Table of Contents

 
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	

2

Table of Contents

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.	

3

Table of Contents

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.

4

Table of Contents
 
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,

5

Table of Contents

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.

6

Table of Contents

			
 	• 	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.

7

Table of Contents

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.	

8

Table of Contents

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;	

9

Table of Contents

			
 	• 	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.

10

Table of Contents

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

11

Table of Contents

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.	

12

Table of Contents

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.

13

Table of Contents

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.

14

Table of Contents

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;	

15

Table of Contents

			
 	• 	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

16

Table of Contents

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.

17

Table of Contents

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.

18

Table of Contents

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

19

Table of Contents

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

20

Table of Contents

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,

21

Table of Contents

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.
 
“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 our employees and audited by an independent petroleum consultant. The Society of Petroleum Engineers’ definition of an audit is an examination of a company’s proved oil and gas reserves and net cash flow by an independent petroleum

22

Table of Contents

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.	

23

Table of Contents

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

24

Table of Contents

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	

25

Table of Contents

			
		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	 	

26

Table of Contents

 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	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.	
27

Table of Contents

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.	

28

Table of Contents

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.

29

Table of Contents

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.

30

Table of Contents
 
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	 	

31

Table of Contents

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.

32

Table of Contents

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.	

33

Table of Contents

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,	

34

Table of Contents

			
 		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

35

Table of Contents

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

36

Table of Contents

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.

37

Table of Contents

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.	

38

Table of Contents

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	 	

39

Table of Contents

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.

40

Table of Contents

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.

41

Table of Contents

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.

42

Table of Contents

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

43

Table of Contents

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.

44

Table of Contents

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

45

Table of Contents

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	 	

46

Table of Contents

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

47

Table of Contents

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.

48

Table of Contents

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

49

Table of Contents

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	)%	

50

Table of Contents

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	 	

51

Table of Contents

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.”

52

Table of Contents

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.

53

Table of Contents

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.

54

Table of Contents

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.

55

Table of Contents

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

56

Table of Contents

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

57

Table of Contents

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.

58

Table of Contents

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	 	

59

Table of Contents

 
			
(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

60

Table of Contents

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.

61

Table of Contents

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

62

Table of Contents

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

63

Table of Contents

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

64

Table of Contents

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

65

Table of Contents

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 .

66

Table of Contents

 	 	 	 	 	
 	 	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	 	 	 	 	 	Weighted	 	
 	 	Volume	 	 	Floor Range	 	 	Average Price	 	 	Ceiling Range	 	 	Average Price	 	
Period	 	(Bbls/d)	 	 	($/Bbl)	 	 	($/Bbl)	 	 	($/Bbl)	 	 	($/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)	 	 	($/Bbl)	 	 	($/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.
67

Table of Contents

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.

68

Table of Contents

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

69

Table of Contents

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

70

Table of Contents

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

71

Table of Contents

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	 	 	 	 	 	Weighted	 	
 	 	Volume	 	 	Floor Range	 	 	Average Price	 	 	Ceiling Range	 	 	Average Price	 	
Period	 	(Bbls/d)	 	 	($/Bbl)	 	 	($/Bbl)	 	 	($/Bbl)	 	 	($/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

72

Table of Contents

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.

73

Table of Contents

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.

74

Table of Contents
 
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

75

Table of Contents

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.

76

Table of Contents

 
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.

77

Table of Contents

 
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.

78

Table of Contents

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.

79

Table of Contents

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.

80

Table of Contents

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

 	• 	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;	

81

Table of Contents

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

82

Table of Contents

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

83

Table of Contents

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

84

Table of Contents

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.

85

Table of Contents

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.
86

Table of Contents

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

87

Table of Contents

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	 	

88

Table of Contents

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	 	

89

Table of Contents

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	 	

90

Table of Contents

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.

91

Table of Contents

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.

92

Table of Contents

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.

93

Table of Contents

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

94

Table of Contents

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.

95

Table of Contents

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

96

Table of Contents

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	)	

97

Table of Contents

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.
98

Table of Contents

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	)	

99

Table of Contents

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.

100

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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	 	 	 	—	 	 	 	—	 	

101

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
 
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	 	

102

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
 
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.

103

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
 
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	 	

104

Table of Contents

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
 
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.

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.

105

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
 
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.
106

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
 
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

107

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
 
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.

108

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
 
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.

109

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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	 	

110

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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

111

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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.

112

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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	 	

113

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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	 	

 
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.

114

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.

115

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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.

116

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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

117

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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.

118

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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	 	

119

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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.

120

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
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.

121

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 	 	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

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
 
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

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
 
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

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
 
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

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
 
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

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
 
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

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
 
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

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
 
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

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
 
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

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
 
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	 	

131

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
 
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	 	

132

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
 
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	 	

133

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
 
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.	
134

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
 
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.

135

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
 
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

136

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
 
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	 	

137

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
 
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	 	

138

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
 
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	 	

 

139

Table of Contents

DEVON ENERGY CORPORATION AND SUBSIDIARIES
 
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

Table of Contents

		
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.

141

Table of Contents
 
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.

142

Table of Contents
 
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

Table of Contents

 	 	 	 	 	
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

Table of Contents

 	 	 	 	 	
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

Table of Contents

 	 	 	 	 	
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

Table of Contents
 
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

Table of Contents
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	

Exhibit 10.15

	 	Devon Energy Corporation
ID: 73-1567067
20 North Broadway
Oklahoma City, Oklahoma 73102-8260	
 
NOTICE OF GRANT OF INCENTIVE STOCK OPTIONS
AND AWARD AGREEMENT

 	 	 	
		
%%FIRST_NAME%-% %%MIDDLE_NAME%-% %%LAST_NAME%-% Option Number:	
%%OPTION_NUMBER%-%	 	 	
%%ADDRESS_LINE_1%-%	 	Plan: %%EQUITY_PLAN%-%	
%%ADDRESS_LINE_2%-%	 	ID: %%EMPLOYEE_IDENTIFIER%-%	
%%CITY%-%, %%STATE%-%, %%ZIPCODE%-%	 	 	
 
Effective %%OPTION_DATE%-% , you have been granted an Incentive Stock Option to buy %%TOTAL_SHARES_GRANTED%-% shares of Devon Energy Corporation (the “Company”) Common Stock at $%%OPTION_PRICE%-% per share. The Incentive Stock Option shall expire on %%EXPIRE_DATE_PERIOD1%-% (the “Expiration Date”).
Shares in each period will become fully vested on the date shown.
 	 	 	 	 	
Shares	 	Vest Type	 	Full Vest	
%%SHARES_PERIOD1%-%	 	%%VEST_TYPE_PERIOD1%-%	 	%%VEST_DATE_PERIOD1%-%	
%%SHARES_PERIOD2%-%	 	%%VEST_TYPE_PERIOD2%-%	 	%VEST_DATE_PERIOD2%-%	
%%SHARES_PERIOD3%-%	 	%%VEST_TYPE_PERIOD3%-%	 	%%VEST_DATE_PERIOD3%-%	
%%SHARES_PERIOD4%-%	 	%%VEST_TYPE_PERIOD4%-%	 	%%VEST_DATE_PERIOD4%-%	
%%SHARES_PERIOD5%-%	 	%%VEST_TYPE_PERIOD5%-%	 	%%VEST_DATE_PERIOD5%-%	
 
By accepting this agreement online, you and the Company agree that these options are granted under and governed by the terms and conditions of the Company’s 2009 Long-Term Incentive Plan and the Award Agreement, both of which are attached and made a part of this document.

 

DEVON ENERGY CORPORATION
2009 LONG-TERM INCENTIVE PLAN
INCENTIVE STOCK OPTION
AWARD AGREEMENT
     THIS INCENTIVE STOCK OPTION AWARD AGREEMENT (the “Award Agreement”), is entered into as of %%OPTION_DATE%-% (the “Date of Grant”), by and between Devon Energy Corporation (the “Company”) and %%FIRST_NAME%-% %%MIDDLE_NAME%-% %%LAST_NAME%-% (the “Participant”);
WITNESSETH:
     WHEREAS, the Participant is an employee of the Company or a Subsidiary or Affiliated Entity of the Company, and it is important to the Company that the Participant be encouraged to remain in the employ of the Company or a Subsidiary or Affiliated Entity of the Company, as applicable; and
     WHEREAS, in recognition of such facts, the Company desires to provide to the Participant an incentive stock option to purchase %%TOTAL_SHARES_GRANTED%-% shares of the Common Stock of the Company (the “Covered Shares”), as hereinafter provided, pursuant to the “Devon Energy Corporation 2009 Long-Term Incentive Plan” (the “Plan”), a copy of which is attached hereto.
     NOW, THEREFORE, in consideration of the mutual covenants hereinafter set forth and for good and valuable consideration, the Participant and the Company hereby agree as follows:
      Section 1. Grant of Incentive Stock Option . The Company hereby grants to the Participant an incentive stock option intended to qualify under Section 422 of the Code to purchase all or any part of the Covered Shares (the “Incentive Stock Option”), subject to the terms and conditions of this Award Agreement and the Plan, which is incorporated herein by reference and made a part hereof for all purposes. The purchase price for each Covered Share to be purchased hereunder shall be the exercise price set forth on the Cover Page (the “Exercise Price”).
      Section 2. Times of Exercise of Incentive Stock Option .
     (a) The Incentive Stock Option shall become fully vested and exercisable on and after the vesting date for each installment of Covered Shares as described in the following schedule (the “Vesting Date”) (but only if the Participant’s Date of Termination has not occurred before the Vesting Date):
Vesting Schedule
 	 	 	
Vesting Date	 	Covered Shares Vesting	
%%VEST_DATE_PERIOD1%-%	 	%%SHARES_PERIOD1%-%	
%%VEST_DATE_PERIOD2%-%	 	%%SHARES_PERIOD2%-%	
%%VEST_DATE_PERIOD3%-%	 	%%SHARES_PERIOD3%-%	
%%VEST_DATE_PERIOD4%-%	 	%%SHARES_PERIOD4%-%	
%%VEST_DATE_PERIOD5%-%	 	%%SHARES_PERIOD5%-%	

 

     (b) The Incentive Stock Option shall become fully vested and exercisable upon the occurrence of a Change of Control Event that occurs prior to the Participant’s Date of Termination.
     (c) If (i) the Participant’s Date of Termination occurs under circumstances in which the Participant is entitled to a severance payment from the Company, a Subsidiary, or an Affiliated Entity under (A) the Participant’s employment agreement or severance agreement with the Company due to a termination of the Participant’s employment by the Company without “cause” or by the Participant for “good reason” in accordance with the Participant’s employment agreement or severance agreement or (B) the Devon Energy Corporation Severance Plan and (ii) the Participant signs and returns to the Company a release of claims against the Company in a form prepared by the Company (the “Release”) and the Participant does not revoke the Release prior to the date the Release becomes effective, then the Incentive Stock Option shall become fully vested and exercisable effective as of the Participant’s Date of Termination. If the Participant fails to sign and return the Release to the Company or revokes the Release prior to the date the Release becomes effective, then the unvested portion of the Incentive Stock Option shall be forfeited.
     (d) The Incentive Stock Option shall become fully vested and exercisable upon the Participant’s Date of Termination if the Participant’s Date of Termination occurs by reason of the Participant’s death. The Committee may, in its sole and absolute discretion, elect to vest all or a portion of the unvested portion of the Incentive Stock Option upon the Participant’s Date of Termination if the Participant’s Date of Termination occurs by reason of disability, Normal Retirement Date, Early Retirement Date, or other special circumstances (as determined by the Committee).
     (e) The Incentive Stock Option may be exercised on or after the Participant’s Date of Termination only as to that portion of the Covered Shares for which it was exercisable immediately prior to such Date of Termination, or became exercisable upon the Date of Termination.
      Section 3. Term of Incentive Stock Option . The Incentive Stock Option shall expire and cease to be exercisable on the earliest to occur of:
     (a) The Expiration Date set forth on the Cover Page.
     (b) If the Participant’s Date of Termination occurs by reason of death, the three-year anniversary of such Date of Termination.
     (c) If the Participant’s Date of Termination occurs by reason of disability, and Section (d) below (relating to termination on or after Normal Retirement Date) does not apply, the one-year anniversary of such Date of Termination.
     (d) If the Participant’s Date of Termination occurs on or after the Participant’s Normal Retirement Date, the three-year anniversary of such Date of Termination.
     (e) If the Participant’s Date of Termination occurs on or after the Participant’s Early Retirement Date but prior to the Participant’s Normal Retirement Date, and Section (b) above (relating to termination because of death) does not apply, the one-year anniversary of such Date of Termination (or such later date as may be permitted by the Committee).
     (f) If the Participant’s Date of Termination occurs under circumstances in which the Participant is entitled to a severance payment from the Company, a Subsidiary of the Company, or an Affiliated Entity under an employment agreement or severance agreement

 

with the Company, the last day of the Severance Period. The “Severance Period” shall be the longer of:
(i) the period beginning on the Date of Termination and continuing through the end of the period during which such severance payments are paid to the Participant; or
(ii) the period described in the following clause (B), if the amount of the Participant’s severance payment is determined in whole or in part as being equal to the product of (A) the Participant’s salary rate, multiplied by (B) a period over which such amount would be computed.
     (g) If the Participant’s Date of Termination occurs and none of Sections (b), (c), (d), (e), and (f) are applicable, the three month anniversary of such Date of Termination.
The Participant should be aware that exercising an incentive stock option more than three months after the Date of Termination (one year in the case of termination by reason of certain disabilities) will generally result in the option being treated as a nonqualified option rather than an incentive stock option for tax purposes. The Participant should also be aware that if his or her employment is transferred to a limited liability company that is an Affiliated Entity that does not satisfy the definition of “company” or “subsidiary” in Section 424 of the Code, the transfer will be classified as a termination of employment for purposes of the incentive stock option rules regardless of whether it constitutes a Date of Termination under this Award Agreement. As a result, the option, if not exercised within three months of such transfer, will be treated as a nonqualified stock option rather than an incentive stock option for tax purposes. Regardless of classification of the option for tax purposes, this Award Agreement shall continue in full force and effect.
      Section 4. Nontransferability of Incentive Stock Option . The Incentive Stock Option shall not be transferable except by will or the laws of descent and distribution, and the Incentive Stock Option may be exercised during the lifetime of the Participant only by the Participant. Without limiting the generality of the previous sentence, the Incentive Stock Option may not be assigned, transferred (except as provided above), pledged or hypothecated in any way whatsoever, shall not be assignable by operation of law and shall not be subject to execution, attachment, or similar process. Any attempted assignment, transfer, pledge, hypothecation or other disposition of the Incentive Stock Option contrary to the provisions hereof shall be null and void and without effect.
      Section 5. Employment . So long as the Participant shall continue to be an employee of the Company or one or more of the Subsidiaries or Affiliated Entities of the Company, the Incentive Stock Option shall not be affected by any change of duties or position. Nothing in the Plan or in this Award Agreement shall confer upon the Participant any right to continue in the employ of the Company or its Subsidiaries or Affiliated Entities, or interfere in any way with the right to terminate the Participant’s employment at any time.
      Section 6. Annual Limitation on Exercise of Incentive Stock Options . Except as provided in Section 2(b) - (d) herein, in no event during any calendar year will the aggregate Fair Market Value, determined as of the Date of Grant, of the Covered Shares for which the Participant may first have the right to exercise under the Incentive Stock Option and any other “incentive stock options” granted under all plans qualified under Section 422 of the Code which are sponsored by the Company, its parent or its Subsidiaries or Affiliated Entities exceed $100,000.

 

      Section 7. Method of Exercising Incentive Stock Option.
     (a)  Procedures for Exercise . The Incentive Stock Option may be exercised prior to the Expiration Date by providing written notice in the form prescribed by the Company to the Secretary of the Company or following the electronic exercise procedures adopted by the Company. The written notice shall state the election to exercise the Incentive Stock Option, the number of Covered Shares to be purchased upon exercise, the form of payment, and shall be signed by the person exercising the Incentive Stock Option.
     (b)  Form of Payment . Payment of the full Exercise Price for the Covered Shares purchased under this Award Agreement shall accompany the Participant’s notice of exercise, together with full payment of applicable withholding taxes, if any. Payment shall be made (i) in cash or by check, draft or money order payable to the order of the Company; (ii) by delivering shares of Common Stock having a Fair Market Value on the date of payment equal to the amount of the Exercise Price, but only to the extent such form of payment would not result in a compensation expense to the Company for financial accounting purposes with respect to the shares of Common Stock used to pay the Exercise Price unless otherwise determined by the Committee; or (iii) a combination of the foregoing.
     (c)  Further Information . In the event the Incentive Stock Option is exercised, pursuant to the foregoing provisions of this Section 7, by any person other than the Participant due to the Participant’s death, such notice shall also be accompanied by appropriate proof of such person’s right to exercise the Incentive Stock Option. The notice so required shall be given electronically or by personal delivery to the Secretary of the Company or by registered or certified mail, addressed to the Company at 20 North Broadway, Oklahoma City, Oklahoma 73102-8260, and it shall be deemed to have been given when it is so delivered or when it is so deposited in the United States mail in an envelope addressed to the Company, as aforesaid, properly stamped for delivery as a registered or certified letter.
      Section 8. Securities Law Restrictions . The Incentive Stock Option shall be exercised and Common Stock issued only upon compliance with the Securities Act of 1933, as amended (the “Act”), and any other applicable securities law, or pursuant to an exemption therefrom. If deemed necessary by the Company to comply with the Act or any applicable laws or regulations relating to the sale of securities, the Participant, at the time of exercise and as a condition imposed by the Company, shall represent, warrant and agree that the Covered Shares subject to the Incentive Stock Option are being purchased for investment and not with any present intention to resell the same and without a view to distribution, and the Participant shall, upon the request of the Company, execute and deliver to the Company an agreement to such effect.
      Section 9. Disqualifying Disposition of Stock . If the Participant shall make a disposition (within the meaning of Section 424(c) of the Code) of any Covered Shares within one year after the date of exercise or within two years after the Date of Grant, then in either such event, the Participant shall promptly notify the Company, by delivery of written notice to the Secretary of the Company, of (i) the date of disposition, (ii) the number of Covered Shares which were disposed of and (iii) the price at which such Covered Shares were disposed of or the amount of any other consideration received on such disposition. The Company may make such provision as it may deem appropriate for the withholding of any applicable federal, state or local taxes that it determines it may be obligated to withhold or pay in connection with the exercise of the Incentive Stock Option or the disposition of Covered Shares acquired upon exercise of the Incentive Stock Option.
      Section 10. Notices . All notices or other communications relating to the Plan and this Award Agreement as it relates to the Participant shall be in writing and shall be delivered electronically, personally or mailed (U.S. Mail) by the Company to the Participant at the then

 

current address as maintained by the Company or such other address as the Participant may advise the Company in writing.
      Section 11. Definitions . Words, terms, or phrases used in this Agreement shall have the meanings set forth in this Section 11. Capitalized terms used in this Award Agreement but not defined herein shall have the meaning designated in the Plan.
     (a) “Act” has the meaning set forth in Section 8.
     (b) “Award Agreement” has the meaning set forth in the preamble.
     (c) “Code” means Internal Revenue Code of 1986, as amended.
     (d) “Company” has the meaning set forth on the Cover Page.
     (e) “Covered Shares” has the meaning set forth in the preamble.
     (f) “Date of Grant” has the meaning set forth in the preamble.
     (g) “Date of Termination” means the first day occurring on or after the Date of Grant on which the Participant is not employed by the Company, a Subsidiary, or an Affiliated Entity, regardless of the reason for the termination of employment; provided however, that a termination of employment shall not be deemed to occur by reason of a transfer of the Participant between the Company, a Subsidiary, and an Affiliated Entity or between two Subsidiaries or two Affiliated Entities. The Participant’s employment shall not be considered terminated while the Participant is on a leave of absence from the Company, a Subsidiary, or an Affiliated Entity approved by the Participant’s employer pursuant to Company policies. If, as a result of a sale or other transaction, the Participant’s employer ceases to be either a Subsidiary or an Affiliated Entity and the Participant is not, at the end of the 30-day period following the transaction, employed by the Company or an entity that is then a Subsidiary or an Affiliated Entity, then the date of the occurrence of such transaction shall be treated as the Participant’s Date of Termination.
     (h) “Early Retirement Date” means, with respect to the Participant, the first day of a month that occurs on or after the date the Participant (i) attains age 55 and (ii) earns at least 10 Years of Service.
     (i) “Exercise Price” has the meaning set forth in Section 1.
     (j) “Expiration Date” has the meaning set forth on the Cover Page.
     (k) “Incentive Stock Option” has the meaning set forth in Section 1.
     (l) “Normal Retirement Date” means, with respect to the Participant, the first day of a month that occurs on or after the date the Participant attains age 65.
     (m) “Participant” has the meaning set forth in the preamble.
     (n) “Plan” has the meaning set forth in the preamble.
     (o) “Vesting Date” has the meaning set forth in Section 2.
     (p) “Year of Service” means a calendar year in which the Participant is employed with the Company, a Subsidiary or Affiliated Entity for at least nine months of a calendar

 

year. When calculating Years of Service hereunder, Participant’s first hire date with the Company, a Subsidiary or Affiliated Entity shall be used.

“COMPANY”	 	DEVON ENERGY CORPORATION	
 	 	a Delaware corporation	
 	 	 	
“PARTICIPANT”	 	%%FIRST_NAME%-% %%MIDDLE_NAME%-% %LAST_NAME%-%	
 	 	%%ADDRESS_LINE_1%-%	
 	 	%%ADDRESS_LINE_2%-%	
 	 	%%CITY%-%, %%STATE%-%, %%ZIPCODE%-%	
 	 	ID %%EMPLOYEE_IDENTIFIER%-%	

Exhibit 10.16

	 	Devon Energy Corporation
ID: 73-1567067
20 North Broadway
Oklahoma City, Oklahoma 73102-8260	
 
NOTICE OF GRANT OF NONQUALIFIED STOCK OPTIONS
AND AWARD AGREEMENT

 	 	 	
		
%%FIRST_NAME%-% %%MIDDLE_NAME%-% %%LAST_NAME%-%	 	Option Number:	
%%OPTION_NUMBER%-%	 	 	
%%ADDRESS_LINE1%-%	 	Plan: %%EQUITY_PLAN%-%	
%%ADDRESS_LINE2%-%	 	ID: %%EMPLOYEE_IDENTIFIER%-%	
%%CITY%-%, %%STATE%-%, %%ZIPCODE%-%	 	 	
 
Effective %%OPTION_DATE%-% , you have been granted a Nonqualified Stock Option to buy %%TOTAL_SHARES_GRANTED%-% shares of Devon Energy Corporation (the “Company”) Common Stock at $%%OPTION_PRICE%-% per share. The Nonqualified Stock Option shall expire on %%EXPIRE_DATE_PERIOD1%-% (the “Expiration Date”).
Shares in each period will become fully vested on the date shown.
 	 	 	 	 	
Shares	 	Vest Type	 	Full Vest	
%%SHARES_PERIOD1%-%	 	%%VEST_TYPE_PERIOD1%-%	 	%%VEST_DATE_PERIOD1%-%	
%%SHARES_PERIOD2%-%	 	%%VEST_TYPE_PERIOD2%-%	 	%%VEST_DATE_PERIOD2%-%	
%%SHARES_PERIOD3%-%	 	%%VEST_TYPE_PERIOD3%-%	 	%%VEST_DATE_PERIOD3%-%	
%%SHARES_PERIOD4%-%	 	%%VEST_TYPE_PERIOD4%-%	 	%%VEST_DATE_PERIOD4%-%	
%%SHARES_PERIOD5%-%	 	%%VEST_TYPE_PERIOD5%-%	 	%%VEST_DATE_PERIOD5%-%	
 
By accepting this agreement online, you and the Company agree that these options are granted under and governed by the terms and conditions of the Company’s 2009 Long-Term Incentive Plan and the Award Agreement, both of which are attached and made a part of this document.

 

DEVON ENERGY CORPORATION
2009 LONG-TERM INCENTIVE PLAN
EMPLOYEE NONQUALIFIED STOCK OPTION
AWARD AGREEMENT
     THIS NONQUALIFIED STOCK OPTION AWARD AGREEMENT (the “Award Agreement”), is entered into as of %%OPTION_DATE%-% (the “Date of Grant”), by and between Devon Energy Corporation (the “Company”) and %%FIRST_NAME%-% %%MIDDLE_NAME%-% %%LAST_NAME%-% (the “Participant”);
WITNESSETH:
     WHEREAS, the Participant is an employee of the Company or a Subsidiary or Affiliated Entity of the Company, and it is important to the Company that the Participant be encouraged to remain in the employ of the Company or a Subsidiary or Affiliated Entity of the Company, as applicable; and
     WHEREAS, in recognition of such facts, the Company desires to provide to the Participant a nonqualified stock option to purchase %%TOTAL_SHARES_GRANTED%-% shares of the Common Stock of the Company (the “Covered Shares”), as hereinafter provided, pursuant to the “Devon Energy Corporation 2009 Long-Term Incentive Plan” (the “Plan”), a copy of which is attached hereto.
     NOW, THEREFORE, in consideration of the mutual covenants hereinafter set forth and for good and valuable consideration, the Participant and the Company hereby agree as follows:
      Section 1. Grant of Stock Option . The Company hereby grants to the Participant a nonqualified stock option that is not intended to qualify under Section 422 of the Code, to purchase all or any part of the Covered Shares (the “Stock Option”) subject to the terms and conditions of this Award Agreement and the Plan, which is incorporated herein by reference and made a part hereof for all purposes. The purchase price for each Covered Share to be purchased hereunder shall be the exercise price set forth on the Cover Page (the “Exercise Price”).
      Section 2. Times of Exercise of Stock Option .
     (a) The Stock Option shall become fully vested and exercisable on and after the vesting date for each installment of Covered Shares as described in the following schedule (the “Vesting Date”) (but only if the Participant’s Date of Termination has not occurred before the Vesting Date):
Vesting Schedule
 	 	 	
Vesting Date	 	Covered Shares Vesting	
%%VEST_DATE_PERIOD1%-%	 	%%SHARES_PERIOD1%-%	
%%VEST_DATE_PERIOD2%-%	 	%%SHARES_PERIOD2%-%	
%%VEST_DATE_PERIOD3%-%	 	%%SHARES_PERIOD3%-%	
%%VEST_DATE_PERIOD4%-%	 	%%SHARES_PERIOD4%-%	
%%VEST_DATE_PERIOD5%-%	 	%%SHARES_PERIOD5%-%	

 

     (b) The Stock Option shall become fully vested and exercisable upon the occurrence of a Change of Control Event that occurs (i) prior to the Participant’s Date of Termination or (ii) if the Participant has retired prior to such Change of Control Event, is Post-Retirement Eligible and no Non-Compliance Event has occurred, following the Participant’s Date of Termination.
     (c) If (i) the Participant’s Date of Termination occurs under circumstances in which the Participant is entitled to a severance payment from the Company, a Subsidiary, or an Affiliated Entity under (A) the Participant’s employment agreement or severance agreement with the Company due to a termination of the Participant’s employment by the Company without “cause” or by the Participant for “good reason” in accordance with the Participant’s employment agreement or severance agreement, or (B) the Devon Energy Corporation Severance Plan, and (ii) the Participant signs and returns to the Company a release of claims against the Company in a form prepared by the Company (the “Release”) and the Participant does not revoke the Release prior to the date the Release becomes effective, then the Stock Option shall become fully vested and exercisable effective as of the Participant’s Date of Termination. If the Participant fails to sign and return the Release to the Company or revokes the Release prior to the date the Release becomes effective, then the unvested portion of the Stock Option shall be forfeited.
     (d) The Stock Option shall become fully vested and exercisable upon the Participant’s Date of Termination if the Participant’s Date of Termination occurs by reason of the Participant’s death. The Committee may, in its sole and absolute discretion, elect to vest all or a portion of the unvested portion of the Stock Option upon the Participant’s Date of Termination if the Participant’s Date of Termination occurs by reason of disability, Normal Retirement Date, Early Retirement Date, or other special circumstances (as determined by the Committee).
     (e) Notwithstanding any provision to the contrary in this Award Agreement, if the Participant is Post-Retirement Eligible, the Participant shall, subject to the satisfaction of the conditions in Section 9, be eligible to vest, in accordance with the Vesting Schedule above in Section 2(a), in the installments of the Covered Shares of the Stock Option that remain unvested on the Date of Termination as follows:
 	 	 	 	 	
 	 	Percentage of each Unvested Installment	
 	 	of Covered Shares of the Stock Option	
Age at Retirement	 	Eligible to be Earned by the Participant	
 	
54 and earlier	 	 	0	%	
55	 	 	60	%	
56	 	 	65	%	
57	 	 	70	%	
58	 	 	75	%	
59	 	 	80	%	
60 and beyond	 	 	100	%	
     If (i) the Participant is Post-Retirement Eligible, (ii) the death of the Participant occurs following the Date of Termination, and (iii) no Non-Compliance Event has occurred prior to the date of the Participant’s death, then any percentages of installments of the Covered Shares of the Stock Option that remain unvested on the date of the Participant’s

 

death but in which the Participant was eligible to vest pursuant to this Section 2(e) shall become fully vested and exercisable upon the Participant’s death.
     Nothing in this Award Agreement shall be construed to affect the application of Section 12.5 of the Plan (relating to Change of Control), to the extent such Section would otherwise be applicable.
      Section 3. Term of Stock Option . The Stock Option shall expire and cease to be exercisable on the earliest to occur of:
     (a) The Expiration Date set forth on the Cover Page.
     (b) If the Participant’s Date of Termination occurs by reason of death, the three-year anniversary of such Date of Termination.
     (c) If the Participant’s Date of Termination occurs by reason of disability, and Section (d) below (relating to termination or after Normal Retirement Date) does not apply, the one-year anniversary of such Date of Termination.
     (d) If the Participant’s Date of Termination occurs by reason of Participant’s retirement and the Participant is Post-Retirement Eligible, the Expiration Date of the Stock Option; provided, however, if a Non-Compliance Event occurs following the Date of Termination, the Stock Option shall cease to be exercisable on the one-year anniversary of such Non-Compliance Event.
     (e) If (i) the Participant is Post-Retirement Eligible, (ii) the death of the Participant occurs following the Date of Termination, (iii) there are percentages of installments of the Covered Shares of the Stock Option that remain unvested as of the date of the Participant’s death but in which the Participant was eligible to vest pursuant to Section 2(e), and (iv) no Non-Compliance Event has occurred prior to the date of the Participant’s death, the three-year anniversary of the date of the Participant’s death.
     (f) If (i) the Participant’s Date of Termination occurs by reason of the Participant’s retirement, (ii) the Date of Termination occurs on or after the Participant’s Normal Retirement Date and (iii) the Participant is not Post-Retirement Eligible, the three-year anniversary of such Date of Termination (or such later date as may be permitted by the Committee).
     (g) If the Participant’s Date of Termination occurs under circumstances in which the Participant is entitled to a severance payment from the Company, a Subsidiary of the Company, or an Affiliated Entity under an employment agreement or severance agreement with the Company, the last day of the Severance Period. The “Severance Period” shall be the longer of:
(i) the period beginning on the Date of Termination and continuing through the end of the period during which such severance payments are paid to the Participant; or
(ii) the period described in the following clause (B), if the amount of the Participant’s severance payment is determined in whole or in part as being equal to the product of (A) the Participant’s salary rate, multiplied by (B) a period over which such amount would be computed.

 

     (h) If the Participant’s Date of Termination occurs and none of Sections (b), (c), (d), (e), (f) and (g) are applicable, the three month anniversary of such Date of Termination.
      Section 4. Nontransferability of Stock Option . The Stock Option may be exercised during the lifetime of the Participant only by the Participant. Without limiting the generality of the previous sentence, the Stock Option shall not be assigned, transferred (except as provided above), pledged or hypothecated in any way whatsoever, shall not be assigned by operation of law, and shall not be subject to execution, attachment or similar process. Any attempted assignment, transfer, pledge, hypothecation or other disposition of the Stock Option contrary to the provisions hereof, shall be null and void and without effect. However, in the event of a Participant’s death, the Stock Option may be transferred in accordance with the provisions of a Participant’s will, the applicable laws of descent and distribution, or a beneficiary designation that is in a form approved by the Committee.
      Section 5. Employment . So long as the Participant shall continue to be an employee of the Company or one or more of the Subsidiaries or Affiliated Entities of the Company, the Stock Option shall not be affected by any change of duties or position. Nothing in the Plan or in this Award Agreement shall confer upon the Participant any right to continue in the employ of the Company or any of its Subsidiaries or Affiliated Entities, or interfere in any way with the right to terminate the Participant’s employment at any time.
      Section 6. Method of Exercising Stock Option.
     (a)  Procedures for Exercise . The Stock Option may be exercised prior to the Expiration Date by providing written notice in the form prescribed by the Company to the Secretary of the Company or following the electronic exercise procedures adopted by the Company. The written notice shall state the election to exercise the Stock Option, the number of Covered Shares to be purchased upon exercise, the form of payment, and shall be signed by the person exercising the Stock Option.
     (b)  Form of Payment . Payment of the full Exercise Price for the Covered Shares purchased under this Award Agreement shall accompany the Participant’s notice of exercise, together with full payment of applicable withholding taxes, if any. Payment shall be made (i) in cash or by check, draft or money order payable to the order of the Company; (ii) by delivering shares of Common Stock having a Fair Market Value on the date of payment equal to the amount of the Exercise Price, but only to the extent such form of payment would not result in a compensation expense to the Company for financial accounting purposes with respect to the shares of Common Stock used to pay the Exercise Price unless otherwise determined by the Committee; or (iii) a combination of the foregoing.
     (c)  Further Information . In the event the Stock Option is exercised, pursuant to the foregoing provisions of this Section 6, by any person other than the Participant due to the Participant’s death, notice shall also be accompanied by appropriate proof of such person’s right to exercise the Stock Option. The notice so required shall be given electronically or by personal delivery to the Secretary of the Company or by registered or certified mail, addressed to the Company at 20 North Broadway, Oklahoma City, Oklahoma 73102-8260, Attention: Secretary, and it shall be deemed to have been given when it is delivered or when it is deposited in the United States mail in an envelope addressed to the Company, as aforesaid, properly stamped for delivery as a registered or certified letter.
      Section 7. Securities Law Restrictions . The Stock Option shall be exercised and Common Stock issued only upon compliance with the Securities Act of 1933, as amended (the “Act”), and any other applicable securities law, or pursuant to an exemption therefrom. If

 

deemed necessary by the Company to comply with the Act or any applicable laws or regulations relating to the sale of securities, the Participant, at the time of exercise and as a condition imposed by the Company, shall represent, warrant and agree that the Covered Shares subject to the Stock Option are being purchased for investment and not with any present intention to resell the same and without a view to distribution, and the Participant shall, upon the request of the Company, execute and deliver to the Company an agreement to such effect.
      Section 8. Notices . All notices or other communications relating to the Plan and this Award Agreement as it relates to the Participant shall be in writing and shall be delivered electronically, personally or mailed (U.S. Mail) by the Company to the Participant at the then current address as maintained by the Company or such other address as the Participant may advise the Company in writing.
      Section 9. Conditions to Post-Retirement Vesting .
     (a)  Notice of and Conditions to Post-Retirement Vesting . If the Participant is Post-Retirement Eligible, the Company shall, within a reasonable period of time prior to the Participant’s Date of Termination, notify the Participant that the Participant has the right, pursuant to this Section 9(a), to continue to vest following the Date of Termination in any unvested installments of Covered Shares of the Stock Option (each such unvested installment, an “Installment”). The Participant shall have the right to vest in such Installments of Covered Shares of the Stock Option provided that the Participant executes and delivers to the Company, with respect to each such Installment, the following documentation: (i) a non-disclosure letter agreement, in the form attached as Exhibit A, (a “Non-Disclosure Agreement”) on or before January 1 of the year in which such Installment vests pursuant to the Vesting Schedule (or, with respect to the calendar year in which the Date of Termination occurs, on or before the Date of Termination), and (ii) a compliance certificate, in the form attached as Exhibit B, (a “Compliance Certificate”) indicating the Participant’s full compliance with the Non-Disclosure Agreement on or before November 1 of the year in which such Installment vests pursuant to the Vesting Schedule.
     (b)  Consequences of Failure to Satisfy Vesting Conditions. In the event that, with respect to any given Installment, the Participant fails to deliver either the respective Non-Disclosure Agreement or Compliance Certificate for such Installment on or before the date required for the delivery of such document (such failure, a “Non-Compliance Event”), the Participant shall not be entitled to vest in any unvested Installments that would vest from and after the date of the Non-Compliance Event and the Company shall be authorized to take any and all such actions as are necessary to cause such unvested Stock Options to not vest and to terminate. The only remedy of the Company for failure to deliver a Non-Disclosure Agreement or a Compliance Certificate shall be the failure to vest in, and cancellation of, any unvested Installments then held by the Participant.
      Section 10. Definitions . Words, terms, or phrases used in this Agreement shall have the meanings set forth in this Section 10. Capitalized terms used in this Award Agreement but not defined herein shall have the meaning designated in the Plan.
     (a) “Act” has the meaning set forth in Section 7.
     (b) “Award Agreement” has the meaning set forth in the preamble.
     (c) “Code” means Internal Revenue Code of 1986, as amended.

 

     (d) “Company” has the meaning set forth on the Cover Page.
     (e) “Compliance Certificate” has the meaning set forth in Section 9(a).
     (f) “Covered Shares” has the meaning set forth in the preamble.
     (g) “Date of Grant” has the meaning set forth in the preamble.
     (h) “Date of Termination” means the first day occurring on or after the Date of Grant on which the Participant is not employed by the Company, a Subsidiary, or an Affiliated Entity, regardless of the reason for the termination of employment; provided, however, that a termination of employment shall not be deemed to occur by reason of a transfer of the Participant between the Company, a Subsidiary, and an Affiliated Entity or between two Subsidiaries or two Affiliated Entities. The Participant’s employment shall not be considered terminated while the Participant is on a leave of absence from the Company, a Subsidiary, or an Affiliated Entity approved by the Participant’s employer pursuant to Company policies. If, as a result of a sale or other transaction, the Participant’s employer ceases to be either a Subsidiary or an Affiliated Entity and the Participant is not, at the end of the 30-day period following the transaction, employed by the Company or an entity that is then a Subsidiary or an Affiliated Entity, then the date of the occurrence of such transaction shall be treated as the Participant’s Date of Termination.
     (i) “Early Retirement Date” means, with respect to the Participant, the first day of a month that occurs on or after the date the Participant (i) attains age 55 and (ii) earns at least 10 Years of Service.
     (j) “Exercise Price” has the meaning set forth in Section 1.
     (k) “Expiration Date” has the meaning set forth on the Cover Page.
     (l) “Installment” has the meaning set forth in Section 9(a).
     (m) “Non-Compliance Event” has the meaning set forth in Section 9(b).
     (n) “Non-Disclosure Agreement” has the meaning set forth in Section 9(a).
     (o) “Normal Retirement Date” means, with respect to the Participant, the first day of a month that occurs on or after the date the Participant attains age 65.
     (p) “Participant” has the meaning set forth in the preamble.
     (q) “Plan” has the meaning set forth in the preamble.
     (r) “Post-Retirement Eligible” means the Participant’s Date of Termination occurs (i) by reason of the Participant’s retirement and (ii) on or after the Participant’s Early Retirement Date.
     (s) “Stock Option” has the meaning set forth in Section 1.
     (t) “Vesting Date” has the meaning set forth in Section 2.
     (u) “Year of Service” means a calendar year in which the Participant is employed with the Company, a Subsidiary or Affiliated Entity for at least nine months of a calendar

 

year. When calculating Years of Service hereunder, Participant’s first hire date with the Company, a Subsidiary or Affiliated Entity shall be used.

“COMPANY”	 	DEVON ENERGY CORPORATION	
 	 	a Delaware corporation	
 	 	 	
“PARTICIPANT”	 	%%FIRST_NAME%-% %%MIDDLE_NAME%-% %%LAST_NAME%-%	
 	 	%%ADDRESS_LINE1%-%	
 	 	%%ADDRESS_LINE2%-%	
 	 	%%CITY%-%, %%STATE%-%, %%ZIPCODE%-%	
 	 	ID: %%EMPLOYEE_IDENTIFIER%-%	

 

EXHIBIT A
Form of Non-Disclosure Agreement
[Insert Date]
Devon Energy Corporation
20 North Broadway
Oklahoma City, OK 73102
          Re: Non-Disclosure Agreement
Ladies and Gentlemen:
     This letter agreement is entered between Devon Energy Corporation (together with its subsidiaries and affiliates, the “Company”) and the undersigned (the “Participant”) in connection with that certain Nonqualified Stock Option Award Agreement (the “Agreement”) dated _______________, 20__ between the Company and the Participant. All capitalized terms used in this letter agreement shall have the same meaning ascribed to them in the Agreement unless specifically denoted otherwise.
     The Participant acknowledges that, during the course of and in connection with the employment relationship between the Participant and the Company, the Company provided and the Participant accepted access to the Company’s trade secrets and confidential and proprietary information, which included, without limitation, information pertaining to the Company’s finances, oil and gas properties and prospects, compensation structures, business and litigation strategies and future business plans and other information or material that is of special and unique value to the Company and that the Company maintains as confidential and does not disclose to the general public, whether through its annual report and/or filings with the Securities and Exchange Commission or otherwise (the “Confidential Information”).
     The Participant acknowledges that his position with the Company was one of trust and confidence because of the access to the Confidential Information, requiring the Participant’s best efforts and utmost diligence to protect and maintain the confidentiality of the Confidential Information. Unless required by the Company or with the Company’s express written consent, the Participant will not, during the term of this letter agreement, directly or indirectly, disclose to others or use for his own benefit or the benefit of another any of the Confidential Information, whether or not the Confidential Information is acquired, learned, attained or developed by the Participant alone or in conjunction with others.
     The Participant agrees that, due to his access to the Confidential Information, the Participant would inevitably use and/or disclose that Confidential Information in breach of his confidentiality and non-disclosure obligations if the Participant worked in certain capacities or engaged in certain activities for a period of time following his employment with the Company, specifically in a position that involves (i) responsibility and decision-making authority or input at the executive level regarding any subject or responsibility, (ii) decision-making responsibility or input at any management level in the Participant’s individual area of assignment with the Company, or (iii) responsibility and decision-making

 

authority or input that otherwise allows the use of the Confidential Information (collectively referred to as the “Restricted Occupation”). Therefore, except with the prior written consent of the Company, during the term of this letter agreement, the Participant agrees not to be employed by, consult for or otherwise act on behalf of any person or entity in any capacity in which he would be involved, directly or indirectly, in a Restricted Occupation. The Participant acknowledges that this commitment is intended to protect the Confidential Information and is not intended to be applied or interpreted as a covenant against competition.
     The Participant further agrees that, during the term of this letter agreement, the Participant will not, directly or indirectly on behalf of a person or entity or otherwise, (i) solicit any of the established customers of the Company or attempt to induce any of the established customers of the Company to cease doing business with the Company, or (ii) solicit any of the employees of the Company to cease employment with the Company.
     This letter agreement shall become effective upon execution by the Participant and the Company and shall terminate on December 31, 20__. [NOTE: Insert date that is the end of the calendar year of the letter agreement.]
     If you agree to the above terms and conditions, please execute a copy of this letter agreement below and return a copy to me.

 	 	“PARTICIPANT”	 	 	

 	 	 
[Name of Participant]	 	 	
THE UNDERSIGNED HEREBY ACCEPTS AND AGREES TO THE TERMS SET FORTH ABOVE AS OF THIS ____ DAY OF ____________, ___.

 	 	“COMPANY”	 	 	
 	 	 	 	 	 	 	
 	 	DEVON ENERGY CORPORATION	 	 	
 	 	 	 	 	 	 	
 	 	By:	 	 	 	 	
 	 	Name:	 	 	 	 	
 	 	Title:	 	 	 	 	

 

EXHIBIT B
Form of Compliance Certificate
     I hereby certify that I am in full compliance with the covenants contained in that certain letter agreement (the “Agreement”) dated as of ____________, ____ between Devon Energy Corporation and me and have been in full compliance with such covenants at all times during the period ending October 31, ____.

 		
 	 	 
[Name of Participant]	 	 	
Dated:                     

Exhibit 10.18

	 	Devon Energy Corporation
ID: 73-1567067
20 North Broadway
Oklahoma City, Oklahoma 73102-8260	
 
NOTICE OF GRANT OF RESTRICTED STOCK AWARD
AND AWARD AGREEMENT

 	 	 	
		
%%FIRST_NAME%-% %%MIDDLE_NAME%-% %%LAST_NAME%-% Award Number :
%%OPTION_NUMBER%-%	
%%ADDRESS_LINE_1%-%	 	Plan: %%EQUITY_PLAN%-%	
%%ADDRESS_LINE_2%-%	 	ID: %%EMPLOYEE_IDENTIFIER%-%	
%%CITY%-%, %%STATE%-%, %%ZIPCODE%-%	 	 	
 
Effective «%%OPTION_DATE%-% , you have been granted a Restricted Stock Award of %%TOTAL_SHARES_GRANTED%-% shares of Devon Energy Corporation (the “Company”) Common Stock. These shares are restricted until the vesting date(s) shown below.
The award will vest in increments on the date(s) shown.
 	 	 	
Shares	 	Full Vest	
%%SHARES_PERIOD1%-%	 	%%VEST_DATE_PERIOD1%-%	
%%SHARES_PERIOD2%-%	 	%%VEST_DATE_PERIOD2%-%	
%%SHARES_PERIOD3%-%	 	%%VEST_DATE_PERIOD3%-%	
%%SHARES_PERIOD4%-%	 	%%VEST_DATE_PERIOD4%-%	
 
By accepting this agreement online, you and the Company agree that this award is granted under and governed by the terms and conditions of the Company’s 2009 Long-Term Incentive Plan and the Award Agreement, both of which are attached and made a part of this document.

 

DEVON ENERGY CORPORATION
2009 LONG-TERM INCENTIVE PLAN
RESTRICTED STOCK AWARD AGREEMENT
          THIS RESTRICTED STOCK AWARD AGREEMENT (the “Award Agreement”) is entered into as of %%OPTION_DATE%-% (the “Date of Grant”), by and between Devon Energy Corporation (the “Company”) and %%FIRST_NAME%-% %%MIDDLE_NAME%-% %%LAST_NAME%-% (the “Participant”);
W I T N E S S E T H:
          WHEREAS, the Company has previously adopted the “Devon Energy Corporation 2009 Long-Term Incentive Plan” (the “Plan”); and
          WHEREAS, in connection with the Participant’s employment with the Company, the Company desires to award to the Participant %%TOTAL_SHARES_GRANTED%-% shares of the Company’s Common Stock under the Plan subject to the terms and conditions of this Award Agreement; and
          NOW, THEREFORE, in consideration of the premises and the mutual promises and covenants herein contained, the Participant and the Company agree as follows:
          1. The Plan . The Plan, a copy of which is attached hereto, is hereby incorporated by reference herein and made a part hereof for all purposes, and when taken with this Award Agreement shall govern the rights of the Participant and the Company with respect to the Award.
          2. Grant of Award . The Company hereby grants to the Participant an award (the “Award”) of %%TOTAL_SHARES_GRANTED%-% shares of the Company’s Common Stock (the “Restricted Stock”), on the terms and conditions set forth herein and in the Plan.
          3. Terms of Award .
               (a)  Escrow of Shares . A certificate or book-entry registration representing the Restricted Stock shall be issued in the name of the Participant and shall be escrowed with the Secretary of the Company (the “Escrow Agent”) subject to removal of the restrictions placed thereon or forfeiture pursuant to the terms of this Award Agreement.
                (b) Vesting . Except as provided in this Section 3, if the Participant’s Date of Termination has not occurred as of the vesting dates specified below (the “Vesting Dates”), then, the Participant shall be entitled, subject to the applicable provisions of the Plan and this Award Agreement having been satisfied, to receive on or within a reasonable time after the applicable Vesting Dates the number of shares of Common Stock as described in the following schedule. Once vested pursuant to the terms of this Award Agreement, the Restricted Stock shall be deemed “Vested Stock.”
Vesting Schedule
 	 	 	
Vesting Dates	 	Shares Vesting	
%%VEST_DATE_PERIOD1%-%	 	%%SHARES_PERIOD1%-%	
%%VEST_DATE_PERIOD2%-%	 	%%SHARES_PERIOD2%-%	
%%VEST_DATE_PERIOD3%-%	 	%%SHARES_PERIOD3%-%	
%%VEST_DATE_PERIOD4%-%	 	%%SHARES_PERIOD4%-%	

 

The Participant shall forfeit the unvested portion of the Award (including the underlying Restricted Stock and Accrued Dividends) upon the occurrence of the Participant’s Date of Termination unless the Award becomes vested under the circumstances described in paragraphs (i), (ii), (iii) or (iv) below.
               (i) The Restricted Stock shall become fully vested upon the occurrence of a Change of Control Event that occurs (i) prior to the Participant’s Date of Termination or (ii) if the Participant has retired prior to such Change of Control Event, is Post-Retirement Eligible and no Non-Compliance Event has occurred, following the Participant’s Date of Termination.
               (ii) If (A) the Participant’s Date of Termination occurs under circumstances in which the Participant is entitled to a severance payment from the Company, a Subsidiary, or an Affiliated Entity under (1) the Participant’s employment agreement or severance agreement with the Company due to a termination of the Participant’s employment by the Company without “cause” or by the Participant for “good reason” in accordance with the Participant’s employment agreement or severance agreement or (2) the Devon Energy Corporation Severance Plan and (B) the Participant signs and returns to the Company a release of claims against the Company in a form prepared by the Company (the “Release”), the Restricted Stock shall become fully vested upon the date the Release becomes effective and the Restricted Stock shall be released within a reasonable time after the applicable Vesting Date. If the Participant fails to sign and return the Release to the Company or revokes the Release prior to the date the Release becomes effective, the unvested shares of Restricted Stock subject to this Award Agreement shall be forfeited.
               (iii) The Restricted Stock shall become fully vested upon the Participant’s Date of Termination if the Participant’s Date of Termination occurs by reason of the Participant’s death. The Committee may in its sole and absolute discretion, elect to vest all or a portion of the unvested Restricted Stock upon the Participant’s Date of Termination if the Participant’s Date of Termination occurs by reason of disability, Normal Retirement Date, Early Retirement Date, or other special circumstances (as determined by the Committee).
               (iv) Notwithstanding any provision to the contrary in this Agreement, if the Participant is Post-Retirement Eligible, the Participant shall, subject to the satisfaction of the conditions in Section 14, be eligible to vest in accordance with the Vesting Schedule above in Section 3(b), in the installments of Restricted Stock that remain unvested on the Date of Termination as follows:
 	 	 	 	 	
 	 	Percentage of each Unvested Installment of	
Age at Retirement	 	Restricted Stock Eligible to be Earned by the
Participant	
54 and earlier	 	 	0	%	
55	 	 	60	%	
56	 	 	65	%	
57	 	 	70	%	
58	 	 	75	%	
59	 	 	80	%	
60 and beyond	 	 	100	%	
     If (i) the Participant is Post-Retirement Eligible, (ii) the death of the Participant occurs following the Date of Termination, and (iii) no Non-Compliance Event has occurred prior to the date of the Participant’s death, then any percentages of installments of Restricted Stock that remain unvested on the date of the Participant’s death but in which the Participant was eligible to vest pursuant to this Section 3(b)(iv) shall become fully vested upon the Participant’s death.

 

               (c)  Voting Rights and Dividends . The Participant shall have all of the voting rights attributable to the shares of Restricted Stock. Regular quarterly cash dividends declared and paid by the Company with respect to the shares of Restricted Stock shall be paid to the Participant. Any extraordinary dividends declared and paid by the Company with respect to shares of Restricted Stock (the “Accrued Dividends”) shall not be paid to the Participant until such Restricted Stock becomes Vested Stock. Accrued Dividends shall be held by the Company as a general obligation and paid to the Participant at the time the underlying Restricted Stock becomes Vested Stock.
               (d)  Vested Stock — Removal of Restrictions . Upon Restricted Stock becoming Vested Stock, all restrictions shall be removed from the certificates or book-entry registrations and the Secretary of the Company shall deliver to the Participant certificates or a Direct Registration Statement for the book-entry registration representing such Vested Stock free and clear of all restrictions, except for any applicable securities laws restrictions, together with a check in the amount of all Accrued Dividends attributed to such Vested Stock without interest thereon.
          4. Legends . The shares of Restricted Stock which are the subject of this Award Agreement shall be subject to the following legend:
“THE SHARES OF STOCK EVIDENCED BY THIS CERTIFICATE OR BOOK-ENTRY REGISTRATION ARE SUBJECT TO AND ARE TRANSFERABLE ONLY IN ACCORDANCE WITH THAT CERTAIN AWARD AGREEMENT DATED %%OPTION_DATE%-% FOR THE DEVON ENERGY CORPORATION 2009 LONG-TERM INCENTIVE PLAN. ANY ATTEMPTED TRANSFER OF THE SHARES OF STOCK EVIDENCED BY THIS CERTIFICATE OR BOOK-ENTRY REGISTRATION IN VIOLATION OF SUCH AWARD AGREEMENT SHALL BE NULL AND VOID AND WITHOUT EFFECT. A COPY OF THE AWARD AGREEMENT MAY BE OBTAINED FROM THE SECRETARY OF DEVON ENERGY CORPORATION.”
          5. Delivery of Forfeited Shares . The Participant authorizes the Secretary to deliver to the Company any and all shares of Restricted Stock that are forfeited under the provisions of this Award Agreement. The Participant further authorizes the Company to hold as a general obligation of the Company any Accrued Dividends and to pay the Accrued Dividends to the Participant at the time the underlying Restricted Stock becomes Vested Stock.
          6. Employment. Nothing in the Plan or in this Award Agreement shall confer upon the Participant any right to continue in the employ of the Company or any of its Subsidiaries or Affiliated Entities, or interfere in any way with the right to terminate the Participant’s employment at any time.
          7. Nontransferability of Award . The Participant shall not have the right to sell, assign, transfer, convey, dispose, pledge, hypothecate, burden, encumber or charge any Restricted Stock or any interest therein in any manner whatsoever.
          8. Notices . All notices or other communications relating to the Plan and this Award Agreement as it relates to the Participant shall be in writing and shall be delivered electronically, personally or mailed (U.S. mail) by the Company to the Participant at the then current address as maintained by the Company or such other address as the Participant may advise the Company in writing.
          9. Binding Effect and Governing Law . This Award Agreement shall be (i) binding upon and inure to the benefit of the parties hereto and their respective heirs, successors and assigns except as may be limited by the Plan, and (ii) governed and construed under the laws of the State of Oklahoma.

 

          10. Withholding . The Company and the Participant shall comply with all federal and state laws and regulations respecting the required withholding, deposit and payment of any income, employment or other taxes relating to the Award (including Accrued Dividends). The Company shall withhold the employer’s minimum statutory withholding based upon minimum statutory withholding rates for federal and state purposes, including payroll taxes, that are applicable to such supplemental taxable income. Any payment of required withholding taxes by the Participant in the form of Common Stock shall not be permitted if it would result in an accounting charge with respect to such shares used to pay such taxes unless otherwise approved by the Committee.
          11. Award Subject to Claims of Creditors . The Participant shall not have any interest in any particular assets of the Company, its parent, if applicable, or any Subsidiary or Affiliated Entity by reason of the right to earn an Award (including Accrued Dividends) under the Plan and this Award Agreement, and the Participant or any other person shall have only the rights of a general unsecured creditor of the Company, its parent, if applicable, or a Subsidiary or Affiliated Entity with respect to any rights under the Plan or this Award Agreement.
          12. Captions . The captions of specific provisions of this Award Agreement are for convenience and reference only, and in no way define, describe, extend or limit the scope of this Award Agreement or the intent of any provision hereof.
          13. Counterparts . This Award Agreement may be executed in any number of identical counterparts, each of which shall be deemed an original for all purposes, but all of which taken together shall form one agreement.
          14. Conditions to Post-Retirement Vesting .
               (a)  Notice of and Conditions to Post-Retirement Vesting . If the Participant is Post-Retirement Eligible, the Company shall, within a reasonable period of time prior to the Participant’s Date of Termination, notify the Participant that the Participant has the right, pursuant to this Section 14(a), to continue to vest following the Date of Termination in any unvested installments of Restricted Stock (each such unvested installment, an “Installment”). The Participant shall have the right to vest in such Installments of Restricted Stock, provided that the Participant executes and delivers to the Company, with respect to each such Installment, the following documentation: (i) a non-disclosure letter agreement, in the form attached as Exhibit A, (a “Non-Disclosure Agreement”) on or before January 1 of the year in which such Installment vests pursuant to the Vesting Schedule (or, with respect to the calendar year in which the Date of Termination occurs, on or before the Date of Termination), and (ii) a compliance certificate, in the form attached as Exhibit B, (a “Compliance Certificate”) indicating the Participant’s full compliance with the Non-Disclosure Agreement on or before November 1 of the year in which such Installment vests pursuant to the Vesting Schedule.
               (b)  Consequences of Failure to Satisfy Vesting Conditions . In the event that, with respect to any given Installment, the Participant fails to deliver either the respective Non-Disclosure Agreement or Compliance Certificate for such Installment on or before the date required for the delivery of such document (such failure, a “Non-Compliance Event”), the Participant shall not be entitled to vest in any unvested Installments that would vest from and after the date of the Non-Compliance Event and the Company shall be authorized to take any and all such actions as are necessary to cause such unvested Restricted Stock to not vest and to terminate. The only remedy of the Company for failure to deliver a Non-Disclosure Agreement or a Compliance Certificate shall be the failure to vest in, and cancellation of, any unvested Installments then held by the Participant.

 

          15.  Definitions . Words, terms or phrases used in this Award Agreement shall have the meaning set forth in this Section 15. Capitalized terms used in this Award Agreement but not defined herein shall have the meaning designated in the Plan.
          (a) “Accrued Dividends” has the meaning set forth in Section 3(c).
          (b) “Award” has the meaning set forth in Section 2.
          (c) “Award Agreement” has the meaning set forth in the preamble.
          (d) “Company has the meaning set forth on the Cover Page.
          (e) “Compliance Certificate” has the meaning set forth in Section 14(a).
          (f) “Date of Grant” has the meaning set forth in the preamble.
          (g) “Date of Termination” means the first day occurring on or after the Date of Grant on which the Participant is not employed by the Company, a Subsidiary, or an Affiliated Entity regardless of the reason for the termination of employment; provided, however, that a termination of employment shall not be deemed to occur by reason of a transfer of the Participant between the Company, a Subsidiary, and an Affiliated Entity or between two Subsidiaries or two Affiliated Entities. The Participant’s employment shall not be considered terminated while the Participant is on a leave of absence from the Company, a Subsidiary, or an Affiliated Entity approved by the Participant’s employer pursuant to Company policies. If, as a result of a sale or other transaction, the Participant’s employer ceases to be either a Subsidiary or an Affiliated Entity, and the Participant is not, at the end of the 30-day period following the transaction, employed by the Company or an entity that is then a Subsidiary or Affiliated Entity, then the date of occurrence of such transaction shall be treated as the Participant’s Date of Termination.
          (h) “Early Retirement Date” means, with respect to the Participant, the first day of a month that occurs on or after the date the Participant (i) attains age 55 and (ii) earns at least 10 Years of Service.
          (i) “Escrow Agent” has the meaning set forth in Section 3(a).
          (j) “Installment” has the meaning set forth in Section 14(a).
          (k) “Non-Compliance Event” has the meaning set forth in Section 14(b).
          (l) “Non-Disclosure Agreement” has the meaning set forth in Section 14(a).
          (m) “Normal Retirement Date” means, with respect to the Participant, the first day of a month that occurs on or after the date the Participant attains age 65.
          (n) “Participant” has the meaning set forth in the preamble.
          (o) “Plan” has the meaning set forth in the preamble.
          (p) “Post-Retirement Eligible” means the Participant’s Date of Termination occurs (i) by reason of the Participant’s retirement and (ii) on or after the Participant’s Early Retirement Date.
          (q) “Restricted Stock” has the meaning set forth in Section 2.
          (r) “Vested Stock” has the meaning set forth in Section 3(b).

 

          (s) “Vesting Date” has the meaning set forth in Section 3(b).
          (t) “Year of Service” means a calendar year in which the Participant is employed with the Company, a Subsidiary or Affiliated Entity for at least nine months of a calendar year. When calculating Years of Service hereunder, Participant’s first hire date with the Company, a Subsidiary or Affiliated Entity shall be used.

“COMPANY”	 	DEVON ENERGY CORPORATION	
 	 	a Delaware corporation	
 	 	 	
“PARTICIPANT”	 	%%FIRST_NAME%-% %%MIDDLE_NAME%-% %%LAST_NAME%-%	
 	 	%%ADDRESS_LINE1%-%	
 	 	%%ADDRESS_LINE2%-%	
 	 	%%CITY%-%, %%STATE%-%, %%ZIPECODE%-%	
 	 	ID «ID»	

 

EXHIBIT A
Form of Non-Disclosure Agreement
[Insert Date]
Devon Energy Corporation
20 North Broadway
Oklahoma City, OK 73102

           Re:	 	Non-Disclosure Agreement	
Ladies and Gentlemen:
     This letter agreement is entered between Devon Energy Corporation (together with its subsidiaries and affiliates, the “Company”) and the undersigned (the “Participant”) in connection with that certain Amendment to Restricted Stock Award Agreements (the “Agreement”) dated _______________, 20___ between the Company and the Participant. All capitalized terms used in this letter agreement shall have the same meaning ascribed to them in the Agreement unless specifically denoted otherwise.
     The Participant acknowledges that, during the course of and in connection with the employment relationship between the Participant and the Company, the Company provided and the Participant accepted access to the Company’s trade secrets and confidential and proprietary information, which included, without limitation, information pertaining to the Company’s finances, oil and gas properties and prospects, compensation structures, business and litigation strategies and future business plans and other information or material that is of special and unique value to the Company and that the Company maintains as confidential and does not disclose to the general public, whether through its annual report and/or filings with the Securities and Exchange Commission or otherwise (the “Confidential Information”).
     The Participant acknowledges that his position with the Company was one of trust and confidence because of the access to the Confidential Information, requiring the Participant’s best efforts and utmost diligence to protect and maintain the confidentiality of the Confidential Information. Unless required by the Company or with the Company’s express written consent, the Participant will not, during the term of this letter agreement, directly or indirectly, disclose to others or use for his own benefit or the benefit of another any of the Confidential Information, whether or not the Confidential Information is acquired, learned, attained or developed by the Participant alone or in conjunction with others.
     The Participant agrees that, due to his access to the Confidential Information, the Participant would inevitably use and/or disclose that Confidential Information in breach of his confidentiality and non-disclosure obligations if the Participant worked in certain capacities or engaged in certain activities for a period of time following his employment with the Company, specifically in a position that involves (i) responsibility and decision-making authority or input at the executive level regarding any subject or responsibility, (ii) decision-making responsibility or input at any management level in

 

the Participant’s individual area of assignment with the Company, or (iii) responsibility and decision-making authority or input that otherwise allows the use of the Confidential Information (collectively referred to as the “Restricted Occupation”). Therefore, except with the prior written consent of the Company, during the term of this letter agreement, the Participant agrees not to be employed by, consult for or otherwise act on behalf of any person or entity in any capacity in which he would be involved, directly or indirectly, in a Restricted Occupation. The Participant acknowledges that this commitment is intended to protect the Confidential Information and is not intended to be applied or interpreted as a covenant against competition.
     The Participant further agrees that during the term of this letter agreement, the Participant will not, directly or indirectly on behalf of a person or entity or otherwise, (i) solicit any of the established customers of the Company or attempt to induce any of the established customers of the Company to cease doing business with the Company, or (ii) solicit any of the employees of the Company to cease employment with the Company.
     This letter agreement shall become effective upon execution by the Participant and the Company and shall terminate on December 31, 20__. [Note: Insert date that is the end of the calendar year of the letter agreement.]
     If you agree to the above terms and conditions, please execute a copy of this letter agreement below and return a copy to me.

 	 	“PARTICIPANT”	 	 	

 	 	 
[Name of Participant]	 	 	
THE UNDERSIGNED HEREBY ACCEPTS AND AGREES TO THE TERMS SET FORTH ABOVE AS OF THIS ____ DAY OF ____________, ___.

 	 	“COMPANY”	 	 	
 	 	 	 	 	 	 	
 	 	DEVON ENERGY CORPORATION	 	 	
 	 	 	 	 	 	 	
 	 	By:	 	 	 	 	
 	 	Name:	 	 	 	 	
 	 	Title:	 	 	 	 	

 

EXHIBIT B
Form of Compliance Certificate
     I hereby certify that I am in full compliance with the covenants contained in that certain letter agreement (the “Agreement”) dated as of ____________, ____ between Devon Energy Corporation and me and have been in full compliance with such covenants at all times during the period ending October 31, ____.

		
 	 	 	 	 
[Name of Participant]	 	 	
 	 	 	 	 	 	 	
Dated:	 	 	 	 	 	 	

   

Exhibit 10.21
RETIREMENT AGREEMENT
     This Retirement Agreement (the “ Agreement ”) is entered into as of February 23, 2011, by and between Danny J. Heatly (“ Employee ”) and Devon Energy Corporation (the “ Company ”).
RECITALS
     WHEREAS, Employee is employed by the Company as its Senior Vice President, Accounting and Chief Accounting Officer.
     WHEREAS, Employee and the Company have entered into an Amended and Restated Severance Agreement with an effective date of December 15, 2008 (the “ Severance Agreement ”).
     WHEREAS, Employee previously expressed to the Company his desire to retire on or around his 55 th birthday on December 7, 2010.
     WHEREAS, during discussions between Employee and the Company regarding the timing of Employee’s retirement, the Company requested that Employee consider delaying his retirement until after the preparation of the Company’s audited financial statements for fiscal year 2010 and the filing of the Company’s related Form 10-K with the Securities and Exchange Commission.
     WHEREAS, the parties desire to enter this Agreement to reflect their mutual undertakings, promises, and agreements concerning Employee’s retirement from the Company and benefits to Employee upon or by reason of such retirement.
     NOW, THEREFORE, in exchange for the valuable consideration paid or given under this Agreement, the receipt, adequacy, and sufficiency of which is hereby acknowledged, the parties knowingly and voluntarily agree to the following terms:
TERMS

1.	 	Retirement Date and Effect of Retirement . Capitalized terms not defined by this Agreement shall have the same meaning as defined by the Severance Agreement. Pursuant to paragraph 3(g) of the Severance Agreement, this Agreement constitutes Employee’s Notice of Termination to the Company that he desires to retire and terminate his employment with the Company without Good Reason. Such retirement shall result in a Separation from Service and shall be effective March 4, 2011 (the “ Retirement Date ”). Until the Retirement Date, Employee shall continue full-time employment with the Company and shall satisfactorily perform such job duties and such services for the Company as are requested from time to time by the Company’s Executive Vice President and Chief Financial Officer.	
 		
2.	 	Enforceability of Severance Agreement. Nothing in this Agreement shall be construed to limit, supersede, or cancel any of the Company’s or Employee’s rights or obligations under the Severance Agreement, which shall remain in full force and effect according to its terms.	

 

3.	 	Final Pay and Benefits . Upon Employee’s Separation from Service on the Retirement Date, Employee shall receive all Accrued Obligations in accordance with Paragraph 4(a) of the Severance Agreement. In addition, in consideration of Employee’s contributions to the Company during his employment and his decision to delay his retirement until the Retirement Date, any outstanding stock options, restricted stock awards or other equity-based compensation that have not fully vested on the Retirement Date (the “ Unvested Awards ”) shall continue to vest according to the vesting schedule originally set forth in the applicable award agreements covering the Unvested Awards (“ Post-Retirement Vesting ”). The Company and Employee hereby agree to effectuate the Employee’s Post-Retirement Vesting of Employee’s Unvested Awards by execution and delivery of amendments to Employee’s award agreements covering the Unvested Awards in the forms of Annexes A, B and C .	
 		
4.	 	Return of Property . Employee shall return to the Company any and all items of its property, including without limitation keys, badge/access cards, computers, software, cellular telephones and personal digital devices, calculators, equipment, credit cards, forms, files, manuals, correspondence, business records, personnel data, lists of employees, salary and benefits information, contracts, contract information, training materials, computer tapes and diskettes or other portable media, computer-readable files and data stored on any hard drive or other installed device, and data processing reports, and any and all other documents, property, or Confidential Information which he has had possession of or control over during his employment with the Company. Employee’s obligations under this paragraph shall not apply to, and Employee may retain a copy of, personnel, benefit, or payroll documents concerning only him.	
 		
5.	 	Waiver of Rights to Relief Not Provided in This Agreement . Employee shall and hereby does irrevocably waive any right to monetary recovery from the Company or its Affiliates, whether sought directly by him or any administrative agency or other public authority, individual, or group of individuals that should pursue any claim on his behalf; and he shall not request or accept from the Company or its Affiliates, as compensation or damages related to his employment or the termination of his employment with the Company, anything of value that is not provided for in this Agreement.	
 		
6.	 	Non-prosecution . Except as requested by the Company, or as permitted or compelled by law or judicial process, Employee shall not assist, cooperate with, or supply information of any kind to any individual, private-party litigant, governmental agency or their agents or attorneys (a) in any proceeding, investigation, or inquiry raising issues involving the Company or its Affiliates, or (b) in any other litigation against the Company or its Affiliates.	
 		
7.	 	No Violations . Employee represents that he has not informed the Company of, and that he is unaware of, any alleged violations of law, the Company’s standards of business conduct or personnel policies, or other misconduct by Company that have not been resolved satisfactorily by the Company.	
 		
8.	 	Governing Law; Severability; Interpretation . This Agreement and the rights and duties of the parties under it shall be governed by the laws of the State of Oklahoma, without regard to any conflicts of laws principles. If any provision of this Agreement is held to be unenforceable, such provision shall be considered separate, distinct, and	
 2 

 

 	 	severable from the other remaining provisions of this Agreement, and shall not affect the validity or enforceability of such other remaining provisions; and in all other respects, this Agreement shall remain in full force and effect. If any provision of this Agreement is held to be unenforceable as written but may be made to be enforceable by limitation, then such provision shall be enforceable to the maximum extent permitted by applicable law. The language of all parts of this Agreement shall in all cases be construed as a whole, according to its fair meaning, and not strictly for or against any of the parties.	

9.	 	Assignment . Employee’s obligations, rights, and benefits under this Agreement are personal to Employee and shall not be assigned to any person or entity without written permission from the Company. This Agreement shall be binding upon and inure to the benefit of the parties and their respective heirs, legal representatives, successors, and permitted assigns.	
 		
10.	 	Consultation With an Attorney . Employee has the right, and is encouraged by this paragraph, to consult with an attorney before signing this Agreement.	
 		
11.	 	Knowing and Voluntary Agreement . Employee acknowledges that (a) he has had a reasonable period in which to deliberate regarding the terms of this Agreement and to consider whether to sign this Agreement, (b) he fully understands the meaning and effect of signing this Agreement, and (c) his signing of this Agreement is knowing and voluntary. Employee further acknowledges that the Company has not made any promise or representation to him concerning this Agreement that is not expressed in this Agreement, and that in signing this Agreement, he is not relying on any statement or representation by Company, but is instead relying solely on his own judgment and consultation with his attorney, if any.	
 		
12.	 	Independent Consideration; Common-Law Duties . Whether expressly stated in this Agreement or not, all obligations Employee assumes and undertakings he makes by signing this Agreement are understood to be in consideration of the mutual promises and undertakings in this Agreement. Employee further acknowledges and agrees that his obligations under this Agreement supplement, rather than supplant, his common-law duties owed to the Company.	
 		
13.	 	Modification . No provision of this Agreement may be amended, modified, or waived unless such amendment, modification, or waiver is agreed to in writing and signed by Employee and by a duly authorized officer of the Company.	
 		
14.	 	Internal Revenue Code Section 409A; Consultation With a Tax Advisor . The parties have drafted this Agreement in accordance with Section 409A of the Internal Revenue Code and intend that it comply with Section 409A of the Code and any related rules, regulations, or other guidance. The parties further intend that this Agreement shall be interpreted and construed to comply with Section 409A of the Code. The parties agree to cooperate and work together in good faith to take all actions reasonably necessary to effectuate the intent of this paragraph. Notwithstanding the preceding sentence, Employee shall be solely responsible for any risk that the tax treatment of all or part of the Accrued Obligations or the Post-Retirement Vesting may be affected by Section 409A of the Code and impose significant adverse tax consequences on him, including accelerated taxation, a 20% additional tax, and interest. Because of the	
 3 

 

 	 	potential tax consequences, Employee has the right, and is encouraged by this paragraph, to consult with a tax advisor before signing this Agreement.	

15.	 	Paragraph Headings . The paragraph headings in this Agreement are for convenience of reference only, form no part of this Agreement, and shall not affect its interpretation.	
 		
16.	 	Counterparts . This Agreement may be executed in one or more counterparts, each of which shall be deemed an original and all of which together shall be considered one and the same agreement.	
 		
17.	 	Entire Agreement . This Agreement constitutes the entire agreement among the parties with respect to the subject matters hereof and supersede any and all prior or contemporaneous oral and written agreements and understandings with respect to such subject matters.	
[SIGNATURES APPEAR ON FOLLOWING PAGE]
 4 

 

     This RETIREMENT AGREEMENT has been executed and agreed to as of the date first written above.

DANNY J. HEATLY	 	DEVON ENERGY CORPORATION	 	 	
 	 	 	 	 	
      /s/ Danny J. Heatly	 	     /s/ Frank W. Rudolph	 	 	
 
Danny J. Heatly	 	 
Frank W. Rudolph	 	 	
 	 	Executive Vice President, Human Resources	 	 	
 5 

 

ANNEX A
AMENDMENT TO RESTRICTED STOCK AWARD AGREEMENT
UNDER THE
DEVON ENERGY CORPORATION 200__ LONG-TERM INCENTIVE PLAN
     THIS AMENDMENT TO RESTRICTED STOCK AWARD AGREEMENT (“Amendment”) is entered into as of the ____ day of ________, 2011 by and between Devon Energy Corporation, a Delaware corporation (the “Company”), and Danny J. Heatly (the “Participant”).
W I T N E S S E T H:
     WHEREAS, the Company and the Participant have previously entered into a certain Restricted Stock Award Agreement under the Devon Energy Corporation 200__ Long-Term Incentive Plan listed on Exhibit A (the “Agreement”), which granted to the Participant shares of Common Stock of the Company (the “Restricted Stock”) in exchange for the Participant’s performance of future services for the Company subject to the terms and conditions of the Agreement; and
     WHEREAS, the Company and the Participant desire to amend the Agreement with respect to vesting of the Restricted Stock following the date of retirement of the Participant under certain circumstances; and
     WHEREAS, Section 12.6 of the Plan permits the Compensation Committee of the Company’s Board of Directors (the “Committee”) to amend the Agreement; and
     WHEREAS, the Committee has approved the amendment of the Agreements as set forth herein.
     NOW, THEREFORE, for good and valuable consideration, the receipt of which is hereby acknowledged, the parties hereto agree that the Agreement is hereby amended as follows:

 	1.	 	The last sentence of Section 3(b) is amended to read as follows:	
 		
 	 	 	“The Participant shall forfeit the unvested portion of the Award (including the underlying Restricted Stock and “Accrued Dividends,” as such term is hereinafter defined) upon the occurrence of the Participant’s Date of Termination unless the Award becomes vested under the circumstances described in Sections 3(b)(i), (ii), (iii) or (iv) below.”	
 		
 	2.	 	The first sentence of Section 3(b)(i) is hereby amended to read as follows:	
 		
 	 	 	“The Restricted Stock shall become fully vested upon the occurrence of a Change of Control Event that occurs (A) prior to the Participant’s Date of Termination or (B) if the Participant has retired prior to such Change of Control Event, is Post-Retirement Eligible and no Non-Compliance Event has occurred, following the Participant’s Date of Termination.”	

 

 	3.	 	Section 3(b) is hereby amended to add a Section 3(b)(iv):	
 		
 	 	 	“(iv) Notwithstanding any provision to the contrary in this Agreement, if the Participant is Post-Retirement Eligible, the Participant shall, subject to the satisfaction of the conditions in Section 14, be eligible to vest in accordance with the Vesting Schedule above in Section 3(b), in the installments of Restricted Stock that remain unvested on the Date of Termination. If (i) the Participant is Post-Retirement Eligible, (ii) the death of the Participant occurs following the Date of Termination, and (iii) no Non-Compliance Event has occurred prior to the date of the Participant’s death, then any installments of Restricted Stock that remain unvested on the date of the Participant’s death but in which the Participant was eligible to vest pursuant to this Section 3(b)(iv) shall become fully vested upon the Participant’s death.”	
 		
 	4.	 	By adding a new Section 14 that provides as follows:	
 		
 	 	 	“14. Conditions to Post-Retirement Vesting .	

 	(a)	 	Notice of and Conditions to Post-Retirement Vesting. If the Participant is Post-Retirement Eligible, the Company shall, within a reasonable period of time prior to the Participant’s Date of Termination, notify the Participant that the Participant has the right, pursuant to this Section 14(a), to continue to vest following the Date of Termination in any unvested installments of Restricted Stock (each such unvested installment, an “Installment”). The Participant shall have the right to vest in such Installments of Restricted Stock provided that the Participant executes and delivers to the Company, with respect to each such Installment, the following documentation: (i) a non-disclosure letter agreement, in the form attached as Exhibit B, (a “Non-Disclosure Agreement”) on or before January 1 of the year in which such Installment vests pursuant to the Vesting Schedule (or, with respect to the calendar year in which the Date of Termination occurs, on or before the Date of Termination), and (ii) a compliance certificate, in the form attached as Exhibit C , (a “Compliance Certificate”) indicating the Participant’s full compliance with the Non-Disclosure Agreement on or before November 1 of the year in which such Installment vests pursuant to the Vesting Schedule.	
 		
 	(b)	 	Consequences of Failure to Satisfy Vesting Conditions. In the event that, with respect to any given Installment, the Participant fails to deliver either the respective Non-Disclosure Agreement or Compliance Certificate for such Installment on or before the date required for the delivery of such document (such failure, a “Non-Compliance Event”),	
ii

 

 	 	 	the Participant shall not be entitled to vest in any unvested Installments that would vest from and after the date of the Non-Compliance Event and the Company shall be authorized to take any and all such actions as are necessary to cause such unvested Restricted Stock to not vest and to terminate. The only remedy of the Company for failure to deliver a Non-Disclosure Agreement or a Compliance Certificate shall be the failure to vest in, and cancellation of, any unvested Installments then held by the Participant.”	

 	5.	 	Section 3 is hereby amended to add a Section 3(p):	
 		
 	 	 	“(f) Post-Retirement Eligible . For purposes of this Agreement, ‘Post-Retirement Eligible’ means the Participant’s Date of Termination occurs (i) by reason of the Participant’s retirement and (ii) on or after the Participant has attained age fifty-five (55) with ten (10) or more Years of Service, as that term is defined in the Retirement Plan for Employees of Devon Energy Corporation (the “Retirement Plan”).”	
     The Agreement is not amended in any respect except as herein provided. This Amendment is not intended and shall not be construed as increasing the aggregate number of shares of Common Stock granted under the Agreement.
     All capitalized terms used in this Amendment shall have the same meaning ascribed to them in the Plan and the Agreement unless specifically denoted otherwise.
[SIGNATURES APPEAR ON FOLLOWING PAGE]
iii

 

     IN WITNESS WHEREOF, the parties have executed this Amendment as of the day and year first above written.

“Company”	 	Devon Energy Corporation, a Delaware corporation	 	 	
 	 	 	 	 	 	 	
 	 	By:	 	 	 	 	
 	 	 	 	 	 	 	
“Participant”	 	 	 	 	 	 	
 	 	 	 	 	
 	 	Danny J. Heatly	 	 	
iv

 

EXHIBIT A
Restricted Stock Award Agreement
Subject to Amendment
[Insert list of agreements]

 

EXHIBIT B
Form of Non-Disclosure Agreement
[Insert Date]
Devon Energy Corporation
20 North Broadway
Oklahoma City, OK 73102
          Re: Non-Disclosure Agreement
Ladies and Gentlemen:
     This letter agreement is entered between Devon Energy Corporation (together with its subsidiaries and affiliates, the “Company”) and the undersigned (the “Participant”) in connection with that certain Amendment to Restricted Stock Award Agreements (the “Amendment”) dated _______________, __________ between the Company and the Participant. All capitalized terms used in this letter agreement shall have the same meaning ascribed to them in the Amendment unless specifically denoted otherwise.
     The Participant acknowledges that, during the course of and in connection with the employment relationship between the Participant and the Company, the Company provided and the Participant accepted access to the Company’s trade secrets and confidential and proprietary information, which included, without limitation, information pertaining to the Company’s finances, oil and gas properties and prospects, compensation structures, business and litigation strategies and future business plans and other information or material that is of special and unique value to the Company and that the Company maintains as confidential and does not disclose to the general public, whether through its annual report and/or filings with the Securities and Exchange Commission or otherwise (the “Confidential Information”).
     The Participant acknowledges that his position with the Company was one of trust and confidence because of the access to the Confidential Information, requiring the Participant’s best efforts and utmost diligence to protect and maintain the confidentiality of the Confidential Information. Unless required by the Company or with the Company’s express written consent, the Participant will not, during the term of this letter agreement, directly or indirectly, disclose to others or use for his own benefit or the benefit of another any of the Confidential Information, whether or not the Confidential Information is acquired, learned, attained or developed by the Participant alone or in conjunction with others.
     The Participant agrees that, due to his access to the Confidential Information, the Participant would inevitably use and/or disclose that Confidential Information in breach of his confidentiality and non-disclosure obligations if the Participant worked in certain capacities or engaged in certain activities for a period of time following his employment with the Company, specifically in a position that involves (i) responsibility and decision-making authority or input at the executive level regarding any subject or responsibility, (ii) decision-making responsibility or input at any management level in

 

the Participant’s individual area of assignment with the Company, or (iii) responsibility and decision-making authority or input that otherwise allows the use of the Confidential Information (collectively referred to as the “Restricted Occupation”). Therefore, except with the prior written consent of the Company, during the term of this letter agreement, the Participant agrees not to be employed by, consult for or otherwise act on behalf of any person or entity in any capacity in which he would be involved, directly or indirectly, in a Restricted Occupation. The Participant acknowledges that this commitment is intended to protect the Confidential Information and is not intended to be applied or interpreted as a covenant against competition.
     The Participant further agrees that during the term of this letter agreement, the Participant will not, directly or indirectly on behalf of a person or entity or otherwise, (i) solicit any of the established customers of the Company or attempt to induce any of the established customers of the Company to cease doing business with the Company, or (ii) solicit any of the employees of the Company to cease employment with the Company.
     This letter agreement shall become effective upon execution by the Participant and the Company and shall terminate on December 31, 200__. [Note: Insert date that is the end of the calendar year of the letter agreement.]
     If you agree to the above terms and conditions, please execute a copy of this letter agreement below and return a copy to me.

 	 	“PARTICIPANT”	 	 	

 	 	 
[Name of Participant]	 	 	
THE UNDERSIGNED HEREBY ACCEPTS AND AGREES TO THE TERMS SET FORTH ABOVE AS OF THIS ____ DAY OF ____________, ___.

 	 	“COMPANY”	 	 	
 	 	 	 	 	 	 	
 	 	DEVON ENERGY CORPORATION	 	 	
 	 	 	 	 	 	 	
 	 	By:	 	 	 	 	
 	 	Name:	 	 	 	 	
 	 	Title:	 	 	 	 	
 	 	 	 	 	 	 	
ii

 

EXHIBIT C
Form of Compliance Certificate
     I hereby certify that I am in full compliance with the covenants contained in that certain letter agreement (the “Agreement”) dated as of ____________, ____ between Devon Energy Corporation and me and have been in full compliance with such covenants at all times during the period ending October 31, ____.

 		
 	 	 
[Name of Participant]	 	 	
Dated:                                             

 

ANNEX B
AMENDMENT TO NONQUALIFIED STOCK OPTION AGREEMENT
UNDER THE
DEVON ENERGY CORPORATION 200__ LONG-TERM INCENTIVE PLAN
THIS AMENDMENT TO NONQUALIFIED STOCK OPTION AGREEMENT (“Amendment”) is entered into as of the ___ day of ______, 2011 by and between Devon Energy Corporation, a Delaware corporation (the “Company”), and Danny J. Heatly (the “Participant”).
W I T N E S S E T H:
     WHEREAS, the Company and the Participant have previously entered into a certain Nonqualified Stock Option Agreement under the Devon Energy Corporation 200__ Long-Term Incentive Plan listed on Exhibit A (the “Agreement”), which granted to the Participant options to purchase shares of Common Stock of the Company (the “Stock Options”) in exchange for the Participant’s performance of future services for the Company pursuant to the terms of the Agreement; and
     WHEREAS, the Company and the Participant desire to amend the Agreement with respect to the vesting and exercisability of the Stock Options following the date of retirement of the Participant under certain circumstances; and
     WHEREAS, Section 12.6 of the Plan permits the Compensation Committee of the Company’s Board of Directors (the “Committee”) to amend the Agreement; and
     WHEREAS, the Committee has approved the amendment of the Agreement as set forth herein.
     NOW, THEREFORE, for good and valuable consideration, the receipt of which is hereby acknowledged, the parties hereto agree that the Agreement is hereby amended as follows:

 	1.	 	The first sentence of Section 2(a) is hereby amended to read as follows:	
 		
 	 	 	“The Stock Option shall become fully vested and exercisable on and after the vesting date for each installment of Covered Shares as described in the following schedule (the “Vesting Date”) (but only if the Participant’s Date of Termination has not occurred before the Vesting Date):”	
 		
 	2.	 	Section 2(b) is hereby amended to read as follows:	
 		
 	 	 	“The Stock Option shall become fully vested and exercisable upon the occurrence of a Change of Control Event that occurs (i) prior to the Participant’s Date of Termination or (ii) if the Participant has retired prior to such Change of Control Event, is Post-Retirement Eligible and no Non-Compliance Event has occurred, following the Participant’s Date of Termination.”	

 

 	3.	 	Section 2 is hereby amended to add a Section 2(e):	
 		
 	 	 	“(e) Notwithstanding any provision to the contrary in this Award Agreement, if the Participant is Post-Retirement Eligible, the Participant shall, subject to the satisfaction of the conditions in Section 9, be eligible to vest, in accordance with the Vesting Schedule above in Section 2(a), in the installments of the Covered Shares of the Stock Option that remain unvested on the Date of Termination. If (i) the Participant is Post-Retirement Eligible, (ii) the death of the Participant occurs following the Date of Termination, and (iii) no Non-Compliance Event has occurred prior to the date of the Participant’s death, then any installments of the Covered Shares of the Stock Option that remain unvested on the date of the Participant’s death but in which the Participant was eligible to vest pursuant to this Section 2(e) shall become fully vested and exercisable upon the Participant’s death.”	
 		
 	4.	 	Section 3 is hereby amended to read as follows:	
 		
 	 	 	“ Term of Stock Option . The Stock Option shall cease to be exercisable on the earliest to occur of:	

 	(a)	 	The Expiration Date set forth on the Cover Page.	
 		
 	(b)	 	If the Participant’s Date of Termination occurs by reason of death, the three-year anniversary of such Date of Termination.	
 		
 	(c)	 	If the Participant’s Date of Termination occurs by reason of Disability, the one-year anniversary of such Date of Termination.	
 		
 	(d)	 	If the Participant’s Date of Termination occurs on or after the Participant’s Early Retirement Date or on or after the Participant’s Normal Retirement Date, and Sections (b) and (e) do not apply, the one-year anniversary of such Date of Termination (or such later date as may be permitted by the Committee).	
 		
 	(e)	 	If the Participant’s Date of Termination occurs by reason of the Participant’s retirement and the Participant is Post-Retirement Eligible, the Expiration Date of the Stock Option; provided, however, if a Non-Compliance Event occurs following such Date of Termination, the Stock Option shall cease to be exercisable on the one-year anniversary of such Non-Compliance Event.	
 		
 	(f)	 	If (i) the Participant is Post-Retirement Eligible, (ii) the death of the Participant occurs following the Date of Termination, (iii) there are installments of the Covered Shares of the Stock Option that remain unvested as of the date of the Participant’s death but in which the Participant was eligible to vest pursuant to Section 2(e), and (iv) no Non-Compliance Event has occurred prior to the date of the	
ii

 

 	 	 	Participant’s death, the three-year anniversary of the date of the Participant’s death.	
 		
 	(g)	 	If the Participant’s Date of Termination occurs under circumstances in which the Participant is entitled to severance benefits from the Company, a Subsidiary of the Company, or an Affiliated Entity under an employment agreement or severance agreement, the last day of the Severance Period. The “Severance Period” shall be the longer of:	

 	(i)	 	the period beginning on the Date of Termination and continuing through the end of the period during which such severance benefits are paid to the Participant; or	
 		
 	(ii)	 	the period described in the following clause (b), if the amount of the Participant’s severance benefits is determined in whole or in part as being equal to the product of (a) the Participant’s salary rate, multiplied by (b) a period over which such benefit would be computed.	

 	(h)	 	If the Participant’s Date of Termination occurs and Sections (b), (c), (d), (e), (f) and (g) are not applicable, the three-month anniversary of such Date of Termination.”	

 	5.	 	By adding a new Section 9 that provides as follows:	
 		
 	 	 	“9. Conditions to Post-Retirement Vesting .	

 	(a)	 	Notice of and Conditions to Post-Retirement Vesting . If the Participant is Post-Retirement Eligible, the Company shall, within a reasonable period of time prior to the Participant’s Date of Termination, notify the Participant that the Participant has the right, pursuant to this Section 9(a), to continue to vest following the Date of Termination in any unvested installments of Covered Shares of the Stock Option (each such unvested installment, an “Installment”). The Participant shall have the right to vest in such Installments of Covered Shares of the Stock Option provided that the Participant executes and delivers to the Company, with respect to each such Installment, the following documentation: (i) a non-disclosure letter agreement, in the form attached as Exhibit B, (a “Non-Disclosure Agreement”) on or before January 1 of the year in which such Installment vests pursuant to the Vesting Schedule (or, with respect to the calendar year in which the Date of Termination occurs, on or before the Date of Termination), and (ii) a compliance certificate, in the form attached as Exhibit C, (a “Compliance Certificate”) indicating the Participant’s full compliance with the Non-Disclosure Agreement on or before November 1 of the year in which such Installment vests pursuant to the Vesting Schedule.	
iii

 

 	(b)	 	Consequences of Failure to Satisfy Vesting Conditions. In the event that, with respect to any given Installment, the Participant fails to deliver either the respective Non-Disclosure Agreement or Compliance Certificate for such Installment on or before the date required for the delivery of such document (such failure, a “Non-Compliance Event”), the Participant shall not be entitled to vest in any unvested Installments that would vest from and after the date of the Non-Compliance Event and the Company shall be authorized to take any and all such actions as are necessary to cause such unvested Stock Options to not vest and to terminate. The only remedy of the Company for failure to deliver a Non-Disclosure Agreement or a Compliance Certificate shall be the failure to vest in, and cancellation of, any unvested Installments then held by the Participant.”	

 	6.	 	Section 10 is hereby amended by adding a new definition in Section 10(r) as follows:	
 		
 	 	 	““Post-Retirement Eligible” means the Participant’s Date of Termination occurs (i) by reason of the Participant’s retirement and (ii) on or after the Participant has attained age fifty-five (55) with ten (10) or more Years of Service, as that term is defined in the Retirement Plan.”	
     The Agreement is not amended in any respect except as herein provided. This Amendment is not intended and shall not be construed as increasing the aggregate number of shares of Common Stock subject to the Stock Options under the Agreement.
     All capitalized terms used in this Amendment shall have the same meaning ascribed to them in the Plan and the Agreement unless specifically denoted otherwise.
[SIGNATURES APPEAR ON FOLLOWING PAGE]
iv

 

     IN WITNESS WHEREOF, the parties have executed this Amendment as of the day and year first above written.

“Company”	 	Devon Energy Corporation, a Delaware corporation	 	 	
 	 	 	 	 	 	 	
 	 	By:	 	 	 	 	
 	 	 	 	 	 	 	
“Participant”	 	 	 	 	 	 	
 	 	 	 	 	
 	 	Danny J. Heatly	 	 	
v 

 

EXHIBIT A
Nonqualified Stock Option Agreements
Subject to Amendment
[Insert list of agreements]

 

EXHIBIT B
Form of Non-Disclosure Agreement
[Insert Date]
Devon Energy Corporation
20 North Broadway
Oklahoma City, OK 73102
          Re: Non-Disclosure Agreement
Ladies and Gentlemen:
     This letter agreement is entered between Devon Energy Corporation (together with its subsidiaries and affiliates, the “Company”) and the undersigned (the “Participant”) in connection with that certain Amendment to Nonqualified Stock Option Agreements (the “Amendment”) dated _______________, _______ between the Company and the Participant. All capitalized terms used in this letter agreement shall have the same meaning ascribed to them in the Amendment unless specifically denoted otherwise.
     The Participant acknowledges that, during the course of and in connection with the employment relationship between the Participant and the Company, the Company provided and the Participant accepted access to the Company’s trade secrets and confidential and proprietary information, which included, without limitation, information pertaining to the Company’s finances, oil and gas properties and prospects, compensation structures, business and litigation strategies and future business plans and other information or material that is of special and unique value to the Company and that the Company maintains as confidential and does not disclose to the general public, whether through its annual report and/or filings with the Securities and Exchange Commission or otherwise (the “Confidential Information”).
     The Participant acknowledges that his position with the Company was one of trust and confidence because of the access to the Confidential Information, requiring the Participant’s best efforts and utmost diligence to protect and maintain the confidentiality of the Confidential Information. Unless required by the Company or with the Company’s express written consent, the Participant will not, during the term of this letter agreement, directly or indirectly, disclose to others or use for his own benefit or the benefit of another any of the Confidential Information, whether or not the Confidential Information is acquired, learned, attained or developed by the Participant alone or in conjunction with others.
     The Participant agrees that, due to his access to the Confidential Information, the Participant would inevitably use and/or disclose that Confidential Information in breach of his confidentiality and non-disclosure obligations if the Participant worked in certain capacities or engaged in certain activities for a period of time following his employment with the Company, specifically in a position that involves (i) responsibility and decision-making authority or input at the executive level regarding any subject or responsibility, (ii) decision-making responsibility or input at any management level in the Participant’s individual area of assignment with the Company, or (iii) responsibility and decision-making

 

authority or input that otherwise allows the use of the Confidential Information (collectively referred to as the “Restricted Occupation”). Therefore, except with the prior written consent of the Company, during the term of this letter agreement, the Participant agrees not to be employed by, consult for or otherwise act on behalf of any person or entity in any capacity in which he would be involved, directly or indirectly, in a Restricted Occupation. The Participant acknowledges that this commitment is intended to protect the Confidential Information and is not intended to be applied or interpreted as a covenant against competition.
     The Participant further agrees that, during the term of this letter agreement, the Participant will not, directly or indirectly on behalf of a person or entity or otherwise, (i) solicit any of the established customers of the Company or attempt to induce any of the established customers of the Company to cease doing business with the Company, or (ii) solicit any of the employees of the Company to cease employment with the Company.
     This letter agreement shall become effective upon execution by the Participant and the Company and shall terminate on December 31, 200_. [NOTE: Insert date that is the end of the calendar year of the letter agreement.]
     If you agree to the above terms and conditions, please execute a copy of this letter agreement below and return a copy to me.

 	 	“PARTICIPANT”	 	 	

 	 	 
[Name of Participant]	 	 	
THE UNDERSIGNED HEREBY ACCEPTS AND AGREES TO THE TERMS SET FORTH ABOVE AS OF THIS ____ DAY OF ____________, ___.

 	 	“COMPANY”	 	 	
 	 	 	 	 	 	 	
 	 	DEVON ENERGY CORPORATION	 	 	
 	 	 	 	 	 	 	
 	 	By:	 	 	 	 	
 	 	Name:	 	 	 	 	
 	 	Title:	 	 	 	 	
 	 	 	 	 	 	 	
ii

 

EXHIBIT C
Form of Compliance Certificate
     I hereby certify that I am in full compliance with the covenants contained in that certain letter agreement (the “Agreement”) dated as of ____________, ____ between Devon Energy Corporation and me and have been in full compliance with such covenants at all times during the period ending October 31, ____.

 		
 	 	 
[Name of Participant]	 	 	
Dated:                                             

 

ANNEX C
AMENDMENT TO INCENTIVE STOCK OPTION AGREEMENT
UNDER THE
DEVON ENERGY CORPORATION 200__ LONG-TERM INCENTIVE PLAN
     THIS AMENDMENT TO INCENTIVE STOCK OPTION AGREEMENT (“Amendment”) is entered into as of the ____ day of ______, 2011 by and between Devon Energy Corporation, a Delaware corporation (the “Company”), and Danny J. Heatly (the “Participant”).
W I T N E S S E T H:
     WHEREAS, the Company and the Participant have previously entered into a certain Incentive Stock Option Agreement under the Devon Energy Corporation 200__ Long-Term Incentive Plan listed on Exhibit A (the “Agreements”), which granted to the Participant incentive stock options to purchase shares of Common Stock of the Company (the “Incentive Stock Options”) in exchange for the Participant’s performance of future services for the Company pursuant to the terms of the Agreement; and
     WHEREAS, the Company and the Participant desire to amend the Agreement with respect to the vesting and exercisability of the Incentive Stock Options following the date of retirement of the Participant under certain circumstances; and
     WHEREAS, Section 12.6 of the Plan permits the Compensation Committee of the Company’s Board of Directors (the “Committee”) to amend the Agreement; and
     WHEREAS, the Committee has approved the amendment of the Agreement as set forth herein.
     NOW, THEREFORE, for good and valuable consideration, the receipt of which is hereby acknowledged, the parties hereto agree that the Agreement is hereby amended as follows:

 	1.	 	The first sentence of Section 2(a) is hereby amended to read as follows:	

 	 	 	“The Incentive Stock Option shall become fully vested and exercisable on and after the vesting date for each installment of Covered Shares as described in the following schedule (the “Vesting Date”) (but only if the Participant’s Date of Termination has not occurred before the Vesting Date, except as otherwise provided in Section 3 of this Award Agreement):”	

 	2.	 	The first sentence of Section 2(b) is hereby amended to read as follows:	

 	 	 	“The Incentive Stock Option shall become fully vested and exercisable upon the occurrence of a Change of Control Event that occurs (i) prior to the Participant’s Date of Termination or (ii) if the Participant has retired prior to such Change of Control Event, is Post-Retirement Eligible, and no Non-Compliance Event has occurred, following the Participant’s Date of Termination.”	

 

 	3.	 	Section 2(e) is hereby amended to read as follows:	

 	 	 	“(d) Notwithstanding any provision to the contrary in this Award Agreement, if the Participant is Post-Retirement Eligible, the Participant shall, subject to the satisfaction of the conditions in Section 11, be eligible to vest, in accordance with the Vesting Schedule above in Section 2(a), in the installments of the Covered Shares of the Incentive Stock Option that remain unvested on the Date of Termination. If (i) the Participant is Post-Retirement Eligible, (ii) the death of the Participant occurs following the Date of Termination, and (iii) no Non-Compliance Event has occurred prior to the date of the Participant’s death, then any installments of the Covered Shares of the Incentive Stock Option that remain unvested on the date of the Participant’s death but in which the Participant was eligible to vest pursuant to this Section 2(e) shall become fully vested and exercisable upon the Participant’s death.”	

 	4.	 	Section 3 is hereby amended to read as follows:	

 	 	 	“ Term of Incentive Stock Option . The Incentive Stock Option shall cease to be exercisable on the earliest to occur of:	

 	(i)	 	The Expiration Date set forth on the Cover Page.	
 		
 	(j)	 	If the Participant’s Date of Termination occurs by reason of death, the three-year anniversary of such Date of Termination.	
 		
 	(k)	 	If the Participant’s Date of Termination occurs by reason of Disability, the one-year anniversary of such Date of Termination.	
 		
 	(l)	 	If the Participant’s Date of Termination occurs on or after the Participant’s Early Retirement Date or on or after the Participant’s Normal Retirement Date, and Sections (b) and (e) do not apply, the one-year anniversary of such Date of Termination (or such later date as may be permitted by the Committee).	
 		
 	(m)	 	If the Participant’s Date of Termination occurs by reason of the Participant’s retirement and the Participant is Post-Retirement Eligible, the Expiration Date of the Incentive Stock Option; provided, however, if a Non-Compliance Event occurs following such Date of Termination, the Incentive Stock Option shall cease to be exercisable on the one-year anniversary of such Non-Compliance Event.	
 		
 	(n)	 	If (i) the Participant is Post-Retirement Eligible, (ii) the death of the Participant occurs following the Date of Termination, (iii) there are installments of the Covered Shares of the Incentive Stock Option that remain unvested as of the date of the Participant’s death but in which the Participant was eligible to vest pursuant to Section 3(d), and (iv) no Non-Compliance Event has occurred prior to the date of	
ii

 

 	 	 	the Participant’s death, the three-year anniversary of the date of the Participant’s death.	
 		
 	(o)	 	If the Participant’s Date of Termination occurs under circumstances in which the Participant is entitled to severance benefits from the Company, a Subsidiary of the Company, or an Affiliated Entity under an employment agreement or severance agreement, the last day of the Severance Period. The “Severance Period” shall be the longer of:	

 	(i)	 	the period beginning on the Date of Termination and continuing through the end of the period during which such severance benefits are paid to the Participant; or	
 		
 	(ii)	 	the period described in the following clause (b), if the amount of the Participant’s severance benefits is determined in whole or in part as being equal to the product of (a) the Participant’s salary rate, multiplied by (b) a period over which such benefit would be computed.	

 	(p)	 	If the Participant’s Date of Termination occurs and Sections (b), (c), (d), (e), (f) and (g) are not applicable, the three-month anniversary of such Date of Termination.	

 	 	 	The Participant should be aware that exercising the Incentive Stock Option more than three months after the Date of Termination (one year in the case of termination by reason of certain disabilities) will generally result in the option being treated as a nonqualified option rather than an incentive stock option for tax purposes. The Participant should also be aware that if his or her employment is transferred to a limited liability company that is an Affiliated Entity that does not satisfy the definition of “company” or “subsidiary” in Section 424 of the Code, the transfer will be classified as a termination of employment for purposes of the incentive stock option rules regardless of whether it constitutes a Date of Termination under this Award Agreement. As a result, the option, if not exercised within three months of such transfer, will be treated as a nonqualified stock option rather than an incentive stock option for tax purposes. Regardless of classification of the option for tax purposes, this Award Agreement shall continue in full force and effect. ”	

 	5.	 	By adding a new Section 11 that provides as follows:	

 	 	 	“11. Conditions to Post-Retirement Vesting .	

 	(c)	 	Notice of and Conditions to Post-Retirement Vesting . If the Participant is Post-Retirement Eligible, the Company shall, within a reasonable period of time prior to the Participant’s Date of Termination, notify the Participant that the Participant has the	
iii

 

 	 	 	right, pursuant to this Section 11(a), to continue to vest following the Date of Termination in any unvested installments of Covered Shares of the Incentive Stock Option (each such unvested installment, an “Installment”). The Participant shall have the right to vest in such Installments of Covered Shares of the Incentive Stock Option provided that the Participant executes and delivers to the Company, with respect to each such Installment, the following documentation: (i) a non-disclosure letter agreement, in the form attached as Exhibit B, (a “Non-Disclosure Agreement”) on or before January 1 of the year in which such Installment vests pursuant to the Vesting Schedule (or, with respect to the calendar year in which the Date of Termination occurs, on or before the Date of Termination), and (ii) a compliance certificate, in the form attached as Exhibit C, (a “Compliance Certificate”) indicating the Participant’s full compliance with the Non-Disclosure Agreement on or before November 1 of the year in which such Installment vests pursuant to the Vesting Schedule.	
 		
 	(d)	 	Consequences of Failure to Satisfy Vesting Conditions. In the event that, with respect to any given Installment, the Participant fails to deliver either the respective Non-Disclosure Agreement or Compliance Certificate for such Installment on or before the date required for the delivery of such document (such failure, a “Non-Compliance Event”), the Participant shall not be entitled to vest in any unvested Installments that would vest from and after the date of the Non-Compliance Event and the Company shall be authorized to take any and all such actions as are necessary to cause such unvested Incentive Stock Options to not vest and to terminate. The only remedy of the Company for failure to deliver a Non-Disclosure Agreement or a Compliance Certificate shall be the failure to vest in, and cancellation of, any unvested Installments then held by the Participant.”	

 	6.	 	Section 12 is hereby amended by adding a new definition in Section 12(o) as follows:	

 	 	 	“‘Post-Retirement Eligible’ means the Participant’s Date of Termination occurs (i) by reason of the Participant’s retirement and (ii) on or after the Participant has attained age fifty-five (55) with ten (10) or more Years of Service, as that term is defined in the Retirement Plan.”	
     The Agreement is not amended in any respect except as herein provided. This Amendment is not intended and shall not be construed as increasing the aggregate number of shares of Common Stock subject to the Incentive Stock Options under the Agreement.
     All capitalized terms used in this Amendment shall have the same meaning ascribed to them in the Plan and the Agreement unless specifically denoted otherwise.
[SIGNATURES APPEAR ON FOLLOWING PAGE]
iv

 

     IN WITNESS WHEREOF, the parties have executed this Amendment as of the day and year first above written.

“Company”	 	Devon Energy Corporation, a Delaware corporation	 	 	
 	 	 	 	 	 	 	
 	 	By:	 	 	 	 	
 	 	 	 	 	 	 	
“Participant”	 	 	 	 	 	 	
 	 	 	 	 	
 	 	Danny J. Heatly	 	 	
v 

 

EXHIBIT A
Incentive Stock Option Agreements
Subject to Amendment
[Insert list of agreements]

 

EXHIBIT B
Form of Non-Disclosure Agreement
[Insert Date]
Devon Energy Corporation
20 North Broadway
Oklahoma City, OK 73102
          Re: Non-Disclosure Agreement
Ladies and Gentlemen:
     This letter agreement is entered between Devon Energy Corporation (together with its subsidiaries and affiliates, the “Company”) and the undersigned (the “Participant”) in connection with that certain Amendment to Incentive Stock Option Agreements (the “Amendment”) dated _______________, ___________ between the Company and the Participant. All capitalized terms used in this letter agreement shall have the same meaning ascribed to them in the Amendment unless specifically denoted otherwise.
     The Participant acknowledges that, during the course of and in connection with the employment relationship between the Participant and the Company, the Company provided and the Participant accepted access to the Company’s trade secrets and confidential and proprietary information, which included, without limitation, information pertaining to the Company’s finances, oil and gas properties and prospects, compensation structures, business and litigation strategies and future business plans and other information or material that is of special and unique value to the Company and that the Company maintains as confidential and does not disclose to the general public, whether through its annual report and/or filings with the Securities and Exchange Commission or otherwise (the “Confidential Information”).
     The Participant acknowledges that his position with the Company was one of trust and confidence because of the access to the Confidential Information, requiring the Participant’s best efforts and utmost diligence to protect and maintain the confidentiality of the Confidential Information. Unless required by the Company or with the Company’s express written consent, the Participant will not, during the term of this letter agreement, directly or indirectly, disclose to others or use for his own benefit or the benefit of another any of the Confidential Information, whether or not the Confidential Information is acquired, learned, attained or developed by the Participant alone or in conjunction with others.
     The Participant agrees that, due to his access to the Confidential Information, the Participant would inevitably use and/or disclose that Confidential

 

Information in breach of his confidentiality and non-disclosure obligations if the Participant worked in certain capacities or engaged in certain activities for a period of time following his employment with the Company, specifically in a position that involves (i) responsibility and decision-making authority or input at the executive level regarding any subject or responsibility, (ii) decision-making responsibility or input at any management level in the Participant’s individual area of assignment with the Company, or (iii) responsibility and decision-making authority or input that otherwise allows the use of the Confidential Information (collectively referred to as the “Restricted Occupation”). Therefore, except with the prior written consent of the Company, during the term of this letter agreement, the Participant agrees not to be employed by, consult for or otherwise act on behalf of any person or entity in any capacity in which he would be involved, directly or indirectly, in a Restricted Occupation. The Participant acknowledges that this commitment is intended to protect the Confidential Information and is not intended to be applied or interpreted as a covenant against competition.
     The Participant further agrees that, during the term of this letter agreement, the Participant will not, directly or indirectly on behalf of a person or entity or otherwise, (i) solicit any of the established customers of the Company or attempt to induce any of the established customers of the Company to cease doing business with the Company, or (ii) solicit any of the employees of the Company to cease employment with the Company.
     This letter agreement shall become effective upon execution by the Participant and the Company and shall terminate on December 31, 200_. [NOTE: Insert date that is the end of the calendar year of the letter agreement.]
     If you agree to the above terms and conditions, please execute a copy of this letter agreement below and return a copy to me.

 	 	“PARTICIPANT”	 	 	

 	 	 
[Name of Participant]	 	 	
THE UNDERSIGNED HEREBY ACCEPTS AND AGREES TO THE TERMS SET FORTH ABOVE AS OF THIS ____ DAY OF ____________, ___.

 	 	“COMPANY”	 	 	
 	 	 	 	 	 	 	
 	 	DEVON ENERGY CORPORATION	 	 	
 	 	 	 	 	 	 	
 	 	By:	 	 	 	 	
 	 	Name:	 	 	 	 	
 	 	Title:	 	 	 	 	
 	 	 	 	 	 	 	
ii

 

EXHIBIT C
Form of Compliance Certificate
     I hereby certify that I am in full compliance with the covenants contained in that certain letter agreement (the “Agreement”) dated as of ____________, ____ between Devon Energy Corporation and me and have been in full compliance with such covenants at all times during the period ending October 31, ____.

 		
 	 	 
[Name of Participant]	 	 	
Dated:                                            

Exhibit 10.22

Devon Energy Corporation	 	405 235 3611 Phone	
20 North Broadway	 	www.devonenergy.com	
Oklahoma City, OK 73102-8260	 	 	

December ___, 2010
[INSERT NAME]
[INSERT ADDRESS]
[INSERT CITY], OK [INSERT ZIP CODE]
Re: Amendment of RSA and NQSO Agreements
Dear [INSERT NAME]:
This letter agreement memorializes our understanding with respect to the amendment of (i) the Restricted Stock Award Agreements under (a) the Devon Energy Corporation 2009 Long-Term Incentive Plan identified on Annex A as the 2009 RSA Agreements (the “2009 RSA Agreements”) and (b) the Devon Energy Corporation 2005 Long-Term Incentive Plan identified on Annex A as the 2005 RSA Agreements (the “2005 RSA Agreements” and, together with the 2009 RSA Agreements, the “RSA Agreements”) and (ii) the Nonqualified Stock Option Award Agreements under (a) the Devon Energy Corporation 2009 Long-Term Incentive Plan identified on Annex A as the 2009 NQSO Agreements (the “2009 NQSO Agreements”) and (b) the Devon Energy Corporation 2005 Long-Term Incentive Plan identified on Annex A as the 2005 NQSO Agreements (the “2005 NQSO Agreements” and, together with the 2009 NQSO Agreements, the “NQSO Agreements”), in each case between you and Devon Energy Corporation.
Each RSA Agreement is hereby amended to insert the following at the end of Section 3(b)(iv):
“If (i) the Participant is Post-Retirement Eligible, (ii) the death of the Participant occurs following the Date of Termination, and (iii) no Non-Compliance Event has occurred prior to the date of the Participant’s death, then any percentages of installments of Restricted Stock that remain unvested on the date of the Participant’s death but in which the Participant was eligible to vest pursuant to this Section 3(b)(iv) shall become fully vested upon the Participant’s death.”
Each NQSO Agreement is hereby amended to insert the following at the end of Section 2(e) (in the case of the 2009 NQSO Agreements) and Section 3(d) (in the case of the 2005 NQSO Agreements):
“If (i) the Participant is Post-Retirement Eligible, (ii) the death of the Participant occurs following the Date of Termination, and (iii) no Non-Compliance Event has occurred prior to the date of the Participant’s death, then any percentages of installments of the Covered Shares of the Stock Option that remain unvested on the date of the Participant’s death but in which the Participant was eligible to vest

 

pursuant to this [Section 2(e)] 1 [Section 3(d)] 2 shall become fully vested and exercisable upon the Participant’s death.”
Each NQSO Agreement is hereby amended to (i) insert a new subsection (g) in Section 4 as set forth below, (ii) re-letter the existing subsection (g) as subsection (h) and (iii) insert a reference to subsection (g) as an addition to the list of cross-referenced subsections in re-lettered subsection (h):
     “(g) If (i) the Participant is Post-Retirement Eligible, (ii) the death of the Participant occurs following the Date of Termination, (iii) there are percentages of installments of the Covered Shares of the Stock Option that remain unvested as of the date of the Participant’s death but in which the Participant was eligible to vest pursuant to Section 2(e), and (iv) no Non-Compliance Event has occurred prior to the date of the Participant’s death, the three-year anniversary of the date of the Participant’s death.”
Sincerely,
DEVON ENERGY CORPORATION
Frank W. Rudolph
Executive Vice President, Human Resources
Acknowledged and agreed to:
_______________________
[INSERT NAME]
______________________
Date Signed

1	 	Language inserted in 2009 NQSO Agreements	
 		
2	 	Language inserted in 2005 NQSO Agreements	

 

ANNEX A
2009 RSA Agreements:
[Insert]
2005 RSA Agreements:
[Insert]
2009 NQSO Agreements:
[Insert]
2005 NQSO Agreements:
[Insert]

Exhibit 12
RATIOS OF EARNINGS TO FIXED CHARGES AND TO
COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS
December 31, 2010
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Years Ended December 31,	 	
 	 	2010	 	 	2009	 	 	2008	 	 	2007	 	 	2006	 	
EARNINGS:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Adjusted (loss) earnings from continuing operations before income taxes	 	$	3,548	 	 	$	(4,574	)	 	$	(4,208	)	 	$	3,283	 	 	$	3,151	 	
Add fixed charges (see below)	 	 	460	 	 	 	467	 	 	 	459	 	 	 	550	 	 	 	515	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Adjusted (loss) earnings	 	$	4,008	 	 	$	(4,107	)	 	$	(3,749	)	 	$	3,833	 	 	$	3,666	 	

FIXED CHARGES AND PREFERRED STOCK DIVIDENDS:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Gross interest expense	 	$	439	 	 	$	444	 	 	$	440	 	 	$	532	 	 	$	500	 	
Estimated interest component of operating lease payments	 	 	21	 	 	 	23	 	 	 	19	 	 	 	18	 	 	 	15	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Fixed charges	 	 	460	 	 	 	467	 	 	 	459	 	 	 	550	 	 	 	515	 	
Preferred stock requirements, pre-tax	 	 	—	 	 	 	—	 	 	 	9	 	 	 	15	 	 	 	15	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Combined fixed charges and preferred stock dividends	 	$	460	 	 	$	467	 	 	$	468	 	 	$	565	 	 	$	530	 	

Ratio of earnings to fixed charges	 	 	8.71	 	 	 	N/A	 	 	 	N/A	 	 	 	6.97	 	 	 	7.11	 	
Ratio of earnings to combined fixed charges and preferred stock dividends	 	 	8.71	 	 	 	N/A	 	 	 	N/A	 	 	 	6.78	 	 	 	6.91	 	
Insufficiency of earnings to cover fixed charges	 	 	N/A	 	 	$	4,574	 	 	$	4,208	 	 	 	N/A	 	 	 	N/A	 	
Insufficiency of earnings to cover combined fixed charges and preferred stock dividends	 	 	N/A	 	 	$	4,574	 	 	$	4,217	 	 	 	N/A	 	 	 	N/A	 	

N/A	 	Not applicable.	

EXHIBIT 21
DEVON ENERGY CORPORATION
Significant Subsidiaries

1.	 	Devon Energy Corporation (Oklahoma), an Oklahoma corporation	
 		
2.	 	Devon Financing Corporation, L.L.C., a Delaware limited liability company	
 		
3.	 	Devon OEI Holdings, Inc., a Delaware corporation	
 		
4.	 	Devon OEI, L.L.C., a Delaware limited liability company	
 		
5.	 	Devon OEI Operating, L.L.C., a Delaware limited liability company	
 		
6.	 	Devon Energy Production Company, L.P., an Oklahoma limited partnership	
 		
7.	 	Devon Western Company, Inc., a Delaware corporation	
 		
8.	 	Devon Western Operating, L.L.C., a Delaware limited liability company	
 		
9.	 	Devon Operating Company Ltd., an Alberta corporation	
 		
10.	 	Devon Canada Holdings LP, an Alberta limited partnership	
 		
11.	 	Devon Canada Corporation, a Nova Scotia corporation	
 		
12.	 	Devon NEC Corporation, a Nova Scotia corporation	
 		
13.	 	Devon AXL, a general partnership registered in Alberta	
 		
14.	 	Devon Canada, a general partnership registered in Alberta	

Exhibit 23.1
Consent of Independent Registered Public Accounting Firm
The Board of Directors
Devon Energy Corporation:
We consent to the incorporation by reference in the registration statements (File No. 333-68694, 333-47672, 333-44702, 333-104933, 333-104922, 333-103679, 333-159796 and 333-127630) on Form S-8 and the Registration Statement (File No. 333-156025) on Form S-3 of Devon Energy Corporation of our report dated February 23, 2011, with respect to the consolidated balance sheets of Devon Energy Corporation 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, and the effectiveness of internal control over financial reporting as of December 31, 2010, which report appears in the December 31, 2010 annual report on Form 10-K of Devon Energy Corporation.
KPMG LLP
Oklahoma City, Oklahoma
February 23, 2011

Exhibit 23.2
ENGINEER’S CONSENT
We consent to incorporation by reference in the Registration Statements (File Nos. 333-68694, 333-47672, 333-44702, 333-104922, 333-104933, 333-103679, 333-127630 and 333-159796) on Form S-8, and the Registration Statement (File No. 333-156025) on Form S-3 of Devon Energy Corporation of the reference to our reports for Devon Energy Corporation, which appears in the December 31, 2010 annual report on Form 10-K of Devon Energy Corporation.
 	 	 	 	 	
 	LaRoche Petroleum Consultants, Ltd.
 	 	
 	By:  	/s/ William M. Kazmann  	 	
 	 	William M. Kazmann 	 	
 	 	Partner 	 	
 	
February 16, 2011

Exhibit 23.3
ENGINEER’S CONSENT
We consent to incorporation by reference in the Registration Statements (File Nos. 333-68694, 333-47672, 333-44702, 333-104922, 333-104933, 333-103679, 333-127630 and 333-159796) on Form S-8, and the Registration Statement (File No. 333-156025) on Form S-3 of Devon Energy Corporation of the reference to our reports for Devon Energy Corporation, which appears in the December 31, 2010 annual report on Form 10-K of Devon Energy Corporation.
 	 	 	 	 	
 	AJM Petroleum Consultants
 	 	
 	By:  	/s/ Robin G. Bertram  	 	
 	 	Robin G. Bertram, P.Eng. 	 	

February 15, 2011

Exhibit 31.1
CERTIFICATION PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, John Richels, certify that:
     1. I have reviewed this annual report on Form 10-K of Devon Energy Corporation;
     2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
     3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
     4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
     a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
     b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
     c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
     d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
     5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):
     a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
     b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

 	/s/ John Richels  	 	
 	John Richels 	 	
 	President and Chief Executive Officer  	 	
Date: February 23, 2011

Exhibit 31.2
CERTIFICATION PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Jeffrey A. Agosta, certify that:
     1. I have reviewed this annual report on Form 10-K of Devon Energy Corporation;
     2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
     3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
     4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
     a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
     b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
     c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
     d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
     5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):
     a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
     b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

 	/s/ Jeffrey A. Agosta  	 	
 	Jeffrey A. Agosta 	 	
 	Chief Financial Officer  	 	
Date: February 23, 2011

Exhibit 32.1
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the annual report of Devon Energy Corporation (“Devon”) on Form 10-K for the period ended December 31, 2010 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, John Richels, Chief Executive Officer of Devon, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

 	(1)	 	The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and	
 		
 	(2)	 	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Devon.	

/s/ John Richels  	 	 	
John Richels 	 	 	
Chief Executive Officer  	 	 	
February 23, 2011

Exhibit 32.2
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the annual report of Devon Energy Corporation (“Devon”) on Form 10-K for the period ended December 31, 2010 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Jeffrey A. Agosta, Chief Financial Officer of Devon, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

 	(1)	 	The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and	
 		
 	(2)	 	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Devon.	

/s/ Jeffrey A. Agosta  	 	 	
Jeffrey A. Agosta 	 	 	
Chief Financial Officer  	 	 	
February 23, 2011 	 	 	

Exhibit 99.1

February 7, 2011
Mr. Bob Fant
Director Reserves and Economics
Devon Energy Corporation
20 North Broadway
Oklahoma City, OK 73102
Dear Mr. Fant:
     At your request, LaRoche Petroleum Consultants, Ltd. (LPC) has audited the estimates of proved reserves and future net cash flow, as of December 31, 2010, to the Devon Energy Corporation (Devon) interest in certain properties located in Devon’s Central, Western, and Southern Divisions in the United States as prepared and completed by Devon on January 15, 2011. The reserve estimates were prepared by Devon for public disclosure according to the United States Security and Exchange Commission (SEC) guidelines, and our audit is to confirm the accuracy of those estimates and classifications within the applicable SEC rules, regulations, and guidelines. It should be understood that our audit described herein does not constitute a complete reserve study of the oil and gas properties of Devon. It is our understanding that the properties audited by LPC comprise approximately ninety-four percent (94%) of Devon’s aggregate reserves for the three Divisions set out above as estimated and reported by Devon. We prepared our own estimates of proved reserves and net cash flow for all of the properties audited, and compared our estimates to those prepared by Devon to complete our audit of such properties. We believe the assumptions, data, methods, and procedures used are appropriate for the purpose of this audit. Estimates by Devon and LPC are based on constant prices and costs as set forth in this letter and conform to our understanding of the SEC guidelines, reserves definitions, and applicable accounting rules.
     It is our understanding that the properties audited by LPC and reflected in this audit report comprise sixty-nine percent (69%) of Devon’s aggregate, corporate reserves as estimated and reported by Devon.
     The Central Division reserves are for the field areas designated by Devon’s internal naming system as the Barnett Shale North Project Area; the Barnett Shale South Project Area; Arkoma Conventional, Arkoma Other Unconventional, and Northridge Unconventional of the Eastern Oklahoma Project Area; Allison Parks/West Park, Buffalo Wallow, Hansford Area, Hemphill Area, Hugoton Kansas Area, Kansas Other, Mendota, and TX-KS-OK Panhandle of the Texas-Kansas Project Area; Anadarko Other, Burns Flat, Cana, Knox Area, Watonga Trend, and Weatherford of the Western Oklahoma Project Area.
     The Southern Division reserves are for the areas designated by Devon’s internal naming system as Field Groups consisting of the Agua Dulce Area, Bethany, Carthage Central, Carthage South, Central (Haynesville Shale), Central Texas, Coastal Frio, Duval, Madisonville, Montgomery County Area, Nan-Su-Gail, North (Haynesville Shale), Personville, Polk County Area, Rocky Mount / Serepta, South Louisiana, Southeast (Haynesville Shale), Stockman/Appleby, Waskom, and Zapata Area.

 

Mr. Bob Fant
February 7, 2011
Page 2
     The Western Division reserves are for the following areas as designated by Devon’s internal naming system. For the Rocky Mountain District, the Bear Paw Uplift, Big Horn, Green River, New Ventures Rockies, Powder River Basin CBM, Powder River Basin Conventional, RM Other, San Juan, Uinta, and Washakie Project Areas are included. For the Permian Basin District, the Ackerly Area, Anton Irish, Catclaw Draw Area, Corbin Area, Deep Delaware, Diamond Mound, Fullerton Area, Gaucho Area, Hackberry, Ingle Wells/Sand Dunes Keystone/Kermit, McKnight, Midland Basin, Odessa, Other PB New Mexico, Other PB Texas, Outland Area, Ozona Area, Potato Basin Area, Reeves, Slaughter, Townsend Area, Waddell North, Waddell South, Wasson, and Welch Area Field Groups are included.
     The oil reserves include crude oil and condensate. Oil and natural gas liquid (NGL) reserves are expressed in barrels which are equivalent to 42 United States gallons. Gas volumes are expressed in thousands of standard cubic feet (Mcf) at the contract temperature and pressure bases.
     The estimated reserves and future cash flow are for proved developed producing, proved developed non-producing, and proved undeveloped reserves. Devon’s estimates do not include any value for unproven reserves classified as probable or possible reserves that might exist for these properties, nor did it include any consideration that could be attributed to interests in undeveloped acreage beyond those tracts for which reserves have been estimated.
     When compared on a field-by-field basis, some estimates determined by Devon are greater and some are lesser than the estimates determined by LPC. However, in our opinion, Devon’s estimates of proved oil and gas reserves and future cash flow, as audited by LPC, are in the aggregate reasonable, are within 10 percent of our numbers and have been prepared in accordance with generally accepted petroleum engineering and evaluation methods and procedures. These methods and procedures are set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information promulgated by the Society of Petroleum Engineers. We are satisfied with the methods and procedures used by Devon in preparing the December 31, 2010 reserve and future cash flow estimates. We saw nothing of an unusual nature that would cause us to take exception with the estimates, in the aggregate, as prepared by Devon.
     The estimated reserves and future cash flow amounts in this audit of the Devon report are related to hydrocarbon prices. The price calculation methodology specified by the SEC regulations was used in the preparation of those estimates; however, actual future prices may vary significantly from the SEC-specified pricing. In addition, future changes in taxation affecting oil and gas producing companies and their products, and changes in environmental and administrative regulations may significantly affect the ability of Devon to operate and produce oil and gas at the projected levels. Therefore, volumes of reserves actually recovered and amounts of cash flow actually received may differ significantly from the estimated quantities presented in this audit.
     Estimates of reserves for this audit were prepared using standard geological and engineering methods generally accepted by the petroleum industry. The reserves in this audit have been estimated using deterministic methods. The method or combination of methods utilized in the evaluation of each reservoir included consideration of the stage of development of the reservoir, quality and completeness of basic data, and production history. Recovery from various reservoirs and leases was estimated after consideration of the type of energy inherent in the reservoirs, the structural positions of the properties, and reservoir and well performance. In some instances, comparisons were made to similar properties where more complete data were available. We have

 

Mr. Bob Fant
February 7, 2011
Page 3
used all methods and procedures that we considered necessary under the circumstances to prepare this audit. We have excluded from our consideration all matters as to which the controlling interpretation may be legal or accounting rather than engineering or geosciences.
     Benchmark prices used in this audit are based on the twelve-month unweighted arithmetic average of the first day of the month price for the period January through December 2010. Oil prices used by Devon are based on a Cushing West Texas Intermediate crude oil price of $79.43 per barrel, as published in Platts Oilgram, adjusted by lease for gravity, crude quality, transportation fees, and regional price differentials. Gas prices are based on a Henry Hub gas price of $4.376 per MMBTU, as published in Platts Gas Daily, adjusted by lease for energy content, transportation fees, and regional price differentials. NGL prices are based on a Mt. Belvieu composite product price of $39.25 per barrel, as published in the OPIS daily price bulletin, adjusted by area for composition, quality, transportation fees, and regional price differentials. Price differentials and adjustments to physical spot prices as of December 2010 were furnished by Devon and were accepted as presented. Oil and gas prices are held constant throughout the life of the properties. The weighted average prices over the life of the properties are $76.08 per barrel for oil, $3.67 per Mcf for gas, and $30.02 per barrel for NGL.
     Lease and well operating expenses were furnished by Devon and were confirmed by LPC from a review of Devon accounting data on a Project Area or Field Group basis. As requested, expenses for the Devon-operated properties include only direct lease and field level costs. For properties operated by others, these expenses include the per-well overhead costs allowed under joint operating agreements along with direct lease and field level costs. Headquarters general and administrative overhead expenses of Devon are not included. Operating expenses are held constant throughout the life of the properties.
     Capital costs and timing of all investments have been provided by Devon and are included as required for workovers, new development wells, and production equipment. Devon has represented to us that they have the ability and intent to implement their capital expenditure program as scheduled. Devon’s estimates of the cost to plug and abandon the wells net of salvage value are included and scheduled at the end of the economic life of individual properties. These costs are held constant.
     LPC has made no investigation of possible gas volume and value imbalances that may have been the result of overdelivery or underdelivery to the Devon interest. Our projections are based on Devon receiving its net revenue interest share of estimated future gross oil, gas, and NGL production.
     An on-site inspection of the properties has not been performed nor has the mechanical operation or condition of the wells and their related facilities been examined by LPC. The costs associated with the continued operation of uneconomic properties are not reflected in the cash flows.
     The evaluation of potential environmental liability from the operation and abandonment of the properties is beyond the scope of this audit. In addition, no evaluation was made to determine the degree of operator compliance with current environmental rules, regulations, and reporting requirements. Therefore, no estimate of the potential economic liability, if any, from environmental concerns is included in our projections.

 

Mr. Bob Fant
February 7, 2011
Page 4
     In our audit, we accepted without independent verification the accuracy and completeness of the information and data furnished by Devon with respect to ownership interest, oil and gas production, well test data, oil and gas prices, operating and development costs, and any agreements relating to current and future operations of the properties and sales of production. However, if in the course of our examination something came to our attention which brought into question the validity or sufficiency of any such information or data, we did not rely on such information or data until we had satisfactorily resolved our questions relating thereto or had independently verified such information or data.
     The reserves estimated in our audit process and those presented by Devon are estimates only and should not be construed as exact quantities. They may or may not be recovered; if recovered, the revenues there from and the costs related thereto could be more or less than the estimated amounts. These estimates should be accepted with the understanding that future development, production history, changes in regulations, product prices, and operating expenses would probably cause us to make revisions in subsequent evaluations. A portion of these reserves are for behind-pipe zones, undeveloped locations, and producing wells that lack sufficient production history to utilize performance-related reserve estimates. Therefore, these reserves are based on estimates of reservoir volumes and recovery efficiencies along with analogies to similar production. These reserve estimates are subject to a greater degree of uncertainty than those based on substantial production and pressure data. It may be necessary to revise these estimates up or down in the future as additional performance data become available. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geological data; therefore, our conclusions represent informed professional judgments only, not statements of fact.
     The results of our third party study were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Devon Energy Corporation.
     Devon Energy Corporation makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, Devon Energy Corporation has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-3 and Form S-8 of Devon Energy Corporation of the references to our name together with references to our third party audit for Devon Energy Corporation, which appears in the December 31, 2010 annual report on Form 10-K of Devon Energy Corporation. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by Devon Energy Corporation.
     We have provided Devon Energy Corporation with a digital version of the original signed copy of this audit letter. In the event there are any differences between the digital version included in filings made by Devon Energy Corporation and the original signed audit letter, the original signed audit letter shall control and supersede the digital version.
     LPC’s technical personnel responsible for preparing this audit meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information promulgated by the Society of Petroleum Engineers. The technical person primarily responsible for overseeing the preparation of the LPC audit is William M. Kazmann. Mr. Kazmann is a Professional Engineer licensed in the State of Texas who has thirty-six years of engineering experience in the oil and gas industry. Mr. Kazmann earned Bachelor of Science and Master of Science degrees in Petroleum

 
Mr. Bob Fant
February 7, 2011
Page 5
     Engineering from the University of Texas at Austin and has prepared reserves estimates for his employers and his own companies throughout his career. He has prepared and overseen preparation of reports for public filings for LPC for the past fourteen years. We are independent petroleum engineers, geologists, and geophysicists and are not employed on a contingent basis. Data pertinent to the audit are maintained on file in our office.

 	 	Very truly yours,	 	 	
 	 	 	 	 	
 	 	LaRoche Petroleum Consultants, Ltd.	
 	 	State of Texas Registration Number F-1360	

 	 	William M. Kazmann	 	 	
 	 	Licensed Professional Engineer	
 	 	State of Texas No. 45012	 	 	

 	 	Joe A. Young	 	 	
 	 	Licensed Professional Engineer	 	 	
 	 	State of Texas No. 62866	 	 	

					
	 	 	 	Exhibit 99.2	
January 25, 2011
Devon Energy Corporation
20 North Broadway
Oklahoma City, Oklahoma
USA 73102
Attention: Mr. Bob Fant

Re:  	 	Devon Canada Corporation
December 31, 2010 Reserve Audit Opinion	
At your request and authorization, AJM Petroleum Consultants (“AJM”) has audited the reserves management processes and practices of Devon Canada Corporation (“Devon Canada”) as of December 31, 2010. Our examination included such tests and procedures as we considered necessary under the circumstances to render our opinion.
During the course of our examination, we audited in excess of 89 percent of Devon Canada’s total proved reserves. AJM’s estimate for the audited properties varied from Devon Canada’s estimates by less than 10 percent. When compared to Devon Canada’s parent corporation, Devon Energy Corporation, AJM audited 24 percent of the company’s total proved reserves.
The scope of the audit consisted of the independent preparation of our own estimates of the proved and proved plus probable reserves and the comparison of our proved reserve results to the estimates prepared by the company. When compared on a field by field basis, some estimates prepared by Devon Canada are greater than and some are less than those prepared by AJM. However, in our opinion, the estimates prepared by Devon Canada are in aggregate reasonable, are within the established audit tolerance of plus or minus 10 percent and the estimates have been prepared in accordance with generally accepted petroleum engineering practices and procedures. These practices and procedures are detailed within the Canadian Oil and Gas Evaluation Handbook (“COGEH”), set out by the Society of Petroleum Evaluation Engineers (“SPEE”) as well as the Society of Petroleum Engineers’ (“SPE”) Standards Pertaining to the Estimation and Auditing of Oil and Gas Reserves. The proved and proved plus probable reserve estimates prepared by both Devon Canada and AJM conform to the reserve definitions as set forth in the SEC’s Regulation S-X Part 210.4-10(a) and as clarified in subsequent Commission Staff Accounting Bulletins. We believe that such assumptions, data, methods, and procedures are appropriate for the purpose served by the report.

 

- 2 -
Devon Energy Corporation
December 31, 2010 Reserve Audit Opinion
AJM was provided with Devon Canada’s base hydrocarbon prices (oil, gas, condensate and natural gas liquids) as of December 31, 2010 in order to estimate the company’s net after royalty reserves. In accordance with SEC requirements all prices and costs (capital and operating) were held constant. The effects of derivative instruments designated as price hedges of oil and gas quantities if any, are not reflected in AJM’s individual property evaluations. An oil equivalent conversion factor of 6.0 Mcf per 1.0 barrel oil was used for sales gas.
In general terms, Devon Canada’s corporate structure is such that lands are held within either Devon Canada Partnership (“DCP”) or Devon NEC Corporation (“NEC”). For the purpose of this evaluation, properties which consist of both DCP and NEC lands are reported separately.
The Evaluation Procedure section included in this report details the reserves definitions, price and market demand forecasts and general procedure used by AJM in its reserve estimates. The extent and character of ownership and all factual data supplied by Devon Canada Corporation were accepted as presented. A field inspection and environmental/safety assessment of the properties was not made by AJM and the consultant makes no representations and accepts no responsibilities in this regard.
It should be understood that our audit does not constitute a complete reserves study of the oil and gas properties of your company. In the conduct of our examinations we have not independently verified the accuracy and completeness of all the information and data furnished by your company with respect to ownership interests, oil and gas production, historical costs of operations and development, product prices, and agreements relating to current and future operations and sales of production. We have, however, specifically identified to you the information and data upon which we relied so that you can subject it to procedures you consider necessary. Furthermore, if in the course of our examination something came to our attention that brought into question the validity or sufficiency of any of the information or data, we did not rely on that information or data until we had satisfactorily resolved our questions or independently verified it.
We are independent with respect to the company as provided in the standards pertaining to the estimating and auditing of oil and gas reserves information included in COGEH and the Association of Professional Engineers, Geologists and Geophysicists of Alberta (“APEGGA”).
This audit is for the information of your company and for the information and assistance of its independent public accountants in connection with their review of, and report upon, the financial statements of your company. Supporting data documenting the audit, along with data provided by Devon Canada, are on file in our office. The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Devon Energy Corporation.
Devon Energy Corporation makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, Devon Energy Corporation has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-X of Devon Energy Corporation to the references to our name as well as to the references to our third party

 

 -3- 
Devon Energy Corporation
December 31, 2010 Reserve Audit Opinion
report for Devon Energy Corporation, which appears in the December 31, 2010 annual report on Form 10-K of Devon Energy Corporation. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by Devon Energy Corporation.
Yours truly,
 	 	 	 	 	
AJM Petroleum Consultants
 	 	 	
By:  	  	 	 	
 	Robin G. Bertram, P. Eng. 	 	 	
 	Executive Vice President 	 	 	
/ct

 

 	 	 	 	 	
EVALUATION PROCEDURE
DEFINITIONS AND METHODOLOGY
Effective as of December 2010

 

 2 
Table of Contents
Procedure
Reserve Definitions
Resource and Reserves Estimation
Production Forecasts
Land Schedules and Maps
Geology
Royalties and Taxes
Operating and Capital Considerations
Price and Market Demand Forecasts
Glossary of Terms

 

 3 
PROCEDURE
AJM Petroleum Consultants has prepared estimates of resources and reserves in accordance with the definitions published in The Canadian Oil and Gas Evaluation Handbook (COGEH), Volume 1, 2 nd Edition. The reader is referred to the Handbook for a complete description of the particular definitions quoted as follows.
Resources or Reserves Evaluation
A “Resources or Reserves Evaluation” is the process whereby a qualified reserves evaluator estimates the quantities and values of oil and gas resources or reserves by interpreting and assessing all available pertinent data. The value of an oil and gas asset is a function of the ability or potential ability of that asset to generate future net revenue, and it is measured using a set of forward-looking assumptions regarding resources or reserves, production, prices, and costs. Evaluations of oil and gas assets, in particular reserves, include a discounted cash flow analysis of estimated future net revenue.
Reserves Audit
A “Reserves Audit” is the process carried out by a qualified reserves auditor that results in a reasonable assurance, in the form of an opinion, that the reserves information has in all material respects been determined and presented according to the principles and definitions adopted by the Society of Petroleum Evaluation Engineers (“SPEE”) (Calgary Chapter), and Association of Professional Engineers, Geologists and Geophysicists of Alberta (“APEGGA”) and are, therefore free of material misstatement.
The reserves evaluations prepared by the Corporation have been audited, not for the purpose of verifying exactness, but the reserves information, company policies, procedures, and methods used in estimating the reserves will be examined in sufficient detail so that AJM Petroleum Consultants (“AJM”) can express an opinion as to whether, in the aggregate, the reserves information presented by the Corporation are reasonable.
AJM may require its own independent evaluation of the reserves information for a small number of properties, or for a large number of properties as tests for the reasonableness of the Corporation’s

 

 4 
evaluations. The tests to be applied to the Corporation’s evaluations insofar as their methods and controls and the properties selected to be re-evaluated will be determined by AJM, in its sole judgment, to arrive at an opinion as to the reasonableness of the Corporation’s evaluations.
Reserves Review
A “Reserves Review” is the process whereby a reserves auditor conducts a high-level assessment of reserves information to determine if it is plausible. The steps consist primarily of enquiry, analytical procedure, analysis, review of historical reserves performance, and discussion with the Corporation’s reserves management staff.
“Plausible” means the reserves data appear to be worthy of belief based on the information obtained by the independent qualified reserves auditor in carrying out the aforementioned steps. Negative assurance can be given by the independent reserves auditor, but an opinion cannot. For example, “Nothing came to my attention that would indicate the reserves information has not been prepared and presented in accordance with principles and definitions adopted by the SPEE (Calgary Chapter), and APEGGA (Practice Standard for the Evaluation of Oil and Gas Reserves for Public Disclosure).
Reviews do not require examination of the detailed document that supports the reserves information, unless this information does not appear to be plausible.

 

 5 
RESERVE DEFINITIONS
Reserve Classification: Proved and probable reserves are classified by AJM Petroleum Consultants in accordance with the following definitions that are the United States Securities and Exchange Commission Regulation S-X Part 210.4-10. These definitions are as follows:
Proved Oil And Gas Reserves : Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. A high degree of confidence exists if the quantity is much more likely to be achieved than not. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

 	(i)	 	Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.	
 		
 	(ii)	 	Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.	
 		
 	(iii)	 	Estimates of proved reserves do not include the following:	

 	(A)	 	oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”;	

 

 6 

 	(B)	 	crude oil, natural gas and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; and	
 		
 	(C)	 	crude oil, natural gas and natural gas liquids, that may occur in undrilled prospects.	
Proved Developed Oil And Gas Reserves: Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
The SEC does not further subdivide proved developed reserves. AJM further subdivides proved developed reserves between proved developed producing and proved developed non-producing reserves, as follows. The definition and guidelines are documented in the Petroleum Resources Management System (“PRMS”) prepared by the Oil and Gas Reserves Committee of the Society of Petroleum Engineers (SPE), World Petroleum Council (WPC), the American Association of Petroleum Geologists (AAPG), and the Society of Petroleum Evaluation Engineers (SPEE).
Proved Developed Producing Reserves: Proved developed producing reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.
Proved Developed Non-Producing Reserves: Proved developed non-producing reserves include shut-in and behind-pipe reserves. Shut-in reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe reserves are expected to be recovered from zones in existing wells which will require additional completion work or

 

 7 
future recompletion prior to the start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.
Proved Undeveloped Reserves: Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.
Probable Reserves: Probable reserves are those additional reserves which analysis of geoscience and engineering data indicates are less certain to be recovered than proved reserves but more certain to be recovered than possible reserves. It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated proved plus probable reserves (2P).
The SEC does not further sub-divide probable reserves. AJM further sub-divides probable reserves into developed and undeveloped and producing and non-producing, as follows:
Probable Developed: Probable developed reserves are expected quantities to be recovered from existing wells and facilities. Reserves are considered developed only after the necessary equipment has been installed, or when the costs to do so are relatively minor compared to the cost of a well. Developed reserves may be subcategorized as producing or non-producing.
Producing: Probable reserves that are expected to be recovered from completion intervals which are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.

 

 8 
Non-Producing: Probable reserves include shut-in and behind-pipe reserves. Shut-in reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future recompletion prior to the start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.
Probable Undeveloped: Probable undeveloped reserves are quantities expected to be recovered through future investments: (1) from new wells on undrilled acreage in known accumulations, (2) from deepening existing wells to a different (but known) reservoir, or (3) where a relatively large expenditure (eg. when compared to the cost of drilling a new well) is required to (a) recomplete an existing well or (b) install production or transportation facilities for primary or improved recovery projects.

 

 9 
RESOURCE AND RESERVE ESTIMATION
AJM generally assigns reserves to properties via deterministic methods. Probabilistic estimation techniques are typically used where there is a low degree of certainty in the information available and is generally used in resource evaluations. This will be stated within the detailed property reports.
Deterministic
Reserves and resources were estimated either by i) volumetric, ii) decline curve analysis, iii) material balance techniques, or iv) performance predictions.
Volumetric reserves were estimated using the wellbore net pay and an assigned drainage area or, where sufficient data was available, the reservoir volumes calculated from isopach maps. Reservoir rock and fluid data were obtained from available core analysis, well logs, PVT data, gas analysis, government sources, and other published information either on the evaluated pool or from a similar reservoir in the immediate area. In mature (producing) reservoirs decline curve analysis and/or material balance was utilized in all applicable evaluations.
Statistical Analysis
Whenever there is the need within an evaluation to assign reserves based on analogy or when volumetric reserves are being assigned, AJM utilizes a variety of different tools in support of. When evaluating Western Canadian prospects, typically AJM uses petroCUBE™.
The petroCUBE program is a web-based ( www.petroCUBE.com ) product co-developed by AJM Petroleum Consultants and geoLOGIC Systems Inc. petroCUBE provides geostatistical, technical, and financial information for conventional hydrocarbon plays throughout the Western Canadian Sedimentary Basin (“WCSB”).
The information provided by petroCUBE is an unbiased independent perspective into the historical performance of the conventional hydrocarbon activity in the WCSB. The statistical information is

 

 10 
presented by commodity type (gas, oil) with each commodity further analyzed by geographic area and play type.
Analysis output includes cumulative frequency resource distribution curves, chance of success tables, production performance profiles for each play type and area, unrisked and risked resources, and initial production rates on a per well zone basis, and full cycle economic and play parameters.
Cumulative frequency curves show how the volumes for a play are distributed. These calculations include the average volumes for a play (P 50 ), volumes for the best 10 percent of the wells (P 10 ), the minimum volumes developed by 90 percent of the wells (P 90 ).
Reserves assigned are compared to those volumes noted in the cumulative frequency curves for the corresponding area and play type. Typically an expected or proved plus probable reserve is a P 50 volume.
Probabilistic
Because of the uncertainty inherent in reservoir parameters, probabilistic analysis, which is based on statistical techniques, provides a formulated approach by which to obtain a reasonable assessment of the petroleum initially in place (PIIP) and/or the recoverable resource. Probabilistic analysis involves generating a range of possible outcomes for each unknown parameter and their associated probability of occurrence. When probabilistic analysis is applied to resource estimation, it provides a range of possible PIIPs or recoverable resources.
In preparing a resource estimate, AJM assesses the following volumetric parameters: areal extent, net pay thickness, porosity, hydrocarbon saturation, reservoir temperature, reservoir pressure, gas compressibility factor, recovery factor, and surface loss. A team of professional engineers and geologists experienced in probabilistic resource evaluation considered each of the parameters individually to estimate the most reasonable range of values. Working from existing data, the team discusses and agrees on the low (P 90 ) and high (P 10 ) values for each parameter. To help test the reasonableness of the proposed range, a minimum (P 99 ) and maximum (P 1 ) value are also extrapolated from the low and high values. After ranges

 

 11 
have been established for each parameter, these independent distributions are used to determine a P 90 , P 50 , and P 10 result which comprise AJM’s estimated range of PIIP or recoverable resource.
It is important to note that the process used to determine the final P 10 , P 90 , and P 50 results involves multiplying the various volumetric parameters together. This yields results which require adjustments to maintain an appropriate probability of occurrence. For example, when calculating total reservoir volume (Area x Pay), the chance of getting a volume greater than the P 10 Area x P 10 Pay is less than 10 percent — the chance of getting the calculated result is only 3.5 percent (p 3.5 ). As you multiply additional P 10 values, the probability of achieving the calculated value becomes less likely. Similarly, multiplying P 90 parameters together will yield a result that has a probability greater than P 90 . As such, when multiplying independent distributions together the results must be adjusted via interpolation to determine final P 90 and P 10 values.
The results appearing in this report represent interpolated P 90 and P 10 values. As defined by COGEH (and the Petroleum Resource Management System “PRMS”), the P 50 estimate is the “best estimate” for reporting purposes.
PRODUCTION FORECASTS
Production forecasts were based on historical trends or by comparison with other wells in the immediate area producing from similar reservoirs. Non-producing gas reserves were forecast to come on-stream within the first two years from the effective date under direct sales pricing and deliverability assumptions, if a tie-in point to an existing gathering system was in close proximity (approximately two miles). If the tie-in point was of a greater distance (and dependent on the reserve volume and risk) the reserves were forecast to come on-stream in years three or four from the effective date. If the reserves were located in a remote location and/or the reserve volume was of higher risk, the reserves were forecast to come on-stream beyond five years from the effective date. These on-stream dates were used when the company could not provide specific on-stream date information.

 

 12 
LAND SCHEDULE AND MAPS
The evaluated Corporation provided schedules of land ownership which included lessor and lessee royalty burdens. The land data was accepted as factual and no investigation of title by AJM was made to verify the records.
Well maps included within this report represent all of the Corporation’s interests that were evaluated in the specified area.
GEOLOGY
An initial review of each property is undertaken to establish the produced maturity of the reservoir being evaluated. Where extensive production history exists a geologic analysis is not conducted since the remaining hydrocarbons can be determined by productivity analysis.
For properties that are not of a mature production nature a geologic review is conducted. This work consists of:

 	•	 	developing a regional understanding of the play,	
 		
 	•	 	assessing reservoir parameters from the nearest analogous production,	
 		
 	•	 	analysis of all relevant well data including logs, cores, and tests to measure net formation thickness (pay), porosity, and initial water saturation,	
 		
 	•	 	auditing of client mapping or developing maps to meet AJM’s need to establish volumetric hydrocarbons-in-place.	
Procedures specific to the project are discussed in the body of the report.

 

 13 
ROYALTIES AND TAXES
General
All royalties and taxes, including the lessor and overriding royalties, are based on government regulations, negotiated leases or farmout agreements, that were in effect as of the evaluation effective date. If regulations change, the net after royalty recoverable reserve volumes may differ materially.
AJM Petroleum Consultants utilizes a variety of reserves and valuation products in determining the result sets.

 

 14 
OPERATING AND CAPITAL CONSIDERATIONS
Operating and capital costs were based on current costs escalated to the date the cost was incurred, and are in current year dollars. The economic runs provide the escalated dollar costs as found in the Pricing Table 1 in the Price and Market Demand section.
Reserves estimated to meet the standards of NI 51-101 for constant prices and costs (optimal), are based on unescalated operating and capital costs.
Capital costs were either provided by the Corporation (and reviewed by AJM for reasonableness); or determined by AJM taking into account well capability, facility requirement, and distance to markets. Facility expenditures for shut-in gas are forecast to occur prior to the well’s first production.
Operating costs were determined from historical data on the property as provided by the evaluated Corporation. If this data was not available or incomplete, the costs were based on AJM experience and historical database. Operating costs are defined into three types.
The first type, variable ($/Unit), covers the costs directly associated with the product production. Costs for processing, gathering and compression are based on raw gas volumes. Over the life of the project the costs are inflated in escalated runs to reflect the increase in costs over time. In a constant dollar review the costs remain flat over the project life.
The second type, fixed plant or battery ($/year), is again a fixed component over the project life and reflects any gas plant or battery operating costs allocated back to the evaluated group. The plant or battery can also be run as a separate group and subsequently consolidated at the property level.
The third type takes the remaining costs that are not associated with the first two and assigns them to the well based on a fixed and variable component. A split of 65 percent fixed and 35 percent variable assumes efficiencies of operation over time, i.e.: the well operator can reduce the number of monthly visits as the well matures, workovers may be delayed, well maintenance can also be reduced. The basic assumption is that the field operator will continue to find efficiencies to reduce the costs over time to maintain the overall $/Boe cost. Thus as the production drops over time the 35 percent variable cost will account for these

 

 15 
efficiencies. If production is flat all the costs will also remain flat. Both the fixed and variable costs in this type are inflated in the escalated case and held constant in the constant dollar review. These costs also include property taxes, lease rentals, government fees, and administrative overhead.
In evaluations conducted for purposes of NI 51-101 well abandonment costs have been included. These costs were either provided by the Corporation (and reviewed by AJM for reasonableness) or estimated by AJM based on its experience. For undeveloped reserve estimates for undrilled locations, site reclamation costs are also included for the purpose of determining whether reserves should be attributed to that property in the first year in which the reserves are considered for attribution to the property.

 

 16 
PRICE AND MARKET DEMAND FORECASTS
Pricing Overview
Devon provided AJM with hydrocarbon prices (oil, gas condensate, and natural gas liquids) appropriate for use in the preparation of a reserves report to be filed with the SEC with an effective date of December 31, 2010. These prices were calculated in accordance with the “Modernization of Oil and Gas Reporting: Final Rule” and were determined by taking the un-weighted average of the prices on the first day of the month for the preceding 12 months (January 1, 2010 through to December 1, 2010).
The effects of derivative instruments designated as price hedges of oil and gas quantities if any, are not reflected in AJM’s individual property evaluations.
 	      	 	 	 	      	 	 	 	      	 	 	 	
 	 	 	 	 	 	 	 	 	 	Weighted Average	
 	 	 	 	 	 	Benchmark Price	 	Realized Report Price	
 	 	Benchmark	 	($US)	 	($US)	
Oil	 	NYMEX WTI @ Cushing	 	$79.43/bbl	 	$58.72/bbl	
Gas	 	NYMEX Henry Hub	 	$4.38/MMbtu	 	$3.96/Mcf	
NGL	 	Mt. Belvieu	 	$39.25/bbl	 	$44.97/bbl	

 

 17 
GLOSSARY OF TERMS
AJM subscribes to the Glossary of Terms as defined by the Canadian Oil and Gas Evaluation Handbook, Volume 2.