DVN 10-K Annual Report Dec. 31, 2010

DEVON ENERGY CORP/DE

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10-K 1 d78726e10vk.htm FORM 10-K e10vk

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K


(Mark One)
þ		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the fiscal year ended December 31, 2010
or
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number 001-32318

Devon Energy Corporation

(Exact name of registrant as specified in its charter)


Delaware		73-1567067
(State of other jurisdiction of incorporation or organization)		(I.R.S. Employer identification No.)
20 North Broadway, Oklahoma City, Oklahoma		73102-8260
(Address of principal executive offices)		(Zip code)

Registrant’s telephone number, including area code:

(405) 235-3611

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


Title of each class		Name of each exchange on which registered

Common stock, par value $0.10 per share		The New York Stock Exchange

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

None

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

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

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. o

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


Large accelerated filer þ	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o
	(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 o No þ

The aggregate market value of the voting common stock held by non-affiliates of the registrant as of June 30, 2010, was approximately $26.6 billion, based upon the closing price of $60.92 per share as reported by the New York Stock Exchange on such date. On February 10, 2011, 427 million shares of common stock were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE
Proxy statement for the 2011 annual meeting of stockholders — Part III

DEVON ENERGY CORPORATION

INDEX TO FORM 10-K ANNUAL REPORT
TO THE SECURITIES AND EXCHANGE COMMISSION


		Definitions	3
		Information Regarding Forward-Looking Statements	4
PART I
	Item 1.	Business	5
	Item 1A.	Risk Factors	12
	Item 1B.	Unresolved Staff Comments	17
	Item 2.	Properties	17
	Item 3.	Legal Proceedings	30
	Item 4.	Submission of Matters to a Vote of Security Holders	30
PART II
	Item 5.	Market for Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	31
	Item 6.	Selected Financial Data	33
	Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	34
	Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	71
	Item 8.	Financial Statements and Supplementary Data	74
	Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	141
	Item 9A.	Controls and Procedures	141
	Item 9B.	Other Information	141
PART III
	Item 10.	Directors, Executive Officers and Corporate Governance	142
	Item 11.	Executive Compensation	142
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	142
	Item 13.	Certain Relationships and Related Transactions, and Director Independence	142
	Item 14.	Principal Accounting Fees and Services	142
PART IV
	Item 15.	Exhibits and Financial Statement Schedules	143
SIGNATURES			147
EX-10.15
EX-10.16
EX-10.18
EX-10.21
EX-10.22
EX-12
EX-21
EX-23.1
EX-23.2
EX-23.3
EX-31.1
EX-31.2
EX-32.1
EX-32.2
EX-99.1
EX-99.2
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

DEFINITIONS

Measurements of Oil, Natural Gas and Natural Gas Liquids


	•	“NGL” or “NGLs” means natural gas liquids.

	•	“Oil” includes crude oil and condensate.

	•	“Bbl” means barrel of oil. One barrel equals 42 U.S. gallons.


	•	“MBbls” means thousand barrels.

	•	“MMBbls” means million barrels.

	•	“MBbls/d” means thousand barrels per day.


	•	“Mcf” means thousand cubic feet of natural gas.


	•	“MMcf” means million cubic feet.

	•	“Bcf” means billion cubic feet.

	•	“Bcfe” means billion cubic feet equivalent.

	•	“MMcf/d” means million cubic feet per day.


	•	“Boe” means barrel of oil equivalent, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of gas.


	•	“MBoe” means thousand Boe.

	•	“MMBoe” means million Boe.

	•	“MBoe/d” means thousand Boe per day.


	•	“Btu” means British thermal units, a measure of heating value.


	•	“MMBtu” means million Btu.

	•	“MMBtu/d” means million Btu per day.

Geographic Areas


	•	“Canada” means the operations of Devon encompassing oil and gas properties located in Canada.

	•	“International” means the discontinued operations of Devon that encompass oil and gas properties that lie outside the United States and Canada.

	•	“North America Onshore” means the operations of Devon encompassing oil and gas properties in the continental United States and Canada.

	•	“U.S. Offshore” means the divested operations of Devon that encompassed oil and gas properties in the Gulf of Mexico.

	•	“U.S. Onshore” means the properties of Devon encompassing oil and gas properties in the continental United States.

Other


	•	“Federal Funds Rate” means the interest rate at which depository institutions lend balances at the Federal Reserve to other depository institutions overnight.

	•	“Inside FERC” refers to the publication Inside F.E.R.C.’s Gas Market Report.

	•	“LIBOR” means London Interbank Offered Rate.

	•	“NYMEX” means New York Mercantile Exchange.

	•	“SEC” means United States Securities and Exchange Commission.

INFORMATION REGARDING FORWARD-LOOKING STATEMENTS

This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts included or incorporated by reference in this report, including, without limitation, statements regarding our future financial position, business strategy, budgets, projected revenues, projected costs and plans and objectives of management for future operations, are forward-looking statements. Such forward-looking statements are based on our examination of historical operating trends, the information used to prepare the December 31, 2010 reserve reports and other data in our possession or available from third parties. In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as “may,” “will,” “expect,” “intend,” “project,” “estimate,” “anticipate,” “believe,” or “continue” or similar terminology. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, our assumptions about:


	•	energy markets, including the supply and demand for oil, gas, NGLs and other products or services, as well as the prices of oil, gas, NGLs and other products or services, including regional pricing differentials;

	•	production levels, including Canadian production subject to government royalties, which fluctuate with prices and production;

	•	reserve levels;

	•	competitive conditions;

	•	technology;

	•	the availability of capital resources within the securities or capital markets and related risks such as general credit, liquidity, market and interest-rate risks;

	•	capital expenditure and other contractual obligations;

	•	currency exchange rates;

	•	the weather;

	•	inflation;

	•	the availability of goods and services;

	•	drilling risks;

	•	future processing volumes and pipeline throughput;

	•	general economic conditions, whether internationally, nationally or in the jurisdictions in which we or our subsidiaries conduct business;

	•	public policy and government regulatory changes, including changes in royalty, production tax and income tax regimes, changes in hydraulic fracturing regulation, changes in environmental regulation and liability under federal, state, local or foreign environmental laws and regulations;

	•	terrorism;

	•	occurrence of property acquisitions or divestitures; and

	•	other factors disclosed under “Item 2. Properties” “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” and elsewhere in this report.

All subsequent written and oral forward-looking statements attributable to Devon, or persons acting on its behalf, are expressly qualified in their entirety by the cautionary statements. We assume no duty to update or revise our forward-looking statements based on changes in internal estimates or expectations or otherwise.

PART I


Item 1.	*Business*

General

Devon Energy Corporation, including its subsidiaries (“Devon”), is an independent energy company engaged primarily in exploration, development and production of natural gas and oil. Our operations are concentrated in various North American onshore areas in the United States and Canada. We also have offshore operations located in Brazil and Angola that are currently in the process of being divested.

To complement our upstream oil and gas operations in North America, we have a large marketing and midstream operation. With these operations, we market gas, crude oil and NGLs. We also construct and operate pipelines, storage and treating facilities and natural gas processing plants. These midstream facilities are used to transport oil, gas, and NGLs and process natural gas.

We began operations in 1971 as a privately held company. We have been publicly held since 1988, and our common stock is listed on the New York Stock Exchange. Our principal and administrative offices are located at 20 North Broadway, Oklahoma City, OK 73102-8260 (telephone 405/235-3611).

Strategy

As an enterprise, we aspire to be the premier independent natural gas and oil company in North America. To achieve this, we continuously strive to optimize value for our shareholders by growing cash flows, earnings, production and reserves, all on a per debt-adjusted share basis. We do this by:


	•	exercising capital discipline;

	•	investing in oil and gas properties with high operating margins;

	•	balancing our reserves and production mix between natural gas and liquids;

	•	maintaining a low overall cost structure;

	•	improving performance through our marketing and midstream operations; and

	•	preserving financial flexibility.

Over the decade leading up to 2010, we captured an abundance of resources by carrying out this strategy. We pioneered horizontal drilling in the Barnett Shale and extended this technique to other natural gas shale plays in the United States and Canada. We became proficient with steam-assisted gravity drainage with our Jackfish oil sands development in Alberta, Canada. We achieved key oil discoveries with our drilling in the deepwater Gulf of Mexico and offshore Brazil. We have tripled our proved oil and gas reserves since 2000, and have also assembled an extensive inventory of exploration assets representing additional unproved resources.

Building off our past successes, in November 2009, we announced plans to strategically reposition Devon as a North American onshore exploration and production company. As part of this strategic repositioning, we are bringing forward the value of our offshore assets located in the Gulf of Mexico and countries outside North America by divesting them. As of the end of 2010, we had sold our properties in the Gulf of Mexico, Azerbaijan, China and other International regions, generating $5.6 billion in after-tax proceeds. Additionally, we have entered into agreements to sell our remaining offshore assets in Brazil and Angola and are waiting for the respective governments to approve the divestitures. Once the pending transactions are complete, we expect to have generated more than $8 billion in after-tax proceeds.

This repositioning has allowed us to focus our operations on our premier portfolio of North American onshore assets. Historically, our North American onshore assets have consistently provided us our highest risk-adjusted investment returns. By selling our offshore assets, we are able to conduct an aggressive, yet disciplined, pursuit of the untapped value of these North American onshore opportunities. More specifically,

given the current challenged market for natural gas prices, our near-term focus is on the oil and liquids-rich opportunities that exist within our balanced portfolio of properties.

Besides investing in our onshore exploration and development opportunities, we are also using the divestiture proceeds to reduce our debt significantly and conduct up to a $3.5 billion common share repurchase program.

Presentation of Discontinued Operations

As a result of our November 2009 repositioning announcement, all amounts in this document related to our International operations are presented as discontinued. Therefore, financial data and operational data, such as reserves, production, wells and acreage, provided in this document exclude amounts related to our International operations unless otherwise provided.

Our U.S. Offshore operations do not qualify as discontinued operations under accounting rules. As such, financial and operational data provided in this document that pertain to our continuing operations include amounts related to our U.S. Offshore operations that were divested in 2010. Where appropriate, we have presented amounts related to our U.S. Offshore assets separate from those of our North American Onshore assets.

Development of Business

Since our first issuance of common stock to the public in 1988, we have executed strategies that have been focused on growth and value creation for our shareholders. We increased our total proved reserves from 8 MMBoe at year-end 1987 to 2,873 MMBoe at year-end 2010. During this same time period, we increased annual production from 1 MMBoe in 1987 to 228 MMBoe in 2010. Our expansion over this time period is attributable to a focused mergers and acquisitions program spanning a number of years, as well as active and successful exploration and development programs in more recent years. Additionally, our growth has provided meaningful value creation for our shareholders. The growth statistics from 1987 to 2010 translate into annual per share growth rates of 8% for production and 11% for reserves.

As a result of this growth, we have become one of the largest independent oil and gas companies in North America. During 2010, we continued to build off our past successes with a number of key accomplishments, including those discussed below.


	•	Drilling Success — We drilled 1,584 gross wells in 2010 on our North American onshore properties with a 99% success rate. We increased oil and NGL production from our North American onshore properties by 6% in 2010, to an average of 193 MBoe per day.

	•	Cana-Woodford Shale — We drilled 87 wells in the Cana-Woodford Shale play in western Oklahoma and more than doubled our industry-leading leasehold position in the play to more than 240,000 net acres. Our 2010 production exit rate from the Cana-Woodford increased more than 210% over the prior year to an average of 147 MMcf of gas equivalent per day, including 4 MBbls per day of liquids production. We also completed construction and commenced operation of our Cana gas processing plant in 2010.

	•	Permian Basin — We exited 2010 with Permian production of 45 MBoe per day, which represented a 16% increase compared to 2009. We have nearly one million net acres of leasehold in the region targeting various oil and liquids-rich play types.

	•	Jackfish — In 2010, our net production from our Jackfish oil sands project averaged 25 MBbls per day. Following scheduled facilities maintenance in the third quarter and a third-party pipeline system outage in the fourth quarter, our net Jackfish production ramped back up to 30 MBbls per day at year-end.

Construction of our second Jackfish project is now complete. We expect to begin injecting steam at Jackfish 2 in the second quarter, with first oil production expected by the end of 2011. We applied for regulatory approval of a third phase of Jackfish in the third quarter of 2010.


	•	Pike — We added to our Canadian oil position by acquiring a 50% interest in the Pike oil sands leases. The Pike acreage lies immediately adjacent to our highly successful Jackfish project and has estimated gross recoverable resources that may exceed Jackfish. We are the operator of the project and are currently drilling appraisal wells and acquiring seismic data. The drilling results and seismic will help us determine the optimal configuration for the initial phase of development.

	•	Barnett Shale — Our 2010 production exit rate was 1.2 Bcfe per day, including 43 MBbls per day of liquids production. This represents a 16% increase in total production compared to the 2009 exit rate.

Financial Information about Segments and Geographical Areas

Notes 20 and 22 to the consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” of this report contain information on our segments and geographical areas.

Oil, Natural Gas and NGL Marketing and Delivery Commitments

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) or short-term (less than one year) agreements. Regardless of the term of the contract, the vast majority of our production is sold at variable or market sensitive prices.

Additionally, we may periodically enter into financial hedging arrangements or fixed-price contracts associated with a portion of our oil and gas production. These activities are intended to support targeted price levels and to manage our exposure to price fluctuations. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

Oil Marketing

Our oil production is sold under both long-term and short-term agreements at prices negotiated with third parties. Although exact percentages vary daily, as of January 2011, approximately 81% of our oil production was sold under short-term contracts at variable or market-sensitive prices. The remaining 19% of oil production was sold under long-term, market-indexed contracts that are subject to market pricing variations.

Natural Gas Marketing

Our gas production is also sold under both long-term and short-term agreements at prices negotiated with third parties. Although exact percentages vary daily, as of January 2011, approximately 81% of our gas production was sold under short-term contracts at variable or market-sensitive prices. These market-sensitive sales are referred to as “spot market” sales. Another 18% of our production was committed under various long-term contracts, which dedicate the gas to a purchaser for an extended period of time, but still at market-sensitive prices. The remaining 1% of our gas production was sold under long-term, fixed-price contracts.

NGL Marketing

Our NGL production is sold under both long-term and short-term agreements at prices negotiated with third parties. Although exact percentages vary, as of January 2011, approximately 83% of our NGL production was sold under short-term contracts at variable or market-sensitive prices. Approximately 9% of our NGL production was sold under short-term, fixed-price contracts. The remaining 8% of NGL production was sold under long-term, market-sensitive price contracts.

Delivery Commitments

A portion of our production is sold under certain contractual arrangements that specify the delivery of a fixed and determinable quantity. Although exact amounts vary, as of January 2011, we were committed to deliver the following fixed quantities of our oil and natural gas production:


			Less Than		1-3		3-5		More Than
	Total		1 Year		Years		Years		5 Years

Oil (MMBbls)		210		14		41		43		112
Natural gas (Bcf)		607		226		223		103		55
NGLs (MMBbls)		13		13		—		—		—

Total (MMBoe)(1)		324		65		78		60		121


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

We expect to fulfill our delivery commitments over the next three years with production from our proved developed reserves. We expect to fulfill our longer-term delivery commitments beyond three years primarily with our proved developed reserves. In certain regions, we expect to fulfill these longer-term delivery commitments with our proved undeveloped reserves. See Note 22 to the consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” of this report for information related to our proved reserves, including the development of 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 delivery commitments. However, should our proved reserves not be sufficient to satisfy our future delivery commitments, we can and may use spot market purchases to fulfill the commitments.

Marketing and Midstream Activities

The primary objective of our marketing and midstream operations is to add value to us and other producers to whom we provide such services by gathering, processing and marketing oil, gas and NGL production in a timely and efficient manner. Our most significant midstream asset is the Bridgeport processing plant and gathering system located in north Texas. These facilities serve not only our gas production from the Barnett Shale but also gas production of other producers in the area. We have other natural gas processing plants that support our operations, including a plant completed in 2010 that serves the Cana-Woodford Shale production. Our midstream assets also include our 50% interest in the Access Pipeline transportation system in Canada. This pipeline system allows us to blend our Jackfish heavy oil production with condensate or other blend-stock and transport the combined product to the Edmonton area for sale.

Our marketing and midstream revenues are primarily generated by:


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

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

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


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

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

	•	purchasing third-party NGLs;

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

	•	transporting products on unrelated third-party pipelines.

Customers

We sell our gas production to a variety of customers including pipelines, utilities, gas marketing firms, industrial users and local distribution companies. Gathering systems and interstate and intrastate pipelines are used to consummate gas sales and deliveries.

The principal customers for our crude oil production are refiners, remarketers and other companies, some of which have pipeline facilities near the producing properties. In the event pipeline facilities are not conveniently available, crude oil is trucked or shipped to storage, refining or pipeline facilities.

Our NGL production is primarily sold to customers engaged in petrochemical, refining and heavy oil blending activities. Pipelines, railcars and trucks are utilized to move our products to market.

During 2010, 2009 and 2008, no purchaser accounted for over 10% of our revenues.

Seasonal Nature of Business

Generally, the demand for natural gas decreases during the summer months and increases during the winter months. Seasonal anomalies such as mild winters or hot summers sometimes lessen this fluctuation. In addition, pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations.

Public Policy and Government Regulation

The oil and natural gas industry is subject to various types of regulation throughout the world. Laws, rules, regulations and other policy implementations affecting the oil and natural gas industry have been pervasive and are under constant review for amendment or expansion. Pursuant to public policy changes, numerous government agencies have issued extensive laws and regulations binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Such laws and regulations have a significant impact on oil and gas exploration, production and marketing and midstream activities. These laws and regulations increase the cost of doing business and, consequently, affect profitability. Because public policy changes affecting the oil and natural gas industry are commonplace and because existing laws and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws and regulations. However, we do not expect that any of these laws and regulations will affect our operations in a manner materially different than they would affect other oil and natural gas companies of similar size and financial strength.

During 2010, as part of a strategic restructuring of the company, we sold our properties in the Gulf of Mexico and the majority of our assets outside North America, Additionally, we have entered into agreements to sell our remaining offshore assets in Brazil and Angola and are waiting for the respective governments to approve the divestitures. These divestitures reduce our vulnerability to laws, rules and regulations imposed by foreign governments, as well as those imposed in the United States for offshore exploration and production. The following are significant areas of government control and regulation affecting our operations in the United States and Canada.

Exploration and Production Regulation

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


	•	acquisition of seismic data;

	•	location of wells;

	•	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 United States, some states allow the forced pooling or integration of tracts to facilitate exploration, while other states rely on voluntary pooling of lands and leases, which may make it more difficult to develop oil and gas properties. In addition, state conservation laws generally limit the venting or flaring of natural gas and impose certain requirements regarding the ratable purchase of production. The effect of these regulations is to limit the amounts of oil and gas we can produce from our wells and to limit the number of wells or the locations at which we can drill.

Certain of our U.S. natural gas and oil leases are granted by the federal government and administered by the Bureau of Land Management of the Department of the Interior. Such leases require compliance with detailed federal regulations and orders that regulate, among other matters, drilling and operations on lands covered by these leases, and calculation and disbursement of royalty payments to the federal government. The federal government has been particularly active in recent years in evaluating and, in some cases, promulgating new rules and regulations regarding competitive lease bidding and royalty payment obligations for production from federal lands.

Royalties and Incentives in Canada

The royalty system in Canada is a significant factor in the profitability of oil and gas production. Royalties payable on production from lands other than Crown lands are determined by negotiations between the parties. Crown royalties are determined by government regulation and are generally calculated as a percentage of the value of the gross production, with the royalty rate dependent in part upon prescribed reference prices, well productivity, geographical location and the type and quality of the petroleum product produced. From time to time, the federal and provincial governments of Canada also have established incentive programs such as royalty rate reductions, royalty holidays, tax credits and fixed rate and profit-sharing royalties for the purpose of encouraging oil and gas exploration or enhanced recovery projects. These incentives generally have the effect of increasing our revenues, earnings and cash flow.

Pricing and Marketing in Canada

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

Environmental and Occupational Regulations

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


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

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

	•	the emission of certain gases into the atmosphere;

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

	•	the development of emergency response and spill contingency plans.

The application of worldwide standards, such as ISO 14000 governing environmental management systems, is required to be implemented for some international oil and gas operations.

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

We maintain levels of insurance customary in the industry to limit our financial exposure in the event of a substantial environmental claim resulting from sudden, unanticipated and accidental discharges of oil, salt water or other substances. However, we do not maintain 100% coverage concerning any environmental claim, and no coverage is maintained with respect to any penalty or fine required to be paid because of a violation of law.

In 2010, the United States Environmental Protection Agency (“EPA”) issued rules requiring oil and natural gas companies to track and report their greenhouse gas emissions. For Devon, this involves collecting emissions data at more than 17,000 well sites and numerous natural gas plants and compressor stations. While these rules increase our cost of doing business, we do not anticipate that we would be impacted to any greater degree than other similar oil and natural gas companies.

The Kyoto Protocol was adopted by numerous countries in 1997 and implemented in 2005. The Protocol requires reductions of certain emissions of greenhouse gases. Although the United States has not ratified the Protocol, the other countries in which we operate have. In 2007, Canada ratified the Kyoto Protocol and committed to reducing Canada’s greenhouse gas emissions. This commitment was renewed by signing the Copenhagen Accord in 2009 and the Cancun Agreement in 2010. Although there is no framework in place, Canada remains focused on the original reduction target of the Kyoto Protocol and is working to align greenhouse gas policy with the United States. The mandatory reductions on greenhouse gas emissions will create additional costs for the Canadian oil and gas industry, including Devon. Provincially, British Columbia and Alberta have greenhouse gas legislation and regulation that carry some compliance burden for the oil and gas sector. Presently, it is not possible to accurately estimate the costs we could incur to comply with any future laws or regulations developed to achieve emissions reductions in Canada or elsewhere, but such expenditures could be substantial.

In 2006, we established our Corporate Climate Change Position and Strategy. Key components of the strategy include initiation of energy efficiency measures, tracking emerging climate change legislation and publication of a corporate greenhouse gas emission inventory. We last published our emission inventory on January 2008. We will publish another emission inventory on or before March 31, 2011 to comply with a reporting mandate issued by the EPA. Additionally, we continue to explore energy efficiency measures and

greenhouse emission reduction opportunities. We also continue to monitor legislative and regulatory climate change developments, such as the proposals described above.

Employees

As of December 31, 2010, we had approximately 5,000 employees. We consider labor relations with our employees to be satisfactory. We have not had any work stoppages or strikes pertaining to our employees.

Competition

See “Item 1A. Risk Factors.”

Availability of Reports

Through our website, http://www.devonenergy.com, we make available electronic copies of the charters of the committees of our Board of Directors, other documents related to our corporate governance (including our Code of Ethics for the Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer), and documents we file or furnish to the SEC, including our 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. 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.


Item 1A.	*Risk Factors*

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

Oil, Gas and NGL Prices are Volatile

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


	•	consumer demand for oil, gas and NGLs;

	•	conservation efforts;

	•	OPEC production levels;

	•	weather;

	•	regional pricing differentials;

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

	•	differing quality and NGL content of gas produced;

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

	•	the price and availability of alternative fuels;

	•	the overall economic environment; and

	•	governmental regulations and taxes.

Estimates of Oil, Gas and NGL Reserves are Uncertain

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

Discoveries or Acquisitions of Additional 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.

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

Strong competition exists in all sectors of the oil and gas industry. We compete with major integrated and other independent oil and gas companies for the acquisition of oil and gas leases and properties. We also compete for the equipment and personnel required to explore, develop and operate properties. Competition is also prevalent in the marketing of oil, gas and NGLs. Typically, during times of high or rising commodity prices, drilling and operating costs will also increase. Higher prices will also generally increase the costs of properties available for acquisition. 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 a number of different 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 Activities Limit Participation in Commodity Price Increases and Increase Exposure to Counterparty Credit Risk

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 counterparties to our hedging contracts 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 United States and Canada. In addition, we are also subject to the laws and regulations of various states, provinces, tribal and local governments. Pursuant to public policy changes, numerous government departments and agencies have issued extensive rules and regulations binding on the oil and gas industry and its individual members, some of which carry substantial penalties for failure to comply. Changes in such public policy have affected, and at times in the future could affect, our operations. Political developments can restrict production levels, enact price controls, change environmental protection requirements, and increase taxes, royalties and other amounts payable to governments or governmental agencies. Existing laws and regulations can also require us to incur substantial costs to maintain regulatory compliance. Our operating and other compliance costs could increase further if existing laws and regulations are revised or reinterpreted or if new laws and regulations become applicable to our operations. Although we are unable to predict changes to existing laws and regulations, such changes could significantly impact our profitability, financial condition and liquidity, particularly changes related to hydraulic fracturing, income taxes and climate change as discussed below.

Hydraulic Fracturing — The U.S. Congress is currently considering legislation to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and natural-gas industry in the hydraulic-fracturing process. Currently, regulation of hydraulic fracturing is primarily conducted at the state level through permitting and other compliance requirements. This legislation, if adopted, could establish an additional level of regulation and permitting at the federal level.

Income Taxes — The U.S. President’s recent budget proposals include provisions that would, if enacted, make significant changes to United States tax laws. The most significant change would eliminate the immediate deduction for intangible drilling and development costs.

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

Environmental Matters and Costs Can Be Significant

As an owner, lessee or operator of oil and gas properties, we are subject to various federal, state, provincial, tribal and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on us for the cost of pollution clean-up resulting from our operations in affected areas. Any future environmental costs of fulfilling our commitments to the environment are uncertain and will be governed by several factors, including future changes to regulatory requirements. There is no assurance that changes in or additions to public policy regarding the protection of the environment will not have a significant impact on our operations and profitability.

Insurance Does Not Cover All Risks

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

International Operations Have Uncertain Political, Economic and Other Risks

Our operations outside North America are based in Brazil and Angola. As noted earlier in this report, we are in the process of divesting our operations outside North America. However, until we cease operating in these locations, we face political and economic risks and other uncertainties in these areas that are more prevalent than what exist for our operations in North America. Such factors include, but are not limited to:


	•	general strikes and civil unrest;

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

	•	import and export regulations;


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

	•	transportation regulations and tariffs;

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

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

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

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

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

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

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

Certain of Our Investments Are Subject To Risks That May Affect Their Liquidity and Value

To maximize earnings on available cash balances, we periodically invest in securities that we consider to be short-term in nature and generally available for short-term liquidity needs. During 2007, we purchased asset-backed securities that have an auction rate reset feature (“auction rate securities”). Our auction rate securities generally have contractual maturities of more than 20 years. However, the underlying interest rates on our securities are scheduled to reset every seven to 28 days. Therefore, when we bought these securities, they were generally priced and subsequently traded as short-term investments because of the interest rate reset feature. At December 31, 2010, our auction rate securities totaled $94 million.

Since February 8, 2008, we have experienced difficulty selling our securities due to the failure of the auction mechanism, which provided liquidity to these securities. An auction failure means that the parties wishing to sell securities could not do so. The securities for which auctions have failed will continue to accrue interest and be auctioned every seven to 28 days until the auction succeeds, the issuer calls the securities or the securities mature. Due to continued auction failures throughout 2009 and 2010, we consider these investments to be long-term in nature and generally not available for short-term liquidity needs. Therefore, we have classified these investments as other long-term assets.

Our auction rate securities are rated AAA — the highest rating — by one or more rating agencies and are collateralized by student loans that are substantially guaranteed by the United States government. These investments are subject to general credit, liquidity, market and interest rate risks, which may be exacerbated by problems in the global credit markets, including but not limited to, U.S. subprime mortgage defaults and writedowns by major financial institutions due to deteriorating values of their asset portfolios. These and other

related factors have affected various sectors of the financial markets and caused credit and liquidity issues. If issuers are unable to successfully close future auctions and their credit ratings deteriorate, our ability to liquidate these securities and fully recover the carrying value of our investment in the near term may be limited. Under such circumstances, we may record an impairment charge on these investments in the future.


Item 1B.	*Unresolved Staff Comments*

Not applicable.


Item 2.	*Properties*

Property Overview

Our oil and gas operations are concentrated within various North American onshore basins across the United States and Canada. Our properties consist of interests in developed and undeveloped oil and gas leases and mineral acreage in these regions. These ownership interests entitle us to drill for and produce oil, natural gas and NGLs from specific areas. Our interests are mostly in the form of working interests and, to a lesser extent, overriding royalty, mineral, and other forms of direct and indirect ownership in oil and gas properties.

As previously mentioned, we have completed substantially all of our offshore divestitures, with the exception of assets in Brazil and Angola. We have entered into agreements to sell these assets and are waiting for the respective governments to approve the divestitures.

We also have a substantial midstream business that includes natural gas and NGL processing plants and pipeline systems across North America. In aggregate, we have ownership in approximately 13,000 miles of pipeline and 65 natural gas processing and treating plants. Our most significant concentration of midstream assets is located in north Texas at our Barnett Shale field. These assets include over 3,000 miles of pipeline, two natural gas processing plants with 750 MMcf per day of total capacity, and a 15 MBbls per day NGL fractionator. In 2010, we completed construction of a natural gas processing plant to support the growing development of our Cana-Woodford Shale properties. The Cana plant has an initial capacity of 200 MMcf per day with the design capacity to expand up to 600 MMcf per day.

Our midstream assets also include the Access Pipeline transportation system in Canada. This 220-mile dual pipeline system extends from our Jackfish operations in Alberta with connectivity to a 350 MBbls storage terminal near Edmonton. The dual pipeline system allows us to deliver diluents to Jackfish for the blending of our heavy oil production and transport the combined product to the Edmonton crude oil market for sale. We have a 50% ownership interest in the Access Pipeline.

The following sections provide additional details of our oil and gas properties, including information about proved reserves, production, wells, acreage and drilling activities.

Property Profiles

The locations of our key properties are presented on the following map.

The following table presents proved reserve information for our key properties as of December 31, 2010, along with their production volumes for the year 2010. Our key properties include those that currently have significant proved reserves or production. These key properties also include properties that do not have current significant levels of proved reserves or production, but are expected be the source of future significant growth in proved reserves and production.


	Proved		Proved
	Reserves		Reserves			Production		Production
	(MMBoe)(1)		%(2)			(MMBoe)(1)		%(2)

U.S.
Barnett Shale		1,112		38.7	%		70		31.6	%
Carthage		182		6.3	%		12		5.6	%
Cana-Woodford Shale		175		6.1	%		7		3.0	%
Permian Basin		167		5.8	%		16		7.0	%
Washakie		95		3.3	%		8		3.7	%
Arkoma-Woodford Shale		48		1.7	%		5		2.1	%
Groesbeck		48		1.7	%		6		2.6	%
Granite Wash		40		1.4	%		4		1.8	%
Haynesville-Bossier Shale		11		0.4	%		1		0.6	%
Other U.S. Onshore		229		7.9	%		29		13.1	%

Total U.S. Onshore		2,107		73.3	%		158		71.1	%

Canada
Jackfish		440		15.3	%		9		4.1	%
Northwest		107		3.7	%		15		6.6	%
Lloydminster		65		2.3	%		15		6.7	%
Deep Basin		56		2.0	%		10		4.5	%
Horn River Basin		11		0.4	%		1		0.2	%
Pike		—		—			—		—
Other Canada		87		3.0	%		15		6.8	%

Total Canada		766		26.7	%		65		28.9	%

North America Onshore		2,873		100.0	%		223		100.0	%


(1)		Gas 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, which rate is not necessarily indicative of the relationship of gas and oil prices. NGL reserves and production are converted to Boe on a one-to-one basis with oil.

(2)		Percentage of proved reserves and production the property bears to total proved reserves and production based on actual figures and not the rounded figures included in this table.

The following profile information includes the location, acreage, formation type, average working interest and 2010 drilling activities of our key properties presented in the table above. Due to the continued depressed natural gas price environment, we are shifting the vast majority of our 2011 drilling activity to focus on the oil and liquids-rich gas properties within our portfolio. For the key properties that are primarily liquids-based, we also provide our 2011 drilling plans in the profile information below.

U.S.

Barnett Shale — The Barnett Shale, located in north Texas, is our largest property both in terms of production and proved reserves. Our leases include approximately 630,000 net acres located primarily in Denton, Johnson, Parker, Tarrant and Wise counties. The Barnett Shale is a non-conventional reservoir and it

produces natural gas and NGLs. We have an average working interest of 89%. We drilled 460 gross wells in 2010 and plan to drill approximately 320 gross wells in 2011.

Carthage — The Carthage area in east Texas includes primarily Harrison, Marion, Panola and Shelby counties. Our average working interest is 86% and we hold approximately 225,000 net acres. Our Carthage area wells produce primarily natural gas and NGLs from conventional reservoirs. We drilled 26 gross wells in 2010 in this area.

Cana-Woodford Shale — The Cana-Woodford Shale is located primarily in Canadian, Blaine, Caddo, and Dewey counties in western Oklahoma. Our average working interest is 52% and we hold more than 240,000 net acres. Our Cana-Woodford Shale properties produce natural gas, NGLs and condensate from a non-conventional reservoir. We drilled 87 gross wells in 2010 and plan to drill around 220 gross wells in 2011.

Permian Basin — Our oil and gas properties in the Permian Basin in west Texas and southeast New Mexico comprise approximately 950,000 net acres. Our drilling activity is targeting the liquids-rich targets within the Avalon Shale, Bone Spring, Wolfberry and undisclosed play types within other conventional reservoirs. Our average working interest in these properties is 53%. In 2010, we drilled 262 gross wells and plan to drill approximately 300 gross wells in 2011.

Washakie — Our Washakie area leases are concentrated in Carbon and Sweetwater counties in southern Wyoming. Our average working interest is about 76% and we hold about 160,000 net acres in the area. The Washakie wells produce primarily natural gas from conventional reservoirs. In 2010, we drilled 93 gross wells.

Arkoma-Woodford Shale — Our Arkoma-Woodford Shale properties in southeastern Oklahoma produce natural gas and NGLs from a non-conventional reservoir. Our more than 55,000 net acres are concentrated in Coal and Hughes counties, and we have an average working interest of about 31%. In 2010, we drilled 61 gross wells in this area.

Groesbeck — The Groesbeck area of east Texas includes portions of Freestone, Leon, Limestone and Robertson counties. Our average working interest is 72% and we hold about 130,000 net acres of land. The Groesbeck wells produce primarily natural gas from conventional reservoirs. In 2010, we drilled 20 gross wells in this area.

Granite Wash — The Granite Wash is concentrated in Hemphill and Wheeler counties in the Texas Panhandle and in western Oklahoma. Our average working interest is approximately 48% and we hold approximately 60,000 net acres of land. The Granite Wash wells produce liquids and natural gas from conventional reservoirs. In 2010, we drilled 29 gross wells in this area and plan to drill approximately 55 gross wells in 2011.

Haynesville-Bossier Shale — Our Haynesville Shale acreage position spans across east Texas and north Louisiana with an average working interest of 92%. To date, our drilling activity has been focused on approximately 150,000 acres located in Panola, Shelby and San Augustine counties in east Texas. We drilled 23 gross wells in 2010.

Canada

Jackfish — Jackfish is our 100%-owned 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. We expect this project to maintain a flat production profile for greater than 20 years at an average net production rate of approximately 25-30 MBbls per day. We have completed construction of the second phase of Jackfish and we have filed a regulatory application for a third phase. The second and third phases of Jackfish are each expected to eventually produce approximately 30 MBbls per day of heavy oil production net of royalties over the life of the projects.

Northwest — The Northwest region includes acreage within west central Alberta and northeast British Columbia. We hold approximately 1.9 million net acres in the region, which produces primarily natural gas

from conventional reservoirs. Our average working interest in the area is approximately 73%. In 2010, we drilled 67 gross wells and plan to drill about 50 gross wells in 2011.

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 steam injection. We hold 2.4 million net acres and have an 89% average working interest in our Lloydminster properties. In 2010, we drilled 181 gross wells and plan to drill a similar amount of gross wells in 2011.

Deep Basin — Our properties in Canada’s Deep Basin include portions of west central Alberta and east central British Columbia. We hold approximately 520,000 net acres in the Deep Basin. The area produces natural gas and liquids from conventional reservoirs. Our average working interest in the Deep Basin is 43%. In 2010, we drilled 39 gross wells and plan to drill approximately 30 gross wells in 2011.

Horn River Basin — The Horn River Basin, located in northeast British Columbia, is a non-conventional gas reservoir targeting the Devonian Shale. Our leases include approximately 170,000 net acres with a 100% working interest. We drilled 7 gross wells in 2010.

Pike — Our 50%-owned Pike oil sands acreage is situated directly to the south of our Jackfish acreage in east central Alberta. This position was attained in 2010 through a joint venture agreement with BP. The Pike leasehold is currently undeveloped and has no proved reserves or production as of December 31, 2010. We began appraisal drilling near the end of 2010 and are acquiring seismic data. The drilling results and seismic will help us determine the optimal configuration for the initial phase of development. We expect to begin the regulatory application process for the first Pike phase around the end of 2011.

Preparation of Reserves Estimates and Reserves Audits

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.” As a result, we have developed internal policies for estimating and recording reserves. Our policies regarding booking reserves require proved reserves to be in compliance with the SEC definitions and guidance. 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. Such qualifications include any or all of the following:


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

	•	a petroleum engineering license, or similar certification;

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

	•	relevant experience estimating reserves.

The current Director of the Group has all of the qualifications listed above. The current Director has been involved with reserves estimation in accordance with SEC definitions and guidance since 1987. He has experience in reserves estimation for projects in the United States (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 ten years,

including the past three in his current position as Director of Reserves and Economics. During his career with Devon and others, he was the primary reservoir engineer for projects including, but not limited to:


	•	Hugoton Gas Field (Kansas)

	•	Sho-Vel-Tum CO ₂ Flood (Oklahoma)

	•	West Loco Hills Unit Waterflood and CO ₂ Flood (New Mexico)

	•	Dagger Draw Oil Field (New Mexico)

	•	Clarke Lake Gas Field (Alberta, Canada)

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

	•	ACG Unit (Caspian Sea)

As the primary reservoir engineer, he was responsible for reserves estimation on each of these projects. These reserves estimates were utilized internally and for SEC filings.

From 2003 to 2010, he served as the reservoir engineering representative on our internal Peer Review Team, reviewing reserves and resource estimates for projects including, but not limited to:


	•	Mobile Bay Norphlet Discoveries (Gulf of Mexico Shelf)

	•	Cascade Lower Tertiary Development (Gulf of Mexico Deepwater)

	•	Polvo Development (Campos Basin, Brazil)

Additionally, 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 2010, we engaged two such firms to audit a significant portion of our proved reserves. LaRoche Petroleum Consultants, Ltd. audited the 2010 reserve estimates for 94% of our U.S. onshore properties. AJM Petroleum Consultants audited 89% of our Canadian reserves.

Set forth below is a summary of the North American reserves that were evaluated, either by preparation or audit, by independent petroleum consultants for each of the years ended 2010, 2009 and 2008.


	2010					2009						2008
	Prepared		Audited			Prepared			Audited			Prepared			Audited

U.S. Onshore		—		94	%		—			93	%		—			92	%
U.S. Offshore		N/A		N/A			100	%		—			100	%		—
Total U.S.		—		94	%		5	%		89	%		5	%		87	%
Canada		—		89	%		—			91	%		—			78	%
Total North America		—		93	%		3	%		89	%		4	%		85	%

N/A Not applicable — We sold all our U.S. Offshore properties during 2010.

consultant that is conducted for the purpose of expressing an opinion as to whether such estimates, in aggregate, are reasonable and have been estimated and presented in conformity with generally accepted petroleum engineering and evaluation methods and procedures.

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

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


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

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

	•	oversee and evaluate, prepare and disclose our compliance with legal and regulatory requirements related to our oil, gas and NGL reserves;

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

	•	monitor the performance of our independent engineering consultants.

Proved Oil, Natural Gas and NGL Reserves

The following table presents our estimated proved reserves by continent and for each significant country as of December 31, 2010. These estimates correspond with the method used in presenting the “Supplemental Information on Oil and Gas Operations” in Note 22 to our consolidated financial statements included in this report.


					Natural
	Oil		Natural Gas		Gas Liquids		Total(1)
	(MMBbls)		(Bcf)		(MMBbls)		(MMBoe)

Proved Reserves
United States		148		9,065		449		2,107
Canada		533		1,218		30		766

Total North America		681		10,283		479		2,873

Proved Developed Reserves
United States		131		7,280		353		1,696
Canada		126		1,144		28		346

Total North America		257		8,424		381		2,042

Proved Undeveloped Reserves
United States		17		1,785		96		411
Canada		407		74		2		420

Total North America		424		1,859		98		831


(1)		Gas reserves are converted to Boe at the rate of six Mcf per Bbl of oil, based upon the approximate relative energy content of gas and oil. This rate is not necessarily indicative of the relationship of natural gas and oil prices. Natural gas liquids reserves are converted to Boe on a one-to-one basis with oil.

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 2010 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 Developed Reserves

As presented in the previous table, we had 2,042 MMBoe of proved developed reserves at December 31, 2010. Proved developed reserves consist of proved developed producing reserves and proved developed non-producing reserves. The following table provides additional information regarding our proved developed reserves at December 31, 2010.


					Natural
	Oil		Natural Gas		Gas Liquids		Total(1)
	(MMBbls)		(Bcf)		(MMBbls)		(MMBoe)

Proved Developed Producing Reserves
United States		123		6,702		318		1,557
Canada		116		1,031		25		314

Total North America		239		7,733		343		1,871

Proved Developed Non-Producing Reserves
United States		8		578		35		139
Canada		10		113		3		32

Total North America		18		691		38		171


(1)		Gas reserves are converted to Boe at the rate of six Mcf per Bbl of oil, based upon the approximate relative energy content of gas and oil. This rate is not necessarily indicative of the relationship of natural gas and oil prices. Natural gas liquids reserves are converted to Boe on a one-to-one basis with oil.

Proved Undeveloped Reserves

The following table presents the changes in our total proved undeveloped reserves during 2010 (in MMBoe).


Proved undeveloped reserves as of December 31, 2009	811
Extensions and discoveries	145
Revisions due to prices	13
Revisions other than price	(8	)
Sale of reserves	(39	)
Conversion to proved developed reserves	(91	)

Proved undeveloped reserves as of December 31, 2010	831

At December 31, 2010, we had 831 MMBoe of proved undeveloped reserves. This represents a 2% increase as compared to 2009 and represents 29% of our total proved reserves. A large contributor to the increase was our 2010 drilling activities, which increased our proved undeveloped reserves 145 MMBoe. The divestiture of our Gulf of Mexico properties reduced our proved undeveloped reserves by 39 MMBoe.

As a result of 2010 development activities, we converted 91 MMBoe, or 11%, of the 2009 proved undeveloped reserves to proved developed reserves. This conversion rate implies a nine-year development cycle, which exceeds the five-year general guideline for recording proved undeveloped reserves. However, our

overall proved undeveloped conversion rate is largely impacted by the pace of development at Jackfish. Excluding our Jackfish reserves, our 2010 proved undeveloped conversion rate implies a development cycle that approximates five years.

At December 31, 2010 and 2009, our Jackfish proved undeveloped reserves were 396 MMBoe and 351 MMBoe, respectively. Development schedules for the Jackfish reserves are primarily controlled by the need to keep the processing plants at their full capacity of 35,000 barrels of oil per day per facility. Processing plant capacity is controlled by factors such as total steam processing capacity, steam-oil ratios and air quality discharge permits. As a result, these reserves will remain classified as proved undeveloped for more than five years. Currently, the development schedule for these reserves extends though the year 2025. We have made significant funding commitments toward the development of the Jackfish reserves.

See Note 22 to the consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” of this report for further discussion of the contributions by project area of all changes to total proved reserves.

Proved Reserves Cash Flows

The following table presents estimated cash flow information related to our December 31, 2010 estimated proved reserves. Similar to reserves, the cash flow estimates correspond with the method used in presenting the “Supplemental Information on Oil and Gas Operations” in Note 22 to our consolidated financial statements included in this report.


	Total		Proved		Proved
	Proved		Developed		Undeveloped
	Reserves		Reserves		Reserves
			(In millions)

Pre-Tax Future Net Revenue(1)
United States	$	27,650	$	23,640	$	4,010
Canada		19,173		7,222		11,951

Total North America	$	46,823	$	30,862	$	15,961

Pre-Tax 10% Present Value(1)
United States	$	12,863	$	12,093	$	770
Canada		9,622		5,216		4,406

Total North America	$	22,485	$	17,309	$	5,176

Standardized Measure of Discounted Future Net Cash Flows(1)(2)
United States	$	8,843
Canada		7,509

Total North America	$	16,352


(1)		Estimated pre-tax future net revenue represents estimated future revenue to be generated from the production of proved reserves, net of estimated production and development costs and site restoration and abandonment charges. The amounts shown do not give effect to depreciation, depletion and amortization, or to non-property related expenses such as debt service and income tax expense.

		Future net revenues are calculated using prices that represent the average of the first-day-of-the-month price for the 12-month period prior to December 31, 2010. These prices were not changed except where different prices were fixed and determinable from applicable contracts. These assumptions yielded average prices over the life of our properties of $59.94 per Bbl of oil, $3.73 per Mcf of gas and $31.11 per Bbl of NGLs. The prices used in calculating the estimated future net revenues attributable to proved reserves do not necessarily reflect market prices for oil, gas and NGL production subsequent to December 31, 2010. There can be no assurance that all of the proved reserves will be produced and sold within the periods


		indicated, that the assumed prices will be realized or that existing contracts will be honored or judicially enforced.

		The present value of after-tax future net revenues discounted at 10% per annum (“standardized measure”) was $16.4 billion at the end of 2010. Included as part of standardized measure were discounted future income taxes of $6.1 billion. Excluding these taxes, the present value of our pre-tax future net revenue (“pre-tax 10% present value”) was $22.5 billion. We believe the pre-tax 10% present value is a useful measure in addition to the after-tax standardized measure. The pre-tax 10% present value assists in both the determination of future cash flows of the current reserves as well as in making relative value comparisons among peer companies. The after-tax standardized measure is dependent on the unique tax situation of each individual company, while the pre-tax 10% present value is based on prices and discount factors, which are more consistent from company to company. We also understand that securities analysts use the pre-tax 10% present value measure in similar ways.

(2)		See Note 22 to the consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.”

Production, Production Prices and Production Costs

The following tables present our production and average sales prices by continent and for each significant field and country for the past three years.


	Year Ended December 31, 2010
	Oil		Natural Gas		NGLs		Total(1)
	(MMBbls)		(Bcf)		(MMBbls)		(MMBoe)

Production
Barnett Shale		1		335		13		70
Other United States fields		15		381		15		93

Total United States		16		716		28		163

Jackfish		9		—		—		9
Other Canada fields		16		214		4		56

Total Canada		25		214		4		65

Total North America		41		930		32		228


	Oil		Natural Gas		NGLs		Combined(1)
	(Per Bbl)		(Per Mcf)		(Per Bbl)		(Per Boe)

Production Prices
Barnett Shale	$	77.40	$	3.55	$	29.97	$	23.48
Total United States	$	75.81	$	3.76	$	30.86	$	29.06
Jackfish	$	52.51		—		—	$	52.51
Total Canada	$	58.60	$	4.11	$	46.60	$	39.11
Total North America	$	65.14	$	3.84	$	32.61	$	31.91


	Year Ended December 31, 2009
	Oil		Natural Gas		NGLs		Total(1)
	(MMBbls)		(Bcf)		(MMBbls)		(MMBoe)

Production
Barnett Shale		—		331		13		69
Other United States fields		17		412		13		98

Total United States		17		743		26		167

Jackfish		8		—		—		8
Other Canada fields		17		223		4		58

Total Canada		25		223		4		66

Total North America		42		966		30		233


	Oil		Natural Gas		NGLs		Combined(1)
	(Per Bbl)		(Per Mcf)		(Per Bbl)		(Per Boe)

Production Prices
Barnett Shale	$	58.78	$	2.99	$	22.36	$	19.08
Total United States	$	57.56	$	3.20	$	23.51	$	23.71
Jackfish	$	41.07		—		—	$	41.07
Total Canada	$	47.35	$	3.66	$	33.09	$	32.29
Total North America	$	51.39	$	3.31	$	24.71	$	26.15


	Year Ended December 31, 2008
	Oil		Natural Gas		NGLs		Total(1)
	(MMBbls)		(Bcf)		(MMBbls)		(MMBoe)

Production
Barnett Shale		—		321		12		66
Other United States fields		17		405		12		96

Total United States		17		726		24		162

Jackfish		4		—		—		4
Other Canada fields		18		212		4		57

Total Canada		22		212		4		61

Total North America		39		938		28		223


	Oil		Natural Gas		NGLs		Combined(1)
	(Per Bbl)		(Per Mcf)		(Per Bbl)		(Per Boe)

Production Prices
Barnett Shale	$	97.23	$	7.38	$	39.34	$	43.71
Total United States	$	98.83	$	7.59	$	41.21	$	50.55
Jackfish	$	50.67		—		—	$	50.67
Total Canada	$	71.04	$	8.17	$	61.45	$	57.65
Total North America	$	83.35	$	7.73	$	44.08	$	52.49


(1)		Gas reserves are converted to Boe at the rate of six Mcf per Bbl of oil, based upon the approximate relative energy content of gas and oil. This rate is not necessarily indicative of the relationship of natural gas and oil prices. Natural gas liquids reserves are converted to Boe on a one-to-one basis with oil.

The following table presents our production cost per Boe by continent and for each significant field and country for the past three years. Production costs do not include ad valorem or severance taxes.


	Year Ended December 31,
	2010		2009		2008

Barnett Shale	$	3.87	$	3.96	$	4.34
Total United States	$	5.47	$	5.97	$	6.62
Jackfish	$	16.81	$	12.75	$	28.93
Total Canada	$	12.37	$	10.15	$	12.74
Total North America	$	7.42	$	7.16	$	8.29

Drilling Activities and Results

The following tables summarize our development and exploratory drilling results for the past three years.


	Year Ended December 31, 2010
	Development Wells(1)				Exploratory Wells(1)				Total Wells(1)
	Productive		Dry		Productive		Dry		Productive		Dry

U.S. Onshore		853.2		5.3		23.4		1.5		876.6		6.8
U.S. Offshore		2.5		—		—		—		2.5		—

Total U.S.		855.7		5.3		23.4		1.5		879.1		6.8
Canada		267.8		—		41.9		1.0		309.7		1.0

Total North America		1,123.5		5.3		65.3		2.5		1,188.8		7.8


	Year Ended December 31, 2009
	Development Wells(1)				Exploratory Wells(1)				Total Wells(1)
	Productive		Dry		Productive		Dry		Productive		Dry

U.S. Onshore		506.5		3.0		6.8		1.5		513.3		4.5
U.S. Offshore		1.5		0.8		—		0.5		1.5		1.3

Total U.S.		508.0		3.8		6.8		2.0		514.8		5.8
Canada		307.2		—		28.2		—		335.4		—

Total North America		815.2		3.8		35.0		2.0		850.2		5.8


	Year Ended December 31, 2008
	Development Wells(1)				Exploratory Wells(1)				Total Wells(1)
	Productive		Dry		Productive		Dry		Productive		Dry

U.S. Onshore		1,024.0		17.5		12.8		2.0		1,036.8		19.5
U.S. Offshore		9.0		1.0		0.8		1.8		9.8		2.8

Total U.S.		1,033.0		18.5		13.6		3.8		1,046.6		22.3
Canada		528.9		3.2		50.1		3.3		579.0		6.5

Total North America		1,561.9		21.7		63.7		7.1		1,625.6		28.8


(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 results, as of February 1, 2011, of our wells that were in progress as of December 31, 2010.


	Productive				Dry				Still in Progress				Total
	Gross(1)		Net(2)		Gross(1)		Net(2)		Gross(1)		Net(2)		Gross(1)		Net(2)

U.S.		47		31.5		—		—		193		128.8		240		160.3
Canada		9		6.9		—		—		4		3.0		13		9.9

Total North America		56		38.4		—		—		197		131.8		253		170.2


(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.

Well Statistics

The following table sets forth our producing wells as of December 31, 2010.


	Oil Wells				Natural Gas Wells				Total Wells
	Gross(1)		Net(2)		Gross(1)		Net(2)		Gross(1)		Net(2)

U.S.		7,864		2,741		19,719		13,125		27,583		15,866
Canada		4,980		3,798		5,534		3,258		10,514		7,056

Total North America		12,844		6,539		25,253		16,383		38,097		22,922


(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.

Acreage Statistics

The following table sets forth our developed and undeveloped oil and gas lease and mineral acreage as of December 31, 2010. The acreage in the table below includes 1.4 million, 0.5 million and 0.9 million net acres subject to leases that are scheduled to expire during 2011, 2012 and 2013, respectively.


	Developed				Undeveloped				Total
	Gross(1)		Net(2)		Gross(1)		Net(2)		Gross(1)		Net(2)
	(In thousands)

U.S.		3,249		2,179		6,683		3,806		9,932		5,985
Canada		3,647		2,258		7,571		5,013		11,218		7,271

Total North America		6,896		4,437		14,254		8,819		21,150		13,256


(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.

Operation of Properties

The day-to-day operations of oil and gas properties are the responsibility of an operator designated under pooling or operating agreements. The operator supervises production, maintains production records, employs field personnel and performs other functions.

We are the operator of 23,056 of our wells. As operator, we receive reimbursement for direct expenses incurred in the performance of our duties as well as monthly per-well producing and drilling overhead reimbursement at rates customarily charged in the area. In presenting our financial data, we record the monthly overhead reimbursements as a reduction of general and administrative expense, which is a common industry practice.

Title to Properties

Title to properties is subject to contractual arrangements customary in the oil and gas industry, liens for current taxes not yet due and, in some instances, other encumbrances. We believe that such burdens do not materially detract from the value of such properties or from the respective interests therein or materially interfere with their use in the operation of the business.

As is customary in the industry, other than a preliminary review of local records, little investigation of record title is made at the time of acquisitions of undeveloped properties. Investigations, 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.


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.	*Submission of Matters to a Vote of Security Holders*

There were no matters submitted to a vote of security holders during the fourth quarter of 2010.

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 10, 2011, there were 12,704 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 2010 and 2009. Also, included are the quarterly dividends per share paid during 2010 and 2009. 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

2010:
Quarter Ended March 31, 2010	$	76.79	$	62.38	$	0.16
Quarter Ended June 30, 2010	$	70.80	$	58.58	$	0.16
Quarter Ended September 30, 2010	$	66.21	$	59.07	$	0.16
Quarter Ended December 31, 2010	$	78.86	$	63.76	$	0.16
2009:
Quarter Ended March 31, 2009	$	73.11	$	38.55	$	0.16
Quarter Ended June 30, 2009	$	67.40	$	43.35	$	0.16
Quarter Ended September 30, 2009	$	72.91	$	48.74	$	0.16
Quarter Ended December 31, 2009	$	75.05	$	62.60	$	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 based on the following assumptions:


	•	$100 was invested on December 31, 2005 in Devon’s common stock, the S&P 500 Index and the SIC Code, and

	•	Dividends have been reinvested subsequent to the initial investment.

Comparison of 5-Year Cumulative Total Return
Devon, S&P 500 Index and SIC Code

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

Issuer Purchases of Equity Securities

The following table provides information regarding purchases of our common stock that were made by us during the fourth quarter of 2010. All purchases were part of publicly announced plans or programs.


					Maximum Dollar
					Value of Shares
	Total Number				that May Yet Be
	of Shares		Average Price		Purchased Under the
Period	Purchased(1)		Paid per Share		Plans or Programs(1)
					(In millions)

October 1 – October 31		330,000	$	65.64	$	2,542
November 1 – November 30		348,400	$	71.36	$	2,517
December 1 – December 31		2,917,900	$	74.82	$	2,299

Total		3,596,300	$	73.64


(1)		In May 2010, our Board of Directors approved a $3.5 billion share repurchase program. This program expires December 31, 2011. As of December 31, 2010, we had repurchased 18.3 million common shares for $1.2 billion, or $65.58 per share under this program.

New York Stock Exchange Certifications

This Form 10-K includes as exhibits the certifications of our Chief Executive Officer and Chief Financial Officer, required to be filed with the SEC pursuant to Section 302 of the Sarbanes Oxley Act of 2002. We have also filed with the New York Stock Exchange the 2010 annual certification of our Chief Executive Officer confirming that we have complied with the New York Stock Exchange corporate governance listing standards.


Item 6.	*Selected Financial Data*

The following selected financial information (not covered by the report of our independent registered public accounting firm) should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and the consolidated financial statements and the notes thereto included in “Item 8. Financial Statements and Supplementary Data.”


	Year Ended December 31,
	2010		2009			2008			2007		2006
	(In millions, except per share amounts)

Revenues	$	9,940	$	8,015		$	13,858		$	9,975	$	9,143
Earnings (loss) from continuing operations(1)	$	2,333	$	(2,753	)	$	(3,039	)	$	2,485	$	2,316
Earnings (loss) per share from continuing operations — Basic	$	5.31	$	(6.20	)	$	(6.86	)	$	5.56	$	5.22
Earnings (loss) per share from continuing operations — Diluted	$	5.29	$	(6.20	)	$	(6.86	)	$	5.50	$	5.15
Cash dividends per common share	$	0.64	$	0.64		$	0.64		$	0.56	$	0.45
Total assets(1)	$	32,927	$	29,686		$	31,908		$	41,456	$	35,063
Long-term debt	$	3,819	$	5,847		$	5,661		$	6,924	$	5,568


(1)		During 2009 and 2008, we recorded noncash reductions of carrying value of oil and gas properties totaling $6.4 billion ($4.1 billion after income taxes) and $9.9 billion ($6.7 billion after income taxes), respectively, related to our continuing operations as discussed in Note 15 of the consolidated financial statements.


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 reviewed in conjunction with our “Selected Financial Data” and “Financial Statements and Supplementary Data.” Our discussion and analysis relates to the following subjects:


	•	Overview of Business

	•	Overview of 2010 Results

	•	Business and Industry Outlook

	•	Results of Operations

	•	Capital Resources, Uses and Liquidity

	•	Contingencies and Legal Matters

	•	Critical Accounting Policies and Estimates

	•	Forward-Looking Estimates

Overview of Business

Devon is one of North America’s leading independent oil and gas exploration and production companies. Our operations are focused in the United States and Canada. We also own natural gas pipelines and treatment facilities in many of our producing areas, making us one of North America’s larger processors of natural gas liquids.

As an enterprise, we strive to optimize value for our shareholders by growing cash flows, earnings, production and reserves, all on a per debt-adjusted share basis. We accomplish this by replenishing our reserves and production and managing other key operational elements that drive our success. These items are discussed more fully below.


	•	Reserves and production growth — Our financial condition and profitability are significantly affected by the amount of proved reserves we own. Oil and gas properties are our most significant assets, and the reserves that relate to such properties are key to our future success. To increase our proved reserves, we must replace quantities produced with additional reserves from successful exploration and development activities or property acquisitions. Additionally, our profitability and operating cash flows are largely dependent on the amount of oil, gas and NGLs we produce. Growing production from existing properties is difficult because the rate of production from oil and gas properties generally declines as reserves are depleted. As a result, we constantly drill for and develop reserves on properties that provide a balance of near-term and long-term production. In addition, we may acquire properties with proved reserves that we can develop and subsequently produce to help create value.

	•	Capital investment discipline — Effectively deploying our resources into capital projects is key to maintaining and growing future production and oil and gas reserves. As a result, we have historically deployed virtually all our available cash flow into capital projects. Therefore, maintaining a disciplined approach to investing in capital projects is important to our profitability and financial condition. Our ability to control capital expenditures can be affected by changes in commodity prices. During times of high commodity prices, drilling and related costs often escalate due to the effects of supply versus demand economics. The inverse is also true.

	•	High return projects — We seek to invest our capital resources into projects where we can generate the highest risk-adjusted investment returns. One factor that can have a significant impact on such returns is our drilling success. Combined with appropriate revenue and cost-management strategies,


		high drilling success rates are important to generating competitive returns on our capital investment. During 2010, we drilled 1,588 gross wells and 99% of those were successful. This success rate is similar to our drilling achievements in recent years, demonstrating a proven track record of success. By accomplishing high drilling success rates, we provide an inventory of reserves growth and a platform of opportunities on our undrilled acreage that can be profitably developed.


	•	Reserves and production balance — As evidenced by history, commodity prices are inherently volatile. In addition, oil and gas prices often diverge due to a variety of circumstances. Consequently, we value a balance of reserves and production between gas and liquids that can add stability to our revenue stream when either commodity price is under pressure. Our production mix in 2010 was approximately 68% gas and 32% oil and NGLs such as propane, butane and ethane. Our year-end reserves were approximately 60% gas and 40% liquids. With planned future growth in oil from Jackfish, Pike and other projects, combined with an inventory of shale natural gas plays, we expect to maintain this balance in the future.

	•	Operating cost controls — To maintain our competitive position, we must control our lease operating costs and other production costs. As reservoirs are depleted and production rates decline, per unit production costs will generally increase and affect our profitability and operating cash flows. Similar to capital expenditures, our ability to control operating costs can be affected by significant changes in commodity prices. Our base production is focused in core areas of our operations where we can achieve economies of scale to help manage our operating costs.

	•	Marketing and midstream performance improvement — We enhance the value of our oil and gas operations with our marketing and midstream business. By efficiently gathering and processing oil, gas and NGL production, our midstream operations enhance our project returns and contribute to our strategies to grow reserves and production and manage expenditures. Additionally, by effectively marketing our production, we maximize the prices received for our oil, gas and NGL production in relation to market prices. This is important because our profitability is highly dependent on market prices. These prices are determined primarily by market conditions. Market conditions for these products have been, and will continue to be, influenced by regional and worldwide economic and political conditions, weather, supply disruptions and other local market conditions that are beyond our control. To manage this volatility, we utilize financial hedging arrangements. As of February 10, 2011, approximately 29% of our 2011 gas production is associated with financial price swaps and fixed-price physicals. We also have basis swaps associated with 0.2 Bcf per day of our 2011 gas production. Additionally, approximately 36% of our 2011 oil production is associated with financial price collars. We also have call options that, if exercised, would relate to an additional 16% of our 2011 oil production.

	•	Financial flexibility preservation — As mentioned, commodity prices have been and will continue to be volatile and will continue to impact our profitability and cash flow. We understand this fact and manage our debt levels accordingly to preserve our liquidity and financial flexibility. We generally operate within the cash flow generated by our operations. However, during periods of low commodity prices, we may use our balance sheet strength to access debt or equity markets, allowing us to preserve our business and maintain momentum until markets recover. When prices improve, we can utilize excess operating cash flow to repay debt and invest in our activities that not only maintain but also increase value per share.

Overview of 2010 Results

2010 was an outstanding year for Devon. We reported record net earnings and reserves and made significant progress on our offshore divestiture program announced in November 2009. We sold our properties in the Gulf of Mexico, Azerbaijan, China and other International regions, generating $5.6 billion in after-tax proceeds and after-tax gains of $1.7 billion. Additionally, we have entered into agreements to sell our remaining offshore assets in Brazil and Angola and are waiting for the respective governments to approve the

divestitures. Once the pending transactions are complete, we expect to have generated more than $8 billion in after-tax proceeds from all our divestitures.

These divestitures have allowed us to begin focusing entirely on our North American Onshore oil and natural gas portfolio. We grew North American Onshore production 1% in 2010 and replaced approximately 175% of our production with the drill bit at very attractive costs. The operational success we had with the drill bit increased our reserves to 2,873 MMBoe, the highest level in our history.

While our total North American Onshore production grew 1% in 2010, our oil and NGL production increased 6% over 2009. Liquids prices began to stabilize in 2009 and continued to strengthen throughout 2010. Although our realized price for gas increased 17% in 2010, gas prices continue to be weak. Considering the current and expected trends in commodity pricing, we have leveraged the value of our balanced portfolio and shifted capital spending toward the more profitable liquids-rich development opportunities currently available to us. The performance of these assets and higher price realizations are reflected in the 2010 earnings increase.

Key measures of our performance for 2010, as well as certain operational developments, are summarized below:


	•	North America Onshore oil and NGL production grew 6% over 2009, to 71 million Boe.

	•	North American Onshore gas production decreased 1% compared with 2009, to 152 million Boe.

	•	The combined realized price for oil, gas and NGLs per Boe increased 22% to $31.91.

	•	Oil, gas and NGL derivatives generated net gains of $811 million in 2010, including cash receipts of $888 million.

	•	Per unit lease operating costs increased 4% to $7.42 per Boe.

	•	Operating cash flow increased to $5.5 billion, representing a 16% increase over 2009.

	•	Capitalized costs incurred in our oil and gas activities were $6.5 billion in 2010. This includes $1.2 billion for unproved acreage acquisitions.

	•	Reserves increased to 2,873 MMBoe, an all-time high.

From an operational perspective, we completed another successful year with the drill-bit. We drilled 1,584 gross wells on our North America Onshore properties with a 99% success rate and grew our related proved reserves 9%.

During 2010, we more than doubled our industry-leading leasehold position in the liquids-rich Cana-Woodford shale play in western Oklahoma to more than 240,000 net acres. This allowed us to grow production more than 210% from the end of 2009 to the end of 2010. As a result of the success of our drilling and development efforts in the Cana-Woodford shale, we also constructed a gas processing plant in 2010.

In the Barnett Shale, we exited 2010 with production of 1.2 Bcfe per day, which includes 43 MBbls per day of liquids production. This represents a 16% increase in total production compared to the 2009 exit rate.

In the Permian Basin, we continued to assemble additional liquids-rich acreage. By the end of 2010, we had approximately one million net acres on liquids-rich development opportunities which led to an increase in production of 16% from the end of 2009 to the end of 2010.

Our net production from our Jackfish oil sands project in Canada averaged 25 MBbls per day. Jackfish continues to be one of Canada’s most successful steam-assisted gravity drainage projects. Construction of our second Jackfish project is now complete. We expect to have first oil production by the end of 2011. Additionally, we applied for regulatory approval of a third phase of Jackfish in 2010.

During 2010, we used a portion of our offshore divestiture proceeds to invest $1.2 billion in unproved leasehold acquisition focused on oil and liquids-rich gas plays. Our most significant single investment was our $500 million acquisition of a 50% interest in the Pike oil sands. The Pike acreage lies immediately adjacent to

the Jackfish project. We began appraisal drilling at Pike near the end of 2010 and are acquiring seismic data. The drilling results and seismic will help us determine the optimal configuration for the initial phase of development. We expect to begin the regulatory application process for the first Pike phase around the end of 2011.

Our performance and offshore divestiture success throughout 2010 enabled us to end the year with a robust level of liquidity. At the end of 2010, we had $3.4 billion of cash and short-term investments and $2.6 billion of available credit.

Business and Industry Outlook

Even though we possess a great deal of financial strength and flexibility, we are fully committed to exercising capital discipline, maximizing profits, maintaining balance sheet strength and optimizing growth per debt-adjusted share. Our portfolio of assets provides a great deal of investment flexibility. At the end of 2010, our proved reserves were comprised of approximately 60% gas and 40% liquids. While gas prices remain challenged in the market, our near-term focus is on the oil and liquids-rich opportunities that exist within our balanced portfolio of properties. As a result, the vast majority of our 2011 drilling activity will be centered on our oil and liquids-rich gas properties. Should the outlook for commodity prices change, we have the flexibility to redirect our capital to ensure we continually focus on the highest-return assets in our portfolio.

Our ability to leverage the depth and breadth of our existing portfolio of properties will be key to the successful execution of our growth and value-creation objectives. With 2.9 billion Boe of proved reserves at the end of 2010, our North American onshore assets will provide many years of visible, economic growth and a good balance between liquids and natural gas. In 2011, we are targeting a 6-8% production increase. However, we expect this growth will be driven by oil and NGLs growth of at least 16%. Additionally, we will continue to use a portion of our offshore divestiture proceeds to repurchase common stock under our $3.5 billion share repurchase program. Therefore, our 2011 production growth will be even higher on a per debt-adjusted share basis.

Results of Operations

As previously stated, we are in the process of divesting our offshore assets. As a result, 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 have divested our U.S. Offshore operations, 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.

Revenues

Our oil, gas and NGL production volumes are shown in the following table.


	Year Ended December 31,
			2010 vs.					2009 vs.
	2010		2009(2)			2009		2008(2)			2008

Oil (MMBbls)
U.S. Onshore		14		+17	%		12		+3	%		11
Canada		25		−1	%		25		+17	%		22

North America Onshore		39		+5	%		37		+12	%		33
U.S. Offshore		2		−62	%		5		−15	%		6

Total		41		−3	%		42		+8	%		39

Gas (Bcf)
U.S. Onshore		699		+0	%		698		+5	%		669
Canada		214		−4	%		223		+5	%		212

North America Onshore		913		−1	%		921		+5	%		881
U.S. Offshore		17		−63	%		45		−22	%		57

Total		930		−4	%		966		+3	%		938

NGLs (MMBbls)
U.S. Onshore		28		+10	%		25		+9	%		24
Canada		4		−6	%		4		−5	%		4

North America Onshore		32		+8	%		29		+7	%		28
U.S. Offshore		—		−55	%		1		+27	%		—

Total		32		+6	%		30		+7	%		28

Total (MMBoe)(1)
U.S. Onshore		158		+3	%		154		+5	%		146
Canada		65		−3	%		66		+9	%		61

North America Onshore		223		+1	%		220		+6	%		207
U.S. Offshore		5		−62	%		13		−18	%		16

Total		228		−2	%		233		+4	%		223


(1)		Gas volumes are converted to Boe at the rate of six Mcf of gas per barrel of oil, based upon the approximate relative energy content of gas and oil, which rate is not necessarily indicative of the relationship of gas and oil prices. NGL volumes are converted to Boe on a one-to-one basis with oil.

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

The following table presents the prices we realized on our production volumes. These prices exclude any effects due to our oil, gas and NGL derivatives.


	Year Ended December 31,
			2010 vs.					2009 vs.
	2010		2009			2009		2008			2008

Oil (per Bbl)
U.S. Onshore	$	75.53		+34	%	$	56.17		−41	%	$	95.63
Canada	$	58.60		+24	%	$	47.35		−33	%	$	71.04
North America Onshore	$	64.51		+29	%	$	50.11		−37	%	$	79.45
U.S. Offshore	$	77.81		+28	%	$	60.75		−42	%	$	104.90
Total	$	65.14		+27	%	$	51.39		−38	%	$	83.35
Gas (per Mcf)
U.S. Onshore	$	3.73		+19	%	$	3.14		−58	%	$	7.43
Canada	$	4.11		+12	%	$	3.66		−55	%	$	8.17
North America Onshore	$	3.82		+17	%	$	3.27		−57	%	$	7.61
U.S. Offshore	$	5.12		+22	%	$	4.20		−56	%	$	9.53
Total	$	3.84		+16	%	$	3.31		−57	%	$	7.73
NGLs (per Bbl)
U.S. Onshore	$	30.78		+32	%	$	23.40		−43	%	$	40.97
Canada	$	46.60		+41	%	$	33.09		−46	%	$	61.45
North America Onshore	$	32.55		+32	%	$	24.65		−44	%	$	43.94
U.S. Offshore	$	38.22		+39	%	$	27.42		−46	%	$	51.11
Total	$	32.61		+32	%	$	24.71		−44	%	$	44.08
Combined (per Boe)(1)
U.S. Onshore	$	28.42		+27	%	$	22.41		−53	%	$	47.91
Canada	$	39.11		+21	%	$	32.29		−44	%	$	57.65
North America Onshore	$	31.52		+24	%	$	25.38		—50	%	$	50.78
U.S. Offshore	$	49.06		+26	%	$	38.83		−48	%	$	74.55
Total	$	31.91		+22	%	$	26.15		−50	%	$	52.49


(1)		Gas volumes are converted to Boe at the rate of six Mcf of gas per barrel of oil, based upon the approximate relative energy content of gas and oil, which rate is not necessarily indicative of the relationship of gas and oil prices. NGL volumes are converted to Boe on a one-to-one basis with oil.

The volume and price changes in the tables above caused the following changes to our oil, gas and NGL sales between 2008 and 2010.


	Oil			Gas			NGLs			Total
	(In millions)

2008 sales	$	3,233		$	7,244		$	1,243		$	11,720
Changes due to volumes		258			222			89			569
Changes due to prices		(1,338	)		(4,269	)		(585	)		(6,192	)

2009 sales		2,153			3,197			747			6,097
Changes due to volumes		(67	)		(122	)		46			(143	)
Changes due to prices		557			497			254			1,308

2010 sales	$	2,643		$	3,572		$	1,047		$	7,262

Oil Sales

2010 vs. 2009 Oil sales increased $557 million as a result of a 27% increase in our realized price. The largest contributor to the increase in our realized price was the increase in the average NYMEX West Texas Intermediate index price over the same time period.

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

2009 vs. 2008 Oil sales decreased $1.3 billion as a result of a 38% decrease in our realized price without hedges. The largest contributor to the decrease in our realized price was the decrease in the average NYMEX West Texas Intermediate index price over the same time period.

Oil sales increased $258 million due to a three million barrel, or 8%, increase in production. The increased production resulted primarily from the continued development of Jackfish in Canada.

Gas Sales

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

A four percent decrease in production during 2010 caused gas sales to decrease by $122 million. The decrease was primarily due to the divestiture of our U.S. Offshore properties in the second quarter of 2010, as well as higher Canadian government royalties. Also, our other North America Onshore properties decreased one percent due to reduced drilling during most of 2009 in response to lower gas prices. As a result of the reduced drilling activities during 2009, natural declines of existing wells outpaced production gains from new drilling in 2010.

2009 vs. 2008 Gas sales decreased $4.3 billion as a result of a 57% decrease in our realized price without hedges. This decrease was largely due to decreases in the North American regional index prices upon which our gas sales are based.

A three percent increase in production during 2009 caused gas sales to increase by $222 million. Our North America Onshore properties contributed 40 Bcf of higher volumes. This increase included 25 Bcf of higher production in Canada due to a decline in Canadian government royalties, resulting largely from lower gas prices. The remainder of the North America Onshore growth resulted from new drilling and development that exceeded natural production declines, primarily in the Barnett Shale field in north Texas. These increases were partially offset by 12 Bcf of lower production from our U.S. Offshore properties, largely resulting from natural production declines.

NGL Sales

2010 vs. 2009 NGL sales increased $254 million during 2010 as a result of a 32% increase in our realized price. The increase was largely due to an increase in the Mont Belvieu, Texas index price over the same time period. NGL sales increased $46 million in 2010 due to a six percent increase in production. The increase in production was primarily due to increased drilling in North America Onshore areas that have liquids-rich gas.

2009 vs. 2008 NGL sales decreased $585 million as a result of a 44% decrease in our realized price. This decrease was largely due to a decrease in the Mont Belvieu, Texas index price over the same time period. NGL sales increased $89 million in 2009 due to a seven percent increase in production. The increase in production is primarily due to drilling and development in the Barnett Shale.

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,
	2010			2009			2008
	(In millions)

Cash settlement receipts (payments):
Gas derivatives	$	888		$	505		$	(424	)
Oil derivatives		—			—			27

Total cash settlements		888			505			(397	)

Unrealized gains (losses) on fair value changes:
Gas derivatives		12			(83	)		243
Oil derivatives		(91	)		(38	)		—
NGL derivatives		2			—			—

Total unrealized gains (losses) on fair value changes		(77	)		(121	)		243

Oil, gas and NGL derivatives	$	811		$	384		$	(154	)


	Year Ended December 31, 2010
	Oil		Gas		NGLs		Total
	(Per Bbl)		(Per Mcf)		(Per Bbl)		(Per Boe)

Realized price without hedges	$	65.14	$	3.84	$	32.61	$	31.91
Cash settlements of hedges		—		0.96		—		3.90

Realized price, including cash settlements	$	65.14	$	4.80	$	32.61	$	35.81


	Year Ended December 31, 2009
	Oil		Gas		NGLs		Total
	(Per Bbl)		(Per Mcf)		(Per Bbl)		(Per Boe)

Realized price without hedges	$	51.39	$	3.31	$	24.71	$	26.15
Cash settlements of hedges		—		0.52		—		2.16

Realized price, including cash settlements	$	51.39	$	3.83	$	24.71	$	28.31


	Year Ended December 31, 2008
	Oil		Gas			NGLs		Total
	(Per Bbl)		(Per Mcf)			(Per Bbl)		(Per Boe)

Realized price without hedges	$	83.35	$	7.73		$	44.08	$	52.49
Cash settlements of hedges		0.70		(0.46	)		—		(1.78	)

Realized price, including cash settlements	$	84.05	$	7.27		$	44.08	$	50.71

Our oil, gas, and NGL derivatives include price swaps, costless collars and basis swaps. For the price swaps, we receive a fixed price for our production and pay a variable market price to the contract counterparty. The price collars set a floor and ceiling price. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, we cash-settle the difference with the counterparty. For the basis swaps, we receive a fixed differential between two index prices and pay a variable differential on the same two index prices to the contract counterparty. Cash settlements presented in the tables above represent net realized gains or losses related to these various instruments.

Additionally, to facilitate a portion of our price swaps, we have sold gas call options for 2012 and oil call options for 2011 and 2012. The call options give the counterparty the right to place us into a price swap at a predetermined fixed price. The terms of these call options are presented in “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” of this report.

During 2010 and 2009, we received $888 million, or $0.96 per Mcf, and $505 million, or $0.52 per Mcf, respectively, from counterparties to settle our gas derivatives. During 2008, we paid $424 million, or $0.46 per Mcf to counterparties to settle our gas derivatives and received $27 million, or $0.70 per Bbl from counterparties to settle our oil derivatives. We had no settlements on NGL derivatives in any of these periods.

In addition to recognizing these cash settlement effects, we also recognize unrealized changes in the fair values of our oil, gas and NGL derivative instruments in each reporting period. We estimate the fair values of these derivatives primarily by using internal discounted cash flow calculations. We periodically validate our valuation techniques by comparing our internally generated fair value estimates with those obtained from contract counterparties or brokers.

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. Based on the amount of volumes subject to our gas derivative financial instruments at December 31, 2010, a 10% increase in these forward curves would have decreased our 2010 unrealized gains by approximately $154 million. A 10% increase in the forward curves associated with our oil derivative financial instruments would have increased our 2010 unrealized losses by approximately $142 million. Another key input to our cash flow calculations is our estimate of volatility for these forward curves, which we base primarily upon implied volatility. Finally, the amount of production subject to oil, gas and NGL derivatives is not a variable in our cash flow calculations, but it does impact the total derivative values.

Counterparty credit risk is also a component of commodity derivative valuations. We have mitigated our exposure to any single counterparty by contracting with thirteen separate counterparties. Additionally, our derivative contracts generally require cash collateral to be posted if either our or the counterparty’s credit rating falls below investment grade. The mark-to-market exposure threshold, above which collateral must be posted, decreases as the debt rating falls further below investment grade. Such thresholds generally range from zero to $50 million for the majority of our contracts. As of December 31, 2010, the credit ratings of all our counterparties were investment grade.

Including the cash settlements discussed above, our oil, gas and NGL derivatives generated net gains of $811 million and $384 million during 2010 and 2009, respectively, and a net loss of $154 million during 2008. In addition to the impact of cash settlements, these net gains and losses were impacted by new positions and settlements that occurred during each period, as well as the relationships between contract prices and the associated forward curves. A summary of our outstanding oil, gas and NGL derivative positions as of December 31, 2010 is included in Item 7A. “Quantitative and Qualitative Disclosures About Market Risk” of this report.

Marketing and Midstream Revenues and Operating Costs and Expenses

The details of the changes in marketing and midstream revenues, operating costs and expenses and the resulting operating profit are shown in the table below.


	Year Ended December 31,
			2010 vs					2009 vs
	2010		2009(1)			2009		2008(1)			2008
	($ in millions)

Marketing and midstream:
Revenues	$	1,867		+22	%	$	1,534		−33	%	$	2,292
Operating costs and expenses		1,357		+33	%		1,022		−37	%		1,611

Operating profit	$	510		−0	%	$	512		−25	%	$	681


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

2010 vs. 2009 Marketing and midstream revenues increased $333 million and operating costs and expenses increased $335 million, causing operating profit to decrease $2 million. Both revenues and expenses increased primarily due to higher natural gas and NGL prices, partially offset by the effects of lower gas marketing profits.

2009 vs. 2008 Marketing and midstream revenues decreased $758 million and operating costs and expenses decreased $589 million, causing operating profit to decrease $169 million. Both revenues and expenses decreased primarily due to lower natural gas and NGL prices, partially offset by higher NGL production and gas pipeline throughput.

Lease Operating Expenses (“LOE”)

The details of the changes in LOE are shown in the table below.


	Year Ended December 31,
			2010 vs.					2009 vs.
	2010		2009(1)			2009		2008(1)			2008

Lease operating expenses ($ in millions):
U.S. Onshore	$	832		−1	%	$	838		−6	%	$	893
Canada		797		+18	%		673		−13	%		776

North American Onshore		1,629		+8	%		1,511		−10	%		1,669
U.S. Offshore		60		−62	%		159		−13	%		182

Total	$	1,689		+1	%	$	1,670		−10	%	$	1,851

Lease operating expenses per Boe:
U.S. Onshore	$	5.26		−4	%	$	5.46		−11	%	$	6.11
Canada	$	12.37		+22	%	$	10.15		−20	%	$	12.74
North American Onshore	$	7.32		+7	%	$	6.87		−15	%	$	8.06
U.S. Offshore	$	12.00		+0	%	$	11.98		+6	%	$	11.29
Total	$	7.42		+4	%	$	7.16		−14	%	$	8.29


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

2010 vs. 2009 LOE increased $19 million in 2010, which included a $118 million increase related to our North America Onshore operations and a $99 million decrease related to our U.S. Offshore operations. North America Onshore LOE increased $78 million due to changes in the exchange rate between the U.S. and

Canadian dollars. The remainder of the increase in North America Onshore LOE is primarily due to increased costs related to our Jackfish operation in Canada. U.S. Offshore LOE decreased primarily due to property divestitures in the second quarter of 2010. The increase due to exchange rates was also the main contributor to the changes in North America Onshore and total LOE per Boe.

2009 vs. 2008 LOE decreased $181 million in 2009. LOE dropped $182 million due to declining costs for fuel, materials, equipment and personnel, as well as declines in maintenance and well workover projects. Such declines largely resulted from decreasing demand for field services due to lower oil and gas prices. Changes in the exchange rate between the U.S. and Canadian dollar reduced LOE $49 million. Additionally, LOE decreased $31 million as a result of hurricane damages in 2008 to certain of our U.S. Offshore facilities and transportation systems. These factors, excluding the hurricane damage, were also the main contributors to the decrease in LOE per Boe on our North America Onshore properties. Production growth at our large-scale Jackfish project also contributed to a decrease in LOE per Boe. As Jackfish production approached the facility’s capacity during 2009, its per-unit costs declined, contributing to lower overall LOE per Boe. The remainder of our four percent company-wide production growth added $81 million to LOE during 2009.

Taxes Other Than Income Taxes

Taxes other than income taxes consist primarily of production taxes and ad valorem taxes assessed by various government agencies on our U.S. Onshore properties. Production taxes are based on a percentage of production revenues that varies by property and government jurisdiction. Ad valorem taxes generally are based on property values as determined by the government agency assessing the tax. The following table details the changes in our taxes other than income taxes.


	Year Ended December 31,
			2010 vs					2009 vs
	2010		2009(1)			2009		2008(1)			2008
	($ in millions)

Production	$	210		+59	%	$	132		−57	%	$	306
Ad valorem		165		−6	%		175		+8	%		162
Other		5		−30	%		7		−4	%		8

Total	$	380		+21	%	$	314		−34	%	$	476


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

2010 vs. 2009 Production taxes increased $78 million in 2010. This increase was largely due to higher U.S. Onshore revenues, as well as a decrease in production tax credits associated with certain properties in the state of Texas. Ad valorem taxes decreased $10 million primarily due to lower assessed values of our U.S. Onshore oil and gas property and equipment.

2009 vs. 2008 Production taxes decreased $174 million in 2009. This decrease was largely due to lower U.S. Onshore revenues, as well as an increase in production tax credits associated with certain properties in the state of Texas. Ad valorem taxes increased $13 million primarily due to higher assessed oil and gas property and equipment values.

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

DD&A of oil and gas properties is calculated by multiplying the percentage of total proved reserve volumes produced during the year, by the “depletable base.” The depletable base represents our capitalized investment, net of accumulated DD&A and reductions of carrying value, plus future development costs related to proved undeveloped reserves. 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. Oil and gas property DD&A is calculated separately on a country-by-country basis.

The changes in our production volumes, DD&A rate per unit and DD&A of oil and gas properties are shown in the table below.


	Year Ended December 31,
			2010 vs					2009 vs
	2010		2009(1)			2009		2008(1)			2008

Total production volumes (MMBoe)		228		−2	%		233		+4	%		223
DD&A rate ($ per Boe)	$	7.36		−6	%	$	7.86		−40	%	$	13.20

DD&A expense ($ in millions)	$	1,675		−9	%	$	1,832		−38	%	$	2,948


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

The following table details the changes in DD&A of oil and gas properties between 2008 and 2010 due to the changes in production volumes and DD&A rate presented in the table above (in millions).


2008 DD&A	$	2,948
Change due to volumes		130
Change due to rate		(1,246	)

2009 DD&A		1,832
Change due to volumes		(43	)
Change due to rate		(114	)

2010 DD&A	$	1,675

2010 vs. 2009 Oil and gas property-related DD&A decreased $114 million during 2010 due to a six percent decrease in the DD&A rate. The largest contributors to the rate decrease were our 2010 U.S. Offshore property divestitures and a reduction of the carrying value of our United States oil and gas properties recognized in the first quarter of 2009. This reduction totaled $6.4 billion and resulted from a full cost ceiling limitation. These decreases were partially offset by the effects of costs incurred and the transfer of previously unproved costs to the depletable base as a result of 2010 drilling and development activities, as well as changes in the exchange rate between the U.S. and Canadian dollars.

2009 vs. 2008 Oil and gas property related DD&A decreased $1.2 billion due to a 40% decrease in the DD&A rate. The largest contributors to the rate decrease were reductions of the carrying values of certain of our oil and gas properties recognized in the first quarter of 2009 and the fourth quarter of 2008. These reductions totaled $16.3 billion and resulted from full cost ceiling limitations in the United States and Canada. In addition, the effects of changes in the exchange rate between the U.S. and Canadian dollars also contributed to the rate decrease. These factors were partially offset by the effects of costs incurred and the transfer of previously unproved costs to the depletable base as a result of 2009 drilling activities. Partially offsetting the impact from the lower 2009 DD&A rate was our four percent production increase, which caused oil and gas property related DD&A expense to increase $130 million.

The impact of adopting the SEC’s new Modernization of Oil and Gas Reporting rules at the end of 2009 had virtually no impact on our DD&A rate.

General and Administrative Expenses (“G&A”)

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

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


	Year Ended December 31,
				2010 vs						2009 vs
	2010			2009(1)			2009			2008(1)			2008
	($ in millions)

Gross G&A	$	987			−11	%	$	1,107			+0	%	$	1,103
Capitalized G&A		(311	)		−6	%		(332	)		−2	%		(337	)
Reimbursed G&A		(113	)		−11	%		(127	)		+5	%		(121	)

Net G&A	$	563			−13	%	$	648			+0	%	$	645


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

2010 vs. 2009 Gross G&A decreased $120 million largely due to a decline in employee severance costs. Such costs decreased primarily due to Gulf of Mexico employees that were impacted by the integration of our Gulf of Mexico and International operations into one offshore unit in the second quarter of 2009 and other employee departures during 2009. Gross G&A, as well as capitalized G&A, also decreased subsequent to our mid-year 2010 Gulf of Mexico divestitures as a result of the decline in our workforce. The Gulf of Mexico divestitures were also the main contributor to the decrease in G&A reimbursements. Gross and capitalized G&A also declined due to reduced spending initiatives for certain discretionary cost categories. These decreases were partially offset by an increase due to the effects of changes in the exchange rate between the U.S. and Canadian dollars.

2009 vs. 2008 Gross G&A increased $4 million. This increase was due to approximately $60 million of higher costs for employee compensation and benefits, mostly offset by the effects of our 2009 reduced spending initiatives for certain discretionary cost categories.

Employee cost increases in 2009 included an additional $57 million of severance costs. This increase was primarily due to Gulf of Mexico and other employee departures during 2009. Additionally, postretirement benefit costs increased approximately $50 million. The increases in employee costs were partially offset by a $27 million decrease due to accelerated share-based compensation expense recognized in 2008 resulting from a modification of certain executives compensation arrangements. The modified compensation arrangements provide that executives who meet certain years-of-service and age criteria can retire and continue vesting in outstanding share-based grants. Although this modification does not accelerate the vesting of the executives’ grants, it does accelerate the expense recognition as executives approach the years-of-service and age criteria.

Restructuring Costs

The following schedule includes the components of restructuring costs.


	Year Ended December 31, 2010									Year Ended December 31, 2009
	Continuing			Discontinued						Continuing		Discontinued
	Operations			Operations			Total			Operations		Operations		Total
	(In millions)

Cash severance	$	(17	)	$	1		$	(16	)	$	66	$	24	$	90
Share-based awards		(10	)		(5	)		(15	)		39		24		63
Lease obligations		70			—			70			—		—		—
Asset impairments		11			—			11			—		—		—
Other		3			—			3			—		—		—

Restructuring costs	$	57		$	(4	)	$	53		$	105	$	48	$	153

Employee Severance

In the fourth quarter of 2009, we recognized $153 million of estimated employee severance costs associated with the planned divestiture of our offshore assets that was announced in November 2009. This amount was based on estimates of the number of employees that would ultimately be impacted by the divestitures and included amounts related to cash severance costs and accelerated vesting of share-based grants. Of the $153 million total, $105 million related to our U.S. Offshore operations and the remainder related to our International discontinued operations.

During 2010, we divested all of our U.S. Offshore assets and a significant part of our International assets. As a result of these divestitures and associated employee terminations, we decreased our estimate of employee severance costs in 2010 by $31 million. More offshore employees than previously estimated received comparable positions with either the purchaser of the properties or in our U.S. Onshore operations, and this caused the $31 million decrease to our severance estimate. This decrease includes $27 million related to our U.S. Offshore operations and $4 million related to our International discontinued operations.

Lease Obligations

As a result of the divestitures discussed above, 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 represent the present value of our future obligations under the leases, net of anticipated sublease income. The 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.

Asset Impairments

In 2010, we recognized $11 million of asset impairment charges for leasehold improvements and furniture associated with the office space we ceased using.

Interest Expense

The following schedule includes the components of interest expense.


	Year Ended December 31,
	2010			2009			2008
	(In millions)

Interest based on debt outstanding	$	408		$	437		$	426
Capitalized interest		(76	)		(94	)		(111	)
Early retirement of debt		19			—			—
Other		12			6			14

Total interest expense	$	363		$	349		$	329

2010 vs. 2009 Interest based on debt outstanding decreased in 2010 primarily due to the retirement of $177 million of 10.125% notes upon their maturity in the fourth quarter of 2009 and the early redemption of our 7.25% senior notes as discussed below.

Capitalized interest decreased during 2010 primarily due to the divestitures of our U.S. Offshore properties during the first half of 2010, which was partially offset by higher capitalized interest associated with our Canadian oil sands development projects.

In the second quarter of 2010, we redeemed $350 million of 7.25% senior notes prior to their scheduled maturity of October 1, 2011. The notes were redeemed for $384 million, which represented 100 percent of the principal amount, a make-whole premium of $28 million and $6 million of accrued and unpaid interest. On the date of redemption, these notes also had an unamortized premium of $9 million. The $19 million presented

in the table above represents the net of the $28 million make-whole premium and $9 million amortization of the remaining premium.

2009 vs. 2008 Interest based on debt outstanding increased $11 million from 2008 to 2009. This increase was primarily due to interest paid on the $500 million of 5.625% senior unsecured notes and $700 million of 6.30% senior unsecured notes that we issued in January 2009. This was partially offset by lower interest resulting from the retirement of our exchangeable debentures during the third quarter of 2008 and lower interest rates on our floating-rate commercial paper borrowings.

Capitalized interest decreased from 2008 to 2009 primarily due to the sales of our West African exploration and development properties in 2008 and the completion of the Access pipeline transportation system in Canada in the second quarter of 2008.

Interest-Rate and Other Financial Instruments

The details of the changes in our interest-rate and other financial instruments are shown in the table below.


	Year Ended December 31,
	2010			2009			2008
	(In millions)

(Gains) losses from:
Interest rate swaps — cash settlements	$	(44	)	$	(40	)	$	(1	)
Interest rate swaps — unrealized fair value changes		30			(66	)		(104	)
Chevron common stock		—			—			363
Option embedded in exchangeable debentures		—			—			(109	)

Total	$	(14	)	$	(106	)	$	149

Interest Rate Swaps

During 2010, 2009 and 2008, we received cash settlements totaling $44 million, $40 million and $1 million, respectively, from counterparties to settle our interest rate swaps.

In addition to recognizing cash settlements, we recognize unrealized changes in the fair values of our interest rate swaps each reporting period. 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. We periodically validate our valuation techniques by comparing our internally generated fair value estimates with those obtained from contract counterparties or brokers. In 2010, we recorded an unrealized loss of $30 million as a result of changes in interest rates. In 2009 and 2008, we recorded unrealized gains of $66 million and $104 million, respectively, as a result of changes in interest rates.

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 a third party. Based on the notional amount subject to the interest rate swaps at December 31, 2010, a 10% increase in these forward curves would have decreased our 2010 unrealized loss for our interest rate swaps by approximately $68 million.

Similar to our commodity derivative contracts, counterparty credit risk is also a component of interest rate derivative valuations. We have mitigated our exposure to any single counterparty by contracting with seven separate counterparties. Additionally, our derivative contracts generally require cash collateral to be posted if either our or the counterparty’s credit rating falls below investment grade. The mark-to-market exposure threshold, above which collateral must be posted, decreases as the debt rating falls further below investment grade. Such thresholds generally range from zero to $50 million for the majority of our contracts. The credit ratings of all our counterparties were investment grade as of December 31, 2010.

Chevron Common Stock and Related Embedded Option

Until October 31, 2008, we owned 14.2 million shares of Chevron common stock and recognized unrealized changes in the fair value of this investment. On October 31, 2008, we exchanged these shares of Chevron common stock for Chevron’s interest in the Drunkard’s Wash properties located in east-central Utah and $280 million in cash. In accordance with the terms of the exchange, the fair value of our investment in the Chevron shares was estimated to be $67.71 per share on the exchange date. Prior to the exchange of these shares, we calculated the fair value of our investment in Chevron common stock using Chevron’s published market price.

We also recognized unrealized changes in the fair value of the conversion option embedded in the debentures exchangeable into shares of Chevron common stock. The embedded option was not actively traded in an established market. Therefore, we estimated its fair value using quotes obtained from a broker for trades occurring near the valuation date.

The loss during 2008 on our investment in Chevron common stock was directly attributable to a $25.62 per share decrease in the estimated fair value while we owned Chevron’s common stock during the year. The gain on the embedded option during 2008 was directly attributable to the change in fair value of the Chevron common stock from January 1, 2008 to the maturity date of August 15, 2008.

Reduction of Carrying Value of Oil and Gas Properties

During 2009 and 2008, we reduced the carrying values of certain of our oil and gas properties due to full cost ceiling limitations. A summary of these reductions and additional discussion is provided below.


	Year Ended December 31,
	2009				2008
			After				After
	Gross		Taxes		Gross		Taxes
	(In millions)

United States	$	6,408	$	4,085	$	6,538	$	4,168
Canada		—		—		3,353		2,488

Total	$	6,408	$	4,085	$	9,891	$	6,656

The 2009 reduction was recognized in the first quarter and the 2008 reductions were recognized in the fourth quarter. The reductions resulted from significant decreases in each country’s full cost ceiling compared to the immediately preceding quarter. The lower United States ceiling value in the first quarter of 2009 largely resulted from the effects of declining natural gas prices subsequent to December 31, 2008. The lower ceiling values in the fourth quarter of 2008 largely resulted from the effects of sharp declines in oil, gas and NGL prices compared to September 30, 2008.

To demonstrate these declines, the March 31, 2009, December 31, 2008 and September 30, 2008 weighted average wellhead prices are presented in the following table.


	March 31, 2009						December 31, 2008						September 30, 2008
	Oil		Gas		NGLs		Oil		Gas		NGLs		Oil		Gas		NGLs
Country	(Per Bbl)		(Per Mcf)		(Per Bbl)		(Per Bbl)		(Per Mcf)		(Per Bbl)		(Per Bbl)		(Per Mcf)		(Per Bbl)

United States	$	47.30	$	2.67	$	17.04	$	42.21	$	4.68	$	16.16	$	97.62	$	5.28	$	38.00
Canada		N/A		N/A		N/A	$	23.23	$	5.31	$	20.89	$	59.72	$	6.00	$	62.78

N/A Not applicable.

The March 31, 2009 oil and gas wellhead prices in the table above compare to the NYMEX cash price of $49.66 per Bbl for crude oil and the Henry Hub spot price of $3.63 per MMBtu for gas. The December 31, 2008 oil and gas wellhead prices in the table above compare to the NYMEX cash price of $44.60 per Bbl for crude oil and the Henry Hub spot price of $5.71 per MMBtu for gas. The September 30, 2008, wellhead prices

in the table compare to the NYMEX cash price of $100.64 per Bbl for crude oil and the Henry Hub spot price of $7.12 per MMBtu for gas.

Other, net

The following table includes the components of other, net.


	Year Ended December 31,
	2010			2009			2008
	(In millions)

Interest and dividend income	$	(13	)	$	(8	)	$	(54	)
Deep water royalties		—			(84	)		—
Hurricane insurance proceeds		—			—			(162	)
Other		(32	)		24			(1	)

Total	$	(45	)	$	(68	)	$	(217	)

Interest and dividend income decreased from 2008 to 2009 due to a decrease in dividends received on our previously owned investment in Chevron common stock and a decrease in interest received on cash equivalents due to lower rates and balances.

In 1995, the United States Congress passed the Deep Water Royalty Relief Act. The intent of this legislation was to encourage deep water exploration in the Gulf of Mexico by providing relief from the obligation to pay royalties on certain federal leases. Deep water leases issued in certain years by the Minerals Management Service (the “MMS”) have contained price thresholds, such that if the market prices for oil or gas exceeded the thresholds for a given year, royalty relief would not be granted for that year.

In October 2007, a federal district court ruled in favor of a plaintiff who had challenged the legality of including price thresholds in deep water leases. Additionally, in January 2009 a federal appellate court upheld this district court ruling. This judgment was later appealed to the United States Supreme Court, which, in October 2009, declined to review the appellate court’s ruling. The Supreme Court’s decision ended the MMS’s judicial course to enforce the price thresholds.

Prior to September 30, 2009, we had $84 million accrued for potential royalties on various deep water leases. Based upon the Supreme Court’s decision, we reduced to zero the $84 million loss contingency accrual in the third quarter of 2009.

In 2008, we recognized $162 million of excess insurance recoveries for damages suffered in 2005 related to hurricanes that struck the Gulf of Mexico. The excess recoveries resulted from business interruption claims on policies that were in effect when the 2005 hurricanes occurred.

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,
	2010			2009			2008

Total income tax expense (benefit) (In millions)	$	1,235		$	(1,773	)	$	(1,121	)

U.S. statutory income tax rate		35	%		(35	)%		(35	)%
Repatriations and assumed repatriations		4	%		1	%		7	%
State income taxes		1	%		(2	)%		(1	)%
Taxation on Canadian operations		(1	)%		(1	)%		5	%
Other		(4	)%		(2	)%		(3	)%

Effective income tax expense (benefit) rate		35	%		(39	)%		(27	)%

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

During 2008, we recognized $312 million of additional income tax expense that resulted from two related factors associated with our foreign operations. First, during 2008, we repatriated $2.6 billion from certain foreign subsidiaries to the United States. Second, we made certain tax policy election changes in the second quarter of 2008 to minimize the taxes we otherwise would pay for the cash repatriations, as well as the taxable gains associated with the sales of assets in West Africa. As a result of the repatriation and tax policy election changes, we recognized $295 million of additional current tax expense and $17 million of additional deferred tax expense. Excluding the $312 million of additional tax expense, our effective income tax benefit rate would have been 34% for 2008.

Earnings From Discontinued Operations

For all years presented in the following tables, our discontinued operations include amounts related to our assets in Azerbaijan, Brazil, China and other minor International properties. Additionally, during 2008, our discontinued operations included amounts related to our assets in West Africa, including Equatorial Guinea, Cote d’Ivoire, Gabon and other countries in the region until they were sold. Following are the components of earnings from discontinued operations.


	Year Ended December 31,
	2010			2009			2008

Total production (MMBoe)		10			16			18
Combined price without hedges (per Boe)	$	72.68		$	59.25		$	92.72

	(In millions)
Operating revenues	$	693		$	945		$	1,702

Expenses and other, net:
Operating expenses		212			496			776
Restructuring costs		(4	)		48			—
Reduction of carrying value of oil and gas properties		—			109			494
Gain on sale of oil and gas properties		(1,818	)		(17	)		(819	)
Other, net		(82	)		(13	)		(7	)

Total expenses and other, net		(1,692	)		623			444

Earnings before income taxes		2,385			322			1,258
Income tax expense		168			48			367

Earnings from discontinued operations	$	2,217		$	274		$	891

The following table presents gains on our offshore and African divestiture transactions by year.


	Year Ended December 31,
	2010						2009				2008
				After					After				After
	Gross			Taxes			Gross		Taxes		Gross		Taxes
	(In millions)

Azerbaijan	$	1,543		$	1,524		$	—	$	—	$	—	$	—
China — Panyu		308			235			—		—		—		—
Equatorial Guinea		—			—			—		—		619		544
Gabon		—			—			—		—		117		122
Cote d’Ivoire		—			—			17		17		83		95
Other		(33	)		(27	)		—		—		—		8

Total	$	1,818		$	1,732		$	17	$	17	$	819	$	769

2010 vs. 2009 Earnings increased $1.9 billion in 2010 primarily as a result of the $1.5 billion gain ($1.5 billion after taxes) from the divestiture of our Azerbaijan operations and the $308 million gain ($235 million after taxes) from the divestiture of our Panyu operations in China. Also, earnings increased $109 million due to the 2009 reductions of carrying value of our oil and gas properties, which primarily related to Brazil. The Brazilian reduction resulted largely from an exploratory well drilled at the BM-BAR-3 block in the offshore Barreirinhas Basin. After drilling this well in the first quarter of 2009, we concluded that the well did not have adequate reserves for commercial viability. As a result, the seismic, leasehold and drilling costs associated with this well contributed to the reduction recognized in the first quarter of 2009.

2009 vs. 2008 Earnings from discontinued operations decreased $617 million in 2009. Our discontinued earnings were impacted by several factors. First, operating revenues declined largely due to a 36% decrease in the price realized on our production, which was driven by a decline in crude oil index prices. Second, both operating revenues and expenses declined due to divestitures that closed in 2008. Earnings also decreased $752 million in 2009 due to larger gains recognized on West African asset divestitures in 2008.

Partially offsetting these decreased earnings in 2009 was the larger reduction of carrying value recognized in 2008 compared to 2009. The reductions largely consisted of full cost ceiling limitations related to our assets in Brazil that were caused by a decline in oil prices.

Capital Resources, Uses and Liquidity

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

Sources and Uses of Cash

The following table presents the sources and uses of our cash and cash equivalents. The table presents capital expenditures on a cash basis. Therefore, these amounts differ from capital expenditure amounts that include accruals and are referred to elsewhere in this document. Additional discussion of these items follows the table.


	2010			2009			2008
	(In millions)

Sources of cash and cash equivalents:
Operating cash flow — continuing operations	$	5,022		$	4,232		$	8,448
Divestitures of property and equipment		4,310			34			117
Cash distributed from discontinued operations		2,864			—			1,898
Commercial paper borrowings		—			1,431			1
Debt issuance, net of commercial paper repayments		—			182			—
Redemptions of long-term investments		21			7			250
Stock option exercises		111			42			116
Proceeds from exchange of Chevron stock		—			—			280
Other		16			8			59

Total sources of cash and cash equivalents		12,344			5,936			11,169

Uses of cash and cash equivalents:
Capital expenditures		(6,476	)		(4,879	)		(8,843	)
Commercial paper repayments		(1,432	)		—			—
Debt repayments		(350	)		(178	)		(1,031	)
Net credit facility repayments		—			—			(1,450	)
Repurchases of common stock		(1,168	)		—			(665	)
Redemption of preferred stock		—			—			(150	)
Dividends		(281	)		(284	)		(289	)
Purchases of short-term investments		(145	)		—			—
Other		(19	)		(17	)		—

Total uses of cash and cash equivalents		(9,871	)		(5,358	)		(12,428	)

Increase (decrease) from continuing operations		2,473			578			(1,259	)
Increase (decrease) from discontinued operations, net of distributions to continuing operations		(211	)		6			386
Effect of foreign exchange rates		17			43			(116	)

Net increase (decrease) in cash and cash equivalents	$	2,279		$	627		$	(989	)

Cash and cash equivalents at end of year	$	3,290		$	1,011		$	384

Short-term investments at end of year	$	145		$	—		$	—

Operating Cash Flow — Continuing Operations

Net cash provided by operating activities (“operating cash flow”) continued to be a significant source of capital and liquidity in 2010. Changes in operating cash flow from our continuing operations are largely due to the same factors that affect our net earnings, with the exception of those earnings changes due to such noncash expenses as DD&A, financial instrument fair value changes, property impairments and deferred income taxes. As a result, our operating cash flow increased 19% during 2010 primarily due to the increase in revenues as discussed in the “Results of Operations” section of this report.

During 2010, our operating cash flow funded approximately 78% of our cash payments for capital expenditures. However, our capital expenditures for 2010 included $500 million paid to form a heavy oil joint venture and acquire a 50 percent interest in the Pike oil sands in Alberta, Canada. This acquisition was completed in connection with the offshore divestitures discussed below. Excluding this $500 million acquisition, our operating cash flow funded approximately 84% of our capital expenditures during 2010. Offshore divestiture proceeds were used to fund the remainder of our cash-based capital expenditures.

During 2009, our operating cash flow funded approximately 87% of our cash payments for capital expenditures. Commercial paper borrowings were used to fund the remainder of our cash-based capital expenditures. During 2008, our capital expenditures were primarily funded by our operating cash flow and pre-existing cash balances.

Other Sources of Cash — Continuing and Discontinued Operations

As needed, we supplement our operating cash flow and available cash by accessing available credit under our senior credit facility and commercial paper program. We may also issue long-term debt to supplement our operating cash flow while maintaining adequate liquidity under our credit facilities. Additionally, we may acquire short-term investments to maximize our income on available cash balances. As needed, we reduce such short-term investment balances to further supplement our operating cash flow and available cash.

During 2010, we divested our U.S. Offshore, Azerbaijan, China and other minor international properties, generating $6.6 billion in pre-tax proceeds net of closing adjustments, or $5.6 billion after taxes. We have used proceeds from these divestitures to repay all our commercial paper borrowings, retire $350 million of other debt that was to mature in October 2011 and begin repurchasing our common shares. In addition, we began redeploying proceeds into our North America Onshore properties, including the $500 million Pike oil sands acquisition mentioned above.

During 2009, we issued $500 million of 5.625% senior unsecured notes due January 15, 2014 and $700 million of 6.30% senior unsecured notes due January 15, 2019. The net proceeds received of $1.187 billion, after discounts and issuance costs, were used primarily to repay Devon’s $1.005 billion of outstanding commercial paper as of December 31, 2008. Subsequent to the $1.005 billion commercial paper repayment in January 2009, we utilized additional commercial paper borrowings of $1.431 billion to fund capital expenditures in excess of our operating cash flow.

During 2008, we received $2.6 billion in pre-tax proceeds, or $1.9 billion after taxes and purchase price adjustments from sales of assets located in Equatorial Guinea and other West African countries. Also, in conjunction with these asset sales, we repatriated an additional $2.6 billion of earnings from certain foreign subsidiaries to the United States. We used these combined sources of cash in 2008 to fund debt repayments, common stock repurchases, redemptions of preferred stock and dividends on common and preferred stock. Additionally, we reduced our short-term investment balances by $250 million and received $280 million from the exchange of our investment in Chevron common stock.

Capital Expenditures

Our capital expenditures are presented by geographic area and type in the following table. The amounts in the table below reflect cash payments for capital expenditures, including cash paid for capital expenditures incurred in prior periods. Capital expenditures actually incurred during 2010, 2009 and 2008 were approximately $6.9 billion, $4.7 billion and $10.0 billion, respectively.


	2010		2009		2008
	(In millions)

U.S. Onshore	$	3,689	$	2,413	$	5,606
Canada		1,826		1,064		1,459

North American Onshore		5,515		3,477		7,065
U.S. Offshore		376		845		1,157

Total exploration and development		5,891		4,322		8,222
Midstream		236		323		451
Other		349		234		170

Total continuing operations	$	6,476	$	4,879	$	8,843

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 $5.9 billion, $4.3 billion and $8.2 billion in 2010, 2009 and 2008, respectively. The increase in exploration and development capital spending in 2010 was partially due to the $500 million Pike oil sands acquisition mentioned above. Additionally, with rising oil and NGL prices and proceeds from our offshore divestiture program, we are increasing drilling primarily to grow liquids production across our North America Onshore portfolio of properties.

The decline in capital expenditures from 2008 to 2009 was due to decreased drilling activities in most of our operating areas in response to lower commodity prices in 2009 compared to previous years. Also, the 2008 capital expenditures include $2.6 billion related to acquisitions of properties in Texas, Louisiana, Oklahoma and Canada.

Capital expenditures for our midstream operations are primarily for the construction and expansion of natural gas processing plants, natural gas gathering and pipeline systems and oil pipelines. Our midstream capital expenditures in 2010 were largely impacted by reduced U.S. Onshore dry gas drilling activities.

Capital expenditures related to corporate activities increased in 2010. This increase is largely driven by the construction of our new headquarters in Oklahoma City.

Net Repayments of Debt

During 2010, we repaid $1.4 billion of commercial paper borrowings and redeemed $350 million of 7.25% senior notes prior to their scheduled maturity of October 1, 2011, primarily with proceeds received from our U.S. Offshore divestitures.

During 2009, we repaid our $177 million 10.125% notes upon maturity in the fourth quarter.

During 2008, we repaid $1.5 billion in outstanding credit facility borrowings primarily with proceeds received from the sales of assets under our African divestiture program. Also during 2008, virtually all holders of exchangeable debentures exercised their option to exchange their debentures for shares of Chevron common stock owned by us. The debentures matured on August 15, 2008. In lieu of delivering our shares of Chevron common stock, we exercised our option to pay the exchanging debenture holders cash totaling $1.0 billion. This amount included the retirement of debentures with a book value of $652 million and a $379 million payment of the related embedded derivative option.

Repurchases of Common Stock

The following table summarizes our repurchases, including unsettled shares, under approved plans during 2010 and 2008 (amounts and shares in millions).


	2010						2008
Repurchase Program	Amount		Shares		Per Share		Amount		Shares		Per Share

2010 program	$	1,201		18.3	$	65.58	$	—		—	$	—
Annual program		—		—		—		178		2.0	$	87.83
2007 program		—		—		—		487		4.5	$	109.25

Totals	$	1,201		18.3	$	65.58	$	665		6.5	$	102.56

No shares were repurchased in 2009. The 2010 program expires on December 31, 2011 and the 2008 program and annual program expired on December 31, 2009.

Redemption of Preferred Stock

On June 20, 2008, we redeemed all 1.5 million outstanding shares of our 6.49% Series A cumulative preferred stock. Each share of preferred stock was redeemed for cash at a redemption price of $100 per share, plus accrued and unpaid dividends up to the redemption date.

Dividends

Devon paid common stock dividends of $281 million (or $0.64 per share) in 2010 and $284 million (or $0.64 per share) in both 2009 and 2008, respectively. Devon paid dividends of $5 million in 2008 to preferred stockholders. Devon redeemed its outstanding preferred stock in the second quarter of 2008.

Liquidity

Historically, our primary source of capital and liquidity has been operating cash flow. Additionally, we maintain revolving lines of credit and a commercial paper program, which can be accessed as needed to supplement operating cash flow. Other available sources of capital and liquidity include the issuance of equity and debt securities that can be issued pursuant to our automatically effective registration statement filed with the SEC. This registration statement can be used to offer short-term and long-term debt securities. Another major source of future liquidity will be proceeds from the sales of our remaining offshore assets in Brazil and Angola. We estimate the combination of these sources of capital will be adequate to fund future capital expenditures, share repurchases, debt repayments and other contractual commitments as discussed later in this section.

Operating Cash Flow

Our operating cash flow is sensitive to many variables, the most volatile of which is pricing of the oil, gas and NGLs produced. Due to improving oil and NGL prices, our operating cash flow increased approximately 16% to $5.5 billion in 2010 as compared to 2009. We expect operating cash flow to continue to be our primary source of liquidity.

Commodity Prices — Prices for oil, gas and NGLs 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 oil, gas and NGL prices and are beyond our control. We expect this volatility to continue throughout 2011.

To mitigate some of the risk inherent in prices, we have utilized various price swap, fixed-price physical delivery and price collar contracts to set minimum and maximum prices on our 2011 production. As of February 10, 2011, approximately 29% of our 2011 gas production is associated with financial price swaps and fixed-price physicals. We also have basis swaps associated with 0.2 Bcf per day of our 2011 gas production. Additionally, approximately 36% of our 2011 oil production is associated with financial price

collars. We also have call options that, if exercised, would hedge an additional 16% of our 2011 oil production.

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

Interest Rates — Our operating cash flow can also be sensitive to interest rate fluctuations. As of February 10, 2011, we had total debt of $6.2 billion with an overall weighted average borrowing rate of 6.4%. To manage our exposure to interest rate volatility, we have interest rate swap instruments with a total notional amount of $2.1 billion. These consist of instruments with a notional amount of $1.15 billion in which we receive a fixed rate and pay a variable rate. The remaining instruments consist of forward starting swaps. Under the terms of the forward starting swaps, we will net settle these contracts in September 2011, or sooner should we elect, based upon us paying a fixed rate and receiving a floating rate. Including the effects of these swaps, the weighted-average interest rate related to our debt was 5.7% as of February 10, 2011.

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. We are also exposed to the credit risk of counterparties to our derivative financial contracts as discussed previously in this report. 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, posting of letters of credit, prepayment requirements and collateral posting requirements.

Offshore Divestitures

During 2010, we sold our properties in the Gulf of Mexico, Azerbaijan, China and other International regions, generating $5.6 billion in after-tax proceeds. Additionally, we have entered into agreements to sell our remaining offshore assets in Brazil and Angola and are waiting for the respective governments to approve the divestitures. Once the pending transactions are complete, we expect to have generated more than $8 billion in after-tax proceeds. Similar to 2010, we expect to continue using the divestiture proceeds to invest in North America Onshore exploration and development opportunities, reduce our debt and repurchase our common shares.

Credit Availability

We have a $2.65 billion syndicated, unsecured revolving line of credit (the “Senior Credit Facility”) that can be accessed to provide liquidity as needed. The maturity date for $2.19 billion of the Senior Credit Facility is April 7, 2013. The maturity date for the remaining $0.46 billion is April 7, 2012. All amounts outstanding will be due and payable on the respective maturity dates unless the maturity is extended. Prior to each April 7 anniversary date, we have the option to extend the maturity of the Senior Credit Facility for one year, subject to the approval of the lenders. The Senior Credit Facility includes a revolving Canadian subfacility in a maximum amount of U.S. $500 million.

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.

We also have access to short-term credit under our commercial paper program. Total borrowings under the commercial paper program may not exceed $2.2 billion. Also, any borrowings under the commercial paper program reduce available capacity under the Senior Credit Facility on a dollar-for-dollar basis. Commercial paper debt generally has a maturity of between one and 90 days, although it can have a maturity of up to 365 days, and bears interest at rates agreed to at the time of the borrowing. The interest rate is based on a

standard index such as the Federal Funds Rate, LIBOR, or the money market rate as found on the commercial paper market.

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%. The credit agreement defines total funded debt as funds received through the issuance of debt securities such as debentures, bonds, notes payable, credit facility borrowings and short-term commercial paper borrowings. In addition, total funded debt includes all obligations with respect to payments received in consideration for oil, gas and NGL production yet to be acquired or produced at the time of payment. Funded debt excludes our outstanding letters of credit and trade payables. The credit agreement defines total capitalization as the sum of funded debt and stockholders’ equity adjusted for noncash financial writedowns, such as full cost ceiling impairments. As of December 31, 2010, we were in compliance with this covenant. Our debt-to-capitalization ratio at December 31, 2010, as calculated pursuant to the terms of the agreement, was 15.1%.

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.

The following schedule summarizes the capacity of our Senior Credit Facility by maturity date, as well as our available capacity as of February 10, 2011 (in millions).


April 7, 2012 maturity	$	463
April 7, 2013 maturity		2,187

Total Senior Credit Facility		2,650
Less:
Outstanding credit facility borrowings		—
Outstanding commercial paper borrowings		625
Outstanding letters of credit		39

Total available capacity	$	1,986

As presented in the table above, we had $625 million of commercial paper borrowings as of February 10, 2011. Although we ended 2010 with $3.4 billion of cash and short-term investments, the vast majority of this amount consists of proceeds from our International offshore divestitures. For the time being, we have decided not to repatriate these proceeds to the United States or permanently invest them in Canada. This decision is based on our ongoing evaluation of our future cash needs across our operations in the United States and Canada, as well as the relatively low borrowing rates on our short-term borrowings. If we do not repatriate these proceeds to the United States in the near-term, we may continue to increase our commercial paper borrowings to supplement our operating cash flow in funding our common stock repurchases and capital expenditures.

Debt Ratings

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

There are no “rating triggers” in any of our contractual obligations that would accelerate scheduled maturities should our debt rating fall below a specified level. Our cost of borrowing under our Senior Credit Facility is predicated on our corporate debt rating. Therefore, even though a ratings downgrade would not accelerate scheduled maturities, it would adversely impact the interest rate on any borrowings under our Senior Credit Facility. Under the terms of the Senior Credit Facility, a one-notch downgrade would increase the fully-drawn borrowing costs from LIBOR plus 35 basis points to a new rate of LIBOR plus 45 basis points. A ratings downgrade could also adversely impact our ability to economically access debt markets in the future. As of December 31, 2010, we were not aware of any potential ratings downgrades being contemplated by the rating agencies.

Capital Expenditures

Our 2011 capital expenditures are expected to range from $5.4 billion to $6.0 billion. To a certain degree, the ultimate timing of these capital expenditures is within our control. Therefore, if commodity prices fluctuate from current estimates, we could choose to defer a portion of these planned 2011 capital expenditures until later periods, or accelerate capital expenditures planned for periods beyond 2011 to achieve the desired balance between sources and uses of liquidity. Based upon current price expectations for 2011, our existing commodity hedging contracts, available cash balances and credit availability, we anticipate having adequate capital resources to fund our 2011 capital expenditures.

Common Stock Repurchase Program

As a result of the success we have experienced with our offshore divestiture program, we announced a share repurchase program in May 2010. The program authorizes the repurchase of up to $3.5 billion of our common shares and expires December 31, 2011. As of February 10, 2011, we had repurchased $1.6 billion, or 23.5 million of our shares at an average price of $69.60. We will continue to use proceeds from our offshore divestiture program in 2011 to fund our repurchase program.

Contractual Obligations

A summary of our contractual obligations as of December 31, 2010, is provided in the following table.


	Payments Due by Period
			Less Than		1-3		3-5		More Than
	Total		1 Year		Years		Years		5 Years
					(In millions)

North American Onshore:
Purchase obligations(1)	$	7,710	$	551	$	1,471	$	1,568	$	4,120
Debt(2)		5,628		1,812		9		582		3,225
Interest expense(3)		4,645		392		544		502		3,207
Drilling and facility obligations(4)		1,163		747		410		6		—
Firm transportation agreements(5)		1,734		282		487		408		557
Asset retirement obligations(6)		1,497		74		102		110		1,211
Lease obligations(7)		489		58		104		77		250
Other(8)		389		59		141		156		33

Total North America Onshore		23,255		3,975		3,268		3,409		12,603

Offshore:
Drilling and facility obligations(4)		595		314		281		—		—
Asset retirement obligations(6)		24		—		—		24		—
Lease obligations(7)		111		38		58		15		—

Total Offshore		730		352		339		39		—

Grand Total	$	23,985	$	4,327	$	3,607	$	3,448	$	12,603


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

(2)		Debt amounts represent scheduled maturities of our debt obligations at December 31, 2010, excluding $2 million of net premiums included in the carrying value of debt.

(3)		Interest expense relates to our fixed-rate debt and represents the scheduled cash payments. We had no variable-rate debt outstanding as of December 31, 2010.

(4)		Drilling and facility obligations represent contractual agreements with third-party service providers to procure drilling rigs and other related services for developmental and exploratory drilling and facilities construction. Our offshore commitment primarily relates to a long-term contract for a deepwater drilling rig being used in Brazil. Our lease and remaining commitments for this rig will be assumed by the buyer of our assets in Brazil when the associated divestiture transaction closes.

(5)		Firm transportation agreements represent “ship or pay” arrangements whereby we have committed to ship certain volumes of oil, gas and NGLs for a fixed transportation fee. We have entered into these agreements to aid the movement of our production to market. We expect to have sufficient production to utilize these transportation services.

(6)		Asset retirement obligations represent estimated discounted costs for future dismantlement, abandonment and rehabilitation costs. These obligations are recorded as liabilities on our December 31, 2010 balance sheet.

(7)		Lease obligations for our North America onshore operations consist primarily of non-cancelable leases for office space and equipment used in our daily operations. Lease obligations for our offshore operations consist primarily of an FPSO in Brazil. The Polvo FPSO lease term expires in 2014. Our lease and remaining commitments for this FPSO will be assumed by the buyer of our assets in Brazil when the associated divestiture transaction closes.

(8)		These amounts include $193 million related to uncertain tax positions. Expected pension funding obligations have not been included in this table, but are presented and discussed in the section immediately below.

Pension Funding and Estimates

Funded Status — As compared to the projected benefit obligation, our qualified and nonqualified defined benefit plans were underfunded by $492 million and $448 million at December 31, 2010 and 2009, respectively. A detailed reconciliation of the 2010 changes to our underfunded status is in Note 8 to the consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” of this report. Of the $492 million underfunded status at the end of 2010, $198 million is attributable to various nonqualified defined benefit plans that have no plan assets. However, we have established certain trusts to fund the benefit obligations of such nonqualified plans. As of December 31, 2010, these trusts had investments with a fair value of $36 million. The value of these trusts is in noncurrent other assets in our consolidated balance sheets included in “Item 8. Financial Statements and Supplementary Data” of this report.

As compared to the accumulated benefit obligation, our qualified defined benefit plans were underfunded by $218 million at December 31, 2010. The accumulated benefit obligation differs from the projected benefit obligation in that the former includes no assumption about future compensation levels.

Our funding policy regarding the qualified defined benefit plans is to contribute the amounts necessary for the plans’ assets to approximately equal the present value of benefits earned by the participants, as calculated in accordance with the provisions of the Pension Protection Act. While we did have investment gains in 2010 and 2009, the investment losses experienced during 2008 significantly reduced the value of our

plans’ assets. We estimate we will contribute approximately $84 million to our qualified pension plans during 2011. However, actual contributions may be different than this amount.

Our funding policy regarding the nonqualified defined benefit plans is to supplement as needed the amounts accumulated in the related trusts with available cash and cash equivalents.

Pension Estimate Assumptions — Our pension expense is recognized on an accrual basis over employees’ approximate service periods and is impacted by funding decisions or requirements. We recognized expense for our defined benefit pension plans of $85 million, $119 million and $61 million in 2010, 2009 and 2008, respectively. We estimate that our pension expense will approximate $91 million in 2011. Should our actual 2011 contributions to qualified and nonqualified plans vary significantly from our current estimate of $93 million, our actual 2011 pension expense could vary from this estimate.

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

We assumed that our plan assets would generate a long-term weighted average rate of return of 6.94% and 7.18% at December 31, 2010 and 2009, respectively. We developed these expected long-term rate of return assumptions by evaluating input from external consultants and economists as well as long-term inflation assumptions. The expected long-term rate of return on plan assets is based on a target allocation of investment types in such assets. At December 31, 2010, the target allocations for plan assets were 47.5% for equity securities, 40% for fixed-income securities and 12.5% for other investment types. Equity securities consist of investments in large capitalization and small capitalization companies, both domestic and international. Fixed-income securities include corporate bonds of investment-grade companies from diverse industries, United States Treasury obligations and asset-backed securities. Other investment types include short-term investment funds and a hedge fund of funds. We expect our long-term asset allocation on average to approximate the targeted allocation. We regularly review our actual asset allocation and periodically rebalance the investments to the targeted allocation when considered appropriate.

Pension expense increases as the expected rate of return on plan assets decreases. A decrease in our long-term rate of return assumption of 100 basis points would increase the expected 2011 pension expense by $6 million.

We discounted our future pension obligations using a weighted average rate of 5.50% and 6.00% at December 31, 2010 and 2009. The discount rate is determined at the end of each year based on the rate at which obligations could be effectively settled, considering the expected timing of future cash flows related to the plans. This rate is based on high-quality bond yields, after allowing for call and default risk. High quality corporate bond yield indices are considered when selecting the discount rate.

The pension liability and future pension expense both increase as the discount rate is reduced. Lowering the discount rate by 25 basis points would increase our pension liability at December 31, 2010, by $37 million, and increase estimated 2011 pension expense by $5 million.

At December 31, 2010, we had net actuarial losses of $357 million, which will be recognized as a component of pension expense in future years. These losses are primarily due to investment losses on plan assets in 2008, reductions in the discount rate since 2001 and increases in participant wages. We estimate that approximately $32 million and $26 million of the unrecognized actuarial losses will be included in pension expense in 2011 and 2012, respectively. The $32 million estimated to be recognized in 2011 is a component of the total estimated 2011 pension expense of $91 million referred to earlier in this section.

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

Contingencies and Legal Matters

For a detailed discussion of contingencies and legal matters, see Note 10 to the consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” of this report.

Critical Accounting Policies and Estimates

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

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

Full Cost Method of Accounting and Proved Reserves

Policy Description

We follow the full cost method of accounting for our oil and gas properties. Under this method all costs associated with property acquisition, exploration and development activities are capitalized, including our internal costs that can be directly identified with such activities. Capitalized costs are depleted on an equivalent unit-of-production method, converting gas to oil at the ratio of six thousand cubic feet of gas to one barrel of oil. Depletion is calculated using the capitalized costs, including estimated asset retirement costs, plus the estimated future expenditures to be incurred in developing proved reserves, net of estimated salvage values. Costs associated with unproved properties are excluded from the depletion calculation until it is determined whether or not proved reserves can be assigned to such properties.

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

Judgments and Assumptions

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. Certain of our reserve estimates are prepared or audited by outside petroleum consultants, while other reserve estimates are prepared by our engineers. See Note 22 of the accompanying consolidated financial statements for a summary of the amount of our reserves that are prepared or audited by outside petroleum consultants.

The passage of time provides more qualitative information regarding estimates of reserves, when revisions are made to prior estimates to reflect updated information. In the past five years, annual performance revisions to our reserve estimates, which have been both increases and decreases in individual years, have averaged less

than 2% 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. The ceiling calculation dictates that a 10% discount factor be used and future net revenues are calculated using prices that represent the average of the first-day-of-the-month price for the 12-month period prior to the end of each quarterly period. Therefore, the future net revenues associated with the estimated proved reserves are not based on our assessment of future prices or costs. In calculating the ceiling, we adjust the end-of-period price by the effect of derivative contracts in place that qualify for hedge accounting treatment. This adjustment requires little judgment as the calculated average price is adjusted using the contract prices for such hedges. None of our outstanding derivative contracts at December 31, 2010 qualified for hedge accounting treatment.

Because the ceiling calculation dictates the use of prices that are not representative of future prices and requires a 10% discount factor, the resulting value is not indicative of the true fair value of the reserves. Oil and gas prices have historically been cyclical and, for any particular 12-month period, can be either higher or lower than our long-term price forecast, which is a more appropriate input for estimating fair value. Therefore, oil and gas property writedowns that result from applying the full cost ceiling limitation, and that are caused by fluctuations in price as opposed to reductions to the underlying quantities of reserves, should not be viewed as absolute indicators of a reduction of the ultimate value of the related reserves.

Because of the volatile nature of oil and gas prices, it is not possible to predict the timing or magnitude of full cost writedowns. In addition, due to the inter-relationship of the various judgments made to estimate proved reserves, it is impractical to provide quantitative analyses of the effects of potential changes in these estimates. However, decreases in estimates of proved reserves would generally increase our depletion rate and, thus, our depletion expense. Decreases in our proved reserves may also increase the likelihood of recognizing a full cost ceiling writedown.

Derivative Financial Instruments

Policy Description

We periodically enter into derivative financial instruments with respect to a portion of our oil, gas and NGL production that hedge the future prices received. These instruments are used to manage the inherent uncertainty of future revenues due to commodity price volatility. Our commodity derivative financial instruments include financial price swaps, basis swaps, costless price collars and call options. Additionally, we periodically enter into interest rate swaps to manage our exposure to interest rate volatility. Under the terms of certain of our interest-rate swaps, we receive a fixed rate and pay a variable rate on a total notional amount. The remainder of our swaps represent forward starting swaps, under which we will pay a fixed rate and receive a floating rate on a total notional amount.

All derivative financial instruments are recognized at their current fair value as either assets or liabilities in the balance sheet. Changes in the fair value of these derivative financial instruments are recorded in the statement of operations unless specific hedge accounting criteria are met. For derivative financial instruments held during 2010, 2009 and 2008, we chose not to meet the necessary criteria to qualify our derivative financial instruments for hedge accounting treatment. Cash settlements with counterparties to our derivative financial instruments also increase or decrease earnings at the time of the settlement.

Judgments and Assumptions

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 United States 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 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 and/or brokers.

In spite of the recent turmoil in the financial markets, 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 thirteen separate counterparties, and our interest rate derivative contracts are held with seven separate counterparties. Second, our derivative contracts generally require cash collateral to be posted if either our or the counterparty’s credit rating falls below “investment grade”. The mark-to-market exposure threshold for collateral posting decreases as the debt rating falls further below investment grade. Such thresholds generally range from zero to $50 million for the majority of our contracts. As of December 31, 2010, the credit ratings of all our counterparties were investment grade.

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 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.”

Goodwill

Policy Description

Accounting for the acquisition of a business requires the allocation of the purchase price to the tangible and intangible net assets acquired with any excess recorded as goodwill. Goodwill is assessed for impairment at least annually. The impairment test requires allocating goodwill and all other assets and liabilities to assigned reporting units. The fair value of each reporting unit is estimated and compared to the net book value of the reporting unit. If the estimated fair value of the reporting unit is less than the net book value, including goodwill, then the goodwill is written down to the implied fair value of the goodwill through a charge to expense.

Judgments and Assumptions

The annual impairment test, which we conduct as of October 31 each year, 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 based upon 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 reserves. In our comparable transactions analysis, we review certain acquisition multiples for selected independent exploration and production company transactions and oil and gas asset packages announced recently. In our premiums paid analysis, we use a sample of selected independent exploration and production company transactions in addition to selected transactions of all publicly traded companies announced recently, to 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 mean and 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, 2010, the date of our last impairment test, the fair values of our United States and Canadian reporting units substantially exceeded their related carrying values.

A lower goodwill value decreases the likelihood of an impairment charge. However, unfavorable changes in reserves or in our price forecast would increase the likelihood of a goodwill impairment charge. A goodwill impairment charge would have no effect on liquidity or capital resources. However, it would adversely affect our results of operations in that period.

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

Income Taxes

Policy Description

We are required to estimate federal, state, provincial and foreign income taxes for each jurisdiction in which we operate. This process involves estimating the actual current tax exposure together with assessing future tax consequences resulting in deferred income taxes. We account for deferred income taxes using the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases. Deferred tax assets are also recognized for the future tax benefits attributable to the expected utilization of existing tax net operating loss carryforwards and other types of carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

Judgments and Assumptions

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 applied at 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. 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 in these accruals may occur in the future, based on the progress of ongoing tax audits, changes in legislation and resolution of pending tax matters.

Forward-Looking Estimates

We are providing our 2011 forward-looking estimates in this section. These estimates were based on our examination of historical operating trends, the information used to prepare our December 31, 2010, reserve reports and other data in our possession or available from third parties. The forward-looking estimates in this report were prepared assuming demand, curtailment, producibility and general market conditions for our oil, gas and NGLs during 2011 will be similar to 2010, unless otherwise noted. We make reference to the “Disclosure Regarding Forward-Looking Statements” at the beginning of this report. Amounts related to our Canadian operations have been converted to U.S. dollars using an estimated average 2011 exchange rate of $0.95 dollar to $1.00 Canadian dollar.

During 2011, our operations are substantially comprised of our ongoing North America Onshore operations. We also have International operations in Brazil and Angola that we are divesting. We have entered into agreements to sell our assets in Brazil for $3.2 billion and our assets in Angola for $70 million, plus contingent consideration. As a result of these divestitures, all revenues, expenses and capital related to our International operations are reported as discontinued operations in our financial statements. Additionally, all forward-looking estimates in this document exclude amounts related to our International operations, unless otherwise noted.

North America Onshore Operating Items

The following 2011 estimates relate only to our North America Onshore assets.

Oil, Gas and NGL Production

Set forth below are our estimates of oil, gas and NGL production for 2011. We estimate that our combined oil, gas and NGL production will total approximately 236 to 240 MMBoe.


	Oil		Gas		NGLs		Total
	(MMBbls)		(Bcf)		(MMBbls)		(MMBoe)

U.S. Onshore		17		736		34		174
Canada		28		199		3		64

North America Onshore		45		935		37		238

Oil and Gas Prices

We expect our 2011 average prices for the oil and gas production from each of our operating areas to differ from the NYMEX price as set forth in the following table. The expected ranges for prices are exclusive of the anticipated effects of the financial contracts presented in the “Commodity Price Risk Management” section below.

The NYMEX price for oil is determined using the monthly average of settled prices on each trading day for benchmark West Texas Intermediate crude oil delivered at Cushing, Oklahoma. The NYMEX price for gas is determined using the first-of-month South Louisiana Henry Hub price index as published monthly in Inside FERC .


	Expected Range of Prices
	as a % of NYMEX Price
	Oil	Gas

U.S. Onshore	89% to 99%	80% to 90%
Canada	63% to 73%	82% to 92%
North America Onshore	73% to 83%	80% to 90%

Commodity Price Risk Management

From time to time, we enter into NYMEX related financial commodity collar and price swap contracts. Such contracts are used to manage the inherent uncertainty of future revenues due to oil, gas and NGL price volatility. Although these financial contracts do not relate to specific production from our operating areas, they will affect our overall revenues, earnings and cash flow in 2011.

As of February 10, 2011, our financial commodity contracts pertaining to 2011 consisted of oil price collars, oil call options, gas price swaps, gas basis swaps and NGL basis swaps. The key terms of these contracts are presented in the following tables.


	Gas Price Swaps
			Weighted
	Volume		Average Price
Period	(MMBtu/d)		($/MMBtu)

Total year 2011		730,226	$	5.49

Gas Basis Swaps

Weighted Average

Differential to

Volume

Henry Hub

Period

Index

(MMBtu/d)

($/MMBtu)

Total year 2011

Panhandle Eastern Pipeline

150,000

0.33

Oil Price Collars

Floor Price

Ceiling Price

Weighted

Volume

Floor Range

Average Price

Ceiling Range

Average Price

Period

(Bbls/d)

($/Bbl)

Total year 2011

45,000

75.00 - $75.00

75.00

105.00 - $116.10

108.89


	Oil Call Options Sold
			Weighted
	Volume		Average Price
Period	(Bbls /d)		($/Bbl)

Total year 2011		19,500	$	95.00

NGL Basis Swaps

Pay

Natural

Receive

Volume

Gasoline

Oil

Period

(Bbls/d)

($/Bbl)

Total year 2011

500

70.77

80.52

To the extent that monthly NYMEX prices in 2011 are outside of the ranges established by the collars or differ from those established by the swaps, we and the counterparties to the contracts will cash-settle the difference. Such settlements will either increase or decrease our revenues for the period. Also, we will mark-to-market the contracts based on their fair values throughout 2011. Changes in the contracts’ fair values will also be recorded as increases or decreases to our revenues. The expected ranges of our realized prices as a percentage of NYMEX prices, which are presented earlier in this report, do not include any estimates of the impact on our prices from monthly settlements or changes in the fair values of our price collars and swaps.

Marketing and Midstream Revenues and Expenses

Marketing and midstream revenues and expenses are derived primarily from our gas processing plants and gas pipeline systems. These revenues and expenses vary in response to several factors. The factors include, but are not limited to, changes in production and NGL content from wells connected to the pipelines and related processing plants, changes in the absolute and relative prices of gas and NGLs, provisions of contractual agreements and the amount of repair and maintenance activity required to maintain anticipated processing levels and pipeline throughput volumes.

These factors increase the uncertainty inherent in estimating future marketing and midstream revenues and expenses. Given these uncertainties, we estimate that our 2011 marketing and midstream operating profit will be between $485 million and $535 million. We estimate that marketing and midstream revenues will be between $1.485 billion and $1.760 billion, and marketing and midstream expenses will be between $1.000 billion and $1.225 billion.

Production and Operating Expenses

These expenses, which include transportation costs, vary in response to several factors. Among the most significant of these factors are additions to or deletions from the property base, changes in the general price level of services and materials that are used in the operation of the properties, as well as the amount of repair and workover activity required. Additionally, lease operating expenses associated with oil production, particularly heavy oil production, are generally higher than operating expenses associated with gas and NGL production. Oil, gas and NGL prices also have an effect on lease operating expenses and impact the economic feasibility of planned workover projects.

Given these uncertainties, we expect that our 2011 lease operating expenses will be between $1.78 billion and $1.88 billion.

Taxes Other Than Income Taxes

Our taxes other than income taxes primarily consist of production taxes and ad valorem taxes that relate to our U.S. Onshore properties and are assessed by various government agencies. Production taxes are based on a percentage of production revenues that varies by property and government jurisdiction. Ad valorem taxes generally are based on property values as determined by the government agency assessing the tax. Over time, a certain property’s assessed value will increase or decrease due to changes in commodity sales prices, production volumes and proved reserves. Therefore, ad valorem taxes will generally move in the same direction as our oil, gas and NGL sales but in a less predictable manner compared to production taxes. Additionally, both production and ad valorem taxes will increase or decrease due to changes in the rates assessed by the government agencies.

Given these uncertainties, we estimate that our taxes other than income taxes for 2011 will be between 5.20% and 6.20% of total oil, gas and NGL sales.

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

Our 2011 oil and gas property DD&A rate will depend on various factors. Most notable among such factors are the amount of proved reserves that will be added from drilling or acquisition efforts in 2011 compared to the costs incurred for such efforts, revisions to our year-end 2010 reserve estimates that, based on prior experience, are likely to be made during 2011, as well as potential carrying value reductions that result from full cost ceiling tests.

Given these uncertainties, we estimate that our oil and gas property related DD&A rate will be between $7.40 per Boe and $8.00 per Boe. Based on these DD&A rates and the production estimates set forth earlier, oil and gas property related DD&A expense for 2010 is expected to be between $1.76 billion and $1.90 billion.

Additionally, we expect that our depreciation and amortization expense related to non-oil and gas fixed assets will total between $265 million and $295 million in 2011.

Accretion of Asset Retirement Obligation

Accretion of asset retirement obligation in 2011 is expected to be between $85 million and $95 million.

General and Administrative Expenses (“G&A”)

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

Given these limitations, we estimate our G&A for 2011 will be between $590 million and $630 million. This estimate includes approximately $110 million of non-cash, share-based compensation, net of related capitalization in accordance with the full cost method of accounting for oil and gas properties.

Interest Expense

Future interest rates and debt outstanding have a significant effect on our interest expense. We can only marginally influence the prices we will receive in 2011 from sales of oil, gas and NGLs and the resulting cash flow. This increases the margin of error inherent in estimating future outstanding debt balances and related interest expense. Other factors that affect outstanding debt balances and related interest expense, such as the amount and timing of capital expenditures, are generally within our control.

As of December 31, 2010, we had total debt of $5.6 billion, which is exclusively fixed-rate debt at an overall weighted average rate of 7.1%. Our debt includes $1.75 billion that is scheduled to mature on September 30, 2011. We also have access to the commercial paper market and our credit lines. Any commercial paper or credit line borrowings would bear interest at variable rates.

Based on the factors above, we expect our 2011 interest expense to be between $300 million and $340 million. The estimated interest expense is exclusive of the anticipated effects of the interest rate swap contracts presented in the “Interest Rate Risk Management” section below.

The 2011 interest expense estimate above is comprised of three primary components — interest related to outstanding debt, fees and issuance costs and capitalized interest. We expect interest expense in 2011 related to our outstanding debt, including net accretion of related discounts, to be between $380 million and $420 million. We expect interest expense in 2011 related to facility and agency fees, amortization of debt issuance costs and other miscellaneous items not related to outstanding debt balances to be between $5 million and $15 million. During 2011, we also expect to capitalize between $85 million and $95 million of interest, of which $45 to $55 million relates to our continuing oil and gas activities and the remainder relates to certain corporate construction projects and our discontinued operations.

Interest Rate Risk Management

From time to time, we enter into interest rate swaps. Such contracts are used to manage our exposure to interest rate volatility.

As of December 31, 2010, our interest rate swaps pertaining to 2011 consisted of instruments with a total notional amount of $2.10 billion. These consist of instruments with a notional amount of $1.15 billion in which we receive a fixed rate and pay a variable rate. The remaining instruments consist of forward starting swaps. Under the terms of the forward starting swaps, we will net settle these contracts in September 2011, or sooner should we elect. The net settlement amount will be based upon us paying a weighted-average fixed rate

of 3.92% and receiving a floating rate that is based upon the three-month LIBOR. The difference between the fixed and floating rate will be applied to the notional amount for the 30-year period from September 30, 2011 to September 30, 2041. The key terms of these contracts are presented in the following tables.


Fixed-to-Floating Swaps
		Fixed Rate			Variable
Notional		Received			Rate Paid	Expiration
(In millions)

$	300		4.30	%	Six month LIBOR		July 18, 2011
	100		1.90	%	Federal funds rate		August 3, 2012
	500		3.90	%	Federal funds rate		July 18, 2013
	250		3.85	%	Federal funds rate		July 22, 2013

$	1,150		3.82	%

Forward Starting Swaps

Fixed Rate

Variable

Notional

Paid

Rate Received

Expiration

(In millions)

950

3.92

Three month LIBOR

September 30, 2011

Income Taxes

Our financial income tax rate in 2011 will vary materially depending on the actual amount of financial pre-tax earnings. The tax rate for 2011 will be significantly affected by the proportional share of consolidated pre-tax earnings generated by our United States and Canadian operations due to the different tax rates of each country. Also, certain tax deductions and credits will have a fixed impact on 2011 income tax expense regardless of the level of pre-tax earnings that are produced. Additionally, significant changes in estimated capital expenditures, production levels of oil, gas and NGLs, the prices of such products, marketing and midstream revenues, or any of the various expense items could materially alter the effect of these tax deductions and credits on 2011 financial income tax rates.

Given the uncertainty of pre-tax earnings, we expect that our total financial income tax rate in 2011 will be between 20% and 40%. The current income tax rate is expected to be between 0% and 10%. The deferred income tax rate is expected to be between 20% and 30%.

Capital Resources, Uses and Liquidity

North America Onshore Capital Expenditures

Our capital expenditures budget is based on an expected range of future oil, gas and NGL prices as well as the expected costs of the capital additions. Should actual prices received differ materially from our price expectations for our future production, some projects may be accelerated or deferred and, consequently, may increase or decrease total 2011 capital expenditures. In addition, if the actual material or labor costs of the budgeted items vary significantly from the anticipated amounts, actual capital expenditures could vary materially from our estimates.

Given the limitations discussed above, we estimate that our 2011 oil and gas development and exploration capital expenditures will be between $4.500 billion and $4.900 billion. We estimate that our development capital will be between $3.875 billion and $4.175 billion. Development capital includes activity related to reserves classified as proved and drilling that does not offset currently productive units and for which there is not a certainty of continued production from a known productive formation. Development capital also includes estimates for plugging and abandonment charges. We estimate that our exploration capital will be between $625 million and $725 million. Exploration capital includes exploratory drilling to find and produce oil or gas in previously untested fault blocks or new reservoirs. Exploration capital also includes purchases of proved and unproved leasehold acreage. In addition to the development and exploration expenditures, we expect to

capitalize between $330 million and $350 million of G&A expenses and between $45 million and $55 million of interest related to our oil and gas activities.

In addition, we expect to spend between $225 million and $300 million on our midstream assets, which primarily include our oil pipelines, gas processing plants, and gas gathering and pipeline systems. We also expect total capital for corporate activities will be between $300 million and $395 million, including approximately $30 million of capitalized interest related to certain construction projects.

Other Cash Uses

In May 2010, our Board of Directors approved a $3.5 billion share repurchase program. This program expires on December 31, 2011. Through February 10, 2011, we had repurchased 23.5 million common shares for $1.6 billion, or $69.60 per share.

Our management expects the policy of paying a quarterly common stock dividend to continue. With the current $0.16 per share quarterly dividend rate and expected share repurchases, 2011 dividends are expected to approximate $264 million.

Capital Resources and Liquidity

Our estimated 2011 cash uses, including our capital activities, are expected to be funded primarily through a combination of our existing cash balances and operating cash flow, supplemented with commercial paper borrowings. At the beginning of 2011, we held $3.4 billion in cash and short-term investments. The amount of operating cash flow to be generated during 2011 is uncertain due to the factors affecting revenues and expenses as previously cited. However, if our operating cash flow were significantly less than our estimates, we would access the commercial paper market. Also, we have credit lines that we could access if deemed necessary. As of February 10, 2011, we had $2.0 billion of available credit under our credit lines.

Another major source of liquidity in 2011 will be the proceeds from the divestiture of our assets in Brazil and, to a lesser extent, the divestiture of our assets in Angola.

These sources of liquidity will allow us to continue repurchasing common shares and investing in the opportunities that exist across our North America Onshore portfolio of properties. We expect our combined capital resources to be adequate to fund our anticipated capital expenditures and other cash uses for 2011.


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 in the pricing applicable to our oil, gas and NGL production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our U.S. and Canadian gas and NGL production. Pricing for oil, gas and NGL production has been volatile and unpredictable for several years. See “Item 1A. Risk Factors.” Consequently, we periodically enter into financial hedging activities with respect to a portion of our oil, gas and NGL production through various financial transactions that hedge the future prices received. These transactions include financial price swaps, basis swaps and costless price collars. Additionally, to facilitate a portion of our price swaps, we have sold gas

call options for 2012 and oil call options for 2011 and 2012. The key terms of our derivatives in place as of December 31, 2010 are presented in the following tables.


	Gas Price Swaps
			Weighted
	Volume		Average Price
Period	(MMBtu/d)		($/MMBtu)

Total year 2011		712,500	$	5.51

Gas Basis Swaps

Weighted Average

Differential to

Volume

Henry Hub

Period

Index

(MMBtu/d)

($/MMBtu)

Total year 2011

Panhandle Eastern Pipeline

150,000

0.33


	Gas Call Options Sold
			Weighted
	Volume		Average Price
Period	(MMBtu/d)		($/MMBtu)

Total year 2012		487,500	$	6.00

Oil Price Collars

Floor Price

Ceiling Price

Weighted

Volume

Floor Range

Average Price

Ceiling Range

Average Price

Period

(Bbls/d)

($/Bbl)

Total year 2011

45,000

75.00 - $75.00

75.00

105.00 - $116.10

108.89


	Oil Call Options Sold
			Weighted
	Volume		Average Price
Period	(Bbls/d)		($/Bbl)

Total year 2011		19,500	$	95.00
Total year 2012		19,500	$	95.00


	NGL Basis Swaps
			Pay
			Natural		Receive
	Volume		Gasoline		Oil
Period	(Bbls/d)		($/Bbl)		($/Bbl)

Total year 2011		500	$	70.77	$	80.52
Total year 2012		500	$	71.82	$	81.92

The fair values of our commodity derivatives presented in the tables above are largely determined by estimates of the forward curves of the relevant price indices. At December 31, 2010, a 10% increase in the forward curves associated with our gas derivative instruments would have decreased the fair value of such instruments by approximately $154 million. A 10% increase in the forward curves associated with our oil derivative instruments would have decreased the fair value of these instruments by approximately $142 million.

Interest Rate Risk

At December 31, 2010, we had debt outstanding of $5.6 billion with fixed rates averaging 7.1%.

As of December 31, 2010, our interest rate swaps consisted of instruments with a total notional amount of $2.1 billion. These consist of instruments with a notional amount of $1.15 billion in which we receive a fixed rate and pay a variable rate. The remaining instruments consist of forward starting swaps. Under the terms of the forward starting swaps, we will net settle these contracts in September 2011, or sooner should we

elect. The net settlement amount will be based upon us paying a weighted-average fixed rate of 3.92% and receiving a floating rate that is based upon the three-month LIBOR. The difference between the fixed and floating rate will be applied to the notional amount for the 30-year period from September 30, 2011 to September 30, 2041. The key terms of these contracts are presented in the following tables.


Fixed-to-Floating Swaps
		Fixed Rate			Variable
Notional		Received			Rate Paid	Expiration
(In millions)

$	300		4.30	%	Six month LIBOR		July 18, 2011
	100		1.90	%	Federal funds rate		August 3, 2012
	500		3.90	%	Federal funds rate		July 18, 2013
	250		3.85	%	Federal funds rate		July 22, 2013

$	1,150		3.82	%

Forward Starting Swaps

Fixed Rate

Variable

Notional

Paid

Rate Received

Expiration

(In millions)

950

3.92

Three month LIBOR

September 30, 2011

The fair values of our interest rate instruments are largely determined by estimates of the forward curves of the Federal Funds rate and LIBOR. At December 31, 2010, a 10% increase in these forward curves would have increased the fair value of our interest rate swaps by approximately $68 million.

Foreign Currency Risk

Our net assets, net earnings and cash flows from our Canadian subsidiaries are based on the U.S. dollar equivalent of such amounts measured in the Canadian dollar functional currency. Assets and liabilities of the Canadian subsidiaries are translated to U.S. dollars using the applicable exchange rate as of the end of a reporting period. Revenues, expenses and cash flow are translated using the average exchange rate during the reporting period. A 10% unfavorable change in the Canadian-to-U.S. dollar exchange rate would not materially impact our December 31, 2010 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			75
Consolidated Financial Statements			76
Consolidated Balance Sheets as of December 31, 2010 and 2009			76
Consolidated Statements of Operations for the Years Ended December 31, 2010, 2009 and 2008			77
Consolidated Statements of Comprehensive Earnings (Loss) for the Years Ended December 31, 2010, 2009 and 2008			78
Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2010, 2009 and 2008			79
Consolidated Statements of Cash Flows for the Years Ended December 31, 2010, 2009 and 2008			80
Notes to Consolidated Financial Statements			81

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, 2010 and 2009, and the related consolidated statements of operations, comprehensive earnings (loss), stockholders’ equity and cash flows for each of the years in the three-year period ended December 31, 2010. We also have audited Devon Energy Corporation’s internal control over financial reporting as of December 31, 2010, 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, 2010 and 2009, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2010, 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, 2010, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

KPMG LLP

Oklahoma City, Oklahoma

February 23, 2011

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


	December 31,
	2010			2009
	(In millions, except
	share data)

ASSETS
Current assets:
Cash and cash equivalents	$	2,866		$	646
Accounts receivable		1,202			1,208
Current assets held for sale		563			657
Other current assets		924			481

Total current assets		5,555			2,992

Property and equipment, at cost:
Oil and gas, based on full cost accounting:
Subject to amortization		56,012			52,352
Not subject to amortization		3,434			4,078

Total oil and gas		59,446			56,430
Other .		4,429			4,045

Total property and equipment, at cost		63,875			60,475
Less accumulated depreciation, depletion and amortization		(44,223	)		(41,708	)

Property and equipment, net		19,652			18,767

Goodwill		6,080			5,930
Long-term assets held for sale		859			1,250
Other long-term assets		781			747

Total assets	$	32,927		$	29,686


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable — trade	$	1,411		$	1,137
Revenues and royalties due to others		538			486
Short-term debt		1,811			1,432
Current liabilities associated with assets held for sale		305			234
Other current liabilities		518			513

Total current liabilities		4,583			3,802

Long-term debt		3,819			5,847
Asset retirement obligations		1,423			1,418
Liabilities associated with assets held for sale		26			213
Other long-term liabilities		1,067			937
Deferred income taxes		2,756			1,899
Stockholders’ equity:
Common stock, $0.10 par value. Authorized 1.0 billion shares; issued 431.9 million and 446.7 million shares in 2010 and 2009, respectively		43			45
Additional paid-in capital		5,601			6,527
Retained earnings		11,882			7,613
Accumulated other comprehensive earnings		1,760			1,385
Treasury stock, at cost. 0.4 million shares in 2010		(33	)		—

Total stockholders’ equity		19,253			15,570

Commitments and contingencies (Note 10)
Total liabilities and stockholders’ equity	$	32,927		$	29,686

See accompanying notes to consolidated financial statements.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS


	Year Ended December 31,
	2010			2009			2008
	(In millions, except per share amounts)

Revenues:
Oil, gas and NGL sales	$	7,262		$	6,097		$	11,720
Oil, gas and NGL derivatives		811			384			(154	)
Marketing and midstream revenues		1,867			1,534			2,292

Total revenues		9,940			8,015			13,858

Expenses and other, net:
Lease operating expenses		1,689			1,670			1,851
Taxes other than income taxes		380			314			476
Marketing and midstream operating costs and expenses		1,357			1,022			1,611
Depreciation, depletion and amortization of oil and gas properties		1,675			1,832			2,948
Depreciation and amortization of non-oil and gas properties		255			276			255
Accretion of asset retirement obligations		92			91			80
General and administrative expenses		563			648			645
Restructuring costs		57			105			—
Interest expense		363			349			329
Interest-rate and other financial instruments		(14	)		(106	)		149
Reduction of carrying value of oil and gas properties		—			6,408			9,891
Other, net		(45	)		(68	)		(217	)

Total expenses and other, net		6,372			12,541			18,018
Earnings (loss) from continuing operations before income taxes		3,568			(4,526	)		(4,160	)
Income tax expense (benefit):
Current		516			241			441
Deferred		719			(2,014	)		(1,562	)

Total income tax expense (benefit)		1,235			(1,773	)		(1,121	)

Earnings (loss) from continuing operations		2,333			(2,753	)		(3,039	)
Discontinued operations:
Earnings from discontinued operations before income taxes		2,385			322			1,258
Discontinued operations income tax expense		168			48			367

Earnings from discontinued operations		2,217			274			891

Net earnings (loss)		4,550			(2,479	)		(2,148	)
Preferred stock dividends		—			—			5

Net earnings (loss) applicable to common stockholders	$	4,550		$	(2,479	)	$	(2,153	)

Basic net earnings (loss) per share:
Basic earnings (loss) from continuing operations per share	$	5.31		$	(6.20	)	$	(6.86	)
Basic earnings from discontinued operations per share		5.04			0.62			2.01

Basic net earnings (loss) per share	$	10.35		$	(5.58	)	$	(4.85	)

Diluted net earnings (loss) per share:
Diluted earnings (loss) from continuing operations per share	$	5.29		$	(6.20	)	$	(6.86	)
Diluted earnings from discontinued operations per share		5.02			0.62			2.01

Diluted net earnings (loss) per share	$	10.31		$	(5.58	)	$	(4.85	)

See accompanying notes to consolidated financial statements.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE EARNINGS (LOSS)


	Year Ended December 31,
	2010			2009			2008
	(In millions)

Net earnings (loss)	$	4,550		$	(2,479	)	$	(2,148	)
Foreign currency translation:
Change in cumulative translation adjustment		397			993			(1,960	)
Foreign currency translation income tax benefit (expense)		(20	)		(62	)		79

Foreign currency translation total		377			931			(1,881	)

Pension and postretirement benefit plans:
Net actuarial gain (loss) and prior service cost arising in current year		(33	)		59			(239	)
Recognition of net actuarial loss and prior service cost in net earnings (loss)		31			54			18
Pension and postretirement benefit plans income tax benefit (expense)		—			(42	)		80

Pension and postretirement benefit plans total		(2	)		71			(141	)

Other comprehensive earnings (loss), net of tax		375			1,002			(2,022	)

Comprehensive earnings (loss)	$	4,925		$	(1,477	)	$	(4,170	)

See accompanying notes to consolidated financial statements.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY


																Accumulated
										Additional						Other						Total
	Preferred			Common Stock						Paid-In			Retained			Comprehensive			Treasury			Stockholders’
	Stock			Shares			Amount			Capital			Earnings			Income			Stock			Equity
	(In millions)

Balance as of December 31, 2007	$	1			444		$	44		$	6,743		$	12,813		$	2,405		$	—		$	22,006
Net earnings (loss)		—			—			—			—			(2,148	)		—			—			(2,148	)
Other comprehensive earnings (loss), net of tax		—			—			—			—			—			(2,022	)		—			(2,022	)
Stock option exercises		—			4			1			123			—			—			(8	)		116
Restricted stock grants, net of cancellations		—			3			—			—			—			—			—			—
Common stock repurchased		—			(7	)		—			—			—			—			(709	)		(709	)
Common stock retired		—			—			(1	)		(716	)		—			—			717			—
Redemption of preferred stock		(1	)		—			—			(149	)		—			—			—			(150	)
Common stock dividends		—			—			—			—			(284	)		—			—			(284	)
Preferred stock dividends		—			—			—			—			(5	)		—			—			(5	)
Share-based compensation		—			—			—			196			—			—			—			196
Share-based compensation tax benefits		—			—			—			60			—			—			—			60

Balance as of December 31, 2008	$	—			444			44			6,257			10,376			383			—			17,060

Net earnings (loss)					—			—			—			(2,479	)		—			—			(2,479	)
Other comprehensive earnings (loss), net of tax					—			—			—			—			1,002			—			1,002
Stock option exercises					1			1			47			—			—			(5	)		43
Restricted stock grants, net of cancellations					2			—			—			—			—			—			—
Common stock repurchased					—			—			—			—			—			(40	)		(40	)
Common stock retired					—			—			(45	)		—			—			45			—
Common stock dividends					—			—			—			(284	)		—			—			(284	)
Share-based compensation					—			—			260			—			—			—			260
Share-based compensation tax benefits					—			—			8			—			—			—			8

Balance as of December 31, 2009					447			45			6,527			7,613			1,385			—			15,570
Net earnings (loss)					—			—			—			4,550			—			—			4,550
Other comprehensive earnings (loss), net of tax					—			—			—			—			375			—			375
Stock option exercises					2			—			117			—			—			(6	)		111
Restricted stock grants, net of cancellations					2			—			—			—			—			—			—
Common stock repurchased					—			—			—			—			—			(1,246	)		(1,246	)
Common stock retired					(19	)		(2	)		(1,217	)		—			—			1,219			—
Common stock dividends					—			—			—			(281	)		—			—			(281	)
Share-based compensation					—			—			158			—			—			—			158
Share-based compensation tax benefits					—			—			16			—			—			—			16

Balance as of December 31, 2010					432		$	43		$	5,601		$	11,882		$	1,760		$	(33	)	$	19,253

See accompanying notes to consolidated financial statements.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Year Ended December 31,
	2010			2009			2008
	(In millions)

Cash flows from operating activities:
Earnings (loss) from continuing operations	$	2,333		$	(2,753	)	$	(3,039	)
Adjustments to reconcile earnings (loss) from continuing operations to net cash provided by operating activities:
Depreciation, depletion and amortization		1,930			2,108			3,203
Deferred income tax expense (benefit)		719			(2,014	)		(1,562	)
Reduction of carrying value of oil and gas properties		—			6,408			9,891
Unrealized change in fair value of financial instruments		107			55			(456	)
Other noncash charges		215			288			623
Net decrease (increase) in working capital		(273	)		149			(207	)
Decrease (increase) in long-term other assets		32			(6	)		(53	)
Increase (decrease) in long-term other liabilities		(41	)		(3	)		48

Cash from operating activities — continuing operations		5,022			4,232			8,448
Cash from operating activities — discontinued operations		456			505			960

Net cash from operating activities		5,478			4,737			9,408

Cash flows from investing activities:
Proceeds from property and equipment divestitures		4,310			34			117
Capital expenditures		(6,476	)		(4,879	)		(8,843	)
Proceeds from exchange of Chevron Corporation common stock		—			—			280
Purchases of short-term investments		(145	)		—			(50	)
Redemptions of long-term investments		21			7			300
Other		(19	)		(17	)		—

Cash from investing activities — continuing operations		(2,309	)		(4,855	)		(8,196	)
Cash from investing activities — discontinued operations		2,197			(499	)		1,323

Net cash from investing activities		(112	)		(5,354	)		(6,873	)

Cash flows from financing activities:
Net commercial paper (repayments) borrowings		(1,432	)		426			1
Debt repayments		(350	)		(178	)		(1,031	)
Proceeds from borrowings of long-term debt, net of issuance costs		—			1,187			—
Credit facility repayments		—			—			(3,191	)
Credit facility borrowings		—			—			1,741
Redemption of preferred stock		—			—			(150	)
Proceeds from stock option exercises		111			42			116
Repurchases of common stock		(1,168	)		—			(665	)
Dividends paid on common and preferred stock		(281	)		(284	)		(289	)
Excess tax benefits related to share-based compensation		16			8			60

Net cash from financing activities		(3,104	)		1,201			(3,408	)

Effect of exchange rate changes on cash		17			43			(116	)

Net increase (decrease) in cash and cash equivalents		2,279			627			(989	)
Cash and cash equivalents at beginning of period (including cash related to assets held for sale)		1,011			384			1,373

Cash and cash equivalents at end of period (including cash related to assets held for sale)	$	3,290		$	1,011		$	384

See accompanying notes to consolidated financial statements.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1.	Summary of Significant Accounting Policies

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

Nature of Business and Principles of Consolidation

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


	•	the Mid-Continent area of the central and southern United States, principally in north and east Texas, as well as Oklahoma;

	•	the Permian Basin within Texas and New Mexico;

	•	the Rocky Mountains area of the United States stretching from the Canadian border into northern New Mexico;

	•	the onshore areas of the Gulf Coast, principally in south Texas and south Louisiana; and

	•	the provinces of Alberta, British Columbia and Saskatchewan in Canada.

In November 2009, Devon announced plans to strategically reposition itself as a North American onshore exploration and development company. During 2010, Devon divested its properties in the Gulf of Mexico, Azerbaijan, China and other International regions. Additionally, Devon has entered into agreements to sell its remaining offshore assets in Brazil and Angola. These activities are more fully described in Note 5.

Devon also has marketing and midstream operations that perform various activities to support the oil and gas operations of Devon and unrelated third parties. Such activities include marketing gas, crude oil and NGLs, as well as constructing and operating pipelines, storage and treating facilities and natural gas processing plants.

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

Use of Estimates in the Preparation of Financial Statements


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

	•	the carrying value of oil and gas properties;

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

	•	derivative financial instruments;

	•	income taxes;

	•	asset retirement obligations;

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	•	obligations related to employee pension and postretirement benefits; and

	•	legal and environmental risks and exposures.

Derivative Financial Instruments

Devon is exposed to certain risks relating to its ongoing business operations, including risks related to commodity prices, interest rates and Canadian to U.S. dollar exchange rates. As discussed more fully below, Devon uses derivative instruments primarily to manage commodity price risk and interest rate risk. Devon does not hold or issue derivative financial instruments for speculative trading purposes. Besides these derivative instruments, Devon also had an embedded option derivative related to the fair value of its debentures exchangeable into shares of Chevron common stock. Devon ceased to have this option when the exchangeable debentures matured on August 15, 2008.

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

Devon periodically enters into interest rate swaps to manage its exposure to interest rate volatility. Devon’s interest rate swaps include contracts in which Devon receives a fixed rate and pays a variable rate on a total notional amount. Devon also has forward starting swaps. Under the terms of the forward starting swaps, Devon will net settle these contracts in September 2011 or sooner should Devon elect. The net settlement amount will be based upon Devon paying a fixed rate and receiving a floating rate that is based upon the three-month LIBOR. The difference between the fixed and floating rate will be applied to the notional amount for the 30-year period from September 30, 2011 to September 30, 2041.

All derivative financial instruments are recognized at their current fair value as either assets or liabilities in the balance sheet. Changes in the fair value of these derivative financial instruments are recorded in the statement of operations unless specific hedge accounting criteria are met. For derivative financial instruments held during the three-year period ended December 31, 2010, Devon chose not to meet the necessary criteria to qualify its derivative financial instruments for hedge accounting treatment. Cash settlements with counterparties to Devon’s derivative financial instruments are also recorded in the statement of operations.

By using derivative financial instruments to hedge exposures to changes in commodity prices and interest rates, Devon exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. To mitigate this risk, the hedging instruments are placed with a number of counterparties whom Devon believes are minimal credit risks. It is Devon’s policy to enter into derivative contracts only with investment grade rated counterparties deemed by management to be competent and competitive market makers. Additionally, Devon’s derivative contracts generally require cash collateral to be posted if either its or the counterparty’s credit rating falls below investment grade. The mark-to-market exposure threshold, above which collateral must be posted, decreases as the debt rating falls further below investment grade. Such thresholds generally range from zero to $50 million for the majority of

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

our contracts. As of December 31, 2010, the credit ratings of all Devon’s counterparties were investment grade.

Market risk is the change in the value of a derivative financial instrument that results from a change in commodity prices, interest rates or other relevant underlyings. The market risks associated with commodity price and interest rate contracts are managed by establishing and monitoring parameters that limit the types and degree of market risk that may be undertaken. The oil and gas reference prices upon which the commodity instruments are based reflect various market indices that have a high degree of historical correlation with actual prices received by Devon.

See Note 3 for the amounts included in Devon’s accompanying consolidated balance sheets and consolidated statements of operations associated with its derivative financial instruments.

Fair Value Measurements

Certain of Devon’s assets and liabilities are measured at fair value at each reporting date. Fair value represents the price that would be received to sell the asset or paid to transfer the liability in an orderly transaction between market participants. This price is commonly referred to as the “exit price”.

Fair value measurements are classified according to a hierarchy that prioritizes the inputs underlying the valuation techniques. This hierarchy consists of three broad levels. Level 1 inputs on the hierarchy consist of unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. Level 2 measurements are based on inputs other than quoted prices that are generally observable for the asset or liability. Common examples of Level 2 inputs include quoted prices for similar assets and liabilities in active markets or quoted prices for identical assets and liabilities in markets not considered to be active. Level 3 measurements have the lowest priority and are based upon inputs that are not observable from objective sources. The most common Level 3 fair value measurement is an internally developed cash flow model. Devon uses appropriate valuation techniques based on the available inputs to measure the fair values of its assets and liabilities. When available, Devon measures fair value using Level 1 inputs because they generally provide the most reliable evidence of fair value.

See Note 11 for fair value measurements included in Devon’s accompanying consolidated balance sheets.

Discontinued Operations

As a result of the November 2009 plan to divest Devon’s offshore assets, all amounts related to Devon’s International operations are classified as discontinued operations. The Gulf of Mexico properties that were divested in 2010 do not qualify as discontinued operations under accounting rules. As such, amounts in these notes and the accompanying consolidated financial statements that pertain to continuing operations include amounts related to Devon’s offshore Gulf of Mexico operations. See Note 5 for additional details of the offshore divestiture program.

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

Property and Equipment

Devon follows the full cost method of accounting for its oil and gas properties. Accordingly, all costs incidental to the acquisition, exploration and development of oil and gas properties, including costs of undeveloped leasehold, dry holes and leasehold equipment, are capitalized. Internal costs incurred that are

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

directly identified with acquisition, exploration and development activities undertaken by Devon for its own account, and that are not related to production, general corporate overhead or similar activities, are also capitalized. Interest costs incurred and attributable to unproved oil and gas properties under current evaluation and major development projects of oil and gas properties are also capitalized. All costs related to production activities, including workover costs incurred solely to maintain or increase levels of production from an existing completion interval, are charged to expense as incurred.

Under the full cost method of accounting, the net book value of oil and gas properties, less related deferred income taxes, may not exceed a calculated “ceiling.” The ceiling limitation is the estimated after-tax future net revenues, discounted at 10% per annum, from proved oil, gas and NGL reserves plus the cost of properties not subject to amortization. Estimated future net revenues exclude future cash outflows associated with settling asset retirement obligations included in the net book value of oil and gas properties. Such limitations are imposed separately on a country-by-country basis and are tested quarterly.

Future net revenues are calculated using prices that represent the average of the first-day-of-the-month price for the 12-month period prior to the end of the period. Prior to December 31, 2009, prices and costs used to calculate future net revenues were those as of the end of the appropriate quarterly period. Prices are held constant indefinitely and are not changed except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including derivative contracts in place that qualify for hedge accounting treatment. None of Devon’s derivative contracts held during the three-year period ended December 31, 2010 qualified for hedge accounting treatment.

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

Capitalized costs are depleted by an equivalent unit-of-production method, converting gas to oil at the ratio of six thousand cubic feet of gas to one barrel of oil. Depletion is calculated using the capitalized costs, including estimated asset retirement costs, plus the estimated future expenditures (based on current costs) to be incurred in developing proved reserves, net of estimated salvage values.

Costs associated with unproved properties are excluded from the depletion calculation until it is determined whether or not proved reserves can be assigned to such properties. Devon assesses its unproved properties for impairment quarterly. Significant unproved properties are assessed individually. Costs of insignificant unproved properties are transferred into the depletion calculation over holding periods ranging from three to five years.

No gain or loss is recognized upon disposal of oil and gas properties unless such disposal significantly alters the relationship between capitalized costs and proved reserves in a particular country.

Depreciation of midstream pipelines are provided on a unit-of-production basis. Depreciation and amortization of other property and equipment, including corporate and other midstream assets and leasehold improvements, are provided using the straight-line method based on estimated useful lives ranging from three to 39 years. Interest costs incurred and attributable to major midstream and corporate construction projects are also capitalized.

Devon recognizes liabilities for retirement obligations associated with tangible long-lived assets, such as producing well sites, offshore production platforms, and midstream pipelines and processing plants when there is a legal obligation associated with the retirement of such assets and the amount can be reasonably estimated. The initial measurement of an asset retirement obligation is recorded as a liability at its fair value, with an offsetting asset retirement cost recorded as an increase to the associated property and equipment on the consolidated balance sheet. If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement cost. The asset retirement cost is

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

depreciated using a systematic and rational method similar to that used for the associated property and equipment.

Investments

Devon reports its investments and other marketable securities at fair value, except for debt securities in which management has the ability and intent to hold until maturity.

Devon’s primary investments consist of auction rate securities that totaled $94 million and $115 million at December 31, 2010 and 2009, respectively. These securities are rated AAA — the highest rating — by one or more rating agencies and are collateralized by student loans that are substantially guaranteed by the United States government. Although Devon’s auction rate securities generally have contractual maturities of more than 20 years, the underlying interest rates on such securities are scheduled to reset every seven to 28 days. Therefore, these auction rate securities were generally priced and subsequently traded as short-term investments because of the interest rate reset feature.

Since February 8, 2008, Devon has experienced difficulty selling its securities due to the failure of the auction mechanism, which provided liquidity to these securities. An auction failure means that the parties wishing to sell securities could not do so. The securities for which auctions have failed will continue to accrue interest and be auctioned every seven to 28 days until the auction succeeds, the issuer calls the securities or the securities mature.

From February 2008, when auctions began failing, to December 31, 2010, issuers have redeemed $58 million of Devon’s auction rate securities holdings at par. However, based on continued auction failures and the current market for Devon’s auction rate securities, Devon has classified its auction rate securities as long-term investments as of December 31, 2010. These securities are included in other long-term assets in the accompanying consolidated balance sheet. Devon has the ability to hold the securities until maturity. At this time, Devon does not believe the values of its long-term securities are impaired.

Goodwill

Goodwill represents the excess of the purchase price of business combinations over the fair value of the net assets acquired and is tested for impairment at least annually. The impairment test requires allocating goodwill and all other assets and liabilities to assigned reporting units. The fair value of each reporting unit is estimated and compared to the net book value of the reporting unit. If the estimated fair value of the reporting unit is less than the net book value, including goodwill, then the goodwill is written down to the implied fair value of the goodwill through a charge to expense. Because quoted market prices are not available for Devon’s reporting units, the fair values of the reporting units are estimated based upon several valuation analyses, including comparable companies, comparable transactions and premiums paid.

Devon performed annual impairment tests of goodwill in the fourth quarters of 2010, 2009 and 2008. Based on these assessments, no impairment of goodwill was required.

The table below provides a summary of Devon’s goodwill, by assigned reporting unit, as of December 31, 2010 and 2009. The increase in Devon’s continuing operations goodwill from 2009 to 2010 is due to changes in the exchange rate between the U.S. dollar and the Canadian dollar. Devon removed all its International goodwill in conjunction with the Azerbaijan divestiture that closed in 2010. Such goodwill was presented in long-term assets held for sale in the accompanying December 31, 2009 consolidated balance sheet.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	December 31,
	2010		2009
	(In millions)

United States	$	3,046	$	3,046
Canada		3,034		2,884

Total (continuing operations)	$	6,080	$	5,930

International (assets held for sale)	$	—	$	68

Foreign Currency Translation Adjustments

The U.S. dollar is the functional currency for Devon’s consolidated operations except its Canadian subsidiaries, which use the Canadian dollar as the functional currency. Therefore, the assets and liabilities of Devon’s Canadian subsidiaries are translated into U.S. dollars based on the current exchange rate in effect at the balance sheet dates. Canadian income and expenses are translated at average rates for the periods presented. Translation adjustments have no effect on net income and are included in accumulated other comprehensive earnings in stockholders’ equity. The following table presents the balances of Devon’s cumulative translation adjustments included in accumulated other comprehensive earnings (in millions).


December 31, 2007	$	2,566
December 31, 2008	$	685
December 31, 2009	$	1,616
December 31, 2010	$	1,993

Commitments and Contingencies

Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Liabilities for environmental remediation or restoration claims are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. Expenditures related to such environmental matters are expensed or capitalized in accordance with Devon’s accounting policy for property and equipment. Reference is made to Note 10 for a discussion of amounts recorded for these liabilities.

Revenue Recognition and Gas Balancing

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

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

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Marketing and midstream revenues are recorded at the time products are sold or services are provided to third parties at a fixed or determinable price, delivery or performance has occurred, title has transferred and collectability of the revenue is probable. Revenues and expenses attributable to oil, gas and NGL purchases, transportation and processing contracts are reported on a gross basis when Devon takes title to the products and has risks and rewards of ownership.

During 2010, 2009 and 2008, no purchaser accounted for more than 10% of Devon’s revenues from continuing operations.

General and Administrative Expenses

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

Share Based Compensation

Devon grants stock options, restricted stock awards and other types of share-based awards to members of its Board of Directors and selected employees. All such awards are measured at fair value on the date of grant and are recognized as a component of general and administrative expenses in the accompanying statements of operations over the applicable requisite service periods. As a result of Devon’s strategic repositioning announced in 2009, certain share based awards were accelerated and recognized as a component of restructuring expense in the accompanying 2010 and 2009 statements of operations.

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

Income Taxes

Devon is subject to current income taxes assessed by the federal and various state jurisdictions in the United States and by other foreign jurisdictions. In addition, Devon accounts for deferred income taxes related to these jurisdictions using the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases. Deferred tax assets are also recognized for the future tax benefits attributable to the expected utilization of existing tax net operating loss carryforwards and other types of carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

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

Devon recognizes the financial statement effects of tax positions when it is more likely than not, based on the technical merits, that the position will be sustained upon examination by a taxing authority. Recognized tax positions are initially and subsequently measured as the largest amount of tax benefit that is more likely than not of being realized upon ultimate settlement with a taxing authority. Liabilities for unrecognized tax benefits related to such tax positions are included in other long-term liabilities unless the tax position is expected to be settled within the upcoming year, in which case the liabilities are included in other current liabilities. Interest and penalties related to unrecognized tax benefits are included in current income tax

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

expense. Additional information regarding Devon’s unrecognized tax benefits, including changes in such amounts during 2010 and 2009, is provided in Note 17.

Net Earnings (Loss) Per Common Share

Devon’s basic earnings per share amounts have been computed based on the average number of shares of common stock outstanding for the period. Basic earnings per share includes the effect of participating securities, which primarily consist of Devon’s outstanding restricted stock awards. Diluted earnings per share is calculated using the treasury stock method to reflect the potential dilution that could occur if Devon’s dilutive outstanding stock options were exercised.

Cash and Cash Equivalents

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


2.	Accounts Receivable

The components of accounts receivable include the following:


	December 31,
	2010			2009
	(In millions)

Oil, gas and NGL sales	$	786		$	752
Joint interest billings		182			151
Marketing and midstream revenues		163			188
Production tax credits		46			110
Other		35			19

Gross accounts receivable		1,212			1,220
Allowance for doubtful accounts		(10	)		(12	)

Net accounts receivable	$	1,202		$	1,208

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


3.	Derivative Financial Instruments

The following table presents the derivative fair values included in the accompanying consolidated balance sheets. Devon has elected not to designate any of its derivative instruments for hedge accounting treatment.


		December 31,
	Balance Sheet Caption	2010		2009
		(In millions)

Asset derivatives:
Commodity derivatives	Other current assets	$	248	$	172
Commodity derivatives	Other long-term assets		1		—
Interest rate derivatives	Other current assets		100		39
Interest rate derivatives	Other long-term assets		40		131

Total asset derivatives		$	389	$	342

Liability derivatives:
Commodity derivatives	Other current liabilities	$	50	$	38
Commodity derivatives	Other long-term liabilities		142		—

Total liability derivatives		$	192	$	38

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


	Statement of Operations Caption	2010			2009			2008
		(In millions)

Cash settlements:
Commodity derivatives	Oil, gas and NGL derivatives	$	888		$	505		$	(397	)
Interest rate derivatives	Interest-rate and other financial instruments		44			40			1

Total cash settlements			932			545			(396	)

Unrealized gains (losses):
Commodity derivatives	Oil, gas and NGL derivatives		(77	)		(121	)		243
Interest rate derivatives	Interest-rate and other financial instruments		(30	)		66			104
Embedded option	Interest-rate and other financial instruments		—			—			109

Total unrealized gains (losses)			(107	)		(55	)		456

Net gain recognized on statement of operations		$	825		$	490		$	60

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


4.	Other Current Assets

The components of other current assets include the following:


	December 31,
	2010		2009
	(In millions)

Derivative financial instruments	$	348	$	211
Income tax receivable		270		53
Short-term investments		145		—
Inventories		120		182
Other		41		35

Other current assets	$	924	$	481


5.	Property and Equipment

Property and equipment consists of the following:


	December 31,
	2010			2009
	(In millions)

Oil and gas properties:
Subject to amortization	$	56,012		$	52,352
Not subject to amortization		3,434			4,078

Total		59,446			56,430
Accumulated depreciation, depletion and amortization		(42,676	)		(40,312	)

Net oil and gas properties		16,770			16,118

Other property and equipment		4,429			4,045
Accumulated depreciation and amortization		(1,547	)		(1,396	)

Net other property and equipment		2,882			2,649

Property and equipment, net	$	19,652		$	18,767

The following is a summary of Devon’s oil and gas properties not subject to amortization as of December 31, 2010.


	Costs Incurred In
							Prior to
	2010		2009		2008		2008		Total
	(In millions)

Acquisition costs	$	1,188	$	121	$	1,049	$	671	$	3,029
Exploration costs		130		40		39		5		214
Development costs		159		1		9		—		169
Capitalized interest		22		—		—		—		22

Total oil and gas properties not subject to amortization	$	1,499	$	162	$	1,097	$	676	$	3,434

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Offshore Divestitures

In November 2009, Devon announced plans to reposition itself strategically as a North America onshore exploration and production company. As part of this strategic repositioning, Devon is bringing forward the value of its offshore assets by divesting them.

Closed Transactions

The following table presents Devon’s offshore divestiture transactions that closed in 2010. Gross proceeds represent contract prices based upon a January 1, 2010 effective date for the Gulf of Mexico and Azerbaijan divestitures, a May 1, 2010 effective date for the China — Panyu divestiture and a September 1, 2010 effective date for the China-Exploration divestiture. After-tax proceeds represent gross proceeds adjusted for customary purchase price adjustments, selling costs and income taxes. The purchase price adjustments consist primarily of net cash flow subsequent to the effective date of the divestitures. Proved reserves in the following table are based upon estimated proved reserves as of the divestiture dates.


	Gross		After-Tax		Proved
	Proceeds		Proceeds		Reserves
	(In millions)				(MMBoe)
					(Unaudited)

Gulf of Mexico (continuing operations)	$	4,145	$	3,222		91
Azerbaijan (discontinued operations)		2,000		1,925		56
China — Panyu (discontinued operations)		515		405		13
China — Exploration (discontinued operations)		77		59		—
Other (discontinued operations)		38		38		20

Total	$	6,775	$	5,649		180

Proceeds from these divestitures are being used to retire debt and repurchase Devon common shares. Additionally, Devon is using divestiture proceeds to fund North America Onshore exploration and development opportunities, including a joint-venture investment in the Pike oil sands discussed below.

Under full cost accounting rules, sales or other dispositions of oil and gas properties are generally accounted for as adjustments to capitalized costs, with no recognition of gain or loss. However, if not recognizing a gain or loss on the disposition would otherwise significantly alter the relationship between a cost center’s capitalized costs and proved reserves, then a gain or loss must be recognized.

The Gulf of Mexico divestitures presented above did not significantly alter such relationship for Devon’s United States cost center. Therefore, Devon did not recognize a gain in connection with the Gulf of Mexico divestitures. The Azerbaijan divestiture included all of Devon’s properties in its Azerbaijan cost center. As a result, Devon recognized a $1,543 million ($1,524 million after-tax) gain during 2010 in connection with the Azerbaijan divestiture. Panyu was Devon’s only producing property in its China cost center. As a result, Devon recognized a $308 million ($235 million after-tax) gain in connection with the Panyu divestiture in 2010. These gains are included in “earnings from discontinued operations” in the accompanying 2010 consolidated statement of operations.

Pending Transactions

Devon has entered into agreements to sell its remaining offshore assets in Brazil and Angola and is waiting for the respective governments to approve the divestitures. The Brazil divestiture is valued at $3.2 billion, and Devon expects to record a gain upon the close of this transaction. For the Angola divestiture, Devon will receive $70 million at closing, and has the potential to receive future consideration that is contingent upon the buyer achieving certain milestones.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Deepwater Drilling Rigs

As part of its offshore operations, Devon was leasing three deepwater drilling rigs. The Seadrill West Sirius and Ocean Endeavor deepwater drilling rigs were used in Devon’s Gulf of Mexico operations. The Transocean Deepwater Discovery is currently being used in Devon’s operations in Brazil.

In conjunction with the deepwater Gulf of Mexico divestiture that closed in the second quarter of 2010, the buyer assumed Devon’s lease and remaining commitments for the Seadrill West Sirius rig. Subsequent to closing all its Gulf of Mexico divestitures, Devon agreed to pay $31 million to the owner of the Ocean Endeavor rig to terminate the lease. The $31 million lease termination cost is included in oil and gas property and equipment in the accompanying December 31, 2010, consolidated balance sheet. The buyer of Devon’s assets in Brazil will assume Devon’s lease and remaining commitments for the Transocean Deepwater Discovery rig when the divestiture transaction closes.

Oil Sands Joint Venture

In conjunction with certain offshore divestitures in the second quarter of 2010, Devon formed a heavy oil joint venture to operate and develop the Pike oil sands leases in Alberta, Canada. As a result, Devon acquired a 50 percent interest in the Pike oil sands leases for $500 million. Devon will also fund $155 million of Canadian dollar capital costs on behalf of its joint-venture partner in the form of a non-interest bearing promissory note. The majority of the capital costs are expected to be paid during 2011 and 2012. See Note 6 for more information regarding the promissory note.

Reductions of Carrying Value

In the first quarter of 2009 and the fourth quarter of 2008, Devon reduced the carrying values of its oil and gas properties due to full cost ceiling limitations. These reductions are discussed in Note 15.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


6.	Debt and Related Expenses

A summary of Devon’s debt is as follows:


	December 31,
	2010		2009
	(In millions)

Commercial paper	$	—	$	1,432
Other debentures and notes:
7.25% retired on June 25, 2010		—		350
6.875% due September 30, 2011		1,750		1,750
5.625% due January 15, 2014		500		500
Non-interest bearing promissory note due June 29, 2014		144		—
8.25% due July 1, 2018		125		125
6.30% due January 15, 2019		700		700
7.50% due September 15, 2027		150		150
7.875% due September 30, 2031		1,250		1,250
7.95% due April 15, 2032		1,000		1,000
Other		9		10
Net premium on other debentures and notes		2		12

Total debt		5,630		7,279
Less amount classified as short-term debt		1,811		1,432

Long-term debt	$	3,819	$	5,847

Debt maturities as of December 31, 2010, excluding premiums and discounts, are as follows (in millions):


2011	$	1,812
2012		9
2013		—
2014		582
2015		—
2016 and thereafter		3,225

Total	$	5,628

Credit Lines

Devon has a $2,650 million syndicated, unsecured revolving line of credit (the “Senior Credit Facility”). The maturity date for $2,187 million of the Senior Credit Facility is April 7, 2013. The maturity date for the remaining $463 million is April 7, 2012. All amounts outstanding will be due and payable on the respective maturity dates unless the maturity is extended. Prior to each April 7 anniversary date, Devon has the option to extend the maturity of the Senior Credit Facility for one year, subject to the approval of the lenders. The Senior Credit Facility includes a revolving Canadian subfacility in a maximum amount of U.S. $500 million.

Amounts borrowed under the Senior Credit Facility may, at the election of Devon, bear interest at various fixed rate options for periods of up to twelve months. Such rates are generally less than the prime rate. However, Devon may elect to borrow at the prime rate. The Senior Credit Facility currently provides for an annual facility fee of $1.9 million that is payable quarterly in arrears. As of December 31, 2010, there were no borrowings under the Senior Credit Facility.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The Senior Credit Facility contains only one material financial covenant. This covenant requires Devon’s ratio of total funded debt to total capitalization to be less than 65%. The credit agreement contains definitions of total funded debt and total capitalization that include adjustments to the respective amounts reported in the consolidated financial statements. Also, total capitalization is adjusted to add back noncash financial writedowns such as full cost ceiling impairments or goodwill impairments. As of December 31, 2010, Devon was in compliance with this covenant. Devon’s debt-to-capitalization ratio at December 31, 2010, as calculated pursuant to the terms of the agreement, was 15.1%.

The following schedule summarizes the capacity of Devon’s Senior Credit Facility by maturity date, as well as its available capacity as of December 31, 2010 (in millions).


April 7, 2012 maturity	$	463
April 7, 2013 maturity		2,187

Total Senior Credit Facility		2,650
Less:
Outstanding Senior Credit Facility borrowings		—
Outstanding commercial paper borrowings		—
Outstanding letters of credit		38

Total available capacity	$	2,612

Commercial Paper

Devon also has access to approximately $2,200 million of short-term credit under its commercial paper program. Any borrowings under the commercial paper program reduce available capacity under the Senior Credit Facility on a dollar-for-dollar basis. Commercial paper debt generally has a maturity of between one and 90 days, although it can have a maturity of up to 365 days, and bears interest at rates agreed to at the time of the borrowing. The interest rate is based on a standard index such as the Federal Funds Rate, LIBOR, or the money market rate as found on the commercial paper market.

During the first half of 2010, Devon repaid $1,432 million of commercial paper borrowings primarily with proceeds received from its Gulf of Mexico property divestitures. At December 31, 2010, Devon had no outstanding commercial paper borrowings. The average borrowing rate for Devon’s $1,432 million of commercial paper borrowings at December 31, 2009 was 0.29%.

$350 Million 7.25% Senior Notes Due October 1, 2011

On June 25, 2010, Devon redeemed $350 million of 7.25% senior notes prior to their scheduled maturity of October 1, 2011, primarily with proceeds received from its Gulf of Mexico divestitures. The notes were redeemed for $384 million, which represented 100 percent of the principal amount, a make-whole premium of $28 million and $6 million of accrued and unpaid interest. On the date of redemption, these notes also had an unamortized premium of $9 million. The $28 million make-whole premium and $9 million amortization of the remaining premium are included in interest expense in the accompanying 2010 consolidated statements of operations.

Non-Interest Bearing Promissory Note Due June 29, 2014

On June 29, 2010, Devon issued a four-year $155 million Canadian dollar non-interest bearing promissory note in connection with the formation of the Pike oil sands joint venture described in Note 5. The present value of the note was $139 million on the issue date based upon an effective interest rate of 3.125%. At

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

December 31, 2010, the note had a carrying value of $144 million, of which $62 million is presented as short-term debt and the remainder is presented as long-term debt in the accompanying consolidated balance sheet.

Other Debentures and Notes

Following are descriptions of the various other debentures and notes outstanding at December 31, 2010, as listed in the table presented at the beginning of this note.

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

On October 3, 2001, Devon, through Devon Financing Corporation, U.L.C. (“Devon Financing”), a wholly-owned finance subsidiary, sold these notes and debentures, which are unsecured and unsubordinated obligations of Devon Financing. Devon has fully and unconditionally guaranteed on an unsecured and unsubordinated basis the obligations of Devon Financing under the debt securities. The proceeds from the issuance of these debt securities were used to fund a portion of the acquisition of Anderson Exploration.

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

On January 9, 2009, Devon sold these notes, which are unsecured and unsubordinated obligations of Devon. The net proceeds from issuance of this debt were used primarily to repay Devon’s outstanding commercial paper as of December 31, 2008.

Ocean Debt

As a result of the April 25, 2003 merger with Ocean Energy, Inc., Devon assumed certain debt instruments that remain outstanding at December 31, 2010. The table below summarizes the debt assumed, the fair value of the debt at April 25, 2003, and the effective interest rate of the debt assumed after determining the fair values of the respective notes using April 25, 2003, market interest rates. The premiums resulting from fair values exceeding face values are being amortized using the effective interest method. All of the notes are general unsecured obligations of Devon.


	Fair Value of		Effective Rate of
Debt Assumed	Debt Assumed		Debt Assumed
	(In millions)

8.250% due July 2018 (principal of $125 million)	$	147		5.5	%
7.500% due September 2027(principal of $150 million)	$	169		6.5	%

7.95% Notes due April 15, 2032

On March 25, 2002, Devon sold these notes, which are unsecured and unsubordinated obligations of Devon. The net proceeds received, after discounts and issuance costs, were $986 million and were used to retire other indebtedness.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Interest Expense

The following schedule includes the components of interest expense.


	Year Ended December 31,
	2010			2009			2008
				(In millions)

Interest based on debt outstanding	$	408		$	437		$	426
Capitalized interest		(76	)		(94	)		(111	)
Early retirement of debt		19			—			—
Other		12			6			14

Total	$	363		$	349		$	329


7.	Asset Retirement Obligations

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


	Year Ended
	December 31,
	2010			2009
	(In millions)

Asset retirement obligations as of beginning of year	$	1,513		$	1,387
Liabilities incurred		55			56
Liabilities settled		(129	)		(123	)
Revision of estimated obligation		194			33
Liabilities assumed by others		(269	)		(30	)
Accretion expense on discounted obligation		92			91
Foreign currency translation adjustment		41			99

Asset retirement obligations as of end of year		1,497			1,513
Less current portion		74			95

Asset retirement obligations, long-term	$	1,423		$	1,418

During 2010 and 2009, Devon recognized revisions to its asset retirement obligations totaling $194 million and $33 million, respectively. The primary factors causing the 2010 and 2009 increases were an overall increase in abandonment cost estimates and a decrease in the discount rate used to present value the obligations.

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


8.	Retirement Plans

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

The Supplemental Plans provide retirement benefits for certain employees whose benefits under the Qualified Plans are limited by income tax regulations. The Supplemental Plans’ benefits are based on the employees’ years of service and compensation. For certain Supplemental Plans, Devon has established trusts to

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

fund these plans’ benefit obligations. The total value of these trusts was $36 million and $39 million at December 31, 2010 and 2009, respectively, and is included in other long-term assets in the accompanying consolidated balance sheets. For the remaining Supplemental Plans for which trusts have not been established, benefits are funded from Devon’s available cash and cash equivalents.

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

Benefit Obligations and Funded Status

The following table presents the status of Devon’s pension and other postretirement benefit plans. The benefit obligation for pension plans represents the projected benefit obligation, while the benefit obligation for the postretirement benefit plans represents the accumulated benefit obligation. The accumulated benefit obligation differs from the projected benefit obligation in that the former includes no assumption about future compensation levels. The accumulated benefit obligation for pension plans at December 31, 2010 and 2009 was $1,010 million and $873 million, respectively. Devon’s benefit obligations and plan assets are measured each year as of December 31.


							Other
	Pension						Postretirement
	Benefits						Benefits
	2010			2009			2010			2009
	(In millions)

Change in benefit obligation:
Benefit obligation at beginning of year	$	980		$	931		$	64		$	56
Service cost		33			43			1			1
Interest cost		58			58			3			3
Actuarial loss (gain)		82			4			1			7
Curtailment (gain) loss		—			(26	)		—			1
Plan amendments		5			—			(22	)		—
Foreign exchange rate changes		2			5			—			—
Participant contributions		—			—			2			2
Benefits paid		(36	)		(35	)		(6	)		(6	)

Benefit obligation at end of year		1,124			980			43			64

Change in plan assets:
Fair value of plan assets at beginning of year		532			430			—			—
Actual return on plan assets		69			80			—			—
Employer contributions		66			55			4			4
Participant contributions		—			—			2			2
Benefits paid		(36	)		(35	)		(6	)		(6	)
Foreign exchange rate changes		1			2			—			—

Fair value of plan assets at end of year		632			532			—			—

Funded status at end of year	$	(492	)	$	(448	)	$	(43	)	$	(64	)

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


							Other
	Pension						Postretirement
	Benefits						Benefits
	2010			2009			2010			2009
	(In millions)

Amounts recognized in balance sheet:
Noncurrent assets	$	2		$	2		$	—		$	—
Current liabilities		(9	)		(8	)		(4	)		(5	)
Noncurrent liabilities		(485	)		(442	)		(39	)		(59	)

Net amount	$	(492	)	$	(448	)	$	(43	)	$	(64	)

Amounts recognized in accumulated other comprehensive earnings:
Net actuarial loss (gain)	$	357		$	334		$	(5	)	$	(6	)
Prior service cost (credit)		21			20			(12	)		11

Total	$	378		$	354		$	(17	)	$	5

The plan assets for pension benefits in the table above exclude the assets held in trusts for the Supplemental Plans. However, employer contributions for pension benefits in the table above include $8 million and $9 million for 2010 and 2009, respectively, which were transferred from the trusts established for the Supplemental Plans.

Certain of Devon’s pension plans have a projected benefit obligation and accumulated benefit obligation in excess of plan assets at December 31, 2010 and 2009 as presented in the table below.


	December 31,
	2010		2009
	(In millions)

Projected benefit obligation	$	1,110	$	967
Accumulated benefit obligation	$	996	$	860
Fair value of plan assets	$	616	$	517

The plan assets included in the above table exclude the Supplemental Plan trusts, which had a total value of $36 million and $39 million at December 31, 2010 and 2009, respectively.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Net Periodic Benefit Cost and Other Comprehensive Earnings

The following table presents the components of net periodic benefit cost and other comprehensive earnings for Devon’s pension and other postretirement benefit plans.


										Other
	Pension Benefits									Postretirement Benefits
	2010			2009			2008			2010			2009			2008
	(In millions)

Net periodic benefit cost:
Service cost	$	33		$	43		$	41		$	1		$	1		$	1
Interest cost		58			58			54			3			3			4
Expected return on plan assets		(37	)		(35	)		(50	)		—			—			—
Curtailment and settlement expense		—			5			—			—			1			—
Recognition of net actuarial loss (gain)		28			45			14			—			(1	)		—
Recognition of prior service cost		3			3			2			1			2			2

Total net periodic benefit cost		85			119			61			5			6			7
Other comprehensive earnings:
Actuarial (gain) loss arising in current year		49			(66	)		245			1			7			(15	)
Prior service cost (credit) arising in current year		5			—			9			(22	)		—			—
Recognition of net actuarial (loss) gain in net periodic benefit cost		(27	)		(45	)		(14	)		—			1			—
Recognition of prior service cost, including curtailment, in net periodic benefit cost		(3	)		(8	)		(2	)		(1	)		(2	)		(2	)

Total other comprehensive earnings (loss)		24			(119	)		238			(22	)		6			(17	)

Total recognized	$	109		$	—		$	299		$	(17	)	$	12		$	(10	)

The following table presents the estimated net actuarial loss and prior service cost for the pension and other postretirement plans that will be amortized from accumulated other comprehensive earnings into net periodic benefit cost during 2011.


			Other
	Pension		Postretirement
	Benefits		Benefits
	(In millions)

Net actuarial loss	$	32	$	—
Prior service cost (credit)		3		(2	)

Total	$	35	$	(2	)

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Assumptions

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


										Other
	Pension Benefits									Postretirement Benefits
	2010			2009			2008			2010			2009			2008

Assumptions to determine benefit obligations:
Discount rate		5.50	%		6.00	%		6.00	%		4.90	%		5.70	%		6.00	%
Rate of compensation increase		6.94	%		6.95	%		7.00	%		N/A			N/A			N/A
Assumptions to determine net periodic benefit cost:
Discount rate		6.00	%		6.00	%		6.18	%		5.70	%		6.00	%		6.00	%
Expected return on plan assets		6.94	%		7.18	%		8.40	%		N/A			N/A			N/A
Rate of compensation increase		6.94	%		6.95	%		7.00	%		N/A			N/A			N/A

Discount rate — Future pension and postretirement obligations are discounted at the end of each year based on the rate at which obligations could be effectively settled, considering the timing of estimated future cash flows related to the plans. This rate is based on high-quality bond yields, after allowing for call and default risk. High quality corporate bond yield indices are considered when selecting the discount rate.

Rate of compensation increase — For measurement of the 2010 benefit obligation for the pension plans, the 6.94% compensation increase in the table above represents the assumed increase through 2011. The rate was assumed to decrease to 5% in the year 2012 and remain at that level thereafter.

Expected return on plan assets — The expected rate of return on plan assets was determined by evaluating input from external consultants and economists as well as long-term inflation assumptions. Devon expects the long-term asset allocation to approximate the targeted allocation. Therefore, the expected long-term rate of return on plan assets is based on the target allocation of investment types in such assets. See plan assets discussion below for more information on Devon’s target allocations.

Other assumptions — For measurement of the 2010 benefit obligation for the other postretirement medical plans, an 8.3% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2011. The rate was assumed to decrease annually to an ultimate rate of 5% in the year 2029 and remain at that level thereafter. Assumed health care cost-trend rates affect the amounts reported for retiree health care costs. A one-percentage-point change in the assumed health care cost-trend rates would have the following effects on the December 31, 2010 other postretirement benefits obligation and the 2011 service and interest cost components of net periodic benefit cost.


	One		One
	Percent		Percent
	Increase		Decrease
	(In millions)

Effect on benefit obligation	$	2	$	(2	)
Effect on service and interest costs	$	—	$	—

Pension Plan Assets

Devon’s overall investment objective for its pension plans’ assets is to achieve long-term growth of invested capital and income to ensure benefit payments can be funded when required. To assist in achieving this objective, Devon has established certain investment strategies, including target allocation percentages and permitted and prohibited investments, designed to mitigate risks inherent with investing.

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The vast majority of Devon’s plan assets are invested in diversified asset types to generate long-term growth and income. The remaining plan assets, generally less than 5%, are invested in assets that can be used for near-term benefit payments. Derivatives or other speculative investments considered high risk are generally prohibited.

At the end of 2010 and 2009, Devon’s target allocations for plan assets were 47.5% for equity securities, 40% for fixed-income securities and 12.5% for other investment types. The fair values of Devon’s pension assets at December 31, 2010 and 2009 are presented by asset class in the following tables.


	As of December 31, 2010
						Fair Value Measurements Using:
	Actual					Level 1		Level 2		Level 3
	Allocation			Total		Inputs		Inputs		Inputs
	($ In millions)

Equity securities:
United States large cap		22.3	%	$	141	$	—	$	141	$	—
United States small cap		14.1	%		89		89		—		—
International large cap		14.4	%		91		50		41		—

Total equity securities		50.8	%		321		139		182		—

Fixed-income securities:
Corporate bonds		22.0	%		139		139		—		—
United States Treasury obligations		10.9	%		69		69		—		—
Other bonds		4.6	%		29		29		—		—

Total fixed-income securities		37.5	%		237		237		—		—

Other securities:
Short-term investment funds		2.5	%		16		—		16		—
Hedge funds		9.2	%		58		—		—		58

Total other securities		11.7	%		74		—		16		58

Total investments		100.0	%	$	632	$	376	$	198	$	58


	As of December 31, 2009
						Fair Value Measurements Using:
	Actual					Level 1		Level 2		Level 3
	Allocation			Total		Inputs		Inputs		Inputs
	(In millions)

Equity securities:
United States large cap		18.8	%	$	100	$	—	$	100	$	—
United States small cap		15.2	%		81		81		—		—
International large cap		15.2	%		81		44		37		—

Total equity securities		49.2	%		262		125		137		—

Fixed-income securities:
Corporate bonds		25.1	%		133		133		—		—
United States Treasury obligations		9.8	%		52		52		—		—
Other bonds		3.9	%		21		21		—		—

Total fixed-income securities		38.8	%		206		206		—		—

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	As of December 31, 2009
						Fair Value Measurements Using:
	Actual					Level 1		Level 2		Level 3
	Allocation			Total		Inputs		Inputs		Inputs
	(In millions)

Other securities:
Short-term investment funds		2.4	%		13		—		13		—
Hedge funds		9.6	%		51		—		—		51

Total other securities		12.0	%		64		—		13		51

Total investments		100.0	%	$	532	$	331	$	150	$	51

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

Equity securities — Devon’s equity securities consist of investments in United States large and small capitalization companies and international large capitalization companies. These equity securities are actively traded securities that can be redeemed upon demand. The fair values of these Level 1 securities are based upon quoted market prices.

Devon’s equity securities also include commingled funds that invest in large capitalization companies. These equity securities can be redeemed on demand but are not actively traded. The fair values of these Level 2 securities are based upon the net asset values provided by the investment managers.

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

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

Devon’s other securities also include a hedge fund of funds that invests both long and short using a variety of investment strategies. Management of the hedge fund has the ability to shift investments from value to growth strategies, from small to large capitalization stocks, and from a net long position to a net short position. Devon’s hedge fund is not actively traded and Devon is subject to redemption restrictions with regards to this investment. The fair value of this Level 3 investment represents the fair value as determined by the hedge fund manager.

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


	Hedge Funds
	(In millions)

December 31, 2008	$	—
Purchases		51

December 31, 2009		51
Purchases		3
Investment returns		4

December 31, 2010	$	58

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Expected Cash Flows

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


			Other
	Pension		Postretirement
	Benefits		Benefits
	(In millions)

Devon’s 2011 contributions	$	93	$	4
Benefit payments:
2011	$	42	$	4
2012	$	45	$	4
2013	$	49	$	4
2014	$	52	$	4
2015	$	54	$	4
2016 to 2020	$	328	$	21

Expected contributions included in the table above include amounts related to Devon’s Qualified Plans, Supplemental Plans and Postretirement Plans. Of the benefits expected to be paid in 2011, $9 million of pension benefits is expected to be funded from the trusts established for the Supplemental Plans and all $4 million of other postretirement benefits is expected to be funded from Devon’s available cash and cash equivalents. Expected employer contributions and benefit payments for other postretirement benefits are presented net of employee contributions.

Other Benefit Plans

Devon’s 401(k) Plan covers all its employees in the United States. At its discretion, Devon may match a certain percentage of the employees’ contributions to the plan. The matching percentage is determined annually by the Board of Directors.

Devon also has an enhanced defined contribution structure related to its 401(k) Plan. Participants who elected to participate in this enhanced defined contribution structure when it was established, as well as all employees hired after the enhanced defined contribution structure was established, receive a discretionary match of a percentage of their contributions to the 401(k) Plan. The participants also receive additional, nondiscretionary contributions by Devon calculated as a percentage of annual compensation. The percentage will vary based on the employees’ years of service.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table presents Devon’s expense related to these defined contribution plans.


	Year Ended December 31,
	2010		2009		2008
	(In millions)

401(k) plan	$	18	$	20	$	21
Enhanced contribution plan		14		14		12
Canadian pension and savings plans		17		15		16

Total expense	$	49	$	49	$	49


9.	Stockholders’ Equity

The authorized capital stock of Devon consists of 1 billion shares of common stock, par value $0.10 per share, and 4.5 million shares of preferred stock, par value $1.00 per share. The preferred stock may be issued in one or more series, and the terms and rights of such stock will be determined by the Board of Directors.

Devon’s Board of Directors has designated 2.9 million shares of the preferred stock as Series A Junior Participating Preferred Stock (the “Series A Junior Preferred Stock”). At December 31, 2010, there were no shares of Series A Junior Preferred Stock issued or outstanding. The Series A Junior Preferred Stock is entitled to receive cumulative quarterly dividends per share equal to the greater of $1.00 or 100 times the aggregate per share amount of all dividends (other than stock dividends) declared on common stock since the immediately preceding quarterly dividend payment date or, with respect to the first payment date, since the first issuance of Series A Junior Preferred Stock. Holders of the Series A Junior Preferred Stock are entitled to 100 votes per share on all matters submitted to a vote of the stockholders. The Corporation, at its option, may redeem shares of the Series A Junior Participating Preferred Stock in whole at any time and in part from time to time, at a redemption price equal to 100 times the current per share market price of the Common Stock on the date of the mailing of the notice of redemption. The Series A Junior Preferred Stock ranks prior to the common stock but junior to all other classes of Preferred Stock.

Stock Repurchases

During 2010, Devon’s Board of Directors announced a share repurchase program that authorizes the repurchase of up to $3,500 million of its common shares. This program, which expires December 31, 2011, was created as a result of the success experienced from the offshore divestiture program described in Note 5.

During 2008, Devon’s Board of Directors approved an ongoing, annual stock repurchase program to minimize dilution resulting from restricted stock issued to, and options exercised by, employees. Also, Devon’s Board of Directors approved a program in 2007 to repurchase up to 50 million shares. This program was created as a potential use of the proceeds received from Devon’s West African property divestitures. Both of these plans expired on December 31, 2009.

The following table summarizes Devon’s repurchases under approved plans (amounts and shares in millions).


	2010						2008
Repurchase Program	Amount		Shares		Per Share		Amount		Shares		Per Share

2010 program	$	1,201		18.3	$	65.58	$	—		—	$	—
Annual program		—		—		—		178		2.0	$	87.83
2007 program		—		—		—		487		4.5	$	109.25

Totals	$	1,201		18.3	$	65.58	$	665		6.5	$	102.56

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Preferred Stock Redemption

On June 20, 2008, Devon redeemed all 1.5 million outstanding shares of its 6.49% Series A cumulative preferred stock. Each share of preferred stock was redeemed for cash at a redemption price of $100 per share, plus accrued and unpaid dividends up to the redemption date.

Dividends


10.	Commitments and Contingencies

Devon is party to various legal actions arising in the normal course of business. Matters that are probable of unfavorable outcome to Devon and which can be reasonably estimated are accrued. Such accruals are based on information known about the matters, Devon’s estimates of the outcomes of such matters and its experience in contesting, litigating and settling similar matters. None of the actions are believed by management to involve future amounts that would be material to Devon’s financial position or results of operations after consideration of recorded accruals although actual amounts could differ materially from management’s estimate.

Environmental Matters

Devon is subject to certain laws and regulations relating to environmental remediation activities associated with past operations, such as the Comprehensive Environmental Response, Compensation, and Liability Act and similar state statutes. In response to liabilities associated with these activities, loss accruals primarily consist of estimated uninsured costs associated with remediation. Devon’s monetary exposure for environmental matters is not expected to be material.

Royalty Matters

Numerous natural gas producers and related parties, including Devon, have been named in various lawsuits alleging violation of the federal False Claims Act. The suits allege that the producers and related parties used below-market prices, improper deductions, improper measurement techniques and transactions with affiliates, which resulted in underpayment of royalties in connection with natural gas and NGLs produced and sold from federal and Indian owned or controlled lands. Devon does not currently believe that it is subject to material exposure with respect to such royalty matters.

Other Matters

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

Commitments

The following is a schedule by year of purchase obligations, future minimum payments for drilling and facility obligations, firm transportation agreements and leases that have initial or remaining noncancelable lease terms in excess of one year as of December 31, 2010. The schedule includes separate amounts for Devon’s continuing and discontinued operations.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


			Drilling
			and		Firm		Office and
	Purchase		Facility		Transportation		Equipment		FPSO
Year Ending December 31,	Obligations		Obligations		Agreements		Leases		Lease
	(In millions)

Continuing operations:
2011	$	551	$	747	$	282	$	58	$	—
2012		708		280		254		56		—
2013		763		130		233		48		—
2014		784		6		218		39		—
2015		784		—		190		38		—
Thereafter		4,120		—		557		250		—

Total		7,710		1,163		1,734		489		—

Discontinued operations:
2011		—		314		—		9		29
2012		—		171		—		—		29
2013		—		110		—		—		29
2014		—		—		—		—		15

Total		—		595		—		9		102

Total operations	$	7,710	$	1,758	$	1,734	$	498	$	102

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

Devon has certain drilling and facility obligations under contractual agreements with third-party service providers to procure drilling rigs and other related services for developmental and exploratory drilling and facilities construction. Included in the discontinued operations obligations are amounts related to a long-term contract for a deepwater drilling rig being used in Brazil. Devon’s lease and remaining commitments for this rig will be assumed by the buyer of its assets in Brazil when the associated divestiture transaction closes.

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

Devon leases certain office space and equipment under operating lease arrangements. Total rental expense included in general and administrative expenses under operating leases, net of sub-lease income, was $57 million, $56 million and $44 million in 2010, 2009 and 2008, respectively.

Devon has a floating, production, storage and offloading facility (“FPSO”) that is being used in the Polvo project offshore Brazil and is being leased under operating lease arrangements. This lease will be assumed by the buyer when the associated divestiture transaction closes. However, the amounts in the table above reflect Devon’s full commitments under the lease. Total rental expense included in lease operating expenses for Devon’s FPSO’s was $25 million, $36 million and $25 million in 2010, 2009 and 2008, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


11.	Fair Value Measurements

Certain of Devon’s assets and liabilities are reported at fair value in the accompanying consolidated balance sheets. Such assets and liabilities include amounts for both financial and nonfinancial instruments. The following tables provide carrying value and fair value measurement information for Devon’s financial assets and liabilities.

The carrying values of cash and cash equivalents, accounts receivable and accounts payable (including income taxes payable and other accrued expenses) included in the accompanying consolidated balance sheets approximated fair value at December 31, 2010 and 2009. These assets and liabilities are not presented in the following tables.

Information regarding the fair values of Devon’s pension plan assets is provided in Note 8.


				Total			Fair Value Measurements Using:
	Carrying			Fair			Level 1			Level 2			Level 3
	Amount			Value			Inputs			Inputs			Inputs
	(In millions)

December 31, 2010 assets (liabilities):
Commodity asset derivatives	$	249		$	249		$	—		$	249		$	—
Commodity liability derivatives	$	(192	)	$	(192	)	$	—		$	(192	)	$	—
Interest rate derivatives	$	140		$	140		$	—		$	140		$	—
Debt	$	(5,630	)	$	(6,629	)	$	—		$	(6,485	)	$	(144	)
Long-term investments	$	94		$	94		$	—		$	—		$	94
Short-term investments	$	145		$	145		$	145		$	—		$	—
December 31, 2009 assets (liabilities):
Commodity asset derivatives	$	172		$	172		$	—		$	172		$	—
Commodity liability derivatives	$	(38	)	$	(38	)	$	—		$	(38	)	$	—
Interest rate derivatives	$	170		$	170		$	—		$	170		$	—
Debt	$	(7,279	)	$	(8,214	)	$	(1,432	)	$	(6,782	)	$	—
Long-term investments	$	115		$	115		$	—		$	—		$	115

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

Level 1 Fair Value Measurements

Debt — The fair value of Devon’s variable-rate commercial paper borrowings is the carrying value.

Short-term investments — Devon’s short-term investments consist entirely of United States Treasury bills with maturities over 90 days.

Level 2 Fair Value Measurements

Commodity derivatives — The fair values of commodity derivatives are estimated using internal discounted cash flow calculations based upon forward commodity price curves, quotes obtained from brokers for contracts with similar terms or quotes obtained from counterparties to the agreements. The most significant input to the cash flow calculations is Devon’s estimate of future commodity prices. Devon bases its 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 the cash flow calculations is Devon’s estimate of volatility for these forward curves, which is based primarily upon implied volatility. The resulting estimated future cash inflows or outflows over

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

the lives of the contracts are discounted primarily using United States Treasury bill rates. These pricing and discounting inputs are sensitive to the period of the contract, as well as changes in forward prices and regional price differentials.

Interest rate derivatives — The fair values of the interest rate derivatives are estimated using internal discounted cash flow calculations based upon forward interest-rate yield curves or quotes obtained from counterparties to the agreements. The most significant input to Devon’s cash flow calculations is its estimate of future interest rate yields. Devon bases its estimate of future yields upon its 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 rate. These yield and discounting inputs are sensitive to the period of the contract, as well as changes in forward interest rate yields.

Debt — Devon’s Level 2 fixed-rate debt instruments do not actively trade in an established market. The fair values of this debt are estimated by discounting the principal and interest payments at rates available for debt with similar terms and maturity.

Level 3 Fair Value Measurements

Debt — Devon’s Level 3 debt consisted of the non-interest bearing promissory note discussed in Note 5. Due to the lack of an active market for Devon’s promissory note, quoted marked prices for this note were not available. Therefore, Devon used valuation techniques that rely on unobservable inputs to estimate the fair value of its promissory note. The fair value of this debt is estimated using internal discounted cash flow calculations based upon estimated future payment schedules and a 3.125% interest rate. As a result of using these inputs, Devon concluded the estimated fair value of its non-interest bearing promissory note approximated the carrying value as of December 31, 2010.

Long-term investments — Devon’s long-term investments presented in the tables above consisted entirely of auction rate securities. Due to the auction failures discussed in Note 1 and the lack of an active market for Devon’s auction rate securities, quoted market prices for these securities were not available as of December 31, 2010 and December 31, 2009. Therefore, Devon used valuation techniques that rely on unobservable inputs to estimate the fair values of its long-term auction rate securities. These inputs were based on the AAA credit rating of the securities, the probability of full repayment of the securities considering the United States government guarantees of substantially all of the underlying student loans, the collection of all accrued interest to date and continued receipts of principal at par. As a result of using these inputs, Devon concluded the estimated fair values of its long-term auction rate securities approximated the par values as of December 31, 2010 and December 31, 2009. At this time, Devon does not believe the values of its long-term securities are impaired.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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


				Long-Term
	Debt			Investments
	(In millions)

December 31, 2008	$	—		$	122
Redemptions of principal		—			(7	)

December 31, 2009		—			115
Issuance of promissory note		(139	)		—
Foreign exchange translation adjustment		(9	)		—
Accretion of promissory note		(3	)		—
Redemptions of principal		7			(21	)

December 31, 2010	$	(144	)	$	94


12.	Share-Based Compensation

On June 3, 2009, Devon’s stockholders adopted the 2009 Long-Term Incentive Plan, which expires on June 2, 2019. This plan authorizes the Compensation Committee, which consists of non-management members of Devon’s Board of Directors, to grant nonqualified and incentive stock options, restricted stock awards, Canadian restricted stock units, performance units, stock appreciation rights and cash-out rights to eligible employees. The plan also authorizes the grant of nonqualified stock options, restricted stock awards, restricted stock units and stock appreciation rights to directors. A total of 21.5 million shares of Devon common stock have been reserved for issuance pursuant to the plan. To calculate shares issued under the plan, options granted represent one share and other awards represent 1.84 shares.

Devon also has stock option plans that were adopted in 2005, 2003 and 1997 under which stock options and restricted stock awards were issued to key management and professional employees. Options granted under these plans remain exercisable by the employees owning such options, but no new options or restricted stock awards will be granted under these plans. Devon also has stock options outstanding that were assumed as part of the acquisitions of Ocean and Mitchell Energy & Development Corp.

The following table presents the effects of share-based compensation included in Devon’s accompanying consolidated statement of operations. The vesting for certain share-based awards was accelerated as part of Devon’s strategic repositioning. The associated expense for these accelerated awards is included in restructuring costs in the accompanying consolidated statement of operations. See Note 13 for further details.


	2010		2009		2008
	(In millions)

Gross general and administrative expense	$	188	$	209	$	212
Share-based compensation expense capitalized pursuant to the full cost method of accounting for oil and gas properties	$	58	$	66	$	54
Related income tax benefit	$	40	$	43	$	47

With the approval of Devon’s Compensation Committee, Devon modified the share-based compensation arrangements for certain of Devon’s executives in the second quarter of 2008. The modified compensation arrangements provide that executives who meet certain years-of-service and age criteria can retire and continue vesting in outstanding share-based grants. As a condition to receiving the benefits of these modifications, the executives must agree not to use or disclose Devon’s confidential information and not to solicit Devon’s employees and customers. The executives are required to agree to these conditions at retirement and again in each subsequent year until all grants have vested.

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Although this modification does not accelerate the vesting of the executives’ grants, it does accelerate the expense recognition as executives approach the years-of-service and age criteria. When the modification was made in the second quarter of 2008, certain executives had already met the years-of-service and age criteria. As a result, Devon recognized an additional $27 million of share-based compensation expense in the second quarter of 2008 related to this modification. This additional expense would have been recognized in future reporting periods if the modification had not been made and the executives continued their employment at Devon.

Stock Options

Under Devon’s 2009 Long-Term Incentive Plan, the exercise price of stock options granted may not be less than the market value of the stock at the date of grant. In addition, options granted are exercisable during a period established for each grant, which may not exceed eight years from the date of grant. The recipient must pay the exercise price in cash or in common stock, or a combination thereof, at the time that the option is exercised. Options granted generally have a vesting period that ranges from three to four years.

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

The following table presents a summary of the grant-date fair values of stock options granted and the related assumptions. All such amounts represent the weighted-average amounts for each year.


	2010			2009			2008

Grant-date fair value	$	25.41		$	22.85		$	21.77
Volatility factor		45.3	%		47.7	%		44.3	%
Dividend yield		1.0	%		0.9	%		0.9	%
Risk-free interest rate		1.1	%		2.1	%		1.2	%
Expected term (in years)		4.5			4.0			3.8

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The following table presents a summary of Devon’s outstanding stock options as of December 31, 2010, including changes during the year then ended.


						Weighted
				Weighted		Average
				Average		Remaining		Aggregate
				Exercise		Contractual		Intrinsic
	Options			Price		Term		Value
	(In thousands)					(In Years)		(In millions)

Outstanding at December 31, 2009		12,160		$	59.07
Granted		1,913		$	72.54
Exercised		(2,309	)	$	50.63
Forfeited		(330	)	$	72.48

Outstanding at December 31, 2010		11,434		$	62.64		3.8	$	201

Vested and expected to vest at December 31, 2010		11,369		$	62.59		3.8	$	200

Exercisable at December 31, 2010		7,768		$	59.63		2.7	$	164

The aggregate intrinsic value of stock options that were exercised during 2010, 2009 and 2008 was $47 million, $51 million and $263 million, respectively. As of December 31, 2010, Devon’s unrecognized compensation cost related to unvested stock options was $65 million. Such cost is expected to be recognized over a weighted-average period of 2.8 years.

Restricted Stock Awards and Units

Under Devon’s 2009 Long-Term Incentive Plan, restricted stock awards and units are subject to the terms, conditions, restrictions and limitations, if any, that the Compensation Committee deems appropriate, including restrictions on continued employment. Generally, restricted stock awards and units vest over a minimum restriction period of at least three years from the date of grant. During the vesting period, recipients of restricted stock awards receive dividends that are not subject to restrictions or other limitations. The fair value of restricted stock awards and units on the date of grant is expensed over the applicable vesting period. Devon estimates the fair values of restricted stock awards and units as the closing price of Devon’s common stock on the grant date of the award or unit.

The following table presents a summary of Devon’s unvested restricted stock awards as of December 31, 2010, including changes during the year then ended.


				Weighted
	Restricted			Average
	Stock			Grant-Date
	Awards			Fair Value
	(In thousands)

Unvested at December 31, 2009		6,165		$	69.76
Granted		2,026		$	73.19
Vested		(2,619	)	$	70.56
Forfeited		(261	)	$	70.94

Unvested at December 31, 2010		5,311		$	70.60

The aggregate fair value of restricted stock awards that vested during 2010, 2009 and 2008 was $184 million, $165 million and $185 million, respectively. As of December 31, 2010, Devon’s unrecognized

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compensation cost related to unvested restricted stock awards and units was $311 million. Such cost is expected to be recognized over a weighted-average period of 2.8 years.


13.	Restructuring Costs

Employee Severance

In the fourth quarter of 2009, Devon recognized $153 million of estimated employee severance costs associated with the planned divestiture of its offshore assets that was announced in November 2009. This amount was based on estimates of the number of employees that would ultimately be impacted by the divestitures and included amounts related to cash severance costs and accelerated vesting of share-based grants. Of the $153 million total, $105 million related to Devon’s U.S. Offshore operations and the remainder related to its International discontinued operations.

As discussed in Note 5, during 2010 Devon divested all of its U.S. Offshore assets and a significant part of its International assets. As a result of these divestitures and associated employee terminations, Devon decreased its estimate of employee severance costs in 2010 by $31 million. More offshore employees than previously estimated received comparable positions with either the purchaser of the properties or in Devon’s U.S. Onshore operations, and this caused the $31 million decrease to the severance estimate. This decrease includes $27 million related to Devon’s U.S. Offshore operations and $4 million related to its International discontinued operations.

Lease Obligations

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

Asset Impairments

In 2010, Devon recognized $11 million of asset impairment charges for leasehold improvements and furniture associated with the office space it ceased using.

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Financial Statement Presentation

The schedule below summarizes the components of restructuring costs in the accompanying consolidated statements of operations.


	Year Ended									Year Ended
	December 31, 2010									December 31, 2009
	Continuing			Discontinued						Continuing		Discontinued
	Operations			Operations			Total			Operations		Operations		Total
	(In millions)

Cash severance	$	(17	)	$	1		$	(16	)	$	66	$	24	$	90
Share-based awards		(10	)		(5	)		(15	)		39		24		63
Lease obligations		70			—			70			—		—		—
Asset impairments		11			—			11			—		—		—
Other		3			—			3			—		—		—

Restructuring costs	$	57		$	(4	)	$	53		$	105	$	48	$	153

Amounts related to cash severance and lease obligations are accrued for in other current liabilities and other long-term liabilities in the accompanying consolidated balance sheets, while amounts related to accelerated share-based awards are recorded as a reduction to Devon’s additional paid-in capital in the accompanying consolidated balance sheets. The schedule below summarizes activity and liability balances associated with Devon’s restructuring liabilities.


	Other Current Liabilities									Other Long-Term Liabilities
	Continuing			Discontinued						Continuing		Discontinued
	Operations			Operations			Total			Operations		Operations		Total
	(In millions)

Balance as of December 31, 2008	$	—		$	—		$	—		$	—	$	—	$	—
Cash severance accrual		61			23			84			—		—		—

Balance as of December 31, 2009		61			23			84			—		—		—
Lease obligations incurred		17			—			17			50		—		50
Cash severance paid		(30	)		(8	)		(38	)		—		—		—
Cash severance revision		(17	)		1			(16	)		—		—		—
Other		—			—			—			1		—		1

Balance as of December 31, 2010	$	31		$	16		$	47		$	51	$	—	$	51

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14.	Interest-Rate and Other Financial Instruments

The following table presents the changes in fair value and cash settlements related to Devon’s interest-rate and other financial instruments presented in the accompanying consolidated statements of operations.


	Year Ended December 31,
	2010			2009			2008
	(In millions)

(Gains) and losses from:
Interest rate swaps — settlements (See Note 3)	$	(44	)	$	(40	)	$	(1	)
Interest rate swaps — fair value changes (See Note 3)		30			(66	)		(104	)
Chevron common stock		—			—			363
Option embedded in exchangeable debentures		—			—			(109	)

Total	$	(14	)	$	(106	)	$	149

Until October 31, 2008, Devon owned 14.2 million shares of Chevron common stock. These shares were held in connection with debt owed by Devon that contained an exchange option. The exchange option allowed the debt holders, prior to the debt’s maturity of August 15, 2008, to exchange the debt for shares of Chevron common stock owned by Devon. However, Devon had the option to settle any exchanges with cash equal to the market value of Chevron common stock at the time of the exchange. Devon settled remaining exchange requests during 2008 by paying $1.0 billion. On October 31, 2008, Devon transferred its 14.2 million shares of Chevron common stock to Chevron. In exchange, Devon received Chevron’s interest in the Drunkard’s Wash coalbed natural gas field in east-central Utah and $280 million in cash.


15.	Reduction of Carrying Value of Oil and Gas Properties

During 2009 and 2008, Devon reduced the carrying values of certain of its oil and gas properties due to full cost ceiling limitations. A summary of these reductions and additional discussion is provided below.


	Year Ended December 31,
	2009				2008
			After				After
	Gross		Taxes		Gross		Taxes
	(In millions)

United States	$	6,408	$	4,085	$	6,538	$	4,168
Canada		—		—		3,353		2,488

Total	$	6,408	$	4,085	$	9,891	$	6,656

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16.	Other, net

The components of other, net in the accompanying consolidated statements of operations include the following:


	Year Ended
	December 31,
	2010			2009			2008
	(In millions)

Interest and dividend income	$	(13	)	$	(8	)	$	(54	)
Deep water royalties		—			(84	)		—
Hurricane insurance proceeds		—			—			(162	)
Other		(32	)		24			(1	)

Total	$	(45	)	$	(68	)	$	(217	)

Deep water Gulf of Mexico leases issued in certain years by the Minerals Management Service (the “MMS”) contained price thresholds, such that if the market prices for oil or gas exceeded the thresholds for a given year, royalty relief would not be granted for that year. In October 2007, a federal district court ruled in favor of a plaintiff who had challenged the legality of including price thresholds in deep water leases. This judgment was later appealed to the United States Supreme Court, which, in October 2009, declined to review the appellate court’s ruling. The Supreme Court’s decision ended the MMS’s judicial course to enforce the price thresholds. At the time of the Supreme Court’s decision, Devon had $84 million accrued for potential royalties on various deep water leases. Based upon the Supreme Court’s decision, Devon reduced to zero the $84 million loss contingency accrual in 2009.

In 2008, Devon recognized $162 million of excess insurance recoveries for damages suffered in 2005 related to hurricanes that struck the Gulf of Mexico. The excess recoveries resulted from business interruption claims on policies that were in effect when the 2005 hurricanes occurred.

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17.	Income Taxes

Income Tax Expense (Benefit)

The earnings (loss) from continuing operations before income taxes and the components of income tax expense (benefit) were as follows:


	Year Ended December 31,
	2010			2009			2008
	(In millions)

Earnings (loss) from continuing operations before income taxes:
U.S.	$	2,943		$	(4,961	)	$	(2,190	)
Canada		625			435			(1,970	)

Total	$	3,568		$	(4,526	)	$	(4,160	)

Current income tax expense:
U.S. federal	$	244		$	45		$	258
Various states		16			18			31
Canada and various provinces		256			178			152

Total current tax expense		516			241			441

Deferred income tax expense (benefit):
U.S. federal		781			(1,846	)		(875	)
Various states		21			(111	)		(65	)
Canada and various provinces		(83	)		(57	)		(622	)

Total deferred tax expense (benefit)		719			(2,014	)		(1,562	)

Total income tax expense (benefit)	$	1,235		$	(1,773	)	$	(1,121	)

The taxes on the results of discontinued operations presented in the accompanying consolidated statements of operations were all related to Devon’s international operations outside North America.

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


	Year Ended December 31,
	2010			2009			2008
	(In millions)

Expected income tax expense (benefit) based on U.S. statutory tax rate of 35%	$	1,249		$	(1,584	)	$	(1,456	)
Repatriations and assumed repatriations		144			55			312
State income taxes		31			(99	)		(29	)
Taxation on Canadian operations		(60	)		(31	)		227
Other		(129	)		(114	)		(175	)

Total income tax expense (benefit)	$	1,235		$	(1,773	)	$	(1,121	)

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

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During 2008, Devon recognized $312 million of additional income tax expense that resulted from two related factors associated with its foreign operations. First, during 2008, Devon repatriated $2.6 billion from certain foreign subsidiaries to the United States. Second, Devon made certain tax policy election changes in the second quarter of 2008 to minimize the taxes it otherwise would pay for the cash repatriations, as well as the taxable gains associated with the sales of assets in West Africa. As a result of the repatriation and tax policy election changes, Devon recognized $295 million of additional current tax expense and $17 million of additional deferred tax expense.

Deferred Tax Assets and Liabilities

The tax effects of temporary differences that gave rise to significant portions of the deferred tax assets and liabilities are presented below:


	December 31,
	2010			2009
	(In millions)

Deferred tax assets:
Net operating loss carryforwards	$	159		$	11
Asset retirement obligations		494			474
Pension benefit obligations		133			130
Other		171			133

Total deferred tax assets		957			748

Deferred tax liabilities:
Property and equipment, principally due to nontaxable business combinations, differences in depreciation, and the expensing of intangible drilling costs for tax purposes		(3,130	)		(2,315	)
Fair value of financial instruments		(70	)		(108	)
Long-term debt		(198	)		(162	)
Taxes on unremitted foreign earnings		(211	)		(55	)
Other		(20	)		(7	)

Total deferred tax liabilities		(3,629	)		(2,647	)

Net deferred tax liability	$	(2,672	)	$	(1,899	)

As shown in the above table, Devon has recognized $957 million of deferred tax assets as of December 31, 2010. Included in total deferred tax assets is $159 million related to various carryforwards available to offset future income taxes. The carryforwards consist of $538 million of Canadian net operating loss carryforwards, which expire between 2023 and 2030, and $161 million of state net operating loss carryforwards, which expire primarily between 2011 and 2024. The tax benefits of carryforwards are recorded as an asset to the extent that management assesses the utilization of such carryforwards to be “more likely than not.” When the future utilization of some portion of the carryforwards is determined not to be “more likely than not,” a valuation allowance is provided to reduce the recorded tax benefits from such assets.

Devon expects the tax benefits from the Canadian net operating loss carryforward to be utilized between 2011 and 2016. Also, Devon expects the tax benefits from the state net operating loss carryforwards to be utilized between 2012 and 2015. Such expectations are based upon current estimates of taxable income during these periods, considering limitations on the annual utilization of these benefits as set forth by tax regulations. Significant changes in such estimates caused by variables such as future oil and gas prices or capital expenditures could alter the timing of the eventual utilization of such carryforwards. There can be no

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assurance that Devon will generate any specific level of continuing taxable earnings. However, management believes that Devon’s future taxable income will more likely than not be sufficient to utilize substantially all its tax carryforwards prior to their expiration.

As of December 31, 2010, approximately $4.3 billion of Devon’s unremitted earnings from its foreign subsidiaries were deemed to be permanently reinvested. As a result, Devon has not recognized a deferred tax liability for United States income taxes associated with such earnings. If such earnings were to be remitted to the United States, Devon may be subject to United States income taxes and foreign withholding taxes. However, it is not practical to estimate the amount of additional taxes that may be payable due to the inter-relationship of the various factors involved in making such an estimate.

Unrecognized Tax Benefits

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


	2010			2009
	(In millions)

Balance at beginning of year	$	272		$	260
Tax positions taken in prior periods		40			—
Tax positions taken in current year		5			20
Accrual of interest related to tax positions taken		9			7
Lapse of statute of limitations		(5	)		(15	)
Settlements		(129	)		(5	)
Foreign currency translation		2			5

Balance at end of year	$	194		$	272

Devon’s unrecognized tax benefit balance at December 31, 2010 and 2009 included $27 million and $35 million of interest and penalties, respectively. If recognized, all of Devon’s unrecognized tax benefits as of December 31, 2010 would affect Devon’s effective income tax rate.

Included below is a summary of the tax years, by jurisdiction, that remain subject to examination by taxing authorities.


Jurisdiction	Tax Years Open

U.S. federal		2005-2010
Various U.S. states		2005-2010
Canada federal		2003-2010
Various Canadian provinces		2003-2010

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


18.	Discontinued Operations

For the three-year period ended December 31, 2010, Devon’s discontinued operations include amounts related to its assets in Azerbaijan, Brazil, China, Angola and other minor International properties. Additionally, during 2008, Devon’s discontinued operations included amounts related to its assets in Egypt and West Africa, including Equatorial Guinea, Cote d’Ivoire, Gabon and other countries in the region, until they were sold.

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Revenues related to Devon’s discontinued operations totaled $693 million, $945 million and $1,702 million during 2010, 2009 and 2008, respectively. Earnings from discontinued operations before income taxes totaled $2,385 million, $322 million and $1,258 million during 2010, 2009 and 2008, respectively. Earnings before income taxes in each of these years were largely impacted by gains on the divestiture transactions. The following table presents the gains on the divestitures by year.


	Year Ended December 31,
	2010						2009				2008
				After					After				After
	Gross			Taxes			Gross		Taxes		Gross		Taxes
	(In millions)

Azerbaijan	$	1,543		$	1,524		$	—	$	—	$	—	$	—
China — Panyu		308			235			—		—		—		—
Equatorial Guinea		—			—			—		—		619		544
Gabon		—			—			—		—		117		122
Cote d’Ivoire		—			—			17		17		83		95
Other		(33	)		(27	)		—		—		—		8

Total	$	1,818		$	1,732		$	17	$	17	$	819	$	769

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


	December 31,
	2010		2009
	(In millions)

Cash and cash equivalents	$	424	$	365
Accounts receivable		43		165
Other current assets		96		127

Current assets	$	563	$	657

Property and equipment, net	$	848	$	1,099
Goodwill		—		68
Other long-term assets		11		83

Total long-term assets	$	859	$	1,250

Accounts payable	$	260	$	158
Other current liabilities		45		76

Current liabilities	$	305	$	234

Asset retirement obligations	$	24	$	109
Deferred income taxes		2		101
Other liabilities		—		3

Long-term liabilities	$	26	$	213

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Reductions of Carrying Value of Oil and Gas Properties

During 2009 and 2008, Devon reduced the carrying values of certain of its oil and gas properties that are now held for sale. These reductions primarily resulted from full cost ceiling limitations. A summary of these reductions and additional discussion is provided below.


	Year Ended December 31,
	2009				2008
			After				After
	Gross		Taxes		Gross		Taxes
	(In millions)				(In millions)

Brazil	$	103	$	103	$	437	$	437
Other		6		2		57		28

Total	$	109	$	105	$	494	$	465

Brazil’s 2009 reduction resulted largely from an exploratory well drilled at the BM-BAR-3 block in the offshore Barreirinhas Basin. After drilling this well in the first quarter of 2009, Devon concluded that the well did not have adequate reserves for commercial viability. As a result, the seismic, leasehold and drilling costs associated with this well contributed to the reduction recognized in the first quarter of 2009.

Brazil’s 2008 reduction was recognized in the fourth quarter of 2008 and resulted primarily from a significant decrease in its full cost ceiling. The lower ceiling value largely resulted from the effects of sharp declines in oil prices compared to previous quarter-end prices.


19.	Earnings (Loss) Per Share

The following table reconciles earnings from continuing operations and common shares outstanding used in the calculations of basic and diluted earnings (loss) per share. Because a net loss from continuing operations was incurred during 2009 and 2008, the dilutive shares produce an antidilutive net loss per share result.

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Therefore, the diluted loss per share from continuing operations reported in the accompanying 2009 and 2008 consolidated statements of operations are the same as the basic loss per share amounts.


							Earnings
	Earnings			Common			(Loss)
	(Loss)			Shares			per Share
	(In millions, except per share amounts)

Year Ended December 31, 2010:
Earnings from continuing operations	$	2,333			440
Attributable to participating securities		(26	)		(5	)

Basic earnings per share		2,307			435		$	5.31
Dilutive effect of potential common shares issuable upon the exercise of outstanding stock options		—			1

Diluted earnings per share	$	2,307			436		$	5.29

Year Ended December 31, 2009:
Loss from continuing operations	$	(2,753	)		444
Attributable to participating securities		31			(5	)

Basic and diluted loss per share	$	(2,722	)		439		$	(6.20	)

Year Ended December 31, 2008:
Loss from continuing operations	$	(3,039	)		444
Attributable to participating securities		31			(5	)
Less preferred stock dividends		(5	)

Basic and diluted loss per share	$	(3,013	)		439		$	(6.86	)

Certain options to purchase shares of Devon’s common stock were excluded from the dilution calculations because the options were antidilutive. These excluded options totaled 6 million, 9 million and 5 million in 2010, 2009 and 2008, respectively.


20.	Segment Information

Devon manages its North American onshore operations through six distinct operating segments, or divisions, which are defined primarily by geographic areas. For financial reporting purposes, Devon aggregates its United States divisions into one reporting segment due to the similar nature of the businesses. However, Devon’s Canadian and International divisions are reported as separate reporting segments primarily due to significant differences in the respective regulatory environments.

Devon’s segments are all primarily engaged in oil and gas producing activities, and certain information regarding such activities for each segment is included in Note 22. Following is certain financial information regarding Devon’s segments for 2010, 2009 and 2008. The revenues reported are all from external customers.

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	U.S.		Canada		International		Total
	(In millions)

As of December 31, 2010:
Current assets	$	2,473	$	2,519	$	563	$	5,555
Property and equipment, net		12,379		7,273		—		19,652
Goodwill		3,046		3,034		—		6,080
Other assets		422		359		859		1,640

Total assets	$	18,320	$	13,185	$	1,422	$	32,927

Current liabilities	$	1,701	$	2,577	$	305	$	4,583
Long-term debt		2,502		1,317		—		3,819
Asset retirement obligations		566		857		—		1,423
Other liabilities		1,005		62		26		1,093
Deferred income taxes		1,571		1,185		—		2,756
Stockholders’ equity		10,975		7,187		1,091		19,253

Total liabilities and stockholders’ equity	$	18,320	$	13,185	$	1,422	$	32,927

122

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	U.S.			Canada			Total
	(In millions)

Year Ended December 31, 2010:
Revenues:
Oil, gas and NGL sales	$	4,742		$	2,520		$	7,262
Oil, gas and NGL derivatives		809			2			811
Marketing and midstream revenues		1,742			125			1,867

Total revenues		7,293			2,647			9,940

Expenses and other, net:
Lease operating expenses		892			797			1,689
Taxes other than income taxes		341			39			380
Marketing and midstream operating costs and expenses		1,256			101			1,357
Depreciation, depletion and amortization of oil and gas properties		998			677			1,675
Depreciation and amortization of non-oil and gas properties		231			24			255
Accretion of asset retirement obligations		42			50			92
General and administrative expenses		433			130			563
Restructuring costs		57			—			57
Interest expense		159			204			363
Interest-rate and other financial instruments		(14	)		—			(14	)
Other, net		(45	)		—			(45	)

Total expenses and other, net		4,350			2,022			6,372

Earnings from continuing operations before income taxes		2,943			625			3,568
Income tax expense (benefit):
Current		260			256			516
Deferred		802			(83	)		719

Total income tax expense		1,062			173			1,235

Earnings from continuing operations	$	1,881		$	452		$	2,333

Capital expenditures, before revision of future asset retirement obligations	$	4,935		$	1,985		$	6,920
Revision of future asset retirement obligations		72			122			194

Capital expenditures, continuing operations	$	5,007		$	2,107		$	7,114

123

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	U.S.		Canada		International		Total
	(In millions)

As of December 31, 2009:
Current assets	$	1,449	$	886	$	657	$	2,992
Property and equipment, net		13,199		5,568		—		18,767
Goodwill		3,046		2,884		—		5,930
Other assets		674		73		1,250		1,997

Total assets	$	18,368	$	9,411	$	1,907	$	29,686

Current liabilities	$	2,993	$	575	$	234	$	3,802
Long-term debt		2,866		2,981		—		5,847
Asset retirement obligations		754		664		—		1,418
Other liabilities		890		47		213		1,150
Deferred income taxes		860		1,039		—		1,899
Stockholders’ equity		10,005		4,105		1,460		15,570

Total liabilities and stockholders’ equity	$	18,368	$	9,411	$	1,907	$	29,686

124

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	U.S.			Canada			Total
	(In millions)

Year Ended December 31, 2009:
Revenues:
Oil, gas and NGL sales	$	3,958		$	2,139		$	6,097
Oil, gas and NGL derivatives		382			2			384
Marketing and midstream revenues		1,498			36			1,534

Total revenues		5,838			2,177			8,015

Expenses and other, net:
Lease operating expenses		997			673			1,670
Taxes other than income taxes		278			36			314
Marketing and midstream operating costs and expenses		1,004			18			1,022
Depreciation, depletion and amortization of oil and gas properties		1,247			585			1,832
Depreciation and amortization of non-oil and gas properties		251			25			276
Accretion of asset retirement obligations		53			38			91
General and administrative expenses		529			119			648
Restructuring costs		105			—			105
Interest expense		125			224			349
Interest-rate and other financial instruments		(106	)		—			(106	)
Reduction of carrying value of oil and gas properties		6,408			—			6,408
Other, net		(92	)		24			(68	)

Total expenses and other, net		10,799			1,742			12,541

(Loss) earnings from continuing operations before income taxes		(4,961	)		435			(4,526	)
Income tax (benefit) expense:
Current		63			178			241
Deferred		(1,957	)		(57	)		(2,014	)

Total income tax (benefit) expense		(1,894	)		121			(1,773	)

(Loss) earnings from continuing operations	$	(3,067	)	$	314		$	(2,753	)

Capital expenditures, before revision of future asset retirement obligations	$	3,536		$	1,114		$	4,650
Revision of future asset retirement obligations		48			(15	)		33

Capital expenditures, continuing operations	$	3,584		$	1,099		$	4,683

125

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	U.S.			Canada			Total
	(In millions)

Year Ended December 31, 2008:
Revenues:
Oil, gas and NGL sales	$	8,206		$	3,514		$	11,720
Oil, gas and NGL derivatives		(154	)		—			(154	)
Marketing and midstream revenues		2,247			45			2,292

Total revenues		10,299			3,559			13,858

Expenses and other, net:
Lease operating expenses		1,075			776			1,851
Taxes other than income taxes		438			38			476
Marketing and midstream operating costs and expenses		1,593			18			1,611
Depreciation, depletion and amortization of oil and gas properties		1,998			950			2,948
Depreciation and amortization of non-oil and gas properties		229			26			255
Accretion of asset retirement obligations		42			38			80
General and administrative expenses		513			132			645
Interest expense		117			212			329
Interest-rate and other financial instruments		149			—			149
Reduction of carrying value of oil and gas properties		6,538			3,353			9,891
Other, net		(203	)		(14	)		(217	)

Total expenses and other, net		12,489			5,529			18,018

Loss from continuing operations before income taxes		(2,190	)		(1,970	)		(4,160	)
Income tax (benefit) expense:
Current		289			152			441
Deferred		(940	)		(622	)		(1,562	)

Total income tax benefit		(651	)		(470	)		(1,121	)

Loss from continuing operations	$	(1,539	)	$	(1,500	)	$	(3,039	)

Capital expenditures, before revision of future asset retirement obligations	$	8,313		$	1,639		$	9,952
Revision of future asset retirement obligations		152			73			225

Capital expenditures, continuing operations	$	8,465		$	1,712		$	10,177

126

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


21.	Supplemental Information to Statements of Cash Flows

Information related to Devon’s cash flows are presented below:


	Year Ended December 31,
	2010			2009			2008
	(In millions)

Net decrease (increase) in working capital:
Decrease in accounts receivable	$	23		$	142		$	187
Decrease (increase) in other current assets		21			212			(46	)
Increase (decrease) in accounts payable		37			(91	)		159
Increase in revenues and royalties due to others		48			—			11
Decrease in income taxes payable		(203	)		(48	)		(309	)
Decrease in other current liabilities		(199	)		(66	)		(209	)

Net (increase) decrease in working capital	$	(273	)	$	149		$	(207	)

Supplementary cash flow data — total operations:
Interest paid (net of capitalized interest)	$	359		$	314		$	336
Income taxes paid	$	955		$	68		$	1,436
Noncash investing activity — exchange of investment in Chevron common stock for oil and gas properties	$	—		$	—		$	610


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

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

Costs Incurred

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


	Year Ended December 31, 2010
	U.S.		U.S.		Total				North
	Onshore		Offshore		U.S.		Canada		America
	(In millions)

Property acquisition costs:
Proved properties	$	29	$	—	$	29	$	4	$	33
Unproved properties		592		2		594		590		1,184
Exploration costs		339		89		428		260		688
Development costs		3,126		297		3,423		1,216		4,639

Costs incurred	$	4,086	$	388	$	4,474	$	2,070	$	6,544

127

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Year Ended December 31, 2009
	U.S.		U.S.		Total				North
	Onshore		Offshore		U.S.		Canada		America
	(In millions)

Property acquisition costs:
Proved properties	$	17	$	—	$	17	$	18	$	35
Unproved properties		52		11		63		72		135
Exploration costs		122		260		382		152		534
Development costs		2,011		537		2,548		835		3,383

Costs incurred	$	2,202	$	808	$	3,010	$	1,077	$	4,087


	Year Ended December 31, 2008
	U.S.		U.S.		Total				North
	Onshore		Offshore		U.S.		Canada		America
	(In millions)

Property acquisition costs:
Proved properties	$	822	$	—	$	822	$	—	$	822
Unproved properties		1,226		185		1,411		352		1,763
Exploration costs		206		638		844		173		1,017
Development costs		4,182		551		4,733		1,131		5,864

Costs incurred	$	6,436	$	1,374	$	7,810	$	1,656	$	9,466

Pursuant to the full cost method of accounting, Devon capitalizes certain of its general and administrative expenses that are related to property acquisition, exploration and development activities. Such capitalized expenses, which are included in the costs shown in the preceding tables, were $311 million, $332 million and $337 million in the years 2010, 2009 and 2008, respectively. Also, Devon capitalizes interest costs incurred and attributable to unproved oil and gas properties and major development projects of oil and gas properties. Capitalized interest expenses, which are included in the costs shown in the preceding tables, were $37 million, $74 million and $71 million in the years 2010, 2009 and 2008, respectively.

128

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Results of Operations

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


	Year Ended December 31, 2010
	United States			Canada			North America
	(In millions)

Oil, gas and NGL sales	$	4,742		$	2,520		$	7,262
Lease operating expenses		(892	)		(797	)		(1,689	)
Taxes other than income taxes		(319	)		(40	)		(359	)
Depreciation, depletion and amortization		(998	)		(677	)		(1,675	)
Accretion of asset retirement obligations		(42	)		(50	)		(92	)
General and administrative expenses		(133	)		(83	)		(216	)
Income tax expense		(849	)		(246	)		(1,095	)

Results of operations	$	1,509		$	627		$	2,136

Depreciation, depletion and amortization per Boe	$	6.11		$	10.51		$	7.36


	Year Ended December 31, 2009
	United States			Canada			North America
	(In millions)

Oil, gas and NGL sales	$	3,958		$	2,139		$	6,097
Lease operating expenses		(997	)		(673	)		(1,670	)
Taxes other than income taxes		(258	)		(35	)		(293	)
Depreciation, depletion and amortization		(1,247	)		(585	)		(1,832	)
Accretion of asset retirement obligations		(53	)		(38	)		(91	)
General and administrative expenses		(145	)		(74	)		(219	)
Reduction of carrying value of oil and gas properties		(6,408	)		—			(6,408	)
Income tax benefit (expense)		1,800			(210	)		1,580

Results of operations	$	(3,350	)	$	524		$	(2,836	)

Depreciation, depletion and amortization per Boe	$	7.47		$	8.84		$	7.86

129

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Year Ended December 31, 2008
	United States			Canada			North America
	(In millions)

Oil, gas and NGL sales	$	8,206		$	3,514		$	11,720
Lease operating expenses		(1,075	)		(776	)		(1,851	)
Taxes other than income taxes		(420	)		(37	)		(457	)
Depreciation, depletion and amortization		(1,998	)		(950	)		(2,948	)
Accretion of asset retirement obligations		(42	)		(38	)		(80	)
General and administrative expenses		(148	)		(87	)		(235	)
Reduction of carrying value of oil and gas properties		(6,538	)		(3,353	)		(9,891	)
Income tax benefit		719			405			1,124

Results of operations	$	(1,296	)	$	(1,322	)	$	(2,618	)

Depreciation, depletion and amortization per Boe	$	12.31		$	15.59		$	13.20

130

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Proved Reserves

The following tables present Devon’s estimated proved developed and proved undeveloped reserves by product for each significant country for the three years ended December 31, 2010. The significant changes in Devon’s reserves are discussed following the tables.


	Oil (MMBbls)
	U.S.			U.S.			Total						North
	Onshore			Offshore			U.S.			Canada			America

Proved developed and undeveloped reserves:
December 31, 2007		131			39			170			388			558
Revisions due to prices		(17	)		(3	)		(20	)		(349	)		(369	)
Revisions other than price		2			3			5			2			7
Extensions and discoveries		11			1			12			120			132
Purchase of reserves		18			—			18			—			18
Production		(11	)		(6	)		(17	)		(22	)		(39	)
Sale of reserves		(1	)		—			(1	)		(5	)		(6	)

December 31, 2008		133			34			167			134			301
Revisions due to prices		9			2			11			291			302
Revisions other than price		—			1			1			(8	)		(7	)
Extensions and discoveries		9			2			11			122			133
Purchase of reserves		—			—			—			—			—
Production		(12	)		(5	)		(17	)		(25	)		(42	)
Sale of reserves		—			(1	)		(1	)		—			(1	)

December 31, 2009		139			33			172			514			686
Revisions due to prices		4			1			5			(24	)		(19	)
Revisions other than price		2			2			4			9			13
Extensions and discoveries		19			1			20			59			79
Purchase of reserves		—			—			—			—			—
Production		(14	)		(2	)		(16	)		(25	)		(41	)
Sale of reserves		(2	)		(35	)		(37	)		—			(37	)

December 31, 2010		148			—			148			533			681

Proved developed reserves as of:
December 31, 2007		122			26			148			195			343
December 31, 2008		111			22			133			110			243
December 31, 2009		119			21			140			149			289
December 31, 2010		131			—			131			126			257
Proved undeveloped reserves as of:
December 31, 2007		9			13			22			193			215
December 31, 2008		22			12			34			24			58
December 31, 2009		20			12			32			365			397
December 31, 2010		17			—			17			407			424

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Gas (Bcf)
	U.S.			U.S.			Total						North
	Onshore			Offshore			U.S.			Canada			America

Proved developed and undeveloped reserves:
December 31, 2007		6,765			378			7,143			1,844			8,987
Revisions due to prices		(367	)		(2	)		(369	)		(219	)		(588	)
Revisions other than price		85			21			106			(12	)		94
Extensions and discoveries		1,916			50			1,966			111			2,077
Purchase of reserves		250			—			250			2			252
Production		(669	)		(57	)		(726	)		(212	)		(938	)
Sale of reserves		(1	)		—			(1	)		(4	)		(5	)

December 31, 2008		7,979			390			8,369			1,510			9,879
Revisions due to prices		(661	)		(4	)		(665	)		(29	)		(694	)
Revisions other than price		119			(62	)		57			(14	)		43
Extensions and discoveries		1,387			64			1,451			67			1,518
Purchase of reserves		1			—			1			6			7
Production		(698	)		(45	)		(743	)		(223	)		(966	)
Sale of reserves		—			(1	)		(1	)		(29	)		(30	)

December 31, 2009		8,127			342			8,469			1,288			9,757
Revisions due to prices		449			2			451			21			472
Revisions other than price		105			(26	)		79			(17	)		62
Extensions and discoveries		1,088			7			1,095			131			1,226
Purchase of reserves		12			—			12			9			21
Production		(699	)		(17	)		(716	)		(214	)		(930	)
Sale of reserves		(17	)		(308	)		(325	)		—			(325	)

December 31, 2010		9,065			—			9,065			1,218			10,283

Proved developed reserves as of:
December 31, 2007		5,547			196			5,743			1,506			7,249
December 31, 2008		6,469			212			6,681			1,357			8,038
December 31, 2009		6,447			185			6,632			1,213			7,845
December 31, 2010		7,280			—			7,280			1,144			8,424
Proved undeveloped reserves as of:
December 31, 2007		1,218			182			1,400			338			1,738
December 31, 2008		1,510			178			1,688			153			1,841
December 31, 2009		1,680			157			1,837			75			1,912
December 31, 2010		1,785			—			1,785			74			1,859

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Natural Gas Liquids (MMBbls)
	U.S.			U.S.			Total						North
	Onshore			Offshore			U.S.			Canada			America

Proved developed and undeveloped reserves:
December 31, 2007		281			1			282			39			321
Revisions due to prices		(18	)		—			(18	)		(2	)		(20	)
Revisions other than price		5			1			6			—			6
Extensions and discoveries		65			—			65			2			67
Purchase of reserves		6			—			6			—			6
Production		(24	)		—			(24	)		(4	)		(28	)
Sale of reserves		—			—			—			—			—

December 31, 2008		315			2			317			35			352
Revisions due to prices		(11	)		—			(11	)		2			(9	)
Revisions other than price		36			1			37			—			37
Extensions and discoveries		70			—			70			1			71
Purchase of reserves		—			—			—			—			—
Production		(25	)		(1	)		(26	)		(4	)		(30	)
Sale of reserves		—			—			—			—			—

December 31, 2009		385			2			387			34			421
Revisions due to prices		14			—			14			(1	)		13
Revisions other than price		13			3			16			(1	)		15
Extensions and discoveries		68			—			68			2			70
Purchase of reserves		—			—			—			—			—
Production		(28	)		—			(28	)		(4	)		(32	)
Sale of reserves		(3	)		(5	)		(8	)		—			(8	)

December 31, 2010		449			—			449			30			479

Proved developed reserves as of:
December 31, 2007		243			1			244			30			274
December 31, 2008		260			1			261			31			292
December 31, 2009		293			1			294			32			326
December 31, 2010		353			—			353			28			381
Proved undeveloped reserves as of:
December 31, 2007		38			—			38			9			47
December 31, 2008		55			1			56			4			60
December 31, 2009		92			1			93			2			95
December 31, 2010		96			—			96			2			98

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Total (MMBoe)(1)
	U.S.			U.S.			Total						North
	Onshore			Offshore			U.S.			Canada			America

Proved developed and undeveloped reserves:
December 31, 2007		1,539			103			1,642			734			2,376
Revisions due to prices		(97	)		(3	)		(100	)		(387	)		(487	)
Revisions other than price		21			7			28			—			28
Extensions and discoveries		395			10			405			141			546
Purchase of reserves		66			—			66			—			66
Production		(146	)		(16	)		(162	)		(61	)		(223	)
Sale of reserves		(1	)		—			(1	)		(6	)		(7	)

December 31, 2008		1,777			101			1,878			421			2,299
Revisions due to prices		(113	)		1			(112	)		289			177
Revisions other than price		57			(8	)		49			(11	)		38
Extensions and discoveries		311			12			323			135			458
Purchase of reserves		—			—			—			1			1
Production		(154	)		(13	)		(167	)		(66	)		(233	)
Sale of reserves		—			(1	)		(1	)		(6	)		(7	)

December 31, 2009		1,878			92			1,970			763			2,733
Revisions due to prices		92			1			93			(21	)		72
Revisions other than price		32			1			33			5			38
Extensions and discoveries		269			2			271			83			354
Purchase of reserves		2			—			2			2			4
Production		(158	)		(5	)		(163	)		(65	)		(228	)
Sale of reserves		(8	)		(91	)		(99	)		(1	)		(100	)

December 31, 2010		2,107			—			2,107			766			2,873

Proved developed reserves as of:
December 31, 2007		1,290			59			1,349			476			1,825
December 31, 2008		1,449			59			1,508			367			1,875
December 31, 2009		1,486			53			1,539			383			1,922
December 31, 2010		1,696			—			1,696			346			2,042
Proved undeveloped reserves as of:
December 31, 2007		249			44			293			258			551
December 31, 2008		328			42			370			54			424
December 31, 2009		392			39			431			380			811
December 31, 2010		411			—			411			420			831


(1)		Gas reserves are converted to Boe at the rate of six Mcf per Bbl of oil, based upon the approximate relative energy content of gas and oil. This rate is not necessarily indicative of the relationship of natural gas and oil prices. Natural gas liquids reserves are converted to Boe on a one-to-one basis with oil.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Price Revisions

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

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

2008 — Due to significantly lower oil, gas and NGL prices as of December 31, 2008 compared to December 31, 2007, 487 MMBoe of reserves were not considered proved as of December 31, 2008. Of the 487 MMBoe price revisions, 331 MMBoe related to Jackfish.

The 487 MMBoe price revision also included 28 MMBoe related to Devon’s proved reserves in the Canadian province of Alberta. In December 2008, the provincial government of Alberta enacted a new royalty regime. The new regime for conventional oil, gas, NGL and heavy oil production was effective January 1, 2009. As a result of the newly enacted royalties, Devon’s proved reserves decreased as of December 31, 2008.

Revisions Other Than Price

Total revisions other than price for 2010, 2009 and 2008 primarily related to Devon’s drilling and development in the Barnett Shale.

Extensions and Discoveries

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

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

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

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

2008 — Of the 546 MMBoe of 2008 extensions and discoveries, 252 MMBoe related to the Barnett Shale, 101 MMBoe related to Jackfish, 44 MMBoe related to Carthage conventional, 21 MMBoe related to the Cana-Woodford Shale, 19 MMBoe related to the Lloydminster heavy oil development in Canada and 17 MMBoe related to the Arkoma-Woodford Shale area in southeastern Oklahoma.

The 2008 extensions and discoveries included 420 MMBoe related to additions from Devon’s infill drilling activities, including 243 MMBoe at the Barnett Shale, 101 MMBoe at Jackfish, 22 MMBoe at Carthage conventional, 18 MMBoe at Lloydminster and 11 MMBoe at the Cana-Woodford Shale.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Purchase of Reserves

The 2008 total included 34 MMBoe located in Utah and 27 MMBoe located in the Permian Basin.

Sale of Reserves

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

SEC’s Modernization of Oil and Gas Reporting

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

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

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

Prepared and Audited Reserves

Set forth below is a summary of the reserves that were evaluated, either by preparation or audit, by independent petroleum consultants for each of the years ended 2010, 2009 and 2008.


	2010					2009						2008
	Prepared		Audited			Prepared			Audited			Prepared			Audited

U.S. Onshore		—		94	%		—			93	%		—			92	%
U.S. Offshore		N/A		N/A			100	%		—			100	%		—
U.S.		—		94	%		5	%		89	%		5	%		87	%
Canada		—		89	%		—			91	%		—			78	%
North America		—		93	%		3	%		89	%		4	%		85	%

N/A Not applicable — Devon sold its U.S. Offshore properties during 2010.

“Prepared” reserves are those quantities of reserves that were prepared by an independent petroleum consultant. “Audited” reserves are those quantities of reserves that were estimated by Devon 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 2010, the U.S. reserves were evaluated by the independent petroleum consultants of LaRoche Petroleum Consultants, Ltd. In 2009 and 2008, the U.S. reserves were evaluated by the independent petroleum

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Standardized Measure

The tables below reflect the standardized measure of discounted future net cash flows related to Devon’s interest in proved reserves.


	Year Ended December 31, 2010
	United States			Canada			North America
	(In millions)

Future cash inflows	$	58,093		$	35,948		$	94,041
Future costs:
Development		(6,220	)		(4,526	)		(10,746	)
Production		(24,223	)		(12,249	)		(36,472	)
Future income tax expense		(8,643	)		(4,209	)		(12,852	)

Future net cash flows		19,007			14,964			33,971
10% discount to reflect timing of cash flows		(10,164	)		(7,455	)		(17,619	)

Standardized measure of discounted future net cash flows	$	8,843		$	7,509		$	16,352


	Year Ended December 31, 2009
	United States			Canada			North America
	(In millions)

Future cash inflows	$	44,571		$	28,442		$	73,013
Future costs:
Development		(6,814	)		(4,132	)		(10,946	)
Production		(22,184	)		(9,847	)		(32,031	)
Future income tax expense		(3,572	)		(3,408	)		(6,980	)

Future net cash flows		12,001			11,055			23,056
10% discount to reflect timing of cash flows		(6,121	)		(5,532	)		(11,653	)

Standardized measure of discounted future net cash flows	$	5,880		$	5,523		$	11,403


	Year Ended December 31, 2008
	United States			Canada			North America
	(In millions)

Future cash inflows	$	51,284		$	11,459		$	62,743
Future costs:
Development		(6,887	)		(1,623	)		(8,510	)
Production		(24,113	)		(5,742	)		(29,855	)
Future income tax expense		(5,585	)		(942	)		(6,527	)

Future net cash flows		14,699			3,152			17,851
10% discount to reflect timing of cash flows		(7,318	)		(1,140	)		(8,458	)

Standardized measure of discounted future net cash flows	$	7,381		$	2,012		$	9,393

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Future cash inflows, development costs and production costs were computed using the same assumptions for prices and costs that were used to estimate Devon’s proved oil and gas reserves at the end of each year. For 2010, the prices averaged $59.94 per barrel of oil, $3.73 per Mcf of gas and $31.11 per barrel of natural gas liquids. Of the $10,746 million of future development costs as of the end of 2010, $1,418 million, $1,447 million and $972 million are estimated to be spent in 2011, 2012 and 2013, respectively.

Future development costs include not only development costs, but also future dismantlement, abandonment and rehabilitation costs. Included as part of the $10,746 million of future development costs are $2,263 million of future dismantlement, abandonment and rehabilitation costs.

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

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


	Year Ended December 31,
	2010			2009			2008
	(In millions)

Beginning balance	$	11,403		$	9,393		$	20,582
Oil, gas and NGL sales, net of production costs		(4,982	)		(3,915	)		(9,177	)
Net changes in prices and production costs		7,423			(1,672	)		(13,839	)
Extensions and discoveries, net of future development costs		3,048			2,378			1,729
Purchase of reserves, net of future development costs		23			6			214
Development costs incurred that reduced future development costs		1,559			1,012			1,660
Revisions of quantity estimates		287			4,051			(1,294	)
Sales of reserves in place		(815	)		(37	)		(2	)
Accretion of discount		1,487			1,281			2,894
Net change in income taxes		(2,663	)		(51	)		4,934
Other, primarily changes in timing and foreign exchange rates		(418	)		(1,043	)		1,692

Ending balance	$	16,352		$	11,403		$	9,393

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


23.	Supplemental Quarterly Financial Information (Unaudited)

Following is a summary of the unaudited interim results of operations for the years ended December 31, 2010 and 2009.


	2010
	First		Second		Third		Fourth		Full
	Quarter		Quarter		Quarter		Quarter		Year
	(In millions, except per share amounts)

Revenues	$	3,220	$	2,232	$	2,353	$	2,135	$	9,940


Earnings from continuing operations before income taxes	$	1,588	$	613	$	699	$	668	$	3,568
Earnings from continuing operations	$	1,074	$	352	$	429	$	478	$	2,333
Earnings from discontinued operations		118		354		1,661		84		2,217

Net earnings	$	1,192	$	706	$	2,090	$	562	$	4,550

Basic net earnings per common share:
Earnings from continuing operations	$	2.40	$	0.79	$	0.99	$	1.10	$	5.31
Earnings from discontinued operations		0.27		0.80		3.82		0.20		5.04

Net earnings	$	2.67	$	1.59	$	4.81	$	1.30	$	10.35

Diluted net earnings per common share:
Earnings from continuing operations	$	2.39	$	0.79	$	0.98	$	1.10	$	5.29
Earnings from discontinued operations		0.27		0.79		3.81		0.19		5.02

Net earnings	$	2.66	$	1.58	$	4.79	$	1.29	$	10.31

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	2009
	First			Second		Third		Fourth		Full
	Quarter			Quarter		Quarter		Quarter		Year
	(In millions, except per share amounts)

Revenues	$	1,900		$	1,822	$	1,848	$	2,445	$	8,015


(Loss) earnings from continuing operations before income taxes	$	(6,162	)	$	299	$	471	$	866	$	(4,526	)
(Loss) earnings from continuing operations	$	(3,882	)	$	190	$	382	$	557	$	(2,753	)
(Loss) earnings from discontinued operations		(77	)		124		117		110		274

Net (loss) earnings	$	(3,959	)	$	314	$	499	$	667	$	(2,479	)

Basic net (loss) earnings per common share:
(Loss) earnings from continuing operations	$	(8.74	)	$	0.43	$	0.86	$	1.25	$	(6.20	)
(Loss) earnings from discontinued operations		(0.18	)		0.28		0.27		0.25		0.62

Net (loss) earnings	$	(8.92	)	$	0.71	$	1.13	$	1.50	$	(5.58	)

Diluted net (loss) earnings per common share:
(Loss) earnings from continuing operations	$	(8.74	)	$	0.42	$	0.86	$	1.25	$	(6.20	)
(Loss) earnings from discontinued operations		(0.18	)		0.28		0.26		0.24		0.62

Net (loss) earnings	$	(8.92	)	$	0.70	$	1.12	$	1.49	$	(5.58	)

Earnings (Loss) from Continuing Operations

The third quarter of 2010 includes restructuring costs that relate to Devon’s offshore asset divestitures and total $63 million ($40 million after income taxes, or $0.09 per diluted share).

The first quarter of 2009 includes a reduction of the carrying values of United States oil and gas properties totaling $6,408 million ($4,085 million after income taxes, or $9.20 per diluted share).

The fourth quarter of 2009 includes restructuring costs that relate to Devon’s planned asset divestitures and total $105 million ($67 million after income taxes, or $0.15 per diluted share).

Earnings (Loss) from Discontinued Operations

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

The third quarter of 2010 includes the divestiture of our Azerbaijan operations and the related gain was $1.541 million ($1.522 million after income taxes, or $3.49 per diluted share).

The first quarter of 2009 includes reductions of the carrying values of oil and gas properties totaling $109 million ($105 million after income taxes, or $0.24 per diluted share).

The fourth quarter of 2009 includes restructuring costs that relate to Devon’s planned asset divestitures and total $48 million ($31 million after income taxes, or $0.07 per diluted share).

140


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

Not Applicable.


Item 9A.	*Controls and Procedures*

Disclosure Controls and Procedures

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

Based on their evaluation, Devon’s principal executive and principal financial officers have concluded that Devon’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) were effective as of December 31, 2010 to ensure that the information required to be disclosed by Devon in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms.

Management’s Annual Report on Internal Control Over Financial Reporting

Devon’s management is responsible for establishing and maintaining adequate internal control over financial reporting for Devon, as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. Under the supervision and with the participation of Devon’s management, including our principal executive and principal financial officers, Devon conducted an evaluation of the effectiveness of its internal control over financial reporting based on the framework in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO Framework”). Based on this evaluation under the COSO Framework, which was completed on February 21, 2011, management concluded that its internal control over financial reporting was effective as of December 31, 2010.

The effectiveness of Devon’s internal control over financial reporting as of December 31, 2010 has been audited by KPMG LLP, an independent registered public accounting firm who audited Devon’s consolidated financial statements as of and for the year ended December 31, 2010, as stated in their report, which is included under “Item 8. Financial Statements and Supplementary Data.”

Changes in Internal Control Over Financial Reporting

There was no change in Devon’s internal control over financial reporting during the fourth quarter of 2010 that has materially affected, or is reasonably likely to materially affect, Devon’s internal control over financial reporting.


Item 9B.	*Other Information*

Danny Heatly, our Senior Vice President, Accounting and Chief Accounting Officer, has notified Devon of his retirement, effective March 4, 2011. In connection with Mr. Heatly’s retirement, Mr. Heatly and Devon entered into a Retirement Agreement, dated February 23, 2011 (the “Retirement Agreement”), in which Devon agreed to provide continued vesting of Mr. Heatly’s outstanding equity awards and Mr. Heatly made certain representations and covenants in favor of Devon. The Retirement Agreement is attached as Exhibit 10.21 to this Annual Report on Form 10-K.

Following Mr. Heatly’s retirement, Jeffrey A. Agosta, 43, Devon’s Executive Vice President and Chief Financial Officer will also serve as principal accounting officer.

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PART III


Item 10.	*Directors, Executive Officers and Corporate Governance*

The information called for by this Item 10 is incorporated hereby by reference to the definitive Proxy Statement to be filed by Devon pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 not later than April 30, 2011.


Item 11.	*Executive Compensation*

The information called for by this Item 11 is incorporated herein by reference to the definitive Proxy Statement to be filed by Devon pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 not later than April 30, 2011.


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

The information called for by this Item 12 is incorporated herein by reference to the definitive Proxy Statement to be filed by Devon pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 not later than April 30, 2011.


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

The information called for by this Item 13 is incorporated herein by reference to the definitive Proxy Statement to be filed by Devon pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 not later than April 30, 2011.


Item 14.	*Principal Accounting Fees and Services*

The information called for by this Item 14 is incorporated herein by reference to the definitive Proxy Statement to be filed by Devon pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 not later than April 30, 2011.

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PART IV


Item 15.	*Exhibits and Financial Statement Schedules*

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

1. Consolidated Financial Statements

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

2. Consolidated Financial Statement Schedules

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

3. Exhibits


Exhibit No.			Description

	1	.1	Underwriting Agreement, dated as of January 6, 2009, among Devon Energy Corporation and Banc of America Securities LLC, J.P. Morgan Securities Inc. and UBS Securities LLC, as representatives of the several Underwriters named therein (incorporated by reference to Exhibit 1.1 to Registrant’s Form 8-K filed on January 9, 2009).
	2	.1	Agreement and Plan of Merger, dated as of February 23, 2003, by and among Registrant, Devon NewCo Corporation, and Ocean Energy, Inc. (incorporated by reference to Registrant’s Amendment No. 1 to Form S-4 Registration No. 333-103679, filed March 20, 2003).
	2	.2	Amended and Restated Agreement and Plan of Merger, dated as of August 13, 2001, by and among Registrant, Devon NewCo Corporation, Devon Holdco Corporation, Devon Merger Corporation, Mitchell Merger Corporation and Mitchell Energy & Development Corp. (incorporated by reference to Annex A to Registrant’s Joint Proxy Statement/Prospectus of Form S-4 Registration Statement No. 333-68694 as filed August 30, 2001).
	2	.3	Offer to Purchase for Cash and Directors’ Circular dated September 6, 2001 (incorporated by reference to Registrant’s and Devon Acquisition Corporation’s Schedule 14D-1F filing, filed September 6, 2001).
	2	.4	Pre-Acquisition Agreement, dated as of August 31, 2001, between Registrant and Anderson Exploration Ltd. (incorporated by reference to Exhibit 2.2 to Registrant’s Registration Statement on Form S-4, File No. 333-68694 as filed September 14, 2001).
	2	.5	Amendment No. One, dated as of July 11, 2000, to Agreement and Plan of Merger by and among Registrant, Devon Merger Co. and Santa Fe Snyder Corporation dated as of May 25, 2000 (incorporated by reference to Exhibit 2.1 to Registrant’s Form 8-K filed on July 12, 2000).
	2	.6	Amended and Restated Agreement and Plan of Merger among Registrant, Devon Energy Corporation (Oklahoma), Devon Oklahoma Corporation and PennzEnergy Company dated as of May 19, 1999 (incorporated by reference to Exhibit 2.1 to Registrant’s Form S-4, File No. 333-82903).
	3	.1	Registrant’s Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 of Registrant’s Form 10-K filed on March 7, 2005).
	3	.2	Registrant’s Certificate of Amendment of Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 of Registrant’s Form 10-Q filed on August 7, 2008).
	3	.3	Registrant’s Bylaws (incorporated by reference to Exhibit 3.1 of Registrant’s Form 8-K filed on March 6, 2009).
	4	.1	Indenture, dated as of March 1, 2002, between Registrant and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to senior debt securities issuable by Registrant (the “Senior Indenture”) (incorporated by reference to Exhibit 4.1 of Registrant’s Form 8-K filed April 9, 2002).
	4	.2	Supplemental Indenture No. 1, dated as of March 25, 2002, to Indenture dated as of March 1, 2002, between Registrant and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to the 7.95% Senior Debentures due 2032 (incorporated by reference to Exhibit 4.2 to Registrant’s Form 8-K filed on April 9, 2002).

143


Exhibit No.			Description

	4	.3	Supplemental Indenture No. 3, dated as of January 9, 2009, to Indenture dated as of March 1, 2002, between Registrant and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to the 5.625% Senior Notes due 2014 and the 6.30% Senior Notes due 2019 (incorporated by reference to Exhibit 4.1 to Registrant’s Form 8-K filed on January 9, 2009).
	4	.4	Indenture dated as of October 3, 2001, by and among Devon Financing Corporation, U.L.C. as Issuer, Registrant as Guarantor, and The Bank of New York Mellon Trust Company, N.A., originally The Chase Manhattan Bank, as Trustee, relating to the 6.875% Senior Notes due 2011 and the 7.875% Debentures due 2031 (incorporated by reference to Exhibit 4.7 to Registrant’s Registration Statement on Form S-4, File No. 333-68694 as filed October 31, 2001).
	4	.5	Indenture dated as of July 8, 1998 among Devon OEI Operating, Inc. (as successor by merger to Ocean Energy, Inc.), its Subsidiary Guarantors, and Wells Fargo Bank Minnesota, N.A., as Trustee, relating to the 8.25% Senior Notes due 2018 (incorporated by reference to Exhibit 10.24 to the Form 10-Q for the period ended June 30, 1998 of Ocean Energy, Inc. (Registration No. 0-25058)).
	4	.6	First Supplemental Indenture, dated March 30, 1999 to Indenture dated as of July 8, 1998 among Devon OEI Operating, Inc. (as successor by merger to Ocean Energy, Inc.), its Subsidiary Guarantors, and Wells Fargo Bank Minnesota, N.A., as Trustee, relating to the 8.25% Senior Notes due 2018 (incorporated by reference to Exhibit 4.5 to Ocean Energy, Inc.’s Form 10-Q for the period ended March 31, 1999).
	4	.7	Second Supplemental Indenture, dated as of May 9, 2001 to Indenture dated as of July 8, 1998 among Devon OEI Operating, Inc. (as successor by merger to Ocean Energy, Inc.), its Subsidiary Guarantors, and Wells Fargo Bank Minnesota, N.A., as Trustee, relating to the 8.25% Senior Notes due 2018 (incorporated by reference to Exhibit 99.2 to Ocean Energy, Inc.’s Current Report on Form 8-K filed with the SEC on May 14, 2001).
	4	.8	Third Supplemental Indenture, dated January 23, 2006 to Indenture dated as of July 8, 1998 among Devon OEI Operating, Inc. as Issuer, Devon Energy Production Company, L.P. as Successor Guarantor, and Wells Fargo Bank Minnesota, N.A., as Trustee, relating to the 8.25% Senior Notes due 2018 (incorporated by reference to Exhibit 4.23 of Registrant’s Form 10-K for the year ended December 31, 2005).
	4	.9	Senior Indenture dated September 1, 1997, among Devon OEI Operating, Inc. (as successor by merger to Ocean Energy, Inc.) and The Bank of New York Mellon Trust Company, N.A., as Trustee, and Specimen of 7.50% Senior Notes (incorporated by reference to Exhibit 4.4 to Ocean Energy’s Annual Report on Form 10-K for the year ended December 31, 1997)).
	4	.10	First Supplemental Indenture, dated as of March 30, 1999 to Senior Indenture dated as of September 1, 1997, among Devon OEI Operating, Inc. (as successor by merger to Ocean Energy, Inc.) and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to the 7.50% Senior Notes Due 2027 (incorporated by reference to Exhibit 4.10 to Ocean Energy’s Form 10-Q for the period ended March 31, 1999).
	4	.11	Second Supplemental Indenture, dated as of May 9, 2001 to Senior Indenture dated as of September 1, 1997, among Devon OEI Operating, Inc. (as successor by merger to Ocean Energy, Inc.), its Subsidiary Guarantors, and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to the 7.50% Senior Notes Due 2027 (incorporated by reference to Exhibit 99.4 to Ocean Energy, Inc.’s Current Report on Form 8-K filed with the SEC on May 14, 2001).
	4	.12	Third Supplemental Indenture, dated December 31, 2005 to Senior Indenture dated as of September 1, 1997, among Devon OEI Operating, Inc. as Issuer, Devon Energy Production Company, L.P. as Successor Guarantor, and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to the 7.50% Senior Notes Due 2027 (incorporated by reference to Exhibit 4.27 of Registrant’s Form 10-K for the year ended December 31, 2005).
	10	.1	Amended and Restated Investor Rights Agreement, dated as of August 13, 2001, by and among Registrant, Devon Holdco Corporation, George P. Mitchell and Cynthia Woods Mitchell (incorporated by reference to Annex C to the Joint Proxy Statement/Prospectus of Form S-4 Registration Statement No. 333-68694 as filed August 30, 2001).

144


Exhibit No.			Description

	10	.2	First Amendment to Credit Agreement dated as of December 19, 2007, among Registrant as Borrower, Bank of America, N.A., individually and as Administrative Agent and the Lenders party thereto (incorporated by reference to Exhibit 10.3 to Registrant’s Form 10-K filed February 27, 2009).
	10	.3	Amended and Restated Credit Agreement dated March 24, 2006, effective as of April 7, 2006, among Registrant as US Borrower, Northstar Energy Corporation and Devon Canada Corporation as Canadian Borrowers, Bank of America, N.A. as Administrative Agent, Swing Line Lender and L/C Issuer; JPMorgan Chase Bank, N.A. as Syndication Agent, Bank of Montreal D/B/A “Harris Nesbitt”, Royal Bank of Canada, Wachovia Bank, National Association as Co-Documentation Agents and The Other Lenders Party Hereto, Banc of America Securities L.L.C. and J.P. Morgan Securities Inc., as Joint Lead Arrangers and Book Managers for the $2.0 billion five-year revolving credit facility (incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed on May 4, 2006).
	10	.4	First Amendment to Amended and Restated Credit Agreement dated as of June 1, 2006, among Registrant as the US Borrower, Northstar Energy Corporation and Devon Canada Corporation as the Canadian Borrowers, Bank of America, N.A., individually and as Administrative Agent and the Lenders party to this Amendment. (incorporated by reference to Exhibit 10.2 to Registrant’s Form 10-Q filed on November 7, 2007).
	10	.5	Second Amendment to Amended and Restated Credit Agreement dated as of September 19, 2007, among Registrant as the US Borrower, Northstar Energy Corporation and Devon Canada Corporation as the Canadian Borrowers, Bank of America, N.A., individually and as Administrative Agent and the Lenders party to this Amendment. (incorporated by reference to Exhibit 10.3 to Registrant’s Form 10-Q filed on November 7, 2007).
	10	.6	Third Amendment to Amended and Restated Credit Agreement dated as of December 19, 2007, among Registrant as the US Borrower, Northstar Energy Corporation and Devon Canada Corporation as the Canadian Borrowers, Bank of America, N.A., individually and as Administrative Agent and the Lenders party thereto (incorporated by reference to Exhibit 10.7 to Registrant’s Form 10-K filed February 27, 2009).
	10	.7	Fourth Amendment to Amended and Restated Credit Agreement dated as of April 7, 2008, among Registrant as US Borrower, Northstar Energy Corporation and Devon Canada Corporation as the Canadian Borrowers, Bank of America, N.A., individually and as Administrative Agent and the Lenders party thereto (incorporated by reference to Exhibit 10.1 of Registrant’s Form 10-Q filed on May 7, 2008).
	10	.8	Fifth Amendment to Amended and Restated Credit Agreement dated as of November 5, 2008, among Registrant as US Borrower, Northstar Energy Corporation and Devon Canada Corporation as the Canadian Borrowers, Bank of America, N.A., individually and as Administrative Agent, and the Lenders party thereto (incorporated by reference to Exhibit 10.2 of Registrant’s Form 10-Q filed on November 6, 2008).
	10	.9	Devon Energy Corporation 2009 Long-Term Incentive Plan (incorporated by reference to Registrant’s Form S-8 Registration No. 333-159796, filed June 5, 2009).*
	10	.10	Devon Energy Corporation 2005 Long-Term Incentive Plan (incorporated by reference to Registrant’s Form S-8 Registration No. 333-127630, filed August 17, 2005) .*
	10	.11	First Amendment to Devon Energy Corporation 2005 Long-Term Incentive Plan (incorporated by reference to Appendix A to Registrant’s Proxy Statement for the 2006 Annual Meeting of Stockholders filed on April 28, 2006).*
	10	.12	Devon Energy Corporation 2003 Long-Term Incentive Plan (incorporated by reference to Registrant’s Form S-8 Registration No. 333-104922, filed May 1, 2003).*
	10	.13	Devon Energy Corporation 1997 Stock Option Plan (as amended August 29, 2000) (incorporated by reference to Exhibit A to Registrant’s Proxy Statement for the 1997 Annual Meeting of Shareholders filed on April 3, 1997).*
	10	.14	Amended and Restated Form of Employment Agreement between Registrant and Jeffrey A. Agosta, David A. Hager, R. Alan Marcum, J. Larry Nichols, John Richels, Frank W. Rudolph, Darryl G. Smette, Lyndon C. Taylor and William F. Whitsitt dated December 15, 2008 (incorporated by reference to Exhibit 10.19 to Registrant’s Form 10-K filed February 27, 2009).*

145


Exhibit No.			Description

	10	.15	Form of Incentive Stock Option Award Agreement under the 2009 Long-Term Incentive Plan between Registrant and Jeffrey A. Agosta, David A. Hager, R. Alan Marcum, J. Larry Nichols, John Richels, Frank W. Rudolph, Darryl G. Smette, Lyndon C. Taylor and William F. Whitsitt for incentive stock options granted.*
	10	.16	Form of Employee Nonqualified Stock Option Award Agreement under the 2009 Long-Term Incentive Plan between Registrant and Jeffrey A. Agosta, David A. Hager, R. Alan Marcum, J. Larry Nichols, John Richels, Frank W. Rudolph, Darryl G. Smette, Lyndon C. Taylor and William F. Whitsitt for nonqualified stock options granted.*
	10	.17	Form of Non-Management Director Nonqualified Stock Option Award Agreement under the Devon Energy Corporation 2009 Long-Term Incentive Plan between Registrant and all Non-Management Directors for nonqualified stock options granted (incorporated by reference to Exhibit 10.20 to Registrant’s Form 10-K filed on February 25, 2010).*
	10	.18	Form of Restricted Stock Award Agreement under the 2009 Long-Term Incentive Plan between Registrant and Jeffrey A. Agosta, David A. Hager, R. Alan Marcum, J. Larry Nichols, John Richels, Frank W. Rudolph, Darryl G. Smette, Lyndon C. Taylor and William F. Whitsitt for restricted stock awards.*
	10	.19	Form of Restricted Stock Award Agreement under the 2009 Long-Term Incentive Plan between Registrant and all Non-Management Directors for restricted stock awards (incorporated by reference to Exhibit 10.22 to Registrant’s Form 10-K filed on February 25, 2010).*
	10	.20	Amended and Restated Severance Agreement between Registrant and Danny J. Heatly, dated December 15, 2008 (incorporated by reference to Exhibit 10.27 to Registrant’s Form 10-K filed on February 27, 2009).*
	10	.21	Retirement Agreement between Registrant and Danny J. Heatly, dated February 23, 2011.*
	10	.22	Form of Letter Agreement amending the restricted stock award agreements, nonqualified stock option agreements and incentive stock option agreements under the 2009 Long-Term Incentive Plan and the 2005 Long-Term Incentive Plan between Registrant and J. Larry Nichols, John Richels and Darryl G. Smette.*
	12		Statement of computations of ratios of earnings to fixed charges and to combined fixed charges and preferred stock dividends.
	21		Registrant’s Significant Subsidiaries.
	23	.1	Consent of KPMG LLP.
	23	.2	Consent of LaRoche Petroleum Consultants.
	23	.3	Consent of AJM Petroleum Consultants.
	31	.1	Certification of principal executive officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	31	.2	Certification of principal financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	32	.1	Certification of principal executive officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
	32	.2	Certification of principal financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
	99	.1	Report of LaRoche Petroleum Consultants.
	99	.2	Report of AJM Petroleum Consultants.
	101	.INS	XBRL Instance Document
	101	.SCH	XBRL Taxonomy Extension Schema Document
	101	.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
	101	.LAB	XBRL Taxonomy Extension Labels Linkbase Document
	101	.PRE	XBRL Taxonomy Extension Presentation Linkbase Document
	101	.DEF	XBRL Taxonomy Extension Definition Linkbase Document


*		Compensatory plans or arrangements

146

SIGNATURES

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

DEVON ENERGY CORPORATION


	By:	/s/ JOHN RICHELS

John Richels,

President and Chief Executive Officer

February 23, 2011

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



/s/ John Richels John Richels	President, Chief Executive Officer and Director	February 23, 2011

/s/ J. Larry Nichols J. Larry Nichols	Executive Chairman and Director	February 23, 2011

/s/ Jeffrey A. Agosta Jeffrey A. Agosta	Executive Vice President and Chief Financial Officer	February 23, 2011

/s/ Danny J. Heatly Danny J. Heatly	Senior Vice President — Accounting and Chief Accounting Officer	February 23, 2011

/s/ Robert H. Henry Robert H. Henry	Director	February 23, 2011

/s/ John A. Hill John A. Hill	Director	February 23, 2011

/s/ Michael M. Kanovsky Michael M. Kanovsky	Director	February 23, 2011

/s/ J. Todd Mitchell J. Todd Mitchell	Director	February 23, 2011

/s/ Robert A. Mosbacher, Jr. Robert A. Mosbacher, Jr.	Director	February 23, 2011

/s/ Duane C. Radtke Duane C. Radtke	Director	February 23, 2011

/s/ Mary P. Ricciardello Mary P. Ricciardello	Director	February 23, 2011

147

INDEX TO EXHIBITS


Exhibit No.			Description

	10	.15	Form of Incentive Stock Option Award Agreement under the 2009 Long-Term Incentive Plan between Registrant and Jeffrey A. Agosta, David A. Hager, R. Alan Marcum, J. Larry Nichols, John Richels, Frank W. Rudolph, Darryl G. Smette, Lyndon C. Taylor and William F. Whitsitt for incentive stock options granted.*
	10	.16	Form of Employee Nonqualified Stock Option Award Agreement under the 2009 Long-Term Incentive Plan between Registrant and Jeffrey A. Agosta, David A. Hager, R. Alan Marcum, J. Larry Nichols, John Richels, Frank W. Rudolph, Darryl G. Smette, Lyndon C. Taylor and William F. Whitsitt for nonqualified stock options granted.*
	10	.18	Form of Restricted Stock Award Agreement under the 2009 Long-Term Incentive Plan between Registrant and Jeffrey A. Agosta, David A. Hager, R. Alan Marcum, J. Larry Nichols, John Richels, Frank W. Rudolph, Darryl G. Smette, Lyndon C. Taylor and William F. Whitsitt for restricted stock awards.*
	10	.21	Retirement Agreement between Registrant and Danny J. Heatly, dated February 23, 2011.*
	10	.22	Form of Letter Agreement amending the restricted stock award agreements, nonqualified stock option agreements and incentive stock option agreements under the 2009 Long-Term Incentive Plan and the 2005 Long-Term Incentive Plan between Registrant and J. Larry Nichols, John Richels and Darryl G. Smette.*
	12		Statement of computations of ratios of earnings to fixed charges and to combined fixed charges and preferred stock dividends.
	21		Registrant’s Significant Subsidiaries.
	23	.1	Consent of KPMG LLP.
	23	.2	Consent of LaRoche Petroleum Consultants.
	23	.3	Consent of AJM Petroleum Consultants.
	31	.1	Certification of principal executive officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	31	.2	Certification of principal financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	32	.1	Certification of principal executive officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
	32	.2	Certification of principal financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
	99	.1	Report of LaRoche Petroleum Consultants.
	99	.2	Report of AJM Petroleum Consultants.
	101	.INS	XBRL Instance Document
	101	.SCH	XBRL Taxonomy Extension Schema Document
	101	.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
	101	.LAB	XBRL Taxonomy Extension Labels Linkbase Document
	101	.PRE	XBRL Taxonomy Extension Presentation Linkbase Document
	101	.DEF	XBRL Taxonomy Extension Definition Linkbase Document


*		Compensatory plans or arrangements

TABLE OF CONTENTS

Part Iprint Item 1. Businessprint Item 1A. Risk Factorsprint Item 1B. Unresolved Staff Commentsprint Item 2. Propertiesprint Item 3. Legal Proceedingsprint Item 4. Submission Of Matters To A Vote Of Security Holdersprint Part IIprint Item 5. Market For Common Equity, Related Stockholder Matters and Issuer Purchases Of Equity Securitiesprint Item 6. Selected Financial Dataprint Item 7. Management S Discussion and Analysis Of Financial Condition and Results Of Operationsprint Item 7A. Quantitative and Qualitative Disclosures About Market Riskprint Item 8. Financial Statements and Supplementary Dataprint Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosureprint Item 9A. Controls and Proceduresprint Item 9B. Other Informationprint Part IIIprint Item 10. Directors, Executive Officers and Corporate Governanceprint Item 11. Executive Compensationprint Item 12. Security Ownership Of Certain Beneficial Owners and Management and Related Stockholder Mattersprint Item 13. Certain Relationships and Related Transactions, and Director Independenceprint Item 14. Principal Accounting Fees and Servicesprint Part IVprint Item 15. Exhibits and Financial Statement Schedulesprint

Exhibits

EX-10.15 EX-10.16 EX-10.18 EX-10.21 EX-10.22 EX-12 EX-21 EX-23.1 EX-23.2 EX-23.3 EX-31.1 EX-31.2 EX-32.1 EX-32.2 EX-99.1 EX-99.2

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DVN 10-K Fiscal year ended Dec. 31, 2010