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, 2012

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.)

333 West Sheridan Avenue, Oklahoma City, Oklahoma		73102-5015
(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 x 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 x

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 x 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 x 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 x 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 x

The aggregate market value of the voting common stock held by non-affiliates of the registrant as of June 29, 2012, was approximately $23.3 billion, based upon the closing price of $57.99 per share as reported by the New York Stock Exchange on such date. On February 6, 2013, 406.0 million shares of common stock were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Proxy statement for the 2013 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			22
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations			23
Item 7A. Quantitative and Qualitative Disclosures about Market Risk			44
Item 8. Financial Statements and Supplementary Data			46
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			102
Item 9A. Controls and Procedures			102
Item 9B. Other Information			102

PART III

Item 10. Directors, Executive Officers and Corporate Governance			103
Item 11. Executive Compensation			103
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			103
Item 13. Certain Relationships and Related Transactions, and Director Independence			103
Item 14. Principal Accountant Fees and Services			103

PART IV

Item 15. Exhibits and Financial Statement Schedules			104
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, 2012 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 natural gas liquids (“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

Items 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 bitumen 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 333 West Sheridan, Oklahoma City, OK 73102-5015 (telephone 405/235-3611). As of December 31, 2012, we had approximately 5,700 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 strive to maximize long-term value for our shareholders by delivering strong full-cycle margins on our assets and top-quartile per share returns. In pursuit of this objective, we focus on growing cash flow per share, adjusted for debt, which has the greatest long-term correlation to share price appreciation in our industry. We also focus on growth in earnings, production and reserves, all on a per debt-adjusted share basis. We do this by:

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exercising capital allocation and investment discipline;

•

focusing on high-return projects;

•

maintaining a low cost structure;

•

preserving financial strength and flexibility; and

•

balancing our production and resource mix between oil, natural gas and NGLs.

We hold 14 million net acres, of which roughly two-thirds are undeveloped, providing us with a platform for future growth. An important factor in determining the direction of our growth strategy, particularly our capital allocation, is the current and forecasted pricing applicable to our production. Our industry had been operating in an environment that had involved depressed North American gas prices contrasted with more robust prices for oil and NGLs. Consequently, with a production profile that is approximately 60% gas, we have focused our recent capital programs on higher-margin, liquids-based resource capture and development. With recent changes in market conditions that have led to challenged prices for NGLs and Canadian heavy oil, we are refining our capital allocations as needed and evaluating other investment opportunities to maximize and accelerate growth in cash flow per debt-adjusted share.

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 2012. 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. In the following table and throughout this report, we convert our proved reserves and production to Boe. 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. Bitumen and NGL proved reserves and production are converted to Boe on a one-to-one basis with oil.


	Proved Reserves								Production
	MMBoe		% of Total			% Liquids			MBoe/d		% of Total			% Liquids			Total Net Acres		Gross Wells Drilled
														(In thousands)
U.S.
Barnett Shale		1,058		35.7	%		23.7	%		227.5		33.3	%		21.3	%		620		322
Cana-Woodford Shale		427		14.4	%		41.4	%		48.3		7.1	%		30.0	%		260		164
Permian Basin		227		7.6	%		79.6	%		61.6		9.0	%		77.1	%		1,530		241
Gulf Coast/East Texas		221		7.5	%		25.0	%		61.3		9.0	%		23.7	%		1,660		50
Rocky Mountains		157		5.3	%		37.1	%		58.7		8.6	%		28.1	%		1,165		16
Granite Wash		51		1.7	%		41.0	%		18.7		2.7	%		45.5	%		65		48
Mississippian		6		0.2	%		61.5	%		1.0		0.2	%		76.8	%		545		35
Other		89		3.1	%		32.6	%		22.5		3.3	%		29.2	%		1,155		71

Total U.S.		2,236		75.5	%		34.7	%		499.7		73.2	%		31.5	%		7,000		947

Canada
Canadian Oil Sands		528		17.8	%		100.0	%		47.6		7.0	%		100.0	%		90		16
Lloydminster		38		1.3	%		86.9	%		37.0		5.4	%		82.5	%		2,740		173
Other		161		5.4	%		32.4	%		98.0		14.4	%		20.2	%		4,245		72

Total Canada		727		24.5	%		84.3	%		182.6		26.8	%		53.6	%		7,075		261

Devon		2,963		100.0	%		46.9	%		682.3		100.0	%		37.4	%		14,075		1,208

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, NGLs and condensate.

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 in excess of 5,000 wells in the Barnett Shale since 2002, yet we still have several thousand remaining drilling locations. In 2013, we plan to drill approximately 150 wells, focused in the areas with the highest liquids content.

In addition, we have a significant processing plant and gathering system in north Texas to service these properties. Our Bridgeport plant is one of the largest processing plants in the U.S., currently with 650 MMcf per day of total capacity, and an additional 140 MMcf expansion expected in 2013 to accommodate increasing demand from our liquids-rich drilling. These midstream assets also include an extensive pipeline system and a 15 MBbls per day NGL fractionator.

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 Shale is a leading growth area for us 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 Shale. During 2012, we increased our production by 45 percent. We have several thousand remaining drilling locations. In 2013, we plan to drill approximately 150 wells.

In addition, we have a significant processing plant and gathering system to service these properties. Our Cana plant currently has 200 MMcf per day of total capacity, and an additional 150 MMcf expansion expected in 2013 to accommodate increasing demand from our liquids-rich drilling.

Permian Basin — Our acreage is located in various counties in west Texas and southeast New Mexico. These properties have been a legacy asset for us and continue to offer both exploration and low-risk development opportunities. We entered into a joint venture arrangement with Sumitomo in 2012, covering approximately 650,000 net acres in the Cline Shale and Midland-Wolfcamp Shale and further strengthening the capital efficiency of our exploration programs. In addition to the Cline and Wolfcamp Shale activity, our current drilling activity continues to target conventional and non-conventional oil and liquids-rich gas targets within the Conventional Delaware, Bone Spring, Midland-Wolfcamp, Wolfberry and Avalon Shale plays. In 2013, we plan to drill approximately 300 wells.

Gulf Coast/East Texas— Our acreage is located primarily in Harrison, Marion, Panola and Shelby counties in the Carthage/Groesbeck areas of east Texas. These wells produce natural gas and NGLs from conventional reservoirs. In 2013, we plan to drill approximately 10 wells, focused in the areas with the highest liquids content.

Rocky Mountains— These leases are primarily concentrated in the Washakie area 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 area for many years. In 2013, we plan to drill approximately 25 wells, focused in the areas with the highest liquids content.

In recent years we also have acquired a significant acreage position in the DJ Basin. This acquired acreage, along with our legacy Powder River Basin acreage, primarily targets oil in the Niobrara formation. These acres are principally located in eastern Wyoming and are being explored using 3D seismic to identify appropriate drilling zones. Furthermore, in early 2012, we entered into a joint venture arrangement with Sinopec to explore and develop the Niobrara and other new venture properties.

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 2013, we plan to drill approximately 50 wells.

Mississippian — These properties represent some of our newest assets, with most of our position acquired since 2011. Located in northern Oklahoma and southern Kansas, these acres target oil in the Mississippian Lime and Woodford Shale and are being explored and developed under our joint venture arrangement with Sinopec and independently by us on the acreage outside of our area of mutual interest with Sinopec. In 2013, we plan to drill approximately 400 wells.

Canada

Canadian Oil Sands — We are the first and only U.S.-based independent energy company to develop and operate a bitumen oil sands project in Canada. We currently have two main projects, Jackfish and Pike, located in Alberta, Canada.

Jackfish is our thermal heavy oil project in the non-conventional oil sands of east central Alberta. 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. Jackfish production increased 37 percent in 2012 as the second phase of Jackfish, which came on-line in the second quarter of 2011, continued to increase production. Construction of a third phase began in 2012 with plant startup expected by year-end 2014. 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.

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, 2012. We filed a regulatory application in 2012 for the first phase of this project, with gross capacity of 105 MBbls per day, in which we hold a 50 percent interest.

To facilitate the delivery of our heavy oil production, we have a 50 percent interest in the Access Pipeline transportation system in Canada. This pipeline system allows us to blend our Jackfish, and eventually our Pike, heavy oil production with condensate or other blend-stock and transport the combined product to the Edmonton area for sale. The Access Pipeline system is currently undergoing a capacity expansion that we anticipate will be completed in late 2014. This expansion, in which we have a 50% interest, is expected to create adequate capacity to transport our anticipated Jackfish and Pike heavy oil production to the Edmonton market hub. Additionally, it will increase the transport capacity of condensate diluent available at our thermal oil facilities.

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.

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 approximately 2,500 wells in the area since 2003. In 2013, we plan to drill approximately 155 wells.

Proved Reserves

For estimates of our 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 2012 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 twelve years, including the past five in his current position. During his career, he has been 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 2012, we engaged two such firms to audit 92 percent of our proved reserves. LaRoche Petroleum Consultants, Ltd. audited 91 percent of our 2012 U.S. reserves, and Deloitte audited 93 percent 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
Year Ended December 31,	Oil (MMBbls)		Bitumen (MMBbls)		Gas (Bcf)		NGLs (MMBbls)		Total (MMBoe)
2012
Barnett Shale		1		—		393		17		83
Jackfish		—		17		—		—		17
U.S.		21		—		752		36		183
Canada		15		17		186		4		67
Total North America		36		17		938		40		250
2011
Barnett Shale		1		—		367		16		78
Jackfish		—		13		—		—		13
U.S.		17		—		740		33		173
Canada		15		13		213		4		67
Total North America		32		13		953		37		240
2010
Barnett Shale		1		—		335		13		70
Jackfish		—		9		—		—		9
U.S.		16		—		716		28		163
Canada		16		9		214		4		65
Total North America		32		9		930		32		228


	Average Sales Price								Production Cost (Per Boe)
Year Ended December 31,	Oil (Per Bbl)		Bitumen (Per Bbl)		Gas (Per Mcf)		NGLs (Per Bbl)		Production Cost (Per Boe)
2012
Barnett Shale	$	91.45	$	—	$	2.23	$	27.57	$	3.91
Jackfish	$	—	$	47.75	$	—	$	—	$	19.48
U.S.	$	88.68	$	—	$	2.32	$	28.49	$	5.79
Canada	$	68.08	$	47.75	$	2.49	$	48.63	$	15.18
Total North America	$	80.35	$	47.75	$	2.36	$	30.42	$	8.30
2011
Barnett Shale	$	94.23	$	—	$	3.30	$	39.00	$	3.97
Jackfish	$	—	$	58.16	$	—	$	—	$	17.28
U.S.	$	91.19	$	—	$	3.50	$	39.47	$	5.35
Canada	$	74.32	$	58.16	$	3.87	$	55.99	$	13.82
Total North America	$	83.16	$	58.16	$	3.58	$	41.10	$	7.71
2010
Barnett Shale	$	77.40	$	—	$	3.55	$	29.97	$	3.87
Jackfish	$	—	$	52.51	$	—	$	—	$	16.81
U.S.	$	75.81	$	—	$	3.76	$	30.86	$	5.47
Canada	$	62.00	$	52.51	$	4.11	$	46.60	$	12.37
Total North America	$	68.75	$	52.51	$	3.84	$	32.61	$	7.42

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
2012
U.S.		668.2		1.0		24.6		4.9		692.8		5.9		698.7
Canada		209.3		4.0		27.3		1.0		236.6		5.0		241.6

Total North America		877.5		5.0		51.9		5.9		929.4		10.9		940.3

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

(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, 2013, results of our wells that were in progress on December 31, 2012.


	Productive				Dry				Still in Progress				Total
	Gross⁽¹⁾		Net⁽²⁾		Gross⁽¹⁾		Net ⁽²⁾		Gross⁽¹⁾		Net⁽²⁾		Gross⁽¹⁾		Net⁽²⁾
U.S.		65.0		53.6		—		—		126.0		65.6		191.0		119.2
Canada		8.0		7.6		—		—		1.0		0.7		9.0		8.3

Total North America		73.0		61.2		—		—		127.0		66.3		200.0		127.5

(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, 2012.


	Oil Wells⁽¹⁾				Natural Gas Wells				Total Wells
	Gross⁽²⁾		Net⁽³⁾		Gross⁽²⁾		Net⁽³⁾		Gross⁽²⁾		Net⁽³⁾
U.S.		8,655		3,202		20,858		13,672		29,513		16,874
Canada		5,316		4,119		5,578		3,320		10,894		7,439

Total North America		13,971		7,321		26,436		16,992		40,407		24,313

(1)	Includes bitumen wells.

(2)	Gross wells are the sum of all wells in which we own an interest.

(3)	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 25,000 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, 2012. The acreage in the table includes 1.4 million, 0.8 million and 1.6 million net acres subject to leases that are scheduled to expire during 2013, 2014 and 2015, respectively.


	Developed				Undeveloped				Total
	Gross⁽¹⁾		Net⁽²⁾		Gross⁽¹⁾		Net ⁽²⁾		Gross⁽¹⁾		Net⁽²⁾
	(In thousands)
U.S.		3,195		2,210		7,830		4,790		11,025		7,000
Canada		3,665		2,270		6,635		4,805		10,300		7,075

Total North America		6,860		4,480		14,465		9,595		21,325		14,075

(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

Our marketing and midstream operations provide gathering, compression, treating, processing, fractionation and marketing services to us and other third-parties. We generate revenues from these operations by collecting service fees and selling processed gas and NGLs. The expenses associated with these operations primarily consist of the costs to operate our gathering systems, plants and related facilities, as well as purchases of gas and NGLs.

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, gas and NGL 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 2013, our production was sold under the following contracts.


	Short-Term						Long-Term
	Variable			Fixed			Variable			Fixed
Oil and bitumen		76	%		—			24	%		—
Natural gas		73	%		—			27	%		—
NGLs		78	%		14	%		1	%		7	%

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 December 31, 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 and bitumen (MMBbls)		124		14		30		31		49
Natural gas (Bcf)		1,175		623		374		133		45
NGLs (MMBbls)		10		5		3		2		—

Total (MMBoe)		330		123		95		55		57

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 2012, 2011 and 2010, no purchaser accounted for over 10 percent of our revenues.

Competition

See “Item 1A. Risk Factors.”

Public Policy and Government Regulation

The oil and natural gas industry is subject to regulation throughout the world. Laws, rules, regulations and other policy implementation actions affecting the oil and natural gas industry have been pervasive and are under constant review for amendment or expansion. Numerous government agencies have issued extensive laws and regulations which are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. These laws and regulations increase the cost of doing business and consequently affect profitability. Because public policy changes are commonplace, and existing laws and regulations are frequently amended, we are unable to predict the future cost or impact of compliance. However, we do not expect that any of these laws and regulations will affect our operations differently 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 federal, state, provincial, tribal and local laws and regulations. These laws and regulations relate to matters that include:

•

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. These regulations limit the amounts of oil and gas we can produce from our wells and 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. Occasionally the federal and provincial governments of Canada also have established incentive programs, such as royalty rate reductions, royalty holidays, and tax credits, for the purpose of encouraging oil and gas exploration or enhanced recovery projects. These incentives generally increase our revenues, earnings and cash flow.

Marketing in Canada

Any oil or gas export 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 many 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:

•

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 yet 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:

•

supply of and 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 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 require substantial compliance costs and 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 and Indian lands. Currently, regulation of hydraulic fracturing is conducted primarily at the state level through permitting and other compliance requirements. We lease federal and Indian 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 of 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. Recently, the U.S. President and other policy makers have proposed provisions that would, if enacted, make significant changes to U.S. tax laws applicable to us. The most significant change to our business would eliminate the immediate deduction for intangible drilling and development costs. Such a change could have a material adverse effect on our profitability, financial condition and liquidity.

Climate Change – Policymakers in the U.S. and Canada are increasingly focusing on whether the emissions of greenhouse gases, such as carbon dioxide and methane, are contributing to harmful climatic changes. Policymakers at both the U.S. federal and state levels have introduced legislation and proposed new regulations that are designed to quantify and limit the emission of greenhouse gases through inventories, limitations and/or

taxes on greenhouse gas emissions. Legislative initiatives and discussions to date have focused on the development of cap-and-trade and/or carbon tax programs. A cap-and-trade program 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 could be relevant to us and our operations in several ways. First, the equipment we use to explore for, develop, produce and process oil and natural gas emits greenhouse gases. We could therefore be subject to caps, and penalties if emissions exceeded the caps. Second, the combustion of carbon-based fuels, such as the oil, gas and NGLs we sell, emits carbon dioxide and other greenhouse gases. Therefore, demand for our products could be reduced by imposition of caps and penalties on our customers. Carbon taxes could likewise affect us by being based on emissions from our equipment and/or emissions resulting from use of our products by our customers. Of overriding significance would be the point of regulation or taxation. Application of caps or taxes on companies such as Devon, based on carbon content of produced oil and gas volumes rather than on consumer emissions, could lead to penalties, fees or tax assessments for which there are no mechanisms to pass them through the distribution and consumption chain where fuel use or conservation choices are made. Moreover, because oil and natural gas are used as chemical feedstocks and not solely as fossil fuel, applying a carbon tax to oil and gas at the production stage would be excessive with respect to actual carbon emissions from petroleum fuels.

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 people 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 percent 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

Not applicable.

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

Not applicable.

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 6, 2013, there were 11,695 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 2012 and 2011, as well as the quarterly dividends per share paid during 2012 and 2011. 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
	High		Low		Per Share
2012:
Quarter Ended December 31, 2012	$	63.00	$	50.89	$	0.20
Quarter Ended September 30, 2012	$	63.95	$	54.56	$	0.20
Quarter Ended June 30, 2012	$	73.14	$	54.01	$	0.20
Quarter Ended March 31, 2012	$	76.34	$	62.13	$	0.20
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

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, 2007 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 the 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 2012. Such purchases represent shares received by us from employees and directors for the payment of personal income tax withholding on restricted stock vesting and stock option exercises.


Period	Total Number of Shares Purchased		Average Price Paid per Share
October 1 - October 31		6,000	$	60.15
November 1 - November 30		406,725	$	52.72
December 1 - December 31		459,320	$	52.24

Total		872,045	$	52.52

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. Eligible employees purchased approximately 57,000 shares of our common stock in 2012, 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.

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. Eligible Canadian employees purchased approximately 22,900 shares of our common stock in 2012, 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,
	2012			2011		2010		2009			2008
	(In millions, except per share amounts)
Revenues	$	9,502		$	11,454	$	9,940	$	8,015		$	13,858
Earnings (loss) from continuing operations⁽¹⁾	$	(185	)	$	2,134	$	2,333	$	(2,753	)	$	(3,039	)
Earnings (loss) per share from continuing operations - Basic	$	(0.47	)	$	5.12	$	5.31	$	(6.20	)	$	(6.86	)
Earnings (loss) per share from continuing operations - Diluted	$	(0.47	)	$	5.10	$	5.29	$	(6.20	)	$	(6.86	)
Cash dividends per common share	$	0.80		$	0.67	$	0.64	$	0.64		$	0.64
Weighted average common shares outstanding - Basic		405			417		440		444			444
Weighted average common shares outstanding - Diluted		405			418		441		444			444
Total assets⁽¹⁾	$	43,326		$	41,117	$	32,927	$	29,686		$	31,908
Long-term debt	$	8,455		$	5,969	$	3,819	$	5,847		$	5,661
Stockholders’ equity	$	21,278		$	21,430	$	19,253	$	15,570		$	17,060

(1)	During 2012, 2009 and 2008, we recorded noncash asset impairments totaling $2.0 billion ($1.3 billion after income taxes), $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 2012 Results

As an enterprise, we strive to optimize value for our shareholders by growing cash flow, 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.

2012 was a year of mixed results for Devon. We grew our production 4% and closed two significant joint venture transactions with a combined value of approximately $4.0 billion. Furthermore, with a focus on development of higher-margin oil and bitumen properties in our portfolio, we increased our oil and bitumen production 20% in 2012 and are positioned to deliver similar oil and bitumen growth in 2013. However, this growth was overshadowed by the effects of declining commodity prices, which negatively impacted a number of our 2012 financial performance measures, as well as our year-end proved reserves. Key measures of our 2012 performance are summarized below, which exclude amounts from our discontinued operations.


	Year Ended December 31,
	2012			Change			2011		Change			2010
	($ in millions, except per share amounts)
Net earnings (loss)	$	(185	)		-109	%	$	2,134		-9	%	$	2,333
Adjusted earnings⁽¹⁾	$	1,322			-48	%	$	2,536		+0	%	$	2,536
Earnings (loss) per share	$	(0.47	)		-109	%	$	5.10		-4	%	$	5.29
Adjusted earnings per share⁽¹⁾	$	3.26			-46	%	$	6.07		+6	%	$	5.75
Production (MBoe/d)		682.3			+4	%		657.7		+5	%		623.6
Realized price per Boe	$	28.65			-17	%	$	34.64		+9	%	$	31.91
Operating margin per Boe ⁽²⁾	$	19.41			-23	%	$	25.15		+1	%	$	24.89
Operating cash flow	$	4,930			-21	%	$	6,246		+24	%	$	5,022
Adjusted operating cash flow⁽¹⁾	$	4,892			-21	%	$	6,225		+7	%	$	5,840
Capitalized costs	$	8,474			+9	%	$	7,795		+13	%	$	6,920
Shareholder distributions ⁽³⁾	$	324			-88	%	$	2,610		+80	%	$	1,449
Reserves (MMBoe)		2,963			-1	%		3,005		+5	%		2,873

(1)

Adjusted earnings, adjusted earnings per share and adjusted operating cash flow are not financial measures prepared in accordance with accounting principles generally accepted in the U.S. (GAAP). For a description of adjusted earnings, adjusted earnings per share and adjusted operating cash flow as well as reconciliations to the comparable GAAP measures, see “Non-GAAP Measures” in this Item 7.

(2)

Computed as revenues from commodity sales, commodity derivatives settlements, and marketing and midstream operations, less expenses for lease operations, marketing and midstream operations, general and administration, taxes other than income taxes and interest, with the result divided by total production.

(3)	Includes common stock dividends and share repurchases.

Our 2012 net loss resulted from noncash asset impairments, which reduced our earnings by $2.0 billion ($1.3 billion after tax). Excluding the asset impairments and other items typically excluded by securities analysts, our adjusted earnings were $1.3 billion, or $3.26 per diluted share. This compares to adjusted earnings of $2.5 billion, or $6.07 per diluted share in 2011.

In spite of growing our production, our 2012 adjusted earnings, adjusted cash flow, operating margin and proved reserves declined largely due to the effects of lower commodity prices. In virtually all our operating areas, we realized lower prices in 2012 due to either declines in benchmarks or widening price differentials. The most significant price declines were associated with our gas and NGL production, for which we experienced realized price decreases of 34% and 26%, respectively. With increasing focus on oil and bitumen production growth, which generally require a higher cost to produce per unit than our gas projects, we were also impacted by upward pressure on operating costs.

We replaced 152% of our 2012 production from proved reserve extensions, discoveries and revisions other than price. Yet, our proved reserves decreased 1% overall due to significant downward revisions resulting from lower gas and NGL prices.

Business and Industry Outlook

During 2012, natural gas traded at prices we have not experienced for a decade. These low prices are the result of a significant imbalance between supply and demand in North America. On the supply side, new technologies, particularly hydraulic fracturing and horizontal drilling, have enabled natural gas producers to bring on line meaningful new supplies of natural gas around North America. On the demand side, the past winter was one of the warmest on record, which reduced demand for natural gas. Consequently, North America has an unusually high amount of gas in storage that will continue to oversupply the market. However, there are some favorable trends. Utilities around the country are switching from coal to natural gas at a meaningful rate. New petro-chemical plants are being built and other industries are expanding in the U.S. Looking to 2013, increased demand should cause natural gas prices to stabilize or possibly to increase moderately from 2012 levels.

As a result of the low natural gas prices, we and other producers have been focused on growing oil, bitumen and liquids-rich gas production. Similar to natural gas, regional imbalances between supply and demand of these liquids have caused price declines. In 2012, the most negative impact to us from these imbalances related to our U.S. NGLs and our Canadian heavy oil. The NGL imbalances have largely resulted from increased liquids-rich gas production without corresponding increases in either NGL pipeline delivery systems or consumer demand. We expect NGL prices will remain challenged for 2013 and, perhaps longer, due to the long-lead time associated with the construction of new petrochemical capacity. Our Canadian heavy oil production has recently been impacted by pipeline outages and refinery downtime. With increasing industry heavy oil production and current pipeline capacity, the pipeline outages and refinery downtimes had greater impacts to producers’ realized prices during 2012. Like other producers, we are beginning to use rail to deliver a portion of our heavy oil to downstream markets. We are also optimistic the U.S. government will approve construction of the Keystone XL pipeline. Provided the pipeline outages are not recurring and industry’s planned refinery expansions occur during the first half of 2013, the downward pressures on Canadian heavy oil prices should be relatively temporary in nature.

While we are optimistic about the long-term future of prices, we expect benchmark prices will continue to be volatile and in some cases will be challenged in 2013. We are most optimistic about oil prices and believe our oil properties largely represent the highest-return assets in our portfolio. Therefore, our near-term focus will be on these properties. We also realize that we possess a great deal of financial strength, flexibility and liquidity. We will use these resources to develop our portfolio of properties and explore other opportunities to maximize shareholder value, including monetization of our existing assets or entering into new ventures or acquisitions.

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,
	2012		Change			2011		Change			2010
Oil (MBbls/d)
U.S. Onshore		58.7		+28	%		46.0		+24	%		37.0
Canada		39.8		-5	%		41.7		-6	%		44.2

North America Onshore		98.5		+12	%		87.7		+8	%		81.2
U.S. Offshore		—		N/M			—		-100	%		5.2

Total		98.5		+12	%		87.7		+1	%		86.4

Bitumen (MBbls/d)
Canada		47.6		+37	%		34.8		+41	%		24.7

Gas (MMcf/d)
U.S. Onshore		2,054.5		+1	%		2,026.6		+6	%		1,913.8
Canada		508.3		-13	%		583.1		-1	%		586.9

North America Onshore		2,562.8		-2	%		2,609.7		+4	%		2,500.7
U.S. Offshore		—		N/M			—		-100	%		46.0

Total		2,562.8		-2	%		2,609.7		+2	%		2,546.7

NGLs (MBbls/d)
U.S. Onshore		98.6		+9	%		90.4		+17	%		77.3
Canada		10.5		+6	%		9.9		+2	%		9.8

North America Onshore		109.1		+9	%		100.3		+15	%		87.1
U.S. Offshore		—		N/M			—		-100	%		0.9

Total		109.1		+9	%		100.3		+14	%		88.0

Combined (MBoe/d)
U.S. Onshore		499.7		+5	%		474.1		+9	%		433.3
Canada		182.6		-1	%		183.6		+4	%		176.5

North America Onshore		682.3		+4	%		657.7		+8	%		609.8
U.S. Offshore		—		N/M			—		-100	%		13.8

Total		682.3		+4	%		657.7		+5	%		623.6


	Year Ended December 31,
	2012⁽¹⁾		Change			2011 ⁽¹⁾		Change			2010 ⁽¹⁾
Oil (per Bbl)
U.S. Onshore	$	88.68		-3	%	$	91.19		+21	%	$	75.53
Canada	$	68.08		-8	%	$	74.32		+20	%	$	62.00
North America Onshore	$	80.35		-3	%	$	83.16		+22	%	$	68.17
U.S. Offshore	$	—		N/M		$	—		-100	%	$	77.81
Total	$	80.35		-3	%	$	83.16		+21	%	$	68.75
Bitumen (per Bbl)
Canada	$	47.75		-18	%	$	58.16		+11	%	$	52.51
Gas (per Mcf)
U.S. Onshore	$	2.32		-34	%	$	3.50		-6	%	$	3.73
Canada	$	2.49		-36	%	$	3.87		-6	%	$	4.11
North America Onshore	$	2.36		-34	%	$	3.58		-6	%	$	3.82
U.S. Offshore	$	—		N/M		$	—		-100	%	$	5.12
Total	$	2.36		-34	%	$	3.58		-7	%	$	3.84
NGLs (per Bbl)
U.S. Onshore	$	28.49		-28	%	$	39.47		+28	%	$	30.78
Canada	$	48.63		-13	%	$	55.99		+20	%	$	46.60
North America Onshore	$	30.42		-26	%	$	41.10		+26	%	$	32.55
U.S. Offshore	$	—		N/M		$	—		-100	%	$	38.22
Total	$	30.42		-26	%	$	41.10		+26	%	$	32.61
Combined (per Boe)
U.S. Onshore	$	25.59		-18	%	$	31.31		+10	%	$	28.42
Canada	$	37.01		-14	%	$	43.23		+11	%	$	39.11
North America Onshore	$	28.65		-17	%	$	34.64		+10	%	$	31.52
U.S. Offshore	$	—		N/M		$	—		-100	%	$	49.06
Total	$	28.65		-17	%	$	34.64		+9	%	$	31.91

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

Commodity Sales

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


	Oil			Bitumen			Gas			NGLs			Total
	(In millions)
2010 sales	$	2,169		$	474		$	3,572		$	1,047		$	7,262
Change due to volumes		30			193			88			147			458
Change due to prices		461			72			(249	)		311			595

2011 sales		2,660			739			3,411			1,505			8,315
Change due to volumes		337			273			(52	)		137			695
Change due to prices		(101	)		(181	)		(1,148	)		(427	)		(1,857	)

2012 sales	$	2,896		$	831		$	2,211		$	1,215		$	7,153

Volumes 2012 vs. 2011 – Upstream sales increased $695 million due to a 4 percent increase in production. Oil and bitumen production were the largest drivers of the increase, accounting for nearly 90 percent of the higher sales. As a result of continued development of our liquids-rich properties in the Permian Basin, our oil sales increased $337 million. Bitumen sales increased $273 million due to development of our Jackfish thermal heavy oil projects in Canada. Additionally, our NGL sales increased $137 million as a result of continued drilling in the liquids-rich gas portions of the Barnett Shale, Cana-Woodford Shale and Granite Wash. These increases were partially offset by a slight decrease in our 2012 gas production, resulting in a $52 million decline in sales.

Volumes 2011 vs. 2010 – Upstream sales increased $458 million due to a 5 percent increase in production. Bitumen and NGL volume increases resulted in $340 million higher sales. Additional volumes for both of these products were primarily due to the same reasons discussed in our 2012 vs. 2011 comparison above. Additionally, we saw slight increases in our oil and gas volumes which resulted in $118 million higher sales.

Production information for our key properties is summarized below:

•

Permian Basin production increased 26 percent compared to the prior year and 44 percent since 2010. Oil production accounted for nearly 60 percent of our 62,000 Boe per day produced in the Permian Basin during 2012. The 2012 increase in total production was driven by a 30 percent increase in oil production.

•

Barnett Shale production increased 7 percent compared to the prior year and 18 percent since 2010. Liquids production accounted for 21 percent of our 1.4 Bcfe per day produced in the Barnett Shale during 2012. The 2012 increase in total production was driven by a 7 percent increase in liquids production.

•

Cana-Woodford Shale production increased 45 percent compared to the prior year and 168 percent since 2010. Liquids production accounted for 30 percent of our 290 MMcfe per day produced in Cana during 2012. The 2012 increase in total production was driven by a 67 percent increase in liquids production.

•

Canadian Oil Sands production increased 37 percent compared to the prior year and 92 percent since 2010. Bitumen production accounted for all of our 48,000 Boe per day produced in 2012.

•

Granite Wash production increased 14 percent compared to the prior year and 68 percent since 2010. Liquids production accounted for 46 percent of our 19,000 Boe per day produced in Granite Wash during 2012. The 2012 increase in production was driven by a 20 percent increase in liquids production.

•

By the end of 2012, Mississippian production was up to almost 3,000 Boe per day. We drilled our first 35 wells in 2012. Oil production accounted for 63 percent of our total production in 2012.

•

Gulf Coast/East Texas production decreased 14 percent in 2012. Although total production was down, oil production increased 8 percent in 2012. Liquids production accounted for nearly 25 percent of our 368 MMcfe per day produced in Gulf Coast/East Texas during 2012.

•

Rocky Mountain production decreased 9 percent in 2012. Although total production was down, oil production increased 17 percent in 2012. Liquids production accounted for 28 percent of our 352 MMcfe per day produced in the Rocky Mountains during 2012.

•

Lloydminster production decreased 6 percent in 2012. Oil production accounted for 82 percent of our 37,000 Boe per day produced at Lloydminster during 2012.

Prices 2012 vs. 2011 – Upstream sales decreased $1.9 billion due to a 17 percent decrease in our realized price without hedges. Our gas sales were the most significantly impacted with a $1.1 billion decrease in sales. The change in our gas price was largely due to fluctuations of the North American regional index prices upon which our gas sales are based. We also experienced declines in our NGL, bitumen and oil sales due to our realized price. The largest contributors to the lower liquids prices were lower NGL prices at the Mont Belvieu, Texas hub and wider bitumen differentials to the NYMEX West Texas Intermediate index price.

Prices 2011 vs. 2010 – Upstream sales increased $595 million due to a 9 percent increase in our realized price without hedges. Our realized price for oil, bitumen and NGLs increased primarily due to an increase in the average index price for which each product is sold. Our realized price for gas decreased primarily due to fluctuations of the North American regional index prices upon which our gas sales are based.

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,
	2012			2011			2010
	(In millions)
Cash settlements:
Gas derivatives	$	610		$	416		$	888
Oil derivatives		259			(26	)		—
NGL derivatives		1			2			—

Total cash settlements		870			392			888

Unrealized gains (losses) on fair value changes:
Gas derivatives		(330	)		305			12
Oil derivatives		150			185			(91	)
NGL derivatives		3			(1	)		2

Total unrealized gains (losses) on fair value changes		(177	)		489			(77	)

Oil, gas and NGL derivatives	$	693		$	881		$	811


	Year Ended December 31, 2012
	Oil (Per Bbl)			Bitumen (Per Bbl)		Gas (Per Mcf)		NGLs (Per Bbl)		Boe (Per Boe)
Realized price without hedges	$	80.35		$	47.75	$	2.36	$	30.42	$	28.65
Cash settlements of hedges		7.18			—		0.65		0.04		3.48

Realized price, including cash settlements	$	87.53		$	47.75	$	3.01	$	30.46	$	32.13


	Year Ended December 31, 2011
	Oil (Per Bbl)			Bitumen (Per Bbl)		Gas (Per Mcf)		NGLs (Per Bbl)		Boe (Per Boe)
Realized price without hedges	$	83.16		$	58.16	$	3.58	$	41.10	$	34.64
Cash settlements of hedges		(0.81	)		—		0.44		0.07		1.63

Realized price, including cash settlements	$	82.35		$	58.16	$	4.02	$	41.17	$	36.27


	Year Ended December 31, 2010
	Oil (Per Bbl)			Bitumen (Per Bbl)		Gas (Per Mcf)		NGLs (Per Bbl)		Boe (Per Boe)
Realized price without hedges	$	68.75		$	52.51	$	3.84	$	32.61	$	31.91
Cash settlements of hedges		—			—		0.96		—		3.90

Realized price, including cash settlements	$	68.75		$	52.51	$	4.80	$	32.61	$	35.81

Cash settlements as presented in the tables above represent realized gains or losses related to these various instruments. A summary of our open commodity derivative positions 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, basis swaps and call options. To facilitate a portion of our price swaps, we sold gas call options for 2012 and 2014 and oil call options for 2011 through 2014. 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 $693 million, $881 million and $811 million during 2012, 2011 and 2010, respectively.

Marketing and Midstream Revenues and Operating Costs and Expenses


	Year Ended December 31,
	2012		Change			2011		Change			2010
	($ in millions)
Revenues	$	1,656		-27	%	$	2,258		+21	%	$	1,867
Operating costs and expenses		1,246		-27	%		1,716		+26	%		1,357

Operating profit	$	410		-24	%	$	542		+6	%	$	510

2012 vs. 2011 Marketing and midstream operating profit decreased $132 million primarily due to lower natural gas and NGL prices.

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

Lease Operating Expenses (“LOE”)


	Year Ended December 31,
	2012		Change			2011		Change			2010
LOE ($ in millions):
U.S. Onshore	$	1,059		+14	%	$	925		+11	%	$	832
Canada		1,015		+10	%		926		+16	%		797

North America Onshore		2,074		+12	%		1,851		+14	%		1,629
U.S. Offshore		—		N/M			—		-100	%		60

Total	$	2,074		+12	%	$	1,851		+10	%	$	1,689


LOE per Boe:
U.S. Onshore	$	5.79		+8	%	$	5.35		+2	%	$	5.26
Canada	$	15.18		+10	%	$	13.82		+12	%	$	12.37
North America Onshore	$	8.30		+8	%	$	7.71		+5	%	$	7.32
U.S. Offshore	$	—		N/M		$	—		-100	%	$	12.00
Total	$	8.30		+8	%	$	7.71		+4	%	$	7.42

2012 vs. 2011 LOE increased $0.59 per Boe largely because of our oil production growth, particularly at our Jackfish thermal heavy oil projects in Canada and in the Permian Basin in the U.S. Such oil projects generally require a higher cost to produce per unit than our gas projects. We also experienced inflationary pressures on costs in certain operating areas, which increased LOE per Boe.

2011 vs. 2010 LOE increased $0.29 per Boe. 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. We also experienced inflationary pressures on costs in certain operating areas. 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.

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


	Year Ended December 31,
	2012		Change			2011		Change			2010
DD&A ($ in millions):
Oil & gas properties	$	2,526		+27	%	$	1,987		+19	%	$	1,675
Other properties		285		+9	%		261		+2	%		255

Total	$	2,811		+25	%	$	2,248		+17	%	$	1,930


DD&A per Boe:
Oil & gas properties	$	10.12		+22	%	$	8.28		+13	%	$	7.36
Other properties		1.14		+5	%		1.09		-3	%		1.12

Total	$	11.26		+20	%	$	9.37		+10	%	$	8.48

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.

2012 vs. 2011 Oil and gas property DD&A increased $460 million due to a 22 percent increase in the DD&A rate and $79 million due to our 4 percent increase in production. The largest contributors to the higher rate were our 2012 drilling and development activities.

2011 vs. 2010 Oil and gas property DD&A increased $221 million 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.

General and Administrative Expenses (“G&A”)


	Year Ended December 31,
	2012			Change			2011			Change			2010
	($ in millions)
Gross G&A	$	1,171			+13	%	$	1,036			+5	%	$	987
Capitalized G&A		(359	)		+7	%		(337	)		+8	%		(311	)
Reimbursed G&A		(120	)		+5	%		(114	)		+1	%		(113	)

Net G&A	$	692			+18	%	$	585			+4	%	$	563

Net G&A per Boe	$	2.77			+14	%	$	2.44			-1	%	$	2.47

2012 vs. 2011 Net G&A and net G&A per Boe increased largely due to higher employee compensation and benefits. Employee costs increased primarily from an expansion of our workforce as part of growing production operations at certain of our key areas, including Jackfish, the Permian Basin and the Cana-Woodford Shale.

2011 vs. 2010 Net G&A increased 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.

Taxes Other Than Income Taxes


	Year Ended December 31,
	2012			Change			2011			Change			2010
	($ in millions)
Production	$	224			-10	%	$	248			+18	%	$	210
Ad valorem and other		190			+8	%		176			+4	%		170

Taxes other than income taxes	$	414			-3	%	$	424			+12	%	$	380


Percentage of oil, gas and NGL revenue:
Production		3.13	%		+5	%		2.98	%		+3	%		2.90	%
Ad valorem and other		2.65	%		+25	%		2.12	%		-9	%		2.34	%

Total		5.78	%		+13	%		5.10	%		-3	%		5.24	%

2012 vs. 2011 Taxes other than income taxes decreased primarily due to a decrease in our U.S. Onshore revenues, on which the majority of our production taxes are assessed.

2011 vs. 2010 Taxes other than income taxes increased 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,
	2012			Change			2011			Change			2010
	($ in millions)
Interest based on debt outstanding	$	440			+6	%	$	414			+2	%	$	408
Capitalized interest		(48	)		-33	%		(72	)		-5	%		(76	)
Early retirement of debt		—			N/M			—			-100	%		19
Other		14			+33	%		10			-17	%		12

Interest expense	$	406			+15	%	$	352			-3	%	$	363

2012 vs. 2011 Interest expense increased primarily due to additional debt borrowings and lower capitalized interest, partially offset by lower weighted average interest rates. Borrowings were primarily used to fund capital expenditures in excess of our operating cash flow and 2012 divestiture proceeds.

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.

Restructuring Costs


	Year Ended December 31,
	2012			2011			2010
	(In millions)
Office consolidation:
Employee severance and retention	$	77		$	—		$	—
Lease obligations and other		3			—			—

Total		80			—			—

Offshore divestitures:
Employee severance		(3	)		8			(27	)
Lease obligations and other		(3	)		(10	)		84

Total		(6	)		(2	)		57

Restructuring costs (1)	$	74		$	(2	)	$	57

(1)	Restructuring costs related to our discontinued operations totaled $(2) million and $(4) million in 2011 and 2010, respectively. These costs primarily consist of employee severance and are not included in the table. There were no costs related to discontinued operations in 2012.

Office Consolidation

In October 2012, we announced plans to consolidate our U.S. personnel into a single operations group centrally located at our corporate headquarters in Oklahoma City. As a result, we are in the process of closing our office in Houston and transferring operational responsibilities for assets in South Texas, East Texas and Louisiana to Oklahoma City. This initiative is expected to be substantially complete by the end of the first quarter 2013.

Employee severance – In the fourth quarter of 2012, we recognized $77 million of estimated employee severance costs associated with the office consolidation. This amount was based on estimates of the number employees that would ultimately be impacted by the office consolidation and included amounts related to cash severance costs and accelerated vesting of share-based grants.

Lease obligations and other – As of December 31, 2012, we incurred $3 million of restructuring costs related to certain office space that is subject to non-cancellable operating lease agreements and that we ceased using as a part of the office consolidation. In 2013 we expect to incur approximately $25 million of additional restructuring costs that represent 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.

Divestiture of Offshore Assets

In the fourth quarter of 2009, we announced plans to divest our offshore assets. As of December 31, 2012, we had divested all of our U.S. Offshore and International assets and incurred $196 million of restructuring costs associated with the 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 and other – 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 $13 million of asset impairment charges for leasehold improvements and furniture associated with the office space that we ceased using.

Asset Impairments


	Year Ended December 31, 2012
	Gross		Net of Taxes
	(In millions)
U.S. oil and gas assets	$	1,793	$	1,142
Canada oil and gas assets		163		122
Midstream assets		68		44

Total asset impairments	$	2,024	$	1,308

Oil and Gas Impairments

Under the full-cost method of accounting, capitalized costs of oil and gas properties are subject to a quarterly full cost ceiling test, which is discussed in Note 1 to the financial statements under “Item 8. Consolidated Financial Statements” of this report.

The oil and gas impairments resulted primarily from declines in the U.S. and Canada full cost ceilings. The lower ceiling values resulted primarily from decreases in the 12-month average trailing prices for oil, natural gas and NGLs, which have reduced proved reserve values.

If pricing conditions do not improve, we may incur full cost ceiling impairments related to our oil and gas property and equipment in 2013.

Midstream Impairments

Due to declining natural gas production resulting from low natural gas and NGL prices, we determined that the carrying amounts of certain of our midstream facilities were not recoverable from estimated future cash flows. Consequently, the assets were written down to their estimated fair values, which were determined using discounted cash flow models.

Other, net


	Year Ended December 31,
	2012			2011			2010
	(In millions)
Accretion of asset retirement obligations	$	110		$	92		$	92
Interest rate derivatives		15			11			(14	)
Foreign currency derivatives		18			(16	)		—
Foreign exchange loss (gain)		(15	)		25			(7	)
Interest income		(36	)		(21	)		(13	)
Other		(14	)		(101	)		(25	)

Other, net	$	78		$	(10	)	$	33

2012 vs. 2011 Other, net increased primarily due to $88 million of excess insurance recoveries received in 2011 related to certain weather and operational claims.

2011 vs. 2010 Other, net decreased primarily due to excess insurance recoveries received in 2011 as discussed above. The remainder of the variance primarily relates to the net effect of interest rate derivatives 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,
	2012			2011			2010
Total income tax expense (benefit) (in millions)	$	(132	)	$	2,156		$	1,235

U.S. statutory income tax rate		(35	%)		35	%		35	%
State income taxes		6	%		1	%		1	%
Taxation on Canadian operations		(6	%)		(2	%)		(1	%)
Assumed repatriations		0	%		17	%		4	%
Other		(7	%)		(1	%)		(4	%)

Effective income tax rate		(42	%)		50	%		35	%

In the table above, the “other” effect is primarily comprised of permanent tax differences for which the dollar amounts do not increase or decrease as our pre-tax earnings do. Generally, such items typically have an insignificant impact on our effective income tax rate. However, these items have a more noticeable impact to our rate for the year ended December 31, 2012 because of the relatively small pre-tax loss for that period.

During 2011 and 2010, 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 indefinitely reinvested. Accordingly, we recognized deferred income tax expense of $725 million and $144 million during 2011 and 2010, respectively, related to assumed repatriations of earnings from our foreign subsidiaries.

Earnings (Loss) From Discontinued Operations


	Year Ended December 31,
	2012			2011		2010
	(In millions)
Operating earnings	$	—		$	38	$	567
Gain (loss) on sale of oil and gas properties		(16	)		2,552		1,818

Earnings (loss) before income taxes		(16	)		2,590		2,385
Income tax expense		5			20		168

Earnings (loss) from discontinued operations	$	(21	)	$	2,570	$	2,217

The earnings (loss) in each period were primarily driven by gains (losses) on the sales of our oil and gas assets in each period. The following table presents gains and losses on our divestiture transactions by year.


	Year Ended December 31,
	2012						2011				2010
	Gross			Net of Taxes			Gross		Net of Taxes		Gross			Net of Taxes
	(In millions)
Angola	$	(16	)	$	(21	)	$	—	$	—	$	—		$	—
Brazil		—			—			2,548		2,548		—			—
Azerbaijan		—			—			—		—		1,543			1,524
China - Panyu		—			—			—		—		308			235
Other		—			—			4		4		(33	)		(27	)

Total	$	(16	)	$	(21	)	$	2,552	$	2,552	$	1,818		$	1,732

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,
	2012			2011			2010
	(In millions)
Operating cash flow - continuing operations	$	4,930		$	6,246		$	5,022
Debt activity, net		1,921			4,187			(1,782	)
Divestitures of property and equipment		1,539			3,380			7,002
Capital expenditures		(8,225	)		(7,534	)		(6,476	)
Shareholder distributions		(324	)		(2,610	)		(1,449	)
Other		81			(46	)		107

Net change in cash and short-term investments	$	(78	)	$	3,623		$	2,424

Cash and short-term investments at end of period	$	6,980		$	7,058		$	3,435

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 2012. Our operating cash flow decreased 21 percent during 2012 primarily due to lower commodity prices and higher expenses, partially offset by additional cash flow from our production growth and higher realized gains from our commodity derivatives.

During 2012 our operating cash flow funded approximately three-fourths of our cash payments for capital expenditures, net of divestitures proceeds. Leveraging our liquidity, we used debt to fund the remainder of our cash-based capital expenditures.

Debt Activity, Net

During 2012, we increased our debt borrowings by $1.9 billion as a result of issuing $2.5 billion of long-term debt and repaying approximately $0.6 billion of outstanding short-term debt. The additional borrowings were primarily used to fund capital expenditures in excess of our operating cash flow.

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.

Divestitures of Property and Equipment

During 2012, we closed joint venture transactions with Sinopec and Sumitomo. Sinopec paid approximately $900 million in cash and received a 33.3 percent interest in five of our new ventures exploration plays in the U.S. Sinopec is also funding approximately $1.6 billion of our share of future exploration, development and drilling costs associated with these plays. Sumitomo paid approximately $400 million and received a 30 percent interest in the Cline and Midland-Wolfcamp Shale plays in Texas. Additionally, Sumitomo is funding approximately $1.0 billion of our share of future exploration, development and drilling costs associated with these plays. At December 31, 2012, Sinopec’s and Sumitomo’s remaining commitment to fund our share of future costs associated with these plays was approximately $2.3 billion.

Also in 2012, we sold our West Johnson County Plant and gathering system in north Texas for approximately $90 million and divested our Angola operations for approximately $71 million.

In 2011 and 2010, our divestitures primarily related to the divestitures of our offshore assets.

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,
	2012		2011		2010
	(In millions)
U.S. Onshore	$	5,719	$	5,128	$	3,689
Canada		1,606		1,571		1,826

North America Onshore		7,325		6,699		5,515
U.S. Offshore		—		—		376

Total oil and gas		7,325		6,699		5,891
Midstream		504		333		236
Other		396		502		349

Total continuing operations	$	8,225	$	7,534	$	6,476

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 $7.3 billion, $6.7 billion and $5.9 billion in 2012, 2011 and 2010, respectively. The increases in exploration and development capital spending in 2012 and 2011 were primarily due to new venture acreage acquisitions and increased drilling and development. With rising oil prices and proceeds from our offshore divestitures, we have increased our onshore North American acreage positions and associated exploration and development activities to drive near-term growth of our liquids, particularly oil, production.

Capital expenditures for our midstream operations are primarily for the construction and expansion of natural gas processing plants, natural gas gathering 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 decreased in 2012. This decrease is largely driven by the construction of our new headquarters in Oklahoma City being substantially complete in early 2012.

Shareholder Distributions

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


	2012						2011						2010
	Amount		Shares		Per Share		Amount		Shares		Per Share		Amount		Shares		Per Share
Repurchases		N/A		N/A		N/A	$	2,332		31.3	$	74.54	$	1,168		17.9	$	65.28
Dividends	$	324		N/A	$	0.80	$	278		N/A	$	0.67	$	281		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 percent of our outstanding shares, at an average price of $71.18 per share.

Liquidity

Historically, our primary sources of capital and liquidity have been our operating cash flow, asset divestiture proceeds 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 lower commodity prices, our operating cash flow from continuing operations decreased 21 percent to $4.9 billion in 2012. 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 2013.

To mitigate some of the risk inherent in prices, we have utilized various derivative financial instruments to set minimum prices on our future production. The key terms to our oil, gas and NGL derivative financial instruments as of December 31, 2012 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 generally true during periods of depressed commodity prices or reduced activity.

Interest Rates – Our operating cash flow can also be impacted by interest rate fluctuations. As of December 31, 2012, we had total debt of $11.6 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 3.8 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, prepayments or collateral postings.

As recent years indicate, we have a history of investing more than 100 percent 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 $3.0 billion syndicated, unsecured revolving line of credit (the “Senior Credit Facility”). The Senior Credit Facility has an initial maturity date of October 24, 2017. However, prior to the maturity date, we have the option to extend the maturity for up to two additional one-year periods, subject to the approval of the lenders.

Amounts borrowed under the Senior Credit Facility may, at our election, bear interest at various fixed rate options for periods of up to twelve months. Such rates are generally less than the prime rate. However, we may elect to borrow at the prime rate. As of December 31, 2012, we had $2.9 billion of available capacity under our syndicated, unsecured Senior Credit Facility, net of letters of credit outstanding.

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 write-downs, such as full cost ceiling impairments. As of December 31, 2012, we were in compliance with this covenant. Our debt-to-capitalization ratio at December 31, 2012, as calculated pursuant to the terms of the agreement, was 25.4 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 $5.0 billion of short-term credit under our commercial paper program. Commercial paper debt generally has a maturity of between 1 and 90 days, although it can have a maturity of up to 365 days, and bears interest at rates agreed to at the time of the borrowing. The interest rate is generally based on a standard index such as the Federal Funds Rate, LIBOR, or the money market rate as found in the commercial paper market. As of December 31, 2012, we had $3.2 billion of borrowings under our commercial paper program.

At the end of 2012, we held approximately $7.0 billion of cash and short-term investments. Included in this total was $6.5 billion of cash and short-term investments held by our foreign subsidiaries. We do not currently expect to repatriate the $6.5 billion to the U.S. This expectation is based on planned investments to develop and grow our Canadian business, our current forecasts for both our U.S. and Canadian operations, currently favorable borrowing conditions in the U.S., and existing U.S. income tax laws pertaining to repatriations of foreign earnings. Therefore, with limited cash and short-term investments in the U.S., we expect to continue funding our U.S. business with a combination of our U.S.-based operating cash flow and borrowings. We do not expect near-term borrowing increases will have a material negative effect on our overall liquidity or financial condition.

If we were to repatriate a portion or all of the cash and short-term investments held by our foreign subsidiaries, we would recognize and pay current income taxes in accordance with current U.S. tax law. The payment of such additional income tax would materially decrease the amount of cash and short-term investments ultimately available to fund our business.

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 112.5 basis points to a new rate of LIBOR plus 125 basis points. A ratings downgrade could also adversely impact our ability to economically access debt markets in the future. As of December 31, 2012, we were not aware of any potential ratings downgrades being contemplated by the rating agencies.

Capital Expenditures

Our 2013 capital expenditures are expected to range from $6.4 billion to $7.0 billion, including $5.3 billion to $5.8 billion for our oil and gas operations, which include capitalized G&A and interest. 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 2013 capital expenditures until later periods or accelerate capital expenditures planned for periods beyond 2013 to achieve the desired balance between sources and uses of liquidity. Based upon current price expectations for 2013, our existing commodity hedging contracts, available cash balances and credit availability, we anticipate having adequate capital resources to fund our 2013 capital expenditures.

Additionally, our financial and operational flexibility has been further enhanced by the joint venture transactions that we entered into in 2012 with Sinopec and Sumitomo. Pursuant to the joint venture agreements, Sinopec and Sumitomo are subject to drilling carries with remaining commitments that totaled $2.3 billion at the end of 2012. These drilling carries will fund 70 percent of our capital requirements related to joint venture properties, which results in our partners paying approximately 80 percent of the overall development costs during the carry period. This is allowing us to accelerate the de-risking and commercialization of the joint venture properties without diverting capital from our core development projects. We expect the remaining carries will be realized by the end of 2014.

Contractual Obligations

A summary of our contractual obligations as of December 31, 2012, 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)	$	11,664	$	3,189	$	500	$	1,250	$	6,725
Interest expense (2)		7,662		456		870		837		5,499
Purchase obligations (3)		6,995		826		1,723		1,705		2,741
Operational agreements (4)		3,496		391		797		682		1,626
Asset retirement obligations (5)		2,095		99		134		140		1,722
Drilling and facility obligations (6)		950		777		173		—		—
Lease obligations (7)		312		50		65		56		141
Other (8)		339		122		149		53		15

Total North America	$	33,513	$	5,910	$	4,411	$	4,723	$	18,469

(1)	Debt amounts represent scheduled maturities of our debt obligations at December 31, 2012, excluding $20 million of net discounts included in the carrying value of debt.

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

(3)

Purchase obligation amounts represent contractual commitments primarily to purchase condensate at market prices for use at our heavy oil projects in Canada. We have entered into these agreements because condensate is an integral part of the heavy oil production and transportation processes. 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)	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 downstream markets.

(5)	Asset retirement obligations represent estimated discounted costs for future dismantlement, abandonment and rehabilitation costs. These obligations are recorded as liabilities on our December 31, 2012 balance sheet.

(6)	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.

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

(8)	These amounts include $216 million related to uncertain tax positions.

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 2012, 92 percent 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 two 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 write-downs 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 write-downs. 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 write-down.

Derivative Financial Instruments

We periodically enter into derivative financial instruments with respect to a portion of our oil, gas and NGL production to hedge 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.

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 fifteen separate counterparties, and our interest rate derivative contracts are held with four 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.

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 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, 2012, the date of our last impairment test, the fair values of our U.S. and Canadian reporting units 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 could result in 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.

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.

Non-GAAP Measures

We make reference to “adjusted earnings”, “adjusted earnings per share” and “adjusted cash flow” in “Overview of 2012 Results” in this Item 7 that are not required by or presented in accordance with GAAP. These non-GAAP measures should not be considered as alternatives to GAAP measures. Adjusted earnings represents net earnings excluding certain non-cash or non-recurring items that are typically excluded by securities analysts in their published estimates of our financial results. Adjusted cash flow represents cash flow from operating activities excluding certain balance sheet changes and non-recurring items that are typically excluded by securities analysts in their published estimates of our financial results. We believe these non-GAAP measures facilitate comparisons of our performance to earnings and cash flow estimates published by securities analysts. We also believe these non-GAAP measures can facilitate comparisons of our performance between periods and to the performance of our peers. The tables below exclude amounts related to our discontinued operations.

Adjusted Earnings and Adjusted Earnings Per Share

Below are reconciliations of our adjusted earnings and earnings per share to their comparable GAAP measures.


	Year Ended December 31,
	2012			2011			2010
	(In millions, except per share amounts)
Earnings (loss) (GAAP)	$	(185	)	$	2,134		$	2,333
Adjustments (net of taxes):
Asset impairments		1,308			—			—
Oil, gas and NGL derivatives		112			(310	)		50
Restructuring costs		49			(2	)		36
Interest rate and other financial instruments		21			72			19
Income tax accrual adjustment		17			(42	)		(58	)
U.S. income taxes on foreign earnings		—			744			144
Insurance proceeds		—			(60	)		—
Additional interest costs on debt retirement		—			—			12

Adjusted earnings (Non-GAAP)	$	1,322		$	2,536		$	2,536


	Year Ended December 31,
	2012			2011			2010
	(In millions, except per share amounts)

Diluted earnings per share (GAAP)	$	(0.47	)	$	5.10		$	5.29
Adjustments (net of taxes):
Asset impairments		3.23			—			—
Oil, gas and NGL derivatives		0.28			(0.74	)		0.11
Restructuring costs		0.13			—			0.08
Interest rate and other financial instruments		0.05			0.17			0.04
Income tax accrual adjustment		0.04			(0.10	)		(0.13	)
U.S. income taxes on foreign earnings		—			1.78			0.33
Insurance proceeds		—			(0.14	)		—
Additional interest costs on debt retirement		—			—			0.03

Adjusted earnings per share (Non-GAAP)	$	3.26		$	6.07		$	5.75

Adjusted Cash Flow

Below is a reconciliation of our adjusted cash flow to its comparable GAAP measure.


	Year Ended December 31,
	2012			2011			2010
	(In millions)
Cash flow from operating activities (GAAP)	$	4,930		$	6,246		$	5,022
Adjustments (net of taxes):
Changes in assets and liabilities		(19	)		275			282

Cash flow from operating activities before balance sheet changes (Non-GAAP)		4,911			6,521			5,304

Income tax accrual adjustment		(44	)		(244	)		(329	)
Restructuring costs		25			(3	)		64
Insurance proceeds		—			(67	)		—
Current taxes on divestitures		—			18			783
Current taxes on debt retirement		—			—			18

Adjusted cash flow (Non-GAAP)	$	4,892		$	6,225		$	5,840

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, 2012 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, 2012, 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	$	(162	)	$	156
Oil derivatives	$	(214	)	$	229
NGL derivatives	$	(2	)	$	2

Interest Rate Risk

At December 31, 2012, we had total debt of $11.6 billion. Our long-term debt of $8.4 billion bears fixed interest rates averaging 5.4 percent. The remaining $3.2 billion of commercial paper borrowings bears interest at fixed rates which averaged 0.37 percent. Our commercial paper borrowings typically have maturity rates between 1 and 90 days.

As of December 31, 2012, 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. A 10 percent change in these forward curves would not have materially impacted our balance sheet at December 31, 2012.

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 an 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, 2012 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, 2012, we held foreign currency exchange forward contracts to hedge exposures to fluctuations in exchange rates on the Canadian-dollar cash and intercompany loans. 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, 2012, 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		47

Consolidated Financial Statements
Consolidated Comprehensive Statements of Earnings		48
Consolidated Statements of Cash Flows		49
Consolidated Balance Sheets		50
Consolidated Statements of Stockholders’ Equity		51
Notes to Consolidated Financial Statements		52

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, 2012 and 2011, 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, 2012. We also have audited Devon Energy Corporation’s internal control over financial reporting as of December 31, 2012, 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, 2012 and 2011, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2012, 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, 2012, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

/s/ KPMG LLP

Oklahoma City, Oklahoma

February 21, 2013

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED COMPREHENSIVE STATEMENTS OF EARNINGS


	Year Ended December 31,
	2012			2011			2010
	(In millions, except per share amounts)
Revenues:
Oil, gas and NGL sales	$	7,153		$	8,315		$	7,262
Oil, gas and NGL derivatives		693			881			811
Marketing and midstream revenues		1,656			2,258			1,867

Total revenues		9,502			11,454			9,940

Expenses and other, net:
Lease operating expenses		2,074			1,851			1,689
Marketing and midstream operating costs and expenses		1,246			1,716			1,357
Depreciation, depletion and amortization		2,811			2,248			1,930
General and administrative expenses		692			585			563
Taxes other than income taxes		414			424			380
Interest expense		406			352			363
Restructuring costs		74			(2	)		57
Asset impairments		2,024			—			—
Other, net		78			(10	)		33

Total expenses and other, net		9,819			7,164			6,372

Earnings (loss) from continuing operations before income taxes		(317	)		4,290			3,568
Current income tax expense (benefit)		52			(143	)		516
Deferred income tax expense (benefit)		(184	)		2,299			719

Earnings (loss) from continuing operations		(185