible underground migration of hydrocarbons and chemicals. The occurrence of any of these risks could result in environmental pollution, damage to or destruction of our property, equipment and natural resources, injury to person or loss of life. Additionally, for our non-operated properties, we generally depend on the operator for operational safety and regulatory compliance.

To mitigate financial losses resulting from these operational hazards, we maintain comprehensive general liability insurance, as well as insurance coverage against certain losses resulting from physical damages, loss of well control, business interruption and pollution events that are considered sudden and accidental. We also maintain worker’s compensation and employer’s liability insurance. However, our insurance coverage does not provide 100% reimbursement of potential losses resulting from these operational hazards. Additionally, insurance coverage is generally not available to us for pollution events that are considered gradual, and we have

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limited or no insurance coverage for certain risks such as political risk, war and terrorism. Our insurance does not cover penalties or fines assessed by governmental authorities. The occurrence of a significant event against which we are not fully insured could have a material adverse effect on our profitability, financial condition and liquidity.

Limited Control on Properties Operated by Others

Certain of the properties in which we have an interest are operated by other companies and involve third-party working interest owners. We have limited influence and control over the operation or future development of such properties, including compliance with environmental, health and safety regulations or the amount of required future capital expenditures. These limitations and our dependence on the operator and other working interest owners for these properties could result in unexpected future costs and adversely affect our financial condition and results of operations.

Item 1B. Unresolved Staff Comments

None.

Item 3. Legal Proceedings

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

Item 4. Mine Safety Disclosures

None.

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PART II

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

Our common stock is traded on the New York Stock Exchange (the “NYSE”). On February 9, 2012, there were 12,183 holders of record of our common stock. The following table sets forth the quarterly high and low sales prices for our common stock as reported by the NYSE during 2011 and 2010, as well as the quarterly dividends per share paid during 2011 and 2010. We began paying regular quarterly cash dividends on our common stock in the second quarter of 1993. We anticipate continuing to pay regular quarterly dividends in the foreseeable future.

	Price Range of Common Stock				Dividends Per Share
	High		Low
2011:
Quarter Ended December 31, 2011	$	69.55	$	50.74	$	0.17
Quarter Ended September 30, 2011	$	84.52	$	55.14	$	0.17
Quarter Ended June 30, 2011	$	92.69	$	75.50	$	0.17
Quarter Ended March 31, 2011	$	93.55	$	76.96	$	0.16
2010:
Quarter Ended December 31, 2010	$	78.86	$	63.76	$	0.16
Quarter Ended September 30, 2010	$	66.21	$	59.07	$	0.16
Quarter Ended June 30, 2010	$	70.80	$	58.58	$	0.16
Quarter Ended March 31, 2010	$	76.79	$	62.38	$	0.16

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Performance Graph

The following performance graph compares the yearly percentage change in the cumulative total shareholder return on Devon’s common stock with the cumulative total returns of the Standard & Poor’s 500 index (“the S&P 500 Index”) and the group of companies included in the Crude Petroleum and Natural Gas Standard Industrial Classification code (“the SIC Code”). The graph was prepared assuming $100 was invested on December 31, 2006 in Devon’s common stock, the S&P 500 Index and the SIC Code and dividends have been reinvested subsequent to the initial investment.

The graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933, as amended, or Securities Exchange Act of 1934, as amended, except to the extent that we specifically incorporate such information by reference into such a filing. The graph and information is included for historical comparative purposes only and should not be considered indicative of future stock performance.

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Issuer Purchases of Equity Securities

The following table provides information regarding purchases of our common stock that were made by us during the fourth quarter of 2011.

Period	Total Number of Shares Purchased(2)		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs(1)		Maximum Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs(1)
							(In millions)
October 1 – October 31		3,228,557	$	58.52		3,227,800	$	108
November 1 – November 30		1,813,994	$	66.38		1,618,110	$	—
December 1 – December 31		475,685	$	64.68		—	$	—
Total		5,518,236	$	61.64		4,845,910

(1) In May 2010, our Board of Directors approved a $3.5 billion share repurchase program. We completed this program in the fourth quarter of 2011. In total, we repurchased 49.2 million common shares for $3.5 billion, or $71.18 per share, under this program.

(2) During the fourth quarter of 2011, we repurchased 672,326 shares from company employees for the payment of personal income tax withholdings resulting from restricted stock vesting and stock option exercises. Such repurchases are in addition to the $3.5 billion repurchase program.

Under the Devon Energy Corporation Incentive Savings Plan (the “Plan”), eligible employees may purchase shares of our common stock through an investment in the Devon Stock Fund (the “Stock Fund”), which is administered by an independent trustee, Fidelity Management Trust Company. Eligible employees purchased approximately 45,000 shares of our common stock in 2011, at then-prevailing stock prices, that they held through their ownership in the Stock Fund. We acquired the shares of our common stock sold under the Plan through open-market purchases. We filed a registration statement on Form S-8 on January 26, 2012 registering any offers and sales of interests in the Plan or the Stock Fund and of the underlying shares of our common stock purchased by Plan participants after that date.

Similarly, under the Devon Canada Corporation Savings Plan (the “Canadian Plan”), eligible Canadian employees may purchase shares of our common stock through an investment in the Canadian Plan, which is administered by an independent trustee, Sun Life Assurance Company of Canada. Eligible Canadian employees purchased approximately 9,000 shares of our common stock in 2011, at then-prevailing stock prices, that they held through their ownership in the Canadian Plan. We acquired the shares sold under the Canadian Plan through open-market purchases. These shares and any interest in the Canadian Plan were offered and sold in reliance on the exemptions for offers and sales of securities made outside of the U.S., including under Regulation S for offers and sales of securities to employees pursuant to an employee benefit plan established and administered in accordance with the law of a country other than the U.S.

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Item 6. Selected Financial Data

The financial information below should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data” of this report.

	Year Ended December 31,
	2011		2010		2009			2008			2007
	(In millions, except per share amounts)
Revenues	$	11,454	$	9,940	$	8,015		$	13,858		$	9,975
Earnings (loss) from continuing operations(1)	$	2,134	$	2,333	$	(2,753	)	$	(3,039	)	$	2,485
Earnings (loss) per share from continuing operations — Basic	$	5.12	$	5.31	$	(6.20	)	$	(6.86	)	$	5.56
Earnings (loss) per share from continuing operations — Diluted	$	5.10	$	5.29	$	(6.20	)	$	(6.86	)	$	5.50
Cash dividends per common share	$	0.67	$	0.64	$	0.64		$	0.64		$	0.56
Weighted average common shares outstanding — Basic		417		440		444			444			445
Weighted average common shares outstanding — Diluted		418		441		444			444			450
Total assets(1)	$	41,117	$	32,927	$	29,686		$	31,908		$	41,456
Long-term debt	$	5,969	$	3,819	$	5,847		$	5,661		$	6,924
Stockholders’ equity	$	21,430	$	19,253	$	15,570		$	17,060		$	22,006

(1) During 2009 and 2008, we recorded noncash reductions of the carrying value of oil and gas properties totaling $6.4 billion ($4.1 billion after income taxes) and $9.9 billion ($6.7 billion after income taxes), respectively.

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 and should be read in conjunction with “Item 8. Financial Statements and Supplementary Data” of this report.

Overview of Business

As an enterprise, we strive to optimize value for our shareholders by growing cash flows, earnings, production and reserves, all on a per debt-adjusted share basis. We accomplish this by executing our strategy, which is outlined in “Items 1 and 2. Business and Properties” of this report

Overview of 2011 Results

2011 was an outstanding year for Devon. We generated record net earnings, increased proved reserves to an all-time high and completed our highly successful strategic repositioning, transforming us into a pure North American onshore company. We have now essentially completed our offshore divestiture program. In aggregate, the divestiture program generated after-tax proceeds of approximately $8 billion, assuming the repatriation of a substantial portion of the foreign proceeds under current U.S. tax law. We also completed our $3.5 billion share repurchase program in the fourth quarter of 2011.

As we have increased our focus on the vast opportunities in our North American onshore portfolio of properties, we are seeing improvements in key measures of our performance, including growth in liquids

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production and cash flow, both on a per share debt-adjusted basis, which is key to maximizing shareholder value. Key measures of our 2011 production performance, as well as certain other financial measures and operational developments, are summarized below:

• North America Onshore liquids production grew 15% over 2010, to 223 MBoe per day.

• North America Onshore gas production increased 4% compared with 2010, to 2,610 MMcf per day.

• The combined realized price for oil, gas and NGLs per Boe increased 9% to $34.64.

• Oil, gas and NGL derivatives generated net gains of $881 million in 2011, including cash receipts of $392 million.

• Per unit lease operating costs increased 4% to $7.71 per Boe.

• Operating cash flow increased to $6.2 billion, representing a 14% increase over 2010.

• Capitalized costs incurred in our oil and gas activities totaled $6.9 billion in 2011. This includes approximately $1.5 billion for acreage acquisitions and exploration activity.

• Reserves reached an all-time high of 3,005 MMBoe.

Fourth Quarter Operational Developments

• We increased our fourth-quarter liquids production by 21 percent compared to the year-ago period, to 238,000 barrels per day.

• This liquids growth drove our production ten percent higher than the year-ago quarter to a record 680,000 equivalent barrels per day.

• In the fourth-quarter, our exploration and production capital totaled $1.9 billion. This amount includes approximately $400 million of opportunistic leasehold acquisition, consisting of acreage additions in the Ohio Utica and leasehold capture in an undisclosed, new oil opportunity.

• In the Permian Basin, we increased oil and natural gas liquids production 22 percent compared to the fourth-quarter 2010. Liquids production accounted for nearly 75 percent of the 53,000 equivalent barrels per day produced in the Permian Basin during the quarter.

• We completed eight operated Bone Spring wells within the Permian Basin in the fourth quarter. Initial daily production from these wells averaged more than 600 Boe per day per well.

• In total, net production from our Jackfish 1 and Jackfish 2 projects averaged a record 43,000 barrels per day in the fourth quarter, representing a 91 percent increase over the year-ago quarter. Our Jackfish 2 production exited the fourth quarter at 14,000 barrels per day and will continue to ramp-up throughout 2012.

• In early December, we received regulatory approval for our third 35,000 barrel per day Jackfish project. We have begun construction with plant startup targeted for late 2014.

• Immediately adjacent to Jackfish, we are currently drilling appraisal wells and acquiring seismic on our Pike oil sands lease to determine the optimal development plan. In total, we expect Pike will support up to five 35,000 barrel per day projects.

• Fourth-quarter production from our Cana-Woodford Shale play in western Oklahoma increased 83 percent over the fourth quarter of 2010. Net production averaged a record 250 million cubic feet of gas equivalent per day, including 3,100 barrels of oil and 7,400 barrels per day of natural gas liquids.

• Our Barnett Shale production averaged a record 1.32 billion cubic feet of gas equivalent per day in the fourth quarter of 2011, an 11 percent increase over the fourth quarter of 2010. Liquids production accounted for 21 percent of total production, averaging 47,000 barrels per day during the quarter.

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• We brought six operated Granite Wash wells online in the fourth quarter. Initial production from these wells averaged 1,300 barrels of oil-equivalent per day. Fourth-quarter production from our Granite Wash play reached 19,100 barrels per day, a 47 percent increase over 2010.

Business and Industry Outlook

We possess a great deal of financial strength and flexibility and are fully committed to exercising capital discipline, maximizing profits, maintaining balance sheet strength and optimizing growth per debt-adjusted share. Our portfolio of assets provides a great deal of investment flexibility. We expect gas prices will remain challenged in the market throughout 2012. Therefore, our near-term focus is on the oil and liquids-rich opportunities that exist within our balanced portfolio of properties. The vast majority of our 2012 drilling activity will be centered on our oil and liquids-rich gas properties. Should the outlook for commodity prices change, we have the flexibility to redirect our capital to ensure we continually focus on the highest-return assets in our portfolio.

Additionally, our financial and operational flexibility will be further enhanced by the transaction that we announced in early 2012 with Sinopec International Petroleum Exploration & Production Corporation, which we expect to close in the first quarter of 2012. Pursuant to the terms of the agreement, Sinopec will pay $2.5 billion, including a $900 million payment at closing and $1.6 billion toward our share of future drilling costs, and will receive a 33.3% interest in five of our new venture plays.

Our ability to leverage the depth and breadth of our existing portfolio of properties will be important to successfully achieve our growth and value-creation objectives. With 3,005 MMBoe of proved reserves at the end of 2011, our assets will provide many years of visible, economic growth and a good balance between liquids and natural gas. In 2012, we are targeting a 6 percent production increase, which will be fueled by liquids growth approaching 20%.

Results of Operations

All amounts in this document related to our International operations are presented as discontinued. Therefore, the production, revenue and expense amounts presented in this “Results of Operations” section exclude amounts related to our International assets unless otherwise noted.

Even though we divested our U.S. Offshore operations in 2010, these properties do not qualify as discontinued operations under accounting rules. As such, financial and operating data provided in this document that pertain to our continuing operations include amounts related to our U.S. Offshore operations. To facilitate comparisons of our ongoing operations subsequent to the planned divestitures, we have presented amounts related to our U.S. Offshore assets separate from those of our North American Onshore assets where appropriate.

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Production, Prices and Revenues

	Year Ended December 31,
	2011		2011 vs. 2010(1)			2010		2010 vs. 2009(1)			2009
Oil (MBbls/d)
U.S. Onshore		46		+24	%		37		+17	%		32
Canada		77		+11	%		69		–1	%		69
North America Onshore		123		+16	%		106		+5	%		101
U.S. Offshore		—		–100	%		5		–62	%		14
Total		123		+10	%		111		–3	%		115
Gas (MMcf/d)
U.S. Onshore		2,027		+6	%		1,914		0	%		1,914
Canada		583		–1	%		587		–4	%		611
North America Onshore		2,610		+4	%		2,501		–1	%		2,525
U.S. Offshore		—		–100	%		46		–63	%		123
Total		2,610		+2	%		2,547		–4	%		2,648
NGLs (MBbls/d)
U.S. Onshore		90		+17	%		77		+10	%		70
Canada		10		+2	%		10		–6	%		11
North America Onshore		100		+15	%		87		+8	%		81
U.S. Offshore		—		–100	%		1		–55	%		2
Total		100		+14	%		88		+6	%		83
Combined (MBoe/d)(2)
U.S. Onshore		474		+9	%		433		+3	%		421
Canada		184		+4	%		177		–3	%		182
North America Onshore		658		+8	%		610		+1	%		603
U.S. Offshore		—		–100	%		14		–62	%		36
Total		658		+5	%		624		–2	%		639

(1) Percentage changes are based on actual figures rather than the rounded figures presented.

(2) Gas production is converted to Boe at the rate of six Mcf of gas per Bbl of oil, based upon the approximate relative energy content of gas and oil. NGL production is converted to Boe on a one-to-one basis with oil.

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	Year Ended December 31,
	2011(1)		2011 vs. 2010			2010(1)		2010 vs. 2009			2009(1)
Oil (per Bbl)
U.S. Onshore	$	91.19		+21	%	$	75.53		+34	%	$	56.17
Canada	$	66.97		+14	%	$	58.60		+24	%	$	47.35
North America Onshore	$	76.06		+18	%	$	64.51		+29	%	$	50.11
U.S. Offshore	$	—		–100	%	$	77.81		+28	%	$	60.75
Total	$	76.06		+17	%	$	65.14		+27	%	$	51.39
Gas (per Mcf)
U.S. Onshore	$	3.50		–6	%	$	3.73		+19	%	$	3.14
Canada	$	3.87		–6	%	$	4.11		+12	%	$	3.66
North America Onshore	$	3.58		–6	%	$	3.82		+17	%	$	3.27
U.S. Offshore	$	—		–100	%	$	5.12		+22	%	$	4.20
Total	$	3.58		–7	%	$	3.84		+16	%	$	3.31
NGLs (per Bbl)
U.S. Onshore	$	39.47		+28	%	$	30.78		+32	%	$	23.40
Canada	$	55.99		+20	%	$	46.60		+41	%	$	33.09
North America Onshore	$	41.10		+26	%	$	32.55		+32	%	$	24.65
U.S. Offshore	$	—		–100	%	$	38.22		+39	%	$	27.42
Total	$	41.10		+26	%	$	32.61		+32	%	$	24.71
Combined (per Boe)
U.S. Onshore	$	31.31		+10	%	$	28.42		+27	%	$	22.41
Canada	$	43.23		+11	%	$	39.11		+21	%	$	32.29
North America Onshore	$	34.64		+10	%	$	31.52		+24	%	$	25.38
U.S. Offshore	$	—		–100	%	$	49.06		+26	%	$	38.83
Total	$	34.64		+9	%	$	31.91		+22	%	$	26.15

(1) Prices presented exclude any effects due to oil, gas and NGL derivatives.

The volume and price changes in the tables above caused the following changes to our oil, gas and NGL sales.

	Oil			Gas			NGLs		Total
	(In millions)
2009 sales	$	2,153		$	3,197		$	747	$	6,097
Changes due to volumes		(67	)		(122	)		46		(143	)
Changes due to prices		557			497			254		1,308
2010 sales		2,643			3,572			1,047		7,262
Changes due to volumes		268			88			147		503
Changes due to prices		488			(249	)		311		550
2011 sales	$	3,399		$	3,411		$	1,505	$	8,315

Oil Sales

2011 vs. 2010 Oil sales increased $488 million in 2011 as a result of a 17 percent increase in our realized price without hedges. The largest contributor to the higher realized price was an increase in the average NYMEX West Texas Intermediate price.

Oil sales increased $268 million due to a 10 percent increase in production. The increase in production was driven by the continued development of our Permian Basin properties and our Jackfish thermal heavy oil projects in Canada. This increase was partially offset by the divestiture of our U.S. Offshore properties in the second quarter of 2010.

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2010 vs. 2009 Oil sales increased $557 million as a result of a 27 percent increase in our realized price without hedges. The largest contributor to the higher realized price was an increase in the average NYMEX West Texas Intermediate index price.

Oil sales decreased $67 million due to a 3 percent production decline. The decrease was comprised of the net effects of a 62 percent decrease in our U.S. Offshore production and a 5 percent increase in our North America Onshore production. The decrease in our U.S. Offshore production was primarily due to the divestiture of such properties in the second quarter of 2010. The increased North America Onshore production resulted primarily from continued development of our Permian Basin properties and our Jackfish thermal heavy oil projects in Canada.

Gas Sales

2011 vs. 2010 Gas sales decreased $249 million in 2011 as a result of a 7 percent decrease in our realized price without hedges. The change in price was largely due to fluctuations of the North American regional index prices upon which our gas sales are based.

Gas sales increased $88 million due to a 2 percent increase in production. The increased production resulted primarily from continued development activities in the Barnett and Cana-Woodford Shales, partially offset by natural declines in our other operating areas. This increase was partially offset by the divestiture of our U.S. Offshore properties in the second quarter of 2010.

2010 vs. 2009 Gas sales increased $497 million as a result of a 16 percent increase in our realized price without hedges. This increase was largely due to higher North American regional index prices upon which our gas sales are based.

Gas sales decreased $122 million due to a 4 percent decrease in production. The decrease was primarily due to the divestiture of our U.S. Offshore properties in the second quarter of 2010. Also, our North American Onshore properties decreased 1 percent due to reduced drilling during most of 2009 in response to lower gas prices.

NGL Sales

2011 vs. 2010 NGL sales increased $311 million in 2011 due to a 26 percent increase in our realized price without hedges. The higher price was largely due to an increase in the Mont Belvieu, Texas hub price.

NGL sales increased $147 million in 2011 due to a 14 percent increase in production. The increased production was primarily due to increased drilling in our Barnett Shale, Cana-Woodford Shale and Granite Wash locations.

2010 vs. 2009 NGL sales increased $254 million in 2010 as a result of a 32 percent increase in our realized price. The higher price was largely due to an increase in the Mont Belvieu, Texas hub price.

NGL sales increased $46 million in 2010 due to a 6 percent increase in production. The increase in production was primarily due to increased drilling in our North American Onshore areas that have liquids-rich gas.

Oil, Gas and NGL Derivatives

The following tables provide financial information associated with our oil, gas and NGL hedges. The first table presents the cash settlements and unrealized gains and losses recognized as components of our revenues.

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The subsequent tables present our oil, gas and NGL prices with, and without, the effects of the cash settlements. The prices do not include the effects of unrealized gains and losses.

	Year Ended December 31,
	2011			2010			2009
	(In millions)
Cash settlements:
Gas derivatives	$	416		$	888		$	505
Oil derivatives		(26	)		—			—
NGL derivatives		2			—			—
Total cash settlements		392			888			505
Unrealized gains (losses) on fair value changes:
Gas derivatives		305			12			(83	)
Oil derivatives		185			(91	)		(38	)
NGL derivatives		(1	)		2			—
Total unrealized gains (losses)		489			(77	)		(121	)
Oil, gas and NGL derivatives	$	881		$	811		$	384

	Year ended December 31, 2011
	Oil (Per Bbl)			Gas (Per Mcf)		NGLs (Per Bbl)		Total (Per Boe)
Realized price without hedges	$	76.06		$	3.58	$	41.10	$	34.64
Cash settlements of hedges		(0.58	)		0.44		0.07		1.63
Realized price, including cash settlements	$	75.48		$	4.02	$	41.17	$	36.27

	Year ended December 31, 2010
	Oil (Per Bbl)		Gas (Per Mcf)		NGLs (Per Bbl)		Total (Per Boe)
Realized price without hedges	$	65.14	$	3.84	$	32.61	$	31.91
Cash settlements of hedges		—		0.96		—		3.90
Realized price, including cash settlements	$	65.14	$	4.80	$	32.61	$	35.81

	Year ended December 31, 2009
	Oil (Per Bbl)		Gas (Per Mcf)		NGLs (Per Bbl)		Total (Per Boe)
Realized price without hedges	$	51.39	$	3.31	$	24.71	$	26.15
Cash settlements of hedges		—		0.52		—		2.16
Realized price, including cash settlements	$	51.39	$	3.83	$	24.71	$	28.31

A summary of our outstanding commodity derivatives is included in Note 2 to the financial statements included in “Item 8. Financial Statements and Supplementary Data” of this report. Our oil, gas and NGL derivatives include price swaps, costless collars and basis swaps. For the price swaps, we receive a fixed price for our production and pay a variable market price to the contract counterparty. The price collars set a floor and ceiling price. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, we cash-settle the difference with the counterparty to the collars. For the basis swaps, we receive a fixed differential between two regional gas index prices and pay a variable differential on the same two index prices to the contract counterparty. Cash settlements as presented in the tables above represent realized gains or losses related to these various instruments.

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Also, to facilitate a portion of our price swaps, we sold gas call options for 2012 and oil call options for 2011 and 2012. The call options give counterparties the right to purchase production at a predetermined price.

In addition to cash settlements, we also recognize unrealized changes in the fair values of our oil, gas and NGL derivative instruments in each reporting period. The changes in fair value resulted from new positions and settlements that occurred during each period, as well as the relationships between contract prices and the associated forward curves. Including the cash settlements discussed above, our oil, gas and NGL derivatives generated net gains of $881 million, $811 million and $384 million during 2011, 2010 and 2009, respectively.

Marketing and Midstream Revenues and Operating Costs and Expenses

	Year Ended December 31,
	2011		2011 vs. 2010(1)			2010		2010 vs. 2009(1)			2009
	($ in millions)
Marketing and midstream:
Revenues	$	2,258		+21	%	$	1,867		+22	%	$	1,534
Operating costs and expenses		1,716		+26	%		1,357		+33	%		1,022
Operating profit	$	542		+6	%	$	510		0	%	$	512

(1) Percentage changes are based on actual figures rather than the rounded figures presented.

2011 vs. 2010 Marketing and midstream operating profit increased $32 million primarily due to higher gas throughput and higher NGL prices.

2010 vs. 2009 Marketing and midstream operating profit decreased $2 million primarily due to higher natural gas and NGL prices, partially offset by the effects of lower gas marketing profits.

Lease Operating Expenses (“LOE”)

	Year Ended December 31,
	2011		2011 vs. 2010(1)			2010		2010 vs. 2009(1)			2009
LOE ($ in millions):
U.S. Onshore	$	925		+11	%	$	832		–1	%	$	838
Canada		926		+16	%		797		+18	%		673
North America Onshore		1,851		+14	%		1,629		+8	%		1,511
U.S. Offshore		—		–100	%		60		–62	%		159
Total	$	1,851		+10	%	$	1,689		+1	%	$	1,670
LOE per Boe:
U.S. Onshore	$	5.35		+2	%	$	5.26		–4	%	$	5.46
Canada	$	13.82		+12	%	$	12.37		+22	%	$	10.15
North America Onshore	$	7.71		+5	%	$	7.32		+7	%	$	6.87
U.S. Offshore	$	—		–100	%	$	12.00		0	%	$	11.98
Total	$	7.71		+4	%	$	7.42		+4	%	$	7.16

(1) Percentage changes are based on actual figures rather than the rounded figures presented.

2011 vs. 2010 LOE increased $0.29 per Boe in 2011. LOE increased $0.39 per Boe, excluding the U.S. Offshore operations that were sold in the second quarter of 2010. The largest contributor to the higher North America Onshore unit cost is our oil production growth, particularly at our Jackfish thermal heavy oil projects in

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Canada. Such oil projects generally require a higher cost to produce per unit than our gas projects. We also experienced upward pressures on costs in certain operating areas, which increased LOE per Boe. Additionally, LOE per Boe increased $0.15 due to a $36 million increase from changes in the exchange rate between the U.S. and Canadian dollars.

2010 vs. 2009 LOE increased $0.26 per Boe in 2010. LOE increased $0.45 per Boe, excluding costs associated with our U.S. Offshore operations. LOE per Boe increased $0.34 due to a $78 million increase from changes in the exchange rate between the U.S. and Canadian dollars. The remainder of the increase in North America Onshore LOE per Boe was primarily due to increased costs related to our Jackfish operation in Canada.

Depreciation, Depletion and Amortization (“DD&A”)

	Year Ended December 31,
	2011		2011 vs. 2010(1)			2010		2010 vs. 2009(1)			2009
DD&A ($ in millions):
Oil & gas properties	$	1,987		+19	%	$	1,675		–9	%	$	1,832
Other properties		261		+2	%		255		–8	%		276
Total	$	2,248		+17	%	$	1,930		–8	%	$	2,108
DD&A per Boe:
Oil & gas properties	$	8.28		+13	%	$	7.36		–6	%	$	7.86
Other properties	$	1.09		–3	%	$	1.12		–5	%	$	1.18
Total	$	9.37		+10	%	$	8.48		–6	%	$	9.04

(1) Percentage changes are based on actual figures rather than the rounded figures presented.

A description of how DD&A of our oil and gas properties is calculated is included in Note 1 to the financial statements included in “Item 8. Financial Statements and Supplementary Data” of this report. Generally, when reserve volumes are revised up or down, then the DD&A rate per unit of production will change inversely. However, when 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.

2011 vs. 2010 Oil and gas property DD&A increased $221 million during 2011 due to a 13 percent increase in the DD&A rate and $91 million due to our 5 percent increase in production. The largest contributors to the higher rate were our 2011 drilling and development activities and changes in the exchange rate between the U.S. and Canadian dollars. These increases were partially offset by the divestiture of our U.S. Offshore properties in the second quarter of 2010.

2010 vs. 2009 Oil and gas property DD&A decreased $114 million during 2010 due to a 6 percent decrease in the DD&A rate and $43 million due to our 2 percent decline in production. The largest contributors to the rate decrease were our 2010 U.S. Offshore property divestitures and a $6.4 billion reduction of the carrying value of our U.S. oil and gas properties recognized in the first quarter of 2009. These decreases were partially offset by the effects of costs incurred and transfers of previously unproved costs to the depletable base as a result of our 2010 drilling and development activities, as well as changes in the exchange rate between the U.S. and Canadian dollars.

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General and Administrative Expenses (“G&A”)

	Year Ended December 31,
	2011			2011 vs. 2010(1)			2010			2010 vs. 2009(1)			2009
	($ in millions)
Gross G&A	$	1,036			+5	%	$	987			–11	%	$	1,107
Capitalized G&A		(337	)		+8	%		(311	)		–6	%		(332	)
Reimbursed G&A		(114	)		+1	%		(113	)		–11	%		(127	)
Net G&A	$	585			+4	%	$	563			–13	%	$	648
Net G&A per Boe	$	2.44			–1	%	$	2.47			–11	%	$	2.78

(1) Percentage changes are based on actual figures rather than the rounded figures presented.

2011 vs. 2010 Net G&A increased during 2011 primarily due to higher employee compensation and benefits, while net G&A per Boe slightly declined as we grew production at a higher rate than G&A.

2010 vs. 2009 Net G&A on an absolute and per Boe basis decreased largely due to a decline in employee severance costs. Such costs decreased primarily due to employees that were impacted by the integration of our offshore operations into one unit in 2009. In addition, net G&A decreased subsequent to our mid-year 2010 offshore divestitures as a result of the decline in our workforce.

Taxes Other Than Income Taxes

	Year Ended December 31,
	2011		2011 vs. 2010(1)		2010		2010 vs. 2009(1)		2009
	($ in millions)
Production	$	248		+18%	$	210		+59%	$	132
Ad valorem and other		176		+4%		170		–7%		182
Total	$	424		+12%	$	380		+21%	$	314
Taxes other than income taxes % of oil, gas and NGL revenue		5.10%		-3%		5.24%		+2%		5.16%

(1) Percentage changes are based on actual figures rather than the rounded figures presented.

Taxes other than income taxes increased in each period primarily due to an increase in our U.S. Onshore revenues, on which the majority of our production taxes are assessed.

Interest Expense

	Year Ended December 31,
	2011			2010			2009
	(In millions)
Interest based on debt outstanding	$	414		$	408		$	437
Capitalized interest		(72	)		(76	)		(94	)
Early retirement of debt		—			19			—
Other		10			12			6
Total	$	352		$	363		$	349

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2011 vs. 2010 Interest expense decreased primarily due to costs associated with the early retirement of our $350 million notes in 2010. This was partially offset by higher interest resulting from increased debt balances in 2011.

2010 vs. 2009 Interest expense increased due to costs associated with the early retirement of debt discussed above and a decrease in our capitalized interest. The decrease in capitalized interest resulted primarily from the divestiture of our U.S. Offshore properties in 2010. These increases were partially offset by lower interest on our debt balances resulting from the retirement of $350 million of notes in 2010 and $177 million of notes in 2009.

Restructuring Costs

	Year Ended December 31,
	2011			2010			2009
	(In millions)
Cash severance	$	9		$	(17	)	$	66
Share-based awards		(1	)		(10	)		39
Lease obligations		(13	)		70			—
Asset impairments		2			11			—
Other		1			3			—
Total(1)	$	(2	)	$	57		$	105

(1) Restructuring costs related to our discontinued operations totaled $(2) million, $(4) million, and $48 million in 2011, 2010, and 2009, respectively. These costs primarily consist of employee severance and are not included in the table.

In the fourth quarter of 2009, we announced plans to divest our offshore assets. As of December 31, 2011, we had divested all of our U.S. Offshore assets and substantially all of our International assets. Through the end of 2011, we had incurred $202 million of restructuring costs associated with these divestitures.

Employee Severance

This amount was originally based on estimates of the number of employees that would ultimately be impacted by the offshore divestitures and included amounts related to cash severance costs and accelerated vesting of share-based grants. As the divestiture program progressed, we decreased our overall estimate of employee severance costs. More offshore employees than previously estimated received comparable positions with either the purchaser of the properties or in our U.S. Onshore operations.

Lease Obligations

As a result of the divestitures, we ceased using certain office space that was subject to non-cancellable operating lease arrangements. Consequently, in 2010 we recognized $70 million of restructuring costs that represented the present value of our future obligations under the leases, net of anticipated sublease income. Our estimate of lease obligations was based upon certain key estimates that could change over the term of the leases. These estimates include the estimated sublease income that we may receive over the term of the leases, as well as the amount of variable operating costs that we will be required to pay under the leases.

In addition, we recognized $11 million of asset impairment charges for leasehold improvements and furniture associated with the office space that we ceased using.

Reduction of Carrying Value of Oil and Gas Properties

In the first quarter of 2009, we reduced the carrying value of our U.S. oil and gas properties $6.4 billion, or $4.1 billion after taxes, due to a full cost ceiling limitation. The lower ceiling value largely resulted from the

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effects of declining natural gas prices subsequent to December 31, 2008. To demonstrate the decline, the March 31, 2009 and December 31, 2008 weighted average wellhead prices are presented in the following table.

March 31, 2009					December 31, 2008
Oil (Per Bbl)	Gas (Per Mcf)		NGLs (Per Bbl)		Oil (Per Bbl)		Gas (Per Mcf)		NGLs (Per Bbl)
$47.30	$	2.67	$	17.04	$	42.21	$	4.68	$	16.16

The March 31, 2009 oil and gas wellhead prices in the table above compare to the NYMEX cash price of $49.66 per Bbl for crude oil and the Henry Hub spot price of $3.63 per MMBtu for gas. The December 31, 2008 oil and gas wellhead prices in the table above compare to the NYMEX cash price of $44.60 per Bbl for crude oil and the Henry Hub spot price of $5.71 per MMBtu for gas.

Other, net

	Year Ended December 31,
	2011			2010			2009
	(In millions)
Accretion of asset retirement obligations	$	92		$	92		$	91
Interest rate swaps — unrealized fair value changes		88			30			(66	)
Interest rate swaps — cash settlements		(77	)		(44	)		(40	)
Interest income		(21	)		(13	)		(8	)
Other		(92	)		(32	)		(60	)
Total	$	(10	)	$	33		$	(83	)

2011 vs. 2010 Other, net decreased primarily due to $88 million of excess insurance recoveries received in 2011 related to certain weather and operational claims. The remainder of the variance primarily relates to the net effect of interest rate swap cash settlements and unrealized fair value changes due to changes in the related interest rates upon which the instruments are based.

2010 vs. 2009 Other, net increased primarily due to the reversal of a $84 million loss contingency accrual in 2009. We had previously accrued $84 million for potential royalties on various deep water leases but due to a federal district court ruling we reversed the accrual in 2009. The remainder of the variance primarily relates to the net effect of interest rate swap cash settlements and unrealized fair value changes due to changes in the related interest rates upon which the instruments are based.

Income Taxes

The following table presents our total income tax expense (benefit) and a reconciliation of our effective income tax rate to the U.S. statutory income tax rate.

	Year Ended December 31,
	2011			2010			2009
Total income tax expense (benefit) (In millions)	$	2,156		$	1,235		$	(1,773	)
U.S. statutory income tax rate		35	%		35	%		(35	%)
Assumed repatriations		17	%		4	%		1	%
State income taxes		1	%		1	%		(2	%)
Taxation on Canadian operations		(2	%)		(1	%)		(1	%)
Other		(1	%)		(4	%)		(2	%)
Effective income tax expense (benefit) rate		50	%		35	%		(39	%)

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During 2011, 2010 and 2009, pursuant to the completed and planned divestitures of our International assets located outside North America, a portion of our foreign earnings were no longer deemed to be permanently reinvested. Accordingly, we recognized deferred income tax expense of $725 million, $144 million and $55 million during 2011, 2010 and 2009, respectively, related to assumed repatriations of earnings from our foreign subsidiaries.

Earnings From Discontinued Operations

	Year Ended December 31,
	2011		2010		2009
	(In millions)
Operating earnings	$	38	$	567	$	305
Gain on sale of oil and gas properties		2,552		1,818		17
Earnings before income taxes		2,590		2,385		322
Income tax expense		20		168		48
Earnings from discontinued operations	$	2,570	$	2,217	$	274

The earnings in each period were primarily driven by gains on the sales of our oil and gas assets in each period. The following table presents gains on our divestiture transactions by year. Also, in 2009 we reduced the carrying value of our oil and gas properties in Brazil by $109 million due to full cost ceiling limitation resulting from drilling results at the BM-BAR-3 offshore block.

	Year Ended December 31,
	2011				2010						2009
	Gross		After Taxes		Gross			After Taxes			Gross		After Taxes
	(In millions)
Brazil	$	2,548	$	2,548	$	—		$	—		$	—	$	—
Azerbaijan		—		—		1,543			1,524			—		—
China — Panyu		—		—		308			235			—		—
Other		4		4		(33	)		(27	)		17		17
Total	$	2,552	$	2,552	$	1,818		$	1,732		$	17	$	17

Capital Resources, Uses and Liquidity

Sources and Uses of Cash

The following table presents the major source and use categories of our cash and cash equivalents.

	Year Ended December 31,
	2011			2010			2009
	(In millions)
Operating cash flow — continuing operations	$	6,246		$	5,022		$	4,232
Debt activity, net		4,187			(1,782	)		1,435
Divestitures of property and equipment		3,380			7,002			34
Capital expenditures		(7,534	)		(6,476	)		(4,879	)
Common stock repurchases and dividends		(2,610	)		(1,449	)		(284	)
Short-term investment activity, net		(1,348	)		(124	)		7
Other		(56	)		86			82
Net increase in cash and cash equivalents	$	2,265		$	2,279		$	627
Cash and cash equivalents at end of year	$	5,555		$	3,290		$	1,011
Short-term investments at end of year	$	1,503		$	145		$	—

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Operating Cash Flow — Continuing Operations

Net cash provided by operating activities (“operating cash flow”) continued to be a significant source of capital and liquidity in 2011. Our operating cash flow increased 24 percent in spite of the $454 million of discretionary contributions made to our pension plans in 2011. The increase was largely due to higher current income taxes in 2010 associated with taxable gains on our U.S. Offshore divestitures and higher commodity prices and production, partially offset by lower realized gains from our commodity derivatives.

During 2011, 2010 and 2009 our operating cash flow funded 83%, 78% and 87% of our cash payments for capital expenditures. As needed, we supplement our operating cash flow and available cash by reducing short-term investment balances or accessing available credit under our credit facilities and commercial paper program. We may also issue long-term debt to supplement our operating cash flow while maintaining adequate liquidity under our credit facilities. Additionally, we may acquire short-term investments to maximize our income on available cash balances.

Debt Activity, Net

During 2011, we increased our commercial paper borrowings by $3.7 billion and received $0.5 billion from new debt issuances, net of debt maturities. Proceeds were primarily used to fund capital expenditures and common stock repurchases in excess of operating cash flow.

During 2010, we repaid $1.4 billion of commercial paper borrowings and redeemed our $350 million notes, primarily with proceeds received from our U.S. Offshore divestitures.

During 2009, we increased our commercial paper borrowings by $400 million and our term debt $1.0 billion, net of maturities. These proceeds were primarily used to fund capital expenditures in excess of our operating cash flow.

Divestitures of Property and Equipment

The following table presents the components of our divestiture transactions.

	Year Ended December 31,
	2011		2010		2009
	(In millions)
Brazil	$	3,251	$	—	$	—
Gulf of Mexico		—		4,059		—
Azerbaijan		—		1,925		—
China — Panyu and Exploration		—		592		—
Other		129		426		34
Total	$	3,380	$	7,002	$	34

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Capital Expenditures

The amounts in the table below reflect cash payments for capital expenditures, including cash paid for capital expenditures incurred in prior periods.

	Year Ended December 31,
	2011		2010		2009
	(In millions)
U.S. Onshore	$	5,128	$	3,689	$	2,413
Canada		1,571		1,826		1,064
North America Onshore		6,699		5,515		3,477
U.S. Offshore		—		376		845
Total oil and gas		6,699		5,891		4,322
Midstream		333		236		323
Other		502		349		234
Total continuing operations	$	7,534	$	6,476	$	4,879

Our capital expenditures consist of amounts related to our oil and gas exploration and development operations, our midstream operations and other corporate activities. The vast majority of our capital expenditures are for the acquisition, drilling and development of oil and gas properties, which totaled $6.7 billion, $5.9 billion and $4.3 billion in 2011, 2010 and 2009, respectively. The increases in exploration and development capital spending in 2011 and 2010 were primarily due to new venture acreage acquisitions, the 2010 $500 million Pike oil sands acquisition and increased drilling and development. With rising oil prices and proceeds from our offshore divestitures, we have increased our acreage positions and associated exploration and development activities to drive near-term growth of our onshore liquids production.

The increase in North American Onshore exploration and development capital spending in 2010 compared to 2009 was due to the $500 million Pike oil sands acquisition and increased drilling primarily to grow liquids production.

Capital expenditures for our midstream operations are primarily for the construction and expansion of natural gas processing plants, natural gas pipeline systems and oil pipelines. Our midstream capital expenditures are largely impacted by oil and gas drilling activities. Therefore, the increase in development drilling also increased midstream capital activities.

Capital expenditures related to other activities increased in 2011. This increase is largely driven by the construction of our new headquarters in Oklahoma City.

Common Stock Repurchases and Dividends

The following table summarizes our repurchases, including unsettled shares, and our common stock dividends (amounts and shares in millions).

	2011						2010						2009
	Amount		Shares		Per Share		Amount		Shares		Per Share		Amount		Shares	Per Share
Repurchases	$	2,299		30.9	$	74.49	$	1,201		18.3	$	65.58	$	N/A	N/A	$	N/A
Dividends	$	278		N/A	$	0.67	$	281		N/A	$	0.64	$	284	N/A	$	0.64

In connection with our offshore divestitures, we conducted a $3.5 billion share repurchase program that we completed in the fourth quarter of 2011. Under the program, we repurchased 49.2 million shares, representing 11% of our outstanding shares, at an average price of $71.18 per share.

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Short-Term Investment Activity, Net

During 2011, we had net short-term investment purchases totaling $1.3 billion. These purchases represent our investment of a portion of the International offshore divestiture proceeds into commercial paper, U.S. and Canadian Treasury securities and other marketable securities.

Liquidity

Historically, our primary sources of capital and liquidity have been our operating cash flow and cash on hand. Additionally, we maintain revolving lines of credit and a commercial paper program, which can be accessed as needed to supplement operating cash flow and cash balances. Other available sources of capital and liquidity include debt and equity securities that can be issued pursuant to our shelf registration statement filed with the SEC. We estimate the combination of these sources of capital will be adequate to fund future capital expenditures, debt repayments and other contractual commitments as discussed in this section.

Operating Cash Flow

Our operating cash flow is sensitive to many variables, the most volatile of which are the prices of the oil, gas and NGLs we produce. Due to higher liquids production and prices, our operating cash flow from continuing operations increased 24 percent to $6.2 billion in 2011. We expect operating cash flow to continue to be our primary source of liquidity.

Commodity Prices — Prices 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, which are difficult to predict, create volatility in prices and are beyond our control. We expect this volatility to continue throughout 2012.

To mitigate some of the risk inherent in prices, we have utilized various derivative financial instruments to set minimum and maximum prices on our 2012 production. The key terms to our oil, gas and NGL derivative financial instruments as of December 31, 2011 are presented in Note 2 to the financial statements under “Item 8. Financial Statements and Supplementary Data” of this report.

Commodity prices can also affect our operating cash flow through an indirect effect on operating expenses. Significant commodity price increases can lead to an increase in drilling and development activities. As a result, the demand and cost for people, services, equipment and materials may also increase, causing a negative impact on our cash flow. However, the inverse is also true during periods of depressed commodity prices.

Interest Rates — Our operating cash flow can also be impacted by interest rate fluctuations. As of December 31, 2011, we had total debt of $9.8 billion with an overall weighted average borrowing rate of 4.0 percent. We have derivative financial instruments in place that reduce our weighted-average interest rate to 3.7 percent.

Credit Losses — Our operating cash flow is also exposed to credit risk in a variety of ways. We are exposed to the credit risk of the customers who purchase our oil, gas and NGL production. We are also exposed to credit risk related to the collection of receivables from our joint-interest partners for their proportionate share of expenditures made on projects we operate. Additionally, we are exposed to the credit risk of counterparties to our derivative financial contracts. We utilize a variety of mechanisms to limit our exposure to the credit risks of our customers, partners and counterparties. Such mechanisms include, under certain conditions, requiring letters of credit, prepayment requirements or collateral posting requirements.

As 2011, 2010 and 2009 demonstrate, we have a history of investing more than 100% of our operating cash flow into capital development activities to grow our company and maximize value for our shareholders. Therefore, negative movements in any of the variables discussed above would not only impact our operating cash flow, but also would likely impact the amount of capital investment we could or would make.

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Credit Availability

We have a $2.65 billion syndicated, unsecured revolving line of credit (the “Senior Credit Facility”) that can be accessed to provide liquidity as needed. The maturity date for $2.19 billion of the Senior Credit Facility is April 7, 2013. The maturity date for the remaining $0.46 billion is April 7, 2012. All amounts outstanding will be due and payable on the respective maturity dates unless the maturity is extended. Prior to each April 7 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. The Senior Credit Facility includes a revolving Canadian subfacility in a maximum amount of U.S. $0.5 billion.

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 February 9, 2012, we had $1.8 billion of available capacity under our syndicated, unsecured Senior Credit Facility.

The Senior Credit Facility contains only one material financial covenant. This covenant requires us to maintain a ratio of total funded debt to total capitalization, as defined in the credit agreement, of no more than 65 percent. The credit agreement defines total funded debt as funds received through the issuance of debt securities such as debentures, bonds, notes payable, credit facility borrowings and short-term commercial paper borrowings. In addition, total funded debt includes all obligations with respect to payments received in consideration for oil, gas and NGL production yet to be acquired or produced at the time of payment. Funded debt excludes our outstanding letters of credit and trade payables. The credit agreement defines total capitalization as the sum of funded debt and stockholders’ equity adjusted for noncash financial writedowns, such as full cost ceiling impairments. As of December 31, 2011, we were in compliance with this covenant. Our debt-to-capitalization ratio at December 31, 2011, as calculated pursuant to the terms of the agreement, was 22.8 percent.

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 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 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. In 2011, we increased our commercial paper program from $2.2 billion to $5.0 billion. Commercial paper debt generally has a maturity of between one and 90 days, although it can have a maturity of up to 365 days, and bears interest at rates agreed to at the time of the borrowing. The interest rate is generally based on a standard index such as the Federal Funds Rate, LIBOR, or the money market rate as found in the commercial paper market. As of February 9, 2012, we had $3.1 billion of borrowings under our commercial paper program.

Although we ended 2011 with approximately $7.1 billion of cash and short-term investments, the vast majority of this amount consists of proceeds from our International offshore divestitures that are held by certain of our foreign subsidiaries. We do not currently expect to repatriate such amounts to the U.S. If we were to repatriate a portion or all of the cash and short-term investments held by these foreign subsidiaries, we would be required to accrue and pay current income taxes in accordance with current U.S. tax law. With these proceeds remaining outside of the U.S., we expect to continue using commercial paper or credit facility borrowings in the U.S. to supplement our U.S. based operating cash flow. We do not expect near-term increases in such borrowings will have a material effect on our overall liquidity or financial condition.

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Debt Ratings

We receive debt ratings from the major ratings agencies in the U.S. In determining our debt ratings, the agencies consider a number of qualitative and quantitative items including, but not limited to, commodity pricing levels, our liquidity, asset quality, reserve mix, debt levels, cost structure, planned asset sales, near-term and long-term production growth opportunities and capital allocation challenges. Our current debt ratings are BBB+ with a stable outlook by both Fitch and Standard & Poor’s, and Baa1 with a stable outlook by Moody’s.

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 from LIBOR plus 35 basis points to a new rate of LIBOR plus 45 basis points. A ratings downgrade could also adversely impact our ability to economically access debt markets in the future. As of December 31, 2011, we were not aware of any potential ratings downgrades being contemplated by the rating agencies.

Capital Expenditures

Our 2012 capital expenditures are expected to range from $6.2 billion to $6.8 billion, including $5.5 billion to $5.9 billion for our oil and gas operations. To a certain degree, the ultimate timing of these capital expenditures is within our control. Therefore, if commodity prices fluctuate from our current estimates, we could choose to defer a portion of these planned 2012 capital expenditures until later periods or accelerate capital expenditures planned for periods beyond 2012 to achieve the desired balance between sources and uses of liquidity. Based upon current price expectations for 2012, our existing commodity hedging contracts, available cash balances and credit availability, we anticipate having adequate capital resources to fund our 2012 capital expenditures.

Additionally, our financial and operational flexibility will be further enhanced by the transaction that we announced in early 2012 with Sinopec International Petroleum Exploration & Production Corporation, which we expect to close in the first quarter of 2012. Pursuant to the agreement, Sinopec will pay $2.5 billion, including a $900 million payment at closing and $1.6 billion toward our share of future drilling costs, and will receive a 33.3% interest in five of our new venture plays discussed in “Items 1 and 2. Business and Properties” of this report.

The $900 million cash payment at closing will recoup more than 100% of our costs incurred up to the closing date. Additionally, the proceeds from this transaction will significantly reduce our future capital commitments. The drilling carry will fund 70 percent of our capital requirements related to these properties, which results in Sinopec paying 80 percent of the overall development costs during the carry period. This will allow us to accelerate the de-risking and commercialization of the five plays without diverting capital from our core development projects. We expect the entire $1.6 billion carry will be realized by the end of 2014.

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Contractual Obligations

A summary of our contractual obligations as of December 31, 2011, is provided in the following table.

	Payments Due by Period
	Total		Less Than 1 Year		1-3 Years		3-5 Years		More Than 5 Years
	(In millions)
Debt(1)	$	9,786	$	3,811	$	500	$	500	$	4,975
Interest expense(2)		6,611		374		734		692		4,811
Purchase obligations(3)		8,454		900		1,810		1,829		3,915
Drilling and facility obligations(4)		1,475		919		556		—		—
Operational agreements(5)		2,136		306		585		459		786
Asset retirement obligations(6)		1,563		67		106		113		1,277
Lease obligations(7)		473		63		103		87		220
Other(8)		222		35		136		18		33
Total North America	$	30,720	$	6,475	$	4,530	$	3,698	$	16,017

(1) Debt amounts represent scheduled maturities of our debt obligations at December 31, 2011, excluding $6 million of net discounts included in the carrying value of debt.

(2) Interest expense represents the scheduled cash payments on our long-term fixed-rate debt.

(3) Purchase obligation amounts represent contractual commitments to purchase condensate at market prices for use at our heavy oil projects in Canada. We have entered into these agreements because the condensate is an integral part of the heavy oil production process and any disruption in our ability to obtain condensate could negatively affect our ability to produce and transport heavy oil at these locations. Our total obligation related to condensate purchases expires in 2021. The value of the obligation in the table above is based on the contractual volumes and our internal estimate of future condensate market prices.

(4) Drilling and facility obligations represent contractual agreements with third-party service providers to procure drilling rigs and other related services for developmental and exploratory drilling and facilities construction.

(5) Operational agreements represent commitments to transport or process certain volumes of oil, gas and NGLs for a fixed fee. We have entered into these agreements to aid the movement of our production to market.

(6) Asset retirement obligations represent estimated discounted costs for future dismantlement, abandonment and rehabilitation costs. These obligations are recorded as liabilities on our December 31, 2011 balance sheet.

(7) Lease obligations consist primarily of non-cancelable leases for office space and equipment used in our daily operations.

(8) These amounts include $165 million related to uncertain tax positions. Future contributions to our qualified pension plans have not been included in the table above. During 2011, we made $454 million of contributions to our pension plans. Consequently, we expect required pension plan contributions will be insignificant for the foreseeable future.

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Contingencies and Legal Matters

For a detailed discussion of contingencies and legal matters, see Note 18 to the financial statements included in “Item 8. Financial Statements and Supplementary Data” of this report.

Critical Accounting Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires us to make estimates, judgments 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. We consider the following to be our most critical accounting estimates that involve judgment and have reviewed these critical accounting estimates with the Audit Committee of our Board of Directors.

Full Cost Method of Accounting and Proved Reserves

Our estimates of proved reserves are a major component of the depletion and full cost ceiling calculations. Additionally, our proved reserves represent the element of these calculations that require 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, 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. Our engineers prepare our reserve estimates. We then subject certain of our reserve estimates to audits performed by outside petroleum consultants. In 2011, 95% of our reserves were subjected to such audits.

The passage of time provides more qualitative information regarding estimates of reserves, when revisions are made to prior estimates to reflect updated information. In the past five years, annual performance revisions to our reserve estimates, which have been both increases and decreases in individual years, have averaged less than 2 percent of the previous year’s estimate. However, there can be no assurance that more significant revisions will not be necessary in the future. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions.

While the quantities of proved reserves require substantial judgment, the associated prices of oil, 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. Applicable rules require future net revenues to be calculated using prices that represent the average of the first-day-of-the-month price for the 12-month period prior to the end of each quarterly period. Such rules also dictate that a 10 percent discount factor be used. Therefore, the discounted future net revenues associated with the estimated proved reserves are not based on our assessment of future prices or costs or our enterprise risk.

Because the ceiling calculation dictates the use of prices that are not representative of future prices and requires a 10 percent discount factor, the resulting value is not indicative of the true fair value of the reserves. Oil and gas prices have historically been cyclical and, for any particular 12-month period, can be either higher or lower than our long-term price forecast, which is a more appropriate input for estimating 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.

Because of the volatile nature of oil and gas prices, it is not possible to predict the timing or magnitude of full cost writedowns. In addition, due to the inter-relationship of the various judgments made to estimate proved

42

reserves, it is impractical to provide quantitative analyses of the effects of potential changes in these estimates. However, decreases in estimates of proved reserves would generally increase our depletion rate and, thus, our depletion expense. Decreases in our proved reserves may also increase the likelihood of recognizing a full cost ceiling writedown.

Derivative Financial Instruments

We periodically enter into derivative financial instruments with respect to a portion of our oil, gas and NGL production that hedge the future prices received. Our commodity derivative financial instruments include financial price swaps, basis swaps, costless price collars and call options.

The estimates of the fair values of our derivative instruments require substantial judgment. We estimate the fair values of our commodity derivative financial instruments primarily by using internal discounted cash flow calculations. The most significant variable to our cash flow calculations is our estimate of future commodity prices. We base our estimate of future prices upon published forward commodity price curves such as the Inside FERC Henry Hub forward curve for gas instruments and the NYMEX West Texas Intermediate forward curve for oil instruments. Another key input to our cash flow calculations is our estimate of volatility for these forward curves, which we base primarily upon implied volatility. The resulting estimated future cash inflows or outflows over the lives of the contracts are discounted primarily using U.S. Treasury bill rates. These pricing and discounting variables are sensitive to the period of the contract and market volatility as well as changes in forward prices and regional price differentials.

We periodically enter into interest rate swaps to manage our exposure to interest rate volatility. Under the terms of our interest-rate swaps, we receive a fixed rate and pay a variable rate on a total notional amount.

We estimate the fair values of our interest rate swap financial instruments primarily by using internal discounted cash flow calculations based upon forward interest-rate yields. The most significant variable to our cash flow calculations is our estimate of future interest rate yields. We base our estimate of future yields upon our own internal model that utilizes forward curves such as the LIBOR or the Federal Funds Rate provided by third parties. The resulting estimated future cash inflows or outflows over the lives of the contracts are discounted using the LIBOR and money market futures rates. These yield and discounting variables are sensitive to the period of the contract and market volatility as well as changes in forward interest rate yields.

We periodically validate our valuation techniques by comparing our internally generated fair value estimates with those obtained from contract counterparties or brokers.

Counterparty credit risk has not had a significant effect on our cash flow calculations and derivative valuations. This is primarily the result of two factors. First, we have mitigated our exposure to any single counterparty by contracting with numerous counterparties. Our commodity derivative contracts are held with fourteen separate counterparties, and our interest rate derivative contracts are held with five separate counterparties. Second, our derivative contracts generally require cash collateral to be posted if either our or the counterparty’s credit rating falls below certain credit rating levels. The mark-to-market exposure threshold for collateral posting decreases as the debt rating falls further below such credit levels. Thresholds generally range from zero to $55 million for the majority of our contracts. As of December 31, 2011, the credit ratings of all our counterparties were within our established guidelines.

Because we have chosen not to qualify our derivatives for hedge accounting treatment, changes in the fair values of derivatives can have a significant impact on our reported results of operations. Generally, changes in derivative fair values will not impact our liquidity or capital resources.

Settlements of derivative instruments, regardless of whether they qualify for hedge accounting, do have an impact on our liquidity and results of operations. Generally, if actual market prices are higher than the price of

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the derivative instruments, 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 can 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” of this report.

Goodwill

The annual impairment test, which we conduct as of October 31 each year, includes an assessment of qualitative factors and requires us to estimate the fair values of our own assets and liabilities. Because quoted market prices are not available for our reporting units, we must estimate the fair values to conduct the goodwill impairment test. The most significant judgments involved in estimating the fair values of our reporting units relate to the valuation of our property and equipment. We develop estimated fair values of our property and equipment by performing various quantitative analyses using information related to comparable companies, comparable transactions and premiums paid.

In our comparable companies analysis, we review the public stock market trading multiples for selected publicly traded independent exploration and production companies with financial and operating characteristics that are comparable to our respective reporting units. Such characteristics are market capitalization, location of proved reserves and the characterization of the operations. In our comparable transactions analysis, we review certain acquisition multiples for selected independent exploration and production company transactions and oil and gas asset packages announced recently. In our 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. We then review the premiums paid to the price of the target one day and one month prior to the announcement of the transaction. We use this information to determine the median premiums paid.

We then use the comparable company multiples, comparable transaction multiples, transaction premiums and other data to develop valuation estimates of our property and equipment. We also use market and other data to develop valuation estimates of the other assets and liabilities included in our reporting units. At October 31, 2011, the date of our last impairment test, the fair values of our U.S. and Canadian reporting units substantially exceeded their related carrying values.

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.

Income Taxes

The amount of income taxes recorded requires interpretations of complex rules and regulations of federal, state, provincial and foreign tax jurisdictions. We recognize current tax expense based on estimated taxable income for the current period and the applicable statutory tax rates. We routinely assess potential uncertain tax positions and, if required, estimate and establish accruals for such amounts. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and other tax carryforwards. We routinely assess our deferred tax assets and reduce such assets by a valuation allowance if we deem it is more likely than not that

44

some portion or all of the deferred tax assets will not be realized. We also assess factors relative to whether our foreign earnings are considered permanently reinvested. Changes in any of these factors could require recognition of additional deferred, or even current, U.S. income tax expense. The accruals for deferred tax assets and liabilities are subject to a significant amount of judgment by management and are reviewed and adjusted routinely based on changes in facts and circumstances. Material changes to our tax accruals may occur in the future based on the progress of ongoing audits, changes in legislation or resolution of pending matters.

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 our risk of loss arising from adverse changes in oil, gas and NGL prices, interest rates and foreign currency exchange rates. The following 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 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 gas and NGL production. Pricing for oil, gas and NGL production has been volatile and unpredictable for several years as discussed in “Item 1A. Risk Factors” of this report. Consequently, we periodically enter into financial hedging activities with respect to a portion of our production through various financial transactions that hedge future prices received. The key terms to all our oil, gas and NGL derivative financial instruments as of December 31, 2011 are presented in Note 2 to the financial statements under “Item 8. Financial Statements and Supplementary Data” of this report.

The fair values of our commodity derivatives are largely determined by estimates of the forward curves of the relevant price indices. At December 31, 2011, a 10 percent increase and 10 percent decrease in the forward curves associated with our commodity derivative instruments would have changed our net asset positions by the following amounts:

	10% Increase			10% Decrease
	(In millions)
Gain/(loss):
Gas derivatives	$	(93	)	$	93
Oil derivatives	$	(224	)	$	215

Interest Rate Risk

At December 31, 2011, we had debt outstanding of $9.8 billion. Of this amount, $6.1 billion bears fixed interest rates averaging 6.3 percent. Additionally, we had $3.7 billion of outstanding commercial paper, bearing interest at floating rates which averaged 0.45 percent. As of December 31, 2011, we had open interest rate swap positions that are presented in Note 2 to the financial statements under “Item 8. Financial Statements and Supplementary Data” of this report.

The fair values of our interest rate swaps are largely determined by estimates of the forward curves of the Federal Funds rate and LIBOR. A 10 percent change in these forward curves would not materially impact our balance sheet at December 31, 2011.

45

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 percent unfavorable change in the Canadian-to-U.S. dollar exchange rate would not materially impact our December 31, 2011 balance sheet.

Our non-Canadian foreign subsidiaries have a U.S. dollar functional currency. However, one of these foreign subsidiaries holds Canadian-dollar cash and engages in short-term intercompany loans with Canadian subsidiaries that are sometimes based in Canadian dollars. Additionally, at December 31, 2011, we held foreign currency exchange forward contracts to hedge exposures to fluctuations in exchange rates on the Canadian-dollar cash. The increase or decrease in the value of the forward contracts is offset by the increase or decrease to the U.S. dollar equivalent of the Canadian-dollar cash. The value of the intercompany loans increases or decreases from the remeasurement of the loans into the U.S. dollar functional currency. Based on the amount of the intercompany loans as of December 31, 2011, a 10 percent change in the foreign currency exchange rates would not materially impact our balance sheet.

46

Item 8. Financial Statements and Supplementary Data

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

AND CONSOLIDATED FINANCIAL STATEMENT SCHEDULES

Report of Independent Registered Public Accounting Firm	48
Consolidated Financial Statements
Consolidated Comprehensive Statements of Earnings	49
Consolidated Statements of Cash Flows	50
Consolidated Balance Sheets	51
Consolidated Statements of Stockholders’ Equity	52
Notes to Consolidated Financial Statements	53

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.

47

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, 2011 and 2010, and the related consolidated comprehensive statements of earnings, cash flows and stockholders’ equity for each of the years in the three-year period ended December 31, 2011. We also have audited Devon Energy Corporation’s internal control over financial reporting as of December 31, 2011, 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 these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Annual Report contained in “Item 9A. Controls and Procedures” of Devon Energy Corporation’s Annual Report on Form 10-K. Our responsibility is to express an opinion on these consolidated financial statements and an opinion on the Company’s internal control over financial reporting 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 audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the consolidated financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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, 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, 2011 and 2010, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2011, in conformity with U.S. generally accepted accounting principles. Also in our opinion, Devon Energy Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

KPMG LLP

Oklahoma City, Oklahoma

February 23, 2012

48

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED COMPREHENSIVE STATEMENTS OF EARNINGS

	Year Ended December 31,
	2011			2010			2009
	(In millions, except per share amounts)
Revenues:
Oil, gas and NGL sales	$	8,315		$	7,262		$	6,097
Oil, gas and NGL derivatives		881			811			384
Marketing and midstream revenues		2,258			1,867			1,534
Total revenues		11,454			9,940			8,015
Expenses and other, net:
Lease operating expenses		1,851			1,689			1,670
Marketing and midstream operating costs and expenses		1,716			1,357			1,022
Depreciation, depletion and amortization		2,248			1,930			2,108
General and administrative expenses		585			563			648
Taxes other than income taxes		424			380			314
Interest expense		352			363			349
Restructuring costs		(2	)		57			105
Reduction of carrying value of oil and gas properties		—			—			6,408
Other, net		(10	)		33			(83	)
Total expenses and other, net		7,164			6,372			12,541
Earnings (loss) from continuing operations before income taxes		4,290			3,568			(4,526	)
Current income tax (benefit) expense		(143	)		516			241
Deferred income tax expense (benefit)		2,299			719			(2,014	)
Earnings (loss) from continuing operations		2,134			2,333			(2,753	)
Earnings from discontinued operations, net of income tax expense		2,570			2,217			274
Net earnings (loss)	$	4,704		$	4,550		$	(2,479	)
Basic net earnings per share:
Basic earnings (loss) from continuing operations per share	$	5.12		$	5.31		$	(6.20	)
Basic earnings from discontinued operations per share		6.17			5.04			0.62
Basic net earnings (loss) per share	$	11.29		$	10.35		$	(5.58	)
Diluted net earnings per share:
Diluted earnings (loss) from continuing operations per share	$	5.10		$	5.29		$	(6.20	)
Diluted earnings from discontinued operations per share		6.15			5.02			0.62
Diluted net earnings (loss) per share	$	11.25		$	10.31		$	(5.58	)
Comprehensive earnings (loss):
Net earnings (loss)	$	4,704		$	4,550		$	(2,479	)
Other comprehensive income, net of tax:
Foreign currency translation adjustments		(191	)		377			931
Pension and postretirement plans		6			(2	)		71
Other comprehensive (loss) earnings, net of tax		(185	)		375			1,002
Comprehensive earnings (loss)	$	4,519		$	4,925		$	(1,477	)

See accompanying notes to consolidated financial statements.

49

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2011			2010			2009
	(In millions)
Cash flows from operating activities:
Net earnings (loss)	$	4,704		$	4,550		$	(2,479	)
Earnings from discontinued operations, net of tax		(2,570	)		(2,217	)		(274	)
Adjustments to reconcile earnings (loss) from continuing operations to net cash from operating activities:
Depreciation, depletion and amortization		2,248			1,930			2,108
Deferred income tax expense (benefit)		2,299			719			(2,014	)
Unrealized change in fair value of financial instruments		(401	)		107			55
Reduction of carrying value of oil and gas properties		—			—			6,408
Other noncash charges		241			215			288
Net decrease (increase) in working capital		185			(273	)		149
Decrease (increase) in long-term other assets		33			32			(6	)
Decrease in long-term other liabilities		(493	)		(41	)		(3	)
Cash from operating activities — continuing operations		6,246			5,022			4,232
Cash from operating activities — discontinued operations		(22	)		456			505
Net cash from operating activities		6,224			5,478			4,737
Cash flows from investing activities:
Capital expenditures		(7,534	)		(6,476	)		(4,879	)
Proceeds from property and equipment divestitures		129			4,310			34
Purchases of short-term investments		(6,691	)		(145	)		—
Redemptions of short-term investments		5,333			—			—
Redemptions of long-term investments		10			21			7
Other		(39	)		(19	)		(17	)
Cash from investing activities — continuing operations		(8,792	)		(2,309	)		(4,855	)
Cash from investing activities — discontinued operations		3,146			2,197			(499	)
Net cash from investing activities		(5,646	)		(112	)		(5,354	)
Cash flows from financing activities:
Net commercial paper borrowings (repayments)		3,726			(1,432	)		426
Proceeds from borrowings of long-term debt, net of issuance costs		2,221			—			1,187
Debt repayments		(1,760	)		(350	)		(178	)
Proceeds from stock option exercises		101			111			42
Repurchases of common stock		(2,332	)		(1,168	)		—
Dividends paid on common stock		(278	)		(281	)		(284	)
Excess tax benefits related to share-based compensation		13			16			8
Net cash from financing activities		1,691			(3,104	)		1,201
Effect of exchange rate changes on cash		(4	)		17			43
Net increase in cash and cash equivalents		2,265			2,279			627
Cash and cash equivalents at beginning of period (including cash related to assets previously held for sale in 2010 and 2009)		3,290			1,011			384
Cash and cash equivalents at end of period (including cash related to assets previously held for sale in 2010 and 2009)	$	5,555		$	3,290		$	1,011

See accompanying notes to consolidated financial statements.

50

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	December 31,
	2011			2010
	(In millions, except share data)
ASSETS
Current assets:
Cash and cash equivalents	$	5,555		$	2,866
Short-term investments		1,503			145
Accounts receivable		1,379			1,202
Current assets held for sale		21			563
Other current assets		847			779
Total current assets		9,305			5,555
Property and equipment, at cost:
Oil and gas, based on full cost accounting:
Subject to amortization		61,696			56,012
Not subject to amortization		3,982			3,434
Total oil and gas		65,678			59,446
Other		5,098			4,429
Total property and equipment, at cost		70,776			63,875
Less accumulated depreciation, depletion and amortization		(46,002	)		(44,223	)
Property and equipment, net		24,774			19,652
Goodwill		6,013			6,080
Long-term assets held for sale		132			859
Other long-term assets		893			781
Total assets	$	41,117		$	32,927
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	1,471		$	1,411
Revenues and royalties payable		678			538
Short-term debt		3,811			1,811
Current liabilities associated with assets held for sale		48			305
Other current liabilities		730			518
Total current liabilities		6,738			4,583
Long-term debt		5,969			3,819
Asset retirement obligations		1,496			1,423
Liabilities associated with assets held for sale		—			26
Other long-term liabilities		721			1,067
Deferred income taxes		4,763			2,756
Stockholders’ equity:
Common stock, $0.10 par value. Authorized 1.0 billion shares; issued 404.1 million and 431.9 million shares in 2011 and 2010, respectively		40			43
Additional paid-in capital		3,507			5,601
Retained earnings		16,308			11,882
Accumulated other comprehensive earnings		1,575			1,760
Treasury stock, at cost. 0.4 million shares in 2010		—			(33	)
Total stockholders’ equity		21,430			19,253
Commitments and contingencies (Note 18)
Total liabilities and stockholders’ equity	$	41,117		$	32,927

See accompanying notes to consolidated financial statements.

51

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

	Common Stock						Additional Paid-In Capital			Retained Earnings			Accumulated Other Comprehensive Earnings			Treasury Stock			Total Stockholders’ Equity
	Shares			Amount
Balance as of December 31, 2008		444		$	44		$	6,257		$	10,376		$	383		$	—		$	17,060
Net earnings (loss)		—			—			—			(2,479	)		—			—			(2,479	)
Other comprehensive earnings (loss), net of tax		—			—			—			—			1,002			—			1,002
Stock option exercises		1			1			47			—			—			(5	)		43
Restricted stock grants, net of cancellations		2			—			—			—			—			—			—
Common stock repurchased		—			—			—			—			—			(40	)		(40	)
Common stock retired		—			—			(45	)		—			—			45			—
Common stock dividends		—			—			—			(284	)		—			—			(284	)
Share-based compensation		—			—			260			—			—			—			260
Share-based compensation tax benefits		—			—			8			—			—			—			8
Balance as of December 31, 2009		447			45			6,527			7,613			1,385			—			15,570
Net earnings (loss)		—			—			—			4,550			—			—			4,550
Other comprehensive earnings (loss), net of tax		—			—			—			—			375			—			375
Stock option exercises		2			—			117			—			—			(6	)		111
Restricted stock grants, net of cancellations		2			—			—			—			—			—			—
Common stock repurchased		—			—			—			—			—			(1,246	)		(1,246	)
Common stock retired		(19	)		(2	)		(1,217	)		—			—			1,219			—
Common stock dividends		—			—			—			(281	)		—			—			(281	)
Share-based compensation		—			—			158			—			—			—			158
Share-based compensation tax benefits		—			—			16			—			—			—			16
Balance as of December 31, 2010		432			43			5,601			11,882			1,760			(33	)		19,253
Net earnings (loss)		—			—			—			4,704			—			—			4,704
Other comprehensive earnings (loss), net of tax		—			—			—			—			(185	)		—			(185	)
Stock option exercises		2			—			112			—			—			(11	)		101
Restricted stock grants, net of cancellations		1			—			—			—			—			—			—
Common stock repurchased		—			—			—			—			—			(2,337	)		(2,337	)
Common stock retired		(31	)		(3	)		(2,378	)		—			—			2,381			—
Common stock dividends		—			—			—			(278	)		—			—			(278	)
Share-based compensation		—			—			159			—			—			—			159
Share-based compensation tax benefits		—			—			13			—			—			—			13
Balance as of December 31, 2011		404		$	40		$	3,507		$	16,308		$	1,575		$	—		$	21,430

See accompanying notes to consolidated financial statements.

52

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

Devon Energy Corporation (“Devon”) is a leading independent energy company engaged primarily in the exploration, development and production of oil and natural gas. Devon’s operations are concentrated in various North American onshore areas in the U.S. and Canada. Devon also owns natural gas pipelines, plants and treatment facilities in many of its producing areas, making it one of North America’s larger processors of natural gas.

Accounting policies used by Devon and its subsidiaries conform to accounting principles generally accepted in the United States of America and reflect industry practices. The more significant of such policies are discussed below.

Principles of Consolidation

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

Use of Estimates

The preparation of financial statements 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 the following:

• proved reserves and related present value of future net revenues;

• the carrying value of oil and gas properties;

• derivative financial instruments;

• the fair value of reporting units and related assessment of goodwill for impairment;

• income taxes;

• asset retirement obligations;

• obligations related to employee pension and postretirement benefits; and

• legal and environmental risks and exposures.

Revenue Recognition and Gas Balancing

Oil, gas and NGL sales are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectability of the revenue is probable. Delivery occurs and title is transferred when production has been delivered to a pipeline, railcar or truck. Cash received relating to future production is deferred and recognized when all revenue recognition criteria are met. Taxes assessed by governmental authorities on oil, gas and NGL sales are presented separately from such revenues in the accompanying comprehensive statements of earnings.

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 differences

53

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

create imbalances that are recognized as a liability only when the estimated remaining reserves will not be sufficient to enable the underproduced owner to recoup its entitled share through production. 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. 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.

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, delivery or performance has occurred, title has transferred and collectability of the revenue is probable. Revenues and expenses attributable to oil, gas and NGL purchases, transportation and processing contracts are reported on a gross basis when Devon takes title to the products and has risks and rewards of ownership.

During 2011, 2010 and 2009, no purchaser accounted for more than 10 percent of Devon’s revenues from continuing operations.

Derivative Financial Instruments

Devon is exposed to certain risks relating to its ongoing business operations, including risks related to commodity prices, interest rates and Canadian to U.S. dollar exchange rates. As discussed more fully below, Devon uses derivative instruments primarily to manage commodity price risk and interest rate risk. Devon does not hold or issue derivative financial instruments for speculative trading purposes.

Devon periodically enters into derivative financial instruments with respect to a portion of its oil, gas and NGL production that hedge the future prices received. These instruments are used to manage the inherent uncertainty of future revenues due to commodity price volatility. Devon’s derivative financial instruments include financial price swaps, basis swaps, costless price collars and call options. Under the terms of the price swaps, Devon receives a fixed price for its production and pays a variable market price to the contract counterparty. For the basis swaps, Devon receives a fixed differential between two regional gas index prices and pays a variable differential on the same two index prices to the contract counterparty. The price collars set a floor and ceiling price for the hedged production. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, Devon will cash-settle the difference with the counterparty to the collars. The call options give counterparties the right to purchase production at a predetermined price.

Devon periodically enters into interest rate swaps to manage its exposure to interest rate volatility. Devon’s interest rate swaps include contracts in which Devon receives a fixed rate and pays a variable rate on a total notional amount.

All derivative financial instruments are recognized at their current fair value as either assets or liabilities in the balance sheet. Changes in the fair value of these derivative financial instruments are recorded in earnings unless specific hedge accounting criteria are met. For derivative financial instruments held during the three-year period ended December 31, 2011, Devon chose not to meet the necessary criteria to qualify its derivative financial instruments for hedge accounting treatment. Cash settlements with counterparties on Devon’s derivative financial instruments are also recorded in earnings.

By using derivative financial instruments to hedge exposures to changes in commodity prices and interest rates, Devon is exposed to credit 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 a number of counterparties

54

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

whom 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. Additionally, Devon’s derivative contracts generally require cash collateral to be posted if either its or the counterparty’s credit rating falls below certain credit rating levels. The mark-to-market exposure threshold, above which collateral must be posted, decreases as the debt rating falls further below such credit levels. Thresholds generally range from zero to $55 million for the majority of Devon’s contracts. As of December 31, 2011, the credit ratings of all Devon’s counterparties were within established guidelines.

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.

Share Based Compensation

Devon grants stock options, restricted stock awards and other types of share-based awards to members of its Board of Directors and selected employees. All such awards are measured at fair value on the date of grant and are recognized as a component of general and administrative expenses in the accompanying comprehensive statements of earnings over the applicable requisite service periods. As a result of Devon’s strategic repositioning announced in 2009, certain share based awards were accelerated and recognized as a component of restructuring expense in the accompanying comprehensive statements of earnings.

Generally, Devon uses new shares from approved incentive programs to grant share-based awards and to issue shares upon stock option exercises. Shares repurchased under approved programs are available to be issued as part of Devon’s share based awards. However, Devon has historically cancelled these shares upon repurchase.

Income Taxes

Devon is subject to current income taxes assessed by the federal and various state jurisdictions in the U.S. and by other foreign jurisdictions. In addition, Devon accounts for deferred income taxes related to these jurisdictions using the asset and liability method. Under this method, 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. Deferred tax assets are also recognized for the future tax benefits attributable to the expected utilization of existing tax net operating loss carryforwards and other types of carryforwards. If the future utilization of some portion of carryforwards is determined to be unlikely, a valuation allowance is provided to reduce the recorded tax benefits from such assets. 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.

Devon does not recognize U.S. deferred income taxes on the unremitted earnings of its foreign subsidiaries that are deemed to be permanently reinvested. When such earnings are no longer deemed permanently reinvested, Devon recognizes the appropriate deferred, or even current, income tax liabilities.

Devon recognizes the financial statement effects of tax positions when it is more likely than not, based on the technical merits, that the position will be sustained upon examination by a taxing authority. Recognized tax

55

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

positions are initially and subsequently measured as the largest amount of tax benefit that is more likely than not of being realized upon ultimate settlement with a taxing authority. Liabilities for unrecognized tax benefits related to such tax positions are included in other long-term liabilities unless the tax position is expected to be settled within the upcoming year, in which case the liabilities are included in other current liabilities. Interest and penalties related to unrecognized tax benefits are included in current income tax expense.

Net Earnings (Loss) Per Common Share

Devon’s basic earnings per share amounts have been computed based on the average number of shares of common stock outstanding for the period. Basic earnings per share includes the effect of participating securities, which primarily consist of Devon’s outstanding restricted stock awards. Diluted earnings per share is calculated using the treasury stock method to reflect the assumed issuance of common shares for all potentially dilutive securities. Such securities primarily consist of outstanding stock options.

Cash and Cash Equivalents

Devon considers all highly liquid investments with original contractual maturities of three months or less to be cash equivalents.

Investments

Devon periodically invests excess cash in U.S. and Canadian Treasury securities and other marketable securities. During 2011, Devon invested a portion of the International offshore divestiture proceeds into such securities, causing short-term investments to increase.

Devon considers securities with original contractual maturities in excess of three months, but less than one year to be short-term investments. Investments with contractual maturities in excess of one year are classified as long-term, unless such investments are classified as trading or available-for-sale.

Devon reports its investments and other marketable securities at fair value, except for debt securities in which management has the ability and intent to hold until maturity. Such debt securities totaled $84 million and $94 million at December 31, 2011 and 2010, respectively and are included in other long-term assets in the accompanying balance sheet. Devon has the ability to hold the securities until maturity and does not believe the values of its long-term securities are impaired.

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 that 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. 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.

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 estimated after-tax future net revenues, discounted at 10 percent per annum, from proved oil, gas and NGL reserves plus the cost of properties

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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 tested quarterly and imposed separately on a country-by-country basis.

Future net revenues are calculated using prices that represent the average of the first-day-of-the-month price for the 12-month period prior to the end of the period. Prices are held constant indefinitely and are not changed except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including derivative contracts in place that qualify for hedge accounting treatment. None of Devon’s derivative contracts held during the three-year period ended December 31, 2011, qualified for hedge accounting treatment.

Any excess of the net book value, less related deferred taxes, over the ceiling is written off as an expense. An expense recorded in one period may not be reversed in a subsequent period even though higher commodity prices may have increased the ceiling applicable to the subsequent period.

Capitalized costs are depleted by an equivalent unit-of-production method, converting gas to oil at the ratio of six thousand cubic feet of 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.

Costs associated with unproved properties are excluded from the depletion calculation 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 into the depletion calculation over holding periods ranging from three to six years.

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.

Depreciation of midstream pipelines are provided on a unit-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 ranging from three to 39 years. Interest costs incurred and attributable to major midstream and corporate construction projects are also capitalized.

Devon recognizes liabilities for retirement obligations associated with tangible long-lived assets, such as producing well sites and midstream pipelines and processing plants when there is a legal obligation associated with the retirement of such assets and the amount can be reasonably estimated. The initial measurement of an asset retirement obligation is recorded as a liability at its fair value, with an offsetting asset retirement cost recorded as an increase to the associated property and equipment on the consolidated balance sheet. When the assumptions used to estimate a recorded asset retirement obligation change, a revision is recorded to both the asset retirement obligation and the asset retirement cost. The asset retirement cost is depreciated using a systematic and rational method similar to that used for the associated property and equipment.

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. Such test includes an assessment of qualitative and quantitative factors. 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.

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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 2011, 2010 and 2009. Based on these assessments, no impairment of goodwill was required.

The table below provides a summary of Devon’s goodwill, by assigned reporting unit. The decrease in Devon’s goodwill from 2010 to 2011 was due to changes in the exchange rate between the U.S. dollar and the Canadian dollar.

	December 31,
	2011		2010
	(In millions)
U.S.	$	3,046	$	3,046
Canada		2,967		3,034
Total	$	6,013	$	6,080

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. Liabilities for environmental remediation or restoration claims are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. Expenditures related to such environmental matters are expensed or capitalized in accordance with Devon’s accounting policy for property and equipment.

Fair Value Measurements

Certain of Devon’s assets and liabilities are measured at fair value at each reporting date. Fair value represents the price that would be received to sell the asset or paid to transfer the liability in an orderly transaction between market participants. This price is commonly referred to as the “exit price.” Fair value measurements are classified according to a hierarchy that prioritizes the inputs underlying the valuation techniques. This hierarchy consists of three broad levels:

• Level 1 – Inputs consist of unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. When available, Devon measures fair value using Level 1 inputs because they generally provide the most reliable evidence of fair value.

• Level 2 – Inputs consist of quoted prices that are generally observable for the asset or liability. Common examples of Level 2 inputs include quoted prices for similar assets and liabilities in active markets or quoted prices for identical assets and liabilities in markets not considered to be active.

• Level 3 – Inputs are not observable from objective sources and have the lowest priority. The most common Level 3 fair value measurement is an internally developed cash flow model.

Discontinued Operations

As a result of the November 2009 plan to divest Devon’s offshore assets, all amounts related to Devon’s International operations are classified as discontinued operations. The Gulf of Mexico properties that were divested in 2010 do not qualify as discontinued operations under accounting rules. As such, amounts in these notes and the accompanying financial statements that pertain to continuing operations include amounts related to Devon’s offshore Gulf of Mexico operations.

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The captions assets held for sale and liabilities associated with assets held for sale in the accompanying balance sheets present the assets and liabilities associated with Devon’s discontinued operations. Devon measures its assets held for sale at the lower of its carrying amount or estimated fair value less costs to sell. Additionally, Devon does not recognize depreciation, depletion and amortization on its long-lived assets held for sale.

Foreign Currency Translation Adjustments

The U.S. dollar is the functional currency for Devon’s consolidated operations except its Canadian subsidiaries, which use the Canadian dollar as the 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. Canadian 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 earnings in stockholders’ equity.

2. Derivative Financial Instruments

Commodity Derivatives

As of December 31, 2011, Devon had the following open oil derivative positions. Devon’s oil derivatives settle against the average of the prompt month NYMEX West Texas Intermediate futures price.

Production Period	Price Swaps				Price Collars						Call Options Sold
Period	Volume (Bbls/d)		Weighted Average  Price ($/Bbl)		Volume (Bbls/d)		Weighted Average Floor  Price ($/Bbl)		Weighted Average Ceiling  Price ($/Bbl)		Volume (Bbls/d)		Weighted Average  Price ($/Bbl)
Q1-Q4 2012		22,000	$	107.17		54,000	$	85.74	$	126.42		19,500	$	95.00
Q1-Q4 2013		—		—		7,000	$	90.00	$	125.12		—		—

As of December 31, 2011, Devon had the following open natural gas derivative positions. Devon’s natural gas derivative settle against the Inside FERC first of the month Henry Hub index.

Production Period	Price Swaps				Price Collars						Call Options Sold
Period	Volume (MMBtu/d)		Weighted Average  Price ($/MMBtu)		Volume (MMBtu/d)		Weighted Average Floor  Price ($/MMBtu)		Weighted Average Ceiling  Price ($/MMBtu)		Volume (MMBtu/d)		Weighted Average  Price ($/MMBtu)
Q1-Q4 2012		325,000	$	5.09		490,000	$	4.75	$	5.57		487,500	$	6.00

Basis Swaps
Production Period	Index	Volume (MMBtu/d)		Weighted Average Differential to Henry Hub ($/MMBtu)
Q1-Q4 2012	El Paso Natural Gas Co. (Permian)		85,000	$	(0.14	)
Q1-Q4 2012	Panhandle Eastern Pipeline		70,000	$	(0.15	)
Q1-Q4 2012	Colorado Interstate Gas Co.		10,000	$	(0.18	)

Interest Rate Derivatives

As of December 31, 2011, Devon had the following open interest rate derivative positions:

Notional	Fixed Rate Received			Variable Rate Paid	Expiration
(In millions)
$100		1.90	%	Federal funds rate	August 2012
750		3.88	%	Federal funds rate	July 2013
$850		3.65	%

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Foreign Exchange Derivatives

As of December 31, 2011, Devon had the following open foreign exchange rate derivative positions:

Forward Contract
Currency	Contract Type		CAD Notional		Fixed Rate Received		Expiration
			(In millions)		(CAD-USD)
Canadian Dollar		Sell	$	305		0.9812		March 30, 2012

Financial Statement Presentation

The following table presents the cash settlements and unrealized gains and losses on fair value changes included in the accompanying comprehensive statements of earnings associated with derivative financial instruments.

	Comprehensive Statement of Earnings Caption	2011			2010			2009
		(In millions)
Cash settlements:
Commodity derivatives	Oil, gas and NGL derivatives	$	392		$	888		$	505
Interest rate derivatives	Other, net		77			44			40
Foreign exchange derivatives	Other, net		16			—			—
Total cash settlements			485			932			545
Unrealized gains (losses):
Commodity derivatives	Oil, gas and NGL derivatives		489			(77	)		(121	)
Interest rate derivatives	Other, net		(88	)		(30	)		66
Total unrealized gains (losses)			401			(107	)		(55	)
Net gain recognized on comprehensive statements of earnings		$	886		$	825		$	490

The following table presents the derivative fair values included in the accompanying balance sheets.

		December 31,
	Balance Sheet Caption	2011		2010
		(In millions)
Asset derivatives:
Commodity derivatives	Other current assets	$	611	$	248
Commodity derivatives	Other long-term assets		17		1
Interest rate derivatives	Other current assets		30		100
Interest rate derivatives	Other long-term assets		22		40
Total asset derivatives		$	680	$	389
Liability derivatives:
Commodity derivatives	Other current liabilities	$	82	$	50
Commodity derivatives	Other long-term liabilities		—		142
Total liability derivatives		$	82	$	192

3. Share-Based Compensation

On June 3, 2009, Devon’s stockholders adopted the 2009 Long-Term Incentive Plan, which expires on June 2, 2019. This plan authorizes the Compensation Committee, which consists of independent non-management members of Devon’s Board of Directors, to grant nonqualified and incentive stock options, restricted stock awards, performance

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restricted stock awards, Canadian restricted stock units, performance share units, stock appreciation rights and cash-out rights to eligible employees. The plan also authorizes the grant of nonqualified stock options, restricted stock awards, restricted stock units and stock appreciation rights to directors. A total of 21.5 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 1.84 shares.

Devon also has stock option plans that were adopted in 2005, 2003 and 1997 under which stock options and restricted stock awards were issued to certain 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 its 2003 acquisition of Ocean Energy.

The following table presents the effects of share-based compensation included in Devon’s accompanying comprehensive statements of earnings. The vesting for certain share-based awards was accelerated as part of Devon’s strategic repositioning. The associated expense for these accelerated awards is included in restructuring costs in the accompanying comprehensive statements of earnings. See Note 4 for further details.

	2011		2010		2009
	(In millions)
Gross general and administrative expense	$	181	$	188	$	209
Share-based compensation expense capitalized pursuant to the full cost method of accounting for oil and gas properties	$	56	$	58	$	66
Related income tax benefit	$	33	$	40	$	43

Stock Options

In accordance with Devon’s incentive plans, the exercise price of stock options granted may not be less than the market value of the stock at the date of grant. In addition, options granted are exercisable during a period established for each grant, which may not exceed eight years from the date of grant. The recipient must pay the exercise price in cash or in common stock, or a combination thereof, at the time that the option is exercised. Generally, the service requirement for vesting ranges from zero to four years.

The fair value of stock options on the date of grant is expensed over the applicable vesting period. Devon estimates the fair values of stock options granted using a Black-Scholes option valuation model, which requires Devon to make several assumptions. The volatility of Devon’s common stock is based on the historical volatility of the market price of Devon’s common stock over a period of time equal to the expected term of the option and ending on the grant date. The dividend yield is based on Devon’s historical and current yield in effect at the date of grant. The risk-free interest rate is based on the zero-coupon U.S. Treasury yield for the expected term of the option at the date of grant. The expected term of the options is based on historical exercise and termination experience for various groups of employees and directors. Each group is determined based on the similarity of their historical exercise and termination behavior. The following table presents a summary of the grant-date fair values of stock options granted and the related assumptions. All such amounts represent the weighted-average amounts for each year.

	2011		2010		2009
Grant-date fair value	$	23.11	$	25.41	$	22.85
Volatility factor		46.0%		45.3%		47.7%
Dividend yield		1.0%		1.0%		0.9%
Risk-free interest rate		0.8%		1.1%		2.1%
Expected term (in years)		4.2		4.5		4.0

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The following table presents a summary of Devon’s outstanding stock options.

				Weighted Average
	Options			Exercise Price		Remaining Term		Intrinsic Value
	(In thousands)					(In years)		(In millions)
Outstanding at December 31, 2010		11,434		$	62.64
Granted		1,962		$	66.98
Exercised		(2,366	)	$	47.51
Forfeited		(487	)	$	73.32
Outstanding at December 31, 2011		10,543		$	66.35		4.31	$	40
Vested and expected to vest at December 31, 2011		10,428		$	66.33		4.27	$	40
Exercisable at December 31, 2011		6,716		$	65.39		2.90	$	39

The aggregate intrinsic value of stock options that were exercised during 2011, 2010 and 2009 was $81 million, $47 million and $51 million, respectively. As of December 31, 2011, Devon’s unrecognized compensation cost related to unvested stock options was $70 million. Such cost is expected to be recognized over a weighted-average period of 3.0 years.

Restricted Stock Awards and Units

These awards and units are subject to the terms, conditions, restrictions and limitations, if any, that the Compensation Committee deems appropriate, including restrictions on continued employment. Generally, the service requirement for vesting ranges from zero to four years. During the vesting period, recipients of such awards receive dividends that are not subject to restrictions or other limitations. Devon estimates the fair values of restricted stock awards and units as the closing price of Devon’s common stock on the grant date of the award or unit, which is expensed over the applicable vesting period. The following table presents a summary of Devon’s unvested restricted stock awards and units.

	Restricted Stock Awards & Units			Weighted Average Grant-Date Fair Value
	(In thousands)
Unvested at December 31, 2010		5,311		$	70.60
Granted		2,301		$	65.40
Vested		(2,188	)	$	72.05
Forfeited		(200	)	$	71.18
Unvested at December 31, 2011		5,224		$	67.85

The aggregate fair value of restricted stock awards and units that vested during 2011, 2010 and 2009 was $145 million, $184 million and $165 million, respectively. As of December 31, 2011, Devon’s unrecognized compensation cost related to unvested restricted stock awards and units was $305 million. Such cost is expected to be recognized over a weighted-average period of 2.8 years.

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Performance Based Restricted Stock Awards

In December 2011, certain members of Devon’s senior management were granted performance based share awards. Vesting of the awards is dependent on Devon meeting certain internal performance targets and the recipient meeting certain service requirements. Generally, the service requirement for vesting ranges from zero to four years. If Devon meets or exceeds the performance target, the awards vest after the recipient meets the related requisite service period. If the performance target and service period requirement are not met, the award does not vest. Once vested, recipients are entitled to dividends on the awards. Devon estimates the fair values of the awards as the closing price of Devon’s common stock on the grant date of the award, which is expensed over the applicable vesting period. The following table presents a summary of Devon’s performance based restricted stock awards.

	Performance Restricted Stock Awards		Weighted Average Grant-Date Fair Value
	(In thousands)
Unvested at December 31, 2010		—	$	—
Granted		184	$	65.10
Unvested at December 31, 2011		184	$	65.10

As of December 31, 2011, Devon’s unrecognized compensation cost related to these awards was $4 million. Such cost is expected to be recognized over a weighted-average period of 2.4 years.

Performance Share Units

In December 2011, certain members of Devon’s senior management were granted performance share units. Each unit that vests entitles the recipient to one share of Devon common stock. The vesting of these units is based on comparing Devon’s total shareholder return (“TSR”) to the TSR of a predetermined group of fourteen peer companies over the specified two- or three-year performance period. The vesting of units may be between zero and 200 percent of the units granted depending on Devon’s TSR as compared to the peer group on the vesting date.

During the vesting period, recipients will receive dividend equivalents with respect to each outstanding performance share unit. The fair value of each performance share unit is estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all grants made under the plan: (i) a risk-free interest rate; (ii) a volatility assumption based on the historical realized price volatility of Devon and the designated peer group; and (iii) an estimated ranking of Devon among the designated peer group. The fair value of the unit on the date of grant is expensed over the applicable vesting period.

The following table presents a summary of Devon’s performance share units.

	Performance Share Units		Weighted Average Grant-Date Fair Value
	(In thousands)
Unvested at December 31, 2010		—	$	—
Granted(1)		171	$	81.70
Unvested at December 31, 2011		171	$	81.70

(1) A maximum of 341,000 common shares could be awarded based upon Devon’s final TSR ranking.

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As of December 31, 2011, Devon’s unrecognized compensation cost related to unvested units was $8 million. Such cost is expected to be recognized over a weighted-average period of 2.3 years.

4. Restructuring Costs

In the fourth quarter of 2009, Devon announced plans to divest its offshore assets. As of December 31, 2011, Devon had divested all of its U.S. Offshore assets and substantially all of its International assets. Through the end of 2011, Devon had incurred $202 million of restructuring costs associated with these divestitures.

Employee Severance

This amount was originally based on estimates of the number of employees that would ultimately be impacted by the offshore divestitures and included amounts related to cash severance costs and accelerated vesting of share-based grants. As the divestiture program progressed, Devon decreased its overall estimate of employee severance costs. More offshore employees than previously estimated received comparable positions with either the purchaser of the properties or in Devon’s U.S. Onshore operations.

Lease Obligations

As a result of the divestitures, Devon ceased using certain office space that was subject to non-cancellable operating lease arrangements. Consequently, in 2010 Devon recognized $70 million of restructuring costs that represented the present value of its future obligations under the leases, net of anticipated sublease income. Devon’s estimate of lease obligations was based upon certain key estimates that could change over the term of the leases. These estimates include the estimated sublease income that Devon may receive over the term of the leases, as well as the amount of variable operating costs that Devon will be required to pay under the leases. In addition, Devon recognized $11 million of asset impairment charges for leasehold improvements and furniture associated with the office space that it ceased using.

Financial Statement Presentation

The schedule below summarizes restructuring costs presented in the accompanying comprehensive statements of earnings. Restructuring costs relating to Devon’s discontinued operations totaled $(2) million, $(4) million, and $48 million in 2011, 2010, and 2009, respectively. These costs primarily relate to cash severance and share-based awards and are not included in the schedule below.

	Year Ended December 31,
	2011			2010			2009
	(In millions)
Cash severance	$	9		$	(17	)	$	66
Share-based awards		(1	)		(10	)		39
Lease obligations		(13	)		70			—
Asset impairments		2			11			—
Other		1			3			—
Total	$	(2	)	$	57		$	105

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The schedule below summarizes activity and balances associated with Devon’s restructuring liabilities. Devon’s restructuring liabilities related to its discontinued operations totaled $16 million and $23 million at December 31, 2010, and 2009, respectively. There was no liability at the end of 2011. These liabilities primarily relate to cash severance and are not included in the schedule below.

	Other Current Liabilities			Other Long-Term Liabilities			Total
	(In millions)
Balance as of December 31, 2009	$	61		$	—		$	61
Lease obligations incurred		17			51			68
Cash severance settled		(30	)		—			(30	)
Cash severance revision		(17	)		—			(17	)
Balance as of December 31, 2010		31			51			82
Lease obligations settled		(8	)		(12	)		(20	)
Cash severance settled		(13	)		—			(13	)
Lease obligations revision		10			(23	)		(13	)
Cash severance revision		9			—			9
Balance as of December 31, 2011	$	29		$	16		$	45

5. Other, net

The components of other, net in the accompanying comprehensive statement of earnings include the following:

	Year Ended December 31,
	2011			2010			2009
	(In millions)
Accretion of asset retirement obligations	$	92		$	92		$	91
Interest rate swaps – unrealized fair value changes		88			30			(66	)
Interest rate swaps – cash settlements		(77	)		(44	)		(40	)
Interest income		(21	)		(13	)		(8	)
Other		(92	)		(32	)		(60	)
Total	$	(10	)	$	33		$	(83	)

During 2011, Devon received $88 million of excess insurance recoveries related to certain weather and operational claims. In 2009, Devon reversed an $84 million loss contingency accrual. Devon had previously accrued $84 million for potential royalties on various deep water leases but reversed the accrual in 2009 due to a federal district court ruling.

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6. Income Taxes

Income Tax Expense (Benefit)

Devon’s income tax components are presented in the following table.

	Year Ended December 31,
	2011			2010			2009
	(In millions)
Current income tax (benefit) expense:
U.S. federal	$	(143	)	$	244		$	45
Various states		20			16			18
Canada and various provinces		(20	)		256			178
Total current tax (benefit) expense		(143	)		516			241
Deferred income tax expense (benefit):
U.S. federal		1,986			781			(1,846	)
Various states		95			21			(111	)
Canada and various provinces		218			(83	)		(57	)
Total deferred tax expense (benefit)		2,299			719			(2,014	)
Total income tax expense (benefit)	$	2,156		$	1,235		$	(1,773	)

Total income tax expense (benefit) differed from the amounts computed by applying the U.S. federal income tax rate to earnings (loss) from continuing operations before income taxes as a result of the following:

	Year Ended December 31,
	2011			2010			2009
	(In millions)
Expected income tax expense (benefit) based on U.S. statutory tax rate of 35%	$	1,502		$	1,249		$	(1,584	)
Assumed repatriations		725			144			55
State income taxes		70			31			(99	)
Taxation on Canadian operations		(91	)		(60	)		(31	)
Other		(50	)		(129	)		(114	)
Total income tax expense (benefit)	$	2,156		$	1,235		$	(1,773	)

During 2011, 2010 and 2009, pursuant to the completed and planned divestitures of our International assets located outside North America, a portion of Devon’s foreign earnings were no longer deemed to be permanently reinvested. Accordingly, Devon recognized deferred income tax expense of $725 million, $144 million and $55 million during 2011, 2010 and 2009 respectively, related to assumed repatriations of earnings from its foreign subsidiaries.

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Deferred Tax Assets and Liabilities

The tax effects of temporary differences that gave rise to Devon’s deferred tax assets and liabilities are presented below:

	December 31,
	2011			2010
	(In millions)
Deferred tax assets:
Net operating loss carryforwards	$	222		$	159
Asset retirement obligations		447			494
Pension benefit obligations		130			133
Other		117			171
Total deferred tax assets		916			957
Deferred tax liabilities:
Property and equipment		(4,475	)		(3,130	)
Fair value of financial instruments		(218	)		(70	)
Long-term debt		(185	)		(198	)
Taxes on unremitted foreign earnings		(936	)		(211	)
Other		(27	)		(20	)
Total deferred tax liabilities		(5,841	)		(3,629	)
Net deferred tax liability	$	(4,925	)	$	(2,672	)

Devon has recognized $222 million of deferred tax assets related to various carryforwards available to offset future income taxes. The carryforwards consist of $829 million of Canadian net operating loss carryforwards, which expire between 2026 and 2031, and $206 million of state net operating loss carryforwards, which expire primarily between 2012 and 2031. Devon expects the tax benefits from the Canadian net operating loss carryforwards to be utilized between 2013 and 2017. Also, Devon expects the tax benefits from the state net operating loss carryforwards to be utilized between 2012 and 2016. Such expectations are based upon current estimates of taxable income during these periods, 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, gas and NGL prices or capital expenditures 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.

As of December 31, 2011, approximately $5.4 billion of Devon’s unremitted earnings from its foreign subsidiaries were deemed to be permanently reinvested. As a result, Devon has not recognized a deferred tax liability for U.S. income taxes associated with such earnings. If such earnings were to be remitted to the U.S., Devon may be subject to U.S. income taxes and foreign withholding taxes. However, it is not practical to estimate the amount of additional taxes that may be payable due to the inter-relationship of the various factors involved in making such an estimate.

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Unrecognized Tax Benefits

The following table presents changes in Devon’s unrecognized tax benefits.

	December 31,
	2011			2010
	(In millions)
Balance at beginning of year	$	194		$	272
Tax positions taken in prior periods		(3	)		40
Tax positions taken in current year		27			5
Accrual of interest related to tax positions taken		(7	)		9
Lapse of statute of limitations		(41	)		(5	)
Settlements		(5	)		(129	)
Foreign currency translation		—			2
Balance at end of year	$	165		$	194

Devon’s unrecognized tax benefit balance at December 31, 2011 and 2010, included $20 million and $27 million of interest and penalties, respectively. If recognized, all of Devon’s unrecognized tax benefits as of December 31, 2011 would affect Devon’s effective income tax rate. Included below is a summary of the tax years, by jurisdiction, that remain subject to examination by taxing authorities.

Jurisdiction	Tax Years Open
U.S. federal		2008-2011
Various U.S. states		2007-2011
Canada federal		2003-2011
Various Canadian provinces		2003-2011

Certain statute of limitation expirations are scheduled to occur in the next twelve months. However, Devon is currently in various stages of the administrative review process for certain open tax years. In addition, Devon is currently subject to various income tax audits that have not reached the administrative review process. As a result, Devon cannot reasonably anticipate the extent that the liabilities for unrecognized tax benefits will increase or decrease within the next twelve months.

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7. Earnings (Loss) Per Share

The following table reconciles earnings from continuing operations and common shares outstanding used in the calculations of basic and diluted earnings (loss) per share. Because a net loss from continuing operations was incurred during 2009, the dilutive shares produce an antidilutive net loss per share result. As a result, the diluted loss per share from continuing operations is same as the basic loss per share amount.

	Earnings			Common Shares			Earnings (Loss) per Share
	(In millions, except per share amounts)
Year Ended December 31, 2011:
Earnings from continuing operations	$	2,134			417
Attributable to participating securities		(23	)		(5	)
Basic earnings per share		2,111			412		$	5.12
Dilutive effect of potential common shares issuable		—			2
Diluted earnings per share	$	2,111			414		$	5.10
Year Ended December 31, 2010:
Earnings from continuing operations	$	2,333			440
Attributable to participating securities		(26	)		(5	)
Basic earnings per share		2,307			435		$	5.31
Dilutive effect of potential common shares issuable		—			1
Diluted earnings per share	$	2,307			436		$	5.29
Year Ended December 31, 2009:
Loss from continuing operations	$	(2,753	)		444
Attributable to participating securities		31			(5	)
Basic and diluted loss per share	$	(2,722	)		439		$	(6.20	)

Certain options to purchase shares of Devon’s common stock were excluded from the dilution calculations because the options were antidilutive. These excluded options totaled 3 million, 6 million and 9 million in 2011, 2010 and 2009, respectively.

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8. Other Comprehensive Earnings

Components of other comprehensive earnings consist of the following:

	Year Ended December 31,
	2011			2010			2009
	(In millions)
Foreign currency translation:
Accumulated foreign currency translation at beginning of year	$	1,993		$	1,616		$	685
Change in cumulative translation adjustment		(200	)		397			993
Income tax benefit (expense)		9			(20	)		(62	)
Accumulated foreign currency translation at end of year		1,802			1,993			1,616
Pension and postretirement benefit plans:
Accumulated pension and postretirement benefit at beginning of year		(233	)		(231	)		(302	)
Net actuarial (loss) gain and prior service cost arising in current year		(21	)		(33	)		59
Income tax benefit (expense)		8			11			(22	)
Recognition of net actuarial loss and prior service cost in net earnings		30			31			54
Income tax expense		(11	)		(11	)		(20	)
Accumulated pension and postretirement benefits at end of year		(227	)		(233	)		(231	)
Accumulated other comprehensive earnings, net of tax	$	1,575		$	1,760		$	1,385

9. Supplemental Information to Statements of Cash Flows

	Year Ended December 31,
	2011			2010			2009
	(In millions)
Net decrease (increase) in working capital:
(Increase) decrease in accounts receivable	$	(185	)	$	23		$	142
Decrease in other current assets		125			21			212
Increase (decrease) in accounts payable		64			37			(91	)
Increase in revenues and royalties payable		144			48			—
Increase (decrease) in income taxes payable		78			(203	)		(48	)
Decrease in other current liabilities		(41	)		(199	)		(66	)
Net decrease (increase) in working capital	$	185		$	(273	)	$	149
Supplementary cash flow data – total operations:
Interest paid (net of capitalized interest)	$	325		$	359		$	314
Income taxes (received) paid	$	(383	)	$	955		$	68

10. Short-Term Investments

The components of short-term investments include the following:

	December 31,
	2011		2010
	(In millions)
Commercial paper	$	1,013	$	—
U.S. Treasuries		201		145
Other		289		—
Total	$	1,503	$	145

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As of December 31, 2011, the average remaining maturity of these investments was 75 days, with a weighted average yield of 0.28 percent.

11. Accounts Receivable

The components of accounts receivable include the following:

	December 31,
	2011			2010
	(In millions)
Oil, gas and NGL sales	$	928		$	786
Joint interest billings		247			204
Marketing and midstream revenues		174			165
Other		39			57
Gross accounts receivable		1,388			1,212
Allowance for doubtful accounts		(9	)		(10	)
Net accounts receivable	$	1,379		$	1,202

12. Other Current Assets

The components of other current assets include the following:

	December 31,
	2011		2010
	(In millions)
Derivative financial instruments	$	641	$	348
Inventories		102		120
Income tax receivable		35		270
Other		69		41
Other current assets	$	847	$	779

13. Property and Equipment

See Note 22 for disclosure of Devon’s capitalized costs related to its oil and gas exploration and development activities.

In November 2009, Devon announced plans to divest its offshore assets. In 2011, Devon substantially completed its planned divestiture program. In aggregate, Devon’s U.S. and International sales generated total proceeds of $10 billion as presented in the following table. Assuming repatriation of a portion of the foreign proceeds under current U.S. tax law the after-tax proceeds from these transactions were approximately $8 billion.

	Cash Proceeds		Year of Divestiture
	(In millions)
Brazil (discontinued operations)	$	3,251		2011
Gulf of Mexico (continuing operations)		4,059		2010
Azerbaijan (discontinued operations)		1,925		2010
China — Panyu and Exploration (discontinued operations)		592		2010
Other (discontinued operations)		175		2010
Total	$	10,002

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Reductions of Carrying Value

In the first quarter of 2009, Devon reduced the carrying value of its U.S. oil and gas properties $6.4 billion, or $4.1 billion after taxes, due to a full cost ceiling limitation. The reduction resulted from a significant decrease in the full cost ceiling due to the effects of declining natural gas prices subsequent to December 31, 2008.

Sinopec Transaction

In January 2012, Devon announced a transaction with Sinopec International Petroleum Exploration & Production Corporation that Devon expects to close in the first quarter of 2012. Under the agreement, Sinopec will pay $2.5 billion, including $900 million at closing and $1.6 billion toward Devon’s share of future drilling costs, and will receive a 33.3% interest in five new venture exploration plays in the United States.

14. Debt and Related Expenses

A summary of Devon’s debt is as follows:

	December 31,
	2011			2010
	(In millions)
Commercial paper	$	3,726		$	—
Other debentures and notes:
6.875% retired upon maturity on September 30, 2011		—			1,750
5.625% due January 15, 2014		500			500
Non-interest bearing promissory note due June 29, 2014		85			144
2.40% due July 15, 2016		500			—
8.25% due July 1, 2018		125			125
6.30% due January 15, 2019		700			700
4.00% due July 15, 2021		500			—
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
5.60% due July 15, 2041		1,250			—
Other		—			9
Net discount on other debentures and notes		(6	)		2
Total debt		9,780			5,630
Less amount classified as short-term debt		3,811			1,811
Long-term debt	$	5,969		$	3,819

Debt maturities as of December 31, 2011, excluding premiums and discounts, are as follows (in millions):

2012	$	3,811
2013		—
2014		500
2015		—
2016		500
2017 and thereafter		4,975
Total	$	9,786

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Credit Lines

Devon has a $2.65 billion syndicated, unsecured revolving line of credit (the “Senior Credit Facility”). The maturity date for $2.19 billion of the Senior Credit Facility is April 7, 2013. The maturity date for the remaining $0.46 billion is April 7, 2012. All amounts outstanding will be due and payable on the respective maturity dates unless the maturity is extended. Prior to each April 7 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. The Senior Credit Facility includes a revolving Canadian subfacility in a maximum amount of U.S. $0.5 billion.

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. However, Devon may 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. As of December 31, 2011, there were no borrowings under the Senior Credit Facility.

The Senior Credit Facility contains only one material financial covenant. This covenant requires Devon’s ratio of total funded debt to total capitalization to be less than 65 percent. The credit agreement contains definitions of total funded debt and total capitalization that include adjustments to the respective amounts reported in the accompanying financial statements. Also, total capitalization is adjusted to add back noncash financial writedowns such as full cost ceiling impairments or goodwill impairments. As of December 31, 2011, Devon was in compliance with this covenant. Devon’s debt-to-capitalization ratio at December 31, 2011, as calculated pursuant to the terms of the agreement, was 22.8 percent.

Commercial Paper

Devon has access to $5.0 billion of short-term credit under its commercial paper program. Commercial paper debt generally has a maturity of between 1 and 90 days, although it can have a maturity of up to 365 days, and bears interest at rates agreed to at the time of the borrowing. The interest rate is generally based on a standard index such as the Federal Funds Rate, LIBOR, or the money market rate as found in the commercial paper market. As of December 31, 2011, Devon’s weighted average borrowing rate on its commercial paper borrowings was 0.45 percent.

Other Debentures and Notes

Following are descriptions of the various other debentures and notes outstanding at December 31, 2011, as listed in the table presented at the beginning of this note.

5.625% Notes due January 15, 2014 and 6.30% Notes due January 15, 2019

In January 2009, Devon issued $1.2 billion of senior notes. The net proceeds were used primarily to repay outstanding commercial paper as of December 31, 2008. These notes are unsecured and unsubordinated obligations of Devon.

Non-Interest Bearing Promissory Note due June 29, 2014

In June 2010, Devon issued a four-year $155 million Canadian dollar non-interest bearing promissory note in connection with the formation of the Pike oil sands joint venture. The present value of the note was $139

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million on the issue date based upon an effective interest rate of 3.125%. At December 31, 2011, the note had a carrying value of $85 million, which is presented as short-term debt in the accompanying balance sheet because it is expected to be repaid during 2012.

2.40% Notes due July 15, 2016, 4.00% Notes due July 15, 2021 and 5.60% Notes due July 15, 2041

In July 2011, Devon issued $2.25 billion of senior notes. The net proceeds were used to repay outstanding commercial paper debt. These notes are unsecured and unsubordinated obligations of Devon.

Ocean Debt

On April 25, 2003, Devon merged with Ocean Energy, Inc. and assumed certain debt instruments. The table below summarizes the debt assumed that remains outstanding as of December 31, 2011, including the fair value of the debt at April 25, 2003, and the effective interest rate of the debt after determining the fair values using April 25, 2003, market interest rates. The premiums resulting from fair values exceeding face values are being amortized using the effective interest method. Both notes are general unsecured obligations of Devon.

Debt Assumed	Fair Value of Debt  Assumed		Effective Rate of Debt Assumed
	(In millions)
8.250% due July 2018 (principal of $125 million)	$	147		5.5	%
7.500% due September 2027 (principal of $150 million)	$	169		6.5	%

7.875% Debentures due September 30, 2031

In October 2001, Devon, through Devon Financing Corporation, U.L.C. (“Devon Financing”), a wholly owned finance subsidiary, sold 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 were used to fund a portion of the acquisition of Anderson Exploration.

7.95% Notes due April 15, 2032

In March 2002, Devon sold these notes, which are unsecured and unsubordinated obligations of Devon. The net proceeds were used to retire other indebtedness.

Interest Expense

The following schedule includes the components of interest expense.

	Year Ended December 31,
	2011			2010			2009
	(In millions)
Interest based on debt outstanding	$	414		$	408		$	437
Capitalized interest		(72	)		(76	)		(94	)
Early retirement of debt		—			19			—
Other		10			12			6
Total	$	352		$	363		$	349

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

15. Asset Retirement Obligations

The schedule below summarizes changes in Devon’s asset retirement obligations.

	Year Ended December 31,
	2011			2010
	(In millions)
Asset retirement obligations as of beginning of year	$	1,497		$	1,513
Liabilities incurred		53			55
Liabilities settled		(82	)		(129	)
Revision of estimated obligation		25			194
Liabilities assumed by others		—			(269	)
Accretion expense on discounted obligation		92			92
Foreign currency translation adjustment		(22	)		41
Asset retirement obligations as of end of year		1,563			1,497
Less current portion		67			74
Asset retirement obligations, long-term	$	1,496		$	1,423

During 2010, Devon recognized a revision to its asset retirement obligations totaling $194 million. The increase was primarily due to an overall increase in abandonment cost estimates and a decrease in the discount rate used to present value the obligations.

During 2010, Devon reduced its asset retirement obligations by $269 million primarily for those obligations that were assumed by purchasers of Devon’s Gulf of Mexico oil and gas properties.

16. Retirement Plans

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

The nonqualified plans provide retirement benefits for certain employees whose benefits under the qualified plans are limited by income tax regulations. The nonqualified plans’ benefits are based on the employees’ years of service and compensation. For certain nonqualified plans, Devon has established trusts to fund these plans’ benefit obligations. The total value of these trusts was $32 million and $36 million at December 31, 2011 and 2010, respectively, and is included in other long-term assets in the accompanying balance sheets. For the remaining nonqualified 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 that provide benefits for substantially all U.S. employees. The 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 such plans are estimated based on Devon’s future cost-sharing intentions. Devon’s funding policy for the plans is to fund the benefits as they become payable with available cash and cash equivalents.

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Benefit Obligations and Funded Status

The following table presents the funded status of Devon’s qualified and nonqualified pension and other postretirement benefit plans. 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, 2011 and 2010 was $1.2 billion and $1.0 billion, respectively. Devon’s benefit obligations and plan assets are measured each year as of December 31. Devon’s 2011 pension plan contributions of $454 million presented in the table were primarily discretionary. After these contributions, the projected benefit obligation for Devon’s qualified plans was fully funded as of December 31, 2011.

	Pension Benefits						Postretirement Benefits
	2011			2010			2011			2010
	(In millions)
Change in benefit obligation:
Benefit obligation at beginning of year	$	1,124		$	980		$	43		$	64
Service cost		37			33			1			1
Interest cost		60			58			2			3
Actuarial loss (gain)		123			82			(8	)		1
Plan amendments		—			5			5			(22	)
Plan settlements		—			—			(4	)		—
Foreign exchange rate changes		(1	)		2			—			—
Participant contributions		—			—			3			2
Benefits paid		(40	)		(36	)		(5	)		(6	)
Benefit obligation at end of year		1,303			1,124			37			43
Change in plan assets:
Fair value of plan assets at beginning of year		632			532			—			—
Actual return on plan assets		141			69			—			—
Employer contributions		454			66			7			4
Participant contributions		—			—			3			2
Plan settlements		—			—			(5	)		—
Benefits paid		(40	)		(36	)		(5	)		(6	)
Foreign exchange rate changes		—			1			—			—
Fair value of plan assets at end of year		1,187			632			—			—
Funded status at end of year	$	(116	)	$	(492	)	$	(37	)	$	(43	)
Amounts recognized in balance sheet:
Noncurrent assets	$	116		$	2		$	—		$	—
Current liabilities		(10	)		(9	)		(3	)		(4	)
Noncurrent liabilities		(222	)		(485	)		(34	)		(39	)
Net amount	$	(116	)	$	(492	)	$	(37	)	$	(43	)
Amounts recognized in accumulated other comprehensive earnings:
Net actuarial loss (gain)	$	348		$	357		$	(9	)	$	(5	)
Prior service cost (credit)		18			21			(5	)		(12	)
Total	$	366		$	378		$	(14	)	$	(17	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The plan assets for pension benefits in the table above exclude the assets held in trusts for the nonqualified plans. However, employer contributions for pension benefits in the table above include $8 million for both 2011 and 2010, which were transferred from the trusts established for the nonqualified plans.

Certain of Devon’s pension plans have a projected benefit obligation and accumulated benefit obligation in excess of plan assets at December 31, 2011 and 2010 as presented in the table below.

	December 31,
	2011		2010
	(In millions)
Projected benefit obligation	$	232	$	1,110
Accumulated benefit obligation	$	189	$	996
Fair value of plan assets	$	—	$	616

Net Periodic Benefit Cost and Other Comprehensive Earnings

The following table presents the components of net periodic benefit cost and other comprehensive earnings.

	Pension Benefits									Postretirement Benefits
	2011			2010			2009			2011			2010			2009
	(In millions)
Net periodic benefit cost:
Service cost	$	37		$	33		$	43		$	1		$	1		$	1
Interest cost		60			58			58			2			3			3
Expected return on plan assets		(42	)		(36	)		(35	)		—			—			—
Curtailment and settlement expense		—			—			5			(3	)		—			—
Recognition of net actuarial loss (gain)		32			27			45			—			—			(1	)
Recognition of prior service cost		3			3			3			(2	)		1			2
Total net periodic benefit cost		90			85			119			(2	)		5			5
Other comprehensive earnings:
Actuarial loss (gain) arising in current year		23			50			(66	)		(7	)		1			7
Prior service cost (credit) arising in current year		—			4			—			5			(22	)		—
Recognition of net actuarial loss, including settlement expense, in net periodic benefit cost		(32	)		(27	)		(45	)		3			—			1
Recognition of prior service cost, including curtailment, in net periodic benefit cost		(3	)		(3	)		(8	)		2			(1	)		(2	)
Total other comprehensive (loss) earnings		(12	)		24			(119	)		3			(22	)		6
Total recognized	$	78		$	109		$	—		$	1		$	(17	)	$	11

The following table presents the estimated net actuarial loss and prior service cost that will be amortized from accumulated other comprehensive earnings into net periodic benefit cost during 2012.

	Pension Benefits		Postretirement Benefits
	(In millions)
Net actuarial loss (gain)	$	24	$	(1	)
Prior service cost (credit)		3		(1	)
Total	$	27	$	(2	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Assumptions

The following table presents the weighted average actuarial assumptions used to determine obligations and periodic costs.

	Pension Benefits									Postretirement Benefits
	2011			2010			2009			2011			2010			2009
Assumptions to determine benefit obligations:
Discount rate		4.65	%		5.50	%		6.00	%		4.25	%		4.90	%		5.70	%
Rate of compensation increase		4.97	%		6.94	%		6.95	%		N/A			N/A			N/A
Assumptions to determine net periodic benefit cost:
Discount rate		5.50	%		6.00	%		6.00	%		4.90	%		5.70	%		6.00	%
Expected return on plan assets		6.48	%		6.94	%		7.18	%		N/A			N/A			N/A
Rate of compensation increase		6.94	%		6.95	%		6.95	%		N/A			N/A			N/A

Discount rate — 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 future cash flows related to the plans. This rate is based on high-quality bond yields, after allowing for call and default risk.

Rate of compensation increase — For measurement of the 2011 benefit obligation for the pension plans, a 4.97% compensation increase was assumed.

Expected return on plan assets — 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. See the pension plan assets section below for more information on Devon’s target allocations.

Other assumptions — For measurement of the 2011 benefit obligation for the other postretirement medical plans, an 8.2% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2012. The rate was assumed to decrease annually to an ultimate rate of 5% in the year 2029 and remain at that level thereafter. Assumed health care cost-trend rates affect the amounts reported for retiree health care costs. A one-percentage-point change in the assumed health care cost-trend rates would have changed the postretirement benefits obligation as of December 31, 2011, by $2 million and would change the 2012 service and interest cost components of net periodic benefit cost by less than $1 million.

Pension Plan Assets

Devon’s overall investment objective for its pension plans’ assets is to achieve stability of the plans’ funded status while providing long-term growth of invested capital and income to ensure benefit payments 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. Derivatives or other speculative investments considered high risk are generally prohibited. The following table presents Devon’s target allocation for its pension plan assets. Devon made significant contributions to its qualified pension plans in 2011. As a result, Devon revised its target allocations in 2011.

	December 31,
	2011			2010
Fixed income		70	%		40	%
Equity		20	%		47.5	%
Other		10	%		12.5	%

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The fair values of Devon’s pension assets are presented by asset class in the following tables.

	As of December 31, 2011
	Actual Allocation			Total		Fair Value Measurements Using:
						Level 1 Inputs		Level 2 Inputs		Level 3 Inputs
	($ In millions)
Fixed-income securities:
U.S. Treasury obligations		43.9	%	$	522	$	27	$	495	$	—
Corporate bonds		24.8	%		294		265		29		—
Other bonds		3.1	%		36		36		—		—
Total fixed-income securities		71.8	%		852		328		524		—
Equity securities:
Global (large, mid, small cap)		18.0	%		214		—		214		—
Other securities:
Hedge fund & alternative investments		8.9	%		106		16		—		90
Short-term investment funds		1.3	%		15		—		15		—
Total other securities		10.2	%		121		16		15		90
Total investments		100.0	%	$	1,187	$	344	$	753	$	90

	As of December 31, 2010
	Actual Allocation			Total		Fair Value Measurements Using:
						Level 1 Inputs		Level 2 Inputs		Level 3 Inputs
	($ In millions)
Equity securities:
U.S. large cap		22.3	%	$	141	$	—	$	141	$	—
U.S. small cap		14.1	%		89		89		—		—
International large cap		14.4	%		91		50		41		—
Total equity securities		50.8	%		321		139		182		—
Fixed-income securities:
Corporate bonds		22.0	%		139		139		—		—
U.S. Treasury obligations		10.9	%		69		69		—		—
Other bonds		4.6	%		29		29		—		—
Total fixed-income securities		37.5	%		237		237		—		—
Other securities:
Hedge funds		9.2	%		58		—		—		58
Short-term investment funds		2.5	%		16		—		16		—
Total other securities		11.7	%		74		—		16		58
Total investments		100.0	%	$	632	$	376	$	198	$	58

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The following methods and assumptions were used to estimate the fair values in the tables above.

Fixed-income securities — Devon’s fixed-income securities consist of U.S. Treasury obligations, bonds issued by investment-grade companies from diverse industries, and asset-backed securities. These fixed-income securities are actively traded securities that can be redeemed upon demand. The fair values of these Level 1 securities are based upon quoted market prices.

Devon’s fixed income securities also include commingled funds that primarily invest in long-term bonds and U.S. Treasury securities. These fixed income securities can be redeemed on demand but are not actively traded. The fair values of these Level 2 securities are based upon the net asset values provided by the investment managers.

Equity securities — Devon’s equity securities include a commingled global equity fund that invests in large, mid and small capitalization stocks across the world’s developed and emerging markets. These equity securities can be redeemed on demand but are not actively traded. The fair values of these Level 2 securities are based upon the net asset values provided by the investment managers.

At December 31, 2010, Devon’s equity securities consisted of investments in U.S. large and small capitalization companies and international large capitalization companies. These equity securities were actively traded securities that could be redeemed upon demand. The fair values of these Level 1 securities are based upon quoted market prices.

At December 31, 2010, Devon’s equity securities also included a commingled fund that invested in large capitalization companies. These equity securities could be redeemed on demand but were not actively traded. The fair values of these Level 2 securities are based upon the net asset values provided by the investment managers.

Other securities — Devon’s other securities include commingled, short-term investment funds. These securities can be redeemed on demand but are not actively traded. The fair values of these Level 2 securities are based upon the net asset values provided by investment managers.

Devon’s hedge fund and alternative investments include an investment in an actively traded global mutual fund that focuses on alternative investment strategies and a hedge fund of funds that invests both long and short using a variety of investment strategies. Devon’s hedge fund of funds is not actively traded and Devon is subject to redemption restrictions with regards to this investment. The fair value of this Level 3 investment represents the fair value as determined by the hedge fund manager.

Included below is a summary of the changes in Devon’s Level 3 plan assets (in millions).

December 31, 2009	$	51
Purchases		3
Investment returns		4
December 31, 2010		58
Purchases		33
Investment returns		(1	)
December 31, 2011	$	90

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Expected Cash Flows

The following table presents expected cash flow information for Devon’s pension and other postretirement benefit plans.

	Pension Benefits		Postretirement Benefits
	(In millions)
Devon’s 2012 contributions	$	9	$	3
Benefit payments:
2012	$	44	$	3
2013	$	49	$	3
2014	$	52	$	3
2015	$	56	$	3
2016	$	61	$	3
2017 to 2021	$	390	$	14

Expected contributions included in the table above include amounts related to Devon’s qualified plans, nonqualified plans and postretirement plans. Of the benefits expected to be paid in 2012, the $9 million of pension benefits is expected to be funded from the trusts established for the nonqualified plans and the $3 million of other postretirement benefits 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.

Defined Contribution Plans

Devon maintains several defined contribution plans covering its employees in the U.S. and Canada. Such plans include Devon’s 401(k) plan, enhanced contribution plan and Canadian pension and savings plan. Contributions are primarily based upon percentages of annual compensation and years of service. In addition, each plan is subject to regulatory limitations by each respective government. The following table presents Devon’s expense related to these defined contribution plans.

	Year Ended December 31,
	2011		2010		2009
	(In millions)
401(k) and enhanced contribution plans	$	33	$	32	$	34
Canadian pension and savings plans		21		17		15
Total	$	54	$	49	$	49

17. Stockholders’ Equity

The authorized capital stock of Devon consists of 1 billion 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.

Devon’s Board of Directors has designated 2.9 million shares of the preferred stock as Series A Junior Participating Preferred Stock (the “Series A Junior Preferred Stock”). At December 31, 2011, 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 100 times the aggregate per share amount of all dividends (other than stock dividends) declared on common stock since the immediately

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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 100 votes per share on all matters submitted to a vote of the stockholders. Devon, at its option, may redeem shares of the Series A Junior Participating Preferred Stock in whole at any time and in part from time to time, at a redemption price equal to 100 times the current per share market price of Devon’s common stock on the date of the mailing of the notice of redemption. The Series A Junior Preferred Stock ranks prior to the common stock but junior to all other classes of Preferred Stock.

Stock Repurchases

During 2010, Devon’s Board of Directors announced a share repurchase program that authorized the repurchase of up to $3.5 billion of its common shares. Devon completed the repurchase program in the fourth quarter of 2011. In total, Devon repurchased 49.2 million shares for $3.5 billion, or $71.18 per share. The following table summarizes Devon’s repurchases under the 2010 program by year (amounts and shares in millions).

	2011					2010
		Amount	Shares		Per Share		Amount	Shares		Per Share
Repurchases	$	2,299	30.9	$	74.49	$	1,201	18.3	$	65.58

Dividends

Devon paid common stock dividends of $278 million (or $0.67 per share), $281 million (or $0.64 per share) and $284 million (or $0.64 per share) in 2011, 2010 and 2009 respectively. In the second quarter of 2011, Devon increased its dividend rate from $0.16 per share to $0.17 per share.

18. 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 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.

Royalty Matters

Numerous natural 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 NGLs produced and sold from federal and Indian owned or controlled lands. Devon does not currently believe that it is subject to material exposure with respect to such royalty matters.

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 and similar state statutes. In response to liabilities associated with these activities, loss accruals primarily consist of estimated uninsured costs associated with remediation. Devon’s monetary exposure for environmental matters is not expected to be material.

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Chief Redemption Matters

In 2006, Devon acquired Chief Holdings LLC (“Chief”) from the owners of Chief, including Trevor Rees-Jones, the majority owner of Chief. In 2008, a former owner of Chief filed a petition against Rees-Jones, as the former majority owner of Chief, and Devon, as Chief’s successor pursuant to the 2006 acquisition. The petition claimed, among other things, violations of the Texas Securities Act, fraud and breaches of Rees-Jones’ fiduciary responsibility to the former owner in connection with Chief’s 2004 redemption of the owner’s minority ownership stake in Chief.

On June 20, 2011, a court issued a judgment against Rees-Jones for $196 million, of which $133 million of the judgment was also issued against Devon. Both Rees-Jones and Devon are appealing the judgment. However, if the appeal is unsuccessful, Devon can and will seek full payment of the judgment and any related interest, costs and expenses from Rees-Jones pursuant to an existing indemnification agreement between Rees-Jones, certain other parties and Devon. Devon does not expect to have any net exposure as a result of the judgment. However, because Devon does not have a legal right of set off with respect to the judgment, Devon has recorded in its December 31, 2011, balance sheet both a $133 million liability relating to the judgment with an offsetting $133 million receivable relating to its right to be indemnified by Rees-Jones and certain other parties pursuant to the indemnification agreement.

Other Matters

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

Commitments

The following is a schedule by year of Devon’s commitments that have initial or remaining noncancelable lease terms in excess of one year as of December 31, 2011.

Year Ending December 31,	Purchase Obligations		Drilling and Facility Obligations		Operational Agreements		Office and Equipment Leases
	(In millions)
2012	$	900	$	919	$	306	$	63
2013		905		456		302		56
2014		905		100		283		47
2015		905		—		250		44
2016		924		—		209		43
Thereafter		3,915		—		786		220
Total	$	8,454	$	1,475	$	2,136	$	473

Devon has certain purchase obligations related to its heavy oil projects in Canada to purchase condensate at market prices. Devon entered into these agreements because the condensate is an integral part of the heavy oil production process and any disruption in Devon’s ability to obtain condensate could negatively affect its ability to produce and transport heavy oil at these locations. Devon’s total obligation related to condensate purchases expires in 2021. The value of these purchase obligations presented in the table above is based on the contractual volumes and Devon’s internal estimate of future condensate market prices.

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

Devon has certain operational agreements whereby Devon has committed to transport or process certain volumes of oil, gas and NGLs for a fixed fee. Devon has entered into these agreements to aid the movement of its production to market.

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 $42 million, $57 million and $56 million in 2011, 2010 and 2009, respectively.

19. Fair Value Measurements

The following tables provide carrying value and fair value measurement information for Devon’s financial assets and liabilities. The carrying values of cash, accounts receivable, other current receivables, accounts payable, other payables and accrued expenses included in the accompanying balance sheets approximated fair value at December 31, 2011 and December 31, 2010. These assets and liabilities are not presented in the following table. Additionally, information regarding the fair values of Devon’s pension plan assets is provided in Note 16.

	Carrying Amount			Total Fair Value			Fair Value Measurements Using:
							Level 1   Inputs		Level 2   Inputs			Level 3   Inputs
	(In millions)
December 31, 2011 assets (liabilities):
Cash equivalents	$	5,123		$	5,123		$	1,369	$	3,754		$	—
Short-term investments	$	1,503		$	1,503		$	490	$	1,013		$	—
Long-term investments	$	84		$	84		$	—	$	—		$	84
Commodity derivatives	$	628		$	628		$	—	$	628		$	—
Commodity derivatives	$	(82	)	$	(82	)	$	—	$	(82	)	$	—
Interest rate derivatives	$	52		$	52		$	—	$	52		$	—
Debt	$	(9,780	)	$	(11,380	)	$	—	$	(11,295	)	$	(85	)

	Carrying Amount			Total Fair Value			Fair Value Measurements Using:
							Level 1 Inputs		Level 2 Inputs			Level 3 Inputs
	(In millions)
December 31, 2010 assets (liabilities):
Cash equivalents	$	2,335		$	2,335		$	2,335	$	—		$	—
Short-term investments	$	145		$	145		$	145	$	—		$	—
Long-term investments	$	94		$	94		$	—	$	—		$	94
Commodity derivatives	$	249		$	249		$	—	$	249		$	—
Commodity derivatives	$	(192	)	$	(192	)	$	—	$	(192	)	$	—
Interest rate derivatives	$	140		$	140		$	—	$	140		$	—
Debt	$	(5,630	)	$	(6,629	)	$	—	$	(6,485	)	$	(144	)

The following methods and assumptions were used to estimate the fair values in the tables above.

Level 1 Fair Value Measurements

Cash equivalents and short-term investments — Amounts consist primarily of U.S. and Canadian Treasury bills and money market investments. The fair value approximates the carrying value.

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Level 2 Fair Value Measurements

Cash equivalents and short-term investments — Amounts consist primarily of commercial paper investments. The fair value is based upon quotes from brokers, which generally approximate the carrying value.

Commodity and interest rate derivatives — The fair values of commodity and interest rate derivatives are estimated using internal discounted cash flow calculations based upon forward curves and quotes obtained from brokers for contracts with similar terms or quotes obtained from counterparties to the agreements.

Debt — Devon’s debt instruments do not actively trade in an established market. The fair values of its fixed-rate debt are estimated based on rates available for debt with similar terms and maturity. The fair value of Devon’s variable-rate commercial paper borrowings is the carrying value.

Level 3 Fair Value Measurements

Debt — Devon’s Level 3 debt consisted of a non-interest bearing promissory note. Due to the lack of an active market, quoted marked prices for this note were not available. Therefore, Devon used valuation techniques that rely on unobservable inputs to estimate the fair value of its promissory note. The fair value of this debt is estimated using internal discounted cash flow calculations based upon estimated future payment schedules and a 3.125% interest rate. As a result of using these inputs, Devon concluded the estimated fair value of its non-interest bearing promissory note approximated the carrying value as of December 31, 2011 and December 31, 2010.

Long-term investments — Devon’s long-term investments presented in the tables above consisted entirely of auction rate securities. Due to auction failures and the lack of an active market for Devon’s auction rate securities, quoted market prices for these securities were not available. Therefore, Devon used valuation techniques that rely on unobservable inputs to estimate the fair values of its long-term auction rate securities. These inputs were based on the AAA credit rating of the securities, the probability of full repayment of the securities considering the U.S. government guarantees substantially all of the underlying student loans, the collection of all accrued interest to date and continued receipts of principal at par. As a result of using these inputs, Devon concluded the estimated fair values of its long-term auction rate securities approximated the par values as of December 31, 2011 and December 31, 2010.

Included below is a summary of the changes in Devon’s Level 3 fair value measurements.

	Year Ended December 31,
	2011			2010
	(In millions)
Long-term investments balance at beginning of period	$	94		$	115
Redemptions of principal		(10	)		(21	)
Long-term investments balance at end of period	$	84		$	94
Debt balance at beginning of period	$	(144	)	$	—
Issuance of promissory note		—			(139	)
Foreign exchange translation adjustment		1			(9	)
Accretion of promissory note		(5	)		(3	)
Redemptions of principal		63			7
Debt balance at end of period	$	(85	)	$	(144	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

20. Discontinued Operations

For the three-year period ended December 31, 2011, Devon’s discontinued operations included amounts related to its assets in Azerbaijan, Brazil, China, Angola and other minor International properties. By the end of 2011, Devon had sold all these assets except for its assets in Angola. Devon has entered into an agreement to sell its Angolan assets. Upon closing, Devon will receive $70 million and the right to future contingent consideration based on achievement of certain objectives.

Revenues related to Devon’s discontinued operations totaled $43 million, $693 million and $945 million during 2011, 2010 and 2009, respectively. Earnings from discontinued operations before income taxes totaled $2.6 billion, $2.4 billion and $322 million during 2011, 2010 and 2009, respectively. Earnings before income taxes in 2011 and 2010 were largely impacted by gains on divestiture transactions. The following table presents the gains on the divestitures by year.

	Year Ended December 31,
	2011				2010						2009
	Gross		After Tax		Gross			After Tax			Gross		After Tax
	(In millions)
Brazil	$	2,548	$	2,548	$	—		$	—		$	—	$	—
Azerbaijan		—		—		1,543			1,524			—		—
China — Panyu		—		—		308			235			—		—
Other		4		4		(33	)		(27	)		17		17
Total	$	2,552	$	2,552	$	1,818		$	1,732		$	17	$	17

The following table presents the main classes of assets and liabilities associated with Devon’s discontinued operations.

	December 31,
	2011		2010
	(In millions)
Cash and cash equivalents	$	—	$	424
Other current assets		21		139
Current assets	$	21	$	563
Property and equipment, net	$	132	$	859
Accounts payable	$	20	$	260
Other current liabilities		28		45
Current liabilities	$	48	$	305
Other long-term liabilities	$	—	$	26

Reduction of Carrying Value of Oil and Gas Properties

During 2009, Devon reduced the carrying value of its Brazil oil and gas properties by $109 million ($105 million after tax). This reduction resulted largely from an exploratory well drilled at the BM-BAR-3 block in the offshore Barreirinhas Basin that did not have adequate reserves for commercial viability.

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21. Segment Information

Devon manages its operations through distinct operating segments, or divisions, which are defined primarily by geographic areas. For financial reporting purposes, Devon aggregates its U.S. divisions into one reporting segment due to the similar nature of the businesses. However, Devon’s Canadian division is reported as a separate reporting segment primarily due to the significant differences in the regulatory environment. Devon’s segments are all primarily engaged in oil and gas producing activities, and certain information regarding such activities for each segment is included in Note 22. Following is certain financial information regarding Devon’s segments. Revenues are all from external customers.

	U.S.			Canada		Total
	(In millions)
Year Ended December 31, 2011:
Oil, gas and NGL sales	$	5,418		$	2,897	$	8,315
Oil, gas and NGL derivatives	$	881		$	—	$	881
Marketing and midstream revenues	$	2,059		$	199	$	2,258
Interest expense	$	204		$	148	$	352
Depreciation, depletion and amortization	$	1,439		$	809	$	2,248
Earnings from continuing operations before income taxes	$	3,477		$	813	$	4,290
Income tax expense	$	1,958		$	198	$	2,156
Earnings from continuing operations	$	1,519		$	615	$	2,134
Property and equipment, net	$	16,989		$	7,785	$	24,774
Total continuing assets(1)	$	22,622		$	18,342	$	40,964
Capital expenditures	$	6,112		$	1,708	$	7,820
Year Ended December 31, 2010:
Oil, gas and NGL sales	$	4,742		$	2,520	$	7,262
Oil, gas and NGL derivatives	$	809		$	2	$	811
Marketing and midstream revenues	$	1,742		$	125	$	1,867
Interest expense	$	159		$	204	$	363
Depreciation, depletion and amortization	$	1,229		$	701	$	1,930
Earnings from continuing operations before income taxes	$	2,943		$	625	$	3,568
Income tax expense	$	1,062		$	173	$	1,235
Earnings from continuing operations	$	1,881		$	452	$	2,333
Property and equipment, net	$	12,379		$	7,273	$	19,652
Total continuing assets (1)	$	18,320		$	13,185	$	31,505
Capital expenditures	$	5,007		$	2,107	$	7,114
Year Ended December 31, 2009:
Oil, gas and NGL sales	$	3,958		$	2,139	$	6,097
Oil, gas and NGL derivatives	$	382		$	2	$	384
Marketing and midstream revenues	$	1,498		$	36	$	1,534
Interest expense	$	125		$	224	$	349
Depreciation, depletion and amortization	$	1,498		$	610	$	2,108
(Loss) earnings from continuing operations before income taxes	$	(4,961	)	$	435	$	(4,526	)
Income tax (benefit) expense	$	(1,894	)	$	121	$	(1,773	)
(Loss) earnings from continuing operations	$	(3,067	)	$	314	$	(2,753	)
Reduction of carrying value of oil and gas properties	$	6,408		$	—	$	6,408
Capital expenditures	$	3,584		$	1,099	$	4,683

(1) Total assets in the table above do not include assets held for sale related to Devon’s discontinued operations, which totaled $153 million, $1.4 billion, and $1.9 billion in 2011, 2010 and 2009, respectively.

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

Supplemental unaudited information regarding Devon’s oil and gas activities is presented in this note. The information is provided separately by country and continent. Additionally, the costs incurred and reserves information for the U.S. is segregated between Devon’s onshore and offshore operations. Unless otherwise noted, this supplemental information excludes amounts for all periods presented related to Devon’s discontinued operations.

Costs Incurred

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

	Year Ended December 31, 2011
	U.S. Onshore		U.S. Offshore		Total U.S.		Canada		North America
	(In millions)
Property acquisition costs:
Proved properties	$	34	$	—	$	34	$	14	$	48
Unproved properties		851		—		851		88		939
Exploration costs		272		—		272		266		538
Development costs		4,130		—		4,130		1,288		5,418
Costs incurred	$	5,287	$	—	$	5,287	$	1,656	$	6,943

	Year Ended December 31, 2010
	U.S. Onshore		U.S. Offshore		Total U.S.		Canada		North America
	(In millions)
Property acquisition costs:
Proved properties	$	29	$	—	$	29	$	4	$	33
Unproved properties		592		2		594		590		1,184
Exploration costs		339		89		428		260		688
Development costs		3,126		297		3,423		1,216		4,639
Costs incurred	$	4,086	$	388	$	4,474	$	2,070	$	6,544

	Year Ended December 31, 2009
	U.S. Onshore		U.S. Offshore		Total U.S.		Canada		North America
	(In millions)
Property acquisition costs:
Proved properties	$	17	$	—	$	17	$	18	$	35
Unproved properties		52		11		63		72		135
Exploration costs		122		260		382		152		534
Development costs		2,011		537		2,548		835		3,383
Costs incurred	$	2,202	$	808	$	3,010	$	1,077	$	4,087

Pursuant to the full cost method of accounting, Devon capitalizes certain of its general and administrative expenses that are related to property acquisition, exploration and development activities. Such capitalized expenses, which are included in the costs shown in the preceding tables, were $337 million, $311 million and

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$332 million in the years 2011, 2010 and 2009, 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 $45 million, $37 million and $74 million in the years 2011, 2010 and 2009, respectively.

Capitalized Costs

The following tables reflect the aggregate capitalized costs related to oil and gas activities.

	December 31, 2011
	U.S.			Canada			North America
	(In millions)
Proved properties	$	41,397		$	20,299		$	61,696
Unproved properties		2,347			1,635			3,982
Total oil & gas properties		43,744			21,934			65,678
Accumulated DD&A		(29,742	)		(14,585	)		(44,327	)
Net capitalized costs	$	14,002		$	7,349		$	21,351

	December 31, 2010
	U.S.			Canada			North America
	(In millions)
Proved properties	$	36,301		$	19,711		$	56,012
Unproved properties		2,156			1,278			3,434
Total oil & gas properties		38,457			20,989			59,446
Accumulated DD&A		(28,546	)		(14,130	)		(42,676	)
Net capitalized costs	$	9,911		$	6,859		$	16,770

The following is a summary of Devon’s oil and gas properties not subject to amortization as of December 31, 2011.

	Costs Incurred In
	2011		2010		2009		Prior to 2009		Total
	(In millions)
Acquisition costs	$	894	$	1,101	$	112	$	1,037	$	3,144
Exploration costs		234		81		6		11		332
Development costs		359		72		1		9		441
Capitalized interest		43		22		—		—		65
Total oil and gas properties not subject to amortization	$	1,530	$	1,276	$	119	$	1,057	$	3,982

Results of Operations

The following tables include revenues and expenses directly associated 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

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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.

	Year Ended December 31, 2011
	U.S.			Canada			North America
	(In millions)
Oil, gas and NGL sales	$	5,418		$	2,897		$	8,315
Lease operating expenses		(925	)		(926	)		(1,851	)
Depreciation, depletion and amortization		(1,201	)		(786	)		(1,987	)
General and administrative expenses		(132	)		(119	)		(251	)
Taxes other than income taxes		(357	)		(45	)		(402	)
Accretion of asset retirement obligations		(34	)		(57	)		(91	)
Income tax expense		(1,005	)		(250	)		(1,255	)
Results of operations	$	1,764		$	714		$	2,478
Depreciation, depletion and amortization per Boe	$	6.94		$	11.74		$	8.28

	Year Ended December 31, 2010
	U.S.			Canada			North America
	(In millions)
Oil, gas and NGL sales	$	4,742		$	2,520		$	7,262
Lease operating expenses		(892	)		(797	)		(1,689	)
Depreciation, depletion and amortization		(998	)		(677	)		(1,675	)
General and administrative expenses		(133	)		(83	)		(216	)
Taxes other than income taxes		(319	)		(40	)		(359	)
Accretion of asset retirement obligations		(42	)		(50	)		(92	)
Income tax expense		(849	)		(246	)		(1,095	)
Results of operations	$	1,509		$	627		$	2,136
Depreciation, depletion and amortization per Boe	$	6.11		$	10.51		$	7.36

	Year Ended December 31, 2009
	U.S.			Canada			North America
	(In millions)
Oil, gas and NGL sales	$	3,958		$	2,139		$	6,097
Lease operating expenses		(997	)		(673	)		(1,670	)
Depreciation, depletion and amortization		(1,247	)		(585	)		(1,832	)
General and administrative expenses		(145	)		(74	)		(219	)
Taxes other than income taxes		(258	)		(35	)		(293	)
Reduction of carrying value of oil and gas properties		(6,408	)		—			(6,408	)
Accretion of asset retirement obligations		(53	)		(38	)		(91	)
Income tax benefit		1,800			(210	)		1,580
Results of operations	$	(3,350	)	$	524		$	(2,836	)
Depreciation, depletion and amortization per Boe	$	7.47		$	8.84		$	7.86

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Proved Reserves

The following tables present Devon’s estimated proved reserves by product for each significant country.

	Oil (MMBbls)
	U.S. Onshore			U.S. Offshore			Total U.S.			Canada			North America
Proved developed and undeveloped reserves:
December 31, 2008		133			34			167			134			301
Revisions due to prices		9			2			11			291			302
Revisions other than price		—			1			1			(8	)		(7	)
Extensions and discoveries		9			2			11			122			133
Production		(12	)		(5	)		(17	)		(25	)		(42	)
Sale of reserves		—			(1	)		(1	)		—			(1	)
December 31, 2009		139			33			172			514			686
Revisions due to prices		4			1			5			(24	)		(19	)
Revisions other than price		2			2			4			9			13
Extensions and discoveries		19			1			20			59			79
Production		(14	)		(2	)		(16	)		(25	)		(41	)
Sale of reserves		(2	)		(35	)		(37	)		—			(37	)
December 31, 2010		148			—			148			533			681
Revisions due to prices		2			—			2			(15	)		(13	)
Revisions other than price		(1	)		—			(1	)		11			10
Extensions and discoveries		36			—			36			36			72
Production		(17	)		—			(17	)		(28	)		(45	)
December 31, 2011		168			—			168			537			705
Proved developed reserves as of:
December 31, 2008		111			22			133			110			243
December 31, 2009		119			21			140			149			289
December 31, 2010		131			—			131			126			257
December 31, 2011		146			—			146			163			309
Proved developed-producing reserves as of:
December 31, 2008		103			9			112			91			203
December 31, 2009		112			12			124			137			261
December 31, 2010		123			—			123			116			239
December 31, 2011		139			—			139			155			294
Proved undeveloped reserves as of:
December 31, 2008		22			12			34			24			58
December 31, 2009		20			12			32			365			397
December 31, 2010		17			—			17			407			424
December 31, 2011		22			—			22			374			396

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	Gas (Bcf)
	U.S. Onshore			U.S. Offshore			Total U.S.			Canada			North America
Proved developed and undeveloped reserves:
December 31, 2008		7,979			390			8,369			1,510			9,879
Revisions due to prices		(661	)		(4	)		(665	)		(29	)		(694	)
Revisions other than price		119			(62	)		57			(14	)		43
Extensions and discoveries		1,387			64			1,451			67			1,518
Purchase of reserves		1			—			1			6			7
Production		(698	)		(45	)		(743	)		(223	)		(966	)
Sale of reserves		—			(1	)		(1	)		(29	)		(30	)
December 31, 2009		8,127			342			8,469			1,288			9,757
Revisions due to prices		449			2			451			21			472
Revisions other than price		105			(26	)		79			(17	)		62
Extensions and discoveries		1,088			7			1,095			131			1,226
Purchase of reserves		12			—			12			9			21
Production		(699	)		(17	)		(716	)		(214	)		(930	)
Sale of reserves		(17	)		(308	)		(325	)		—			(325	)
December 31, 2010		9,065			—			9,065			1,218			10,283
Revisions due to prices		(1	)		—			(1	)		(60	)		(61	)
Revisions other than price		(243	)		—			(243	)		(38	)		(281	)
Extensions and discoveries		1,410			—			1,410			58			1,468
Purchase of reserves		16			—			16			20			36
Production		(740	)		—			(740	)		(213	)		(953	)
Sale of reserves		—			—			—			(6	)		(6	)
December 31, 2011		9,507			—			9,507			979			10,486
Proved developed reserves as of:
December 31, 2008		6,469			212			6,681			1,357			8,038
December 31, 2009		6,447			185			6,632			1,213			7,845
December 31, 2010		7,280			—			7,280			1,144			8,424
December 31, 2011		7,957			—			7,957			951			8,908
Proved developed-producing reserves as of:
December 31, 2008		5,787			64			5,851			1,194			7,045
December 31, 2009		5,860			137			5,997			1,075			7,072
December 31, 2010		6,702			—			6,702			1,031			7,733
December 31, 2011		7,409			—			7,409			862			8,271
Proved undeveloped reserves as of:
December 31, 2008		1,510			178			1,688			153			1,841
December 31, 2009		1,680			157			1,837			75			1,912
December 31, 2010		1,785			—			1,785			74			1,859
December 31, 2011		1,550			—			1,550			28			1,578

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	Natural Gas Liquids (MMBbls)
	U.S. Onshore			U.S. Offshore			Total U.S.			Canada			North America
Proved developed and undeveloped reserves:
December 31, 2008		315			2			317			35			352
Revisions due to prices		(11	)		—			(11	)		2			(9	)
Revisions other than price		36			1			37			—			37
Extensions and discoveries		70			—			70			1			71
Production		(25	)		(1	)		(26	)		(4	)		(30	)
December 31, 2009		385			2			387			34			421
Revisions due to prices		14			—			14			(1	)		13
Revisions other than price		13			3			16			(1	)		15
Extensions and discoveries		68			—			68			2			70
Production		(28	)		—			(28	)		(4	)		(32	)
Sale of reserves		(3	)		(5	)		(8	)		—			(8	)
December 31, 2010		449			—			449			30			479
Revisions due to prices		4			—			4			(1	)		3
Revisions other than price		1			—			1			—			1
Extensions and discoveries		102			—			102			2			104
Purchase of reserves		2			—			2			—			2
Production		(33	)		—			(33	)		(4	)		(37	)
December 31, 2011		525			—			525			27			552
Proved developed reserves as of:
December 31, 2008		260			1			261			31			292
December 31, 2009		293			1			294			32			326
December 31, 2010		353			—			353			28			381
December 31, 2011		402			—			402			26			428
Proved developed-producing reserves as of:
December 31, 2008		230			—			230			29			259
December 31, 2009		265			1			266			28			294
December 31, 2010		318			—			318			26			344
December 31, 2011		372			—			372			24			396
Proved undeveloped reserves as of:
December 31, 2008		55			1			56			4			60
December 31, 2009		92			1			93			2			95
December 31, 2010		96			—			96			2			98
December 31, 2011		123			—			123			1			124

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	Total (MMBoe)(1)
	U.S. Onshore			U.S. Offshore			Total U.S.			Canada			North America
Proved developed and undeveloped reserves:
December 31, 2008		1,777			101			1,878			421			2,299
Revisions due to prices		(113	)		1			(112	)		289			177
Revisions other than price		57			(8	)		49			(11	)		38
Extensions and discoveries		311			12			323			135			458
Purchase of reserves		—			—			—			1			1
Production		(154	)		(13	)		(167	)		(66	)		(233	)
Sale of reserves		—			(1	)		(1	)		(6	)		(7	)
December 31, 2009		1,878			92			1,970			763			2,733
Revisions due to prices		92			1			93			(21	)		72
Revisions other than price		32			1			33			5			38
Extensions and discoveries		269			2			271			83			354
Purchase of reserves		2			—			2			2			4
Production		(158	)		(5	)		(163	)		(65	)		(228	)
Sale of reserves		(8	)		(91	)		(99	)		(1	)		(100	)
December 31, 2010		2,107			—			2,107			766			2,873
Revisions due to prices		6			—			6			(27	)		(21	)
Revisions other than price		(41	)		—			(41	)		6			(35	)
Extensions and discoveries		374			—			374			47			421
Purchase of reserves		5			—			5			3			8
Production		(173	)		—			(173	)		(67	)		(240	)
Sale of reserves		—			—			—			(1	)		(1	)
December 31, 2011		2,278			—			2,278			727			3,005
Proved developed reserves as of:
December 31, 2008		1,449			59			1,508			367			1,875
December 31, 2009		1,486			53			1,539			383			1,922
December 31, 2010		1,696			—			1,696			346			2,042
December 31, 2011		1,875			—			1,875			348			2,223
Proved developed-producing reserves as of:
December 31, 2008		1,298			20			1,318			319			1,637
December 31, 2009		1,354			35			1,389			344			1,733
December 31, 2010		1,557			—			1,557			314			1,871
December 31, 2011		1,746			—			1,746			323			2,069
Proved undeveloped reserves as of:
December 31, 2008		328			42			370			54			424
December 31, 2009		392			39			431			380			811
December 31, 2010		411			—			411			420			831
December 31, 2011		403			—			403			379			782

(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 gas and oil. This rate is not necessarily indicative of the relationship of natural gas and oil prices. Natural gas liquids reserves are converted to Boe on a one-to-one basis with oil.

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Proved Undeveloped Reserves

The following table presents the changes in our total proved undeveloped reserves during 2011 (in MMBoe).

	U.S. Onshore			Canada			North America
Proved undeveloped reserves as of December 31, 2010		411			420			831
Extensions and discoveries		118			30			148
Revisions due to prices		(2	)		(14	)		(16	)
Revisions other than price		(56	)		5			(51	)
Conversion to proved developed reserves		(68	)		(62	)		(130	)
Proved undeveloped reserves as of December 31, 2011		403			379			782

At December 31, 2011, Devon had 782 MMBoe of proved undeveloped reserves. This represents a 6% decrease as compared to 2010 and represents 26% of its total proved reserves. Drilling activities increased Devon’s proved undeveloped reserves 148 MMBoe and resulted in the conversion of 130 MMBoe, or 16%, of the 2010 proved undeveloped reserves to proved developed reserves. Additionally, revisions other than price decreased Devon’s proved undeveloped reserves 51 MMBoe primarily due to its evaluation of certain U.S. onshore dry-gas areas, which it does not expect to develop in the next five years. The largest revisions relate to the dry-gas areas at Carthage in east Texas and the Barnett Shale in north Texas.

A significant amount of Devon’s proved undeveloped reserves at the end of 2011 largely related to its Jackfish operations. At December 31, 2011 and 2010, Devon’s Jackfish proved undeveloped reserves were 367 MMBoe and 396 MMBoe, respectively. Development schedules for the Jackfish reserves are primarily controlled by the need to keep the processing plants at their 35,000 barrel daily facility capacity. Processing plant capacity is controlled by factors such as total steam processing capacity, steam-oil ratios and air quality discharge permits. As a result, these reserves are classified as proved undeveloped for more than five years. Currently, the development schedule for these reserves extends though the year 2025.

Price Revisions

2011—Reserves decreased 21 MMBoe due to lower gas prices and higher oil prices. The higher oil prices increased Devon’s Canadian royalty burden, which reduced Devon’s oil reserves.

2010—Reserves increased 72 MMBoe due to higher gas prices, partially offset by the effect of higher oil prices. The higher oil prices increased Devon’s Canadian royalty burden, which reduced Devon’s oil reserves. Of the 72 MMBoe price revisions, 43 MMBoe related to the Barnett Shale and 22 MMBoe related to the Rocky Mountain area.

2009—Reserves increased 177 MMBoe due to higher oil prices, partially offset by lower gas prices. The increase in oil reserves primarily related to Devon’s Jackfish thermal heavy oil reserves in Canada. At the end of 2008, 331 MMBoe of reserves related to Jackfish were not considered proved. However, due to higher prices, these reserves were considered proved as of December 31, 2009. Significantly lower gas prices caused Devon’s reserves to decrease 116 MMBoe, which primarily related to its U.S. reserves.

Revisions Other Than Price

Total revisions other than price for 2011 primarily related to Devon’s evaluation of certain dry gas regions noted in the proved undeveloped reserves discussion above. Total revisions other than price for 2010 and 2009 primarily related to Devon’s drilling and development in the Barnett Shale.

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Extensions and Discoveries

2011 — Of the 421 MMBoe of 2011 extensions and discoveries, 162 MMBoe related to the Cana-Woodford Shale in western Oklahoma, 115 MMBoe related to the Barnett Shale, 39 MMBoe related to the Permian Basin, 30 MMBoe related to Jackfish, 19 MMBoe related to the Rocky Mountain area and 17 MMBoe related to the Granite Wash area in the Texas panhandle and western Oklahoma.

The 2011 extensions and discoveries included 168 MMBoe related to additions from Devon’s infill drilling activities, including 80 MMBoe at the Cana-Woodford Shale and 77 MMBoe at the Barnett Shale.

2010 — Of the 354 MMBoe of 2010 extensions and discoveries, 101 MMBoe related to the Cana-Woodford Shale, 87 MMBoe related to the Barnett Shale, 55 MMBoe related to Jackfish, 19 MMBoe related to the Permian Basin, 15 MMBoe related to the Rocky Mountain area and 14 MMBoe related to the Carthage area.

The 2010 extensions and discoveries included 107 MMBoe related to additions from Devon’s infill drilling activities, including 43 MMBoe at the Barnett Shale and 47 MMBoe at the Cana-Woodford Shale.

2009 — Of the 458 MMBoe of 2009 extensions and discoveries, 204 MMBoe related to the Barnett Shale, 118 MMBoe related to Jackfish, 49 MMBoe related to the Cana-Woodford Shale, 14 MMBoe related to the Rocky Mountain area, 11 MMBoe related to Deepwater Production in the Gulf, 8 MMBoe related to the Carthage area and 7 MMBoe related to the Haynesville Shale area in east Texas.

The 2009 extensions and discoveries included 371 MMBoe related to additions from Devon’s infill drilling activities, including 203 MMBoe at the Barnett Shale, 118 MMBoe at Jackfish and 24 MMBoe at the Cana-Woodford Shale.

Sale of Reserves

The 2010 total primarily relates to the divestiture of Devon’s Gulf of Mexico properties.

SEC’s Modernization of Oil and Gas Reporting

At the end of 2009, Devon adopted the SEC’s Modernization of Oil and Gas Reporting, as well as the conforming rule changes issued by the Financial Accounting Standards Board. Upon adoption, the two primary rule changes that impacted Devon’s year-end reserves estimates were those related to assumptions for pricing and reasonable certainty.

The SEC’s prior rules required proved reserve estimates to be calculated using prices as of the end of the period and held constant over the life of the reserves. The revised rules require reserves estimates to be calculated using an average of the first-day-of-the-month price for the preceding 12-month period.

The revised rules amend the definition of proved reserves to permit the use of reliable technologies to establish the reasonable certainty of proved reserves. This revision includes provisions for establishing levels of lowest known hydrocarbons and highest known oil through reliable technology other than well penetrations. This revision also allows proved reserves to be claimed beyond development spacing areas that are immediately adjacent to developed spacing areas if economic producibility can be established with reasonable certainty based on reliable technologies. As a result of adopting these provisions of the new rules, Devon’s 2009 reserves increased approximately 65 MMBoe, or 2%. This increase is included in the 2009 extensions and discoveries total.

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Standardized Measure

The tables below reflect Devon’s standardized measure of discounted future net cash flows from its proved reserves.

	Year Ended December 31, 2011
	U.S.			Canada			North America
	(In millions)
Future cash inflows	$	69,305		$	36,786		$	106,091
Future costs:
Development		(6,817	)		(4,678	)		(11,495	)
Production		(26,217	)		(15,063	)		(41,280	)
Future income tax expense		(11,432	)		(3,763	)		(15,195	)
Future net cash flows		24,839			13,282			38,121
10% discount to reflect timing of cash flows		(13,492	)		(6,785	)		(20,277	)
Standardized measure of discounted future net cash flows	$	11,347		$	6,497		$	17,844

	Year Ended December 31, 2010
	U.S.			Canada			North America
	(In millions)
Future cash inflows	$	58,093		$	35,948		$	94,041
Future costs:
Development		(6,220	)		(4,526	)		(10,746	)
Production		(24,223	)		(12,249	)		(36,472	)
Future income tax expense		(8,643	)		(4,209	)		(12,852	)
Future net cash flows		19,007			14,964			33,971
10% discount to reflect timing of cash flows		(10,164	)		(7,455	)		(17,619	)
Standardized measure of discounted future net cash flows	$	8,843		$	7,509		$	16,352

	Year Ended December 31, 2009
	U.S.			Canada			North America
	(In millions)
Future cash inflows	$	44,571		$	28,442		$	73,013
Future costs:
Development		(6,814	)		(4,132	)		(10,946	)
Production		(22,184	)		(9,847	)		(32,031	)
Future income tax expense		(3,572	)		(3,408	)		(6,980	)
Future net cash flows		12,001			11,055			23,056
10% discount to reflect timing of cash flows		(6,121	)		(5,532	)		(11,653	)
Standardized measure of discounted future net cash flows	$	5,880		$	5,523		$	11,403

Future cash inflows, development costs and production costs were computed using the same assumptions for prices and costs that were used to estimate Devon’s proved oil and gas reserves at the end of each year. For 2011, the prices averaged $67.31 per barrel of oil, $3.51 per Mcf of gas and $39.28 per barrel of natural gas liquids. Of the $11.5 billion of future development costs as of the end of 2011, $1.6 billion, $1.4 billion and $1.1 billion are estimated to be spent in 2012, 2013 and 2014, respectively.

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Future development costs include not only development costs, but also future asset retirement costs. Included as part of the $11.5 billion of future development costs are $2.2 billion of future asset retirement 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.

The principal changes in Devon’s standardized measure of discounted future net cash flows are as follows:

	Year Ended December 31,
	2011			2010			2009
	(In millions)
Beginning balance	$	16,352		$	11,403		$	9,393
Oil, gas and NGL sales, net of production costs		(5,794	)		(4,982	)		(3,915	)
Net changes in prices and production costs		1,875			7,423			(1,672	)
Extensions and discoveries, net of future development costs		3,714			3,048			2,378
Purchase of reserves, net of future development costs		57			23			6
Development costs incurred that reduced future development costs		1,302			1,559			1,012
Revisions of quantity estimates		(668	)		287			4,051
Sales of reserves in place		(2	)		(815	)		(37	)
Accretion of discount		2,248			1,487			1,281
Net change in income taxes		(929	)		(2,663	)		(51	)
Other, primarily changes in timing and foreign exchange rates		(311	)		(418	)		(1,043	)
Ending balance	$	17,844		$	16,352		$	11,403

The following table presents Devon’s estimated pretax cash flow information related to its proved reserves.

	Year Ended December 31, 2011
	U.S.		Canada		North America
	(In millions)
Pre-Tax Future Net Revenue(1)
Proved Developed Reserves	$	30,473	$	7,757	$	38,230
Proved Undeveloped Reserves		5,798		9,288		15,086
Total Proved Reserves	$	36,271	$	17,045	$	53,316
Pre-Tax 10% Present Value(1)
Proved Developed Reserves	$	15,165	$	5,830	$	20,995
Proved Undeveloped Reserves		1,404		2,508		3,912
Total Proved Reserves	$	16,569	$	8,338	$	24,907

(1) Estimated pre-tax 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 depreciation, depletion and amortization, or to non-property related expenses such as debt service and income tax expense.

The present value of after-tax future net revenues discounted at 10% per annum (“standardized measure”) was $17.8 billion at the end of 2011. Included as part of standardized measure were discounted future income taxes of $7.1 billion. Excluding these taxes, the present value of our pre-tax future net revenue

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(“pre-tax 10% present value”) was $24.9 billion. Devon believes the pre-tax 10% present value is a useful measure in addition to the after-tax standardized measure. The pre-tax 10% present value 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 after-tax 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 more consistent from company to company.

23. Supplemental Quarterly Financial Information (Unaudited)

Following is a summary of Devon’s unaudited interim results of operations.

	2011
	First Quarter		Second Quarter		Third Quarter			Fourth Quarter			Full Year
	(In millions, except per share amounts)
Revenues	$	2,147	$	3,220	$	3,502		$	2,585		$	11,454
Earnings from continuing operations before income taxes	$	580	$	1,378	$	1,538		$	794		$	4,290
Earnings from continuing operations	$	389	$	184	$	1,040		$	521		$	2,134
Earnings (loss) from discontinued operations		27		2,559		(2	)		(14	)		2,570
Net earnings	$	416	$	2,743	$	1,038		$	507		$	4,704
Basic net earnings per common share:
Earnings from continuing operations	$	0.91	$	0.44	$	2.51		$	1.29		$	5.12
Earnings (loss) from discontinued operations		0.06		6.06		—			(0.04	)		6.17
Net earnings	$	0.97	$	6.50	$	2.51		$	1.25		$	11.29
Diluted net earnings per common share:
Earnings from continuing operations	$	0.91	$	0.43	$	2.50		$	1.29		$	5.10
Earnings (loss) from discontinued operations		0.06		6.05		—			(0.04	)		6.15
Net earnings	$	0.97	$	6.48	$	2.50		$	1.25		$	11.25

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	2010
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Full Year
	(In millions, except per share amounts)
Revenues	$	3,220	$	2,232	$	2,353	$	2,135	$	9,940
(Loss) earnings from continuing operations before income taxes	$	1,588	$	613	$	699	$	668	$	3,568
(Loss) earnings from continuing operations	$	1,074	$	352	$	429	$	478	$	2,333
(Loss) earnings from discontinued operations		118		354		1,661		84		2,217
Net (loss) earnings	$	1,192	$	706	$	2,090	$	562	$	4,550
Basic net (loss) earnings per common share:
(Loss) earnings from continuing operations	$	2.40	$	0.79	$	0.99	$	1.10	$	5.31
(Loss) earnings from discontinued operations		0.27		0.80		3.82		0.20		5.04
Net (loss) earnings	$	2.67	$	1.59	$	4.81	$	1.30	$	10.35
Diluted net (loss) earnings per common share:
(Loss) earnings from continuing operations	$	2.39	$	0.79	$	0.98	$	1.10	$	5.29
(Loss) earnings from discontinued operations		0.27		0.79		3.81		0.19		5.02
Net (loss) earnings	$	2.66	$	1.58	$	4.79	$	1.29	$	10.31

Earnings (Loss) from Continuing Operations

The second quarter of 2011 includes deferred income taxes of $725 million (or $1.71 per diluted share) related to assumed repatriations of foreign earnings that were no longer deemed to be permanently reinvested in accordance with accounting principles generally accepted in the U.S.

Earnings (Loss) from Discontinued Operations

The second quarter of 2011 includes the divestiture of our Brazil operations and the related gain was $2.5 billion ($2.5 billion after income taxes, or $6.01 per diluted share).

The second quarter of 2010 includes the divestiture of our Panyu operations in China and the related gain was $308 million ($235 million after income taxes, or $0.52 per diluted share).

The third quarter of 2010 includes the divestiture of our Azerbaijan operations and the related gain was $1.5 billion ($1.5 billion after income taxes, or $3.49 per diluted share).

100

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, 2011 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 21, 2012, management concluded that its internal control over financial reporting was effective as of December 31, 2011.

The effectiveness of Devon’s internal control over financial reporting as of December 31, 2011 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, 2011, as stated in their report, which is included under “Item 8. Financial Statements and Supplementary Data” in this report.

Changes in Internal Control Over Financial Reporting

There was no change in Devon’s internal control over financial reporting during the fourth quarter of 2011 that has materially affected, or is reasonably likely to materially affect, Devon’s internal control over financial reporting.

Item 9B. Other Information

Not Applicable.

101

PART III

Item 10. Directors, Executive Officers and Corporate Governance

The information called for by this Item 10 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 29, 2012.

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 29, 2012.

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 29, 2012.

Item 13. Certain Relationships and Related Transactions, and Director Independence

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 29, 2012.

Item 14. Principal Accounting 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 29, 2012.

102

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. Financial Statements and Supplementary Data” 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
1.1	Underwriting Agreement, dated as of January 6, 2009, among Devon Energy Corporation and Banc of America Securities LLC, J.P. Morgan Securities Inc. and UBS Securities LLC, as representatives of the several Underwriters named therein (incorporated by reference to Exhibit 1.1 to Registrant’s Form 8-K filed on January 9, 2009).
1.2	Underwriting Agreement, dated as of July 5, 2011, among Devon Energy Corporation, Goldman, Sachs & Co., Morgan Stanley & Co. LLC and UBS Securities LLC, as representatives of the several Underwriters named therein (incorporated by reference to Exhibit 1.1 to Registrant’s Form 8-K filed on July 7, 2011).
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	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).
2.6	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).
3.1	Registrant’s Amended and Restated Certificate of Incorporation (incorporated by reference to Appendix A to Registrant’s Proxy Statement for the 2011 Annual Meeting of Stockholders filed on April 27, 2011).

103

Exhibit No.	Description
3.2	Registrant’s Bylaws (incorporated by reference to Exhibit 3.1 of Registrant’s Form 8-K filed on June 9, 2011).
4.1	Indenture, dated as of July 12, 2011, between Registrant and UMB Bank, National Association, as Trustee, relating to the 2.40% Senior Notes due 2016, the 4.00% Senior Notes due 2021 and the 5.60% Senior Notes due 2041 (incorporated by reference to Exhibit 4.1 to Registrant’s Form 8-K filed on July 12, 2011).
4.2	Supplemental Indenture No. 1, dated as of July 12, 2011, to Indenture dated as of July 12, 2011, between Registrant and UMB Bank, National Association, as Trustee, relating to the 2.40% Senior Notes due 2016, the 4.00% Senior Notes due 2021 and the 5.60% Senior Notes due 2041 (incorporated by reference to Exhibit 4.2 to Registrant’s Form 8-K filed on July 12, 2011).
4.3	Indenture, dated as of March 1, 2002, between Registrant and The Bank of New York Mellon Trust Company, N.A., 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).
4.4	Supplemental Indenture No. 1, dated as of March 25, 2002, to Indenture dated as of March 1, 2002, between Registrant and The Bank of New York Mellon Trust Company, N.A., 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).
4.5	Supplemental Indenture No. 3, dated as of January 9, 2009, to Indenture dated as of March 1, 2002, between Registrant and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to the 5.625% Senior Notes due 2014 and the 6.30% Senior Notes due 2019 (incorporated by reference to Exhibit 4.1 to Registrant’s Form 8-K filed on January 9, 2009).
4.6	Indenture dated as of October 3, 2001, by and among Devon Financing Corporation, U.L.C. as Issuer, Registrant as Guarantor, and The Bank of New York Mellon Trust Company, N.A., originally 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).
4.7	Indenture dated as of July 8, 1998 among Devon OEI Operating, Inc. (as successor by merger to 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)).
4.8	First Supplemental Indenture, dated March 30, 1999 to Indenture dated as of July 8, 1998 among Devon OEI Operating, Inc. (as successor by merger to 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).
4.9	Second Supplemental Indenture, dated as of May 9, 2001 to Indenture dated as of July 8, 1998 among Devon OEI Operating, Inc. (as successor by merger to 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).
4.10	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, N.A., as Trustee, relating to the 8.25% Senior Notes due 2018 (incorporated by reference to Exhibit 4.23 of Registrant’s Form 10-K for the year ended December 31, 2005).

104

Exhibit No.	Description
4.11	Senior Indenture dated September 1, 1997, among Devon OEI Operating, Inc. (as successor by merger to Ocean Energy, Inc.) and The Bank of New York Mellon Trust Company, N.A., as Trustee, and Specimen of 7.50% Senior Notes (incorporated by reference to Exhibit 4.4 to Ocean Energy’s Annual Report on Form 10-K for the year ended December 31, 1997)).
4.12	First Supplemental Indenture, dated as of March 30, 1999 to Senior Indenture dated as of September 1, 1997, among Devon OEI Operating, Inc. (as successor by merger to Ocean Energy, Inc.) and The Bank of New York Mellon Trust Company, N.A., 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).
4.13	Second Supplemental Indenture, dated as of May 9, 2001 to Senior Indenture dated as of September 1, 1997, among Devon OEI Operating, Inc. (as successor by merger to Ocean Energy, Inc.), its Subsidiary Guarantors, and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to the 7.50% Senior Notes Due 2027 (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).
4.14	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 Mellon Trust Company, N.A., as Trustee, relating to the 7.50% Senior Notes Due 2027 (incorporated by reference to Exhibit 4.27 of Registrant’s Form 10-K for the year ended December 31, 2005).
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 (incorporated by reference to Annex C to the Joint Proxy Statement/Prospectus of Form S-4 Registration Statement No. 333-68694 as filed August 30, 2001).
10.2	First Amendment to Credit Agreement dated as of December 19, 2007, among Registrant as Borrower, Bank of America, N.A., individually and as Administrative Agent and the Lenders party thereto (incorporated by reference to Exhibit 10.3 to Registrant’s Form 10-K filed February 27, 2009).
10.3	Amended and Restated Credit Agreement dated March 24, 2006, effective as of April 7, 2006, 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, N.A. 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 L.L.C. and J.P. Morgan Securities Inc., as Joint Lead Arrangers and Book Managers for the $2.0 billion five-year revolving credit facility (incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed on May 4, 2006).
10.4	First Amendment to Amended and Restated Credit Agreement dated as of June 1, 2006, among Registrant as the US Borrower, Northstar Energy Corporation and Devon Canada Corporation as the Canadian Borrowers, Bank of America, N.A., individually and as Administrative Agent and the Lenders party to this Amendment. (incorporated by reference to Exhibit 10.2 to Registrant’s Form 10-Q filed on November 7, 2007).
10.5	Second Amendment to Amended and Restated Credit Agreement dated as of September 19, 2007, among Registrant as the US Borrower, Northstar Energy Corporation and Devon Canada Corporation as the Canadian Borrowers, Bank of America, N.A., individually and as Administrative Agent and the Lenders party to this Amendment. (incorporated by reference to Exhibit 10.3 to Registrant’s Form 10-Q filed on November 7, 2007).

105

Exhibit No.	Description
10.6	Third Amendment to Amended and Restated Credit Agreement dated as of December 19, 2007, among Registrant as the US Borrower, Northstar Energy Corporation and Devon Canada Corporation as the Canadian Borrowers, Bank of America, N.A., individually and as Administrative Agent and the Lenders party thereto (incorporated by reference to Exhibit 10.7 to Registrant’s Form 10-K filed February 27, 2009).
10.7	Fourth Amendment to Amended and Restated Credit Agreement dated as of April 7, 2008, among Registrant as US Borrower, Northstar Energy Corporation and Devon Canada Corporation as the Canadian Borrowers, Bank of America, N.A., individually and as Administrative Agent and the Lenders party thereto (incorporated by reference to Exhibit 10.1 of Registrant’s Form 10-Q filed on May 7, 2008).
10.8	Fifth Amendment to Amended and Restated Credit Agreement dated as of November 5, 2008, among Registrant as US Borrower, Northstar Energy Corporation and Devon Canada Corporation as the Canadian Borrowers, Bank of America, N.A., individually and as Administrative Agent, and the Lenders party thereto (incorporated by reference to Exhibit 10.2 of Registrant’s Form 10-Q filed on November 6, 2008).
10.9	Devon Energy Corporation 2009 Long-Term Incentive Plan (incorporated by reference to Registrant’s Form S-8 Registration No. 333-159796, filed June 5, 2009).*
10.10	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).*
10.11	First Amendment to Devon Energy Corporation 2005 Long-Term Incentive Plan (incorporated by reference to Appendix A to Registrant’s Proxy Statement for the 2006 Annual Meeting of Stockholders filed on April 28, 2006).*
10.12	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).*
10.13	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).*
10.14	Devon Energy Corporation Non-Qualified Deferred Compensation Plan (amended and restated effective November 11, 2008).*
10.15	Devon Energy Corporation Benefit Restoration Plan (amended and restated effective January 1, 2012).*
10.16	Devon Energy Corporation Defined Contribution Restoration Plan (amended and restated effective January 1, 2012).*
10.17	Devon Energy Corporation Supplemental Contribution Plan (amended and restated effective January 1, 2012).*
10.18	Devon Energy Corporation Supplemental Executive Retirement Plan (amended and restated effective January 1, 2012).*
10.19	Devon Energy Corporation Supplemental Retirement Income Plan (amended and restated effective January 1, 2012).*
10.20	Devon Energy Corporation Incentive Savings Plan (incorporated by reference to Registrant’s Form S-8 Registration No. 333-179181, filed January 26, 2012).*

106

Exhibit No.	Description
10.21	Form of Amendment No. 1 to the Amended and Restated Employment Agreement, incorporated by reference to Exhibit 10.19 to Registrant’s Form 10-K filed February 27, 2009, between Registrant and Jeffrey A. Agosta, David A. Hager, R. Alan Marcum, J. Larry Nichols, John Richels, Frank W. Rudolph, Darryl G. Smette, Lyndon C. Taylor and William F. Whitsitt dated April 19, 2011. (incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K filed April 25, 2011).*
10.22	Amended and Restated Form of Employment Agreement between Registrant and Jeffrey A. Agosta, David A. Hager, R. Alan Marcum, J. Larry Nichols, John Richels, Frank W. Rudolph, Darryl G. Smette, Lyndon C. Taylor and William F. Whitsitt dated December 15, 2008 (incorporated by reference to Exhibit 10.19 to Registrant’s Form 10-K filed February 27, 2009).*
10.23	Form of Notice of Grant of Performance Restricted Stock Award and Award Agreement under the 2009 Long-Term Incentive Plan between Registrant and Jeffrey A. Agosta, David A. Hager, R. Alan Marcum, J. Larry Nichols, John Richels, Frank W. Rudolph, Darryl G. Smette, Lyndon C. Taylor and William F. Whitsitt for performance based restricted stock awarded (incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K filed on December 7, 2011).*
10.24	Form of Notice of Grant of Performance Share Unit Award and Award Agreement under the 2009 Long-Term Incentive Plan between Registrant and Jeffrey A. Agosta, David A. Hager, R. Alan Marcum, J. Larry Nichols, John Richels, Frank W. Rudolph, Darryl G. Smette, Lyndon C. Taylor and William F. Whitsitt for performance based restricted share units awarded (incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K filed on December 7, 2011).*
10.25	Form of Incentive Stock Option Award Agreement under the 2009 Long-Term Incentive Plan between Registrant and Jeffrey A. Agosta, David A. Hager, R. Alan Marcum, J. Larry Nichols, John Richels, Frank W. Rudolph, Darryl G. Smette, Lyndon C. Taylor and William F. Whitsitt for incentive stock options granted (incorporated by reference to Exhibit 10.15 to Registrant’s Form 10-K filed on February 25, 2011).*
10.26	Form of Employee Nonqualified Stock Option Award Agreement under the 2009 Long-Term Incentive Plan between Registrant and Jeffrey A. Agosta, David A. Hager, R. Alan Marcum, J. Larry Nichols, John Richels, Frank W. Rudolph, Darryl G. Smette, Lyndon C. Taylor and William F. Whitsitt for nonqualified stock options granted (incorporated by reference to Exhibit 10.16 to Registrant’s Form 10-K filed on February 25, 2011).*
10.27	Form of Non-Management Director Nonqualified Stock Option Award Agreement under the Devon Energy Corporation 2009 Long-Term Incentive Plan between Registrant and all Non-Management Directors for nonqualified stock options granted (incorporated by reference to Exhibit 10.20 to Registrant’s Form 10-K filed on February 25, 2010).*
10.28	Form of Restricted Stock Award Agreement under the 2009 Long-Term Incentive Plan between Registrant and Jeffrey A. Agosta, David A. Hager, R. Alan Marcum, J. Larry Nichols, John Richels, Frank W. Rudolph, Darryl G. Smette, Lyndon C. Taylor and William F. Whitsitt for restricted stock awards (incorporated by reference to Exhibit 10.18 to Registrant’s Form 10-K filed on February 25, 2011).*
10.29	Form of Restricted Stock Award Agreement under the 2009 Long-Term Incentive Plan between Registrant and all Non-Management Directors for restricted stock awards (incorporated by reference to Exhibit 10.22 to Registrant’s Form 10-K filed on February 25, 2010).*
10.30	Form of Letter Agreement amending the restricted stock award agreements, nonqualified stock option agreements and incentive stock option agreements under the 2009 Long-Term Incentive Plan and the 2005 Long-Term Incentive Plan between Registrant and J. Larry Nichols, John Richels and Darryl G. Smette (incorporated by reference to Exhibit 10.22 to Registrant’s Form 10-K filed on February 25, 2011).*

107

Exhibit No.	Description
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 AJM Deloitte.
31.1	Certification of principal executive officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of principal financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification of principal executive officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	Certification of principal financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1	Report of LaRoche Petroleum Consultants.
99.2	Report of AJM Deloitte.
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB	XBRL Taxonomy Extension Labels Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document

* Compensatory plans or arrangements

108

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/    JOHN RICHELS
	John Richels
	President and Chief Executive Officer

February 23, 2012

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/    JOHN RICHELS     John Richels	President, Chief Executive Officer and Director	February 23, 2012
/s/    J. LARRY NICHOLS     J. Larry Nichols	Executive Chairman and Director	February 23, 2012
/s/    JEFFREY A. AGOSTA     Jeffrey A. Agosta	Executive Vice President and Chief Financial Officer	February 23, 2012
/s/    ROBERT H. HENRY     Robert H. Henry	Director	February 23, 2012
/s/    JOHN A. HILL     John A. Hill	Director	February 23, 2012
/s/    MICHAEL M. KANOVSKY     Michael M. Kanovsky	Director	February 23, 2012
/s/    ROBERT A. MOSBACHER, JR.     Robert A. Mosbacher, Jr.	Director	February 23, 2012
/s/    DUANE C. RADTKE     Duane C. Radtke	Director	February 23, 2012
/s/    MARY P. RICCIARDELLO     Mary P. Ricciardello	Director	February 23, 2012

109

INDEX TO EXHIBITS

Exhibit No.	Description
10.14	Devon Energy Corporation Non-Qualified Deferred Compensation Plan (amended and restated effective November 11, 2008).*
10.15	Devon Energy Corporation Benefit Restoration Plan (amended and restated effective January 1, 2012).*
10.16	Devon Energy Corporation Defined Contribution Restoration Plan (amended and restated effective January 1, 2012).*
10.17	Devon Energy Corporation Supplemental Contribution Plan (amended and restated effective January 1, 2012).*
10.18	Devon Energy Corporation Supplemental Executive Retirement Plan (amended and restated effective January 1, 2012).*
10.19	Devon Energy Corporation Supplemental Retirement Income Plan (amended and restated effective January 1, 2012).*
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 AJM Deloitte.
31.1	Certification of principal executive officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of principal financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification of principal executive officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	Certification of principal financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1	Report of LaRoche Petroleum Consultants.
99.2	Report of AJM Deloitte.
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB	XBRL Taxonomy Extension Labels Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document

* Compensatory plans or arrangements

110

EX-10.14

Exhibit 10.14

Execution Copy

DEVON ENERGY CORPORATION

NON-QUALIFIED DEFERRED COMPENSATION PLAN

TABLE OF CONTENTS

	Page
ARTICLE I ESTABLISHMENT AND PURPOSE		1
1.1 Establishment		1
1.2 Purpose		1
1.3 ERISA Status		1
ARTICLE II DEFINITIONS		1
2.1 Definitions		1
2.2 Construction		5
2.3 Funding		5
ARTICLE III ELIGIBILITY AND PARTICIPATION		5
3.1 Eligibility and Participation		5
ARTICLE IV ELECTIVE DEFERRALS		6
4.1 Deferrals		6
4.2 Timing of Deferral Election		6
4.3 Election Forms		6
4.4 Hardship Withdrawal Under Qualified Plan		6
ARTICLE V SUPPLEMENTAL COMPANY CONTRIBUTIONS		7
5.1 Supplemental Company Contributions		7
ARTICLE VI PAYMENT OF BENEFITS		7
6.1 Payment Events		7
6.2 Method of Payment Upon Separation from Service		7
6.3 Method of Payment Upon a Change of Control Payment Event		8
6.4 Method of Payment Upon Death		8
6.5 Payment Upon Scheduled In-Service Withdrawal		8
6.6 Payment to Specified Employees Upon Separation from Service		8
6.7 Changes in Method of Payment		9
6.8 Beneficiary Designations		9
6.9 Small Account Balances		9
6.10 Transition Exceptions		9
ARTICLE VII ACCOUNTS AND INVESTMENT		9
7.1 Participant Accounts		9
7.2 Adjustment of Accounts		10
7.3 Investment of Account		10
7.4 Vesting		10
7.5 Account Statements		10

i

ARTICLE VIII ADMINISTRATION	11
8.1 Administration	11
8.2 Indemnification and Exculpation	11
8.3 Rules of Conduct	11
8.4 Legal, Accounting, Clerical and Other Services	11
8.5 Records of Administration	11
8.6 Expenses	11
8.7 Liability	11
8.8 Claims Review Procedures	11
8.9 Finality of Determinations; Exhaustion of Remedies	12
8.10 Effect of Fiduciary Action	13
ARTICLE IX GENERAL PROVISIONS	13
9.1 Effect on Other Plans	13
9.2 Conditions of Employment Not Affected by Plan	14
9.3 Restrictions on Alienation of Benefits	14
9.4 Domestic Relations Orders	14
9.5 Information Required of Participants	14
9.6 Tax Consequences Not Guaranteed	14
9.7 Benefits Payable to Incompetents	14
9.8 Severability	15
9.9 Tax Withholding	15
ARTICLE X AMENDMENT AND TERMINATION	15
10.1 Amendment and/or Termination	15
ARTICLE XI MISCELLANEOUS PROVISIONS	15
11.1 Articles and Section Titles and Headings	15
11.2 Joint Obligations	15
11.3 Governing Law	15

ii

DEVON ENERGY CORPORATION

NON-QUALIFIED DEFERRED COMPENSATION PLAN

ARTICLE I

ESTABLISHMENT AND PURPOSE

1.1 Establishment. Devon Energy Corporation, a Delaware corporation (“Company”), established the Devon Energy Corporation Non-Qualified Deferred Compensation Plan effective October 1, 2001 (“Plan”). The Company hereby amends and restates the Plan effective November 11, 2008. This amendment and restatement only applies to the amounts deferred under the Plan on or after January 1, 2005, and to amounts deferred prior to January 1, 2005 that were not vested as of December 31, 2004. Amounts deferred under the Plan prior to January 1, 2005 that were vested as of December 31, 2004 (the “Grandfathered Amounts”) shall be subject to the provisions of the Plan as in effect on October 3, 2004. It is intended that the Grandfathered Amounts are to remain exempt from the requirements of Section 409A of the Code.

1.2 Purpose. The Plan shall provide Eligible Employees the ability to defer payment of Base Salary and Bonus. The Plan is also intended to provide the amount of the benefit which could otherwise be earned under the Devon Energy Corporation Incentive Savings Plan (the “Qualified Plan”) but which cannot be contributed due to the limitations imposed by (i) Section 401(a)(17) of the Code, which limits the annual compensation that may be taken into account in computing benefits under plans qualified under Sections 401(a) and 501(a) of the Code and (ii) Sections 401(k) and 402(g) of the Code which limit benefits that may be contributed by the Company as a “matching contribution” under Section 401 (m) of the Code (collectively referred to as the “IRS Limitations”).

1.3 ERISA Status. The Plan is intended to qualify for the exemptions provided under Title I of ERISA for plans that are not tax-qualified and that are maintained primarily to provide deferred compensation for a select group of management or highly compensated employees as defined in Section 201(2) of ERISA.

ARTICLE II

DEFINITIONS

2.1 Definitions. For purposes of this Plan, the following definitions shall apply:

(a) “Account” means the recordkeeping accounts maintained by the Company to record the payment obligation of the Company to a Participant as determined under the terms of this Plan. The Company may maintain an Account to record the total obligation to the Participant under this Plan and component accounts to reflect amounts payable at different times and in different forms. Reference to an Account means any such Account established by the Company as the context requires.

(b) “Affiliate” means a corporation, trade or business that, together with the Company, is treated as a single employer under Code Section 414(b) or (c).

(c) “Applicable Contribution Percentage” means the maximum matching contribution percentage the Participant is eligible to receive under the terms of the Qualified Plan for the Plan Year.

(d) “Base Salary” means the Participant’s annualized gross rate of base salary paid before any deductions of any kind whatsoever.

(e) “Beneficiary” means the person, persons, trust, or other entity designated by a Participant on the beneficiary designation form adopted by the Company to receive benefits, if any, under this Plan at such Participant’s death pursuant to Section 6.4.

(f) “Board” means the Board of Directors of the Company.

(g) “Bonus” means the Participant’s cash bonus to be earned during each calendar year before any deductions of any kind whatsoever.

(h) “Change of Control Payment Event” shall mean and shall be deemed to have occurred when one of the events described in paragraphs (i), (ii), (iii), or (iv) below occurs. For the purpose of this subsection (h), the term “Company” shall mean Devon Energy Corporation and any successor thereto.

(i) The acquisition of stock of the Company by any one person, or more than one person acting as a group (as defined in §1.409A-3(i)(5)(v)(B) of the Treasury Regulations) (a “Person”) that, together with stock held by such Person, constitutes more than 50% of either (I) the then outstanding shares of common stock of the Company or (II) the combined voting power of the then outstanding voting securities of the Company entitled to vote generally in the election of directors; provided, however, that the following acquisitions shall not constitute a Change of Control Payment Event: (A) any acquisition by an underwriter temporarily holding securities pursuant to an offering of such securities, (B) any acquisition by the Company; (C) any acquisition by any employee benefit plan (or related trust) sponsored or maintained by the Company or any corporation controlled by the Company. If a Change of Control Payment Event occurs by reason of an acquisition described in this paragraph (i), no additional Change of Control Payment Event shall be deemed to occur under this paragraph (i) by reason of subsequent changes in the holdings of such Person (except if the holdings of such Person are reduced to 50% or below and thereafter increase to more than 50%).

(ii) During a 12-month period, a majority of the individuals who, as of November 11, 2008, constitute the Board (the “Incumbent Board”) are replaced; provided, however, that any individual becoming a director subsequent to November 11, 2008 whose election, appointment or nomination for election by the Company’s shareholders was approved by a vote of at least a majority of the directors then comprising the Incumbent Board shall be considered as though such individual were a member of the Incumbent Board, but excluding, for purposes of this definition, any such individual whose initial assumption of office occurs as a result of an actual or publicly threatened election contest (as such terms are used in Rule 14a-11 promulgated under the Exchange Act) with respect to the election or removal of directors or other actual or publicly threatened solicitation of proxies or consents by or on behalf of a Person other than the Board.

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(iii) The date a Person acquires (or has acquired during the 12-month period ending on the date of the most recent acquisition by such Person) ownership of stock of the Company possessing 30% or more of the combined voting power of the then outstanding voting securities of the Company; provided that, if a Change of Control Payment Event occurs by reason of an acquisition described in this paragraph (iii), no additional Change of Control Payment Event shall be deemed to occur under this paragraph (iii) or paragraph (i) by reason of the acquisition of additional control of the Company by the same Person.

(iv) Approval by the shareholders of the Company of the sale or other disposition of all or substantially all of the assets of the Company to a Person, provided that, a transfer of the Company’s assets shall not be treated as a Change of Control Payment Event if the assets are transferred to:

(1) A shareholder of the Company (immediately before the asset transfer) in exchange for or with respect to its stock;

(2) An entity, 50% or more of the total value or voting power of which is owned, directly or indirectly, by the Company;

(3) A person that owns, directly or indirectly, 50% or more of the total value or voting power of all the outstanding stock of the Company; or

(4) An entity, at least 50% of the total value or voting power of which is owned, directly or indirectly by a Person described in subparagraph (3).

Except as otherwise provided in this paragraph (iv), a person’s status is determined immediately after the transfer of the assets.

(i)   “Code” means the Internal Revenue Code of 1986, as amended from time to time, and any Regulations relating thereto.

(j)   “Committee” means the Compensation Committee of the Board of Directors of the Company or a committee established by the Compensation Committee that has been delegated duties related to the Plan.

(k)  “Credited Earnings” means the gains or losses applied to a Participant’s Account pursuant to Section 7.2.

(1)  “Deferred Amount” means the portion of a Participant’s Base Salary or Bonus which the Participant elects to defer pursuant to Article IV Deferred Amounts shall be determined by reference to the Plan Year in which the amount was deferred by the Participant.

(m) “Disabled” or “Disability” means the Participant is unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment that can be expected to result in death or last for a continuous period of not less than 12 months. The Committee shall determine whether a Participant is Disabled in accordance with Section 409A of the Code.

3

(n) “ERISA” means the Employee Retirement Income Security Act of 1974, as amended.

(o) “Eligible Employee” means an employee who (i) is designated by the Committee as belonging to a “select group of management or highly compensated employees,” as such phrase is defined under ERISA, (ii) an executive of the Company or an Affiliate employed at a minimum salary level designated from time to time by the Committee; (iii) a resident of the United States; and (iv) paid on the Company’s or its Affiliates’ United States payroll.

(p) “Employer” shall mean the Company and/or any Affiliate that employs a Participant in the Plan.

(q) “Participant” means an Eligible Employee who has Deferred Amounts and/or Supplemental Company Matching Contributions credited to an Account under this Plan.

(r)  “Plan” means this Devon Energy Non-Qualified Deferred Compensation Plan, as amended and restated effective November 11,2008.

(s) “Plan-Approved Domestic Relations Order” means a qualified domestic relations order as defined in Section

414(p)(l)(B) of the Code that meets the requirements established by the Committee.

(t)  “Plan Year” means the 12-month period beginning on January 1^st and ending on December 31^st.

(u) “Qualified Plan” means the Devon Energy Corporation Incentive Savings Plan.

(v) “Separation from Service” means termination of employment with the Employer under the circumstances described below. Whether a Separation from Service has occurred shall be determined by the Committee in accordance with Section 409A of the Code.

Except in the case of a Participant on a bona fide leave of absence as provided below, a Participant is deemed to have incurred a Separation from Service if the Employer and the Participant reasonably anticipated that the level of services to be performed by the Participant after a certain date would be reduced to 20% or less of the average services rendered by the Participant during the immediately preceding 36-month period (or the total period of employment, if less than 36 months), disregarding periods during which the Participant was on a bona fide leave of absence.

A Participant who is absent from work due to military leave, sick leave, or other bona fide leave of absence shall incur a Separation from Service on the first date immediately following the later of (i) the six-month anniversary of the commencement of the leave or (ii) the expiration of the Participant’s right, if any, to reemployment under statute or contract.

For purposes of determining whether a Separation from Service has occurred, the Employer means the Employer as defined in Section 2.1(p) of the Plan, except that for purposes of determining whether another organization is an Affiliate of the Company, common ownership of at least 50% shall be determinative.

4

(w) “Specified Employee” means those employees of the Company who are determined by the Committee to be a “specified employee” in accordance with Section 409A of the Code and the regulations promulgated thereunder and the Devon Energy Corporation Specified Employee Policy.

(x) “Supplemental Company Contribution” means the contribution made by the Company for the benefit of a Participant under Article V of the Plan in any Plan Year.

2.2 Construction. Except when otherwise indicated by the context, any masculine terminology when used in the Plan shall also include the feminine gender, and the definition of any term in the singular shall also include the plural.

2.3 Funding. The benefits described in this Plan are contractual obligations of the Employers to pay compensation for services, and shall constitute a liability to the Participants and/or their Beneficiaries in accordance with the terms hereof. All amounts paid under this Plan shall be paid in cash from the general assets of the Employers and shall be subject to the general creditors of the Company and the Employer of the Participant. Benefits shall be reflected on the accounting records of the Employers but shall not be construed to create, or require the creation of, a trust, custodial or escrow account. No special or separate fund need be established and no segregation of assets need be made to assure the payment of such benefits. No Participant shall have any right, title or interest whatever in or to any investment reserves, accounts, funds or assets that the Employer may purchase, establish or accumulate to aid in providing the benefits described in this Plan. Nothing contained in this Plan, and no action taken pursuant to its provisions, shall create or be construed to create a trust or a fiduciary relationship of any kind between an Employer or the Company and a Participant or any other person. Provided, the Company may establish and/or continue a grantor trust as defined in Section 671 of the Code to provide a source of funding for amounts deferred hereunder Neither a Participant nor the Beneficiary of a Participant shall acquire any interest hereunder greater than that of an unsecured creditor of the Company or any Affiliate who is the Employer of such Participant.

ARTICLE III

ELIGIBILITY AND PARTICIPATION

3.1 Eligibility and Participation. The Committee shall provide employees selected for participation in this Plan with notice of the employee’s selection as an Eligible Employee under this Plan for the applicable Plan Year and permit such Eligible Employee the opportunity to make an election pursuant to Article IV Such notice may be given at such time and in such manner as the Committee may determine. All determinations as to whether an employee is eligible to make deferral elections shall be made by the Committee. The determinations of the Committee shall be final and binding on all employees.

5

ARTICLE IV

ELECTIVE DEFERRALS

4.1 Deferrals. Elective deferrals may be made with respect to the following sources in accordance with the provisions of Article IV:

(a) Bonus. An Eligible Employee may elect to defer up to 100% of the Eligible Employee’s Bonus as long as such deferral does not reduce such Eligible Employee’s Bonus below an amount necessary to satisfy applicable withholding tax obligations, benefit plan contributions, and income tax withholding obligations. The amount deferred shall be specified as a percentage or dollar amount of any Bonus which may be earned by an Eligible Employee in the applicable Plan Year.

(b) Base Salary. An Eligible Employee may elect to defer up to 50% of the Eligible Employee’s Base Salary as long as such deferral does not reduce such Eligible Employee’s Base Salary below an amount necessary to satisfy applicable withholding tax obligations, benefit plan contributions, and income tax withholding obligations. The amount deferred shall be specified as a percentage or dollar amount of any Base Salary which may be earned by an Eligible Employee in the applicable Plan Year.

4.2 Timing of Deferral Election. An Eligible Employee must file a deferral election form for each Plan Year. Except as may be permitted by the Code or the regulations adopted thereunder, the election to defer Base Salary or Bonus shall apply to Base Salary or Bonus earned during the Plan Year which commences immediately following the Plan Year in which the election is made and is irrevocable except as otherwise provided herein. Elections to defer Base Salary or Bonus must be completed and filed before December 31 of the year immediately preceding the Plan Year in which the election is to apply. If an employee hired during the Plan Year is selected by the Committee to participate in this Plan, the Eligible Employee may make an election to defer within 30 days after the date the employee becomes eligible to participate in the Plan with respect to Base Salary or Bonus paid for services performed after the date the election to defer is made. Whether an employee is treated as newly eligible for participation in the Plan will be determined in accordance with Section 409A of the Code and the regulations thereunder.

4.3 Election Forms. All elections to defer shall be made on a deferral election form. In addition to the deferral election form, a Participant may be required by the Committee to complete additional forms such that they have adequate information concerning the Deferred Amount, timing of distributions and the form of payment, if applicable.

4.4 Hardship Withdrawal Under Qualified Plan. If a Participant makes a “hardship withdrawal” under the Qualified Plan and such Participant is prohibited from making future contributions under such Qualified Plan (and this Plan) by the terms of such qualified retirement plan, then, contributions by the Participant under this Plan shall be automatically suspended until Participant contributions are again permitted under the Qualified Plan.

6

ARTICLE V

SUPPLEMENTAL COMPANY CONTRIBUTIONS

5.1 Supplemental Company Contributions. If the Participant is employed by the Company on the last day of the Plan Year, the Company will make a Supplemental Company Contribution to this Plan on behalf of each Participant in an amount equal to (a) minus (b) below:

(a) The Applicable Contribution Percentage multiplied by the Participant’s Base Salary and Bonus.

(b) The Applicable Contribution Percentage multiplied by such Participant’s “eligible 401(k) compensation” which shall, for purposes of this Article V, be defined as the Participant’s Base Salary and Bonus less the Participant’s Deferred Amount up to the IRS Limitations for the applicable Plan Year.

Provided, however, the Supplemental Company Contribution cannot exceed the Participant’s Deferred Amount for the applicable Plan Year In the event a Participant’s employment is terminated due to death or Disability or due to an approved reason, as determined by the Committee in its sole discretion, a Supplemental Company Contribution may be made for the Plan Year even if the Participant is not employed on the last day of the Plan Year.

ARTICLE VI

PAYMENT OF BENEFITS

6.1 Payment Events. Unless otherwise distributed in accordance with the terms of a Scheduled In-Service Withdrawal, a Participant’s Account shall become payable at the time and in the form described in this Article upon the earlier to occur of the following events: (i) a Participant’s Separation from Service; (ii) a Participant’s Disability; (iii) a Change of Control Payment Event or (iv) the Participant’s death.

6.2 Method of Payment Upon Separation from Service. A Participant must specify on the deferral election form for each Plan Year the method of payment of the portion of Participant’s Account attributable to such Plan Year A Participant may designate payment in the form of a single lump sum payment or quarterly installment payments payable over a period of 5, 10 or 15 years. Installment payments shall be paid quarterly, with the first installment paid within 90 days following the Participant’s Separation from Service, unless the Participant is a Specified Employee, or in the case of Disability, within 90 days of the date the Participant is Disabled and each subsequent installment paid on a quarterly basis until all installment payments have been paid. If the Participant (i) fails to make an effective designation as to the method of payment or (ii) elects to receive payment in the form of a lump sum, payment shall be automatically made in the form of a single lump sum payment within 90 days following the Participant’s Separation from Service, unless the Participant is a Specified Employee, or in the case of Disability, within 90 days of the date the Participant was Disabled. In the event the Participant is a Specified Employee, payment shall be postponed for a period of six months following Separation from Service and shall commence within 90 days of the first business day of the seventh month following Separation from Service.

7

6.3 Method of Payment Upon a Change of Control Payment Event. Plan Account balances will be paid within 90 days of the occurrence of a Change of Control Payment Event. A Participant may designate payment in the form of a single lump sum payment or quarterly installment payments payable over a period of 5, 10 or 15 years. If the Participant fails to make an effective designation as to the method of payment, payment will be made in the form of a lump sum.

6.4 Method of Payment Upon Death. If a Participant dies with a balance credited to the Participant’s Account, such balance shall be paid to the Participant’s Beneficiary. If the Participant dies prior to the time of payment of the Account, the then current balance of each of the Participant’s Account or subaccount shall be paid to the Participant’s Beneficiary in a lump sum commencing within 90 days of the date of Participant’s death. If payment of Participant’s Account has commenced as of the date of Participant’s death, the then current balance of each Account or subaccount payable to a Beneficiary shall be paid under the method designated for the payment of such amount by the Participant commencing within 90 days of the date of Participant’s death. Each Beneficiary of a deceased Participant who is eligible to receive payments under this Section shall have the amounts to be paid to such Beneficiary allocated to a subaccount in the name of the Beneficiary under the deceased Participant’s Account. Such subaccount shall be adjusted from time to time as provided in Article VII.

6.5 Payment Upon Scheduled In-Service Withdrawal. A Participant may schedule distribution of the Deferred Amounts and any Credited Earning attributable thereto attributable to a particular Plan Year (“Scheduled In-Service Withdrawal”) at least two years after the Plan Year in which deferrals were made. Participants must request a Scheduled In-Service Withdrawal on the election form that is submitted in conjunction with the deferral election for such Plan Year Except as provided in Section 6.10 below, if a Participant fails to elect a Scheduled In-Service Withdrawal for that Plan Year, a Participant will not be eligible to obtain a Scheduled In-Service Withdrawal for such Plan Year.

(a) The Participant may elect either a lump sum payment or quarterly installment payments for a period of 1 to 5 years. Payment will be made (or commence in the case of installments) within 30 days of the first business day of January in the year elected.

(b) A Participant may postpone payment of a Scheduled In-Service Withdrawal to a date at least five years later than the previously Scheduled In-Service Withdrawal date by filing a written request with the Committee at least twelve months prior to the date the Scheduled In-Service Withdrawal is scheduled to begin.

(c) In the event of death, Disability, the occurrence of a Change of Control Payment Event or Separation from Service, payment of the Participant’s Account shall be determined with respect to elections made in reference to termination of employment, without regard to the otherwise Scheduled In-Service Withdrawal which shall be deemed to be cancelled.

6.6 Payment to Specified Employees Upon Separation from Service. In no event shall a Specified Employee receive a payment under this Plan following a Separation from Service prior to the first business day of the seventh month following the date of Separation from Service.

8

6.7   Changes in Method of Payment. The method of payment may be changed from time to time by the Participant, but in no event will such change be considered valid if the change occurs within the twelve-month period prior to the date payment would have otherwise commenced. Any requests to change the method of payment will not take effect for twelve months following the date it is received by the Committee and the first payment with respect to such election will be deferred for a period of at least five years from the date such payment would otherwise have commenced.

6.8   Beneficiary Designations. A Participant shall designate on a beneficiary designation form a Beneficiary who, upon the Participant’s death, will receive payments that otherwise would have been paid to him under the Plan. All Beneficiary designations shall be in writing. Any such designation shall be effective only if and when delivered to the Committee during the lifetime of the Participant. A Participant may change a Beneficiary or Beneficiaries by filing a new beneficiary designation form. The latest beneficiary designation form shall apply to the combined Accounts and subaccounts of the Participant. If a Beneficiary of a Participant predeceases the Participant, the designation of such Beneficiary shall be void. If a Beneficiary to whom benefits under the Plan remain unpaid dies after the Participant and the Participant failed to specify a contingent Beneficiary on the appropriate beneficiary designation form, the remainder of such death benefit payments shall be paid to such Beneficiary’s estate. If a Participant fails to designate a Beneficiary with respect to any death benefit payments or if such designation is ineffective, in whole or in part, any payment that otherwise would have been paid to such Participant shall be paid to the Participant’s estate.

6.9   Small Account Balances. If, upon Separation from Service, the value of the Participant’s Account is less than $10,000, the balance of such Account shall be paid in a single lump sum.

6.10 Transition Exceptions. Under the transition guidance issued by the Internal Revenue Service under Section 409A of the Code, an exception to the general timing rules shall apply to 2005, 2006, 2007 and 2008 Plan Year Account balances, Participant’s elections for the 2005, 2006, 2007 and 2008 Plan Years may be revised with respect to the timing and method of payment; provided, that such revised election (i) if made in the 2007 Plan Year, does not cause amounts that were otherwise payable in 2007 to be paid in a subsequent year, and does not provide for amounts payable in a subsequent year to be paid in 2007, and (ii) if made in the 2008 Plan Year, does not cause amounts that were otherwise payable in 2008 to be paid in a subsequent year, and does not provide for amounts payable in a subsequent year to be paid in 2008. The Committee will administer this provision to ensure compliance with IRS Notice 2006-79.

ARTICLE VII

ACCOUNTS AND INVESTMENT

7.1 Participant Accounts. The Committee shall maintain, or cause to be maintained, a bookkeeping Account for each Participant for the purpose of accounting for the Participant’s interest under the Plan. The Committee shall maintain within each Participant’s Account such subaccounts as may be necessary to identify each separate Deferred Amount, Supplemental Company Matching Contribution and Credited Earnings attributable thereto, by reference to the Plan Year to which each Deferred Amount and

9

Supplemental Company Matching Contribution relates. The combination of the subaccounts maintained in the name of a Participant shall comprise the Participant’s Account.

7.2 Adjustment of Accounts. Each Participant’s Account shall be adjusted to reflect all Deferred Amounts and Supplemental Company Matching Contributions credited to the Participant’s Account, all positive or negative Credited Earnings credited or debited to the Participant’s Account as provided by Section 7.3, and all benefit payments charged to the Participant’s Account. A Participant’s Deferred Amount shall be credited to such Participant’s Account as of the date on which the amount being deferred would have become payable to the Participant absent the election to defer, or on such other date as the Committee specifies, and shall be credited to the applicable subaccount within such Account by reference to the applicable Plan Year. Supplemental Company Matching Contributions shall be credited to a Participant’s Account and shall be subject to the vesting requirements described in Section 7.4. Charges to a Participant’s Account to reflect benefit payments shall be made as of the date of any such payment and charged to the applicable subaccount within such Account. As of any relevant date, the balance standing to the credit of a Participant’s Account, and each separate subaccount comprising such Account, shall be the respective balance in such Account and the component subaccounts as of the close of business on such date after all applicable credits, debits and charges have been posted.

7.3 Investment of Account. The Committee will offer Participants a selection of benchmark funds as deemed investment alternatives. The benchmark funds offered will be determined in the sole discretion of the Committee. Each Participant may select among the different benchmark funds offered. The deemed investments in benchmark funds are only for the purpose of determining the Company’s payment obligation under the Plan. Credited Earnings shall be allocated to a Participant’s Account pursuant to the performance of the benchmark funds selected by the Participant. A Participant may, as frequently as daily, modify his election of benchmark funds through a procedure designated by the Committee. Such modification will be in accordance with rules and procedures adopted by the Committee.

7.4 Vesting. Subject to the conditions and limitations on payment of benefits under the Plan, a Participant shall always have a fully vested and nonforfeitable beneficial interest in the balance standing to the credit of the Participant’s Account attributable to Deferred Amounts and Credited Earnings attributable to the Deferred Amounts. A Participant shall become vested in Supplemental Company Matching Contributions and Credited Earnings thereon as such Participant would be vested pursuant to the terms of the Qualified Plan.

7.5 Account Statements. The Committee shall provide each Participant with a statement of the status of the Participant’s Account under the Plan. The Committee shall provide such statement annually or at such other times as the Committee may determine. Account statements shall be in the format prescribed by the Committee.

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ARTICLE VIII

ADMINISTRATION

8.1 Administration. The Plan shall be administered, construed and interpreted by the Committee. The Committee shall have the sole authority and discretion to determine eligibility and to construe the terms of the Plan. The determinations by the Committee as to any disputed questions arising under the Plan, including the Eligible Employees who are eligible to be Participants in the Plan and the amounts of their benefits under the Plan, and the construction and interpretation by the Committee of any provision of the Plan, shall be final, conclusive and binding upon all persons including Participants, their beneficiaries, the Company, its stockholders and employees and the Employers.

8.2 Indemnification and Exculpation. The members of the Committee and its agents shall be indemnified and held harmless by the Company against and from any and all loss, cost, liability or expense that may be imposed upon or reasonably incurred by them in connection with or resulting from any claim, action, suit or proceeding to which they may be a party or in which they may be involved by reason of any action taken or failure to act under this Plan and against and from any and all amounts paid by them in settlement (with the Company’s written approval) or paid by them in satisfaction of a judgment in any such action, suit or proceeding. The foregoing provisions shall not be applicable to any person if the loss, cost, liability or expense is due to such person’s gross negligence or willful misconduct.

8.3 Rules of Conduct. The Committee shall adopt such rules for the conduct of its business and the administration of this Plan as it considers desirable, provided they do not conflict with the provisions of this Plan.

8.4 Legal, Accounting, Clerical and Other Services. The Committee may authorize one or more if its members or any agent to act on its behalf and may contract for legal, accounting, clerical and other services to carry out this Plan. The Company shall pay all expenses of the Committee.

8.5 Records of Administration. The Committee shall keep records reflecting the administration of this Plan which shall be subject to audit by the Company.

8.6 Expenses. The expenses of administering the Plan shall be borne by the Company.

8.7 Liability. No member of the Board of Directors or of the Committee shall be liable for any act or action, whether of commission or omission, taken by any other member, or by any officer, agent, or employee of the Company or of any such body, nor, except in circumstances involving his bad faith, for anything done or omitted to be done by himself.

8.8 Claims Review Procedures. The following claim procedures shall apply until such time as a Change of Control Payment Event has occurred. During the 24-month period following a Change of Control Payment Event, these procedures shall apply only to the extent the claimant requests their application. After the expiration of the 24-month period following a Change of Control Payment Event, then, these procedures shall again apply until the occurrence of a subsequent Change of Control Payment Event.

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(a) Denial of Claim. If a claim for benefits is wholly or partially denied, the claimant shall be given notice in writing of the denial within a reasonable time after the receipt of the claim, but not later than 90 days after the receipt of the claim. However, if special circumstances require an extension, written notice of the extension shall be furnished to the claimant before the termination of the 90-day period. In no event shall the extension exceed a period of 90 days after the expiration of the initial 90-day period. The notice of the denial shall contain the following information written in a manner that may be understood by a claimant:

(i)   The specific reasons for the denial;

(ii)  Specific reference to pertinent Plan provisions on which the denial is based;

(iii) A description of any additional material or information necessary for the claimant to perfect his claim and an explanation of why such material or information is necessary;

(iv) An explanation that a full and fair review by the Committee of the denial may be requested by the claimant or his authorized representative by filing a written request for a review with the Committee within 60 days after the notice of the denial is received; and

(v) If a request for review is filed, the claimant or his authorized representative may review pertinent documents and submit issues and comments in writing within the 60-day period described in Section 8.8(a)(iv).

(b) Decisions After Review. The decision of the Committee with respect to the review of the denial shall be made promptly and in writing, but not later than 60 days after the Committee receives the request for the review. However, if special circumstances require an extension of time, a decision shall be rendered not later than 120 days after the receipt of the request for review. A written notice of the extension shall be furnished to the claimant prior to the expiration of the initial 60-day period. The claimant shall be given a copy of the decision, which shall state, in a manner calculated to be understood by the claimant, the specific reasons for the decision and specific references to the pertinent Plan provisions on which the decision is based.

(c) Other Procedures. Notwithstanding the foregoing, the Committee may, in its discretion, adopt different procedures for different claims without being bound by past actions. Any procedures adopted, however, shall be designed to afford a claimant a full and fair review of his claim and shall comply with applicable regulations under ERISA.

8.9 Finality of Determinations; Exhaustion of Remedies. To the extent permitted by law, decisions reached under the claims procedures set forth in Section 8.8 shall be final and binding on all parties. No legal action for benefits under the Plan shall be brought unless and until the claimant has exhausted his remedies under Section 8.8. In any such legal action, the claimant may only present evidence and theories which the claimant presented during the claims procedure. Any claims which the claimant does not in good faith pursue through the review stage of the procedure shall be treated as having been irrevocably waived. Judicial review of a

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claimant’s denied claim shall be limited to a determination of whether the denial was arbitrary, capricious or an abuse of discretion based on the evidence and theories the claimant presented during the claims procedure. This Section shall have no application during the 24-month period following a Change of Control Payment Event as to a claim which is first asserted or first denied after the Change of Control Payment Event and, as to such a claim, the de novo standard of judicial review shall apply. After the expiration of the 24-month period following a Change of Control Payment Event, then, this Section shall again apply until the occurrence of a subsequent Change of Control Payment Event.

8.10 Effect of Fiduciary Action. The Plan shall be interpreted by the Committee and all Plan fiduciaries in accordance with the terms of the Plan and their intended meanings. However, the Committee and all Plan fiduciaries shall have the discretion to make any findings of fact needed in the administration of the Plan, and shall have the discretion to interpret or construe ambiguous, unclear or implied (but omitted) terms in any fashion they deem to be appropriate in their sole judgment. Except as stated in Section 8.9, the validity of any such finding of fact, interpretation, construction or decision shall not be given de novo review if challenged in court, by arbitration or in any other forum, and shall be upheld unless clearly arbitrary or capricious. To the extent the Committee or any Plan fiduciary has been granted discretionary authority under the Plan, the Committee’s or Plan fiduciary’s prior exercise of such authority shall not obligate it to exercise its authority in a like fashion thereafter. If any Plan provision does not accurately reflect its intended meaning, as demonstrated by consistent interpretations or other evidence of intent, or as determined by the Committee in it sole and exclusive judgment, the provision shall be considered ambiguous and shall be interpreted by the Committee and all Plan fiduciaries in a fashion consistent with its intent, as determined by the Committee in its sole discretion. The Committee may amend the Plan retroactively to cure any such ambiguity. This Section may not be invoked by any person to require the Plan to be interpreted in a manner which is inconsistent with its interpretation by the Committee or by any Plan fiduciaries. All actions taken and all determinations made in good faith by the Committee or by Plan fiduciaries shall be final and binding upon all persons claiming any interest in or under the Plan. This Section shall not apply to fiduciary or Committee actions or interpretations which take place or are made during the 24-month period following a Change of Control Payment Event. After the expiration of the 24-month period following a Change of Control Payment Event, then, this Section shall again apply until the occurrence of a subsequent Change of Control Payment Event.

ARTICLE IX

GENERAL PROVISIONS

9.1   Effect on Other Plans. Deferred Amounts shall not be considered as part of a Participant’s compensation for the purpose of any qualified employee pension plans maintained by the Company or its Affiliates in the Plan Year in which any deferral occurs under this Plan, and such amounts will not be considered under the Company’s Qualified Plan in the Plan Year in which payment occurs, but may be considered as covered compensation under the Company’s qualified defined benefit pension plan entitled “Retirement Plan for Employees of Devon Energy Corporation” if permitted under the terms of such plan. However, such amounts may be taken into account under all other employee benefit plans maintained by the Company or its Affiliates in the year in which such amounts would have been payable absent the deferral election; provided, such amounts shall not be taken into account if their inclusion would jeopardize the tax-qualified status of the plan to which they relate.

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9.2 Conditions of Employment Not Affected by Plan. The establishment and maintenance of the Plan shall not be construed as conferring any legal rights upon any Participant to the continuation of employment with the Company, nor shall the Plan interfere with the rights of the Company to discharge any Participant with or without cause.

9.3 Restrictions on Alienation of Benefits. No right or benefit under this Plan shall be subject to anticipation, alienation, sale, assignment, pledge, encumbrance, or charge, and any attempt to anticipate, alienate, sell, assign, pledge, encumber, or charge the same shall be void. No right or benefit hereunder shall in any manner be liable for or subject to the debts, contracts, liabilities, or torts of the person entitled to such benefit. If any Participant or the Participant’s Beneficiary under this Plan should become bankrupt or attempt to anticipate, alienate, sell, assign, pledge, encumber, or charge any right to a benefit hereunder, then, such right or benefit shall cease and terminate. Notwithstanding the foregoing, in the event that all or any portion of the benefit of a Participant is transferred to the former spouse of the Participant incident to a divorce, the Committee shall maintain such amount for the benefit of the former spouse until distributed in the manner required by an order of any court having jurisdiction over the divorce, and the former spouse shall be entitled to the same rights as the Participant with respect to such benefit.

9.4 Domestic Relations Orders. The Committee shall establish procedures for determining whether an order directed to the Plan is a Plan-Approved Domestic Relations Order If the Committee determines that an order is a Plan-Approved Domestic Relations Order, the Committee shall cause the payment of amounts pursuant to or segregate a separate account as provided by (and to prevent any payment or act which might be inconsistent with) the Plan-Approved Domestic Relations Order to the extent permitted by Section 409A of the Code.

9.5 Information Required of Participants. Payment of benefits shall begin as of the payment date(s) provided in this Plan and no formal claim shall be required therefor; provided, in the interest of orderly administration of the Plan, the Committee may make reasonable requests of Participants and Beneficiaries to furnish information which is reasonably necessary and appropriate to the orderly administration of the Plan, and, to that limited extent, payments under the Plan are conditioned upon the Participants and Beneficiaries promptly furnishing true, full and complete information as the Committee may reasonably request.

9.6 Tax Consequences Not Guaranteed. The Company does not warrant that this Plan will have any particular tax consequences for Participants or Beneficiaries and shall not be liable to them if tax consequences they anticipate do not actually occur The Company shall have no obligation to indemnify a Participant or Beneficiary for lost tax benefits (or other damage or loss).

9.7 Benefits Payable to Incompetents. Any benefits payable hereunder to a minor or person under legal disability may be made, at the discretion of the Committee, (i) directly to the said person, or (ii) to a parent, spouse, relative by blood or marriage, or the legal representative of said person. The Committee shall not be required to see to the application of any such payment, and the payee’s receipt shall be a full and final discharge of the Committee’s responsibility hereunder.

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9.8 Severability. If any provision of the Plan is held invalid or illegal for any reason, any illegality or invalidity shall not affect the remaining provisions of the Plan, and the Plan shall be construed and enforced as if the illegal or invalid provision had never been contained therein. The Company shall have the privilege and opportunity to correct and remedy such questions of illegality or invalidity by amendment.

9.9 Tax Withholding. The Employer may withhold from a payment or accrued benefit or from the Participant’s other compensation any federal, state, or local taxes required by law to be withheld with respect to such payment or accrued benefit and such sums as the Employer may reasonably estimate as necessary to cover any taxes for which the Employer may be liable and which may be assessed with regard to such payment.

ARTICLE X

AMENDMENT AND TERMINATION

10.1 Amendment and/or Termination. The Committee may amend or modify the Plan at any time and in any manner. Provided, (i) no amendment shall reduce any portion of a Participant’s Account that is vested and (ii) no amendment shall be effective to the extent it results in a violation of Section 409A of the Code. The Committee may terminate the Plan within the parameters and limitations imposed by Section 409A of the Code.

ARTICLE XI

MISCELLANEOUS PROVISIONS

11.1 Articles and Section Titles and Headings. The titles and headings at the beginning of each Article and Section shall not be considered in construing the meaning of any provisions in this Plan.

11.2 Joint Obligations. For purposes of this Plan, the Company and Devon Energy Company, L.P., an Oklahoma limited partnership, shall have joint and several liability for all obligations hereunder.

11.3 Governing Law. This Plan is subject to ERISA, but is exempt from most parts of ERISA since it is an unfunded deferred compensation plan maintained for a select group of management or highly compensated employees. In no event shall any references to ERISA in the Plan be construed to mean that the Plan is subject to any particular provisions of ERISA. The Plan shall be governed and construed in accordance with federal law and the laws of the State of Oklahoma, except to the extent such laws are preempted by ERISA.

* * * * * * * * *

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IN WITNESS WHEREOF, the Company and each Employer have caused this instrument to be executed by their duly authorized officers in a number of copies, each of which shall be deemed an original but all of which shall constitute one and the same instrument.

DEVON ENERGY CORPORATION, a Delaware corporation
By:	/s/     Frank W. Rudolph
	Frank W. Rudolph,
	Executive Vice President -Human Resources
DEVON ENERGY PRODUCTION COMPANY, L.P., an Oklahoma limited partnership
By:	/s/     Frank W. Rudolph
	Frank W. Rudolph,
	Executive Vice President
DEVON ENERGY MANAGEMENT COMPANY, LLC
By:	DVN Operating Company, LLC, as General Partner
By:	/s/     Frank W. Rudolph
	Frank W. Rudolph, Executive Vice President

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EX-10.15

Exhibit 10.15

Execution Copy

DEVON ENERGY CORPORATION

BENEFIT RESTORATION PLAN

DEVON ENERGY CORPORATION

BENEFIT RESTORATION PLAN

ARTICLE I

ESTABLISHMENT AND PURPOSE

1.1 Establishment and Purpose. Contrary to the desire of the Employers, the amount of the benefits payable to or on account of participants under the Retirement Plan may be limited by reason of the application of certain provisions of the Code. Accordingly, the Company established the Devon Energy Corporation Benefit Restoration Plan (the “Plan”) effective as of January 1, 2001 to provide additional retirement benefits to certain employees. The Plan is intended to qualify for the exemptions provided under Title 1 of ERISA for plans that are not tax qualified and that are maintained primarily to provide deferred compensation for a select group of management or highly compensated employees as defined in Section 201(2) of ERISA. The Company amended and restated the Plan effective January 1, 2009 and subsequently amended the Plan effective January 1, 2009. The Plan is hereby amended and restated effective January 1, 2012 to incorporate prior amendments and to make certain other clarifying changes.

ARTICLE II

DEFINITIONS AND CONSTRUCTION

2.1 Definitions. The following words, terms, and phrases used in the Plan shall have the meanings set forth in this Section 2.1:

(a) “Affiliate” means a corporation, trade or business that, together with the Company, is treated as a single employer under Section 414(b) or (c) of the Code.

(b) “Beneficiary” means the trust, person or persons designated by a Participant on a beneficiary designation form adopted by the Company to receive benefits, if any, under this Plan in the event of the Participant’s death.

(c) “Board” means the Board of Directors of the Company.

(d) “Cause” means, with respect to any Participant, any of the following:

(i) the willful failure of a Participant to substantially perform the Participant’s duties for the Company or an Affiliate (other than due to physical or mental incapacity) within thirty (30) days after receiving a written demand for substantial performance from the Supervisor, the Chief Executive Officer, or the Board;

(ii) the willful engaging by the Participant in illegal or dishonest conduct or gross misconduct that is materially and demonstrably injurious to the Company or an Affiliate; or

(iii) conviction of the Participant of a felony or any crime of moral turpitude, a guilty or nolo contendere plea by the Participant with respect to a felony or any crime of moral turpitude, or the deferred adjudication or unadjudicated probation of the Participant with respect to a felony or any crime of moral turpitude.

Provided, however, that (1) an act or omission by the Participant shall be considered “willful” only if it was not in good faith and was without reasonable belief that it was in the Company’s best interests, and (ii) any act or omission by the Participant based upon authority granted by resolution duly adopted by the Board, the instructions of the Supervisor, or the advice of counsel for the Company, shall be conclusively presumed to be in good faith and in the Company’s best interests.

(e) “Change of Control Payment Event” shall mean and shall be deemed to have occurred when one of the events described in paragraphs (i), (ii), (iii), or (iv) below occurs. For the purpose of this subsection (e), the term “Company” shall mean Devon Energy Corporation and any successor thereto.

(i) The acquisition of stock of the Company by any one person, or more than one person acting as a group (as defined in §1.409A-3(i)(5)(v)(B) of the Treasury Regulations) (a “Person”) that, together with stock held by such Person, constitutes more than 50% of either (I) the then outstanding shares of common stock of the Company or (II) the combined voting power of the then outstanding voting securities of the Company entitled to vote generally in the election of directors; provided, however, that the following acquisitions shall not constitute a Change of Control Payment Event: (A) any acquisition by an underwriter temporarily holding securities pursuant to an offering of such securities; (B) any acquisition by the Company; (C) any acquisition by any employee benefit plan (or related trust) sponsored or maintained by the Company or any corporation controlled by the Company: If a Change of Control Payment Event occurs by reason of an acquisition described in this paragraph (i), no additional Change of Control Payment Event shall be deemed to occur under this paragraph (i) by reason of subsequent changes in the holdings of such Person (except if the holdings of such Person are reduced to 50% or below and thereafter increase to more than 50%).

(ii) During a twelve (12) month period, a majority of the individuals who, as of January 1, 2009, constitute the Board (the “Incumbent Board”) are replaced; provided, however, that any individual becoming a director subsequent to January 1, 2009 whose election, appointment or nomination for election by the Company’s shareholders was approved by a vote of at least a majority of the directors then comprising the Incumbent Board shall be considered as though such individual were a member of the Incumbent Board, but excluding, for purposes of this definition, any such individual whose initial assumption of office occurs as a result of an actual or publicly threatened election contest (as such terms are used in Rule 14a-11 promulgated under the Exchange Act) with respect to the election or removal of directors or other actual or publicly threatened solicitation of proxies or consents by or on behalf of a Person other than the Board.

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(iii) The date a Person acquires (or has acquired during the 12-month period ending on the date of the most recent acquisition by such Person) ownership of stock of the Company possessing 30% or more of the combined voting power of the then outstanding voting securities of the Company; provided that, if a Change of Control Payment Event occurs by reason of an acquisition described in this paragraph (iii), no additional Change of Control Payment Event shall be deemed to occur under this paragraph (iii) or paragraph (i) by reason of the acquisition of additional control of the Company by the same Person.

(iv) Approval by the shareholders of the Company of the sale or other disposition of all or substantially all of the assets of the Company to a Person; provided that, a transfer of the Company’s assets shall not be treated as a Change of Control Payment Event if the assets are transferred to:

(1) A shareholder of the Company (immediately before the asset transfer) in exchange for or with respect to its stock;

(2) An entity, 50% or more of the total value or voting power of which is owned, directly or indirectly, by the Company;

(3) A person that owns, directly or indirectly, 50% or more of the total value or voting power of all the outstanding stock of the Company; or

(4) An entity, at least 50% of the total value or voting power of which is owned, directly or indirectly by a Person described in subparagraph (3).

Except as otherwise provided in this paragraph (iv), a person’s status is determined immediately after the transfer of the assets.

(f) A “Change of Control Vesting Event” shall mean the occurrence of any one of the following events:

(i) The Incumbent Directors cease for any reason to constitute at least a majority of the Board;

(ii) any person is or becomes a “beneficial owner” (as defined in Rule 13d-3 under the Act), directly or indirectly, of Company securities representing 30% or more of either (x) the Company’s outstanding shares of common stock or (y) the combined voting power of the Company’s then outstanding securities eligible to vote in the election of directors (each, “Company Securities”); provided, however, that the event described in this paragraph (ii) shall not be deemed to be a Change in Control Vesting Event by virtue of any of the following acquisitions or transactions: (A) by the Company or any subsidiary, (B) by any employee benefit plan (or related trust) sponsored or maintained by the Company or any subsidiary, (C) by an underwriter temporarily holding securities pursuant to an offering of such securities, or (D) pursuant to a Non-Qualifying Transaction;

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(iii) the consummation of a merger, consolidation, statutory share exchange, or similar form of corporate transaction involving the Company or any of its subsidiaries that requires the approval of the Company’s stockholders, whether for such transaction or the issuance of securities in the transaction (a “Reorganization”), or the sale or other disposition of all or substantially all of the Company’s assets to an entity that is not an Affiliate (a “Sale”), unless:

(1) the holders of the Company’s shares of common stock either receive in such Reorganization or Sale, or hold immediately following the consummation of the Reorganization or Sale, more than 50% of each of the outstanding common stock and the total voting power of securities eligible to vote in the election of directors of (x) the corporation resulting from such Reorganization or the corporation that has acquired all or substantially all of the assets of the Company in connection with a Sale (in either case, the “Surviving Corporation”), or (y) if applicable, the ultimate parent corporation that directly or indirectly has beneficial ownership of 100% of the voting securities eligible to elect directors of the Surviving Corporation (the “Parent Corporation”);

(2) no person (other than any employee benefit plan (or related trust) sponsored or maintained by the Surviving Corporation or the Parent Corporation) is or becomes, as a result of the Reorganization or Sale, the beneficial owner, directly or indirectly, of 30% or more of the outstanding shares of common stock or the total voting power of the outstanding voting securities eligible to vote in the election of directors of the Parent Corporation (or, if there is no Parent Corporation, the Surviving Corporation); and

(3) at least a majority of the members of the board of directors of the Parent Corporation (or, if there is no Parent Corporation, the Surviving Corporation) following the consummation of the Reorganization or Sale were Incumbent Directors at the time of the Board’s approval of the execution of the initial agreement providing for such Reorganization or Sale;

(any Reorganization or Sale that satisfies all of the criteria specified in (i), (ii) and (iii) above shall be deemed to be a “Non-Qualifying Transaction”); or

(iv) the Company’s stockholders approve a plan of complete liquidation or dissolution of the Company,

Notwithstanding the foregoing, a Change in Control Vesting Event shall not be deemed to occur solely because any person acquires beneficial ownership of more than 30% of Company Securities due to the Company’s acquisition of Company Securities that reduces the number of Company Securities outstanding; provided, however, if, following such acquisition by the Company, such person becomes the beneficial owner of additional Company Securities that increases the percentage of

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outstanding Company Securities beneficially owned by such person, a Change in Control Vesting Event shall then occur. In addition, if a Change in Control Vesting Event occurs pursuant to paragraph (ii) above, then no additional Change in Control Vesting Event shall be deemed to occur pursuant to paragraph (ii) by reason of subsequent changes in holdings by such person (except if the holdings by such person are reduced below 30% and thereafter increase to 30% or above).

If (I) a Participant’s Date of Termination occurs on or after the date of approval by the Company’s shareholders of a transaction described in paragraph (iii) above; (II) the transaction so approved by shareholders is consummated and constitutes a Change of Control Vesting Event under paragraph (iii) above; and (III) prior to the consummation of such transaction, the Participant’s Date of Termination occurs, then for purposes of applying the provisions of Section 4.2 (relating to vesting), the Change of Control Vesting Event shall be deemed to have occurred with respect to such Participant immediately prior to such Participant’s Date of Termination.

If (A) a Participant’s Date of Termination occurs prior to a Change of Control Vesting Event by reason of termination by the Company without Cause; (B) the Participant reasonably demonstrates that such termination either:

(1) was at the request of a third party who had indicated an intention or taken steps reasonably calculated to effect a Change of Control Vesting Event or who effectuates a Change of Control Vesting Event or

(2) was otherwise in connection with, or in anticipation of, a Change of Control Vesting Event which actually occurs,

then, for purposes of this Plan, a Change of Control Vesting Event with respect to that Participant shall be deemed to be the date immediately prior to the Participant’s Date of Termination; provided that, to the extent that the application of this sentence results in the Participant becoming entitled to benefits under the Plan, commencement of such benefits shall be required to occur not earlier than the Change of Control Vesting Event or, in the case of a Change of Control Vesting Event described in paragraph (iii) above, consummation of the transaction. If any such termination occurs while an agreement is pending and the effective provisions of such agreement provide for a transaction or transactions which, if consummated, would constitute a Change of Control Vesting Event, and such Change of Control Vesting Event occurs, then such termination shall conclusively be presumed to be in connection with a Change of Control Vesting Event.

(g) “Code” means the Internal Revenue Code of 1986, as amended.

(h) “Company” means Devon Energy Corporation, a Delaware corporation.

(i) “Committee” means the Compensation Committee of the Board of Directors.

(j) A Participant’s “Date of Termination” means the first day on which the Participant incurs a Separation from Service.

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(k) “Employer” means the Company and each Affiliate with employees who have been selected to participate in the Plan. Until action to the contrary is taken by the Board, the Company shall be deemed to have consented to the participation in the Plan by any Affiliates.

(l) “Exchange Act” means the Securities Exchange Act of 1934.

(m) “Incumbent Directors” means the members of the Board on January 1, 2009; provided, however, that (x) any person becoming a director and whose election or nomination for election was approved by a vote of at least a majority of the Incumbent Directors then on the Board (either by a specific vote or by approval of the proxy statement of the Company in which such person is named as a nominee for director, without written objection to such nomination) shall be deemed an Incumbent Director, and (y) no individual initially elected or nominated as a director of the Company as a result of an actual or threatened election contest (as described in Rule 14a-11 under the Act) or other actual or threatened solicitation of proxies or consents by or on behalf of any person (as such term is used in Sections 13(d)(3) and 14(d)(2) of the Act) other than the Board, including by reason of any agreement intended to avoid or settle any such election contest or solicitation of proxies or consents, shall be deemed an Incumbent Director.

(n) “Participant” shall have the meaning ascribed to it in Section 3.1.

(o) “Participation Agreement” shall mean the agreement which will be entered into by and between the Company and the Participant in accordance with Section 3.3.

(p) “Plan-Approved Domestic Relations Order” means a qualified domestic relations order as defined in Section 414(p)(1)(B) of the Code that meets the requirements established by the Committee.

(q) “Plan Year” means the calendar year.

(r) “Retirement Plan” means the Retirement Plan for Employees of Devon Energy Corporation.

(s) “Separation from Service” means termination of employment with the Employer under the circumstances described below. Whether a Separation from Service has occurred shall be determined by the Committee in accordance with Code Section 409A. Except in the case of a Participant on a military leave, sick leave or bona fide leave of absence as provided below, a Participant is deemed to have incurred a Separation from Service if the Employer and the Participant reasonably anticipated that the level of services to be performed by the Participant after a certain date would be reduced to 20% or less of the average services rendered by the Participant during the immediately preceding 36-month period (or the total period of employment, if less than 36 months), disregarding periods during which the Participant was on military leave, sick leave or a bona fide leave of absence.

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A Participant who is absent from work due to military leave, sick leave, or other bona fide leave of absence shall incur a Separation from Service on the first date immediately following the later of (i) the six-month anniversary of the commencement of the leave or (ii) the expiration of the Participant’s right, if any, to reemployment under statute or contract.

For purposes of determining whether a Separation from Service has occurred, the Employer means the Employer as defined in subsection (k) above, except that for purposes of determining whether another organization is an Affiliate of the Company, common ownership of at least 50% shall be determinative.

(t) “Specified Employee” means those employees of the Company or an Affiliate who are determined by the Committee to be a “specified employee” in accordance with Section 409A of the Code and the regulations promulgated thereunder and the Devon Energy Corporation Specified Employee Policy.

(u) “SRIP” means the Supplemental Retirement Income Plan of Devon Energy Corporation.

(v) “Supervisor” means the person to whom the Participant reports as determined by the Chief Executive Officer of the Company or his or her designee from time to time.

2.2 Construction. Other words, terms, and phrases used in the Plan are defined in the Retirement Plan or elsewhere in this Plan. Except where a word, term, or phrase is otherwise defined in the Plan, defined under Section 409A of the Code, or where the context clearly implies or indicates the contrary, a word, term, or phrase used in the Retirement Plan is similarly used in this Plan.

ARTICLE III

PARTICIPATION

3.1 Eligibility. Subject to the terms and conditions of the Plan, the Committee, in its discretion, at such times as the Committee determines, shall designate those employees of the Employers who are eligible to receive benefits under the Plan, and thereby become “Participants” in the Plan.

3.2 Plan Not Contract of Employment. The Plan does not constitute a contract of employment, and participation in the Plan will not give any employee the right to be retained in the employ of any Employer or Affiliate nor any right or claim to any benefit under the Plan, unless such right or claim has specifically accrued under the terms of the Plan.

3.3 Agreements. Any employee having been selected by the Committee as a Participant shall, as a condition of participation, complete, and return to the Committee, a Participation Agreement in such form and at such time as the Committee shall prescribe.

ARTICLE IV

AMOUNT AND PAYMENT OF RESTORATION BENEFIT

4.1 Amount of Restoration Benefit. Subject to the terms and conditions of the Plan, each Participant’s “Restoration Benefit,” if any, shall be determined in accordance with the following:

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(a) Determination of Restoration Benefit. A Participant’s “Restoration Benefit” shall equal the Participant’s Target Benefit minus (ii) the Participant’s Net Retirement Plan Benefit.

(b) Determination of Target Benefit. A Participant’s “Target Benefit” shall be the benefit the Participant would have been entitled to receive under the Retirement Plan if all of the following paragraphs (i) through (iv) applied:

(i) The limitations of the Plan intended to comply with Code section 401(a)(17) had been inapplicable to the determination of the Participant’s benefit under the Retirement Plan.

(ii) The limitations of the Plan intended to comply with Code section 415 had been inapplicable to the determination of the Participant’s benefit under the Retirement Plan.

(iii) In the case of a Participant to whom the provisions of Section 5.1(b) of the Retirement Plan (relating to Participants with compensation of $220,000 or more) would otherwise apply, the provisions of Section 5.1(a) of the Retirement Plan instead had been applied to such Participant.

(iv) In the case of a Participant whose compensation is determined under the Retirement Plan after reduction to reflect elective deferrals, by the Participant of amounts that would otherwise be included in Compensation in the absence of such deferral, the Target Benefit shall be determined as though those deferred amounts had been included in the determination of the Participant’s compensation at the time they would have been paid in the absence of such deferral. Conversely, such amounts shall not be included in determining the Target Benefit when they are paid to the Participant. Provided further, the calculation of the Target Benefit will include elective deferrals that were made by a Participant prior to the Participant’s selection for participation in this Plan.

A Participant’s “Target Benefit” shall be determined utilizing the assumption that the Participant’s benefit under the Retirement Plan will be determined based upon the time and form of payment applicable to the Participant’s benefit under this Plan.

With respect to any Participant who elected under the Company’s revised Retirement Plan to cease to accrue benefits under the Retirement Plan as of December 31, 2007, the following shall apply in calculating his Target Benefit:

(i) Restoration Benefits shall cease to accrue under this Plan as of December 31, 2007,

(ii) the Target Benefit shall be calculated based upon the terms and provisions of the Retirement Plan in effect as of December 31, 2007, and

(iii) Compensation increases or changes to the Retirement Plan after December 31, 2007 shall be disregarded for calculation of the Target Benefit and the Restoration Benefit under this Plan.

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(c) Determination of Net Retirement Plan Benefit. A Participant’s “Net Retirement Plan Benefit” shall be the benefit the Participant has accrued under the Retirement Plan. For purposes of calculating the Restoration Benefit, a Participant’s “Net Retirement Plan Benefit” shall be determined based on the form and time of payment applicable to the Participant’s benefit under this Plan.

(d) Minimum Benefit for MEDC Participants. In no event shall the Participant’s Target Benefit be less than the sum of the benefits frozen as of February 28, 2003 in the (i) Mitchell Energy & Development Corp. Executive Excess Business Plan, (ii) Mitchell Energy & Development Corp. Excess Benefit Plan, (iii) Mitchell Energy & Development Corp. Restoration Benefit Plan and (iv) Mitchell Energy & Development Corp. Retirement Plan.

4.2 Vesting. Except as otherwise provided by this Section 4.2, and subject to the terms of the Plan, a Restoration Benefit shall be payable under the Plan to or on behalf of a Participant if he or she is vested in such benefit as of the date of the payment event specified in Section 4.3: If a Participant is not vested in his or her Restoration Benefit under this Plan as of the date of the payment event specified in Section 4.3, then no benefits shall be payable to or on behalf of the Participant under the Plan. A Participant’s vesting shall be subject to the following:

(a) Vesting Date. A Participant shall become vested in the Restoration Benefit at the time at which the Participant becomes vested in his or her benefit under the Retirement Plan.

(b) SRIP Vesting. Notwithstanding the foregoing provisions of this Section 4.2, if a Participant is vested in his or her benefits under the SRIP, then no benefit shall be payable to or on behalf of the Participant under this Plan. However, it is recited here, for the avoidance of doubt, that for purposes of this subsection (b), a Participant shall not be deemed to be vested in his or her benefits under the SRIP as of the date of the payment event specified in Section 4.3 if such Participant fails to be entitled to benefits under the SRIP by reason of his or her Date of Termination occurring for Cause. It is the intent of the Company and is a condition for participation in this Plan that there be no duplication of benefits earned under this Plan and the SRIP.

4.3 Form of Payment and Commencement Date.

(a) Payment Events. Except as otherwise provided in the Plan, the Restoration Benefit payable to or on behalf of a Participant under this Plan shall be paid upon the later to occur of the following events: (i) a Participant’s Date of Termination or (ii) the attainment of age 55. In addition, payment of the Restoration Benefit will occur earlier in the event of (i) a Change of Control Payment Event or (ii) the Participant’s death.

(b) Form and Timing of Payment Upon Separation from Service. The Participant may elect from the following actuarially equivalent forms of benefit payments under the Plan depending upon the date payment commences as follows:

Payment Commences Prior to August 1, 2009:

(i) Single Life Annuity;

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(ii) 100% Joint and Survivor Annuity; (m) 66% Joint and Survivor Annuity;

(iii) 50% Joint and Survivor Annuity;

(iv) 40% Joint and Survivor Annuity; and

(v) Life/Ten-Year Certain.

Payment Commences August 1, 2009 or Later:

(i) Single Life Annuity;

(ii) 100% Joint and Survivor Annuity;

(iii) 50% Joint and Survivor Annuity;

(iv) 25% Joint and Survivor Annuity; and

(v) Life/Ten-Year Certain.

In the event the Participant fails to make an election, the default form of payment will be the 100% Joint and Survivor Annuity if at the time payment commences the Participant is married and a Single Life Annuity if the Participant is not married at the time payment commences. If the Participant is eligible for the PZE Spouse’s pension, the conversion of the benefit from a single life annuity to the form of payment elected will reflect the PZE Spouse’s pension and be calculated using the same methodology as is used in the Retirement Plan. Payment of the Restoration Benefit will commence as of the first of the month coincident with or next following the later of (i) 90 days following the Date of Termination or (ii) 90 days following the date the Participant attains age 55 unless the Participant is a Specified Employee. Payment of the Restoration Benefit to a Specified Employee shall be postponed for a period of six months following the Date of Termination and shall commence within 30 days of the first business day of the seventh month following the Date of Termination or, if later, within 30 days following the date the Participant attains age 55. In addition to the commencement of payment of the Restoration Benefit, a Participant who is a Specified Employee and attains age 55 on or before the completion of the six-month delay shall receive a lump sum payment within 30 days of the first business day of the seventh month following the Date of Termination of the amount of Restoration Benefit that would have otherwise been paid during the six-month delay required due to the Participant’s status as a Specified Employee. If payment of the Participant’s benefit is delayed due to his or her status as a Specified Employee, the Restoration Benefit payable shall be calculated as of the date the Restoration Benefit would have been paid but for the six-month delay. Any form of payment under this subsection (b) shall be actuarially equivalent to the form of payment that would otherwise be payable to the Participant in the absence of this subsection (b), using the actuarial assumptions set forth in the Retirement Plan.

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(c) Form and Timing of Payment Upon Change of Control Payment Event. If a Change of Control Payment Event occurs, in lieu of any other benefits under the Plan, and notwithstanding the foregoing provisions of this Section 4.3 (except for the restrictions on payment to Specified Employees), the Participant shall be entitled to a lump sum payment which is the actuarial equivalent of the Participant’s Restoration Benefit payable within 90 days of the effective date of the Change of Control Payment Event. For purposes of this subsection (c), the determination of actuarial equivalency will be made using the actuarial assumptions for determination of lump sums as set forth in the Retirement Plan; provided that in determining such actuarial equivalence, the Participant’s Restoration Benefit shall be deemed to be payable immediately on the effective date of the Change of Control Payment Event, so that the Early Retirement Adjustment Factors (as set forth in Article VII of the Retirement Plan) shall not be applied to reduce the amount otherwise payable.

(d) Form and Timing of Payment Upon Death. Payment of the Restoration Benefit will commence within 90 days of the date of the Participant’s death in the form of a 100% Joint and Survivor Annuity if the Participant was 55 years of age or older on such date. If the Participant was not age 55, payment shall be delayed until the date the Participant would have attained age 55. The Restoration Benefit shall be adjusted for payment of a death benefit as provided in Article 6 of the Retirement Plan, except that the timing of payment will be as stipulated in this Plan.

(e) Payment to Specified Employees upon Separation from Service. In no event shall a Specified Employee that is receiving a payment under this Plan due to their Separation from Service receive a payment prior to the first business day of the seventh month following the date of Separation from Service, unless the Separation from Service results from death.

(f) De Minimis Amounts. The Company shall distribute a Participant’s benefit in the form of a single lump sum payment in the event the lump sum value of the Restoration Benefit using the actuarial assumptions for determination of lump sums as set forth in the Retirement Plan is $10,000 or less on the date payment is scheduled to commence under Sections 4.3(b), (c) or (d) and such payment shall result in termination of the Participant’s entire interest in the Plan.

4.4 Restrictions on Alienation of Benefits. No right or benefit under this Plan shall be subject to anticipation, alienation, sale, assignment, pledge, encumbrance, or charge, and any attempt to anticipate, alienate, sell, assign, pledge, encumber, or charge the same shall be void. No right or benefit hereunder shall in any manner be liable for or subject to the debts, contracts, liabilities, or torts of the person entitled to such benefit. Neither the Company nor any Affiliate shall be entitled to set off against the amounts payable to the Participant under this Plan any amounts owed to the Company or the Affiliate by the Participant. Notwithstanding the foregoing, in the event that all or any portion of the benefit of a Participant is transferred to the former spouse of the Participant incident to a divorce, the Committee shall maintain such amount for the benefit of the former spouse until distributed in the manner required by an order of any court having jurisdiction over the divorce, and the former spouse shall be entitled to the same rights as the Participant with respect to such benefit.

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4.5 Domestic Relations Orders. The Committee shall establish procedures for determining whether an order directed to the Plan is a Plan-Approved Domestic Relations Order If the Committee determines that an order is a Plan-Approved Domestic Relations Order, the Committee shall cause the payment of amounts pursuant to or segregate a separate account as provided by (and to prevent any payment or act which might be inconsistent with) the Plan-Approved Domestic Relations Order to the extent permitted by Section 409A of the Code.

4.6 Abandonment of Benefits. Each Participant and Beneficiary shall file with the Committee, from time to time in writing, his or her address and each change of address, and any communication addressed to a Participant or Beneficiary at the last address filed with the Committee, or if no such address was filed, then at the last address as shown on the records of the Participant’s employer, shall be binding on the Participant or the Participant’s Beneficiary for all purposes of the Plan, and the Committee shall not be obliged to search for or ascertain the whereabouts of any Participant or Beneficiary; provided, that the Committee shall mail an annual notice of unpaid benefits to such person at such last address. If the Committee furnishes such annual notice to any Participant, or Beneficiary of a deceased Participant, that the Participant is entitled to a distribution, and the Participant or Beneficiary fails to claim such distribution or make their whereabouts known to the Committee within five years thereafter, such benefits shall be deemed forfeited and retained by or returned to the Company.

4.7 Information Required of Participants. Payment of benefits under the Plan shall begin as of the payment date provided in this Plan and no formal claim shall be required therefor; provided that a Participant may file a claim for benefits in accordance with procedures established by the Committee; and further provided that the Committee may make reasonable requests of Participants and Beneficiaries to furnish information which is reasonably necessary and appropriate to the orderly administration of the Plan, and payments under the Plan are conditioned upon the Participants and Beneficiaries promptly furnishing true, full and complete information as the Committee may reasonably request.

4.8 Benefits Payable to Incompetents. Any benefits payable hereunder to a minor or person under legal disability may be made, at the discretion of the Committee, (i) directly to the said person, or (ii) to a parent, spouse, relative by blood or marriage, or the legal representative of said person. The Committee shall not be required to see to the application of any such payment, and the payee’s receipt shall be a full and final discharge of the Committee’s responsibility hereunder.

4.9 Tax Withholding. All distributions under the Plan are subject to withholding of all applicable taxes.

ARTICLE V

SOURCE OF BENEFIT PAYMENTS

5.1 Liability for Benefit Payments. Any benefit payable under the Plan shall be paid from the general revenues of the Employer with respect to whose employee or filmier employee the benefit is payable, subject to the following:

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(a) Multiple Employers of Participant. If a Participant has been employed by more than one Employer, the portion of the Participant’s Plan benefits payable by any such Employer shall be in proportion to the benefit the Participant accrued under this Plan for his or her period of service with that Employer.

(b) Effect of Transaction. If, as a result of a sale or other transaction, the Participant’s employer after the transaction is not, or ceases to be, an Affiliate (and is or becomes an entity that is separate from the Company or an Affiliate), then, in determining liability for benefits due to the Participant under the Plan, the foregoing provisions of this Section 5.1 shall be applicable to entities which remain Employers under the Plan.

5.2 Discretionary Establishment of Trust. An Employer, in its discretion, may establish a trust, and may use the assets of the trust, to partially or fully satisfy its obligations under the Plan. Neither a Participant nor any other person shall, by reason of the Plan or any such trust, acquire any right in or title to any assets, funds or property of the Employers whatsoever, including, without limitation, any specific funds, assets, or other property which the Employers, in their sole discretion, may set aside in anticipation of a liability under the Plan. A Participant shall have only a contractual right to the amounts, if any, payable under the Plan, unsecured by any assets of the Employers. Nothing contained in the Plan shall constitute a guarantee by any of the Employers that the assets of the Employers shall be sufficient to pay any benefits to any person. No action in the establishment of a trust shall result in a Participant acquiring any interest greater than that of an unsecured creditor of the Company or any Employer of a Participant under the Plan.

5.3 Secondary Liability for Payment. To the extent that the Company and/or an Affiliate are not otherwise obligated to provide benefits to any Participant by the provisions of Section 5.1, the Company shall take such actions as are necessary, and cause each Affiliate to take such actions as are necessary, to cause each such entity (the “Guarantors”) to jointly and severally guarantee the payment of benefits otherwise due to the Participant under this Plan. However, in no event shall the guarantee provided by the preceding sentence give rise to an obligation unless the employer or employers primarily obligated to make the payment do not pay such benefit within 30 days of the due date for such payment, and no entity organized under the laws of any jurisdiction outside the United States shall have an obligation to enter into such guarantee. Each of the Guarantors shall be subrogated to the Participant’s rights under the Plan to the extent of any payments by each such Guarantor to or on account of the Participant under this Section 5.3, For the avoidance of doubt, it is recited here that after a transaction described in Section 5.1(b), this Section 5.3 shall continue to be applicable to a Participant affected by such transaction.

ARTICLE VI

COMMITTEE

6.1 Administration. The authority to control and manage all aspects of the operation and administration of the Plan shall be vested in the Committee. The Committee shall be selected by the Board. If the Committee does not exist, or for any other reason determined by the Board, the Board may take any action under the Plan that would otherwise be the responsibility of the Committee. Until otherwise provided by the Board in accordance with this Article VI, the Committee shall be comprised of the members of the Compensation Committee of the Company.

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6.2 Powers of Committee. The Committee is authorized to (i) interpret the Plan; (ii) to establish, amend, and rescind any rules and regulations relating to the Plan; (iii) to determine the terms and provisions of any agreements made pursuant to the Plan; (iv) to accelerate the vesting of any Participant; and (v) to make all other determinations that may be necessary or advisable for the administration of the Plan so long as the exercise of any discretion under this Section 6.2 does not violate Section 409A of the Code. Except as otherwise specifically provided by the Plan, any determinations to be made by the Committee under the Plan shall be decided by the Committee in its sole discretion. Any interpretation of the Plan by the Committee and any decision made by it under the Plan is final and binding on all persons.

6.3 Delegation by Committee. The Committee may by resolution, in its discretion, delegate administrative duties to one or more subcommittees comprised of employees of the Company appointed by the Committee. Any such delegation may be revoked at any time.

6.4 Information to be Furnished to Committee. The Employers and Affiliates shall furnish the Committee with such data and information as may be required for it to discharge its duties. The records of the Employers and Affiliates as to an employee’s or Participant’s employment, termination of employment, leave of absence, reemployment and compensation shall be conclusive on all persons unless determined to be incorrect. Participants and other persons entitled to benefits under the Plan must furnish the Committee such evidence, data or information as the Committee considers desirable to carry out the Plan.

6.5 Liability and Indemnification of Committee. No member or authorized delegate of the Committee shall be liable to any person for any action taken or omitted in connection with the administration of the Plan unless attributable to the person’s own fraud or willful misconduct; nor shall the Employers be liable to any person for any such action unless attributable to fraud or willful misconduct on the part of a director or employee of the Employers. The Committee, the individual members thereof, and persons acting as the authorized delegates of the Committee under the Plan, shall be indemnified by the Employers against any and all liabilities, losses, costs and expenses (including legal fees and expenses) of whatsoever kind and nature which may be imposed on, incurred by or asserted against the Committee or its members or authorized delegates by reason of the performance of a Committee function if the Committee or its members or authorized delegates did not act dishonestly or in willful violation of the law or regulation under which such liability, loss, cost or expense arises. This indemnification shall not duplicate but may supplement any coverage available under any applicable insurance.

6.6 Expenses. The expenses of administering the Plan shall be borne by the Company.

ARTICLE VII

CLAIMS PROCEDURE

7.1 Claims Review Procedures. The following claim procedures shall apply until such time as a Change of Control Payment Event has occurred. During the 24-month period following a Change of Control Payment Event, these procedures shall apply only to the extent the claimant requests their application. After the expiration of the 24-month period following a Change of Control Payment

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Event, then, these procedures shall again apply until the occurrence of a subsequent Change of Control Payment Event.

(a) Denial of Claim. If a claim for benefits is wholly or partially denied, the claimant shall be given notice in writing of the denial within a reasonable time after the receipt of the claim, but not later than 90 days after the receipt of the claim. However, if special circumstances require an extension, written notice of the extension shall be furnished to the claimant before the termination of the 90-day period. In no event shall the extension exceed a period of 90 days after the expiration of the initial 90-day period. The notice of the denial shall contain the following information written in a manner that may be understood by a claimant:

(i) The specific reasons for the denial;

(ii) Specific reference to pertinent Plan provisions on which the denial is based;

(iii) A description of any additional material or information necessary for the claimant to perfect his claim and an explanation of why such material or information is necessary;

(iv) An explanation that a full and fair review by the Committee of the denial may be requested by the claimant or his authorized representative by filing a written request for a review with the Committee within 60 days after the notice of the denial is received; and

(v) If a request for review is filed, the claimant or his authorized representative may review pertinent documents and submit issues and comments in writing within the 60-day period described in paragraph (iv) above.

(b) Decisions After Review. The decision of the Committee with respect to the review of the denial shall be made promptly and in writing, but not later than 60 days after the Committee receives the request for the review. However, if special circumstances require an extension of time, a decision shall be rendered not later than 120 days after the receipt of the request for review. A written notice of the extension shall be furnished to the claimant prior to the expiration of the initial 60-day period. The claimant shall be given a copy of the decision, which shall state, in a manner calculated to be understood by the claimant, the specific reasons for the decision and specific references to the pertinent Plan provisions on which the decision is based.

(c) Other Procedures. Notwithstanding the foregoing, the Committee may, in its discretion, adopt different procedures for different claims without being bound by past actions. Any procedures adopted, however, shall be designed to afford a claimant a full and fair review of his claim and shall comply with applicable regulations under ERISA.

7.2 Finality of Determinations; Exhaustion of Remedies. To the extent permitted by law, decisions reached under the claims procedures set forth in Section 7.1 shall be final and binding on all parties. No legal action for benefits under the Plan shall be brought unless and until the claimant has exhausted his remedies under Section 7.1. In any such legal action, the claimant may only present

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evidence and theories which the claimant presented during the claims procedure. Any claims which the claimant does not in good faith pursue through the review stage of the procedure shall be treated as having been irrevocably waived. Judicial review of a claimant’s denied claim shall be limited to a determination of whether the denial was arbitrary, capricious or an abuse of discretion based on the evidence and theories the claimant presented during the claims procedure. This Section shall have no application during the 24-month period following a Change of Control Payment Event as to a claim which is first asserted or first denied after the Change of Control Payment Event and, as to such a claim, the de novo standard of judicial review shall apply After the expiration of the 24-month period following a Change of Control Payment Event, then, this Section shall again apply until the occurrence of a subsequent Change of Control Payment Event.

7.3 Effect of Fiduciary Action. The Plan shall be interpreted by the Committee and all Plan fiduciaries in accordance with the terms of the Plan and their intended meanings. However, the Committee and all Plan fiduciaries shall have the sole discretion to make any findings of fact needed in the administration of the Plan, and shall have the sole discretion to interpret or construe ambiguous, unclear or implied (but omitted) terms in any fashion they deem to be appropriate in their sole judgment. Except as stated in Section 7.2, the validity of any such finding of fact, interpretation, construction or decision shall not be given de novo review if challenged in court, by arbitration or in any other forum, and shall be upheld unless clearly arbitrary or capricious. To the extent the Committee or any Plan fiduciary has been granted discretionary authority under the Plan, the Committee’s or Plan fiduciary’s prior exercise of such authority shall not obligate it to exercise its authority in a like fashion thereafter. If any Plan provision does not accurately reflect its intended meaning, as demonstrated by consistent interpretations or other evidence of intent, or as determined by the Committee in it sole and exclusive judgment, the provision shall be considered ambiguous and shall be interpreted by the Committee and all Plan fiduciaries in a fashion consistent with its intent, as determined by the Committee in its sole discretion. The Committee, without the need for Board of Directors’ approval, may amend the Plan retroactively to cure any such ambiguity, This Section may not be invoked by any person to require the Plan to be interpreted in a manner which is inconsistent with its interpretation by the Committee or by any Plan fiduciaries. All actions taken and all determinations made in good faith by the Committee or by Plan fiduciaries shall be final and binding upon all persons claiming any interest in or under the Plan. This Section shall not apply to fiduciary or Committee actions or interpretations which take place or are made during the 24-month period following a Change of Control Payment Event. After the expiration of the 24-month period following a Change of Control Payment Event, then, this Section shall again apply until the occurrence of a subsequent Change of Control Payment Event.

ARTICLE VIII

MISCELLANEOUS

8.1 Tax Consequences Not Guaranteed. The Employers do not warrant that this Plan will have any particular tax consequences for Participants or Beneficiaries and shall not be liable to them if tax consequences they anticipate do not actually occur. Neither the Company nor the Affiliates shall have any obligation to indemnify a Participant or Beneficiary for lost tax benefits (or other damage or loss).

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8.2 Severability. If any provision of the Plan is held invalid or illegal for any reason, any illegality or invalidity shall not affect the remaining provisions of the Plan, and the Plan shall be construed and enforced as if the illegal or invalid provision had never been contained therein. The Company shall be permitted to correct and remedy such questions of illegality or invalidity by amendment.

8.3 Benefits Under Other Plans. Benefits payable under the Plan shall be disregarded for purposes of determining the benefits under the plans of the Company and the Affiliates (including, without limitation the plans intended to be qualified under section 401(a) of the Code), except as otherwise specifically provided in the affected plan.

8.4 Gender and Number. Except when otherwise indicated by the context, any masculine terminology when used in the Plan shall also include the feminine gender, and the definition of any term in the singular shall also include the plural.

8.5 Action by Company or Affiliate. Any action required or permitted to be taken by the Company or any Employer or other Affiliate shall be by resolution of its board of directors or comparable governing body, or by action of one or more members of the board or comparable governing body (including a committee of the board) who are duly authorized to act for the board, or by a duly authorized officer of such company.

8.6 Successors. The Plan shall be binding upon and inure to the benefit of the Company and any successors of the Company, subject to the following:

(a) The Company will require any successor (whether direct or indirect, by purchase, merger, consolidation or otherwise) to all or substantially all of the business or assets of the Company to expressly assume and agree to perform the Plan in the same manner and to the same extent that the Company would be required to perform it if no such succession had taken place.

(b) After a successor assumes the Plan in accordance with this Section 8.6, only such successor shall be liable for amounts payable after such assumption, and no other companies shall have liability for amounts payable after such assumption.

8.7 Evidence. Evidence required of the Participant under the Plan may be by certificate, affidavit, document or other information which the Committee considers pertinent and reliable, and signed, made or presented by the proper party or parties.

8.8 Applicable Laws. The Plan shall be construed and administered in accordance with the laws of the State of Oklahoma to the extent that such laws are not preempted by the laws of the United States of America.

8.9 Attorney Fees. If any contest or dispute shall arise between an Employer (or the Committee) and a Participant regarding the Participant’s right to benefits under the Plan, the following will apply:

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(a) The Employer otherwise responsible for payment of the benefits shall reimburse Participant for all legal fees and expenses reasonably incurred by Participant in connection with such contest or dispute (provided that such legal fees are calculated on an hourly, and not on a contingency fee, basis), costs and expenses incurred by the Participant in connection with such enforcement or defense.

(b) The Participant shall be entitled to select his or her legal counsel; provided, however, that such right of selection shall not affect the requirement that any costs and expenses reimbursable under this Section 8.9 be reasonable.

(c) Except as otherwise provided in subsection (d) below, reimbursement by the Employer shall be made as soon as practicable following the resolution of the contest or dispute to the extent the Employer receives appropriate documentation evidencing the incurrence of such attorneys’ fees, costs, and expenses but no later than December 31 of the year immediately following the year in which resolution of the contest or dispute occurs. However, subject to subsection (d) below, no such reimbursement shall be due under this Section 8.9 if the Participant is not successful in respect of any of the Participant’s material claims or defenses brought, raised or pursued in connection with such contest or dispute.

(d) In the event that (i) within the period beginning on the Change of Control Payment Event and ending on the last day of the 24^th calendar month following the calendar month in which a Change of Control Payment Event occurs, a claim (a “Claim”) for arbitration or a lawsuits filed by a Participant in connection with a dispute, claim, or controversy regarding the Participant’s rights and obligations under the Plan or (ii) a Claim has been filed prior to a Change of Control Payment Event but has not been resolved as of the Change of Control Payment Event, then payments required under this Section 8.9 with respect to such Claim shall be made by the Employer to the Participant (or directly to the Participant’s attorney) promptly following submission to the Employer of appropriate documentation evidencing the incurrence of such attorneys’ fees, costs, and expenses but no later than December 31 of the year immediately following the year in which resolution of the contest or dispute occurs. If the Participant is not successful in respect of any of the Participant’s material claims or defenses brought, raised or pursued in connection with such contest or dispute, the Participant shall repay the Employer the amount of any such reimbursement received in connection with such dispute in accordance with this Section 8.9 (without interest) as soon as practicable following the resolution of such contest or dispute.

ARTICLE IX

AMENDMENT AND TERMINATION

9.1 Amendment and/or Termination. The Board may, at any time, amend or terminate the Plan, subject to the following:

(a) Reduction of Accrued Benefits. Neither an amendment nor termination of the Plan shall reduce or impair the benefits accrued by or on behalf of any Participant whose Date of Termination occurred prior to the date on which such amendment or termination is adopted by the Board. Neither an amendment nor termination of the Plan shall reduce or impair the benefits accrued by or on behalf of any Participant whose Date of Termination occurs on or after the date on which such amendment or termination is

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adopted by the Board, as compared to the benefits accrued under the Plan on the date immediately prior to the date on which the amendment or termination is adopted by the Board, if each Participant who had not previously incurred a Date of Termination was deemed to have incurred a Date of Termination immediately prior to the date of such adoption and commenced payment of benefits under the Plan on the earliest commencement date that would be permitted under the terms of the Plan (as in effect prior to the amendment or termination) following such deemed Date of Termination.

(b) Vesting Rate. Neither an amendment nor termination of the Plan shall adversely affect the Participant’s right to vest in benefits in accordance with Section 4.2(a) (relating to vesting at the same time as vesting under the Retirement Plan occurs), regardless of whether such vesting would occur on, before, or after the date such amendment or termination is adopted. However, the limitation in this subsection (b) shall not apply to persons who first become Participants in the Plan after such amendment or termination is adopted.

(c) Amendment of Provisions for Vesting upon a Change of Control Vesting Event. Notwithstanding the provisions of subsection (e) below, in no event shall any amendment or termination adopted by the Board during the period beginning six months prior to any Change of Control Vesting Event and ending immediately after the Change of Control Vesting Event adversely affect the Participant’s right to vest in accordance with Section 4.2(a).

(d) Accrual Rate After Change of Control Vesting Event. Except for a reduction resulting from an amendment of the Retirement Plan as described in subsection (e) below, no amendment or termination adopted by the Board during the period beginning six months prior to any Change of Control Vesting Event and ending on the last day of the 24^th calendar month following the calendar month in which occurs a Change of Control Vesting Event shall result in a reduction in the rate (as compared to the rate that would have applied in the absence of such amendment or termination) at which benefits would be accrued for service during the period beginning on the Change of Control Vesting Event and ending on the last day of the 24^th calendar month following the calendar month in which occurs a Change of Control Vesting Event.

(e) Changes in Retirement Plan. If the benefit accrual rate under the Retirement Plan is terminated or curtailed, the benefit accrual rate under this Plan shall be similarly terminated or curtailed.

(f) Section 409A. The Plan may not be amended if the amendment would result in a violation of Section 409A. The Plan may only be terminated in a manner that is compliant with the provisions of Section 409A regarding permitted plan terminations.

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IN WITNESS WHEREOF, the Company has caused this instrument to be executed by their duly authorized officers in a number of copies, each of which shall be deemed an original but all of which shall constitute one and the same instrument, effective as of January 1, 2012.

DEVON ENERGY CORPORATION
By:	/s/    Frank W. Rudolph
	Frank W. Rudolph, Executive Vice President – Human Resources

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EX-10.16

Exhibit 10.16

Execution Copy

DEVON ENERGY CORPORATION

DEFINED CONTRIBUTION RESTORATION PLAN

ARTICLE I ESTABLISHMENT AND PURPOSE	1
1.1   Establishment	1
1.2   Purpose	1
1.3   ERISA Status	1
ARTICLE II DEFINITIONS	1
2.1   Definitions	1
2.2   Construction	4
2.3   Funding	4
ARTICLE III ELIGIBILITY AND PARTICIPATION	5
3.1   Eligibility and Participation	5
ARTICLE IV COMPANY CONTRIBUTIONS	5
4.1   Company Contributions	5
ARTICLE V PAYMENT OF BENEFITS	5
5.1   Payment Events	5
5.2   Time and Method of Payment	5
5.3   Payment to Specified Employees Upon Separation from Service	6
5.4   Beneficiary Designations	6
ARTICLE VI ACCOUNTS AND INVESTMENT	6
6.1   Participant Accounts	6
6.2   Adjustment of Accounts	6
6.3   Investment of Account	7
6.4   Vesting	7
6.5   Account Statements	7
ARTICLE VII ADMINISTRATION	7
7.1   Administration	7
7.2   Indemnification and Exculpation	7
7.3   Rules of Conduct	7
7.4   Legal, Accounting, Clerical and Other Services	7
7.5   Records of Administration	8
7.6   Expenses	8
7.7   Liability	8
7.8   Claims Review Procedures	8
7.9   Finality of Determinations; Exhaustion of Remedies	9
7.10 Effect of Fiduciary Action	9
ARTICLE VIII GENERAL PROVISIONS	10
8.1   Conditions of Employment Not Affected by Plan	10
8.2   Restrictions on Alienation of Benefits	10
8.3   Information Required of Participants	10
8.4   Tax Consequences Not Guaranteed	10
8.5   Benefits Payable to Incompetents	10

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8.6   Severability	11
8.7   Tax Withholding	11
8.8   Domestic Relations Orders	11
ARTICLE IX AMENDMENT AND TERMINATION	11
9.1   Amendment and/or Termination	11
ARTICLE X MISCELLANEOUS PROVISIONS	11
10.1 Articles and Section Titles and Headings	11
10.2 Joint Obligations	11
10.3 Governing Law	11

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DEVON ENERGY CORPORATION

DEFINED CONTRIBUTION RESTORATION PLAN

ARTICLE I

ESTABLISHMENT AND PURPOSE

1.1 Establishment. Devon Energy Corporation, a Delaware corporation (“Company”), established an unfunded, nonqualified deferred compensation plan known as the Devon Energy Corporation Defined Contribution Restoration Plan (the “Plan”) effective December 1, 2007. The Company amended and restated the Plan November 11, 2008, with such amendment and restatement effective December 1, 2007, and further amended the Plan effective January 1, 2009. The Plan is hereby amended and restated effective January 1, 2012 to incorporate prior amendments and to make certain other clarifying changes.

1.2 Purpose. The Plan is intended to provide the amount of the benefit which could otherwise be earned under the Devon Energy Corporation Incentive Savings Plan (the “Qualified Plan”) but which cannot be contributed due to the limitations imposed by Section 401(a)(17) of the Code, which limits the annual compensation that may be taken into account in computing benefits under plans qualified under Section 401(a) and 501(a) of the Code.

1.3 ERISA Status. The Plan is intended to qualify for the exemptions provided under Title I of ERISA for plans that are not tax-qualified and that are maintained primarily to provide deferred compensation for a select group of management or highly compensated employees as defined in Section 201(2) of ERISA.

ARTICLE II

DEFINITIONS

2.1 Definitions. For purposes of this Plan, the following definitions shall apply.

(a) “Account” means the recordkeeping accounts maintained by the Company to record the payment obligation of the Company to a Participant as determined under the terms of this Plan. The Company may maintain an Account to record the total obligation to the Participant under this Plan and component accounts to reflect amounts payable at different times and in different forms. Reference to an Account means any such Account established by the Company as the context requires.

(b) “Affiliate” means a corporation, trade or business that, together with the Company, is treated as a single employer under Code Section 414(b) or (c).

(c) “Beneficiary” means the person, persons, trust, or other entity designated by a Participant on the beneficiary designation form adopted by the Company to receive benefits, if any, under this Plan at such Participant’s death pursuant to Section 5.2.

(d) “Board” means the Board of Directors of the Company.

(e) “Change of Control Payment Event” shall mean and shall be deemed to have occurred each time any one of the events described in paragraphs (i), (ii), (iii), or (iv) below occurs. For the purpose of this subsection (e), the term “Company” shall mean Devon Energy Corporation and any successor thereto.

(i) The acquisition of stock of the Company by any one person, or more than one person acting as a group (as defined in §1.409A-3(i)(5)(v)(B) of the Treasury Regulations) (a “Person”) if, immediately after such acquisition, such Person owns more than 50% of either (I) the then outstanding shares of common stock of the Company or (II) the combined voting power of the then outstanding voting securities of the Company entitled to vote generally in the election of directors; provided, however, that the following acquisitions shall not constitute a Change of Control Payment Event: (A) any acquisition by an underwriter temporarily holding securities pursuant to an offering of such securities; (B) any acquisition by the Company; (C) any acquisition by any employee benefit plan (or related trust) sponsored or maintained by the Company or any corporation controlled by the Company. If a Change of Control Payment Event occurs by reason of an acquisition described in this paragraph (i), no additional Change of Control Payment Event shall be deemed to occur under this paragraph (i) by reason of subsequent changes in the holdings of such Person (except if the holdings of such Person are reduced to 50% or below and thereafter increase to more than 50%).

(ii) During a 12-month period, a majority of the individuals who, as of December 1, 2007, constitute the Board (the “Incumbent Board”) are replaced; provided, however, that any individual becoming a director subsequent to December 1, 2007 whose election, appointment or nomination for election by the Company’s shareholders was approved by a vote of at least a majority of the directors then comprising the Incumbent Board shall be considered as though such individual were a member of the Incumbent Board, but excluding, for purposes of this definition, any such individual whose initial assumption of office occurs as a result of an actual or publicly threatened election contest (as such terms are used in Rule 14a-11 promulgated under the Exchange Act) with respect to the election or removal of directors or other actual or publicly threatened solicitation of proxies or consents by or on behalf of a Person other than the Board.

(iii) The date a Person acquires (or has acquired during the 12-month period ending on the date of the most recent acquisition by such Person) ownership of stock of the Company possessing 30% or more of the combined voting power of the then outstanding voting securities of the Company; provided that, if a Change of Control Payment Event occurs by reason of such acquisition, no additional Change of Control Payment Event shall be deemed to occur under this paragraph (iii) or paragraph (i) by reason of the acquisition of additional control of the Company by the same Person.

(iv) Approval by the shareholders of the Company of the sale or other disposition of all or substantially all of the assets of the Company to a Person; provided that, a transfer of the Company’s assets shall not be treated as a Change of Control Payment Event if the assets are transferred to:

(1) A shareholder of the Company (immediately before the asset transfer) in exchange for or with respect to its stock;

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(2) An entity, 50% or more of the total value or voting power of which is owned, directly or indirectly, by the Company;

(3) A person that owns, directly or indirectly, 50% or more of the total value or voting power of all the outstanding stock of the Company; or

(4) An entity, at least 50% of the total value or voting power of which is owned, directly or indirectly by a Person described in subsection (e)(iv)(3).

Except as otherwise provided in this subsection (e)(iv), a person’s status is determined immediately after the transfer of the assets.

(f)   “Code” means the Internal Revenue Code of 1986, as amended from time to time, and any Regulations relating thereto.

(g)  “Committee” means the Compensation Committee appointed by the Board of Directors of the Company or a committee established by the Compensation Committee that has been delegated duties related to the Plan.

(h)  “Company Contribution” means the contribution made by the Company for the benefit of the Participant under Article IV of the Plan in any Plan Year.

(i)   “Credited Earnings” means the gains or losses applied to a Participant’s Account pursuant to Section 6.2.

(j)   “Disabled” or “Disability” means a Participant is unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment that can be expected to result in death or last for a continuous period of not less than 12 months. The Committee shall determine whether a Participant is Disabled in accordance with Section 409A of the Code.

(k)  “ERISA” means the Employee Retirement Income Security Act of 1974, as amended.

(l)   “Eligible Employee” means an Employee who is a participant in the Qualified Plan who is designated by the Committee as belonging to a “select group of management or highly compensated employees” as such phrase is defined under ERISA whose Company contribution to the Qualified Plan is limited due to the IRS Limitations.

(m) “Employer” shall mean the Company and/or any Affiliate that employs the Participants.

(n)  “Participant” means an Eligible Employee who has Company Contributions credited to an Account under this Plan.

(o)  “Plan” means this Devon Energy Corporation Defined Contribution Restoration Plan.

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(p) “Plan-Approved Domestic Relations Order” means a qualified domestic relations order as defined in Section 414(p)(1)(B) of the Code that meets the requirements established by the Committee.

(q) “Plan Year” means the 12-month period beginning on January 1st and ending on December 31^st.

(r) “Qualified Plan” means the Devon Energy Corporation Incentive Savings Plan.

(s) “Separation from Service” A Participant incurs a Separation from Service upon termination of employment with the Employer Whether a Separation from Service has occurred shall be determined by the Committee in accordance with Section 409A of the Code.

Except in the case of a Participant on a bona fide leave of absence as provided below, a Participant is deemed to have incurred a Separation from Service if the Employer and the Participant reasonably anticipated that the level of services to be performed by the Participant after a certain date would be reduced to 20% or less of the average services rendered by the Participant during the immediately preceding 36-month period (or the total period of employment, if less than 36 months), disregarding periods during which the Participant was on a bona fide leave of absence.

A Participant who is absent from work due to military leave, sick leave, or other bona fide leave of absence shall incur a Separation from Service on the first date immediately following the later of (i) the six-month anniversary of the commencement of the leave or (ii) the expiration of the Participant’s right, if any, to reemployment under statute or contract.

For purposes of determining whether a Separation from Service has occurred, the Employer means the Employer as defined in Section 2.1(m) of the Plan, except that for purposes of determining whether another organization is an Affiliate of the Company, common ownership of at least 50% shall be determinative.

(t) “Specified Employee” means those employees of the Company who are determined by the Committee to be a “specified employee” in accordance with Section 409A of the Code and the regulations promulgated thereunder and the Devon Energy Corporation Specified Employee Policy.

2.2 Construction. Except when otherwise indicated by the context, any masculine terminology when used in the Plan shall also include the feminine gender, and the definition of any term in the singular shall also include the plural.

2.3 Funding. The benefits described in this Plan are contractual obligations of the Employers to pay compensation for services, and shall constitute a liability to the Participants and/or their Beneficiaries in accordance with the terms hereof. All amounts paid under this Plan shall be paid in cash from the general assets of the Employers and shall be subject to the general creditors of the Company and the Employer of the Participant. Benefits shall be reflected on the accounting records of the Employers but shall not be construed to create, or require the creation of, a trust, custodial or escrow account. No special or separate fund need be established and

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no segregation of assets need be made to assure the payment of such benefits. No Participant shall have any right, title or interest whatever in or to any investment reserves, accounts, funds or assets that the Employer may purchase, establish or accumulate to aid in providing the benefits described in this Plan. Nothing contained in this Plan, and no action taken pursuant to its provisions, shall create or be construed to create a trust or a fiduciary relationship of any kind between an Employer or the Company and a Participant or any other person. Provided, the Company may establish and/or continue a grantor trust as defined in Section 671 of the Code to provide a source of funding for amounts deferred hereunder. Neither a Participant nor the Beneficiary of a Participant shall acquire any interest hereunder greater than that of an unsecured creditor of the Company or any Affiliate who is the Employer of such Participant.

ARTICLE III

ELIGIBILITY AND PARTICIPATION

3.1 Eligibility and Participation. All determinations as to an Employee’s status as an Eligible Employee shall be made by the Committee. The determinations of the Committee shall be final and binding on all employees. Eligible Employees who have received Company Contributions under this Plan shall continue as a Participant as long as there is a balance credited to his or her Account.

ARTICLE IV

COMPANY CONTRIBUTIONS

4.1 Company Contributions. The Company Contribution for a Plan Year will be equal to the amount of Company contributions that would have otherwise been allocated to the Participant under the Qualified Plan but for (i) the application of Section 401(a)(17) of the Code and (ii) the reduction in the Participant’s eligible compensation under the Qualified Plan to reflect elective deferrals in a non-qualified deferred compensation plan sponsored by the Company.

ARTICLE V

PAYMENT OF BENEFITS

5.1 Payment Events. A Participant’s Account shall become payable at the time and in the form described in this Article upon the earlier to occur of the following events: (i) a Participant’s Separation from Service; (ii) a Participant’s Disability; (iii) a Change of Control Payment Event or (iv) the Participant’s death.

5.2 Time and Method of Payment. Plan Account balances will be paid in the form of a single lump sum payment within 90 days of the Participant’s death or Disability or the occurrence of a Change of Control Payment Event. Plan Account balances will also be paid in the form of a single lump sum payment within 90 days of the date of a Participant’s Separation from Service unless the Participant is a Specified Employee. In the event the Participant is a Specified Employee, payment shall be made in the form of a single lump sum payment within 90 days of the first business day of the seventh month following Separation from Service. It is possible that a Participant may be entitled to a Company Contribution for the Plan Year in which the payment event occurs but such amount, if any, will not be determinable until the Plan Year immediately following the Plan Year in which the payment event

5

occurred. Therefore, to the extent the Participant is entitled to a Company Contribution that is attributable to the Plan Year in which a payment event occurs, such amount shall be paid in a lump sum by December 31 of the Plan Year immediately following the Plan Year in which the payment event occurred.

5.3 Payment to Specified Employees Upon Separation from Service. In no event shall a Specified Employee receive a payment under this Plan following a Separation from Service prior to the first business day of the seventh month following the date of Separation from Service.

5.4 Beneficiary Designations. A Participant shall designate on a beneficiary designation form a Beneficiary who, upon the Participant’s death, will receive payments that otherwise would have been paid to him under the Plan. All Beneficiary designations shall be in writing. Any such designation shall be effective only if and when delivered to the Committee during the lifetime of the Participant. A Participant may change a Beneficiary or Beneficiaries by filing a new beneficiary designation form. The latest beneficiary designation form shall apply to the combined Accounts and subaccounts of the Participant. If a Beneficiary of a Participant predeceases the Participant, the designation of such Beneficiary shall be void. If a Beneficiary to whom benefits under the Plan remain unpaid dies after the Participant and the Participant failed to specify a contingent Beneficiary on the appropriate beneficiary designation form, the remainder of such death benefit payments shall be paid to such Beneficiary’s estate. If a Participant fails to designate a Beneficiary with respect to any death benefit payments or if such designation is ineffective, in whole or in part, any payment that otherwise would have been paid to such Participant shall be paid to the Participant’s estate.

ARTICLE VI

ACCOUNTS AND INVESTMENT

6.1 Participant Accounts. The Committee shall maintain, or cause to be maintained, a bookkeeping Account for each Participant for the purpose of accounting for the Participant’s interest under the Plan.

6.2 Adjustment of Accounts. Each Participant’s Account shall be adjusted to reflect all Company Contributions credited to the Participant’s Account, all positive or negative Credited Earnings credited or debited to the Participant’s Account as provided by Section 6.3, and all benefit payments charged to the Participant’s Account. Company Contributions shall be credited to a Participant’s Account and shall be subject to the vesting requirements described in Section 6.4, Credited Earnings and other earnings shall be credited to Participant Accounts pursuant to the performance of the investments held for the benefit of the Participant. Charges to a Participant’s Account to reflect benefit payments shall be made as of the date of any such payment and charged to the applicable subaccount within such Account. As of any relevant date, the balance standing to the credit of a Participant’s Account, and each separate subaccount comprising such Account, shall be the respective balance in such Account and the component subaccounts as of the close of business on such date after all applicable credits, debits and charges have been posted.

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6.3 Investment of Account. The Committee will offer more than one benchmark fund as a deemed investment alternative. The benchmark funds offered will be determined in the sole discretion of the Committee. Each Participant may select among the different benchmark funds offered. The deemed investments in benchmark funds are only for the purpose of determining the Company’s payment obligation under the Plan. A Participant who has a choice of more than one such benchmark fund may, as frequently as daily, modify his election of benchmark funds through a procedure designated by the Committee. Such modification will be in accordance with rules and procedures adopted by the Committee.

6.4 Vesting. A Participant shall become vested in Company Contributions and Credited Earnings thereon as such Participant would be vested pursuant to the terms of the Qualified Plan.

6.5 Account Statements. The Committee shall provide each Participant with a statement of the status of the Participant’s Account under the Plan. The Committee shall provide such statement annually or at such other times as the Committee may determine. Annual statements shall be in the format prescribed by the Committee.

ARTICLE VII

ADMINISTRATION

7.1 Administration. The Plan shall be administered, construed and interpreted by the Committee. The Committee shall have the sole authority and discretion to determine eligibility and to construe the terms of the Plan. The determinations by the Committee as to any disputed questions arising under the Plan, including the Eligible Employees who are eligible to be Participants in the Plan and the amounts of their benefits under the Plan, and the construction and interpretation by the Committee of any provision of the Plan, shall be final, conclusive and binding upon all persons including Participants, their beneficiaries, the Company, its stockholders and employees and the Employers.

7.2 Indemnification and Exculpation. The members of the Committee and its agents shall be indemnified and held harmless by the Company against and from any and all loss, cost, liability or expense that may be imposed upon or reasonably incurred by them in connection with or resulting from any claim, action, suit or proceeding to which they may be a party or in which they may be involved by reason of any action taken or failure to act under this Plan and against and from any and all amounts paid by them in settlement (with the Company’s written approval) or paid by them in satisfaction of a judgment in any such action, suit or proceeding. The foregoing provisions shall not be applicable to any person if the loss, cost, liability or expense is due to such person’s gross negligence or willful misconduct.

7.3 Rules of Conduct. The Committee shall adopt such rules for the conduct of its business and the administration of this Plan as it considers desirable, provided they do not conflict with the provisions of this Plan.

7.4 Legal, Accounting, Clerical and Other Services. The Committee may authorize one or more if its members or any agent to act on its behalf and may contract for legal, accounting, clerical and other services to carry out this Plan. The Company shall pay all expenses of the Committee.

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7.5 Records of Administration. The Committee shall keep records reflecting the administration of this Plan which shall be subject to audit by the Company.

7.6 Expenses. The expenses of administering the Plan shall be borne by the Company.

7.7 Liability. No member of the Board of Directors or of the Committee shall be liable for any act or action, whether of commission or omission, taken by any other member, or by any officer, agent, or employee of the Company or of any such body, nor, except in circumstances involving his bad faith, for anything done or omitted to be done by himself.

7.8 Claims Review Procedures. The following claim procedures shall apply until such time as a Change of Control Payment Event has occurred. During the 24-month period following a Change of Control Payment Event, these procedures shall apply only to the extent the claimant requests their application. After the expiration of the 24-month period following a Change of Control Payment Event, then, these procedures shall again apply until the occurrence of a subsequent Change of Control Payment Event.

(a) Denial of Claim. If a claim for benefits is wholly or partially denied, the claimant shall be given notice in writing of the denial within a reasonable time after the receipt of the claim, but not later than 90 days after the receipt of the claim. However, if special circumstances require an extension, written notice of the extension shall be furnished to the claimant before the termination of the 90-day period. In no event shall the extension exceed a period of 90 days after the expiration of the initial 90-day period. The notice of the denial shall contain the following information written in a manner that may be understood by a claimant:

(i) The specific reasons for the denial;

(ii) Specific reference to pertinent Plan provisions on which the denial is based;

(iii) A description of any additional material or information necessary for the claimant to perfect his claim and an explanation of why such material or information is necessary;

(iv) An explanation that a full and fair review by the Committee of the denial may be requested by the claimant or his authorized representative by filing a written request for a review with the Committee within 60 days after the notice of the denial is received; and

(v) If a request for review is filed, the claimant or his authorized representative may review pertinent documents and submit issues and comments in writing within the 60-day period described in Section 7.8(a)(iv).

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(b) Decisions After Review. The decision of the Committee with respect to the review of the denial shall be made promptly and in writing, but not later than 60 days after the Committee receives the request for the review However, if special circumstances require an extension of time, a decision shall be rendered not later than 120 days after the receipt of the request for review. A written notice of the extension shall be furnished to the claimant prior to the expiration of the initial 60-day period. The claimant shall be given a copy of the decision, which shall state, in a manner calculated to be understood by the claimant, the specific reasons for the decision and specific references to the pertinent Plan provisions on which the decision is based.

(c) Other Procedures. Notwithstanding the foregoing, the Committee may, in its discretion, adopt different procedures for different claims without being bound by past actions. Any procedures adopted, however, shall be designed to afford a claimant a full and fair review of his claim and shall comply with applicable regulations under ERISA.

7.9 Finality of Determinations; Exhaustion of Remedies. To the extent permitted by law, decisions reached under the claims procedures set forth in Section 7.8 shall be final and binding on all parties. No legal action for benefits under the Plan shall be brought unless and until the claimant has exhausted his remedies under Section 7.8. In any such legal action, the claimant may only present evidence and theories which the claimant presented during the claims procedure. Any claims which the claimant does not in good faith pursue through the review stage of the procedure shall be treated as having been irrevocably waived. Judicial review of a claimant’s denied claim shall be limited to a determination of whether the denial was arbitrary, capricious or an abuse of discretion based on the evidence and theories the claimant presented during the claims procedure. This Section shall have no application during the 24-month period following a Change of Control Payment Event as to a claim which is first asserted or first denied after the Change of Control Payment Event and, as to such a claim, the de novo standard of judicial review shall apply After the expiration of the 24-month period following a Change of Control Payment Event, then, this Section shall again apply until the occurrence of a subsequent Change of Control Payment Event.

7.10 Effect of Fiduciary Action. The Plan shall be interpreted by the Committee and all Plan fiduciaries in accordance with the terms of the Plan and their intended meanings. However, the Committee and all Plan fiduciaries shall have the discretion to make any findings of fact needed in the administration of the Plan, and shall have the discretion to interpret or construe ambiguous, unclear or implied (but omitted) terms in any fashion they deem to be appropriate in their sole judgment. Except as stated in Section 7 9, the validity of any such finding of fact, interpretation, construction or decision shall not be given de novo review if challenged in court, by arbitration or in any other forum, and shall be upheld unless clearly arbitrary or capricious. To the extent the Committee or any Plan fiduciary has been granted discretionary authority under the Plan, the Committee’s or Plan fiduciary’s prior exercise of such authority shall not obligate it to exercise its authority in a like fashion thereafter. If any Plan provision does not accurately reflect its intended meaning, as demonstrated by consistent interpretations or other evidence of intent, or as determined by the Committee in it sole and exclusive judgment, the provision shall be considered ambiguous and shall be interpreted by the Committee and all Plan fiduciaries in a fashion consistent with its intent, as determined by the Committee in its sole discretion. The Committee, without the need for Board of Directors’ approval, may amend the Plan retroactively to cure any such ambiguity. This Section may not be invoked by any person to require the Plan to be interpreted in a manner which is inconsistent with its interpretation by the Committee

9

or by any Plan fiduciaries. All actions taken and all determinations made in good faith by the Committee or by Plan fiduciaries shall be final and binding upon all persons claiming any interest in or under the Plan. This Section shall not apply to fiduciary or Committee actions or interpretations which take place or are made during the 24-month period following a Change of Control Payment Event. After the expiration of the 24-month period following a Change of Control Payment Event, then, this Section shall again apply until the occurrence of a subsequent Change of Control Payment Event.

ARTICLE VIII

GENERAL PROVISIONS

8.1 Conditions of Employment Not Affected by Plan. The establishment and maintenance of the Plan shall not be construed as conferring any legal rights upon any Participant to the continuation of employment with the Company, nor shall the Plan interfere with the rights of the Company to discharge any Participant with or without cause.

8.2 Restrictions on Alienation of Benefits. No right or benefit under this Plan shall be subject to anticipation, alienation, sale, assignment, pledge, encumbrance, or charge, and any attempt to anticipate, alienate, sell, assign, pledge, encumber, or charge the same shall be void. No right or benefit hereunder shall in any manner be liable for or subject to the debts, contracts, liabilities, or torts of the person entitled to such benefit. If any Participant or the Participant’s Beneficiary under this Plan should become bankrupt or attempt to anticipate, alienate, sell, assign, pledge, encumber, or charge any right to a benefit hereunder, then, such right or benefit shall cease and terminate.

8.3 Information Required of Participants. Payment of benefits shall begin as of the payment date(s) provided in this Plan and no formal claim shall be required therefor; provided, in the interest of orderly administration of the Plan, the Committee may make reasonable requests of Participants and Beneficiaries to furnish information which is reasonably necessary and appropriate to the orderly administration of the Plan, and, to that limited extent, payments under the Plan are conditioned upon the Participants and Beneficiaries promptly furnishing true, full and complete information as the Committee may reasonably request.

8.4 Tax Consequences Not Guaranteed. The Company does not warrant that this Plan will have any particular tax consequences for Participants or Beneficiaries and shall not be liable to them if tax consequences they anticipate do not actually occur. The Company shall have no obligation to indemnify a Participant or Beneficiary for lost tax benefits (or other damage or loss).

8.5 Benefits Payable to Incompetents. Any benefits payable hereunder to a minor or person under legal disability may be made, at the discretion of the Committee, (i) directly to the said person, or (ii) to a parent, spouse, relative by blood or marriage, or the legal representative of said person. The Committee shall not be required to see to the application of any such payment, and the payee’s receipt shall be a full and final discharge of the Committee’s responsibility hereunder.

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8.6 Severability. If any provision of the Plan is held invalid or illegal for any reason, any illegality or invalidity shall not affect the remaining provisions of the Plan, and the Plan shall be construed and enforced as if the illegal or invalid provision had never been contained therein. The Company shall have the privilege and opportunity to correct and remedy such questions of illegality or invalidity by amendment.

8.7 Tax Withholding. The Employer may withhold from a payment or accrued benefit or from the Eligible Employee’s other compensation any federal, state, or local taxes required by law to be withheld with respect to such payment or accrued benefit and such sums as the Employer may reasonably estimate as necessary to cover any taxes for which the Employer may be liable and which may be assessed with regard to such payment.

8.8 Domestic Relations Orders. The Committee shall establish procedures for determining whether an order directed to the Plan is a Plan-Approved Domestic Relations Order. If the Committee determines that an order is a Plan-Approved Domestic Relations Order, the Committee shall cause the payment of amounts pursuant to or segregate a separate account as provided by (and to prevent any payment or act which might be inconsistent with) the Plan-Approved Domestic Relations Order to the extent permitted by Section 409A of the Code.

ARTICLE IX

AMENDMENT AND TERMINATION

9.1 Amendment and/or Termination. The Committee may amend or modify the Plan at any time and in any manner. Provided, (i) no amendment shall reduce any portion of a Participant’s Account that is vested and (ii) no amendment shall be effective to the extent it results in a violation of Section 409A of the Code. The Committee may terminate the Plan within the parameters and limitations imposed by Section 409A of the Code.

ARTICLE X

MISCELLANEOUS PROVISIONS

10.1 Articles and Section Titles and Headings. The titles and headings at the beginning of each Article and Section shall not be considered in construing the meaning of any provisions in this Plan.

10.2 Joint Obligations. For purposes of this Plan, the Company and Devon Energy Company, L.P., an Oklahoma limited partnership shall have joint and several liability for all obligations hereunder.

10.3 Governing Law. This Plan is subject to ERISA, but is exempt from most parts of ERISA since it is an unfunded deferred compensation plan maintained for a select group of management or highly compensated employees. In no event shall any references to ERISA in the Plan be construed to mean that the Plan is subject to any particular provisions of ERISA. The Plan shall be governed and construed in accordance with federal law and the laws of the State of Oklahoma, except to the extent such laws are preempted by ERISA.

* * * * * * * * *

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IN WITNESS WHEREOF, the Company has caused this instrument to be executed by their duly authorized officers in a number of copies, each of which shall be deemed an original but all of which shall constitute one and the same instrument.

DEVON ENERGY CORPORATION, a Delaware corporation
By:	/s/    Frank W. Rudolph
	Frank W. Rudolph, Executive Vice-President –
	Human Resources

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EX-10.17

Exhibit 10.17

Execution Copy

DEVON ENERGY CORPORATION

SUPPLEMENTAL CONTRIBUTION PLAN

ARTICLE I ESTABLISHMENT AND PURPOSE	1
1.1 Establishment	1
1.2 Purpose	1
ARTICLE II DEFINITIONS	1
2.1 Definitions	1
2.2 Construction	4
2.3 Funding	4
ARTICLE III ELIGIBILITY AND PARTICIPATION	5
3.1 Eligibility and Participation	5
ARTICLE IV COMPANY CONTRIBUTIONS	5
4.1 Company Contributions	5
ARTICLE V PAYMENT OF BENEFITS	5
5.1 Payment Events	5
5.2 Time and Method of Payment	5
5.3 Payment to Specified Employees Upon Separation from Service	6
5.4 Beneficiary Designations	6
ARTICLE VI ACCOUNTS AND INVESTMENT	6
6.1 Participant Accounts	6
6.2 Adjustment of Accounts	6
6.3 Investment of Account	6
6.4 Vesting	7
6.5 Account Statements	7
ARTICLE VII ADMINISTRATION	7
7.1 Administration	7
7.2 Indemnification and Exculpation	7
7.3 Rules of Conduct	7
7.4 Legal, Accounting, Clerical and Other Services	7
7.5 Records of Administration	7
7.6 Expenses	8
7.7 Liability	8
7.8 Claims Review Procedures	8
7.9 Finality of Determinations; Exhaustion of Remedies	9
7.10 Effect of Fiduciary Action	9
ARTICLE VIII GENERAL PROVISIONS	10
8.1 Conditions of Employment Not Affected by Plan	10
8.2 Restrictions on Alienation of Benefits	10
8.3 Information Required of Participants	10
8.4 Tax Consequences Not Guaranteed	10
8.5 Benefits Payable to Incompetents	10
8.6 Severability	10

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8.7   Tax Withholding	11
8.8   Domestic Relations Orders	11
ARTICLE IX AMENDMENT AND TERMINATION	11
9.1   Amendment and/or Termination	11
ARTICLE X MISCELLANEOUS PROVISIONS	11
10.1 Articles and Section Titles and Headings	11
10.2 Joint Obligations	11
10.3 Governing Law	11

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DEVON ENERGY CORPORATION

SUPPLEMENTAL CONTRIBUTION PLAN

ARTICLE I

ESTABLISHMENT AND PURPOSE

1.1 Establishment. Devon Energy Corporation, a Delaware corporation (“Company”), established an unfunded, nonqualified deferred compensation plan to be known as the Devon Energy Corporation Supplemental Contribution Plan (the “Plan”) effective December 1, 2007. The Company amended and restated the Plan November 11, 2008 with such amendment and restatement effective on December 1, 2007. The Company further amended the Plan effective January 1, 2009 and hereby amends and restates the Plan effective January 1, 2012 to incorporate prior amendments and to make certain other clarifying changes.

1.2 Purpose. The Plan is intended to provide the amount of the benefit which could otherwise be earned under the Devon Energy Corporation Incentive Savings Plan (the “Qualified Plan”) but which cannot be contributed due to the limitations imposed by Section 415 of the Code, which limits amounts of contributions that may be allocated annually to a participant under the Qualified Plan.

1.3 ERISA Status. The Plan is intended to qualify for the exemptions provided under Title I of ERISA for plans that are not tax-qualified and that are maintained solely for the purpose of providing benefits for certain employees in excess of the limitations on contributions and benefits imposed by Section 415 on plans to which that section applies.

ARTICLE II

DEFINITIONS

2.1 Definitions. For purposes of this Plan, the following definitions shall apply.

(a) “Account” means the recordkeeping accounts maintained by the Company to record the payment obligation of the Company to a Participant as determined under the terms of this Plan. The Company may maintain an Account to record the total obligation to the Participant under this Plan and component accounts to reflect amounts payable at different times and in different forms. Reference to an Account means any such Account established by the Company as the context requires.

(b) “Affiliate” means a corporation, trade or business that, together with the Company, is treated as a single employer under Code Section 414(b) or (c).

(c) “Beneficiary” means the person, persons, trust, or other entity designated by a Participant on the beneficiary designation form adopted by the Company to receive benefits, if any, under this Plan at such Participant’s death pursuant to Section 5.2.

(d) “Board” means the Board of Directors of the Company.

(e) “Change of Control Payment Event” shall mean and shall be deemed to have occurred each time any one of the events described in paragraphs (i), (ii), (iii), or (iv) below occurs. For the purpose of this subsection (e), the term “Company” shall mean Devon Energy Corporation and any successor thereto.

(i) The acquisition of stock of the Company by any one person, or more than one person acting as a group (as defined in §1.409A-3(i)(5)(v)(B) of the Treasury Regulations) (a “Person”) if, immediately after such acquisition, such Person owns more than 50% of either (I) the then outstanding shares of common stock of the Company or (II) the combined voting power of the then outstanding voting securities of the Company entitled to vote generally in the election of directors; provided, however, that the following acquisitions shall not constitute a Change of Control Payment Event: (A) any acquisition by an underwriter temporarily holding securities pursuant to an offering of such securities; (B) any acquisition by the Company; (C) any acquisition by any employee benefit plan (or related trust) sponsored or maintained by the Company or any corporation controlled by the Company. If a Change of Control Payment Event occurs by reason of an acquisition described in this paragraph (i), no additional Change of Control Payment Event shall be deemed to occur under this paragraph (i) by reason of subsequent changes in the holdings of such Person (except if the holdings of such Person are reduced to 50% or below and thereafter increase to more than 50%).

(ii) During a 12-month period, a majority of the individuals who, as of December 1, 2007, constitute the Board (the “Incumbent Board”) are replaced; provided, however, that any individual becoming a director subsequent to December 1, 2007 whose election, appointment or nomination for election by the Company’s shareholders was approved by a vote of at least a majority of the directors then comprising the Incumbent Board shall be considered as though such individual were a member of the Incumbent Board, but excluding, for purposes of this definition, any such individual whose initial assumption of office occurs as a result of an actual or publicly threatened election contest (as such terms are used in Rule 14a-11 promulgated under the Exchange Act) with respect to the election or removal of directors or other actual or publicly threatened solicitation of proxies or consents by or on behalf of a Person other than the Board.

(iii) The date a Person acquires (or has acquired during the 12-month period ending on the date of the most recent acquisition by such Person) ownership of stock of the Company possessing 30% or more of the combined voting power of the then outstanding voting securities of the Company; provided that, if a Change of Control Payment Event occurs by reason of such acquisition, no additional Change of Control Payment Event shall be deemed to occur under this paragraph (iii) or paragraph (i) by reason of the acquisition of additional control of the Company by the same Person.

(iv) Approval by the shareholders of the Company of the sale or other disposition of all or substantially all of the assets of the Company to a Person; provided that, a transfer of the Company’s assets shall not be treated as a Change of Control Payment Event if the assets are transferred to:

(1) A shareholder of the Company (immediately before the asset transfer) in exchange for or with respect to its stock;

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(2) An entity, 50% or more of the total value or voting power of which is owned, directly or indirectly, by the Company;

(3) A person that owns, directly or indirectly, 50% or more of the total value or voting power of all the outstanding stock of the Company; or

(4) An entity, at least 50% of the total value or voting power of which is owned, directly or indirectly by a Person described in subsection (e)(iv)(3).

Except as otherwise provided in this subsection (e)(iv), a person’s status is determined immediately after the transfer of the assets.

(f)   “Code” means the Internal Revenue Code of 1986, as amended from time to time, and any Regulations relating thereto.

(g)  “Committee” means the Compensation Committee appointed by the Board of Directors of the Company or a committee established by the Compensation Committee that has been delegated duties related to the Plan.

(h)  “Company Contribution” means the contribution made by the Company for the benefit of the Participant under Article IV of the Plan in any Plan Year.

(i)   “Credited Earnings” means the gains or losses applied to a Participant’s Account pursuant to Section 6.2.

(j)   “Disabled” or “Disability” means a Participant is unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment that can be expected to result in death or last for a continuous period of not less than 12 months. The Committee shall determine whether a Participant is Disabled in accordance with Section 409A of the Code.

(k)  “ERISA” means the Employee Retirement Income Security Act of 1974, as amended.

(l)   “Eligible Employee” means an Employee who is a participant in the Qualified Plan whose Company contribution to the Qualified Plan is limited due to the application of Section 415 of the Code.

(m) “Employer” shall mean the Company and/or any Affiliate that employs the Participants.

(n)  “Participant” means an Eligible Employee who has Company Contributions credited to an Account under this Plan.

(o)  “Plan” means this Devon Energy Corporation Supplemental Contribution Plan.

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(p) “Plan-Approved Domestic Relations Order” means a qualified domestic relations order as defined in Section 414(p)(1)(B) of the Code that meets the requirements established by the Committee.

(q) “Plan Year” means the 12-month period beginning on January 1^st and ending on December 31^st.

(r) “Qualified Plan” means the Devon Energy Corporation Incentive Savings Plan.

(s) “Separation from Service” A Participant incurs a Separation from Service upon termination of employment with the Employer Whether a Separation from Service has occurred shall be determined by the Committee in accordance with Section 409A of the Code.

Except in the case of a Participant on a bona fide leave of absence as provided below, a Participant is deemed to have incurred a Separation from Service if the Employer and the Participant reasonably anticipated that the level of services to be performed by the Participant after a certain date would be reduced to 20% or less of the average services rendered by the Participant during the immediately preceding 36-month period (or the total period of employment, if less than 36 months), disregarding periods during which the Participant was on a bona fide leave of absence.

A Participant who is absent from work due to military leave, sick leave, or other bona fide leave of absence shall incur a Separation from Service on the first date immediately following the later of (i) the six-month anniversary of the commencement of the leave or (ii) the expiration of the Participant’s right, if any, to reemployment under statute or contract.

For purposes of determining whether a Separation from Service has occurred, the Employer means the Employer as defined in Section 2.1(m) of the Plan, except that for purposes of determining whether another organization is an Affiliate of the Company, common ownership of at least 50% shall be determinative.

(t) “Specified Employee” means those employees of the Company who are determined by the Committee to be a “specified employee” in accordance with Section 409A of the Code and the regulations promulgated thereunder and the Devon Energy Corporation Specified Employee Policy.

2.2 Construction. Except when otherwise indicated by the context, any masculine terminology when used in the Plan shall also include the feminine gender, and the definition of any term in the singular shall also include the plural.

2.3 Funding. The benefits described in this Plan are contractual obligations of the Employers to pay compensation for services, and shall constitute a liability to the Participants and/or their Beneficiaries in accordance with the terms hereof. All amounts paid under this Plan shall be paid in cash from the general assets of the Employers and shall be subject to the general creditors of the Company and the Employer of the Participant. Benefits shall be reflected on the accounting records of the Employers but shall not be construed to create, or require the creation of, a trust, custodial or escrow account. No special or separate fund need be established and

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no segregation of assets need be made to assure the payment of such benefits. No Participant shall have any right, title or interest whatever in or to any investment reserves, accounts, funds or assets that the Employer may purchase, establish or accumulate to aid in providing the benefits described in this Plan. Nothing contained in this Plan, and no action taken pursuant to its provisions, shall create or be construed to create a trust or a fiduciary relationship of any kind between an Employer or the Company and a Participant or any other person. Provided, the Company may establish and/or continue a grantor trust as defined in Section 671 of the Code to provide a source of funding for amounts deferred hereunder. Neither a Participant nor the Beneficiary of a Participant shall acquire any interest hereunder greater than that of an unsecured creditor of the Company or any Affiliate who is the Employer of such Participant.

ARTICLE III

ELIGIBILITY AND PARTICIPATION

3.1 Eligibility and Participation. All determinations as to an employee’s status as an Eligible Employee shall be made by the Committee. The determinations of the Committee shall be final and binding on all employees. Eligible Employees who have received Company Contributions under this Plan shall continue as a Participant as long as there is a balance credited to his or her Account.

ARTICLE IV

COMPANY CONTRIBUTIONS

4.1 Company Contributions. The Company Contribution for a Plan Year will be equal to the amount of Company contributions that would have otherwise been allocated to the Participant under the Qualified Plan but for the application of Section 415 of the Code.

ARTICLE V

PAYMENT OF BENEFITS

5.1 Payment Events. A Participant’s Account shall become payable at the time and in the form described in this Article upon the earlier to occur of the following events: (i) a Participant’s Separation from Service; (ii) a Participant’s Disability; (iii) a Change of Control Payment Event or (iv) the Participant’s death.

5.2 Time and Method of Payment. Time and Method of Payment. Plan Account balances will be paid in the form of a single lump sum payment within 90 days of the Participant’s death or Disability or the occurrence of a Change of Control Payment Event. Plan Account balances will also be paid in the form of a single lump sum payment within 90 days of the date of a Participant’s Separation from Service unless the Participant is a Specified Employee. In the event the Participant is a Specified Employee, payment shall be made in the form of a single lump sum payment within 90 days of the first business day of the seventh month following Separation from Service. It is possible that a Participant may be entitled to a Company Contribution for the Plan Year in which the payment event occurs but such amount, if any, will not be determinable until the Plan Year immediately following the Plan Year in which the payment event occurred. Therefore, to the extent the Participant is entitled to a Company Contribution that is attributable to the Plan Year in which a payment event occurs, such amount shall be paid in a lump sum by December 31 of the Plan Year immediately following the Plan Year in which the payment event occurred.

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5.3 Payment to Specified Employees Upon Separation from Service. In no event shall a Specified Employee receive a payment under this Plan following a Separation from Service prior to the first business day of the seventh month following the date of Separation from Service.

5.4 Beneficiary Designations. A Participant shall designate on a beneficiary designation form a Beneficiary who, upon the Participant’s death, will receive payments that otherwise would have been paid to him under the Plan. All Beneficiary designations shall be in writing. Any such designation shall be effective only if and when delivered to the Committee during the lifetime of the Participant. A Participant may change a Beneficiary or Beneficiaries by filing a new beneficiary designation form. The latest beneficiary designation form shall apply to the combined Accounts and subaccounts of the Participant. If a Beneficiary of a Participant predeceases the Participant, the designation of such Beneficiary shall be void. If a Beneficiary to whom benefits under the Plan remain unpaid dies after the Participant and the Participant failed to specify a contingent Beneficiary on the appropriate beneficiary designation form, the remainder of such death benefit payments shall be paid to such Beneficiary’s estate. If a Participant fails to designate a Beneficiary with respect to any death benefit payments or if such designation is ineffective, in whole or in part, any payment that otherwise would have been paid to such Participant shall be paid to the Participant’s estate.

ARTICLE VI

ACCOUNTS AND INVESTMENT

6.1 Participant Accounts. The Committee shall maintain, or cause to be maintained, a bookkeeping Account for each Participant for the purpose of accounting for the Participant’s interest under the Plan.

6.2 Adjustment of Accounts. Each Participant’s Account shall be adjusted to reflect all Company Contributions credited to the Participant’s Account, all positive or negative Credited Earnings credited or debited to the Participant’s Account as provided by Section 6.3, and all benefit payments charged to the Participant’s Account. Company Contributions shall be credited to a Participant’s Account and shall be subject to the vesting requirements described in Section 6.4. Credited Earnings and other earnings shall be credited to Participant Accounts pursuant to the performance of the investments held for the benefit of the Participant. Charges to a Participant’s Account to reflect benefit payments shall be made as of the date of any such payment and charged to the applicable subaccount within such Account. As of any relevant date, the balance standing to the credit of a Participant’s Account, and each separate subaccount comprising such Account, shall be the respective balance in such Account and the component subaccounts as of the close of business on such date after all applicable credits, debits and charges have been posted.

6.3 Investment of Account. The Committee will offer more than one benchmark fund as a deemed investment alternative. The benchmark funds offered will be determined in the sole discretion of the Committee. Each Participant may select among the different

6

benchmark funds offered. The deemed investments in benchmark funds are only for the purpose of determining the Company’s payment obligation under the Plan. A Participant who has a choice of more than one such benchmark fund may, as frequently as daily, modify his election of benchmark funds through a procedure designated by the Committee. Such modification will be in accordance with rules and procedures adopted by the Committee.

6.4 Vesting. A Participant shall become vested in Company Contributions and Credited Earnings thereon as such Participant would be vested pursuant to the terms of the Qualified Plan.

6.5 Account Statements. The Committee shall provide each Participant with a statement of the status of the Participant’s Account under the Plan. The Committee shall provide such statement annually or at such other times as the Committee may determine. Annual statements shall be in the format prescribed by the Committee.

ARTICLE VII

ADMINISTRATION

7.1 Administration. The Plan shall be administered, construed and interpreted by the Committee. The Committee shall have the sole authority and discretion to determine eligibility and to construe the terms of the Plan. The determinations by the Committee as to any disputed questions arising under the Plan, including the Eligible Employees who are eligible to be Participants in the Plan and the amounts of their benefits under the Plan, and the construction and interpretation by the Committee of any provision of the Plan, shall be final, conclusive and binding upon all persons including Participants, their beneficiaries, the Company, its stockholders and employees and the Employers.

7.2 Indemnification and Exculpation. The members of the Committee and its agents shall be indemnified and held harmless by the Company against and from any and all loss, cost, liability or expense that may be imposed upon or reasonably incurred by them in connection with or resulting from any claim, action, suit or proceeding to which they may be a party or in which they may be involved by reason of any action taken or failure to act under this Plan and against and from any and all amounts paid by them in settlement (with the Company’s written approval) or paid by them in satisfaction of a judgment in any such action, suit or proceeding. The foregoing provisions shall not be applicable to any person if the loss, cost, liability or expense is due to such person’s gross negligence or willful misconduct.

7.3 Rules of Conduct. The Committee shall adopt such rules for the conduct of its business and the administration of this Plan as it considers desirable, provided they do not conflict with the provisions of this Plan.

7.4 Legal, Accounting, Clerical and Other Services. The Committee may authorize one or more if its members or any agent to act on its behalf and may contract for legal, accounting, clerical and other services to carry out this Plan. The Company shall pay all expenses of the Committee.

7.5 Records of Administration. The Committee shall keep records reflecting the administration of this Plan which shall be subject to audit by the Company.

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7.6 Expenses. The expenses of administering the Plan shall be borne by the Company.

7.7 Liability. No member of the Board of Directors or of the Committee shall be liable for any act or action, whether of commission or omission, taken by any other member, or by any officer, agent, or employee of the Company or of any such body, nor, except in circumstances involving his bad faith, for anything done or omitted to be done by himself.

7.8 Claims Review Procedures. The following claim procedures shall apply until such time as a Change of Control Payment Event has occurred. During the 24-month period following a Change of Control Payment Event, these procedures shall apply only to the extent the claimant requests their application. After the expiration of the 24-month period following a Change of Control Payment Event, then, these procedures shall again apply until the occurrence of a subsequent Change of Control Payment Event.

(a) Denial of Claim. If a claim for benefits is wholly or partially denied, the claimant shall be given notice in writing of the denial within a reasonable time after the receipt of the claim, but not later than 90 days after the receipt of the claim. However, if special circumstances require an extension, written notice of the extension shall be furnished to the claimant before the termination of the 90-day period. In no event shall the extension exceed a period of 90 days after the expiration of the initial 90-day period. The notice of the denial shall contain the following information written in a manner that may be understood by a claimant:

(i)   The specific reasons for the denial;

(ii)  Specific reference to pertinent Plan provisions on which the denial is based;

(iii) A description of any additional material or information necessary for the claimant to perfect his claim and an explanation of why such material or information is necessary;

(iv) An explanation that a full and fair review by the Committee of the denial may be requested by the claimant or his authorized representative by filing a written request for a review with the Committee within 60 days after the notice of the denial is received; and

(v)   If a request for review is filed, the claimant or his authorized representative may review pertinent documents and submit issues and comments in writing within the 60-day period described in Section 7.8(a)(iv).

(b) Decisions After Review. The decision of the Committee with respect to the review of the denial shall be made promptly and in writing, but not later than 60 days after the Committee receives the request for the review. However, if special circumstances require an extension of time, a decision shall be rendered not later than 120 days after the receipt of the request for review. A written notice of the extension shall be furnished to the claimant prior to the expiration of the initial 60-day period. The claimant shall be given a copy of the decision, which shall state, in a manner calculated to be understood by the claimant, the specific reasons for the decision and specific references to the pertinent Plan provisions on which the decision is based.

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(c) Other Procedures. Notwithstanding the foregoing, the Committee may, in its discretion, adopt different procedures for different claims without being bound by past actions. Any procedures adopted, however, shall be designed to afford a claimant a full and fair review of his claim and shall comply with applicable regulations under ERISA.

7.9   Finality of Determinations; Exhaustion of Remedies. To the extent permitted by law, decisions reached under the claims procedures set forth in Section 7.8 shall be final and binding on all parties. No legal action for benefits under the Plan shall be brought unless and until the claimant has exhausted his remedies under Section 7.8. In any such legal action, the claimant may only present evidence and theories which the claimant presented during the claims procedure. Any claims which the claimant does not in good faith pursue through the review stage of the procedure shall be treated as having been irrevocably waived. Judicial review of a claimant’s denied claim shall be limited to a determination of whether the denial was arbitrary, capricious or an abuse of discretion based on the evidence and theories the claimant presented during the claims procedure. This Section shall have no application during the 24-month period following a Change of Control Payment Event as to a claim which is first asserted or first denied after the Change of Control Payment Event and, as to such a claim, the de novo standard of judicial review shall apply. After the expiration of the 24-month period following a Change of Control Payment Event, then, this Section shall again apply until the occurrence of a subsequent Change of Control Payment Event.

7.10 Effect of Fiduciary Action. The Plan shall be interpreted by the Committee and all Plan fiduciaries in accordance with the terms of the Plan and their intended meanings. However, the Committee and all Plan fiduciaries shall have the discretion to make any findings of fact needed in the administration of the Plan, and shall have the discretion to interpret or construe ambiguous, unclear or implied (but omitted) terms in any fashion they deem to be appropriate in their sole judgment. Except as stated in Section 7 9, the validity of any such finding of fact, interpretation, construction or decision shall not be given de novo review if challenged in court, by arbitration or in any other forum, and shall be upheld unless clearly arbitrary or capricious. To the extent the Committee or any Plan fiduciary has been granted discretionary authority under the Plan, the Committee’s or Plan fiduciary’s prior exercise of such authority shall not obligate it to exercise its authority in a like fashion thereafter. If any Plan provision does not accurately reflect its intended meaning, as demonstrated by consistent interpretations or other evidence of intent, or as determined by the Committee in it sole and exclusive judgment, the provision shall be considered ambiguous and shall be interpreted by the Committee and all Plan fiduciaries in a fashion consistent with its intent, as determined by the Committee in its sole discretion. The Committee, without the need for Board of Directors’ approval, may amend the Plan retroactively to cure any such ambiguity. This Section may not be invoked by any person to require the Plan to be interpreted in a manner which is inconsistent with its interpretation by the Committee or by any Plan fiduciaries. All actions taken and all determinations made in good faith by the Committee or by Plan fiduciaries shall be final and binding upon all persons claiming any interest in or under the Plan. This Section shall not apply to fiduciary or Committee actions or interpretations which take place or are made during the 24-month period following a Change of Control Payment Event. After the expiration of the 24-month period following a Change of Control Payment Event, then, this Section shall again apply until the occurrence of a subsequent Change of Control Payment Event.

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ARTICLE VIII

GENERAL PROVISIONS

8.1 Conditions of Employment Not Affected by Plan. The establishment and maintenance of the Plan shall not be construed as conferring any legal rights upon any Participant to the continuation of employment with the Company, nor shall the Plan interfere with the rights of the Company to discharge any Participant with or without cause.

8.2 Restrictions on Alienation of Benefits. No right or benefit under this Plan shall be subject to anticipation, alienation, sale, assignment, pledge, encumbrance, or charge, and any attempt to anticipate, alienate, sell, assign, pledge, encumber, or charge the same shall be void. No right or benefit hereunder shall in any manner be liable for or subject to the debts, contracts, liabilities, or torts of the person entitled to such benefit. If any Participant or the Participant’s Beneficiary under this Plan should become bankrupt or attempt to anticipate, alienate, sell, assign, pledge, encumber, or charge any right to a benefit hereunder, then, such right or benefit shall cease and terminate.

8.3 Information Required of Participants. Payment of benefits shall begin as of the payment date(s) provided in this Plan and no formal claim shall be required therefor; provided, in the interest of orderly administration of the Plan, the Committee may make reasonable requests of Participants and Beneficiaries to furnish information which is reasonably necessary and appropriate to the orderly administration of the Plan, and, to that limited extent, payments under the Plan are conditioned upon the Participants and Beneficiaries promptly furnishing true, full and complete information as the Committee may reasonably request.

8.4 Tax Consequences Not Guaranteed. The Company does not warrant that this Plan will have any particular tax consequences for Participants or Beneficiaries and shall not be liable to them if tax consequences they anticipate do not actually occur. The Company shall have no obligation to indemnify a Participant or Beneficiary for lost tax benefits (or other damage or loss).

8.5 Benefits Payable to Incompetents. Any benefits payable hereunder to a minor or person under legal disability may be made, at the discretion of the Committee, (i) directly to the said person, or (ii) to a parent, spouse, relative by blood or marriage, or the legal representative of said person. The Committee shall not be required to see to the application of any such payment, and the payee’s receipt shall be a full and final discharge of the Committee’s responsibility hereunder.

8.6 Severability. If any provision of the Plan is held invalid or illegal for any reason, any illegality or invalidity shall not affect the remaining provisions of the Plan, and the Plan shall be construed and enforced as if the illegal or invalid provision had never been contained therein. The Company shall have the privilege and opportunity to correct and remedy such questions of illegality or invalidity by amendment.

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8.7   Tax Withholding. The Employer may withhold from a payment or accrued benefit or from the Eligible Employee’s other compensation any federal, state, or local taxes required by law to be withheld with respect to such payment or accrued benefit and such sums as the Employer may reasonably estimate as necessary to cover any taxes for which the Employer may be liable and which may be assessed with regard to such payment.

8.8   Domestic Relations Orders. The Committee shall establish procedures for determining whether an order directed to the Plan is a Plan-Approved Domestic Relations Order. If the Committee determines that an order is a Plan-Approved Domestic Relations Order, the Committee shall cause the payment of amounts pursuant to or segregate a separate account as provided by (and to prevent any payment or act which might be inconsistent with) the Plan-Approved Domestic Relations Order to the extent permitted by Section 409A of the Code.

ARTICLE IX

AMENDMENT AND TERMINATION

9.1   Amendment and/or Termination. The Committee may amend or modify the Plan at any time and in any manner. Provided, (i) no amendment shall reduce any portion of a Participant’s Account that is vested and (ii) no amendment shall be effective to the extent it results in a violation of 409A of the Code. The Committee may terminate the Plan within the parameters and limitations imposed by Section 409A of the Code.

ARTICLE X

MISCELLANEOUS PROVISIONS

10.1 Articles and Section Titles and Headings. The titles and headings at the beginning of each Article and Section shall not be considered in construing the meaning of any provisions in this Plan.

10.2 Joint Obligations. For purposes of this Plan, the Company and Devon Energy Company, L.P., an Oklahoma limited partnership shall have joint and several liability for all obligations hereunder.

10.3 Governing Law. This Plan is subject to ERISA, but is exempt from most parts of ERISA since it is an unfunded deferred compensation plan maintained for a select group of management or highly compensated employees. In no event shall any references to ERISA in the Plan be construed to mean that the Plan is subject to any particular provisions of ERISA. The Plan shall be governed and construed in accordance with federal law and the laws of the State of Oklahoma, except to the extent such laws are preempted by ERISA.

*         *         *         *

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IN WITNESS WHEREOF, the Company has caused this instrument to be executed by their duly authorized officers in a number of copies, each of which shall be deemed an original but all of which shall constitute one and the same instrument.

DEVON ENERGY CORPORATION, a Delaware corporation
By:	/s/    Frank W. Rudolph
	Frank W. Rudolph, Executive Vice-President Human Resources

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EX-10.18

Exhibit 10.18

DEVON ENERGY CORPORATION

SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN

TABLE OF CONTENTS

	Page
ARTICLE I ESTABLISHMENT AND PURPOSE		1
1.1 Establishment		1
1.2 Purpose		1
1.3 ERISA Status		1
ARTICLE II DEFINITIONS		2
2.1 Definitions		2
2.2 Construction		6
2.3 Funding		7
ARTICLE III ELIGIBILITY AND PARTICIPATION		7
3.1 Eligibility		7
3.2 Plan Not Contract of Employment		7
ARTICLE IV COMPANY CONTRIBUTIONS		7
4.1 Plan Year by Plan Year Contribution Amount		7
4.2 Change of Control Contribution Amount		8
ARTICLE V VESTING		8
5.1 Vesting		8
5.2 Forfeitures		9
ARTICLE VI PAYMENT OF ACCOUNT		9
6.1 Payment Events		9
6.2 Time and Method of Payment		9
6.3 Beneficiary Designations		10
ARTICLE VII ACCOUNTS AND INVESTMENT		10
7.1 Participant Accounts		10
7.2 Adjustment of Accounts		10
7.3 Credited Earnings		11
7.4 Account Statements		11
ARTICLE VIII ADMINISTRATION		11
8.1 Administration		11
8.2 Indemnification		11
8.3 Rules of Conduct		11
8.4 Legal, Accounting, Clerical and Other Services		11
8.5 Records of Administration		11
8.6 Expenses		12
8.7 Liability		12

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TABLE OF CONTENTS

(continued)

	Page
8.8   Claims Review Procedures		12
8.9   Finality of Determinations; Exhaustion of Remedies		13
8.10 Effect of Fiduciary Action		13
ARTICLE IX GENERAL PROVISIONS		14
9.1   Restrictions on Alienation of Benefits		14
9.2   Information Required of Participants		14
9.3   Tax Consequences Not Guaranteed		14
9.4   Benefits Payable to Minors or Persons with Legal Disability		14
9.5   Severability		14
9.6   Tax Withholding		14
9.7   Domestic Relations Orders		14
9.8   No Guaranty of Benefits		15
ARTICLE X AMENDMENT AND TERMINATION		15
ARTICLE XI MISCELLANEOUS PROVISIONS		15
11.1 Articles and Section Titles and Headings		15
11.2 Joint Obligations		15
11.3 Unfunded Plan		15
11.4 Governing Law		16
11.5 Compliance with Code Section 409A		16

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DEVON ENERGY CORPORATION

SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN

ARTICLE I

ESTABLISHMENT AND PURPOSE

1.1 Establishment. Devon Energy Corporation, a Delaware corporation (“Company”), has established an unfunded, nonqualified deferred compensation plan known as the Devon Energy Corporation Supplemental Executive Retirement Plan (the “Plan”). This Plan is effective January 1, 2010 for key executive officers selected by the Committee to participate in this Plan and was originally adopted by the Company on February 14, 2011. This Plan was amended and restated as of October 10, 2011 to clarify the benefits provided in certain circumstances following a Change in Control Payment Event and to make certain other clarifying changes. This Plan is hereby amended and restated effective as of January 1, 2012 to incorporate prior amendments and to make certain other clarifying changes.

1.2 Purpose. Certain key employees of the Company or an Affiliate (as defined in Section 2.1(c)) may participate in one or more of the following plans: the Devon Energy Corporation Incentive Savings Plan (“Incentive Savings Plan”), the Devon Energy Corporation Defined Contribution Restoration Plan (“DC Restoration Plan”) and the Devon Energy Corporation Supplemental Contribution Plan (“Supplemental Contribution Plan”). It is anticipated and intended that the benefits paid to such key employees from such plans will provide each key employee with a comparable benefit to the benefit that would otherwise be provided to the key employee under the Retirement Plan for Employees of Devon Energy Corporation (“Retirement Plan”) and the Devon Energy Corporation Supplemental Retirement Income Plan (“SRI Plan”). For these purposes, the group of “key employees” includes those key employees who are providing services to the Company or an Affiliate in key positions of management and responsibility and who either (i) elected, through the retirement choice project, to participate in the Incentive Savings Plan and declined participation in the Retirement Plan, or (ii) were hired after October 1, 2007 and, therefore, ineligible for participation in the Retirement Plan. However, there may be circumstances where, due to a limited opportunity to accrue years of service, the Committee may determine that a supplemental retirement benefit is needed to attain a comparable benefit. This Plan allows key employees selected by the Committee to participate in this Plan with the opportunity to earn and receive a supplement to the benefits otherwise payable to each such key employee under the Incentive Savings Plan, the DC Restoration Plan, and/or the Supplemental Contribution Plan in order to ensure the executive is receiving a level of retirement benefits commensurate with his role at the Company. The supplemental benefit payable under this Plan will be determined based upon the Contributions and Credited Earnings credited to a Participant’s Account. Benefits to be earned under this Plan are not guaranteed and will be earned in accordance with the terms of this Plan.

1.3 ERISA Status. This Plan is intended to qualify for the exemptions provided under Title I of ERISA for plans that are not tax-qualified and that are maintained primarily to provide deferred compensation for a select group of management or highly compensated salaried employees as defined in ERISA Section 201(2).

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ARTICLE II

DEFINITIONS

2.1 Definitions. For purposes of this Plan, the following definitions shall apply:

(a) “Account” means the recordkeeping account maintained by the Company to record the payment obligation of the Company to a Participant as determined under the terms of this Plan.

(b) “Admission Date” means the date on which an Eligible Employee becomes a Participant in this Plan.

(c) “Affiliate” means a corporation, trade or business that, together with the Company, is treated as a single employer under Code Section 414(b) or (c).

(d) “Annual Bonus” shall mean the bonus payable to the Participant in the Plan Year in question as reported on the payroll records of the Company; provided, that for purposes of determining a Participant’s contribution amount under Section 4.2, Annual Bonus shall mean the greater of (i) the average of the annual bonuses paid to the Participant for the three most recently completed annual bonus periods preceding the Participant’s Separation from Service, or (ii) the greater of the Participant’s target bonus amount for (I) the year in which the Change of Control Payment Event occurred, or (II) the year in which the Participant’s Separation from Service occurs.

(e) “Annual Compensation” means “compensation” (as defined under Section 2.1(m), as amended, of the Incentive Plan) payable to an eligible Participant in a Plan Year, determined before deductions of any kind and determined without regard to any limitation imposed by the Code under the Incentive Savings Plan; provided, that for purposes of determining a Participant’s contribution amount under Section 4.2, Annual Compensation shall mean the greater of the Participant’s base rate of pay as in effect for (i) the year in which the Change of Control Payment Event occurred, or (ii) the year in which the Participant’s Separation from Service occurs. For clarification purposes, in each Plan Year a Participant’s Annual Compensation shall include the amount of the Participant’s Annual Bonus that is paid in such Plan Year.

(f) “Beneficiary” means, pursuant to Section 6.4, the person, persons, trust, or other entity designated by a Participant on the beneficiary designation form adopted by the Company to receive benefits, if any, under this Plan following Participant’s death.

(g) “Cause” or “cause” shall mean (i) if there is a written employment or severance agreement between the Participant and the Employer or an Affiliate that defines termination of such employment relationship for cause, “cause” as defined in such agreement, and (ii) in the absence of such a written employment or severance agreement, (I) the willful failure by the Participant to substantially perform the Participant’s duties for the Employer or an Affiliate (other than due to physical or mental incapacity) within thirty (30) days after receiving a written demand for substantial performance from the Company’s Chief Executive Officer or Board of Directors, (II) the willful engaging by the Participant in illegal or dishonest conduct or gross misconduct that is materially and demonstrably injurious to the Employer or an Affiliate, or (III) the conviction of the Participant of a felony or any crime of moral

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turpitude, a guilty or nolo contendere plea by the Participant with respect to a felony or any crime of moral turpitude, or the deferred adjudication or unadjudicated probation of the Participant with respect to a felony or any crime of moral turpitude, provided, however, that (x) an act or omission by the Participant shall be considered “willful” only if it was not in good faith and was without reasonable belief that it was in the Employer’s best interests, and (y) any act or omission by the Participant based upon authority granted by resolution duly adopted by the Company’s Board of Directors, the instructions of the Company’s Chief Executive Officer, or the advice of counsel for the Company shall be conclusively presumed to be in good faith and in the Company’s best interests.

(h) “Change of Control Payment Event” shall mean and shall be deemed to have occurred each time any one of the events described in paragraphs (i), (ii), (iii) or (iv) below occurs. For the purpose of this subsection (h), the term “Company” shall mean Devon Energy Corporation and any successor thereto.

(i) The acquisition of stock of the Company by any one person, or more than one person acting as a group (as defined in §1.409A-3(i)(5)(v)(B) of the Treasury Regulations) (a “Person”) if, immediately after such acquisition, such Person owns more than 50% of either (I) the then outstanding shares of common stock of the Company or (II) the combined voting power of the then outstanding voting securities of the Company entitled to vote generally in the election of directors; provided, however, that the following acquisitions shall not constitute a Change of Control Payment Event: (A) any acquisition by an underwriter temporarily holding securities pursuant to an offering of such securities; (B) any acquisition by the Company; (C) any acquisition by any employee benefit plan (or related trust) sponsored or maintained by the Company or any corporation controlled by the Company. If a Change of Control Payment Event occurs by reason of an acquisition described in this paragraph (i), no additional Change of Control Payment Event shall be deemed to occur under this paragraph (i) by reason of subsequent changes in the holdings of such Person (except if the holdings of such Person are reduced to 50% or below and thereafter increase to more than 50%).

(ii) During a 12-month period, a majority of the individuals who, as of January 1, 2009, constitute the Board (the “Incumbent Board”) are replaced; provided, however, that any individual becoming a director subsequent to January 1, 2009 whose election, appointment or nomination for election by the Company’s shareholders was approved by a vote of at least a majority of the directors then comprising the Incumbent Board shall be considered as though such individual were a member of the Incumbent Board, but excluding, for purposes of this definition, any such individual whose initial assumption of office occurs as a result of an actual or publicly threatened election contest (as such terms are used in Rule 14a-11 promulgated under the Exchange Act) with respect to the election or removal of directors or other actual or publicly threatened solicitation of proxies or consents by or on behalf of a Person other than the Board.

(iii) The date a Person acquires (or has acquired during the 12-month period ending on the date of the most recent acquisition by such Person) ownership of stock of the Company possessing 30% or more of the combined voting power of the then outstanding voting securities of the Company; provided that, if a Change of Control Payment Event occurs by reason of such acquisition, no additional Change of Control Payment Event shall be deemed to occur under this paragraph (iii) or paragraph (i) by reason of the acquisition of additional control of the Company by the same Person.

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(iv) Approval by the shareholders of the Company of the sale or other disposition of all or substantially all of the assets of the Company to a Person; provided that, a transfer of the Company’s assets shall not be treated as a Change of Control Payment Event if the assets are transferred to:

(1) A shareholder of the Company (immediately before the asset transfer) in exchange for or with respect to its stock;

(2) An entity, 50% or more of the total value or voting power of which is owned, directly or indirectly, by the Company;

(3) A person that owns, directly or indirectly, 50% or more of the total value or voting power of all the outstanding stock of the Company; or

(4) An entity, at least 50% of the total value or voting power of which is owned, directly or indirectly by a Person described in subsection (g)(iv)(3).

Except as otherwise provided in this subsection (iv), a person’s status is determined immediately after the transfer of the assets.

(i)   “Code” means the Internal Revenue Code of 1986, as amended from time to time, and any regulations relating thereto.

(j)   “Committee” means the Compensation Committee appointed by the Board of Directors of the Company or a committee established by the Compensation Committee that has been delegated duties related to this Plan.

(k)  “Company” means Devon Energy Corporation, a Delaware corporation.

(l)   “Contribution Amount” or “Contributions” means the amount contributed by the Company to the Participant’s Account pursuant to Article IV. Contribution Amounts shall be determined by reference to this Plan Year.

(m) “Credited Earnings” means the earnings or losses credited to a Participant’s Account pursuant to Section 7.3.

(n)  “Disabled” or “Disability” means a Participant is unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment that can be expected to result in death or last for a continuous period of not less than 12 months. The Committee shall determine whether a Participant is Disabled in accordance with Code Section 409A.

(o)  “ERISA” means the Employee Retirement Income Security Act of 1974, as amended.

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(p) “Eligible Employee” means a key employee of an Employer who is providing services to the Employer in key positions of management and responsibility and who either (i) elected, through the retirement choice project, to participate in the Incentive Savings Plan and declined participation in the Retirement Plan, or (ii) was hired after October 1, 2007 and, therefore, ineligible for participation in the Retirement Plan.

(q) “Employer” shall mean the Company and/or any Affiliate that employs the Participant.

(r) “Good reason” or “good reason” shall mean (i) if there is a written employment or severance agreement between the Participant and the Employer or an Affiliate that defines termination of such employment relationship for good reason, “good reason” as defined in such agreement, and (ii) in the absence of such a written employment or severance agreement, (I) the assignment of any duties materially inconsistent with the Participant’s position (including status, offices, and titles), authority, duties, or responsibilities, other than an isolated, insubstantial, or inadvertent action not taken in bad faith and which the Employer remedies promptly after receipt of notice from the Participant; provided, however, that Good Reason shall not exist under the Plan solely because of a change in the Participant’s reporting relationship, (II) any reduction in Annual Compensation or material failure to provide incentive compensation opportunities or benefits to the Participant that are comparable to the incentive compensation opportunities and benefits provided to similarly situated employees of the Employer, (III) any material failure by the Company to comply with any provision of the Plan, other than an isolated, insubstantial, or inadvertent failure not occurring in bad faith and which and which the Company remedies promptly after receipt of notice from the Participant, and any relocation of the Participant’s principal office to a location more than fifty (50) miles from the Participant’s principal office prior to such relocation.

(s) “Incentive Plan” shall mean the Devon Energy Corporation Incentive Savings Plan.

(t) “Offset Amount” shall mean the sum of: (i) the “Devon Retirement Contribution” under the Devon Energy Corporation Incentive Savings Plan, (ii) the “Company Contribution” under the Devon Energy Corporation Supplemental Contribution Plan and/or (iii) the “Company Contribution” under the Devon Energy Corporation Defined Contribution Restoration Plan contributed by the Company for the benefit of the Participant with respect to the applicable Plan Year.

(u) “Overall Annual Contribution Percentage” means the percentage of Annual Compensation that is established by the Committee for each Participant and represents an appropriate level of retirement benefits to be paid to the Participant, in the aggregate under all retirement plans in which the Participant participates. A Participant’s Overall Annual Contribution Percentage shall be determined before any reduction for amounts contributed on the Participant’s behalf under the Incentive Savings Plan, the DC Restoration Plan, and the Supplemental Contribution Plan and shall be set forth in writing in a form approved by the Committee.

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(v) “Participant” means an Eligible Employee who has been selected by the Committee to participate in this Plan.

(w) “Plan” means this Devon Energy Corporation Supplemental Executive Retirement Plan.

(x) “Plan-Approved Domestic Relations Order” means a qualified domestic relations order that meets the requirements established by the Committee.

(y) “Plan Year” means the 12-month period beginning on January 1^st and ending on December 31^st.

(z) “Separation from Service” A Participant incurs a Separation from Service upon termination of employment with the Employer. Whether a Separation from Service has occurred shall be determined by the Committee in accordance with Code Section 409A.

Except in the case of a Participant on a bona fide leave of absence as provided below, a Participant is deemed to have incurred a Separation from Service if the Employer and the Participant reasonably anticipated that the level of services to be performed by the Participant after a certain date would be reduced to 20% or less of the average services rendered by the Participant during the immediately preceding 36-month period (or the total period of employment, if less than 36 months), disregarding periods during which the Participant was on a bona fide leave of absence.

A Participant who is absent from work due to military leave, sick leave, or other bona fide leave of absence shall incur a Separation from Service on the first date immediately following the later of (i) the six-month anniversary of the commencement of the leave or (ii) the expiration of the Participant’s right, if any, to reemployment under statute or contract.

For purposes of determining whether a Separation from Service has occurred, the Employer means the Employer as defined in Section 2.1(p) of this Plan, except that for purposes of determining whether another organization is an Affiliate of the Company, common ownership of at least 50% shall be determinative.

(aa) “Specified Employee” shall, for any Plan Year in which any stock of the Company is publicly traded on an established securities market, mean a “key employee” (within the meaning of that term under Code Section 416(i)), as determined by the Committee in accordance with the applicable standards of Code Section 409A and the Treasury Regulations thereunder and applied on a consistent basis for all non-qualified deferred compensation plans of the Employer Group subject to Code Section 409A. The Specified Employees shall be identified on December 31 of each calendar year and shall have that status for the twelve (12)-month period beginning on April 1 of the following calendar year. Determinations by the Committee regarding Specified Employees shall be final and binding on all affected parties.

2.2 Construction. It is intended that this Plan comply with Code Section 409A; therefore, in the event that a Plan definition or provision is determined to be ambiguous, it shall be interpreted so as to comply with Code Section 409A. The masculine gender, where appearing in this Plan, shall be deemed to include the feminine gender, unless the context clearly indicates to the contrary. Any word

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appearing herein in the plural shall include the singular, where appropriate, and likewise the singular shall include the plural, unless the context clearly indicates to the contrary.

2.3 Funding. The benefits described in this Plan are contractual obligations of the Employer to pay compensation for services, and shall constitute a liability to the Participants and/or their Beneficiaries in accordance with the terms hereof. All amounts paid under this Plan shall be paid in cash from the general assets of the Employer and shall be subject to the general creditors of the Company and the Employer of the Participant. Benefits shall be reflected on the accounting records of the Employer but shall not be construed to create, or require the creation of, a trust, custodial or escrow account. No special or separate fund need be established and no segregation of assets need be made to assure the payment of such benefits. No Participant shall have any right, title or interest whatsoever in or to any investment reserves, accounts, funds or assets that the Employer may purchase, establish or accumulate to aid in providing the benefits described in this Plan. Nothing contained in this Plan, and no action taken pursuant to its provisions, shall create or be construed to create a trust or a fiduciary relationship of any kind between an Employer or the Company and a Participant or any other person. Provided, the Company may establish and/or continue a grantor trust as defined in Code Section 671 to provide a source of funding for amounts deferred hereunder. Neither a Participant nor the Beneficiary of a Participant shall acquire any interest hereunder greater than that of an unsecured creditor of the Company or any Affiliate who is the Employer of such Participant.

ARTICLE III

ELIGIBILITY AND PARTICIPATION

3.1 Eligibility. The Committee shall provide Eligible Employees selected for participation in this Plan with notice of their selection to be a Participant under this Plan. Notice may be given at such time and in such manner as the Committee may determine. All determinations regarding eligibility for participation in this Plan will be made by the Committee. The determinations of the Committee shall be final and binding.

3.2 Plan Not Contract of Employment. This Plan does not constitute a contract of employment, and participation in this Plan will not give any Participant the right to be retained in the employ of the Company nor any right or claim to any benefit under this Plan, unless such right or claim has specifically accrued under the terms of this Plan.

ARTICLE IV

COMPANY CONTRIBUTIONS

4.1 Plan Year by Plan Year Contribution Amount. At the time the Participant is selected for participation in this Plan, the Committee shall establish the Overall Annual Contribution Percentage for the Participant. For each Participant, the Contribution Amount to be contributed to such Participant’s Account each Plan Year will be equal to (i) the Participant’s Overall Annual Contribution Percentage multiplied by the Participant’s Annual Compensation for the applicable Plan Year minus (ii) the Offset Amount.

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4.2 Change of Control Contribution Amount. Notwithstanding Section 4.1, if a Participant has a Separation from Service as a result of the Company’s termination of the Participant’s employment without Cause or the Participant’s termination of employment for Good Reason within 24 months following the effective date of a Change of Control Payment Event, the Company will contribute an amount equal to three (3) times the Participant’s Overall Annual Contribution Percentage multiplied by the Participant’s Annual Compensation and, for the avoidance of doubt, this contribution amount shall not be offset by the Offset Amount or any other offset.

ARTICLE V

VESTING

5.1 Vesting. A Participant shall vest in his Account balance pursuant to the following provisions:

(a) Participant Death or Disability. If a Participant has a Separation from Service as a result of death or Disability, the Participant’s Account balance will be one hundred percent (100%) vested.

(b) Change in Control Payment Event. In the event of the occurrence of a Change of Control Payment Event, the Participant’s Account balance will be one hundred percent (100%) vested.

(c) Separation from Service for Good Reason or without Cause. If a Participant has a Separation from Service as a result of the Company’s termination of the Participant’s employment without Cause or the Participant’s termination of employment for Good reason, the Participant’s Account balance will be one hundred percent (100%) vested.

(d) Completion of Service Vesting. If not vested earlier pursuant to Sections 5.1 (a), (b), or (c), or except as provided under Section 5.1(e), the right to receive payment of any amount under this Plan is contingent upon completion of a period of continuous employment service with the Participant’s Employer (including all of a Participant’s service worked with the Employer or an Affiliate and service both before and after the Participant became eligible to participate in the Plan) until the applicable vesting date. The Participant will be vested in the balance of his Account in accordance with the following schedule:

Years of Continuous Service	Vested Percentage
Less than 5 years		0	%
5 years		50	%
6 years		60	%
7 years		70	%
8 years		80	%
9 years		90	%
10 or more		100	%

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(e) Acceleration of Vesting. Notwithstanding anything to the contrary herein, if the Participant has attained age 62 on or before the Participant’s Admission Date or attains age 62 during the Participant’s vesting period, as established in Section 5.1(d), Participant shall be fully vested in his Account on the later of (i) the date the Participant attains age 62, or the (ii) fifth anniversary of the Participant’s Admission Date.

5.2 Forfeitures. Unless a Participant is vested in his Account balance pursuant to Section 5.1, the unvested portion of a Participant’s Account shall be forfeited upon the Participant’s Separation from Service.

ARTICLE VI

PAYMENT OF ACCOUNT

6.1 Payment Events. A Participant’s vested Account shall become payable at the time and in the form described in this Article upon Separation from Service. A Participant’s vested Account shall also become payable prior to this time in the event of (i) a Participant’s Disability, (ii) a Change of Control Payment Event or (iii) a Participant’s death.

6.2 Time and Method of Payment.

(a) Separation from Service; Disability, Death, Change of Control Payment Event. In the event a Participant’s Account becomes payable due to Separation from Service, Disability, death, or a Change of Control Payment Event, the Participant will receive a distribution of his Account balance in the form of a single lump sum distribution with such distribution being made within 90 days of the date of Separation from Service, Disability, death, or Change of Control Payment Event, as applicable, subject to the six-month delay requirement set forth in Section 6.3.

(b) Final Contribution Amount. It is possible that a Participant may be entitled to a Contribution Amount for a Plan Year in which a payment event occurs but such Contribution Amount, if any, will not be determinable until the Plan Year immediately following this Plan Year in which the payment event occurred. Therefore, to the extent the Participant is entitled to a Contribution Amount that is attributable to the Plan Year in which a payment event occurs, such Contribution Amount will be paid in a lump sum by December 31 of the Plan Year immediately following the Plan Year in which the payment event occurred.

For any Plan Year in which any stock of the Company is publicly traded on an established securities market, notwithstanding any provision to the contrary in this Plan, no distribution which becomes due and payable by reason of a Participant’s Separation from Service shall be made to such Participant prior to the earlier of (i) the first day of the seventh (7th) month following the date of the Participant’s Separation from Service or (ii) the date of his or her death, if the Participant is deemed at the time of such Separation from Service to be a Specified Employee and such delayed commencement is otherwise required in order to avoid a prohibited distribution under Code Section 409A(a)(2). If payment of any amount under this Plan is required to be delayed for a period of six (6) months after Separation from Service pursuant to Code Section 409A, the accumulated postponed amount, with interest, shall be paid in a lump sum payment within ninety (90) days after the end of the six-month period. If the Participant dies during the

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postponement period prior to the payment of postponed amount, the amounts withheld on account of Code Section 409A, with interest, shall be paid to the personal representative of the Participant’s estate within sixty (60) days after the date of the Participant’s death. If amounts are postponed on account of section 409A, the postponed amounts will be credited with interest for the postponement period based upon the investment return provisions of Article VII.

In accordance with section 1.409A-3(d) of the Treasury Regulations, a distribution under this Plan will be treated as made on the designated “payment date” if the payment is made (i) at such date or a later date within the same calendar year, or if later, by the 15th day of the third month following the date designated in this Plan (provided the Participant may not, directly or indirectly, designate the year of payment), or (ii) at a date no earlier that 30 days before the designated Payment Date and the Participant (or, in the event of the death of the Participant, his or her Beneficiary) may not directly or indirectly designate the calendar year of the payment.

6.3 Beneficiary Designations. A Participant shall designate on a beneficiary designation form a Beneficiary who, upon the Participant’s death, will receive payments that otherwise would have been paid to him under this Plan. All Beneficiary designations shall be in writing. Any such designation shall be effective only if and when delivered to the Committee during the lifetime of the Participant. A Participant may change a Beneficiary or Beneficiaries by filing a new beneficiary designation form. The latest beneficiary designation form shall apply to the Account of the Participant. If a Beneficiary of a Participant predeceases the Participant, the designation of such Beneficiary shall be void. If a Participant fails to designate a Beneficiary with respect to any death benefit payments or if such designation is ineffective, any payment that does not have an effective Beneficiary designation shall be paid to the Participant’s estate.

If a married Participant designates the Participant’s spouse as the Participant’s Beneficiary, and subsequent to such designation, the Participant and the Participant’s spouse are divorced, such designation shall automatically be voided. In this instance, the Participant’s Beneficiary shall be the secondary Beneficiary, or if no such designation has been made, the Participant’s designation as made under the Incentive Plan. Should the Participant wish to designate an ex-spouse as his or her Beneficiary, he or she must affirmatively do so by completing a new Beneficiary designation form after the divorce, naming his ex-spouse as his or her Beneficiary.

ARTICLE VII

ACCOUNTS AND INVESTMENT

7.1 Participant Accounts. The Committee shall maintain, or cause to be maintained, an Account for each Participant for the purpose of accounting for the Participant’s interest under this Plan. This Account shall be maintained for bookkeeping purposes only. No cash amounts shall actually be deposited into the Account. No interest shall be credited on amounts credited to the Account.

7.2 Adjustment of Accounts. Each Participant’s Account shall be adjusted to reflect all Contributions credited to the Participant’s Account, all Credited Earnings credited or debited to the Participant’s Account as provided by Section 7.3, and all payments charged to the Participant’s Account.

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7.3 Credited Earnings. The Committee will offer Participants a selection of benchmark funds as deemed investment alternatives. The benchmark funds offered will be determined in the sole discretion of the Committee. Each Participant may select among the different benchmark funds offered. The deemed investments in benchmark funds are only for the purpose of determining the Company’s payment obligation under this Plan. Credited Earnings shall be allocated to a Participant’s Account pursuant to the performance of the benchmark funds selected by the Participant. A Participant may, as frequently as daily, modify his election of benchmark funds through a procedure designated by the Committee. Such modification will be in accordance with rules and procedures adopted by the Committee.

7.4 Account Statements. The Committee shall provide each Participant with a statement of the status of the Participant’s Account under this Plan. The Committee shall provide such statement annually or at such other times as the Committee may determine. Annual statements shall be in the format prescribed by the Committee.

ARTICLE VIII

ADMINISTRATION

8.1 Administration. This Plan shall be administered, construed and interpreted by the Committee. The Committee shall have the sole authority and discretion to determine eligibility and to interpret and construe the terms of this Plan. The determinations by the Committee as to any disputed questions arising under this Plan, and the construction and interpretation by the Committee of any provision of this Plan, shall be made in the Committee’s sole discretion and shall be final, conclusive and binding upon all persons including Participants, their beneficiaries, the Company, its stockholders and employees and the Employers.

8.2 Indemnification. The members of the Committee and its agents shall be indemnified and held harmless by the Company against and from any and all loss, cost, liability or expense that may be imposed upon or reasonably incurred by them in connection with or resulting from any claim, action, suit or proceeding to which they may be a party or in which they may be involved by reason of any action taken or failure to act under this Plan and against and from any and all amounts paid by them in settlement (with the Company’s written approval) or paid by them in satisfaction of a judgment in any such action, suit or proceeding. The foregoing provisions shall not be applicable to any person if the loss, cost, liability or expense is due to such person’s gross negligence or willful misconduct.

8.3 Rules of Conduct. The Committee shall adopt such rules for the conduct of its business and the administration of this Plan as it considers desirable, provided they do not conflict with the provisions of this Plan.

8.4 Legal, Accounting, Clerical and Other Services. The Committee may authorize one or more of its members or any agent to act on its behalf and may contract for legal, accounting, clerical and other services to carry out this Plan. The Company shall pay all expenses of the Committee.

8.5 Records of Administration. The Committee shall keep records reflecting the administration of this Plan, which shall be subject to audit by the Company.

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8.6 Expenses. The expenses of administering this Plan shall be borne by the Company.

8.7 Liability. No member of the Board of Directors or of the Committee (or any authorized delegate thereof) shall be liable for any act or action, whether of commission or omission, taken by any other member, or by any officer, agent, or employee of the Company or of any such body, nor, except in circumstances involving his bad faith, for anything done or omitted to be done by himself.

8.8 Claims Review Procedures. The following claim procedures shall apply until such time as a Change of Control Payment Event has occurred. During the 24-month period following a Change of Control Payment Event, these procedures shall apply only to the extent the claimant requests their application. After the expiration of the 24-month period following a Change of Control Payment Event, these procedures shall again apply until the occurrence of a subsequent Change of Control Payment Event.

(a) Denial of Claim. If a claim for benefits is wholly or partially denied, the claimant shall be given notice in writing of the denial within a reasonable time after the receipt of the claim, but not later than 90 days after the receipt of the claim. However, if special circumstances require an extension, written notice of the extension shall be furnished to the claimant before the termination of the 90-day period. In no event shall the extension exceed a period of 90 days after the expiration of the initial 90-day period. The notice of the denial shall contain the following information written in a manner that may be understood by a claimant:

(i) The specific reasons for the denial;

(ii) Specific reference to pertinent Plan provisions on which the denial is based;

(iii) A description of any additional material or information necessary for the claimant to perfect his claim and an explanation of why such material or information is necessary;

(iv) An explanation that a full and fair review by the Committee of the denial may be requested by the claimant or his authorized representative by filing a written request for a review with the Committee within 60 days after the notice of the denial is received; and

(v) If a request for review is filed, the claimant or his authorized representative may review pertinent documents and submit issues and comments in writing within the 60-day period described in Section 8.8(a)(iv).

(b) Decisions After Review. The decision of the Committee with respect to the review of the denial shall be made promptly and in writing, but not later than 60 days after the Committee receives the request for the review. However, if special circumstances require an extension of time, a decision shall be rendered not later than 120 days after the receipt of the request for review. A written notice of the extension shall be furnished to the claimant prior to the expiration of the initial 60-day period. The claimant shall be given a copy of the decision, which shall state, in a manner calculated to be understood by the claimant, the specific reasons for the decision and specific references to the pertinent Plan provisions on which the decision is based.

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(c) Other Procedures. Notwithstanding the foregoing, the Committee may, in its discretion, adopt different procedures for different cla｢ims without being bound by past actions. Any procedures adopted, however, shall be designed to afford a claimant a full and fair review of his claim and shall comply with applicable regulations under ERISA.

8.9   Finality of Determinations; Exhaustion of Remedies. To the extent permitted by law, decisions reached under the claims procedures set forth in Section 8.8 shall be final and binding on all parties. No legal action for benefits under this Plan shall be brought unless and until the claimant has exhausted his remedies under Section 8.8. In any such legal action, the claimant may only present evidence and theories which the claimant presented during the claims procedure. Any claims which the claimant does not in good faith pursue through the review stage of the procedure shall be treated as having been irrevocably waived. Judicial review of a claimant’s denied claim shall be limited to a determination of whether the denial was arbitrary, capricious or an abuse of discretion based on the evidence and theories the claimant presented during the claims procedure. This Section shall have no application during the 24-month period following a Change of Control Payment Event as to a claim which is first asserted or first denied after the Change of Control Payment Event and, as to such a claim, the de novo standard of judicial review shall apply.

8.10 Effect of Fiduciary Action. This Plan shall be interpreted by the Committee and all Plan fiduciaries in accordance with the terms of this Plan and their intended meanings. However, the Committee and all Plan fiduciaries shall have the discretion to make any findings of fact needed in the administration of this Plan, and shall have the discretion to interpret or construe ambiguous, unclear or implied (but omitted) terms in any fashion they deem to be appropriate in their sole judgment. Except as stated in Section 8.9, the validity of any such finding of fact, interpretation, construction or decision shall not be given de novo review if challenged in court, by arbitration or in any other forum, and shall be upheld unless clearly arbitrary or capricious. To the extent the Committee or any Plan fiduciary has been granted discretionary authority under this Plan, the Committee’s or Plan fiduciary’s prior exercise of such authority shall not obligate it to exercise its authority in a like fashion thereafter. If any Plan provision does not accurately reflect its intended meaning, as demonstrated by consistent interpretations or other evidence of intent, or as determined by the Committee in its sole and exclusive judgment, the provision shall be considered ambiguous and shall be interpreted by the Committee and all Plan fiduciaries in a fashion consistent with its intent, as determined by the Committee in its sole discretion. The Committee, without the need for Board of Directors’ approval, may amend this Plan retroactively to cure any such ambiguity. This Section may not be invoked by any person to require this Plan to be interpreted in a manner which is inconsistent with its interpretation by the Committee or by any Plan fiduciaries. All actions taken and all determinations made in good faith by the Committee or by Plan fiduciaries shall be final and binding upon all persons claiming any interest in or under this Plan. This Section shall not apply to fiduciary or Committee actions or interpretations which take place or are made during the 24-month period following a Change of Control Payment Event. After the expiration of the 24-month period following a Change of Control Payment Event, this Section shall again apply until the occurrence of a subsequent Change of Control Payment Event.

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ARTICLE IX

GENERAL PROVISIONS

9.1 Restrictions on Alienation of Benefits. No right or benefit under this Plan shall be subject to anticipation, alienation, sale, assignment, pledge, encumbrance, or charge, and any attempt to anticipate, alienate, sell, assign, pledge, encumber, or charge the same shall be void except as provided in Section 9.7. No right or benefit hereunder shall in any manner be liable for or subject to the debts, contracts, liabilities, or torts of the person entitled to such benefit.

9.2 Information Required of Participants. Payment of benefits shall be made in accordance with Article VI of this Plan and no formal claim shall be required. However, the Committee may make requests of Participants and Beneficiaries to furnish information which is necessary and appropriate to the orderly administration of this Plan, and, to that limited extent, payments under this Plan are conditioned upon the Participants and Beneficiaries promptly furnishing true, full and complete information as the Committee may request.

9.3 Tax Consequences Not Guaranteed. The Company does not warrant that this Plan will have any particular tax consequences for Participants or Beneficiaries and shall not be liable to them if tax consequences they anticipate do not actually occur. The Company shall have no obligation to indemnify a Participant or Beneficiary for lost tax benefits (or other damage or loss).

9.4 Benefits Payable to Minors or Persons with Legal Disability. Any benefits payable hereunder to a minor or person under legal disability may be made, at the discretion of the Committee, (i) directly to said person, or (ii) to a parent, spouse, relative by blood or marriage, or the legal representative of said person. The Committee shall not be required to see to the application of any such payment, and the payee’s receipt shall be a full and final discharge of the Committee’s responsibility hereunder.

9.5 Severability. Any provisions of this Plan held invalid or illegal for any reason shall not affect the remaining provisions of this Plan, and this Plan shall be construed and enforced as if the illegal or invalid provision had never been contained therein. The Company shall have the privilege and opportunity to correct and remedy such questions of illegality or invalidity by amendment.

9.6 Tax Withholding. The Employer may withhold from a payment or from the Participant’s other compensation any federal, state, or local taxes required by law to be withheld with respect to such payment and such sums as the Employer may reasonably estimate as necessary to cover any taxes for which the Employer may be liable to withhold on behalf of a Participant and which may be assessed with regard to such payment.

9.7 Domestic Relations Orders. The Committee shall establish procedures for determining whether an order directed to this Plan is a Plan-Approved Domestic Relations Order. If the Committee determines that an order is a Plan-Approved Domestic Relations Order, the Committee shall cause the payment of amounts pursuant to or segregate a separate account as provided by (and to prevent any payment or act which might be inconsistent with) this Plan-Approved Domestic Relations Order to the extent permitted by Code Section 409A.

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9.8   No Guaranty of Benefits. Nothing contained in this Plan shall constitute a guaranty by the Company or an Affiliate or any other person or entity that the assets of the Company or an Affiliate will be sufficient to pay any benefit hereunder.

ARTICLE X

AMENDMENT AND TERMINATION

The Committee may amend or modify this Plan at any time and in any manner. Provided, no amendment shall be effective to the extent it results in a violation of Code Section 409A. The Committee shall also have the right to terminate this Plan at any time, provided that all of the requirements of section 1.409A of the Treasury Regulations are met. If such a complete termination occurs, this Plan shall cease to operate and the Contribution Amounts awarded under this Plan shall be distributable in accordance with Article VI which shall survive the termination of this Plan until all distributions have been made. Notwithstanding the preceding, upon termination of this Plan, the Committee may, in its sole and absolute discretion, subject only to compliance with Code Section 409A restrictions and requirements for plan termination distributions, direct that all benefits hereunder will be paid as soon as administratively practicable thereafter. In no event shall an amendment or termination adopted during the period beginning six months prior to a Change of Control Payment Event and ending on the last day of the 24^th calendar month following the calendar month in which the Change of Control Payment Event occurs adversely affect the Participant’s right to vest or to receive additional Contributions to his or her Account.

ARTICLE XI

MISCELLANEOUS PROVISIONS

11.1 Articles and Section Titles and Headings. The titles and headings at the beginning of each Article and Section shall not be considered in construing the meaning of any provisions in this Plan.

11.2 Joint Obligations. For purposes of this Plan, the Company and Devon Energy Company, L.P., an Oklahoma limited partnership, shall have joint and several liability for all obligations hereunder.

11.3 Unfunded Plan. To the extent that this Plan is determined to provide for pension benefits within the meaning of ERISA, this Plan is an unfunded plan maintained primarily to provide benefits for a select group of “management or highly-compensated employees” within the meanings of sections 201, 301, and 401 of ERISA, and therefore is exempt from the provisions of Parts 2, 3, and 4 of Title I of ERISA. Accordingly, the Board may terminate this Plan and make no further benefit payments or remove certain employees as Participants if it is determined by the United States Department of Labor, a court of competent jurisdiction, or an opinion of counsel that this Plan constitutes an employee pension benefit plan within the meaning of section 3(2) of ERISA (as currently in effect or hereafter amended) which is not so exempt.

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11.4 Governing Law. This Plan is subject to ERISA, but is exempt from most parts of ERISA since it is an unfunded deferred compensation plan maintained for a select group of management or highly compensated employees. In no event shall any references to ERISA in this Plan be construed to mean that this Plan is subject to any particular provisions of ERISA. This Plan shall be governed and construed in accordance with federal law and the laws of the State of Oklahoma, except to the extent such laws are preempted by ERISA.

11.5 Compliance with Code Section 409A. All provisions herein, or incorporated by reference, shall be construed and interpreted to comply with, and if necessary any such provision shall be held null and void to the extent such provision or part of the provision fails to comply with, Code Section 409A and the regulations thereunder. If any payment or benefit cannot be provided or made at the time specified herein without incurring sanctions under Code Section 409A, then such benefit or payment shall be provided in full at the earliest time thereafter when such sanctions will not be imposed. All payments to be made upon a termination from employment under this Plan may only be made upon a “separation from service” under Code Section 409A. For purposes of Code Section 409A, each payment made under this Plan shall be treated as a separate payment. In addition, the right to a series of installment payments under this Plan (if any) is to be treated as a right to a series of separate payments. Notwithstanding anything in this Plan to the contrary, distributions may only be made under this Plan upon an event and in a manner permitted by Code Section 409A, including the six-month delay, if applicable, or an applicable exemption. In no event may the Participant, directly or indirectly, designate the calendar year of a payment.

*        *        *         *

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IN WITNESS WHEREOF, the Company has caused this instrument to be executed by its duly authorized officers in a number of copies, each of which shall be deemed an original but all of which shall constitute one and the same instrument, effective as set forth above.

DEVON ENERGY CORPORATION, a Delaware corporation
By:	/s/    Frank W. Rudolph
	Frank W. Rudolph, Executive Vice President –
	Human Resources

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EX-10.19

Exhibit 10.19

SUPPLEMENTAL RETIREMENT INCOME PLAN OF

DEVON ENERGY CORPORATION

TABLE OF CONTENTS

	Page
ARTICLE I ESTABLISHMENT AND PURPOSE		1
1.1 Purpose and Effective Date		1
ARTICLE II DEFINITIONS AND CONSTRUCTION		1
2.1 Definitions		1
2.2 Construction		7
ARTICLE III PARTICIPATION		8
3.1 Eligibility		8
3.2 Plan Not Contract of Employment		8
3.3 Agreements		8
ARTICLE IV AMOUNT AND PAYMENT OF SUPPLEMENTAL BENEFIT		8
4.1 Amount of Supplemental Benefit		8
4.2 Vesting		10
4.3 Form of Payment and Commencement Date		11
4.4 Restrictions on Alienation of Benefits		13
4.5 Domestic Relations Orders		13
4.6 Abandonment of Benefits		14
4.7 Information Required of Participants		14
4.8 Benefits Payable to Incompetents		14
4.9 Tax Withholding		14
ARTICLE V SOURCE OF BENEFIT PAYMENTS		14
5.1 Liability for Benefit Payments		14
5.2 Discretionary Establishment of Trust		15
5.3 Secondary Liability for Payment		15
ARTICLE VI COMMITTEE		15
6.1 Administration		15
6.2 Powers of Committee		15
6.3 Delegation by Committee		16
6.4 Information to be Furnished to Committee		16
6.5 Liability and Indemnification of Committee		16
6.6 Expenses		16
ARTICLE VII CLAIMS PROCEDURE		16
7.1 Claims Review Procedures		16
7.2 Finality of Determinations; Exhaustion of Remedies		17
7.3 Effect of Fiduciary Action		18
ARTICLE VIII MISCELLANEOUS		18
8.1 Tax Consequences Not Guaranteed		18
8.2 Severability		19
8.3 Benefits Under Other Plans		19

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TABLE OF CONTENTS

(continued)

	Page
8.4 Gender and Number		19
8.5 Action by Company or Affiliate		19
8.6 Successors		19
8.7 Evidence		19
8.8 Applicable Laws		19
8.9 Attorney Fees		19
ARTICLE IX AMENDMENT AND TERMINATION		20
9.1 Amendment and/or Termination		20

APPENDIX A

APPENDIX B

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SUPPLEMENTAL RETIREMENT INCOME PLAN OF

DEVON ENERGY CORPORATION

ARTICLE I

ESTABLISHMENT AND PURPOSE

1.1 Purpose and Effective Date. The Company established the Supplemental Retirement Income Plan of Devon Energy Corporation (the “Plan”) effective July 1, 1995, and such Plan was amended and restated May 19, 1999. The Plan was subsequently amended and restated effective as of August 1, 2001 and again effective as of January 1, 2009. The Plan is hereby amended and restated effective as of January 1, 2012 to incorporate prior amendments and to make certain other clarifying changes. The Plan is intended to qualify for the exemptions provided under Title 1 of ERISA for plans that are not tax qualified and that are maintained primarily to provide deferred compensation for a select group of management or highly compensated employees as defined in Section 201(2) of ERISA.

ARTICLE II

DEFINITIONS AND CONSTRUCTION

2.1 Definitions. The following words, terms, and phrases used in the Plan shall have the meanings set forth in this Section 2.1:

(a) “Affiliate” means a corporation, trade or business that, together with the Company, is treated as a single employer under Section 414(b) or (c) of the Code.

(b) “Beneficiary” means the trust, person or persons designated by a Participant on a beneficiary designation form adopted by the Company to receive benefits, if any, under this Plan in the event of the Participant’s death.

(c) “Board” means the Board of Directors of the Company.

(d) “Cause” means, with respect to any Participant any of the following:

(i) the willful failure of a Participant to substantially perform the Participant’s duties for the Company or an Affiliate (other than due to physical or mental incapacity) within thirty (30) days after receiving a written demand for substantial performance from the Supervisor, the Chief Executive Officer, or the Board;

(ii) the willful engaging by the Participant in illegal or dishonest conduct or gross misconduct that is materially and demonstrably injurious to the Company or an Affiliate; or

(iii) conviction of the Participant of a felony or any crime of moral turpitude, a guilty or nolo contendere plea by the Participant with respect to a felony or any crime of moral turpitude, or the deferred adjudication or unadjudicated probation of the Participant with respect to a felony or any crime of moral turpitude.

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Provided, however, that (1) an act or omission by the Participant shall be considered “willful” only if it was not in good faith and was without reasonable belief that it was in the Company’s best interests, and (2) any act or omission by the Participant based upon authority granted by resolution duly adopted by the Board, the instructions of the Supervisor, or the advice of counsel for the Company, shall be conclusively presumed to be in good faith and in the Company’s best interests.

(e) “Change of Control Payment Event” shall mean and shall be deemed to have occurred when one of the events described in paragraphs (i), (ii), (iii), or (iv) below occurs. For the purpose of this subsection (e), the term “Company” shall mean Devon Energy Corporation and any successor thereto.

(i) The acquisition of stock of the Company by any one person, or more than one person acting as a group (as defined in §1.409A-3(i)(5)(v)(B) of the Treasury Regulations) (a “Person”) that, together with stock held by such Person, constitutes more than 50% of either (I) the then outstanding shares of common stock of the Company or (II) the combined voting power of the then outstanding voting securities of the Company entitled to vote generally in the election of directors; provided, however, that the following acquisitions shall not constitute a Change of Control Payment Event: (A) any acquisition by an underwriter temporarily holding securities pursuant to an offering of such securities; (B) any acquisition by the Company; (C) any acquisition by any employee benefit plan (or related trust) sponsored or maintained by the Company or any corporation controlled by the Company. If a Change of Control Payment Event occurs by reason of an acquisition described in this paragraph (i), no additional Change of Control Payment Event shall be deemed to occur under this paragraph (i) by reason of subsequent changes in the holdings of such Person (except if the holdings of such Person are reduced to 50% or below and thereafter increase to more than 50%).

(ii) During a 12-month period, a majority of the individuals who, as of January 1, 2009, constitute the Board (the “Incumbent Board”) are replaced; provided, however, that any individual becoming a director subsequent to January 1, 2009 whose election, appointment or nomination for election by the Company’s shareholders was approved by a vote of at least a majority of the directors then comprising the Incumbent Board shall be considered as though such individual were a member of the Incumbent Board, but excluding, for purposes of this definition, any such individual whose initial assumption of office occurs as a result of an actual or publicly threatened election contest (as such terms are used in Rule 14a-11 promulgated under the Exchange Act) with respect to the election or removal of directors or other actual or publicly threatened solicitation of proxies or consents by or on behalf of a Person other than the Board.

2

(iii) The date a Person acquires (or has acquired during the 12-month period ending on the date of the most recent acquisition by such Person) ownership of stock of the Company possessing 30% or more of the combined voting power of the then outstanding voting securities of the Company; provided that, if a Change of Control Payment Event occurs by reason of an acquisition described in this paragraph (iii), no additional Change of Control Payment Event shall be deemed to occur under this paragraph (iii) or paragraph (i) by reason of the acquisition of additional control of the Company by the same Person.

(iv) Approval by the shareholders of the Company of the sale or other disposition of all or substantially all of the assets of the Company to a Person; provided that, a transfer of the Company’s assets shall not be treated as a Change of Control Payment Event if the assets are transferred to:

(1) A shareholder of the Company (immediately before the asset transfer) in exchange for or with respect to its stock;

(2) An entity, 50% or more of the total value or voting power of which is owned, directly or indirectly, by the Company;

(3) A person that owns, directly or indirectly, 50% or more of the total value or voting power of all the outstanding stock of the Company; or

(4) An entity, at least 50% of the total value or voting power of which is owned, directly or indirectly by a Person described in subparagraph (3).

Except as otherwise provided in this paragraph (iv), a person’s status is determined immediately after the transfer of the assets.

(f) A “Change of Control Vesting Event” shall mean the occurrence of any one of the following events:

(i) the Incumbent Directors cease for any reason to constitute at least a majority of the Board;

(ii) any person is or becomes a “beneficial owner” (as defined in Rule 13d-3 under the Act), directly or indirectly, of Company securities representing 30% or more of either (x) the Company’s outstanding shares of common stock or (y) the combined voting power of the Company’s then outstanding securities eligible to vote in the election of directors (each, “Company Securities”); provided, however, that the event described in this paragraph (ii) shall not be deemed to be a Change in Control Vesting Event by virtue of any of the following acquisitions or transactions: (A) by the Company or any subsidiary, (B) by any employee benefit plan (or related trust) sponsored or maintained

3

by the Company or any subsidiary, (C) by an underwriter temporarily holding securities pursuant to an offering of such securities, or (D) pursuant to a Non-Qualifying Transaction;

(iii) the consummation of a merger, consolidation, statutory share exchange, or similar form of corporate transaction involving the Company or any of its subsidiaries that requires the approval of the Company’s stockholders, whether for such transaction or the issuance of securities in the transaction (a “Reorganization”), or the sale or other disposition of all or substantially all of the Company’s assets to an entity that is not an Affiliate (a “Sale”), unless:

(1) the holders of the Company’s shares of common stock either receive in such Reorganization or Sale, or hold immediately following the consummation of the Reorganization or Sale, more than 50% of each of the outstanding common stock and the total voting power of securities eligible to vote in the election of directors of (x) the corporation resulting from such Reorganization or the corporation that has acquired all or substantially all of the assets of the Company in connection with a Sale (in either case, the “Surviving Corporation”), or (y) if applicable, the ultimate parent corporation that directly or indirectly has beneficial ownership of 100% of the voting securities eligible to elect directors of the Surviving Corporation (the “Parent Corporation”),

(2) no person (other than any employee benefit plan (or related trust) sponsored or maintained by the Surviving Corporation or the Parent Corporation) is or becomes, as a result of the Reorganization or Sale, the beneficial owner, directly or indirectly, of 30% or more of the outstanding shares of common stock or the total voting power of the outstanding voting securities eligible to vote in the election of directors of the Parent Corporation (or, if there is no Parent Corporation, the Surviving Corporation), and

(3) at least a majority of the members of the board of directors of the Parent Corporation (or, if there is no Parent Corporation, the Surviving Corporation) following the consummation of the Reorganization or Sale were Incumbent Directors at the time of the Board’s approval of the execution of the initial agreement providing for such Reorganization or Sale;

(any Reorganization or Sale that satisfies all of the criteria specified in (1), (2) and (3) above shall be deemed to be a “Non-Qualifying Transaction”); or

(iv) the Company’s stockholders approve a plan of complete liquidation or dissolution of the Company.

4

Notwithstanding the foregoing, a Change in Control Vesting Event shall not be deemed to occur solely because any person acquires beneficial ownership of more than 30% of Company Securities due to the Company’s acquisition of Company Securities that reduces the number of Company Securities outstanding; provided, however, if, following such acquisition by the Company, such person becomes the beneficial owner of additional Company Securities that increases the percentage of outstanding Company Securities beneficially owned by such person, a Change in Control Vesting Event shall then occur. In addition, if a Change in Control Vesting Event occurs pursuant to paragraph (ii) above, then no additional Change in Control Vesting Event shall be deemed to occur pursuant to paragraph (ii) by reason of subsequent changes in holdings by such person (except if the holdings by such person are reduced below 30% and thereafter increase to 30% or above).

If (I) a Participant’s Date of Termination occurs on or after the date of approval by the Company’s shareholders of a transaction described in paragraph (iii) above; (II) the transaction so approved by shareholders is consummated and constitutes a Change of Control Vesting Event under paragraph (iii) above; and (III) prior to the consummation of such transaction, the Participant’s Date of Termination occurs, then for purposes of applying the provisions of Section 4.2 (relating to vesting), the Change of Control Vesting Event shall be deemed to have occurred with respect to such Participant immediately prior to such Participant’s Date of Termination.

If (A) a Participant’s Date of Termination occurs prior to a Change of Control Vesting Event by reason of termination by the Company without Cause; (B) the Participant reasonably demonstrates that such termination either:

(1) was at the request of a third party who had indicated an intention or taken steps reasonably calculated to effect a Change of Control Vesting Event or who effectuates a Change of Control Vesting Event or

(2) was otherwise in connection with, or in anticipation of, a Change of Control Vesting Event which actually occurs,

then, for purposes of this Plan, a Change of Control Vesting Event with respect to that Participant shall be deemed to be the date immediately prior to the Participant’s Date of Termination; provided that, to the extent that the application of this sentence results in the Participant becoming entitled to benefits under the Plan, commencement of such benefits shall be required to occur not earlier than the Change of Control Vesting Event or, in the case of a Change of Control Vesting Event described in paragraph (iii) above, consummation of the transaction. If any such termination occurs while an agreement is pending and the effective provisions of such agreement provide for a transaction or transactions which, if consummated, would constitute a Change of Control Vesting Event, and such Change of Control Vesting Event occurs, then such termination shall conclusively be presumed to be in connection with a Change of Control Vesting Event.

(g) “Code” means the Internal Revenue Code of 1986, as amended.

5

(h) “Company” means Devon Energy Corporation, a Delaware corporation.

(i) “Committee” shall mean the Compensation Committee of the Board of Directors of the Company.

(j) A Participant’s “Date of Termination” means the first day on which the Participant incurs a Separation from Service.

(k) A Participant’s “Early Retirement Date” means the first day of the month coinciding or following the date the Participant’s Date of Termination occurs after either (i) earning at least ten Years of Credited Service and attaining at least age 55; or (ii) earning at least 20 Years of Credited Service.

(l) “Employer” means the Company and each Affiliate with employees who have been selected to participate in the Plan. Until action to the contrary is taken by the Board, the Company shall be deemed to have consented to the participation in the Plan by any Affiliates.

(m) “Incumbent Directors” means the members of the Board on January 1, 2009; provided, however, that (x) any person becoming a director and whose election or nomination for election was approved by a vote of at least a majority of the Incumbent Directors then on the Board (either by a specific vote or by approval of the proxy statement of the Company in which such person is named as a nominee for director, without written objection to such nomination) shall be deemed an Incumbent Director, and (y) no individual initially elected or nominated as a director of the Company as a result of an actual or threatened election contest (as described in Rule 14a-11 under the Act) or other actual or threatened solicitation of proxies or consents by or on behalf of any person (as such term is used in Sections 13(d)(3) and 14(d)(2) of the Act) other than the Board, including by reason of any agreement intended to avoid or settle any such election contest or solicitation of proxies or consents, shall be deemed an Incumbent Director.

(n) “Exchange Act” means the Securities Exchange Act of 1934.

(o) “Participant” shall have the meaning ascribed to it in Section 3.1.

(p) “Participation Agreement” shall mean the agreement which will be entered into by and between the Company and the Participant in accordance with Section 3.3.

(q) “Plan-Approved Domestic Relations Order” means a qualified domestic relations order as defined in Section 414(p)(1)(B) of the Code that meets the requirements established by the Committee.

(r) “Plan Year” means the calendar year.

(s) “Restoration Plan” means the Devon Energy Corporation Benefit Restoration Plan.

6

(t) “Retirement Plan” means the Retirement Plan for Employees of Devon Energy Corporation.

(u) “Separation from Service” means termination of employment with the Employer under the circumstances described below. Whether a Separation from Service has occurred shall be determined by the Committee in accordance with Code Section 409A.

Except in the case of a Participant on a military leave, sick leave or bona fide leave of absence as provided below, a Participant is deemed to have incurred a Separation from Service if the Employer and the Participant reasonably anticipated that the level of services to be performed by the Participant after a certain date would be reduced to 20% or less of the average services rendered by the Participant during the immediately preceding 36-month period (or the total period of employment, if less than 36 months), disregarding periods during which the Participant was on a military leave, sick leave or bona fide leave of absence.

A Participant who is absent from work due to military leave, sick leave, or other bona fide leave of absence shall incur a Separation from Service on the first date immediately following the later of (i) the six-month anniversary of the commencement of the leave or (ii) the expiration of the Participant’s right, if any, to reemployment under statute or contract.

For purposes of determining whether a Separation from Service has occurred, the Employer means the Employer as defined in subsection (l), except that for purposes of determining whether another organization is an Affiliate of the Company, common ownership of at least 50% shall be determinative.

(v) “Specified Employee” means those employees of the Company or an Affiliate who are determined by the Committee to be a “specified employee” in accordance with Section 409A of the Code and the regulations promulgated thereunder and the Devon Energy Corporation Specified Employee Policy.

(w) “Supervisor” means the person to whom the Participant reports as determined by the Chief Executive Officer of the Company or his or her designee from time to time.

(x) “Years of Credited Service” shall mean “Years of Credited Service” as such term is defined in the Retirement Plan.

2.2 Construction. Other words, terms, and phrases used in the Plan are defined in the Retirement Plan or elsewhere in this Plan. Except where a word, term, or phrase is otherwise defined in the Plan, defined under Section 409A of the Code, or where the context clearly implies or indicates the contrary, a word, term, or phrase used in the Retirement Plan is similarly used in this Plan.

7

ARTICLE III

PARTICIPATION

3.1 Eligibility. Subject to the terms and conditions of the Plan, the Committee, in its discretion, at such times as the Committee determines, shall designate those employees of the Employers who are eligible to receive benefits under the Plan, and thereby become “Participants” in the Plan.

3.2 Plan Not Contract of Employment. The Plan does not constitute a contract of employment, and participation in the Plan will not give any employee the right to be retained in the employ of any Employer or Affiliate nor any right or claim to any benefit under the Plan, unless such right or claim has specifically accrued under the terms of the Plan.

3.3 Agreements. Any employee having been selected by the Committee as a Participant shall, as a condition of participation, complete, and return to the Committee, a Participation Agreement in such form and at such time as the Committee shall prescribe.

ARTICLE IV

AMOUNT AND PAYMENT OF SUPPLEMENTAL BENEFIT

4.1 Amount of Supplemental Benefit. Subject to the terms and conditions of the Plan, each Participant’s “Supplemental Benefit,” if any, shall be determined in accordance with the following:

(a) Determination of Supplemental Benefit. A Participant’s “Supplemental Benefit” shall equal (i) the Participant’s Target Benefit minus (ii) the Participant’s Net Retirement Plan Benefit.

(b) Determination of Target Benefit. A Participant’s “Target Benefit” shall be the benefit the Participant would have been entitled to receive under the Retirement Plan if all of the following paragraphs (i) through (v) applied:

(i) The limitations of the Plan intended to comply with Code Section 401(a)(17) had been inapplicable to the determination of the Participant’s benefit under the Retirement Plan.

(ii) The limitations of the Plan intended to comply with Code Section 415 had been inapplicable to the determination of the Participant’s benefit under the Retirement Plan.

(iii) The number “25” which appears two times in Section 5.1(a) of the Retirement Plan had been replaced in both instances with the number “20”.

(iv) Subject to paragraph (iii) above, in the case of a Participant to whom the provisions of Section 5.1(b) of the Retirement Plan (relating to Participants with compensation of $220,000 or more) would otherwise apply, the provisions of Section 5.1(a) of the Retirement Plan instead had been applied to such Participant.

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(v) In the case of a Participant whose compensation is determined under the Retirement Plan after reduction to reflect elective deferrals by the Participant of amounts that would otherwise be included in compensation in the absence of such deferral, the Target Benefit shall be determined as though those deferred amounts had been included in the determination of the Participant’s compensation at the time they would have been paid in the absence of such deferral. Conversely, such amounts shall not be included in determining the Target Benefit when they are paid to the Participant. Provided further, the calculation of the Target Benefit will include elective deferrals that were made by a Participant prior to the Participant’s selection for participation in this Plan.

A Participant’s “Target Benefit” shall be determined utilizing the assumption that the Participant’s benefit under the Retirement Plan will be determined based upon the time and form of payment applicable to the Participant’s benefit under this Plan.

With respect to any Participant who elected under the Company’s revised Retirement Plan to cease to accrue benefits under the Retirement Plan as of December 31, 2007, the following shall apply in calculating his Target Benefit:

(i) Supplemental Benefits shall cease to accrue under this Plan as of December 31, 2007;

(ii) the Target Benefit shall be calculated based upon the terms and provisions of the Retirement Plan in effect as of December 31, 2007; and

(iii) Compensation increases after December 31, 2007 shall be disregarded for calculation of the Target Benefit and the Supplemental Benefit under this Plan.

(c) Determination of Net Retirement Plan Benefit. A Participant’s “Net Retirement Plan Benefit” shall be the benefit the Participant has accrued under the Retirement Plan. For purposes of calculating the Supplemental Benefit, a Participant’s “Net Retirement Plan Benefit” shall be determined based on the form and time of payment applicable to the Participant’s benefit under this Plan.

(d) Early Retirement Eligibility. In determining a Participant’s Target Benefit under this Section 4.1, the definition of the term “Early Retirement Date” shall have the meaning set forth in Section 2.1 of this Plan, rather than the definition set forth in the Retirement Plan (which is set forth in the Retirement Plan in Section 2.1(z)).

(e) Minimum Benefit for MEDC Participants. In no event shall the Participant’s Target Benefit be less than the sum of the benefits frozen as of February 28, 2003 in the (i) Mitchell Energy & Development Corp. Executive Excess Business Plan, (ii) Mitchell Energy & Development Corp. Excess Benefit Plan, (iii) Mitchell Energy & Development Corp. Restoration Benefit Plan, and (iv) Mitchell Energy & Development Corp. Retirement Plan.

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(f) Change of Control Vesting Event. If a Participant who is a member of the Company’s Executive Committee and who has entered into an employment agreement with the Company is terminated without Cause or terminates employment for “good reason” (in accordance with the Participant’s employment agreement), during the period beginning on a Change of Control Vesting Event and ending on the last day of the 24th calendar month following the calendar month in which a Change of Control Vesting Event occurs, the Participant’s entitlement to benefits under the Plan shall be determined as though, at the time of termination, (A) the Participant had earned three (3) Years of Credited Service in addition to the Participant’s actual Years of Credited Service at the Date of Termination, (B) the Participant’s compensation for such three (3) years of additional service was equal to the greater of the Participant’s compensation as of the Date of Termination or the Participant’s compensation immediately prior to the Change of Control Vesting Event; and (C) the Participant was three years older than the Participant’s actual age at the Date of Termination. However, the deemed additional Years of Credited Service credited pursuant to this paragraph shall not occur to the extent that such service would result in service in excess of the maximum years of service permitted to be taken into account under the Plan.

(g) Variation in Calculation of Supplemental Benefit Under Appendix A. The calculation of the Supplemental Benefit for the Participants listed on Appendix A shall be determined by incorporating the additional modifications described on Appendix A. The provisions of this Plan as modified in this Section 4.1(g) shall replace and supersede any prior letter agreements between the Company and such Participants.

(h) Variation in Calculation of Supplemental Benefit Under Appendix B. The calculation of the Supplemental Benefit for the Participants listed on Appendix B shall be determined by incorporating the additional modifications described on Appendix B. The provisions of this Plan as modified in this Section 4.1(h) shall replace and supercede any prior letter agreements between the Company and such Participants.

4.2 Vesting. Except as otherwise provided by this Section 4.2, and subject to the terms of the Plan, a Supplemental Benefit shall be payable under the Plan to or on behalf of a Participant if he or she is vested in such benefit upon the date a payment event listed in Section 4.3 below occurs. If a Participant is not vested in his or her Supplemental Benefit under this Plan as of the payment event specified in Section 4.3, then no benefits shall be payable to or on behalf of the Participant under the Plan. A Participant’s vesting shall be subject to the following:

(a) Vesting Date. A Participant shall become vested in the Supplemental Benefit at the time at which the Participant has completed five (5) Years of Credited Service. For the avoidance of doubt, it is recited here that, except as otherwise expressly provided in this Section 4.2, a Participant shall forfeit any of his or her Supplemental Benefit if the Participant has not completed five Years of Credited Service.

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(b) Termination for Cause. Notwithstanding the provisions of subsection (a) above, in the event the Participant’s employment is terminated for Cause, the Participant shall forfeit all benefits under the Plan upon the Participant’s Date of Termination.

(c) Acceleration of Vesting. Notwithstanding the provisions of Section 4.2(a) above, in the event of (i) the Participant’s termination of employment by the Employer without Cause, (ii) the Participant’s termination of employment for “good reason” in accordance with the Participant’s employment agreement, (iii) the occurrence of a Change of Control Vesting Event or (iv) the Participant’s death, the Participant shall be fully vested in all benefits under the Plan.

(d) Effect on Restoration Plan. Notwithstanding the foregoing provisions of this Section 4.2, if a Participant receives his or her benefits under this Plan, then no benefit shall be payable to or on behalf of the Participant under the Restoration Plan. It is the intent of the Company and is a condition for participation in this Plan that there be no duplication of benefits earned under this Plan and the Restoration Plan.

4.3 Form of Payment and Commencement Date.

(a) Payment Events. Except as otherwise provided in the Plan, the Supplemental Benefit payable to or on behalf of a Participant under this Plan shall be paid upon the later to occur of the following events: (i) a Participant’s Date of Termination or (ii) the attainment of age 55. In addition, payment of the Supplemental Benefit will occur in the event of (i) a Change of Control Payment Event or (ii) the Participant’s death.

(b) Form and Timing of Payment Upon Separation from Service. The Participant may elect from the following forms of actuarially equivalent benefit payments under the Plan depending upon the date payment commences as follows:

Payment Commences Prior to August 1, 2009:

(i) Single Life Annuity;

(ii) 100% Joint and Survivor Annuity;

(iii) 66% Joint and Survivor Annuity;

(iv) 50% Joint and Survivor Annuity;

(v) 40% Joint and Survivor Annuity; and

(vi) Life/Ten-Year Certain.

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Payment Commences August 1, 2009 or Later:

(i) Single Life Annuity;

(ii) 100% Joint and Survivor Annuity;

(iii) 50% Joint and Survivor Annuity;

(iv) 25% Joint and Survivor Annuity; and

(v) Life/Ten-Year Certain.

In the event the Participant fails to make an election, the default form of payment will be the 100% Joint and Survivor Annuity if at the time payment commences the Participant is married and a Single Life Annuity if the Participant is not married at the time payment commences. If the Participant is eligible for the PZE Spouse’s pension, the conversion of the benefit from a single life annuity to the form of payment elected will reflect the PZE Spouse’s pension and be calculated using the same methodology as is used in the Retirement Plan. Payment of the Supplemental Benefit will commence as of the first of the month coincident with or next following the later of (i) 90 days following the Date of Termination or (ii) 90 days following the date the Participant attains age 55 unless the Participant is a Specified Employee. Payment of the Supplemental Benefit to a Specified Employee shall be postponed for a period of six months following the Date of Termination and shall commence within 30 days of the first business day of the seventh month following the Date of Termination or, if later, within 30 days following the date the Participant attains age 55. In addition to the commencement of payment of the Supplemental Benefit, a Participant who is a Specified Employee and attains age 55 on or before the completion of the six-month delay shall receive a lump sum payment within 30 days of the first business day of the seventh month following the Date of Termination of the amount of Supplemental Benefit that would have otherwise been paid during the six-month delay required due to the Participant’s status as a Specified Employee. If payment of the Participant’s Supplemental Benefit is delayed due to his or her status as a Specified Employee, the Supplemental Benefit payable shall be calculated as of the date the Supplemental Benefit would have been paid but for the six-month delay. Any form of payment under this subsection (b) shall be actuarially equivalent to the form of payment that would otherwise be payable to the Participant in the absence of this subsection (b), using the actuarial assumptions set forth in the Retirement Plan.

(c) Form and Time of Payment Upon Change of Control Payment Event. If a Change of Control Payment Event occurs, in lieu of any other benefits under the Plan, and notwithstanding the foregoing provisions of this Section 4.3 (except for the restrictions on payment to Specified Employees), the Participant shall be entitled to a lump sum payment which is the actuarial equivalent of the Participant’s Supplemental Benefit payable within 90 days of the effective date of the Change of Control Payment Event. For purposes of this subsection (c), the determination of actuarial equivalency will be made using the actuarial assumptions for determination of lump sums as set forth in the Retirement Plan; provided that in determining

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such actuarial equivalence, the Participant’s Supplemental Benefit shall be deemed to be payable immediately on the effective date of the Change of Control Payment Event, so that the Early Retirement Adjustment Factors (as set forth in Article VII of the Retirement Plan) shall not be applied to reduce the amount otherwise payable.

(d) Form and Time of Payment Upon Death. Payment of the Supplemental Benefit will commence within 90 days of the date of the Participant’s death in the form of a 100% Joint and Survivor Annuity if the Participant was 55 years of age or older on such date. If the Participant was not age 55, payment shall be delayed until the date the Participant would have attained age 55. The Supplemental Benefit shall be adjusted for payment of a death benefit as provided in Article 6 of the Retirement Plan, except that the timing of payment will be as stipulated in this Plan.

(e) Payment to Specified Employees upon Separation from Service. In no event shall a Specified Employee that is receiving a payment under this Plan due to their Separation from Service receive a payment prior to the first business day of the seventh month following the date of Separation from Service, unless the Separation from Service results from death.

(f) De Minimis Amounts. The Company shall distribute a Participant’s benefit in the form of a single lump sum payment in the event the lump sum value of the Supplemental Benefit, using the actuarial assumptions for determination of lump sums as set forth in the Retirement Plan, is $10,000 or less on the date payment is scheduled to commence under Sections 4.3(b), (c) or (d) and such payment shall result in termination of the Participant’s entire interest in the Plan.

4.4 Restrictions on Alienation of Benefits. No right or benefit under this Plan shall be subject to anticipation, alienation, sale, assignment, pledge, encumbrance, or charge, and any attempt to anticipate, alienate, sell, assign, pledge, encumber, or charge the same shall be void. No right or benefit hereunder shall in any manner be liable for or subject to the debts, contracts, liabilities, or torts of the person entitled to such benefit. Neither the Company nor any Affiliate shall be entitled to set off against the amounts payable to the Participant under this Plan any amounts owed to the Company or the Affiliate by the Participant. Notwithstanding the foregoing, in the event that all or any portion of the benefit of a Participant is transferred to the former spouse of the Participant incident to a divorce, the Committee shall maintain such amount for the benefit of the former spouse until distributed in the manner required by an order of any court having jurisdiction over the divorce, and the former spouse shall be entitled to the same rights as the Participant with respect to such benefit.

4.5 Domestic Relations Orders. The Committee shall establish procedures for determining whether an order directed to the Plan is a Plan-Approved Domestic Relations Order. If the Committee determines that an order is a Plan-Approved Domestic Relations Order, the Committee shall cause the payment of amounts pursuant to or segregate a separate account as provided by (and to prevent any payment or act which might be inconsistent with) the Plan-Approved Domestic Relations Order to the extent permitted by Section 409A of the Code.

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4.6 Abandonment of Benefits. Each Participant and Beneficiary shall file with the Committee, from time to time in writing, his or her address and each change of address, and any communication addressed to a Participant or Beneficiary at the last address filed with the Committee, or if no such address was filed, then at the last address as shown on the records of the Participant’s employer, shall be binding on the Participant or the Participant’s Beneficiary for all purposes of the Plan, and the Committee shall not be obliged to search for or ascertain the whereabouts of any Participant or Beneficiary; provided, that the Committee shall mail an annual notice of unpaid benefits to such person at such last address. If the Committee furnishes such annual notice to any Participant, or Beneficiary of a deceased Participant, that the Participant is entitled to a distribution, and the Participant or Beneficiary fails to claim such distribution or make their whereabouts known to the Committee within five years thereafter, such benefits shall be deemed forfeited and retained by or returned to the Company.

4.7 Information Required of Participants. Payment of benefits under the Plan shall begin as of the payment date provided in this Plan and no formal claim shall be required therefor; provided that a Participant may file a claim for benefits in accordance with procedures established by the Committee; and further provided that the Committee may make reasonable requests of Participants and Beneficiaries to furnish information which is reasonably necessary and appropriate to the orderly administration of the Plan, and payments under the Plan are conditioned upon the Participants and Beneficiaries promptly furnishing true, full and complete information as the Committee may reasonably request.

4.8 Benefits Payable to Incompetents. Any benefits payable hereunder to a minor or person under legal disability may be made, at the discretion of the Committee, (i) directly to the said person, or (ii) to a parent, spouse, relative by blood or marriage, or the legal representative of said person. The Committee shall not be required to see to the application of any such payment, and the payee’s receipt shall be a full and final discharge of the Committee’s responsibility hereunder.

4.9 Tax Withholding. All distributions under the Plan are subject to withholding of all applicable taxes.

ARTICLE V

SOURCE OF BENEFIT PAYMENTS

5.1 Liability for Benefit Payments. Any benefit payable under the Plan shall be paid from the general revenues of the Employer with respect to whose employee or former employee the benefit is payable, subject to the following:

(a) Multiple Employers of Participant. If a Participant has been employed by more than one Employer, the portion of the Participant’s Plan benefits payable by any such Employer shall be in proportion to the benefit the Participant accrued under this Plan for his or her period of service with that Employer.

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(b) Effect of Transaction. If, as a result of a sale or other transaction, the Participant’s employer after the transaction is not, or ceases to be, an Affiliate (and is or becomes an entity that is separate from the Company or an Affiliate), then, in determining liability for benefits due to the Participant under the Plan, the foregoing provisions of this Section 5.1 shall be applicable to entities which remain Employers under the Plan.

5.2 Discretionary Establishment of Trust. An Employer, in its discretion, may establish a trust, and may use the assets of the trust, to partially or fully satisfy its obligations under the Plan. Neither a Participant nor any other person shall, by reason of the Plan or any such trust, acquire any right in or title to any assets, funds or property of the Employers whatsoever, including, without limitation, any specific funds, assets, or other property which the Employers, in their sole discretion, may set aside in anticipation of a liability under the Plan. A Participant shall have only a contractual right to the amounts, if any, payable under the Plan, unsecured by any assets of the Employers. Nothing contained in the Plan shall constitute a guarantee by any of the Employers that the assets of the Employers shall be sufficient to pay any benefits to any person. No action in the establishment of a trust shall result in a Participant acquiring any interest greater than that of an unsecured creditor of the Company or any Employer of a Participant under the Plan.

5.3 Secondary Liability for Payment. To the extent that the Company and/or an Affiliate are not otherwise obligated to provide benefits to any Participant by the provisions of Section 5.1, the Company shall take such actions as are necessary, and cause each Affiliate to take such actions as are necessary, to cause each such entity (the “Guarantors”) to jointly and severally guarantee the payment of benefits otherwise due to the Participant under this Plan. However, in no event shall the guarantee provided by the preceding sentence give rise to an obligation unless the employer or employers primarily obligated to make the payment do not pay such benefit within 30 days of the due date for such payment, and no entity organized under the laws of any jurisdiction outside the United States shall have an obligation to enter into such guarantee. Each of the Guarantors shall be subrogated to the Participant’s rights under the Plan to the extent of any payments by each such Guarantor to or on account of the Participant under this Section 5.3. For the avoidance of doubt, it is recited here that after a transaction described in Section 5.1(b), this Section 5.3 shall continue to be applicable to a Participant affected by such transaction.

ARTICLE VI

COMMITTEE

6.1 Administration. The authority to control and manage all aspects of the operation and administration of the Plan shall be vested in the Committee. The Committee shall be selected by the Board. If the Committee does not exist, or for any other reason determined by the Board, the Board may take any action under the Plan that would otherwise be the responsibility of the Committee. Until otherwise provided by the Board in accordance with this Article VI, the Committee shall be comprised of the members of the Compensation Committee of the Company.

6.2 Powers of Committee. The Committee is authorized to (i) interpret the Plan; (ii) to establish, amend, and rescind any rules and regulations relating to the Plan; (iii) to determine the terms and provisions of any agreements made pursuant to the Plan; (iv) to accelerate the vesting of any Participant; and (v) to make all other determinations that may be necessary or advisable for the

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administration of the Plan so long as the exercise of this discretion does not violate Section 409A. Except as otherwise specifically provided by the Plan, any determinations to be made by the Committee under the Plan shall be decided by the Committee in its sole discretion. Any interpretation of the Plan by the Committee and any decision made by it under the Plan is final and binding on all persons.

6.3 Delegation by Committee. The Committee may by resolution, in its discretion, delegate administrative duties to one or more subcommittee(s) comprised of employees of the Company appointed by the Committee. Any such delegation may be revoked at any time.

6.4 Information to be Furnished to Committee. The Employers and Affiliates shall furnish the Committee with such data and information as may be required for it to discharge its duties. The records of the Employers and Affiliates as to an employee’s or Participant’s employment, termination of employment, leave of absence, reemployment and compensation shall be conclusive on all persons unless determined to be incorrect. Participants and other persons entitled to benefits under the Plan must furnish the Committee such evidence, data or information as the Committee considers desirable to carry out the Plan.

6.5 Liability and Indemnification of Committee. No member or authorized delegate of the Committee shall be liable to any person for any action taken or omitted in connection with the administration of the Plan unless attributable to the person’s own fraud or willful misconduct; nor shall the Employers be liable to any person for any such action unless attributable to fraud or willful misconduct on the part of a director or employee of the Employers. The Committee, the individual members thereof, and persons acting as the authorized delegates of the Committee under the Plan, shall be indemnified by the Employers against any and all liabilities, losses, costs and expenses (including legal fees and expenses) of whatsoever kind and nature which may be imposed on, incurred by or asserted against the Committee or its members or authorized delegates by reason of the performance of a Committee function if the Committee or its members or authorized delegates did not act dishonestly or in willful violation of the law or regulation under which such liability, loss, cost or expense arises. This indemnification shall not duplicate but may supplement any coverage available under any applicable insurance.

6.6 Expenses. The expenses of administering the Plan shall be borne by the Company.

ARTICLE VII

CLAIMS PROCEDURE

7.1 Claims Review Procedures. The following claim procedures shall apply until such time as a Change of Control Payment Event has occurred. During the 24-month period following a Change of Control Payment Event, these procedures shall apply only to the extent the claimant requests their application. After the expiration of the 24-month period following a Change of Control Payment Event, then, these procedures shall again apply until the occurrence of a subsequent Change of Control Payment Event.

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(a) Denial of Claim. If a claim for benefits is wholly or partially denied, the claimant shall be given notice in writing of the denial within a reasonable time after the receipt of the claim, but not later than 90 days after the receipt of the claim. However, if special circumstances require an extension, written notice of the extension shall be furnished to the claimant before the termination of the 90-day period. In no event shall the extension exceed a period of 90 days after the expiration of the initial 90-day period. The notice of the denial shall contain the following information written in a manner that may be understood by a claimant:

(i) The specific reasons for the denial;

(ii) Specific reference to pertinent Plan provisions on which the denial is based;

(iii) A description of any additional material or information necessary for the claimant to perfect his claim and an explanation of why such material or information is necessary;

(iv) An explanation that a full and fair review by the Committee of the denial may be requested by the claimant or his authorized representative by filing a written request for a review with the Committee within 60 days after the notice of the denial is received; and

(v) If a request for review is filed, the claimant or his authorized representative may review pertinent documents and submit issues and comments in writing within the 60-day period described in paragraph (iv) above.

(b) Decisions After Review. The decision of the Committee with respect to the review of the denial shall be made promptly and in writing, but not later than 60 days after the Committee receives the request for the review. However, if special circumstances require an extension of time, a decision shall be rendered not later than 120 days after the receipt of the request for review. A written notice of the extension shall be furnished to the claimant prior to the expiration of the initial 60-day period. The claimant shall be given a copy of the decision, which shall state, in a manner calculated to be understood by the claimant, the specific reasons for the decision and specific references to the pertinent Plan provisions on which the decision is based.

(c) Other Procedures. Notwithstanding the foregoing, the Committee may, in its discretion, adopt different procedures for different claims without being bound by past actions. Any procedures adopted, however, shall be designed to afford a claimant a full and fair review of his claim and shall comply with applicable regulations under ERISA.

7.2 Finality of Determinations; Exhaustion of Remedies. To the extent permitted by law, decisions reached under the claims procedures set forth in Section 7.1 shall be final and binding on all parties. No legal action for benefits under the Plan shall be brought unless and until the claimant has exhausted his or her remedies under Section 7.1. In any such legal action, the claimant may only present evidence and theories which the claimant presented during the claims procedure. Any claims which the claimant does not in

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good faith pursue through the review stage of the procedure shall be treated as having been irrevocably waived. Judicial review of a claimant’s denied claim shall be limited to a determination of whether the denial was arbitrary, capricious or an abuse of discretion based on the evidence and theories the claimant presented during the claims procedure. This Section shall have no application during the 24-month period following a Change of Control Payment Event as to a claim which is first asserted or first denied after the Change of Control Payment Event and, as to such a claim, the de novo standard of judicial review shall apply. After the expiration of the 24-month period following a Change of Control Payment Event, then, this Section shall again apply until the occurrence of a subsequent Change of Control Payment Event.

7.3 Effect of Fiduciary Action. The Plan shall be interpreted by the Committee and all Plan fiduciaries in accordance with the terms of the Plan and their intended meanings. However, the Committee and all Plan fiduciaries shall have the sole discretion to make any findings of fact needed in the administration of the Plan, and shall have the sole discretion to interpret or construe ambiguous, unclear or implied (but omitted) terms in any fashion they deem to be appropriate in their sole judgment. Except as stated in Section 7.2, the validity of any such finding of fact, interpretation, construction or decision shall not be given de novo review if challenged in court, by arbitration or in any other forum, and shall be upheld unless clearly arbitrary or capricious. To the extent the Committee or any Plan fiduciary has been granted discretionary authority under the Plan, the Committee’s or Plan fiduciary’s prior exercise of such authority shall not obligate it to exercise its authority in a like fashion thereafter. If any Plan provision does not accurately reflect its intended meaning, as demonstrated by consistent interpretations or other evidence of intent, or as determined by the Committee in its sole and exclusive judgment, the provision shall be considered ambiguous and shall be interpreted by the Committee and all Plan fiduciaries in a fashion consistent with its intent, as determined by the Committee in its sole discretion. The Committee, without the need for Board of Directors’ approval, may amend the Plan retroactively to cure any such ambiguity. This Section may not be invoked by any person to require the Plan to be interpreted in a manner which is inconsistent with its interpretation by the Committee or by any Plan fiduciaries. All actions taken and all determinations made in good faith by the Committee or by Plan fiduciaries shall be final and binding upon all persons claiming any interest in or under the Plan. This Section shall not apply to fiduciary or Committee actions or interpretations which take place or are made during the 24-month period following a Change of Control Payment Event. After the expiration of the 24-month period following a Change of Control Payment Event, then, this Section shall again apply until the occurrence of a subsequent Change of Control Payment Event.

ARTICLE VIII

MISCELLANEOUS

8.1 Tax Consequences Not Guaranteed. The Employers do not warrant that this Plan will have any particular tax consequences for Participants or Beneficiaries and shall not be liable to them if tax consequences they anticipate do not actually occur. Neither the Company nor the Affiliates shall have any obligation to indemnify a Participant or Beneficiary for lost tax benefits (or other damage or loss) because of change in Plan design or funding.

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8.2 Severability. If any provision of the Plan is held invalid or illegal for any reason, any illegality or invalidity shall not affect the remaining provisions of the Plan, and the Plan shall be construed and enforced as if the illegal or invalid provision had never been contained therein. The Company shall be permitted to correct and remedy such questions of illegality or invalidity by amendment.

8.3 Benefits Under Other Plans. Benefits payable under the Plan shall be disregarded for purposes of determining the benefits under the plans of the Company and the Affiliates (including, without limitation the plans intended to be qualified under section 401(a) of the Code), except as otherwise specifically provided in the affected plan.

8.4 Gender and Number. Except when otherwise indicated by the context, any masculine terminology when used in the Plan shall also include the feminine gender, and the definition of any term in the singular shall also include the plural.

8.5 Action by Company or Affiliate. Any action required or permitted to be taken by the Company or any Employer or other Affiliate shall be by resolution of its board of directors or comparable governing body, or by action of one or more members of the board or comparable governing body (including a committee of the board) who are duly authorized to act for the board, or by a duly authorized officer of such company.

8.6 Successors. The Plan shall be binding upon and inure to the benefit of the Company and any successors of the Company, subject to the following:

(a) The Company will require any successor (whether direct or indirect, by purchase, merger, consolidation or otherwise) to all or substantially all of the business or assets of the Company to expressly assume and agree to perform the Plan in the same manner and to the same extent that the Company would be required to perform it if no such succession had taken place.

(b) After a successor assumes this Plan in accordance with this Section 8.6, only such successor shall be liable for amounts payable after such assumption, and no other companies shall have liability for amounts payable after such assumption.

8.7 Evidence. Evidence required of the Participant under the Plan may be by certificate, affidavit, document or other information which the Committee considers pertinent and reliable, and signed, made or presented by the proper party or parties.

8.8 Applicable Laws. The Plan shall be construed and administered in accordance with the laws of the State of Oklahoma to the extent that such laws are not preempted by the laws of the United States of America.

8.9 Attorney Fees. If any contest or dispute shall arise between an Employer (or the Committee) and a Participant regarding the Participant’s right to benefits under the Plan, the following will apply:

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(a) The Employer otherwise responsible for payment of the benefits shall reimburse Participant for all legal fees and expenses reasonably incurred by Participant in connection with such contest or dispute (provided that such legal fees are calculated on an hourly, and not on a contingency fee, basis), costs and expenses incurred by the Participant in connection with such enforcement or defense.

(b) The Participant shall be entitled to select his or her legal counsel; provided, however, that such right of selection shall not affect the requirement that any costs and expenses reimbursable under this Section 8.9 be reasonable.

(c) Except as otherwise provided in subsection (d) below, reimbursement by the Employer shall be made as soon as practicable following the resolution of the contest or dispute to the extent the Employer receives appropriate documentation evidencing the incurrence of such attorneys’ fees, costs, and expenses but no later than December 31 of the year immediately following the year in which resolution of the contest or dispute occurs. However, subject to subsection (d) below, no such reimbursement shall be due under this Section 8.9 if the Participant is not successful in respect of any of the Participant’s material claims or defenses brought, raised or pursued in connection with such contest or dispute.

(d) In the event that (i) within the period beginning on the Change of Control Payment Event and ending on the last day of the 24th calendar month following the calendar month in which a Change of Control Payment Event, a claim (a “Claim”) for arbitration or a lawsuit filed by a Participant in connection with a dispute, claim, or controversy regarding the Participant’s rights and obligations under the Plan or (ii) a Claim has been filed prior to a Change of Control Payment Event but has not been resolved as of the Change of Control Payment Event, then payments required under this Section 8.9 with respect to such Claim shall be made by the Employer to the Participant (or directly to the Participant’s attorney) promptly following submission to the Employer of appropriate documentation evidencing the incurrence of such attorneys’ fees, costs, and expenses but no later than December 31 of the year immediately following the year in which resolution of the contest or dispute occurs. If the Participant is not successful in respect of any of the Participant’s material claims or defenses brought, raised or pursued in connection with such contest or dispute, the Participant shall repay the Employer the amount of any such reimbursement received in connection with such dispute in accordance with this Section 8.9 (without interest) as soon as practicable following the resolution of such contest or dispute.

ARTICLE IX

AMENDMENT AND TERMINATION

9.1 Amendment and/or Termination. The Board may, at any time, amend or terminate the Plan, subject to the following:

(a) Reduction of Accrued Benefits. Neither an amendment nor termination of the Plan shall reduce or impair the benefits accrued by or on behalf of any Participant whose Date of Termination occurred prior to the date on which such amendment or termination is adopted by the Board. Neither an amendment nor termination of the Plan shall reduce or impair the

20

benefits accrued by or on behalf of any Participant whose Date of Termination occurs on or after the date on which such amendment or termination is adopted by the Board, as compared to the benefits accrued under the Plan on the date immediately prior to the date on which the amendment or termination is adopted by the Board, if each Participant who had not previously incurred a Date of Termination was deemed to have incurred a Date of Termination immediately prior to the date of such adoption and commenced payment of benefits under the Plan on the earliest commencement date that would be permitted under the terms of the Plan (as in effect prior to the amendment or termination) following such deemed Date of Termination.

(b) Vesting Rate. Neither an amendment nor termination of the Plan shall adversely affect the Participant’s right to vest in benefits in accordance with Section 4.2(a), regardless of whether such vesting would occur on, before, or after the date such amendment or termination is adopted. However, the limitation in this subsection (b) shall not apply to persons who first become Participants in the Plan after such amendment or termination is adopted.

(c) Amendment of Provisions for Change of Control Vesting Event. In no event shall any amendment or termination adopted by the Board during the period beginning six months prior to any Change of Control Vesting Event and ending on the last day of the 24th calendar month following the calendar month in which occurs a Change of Control Vesting Event adversely affect the Participant’s right to vest in accordance with Section 4.2(c) during the period beginning six months prior to any Change of Control Vesting Event and ending on the last day of the 24th calendar month following the calendar month in which occurs a Change of Control Vesting Event.

(d) Accrual Rate After Change of Control Vesting Event. In no event shall any amendment or termination adopted by the Board during the period beginning six months prior to a Change of Control Vesting Event and ending on the last day of the 24th calendar month following the calendar month in which occurs a Change of Control Vesting Event result in a reduction in the rate (as compared to the rate that would have applied in the absence of such amendment or termination) at which benefits would be accrued for service during the period beginning on the Change of Control Vesting Event and ending on the last day of the 24th calendar month following the calendar month in which occurs a Change of Control Vesting Event.

(e) Changes in Retirement Plan. If the benefit accrual rate under the Retirement Plan is terminated or curtailed, the benefit accrual rate under this Plan shall be similarly terminated or curtailed. However, if the benefit accrual rate under the Retirement Plan is terminated or curtailed during the period beginning on a Change of Control Vesting Event and ending on the last day of the 24th calendar month following the calendar month in which occurs a Change of Control Vesting Event, then the benefit accrual rate under this Plan shall be deemed to have been modified so that the Supplemental Benefit provided under this Plan will equal the excess of (i) the Target Benefit that would have been provided if the benefit accrual

21

rate under the Retirement Plan had not been terminated or curtailed during such period, over (ii) the Net Retirement Plan Benefit (determined after taking into account such termination or curtailment to the extent it is applicable to the Participant).

(f) Section 409A. The Plan may not be amended if the amendment would result in a violation of Section 409A. The Plan may only be terminated in a manner that is compliant with the provisions of Section 409A regarding permitted plan termination.

IN WITNESS WHEREOF, the Company has caused this instrument to be executed by their duly authorized officers in a number of copies, each of which shall be deemed an original but all of which shall constitute one and the same instrument, effective as of January 1, 2012.

DEVON ENERGY CORPORATION
By:	/s/    Frank W. Rudolph
	Frank W. Rudolph, Executive Vice President—Human Resources

22

APPENDIX A

The following Participants shall have their Supplemental Benefit calculated in accordance with the provisions of this Appendix A:

Rick D. Clark Steve G. Cromwell Jeff D. Hall Danny J. Heatly Brian J. Jennings J. Michael Lacey Duke R. Ligon Marian J. Moon J. Larry Nichols Darryl G. Smette William T. Vaughn

The determination of the Supplemental Benefit under this Plan for the Participants listed in this Appendix A will be made as though Section 4.1(a) of the Plan had been replaced with the following new Section 4.1(a):

(a) Determination of Supplemental Benefit. A Participant’s Supplemental Benefit shall equal (i) minus (ii) where:

(i) is the Participant’s Target Benefit; and

(ii) is the Participant’s Net Retirement Plan Benefit multiplied by a fraction, the denominator of which shall be “20” and the numerator of which shall be the actual “Years of Benefit Accrual Service” (as defined in the Retirement Plan) earned at the calculated date not to exceed 20.

It is the intent that paragraph (ii) above shall be subtracted in its entirety from paragraph (i) in computing the Supplemental Benefit.

APPENDIX B

The following Participants shall have their Supplemental Benefit calculated in accordance with the provisions of this Appendix B: John Richels. The determination of the Supplemental Benefit under this Plan for the Participants listed in this Appendix B will be in accordance with the terms of the Plan but will be made as though the changes set forth on this Appendix B were made to the Plan.

I. Section 2 of the Supplemental Retirement Income Plan (the “Plan”) is hereby changed to include new Subsections (y), (z), (aa), (bb), (cc), (dd), (ee) and (ff), as follows:

(y) ‘CPP’ means the Canada Pension Plan.

(z) ‘Devon Canada’ means Devon Canada Corporation, a wholly-owned subsidiary of the Company.

(aa) ‘Devon Canada Employee’ means an employee of Devon Canada who ceases to be an employee of Devon Canada and who immediately thereafter becomes an Employee of the Company.

(bb) ‘Devon Canada Supplemental Plan’ means the Devon Canada Corporation Supplemental Executive Retirement Plan.

(cc) ‘Devon Canada Supplemental Plan Benefit’ means the estimated monthly benefit payable to a Participant who is a Devon Canada Employee at the same time and in the same form of payment as the time and form of the payment of the Supplemental Benefit but determined upon the assumption that he would have no further compensation considered in calculating his Devon Canada Supplemental Plan Benefit after he ceases to be an employee of Devon Canada.

(dd) ‘CPP Benefit’ means the estimated monthly amount payable to a Participant who was a Devon Canada Employee at his Normal Retirement Date under the Canada Pension Plan as in effect on the earlier of his Normal Retirement Date or Date of Termination, but determined upon the assumption that he would have no further compensation considered in calculating his Canada Pension Plan Benefit after he ceases to be an employee of Devon Canada.

(ee) ‘Registered Pension Plan’ means the Pension Plan for Employees of Devon Canada Corporation or any successor thereto or replacement therefore, as amended from time to time.

(ff) ‘Registered Pension Plan Benefit’ means the monthly amount which would be payable to the Participant who was a Devon Canada Employee for the aggregate defined contribution account balance held for the benefit of such Participant under the Registered Pension Plan as of the Participant’s Date of Termination with such account balance hypothetically converted to an annuity payable at the same time and in the same form of payment as the time and

1

form of the payment of the Supplemental Benefit; which hypothetical annuity shall be calculated using the actuarial assumptions set forth in the Retirement Plan.

II. Section 4.1(a) of the Plan is hereby amended in its entirety to read as follows:

“Section 4.1(a) Determination of Supplemental Benefit. A Participant’s ‘Supplemental Benefit’ shall equal (i) the Participant’s Target Benefit minus (ii) the sum of (A) and (B), each determined as follows:

(A) the product obtained by multiplying (1) a fraction, the denominator of which shall be 20 and the numerator of which shall be the actual Years of Credited Service earned at the calculation date not to exceed 20 times (2) the sum of the Participant’s Registered Pension Plan Benefit and the Participant’s Net Retirement Plan Benefit as determined without taking into account the changes to the Plan effected by the 2010 First Amendment to the Plan executed December 31, 2010 (the ‘2010 First Amendment’); and

(B) the difference between (1) the Participant’s Net Retirement Plan Benefit taking into account all amendments to the Plan (including, without limitation, the 2010 First Amendment), and (2) the Participant’s Net Retirement Plan Benefit as determined without taking into account the changes to the Plan effected by the 2010 First Amendment.”

III. Section 4.1(b) of the Plan is amended to include the following new Subsections (vi) and (vii):

(vi) For purposes of calculating the Target Benefit references in the Retirement Plan to Primary Social Security Benefit shall mean Primary Social Security Benefit and CPP Benefit.

(vii) For all purposes under this Plan, including calculating the Target Benefit of a Devon Canada Employee, employment service of such Devon Canada Employee with Devon Canada shall be considered as employment service with the Company.

IV. There is added to Section 4 of the Plan new Subsections (i), (j), and (k) to read as follows:

“(i) Former Devon Canada Employee. Any Devon Canada Employee who has been selected for participation in this Plan, shall be deemed to have been an employee of the Company from such individual’s original date of hire with Devon Canada up to such individual’s date of hire by the Company and thereafter, while employed by the Company. For purposes of this Plan, the original date of hire of John Richels with Devon Canada is April 1, 1996. Except as otherwise provided in this Plan, in determining such Devon Canada Employee’s employment service, the same rules as applicable for calculating

2

employment service for other Participants under this Plan will be applied to the Devon Canada Employees. A former Devon Canada Employee who is a Participant in this Plan will be eligible to participate in the Retirement Plan in accordance with its terms, which recognizes employment service with Devon Canada for purposes of eligibility and vesting, but not for calculation of benefit accrual.

(j) Minimum Benefit for Devon Canada Employee. Any Devon Canada Employee who has been selected to participate in this Plan will be eligible to earn a Supplemental Benefit but in no event will the benefit under this Plan at any point in time be less than such Participant’s benefit earned under the Devon Canada Supplemental Plan calculated as of such Participant’s Date of Termination. The minimum benefit of such Participant shall assume that neither Devon Canada nor the Company are making further contributions to the CPP or the Registered Pension Plan and any additional increase in value of the Registered Pension Plan Benefit shall be attributable to investment earnings credited to the Participant’s account in such plan, and no further benefits are earned under the Devon Canada Supplemental Plan as of the date of hire of such Devon Canada Employee by the Company.

(k) No Duplication of Benefits. Any former Devon Canada Employee who has been selected for participation in this Plan, and who was formerly a Participant in the Devon Canada Supplemental Plan, shall, as a condition for participation in this Plan waive any benefit payable under the Devon Canada Supplemental Plan and there shall be no duplication of benefits between this Plan, the Retirement Plan, the Canada Pension Plan, the CPP, the Registered Pension Plan and the Devon Canada Supplemental Plan. A former Devon Canada Employee who does not waive his or her Devon Canada Supplemental Plan Benefit shall not be eligible for benefits under this Plan.”

3

EX-12

Exhibit 12

RATIOS OF EARNINGS TO FIXED CHARGES AND TO

COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS

December 31, 2011

	Years Ended December 31,
	2011		2010		2009			2008			2007
EARNINGS:
Adjusted (loss) earnings from continuing operations before income taxes	$	4,264	$	3,548	$	(4,574	)	$	(4,208	)	$	3,283
Add fixed charges (see below)		439		460		467			459			550
Adjusted (loss) earnings	$	4,703	$	4,008	$	(4,107	)	$	(3,749	)	$	3,833
FIXED CHARGES AND PREFERRED STOCK DIVIDENDS:
Gross interest expense	$	425	$	439	$	444		$	440		$	532
Estimated interest component of operating lease payments		14		21		23			19			18
Fixed charges		439		460		467			459			550
Preferred stock requirements, pre-tax		—		—		—			9			15
Combined fixed charges and preferred stock dividends	$	439	$	460	$	467		$	468		$	565
Ratio of earnings to fixed charges		10.71		8.71		N/A			N/A			6.97
Ratio of earnings to combined fixed charges and preferred stock dividends		10.71		8.71		N/A			N/A			6.78
Insufficiency of earnings to cover fixed charges		N/A		N/A	$	4,574		$	4,208			N/A
Insufficiency of earnings to cover combined fixed charges and preferred stock dividends		N/A		N/A	$	4,574		$	4,217			N/A

N/A Not applicable.

EX-21

EXHIBIT 21

DEVON ENERGY CORPORATION

Significant Subsidiaries

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

2. Devon Financing Corporation, L.L.C., a Delaware limited liability company

3. Devon OEI Holdings, L.L.C., a Delaware limited liability company

4. Devon OEI Operating, L.L.C., a Delaware limited liability company

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

6. Devon Energy International, Ltd., a Delaware corporation

7. Devon Operating Company Ltd., an Alberta corporation

8. Devon Canada Holdings LP, an Alberta limited partnership

9. Devon Canada Corporation, a Nova Scotia corporation

10. Devon AXL, a general partnership registered in Alberta

11. Devon NEC Corporation, a Nova Scotia corporation

12. Devon Canada, a general partnership registered in Alberta

EX-23.1

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 No. 333-68694, 333-47672, 333-44702, 333-104933, 333-104922, 333-103679, 333-159796, 333-127630 and 333-179181) on Form S-8 and the Registration Statement (File No. 333-178453) on Form S-3 of Devon Energy Corporation of our report dated February 23, 2012, with respect to the consolidated balance sheets of Devon Energy Corporation as of December 31, 2011 and 2010, and the related consolidated comprehensive statements of earnings, cash flows, and stockholders’ equity for each of the years in the three-year period ended December 31, 2011, and the effectiveness of internal control over financial reporting as of December 31, 2011, which report appears in the December 31, 2011 annual report on Form 10-K of Devon Energy Corporation.

KPMG LLP

Oklahoma City, Oklahoma

February 23, 2012

EX-23.2

Exhibit 23.2

ENGINEER’S CONSENT

We consent to incorporation by reference in the Registration Statements (File Nos. 333-68694, 333-47672, 333-44702, 333-104922, 333-104933, 333-103679, 333-127630, 333-159796 and 333-179181) on Form S-8, and the Registration Statement (File No. 333-178453) on Form S-3 of Devon Energy Corporation of the reference to our reports for Devon Energy Corporation, which appears in the December 31, 2011 annual report on Form 10-K of Devon Energy Corporation.

LaRoche Petroleum Consultants, Ltd.
By:	/s/ William M. Kazmann
	William M. Kazmann Partner

February 23, 2012

EX-23.3

Exhibit 23.3

ENGINEER’S CONSENT

We consent to incorporation by reference in the Registration Statements (File Nos. 333-68694, 333-47672, 333-44702, 333-104922, 333-104933, 333-103679, 333-127630, 333-159796 and 333-179181) on Form S-8, and the Registration Statement (File No. 333-178453) on Form S-3 of Devon Energy Corporation of the reference to our reports for Devon Energy Corporation, which appears in the December 31, 2011 annual report on Form 10-K of Devon Energy Corporation.

AJM Deloitte
By:	/s/ Robin G. Bertram
	Robin G. Bertram, P.Eng.

February 23, 2012

EX-31.1

Exhibit 31.1

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, John Richels, 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/ John Richels

John Richels

President and Chief Executive Officer

Date: February 22, 2012

EX-31.2

Exhibit 31.2

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Jeffrey A. Agosta, 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/ Jeffrey A. Agosta

Jeffrey A. Agosta

Executive Vice President and Chief Financial Officer

Date: February 22, 2012

EX-32.1

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, 2011 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, John Richels, President and 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/ John Richels

John Richels

President and Chief Executive Officer

February 22, 2012

EX-32.2

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, 2011 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Jeffrey A. Agosta, Executive Vice President and 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/ Jeffrey A. Agosta

Jeffrey A. Agosta

Executive Vice President and Chief Financial Officer

February 22, 2012

EX-99.1

Exhibit 99.1

January 26, 2012

Mr. Bob Fant

Director Reserves and Economics

Devon Energy Corporation

20 North Broadway

Oklahoma City, OK 73102

Dear Mr. Fant:

At your request, LaRoche Petroleum Consultants, Ltd. (LPC) has audited the estimates of proved reserves and future net cash flow, as of December 31, 2011, to the Devon Energy Corporation (Devon) interest in certain properties located in Devon’s Mid-Continent and Southern Divisions in the United States as prepared and completed by Devon on December 28, 2011. The reserve estimates were prepared by Devon for public disclosure according to the United States Security and Exchange Commission (SEC) guidelines, and our audit is to confirm the accuracy of those estimates and classifications within the applicable SEC rules, regulations, and guidelines. It should be understood that our audit described herein does not constitute a complete reserve study of the oil and gas properties of Devon. It is our understanding that the properties audited by LPC comprise approximately ninety-seven percent (97%) of Devon’s aggregate reserves for the two Divisions set out above as estimated and reported by Devon. We prepared our own estimates of proved reserves and net cash flow for all of the properties audited, and compared our estimates to those prepared by Devon to complete our audit of such properties. We believe the assumptions, data, methods, and procedures used are appropriate for the purpose of this audit. Estimates by Devon and LPC are based on constant prices and costs as set forth in this letter and conform to our understanding of the SEC guidelines, reserves definitions, and applicable accounting rules.

It is our understanding that the properties audited by LPC and reflected in this audit report comprise seventy-three percent (73%) of Devon’s aggregate, corporate reserves as estimated and reported by Devon.

The Mid-Continent Division reserves presented above are for the field areas designated by Devon’s internal naming system. These areas include 1) Ft. Worth Basin District: Field Groups Boonsville, Boonsville South, FWB Conventional Minor, FWB Conventional Minor South, NEBS Core Lean, NEBS Core N Denton, Nebs Core N Wise, NEBS Core Rich Denton, NEBS Core Rich Wise, NEBS Noncore Denton, NEBS Noncore Lean, NEBS Noncore South, NEBS Noncore W Viola North, NEBS Noncore W Viola South, NEBS Noncore Western Extension, and NEBS Noncore Wise; 2) Mid-Continent District: Field Groups Cana, Granite Wash and Northridge Unconventional; 3) Permian Basin District: Field Groups Ackerly Area, Anton Irish, Catclaw Draw Area, Corbin Area, Deep Delaware, Diamond Mound, El Dorado, Fullerton Area, Gaucho Area, Hackberry, Ingle Wells/Sand Dunes, Keystone/Kermit, McKnight, Mi Vida, Midland Basin, Odessa, Other PB New Mexico, Other PB Texas, Outland Area, Ozona Area, Potato Basin Area, Reeves, Slaughter, Townsend Area, Waddell North, Waddell South, Wasson, Welch Area, and Wolfberry NW; 4) Rocky Mountain District: Project Areas Bear Paw Uplift, Big Horn, Green River, Powder River Basin CBM, Powder River Basin Conventional, RM Other, San Juan, Washakie and Wind River.

2435 N. Central Expressway • Richardson, Texas 75080

Phone (214) 363-3337 • Fax (214) 363-1608

Mr. Bob Fant

January 26, 2012

Page 2

The Southern Division reserves presented above are for the areas designated by Devon’s internal naming system as Field Groups consisting of the Agua Dulce Area, Bald Prairie, Bethany, Carthage Central, Carthage South, Central (Haynesville Shale), East Texas Other, Groesbeck Other, Montgomery County Area, Nan-Su-Gail, North Louisiana Other, North (Haynesville Shale), Oaks, Personville, Ruston, Shady Grove, Southeast (Haynesville Shale), Stockman/Appleby, Waskom, and Zapata Area.

The oil reserves include crude oil and condensate. Oil and natural gas liquid (NGL) reserves are expressed in barrels which are equivalent to 42 United States gallons. Gas volumes are expressed in thousands of standard cubic feet (Mcf) at the contract temperature and pressure bases.

The estimated reserves and future cash flow are for proved developed producing, proved developed non-producing, and proved undeveloped reserves. Devon’s estimates do not include any value for unproven reserves classified as probable or possible reserves that might exist for these properties, nor did it include any consideration that could be attributed to interests in undeveloped acreage beyond those tracts for which reserves have been estimated.

When compared on a field-by-field basis, some estimates determined by Devon are greater and some are lesser than the estimates determined by LPC. However, in our opinion, Devon’s estimates of proved oil and gas reserves and future cash flow, as audited by LPC, are in the aggregate reasonable, are within 10 percent of our numbers and have been prepared in accordance with generally accepted petroleum engineering and evaluation methods and procedures. These methods and procedures are set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information promulgated by the Society of Petroleum Engineers. We are satisfied with the methods and procedures used by Devon in preparing the December 31, 2011 reserve and future cash flow estimates. We saw nothing of an unusual nature that would cause us to take exception with the estimates, in the aggregate, as prepared by Devon.

The estimated reserves and future cash flow amounts in this audit of the Devon report are related to hydrocarbon prices. The price calculation methodology specified by the SEC regulations was used in the preparation of those estimates; however, actual future prices may vary significantly from the SEC-specified pricing. In addition, future changes in taxation affecting oil and gas producing companies and their products, and changes in environmental and administrative regulations may significantly affect the ability of Devon to operate and produce oil and gas at the projected levels. Therefore, volumes of reserves actually recovered and amounts of cash flow actually received may differ significantly from the estimated quantities presented in this audit.

Estimates of reserves for this audit were prepared using standard geological and engineering methods generally accepted by the petroleum industry. The reserves in this audit have been estimated using deterministic methods. The method or combination of methods utilized in the evaluation of each reservoir included consideration of the stage of development of the reservoir, quality and completeness of basic data, and production history. Recovery from various reservoirs and leases was estimated after consideration of the type of energy inherent in the reservoirs, the structural positions of the properties, and reservoir and well performance. In some instances, comparisons were made to similar properties where more complete data were available. We have

LaRoche Petroleum Consultants, Ltd.

Mr. Bob Fant

January 26, 2012

Page 3

used all methods and procedures that we considered necessary under the circumstances to prepare this audit. We have excluded from our consideration all matters as to which the controlling interpretation may be legal or accounting rather than engineering or geosciences.

Benchmark prices used in this audit are based on the twelve-month unweighted arithmetic average of the first day of the month price for the period January through December 2011. Oil prices used by Devon are based on a Cushing West Texas Intermediate crude oil price of $96.19 per barrel, as published in Platts Oilgram, adjusted by lease for gravity, crude quality, transportation fees, and regional price differentials. Gas prices are based on a Henry Hub gas price of $4.118 per MMBTU, as published in Platts Gas Daily, adjusted by lease for energy content, transportation fees, and regional price differentials. NGL prices are based on a Mt. Belvieu composite product price of $49.88 per barrel, as published in the OPIS daily price bulletin, adjusted by area for composition, quality, transportation fees, and regional price differentials. Price differentials and adjustments to physical spot prices as of December 2011 were furnished by Devon and were accepted as presented. Oil and gas prices are held constant throughout the life of the properties. The weighted average prices over the life of the properties are $92.56 per barrel for oil, $3.44 per Mcf for gas, and $38.25 per barrel for NGL in the Mid-Continent Division. The weighted average prices over the life of the properties are $93.90 per barrel for oil, $3.97 per Mcf for gas, and $44.26 per barrel for NGL in the Southern Division.

Lease and well operating expenses were furnished by Devon and were confirmed by LPC from a review of Devon accounting data on a Project Area or Field Group basis. As requested, expenses for the Devon-operated properties include only direct lease and field level costs. For properties operated by others, these expenses include the per-well overhead costs allowed under joint operating agreements along with direct lease and field level costs. Headquarters general and administrative overhead expenses of Devon are not included. Operating expenses are held constant throughout the life of the properties.

Capital costs and timing of all investments have been provided by Devon and are included as required for workovers, new development wells, and production equipment. Devon has represented to us that they have the ability and intent to implement their capital expenditure program as scheduled. Devon’s estimates of the cost to plug and abandon the wells net of salvage value are included and scheduled at the end of the economic life of individual properties. These costs are held constant.

LPC has made no investigation of possible gas volume and value imbalances that may have been the result of overdelivery or underdelivery to the Devon interest. Our projections are based on Devon receiving its net revenue interest share of estimated future gross oil, gas, and NGL production.

An on-site inspection of the properties has not been performed nor has the mechanical operation or condition of the wells and their related facilities been examined by LPC. The costs associated with the continued operation of uneconomic properties are not reflected in the cash flows.

The evaluation of potential environmental liability from the operation and abandonment of the properties is beyond the scope of this audit. In addition, no evaluation was made to determine the degree of operator compliance with current environmental rules, regulations, and reporting requirements. Therefore, no estimate of the potential economic liability, if any, from environmental concerns is included in our projections.

LaRoche Petroleum Consultants, Ltd.

Mr. Bob Fant

January 26, 2012

Page 4

In our audit, we accepted without independent verification the accuracy and completeness of the information and data furnished by Devon with respect to ownership interest, oil and gas production, well test data, oil and gas prices, operating and development costs, and any agreements relating to current and future operations of the properties and sales of production. However, if in the course of our examination something came to our attention which brought into question the validity or sufficiency of any such information or data, we did not rely on such information or data until we had satisfactorily resolved our questions relating thereto or had independently verified such information or data.

The reserves estimated in our audit process and those presented by Devon are estimates only and should not be construed as exact quantities. They may or may not be recovered; if recovered, the revenues there from and the costs related thereto could be more or less than the estimated amounts. These estimates should be accepted with the understanding that future development, production history, changes in regulations, product prices, and operating expenses would probably cause us to make revisions in subsequent evaluations. A portion of these reserves are for behind-pipe zones, undeveloped locations, and producing wells that lack sufficient production history to utilize performance-related reserve estimates. Therefore, these reserves are based on estimates of reservoir volumes and recovery efficiencies along with analogies to similar production. These reserve estimates are subject to a greater degree of uncertainty than those based on substantial production and pressure data. It may be necessary to revise these estimates up or down in the future as additional performance data become available. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geological data; therefore, our conclusions represent informed professional judgments only, not statements of fact.

The results of our third party study were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Devon Energy Corporation.

Devon Energy Corporation makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, Devon Energy Corporation has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-3 and Form S-8 of Devon Energy Corporation of the references to our name together with references to our third party audit for Devon Energy Corporation, which appears in the December 31, 2011 annual report on Form 10-K of Devon Energy Corporation. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by Devon Energy Corporation.

We have provided Devon Energy Corporation with a digital version of the original signed copy of this audit letter. In the event there are any differences between the digital version included in filings made by Devon Energy Corporation and the original signed audit letter, the original signed audit letter shall control and supersede the digital version.

LPC’s technical personnel responsible for preparing this audit meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information promulgated by the Society of Petroleum Engineers. The technical person primarily responsible for overseeing the preparation of the LPC audit is William M. Kazmann. Mr. Kazmann is a Professional Engineer licensed in the State of Texas who has thirty-seven years of engineering experience in the oil and gas industry. Mr. Kazmann earned Bachelor of Science and Master of

LaRoche Petroleum Consultants, Ltd.

Mr. Bob Fant

January 26, 2012

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Science degrees in Petroleum Engineering from the University of Texas at Austin and has prepared reserves estimates for his employers and his own companies throughout his career. He has prepared and overseen preparation of reports for public filings for LPC for the past fifteen years. We are independent petroleum engineers, geologists, and geophysicists and are not employed on a contingent basis. Data pertinent to the audit are maintained on file in our office.

Very truly yours,

LaRoche Petroleum Consultants, Ltd.

State of Texas Registration Number F-1360

/s/ William M. Kazmann

William M. Kazmann

Licensed Professional Engineer

State of Texas No. 45012

/s/ Joe A. Young

Joe A. Young

Licensed Professional Engineer

State of Texas No. 62866

WMK:mk

11-400, 500, 700

LaRoche Petroleum Consultants, Ltd.

EX-99.2

Exhibit 99.2

    Fifth Avenue Place 600, 425 – 1 Street SW Calgary AB T2P 3L8 Canada   Tel: 403-648-3200 Fax: 403-265-0862 www.deloitte.ca

January 25, 2012

Devon Energy Corporation

20 North Broadway

Oklahoma City, Oklahoma

USA 73102

Attention: Mr. Bob Fant

Re: Devon Canada Corporation

December 31, 2011 reserve audit opinion

At your request and authorization, Deloitte & Touche LLP (“AJM Deloitte”) has audited the reserves management processes and practices of Devon Canada Corporation (“Devon Canada”) as of December 31, 2011. Our examination included such tests and procedures as we considered necessary under the circumstances to render our opinion.

During the course of our examination, we audited in excess of 89 percent of Devon Canada’s total proved reserves. AJM Deloitte’s estimate for the audited properties varied from Devon Canada’s estimates by less than 10 percent. When compared to Devon Canada’s parent corporation, Devon Energy Corporation, AJM Deloitte audited 22 percent of the company’s total proved reserves.

The scope of the audit consisted of the independent preparation of our own estimates of the proved and proved plus probable reserves and the comparison of our proved reserve results to the estimates prepared by the company. When compared on a field by field basis, some estimates prepared by Devon Canada are greater than and some are less than those prepared by AJM Deloitte. However, in our opinion, the estimates prepared by Devon Canada are in aggregate reasonable, are within the established audit tolerance of plus or minus 10 percent and the estimates have been prepared in accordance with generally accepted petroleum engineering practices and procedures. These practices and procedures are detailed within the Canadian Oil and Gas Evaluation Handbook (“COGEH”), set out by the Society of Petroleum Evaluation Engineers (“SPEE”) as well as the Society of Petroleum Engineers’ (“SPE”) Standards Pertaining to the Estimation and Auditing of Oil and Gas Reserves. The proved and proved plus probable reserve estimates prepared by both Devon Canada and AJM conform to the reserve definitions as set forth in the SEC’s Regulation S-X Part 210.4-10(a) and as clarified in subsequent Commission Staff Accounting Bulletins. We believe that such assumptions, data, methods, and procedures are appropriate for the purpose served by the report.

AJM Deloitte was provided with Devon Canada’s base hydrocarbon prices (oil, gas, condensate and natural gas liquids) as of December 31, 2011 in order to estimate the company’s net after royalty reserves. In accordance with SEC requirements all prices and costs (capital and operating) were held constant. The effects of derivative instruments designated as price hedges of oil and gas quantities if any, are not reflected in AJM Deloitte’s individual property evaluations. An oil equivalent conversion factor of 6.0 Mcf per 1.0 barrel oil was used for sales gas.

In general terms, Devon Canada’s corporate structure is such that lands are held within either Devon Canada Partnership (“DCP”) or Devon NEC Corporation (“NEC”). For the purpose of this evaluation, properties which consist of both DCP and NEC lands are reported separately.

The Evaluation Procedure section included in this report details the reserves definitions, price and market demand forecasts and general procedure used by AJM Deloitte in its reserve estimates. The extent and character of ownership and all factual data supplied by Devon Canada Corporation were accepted as presented. A field inspection and environmental/safety assessment of the properties was not made by AJM Deloitte and the consultant makes no representations and accepts no responsibilities in this regard.

It should be understood that our audit does not constitute a complete reserves study of the oil and gas properties of your company. In the conduct of our examinations we have not independently verified the accuracy and completeness of all the information and data furnished by your company with respect to ownership interests, oil and gas production, historical costs of operations and development, product prices, and agreements relating to current and future operations and sales of production. We have, however, specifically identified to you the information and data upon which we relied so that you can subject it to procedures you consider necessary. Furthermore, if in the course of our examination something came to our attention that brought into question the validity or sufficiency of any of the information or data, we did not rely on that information or data until we had satisfactorily resolved our questions or independently verified it.

We are independent with respect to the company as provided in the standards pertaining to the estimating and auditing of oil and gas reserves information included in COGEH and the Association of Professional Engineers, Geologists and Geophysicists of Alberta (“APEGGA”).

This audit is for the information of your company and for the information and assistance of its independent public accountants in connection with their review of, and report upon, the financial statements of your company. Supporting data documenting the audit, along with data provided by Devon Canada, are on file in our office. The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Devon Energy Corporation.

Devon Energy Corporation makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, Devon Energy Corporation has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-X of Devon Energy Corporation to the references to our name as well as to the references to our third party report for Devon Energy Corporation, which appears in the December 31, 2011 annual report on Form 10-K of Devon Energy Corporation. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by Devon Energy Corporation.

Yours truly,

Original signed by: “Robin G. Bertram”

Robin G. Bertram, P. Eng.

Associate Partner

Deloitte & Touche LLP

/ct

Evaluation procedure

Definitions and methodology

Effective as of December 2011

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Table of Contents

Definitions

• Procedure

• Reserve definitions

Resource and reserve estimation

Production forecasts

Land schedules and maps

Geology

Royalties and taxes

Capital and operating considerations

Price and market demand forecasts

Glossary of terms

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Procedure

AJM Deloitte has prepared estimates of resources and reserves in accordance with the process published in The Canadian Oil and Gas Evaluation Handbook (COGEH), Volume 1, 2^nd Edition. The reader is referred to the Handbook for a complete description of the particular process quoted as follows.

Resources or reserves evaluation

A “Resources or Reserves Evaluation” is the process whereby a qualified reserves evaluator estimates the quantities and values of oil and gas resources or reserves by interpreting and assessing all available pertinent data. The value of an oil and gas asset is a function of the ability or potential ability of that asset to generate future net revenue, and it is measured using a set of forward-looking assumptions regarding resources or reserves, production, prices, and costs. Evaluations of oil and gas assets, in particular reserves, include a discounted cash flow analysis of estimated future net revenue.

Reserves audit

A “Reserves Audit” is the process carried out by a qualified reserves auditor that results in a reasonable assurance, in the form of an opinion, that the reserves information has in all material respects been determined and presented according to the principles and definitions adopted by the Society of Petroleum Evaluation Engineers (“SPEE”) (Calgary Chapter), and Association of Professional Engineers, Geologists and Geophysicists of Alberta (“APEGGA”) and are, therefore free of material misstatement.

The reserves evaluations prepared by the Corporation have been audited, not for the purpose of verifying exactness, but the reserves information, company policies, procedures, and methods used in estimating the reserves will be examined in sufficient detail so that AJM Deloitte can express an opinion as to whether, in the aggregate, the reserves information presented by the Corporation are reasonable.

AJM Deloitte may require its own independent evaluation of the reserves information for a small number of properties, or for a large number of properties as tests for the reasonableness of the Corporation’s evaluations. The tests to be applied to the Corporation’s evaluations insofar as their methods and controls and the properties selected to be re-evaluated will be determined by AJM Deloitte, in its sole judgment, to arrive at an opinion as to the reasonableness of the Corporation’s evaluations.

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Reserves review

A “Reserves Review” is the process whereby a reserves auditor conducts a high-level assessment of reserves information to determine if it is plausible. The steps consist primarily of enquiry, analytical procedure, analysis, review of historical reserves performance, and discussion with the Corporation’s reserves management staff.

“Plausible” means the reserves data appear to be worthy of belief based on the information obtained by the independent qualified reserves auditor in carrying out the aforementioned steps. Negative assurance can be given by the independent reserves auditor, but an opinion cannot. For example, “Nothing came to my attention that would indicate the reserves information has not been prepared and presented in accordance with principles and definitions adopted by the SPEE (Calgary Chapter), and APEGGA (Practice Standard for the Evaluation of Oil and Gas Reserves for Public Disclosure).

Reviews do not require examination of the detailed document that supports the reserves information, unless this information does not appear to be plausible.

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Reserve definitions

Reserve classification

Proved reserves are classified by AJM Deloitte in accordance with the following definitions that are the United States Securities and Exchange Commission Regulation S-X Part 210.4-10. These definitions are as follows:

Proved oil and gas reserves

Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e. prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

• Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

• Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

• Estimates of proved reserves do not include the following:

a. oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”;

b. crude oil, natural gas and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors;

c. crude oil, natural gas and natural gas liquids, that may occur in undrilled prospects; and

d. crude oil, natural gas and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

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Proved developed oil and gas reserves

Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

The SEC does not further subdivide proved developed reserves. AJM Deloitte further subdivides proved developed reserves between proved developed producing and proved developed non-producing reserves, as follows. The definition and guidelines are documented in the Petroleum Resources Management System (“PRMS”) prepared by the Oil and Gas Reserves Committee of the Society of Petroleum Engineers (SPE), World Petroleum Council (WPC), the American Association of Petroleum Geologists (AAPG), and the Society of Petroleum Evaluation Engineers (SPEE).

Proved Developed Producing Reserves: Proved developed producing reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Proved Developed Non-Producing Reserves: Proved developed non-producing reserves include shut-in and behind-pipe reserves. Shut-in reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe reserves are expected to be recovered from zones in existing wells which will require additional completion work or future recompletion prior to the start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

Proved Undeveloped Reserves: Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of

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production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

Probable reserves

Probable reserves are those additional reserves which analysis of geoscience and engineering data indicates are less likely to be recovered than proved reserves but more certain to be recovered than possible reserves. It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated proved plus probable reserves (2P).

The SEC further sub-divides probable reserves. AJM Deloitte further sub-divides probable reserves into developed and undeveloped and producing and non-producing, as follows:

Probable Developed reserves are expected quantities to be recovered from existing wells and facilities. Reserves are considered developed only after the necessary equipment has been installed, or when the costs to do so are relatively minor compared to the cost of a well. Developed reserves may be subcategorized as producing or non-producing.

Producing: Probable reserves that are expected to be recovered from completion intervals which are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Non-Producing: Probable reserves include shut-in and behind-pipe reserves. Shut-in reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future recompletion prior to the start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

Probable Undeveloped reserves are quantities expected to be recovered through future investments: (1) from new wells on undrilled acreage in known accumulations, (2) from deepening existing wells to a different (but known) reservoir, or (3) where a relatively large expenditure (eg. when compared to the cost of drilling a new well) is required to (a) recomplete an existing well or (b) install production or transportation facilities for primary or improved recovery projects.

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Resource and reserve estimation

AJM Deloitte generally assigns reserves to properties via deterministic methods. Probabilistic estimation techniques are typically used where there is a low degree of certainty in the information available and is generally used in resource evaluations. This will be stated within the detailed property reports.

Deterministic

Reserves and resources were estimated either by i) volumetric, ii) decline curve analysis, iii) material balance techniques, or iv) performance predictions.

Volumetric reserves were estimated using the wellbore net pay and an assigned drainage area or, where sufficient data was available, the reservoir volumes calculated from isopach maps. Reservoir rock and fluid data were obtained from available core analysis, well logs, PVT data, gas analysis, government sources, and other published information either on the evaluated pool or from a similar reservoir in the immediate area. In mature (producing) reservoirs decline curve analysis and/or material balance was utilized in all applicable evaluations.

Statistical analysis

Whenever there is the need within an evaluation to assign reserves based on analogy or when volumetric reserves are being assigned, AJM Deloitte utilizes a variety of different tools in support of. When evaluating Western Canadian prospects, typically AJM Deloitte uses petroCUBE™.

The petroCUBE program is a web-based (www.petroCUBE.com) product co-developed by AJM Deloitte and geoLOGIC Systems Inc. petroCUBE provides geostatistical, technical, and financial information for conventional hydrocarbon plays throughout the Western Canadian Sedimentary Basin (“WCSB”).

The information provided by petroCUBE is an unbiased independent perspective into the historical performance of the conventional hydrocarbon activity in the WCSB. The statistical information is presented by commodity type (gas, oil) with each commodity further analyzed by geographic area and play type.

Analysis output includes cumulative frequency resource distribution curves, chance of success tables, production performance profiles for each play type and area, unrisked and risked resources, and initial production rates on a per well zone basis, and full cycle economic and play parameters.

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Cumulative frequency curves show how the volumes for a play are distributed. These calculations include the average volumes for a play (P₅₀), volumes for the best 10 percent of the wells (P₁₀), the minimum volumes developed by 90 percent of the wells (P₉₀).

Reserves assigned are compared to those volumes noted in the cumulative frequency curves for the corresponding area and play type. Typically an expected or proved plus probable reserve is a P₅₀ volume.

Probabilistic

Because of the uncertainty inherent in reservoir parameters, probabilistic analysis, which is based on statistical techniques, provides a formulated approach by which to obtain a reasonable assessment of the petroleum initially in place (PIIP) and/or the recoverable resource. Probabilistic analysis involves generating a range of possible outcomes for each unknown parameter and their associated probability of occurrence. When probabilistic analysis is applied to resource estimation, it provides a range of possible PIIPs or recoverable resources.

In preparing a resource estimate, AJM Deloitte assesses the following volumetric parameters: areal extent, net pay thickness, porosity, hydrocarbon saturation, reservoir temperature, reservoir pressure, gas compressibility factor, recovery factor, and surface loss. A team of professional engineers and geologists experienced in probabilistic resource evaluation considered each of the parameters individually to estimate the most reasonable range of values. Working from existing data, the team discusses and agrees on the low (P₉₀) and high (P₁₀) values for each parameter. To help test the reasonableness of the proposed range, a minimum (P₉₉) and maximum (P₁) value are also extrapolated from the low and high values. After ranges have been established for each parameter, these independent distributions are used to determine a P₉₀, P₅₀, and P₁₀ result which comprise AJM Deloitte’s estimated range of PIIP or recoverable resource.

It is important to note that the process used to determine the final P₁₀, P₉₀, and P₅₀ results involves multiplying the various volumetric parameters together. This yields results which require adjustments to maintain an appropriate probability of occurrence. For example, when calculating total reservoir volume (Area x Pay), the chance of getting a volume greater than the P₁₀ Area x P₁₀ Pay is less than 10 percent – the chance of getting the calculated result is only 3.5 percent (p_3.5). As you multiply additional P₁₀ values, the probability of achieving the calculated value becomes less likely. Similarly, multiplying P₉₀ parameters together will yield a result that has a probability greater than P₉₀. As such, when multiplying independent distributions together the results must be adjusted via interpolation to determine final P₉₀ and P₁₀ values.

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The results appearing in this report represent interpolated P₉₀ and P₁₀ values. As defined by COGEH (and the Petroleum Resource Management System “PRMS”), the P₅₀ estimate is the “best estimate” for reporting purposes.

Production forecasts

Production forecasts were based on historical trends or by comparison with other wells in the immediate area producing from similar reservoirs. Non-producing gas reserves were forecast to come on-stream within the first two years from the effective date under direct sales pricing and deliverability assumptions, if a tie-in point to an existing gathering system was in close proximity (approximately two miles). If the tie-in point was of a greater distance (and dependent on the reserve volume and risk) the reserves were forecast to come on-stream in years three or four from the effective date. If the reserves were located in a remote location and/or the reserve volume was of higher risk, the reserves were forecast to come on-stream beyond five years from the effective date. These on-stream dates were used when the company could not provide specific on-stream date information.

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Land schedule and maps

The evaluated Corporation provided schedules of land ownership which included lessor and lessee royalty burdens. The land data was accepted as factual and no investigation of title by AJM Deloitte was made to verify the records.

Well maps included within this report represent all of the Corporation’s interests that were evaluated in the specified area.

Geology

An initial review of each property is undertaken to establish the produced maturity of the reservoir being evaluated. Where extensive production history exists a geologic analysis is not conducted since the remaining hydrocarbons can be determined by productivity analysis.

For properties that are not of a mature production nature a geologic review is conducted. This work consists of:

• developing a regional understanding of the play,

• assessing reservoir parameters from the nearest analogous production,

• analysis of all relevant well data including logs, cores, and tests to measure net formation thickness (pay), porosity, and initial water saturation,

• auditing of client mapping or developing maps to meet AJM Deloitte’s need to establish volumetric hydrocarbons-in-place.

Procedures specific to the project are discussed in the body of the report.

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Royalties and taxes

General

All royalties and taxes, including the lessor and overriding royalties, are based on government regulations, negotiated leases or farmout agreements, that were in effect as of the evaluation effective date. If regulations change, the net after royalty recoverable reserve volumes may differ materially.

AJM Deloitte utilizes a variety of reserves and valuation products in determining the result sets.

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Capital and operating considerations

Operating and capital costs were based on current costs escalated to the date the cost was incurred, and are in current year dollars. The economic runs provide the escalated dollar costs as found in the Pricing Table 1 in the Price and Market Demand section.

Reserves estimated to meet the standards of NI 51-101 for constant prices and costs (optimal), are based on unescalated operating and capital costs.

Capital costs were either provided by the Corporation (and reviewed by AJM Deloitte for reasonableness); or determined by AJM Deloitte taking into account well capability, facility requirement, and distance to markets. Facility expenditures for shut-in gas are forecast to occur prior to the well’s first production.

Operating costs were determined from historical data on the property as provided by the evaluated Corporation. If this data was not available or incomplete, the costs were based on AJM Deloitte experience and historical database. Operating costs are defined into three types.

The first type, variable ($/Unit), covers the costs directly associated with the product production. Costs for processing, gathering and compression are based on raw gas volumes. Over the life of the project the costs are inflated in escalated runs to reflect the increase in costs over time. In a constant dollar review the costs remain flat over the project life.

The second type, fixed plant or battery ($/year), is again a fixed component over the project life and reflects any gas plant or battery operating costs allocated back to the evaluated group. The plant or battery can also be run as a separate group and subsequently consolidated at the property level.

The third type takes the remaining costs that are not associated with the first two and assigns them to the well based on a fixed and variable component. A split of 65 percent fixed and 35 percent variable assumes efficiencies of operation over time, i.e.: the well operator can reduce the number of monthly visits as the well matures, workovers may be delayed, well maintenance can also be reduced. The basic assumption is that the field operator will continue to find efficiencies to reduce the costs over time to maintain the overall $/Boe cost. Thus as the production drops over time the 35 percent variable cost will account for these efficiencies. If production is flat all the costs will also remain flat. Both the fixed and variable costs in this type are inflated in the escalated case and held constant in the constant dollar review. These costs also include property taxes, lease rentals, government fees, and administrative overhead.

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In reserve evaluations conducted for purposes of NI 51-101, or, if an economic analysis was prepared for a resource evaluation, well abandonment and reclamation costs have been included and these costs were either provided by the Corporation (and reviewed by AJM Deloitte for reasonableness) or based on area averages (only the base abandonment costs were utilized and no consideration for groundwater protection, vent flow repair costs, or gas migration costs were considered). If there were multiple events to abandon the costs were increased by a 25 percent factor. Site reclamation costs were based on information provided by the Corporation or based on area averages. For undeveloped reserve estimates for undrilled locations, both abandonment and site reclamation costs are also included for the purpose of determining whether reserves should be attributed to that property in the first year in which the reserves are considered for attribution to the property.

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Price and market demand forecasts

Pricing overview

Devon provided AJM Deloitte with hydrocarbon prices (oil, gas condensate, and natural gas liquids) appropriate for use in the preparation of a reserves report to be filed with the SEC with an effective date of December 31, 2011. These prices were calculated in accordance with the “Modernization of Oil and Gas Reporting: Final Rule” and were determined by taking the un-weighted average of the prices on the first day of the month for the preceding 12 months (January 1, 2011 through to December 1, 2011).

The effects of derivative instruments designated as price hedges of oil and gas quantities if any, are not reflected in AJM Deloitte’s individual property evaluations.

	Benchmark	Benchmark price ($US)	Weighted average realized report price ($US)
Oil	NYMEX WTI @ Cushing	$96.19/bbl	$64.34/bbl
Gas	NYMEX Henry Hub	$4.12/MMbtu	$3.55/Mcf
NGL	Mt. Belvieu	$49.88/bbl	$45.08/bbl

16

Glossary of terms

AJM Deloitte subscribes to the Glossary of Terms as defined by the Canadian Oil and Gas Evaluation Handbook, Volume 2.

17

XML

Supplemental Information To Statements Of Cash Flows (Tables)

12 Months Ended

Dec. 31, 2011

Supplemental Information To Statements Of Cash Flows [Abstract]

Schedule Of Supplemental To Cash Flow Information

	Year Ended December 31,
	2011	2010	2009
	(In millions)
Net decrease (increase) in working capital:
(Increase) decrease in accounts receivable	$       (185)	$           23	$         142
Decrease in other current assets	125	21	212
Increase (decrease) in accounts payable	64	37	(91)
Increase in revenues and royalties payable	144	48	—
Increase (decrease) in income taxes payable	78	(203)	(48)
Decrease in other current liabilities	(41)	(199)	(66)
Net decrease (increase) in working capital	$         185	$       (273)	$         149
Supplementary cash flow data – total operations:
Interest paid (net of capitalized interest)	$         325	$         359	$         314
Income taxes (received) paid	$       (383)	$         955	$           68

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Supplemental Information On Oil And Gas Operations (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009 Boe
Reserve Quantities [Line Items]
Capitalized general and administrative expenses	$ 337,000,000	$ 311,000,000	$ 332,000,000
Capitalized interest expenses	(72,000,000)	(76,000,000)	(94,000,000)
Proved undeveloped reserves	782
Decrease in proved undeveloped reserves	6.00%
Percentage of total proved reserves	26.00%
Proved undeveloped reserves, drilling activities	148
Proved undeveloped reserves, drilling activities, conversion	130
Proved undeveloped reserves to proved developed reserves, conversion, percentage	16.00%
Increase in reserves due to adoption of SEC' modernization of oil and gas reporting (MMBoe)			65
Percent increase in reserves due to adoption of SEC's modernization of oil and gas reporting			2.00%
Average price per barrel of oil used to estimate proved oil reserves	67.31
Average price per Mcf of gas used to estimated proved gas	3.51
Average price per barrel of natural gas liquids used to estimate proved NGL reserves	39.28
Future development costs	11,500,000,000
Future development costs estimated to be spent in 2012	1,600,000,000
Future development costs estimated to be spent in 2013	1,400,000,000
Future development costs estimated to be spent in 2014	1,100,000,000
Future dismantlement, abandonment and rehabilitation costs	2,200,000,000
Future net revenues discounted	10.00%
After tax future net revenue discounted	17,800,000,000
Standardized measure discounted future income taxes	7,100,000,000
Pre tax future net revenue	24,900,000,000
Pre tax present value percentage	10.00%
Barnett Shale [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, revisions due to prices		43
Proved developed and undeveloped reserves, extensions and discoveries	115	87	204
Proved developed and undeveloped reserves, extensions and discoveries related to additions from in fill drilling activities	77	43	203
Jackfish [Member]
Reserve Quantities [Line Items]
Unproved developed and undeveloped reserves, revisions due to prices			331
Proved developed and undeveloped reserves, extensions and discoveries	30	55	118
Proved developed and undeveloped reserves, extensions and discoveries related to additions from in fill drilling activities			118
Proved undeveloped reserves	367	396
Daily facility capacity	35,000
Carthage [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, extensions and discoveries		14	8
Granite Wash Area [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, extensions and discoveries	17
Cana-Woodford Shale [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, extensions and discoveries	162	101	49
Proved developed and undeveloped reserves, extensions and discoveries related to additions from in fill drilling activities	80	47	24
Rocky Mountain [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, revisions due to prices		22
Proved developed and undeveloped reserves, extensions and discoveries	19	15	14
Deepwater Production In The Gulf [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, extensions and discoveries			11
Haynesville Shale [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, extensions and discoveries			7
Permian Basin [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, extensions and discoveries	39	19
Oil And Gas Properties [Member]
Reserve Quantities [Line Items]
Capitalized interest expenses	$ 45,000,000	$ 37,000,000	$ 74,000,000
Total (MMBoe) [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, revisions due to prices	(21)	72	177
Proved developed and undeveloped reserves, extensions and discoveries	421	354	458
Proved developed and undeveloped reserves, extensions and discoveries related to additions from in fill drilling activities	168	107	371
Total (MMBoe) [Member] | United States [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, revisions due to prices			(116)

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Summary Of Significant Accounting Policies (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Summary Of Significant Accounting Policies [Line Items]
Percent of revenue not exceeded by client	10.00%
Auction rate securities	$ 84	$ 94
After-tax future net revenue discount rate	10.00%
Twelve month period prior to the end of the period for future net revenues calculation	12
Estimated useful life range, years, maximum	39
Estimated useful life range, years, minimum	3
Maximum [Member]
Summary Of Significant Accounting Policies [Line Items]
Mark-to-market threshold above which collateral must be posted	55
Depletion calculation holding period, years	6
Minimum [Member]
Summary Of Significant Accounting Policies [Line Items]
Mark-to-market threshold above which collateral must be posted	$ 0
Depletion calculation holding period, years	3

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Commitments And Contingencies (Tables)

12 Months Ended

Dec. 31, 2011

Commitments And Contingencies [Abstract]

Schedule Of Commitments And Contingencies

Year Ending December 31,	Purchase Obligations	Drilling and Facility Obligations	Operational Agreements	Office and Equipment Leases
	(In millions)
2012	$         900	$         919	$              306	$         63
2013	905	456	302	56
2014	905	100	283	47
2015	905	—	250	44
2016	924	—	209	43
Thereafter	3,915	—	786	220
Total	$     8,454	$     1,475	$           2,136	$      473

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Supplemental Information On Oil And Gas Operations (Estimated Pretax Cash Flow Information Related To Proved Reserves) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011
United States [Member]
Pre-Tax Future Net Revenue, Proved Developed Reserves	$ 30,473	[1]
Pre-Tax Future Net Revenue, Proved Undeveloped Reserves	5,798	[1]
Pre-Tax Future Net Revenue, Total Proved Reserves	36,271	[1]
Pre-Tax 10% Present Value, Proved Developed Reserves	15,165	[1]
Pre-Tax 10% Present Value, Proved Undeveloped Reserves	1,404	[1]
Pre-Tax 10% Present Value, Total Proved Reserves	16,569	[1]
Canada [Member]
Pre-Tax Future Net Revenue, Proved Developed Reserves	7,757	[1]
Pre-Tax Future Net Revenue, Proved Undeveloped Reserves	9,288	[1]
Pre-Tax Future Net Revenue, Total Proved Reserves	17,045	[1]
Pre-Tax 10% Present Value, Proved Developed Reserves	5,830	[1]
Pre-Tax 10% Present Value, Proved Undeveloped Reserves	2,508	[1]
Pre-Tax 10% Present Value, Total Proved Reserves	8,338	[1]
North America [Member]
Pre-Tax Future Net Revenue, Proved Developed Reserves	38,230	[1]
Pre-Tax Future Net Revenue, Proved Undeveloped Reserves	15,086	[1]
Pre-Tax Future Net Revenue, Total Proved Reserves	53,316	[1]
Pre-Tax 10% Present Value, Proved Developed Reserves	20,995	[1]
Pre-Tax 10% Present Value, Proved Undeveloped Reserves	3,912	[1]
Pre-Tax 10% Present Value, Total Proved Reserves	$ 24,907	[1]

[1] Estimated pre-tax 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 depreciation, depletion and amortization, or to non-property related expenses such as debt service and income tax expense.

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Other, Net (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2009
Other, Net [Abstract]
Insurance recoveries	$ 88
Loss contingency accrual		$ 84

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Summary Of Significant Accounting Policies (Schedule Of Goodwill By Business Segment) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Summary Of Significant Accounting Policies [Line Items]
Goodwill	$ 6,013	$ 6,080
Canada [Member]
Summary Of Significant Accounting Policies [Line Items]
Goodwill	2,967	3,034
United States [Member]
Summary Of Significant Accounting Policies [Line Items]
Goodwill	$ 3,046	$ 3,046

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Earnings (Loss) Per Share (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Earnings (loss) from continuing operations	$ 521	$ 1,040	$ 184	$ 389	$ 478	$ 429	$ 352	$ 1,074	$ 2,134	$ 2,333	$ (2,753)
Basic earnings (loss) from continuing operations per share	$ 1.29	$ 2.51	$ 0.44	$ 0.91	$ 1.10	$ 0.99	$ 0.79	$ 2.40	$ 5.12	$ 5.31	$ (6.20)
Diluted earnings from continuing operations per share	$ 1.29	$ 2.50	$ 0.43	$ 0.91	$ 1.10	$ 0.98	$ 0.79	$ 2.39	$ 5.10	$ 5.29	$ (6.20)
Antidilutive securities excluded from computation of earnings per share, amount									3	6	9
Earnings [Member]
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Earnings (loss) from continuing operations									2,134	2,333	(2,753)
Attributable to participating securities									(23)	(26)	31
Net earnings (loss) applicable to common stockholders									2,111	2,307
Diluted earnings per share									2,111	2,307
Basic and diluted loss per share											$ (2,722)
Common Shares [Member]
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Earnings from continuing operations, in shares									417	440	444
Attributable to participating securities, in shares									(5)	(5)	(5)
Basic earnings per share, shares									412	435
Dilutive effect of potential common shares issuable upon the exercise of outstanding stock options, in shares									2	1
Diluted earnings per share, shares									414	436
Basic and diluted earnings per share, shares											439
Earnings (Loss) Per Share [Member]
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Basic earnings (loss) from continuing operations per share									$ 5.12	$ 5.31
Diluted earnings from continuing operations per share									$ 5.10	$ 5.29
Basic and diluted loss from continuing operations per share											$ (6.20)

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Commitments And Contingencies (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Jun. 20, 2011
Issued court judgment				$ 196
Recorded liability due to court judgment	133
Recorded receivable due to indemnification agreement	133
Obligation related to the purchase of condensate, year of expiration	2021
Total rental expense, including certain office space and equipment under operating lease agreements, net of sub-lease income	42	57	56
Devon [Member]
Issued court judgment				$ 133

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Retirement Plans (Tables)

12 Months Ended

Dec. 31, 2011

Dec. 31, 2010

Schedule Of Changes In Defined Benefit Plan Obligations

	Pension Benefits		Postretirement Benefits
	2011	2010	2011	2010
	(In millions)
Change in benefit obligation:
Benefit obligation at beginning of year	$ 1,124	$    980	$       43	$       64
Service cost	37	33	1	1
Interest cost	60	58	2	3
Actuarial loss (gain)	123	82	(8)	1
Plan amendments	—	5	5	(22)
Plan settlements	—	—	(4)	—
Foreign exchange rate changes	(1)	2	—	—
Participant contributions	—	—	3	2
Benefits paid	(40)	(36)	(5)	(6)
Benefit obligation at end of year	1,303	1,124	37	43
Change in plan assets:
Fair value of plan assets at beginning of year	632	532	—	—
Actual return on plan assets	141	69	—	—
Employer contributions	454	66	7	4
Participant contributions	—	—	3	2
Plan settlements	—	—	(5)	—
Benefits paid	(40)	(36)	(5)	(6)
Foreign exchange rate changes	—	1	—	—
Fair value of plan assets at end of year	1,187	632	—	—
Funded status at end of year	$   (116)	$   (492)	$     (37)	$     (43)
Amounts recognized in balance sheet:
Noncurrent assets	$    116	$         2	$       —	$       —
Current liabilities	(10)	(9)	(3)	(4)
Noncurrent liabilities	(222)	(485)	(34)	(39)
Net amount	$   (116)	$   (492)	$     (37)	$     (43)
Amounts recognized in accumulated other   comprehensive earnings:
Net actuarial loss (gain)	$    348	$    357	$        (9)	$        (5)
Prior service cost (credit)	18	21	(5)	(12)
Total	$    366	$    378	$     (14)	$     (17)

Schedule Of Pension Plans With Projected And Accumulated Benefit Obligations In Excess Of Plan Assets

	December 31,
	2011	2010
	(In millions)
Projected benefit obligation	$      232	$   1,110
Accumulated benefit obligation	$      189	$      996
Fair value of plan assets	$         —	$      616

Schedule Of Components Of Net Periodic Benefit Cost And Other Comprehensive Income For Defined Benefit Plans

	Pension Benefits			Postretirement Benefits
	2011	2010	2009	2011	2010	2009
	(In millions)
Net periodic benefit cost:
Service cost	$       37	$        33	$       43	$          1	$        1	$         1
Interest cost	60	58	58	2	3	3
Expected return on plan assets	(42)	(36)	(35)	—	—	—
Curtailment and settlement expense	—	—	5	(3)	—	—
Recognition of net actuarial loss (gain)	32	27	45	—	—	(1)
Recognition of prior service cost	3	3	3	(2)	1	2
Total net periodic benefit cost	90	85	119	(2)	5	5
Other comprehensive earnings:
Actuarial loss (gain) arising in current year	23	50	(66)	(7)	1	7
Prior service cost (credit) arising in current year.	—	4	—	5	(22)	—
Recognition of net actuarial loss, including     settlement expense, in net periodic benefit cost	(32)	(27)	(45)	3	—	1
Recognition of prior service cost, including     curtailment, in net periodic benefit cost	(3)	(3)	(8)	2	(1)	(2)
Total other comprehensive (loss) earnings	(12)	24	(119)	3	(22)	6
Total recognized	$       78	$      109	$       —	$          1	$     (17)	$       11

Schedule Of Estimated Net Actuarial Loss And Prior Service Cost For Pension And Other Postretirement Plans To Be Amortized

	Pension Benefits	Postretirement      Benefits
	(In millions)
Net actuarial loss (gain)	$       24	$                (1)
Prior service cost (credit)	3	(1)
Total	$       27	$                (2)

Schedule Of Weighted-Average Assumptions Used To Determine Benefit Obligations And Net Periodic Pension Costs

	Pension Benefits			Postretirement Benefits
	2011	2010	2009	2011	2010	2009
Assumptions to determine benefit obligations:
Discount rate	4.65%	5.50%	6.00%	4.25%	4.90%	5.70%
Rate of compensation increase	4.97%	6.94%	6.95%	N/A	N/A	N/A
Assumptions to determine net periodic benefit cost:
Discount rate	5.50%	6.00%	6.00%	4.90%	5.70%	6.00%
Expected return on plan assets	6.48%	6.94%	7.18%	N/A	N/A	N/A
Rate of compensation increase	6.94%	6.95%	6.95%	N/A	N/A	N/A

Schedule Of Fair Value Of Pension Assets

	As of December 31, 2011
			Fair Value Measurements Using:
	Actual Allocation	Total	Level 1 Inputs	Level 2 Inputs	Level 3 Inputs
	($ In millions)
Fixed-income securities:
U.S. Treasury obligations	43.9%	$           522	$              27	$           495	$              —
Corporate bonds	24.8%	294	265	29	—
Other bonds	3.1%	36	36	—	—
Total fixed-income securities	71.8%	852	328	524	—
Equity securities:
Global (large, mid, small cap)	18.0%	214	—	214	—
Other securities:
Hedge fund & alternative investments.	8.9%	106	16	—	90
Short-term investment funds	1.3%	15	—	15	—
Total other securities	10.2%	121	16	15	90
Total investments	100.0%	$        1,187	$           344	$           753	$              90

	As of December 31, 2010
			Fair Value Measurements Using:
	Actual Allocation	Total	Level 1 Inputs	Level 2 Inputs	Level 3 Inputs
	($ In millions)
Equity securities:
U.S. large cap	22.3%	$           141	$              —	$           141	$              —
U.S. small cap	14.1%	89	89	—	—
International large cap	14.4%	91	50	41	—
Total equity securities	50.8%	321	139	182	—
Fixed-income securities:
Corporate bonds	22.0%	139	139	—	—
U.S. Treasury obligations	10.9%	69	69	—	—
Other bonds	4.6%	29	29	—	—
Total fixed-income securities	37.5%	237	237	—	—
Other securities:
Hedge funds	9.2%	58	—	—	58
Short-term investment funds	2.5%	16	—	16	—
Total other securities	11.7%	74	—	16	58
Total investments	100.0%	$           632	$           376	$           198	$              58

Schedule Of Changes To Level 3 Plan Assets

December 31, 2009	$               51
Purchases	3
Investment returns	4
December 31, 2010	58
Purchases	33
Investment returns	(1)
December 31, 2011	$               90

Schedule Of Expected Cash Flow Information For Pension And Other Postretirement Benefit Plans

	Pension Benefits	Postretirement Benefits
	(In millions)
Devon's 2012 contributions	$           9	$                 3
Benefit payments:
2012	$         44	$                 3
2013	$         49	$                 3
2014	$         52	$                 3
2015	$         56	$                 3
2016	$         61	$                 3
2017 to 2021	$       390	$               14

Schedule Of Expense Related To These Defined Contribution Plans

	Year Ended December 31,
	2011	2010	2009
	(In millions)
401(k) and enhanced contribution plans	$     33	$     32	$     34
Canadian pension and savings plans	21	17	15
Total	$     54	$     49	$     49

Target Allocation [Member]

Schedule Of Fair Value Of Pension Assets

	December 31,
	2011	2010
Fixed income	70%	40%
Equity	20%	47.5%
Other	10%	12.5%

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Share-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2011

Share-Based Compensation [Abstract]

Schedule of the Effects of Share-Based Compensation Included in the Consolidated Comprehensive Statements of Earnings

	2011	2010	2009
	(In millions)
Gross general and administrative expense	$    181	$    188	$    209
Share-based compensation expense capitalized pursuant to the   full cost method of accounting for oil and gas properties	$      56	$      58	$      66
Related income tax benefit	$      33	$      40	$      43

Summary Of Unvested Restricted Stock Awards And Units, Including Changes During The Year

	Restricted Stock Awards & Units	Weighted Average Grant-Date Fair Value
	(In thousands)
Unvested at December 31, 2010	5,311	$  70.60
Granted	2,301	$  65.40
Vested	(2,188)	$  72.05
Forfeited	(200)	$  71.18
Unvested at December 31, 2011	5,224	$  67.85

Summary Of The Grant-Date Fair Values Of Stock Options Granted And Their Related Assumptions, Represented By The Weighted-Average Amounts

	2011	2010	2009
Grant-date fair value	$23.11	$25.41	$22.85
Volatility factor	46.0%	45.3%	47.7%
Dividend yield	1.0%	1.0%	0.9%
Risk-free interest rate	0.8%	1.1%	2.1%
Expected term (in years)	4.2	4.5	4.0

Summary Of Outstanding Stock Options, Including Changes During The Year

		Weighted Average
	Options	Exercise Price	Remaining Term	Intrinsic Value
	(In thousands)		(In years)	(In millions)
Outstanding at December 31, 2010	11,434	$  62.64
Granted	1,962	$  66.98
Exercised	(2,366)	$  47.51
Forfeited	(487)	$  73.32
Outstanding at December 31, 2011	10,543	$  66.35	4.31	$   40
Vested and expected to vest at December 31, 2011..	10,428	$  66.33	4.27	$   40
Exercisable at December 31, 2011	6,716	$  65.39	2.90	$   39

Summary Of Performance Based Restricted Stock Awards

	Performance Restricted Stock Awards	Weighted Average Grant-Date Fair Value
	(In thousands)
Unvested at December 31, 2010	—	$        —
Granted	184	$  65.10
Unvested at December 31, 2011	184	$  65.10

Summary Of Performance Share Units

	Share Units	Weighted Average Grant-Date Fair Value
	(In thousands)
Unvested at December 31, 2010	—	$        —
Granted (1)	171	$  81.70
Unvested at December 31, 2011	171	$  81.70

____________________________

(1)A maximum of 341,000 common shares could be awarded based upon Devon's final TSR ranking.

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Other Comprehensive Earnings (Components Of Other Comprehensive Earnings) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Accumulated foreign currency translation at beginning of year	$ 1,993	$ 1,616	$ 685
Change in cumulative translation adjustment	(200)	397	993
Income tax benefit (expense)	9	(20)	(62)
Accumulated foreign currency translation at end of year	1,802	1,993	1,616
Accumulated pension and postretirement benefit at beginning of year	(233)	(231)	(302)
Net actuarial (loss) gain and prior service cost arising in current year	(21)	(33)	59
Recognition of net actuarial loss and prior service cost in net earnings	30	31	54
Accumulated pension and postretirement benefits at end of year	(227)	(233)	(231)
Accumulated other comprehensive earnings, net of tax	1,575	1,760	1,385
Cost Arising In Current Year [Member]
Income tax benefit (expense)	8	11	(22)
Income tax expense	$ (11)	$ (11)	$ (20)

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Supplemental Information On Oil And Gas Operations (Proved Undeveloped Reserves) (Details)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
U.S. Onshore [Member]
Reserve Quantities [Line Items]
Proved undeveloped reserves	403	411
Proved Undeveloped Reserves, Extensions and discoveries	118
Proved Undeveloped Reserves, Revisions due to prices	(2)
Proved Undeveloped Reserves, Revisions other than price	(56)
Proved Undeveloped Reserves, Conversion to proved developed reserves	(68)
Canada [Member]
Reserve Quantities [Line Items]
Proved undeveloped reserves	379	420
Proved Undeveloped Reserves, Extensions and discoveries	30
Proved Undeveloped Reserves, Revisions due to prices	(14)
Proved Undeveloped Reserves, Revisions other than price	5
Proved Undeveloped Reserves, Conversion to proved developed reserves	(62)
North America [Member]
Reserve Quantities [Line Items]
Proved undeveloped reserves	782	831
Proved Undeveloped Reserves, Extensions and discoveries	148
Proved Undeveloped Reserves, Revisions due to prices	(16)
Proved Undeveloped Reserves, Revisions other than price	(51)
Proved Undeveloped Reserves, Conversion to proved developed reserves	(130)

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Income Taxes (Schedule Of Income Tax Expense (Benefit)) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Income Taxes [Abstract]
U.S. federal	$ (143)	$ 244	$ 45
Various states	20	16	18
Canada and various provinces	(20)	256	178
Total current tax (benefit) expense	(143)	516	241
U.S. federal	1,986	781	(1,846)
Various states	95	21	(111)
Canada and various provinces	218	(83)	(57)
Total deferred tax expense (benefit)	2,299	719	(2,014)
Total income tax expense (benefit)	$ 2,156	$ 1,235	$ (1,773)

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Debt And Related Expenses (Schedule Of Debt Assumed Upon Acquisition Of Business) (Details) (USD $)		12 Months Ended
	Jun. 29, 2010	Dec. 31, 2011 8.25% Due July 1, 2018 [Member]	Dec. 31, 2011 7.50% Due September 15, 2027 [Member]
Debt Instrument [Line Items]
Principal amount of debt		$ 125,000,000	$ 150,000,000
Debt, maturity date		Jul. 01, 2018	Sep. 15, 2027
Debt interest rate, stated percentage		8.25%	7.50%
Fair Value of Debt Assumed		$ 147,000,000	$ 169,000,000
Effective Rate of Debt Assumed	3.125%	5.50%	6.50%

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Derivative Financial Instruments (Schedule Of Open Interest Rate Swap Derivative Positions) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011
Derivative [Line Items]
Notional	$ 850
Average Fixed Rate Received	3.65%
August 2012 [Member]
Derivative [Line Items]
Notional	100
Variable Rate Paid	Federal funds rate
Fixed Rate Received	1.90%
Expiration	August 2012
July 2013 [Member]
Derivative [Line Items]
Notional	$ 750
Variable Rate Paid	Federal funds rate
Fixed Rate Received	3.88%
Expiration	July 2013

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Discontinued Operations (Schedule Of Gain (Loss) From Discontinued Operations) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gross	$ 2,552	$ 1,818	$ 17
After Tax	2,552	1,732	17
Brazil [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gross	2,548
After Tax	2,548
Azerbaijan [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gross		1,543
After Tax		1,524
China Panyu [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gross		308
After Tax		235
Other Segment [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gross	4	(33)	17
After Tax	$ 4	$ (27)	$ 17

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Income Taxes (Schedule Of Changes In Unrecognized Tax Benefits) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Income Taxes [Abstract]
Balance at beginning of year	$ 194	$ 272
Tax positions taken in prior periods	(3)	40
Tax positions taken in current year	27	5
Accrual of interest related to tax positions taken	(7)	9
Lapse of statute of limitations	(41)	(5)
Settlements	(5)	(129)
Foreign currency translation		2
Balance at end of year	$ 165	$ 194

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Debt And Related Expenses (Narrative) (Details)	1 Months Ended									1 Months Ended	12 Months Ended
	Jul. 31, 2011 USD ($)	Jun. 30, 2009 USD ($)	Jun. 30, 2009 CAD	Dec. 31, 2011 USD ($)	Jun. 29, 2010	Dec. 31, 2011 Current Borrowing Capacity [Member] USD ($)	Dec. 31, 2011 Minimum [Member]	Dec. 31, 2011 Maximum [Member]	Dec. 31, 2011 Maximum [Member] Commercial Paper General Maturity Maximum [Member]	Jan. 31, 2009 Senior Notes Due January 15, 2014 [Member] USD ($)	Dec. 31, 2011 Line Of Credit Facility [Member] USD ($)	Dec. 31, 2011 Senior Credit Facility Due April 7,2012 [Member] USD ($)	Dec. 31, 2011 Senior Credit Facility Due April 7,2013[Member] USD ($)	Dec. 31, 2011 Canadian Subfacility [Member] USD ($)
Debt Instrument [Line Items]
Senior credit facility, borrowing capacity											$ 2,650,000,000	$ 460,000,000	$ 2,190,000,000	$ 500,000,000
Senior credit facility, expiration date												April 7, 2012	April 7, 2013
Annual facility fee											1,900,000
Outstanding senior credit facility borrowings				0
Ratio of total funded debt to total capitalization to be less than				65.00%
Debt-to-capitalization ratio, current percentage				22.8
Commercial paper program, borrowing capacity						5,000,000,000
Commercial paper maturity (days)							1	365	90
Average borrowing rate on commercial paper borrowings				0.45%
Issuance of non interest bearing promissory note			155,000,000
Present value of promissory note		139,000,000
Debt instrument, interest rate, effective percentage					3.125%
Non-interest bearing promissory note carrying value				85,000,000
Commercial Paper				3,726,000,000
Senior notes	$ 2,250,000,000									$ 1,200,000

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Short-Term Investments Components Of Short-Term Investments (Components Of Short-Term Investments) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011 days	Dec. 31, 2010
Schedule of Investments [Line Items]
Average remaining maturity on short-term investments	75
Average yield on short-term investments	0.28%
Short-term investments	$ 1,503	$ 145
Other [Member]
Schedule of Investments [Line Items]
Short-term investments	289
Commercial Paper [Member]
Schedule of Investments [Line Items]
Short-term investments	1,013
U.S. Treasuries [Member]
Schedule of Investments [Line Items]
Short-term investments	$ 201	$ 145

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Debt And Related Expenses (Schedule Of Debt Instruments) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Debt Instrument [Line Items]
Commercial paper	$ 3,726
Net discount on other debentures and notes	(6)	2
Total debt	9,780	5,630
Less amount classified as short-term debt	3,811	1,811
Long-term debt	5,969	3,819
6.875% Retired On September 30, 2011 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage	6.875%
Debt, maturity date	Sep. 30, 2011
Long term debt, gross		1,750
5.625% Due January 15, 2014 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage	5.625%
Debt, maturity date	Jan. 15, 2014
Long term debt, gross	500	500
Non-Interest Bearing Promissory Note [Member]
Debt Instrument [Line Items]
Debt, maturity date	Jun. 29, 2014
Long term debt, gross	85	144
2.40% Due July 15, 2016 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage	2.40%
Debt, maturity date	Jul. 15, 2016
Long term debt, gross	500
8.25% Due July 1, 2018 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage	8.25%
Debt, maturity date	Jul. 01, 2018
Long term debt, gross	125	125
6.30% Due January 15, 2019 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage	6.30%
Debt, maturity date	Jan. 15, 2019
Long term debt, gross	700	700
4.00% Due July 15, 2021 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage	4.00%
Debt, maturity date	Jul. 15, 2021
Long term debt, gross	500
7.50% Due September 15, 2027 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage	7.50%
Debt, maturity date	Sep. 15, 2027
Long term debt, gross	150	150
7.875% Due September 30, 2031[Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage	7.875%
Debt, maturity date	Sep. 30, 2031
Long term debt, gross	1,250	1,250
7.95% Due April 15, 2032 [Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage	7.95%
Debt, maturity date	Apr. 15, 2032
Long term debt, gross	1,000	1,000
5.60% Due July 15, 2041[Member]
Debt Instrument [Line Items]
Debt interest rate, stated percentage	5.60%
Debt, maturity date	Jul. 15, 2041
Long term debt, gross	1,250
Other Debt [Member]
Debt Instrument [Line Items]
Long term debt, gross		$ 9

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Income Taxes (Summary Of The Tax Years By Jurisdiction That Remain Subject To Examination By Taxing Authorities) (Details)	12 Months Ended
	Dec. 31, 2011
U. S. Federal [Member]
Open Tax Years by Major Tax Jurisdiction	2008-2011
Various U.S. States [Member]
Open Tax Years by Major Tax Jurisdiction	2007-2011
Canada Federal [Member]
Open Tax Years by Major Tax Jurisdiction	2003-2011
Various Canadian Provinces [Member]
Open Tax Years by Major Tax Jurisdiction	2003-2011

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Other, Net (Components Of Other, Net) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Accretion of asset retirement obligations	$ 92	$ 92	$ 91
Interest rate swaps - unrealized fair value changes	401	(107)	(55)
Interest rate swaps - cash settlements	(485)	(932)	(545)
Interest income	(21)	(13)	(8)
Other	(92)	(32)	(60)
Total	(10)	33	(83)
Interest Rate Derivatives [Member]
Interest rate swaps - unrealized fair value changes	88	30	(66)
Interest rate swaps - cash settlements	$ (77)	$ (44)	$ (40)

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Fair Value Measurements

12 Months Ended

Dec. 31, 2011

Fair Value Measurements [Abstract]

Fair Value Measurements

19.  Fair Value Measurements  

The following tables provide carrying value and fair value measurement information for Devon's financial assets and liabilities. The carrying values of cash, accounts receivable, other current receivables, accounts payable, other payables and accrued expenses included in the accompanying balance sheets approximated fair value at December 31, 2011 and December 31, 2010.These assets and liabilities are not presented in the following table. Additionally, information regarding the fair values of Devon's pension plan assets is provided in Note 16.

			Fair Value Measurements Using:
	Carrying Amount	Total Fair Value	Level 1 Inputs	Level 2 Inputs	Level 3 Inputs
	(In millions)
December 31, 2011 assets (liabilities):
Cash equivalents	$5,123	$5,123	$1,369	$3,754	$—
Short-term investments	$1,503	$1,503	$490	$1,013	$—
Long-term investments	$84	$84	$—	$—	$84
Commodity derivatives	$628	$628	$—	$628	$—
Commodity derivatives	$(82)	$(82)	$—	$(82)	$—
Interest rate derivatives	$52	$52	$—	$52	$—
Debt	$(9,780)	$(11,380)	$—	$(11,295)	$(85)

			Fair Value Measurements Using:
	Carrying Amount	Total Fair Value	Level 1 Inputs	Level 2 Inputs	Level 3 Inputs
	(In millions)
December 31, 2010 assets (liabilities):
Cash equivalents	$2,335	$2,335	$2,335	$—	$—
Short-term investments	$145	$145	$145	$—	$—
Long-term investments	$94	$94	$—	$—	$94
Commodity derivatives	$249	$249	$—	$249	$—
Commodity derivatives	$(192)	$(192)	$—	$(192)	$—
Interest rate derivatives	$140	$140	$—	$140	$—
Debt	$(5,630)	$(6,629)	$—	$(6,485)	$(144)

The following methods and assumptions were used to estimate the fair values in the tables above.

Level 1 Fair Value Measurements

Cash equivalents and short-term investments — Amounts consist primarily of U.S. and Canadian Treasury bills and money market investments. The fair value approximates the carrying value.

Level 2 Fair Value Measurements

Cash equivalents and short-term investments— Amounts consist primarily of commercial paper investments. The fair value is based upon quotes from brokers, which generally approximate the carrying value.

Commodity and interest rate derivatives — The fair values of commodity and interest rate derivatives are estimated using internal discounted cash flow calculations based upon forward curves and quotes obtained from brokers for contracts with similar terms or quotes obtained from counterparties to the agreements.

Debt — Devon's debt instruments do not actively trade in an established market. The fair values of its fixed-rate debt are estimated based on at rates available for debt with similar terms and maturity. The fair value of Devon's variable-rate commercial paper borrowings is the carrying value.

Level 3 Fair Value Measurements

Debt — Devon's Level 3 debt consisted of a non-interest bearing promissory note. Due to the lack of an active market, quoted marked prices for this note were not available. Therefore, Devon used valuation techniques that rely on unobservable inputs to estimate the fair value of its promissory note. The fair value of this debt is estimated using internal discounted cash flow calculations based upon estimated future payment schedules and a 3.125% interest rate. As a result of using these inputs, Devon concluded the estimated fair value of its non-interest bearing promissory note approximated the carrying value as of December 31, 2011 and December 31, 2010.

Long-term investments — Devon's long-term investments presented in the tables above consisted entirely of auction rate securities. Due to auction failures and the lack of an active market for Devon's auction rate securities, quoted market prices for these securities were not available. Therefore, Devon used valuation techniques that rely on unobservable inputs to estimate the fair values of its long-term auction rate securities. These inputs were based on the AAA credit rating of the securities, the probability of full repayment of the securities considering the U.S. government guarantees substantially all of the underlying student loans, the collection of all accrued interest to date and continued receipts of principal at par. As a result of using these inputs, Devon concluded the estimated fair values of its long-term auction rate securities approximated the par values as of December 31, 2011 and December 31, 2010.

Included below is a summary of the changes in Devon's Level 3 fair value measurements.

	Year Ended December 31,
	2011	2010
	(In millions)
Long-term investments balance at beginning of period	$94	$115
Redemptions of principal	(10)	(21)
Long-term investments balance at end of period	$84	$94
Debt balance at beginning of period	$(144)	$—
Issuance of promissory note	—	(139)
Foreign exchange translation adjustment	1	(9)
Accretion of promissory note	(5)	(3)
Redemptions of principal	63	7
Debt balance at end of period	$(85)	$(144)

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Discontinued Operations (Tables)

12 Months Ended

Dec. 31, 2011

Schedule Of Gains On Divestiture Transactions By Year [Member]

Schedule Of Gains On Divestiture Transactions By Year

	Year Ended December 31,
	2011		2010		2009
	Gross	After Tax	Gross	After Tax	Gross	After Tax
	(In millions)
Brazil	$ 2,548	$ 2,548	$       —	$       —	$       —	$       —
Azerbaijan	—	—	1,543	1,524	—	—
China - Panyu	—	—	308	235	—	—
Other	4	4	(33)	(27)	17	17
Total	$ 2,552	$ 2,552	$ 1,818	$ 1,732	$      17	$      17

Main Classes Of Assets And Liabilities [Member]

Schedule Of Discontinued Operations Disclosures

	December 31,
	2011	2010
	(In millions)
Cash and cash equivalents	$        —	$      424
Other current assets	21	139
Current assets	$        21	$      563
Property and equipment, net	$      132	$      859
Accounts payable	$        20	$      260
Other current liabilities	28	45
Current liabilities	$        48	$      305
Other long-term liabilities	$         —	$        26

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Other Current Assets (Tables)

12 Months Ended

Dec. 31, 2011

Other Current Assets [Abstract]

Schedule Of Components Of Other Current Assets

	December 31,
	2011	2010
	(In millions)
Derivative financial instruments	$        641	$        348
Inventories	102	120
Income tax receivable	35	270
Other	69	41
Other current assets	$        847	$        779

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Income Taxes (Schedule Of Deferred Tax Assets And Liabilities) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Income Taxes [Abstract]
Net operating loss carryforwards	$ 222	$ 159
Asset retirement obligations	447	494
Pension benefit obligations	130	133
Other	117	171
Total deferred tax assets	916	957
Property and equipment	(4,475)	(3,130)
Fair value of financial instruments	(218)	(70)
Long-term debt	(185)	(198)
Taxes on unremitted foreign earnings	(936)	(211)
Other	(27)	(20)
Total deferred tax liabilities	(5,841)	(3,629)
Net deferred tax liability	$ (4,925)	$ (2,672)

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Retirement Plans (Schedule Of Weighted Average Actuarial Assumptions Used To Determine Benefit Obligations And Net Periodic Benefit Costs) (Details)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Assumptions to determine benefit obligations - Discount rate	4.65%	5.50%	6.00%
Assumptions to determine benefit obligations - Rate of compensation increase	4.97%	6.94%	6.95%
Assumptions to determine net periodic benefit cost - Discount rate	5.50%	6.00%	6.00%
Assumptions to determine net periodic benefit cost - Expected return on plan assets	6.48%	6.94%	7.18%
Assumptions to determine net periodic benefit cost - Rate of compensation increase	6.94%	6.95%	6.95%
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Assumptions to determine benefit obligations - Discount rate	4.25%	4.90%	5.70%
Assumptions to determine benefit obligations - Rate of compensation increase
Assumptions to determine net periodic benefit cost - Discount rate	4.90%	5.70%	6.00%
Assumptions to determine net periodic benefit cost - Expected return on plan assets
Assumptions to determine net periodic benefit cost - Rate of compensation increase

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Earnings (Loss) Per Share (Tables)

12 Months Ended

Dec. 31, 2011

Earnings (Loss) Per Share [Abstract]

Earnings Per Share Computations

	Earnings	Common Shares	Earnings (Loss) per Share
	(In millions, except per share amounts)
Year Ended December 31, 2011:
Earnings from continuing operations	$        2,134	417
Attributable to participating securities	(23)	(5)
Basic earnings per share	2,111	412	$     5.12
Dilutive effect of potential common shares issuable	—	2
Diluted earnings per share	$        2,111	414	$     5.10
Year Ended December 31, 2010:
Earnings from continuing operations	$        2,333	440
Attributable to participating securities	(26)	(5)
Basic earnings per share	2,307	435	$     5.31
Dilutive effect of potential common shares issuable	—	1
Diluted earnings per share	$        2,307	436	$     5.29
Year Ended December 31, 2009:
Loss from continuing operations	$       (2,753)	444
Attributable to participating securities	31	(5)
Basic and diluted loss per share	$       (2,722)	439	$       (6.20)

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Supplemental Information On Oil And Gas Operations (Tables)

12 Months Ended

Dec. 31, 2011

Supplemental Information On Oil And Gas Operations [Abstract]

Costs Incurred

	Year Ended December 31, 2011
	U.S. Onshore	U.S. Offshore	Total U.S.	Canada	North America
	(In millions)
Property acquisition costs:
Proved properties	$         34	$          —	$         34	$         14	$         48
Unproved properties	851	—	851	88	939
Exploration costs	272	—	272	266	538
Development costs	4,130	—	4,130	1,288	5,418
Costs incurred	$    5,287	$         —	$    5,287	$    1,656	$    6,943

	Year Ended December 31, 2010
	U.S. Onshore	U.S. Offshore	Total U.S.	Canada	North America
	(In millions)
Property acquisition costs:
Proved properties	$         29	$          —	$         29	$            4	$         33
Unproved properties	592	2	594	590	1,184
Exploration costs	339	89	428	260	688
Development costs	3,126	297	3,423	1,216	4,639
Costs incurred	$    4,086	$       388	$    4,474	$    2,070	$    6,544

	Year Ended December 31, 2009
	U.S. Onshore	U.S. Offshore	Total U.S.	Canada	North America
	(In millions)
Property acquisition costs:
Proved properties	$         17	$          —	$         17	$         18	$         35
Unproved properties	52	11	63	72	135
Exploration costs	122	260	382	152	534
Development costs	2,011	537	2,548	835	3,383
Costs incurred	$    2,202	$       808	$    3,010	$    1,077	$    4,087

Capitalized Costs

	December 31, 2011
	U.S	Canada	North America
	(In millions)
Proved properties	$   41,397	$   20,299	$   61,696
Unproved properties	2,347	1,635	3,982
Total oil & gas properties	43,744	21,934	65,678
Accumulated DD&A	(29,742)	(14,585)	(44,327)
Net capitalized costs	$   14,002	$     7,349	$   21,351

	December 31, 2010
	U.S	Canada	North America
	(In millions)
Proved properties	$   36,301	$   19,711	$   56,012
Unproved properties	2,156	1,278	3,434
Total oil & gas properties	38,457	20,989	59,446
Accumulated DD&A	(28,546)	(14,130)	(42,676)
Net capitalized costs	$     9,911	$     6,859	$   16,770

Oil And Gas Properties Not Subject To Amortization

	Costs Incurred In
	2011	2010	2009	Prior to 2009	Total
	(In millions)
Acquisition costs	$       894	$    1,101	$       112	$    1,037	$    3,144
Exploration costs	234	81	6	11	332
Development costs	359	72	1	9	441
Capitalized interest	43	22	—	—	65
Total oil and gas properties not subject to amortization	$    1,530	$    1,276	$       119	$    1,057	$    3,982

Results Of Operations

	Year Ended December 31, 2011
	United States	Canada	North America
	(In millions)
Oil, gas and NGL sales	$     5,418	$     2,897	$     8,315
Lease operating expenses	(925)	(926)	(1,851)
Depreciation, depletion and amortization	(1,201)	(786)	(1,987)
General and administrative expenses	(132)	(119)	(251)
Taxes other than income taxes	(357)	(45)	(402)
Accretion of asset retirement obligations	(34)	(57)	(91)
Income tax expense	(1,005)	(250)	(1,255)
Results of operations	$     1,764	$         714	$     2,478
Depreciation, depletion and amortization per Boe	$        6.94	$     11.74	$        8.28

	Year Ended December 31, 2010
	United States	Canada	North America
	(In millions)
Oil, gas and NGL sales	$     4,742	$     2,520	$     7,262
Lease operating expenses	(892)	(797)	(1,689)
Depreciation, depletion and amortization	(998)	(677)	(1,675)
General and administrative expenses	(133)	(83)	(216)
Taxes other than income taxes	(319)	(40)	(359)
Accretion of asset retirement obligations	(42)	(50)	(92)
Income tax expense	(849)	(246)	(1,095)
Results of operations	$     1,509	$         627	$     2,136
Depreciation, depletion and amortization per Boe	$        6.11	$     10.51	$        7.36

	Year Ended December 31, 2009
	United States	Canada	North America
	(In millions)
Oil, gas and NGL sales	$     3,958	$     2,139	$     6,097
Lease operating expenses	(997)	(673)	(1,670)
Depreciation, depletion and amortization	(1,247)	(585)	(1,832)
General and administrative expenses	(145)	(74)	(219)
Taxes other than income taxes	(258)	(35)	(293)
Reduction of carrying value of oil and gas properties	(6,408)	—	(6,408)
Accretion of asset retirement obligations	(53)	(38)	(91)
Income tax benefit	1,800	(210)	1,580
Results of operations	$    (3,350)	$         524	$    (2,836)
Depreciation, depletion and amortization per Boe	$        7.47	$        8.84	$        7.86

Proved Reserves

	Oil (MMBbls)
	U.S. Onshore	U.S. Offshore	Total U.S.	Canada	North America
Proved developed and undeveloped reserves:
December 31, 2008	133	34	167	134	301
Revisions due to prices	9	2	11	291	302
Revisions other than price	—	1	1	(8)	(7)
Extensions and discoveries	9	2	11	122	133
Production	(12)	(5)	(17)	(25)	(42)
Sale of reserves	—	(1)	(1)	—	(1)
December 31, 2009	139	33	172	514	686
Revisions due to prices	4	1	5	(24)	(19)
Revisions other than price	2	2	4	9	13
Extensions and discoveries	19	1	20	59	79
Production	(14)	(2)	(16)	(25)	(41)
Sale of reserves	(2)	(35)	(37)	—	(37)
December 31, 2010	148	—	148	533	681
Revisions due to prices	2	—	2	(15)	(13)
Revisions other than price	(1)	—	(1)	11	10
Extensions and discoveries	36	—	36	36	72
Production	(17)	—	(17)	(28)	(45)
December 31, 2011	168	—	168	537	705
Proved developed reserves as of:
December 31, 2008	111	22	133	110	243
December 31, 2009	119	21	140	149	289
December 31, 2010	131	—	131	126	257
December 31, 2011	146	—	146	163	309
Proved developed-producing reserves as of:
December 31, 2008	103	9	112	91	203
December 31, 2009	112	12	124	137	261
December 31, 2010	123		123	116	239
December 31, 2011	139	—	139	155	294
Proved undeveloped reserves as of:
December 31, 2008	22	12	34	24	58
December 31, 2009	20	12	32	365	397
December 31, 2010	17	—	17	407	424
December 31, 2011	22	—	22	374	396

	Gas (Bcf)
	U.S. Onshore	U.S. Offshore	Total U.S.	Canada	North America
Proved developed and undeveloped reserves:
December 31, 2008	7,979	390	8,369	1,510	9,879
Revisions due to prices	(661)	(4)	(665)	(29)	(694)
Revisions other than price	119	(62)	57	(14)	43
Extensions and discoveries	1,387	64	1,451	67	1,518
Purchase of reserves	1	—	1	6	7
Production	(698)	(45)	(743)	(223)	(966)
Sale of reserves	—	(1)	(1)	(29)	(30)
December 31, 2009	8,127	342	8,469	1,288	9,757
Revisions due to prices	449	2	451	21	472
Revisions other than price	105	(26)	79	(17)	62
Extensions and discoveries	1,088	7	1,095	131	1,226
Purchase of reserves	12	—	12	9	21
Production	(699)	(17)	(716)	(214)	(930)
Sale of reserves	(17)	(308)	(325)	—	(325)
December 31, 2010	9,065	—	9,065	1,218	10,283
Revisions due to prices	(1)	—	(1)	(60)	(61)
Revisions other than price	(243)	—	(243)	(38)	(281)
Extensions and discoveries	1,410	—	1,410	58	1,468
Purchase of reserves	16	—	16	20	36
Production	(740)	—	(740)	(213)	(953)
Sale of reserves	—	—	—	(6)	(6)
December 31, 2011	9,507	—	9,507	979	10,486
Proved developed reserves as of:
December 31, 2008	6,469	212	6,681	1,357	8,038
December 31, 2009	6,447	185	6,632	1,213	7,845
December 31, 2010	7,280	—	7,280	1,144	8,424
December 31, 2011	7,957	—	7,957	951	8,908
Proved developed-producing reserves as of:
December 31, 2008	5,787	64	5,851	1,194	7,045
December 31, 2009	5,860	137	5,997	1,075	7,072
December 31, 2010	6,702	—	6,702	1,031	7,733
December 31, 2011	7,409	—	7,409	862	8,271
Proved undeveloped reserves as of:
December 31, 2008	1,510	178	1,688	153	1,841
December 31, 2009	1,680	157	1,837	75	1,912
December 31, 2010	1,785	—	1,785	74	1,859
December 31, 2011	1,550	—	1,550	28	1,578

	Natural Gas Liquids (MMBbls)
	U.S. Onshore	U.S. Offshore	Total U.S.	Canada	North America
Proved developed and undeveloped reserves:
December 31, 2008	315	2	317	35	352
Revisions due to prices	(11)	—	(11)	2	(9)
Revisions other than price	36	1	37	—	37
Extensions and discoveries	70	—	70	1	71
Production	(25)	(1)	(26)	(4)	(30)
December 31, 2009	385	2	387	34	421
Revisions due to prices	14	—	14	(1)	13
Revisions other than price	13	3	16	(1)	15
Extensions and discoveries	68	—	68	2	70
Production	(28)	—	(28)	(4)	(32)
Sale of reserves	(3)	(5)	(8)	—	(8)
December 31, 2010	449	—	449	30	479
Revisions due to prices	4	—	4	(1)	3
Revisions other than price	1	—	1	—	1
Extensions and discoveries	102	—	102	2	104
Purchase of reserves	2	—	2	—	2
Production	(33)	—	(33)	(4)	(37)
December 31, 2011	525	—	525	27	552
Proved developed reserves as of:
December 31, 2008	260	1	261	31	292
December 31, 2009	293	1	294	32	326
December 31, 2010	353	—	353	28	381
December 31, 2011	402	—	402	26	428
Proved developed-producing reserves as of:
December 31, 2008	230	—	230	29	259
December 31, 2009	265	1	266	28	294
December 31, 2010	318	—	318	26	344
December 31, 2011	372	—	372	24	396
Proved undeveloped reserves as of:
December 31, 2008	55	1	56	4	60
December 31, 2009	92	1	93	2	95
December 31, 2010	96	—	96	2	98
December 31, 2011	123	—	123	1	124

	Total (MMBoe) (1)
	U.S. Onshore	U.S. Offshore	Total U.S.	Canada	North America
Proved developed and undeveloped reserves:
December 31, 2008	1,777	101	1,878	421	2,299
Revisions due to prices	(113)	1	(112)	289	177
Revisions other than price	57	(8)	49	(11)	38
Extensions and discoveries	311	12	323	135	458
Purchase of reserves	—	—	—	1	1
Production	(154)	(13)	(167)	(66)	(233)
Sale of reserves	—	(1)	(1)	(6)	(7)
December 31, 2009	1,878	92	1,970	763	2,733
Revisions due to prices	92	1	93	(21)	72
Revisions other than price	32	1	33	5	38
Extensions and discoveries	269	2	271	83	354
Purchase of reserves	2	—	2	2	4
Production	(158)	(5)	(163)	(65)	(228)
Sale of reserves	(8)	(91)	(99)	(1)	(100)
December 31, 2010	2,107	—	2,107	766	2,873
Revisions due to prices	6	—	6	(27)	(21)
Revisions other than price	(41)	—	(41)	6	(35)
Extensions and discoveries	374	—	374	47	421
Purchase of reserves	5	—	5	3	8
Production	(173)	—	(173)	(67)	(240)
Sale of reserves	—	—	—	(1)	(1)
December 31, 2011	2,278	—	2,278	727	3,005
Proved developed reserves as of:
December 31, 2008	1,449	59	1,508	367	1,875
December 31, 2009	1,486	53	1,539	383	1,922
December 31, 2010	1,696	—	1,696	346	2,042
December 31, 2011	1,875	—	1,875	348	2,223
Proved developed-producing reserves as of:
December 31, 2008	1,298	20	1,318	319	1,637
December 31, 2009	1,354	35	1,389	344	1,733
December 31, 2010	1,557	—	1,557	314	1,871
December 31, 2011	1,746	—	1,746	323	2,069
Proved undeveloped reserves as of:
December 31, 2008	328	42	370	54	424
December 31, 2009	392	39	431	380	811
December 31, 2010	411	—	411	420	831
December 31, 2011	403	—	403	379	782

____________________________

(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 gas and oil. This rate is not necessarily indicative of the relationship of natural gas and oil prices. Natural gas liquids reserves are converted to Boe on a one-to-one basis with oil.

Proved Undeveloped Reserves

	U.S. Onshore	Canada	North America
Proved undeveloped reserves as of December 31, 2010	411	420	831
Extensions and discoveries	118	30	148
Revisions due to prices	(2)	(14)	(16)
Revisions other than price	(56)	5	(51)
Conversion to proved developed reserves	(68)	(62)	(130)
Proved undeveloped reserves as of December 31, 2011	403	379	782

Standardized Measure Of Discounted Future Net Cash Flows Related To Interest In Proved Reserves

	Year Ended December 31, 2011
	U.S	Canada	North America
	(In millions)
Future cash inflows	$   69,305	$   36,786	$ 106,091
Future costs:
Development	(6,817)	(4,678)	(11,495)
Production	(26,217)	(15,063)	(41,280)
Future income tax expense	(11,432)	(3,763)	(15,195)
Future net cash flows	24,839	13,282	38,121
10% discount to reflect timing of cash flows	(13,492)	(6,785)	(20,277)
Standardized measure of discounted future net cash flows	$   11,347	$     6,497	$   17,844

	Year Ended December 31, 2010
	U.S	Canada	North America
	(In millions)
Future cash inflows	$   58,093	$   35,948	$   94,041
Future costs:
Development	(6,220)	(4,526)	(10,746)
Production	(24,223)	(12,249)	(36,472)
Future income tax expense	(8,643)	(4,209)	(12,852)
Future net cash flows	19,007	14,964	33,971
10% discount to reflect timing of cash flows	(10,164)	(7,455)	(17,619)
Standardized measure of discounted future net cash flows	$     8,843	$     7,509	$   16,352
	Year Ended December 31, 2009
	U.S	Canada	North America
	(In millions)
Future cash inflows	$   44,571	$   28,442	$   73,013
Future costs:
Development	(6,814)	(4,132)	(10,946)
Production	(22,184)	(9,847)	(32,031)
Future income tax expense	(3,572)	(3,408)	(6,980)
Future net cash flows	12,001	11,055	23,056
10% discount to reflect timing of cash flows	(6,121)	(5,532)	(11,653)
Standardized measure of discounted future net cash flows	$     5,880	$     5,523	$   11,403

Schedule Of Principal Changes In The Standardized Measure Of Discounted Future Net Cash Flows Attributable To Proved Reserves

	Year Ended December 31,
	2011	2010	2009
	(In millions)
Beginning balance	$   16,352	$   11,403	$     9,393
Oil, gas and NGL sales, net of production costs	(5,794)	(4,982)	(3,915)
Net changes in prices and production costs	1,875	7,423	(1,672)
Extensions and discoveries, net of future development costs	3,714	3,048	2,378
Purchase of reserves, net of future development costs	57	23	6
Development costs incurred that reduced future development costs..	1,302	1,559	1,012
Revisions of quantity estimates	(668)	287	4,051
Sales of reserves in place	(2)	(815)	(37)
Accretion of discount	2,248	1,487	1,281
Net change in income taxes	(929)	(2,663)	(51)
Other, primarily changes in timing and foreign exchange rates	(311)	(418)	(1,043)
Ending balance	$   17,844	$   16,352	$   11,403

Estimated Pretax Cash Flow Information Related To Proved Reserves

	Year Ended December 31, 2011
	U.S	Canada	North America
Pre-Tax Future Net Revenue (1)	(In millions)
Proved Developed Reserves	$   30,473	$     7,757	$   38,230
Proved Undeveloped Reserves	5,798	9,288	15,086
Total Proved Reserves	$   36,271	$   17,045	$   53,316

Pre-Tax 10% Present Value (1)
Proved Developed Reserves	$   15,165	$     5,830	$   20,995
Proved Undeveloped Reserves	1,404	2,508	3,912
Total Proved Reserves	$   16,569	$     8,338	$   24,907

____________________________

(1)   Estimated pre-tax 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 depreciation, depletion and amortization, or to non-property related expenses such as debt service and income tax expense.

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Restructuring Costs (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Restructuring Cost and Reserve [Line Items]
Restructuring charges	$ (2)	$ 57	$ 105
Asset impairment charges		11
Restructuring liabilities	45	82	61
Restructuring and Related Cost, Cost Incurred to Date	202
Discontinued Operations [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring charges	(2)	(4)	48
Restructuring liabilities		16	23
Lease Obligations [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring charges	$ (13)	$ 70

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Segment Information (Condensed Statements Of Comprehensive Earnings And Balance Sheets Of Reportable Segments) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended									12 Months Ended
	Dec. 31, 2011		Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011		Dec. 31, 2010	Dec. 31, 2009
Segment Reporting Information [Line Items]
Oil, gas and NGL sales										$ 8,315		$ 7,262	$ 6,097
Oil, gas and NGL derivatives										881		811	384
Marketing and midstream revenues										2,258		1,867	1,534
Interest expense										352		363	349
Depreciation, depletion and amortization										2,248		1,930	2,108
Earnings (loss) from continuing operations before income taxes	794		1,538	1,378	580	668	699	613	1,588	4,290		3,568	(4,526)
Income tax (benefit) expense										2,156		1,235	(1,773)
Earnings (loss) from continuing operations	521		1,040	184	389	478	429	352	1,074	2,134		2,333	(2,753)
Property and equipment, net	24,774					19,652				24,774		19,652
Total continuing assets	40,964	[1]				31,505				40,964	[1]	31,505
Reduction of carrying value of oil and gas properties													6,408
Capital expenditures										7,820		7,114	4,683
Assets held for sale	153					1,400				153		1,400	1,900
U.S. [Member]
Segment Reporting Information [Line Items]
Oil, gas and NGL sales										5,418		4,742	3,958
Oil, gas and NGL derivatives										881		809	382
Marketing and midstream revenues										2,059		1,742	1,498
Interest expense										204		159	125
Depreciation, depletion and amortization										1,439		1,229	1,498
Earnings (loss) from continuing operations before income taxes										3,477		2,943	(4,961)
Income tax (benefit) expense										1,958		1,062	(1,894)
Earnings (loss) from continuing operations										1,519		1,881	(3,067)
Property and equipment, net	16,989					12,379				16,989		12,379
Total continuing assets	22,622	[1]				18,320				22,622	[1]	18,320
Reduction of carrying value of oil and gas properties													6,408
Capital expenditures										6,112		5,007	3,584
Canada [Member]
Segment Reporting Information [Line Items]
Oil, gas and NGL sales										2,897		2,520	2,139
Oil, gas and NGL derivatives												2	2
Marketing and midstream revenues										199		125	36
Interest expense										148		204	224
Depreciation, depletion and amortization										809		701	610
Earnings (loss) from continuing operations before income taxes										813		625	435
Income tax (benefit) expense										198		173	121
Earnings (loss) from continuing operations										615		452	314
Property and equipment, net	7,785					7,273				7,785		7,273
Total continuing assets	18,342	[1]				13,185				18,342	[1]	13,185
Capital expenditures										$ 1,708		$ 2,107	$ 1,099

[1] Total assets in the table above do not include assets held for sale related to Devon's discontinued operations, which totaled $153 million, $1.4 billion, and $1.9 billion in 2011, 2010 and 2009, respectively.

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Share-Based Compensation (Schedule Of The Effects Of Share Based Compensation Included Included In The Consolidated Comprehensive Statement Of Earnings) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Share-Based Compensation [Abstract]
Gross general and administrative expense	$ 181	$ 188	$ 209
Share-based compensation expense capitalized pursuant to the full cost method of accounting for oil and gas properties	56	58	66
Related income tax benefit	$ 33	$ 40	$ 43

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Stockholders' Equity (Tables)

12 Months Ended

Dec. 31, 2011

Stockholders' Equity [Abstract]

Schedule Of Stock Repurchases

	2011			2010
	Amount	Shares	Per Share	Amount	Shares	Per Share
Repurchases	$   2,299	30.9	$   74.49	$   1,201	18.3	$   65.58

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Share-Based Compensation

12 Months Ended

Dec. 31, 2011

Share-Based Compensation [Abstract]

Share-Based Compensation

3. Share-Based Compensation

On June 3, 2009, Devon's stockholders adopted the 2009 Long-Term Incentive Plan, which expires on June 2, 2019. This plan authorizes the Compensation Committee, which consists of independent non-management members of Devon's Board of Directors, to grant nonqualified and incentive stock options, restricted stock awards, performance restricted stock awards, Canadian restricted stock units, performance share units, stock appreciation rights and cash-out rights to eligible employees. The plan also authorizes the grant of nonqualified stock options, restricted stock awards, restricted stock units and stock appreciation rights to directors. A total of 21.5 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 1.84 shares.

Devon also has stock option plans that were adopted in 2005, 2003 and 1997 under which stock options and restricted stock awards were issued to certain 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 its 2003 acquisition of Ocean Energy.  

The following table presents the effects of share-based compensation included in Devon's accompanying comprehensive statements of earnings. The vesting for certain share-based awards was accelerated as part of Devon's strategic repositioning. The associated expense for these accelerated awards is included in restructuring costs in the accompanying comprehensive statements of earnings. See Note 4 for further details.

	2011	2010	2009
	(In millions)
Gross general and administrative expense	$    181	$    188	$    209
Share-based compensation expense capitalized pursuant to the   full cost method of accounting for oil and gas properties	$      56	$      58	$      66
Related income tax benefit	$      33	$      40	$      43

Stock Options

In accordance with Devon's incentive plans, the exercise price of stock options granted may not be less than the market value of the stock at the date of grant. In addition, options granted are exercisable during a period established for each grant, which may not exceed eight years from the date of grant. The recipient must pay the exercise price in cash or in common stock, or a combination thereof, at the time that the option is exercised. Generally, the service requirement for vesting ranges from zero to four years.

The fair value of stock options on the date of grant is expensed over the applicable vesting period. Devon estimates the fair values of stock options granted using a Black-Scholes option valuation model, which requires Devon to make several assumptions. The volatility of Devon's common stock is based on the historical volatility of the market price of Devon's common stock over a period of time equal to the expected term of the option and ending on the grant date. The dividend yield is based on Devon's historical and current yield in effect at the date of grant. The risk-free interest rate is based on the zero-coupon U.S. Treasury yield for the expected term of the option at the date of grant. The expected term of the options is based on historical exercise and termination experience for various groups of employees and directors. Each group is determined based on the similarity of their historical exercise and termination behavior. The following table presents a summary of the grant-date fair values of stock options granted and the related assumptions. All such amounts represent the weighted-average amounts for each year.

	2011	2010	2009
Grant-date fair value	$23.11	$25.41	$22.85
Volatility factor	46.0%	45.3%	47.7%
Dividend yield	1.0%	1.0%	0.9%
Risk-free interest rate	0.8%	1.1%	2.1%
Expected term (in years)	4.2	4.5	4.0

The following table presents a summary of Devon's outstanding stock options.

		Weighted Average
	Options	Exercise Price	Remaining Term	Intrinsic Value
	(In thousands)		(In years)	(In millions)
Outstanding at December 31, 2010	11,434	$  62.64
Granted	1,962	$  66.98
Exercised	(2,366)	$  47.51
Forfeited	(487)	$  73.32
Outstanding at December 31, 2011	10,543	$  66.35	4.31	$   40
Vested and expected to vest at December 31, 2011..	10,428	$  66.33	4.27	$   40
Exercisable at December 31, 2011	6,716	$  65.39	2.90	$   39

The aggregate intrinsic value of stock options that were exercised during 2011, 2010 and 2009 was $81 million, $47 million and $51 million, respectively. As of December 31, 2011, Devon's unrecognized compensation cost related to unvested stock options was $70 million. Such cost is expected to be recognized over a weighted-average period of 3.0 years.

Restricted Stock Awards and Units

These awards and units are subject to the terms, conditions, restrictions and limitations, if any, that the Compensation Committee deems appropriate, including restrictions on continued employment. Generally, the service requirement for vesting ranges from zero to four years. During the vesting period, recipients of such awards receive dividends that are not subject to restrictions or other limitations. Devon estimates the fair values of restricted stock awards and units as the closing price of Devon's common stock on the grant date of the award or unit, which is expensed over the applicable vesting period. The following table presents a summary of Devon's unvested restricted stock awards and units.

	Restricted Stock Awards & Units	Weighted Average Grant-Date Fair Value
	(In thousands)
Unvested at December 31, 2010	5,311	$  70.60
Granted	2,301	$  65.40
Vested	(2,188)	$  72.05
Forfeited	(200)	$  71.18
Unvested at December 31, 2011	5,224	$  67.85

The aggregate fair value of restricted stock awards and units that vested during 2011, 2010 and 2009 was $145 million, $184 million and $165 million, respectively. As of December 31, 2011, Devon's unrecognized compensation cost related to unvested restricted stock awards and units was $305 million. Such cost is expected to be recognized over a weighted-average period of 2.8 years.

Performance Based Restricted Stock Awards

In December 2011, certain members of Devon's senior management were granted performance based share awards. Vesting of the awards is dependent on Devon meeting certain internal performance targets and the recipient meeting certain service requirements. Generally, the service requirement for vesting ranges from zero to four years. If Devon meets or exceeds the performance target, the awards vest after the recipient meets the related requisite service period. If the performance target and service period requirement are not met, the award does not vest. Once vested, recipients are entitled to dividends on the awards. Devon estimates the fair values of the awards as the closing price of Devon's common stock on the grant date of the award, which is expensed over the applicable vesting period. The following table presents a summary of Devon's performance based restricted stock awards.

	Performance Restricted Stock Awards	Weighted Average Grant-Date Fair Value
	(In thousands)
Unvested at December 31, 2010	—	$        —
Granted	184	$  65.10
Unvested at December 31, 2011	184	$  65.10

As of December 31, 2011, Devon's unrecognized compensation cost related to these awards was $4 million. Such cost is expected to be recognized over a weighted-average period of 2.4 years.

Performance Share Units  

In December 2011, certain members of Devon's senior management were granted performance share units. Each unit that vests entitles the recipient to one share of Devon common stock. The vesting of these units is based on comparing Devon's total shareholder return ("TSR") to the TSR of a predetermined group of fourteen peer companies over the specified two- or three-year performance period. The vesting of units may be between zero and 200 percent of the units granted depending on Devon's TSR as compared to the peer group on the vesting date.

During the vesting period, recipients will receive dividend equivalents with respect to each outstanding performance share unit. The fair value of each performance share unit is estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all grants made under the plan: (i) a risk-free interest rate; (ii) a volatility assumption based on the historical realized price volatility of Devon and the designated peer group; and (iii) an estimated ranking of Devon among the designated peer group. The fair value of the unit on the date of grant is expensed over the applicable vesting period.

The following table presents a summary of Devon's performance share units.

	Share Units	Weighted Average Grant-Date Fair Value
	(In thousands)
Unvested at December 31, 2010	—	$        —
Granted (1)	171	$  81.70
Unvested at December 31, 2011	171	$  81.70

____________________________

(1)A maximum of 341,000 common shares could be awarded based upon Devon's final TSR ranking.

As of December 31, 2011, Devon's unrecognized compensation cost related to unvested units was $8 million. Such cost is expected to be recognized over a weighted-average period of 2.3 years.

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Supplemental Information On Oil And Gas Operations (Results Of Operations) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil, gas and NGL sales	$ 8,315	$ 7,262	$ 6,097
Lease operating expenses	(1,851)	(1,689)	(1,670)
Depreciation, depletion and amortization	(2,248)	(1,930)	(2,108)
Reduction of carrying value of oil and gas properties			(6,408)
United States [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil, gas and NGL sales	5,418	4,742	3,958
Lease operating expenses	(925)	(892)	(997)
Depreciation, depletion and amortization	(1,201)	(998)	(1,247)
General and administrative expenses	(132)	(133)	(145)
Taxes other than income taxes	(357)	(319)	(258)
Accretion of asset retirement obligations	(34)	(42)	(53)
Income tax expense	(1,005)	(849)	1,800
Results of operations	1,764	1,509	(3,350)
Depreciation, depletion and amortization per Boe	6.94	6.11	7.47
Reduction of carrying value of oil and gas properties			(6,408)
Canada [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil, gas and NGL sales	2,897	2,520	2,139
Lease operating expenses	(926)	(797)	(673)
Depreciation, depletion and amortization	(786)	(677)	(585)
General and administrative expenses	(119)	(83)	(74)
Taxes other than income taxes	(45)	(40)	(35)
Accretion of asset retirement obligations	(57)	(50)	(38)
Income tax expense	(250)	(246)	(210)
Results of operations	714	627	524
Depreciation, depletion and amortization per Boe	11.74	10.51	8.84
North America [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Oil, gas and NGL sales	8,315	7,262	6,097
Lease operating expenses	(1,851)	(1,689)	(1,670)
Depreciation, depletion and amortization	(1,987)	(1,675)	(1,832)
General and administrative expenses	(251)	(216)	(219)
Taxes other than income taxes	(402)	(359)	(293)
Accretion of asset retirement obligations	(91)	(92)	(91)
Income tax expense	(1,255)	(1,095)	1,580
Results of operations	2,478	2,136	(2,836)
Depreciation, depletion and amortization per Boe	8.28	7.36	7.86
Reduction of carrying value of oil and gas properties			$ (6,408)

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Share-Based Compensation (Summary Of The Grant-Date Fair Values Of Stock Options Granted And Their Related Assumptions, Represented By The Weighted-Average Amounts) (Details) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Share-Based Compensation [Abstract]
Grant-date fair value	$ 23.11	$ 25.41	$ 22.85
Volatility factor	46.00%	45.30%	47.70%
Dividend yield	1.00%	1.00%	0.90%
Risk-free interest rate	0.80%	1.10%	2.10%
Expected term (in years)	4.2	4.5	4.0

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Property And Equipment (Tables)

12 Months Ended

Dec. 31, 2011

Property And Equipment [Abstract]

Schedule Of Proceeds From Offshore Divestitures

	Cash Proceeds	Year of Divestiture
	(In millions)
Brazil (discontinued operations)	$     3,251	2011
Gulf of Mexico (continuing operations)	4,059	2010
Azerbaijan (discontinued operations)	1,925	2010
China – Panyu and Exploration (discontinued operations)	592	2010
Other (discontinued operations)	175	2010
Total	$   10,002

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Supplemental Quarterly Financial Information

12 Months Ended

Dec. 31, 2011

Supplemental Quarterly Financial Information [Abstract]

Supplemental Quarterly Financial Information

23. Supplemental Quarterly Financial Information (Unaudited)

Following is a summary of Devon's unaudited interim results of operations.

	2011
	First Quarter	Second Quarter	Third Quarter	Fourth Quarter	Full Year
	(In millions, except per share amounts)
Revenues	$2,147	$3,220	$3,502	$2,585	$11,454
Earnings from continuing operations before income taxes	$580	$1,378	$1,538	$794	$4,290
Earnings from continuing operations	$389	$184	$1,040	$521	$2,134
Earnings (loss) from discontinued operations	27	2,559	(2)	(14)	2,570
Net earnings	$416	$2,743	$1,038	$507	$4,704
Basic net earnings per common share:
Earnings from continuing operations	$0.91	$0.44	$2.51	$1.29	$5.12
Earnings (loss) from discontinued operations	0.06	6.06	—	(0.04)	6.17
Net earnings	$0.97	$6.50	$2.51	$1.25	$11.29
Diluted net earnings per common share:
Earnings from continuing operations	$0.91	$0.43	$2.50	$1.29	$5.10
Earnings (loss) from discontinued operations	0.06	6.05	—	(0.04)	6.15
Net earnings	$0.97	$6.48	$2.50	$1.25	$11.25

	2010
	First Quarter	Second Quarter	Third Quarter	Fourth Quarter	Full Year
	(In millions, except per share amounts)
Revenues	$3,220	$2,232	$2,353	$2,135	$9,940
(Loss) earnings from continuing operations before income taxes	$1,588	$613	$699	$668	$3,568
(Loss) earnings from continuing operations	$1,074	$352	$429	$478	$2,333
(Loss) earnings from discontinued operations	118	354	1,661	84	2,217
Net (loss) earnings	$1,192	$706	$2,090	$562	$4,550
Basic net (loss) earnings per common share:
(Loss) earnings from continuing operations	$2.40	$0.79	$0.99	$1.10	$5.31
(Loss) earnings from discontinued operations..	0.27	0.80	3.82	0.20	5.04
Net (loss) earnings	$2.67	$1.59	$4.81	$1.30	$10.35
Diluted net (loss) earnings per common share:
(Loss) earnings from continuing operations	$2.39	$0.79	$0.98	$1.10	$5.29
(Loss) earnings from discontinued operations..	0.27	0.79	3.81	0.19	5.02
Net (loss) earnings	$2.66	$1.58	$4.79	$1.29	$10.31

Earnings (Loss) from Continuing Operations

The second quarter of 2011 includes deferred income taxes of $725 million (or $1.71 per diluted share) related to assumed repatriations of foreign earnings that were no longer deemed to be permanently reinvested in accordance with accounting principles generally accepted in the U.S.

Earnings (Loss) from Discontinued Operations

The second quarter of 2011 includes the divestiture of our Brazil operations and the related gain was $2.5 billion ($2.5 billion after income taxes, or $6.01 per diluted share).

The second quarter of 2010 includes the divestiture of our Panyu operations in China and the related gain was $308 million ($235 million after income taxes, or $0.52 per diluted share).

The third quarter of 2010 includes the divestiture of our Azerbaijan operations and the related gain was $1.5 billion ($1.5 billion after income taxes, or $3.49 per diluted share).

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Supplemental Information On Oil And Gas Operations

12 Months Ended

Dec. 31, 2011

Supplemental Information On Oil And Gas Operations [Abstract]

Supplemental Information On Oil And Gas Operations

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

Supplemental unaudited information regarding Devon's oil and gas activities is presented in this note. The information is provided separately by country and continent. Additionally, the costs incurred and reserves information for the U.S. is segregated between Devon's onshore and offshore operations. Unless otherwise noted, this supplemental information excludes amounts for all periods presented related to Devon's discontinued operations.

Costs Incurred

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

	Year Ended December 31, 2011
	U.S. Onshore	U.S. Offshore	Total U.S.	Canada	North America
	(In millions)
Property acquisition costs:
Proved properties	$         34	$          —	$         34	$         14	$         48
Unproved properties	851	—	851	88	939
Exploration costs	272	—	272	266	538
Development costs	4,130	—	4,130	1,288	5,418
Costs incurred	$    5,287	$         —	$    5,287	$    1,656	$    6,943

	Year Ended December 31, 2010
	U.S. Onshore	U.S. Offshore	Total U.S.	Canada	North America
	(In millions)
Property acquisition costs:
Proved properties	$         29	$          —	$         29	$            4	$         33
Unproved properties	592	2	594	590	1,184
Exploration costs	339	89	428	260	688
Development costs	3,126	297	3,423	1,216	4,639
Costs incurred	$    4,086	$       388	$    4,474	$    2,070	$    6,544

	Year Ended December 31, 2009
	U.S. Onshore	U.S. Offshore	Total U.S.	Canada	North America
	(In millions)
Property acquisition costs:
Proved properties	$         17	$          —	$         17	$         18	$         35
Unproved properties	52	11	63	72	135
Exploration costs	122	260	382	152	534
Development costs	2,011	537	2,548	835	3,383
Costs incurred	$    2,202	$       808	$    3,010	$    1,077	$    4,087

Pursuant to the full cost method of accounting, Devon capitalizes certain of its general and administrative expenses that are related to property acquisition, exploration and development activities. Such capitalized expenses, which are included in the costs shown in the preceding tables, were $337 million, $311 million and $332 million in the years 2011, 2010 and 2009, 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 $45 million, $37 million and $74 million in the years 2011, 2010 and 2009, respectively.

Capitalized Costs

The following tables reflect the aggregate capitalized costs related to oil and gas activities.

	December 31, 2011
	U.S	Canada	North America
	(In millions)
Proved properties	$   41,397	$   20,299	$   61,696
Unproved properties	2,347	1,635	3,982
Total oil & gas properties	43,744	21,934	65,678
Accumulated DD&A	(29,742)	(14,585)	(44,327)
Net capitalized costs	$   14,002	$     7,349	$   21,351

	December 31, 2010
	U.S	Canada	North America
	(In millions)
Proved properties	$   36,301	$   19,711	$   56,012
Unproved properties	2,156	1,278	3,434
Total oil & gas properties	38,457	20,989	59,446
Accumulated DD&A	(28,546)	(14,130)	(42,676)
Net capitalized costs	$     9,911	$     6,859	$   16,770

The following is a summary of Devon's oil and gas properties not subject to amortization as of December 31, 2011.

	Costs Incurred In
	2011	2010	2009	Prior to 2009	Total
	(In millions)
Acquisition costs	$       894	$    1,101	$       112	$    1,037	$    3,144
Exploration costs	234	81	6	11	332
Development costs	359	72	1	9	441
Capitalized interest	43	22	—	—	65
Total oil and gas properties not subject to amortization	$    1,530	$    1,276	$       119	$    1,057	$    3,982

Results of Operations

The following tables include revenues and expenses directly associated 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.    

	Year Ended December 31, 2011
	United States	Canada	North America
	(In millions)
Oil, gas and NGL sales	$     5,418	$     2,897	$     8,315
Lease operating expenses	(925)	(926)	(1,851)
Depreciation, depletion and amortization	(1,201)	(786)	(1,987)
General and administrative expenses	(132)	(119)	(251)
Taxes other than income taxes	(357)	(45)	(402)
Accretion of asset retirement obligations	(34)	(57)	(91)
Income tax expense	(1,005)	(250)	(1,255)
Results of operations	$     1,764	$         714	$     2,478
Depreciation, depletion and amortization per Boe	$        6.94	$     11.74	$        8.28

	Year Ended December 31, 2010
	United States	Canada	North America
	(In millions)
Oil, gas and NGL sales	$     4,742	$     2,520	$     7,262
Lease operating expenses	(892)	(797)	(1,689)
Depreciation, depletion and amortization	(998)	(677)	(1,675)
General and administrative expenses	(133)	(83)	(216)
Taxes other than income taxes	(319)	(40)	(359)
Accretion of asset retirement obligations	(42)	(50)	(92)
Income tax expense	(849)	(246)	(1,095)
Results of operations	$     1,509	$         627	$     2,136
Depreciation, depletion and amortization per Boe	$        6.11	$     10.51	$        7.36

	Year Ended December 31, 2009
	United States	Canada	North America
	(In millions)
Oil, gas and NGL sales	$     3,958	$     2,139	$     6,097
Lease operating expenses	(997)	(673)	(1,670)
Depreciation, depletion and amortization	(1,247)	(585)	(1,832)
General and administrative expenses	(145)	(74)	(219)
Taxes other than income taxes	(258)	(35)	(293)
Reduction of carrying value of oil and gas properties	(6,408)	—	(6,408)
Accretion of asset retirement obligations	(53)	(38)	(91)
Income tax benefit	1,800	(210)	1,580
Results of operations	$    (3,350)	$         524	$    (2,836)
Depreciation, depletion and amortization per Boe	$        7.47	$        8.84	$        7.86

Proved Reserves

The following tables present Devon's estimated proved reserves by product for each significant country.

	Oil (MMBbls)
	U.S. Onshore	U.S. Offshore	Total U.S.	Canada	North America
Proved developed and undeveloped reserves:
December 31, 2008	133	34	167	134	301
Revisions due to prices	9	2	11	291	302
Revisions other than price	—	1	1	(8)	(7)
Extensions and discoveries	9	2	11	122	133
Production	(12)	(5)	(17)	(25)	(42)
Sale of reserves	—	(1)	(1)	—	(1)
December 31, 2009	139	33	172	514	686
Revisions due to prices	4	1	5	(24)	(19)
Revisions other than price	2	2	4	9	13
Extensions and discoveries	19	1	20	59	79
Production	(14)	(2)	(16)	(25)	(41)
Sale of reserves	(2)	(35)	(37)	—	(37)
December 31, 2010	148	—	148	533	681
Revisions due to prices	2	—	2	(15)	(13)
Revisions other than price	(1)	—	(1)	11	10
Extensions and discoveries	36	—	36	36	72
Production	(17)	—	(17)	(28)	(45)
December 31, 2011	168	—	168	537	705
Proved developed reserves as of:
December 31, 2008	111	22	133	110	243
December 31, 2009	119	21	140	149	289
December 31, 2010	131	—	131	126	257
December 31, 2011	146	—	146	163	309
Proved developed-producing reserves as of:
December 31, 2008	103	9	112	91	203
December 31, 2009	112	12	124	137	261
December 31, 2010	123		123	116	239
December 31, 2011	139	—	139	155	294
Proved undeveloped reserves as of:
December 31, 2008	22	12	34	24	58
December 31, 2009	20	12	32	365	397
December 31, 2010	17	—	17	407	424
December 31, 2011	22	—	22	374	396

	Gas (Bcf)
	U.S. Onshore	U.S. Offshore	Total U.S.	Canada	North America
Proved developed and undeveloped reserves:
December 31, 2008	7,979	390	8,369	1,510	9,879
Revisions due to prices	(661)	(4)	(665)	(29)	(694)
Revisions other than price	119	(62)	57	(14)	43
Extensions and discoveries	1,387	64	1,451	67	1,518
Purchase of reserves	1	—	1	6	7
Production	(698)	(45)	(743)	(223)	(966)
Sale of reserves	—	(1)	(1)	(29)	(30)
December 31, 2009	8,127	342	8,469	1,288	9,757
Revisions due to prices	449	2	451	21	472
Revisions other than price	105	(26)	79	(17)	62
Extensions and discoveries	1,088	7	1,095	131	1,226
Purchase of reserves	12	—	12	9	21
Production	(699)	(17)	(716)	(214)	(930)
Sale of reserves	(17)	(308)	(325)	—	(325)
December 31, 2010	9,065	—	9,065	1,218	10,283
Revisions due to prices	(1)	—	(1)	(60)	(61)
Revisions other than price	(243)	—	(243)	(38)	(281)
Extensions and discoveries	1,410	—	1,410	58	1,468
Purchase of reserves	16	—	16	20	36
Production	(740)	—	(740)	(213)	(953)
Sale of reserves	—	—	—	(6)	(6)
December 31, 2011	9,507	—	9,507	979	10,486
Proved developed reserves as of:
December 31, 2008	6,469	212	6,681	1,357	8,038
December 31, 2009	6,447	185	6,632	1,213	7,845
December 31, 2010	7,280	—	7,280	1,144	8,424
December 31, 2011	7,957	—	7,957	951	8,908
Proved developed-producing reserves as of:
December 31, 2008	5,787	64	5,851	1,194	7,045
December 31, 2009	5,860	137	5,997	1,075	7,072
December 31, 2010	6,702	—	6,702	1,031	7,733
December 31, 2011	7,409	—	7,409	862	8,271
Proved undeveloped reserves as of:
December 31, 2008	1,510	178	1,688	153	1,841
December 31, 2009	1,680	157	1,837	75	1,912
December 31, 2010	1,785	—	1,785	74	1,859
December 31, 2011	1,550	—	1,550	28	1,578

	Natural Gas Liquids (MMBbls)
	U.S. Onshore	U.S. Offshore	Total U.S.	Canada	North America
Proved developed and undeveloped reserves:
December 31, 2008	315	2	317	35	352
Revisions due to prices	(11)	—	(11)	2	(9)
Revisions other than price	36	1	37	—	37
Extensions and discoveries	70	—	70	1	71
Production	(25)	(1)	(26)	(4)	(30)
December 31, 2009	385	2	387	34	421
Revisions due to prices	14	—	14	(1)	13
Revisions other than price	13	3	16	(1)	15
Extensions and discoveries	68	—	68	2	70
Production	(28)	—	(28)	(4)	(32)
Sale of reserves	(3)	(5)	(8)	—	(8)
December 31, 2010	449	—	449	30	479
Revisions due to prices	4	—	4	(1)	3
Revisions other than price	1	—	1	—	1
Extensions and discoveries	102	—	102	2	104
Purchase of reserves	2	—	2	—	2
Production	(33)	—	(33)	(4)	(37)
December 31, 2011	525	—	525	27	552
Proved developed reserves as of:
December 31, 2008	260	1	261	31	292
December 31, 2009	293	1	294	32	326
December 31, 2010	353	—	353	28	381
December 31, 2011	402	—	402	26	428
Proved developed-producing reserves as of:
December 31, 2008	230	—	230	29	259
December 31, 2009	265	1	266	28	294
December 31, 2010	318	—	318	26	344
December 31, 2011	372	—	372	24	396
Proved undeveloped reserves as of:
December 31, 2008	55	1	56	4	60
December 31, 2009	92	1	93	2	95
December 31, 2010	96	—	96	2	98
December 31, 2011	123	—	123	1	124

	Total (MMBoe) (1)
	U.S. Onshore	U.S. Offshore	Total U.S.	Canada	North America
Proved developed and undeveloped reserves:
December 31, 2008	1,777	101	1,878	421	2,299
Revisions due to prices	(113)	1	(112)	289	177
Revisions other than price	57	(8)	49	(11)	38
Extensions and discoveries	311	12	323	135	458
Purchase of reserves	—	—	—	1	1
Production	(154)	(13)	(167)	(66)	(233)
Sale of reserves	—	(1)	(1)	(6)	(7)
December 31, 2009	1,878	92	1,970	763	2,733
Revisions due to prices	92	1	93	(21)	72
Revisions other than price	32	1	33	5	38
Extensions and discoveries	269	2	271	83	354
Purchase of reserves	2	—	2	2	4
Production	(158)	(5)	(163)	(65)	(228)
Sale of reserves	(8)	(91)	(99)	(1)	(100)
December 31, 2010	2,107	—	2,107	766	2,873
Revisions due to prices	6	—	6	(27)	(21)
Revisions other than price	(41)	—	(41)	6	(35)
Extensions and discoveries	374	—	374	47	421
Purchase of reserves	5	—	5	3	8
Production	(173)	—	(173)	(67)	(240)
Sale of reserves	—	—	—	(1)	(1)
December 31, 2011	2,278	—	2,278	727	3,005
Proved developed reserves as of:
December 31, 2008	1,449	59	1,508	367	1,875
December 31, 2009	1,486	53	1,539	383	1,922
December 31, 2010	1,696	—	1,696	346	2,042
December 31, 2011	1,875	—	1,875	348	2,223
Proved developed-producing reserves as of:
December 31, 2008	1,298	20	1,318	319	1,637
December 31, 2009	1,354	35	1,389	344	1,733
December 31, 2010	1,557	—	1,557	314	1,871
December 31, 2011	1,746	—	1,746	323	2,069
Proved undeveloped reserves as of:
December 31, 2008	328	42	370	54	424
December 31, 2009	392	39	431	380	811
December 31, 2010	411	—	411	420	831
December 31, 2011	403	—	403	379	782

____________________________

(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 gas and oil. This rate is not necessarily indicative of the relationship of natural gas and oil prices. Natural gas liquids reserves are converted to Boe on a one-to-one basis with oil.

Proved Undeveloped Reserves

The following table presents the changes in our total proved undeveloped reserves during 2011 (in MMBoe).

	U.S. Onshore	Canada	North America
Proved undeveloped reserves as of December 31, 2010	411	420	831
Extensions and discoveries	118	30	148
Revisions due to prices	(2)	(14)	(16)
Revisions other than price	(56)	5	(51)
Conversion to proved developed reserves	(68)	(62)	(130)
Proved undeveloped reserves as of December 31, 2011	403	379	782

At December 31, 2011, Devon had 782 MMBoe of proved undeveloped reserves. This represents a 6% decrease as compared to 2010 and represents 26% of its total proved reserves. Drilling activities increased Devon's proved undeveloped reserves 148 MMBoe and resulted in the conversion of 130 MMBoe, or 16%, of the 2010 proved undeveloped reserves to proved developed reserves. Additionally, revisions other than price decreased Devon's proved undeveloped reserves 51 MMBoe primarily due to its evaluation of certain U.S. onshore dry-gas areas, which it does not expect to develop in the next five years. The largest revisions relate to the dry-gas areas at Carthage in east Texas and the Barnett Shale in north Texas.

A significant amount of Devon's proved undeveloped reserves at the end of 2011 largely related to its Jackfish operations. At December 31, 2011 and 2010, Devon's Jackfish proved undeveloped reserves were 367 MMBoe and 396 MMBoe, respectively. Development schedules for the Jackfish reserves are primarily controlled by the need to keep the processing plants at their 35,000 barrel daily facility capacity. Processing plant capacity is controlled by factors such as total steam processing capacity, steam-oil ratios and air quality discharge permits. As a result, these reserves are classified as proved undeveloped for more than five years. Currently, the development schedule for these reserves extends though the year 2025.

Price Revisions

2011 - Reserves decreased 21 MMBoe due to lower gas prices and higher oil prices. The higher oil prices increased Devon's Canadian royalty burden, which reduced Devon's oil reserves.

2010 - Reserves increased 72 MMBoe due to higher gas prices, partially offset by the effect of higher oil prices. The higher oil prices increased Devon's Canadian royalty burden, which reduced Devon's oil reserves. Of the 72 MMBoe price revisions, 43 MMBoe related to the Barnett Shale and 22 MMBoe related to the Rocky Mountain area.

2009 – Reserves increased 177 MMBoe due to higher oil prices, partially offset by lower gas prices. The increase in oil reserves primarily related to Devon's Jackfish thermal heavy oil reserves in Canada. At the end of 2008, 331 MMBoe of reserves related to Jackfish were not considered proved. However, due to higher prices, these reserves were considered proved as of December 31, 2009. Significantly lower gas prices caused Devon's reserves to decrease 116 MMBoe, which primarily related to its U.S reserves.

Revisions Other Than Price

Total revisions other than price for 2011 primarily related to Devon's evaluation of certain dry gas regions noted in the proved undeveloped reserves discussion above. Total revisions other than price for 2010 and 2009 primarily related to Devon's drilling and development in the Barnett Shale.

Extensions and Discoveries

2011 – Of the 421 MMBoe of 2011 extensions and discoveries, 162 MMBoe related to the Cana-Woodford Shale in western Oklahoma, 115 MMBoe related to the Barnett Shale, 39 MMBoe related to the Permian Basin, 30 MMBoe related to Jackfish, 19 MMBoe related to the Rocky Mountain area and 17 MMBoe related to the Granite Wash area in the Texas panhandle and western Oklahoma.

The 2011 extensions and discoveries included 168 MMBoe related to additions from Devon's infill drilling activities, including 80 MMBoe at the Cana-Woodford Shale and 77 MMBoe at the Barnett Shale.

2010 – Of the 354 MMBoe of 2010 extensions and discoveries, 101 MMBoe related to the Cana-Woodford Shale, 87 MMBoe related to the Barnett Shale, 55 MMBoe related to Jackfish, 19 MMBoe related to the Permian Basin, 15 MMBoe related to the Rocky Mountain area and 14 MMBoe related to the Carthage area.

The 2010 extensions and discoveries included 107 MMBoe related to additions from Devon's infill drilling activities, including 43 MMBoe at the Barnett Shale and 47 MMBoe at the Cana-Woodford Shale.

2009 – Of the 458 MMBoe of 2009 extensions and discoveries, 204 MMBoe related to the Barnett Shale, 118 MMBoe related to Jackfish, 49 MMBoe related to the Cana-Woodford Shale, 14 MMBoe related to the Rocky Mountain area, 11 MMBoe related to Deepwater Production in the Gulf, 8 MMBoe related to the Carthage area and 7 MMBoe related to the Haynesville Shale area in east Texas.

The 2009 extensions and discoveries included 371 MMBoe related to additions from Devon's infill drilling activities, including 203 MMBoe at the Barnett Shale, 118 MMBoe at Jackfish and 24 MMBoe at the Cana-Woodford Shale.

Sale of Reserves

The 2010 total primarily relates to the divestiture of Devon's Gulf of Mexico properties.

SEC's Modernization of Oil and Gas Reporting

At the end of 2009, Devon adopted the SEC's Modernization of Oil and Gas Reporting, as well as the conforming rule changes issued by the Financial Accounting Standards Board. Upon adoption, the two primary rule changes that impacted Devon's year-end reserves estimates were those related to assumptions for pricing and reasonable certainty.

The SEC's prior rules required proved reserve estimates to be calculated using prices as of the end of the period and held constant over the life of the reserves. The revised rules require reserves estimates to be calculated using an average of the first-day-of-the-month price for the preceding 12-month period.

The revised rules amend the definition of proved reserves to permit the use of reliable technologies to establish the reasonable certainty of proved reserves. This revision includes provisions for establishing levels of lowest known hydrocarbons and highest known oil through reliable technology other than well penetrations. This revision also allows proved reserves to be claimed beyond development spacing areas that are immediately adjacent to developed spacing areas if economic producibility can be established with reasonable certainty based on reliable technologies. As a result of adopting these provisions of the new rules, Devon's 2009 reserves increased approximately 65 MMBoe, or 2%. This increase is included in the 2009 extensions and discoveries total.

Standardized Measure

The tables below reflect Devon's standardized measure of discounted future net cash flows from its proved reserves.  

	Year Ended December 31, 2011
	U.S	Canada	North America
	(In millions)
Future cash inflows	$   69,305	$   36,786	$ 106,091
Future costs:
Development	(6,817)	(4,678)	(11,495)
Production	(26,217)	(15,063)	(41,280)
Future income tax expense	(11,432)	(3,763)	(15,195)
Future net cash flows	24,839	13,282	38,121
10% discount to reflect timing of cash flows	(13,492)	(6,785)	(20,277)
Standardized measure of discounted future net cash flows	$   11,347	$     6,497	$   17,844

	Year Ended December 31, 2010
	U.S	Canada	North America
	(In millions)
Future cash inflows	$   58,093	$   35,948	$   94,041
Future costs:
Development	(6,220)	(4,526)	(10,746)
Production	(24,223)	(12,249)	(36,472)
Future income tax expense	(8,643)	(4,209)	(12,852)
Future net cash flows	19,007	14,964	33,971
10% discount to reflect timing of cash flows	(10,164)	(7,455)	(17,619)
Standardized measure of discounted future net cash flows	$     8,843	$     7,509	$   16,352
	Year Ended December 31, 2009
	U.S	Canada	North America
	(In millions)
Future cash inflows	$   44,571	$   28,442	$   73,013
Future costs:
Development	(6,814)	(4,132)	(10,946)
Production	(22,184)	(9,847)	(32,031)
Future income tax expense	(3,572)	(3,408)	(6,980)
Future net cash flows	12,001	11,055	23,056
10% discount to reflect timing of cash flows	(6,121)	(5,532)	(11,653)
Standardized measure of discounted future net cash flows	$     5,880	$     5,523	$   11,403

Future cash inflows, development costs and production costs were computed using the same assumptions for prices and costs that were used to estimate Devon's proved oil and gas reserves at the end of each year. For 2011, the prices averaged $67.31 per barrel of oil, $3.51 per Mcf of gas and $39.28 per barrel of natural gas liquids. Of the $11.5 billion of future development costs as of the end of 2011, $1.6 billion, $1.4 billion and $1.1 billion are estimated to be spent in 2012, 2013 and 2014, respectively.

Future development costs include not only development costs, but also future asset retirement costs. Included as part of the $11.5 billion of future development costs are $2.2 billion of future asset retirement 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.

The principal changes in Devon's standardized measure of discounted future net cash flows are as follows:

	Year Ended December 31,
	2011	2010	2009
	(In millions)
Beginning balance	$   16,352	$   11,403	$     9,393
Oil, gas and NGL sales, net of production costs	(5,794)	(4,982)	(3,915)
Net changes in prices and production costs	1,875	7,423	(1,672)
Extensions and discoveries, net of future development costs	3,714	3,048	2,378
Purchase of reserves, net of future development costs	57	23	6
Development costs incurred that reduced future development costs..	1,302	1,559	1,012
Revisions of quantity estimates	(668)	287	4,051
Sales of reserves in place	(2)	(815)	(37)
Accretion of discount	2,248	1,487	1,281
Net change in income taxes	(929)	(2,663)	(51)
Other, primarily changes in timing and foreign exchange rates	(311)	(418)	(1,043)
Ending balance	$   17,844	$   16,352	$   11,403

The following table presents Devon's estimated pretax cash flow information related to its proved reserves.

	Year Ended December 31, 2011
	U.S	Canada	North America
Pre-Tax Future Net Revenue (1)	(In millions)
Proved Developed Reserves	$   30,473	$     7,757	$   38,230
Proved Undeveloped Reserves	5,798	9,288	15,086
Total Proved Reserves	$   36,271	$   17,045	$   53,316

Pre-Tax 10% Present Value (1)
Proved Developed Reserves	$   15,165	$     5,830	$   20,995
Proved Undeveloped Reserves	1,404	2,508	3,912
Total Proved Reserves	$   16,569	$     8,338	$   24,907

____________________________

(1)   Estimated pre-tax 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 depreciation, depletion and amortization, or to non-property related expenses such as debt service and income tax expense.

The present value of after-tax future net revenues discounted at 10% per annum ("standardized measure") was $17.8 billion at the end of 2011. Included as part of standardized measure were discounted future income taxes of $7.1 billion. Excluding these taxes, the present value of our pre-tax future net revenue ("pre-tax 10% present value") was $24.9 billion. Devon believes the pre-tax 10% present value is a useful measure in addition to the after-tax standardized measure. The pre-tax 10% present value 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 after-tax 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 more consistent from company to company.

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Retirement Plans (Schedule Of Changes In Level 3 Assets) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Defined Benefit Plan Disclosure [Line Items]
Level 3 plan assets	$ 90	$ 58	$ 51
Investment Returns Of Hedge Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Level 3 plan assets	(1)	4
Purchases Of Hedge Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Level 3 plan assets	$ 33	$ 3

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Derivative Financial Instruments (Schedule Of Open Commodity Derivative Positions) (Details)	12 Months Ended
	Dec. 31, 2011
Q1-Q4 2012 [Member] | Bbl [Member] | Open Oil Derivative Positions [Member] | Price Swaps [Member]
Derivative [Line Items]
Volume per day	22,000
Weighted Average Price	107.17
Q1-Q4 2012 [Member] | Bbl [Member] | Open Oil Derivative Positions [Member] | Price Collars [Member]
Derivative [Line Items]
Volume per day	54,000
Weighted Average Floor Price	85.74
Weighted Average Ceiling Price	126.42
Q1-Q4 2012 [Member] | Bbl [Member] | Open Oil Derivative Positions [Member] | Call Options Sold [Member]
Derivative [Line Items]
Volume per day	19,500
Weighted Average Price	95.00
Q1-Q4 2012 [Member] | MMBtu [Member] | El Paso Natural Gas Co [Member] | NGL Basis Swap [Member]
Derivative [Line Items]
Volume per day	85,000
Weighted Average Differential to Henry hub	(0.14)
Q1-Q4 2012 [Member] | MMBtu [Member] | Panhandle Eastern Pipeline [Member] | NGL Basis Swap [Member]
Derivative [Line Items]
Volume per day	70,000
Weighted Average Differential to Henry hub	(0.15)
Q1-Q4 2012 [Member] | MMBtu [Member] | Colorado Interstate Gas Co [Member] | NGL Basis Swap [Member]
Derivative [Line Items]
Volume per day	10,000
Weighted Average Differential to Henry hub	(0.18)
Q1-Q4 2012 [Member] | MMBtu [Member] | Open Natural Gas Derivative Positions [Member] | Price Swaps [Member]
Derivative [Line Items]
Volume per day	325,000
Weighted Average Price	5.09
Q1-Q4 2012 [Member] | MMBtu [Member] | Open Natural Gas Derivative Positions [Member] | Price Collars [Member]
Derivative [Line Items]
Volume per day	490,000
Weighted Average Floor Price	4.75
Weighted Average Ceiling Price	5.57
Q1-Q4 2012 [Member] | MMBtu [Member] | Open Natural Gas Derivative Positions [Member] | Call Options Sold [Member]
Derivative [Line Items]
Volume per day	487,500
Weighted Average Price	6.00
Q1-Q4 2013 [Member] | Bbl [Member] | Open Oil Derivative Positions [Member] | Price Collars [Member]
Derivative [Line Items]
Volume per day	7,000
Weighted Average Floor Price	90.00
Weighted Average Ceiling Price	125.12

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Debt And Related Expenses (Tables)

12 Months Ended

Dec. 31, 2011

Debt And Related Expenses [Abstract]

Schedule Of Long-term Debt Instruments

	December 31,
	2011	2010
	(In millions)
Commercial paper	$       3,726	$            —
Other debentures and notes:
6.875% retired upon maturity on September 30, 2011	—	1,750
5.625% due January 15, 2014	500	500
Non-interest bearing promissory note due June 29, 2014	85	144
2.40% due July 15, 2016	500	—
8.25% due July 1, 2018	125	125
6.30% due January 15, 2019	700	700
4.00% due July 15, 2021	500	—
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
5.60% due July 15, 2041	1,250	—
Other	—	9
Net discount on other debentures and notes	(6)	2
Total debt	9,780	5,630
Less amount classified as short-term debt	3,811	1,811
Long-term debt	$       5,969	$   3,819

Schedule Of Debt Maturities

2012	$       3,811
2013	—
2014	500
2015	—
2016	500
2017 and thereafter	4,975
Total	$       9,786

Schedule Of Debt Assumed Upon Acquisition Of Business

Debt Assumed	Fair Value of Debt Assumed	Effective Rate of Debt Assumed
	(In millions)
8.250% due July 2018 (principal of $125 million)	$            147	5.5%
7.500% due September 2027 (principal of $150 million)	$            169	6.5%

Schedule Of Interest Expense Components

	Year Ended December 31,
	2011	2010	2009
	(In millions)
Interest based on debt outstanding	$         414	$         408	$         437
Capitalized interest	(72)	(76)	(94)
Early retirement of debt	—	19	—
Other	10	12	6
Total	$         352	$         363	$         349

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Summary Of Significant Accounting Policies (Policy)

12 Months Ended

Dec. 31, 2011

Summary Of Significant Accounting Policies [Abstract]

Principles Of Consolidation

Principles of Consolidation

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

Use Of Estimates

Use of Estimates

The preparation of financial statements 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 the following:

• proved reserves and related present value of future net revenues;

• the carrying value of oil and gas properties;

• derivative financial instruments;

• the fair value of reporting units and related assessment of goodwill for impairment;

• income taxes;

• asset retirement obligations;

• obligations related to employee pension and postretirement benefits; and

• legal and environmental risks and exposures.

Revenue Recognition And Gas Balancing

Revenue Recognition and Gas Balancing

Oil, gas and NGL sales are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectability of the revenue is probable. Delivery occurs and title is transferred when production has been delivered to a pipeline, railcar or truck. Cash received relating to future production is deferred and recognized when all revenue recognition criteria are met. Taxes assessed by governmental authorities on oil, gas and NGL sales are presented separately from such revenues in the accompanying comprehensive statements of earnings.

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 differences create imbalances that are recognized as a liability only when the estimated remaining reserves will not be sufficient to enable the underproduced owner to recoup its entitled share through production. 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. 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.

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, delivery or performance has occurred, title has transferred and collectability of the revenue is probable. Revenues and expenses attributable to oil, gas and NGL purchases, transportation and processing contracts are reported on a gross basis when Devon takes title to the products and has risks and rewards of ownership.

During 2011, 2010 and 2009, no purchaser accounted for more than 10 percent of Devon's revenues from continuing operations.

Derivative Financial Instruments

Derivative Financial Instruments

Devon is exposed to certain risks relating to its ongoing business operations, including risks related to commodity prices, interest rates and Canadian to U.S. dollar exchange rates. As discussed more fully below, Devon uses derivative instruments primarily to manage commodity price risk and interest rate risk. Devon does not hold or issue derivative financial instruments for speculative trading purposes.

Devon periodically enters into derivative financial instruments with respect to a portion of its oil, gas and NGL production that hedge the future prices received. These instruments are used to manage the inherent uncertainty of future revenues due to commodity price volatility. Devon's derivative financial instruments include financial price swaps, basis swaps, costless price collars and call options. Under the terms of the price swaps, Devon receives a fixed price for its production and pays a variable market price to the contract counterparty. For the basis swaps, Devon receives a fixed differential between two regional gas index prices and pays a variable differential on the same two index prices to the contract counterparty. The price collars set a floor and ceiling price for the hedged production. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, Devon will cash-settle the difference with the counterparty to the collars. The call options give counterparties the right to purchase production at a predetermined price.

Devon periodically enters into interest rate swaps to manage its exposure to interest rate volatility. Devon's interest rate swaps include contracts in which Devon receives a fixed rate and pays a variable rate on a total notional amount.

All derivative financial instruments are recognized at their current fair value as either assets or liabilities in the balance sheet. Changes in the fair value of these derivative financial instruments are recorded in earnings unless specific hedge accounting criteria are met. For derivative financial instruments held during the three-year period ended December 31, 2011, Devon chose not to meet the necessary criteria to qualify its derivative financial instruments for hedge accounting treatment. Cash settlements with counterparties on Devon's derivative financial instruments are also recorded in earnings.

By using derivative financial instruments to hedge exposures to changes in commodity prices and interest rates, Devon is exposed to credit 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 a number of counterparties whom 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. Additionally, Devon's derivative contracts generally require cash collateral to be posted if either its or the counterparty's credit rating falls below certain credit rating levels. The mark-to-market exposure threshold, above which collateral must be posted, decreases as the debt rating falls further below such credit levels. Thresholds generally range from zero to $55 million for the majority of Devon's contracts. As of December 31, 2011, the credit ratings of all Devon's counterparties were investment grade.

General And Administrative Expenses

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.

Share Based Compensation

Share Based Compensation

Devon grants stock options, restricted stock awards and other types of share-based awards to members of its Board of Directors and selected employees. All such awards are measured at fair value on the date of grant and are recognized as a component of general and administrative expenses in the accompanying comprehensive statements of earnings over the applicable requisite service periods. As a result of Devon's strategic repositioning announced in 2009, certain share based awards were accelerated and recognized as a component of restructuring expense in the accompanying comprehensive statements of earnings.

Generally, Devon uses new shares from approved incentive programs to grant share-based awards and to issue shares upon stock option exercises. Shares repurchased under approved programs are available to be issued as part of Devon's share based awards. However, Devon has historically cancelled these shares upon repurchase.

Income Taxes

Income Taxes

Devon is subject to current income taxes assessed by the federal and various state jurisdictions in the U.S. and by other foreign jurisdictions. In addition, Devon accounts for deferred income taxes related to these jurisdictions using the asset and liability method. Under this method, 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. Deferred tax assets are also recognized for the future tax benefits attributable to the expected utilization of existing tax net operating loss carryforwards and other types of carryforwards. If the future utilization of some portion of carryforwards is determined to be unlikely, a valuation allowance is provided to reduce the recorded tax benefits from such assets. 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.

Devon does not recognize U.S. deferred income taxes on the unremitted earnings of its foreign subsidiaries that are deemed to be permanently reinvested. When such earnings are no longer deemed permanently reinvested, Devon recognizes the appropriate deferred, or even current, income tax liabilities.

Devon recognizes the financial statement effects of tax positions when it is more likely than not, based on the technical merits, that the position will be sustained upon examination by a taxing authority. Recognized tax positions are initially and subsequently measured as the largest amount of tax benefit that is more likely than not of being realized upon ultimate settlement with a taxing authority. Liabilities for unrecognized tax benefits related to such tax positions are included in other long-term liabilities unless the tax position is expected to be settled within the upcoming year, in which case the liabilities are included in other current liabilities. Interest and penalties related to unrecognized tax benefits are included in current income tax expense.

Net Earnings (Loss) Per Common Share

Net Earnings (Loss) Per Common Share

Devon's basic earnings per share amounts have been computed based on the average number of shares of common stock outstanding for the period. Basic earnings per share includes the effect of participating securities, which primarily consist of Devon's outstanding restricted stock awards. Diluted earnings per share is calculated using the treasury stock method to reflect the assumed issuance of common shares for all potentially dilutive securities. Such securities primarily consist of outstanding stock options.

Cash And Cash Equivalents

Cash and Cash Equivalents

Devon considers all highly liquid investments with original contractual maturities of three months or less to be cash equivalents.

Investments

Investments

Devon periodically invests excess cash in U.S. and Canadian Treasury securities and other marketable securities. During 2011, Devon invested a portion of the International offshore divestiture proceeds into such securities, causing short-term investments to increase.

Devon considers securities with original contractual maturities in excess of three months, but less than one year to be short-term investments. Investments with contractual maturities in excess of one year are classified as long-term, unless such investments are classified as trading or available-for-sale.

Devon reports its investments and other marketable securities at fair value, except for debt securities in which management has the ability and intent to hold until maturity. Such debt securities totaled $84 million and $94 million at December 31, 2011 and 2010, respectively and are included in other long-term assets in the accompanying balance sheet. Devon has the ability to hold the securities until maturity and does not believe the values of its long-term securities are impaired.

Property And Equipment

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 that 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. 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.

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 estimated after-tax future net revenues, discounted at 10 percent per annum, from proved oil, 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 tested quarterly and imposed separately on a country-by-country basis.

Future net revenues are calculated using prices that represent the average of the first-day-of-the-month price for the 12-month period prior to the end of the period. Prices are held constant indefinitely and are not changed except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including derivative contracts in place that qualify for hedge accounting treatment. None of Devon's derivative contracts held during the three-year period ended December 31, 2011, qualified for hedge accounting treatment.

Any excess of the net book value, less related deferred taxes, over the ceiling is written off as an expense. An expense recorded in one period may not be reversed in a subsequent period even though higher commodity prices may have increased the ceiling applicable to the subsequent period.

Capitalized costs are depleted by an equivalent unit-of-production method, converting gas to oil at the ratio of six thousand cubic feet of 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.

Costs associated with unproved properties are excluded from the depletion calculation 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 into the depletion calculation over holding periods ranging from three to six years.

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.

Depreciation of midstream pipelines are provided on a unit-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 ranging from three to 39 years. Interest costs incurred and attributable to major midstream and corporate construction projects are also capitalized.

Devon recognizes liabilities for retirement obligations associated with tangible long-lived assets, such as producing well sites and midstream pipelines and processing plants when there is a legal obligation associated with the retirement of such assets and the amount can be reasonably estimated. The initial measurement of an asset retirement obligation is recorded as a liability at its fair value, with an offsetting asset retirement cost recorded as an increase to the associated property and equipment on the consolidated balance sheet. When the assumptions used to estimate a recorded asset retirement obligation change, a revision is recorded to both the asset retirement obligation and the asset retirement cost. The asset retirement cost is depreciated using a systematic and rational method similar to that used for the associated property and equipment.

Goodwill

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. Such test includes an assessment of qualitative and quantiative factors. 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 2011, 2010 and 2009. Based on these assessments, no impairment of goodwill was required.

The table below provides a summary of Devon's goodwill, by assigned reporting unit. The decrease in Devon's goodwill from 2010 to 2011 was due to changes in the exchange rate between the U.S. dollar and the Canadian dollar.

	December 31,
	2011	2010
	(In millions)
U.S.	$   3,046	$   3,046
Canada	2,967	3,034
Total	$   6,013	$   6,080

Commitments And Contingencies

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. Liabilities for environmental remediation or restoration claims are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. Expenditures related to such environmental matters are expensed or capitalized in accordance with Devon's accounting policy for property and equipment.

Fair Value Measurements

Fair Value Measurements

Certain of Devon's assets and liabilities are measured at fair value at each reporting date. Fair value represents the price that would be received to sell the asset or paid to transfer the liability in an orderly transaction between market participants. This price is commonly referred to as the "exit price." Fair value measurements are classified according to a hierarchy that prioritizes the inputs underlying the valuation techniques. This hierarchy consists of three broad levels:

·Level 1 - Inputs consist of unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. When available, Devon measures fair value using Level 1 inputs because they generally provide the most reliable evidence of fair value.

·Level 2 – Inputs consist of quoted prices that are generally observable for the asset or liability. Common examples of Level 2 inputs include quoted prices for similar assets and liabilities in active markets or quoted prices for identical assets and liabilities in markets not considered to be active.

·Level 3 - Inputs are not observable from objective sources and have the lowest priority. The most common Level 3 fair value measurement is an internally developed cash flow model.

Discontinued Operations

Discontinued Operations

As a result of the November 2009 plan to divest Devon's offshore assets, all amounts related to Devon's International operations are classified as discontinued operations. The Gulf of Mexico properties that were divested in 2010 do not qualify as discontinued operations under accounting rules. As such, amounts in these notes and the accompanying financial statements that pertain to continuing operations include amounts related to Devon's offshore Gulf of Mexico operations.

The captions assets held for sale and liabilities associated with assets held for sale in the accompanying balance sheets present the assets and liabilities associated with Devon's discontinued operations. Devon measures its assets held for sale at the lower of its carrying amount or estimated fair value less costs to sell. Additionally, Devon does not recognize depreciation, depletion and amortization on its long-lived assets held for sale.

Foreign Currency Translation Adjustments

Foreign Currency Translation Adjustments

       The U.S. dollar is the functional currency for Devon's consolidated operations except its Canadian subsidiaries, which use the Canadian dollar as the 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. Canadian 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 earnings in stockholders' equity.

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Summary Of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2011

Summary Of Significant Accounting Policies [Abstract]

Schedule Of Goodwill By Business Segment

	December 31,
	2011	2010
	(In millions)
U.S.	$   3,046	$   3,046
Canada	2,967	3,034
Total	$   6,013	$   6,080

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Derivative Financial Instruments

12 Months Ended

Dec. 31, 2011

Derivative Financial Instruments [Abstract]

Derivative Financial Instruments

2. Derivative Financial Instruments

Commodity Derivatives

As of December 31, 2011, Devon had the following open oil derivative positions. Devon's oil derivatives settle against the average of the prompt month NYMEX West Texas Intermediate futures price.

Production Period	Price Swaps		Price Collars			Call Options Sold
Period	Volume (Bbls/d)	Weighted Average Price ($/Bbl)	Volume (Bbls/d)	Weighted Average Floor Price ($/Bbl)	Weighted Average Ceiling Price ($/Bbl)	Volume (Bbls/d)	Weighted Average Price ($/Bbl)
Q1-Q4 2012.	22,000	$107.17	54,000	$85.74	$126.42	19,500	$95.00
Q1-Q4 2013.	—	—	7,000	$90.00	$125.12	—	—

As of December 31, 2011, Devon had the following open natural gas derivative positions. Devon's natural gas derivative settle against the Inside FERC first of the month Henry Hub index.

Production Period	Price Swaps		Price Collars			Call Options Sold
Period	Volume (MMBtu/d)	Weighted Average Price ($/MMBtu)	Volume (MMBtu/d)	Weighted Average Floor Price ($/MMBtu)	Weighted Average Ceiling Price ($/MMBtu)	Volume (MMBtu/d)	Weighted Average Price ($/MMBtu)
Q1-Q4 2012.	325,000	$5.09	490,000	$4.75	$5.57	487,500	$6.00

Basis Swaps
Production Period	Index	Volume (MMBtu/d)	Weighted Average Differential to Henry Hub ($/MMBtu)
Q1-Q4 2012	El Paso Natural Gas Co. (Permian)	85,000	$(0.14)
Q1-Q4 2012	Panhandle Eastern Pipeline	70,000	$(0.15)
Q1-Q4 2012	Colorado Interstate Gas Co.	10,000	$(0.18)

Interest Rate Derivatives

As of December 31, 2011, Devon had the following open interest rate derivative positions:

Notional	Fixed Rate Received	Variable Rate Paid	Expiration
(In millions)
$           100	1.90%	Federal funds rate	August 2012
750	3.88%	Federal funds rate	July 2013
$           850	3.65%

Foreign Exchange Derivatives

As of December 31, 2011, Devon had the following open foreign exchange rate derivative positions:

Forward Contract
Currency	Contract Type	CAD Notional	Fixed Rate Received	Expiration
		(In millions)	(CAD-USD)
Canadian Dollar	Sell	$           305	0.9812	March 30, 2012

Financial Statement Presentation

The following table presents the cash settlements and unrealized gains and losses on fair value changes included in the accompanying comprehensive statements of earnings associated with derivative financial instruments.

	Comprehensive Statement of Earnings Caption		2011	2010	2009
			(In millions)
Cash settlements:
Commodity derivatives	Oil, gas and NGL derivatives		$  392	$   888	$   505
Interest rate derivatives	Other, net		77	44	40
Foreign exchange derivatives	Other, net		16	—	—
Total cash settlements			485	932	545
Unrealized gains (losses):
Commodity derivatives		Oil, gas and NGL derivatives	489	(77)	(121)
Interest rate derivatives		Other, net	(88)	(30)	66
Total unrealized gains (losses)			401	(107)	(55)
Net gain recognized on comprehensive statements of earnings			$   886	$   825	$   490

The following table presents the derivative fair values included in the accompanying balance sheets.

		December 31,
	Balance Sheet Caption	2011	2010
		(In millions)
Asset derivatives:
Commodity derivatives	Other current assets	$      611	$      248
Commodity derivatives	Other long-term assets	17	1
Interest rate derivatives	Other current assets	30	100
Interest rate derivatives	Other long-term assets	22	40
Total asset derivatives		$      680	$      389

Liability derivatives:
Commodity derivatives	Other current liabilities	$         82	$         50
Commodity derivatives	Other long-term liabilities	—	142
Total liability derivatives		$         82	$      192

 

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Derivative Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2011

Derivative [Line Items]

Schedule Of Open Interest Rate Swap Derivative Positions

		December 31,
	Balance Sheet Caption	2011	2010
		(In millions)
Asset derivatives:
Commodity derivatives	Other current assets	$      611	$      248
Commodity derivatives	Other long-term assets	17	1
Interest rate derivatives	Other current assets	30	100
Interest rate derivatives	Other long-term assets	22	40
Total asset derivatives		$      680	$      389

Liability derivatives:
Commodity derivatives	Other current liabilities	$         82	$         50
Commodity derivatives	Other long-term liabilities	—	142
Total liability derivatives		$         82	$      192

Schedule Of Derivative Financial Instruments Included In The Consolidated Balance Sheets And Consolidated Statement Of Operations

	Comprehensive Statement of Earnings Caption		2011	2010	2009
			(In millions)
Cash settlements:
Commodity derivatives	Oil, gas and NGL derivatives		$  392	$   888	$   505
Interest rate derivatives	Other, net		77	44	40
Foreign exchange derivatives	Other, net		16	—	—
Total cash settlements			485	932	545
Unrealized gains (losses):
Commodity derivatives		Oil, gas and NGL derivatives	489	(77)	(121)
Interest rate derivatives		Other, net	(88)	(30)	66
Total unrealized gains (losses)			401	(107)	(55)
Net gain recognized on comprehensive statements of earnings			$   886	$   825	$   490

Commodity Derivatives [Member]

Derivative [Line Items]

Schedule Of Open Commodity Derivative Positions

Production Period	Price Swaps		Price Collars			Call Options Sold
Period	Volume (Bbls/d)	Weighted Average Price ($/Bbl)	Volume (Bbls/d)	Weighted Average Floor Price ($/Bbl)	Weighted Average Ceiling Price ($/Bbl)	Volume (Bbls/d)	Weighted Average Price ($/Bbl)
Q1-Q4 2012.	22,000	$107.17	54,000	$85.74	$126.42	19,500	$95.00
Q1-Q4 2013.	—	—	7,000	$90.00	$125.12	—	—

As of December 31, 2011, Devon had the following open natural gas derivative positions. Devon's natural gas derivative settle against the Inside FERC first of the month Henry Hub index.

Production Period	Price Swaps		Price Collars			Call Options Sold
Period	Volume (MMBtu/d)	Weighted Average Price ($/MMBtu)	Volume (MMBtu/d)	Weighted Average Floor Price ($/MMBtu)	Weighted Average Ceiling Price ($/MMBtu)	Volume (MMBtu/d)	Weighted Average Price ($/MMBtu)
Q1-Q4 2012.	325,000	$5.09	490,000	$4.75	$5.57	487,500	$6.00

Basis Swaps
Production Period	Index	Volume (MMBtu/d)	Weighted Average Differential to Henry Hub ($/MMBtu)
Q1-Q4 2012	El Paso Natural Gas Co. (Permian)	85,000	$(0.14)
Q1-Q4 2012	Panhandle Eastern Pipeline	70,000	$(0.15)
Q1-Q4 2012	Colorado Interstate Gas Co.	10,000	$(0.18)

Interest Rate Derivatives [Member]

Derivative [Line Items]

Schedule Of Open Commodity Derivative Positions

Notional	Fixed Rate Received	Variable Rate Paid	Expiration
(In millions)
$           100	1.90%	Federal funds rate	August 2012
750	3.88%	Federal funds rate	July 2013
$           850	3.65%

Foreign Exchange Derivatives [Member]

Derivative [Line Items]

Schedule Of Open Commodity Derivative Positions

Forward Contract
Currency	Contract Type	CAD Notional	Fixed Rate Received	Expiration
		(In millions)	(CAD-USD)
Canadian Dollar	Sell	$           305	0.9812	March 30, 2012

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Other Current Assets (Schedule Of Components Of Other Current Assets) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Other Current Assets [Line Items]
Derivative financial instruments	$ 680	$ 389
Other current assets	847	779
Other Current Assets [Member]
Other Current Assets [Line Items]
Derivative financial instruments	641	348
Inventories	102	120
Income taxes receivable	35	270
Other	69	41
Other current assets	$ 847	$ 779

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Supplemental Information On Oil And Gas Operations (Capitalized Costs) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Capitalized Costs, Proved properties	$ 61,696	$ 56,012
United States [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Capitalized Costs, Proved properties	41,397	36,301
Capitalized Costs, Unproved properties	2,347	2,156
Capitalized Costs, Total oil & gas properties	43,744	38,457
Capitalized Costs, Accumulated DD&A	(29,742)	(28,546)
Net capitalized costs	14,002	9,911
Canada [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Capitalized Costs, Proved properties	20,299	19,711
Capitalized Costs, Unproved properties	1,635	1,278
Capitalized Costs, Total oil & gas properties	21,934	20,989
Capitalized Costs, Accumulated DD&A	(14,585)	(14,130)
Net capitalized costs	7,349	6,859
North America [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Capitalized Costs, Proved properties	61,696	56,012
Capitalized Costs, Unproved properties	3,982	3,434
Capitalized Costs, Total oil & gas properties	65,678	59,446
Capitalized Costs, Accumulated DD&A	(44,327)	(42,676)
Net capitalized costs	$ 21,351	$ 16,770

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Short-Term Investments (Tables)

12 Months Ended

Dec. 31, 2011

Short-Term Investments [Abstract]

Components Of Short-Term Investments

	December 31,
	2011	2010
	(In millions)
Commercial paper	$     1,013	$           —
U.S. Treasuries	201	145
Other	289	—
Total	$     1,503	$        145

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Supplemental Quarterly Financial Information (Tables)

12 Months Ended

Dec. 31, 2011

Supplemental Quarterly Financial Information [Abstract]

Schedule Of Quarterly Financial Information

	2011
	First Quarter	Second Quarter	Third Quarter	Fourth Quarter	Full Year
	(In millions, except per share amounts)
Revenues	$2,147	$3,220	$3,502	$2,585	$11,454
Earnings from continuing operations before income taxes	$580	$1,378	$1,538	$794	$4,290
Earnings from continuing operations	$389	$184	$1,040	$521	$2,134
Earnings (loss) from discontinued operations	27	2,559	(2)	(14)	2,570
Net earnings	$416	$2,743	$1,038	$507	$4,704
Basic net earnings per common share:
Earnings from continuing operations	$0.91	$0.44	$2.51	$1.29	$5.12
Earnings (loss) from discontinued operations	0.06	6.06	—	(0.04)	6.17
Net earnings	$0.97	$6.50	$2.51	$1.25	$11.29
Diluted net earnings per common share:
Earnings from continuing operations	$0.91	$0.43	$2.50	$1.29	$5.10
Earnings (loss) from discontinued operations	0.06	6.05	—	(0.04)	6.15
Net earnings	$0.97	$6.48	$2.50	$1.25	$11.25

	2010
	First Quarter	Second Quarter	Third Quarter	Fourth Quarter	Full Year
	(In millions, except per share amounts)
Revenues	$3,220	$2,232	$2,353	$2,135	$9,940
(Loss) earnings from continuing operations before income taxes	$1,588	$613	$699	$668	$3,568
(Loss) earnings from continuing operations	$1,074	$352	$429	$478	$2,333
(Loss) earnings from discontinued operations	118	354	1,661	84	2,217
Net (loss) earnings	$1,192	$706	$2,090	$562	$4,550
Basic net (loss) earnings per common share:
(Loss) earnings from continuing operations	$2.40	$0.79	$0.99	$1.10	$5.31
(Loss) earnings from discontinued operations..	0.27	0.80	3.82	0.20	5.04
Net (loss) earnings	$2.67	$1.59	$4.81	$1.30	$10.35
Diluted net (loss) earnings per common share:
(Loss) earnings from continuing operations	$2.39	$0.79	$0.98	$1.10	$5.29
(Loss) earnings from discontinued operations..	0.27	0.79	3.81	0.19	5.02
Net (loss) earnings	$2.66	$1.58	$4.79	$1.29	$10.31

XML

Income Taxes (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Effective income tax rate	35.00%
Deferred income tax expense (benefit)	$ 2,299,000,000	$ 719,000,000	$ (2,014,000,000)
Tax credit carryforward, deferred tax asset	222,000,000
Net operating loss carryforward, domestic	206,000,000
Unremitted earnings from subsidiaries permanently reinvested	5,400,000,000
Unrecognized tax benefit balances of interest and penalties	20,000,000	27,000,000
Assumed Repatriation Of Earnings [Member]
Deferred income tax expense (benefit)	725,000,000	144,000,000	55,000,000
State [Member] | Maximum [Member]
Operating loss carryforward, expiration period	2031
Operating loss carryforward, utilization period	2016
State [Member] | Minimum [Member]
Operating loss carryforward, expiration period	2012
Operating loss carryforward, utilization period	2012
Canadian [Member]
Net operating loss carryforward, foreign	$ 829,000,000
Canadian [Member] | Maximum [Member]
Operating loss carryforward, expiration period	2031
Operating loss carryforward, utilization period	2017
Canadian [Member] | Minimum [Member]
Operating loss carryforward, expiration period	2026
Operating loss carryforward, utilization period	2013

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Consolidated Comprehensive Statements Of Earnings (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Revenues:
Oil, gas and NGL sales	$ 8,315	$ 7,262	$ 6,097
Oil, gas and NGL derivatives	881	811	384
Marketing and midstream revenues	2,258	1,867	1,534
Total revenues	11,454	9,940	8,015
Expenses and other, net:
Lease operating expenses	1,851	1,689	1,670
Marketing and midstream operating costs and expenses	1,716	1,357	1,022
Depreciation, depletion and amortization	2,248	1,930	2,108
General and administrative expenses	585	563	648
Taxes other than income taxes	424	380	314
Interest expense	352	363	349
Restructuring costs	(2)	57	105
Reduction of carrying value of oil and gas properties			6,408
Other, net	(10)	33	(83)
Total expenses and other, net	7,164	6,372	12,541
Earnings (loss) from continuing operations before income taxes	4,290	3,568	(4,526)
Current income tax (benefit) expense	(143)	516	241
Deferred income tax expense (benefit)	2,299	719	(2,014)
Earnings (loss) from continuing operations	2,134	2,333	(2,753)
Earnings from discontinued operations, net of income tax expense	2,570	2,217	274
Net earnings (loss)	4,704	4,550	(2,479)
Basic net earnings per share:
Basic earnings (loss) from continuing operations per share	$ 5.12	$ 5.31	$ (6.20)
Basic earnings from discontinued operations per share	$ 6.17	$ 5.04	$ 0.62
Basic net earnings (loss) per share	$ 11.29	$ 10.35	$ (5.58)
Diluted net earnings per share:
Diluted earnings (loss) from continuing operations per share	$ 5.10	$ 5.29	$ (6.20)
Diluted earnings from discontinued operations per share	$ 6.15	$ 5.02	$ 0.62
Diluted net earnings (loss) per share	$ 11.25	$ 10.31	$ (5.58)
Comprehensive earnings (loss):
Net earnings (loss)	4,704	4,550	(2,479)
Other comprehensive income, net of tax:
Foreign currency translation adjustments	(191)	377	931
Pension and postretirement plans	6	(2)	71
Other comprehensive (loss) earnings, net of tax	(185)	375	1,002
Comprehensive earnings (loss)	$ 4,519	$ 4,925	$ (1,477)

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2011

Asset Retirement Obligations [Abstract]

Schedule Of Asset Retirement Obligations

	Year Ended December 31,
	2011	2010
	(In millions)
Asset retirement obligations as of beginning of year	$     1,497	$     1,513
Liabilities incurred	53	55
Liabilities settled	(82)	(129)
Revision of estimated obligation	25	194
Liabilities assumed by others	—	(269)
Accretion expense on discounted obligation	92	92
Foreign currency translation adjustment	(22)	41
Asset retirement obligations as of end of year	1,563	1,497
Less current portion	67	74
Asset retirement obligations, long-term	$     1,496	$     1,423

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Retirement Plans (Schedule Of Estimated Net Actuarial Loss And Prior Service Cost For The Pension And Other Postretirement Plans That Will Be Amortized From Accumulated Other Comprehensive Income Into Net Periodic Benefit Cost During 2011) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss (gain)	$ 24
Prior service cost (credit)	3
Total	27
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss (gain)	(1)
Prior service cost (credit)	(1)
Total	$ (2)

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Supplemental Information On Oil And Gas Operations (Costs Incurred) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
U.S. Onshore [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Property acquisition costs, proved properties	$ 34	$ 29	$ 17
Property acquisition costs, unproved properties	851	592	52
Exploration costs	272	339	122
Development costs	4,130	3,126	2,011
Costs incurred	5,287	4,086	2,202
U.S. Offshore [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Property acquisition costs, proved properties
Property acquisition costs, unproved properties		2	11
Exploration costs		89	260
Development costs		297	537
Costs incurred		388	808
Total U.S [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Property acquisition costs, proved properties	34	29	17
Property acquisition costs, unproved properties	851	594	63
Exploration costs	272	428	382
Development costs	4,130	3,423	2,548
Costs incurred	5,287	4,474	3,010
Canada [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Property acquisition costs, proved properties	14	4	18
Property acquisition costs, unproved properties	88	590	72
Exploration costs	266	260	152
Development costs	1,288	1,216	835
Costs incurred	1,656	2,070	1,077
North America [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Property acquisition costs, proved properties	48	33	35
Property acquisition costs, unproved properties	939	1,184	135
Exploration costs	538	688	534
Development costs	5,418	4,639	3,383
Costs incurred	$ 6,943	$ 6,544	$ 4,087

XML

Consolidated Statements Of Stockholders' Equity (USD $) In Millions, except Share data	Common Shares [Member]	Additional Paid-In Capital [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Earnings [Member]	Treasury Stock [Member]	Total
Balance, at Dec. 31, 2008	$ 44	$ 6,257	$ 10,376	$ 383		$ 17,060
Balance, shares, at Dec. 31, 2008	444,000,000
Net earnings (loss)			(2,479)			(2,479)
Other comprehensive earnings (loss), net of tax				1,002		1,002
Stock option exercises	1	47			(5)	43
Stock option exercises, shares	1,000,000
Restricted stock grants, net of cancellations, shares	2,000,000
Common stock repurchased					(40)	(40)
Common stock repurchased, shares
Common stock retired		(45)			45
Common stock retired, shares
Common stock dividends			(284)			(284)
Share-based compensation		260				260
Share-based compensation tax benefits		8				8
Balance, at Dec. 31, 2009	45	6,527	7,613	1,385		15,570
Balance, shares, at Dec. 31, 2009	447,000,000
Net earnings (loss)			4,550			4,550
Other comprehensive earnings (loss), net of tax				375		375
Stock option exercises		117			(6)	111
Stock option exercises, shares	2,000,000
Restricted stock grants, net of cancellations, shares	2,000,000
Common stock repurchased					(1,246)	(1,246)
Common stock retired	(2)	(1,217)			1,219
Common stock retired, shares	(19,000,000)
Common stock dividends			(281)			(281)
Share-based compensation		158				158
Share-based compensation tax benefits		16				16
Balance, at Dec. 31, 2010	43	5,601	11,882	1,760	(33)	19,253
Balance, shares, at Dec. 31, 2010	432,000,000
Net earnings (loss)			4,704			4,704
Other comprehensive earnings (loss), net of tax				(185)		(185)
Stock option exercises		112			(11)	101
Stock option exercises, shares	2,000,000					2,366,000
Restricted stock grants, net of cancellations, shares	1,000,000
Common stock repurchased					(2,337)	(2,337)
Common stock retired	(3)	(2,378)			2,381
Common stock retired, shares	(31,000,000)
Common stock dividends			(278)			(278)
Share-based compensation		159				159
Share-based compensation tax benefits		13				13
Balance, at Dec. 31, 2011	$ 40	$ 3,507	$ 16,308	$ 1,575		$ 21,430
Balance, shares, at Dec. 31, 2011	404,000,000

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Retirement Plans (Schedule Of Projected Benefit Obligation And Accumulated Benefit Obligation In Excess Of Plan Assets) (Details) (Pension Plans With Projected And Accumulated Benefit Obligations In Excess Of Plan Assets [Member], USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Pension Plans With Projected And Accumulated Benefit Obligations In Excess Of Plan Assets [Member]
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation	$ 232	$ 1,110
Accumulated benefit obligation	189	996
Fair value of plan assets		$ 616

XML

Derivative Financial Instruments (Schedule Of Derivative Financial Instruments Included In The Consolidated Balance Sheets And Consolidated Comprehensive Statement Of Earnings) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Derivative [Line Items]
Fair value of derivative assets	$ 680	$ 389
Fair value of derivative liabilities	82	192
Total cash settlements	485	932	545
Total unrealized gains (losses)	401	(107)	(55)
Net gain recognized on comprehensive statements of earnings	886	825	490
Other Current Assets [Member]
Derivative [Line Items]
Fair value of derivative assets	641	348
Commodity Derivatives [Member]
Derivative [Line Items]
Total cash settlements	392	888	505
Total unrealized gains (losses)	489	(77)	(121)
Commodity Derivatives [Member] | Other Current Assets [Member]
Derivative [Line Items]
Fair value of derivative assets	611	248
Commodity Derivatives [Member] | Other Long-Term Assets [Member]
Derivative [Line Items]
Fair value of derivative assets	17	1
Commodity Derivatives [Member] | Other Current Liabilities [Member]
Derivative [Line Items]
Fair value of derivative liabilities	82	50
Commodity Derivatives [Member] | Other Long-Term Liabilities [Member]
Derivative [Line Items]
Fair value of derivative liabilities		142
Interest Rate Derivatives [Member]
Derivative [Line Items]
Total cash settlements	77	44	40
Total unrealized gains (losses)	88	30	(66)
Interest Rate Derivatives [Member] | Other Current Assets [Member]
Derivative [Line Items]
Fair value of derivative assets	30	100
Interest Rate Derivatives [Member] | Other Long-Term Assets [Member]
Derivative [Line Items]
Fair value of derivative assets	22	40
Foreign Exchange Derivatives [Member]
Derivative [Line Items]
Total cash settlements	$ 16

XML

Retirement Plans (Schedule Of Fair Values Of Pension Assets By Asset Class) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Defined Benefit Plan Disclosure [Line Items]
Total investments, sum of allocation percentages	100.00%	100.00%
Fair value measurements	$ 1,187	$ 632
Level 1 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value measurements	344	376
Level 2 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value measurements	753	198
Level 3 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value measurements	90	58
Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Equity securities, actual allocation	18.00%	50.80%
Fair value measurements	214	321
Equity Securities [Member] | Level 1 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value measurements		139
Equity Securities [Member] | Level 2 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value measurements	214	182
Equity Securities [Member] | United States Large Cap [Member]
Defined Benefit Plan Disclosure [Line Items]
Equity securities, actual allocation		22.30%
Fair value measurements		141
Equity Securities [Member] | United States Large Cap [Member] | Level 2 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value measurements		141
Equity Securities [Member] | United States Small Cap [Member]
Defined Benefit Plan Disclosure [Line Items]
Equity securities, actual allocation		14.10%
Fair value measurements		89
Equity Securities [Member] | United States Small Cap [Member] | Level 1 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value measurements		89
Equity Securities [Member] | International Large Cap [Member]
Defined Benefit Plan Disclosure [Line Items]
Equity securities, actual allocation		14.40%
Fair value measurements		91
Equity Securities [Member] | International Large Cap [Member] | Level 1 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value measurements		50
Equity Securities [Member] | International Large Cap [Member] | Level 2 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value measurements		41
Fixed Income Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fixed income securities, actual allocation	71.80%	37.50%
Fair value measurements	852	237
Fixed Income Securities [Member] | Level 1 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value measurements	328	237
Fixed Income Securities [Member] | Level 2 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value measurements	524
Fixed Income Securities [Member] | Corporate Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fixed income securities, actual allocation	24.80%	22.00%
Fair value measurements	294	139
Fixed Income Securities [Member] | Corporate Bonds [Member] | Level 1 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value measurements	265	139
Fixed Income Securities [Member] | Corporate Bonds [Member] | Level 2 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value measurements	29
Fixed Income Securities [Member] | United States Treasury Obligations [Member]
Defined Benefit Plan Disclosure [Line Items]
Fixed income securities, actual allocation	43.90%	10.90%
Fair value measurements	522	69
Fixed Income Securities [Member] | United States Treasury Obligations [Member] | Level 1 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value measurements	27	69
Fixed Income Securities [Member] | United States Treasury Obligations [Member] | Level 2 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value measurements	495
Fixed Income Securities [Member] | Other Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fixed income securities, actual allocation	3.10%	4.60%
Fair value measurements	36	29
Fixed Income Securities [Member] | Other Bonds [Member] | Level 1 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value measurements	36	29
Other Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Other securities, actual allocation	10.20%	11.70%
Fair value measurements	121	74
Other Securities [Member] | Level 1 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value measurements	16
Other Securities [Member] | Level 2 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value measurements	15	16
Other Securities [Member] | Level 3 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value measurements	90	58
Other Securities [Member] | Hedge Fund & Alternative Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Other securities, actual allocation	8.90%	9.20%
Fair value measurements	106	58
Other Securities [Member] | Hedge Fund & Alternative Investments [Member] | Level 1 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value measurements	16
Other Securities [Member] | Hedge Fund & Alternative Investments [Member] | Level 3 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value measurements	90	58
Other Securities [Member] | Short Term Investment Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Other securities, actual allocation	1.30%	2.50%
Fair value measurements	15	16
Other Securities [Member] | Short Term Investment Funds [Member] | Level 2 Inputs [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value measurements	$ 15	$ 16

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Other, Net (Tables)

12 Months Ended

Dec. 31, 2011

Other, Net [Abstract]

Components Of Other, Net

	Year Ended December 31,
	2011	2010	2009
	(In millions)
Accretion of asset retirement obligations	$92	$92	$91
Interest rate swaps – unrealized fair value changes	88	30	(66)
Interest rate swaps – cash settlements	(77)	(44)	(40)
Interest income	(21)	(13)	(8)
Other	(92)	(32)	(60)
Total	$(10)	$33	$(83)

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Share-Based Compensation (Summary Of Restricted Stock Awards And Units) (Details) (Performance Based Restricted Stock Awards [Member], USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2011
Performance Based Restricted Stock Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested at December 31, 2010
Performance Based Restricted Stock Awards, Granted	184
Unvested at December 31, 2011	184
Weighted Average Grant-Date Fair Value, Unvested at December 31, 2010
Weighted Average Grant-Date Fair Value, Granted	$ 65.10
Weighted Average Grant-Date Fair Value, Unvested at December 31, 2011	$ 65.10

XML

Retirement Plans

12 Months Ended

Dec. 31, 2011

Retirement Plans [Abstract]

Retirement Plans

16. Retirement Plans

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

The nonqualified plans provide retirement benefits for certain employees whose benefits under the qualified plans are limited by income tax regulations. The nonqualified benefits are based on the employees' years of service and compensation. For certain nonqualified plans, Devon has established trusts to fund these plans' benefit obligations. The total value of these trusts was $32 million and $36 million at December 31, 2011 and 2010, respectively, and is included in other long-term assets in the accompanying balance sheets. For the remaining nonqualified 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") that provide benefits for substantially all U.S. 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 Devon's future cost-sharing intentions. 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 and Funded Status

The following table presents the funded status of Devon's qualified and nonqualified pension and other postretirement benefit plans. 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, 2011 and 2010 was $1.2 billion and $1.0 billion, respectively. Devon's benefit obligations and plan assets are measured each year as of December 31. Devon's 2011 pension plan contributions of $454 million presented in the table were primarily discretionary. After these contributions, the projected benefit obligation for Devon's qualified plans was fully funded as of December 31, 2011.

	Pension Benefits		Postretirement Benefits
	2011	2010	2011	2010
	(In millions)
Change in benefit obligation:
Benefit obligation at beginning of year	$ 1,124	$    980	$       43	$       64
Service cost	37	33	1	1
Interest cost	60	58	2	3
Actuarial loss (gain)	123	82	(8)	1
Plan amendments	—	5	5	(22)
Plan settlements	—	—	(4)	—
Foreign exchange rate changes	(1)	2	—	—
Participant contributions	—	—	3	2
Benefits paid	(40)	(36)	(5)	(6)
Benefit obligation at end of year	1,303	1,124	37	43
Change in plan assets:
Fair value of plan assets at beginning of year	632	532	—	—
Actual return on plan assets	141	69	—	—
Employer contributions	454	66	7	4
Participant contributions	—	—	3	2
Plan settlements	—	—	(5)	—
Benefits paid	(40)	(36)	(5)	(6)
Foreign exchange rate changes	—	1	—	—
Fair value of plan assets at end of year	1,187	632	—	—
Funded status at end of year	$   (116)	$   (492)	$     (37)	$     (43)
Amounts recognized in balance sheet:
Noncurrent assets	$    116	$         2	$       —	$       —
Current liabilities	(10)	(9)	(3)	(4)
Noncurrent liabilities	(222)	(485)	(34)	(39)
Net amount	$   (116)	$   (492)	$     (37)	$     (43)
Amounts recognized in accumulated other   comprehensive earnings:
Net actuarial loss (gain)	$    348	$    357	$        (9)	$        (5)
Prior service cost (credit)	18	21	(5)	(12)
Total	$    366	$    378	$     (14)	$     (17)

The plan assets for pension benefits in the table above exclude the assets held in trusts for the nonqualified plans. However, employer contributions for pension benefits in the table above include $8 million for both 2011 and 2010, which were transferred from the trusts established for the nonqualified plans.

Certain of Devon's pension plans have a projected benefit obligation and accumulated benefit obligation in excess of plan assets at December 31, 2011 and 2010 as presented in the table below.

	December 31,
	2011	2010
	(In millions)
Projected benefit obligation	$      232	$   1,110
Accumulated benefit obligation	$      189	$      996
Fair value of plan assets	$         —	$      616

Net Periodic Benefit Cost and Other Comprehensive Earnings

The following table presents the components of net periodic benefit cost and other comprehensive earnings.

	Pension Benefits			Postretirement Benefits
	2011	2010	2009	2011	2010	2009
	(In millions)
Net periodic benefit cost:
Service cost	$       37	$        33	$       43	$          1	$        1	$         1
Interest cost	60	58	58	2	3	3
Expected return on plan assets	(42)	(36)	(35)	—	—	—
Curtailment and settlement expense	—	—	5	(3)	—	—
Recognition of net actuarial loss (gain)	32	27	45	—	—	(1)
Recognition of prior service cost	3	3	3	(2)	1	2
Total net periodic benefit cost	90	85	119	(2)	5	5
Other comprehensive earnings:
Actuarial loss (gain) arising in current year	23	50	(66)	(7)	1	7
Prior service cost (credit) arising in current year.	—	4	—	5	(22)	—
Recognition of net actuarial loss, including     settlement expense, in net periodic benefit cost	(32)	(27)	(45)	3	—	1
Recognition of prior service cost, including     curtailment, in net periodic benefit cost	(3)	(3)	(8)	2	(1)	(2)
Total other comprehensive (loss) earnings	(12)	24	(119)	3	(22)	6
Total recognized	$       78	$      109	$       —	$          1	$     (17)	$       11

The following table presents the estimated net actuarial loss and prior service cost that will be amortized from accumulated other comprehensive earnings into net periodic benefit cost during 2012.

	Pension Benefits	Postretirement      Benefits
	(In millions)
Net actuarial loss (gain)	$       24	$                (1)
Prior service cost (credit)	3	(1)
Total	$       27	$                (2)

Assumptions

The following table presents the weighted average actuarial assumptions used to determine obligations and periodic costs.

	Pension Benefits			Postretirement Benefits
	2011	2010	2009	2011	2010	2009
Assumptions to determine benefit obligations:
Discount rate	4.65%	5.50%	6.00%	4.25%	4.90%	5.70%
Rate of compensation increase	4.97%	6.94%	6.95%	N/A	N/A	N/A
Assumptions to determine net periodic benefit cost:
Discount rate	5.50%	6.00%	6.00%	4.90%	5.70%	6.00%
Expected return on plan assets	6.48%	6.94%	7.18%	N/A	N/A	N/A
Rate of compensation increase	6.94%	6.95%	6.95%	N/A	N/A	N/A

Discount rate – 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 future cash flows related to the plans. This rate is based on high-quality bond yields, after allowing for call and default risk.

Rate of compensation increase – For measurement of the 2011 benefit obligation for the pension plans, a 4.97% compensation increase was assumed.

Expected return on plan assets – 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. See the pension plan assets section below for more information on Devon's target allocations.

Other assumptions – For measurement of the 2011 benefit obligation for the other postretirement medical plans, an 8.2% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2012. The rate was assumed to decrease annually to an ultimate rate of 5% in the year 2029 and remain at that level thereafter. Assumed health care cost-trend rates affect the amounts reported for retiree health care costs. A one-percentage-point change in the assumed health care cost-trend rates would have changed the postretirement benefits obligation as of December 31, 2011, by $2 million and would change the 2012 service and interest cost components of net periodic benefit cost by less than $1 million.

Pension Plan Assets

Devon's overall investment objective for its pension plans' assets is to achieve stability of the plans' funded status while providing long-term growth of invested capital and income to ensure benefit payments 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. Derivatives or other speculative investments considered high risk are generally prohibited. The following table presents Devon's target allocation for its pension plan assets. Devon made significant contributions to its qualified pension plans in 2011. As a result, Devon revised its target allocations in 2011.

	December 31,
	2011	2010
Fixed income	70%	40%
Equity	20%	47.5%
Other	10%	12.5%

The fair values of Devon's pension assets are presented by asset class in the following tables.

	As of December 31, 2011
			Fair Value Measurements Using:
	Actual Allocation	Total	Level 1 Inputs	Level 2 Inputs	Level 3 Inputs
	($ In millions)
Fixed-income securities:
U.S. Treasury obligations	43.9%	$           522	$              27	$           495	$              —
Corporate bonds	24.8%	294	265	29	—
Other bonds	3.1%	36	36	—	—
Total fixed-income securities	71.8%	852	328	524	—
Equity securities:
Global (large, mid, small cap)	18.0%	214	—	214	—
Other securities:
Hedge fund & alternative investments.	8.9%	106	16	—	90
Short-term investment funds	1.3%	15	—	15	—
Total other securities	10.2%	121	16	15	90
Total investments	100.0%	$        1,187	$           344	$           753	$              90

	As of December 31, 2010
			Fair Value Measurements Using:
	Actual Allocation	Total	Level 1 Inputs	Level 2 Inputs	Level 3 Inputs
	($ In millions)
Equity securities:
U.S. large cap	22.3%	$           141	$              —	$           141	$              —
U.S. small cap	14.1%	89	89	—	—
International large cap	14.4%	91	50	41	—
Total equity securities	50.8%	321	139	182	—
Fixed-income securities:
Corporate bonds	22.0%	139	139	—	—
U.S. Treasury obligations	10.9%	69	69	—	—
Other bonds	4.6%	29	29	—	—
Total fixed-income securities	37.5%	237	237	—	—
Other securities:
Hedge funds	9.2%	58	—	—	58
Short-term investment funds	2.5%	16	—	16	—
Total other securities	11.7%	74	—	16	58
Total investments	100.0%	$           632	$           376	$           198	$              58

The following methods and assumptions were used to estimate the fair values in the tables above.

Fixed-income securities – Devon's fixed-income securities consist of United States Treasury obligations, bonds issued by investment-grade companies from diverse industries, and asset-backed securities. These fixed-income securities are actively traded securities that can be redeemed upon demand. The fair values of these Level 1 securities are based upon quoted market prices.

Devon's fixed income securities also include commingled funds that primarily invest in long-term bonds and U.S. Treasury securities. These fixed income securities can be redeemed on demand but are not actively traded. The fair values of these Level 2 securities are based upon the net asset values provided by the investment managers.

Equity securities – Devon's equity securities include a commingled global equity fund that invests in large, mid and small capitalization stocks across the world's developed and emerging markets. These equity securities can be redeemed on demand but are not actively traded. The fair values of these Level 2 securities are based upon the net asset values provided by the investment managers.

At December 31, 2010, Devon's equity securities consisted of investments in United States large and small capitalization companies and international large capitalization companies. These equity securities were actively traded securities that could be redeemed upon demand. The fair values of these Level 1 securities are based upon quoted market prices.

At December 31, 2010, Devon's equity securities also included a commingled fund that invested in large capitalization companies. These equity securities could be redeemed on demand but were not actively traded. The fair values of these Level 2 securities are based upon the net asset values provided by the investment managers.

Other securities – Devon's other securities include commingled, short-term investment funds. These securities can be redeemed on demand but are not actively traded. The fair values of these Level 2 securities are based upon the net asset values provided by investment managers.

Devon other securities include an investment in an actively traded global mutual fund that focuses on alternative investment strategies and a hedge fund of funds that invests both long and short using a variety of investment strategies. Management of the hedge fund has the ability to shift investments from value to growth strategies, from small to large capitalization stocks, and from a net long position to a net short position. Devon's hedge fund is not actively traded and Devon is subject to redemption restrictions with regards to this investment. The fair value of this Level 3 investment represents the fair value as determined by the hedge fund manager.

Included below is a summary of the changes in Devon's Level 3 plan assets (in millions).

December 31, 2009	$               51
Purchases	3
Investment returns	4
December 31, 2010	58
Purchases	33
Investment returns	(1)
December 31, 2011	$               90

Expected Cash Flows

The following table presents expected cash flow information for Devon's pension and other postretirement benefit plans.

	Pension Benefits	Postretirement Benefits
	(In millions)
Devon's 2012 contributions	$           9	$                 3
Benefit payments:
2012	$         44	$                 3
2013	$         49	$                 3
2014	$         52	$                 3
2015	$         56	$                 3
2016	$         61	$                 3
2017 to 2021	$       390	$               14

Expected contributions included in the table above include amounts related to Devon's qualified plans, nonqualified plans and Postretirement Plans. Of the benefits expected to be paid in 2012, the $9 million of pension benefits is expected to be funded from the trusts established for the nonqualified and the $3 million of other postretirement benefits 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.

Defined Contribution Plans

Devon maintains several defined contribution plans covering its employees in the U.S. and Canada. Such plans include Devon's 401(k) plan, enhanced contribution plan and Canadian pension and savings plan. Contributions are primarily based upon percentages of annual compensation and years of service. In addition, each plan is subject to regulatory limitations by each respective government. The following table presents Devon's expense related to these defined contribution plans.

	Year Ended December 31,
	2011	2010	2009
	(In millions)
401(k) and enhanced contribution plans	$     33	$     32	$     34
Canadian pension and savings plans	21	17	15
Total	$     54	$     49	$     49

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2011

Income Taxes [Abstract]

Schedule Of Income Tax Expense (Benefit)

	Year Ended December 31,
	2011	2010	2009
	(In millions)
Current income tax (benefit) expense:
U.S. federal	$       (143)	$         244	$           45
Various states	20	16	18
Canada and various provinces	(20)	256	178
Total current tax (benefit) expense	(143)	516	241
Deferred income tax expense (benefit):
U.S. federal	1,986	781	(1,846)
Various states	95	21	(111)
Canada and various provinces	218	(83)	(57)
Total deferred tax expense (benefit)	2,299	719	(2,014)
Total income tax expense (benefit)	$     2,156	$     1,235	$    (1,773)

Schedule Of Effective Income Tax Reconciliation

	Year Ended December 31,
	2011	2010	2009
	(In millions)
Expected income tax expense (benefit) based on U.S. statutory tax   rate of 35%	$     1,502	$     1,249	$    (1,584)
Assumed repatriations.	725	144	55
State income taxes	70	31	(99)
Taxation on Canadian operations	(91)	(60)	(31)
Other	(50)	(129)	(114)
Total income tax expense (benefit)	$     2,156	$     1,235	$    (1,773)

Schedule Of Deferred Tax Assets And Liabilities

	December 31,
	2011	2010
Deferred tax assets:	(In millions)
Net operating loss carryforwards	$        222	$        159
Asset retirement obligations	447	494
Pension benefit obligations	130	133
Other	117	171
Total deferred tax assets	916	957
Deferred tax liabilities:
Property and equipment	(4,475)	(3,130)
Fair value of financial instruments	(218)	(70)
Long-term debt	(185)	(198)
Taxes on unremitted foreign earnings (	(936)	(211)
Other	(27)	(20)
Total deferred tax liabilities	(5,841)	(3,629)
Net deferred tax liability	$    (4,925)	$    (2,672)

Schedule Of Changes In Unrecognized Tax Benefits

	December 31,
	2011	2010
	(In millions)
Balance at beginning of year	$        194	$        272
Tax positions taken in prior periods	(3)	40
Tax positions taken in current year	27	5
Accrual of interest related to tax positions taken	(7)	9
Lapse of statute of limitations	(41)	(5)
Settlements	(5)	(129)
Foreign currency translation	—	2
Balance at end of year	$        165	$        194

Summary Of The Tax Years By Jurisdiction That Remain Subject To Examination By Taxing Authorities

Jurisdiction	Tax Years Open
U.S. federal	2008-2011
Various U.S. states	2007-2011
Canada federal	2003-2011
Various Canadian provinces	2003-2011

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Retirement Plans (Schedule Of Pension Plan Assets Target Allocation) (Details)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Retirement Plans [Abstract]
Fixed income	70.00%	40.00%
Equity	20.00%	47.50%
Other	10.00%	12.50%

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Supplemental Quarterly Financial Information (Schedule Of Quarterly Financial Information) (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Supplemental Quarterly Financial Information [Abstract]
Revenues	$ 2,585	$ 3,502	$ 3,220	$ 2,147	$ 2,135	$ 2,353	$ 2,232	$ 3,220	$ 11,454	$ 9,940	$ 8,015
Earnings (loss) from continuing operations before income taxes	794	1,538	1,378	580	668	699	613	1,588	4,290	3,568	(4,526)
Earnings (loss) from continuing operations	521	1,040	184	389	478	429	352	1,074	2,134	2,333	(2,753)
Earnings (loss) from discontinued operations	(14)	(2)	2,559	27	84	1,661	354	118	2,570	2,217	274
Net (loss) earnings	$ 507	$ 1,038	$ 2,743	$ 416	$ 562	$ 2,090	$ 706	$ 1,192	$ 4,704	$ 4,550	$ (2,479)
Basic earnings (loss) from continuing operations per share	$ 1.29	$ 2.51	$ 0.44	$ 0.91	$ 1.10	$ 0.99	$ 0.79	$ 2.40	$ 5.12	$ 5.31	$ (6.20)
Basic earnings (loss) from discontinued operations per share	$ (0.04)		$ 6.06	$ 0.06	$ 0.20	$ 3.82	$ 0.80	$ 0.27	$ 6.17	$ 5.04	$ 0.62
Net (loss) earnings - basic	$ 1.25	$ 2.51	$ 6.50	$ 0.97	$ 1.30	$ 4.81	$ 1.59	$ 2.67	$ 11.29	$ 10.35	$ (5.58)
Diluted earnings (loss) from continuing operations per share	$ 1.29	$ 2.50	$ 0.43	$ 0.91	$ 1.10	$ 0.98	$ 0.79	$ 2.39	$ 5.10	$ 5.29	$ (6.20)
Diluted earnings (loss) from discontinued operations per share	$ (0.04)		$ 6.05	$ 0.06	$ 0.19	$ 3.81	$ 0.79	$ 0.27	$ 6.15	$ 5.02	$ 0.62
Net (loss) earnings - diluted	$ 1.25	$ 2.50	$ 6.48	$ 0.97	$ 1.29	$ 4.79	$ 1.58	$ 2.66	$ 11.25	$ 10.31	$ (5.58)

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Commitments And Contingencies

12 Months Ended

Dec. 31, 2011

Commitments And Contingencies [Abstract]

Commitments And Contingencies

18. 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 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.

Royalty Matters

Numerous natural 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 NGLs produced and sold from federal and Indian owned or controlled lands. Devon does not currently believe that it is subject to material exposure with respect to such royalty matters.

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 and similar state statutes. In response to liabilities associated with these activities, loss accruals primarily consist of estimated uninsured costs associated with remediation. Devon's monetary exposure for environmental matters is not expected to be material.

Chief Redemption Matters

In 2006, Devon acquired Chief Holdings LLC ("Chief") from the owners of Chief, including Trevor Rees-Jones, the majority owner of Chief. In 2008, a former owner of Chief filed a petition against Rees-Jones, as the former majority owner of Chief, and Devon, as Chief's successor pursuant to the 2006 acquisition. The petition claimed, among other things, violations of the Texas Securities Act, fraud and breaches of Rees-Jones' fiduciary responsibility to the former owner in connection with Chief's 2004 redemption of the owner's minority ownership stake in Chief.

On June 20, 2011, a court issued a judgment against Rees-Jones for $196 million, of which $133 million of the judgment was also issued against Devon. Both Rees-Jones and Devon are appealing the judgment. However, if the appeal is unsuccessful, Devon can and will seek full payment of the judgment and any related interest, costs and expenses from Rees-Jones pursuant to an existing indemnification agreement between Rees-Jones, certain other parties and Devon. Devon does not expect to have any net exposure as a result of the judgment. However, because Devon does not have a legal right of set off with respect to the judgment, Devon has recorded in its December 31, 2011, balance sheet both a $133 million liability relating to the judgment with an offsetting $133 million receivable relating to its right to be indemnified by Rees-Jones and certain other parties pursuant to the indemnification agreement.

Other Matters

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

Commitments

The following is a schedule by year of Devon's commitments that have initial or remaining noncancelable lease terms in excess of one year as of December 31, 2011.

Year Ending December 31,	Purchase Obligations	Drilling and Facility Obligations	Operational Agreements	Office and Equipment Leases
	(In millions)
2012	$         900	$         919	$              306	$         63
2013	905	456	302	56
2014	905	100	283	47
2015	905	—	250	44
2016	924	—	209	43
Thereafter	3,915	—	786	220
Total	$     8,454	$     1,475	$           2,136	$      473

Devon has certain purchase obligations related to its heavy oil projects in Canada to purchase condensate at market prices. Devon entered into these agreements because the condensate is an integral part of the heavy oil production process and any disruption in Devon's ability to obtain condensate could negatively affect its ability to produce and transport heavy oil at these locations. Devon's total obligation related to condensate purchases expires in 2021. The value of these purchase obligations presented in the table above is based on the contractual volumes and Devon's internal estimate of future condensate market prices.

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

Devon has certain operational agreements whereby Devon has committed to ship or process certain volumes of oil, gas and NGLs for a fixed fee. Devon has entered into these agreements to aid the movement of its production to market.

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 $42 million, $57 million and $56 million in 2011, 2010 and 2009, respectively.

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Restructuring Costs (Schedule Of The Components Of Restructuring Costs Included In The Consolidated Statements Of Earnings) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Restructuring Cost and Reserve [Line Items]
Restructuring costs	$ (2)	$ 57	$ 105
Discontinued Operations [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring costs	(2)	(4)	48
Cash Severance [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring costs	9	(17)	66
Asset Impairments [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring costs	2	11
Lease Obligations [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring costs	(13)	70
Share-Based Awards [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring costs	(1)	(10)	39
Other [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring costs	$ 1	$ 3

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Discontinued Operations (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Expected proceeds on divestiture of assets	$ 70
Revenues related to discontinued operations	43	693	945
Earnings from discontinued operations before income taxes	2,600	2,400	322
Impairment of Oil and Gas Properties			6,408
Brazil [Member] | After-Tax [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Impairment of Oil and Gas Properties			105
Brazil [Member] | Gross [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Impairment of Oil and Gas Properties			$ 109

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Summary Of Significant Accounting Policies

12 Months Ended

Dec. 31, 2011

Summary Of Significant Accounting Policies [Abstract]

Summary Of Significant Accounting Policies

1. Summary of Significant Accounting Policies

Devon Energy Corporation ("Devon") is a leading independent energy company engaged primarily in the exploration, development and production of oil and natural gas. Devon's operations are concentrated in various North American onshore areas in the U.S. and Canada. Devon also owns natural gas pipelines, plants and treatment facilities in many of its producing areas, making it one of North America's larger processors of natural gas.

Accounting policies used by Devon and its subsidiaries conform to accounting principles generally accepted in the United States of America and reflect industry practices. The more significant of such policies are discussed below.

Principles of Consolidation

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

Use of Estimates

The preparation of financial statements 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 the following:

• proved reserves and related present value of future net revenues;

• the carrying value of oil and gas properties;

• derivative financial instruments;

• the fair value of reporting units and related assessment of goodwill for impairment;

• income taxes;

• asset retirement obligations;

• obligations related to employee pension and postretirement benefits; and

• legal and environmental risks and exposures.

Revenue Recognition and Gas Balancing

Oil, gas and NGL sales are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectability of the revenue is probable. Delivery occurs and title is transferred when production has been delivered to a pipeline, railcar or truck. Cash received relating to future production is deferred and recognized when all revenue recognition criteria are met. Taxes assessed by governmental authorities on oil, gas and NGL sales are presented separately from such revenues in the accompanying comprehensive statements of earnings.

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 differences create imbalances that are recognized as a liability only when the estimated remaining reserves will not be sufficient to enable the underproduced owner to recoup its entitled share through production. 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. 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.

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, delivery or performance has occurred, title has transferred and collectability of the revenue is probable. Revenues and expenses attributable to oil, gas and NGL purchases, transportation and processing contracts are reported on a gross basis when Devon takes title to the products and has risks and rewards of ownership.

During 2011, 2010 and 2009, no purchaser accounted for more than 10 percent of Devon's revenues from continuing operations.

Derivative Financial Instruments

Devon is exposed to certain risks relating to its ongoing business operations, including risks related to commodity prices, interest rates and Canadian to U.S. dollar exchange rates. As discussed more fully below, Devon uses derivative instruments primarily to manage commodity price risk and interest rate risk. Devon does not hold or issue derivative financial instruments for speculative trading purposes.

Devon periodically enters into derivative financial instruments with respect to a portion of its oil, gas and NGL production that hedge the future prices received. These instruments are used to manage the inherent uncertainty of future revenues due to commodity price volatility. Devon's derivative financial instruments include financial price swaps, basis swaps, costless price collars and call options. Under the terms of the price swaps, Devon receives a fixed price for its production and pays a variable market price to the contract counterparty. For the basis swaps, Devon receives a fixed differential between two regional gas index prices and pays a variable differential on the same two index prices to the contract counterparty. The price collars set a floor and ceiling price for the hedged production. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, Devon will cash-settle the difference with the counterparty to the collars. The call options give counterparties the right to purchase production at a predetermined price.

Devon periodically enters into interest rate swaps to manage its exposure to interest rate volatility. Devon's interest rate swaps include contracts in which Devon receives a fixed rate and pays a variable rate on a total notional amount.

All derivative financial instruments are recognized at their current fair value as either assets or liabilities in the balance sheet. Changes in the fair value of these derivative financial instruments are recorded in earnings unless specific hedge accounting criteria are met. For derivative financial instruments held during the three-year period ended December 31, 2011, Devon chose not to meet the necessary criteria to qualify its derivative financial instruments for hedge accounting treatment. Cash settlements with counterparties on Devon's derivative financial instruments are also recorded in earnings.

By using derivative financial instruments to hedge exposures to changes in commodity prices and interest rates, Devon is exposed to credit 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 a number of counterparties whom 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. Additionally, Devon's derivative contracts generally require cash collateral to be posted if either its or the counterparty's credit rating falls below certain credit rating levels. The mark-to-market exposure threshold, above which collateral must be posted, decreases as the debt rating falls further below such credit levels. Thresholds generally range from zero to $55 million for the majority of Devon's contracts. As of December 31, 2011, the credit ratings of all Devon's counterparties were investment grade.

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.

Share Based Compensation

Devon grants stock options, restricted stock awards and other types of share-based awards to members of its Board of Directors and selected employees. All such awards are measured at fair value on the date of grant and are recognized as a component of general and administrative expenses in the accompanying comprehensive statements of earnings over the applicable requisite service periods. As a result of Devon's strategic repositioning announced in 2009, certain share based awards were accelerated and recognized as a component of restructuring expense in the accompanying comprehensive statements of earnings.

Generally, Devon uses new shares from approved incentive programs to grant share-based awards and to issue shares upon stock option exercises. Shares repurchased under approved programs are available to be issued as part of Devon's share based awards. However, Devon has historically cancelled these shares upon repurchase.

Income Taxes

Devon is subject to current income taxes assessed by the federal and various state jurisdictions in the U.S. and by other foreign jurisdictions. In addition, Devon accounts for deferred income taxes related to these jurisdictions using the asset and liability method. Under this method, 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. Deferred tax assets are also recognized for the future tax benefits attributable to the expected utilization of existing tax net operating loss carryforwards and other types of carryforwards. If the future utilization of some portion of carryforwards is determined to be unlikely, a valuation allowance is provided to reduce the recorded tax benefits from such assets. 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.

Devon does not recognize U.S. deferred income taxes on the unremitted earnings of its foreign subsidiaries that are deemed to be permanently reinvested. When such earnings are no longer deemed permanently reinvested, Devon recognizes the appropriate deferred, or even current, income tax liabilities.

Devon recognizes the financial statement effects of tax positions when it is more likely than not, based on the technical merits, that the position will be sustained upon examination by a taxing authority. Recognized tax positions are initially and subsequently measured as the largest amount of tax benefit that is more likely than not of being realized upon ultimate settlement with a taxing authority. Liabilities for unrecognized tax benefits related to such tax positions are included in other long-term liabilities unless the tax position is expected to be settled within the upcoming year, in which case the liabilities are included in other current liabilities. Interest and penalties related to unrecognized tax benefits are included in current income tax expense.

Net Earnings (Loss) Per Common Share

Devon's basic earnings per share amounts have been computed based on the average number of shares of common stock outstanding for the period. Basic earnings per share includes the effect of participating securities, which primarily consist of Devon's outstanding restricted stock awards. Diluted earnings per share is calculated using the treasury stock method to reflect the assumed issuance of common shares for all potentially dilutive securities. Such securities primarily consist of outstanding stock options.

Cash and Cash Equivalents

Devon considers all highly liquid investments with original contractual maturities of three months or less to be cash equivalents.

Investments

Devon periodically invests excess cash in U.S. and Canadian Treasury securities and other marketable securities. During 2011, Devon invested a portion of the International offshore divestiture proceeds into such securities, causing short-term investments to increase.

Devon considers securities with original contractual maturities in excess of three months, but less than one year to be short-term investments. Investments with contractual maturities in excess of one year are classified as long-term, unless such investments are classified as trading or available-for-sale.

Devon reports its investments and other marketable securities at fair value, except for debt securities in which management has the ability and intent to hold until maturity. Such debt securities totaled $84 million and $94 million at December 31, 2011 and 2010, respectively and are included in other long-term assets in the accompanying balance sheet. Devon has the ability to hold the securities until maturity and does not believe the values of its long-term securities are impaired.

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 that 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. 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.

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 estimated after-tax future net revenues, discounted at 10 percent per annum, from proved oil, 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 tested quarterly and imposed separately on a country-by-country basis.

Future net revenues are calculated using prices that represent the average of the first-day-of-the-month price for the 12-month period prior to the end of the period. Prices are held constant indefinitely and are not changed except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including derivative contracts in place that qualify for hedge accounting treatment. None of Devon's derivative contracts held during the three-year period ended December 31, 2011, qualified for hedge accounting treatment.

Any excess of the net book value, less related deferred taxes, over the ceiling is written off as an expense. An expense recorded in one period may not be reversed in a subsequent period even though higher commodity prices may have increased the ceiling applicable to the subsequent period.

Capitalized costs are depleted by an equivalent unit-of-production method, converting gas to oil at the ratio of six thousand cubic feet of 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.

Costs associated with unproved properties are excluded from the depletion calculation 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 into the depletion calculation over holding periods ranging from three to six years.

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.

Depreciation of midstream pipelines are provided on a unit-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 ranging from three to 39 years. Interest costs incurred and attributable to major midstream and corporate construction projects are also capitalized.

Devon recognizes liabilities for retirement obligations associated with tangible long-lived assets, such as producing well sites and midstream pipelines and processing plants when there is a legal obligation associated with the retirement of such assets and the amount can be reasonably estimated. The initial measurement of an asset retirement obligation is recorded as a liability at its fair value, with an offsetting asset retirement cost recorded as an increase to the associated property and equipment on the consolidated balance sheet. When the assumptions used to estimate a recorded asset retirement obligation change, a revision is recorded to both the asset retirement obligation and the asset retirement cost. The asset retirement cost is depreciated using a systematic and rational method similar to that used for the associated property and equipment.

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. Such test includes an assessment of qualitative and quantiative factors. 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 2011, 2010 and 2009. Based on these assessments, no impairment of goodwill was required.

The table below provides a summary of Devon's goodwill, by assigned reporting unit. The decrease in Devon's goodwill from 2010 to 2011 was due to changes in the exchange rate between the U.S. dollar and the Canadian dollar.

	December 31,
	2011	2010
	(In millions)
U.S.	$   3,046	$   3,046
Canada	2,967	3,034
Total	$   6,013	$   6,080

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. Liabilities for environmental remediation or restoration claims are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. Expenditures related to such environmental matters are expensed or capitalized in accordance with Devon's accounting policy for property and equipment.

Fair Value Measurements

Certain of Devon's assets and liabilities are measured at fair value at each reporting date. Fair value represents the price that would be received to sell the asset or paid to transfer the liability in an orderly transaction between market participants. This price is commonly referred to as the "exit price." Fair value measurements are classified according to a hierarchy that prioritizes the inputs underlying the valuation techniques. This hierarchy consists of three broad levels:

·Level 1 - Inputs consist of unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. When available, Devon measures fair value using Level 1 inputs because they generally provide the most reliable evidence of fair value.

·Level 2 – Inputs consist of quoted prices that are generally observable for the asset or liability. Common examples of Level 2 inputs include quoted prices for similar assets and liabilities in active markets or quoted prices for identical assets and liabilities in markets not considered to be active.

·Level 3 - Inputs are not observable from objective sources and have the lowest priority. The most common Level 3 fair value measurement is an internally developed cash flow model.

Discontinued Operations

As a result of the November 2009 plan to divest Devon's offshore assets, all amounts related to Devon's International operations are classified as discontinued operations. The Gulf of Mexico properties that were divested in 2010 do not qualify as discontinued operations under accounting rules. As such, amounts in these notes and the accompanying financial statements that pertain to continuing operations include amounts related to Devon's offshore Gulf of Mexico operations.

The captions assets held for sale and liabilities associated with assets held for sale in the accompanying balance sheets present the assets and liabilities associated with Devon's discontinued operations. Devon measures its assets held for sale at the lower of its carrying amount or estimated fair value less costs to sell. Additionally, Devon does not recognize depreciation, depletion and amortization on its long-lived assets held for sale.

Foreign Currency Translation Adjustments

       The U.S. dollar is the functional currency for Devon's consolidated operations except its Canadian subsidiaries, which use the Canadian dollar as the 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. Canadian 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 earnings in stockholders' equity.

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Consolidated Statements Of Cash Flows (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Cash flows from operating activities:
Net earnings (loss)	$ 4,704	$ 4,550	$ (2,479)
Earnings from discontinued operations, net of tax	(2,570)	(2,217)	(274)
Adjustments to reconcile earnings (loss) from continuing operations to net cash provided by operating activities:
Depreciation, depletion and amortization	2,248	1,930	2,108
Deferred income tax expense (benefit)	2,299	719	(2,014)
Unrealized change in fair value of financial instruments	(401)	107	55
Reduction of carrying value of oil and gas properties			6,408
Other noncash charges	241	215	288
Net decrease (increase) in working capital	185	(273)	149
Decrease (increase) in long-term other assets	33	32	(6)
Decrease in long-term other liabilities	(493)	(41)	(3)
Cash from operating activities - continuing operations	6,246	5,022	4,232
Cash from operating activities - discontinued operations	(22)	456	505
Net cash from operating activities	6,224	5,478	4,737
Cash flows from investing activities:
Capital expenditures	(7,534)	(6,476)	(4,879)
Proceeds from property and equipment divestitures	129	4,310	34
Purchases of short-term investments	(6,691)	(145)
Redemptions of short-term investments	5,333
Redemptions of long-term investments	10	21	7
Other	(39)	(19)	(17)
Cash from investing activities - continuing operations	(8,792)	(2,309)	(4,855)
Cash from investing activities - discontinued operations	3,146	2,197	(499)
Net cash from investing activities	(5,646)	(112)	(5,354)
Cash flows from financing activities:
Net commercial paper borrowings (repayments)	3,726	(1,432)	426
Proceeds from borrowings of long-term debt, net of issuance costs	2,221		1,187
Debt repayments	(1,760)	(350)	(178)
Proceeds from stock option exercises	101	111	42
Repurchases of common stock	(2,332)	(1,168)
Dividends paid on common stock	(278)	(281)	(284)
Excess tax benefits related to share-based compensation	13	16	8
Net cash from financing activities	1,691	(3,104)	1,201
Effect of exchange rate changes on cash	(4)	17	43
Net increase in cash and cash equivalents	2,265	2,279	627
Cash and cash equivalents at beginning of period (including cash related to assets previously held for sale in 2010 and 2009)	3,290	1,011	384
Cash and cash equivalents at end of period (including cash related to assets previously held for sale in 2010 and 2009)	$ 5,555	$ 3,290	$ 1,011

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Accounts Receivable

12 Months Ended

Dec. 31, 2011

Accounts Receivable [Abstract]

Accounts Receivable

11. Accounts Receivable

The components of accounts receivable include the following:

	December 31,
	2011	2010
	(In millions)
Oil, gas and NGL sales	$        928	$        786
Joint interest billings	247	204
Marketing and midstream revenues	174	165
Other	39	57
Gross accounts receivable	1,388	1,212
Allowance for doubtful accounts	(9)	(10)
Net accounts receivable	$     1,379	$     1,202

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Stockholders' Equity (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Schedule of Capitalization, Equity [Line Items]
Authorized capital stock, common stock shares	1,000,000,000	1,000,000,000
Common stock par value per share	$ 0.10	$ 0.1
Authorized capital stock, preferred stock shares	4,500,000
Preferred stock par value per share	$ 1.00
Redemption price multiplier	100
Authorized repurchase of common shares under share repurchase program	$ 3,500,000,000
Repurchases of common stock	3,500,000,000
Common shares repurchased	49,200,000
Repurchase amount of common shares per share	$ 71.18
Payments of ordinary dividends	278,000,000	281,000,000	284,000,000
Common stock, cash paid on dividends, per share	$ 0.67	$ 0.64	$ 0.64
Stock Repurchase Program 2010 [Member]
Schedule of Capitalization, Equity [Line Items]
Repurchases of common stock	$ 2,299,000,000	$ 1,201,000,000
Common shares repurchased	30,900,000	18,300,000
Repurchase amount of common shares per share	$ 74.49	$ 65.58
Series A Junior Participating Preferred Stock [Member]
Schedule of Capitalization, Equity [Line Items]
Authorized capital stock, preferred stock shares	2,900,000
Preferred stock issued	0
Preferred stock outstanding	0
Cumulative quarterly dividends per share, minimum	$ 1.00
Preferred stock cumulative quarterly dividends aggregate per share multiplier	100
Preferred stock, number of votes per share held	100
Maximum [Member]
Schedule of Capitalization, Equity [Line Items]
Common stock, cash paid on dividends, per share	$ 0.17
Minimum [Member]
Schedule of Capitalization, Equity [Line Items]
Common stock, cash paid on dividends, per share	$ 0.16

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Retirement Plans (Schedule Of Changes In Defined Benefit Plan Obligations)(Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at beginning of year	$ 632
Employer contributions	454
Fair value of plan assets at end of year	1,187
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation at beginning of year, Other Postretirement Benefits	1,000
Benefit obligation at beginning of year,pension benefits	1,124	980
Service cost	37	33	43
Interest cost	60	58	58
Actuarial loss (gain)	123	82
Plan amendments		5
Foreign exchange rate changes	(1)	2
Benefits paid	(40)	(36)
Benefit obligation at end of year, pension benefits	1,303	1,124	980
Benefit obligation at end of year, Other Postretirement Benefits	1,200	1,000
Fair value of plan assets at beginning of year	632	532
Actual return on plan assets	141	69
Employer contributions	454	66
Foreign exchange rate changes		1
Fair value of plan assets at end of year	1,187	632	532
Funded status at end of year	(116)	(492)
Noncurrent assets	116	2
Current liabilities	(10)	(9)
Noncurrent liabilities	(222)	(485)
Net amount	(116)	(492)
Net actuarial loss (gain)	348	357
Prior service cost (credit)	18	21
Total	366	378
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation at beginning of year, Other Postretirement Benefits	43	64
Service cost	1	1	1
Interest cost	2	3	3
Actuarial loss (gain)	(8)	1
Plan amendments	5	(22)
Plan settlements	(4)
Participant contributions	3	2
Benefits paid	(5)	(6)
Benefit obligation at end of year, Other Postretirement Benefits	37	43	64
Employer contributions	7	4
Plan settlements	(5)
Funded status at end of year	(37)	(43)
Current liabilities	(3)	(4)
Noncurrent liabilities	(34)	(39)
Net amount	(37)	(43)
Net actuarial loss (gain)	(9)	(5)
Prior service cost (credit)	(5)	(12)
Total	$ (14)	$ (17)

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Asset Retirement Obligations (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Asset Retirement Obligation Disclosure [Line Items]
Asset retirement obligations as of beginning of year	$ 1,497	$ 1,513
Liabilities incurred	53	55
Liabilities settled	(82)	(129)
Revision of estimated obligation	25	194
Accretion expense on discounted obligation	92	92	91
Foreign currency translation adjustment	(22)	41
Asset retirement obligations as of end of year	1,563	1,497	1,513
Less current portion	67	74
Asset retirement obligations, long-term	1,496	1,423
Assumed By Others [Member]
Asset Retirement Obligation Disclosure [Line Items]
Liabilities settled		$ (269)

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Supplemental Quarterly Financial Information (Narrative) (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended			3 Months Ended				12 Months Ended			3 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Jun. 30, 2011 Discontinued Operations [Member]	Sep. 30, 2010 Discontinued Operations [Member]	Jun. 30, 2010 Discontinued Operations [Member]	Jun. 30, 2011 Assumed Repatriation Of Earnings [Member]	Dec. 31, 2011 Assumed Repatriation Of Earnings [Member]	Dec. 31, 2010 Assumed Repatriation Of Earnings [Member]	Dec. 31, 2009 Assumed Repatriation Of Earnings [Member]	Jun. 30, 2011 Assumed Repatriation Of Earnings [Member] Continuing Operations [Member]
Total deferred tax	$ 2,299	$ 719	$ (2,014)					$ 725	$ 144	$ 55	$ 725
Impact on diluted shares due to deferred income taxes							$ 1.71
Impact on diluted shares due to restructuring costs				$ 6.01	$ 3.49	$ 0.52
Gain on divestiture of operations	2,552	1,818	17	2,500	1,500	308
Gain on divestiture of operations, after-tax	$ 2,552	$ 1,732	$ 17	$ 2,500	$ 1,500	$ 235

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Supplemental Information On Oil And Gas Operations (Standardized Measure Of Discounted Future Net Cash Flows Related To Interest In Proved Reserves) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
United States [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash flows	$ 69,305	$ 58,093	$ 44,571
Future costs development	(6,817)	(6,220)	(6,814)
Future costs production	(26,217)	(24,223)	(22,184)
Future income tax expense	(11,432)	(8,643)	(3,572)
Future net cash flows	24,839	19,007	12,001
10% discount to reflect timing of cash flows	(13,492)	(10,164)	(6,121)
Standardized measure of discounted future net cash flows	11,347	8,843	5,880
Canada [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash flows	36,786	35,948	28,442
Future costs development	(4,678)	(4,526)	(4,132)
Future costs production	(15,063)	(12,249)	(9,847)
Future income tax expense	(3,763)	(4,209)	(3,408)
Future net cash flows	13,282	14,964	11,055
10% discount to reflect timing of cash flows	(6,785)	(7,455)	(5,532)
Standardized measure of discounted future net cash flows	6,497	7,509	5,523
North America [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash flows	106,091	94,041	73,013
Future costs development	(11,495)	(10,746)	(10,946)
Future costs production	(41,280)	(36,472)	(32,031)
Future income tax expense	(15,195)	(12,852)	(6,980)
Future net cash flows	38,121	33,971	23,056
10% discount to reflect timing of cash flows	(20,277)	(17,619)	(11,653)
Standardized measure of discounted future net cash flows	$ 17,844	$ 16,352	$ 11,403

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Document And Entity Information (USD $) In Billions, except Share data in Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Feb. 09, 2012	Jun. 30, 2011
Document And Entity Information [Abstract]
Document Type	10-K
Document Period End Date	Dec. 31, 2011
Amendment Flag	false
Entity Registrant Name	DEVON ENERGY CORP/DE
Entity Central Index Key	0001090012
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2011
Entity Filer Category	Large Accelerated Filer
Document Fiscal Period Focus	FY
Entity Well-known Seasoned Issuer	Yes
Entity Common Stock, Shares Outstanding		404.1
Entity Public Float			$ 32.7

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Other Current Assets

12 Months Ended

Dec. 31, 2011

Other Current Assets [Abstract]

Other Current Assets

12.  Other Current Assets  

The components of other current assets include the following:

	December 31,
	2011	2010
	(In millions)
Derivative financial instruments	$        641	$        348
Inventories	102	120
Income tax receivable	35	270
Other	69	41
Other current assets	$        847	$        779

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Supplemental Information To Statements Of Cash Flows (Schedule Of Supplemental To Cash Flow Information) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Net (increase) decrease in working capital:
(Increase) decrease in accounts receivable	$ (185)	$ 23	$ 142
Decrease in other current assets	125	21	212
Increase (decrease) in accounts payable	64	37	(91)
Increase in revenues and royalties payable	144	48
Increase (decrease) in income taxes payable	78	(203)	(48)
Decrease in other current liabilities	(41)	(199)	(66)
Net (increase) decrease in working capital	185	(273)	149
Supplementary cash flow data - total operations:
Interest paid (net of capitalized interest)	325	359	314
Income taxes (received) paid	$ (383)	$ 955	$ 68

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Debt And Related Expenses (Schedule Of Interest Expense Components) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Debt And Related Expenses [Abstract]
Interest based on debt outstanding	$ 414	$ 408	$ 437
Capitalized interest	(72)	(76)	(94)
Early retirement of debt		19
Other	10	12	6
Total	$ 352	$ 363	$ 349

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Consolidated Balance Sheets (USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Current assets:
Cash and cash equivalents	$ 5,555	$ 2,866
Short-term investments	1,503	145
Accounts receivable	1,379	1,202
Current assets held for sale	21	563
Other current assets	847	779
Total current assets	9,305	5,555
Oil and gas, based on full cost accounting:
Subject to amortization	61,696	56,012
Not subject to amortization	3,982	3,434
Total oil and gas	65,678	59,446
Other	5,098	4,429
Total property and equipment, at cost	70,776	63,875
Less accumulated depreciation, depletion and amortization	(46,002)	(44,223)
Property and equipment, net	24,774	19,652
Goodwill	6,013	6,080
Long-term assets held for sale	132	859
Other long-term assets	893	781
Total assets	41,117	32,927
Current liabilities:
Accounts payable	1,471	1,411
Revenues and royalties payable	678	538
Short-term debt	3,811	1,811
Current liabilities associated with assets held for sale	48	305
Other current liabilities	730	518
Total current liabilities	6,738	4,583
Long-term debt	5,969	3,819
Asset retirement obligations	1,496	1,423
Liabilities associated with assets held for sale		26
Other long-term liabilities	721	1,067
Deferred income taxes	4,763	2,756
Stockholders' equity:
Common stock, $0.10 par value. Authorized 1.0 billion shares; issued 404.1 million and 431.9 million shares in 2011 and 2010, respectively	40	43
Additional paid-in capital	3,507	5,601
Retained earnings	16,308	11,882
Accumulated other comprehensive earnings	1,575	1,760
Treasury stock, at cost. 0.4 million shares in 2010		(33)
Total stockholders' equity	21,430	19,253
Commitments and contingencies (Note 18)
Total liabilities and stockholders' equity	$ 41,117	$ 32,927

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Income Taxes

12 Months Ended

Dec. 31, 2011

Income Taxes [Abstract]

Income Taxes

6. Income Taxes

Income Tax Expense (Benefit)

Devon's income tax components are presented in the following table.

	Year Ended December 31,
	2011	2010	2009
	(In millions)
Current income tax (benefit) expense:
U.S. federal	$       (143)	$         244	$           45
Various states	20	16	18
Canada and various provinces	(20)	256	178
Total current tax (benefit) expense	(143)	516	241
Deferred income tax expense (benefit):
U.S. federal	1,986	781	(1,846)
Various states	95	21	(111)
Canada and various provinces	218	(83)	(57)
Total deferred tax expense (benefit)	2,299	719	(2,014)
Total income tax expense (benefit)	$     2,156	$     1,235	$    (1,773)

Total income tax expense (benefit) differed from the amounts computed by applying the U.S. federal income tax rate to earnings (loss) from continuing operations before income taxes as a result of the following:

	Year Ended December 31,
	2011	2010	2009
	(In millions)
Expected income tax expense (benefit) based on U.S. statutory tax   rate of 35%	$     1,502	$     1,249	$    (1,584)
Assumed repatriations.	725	144	55
State income taxes	70	31	(99)
Taxation on Canadian operations	(91)	(60)	(31)
Other	(50)	(129)	(114)
Total income tax expense (benefit)	$     2,156	$     1,235	$    (1,773)

During 2011, 2010 and 2009, pursuant to the completed and planned divestitures of our International assets located outside North America, a portion of Devon's foreign earnings were no longer deemed to be permanently reinvested. Accordingly, Devon recognized deferred income tax expense of $725 million, $144 million and $55 million during 2011, 2010 and 2009 respectively, related to assumed repatriations of earnings from its foreign subsidiaries.

Deferred Tax Assets and Liabilities

The tax effects of temporary differences that gave rise to Devon's deferred tax assets and liabilities are presented below:

	December 31,
	2011	2010
Deferred tax assets:	(In millions)
Net operating loss carryforwards	$        222	$        159
Asset retirement obligations	447	494
Pension benefit obligations	130	133
Other	117	171
Total deferred tax assets	916	957
Deferred tax liabilities:
Property and equipment	(4,475)	(3,130)
Fair value of financial instruments	(218)	(70)
Long-term debt	(185)	(198)
Taxes on unremitted foreign earnings (	(936)	(211)
Other	(27)	(20)
Total deferred tax liabilities	(5,841)	(3,629)
Net deferred tax liability	$    (4,925)	$    (2,672)

Devon has recognized $222 million of deferred tax assets related to various carryforwards available to offset future income taxes. The carryforwards consist of $829 million of Canadian net operating loss carryforwards, which expire between 2026 and 2031, and $206 million of state net operating loss carryforwards, which expire primarily between 2012 and 2031. Devon expects the tax benefits from the Canadian net operating loss carryforwards to be utilized between 2013 and 2017. Also, Devon expects the tax benefits from the state net operating loss carryforwards to be utilized between 2012 and 2016. Such expectations are based upon current estimates of taxable income during these periods, 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, gas and NGL prices or capital expenditures 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.

As of December 31, 2011, approximately $5.4 billion of Devon's unremitted earnings from its foreign subsidiaries were deemed to be permanently reinvested. As a result, Devon has not recognized a deferred tax liability for U.S. income taxes associated with such earnings. If such earnings were to be remitted to the U.S., Devon may be subject to U.S. income taxes and foreign withholding taxes. However, it is not practical to estimate the amount of additional taxes that may be payable due to the inter-relationship of the various factors involved in making such an estimate.

Unrecognized Tax Benefits

The following table presents changes in Devon's unrecognized tax benefits.

	December 31,
	2011	2010
	(In millions)
Balance at beginning of year	$        194	$        272
Tax positions taken in prior periods	(3)	40
Tax positions taken in current year	27	5
Accrual of interest related to tax positions taken	(7)	9
Lapse of statute of limitations	(41)	(5)
Settlements	(5)	(129)
Foreign currency translation	—	2
Balance at end of year	$        165	$        194

Devon's unrecognized tax benefit balance at December 31, 2011 and 2010, included $20 million and $27 million of interest and penalties, respectively. If recognized, all of Devon's unrecognized tax benefits as of December 31, 2011 would affect Devon's effective income tax rate. Included below is a summary of the tax years, by jurisdiction, that remain subject to examination by taxing authorities.

Jurisdiction	Tax Years Open
U.S. federal	2008-2011
Various U.S. states	2007-2011
Canada federal	2003-2011
Various Canadian provinces	2003-2011

Certain statute of limitation expirations are scheduled to occur in the next twelve months. However, Devon is currently in various stages of the administrative review process for certain open tax years. In addition, Devon is currently subject to various income tax audits that have not reached the administrative review process. As a result, Devon cannot reasonably anticipate the extent that the liabilities for unrecognized tax benefits will increase or decrease within the next twelve months.

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Other, Net

12 Months Ended

Dec. 31, 2011

Other, Net [Abstract]

Other, net

5. Other, net

The components of other, net in the accompanying comprehensive statement of earnings include the following:

	Year Ended December 31,
	2011	2010	2009
	(In millions)
Accretion of asset retirement obligations	$92	$92	$91
Interest rate swaps – unrealized fair value changes	88	30	(66)
Interest rate swaps – cash settlements	(77)	(44)	(40)
Interest income	(21)	(13)	(8)
Other	(92)	(32)	(60)
Total	$(10)	$33	$(83)

During 2011, Devon received $88 million of excess insurance recoveries related to certain weather and operational claims. In 2009, Devon reversed an $84 million loss contingency accrual. Devon had previously accrued $84 million for potential royalties on various deep water leases but reversed the accrual in 2009 due to a federal district court ruling.

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Stockholders' Equity

12 Months Ended

Dec. 31, 2011

Stockholders' Equity [Abstract]

Stockholders' Equity

17. Stockholders' Equity

The authorized capital stock of Devon consists of 1 billion 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.   

Devon's Board of Directors has designated 2.9 million shares of the preferred stock as Series A Junior Participating Preferred Stock (the "Series A Junior Preferred Stock"). At December 31, 2011, 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 100 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 100 votes per share on all matters submitted to a vote of the stockholders. Devon, at its option, may redeem shares of the Series A Junior Participating Preferred Stock in whole at any time and in part from time to time, at a redemption price equal to 100 times the current per share market price of Devon's common stock on the date of the mailing of the notice of redemption. The Series A Junior Preferred Stock ranks prior to the common stock but junior to all other classes of Preferred Stock.

Stock Repurchases

During 2010, Devon's Board of Directors announced a share repurchase program that authorized the repurchase of up to $3.5 billion of its common shares. Devon completed the repurchase program in the fourth quarter of 2011. In total, Devon repurchased 49.2 million shares for $3.5 billion, or $71.18 per share. The following table summarizes Devon's repurchases under the 2010 program by year (amounts and shares in millions).

	2011			2010
	Amount	Shares	Per Share	Amount	Shares	Per Share
Repurchases	$   2,299	30.9	$   74.49	$   1,201	18.3	$   65.58

Dividends

Devon paid common stock dividends of $278 million (or $0.67 per share), $281 million (or $0.64 per share) and $284 million (or $0.64 per share) in 2011, 2010 and 2009 respectively. In the second quarter of 2011, Devon increased its dividend rate from $0.16 per share to $0.17 per share.

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Property And Equipment

12 Months Ended

Dec. 31, 2011

Property And Equipment [Abstract]

Property And Equipment

13. Property and Equipment

See Note 22 for disclosure of Devon's capitalized costs related to its oil and gas exploration and development activities.

In November 2009, Devon announced plans to divest its offshore assets. In 2011, Devon substantially completed its planned divestiture program. In aggregate, Devon's U.S. and International sales generated total proceeds of $10 billion as presented in the following table. Assuming repatriation of a portion of the foreign proceeds under current U.S. tax law the after-tax proceeds from these transactions were approximately $8 billion.

	Cash Proceeds	Year of Divestiture
	(In millions)
Brazil (discontinued operations)	$     3,251	2011
Gulf of Mexico (continuing operations)	4,059	2010
Azerbaijan (discontinued operations)	1,925	2010
China – Panyu and Exploration (discontinued operations)	592	2010
Other (discontinued operations)	175	2010
Total	$   10,002

Reductions of Carrying Value

In the first quarter of 2009, Devon reduced the carrying value of its U.S. oil and gas properties $6.4 billion, or $4.1 billion after taxes, due to a full cost ceiling limitation. The reduction resulted from a significant decrease in the full cost ceiling due to the effects of declining natural gas prices subsequent to December 31, 2008.

Sinopec Transaction

In January 2012, Devon announced a transaction with Sinopec International Petroleum Exploration & Production Corporation that Devon expects to close in the first quarter of 2012. Under the agreement, Sinopec will pay $2.5 billion, including $900 million at closing and $1.6 billion toward Devon's share of future drilling costs, and will receive a 33.3% interest in five new venture exploration plays in the United States.

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Property And Equipment (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended			26 Months Ended	12 Months Ended			3 Months Ended		26 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2011	Dec. 31, 2011 Sinopec International Petroleum Exploration And Production Corporation [Member]	Dec. 31, 2011 Future Drilling Costs [Member] Sinopec International Petroleum Exploration And Production Corporation [Member]	Dec. 31, 2011 Received At Closing [Member] Sinopec International Petroleum Exploration And Production Corporation [Member]	Mar. 31, 2009 Gross [Member]	Mar. 31, 2009 After Taxes [Member]	Dec. 31, 2011 After Taxes [Member]
Property, Plant and Equipment [Line Items]
Gain on divestiture of operations	$ 2,552	$ 1,818	$ 17
Gain on divestiture of operations, after-tax	2,552	1,732	17
Reduction of carrying value of oil and gas properties			6,408					6,400	4,100
Cash Proceeds				10,002						8,000
Payments to acquire interest in joint venture					$ 2,500	$ 1,600	$ 900
Percentage interest in joint venture	33.30%

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Supplemental Information To Statements Of Cash Flows

12 Months Ended

Dec. 31, 2011

Supplemental Information To Statements Of Cash Flows [Abstract]

Supplemental Information To Statements Of Cash Flows

9. Supplemental Information to Statements of Cash Flows

	Year Ended December 31,
	2011	2010	2009
	(In millions)
Net decrease (increase) in working capital:
(Increase) decrease in accounts receivable	$       (185)	$           23	$         142
Decrease in other current assets	125	21	212
Increase (decrease) in accounts payable	64	37	(91)
Increase in revenues and royalties payable	144	48	—
Increase (decrease) in income taxes payable	78	(203)	(48)
Decrease in other current liabilities	(41)	(199)	(66)
Net decrease (increase) in working capital	$         185	$       (273)	$         149
Supplementary cash flow data – total operations:
Interest paid (net of capitalized interest)	$         325	$         359	$         314
Income taxes (received) paid	$       (383)	$         955	$           68

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Share-Based Compensation (Narrative) (Details) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total shares of common stock reserved for issuance pursuant to the 2009 Long-Term Incentive Plan	21,500,000
Number of shares used to calculate shares issued under the 2009 Long-Term Incentive Plan, options granted	1
Number of shares used to calculate shares issued under the 2009 Long-Term Incentive Plan, other awards	1.84
Aggregate intrinsic value of stock options exercised	$ 81	$ 47	$ 51
Aggregate fair value of restricted stock awards vested	145	184	165
Common shares awarded based upon total shareholder return	341,000
Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost	70
Unrecognized compensation cost, weighted-average period of recognition (in years)	3.0
Restricted Stock Awards And Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost	305
Unrecognized compensation cost, weighted-average period of recognition (in years)	2.8
Performance Based Restricted Stock Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost	4
Unrecognized compensation cost, weighted-average period of recognition (in years)	2.4
Performance Share Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost	$ 8
Unrecognized compensation cost, weighted-average period of recognition (in years)	2.3
Maximum [Member] | Performance Share Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units able to vest as a percentage of granted shares	200.00%
Minimum [Member] | Performance Share Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units able to vest as a percentage of granted shares	0.00%

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Discontinued Operations (Schedule Of Main Classes Of Assets And Liabilities Associated With Discontinued Operations) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Discontinued Operations [Abstract]
Cash and cash equivalents		$ 424
Other current assets	21	139
Current assets	21	563
Property and equipment, net	132	859
Accounts payable	20	260
Other current liabilities	28	45
Current liabilities	48	305
Other long-term liabilities		$ 26

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Earnings (Loss) Per Share

12 Months Ended

Dec. 31, 2011

Earnings (Loss) Per Share [Abstract]

Earnings (Loss) Per Share

7.  Earnings (Loss) Per Share  

The following table reconciles earnings from continuing operations and common shares outstanding used in the calculations of basic and diluted earnings (loss) per share. Because a net loss from continuing operations was incurred during 2009, the dilutive shares produce an antidilutive net loss per share result. As a result, the diluted loss per share from continuing operations is same as the basic loss per share amount.

	Earnings	Common Shares	Earnings (Loss) per Share
	(In millions, except per share amounts)
Year Ended December 31, 2011:
Earnings from continuing operations	$        2,134	417
Attributable to participating securities	(23)	(5)
Basic earnings per share	2,111	412	$     5.12
Dilutive effect of potential common shares issuable	—	2
Diluted earnings per share	$        2,111	414	$     5.10
Year Ended December 31, 2010:
Earnings from continuing operations	$        2,333	440
Attributable to participating securities	(26)	(5)
Basic earnings per share	2,307	435	$     5.31
Dilutive effect of potential common shares issuable	—	1
Diluted earnings per share	$        2,307	436	$     5.29
Year Ended December 31, 2009:
Loss from continuing operations	$       (2,753)	444
Attributable to participating securities	31	(5)
Basic and diluted loss per share	$       (2,722)	439	$       (6.20)

Certain options to purchase shares of Devon's common stock were excluded from the dilution calculations because the options were antidilutive. These excluded options totaled 3 million, 6 million and 9 million in 2011, 2010 and 2009, respectively.

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Other Comprehensive Earnings

12 Months Ended

Dec. 31, 2011

Other Comprehensive Earnings [Abstract]

Other Comprehensive Earnings

8. Other Comprehensive Earnings

Components of other comprehensive earnings consist of the following:

	Year Ended December 31,
	2011	2010	2009
	(In millions)
Foreign currency translation:
Accumulated foreign currency translation at beginning of year	$     1,993	$     1,616	$         685
Change in cumulative translation adjustment	(200)	397	993
Income tax benefit (expense)	9	(20)	(62)
Accumulated foreign currency translation at end of year	1,802	1,993	1,616
Pension and postretirement benefit plans:
Accumulated pension and postretirement benefit at beginning of year	(233)	(231)	(302)
Net actuarial (loss) gain and prior service cost arising in current year	(21)	(33)	59
Income tax benefit (expense)	8	11	(22)
Recognition of net actuarial loss and prior service cost in net earnings.	30	31	54
Income tax expense	(11)	(11)	(20)
Accumulated pension and postretirement benefits at end of year	(227)	(233)	(231)
Accumulated other comprehensive earnings, net of tax	$     1,575	$     1,760	$     1,385

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Short-Term Investments

12 Months Ended

Dec. 31, 2011

Short-Term Investments [Abstract]

Short-Term Investments

10.   Short-Term Investments

The components of short-term investments include the following:

	December 31,
	2011	2010
	(In millions)
Commercial paper	$     1,013	$           —
U.S. Treasuries	201	145
Other	289	—
Total	$     1,503	$        145

As of December 31, 2011, the average remaining maturity of these investments was 75 days, with a weighted average yield of 0.28 percent.

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Share-Based Compensation (Summary Of Unvested Restricted Stock Awards And Units, Including Changes During The Year) (Details) (Restricted Stock Awards And Units [Member], USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2011
Restricted Stock Awards And Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested at December 31, 2010	5,311
Restricted Stock Awards And Units, Granted	2,301
Restricted Stock Awards And Units, Vested	(2,188)
Restricted Stock Awards And Units, Forfeited	(200)
Unvested at December 31, 2011	5,224
Weighted Average Grant-Date Fair Value, Unvested at December 31, 2010	$ 70.60
Weighted Average Grant-Date Fair Value, Granted	$ 65.40
Weighted Average Grant-Date Fair Value, Vested	$ 72.05
Weighted Average Grant-Date Fair Value, Forfeited	$ 71.18
Weighted Average Grant-Date Fair Value, Unvested at December 31, 2011	$ 67.85

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Supplemental Information On Oil And Gas Operations (Schedule Of Principal Changes In The Standardized Measure Of Discounted Future Net Cash Flows Attributable To Proved Reserves) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Supplemental Information On Oil And Gas Operations [Abstract]
Beginning balance	$ 16,352	$ 11,403	$ 9,393
Oil, gas and NGL sales, net of production costs	(5,794)	(4,982)	(3,915)
Net changes in prices and production costs	1,875	7,423	(1,672)
Extensions and discoveries, net of future development	3,714	3,048	2,378
Purchase of reserves, net of future development costs	57	23	6
Development costs incurred that reduced future development costs	1,302	1,559	1,012
Revisions of quantity estimates	(668)	287	4,051
Sales of reserves in place	(2)	(815)	(37)
Accretion of discount	2,248	1,487	1,281
Net change in income taxes	(929)	(2,663)	(51)
Other, primarily changes in timing and foreign exchange rates	(311)	(418)	(1,043)
Ending balance	$ 17,844	$ 16,352	$ 11,403

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Property And Equipment (Schedule Of Proceeds From Offshore Divestitures) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended	26 Months Ended
	Dec. 31, 2011	Dec. 31, 2011
Property, Plant and Equipment [Line Items]
Cash Proceeds		$ 10,002
Brazil [Member] | Discontinued Operations [Member]
Property, Plant and Equipment [Line Items]
Cash Proceeds		3,251
Year Of Divestiture	2011
Gulf Of Mexico [Member] | Continuing Operations [Member]
Property, Plant and Equipment [Line Items]
Cash Proceeds		4,059
Year Of Divestiture	2010
Azerbaijan [Member] | Discontinued Operations [Member]
Property, Plant and Equipment [Line Items]
Cash Proceeds		1,925
Year Of Divestiture	2010
China - Panyu And Exploration [Member] | Discontinued Operations [Member]
Property, Plant and Equipment [Line Items]
Cash Proceeds		592
Year Of Divestiture	2010
Other Segment [Member] | Discontinued Operations [Member]
Property, Plant and Equipment [Line Items]
Cash Proceeds		$ 175
Year Of Divestiture	2010

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Share-Based Compensation (Summary Of Performance Share Units) (Details) (Performance Share Units [Member], USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2011
Performance Share Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested at December 31, 2010
Performance Share Units, Granted	171	[1]
Unvested at December 31, 2011	171
Weighted Average Grant-Date Fair Value, Unvested at December 31, 2010
Weighted Average Grant-Date Fair Value, Granted	$ 81.70	[1]
Weighted Average Grant-Date Fair Value, Unvested at December 31, 2011	$ 81.70

[1] A maximum of 341,000 common shares could be awarded based upon Devon's final TSR ranking.

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Retirement Plans (Schedule Of Expense Related To These Defined Contribution Plans) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Defined Benefit Plan Disclosure [Line Items]
Expense related to defined contribution plans	$ 54	$ 49	$ 49
401 (k) Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Expense related to defined contribution plans	33	32	34
Canadian Pension And Savings Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Expense related to defined contribution plans	$ 21	$ 17	$ 15

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Share-Based Compensation (Summary Of Outstanding Stock Options, Including Changes During The Year) (Details) (USD $) In Millions, except Share data in Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011
Share-Based Compensation [Abstract]
Options, Outstanding at December 31, 2010	11,434
Options, Granted	1,962
Options, Exercised	(2,366)
Options, Forfeited	(487)
Options, Outstanding at December 31, 2011	10,543
Options, Vested and expected to vest at December 31, 2011	10,428
Options, Exercisable at December 31, 2011	6,716
Weighted Average Exercise Price, Outstanding at December 31, 2010	$ 62.64
Weighted Average Exercise Price, granted	$ 66.98
Weighted Average Exercise Price, exercised	$ 47.51
Weighted Average Exercise Price, forfeited	$ 73.32
Weighted Average Exercise Price, Outstanding at December 31, 2011	$ 66.35
Weighted Average Exercise Price, Vested and expected to vest at December 31, 2011	$ 66.33
Weighted Average Exercise Price, Exercisable at December 31, 2011	$ 65.39
Weighted Average Remaining Contractual Term, Outstanding at December 31, 2011	4.31
Weighted Average Remaining Contractual Term, Vested and expected to vest at December 31, 2011	4.27
Weighted Average Remaining Contractual Term, Exercisable at December 31, 2011	2.90
Aggregate Intrinsic Value, Outstanding at December 31, 2011	$ 40
Aggregate Intrinsic Value, Vested and expected to vest at December 31, 2011	40
Aggregate Intrinsic Value, Exercisable at December 31, 2011	$ 39

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Retirement Plans (Narrative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Defined Benefit Plan Disclosure [Line Items]
Value of trusts established for certain supplemental plans	$ 32	$ 36
Employer contributions transferred from trusts	8	8
Pension plan contributions	454
Effect on benefit obligation with a 1% increase or decrease	2
Effect on benefit obligation with a 1% increase or decrease	1
Pension benefits to be funded from the trust	9
Postretirement benefits expected to be funded from cash and cash equivalents	3
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation	1,200	1,000
Pension plan contributions	454	66
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation	37	43	64
Pension plan contributions	$ 7	$ 4
Defined benefit plan health care cost trend rate assumed for next fiscal year	8.20%
Defined benefit plan ultimate health care cost trend rate	5.00%

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Restructuring Costs (Tables)

12 Months Ended

Dec. 31, 2011

Restructuring Costs [Abstract]

Schedule Of The Components Of Restructuring Costs Included In The Consolidated Statements Of Earnings

	Year Ended December 31,
	2011	2010	2009
	(In millions)
Cash severance	$9	$(17)	$66
Share-based awards	(1)	(10)	39
Lease obligations	(13)	70	—
Asset impairments	2	11	—
Other	1	3	—
Total	$(2)	$57	$105

Schedule Of The Activity And Balances Associated With Restructuring Liabilities

	Other Current Liabilities	Other Long-Term Liabilities	Total
	(In millions)
Balance as of December 31, 2009	$61	$—	$61
Lease obligations incurred	17	51	68
Cash severance settled	(30)	—	(30)
Cash severance revision	(17)	—	(17)
Balance as of December 31, 2010	31	51	82
Lease obligations settled	(8)	(12)	(20)
Cash severance settled	(13)	—	(13)
Lease obligations revision	10	(23)	(13)
Cash severance revision	9	—	9
Balance as of December 31, 2011	$29	$16	$45

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Segment Information (Tables)

12 Months Ended

Dec. 31, 2011

Segment Information [Abstract]

Condensed Statements Of Comprehensive Earnings And Balance Sheets Of Reportable Segments

	U.S.	Canada	Total
	(In millions)
Year Ended December 31, 2011:
Oil, gas and NGL sales	$     5,418	$     2,897	$     8,315
Oil, gas and NGL derivatives	$         881	$           —	$         881
Marketing and midstream revenues	$     2,059	$         199	$     2,258
Interest expense	$         204	$         148	$         352
Depreciation, depletion and amortization	$     1,439	$         809	$     2,248
Earnings from continuing operations before income taxes	$     3,477	$         813	$     4,290
Income tax expense	$     1,958	$         198	$     2,156
Earnings from continuing operations	$     1,519	$         615	$     2,134
Property and equipment, net	$   16,989	$     7,785	$   24,774
Total continuing assets (1)	$   22,622	$   18,342	$   40,964
Capital expenditures	$     6,112	$     1,708	$     7,820
Year Ended December 31, 2010:
Oil, gas and NGL sales	$     4,742	$     2,520	$     7,262
Oil, gas and NGL derivatives	$         809	$             2	$         811
Marketing and midstream revenues	$     1,742	$         125	$     1,867
Interest expense	$         159	$         204	$         363
Depreciation, depletion and amortization	$     1,229	$         701	$     1,930
Earnings from continuing operations before income taxes	$     2,943	$         625	$     3,568
Income tax expense	$     1,062	$         173	$     1,235
Earnings from continuing operations	$     1,881	$         452	$     2,333
Property and equipment, net	$   12,379	$     7,273	$   19,652
Total continuing assets (1)	$   18,320	$   13,185	$   31,505
Capital expenditures	$     5,007	$     2,107	$     7,114
Year Ended December 31, 2009:
Oil, gas and NGL sales	$     3,958	$     2,139	$     6,097
Oil, gas and NGL derivatives	$         382	$             2	$         384
Marketing and midstream revenues	$     1,498	$           36	$     1,534
Interest expense	$         125	$         224	$         349
Depreciation, depletion and amortization	$     1,498	$         610	$     2,108
(Loss) earnings from continuing operations before income taxes	$    (4,961)	$         435	$    (4,526)
Income tax (benefit) expense	$    (1,894)	$         121	$    (1,773)
(Loss) earnings from continuing operations	$    (3,067)	$         314	$    (2,753)
Reduction of carrying value of oil and gas properties	$     6,408	$           —	$     6,408
Capital expenditures	$     3,584	$     1,099	$     4,683

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2011

Asset Retirement Obligations [Abstract]

Asset Retirement Obligations

15. Asset Retirement Obligations

The schedule below summarizes changes in Devon's asset retirement obligations.

	Year Ended December 31,
	2011	2010
	(In millions)
Asset retirement obligations as of beginning of year	$     1,497	$     1,513
Liabilities incurred	53	55
Liabilities settled	(82)	(129)
Revision of estimated obligation	25	194
Liabilities assumed by others	—	(269)
Accretion expense on discounted obligation	92	92
Foreign currency translation adjustment	(22)	41
Asset retirement obligations as of end of year	1,563	1,497
Less current portion	67	74
Asset retirement obligations, long-term	$     1,496	$     1,423

During 2010, Devon recognized a revision to its asset retirement obligations totaling $194 million. The increase was primarily due to an overall increase in abandonment cost estimates and a decrease in the discount rate used to present value the obligations.

During 2010, Devon reduced its asset retirement obligations by $269 million primarily for those obligations that were assumed by purchasers of Devon's Gulf of Mexico oil and gas properties.

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Supplemental Information On Oil And Gas Operations (Oil And Gas Properties Not Subject To Amortization) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Acquisition costs	$ 3,144
Exploration costs	332
Development costs	441
Capitalized interest	65
Total oil and gas properties not subject to amortization	3,982
2011 [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Acquisition costs	894
Exploration costs	234
Development costs	359
Capitalized interest	43
Total oil and gas properties not subject to amortization	1,530
2010 [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Acquisition costs	1,101
Exploration costs	81
Development costs	72
Capitalized interest	22
Total oil and gas properties not subject to amortization	1,276
2009 [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Acquisition costs	112
Exploration costs	6
Development costs	1
Total oil and gas properties not subject to amortization	119
Prior To 2009 [Member]
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Acquisition costs	1,037
Exploration costs	11
Development costs	9
Total oil and gas properties not subject to amortization	$ 1,057

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Discontinued Operations

12 Months Ended

Dec. 31, 2011

Discontinued Operations [Abstract]

Discontinued Operations

20.  Discontinued Operations   

For the three-year period ended December 31, 2011, Devon's discontinued operations included amounts related to its assets in Azerbaijan, Brazil, China, Angola and other minor International properties. By the end of 2011, Devon had sold all these assets except for its assets in Angola. Devon has entered into an agreement to sell its Angolan assets. Upon closing, Devon will receive $70 million and the right to future contingent consideration based on achievement of certain objectives.

Revenues related to Devon's discontinued operations totaled $43 million, $693 million and $945 million during 2011, 2010 and 2009, respectively. Earnings from discontinued operations before income taxes totaled $2.6 billion, $2.4 billion and $322 million during 2011, 2010 and 2009, respectively. Earnings before income taxes in 2011 and 2010 were largely impacted by gains on divestiture transactions. The following table presents the gains on the divestitures by year.

	Year Ended December 31,
	2011		2010		2009
	Gross	After Tax	Gross	After Tax	Gross	After Tax
	(In millions)
Brazil	$ 2,548	$ 2,548	$       —	$       —	$       —	$       —
Azerbaijan	—	—	1,543	1,524	—	—
China - Panyu	—	—	308	235	—	—
Other	4	4	(33)	(27)	17	17
Total	$ 2,552	$ 2,552	$ 1,818	$ 1,732	$      17	$      17

The following table presents the main classes of assets and liabilities associated with Devon's discontinued operations.    

	December 31,
	2011	2010
	(In millions)
Cash and cash equivalents	$        —	$      424
Other current assets	21	139
Current assets	$        21	$      563
Property and equipment, net	$      132	$      859
Accounts payable	$        20	$      260
Other current liabilities	28	45
Current liabilities	$        48	$      305
Other long-term liabilities	$         —	$        26

Reduction of Carrying Value of Oil and Gas Properties

During 2009, Devon reduced the carrying value of its Brazil oil and gas properties by $109 million ($105 million after tax). This reduction resulted largely from an exploratory well drilled at the BM-BAR-3 block in the offshore Barreirinhas Basin that did not have adequate reserves for commercial viability.

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Retirement Plans (Schedule Of Net Periodic Benefit Cost And Other Comprehensive Income For Pension And Other Postretirement Benefit Plans) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 37	$ 33	$ 43
Interest cost	60	58	58
Expected return on plan assets	(42)	(36)	(35)
Curtailment and settlement expense			5
Recognition of net actuarial loss (gain)	32	27	45
Recognition of prior service cost	3	3	3
Total net periodic benefit cost	90	85	119
Actuarial loss (gain) arising in current year	23	50	(66)
Prior service cost (credit) arising in current year		4
Recognition of net actuarial loss, including settlement expense, in net periodic benefit cost	(32)	(27)	(45)
Recognition of prior service cost, including curtailment, in net periodic benefit cost	(3)	(3)	(8)
Total other comprehensive (loss) earnings	(12)	24	(119)
Total recognized	78	109
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	1	1	1
Interest cost	2	3	3
Curtailment and settlement expense	(3)
Recognition of net actuarial loss (gain)			(1)
Recognition of prior service cost	(2)	1	2
Total net periodic benefit cost	(2)	5	5
Actuarial loss (gain) arising in current year	(7)	1	7
Prior service cost (credit) arising in current year	5	(22)
Recognition of net actuarial loss, including settlement expense, in net periodic benefit cost	3		1
Recognition of prior service cost, including curtailment, in net periodic benefit cost	2	(1)	(2)
Total other comprehensive (loss) earnings	3	(22)	6
Total recognized	$ 1	$ (17)	$ 11

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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2011

Fair Value Measurements [Abstract]

Schedule Of Carrying Value And Fair Value Measurement Information For Financial Assets And Liabilities

			Fair Value Measurements Using:
	Carrying Amount	Total Fair Value	Level 1 Inputs	Level 2 Inputs	Level 3 Inputs
	(In millions)
December 31, 2011 assets (liabilities):
Cash equivalents	$5,123	$5,123	$1,369	$3,754	$—
Short-term investments	$1,503	$1,503	$490	$1,013	$—
Long-term investments	$84	$84	$—	$—	$84
Commodity derivatives	$628	$628	$—	$628	$—
Commodity derivatives	$(82)	$(82)	$—	$(82)	$—
Interest rate derivatives	$52	$52	$—	$52	$—
Debt	$(9,780)	$(11,380)	$—	$(11,295)	$(85)

			Fair Value Measurements Using:
	Carrying Amount	Total Fair Value	Level 1 Inputs	Level 2 Inputs	Level 3 Inputs
	(In millions)
December 31, 2010 assets (liabilities):
Cash equivalents	$2,335	$2,335	$2,335	$—	$—
Short-term investments	$145	$145	$145	$—	$—
Long-term investments	$94	$94	$—	$—	$94
Commodity derivatives	$249	$249	$—	$249	$—
Commodity derivatives	$(192)	$(192)	$—	$(192)	$—
Interest rate derivatives	$140	$140	$—	$140	$—
Debt	$(5,630)	$(6,629)	$—	$(6,485)	$(144)

Schedule Of Changes In Level 3 Fair Value Measurements

	Year Ended December 31,
	2011	2010
	(In millions)
Long-term investments balance at beginning of period	$94	$115
Redemptions of principal	(10)	(21)
Long-term investments balance at end of period	$84	$94
Debt balance at beginning of period	$(144)	$—
Issuance of promissory note	—	(139)
Foreign exchange translation adjustment	1	(9)
Accretion of promissory note	(5)	(3)
Redemptions of principal	63	7
Debt balance at end of period	$(85)	$(144)

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Commitments And Contingencies (Schedule Of Commitments And Contingencies) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011
Purchase Obligations [Member]
Purchase Commitment, Excluding Long-term Commitment [Line Items]
2012	$ 900
2013	905
2014	905
2015	905
2016	924
Thereafter	3,915
Total	8,454
Drilling And Facility Obligations [Member]
Purchase Commitment, Excluding Long-term Commitment [Line Items]
2012	919
2013	456
2014	100
Total	1,475
Firm Transportation Agreements [Member]
Purchase Commitment, Excluding Long-term Commitment [Line Items]
2012	306
2013	302
2014	283
2015	250
2016	209
Thereafter	786
Total	2,136
Office And Equipment Leases [Member]
Purchase Commitment, Excluding Long-term Commitment [Line Items]
2012	63
2013	56
2014	47
2015	44
2016	43
Thereafter	220
Total	$ 473

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Accounts Receivable (Tables)

12 Months Ended

Dec. 31, 2011

Accounts Receivable [Abstract]

Schedule Of Components Of Accounts Receivable

	December 31,
	2011	2010
	(In millions)
Oil, gas and NGL sales	$        928	$        786
Joint interest billings	247	204
Marketing and midstream revenues	174	165
Other	39	57
Gross accounts receivable	1,388	1,212
Allowance for doubtful accounts	(9)	(10)
Net accounts receivable	$     1,379	$     1,202

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Fair Value Measurements (Schedule Of Changes In Level 3 Fair Value Measurements) (Details) (USD $) In Millions, unless otherwise specified	1 Months Ended	12 Months Ended
	Jun. 30, 2009	Dec. 31, 2011	Dec. 31, 2011 Long-Term Investments [Member]	Dec. 31, 2010 Long-Term Investments [Member]	Dec. 31, 2011 Debt [Member]	Dec. 31, 2010 Debt [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term investments balance at beginning of period		$ 94	$ 94	$ 115
Redemptions of principal			(10)	(21)
Long-term investments balance at end of period		84	84	94
Debt balance at beginning of period					(144)
Issuance of promissory note	139					(139)
Foreign exchange translation adjustment					1	(9)
Accretion of promissory note					(5)	(3)
Redemptions of principal					63	7
Debt balance at end of period					$ (85)	$ (144)
Interest rate used to estimate the fair value of debt		3.125%

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Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2011	Dec. 31, 2010
Consolidated Balance Sheets [Abstract]
Common stock, par value (in dollars per share)	$ 0.10	$ 0.1
Common stock, shares authorized (in shares)	1,000,000,000	1,000,000,000
Common stock, shares issued (in shares)	404,100,000	431,900,000
Treasury stock, shares	0	400,000

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Debt And Related Expenses (Schedule Of Debt Maturities) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2011
Debt And Related Expenses [Abstract]
2012	$ 3,811
2013
2014	500
2015
2016	500
2017 and thereafter	4,975
Total	$ 9,786

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Restructuring Costs

12 Months Ended

Dec. 31, 2011

Restructuring Costs [Abstract]

Restructuring Costs

4. Restructuring Costs

In the fourth quarter of 2009, Devon announced plans to divest its offshore assets. As of December 31, 2011, Devon had divested all of its U.S. Offshore assets and substantially all of its International assets. Through the end of 2011, Devon had incurred $202 million of restructuring costs associated with these divestitures.

Employee Severance

This amount was originally based on estimates of the number of employees that would ultimately be impacted by the offshore divestitures and included amounts related to cash severance costs and accelerated vesting of share-based grants. As the divestiture program progressed, Devon decreased its overall estimate of employee severance costs. More offshore employees than previously estimated received comparable positions with either the purchaser of the properties or in Devon's U.S. Onshore operations.

Lease Obligations

As a result of the divestitures, Devon ceased using certain office space that was subject to non-cancellable operating lease arrangements. Consequently, in 2010 Devon recognized $70 million of restructuring costs that represented the present value of its future obligations under the leases, net of anticipated sublease income. Devon's estimate of lease obligations was based upon certain key estimates that could change over the term of the leases. These estimates include the estimated sublease income that Devon may receive over the term of the leases, as well as the amount of variable operating costs that Devon will be required to pay under the leases. In addition, Devon recognized $11 million of asset impairment charges for leasehold improvements and furniture associated with the office space that it ceased using.

Financial Statement Presentation

The schedule below summarizes restructuring costs presented in the accompanying comprehensive statements of earnings. Restructuring costs relating to Devon's discontinued operations totaled $(2) million, $(4) million, and $48 million in 2011, 2010, and 2009, respectively. These costs primarily relate to cash severance and share-based awards and are not included in the schedule below.

	Year Ended December 31,
	2011	2010	2009
	(In millions)
Cash severance	$9	$(17)	$66
Share-based awards	(1)	(10)	39
Lease obligations	(13)	70	—
Asset impairments	2	11	—
Other	1	3	—
Total	$(2)	$57	$105

The schedule below summarizes activity and balances associated with Devon's restructuring liabilities. Devon's restructuring liabilities related to its discontinued operations totaled $16 million and $23 million at December 31, 2010, and 2009, respectively. There was no liability at the end of 2011. These liabilities primarily relate to cash severance and are not included in the schedule below.

	Other Current Liabilities	Other Long-Term Liabilities	Total
	(In millions)
Balance as of December 31, 2009	$61	$—	$61
Lease obligations incurred	17	51	68
Cash severance settled	(30)	—	(30)
Cash severance revision	(17)	—	(17)
Balance as of December 31, 2010	31	51	82
Lease obligations settled	(8)	(12)	(20)
Cash severance settled	(13)	—	(13)
Lease obligations revision	10	(23)	(13)
Cash severance revision	9	—	9
Balance as of December 31, 2011	$29	$16	$45

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Derivative Financial Instruments (Schedule of Foreign Currency Derivative) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011
Derivative Financial Instruments [Abstract]
CAD Notional	$ 305
Expiration	March 30, 2012
Fixed Rate Received	0.9812
Contract Type	Sell

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Accounts Receivable (Schedule Of Components Of Accounts Receivable) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Accounts Receivable [Abstract]
Oil, gas and NGL sales	$ 928	$ 786
Joint interest billings	247	204
Marketing and midstream revenues	174	165
Other	39	57
Gross accounts receivable	1,388	1,212
Allowance for doubtful accounts	(9)	(10)
Net accounts receivable	$ 1,379	$ 1,202

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Fair Value Measurements (Schedule Of Carrying Value And Fair Value Measurement Information For Financial Assets And Liabilities) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	$ 84	$ 94
Derivatives, assets	680	389
Derivatives, liabilities	(82)	(192)
Carrying Amount [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt	(9,780)	(5,630)
Cash equivalents	5,123	2,335
Total Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt	(11,380)	(6,629)
Cash equivalents	5,123	2,335
Level 1 Inputs [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	1,369	2,335
Level 2 Inputs [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt	(11,295)	(6,485)
Cash equivalents	3,754
Level 3 Inputs [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt	(85)	(144)
Short-Term Investments [Member] | Carrying Amount [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	1,503	145
Short-Term Investments [Member] | Total Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	1,503	145
Short-Term Investments [Member] | Level 1 Inputs [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	490	145
Short-Term Investments [Member] | Level 2 Inputs [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	1,013
Long-Term Investments [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	84	94	115
Long-Term Investments [Member] | Carrying Amount [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	84	94
Long-Term Investments [Member] | Total Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	84	94
Long-Term Investments [Member] | Level 3 Inputs [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	84	94
Commodity Derivatives [Member] | Carrying Amount [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives, assets	628	249
Derivatives, liabilities	(82)	(192)
Commodity Derivatives [Member] | Total Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives, assets	628	249
Derivatives, liabilities	(82)	(192)
Commodity Derivatives [Member] | Level 2 Inputs [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives, assets	628	249
Derivatives, liabilities	(82)	(192)
Interest Rate Derivatives [Member] | Carrying Amount [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives, assets	52	140
Interest Rate Derivatives [Member] | Total Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives, assets	52	140
Interest Rate Derivatives [Member] | Level 2 Inputs [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivatives, assets	$ 52	$ 140

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Restructuring Costs (Schedule Of The Activity And Balances Associated With Restructuring Liabilities) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended				12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2010 Discontinued Operations [Member]	Dec. 31, 2009 Discontinued Operations [Member]	Dec. 31, 2011 Cash Severance [Member]	Dec. 31, 2010 Cash Severance [Member]	Dec. 31, 2011 Lease Obligations [Member]	Dec. 31, 2011 Other Current Liabilities [Member]	Dec. 31, 2010 Other Current Liabilities [Member]	Dec. 31, 2011 Other Current Liabilities [Member] Cash Severance [Member]	Dec. 31, 2010 Other Current Liabilities [Member] Cash Severance [Member]	Dec. 31, 2011 Other Current Liabilities [Member] Lease Obligations [Member]	Dec. 31, 2011 Other Long-Term Liabilities [Member]	Dec. 31, 2010 Other Long-Term Liabilities [Member]	Dec. 31, 2011 Other Long-Term Liabilities [Member] Lease Obligations [Member]
Restructuring Cost and Reserve [Line Items]
Balance	$ 82	$ 61	$ 16	$ 23				$ 31	$ 61				$ 51
Lease obligations incurred		68							17					51
Cash severance settled	(13)	(30)						(13)	(30)
Cash severance/lease obligations revision					9	(17)	(13)			9	(17)	10			(23)
Lease obligations settled	(20)							(8)					(12)
Balance	$ 45	$ 82	$ 16	$ 23				$ 29	$ 31				$ 16	$ 51

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Segment Information

12 Months Ended

Dec. 31, 2011

Segment Information [Abstract]

Segment Information

21. Segment Information

Devon manages its operations through distinct operating segments, or divisions, which are defined primarily by geographic areas. For financial reporting purposes, Devon aggregates its U.S. divisions into one reporting segment due to the similar nature of the businesses. However, Devon's Canadian division is reported as a separate reporting segment primarily due to the significant differences in the regulatory environment. Devon's segments are all primarily engaged in oil and gas producing activities, and certain information regarding such activities for each segment is included in Note 22. Following is certain financial information regarding Devon's segments. Revenues are all from external customers.

	U.S.	Canada	Total
	(In millions)
Year Ended December 31, 2011:
Oil, gas and NGL sales	$     5,418	$     2,897	$     8,315
Oil, gas and NGL derivatives	$         881	$           —	$         881
Marketing and midstream revenues	$     2,059	$         199	$     2,258
Interest expense	$         204	$         148	$         352
Depreciation, depletion and amortization	$     1,439	$         809	$     2,248
Earnings from continuing operations before income taxes	$     3,477	$         813	$     4,290
Income tax expense	$     1,958	$         198	$     2,156
Earnings from continuing operations	$     1,519	$         615	$     2,134
Property and equipment, net	$   16,989	$     7,785	$   24,774
Total continuing assets (1)	$   22,622	$   18,342	$   40,964
Capital expenditures	$     6,112	$     1,708	$     7,820
Year Ended December 31, 2010:
Oil, gas and NGL sales	$     4,742	$     2,520	$     7,262
Oil, gas and NGL derivatives	$         809	$             2	$         811
Marketing and midstream revenues	$     1,742	$         125	$     1,867
Interest expense	$         159	$         204	$         363
Depreciation, depletion and amortization	$     1,229	$         701	$     1,930
Earnings from continuing operations before income taxes	$     2,943	$         625	$     3,568
Income tax expense	$     1,062	$         173	$     1,235
Earnings from continuing operations	$     1,881	$         452	$     2,333
Property and equipment, net	$   12,379	$     7,273	$   19,652
Total continuing assets (1)	$   18,320	$   13,185	$   31,505
Capital expenditures	$     5,007	$     2,107	$     7,114
Year Ended December 31, 2009:
Oil, gas and NGL sales	$     3,958	$     2,139	$     6,097
Oil, gas and NGL derivatives	$         382	$             2	$         384
Marketing and midstream revenues	$     1,498	$           36	$     1,534
Interest expense	$         125	$         224	$         349
Depreciation, depletion and amortization	$     1,498	$         610	$     2,108
(Loss) earnings from continuing operations before income taxes	$    (4,961)	$         435	$    (4,526)
Income tax (benefit) expense	$    (1,894)	$         121	$    (1,773)
(Loss) earnings from continuing operations	$    (3,067)	$         314	$    (2,753)
Reduction of carrying value of oil and gas properties	$     6,408	$           —	$     6,408
Capital expenditures	$     3,584	$     1,099	$     4,683

____________________________

(1)   Total assets in the table above do not include assets held for sale related to Devon's discontinued operations, which totaled $153 million, $1.4 billion, and $1.9 billion in 2011, 2010 and 2009, respectively.

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Supplemental Information On Oil And Gas Operations (Proved Reserves) (Details)	12 Months Ended
	Dec. 31, 2011 MMbls		Dec. 31, 2010 MMbls		Dec. 31, 2009 MMbls		Dec. 31, 2008 MMbls
Reserve Quantities [Line Items]
Conversion rate of gas reserves from barrels of oil to Boe	6
U.S. Onshore [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves	403		411
Proved developed and undeveloped reserves, revisions other than price	(2)
Proved developed and undeveloped reserves, extensions and discoveries	118
Canada [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves	379		420
Proved developed and undeveloped reserves, revisions other than price	(14)
Proved developed and undeveloped reserves, extensions and discoveries	30
North America [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves	782		831
Proved developed and undeveloped reserves, revisions other than price	(16)
Proved developed and undeveloped reserves, extensions and discoveries	148
Oil (MMBbls) [Member] | U.S. Onshore [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves	168		148		139		133
Proved developed and undeveloped reserves, revisions due to prices	2		4		9
Proved developed and undeveloped reserves, revisions other than price	(1)		2
Proved developed and undeveloped reserves, extensions and discoveries	36		19		9
Proved developed and undeveloped reserves, production	(17)		(14)		(12)
Proved developed and undeveloped reserves, sale of reserves			(2)
Proved developed reserves, volume	146		131		119		111
Proved developed producing reserves, BOE	139		123		112		103
Proved undeveloped reserves, volume	22		17		20		22
Oil (MMBbls) [Member] | U.S. Offshore [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves					33		34
Proved developed and undeveloped reserves, revisions due to prices			1		2
Proved developed and undeveloped reserves, revisions other than price			2		1
Proved developed and undeveloped reserves, extensions and discoveries			1		2
Proved developed and undeveloped reserves, production			(2)		(5)
Proved developed and undeveloped reserves, sale of reserves			(35)		(1)
Proved developed reserves, volume					21		22
Proved developed producing reserves, BOE					12		9
Proved undeveloped reserves, volume					12		12
Oil (MMBbls) [Member] | Total U.S [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves	168		148		172		167
Proved developed and undeveloped reserves, revisions due to prices	2		5		11
Proved developed and undeveloped reserves, revisions other than price	(1)		4		1
Proved developed and undeveloped reserves, extensions and discoveries	36		20		11
Proved developed and undeveloped reserves, production	(17)		(16)		(17)
Proved developed and undeveloped reserves, sale of reserves			(37)		(1)
Proved developed reserves, volume	146		131		140		133
Proved developed producing reserves, BOE	139		123		124		112
Proved undeveloped reserves, volume	22		17		32		34
Oil (MMBbls) [Member] | Canada [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves	537		533		514		134
Proved developed and undeveloped reserves, revisions due to prices	(15)		(24)		291
Proved developed and undeveloped reserves, revisions other than price	11		9		(8)
Proved developed and undeveloped reserves, extensions and discoveries	36		59		122
Proved developed and undeveloped reserves, production	(28)		(25)		(25)
Proved developed reserves, volume	163		126		149		110
Proved developed producing reserves, BOE	155		116		137		91
Proved undeveloped reserves, volume	374		407		365		24
Oil (MMBbls) [Member] | North America [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves	705		681		686		301
Proved developed and undeveloped reserves, revisions due to prices	(13)		(19)		302
Proved developed and undeveloped reserves, revisions other than price	10		13		(7)
Proved developed and undeveloped reserves, extensions and discoveries	72		79		133
Proved developed and undeveloped reserves, production	(45)		(41)		(42)
Proved developed and undeveloped reserves, sale of reserves			(37)		(1)
Proved developed reserves, volume	309		257		289		243
Proved developed producing reserves, BOE	294		239		261		203
Proved undeveloped reserves, volume	396		424		397		58
Gas (Bcf) [Member] | U.S. Onshore [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves	9,507		9,065		8,127		7,979
Proved developed and undeveloped reserves, revisions due to prices	(1)		449		(661)
Proved developed and undeveloped reserves, revisions other than price	(243)		105		119
Proved developed and undeveloped reserves, extensions and discoveries	1,410		1,088		1,387
Proved developed and undeveloped reserves, purchase of reserves	16		12		1
Proved developed and undeveloped reserves, production	(740)		(699)		(698)
Proved developed and undeveloped reserves, sale of reserves			(17)
Proved developed reserves, volume	7,957		7,280		6,447		6,469
Proved developed producing reserves, BOE	7,409		6,702		5,860		5,787
Proved undeveloped reserves, volume	1,550		1,785		1,680		1,510
Gas (Bcf) [Member] | U.S. Offshore [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves					342		390
Proved developed and undeveloped reserves, revisions due to prices			2		(4)
Proved developed and undeveloped reserves, revisions other than price			(26)		(62)
Proved developed and undeveloped reserves, extensions and discoveries			7		64
Proved developed and undeveloped reserves, production			(17)		(45)
Proved developed and undeveloped reserves, sale of reserves			(308)		(1)
Proved developed reserves, volume					185		212
Proved developed producing reserves, BOE					137		64
Proved undeveloped reserves, volume					157		178
Gas (Bcf) [Member] | Total U.S [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves	9,507		9,065		8,469		8,369
Proved developed and undeveloped reserves, revisions due to prices	(1)		451		(665)
Proved developed and undeveloped reserves, revisions other than price	(243)		79		57
Proved developed and undeveloped reserves, extensions and discoveries	1,410		1,095		1,451
Proved developed and undeveloped reserves, purchase of reserves	16		12		1
Proved developed and undeveloped reserves, production	(740)		(716)		(743)
Proved developed and undeveloped reserves, sale of reserves			(325)		(1)
Proved developed reserves, volume	7,957		7,280		6,632		6,681
Proved developed producing reserves, BOE	7,409		6,702		5,997		5,851
Proved undeveloped reserves, volume	1,550		1,785		1,837		1,688
Gas (Bcf) [Member] | Canada [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves	979		1,218		1,288		1,510
Proved developed and undeveloped reserves, revisions due to prices	(60)		21		(29)
Proved developed and undeveloped reserves, revisions other than price	(38)		(17)		(14)
Proved developed and undeveloped reserves, extensions and discoveries	58		131		67
Proved developed and undeveloped reserves, purchase of reserves	20		9		6
Proved developed and undeveloped reserves, production	(213)		(214)		(223)
Proved developed and undeveloped reserves, sale of reserves	(6)				(29)
Proved developed reserves, volume	951		1,144		1,213		1,357
Proved developed producing reserves, BOE	862		1,031		1,075		1,194
Proved undeveloped reserves, volume	28		74		75		153
Gas (Bcf) [Member] | North America [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves	10,486		10,283		9,757		9,879
Proved developed and undeveloped reserves, revisions due to prices	(61)		472		(694)
Proved developed and undeveloped reserves, revisions other than price	(281)		62		43
Proved developed and undeveloped reserves, extensions and discoveries	1,468		1,226		1,518
Proved developed and undeveloped reserves, purchase of reserves	36		21		7
Proved developed and undeveloped reserves, production	(953)		(930)		(966)
Proved developed and undeveloped reserves, sale of reserves	(6)		(325)		(30)
Proved developed reserves, volume	8,908		8,424		7,845		8,038
Proved developed producing reserves, BOE	8,271		7,733		7,072		7,045
Proved undeveloped reserves, volume	1,578		1,859		1,912		1,841
Natural Gas Liquids (MMBbls) [Member] | U.S. Onshore [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves	525		449		385		315
Proved developed and undeveloped reserves, revisions due to prices	4		14		(11)
Proved developed and undeveloped reserves, revisions other than price	1		13		36
Proved developed and undeveloped reserves, extensions and discoveries	102		68		70
Proved developed and undeveloped reserves, purchase of reserves	2
Proved developed and undeveloped reserves, production	(33)		(28)		(25)
Proved developed and undeveloped reserves, sale of reserves			(3)
Proved developed reserves, volume	402		353		293		260
Proved developed producing reserves, BOE	372		318		265		230
Proved undeveloped reserves, volume	123		96		92		55
Natural Gas Liquids (MMBbls) [Member] | U.S. Offshore [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves					2		2
Proved developed and undeveloped reserves, revisions other than price			3		1
Proved developed and undeveloped reserves, production					(1)
Proved developed and undeveloped reserves, sale of reserves			(5)
Proved developed reserves, volume					1		1
Proved developed producing reserves, BOE					1
Proved undeveloped reserves, volume					1		1
Natural Gas Liquids (MMBbls) [Member] | Total U.S [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves	525		449		387		317
Proved developed and undeveloped reserves, revisions due to prices	4		14		(11)
Proved developed and undeveloped reserves, revisions other than price	1		16		37
Proved developed and undeveloped reserves, extensions and discoveries	102		68		70
Proved developed and undeveloped reserves, purchase of reserves	2
Proved developed and undeveloped reserves, production	(33)		(28)		(26)
Proved developed and undeveloped reserves, sale of reserves			(8)
Proved developed reserves, volume	402		353		294		261
Proved developed producing reserves, BOE	372		318		266		230
Proved undeveloped reserves, volume	123		96		93		56
Natural Gas Liquids (MMBbls) [Member] | Canada [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves	27		30		34		35
Proved developed and undeveloped reserves, revisions due to prices	(1)		(1)		2
Proved developed and undeveloped reserves, revisions other than price			(1)
Proved developed and undeveloped reserves, extensions and discoveries	2		2		1
Proved developed and undeveloped reserves, production	(4)		(4)		(4)
Proved developed reserves, volume	26		28		32		31
Proved developed producing reserves, BOE	24		26		28		29
Proved undeveloped reserves, volume	1		2		2		4
Natural Gas Liquids (MMBbls) [Member] | North America [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves	552		479		421		352
Proved developed and undeveloped reserves, revisions due to prices	3		13		(9)
Proved developed and undeveloped reserves, revisions other than price	1		15		37
Proved developed and undeveloped reserves, extensions and discoveries	104		70		71
Proved developed and undeveloped reserves, purchase of reserves	2
Proved developed and undeveloped reserves, production	(37)		(32)		(30)
Proved developed and undeveloped reserves, sale of reserves			(8)
Proved developed reserves, volume	428		381		326		292
Proved developed producing reserves, BOE	396		344		294		259
Proved undeveloped reserves, volume	124		98		95		60
Total (MMBoe) [Member] | U.S. Onshore [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves	2,278	[1]	2,107	[1]	1,878	[1]	1,777	[1]
Proved developed and undeveloped reserves, revisions due to prices	6	[1]	92	[1]	(113)	[1]
Proved developed and undeveloped reserves, revisions other than price	(41)	[1]	32	[1]	57	[1]
Proved developed and undeveloped reserves, extensions and discoveries	374	[1]	269	[1]	311	[1]
Proved developed and undeveloped reserves, purchase of reserves	5	[1]	2	[1]
Proved developed and undeveloped reserves, production	(173)	[1]	(158)	[1]	(154)	[1]
Proved developed and undeveloped reserves, sale of reserves			(8)	[1]
Proved developed producing reserves, BOE	1,746	[1]	1,557	[1]	1,354	[1]	1,298	[1]
Proved developed reserves, BOE	1,875	[1]	1,696	[1]	1,486	[1]	1,449	[1]
Proved undeveloped reserves, BOE	403	[1]	411	[1]	392	[1]	328	[1]
Total (MMBoe) [Member] | U.S. Offshore [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves					92	[1]	101	[1]
Proved developed and undeveloped reserves, revisions due to prices			1	[1]	1	[1]
Proved developed and undeveloped reserves, revisions other than price			1	[1]	(8)	[1]
Proved developed and undeveloped reserves, extensions and discoveries			2	[1]	12	[1]
Proved developed and undeveloped reserves, production			(5)	[1]	(13)	[1]
Proved developed and undeveloped reserves, sale of reserves			(91)	[1]	(1)	[1]
Proved developed producing reserves, BOE					35	[1]	20	[1]
Proved developed reserves, BOE					53	[1]	59	[1]
Proved undeveloped reserves, BOE					39	[1]	42	[1]
Total (MMBoe) [Member] | Total U.S [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves	2,278	[1]	2,107	[1]	1,970	[1]	1,878	[1]
Proved developed and undeveloped reserves, revisions due to prices	6	[1]	93	[1]	(112)	[1]
Proved developed and undeveloped reserves, revisions other than price	(41)	[1]	33	[1]	49	[1]
Proved developed and undeveloped reserves, extensions and discoveries	374	[1]	271	[1]	323	[1]
Proved developed and undeveloped reserves, purchase of reserves	5	[1]	2	[1]
Proved developed and undeveloped reserves, production	(173)	[1]	(163)	[1]	(167)	[1]
Proved developed and undeveloped reserves, sale of reserves			(99)	[1]	(1)	[1]
Proved developed producing reserves, BOE	1,746	[1]	1,557	[1]	1,389	[1]	1,318	[1]
Proved developed reserves, BOE	1,875	[1]	1,696	[1]	1,539	[1]	1,508	[1]
Proved undeveloped reserves, BOE	403	[1]	411	[1]	431	[1]	370	[1]
Total (MMBoe) [Member] | Canada [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves	727	[1]	766	[1]	763	[1]	421	[1]
Proved developed and undeveloped reserves, revisions due to prices	(27)	[1]	(21)	[1]	289	[1]
Proved developed and undeveloped reserves, revisions other than price	6	[1]	5	[1]	(11)	[1]
Proved developed and undeveloped reserves, extensions and discoveries	47	[1]	83	[1]	135	[1]
Proved developed and undeveloped reserves, purchase of reserves	3	[1]	2	[1]	1	[1]
Proved developed and undeveloped reserves, production	(67)	[1]	(65)	[1]	(66)	[1]
Proved developed and undeveloped reserves, sale of reserves	(1)	[1]	(1)	[1]	(6)	[1]
Proved developed producing reserves, BOE	323	[1]	314	[1]	344	[1]	319	[1]
Proved developed reserves, BOE	348	[1]	346	[1]	383	[1]	367	[1]
Proved undeveloped reserves, BOE	379	[1]	420	[1]	380	[1]	54	[1]
Total (MMBoe) [Member] | North America [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves	3,005	[1]	2,873	[1]	2,733	[1]	2,299	[1]
Proved developed and undeveloped reserves, revisions due to prices	(21)	[1]	72	[1]	177	[1]
Proved developed and undeveloped reserves, revisions other than price	(35)	[1]	38	[1]	38	[1]
Proved developed and undeveloped reserves, extensions and discoveries	421	[1]	354	[1]	458	[1]
Proved developed and undeveloped reserves, purchase of reserves	8	[1]	4	[1]	1	[1]
Proved developed and undeveloped reserves, production	(240)	[1]	(228)	[1]	(233)	[1]
Proved developed and undeveloped reserves, sale of reserves	(1)	[1]	(100)	[1]	(7)	[1]
Proved developed producing reserves, BOE	2,069	[1]	1,871	[1]	1,733	[1]	1,637	[1]
Proved developed reserves, BOE	2,223	[1]	2,042	[1]	1,922	[1]	1,875	[1]
Proved undeveloped reserves, BOE	782	[1]	831	[1]	811	[1]	424	[1]

[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 gas and oil. This rate is not necessarily indicative of the relationship of natural gas and oil prices. Natural gas liquids reserves are converted to Boe on a one-to-one basis with oil.

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Income Taxes (Schedule Of Effective Income Tax Reconciliation) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Income Taxes [Abstract]
Expected income tax expense (benefit) based on U.S. statutory tax rate of 35%	$ 1,502	$ 1,249	$ (1,584)
Assumed repatriations	725	144	55
State income taxes	70	31	(99)
Taxation on Canadian operations	(91)	(60)	(31)
Other	(50)	(129)	(114)
Total income tax expense (benefit)	$ 2,156	$ 1,235	$ (1,773)

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Other Comprehensive Earnings (Tables)

12 Months Ended

Dec. 31, 2011

Other Comprehensive Earnings [Abstract]

Components Of Other Comprehensive Earnings

	Year Ended December 31,
	2011	2010	2009
	(In millions)
Foreign currency translation:
Accumulated foreign currency translation at beginning of year	$     1,993	$     1,616	$         685
Change in cumulative translation adjustment	(200)	397	993
Income tax benefit (expense)	9	(20)	(62)
Accumulated foreign currency translation at end of year	1,802	1,993	1,616
Pension and postretirement benefit plans:
Accumulated pension and postretirement benefit at beginning of year	(233)	(231)	(302)
Net actuarial (loss) gain and prior service cost arising in current year	(21)	(33)	59
Income tax benefit (expense)	8	11	(22)
Recognition of net actuarial loss and prior service cost in net earnings.	30	31	54
Income tax expense	(11)	(11)	(20)
Accumulated pension and postretirement benefits at end of year	(227)	(233)	(231)
Accumulated other comprehensive earnings, net of tax	$     1,575	$     1,760	$     1,385

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Debt And Related Expenses

12 Months Ended

Dec. 31, 2011

Debt And Related Expenses [Abstract]

Debt And Related Expenses

14. Debt and Related Expenses

A summary of Devon's debt is as follows:

	December 31,
	2011	2010
	(In millions)
Commercial paper	$       3,726	$            —
Other debentures and notes:
6.875% retired upon maturity on September 30, 2011	—	1,750
5.625% due January 15, 2014	500	500
Non-interest bearing promissory note due June 29, 2014	85	144
2.40% due July 15, 2016	500	—
8.25% due July 1, 2018	125	125
6.30% due January 15, 2019	700	700
4.00% due July 15, 2021	500	—
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
5.60% due July 15, 2041	1,250	—
Other	—	9
Net discount on other debentures and notes	(6)	2
Total debt	9,780	5,630
Less amount classified as short-term debt	3,811	1,811
Long-term debt	$       5,969	$   3,819

Debt maturities as of December 31, 2011, excluding premiums and discounts, are as follows (in millions):

2012	$       3,811
2013	—
2014	500
2015	—
2016	500
2017 and thereafter	4,975
Total	$       9,786

Credit Lines

Devon has a $2.65 billion syndicated, unsecured revolving line of credit (the "Senior Credit Facility"). The maturity date for $2.19 billion of the Senior Credit Facility is April 7, 2013. The maturity date for the remaining $0.46 billion is April 7, 2012. All amounts outstanding will be due and payable on the respective maturity dates unless the maturity is extended. Prior to each April 7 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. The Senior Credit Facility includes a revolving Canadian subfacility in a maximum amount of U.S. $0.5 billion.

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. However, Devon may 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. As of December 31, 2011, there were no borrowings under the Senior Credit Facility.

The Senior Credit Facility contains only one material financial covenant. This covenant requires Devon's ratio of total funded debt to total capitalization to be less than 65 percent. The credit agreement contains definitions of total funded debt and total capitalization that include adjustments to the respective amounts reported in the accompanying financial statements. Also, total capitalization is adjusted to add back noncash financial writedowns such as full cost ceiling impairments or goodwill impairments. As of December 31, 2011, Devon was in compliance with this covenant. Devon's debt-to-capitalization ratio at December 31, 2011, as calculated pursuant to the terms of the agreement, was 22.8 percent.

Commercial Paper

Devon has access to $5.0 billion of short-term credit under its commercial paper program. Commercial paper debt generally has a maturity of between 1 and 90 days, although it can have a maturity of up to 365 days, and bears interest at rates agreed to at the time of the borrowing. The interest rate is generally based on a standard index such as the Federal Funds Rate, LIBOR, or the money market rate as found on the commercial paper market. As of December 31, 2011, Devon's weighted average borrowing rate on its commercial paper borrowings was 0.45 percent.

Other Debentures and Notes

Following are descriptions of the various other debentures and notes outstanding at December 31, 2011, as listed in the table presented at the beginning of this note.

5.625% Notes due January 15, 2014 and 6.30% Notes due January 15, 2019

In January 2009, Devon issued $1.2 billion of senior notes. The net proceeds were used primarily to repay outstanding commercial paper as of December 31, 2008. These notes are unsecured and unsubordinated obligations of Devon.

Non-Interest Bearing Promissory Note due June 29, 2014

In June 2010, Devon issued a four-year $155 million Canadian dollar non-interest bearing promissory note in connection with the formation of the Pike oil sands joint venture. The present value of the note was $139 million on the issue date based upon an effective interest rate of 3.125%. At December 31, 2011, the note had a carrying value of $85 million, which is presented as short-term debt in the accompanying balance sheet because it is expected to be repaid during 2012.

2.40% Notes due July 15, 2016, 4.00% Notes due July 15, 2021 and 5.60% Notes due July 15, 2041  

In July 2011, Devon issued $2.25 billion of senior notes. The net proceeds were used to repay outstanding commercial paper debt. These notes are unsecured and unsubordinated obligations of Devon.

Ocean Debt

On April 25, 2003, Devon merged with Ocean Energy, Inc. and assumed certain debt instruments. The table below summarizes the debt assumed that remains outstanding as of December 31, 2011, including the fair value of the debt at April 25, 2003, and the effective interest rate of the debt after determining the fair values using April 25, 2003, market interest rates. The premiums resulting from fair values exceeding face values are being amortized using the effective interest method. Both notes are general unsecured obligations of Devon.

Debt Assumed	Fair Value of Debt Assumed	Effective Rate of Debt Assumed
	(In millions)
8.250% due July 2018 (principal of $125 million)	$            147	5.5%
7.500% due September 2027 (principal of $150 million)	$            169	6.5%

7.875% Debentures due September 30, 2031

In October 2001, Devon, through Devon Financing Corporation, U.L.C. ("Devon Financing"), a wholly owned finance subsidiary, sold 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 were used to fund a portion of the acquisition of Anderson Exploration.

7.95% Notes due April 15, 2032

In March 2002, Devon sold these notes, which are unsecured and unsubordinated obligations of Devon. The net proceeds were used to retire other indebtedness.

Interest Expense

The following schedule includes the components of interest expense.

	Year Ended December 31,
	2011	2010	2009
	(In millions)
Interest based on debt outstanding	$         414	$         408	$         437
Capitalized interest	(72)	(76)	(94)
Early retirement of debt	—	19	—
Other	10	12	6
Total	$         352	$         363	$         349

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Retirement Plans (Schedule Of Expected Cash Flow Information For Pension And Other Postretirement Benefit Plans) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2011
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Devon's 2012 contributions	$ 9
2012	44
2013	49
2014	52
2015	56
2016	61
2017 to 2021	390
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Devon's 2012 contributions	3
2012	3
2013	3
2014	3
2015	3
2016	3
2017 to 2021	$ 14