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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-Q

(Mark One)
þ 	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934	
For the quarterly period ended June 30, 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
Former name, address and former fiscal year, if changed from last report: Not applicable
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes   þ     No   ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes   þ     No   ¨
Indicate by check mark 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.

Large accelerated filer	 	þ	  	Accelerated filer	 	¨	
				
Non-accelerated filer	 	¨   (Do not check if a smaller reporting company)	  	Smaller reporting company	 	¨	
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes   ¨     No   þ
On July 18, 2013, 406 million shares of common stock were outstanding.

 

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

Part I Financial Information	  				
Item 1. Consolidated Financial Statements	  				
Consolidated Comprehensive Statements of Earnings	  	 	3	  	
Consolidated Statements of Cash Flows	  	 	4	  	
Consolidated Balance Sheets	  	 	5	  	
Consolidated Statements of Stockholders’ Equity	  	 	6	  	
Notes to Consolidated Financial Statements	  	 	7	  	
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	  	 	21	  	
Item 3. Quantitative and Qualitative Disclosures About Market Risk	  	 	32	  	
Item 4. Controls and Procedures	  	 	32	  	
		
Part II Other Information	  				
Item 1. Legal Proceedings	  	 	34	  	
Item 1A. Risk Factors	  	 	34	  	
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	  	 	34	  	
Item 3. Defaults Upon Senior Securities	  	 	34	  	
Item 4. Mine Safety Disclosures	  	 	34	  	
Item 5. Other Information	  	 	34	  	
Item 6. Exhibits	  	 	35	  	
		
Signatures	  	 	36	  	
INFORMATION REGARDING FORWARD-LOOKING STATEMENTS
This report includes forward-looking statements regarding our expectations and plans, as well as future events or conditions. Such forward-looking statements are based on our examination of historical operating trends, the information used to prepare our December 31, 2012 reserve reports and other data in our possession or available from third parties. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond our control. Consequently, actual future results could differ materially from our expectations due to a number of factors, such as changes in the supply of and demand for oil, natural gas and NGLs and related products and services; exploration or drilling programs; political or regulatory events; general economic and financial market conditions; and other factors discussed in this report.
All subsequent written and oral forward-looking statements attributable to Devon, or persons acting on its behalf, are expressly qualified in their entirety by the cautionary statements above. We assume no duty to update or revise our forward-looking statements based on new information, future events or otherwise.
 
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 DEVON ENERGY CORPORATION AND SUBSIDIARIES
 CONSOLIDATED COMPREHENSIVE STATEMENTS OF EARNINGS

 	  	Three Months
Ended June 30,	 	 	Six Months
Ended June 30,	 	
 	  	2013	 	 	2012	 	 	2013	 	 	2012	 	
 	  	(Unaudited)
(In millions, except per share amounts)	 	
Revenues:	  				 				 				 				
Oil, gas and NGL sales	  	$	2,222	 	 	$	1,617	 	 	$	4,026	 	 	$	3,532	 	
Oil, gas and NGL derivatives	  	 	366	 	 	 	665	 	 	 	46	 	 	 	810	 	
Marketing and midstream revenues	  	 	503	 	 	 	277	 	 	 	991	 	 	 	714	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total revenues	  	 	3,091	 	 	 	2,559	 	 	 	5,063	 	 	 	5,056	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Expenses and other, net:	  				 				 				 				
Lease operating expenses	  	 	559	 	 	 	513	 	 	 	1,084	 	 	 	1,027	 	
Marketing and midstream operating costs and expenses	  	 	382	 	 	 	209	 	 	 	745	 	 	 	534	 	
Depreciation, depletion and amortization	  	 	674	 	 	 	684	 	 	 	1,378	 	 	 	1,364	 	
General and administrative expenses	  	 	167	 	 	 	176	 	 	 	317	 	 	 	344	 	
Taxes other than income taxes	  	 	125	 	 	 	100	 	 	 	238	 	 	 	202	 	
Interest expense	  	 	108	 	 	 	99	 	 	 	218	 	 	 	186	 	
Restructuring costs	  	 	8	 	 	 	—  	  	 	 	46	 	 	 	—  	  	
Asset impairments	  	 	40	 	 	 	—  	  	 	 	1,953	 	 	 	—  	  	
Other, net	  	 	31	 	 	 	44	 	 	 	49	 	 	 	54	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total expenses and other, net	  	 	2,094	 	 	 	1,825	 	 	 	6,028	 	 	 	3,711	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Earnings (loss) from continuing operations before income taxes	  	 	997	 	 	 	734	 	 	 	(965	) 	 	 	1,345	 	
Current income tax expense	  	 	132	 	 	 	31	 	 	 	132	 	 	 	49	 	
Deferred income tax expense (benefit)	  	 	182	 	 	 	226	 	 	 	(441	) 	 	 	405	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Earnings (loss) from continuing operations	  	 	683	 	 	 	477	 	 	 	(656	) 	 	 	891	 	
Loss from discontinued operations, net of tax	  	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	(21	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net earnings (loss)	  	$	683	 	 	$	477	 	 	$	(656	) 	 	$	870	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Basic net earnings (loss) per share:	  				 				 				 				
Basic earnings (loss) from continuing operations per share	  	$	1.69	 	 	$	1.18	 	 	$	(1.63	) 	 	$	2.20	 	
Basic loss from discontinued operations per share	  	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	(0.05	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Basic net earnings (loss) per share	  	$	1.69	 	 	$	1.18	 	 	$	(1.63	) 	 	$	2.15	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Diluted net earnings (loss) per share:	  				 				 				 				
Diluted earnings (loss) from continuing operations per share	  	$	1.68	 	 	$	1.18	 	 	$	(1.63	) 	 	$	2.20	 	
Diluted loss from discontinued operations per share	  	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	(0.05	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Diluted net earnings (loss) per share	  	$	1.68	 	 	$	1.18	 	 	$	(1.63	) 	 	$	2.15	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Comprehensive earnings (loss):	  				 				 				 				
Net earnings (loss)	  	$	683	 	 	$	477	 	 	$	(656	) 	 	$	870	 	
Other comprehensive loss, net of tax:	  				 				 				 				
Foreign currency translation	  	 	(271	) 	 	 	(171	) 	 	 	(454	) 	 	 	(19	) 	
Pension and postretirement plans	  	 	5	 	 	 	5	 	 	 	9	 	 	 	9	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Other comprehensive loss, net of tax	  	 	(266	) 	 	 	(166	) 	 	 	(445	) 	 	 	(10	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Comprehensive earnings (loss)	  	$	417	 	 	$	311	 	 	$	(1,101	) 	 	$	860	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
See accompanying notes to consolidated financial statements.
 
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
 CONSOLIDATED STATEMENTS OF CASH FLOWS

 	  	Six Months
Ended June 30,	 	
 	  	2013	 	 	2012	 	
 	  	(Unaudited)	 	
 	  	(In millions)	 	
Cash flows from operating activities:	  				 				
Net earnings (loss)	  	$	(656	) 	 	$	870	 	
Loss from discontinued operations, net of tax	  	 	—  	  	 	 	21	 	
Adjustments to reconcile earnings (loss) from continuing operations to net cash from operating activities:	  				 				
Depreciation, depletion and amortization	  	 	1,378	 	 	 	1,364	 	
Asset impairments	  	 	1,953	 	 	 	—  	  	
Deferred income tax expense (benefit)	  	 	(441	) 	 	 	405	 	
Unrealized change in fair value of financial instruments	  	 	46	 	 	 	(362	) 	
Other noncash charges	  	 	176	 	 	 	114	 	
Net decrease (increase) in working capital	  	 	(128	) 	 	 	14	 	
Decrease in long-term other assets	  	 	22	  	 	 	3	  	
Increase (decrease) in long-term other liabilities	  	 	48	  	 	 	(3	) 	
	  	 	 	 	 	 	 	 	
Cash from operating activities – continuing operations	  	 	2,398	  	 	 	2,426	 	
Cash from operating activities – discontinued operations	  	 	—  	  	 	 	26	 	
	  	 	 	 	 	 	 	 	
Net cash from operating activities	  	 	2,398	  	 	 	2,452	 	
	  	 	 	 	 	 	 	 	
Cash flows from investing activities:	  				 				
Capital expenditures	  	 	(3,569	) 	 	 	(4,267	) 	
Proceeds from property and equipment divestitures	  	 	34	 	 	 	864	 	
Purchases of short-term investments	  	 	(1,076	) 	 	 	(1,471	) 	
Redemptions of short-term investments	  	 	2,550	 	 	 	2,030	 	
Other	  	 	82	 	 	 	14	 	
	  	 	 	 	 	 	 	 	
Cash from investing activities – continuing operations	  	 	(1,979	) 	 	 	(2,830	) 	
Cash from investing activities – discontinued operations	  	 	—  	  	 	 	58	 	
	  	 	 	 	 	 	 	 	
Net cash from investing activities	  	 	(1,979	) 	 	 	(2,772	) 	
	  	 	 	 	 	 	 	 	
Cash flows from financing activities:	  				 				
Proceeds from borrowings of long-term debt, net of issuance costs	  	 	—  	  	 	 	2,465	 	
Net short-term debt repayments	  	 	(1,495	) 	 	 	(1,498	) 	
Credit facility borrowings	  	 	—  	  	 	 	750	 	
Credit facility repayments	  	 	—  	  	 	 	(750	) 	
Proceeds from stock option exercises	  	 	1	 	 	 	22	 	
Dividends paid on common stock	  	 	(170	) 	 	 	(162	) 	
Excess tax benefits related to share-based compensation	  	 	5	 	 	 	1	 	
	  	 	 	 	 	 	 	 	
Net cash from financing activities	  	 	(1,659	) 	 	 	828	 	
	  	 	 	 	 	 	 	 	
Effect of exchange rate changes on cash	  	 	(34	) 	 	 	38	 	
	  	 	 	 	 	 	 	 	
Net change in cash and cash equivalents	  	 	(1,274	) 	 	 	546	 	
			
Cash and cash equivalents at beginning of period	  	 	4,637	 	 	 	5,555	 	
	  	 	 	 	 	 	 	 	
Cash and cash equivalents at end of period	  	$	3,363	 	 	$	6,101	 	
	  	 	 	 	 	 	 	 	
See accompanying notes to consolidated financial statements.
 
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
 CONSOLIDATED BALANCE SHEETS

 	  	June 30,	 	 	December 31,	 	
 	  	2013	 	 	2012	 	
 	  	(Unaudited)	 	 	 	 	
 	  	(In millions, except share data)	 	
ASSETS	  				 				
Current assets:	  				 				
Cash and cash equivalents	  	$	3,363	 	 	$	4,637	 	
Short-term investments	  	 	869	 	 	 	2,343	 	
Accounts receivable	  	 	1,538	 	 	 	1,245	 	
Other current assets	  	 	587	 	 	 	746	 	
	  	 	 	 	 	 	 	 	
Total current assets	  	 	6,357	 	 	 	8,971	 	
	  	 	 	 	 	 	 	 	
Property and equipment, at cost:	  				 				
Oil and gas, based on full cost accounting:	  				 				
Subject to amortization	  	 	71,057	 	 	 	69,410	 	
Not subject to amortization	  	 	3,382	 	 	 	3,308	 	
	  	 	 	 	 	 	 	 	
Total oil and gas	  	 	74,439	 	 	 	72,718	 	
Other	  	 	5,839	 	 	 	5,630	 	
	  	 	 	 	 	 	 	 	
Total property and equipment, at cost	  	 	80,278	 	 	 	78,348	 	
Less accumulated depreciation, depletion and amortization	  	 	(53,353	) 	 	 	(51,032	) 	
	  	 	 	 	 	 	 	 	
Property and equipment, net	  	 	26,925	 	 	 	27,316	 	
	  	 	 	 	 	 	 	 	
Goodwill	  	 	5,917	 	 	 	6,079	 	
Other long-term assets	  	 	821	 	 	 	960	 	
	  	 	 	 	 	 	 	 	
Total assets	  	$	40,020	 	 	$	43,326	 	
	  	 	 	 	 	 	 	 	
LIABILITIES AND STOCKHOLDERS’ EQUITY	  				 				
Current liabilities:	  				 				
Accounts payable	  	$	1,197	 	 	$	1,451	 	
Revenues and royalties payable	  	 	830	 	 	 	750	 	
Short-term debt	  	 	2,194	 	 	 	3,189	 	
Other current liabilities	  	 	644	 	 	 	613	 	
	  	 	 	 	 	 	 	 	
Total current liabilities	  	 	4,865	 	 	 	6,003	 	
	  	 	 	 	 	 	 	 	
Long-term debt	  	 	7,956	 	 	 	8,455	 	
Asset retirement obligations	  	 	2,121	 	 	 	1,996	 	
Other long-term liabilities	  	 	816	 	 	 	901	 	
Deferred income taxes	  	 	4,196	 	 	 	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	  	 	3,747	 	 	 	3,688	 	
Retained earnings	  	 	14,952	 	 	 	15,778	 	
Accumulated other comprehensive earnings	  	 	1,326	 	 	 	1,771	 	
	  	 	 	 	 	 	 	 	
Total stockholders’ equity	  	 	20,066	 	 	 	21,278	 	
	  	 	 	 	 	 	 	 	
Commitments and contingencies (Note 17)	  				 				
Total liabilities and stockholders’ equity	  	$	40,020	 	 	$	43,326	 	
	  	 	 	 	 	 	 	 	
See accompanying notes to consolidated financial statements.
 
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
 CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

 	  	 	 	  	 	 	  	Additional
Paid-In	 	 	 	 	 	Accumulated
Other	 	 	 	 	 	Total	 	
 	  	Common Stock	 	  			 	Retained	 	 	Comprehensive	 	 	Treasury	 	 	Stockholders’	 	
 	  	Shares	 	  	Amount	 	  	Capital	 	 	Earnings	 	 	Earnings	 	 	Stock	 	 	Equity	 	
 	  	(Unaudited)	 	
 	  	(In millions)	 	
Six Months Ended June 30, 2013:	  				  				  				 				 				 				 				
Balance as of December 31, 2012	  	 	406	 	  	$	41	 	  	$	3,688	 	 	$	15,778	 	 	$	1,771	 	 	$	—  	  	 	$	21,278	 	
Net loss	  	 	—  	  	  	 	—  	  	  	 	—  	  	 	 	(656	) 	 	 	—  	  	 	 	—  	  	 	 	(656	) 	
Other comprehensive loss, net of tax	  	 	—  	  	  	 	—  	  	  	 	—  	  	 	 	—  	  	 	 	(445	) 	 	 	—  	  	 	 	(445	) 	
Stock option exercises	  	 	—  	  	  	 	—  	  	  	 	1	 	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	1	 	
Common stock repurchased	  	 	—  	  	  	 	—  	  	  	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	(9	) 	 	 	(9	) 	
Common stock retired	  	 	—  	  	  	 	—  	  	  	 	(9	) 	 	 	—  	  	 	 	—  	  	 	 	9	 	 	 	—  	  	
Common stock dividends	  	 	—  	  	  	 	—  	  	  	 	—  	  	 	 	(170	) 	 	 	—  	  	 	 	—  	  	 	 	(170	) 	
Share-based compensation	  	 	—  	  	  	 	—  	  	  	 	62	 	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	62	 	
Share-based compensation tax benefits	  	 	—  	  	  	 	—  	  	  	 	5	 	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	5	 	
	  	 	 	 	  	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance as of June 30, 2013	  	 	406	 	  	$	41	 	  	$	3,747	 	 	$	14,952	 	 	$	1,326	 	 	$	—  	  	 	$	20,066	 	
	  	 	 	 	  	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Six Months Ended June 30, 2012:	  				  				  				 				 				 				 				
Balance as of December 31, 2011	  	 	404	 	  	$	40	 	  	$	3,507	 	 	$	16,308	 	 	$	1,575	 	 	$	—  	  	 	$	21,430	 	
Net earnings	  	 	—  	  	  	 	—  	  	  	 	—  	  	 	 	870	 	 	 	—  	  	 	 	—  	  	 	 	870	 	
Other comprehensive loss, net of tax	  	 	—  	  	  	 	—  	  	  	 	—  	  	 	 	—  	  	 	 	(10	) 	 	 	—  	  	 	 	(10	) 	
Stock option exercises	  	 	1	 	  	 	—  	  	  	 	22	 	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	22	 	
Common stock repurchased	  	 	—  	  	  	 	—  	  	  	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	(1	) 	 	 	(1	) 	
Common stock retired	  	 	—  	  	  	 	—  	  	  	 	(1	) 	 	 	—  	  	 	 	—  	  	 	 	1	 	 	 	—  	  	
Common stock dividends	  	 	—  	  	  	 	—  	  	  	 	—  	  	 	 	(162	) 	 	 	—  	  	 	 	—  	  	 	 	(162	) 	
Share-based compensation	  	 	—  	  	  	 	—  	  	  	 	75	 	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	75	 	
Share-based compensation tax benefits	  	 	—  	  	  	 	—  	  	  	 	1	 	 	 	—  	  	 	 	—  	  	 	 	—  	  	 	 	1	 	
	  	 	 	 	  	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance as of June 30, 2012	  	 	405	 	  	$	40	 	  	$	3,604	 	 	$	17,016	 	 	$	1,565	 	 	$	—  	  	 	$	22,225	 	
	  	 	 	 	  	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
See accompanying notes to consolidated financial statements.
 
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. Summary of Significant Accounting Policies
The accompanying unaudited financial statements and notes of Devon Energy Corporation (“Devon”) have been prepared pursuant to the rules and regulations of the United States Securities and Exchange Commission. Pursuant to such rules and regulations, certain disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been omitted. The accompanying financial statements and notes should be read in conjunction with the financial statements and notes included in Devon’s 2012 Annual Report on Form 10-K.
The accompanying unaudited interim financial statements furnished in this report reflect all adjustments that are, in the opinion of management, necessary to a fair statement of Devon’s results of operations and cash flows for the three-month and six-month periods ended June 30, 2013 and 2012 and Devon’s financial position as of June 30, 2013.
2. Derivative Financial Instruments
Objectives and Strategies
Devon periodically enters into derivative financial instruments with respect to a portion of its oil, gas and NGL production. These instruments are used to manage the inherent uncertainty of future revenues due to commodity price volatility and typically include financial price swaps, basis swaps, costless price collars and call options.
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.
Devon does not intend to hold or issue derivative financial instruments for speculative trading purposes and has elected not to designate any of its derivative instruments for hedge accounting treatment.
Counterparty Credit Risk
By using derivative financial instruments, 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 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 contain provisions that provide for collateral payments, depending on levels of exposure and the credit rating of the counterparty.
As of June 30, 2013, Devon held $39 million of cash collateral. Such amount 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.
Commodity Derivatives
As of June 30, 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)	 	
Q3-Q4 2013	  	 	70,000	  	  	$	100.26	  	  	 	65,000	  	  	$	90.13	  	  	$	111.91	  	  	 	10,000	  	  	$	120.00	  	
Q1-Q4 2014	  	 	21,000	  	  	$	94.99	  	  	 	10,000	  	  	$	86.53	  	  	$	102.75	  	  	 	42,000	  	  	$	116.43	  	
Q1-Q4 2015	  	 	500	  	  	$	91.00	  	  	 	—  	  	  	$	—  	  	  	$	—  	  	  	 	22,000	  	  	$	115.45	  	
 
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

 	  	Basis Swaps	 	
Period	  	Index	  	Volume
(Bbls/d)	 	  	Weighted Average
Differential to WTI
($/Bbl)	 	
Q3-Q4 2013	  	Western Canadian Select	  	 	40,000	  	  	$	(22.30	) 	
As of June 30, 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)	 	
Q3-Q4 2013	  	 	987,500	  	  	$	4.09	  	  	 	650,000	  	  	$	3.61	  	  	$	4.28	  	  	 	—	  	  	$	—	  	
Q1-Q4 2014	  	 	800,000	  	  	$	4.42	  	  	 	210,000	  	  	$	4.01	  	  	$	4.71	  	  	 	500,000	  	  	$	5.00	  	
Q1-Q4 2015	  	 	—	  	  	$	—	  	  	 	—	  	  	$	—	  	  	$	—	  	  	 	550,000	  	  	$	5.09	  	

 	  	Price Swaps	 	
Period	  	Volume
(MMBtu/d)	 	  	Weighted
Average Price
($/MMBtu)	 	
Q3-Q4 2013	  	 	28,435	  	  	$	3.46	  	
As of June 30, 2013, Devon had the following open NGL derivative positions. Devon’s NGL derivatives settle against the average of the prompt month OPIS Mont Belvieu, Texas hub.

 	  	Price Swaps	 	
Period	  	Product	 	  	Volume
(Bbls/d)	 	  	Weighted
Average Price
($/Bbl)	 	
Q3-Q4 2013	  	 	Propane	  	  	 	1,141	  	  	$	41.24	  	
Q3-Q4 2013	  	 	Ethane	  	  	 	1,957	  	  	$	15.36	  	

 	  	Basis Swaps	 	
Period	  	Pay	 	  	Volume
(Bbls/d)	 	  	Weighted Average
Differential to WTI
($/Bbl)	 	
Q3-Q4 2013	  	 	Natural Gasoline	  	  	 	500	  	  	$	(6.80	) 	
Interest Rate Derivatives
As of June 30, 2013, Devon had the following open interest rate derivative position:

Notional	  	Weighted Average
Fixed Rate Received	 	Variable Rate Paid	 	  	Expiration	 	
(In millions)	  	 	 	 	 	  	 	 	
$750	  	3.88%	 	 	Federal funds rate	  	  	 	July 2013	  	
 
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
 
Foreign Currency Derivatives
As of June 30, 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	  	  	$	1,261	  	  	0.967	  	 	September 2013	  	
Financial Statement Presentation
The following table presents the cash settlements and unrealized gains and losses on fair value changes included in the accompanying comprehensive statements of earnings associated with derivative financial instruments. Cash settlements and unrealized gains and losses on fair value changes associated with Devon’s commodity derivatives are presented in the “Oil, gas and NGL derivatives” caption in the accompanying comprehensive statements of earnings. Cash settlements and unrealized gains and losses on fair value changes associated with Devon’s interest rate and foreign currency derivatives are presented in the “Other, net” caption in the accompanying comprehensive statements of earnings.

 	  	Three Months
Ended June 30,	 	 	Six Months
Ended June 30,	 	
 	  	2013	 	 	2012	 	 	2013	 	 	2012	 	
 	  	(In millions)	 	
Cash settlements:	  				 				 				 				
Commodity derivatives	  	$	14	  	 	$	267	  	 	$	100	  	 	$	425	  	
Interest rate derivatives	  	 	5	  	 	 	(11	) 	 	 	14	  	 	 	(1	) 	
Foreign currency derivatives	  	 	16	  	 	 	20	  	 	 	35	  	 	 	9	  	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total cash settlements	  	 	35	  	 	 	276	  	 	 	149	  	 	 	433	  	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Unrealized gains (losses):	  				 				 				 				
Commodity derivatives	  	 	352	  	 	 	398	  	 	 	(54	) 	 	 	385	  	
Interest rate derivatives	  	 	(5	) 	 	 	(5	) 	 	 	(14	) 	 	 	(15	) 	
Foreign currency derivatives	  	 	26	  	 	 	(9	) 	 	 	22	  	 	 	(8	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total unrealized gains (losses)	  	 	373	  	 	 	384	  	 	 	(46	) 	 	 	362	  	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net gains recognized on comprehensive statements of earnings	  	$	408	  	 	$	660	  	 	$	103	  	 	$	795	  	

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
 
The following table presents the derivative fair values included in the accompanying balance sheets.

 	  	Balance Sheet Caption	  	June 30, 2013	 	  	December 31, 2012	 	
 	  	 	  	(In millions)	 	
Asset derivatives:	  		  				  				
Commodity derivatives	  	Other current assets	  	$	299	  	  	$	379	  	
Commodity derivatives	  	Other long-term assets	  	 	109	  	  	 	22	  	
Interest rate derivatives	  	Other current assets	  	 	9	  	  	 	23	  	
Foreign currency derivatives	  	Other current assets	  	 	23	  	  	 	1	  	
	  		  	 	 	 	  	 	 	 	
Total asset derivatives	  		  	$	440	  	  	$	425	  	
	  		  	 	 	 	  	 	 	 	
Liability derivatives:	  		  				  				
Commodity derivatives	  	Other current liabilities	  	$	24	  	  	$	3	  	
Commodity derivatives	  	Other long-term liabilities	  	 	69	  	  	 	29	  	
	  		  	 	 	 	  	 	 	 	
Total liability derivatives	  		  	$	93	  	  	$	32	  	
	  		  	 	 	 	  	 	 	 	
3. 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 headquarters in Oklahoma City. As of June 30, 2013, Devon had substantially completed this initiative and incurred $126 million of restructuring costs associated with the office consolidation.
Divestiture of Offshore Assets
In the fourth quarter of 2009, Devon announced plans to divest its offshore assets. Devon completed this divestiture program in 2012, having incurred $196 million of cumulative restructuring costs associated with the divestitures.
Financial Statement Presentation
The schedule below summarizes restructuring costs presented in the accompanying comprehensive statements of earnings related to the office consolidation. There were no costs related to the offshore divestitures in the three-month and six-month periods ended June 30, 2013 and 2012.

 	  	Six Months
Ended June 30,	 	
 	  	2013	 	  	2012	 	
 	  	(In millions)	 	
Lease obligations and other	  	$	40	  	  	$	—  	  	
Asset impairments	  	 	6	  	  	 	—  	  	
	  	 	 	 	  	 	 	 	
Restructuring costs	  	$	46	  	  	$	—  	  	
	  	 	 	 	  	 	 	 	
In the six months ended June 30, 2013, Devon incurred $25 million of restructuring costs related to office space that is subject to non-cancellable operating lease agreements that Devon ceased using as a part of the office consolidation. Devon also recognized $6 million of asset impairment charges for leasehold improvements and furniture associated with the office consolidation.
 
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
 
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	  	
Lease obligations—Offshore	  	 	(9	) 	 	 	(1	) 	 	 	(10	) 	
Employee severance—Offshore	  	 	(5	) 	 	 	—  	  	 	 	(5	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	
Balance as June 30, 2012	  	$	15	  	 	$	15	  	 	$	30	  	
	  	 	 	 	 	 	 	 	 	 	 	 	
Balance as of December 31, 2012	  	$	52	  	 	$	9	  	 	$	61	  	
Lease obligations and other—Office consolidation	  	 	14	  	 	 	11	  	 	 	25	  	
Employee severance—Office consolidation	  	 	(21	) 	 	 	—  	  	 	 	(21	) 	
Lease obligations—Offshore	  	 	(1	) 	 	 	(1	) 	 	 	(2	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	
Balance as of June 30, 2013	  	$	44	  	 	$	19	  	 	$	63	  	
	  	 	 	 	 	 	 	 	 	 	 	 	
4. Other, net
The components of other, net in the accompanying comprehensive statements of earnings include the following:

 	  	Three Months Ended
June 30,	 	 	Six Months Ended
June 30,	 	
 	  	2013	 	 	2012	 	 	2013	 	 	2012	 	
 	  	(In millions)	 	
Accretion of asset retirement obligations	  	$	29	  	 	$	28	  	 	$	57	  	 	$	55	  	
Interest rate derivatives	  	 	—  	  	 	 	16	  	 	 	—  	  	 	 	16	  	
Foreign currency derivatives	  	 	(42	) 	 	 	(11	) 	 	 	(57	) 	 	 	(1	) 	
Foreign exchange loss	  	 	44	  	 	 	15	  	 	 	61	  	 	 	1	  	
Interest income	  	 	(4	) 	 	 	(9	) 	 	 	(12	) 	 	 	(16	) 	
Other	  	 	4	  	 	 	5	  	 	 	—  	  	 	 	(1	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Other, net	  	$	31	  	 	$	44	  	 	$	49	  	 	$	54	  	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
5. Income Taxes
In the second quarter of 2013, Devon repatriated to the United States $2.0 billion of cash from its foreign subsidiaries. In conjunction with the repatriation, Devon recognized approximately $100 million of current income tax expense. The current expense was entirely offset by the recognition of deferred income tax benefits, which included the reduction of the deferred tax liability previously recognized for unremitted foreign earnings deemed not to be indefinitely reinvested.
As of June 30, 2013, Devon’s unremitted foreign earnings totaled approximately $5.6 billion. Of this amount, approximately $4.4 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 U.S. income taxes associated with such earnings. If such earnings were to be repatriated to the U.S., Devon may be subject to U.S. 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.
 
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
 
Devon has deemed the remaining $1.2 billion of unremitted foreign earnings not to be indefinitely reinvested. Consequently, Devon has recognized a deferred tax liability of approximately $550 million associated with such unremitted earnings as of June 30, 2013.
The following table presents our total income tax expense (benefit) and a reconciliation of our effective income tax rate to the U.S. statutory income tax rate.

 	  	Three Months Ended
June 30,	 	 	Six Months Ended
June 30,	 	
 	  	2013	 	 	2012	 	 	2013	 	 	2012	 	
Total income tax expense (benefit) (in millions)	  	$	314	  	 	$	257	  	 	$	(309	) 	 	$	454	  	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
U.S. statutory income tax rate	  	 	35	% 	 	 	35	% 	 	 	(35	%) 	 	 	35	% 	
State income taxes	  	 	1	% 	 	 	1	% 	 	 	(1	%) 	 	 	1	% 	
Taxation on Canadian operations	  	 	(2	%) 	 	 	(1	%) 	 	 	6	% 	 	 	(2	%) 	
Other	  	 	(2	%) 	 	 	—  	  	 	 	(2	%) 	 	 	—  	  	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Effective income tax rate	  	 	32	% 	 	 	35	% 	 	 	(32	%) 	 	 	34	% 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
6. Earnings (Loss) Per Share
The following table reconciles earnings (loss) from continuing operations and common shares outstanding used in the calculations of basic and diluted earnings per share.

 	  	 	 	 	Common	 	 	Earnings (loss)	 	
 	  	Earnings (loss)	 	 	Shares	 	 	per Share	 	
 	  	(In millions, except per share amounts)	 	
Three Months Ended June 30, 2013:	  				 				 				
Earnings from continuing operations	  	$	683	  	 	 	406	  	 				
Attributable to participating securities	  	 	(5	) 	 	 	(4	) 	 				
	  	 	 	 	 	 	 	 	 				
Basic earnings per share	  	 	678	  	 	 	402	  	 	$	1.69	  	
Dilutive effect of potential common shares issuable	  	 	—  	  	 	 	1	  	 				
	  	 	 	 	 	 	 	 	 				
Diluted earnings per share	  	$	678	  	 	 	403	  	 	$	1.68	  	
	  	 	 	 	 	 	 	 	 				
Three Months Ended June 30, 2012:	  				 				 				
Earnings from continuing operations	  	$	477	  	 	 	404	  	 				
Attributable to participating securities	  	 	(6	) 	 	 	(4	) 	 				
	  	 	 	 	 	 	 	 	 				
Basic earnings per share	  	 	471	  	 	 	400	  	 	$	1.18	  	
Dilutive effect of potential common shares issuable	  	 	—  	  	 	 	—  	  	 				
	  	 	 	 	 	 	 	 	 				
Diluted earnings per share	  	$	471	  	 	 	400	  	 	$	1.18	  	
	  	 	 	 	 	 	 	 	 				
Six Months Ended June 30, 2013:	  				 				 				
Loss from continuing operations	  	$	(656	) 	 	 	406	  	 				
Attributable to participating securities	  	 	(1	) 	 	 	(4	) 	 				
	  	 	 	 	 	 	 	 	 				
Basic earnings per share	  	 	(657	) 	 	 	402	  	 	$	(1.63	) 	
Dilutive effect of potential common shares issuable	  	 	—  	  	 	 	—  	  	 				
	  	 	 	 	 	 	 	 	 				
Diluted loss per share	  	$	(657	) 	 	 	402	  	 	$	(1.63	) 	

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

 	  	 	 	 	Common	 	 	Earnings (loss)	 	
 	  	Earnings (loss)	 	 	Shares	 	 	per Share	 	
 	  	(In millions, except per share amounts)	 	
Six Months Ended June 30, 2012:	  				 				 				
Earnings from continuing operations	  	$	891	  	 	 	404	  	 				
Attributable to participating securities	  	 	(10	) 	 	 	(4	) 	 				
	  	 	 	 	 	 	 	 	 				
Basic earnings per share	  	 	881	  	 	 	400	  	 	$	2.20	  	
Dilutive effect of potential common shares issuable	  	 	—  	  	 	 	1	  	 				
	  	 	 	 	 	 	 	 	 				
Diluted earnings per share	  	$	881	  	 	 	401	  	 	$	2.20	  	
	  	 	 	 	 	 	 	 	 				
Certain options to purchase shares of Devon’s common stock are excluded from the dilution calculation because the options are antidilutive. During the three-month and six-month periods ended June 30, 2013, 7.6 million shares were excluded from the diluted earnings per share calculations. During the three-month and six-month periods ended June 30, 2012, 8.9 million shares and 6.7 million shares, respectively, were excluded from the diluted earnings per share calculations.
7. Other Comprehensive Earnings
Components of other comprehensive earnings consist of the following:

 	  	Three Months Ended
June 30,	 	 	Six Months Ended
June 30,	 	
 	  	2013	 	 	2012	 	 	2013	 	 	2012	 	
 	  	(In millions)	 	
Foreign currency translation:	  				 				 				 				
Beginning accumulated foreign currency translation	  	$	1,813	  	 	$	1,954	  	 	$	1,996	  	 	$	1,802	  	
Change in cumulative translation adjustment	  	 	(284	) 	 	 	(179	) 	 	 	(475	) 	 	 	(20	) 	
Income tax benefit	  	 	13	  	 	 	8	  	 	 	21	  	 	 	1	  	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Ending accumulated foreign currency translation	  	 	1,542	  	 	 	1,783	  	 	 	1,542	  	 	 	1,783	  	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Pension and postretirement benefit plans:	  				 				 				 				
Beginning accumulated pension and postretirement benefits	  	 	(221	) 	 	 	(223	) 	 	 	(225	) 	 	 	(227	) 	
Recognition of net actuarial loss and prior service cost in earnings (1)	  	 	6	  	 	 	7	  	 	 	12	  	 	 	13	  	
Income tax expense	  	 	(1	) 	 	 	(2	) 	 	 	(3	) 	 	 	(4	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Ending accumulated pension and postretirement benefits	  	 	(216	) 	 	 	(218	) 	 	 	(216	) 	 	 	(218	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Accumulated other comprehensive earnings, net of tax	  	$	1,326	  	 	$	1,565	  	 	$	1,326	  	 	$	1,565	  	

(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).	
 
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
 
8. Supplemental Information to Statements of Cash Flows

 	  	Six Months Ended
June 30,	 	
 	  	2013	 	 	2012	 	
 	  	(In millions)	 	
Net change in working capital accounts:	  				 				
Accounts receivable	  	$	(300	) 	 	$	384	  	
Other current assets	  	 	72	  	 	 	(191	) 	
Accounts payable	  	 	56	  	 	 	13	  	
Revenues and royalties payable	  	 	82	  	 	 	(139	) 	
Other current liabilities	  	 	(38	) 	 	 	(53	) 	
	  	 	 	 	 	 	 	 	
Net decrease (increase) in working capital	  	$	(128	) 	 	$	14	  	
	  	 	 	 	 	 	 	 	
Interest paid (net of capitalized interest)	  	$	208	  	 	$	169	  	
Income taxes paid (received)	  	$	(2	) 	 	$	88	  	
9. Short-Term Investments
The components of short-term investments include the following:

 	  	June 30, 2013	 	  	December 31, 2012	 	
 	  	(In millions)	 	
Canadian treasury, agency and provincial securities	  	$	759	  	  	$	1,865	  	
U.S. treasuries	  	 	110	  	  	 	429	  	
Other	  	 	—  	  	  	 	49	  	
	  	 	 	 	  	 	 	 	
Short-term investments	  	$	869	  	  	$	2,343	  	
	  	 	 	 	  	 	 	 	
10. Accounts Receivable
The components of accounts receivable include the following:

 	  	June 30, 2013	 	 	December 31, 2012	 	
 	  	(In millions)	 	
Oil, gas and NGL sales	  	$	915	  	 	$	752	  	
Joint interest billings	  	 	432	  	 	 	270	  	
Marketing and midstream revenues	  	 	160	  	 	 	161	  	
Other	  	 	41	  	 	 	72	  	
	  	 	 	 	 	 	 	 	
Gross accounts receivable	  	 	1,548	  	 	 	1,255	  	
Allowance for doubtful accounts	  	 	(10	) 	 	 	(10	) 	
	  	 	 	 	 	 	 	 	
Net accounts receivable	  	$	1,538	  	 	$	1,245	  	

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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
 
11. Property and Equipment
Asset Impairments
In the first six months of 2013, Devon recognized asset impairments related to its oil and gas property and equipment as presented below.

 	  	Six Months Ended June 30, 2013	 	
 	  	Gross	 	  	Net of Taxes	 	
 	  	(In millions)	 	
U.S. oil and gas assets	  	$	1,110	  	  	$	707	  	
Canada oil and gas assets	  	 	843	  	  	 	632	  	
	  	 	 	 	  	 	 	 	
Total asset impairments	  	$	1,953	  	  	$	1,339	  	
	  	 	 	 	  	 	 	 	
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. 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.
The oil and gas impairments resulted primarily from declines in the U.S. and Canada full cost ceilings since December 31, 2012. The lower ceiling values resulted primarily from decreases in the 12-month average trailing prices for oil, bitumen and NGLs, which have reduced proved reserve values.
If estimated future cash flows decline due to price decreases or other factors, Devon could incur additional full cost ceiling impairments related to its oil and gas property and equipment.
12. Goodwill
During the first six months of 2013, Devon’s Canadian goodwill decreased $162 million entirely due to foreign currency translation.
13. Debt
Commercial Paper
During the second quarter of 2013, Devon repatriated $2.0 billion of foreign earnings to the United States and repaid $2.0 billion of commercial paper borrowings. As of June 30, 2013, Devon had $1.7 billion of outstanding commercial paper at an average rate of 0.36 percent.
Credit Lines
Devon has a $3.0 billion syndicated, unsecured revolving line of credit (the “Senior Credit Facility”). As of June 30, 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. As of June 30, 2013, Devon was in compliance with this covenant with a debt-to-capitalization ratio of 22.8 percent.
 
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
 
14. Asset Retirement Obligations
The schedule below summarizes changes in Devon’s asset retirement obligations.

 	  	Six Months Ended June 30,	 	
 	  	2013	 	 	2012	 	
 	  	(In millions)	 	
Asset retirement obligations as of beginning of period	  	$	2,095	  	 	$	1,563	  	
Liabilities incurred	  	 	67	  	 	 	33	  	
Liabilities settled	  	 	(40	) 	 	 	(32	) 	
Revision of estimated obligation	  	 	105	  	 	 	399	  	
Liabilities assumed by others	  	 	(4	) 	 	 	(2	) 	
Accretion expense on discounted obligation	  	 	57	  	 	 	55	  	
Foreign currency translation adjustment	  	 	(72	) 	 	 	(10	) 	
	  	 	 	 	 	 	 	 	
Asset retirement obligations as of end of period	  	 	2,208	  	 	 	2,006	  	
Less current portion	  	 	87	  	 	 	64	  	
	  	 	 	 	 	 	 	 	
Asset retirement obligations, long-term	  	$	2,121	  	 	$	1,942	  	
	  	 	 	 	 	 	 	 	
15. Retirement Plans
The following table presents the components of net periodic benefit cost for Devon’s pension and postretirement benefit plans.

 	  	Pension Benefits	 	 	Postretirement Benefits	 	
 	  	Three Months Ended	 	 	Six Months Ended	 	 	Three Months Ended	 	  	Six Months Ended	 	
 	  	June 30,	 	 	June 30,	 	 	June 30,	 	  	June 30,	 	
 	  	2013	 	 	2012	 	 	2013	 	 	2012	 	 	2013	 	 	2012	 	  	2013	 	 	2012	 	
 	  	(In millions)	 	
Service cost	  	$	9	  	 	$	10	  	 	$	18	  	 	$	21	  	 	$	—  	  	 	$	—  	  	  	$	—  	  	 	$	—  	  	
Interest cost	  	 	13	  	 	 	15	  	 	 	26	  	 	 	30	  	 	 	1	  	 	 	—  	  	  	 	1	  	 	 	1	  	
Expected return on plan assets	  	 	(16	) 	 	 	(16	) 	 	 	(31	) 	 	 	(32	) 	 	 	—  	  	 	 	—  	  	  	 	—  	  	 	 	—  	  	
Amortization of prior service cost (1)	  	 	1	  	 	 	1	  	 	 	2	  	 	 	2	  	 	 	—  	  	 	 	—  	  	  	 	—  	  	 	 	(1	) 	
Net actuarial loss (gain) (1)	  	 	6	  	 	 	6	  	 	 	11	  	 	 	12	  	 	 	(1	) 	 	 	—  	  	  	 	(1	) 	 	 	—  	  	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	  	 	 	 	 	 	 	 	
Net periodic benefit cost (2)	  	$	13	  	 	$	16	  	 	$	26	  	 	$	33	  	 	$	—  	  	 	$	—  	  	  	$	—  	  	 	$	—  	  	

(1)	These net periodic benefit costs were reclassified out of 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)
(Unaudited)
 
16. Stockholders’ Equity
Dividends
Devon paid common stock dividends of $170 million and $162 million in the first six months of 2013 and 2012, respectively. The quarterly cash dividend was $0.20 per share in the first and second quarter of 2012 and in the first quarter of 2013. Devon increased the dividend rate to $0.22 per share in the second quarter of 2013.
17. 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.
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.
Chief Redemption Matters
In 2006, Devon acquired Chief Holdings LLC (“Chief”) from the owners of Chief, including Trevor Rees-Jones, the majority owner of Chief. In 2008, a former owner of Chief filed a petition against Rees-Jones, as the former majority owner of Chief, and Devon, as Chief’s successor pursuant to the 2006 acquisition. The petition claimed, among other things, violations of the Texas Securities Act, fraud and breaches of Rees-Jones’ fiduciary responsibility to the former owner in connection with Chief’s 2004 redemption of the owner’s minority ownership stake in Chief.
On June 20, 2011, a court issued a judgment against Rees-Jones for $196 million, of which $133 million of the judgment was also issued against Devon. Devon did not have a legal right of set off with respect to the judgment. Therefore, Devon had recorded a $133 million long-term liability relating to the judgment with an offsetting $133 million long-term receivable relating to its right to be indemnified by Rees-Jones and certain other parties pursuant to the indemnification agreement.
The plaintiffs and Rees-Jones have settled all claims related to the 2004 redemption. Under the terms of the settlement, Rees-Jones and Devon received full releases for all of the plaintiffs’ claims with Rees-Jones funding all settlement payments. Consequently, Devon reversed the previously recorded liability and asset in the first quarter of 2013.
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.
 
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
 
18. 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 June 30, 2013 and December 31, 2012. Therefore, such financial assets and liabilities are not presented in the following tables.

 	  	 	 	 	 	 	 	Fair Value Measurements Using:	 	
 	  	Carrying	 	 	Total Fair	 	 	Level 1	 	  	Level 2	 	 	Level 3	 	
 	  	Amount	 	 	Value	 	 	Inputs	 	  	Inputs	 	 	Inputs	 	
 	  	(In millions)	 	
June 30, 2013 assets (liabilities):	  				 				 				  				 				
Cash equivalents	  	$	2,559	  	 	$	2,559	  	 	$	65	  	  	$	2,494	  	 	$	—  	  	
Short-term investments	  	$	869	  	 	$	869	  	 	$	110	  	  	$	759	  	 	$	—  	  	
Long-term investments	  	$	62	  	 	$	62	  	 	$	—  	  	  	$	—  	  	 	$	62	  	
Commodity derivatives	  	$	408	  	 	$	408	  	 	$	—  	  	  	$	408	  	 	$	—  	  	
Commodity derivatives	  	$	(93	) 	 	$	(93	) 	 	$	—  	  	  	$	(93	) 	 	$	—  	  	
Interest rate derivatives	  	$	9	  	 	$	9	  	 	$	—  	  	  	$	9	  	 	$	—  	  	
Foreign currency derivatives	  	$	23	  	 	$	23	  	 	$	—  	  	  	$	23	  	 	$	—  	  	
Debt	  	$	(10,150	) 	 	$	(11,026	) 	 	$	—  	  	  	$	(11,026	) 	 	$	—  	  	
December 31, 2012 assets (liabilities):	  				 				 				  				 				
Cash equivalents	  	$	4,149	  	 	$	4,149	  	 	$	200	  	  	$	3,949	  	 	$	—  	  	
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 U.S. 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 are estimated based on rates available for debt with similar terms and maturity. The fair value of Devon’s variable-rate commercial paper is the carrying value.
 
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
 
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 an inactive 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 U.S. 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 June 30, 2013 and December 31, 2012.
Included below is a summary of the changes in Devon’s Level 3 fair value measurements during the first six months of 2013 and 2012.

 	  	Six Months Ended June 30,	 	
 	  	2013	 	 	2012	 	
 	  	(In millions)	 	
Long-term investments balance at beginning of period	  	$	64	  	 	$	84	  	
Redemptions of principal	  	 	(2	) 	 	 	(15	) 	
	  	 	 	 	 	 	 	 	
Long-term investments balance at end of period	  	$	62	  	 	$	69	  	
	  	 	 	 	 	 	 	 	
19. 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. Revenues are all from external customers.

 	  	U.S.	 	  	Canada	 	 	Total	 	
 	  	(In millions)	 	
Three Months Ended June 30, 2013:	  				  				 				
Oil, gas and NGL sales	  	$	1,514	  	  	$	708	  	 	$	2,222	  	
Oil, gas and NGL derivatives	  	$	366	  	  	$	—  	  	 	$	366	  	
Marketing and midstream revenues	  	$	489	  	  	$	14	  	 	$	503	  	
Depreciation, depletion and amortization	  	$	465	  	  	$	209	  	 	$	674	  	
Interest expense	  	$	94	  	  	$	14	  	 	$	108	  	
Asset impairments	  	$	—  	  	  	$	40	  	 	$	40	  	
Earnings from continuing operations before income taxes	  	$	885	  	  	$	112	  	 	$	997	  	
Income tax expense	  	$	294	  	  	$	20	  	 	$	314	  	
Earnings from continuing operations	  	$	591	  	  	$	92	  	 	$	683	  	
Capital expenditures	  	$	1,140	  	  	$	356	  	 	$	1,496	  	
				
Three Months Ended June 30, 2012:	  				  				 				
Oil, gas and NGL sales	  	$	1,014	  	  	$	603	  	 	$	1,617	  	
Oil, gas and NGL derivatives	  	$	665	  	  	$	—  	  	 	$	665	  	
Marketing and midstream revenues	  	$	250	  	  	$	27	  	 	$	277	  	
Depreciation, depletion and amortization	  	$	439	  	  	$	245	  	 	$	684	  	
Interest expense	  	$	84	  	  	$	15	  	 	$	99	  	
Earnings from continuing operations before income taxes	  	$	727	  	  	$	7	  	 	$	734	  	
Income tax expense (benefit)	  	$	259	  	  	$	(2	) 	 	$	257	  	
Earnings from continuing operations	  	$	468	  	  	$	9	  	 	$	477	  	
Capital expenditures	  	$	1,985	  	  	$	384	  	 	$	2,369	  	
 
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)

 	  	U.S.	 	 	Canada	 	 	Total	 	
 	  	(In millions)	 	
				
Six Months Ended June 30, 2013:	  				 				 				
Oil, gas and NGL sales	  	$	2,804	  	 	$	1,222	  	 	$	4,026	  	
Oil, gas and NGL derivatives	  	$	71	  	 	$	(25	) 	 	$	46	  	
Marketing and midstream revenues	  	$	927	  	 	$	64	  	 	$	991	  	
Depreciation, depletion and amortization	  	$	934	  	 	$	444	  	 	$	1,378	  	
Interest expense	  	$	190	  	 	$	28	  	 	$	218	  	
Asset impairments	  	$	1,110	  	 	$	843	  	 	$	1,953	  	
Loss from continuing operations before income taxes	  	$	(202	) 	 	$	(763	) 	 	$	(965	) 	
Income tax benefit	  	$	(101	) 	 	$	(208	) 	 	$	(309	) 	
Loss from continuing operations	  	$	(101	) 	 	$	(555	) 	 	$	(656	) 	
Property and equipment, net	  	$	18,762	  	 	$	8,163	  	 	$	26,925	  	
Total assets	  	$	24,439	  	 	$	15,581	  	 	$	40,020	  	
Capital expenditures	  	$	2,394	  	 	$	940	  	 	$	3,334	  	
				
Six Months Ended June 30, 2012:	  				 				 				
Oil, gas and NGL sales	  	$	2,250	  	 	$	1,282	  	 	$	3,532	  	
Oil, gas and NGL derivatives	  	$	810	  	 	$	—  	  	 	$	810	  	
Marketing and midstream revenues	  	$	649	  	 	$	65	  	 	$	714	  	
Depreciation, depletion and amortization	  	$	870	  	 	$	494	  	 	$	1,364	  	
Interest expense	  	$	155	  	 	$	31	  	 	$	186	  	
Earnings from continuing operations before income taxes	  	$	1,260	  	 	$	85	  	 	$	1,345	  	
Income tax expense	  	$	444	  	 	$	10	  	 	$	454	  	
Earnings from continuing operations	  	$	816	  	 	$	75	  	 	$	891	  	
Property and equipment, net	  	$	18,818	  	 	$	8,423	  	 	$	27,241	  	
Total assets	  	$	24,916	  	 	$	18,554	  	 	$	43,470	  	
Capital expenditures	  	$	3,421	  	 	$	894	  	 	$	4,315	  	
 
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 Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations 
The following discussion and analysis addresses material changes in our results of operations and capital resources and uses for the three-month and six-month periods ended June 30, 2013, compared to the three-month and six-month periods ended June 30, 2012, and in our financial condition and liquidity since December 31, 2012. For information regarding our critical accounting policies and estimates, see our 2012 Annual Report on Form 10-K under “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Overview of 2013 Results
Key components of our financial performance are summarized below, which exclude amounts from our discontinued operations.

 	  	Three Months Ended June 30,	 	 	Six Months Ended June 30,	 	
 	  	2013	 	  	2012	 	  	Change	 	 	2013	 	 	2012	 	  	Change	 	
 	  	($ in millions, except per share amounts)	 	
Net earnings (loss)	  	$	683	  	  	$	477	  	  	 	+43	% 	 	$	(656	) 	 	$	891	  	  	 	-174	%	
Adjusted earnings (1)	  	$	491	  	  	$	224	  	  	 	+119	% 	 	$	761	  	 	$	650	  	  	 	+17	% 	
Earnings (loss) per share	  	$	1.68	  	  	$	1.18	  	  	 	+43	% 	 	$	(1.63	) 	 	$	2.20	  	  	 	-174	%	
Adjusted earnings per share (1)	  	$	1.21	  	  	$	0.55	  	  	 	+119	% 	 	$	1.87	  	 	$	1.61	  	  	 	+17	% 	
Production (MBoe/d)	  	 	697.6	  	  	 	678.9	  	  	 	+3	% 	 	 	692.3	  	 	 	686.2	  	  	 	+1	% 	
Realized price per Boe	  	$	  35.00	  	  	$	  26.18	  	  	 	+34	% 	 	$	32.13	  	 	$	28.28	  	  	 	+14	% 	
Operating margin per Boe (2)	  	$	22.03	  	  	$	17.22	  	  	 	+28	% 	 	$	20.07	  	 	$	19.03	  	  	 	+5	% 	
Operating cash flow	  	$	1,396	  	  	$	1,426	  	  	 	-2	%	 	$	2,398	  	 	$	2,426	  	  	 	-1	%	
Adjusted operating cash flow (1)	  	$	1,397	  	  	$	1,063	  	  	 	+31	% 	 	$	  2,554	  	 	$	  2,412	  	  	 	+6	% 	
Capitalized costs	  	$	1,496	  	  	$	2,368	  	  	 	-37	%	 	$	3,334	  	 	$	4,314	  	  	 	-23	%	
Shareholder distributions	  	$	88	  	  	$	82	  	  	 	+9	% 	 	$	170	  	 	$	162	  	  	 	+5	% 	

(1)	Adjusted earnings, adjusted earnings per share and adjusted operating cash flow are financial measures not prepared in accordance with accounting principles generally accepted in the U.S. (GAAP). For a description of adjusted earnings, adjusted earnings per share and adjusted operating cash flow as well as reconciliations to the comparable GAAP measures, see “Non-GAAP Measures” in this Item 2.	
(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.	
During the three-month and six-month periods ended June 30, 2013, our adjusted earnings, adjusted earnings per share and operating margin per Boe all increased compared to the 2012 periods. The improved 2013 results were driven primarily by increases in gas prices and oil volumes. These factors also contributed to higher adjusted operating cash flow, which when combined with a reduction in capitalized costs, caused our cash flow deficit to narrow considerably in 2013.
During the first six months of 2013, we recognized noncash asset impairments totaling $2.0 billion ($1.3 billion after tax).
 
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Results of Operations
Production, Prices and Revenues

 	  	Three Months Ended June 30,	 	 	Six Months Ended June 30,	 	
 	  	2013	 	  	2012	 	  	Change	 	 	2013	 	  	2012	 	  	Change	 	
Oil (MBbls/d)	  				  				  				 				  				  				
U.S.	  	 	76.2	  	  	 	56.1	  	  	 	+36	% 	 	 	71.9	  	  	 	55.4	  	  	 	+30	% 	
Canada	  	 	39.7	  	  	 	41.4	  	  	 	-4	%	 	 	40.0	  	  	 	41.3	  	  	 	-3	%	
	  	 	 	 	  	 	 	 	  				 	 	 	 	  	 	 	 	  				
Total	  	 	115.9	  	  	 	97.5	  	  	 	+19	% 	 	 	111.9	  	  	 	96.7	  	  	 	+16	% 	
	  	 	 	 	  	 	 	 	  				 	 	 	 	  	 	 	 	  				
Bitumen (MBbls/d)	  				  				  				 				  				  				
Canada	  	 	53.2	  	  	 	51.1	  	  	 	+4	% 	 	 	53.8	  	  	 	48.6	  	  	 	+11	% 	
	  	 	 	 	  	 	 	 	  				 	 	 	 	  	 	 	 	  				
Gas (MMcf/d)	  				  				  				 				  				  				
U.S.	  	 	1,969.6	  	  	 	2,050.2	  	  	 	-4	%	 	 	1,969.3	  	  	 	2,061.0	  	  	 	-4	%	
Canada	  	 	470.5	  	  	 	519.1	  	  	 	-9	%	 	 	462.8	  	  	 	537.8	  	  	 	-14	%	
	  	 	 	 	  	 	 	 	  				 	 	 	 	  	 	 	 	  				
Total	  	 	2,440.1	  	  	 	2,569.3	  	  	 	-5	%	 	 	2,432.1	  	  	 	2,598.8	  	  	 	-6	%	
	  	 	 	 	  	 	 	 	  				 	 	 	 	  	 	 	 	  				
NGLs (MBbls/d)	  				  				  				 				  				  				
U.S.	  	 	112.2	  	  	 	90.0	  	  	 	+25	% 	 	 	111.3	  	  	 	96.1	  	  	 	+16	% 	
Canada	  	 	9.6	  	  	 	12.0	  	  	 	-20	%	 	 	9.9	  	  	 	11.7	  	  	 	-16	%	
	  	 	 	 	  	 	 	 	  				 	 	 	 	  	 	 	 	  				
Total	  	 	121.8	  	  	 	102.0	  	  	 	+19	% 	 	 	121.2	  	  	 	107.8	  	  	 	+12	% 	
	  	 	 	 	  	 	 	 	  				 	 	 	 	  	 	 	 	  				
Combined (MBoe/d)	  				  				  				 				  				  				
U.S.	  	 	516.7	  	  	 	487.9	  	  	 	+6	% 	 	 	511.4	  	  	 	495.0	  	  	 	+3	% 	
Canada	  	 	180.9	  	  	 	191.0	  	  	 	-5	%	 	 	180.9	  	  	 	191.2	  	  	 	-5	%	
	  	 	 	 	  	 	 	 	  				 	 	 	 	  	 	 	 	  				
Total	  	 	697.6	  	  	 	678.9	  	  	 	+3	% 	 	 	692.3	  	  	 	686.2	  	  	 	+1	% 	

 	  	Three Months Ended June 30,	 	 	Six Months Ended June 30,	 	
 	  	2013 (1)	 	  	2012 (1)	 	  	Change	 	 	2013 (1)	 	  	2012 (1)	 	  	Change	 	
Oil (per Bbl)	  				  				  				 				  				  				
U.S.	  	$	  91.56	  	  	$	  88.74	  	  	 	+3	% 	 	$	  89.64	  	  	$	  93.98	  	  	 	-5	%	
Canada	  	$	72.47	  	  	$	65.53	  	  	 	+11	%	 	$	64.76	  	  	$	70.21	  	  	 	-8	%	
Total	  	$	85.02	  	  	$	78.88	  	  	 	+8	% 	 	$	80.73	  	  	$	83.83	  	  	 	-4	%	
Bitumen (per Bbl)	  				  				  				 				  				  				
Canada	  	$	53.90	  	  	$	46.23	  	  	 	+17	% 	 	$	41.10	  	  	$	48.49	  	  	 	-15	%	
Gas (per Mcf)	  				  				  				 				  				  				
U.S.	  	$	3.49	  	  	$	1.72	  	  	 	+103	% 	 	$	3.15	  	  	$	2.00	  	  	 	+58	% 	
Canada	  	$	3.44	  	  	$	1.91	  	  	 	+80	% 	 	$	3.24	  	  	$	2.24	  	  	 	+45	% 	
Total	  	$	3.48	  	  	$	1.76	  	  	 	+98	% 	 	$	3.17	  	  	$	2.05	  	  	 	+55	% 	
NGLs (per Bbl)	  				  				  				 				  				  				
U.S.	  	$	24.80	  	  	$	29.50	  	  	 	-16	%	 	$	25.53	  	  	$	31.56	  	  	 	-19	%	
Canada	  	$	43.68	  	  	$	45.87	  	  	 	-5	%	 	$	45.54	  	  	$	49.92	  	  	 	-9	%	
Total	  	$	26.29	  	  	$	31.42	  	  	 	-16	%	 	$	27.16	  	  	$	33.55	  	  	 	-19	%	
Combined (per Boe)	  				  				  				 				  				  				
U.S.	  	$	32.19	  	  	$	22.86	  	  	 	+41	% 	 	$	30.29	  	  	$	24.98	  	  	 	+21	% 	
Canada	  	$	43.02	  	  	$	34.66	  	  	 	+24	% 	 	$	37.34	  	  	$	36.83	  	  	 	+1	% 	
Total	  	$	35.00	  	  	$	26.18	  	  	 	+34	% 	 	$	32.13	  	  	$	28.28	  	  	 	+14	% 	

(1)	The prices presented exclude any effects due to oil, gas and NGL derivatives.	
 
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The volume and price changes in the tables above caused the following changes to our oil, gas and NGL sales between the three months ended June 30, 2013 and 2012 .

 	  	Three Months Ended June 30,	 	
 	  	Oil	 	  	Bitumen	 	  	Gas	 	 	NGLs	 	 	Total	 	
 	  	(In millions)	 	
2012 sales	  	$	700	  	  	$	215	  	  	$	410	  	 	$	292	  	 	$	1,617	  	
Change due to volumes	  	 	131	  	  	 	9	  	  	 	(20	) 	 	 	57	  	 	 	177	  	
Change due to prices	  	 	65	  	  	 	37	  	  	 	383	  	 	 	(57	) 	 	 	428	  	
	  	 	 	 	  	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	
2013 sales	  	$	896	  	  	$	261	  	  	$	773	  	 	$	292	  	 	$	2,222	  	
	  	 	 	 	  	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	
Upstream sales increased $177 million due to a 16 percent increase in our liquids production, partially offset by a 5 percent decline in our gas production in the second quarter of 2013. As a result of continued development of our oil properties, primarily in the Permian Basin, oil sales increased $131 million. Bitumen sales increased $9 million due to development of our Jackfish thermal heavy oil projects in Canada. Additionally, our NGL sales increased $57 million primarily as a result of continued drilling in the liquids-rich gas portions of the Cana-Woodford and Barnett Shales and the Permian Basin. These increases were partially offset by decreases in our gas production, which resulted in a $20 million decline in sales.
Production information for our key properties is summarized below:
 
 	•	 	Permian Basin production increased 30 percent compared to the second quarter of 2012 and 13 percent compared to the first quarter of 2013. Oil production accounted for 60 percent of our 76,000 Boe per day produced in the Permian Basin during the second quarter of 2013. The year-over-year increase in total production was driven by a 32 percent increase in oil production.	
 
 	•	 	Barnett Shale production increased 4 percent compared to the second quarter of 2012 and decreased 1 percent compared to the first quarter of 2013. Although total production decreased in the second quarter of 2013 compared to the first quarter of 2013, liquids production increased 2 percent. Liquids production accounted for 24 percent of our 1.4 Bcfe per day produced in the Barnett Shale during the second quarter of 2013. The year-over-year increase in total production was driven by a 34 percent increase in liquids production.	
 
 	•	 	Cana-Woodford Shale production increased 15 percent compared to the second quarter of 2012 and decreased 5 percent compared to the first quarter of 2013. Liquids production accounted for 39 percent of our 322 MMcfe per day produced in Cana during the second quarter of 2013. The year-over-year increase in total production was driven by a 48 percent increase in liquids production.	
 
 	•	 	Jackfish production increased 4 percent compared to the second quarter of 2012 and decreased 2 percent compared to the first quarter of 2013. Bitumen production accounted for all of our 53,000 Boe per day produced at Jackfish during the second quarter of 2013. In June 2013, our Jackfish 1 project reached payout status. Consequently, our Jackfish 1 production will be burdened with a higher Canadian provincial government royalty rate beginning with June 2013. The higher royalty rate decreases our production net of royalties.	
 
 	•	 	Granite Wash production increased 16 percent compared to the second quarter of 2012 and 33 percent compared to the first quarter of 2013. Liquids production accounted for 52 percent of our 22,000 Boe per day produced in the Granite Wash during the second quarter of 2013.	
 
 	•	 	Mississippian-Woodford Trend production increased 73 percent compared to the first quarter of 2013 to 5,000 Boe per day. Oil production accounted for 61 percent of our total production in the Mississippian-Woodford Trend during the second quarter of 2013.	
 
 	•	 	Rocky Mountain production decreased 6 percent compared to the second quarter of 2012. Although total production was down, oil production increased 27 percent compared to the second quarter of 2012. Liquids production accounted for nearly 32 percent of our 333 MMcfe per day produced in the Rocky Mountains during the second quarter of 2013.	
 
 	•	 	Gulf Coast/East Texas production decreased 11 percent compared to the second quarter of 2012. Liquids production accounted for nearly 25 percent of our 329 MMcfe per day produced in Gulf Coast/East Texas during the second quarter of 2013.	
 
 	•	 	Lloydminster production decreased 12 percent compared to the second quarter of 2012. Oil production accounted for 94 percent of our 30,000 Boe per day produced at Lloydminster during the second quarter of 2013.	
 
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Upstream sales increased $428 million in the second quarter of 2013 primarily due to a 34 percent increase in our realized price without hedges. Our gas sales were the most significantly impacted with a $383 million increase due to prices. 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. Oil and bitumen sales increased $102 million as a result of 11 percent increase in our realized price without hedges. NGL sales decreased $57 million as a result of a 16 percent decrease in our realized price without hedges. The largest contributor to the lower NGL price was a decrease in the average NGL prices at the Mont Belvieu, Texas hub.
The volume and price changes in the tables above caused the following changes to our oil, gas and NGL sales between the six months ended June, 30, 2013 and 2012.

 	  	Six Months Ended June 30,	 	
 	  	Oil	 	 	Bitumen	 	 	Gas	 	 	NGLs	 	 	Total	 	
 	  	(In millions)	 	
2012 sales	  	$	1,476	  	 	$	429	  	 	$	969	  	 	$	658	  	 	$	3,532	  	
Change due to volumes	  	 	223	  	 	 	43	  	 	 	(67	) 	 	 	78	  	 	 	277	  	
Change due to prices	  	 	(63	) 	 	 	(72	) 	 	 	492	  	 	 	(140	) 	 	 	217	  	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
2013 sales	  	$	1,636	  	 	$	400	  	 	$	1,394	  	 	$	596	  	 	$	4,026	  	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Upstream sales increased $277 million due to a 13 percent increase in our liquids production, partially offset by a 6 percent decline in our gas production in the first six months of 2013. As a result of continued development of our oil properties, primarily in the Permian Basin, oil sales increased $223 million. Bitumen sales increased $43 million due to development of our Jackfish thermal heavy oil projects in Canada. Additionally, our NGL sales increased $78 million primarily as a result of continued drilling in the liquids-rich gas portions of the Cana-Woodford and Barnett Shales and the Permian Basin. These increases were partially offset by decreases in our gas production, which resulted in a $67 million decline in sales.
Upstream sales increased $217 million during the first six months of 2013 due to a 14 percent increase in our realized price without hedges. Our gas sales increased $492 million due to prices. 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. Our liquids sales decreased $275 million due to lower realized prices without hedges. The largest contributors to the lower liquids prices were a decrease in the average NYMEX West Texas Intermediate index price, wider bitumen differentials and lower NGL prices at the Mont Belvieu, Texas hub.
Oil, Gas and NGL Derivatives
A summary of our open commodity derivative positions is included in Note 2 to the financial statements included in “Item 1. Consolidated Financial Statements” of this report. The following tables provide financial information associated with our commodity derivatives. The first table presents the cash settlements and unrealized gains and losses that are recognized as components of our revenues. The subsequent tables present our oil, bitumen, gas and NGL prices with, and without, the effects of the cash settlements. The prices do not include the effects of unrealized gains and losses.

 	  	Three Months Ended June 30,	 	 	Six Months Ended June 30,	 	
 	  	2013	 	 	2012	 	 	2013	 	 	2012	 	
 	  	(In millions)	 	
Cash settlements:	  				 				 				 				
Gas derivatives	  	$	(17	) 	 	$	211	  	 	$	36	  	 	$	374	  	
Oil derivatives	  	 	29	  	 	 	57	  	 	 	61	  	 	 	51	  	
NGL derivatives	  	 	2	  	 	 	(1	) 	 	 	3	  	 	 	—  	  	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total cash settlements	  	 	14	  	 	 	267	  	 	 	100	  	 	 	425	  	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Unrealized gains (losses) on fair value changes:	  				 				 				 				
Gas derivatives	  	 	308	  	 	 	(280	) 	 	 	52	  	 	 	(184	) 	
Oil derivatives	  	 	43	  	 	 	679	  	 	 	(104	) 	 	 	570	  	
NGL derivatives	  	 	1	  	 	 	(1	) 	 	 	(2	) 	 	 	(1	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total unrealized gains (losses) on fair value changes	  	 	352	  	 	 	398	  	 	 	(54	) 	 	 	385	  	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oil, gas and NGL derivatives	  	$	366	  	 	$	665	  	 	$	46	  	 	$	810	  	

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 	  	Three Months Ended June 30, 2013	 	
 	  	Oil	 	  	Bitumen	 	  	Gas	 	 	NGLs	 	  	Boe	 	
 	  	(Per Bbl)	 	  	(Per Bbl)	 	  	(Per Mcf)	 	 	(Per Bbl)	 	  	(Per Boe)	 	
Realized price without hedges	  	$	85.02	  	  	$	53.90	  	  	$	3.48	  	 	$	26.29	  	  	$	35.00	  	
Cash settlements of hedges (1)	  	 	2.82	  	  	 	—  	  	  	 	(0.07	) 	 	 	0.10	  	  	 	0.23	  	
	  	 	 	 	  	 	 	 	  	 	 	 	 	 	 	 	  	 	 	 	
Realized price, including cash settlements	  	$	87.84	  	  	$	53.90	  	  	$	3.41	  	 	$	26.39	  	  	$	35.23	  	

																					
 	  	Three Months Ended June 30, 2012	 	
 	  	Oil	 	  	Bitumen	 	  	Gas	 	  	NGLs	 	  	Boe	 	
 	  	(Per Bbl)	 	  	(Per Bbl)	 	  	(Per Mcf)	 	  	(Per Bbl)	 	  	(Per Boe)	 	
Realized price without hedges	  	$	78.88	  	  	$	46.23	  	  	$	1.76	  	  	$	31.42	  	  	$	26.18	  	
Cash settlements of hedges	  	 	6.36	  	  	 	—  	  	  	 	0.90	  	  	 	—  	  	  	 	4.33	  	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Realized price, including cash settlements	  	$	85.24	  	  	$	46.23	  	  	$	2.66	  	  	$	31.42	  	  	$	30.51	  	

																					
 	  	Six Months Ended June 30, 2013	 	
 	  	Oil	 	  	Bitumen	 	  	Gas	 	  	NGLs	 	  	Boe	 	
 	  	(Per Bbl)	 	  	(Per Bbl)	 	  	(Per Mcf)	 	  	(Per Bbl)	 	  	(Per Boe)	 	
Realized price without hedges	  	$	80.73	  	  	$	41.10	  	  	$	3.17	  	  	$	27.16	  	  	$	32.13	  	
Cash settlements of hedges (1)	  	 	3.05	  	  	 	—  	  	  	 	0.08	  	  	 	0.11	  	  	 	0.80	  	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Realized price, including cash settlements	  	$	83.78	  	  	$	41.10	  	  	$	3.25	  	  	$	27.27	  	  	$	32.93	  	

																					
 	  	Six Months Ended June 30, 2012	 	
 	  	Oil	 	  	Bitumen	 	  	Gas	 	  	NGLs	 	  	Boe	 	
 	  	(Per Bbl)	 	  	(Per Bbl)	 	  	(Per Mcf)	 	  	(Per Bbl)	 	  	(Per Boe)	 	
Realized price without hedges	  	$	83.83	  	  	$	48.49	  	  	$	2.05	  	  	$	33.55	  	  	$	28.28	  	
Cash settlements of hedges	  	 	2.89	  	  	 	—  	  	  	 	0.79	  	  	 	0.01	  	  	 	3.40	  	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Realized price, including cash settlements	  	$	86.72	  	  	$	48.49	  	  	$	2.84	  	  	$	33.56	  	  	$	31.68	  	

(1)	Cash settlements of oil hedges include settlements from our Western Canadian Select basis swaps presented in Note 2 to the financial statements included in “Item 1. Consolidated Financial Statements” of this report.	
Cash settlements presented in the tables above represent realized gains or losses related to various commodity derivatives. In addition to cash settlements, we also recognize unrealized changes in the fair values of our commodity derivatives in each reporting period. The changes in fair value result from new positions and settlements that occur during each period, as well as the relationships between contract prices and the associated forward curves. Including the cash settlements discussed above, our commodity derivatives generated a net gain of $366 million and $665 million in the second quarter of 2013 and 2012, respectively. Including the cash settlements discussed above, our commodity derivatives generated a net gain of $46 million and $810 million in the first six months of 2013 and 2012, respectively.
Marketing and Midstream Revenues and Operating Costs and Expenses

 	  	Three Months Ended June 30,	 	 	Six Months Ended June 30,	 	
 	  	2013	 	  	2012	 	  	Change	 	 	2013	 	  	2012	 	  	Change	 	
 	  	($ in millions)	 	
Revenues	  	$	503	  	  	$	277	  	  	 	+82	% 	 	$	991	  	  	$	714	  	  	 	+39	% 	
Operating costs and expenses	  	 	382	  	  	 	209	  	  	 	+83	% 	 	 	745	  	  	 	534	  	  	 	+40	% 	
	  	 	 	 	  	 	 	 	  				 	 	 	 	  	 	 	 	  				
Operating profit	  	$	121	  	  	$	68	  	  	 	+79	% 	 	$	246	  	  	$	180	  	  	 	+37	% 	
	  	 	 	 	  	 	 	 	  				 	 	 	 	  	 	 	 	  				
During the second quarter and first six months of 2013, marketing and midstream operating profit increased $53 million and $66 million, respectively, primarily due to higher natural gas prices and higher utilization at the fractionator facility in Mont Belvieu.
 
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Lease Operating Expenses (“LOE”)

 	  	Three Months Ended June 30,	 	 	Six Months Ended June 30,	 	
 	  	2013	 	  	2012	 	  	Change	 	 	2013	 	  	2012	 	  	Change	 	
LOE ($ in millions):	  				  				  				 				  				  				
U.S.	  	$	307	  	  	$	259	  	  	 	+19	% 	 	$	595	  	  	$	511	  	  	 	+16	% 	
Canada	  	 	252	  	  	 	254	  	  	 	-1	%	 	 	489	  	  	 	516	  	  	 	-5	%	
	  	 	 	 	  	 	 	 	  				 	 	 	 	  	 	 	 	  				
Total	  	$	559	  	  	$	513	  	  	 	+9	% 	 	$	1,084	  	  	$	1,027	  	  	 	+6	% 	
	  	 	 	 	  	 	 	 	  				 	 	 	 	  	 	 	 	  				
LOE per Boe:	  				  				  				 				  				  				
U.S.	  	$	6.54	  	  	$	5.84	  	  	 	+12	% 	 	$	6.43	  	  	$	5.68	  	  	 	+13	% 	
Canada	  	$	15.25	  	  	$	14.61	  	  	 	+4	% 	 	$	14.92	  	  	$	14.83	  	  	 	+1	% 	
Total	  	$	8.80	  	  	$	8.30	  	  	 	+6	% 	 	$	8.65	  	  	$	8.23	  	  	 	+5	% 	
LOE increased $0.50 per Boe and $0.42 per Boe during the second quarter and first six months of 2013, respectively. The largest contributor to the higher unit cost is related to our liquids production growth, particularly in the Permian Basin in the U.S. Such projects generally require a higher cost to produce per unit than our gas projects. We experienced upward pressures on costs in certain operating areas, which also contributed to the higher LOE per Boe.
Depreciation, Depletion and Amortization (“DD&A”)

 	  	Three Months Ended June 30,	 	 	Six Months Ended June 30,	 	
 	  	2013	 	  	2012	 	  	Change	 	 	2013	 	  	2012	 	  	Change	 	
DD&A ($ in millions):	  				  				  				 				  				  				
Oil & gas properties	  	$	595	  	  	$	612	  	  	 	-3	%	 	$	1,222	  	  	$	1,228	  	  	 	-1	%	
Other properties	  	 	79	  	  	 	72	  	  	 	+9	% 	 	 	156	  	  	 	136	  	  	 	+15	% 	
	  	 	 	 	  	 	 	 	  				 	 	 	 	  	 	 	 	  				
Total	  	$	674	  	  	$	684	  	  	 	-1	%	 	$	1,378	  	  	$	1,364	  	  	 	+1	% 	
	  	 	 	 	  	 	 	 	  				 	 	 	 	  	 	 	 	  				
DD&A per Boe:	  				  				  				 				  				  				
Oil & gas properties	  	$	9.37	  	  	$	9.89	  	  	 	-5	%	 	$	9.75	  	  	$	9.83	  	  	 	-1	%	
Other properties	  	 	1.25	  	  	 	1.18	  	  	 	+6	% 	 	 	1.25	  	  	 	1.09	  	  	 	+14	% 	
	  	 	 	 	  	 	 	 	  				 	 	 	 	  	 	 	 	  				
Total	  	$	10.62	  	  	$	11.07	  	  	 	-4	%	 	$	11.00	  	  	$	10.92	  	  	 	+1	% 	
	  	 	 	 	  	 	 	 	  				 	 	 	 	  	 	 	 	  				
DD&A from our oil and gas properties decreased in both 2013 periods largely as a result of the asset impairment charges recognized in 2012 and 2013. DD&A from our other properties increased in both 2013 periods largely from the construction of our new headquarters in Oklahoma City and natural gas pipeline development in the Cana-Woodford Shale.
General and Administrative Expenses (“G&A”)

 	  	Three Months Ended June 30,	 	 	Six Months Ended June 30,	 	
 	  	2013	 	 	2012	 	 	Change	 	 	2013	 	 	2012	 	 	Change	 	
 	  	($ in millions)	 	
Gross G&A	  	$	287	  	 	$	296	  	 	 	-3	%	 	$	570	  	 	$	584	  	 	 	-2	%	
Capitalized G&A	  	 	(85	) 	 	 	(92	) 	 	 	-9	%	 	 	(183	) 	 	 	(183	) 	 	 	+0	% 	
Reimbursed G&A	  	 	(35	) 	 	 	(28	) 	 	 	+26	% 	 	 	(70	) 	 	 	(57	) 	 	 	+22	% 	
	  	 	 	 	 	 	 	 	 				 	 	 	 	 	 	 	 	 				
Net G&A	  	$	167	  	 	$	176	  	 	 	-5	%	 	$	317	  	 	$	344	  	 	 	-8	%	
	  	 	 	 	 	 	 	 	 				 	 	 	 	 	 	 	 	 				
Net G&A per Boe	  	$	2.63	  	 	$	2.85	  	 	 	-8	%	 	$	2.53	  	 	$	2.76	  	 	 	-8	%	
	  	 	 	 	 	 	 	 	 				 	 	 	 	 	 	 	 	 				
Net G&A and net G&A per Boe decreased in both 2013 periods largely due to lower administrative expenses, as well as higher reimbursements due to increased well counts and reimbursement rates.
 
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Taxes Other Than Income Taxes

 	  	Three Months Ended June 30,	 	 	Six Months Ended June 30,	 	
 	  	2013	 	 	2012	 	 	Change	 	 	2013	 	 	2012	 	 	Change	 	
 	  	($ in millions)	 	
Production	  	$	71	  	 	$	51	  	 	 	+39	% 	 	$	131	  	 	$	104	  	 	 	+26	% 	
Ad valorem and other	  	 	54	  	 	 	49	  	 	 	+10	% 	 	 	107	  	 	 	98	  	 	 	+9	% 	
	  	 	 	 	 	 	 	 	 				 	 	 	 	 	 	 	 	 				
Taxes other than income taxes	  	$	125	  	 	$	100	  	 	 	+25	% 	 	$	238	  	 	$	202	  	 	 	+18	% 	
	  	 	 	 	 	 	 	 	 				 	 	 	 	 	 	 	 	 				
Percentage of oil, gas and NGL revenue:	  				 				 				 				 				 				
Production	  	 	3.2	% 	 	 	3.2	% 	 	 	+1	% 	 	 	3.3	% 	 	 	2.9	% 	 	 	+11	% 	
Ad valorem and other	  	 	2.4	% 	 	 	3.0	% 	 	 	-20	%	 	 	2.6	% 	 	 	2.8	% 	 	 	-5	%	
	  	 	 	 	 	 	 	 	 				 	 	 	 	 	 	 	 	 				
Total	  	 	5.6	% 	 	 	6.2	% 	 	 	-9	%	 	 	5.9	% 	 	 	5.7	% 	 	 	+3	% 	
	  	 	 	 	 	 	 	 	 				 	 	 	 	 	 	 	 	 				
Taxes other than income taxes as a percentage of oil, gas and NGL revenue decreased during the second quarter of 2013, primarily due to ad valorem and other taxes that do not change in direct correlation with oil, gas and NGL revenues. Taxes other than income taxes as a percentage of oil, gas and NGL revenue increased during the first six months of 2013, primarily due to lower Canadian revenues with no associated production taxes as well as ad valorem and other taxes that do not change in direct correlation with oil, gas and NGL revenues.
Interest Expense

 	  	Three Months Ended June 30,	 	 	Six Months Ended June 30,	 	
 	  	2013	 	 	2012	 	 	Change	 	 	2013	 	 	2012	 	 	Change	 	
 	  	($ in millions)	 	
Interest on outstanding debt	  	$	116	  	 	$	108	  	 	 	+7	% 	 	$	234	  	 	$	207	  	 	 	+13	% 	
Capitalized interest	  	 	(12	) 	 	 	(13	) 	 	 	-4	%	 	 	(23	) 	 	 	(29	) 	 	 	-21	%	
Other	  	 	4	  	 	 	4	  	 	 	-3	%	 	 	7	  	 	 	8	  	 	 	-16	%	
	  	 	 	 	 	 	 	 	 				 	 	 	 	 	 	 	 	 				
Interest expense	  	$	108	  	 	$	99	  	 	 	+8	% 	 	$	218	  	 	$	186	  	 	 	+17	% 	
	  	 	 	 	 	 	 	 	 				 	 	 	 	 	 	 	 	 				
Interest expense increased in both 2013 periods primarily due to higher average 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.
Restructuring Costs

 	  	Six Months Ended June 30,	 	
 	  	2013	 	  	2012	 	
 	  	(In millions)	 	
Lease obligations and other	  	$	40	  	  	$	—  	  	
Asset impairments	  	 	6	  	  	 	—  	  	
	  	 	 	 	  	 	 	 	
Restructuring costs	  	$	46	  	  	$	—  	  	
	  	 	 	 	  	 	 	 	
In the six months ended June 30, 2013, we incurred $46 million of restructuring costs associated with the consolidation of our U.S. personnel into one location in Oklahoma City. This amount includes $25 million related to office space that is subject to non-cancellable operating lease agreements that we ceased using as a part of the office consolidation. We also recognized $6 million of asset impairment charges for leasehold improvements and furniture associated with the office consolidation.
 
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Asset Impairments

 	  	Six Months Ended June 30, 2013	 	
 	  	Gross	 	  	Net of Taxes	 	
 	  	(In millions)	 	
U.S. oil and gas assets	  	$	1,110	  	  	$	707	  	
Canada oil and gas assets	  	 	843	  	  	 	632	  	
	  	 	 	 	  	 	 	 	
Total asset impairments	  	$	1,953	  	  	$	1,339	  	
	  	 	 	 	  	 	 	 	
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 11 to the financial statements under “Item 1. Consolidated Financial Statements” of this report.
The oil and gas impairments resulted primarily from declines in the U.S. and Canada full cost ceilings since December 31, 2012. The lower ceiling values resulted primarily from decreases in the 12-month average trailing prices for oil, bitumen and NGLs, which have reduced proved reserve values.
If pricing conditions decline from June 30, 2013, we could incur additional full cost ceiling impairments related to our oil and gas property and equipment.
Income Taxes
The following table presents our total income tax expense (benefit) and a reconciliation of our effective income tax rate to the U.S. statutory income tax rate.

 	  	Three Months Ended June 30,	 	 	Six Months Ended June 30,	 	
 	  	2013	 	 	2012	 	 	2013	 	 	2012	 	
Total income tax expense (benefit) (in millions)	  	$	314	  	 	$	257	  	 	$	(309	) 	 	$	454	  	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
U.S. statutory income tax rate	  	 	35	% 	 	 	35	% 	 	 	(35	%) 	 	 	35	% 	
State income taxes	  	 	1	% 	 	 	1	% 	 	 	(1	%) 	 	 	1	% 	
Taxation on Canadian operations	  	 	(2	%) 	 	 	(1	%) 	 	 	6	% 	 	 	(2	%) 	
Other	  	 	(2	%) 	 	 	—  	  	 	 	(2	%) 	 	 	—  	  	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Effective income tax rate	  	 	32	% 	 	 	35	% 	 	 	(32	%) 	 	 	34	% 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
In the second quarter of 2013, we repatriated to the United States $2.0 billion of cash from our foreign subsidiaries. In conjunction with the repatriation, we recognized approximately $100 million of current income tax expense. The current expense was entirely offset by the recognition of deferred income tax benefits, which included the reduction of the deferred tax liability previously recognized for unremitted foreign earnings deemed not to be indefinitely reinvested.
 
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Capital Resources, Uses and Liquidity
Sources and Uses of Cash
The following table presents the major changes in our cash and short-term investments.

 	  	Six Months Ended June 30,	 	
 	  	2013	 	 	2012	 	
 	  	(In millions)	 	
Operating cash flow – continuing operations	  	$	2,398	  	 	$	2,426	  	
Capital expenditures	  	 	(3,569	) 	 	 	(4,267	) 	
Debt activity, net	  	 	(1,495	) 	 	 	967	  	
Shareholder distributions	  	 	(170	) 	 	 	(162	) 	
Divestitures of property and equipment	  	 	34	  	 	 	935	  	
Other	  	 	54	  	 	 	88	  	
	  	 	 	 	 	 	 	 	
Net change in cash and short-term investments	  	$	(2,748	) 	 	$	(13	) 	
	  	 	 	 	 	 	 	 	
Cash and short-term investments at end of period	  	$	4,232	  	 	$	7,045	  	
	  	 	 	 	 	 	 	 	
Operating Cash Flow – Continuing Operations
Net cash provided by operating activities (“operating cash flow”) was our primary source of capital in the first six months of 2013. Our operating cash flow was comparable to the first six months of 2012.
During the first six months of 2013 and 2012, our operating cash flow funded approximately 70 percent and 60 percent, respectively, of our cash payments for capital expenditures. Leveraging our liquidity, we used cash balances and short-term debt to fund the remainder of our cash-based capital expenditures.
Capital Expenditures
The amounts in the table below reflect cash payments for capital expenditures, including cash paid for capital expenditures incurred in prior periods.

 	  	Six Months Ended June 30,	 	
 	  	2013	 	  	2012	 	
 	  	(In millions)	 	
Development	  	$	2,511	  	  	$	2,437	  	
Exploration	  	 	402	  	  	 	1,263	  	
	  	 	 	 	  	 	 	 	
Subtotal	  	 	2,913	  	  	 	3,700	  	
Capitalized G&A and interest	  	 	202	  	  	 	200	  	
	  	 	 	 	  	 	 	 	
Total oil and gas	  	 	3,115	  	  	 	3,900	  	
Midstream	  	 	385	  	  	 	206	  	
Corporate and other	  	 	69	  	  	 	161	  	
	  	 	 	 	  	 	 	 	
Total capital expenditures	  	$	3,569	  	  	$	4,267	  	
	  	 	 	 	  	 	 	 	
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 $3.1 billion and $3.9 billion in the first six months of 2013 and 2012, respectively. The 21% decline in exploration and development capital spending in the first six months of 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.
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 our plants in the Barnett and Cana-Woodford Shales and the Access Pipeline in Canada.
 
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Debt Activity, Net
During the first six months of 2013, we repatriated $2.0 billion of foreign earnings to the U.S. and repaid outstanding commercial paper borrowings. The repayment resulted in a net repayment of $1.5 billion for the first six months of 2013. During the first six months of 2012, we received $2.5 billion from the issuance of long-term debt, the proceeds of which were primarily used to repay outstanding commercial paper and credit facility borrowings. We also utilized short-term borrowings of $967 million to fund capital expenditures in excess of our operating cash flow.
Shareholder distributions
The following table summarizes our common stock dividends (amounts in millions) during the first six months of 2013 and 2012. In the second quarter of 2013, we increased our quarterly dividend to $0.22 per share.

 	  	Six Months Ended June 30,	 	
 	  	2013	 	  	2012	 	
 	  	Amount	 	  	Per Share	 	  	Amount	 	  	Per Share	 	
Dividends	  	$	170	  	  	$	0.42	  	  	$	162	  	  	$	0.40	  	
Divestitures of Property and Equipment
During the second quarter of 2012, we closed a joint venture transaction with Sinopec. Sinopec paid approximately $900 million in cash and received a 33.3% 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 exploration, development and drilling costs associated with these plays.
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. The following sections discuss changes to our liquidity subsequent to filing our 2012 Annual Report on Form 10-K.
Operating Cash Flow
Our operating cash flow is sensitive to many variables, the most volatile of which are the prices of the oil, gas and NGLs we produce. We expect operating cash flow to continue to be our primary source of liquidity. To mitigate some of the risk inherent in prices, we have utilized various derivative financial instruments to set minimum and maximum prices on a portion of our 2013 production. The key terms to our open oil, gas and NGL derivative financial instruments as of June 30, 2013 are presented in Note 2 to the financial statements under “Item 1. Consolidated Financial Statements” of this report.
Credit Availability
As of June 30, 2013, we had $2.9 billion of available capacity under our syndicated, unsecured revolving line of credit (the “Senior Credit Facility”), net of letters of credit outstanding. We also have access to $5.0 billion of short-term credit under our commercial paper program. At June 30, 2013, we had $1.7 billion of commercial paper borrowings 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, to be no greater than 65 percent. As of June 30, 2013, we were in compliance with this covenant with a debt-to-capitalization ratio of 22.8 percent.
At June 30, 2013, we held approximately $4.2 billion of cash and short-term investments. Included in this total was $4.0 billion of cash and short-term investments held by our foreign subsidiaries. While we are using a portion of our foreign cash to invest in the development and growth of our Canadian business, we did repatriate $2.0 billion to the U.S. in the second quarter of 2013 at a reduced income tax rate. Additionally, as we progress through 2013 and gain additional clarity on our current and expected tax attributes, we believe we could repatriate additional amounts of cash to the U.S. in a tax-efficient manner in the second half of 2013 or in 2014. We anticipate using any repatriated funds to reduce outstanding debt.
 
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Non-GAAP Measures
We make reference to “adjusted earnings,” “adjusted earnings per share” and “adjusted cash flow” in “Overview of 2013 Results” in this Item 2 that are not required by or presented in accordance with GAAP. These non-GAAP measures should not be considered as alternatives to GAAP measures. Adjusted earnings represents net earnings excluding certain non-cash or non-recurring items that are typically excluded by securities analysts in their published estimates of our financial results. Adjusted cash flow represents cash flow from operating activities excluding certain balance sheet changes and non-recurring items that are typically excluded by securities analysts in their published estimates of our financial results. We believe these non-GAAP measures facilitate comparisons of our performance to earnings and cash flow estimates published by securities analysts. We also believe these non-GAAP measures can facilitate comparisons of our performance between periods and to the performance of our peers. The amounts below exclude any amounts from our discontinued operations.
Adjusted Earnings and Adjusted Earnings Per Share
Below are reconciliations of our adjusted earnings and earnings per share to their comparable GAAP measures.

 	  	Three Months Ended June 30,	 	 	Six Months Ended June 30,	 	
 	  	2013	 	 	2012	 	 	2013	 	 	2012	 	
 	  	(In millions, except per share amounts)	 	
Net earnings (loss) (GAAP)	  	$	683	  	 	$	477	  	 	$	(656	) 	 	$	891	  	
Adjustments (net of taxes):	  				 				 				 				
Asset impairments	  	 	31	  	 	 	—  	  	 	 	1,339	  	 	 	—  	  	
Oil, gas and NGL derivatives	  	 	(232	) 	 	 	(258	) 	 	 	37	  	 	 	(250	) 	
Restructuring costs	  	 	5	  	 	 	—  	  	 	 	29	  	 	 	—  	  	
Interest rate and other financial instruments	  	 	4	  	 	 	5	  	 	 	12	  	 	 	9	  	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Adjusted earnings (Non-GAAP)	  	$	491	  	 	$	224	  	 	$	761	  	 	$	650	  	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Earnings (loss) per share (GAAP)	  	$	1.68	  	 	$	1.18	  	 	$	(1.63	) 	 	$	2.20	  	
Adjustments (net of taxes):	  				 				 				 				
Asset impairments	  	 	0.07	  	 	 	—  	  	 	 	3.31	  	 	 	—  	  	
Oil, gas and NGL derivatives	  	 	(0.56	) 	 	 	(0.64	) 	 	 	0.09	  	 	 	(0.61	) 	
Restructuring costs	  	 	0.01	  	 	 	—  	  	 	 	0.07	  	 	 	—  	  	
Interest rate and other financial instruments	  	 	0.01	  	 	 	0.01	  	 	 	0.03	  	 	 	0.02	  	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Adjusted earnings per share (Non-GAAP)	  	$	1.21	  	 	$	0.55	  	 	$	1.87	  	 	$	1.61	  	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Adjusted Cash Flow
Below is a reconciliation of our adjusted operating cash flow to its comparable GAAP measure.

 	  	Three Months Ended June 30,	 	 	Six Months Ended June 30,	 	
 	  	2013	 	 	2012	 	 	2013	 	  	2012	 	
 	  	(In millions)	 	
Operating cash flow (GAAP)	  	$	1,396	  	 	$	1,426	  	 	$	2,398	  	  	$	2,426	  	
Adjustments (net of taxes):	  				 				 				  				
Changes in assets and liabilities	  	 	(97	) 	 	 	(363	) 	 	 	58	  	  	 	(14	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	  	 	 	 	
Operating cash flow before balance sheet changes (Non-GAAP)	  	 	1,299	  	 	 	1,063	  	 	 	2,456	  	  	 	2,412	  	
	  	 	 	 	 	 	 	 	 	 	 	 	  	 	 	 	
Current taxes on cash repatriation	  	 	98	  	 	 	—  	  	 	 	98	  	  	 	—  	  	
	  	 	 	 	 	 	 	 	 	 	 	 	  	 	 	 	
Adjusted operating cash flow (Non-GAAP)	  	$	1,397	  	 	$	1,063	  	 	$	2,554	  	  	$	2,412	  	

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Item 3. Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
We have commodity derivatives that pertain to a portion of our production for the last six months of 2013, as well as 2014 and 2015. The key terms to our open oil, gas and NGL derivative financial instruments as of June 30, 2013 are presented in Note 2 to the financial statements under “Item 1. Consolidated Financial Statements” of this report.
The fair values of our commodity derivatives are largely determined by estimates of the forward curves of the relevant price indices. At June 30, 2013, a 10 percent change 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	  	$	(272	) 	 	$	265	  	
Oil derivatives	  	$	(278	) 	 	$	274	  	
NGL derivatives	  	$	(1	) 	 	$	1	  	
Interest Rate Risk
At June 30, 2013, we had total debt outstanding of $10.2 billion. Of this amount, $8.5 billion bears fixed interest rates averaging 5.4 percent. The remaining $1.7 billion of commercial paper borrowings bears interest rates that averaged 0.36 percent.
As of June 30, 2013, we had open interest rate swap positions that are presented in Note 2 to the financial statements under “Item 1. Consolidated Financial Statements” of this report. The fair values of our interest rate swaps are largely determined by estimates of the forward curves of the Federal Funds rate. A 10 percent change in these forward curves would not have materially impacted our balance sheet at June 30, 2013.
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 June 30, 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. Additionally, at June 30, 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. Additionally, the increase or decrease in the value of the forward contracts is offset by intercompany loans which increase or decrease from the remeasurement of the loans into the U.S. dollar functional currency. Based on the amount of the intercompany loans as of June 30, 2013, a 10 percent change in the foreign currency exchange rates would not have materially impacted our balance sheet.
Item 4. 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.
 
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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 June 30, 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.
Changes in Internal Control Over Financial Reporting
There were no changes in our internal control over financial reporting that occurred during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
 
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 PART II. Other Information
Item 1. Legal Proceedings
There have been no material changes to the information included in Item 3. “Legal Proceedings” in our 2012 Annual Report on Form 10-K.
Item 1A. Risk Factors
There have been no material changes to the information included in Item 1A. “Risk Factors” in our 2012 Annual Report on Form 10-K.
Item 2 . Unregistered Sales of Equity Securities and Use of Proceeds
The following table provides information regarding purchases of our common stock that were made by us during the second quarter of 2013.

Period	  	Total Number
of Shares
Purchased (1)	 	  	Average Price
Paid per Share	 	
April 1 – April 30	  	 	51,108	  	  	$	54.59	  	
May 1 – May 31	  	 	5,843	  	  	$	58.20	  	
June 1 – June 30	  	 	2,935	  	  	$	54.56	  	
	  	 	 	 	  				
Total	  	 	59,886	  	  	$	54.94	  	

(1)	Share repurchases 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.	
Under the Devon Canada Corporation Savings Plan (the “Canadian Plan”), eligible Canadian employees may purchase shares of our common stock through an investment in the Canadian Plan, which is administered by an independent trustee, Sun Life Assurance Company of Canada. Eligible Canadian employees purchased approximately 4,100 shares of our common stock in the second quarter of 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 3. Defaults Upon Senior Securities
Not applicable.
Item 4. Mine Safety Disclosures
Not applicable.
 Item 5. Other Information 
Not applicable.
 
34

Table of Contents
 Item 6. Exhibits 
(a) Exhibits required by Item 601 of Regulation S-K are as follows:

Exhibit
Number	  	Description	
		
    10.1	  	Devon Energy Corporation Non - Qualified Deferred Compensation Plan (as Amended and Restated Effective January 1, 2013).	
		
    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.	
		
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	
 
35

Table of Contents
 SIGNATURES
Pursuant to the requirements 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	
				
Date: August 7, 2013	 		 		 	/s/ Jeffrey A. Agosta	
	 		 		 	Jeffrey A. Agosta	
	 		 		 	Executive Vice President and Chief Financial Officer	
 
36

Table of Contents
INDEX TO EXHIBITS

Exhibit
Number	  	Description	
		
    10.1	  	Devon Energy Corporation Non - Qualified Deferred Compensation Plan (as Amended and Restated Effective January 1, 2013).	
		
    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.	
		
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	
 
37

Exhibit 10.1
DEVON ENERGY CORPORATION
NON-QUALIFIED DEFERRED COMPENSATION PLAN

TABLE OF CONTENTS

 	  	Page	 	
ARTICLE I ESTABLISHMENT AND PURPOSE	  	 	1	  	
		
1.1 Establishment	  	 	1	  	
1.2 Purpose	  	 	1	  	
1.3 ERISA Status	  	 	1	  	
		
ARTICLE II DEFINITIONS	  	 	1	  	
		
2.1 Definitions	  	 	1	  	
2.2 Construction	  	 	5	  	
2.3 Funding	  	 	5	  	
		
ARTICLE III ELIGIBILITY AND PARTICIPATION	  	 	5	  	
		
3.1 Eligibility and Participation	  	 	5	  	
		
ARTICLE IV ELECTIVE DEFERRALS	  	 	5	  	
		
4.1 Deferrals	  	 	5	  	
4.2 Timing of Deferral Election	  	 	6	  	
4.3 Election Forms	  	 	6	  	
4.4 Hardship Withdrawal Under Qualified Plan	  	 	6	  	
		
ARTICLE V SUPPLEMENTAL COMPANY CONTRIBUTIONS	  	 	6	  	
		
5.1 Supplemental Company Contributions	  	 	6	  	
		
ARTICLE VI PAYMENT OF BENEFITS	  	 	7	  	
		
6.1 Payment Events	  	 	7	  	
6.2 Method of Payment Upon Separation from Service	  	 	7	  	
6.3 Method of Payment Upon a Change of Control Payment Event	  	 	7	  	
6.4 Method of Payment Upon Death	  	 	7	  	
6.5 Payment Upon Scheduled In-Service Withdrawal	  	 	8	  	
6.6 Payment to Specified Employees Upon Separation from Service	  	 	8	  	
6.7 Changes in Method of Payment	  	 	8	  	
6.8 Beneficiary Designations	  	 	9	  	
6.9 Small Account Balances	  	 	9	  	
6.10 Transition Exceptions	  	 	9	  	
		
ARTICLE VII ACCOUNTS AND INVESTMENT	  	 	9	  	
		
7.1 Participant Accounts	  	 	9	  	
7.2 Adjustment of Accounts	  	 	10	  	
7.3 Investment of Account	  	 	10	  	
7.4 Vesting	  	 	10	  	
7.5 Account Statements	  	 	10	  	
		
ARTICLE VIII ADMINISTRATION	  	 	10	  	
		
8.1 Administration	  	 	10	  	
8.2 Indemnification and Exculpation	  	 	11	  	
 
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TABLE OF CONTENTS
(continued)

 	  	Page	 	
8.3 Rules of Conduct	  	 	11	  	
8.4 Legal, Accounting, Clerical and Other Services	  	 	11	  	
8.5 Records of Administration	  	 	11	  	
8.6 Expenses	  	 	11	  	
8.7 Liability	  	 	11	  	
8.8 Claims Review Procedures	  	 	11	  	
8.9 Finality of Determinations; Exhaustion of Remedies	  	 	12	  	
8.10 Effect of Committee Action	  	 	13	  	
		
ARTICLE IX GENERAL PROVISIONS	  	 	13	  	
		
9.1 Effect on Other Plans	  	 	13	  	
9.2 Conditions of Employment Not Affected by Plan	  	 	13	  	
9.3 Restrictions on Alienation of Benefits	  	 	14	  	
9.4 Domestic Relations Orders	  	 	14	  	
9.5 Information Required of Participants	  	 	14	  	
9.6 Tax Consequences Not Guaranteed	  	 	14	  	
9.7 Benefits Payable to Incompetents	  	 	14	  	
9.8 Severability	  	 	14	  	
9.9 Compliance with Section 409A	  	 	15	  	
9.10 Tax Withholding	  	 	15	  	
		
ARTICLE X AMENDMENT AND TERMINATION	  	 	15	  	
		
10.1 Amendment and/or Termination	  	 	15	  	
		
ARTICLE XI MISCELLANEOUS PROVISIONS	  	 	15	  	
		
11.1 Articles and Section Titles and Headings	  	 	15	  	
11.2 Joint Obligations	  	 	15	  	
11.3 Governing Law	  	 	15	  	
 
-ii-

DEVON ENERGY CORPORATION
NON-QUALIFIED DEFERRED COMPENSATION PLAN
ARTICLE I
ESTABLISHMENT AND PURPOSE
1.1 Establishment . Devon Energy Corporation, a Delaware corporation (“ Company ”), established the Devon Energy Corporation Non-Qualified Deferred Compensation Plan effective October 1, 2001 (the “ Plan ”). The Company hereby amends and restates the Plan effective January 1, 2013 (the “ Effective Date ”). This amendment and restatement only applies to the amounts deferred under the Plan on or after January 1, 2005, and to amounts deferred prior to January 1, 2005 that were not vested as of December 31, 2004. Amounts deferred under the Plan prior to January 1, 2005 that were vested as of December 31, 2004 (the “ Grandfathered Amounts ”) shall be subject to the provisions of the Plan as in effect on October 3, 2004. It is intended that the Grandfathered Amounts are to remain exempt from the requirements of Section 409A of the Code.
1.2 Purpose . The Plan shall provide Eligible Employees the ability to defer payment of Base Salary and Bonus. The Plan is also intended to provide the amount of the benefit which could otherwise be earned under the Devon Energy Corporation Incentive Savings Plan (the “ Qualified Plan ”) but which cannot be contributed due to the limitations imposed by (i) Section 401(a)(17) of the Code, which limits the annual compensation that may be taken into account in computing benefits under plans qualified under Sections 401(a) and 501(a) of the Code and (ii) Sections 401(k) and 402(g) of the Code which limit benefits that may be contributed by the Company as a “matching contribution” under Section 401(m) of the Code (collectively referred to as the “ IRS Limitations ”).
1.3 ERISA Status . The Plan is intended to qualify for the exemptions provided under Title I of ERISA for plans that are not tax-qualified and that are maintained primarily to provide deferred compensation for a select group of management or highly compensated employees as defined in Section 201(2) of ERISA.
ARTICLE II
DEFINITIONS
2.1 Definitions . For purposes of this Plan, the following definitions shall apply:
(a) “ Account ” means the recordkeeping accounts maintained by the Company to record the payment obligation of the Company to a Participant as determined under the terms of this Plan. The Company may maintain an Account to record the total obligation to the Participant under this Plan and component accounts to reflect amounts payable at different times and in different forms. Reference to an Account means any such Account established by the Company as the context requires.
(b) “ Affiliate ” means a corporation, trade or business that, together with the Company, is treated as a single employer under Section 414(b) or (c) of the Code.

(c) “ Applicable Contribution Percentage ” means the maximum matching contribution percentage the Participant is eligible to receive under the terms of the Qualified Plan for the Plan Year.
(d) “ Base Salary ” means the Participant’s annualized gross rate of base salary paid before any deductions of any kind whatsoever.
(e) “ Beneficiary ” means the person, persons, trust, or other entity designated by a Participant, on the beneficiary designation form adopted by the Committee, to receive benefits, if any, under this Plan at such Participant’s death pursuant to Section 6.4.
(f) “ Board ” means the Board of Directors of the Company.
(g) “ Bonus ” means the Participant’s cash bonus to be earned during each calendar year before any deductions of any kind whatsoever.
(h) “ Change of Control Payment Event ” shall mean and shall be deemed to have occurred when one of the events described in paragraphs (i), (ii), (iii), or (iv) below occurs. For the purpose of this subsection (h), the term “Company” shall mean Devon Energy Corporation and any successor thereto.
(i) The acquisition of stock of the Company by any one person, or more than one person acting as a group (as defined in §1.409A-3(i)(5)(v)(B) of the Treasury Regulations) (a “ Person ”) that, together with stock held by such Person, constitutes more than 50% of either (I) the then outstanding shares of common stock of the Company or (II) the combined voting power of the then outstanding voting securities of the Company entitled to vote generally in the election of directors; provided, however, that the following acquisitions shall not constitute a Change of Control Payment Event: (A) any acquisition by an underwriter temporarily holding securities pursuant to an offering of such securities; (B) any acquisition by the Company; (C) any acquisition by any employee benefit plan (or related trust) sponsored or maintained by the Company or any corporation controlled by the Company. If a Change of Control Payment Event occurs by reason of an acquisition described in this paragraph (i), no additional Change of Control Payment Event shall be deemed to occur under this paragraph (i) by reason of subsequent changes in the holdings of such Person (except if the holdings of such Person are reduced to 50% or below and thereafter increase to more than 50%).
(ii) During a 12-month period, a majority of the individuals who, as of the Effective Date, constitute the Board (the “ Incumbent Board ”) are replaced; provided, however, that any individual becoming a director subsequent to the Effective Date whose election, appointment or nomination for election by the Company’s shareholders was approved by a vote of at least a majority of the directors then comprising the Incumbent Board shall be considered as though such individual were a member of the Incumbent Board, but excluding, for purposes of this definition, any such individual whose initial assumption of office occurs as a result of an actual or publicly threatened election contest (as such terms are used in Rule 14a-11 promulgated under the Exchange Act) with respect to the election or removal of directors or other actual or publicly threatened solicitation of proxies or consents by or on behalf of a Person other than the Board.
 
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(iii) The date a Person acquires (or has acquired during the 12-month period ending on the date of the most recent acquisition by such Person) ownership of stock of the Company possessing 30% or more of the combined voting power of the then outstanding voting securities of the Company; provided that, if a Change of Control Payment Event occurs by reason of an acquisition described in this paragraph (iii), no additional Change of Control Payment Event shall be deemed to occur under this paragraph (iii) or paragraph (i) by reason of the acquisition of additional control of the Company by the same Person.
(iv) Approval by the shareholders of the Company of the sale or other disposition of all or substantially all of the assets of the Company to a Person, provided that, a transfer of the Company’s assets shall not be treated as a Change of Control Payment Event if the assets are transferred to:
(1) A shareholder of the Company (immediately before the asset transfer) in exchange for or with respect to its stock;
(2) An entity, 50% or more of the total value or voting power of which is owned, directly or indirectly, by the Company;
(3) A person that owns, directly or indirectly, 50% or more of the total value or voting power of all the outstanding stock of the Company; or
(4) An entity, at least 50% of the total value or voting power of which is owned, directly or indirectly by a Person described in subparagraph (3).
Except as otherwise provided in this paragraph (iv), a person’s status is determined immediately after the transfer of the assets.
(i) “ Code ” means the Internal Revenue Code of 1986, as amended, and any regulations relating thereto.
(j) “ Committee ” means the Compensation Committee of the Board of Directors of the Company or a committee established by the Compensation Committee that has been delegated duties related to the Plan.
(k) “ Credited Earnings ” means the gains or losses applied to a Participant’s Account pursuant to Section 7.2.
(l) “ Deferred Amount ” means the portion of a Participant’s Base Salary or Bonus which the Participant elects to defer pursuant to Article IV, Deferred Amounts shall be determined by reference to the Plan Year in which the amount was deferred by the Participant.
(m) “ Disabled ” or “ Disability ” means the Participant is unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment that can be expected to result in death or last for a continuous period of not less than 12 months. The Committee shall determine whether a Participant is Disabled in accordance with Section 409A of the Code.
 
3

(n) “ ERISA ” means the Employee Retirement Income Security Act of 1974, as amended.
(o) “ Eligible Employee ” means an employee who (i) is designated by the Committee as belonging to a “select group of management or highly compensated employees,” as such phrase is defined under ERISA; (ii) an executive of the Company or an Affiliate employed at a minimum salary level designated from time to time by the Committee; (iii) a resident of the United States; and (iv) paid on the Company’s or its Affiliates’ United States payroll.
(p) “ Employer ” shall mean the Company and/or any Affiliate that employs a Participant in the Plan.
(q) “ Participant ” means an Eligible Employee who has Deferred Amounts and/or Supplemental Company Contributions credited to an Account under this Plan.
(r) “ Plan ” means this Devon Energy Non-Qualified Deferred Compensation Plan, as amended and restated effective as of the Effective Date.
(s) “ Plan-Approved Domestic Relations Order ” means a qualified domestic relations order as defined in Section 414(p)(1)(B) of the Code that meets the requirements established by the Committee.
(t) “ Plan Year ” means the 12-month period beginning on January 1 and ending on December 31.
(u) “ Qualified Plan ” means the Devon Energy Corporation Incentive Savings Plan or any successor plan thereto.
(v) “ Separation from Service ” means termination of employment with the Employer under the circumstances described below. Whether a Separation from Service has occurred shall be determined by the Committee in accordance with Section 409A of the Code.
Except in the case of a Participant on a bona fide leave of absence as provided below, a Participant is deemed to have incurred a Separation from Service if the Employer and the Participant reasonably anticipated that the level of services to be performed by the Participant after a certain date would be permanently reduced to 20% or less of the average services rendered by the Participant during the immediately preceding 36-month period (or the total period of employment, if less than 36 months), disregarding periods during which the Participant was on a bona fide leave of absence.
A Participant who is absent from work due to military leave, sick leave, or other bona fide leave of absence shall incur a Separation from Service on the first date immediately following the later of (i) the six-month anniversary of the commencement of the leave or (ii) the expiration of the Participant’s right, if any, to reemployment under statute or contract.
For purposes of determining whether a Separation from Service has occurred, the Employer means the Employer as defined in Section 2.1(p), except that for purposes of determining whether another organization is an Affiliate of the Company, common ownership of at least 50% shall be determinative.
 
4

(w) “ Specified Employee ” means those employees of the Company who are determined by the Committee to be a “specified employee” in accordance with Section 409A of the Code and the Devon Energy Corporation Specified Employee Policy.
(x) “ Supplemental Company Contribution ” means the contribution made by the Company for the benefit of a Participant under Article V in any Plan Year.
2.2 Construction . Except when otherwise indicated by the context, any masculine terminology when used in the Plan shall also include the feminine gender, and the definition of any term in the singular shall also include the plural.
2.3 Funding . The benefits described in this Plan are contractual obligations of the Employers to pay compensation for services, and shall constitute a liability to the Participants and/or their Beneficiaries in accordance with the terms hereof. All amounts paid under this Plan shall be paid in cash from the general assets of the Employers and shall be subject to the general creditors of the Company and the Employer of the Participant. Benefits shall be reflected on the accounting records of the Employers but shall not be construed to create, or require the creation of, a trust, custodial or escrow account. No special or separate fund need be established and no segregation of assets need be made to assure the payment of such benefits. No Participant shall have any right, title or interest whatever in or to any investment reserves, accounts, funds or assets that the Employer may purchase, establish or accumulate to aid in providing the benefits described in this Plan. Nothing contained in this Plan, and no action taken pursuant to its provisions, shall create or be construed to create a trust or a fiduciary relationship of any kind between an Employer or the Company and a Participant or any other person. Provided, the Company may establish and/or continue a grantor trust as defined in Section 671 of the Code to provide a source of funding for amounts deferred hereunder Neither a Participant nor the Beneficiary of a Participant shall acquire any interest hereunder greater than that of an unsecured creditor of the Company or any Affiliate who is the Employer of such Participant.
ARTICLE III
ELIGIBILITY AND PARTICIPATION
3.1 Eligibility and Participation . The Committee shall provide employees selected for participation in this Plan with notice of the employee’s selection as an Eligible Employee under this Plan for the applicable Plan Year and permit such Eligible Employee the opportunity to make an election pursuant to Article IV. Such notice may be given at such time and in such manner as the Committee may determine. All determinations as to whether an employee is eligible to make deferral elections shall be made by the Committee. The determinations of the Committee shall be final and binding on all employees.
ARTICLE IV
ELECTIVE DEFERRALS
4.1 Deferrals . Elective deferrals may be made with respect to the following sources in accordance with the provisions of Article IV:
 
5

(a) Bonus . An Eligible Employee may elect to defer up to 100% of the Eligible Employee’s Bonus as long as such deferral does not reduce such Eligible Employee’s Bonus below an amount necessary to satisfy applicable withholding tax obligations, benefit plan contributions, and income tax withholding obligations. The amount deferred shall be specified as a percentage or dollar amount of any Bonus which may be earned by an Eligible Employee in the applicable Plan Year
(b) Base Salary . An Eligible Employee may elect to defer up to 50% of the Eligible Employee’s Base Salary as long as such deferral does not reduce such Eligible Employee’s Base Salary below an amount necessary to satisfy applicable withholding tax obligations, benefit plan contributions, and income tax withholding obligations. The amount deferred shall be specified as a percentage or dollar amount of any Base Salary which may be earned by an Eligible Employee in the applicable Plan Year.
4.2 Timing of Deferral Election . An Eligible Employee must file a deferral election form for each Plan Year. Except as may be permitted by the Code or applicable guidance promulgated thereunder, the election to defer Base Salary or Bonus shall apply to Base Salary or Bonus earned during the Plan Year that commences immediately following the Plan Year in which the election is made and is irrevocable except as otherwise provided herein. Elections to defer Base Salary or Bonus must be completed and filed before December 31 of the year immediately preceding the Plan Year in which the election is to apply. If an employee hired during the Plan Year is selected by the Committee to participate in this Plan, the first Plan Year for which the Eligible Employee shall be entitled to make an election to defer under the Plan is the first Plan Year following the Eligible Employee’s date of hire.
4.3 Election Forms . All elections to defer shall be made on a deferral election form. In addition to the deferral election form, a Participant may be required by the Committee to complete additional forms such that they have adequate information concerning the Deferred Amount, timing of distributions and the form of payment, if applicable.
4.4 Hardship Withdrawal Under Qualified Plan . If a Participant makes a “hardship withdrawal” under the Qualified Plan and such Participant is prohibited (including, without limitation, temporarily suspended) from making future contributions under such Qualified Plan (and this Plan) by the terms of such qualified retirement plan, then, contributions by the Participant under this Plan shall be automatically cancelled for the remainder of the Plan Year.
ARTICLE V
SUPPLEMENTAL COMPANY CONTRIBUTIONS
5.1 Supplemental Company Contributions . If the Participant is employed by the Company on the last day of the Plan Year, the Company will make a Supplemental Company Contribution to this Plan on behalf of each Participant 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.
 
6

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. In the event a Participant’s employment is terminated due to death or Disability or due to an approved reason, as determined by the Committee in its sole discretion, a Supplemental Company Contribution may be made for the Plan Year even if the Participant is not employed on the last day of the Plan Year.
ARTICLE VI
PAYMENT OF BENEFITS
6.1 Payment Events . Unless otherwise distributed in accordance with the terms of a Scheduled In-Service Withdrawal, a Participant’s Account shall become payable at the time and in the form described in this Article upon the earlier to occur of the following events: (i) a Participant’s Separation from Service; (ii) a Participant’s Disability; (iii) a Change of Control Payment Event or (iv) the Participant’s death.
6.2 Method of Payment Upon Separation from Service . A Participant must specify on the deferral election form for each Plan Year the method of payment of the portion of Participant’s Account attributable to such Plan Year. A Participant may designate payment in the form of a single lump sum payment or quarterly installment payments payable over a period of 5, 10 or 15 years. Installment payments shall be paid quarterly, with the first installment paid within 90 days following the Participant’s Separation from Service, unless the Participant is a Specified Employee, or in the case of Disability, within 90 days of the date the Participant is Disabled and each subsequent installment paid on a quarterly basis until all installment payments have been paid. If the Participant (i) fails to make an effective designation as to the method of payment or (ii) elects to receive payment in the form of a lump sum, payment shall be automatically made in the form of a single lump sum payment within 90 days following the Participant’s Separation from Service, unless the Participant is a Specified Employee, or in the case of Disability, within 90 days of the date the Participant was Disabled. In the event the Participant is a Specified Employee, payment shall be postponed for a period of six months following Separation from Service and shall commence within 90 days of the first business day of the seventh month following Separation from Service.
6.3 Method of Payment Upon a Change of Control Payment Event . Plan Account balances will be paid within 90 days of the occurrence of a Change of Control Payment Event. A Participant may designate payment in the form of a single lump sum payment or quarterly installment payments payable over a period of 5, 10 or 15 years, such designation to be made on the election form that is submitted for such Plan Year in accordance with Section 4.2. If the Participant fails to make an effective designation as to the method of payment, payment will be made in the form of a lump sum.
6.4 Method of Payment Upon Death . If a Participant dies with a balance credited to the Participant’s Account, such balance shall be paid to the Participant’s Beneficiary. If the Participant dies prior to the time of payment of the Account, the then current balance of each of
 
7

the Participant’s Account or subaccount shall be paid to the Participant’s Beneficiary in a lump sum commencing within 90 days of the date of Participant’s death. If payment of Participant’s Account has commenced as of the date of Participant’s death, the then current balance of each Account or subaccount payable to a Beneficiary shall be paid under the method designated for the payment of such amount by the Participant commencing within 90 days of the date of Participant’s death. Each Beneficiary of a deceased Participant who is eligible to receive payments under this Section shall have the amounts to be paid to such Beneficiary allocated to a subaccount in the name of the Beneficiary under the deceased Participant’s Account. Such subaccount shall be adjusted from time to time as provided in Article VII.
6.5 Payment Upon Scheduled In-Service Withdrawal . A Participant may schedule distribution of the Deferred Amounts and any Credited Earning attributable thereto attributable to a particular Plan Year (“ Scheduled In-Service Withdrawal ”) at least two years after the Plan Year in which deferrals were made. Participants must request a Scheduled In-Service Withdrawal, and a method of payment described in subsection (a) below, on the election form that is submitted in conjunction with the deferral election for such Plan Year. Except as provided in Section 6.10 below, if a Participant fails to elect a Scheduled In-Service Withdrawal for that Plan Year, a Participant will not be eligible to obtain a Scheduled In-Service Withdrawal for such Plan Year.
(a) The Participant may elect either a lump sum payment or quarterly installment payments for a period of 1 to 5 years. Payment will be made (or commence in the case of installments) within 30 days of the first business day of January in the year elected.
(b) A Participant may postpone payment of a Scheduled In-Service Withdrawal to a date at least five years later than the previously Scheduled In-Service Withdrawal date by filing a written request with the Committee at least twelve months prior to the date the Scheduled In-Service Withdrawal is scheduled to begin. Any request to postpone payment of a Scheduled In-Service Withdrawal will be irrevocable, except as may be permitted by the Code or applicable guidance promulgated thereunder.
(c) In the event of death, Disability, the occurrence of a Change of Control Payment Event or Separation from Service, payment of the Participant’s Account shall be determined with respect to elections made in reference to termination of employment, without regard to the otherwise Scheduled In-Service Withdrawal which shall be deemed to be cancelled.
6.6 Payment to Specified Employees Upon Separation from Service . In no event shall a Specified Employee receive a payment under this Plan following a Separation from Service prior to the first business day of the seventh month following the date of Separation from Service.
6.7 Changes in Method of Payment . The method of payment may be changed from time to time by the Participant, but in no event later than the date that is twelve months prior to the date payment would have otherwise commenced. Any requests to change the method of payment will not take effect for twelve months following the date it is received by the Committee and the first payment with respect to such election will be deferred for a period of at least five years from the date such payment would otherwise have commenced. Any request to change the method of payment will be irrevocable, except as may be permitted by the Code or applicable guidance promulgated thereunder.
 
8

6.8 Beneficiary Designations . A Participant shall designate on a beneficiary designation form a Beneficiary who, upon the Participant’s death, will receive payments that otherwise would have been paid to him under the Plan. All Beneficiary designations shall be in writing. Any such designation shall be effective only if and when delivered to the Committee during the lifetime of the Participant. A Participant may change a Beneficiary or Beneficiaries by filing a new beneficiary designation form. The latest beneficiary designation form shall apply to the combined Accounts and subaccounts of the Participant. If a Beneficiary of a Participant predeceases the Participant, the designation of such Beneficiary shall be void. If a Beneficiary to whom benefits under the Plan remain unpaid dies after the Participant and the Participant failed to specify a contingent Beneficiary on the appropriate beneficiary designation form, the remainder of such death benefit payments shall be paid to such Beneficiary’s estate. If a Participant fails to designate a Beneficiary with respect to any death benefit payments or if such designation is ineffective, in whole or in part, any payment that otherwise would have been paid to such Participant shall be paid to the Participant’s estate.
6.9 Small Account Balances . If, upon Separation from Service, the value of the Participant’s Account is less than $10,000, the balance of such Account shall be paid in a single lump sum.
6.10 Transition Exceptions . Under the transition guidance issued by the Internal Revenue Service under Section 409A of the Code, an exception to the general timing rules shall apply to 2005, 2006, 2007 and 2008 Plan Year Account balances. Participant’s elections for the 2005, 2006, 2007 and 2008 Plan Years may be revised with respect to the timing and method of payment; provided, that such revised election (i) if made in the 2007 Plan Year, does not cause amounts that were otherwise payable in 2007 to be paid in a subsequent year, and does not provide for amounts payable in a subsequent year to be paid in 2007, and (ii) if made in the 2008 Plan Year, does not cause amounts that were otherwise payable in 2008 to be paid in a subsequent year, and does not provide for amounts payable in a subsequent year to be paid in 2008. The Committee will administer this provision to ensure compliance with IRS Notice 2006-79.
ARTICLE VII
ACCOUNTS AND INVESTMENT
7.1 Participant Accounts . The Committee shall maintain, or cause to be maintained, a bookkeeping Account for each Participant for the purpose of accounting for the Participant’s interest under the Plan. The Committee shall maintain within each Participant’s Account such subaccounts as may be necessary to identify each separate Deferred Amount, Supplemental Company Contribution and Credited Earnings attributable thereto, by reference to the Plan Year to which each Deferred Amount and Supplemental Company Contribution relates. The combination of the subaccounts maintained in the name of a Participant shall comprise the Participant’s Account.
 
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7.2 Adjustment of Accounts . Each Participant’s Account shall be adjusted to reflect all Deferred Amounts and Supplemental Company Contributions credited to the Participant’s Account, all positive or negative Credited Earnings credited or debited to the Participant’s Account as provided by Section 7.3, and all benefit payments charged to the Participant’s Account. A Participant’s Deferred Amount shall be credited to such Participant’s Account as of the date on which the amount being deferred would have become payable to the Participant absent the election to defer, or on such other date as the Committee specifies, and shall be credited to the applicable subaccount within such Account by reference to the applicable Plan Year. Supplemental Company Contributions shall be credited to a Participant’s Account and shall be subject to the vesting requirements described in Section 7.4. Charges to a Participant’s Account to reflect benefit payments shall be made as of the date of any such payment and charged to the applicable subaccount within such Account. As of any relevant date, the balance standing to the credit of a Participant’s Account, and each separate subaccount comprising such Account, shall be the respective balance in such Account and the component subaccounts as of the close of business on such date after all applicable credits, debits and charges have been posted.
7.3 Investment of Account . The Committee will offer Participants a selection of benchmark funds as deemed investment alternatives. The benchmark funds offered will be determined in the sole discretion of the Committee. Each Participant may select among the different benchmark funds offered. The deemed investments in benchmark funds are only for the purpose of determining the Company’s payment obligation under the Plan. Credited Earnings shall be allocated to a Participant’s Account pursuant to the performance of the benchmark funds selected by the Participant. A Participant may, as frequently as daily, modify his election of benchmark funds through a procedure designated by the Committee. Such modification will be in accordance with rules and procedures adopted by the Committee.
7.4 Vesting . Subject to the conditions and limitations on payment of benefits under the Plan, a Participant shall always have a fully vested and nonforfeitable beneficial interest in the balance standing to the credit of the Participant’s Account attributable to Deferred Amounts and Credited Earnings attributable to the Deferred Amounts. A Participant shall become vested in Supplemental Company Contributions and Credited Earnings thereon as such Participant would be vested pursuant to the terms of the Qualified Plan.
7.5 Account Statements . The Committee shall provide each Participant with a statement of the status of the Participant’s Account under the Plan. The Committee shall provide such statement annually or at such other times as the Committee may determine. Account statements shall be in the format prescribed by the Committee.
ARTICLE VIII
ADMINISTRATION
8.1 Administration . The Plan shall be administered, construed and interpreted by the Committee. The Committee shall have the sole authority and discretion to determine eligibility and to construe the terms of the Plan. The determinations by the Committee as to any disputed questions arising under the Plan, including the Eligible Employees who are eligible to be Participants in the Plan and the amounts of their benefits under the Plan, and the construction and
 
10

interpretation by the Committee of any provision of the Plan, shall be final, conclusive and binding upon all persons including Participants, their beneficiaries, the Company, its stockholders and employees and the Employers. The Committee may, in its sole discretion, delegate its authority hereunder, including, but not limited to, delegating authority to modify, amend, administer, interpret, construe or vary the Plan, to the extent permitted by applicable law or administrative or regulatory rule, and, to the extent the Committee delegates its authority, applicable references herein to the Committee also shall mean the Committee’s delegate.
8.2 Indemnification and Exculpation . The members of the Committee and its agents shall be indemnified and held harmless by the Company against and from any and all loss, cost, liability or expense that may be imposed upon or reasonably incurred by them in connection with or resulting from any claim, action, suit or proceeding to which they may be a party or in which they may be involved by reason of any action taken or failure to act under this Plan and against and from any and all amounts paid by them in settlement (with the Company’s written approval) or paid by them in satisfaction of a judgment in any such action, suit or proceeding. The foregoing provisions shall not be applicable to any person if the loss, cost, liability or expense is due to such person’s gross negligence or willful misconduct.
8.3 Rules of Conduct . The Committee shall adopt such rules for the conduct of its business and the administration of this Plan as it considers desirable, provided they do not conflict with the provisions of this Plan.
8.4 Legal, Accounting, Clerical and Other Services . The Committee may authorize one or more if its members or any agent to act on its behalf and may contract for legal, accounting, clerical and other services to carry out this Plan. The Company shall pay all expenses of the Committee.
8.5 Records of Administration . The Committee shall keep records reflecting the administration of this Plan which shall be subject to audit by the Company.
8.6 Expenses . The expenses of administering the Plan shall be borne by the Company.
8.7 Liability . No member of the Board of Directors or of the Committee shall be liable for any act or action, whether of commission or omission, taken by any other member, or by any officer, agent, or employee of the Company or of any such body, nor, except in circumstances involving his bad faith, for anything done or omitted to be done by himself.
8.8 Claims Review Procedures . The following claim procedures shall apply until such time as a Change of Control Payment Event has occurred. During the 24-month period following a Change of Control Payment Event, these procedures shall apply only to the extent the claimant requests their application. After the expiration of the 24-month period following a Change of Control Payment Event, then, these procedures shall again apply until the occurrence of a subsequent Change of Control Payment Event.
(a) Denial of Claim . If a claim for benefits is wholly or partially denied, the claimant shall be given notice in writing of the denial within a reasonable time after the receipt of the claim, but not later than 90 days after the receipt of the claim. However, if special
 
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circumstances require an extension, written notice of the extension shall be furnished to the claimant before the termination of the 90-day period. In no event shall the extension exceed a period of 90 days after the expiration of the initial 90-day period. The notice of the denial shall contain the following information written in a manner that may be understood by a claimant:
(i) The specific reasons for the denial;
(ii) Specific reference to pertinent Plan provisions on which the denial is based;
(iii) A description of any additional material or information necessary for the claimant to perfect his claim and an explanation of why such material or information is necessary;
(iv) An explanation that a full and fair review by the Committee of the denial may be requested by the claimant or his authorized representative by filing a written request for a review with the Committee within 60 days after the notice of the denial is received; and
(v) If a request for review is filed, the claimant or his authorized representative may review pertinent documents and submit issues and comments in writing within the 60-day period described in Section 8.8(a)(iv).
(b) Decisions After Review . The decision of the Committee with respect to the review of the denial shall be made promptly and in writing, but not later than 60 days after the Committee receives the request for the review. However, if special circumstances require an extension of time, a decision shall be rendered not later than 120 days after the receipt of the request for review. A written notice of the extension shall be furnished to the claimant prior to the expiration of the initial 60-day period. The claimant shall be given a copy of the decision, which shall state, in a manner calculated to be understood by the claimant, the specific reasons for the decision and specific references to the pertinent Plan provisions on which the decision is based.
(c) Other Procedures . Notwithstanding the foregoing, the Committee may, in its discretion, adopt different procedures for different claims without being bound by past actions. Any procedures adopted, however, shall be designed to afford a claimant a full and fair review of his claim and shall comply with applicable regulations under ERISA.
8.9 Finality of Determinations; Exhaustion of Remedies . To the extent permitted by law, decisions reached under the claims procedures set forth in Section 8.8 shall be final and binding on all parties. No legal action for benefits under the Plan shall be brought unless and until the claimant has exhausted his remedies under Section 8.8. In any such legal action, the claimant may only present evidence and theories which the claimant presented during the claims procedure. Any claims which the claimant does not in good faith pursue through the review stage of the procedure shall be treated as having been irrevocably waived. Judicial review of a claimant’s denied claim shall be limited to a determination of whether the denial was arbitrary, capricious or an abuse of discretion based on the evidence and theories the claimant presented during the claims procedure. This Section shall have no application during the 24-month period
 
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following a Change of Control Payment Event as to a claim which is first asserted or first denied after the Change of Control Payment Event and, as to such a claim, the de novo standard of judicial review shall apply. After the expiration of the 24-month period following a Change of Control Payment Event, then, this Section shall again apply until the occurrence of a subsequent Change of Control Payment Event.
8.10 Effect of Committee Action . The Plan shall be interpreted by the Committee in accordance with the terms of the Plan and their intended meanings. However, the Committee shall have the discretion to make any findings of fact needed in the administration of the Plan, and shall have the discretion to interpret or construe ambiguous, unclear or implied (but omitted) terms in any fashion they deem to be appropriate in their sole judgment. Except as stated in Section 8.9, the validity of any such finding of fact, interpretation, construction or decision shall not be given de novo review if challenged in court, by arbitration or in any other forum, and shall be upheld unless clearly arbitrary or capricious. To the extent the Committee has been granted discretionary authority under the Plan, the Committee’s prior exercise of such authority shall not obligate it to exercise its authority in a like fashion thereafter. If any Plan provision does not accurately reflect its intended meaning, as demonstrated by consistent interpretations or other evidence of intent, or as determined by the Committee in it sole and exclusive judgment, the provision shall be considered ambiguous and shall be interpreted by the Committee and all Plan fiduciaries in a fashion consistent with its intent, as determined by the Committee in its sole discretion. The Committee may amend the Plan retroactively to cure any such ambiguity. This Section may not be invoked by any person to require the Plan to be interpreted in a manner which is inconsistent with its interpretation by the Committee. All actions taken and all determinations made in good faith by the Committee shall be final and binding upon all persons claiming any interest in or under the Plan. This Section shall not apply to Committee actions or interpretations which take place or are made during the 24-month period following a Change of Control Payment Event. After the expiration of the 24-month period following a Change of Control Payment Event, then, this Section shall again apply until the occurrence of a subsequent Change of Control Payment Event.
ARTICLE IX
GENERAL PROVISIONS
9.1 Effect on Other Plans . Deferred Amounts shall not be considered as part of a Participant’s compensation for the purpose of any qualified employee pension plans maintained by the Company or its Affiliates in the Plan Year in which any deferral occurs under this Plan, and such amounts will not be considered under the Company’s Qualified Plan in the Plan Year in which payment occurs, but may be considered as covered compensation under the Company’s qualified defined benefit pension plan entitled “Retirement Plan for Employees of Devon Energy Corporation” if permitted under the terms of such plan. However, such amounts may be taken into account under all other employee benefit plans maintained by the Company or its Affiliates in the year in which such amounts would have been payable absent the deferral election; provided, such amounts shall not be taken into account if their inclusion would jeopardize the tax-qualified status of the plan to which they relate.
9.2 Conditions of Employment Not Affected by Plan . The establishment and maintenance of the Plan shall not be construed as conferring any legal rights upon any Participant to the continuation of employment with the Company, nor shall the Plan interfere with the rights of the Company to discharge any Participant with or without cause.
 
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9.3 Restrictions on Alienation of Benefits . No right or benefit under this Plan shall be subject to anticipation, alienation, sale, assignment, pledge, encumbrance, or charge, and any attempt to anticipate, alienate, sell, assign, pledge, encumber, or charge the same shall be void. No right or benefit hereunder shall in any manner be liable for or subject to the debts, contracts, liabilities, or torts of the person entitled to such benefit. If any Participant or the Participant’s Beneficiary under this Plan should become bankrupt or attempt to anticipate, alienate, sell, assign, pledge, encumber, or charge any right to a benefit hereunder, then, such right or benefit shall cease and terminate. Notwithstanding the foregoing, in the event that all or any portion of the benefit of a Participant was transferred to the former spouse of the Participant incident to a divorce prior to the Effective Date, the Committee shall maintain such amount for the benefit of the former spouse until distributed in the manner required by an order of any court having jurisdiction over the divorce, and the former spouse shall be entitled to the same rights as the Participant with respect to such benefit.
9.4 Domestic Relations Orders . Domestic relations orders purporting to assign a Participant’s benefits under the Plan constitute an impermissible alienation of benefits pursuant to Section 9.3 and shall not be honored by the Committee.
9.5 Information Required of Participants . Payment of benefits shall begin as of the payment date(s) provided in this Plan and no formal claim shall be required therefor; provided, in the interest of orderly administration of the Plan, the Committee may make reasonable requests of Participants and Beneficiaries to furnish information which is reasonably necessary and appropriate to the orderly administration of the Plan, and, to that limited extent, payments under the Plan are conditioned upon the Participants and Beneficiaries promptly furnishing true, full and complete information as the Committee may reasonably request.
9.6 Tax Consequences Not Guaranteed . The Company does not warrant that this Plan will have any particular tax consequences for Participants or Beneficiaries and shall not be liable to them if tax consequences they anticipate do not actually occur. The Company shall have no obligation to indemnify a Participant or Beneficiary for lost tax benefits (or other damage or loss).
9.7 Benefits Payable to Incompetents . Any benefits payable hereunder to a minor or person under legal disability may be made, at the discretion of the Committee, (i) directly to the said person, or (ii) to a parent, spouse, relative by blood or marriage, or the legal representative of said person. The Committee shall not be required to see to the application of any such payment, and the payee’s receipt shall be a full and final discharge of the Committee’s responsibility hereunder.
9.8 Severability . If any provision of the Plan is held invalid or illegal for any reason, any illegality or invalidity shall not affect the remaining provisions of the Plan, and the Plan shall be construed and enforced as if the illegal or invalid provision had never been contained therein. The Company shall have the privilege and opportunity to correct and remedy such questions of illegality or invalidity by amendment.
 
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9.9 Compliance with Section 409A . Notwithstanding anything in the Plan to the contrary, the terms of the Plan and all distributions made hereunder are intended to, and shall be interpreted and applied so as to, comply in all respects with the provisions of Section 409A of the Code and rulings promulgated thereunder and, if necessary, any provision shall be held null and void to the extent such provision (or part thereof) fails to comply with Section 409A of the Code and rulings promulgated thereunder. The Committee shall interpret the Plan consistent with the requirements of Section 409A of the Code, which shall govern the administration of the Plan in the event of any conflict between Plan terms and the applicable requirements of Section 409A of the Code and rulings promulgated thereunder. In any circumstance when a payment may be made in either of two calendar years, in no event may a Participant, directly or indirectly, designate the calendar year of such payment.
9.10 Tax Withholding . The Employer may withhold from a payment or accrued benefit or from the Participant’s other compensation any federal, state, or local taxes required by law to be withheld with respect to such payment or accrued benefit and such sums as the Employer may reasonably estimate as necessary to cover any taxes for which the Employer may be liable and which may be assessed with regard to such payment.
ARTICLE X
AMENDMENT AND TERMINATION
10.1 Amendment and/or Termination . The Committee may amend or modify the Plan at any time and in any manner; provided, however, that (i) no amendment shall reduce any portion of a Participant’s Account that is vested and (ii) no amendment shall be effective to the extent it results in a violation of Section 409A of the Code. The Committee may terminate the Plan within the parameters and limitations imposed by Section 409A of the Code.
ARTICLE XI
MISCELLANEOUS PROVISIONS
11.1 Articles and Section Titles and Headings . The titles and headings at the beginning of each Article and Section shall not be considered in construing the meaning of any provisions in this Plan.
11.2 Joint Obligations . For purposes of this Plan, the Company and Devon Energy Company, L.P., an Oklahoma limited partnership, shall have joint and several liability for all obligations hereunder.
11.3 Governing Law . This Plan is subject to ERISA, but is exempt from most parts of ERISA since it is an unfunded deferred compensation plan maintained for a select group of management or highly compensated employees. In no event shall any references to ERISA in the Plan be construed to mean that the Plan is subject to any particular provisions of ERISA. The Plan shall be governed and construed in accordance with federal law and the laws of the State of Oklahoma, except to the extent such laws are preempted by ERISA.
* * * * * * * * *
 
15

IN WITNESS WHEREOF, the Company has caused this instrument to be executed by its duly authorized officer.

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

Exhibit 31.1
CERTIFICATION PURSUANT TO
RULE 13a-14(a)/15d-14(a),
AS ADOPTED PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, John Richels, certify that:
1. I have reviewed this quarterly report on Form 10-Q 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.
Date: August 7, 2013

	
/s/ John Richels	
John Richels	
President and Chief Executive Officer	

Exhibit 31.2
CERTIFICATION PURSUANT TO
RULE 13a-14(a)/15d-14(a),
AS ADOPTED PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Jeffrey A. Agosta, certify that:
1. I have reviewed this quarterly report on Form 10-Q 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.
Date: August 7, 2013

	
/s/ Jeffrey A. Agosta	
Jeffrey A. Agosta	
Executive Vice President and Chief Financial Officer	

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 Report of Devon Energy Corporation (“Devon”) on Form 10-Q for the period ended June 30, 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	
August 7, 2013	

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 Report of Devon Energy Corporation (“Devon”) on Form 10-Q for the period ended June 30, 2013 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Jeffrey A. Agosta, 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/ Jeffrey A. Agosta	
Jeffrey A. Agosta	
Executive Vice President and Chief Financial Officer	
August 7, 2013