Edgar Filing: DEVON ENERGY CORP/DE

Form 10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2011

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.

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.

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.

LOGO

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.

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.

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

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

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.

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:

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

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a petroleum engineering license, or similar certification;

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memberships in oil and gas industry or trade groups; and

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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:

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Hugoton Gas Field (Kansas),

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Sho-Vel-Tum CO₂ Flood (Oklahoma),

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

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Dagger Draw Oil Field (New Mexico),

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Clarke Lake Gas Field (Alberta, Canada),

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

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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:

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

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oversee the integrity of our reserves evaluation and reporting system;

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

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

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monitor the performance of our independent engineering consultants.

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)		Production Cost (Per Boe)
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.

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.

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	%		—

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;

•

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.

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.

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.

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.

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

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.

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		Dividends Per Share
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

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.

LOGO

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.

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.

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

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.

•

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.

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.


	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.

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.

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.

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

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.

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

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

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	%)

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		$	—

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

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.

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.

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.

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.

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.

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

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

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

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.

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.

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.

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

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.

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