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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
(Mark One)
 	x 	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934	
For the fiscal year ended December 31, 2013
or
 
 	¨ 	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934	
Commission File Number 001-32318
DEVON ENERGY CORPORATION
(Exact name of registrant as specified in its charter)

Delaware	 	73-1567067	
(State of other jurisdiction of incorporation or organization)	 	(I.R.S. Employer identification No.)	
		
333 West Sheridan Avenue, Oklahoma City, Oklahoma	 	73102-5015	
(Address of principal executive offices)	 	(Zip code)	
Registrant’s telephone number, including area code:
(405) 235-3611
Securities registered pursuant to Section 12(b) of the Act:

Title of each class	  	Name of each exchange on which registered	
		
Common stock, par value $0.10 per share	  	The New York Stock Exchange	
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes   x     No   ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes   ¨     No   x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes   x     No   ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes   x     No   ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.     ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer  x             Accelerated filer  ¨              Non-accelerated filer  ¨             Smaller reporting company  ¨
                             (Do not check if a smaller reporting company)
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes   ¨     No   x
The aggregate market value of the voting common stock held by non-affiliates of the registrant as of June 28, 2013, was approximately $20.9 billion, based upon the closing price of $51.88 per share as reported by the New York Stock Exchange on such date. On February 12, 2014, 407.4 million shares of common stock were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Proxy statement for the 2014 annual meeting of stockholders – Part III

 

Table of Contents
DEVON ENERGY CORPORATION
FORM 10-K
 TABLE OF CONTENTS

PART I	  				
		
Items 1 and 2. Business and Properties	  	 	3	  	
Item 1A.   Risk Factors	  	 	17	  	
Item 1B.   Unresolved Staff Comments	  	 	21	  	
Item 3.      Legal Proceedings	  	 	21	  	
Item 4.      Mine Safety Disclosures	  	 	21	  	
		
PART II	  				
		
Item 5.      Market for Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	  	 	22	  	
Item 6.      Selected Financial Data	  	 	24	  	
Item 7.      Management’s Discussion and Analysis of Financial Condition and Results of Operations	  	 	25	  	
Item 7A.   Quantitative and Qualitative Disclosures about Market Risk	  	 	47	  	
Item 8.      Financial Statements and Supplementary Data	  	 	49	  	
Item 9.      Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	  	 	104	  	
Item 9A.   Controls and Procedures	  	 	104	  	
Item 9B.   Other Information	  	 	104	  	
		
PART III	  				
		
Item 10.    Directors, Executive Officers and Corporate Governance	  	 	105	  	
Item 11.    Executive Compensation	  	 	105	  	
Item 12.    Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	  	 	105	  	
Item 13.    Certain Relationships and Related Transactions, and Director Independence	  	 	105	  	
Item 14.    Principal Accountant Fees and Services	  	 	105	  	
		
PART IV	  				
		
Item 15.         Exhibits and Financial Statement Schedules	  	 	106	  	
Signatures	  	 	113	  	
INFORMATION REGARDING FORWARD-LOOKING STATEMENTS
This report includes “forward-looking statements” as defined by the United States Securities and Exchange Commission (“SEC”). Such statements are those concerning strategic plans, our expectations and objectives for future operations, as well as other future events or conditions. Such forward-looking statements are based on our examination of historical operating trends, the information used to prepare our December 31, 2013 reserve reports and other data in our possession or available from third parties. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond our control. Consequently, actual future results could differ materially from our expectations due to a number of factors, such as changes in the supply of and demand for oil, natural gas and natural gas liquids (“NGLs”) and related products and services; exploration or drilling programs; our ability to successfully complete mergers, acquisitions and divestitures; political or regulatory events; general economic and financial market conditions; and other risks and factors discussed in this report.
All subsequent written and oral forward-looking statements attributable to Devon Energy Corporation, or persons acting on its behalf, are expressly qualified in their entirety by the cautionary statements above. We assume no duty to update or revise our forward-looking statements based on new information, future events or otherwise.
 
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 PART I
 Items 1 and 2. Business and Properties 
General
Devon Energy Corporation (“Devon”) is a leading independent energy company engaged primarily in the exploration, development and production of oil, natural gas and NGLs. Our operations are concentrated in various North American onshore areas in the U.S. and Canada. Our portfolio of oil and gas properties provides stable, environmentally responsible production and a platform for future growth. We have nearly doubled our onshore North American oil production since 2008 and have a deep inventory of development opportunities to deliver future oil growth. We produce about 2.4 billion cubic feet of natural gas a day – more than 3 percent of all the gas consumed in North America. We also own natural gas pipelines, plants and treatment facilities in many of our producing areas, making us one of North America’s larger processors of natural gas.
Devon pioneered the commercial development of natural gas from shale and coalbed formations, and we are a proven leader in using steam to produce bitumen from the Canadian oil sands. A Delaware corporation formed in 1971, we have been publicly held since 1988, and our common stock is listed on the New York Stock Exchange. Our principal and administrative offices are located at 333 West Sheridan, Oklahoma City, OK 73102-5015 (telephone 405-235-3611). As of December 31, 2013, we had approximately 5,900 employees.
Devon files or furnishes annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K as well as any amendments to these reports with the SEC. Through our website, http://www.devonenergy.com, we make available electronic copies of the documents we file or furnish to the SEC, the charters of the committees of our Board of Directors and other documents related to our corporate governance (including our Code of Ethics for the Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer). Access to these electronic filings is available free of charge as soon as reasonably practicable after filing or furnishing them to the SEC. Printed copies of our committee charters or other governance documents and filings can be requested by writing to our corporate secretary at the address on the cover of this report.
In addition, the public may read and copy any materials Devon files with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington D.C. 20549. The public may also obtain information about the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Reports filed with the SEC are also made available on its website at www.sec.gov.
Strategy
Our primary goal is to build value per share. In pursuit of this objective, we focus on growing cash flow per share, adjusted for debt, which has the greatest long-term correlation to share price appreciation in our industry. We also focus on growth in earnings, production and reserves, all on a per debt-adjusted share basis. We do this by:
 
 	•	 	exploring for undiscovered oil and natural gas reserves,	
 
 	•	 	purchasing and developing oil and natural gas properties,	
 
 	•	 	enhancing the value of production through marketing and midstream activities,	
 
 	•	 	optimizing production operations to control costs, and	
 
 	•	 	maintaining a strong balance sheet.	
We hold 14 million net acres, of which roughly 60 percent are undeveloped, providing us with a platform for future growth. An important factor in determining the direction of our growth strategy, particularly our capital allocation, is the current and forecasted pricing applicable to our production. Our industry had been operating in an environment that had involved depressed North American gas prices contrasted with more robust prices for oil
 
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and NGLs. Consequently, we have focused our recent capital programs on higher-margin oil and liquids-based resource capture and development. With recent changes in market conditions that have led to challenged prices for NGLs and Canadian heavy oil, we are refining our capital allocations as needed and evaluating other investment opportunities to maximize and accelerate growth in cash flow per debt-adjusted share.
In pursuit of our goal to build value per share, we entered into two significant agreements near the end of 2013. On November 20, 2013, we entered into an agreement with GeoSouthern Intermediate Holdings, LLC, to acquire certain oil and gas properties, leasehold mineral interests and related assets located in the Eagle Ford Shale in south Texas for $6 billion in cash. The transaction is expected to close in the first quarter of 2014, and we have the necessary financing in place to fund the acquisition.
On October 21, 2013, Devon, Crosstex Energy, Inc. and Crosstex Energy, L.P. (collectively “Crosstex”) announced plans to combine substantially all of Devon’s U.S. midstream assets with Crosstex’s assets to form a new midstream business. The new business will consist of EnLink Midstream Partners, L.P. (the “Partnership”) and EnLink Midstream, LLC (“EnLink”), respectively, a master limited partnership and a general partner entity, which will both be publicly traded entities.
In exchange for a controlling interest in both EnLink and the Partnership, Devon will contribute its equity interest in a newly formed Devon subsidiary (“EnLink Holdings”) and $100 million in cash. EnLink Holdings will own Devon’s midstream assets in the Barnett Shale in north Texas and the Cana and Arkoma Woodford Shales in Oklahoma, as well as Devon’s economic interest in Gulf Coast Fractionators in Mt. Belvieu, Texas. The Partnership and EnLink will each own 50% of EnLink Holdings. The completion of these transactions is subject to Crosstex Energy, Inc. shareholder approval. Devon expects Crosstex Energy, Inc. shareholders will approve the transaction, allowing Devon and Crosstex to complete the transaction near the end of the first quarter of 2014.
Upon closing of the transactions, the pro forma ownership of EnLink will be approximately:
 
 	•	 	70% – Devon Energy Corporation	
 
 	•	 	30% – Current Crosstex Energy, Inc. public stockholders	
Upon closing of the transactions, the pro forma ownership of the Partnership will be approximately:
 
 	•	 	53% – Devon Energy Corporation	
 
 	•	 	40% – Current Crosstex Energy, L.P. public unitholders	
 
 	•	 	7% – the General Partner	
In conjunction with the announcement of the GeoSouthern acquisition, we also announced plans to divest certain non-core properties located throughout Canada and the U. S. On February 19, 2014, we announced our first transaction as a part of this divestiture program, in which we agreed to sell the majority of our Canadian conventional assets to Canadian Natural Resources Limited for approximately $2.8 billion ($3.125 billion in Canadian dollars). We expect this non-core divestiture program will generate organizational and operational efficiencies and will allow us to allocate capital and employee resources to higher-value properties and prospects. We expect to complete the majority of the divestitures by the end of 2014. Once the GeoSouthern acquisition and non-core divestitures are complete, we expect oil production will represent more than 30% of our production profile.
 
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Oil and Gas Properties
Property Profiles
The locations of our key properties are presented on the following map. These properties include those that currently have significant proved reserves and production, as well as properties that do not currently have significant levels of proved reserves or production but are expected to be the source of significant future growth in proved reserves and production.

 
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The following table outlines a summary of key data in each of our operating areas for 2013. Notes 21 and 22 to the financial statements included in “Item 8. Financial Statements and Supplementary Data” of this report contain additional information on our segments and geographical areas. In the following table and throughout this report, we convert our proved reserves and production to Boe. Gas proved reserves and production are converted to Boe at the rate of six Mcf of gas per Bbl of oil, based upon the approximate relative energy content of gas and oil. Bitumen and NGL proved reserves and production are converted to Boe on a one-to-one basis with oil.

   	  	Proved Reserves	 	 	Production	 	 	Gross
Wells
Drilled	 	
   	  	MMBoe	 	  	% of
Total	 	 	% Liquids	 	 	    MBoe/d    	 	  	% of
Total	 	 	%
Liquids	 	 			
Anadarko Basin	  	 	406	  	  	 	14	% 	 	 	41	% 	 	 	81.7	  	  	 	12	% 	 	 	42	% 	 	 	184	  	
Barnett Shale	  	 	1,093	  	  	 	37	% 	 	 	23	% 	 	 	227.7	  	  	 	33	% 	 	 	25	% 	 	 	172	  	
Mississippian-Woodford Trend	  	 	32	  	  	 	1	% 	 	 	66	% 	 	 	7.9	  	  	 	1	% 	 	 	75	% 	 	 	232	  	
Permian Basin	  	 	269	  	  	 	9	% 	 	 	79	% 	 	 	78.0	  	  	 	11	% 	 	 	78	% 	 	 	348	  	
Rockies	  	 	37	  	  	 	1	% 	 	 	47	% 	 	 	21.5	  	  	 	3	% 	 	 	40	% 	 	 	37	  	
Other	  	 	161	  	  	 	5	% 	 	 	35	% 	 	 	39.6	  	  	 	6	% 	 	 	35	% 	 	 	5	  	
	  	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	
U.S. core and emerging properties	  	 	1,998	  	  	 	67	% 	 	 	36	% 	 	 	456.4	  	  	 	66	% 	 	 	39	% 	 	 	978	  	
Canadian heavy oil	  	 	584	  	  	 	20	% 	 	 	99	% 	 	 	83.1	  	  	 	12	% 	 	 	96	% 	 	 	186	  	
	  	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	
Total core and emerging properties	  	 	2,582	  	  	 	87	% 	 	 	51	% 	 	 	539.5	  	  	 	78	% 	 	 	48	% 	 	 	1,164	  	
Non-core properties	  	 	381	  	  	 	13	% 	 	 	28	% 	 	 	153.4	  	  	 	22	% 	 	 	23	% 	 	 	111	  	
	  	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	
Total	  	 	2,963	  	  	 	100	% 	 	 	48	% 	 	 	692.9	  	  	 	100	% 	 	 	42	% 	 	 	1,275	  	
	  	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	
Core and Emerging Properties
Anadarko Basin – Our acreage is located primarily in Oklahoma’s Canadian, Blaine, Caddo and Dewey counties. The Anadarko Basin is a non-conventional reservoir and produces natural gas, NGLs and condensate.
The Anadarko Basin has rapidly emerged as one of the most economic shale plays in North America. We are the largest leaseholder and the largest producer in the Anadarko Basin. During 2013, we increased our production by 14 percent. We have several thousand remaining drilling locations. In 2014, we plan to drill approximately 95 wells.
In addition, we have a significant processing plant and gathering system to service these properties. Our Cana plant currently has 350 MMcf per day of total capacity.
Barnett Shale  – This is our largest property both in terms of production and proved reserves. Our leases are located primarily in Denton, Johnson, Parker, Tarrant and Wise counties in north Texas. The Barnett Shale is a non-conventional reservoir, producing natural gas, NGLs and condensate.
We are the largest producer in the Barnett Shale. Since acquiring a substantial position in this field in 2002, we continue to introduce technology and new innovations to enhance production and have transformed this into one of the top producing gas fields in North America. We have drilled in excess of 5,000 wells in the Barnett Shale since 2002, yet we still have several thousand remaining drilling locations. In 2014, we plan to drill approximately 80 wells, focused in the areas with the highest liquids content.
In addition, we have a significant processing plant and gathering system in north Texas to service these properties. Our Bridgeport plant is one of the largest processing plants in the U.S., currently with 790 MMcf per day of total capacity. These midstream assets also include an extensive pipeline system and a 15 MBbls per day NGL fractionator.
 
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Mississippian-Woodford Trend – These properties represent some of our newest assets, with most of our position acquired since 2011. Located in northern Oklahoma and southern Kansas, these acres target oil in the Mississippian Lime and Woodford Shale. These areas are being explored and developed under our joint venture arrangement with Sinopec and independently by us on the acreage outside of our area of mutual interest with Sinopec. In 2014, we plan to drill approximately 230 wells.
Permian Basin – Our acreage is located in various counties in west Texas and southeast New Mexico. These properties have been a legacy asset for us and continue to offer both exploration and low-risk development opportunities. We entered into a joint venture arrangement with Sumitomo in 2012, covering approximately 650,000 net acres in the Cline Shale and Midland-Wolfcamp Shale, further strengthening the capital efficiency of our exploration programs. In addition to the Cline and Wolfcamp Shale activity, our current drilling activity continues to target conventional and non-conventional oil and liquids-rich gas targets within the Conventional Delaware, Bone Spring, Midland-Wolfcamp, Wolfberry and Avalon Shale plays. In 2014, we plan to drill approximately 350 wells.
Rockies – Our operations are focused in the Powder River basin in Wyoming where we have 150,000 net acres. These acres are principally located in eastern Wyoming in the counties of Campbell, Converse and Johnson. We are currently targeting several Cretaceous oil objectives, including the Turner, Frontier and Parkman formations. To date we have identified roughly 600 risked locations across these three formations. Our activity and associated capital in the Powder River basin is a part of our joint venture agreement with Sinopec Corporation, under which we receive a drilling carry that funds a significant portion of our capital requirements during the carry period. In 2014, we plan to drill roughly 25 wells in the Powder River Basin.
Canadian Heavy Oil – We are the first and only U.S.-based independent energy company to develop and operate a bitumen oil sands project in Canada. We currently have two main projects, Jackfish and Pike, located in Alberta, Canada. In addition, our Lloydminster properties are located to the south and east of Jackfish in eastern Alberta and western Saskatchewan. Lloydminster produces heavy oil by conventional means, without the need for steam injection.
Jackfish is our thermal heavy oil project in the non-conventional oil sands of east central Alberta. We are employing steam-assisted gravity drainage at Jackfish. The first phase of Jackfish is fully operational with a gross facility capacity of 35 MBbls per day. Jackfish production increased 8 percent in 2013 as the second phase of Jackfish, which came on-line in the second quarter of 2011, continued to increase production. Construction of a third phase began in 2012 with plant startup expected by year-end 2014. We expect each phase to maintain a flat production profile for greater than 20 years at an average net production rate of approximately 25-30 MBbls per day.
Our Pike oil sands acreage is situated directly to the southeast of our Jackfish acreage in east central Alberta and has similar reservoir characteristics to Jackfish. The Pike leasehold is currently undeveloped and has no proved reserves or production as of December 31, 2013. We filed a regulatory application in 2012 for the first phase of this project, with gross capacity of 105 MBbls per day, in which we hold a 50 percent interest.
To facilitate the delivery of our heavy oil production, we have a 50 percent interest in the Access Pipeline transportation system in Canada. This pipeline system allows us to blend our Jackfish, and eventually our Pike, heavy oil production with condensate or other blend-stock and transport the combined product to the Edmonton area for sale. The Access Pipeline system is currently undergoing a capacity expansion that we anticipate will be completed in late 2014. This expansion is expected to create adequate capacity to transport our anticipated Jackfish and Pike heavy oil production to the Edmonton market hub. Additionally, it will increase the transport capacity of condensate diluent available at our thermal oil facilities.
Our Lloydminster region is well-developed with significant infrastructure and is primarily accessible year-round for drilling. Lloydminster is a low-risk, high margin oil development play. We have drilled approximately 2,700 wells in the area since 2003. In 2014, we plan to drill approximately 175 wells.
 
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Non-Core Properties
Our non-core properties are located throughout the U.S. and Canada and primarily consist of reservoirs that produce dry natural gas. We are in the process of monetizing these assets through a divestiture program we expect to complete by the end of 2014.
Proved Reserves
For estimates of our proved developed and proved undeveloped reserves and the discussion of the contribution by each key property, see Note 22 to the financial statements included in “Item 8. Financial Statements and Supplementary Data” of this report.
No estimates of our proved reserves have been filed with or included in reports to any federal or foreign governmental authority or agency since the beginning of 2013 except in filings with the SEC and the Department of Energy (“DOE”). Reserve estimates filed with the SEC correspond with the estimates of our reserves contained herein. Reserve estimates filed with the DOE are based upon the same underlying technical and economic assumptions as the estimates of our reserves included herein. However, the DOE requires reports to include the interests of all owners in wells that we operate and to exclude all interests in wells that we do not operate.
Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from known reservoirs under existing economic conditions, operating methods and government regulations. To be considered proved, oil and gas reserves must be economically producible before contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Also, the project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
The process of estimating oil, gas and NGL reserves is complex and requires significant judgment as discussed in “Item 1A. Risk Factors” of this report. As a result, we have developed internal policies for estimating and recording reserves. Such policies require proved reserves to be in compliance with the SEC definitions and guidance. Our policies assign responsibilities for compliance in reserves bookings to our Reserve Evaluation Group (the “Group”). These same policies also require that reserve estimates be made by professionally qualified reserves estimators (“Qualified Estimators”), as defined by the Society of Petroleum Engineers’ standards.
The Group, which is led by Devon’s Director of Reserves and Economics, is responsible for the internal review and certification of reserves estimates. We ensure the Group’s Director and key members of the Group have appropriate technical qualifications to oversee the preparation of reserves estimates, including any or all of the following:
 
 	•	 	an undergraduate degree in petroleum engineering from an accredited university, or equivalent;	
 
 	•	 	a petroleum engineering license, or similar certification;	
 
 	•	 	memberships in oil and gas industry or trade groups; and	
 
 	•	 	relevant experience estimating reserves.	
The current Director of the Group has all of the qualifications listed above. The current Director has been involved with reserves estimation in accordance with SEC definitions and guidance since 1987. He has experience in reserves estimation for projects in the U.S. (both onshore and offshore), as well as in Canada, Asia, the Middle East and South America. He has been employed by Devon for the past thirteen years, including the past five in his current position. During his career, he has been responsible for reserves estimation as the primary reservoir engineer for projects including, but not limited to:
 
 	•	 	Hugoton Gas Field (Kansas),	
 
 	•	 	Sho-Vel-Tum CO 2 Flood (Oklahoma),	
 
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 	•	 	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), and	
 
 	•	 	ACG Unit (Caspian Sea).	
From 2003 to 2010, he served as the reservoir engineering representative on our internal peer review team. In this role, he reviewed reserves and resource estimates for projects including, but not limited to, the Mobile Bay Norphlet Discoveries (Gulf of Mexico Shelf), Cascade Lower Tertiary Development (Gulf of Mexico Deepwater) and Polvo Development (Campos Basin, Brazil).
The Group reports independently of any of our operating divisions. The Group’s Director reports to our Vice President of Budget and Reserves, who reports to our Chief Financial Officer. No portion of the Group’s compensation is directly dependent on the quantity of reserves booked.
Throughout the year, the Group performs internal audits of each operating division’s reserves. Selection criteria of reserves that are audited include major fields and major additions and revisions to reserves. In addition, the Group reviews reserve estimates with each of the third-party petroleum consultants discussed below. The Group also ensures our Qualified Estimators obtain continuing education related to the fundamentals of SEC proved reserves assignments.
The Group also oversees audits and reserves estimates performed by third-party consulting firms. During 2013, we engaged two such firms to audit 91 percent of our proved reserves. LaRoche Petroleum Consultants, Ltd. audited 92 percent of our 2013 U.S. reserves, and Deloitte audited 90 percent of our Canadian reserves.
“Audited” reserves are those quantities of reserves that were estimated by our employees and audited by an independent petroleum consultant. The Society of Petroleum Engineers’ definition of an audit is an examination of a company’s proved oil and gas reserves and net cash flow by an independent petroleum consultant that is conducted for the purpose of expressing an opinion as to whether such estimates, in aggregate, are reasonable and have been estimated and presented in conformity with generally accepted petroleum engineering and evaluation methods and procedures.
In addition to conducting these internal and external reviews, we also have a Reserves Committee that consists of three independent members of our Board of Directors. This committee provides additional oversight of our reserves estimation and certification process. The Reserves Committee assists the Board of Directors with its duties and responsibilities in evaluating and reporting our proved reserves, much like our Audit Committee assists the Board of Directors in supervising our audit and financial reporting requirements. Besides being independent, the members of our Reserves Committee also have educational backgrounds in geology or petroleum engineering, as well as experience relevant to the reserves estimation process.
The Reserves Committee meets a minimum of twice a year to discuss reserves issues and policies, and meets separately with our senior reserves engineering personnel and our independent petroleum consultants at those meetings. The responsibilities of the Reserves Committee include the following:
 
 	•	 	approve the scope of and oversee an annual review and evaluation of our oil, gas and NGL reserves;	
 
 	•	 	oversee the integrity of our reserves evaluation and reporting system;	
 
 	•	 	oversee and evaluate our compliance with legal and regulatory requirements related to our reserves;	
 
 	•	 	review the qualifications and independence of our independent engineering consultants; and	
 
 	•	 	monitor the performance of our independent engineering consultants.	
 
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The following table presents our estimated pretax cash flow information related to its proved reserves. 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 herein.

 	  	Year Ended December 31, 2013	 	
 	  	U.S.	 	  	Canada	 	  	Total	 	
 	  	(In millions)	 	
Pre-Tax Future Net Revenue (Non-GAAP) (1)	  				  				  				
Proved Developed Reserves	  	$	26,617	  	  	$	4,100	  	  	$	30,717	  	
Proved Undeveloped Reserves	  	 	3,255	  	  	 	8,188	  	  	 	11,443	  	
	  	 	 	 	  	 	 	 	  	 	 	 	
Total Proved Reserves	  	$	29,872	  	  	$	12,288	  	  	$	42,160	  	

Pre-Tax 10% Present Value (Non-GAAP) (1)	  				  				  				
Proved Developed Reserves	  	$	13,862	  	  	$	3,623	  	  	$	17,485	  	
Proved Undeveloped Reserves	  	 	988	  	  	 	2,864	  	  	 	3,852	  	
	  	 	 	 	  	 	 	 	  	 	 	 	
Total Proved Reserves	  	$	14,850	  	  	$	6,487	  	  	$	21,337	  	

(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, asset impairments or non-property related expenses such as debt service and income tax expense.	
Pre-tax future net revenue and pre-tax 10 percent present value are non-GAAP measures. The present value of after-tax future net revenues discounted at 10 percent per annum (“standardized measure”) was $15.7 billion at the end of 2013. Included as part of standardized measure were discounted future income taxes of $5.6 billion. Excluding these taxes, the present value of our pre-tax future net revenue (“pre-tax 10 percent present value”) was $21.3 billion. We believe the pre-tax 10 percent present value is a useful measure in addition to the after-tax standardized measure. The pre-tax 10 percent 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 percent present value is based on prices and discount factors, which are more consistent from company to company.
 
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Production, Production Prices and Production Costs
The following table presents production, price and cost information for each significant field, country and continent.

 	  	Production	 	
Year Ended December 31,	  	    Oil (MBbls/d)    	 	  	    Bitumen (MBbls/d)    	 	  	    Gas (MMcf/d)    	 	  	    NGLs (MBbls/d)    	 	  	    Total (MBoe/d)    	 	
2013	  				  				  				  				  				
Barnett Shale	  	 	2.0	  	  	 	—  	  	  	 	1,024.9	  	  	 	54.9	  	  	 	227.7	  	
Jackfish	  	 	—  	  	  	 	51.5	  	  	 	—  	  	  	 	—  	  	  	 	51.5	  	
U.S.	  	 	77.7	  	  	 	—  	  	  	 	1,941.8	  	  	 	116.0	  	  	 	517.3	  	
Canada	  	 	39.1	  	  	 	51.5	  	  	 	451.6	  	  	 	9.7	  	  	 	175.6	  	
Total North America	  	 	116.8	  	  	 	51.5	  	  	 	2,393.4	  	  	 	125.7	  	  	 	692.9	  	
2012	  				  				  				  				  				
Barnett Shale	  	 	1.6	  	  	 	—  	  	  	 	1,074.6	  	  	 	46.8	  	  	 	227.5	  	
Jackfish	  	 	—  	  	  	 	47.6	  	  	 	—  	  	  	 	—  	  	  	 	47.6	  	
U.S.	  	 	58.7	  	  	 	—  	  	  	 	2,054.5	  	  	 	98.6	  	  	 	499.7	  	
Canada	  	 	39.8	  	  	 	47.6	  	  	 	508.3	  	  	 	10.5	  	  	 	182.6	  	
Total North America	  	 	98.5	  	  	 	47.6	  	  	 	2,562.8	  	  	 	109.1	  	  	 	682.3	  	
2011	  				  				  				  				  				
Barnett Shale	  	 	1.8	  	  	 	—  	  	  	 	1,006.0	  	  	 	43.7	  	  	 	213.1	  	
Jackfish	  	 	—  	  	  	 	34.8	  	  	 	—  	  	  	 	—  	  	  	 	34.8	  	
U.S.	  	 	46.0	  	  	 	—  	  	  	 	2,026.6	  	  	 	90.4	  	  	 	474.1	  	
Canada	  	 	41.7	  	  	 	34.8	  	  	 	583.1	  	  	 	9.9	  	  	 	183.6	  	
Total North America	  	 	87.7	  	  	 	34.8	  	  	 	2,609.7	  	  	 	100.3	  	  	 	657.7	  	

   	  	Average Sales Price	 	  	Production Cost
(Per Boe)	 	
Year Ended December 31,	  	Oil (Per Bbl)	 	  	Bitumen (Per Bbl)	 	  	Gas (Per Mcf)	 	  	NGLs (Per Bbl)	 	  			
2013	  				  				  				  				  				
Barnett Shale	  	$	97.74	  	  	$	—  	  	  	$	2.90	  	  	$	22.45	  	  	$	4.12	  	
Jackfish	  	$	—  	  	  	$	48.04	  	  	$	—  	  	  	$	—  	  	  	$	17.98	  	
U.S.	  	$	94.52	  	  	$	—  	  	  	$	3.10	  	  	$	25.75	  	  	$	6.65	  	
Canada	  	$	69.18	  	  	$	48.04	  	  	$	3.05	  	  	$	46.17	  	  	$	15.78	  	
Total North America	  	$	86.02	  	  	$	48.04	  	  	$	3.09	  	  	$	27.33	  	  	$	8.97	  	
2012	  				  				  				  				  				
Barnett Shale	  	$	91.45	  	  	$	—  	  	  	$	2.23	  	  	$	27.57	  	  	$	3.91	  	
Jackfish	  	$	—  	  	  	$	47.57	  	  	$	—  	  	  	$	—  	  	  	$	19.51	  	
U.S.	  	$	88.68	  	  	$	—  	  	  	$	2.32	  	  	$	28.49	  	  	$	5.79	  	
Canada	  	$	68.29	  	  	$	47.57	  	  	$	2.49	  	  	$	48.63	  	  	$	15.18	  	
Total North America	  	$	80.43	  	  	$	47.57	  	  	$	2.36	  	  	$	30.42	  	  	$	8.30	  	
2011	  				  				  				  				  				
Barnett Shale	  	$	94.23	  	  	$	—  	  	  	$	3.30	  	  	$	39.00	  	  	$	3.97	  	
Jackfish	  	$	—  	  	  	$	58.16	  	  	$	—  	  	  	$	—  	  	  	$	17.28	  	
U.S.	  	$	91.19	  	  	$	—  	  	  	$	3.50	  	  	$	39.47	  	  	$	5.35	  	
Canada	  	$	74.32	  	  	$	58.16	  	  	$	3.87	  	  	$	55.99	  	  	$	13.82	  	
Total North America	  	$	83.16	  	  	$	58.16	  	  	$	3.58	  	  	$	41.10	  	  	$	7.71	  	
 
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Drilling Statistics
The following table summarizes our development and exploratory drilling results.

 	  	Development Wells   (1)	 	  	Exploratory Wells  (1)	 	  	Total Wells (1)	 	
Year Ended December 31,	  	Productive	 	  	Dry	 	  	Productive	 	  	Dry	 	  	Productive	 	  	Dry	 	  	Total	 	
2013	  				  				  				  				  				  				  				
U.S.	  	 	555.3	  	  	 	—  	  	  	 	56.1	  	  	 	7.0	  	  	 	611.4	  	  	 	7.0	  	  	 	618.4	  	
Canada	  	 	211.9	  	  	 	1.0	  	  	 	7.4	  	  	 	—  	  	  	 	219.3	  	  	 	1.0	  	  	 	220.3	  	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total North America	  	 	767.2	  	  	 	1.0	  	  	 	63.5	  	  	 	7.0	  	  	 	830.7	  	  	 	8.0	  	  	 	838.7	  	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
2012	  				  				  				  				  				  				  				
U.S.	  	 	668.2	  	  	 	1.0	  	  	 	24.6	  	  	 	4.9	  	  	 	692.8	  	  	 	5.9	  	  	 	698.7	  	
Canada	  	 	209.3	  	  	 	4.0	  	  	 	27.3	  	  	 	1.0	  	  	 	236.6	  	  	 	5.0	  	  	 	241.6	  	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total North America	  	 	877.5	  	  	 	5.0	  	  	 	51.9	  	  	 	5.9	  	  	 	929.4	  	  	 	10.9	  	  	 	940.3	  	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
2011	  				  				  				  				  				  				  				
U.S.	  	 	721.2	  	  	 	5.5	  	  	 	18.8	  	  	 	4.0	  	  	 	740.0	  	  	 	9.5	  	  	 	749.5	  	
Canada	  	 	247.6	  	  	 	1.5	  	  	 	19.1	  	  	 	1.0	  	  	 	266.7	  	  	 	2.5	  	  	 	269.2	  	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total North America	  	 	968.8	  	  	 	7.0	  	  	 	37.9	  	  	 	5.0	  	  	 	1,006.7	  	  	 	12.0	  	  	 	1,018.7	  	

(1)	These well counts represent net wells completed during each year. Net wells are gross wells multiplied by our fractional working interests on the well.	
The following table presents the February 1, 2014, results of our wells that were in progress on December 31, 2013.

 	  	Productive	 	  	Dry	 	  	Still in Progress	 	  	Total	 	
 	  	Gross  (1)	 	  	Net  (2)	 	  	Gross  (1)	 	  	Net  (2)	 	  	Gross  (1)	 	  	Net  (2)	 	  	Gross  (1)	 	  	Net  (2)	 	
U.S.	  	 	11.0	  	  	 	5.3	  	  	 	—  	  	  	 	—  	  	  	 	73.0	  	  	 	25.8	  	  	 	84.0	  	  	 	31.1	  	
Canada	  	 	1.0	  	  	 	1.0	  	  	 	—  	  	  	 	—  	  	  	 	5.0	  	  	 	3.1	  	  	 	6.0	  	  	 	4.1	  	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total North America	  	 	12.0	  	  	 	6.3	  	  	 	—  	  	  	 	—  	  	  	 	78.0	  	  	 	28.9	  	  	 	90.0	  	  	 	35.2	  	

(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.	
Productive Wells
The following table sets forth our producing wells as of December 31, 2013.

 	  	Oil Wells (1)	 	  	Natural Gas Wells	 	  	Total Wells	 	
 	  	Gross (2)	 	  	Net (3)	 	  	Gross (2)	 	  	Net (3)	 	  	Gross (2)	 	  	Net (3)	 	
U.S.	  	 	9,328	  	  	 	3,669	  	  	 	20,124	  	  	 	13,092	  	  	 	29,452	  	  	 	16,761	  	
Canada	  	 	5,416	  	  	 	4,271	  	  	 	5,444	  	  	 	3,249	  	  	 	10,860	  	  	 	7,520	  	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total North America	  	 	14,744	  	  	 	7,940	  	  	 	25,568	  	  	 	16,341	  	  	 	40,312	  	  	 	24,281	  	

(1)	Includes bitumen wells.	
(2)	Gross wells are the sum of all wells in which we own an interest.	
(3)	Net wells are gross wells multiplied by our fractional working interests on the well.	
The day-to-day operations of oil and gas properties are the responsibility of an operator designated under pooling or operating agreements. The operator supervises production, maintains production records, employs
 
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field personnel and performs other functions. We are the operator of approximately 24,000 of our wells. As operator, we receive reimbursement for direct expenses incurred to perform our duties, as well as monthly per-well producing and drilling overhead reimbursement at rates customarily charged in the area. In presenting our financial data, we record the monthly overhead reimbursements as a reduction of general and administrative expense, which is a common industry practice.
Acreage Statistics
The following table sets forth our developed and undeveloped lease and mineral acreage as of December 31, 2013. The acreage in the table includes 0.7 million, 1.4 million and 0.6 million net acres subject to leases that are scheduled to expire during 2014, 2015 and 2016, respectively. Approximately 18 MMBoe, or 2.5 percent, of our proved undeveloped reserves was attributable to this expiring acreage as of December 31, 2013. Of the 2.7 million net acres set to expire by December 31, 2016, we will perform operational and administrative actions to continue the lease terms for a portion of the acreage, including all the acreage for which we have proved undeveloped reserves at the end of 2013. However, we do expect to allow a portion of the acreage to expire in the normal course of business. In 2013, we allowed approximately 50% of our expiring acreage to expire.

 	  	Developed	 	  	Undeveloped	 	  	Total	 	
 	  	Gross  (1)	 	  	Net (2)	 	  	Gross (1)	 	  	Net (2)	 	  	Gross (1)	 	  	Net (2)	 	
 	  	(In thousands)	 	
U.S.	  	 	3,312	  	  	 	2,107	  	  	 	9,281	  	  	 	3,698	  	  	 	12,593	  	  	 	5,805	  	
Canada	  	 	3,592	  	  	 	2,221	  	  	 	6,476	  	  	 	4,713	  	  	 	10,068	  	  	 	6,934	  	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total North America	  	 	6,904	  	  	 	4,328	  	  	 	15,757	  	  	 	8,411	  	  	 	22,661	  	  	 	12,739	  	

(1)	Gross acres are the sum of all acres in which we own an interest.	
(2)	Net acres are gross acres multiplied by our fractional working interests on the acreage.	
Title to Properties
Title to properties is subject to contractual arrangements customary in the oil and gas industry, liens for taxes not yet due and, in some instances, other encumbrances. We believe that such burdens do not materially detract from the value of properties or from the respective interests therein or materially interfere with their use in the operation of the business.
As is customary in the industry, other than a preliminary review of local records, little investigation of record title is made at the time of acquisitions of undeveloped properties. Investigations, which generally include a title opinion of outside counsel, are made prior to the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties.
Marketing and Midstream Activities
Our marketing and midstream operations provide gathering, compression, treating, processing, fractionation and marketing services to us and other third parties. We generate revenues from these operations by collecting service fees and selling processed gas and NGLs. The expenses associated with these operations primarily consist of the costs to operate our gathering systems, plants and related facilities, as well as purchases of gas and NGLs.
Oil, Gas and NGL Marketing
The spot markets for oil, gas and NGLs are subject to volatility as supply and demand factors fluctuate. As detailed below, we sell our production under both long-term (one year or more) and short-term (less than one year) agreements at prices negotiated with third parties. Regardless of the term of the contract, the vast majority of our production is sold at variable, or market-sensitive, prices.
 
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Additionally, we may periodically enter into financial hedging arrangements or fixed-price contracts associated with a portion of our oil, gas and NGL production. These activities are intended to support targeted price levels and to manage our exposure to price fluctuations. See Note 2 to the financial statements included in “Item 8. Financial Statements and Supplementary Data” of this report for further information.
As of January 2014, our production was sold under the following contracts.

 	  	Short-Term	 	 	Long-Term	 	
 	  	Variable	 	 	Fixed	 	 	Variable	 	 	Fixed	 	
Oil and bitumen	  	 	67	% 	 	 	—  	  	 	 	33	% 	 	 	—  	  	
Natural gas	  	 	76	% 	 	 	—  	  	 	 	20	% 	 	 	4	% 	
NGLs	  	 	89	% 	 	 	6	% 	 	 	5	% 	 	 	—  	  	
Delivery Commitments
A portion of our production is sold under certain contractual arrangements that specify the delivery of a fixed and determinable quantity. As of December 31, 2013, we were committed to deliver the following fixed quantities of production.

 	  	Total	 	  	Less Than 1 Year	 	  	1-3 Years	 	  	3-5 Years	 	  	More Than
5 Years	 	
Oil and bitumen (MMBbls)	  	 	166	  	  	 	24	  	  	 	45	  	  	 	48	  	  	 	49	  	
Natural gas (Bcf)	  	 	      800	  	  	 	        481	  	  	 	        251	  	  	 	          68	  	  	 	        —  	  	
NGLs (MMBbls)	  	 	61	  	  	 	7	  	  	 	11	  	  	 	12	  	  	 	31	  	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total (MMBoe)	  	 	360	  	  	 	111	  	  	 	98	  	  	 	71	  	  	 	80	  	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
We expect to fulfill our delivery commitments over the next three years with production from our proved developed reserves. We expect to fulfill our longer-term delivery commitments beyond three years primarily with our proved developed reserves. In certain regions, we expect to fulfill these longer-term delivery commitments with our proved undeveloped reserves.
Our proved reserves have been sufficient to satisfy our delivery commitments during the three most recent years, and we expect such reserves will continue to satisfy our future commitments. However, should our proved reserves not be sufficient to satisfy our delivery commitments, we can and may use spot market purchases to fulfill the commitments.
Customers
During 2013, 2012 and 2011, no purchaser accounted for over 10 percent of our operating revenues.
Competition
See “Item 1A. Risk Factors.”
Public Policy and Government Regulation
The oil and natural gas industry is subject to regulation throughout the world. Laws, rules, regulations, taxes, fees and other policy implementation actions affecting the oil and natural gas industry have been pervasive and are under constant review for amendment or expansion. Numerous government agencies have issued extensive laws and regulations which are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. These laws and regulations increase the cost of doing business and consequently affect profitability. Because public policy changes are commonplace, and
 
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existing laws and regulations are frequently amended, we are unable to predict the future cost or impact of compliance. However, we do not expect that any of these laws and regulations will affect our operations differently than they would affect other oil and natural gas companies of similar size and financial strength. The following are significant areas of government control and regulation affecting our operations.
Exploration and Production Regulation
Our oil and gas operations are subject to federal, state, provincial, tribal and local laws and regulations. These laws and regulations relate to matters that include:
 
 	•	 	acquisition of seismic data;	
 
 	•	 	location, drilling and casing of wells;	
 
 	•	 	well design;	
 
 	•	 	hydraulic fracturing;	
 
 	•	 	well production;	
 
 	•	 	spill prevention plans;	
 
 	•	 	emissions and discharge permitting;	
 
 	•	 	use, transportation, storage and disposal of fluids and materials incidental to oil and gas operations;	
 
 	•	 	surface usage and the restoration of properties upon which wells have been drilled;	
 
 	•	 	calculation and disbursement of royalty payments and production taxes;	
 
 	•	 	plugging and abandoning of wells;	
 
 	•	 	transportation of production; and	
 
 	•	 	endangered species and habitat.	
Our operations also are subject to conservation regulations, including the regulation of the size of drilling and spacing units or proration units; the number of wells that may be drilled in a unit; the rate of production allowable from oil and gas wells; and the unitization or pooling of oil and gas properties. In the U.S., some states allow the forced pooling or integration of tracts to facilitate exploration, while other states rely on voluntary pooling of lands and leases, which may make it more difficult to develop oil and gas properties. In addition, state conservation laws generally limit the venting or flaring of natural gas and impose certain requirements regarding the ratable purchase of production. These regulations limit the amounts of oil and gas we can produce from our wells and the number of wells or the locations at which we can drill.
Certain of our U.S. natural gas and oil leases are granted by the federal government and administered by the Bureau of Land Management of the Department of the Interior. Such leases require compliance with detailed federal regulations and orders that regulate, among other matters, drilling and operations on lands covered by these leases, and calculation and disbursement of royalty payments to the federal government. The federal government has been particularly active in recent years in evaluating and, in some cases, promulgating new rules and regulations regarding competitive lease bidding and royalty payment obligations for production from federal lands.
Royalties and Incentives in Canada
The royalty system in Canada is a significant factor in the profitability of oil and gas production. Royalties payable on production from lands other than Crown lands are determined by negotiations between the parties. Crown royalties are determined by government regulation and are generally calculated as a percentage of the value of the gross production, with the royalty rate dependent in part upon prescribed reference prices, well
 
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productivity, geographical location and the type and quality of the petroleum product produced. Occasionally, the federal and provincial governments of Canada also have established incentive programs, such as royalty rate reductions, royalty holidays, and tax credits, for the purpose of encouraging oil and gas exploration or enhanced recovery projects. These incentives generally increase our revenues, earnings and cash flow.
Marketing in Canada
Any oil or gas export that exceeds a certain duration or a certain quantity requires an exporter to obtain export authorizations from Canada’s National Energy Board. The governments of Alberta, British Columbia and Saskatchewan also regulate the volume of natural gas that may be removed from those provinces for consumption elsewhere.
Environmental and Occupational Regulations
We are subject to many federal, state, provincial, tribal and local laws and regulations concerning occupational safety and health as well as the discharge of materials into, and the protection of, the environment. Environmental laws and regulations relate to:
 
 	•	 	assessing the environmental impact of seismic acquisition, drilling or construction activities;	
 
 	•	 	the generation, storage, transportation and disposal of waste materials;	
 
 	•	 	the emission of certain gases into the atmosphere;	
 
 	•	 	the monitoring, abandonment, reclamation and remediation of well and other sites, including sites of former operations; and	
 
 	•	 	the development of emergency response and spill contingency plans.	
We consider the costs of environmental protection and safety and health compliance necessary yet manageable parts of our business. We have been able to plan for and comply with environmental, safety and health initiatives without materially altering our operating strategy or incurring significant unreimbursed expenditures. However, based on regulatory trends and increasingly stringent laws, our capital expenditures and operating expenses related to the protection of the environment and safety and health compliance have increased over the years and will likely continue to increase. We cannot predict with any reasonable degree of certainty our future exposure concerning such matters.
 
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 Item 1A. Risk Factors 
Our business activities, and the oil and gas industry in general, are subject to a variety of risks. If any of the following risk factors should occur, our profitability, financial condition or liquidity could be materially impacted. As a result, holders of our securities could lose part or all of their investment in Devon.
Oil, Gas and NGL Prices are Volatile
Our financial results are highly dependent on the general supply and demand for oil, gas and NGLs, which impact the prices we ultimately realize on our sales of these commodities. A significant downward movement of the prices for these commodities could have a material adverse effect on our revenues, operating cash flows and profitability. Such a downward price movement could also have a material adverse effect on our estimated proved reserves, the carrying value of our oil and gas properties, the level of planned drilling activities and future growth. Historically, market prices and our realized prices have been volatile and are likely to continue to be volatile in the future due to numerous factors beyond our control. These factors include, but are not limited to:
 
 	•	 	supply of and consumer demand for oil, gas and NGLs;	
 
 	•	 	conservation efforts;	
 
 	•	 	OPEC production levels;	
 
 	•	 	weather;	
 
 	•	 	regional pricing differentials;	
 
 	•	 	differing quality of oil produced (i.e., sweet crude versus heavy or sour crude);	
 
 	•	 	differing quality and NGL content of gas produced;	
 
 	•	 	the level of imports and exports of oil, gas and NGLs;	
 
 	•	 	the price and availability of alternative fuels;	
 
 	•	 	the overall economic environment; and	
 
 	•	 	governmental regulations and taxes.	
Estimates of Oil, Gas and NGL Reserves are Uncertain
The process of estimating oil, gas and NGL reserves is complex and requires significant judgment in the evaluation of available geological, engineering and economic data for each reservoir, particularly for new discoveries. Because of the high degree of judgment involved, different reserve engineers may develop different estimates of reserve quantities and related revenue based on the same data. In addition, the reserve estimates for a given reservoir may change substantially over time as a result of several factors including additional development activity, the viability of production under varying economic conditions and variations in production levels and associated costs. Consequently, material revisions to existing reserve estimates may occur as a result of changes in any of these factors. Such revisions to proved reserves could have a material adverse effect on our estimates of future net revenue, as well as our financial condition and profitability. Our policies and internal controls related to estimating and recording reserves are included in “Items 1 and 2. Business and Properties” of this report.
Discoveries or Acquisitions of Reserves are Needed to Avoid a Material Decline in Reserves and Production
The production rates from oil and gas properties generally decline as reserves are depleted, while related per unit production costs generally increase, due to decreasing reservoir pressures and other factors. Therefore, our estimated proved reserves and future oil, gas and NGL production will decline materially as reserves are produced unless we conduct successful exploration and development activities or, through engineering studies,
 
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identify additional producing zones in existing wells, secondary or tertiary recovery techniques, or acquire additional properties containing proved reserves. Consequently, our future oil, gas and NGL production and related per unit production costs are highly dependent upon our level of success in finding or acquiring additional reserves.
Future Exploration and Drilling Results are Uncertain and Involve Substantial Costs
Substantial costs are often required to locate and acquire properties and drill exploratory wells. Such activities are subject to numerous risks, including the risk that we will not encounter commercially productive oil or gas reservoirs. The costs of drilling and completing wells are often uncertain. In addition, oil and gas properties can become damaged or drilling operations may be curtailed, delayed or canceled as a result of a variety of factors including, but not limited to:
 
 	•	 	unexpected drilling conditions;	
 
 	•	 	pressure or irregularities in reservoir formations;	
 
 	•	 	equipment failures or accidents;	
 
 	•	 	fires, explosions, blowouts and surface cratering;	
 
 	•	 	adverse weather conditions;	
 
 	•	 	lack of access to pipelines or other transportation methods;	
 
 	•	 	environmental hazards or liabilities; and	
 
 	•	 	shortages or delays in the availability of services or delivery of equipment.	
A significant occurrence of one of these factors could result in a partial or total loss of our investment in a particular property. In addition, drilling activities may not be successful in establishing proved reserves. Such a failure could have an adverse effect on our future results of operations and financial condition. While both exploratory and developmental drilling activities involve these risks, exploratory drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons.
Competition for Leases, Materials, People and Capital Can Be Significant
Strong competition exists in all sectors of the oil and gas industry. We compete with major integrated and independent oil and gas companies for the acquisition of oil and gas leases and properties. We also compete for the equipment and personnel required to explore, develop and operate properties. Competition is also prevalent in the marketing of oil, gas and NGLs. Typically, during times of high or rising commodity prices, drilling and operating costs will also increase. Higher prices will also generally increase the cost to acquire properties. Certain of our competitors have financial and other resources substantially larger than ours. They also may have established strategic long-term positions and relationships in areas in which we may seek new entry. As a consequence, we may be at a competitive disadvantage in bidding for drilling rights. In addition, many of our larger competitors may have a competitive advantage when responding to factors that affect demand for oil and gas production, such as changing worldwide price and production levels, the cost and availability of alternative fuels, and the application of government regulations.
Midstream Capacity Constraints and Interruptions Impact Commodity Sales
We rely on midstream facilities and systems to process our natural gas production and to transport our production to downstream markets. Such midstream systems include the systems we operate, as well as systems operated by third parties. When possible, we gain access to midstream systems that provide the most advantageous downstream market prices available to us. Regardless of who operates the midstream systems we rely upon, a portion of our production in any region may be interrupted or shut in from time to time due to loss of access to plants, pipelines or gathering systems. Such access could be lost due to a number of factors, including,
 
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but not limited to, weather conditions, accidents, field labor issues or strikes. Additionally, we and third-parties may be subject to constraints that limit our ability to construct, maintain or repair midstream facilities needed to process and transport our production. Such interruptions or constraints could negatively impact our production and associated profitability.
Hedging Limits Participation in Commodity Price Increases and Increases Counterparty Credit Risk Exposure
We periodically enter into hedging activities with respect to a portion of our production to manage our exposure to oil, gas and NGL price volatility. To the extent that we engage in price risk management activities to protect ourselves from commodity price declines, we may be prevented from fully realizing the benefits of commodity price increases above the prices established by our hedging contracts. In addition, our hedging arrangements may expose us to the risk of financial loss in certain circumstances, including instances in which the contract counterparties fail to perform under the contracts.
Public Policy, Which Includes Laws, Rules and Regulations, Can Change
Our operations are generally subject to federal laws, rules and regulations in the 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 require substantial compliance costs and carry substantial penalties for failure to comply. Changes in such public policy have affected, and at times in the future could affect, our operations. Political developments can restrict production levels, enact price controls, change environmental protection requirements, and increase taxes, royalties and other amounts payable to governments or governmental agencies. Existing laws and regulations can also require us to incur substantial costs to maintain regulatory compliance. Our operating and other compliance costs could increase further if existing laws and regulations are revised or reinterpreted or if new laws and regulations become applicable to our operations. Although we are unable to predict changes to existing laws and regulations, such changes could significantly impact our profitability, financial condition and liquidity, particularly changes related to hydraulic fracturing, income taxes and climate change as discussed below.
Hydraulic Fracturing – The Bureau of Land Management is considering the possibility of additional regulation of hydraulic fracturing on federal and Indian lands. Currently, regulation of hydraulic fracturing is conducted primarily at the state level through permitting and other compliance requirements. We lease federal and Indian lands and would be affected by the Interior Department proposal if it were to become law.
Income Taxes – We are subject to federal, state, provincial and local income taxes and our operating cash flow is sensitive to the amount of income taxes we must pay. In the jurisdictions in which we operate, income taxes are assessed on our earnings after consideration of all allowable deductions and credits. Changes in the types of earnings that are subject to income tax, the types of costs that are considered allowable deductions or the rates assessed on our taxable earnings would all impact our income taxes and resulting operating cash flow. Recently, the United States President and other policy makers have proposed provisions that would, if enacted, make significant changes to United States tax laws applicable to us. The most significant change to our business would eliminate the immediate deduction for intangible drilling and development costs. Such a change could have a material adverse effect on our profitability, financial condition and liquidity.
Climate Change – Policymakers in the United States and Canada are increasingly focusing on whether the emissions of greenhouse gases, such as carbon dioxide and methane, are contributing to harmful climatic changes. Policymakers at both the United States federal and state levels have introduced legislation and proposed new regulations that are designed to quantify and limit the emission of greenhouse gases through inventories, limitations and/or taxes on greenhouse gas emissions. Legislative initiatives and discussions to date have focused
 
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on the development of cap-and-trade and/or carbon tax programs. A cap-and-trade program generally would cap overall greenhouse gas emissions on an economy-wide basis and require major sources of greenhouse gas emissions or major fuel producers to acquire and surrender emission allowances. Cap-and-trade programs could be relevant to us and our operations in several ways. First, the equipment we use to explore for, develop, produce and process oil and natural gas emits greenhouse gases. We could therefore be subject to caps, and penalties if emissions exceeded the caps. Second, the combustion of carbon-based fuels, such as the oil, gas and NGLs we sell, emits carbon dioxide and other greenhouse gases. Therefore, demand for our products could be reduced by imposition of caps and penalties on our customers. Carbon taxes could likewise affect us by being based on emissions from our equipment and/or emissions resulting from use of our products by our customers. Of overriding significance would be the point of regulation or taxation. Application of caps or taxes on companies such as Devon, based on carbon content of produced oil and gas volumes rather than on consumer emissions, could lead to penalties, fees or tax assessments for which there are no mechanisms to pass them through the distribution and consumption chain where fuel use or conservation choices are made. Moreover, because oil and natural gas are used as chemical feedstocks and not solely as fossil fuel, applying a carbon tax to oil and gas at the production stage would be excessive with respect to actual carbon emissions from petroleum fuels.
Environmental Matters and Costs Can Be Significant
As an owner, lessee or operator of oil and gas properties, we are subject to various federal, state, provincial, tribal and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on us for the cost of pollution clean-up resulting from our operations in affected areas. Any future environmental costs of fulfilling our commitments to the environment are uncertain and will be governed by several factors, including future changes to regulatory requirements. There is no assurance that changes in or additions to public policy regarding the protection of the environment will not have a significant impact on our operations and profitability.
Insurance Does Not Cover All Risks
Our business is hazardous and is subject to all of the operating risks normally associated with the exploration, development, production, processing and transportation of oil, natural gas and NGLs. Such risks include potential blowouts, cratering, fires, loss of well control, mishandling of fluids and chemicals and possible underground migration of hydrocarbons and chemicals. The occurrence of any of these risks could result in environmental pollution, damage to or destruction of our property, equipment and natural resources, injury to people or loss of life. Additionally, for our non-operated properties, we generally depend on the operator for operational safety and regulatory compliance.
To mitigate financial losses resulting from these operational hazards, we maintain comprehensive general liability insurance, as well as insurance coverage against certain losses resulting from physical damages, loss of well control, business interruption and pollution events that are considered sudden and accidental. We also maintain worker’s compensation and employer’s liability insurance. However, our insurance coverage does not provide 100 percent reimbursement of potential losses resulting from these operational hazards. Additionally, insurance coverage is generally not available to us for pollution events that are considered gradual, and we have limited or no insurance coverage for certain risks such as political risk, war and terrorism. Our insurance does not cover penalties or fines assessed by governmental authorities. The occurrence of a significant event against which we are not fully insured could have a material adverse effect on our profitability, financial condition and liquidity.
Limited Control on Properties Operated by Others
Certain of the properties in which we have an interest are operated by other companies and involve third-party working interest owners. We have limited influence and control over the operation or future development of such properties, including compliance with environmental, health and safety regulations or the amount of
 
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required future capital expenditures. These limitations and our dependence on the operator and other working interest owners for these properties could result in unexpected future costs and adversely affect our financial condition and results of operations.
Cyber Attacks Targeting Our Systems and Infrastructure May Adversely Impact Our Operations
The oil and gas industry has become increasingly dependent on digital technologies to conduct daily operations. Concurrently, the industry has become the subject of increased levels of cyber attack activity. Cyber attacks often attempt to gain unauthorized access to digital systems for purposes of misappropriating assets or sensitive information, corrupting data, or causing operational disruption and may be carried out by third parties or insiders. The techniques utilized range from highly sophisticated efforts to electronically circumvent network security to more traditional intelligence gathering and social engineering aimed at obtaining information necessary to gain access. Cyber attacks may also be carried out in a manner that does not require gaining unauthorized access, such as by causing denial-of-service attacks. Although we have not suffered material losses related to cyber attacks, if we were successfully attacked we may incur substantial remediation and other costs or suffer other negative consequences. Finally, as the sophistication of cyber attacks continues to evolve, we may be required to expend significant additional resources to further enhance our digital security or to remediate vulnerabilities.
Item 1B. Unresolved Staff Comments
We have no unresolved SEC Staff comments that have been outstanding greater than 180 days from December 31, 2013.
Item 3. Legal Proceedings
We are involved in various routine legal proceedings incidental to our business. However, to our knowledge as of the date of this report, there were no material pending legal proceedings to which we are a party or to which any of our property is subject.
 Item 4. Mine Safety Disclosures 
Not applicable.
 
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 PART II
 Item 5. Market for Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Our common stock is traded on the New York Stock Exchange (the “NYSE”). On February 5, 2014, there were 10,893 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 2013 and 2012, as well as the quarterly dividends per share paid during 2013 and 2012. 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    	 	
2013:	  				  				  				
Quarter Ended December 31, 2013	  	$	66.92	  	  	$	57.58	  	  	$	0.22	  	
Quarter Ended September 30, 2013	  	$	60.38	  	  	$	52.00	  	  	$	0.22	  	
Quarter Ended June 30, 2013	  	$	61.10	  	  	$	50.81	  	  	$	0.22	  	
Quarter Ended March 31, 2013	  	$	61.80	  	  	$	51.63	  	  	$	0.20	  	
2012:	  				  				  				
Quarter Ended December 31, 2012	  	$	63.00	  	  	$	50.89	  	  	$	0.20	  	
Quarter Ended September 30, 2012	  	$	63.95	  	  	$	54.56	  	  	$	0.20	  	
Quarter Ended June 30, 2012	  	$	73.14	  	  	$	54.01	  	  	$	0.20	  	
Quarter Ended March 31, 2012	  	$	76.34	  	  	$	62.13	  	  	$	0.20	  	
 
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Performance Graph
The following performance graph compares the yearly percentage change in the cumulative total shareholder return on Devon’s common stock with the cumulative total returns of the Standard & Poor’s 500 index (“the S&P 500 Index”), the group of companies included in the Crude Petroleum and Natural Gas Standard Industrial Classification code (“the SIC Code”) and a peer group of companies to which we compare our performance. The peer group includes Anadarko Petroleum Corporation, Apache Corporation, Chesapeake Energy Corporation, ConocoPhillips, Encana Corporation, EOG Resources, Inc., Hess Corporation, Marathon Oil Corporation, Murphy Oil Corporation, Newfield Exploration Company, Noble Energy, Inc., Occidental Petroleum Corporation, Pioneer Natural Resources Company and Talisman Energy, Inc. The graph was prepared assuming $100 was invested on December 31, 2008 in Devon’s common stock, the S&P 500 Index, the SIC Code and the peer group and dividends have been reinvested subsequent to the initial investment.

The graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended, except to the extent that we specifically incorporate such information by reference into such a filing. The graph and information is included for historical comparative purposes only and should not be considered indicative of future stock performance.
 
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Issuer Purchases of Equity Securities
The following table provides information regarding purchases of our common stock that were made by us during the fourth quarter of 2013. Such purchases represent shares received by us from employees and directors for the payment of personal income tax withholding on restricted stock vesting and stock option exercises.

Period	  	Total Number of
Shares Purchased	 	  	Average Price Paid
per Share	 	
October 1 – October 31	  	 	1,077	  	  	$	63.22	  	
November 1 – November 30	  	 	118,940	  	  	$	60.62	  	
December 1 – December 31	  	 	331,389	  	  	$	60.59	  	
	  	 	 	 	  				
Total	  	 	451,406	  	  	$	60.61	  	
	  	 	 	 	  				
Under the Devon Energy Corporation Incentive Savings Plan (the “Plan”), eligible employees may purchase shares of our common stock through an investment in the Devon Stock Fund (the “Stock Fund”), which is administered by an independent trustee. Eligible employees purchased approximately 52,500 shares of our common stock in 2013, at then-prevailing stock prices, that they held through their ownership in the Stock Fund. We acquired the shares of our common stock sold under the Plan through open-market purchases.
Similarly, under the Devon Canada Corporation Savings Plan (the “Canadian Plan”), eligible Canadian employees may purchase shares of our common stock through an investment in the Canadian Plan, which is administered by an independent trustee. Eligible Canadian employees purchased approximately 10,800 shares of our common stock in 2013, at then-prevailing stock prices, that they held through their ownership in the Canadian Plan. We acquired the shares sold under the Canadian Plan through open-market purchases. These shares and any interest in the Canadian Plan were offered and sold in reliance on the exemptions for offers and sales of securities made outside of the U.S., including under Regulation S for offers and sales of securities to employees pursuant to an employee benefit plan established and administered in accordance with the law of a country other than the U.S.
 Item 6. Selected Financial Data 
The financial information below should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data” of this report.

 	  	Year Ended December 31,	 	
 	  	2013	 	 	2012	 	 	2011	 	  	2010	 	  	2009	 	
 	  	(In millions, except per share amounts)	 	
Operating revenues	  	$	10,397	  	 	$	9,501	  	 	$	11,445	  	  	$	9,935	  	  	$	8,010	  	
Earnings (loss) from continuing operations (1)	  	$	(20	) 	 	$	(185	) 	 	$	2,134	  	  	$	2,333	  	  	$	(2,753	) 	
Earnings (loss) per share from continuing operations – Basic	  	$	(0.06	) 	 	$	(0.47	) 	 	$	5.12	  	  	$	5.31	  	  	$	(6.20	) 	
Earnings (loss) per share from continuing operations – Diluted	  	$	(0.06	) 	 	$	(0.47	) 	 	$	5.10	  	  	$	5.29	  	  	$	(6.20	) 	
Cash dividends per common share	  	$	0.86	  	 	$	0.80	  	 	$	0.67	  	  	$	0.64	  	  	$	0.64	  	
Weighted average common shares outstanding – Basic	  	 	406	  	 	 	404	  	 	 	417	  	  	 	440	  	  	 	444	  	
Weighted average common shares outstanding – Diluted	  	 	406	  	 	 	404	  	 	 	418	  	  	 	441	  	  	 	444	  	
Total assets (1)	  	$	42,877	  	 	$	43,326	  	 	$	41,117	  	  	$	32,927	  	  	$	29,686	  	
Long-term debt	  	$	7,956	  	 	$	8,455	  	 	$	5,969	  	  	$	3,819	  	  	$	5,847	  	
Stockholders’ equity	  	$	20,499	  	 	$	21,278	  	 	$	21,430	  	  	$	19,253	  	  	$	15,570	  	

(1)	During 2013, 2012 and 2009, we recorded noncash asset impairments totaling $2.0 billion ($1.4 billion after income taxes), $2.0 billion ($1.3 billion after income taxes) and $6.4 billion ($4.1 billion after income taxes), respectively.	
 
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 Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 
Introduction
The following discussion and analysis presents management’s perspective of our business, financial condition and overall performance. This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future and should be read in conjunction with “Item 8. Financial Statements and Supplementary Data” of this report.
Overview of 2013 Results
As an enterprise, we strive to optimize value for our shareholders by growing cash flow, earnings, production and reserves, all on a per debt-adjusted share basis. We accomplish this by executing our strategy, which is outlined in “Items 1 and 2. Business and Properties” of this report.
2013 was another year of strong execution and exciting change for Devon. Our oil-focused drilling programs not only accomplished impressive oil production growth, but also expanded margins and improved operating cash flow. Additionally, we took steps to high-grade our portfolio. We did this by announcing an accretive Eagle Ford Shale acquisition, an innovative midstream combination, and the initiation of an asset divestiture program. These actions will provide the platform from which we will deliver outstanding high-margin growth in 2014 and for many years to come.
Key measures of our 2013 performance are summarized below, which exclude amounts from our discontinued operations.

 	  	Year Ended December 31,	 	
 	  	2013	 	 	Change	 	 	2012	 	 	Change	 	 	2011	 	
 	  	($ in millions, except per share amounts)	 	
Net earnings (loss)	  	$	(20	) 	 	 	+89	%	 	$	(185	) 	 	 	-109	%	 	$	2,134	  	
Adjusted earnings (1)	  	$	1,734	  	 	 	+33	% 	 	$	1,305	  	 	 	-49	%	 	$	2,578	  	
Earnings (loss) per share	  	$	(0.06	) 	 	 	+87	%	 	$	(0.47	) 	 	 	-109	%	 	$	5.10	  	
Adjusted earnings per share (1)	  	$	4.26	  	 	 	+32	% 	 	$	3.22	  	 	 	-48	%	 	$	6.17	  	
Production (MBoe/d)	  	 	692.9	  	 	 	+2	% 	 	 	682.3	  	 	 	+4	% 	 	 	657.7	  	
Realized price per Boe	  	$	33.70	  	 	 	+18	% 	 	$	28.65	  	 	 	-17	%	 	$	34.64	  	
Adjusted operating income per Boe (2)	  	$	19.86	  	 	 	+2	% 	 	$	19.41	  	 	 	-23	%	 	$	25.11	  	
Operating cash flow	  	$	5,436	  	 	 	+10	% 	 	$	4,930	  	 	 	-21	%	 	$	6,246	  	
Capitalized costs	  	$	6,643	  	 	 	-22	%	 	$	8,474	  	 	 	+9	% 	 	$	7,795	  	
Shareholder distributions (3)	  	$	348	  	 	 	+8	% 	 	$	324	  	 	 	-88	%	 	$	2,610	  	
Reserves (MMBoe)	  	 	2,963	  	 	 	0	% 	 	 	2,963	  	 	 	-1	%	 	 	3,005	  	

(1)	Adjusted earnings, adjusted earnings per share and adjusted operating cash flow are not financial measures prepared in accordance with accounting principles generally accepted in the United States (GAAP). For a description of adjusted earnings, adjusted earnings per share and adjusted operating cash flow as well as reconciliations to the comparable GAAP measures, see “Non-GAAP Measures” in this Item 7.	
(2)	Computed as revenues from commodity sales, commodity derivatives settlements, and marketing and midstream operations, less expenses for lease operations, marketing and midstream operations, general and administration, taxes other than income taxes and interest, with the result divided by total production.	
(3)	Includes common stock dividends and share repurchases.	
Our 2013 net loss resulted from noncash asset impairments, which reduced our earnings by $2.0 billion ($1.4 billion after tax). Excluding the asset impairments and other items typically excluded by securities analysts, our adjusted earnings were $1.7 billion, or $4.26 per diluted share. This compares to adjusted earnings of $1.3 billion, or $3.22 per diluted share in 2012.
 
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Our 2013 adjusted earnings, adjusted earnings per share and adjusted operating income per Boe all increased compared to 2012. The improved 2013 results were driven primarily by increases in gas prices, oil volumes and oil realizations. These factors also contributed to higher adjusted operating cash flow, which combined with a reduction in capitalized costs, caused our cash flow deficit to narrow considerably in 2013.
Business and Industry Outlook
North American crude oil and natural gas prices have historically been volatile based on supply and demand dynamics and we expect this volatility to continue into 2014. Although natural gas prices improved in 2013 compared to 2012, natural gas continues to be challenged due to an imbalance between supply and demand across North America. However, arctic air movements across North America during the early weeks of 2014 have caused natural gas demand to surge. As storage inventories have significantly declined in response to the recent weather conditions, natural gas prices have surpassed $5 per Mcf for the first time since the summer of 2010. Further helping demand, new uses of natural gas in industrial, power and other sectors will continue to help support price dynamics. Nevertheless, we still expect natural gas prices to be range-bound as natural gas supply continues to grow, particularly in the U.S. Looking to 2014, we expect natural gas prices will remain relatively consistent or possibly increase moderately from 2013 levels.
Similar to natural gas in recent years, a surge in the supply of natural gas liquids has kept prices challenged. The majority of our natural gas is comprised of ethane, one of the most price-challenged liquids processed from the natural gas stream. We expect 2014 natural gas liquids prices will be range-bound and remain relatively flat compared to 2013.
Crude oil prices remained relatively stable throughout 2013, and oil continues to be more valuable than natural gas on a relative energy-equivalent basis. As a result, we and other producers have been focused on growing oil production. North American crude oil supply continues to increase due to the continued use of horizontal drilling technology throughout the U.S. and expansions of heavy oil production operations primarily in Canada. Global crude oil demand is expected to grow with supply in 2014. As crude oil supply grows, transportation capacity to downstream markets will be increasingly important. Bottlenecks and other transportation limitations may continue to add volatility among U.S. and Canadian grades of oil. However, we expect 2014 oil prices will remain relatively consistent with 2013.
We exited 2013 with a production profile comprised of roughly 55 percent natural gas, 25 percent oil, and 20 percent natural gas liquids. Recognizing the relative value of crude oil, we are devoting the vast majority of our 2014 capital investment toward growing our oil production, particularly the sweet grades of oil found in the U.S. To make a significant shift in our production profile, we expect to complete a $6 billion acquisition of Eagle Ford Shale assets in the first quarter of 2014 and divest non-core, dry natural gas assets throughout 2014. Once these transactions are complete, we expect oil will represent more than 30 percent of our production profile.
Further enhancing the value of our assets, we are combining substantially all of our U.S. midstream assets with Crosstex Energy, Inc.’s and Crosstex Energy, L.P.’s assets to form a new midstream business. The new business will consist of EnLink Midstream Partners, L.P. (the “Partnership”) and EnLink Midstream, LLC (“EnLink”), a master limited partnership and a general partner entity, which will both be publicly traded entities. The new midstream business will own Devon’s midstream assets in the Barnett Shale in north Texas and the Cana and Arkoma Woodford Shales in Oklahoma, as well as Devon’s economic interest in Gulf Coast Fractionators in Mt. Belvieu, Texas. Devon will own a 70 percent controlling interest in EnLink and an approximate 53 percent controlling interest in the Partnership.
Results of Operations
All amounts in this document related to our International operations are presented as discontinued. Therefore, the production, revenue and expense amounts presented in this “Results of Operations” section exclude amounts related to our International assets unless otherwise noted.
 
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Oil, Gas and NGL Production

 	  	Year Ended December 31,	 	
 	  	2013	 	  	Change	 	 	2012	 	  	Change	 	 	2011	 	
Oil (MBbls/d)	  				  				 				  				 				
Anadarko Basin	  	 	9.1	  	  	 	+38	% 	 	 	6.6	  	  	 	+52	% 	 	 	4.4	  	
Barnett Shale	  	 	2.0	  	  	 	+22	% 	 	 	1.6	  	  	 	-12	%	 	 	1.8	  	
Mississippian-Woodford Trend	  	 	4.7	  	  	 	+625	% 	 	 	0.7	  	  	 	N/M	  	 	 	—  	  	
Permian Basin	  	 	46.4	  	  	 	+28	% 	 	 	36.3	  	  	 	+30	% 	 	 	27.8	  	
Rockies	  	 	7.8	  	  	 	+30	% 	 	 	6.0	  	  	 	+38	% 	 	 	4.3	  	
Other	  	 	3.0	  	  	 	+5	% 	 	 	2.8	  	  	 	+12	% 	 	 	2.6	  	
	  	 	 	 	  				 	 	 	 	  				 	 	 	 	
U.S. core and emerging properties	  	 	73.0	  	  	 	+35	% 	 	 	54.0	  	  	 	+32	% 	 	 	40.9	  	
Canadian heavy oil	  	 	27.9	  	  	 	-3	%	 	 	28.8	  	  	 	-8	%	 	 	31.2	  	
	  	 	 	 	  				 	 	 	 	  				 	 	 	 	
Total core and emerging properties	  	 	100.9	  	  	 	+22	% 	 	 	82.8	  	  	 	+15	% 	 	 	72.1	  	
Non-core properties	  	 	15.9	  	  	 	+2	% 	 	 	15.7	  	  	 	+1	% 	 	 	15.6	  	
	  	 	 	 	  				 	 	 	 	  				 	 	 	 	
Total	  	 	116.8	  	  	 	+19	% 	 	 	98.5	  	  	 	+12	% 	 	 	87.7	  	
	  	 	 	 	  				 	 	 	 	  				 	 	 	 	
Bitumen (MBbls/d)	  				  				 				  				 				
Canadian heavy oil	  	 	51.5	  	  	 	+8	% 	 	 	47.6	  	  	 	+37	% 	 	 	34.8	  	
						
Gas (MMcf/d)	  				  				 				  				 				
Anadarko Basin	  	 	285.8	  	  	 	0	%	 	 	286.3	  	  	 	+25	% 	 	 	229.1	  	
Barnett Shale	  	 	1,024.9	  	  	 	-5	%	 	 	1,074.6	  	  	 	+7	% 	 	 	1,006.0	  	
Mississippian-Woodford Trend	  	 	11.6	  	  	 	+701	% 	 	 	1.5	  	  	 	N/M	  	 	 	—  	  	
Permian Basin	  	 	104.8	  	  	 	+24	% 	 	 	84.8	  	  	 	+13	% 	 	 	75.1	  	
Rockies	  	 	78.0	  	  	 	-28	%	 	 	108.6	  	  	 	-23	%	 	 	140.3	  	
Other	  	 	153.8	  	  	 	-12	%	 	 	175.0	  	  	 	-16	%	 	 	208.3	  	
	  	 	 	 	  				 	 	 	 	  				 	 	 	 	
U.S. core and emerging properties	  	 	1,658.9	  	  	 	-4	%	 	 	1,730.8	  	  	 	+4	% 	 	 	1,658.8	  	
Canadian heavy oil	  	 	22.3	  	  	 	-18	%	 	 	27.2	  	  	 	-16	%	 	 	32.3	  	
	  	 	 	 	  				 	 	 	 	  				 	 	 	 	
Total core and emerging properties	  	 	1,681.2	  	  	 	-4	%	 	 	1,758.0	  	  	 	+3	% 	 	 	1,691.1	  	
Non-core properties	  	 	712.2	  	  	 	-12	%	 	 	804.8	  	  	 	-12	%	 	 	918.6	  	
	  	 	 	 	  				 	 	 	 	  				 	 	 	 	
Total	  	 	2,393.4	  	  	 	-7	%	 	 	2,562.8	  	  	 	-2	%	 	 	2,609.7	  	
	  	 	 	 	  				 	 	 	 	  				 	 	 	 	
NGLs (MBbls/d)	  				  				 				  				 				
Anadarko Basin	  	 	24.9	  	  	 	+43	% 	 	 	17.3	  	  	 	+43	% 	 	 	12.2	  	
Barnett Shale	  	 	54.9	  	  	 	+17	% 	 	 	46.8	  	  	 	+7	% 	 	 	43.7	  	
Mississippian-Woodford Trend	  	 	1.2	  	  	 	+770	% 	 	 	0.1	  	  	 	N/M	  	 	 	—  	  	
Permian Basin	  	 	14.1	  	  	 	+26	% 	 	 	11.2	  	  	 	+29	% 	 	 	8.7	  	
Rockies	  	 	0.8	  	  	 	+5	% 	 	 	0.8	  	  	 	-5	% 	 	 	0.8	  	
Other	  	 	11.1	  	  	 	+1	% 	 	 	11.0	  	  	 	-11	%	 	 	12.3	  	
	  	 	 	 	  				 	 	 	 	  				 	 	 	 	
U.S. core and emerging properties	  	 	107.0	  	  	 	+23	% 	 	 	87.2	  	  	 	+12	% 	 	 	77.7	  	
Non-core properties	  	 	18.7	  	  	 	-14	%	 	 	21.9	  	  	 	-3	%	 	 	22.6	  	
	  	 	 	 	  				 	 	 	 	  				 	 	 	 	
Total	  	 	125.7	  	  	 	+15	% 	 	 	109.1	  	  	 	+9	% 	 	 	100.3	  	
	  	 	 	 	  				 	 	 	 	  				 	 	 	 	
Combined (MBoe/d)	  				  				 				  				 				
Anadarko Basin	  	 	81.7	  	  	 	+14	% 	 	 	71.7	  	  	 	+31	% 	 	 	54.7	  	
Barnett Shale	  	 	227.7	  	  	 	0	% 	 	 	227.5	  	  	 	+7	% 	 	 	213.1	  	
Mississippian-Woodford Trend	  	 	7.9	  	  	 	+662	% 	 	 	1.0	  	  	 	N/M	  	 	 	—  	  	
Permian Basin	  	 	78.0	  	  	 	+27	% 	 	 	61.6	  	  	 	+26	% 	 	 	49.0	  	
Rockies	  	 	21.5	  	  	 	-13	%	 	 	24.9	  	  	 	-13	%	 	 	28.5	  	
Other	  	 	39.6	  	  	 	-8	%	 	 	43.0	  	  	 	-13	%	 	 	49.7	  	
	  	 	 	 	  				 	 	 	 	  				 	 	 	 	
U.S. core and emerging properties	  	 	456.4	  	  	 	+6	% 	 	 	429.7	  	  	 	+9	% 	 	 	395.0	  	
Canadian heavy oil	  	 	83.1	  	  	 	+3	% 	 	 	80.9	  	  	 	+13	% 	 	 	71.4	  	
	  	 	 	 	  				 	 	 	 	  				 	 	 	 	
Total core and emerging properties	  	 	539.5	  	  	 	+6	% 	 	 	510.6	  	  	 	+9	% 	 	 	466.4	  	
Non-core properties	  	 	153.4	  	  	 	-11	%	 	 	171.7	  	  	 	-10	%	 	 	191.3	  	
	  	 	 	 	  				 	 	 	 	  				 	 	 	 	
Total	  	 	692.9	  	  	 	+2	% 	 	 	682.3	  	  	 	+4	% 	 	 	657.7	  	

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Oil, Gas and NGL Pricing

 	  	Year Ended December 31,	 	
 	  	2013 (1)	 	  	Change	 	 	2012 (1)	 	  	Change	 	 	2011 (1)	 	
Oil (per Bbl)	  				  				 				  				 				
U.S.	  	$	94.52	  	  	 	+7	% 	 	$	88.68	  	  	 	-3	%	 	$	91.19	  	
Canada	  	$	69.18	  	  	 	+1	% 	 	$	68.29	  	  	 	-8	%	 	$	74.32	  	
Total	  	$	86.02	  	  	 	+7	% 	 	$	80.43	  	  	 	-3	%	 	$	83.16	  	
Bitumen (per Bbl)	  				  				 				  				 				
Canada	  	$	48.04	  	  	 	+1	% 	 	$	47.57	  	  	 	-18	%	 	$	58.16	  	
Gas (per Mcf)	  				  				 				  				 				
U.S.	  	$	3.10	  	  	 	+33	% 	 	$	2.32	  	  	 	-34	%	 	$	3.50	  	
Canada	  	$	3.05	  	  	 	+23	% 	 	$	2.49	  	  	 	-36	%	 	$	3.87	  	
Total	  	$	3.09	  	  	 	+31	% 	 	$	2.36	  	  	 	-34	%	 	$	3.58	  	
NGLs (per Bbl)	  				  				 				  				 				
U.S.	  	$	25.75	  	  	 	-10	%	 	$	28.49	  	  	 	-28	%	 	$	39.47	  	
Canada	  	$	46.17	  	  	 	-5	%	 	$	48.63	  	  	 	-13	%	 	$	55.99	  	
Total	  	$	27.33	  	  	 	-10	%	 	$	30.42	  	  	 	-26	%	 	$	41.10	  	
Combined (per Boe)	  				  				 				  				 				
U.S.	  	$	31.59	  	  	 	+23	% 	 	$	25.59	  	  	 	-18	%	 	$	31.31	  	
Canada	  	$	39.91	  	  	 	+8	% 	 	$	37.01	  	  	 	-14	%	 	$	43.23	  	
Total	  	$	33.70	  	  	 	+18	% 	 	$	28.65	  	  	 	-17	%	 	$	34.64	  	

(1)	Prices presented exclude any effects due to oil, gas and NGL derivatives.	
Commodity Sales
The volume and price changes in the tables above caused the following changes to our oil, gas and NGL sales.

 	  	Oil	 	 	Bitumen	 	 	Gas	 	 	NGLs	 	 	Total	 	
 	  	(In millions)	 	
2011 sales	  	$	2,660	  	 	$	739	  	 	$	3,411	  	 	$	1,505	  	 	$	8,315	  	
Change due to volumes	  	 	337	  	 	 	273	  	 	 	(52	) 	 	 	137	  	 	 	695	  	
Change due to prices	  	 	(98	) 	 	 	(184	) 	 	 	(1,148	) 	 	 	(427	) 	 	 	(1,857	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
2012 sales	  	$	2,899	  	 	$	828	  	 	$	2,211	  	 	$	1,215	  	 	$	7,153	  	
Change due to volumes	  	 	531	  	 	 	65	  	 	 	(152	) 	 	 	181	  	 	 	625	  	
Change due to prices	  	 	238	  	 	 	9	  	 	 	639	  	 	 	(142	) 	 	 	744	  	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
2013 sales	  	$	3,668	  	 	$	902	  	 	$	2,698	  	 	$	1,254	  	 	$	8,522	  	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Volumes 2013 vs. 2012 – Upstream sales increased $625 million due to a 15 percent increase in our liquids production, partially offset by a 7 percent decline in our gas production. Oil production was the largest driver of the increase, accounting for 85 percent of the higher sales. Largely due to continued development of our properties in the Permian Basin, the Mississippian-Woodford Trend and the Anadarko Basin, our oil sales increased $531 million. Bitumen sales increased $65 million due to development of our Jackfish thermal heavy oil projects in Canada. Additionally, our NGL sales increased $181 million as a result of continued drilling in the liquids-rich gas portions of the Barnett Shale and the Anadarko Basin. These increases were partially offset by a 7 percent decrease in our 2013 gas production, resulting in a $152 million decline in sales.
Volumes 2012 vs. 2011 – Upstream sales increased $695 million due to a 4 percent increase in production. Oil and bitumen production were the largest drivers of the increase, accounting for nearly 90 percent of the higher sales. As a result of continued development of our liquids-rich properties in the Permian Basin, our oil
 
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sales increased $337 million. Bitumen sales increased $273 million due to development of our Jackfish thermal heavy oil projects in Canada. Additionally, our NGL sales increased $137 million as a result of continued drilling in the liquids-rich gas portions of the Barnett Shale and the Anadarko Basin. These increases were partially offset by a slight decrease in our 2012 gas production, resulting in a $52 million decline in sales.
Prices 2013 vs. 2012 – Upstream sales increased $744 million due to an 18 percent increase in our realized price without hedges. Our gas sales were the most significantly impacted with a $639 million increase in sales. The change in our gas price was largely due to higher North American regional index prices upon which our gas sales are based. Our liquid sales increased $105 million due to higher oil and bitumen sales partially offset by lower NGL sales. The largest contributors to the higher liquids prices were an increase in the average NYMEX West Texas Intermediate index price and a slightly higher bitumen realized price, partially offset by lower NGL prices at the Mont Belvieu, Texas hub.
Prices 2012 vs. 2011 – Upstream sales decreased $1.9 billion due to a 17 percent decrease in our realized price without hedges. Our gas sales were the most significantly impacted with a $1.1 billion decrease in sales. The change in our gas price was largely due to fluctuations of the North American regional index prices upon which our gas sales are based. We also experienced declines in our NGL, bitumen and oil sales due to our realized price. The largest contributors to the lower liquids prices were lower NGL prices at the Mont Belvieu, Texas hub and wider bitumen differentials.
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 fair value 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 fair value gains and losses.

 	  	Year Ended December 31,	 	
 	  	2013	 	 	2012	 	 	2011	 	
 	  	(In millions)	 	
Cash settlements:	  				 				 				
Oil derivatives	  	$	55	  	 	$	259	  	 	$	(26	) 	
Gas derivatives	  	 	139	  	 	 	610	  	 	 	416	  	
NGL derivatives	  	 	1	  	 	 	1	  	 	 	2	  	
	  	 	 	 	 	 	 	 	 	 	 	 	
Total cash settlements	  	 	195	  	 	 	870	  	 	 	392	  	
	  	 	 	 	 	 	 	 	 	 	 	 	
Gains (losses) on fair value changes:	  				 				 				
Oil derivatives	  	 	(243	) 	 	 	150	  	 	 	185	  	
Gas derivatives	  	 	(139	) 	 	 	(330	) 	 	 	305	  	
NGL derivatives	  	 	(4	) 	 	 	3	  	 	 	(1	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	
Total gains (losses) on fair value changes	  	 	(386	) 	 	 	(177	) 	 	 	489	  	
	  	 	 	 	 	 	 	 	 	 	 	 	
Oil, gas and NGL derivatives	  	$	(191	) 	 	$	693	  	 	$	881	  	

																					
 	  	Year Ended December 31, 2013	 	
 	  	Oil
(Per  Bbl)	 	  	Bitumen
(Per Bbl)	 	  	Gas
(Per Mcf)	 	  	NGLs
(Per Bbl)	 	  	Boe
(Per Boe)	 	
Realized price without hedges	  	$	86.02	  	  	$	48.04	  	  	$	3.09	  	  	$	27.33	  	  	$	33.70	  	
Cash settlements of hedges	  	 	1.30	  	  	 	—  	  	  	 	0.16	  	  	 	0.01	  	  	 	0.77	  	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Realized price, including cash settlements	  	$	87.32	  	  	$	48.04	  	  	$	3.25	  	  	$	27.34	  	  	$	34.47	  	

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 	  	Year Ended December 31, 2012	 	
 	  	Oil
(Per  Bbl)	 	 	Bitumen
(Per Bbl)	 	  	Gas
(Per  Mcf)	 	  	NGLs
(Per Bbl)	 	  	Boe
(Per  Boe)	 	
Realized price without hedges	  	$	80.43	  	 	$	47.57	  	  	$	2.36	  	  	$	30.42	  	  	$	28.65	  	
Cash settlements of hedges	  	 	7.19	  	 	 	—  	  	  	 	0.65	  	  	 	0.04	  	  	 	3.48	  	
	  	 	 	 	 	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Realized price, including cash settlements	  	$	87.62	  	 	$	47.57	  	  	$	3.01	  	  	$	30.46	  	  	$	32.13	  	

 	  	Year Ended December 31, 2011	 	
 	  	Oil
(Per Bbl)	 	 	Bitumen
(Per Bbl)	 	  	Gas
(Per Mcf)	 	  	NGLs
(Per Bbl)	 	  	Boe
(Per Boe)	 	
Realized price without hedges	  	$	83.16	  	 	$	58.16	  	  	$	3.58	  	  	$	41.10	  	  	$	34.64	  	
Cash settlements of hedges	  	 	(0.81	) 	 	 	—  	  	  	 	0.44	  	  	 	0.07	  	  	 	1.63	  	
	  	 	 	 	 	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Realized price, including cash settlements	  	$	82.35	  	 	$	58.16	  	  	$	4.02	  	  	$	41.17	  	  	$	36.27	  	
	  	 	 	 	 	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Cash settlements as presented in the tables above represent realized gains or losses related to these various instruments. A summary of our open commodity derivative positions is included in Note 2 to the financial statements included in “Item 8. Financial Statements and Supplementary Data” of this report. Our oil, gas and NGL derivatives include price swaps, costless collars, basis swaps and call options. To facilitate a portion of our price swaps, we sold gas and oil call options for 2014 through 2016. The call options give counterparties the right to purchase production at a predetermined price.
In addition to cash settlements, we also recognize fair value changes on our oil, gas and NGL derivative instruments in each reporting period. The changes in fair value resulted from new positions and settlements that occurred during each period, as well as the relationships between contract prices and the associated forward curves. Including the cash settlements discussed above, our oil, gas and NGL derivatives incurred net losses of $191 million in 2013 and generated net gains of $693 million and $881 million during 2012 and 2011, respectively.
Marketing and Midstream Revenues and Operating Costs and Expenses

 	  	Year Ended December 31,	 	
 	  	2013	 	  	Change	 	 	2012	 	  	Change	 	 	2011	 	
 	  	($ in millions)	 	
Revenues	  	$	2,066	  	  	 	+25	% 	 	$	1,655	  	  	 	-27	%	 	$	2,249	  	
Operating costs and expenses	  	 	1,553	  	  	 	+25	% 	 	 	1,246	  	  	 	-27	%	 	 	1,716	  	
	  	 	 	 	  				 	 	 	 	  				 	 	 	 	
Operating profit	  	$	513	  	  	 	+25	% 	 	$	409	  	  	 	-23	%	 	$	533	  	
	  	 	 	 	  				 	 	 	 	  				 	 	 	 	
2013 vs. 2012 Marketing and midstream operating profit increased $104 million, or 25 percent, from the year ended December 31, 2012 to the year ended December 31, 2013.
Our profit largely increased due to the effects of pricing and marketing activities. Our profit increased nearly $40 million due to our NGL and gas marketing. Additionally, changes in pricing led to an increase in operating profit of approximately $32 million. Higher residue natural gas prices were the primary contributor to the higher profit.
Higher gathering and processing volumes were responsible for an increase in operating profit of $21 million. Higher volumes were primarily the result of NGL production. The increase was largely driven by higher inlet volumes at the Cana processing facility, improved efficiencies at the Cana and Bridgeport processing facilities and downtime impacting our Bridgeport processing facility in 2012.
 
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Operations and maintenance expenses decreased $11 million, or 6 percent primarily due to expenditures for regulatory testing in 2012.
2012 vs. 2011 Marketing and midstream operating profit decreased $124 million, or 23 percent, from the year ended December 31, 2011 to the year ended December 31, 2012.
Our profit largely decreased due to the effects of pricing and marketing activities. Changes in pricing led to a decrease in operating profit of approximately $106 million. Lower residue natural gas and NGL prices were the primary contributor to the lower profit. Additionally, our profit decreased $13 million primarily due to lower profits on our NGL marketing.
Higher gathering, processing and transportation volumes were responsible for an increase in operating profit of $11 million. Higher volumes were primarily the result of additional throughput at Bridgeport and Cana gathering.
Operations and maintenance expenses increased $16 million, or 9 percent primarily due to expenditures for regulatory testing in 2012.
Lease Operating Expenses (“LOE”)

 	  	Year Ended December 31,	 	
 	  	2013	 	  	Change	 	 	2012	 	  	Change	 	 	2011	 	
LOE ($ in millions):	  				  				 				  				 				
U.S.	  	$	1,257	  	  	 	+19	% 	 	$	1,059	  	  	 	+14	% 	 	$	925	  	
Canada	  	 	1,011	  	  	 	-0	%	 	 	1,015	  	  	 	+10	% 	 	 	926	  	
	  	 	 	 	  				 	 	 	 	  				 	 	 	 	
Total	  	$	2,268	  	  	 	+9	% 	 	$	2,074	  	  	 	+12	% 	 	$	1,851	  	
	  	 	 	 	  				 	 	 	 	  				 	 	 	 	
LOE per Boe:	  				  				 				  				 				
U.S.	  	$	6.65	  	  	 	+15	% 	 	$	5.79	  	  	 	+8	% 	 	$	5.35	  	
Canada	  	$	15.78	  	  	 	+4	% 	 	$	15.18	  	  	 	+10	% 	 	$	13.82	  	
Total	  	$	8.97	  	  	 	+8	% 	 	$	8.30	  	  	 	+8	% 	 	$	7.71	  	
2013 vs. 2012 LOE increased $0.67 per Boe largely because of our liquids production growth, particularly in the Permian Basin and the Mississippian-Woodford Trend in the U.S. These projects generally require a higher per unit cost than our gas projects, particularly because they are in the early stages of development. Additionally, we conducted a turnaround at Jackfish 2 in the third quarter of 2013, contributing to higher unit costs in 2013. We also experienced inflationary pressures on costs in certain operating areas, which increased LOE per Boe.
2012 vs. 2011 LOE increased $0.59 per Boe largely because of our oil production growth, particularly at our Jackfish thermal heavy oil projects in Canada and in the Permian Basin in the U.S. We also experienced inflationary pressures on costs in certain operating areas, which increased LOE per Boe.
General and Administrative Expenses (“G&A”)

 	  	Year Ended December 31,	 	
 	  	2013	 	 	Change	 	 	2012	 	 	Change	 	 	2011	 	
 	  	($ in millions)	 	
Gross G&A	  	$	1,128	  	 	 	-4	%	 	$	1,171	  	 	 	+13	% 	 	$	1,036	  	
Capitalized G&A	  	 	(368	) 	 	 	+3	% 	 	 	(359	) 	 	 	+7	% 	 	 	(337	) 	
Reimbursed G&A	  	 	(143	) 	 	 	+19	% 	 	 	(120	) 	 	 	+5	% 	 	 	(114	) 	
	  	 	 	 	 				 	 	 	 	 				 	 	 	 	
Net G&A	  	$	617	  	 	 	-11	%	 	$	692	  	 	 	+18	% 	 	$	585	  	
	  	 	 	 	 				 	 	 	 	 				 	 	 	 	
Net G&A per Boe	  	$	2.44	  	 	 	-12	%	 	$	2.77	  	 	 	+14	% 	 	$	2.44	  	

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2013 vs. 2012 Net G&A and net G&A per Boe decreased largely due to lower personnel expenses and office rent as a result of the Houston office consolidation in 2012 and lower costs as a result of the company-wide implementation of SAP in Q2 2012. Higher reimbursements due to increased liquids drilling activity and reimbursement rates also contributed to the decrease in net G&A and net G&A per Boe.
2012 vs. 2011 Net G&A and net G&A per Boe increased largely due to higher employee compensation and benefits. Employee costs increased primarily from an expansion of our workforce as part of growing production operations at certain of our key areas, including Jackfish, the Permian Basin and the Anadarko Basin.
Production and Property Taxes

 	  	Year Ended December 31,	 	
 	  	2013	 	 	Change	 	 	2012	 	 	Change	 	 	2011	 	
 	  	($ in millions)	 	
Production	  	$	275	  	 	 	+23	% 	 	$	224	  	 	 	-10	%	 	$	248	  	
Property and other	  	 	186	  	 	 	-2	%	 	 	190	  	 	 	+8	% 	 	 	176	  	
	  	 	 	 	 				 	 	 	 	 				 	 	 	 	
Production and property taxes	  	$	461	  	 	 	+11	% 	 	$	414	  	 	 	-3	%	 	$	424	  	

Percentage of oil, gas and NGL revenue:	  				 				 				 				 				
Production	  	 	3.23	% 	 	 	+3	% 	 	 	3.13	% 	 	 	+5	% 	 	 	2.98	% 	
Property and other	  	 	2.18	% 	 	 	-18	%	 	 	2.65	% 	 	 	+25	% 	 	 	2.12	% 	
	  	 	 	 	 				 	 	 	 	 				 	 	 	 	
Total	  	 	5.41	% 	 	 	-6	%	 	 	5.78	% 	 	 	+13	% 	 	 	5.10	% 	
	  	 	 	 	 				 	 	 	 	 				 	 	 	 	
2013 vs. 2012 Production and property taxes increased primarily due to an increase in our U.S. revenues, on which the majority of our production taxes are assessed.
2012 vs. 2011 Production and property taxes decreased primarily due to a decrease in our U.S. revenues, on which the majority of our production taxes are assessed.
Depreciation, Depletion and Amortization (“DD&A”)

 	  	Year Ended December 31,	 	
 	  	2013	 	  	Change	 	 	2012	 	  	Change	 	 	2011	 	
 	  	($ in millions)	 	
DD&A:	  				  				 				  				 				
Oil & gas properties	  	$	2,465	  	  	 	-2	%	 	$	2,526	  	  	 	+27	% 	 	$	1,987	  	
Other properties	  	 	315	  	  	 	+11	% 	 	 	285	  	  	 	+9	% 	 	 	261	  	
	  	 	 	 	  				 	 	 	 	  				 	 	 	 	
Total	  	$	2,780	  	  	 	-1	%	 	$	2,811	  	  	 	+25	% 	 	$	2,248	  	

DD&A per Boe:	  				  				 				  				 				
Oil & gas properties	  	$	9.75	  	  	 	-4	%	 	$	10.12	  	  	 	+22	% 	 	$	8.28	  	
Other properties	  	 	1.24	  	  	 	+9	% 	 	 	1.14	  	  	 	+5	% 	 	 	1.09	  	
	  	 	 	 	  				 	 	 	 	  				 	 	 	 	
Total	  	$	10.99	  	  	 	-2	%	 	$	11.26	  	  	 	+20	% 	 	$	9.37	  	
	  	 	 	 	  				 	 	 	 	  				 	 	 	 	
A description of how DD&A of our oil and gas properties is calculated is included in Note 1 to the financial statements included in “Item 8. Financial Statements and Supplementary Data” of this report. Generally, when reserve volumes are revised up or down, then the DD&A rate per unit of production will change inversely. However, when the depletable base changes, then the DD&A rate moves in the same direction. The per unit DD&A rate is not affected by production volumes. Absolute or total DD&A, as opposed to the rate per unit of production, generally moves in the same direction as production volumes.
 
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2013 vs. 2012 Oil and gas property DD&A decreased $61 million largely as a result of the asset impairment charges recognized in 2012 and 2013. Depreciation and amortization on our other properties increased $30 million largely from the construction of our new headquarters in Oklahoma City and natural gas pipeline development in the Cana-Woodford Shale.
2012 vs. 2011 Oil and gas property DD&A increased $460 million due to a 22 percent increase in the DD&A rate and $79 million due to our 4 percent increase in production. The largest contributors to the higher rate were our 2012 drilling and development activities.
Asset Impairments

 	  	Year Ended December 31, 2013	 	  	Year Ended December 31, 2012	 	
 	  	    Gross    	 	  	    Net of Taxes    	 	  	    Gross    	 	  	    Net of Taxes    	 	
 	  	(In millions)	 	
U.S. oil and gas assets	  	$	1,110	  	  	$	707	  	  	$	1,793	  	  	$	1,142	  	
Canada oil and gas assets	  	 	843	  	  	 	632	  	  	 	163	  	  	 	122	  	
Midstream assets	  	 	23	  	  	 	14	  	  	 	68	  	  	 	44	  	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total asset impairments	  	$	1,976	  	  	$	1,353	  	  	$	2,024	  	  	$	1,308	  	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Oil and Gas Impairments
Under the full cost method of accounting, capitalized costs of oil and gas properties are subject to a quarterly full cost ceiling test, which is discussed in Note 1 to the financial statements under “Item 8. Consolidated Financial Statements” of this report.
The oil and gas impairments resulted primarily from declines in the U.S. and Canada full cost ceilings. The lower ceiling values resulted primarily from decreases in the 12-month average trailing prices for oil, natural gas and NGLs, which have reduced proved reserve values.
Midstream Impairments
Due to declining natural gas production resulting from low natural gas and NGL prices, we determined that the carrying amounts of certain of our midstream facilities were not recoverable from estimated future cash flows. Consequently, the assets were written down to their estimated fair values, which were determined using discounted cash flow models.
Net Financing Costs

 	  	Year Ended December 31,	 	
 	  	2013	 	 	Change	 	 	2012	 	 	Change	 	 	2011	 	
 	  	($ in millions)	 	
Interest based on debt outstanding	  	$	466	  	 	 	+6	% 	 	$	440	  	 	 	+6	% 	 	$	414	  	
Capitalized interest	  	 	(56	) 	 	 	+15	% 	 	 	(48	) 	 	 	-33	%	 	 	(72	) 	
Other fees and expenses	  	 	27	  	 	 	+94	% 	 	 	14	  	 	 	+33	% 	 	 	10	  	
	  	 	 	 	 				 	 	 	 	 				 	 	 	 	
Interest expense	  	 	437	  	 	 	+8	% 	 	 	406	  	 	 	+15	% 	 	 	352	  	
Interest income	  	 	(20	) 	 	 	-43	%	 	 	(36	) 	 	 	+69	% 	 	 	(21	) 	
	  	 	 	 	 				 	 	 	 	 				 	 	 	 	
Net financing costs	  	$	417	  	 	 	+13	% 	 	$	370	  	 	 	+12	% 	 	$	331	  	
	  	 	 	 	 				 	 	 	 	 				 	 	 	 	
2013 vs. 2012 Net financing costs increased primarily due to additional debt borrowings and associated fees, partially offset by lower weighted average interest rates and higher capitalized interest. Borrowings were primarily used to fund capital expenditures in excess of our operating cash flow and to provide funding for our planned Eagle Ford Shale acquisition that is expected to close in the first quarter of 2014.
 
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2012 vs. 2011 Net financing costs increased primarily due to additional debt borrowings and lower capitalized interest, partially offset by lower weighted average interest rates. Borrowings were primarily used to fund capital expenditures in excess of our operating cash flow and divestiture proceeds.
Restructuring Costs

 	  	Year Ended December 31,	 	
 	  	2013	 	  	2012	 	 	2011	 	
 	  	(In millions)	 	
Office consolidation:	  				  				 				
Employee severance and retention	  	$	13	  	  	$	77	  	 	$	—  	  	
Lease obligations and other	  	 	41	  	  	 	3	  	 	 	—  	  	
	  	 	 	 	  	 	 	 	 	 	 	 	
Total	  	 	54	  	  	 	80	  	 	 	—  	  	
	  	 	 	 	  	 	 	 	 	 	 	 	
Offshore divestitures:	  				  				 				
Employee severance	  	$	—  	  	  	$	(3	) 	 	$	8	  	
Lease obligations and other	  	 	—  	  	  	 	(3	) 	 	 	(10	) 	
	  	 	 	 	  	 	 	 	 	 	 	 	
Total	  	 	—  	  	  	 	(6	) 	 	 	(2	) 	
	  	 	 	 	  	 	 	 	 	 	 	 	
Restructuring costs (1)	  	$	54	  	  	$	74	  	 	$	(2	) 	

(1)	Restructuring costs related to our discontinued operations totaled $(2) million in 2011. These costs primarily consist of employee severance and are not included in the table. There were no costs related to discontinued operations in 2013 or 2012.	
Office Consolidation
In October 2012, we announced plans to consolidate our U.S. personnel into a single operations group centrally located at our corporate headquarters in Oklahoma City. As a result, we closed our office in Houston, transferred operational responsibilities for assets in south Texas, east Texas and Louisiana to Oklahoma City and incurred $134 million of restructuring costs associated with the consolidation.
Employee severance and retention – As of December 31, 2013, we had incurred $90 million of employee severance and retention costs associated with the office consolidation. This included amounts related to cash severance costs and accelerated vesting of share-based grants. 
Lease obligations and other – As of December 31, 2013, we had incurred $28 million of restructuring costs related to certain office space that is subject to non-cancellable operating lease agreements and that we ceased using as a part of the office consolidation. Our estimate of lease obligations was based upon certain key estimates that could change over the term of the leases. These estimates include the estimated sublease income that we may receive over the term of the leases, as well as the amount of variable operating costs that we will be required to pay under the leases.
Divestiture of Offshore Assets
In the fourth quarter of 2009, we announced plans to divest our offshore assets. As of December 31, 2012, we had divested all of our U.S. Offshore and International assets and incurred $196 million of restructuring costs associated with the divestitures.
 
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Income Taxes
The following table presents our total income tax expense (benefit) and a reconciliation of our effective income tax rate to the United States statutory income tax rate.

 	  	Year Ended December 31,	 	
 	  	2013	 	 	2012	 	 	2011	 	
Total income tax expense (benefit) (in millions)	  	$	169	  	 	$	(132	) 	 	$	2,156	  	
	  	 	 	 	 	 	 	 	 	 	 	 	
United States statutory income tax rate	  	 	35	% 	 	 	(35	%) 	 	 	35	% 	
State income taxes	  	 	23	% 	 	 	6	% 	 	 	1	% 	
Taxation on Canadian operations	  	 	9	% 	 	 	(6	%) 	 	 	(2	%) 	
Repatriations	  	 	65	% 	 	 	0	% 	 	 	17	% 	
Other	  	 	(19	%) 	 	 	(7	%) 	 	 	(1	%) 	
	  	 	 	 	 	 	 	 	 	 	 	 	
Effective income tax rate	  	 	113	% 	 	 	(42	%) 	 	 	50	% 	
	  	 	 	 	 	 	 	 	 	 	 	 	
Pursuant to the completed and planned divestitures of our International assets located outside North America, a portion of our foreign earnings had been deemed to no longer be indefinitely reinvested. As of December 31, 2012, we had recognized a $936 million deferred income tax liability related to assumed repatriations of earnings from our foreign subsidiaries, including $725 million of deferred income tax expense recognized in 2011.
In the second and fourth quarters of 2013, we repatriated to the U. S. a total of $4.3 billion of our cash held outside of the U. S. In the fourth quarter of 2013, we announced plans to divest of our Canadian non-core properties. These events resulted in incremental income tax expense of $97 million. The incremental expense included $180 million of current income tax expense offset by $83 million of deferred income tax benefit. The $83 million deferred tax benefit was comprised of $180 million of deferred tax benefits that offset the incremental current income tax expense and an additional $97 million of deferred income tax expense accrued in the fourth quarter for assumed repatriations.
In 2013, our state income tax rate is higher than 2012 and 2011 primarily due to the relatively small amount of pre-tax income, resulting from pre-tax income for the U.S. partially offset by a pre-tax loss for Canada. Also, in the table above, the “other” effect is primarily comprised of permanent tax differences for which the dollar amounts do not increase or decrease as our pre-tax earnings do. Generally, such items typically have an insignificant impact on our effective income tax rate. However, these items have a more noticeable impact to our rate for the years ended December 31, 2013 and 2012, respectively, because of the relatively small pre-tax income/loss for those periods. For 2013 “other” was comprised primarily of tax audit adjustments and a favorable tax impact due to acquisition financing.
Earnings (Loss) From Discontinued Operations

 	  	Year Ended December 31,	 	
 	  	2013	 	  	2012	 	 	2011	 	
 	  	(In millions)	 	
Operating earnings	  	$	—  	  	  	$	—  	  	 	$	38	  	
Gain (loss) on sale of oil and gas properties	  	 	—  	  	  	 	(16	) 	 	 	2,552	  	
	  	 	 	 	  	 	 	 	 	 	 	 	
Earnings (loss) before income taxes	  	 	—  	  	  	 	(16	) 	 	 	2,590	  	
Income tax expense	  	 	—  	  	  	 	5	  	 	 	20	  	
	  	 	 	 	  	 	 	 	 	 	 	 	
Earnings (loss) from discontinued operations	  	$	—  	  	  	$	(21	) 	 	$	2,570	  	

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The earnings (loss) in each period were primarily driven by gains (losses) on the sales of our oil and gas assets in each period. In 2012 we incurred a loss of $16 million ($21 million net of taxes) for the sale of our assets in Angola. In 2011 we generated a gain of $2.5 billion ($2.5 billion net of taxes) for the sale of our assets in Brazil.
Capital Resources, Uses and Liquidity
Sources and Uses of Cash
The following table presents the major source and use categories of our cash and cash equivalents.

 	  	Year Ended December 31,	 	
 	  	2013	 	 	2012	 	 	2011	 	
 	  	(In millions)	 	
Operating cash flow – continuing operations	  	$	5,436	  	 	$	4,930	  	 	$	6,246	  	
Capital expenditures	  	 	(6,758	) 	 	 	(8,225	) 	 	 	(7,534	) 	
Debt activity, net	  	 	361	  	 	 	1,921	  	 	 	4,187	  	
Shareholder distributions	  	 	(348	) 	 	 	(324	) 	 	 	(2,610	) 	
Divestitures of property and equipment	  	 	419	  	 	 	1,539	  	 	 	3,380	  	
Other	  	 	(24	) 	 	 	81	  	 	 	(46	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	
Net change in cash and short-term investments	  	$	(914	) 	 	$	(78	) 	 	$	3,623	  	
	  	 	 	 	 	 	 	 	 	 	 	 	
Cash and short-term investments at end of period	  	$	6,066	  	 	$	6,980	  	 	$	7,058	  	
	  	 	 	 	 	 	 	 	 	 	 	 	
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 2013. Our operating cash flow increased 10 percent during 2013 primarily due to higher commodity prices and production growth, partially offset by higher expenses. Our operating cash flow decreased 21 percent during 2012 primarily due to lower commodity prices and higher expenses, partially offset by additional cash flow from our production growth and higher cash settlements from our commodity derivatives.
During 2013 our operating cash flow funded approximately 80 percent of our cash payments for capital expenditures. Leveraging our liquidity, we used cash balances, short-term debt and divestiture proceeds to fund the remainder of our cash-based capital expenditures.
Capital Expenditures

 	  	Year Ended December 31,	 	
 	  	2013	 	  	2012	 	  	2011	 	
 	  	(In millions)	 	
Development	  	$	4,754	  	  	$	5,183	  	  	$	5,269	  	
Exploration	  	 	602	  	  	 	541	  	  	 	378	  	
Acquisition	  	 	256	  	  	 	1,329	  	  	 	901	  	
	  	 	 	 	  	 	 	 	  	 	 	 	
Subtotal	  	 	5,612	  	  	 	7,053	  	  	 	6,548	  	
Capitalized G&A and interest	  	 	354	  	  	 	343	  	  	 	332	  	
	  	 	 	 	  	 	 	 	  	 	 	 	
Total oil and gas	  	 	5,966	  	  	 	7,396	  	  	 	6,880	  	
Midstream	  	 	699	  	  	 	504	  	  	 	333	  	
Corporate and other	  	 	93	  	  	 	325	  	  	 	321	  	
	  	 	 	 	  	 	 	 	  	 	 	 	
Total capital expenditures	  	$	6,758	  	  	$	8,225	  	  	$	7,534	  	

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Our capital expenditures consist of amounts related to our oil and gas exploration and development operations, our midstream operations and other corporate activities. The vast majority of our capital expenditures are for the acquisition, drilling and development of oil and gas properties, which totaled $6.0 billion, $7.4 billion and $6.9 billion in 2013, 2012 and 2011, respectively. The 20 percent decline in exploration, development and acquisition capital spending in 2013 was primarily due to a decline in new venture acreage acquisitions and utilization of the drilling carries in 2013 from our Sinopec and Sumitomo joint venture arrangements. The higher exploration and development capital spending in 2012 and 2011 was primarily due to new venture acreage acquisitions and increased drilling and development. With rising oil prices and proceeds from our offshore divestitures, we increased our onshore North American acreage positions and associated exploration and development activities to drive near-term growth of our oil production.
Capital expenditures for our midstream operations are primarily for the construction and expansion of natural gas processing plants, natural gas gathering systems and oil pipelines. Our midstream capital expenditures are largely impacted by oil and gas drilling activities. The higher 2013 midstream expenditures primarily relate to expansions of our plants serving the Barnett Shale and Cana-Woodford Shale and our Access Pipeline transporting heavy oil in Canada.
Capital expenditures related to other activities decreased in 2013. This decrease is largely driven by the construction of our new headquarters in Oklahoma City, which was completed in 2012.
Debt Activity, Net
During 2013, we increased our debt borrowings by $361 million as a result of issuing $2.25 billion of debt related to the planned Eagle Ford Shale acquisition, which is expected to close in the first quarter of 2014, and repaying approximately $1.9 billion of outstanding short-term debt.
In December 2013, to provide funding for our planned Eagle Ford Shale acquisition, we issued $2.25 billion aggregate principal amount of fixed and floating rate senior notes resulting in cash proceeds of approximately $2.2 billion, net of discounts and issuance costs.
During 2012, we increased our debt borrowings by $1.9 billion as a result of issuing $2.5 billion of long-term debt and repaying approximately $0.6 billion of outstanding short-term debt. The additional borrowings were primarily used to fund capital expenditures in excess of our operating cash flow.
During 2011, we increased our commercial paper borrowings by $3.7 billion and received $0.5 billion from new debt issuances, net of debt maturities. Proceeds were primarily used to fund capital expenditures and common stock repurchases in excess of operating cash flow.
Shareholder Distributions
The following table summarizes our share repurchases and our common stock dividends (amounts and shares in millions).

 	  	2013	 	  	2012	 	  	2011	 	
 	  	Amount	 	  	Shares	 	  	Per Share	 	  	Amount	 	  	Shares	 	  	Per Share	 	  	Amount	 	  	Shares	 	  	Per Share	 	
Repurchases	  	 	N/A	  	  	 	N/A	  	  	 	N/A	  	  	 	N/A	  	  	 	N/A	  	  	 	N/A	  	  	$	2,332	  	  	 	31.3	  	  	$	74.54	  	
Dividends	  	$	348	  	  	 	N/A	  	  	$	0.86	  	  	$	324	  	  	 	N/A	  	  	$	0.80	  	  	$	278	  	  	 	N/A	  	  	$	0.67	  	
In connection with our offshore divestitures, we conducted a $3.5 billion share repurchase program that we completed in the fourth quarter of 2011. Under the program, we repurchased 49.2 million shares, representing 11 percent of our outstanding shares, at an average price of $71.18 per share.
 
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Divestitures of Property and Equipment
In 2013, we sold our Thunder Creek operations in Wyoming for approximately $148 million and our Bear Paw Basin assets in Havre, Montana for approximately $73 million. We also sold other minor oil and gas assets.
During 2012, we closed joint venture transactions with Sinopec and Sumitomo. Sinopec paid approximately $900 million in cash and received a 33.3 percent interest in five of our new ventures exploration plays in the U.S. Sinopec is also funding approximately $1.6 billion of our share of future exploration, development and drilling costs associated with these plays. Sumitomo paid approximately $400 million and received a 30 percent interest in the Cline and Midland-Wolfcamp Shale plays in Texas. Additionally, Sumitomo is funding approximately $1.0 billion of our share of future exploration, development and drilling costs associated with these plays.
Also in 2012, we sold our West Johnson County Plant and gathering system in north Texas for approximately $90 million and divested our Angola operations for approximately $71 million.
In 2011, our divestitures primarily related to the divestitures of our offshore assets.
Liquidity
Historically, our primary sources of capital and liquidity have been our operating cash flow, asset divestiture proceeds and cash on hand. Additionally, we maintain revolving lines of credit and a commercial paper program, which can be accessed as needed to supplement operating cash flow and cash balances. Other available sources of capital and liquidity include debt and equity securities that can be issued pursuant to our shelf registration statement filed with the SEC. We estimate the combination of these sources of capital will be adequate to fund future capital expenditures, debt repayments and other contractual commitments as discussed in this section, including our planned $6 billion acquisition of Eagle Ford Shale assets from GeoSouthern.
Operating Cash Flow and Cash Balances
Our operating cash flow is sensitive to many variables, the most volatile of which are the prices of the oil, gas and NGLs we produce. Due to higher commodity prices, our operating cash flow from continuing operations increased 10 percent to $5.4 billion in 2013. We expect operating cash flow to continue to be our primary source of liquidity.
Commodity Prices – Prices are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors, which are difficult to predict, create volatility in prices and are beyond our control. We expect this volatility to continue throughout 2014.
To mitigate some of the risk inherent in prices, we have utilized various derivative financial instruments to set minimum prices on our future production. The key terms to our oil, gas and NGL derivative financial instruments as of December 31, 2013 are presented in Note 2 to the financial statements under “Item 8. Financial Statements and Supplementary Data” of this report.
Commodity prices can also affect our operating cash flow through an indirect effect on operating expenses. Significant commodity price increases can lead to an increase in drilling and development activities. As a result, the demand and cost for people, services, equipment and materials may also increase, causing a negative impact on our cash flow. However, the inverse is also generally true during periods of depressed commodity prices or reduced activity.
Interest Rates – Our operating cash flow can also be impacted by interest rate fluctuations. As of December 31, 2013, we had total debt of $12.0 billion with an overall weighted average borrowing rate of 4.1 percent.
 
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Credit Losses – Our operating cash flow is also exposed to credit risk in a variety of ways. We are exposed to the credit risk of the customers who purchase our oil, gas and NGL production. We are also exposed to credit risk related to the collection of receivables from our joint-interest partners for their proportionate share of expenditures made on projects we operate. Additionally, we are exposed to the credit risk of counterparties to our derivative financial contracts. We utilize a variety of mechanisms to limit our exposure to the credit risks of our customers, partners and counterparties. Such mechanisms include, under certain conditions, requiring letters of credit, prepayments or collateral postings.
As recent years indicate, we have a history of investing more than 100 percent of our operating cash flow into capital development activities to grow our company and maximize value for our shareholders. Therefore, negative movements in any of the variables discussed above would not only impact our operating cash flow, but also would likely impact the amount of capital investment we could or would make.
At the end of 2013, we held approximately $6.1 billion of cash. Included in this total was $1.8 billion of cash held by our foreign subsidiaries. If we were to repatriate a portion or all of the cash held by our foreign subsidiaries, we would recognize and pay current income taxes in accordance with current U. S. tax law. The payment of such additional income tax would materially decrease the amount of cash and short-term investments ultimately available to fund our business.
Credit Availability
We have a $3.0 billion syndicated, unsecured revolving line of credit (the “Senior Credit Facility”) that matures on October 24, 2018. Amounts borrowed under the Senior Credit Facility may, at our election, bear interest at various fixed rate options for periods of up to twelve months. Such rates are generally less than the prime rate. However, we may elect to borrow at the prime rate. As of December 31, 2013, we had $2.9 billion of available capacity under our syndicated, unsecured Senior Credit Facility, net of letters of credit outstanding.
The Senior Credit Facility contains only one material financial covenant. This covenant requires us to maintain a ratio of total funded debt to total capitalization, as defined in the credit agreement, of no more than 65 percent. The credit agreement defines total funded debt as funds received through the issuance of debt securities such as debentures, bonds, notes payable, credit facility borrowings and short-term commercial paper borrowings. In addition, total funded debt includes all obligations with respect to payments received in consideration for oil, gas and NGL production yet to be acquired or produced at the time of payment. Funded debt excludes our outstanding letters of credit and trade payables. The credit agreement defines total capitalization as the sum of funded debt and stockholders’ equity adjusted for noncash financial write-downs, such as full cost ceiling impairments. As of December 31, 2013, we were in compliance with this covenant. Our debt-to-capitalization ratio at December 31, 2013, as calculated pursuant to the terms of the agreement, was 25.7 percent.
Our access to funds from the Senior Credit Facility is not restricted under any “material adverse effect” clauses. It is not uncommon for credit agreements to include such clauses. These clauses can remove the obligation of the banks to fund the credit line if any condition or event would reasonably be expected to have a material and adverse effect on the borrower’s financial condition, operations, properties or business considered as a whole, the borrower’s ability to make timely debt payments, or the enforceability of material terms of the credit agreement. While our credit facility includes covenants that require us to report a condition or event having a material adverse effect, the obligation of the banks to fund the credit facility is not conditioned on the absence of a material adverse effect.
We also have access to $3.0 billion of short-term credit under our commercial paper program. Commercial paper debt generally has a maturity of between 1 and 90 days, although it can have a maturity of up to 365 days, and bears interest at rates agreed to at the time of the borrowing. The interest rate is generally based on a standard index such as the Federal Funds Rate, LIBOR, or the money market rate as found in the commercial paper market. As of December 31, 2013, we had $1.3 billion of borrowings under our commercial paper program.
 
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Debt Ratings
We receive debt ratings from the major ratings agencies in the U.S. In determining our debt ratings, the agencies consider a number of qualitative and quantitative items including, but not limited to, commodity pricing levels, our liquidity, asset quality, reserve mix, debt levels, cost structure, planned asset sales, near-term and long-term production growth opportunities and capital allocation challenges. Our current debt ratings are BBB with a stable outlook by Fitch, BBB+ with a negative outlook by Standard & Poor’s, and Baa1 with a review for downgrade by Moody’s.
There are no “rating triggers” in any of our debt contractual obligations that would accelerate scheduled maturities should our debt rating fall below a specified level. Our cost of borrowing under our Senior Credit Facility is predicated on our corporate debt rating. Therefore, even though a ratings downgrade would not accelerate scheduled maturities, it would adversely impact the interest rate on any borrowings under our Senior Credit Facility. Under the terms of the Senior Credit Facility, a one-notch downgrade would increase the fully-drawn borrowing costs from LIBOR plus 112.5 basis points to a new rate of LIBOR plus 125 basis points. A ratings downgrade could also adversely impact our ability to economically access debt markets in the future.
Capital Expenditures
Excluding our planned $6 billion Eagle Ford Shale acquisition, our 2014 capital expenditures are expected to range from $6.4 billion to $6.9 billion, including $5.4 billion to $5.8 billion for our oil and gas operations, which include capitalized G&A and interest. To a certain degree, the ultimate timing of these capital expenditures is within our control. Therefore, if commodity prices fluctuate from our current estimates, we could choose to defer a portion of these planned 2014 capital expenditures until later periods or accelerate capital expenditures planned for periods beyond 2014 to achieve the desired balance between sources and uses of liquidity. Based upon current price expectations for 2014, our existing commodity hedging contracts, available cash balances and credit availability, we anticipate having adequate capital resources to fund our 2014 capital expenditures.
Additionally, our financial and operational flexibility has been further enhanced by the joint venture transactions that we entered into in 2012 with Sinopec and Sumitomo. Pursuant to the joint venture agreements, Sinopec and Sumitomo are subject to drilling carries with remaining commitments that totaled $1.4 billion at the end of 2013. These drilling carries will fund 70 percent of our capital requirements related to joint venture properties, which results in our partners paying approximately 80 percent of the overall development costs during the carry period. This is allowing us to accelerate the de-risking and commercialization of the joint venture properties without diverting capital from our core development projects. We expect the remaining carries will be realized by the end of 2015.
Acquisitions and Divestitures
GeoSouthern Acquisition – On November 20, 2013, we entered into an agreement with GeoSouthern Intermediate Holdings, LLC, to acquire certain oil and gas properties, leasehold mineral interests and related assets located in the Eagle Ford Shale in south Texas for $6 billion in cash. The transaction is expected to close in the first quarter of 2014.
To provide funding for the Eagle Ford Shale acquisition, we issued $2.25 billion of senior notes in December 2013. The floating rate senior notes due in 2015 bear interest at a rate equal to three-month LIBOR plus 0.45%, which rate will be reset quarterly. The floating rate senior notes due in 2016 bear interest at a rate equal to three-month LIBOR plus 0.54%, which rate will be reset quarterly. We also entered into a term loan agreement in December 2013 with a group of major financial institutions pursuant to which we may draw up to $2.0 billion to finance, in part, the Eagle Ford Shale acquisition and to pay transaction costs. Half of any loans under the term loan agreement will have a maturity of three years and the other half will have a maturity of five years (the 5-Year Loans). The 5-Year Loans will provide for the partial amortization of principal during the last
 
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two years that they are outstanding. Loans borrowed under the term loan agreement may, at our election, bear interest at various fixed rate options for periods up to six months. Such rates are generally less than the prime rate. However, we may elect to borrow at the prime rate.
In the event that the Eagle Ford Shale acquisition is not completed on or prior to June 30, 2014, we will be required to redeem each series of new senior notes at 101% of the $2.25 billion aggregate principal amount, plus accrued and unpaid interest.
Crosstex Merger – On October 21, 2013, Devon, Crosstex Energy, Inc. and Crosstex Energy, L.P. (collectively “Crosstex”) announced plans to combine substantially all of Devon’s U.S. midstream assets with Crosstex’s assets to form a new midstream business. The new business will consist of EnLink Midstream Partners, L.P. (the “Partnership”) and EnLink Midstream, LLC (“EnLink”), a master limited partnership and a general partner entity, which will both be publicly traded entities.
In exchange for a controlling interest in both EnLink and the Partnership, Devon will contribute its equity interest in a newly formed Devon subsidiary (“EnLink Holdings”) and $100 million in cash. EnLink Holdings will own Devon’s midstream assets in the Barnett Shale in north Texas and the Cana and Arkoma Woodford Shales in Oklahoma, as well as Devon’s economic interest in Gulf Coast Fractionators in Mt. Belvieu, Texas. The Partnership and EnLink will each own 50% of EnLink Holdings. The completion of these transactions is subject to Crosstex Energy, Inc. shareholder approval. Devon expects Crosstex Energy, Inc. shareholders will approve the transaction, allowing Devon and Crosstex to complete the transaction near the end of the first quarter of 2014.
Upon closing of the transactions, the pro forma ownership of EnLink will be approximately:
 
 	•	 	70% – Devon Energy Corporation	
 
 	•	 	30% – Current Crosstex Energy, Inc. public stockholders	
Upon closing of the transactions, the pro forma ownership of the Partnership will be approximately:
 
 	•	 	53% – Devon Energy Corporation	
 
 	•	 	40% – Current Crosstex Energy, L.P. public unitholders	
 
 	•	 	7% – the General Partner	
Asset Divestitures – In conjunction with the announcement of the Eagle Ford Shale acquisition, we also announced plans to monetize certain non-core assets located throughout Canada and the U. S. The divestitures will likely occur in a number of separate transactions, but we expect to complete the majority of the divestitures by the end of 2014.
 
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Contractual Obligations
A summary of our contractual obligations as of December 31, 2013, is provided in the following table.

 	  	Payments Due by Period	 	
 	  	Total	 	  	Less Than
1 Year	 	  	  1-3 Years  	 	  	  3-5 Years  	 	  	More Than 5
Years	 	
 	  	(In millions)	 	
Debt (1)	  	$	12,042	  	  	$	4,067	  	  	$	500	  	  	$	875	  	  	$	6,600	  	
Interest expense (2)	  	 	7,328	  	  	 	472	  	  	 	914	  	  	 	845	  	  	 	5,097	  	
Purchase obligations (3)	  	 	6,425	  	  	 	852	  	  	 	1,819	  	  	 	1,756	  	  	 	1,998	  	
Operational agreements (4)	  	 	3,449	  	  	 	519	  	  	 	876	  	  	 	723	  	  	 	1,331	  	
Asset retirement obligations (5)	  	 	2,228	  	  	 	88	  	  	 	146	  	  	 	141	  	  	 	1,853	  	
Drilling and facility obligations (6)	  	 	366	  	  	 	341	  	  	 	25	  	  	 	—  	  	  	 	—  	  	
Lease obligations (7)	  	 	285	  	  	 	41	  	  	 	72	  	  	 	61	  	  	 	111	  	
Other (8)	  	 	446	  	  	 	272	  	  	 	78	  	  	 	44	  	  	 	52	  	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total	  	$	32,569	  	  	$	6,652	  	  	$	4,430	  	  	$	4,445	  	  	$	17,042	  	

(1)	Debt amounts represent scheduled maturities of our debt obligations at December 31, 2013, excluding $20 million of net discounts included in the carrying value of debt. Included in current debt is the $2.25 billion senior notes related to the GeoSouthern acquisition that will be reclassified to long-term once the transaction closes in the first quarter of 2014.	
 
(2)	Interest expense represents the scheduled cash payments on long-term, fixed-rate debt and an estimate of our floating-rate debt.	
 
(3)	Purchase obligation amounts represent contractual commitments primarily to purchase condensate at market prices for use at our heavy oil projects in Canada. We have entered into these agreements because condensate is an integral part of the heavy oil transportation process. Any disruption in our ability to obtain condensate could negatively affect our ability to transport heavy oil at these locations. Our total obligation related to condensate purchases expires in 2021. The value of the obligation in the table above is based on the contractual volumes and our internal estimate of future condensate market prices.	
 
(4)	Operational agreements represent commitments to transport or process certain volumes of oil, gas and NGLs for a fixed fee. We have entered into these agreements to aid the movement of our production to downstream markets.	
 
(5)	Asset retirement obligations represent estimated discounted costs for future dismantlement, abandonment and rehabilitation costs. These obligations are recorded as liabilities on our December 31, 2013 balance sheet.	
 
(6)	Drilling and facility obligations represent contractual agreements with third-party service providers to procure drilling rigs and other related services for developmental and exploratory drilling and facilities construction.	
 
(7)	Lease obligations consist primarily of non-cancelable leases for office space and equipment used in our daily operations.	
 
(8)	These amounts include $243 million related to uncertain tax positions.	
Contingencies and Legal Matters
For a detailed discussion of contingencies and legal matters, see Note 18 to the financial statements included in “Item 8. Financial Statements and Supplementary Data” of this report.
Critical Accounting Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the
 
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United States of America requires us to make estimates, judgments and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual amounts could differ from these estimates, and changes in these estimates are recorded when known. We consider the following to be our most critical accounting estimates that involve judgment and have reviewed these critical accounting estimates with the Audit Committee of our Board of Directors.
Full Cost Method of Accounting and Proved Reserves
Our estimates of proved reserves are a major component of the depletion and full cost ceiling calculations. Additionally, our proved reserves represent the element of these calculations that require the most subjective judgments. Estimates of reserves are forecasts based on engineering data, projected future rates of production and the timing of future expenditures. The process of estimating oil, gas and NGL reserves requires substantial judgment, resulting in imprecise determinations, particularly for new discoveries. Different reserve engineers may make different estimates of reserve quantities based on the same data. Our engineers prepare our reserve estimates. We then subject certain of our reserve estimates to audits performed by outside petroleum consultants. In 2013, 91 percent of our reserves were subjected to such audits.
The passage of time provides more qualitative information regarding estimates of reserves, when revisions are made to prior estimates to reflect updated information. In the past five years, annual performance revisions to our reserve estimates, which have been both increases and decreases in individual years, have averaged less than two percent of the previous year’s estimate. However, there can be no assurance that more significant revisions will not be necessary in the future. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions.
While the quantities of proved reserves require substantial judgment, the associated prices of oil, gas and NGL reserves, and the applicable discount rate, that are used to calculate the discounted present value of the reserves do not require judgment. Applicable rules require future net revenues to be calculated using prices that represent the average of the first-day-of-the-month price for the 12-month period prior to the end of each quarterly period. Such rules also dictate that a 10 percent discount factor be used. Therefore, the discounted future net revenues associated with the estimated proved reserves are not based on our assessment of future prices or costs or our enterprise risk.
Because the ceiling calculation dictates the use of prices that are not representative of future prices and requires a 10 percent discount factor, the resulting value is not indicative of the true fair value of the reserves. Oil and gas prices have historically been cyclical and, for any particular 12-month period, can be either higher or lower than our long-term price forecast, which is a more appropriate input for estimating fair value. Therefore, oil and gas property write-downs that result from applying the full cost ceiling limitation, and that are caused by fluctuations in price as opposed to reductions to the underlying quantities of reserves, should not be viewed as absolute indicators of a reduction of the ultimate value of the related reserves.
Because of the volatile nature of oil and gas prices, it is not possible to predict the timing or magnitude of full cost write-downs. In addition, due to the inter-relationship of the various judgments made to estimate proved reserves, it is impractical to provide quantitative analyses of the effects of potential changes in these estimates. However, decreases in estimates of proved reserves would generally increase our depletion rate and, thus, our depletion expense. Decreases in our proved reserves may also increase the likelihood of recognizing a full cost ceiling write-down.
Derivative Financial Instruments
We periodically enter into derivative financial instruments with respect to a portion of our oil, gas and NGL production to hedge future prices received. Our commodity derivative financial instruments include financial price swaps, basis swaps, costless price collars and call options.
 
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The estimates of the fair values of our derivative instruments require substantial judgment. We estimate the fair values of our commodity derivative financial instruments primarily by using internal discounted cash flow calculations. The most significant variable to our cash flow calculations is our estimate of future commodity prices. We base our estimate of future prices upon published forward commodity price curves such as the Inside FERC Henry Hub forward curve for gas instruments and the NYMEX West Texas Intermediate forward curve for oil instruments. Another key input to our cash flow calculations is our estimate of volatility for these forward curves, which we base primarily upon implied volatility. The resulting estimated future cash inflows or outflows over the lives of the contracts are discounted primarily using United States Treasury bill rates. These pricing and discounting variables are sensitive to the period of the contract and market volatility as well as changes in forward prices and regional price differentials.
We periodically enter into interest rate swaps to manage our exposure to interest rate volatility. Under the terms of our interest rate swaps, we generally receive a fixed rate and pay a variable rate on a total notional amount. As of December 31, 2013 we had no outstanding interest rate swaps.
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 enter into foreign exchange forward contracts to manage our exposure to fluctuations in exchange rates. Under the terms of our foreign exchange forward contracts, we generally receive U.S. dollars and pay Canadian dollars based on a total notional amount.
We estimate the fair values of our foreign exchange forward contracts primarily by using internal discounted cash flow calculations based upon forward exchange rates. The most significant variable to our cash flow calculations is our observation of forward foreign exchange rates. The resulting future cash inflows or outflows at maturity of the contracts are discounted using Treasury rates. These discounting variables are sensitive to the period of the contract and market volatility.
We periodically validate our valuation techniques by comparing our internally generated fair value estimates with those obtained from contract counterparties.
Counterparty credit risk has not had a significant effect on our cash flow calculations and derivative valuations. This is primarily the result of two factors. First, we have mitigated our exposure to any single counterparty by contracting with numerous counterparties. Our commodity derivative contracts are held with fourteen separate counterparties, and our foreign exchange forward contracts are held with four separate counterparties. Second, our derivative contracts generally require cash collateral to be posted if either our or the counterparty’s credit rating falls below certain credit rating levels. The mark-to-market exposure threshold for collateral posting decreases as the debt rating falls further below such credit levels.
Because we have chosen not to qualify our derivatives for hedge accounting treatment, changes in the fair values of derivatives can have a significant impact on our reported results of operations. Generally, changes in derivative fair values will not impact our liquidity or capital resources.
Settlements of derivative instruments, regardless of whether they qualify for hedge accounting, do have an impact on our liquidity and results of operations. Generally, if actual market prices are higher than the price of the derivative instruments, our net earnings and cash flow from operations will be lower relative to the results that would have occurred absent these instruments. The opposite is also true. Additional information regarding
 
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the effects that changes in market prices can have on our derivative financial instruments, net earnings and cash flow from operations is included in “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” of this report.
Goodwill
The annual impairment test, which we conduct as of October 31 each year, includes an assessment of qualitative factors and requires us to estimate the fair values of our own assets and liabilities. Because quoted market prices are not available for our reporting units, we must estimate the fair values to conduct the goodwill impairment test. The most significant judgments involved in estimating the fair values of our reporting units relate to the valuation of our property and equipment. We develop estimated fair values of our property and equipment by performing various quantitative analyses using information related to comparable companies, comparable transactions and premiums paid.
In our comparable companies analysis, we review the stock market trading multiples for selected publicly traded independent exploration and production companies with financial and operating characteristics that are comparable to our respective reporting units. Such characteristics are market capitalization, location of proved reserves and the characterization of the operations. In our comparable transactions analysis, we review certain acquisition multiples for selected independent exploration and production company transactions and oil and gas asset packages announced recently. In our premiums paid analysis, we use a sample of selected transactions of all publicly traded companies announced recently. We then review the premiums paid to the price of the target one day and one month prior to the announcement of the transaction. We use this information to determine the median premiums paid.
We then use the comparable company multiples, comparable transaction multiples, transaction premiums and other data to develop valuation estimates of our property and equipment. We also use market and other data to develop valuation estimates of the other assets and liabilities included in our reporting units. At October 31, 2013, the date of our last impairment test, the fair values of our U.S. and Canadian reporting units exceeded their related carrying values. The fair value of our U.S. reporting unit substantially exceeded its carrying value. However, the fair value of our Canadian reporting is not substantially in excess of its carrying value. As of October 31, 2013, the fair value of our Canadian reporting unit derived by the average of our three valuation methods (comparable company multiples, comparable transaction multiples, and transaction premiums) exceeded its carrying value by approximately 11 percent. As of December 31, 2013, we had $2.8 billion of goodwill allocated to the Canadian reporting unit.
Significant decreases to our stock price, decreases in commodity prices, negative deviations from projected Canadian reporting unit earnings or unfavorable changes in reserves could result in a goodwill impairment charge. A goodwill impairment charge would have no effect on liquidity or capital resources. However, it would adversely affect our results of operations in that period.
Due to the inter-relationship of the various estimates involved in assessing goodwill for impairment, it is impractical to provide quantitative analyses of the effects of potential changes in these estimates, other than to note the historical average changes in our reserve estimates.
Income Taxes
The amount of income taxes recorded requires interpretations of complex rules and regulations of federal, state, provincial and foreign tax jurisdictions. We recognize current tax expense based on estimated taxable income for the current period and the applicable statutory tax rates. We routinely assess potential uncertain tax positions and, if required, estimate and establish accruals for such amounts. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and other tax carryforwards. We routinely assess our deferred tax assets and reduce such assets by a valuation allowance if we deem it is more likely than not that some portion or all of the deferred tax assets will not be realized.
 
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The accruals for deferred tax assets and liabilities are often based on assumptions that are subject to a significant amount of judgment by management. These assumptions and judgments are reviewed and adjusted as facts and circumstances change. Material changes to our income tax accruals may occur in the future based on the progress of ongoing audits, changes in legislation or resolution of pending matters.
We also assess factors relative to whether our foreign earnings are considered indefinitely reinvested. These factors include forecasted and actual results for both our U.S. and Canadian operations, borrowing conditions in the U.S., and existing United States income tax laws, particularly the laws pertaining to the deductibility of intangible drilling costs and repatriations of foreign earnings. Changes in any of these factors could require recognition of additional deferred, or even current, U.S. income tax expense. We accrue deferred U.S. income tax expense on our foreign earnings when the factors indicate that these earnings are no longer considered indefinitely reinvested.
For our foreign earnings deemed indefinitely reinvested, we do not calculate a hypothetical deferred tax liability on these earnings. Calculating a hypothetical tax on these accumulated earnings is much different from the calculation of the deferred tax liability on our earnings deemed not indefinitely reinvested. A hypothetical tax calculation on the indefinitely reinvested earnings would require the following additional activities:
 
 	•	 	Separate analysis of a diverse chain of foreign entities;	
 
 	•	 	Relying on tax rates on a future remittance that could vary significantly depending on alternative approaches available to repatriate the earnings;	
 
 	•	 	Determining the nature of a yet-to-be-determined future remittance, such as whether the distribution would be a non-taxable return of capital or a distribution of taxable earnings, and calculation of associated withholding taxes, which would vary significantly depending on the circumstances at the deemed time of remittance; and	
 
 	•	 	Further analysis of a variety of other inputs such as the earnings, profits, United States/foreign country tax treaty provisions and the related foreign taxes paid by our foreign subsidiaries, whose earnings are deemed permanently reinvested, over a lengthy history of operations.	
Because of the administrative burden required to perform these additional activities, it is impracticable to calculate a hypothetical tax on the foreign earnings associated with this separate and more complicated chain of companies.
Non-GAAP Measures
We make reference to “adjusted earnings” and “adjusted earnings per share” in “Overview of 2013 Results” in this Item 7. that are not required by or presented in accordance with GAAP. These non-GAAP measures should not be considered as alternatives to GAAP measures. Adjusted earnings, as well as the per share amount, represent net earnings excluding certain non-cash or non-recurring items that are typically excluded by securities analysts in their published estimates of our financial results. Our non-GAAP measures are typically used as a quarterly performance measure. Items may appear to be recurring while comparing on an annual basis. In the below table, restructuring costs were incurred in each of the three year periods, however, these costs relate to different restructuring programs. Amounts excluded for 2013 and a portion of 2012 relate to our office consolidation and amounts excluded for the remaining portion of 2012 and 2011 relate to our offshore divestiture program. For more information on our restructuring programs see Note 6 to the financial statements included in “Item 8. Financial Statements and Supplementary Data” of this report. We believe these non-GAAP measures facilitate comparisons of our performance to earnings estimates published by securities analysts. We also believe these non-GAAP measures can facilitate comparisons of our performance between periods and to the performance of our peers.
 
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Below are reconciliations of our adjusted earnings and earnings per share to their comparable GAAP measures. The reconciliations exclude amounts related to our discontinued operations.

 	  	Year Ended December 31,	 	
 	  	    2013    	 	 	    2012    	 	 	    2011    	 	
 	  	(In millions, except per share amounts)	 	
Net earnings (loss) (GAAP)	  	$	(20	) 	 	$	(185	) 	 	$	2,134	  	
Adjustments (net of taxes):	  				 				 				
Asset impairments	  	 	1,353	  	 	 	1,308	  	 	 	—  	  	
Derivatives and other financial instruments	  	 	131	  	 	 	(425	) 	 	 	(546	) 	
Cash settlements on derivatives and financial instruments	  	 	139	  	 	 	558	  	 	 	308	  	
U.S. income taxes on foreign earnings	  	 	97	  	 	 	—  	  	 	 	744	  	
Restructuring costs	  	 	34	  	 	 	49	  	 	 	(2	) 	
Insurance proceeds	  	 	—  	  	 	 	—  	  	 	 	(60	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	
Adjusted earnings (Non-GAAP)	  	$	1,734	  	 	$	1,305	  	 	$	2,578	  	
	  	 	 	 	 	 	 	 	 	 	 	 	
Earnings (loss) per share (GAAP)	  	$	(0.06	) 	 	$	(0.47	) 	 	$	5.10	  	
Adjustments (net of taxes):	  				 				 				
Asset impairments	  	 	3.35	  	 	 	3.23	  	 	 	—  	  	
Derivatives and other financial instruments	  	 	0.31	  	 	 	(1.04	) 	 	 	(1.33	) 	
Cash settlements on derivatives and financial instruments	  	 	0.34	  	 	 	1.37	  	 	 	0.76	  	
U.S. income taxes on foreign earnings	  	 	0.24	  	 	 	—  	  	 	 	1.78	  	
Restructuring costs	  	 	0.08	  	 	 	0.13	  	 	 	—  	  	
Insurance proceeds	  	 	—  	  	 	 	—  	  	 	 	(0.14	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	
Adjusted earnings per share (Non-GAAP)	  	$	4.26	  	 	$	3.22	  	 	$	6.17	  	
	  	 	 	 	 	 	 	 	 	 	 	 	
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to our risk of loss arising from adverse changes in oil, gas and NGL prices, interest rates and foreign currency exchange rates. The following disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.
Commodity Price Risk
Our major market risk exposure is the pricing applicable to our oil, gas and NGL production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our U.S. and Canadian gas and NGL production. Pricing for oil, gas and NGL production has been volatile and unpredictable as discussed in “Item 1A. Risk Factors” of this report. Consequently, we periodically enter into financial hedging activities with respect to a portion of our production through various financial transactions that hedge future prices received. The key terms to all our oil, gas and NGL derivative financial instruments as of December 31, 2013 are presented in Note 2 to the financial statements under “Item 8. Financial Statements and Supplementary Data” of this report.
 
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The fair values of our commodity derivatives are largely determined by estimates of the forward curves of the relevant price indices. At December 31, 2013, a 10 percent increase and 10 percent decrease in the forward curves associated with our commodity derivative instruments would have changed our net asset positions by the following amounts:

 	  	10% Increase	 	 	10% Decrease	 	
 	  	(In millions)	 	
Gain (loss):	  				 				
Gas derivatives	  	$	(225	) 	 	$	202	  	
Oil derivatives	  	$	(594	) 	 	$	545	  	
NGL derivatives	  	$	(1	) 	 	$	—  	  	
Interest Rate Risk
At December 31, 2013, we had total debt of $12.0 billion. Of this amount, $9.9 billion bears fixed interest rates averaging 4.9 percent. The remaining $2.1 billion of debt is comprised of commercial paper borrowings that bear interest rates averaging 0.30 percent and floating rate debt that at December 31, 2013 had rates averaging 0.73 percent. Our commercial paper borrowings typically have maturities between 1 and 90 days.
Foreign Currency Risk
Our net assets, net earnings and cash flows from our Canadian subsidiaries are based on the U.S. dollar equivalent of such amounts measured in the Canadian dollar functional currency. Assets and liabilities of the Canadian subsidiaries are translated to U.S. dollars using the applicable exchange rate as of the end of a reporting period. Revenues, expenses and cash flow are translated using an average exchange rate during the reporting period. A 10 percent unfavorable change in the Canadian-to-U.S. dollar exchange rate would not materially impact our December 31, 2013 balance sheet.
Our non-Canadian foreign subsidiaries have a U.S. dollar functional currency. However, one of these foreign subsidiaries holds Canadian-dollar cash and engages in short-term intercompany loans with Canadian subsidiaries that are based in Canadian dollars. The value of the Canadian-dollar cash and intercompany loans increases or decreases from the remeasurement of the cash and loans into the U.S. dollar functional currency. Additionally, at December 31, 2013, we held foreign currency exchange forward contracts to hedge exposures to fluctuations in exchange rates on the Canadian-dollar cash and intercompany loans. The increase or decrease in the value of the forward contracts is offset by the increase or decrease to the U.S. dollar equivalent of the Canadian-dollar cash and intercompany loans. Based on the amount of the cash and intercompany loans as of December 31, 2013, a 10 percent change in the foreign currency exchange rates would not have materially impacted our balance sheet.
 
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 Item 8. Financial Statements and Supplementary Data 
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
AND CONSOLIDATED FINANCIAL STATEMENT SCHEDULES

Report of Independent Registered Public Accounting Firm	  	 	50	  	
		
Consolidated Financial Statements	  				
Consolidated Comprehensive Statements of Earnings	  	 	51	  	
Consolidated Statements of Cash Flows	  	 	52	  	
Consolidated Balance Sheets	  	 	53	  	
Consolidated Statements of Stockholders’ Equity	  	 	54	  	
Notes to Consolidated Financial Statements	  	 	55	  	
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.
 
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 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, 2013 and 2012, and the related consolidated comprehensive statements of earnings, cash flows, and stockholders’ equity for each of the years in the three-year period ended December 31, 2013. We also have audited Devon Energy Corporation’s internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control – Integrated Framework (1992) 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, 2013 and 2012, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2013, in conformity with United States 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, 2013, based on criteria established in Internal Control – Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
/s/ KPMG LLP
Oklahoma City, Oklahoma
February 28, 2014
 
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
 CONSOLIDATED COMPREHENSIVE STATEMENTS OF EARNINGS

 	  	Year Ended December 31,	 	
 	  	    2013    	 	 	    2012    	 	 	    2011    	 	
 	  	(In millions, except per share amounts)	 	
Oil, gas and NGL sales	  	$	8,522	 	 	$	7,153	 	 	$	8,315	 	
Oil, gas and NGL derivatives	  	 	(191	) 	 	 	693	 	 	 	881	 	
Marketing and midstream revenues	  	 	2,066	 	 	 	1,655	 	 	 	2,249	 	
	  	 	 	 	 	 	 	 	 	 	 	 	
Total operating revenues	  	 	10,397	 	 	 	9,501	 	 	 	11,445	 	
	  	 	 	 	 	 	 	 	 	 	 	 	
Lease operating expenses	  	 	2,268	 	 	 	2,074	 	 	 	1,851	 	
Marketing and midstream operating expenses	  	 	1,553	 	 	 	1,246	 	 	 	1,716	 	
General and administrative expenses	  	 	617	 	 	 	692	 	 	 	585	 	
Production and property taxes	  	 	461	 	 	 	414	 	 	 	424	 	
Depreciation, depletion and amortization	  	 	2,780	 	 	 	2,811	 	 	 	2,248	 	
Asset impairments	  	 	1,976	 	 	 	2,024	 	 	 	—  	  	
Other operating items	  	 	121	 	 	 	92	 	 	 	(11	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	
Total operating expenses	  	 	9,776	 	 	 	9,353	 	 	 	6,813	 	
	  	 	 	 	 	 	 	 	 	 	 	 	
Operating income	  	 	621	 	 	 	148	 	 	 	4,632	 	
Net financing costs	  	 	417	 	 	 	370	 	 	 	331	 	
Restructuring costs	  	 	54	 	 	 	74	 	 	 	(2	) 	
Other nonoperating items	  	 	1	 	 	 	21	 	 	 	13	 	
	  	 	 	 	 	 	 	 	 	 	 	 	
Earnings (loss) from continuing operations before income taxes	  	 	149	 	 	 	(317	) 	 	 	4,290	 	
Income tax expense (benefit)	  	 	169	 	 	 	(132	) 	 	 	2,156	 	
	  	 	 	 	 	 	 	 	 	 	 	 	
Earnings (loss) from continuing operations	  	 	(20	) 	 	 	(185	) 	 	 	2,134	 	
Earnings (loss) from discontinued operations, net of tax	  	 	—  	  	 	 	(21	) 	 	 	2,570	 	
	  	 	 	 	 	 	 	 	 	 	 	 	
Net earnings (loss)	  	$	(20	) 	 	$	(206	) 	 	$	4,704	 	
	  	 	 	 	 	 	 	 	 	 	 	 	
Basic earnings (loss) from continuing operations per share	  	$	(0.06	) 	 	$	(0.47	) 	 	$	5.12	 	
Basic earnings (loss) from discontinued operations per share	  	 	—  	  	 	 	(0.05	) 	 	 	6.17	 	
	  	 	 	 	 	 	 	 	 	 	 	 	
Basic net earnings (loss) per share	  	$	(0.06	) 	 	$	(0.52	) 	 	$	11.29	 	
	  	 	 	 	 	 	 	 	 	 	 	 	
Diluted earnings (loss) from continuing operations per share	  	$	(0.06	) 	 	$	(0.47	) 	 	$	5.10	 	
Diluted earnings (loss) from discontinued operations per share	  	 	—  	  	 	 	(0.05	) 	 	 	6.15	 	
	  	 	 	 	 	 	 	 	 	 	 	 	
Diluted net earnings (loss) per share	  	$	(0.06	) 	 	$	(0.52	) 	 	$	11.25	 	
	  	 	 	 	 	 	 	 	 	 	 	 	
Comprehensive earnings (loss):	  				 				 				
Net earnings (loss)	  	$	(20	) 	 	$	(206	) 	 	$	4,704	 	
Other comprehensive earnings (loss), net of tax:	  				 				 				
Foreign currency translation	  	 	(548	) 	 	 	194	 	 	 	(191	) 	
Pension and postretirement plans	  	 	45	 	 	 	2	 	 	 	6	 	
	  	 	 	 	 	 	 	 	 	 	 	 	
Other comprehensive earnings (loss), net of tax	  	 	(503	) 	 	 	196	 	 	 	(185	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	
Comprehensive earnings (loss)	  	$	(523	) 	 	$	(10	) 	 	$	4,519	 	
	  	 	 	 	 	 	 	 	 	 	 	 	
See accompanying notes to consolidated financial statements.
 
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
 CONSOLIDATED STATEMENTS OF CASH FLOWS

 	  	Year Ended December 31,	 	
 	  	2013	 	 	2012	 	 	2011	 	
 	  	(In millions)	 	
Cash flows from operating activities:	  				 				 				
Net earnings (loss)	  	$	(20	) 	 	$	(206	) 	 	$	4,704	 	
Loss (earnings) from discontinued operations, net of tax	  	 	—  	  	 	 	21	 	 	 	(2,570	) 	
Adjustments to reconcile earnings (loss) from continuing operations to net cash from operating activities:	  				 				 				
Depreciation, depletion and amortization	  	 	2,780	 	 	 	2,811	 	 	 	2,248	 	
Asset impairments	  	 	1,976	 	 	 	2,024	 	 	 	—  	  	
Deferred income tax expense (benefit)	  	 	97	 	 	 	(184	) 	 	 	2,299	 	
Derivatives and other financial instruments	  	 	135	 	 	 	(660	) 	 	 	(886	) 	
Cash settlements on derivatives and financial instruments	  	 	277	 	 	 	865	 	 	 	485	 	
Other noncash charges	  	 	318	 	 	 	240	 	 	 	241	 	
Net change in working capital	  	 	(298	) 	 	 	(50	) 	 	 	180	 	
Change in long-term other assets	  	 	10	 	 	 	(36	) 	 	 	33	 	
Change in long-term other liabilities	  	 	161	 	 	 	105	 	 	 	(488	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	
Cash from operating activities – continuing operations	  	 	5,436	 	 	 	4,930	 	 	 	6,246	 	
Cash from operating activities – discontinued operations	  	 	—  	  	 	 	26	 	 	 	(22	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	
Net cash from operating activities	  	 	5,436	 	 	 	4,956	 	 	 	6,224	 	
	  	 	 	 	 	 	 	 	 	 	 	 	
Cash flows from investing activities:	  				 				 				
Capital expenditures	  	 	(6,758	) 	 	 	(8,225	) 	 	 	(7,534	) 	
Proceeds from property and equipment divestitures	  	 	419	 	 	 	1,468	 	 	 	129	 	
Purchases of short-term investments	  	 	(1,076	) 	 	 	(4,106	) 	 	 	(6,691	) 	
Redemptions of short-term investments	  	 	3,419	 	 	 	3,266	 	 	 	5,333	 	
Other	  	 	(3	) 	 	 	14	 	 	 	(29	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	
Cash from investing activities – continuing operations	  	 	(3,999	) 	 	 	(7,583	) 	 	 	(8,792	) 	
Cash from investing activities – discontinued operations	  	 	—  	  	 	 	57	 	 	 	3,146	 	
	  	 	 	 	 	 	 	 	 	 	 	 	
Net cash from investing activities	  	 	(3,999	) 	 	 	(7,526	) 	 	 	(5,646	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	
Cash flows from financing activities:	  				 				 				
Proceeds from borrowings of long-term debt, net of issuance costs	  	 	2,233	 	 	 	2,458	 	 	 	2,221	 	
Net short-term debt borrowing (repayments)	  	 	(1,872	) 	 	 	(537	) 	 	 	3,726	 	
Debt repayments	  	 	—  	  	 	 	—  	  	 	 	(1,760	) 	
Credit facility borrowings	  	 	—  	  	 	 	750	 	 	 	—  	  	
Credit facility repayments	  	 	—  	  	 	 	(750	) 	 	 	—  	  	
Proceeds from stock option exercises	  	 	3	 	 	 	27	 	 	 	101	 	
Repurchases of common stock	  	 	—  	  	 	 	—  	  	 	 	(2,332	) 	
Dividends paid on common stock	  	 	(348	) 	 	 	(324	) 	 	 	(278	) 	
Excess tax benefits related to share-based compensation	  	 	4	 	 	 	5	 	 	 	13	 	
	  	 	 	 	 	 	 	 	 	 	 	 	
Net cash from financing activities	  	 	20	 	 	 	1,629	 	 	 	1,691	 	
	  	 	 	 	 	 	 	 	 	 	 	 	
Effect of exchange rate changes on cash	  	 	(28	) 	 	 	23	 	 	 	(4	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	
Net change in cash and cash equivalents	  	 	1,429	 	 	 	(918	) 	 	 	2,265	 	
Cash and cash equivalents at beginning of period	  	 	4,637	 	 	 	5,555	 	 	 	3,290	 	
	  	 	 	 	 	 	 	 	 	 	 	 	
Cash and cash equivalents at end of period	  	$	6,066	 	 	$	4,637	 	 	$	5,555	 	
	  	 	 	 	 	 	 	 	 	 	 	 	
See accompanying notes to consolidated financial statements.
 
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
 CONSOLIDATED BALANCE SHEETS

 	  	December 31,	 	
 	  	    2013    	 	 	    2012    	 	
 	  	(In millions, except
share data)	 	
ASSETS	  				 				
Current assets:	  				 				
Cash and cash equivalents	  	$	6,066	 	 	$	4,637	 	
Short-term investments	  	 	—  	  	 	 	2,343	 	
Accounts receivable	  	 	1,520	 	 	 	1,245	 	
Other current assets	  	 	419	 	 	 	746	 	
	  	 	 	 	 	 	 	 	
Total current assets	  	 	8,005	 	 	 	8,971	 	
	  	 	 	 	 	 	 	 	
Property and equipment, at cost:	  				 				
Oil and gas, based on full cost accounting:	  				 				
Subject to amortization	  	 	73,995	 	 	 	69,410	 	
Not subject to amortization	  	 	2,791	 	 	 	3,308	 	
	  	 	 	 	 	 	 	 	
Total oil and gas	  	 	76,786	 	 	 	72,718	 	
Other	  	 	6,195	 	 	 	5,630	 	
	  	 	 	 	 	 	 	 	
Total property and equipment, at cost	  	 	82,981	 	 	 	78,348	 	
Less accumulated depreciation, depletion and amortization	  	 	(54,534	) 	 	 	(51,032	) 	
	  	 	 	 	 	 	 	 	
Property and equipment, net	  	 	28,447	 	 	 	27,316	 	
	  	 	 	 	 	 	 	 	
Goodwill	  	 	5,858	 	 	 	6,079	 	
Other long-term assets	  	 	567	 	 	 	960	 	
	  	 	 	 	 	 	 	 	
Total assets	  	$	42,877	 	 	$	43,326	 	
	  	 	 	 	 	 	 	 	
LIABILITIES AND STOCKHOLDERS’ EQUITY	  				 				
Current liabilities:	  				 				
Accounts payable	  	$	1,229	 	 	$	1,451	 	
Revenues and royalties payable	  	 	786	 	 	 	750	 	
Short-term debt	  	 	4,066	 	 	 	3,189	 	
Other current liabilities	  	 	574	 	 	 	613	 	
	  	 	 	 	 	 	 	 	
Total current liabilities	  	 	6,655	 	 	 	6,003	 	
	  	 	 	 	 	 	 	 	
Long-term debt	  	 	7,956	 	 	 	8,455	 	
Asset retirement obligations	  	 	2,140	 	 	 	1,996	 	
Other long-term liabilities	  	 	834	 	 	 	901	 	
Deferred income taxes	  	 	4,793	 	 	 	4,693	 	
Stockholders’ equity:	  				 				
Common stock, $0.10 par value. Authorized 1.0 billion shares; issued 406 million shares in 2013 and 2012, respectively	  	 	41	 	 	 	41	 	
Additional paid-in capital	  	 	3,780	 	 	 	3,688	 	
Retained earnings	  	 	15,410	 	 	 	15,778	 	
Accumulated other comprehensive earnings	  	 	1,268	 	 	 	1,771	 	
	  	 	 	 	 	 	 	 	
Total stockholders’ equity	  	 	20,499	 	 	 	21,278	 	
	  	 	 	 	 	 	 	 	
Commitments and contingencies (Note 18)	  				 				
Total liabilities and stockholders’ equity	  	$	42,877	 	 	$	43,326	 	
	  	 	 	 	 	 	 	 	
See accompanying notes to consolidated financial statements.
 
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
 CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

 	 	 
Common Stock	 	 	Additional
Paid-In
Capital	 	 	Retained
Earnings	 	 	Accumulated
Other
Comprehensive
Earnings	 	 	Treasury
Stock	 	 	Total
Stockholders’
Equity	 	
 	 	Shares	 	 	Amount	 	 			 			 			 			 			
 	 	(In millions)	 	
Balance as of December 31, 2010	 	 	432	 	 	$	43	 	 	$	5,601	 	 	$	11,882	 	 	$	1,760	 	 	$	(33	) 	 	$	19,253	 	
Net earnings	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	4,704	 	 	 	—  	  	 	 	—  	  	 	 	4,704	 	
Other comprehensive loss, net of tax	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	(185	) 	 	 	—  	  	 	 	(185	) 	
Stock option exercises	 	 	2	 	 	 	—  	  	 	 	112	 	 	 	—  	  	 	 	—  	  	 	 	(11	) 	 	 	101	 	
Restricted stock grants, net of cancellations	 	 	1	 	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	
Common stock repurchased	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	(2,337	) 	 	 	(2,337	) 	
Common stock retired	 	 	(31	) 	 	 	(3	) 	 	 	(2,378	) 	 	 	—  	  	 	 	—  	  	 	 	2,381	 	 	 	—  	  	
Common stock dividends	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	(278	) 	 	 	—  	  	 	 	—  	  	 	 	(278	) 	
Share-based compensation	 	 	—  	  	 	 	—  	  	 	 	159	 	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	159	 	
Share-based compensation tax benefits	 	 	—  	  	 	 	—  	  	 	 	13	 	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	13	 	
	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance as of December 31, 2011	 	 	404	 	 	 	40	 	 	 	3,507	 	 	 	16,308	 	 	 	1,575	 	 	 	—  	  	 	 	21,430	 	
	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net loss	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	(206	) 	 	 	—  	  	 	 	—  	  	 	 	(206	) 	
Other comprehensive earnings, net of tax	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	196	 	 	 	—  	  	 	 	196	 	
Stock option exercises	 	 	1	 	 	 	1	 	 	 	49	 	 	 	—  	  	 	 	—  	  	 	 	(23	) 	 	 	27	 	
Restricted stock grants, net of cancellations	 	 	1	 	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	
Common stock repurchased	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	(29	) 	 	 	(29	) 	
Common stock retired	 	 	—  	  	 	 	—  	  	 	 	(52	) 	 	 	—  	  	 	 	—  	  	 	 	52	 	 	 	—  	  	
Common stock dividends	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	(324	) 	 	 	—  	  	 	 	—  	  	 	 	(324	) 	
Share-based compensation	 	 	—  	  	 	 	—  	  	 	 	179	 	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	179	 	
Share-based compensation tax benefits	 	 	—  	  	 	 	—  	  	 	 	5	 	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	5	 	
	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance as of December 31, 2012	 	 	406	 	 	 	41	 	 	 	3,688	 	 	 	15,778	 	 	 	1,771	 	 	 	—  	  	 	 	21,278	 	
	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net loss	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	(20	) 	 	 	—  	  	 	 	—  	  	 	 	(20	) 	
Other comprehensive loss, net of tax	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	(503	) 	 	 	—  	  	 	 	(503	) 	
Stock option exercises	 	 	—  	  	 	 	—  	  	 	 	3	 	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	3	 	
Common stock repurchased	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	(36	) 	 	 	(36	) 	
Common stock retired	 	 	—  	  	 	 	—  	  	 	 	(36	) 	 	 	—  	  	 	 	—  	  	 	 	36	 	 	 	—  	  	
Common stock dividends	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	(348	) 	 	 	—  	  	 	 	—  	  	 	 	(348	) 	
Share-based compensation	 	 	—  	  	 	 	—  	  	 	 	121	 	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	121	 	
Share-based compensation tax benefits	 	 	—  	  	 	 	—  	  	 	 	4	 	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	4	 	
	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance as of December 31, 2013	 	 	406	 	 	$	41	 	 	$	3,780	 	 	$	15,410	 	 	$	1,268	 	 	$	—  	  	 	$	20,499	 	
	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
See accompanying notes to consolidated financial statements.
 
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 
1.	Summary of Significant Accounting Policies	
Devon Energy Corporation (“Devon”) is a leading independent energy company engaged primarily in the exploration, development and production of oil, natural gas and NGLs. Devon’s operations are concentrated in various North American onshore areas in the U.S. and Canada. Devon also owns natural gas pipelines, plants and treatment facilities in many of its producing areas, making it one of North America’s larger processors of natural gas.
Accounting policies used by Devon and its subsidiaries conform to accounting principles generally accepted in the United States of America and reflect industry practices. The more significant of such policies are discussed below.
Principles of Consolidation
The accounts of Devon and its wholly owned and controlled subsidiaries are included in the accompanying financial statements. All significant intercompany accounts and transactions have been eliminated in consolidation.
Use of Estimates
The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual amounts could differ from these estimates, and changes in these estimates are recorded when known. Significant items subject to such estimates and assumptions include the following:
 
 	•	 	proved reserves and related present value of future net revenues;	
 
 	•	 	the carrying value of oil and gas properties;	
 
 	•	 	derivative financial instruments;	
 
 	•	 	the fair value of reporting units and related assessment of goodwill for impairment;	
 
 	•	 	income taxes;	
 
 	•	 	asset retirement obligations;	
 
 	•	 	obligations related to employee pension and postretirement benefits; and	
 
 	•	 	legal and environmental risks and exposures.	
Revenue Recognition and Gas Balancing
Oil, gas and NGL sales are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectability of the revenue is probable. Delivery occurs and title is transferred when production has been delivered to a pipeline, railcar or truck. Cash received relating to future production is deferred and recognized when all revenue recognition criteria are met. Taxes assessed by governmental authorities on oil, gas and NGL sales are presented separately from such revenues in the accompanying comprehensive statements of earnings.
Devon follows the sales method of accounting for gas production imbalances. The volumes of gas sold may differ from the volumes to which Devon is entitled based on its interests in the properties. These differences
 
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
create imbalances that are recognized as a liability only when the estimated remaining reserves will not be sufficient to enable the underproduced owner to recoup its entitled share through production. The liability is measured based on current market prices. No receivables are recorded for those wells where Devon has taken less than its share of production unless all revenue recognition criteria are met. If an imbalance exists at the time the wells’ reserves are depleted, settlements are made among the joint interest owners under a variety of arrangements.
Marketing and midstream revenues are recorded at the time products are sold or services are provided to third parties at a fixed or determinable price, delivery or performance has occurred, title has transferred and collectability of the revenue is probable. Revenues and expenses attributable to oil, gas and NGL purchases, transportation and processing contracts are reported on a gross basis when Devon takes title to the products and has risks and rewards of ownership.
During 2013, 2012 and 2011, no purchaser accounted for more than 10 percent of Devon’s operating revenues from continuing operations.
Derivative Financial Instruments
Devon is exposed to certain risks relating to its ongoing business operations, including risks related to commodity prices, interest rates and Canadian to U.S. dollar exchange rates. As discussed more fully below, Devon uses derivative instruments primarily to manage commodity price risk, interest rate risk and foreign exchange risk. Devon does not intend to issue or hold derivative financial instruments for speculative trading purposes.
Devon periodically enters into derivative financial instruments with respect to a portion of its oil, gas and NGL production to hedge 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 typically 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 index prices and pays a variable differential on the same two index prices to the contract counterparty. The price collars set a floor and ceiling price for the hedged production. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, Devon will cash-settle the difference with the counterparty to the collars. The call options give counterparties the right to purchase production at a predetermined price.
Devon periodically enters into interest rate swaps to manage its exposure to interest rate volatility. Devon periodically enters into foreign exchange forward contracts to manage its exposure to fluctuations in exchange rates.
All derivative financial instruments are recognized at their current fair value as either assets or liabilities in the balance sheet. Changes in the fair value of these derivative financial instruments are recorded in earnings unless specific hedge accounting criteria are met. For derivative financial instruments held during the three-year period ended December 31, 2013, Devon chose not to meet the necessary criteria to qualify its derivative financial instruments for hedge accounting treatment. Cash settlements with counterparties on Devon’s derivative financial instruments are also recorded in earnings.
By using derivative financial instruments to hedge exposures to changes in commodity prices, interest rates and foreign currency rates, Devon is exposed to credit risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. To mitigate this risk, the hedging instruments are placed with
 
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
a number of counterparties whom Devon believes are acceptable credit risks. It is Devon’s policy to enter into derivative contracts only with investment grade rated counterparties deemed by management to be competent and competitive market makers. Additionally, Devon’s derivative contracts generally require cash collateral to be posted if either its or the counterparty’s credit rating falls below certain credit rating levels. The mark-to-market exposure threshold, above which collateral must be posted, decreases as the debt rating falls further below such credit levels. As of December 31, 2013, Devon held $3 million of cash collateral, which represented the estimated fair value of certain derivative positions in excess of Devon’s credit guidelines. The collateral is reported in other current liabilities in the accompanying balance sheet.
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 generally recognized as a component of general and administrative expenses in the accompanying comprehensive statements of earnings over the applicable requisite service periods. As a result of Devon’s consolidation of its U.S. operations announced in October 2012, certain share based awards were accelerated and recognized as a component of restructuring costs in the accompanying comprehensive statements of earnings.
Generally, Devon uses new shares from approved incentive programs to grant share-based awards and to issue shares upon stock option exercises. Shares repurchased under approved programs are available to be issued as part of Devon’s share based awards. However, Devon has historically cancelled these shares upon repurchase.
Income Taxes
Devon is subject to current income taxes assessed by the federal and various state jurisdictions in the U.S. and by other foreign jurisdictions. In addition, Devon accounts for deferred income taxes related to these jurisdictions using the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax basis. Deferred tax assets are also recognized for the future tax benefits attributable to the expected utilization of existing tax net operating loss carryforwards and other types of carryforwards. If the future utilization of some portion of carryforwards is determined to be unlikely, a valuation allowance is provided to reduce the recorded tax benefits from such assets. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.
Devon does not recognize U.S. deferred income taxes on the unremitted earnings of its foreign subsidiaries that are deemed to be indefinitely reinvested. When such earnings are no longer deemed indefinitely reinvested, Devon recognizes the appropriate deferred, or even current, income tax liabilities.
Devon recognizes the financial statement effects of tax positions when it is more likely than not, based on the technical merits, that the position will be sustained upon examination by a taxing authority. Recognized tax positions are initially and subsequently measured as the largest amount of tax benefit that is more likely than not
 
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
of being realized upon ultimate settlement with a taxing authority. Liabilities for unrecognized tax benefits related to such tax positions are included in other long-term liabilities unless the tax position is expected to be settled within the upcoming year, in which case the liabilities are included in other current liabilities. Interest and penalties related to unrecognized tax benefits are included in current income tax expense.
Net Earnings (Loss) Per Common Share
Devon’s basic earnings per share amounts have been computed based on the average number of shares of common stock outstanding for the period. Basic earnings per share includes the effect of participating securities, which primarily consist of Devon’s outstanding restricted stock awards. Diluted earnings per share is calculated using the treasury stock method to reflect the assumed issuance of common shares for all potentially dilutive securities. Such securities primarily consist of outstanding stock options.
Cash and Cash Equivalents
Devon considers all highly liquid investments with original contractual maturities of three months or less to be cash equivalents.
Investments
Devon periodically invests excess cash in United States and Canadian treasury securities and other marketable securities. Devon considers securities with original contractual maturities in excess of three months, but less than one year to be short-term investments. Investments with contractual maturities in excess of one year are classified as long-term, unless such investments are classified as trading or available-for-sale.
Devon reports its investments and other marketable securities at fair value, except for debt securities in which management has the ability and intent to hold until maturity. Such debt securities totaled $62 million and $64 million at December 31, 2013 and 2012, respectively, and are included in other long-term assets in the accompanying balance sheet. Devon has the ability to hold the securities until maturity.
Property and Equipment
Devon follows the full cost method of accounting for its oil and gas properties. Accordingly, all costs incidental to the acquisition, exploration and development of oil and gas properties, including costs of undeveloped leasehold, dry holes and leasehold equipment, are capitalized. Internal costs incurred that are directly identified with acquisition, exploration and development activities undertaken by Devon for its own account, and that are not related to production, general corporate overhead or similar activities, are also capitalized. Interest costs incurred and attributable to unproved oil and gas properties under current evaluation and major development projects of oil and gas properties are also capitalized. All costs related to production activities, including workover costs incurred solely to maintain or increase levels of production from an existing completion interval, are charged to expense as incurred.
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 four years.
 
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
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.
Under the full cost method of accounting, capitalized costs of oil and gas properties, net of accumulated DD&A and deferred income taxes, may not exceed the full cost “ceiling” at the end of each quarter. The ceiling is calculated separately for each country and is based on the present value of estimated future net cash flows from proved oil and gas reserves, discounted at 10 percent per annum, net of related tax effects. The 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.
Estimated future net cash flows are calculated using end-of-period costs and an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months. 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, 2013, 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.
Costs for midstream assets that are in use are depreciated over the assets’ estimated useful lives, using either the unit-of-production or straight-line method. Depreciation and amortization of other property and equipment, including corporate and leasehold improvements, are provided using the straight-line method based on estimated useful lives ranging from three to 60 years. Interest costs incurred and attributable to major midstream and corporate construction projects are also capitalized.
Devon recognizes liabilities for retirement obligations associated with tangible long-lived assets, such as producing well sites and midstream pipelines and processing plants when there is a legal obligation associated with the retirement of such assets and the amount can be reasonably estimated. The initial measurement of an asset retirement obligation is recorded as a liability at its fair value, with an offsetting asset retirement cost recorded as an increase to the associated property and equipment on the consolidated balance sheet. When the assumptions used to estimate a recorded asset retirement obligation change, a revision is recorded to both the asset retirement obligation and the asset retirement cost. Devon’s asset retirement obligations include estimated environmental remediation costs which arise from normal operations and are associated with the retirement of such long-lived assets. The asset retirement cost is depreciated using a systematic and rational method similar to that used for the associated property and equipment.
Goodwill
Goodwill represents the excess of the purchase price of business combinations over the fair value of the net assets acquired and is tested for impairment at least annually. Such test includes an assessment of qualitative and quantitative factors. The impairment test requires allocating goodwill and all other assets and liabilities to assigned reporting units. The fair value of each reporting unit is estimated and compared to the net book value of the reporting unit. If the estimated fair value of the reporting unit is less than the net book value, including goodwill, then the goodwill is written down to the implied fair value of the goodwill through a charge to expense. 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.
 
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
Devon performed annual impairment tests of goodwill in the fourth quarters of 2013, 2012 and 2011. Based on these assessments, no impairment of goodwill was required.
The table below provides a summary of Devon’s goodwill, by assigned reporting unit. The decrease in Devon’s goodwill from 2012 to 2013 was primarily due to changes in the exchange rate between the United States dollar and the Canadian dollar.

 	  	December 31,	 	
 	  	    2013    	 	  	    2012    	 	
 	  	(In millions)	 	
U.S.	  	$	3,020	  	  	$	3,046	  	
Canada	  	 	2,838	  	  	 	3,033	  	
	  	 	 	 	  	 	 	 	
Total	  	$	5,858	  	  	$	6,079	  	
	  	 	 	 	  	 	 	 	
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 resulting from improper operation of assets are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. Expenditures related to such environmental matters are expensed or capitalized in accordance with Devon’s accounting policy for property and equipment.
Fair Value Measurements
Certain of Devon’s assets and liabilities are measured at fair value at each reporting date. Fair value represents the price that would be received to sell the asset or paid to transfer the liability in an orderly transaction between market participants. This price is commonly referred to as the “exit price.” Fair value measurements are classified according to a hierarchy that prioritizes the inputs underlying the valuation techniques. This hierarchy consists of three broad levels:
 
 	•	 	Level 1 – Inputs consist of unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. When available, Devon measures fair value using Level 1 inputs because they generally provide the most reliable evidence of fair value.	
 
 	•	 	Level 2 – Inputs consist of quoted prices that are generally observable for the asset or liability. Common examples of Level 2 inputs include quoted prices for similar assets and liabilities in active markets or quoted prices for identical assets and liabilities in markets not considered to be active.	
 
 	•	 	Level 3 – Inputs are not observable from objective sources and have the lowest priority. The most common Level 3 fair value measurement is an internally developed cash flow model.	
Discontinued Operations
All amounts related to Devon’s International operations that were sold in 2012 and 2011 are classified as discontinued operations.
Foreign Currency Translation Adjustments
The United States dollar is the functional currency for Devon’s consolidated operations except its Canadian subsidiaries, which use the Canadian dollar as the functional currency. Assets and liabilities of the Canadian subsidiaries are translated to United States dollars using the applicable exchange rate as of the end of a reporting
 
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
period. Revenues, expenses and cash flow are translated using an average exchange rate during the reporting period. Translation adjustments have no effect on net income and are included in accumulated other comprehensive earnings in stockholders’ equity.
 
2.	Derivative Financial Instruments	
Commodity Derivatives
As of December 31, 2013, Devon had the following open oil derivative positions. Devon’s oil derivatives settle against the average of the prompt month NYMEX West Texas Intermediate futures price.

 	  	Price Swaps	 	  	Price Collars	 	  	Call Options Sold	 	
Period	  	Volume
(Bbls/d)	 	  	Weighted
Average Price
($/Bbl)	 	  	Volume
(Bbls/d)	 	  	Weighted Average
Floor Price ($/Bbl)	 	  	Weighted Average
Ceiling Price ($/Bbl)	 	  	Volume
(Bbls/d)	 	  	Weighted
Average Price
($/Bbl)	 	
Q1-Q4 2014	  	 	75,000	  	  	$	94.14	  	  	 	70,453	  	  	$	89.38	  	  	$	100.58	  	  	 	42,000	  	  	$	116.43	  	
Q1-Q4 2015	  	 	37,500	  	  	$	90.15	  	  	 	—  	  	  	$	—  	  	  	$	—  	  	  	 	22,000	  	  	$	115.45	  	
Q1-Q4 2016	  	 	—  	  	  	$	—  	  	  	 	—  	  	  	$	—  	  	  	$	—  	  	  	 	12,500	  	  	$	95.00	  	
As of December 31, 2013, Devon had the following open natural gas derivative positions. The first table presents Devon’s natural gas derivatives that settle against the Inside FERC first of the month Henry Hub index. The second table presents Devon’s natural gas derivatives that settle against the AECO index.

 	 	Price Swaps	 	 	Price Collars	 	 	Call Options Sold	 	
Period	 	Volume
(MMBtu/d)	 	 	Weighted
Average Price
($/MMBtu)	 	 	Volume
(MMBtu/d)	 	 	Weighted Average
Floor Price
($/MMBtu)	 	 	Weighted Average
Ceiling  Price
($/MMBtu)	 	 	Volume
(MMBtu/d)	 	 	Weighted
Average Price
($/MMBtu)	 	
Q1-Q4 2014	 	 	800,000	  	 	$	4.42	  	 	 	460,000	  	 	$	4.03	  	 	$	4.51	  	 	 	500,000	  	 	$	5.00	  	
Q1-Q4 2015	 	 	—  	  	 	$	—  	  	 	 	—  	  	 	$	—  	  	 	$	—  	  	 	 	550,000	  	 	$	5.09	  	
Q1-Q4 2016	 	 	—  	  	 	$	—  	  	 	 	—  	  	 	$	—  	  	 	$	—  	  	 	 	110,000	  	 	$	5.00	  	

   	  	Basis Swaps	 	
Period	  	Index	 	  	      Volume (MMBtu/d)      	 	  	Weighted Average
Differential  to Henry Hub
($/MMBtu)	 	
Q1-Q4 2014	  	 	AECO	  	  	 	94,781	  	  	$	(0.52	) 	
As of December 31, 2013, Devon had the following open NGL derivative positions. Devon’s NGL positions settle against the average of the prompt month OPIS Mont Belvieu, Texas Index.

    	  	Basis Swaps	 	
Period	  	Pay	 	  	Volume
(Bbls/d)	 	  	Weighted Average
Differential  to WTI
($/Bbl)	 	
Q1-Q4 2014	  	 	Natural Gasoline	  	  	 	329	  	  	$	(10.85	) 	
 
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
Foreign Currency Derivatives
As of December 31, 2013, Devon had the following open foreign currency derivative position:

Forward Contract	 	
Currency	  	Contract
Type	 	  	CAD
Notional	 	  	Weighted Average
Fixed Rate Received	 	  	Expiration	 	
	  	 	 	  	(In millions)	 	  	(CAD-USD)	 	  	 	 	
Canadian Dollar	  	 	Sell	  	  	$	1,002	  	  	 	0.938	  	  	 	March 2014	  	
Financial Statement Presentation
The following table presents the net gains and losses recognized in the accompanying comprehensive statements of earnings associated with derivative financial instruments. Net gains and losses associated with Devon’s commodity derivatives are presented in oil, gas and NGL derivatives in the accompanying comprehensive statements of earnings. Net gains and losses associated with Devon’s interest rate and foreign currency derivatives are presented in other nonoperating items in the accompanying comprehensive statements of earnings.

 	  	Year Ended
December 31,	 	
 	  	2013	 	 	2012	 	 	2011	 	
 	  	(In millions)	 	
Commodity derivatives	  	$	(191	) 	 	$	693	  	 	$	881	  	
Interest rate derivatives	  	 	—  	  	 	 	(15	) 	 	 	(11	) 	
Foreign currency derivatives	  	 	56	  	 	 	(18	) 	 	 	16	  	
	  	 	 	 	 	 	 	 	 	 	 	 	
Net gains (losses) recognized in comprehensive statements of earnings	  	$	(135	) 	 	$	660	  	 	$	886	  	
	  	 	 	 	 	 	 	 	 	 	 	 	
The following table presents the derivative fair values included in the accompanying balance sheets.

 	  	 	  	December 31	 	
 	  	Balance Sheet Caption	  	    2013    	 	  	    2012    	 	
 	  	 	  	(In millions)	 	
Asset derivatives:	  		  				  				
Commodity derivatives	  	Other current assets	  	$	75	  	  	$	379	  	
Commodity derivatives	  	Other long-term assets	  	 	28	  	  	 	22	  	
Interest rate derivatives	  	Other current assets	  	 	—  	  	  	 	23	  	
Foreign currency derivatives	  	Other current assets	  	 	—  	  	  	 	1	  	
	  		  	 	 	 	  	 	 	 	
Total asset derivatives	  		  	$	103	  	  	$	425	  	

Liability derivatives:	  		  				  				
Commodity derivatives	  	Other current liabilities	  	$	58	  	  	$	3	  	
Commodity derivatives	  	Other long-term liabilities	  	 	62	  	  	 	29	  	
Foreign currency derivatives	  	Other current liabilities	  	 	1	  	  	 	—  	  	
	  		  	 	 	 	  	 	 	 	
Total liability derivatives	  		  	$	121	  	  	$	32	  	

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
3.	Share-Based Compensation	
On June 3, 2009, Devon’s stockholders adopted the 2009 Long-Term Incentive Plan, which expires on June 2, 2019. This plan authorizes the Compensation Committee, which consists of independent non-management members of Devon’s Board of Directors, to grant nonqualified and incentive stock options, restricted stock awards, performance restricted stock awards, Canadian restricted stock units, performance share units, stock appreciation rights and cash-out rights to eligible employees. The plan also authorizes the grant of nonqualified stock options, restricted stock awards, restricted stock units and stock appreciation rights to directors.
In the second quarter of 2012, Devon’s stockholders adopted an amendment to the 2009 Long-Term Incentive Plan, which also expires June 2, 2019. This amendment increases the number of shares authorized for issuance from 21.5 million shares to 47.0 million shares. To calculate shares issued under the 2009 Long-Term Incentive Plan subsequent to this amendment, options and stock appreciation rights represent one share and other awards represent 2.38 shares.
Devon also has a stock option plan that was adopted in 2005 under which stock options were issued to certain employees. Options granted under this plan remain exercisable by the employees owning such options, but no new options or restricted stock awards will be granted under this plan.
Devon did not have an annual long-term incentive grant in 2013 due to revisions in the timing of the employee compensation cycle. The annual long-term incentive grant related to 2013 performance was granted in February 2014. The following table presents the effects of share-based compensation included in Devon’s accompanying comprehensive statements of earnings. The vesting for certain share-based awards was accelerated as part of Devon’s consolidation of its U.S. operations announced in October 2012. The associated expense for these accelerated awards is included in restructuring costs in the accompanying comprehensive statements of earnings. See Note 6 for further details.

 	  	Year Ended December 31,	 	
 	  	2013	 	  	2012	 	  	2011	 	
 	  	(In millions)	 	
Gross general and administrative expense	  	$	157	  	  	$	179	  	  	$	181	  	
Share-based compensation expense capitalized pursuant to the full cost method of accounting for oil and gas properties	  	$	60	  	  	$	56	  	  	$	56	  	
Related income tax benefit	  	$	22	  	  	$	31	  	  	$	33	  	
Stock Options
In accordance with Devon’s incentive plans, the exercise price of stock options granted may not be less than the market value of the stock at the date of grant. In addition, options granted are exercisable during a period established for each grant, which may not exceed eight years from the date of grant. The recipient must pay the exercise price in cash or in common stock, or a combination thereof, at the time that the option is exercised. Generally, the service requirement for vesting ranges from zero to four years.
The fair value of stock options on the date of grant is expensed over the applicable vesting period. Devon estimates the fair values of stock options granted using a Black-Scholes option valuation model, which requires Devon to make several assumptions. The volatility of Devon’s common stock is based on the historical volatility of the market price of Devon’s common stock over a period of time equal to the expected term of the option and ending on the grant date. The dividend yield is based on Devon’s historical and current yield in effect at the date
 
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
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 for 2012 and 2011. All such amounts represent the weighted-average amounts for each year. No stock options were granted in 2013.

 	  	2012	 	 	2011	 	
Grant-date fair value	  	$	22.20	  	 	$	23.11	  	
Volatility factor	  	 	42.5	% 	 	 	46.0	% 	
Dividend yield	  	 	1.2	% 	 	 	1.0	% 	
Risk-free interest rate	  	 	1.1	% 	 	 	0.8	% 	
Expected term (in years)	  	 	6.0	  	 	 	4.2	  	
The following table presents a summary of Devon’s outstanding stock options.

 	  	 	 	 	Weighted Average	 	  	 	 	
 	  	Options	 	 	Exercise
Price	 	  	Remaining
Term	 	  	Intrinsic
Value	 	
 	  	(In thousands)	 	 	 	 	  	(In years)	 	  	(In millions)	 	
Outstanding at December 31, 2012	  	 	7,828	  	 	$	69.12	  	  				  				
Exercised	  	 	(61	) 	 	$	57.66	  	  				  				
Expired	  	 	(1,212	) 	 	$	68.47	  	  				  				
Forfeited	  	 	(109	) 	 	$	69.23	  	  				  				
	  	 	 	 	 				  				  				
Outstanding at December 31, 2013	  	 	6,446	  	 	$	69.35	  	  	 	3.76	  	  	$	1	  	
	  	 	 	 	 				  				  				
Vested and expected to vest at December 31, 2013	  	 	6,416	  	 	$	69.36	  	  	 	3.75	  	  	$	1	  	
	  	 	 	 	 				  				  				
Exercisable at December 31, 2013	  	 	5,361	  	 	$	69.50	  	  	 	3.39	  	  	$	1	  	
	  	 	 	 	 				  				  				
The aggregate intrinsic value of stock options that were exercised during 2013, 2012 and 2011 was $0.3 million, $34 million and $81 million, respectively. As of December 31, 2013, Devon’s unrecognized compensation cost related to unvested stock options was $19 million. Such cost is expected to be recognized over a weighted-average period of 1.6 years.
 
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
Restricted Stock Awards and Units
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, the service requirement for vesting ranges from zero to four years. During the vesting period, recipients of restricted stock awards receive dividends that are not subject to restrictions or other limitations. Devon estimates the fair values of restricted stock awards and units as the closing price of Devon’s common stock on the grant date of the award or unit, which is expensed over the applicable vesting period. The following table presents a summary of Devon’s unvested restricted stock awards and units.

 	  	Restricted
Stock Awards
& Units	 	 	Weighted
Average
Grant-Date
Fair Value	 	
 	  	(In thousands)	 	 	 	 	
Unvested at December 31, 2012	  	 	5,740	  	 	$	61.75	  	
Granted	  	 	258	  	 	$	57.27	  	
Vested	  	 	(2,365	) 	 	$	64.13	  	
Forfeited	  	 	(341	) 	 	$	59.82	  	
	  	 	 	 	 				
Unvested at December 31, 2013	  	 	3,292	  	 	$	59.76	  	
	  	 	 	 	 				
The aggregate fair value of restricted stock awards and units that vested during 2013, 2012 and 2011 was $141 million, $112 million and $145 million, respectively. As of December 31, 2013, Devon’s unrecognized compensation cost related to unvested restricted stock awards and units was $166 million. Such cost is expected to be recognized over a weighted-average period of 2.2 years.
Performance Based Restricted Stock Awards
Performance based restricted stock awards are granted to certain members of Devon’s senior management. Vesting of the awards is dependent on Devon meeting certain internal performance targets and the recipient meeting certain service requirements. Generally, the service requirement for vesting ranges from zero to four years. If Devon meets or exceeds the performance target, the awards vest after the recipient meets the related requisite service period. If the performance target and service period requirement are not met, the award does not vest. Once vested, recipients are entitled to dividends on the awards. Devon estimates the fair values of the awards as the closing price of Devon’s common stock on the grant date of the award, which is expensed over the applicable vesting period. The following table presents a summary of Devon’s performance based restricted stock awards.

 	  	Performance
Restricted
Stock Awards	 	 	Weighted
Average
Grant-Date
Fair Value	 	
 	  	(In thousands)	 	 	 	 	
Unvested at December 31, 2012	  	 	408	  	 	$	58.25	  	
Vested	  	 	(92	) 	 	$	65.10	  	
	  	 	 	 	 				
Unvested at December 31, 2013	  	 	316	  	 	$	56.25	  	
	  	 	 	 	 				
As of December 31, 2013, Devon’s unrecognized compensation cost related to these awards was $3 million. Such cost is expected to be recognized over a weighted-average period of 1.4 years.
 
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
Performance Share Units
Performance share units are granted to certain members of Devon’s senior management. Each unit that vests entitles the recipient to one share of Devon common stock. The vesting of these units is based on comparing Devon’s total shareholder return (“TSR”) to the TSR of a predetermined group of fourteen peer companies over the specified two- or three-year performance period. The vesting of units may be between zero and 200 percent of the units granted depending on Devon’s TSR as compared to the peer group on the vesting date.
At the end of the vesting period, recipients receive dividend equivalents with respect to the number of units vested. The fair value of each performance share unit is estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all grants made under the plan: (i) a risk-free interest rate based on United States Treasury rates as of the grant date; (ii) a volatility assumption based on the historical realized price volatility of Devon and the designated peer group; and (iii) an estimated ranking of Devon among the designated peer group. The fair value of the unit on the date of grant is expensed over the applicable vesting period. The following table presents a summary of the grant-date fair values of performance share units granted and the related assumptions.

   	  	2013	  	2012	  	2011	
Grant-date fair value	  	$61.27 – $63.48	  	$61.27 – $63.48	  	$80.24 – $83.15	
Risk-free interest rate	  	0.26% – 0.36%	  	0.26% – 0.36%	  	0.28% – 0.43%	
Volatility factor	  	30.3%	  	30.3%	  	41.8%	
Contractual term (in years)	  	3.0	  	3.0	  	3.0	
The following table presents a summary of Devon’s performance share units.

 	  	Performance
Share Units	 	 	Weighted
Average
Grant-Date
Fair Value	 	
 	  	(In thousands)	 	 	 	 	
Unvested at December 31, 2012	  	 	878	  	 	$	66.93	  	
Granted	  	 	55	  	 	$	61.57	  	
Forfeited	  	 	(8	) 	 	$	63.37	  	
	  	 	 	 	 				
Unvested at December 31, 2013 (1)	  	 	925	  	 	$	66.64	  	

(1)	A maximum of 1.9 million common shares could be awarded based upon Devon’s final TSR ranking.	
As of December 31, 2013, Devon’s unrecognized compensation cost related to unvested units was $24 million. Such cost is expected to be recognized over a weighted-average period of 1.6 years.
 
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
4.	Asset impairments	
In 2013 and 2012, Devon recognized asset impairments related to its oil and gas property and equipment and its U.S. midstream assets as presented below.

 	  	Year Ended December 31, 2013	 	  	Year Ended December 31, 2012	 	
 	  	    Gross    	 	  	    Net of Taxes    	 	  	    Gross    	 	  	    Net of Taxes    	 	
 	  	(In millions)	 	
U.S. oil and gas assets	  	$	1,110	  	  	$	707	  	  	$	1,793	  	  	$	1,142	  	
Canada oil and gas assets	  	 	843	  	  	 	632	  	  	 	163	  	  	 	122	  	
Midstream assets	  	 	23	  	  	 	14	  	  	 	68	  	  	 	44	  	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total asset impairments	  	$	1,976	  	  	$	1,353	  	  	$	2,024	  	  	$	1,308	  	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Oil and Gas Impairments
Under the full cost method of accounting, capitalized costs of oil and gas properties are subject to a quarterly full cost ceiling test, which is discussed in Note 1.
The oil and gas impairments resulted primarily from declines in the U.S. and Canada full cost ceilings. The lower ceiling values resulted primarily from decreases in the 12-month average trailing prices for oil, natural gas and NGLs, which reduced proved reserve values.
Midstream Impairments
Due to declining natural gas production resulting from low natural gas and NGL prices, Devon determined that the carrying amounts of certain of its midstream facilities were not recoverable from estimated future cash flows. Consequently, the assets were written down to their estimated fair values, which were determined using discounted cash flow models. The fair value of Devon’s midstream assets is considered a Level 3 fair value measurement.
 
5.	Other Operating Items	

 	  	Year Ended December 31,	 	
 	  	2013	 	 	2012	 	 	2011	 	
 	  	(In millions)	 	
Accretion of asset retirement obligations	  	$	115	  	 	$	110	  	 	$	92	  	
(Gain) loss on sale of assets	  	 	9	  	 	 	(13	) 	 	 	(2	) 	
Other	  	 	(3	) 	 	 	(5	) 	 	 	(101	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	
Other operating items	  	$	121	  	 	$	92	  	 	$	(11	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	
During 2011, Devon received $88 million of excess insurance recoveries related to certain weather and operational claims.
 
6.	Restructuring Costs	
Office Consolidation
In October 2012, Devon announced plans to consolidate its U.S. personnel into a single operations group centrally located at the company’s corporate headquarters in Oklahoma City. As a result, Devon closed its office in Houston, transferred operational responsibilities for assets in south Texas, east Texas and Louisiana to Oklahoma City and incurred $134 million of restructuring costs associated with the consolidation.
 
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
Divestiture of Offshore Assets
In the fourth quarter of 2009, Devon announced plans to divest its offshore assets. As of December 31, 2012, Devon had divested all of its U.S. Offshore and International assets and incurred $196 million of restructuring costs associated with the divestitures.
Financial Statement Presentation
The schedule below summarizes restructuring costs presented in the accompanying comprehensive statements of earnings.

 	  	Year Ended December 31,	 	
 	  	    2013    	 	  	    2012    	 	 	    2011    	 	
 	  	(In millions)	 	
Office consolidation:	  				  				 				
Employee severance and retention	  	$	13	  	  	$	77	  	 	$	—  	  	
Lease obligations and other	  	 	41	  	  	 	3	  	 	 	—  	  	
	  	 	 	 	  	 	 	 	 	 	 	 	
Total	  	 	54	  	  	 	80	  	 	 	—  	  	
	  	 	 	 	  	 	 	 	 	 	 	 	
Offshore divestitures:	  				  				 				
Employee severance	  	$	—  	  	  	$	(3	) 	 	$	8	  	
Lease obligations and other	  	 	—  	  	  	 	(3	) 	 	 	(10	) 	
	  	 	 	 	  	 	 	 	 	 	 	 	
Total	  	 	—  	  	  	 	(6	) 	 	 	(2	) 	
	  	 	 	 	  	 	 	 	 	 	 	 	
Restructuring costs	  	$	54	  	  	$	74	  	 	$	(2	) 	
	  	 	 	 	  	 	 	 	 	 	 	 	
Employee severance and retention – As of December 31, 2013, Devon had incurred $90 million of employee severance and retention costs associated with the office consolidation. This included amounts related to cash severance costs and accelerated vesting of share-based grants.
Lease obligations and other – As of December 31, 2013, Devon had incurred $28 million of restructuring costs related to certain office space that is subject to non-cancellable operating lease agreements and that it ceased using as a part of the office consolidation. 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 it may receive over the term of the leases, as well as the amount of variable operating costs that it will be required to pay under the leases.
The schedule below summarizes Devon’s restructuring liabilities.

 	  	Other
Current
Liabilities	 	 	Other
Long-Term
Liabilities	 	 	Total	 	
 	  	(In millions)	 	
Balance as of December 31, 2011	  	$	29	  	 	$	16	  	 	$	45	  	
Employee severance – Office consolidation	  	 	49	  	 	 	—  	  	 	 	49	  	
Lease obligations – Offshore	  	 	(17	) 	 	 	(7	) 	 	 	(24	) 	
Employee severance – Offshore	  	 	(9	) 	 	 	—  	  	 	 	(9	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	
Balance as of December 31, 2012	  	 	52	  	 	 	9	  	 	 	61	  	
Employee severance – Office consolidation	  	 	(43	) 	 	 	—  	  	 	 	(43	) 	
Lease obligations – Offshore	  	 	(3	) 	 	 	(2	) 	 	 	(5	) 	
Lease obligations and other – Office consolidation	  	 	21	  	 	 	11	  	 	 	32	  	
	  	 	 	 	 	 	 	 	 	 	 	 	
Balance as of December 31, 2013	  	$	27	  	 	$	18	  	 	$	45	  	

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
7.	Income Taxes	
Income Tax Expense (Benefit)
Devon’s income tax components are presented in the following table.

 	  	Year Ended December 31,	 	
 	  	2013	 	 	2012	 	 	2011	 	
 	  	(In millions)	 	
Current income tax expense (benefit):	  				 				 				
United States federal	  	$	73	  	 	$	60	  	 	$	(143	) 	
Various states	  	 	(5	) 	 	 	(3	) 	 	 	20	  	
Canada and various provinces	  	 	4	  	 	 	(5	) 	 	 	(20	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	
Total current tax expense (benefit)	  	 	72	  	 	 	52	  	 	 	(143	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	
Deferred income tax expense (benefit):	  				 				 				
United States federal	  	 	198	  	 	 	(188	) 	 	 	1,986	  	
Various states	  	 	59	  	 	 	34	  	 	 	95	  	
Canada and various provinces	  	 	(160	) 	 	 	(30	) 	 	 	218	  	
	  	 	 	 	 	 	 	 	 	 	 	 	
Total deferred tax expense (benefit)	  	 	97	  	 	 	(184	) 	 	 	2,299	  	
	  	 	 	 	 	 	 	 	 	 	 	 	
Total income tax expense (benefit)	  	$	169	  	 	$	(132	) 	 	$	2,156	  	
	  	 	 	 	 	 	 	 	 	 	 	 	
Total income tax expense (benefit) differed from the amounts computed by applying the United States federal income tax rate to earnings from continuing operations before income taxes as a result of the following:

 	  	Year Ended December 31,	 	
 	  	2013	 	 	2012	 	 	2011	 	
 	  	(In millions)	 	
Expected income tax expense (benefit) based on United States statutory tax rate of 35%	  	$	52	  	 	$	(111	) 	 	$	1,502	  	
Repatriations	  	 	97	  	 	 	—  	  	 	 	725	  	
State income taxes	  	 	35	  	 	 	20	  	 	 	70	  	
Taxation on Canadian operations	  	 	14	  	 	 	(19	) 	 	 	(91	) 	
Other	  	 	(29	) 	 	 	(22	) 	 	 	(50	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	
Total income tax expense (benefit)	  	$	169	  	 	$	(132	) 	 	$	2,156	  	
	  	 	 	 	 	 	 	 	 	 	 	 	
Pursuant to the completed and planned divestitures of Devon’s International assets located outside North America, a portion of Devon’s foreign earnings had been deemed to no longer be indefinitely reinvested. As of December 31, 2012, Devon had recognized a $936 million deferred income tax liability related to assumed repatriations of earnings from its foreign subsidiaries, including $725 million of deferred income tax expense recognized in 2011.
In the second and fourth quarters of 2013, Devon repatriated to the U. S. a total of $4.3 billion of its cash held outside of the U. S. In the fourth quarter of 2013, Devon announced plans to divest of its Canadian conventional assets. These events resulted in an incremental income tax expense of $97 million. The incremental expense included $180 million of current income tax expense offset by $83 million of deferred income tax benefit. The $83 million deferred tax benefit was comprised of $180 million of deferred tax benefits that offset the incremental current income tax expense and an additional $97 million of deferred income tax expense accrued in the fourth quarter for assumed repatriations.
 
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
Deferred Tax Assets and Liabilities
The tax effects of temporary differences that gave rise to Devon’s deferred tax assets and liabilities are presented below:

 	  	December 31,	 	
 	  	2013	 	 	2012	 	
 	  	(In millions)	 	
Deferred tax assets:	  				 				
Asset retirement obligations	  	$	673	  	 	$	618	  	
Foreign tax credits	  	 	248	  	 	 	—  	  	
Net operating loss carryforwards	  	 	183	  	 	 	427	  	
Alternative minimum tax credits	  	 	105	  	 	 	198	  	
Pension benefit obligations	  	 	104	  	 	 	129	  	
Other	  	 	163	  	 	 	134	  	
	  	 	 	 	 	 	 	 	
Total deferred tax assets	  	 	1,476	  	 	 	1,506	  	
	  	 	 	 	 	 	 	 	
Deferred tax liabilities:	  				 				
Property and equipment	  	 	(5,895	) 	 	 	(4,970	) 	
Long-term debt	  	 	(161	) 	 	 	(198	) 	
Taxes on unremitted foreign earnings	  	 	(157	) 	 	 	(936	) 	
Fair value of financial instruments	  	 	(7	) 	 	 	(141	) 	
Other	  	 	(52	) 	 	 	(76	) 	
	  	 	 	 	 	 	 	 	
Total deferred tax liabilities	  	 	(6,272	) 	 	 	(6,321	) 	
	  	 	 	 	 	 	 	 	
Net deferred tax liability	  	$	(4,796	) 	 	$	(4,815	) 	
	  	 	 	 	 	 	 	 	
Devon has recognized a $248 million deferred tax asset related to foreign tax credit carryforwards which expire between 2019 and 2023. Devon expects the tax benefits from the foreign tax credits to be utilized between 2014 and 2016. Devon also has recognized $183 million of deferred tax assets related to various net operating loss carryforwards available to offset future income taxes. The carryforwards consist of $673 million of Canadian net operating loss carryforwards, which expire between 2028 and 2033, and $197 million of state net operating loss carryforwards, which expire primarily between 2014 and 2032. Devon expects the tax benefits from the Canadian net operating loss carryforwards to be utilized between 2014 and 2017 and the state net operating loss carryforwards to be utilized between 2014 and 2020. Devon has also recognized a $105 million deferred tax asset related to alternative minimum tax credits which have no expiration date and will be available for use against tax on future taxable income.
The expected utilization of Devon’s carryforwards and credits is based upon current estimates of taxable income, considering limitations on the annual utilization of these benefits as set forth by tax regulations. Significant changes in such estimates caused by variables such as future oil, gas and NGL prices or capital expenditures could alter the timing of the eventual utilization of such carryforwards. There can be no assurance that Devon will generate any specific level of continuing taxable earnings. However, management believes that Devon’s future taxable income will more likely than not be sufficient to utilize its tax carryforwards and credits prior to their expiration.
As of December 31, 2013, Devon’s unremitted foreign earnings totaled approximately $4.3 billion. Of this amount, approximately $1.5 billion was deemed to be indefinitely reinvested into the development and growth of Devon’s Canadian business. Therefore, Devon has not recognized a deferred tax liability for United States
 
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
income taxes associated with such earnings. If such earnings were to be repatriated to the U.S., Devon may be subject to United States income taxes and foreign withholding taxes. However, it is not practical to estimate the amount of such additional taxes that may be payable due to the inter-relationship of the various factors involved in making such an estimate.
Devon has deemed the remaining $2.8 billion of unremitted earnings not to be indefinitely reinvested. Consequently, Devon has recognized a $157 million deferred tax liability associated with such unremitted earnings as of December 31, 2013.
Unrecognized Tax Benefits
The following table presents changes in Devon’s unrecognized tax benefits.

 	  	December 31,	 	
 	  	    2013    	 	 	    2012    	 	
 	  	(In millions)	 	
Balance at beginning of year	  	$	216	  	 	$	165	  	
Tax positions taken in prior periods	  	 	(17	) 	 	 	(46	) 	
Tax positions taken in current year	  	 	42	  	 	 	92	  	
Accrual of interest related to tax positions taken	  	 	5	  	 	 	7	  	
Lapse of statute of limitations	  	 	—  	  	 	 	(3	) 	
Foreign currency translation	  	 	(3	) 	 	 	1	  	
	  	 	 	 	 	 	 	 	
Balance at end of year	  	$	243	  	 	$	216	  	
	  	 	 	 	 	 	 	 	
Devon’s unrecognized tax benefit balance at December 31, 2013 and 2012, included $32 million and $27 million, respectively, of interest and penalties. If recognized, $198 million of Devon’s unrecognized tax benefits as of December 31, 2013 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	 	
United States federal	  	 	2008-2013	  	
Various U.S. states	  	 	2008-2013	  	
Canada federal	  	 	2004-2013	  	
Various Canadian provinces	  	 	2004-2013	  	
Certain statute of limitation expirations are scheduled to occur in the next twelve months. However, Devon is currently in various stages of the administrative review process for certain open tax years. In addition, Devon is currently subject to various income tax audits that have not reached the administrative review process. As a result, Devon cannot reasonably anticipate the extent that the liabilities for unrecognized tax benefits will increase or decrease within the next twelve months.
 
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
8.	Earnings Per Share	
The following table reconciles earnings from continuing operations and common shares outstanding used in the calculations of basic and diluted earnings per share.

 	  	Earnings (loss)	 	 	Common
Shares	 	 	Earnings (loss)
per  Share	 	
 	  	(In millions, except per share amounts)	 	
Year Ended December 31, 2013:	  				 				 				
Loss from continuing operations	  	$	(20	) 	 	 	406	  	 				
Attributable to participating securities	  	 	(2	) 	 	 	(4	) 	 				
	  	 	 	 	 	 	 	 	 				
Basic loss per share	  	 	(22	) 	 	 	402	  	 	$	(0.06	) 	
Dilutive effect of potential common shares issuable	  	 	—  	  	 	 	—  	  	 				
	  	 	 	 	 	 	 	 	 				
Diluted loss per share	  	$	(22	) 	 	 	402	  	 	$	(0.06	) 	
	  	 	 	 	 	 	 	 	 				
Year Ended December 31, 2012:	  				 				 				
Loss from continuing operations	  	$	(185	) 	 	 	404	  	 				
Attributable to participating securities	  	 	(3	) 	 	 	(4	) 	 				
	  	 	 	 	 	 	 	 	 				
Basic loss per share	  	 	(188	) 	 	 	400	  	 	$	(0.47	) 	
Dilutive effect of potential common shares issuable	  	 	—  	  	 	 	—  	  	 				
	  	 	 	 	 	 	 	 	 				
Diluted loss per share	  	$	(188	) 	 	 	400	  	 	$	(0.47	) 	
	  	 	 	 	 	 	 	 	 				
Year Ended December 31, 2011:	  				 				 				
Earnings from continuing operations	  	$	2,134	  	 	 	417	  	 				
Attributable to participating securities	  	 	(23	) 	 	 	(5	) 	 				
	  	 	 	 	 	 	 	 	 				
Basic earnings per share	  	 	2,111	  	 	 	412	  	 	$	5.12	  	
Dilutive effect of potential common shares issuable	  	 	—  	 	 	 	2	  	 				
	  	 	 	 	 	 	 	 	 				
Diluted earnings per share	  	$	2,111	  	 	 	414	  	 	$	5.10	  	
	  	 	 	 	 	 	 	 	 				
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 7 million, 9 million and 3 million in 2013, 2012 and 2011, respectively.
 
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
9.	Other Comprehensive Earnings	
Components of other comprehensive earnings consist of the following:

 	  	Year Ended December 31,	 	
 	  	2013	 	 	2012	 	 	2011	 	
 	  	(In millions)	 	
Foreign currency translation:	  				
Beginning accumulated foreign currency translation	  	$	1,996	  	 	$	1,802	  	 	$	1,993	  	
Change in cumulative translation adjustment	  	 	(574	) 	 	 	203	  	 	 	(200	) 	
Income tax benefit (expense)	  	 	26	  	 	 	(9	) 	 	 	9	  	
	  	 	 	 	 	 	 	 	 	 	 	 	
Ending accumulated foreign currency translation	  	 	1,448	  	 	 	1,996	  	 	 	1,802	  	
	  	 	 	 	 	 	 	 	 	 	 	 	
Pension and postretirement benefit plans:	  				 				 				
Beginning accumulated pension and postretirement benefits	  	 	(225	) 	 	 	(227	) 	 	 	(233	) 	
Net actuarial gain (loss) and prior service cost arising in current year	  	 	48	  	 	 	(47	) 	 	 	(21	) 	
Recognition of net actuarial loss and prior service cost in earnings (1)	  	 	24	  	 	 	51	  	 	 	30	  	
Income tax expense	  	 	(27	) 	 	 	(2	) 	 	 	(3	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	
Ending accumulated pension and postretirement benefits	  	 	(180	) 	 	 	(225	) 	 	 	(227	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	
Accumulated other comprehensive earnings, net of tax	  	$	1,268	  	 	$	1,771	  	 	$	1,575	  	

(1)	These accumulated other comprehensive earnings components are included in the computation of net periodic benefit cost, which is a component of general and administrative expenses on the accompanying comprehensive statements of earnings (see “Retirement Plans” note for additional details).	
 
10.	Supplemental Information to Statements of Cash Flows	

 	  	Year Ended December 31,	 	
 	  	2013	 	 	2012	 	 	2011	 	
 	  	(In millions)	 	
Net change in working capital accounts:	  				
Accounts receivable	  	$	(288	) 	 	$	140	  	 	$	(185	) 	
Other current assets	  	 	49	  	 	 	(128	) 	 	 	125	  	
Accounts payable	  	 	26	  	 	 	(8	) 	 	 	64	  	
Revenues and royalties payable	  	 	35	  	 	 	19	  	 	 	144	  	
Other current liabilities	  	 	(120	) 	 	 	(73	) 	 	 	32	  	
	  	 	 	 	 	 	 	 	 	 	 	 	
Net change in working capital	  	$	(298	) 	 	$	(50	) 	 	$	180	  	
	  	 	 	 	 	 	 	 	 	 	 	 	
Interest paid (net of capitalized interest)	  	$	406	  	 	$	334	  	 	$	325	  	
Income taxes paid (received)	  	$	13	  	 	$	100	  	 	$	(383	) 	
 
11.	Short-Term Investments	
The components of short-term investments include the following:

 	  	December 31,
2013	 	  	December  31,
2012	 	
 	  	(In millions)	 	
Canadian treasury, agency and provincial securities	  	$	—  	  	  	$	1,865	  	
United States treasuries	  	 	—  	  	  	 	429	  	
Other	  	 	—  	  	  	 	49	  	
	  	 	 	 	  	 	 	 	
Short-term investments	  	$	—  	  	  	$	2,343	  	

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
12.	Accounts Receivable	
The components of accounts receivable include the following:

 	  	December 31,
2013	 	 	December 31,
2012	 	
 	  	(In millions)	 	
Oil, gas and NGL sales	  	$	851	  	 	$	752	  	
Joint interest billings	  	 	447	  	 	 	270	  	
Marketing and midstream revenues	  	 	172	  	 	 	161	  	
Other	  	 	61	  	 	 	72	  	
	  	 	 	 	 	 	 	 	
Gross accounts receivable	  	 	1,531	  	 	 	1,255	  	
Allowance for doubtful accounts	  	 	(11	) 	 	 	(10	) 	
	  	 	 	 	 	 	 	 	
Net accounts receivable	  	$	1,520	  	 	$	1,245	  	

13.	Acquisitions and Divestitures	
Crosstex Merger
On October 21, 2013, Devon, Crosstex Energy, Inc. and Crosstex Energy, L.P. (collectively “Crosstex”) announced plans to combine substantially all of Devon’s U.S. midstream assets with Crosstex’s assets to form a new midstream business. The new business will consist of EnLink Midstream Partners, L.P. (the “Partnership”) and EnLink Midstream, LLC (“EnLink”), a master limited partnership and a general partner entity, which will both be publicly traded entities.
In exchange for a controlling interest in both EnLink and the Partnership, Devon will contribute its equity interest in a newly formed Devon subsidiary (“EnLink Holdings”) and $100 million in cash. EnLink Holdings will own Devon’s midstream assets in the Barnett Shale in north Texas and the Cana and Arkoma Woodford Shales in Oklahoma, as well as Devon’s economic interest in Gulf Coast Fractionators in Mt. Belvieu, Texas. The Partnership and EnLink will each own 50% of EnLink Holdings. The completion of these transactions is subject to Crosstex Energy, Inc. shareholder approval. Devon expects Crosstex Energy, Inc. shareholders will approve the transaction, allowing Devon and Crosstex to complete the transaction near the end of the first quarter of 2014.
Upon closing of the transactions, the pro forma ownership of EnLink will be approximately:
 
 	•	 	70% – Devon Energy Corporation	
 
 	•	 	30% – Current Crosstex Energy, Inc. public stockholders	
Upon closing of the transactions, the pro forma ownership of the Partnership will be approximately:
 
 	•	 	53% – Devon Energy Corporation	
 
 	•	 	40% – Current Crosstex Energy, L.P. public unitholders	
 
 	•	 	7% – the General Partner	
GeoSouthern Acquisition
On November 20, 2013, Devon entered into an agreement with GeoSouthern Intermediate Holdings, LLC, to acquire certain oil and gas properties, leasehold mineral interests and related assets located in the Eagle Ford Shale in south Texas for $6 billion in cash. The transaction is expected to close in the first quarter of 2014.
 
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
Subsequent Event (unaudited)
In conjunction with the announcement of the GeoSouthern acquisition, Devon also announced plans to divest certain non-core properties located throughout Canada and the U.S. On February 19, 2014, Devon announced its first transaction as part of this divestiture program, in which it agreed to sell the majority of its Canadian conventional assets to Canadian Natural Resources Limited for approximately $2.8 billion ($3.125 billion in Canadian dollars). This transaction is expected to close early in the second quarter of 2014.
 
14.	Debt and Related Expenses	
A summary of Devon’s debt is as follows:

 	  	December 31,	 	
 	  	2013	 	 	2012	 	
 	  	(In millions)	 	
Commercial paper	  	$	1,317	  	 	$	3,189	  	
Other debentures and notes:	  				 				
5.625% due January 15, 2014	  	 	500	  	 	 	500	  	
Floating rate due December 15, 2015	  	 	500	  	 	 	—  	  	
2.40% due July 15, 2016	  	 	500	  	 	 	500	  	
Floating rate due December 15, 2016	  	 	350	  	 	 	—  	  	
1.20% due December 15, 2016	  	 	650	  	 	 	—  	  	
1.875% due May 15, 2017	  	 	750	  	 	 	750	  	
8.25% due July 1, 2018	  	 	125	  	 	 	125	  	
2.25% due December 15, 2018	  	 	750	  	 	 	—  	  	
6.30% due January 15, 2019	  	 	700	  	 	 	700	  	
4.00% due July 15, 2021	  	 	500	  	 	 	500	  	
3.25% due May 15, 2022	  	 	1,000	  	 	 	1,000	  	
7.50% due September 15, 2027	  	 	150	  	 	 	150	  	
7.875% due September 30, 2031	  	 	1,250	  	 	 	1,250	  	
7.95% due April 15, 2032	  	 	1,000	  	 	 	1,000	  	
5.60% due July 15, 2041	  	 	1,250	  	 	 	1,250	  	
4.75% due May 15, 2042	  	 	750	  	 	 	750	  	
Net discount on debentures and notes	  	 	(20	) 	 	 	(20	) 	
	  	 	 	 	 	 	 	 	
Total debt	  	 	12,022	  	 	 	11,644	  	
Less amount classified as short-term debt (1)	  	 	4,066	  	 	 	3,189	  	
	  	 	 	 	 	 	 	 	
Long-term debt	  	$	7,956	  	 	$	8,455	  	

(1)	2013 short-term debt consists of $2.25 billion of senior notes recently issued in conjunction with the planned GeoSouthern acquisition, $1.3 billion of commercial paper and $500 million of senior notes due January 15, 2014.	
 
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
Debt maturities as of December 31, 2013, excluding premiums and discounts, are as follows (in millions):

2014	  	$	4,067	  	
2015	  	 	—  	  	
2016	  	 	500	  	
2017	  	 	750	  	
2018	  	 	125	  	
2019 and thereafter	  	 	6,600	  	
	  	 	 	 	
Total	  	$	12,042	  	
	  	 	 	 	
Credit Lines
Devon has a $3.0 billion syndicated, unsecured revolving line of credit (the “Senior Credit Facility”) that matures on October 24, 2018. However, prior to the maturity date, Devon has the option to extend the maturity for up to one additional one-year period, subject to the approval of the lenders.
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 $3.8 million that is payable quarterly in arrears. As of December 31, 2013, there were no borrowings under the Senior Credit Facility.
The Senior Credit Facility contains only one material financial covenant. This covenant requires Devon’s ratio of total funded debt to total capitalization, as defined in the credit agreement, to be no greater than 65 percent. The credit agreement contains definitions of total funded debt and total capitalization that include adjustments to the respective amounts reported in the accompanying financial statements. Also, total capitalization is adjusted to add back noncash financial write-downs such as full cost ceiling impairments or goodwill impairments. As of December 31, 2013, Devon was in compliance with this covenant with a debt-to-capitalization ratio of 25.7 percent.
Commercial Paper
Devon has access to $3.0 billion of short-term credit under its commercial paper program. Commercial paper debt generally has a maturity of between 1 and 90 days, although it can have a maturity of up to 365 days, and bears interest at rates agreed to at the time of the borrowing. The interest rate is generally based on a standard index such as the Federal Funds Rate, LIBOR, or the money market rate as found in the commercial paper market. As of December 31, 2013, Devon’s weighted average borrowing rate on its commercial paper borrowings was 0.30 percent.
Other Debentures and Notes
Following are descriptions of the various other debentures and notes outstanding at December 31, 2013, as listed in the table presented at the beginning of this note.
GeoSouthern Debt
In December 2013, in conjunction with the planned GeoSouthern acquisition, Devon issued $2.25 billion aggregate principal amount of fixed and floating rate senior notes resulting in cash proceeds of approximately
 
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
$2.2 billion, net of discounts and issuance costs. The floating rate senior notes due in 2015 bear interest at a rate equal to three-month LIBOR plus 0.45 percent, which rate will be reset quarterly. The floating rate senior notes due in 2016 bears interest at a rate equal to three-month LIBOR plus 0.54 percent, which rate will be reset quarterly. The schedule below summarizes the key terms of these notes ($ in millions).

Floating rate due December 15, 2015	  	$	500	  	
Floating rate due December 15, 2016	  	 	350	  	
1.20% due December 15, 2016	  	 	650	  	
2.25% due December 15, 2018	  	 	750	  	
Discount and issuance costs	  	 	(2	) 	
	  	 	 	 	
Net proceeds	  	$	2,248	  	
	  	 	 	 	
In the event that GeoSouthern acquisition is not completed on or prior to June 30, 2014, Devon is required to redeem each series of new senior notes at 101% of the aggregate principal amount of such series, plus accrued and unpaid interest. Due to the redemption features, these senior notes were classified as short-term debt on Devon’s consolidated balance sheet as of December 31, 2013 and will be reclassified as long-term debt once the acquisition is completed.
Additionally, during December 2013, Devon entered into a term loan agreement with a group of major financial institutions pursuant to which Devon may draw up to $2.0 billion to finance, in part, the GeoSouthern acquisition and to pay transaction costs. Half of any loans under the term loan agreement will have a maturity of three years and the other half will have a maturity of five years (the “5-Year Loans”). The 5-Year Loans will provide for the partial amortization of principal during the last two years that they are outstanding. Loans borrowed under the term loan agreement may, at the election of Devon, bear interest at various fixed rate options for periods up to six months. Such rates are generally less than the prime rate. However, Devon may elect to borrow at the prime rate. There were no borrowings under the term loan agreement as of December 31, 2013.
Other Notes
In 2012, 2011, 2009 and 2002 Devon issued senior notes that are unsecured and unsubordinated obligations of Devon. Devon used the net proceeds to repay outstanding commercial paper and credit facility borrowings. The schedule below summarizes the key terms of these notes ($ in millions).

 	  	Date Issued	 	
 	  	May 2012	 	 	July 2011	 	 	January 2009	 	 	March 2002	 	
1.875% due May 15, 2017	  	$	750	  	 	$	—  	  	 	$	—  	  	 	$	—  	  	
3.25% due May 15, 2022	  	 	1,000	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	
4.75% due May 15, 2042	  	 	750	  	 	 	—  	  	 	 	—  	  	 	 	—  	  	
2.40% due July 15, 2016	  	 	—  	  	 	 	500	  	 	 	—  	  	 	 	—  	  	
4.00% due July 15, 2021	  	 	—  	  	 	 	500	  	 	 	—  	  	 	 	—  	  	
5.60% due July 15, 2041	  	 	—  	  	 	 	1,250	  	 	 	—  	  	 	 	—  	  	
5.625% due January 15, 2014	  	 	—  	  	 	 	—  	  	 	 	500	  	 	 	—  	  	
6.30% due January 15, 2019	  	 	—  	  	 	 	—  	  	 	 	700	  	 	 	—  	  	
7.95% due April 15, 2032	  	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	1,000	  	
Discount and issuance costs	  	 	(35	) 	 	 	(29	) 	 	 	(13	) 	 	 	(14	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net proceeds	  	$	2,465	  	 	$	2,221	  	 	$	1,187	  	 	$	986	  	

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
Ocean Debt
On April 25, 2003, Devon merged with Ocean Energy, Inc. and assumed certain debt instruments. The table below summarizes the debt assumed that remains outstanding as of December 31, 2013, including the fair value of the debt at April 25, 2003, and the effective interest rate of the debt after determining the fair values using April 25, 2003, market interest rates. The premiums resulting from fair values exceeding face values are being amortized using the effective interest method. Both notes are general unsecured obligations of Devon.

Debt Assumed	  	Fair Value of
Debt Assumed	 	  	Effective Rate of
Debt Assumed	 	
	  	(In millions)	 	  	 	 	
8.250% due July 2018 (principal of $125 million)	  	$	147	  	  	 	5.5	% 	
7.500% due September 2027 (principal of $150 million)	  	$	169	  	  	 	6.5	% 	
7.875% Debentures due September 30, 2031
In October 2001, Devon, through Devon Financing Corporation, U.L.C. (“Devon Financing”), a wholly owned finance subsidiary, sold debentures, which are unsecured and unsubordinated obligations of Devon Financing. Devon has fully and unconditionally guaranteed on an unsecured and unsubordinated basis the obligations of Devon Financing under the debt securities. The proceeds were used to fund a portion of the acquisition of Anderson Exploration.
Net financing costs
The following schedule includes the components of net financing costs.

 	  	Year Ended December 31,	 	
 	  	2013	 	 	2012	 	 	2011	 	
 	  	(In millions)	 	
Interest based on debt outstanding	  	$	466	  	 	$	440	  	 	$	414	  	
Capitalized interest	  	 	(56	) 	 	 	(48	) 	 	 	(72	) 	
Other fees and expenses	  	 	27	  	 	 	14	  	 	 	10	  	
	  	 	 	 	 	 	 	 	 	 	 	 	
Interest expense	  	 	437	  	 	 	406	  	 	 	352	  	
Interest income	  	 	(20	) 	 	 	(36	) 	 	 	(21	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	
Net financing costs	  	$	417	  	 	$	370	  	 	$	331	  	

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
15.	Asset Retirement Obligations	
The schedule below summarizes changes in Devon’s asset retirement obligations.

 	  	      Year Ended December 31,       	 	
 	  	2013	 	 	2012	 	
 	  	(In millions)	 	
Asset retirement obligations as of beginning of period	  	$	2,095	  	 	$	1,563	  	
Liabilities incurred	  	 	112	  	 	 	90	  	
Liabilities settled	  	 	(83	) 	 	 	(86	) 	
Revision of estimated obligation	  	 	104	  	 	 	420	  	
Liabilities assumed by others	  	 	(28	) 	 	 	(23	) 	
Accretion expense on discounted obligation	  	 	115	  	 	 	110	  	
Foreign currency translation adjustment	  	 	(87	) 	 	 	21	  	
	  	 	 	 	 	 	 	 	
Asset retirement obligations as of end of period	  	 	2,228	  	 	 	2,095	  	
Less current portion	  	 	88	  	 	 	99	  	
	  	 	 	 	 	 	 	 	
Asset retirement obligations, long-term	  	$	2,140	  	 	$	1,996	  	
	  	 	 	 	 	 	 	 	
During 2012, Devon recognized revisions to its asset retirement obligations totaling $420 million. The primary factor contributing to this revision was an overall increase in abandonment cost estimates for certain of its production operations facilities.
 
16.	Retirement Plans	
Devon has various non-contributory defined benefit pension plans, including qualified plans and nonqualified plans. The qualified plans provide retirement benefits for certain U.S. and Canadian employees meeting certain age and service requirements. Benefits for the qualified plans are based on the employees’ years of service and compensation and are funded from assets held in the plans’ trusts.
The nonqualified plans provide retirement benefits for certain employees whose benefits under the qualified plans are limited by income tax regulations. The nonqualified plans’ benefits are based on the employees’ years of service and compensation. For certain nonqualified plans, Devon has established trusts to fund these plans’ benefit obligations. The total value of these trusts was $27 million and $31 million at December 31, 2013 and 2012, respectively, and is included in other long-term assets in the accompanying balance sheets. For the remaining nonqualified plans for which trusts have not been established, benefits are funded from Devon’s available cash and cash equivalents.
Devon also has defined benefit postretirement plans that provide benefits for substantially all U.S. employees. The plans provide medical and, in some cases, life insurance benefits and are either contributory or non-contributory, depending on the type of plan. Benefit obligations for such plans are estimated based on Devon’s future cost-sharing intentions. Devon’s funding policy for the plans is to fund the benefits as they become payable with available cash and cash equivalents.
 
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
Benefit Obligations and Funded Status
The following table presents the funded status of Devon’s qualified and nonqualified pension and 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 was $1.1 billion and $1.2 billion at December 31, 2013 and 2012, respectively. Devon’s benefit obligations and plan assets are measured each year as of December 31. Devon’s 2012 plan settlements relate to a plan amendment which removed a dollar cap on lump sum payments and revised optional forms of payment to include a lump sum distribution feature. The projected benefit obligation for Devon’s qualified plans was fully funded as of December 31, 2013 and 2012.

 	  	Pension Benefits	 	 	Postretirement Benefits	 	
 	  	2013	 	 	2012	 	 	    2013    	 	 	    2012    	 	
 	  	(In millions)	 	
Change in benefit obligation:	  				 				 				 				
Benefit obligation at beginning of year	  	$	1,360	  	 	$	1,303	  	 	$	34	  	 	$	37	  	
Service cost	  	 	36	  	 	 	43	  	 	 	1	  	 	 	1	  	
Interest cost	  	 	51	  	 	 	60	  	 	 	1	  	 	 	1	  	
Actuarial loss (gain)	  	 	(158	) 	 	 	95	  	 	 	(3	) 	 	 	(4	) 	
Plan amendments	  	 	2	  	 	 	14	  	 	 	(8	) 	 	 	—  	  	
Plan curtailments	  	 	—  	  	 	 	(20	) 	 	 	—  	  	 	 	1	  	
Plan settlements	  	 	—  	  	 	 	(93	) 	 	 	—  	  	 	 	—  	  	
Foreign exchange rate changes	  	 	(2	) 	 	 	1	  	 	 	—  	  	 	 	—  	  	
Participant contributions	  	 	—  	  	 	 	—  	  	 	 	3	  	 	 	3	  	
Benefits paid	  	 	(112	) 	 	 	(43	) 	 	 	(4	) 	 	 	(5	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Benefit obligation at end of year	  	 	1,177	  	 	 	1,360	  	 	 	24	  	 	 	34	  	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Change in plan assets:	  				 				 				 				
Fair value of plan assets at beginning of year	  	 	1,165	  	 	 	1,187	  	 	 	—  	  	 	 	—  	  	
Actual return on plan assets	  	 	(57	) 	 	 	102	  	 	 	—  	  	 	 	—  	  	
Employer contributions	  	 	11	  	 	 	11	  	 	 	1	  	 	 	2	  	
Participant contributions	  	 	—  	  	 	 	—  	  	 	 	3	  	 	 	3	  	
Plan settlements	  	 	—  	  	 	 	(93	) 	 	 	—  	  	 	 	—  	  	
Benefits paid	  	 	(112	) 	 	 	(43	) 	 	 	(4	) 	 	 	(5	) 	
Foreign exchange rate changes	  	 	(1	) 	 	 	1	  	 	 	—  	  	 	 	—  	  	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Fair value of plan assets at end of year	  	 	1,006	  	 	 	1,165	  	 	 	—  	  	 	 	—  	  	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Funded status at end of year	  	$	(171	) 	 	$	(195	) 	 	$	(24	) 	 	$	(34	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Amounts recognized in balance sheet:	  				 				 				 				
Noncurrent assets	  	$	47	  	 	$	62	  	 	$	—  	  	 	$	—  	  	
Current liabilities	  	 	(12	) 	 	 	(12	) 	 	 	(3	) 	 	 	(3	) 	
Noncurrent liabilities	  	 	(206	) 	 	 	(245	) 	 	 	(21	) 	 	 	(31	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net amount	  	$	(171	) 	 	$	(195	) 	 	$	(24	) 	 	$	(34	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Amounts recognized in accumulated other comprehensive earnings:	  				 				 				 				
Net actuarial loss (gain)	  	$	279	  	 	$	340	  	 	$	(13	) 	 	$	(11	) 	
Prior service cost (credit)	  	 	23	  	 	 	25	  	 	 	(11	) 	 	 	(4	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	  	$	302	  	 	$	365	  	 	$	(24	) 	 	$	(15	) 	

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
The plan assets for pension benefits in the table above exclude the assets held in trusts for the nonqualified plans. However, employer contributions for pension benefits in the table above include $11 million and $10 million for 2013 and 2012, respectively, which were transferred from the trusts established for the nonqualified plans.
Certain of Devon’s pension plans have a projected benefit obligation and accumulated benefit obligation in excess of plan assets at December 31, 2013 and 2012 as presented in the table below.

 	  	December 31,	 	
 	  	2013	 	  	2012	 	
 	  	(In millions)	 	
Projected benefit obligation	  	$	218	  	  	$	257	  	
Accumulated benefit obligation	  	$	179	  	  	$	216	  	
Fair value of plan assets	  	$	—  	  	  	$	—  	  	
Net Periodic Benefit Cost and Other Comprehensive Earnings
The following table presents the components of net periodic benefit cost and other comprehensive earnings.

 	  	Pension Benefits	 	 	Postretirement
Benefits	 	
 	  	2013	 	 	2012	 	 	2011	 	 	2013	 	 	2012	 	 	2011	 	
 	  	(In millions)	 	
Net periodic benefit cost:	  				 				 				 				 				 				
Service cost	  	$	36	  	 	$	43	  	 	$	37	  	 	$	1	  	 	$	1	  	 	$	1	  	
Interest cost	  	 	51	  	 	 	60	  	 	 	60	  	 	 	1	  	 	 	1	  	 	 	2	  	
Expected return on plan assets	  	 	(62	) 	 	 	(64	) 	 	 	(42	) 	 	 	—  	  	 	 	—  	  	 	 	—  	  	
Curtailment and settlement expense	  	 	—  	  	 	 	26	  	 	 	—  	  	 	 	—  	  	 	 	1	  	 	 	(3	) 	
Recognition of net actuarial loss (gain) (1)	  	 	22	  	 	 	24	  	 	 	32	  	 	 	(1	) 	 	 	(1	) 	 	 	—  	  	
Recognition of prior service cost (1)	  	 	4	  	 	 	3	  	 	 	3	  	 	 	(1	) 	 	 	(1	) 	 	 	(2	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total net periodic benefit cost (2)	  	 	51	  	 	 	92	  	 	 	90	  	 	 	—  	  	 	 	1	  	 	 	(2	) 	
Other comprehensive loss (earnings):	  				 				 				 				 				 				
Actuarial loss (gain) arising in current year	  	 	(39	) 	 	 	37	  	 	 	23	  	 	 	(3	) 	 	 	(4	) 	 	 	(7	) 	
Prior service cost (credit) arising in current year	  	 	2	  	 	 	14	  	 	 	—  	  	 	 	(8	) 	 	 	—  	  	 	 	5	  	
Recognition of net actuarial loss, including settlement expense, in net periodic benefit cost	  	 	(22	) 	 	 	(45	) 	 	 	(32	) 	 	 	1	  	 	 	1	  	 	 	3	  	
Recognition of prior service cost, including curtailment, in net periodic benefit cost	  	 	(4	) 	 	 	(8	) 	 	 	(3	) 	 	 	1	  	 	 	1	  	 	 	2	  	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total other comprehensive loss (earnings)	  	 	(63	) 	 	 	(2	) 	 	 	(12	) 	 	 	(9	) 	 	 	(2	) 	 	 	3	  	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total recognized	  	$	(12	) 	 	$	90	  	 	$	78	  	 	$	(9	) 	 	$	(1	) 	 	$	1	  	

(1)	These net periodic benefit costs were reclassified out of other comprehensive earnings in the current period.	
(2)	Net periodic benefit cost is a component of general and administrative expenses on the accompanying comprehensive statements of earnings.	
 
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
The following table presents the estimated net actuarial loss and prior service cost that will be amortized from accumulated other comprehensive earnings into net periodic benefit cost during 2014.

 	  	Pension
Benefits	 	  	Postretirement
Benefits	 	
 	  	(In millions)	 	
Net actuarial loss (gain)	  	$	18	  	  	$	(1	) 	
Prior service cost (credit)	  	 	4	  	  	 	(1	) 	
	  	 	 	 	  	 	 	 	
Total	  	$	22	  	  	$	(2	) 	
	  	 	 	 	  	 	 	 	
Assumptions
The following table presents the weighted average actuarial assumptions used to determine obligations and periodic costs.

 	  	Pension Benefits	 	 	Postretirement Benefits	 	
 	  	2013	 	 	2012	 	 	2011	 	 	2013	 	 	2012	 	 	2011	 	
Assumptions to determine benefit obligations:	  				 				 				 				 				 				
Discount rate	  	 	4.80	% 	 	 	3.85	% 	 	 	4.65	% 	 	 	3.65	% 	 	 	3.30	% 	 	 	4.25	% 	
Rate of compensation increase	  	 	4.48	% 	 	 	4.48	% 	 	 	4.97	% 	 	 	N/A	  	 	 	N/A	  	 	 	N/A	  	
Assumptions to determine net periodic benefit cost:	  				 				 				 				 				 				
Discount rate	  	 	3.85	% 	 	 	4.65	% 	 	 	5.50	% 	 	 	3.30	% 	 	 	4.25	% 	 	 	4.90	% 	
Expected return on plan assets	  	 	5.48	% 	 	 	5.48	% 	 	 	6.48	% 	 	 	N/A	  	 	 	N/A	  	 	 	N/A	  	
Rate of compensation increase	  	 	4.48	% 	 	 	4.97	% 	 	 	6.94	% 	 	 	N/A	  	 	 	N/A	  	 	 	N/A	  	
Discount rate – Future pension and postretirement obligations are discounted at the end of each year based on the rate at which obligations could be effectively settled, considering the timing of estimated future cash flows related to the plans. This rate is based on high-quality bond yields, after allowing for call and default risk.
Rate of compensation increase – For measurement of the 2013 benefit obligation for the pension plans, a 4.48 percent compensation increase was assumed.
Expected return on plan assets – The expected rate of return on plan assets was determined by evaluating input from external consultants and economists, as well as long-term inflation assumptions. Devon expects the long-term asset allocation to approximate the targeted allocation. Therefore, the expected long-term rate of return on plan assets is based on the target allocation of investment types. See the pension plan assets section below for more information on Devon’s target allocations.
Other assumptions – For measurement of the 2013 benefit obligation for the other postretirement medical plans, a 7.9 percent annual rate of increase in the per capita cost of covered health care benefits was assumed for 2014. The rate was assumed to decrease annually to an ultimate rate of 5 percent in the year 2029 and remain at that level thereafter. Assumed health care cost-trend rates affect the amounts reported for retiree health care costs. A one-percentage-point change in the assumed health care cost-trend rates would have changed the postretirement benefits obligation as of December 31, 2013, by less than $1 million and would change the 2014 service and interest cost components of net periodic benefit cost by less than $1 million.
 
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
Pension Plan Assets
Devon’s overall investment objective for its pension plans’ assets is to achieve stability of the plans’ funded status while providing long-term growth of invested capital and income to ensure benefit payments can be funded when required. To assist in achieving this objective, Devon has established certain investment strategies, including target allocation percentages and permitted and prohibited investments, designed to mitigate risks inherent with investing. Derivatives or other speculative investments considered high risk are generally prohibited. The following table presents Devon’s target allocation for its pension plan assets.

 	  	December 31,	 	
 	  	    2013    	 	 	    2012    	 	
Fixed income	  	 	70	% 	 	 	70	% 	
Equity	  	 	20	% 	 	 	20	% 	
Other	  	 	10	% 	 	 	10	% 	
The fair values of Devon’s pension assets are presented by asset class in the following tables.

 	  	As of December 31, 2013	 	
 	  	 	 	 	 	 	  	Fair Value Measurements Using:	 	
 	  	Actual
Allocation	 	 	Total	 	  	Level 1
Inputs	 	  	Level 2
Inputs	 	  	Level 3
Inputs	 	
 	  	(In millions)	 	
Fixed-income securities:	  				 				  				  				  				
U.S. Treasury obligations	  	 	24.0	% 	 	$	241	  	  	$	69	  	  	$	172	  	  	$	—  	  	
Corporate bonds	  	 	39.5	% 	 	 	398	  	  	 	286	  	  	 	112	  	  	 	—  	  	
Other bonds	  	 	3.1	% 	 	 	31	  	  	 	31	  	  	 	—  	  	  	 	—  	  	
	  	 	 	 	 	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total fixed-income securities	  	 	66.6	% 	 	 	670	  	  	 	386	  	  	 	284	  	  	 	—  	  	
	  	 	 	 	 	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Equity securities:	  				 				  				  				  				
Global (large, mid, small cap)	  	 	19.0	% 	 	 	190	  	  	 	—  	  	  	 	190	  	  	 	—  	  	
	  	 	 	 	 	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Other securities:	  				 				  				  				  				
Hedge fund & alternative investments	  	 	12.5	% 	 	 	127	  	  	 	15	  	  	 	—  	  	  	 	112	  	
Short-term investment funds	  	 	1.9	% 	 	 	19	  	  	 	—  	  	  	 	19	  	  	 	—  	  	
	  	 	 	 	 	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total other securities	  	 	14.4	% 	 	 	146	  	  	 	15	  	  	 	19	  	  	 	112	  	
	  	 	 	 	 	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total investments	  	 	100.0	% 	 	$	1,006	  	  	$	401	  	  	$	493	  	  	$	112	  	

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

 	  	As of December 31, 2012	 	
 	  	 	 	 	 	 	  	Fair Value Measurements Using:	 	
 	  	Actual
Allocation	 	 	Total	 	  	Level 1
Inputs	 	  	Level 2
Inputs	 	  	Level 3
Inputs	 	
 	  	(In millions)	 	
Fixed-income securities:	  				 				  				  				  				
U.S. Treasury obligations	  	 	39.4	% 	 	$	459	  	  	$	65	  	  	$	394	  	  	$	—  	  	
Corporate bonds	  	 	26.5	% 	 	 	308	  	  	 	256	  	  	 	52	  	  	 	—  	  	
Other bonds	  	 	2.4	% 	 	 	28	  	  	 	28	  	  	 	—  	  	  	 	—  	  	
	  	 	 	 	 	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total fixed-income securities	  	 	68.3	% 	 	 	795	  	  	 	349	  	  	 	446	  	  	 	—  	  	
	  	 	 	 	 	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Equity securities:	  				 				  				  				  				
Global (large, mid, small cap)	  	 	20.5	% 	 	 	239	  	  	 	—  	  	  	 	239	  	  	 	—  	  	
	  	 	 	 	 	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Other securities:	  				 				  				  				  				
Hedge fund & alternative investments	  	 	10.3	% 	 	 	120	  	  	 	17	  	  	 	—  	  	  	 	103	  	
Short-term investment funds	  	 	0.9	% 	 	 	11	  	  	 	—  	  	  	 	11	  	  	 	—  	  	
	  	 	 	 	 	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total other securities	  	 	11.2	% 	 	 	131	  	  	 	17	  	  	 	11	  	  	 	103	  	
	  	 	 	 	 	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total investments	  	 	100.0	% 	 	$	1,165	  	  	$	366	  	  	$	696	  	  	$	103	  	
	  	 	 	 	 	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
The following methods and assumptions were used to estimate the fair values in the tables above.
Fixed-income securities – Devon’s fixed-income securities consist of United States Treasury obligations, bonds issued by investment-grade companies from diverse industries, and asset-backed securities. These fixed-income securities are actively traded securities that can be redeemed upon demand. The fair values of these Level 1 securities are based upon quoted market prices.
Devon’s fixed income securities also include commingled funds that primarily invest in long-term bonds and United States Treasury securities. These fixed income securities can be redeemed on demand but are not actively traded. The fair values of these Level 2 securities are based upon the net asset values provided by the investment managers.
Equity securities – Devon’s equity securities include a commingled global equity fund that invests in large, mid and small capitalization stocks across the world’s developed and emerging markets. These equity securities can be redeemed on demand but are not actively traded. The fair values of these Level 2 securities are based upon the net asset values provided by the investment managers.
Other securities – Devon’s other securities include commingled, short-term investment funds. These securities can be redeemed on demand but are not actively traded. The fair values of these Level 2 securities are based upon the net asset values provided by investment managers.
Devon’s hedge fund and alternative investments include an investment in an actively traded global mutual fund that focuses on alternative investment strategies and a hedge fund of funds that invests both long and short using a variety of investment strategies. Devon’s hedge fund of funds is not actively traded and Devon is subject to redemption restrictions with regards to this investment. The fair value of this Level 3 investment represents the fair value as determined by the hedge fund manager.
 
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
Included below is a summary of the changes in Devon’s Level 3 plan assets (in millions).

December 31, 2011	  	$	90	  	
Purchases	  	 	6	  	
Investment returns	  	 	7	  	
	  	 	 	 	
December 31, 2012	  	 	103	  	
Purchases	  	 	—  	  	
Investment returns	  	 	9	  	
	  	 	 	 	
December 31, 2013	  	$	112	  	
	  	 	 	 	
Expected Cash Flows
The following table presents expected cash flow information for Devon’s pension and postretirement benefit plans.

 	  	Pension
Benefits	 	  	Postretirement
Benefits	 	
 	  	(In millions)	 	
Devon’s 2014 contributions	  	$	12	  	  	$	3	  	
Benefit payments:	  				  				
2014	  	$	71	  	  	$	3	  	
2015	  	$	74	  	  	$	3	  	
2016	  	$	75	  	  	$	3	  	
2017	  	$	78	  	  	$	3	  	
2018	  	$	81	  	  	$	3	  	
2019 to 2023	  	$	450	  	  	$	9	  	
Expected contributions included in the table above include amounts related to Devon’s qualified plans, nonqualified plans and postretirement plans. Of the benefits expected to be paid in 2014, the $12 million of pension benefits is expected to be funded from the trusts established for the nonqualified plans and the $3 million of postretirement benefits is expected to be funded from Devon’s available cash and cash equivalents. Expected employer contributions and benefit payments for other postretirement benefits are presented net of employee contributions.
Defined Contribution Plans
Devon maintains several defined contribution plans covering its employees in the U.S. and Canada. Such plans include Devon’s 401(k) plan, enhanced contribution plan and Canadian pension and savings plan. Contributions are primarily based upon percentages of annual compensation and years of service. In addition, each plan is subject to regulatory limitations by each respective government. The following table presents Devon’s expense related to these defined contribution plans.

 	  	Year Ended December 31,	 	
 	  	2013	 	  	2012	 	  	2011	 	
 	  	(In millions)	 	
401(k) and enhanced contribution plans	  	$	41	  	  	$	36	  	  	$	33	  	
Canadian pension and savings plans	  	 	26	  	  	 	23	  	  	 	21	  	
	  	 	 	 	  	 	 	 	  	 	 	 	
Total	  	$	67	  	  	$	59	  	  	$	54	  	

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
17.	Stockholders’ Equity	
The authorized capital stock of Devon consists of 1 billion shares of common stock, par value $0.10 per share, and 4.5 million shares of preferred stock, par value $1.00 per share. The preferred stock may be issued in one or more series, and the terms and rights of such stock will be determined by the Board of Directors.
Devon’s Board of Directors has designated 2.9 million shares of the preferred stock as Series A Junior Participating Preferred Stock (the “Series A Junior Preferred Stock”). At December 31, 2013, there were no shares of Series A Junior Preferred Stock issued or outstanding. The Series A Junior Preferred Stock is entitled to receive cumulative quarterly dividends per share equal to the greater of $1.00 or 100 times the aggregate per share amount of all dividends (other than stock dividends) declared on common stock since the immediately preceding quarterly dividend payment date or, with respect to the first payment date, since the first issuance of Series A Junior Preferred Stock. Holders of the Series A Junior Preferred Stock are entitled to 100 votes per share on all matters submitted to a vote of the stockholders. Devon, at its option, may redeem shares of the Series A Junior Participating Preferred Stock in whole at any time and in part from time to time, at a redemption price equal to 100 times the current per share market price of Devon’s common stock on the date of the mailing of the notice of redemption. The Series A Junior Preferred Stock ranks prior to the common stock but junior to all other classes of Preferred Stock.
Stock Repurchases
In the fourth quarter of 2011, Devon completed its 2010 repurchase program. In total, Devon repurchased 49.2 million shares for $3.5 billion, or $71.18 per share.
Dividends
Devon paid common stock dividends of $348 million, $324 million and $278 million in 2013, 2012 and 2011 respectively. The quarterly cash dividend was $0.16 per share in the first quarter of 2011. Devon increased the dividend rate to $0.17 per share in the second quarter of 2011 and further increased the dividend rate to $0.20 per share in the first quarter of 2012. Devon increased the dividend rate to $0.22 per share in the second quarter of 2013.
 
18.	Commitments and Contingencies	
Devon is party to various legal actions arising in the normal course of business. Matters that are probable of unfavorable outcome to Devon and which can be reasonably estimated are accrued. Such accruals are based on information known about the matters, Devon’s estimates of the outcomes of such matters and its experience in contesting, litigating and settling similar matters. None of the actions are believed by management to involve future amounts that would be material to Devon’s financial position or results of operations after consideration of recorded accruals. Actual amounts could differ materially from management’s estimates.
Royalty Matters
Numerous natural gas producers and related parties, including Devon, have been named in various lawsuits alleging royalty underpayments. The suits allege that the producers and related parties used below-market prices, made improper deductions, used improper measurement techniques and entered into gas purchase and processing arrangements with affiliates that resulted in underpayment of royalties in connection with natural gas and NGLs produced and sold. Devon’s largest exposure for such matters relates to royalties in New Mexico. Devon does not currently believe that it is subject to material exposure with respect to such royalty matters.
 
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
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 remediation costs. Devon’s monetary exposure for environmental matters is not expected to be material.
Other Matters
Devon is involved in other various routine legal proceedings incidental to its business. However, to Devon’s knowledge, there were no other material pending legal proceedings to which Devon is a party or to which any of its property is subject.
Commitments
The following is a schedule by year of Devon’s commitments that have initial or remaining noncancelable terms in excess of one year as of December 31, 2013.

Year Ending December 31,	  	Purchase
Obligations	 	  	Drilling
and
Facility
Obligations	 	  	Operational
Agreements	 	  	Office and
Equipment
Leases	 	
 	  	(In millions)	 	
2014	  	$	852	  	  	$	341	  	  	$	519	  	  	$	41	  	
2015	  	 	874	  	  	 	18	  	  	 	477	  	  	 	38	  	
2016	  	 	945	  	  	 	7	  	  	 	399	  	  	 	34	  	
2017	  	 	871	  	  	 	—  	  	  	 	388	  	  	 	33	  	
2018	  	 	885	  	  	 	—  	  	  	 	335	  	  	 	28	  	
Thereafter	  	 	1,998	  	  	 	—  	  	  	 	1,331	  	  	 	111	  	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total	  	$	6,425	  	  	$	366	  	  	$	3,449	  	  	$	285	  	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Purchase obligation amounts represent contractual commitments primarily to purchase condensate at market prices for use at Devon’s heavy oil projects in Canada. Devon has entered into these agreements because condensate is an integral part of the heavy oil transportation process. Any disruption in Devon’s ability to obtain condensate could negatively affect its ability to transport heavy oil at these locations. Devon’s total obligation related to condensate purchases expires in 2021. The value of the obligation in the table above is based on the contractual volumes and Devon’s internal estimate of future condensate market prices.
Devon has certain drilling and facility obligations under contractual agreements with third-party service providers to procure drilling rigs and other related services for developmental and exploratory drilling and facilities construction.
Devon has certain operational agreements whereby Devon has committed to transport or process certain volumes of oil, gas and NGLs for a fixed fee. Devon has entered into these agreements to aid the movement of its production to downstream markets.
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 $26 million, $42 million and $42 million in 2013, 2012 and 2011, respectively.
 
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
19.	Fair Value Measurements	
The following tables provide carrying value and fair value measurement information for certain of Devon’s financial assets and liabilities. The carrying values of cash, accounts receivable, other current receivables, accounts payable, other payables and accrued expenses included in the accompanying balance sheets approximated fair value at December 31, 2013 and December 31, 2012. Therefore, such financial assets and liabilities are not presented in the following tables. Additionally, information regarding the fair values of Devon’s midstream and pension plan assets is provided in Note 4 and Note 16, respectively.

 	  	 	 	 	 	 	 	Fair Value Measurements Using:	 	
 	  	Carrying
Amount	 	 	Total Fair
Value	 	 	  Level 1  
Inputs	 	  	  Level 2  
Inputs	 	 	  Level 3  
Inputs	 	
 	  	(In millions)	 	
December 31, 2013 assets (liabilities):	  				 				 				  				 				
Cash equivalents	  	$	5,305	  	 	$	5,305	  	 	$	4,191	  	  	$	1,114	  	 	$	—  	  	
Long-term investments	  	$	62	  	 	$	62	  	 	$	—  	  	  	$	—  	  	 	$	62	  	
Commodity derivatives	  	$	103	  	 	$	103	  	 	$	—  	  	  	$	103	  	 	$	—  	  	
Commodity derivatives	  	$	(120	) 	 	$	(120	) 	 	$	—  	  	  	$	(120	) 	 	$	—  	  	
Foreign currency derivatives	  	$	(1	) 	 	$	(1	) 	 	$	—  	  	  	$	(1	) 	 	$	—  	  	
Debt	  	$	(12,022	) 	 	$	(12,908	) 	 	$	—  	  	  	$	(12,908	) 	 	$	—  	  	
						
December 31, 2012 assets (liabilities):	  				 				 				  				 				
Cash equivalents	  	$	4,149	  	 	$	4,149	  	 	$	32	  	  	$	4,117	  	 	$	—  	  	
Short-term investments	  	$	2,343	  	 	$	2,343	  	 	$	429	  	  	$	1,914	  	 	$	—  	  	
Long-term investments	  	$	64	  	 	$	64	  	 	$	—  	  	  	$	—  	  	 	$	64	  	
Commodity derivatives	  	$	401	  	 	$	401	  	 	$	—  	  	  	$	401	  	 	$	—  	  	
Commodity derivatives	  	$	(32	) 	 	$	(32	) 	 	$	—  	  	  	$	(32	) 	 	$	—  	  	
Interest rate derivatives	  	$	23	  	 	$	23	  	 	$	—  	  	  	$	23	  	 	$	—  	  	
Foreign currency derivatives	  	$	1	  	 	$	1	  	 	$	—  	  	  	$	1	  	 	$	—  	  	
Debt	  	$	(11,644	) 	 	$	(13,435	) 	 	$	—  	  	  	$	(13,435	) 	 	$	—  	  	
The following methods and assumptions were used to estimate the fair values in the tables above.
Level 1 Fair Value Measurements
Cash equivalents and short-term investments – Amounts consist primarily of United States and Canadian treasury securities and money market investments. The fair value approximates the carrying value.
Level 2 Fair Value Measurements
Cash equivalents and short-term investments – Amounts consist primarily of Canadian agency and provincial securities and commercial paper investments. The fair value approximates the carrying value.
Commodity, interest rate and foreign currency derivatives – The fair values of commodity, interest rate and foreign currency derivatives are estimated using internal discounted cash flow calculations based upon forward curves and data obtained from independent third parties for contracts with similar terms or data obtained from counterparties to the agreements.
Debt – Devon’s debt instruments do not actively trade in an established market. The fair values of its fixed-rate debt and floating-rate debt are estimated based on rates available for debt with similar terms and maturity. The fair value of Devon’s commercial paper and credit facility borrowings are the carrying values.
 
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
Level 3 Fair Value Measurements
Long-term investments – Devon’s long-term investments presented in the tables above consisted entirely of auction rate securities. Due to auction failures and the lack of an active market for Devon’s auction rate securities, quoted market prices for these securities were not available. Therefore, Devon used valuation techniques that rely on unobservable inputs to estimate the fair values of its long-term auction rate securities. These inputs were based on continued receipts of principal at par, the collection of all accrued interest to date, the probability of full repayment of the securities considering the United States government guarantees substantially all of the underlying student loans, and the AAA credit rating of the securities. 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, 2013 and December 31, 2012.
Included below is a summary of the changes in Devon’s Level 3 fair value measurements.

 	  	Year Ended December 31,	 	
 	  	2013	 	 	2012	 	
 	  	(In millions)	 	
Long-term investments balance at beginning of period	  	$	64	  	 	$	84	  	
Redemptions of principal	  	 	(2	) 	 	 	(20	) 	
	  	 	 	 	 	 	 	 	
Long-term investments balance at end of period	  	$	62	  	 	$	64	  	

20.	Discontinued Operations	
Revenues related to Devon’s discontinued operations totaled $43 million during 2011. Devon did not have revenues related to its discontinued operations during 2013 or 2012. The following table presents the earnings (loss) from Devon’s discontinued operations.

 	  	Year Ended December 31,	 	
 	  	2013	 	  	2012	 	 	2011	 	
 	  	(In millions)	 	
Operating earnings	  	$	—  	  	  	$	—  	  	 	$	38	  	
Gain (loss) on sale of oil and gas properties	  	 	—  	  	  	 	(16	) 	 	 	2,552	  	
	  	 	 	 	  	 	 	 	 	 	 	 	
Earnings (loss) before income taxes	  	 	—  	  	  	 	(16	) 	 	 	2,590	  	
Income tax expense	  	 	—  	  	  	 	5	  	 	 	20	  	
	  	 	 	 	  	 	 	 	 	 	 	 	
Earnings (loss) from discontinued operations	  	$	—  	  	  	$	(21	) 	 	$	2,570	  	

21.	Segment Information	
Devon manages its operations through distinct operating segments, which are defined primarily by geographic areas. For financial reporting purposes, Devon aggregates its U.S. operating segments into one reporting segment due to the similar nature of the businesses. However, Devon’s Canadian operating segment is reported as a separate reporting segment primarily due to the significant differences between the U.S. and Canadian 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. Segment revenues are all from external customers.
 
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 	  	U.S.	 	 	Canada	 	 	Total	 	
 	  	(In millions)	 	
Year Ended December 31, 2013:	  				
Oil, gas and NGL sales	  	$	5,964	  	 	$	2,558	  	 	$	8,522	  	
Oil, gas and NGL derivatives	  	$	(197	) 	 	$	6	  	 	$	(191	) 	
Marketing and midstream revenues	  	$	1,974	  	 	$	92	  	 	$	2,066	  	
Depreciation, depletion and amortization	  	$	1,931	  	 	$	849	  	 	$	2,780	  	
Interest expense	  	$	392	  	 	$	45	  	 	$	437	  	
Asset impairments	  	$	1,133	  	 	$	843	  	 	$	1,976	  	
Earnings (loss) from continuing operations before income taxes	  	$	646	  	 	$	(497	) 	 	$	149	  	
Income tax expense (benefit)	  	$	325	  	 	$	(156	) 	 	$	169	  	
Earnings (loss) from continuing operations	  	$	321	  	 	$	(341	) 	 	$	(20	) 	
Property and equipment, net	  	$	19,969	  	 	$	8,478	  	 	$	28,447	  	
Total assets	  	$	29,317	  	 	$	13,560	  	 	$	42,877	  	
Capital expenditures	  	$	4,802	  	 	$	1,841	  	 	$	6,643	  	
				
Year Ended December 31, 2012:	  				 				 				
Oil, gas and NGL sales	  	$	4,679	  	 	$	2,474	  	 	$	7,153	  	
Oil, gas and NGL derivatives	  	$	681	  	 	$	12	  	 	$	693	  	
Marketing and midstream revenues	  	$	1,541	  	 	$	114	  	 	$	1,655	  	
Depreciation, depletion and amortization	  	$	1,824	  	 	$	987	  	 	$	2,811	  	
Interest expense	  	$	343	  	 	$	63	  	 	$	406	  	
Asset impairments	  	$	1,861	  	 	$	163	  	 	$	2,024	  	
Loss from continuing operations before income taxes	  	$	(263	) 	 	$	(54	) 	 	$	(317	) 	
Income tax benefit	  	$	(97	) 	 	$	(35	) 	 	$	(132	) 	
Loss from continuing operations	  	$	(166	) 	 	$	(19	) 	 	$	(185	) 	
Property and equipment, net	  	$	18,361	  	 	$	8,955	  	 	$	27,316	  	
Total assets	  	$	24,256	  	 	$	19,070	  	 	$	43,326	  	
Capital expenditures	  	$	6,511	  	 	$	1,963	  	 	$	8,474	  	
				
Year Ended December 31, 2011:	  				 				 				
Oil, gas and NGL sales	  	$	5,418	  	 	$	2,897	  	 	$	8,315	  	
Oil, gas and NGL derivatives	  	$	881	  	 	$	—  	  	 	$	881	  	
Marketing and midstream revenues	  	$	2,050	  	 	$	199	  	 	$	2,249	  	
Depreciation, depletion and amortization	  	$	1,439	  	 	$	809	  	 	$	2,248	  	
Interest expense	  	$	204	  	 	$	148	  	 	$	352	  	
Earnings from continuing operations before income taxes	  	$	3,477	  	 	$	813	  	 	$	4,290	  	
Income tax expense	  	$	1,958	  	 	$	198	  	 	$	2,156	  	
Earnings from continuing operations	  	$	1,519	  	 	$	615	  	 	$	2,134	  	
Property and equipment, net	  	$	16,989	  	 	$	7,785	  	 	$	24,774	  	
Total assets (1)	  	$	22,622	  	 	$	18,342	  	 	$	40,964	  	
Capital expenditures	  	$	6,101	  	 	$	1,694	  	 	$	7,795	  	

(1)	Amounts in the table above do not include assets held for sale related to Devon’s discontinued operations, which totaled $153 million in 2011.	
 
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
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. 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, 2013	 	
 	  	U.S.	 	  	Canada	 	  	Total	 	
 	  	(In millions)	 	
Property acquisition costs:	  				  				  				
Proved properties	  	$	19	  	  	$	3	  	  	$	22	  	
Unproved properties	  	 	213	  	  	 	3	  	  	 	216	  	
Exploration costs	  	 	443	  	  	 	152	  	  	 	595	  	
Development costs	  	 	3,838	  	  	 	1,251	  	  	 	5,089	  	
	  	 	 	 	  	 	 	 	  	 	 	 	
Costs incurred	  	$	4,513	  	  	$	1,409	  	  	$	5,922	  	

													
 	  	Year Ended December 31, 2012	 	
 	  	U.S.	 	  	Canada	 	  	Total	 	
 	  	(In millions)	 	
Property acquisition costs:	  				  				  				
Proved properties	  	$	2	  	  	$	71	  	  	$	73	  	
Unproved properties	  	 	1,135	  	  	 	32	  	  	 	1,167	  	
Exploration costs	  	 	351	  	  	 	315	  	  	 	666	  	
Development costs	  	 	4,408	  	  	 	1,691	  	  	 	6,099	  	
	  	 	 	 	  	 	 	 	  	 	 	 	
Costs incurred	  	$	5,896	  	  	$	2,109	  	  	$	8,005	  	

													
 	  	Year Ended December 31, 2011	 	
 	  	U.S.	 	  	Canada	 	  	Total	 	
 	  	(In millions)	 	
Property acquisition costs:	  				  				  				
Proved properties	  	$	34	  	  	$	14	  	  	$	48	  	
Unproved properties	  	 	851	  	  	 	72	  	  	 	923	  	
Exploration costs	  	 	272	  	  	 	282	  	  	 	554	  	
Development costs	  	 	4,130	  	  	 	1,288	  	  	 	5,418	  	
	  	 	 	 	  	 	 	 	  	 	 	 	
Costs incurred	  	$	5,287	  	  	$	1,656	  	  	$	6,943	  	
	  	 	 	 	  	 	 	 	  	 	 	 	
Costs incurred in the tables above include additions and revisions to Devon’s asset retirement obligations. The proceeds received from our joint venture transactions at closing have not been netted against the costs incurred. At December 31, 2013, our partners’ remaining commitments to fund our future costs associated with these joint venture transactions totaled approximately $1.4 billion.
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 $368 million, $359 million and
 
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$337 million in the years 2013, 2012 and 2011, 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 $42 million, $36 million and $45 million in the years 2013, 2012 and 2011, respectively.
Capitalized Costs
The following tables reflect the aggregate capitalized costs related to oil and gas activities.

 	  	December 31, 2013	 	
 	  	U.S.	 	 	Canada	 	 	Total	 	
 	  	(In millions)	 	
Proved properties	  	$	51,366	  	 	$	22,629	  	 	$	73,995	  	
Unproved properties	  	 	1,277	  	 	 	1,514	  	 	 	2,791	  	
	  	 	 	 	 	 	 	 	 	 	 	 	
Total oil & gas properties	  	 	52,643	  	 	 	24,143	  	 	 	76,786	  	
Accumulated DD&A	  	 	(35,848	) 	 	 	(16,613	) 	 	 	(52,461	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	
Net capitalized costs	  	$	16,795	  	 	$	7,530	  	 	$	24,325	  	

 	  	December 31, 2012	 	
 	  	U.S.	 	 	Canada	 	 	Total	 	
 	  	(In millions)	 	
Proved properties	  	$	46,570	  	 	$	22,840	  	 	$	69,410	  	
Unproved properties	  	 	1,703	  	 	 	1,605	  	 	 	3,308	  	
	  	 	 	 	 	 	 	 	 	 	 	 	
Total oil & gas properties	  	 	48,273	  	 	 	24,445	  	 	 	72,718	  	
Accumulated DD&A	  	 	(33,098	) 	 	 	(16,039	) 	 	 	(49,137	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	
Net capitalized costs	  	$	15,175	  	 	$	8,406	  	 	$	23,581	  	
	  	 	 	 	 	 	 	 	 	 	 	 	
The following is a summary of Devon’s oil and gas properties not subject to amortization as of December 31, 2013.

 	  	Costs Incurred In	 	
 	  	2013	 	  	2012	 	  	2011	 	  	Prior to
2011	 	  	Total	 	
 	  	(In millions)	 	
Acquisition costs	  	$	207	  	  	$	725	  	  	$	62	  	  	$	848	  	  	$	1,842	  	
Exploration costs	  	 	226	  	  	 	129	  	  	 	118	  	  	 	30	  	  	 	503	  	
Development costs	  	 	113	  	  	 	132	  	  	 	66	  	  	 	9	  	  	 	320	  	
Capitalized interest	  	 	41	  	  	 	33	  	  	 	33	  	  	 	19	  	  	 	126	  	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total oil and gas properties not subject to amortization	  	$	587	  	  	$	1,019	  	  	$	279	  	  	$	906	  	  	$	2,791	  	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Included in the $2.8 billion of oil and gas properties not subject to amortization are approximately $1.6 billion of costs that we deem significant for individual assessment. These costs relate to our investments in the Pike thermal oil project in Canada, the Mississippian-Woodford Trend in Oklahoma and a portion of our properties in the Permian Basin in Texas. Based on our development plans, we expect to begin including the Pike costs in the amortization computation in 2015 when we receive regulatory approval for the first phase of this project and subsequently begin recognizing the associated proved reserves. We are evaluating and developing the Mississippian-Woodford and Permian properties over the next 3 to 4 years. We expect to include the costs in the amortization computation as we complete our evaluation activities.
 
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Results of Operations
The following tables include revenues and expenses associated with Devon’s oil and gas 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, 2013	 	
 	  	U.S.	 	 	Canada	 	 	Total	 	
 	  	(In millions)	 	
Oil, gas and NGL sales	  	$	5,964	  	 	$	2,558	  	 	$	8,522	  	
Lease operating expenses	  	 	(1,257	) 	 	 	(1,011	) 	 	 	(2,268	) 	
General and administrative expenses	  	 	(125	) 	 	 	(77	) 	 	 	(202	) 	
Production and property taxes	  	 	(380	) 	 	 	(59	) 	 	 	(439	) 	
Depreciation, depletion and amortization	  	 	(1,640	) 	 	 	(825	) 	 	 	(2,465	) 	
Asset impairments	  	 	(1,110	) 	 	 	(843	) 	 	 	(1,953	) 	
Accretion of asset retirement obligations	  	 	(47	) 	 	 	(64	) 	 	 	(111	) 	
Income tax benefit (expense)	  	 	(510	) 	 	 	88	  	 	 	(422	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	
Results of operations	  	$	895	  	 	$	(233	) 	 	$	662	  	
	  	 	 	 	 	 	 	 	 	 	 	 	
Depreciation, depletion and amortization per Boe	  	$	8.69	  	 	$	12.87	  	 	$	9.75	  	

													
 	  	Year Ended December 31, 2012	 	
 	  	U.S.	 	 	Canada	 	 	Total	 	
 	  	(In millions)	 	
Oil, gas and NGL sales	  	$	4,679	  	 	$	2,474	  	 	$	7,153	  	
Lease operating expenses	  	 	(1,059	) 	 	 	(1,015	) 	 	 	(2,074	) 	
General and administrative expenses	  	 	(159	) 	 	 	(137	) 	 	 	(296	) 	
Production and property taxes	  	 	(340	) 	 	 	(55	) 	 	 	(395	) 	
Depreciation, depletion and amortization	  	 	(1,563	) 	 	 	(963	) 	 	 	(2,526	) 	
Asset impairments	  	 	(1,793	) 	 	 	(163	) 	 	 	(1,956	) 	
Accretion of asset retirement obligations	  	 	(40	) 	 	 	(69	) 	 	 	(109	) 	
Income tax benefit (expense)	  	 	99	  	 	 	(3	) 	 	 	96	  	
	  	 	 	 	 	 	 	 	 	 	 	 	
Results of operations	  	$	(176	) 	 	$	69	  	 	$	(107	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	
Depreciation, depletion and amortization per Boe	  	$	8.55	  	 	$	14.41	  	 	$	10.12	  	

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 	  	Year Ended December 31, 2011	 	
 	  	U.S.	 	 	Canada	 	 	Total	 	
 	  	(In millions)	 	
Oil, gas and NGL sales	  	$	5,418	  	 	$	2,897	  	 	$	8,315	  	
Lease operating expenses	  	 	(925	) 	 	 	(926	) 	 	 	(1,851	) 	
General and administrative expenses	  	 	(132	) 	 	 	(119	) 	 	 	(251	) 	
Production and property taxes	  	 	(357	) 	 	 	(45	) 	 	 	(402	) 	
Depreciation, depletion and amortization	  	 	(1,201	) 	 	 	(786	) 	 	 	(1,987	) 	
Accretion of asset retirement obligations	  	 	(34	) 	 	 	(57	) 	 	 	(91	) 	
Income tax expense	  	 	(1,005	) 	 	 	(250	) 	 	 	(1,255	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	
Results of operations	  	$	1,764	  	 	$	714	  	 	$	2,478	  	
	  	 	 	 	 	 	 	 	 	 	 	 	
Depreciation, depletion and amortization per Boe	  	$	6.94	  	 	$	11.74	  	 	$	8.28	  	
	  	 	 	 	 	 	 	 	 	 	 	 	
Proved Reserves
The following tables present Devon’s estimated proved reserves by product by country.

 	  	Oil (MMBbls)	 	
 	  	U.S.	 	 	Canada	 	 	Total	 	
Proved developed and undeveloped reserves:	  				
December 31, 2010	  	 	    148	  	 	 	    93	  	 	 	    241	  	
Revisions due to prices	  	 	2	  	 	 	1	  	 	 	3	  	
Revisions other than price	  	 	(1	) 	 	 	(5	) 	 	 	(6	) 	
Extensions and discoveries	  	 	36	  	 	 	6	  	 	 	42	  	
Production	  	 	(17	) 	 	 	(15	) 	 	 	(32	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	
December 31, 2011	  	 	168	  	 	 	80	  	 	 	248	  	
Revisions due to prices	  	 	(1	) 	 	 	(5	) 	 	 	(6	) 	
Revisions other than price	  	 	(6	) 	 	 	(2	) 	 	 	(8	) 	
Extensions and discoveries	  	 	65	  	 	 	7	  	 	 	72	  	
Production	  	 	(21	) 	 	 	(15	) 	 	 	(36	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	
December 31, 2012	  	 	205	  	 	 	65	  	 	 	270	  	
Revisions due to prices	  	 	1	  	 	 	(1	) 	 	 	—  	  	
Revisions other than price	  	 	(18	) 	 	 	—  	  	 	 	(18	) 	
Extensions and discoveries	  	 	69	  	 	 	7	  	 	 	76	  	
Purchase of reserves	  	 	1	  	 	 	—  	  	 	 	1	  	
Production	  	 	(28	) 	 	 	(15	) 	 	 	(43	) 	
Sale of reserves	  	 	(1	) 	 	 	—  	  	 	 	(1	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	
December 31, 2013	  	 	229	  	 	 	56	  	 	 	285	  	
	  	 	 	 	 	 	 	 	 	 	 	 	
Proved developed reserves as of:	  				 				 				
December 31, 2010	  	 	131	  	 	 	82	  	 	 	213	  	
December 31, 2011	  	 	146	  	 	 	73	  	 	 	219	  	
December 31, 2012	  	 	166	  	 	 	62	  	 	 	228	  	
December 31, 2013	  	 	194	  	 	 	56	  	 	 	250	  	
Proved developed-producing reserves as of:	  				 				 				
December 31, 2010	  	 	123	  	 	 	72	  	 	 	195	  	
December 31, 2011	  	 	139	  	 	 	65	  	 	 	204	  	
December 31, 2012	  	 	155	  	 	 	56	  	 	 	211	  	
December 31, 2013	  	 	178	  	 	 	51	  	 	 	229	  	
Proved undeveloped reserves as of:	  				 				 				
December 31, 2010	  	 	17	  	 	 	11	  	 	 	28	  	
December 31, 2011	  	 	22	  	 	 	7	  	 	 	29	  	
December 31, 2012	  	 	39	  	 	 	3	  	 	 	42	  	
December 31, 2013	  	 	35	  	 	 	—  	  	 	 	35	  	
 
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 	  	Bitumen (MMBbls)	 	
 	  	U.S.	 	  	Canada	 	 	Total	 	
Proved developed and undeveloped reserves:	  				
December 31, 2010	  	 	    —  	  	  	 	    440	  	 	 	    440	  	
Revisions due to prices	  	 	—  	  	  	 	(16	) 	 	 	(16	) 	
Revisions other than price	  	 	—  	  	  	 	16	  	 	 	16	  	
Extensions and discoveries	  	 	—  	  	  	 	30	  	 	 	30	  	
Production	  	 	—  	  	  	 	(13	) 	 	 	(13	) 	
	  	 	 	 	  	 	 	 	 	 	 	 	
December 31, 2011	  	 	—  	  	  	 	457	  	 	 	457	  	
Revisions due to prices	  	 	—  	  	  	 	14	  	 	 	14	  	
Revisions other than price	  	 	—  	  	  	 	7	  	 	 	7	  	
Extensions and discoveries	  	 	—  	  	  	 	67	  	 	 	67	  	
Production	  	 	—  	  	  	 	(17	) 	 	 	(17	) 	
	  	 	 	 	  	 	 	 	 	 	 	 	
December 31, 2012	  	 	—  	  	  	 	528	  	 	 	528	  	
Revisions due to prices	  	 	—  	  	  	 	(11	) 	 	 	(11	) 	
Revisions other than price	  	 	—  	  	  	 	16	  	 	 	16	  	
Extensions and discoveries	  	 	—  	  	  	 	38	  	 	 	38	  	
Production	  	 	—  	  	  	 	(19	) 	 	 	(19	) 	
	  	 	 	 	  	 	 	 	 	 	 	 	
December 31, 2013	  	 	—  	  	  	 	552	  	 	 	552	  	
	  	 	 	 	  	 	 	 	 	 	 	 	
Proved developed reserves as of:	  				  				 				
December 31, 2010	  	 	—  	  	  	 	44	  	 	 	44	  	
December 31, 2011	  	 	—  	  	  	 	90	  	 	 	90	  	
December 31, 2012	  	 	—  	  	  	 	99	  	 	 	99	  	
December 31, 2013	  	 	—  	  	  	 	111	  	 	 	111	  	
Proved developed-producing reserves as of:	  				  				 				
December 31, 2010	  	 	—  	  	  	 	44	  	 	 	44	  	
December 31, 2011	  	 	—  	  	  	 	90	  	 	 	90	  	
December 31, 2012	  	 	—  	  	  	 	99	  	 	 	99	  	
December 31, 2013	  	 	—  	  	  	 	111	  	 	 	111	  	
Proved undeveloped reserves as of:	  				  				 				
December 31, 2010	  	 	—  	  	  	 	396	  	 	 	396	  	
December 31, 2011	  	 	—  	  	  	 	367	  	 	 	367	  	
December 31, 2012	  	 	—  	  	  	 	429	  	 	 	429	  	
December 31, 2013	  	 	—  	  	  	 	441	  	 	 	441	  	
 
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 	  	Gas (Bcf)	 	
 	  	U.S.	 	 	Canada	 	 	Total	 	
Proved developed and undeveloped reserves:	  				
December 31, 2010	  	 	    9,065	  	 	 	    1,218	  	 	 	    10,283	  	
Revisions due to prices	  	 	(1	) 	 	 	(60	) 	 	 	(61	) 	
Revisions other than price	  	 	(243	) 	 	 	(38	) 	 	 	(281	) 	
Extensions and discoveries	  	 	1,410	  	 	 	58	  	 	 	1,468	  	
Purchase of reserves	  	 	16	  	 	 	20	  	 	 	36	  	
Production	  	 	(740	) 	 	 	(213	) 	 	 	(953	) 	
Sale of reserves	  	 	—  	  	 	 	(6	) 	 	 	(6	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	
December 31, 2011	  	 	9,507	  	 	 	979	  	 	 	10,486	  	
Revisions due to prices	  	 	(831	) 	 	 	(99	) 	 	 	(930	) 	
Revisions other than price	  	 	(287	) 	 	 	(33	) 	 	 	(320	) 	
Extensions and discoveries	  	 	1,124	  	 	 	34	  	 	 	1,158	  	
Purchase of reserves	  	 	2	  	 	 	—  	  	 	 	2	  	
Production	  	 	(752	) 	 	 	(186	) 	 	 	(938	) 	
Sale of reserves	  	 	(1	) 	 	 	(11	) 	 	 	(12	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	
December 31, 2012	  	 	8,762	  	 	 	684	  	 	 	9,446	  	
Revisions due to prices	  	 	405	  	 	 	161	  	 	 	566	  	
Revisions other than price	  	 	(299	) 	 	 	67	  	 	 	(232	) 	
Extensions and discoveries	  	 	471	  	 	 	19	  	 	 	490	  	
Purchase of reserves	  	 	1	  	 	 	—  	  	 	 	1	  	
Production	  	 	(709	) 	 	 	(165	) 	 	 	(874	) 	
Sale of reserves	  	 	(81	) 	 	 	(8	) 	 	 	(89	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	
December 31, 2013	  	 	8,550	  	 	 	758	  	 	 	9,308	  	
	  	 	 	 	 	 	 	 	 	 	 	 	
Proved developed reserves as of:	  				 				 				
December 31, 2010	  	 	7,280	  	 	 	1,144	  	 	 	8,424	  	
December 31, 2011	  	 	7,957	  	 	 	951	  	 	 	8,908	  	
December 31, 2012	  	 	7,391	  	 	 	679	  	 	 	8,070	  	
December 31, 2013	  	 	7,707	  	 	 	752	  	 	 	8,459	  	
Proved developed-producing reserves as of:	  				 				 				
December 31, 2010	  	 	6,702	  	 	 	1,031	  	 	 	7,733	  	
December 31, 2011	  	 	7,409	  	 	 	862	  	 	 	8,271	  	
December 31, 2012	  	 	7,091	  	 	 	624	  	 	 	7,715	  	
December 31, 2013	  	 	7,425	  	 	 	680	  	 	 	8,105	  	
Proved undeveloped reserves as of:	  				 				 				
December 31, 2010	  	 	1,785	  	 	 	74	  	 	 	1,859	  	
December 31, 2011	  	 	1,550	  	 	 	28	  	 	 	1,578	  	
December 31, 2012	  	 	1,371	  	 	 	5	  	 	 	1,376	  	
December 31, 2013	  	 	843	  	 	 	6	  	 	 	849	  	
 
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 	  	Natural Gas Liquids (MMBbls)	 	
 	  	U.S.	 	 	Canada	 	 	Total	 	
Proved developed and undeveloped reserves:	  				 				 				
December 31, 2010	  	 	    449	  	 	 	    30	  	 	 	    479	  	
Revisions due to prices	  	 	4	  	 	 	(1	) 	 	 	3	  	
Revisions other than price	  	 	1	  	 	 	—  	  	 	 	1	  	
Extensions and discoveries	  	 	102	  	 	 	2	  	 	 	104	  	
Purchase of reserves	  	 	2	  	 	 	—  	  	 	 	2	  	
Production	  	 	(33	) 	 	 	(4	) 	 	 	(37	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	
December 31, 2011	  	 	525	  	 	 	27	  	 	 	552	  	
Revisions due to prices	  	 	(19	) 	 	 	(5	) 	 	 	(24	) 	
Revisions other than price	  	 	(13	) 	 	 	—  	  	 	 	(13	) 	
Extensions and discoveries	  	 	114	  	 	 	2	  	 	 	116	  	
Production	  	 	(36	) 	 	 	(4	) 	 	 	(40	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	
December 31, 2012	  	 	571	  	 	 	20	  	 	 	591	  	
Revisions due to prices	  	 	8	  	 	 	3	  	 	 	11	  	
Revisions other than price	  	 	(50	) 	 	 	3	  	 	 	(47	) 	
Extensions and discoveries	  	 	64	  	 	 	1	  	 	 	65	  	
Production	  	 	(41	) 	 	 	(4	) 	 	 	(45	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	
December 31, 2013	  	 	552	  	 	 	23	  	 	 	575	  	
	  	 	 	 	 	 	 	 	 	 	 	 	
Proved developed reserves as of:	  				 				 				
December 31, 2010	  	 	353	  	 	 	28	  	 	 	381	  	
December 31, 2011	  	 	402	  	 	 	26	  	 	 	428	  	
December 31, 2012	  	 	431	  	 	 	20	  	 	 	451	  	
December 31, 2013	  	 	468	  	 	 	23	  	 	 	491	  	
Proved developed-producing reserves as of:	  				 				 				
December 31, 2010	  	 	318	  	 	 	26	  	 	 	344	  	
December 31, 2011	  	 	372	  	 	 	24	  	 	 	396	  	
December 31, 2012	  	 	406	  	 	 	19	  	 	 	425	  	
December 31, 2013	  	 	442	  	 	 	21	  	 	 	463	  	
Proved undeveloped reserves as of:	  				 				 				
December 31, 2010	  	 	96	  	 	 	2	  	 	 	98	  	
December 31, 2011	  	 	123	  	 	 	1	  	 	 	124	  	
December 31, 2012	  	 	140	  	 	 	—  	  	 	 	140	  	
December 31, 2013	  	 	84	  	 	 	—  	  	 	 	84	  	
 
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 	  	Total (MMBoe) (1)	 	
 	  	U.S.	 	 	Canada	 	 	Total	 	
Proved developed and undeveloped reserves:	  				
December 31, 2010	  	 	    2,107	  	 	 	    766	  	 	 	    2,873	  	
Revisions due to prices	  	 	6	  	 	 	(27	) 	 	 	(21	) 	
Revisions other than price	  	 	(41	) 	 	 	6	  	 	 	(35	) 	
Extensions and discoveries	  	 	374	  	 	 	47	  	 	 	421	  	
Purchase of reserves	  	 	5	  	 	 	3	  	 	 	8	  	
Production	  	 	(173	) 	 	 	(67	) 	 	 	(240	) 	
Sale of reserves	  	 	—  	  	 	 	(1	) 	 	 	(1	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	
December 31, 2011	  	 	2,278	  	 	 	727	  	 	 	3,005	  	
Revisions due to prices	  	 	(159	) 	 	 	(12	) 	 	 	(171	) 	
Revisions other than price	  	 	(67	) 	 	 	(1	) 	 	 	(68	) 	
Extensions and discoveries	  	 	367	  	 	 	82	  	 	 	449	  	
Production	  	 	(183	) 	 	 	(67	) 	 	 	(250	) 	
Sale of reserves	  	 	—  	  	 	 	(2	) 	 	 	(2	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	
December 31, 2012	  	 	2,236	  	 	 	727	  	 	 	2,963	  	
Revisions due to prices	  	 	76	  	 	 	18	  	 	 	94	  	
Revisions other than price	  	 	(117	) 	 	 	29	  	 	 	(88	) 	
Extensions and discoveries	  	 	212	  	 	 	49	  	 	 	261	  	
Purchase of reserves	  	 	1	  	 	 	—  	  	 	 	1	  	
Production	  	 	(189	) 	 	 	(64	) 	 	 	(253	) 	
Sale of reserves	  	 	(14	) 	 	 	(1	) 	 	 	(15	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	
December 31, 2013	  	 	2,205	  	 	 	758	  	 	 	2,963	  	
	  	 	 	 	 	 	 	 	 	 	 	 	
Proved developed reserves as of:	  				 				 				
December 31, 2010	  	 	1,696	  	 	 	346	  	 	 	2,042	  	
December 31, 2011	  	 	1,875	  	 	 	348	  	 	 	2,223	  	
December 31, 2012	  	 	1,829	  	 	 	294	  	 	 	2,123	  	
December 31, 2013	  	 	1,947	  	 	 	315	  	 	 	2,262	  	
Proved developed-producing reserves as of:	  				 				 				
December 31, 2010	  	 	1,557	  	 	 	314	  	 	 	1,871	  	
December 31, 2011	  	 	1,746	  	 	 	323	  	 	 	2,069	  	
December 31, 2012	  	 	1,743	  	 	 	278	  	 	 	2,021	  	
December 31, 2013	  	 	1,857	  	 	 	297	  	 	 	2,154	  	
Proved undeveloped reserves as of:	  				 				 				
December 31, 2010	  	 	411	  	 	 	420	  	 	 	831	  	
December 31, 2011	  	 	403	  	 	 	379	  	 	 	782	  	
December 31, 2012	  	 	407	  	 	 	433	  	 	 	840	  	
December 31, 2013	  	 	258	  	 	 	443	  	 	 	701	  	

(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. Bitumen and natural gas liquids reserves are converted to Boe on a one-to-one basis with oil.	
 
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
Proved Undeveloped Reserves
The following table presents the changes in Devon’s total proved undeveloped reserves during 2013 (in MMBoe).

 	  	U.S.	 	 	Canada	 	 	Total	 	
Proved undeveloped reserves as of December 31, 2012	  	 	407	  	 	 	433	  	 	 	840	  	
Extensions and discoveries	  	 	57	  	 	 	38	  	 	 	95	  	
Revisions due to prices	  	 	1	  	 	 	(10	) 	 	 	(9	) 	
Revisions other than price	  	 	(91	) 	 	 	13	  	 	 	(78	) 	
Conversion to proved developed reserves	  	 	(116	) 	 	 	(31	) 	 	 	(147	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	
Proved undeveloped reserves as of December 31, 2013	  	 	258	  	 	 	443	  	 	 	701	  	
	  	 	 	 	 	 	 	 	 	 	 	 	
At December 31, 2013, Devon had 701 MMBoe of proved undeveloped reserves. This represents a 17 percent decrease as compared to 2012 and represents 24 percent of total proved reserves. Drilling and development activities increased Devon’s proved undeveloped reserves 95 MMBoe and resulted in the conversion of 147 MMBoe, or 18 percent, of the 2012 proved undeveloped reserves to proved developed reserves. Costs incurred related to the development and conversion of Devon’s proved undeveloped reserves were $1.9 billion for 2013. Additionally, revisions other than price decreased Devon’s proved undeveloped reserves 78 MMBoe primarily due to evaluations of certain U.S. onshore dry-gas areas, which Devon does not expect to develop in the next five years. The largest revisions relate to the dry-gas areas in the Cana-Woodford Shale in western Oklahoma, Carthage in east Texas and the Barnett Shale in north Texas.
A significant amount of Devon’s proved undeveloped reserves at the end of 2013 related to its Jackfish operations. At December 31, 2013 and 2012, Devon’s Jackfish proved undeveloped reserves were 441 MMBoe and 429 MMBoe, respectively. Development schedules for the Jackfish reserves are primarily controlled by the need to keep the processing plants at their 35,000 barrel daily facility capacity. Processing plant capacity is controlled by factors such as total steam processing capacity, steam-oil ratios and air quality discharge permits. As a result, these reserves are classified as proved undeveloped for more than five years. Currently, the development schedule for these reserves extends though the year 2031.
Price Revisions
2013 – Reserves increased 94 MMBoe primarily due to higher gas prices. Of this increase, 43 MMBoe related to the Barnett Shale and 19 MMBoe related to the Rocky Mountain area.
2012 – Reserves decreased 171 MMBoe primarily due to lower gas prices. Of this decrease, 100 MMBoe related to the Barnett Shale and 25 MMBoe related to the Rocky Mountain area.
2011 – Reserves decreased 21 MMBoe due to lower gas prices and higher oil prices. The higher oil prices increased Devon’s Canadian royalty burden, which reduced Devon’s oil reserves.
Revisions Other Than Price
Total revisions other than price for 2013, 2012 and 2011 primarily related to Devon’s evaluation of certain dry gas regions, with the largest revisions being made in the Cana-Woodford Shale, Barnett Shale and Carthage area.
 
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
Extensions and Discoveries
2013 – Of the 261 MMBoe of extensions and discoveries, 76 MMBoe related to the Permian Basin in west Texas and southeast New Mexico, 54 MMBoe related to the Barnett Shale, 42 MMBoe related to the Anadarko Basin, 38 MMBoe related to Jackfish in northeast Alberta, Canada and 32 MMBoe related to the Mississippian-Woodford Trend in north Oklahoma.
The 2013 extensions and discoveries included 175 MMBoe related to additions from Devon’s infill drilling activities, including 23 MMBoe at the Cana-Woodford Shale, 54 MMBoe at the Barnett Shale, 38 MMBoe at Jackfish, 33 MMBoe at the Permian Basin and 20 MMBoe at the Mississippian-Woodford Trend.
2012 – Of the 449 MMBoe of extensions and discoveries, 151 MMBoe related to the Cana-Woodford Shale, 95 MMBoe related to the Barnett Shale, 72 MMBoe related to the Permian Basin, 67 MMBoe related to Jackfish, 16 MMBoe related to the Rocky Mountain area and 18 MMBoe related to the Granite Wash area.
The 2012 extensions and discoveries included 229 MMBoe related to additions from Devon’s infill drilling activities, including 134 MMBoe at the Cana-Woodford Shale and 82 MMBoe at the Barnett Shale.
2011 – Of the 421 MMBoe of extensions and discoveries, 162 MMBoe related to the Cana-Woodford Shale, 115 MMBoe related to the Barnett Shale, 39 MMBoe related to the Permian Basin, 30 MMBoe related to Jackfish, 19 MMBoe related to the Rocky Mountain area and 17 MMBoe related to the Granite Wash area.
The 2011 extensions and discoveries included 168 MMBoe related to additions from Devon’s infill drilling activities, including 80 MMBoe at the Cana-Woodford Shale and 77 MMBoe at the Barnett Shale.
Standardized Measure
The tables below reflect Devon’s standardized measure of discounted future net cash flows from its proved reserves.

 	  	Year Ended December 31, 2013	 	
 	  	U.S.	 	 	Canada	 	 	Total	 	
 	  	(In millions)	 	
Future cash inflows	  	$	61,983	  	 	$	33,305	  	 	$	95,288	  	
Future costs:	  				 				 				
Development	  	 	(5,448	) 	 	 	(5,308	) 	 	 	(10,756	) 	
Production	  	 	(26,663	) 	 	 	(15,709	) 	 	 	(42,372	) 	
Future income tax expense	  	 	(9,046	) 	 	 	(2,327	) 	 	 	(11,373	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	
Future net cash flow	  	 	20,826	  	 	 	9,961	  	 	 	30,787	  	
10% discount to reflect timing of cash flows	  	 	(10,346	) 	 	 	(4,700	) 	 	 	(15,046	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	
Standardized measure of discounted future net cash flows	  	$	10,480	  	 	$	5,261	  	 	$	15,741	  	

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

 	  	Year Ended December 31, 2012	 	
 	  	U.S.	 	 	Canada	 	 	Total	 	
 	  	(In millions)	 	
Future cash inflows	  	$	55,297	  	 	$	33,570	  	 	$	88,867	  	
Future costs:	  				 				 				
Development	  	 	(6,556	) 	 	 	(6,211	) 	 	 	(12,767	) 	
Production	  	 	(24,265	) 	 	 	(16,611	) 	 	 	(40,876	) 	
Future income tax expense	  	 	(6,542	) 	 	 	(1,992	) 	 	 	(8,534	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	
Future net cash flow	  	 	17,934	  	 	 	8,756	  	 	 	26,690	  	
10% discount to reflect timing of cash flows	  	 	(9,036	) 	 	 	(4,433	) 	 	 	(13,469	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	
Standardized measure of discounted future net cash flows	  	$	8,898	  	 	$	4,323	  	 	$	13,221	  	

													
 	  	Year Ended December 31, 2011	 	
 	  	U.S.	 	 	Canada	 	 	Total	 	
 	  	(In millions)	 	
Future cash inflows	  	$	69,305	  	 	$	36,786	  	 	$	106,091	  	
Future costs:	  				 				 				
Development	  	 	(6,817	) 	 	 	(4,678	) 	 	 	(11,495	) 	
Production	  	 	(26,217	) 	 	 	(15,063	) 	 	 	(41,280	) 	
Future income tax expense	  	 	(11,432	) 	 	 	(3,763	) 	 	 	(15,195	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	
Future net cash flow	  	 	24,839	  	 	 	13,282	  	 	 	38,121	  	
10% discount to reflect timing of cash flows	  	 	(13,492	) 	 	 	(6,785	) 	 	 	(20,277	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	
Standardized measure of discounted future net cash flows	  	$	11,347	  	 	$	6,497	  	 	$	17,844	  	
	  	 	 	 	 	 	 	 	 	 	 	 	
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 2013 estimates, Devon’s future realized prices were assumed to be $88.19 per barrel of oil, $47.44 per barrel of bitumen, $3.10 per Mcf of gas and $26.28 per barrel of natural gas liquids. Of the $10.8 billion of future development costs as of the end of 2013, $1.9 billion, $1.5 billion and $0.7 billion are estimated to be spent in 2014, 2015 and 2016, respectively.
Future development costs include not only development costs, but also future asset retirement costs. Included as part of the $10.8 billion of future development costs are $2.7 billion of future asset retirement costs. The future income tax expenses have been computed using statutory tax rates, giving effect to allowable tax deductions and tax credits under current laws.
 
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
 
The principal changes in Devon’s standardized measure of discounted future net cash flows are as follows:

 	  	Year Ended December 31,	 	
 	  	2013	 	 	2012	 	 	2011	 	
 	  	(In millions)	 	
Beginning balance	  	$	13,221	  	 	$	17,844	  	 	$	16,352	  	
Net changes in prices and production costs	  	 	3,018	  	 	 	(9,889	) 	 	 	1,875	  	
Oil, bitumen, gas and NGL sales, net of production costs	  	 	(5,613	) 	 	 	(4,388	) 	 	 	(5,811	) 	
Changes in estimated future development costs	  	 	399	  	 	 	(1,094	) 	 	 	(440	) 	
Extensions and discoveries, net of future development costs	  	 	4,047	  	 	 	4,669	  	 	 	3,714	  	
Purchase of reserves	  	 	14	  	 	 	18	  	 	 	57	  	
Sales of reserves in place	  	 	(44	) 	 	 	(25	) 	 	 	(2	) 	
Revisions of quantity estimates	  	 	(1,040	) 	 	 	162	  	 	 	(228	) 	
Previously estimated development costs incurred during the period	  	 	1,986	  	 	 	1,321	  	 	 	1,302	  	
Accretion of discount	  	 	1,940	  	 	 	1,420	  	 	 	2,248	  	
Other, primarily changes in timing and foreign exchange rates	  	 	(583	) 	 	 	113	  	 	 	(294	) 	
Net change in income taxes	  	 	(1,604	) 	 	 	3,070	  	 	 	(929	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	
Ending balance	  	$	15,741	  	 	$	13,221	  	 	$	17,844	  	

23.	Supplemental Quarterly Financial Information (Unaudited)	
Following is a summary of Devon’s unaudited interim results of operations.

 	  	2013	 	
 	  	First
Quarter	 	 	Second
Quarter	 	  	Third
Quarter	 	  	Fourth
Quarter	 	  	Full
Year	 	
 	  	(In millions, except per share amounts)	 	
Operating revenues	  	$	1,971	  	 	$	3,088	  	  	$	2,714	  	  	$	2,624	  	  	$	10,397	  	
Earnings (loss) before income taxes	  	$	(1,962	) 	 	$	997	  	  	$	639	  	  	$	475	  	  	$	149	  	
Net earnings (loss)	  	$	(1,339	) 	 	$	683	  	  	$	429	  	  	$	207	  	  	$	(20	) 	
Basic net earnings (loss) per common share:	  				 				  				  				  				
Net earnings (loss)	  	$	(3.34	) 	 	$	1.69	  	  	$	1.06	  	  	$	0.51	  	  	$	(0.06	) 	
Diluted net earnings (loss) per common share:	  				 				  				  				  				
Net earnings (loss)	  	$	(3.34	) 	 	$	1.68	  	  	$	1.05	  	  	$	0.51	  	  	$	(0.06	) 	
 
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 	  	2012	 	
 	  	First
Quarter	 	 	Second
Quarter	 	  	Third
Quarter	 	 	Fourth
Quarter	 	 	Full
Year	 	
 	  	(In millions, except per share amounts)	 	
Operating revenues	  	$	2,495	  	 	$	2,561	  	  	$	1,865	  	 	$	2,580	  	 	$	9,501	  	
Earnings (loss) from continuing operations before income taxes	  	$	611	  	 	$	734	  	  	$	(1,161	) 	 	$	(501	) 	 	$	(317	) 	
Earnings (loss) from continuing operations	  	$	414	  	 	$	477	  	  	$	(719	) 	 	$	(357	) 	 	$	(185	) 	
Loss from discontinued operations	  	 	(21	) 	 	 	—  	  	  	 	—  	  	 	 	—  	  	 	 	(21	) 	
	  	 	 	 	 	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	
Net earnings (loss)	  	$	393	  	 	$	477	  	  	$	(719	) 	 	$	(357	) 	 	$	(206	) 	
	  	 	 	 	 	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	
Basic net earnings (loss) per common share:	  				 				  				 				 				
Earnings (loss) from continuing operations	  	$	1.03	  	 	$	1.18	  	  	$	(1.80	) 	 	$	(0.89	) 	 	$	(0.47	) 	
Loss from discontinued operations	  	 	(0.06	) 	 	 	—  	  	  	 	—  	  	 	 	—  	  	 	 	(0.05	) 	
	  	 	 	 	 	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	
Net earnings (loss)	  	$	0.97	  	 	$	1.18	  	  	$	(1.80	) 	 	$	(0.89	) 	 	$	(0.52	) 	
	  	 	 	 	 	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	
Diluted net earnings (loss) per common share:	  				 				  				 				 				
Earnings (loss) from continuing operations	  	$	1.03	  	 	$	1.18	  	  	$	(1.80	) 	 	$	(0.89	) 	 	$	(0.47	) 	
Loss from discontinued operations	  	 	(0.06	) 	 	 	—  	  	  	 	—  	  	 	 	—  	  	 	 	(0.05	) 	
	  	 	 	 	 	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	
Net earnings (loss)	  	$	0.97	  	 	$	1.18	  	  	$	(1.80	) 	 	$	(0.89	) 	 	$	(0.52	) 	
	  	 	 	 	 	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	
Earnings (Loss) from Continuing Operations
The first quarter of 2013 includes U.S. and Canadian asset impairments totaling $1.9 billion ($1.3 billion after income taxes, or $3.25 per diluted share).
The fourth quarter of 2012 includes U.S. and Canadian asset impairments totaling $0.9 billion ($0.6 billion after income taxes, or $1.46 per diluted share).
The third quarter of 2012 includes U.S. asset impairments totaling $1.1 billion ($0.7 billion after income taxes, or $1.78 per diluted share).
 
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 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, our principal executive and principal financial officers have concluded that our 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, 2013 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
Our 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, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control — Integrated Framework issued in 1992 by the Committee of Sponsoring Organizations of the Treadway Commission (the “1992 COSO Framework”). Based on this evaluation under the 1992 COSO Framework, which was completed on February 19, 2014, management concluded that its internal control over financial reporting was effective as of December 31, 2013.
The effectiveness of our internal control over financial reporting as of December 31, 2013 has been audited by KPMG LLP, an independent registered public accounting firm who audited our consolidated financial statements as of and for the year ended December 31, 2013, as stated in their report, which is included under “Item 8. Financial Statements and Supplementary Data” in this report.
Changes in Internal Control Over Financial Reporting
There was no change in our internal control over financial reporting during the fourth quarter of 2013 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
 Item 9B. Other Information 
Not Applicable.
 
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 PART III
 Item 10. Directors, Executive Officers and Corporate Governance 
The information called for by this Item 10 is incorporated herein by reference to the definitive Proxy Statement to be filed by Devon pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 not later than April 30, 2014.
 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, 2014.
 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, 2014.
 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, 2014.
 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, 2014.
 
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 PART IV
 Item 15. Exhibits and Financial Statement Schedules 
(a) The following documents are filed as part of this report:
1. Consolidated Financial Statements
Reference is made to the Index to Consolidated Financial Statements and Consolidated Financial Statement Schedules appearing at “Item 8. Financial Statements and Supplementary Data” in this report.
2. Consolidated Financial Statement Schedules
All financial statement schedules are omitted as they are inapplicable, or the required information has been included in the consolidated financial statements or notes thereto.
3. Exhibits

Exhibit No.	  	Description	
		
1.1	  	Underwriting Agreement, dated December 11, 2013, by and among Registrant and Morgan Stanley & Co. LLC, Barclays Capital Inc. and Goldman, Sachs & Co., as representatives of the several underwriters named therein (incorporated by reference to Exhibit 1.1 to Registrant’s Form 8-K filed December 16, 2013).	
		
2.1	  	Agreement and Plan of Merger dated October 21, 2013, by and among Registrant, Devon Gas Services, L.P., Acacia Natural Gas Corp I, Inc., Crosstex Energy, Inc., New Public Rangers L.L.C., Boomer Merger Sub, Inc. and Rangers Merger Sub, Inc. (incorporated by reference to Exhibit 2.1 to Registrant’s Form 8-K filed October 22, 2013).	
		
2.2	  	Contribution Agreement dated October 21, 2013, by and among Registrant, Devon Gas Corporation, Devon Gas Services, L.P., Southwestern Gas Pipeline, Inc., Crosstex Energy, L.P. and Crosstex Energy Services, L.P. (incorporated by reference to Exhibit 2.2 to Registrant’s Form 8-K filed October 22, 2013).	
		
2.3	  	Purchase and Sale Agreement dated November 20, 2013, among GeoSouthern Intermediate Holdings, LLC, GeoSouthern Energy Corporation (solely with respect to certain sections specified therein), and Devon Energy Production Company, L.P. (incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K/A filed February 18, 2014).	
		
3.1	  	Registrant’s Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 of Registrant’s 10-K for the fiscal year ending December 31, 2012).	
		
3.2	  	Registrant’s Bylaws (incorporated by reference to Exhibit 3.2 of Registrant’s Form 8-K filed June 8, 2012).	
		
3.3	  	Amendment No. 1 to Registrant’s Bylaws (incorporated by reference to Exhibit 3.2 to Registrant’s Form 8-K filed September 16, 2013).	
		
4.1	  	Indenture, dated as of July 12, 2011, between Registrant and UMB Bank, National Association, as Trustee, relating to the 2.40% Senior Notes due 2016, the 4.00% Senior Notes due 2021 and the 5.60% Senior Notes due 2041 (incorporated by reference to Exhibit 4.1 to Registrant’s Form 8-K filed July 12, 2011).	
		
4.2	  	Supplemental Indenture No. 1, dated as of July 12, 2011, to Indenture dated as of July 12, 2011, between Registrant and UMB Bank, National Association, as Trustee, relating to the 2.40% Senior Notes due 2016, the 4.00% Senior Notes due 2021 and the 5.60% Senior Notes due 2041 (incorporated by reference to Exhibit 4.2 to Registrant’s Form 8-K filed July 12, 2011).	
 
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Exhibit No.	  	Description	
		
    4.3	  	Supplemental Indenture No. 2, dated as of May 14, 2012, to Indenture dated as of July 12, 2011, between Registrant and UMB Bank, National Association, as Trustee, relating to the 1.875% Senior Notes due 2017, the 3.250% Senior Notes due 2022 and the 4.750% Senior Notes due 2042 (incorporated by reference to Exhibit 4.1 to Registrant’s Form 8-K filed May 14, 2012).	
		
    4.4	  	Supplemental Indenture No. 3, dated as of December 19, 2013, to Indenture dated as of July 12, 2011, between Registrant and UMB Bank, National Association, as Trustee, relating to the Floating Rate Senior Notes due 2015, the Floating Rate Senior Notes due 2016, the 1.200% Senior Notes due 2016 and the 2.50% Senior Notes due 2018 (incorporated by reference to Exhibit 4.1 to Registrant’s Form 8-K filed December 19, 2013).	
		
    4.5	  	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 4.1 of Registrant’s Form 8-K filed April 9, 2002; File No. 000-30176).	
		
    4.6	  	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 April 9, 2002; File No. 000-30176).	
		
    4.7	  	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 6.30% Senior Notes due 2019 (incorporated by reference to Exhibit 4.1 to Registrant’s Form 8-K filed January 9, 2009; File No. 000-32318).	
		
    4.8	  	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 7.875% Debentures due 2031 (incorporated by reference to Exhibit 4.7 to Registrant’s Registration Statement on Form S-4 as filed October 31, 2001; File No. 333-68694).	
		
    4.9	  	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.; File No. 001-14252).	
		
    4.10	  	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; File No. 001-08094).	
		
    4.11	  	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 Form 8-K filed May 14, 2001; File No. 033-06444).	
		
    4.12	  	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; File No. 001-32318).	
 
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Exhibit No.	  	Description	
		
    4.13	  	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 Inc.’s Form 10-K for the year ended December 31, 1997; File No. 001-08094).	
		
    4.14	  	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; File No. 001-08094).	
		
    4.15	  	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 Form 8-K filed May 14, 2001; File No. 033-06444).	
		
    4.16	  	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; File No. 001-32318).	
		
    9.1	  	Voting Agreement dated October 21, 2013, by and among Registrant, Blackstone/GSO Capital Solutions Overseas Master Fund L.P. and Blackstone/GSO Capital Solutions Fund LP (incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K filed October 22, 2013).	
		
  10.1	  	Credit Agreement dated October 24, 2012, among Registrant, as U.S. Borrower, Devon NEC Corporation and Devon Canada Corporation, as Canadian Borrowers, each lender from time to time party thereto, each L/C Issuer from time to time party thereto, and Bank of America, N.A., as Administrative Agent, Canadian Swing Line Lender and U.S. Swing Line Lender (incorporated by reference to Exhibit 10.1 of Registrant’s Form 8-K filed October 29, 2012).	
		
  10.2	  	Extension Agreement dated September 3, 2013 to the Credit Agreement dated October 24, 2012, among Registrant, as U.S. Borrower, Devon NEC Corporation and Devon Canada Corporation, as Canadian Borrowers, Devon Financing Company, L.L.C., the consenting lenders, and Bank of America, N.A., as Administrative Agent, Canadian Swing Line Lender and U.S. Swing Line Lender, with respect to Borrower’s extension of the Maturity Date from October 24, 2017 to October 24, 2018 (incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed November 6, 2013).	
		
  10.3	  	First Amendment to Credit Agreement dated February 3, 2014, to the Credit Agreement dated October 24, 2012, among Registrant, as U.S. Borrower, Devon NEC Corporation and Devon Canada Corporation, as Canadian Borrowers, each lender from time to time party thereto, each L/C Issuer from time to time party thereto, and Bank of America, N.A., as Administrative Agent, Canadian Swing Line Lender and U.S. Swing Line Lender (incorporated by reference to Exhibit 10.1 of Registrant’s Form 8-K filed February 7, 2014).	
		
  10.4	  	Credit Agreement dated as of December 16, 2013, among Devon Energy Corporation, as Borrower, Morgan Stanley Senior Funding, Inc., as Administrative Agent, and the other lenders party thereto (incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K filed December 20, 2013).	
 
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Exhibit No.	  	Description	
		
  10.5	  	Devon Energy Corporation 2009 Long-Term Incentive Plan (as amended and restated effective June 6, 2012) (incorporated by reference to Registrant’s Form S-8 Registration No.333-182198, filed June 18, 2012).*	
		
  10.6	  	Devon Energy Corporation 2013 Amendment (effective as of March 6, 2013) to the Devon Energy Corporation 2009 Long-Term Plan (as amended and restated effective June 6, 2012) (incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed May 1, 2013).*	
		
  10.7	  	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).*	
		
  10.8	  	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).*	
		
  10.9	  	Devon Energy Corporation Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K, filed June 8, 2012)*	
		
  10.10	  	Devon Energy Corporation Non-Qualified Deferred Compensation Plan (as Amended and Restated Effective January 1, 2013) (incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed August 7, 2013).*	
		
  10.11	  	Devon Energy Corporation Amendment No. 1, dated July 19, 2013, to the Devon Energy Corporation Non-Qualified Deferred Compensation Plan (as Amended and Restated Effective January 1, 2013).*	
		
  10.12	  	Devon Energy Corporation Amendment No. 2, dated July 26, 2013, to the Devon Energy Corporation Non-Qualified Deferred Compensation Plan (as Amended and Restated Effective January 1, 2013).*	
		
  10.13	  	Devon Energy Corporation Amendment No. 3, dated December 16, 2013, to the Devon Energy Corporation Non-Qualified Deferred Compensation Plan (as Amended and Restated Effective January 1, 2013).*	
		
  10.14	  	Devon Energy Corporation Benefit Restoration Plan (amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.15 to Registrant’s Form 10-K, filed February 24, 2012).*	
		
  10.15	  	Devon Energy Corporation Defined Contribution Restoration Plan (amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.16 to Registrant’s Form 10-K, filed February 24, 2012).*	
		
  10.16	  	Devon Energy Corporation Supplemental Contribution Plan (amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.17 to Registrant’s Form 10-K, filed February 24, 2012).*	
		
  10.17	  	Devon Energy Corporation Supplemental Executive Retirement Plan (amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.18 to Registrant’s Form 10-K, filed February 24, 2012).*	
		
  10.18	  	Devon Energy Corporation Supplemental Retirement Income Plan (amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.19 to Registrant’s Form 10-K, filed February 24, 2012).*	
		
  10.19	  	Devon Energy Corporation Incentive Savings Plan (incorporated by reference to Registrant’s Form S-8 Registration No. 333-179181, filed January 26, 2012).*	
 
109

Table of Contents

Exhibit No.	  	Description	
		
  10.20	  	Amended and Restated Form of Employment Agreement between Registrant and Jeffrey A. Agosta, David A. Hager, R. Alan Marcum, John Richels, Frank W. Rudolph, Darryl G. Smette and Lyndon C. Taylor dated December 15, 2008 (incorporated by reference to Exhibit 10.19 to Registrant’s Form 10-K filed February 27, 2009).*	
		
  10.21	  	Form of Amendment No. 1 to the Amended and Restated Employment Agreement, incorporated by reference to Exhibit 10.19 to Registrant’s Form 10-K filed February 27, 2009, between Registrant and Jeffrey A. Agosta, David A. Hager, R. Alan Marcum, John Richels, Frank W. Rudolph, Darryl G. Smette and Lyndon C. Taylor dated April 19, 2011. (incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K filed April 25, 2011).*	
		
  10.22	  	Form of Employment Agreement between Registrant and Tony D. Vaughn dated June 10, 2013 (Amended and Restated Form of Employment Agreement dated December 15, 2008, (Exhibit 10.20 above), as amended by Amendment No. 1 thereto dated April 19, 2011, (Exhibit 10.21 above)).*	
		
  10.23	  	Form of Notice of Grant of Performance Restricted Stock Award and Award Agreement under the 2009 Long-Term Incentive Plan (as amended and restated June 6, 2012) between Registrant and Jeffrey A. Agosta, David A. Hager, R. Alan Marcum, J. Larry Nichols, John Richels, Frank W. Rudolph, Darryl G. Smette and Lyndon C. Taylor for performance based restricted stock awarded (incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K filed December 7, 2011).*	
		
  10.24	  	Form of Notice of Grant of Performance Restricted Stock Award and Award Agreement under the 2009 Long-Term Incentive Plan (as amended and restated June 6, 2012) between Registrant and Jeffrey A. Agosta, David A. Hager, R. Alan Marcum, John Richels, Frank W. Rudolph, Darryl G. Smette, Lyndon C. Taylor and Tony D. Vaughn for performance based restricted stock awarded (incorporated by reference to Exhibit 10.16 to Registrant’s Form 10-K filed February 21, 2013).*	
		
  10.25	  	Form of Notice of Grant of Performance Restricted Stock Award and Award Agreement under the 2009 Long-Term Incentive Plan (as amended and restated June 6, 2012) between Registrant and David A. Hager, R. Alan Marcum, John Richels, Frank W. Rudolph, Darryl G. Smette, Lyndon C. Taylor and Tony D. Vaughn for performance based restricted stock awarded.*	
		
  10.26	  	Form of Notice of Grant of Performance Share Unit Award and Award Agreement under the 2009 Long-Term Incentive Plan (as amended and restated June 6, 2012) between Registrant and Jeffrey A. Agosta, David A. Hager, R. Alan Marcum, John Richels, Frank W. Rudolph, Darryl G. Smette and Lyndon C. Taylor for performance based restricted share units awarded (incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K filed December 7, 2011).*	
		
  10.27	  	Form of Notice of Grant of Performance Share Unit Award and Award Agreement under the 2009 Long-Term Incentive Plan (as amended and restated June 6, 2012) between Registrant and Jeffrey A. Agosta, David A. Hager, R. Alan Marcum, John Richels, Frank W. Rudolph, Darryl G. Smette, Lyndon C. Taylor and Tony D. Vaughn for performance based restricted share units awarded (incorporated by reference to Exhibit 10.17 to Registrant’s Form 10-K filed February 21, 2013).*	
		
  10.28	  	Form of Notice of Grant of Performance Share Unit Award and Award Agreement under the 2009 Long-Term Incentive Plan (as amended and restated June 6, 2012) between Registrant and David A. Hager, R. Alan Marcum, John Richels, Frank W. Rudolph, Darryl G. Smette, Lyndon C. Taylor and Tony D. Vaughn for performance based restricted share units awarded.*	
		
  10.29	  	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 Tony D. Vaughn for incentive stock options granted (incorporated by reference to Exhibit 10.15 to Registrant’s Form 10-K filed February 25, 2011).*	
 
110

Table of Contents

Exhibit No.	  	Description	
		
  10.30	  	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 Tony D. Vaughn for nonqualified stock options granted (incorporated by reference to Exhibit 10.16 to Registrant’s Form 10-K filed February 25, 2011).*	
		
  10.31	  	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).*	
		
  10.32	  	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 Tony D. Vaughn for restricted stock awards (incorporated by reference to Exhibit 10.18 to Registrant’s Form 10-K filed February 25, 2011).*	
		
  10.33	  	Form of Notice of Grant of Restricted Stock Award Agreement under the 2009 Long-Term Incentive Plan between Registrant and all Non-Management Directors for restricted stock awards.*	
		
  10.34	  	Form of Letter Agreement amending the restricted stock award agreements and nonqualified stock option agreements under the 2009 Long-Term Incentive Plan and the 2005 Long-Term Incentive Plan between Registrant and J. Larry Nichols, John Richels and Darryl G. Smette (incorporated by reference to Exhibit 10.22 to Registrant’s Form 10-K filed February 25, 2011).*	
		
  10.35	  	Amendment to Incentive Stock Option Award Agreement between Registrant and J. Larry Nichols dated December 19, 2012, amending the Incentive Stock Option Agreements under the 2009 Long-Term Incentive Plan between Registrant and J. Larry Nichols (incorporated by reference to Exhibit 10.24 to Registrant’s Form 10-K filed February 21, 2013). *	
		
  12	  	Statement of computations of ratio of earnings to fixed charges.	
		
  21	  	Registrant’s Significant Subsidiaries.	
		
  23.1	  	Consent of KPMG LLP.	
		
  23.2	  	Consent of LaRoche Petroleum Consultants, Ltd.	
		
  23.3	  	Consent of Deloitte.	
		
  31.1	  	Certification of principal executive officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.	
		
  31.2	  	Certification of principal financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.	
		
  32.1	  	Certification of principal executive officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.	
		
  32.2	  	Certification of principal financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.	
		
  99.1	  	Report of LaRoche Petroleum Consultants, Ltd.	
		
  99.2	  	Report of Deloitte.	
		
101.INS	  	XBRL Instance Document.	
 
111

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Exhibit No.	  	Description	
		
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	
 
112

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 28, 2014
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	  	President, Chief Executive Officer and	  	February 28, 2014	
	 	John Richels	  	Director	  		
	 		  	(Principal executive officer)	  		
				
	 	/s/ THOMAS L. MITCHELL	  	Executive Vice President	  	February 28, 2014	
	 	Thomas L. Mitchell	  	and Chief Financial Officer
(Principal financial officer and principal accounting officer)	  		
				
	 	/s/ J. LARRY NICHOLS	  	Executive Chairman of the Board	  	February 28, 2014	
	 	J. Larry Nichols	  		  		
				
	 	/s/ BARBARA M. BAUMANN	  	Director	  	February 28, 2014	
	 	Barbara M. Baumann	  		  		
				
	 	/s/ JOHN E. BETHANCOURT	  	Director	  	February 28, 2014	
	 	John E. Bethancourt	  		  		
				
	 	/s/ ROBERT H. HENRY	  	Director	  	February 28, 2014	
	 	Robert H. Henry	  		  		
				
	 	/s/ JOHN A. HILL	  	Director	  	February 28, 2014	
	 	John A. Hill	  		  		
				
	 	/s/ MICHAEL M. KANOVSKY	  	Director	  	February 28, 2014	
	 	Michael M. Kanovsky	  		  		
				
	 	/s/ ROBERT A. MOSBACHER, JR.	  	Director	  	February 28, 2014	
	 	Robert A. Mosbacher, Jr.	  		  		
				
	 	/s/ DUANE C. RADTKE	  	Director	  	February 28, 2014	
	 	Duane C. Radtke	  		  		
				
	 	/s/ MARY P. RICCIARDELLO	  	Director	  	February 28, 2014	
	 	Mary P. Ricciardello	  		  		
 
113

Table of Contents
INDEX TO EXHIBITS

Exhibit No.	  	Description	
		
  10.11	  	Devon Energy Corporation Amendment No. 1, dated July 19, 2013, to the Devon Energy Corporation Non-Qualified Deferred Compensation Plan (as Amended and Restated Effective January 1, 2013).*	
		
  10.12	  	Devon Energy Corporation Amendment No. 2, dated July 26, 2013, to the Devon Energy Corporation Non-Qualified Deferred Compensation Plan (as Amended and Restated Effective January 1, 2013).*	
		
  10.13	  	Devon Energy Corporation Amendment No. 3, dated December 16, 2013, to the Devon Energy Corporation Non-Qualified Deferred Compensation Plan (as Amended and Restated Effective January 1, 2013).*	
		
  10.22	  	Form of Employment Agreement between Registrant and Tony D. Vaughn dated June 10, 2013 (Amended and Restated Form of Employment Agreement dated December 15, 2008, (Exhibit 10.20 above), as amended by Amendment No. 1 thereto dated April 19, 2011, (Exhibit 10.21 above)).*	
		
  10.25	  	Form of Notice of Grant of Performance Restricted Stock Award and Award Agreement under the 2009 Long-Term Incentive Plan (as amended and restated June 6, 2012) between Registrant and David A. Hager, R. Alan Marcum, John Richels, Frank W. Rudolph, Darryl G. Smette, Lyndon C. Taylor and Tony D. Vaughn for performance based restricted stock awarded.*	
		
  10.28	  	Form of Notice of Grant of Performance Share Unit Award and Award Agreement under the 2009 Long-Term Incentive Plan (as amended and restated June 6, 2012) between Registrant and David A. Hager, R. Alan Marcum, John Richels, Frank W. Rudolph, Darryl G. Smette, Lyndon C. Taylor and Tony D. Vaughn for performance based restricted share units awarded.*	
		
  10.33	  	Form of Notice of Grant of Restricted Stock Award Agreement under the 2009 Long-Term Incentive Plan between Registrant and all Non-Management Directors for restricted stock awards.*	
		
  12	  	Statement of computations of ratio of earnings to fixed charges.	
		
  21	  	Registrant’s Significant Subsidiaries.	
		
  23.1	  	Consent of KPMG LLP.	
		
  23.2	  	Consent of LaRoche Petroleum Consultants, Ltd.	
		
  23.3	  	Consent of Deloitte.	
		
  31.1	  	Certification of principal executive officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.	
		
  31.2	  	Certification of principal financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.	
		
  32.1	  	Certification of principal executive officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.	
		
  32.2	  	Certification of principal financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.	
		
  99.1	  	Report of LaRoche Petroleum Consultants, Ltd.	
		
  99.2	  	Report of Deloitte.	
 
114

Table of Contents

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	
 
115

Exhibit 10.11
AMENDMENT 2013-1
TO THE
DEVON ENERGY CORPORATION
NON-QUALIFIED DEFERRED COMPENSATION PLAN
The Devon Energy Corporation Non-Qualified Deferred Compensation Plan (the “ Plan ”) is amended, effective January 1, 2013, as follows:
1. Section 5.1 of the Plan (“ Supplemental Company Contributions ”) is amended in its entirety to read as follows:
“5.1 Supplemental Company Contributions . For each Plan Year, the Company will credit to the Account of each Participant a Supplemental Company Contribution in an amount equal to (a) minus (b) below:
(a) The Applicable Contribution Percentage multiplied by the Participant’s Base Salary and Bonus.
(b) The Applicable Contribution Percentage multiplied by such Participant’s “eligible 401(k) compensation” which, for purposes of this Article V, shall be defined as the Participant’s Base Salary and Bonus less the Participant’s Deferred Amount up to the IRS Limitations for the applicable Plan Year.
Provided, however, that, notwithstanding anything in this Section 5.1 to the contrary, the Supplemental Company Contribution cannot exceed the Participant’s Deferred Amount for the applicable Plan Year; provided further that the Supplemental Company Contribution will only be credited to the Account of a Participant for any Plan Year if such Participant has made the maximum deferral of compensation as permitted under Sections 402(g) and 414(v) of the Code to the Qualified Plan (or, if less, the maximum deferral of compensation as permitted under the terms of the Qualified Plan) and the Company has made the maximum matching contribution to the Qualified Plan as permitted under Section 401(m) of the Code and the Qualified Plan.”
2. Section 7.2 of the Plan (“ Adjustment of Accounts ”) is amended to amend the third sentence thereof (beginning with “Supplemental Company Contributions…”) in its entirety to read as follows:
“Supplemental Company Contributions shall be credited to a Participant’s Account on such date or dates as the Committee specifies and shall be credited to the applicable subaccount within such Account by reference to the applicable Plan Year; provided, however, that under no circumstances shall Supplemental Company Contributions be credited to the Account of a Participant before such Participant has made the maximum deferral of compensation as permitted under Sections 402(g) and 414(v) of the Code to the Qualified Plan (or, if less, the maximum deferral of compensation as permitted under the terms of the Qualified Plan) and the Company has made the maximum matching contribution to the Qualified Plan as permitted under Section 401(m) of the Code and the Qualified Plan. Supplemental Company Contributions shall be subject to the vesting requirements described in Section 7.4.”
 
1

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2

IN WITNESS WHEREOF, Devon Energy Corporation (acting through its authorized delegate) has caused this Amendment 2013-1 to the Devon Energy Corporation Non-Qualified Deferred Compensation Plan to be executed this 19 day of July 2013.

DEVON ENERGY CORPORATION	
		
By:	 	/s/ Frank W. Rudolph	
	 	 	
Name:	 	Frank W. Rudolph	
Title:	 	Executive Vice President, Human Resources	
[ Signature Page to Amendment to the Devon Energy Corporation Non-Qualified Deferred Compensation Plan ]

Exhibit 10.12
AMENDMENT 2013-2
TO THE
DEVON ENERGY CORPORATION
NON-QUALIFIED DEFERRED COMPENSATION PLAN
The Devon Energy Corporation Non-Qualified Deferred Compensation Plan (the “ Plan ”) is amended, effective January 1, 2013, as follows:
1. Section 5.1 of the Plan (“ Supplemental Company Contributions ”) is amended in its entirety to read as follows:
“5.1 Supplemental Company Contributions . For each calendar quarter of the Plan Year (i.e., the quarters ending March 31, June 30, September 30 and December 31), the Company will credit to the Account of each Participant a Supplemental Company Contribution in an amount equal to (a) minus (b) minus (c) below:
(a) The Applicable Contribution Percentage multiplied by the Participant’s Base Salary and Bonus for the Plan Year up through the applicable calendar quarter.
(b) The Applicable Contribution Percentage multiplied by such Participant’s “eligible 401(k) compensation” for the Plan Year up through the applicable calendar quarter, which, for purposes of this Article V, shall be defined as the Participant’s Base Salary and Bonus less the Participant’s Deferred Amount (each for the Plan Year up through the applicable calendar quarter) up to the IRS Limitations for the applicable Plan Year.
(c) The Supplemental Company Contribution, if any, previously credited to the Account of the Participant for the Plan Year.
Provided, however, that, notwithstanding anything in this Section 5.1 to the contrary, the Supplemental Company Contribution cannot exceed the Participant’s Deferred Amount for the applicable Plan Year; provided further that the Supplemental Company Contribution will only be credited to the Account of a Participant for any calendar quarter of the Plan Year if as of the last day of the applicable calendar quarter of the Plan: (i) such Participant has made the maximum deferral of compensation as permitted under Sections 402(g) and 414(v) of the Code to the Qualified Plan (or, if less, the maximum deferral of compensation as permitted under the terms of the Qualified Plan); (ii) the Company has made the maximum matching contribution to the Qualified Plan as permitted under Section 401(m) of the Code and the Qualified Plan and (iii) such Participant is an Eligible Employee.
Notwithstanding the foregoing, for the Plan Year beginning January 1, 2013, the Company shall make a Supplemental Company Contribution for the six-month period beginning January 1, 2013 and ending June 30, 2013 (and the Company shall not be required to make a Supplemental Company Contribution for the calendar quarter ending March 31, 2013); provided, however, that the Participant otherwise satisfies all requirements set forth in this Section 5.1 and the Participant is an Eligible Employee on June 30, 2013.”
 
1

2. Section 7.2 of the Plan (“ Adjustment of Accounts ”) is amended to amend the third sentence thereof (beginning with “Supplemental Company Contributions...”) in its entirety to read as follows:
“Supplemental Company Contributions shall be credited to a Participant’s Account on such date or dates as the Committee specifies and shall be credited to the applicable subaccount within such Account by reference to the applicable Plan Year; provided, however, that under no circumstances shall Supplemental Company Contributions be credited to the Account of a Participant before such Participant has made the maximum deferral of compensation as permitted under Sections 402(g) and 414(v) of the Code to the Qualified Plan (or, if less, the maximum deferral of compensation as permitted under the terms of the Qualified Plan), the Company has made the maximum matching contribution to the Qualified Plan as permitted under Section 401(m) of the Code and the Qualified Plan, and the Participant has otherwise satisfied the requirements set forth in Section 5.1 to receive a Supplemental Company Contribution. Supplemental Company Contributions shall be subject to the vesting requirements described in Section 7.4.”
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2

IN WITNESS WHEREOF, Devon Energy Corporation (acting through its authorized delegate) has caused this Amendment 2013-2 to the Devon Energy Corporation Non-Qualified Deferred Compensation Plan to be executed this 26 th day of July 2013.

DEVON ENERGY CORPORATION	
		
By:	 	/s/ Frank W. Rudolph	
	 	 	
Name:	 	Frank W. Rudolph	
Title:	 	Executive Vice President, Human Resources	
[ Signature Page to Amendment to the Devon Energy Corporation Non-Qualified Deferred Compensation Plan ]

Exhibit 10.13
AMENDMENT 2013-3
TO THE
DEVON ENERGY CORPORATION
NON-QUALIFIED DEFERRED COMPENSATION PLAN
The Devon Energy Corporation Non-Qualified Deferred Compensation Plan (the “ Plan ”) is amended, effective January 1, 2013, as follows:
1. Section 6.2 of the Plan (“ Method of Payment Upon Separation from Service ”) is amended to delete the second sentence thereof and replace it in its entirety to read as follows:
“A Participant may designate payment in the form of a single lump sum payment or quarterly installment payments payable over a period of one or more years as made available to the Participant on the deferral election form provided for such purpose.”
2. Section 6.3 of the Plan (“ Method of Payment Upon a Change of Control Payment Event ”) is amended to delete the second sentence thereof and replace it to read as follows:
“A Participant may designate payment in the form of a single lump sum payment or quarterly installment payments payable over a period of one or more years as made available to the Participant on the deferral election form provided for such purpose, such designation to be made on the election form that is submitted for such Plan Year in accordance with Section 4.2.”
3. Subparagraph (a) of Section 6.5 of the Plan (“ Payment Upon Scheduled In-Service Withdrawal ”) is amended to delete the first sentence thereof and replace it in its entirety to read as follows:
“The Participant may elect either a lump sum payment or quarterly installment payments payable over a period of one or more years as made available to the Participant on the deferral election form provided for such purpose.”
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1

IN WITNESS WHEREOF, Devon Energy Corporation (acting through its authorized delegate) has caused this Amendment 2013-3 to the Devon Energy Corporation Non-Qualified Deferred Compensation Plan to be executed this 16 th day of December 2013.

DEVON ENERGY CORPORATION	
		
By:	 	/s/ Frank W. Rudolph	
	 	 	
Name:	 	Frank W. Rudolph	
Title:	 	Executive Vice President, Human Resources	
[ Signature Page to Amendment to the Devon Energy Corporation Non-Qualified Deferred Compensation Plan ]

Exhibit 10.22
EMPLOYMENT AGREEMENT
This Employment Agreement (this “ Agreement ”) is effective June 10, 2013 (the “ Effective Date ”) by and between Devon Energy Corporation (the “ Company ”) and                      (the “ Executive ”).
WHEREAS, the parties desire to enter into this Agreement relating to the Company’s employment of the Executive.
NOW, THEREFORE, IT IS HEREBY AGREED AS FOLLOWS:
1. Term of Agreement; Defined Terms .
(a) Term of Agreement . This Agreement shall not have any specific duration and shall continue in full force and effect unless and until (i) the Executive’s employment is terminated by either party in accordance with Section 3, and (ii) all obligations and liabilities of the parties arising in connection with such termination or otherwise accruing under this Agreement have been fully satisfied. Notwithstanding any contrary provision in this Agreement, nothing in this Agreement constitutes a guarantee of continued employment but instead provides for certain rights and benefits during the Executive’s employment with the Company and if such employment terminates.
(b) Defined Terms . Capitalized terms used throughout this Agreement have the meaning ascribed to such terms in Exhibit “A” attached hereto.
2. Terms, Conditions, and Benefits of Employment .
(a) Position and Duties . The Executive shall serve as                      of the Company or in such other substantially equivalent position(s) requested by the Board with the appropriate authority, duties, and responsibilities attendant to such position(s). The Executive shall devote his full working time, best efforts, abilities, knowledge, and experience to the Company’s business and affairs as necessary to faithfully perform his duties, responsibilities, and authorities under this Agreement. The Executive may, without violating this Agreement, (i) serve on corporate, civic, charitable, or industry boards or committees, (ii) deliver lectures, fulfill speaking engagements, or teach at educational institutions, or (iii) manage personal investments, so long as such activities do not significantly interfere with the Executive’s obligations under this Agreement; provided, however , that the Executive shall not serve on the board of any business, hold any other position with any business, or otherwise engage in any business activity, without the prior written consent of his Supervisor. If the Executive conducted any such activities as of the Effective Date, then the continuation of such activities (or similar activities for the same organization) after the Effective Date shall be permitted.
(b) Annual Base Salary . The Executive shall receive an Annual Base Salary, which may be increased from time to time in the Company’s discretion but shall not be reduced unless the Company reduces the salaries of similarly situated executives, in which case the Annual Base Salary may be reduced by the same percentage and shall be restored to its prior level when, and to the same extent as, the Company restores the salaries of such similarly situated executives. Any increase in Annual Base Salary shall not limit or reduce any other obligation owed to the Executive under this Agreement.
(c) Annual Bonus . The Executive shall be eligible to participate in a program in which he may receive an Annual Bonus. If the Compensation Committee establishes a target for the Annual Bonus as a percentage of the Annual Base Salary, then such target shall not be less than the targets for similarly situated executives of the Company. Unless otherwise payable under Sections 4(b)(i)(B) or 4(c), the Executive must be actively employed for the entire year upon which the Annual Bonus is based to be eligible to receive such Annual Bonus.

(d) Incentive Awards . In the Compensation Committee’s discretion, the Company may provide the Executive with annual equity grants, or cash awards in lieu of such grants, which shall be comparable to the grants or awards made to similarly situated executives of the Company.
(e) Disability . The Company shall provide the same disability insurance coverage benefits to the Executive as provided to similarly situated executives of the Company. If, during his employment with the Company, the Executive receives Short-Term Disability Payments, then the Company shall pay the Executive the difference between the Short-Term Disability Payments and the portion of his then-current Annual Base Salary the Company would have paid him while receiving Short-Term Disability Payments. If the Executive is Disabled during his employment with the Company and otherwise entitled to receive salary and bonus payments under this Agreement, then any such salary and bonus payments (or such payments in lieu of salary and bonus payments) shall be reduced by the amount of any Short-Term Disability Payments received by the Executive for the period of short-term disability and any benefits paid for the same period under the Company-provided disability insurance coverage.
(f) Expenses . The Company shall reimburse the Executive for all reasonable business-related expenses incurred and accounted for in accordance with its standard policies and procedures for expense reimbursements and deductibles under Section 162 of the Code.
(g) Other Employee Benefits . During the term of this Agreement, the Executive shall be entitled to participate in all employee benefit, welfare, and other plans, practices, policies, and programs applicable to similarly situated executives of the Company, subject to the terms of such plans, practices, policies, and programs as they may be amended from time to time. During any CIC Period, the Company shall continue to provide the Executive (and the Executive’s dependents, if applicable) with the same level of health (including dental), disability, and life (including accidental death/dismemberment) insurance benefits as were provided to the Executive (and the Executive’s dependents, if applicable) immediately before the Change in Control upon terms and conditions that are not materially less favorable to the Executive than as in effect immediately before the Change in Control with respect to each of such health, disability, and life insurance coverages. Beginning on a Change in Control and continuing at all times thereafter, the Company shall not modify the requirements for eligibility for coverage or the benefits under the Retiree Medical Benefit Plan to adversely affect the Executive’s right to coverage or benefits for the Executive and the Executive’s dependents, if applicable.
(h) Fringe Benefits . To the extent not otherwise covered under this Agreement, the Company shall provide the Executive with fringe benefits and perquisites to the same extent and on the same terms as those benefits are provided by the Company from time to time to similarly situated executives of the Company.
3. Termination of Employment; Suspensions; Change in Control .
(a) Termination Upon Death . The Executive’s employment with the Company shall terminate immediately upon the Executive’s death.
 
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(b) Reassignment of Duties and Termination Due to the Executive Becoming Disabled .
(i) Reassignment . Whether or not the Executive is Disabled, the Company may reassign his duties during any time he has become physically or mentally incapable of performing his essential job functions with or without reasonable accommodation or job protection as required by law and no such reassignment shall be deemed Good Reason for the Executive to terminate his employment under Section 3(d).
(ii) Termination . If the Executive becomes Disabled, then the Company may give the Executive written notice of its intent to terminate his employment, in which case such employment shall terminate effective on the thirtieth (30th) day after receipt of such notice as long as the Executive has not been medically released and returned to full-time duty before such thirtieth (30th) day.
(c) Termination by the Company; Cause . The Company may terminate the Executive’s employment with the Company at any time whether with or without Cause. If the Company terminates the Executive’s employment for Cause, then such termination shall not be effective unless and until the Board (i) provides reasonable notice and an opportunity to the Executive and his counsel (if applicable) to be heard at a meeting called to discuss the Executive’s employment and (ii) subsequently provides the Executive with a copy of a resolution duly adopted by at least a two-thirds (2/3) majority of the Board specifying that the Board has determined in good faith that Cause exists for terminating the Executive’s employment.
(d) Termination by the Executive; Good Reason . The Executive may terminate his employment with the Company at any time whether with or without Good Reason. If the Executive believes Good Reason exists for terminating his employment, then he shall give the Company written notice of the acts or omissions constituting Good Reason within thirty (30) days after learning of such acts or omissions constituting Good Reason (the “ Good Reason Notice ”). No termination of employment for Good Reason shall be effective unless (i) within thirty (30) days after receiving the Good Reason Notice, the Company fails to either cure such acts or omissions or notify the Executive of the intended method of cure, and (ii) the Executive delivers a Notice of Termination to the Company and subsequently resigns within thirty (30) days after the Company’s deadline in Section 3(d)(i) expires. Notwithstanding the previous sentence and at the Company’s request, the Executive shall provide services consistent with his then-current authority, duties, and responsibilities for up to ninety (90) days after having provided the Good Reason Notice to the Company.
(e) Paid Suspensions . Notwithstanding any contrary provision in this Agreement, the Company may suspend the Executive with pay for up to thirty (30) days pending an investigation authorized by the Company or the Board, or pursued by, or at the request of, a governmental authority, to determine whether the Executive has engaged in acts or omissions constituting Cause. Any such paid suspension shall not constitute Good Reason for the Executive to terminate his employment under Section 3(d). The Executive shall cooperate with the Company in connection with any such investigation. If the Executive’s employment is subsequently terminated for Cause in connection with such investigation, then the Executive shall repay any amounts paid by the Company to the Executive during such paid suspension.
(f) Effect of a Change in Control on Timing of Termination Date . If the Company terminates the Executive’s employment other than for Cause or the Executive becoming Disabled and a Change in Control occurs following the Termination Date, then such Change in Control shall be deemed to have occurred immediately prior to the Termination Date if either (i) the Termination Date occurs following the execution of an agreement that provides for a transaction or transactions that, if consummated, constitutes such Change in Control, or (ii) the Executive reasonably demonstrates that such termination was either (A) requested by a third party who had indicated an intention or taken steps reasonably calculated to effect the Change in Control or who effectuates such Change in Control, or (B) was otherwise in connection with, or in anticipation of, such Change in Control.
 
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(g) Notice of Termination . Any termination of the Executive’s employment by the Company or by the Executive shall be effective only when communicated by a Notice of Termination given to the other party in accordance with Section 15(d). In the event of a termination by the Executive for Good Reason, a Notice of Termination shall be effective only if given within the time limit established by Section 3(d).
(h) Effect of Termination and Duties Upon Termination . If, on the Termination Date, the Executive is a member of the board of directors (or any similar governing body) or an officer of the Company or any Affiliate, or holds any other position with the Company or an Affiliate, then the Executive shall resign and be deemed to have resigned from all such positions as of the Termination Date. Between the date a Notice of Termination is delivered and the Termination Date, the Executive shall continue to perform his duties under this Agreement and such services for the Company as are necessary and appropriate for a smooth transition to the Executive’s replacement, if any. Notwithstanding the foregoing sentence, the Company may relieve the Executive from further duties under this Agreement after receiving a Notice of Termination; provided, however , that prior to the Termination Date, the Executive shall continue to be treated as a Company employee for other purposes and the Executive’s rights to compensation or benefits shall not be reduced by reason of the relief. Upon the Termination Date, the Executive shall return to the Company any keys, credit cards, passes, confidential documents or material, or other property belonging to the Company, and all writings, files, records, correspondence, notebooks, notes, and other documents and things (including any copies thereof) containing any Confidential Information.
4. Obligations of the Company Upon Termination .
(a) Accrued Obligations . Upon any termination of the Executive’s employment for any reason, the Company shall pay the Executive (i) his accrued Annual Base Salary and accrued, unused vacation through the Termination Date in a lump sum in cash within thirty (30) days after the Termination Date, and (ii) if the Executive is actively employed during the entire year upon which such Annual Bonus is based under Section 2(c) before the Termination Date, the Annual Bonus at the same time as such bonuses are paid to similarly situated executives of the Company but in no event later than two and one-half (2  1 ⁄ 2 ) months after the end of the taxable year in which any substantial risk of forfeiture with respect to such bonus lapses (the payments in (i) and (ii) shall be referred to as the “ Accrued Obligations ”).
(b) Good Reason; Other Than for Cause, Death, or Becoming Disabled . If (x) the Company terminates the Executive’s employment other than for Cause, the Executive’s death, or the Executive becoming Disabled, or (y) the Executive terminates his employment for Good Reason, then the Company shall, in addition to the payment of the Accrued Obligations, have the following obligations to the Executive:
(i) the Company shall pay the Executive within thirty (30) days after the Termination Date
(A) a lump sum in cash equal to three (3) times the sum of:
(1) the greater of (x) the Executive’s then-current Annual Base Salary, or (y) the Executive’s Annual Base Salary at any time during the two (2) years before the Termination Date; and
 
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(2) the highest Annual Bonus received by the Executive within three (3) years before the Termination Date (or, if termination occurs during the CIC Period, the greater of (x) the highest Annual Bonus received by the Executive within three (3) years before the Termination Date, and (y) the highest Annual Bonus received by the Executive within three (3) years before the Change in Control); provided, however , if the Executive’s employment began in the same calendar year as the termination of such employment, then the Annual Bonus amount used for calculating the lump sum payment due shall be determined by the Compensation Committee in its discretion; and
(B) any applicable Prorated Annual Bonus; and
(ii) the Company shall provide the Executive
(A) for the period allowed under Section 4980B of the Code, with the same level of health and dental insurance benefits for the Executive (and his dependents, if applicable) upon substantially similar terms and conditions (including contributions required by the Executive for such benefits) as existed immediately before the Termination Date (or, if more favorable to the Executive, as such benefits and terms and conditions existed immediately before the Change in Control, if applicable); provided, however , if the Executive is not eligible to continue participating in the Company plans providing such benefits (including the Retiree Medical Benefit Plan), then the Company shall otherwise provide such benefits on the same after-tax basis as if continued participation had been permitted. The Company’s obligations under this subparagraph (A) shall apply against its coverage obligations under COBRA. Notwithstanding the foregoing, if the Executive becomes eligible to receive health and dental insurance benefits through subsequent employment, then the Executive shall ensure that a coordination of benefits occurs so that the medical and dental plan of the Executive’s new employer shall be responsible for such medical and dental benefits that are available under the new employer’s plans before any medical and dental benefits are provided pursuant to this subparagraph (A). This subparagraph (A) shall not limit the ability of the Company or an Affiliate to modify the terms of the Retiree Medical Benefit Plan for all participants who are similarly situated as the Executive, subject to the restrictions imposed by the plan;
(B) for three (3) years following the Termination Date, with the same level of life insurance benefits upon substantially similar terms and conditions (including contributions required by the Executive for such benefits) as existed immediately before the Termination Date (or, if more favorable to the Executive, as such benefits and terms and conditions existed immediately before the Change in Control); provided, however , if the Executive is not eligible to continue participating in the Company plans providing such life insurance benefits, then the Company shall otherwise provide such benefits on the same after-tax death benefit basis as if continued participation had been permitted; and
(C) within thirty (30) days after the Termination Date, with a payment in an amount equal to eighteen (18) times the monthly COBRA premium that applies to the Executive (and his dependents if such dependents are then covered by the Company’s medical plans on the Termination Date); and
(iii) the Company shall pay, or reimburse the Executive, for a reasonable amount of outplacement services from a mutually agreeable service provider for twelve (12) months following the Termination Date. The amount of such outplacement services shall be commensurate with the Executive’s title and position with the Company and other executives similarly situated in other companies within the Company’s peer industry group. Any reimbursement of such expenses shall be made by December 31 of the Executive’s taxable year following the year the expenses were incurred; and
(iv) if the Termination Date occurs during the CIC Period, then the Executive shall be deemed, for purposes of the Retiree Medical Benefit Plan, (i) to have earned three (3) years of service in
 
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addition to the Executive’s actual service at the Termination Date, and (ii) to be three (3) years older than his actual age on the Termination Date; provided, however , that the additional deemed service and age shall not be construed to reduce the Executive’s right to benefits under the Retiree Medical Benefit Plan that may otherwise be reduced by reason of such additional service or age. This paragraph (v) shall not limit the ability of the Company or an Affiliate to modify the Retiree Medical Benefit Plan for all participants who are similarly situated as the Executive, subject to the restrictions imposed by the plan and Section 2(g).
(c) Death or Disabled . If the Executive’s employment terminates due to death or because he is Disabled, then this Agreement shall terminate without further obligations to the Executive or his legal representatives, as applicable, under this Agreement, other than the obligation to pay, within thirty (30) days after the Termination Date, (i) the Accrued Obligations, and (ii) any applicable Prorated Annual Bonus.
(d) Cause; Other than for Good Reason . If the Executive’s employment is terminated for Cause or the Executive terminates his employment without Good Reason, then this Agreement shall terminate without further obligations to the Executive under this Agreement other than for payment of the Accrued Obligations.
(e) Application of Section 409A of the Code . Notwithstanding the above paragraphs of this Section 4, if the Company determines that (i) the Executive is a “specified employee” within the meaning of Section 409A of the Code (“ Section 409A ”) as of the date of his “separation from service” as defined by Section 409A (“ Separation from Service ”), and (ii) any amount of any payment to be made under this Section 4 is subject to Section 409A, then such amount shall not be paid to the Executive until six (6) months after the date of his Separation from Service (or, if earlier, the date of his death). In such case, the portion of the payment so delayed shall be paid in a single lump sum in cash on the first (1st) day of the seventh (7th) month following the Executive’s Separation from Service (or, if earlier, upon his death).
(f) General Release . The Company’s obligation to make the payments described under Section 4(b) shall be conditioned on the Executive signing and not revoking the general form of release attached as Exhibit “B” or such other form acceptable to the Company within the time periods provided in such release. The Company shall not be required to make any payment under Section 4(b) until the period for the Executive to revoke the release has expired.
5. Non-Exclusivity of Rights . Except as specifically provided in Sections 4(b)(ii)(A) and 4(b)(iv), nothing in this Agreement shall prevent or limit the Executive’s right to participate in any plan, program, policy, or practice provided by the Company or any Affiliate and for which the Executive may qualify, nor shall anything in this Agreement limit or otherwise affect such rights as the Executive may have under any other contract or agreement with the Company or any Affiliate. Amounts that are vested benefits or that the Executive is otherwise entitled to receive under any plan, policy, practice, or program of, or any contract or agreement with, the Company or any Affiliate at or after the Termination Date shall be payable in accordance with such plan, policy, practice, program, contract, or agreement, except as explicitly modified by this Agreement; provided, however , that the Executive shall not be eligible for severance benefits under any other severance program, policy, practice, or plan of the Company or any Affiliate providing benefits upon involuntary termination of employment.
6. Full Settlement . The Company’s payment and other obligations under this Agreement shall not be affected by any set-off, counterclaim, recoupment, defense, or other claim, right, or action against the Executive or others. The Executive shall have no obligation to seek employment or otherwise mitigate his damages under this Agreement and amounts payable to the Executive under this Agreement shall not be reduced whether or not the Executive obtains other employment, except as provided in Section 4(b)(ii) of this Agreement.
 
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7. Section 4999 of the Code Excise Tax; Cap on Payments.
(a) Cap on Payments . If any payment, benefit or distribution by the Company, any Affiliate or a trust established by the Company or any Affiliate to or for the benefit of the Executive (whether pursuant to this Agreement or otherwise) (each, a “ Payment ” or, collectively, the “ Payments ”) is subject to an excise tax imposed by the Code, including pursuant to Section 4999 of the Code, or the Executive incurs any interest or penalties with respect to such an excise tax (such excise tax and any such interest and penalties shall be referred to as the “ Excise Tax ”), the Payments under Section 4 of this Agreement (the “ Agreement Payments ”) shall be reduced (but not below zero) to an amount that maximizes the aggregate present value (determined in accordance with Section 280G(d)(4) of the Code) of the Payments without causing any Payment to be subject to the limitation of deduction under Section 280G of the Code or the imposition of any Excise Tax, with such reduction being made (i) on a nondiscretionary basis so as to minimize the reduction in the economic value to the Executive, (ii) in a manner consistent with the requirements of Section 409A, and (iii) on a pro-rata basis where more than one Agreement Payment has the same present value for this purpose and they are payable at different times; provided, however , if the net amount retained by the Executive from all the Payments after the reductions described above in this Section 7(a) would be less than the net amount retained by the Executive from all the Payments after the Executive’s payment of any Excise Tax, the Agreement Payments shall not be reduced as set forth in this Section 7(a).
(b) Determinations . All determinations to be made under this Section 7 shall be made by a nationally recognized certified public accounting firm designated by the Company immediately prior to the Change in Control (the “ Accounting Firm ”). The Accounting Firm shall provide its determinations and any supporting calculations to the Company and the Executive within ten (10) days of the termination date or Change in Control, as applicable. Any such determination by the Accounting Firm shall be binding upon the Company and the Executive. All of the fees and expenses of the Accounting Firm in performing the determinations referred to in this Section 7 shall be borne solely by the Company.
8. Confidential Information and Non-Solicitation .
(a) Confidential Information . Given his position and employment with the Company, the Executive acknowledges that he will be using, acquiring, and adding to Confidential Information of a special and unique nature and value to the Company and its strategic plan and financial operations. The Executive further acknowledges that all Confidential Information belongs exclusively to the Company, is material and proprietary, and is critical to the Company’s success. Accordingly, the Executive shall use Confidential Information only to the Company’s benefit and shall not at any time during or after his employment with the Company directly or indirectly disclose any Confidential Information to any person or use any Confidential Information for the Executive’s own benefit, for the benefit of others, or to the Company’s detriment,.
(b) Legally Required Disclosure . If any court or agency requests the Executive to disclose Confidential Information, then the Executive shall promptly notify the Company and take reasonable steps to prevent such disclosure until the Company receives such notice and has an opportunity to respond to such court or agency. If the Executive obtains information that may be subject to the attorney-client privilege of the Company or any Affiliate, then the Executive shall take reasonable steps to maintain the confidentiality of such information and to preserve such privilege.
 
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(c) Exceptions . Confidential Information shall not include knowledge that was acquired during the course of the Executive’s employment under this Agreement that is generally known to persons of the Executive’s experience in other companies in the same industry.
(d) Legal Proceedings . This Section 8 shall not unreasonably restrict the Executive’s ability to disclose Confidential Information in any legal proceeding involving any claim for breach or enforcement of this Agreement. If the parties dispute whether information may be disclosed in accordance with this Section 8(d), then the matter shall be considered an Employment Matter and decided in accordance with Section 10.
(e) Other Obligations . This Agreement supplements, rather than supplants, the Executive’s obligations under any Company policy relating to confidential information and any agreement of the Executive relating to confidentiality, inventions, copyrightable material, business and/or technical information, trade secrets, solicitation of employees, interference with business relationships, competition, and other similar matters that protect the business and operations of the Company or its Affiliates.
(f) Non-Solicitation . During his employment with the Company and for thirty-six (36) months following the date such employment terminates, regardless of the reason for such termination, the Executive shall not directly or indirectly hire, employ, solicit for employment, attempt to solicit for employment, or communicate with about changing employment, any person who was an employee of the Company or its Affiliate within six (6) months of such hiring, employing, soliciting, or communicating (the “ Non-Solicitation Obligation ”); provided, however , that the Non-Solicitation Obligation shall be modified as follows:
(i) if the Termination Date occurs during the CIC Period, then the Non-Solicitation Obligation shall expire on the Termination Date; and
(ii) if the Executive terminates his employment with the Company without Good Reason, then the Non-Solicitation Obligation shall expire twelve (12) months following the Termination Date.
(g) Remedies . The Executive acknowledges and agrees that the Company will have no adequate remedy at law and could be irreparably harmed if the Executive breaches or threatens to breach his obligations under this Section 8. The Company shall be entitled to equitable and/or injunctive relief to prevent any such breach or threatened breach and to specific performance in addition to any other available legal or equitable remedies. The Executive shall not, in any equity proceeding relating to the enforcement of this Section 8, raise the defense that the Company has an adequate remedy at law.
(h) Survival . The Executive’s obligations under this Section 8 shall survive any termination of the Executive’s employment or of this Agreement.
9. Assignment; Successors .
(a) Assignment . The Company’s rights and obligations under this Agreement may not be assigned to any entity other than an Affiliate without the Executive’s consent. The Executive’s duties, responsibilities, authorities, compensation, and benefits are personal to the Executive and may not be assigned to any person or entity without written consent from the Company other than by will or the laws of descent and distribution. This Agreement shall inure to the benefit of and be enforceable by the Executive’s legal representatives.
 
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(b) Successors and Assigns . This Agreement shall inure to the benefit of and be binding upon the Company and its successors and assigns.
(c) Assumption . The Company shall require any successor or assignee (whether direct or indirect, by purchase, merger, consolidation, or otherwise) to all or substantially all of the business and/or assets of the Company to assume expressly and agree to perform this Agreement in the same manner and to the same extent that the Company would be required to perform if no such succession or assignment had taken place.
10. Dispute Resolution and Guarantees of Payment .
(a) Mandatory Arbitration . Subject to Section 10(b), any Employment Matter shall be finally settled by arbitration in Oklahoma City, Oklahoma administered by the AAA under its Employment Arbitration Rules then in effect; provided, however , that the AAA’s Employment Arbitration Rules shall be modified as follows: (i) each arbitrator shall agree to treat as confidential evidence and other information presented, and (ii) there shall be no authority to award punitive damages or liquidated or indirect damages unless such damages could be awarded by a court of competent jurisdiction. The decision of the arbitrator(s) shall be enforceable in any court of competent jurisdiction.
(b) Injunctions and Enforcement of Arbitration Awards . Either party may bring an action or special proceeding in a state or federal court of competent jurisdiction in Oklahoma City, Oklahoma to enforce any arbitration award under Section 10(a). The Company also may bring such an action or proceeding, in addition to its rights under Section 10(a) and whether or not an arbitration proceeding has been or is ever initiated, to temporarily, preliminarily, or permanently enforce Sections 8 or 11. The Executive agrees that (i) violating Sections 8 or 11 would damage the Company in ways that cannot be measured or repaired, (ii) the Company shall be entitled to an injunction, restraining order, or other equitable relief restraining any actual or threatened violation of Sections 8 or 11, (iii) the Company shall not be required to post a bond or prove actual damages when seeking such an injunction, restraining order, or other equitable relief, and (iv) remedies at law for such violations would be inadequate.
(c) Waiver of Jury Trial . To the extent permitted by law, the parties waive any and all rights to a jury trial with respect to any Employment Matter.
(d) Attorney Fees.
(i) If (A) a claim for arbitration or a lawsuit in connection with an Employment Matter (an “ Employment Matter Claim ”) is filed by either of the parties, and (B) the Executive is ultimately successful in respect of one or more material claims or defenses brought, raised or pursued in connection with such Employment Matter Claim, then the Company shall reimburse the Executive for all legal fees and expenses reasonably incurred in connection with such Employment Matter Claim, provided that such legal fees are reasonable and are calculated on an hourly rather than a contingency fee basis, as well as all costs and expenses reasonably incurred in connection with pursuing or defending any such Employment Matter Claim. Except as provided in Section 10(d)(ii) below, the Company shall make such reimbursement to the Executive as soon as practicable following final resolution of the Employment Matter Claim, but no later than December 31 of the year immediately following the year of such resolution, provided that the Company receives appropriate documentation of such attorneys’ fees, costs, and expenses, which shall be provided by the Executive no later than the later of (x) December 31 of the year in which resolution occurs, or (y) sixty (60) days following the resolution of the Employment Matter Claim.
 
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(ii) If an Employment Matter Claim is filed by either of the parties during the CIC Period, or (B) an Employment Matter Claim has been filed prior to a Change in Control but has not been resolved as of the effective date of a Change in Control, then the Executive may submit his request for reimbursement of attorneys’ fees, costs and expenses on a monthly basis during the pendency of such Employment Matter Claim. Within sixty (60) days following the Company’s receipt of each such monthly request and appropriate documentation supporting such request for reimbursement of attorneys’ fees, costs and expenses, the Company shall reimburse the Executive (or pay directly to the Executive’s attorney) the Executive’s attorneys’ fees, costs and expenses that the Company is obligated, pursuant to Section 10(d)(i) above, to reimburse with respect to such Employment Matter Claim. In the event the Executive ultimately fails to be successful with respect to at least one of the Executive’s material claims or defenses brought, raised or pursued in connection with such contest or dispute, the Executive shall repay the Company the amount of any such reimbursement received in connection with such dispute in accordance with this Section 10(d) (without interest) as soon as practicable following the final resolution of such matter.
(e) Secondary Liability for Payment . If any Affiliate is not otherwise obligated to provide benefits to the Executive by this Agreement, then the Company shall take, and cause each such Affiliate (the “ Guarantors ”) to take, such actions as are necessary to cause the Guarantors to jointly and severally guarantee the payment of benefits otherwise due to the Executive under this Agreement if the Company fails to pay such benefit within thirty (30) days of the due date for such payment; provided, however , that no entity organized under the laws of any jurisdiction outside the United States shall have an obligation to enter into such guarantee. Each of the Guarantors shall be subrogated to the Executive’s rights under this Agreement to the extent of any payments by each such Guarantor to or on account of the Executive under this Section 10(e).
11. Non-Disparagement . The Executive shall not make any negative or disparaging comments regarding the Company or its Representatives or its or their respective performance, operations, or business practices, or otherwise take any action that could reasonably be expected to adversely affect the Company or such Representatives or their personal or professional reputations. The Executive may truthfully respond to inquiries by government agencies or to inquiries by any person through a subpoena or other valid judicial process without violating this Section 11, provided that the Executive delivers written notice of such required disclosure to the Company promptly before making such disclosure, unless such notice to the Company is prohibited by applicable law, court order, subpoena, process, or governmental decree.
12. Indemnification and Insurance .
(a) Indemnity . The Company shall, to the maximum extent permitted by law, defend, indemnify, and hold harmless the Executive and the Executive’s heirs, estate, executors, and administrators against any costs, losses, claims, suits, proceedings, damages, or liabilities to which they may become subject to arising from, based on, or relating to the Executive’s employment by the Company (and any predecessor of the Company), or the Executive’s service as an officer or member of the board of directors (or any similar governing body) of the Company (or any predecessor of the Company) or any Affiliate, including without limitation reimbursement for any legal or other expenses reasonably incurred by the Executive in connection with investigation and defending against any such costs, losses, claims, suits, proceedings, damages, or liabilities.
(b) Insurance . The Company shall maintain directors and officers liability insurance in commercially reasonable amounts (as reasonably determined by the Board), and the Executive shall be covered under such insurance to the same extent as other similarly situated executives of the Company; provided, however , that the Company shall not be required to maintain such insurance coverage if the Board determines that it is unavailable at reasonable cost, provided that the Executive is given written notice of any such determination promptly after it is made.
 
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(c) Gross-Up . If the value of any benefits or payment provided under Section 12(a) is subject to income taxes, then the Company shall make an additional payment (a “ Gross-Up Payment ”) to the Executive, by December 31 of the year next following the Executive’s taxable year in which the income taxes were incurred, in an amount equal to 75% of the federal, state, and local income taxes imposed upon such benefits or payment. All determinations to be made under this Section 12(c) (including whether and when a Gross-Up Payment is required) shall be (i) made within thirty (30) days of receipt by the Company of the Executive’s request for the Gross-Up Payment, (ii) made by a nationally recognized certified public accounting firm designated by the Company, and (iii) binding upon the Company and the Executive. All of the fees and expenses of the accounting firm in performing such determinations shall be borne solely by the Company.
13. Executive to Provide Assistance with Claims . During his employment with the Company and following the termination of such employment, regardless of the reason for such termination, the Executive shall assist the Company in defending any claims that may be made against the Company, and shall assist the Company in prosecuting any claims that may be made by the Company, to the extent that such claims may relate to the Executive’s services for the Company. The Executive shall promptly inform the Company if he learns of any lawsuits involving such claims that may be filed against the Company. The Company shall reimburse the Executive for all reasonable out-of-pocket expenses associated with such assistance, including travel expenses, incurred and accounted for in accordance with its standard policies and procedures for expense reimbursements and deductibles under Section 162 of the Code. For periods after the Termination Date, the Company shall provide reasonable compensation to the Executive for such assistance at a rate to be determined by the Company in its discretion. The Executive shall promptly inform the Company if asked to assist in any investigation of the Company that may relate to the Executive’s services for the Company, regardless of whether a lawsuit has then been filed against the Company with respect to such investigation. For purposes of this Section 13, the term “Company” shall include the Company and its Affiliates.
14. Entire Agreement . Except as provided in Section 8(e), this Agreement constitutes the entire agreement among the parties with respect to its subject matters and supersedes any and all prior or contemporaneous oral and written agreements and understandings with respect to such subject matters, including without limit all prior agreements relating to employment, severance, or change in control; provided, however , that this Agreement shall not adversely affect the Executive’s rights under the terms of any option on stock of the Company or any other award based on the stock of the Company.
15. Miscellaneous .
(a) Governing Law . This Agreement shall be governed by and construed in accordance with the laws of the State of Oklahoma, without reference to its conflict-of-laws principles.
(b) Captions . The captions of this Agreement are not part of this Agreement and shall have no force or effect.
(c) Amendment . This Agreement may not be amended or modified except by a written agreement executed by the parties or their respective successors and legal representatives.
 
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(d) Notices . All notices and other communications under this Agreement shall be in writing and sent to the other party by either hand delivery, pre-paid overnight carrier, or registered or certified U.S. mail (return receipt requested) postage prepaid, addressed as follows:
If to the Executive :

Devon Energy Corporation
333 West Sheridan Avenue
Oklahoma City, Oklahoma 73102-5015
If to the Company :
Devon Energy Corporation
C/O Executive Vice President - Human Resources
333 West Sheridan Avenue
Oklahoma City, Oklahoma 73102-5015
With a copy to:
Devon Energy Corporation
C/O Executive Vice President & General Counsel
333 West Sheridan Avenue
Oklahoma City, Oklahoma 73102-5015
or to such other address as either party shall have furnished to the other in writing. Such notice shall be deemed given (i) in the case of hand delivery, the day of delivery; (ii) in the case of overnight delivery, the next business day or the day designated for delivery; and (iii) in the case of certified or registered U.S. mail, five (5) days after deposit in the U.S. mail; provided, however , that in no event shall any such notices be deemed to be given later than the date they are actually received.
(e) Severability . The invalidity or unenforceability of any provision of this Agreement shall not affect the validity or enforceability of any other provision of this Agreement, and this Agreement shall be construed as if such invalid or unenforceable provisions were omitted (but only to the extent such provision cannot be appropriately reformed or modified). If any such provision may be made enforceable by limitation, then such provision shall be deemed to be so limited and shall be enforceable to the maximum extent permitted by applicable law.
(f) Withholdings . The Company may withhold from any amounts payable under this Agreement all amounts authorized by the Executive or required to be withheld under any applicable federal, state, local, or foreign law or regulation.
(g) Waiver . The waiver by either party of a breach of any term or provision of this Agreement shall not operate or be construed as a waiver of a subsequent breach of the same term or provision by either party or of the breach of any other term or provision of this Agreement.
(h) Representations and Warranties . The Executive represents and warrants that (i) he is not, and shall not become, a party to any agreement, contract, arrangement, or understanding, whether of employment or otherwise, that would in any way restrict or prohibit him from undertaking or performing the duties required by this Agreement or that would in any way restrict or prohibit his ability to be employed by the Company in accordance with this Agreement; (ii) his employment by the Company does
 
12

not and shall not violate the terms of any policy of, or any agreement with, any prior employer regarding confidentiality or competition; and (iii) his position with the Company shall not require him to improperly use any trade secrets or confidential information of any prior employer or any other person or entity for whom he has performed services.
(i) Section 409A Compliance . This Agreement is intended to comply with Section 409A and its corresponding regulations, or an exemption therefrom, and payments may only be made under this Agreement upon an event and in a manner permitted by Section 409A, to the extent applicable. All payments to be made upon a termination of employment under this Agreement may only be made upon a Separation from Service under Section 409A. For purposes of Section 409A, the right to a series of payments under this Agreement shall be treated as a right to a series of separate payments. In no event may the Executive, directly or indirectly, designate the calendar year of a payment, including as a result of the timing of the Executive’s execution of the Release. Notwithstanding anything to the contrary herein, if a payment that is subject to execution of the Release could be made in more than one taxable year, payment shall be made in the later taxable year.
[SIGNATURES APPEAR ON FOLLOWING PAGE]
 
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IN WITNESS WHEREOF, the Company and the Executive have executed this Employment Agreement as of the Effective Date.

 	
	
Devon Energy Corporation	

By:	 	Frank W. Rudolph	
Its:	 	Executive Vice President – Human Resources	
 
14

Exhibit A
Definitions
Definitions . The following terms, when used throughout this Agreement, shall have the following meanings:
 
1.	“ AAA ” means the American Arbitration Association.	
 
2.	“ Accounting Firm ” has the meaning ascribed to such term in Section 7(b).	
 
3.	“ Act ” means the Securities Exchange of Act of 1934, as amended from time to time.	
 
4.	“ Accrued Obligations ” has the meaning ascribed to such term in Section 4(a).	
 
5.	“ Affiliate ” means, with respect to the Company, any person that directly, or indirectly through one or more intermediaries, controls, is controlled by, or is under common control with, the Company; provided, however , that a natural person shall not be considered an Affiliate.	
 
6.	“ Agreement ” has the meaning set forth in the preamble.	
 
7.	“ Agreement Payments ” has the meaning ascribed to such term in Section 7(a).	
 
8.	“ Annual Base Salary ” means the annual base salary of the Executive as in effect from time to time.	
 
9.	“ Annual Bonus ” means, with respect to any given year, the annual bonus payable to the Executive with respect to that year, as determined by the Compensation Committee in its discretion.	
 
10.	“ Board ” means, at any given time, the Company’s Board of Directors at that time.	
 
11.	“ Cause ” means any of the following:	
 
 	(a)	the willful failure by the Executive to substantially perform the Executive’s duties for the Company or an Affiliate (other than due to physical or mental incapacity) within thirty (30) days after receiving a written demand for substantial performance from the Supervisor, the CEO, or the Board;	
 
 	(b)	the willful engaging by the Executive in illegal or dishonest conduct or gross misconduct that is materially and demonstrably injurious to the Company or an Affiliate; or	
 
 	(c)	the conviction of the Executive of a felony or any crime of moral turpitude, a guilty or nolo contendere plea by the Executive with respect to a felony or any crime of moral turpitude, or the deferred adjudication or unadjudicated probation of the Executive with respect to a felony or any crime of moral turpitude;	
provided, however, that (x) an act or omission by the Executive shall be considered “willful” only if it was not in good faith and was without reasonable belief that it was in the Company’s best interests, and (y) any act or omission by the Executive based upon authority granted by resolution duly adopted by the Board, the instructions of the Supervisor, or the advice of counsel for the Company shall be conclusively presumed to be in good faith and in the Company’s best interests.
 
12.	“ CEO ” means, at any given time, the Chief Executive Officer of the Company at that time.	
 
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13.	“ Change in Control ” means the occurrence of any one of the following events:	
 
 	(a)	The Incumbent Directors cease for any reason to constitute at least a majority of the Board;	
 
 	(b)	any person is or becomes a “ beneficial owner ” (as defined in Rule 13d-3 under the Act), directly or indirectly, of Company securities representing 30% or more of either (x) the Company’s outstanding shares of common stock or (y) the combined voting power of the Company’s then outstanding securities eligible to vote in the election of directors (each, “ Company Securities ”); provided, however , that the event described in this paragraph (b) shall not be deemed to be a Change in Control by virtue of any of the following acquisitions or transactions: (A) by the Company or any subsidiary, (B) by any employee benefit plan (or related trust) sponsored or maintained by the Company or any subsidiary, (C) by an underwriter temporarily holding securities pursuant to an offering of such securities, or (D) pursuant to a Non-Qualifying Transaction;	
 
 	(c)	the consummation of a merger, consolidation, statutory share exchange, or similar form of corporate transaction involving the Company or any of its subsidiaries that requires the approval of the Company’s stockholders, whether for such transaction or the issuance of securities in the transaction (a “ Reorganization ”), or the sale or other disposition of all or substantially all of the Company’s assets to an entity that is not an Affiliate (a “ Sale ”), unless:	
 
 	(i)	the holders of the Company’s shares of common stock either receive in such Reorganization or Sale, or hold immediately following the consummation of the Reorganization or Sale, more than 50% of each of the outstanding common stock and the total voting power of securities eligible to vote in the election of directors of (x) the corporation resulting from such Reorganization or the corporation that has acquired all or substantially all of the assets of the Company in connection with a Sale (in either case, the “ Surviving Corporation ”), or (y) if applicable, the ultimate parent corporation that directly or indirectly has beneficial ownership of 100% of the voting securities eligible to elect directors of the Surviving Corporation (the “ Parent Corporation ”),	
 
 	(ii)	no person (other than any employee benefit plan (or related trust) sponsored or maintained by the Surviving Corporation or the Parent Corporation) is or becomes, as a result of the Reorganization or Sale, the beneficial owner, directly or indirectly, of 30% or more of the outstanding shares of common stock or the total voting power of the outstanding voting securities eligible to vote in the election of directors of the Parent Corporation (or, if there is no Parent Corporation, the Surviving Corporation), and	
 
 	(iii)	at least a majority of the members of the board of directors of the Parent Corporation (or, if there is no Parent Corporation, the Surviving Corporation) following the consummation of the Reorganization or Sale were Incumbent Directors at the time of the Board’s approval of the execution of the initial agreement providing for such Reorganization or Sale;	
(any Reorganization or Sale that satisfies all of the criteria specified in (i), (ii) and (iii) above shall be deemed to be a “ Non-Qualifying Transaction ”); or
 
 	(d)	the Company’s stockholders approve a plan of complete liquidation or dissolution of the Company.	
 
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Notwithstanding the foregoing, a Change in Control shall not be deemed to occur solely because any person acquires beneficial ownership of more than 30% of Company Securities due to the Company’s acquisition of Company Securities that reduces the number of Company Securities outstanding; provided, however, if, following such acquisition by the Company, such person becomes the beneficial owner of additional Company Securities that increases the percentage of outstanding Company Securities beneficially owned by such person, a Change in Control shall then occur. In addition, if a Change in Control occurs pursuant to paragraph 12(b) above, then no additional Change in Control shall be deemed to occur pursuant to paragraph 12(b) by reason of subsequent changes in holdings by such person (except if the holdings by such person are reduced below 30% and thereafter increase to 30% or above).
 
14.	“ CIC Period ” means the two-year period following a Change in Control.	
 
15.	“ COBRA ” means the Consolidated Omnibus Budget Reconciliation Act of 1986, as amended from time to time.	
 
16.	“ Code ” means Internal Revenue Code of 1986, as amended from time to time.	
 
17.	“ Company ” means the Devon Energy Corporation, as set forth in the preamble to this Agreement, and any successor to or assignee of its business and/or assets that assumes and agrees to perform this Agreement by operation of law or otherwise.	
 
18.	“ Compensation Committee ” means, at any given time, the Compensation Committee of the Board at that time.	
 
19.	“ Confidential Information ” means non-public information (including, without limitation, information regarding litigation and pending litigation) concerning the Company and its Affiliates that was acquired by or disclosed to the Executive during his employment with the Company and following the Termination Date.	
 
20.	“ Disabled ” means, with respect to the Executive, that (a) he has received disability payments under the Company’s long-term disability plan for a period of three (3) months or more, or (b) based upon the written report (prepared after a complete physical examination of the Executive) of a mutually agreeable qualified physician designated by the Company and the Executive or his representative, the Compensation Committee determines, in accordance with Section 409A of the Code, that the Executive has become physically or mentally incapable of performing his essential job functions with or without reasonable accommodation or job protection as required by law for a continuous period expected to last for a continuous period of not less than twelve (12) months.	
 
21.	“ Effective Date ” has the meaning set forth in the preamble to this Agreement.	
 
22.	“ Employment Matter ” means any dispute, controversy, or claim between the parties arising out of, relating to, or concerning this Agreement, the Executive’s employment with the Company, or the termination of that employment.	
 
23.	“ Employment Matter Claim ” has the meaning ascribed to such term in Section 10(d)(i).	
 
24.	“ Excise Tax ” has the meaning ascribed to such term in Section 7(a).	
 
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25.	“ Executive ” has the meaning set forth in the preamble to this Agreement.	
 
26.	“ Good Reason ” means any of the following events, unless the Executive has consented in writing to such events:	
 
 	(a)	the assignment of any duties materially inconsistent with the Executive’s position (including status, offices, titles, and reporting requirements), authority, duties, or responsibilities under this Agreement, other than an isolated, insubstantial, or inadvertent action not taken in bad faith and which the Company remedies promptly after receipt of notice from the Executive;	
 
 	(b)	any material failure by the Company to comply with any provision of this Agreement, other than an isolated, insubstantial, or inadvertent failure not occurring in bad faith and which and which the Company remedies promptly after receipt of notice from the Executive;	
 
 	(c)	any failure by the Company to comply with and satisfy Section 9(c); or	
 
 	(d)	any relocation of the Executive’s principal office to a location more than fifty (50) miles from the Executive’s principal office prior to such relocation.	
 
27.	“ Good Reason Notice ” has the meaning ascribed to such term in Section 3(d).	
 
28.	“ Gross-Up Payment ” has the meaning ascribed to such term in Section 12(c).	
 
29.	“ Guarantors ” has the meaning ascribed to such term in Section 10(e).	
 
30.	“ Incumbent Directors ” means the members of the Board on the Effective Date; provided, however , that (x) any person becoming a director and whose election or nomination for election was approved by a vote of at least a majority of the Incumbent Directors then on the Board (either by a specific vote or by approval of the proxy statement of the Company in which such person is named as a nominee for director, without written objection to such nomination) shall be deemed an Incumbent Director, and (y) no individual initially elected or nominated as a director of the Company as a result of an actual or threatened election contest (as described in Rule 14a-11 under the Act) or other actual or threatened solicitation of proxies or consents by or on behalf of any person (as such term is used in Sections 13(d)(3) and 14(d)(2) of the Act) other than the Board, including by reason of any agreement intended to avoid or settle any such election contest or solicitation of proxies or consents, shall be deemed an Incumbent Director.	
 
31.	“ Non-Solicitation Obligation ” has the meaning ascribed to such term in Section 8(f).	
 
32.	“ Notice of Termination ” means a written notice that (i) indicates the specific termination provision of Section 3 that is being relied upon, (ii) to the extent applicable, reasonably describes the facts and circumstances claimed to provide a basis for termination under the provision so indicated, and (iii) specifies the Termination Date; provided, however , that the failure to describe in the Notice of Termination any fact or circumstance constituting Good Reason or Cause shall not waive any right of either party under this Agreement or preclude either party from asserting such fact or circumstance in enforcing rights under this Agreement.	
 
33.	“ Payment ” has the meaning ascribed to such term in Section 7(a).	
 
34.	A “ person ” shall have the meaning ascribed by Section 3(a)(9) of the Act and shall also mean a natural person, company, government (and any political subdivision, agency, or instrumentality of	
 
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 	a government), corporation, partnership, limited liability company, trust, unincorporated organization, or other entity. When two or more persons act as a partnership, limited partnership, syndicate, or other group for the purposes of acquiring, holding, or disposing Company Securities, such partnership, limited partnership, syndicate, or other group shall be deemed a “ person ” for purposes of this Agreement.	
 
35.	“ Prorated Annual Bonus ” means a prorated amount of an Annual Bonus payable under Sections 4(b)(i)(B) or 4(c). If the Executive’s employment began in a calendar year before the calendar year in which the Termination Date occurs, the Prorated Annual Bonus shall be calculated based on the prior year’s Annual Bonus (if any) times the number of days worked in the year in which the Termination Date occurs divided by three hundred sixty five (365). If the Executive’s employment began in the calendar year in which the Termination Date occurs, then the Prorated Annual Bonus shall be determined by the Compensation Committee in its discretion.	
 
36.	“ Representatives ” means, with respect to the Company, its Affiliates and any of their respective past or present officers, directors, stockholders, partners, members, managers, agents, and employees.	
 
37.	“ Retiree Medical Benefit Plan ” means any retiree medical benefit plan applicable to the Executive or that would be applicable to the Executive if his employment then terminated and he satisfied the applicable age and service requirements.	
 
38.	“ Section 409A ” has the meaning ascribed to such term in Section 4(e).	
 
39.	“ Separation from Service ” has the meaning ascribed to such term in Section 4(e).	
 
40.	“ Short-Term Disability Payments ” means disability payments under the Company’s short-term disability policy or plan that are less than 100% of the then-current Annual Base Salary.	
 
41.	“ Supervisor ” means, with respect to the Executive, the person to whom the Executive reports, as determined by the CEO or the CEO’s designee from time to time.	
 
42.	“ Termination Date ” means the Executive’s last day of employment by the Company or an Affiliate (including any successor to the Company or such Affiliate as determined in accordance with Section 9).	
 
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EXHIBIT B
GENERAL RELEASE
NOTICE
Devon Energy Corporation (the “ Company ”) is an equal opportunity employer. Various laws prohibit employment discrimination based on sex, race, color, national origin, religion, age, disability, eligibility for covered employee benefits, veteran status, and other legally protected characteristics. You may also have rights under other federal, state, and/or municipal statutes, orders, or regulations pertaining to labor, employment, and/or employee benefits. These laws are enforced through the United States Department of Labor (DOL), the Equal Employment Opportunity Commission (EEOC), and various other federal, state, and municipal labor departments, fair employment boards, human rights commissions, similar agencies, and courts.
This General Release is being provided to you in connection with the Employment Agreement previously entered between you and the Company (the “ Employment Agreement ”). You have at least twenty-one (21) days from the date you receive this General Release, if you want it, to consider whether you wish to sign this General Release and receive the payments and benefits (the “ Severance Benefits ”) available under the Employment Agreement for doing so. You have at least until the close of business twenty-one (21) days from the date you receive this General Release to make your decision. You may not, however, sign this General Release until, at the earliest, your last effective date of employment.
BEFORE SIGNING THIS GENERAL RELEASE YOU SHOULD REVIEW IT CAREFULLY. YOU ALSO HAVE THE RIGHT TO CONSULT WITH AN ATTORNEY OF YOUR CHOICE.
You may revoke this General Release within seven (7) days after you sign it and it shall not become effective or enforceable until that revocation period has expired. If you do not timely sign and return this General Release, or if you exercise your right to revoke the General Release after signing it, then you will not be eligible to receive the Severance Benefits. Any revocation must be in writing and must be received by the Company within the seven-day period following your execution of this General Release.
GENERAL RELEASE
In consideration of the Severance Benefits offered to me by the Company under the Employment Agreement, I hereby (i) release and discharge the Company and its predecessors, successors, affiliates, parent, subsidiaries, and partners and each of those entities’ current and former employees, officers, directors, and agents (together, the “ Released Parties ”) from all claims, liabilities, demands, and causes of action, known or unknown, fixed or contingent, that I may have or claim to have against them, including without limit any claims that result from or arise out of my past employment with the Company, the severance of that relationship and/or otherwise, or any contract or agreement with or relating to the Released Parties, and (ii) waive any and all rights I may have with respect to and promise not to file a lawsuit to assert any such claims.
This General Release includes, but is not limited to, claims arising under the Age Discrimination in Employment Act (“ ADEA ”) and any other federal, state, and/or municipal statutes, orders, or regulations pertaining to labor, employment, and/or employee benefits. This General Release also applies without limitation to any claims or rights I may have growing out of any legal or equitable restrictions on the rights of the Released Parties not to continue an employment relationship with their employees, including any express or implied employment or other contracts, and to any claims I may have against the Released Parties for fraudulent inducement or misrepresentation, defamation, wrongful termination, or other torts or retaliation claims in connection with workers’ compensation, any legally protected activity, or alleged whistleblower status, or on any other basis whatsoever.
 
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It is specifically agreed, however, that this General Release does not have any effect on any rights or claims under the ADEA I may have against the Company that arise after the date I execute this General Release or on any vested rights I may have under any of the Company’s qualified benefit plans or arrangements as of or after my last day of employment with the Company or on any of the Company’s obligations under the Employment Agreement.
MISCELLANEOUS
By signing this General Release, I shall, and hereby do, resign from any corporate, board, and other offices and positions I may hold with the Company and its affiliates as of the date my employment with the Company terminated.
I agree that (i) none of the Released Parties shall have any obligation to employ or to hire or rehire me, to consider me for hire, or to deal with me in any respect with regard to potential future employment; (ii) I shall not ever apply for or otherwise seek employment with any of the Released Parties at any time in the future; and (iii) my forbearance to seek future employment as just stated shall be construed as being purely contractual and in no way involuntary, discriminatory, or retaliatory.
I have carefully reviewed and fully understand all the provisions of the Employment Agreement and General Release, including the foregoing Notice. I have not relied on any representation or statement, oral or written, relating to the Employment Agreement or this General Release by the Released Parties that are not set forth in those documents.
The Employment Agreement and this General Release, including the foregoing Notice, set forth the entire agreement between me and the Company with respect to payments and benefits payable to me due to the termination of my employment with the Company, and supersede all prior agreements and understandings, written and oral, between the parties with respect to such subject matters. I understand that my receipt and retention of the Severance Benefits are contingent not only on my execution and non-revocation of this General Release, but also on my continued compliance with my other obligations under the Employment Agreement. I acknowledge that the Company has given me at least twenty-one (21) days to consider whether I wish to accept or reject the Severance Benefits I am otherwise eligible to receive under the Employment Agreement in exchange for signing and not revoking this General Release. I hereby represent and state that I fully understand the effects and consequences of the Employment Agreement and General Release prior to signing those documents.
This General Release and the Company’s obligation to provide the Severance Benefits under the Employment Agreement shall be interpreted and construed to comply with Section 409A of the Internal Revenue Code (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, I understand and acknowledge that I shall be solely responsible for any risk that the tax treatment of all or part of the Severance Benefits may be affected by Section 409A of the Code and impose significant adverse tax consequences on me, including accelerated taxation, a 20% additional tax, and interest. Because of the potential tax consequences, I understand that I have the right, and am encouraged by this paragraph, to consult with a tax advisor of my choice before signing this General Release.
This General Release shall be governed by the laws of the State of Oklahoma, without regard to any conflict-of-laws principles, and shall not be modified unless in a writing signed by both of the parties.
Dated this      day of             , 201    .

 	
[Name]	
 
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Exhibit 10.25

 
 
NOTICE OF GRANT OF PERFORMANCE 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 «Grant_Date» , you have been granted a Performance Restricted Stock Award of %%TOTAL_SHARES_GRANTED%-% shares of Devon Energy Corporation (the “Company”) Common Stock (the “Award”) under the Company’s 2009 Long-Term Incentive Plan, as amended and restated June 6, 2012, including 2013 amendment. None of the shares subject to this Award shall vest, and this Award shall terminate in its entirety, should the Company fail to attain the Performance Goal specified in attached Schedule A for the Performance Period. Except as otherwise provided in the Award Agreement, if such Performance Goal is attained and certified, then the Restricted Shares will vest in four (4) separate installments as follows: (a) twenty-five percent (25%) of the Restricted Shares will vest upon the completion of the Performance Period and the Committee’s certification of the attainment of the Performance Goal, and Vested Stock will be released as soon as practicable following the Committee’s certification of the Company’s attainment of the Performance Goal, and (b) the balance of the Restricted Shares will vest, and Vested Stock will be released, in a series of three (3) successive equal annual installments on the second, third and fourth anniversaries of the Date of Grant.

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, as amended and restated June 6, 2012, including 2013 amendment, and the Award Agreement, both of which are attached and made a part of this document.

DEVON ENERGY CORPORATION
2009 LONG-TERM INCENTIVE PLAN
PERFORMANCE RESTRICTED STOCK AWARD AGREEMENT
THIS PERFORMANCE 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 Devon Energy Corporation 2009 Long-Term Incentive Plan, as amended and restated June 6, 2012, including 2013 amendment (the “Plan”) permits the grant of Restricted Stock that vests based upon performance standards (referred to herein as a “Performance Restricted Stock”) to employees, officers and non-employee directors of the Company and its Subsidiaries and Affiliated Entities, in accordance with the terms and provisions of 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 the Plan; 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 subject to the restrictions placed thereon pursuant to the terms of this Award Agreement (“Performance 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 Performance 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 Performance Restricted Stock shall be deemed “Vested Stock.”

Vesting Schedule
If the Performance Goal (specified in attached Schedule A) for the Performance Period (specified in attached Schedule A) is attained and certified, then the Award will vest in four (4) separate installments as follows:
(i) twenty-five percent (25%) (or %%SHARES_Period1%-% ) of the Restricted Shares will vest upon the completion of the Performance Period and the Vested Stock will be released within a reasonable time following the Committee’s certification of the Company’s attainment of the Performance Goal;
(ii) 25% (or %%SHARES_Period2%-% ) of the Restricted Shares will vest, and the Vested Stock will be released, on %%Vest_DATE_PERIOD2%-% ;
(iii) 25% (or %%SHARES_Period3%-% ) of the Restricted Shares will vest, and the Vested Stock will be released, on %%Vest_DATE_PERIOD3%-% ; and
(iv) the remaining 25% (or %%SHARES_Period4%-% ) of the Restricted Shares will vest, and the Vested Stock will be released, on %%Vest_DATE_PERIOD4%-% .
Notwithstanding the foregoing, no fractional shares of Common Stock shall be issued pursuant to this Award, and any fractional share resulting from any calculation made in accordance with the terms of this Award Agreement shall be aggregated, and any such aggregated shares will vest, and the Vested Stock will be released, at the time provided in (3)(b)(iv) above.
Except as otherwise provided in Section 3(c) below, none of the shares subject to this Award shall vest should the Company fail to attain the Performance Goal for the Performance Period. Except to the extent that an Award has previously vested pursuant to Section 3(c) below, this Award shall terminate in its entirety and shall not vest should the Company fail to attain the Performance Goal for the Performance Period.
(c) Change in Control Event or Death or Disability . Notwithstanding any provision to the contrary in this Award Agreement, a Participant shall become fully and immediately vested in the Award in the event of the Participant’s death or the occurrence of a Change in Control Event, without regard to attainment or certification of the Performance Goal. In the event of the Participant’s death or the occurrence of a Change in Control Event, the Vested Stock will be released within a reasonable time thereafter. If the Participant’s Date of Termination occurs by reason of disability, the Committee may, in its sole and absolute discretion, elect to vest all or a portion of the unvested Performance Restricted Stock upon the Participant’s Date of Termination and the Vested Stock will be released within a reasonable time thereafter.

(d) Termination of Employment . The Participant shall forfeit the unvested portion of the Award (including the underlying Performance Restricted Stock and Accrued Dividends) upon the occurrence of the Participant’s Date of Termination unless the Performance Goal is attained and certified and the Award becomes vested under the circumstances described below.
(i) 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, 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 if 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 such Release becomes effective, the Performance Restricted Stock shall be treated as vested as of the Participant’s Date of Termination, provided the Date of Termination occurs after the Performance Goal is attained and certified, and the Performance Restricted Stock shall be released within a reasonable time thereafter. If the Participant’s Date of Termination occurs before the Performance Goal is attained and certified, the Performance Restricted Stock shall be treated as vested as of the certification of attainment of the Performance Goal, and the Performance Restricted Stock, if vested, shall be released within a reasonable time thereafter. Notwithstanding the foregoing, if the Performance Goal is not attained and certified, or if 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 shares of Performance Restricted Stock subject to this Award Agreement shall not vest pursuant to this Section 3(d)(i) and shall be forfeited.
(ii) If a Participant’s Date of Termination occurs by reason of Normal Retirement Date, Early Retirement Date, or other special circumstances (as determined by the Committee), and the Committee determines, in its sole and absolute discretion, that the Performance Restricted Stock shall continue to vest following the Participant’s Date of Termination, the Performance Restricted Stock shall continue to vest after the Participant’s Date of Termination in accordance with the Vesting Schedule in Section 3(b) above and the Performance Restricted Stock shall be released within a reasonable time after the applicable Vesting Date; provided that, if the Participant is Retirement Eligible, the Participant shall, subject to the satisfaction of the conditions in Section 16, be eligible to vest in accordance with the Vesting Schedule above in Section 3(b), in the installments of Performance Restricted Stock that remain unvested on the Date of Termination as follows:

Age at Retirement	  	Percentage of each Unvested Installment of
Performance 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	% 	

(e) Voting Rights and Dividends . The Participant shall not have voting rights attributable to the shares of Performance Restricted Stock prior to the completion of the Performance Period and the Committee’s certification of the Company’s attainment of the Performance Goal. Any dividends declared and paid by the Company with respect to shares of Performance Restricted Stock prior to the Committee’s certification of the attainment of the Performance Goal (the “Accrued Dividends”) shall not be paid to the Participant until and unless the Committee certifies the attainment of the Performance Goal. Any such Accrued Dividends shall be forfeited if the Award is terminated because the Performance Goal is not attained. If the Performance Goal is attained and certified, the Accrued Dividends shall be paid to the Participant within a reasonable time thereafter and any dividends or other distributions (in cash or other property, but excluding extraordinary dividends) that are declared and/or paid with respect to the shares of Performance Restricted Stock shall be paid to the Participant on a current basis. Any extraordinary dividends ( i.e., special or nonrecurring dividends in excess of the regular dividends paid by the Company), in cash or property, on Performance Restricted Stock shall not be paid until and unless the Performance Restricted Stock becomes Vested Stock.
(f) Certification of Performance Goal . Except in the event of the occurrence of a Change in Control Event, the Committee shall, as soon as practicable following the last day of the Performance Period, determine and certify, based on the Company’s financial statements for the fiscal year coincident with the Performance Period, whether the Performance Goal for the Performance Period has been attained. Such certification shall be final, conclusive and binding on the Participant, and on all other persons, to the maximum extent permitted by law.
(g) Vested Stock - Removal of Restrictions . Upon Performance 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 Performance 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, AS AMENDED AND RESTATED JUNE 6, 2012, INCLUDING 2013 AMENDMENT. 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 Performance 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 Performance Restricted Stock becomes Vested Stock.

6. Certain Corporate Changes . If any change is made to the Common Stock (whether by reason of merger, consolidation, reorganization, recapitalization, stock dividend, stock split, combination of shares, or exchange of shares or any other change in capital structure made without receipt of consideration), then unless such event or change results in the termination of all the Performance Restricted Stock granted under this Award Agreement, the Committee shall adjust, in an equitable manner and as provided in the Plan, the number and class of shares underlying the Performance Restricted Stock, the maximum number of shares for which the Award may vest, and the share price or class of Common Stock as appropriate, to reflect the effect of such event or change in the Company’s capital structure in such a way as to preserve the value of the Award.
7. 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.
8. Nontransferability of Award . The Participant shall not have the right to sell, assign, transfer, convey, dispose, pledge, hypothecate, burden, encumber or charge any Performance Restricted Stock or any interest therein in any manner whatsoever.
9. 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.
10. 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 Delaware.
11. Company Policies . The Participant agrees that the Award will be subject to any applicable clawback or recoupment policies, share trading policies and other policies that may be implemented by the Company’s Board of Directors or a duly authorized committee thereof, from time to time.
12. 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.
13. 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.
14. 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.
15. 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.
16. Conditions to Post-Retirement Vesting .
(a) Notice of and Conditions to Post-Retirement Vesting . If the Participant is 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 16(a), to continue to vest following the Date of Termination in any unvested installments of Performance Restricted Stock (each such unvested installment, an “Installment”). The Participant shall have the right to vest in such Installments of Performance 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 Performance 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.
17. Definitions . Words, terms or phrases used in this Award Agreement shall have the meaning set forth in this Section 17. 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(e).
(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 16(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 16(a).
(k) “ Non-Compliance Event” has the meaning set forth in Section 16(b).
(l) “ Non-Disclosure Agreement ” has the meaning set forth in Section 16(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) “ Performance Restricted Stock ” has the meaning set forth in the preamble and Section 2.
(q) “ 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.

(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»	

SCHEDULE A
PERFORMANCE PERIOD AND PERFORMANCE GOAL
1. Performance Period . The measurement period for the Performance Goal shall be the period beginning January 1, 2014 and ending December 31, 2014 (the “Performance Period”).
2. Performance Goal . The Performance Goal is based on the Company’s cash flow before balance sheet changes. Vesting will be based on the Company’s achievement of $4 billion in cash flow before balance sheet changes during the Performance Period and the Committee’s certification of the attainment of the Performance Goal.
3. Certification of Performance Goal . Except in the event of the occurrence of a Change in Control Event, the Committee shall, as soon as practicable following the last day of the Performance Period, determine and certify, based on the Company’s financial statements for the fiscal year coincident with the Performance Period, whether the Performance Goal for the Performance Period has been attained. Such certification shall be final, conclusive and binding on the Participant, and on all other persons, to the maximum extent permitted by law.
4. Maximum Award . The maximum number of shares of Performance Restricted Stock that may become earned and vested pursuant to this Award is %%TOTAL_SHARES_GRANTED%-% .

EXHIBIT A
Form of Non-Disclosure Agreement
[Insert Date]
Devon Energy Corporation
333 West Sheridan Avenue
Oklahoma City, OK 73102-5010
 
 	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 Performance Restricted Stock 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 10.28

 
 
NOTICE OF GRANT OF PERFORMANCE SHARE UNIT 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 target award of %%TOTAL_SHARES_GRANTED%-% Performance Share Units (“Award”) under the Devon Energy Corporation 2009 Long-Term Incentive Plan, as amended and restated June 6, 2012, including 2013 amendment. Each Performance Share Unit that vests entitles you to one share of Devon Energy Corporation (the “Company”) Common Stock. The vesting of these Performance Share Units is determined pursuant to the following two-step process: (i) first, the maximum number of Performance Share Units in which you can vest shall be calculated based upon the Company’s Total Shareholder Return (“TSR”) over the three-year Performance Period that begins January 1, 2014 and ends December 31, 2016 (the “Performance Period”), (ii) then, if the value (based on the fair market value of a share of Common Stock on the last day of the Performance Period) of the aggregate number of Performance Share Units calculated under clause (i) exceeds the Payout Value Limit described on Schedule A, the number of Performance Share Units calculated under clause (i) shall be reduced so that the value (based on the fair market value of a share of Common Stock on the last day of the Performance Period) of the total number of vested Performance Share Units is equal to the Payout Value Limit. The maximum number of Performance Share Units that you can earn based on clause (i) during the Performance Period will be calculated as follows: %%TOTAL_SHARES_GRANTED%-% x 200%, with actual payout based on the performance level achieved by the Company with respect to the Performance Goal set forth on Schedule A
This Award also entitles you to be paid Dividend Equivalents as set forth in the Award Agreement.

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, as amended and restated June 6, 2012, including 2013 amendment, and the Award Agreement, both of which are attached and made a part of this document.

DEVON ENERGY CORPORATION
2009 LONG-TERM INCENTIVE PLAN
PERFORMANCE SHARE UNIT AGREEMENT
THIS PERFORMANCE SHARE UNIT AWARD AGREEMENT (the “Award Agreement”) is entered into as of %%OPTION_DATE%-% (the “Date of Grant”), by and between Devon Energy Corporation, a Delaware corporation (the “Company”) and %%FIRST_NAME%-% %%MIDDLE_NAME%-% %%LAST_NAME%-% (the “Participant”);
W I T N E S S E T H:
WHEREAS, the Devon Energy Corporation 2009 Long-Term Incentive Plan, as amended and restated June 6, 2012, including 2013 amendment (the “Plan”) permits the grant of Performance Units (hereinafter referred to as “Performance Share Units”) to employees, officers and non-employee directors of the Company and its Subsidiaries and Affiliated Entities, in accordance with the terms and provisions of 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%-% Performance Share Units subject to the terms and conditions of this Award Agreement and the Plan; and
WHEREAS, the Performance Share Units granted pursuant to this Award Agreement shall vest based on the following two-step process: (i) first, the maximum number of Performance Share Units in which Participant can vest shall be calculated based on the attainment and certification of the Performance Goal described on Schedule A as of the end of a Performance Period, (ii) then, if the value (based on the fair market value of a share of Common Stock on the last day of the Performance Period) of the aggregate number of Performance Share Units calculated under clause (i) exceeds the Payout Value Limit described on Schedule A, the number of Performance Share Units calculated under clause (i) shall be reduced so that the value (based on the fair market value of a share of Common Stock on the last day of the Performance Period) of the total number of vested Performance Share Units is equal to the Payout Value Limit; 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 a target award (the “Award”) of %%TOTAL_SHARES_GRANTED%-% Performance Share Units, on the terms and conditions set forth herein and in the Plan. Each Performance Share Unit that vests entitles the Participant to one share of Common Stock.

3. Terms of Award .
(a) Performance Share Unit Account . The Company shall establish a bookkeeping account on its records for the Participant and shall credit the Participant’s Performance Share Units to the bookkeeping account.
(b) General Vesting Terms . Except as provided in this Section 3, the number of Performance Share Units which actually vest under this Agreement shall be determined pursuant to the following two-step process: (i) first, the maximum number of Performance Share Units in which Participant can vest shall be calculated based on the attainment and certification of the Performance Goal described on Schedule A as of the end of a Performance Period, (ii) then, if the value (based on the fair market value of a share of Common Stock on the last day of the Performance Period) of the aggregate number of Performance Share Units calculated under clause (i) exceeds the Payout Value Limit described on Schedule A, the number of Units calculated under clause (i) shall be reduced so that the value (based on the fair market value of a share of Common Stock on the last day of the Performance Period) of the total number of vested Performance Share Units is equal to the Payout Value Limit. Any Performance Share Units that do not vest under the foregoing two-step process as of the end of a Performance Period shall be forfeited as of the end of the Performance Period. Except as specifically provided below in this Section 3, in the event of a termination of the Participant’s employment prior to the end of a Performance Period, all unvested Performance Share Units will be immediately forfeited.
(c) If a 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), and the Committee determines, in its sole and absolute discretion, that the Performance Share Units shall continue to vest following the Participant’s Date of Termination, the Participant shall vest in the maximum number of Performance Share Units in which the Participant could vest, based on the two-step process described in Section 3(b), as if the Participant remained in the employ of the Company through the end of the Performance Period, provided that, if the Participant is Retirement Eligible, such continued vesting shall be subject to the satisfaction of the conditions in Section 15 (except in the case of the Participant’s disability).
(d) Performance Share Units shall continue to vest and the Participant shall vest in the maximum number of Performance Share Units in which the Participant could vest, based on the two-step process described in Section 3(b), as if the Participant remained in the employ of the Company through the end of the Performance Period following the Participant’s Date of Termination that 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, provided that for a severance related termination, 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 such Release becomes effective. 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 Performance Share Units (and Dividend Equivalents) subject to this Award Agreement shall be forfeited.

(e) A Participant shall become fully and immediately vested in the Award at the target level of performance for the Performance Period in the event of (1) the Participant’s death or (2) the occurrence of a Change in Control Event.
(f) Voting Rights and Dividend Equivalents . The Participant shall not have any voting rights with respect to the Performance Share Units. The Participant shall be credited with dividend equivalents (“Dividend Equivalents”) with respect to each outstanding Performance Share Unit to the extent that any dividends or other distributions (in cash or other property) are declared and/or paid with respect to the shares of Common Stock after the commencement of the Performance Period (other than distributions pursuant to a share split, for which an adjustment shall be made as described in Section 4 below). Dividend Equivalents shall be credited to the bookkeeping account established on the records of the Company for the Participant and will vest and be paid in cash to the Participant at the same time, and subject to the same conditions, as are applicable to the underlying Performance Share Units. Accordingly, Dividend Equivalents shall be forfeited to the extent that the Performance Share Units do not vest and are forfeited or cancelled. No interest shall be credited on Dividend Equivalents.
(g) Conversion of Performance Share Units; Delivery of Performance Share Units .
(i) Except in the event of the Participant’s death or the occurrence of a Change in Control Event, the Committee shall, within a reasonably practicable time following the last day of the Performance Period, certify the extent, if any, to which the Performance Goal has been achieved with respect to the Performance Period and the number of Performance Share Units, if any, earned upon attainment of the Performance Goal, as reduced by the Payout Value Limit, if applicable. Such certification shall be final, conclusive and binding on the Participant, and on all other persons, to the maximum extent permitted by law. Payment in respect of vested Performance Share Units and Dividend Equivalents shall be made promptly following the Committee’s certification of the attainment of the Performance Goal and the determination of the number of vested Performance Share Units, but in any event, no later than March 15 of the year following the year in which the Performance Period ends.
(ii) In the event of the Participant’s death or the occurrence of a Change in Control Event, payment in respect of earned and vested Performance Share Units shall be made as soon as reasonably practicable thereafter.
(iii) Notwithstanding any provision of this Award Agreement to the contrary, in no event shall the timing of the Participant’s execution of the Compliance Certificate, directly or indirectly, result in the Participant designating the calendar year of payment, and if a payment that is subject to execution of the Compliance Certificate could be made in more than one taxable year, payment shall be made in the later taxable year.
(iv) All payments in respect of earned and vested Performance Share Units shall be made in freely transferable shares of Common Stock. No fractional shares of Common Stock shall be issued pursuant to this Award, and any fractional share resulting from any calculation made in accordance with the terms of this Award Agreement shall be rounded down to the next whole share.

4. Certain Corporate Changes . If any change is made to the Common Stock (whether by reason of merger, consolidation, reorganization, recapitalization, stock dividend, stock split, combination of shares, or exchange of shares or any other change in capital structure made without receipt of consideration), then unless such event or change results in the termination of all the Performance Share Units granted under this Award Agreement, the Committee shall adjust, in an equitable manner and as provided in the Plan, the number and class of shares underlying the Performance Share Units, the maximum number of shares for which the Performance Share Units may vest, and the share price or class of Common Stock for purposes of the Performance Goal, as appropriate, to reflect the effect of such event or change in the Company’s capital structure in such a way as to preserve the value of the Performance Share Units. Any adjustment that occurs under the terms of this Section 4 or the Plan will not change the timing or form of payment with respect to any Performance Share Units except as permitted in accordance with section 409A of the Code.
5. 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.
6. Nontransferability of Award . The Participant shall not have the right to sell, assign, transfer, convey, dispose, pledge, hypothecate, burden, encumber or charge any Performance Share Unit or any interest therein in any manner whatsoever.
7. Notices . All notices or other communications relating to the Plan and this Agreement as it relates to the Participant shall be in writing and shall be delivered 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.
8. 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 Delaware.
9. Company Policies . The Participant agrees that the Award will be subject to any applicable clawback or recoupment policies, share trading policies and other policies that may be implemented by the Company’s Board of Directors or a duly authorized committee thereof, from time to time.
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 Dividend Equivalents). 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 Dividend Equivalents) 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. Compliance with Section 409A . This Award is intended to comply with the applicable requirements of section 409A of the Code and shall be administered in accordance with section 409A of the Code. Notwithstanding anything in this Award Agreement to the contrary, if the Performance Share Units constitute “deferred compensation” under section 409A of the Code and any Performance Share Units become payable pursuant to the Participant’s termination of employment, settlement of the Performance Share Units shall be delayed for a period of six months after the Participant’s termination of employment if the Participant is a “specified employee” as defined under section 409A of the Code and if required pursuant to section 409A of the Code. If settlement of the Performance Share Units is delayed, the Performance Share Units shall be settled within 30 days of the date that is the six-month anniversary of the Participant’s termination of employment. If the Participant dies during the six-month delay, the Performance Share Units shall be settled in accordance with the Participant’s will or under the applicable laws of descent and distribution. Notwithstanding any provision to the contrary herein, distributions made with respect to this Award may only be made in a manner and upon an event permitted by section 409A of the Code, and all payments to be made upon a termination of employment hereunder may only be made upon a “separation from service” as defined under section 409A of the Code. To the extent that any provision of the Award Agreement would cause a conflict with the requirements of section 409A of the Code, or would cause the administration of the Performance Share Units to fail to satisfy the requirements of section 409A of the Code, such provision shall be deemed null and void to the extent permitted by applicable law. In no event shall a Participant, directly or indirectly, designate the calendar year of payment. This Award Agreement may be amended without the consent of the Participant in any respect deemed by the Board of Directors or its delegate to be necessary in order to preserve compliance with section 409A of the Code.
13. 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.
14. 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.
15. Conditions to Post-Retirement Vesting .
(a) Notice of and Conditions to Post-Retirement Vesting . If the Participant is 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 15(a), to continue to vest following the Date of Termination in any unvested Performance Share Units provided that the Participant executes and delivers to the Company the following documentation: (i) a non-disclosure letter agreement, in the form attached as Exhibit A,(a “Non-Disclosure Agreement”), 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, no later than the time(s) required by the Committee.

(b) Consequences of Failure to Satisfy Vesting Conditions . In the event that, the Participant fails to deliver either the respective Non-Disclosure Agreement or Compliance Certificate 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 Performance Share Units and the unvested Performance Share Units subject to this Award Agreement shall be forfeited. The only remedy of the Company for failure to deliver a Non-Disclosure Agreement or a Compliance Certificate shall be the Participant’s failure to vest in, and forfeiture of, any unvested Performance Share Units.
16. Definitions . Words, terms or phrases used in this Award Agreement shall have the meaning set forth in this Section 16. Capitalized terms used in this Award Agreement but not defined herein shall have the meaning designated in the Plan.
(a) “ Award ” has the meaning set forth in Section 2.
(b) “ Award Agreement ” has the meaning set forth in the preamble.
(c) “ Company ” has the meaning set forth on the Cover Page.
(d) “ Compliance Certificate ” has the meaning set forth in Section 15(a).
(e) “ Date of Grant ” has the meaning set forth in the preamble.
(f) “ 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.
(g) “ Dividend Equivalent ” has the meaning set forth in Section 3(f).
(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) “ Non-Compliance Event ” has the meaning set forth in Section 15(b).

(j) “ Non-Disclosure Agreement ” has the meaning set forth in Section 15(a).
(k) “ 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.
(l) “ Participant ” has the meaning set forth in the preamble.
(m) “ Payout Value Limit ” has the meaning set forth in Section 4 of Schedule A.
(n) “ Performance Goal ” shall mean the performance goal specified on Schedule A which must be attained and certified in order to satisfy the first step of the 2-step process for vesting in the shares of Common Stock subject to this Award.
(o) “ Performance Period ” has the meaning set forth on the Cover Page and Schedule A over which the attainment of the Performance Goal is to be measured.
(p) “ Performance Share Unit ” the meaning set forth in the preamble.
(q) “ Plan ” has the meaning set forth in the preamble.
(r) “ Retirement Eligible ” means the Participant’s Date of Termination occurs on or after the Participant’s Early Retirement Date or Normal Retirement Date.
(s) “ 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%-%	

SCHEDULE A
PERFORMANCE GOAL, PERFORMANCE PERIOD AND PAYOUT VALUE LIMIT
1. Performance Period . The maximum number of Performance Share Units in which Participant can vest pursuant to the Award shall be calculated based on the Performance Goal over a three-year Performance Period that begins January 1, 2014 and ends December 31, 2016 (the “Performance Period”).
2. Performance Goal . The Performance Goal is based on total shareholder return (“TSR”). TSR shall mean the rate of return stockholders receive through stock price changes and the assumed reinvestment of dividends over the Performance Period. Vesting will be based on the Company’s TSR ranking relative to the TSR ranking of the Peer Companies (identified in Section 3(d) below). At the end of the Performance Period, the TSR for the Company, and for each Peer Company, shall be determined pursuant to the following formula:

TSR =  (Closing Average Share Value - Opening Average Share Value) + Reinvested Dividends	  		
        Opening Average Share Value	  		
The result shall be rounded to the nearest hundredth of one percent (.01%).
(a) The term “Closing Average Share Value” means the average value of the common stock for the 30 trading days ending on the last day of the Performance Period, which shall be calculated as follows: (i) determine the closing price of the common stock on each trading date during 30-day period and (ii) average the amounts so determined for the 30-day period.
(b) The term “Opening Average Share Value” means the average value of the common stock for the 30 trading days preceding the start of the Performance Period, which shall be calculated as follows: (i) determine the closing price of the common stock on each trading date during the 30-day period and (ii) average the amounts so determined for the 30-day period.
(c) “Reinvested Dividends” shall be calculated by multiplying (i) the aggregate number of shares (including fractional shares) that could have been purchased during the Performance Period had each cash dividend paid on a single share during that period been immediately reinvested in additional shares (or fractional shares) at the closing selling price per share on the applicable dividend payment date by (ii) the average daily closing price per share calculated for the duration of the Performance Period following the dividend payment date.
(d) Each of the foregoing amounts shall be equitably adjusted for stock splits, stock dividends, recapitalizations and other similar events affecting the shares in question without the issuer’s receipt of consideration.

3. Vesting Schedule . The Performance Share Units will vest pursuant to the Award, subject to application of the Payout Value Limit described in Section 4 below, based on the Company’s relative TSR ranking in respect of the Performance Period as compared to the TSR ranking of the Peer Companies, in accordance with the following schedule:

Devon Energy Corporation Relative TSR Ranking	  	Vesting
(Percentage of Target Award)
in the event of Positive TSR	 	 	Vesting
(Percentage of Target
Award) in the event of
Negative TSR	 	
1-3	  	 	200	% 	 	 	100	% 	
4	  	 	175	% 	 	 	100	% 	
5	  	 	150	% 	 	 	100	% 	
6	  	 	125	% 	 	 	100	% 	
7	  	 	100	% 	 	 	100	% 	
Median	  	 	90	% 	 	 	90	% 	
9	  	 	80	% 	 	 	80	% 	
10	  	 	70	% 	 	 	70	% 	
11	  	 	60	% 	 	 	60	% 	
12	  	 	50	% 	 	 	50	% 	
13-15	  	 	0	% 	 	 	0	% 	
(a) In the event TSR is positive for the Performance Period, the maximum number of Performance Share Units that can vest for the Performance Period may range from 0% to 200% of the target Award, with the actual percentage to be determined on the basis of the percentile level at which the Committee certifies that the Performance Goal has been attained in relation to the corresponding Performance Goal for Peer Companies for the Performance Period; provided however, that the maximum number of Performance Share Units that may become earned and vested during such Performance Period will be calculated as follows: %%TOTAL_SHARES_GRANTED%-% x 200%.
(b) In the event the Company’s TSR is negative for the Performance Period, the maximum number of Performance Share Units that can vest for the Performance Period may range from 0% to 100% of the target Award, with the actual percentage to be determined on the basis of the percentile level at which the Committee certifies that the Performance Goal has been attained in relation to the corresponding Performance Goal for Peer Companies for the Performance Period; provided however, that the maximum number of Performance Share Units that may become earned and vested during such Performance Period will be calculated as follows: %%TOTAL_SHARES_GRANTED%-% x 100%.
(c) The Committee retains sole discretion to reduce the vesting percentage (and thus the maximum number of Performance Share Units that may vest), including reduction to zero, without regard to the performance of the Company’s TSR relative to the TSR of the Peer Companies. In addition, vesting of Performance Share Units shall be subject to the Payout Value Limit described in Section 4 below.
(d) If the Company’s final TSR value is equal to the TSR value of a Peer Company, the Committee shall assign the Company the higher ranking.
(e) In addition to the Company, the Peer Companies are Anadarko Petroleum Corporation, Apache Corporation, Chesapeake Energy Corporation, Newfield Exploration Company, ConocoPhillips, EnCana Corporation, EOG Resources, Inc., Hess Corporation, Marathon Oil Corporation, Murphy Oil Corporation, Noble Energy, Inc., Occidental Petroleum Corporation, Pioneer Natural Resources Company, and Talisman Energy, Inc.

(f) The Peer Companies will be subject to change as follows:
(i) In the event of a merger, acquisition or business combination transaction of a Peer Company, in which the Peer Company is the surviving entity and remains publicly traded, the surviving entity shall remain a Peer Company. Any entity involved in the transaction that is not the surviving company shall no longer be a Peer Company.
(ii) If a Peer Company ceases to be a publicly traded company at any time during the Performance Period, for any reason, such company shall remain a Peer Company but shall be deemed to have a TSR of negative 100% (-100%).
4. Reduction . If the value (based on the fair market value of a share of Common Stock on the last day of the Performance Period) of the aggregate number of Performance Share Units that vest pursuant to the Award based on Sections 1-3 of this Schedule A exceeds the Payout Value Limit, then the maximum number of vested Performance Share Units calculated under Sections 1-3 of this Schedule A shall be reduced so that the value (based on the fair market value of a share of Common Stock on the last day of the Performance Period) of the total number of Performance Share Units that vest pursuant to the Award is equal to the Payout Value Limit. The “Payout Value Limit” shall be equal to the product of (a) the fair market value of a share of Common Stock on the first day of the Performance Period, times (b) the target number of Units subject to the Award, times (c) four.
5. General Vesting Terms . Any fractional Performance Share Unit resulting from the vesting of the Performance Share Units in accordance with the Award Agreement shall be rounded down to the nearest whole number. Any portion of the Performance Share Units that does not vest as of the end of the Performance Period shall be forfeited as of the end of the Performance Period.

EXHIBIT A
Form of Non-Disclosure Agreement
[Insert Date]
Devon Energy Corporation
333 West Sheridan Avenue
Oklahoma City, OK 73102-5010
 
 	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 Performance Share Unit Award Agreement (the “Agreement”) 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 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 2014-2016 Performance Period.]
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             ,         .

 	
[Name of Participant]	

Dated:	 	 	

Exhibit 10.33

	  	Devon Energy Corporation	
	  	ID: 73-1567067	
	  	333 West Sheridan Avenue	
	  	Oklahoma City, Oklahoma 73102-5015	

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 vest 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 your signature and the Company’s signature below, 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, as amended and restated June 6, 2012, including 2013 amendment, and the Award Agreement, both of which are attached and made a part of this document.

 

Devon Energy Corporation	 		 	Date	

%%FIRST_NAME%-% %%MIDDLE_NAME%-% %%LAST_NAME%-%	 		 	Date	

DEVON ENERGY CORPORATION
2009 LONG-TERM INCENTIVE PLAN
NON-MANAGEMENT DIRECTOR
RESTRICTED STOCK AWARD AGREEMENT
THIS RESTRICTED STOCK AWARD AGREEMENT (the “Agreement”) 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 Company has previously adopted the “Devon Energy Corporation 2009 Long-Term Incentive Plan”, as amended and restated June 6, 2012, including 2013 amendment (the “Plan”); and
WHEREAS, the Participant is a nonemployee director of the Company and it is important to the Company that the Participant be encouraged to remain a director of the Company; and
WHEREAS, in recognition of such facts, the Company desires to award to the Participant %%TOTAL_SHARES_GRANTED%-% shares of the Company Common Stock under the Plan subject to the terms and conditions of this 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 Agreement shall govern the rights of the Participant and the Company with respect to the Award (as defined below).
2. Grant of Award . The Company hereby grants to the Participant an award (the “Award”) of %%TOTAL_SHARES_GRANTED%-% shares of the Company 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 Agreement.
(b) Vesting . If the Participant’s Date of Termination has not occurred as of the vesting date(s) specified below (the “Vesting Date(s)”), then, the Participant shall be entitled, subject to the applicable provisions of the Plan and this Agreement having been satisfied, to receive on or within a reasonable time after the applicable Vesting Date(s), the number of shares of Common Stock as described in the following schedule. Once vested pursuant to the terms of this 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,” 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 paragraphs (i), (ii) or (iii) below.
(i) The Award shall become fully vested upon the occurrence of a Change of Control Event which occurs prior to the Participant’s Date of Termination.
(ii) The Award 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 discretion, elect to accelerate vesting of all or any portion of the Award if the Date of Termination occurs by reason of the Participant’s disability or occurs under other special circumstances (as determined by the Committee).
(iii) The Award 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 Mandatory Retirement.
(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 (“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 the Award shall be subject to the following legend:
“THE SHARES OF STOCK EVIDENCED BY THIS CERTIFICATE OR BOOK-ENTRY REGISTRATION ARE SUBJECT TO AND ARE TRANSFERRABLE ONLY IN ACCORDANCE WITH THAT CERTAIN RESTRICTED STOCK AWARD AGREEMENT DATED %%OPTION_DATE%-% FOR THE DEVON ENERGY CORPORATION 2009 LONG-TERM INCENTIVE PLAN, AS AMENDED AND RESTATED JUNE 6, 2012, INCLUDING 2013 AMENDMENT. ANY ATTEMPTED TRANSFER OF THE SHARES OF STOCK EVIDENCED BY THIS CERTIFICATE OR BOOK-ENTRY REGISTRATION IN VIOLATION OF SUCH AGREEMENT SHALL BE NULL AND VOID AND WITHOUT EFFECT. A COPY OF THE 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 Agreement. The Participant further authorizes the Company to hold as a general obligation of the Company any Accrued Dividends and to pay such dividends to the Participant at the time the underlying Restricted Stock becomes Vested Stock.
6. Nontransferability of Award . The Participant shall not have the right to sell, assign, transfer, convey, dispose, pledge, hypothecate, burden, encumber or charge the Award or any Restricted Stock or any interest therein in any manner whatsoever.

7. Notices . All notices or other communications relating to the Plan and this 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.
8. Binding Effect and Governing Law . This 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.
9. 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 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 Agreement.
10. Captions . The captions of specific provisions of this Agreement are for convenience and reference only, and in no way define, describe, extend or limit the scope of this Agreement or the intent of any provision hereof.
11. Counterparts . This 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.
12. Definitions . Words, terms, or phrases used in this Agreement shall have the meaning set forth in this Section 12. Capitalized terms used in this 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) “Agreement” has the meaning set forth in the preamble.
(c) “Award” has the meaning set forth in Section 2.
(d) “Company” has the meaning set forth on the Cover Page.
(e) “Date of Grant” has the meaning set forth in the preamble.
(f) “Date of Termination” means the first day occurring on or after the Date of Grant on which the Participant is not a member of the Board.
(g) “Escrow Agent” has the meaning set forth in Section 3(a).
(h) “Mandatory Retirement” means the Participant’s mandatory retirement from the Board of Directors at the next annual meeting of shareholders following the date the Participant reaches his 73 rd birthday.
(i) “Restricted Stock” has the meaning set forth in Section 2.
(i) “Vested Stock” has the meaning set forth in Section 3(b).
(k) “Vesting Date” has the meaning set forth in Section 3(b).

IN WITNESS WHEREOF, the parties hereto have executed this Agreement on the day and year first above written.

“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 12
RATIO OF EARNINGS TO FIXED CHARGES
December 31, 2013

 	  	Years Ended December 31,	 	
 	  	2013	 	 	2012	 	 	2011	 	 	2010	 	 	2009	 	
 	  	(In millions, expect ratio amounts)	 	
Earnings (loss) from continuing operations before income taxes	  	$	149	  	 	$	(317	) 	 	$	4,290	  	 	$	3,568	  	 	$	(4,527	) 	
Capitalized interest, net of amortization	  	 	(4	) 	 	 	(2	) 	 	 	(26	) 	 	 	(20	) 	 	 	(47	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
	  	 	145	  	 	 	(319	) 	 	 	4,264	  	 	 	3,548	  	 	 	(4,574	) 	
Fixed charges:	  				 				 				 				 				
Interest expensed and capitalized	  	 	493	  	 	 	454	  	 	 	424	  	 	 	439	  	 	 	444	  	
Estimate of interest within rental expense	  	 	9	  	 	 	14	  	 	 	14	  	 	 	21	  	 	 	23	  	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total fixed charges	  	 	501	  	 	 	468	  	 	 	438	  	 	 	460	  	 	 	467	  	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Earnings (loss) available for payment of fixed charges	  	$	646	  	 	$	149	  	 	$	4,702	  	 	$	4,008	  	 	$	(4,107	) 	

Ratio of earnings to fixed charges	  	$	1.29	  	 	 	N/A	  	 	$	10.74	  	 	$	8.71	  	 	 	N/A	  	
Insufficient earnings to fixed charges	  	 	N/A	  	 	$	319	  	 	 	N/A	  	 	 	N/A	  	 	$	4,574	  	
 
N/A    Not applicable.

Exhibit 21
DEVON ENERGY CORPORATION
Significant Subsidiaries
 
1.	Devon Energy Corporation (Oklahoma), an Oklahoma corporation	
 
2.	Devon Financing Company, L.L.C., a Delaware limited liability company	
 
3.	Devon OEI Holdings, L.L.C., a Delaware limited liability company	
 
4.	Devon OEI Operating, L.L.C., a Delaware limited liability company	
 
5.	Devon Energy Production Company, L.P., an Oklahoma limited partnership	
 
6.	Devon AXL, a general partnership registered in Alberta	
 
7.	Devon Canada Corporation, a Nova Scotia corporation	
 
8.	Devon Operating Company Ltd., an Alberta corporation	
 
9.	Devon Canada Holdings LP, an Alberta limited partnership	
 
10.	Devon Canada, a general partnership registered in Alberta	
 
11.	Devon NEC Corporation, a Nova Scotia corporation	

Exhibit 23.1
Consent of Independent Registered Public Accounting Firm
The Board of Directors
Devon Energy Corporation:
We consent to the incorporation by reference in the registration statements (File No. 333-68694, 333-47672, 333-44702, 333-104933, 333-104922, 333-103679, 333-159796, 333-127630, 333-179181, 333-182198) on Form S-8 and the registration statement (File No. 333-178453) on Form S-3 of Devon Energy Corporation of our report dated February 28, 2014, with respect to the consolidated balance sheets of Devon Energy Corporation as of December 31, 2013 and 2012, and the related consolidated comprehensive statements of earnings, cash flows, and stockholders’ equity for each of the years in the three-year period ended December 31, 2013, and the effectiveness of internal control over financial reporting as of December 31, 2013, which report appears in the December 31, 2013 annual report on Form 10-K of Devon Energy Corporation.

/s/ KPMG LLP	
Oklahoma City, Oklahoma
February 28, 2014

Exhibit 23.2
ENGINEER’S CONSENT
We consent to incorporation by reference in the Registration Statements (File Nos. 333-68694, 333-47672, 333-44702, 333-104922, 333-104933, 333-103679, 333-127630, 333-159796, 333-179181 and 333-182198) on Form S-8, and the Registration Statement (File No. 333-178453) on Form S-3 of Devon Energy Corporation of the reference to our reports for Devon Energy Corporation, which appears in the December 31, 2013 annual report on Form 10-K of Devon Energy Corporation.

LaRoche Petroleum Consultants, Ltd.	
		
By:	 	/s/ William M. Kazmann	
	 	William M. Kazmann
Partner	
February 19, 2014

Exhibit 23.3
ENGINEER’S CONSENT
We consent to incorporation by reference in the Registration Statements (File Nos. 333-68694, 333-47672, 333-44702, 333-104922, 333-104933, 333-103679, 333-127630, 333-159796, 333-179181 and 333-182198) on Form S-8, and the Registration Statement (File No. 333-178453) on Form S-3 of Devon Energy Corporation of the reference to our reports for Devon Energy Corporation, which appears in the December 31, 2013 annual report on Form 10-K of Devon Energy Corporation.

Deloitte	
		
By:	 	/s/ Robin G. Bertram	
	 	Robin G. Bertram, P.Eng	
February 11, 2014

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 28, 2014

Exhibit 31.2
CERTIFICATION PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Thomas L. Mitchell, 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/ Thomas L. Mitchell	 		
	 	Thomas L. Mitchell	 		
	 	Executive Vice President and Chief Financial Officer	 		
Date: February 28, 2014

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, 2013 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, John Richels, President and Chief Executive Officer of Devon, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:
 
 	(1)	The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and	
 
 	(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Devon.	

/s/ John Richels	
John Richels	
President and Chief Executive Officer	
February 28, 2014	

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, 2013 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Thomas L. Mitchell, Executive Vice President and Chief Financial Officer of Devon, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:
 
 	(1)	The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and	
 
 	(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Devon.	

/s/ Thomas L. Mitchell	
Thomas L. Mitchell	
Executive Vice President and Chief Financial Officer	
February 28, 2014	

Exhibit 99.1

January 28, 2014
Mr. Bob Fant
Director Reserves and Economics
Devon Energy Corporation
333 West Sheridan Avenue
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, 2013, to the Devon Energy Corporation (Devon) interest in certain properties located in Devon’s US Division in the United States as prepared and completed by Devon on January 10, 2014. 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-two percent (92%) of Devon’s aggregate proved reserves for the US Division 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-eight percent (68%) of Devon’s aggregate, corporate proved reserves as estimated and reported by Devon.
The US Division reserves presented above are for the field areas designated by Devon’s internal naming system. These areas include 1) Anadarko Basin Business Unit: Field Groups Cana, and Cana Other; 2) Mississippian Business Unit: Field Groups Frank NONSDA and Frank SDA; 3) North Texas Business Unit: Field Groups Boonsville, Boonsville South, FWB Conventional Minor, FWB Conventional Minor South, NEBS Core Lean, NEBS Core N Denton, NEBS Core N Wise, NEBS Core Rich Denton, NEBS Core Rich Wise, NEBS Noncore Denton, NEBS Noncore Lean, NEBS Noncore South, NEBS Noncore W Viola North, NEBS Noncore W Viola South, NEBS Noncore Western Extension, and NEBS Noncore Wise; 4) Permian Basin Business Unit: Field Groups Ackerly Area, Anton Irish, Catclaw Draw Area, Corbin Area, Deep Delaware, Diamond Mound, El Dorado, Fullerton Area, Gaucho Area, Hackberry, Ingle Wells/Sand Dunes, Keystone/Kermit, McKnight, Mi Vida, Midland Basin, Odessa, Other PB New Mexico, Other PB Texas East, Other PB Texas West, Outland Area, Ozona Area, Potato Basin Area, Reeves, Silver City, Slaughter, Townsend Area, Waddell North, Waddell South, Wasson, Welch Area, and Wolfberry NW; 5) Southern Business Unit: Field Groups Arkansas Other, Bethany, Bethany Haynesville Shale, Calhoun, Carthage Central, Carthage North Other,
 
2435 N Central Expressway, Suite 1500 — Dallas TX 75080 — Phone (214) 363-3337 — Fax (214) 363-1608

Carthage South, Central (Haynesville Shale), East Texas Other, Eastern Ohio, Lassater, Mississippi Other, North Louisiana Other, Northwest Louisiana Other, Rocky Mount/Serepta, Ruston North, Shady Grove, South (Haynesville Shale), South Louisiana, Southeast (Haynesville Shale), Stockman/Appleby, Waskom, and Waskom Haynesville Shale Area; 6) Rocky Mountain Business Unit: Project Areas Big Horn, Green River, Powder River Basin CBM, RM Other, San Juan, Washakie and Wind River.
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, 2013 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 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.
 
LaRoche Petroleum Consultants, Ltd.

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 2013. Oil prices used by Devon are based on a Cushing West Texas Intermediate crude oil price of $96.94 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 $3.67 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 $31.37 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 2013 were furnished by Devon and were accepted as presented. Oil and gas prices are held constant throughout the life of the properties. The weighted average prices over the life of the properties are $92.29 per barrel for oil, $3.09 per Mcf for gas, and $25.72 per barrel for NGL in the US Division.
Lease and well operating expenses were furnished by Devon and were confirmed by LPC from a review of Devon accounting data on a Project Area or Field Group basis. As requested, expenses for the Devon-operated properties include only direct lease and field level costs. For properties operated by others, these expenses include the per-well overhead costs allowed under joint operating agreements along with direct lease and field level costs. Headquarters general and administrative overhead expenses of Devon are not included. Operating expenses are held constant throughout the life of the properties.
Capital costs and timing of all investments have been provided by Devon and are included as required for workovers, new development wells, and production equipment. Devon has represented to us that they have the ability and intent to implement their capital expenditure program as scheduled. Devon’s estimates of the cost to plug and abandon the wells net of salvage value are included and scheduled at the end of the economic life of individual properties. These costs are held constant.
LPC has made no investigation of possible gas volume and value imbalances that may have been the result of overdelivery or underdelivery to the Devon interest. Our projections are based on Devon receiving its net revenue interest share of estimated future gross oil, gas, and NGL production.
An on-site inspection of the properties has not been performed nor has the mechanical operation or condition of the wells and their related facilities been examined by LPC. The costs associated with the continued operation of uneconomic properties are not reflected in the cash flows.
The evaluation of potential environmental liability from the operation and abandonment of the properties is beyond the scope of this audit. In addition, no evaluation was made to determine the degree of operator compliance with current environmental rules, regulations, and reporting requirements. Therefore, no estimate of the potential economic liability, if any, from environmental concerns is included in our projections.
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
 
LaRoche Petroleum Consultants, Ltd.

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 Securities 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, 2013 annual report on Form 10-K and/or 10-K/A 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-nine years of engineering experience in the oil and gas industry. Mr. Kazmann earned Bachelor of Science and Master of Science degrees in Petroleum Engineering from the University of Texas at Austin and has prepared reserves estimates for his employers and his own companies throughout his career. He has
 
LaRoche Petroleum Consultants, Ltd.

prepared and overseen preparation of reports for public filings for LPC for the past seventeen years. We are independent petroleum engineers, geologists, and geophysicists and are not employed on a contingent basis. Data pertinent to the audit are maintained on file in our office.
Very truly yours,
LaRoche Petroleum Consultants, Ltd.
State of Texas Registration Number F-1360
/s/ William M. Kazmann
William M. Kazmann
Licensed Professional Engineer
State of Texas No. 45012
/s/ Joe A. Young
Joe A. Young
Licensed Professional Engineer
State of Texas No. 62866
WMK:mk
13-600
cc: Gary Cartwright
 
LaRoche Petroleum Consultants, Ltd.

Exhibit 99.2

	  		  	Deloitte LLP
Suite 700,850 – 2nd Street S.W.
Calgary, AB T2P OR8
Canada
 
Tel: 403-267-1700
Fax: 587-774-5398
www.deloitte.ca	
February 5, 2014
Devon Energy Corporation
333 West Sheridan
Oklahoma City, Oklahoma
USA 73102
Attention: Mr. Bob Fant
 
Re:	Devon Canada Corporation	
    	December 31, 2013 reserve audit opinion	
At your request and authorization, Deloitte LLP (Deloitte) has audited the reserves management processes and practices of Devon Canada Corporation (Devon Canada) as of December 31, 2013. Our audit was completed on December 15, 2013 and 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 for certain properties within Western Canada. Deloitte’s estimate for the audited properties varied from Devon Canada’s estimates by less than 10 percent. When compared to Devon Canada’s parent corporation, Devon Energy Corporation, Deloitte audited 23 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 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 Deloitte. However, in our opinion, the estimates prepared by Devon Canada are in aggregate reasonable, are within the established audit tolerance of plus or minus 10 percent and the estimates have been prepared in accordance with generally accepted petroleum engineering practices and procedures. These practices and procedures are detailed within the Canadian Oil and Gas Evaluation Handbook (COGEH), set out by the Society of Petroleum Evaluation Engineers (SPEE) as well as the Society of Petroleum Engineers’ (SPE) Standards Pertaining to the Estimation and Auditing of Oil and Gas Reserves. We believe that such assumptions, data, methods, and procedures are appropriate for the purpose served by the report. For the purpose of this audit only deterministic methods were used. The proved reserve estimates prepared by both Devon Canada and Deloitte 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.
Deloitte was provided with Devon Canada’s base hydrocarbon prices (oil, gas, condensate and natural gas liquids) as of December 31, 2013 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 Deloitte’s individual property evaluations. An oil equivalent conversion factor of 6.0 Mcf per 1.0 barrel oil was used for sales gas.

Devon Energy Corporation
December 31, 2013 reserve audit opinion
Page 2
 
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 Deloitte and the consultant makes no representations and accepts no responsibilities in this regard.
It should be understood that our audit does not constitute a complete reserves study of the oil and gas properties of your company. In the conduct of our examinations we have not independently verified the accuracy and completeness of all the information and data furnished by your company with respect to ownership interests, oil and gas production, historical costs of operations and development, product prices, and agreements relating to current and future operations and sales of production. We have, however, specifically identified to you the information and data upon which we relied so that you can subject it to procedures you consider necessary. Furthermore, if in the course of our examination something came to our attention that brought into question the validity or sufficiency of any of the information or data, we did not rely on that information or data until we had satisfactorily resolved our questions or independently verified it.
The accuracy of any reserve and production estimates is a function of the quality and quantity of available data and of engineering interpretation and judgment. While reserve and production estimates adhere to Regulation S-K, 229.1202 and Regulation S-X, 4-10(a) (as applicable), the estimates should be accepted with the understanding that reservoir performance subsequent to the date of the estimate may justify revision, either upward or downward. If government regulations change, the net after royalty recoverable reserve volumes may change materially.
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 and Geoscientists’ of Alberta (APEGA).
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 audit, 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 audit for Devon Energy Corporation, which appears in the December 31, 2013 annual report on Form 10-K of Devon Energy Corporation. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by Devon Energy Corporation.
Yours truly,
Original signed by: “Robin G. Bertram”
Robin G. Bertram, P. Eng.
Partner
Deloitte LLP
/ct