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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, 2006
or
 	 	 	
o	 	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934	
Commission File No. 001-32318
Devon Energy Corporation
(Exact Name of Registrant as Specified in its Charter)
 	 	 	
Delaware	 	73-1567067	
(State or Other Jurisdiction of	 	(I.R.S. Employer	
Incorporation or Organization)	 	Identification Number)	
 	 	 	
20 North Broadway	 	 	
Oklahoma City, Oklahoma	 	73102-8260	
(Address of Principal Executive Offices)	 	(Zip Code)	
Registrant’s telephone number, including area code:
(405) 235-3611
Former name, former 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 o
     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer þ           Accelerated filer o           Non-accelerated filer o
     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o   No þ
     The number of shares outstanding of Registrant’s common stock, par value $0.10, as of June 30, 2006, was 441,051,000.

 

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DEVON ENERGY CORPORATION
Index to Form 10-Q Quarterly Report
to the Securities and Exchange Commission
 	 	 	 	 	 	 	
 	 	 	 	Page	
 	 	 	 	No.	
Part I. Financial Information	
 	 	 	 	 	 	 	
Item 1.	 	Consolidated Financial Statements	 	 	 	 	
 	 	 	 	 	 	 	
 	 	Consolidated Balance Sheets as of June 30, 2006 (Unaudited) and December 31, 2005	 	 	5	 	
 	 	 	 	 	 	 	
 	 	Consolidated Statements of Operations (Unaudited) for the Three Months and Six Months Ended June 30, 2006 and 2005	 	 	6	 	
 	 	 	 	 	 	 	
 	 	Consolidated Statements of Stockholders’ Equity and Comprehensive Income (Unaudited) for the Six Months Ended June 30, 2006 and 2005	 	 	7	 	
 	 	 	 	 	 	 	
 	 	Consolidated Statements of Cash Flows (Unaudited) for the Six Months Ended June 30, 2006 and 2005	 	 	8	 	
 	 	 	 	 	 	 	
 	 	Notes to Consolidated Financial Statements (Unaudited)	 	 	9	 	
 	 	 	 	 	 	 	
Item 2.	 	Management’s Discussion and Analysis of Financial Condition and Results of Operations	 	 	25	 	
 	 	 	 	 	 	 	
Item 4.	 	Controls and Procedures	 	 	37	 	
 	 	 	 	 	 	 	
Part II. Other Information	
 	 	 	 	 	 	 	
Item 2.	 	Unregistered Sales of Equity Securities, Use of Proceeds and Issuer Purchases of Equity Securities	 	 	38	 	
 	 	 	 	 	 	 	
Item 4.	 	Submission of Matters to a Vote of Security Holders	 	 	38	 	
 	 	 	 	 	 	 	
Item 6.	 	Exhibits	 	 	40	 	
 	 	 	 	 	 	 	
SIGNATURES	 	 	40	 	
  Amendment to Rights Agreement	
  Certification of CEO Pursuant to Section 302	
  Certification of CFO Pursuant to Section 302	
  Certification of CEO Pursuant to Section 906	
  Certification of CFO Pursuant to Section 906	
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DEFINITIONS
       As used in this document:
     “Bbl” or “Bbls” means barrel or barrels.
     “Bcf” means billion cubic feet.
     “Boe” means barrel of oil equivalent, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of gas.
     “MMBbls” means million barrels.
     “MMBoe” means million Boe.
     “Mcf” means thousand cubic feet.
     “NGL” or “NGLs” means natural gas liquids.
     “Oil” includes crude oil and condensate.
     “SEC” means United States Securities and Exchange Commission.
     “Domestic” means the properties of Devon in the onshore continental United States and the offshore Gulf of Mexico.
     “United States Onshore” means the properties of Devon in the continental United States.
     “United States Offshore” means the properties of Devon in the Gulf of Mexico.
     “Canada” means the division of Devon encompassing oil and gas properties located in Canada.
     “International” means the division of Devon encompassing oil and gas properties that lie outside the United States and Canada.
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PART I. Financial Information
Item 1. Financial Statements
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
 	 	 	 	 	 	 	 	 	
 	 	June 30,	 	 	December 31,	 	
 	 	2006	 	 	2005	 	
 	 	(Unaudited)	 	 	 	 	 	
 	 	(In millions, except share data)	 	
ASSETS	 	 	 	 	 	 	 	 	
Current assets:	 	 	 	 	 	 	 	 	
Cash and cash equivalents	 	$	1,030	 	 	 	1,606	 	
Short-term investments	 	 	332	 	 	 	680	 	
Accounts receivable	 	 	1,404	 	 	 	1,601	 	
Deferred income taxes	 	 	90	 	 	 	158	 	
Other current assets	 	 	189	 	 	 	161	 	
 	 	 	 	 	 	 	
Total current assets	 	 	3,045	 	 	 	4,206	 	
 	 	 	 	 	 	 	
Property and equipment, at cost, based on the full cost method of accounting for oil and gas properties ($3,890 and $2,747 excluded from amortization in 2006 and 2005, respectively)	 	 	39,773	 	 	 	34,246	 	
Less accumulated depreciation, depletion and amortization	 	 	16,454	 	 	 	15,114	 	
 	 	 	 	 	 	 	
 	 	 	23,319	 	 	 	19,132	 	
Investment in Chevron Corporation common stock, at fair value	 	 	880	 	 	 	805	 	
Goodwill	 	 	5,823	 	 	 	5,705	 	
Other assets	 	 	451	 	 	 	425	 	
 	 	 	 	 	 	 	
Total assets	 	$	33,518	 	 	 	30,273	 	
 	 	 	 	 	 	 	
LIABILITIES AND STOCKHOLDERS’ EQUITY	 	 	 	 	 	 	 	 	
Current liabilities:	 	 	 	 	 	 	 	 	
Accounts payable:	 	 	 	 	 	 	 	 	
Trade	 	$	1,137	 	 	 	947	 	
Revenues and royalties due to others	 	 	492	 	 	 	666	 	
Income taxes payable	 	 	147	 	 	 	293	 	
Short-term debt	 	 	2,098	 	 	 	662	 	
Accrued interest payable	 	 	127	 	 	 	127	 	
Current portion of asset retirement obligation	 	 	73	 	 	 	50	 	
Accrued expenses and other current liabilities	 	 	124	 	 	 	189	 	
 	 	 	 	 	 	 	
Total current liabilities	 	 	4,198	 	 	 	2,934	 	
 	 	 	 	 	 	 	
Debentures exchangeable into shares of Chevron Corporation common stock	 	 	718	 	 	 	709	 	
Other long-term debt	 	 	5,238	 	 	 	5,248	 	
Fair value of derivative financial instruments	 	 	183	 	 	 	125	 	
Asset retirement obligation, long-term	 	 	766	 	 	 	618	 	
Other liabilities	 	 	370	 	 	 	372	 	
Deferred income taxes	 	 	5,552	 	 	 	5,405	 	
Stockholders’ equity:	 	 	 	 	 	 	 	 	
Preferred stock of $1.00 par value	 	 	 	 	 	 	 	 	
Authorized 4,500,000 shares; issued 1,500,000 ($150 million aggregate liquidation value)	 	 	1	 	 	 	1	 	
Common stock of $0.10 par value	 	 	 	 	 	 	 	 	
Authorized 800,000,000 shares; issued 441,358,000 in 2006 and 443,488,000 in 2005	 	 	44	 	 	 	44	 	
Additional paid-in capital	 	 	6,762	 	 	 	6,928	 	
Retained earnings	 	 	7,932	 	 	 	6,477	 	
Accumulated other comprehensive income	 	 	1,772	 	 	 	1,414	 	
Treasury stock, at cost: 307,000 shares in 2006 and 37,000 shares in 2005	 	 	(18	)	 	 	(2	)	
 	 	 	 	 	 	 	
Total stockholders’ equity	 	 	16,493	 	 	 	14,862	 	
 	 	 	 	 	 	 	
Total liabilities and stockholders’ equity	 	$	33,518	 	 	 	30,273	 	
 	 	 	 	 	 	 	
See accompanying notes to consolidated financial statements.
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Three Months Ended	 	 	Six Months Ended	 	
 	 	June 30,	 	 	June 30,	 	
 	 	2006	 	 	2005	 	 	2006	 	 	2005	 	
 	 	 	 	 	 	(Unaudited)	 	 	 	 	 	
 	 	(In millions, except per share amounts)	 	
Revenues:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oil sales	 	$	857	 	 	 	650	 	 	 	1,572	 	 	 	1,265	 	
Gas sales	 	 	1,170	 	 	 	1,272	 	 	 	2,534	 	 	 	2,447	 	
NGL sales	 	 	193	 	 	 	157	 	 	 	369	 	 	 	302	 	
Marketing and midstream revenues	 	 	397	 	 	 	389	 	 	 	859	 	 	 	805	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total revenues	 	 	2,617	 	 	 	2,468	 	 	 	5,334	 	 	 	4,819	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Expenses and other income, net:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Lease operating expenses	 	 	362	 	 	 	338	 	 	 	711	 	 	 	686	 	
Production taxes	 	 	86	 	 	 	75	 	 	 	169	 	 	 	153	 	
Marketing and midstream operating costs and expenses	 	 	288	 	 	 	296	 	 	 	627	 	 	 	627	 	
Depreciation, depletion and amortization of oil and gas properties	 	 	556	 	 	 	494	 	 	 	1,063	 	 	 	1,035	 	
Depreciation and amortization of non-oil and gas properties	 	 	43	 	 	 	41	 	 	 	85	 	 	 	79	 	
Accretion of asset retirement obligation	 	 	13	 	 	 	11	 	 	 	24	 	 	 	23	 	
General and administrative expenses	 	 	90	 	 	 	78	 	 	 	180	 	 	 	136	 	
Interest expense	 	 	102	 	 	 	146	 	 	 	203	 	 	 	264	 	
Effects of changes in foreign currency exchange rates	 	 	—	 	 	 	11	 	 	 	(1	)	 	 	11	 	
Change in fair value of derivative financial instruments	 	 	47	 	 	 	(18	)	 	 	59	 	 	 	34	 	
Reduction of carrying value of oil and gas properties	 	 	16	 	 	 	—	 	 	 	101	 	 	 	—	 	
Other income, net	 	 	(30	)	 	 	(14	)	 	 	(58	)	 	 	(152	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total expenses and other income, net	 	 	1,573	 	 	 	1,458	 	 	 	3,163	 	 	 	2,896	 	
Earnings before income tax expense	 	 	1,044	 	 	 	1,010	 	 	 	2,171	 	 	 	1,923	 	
Income tax expense (benefit):	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Current	 	 	198	 	 	 	277	 	 	 	502	 	 	 	629	 	
Deferred	 	 	(13	)	 	 	80	 	 	 	110	 	 	 	78	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total income tax expense	 	 	185	 	 	 	357	 	 	 	612	 	 	 	707	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Net earnings	 	 	859	 	 	 	653	 	 	 	1,559	 	 	 	1,216	 	
Preferred stock dividends	 	 	3	 	 	 	3	 	 	 	5	 	 	 	5	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Net earnings applicable to common stockholders	 	$	856	 	 	 	650	 	 	 	1,554	 	 	 	1,211	 	

Net earnings per average common share outstanding:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Basic	 	$	1.94	 	 	 	1.40	 	 	 	3.52	 	 	 	2.57	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Diluted	 	$	1.92	 	 	 	1.38	 	 	 	3.47	 	 	 	2.53	 	

Weighted average common share outstanding:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Basic	 	 	440	 	 	 	464	 	 	 	441	 	 	 	472	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Diluted	 	 	446	 	 	 	471	 	 	 	447	 	 	 	479	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
See accompanying notes to consolidated financial statements.
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME
(Unaudited)
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	Accumulated	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	Additional	 	 	 	 	 	 	Other	 	 	 	 	 	 	Total	 	
 	 	Preferred	 	 	Common	 	 	Paid-In	 	 	Retained	 	 	Comprehensive	 	 	Treasury	 	 	Stockholders’	 	
 	 	Stock	 	 	Stock	 	 	Capital	 	 	Earnings	 	 	Income	 	 	Stock	 	 	Equity	 	
 	 	(In millions)	 	
Six Months Ended June 30, 2006	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance as of December 31, 2005	 	$	1	 	 	 	44	 	 	 	6,928	 	 	 	6,477	 	 	 	1,414	 	 	 	(2	)	 	 	14,862	 	
Comprehensive income:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net earnings	 	 	—	 	 	 	—	 	 	 	—	 	 	 	1,559	 	 	 	—	 	 	 	—	 	 	 	1,559	 	
Other comprehensive income (loss), net of tax:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Foreign currency translation adjustments	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	311	 	 	 	—	 	 	 	311	 	
Change in fair value of derivative financial instruments	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(1	)	 	 	—	 	 	 	(1	)	
Unrealized gain on marketable securities	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	48	 	 	 	—	 	 	 	48	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Other comprehensive income	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	358	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Comprehensive income	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	1,917	 	
Stock issued	 	 	—	 	 	 	—	 	 	 	27	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	27	 	
Stock repurchased	 	 	—	 	 	 	—	 	 	 	(238	)	 	 	—	 	 	 	—	 	 	 	(15	)	 	 	(253	)	
Dividends on common stock	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(99	)	 	 	—	 	 	 	—	 	 	 	(99	)	
Dividends on preferred stock	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(5	)	 	 	—	 	 	 	—	 	 	 	(5	)	
Grant of restricted stock awards, net of cancellations	 	 	—	 	 	 	—	 	 	 	1	 	 	 	—	 	 	 	—	 	 	 	(1	)	 	 	—	 	
Stock option and restricted stock expense	 	 	—	 	 	 	—	 	 	 	37	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	37	 	
Excess tax benefits related to share-based compensation	 	 	—	 	 	 	—	 	 	 	7	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	7	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance as of June 30, 2006	 	$	1	 	 	 	44	 	 	 	6,762	 	 	 	7,932	 	 	 	1,772	 	 	 	(18	)	 	 	16,493	 	

Six Months Ended June 30, 2005	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance as of December 31, 2004	 	$	1	 	 	 	48	 	 	 	9,002	 	 	 	3,693	 	 	 	930	 	 	 	—	 	 	 	13,674	 	
Comprehensive income:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net earnings	 	 	—	 	 	 	—	 	 	 	—	 	 	 	1,216	 	 	 	—	 	 	 	—	 	 	 	1,216	 	
Other comprehensive income (loss), net of tax:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Foreign currency translation adjustments	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(100	)	 	 	—	 	 	 	(100	)	
Reclassification adjustment for derivative losses reclassified into oil and gas sales	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	192	 	 	 	—	 	 	 	192	 	
Change in fair value of derivative financial instruments	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(171	)	 	 	—	 	 	 	(171	)	
Unrealized gain on marketable securities	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	31	 	 	 	—	 	 	 	31	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Other comprehensive loss	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	(48	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Comprehensive income	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	1,168	 	
Stock issued	 	 	—	 	 	 	—	 	 	 	81	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	81	 	
Stock repurchased and retired	 	 	—	 	 	 	(3	)	 	 	(1,559	)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(1,562	)	
Dividends on common stock	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(70	)	 	 	—	 	 	 	—	 	 	 	(70	)	
Dividends on preferred stock	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(5	)	 	 	—	 	 	 	—	 	 	 	(5	)	
Restricted stock expense	 	 	—	 	 	 	—	 	 	 	13	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	13	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance as of June 30, 2005	 	$	1	 	 	 	45	 	 	 	7,537	 	 	 	4,834	 	 	 	882	 	 	 	—	 	 	 	13,299	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
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,	 	
 	 	2006	 	 	2005	 	
 	 	(Unaudited)	 	
 	 	(In millions)	 	
Cash flows from operating activities:	 	 	 	 	 	 	 	 	
Net earnings	 	$	1,559	 	 	 	1,216	 	
Adjustments to reconcile net earnings to net cash provided by operating activities:	 	 	 	 	 	 	 	 	
Depreciation, depletion and amortization	 	 	1,148	 	 	 	1,114	 	
Deferred income tax expense	 	 	110	 	 	 	78	 	
Net gain on sales of non-oil and gas property and equipment	 	 	(5	)	 	 	(150	)	
Reduction of carrying value of oil and gas properties	 	 	101	 	 	 	—	 	
Other non-cash charges	 	 	112	 	 	 	95	 	
Changes in assets and liabilities:	 	 	 	 	 	 	 	 	
(Increase) decrease in:	 	 	 	 	 	 	 	 	
Accounts receivable	 	 	269	 	 	 	9	 	
Other current assets	 	 	(17	)	 	 	(6	)	
Long-term other assets	 	 	(6	)	 	 	35	 	
Increase (decrease) in:	 	 	 	 	 	 	 	 	
Accounts payable	 	 	(168	)	 	 	112	 	
Income taxes payable	 	 	(156	)	 	 	(75	)	
Debt, including current maturities	 	 	—	 	 	 	(67	)	
Accrued interest and expenses	 	 	(108	)	 	 	46	 	
Long-term other liabilities	 	 	(21	)	 	 	(22	)	
 	 	 	 	 	 	 	
Net cash provided by operating activities	 	 	2,818	 	 	 	2,385	 	
 	 	 	 	 	 	 	
Cash flows from investing activities:	 	 	 	 	 	 	 	 	
Proceeds from sales of property and equipment	 	 	26	 	 	 	2,161	 	
Capital expenditures	 	 	(4,715	)	 	 	(1,976	)	
Purchases of short-term investments	 	 	(1,698	)	 	 	(2,765	)	
Sales of short-term investments	 	 	2,046	 	 	 	3,183	 	
 	 	 	 	 	 	 	
Net cash (used in) provided by investing activities	 	 	(4,341	)	 	 	603	 	
 	 	 	 	 	 	 	
Cash flows from financing activities:	 	 	 	 	 	 	 	 	
Proceeds from borrowings of debt, net of issuance costs	 	 	1,452	 	 	 	—	 	
Principal payments on debt, including current maturities	 	 	(208	)	 	 	(354	)	
Proceeds from exercise of stock options	 	 	27	 	 	 	81	 	
Repurchase of common stock	 	 	(253	)	 	 	(1,562	)	
Excess tax benefits related to share-based compensation	 	 	7	 	 	 	—	 	
Dividends paid on common stock	 	 	(99	)	 	 	(70	)	
Dividends paid on preferred stock	 	 	(5	)	 	 	(5	)	
 	 	 	 	 	 	 	
Net cash provided by (used in) financing activities	 	 	921	 	 	 	(1,910	)	
 	 	 	 	 	 	 	
Effect of exchange rate changes on cash	 	 	26	 	 	 	(3	)	
 	 	 	 	 	 	 	
Net (decrease) increase in cash and cash equivalents	 	 	(576	)	 	 	1,075	 	
Cash and cash equivalents at beginning of period	 	 	1,606	 	 	 	1,152	 	
 	 	 	 	 	 	 	
Cash and cash equivalents at end of period	 	$	1,030	 	 	 	2,227	 	
 	 	 	 	 	 	 	
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 consolidated financial statements and notes thereto of Devon Energy Corporation (“Devon”) have been prepared pursuant to the rules and regulations of the United States Securities and Exchange Commission. Accordingly, 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 consolidated financial statements and notes thereto should be read in conjunction with the consolidated financial statements and notes thereto included in Devon’s 2005 Annual Report on Form 10-K.
     In the opinion of Devon’s management, all adjustments (all of which are normal and recurring) have been made which are necessary to fairly state the consolidated financial position of Devon and its subsidiaries as of June 30, 2006, and the results of their operations and their cash flows for the three-month and six-month periods ended June 30, 2006 and 2005.
     Certain prior period amounts have been reclassified to conform to the current period presentation.
Earnings Per Share
     The following table reconciles the net earnings and common shares outstanding used in the calculations of basic and diluted earnings per share for the three-month and six-month periods ended June 30, 2006 and 2005.
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Weighted	 	 	 	 	
 	 	Net Earnings	 	 	Average	 	 	 	 	
 	 	Applicable to	 	 	Common	 	 	Net	 	
 	 	Common	 	 	Shares	 	 	Earnings	 	
 	 	Stockholders	 	 	Outstanding	 	 	Per Share	 	
 	 	(In millions, except per share amounts)	 	
Three Months Ended June 30, 2006:	 	 	 	 	 	 	 	 	 	 	 	 	
Basic earnings per share	 	$	856	 	 	 	440	 	 	$	1.94	 	
 	 	 	 	 	 	 	 	 	 	 	 	
Dilutive effect of potential common shares issuable upon the exercise of outstanding stock options	 	 	—	 	 	 	6	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	
Diluted earnings per share	 	$	856	 	 	 	446	 	 	$	1.92	 	

Three Months Ended June 30, 2005:	 	 	 	 	 	 	 	 	 	 	 	 	
Basic earnings per share	 	$	650	 	 	 	464	 	 	$	1.40	 	
 	 	 	 	 	 	 	 	 	 	 	 	
Dilutive effect of potential common shares issuable upon the exercise of outstanding stock options	 	 	—	 	 	 	7	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	
Diluted earnings per share	 	$	650	 	 	 	471	 	 	$	1.38	 	
 	 	 	 	 	 	 	 	 	 	
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	Weighted	 	 	 	 	
 	 	Net Earnings	 	 	Average	 	 	 	 	
 	 	Applicable to	 	 	Common	 	 	Net	 	
 	 	Common	 	 	Shares	 	 	Earnings	 	
 	 	Stockholders	 	 	Outstanding	 	 	Per Share	 	
 	 	(In millions, except per share amounts)	 	
Six Months Ended June 30, 2006:	 	 	 	 	 	 	 	 	 	 	 	 	
Basic earnings per share	 	$	1,554	 	 	 	441	 	 	$	3.52	 	
 	 	 	 	 	 	 	 	 	 	 	 	
Dilutive effect of potential common shares issuable upon the exercise of outstanding stock options	 	 	—	 	 	 	6	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	
Diluted earnings per share	 	$	1,554	 	 	 	447	 	 	$	3.47	 	

Six Months Ended June 30, 2005:	 	 	 	 	 	 	 	 	 	 	 	 	
Basic earnings per share	 	$	1,211	 	 	 	472	 	 	$	2.57	 	
 	 	 	 	 	 	 	 	 	 	 	 	
Dilutive effect of potential common shares issuable upon the exercise of outstanding stock options	 	 	—	 	 	 	7	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	
Diluted earnings per share	 	$	1,211	 	 	 	479	 	 	$	2.53	 	
 	 	 	 	 	 	 	 	 	 	
     Certain options to purchase shares of Devon’s common stock are excluded from the dilution calculations because the options are antidilutive. During both the three-month and six-month periods ended 2006, 2.6 million shares were excluded from the diluted earnings per share calculations. During the three-months and six-months ended 2005, 36,000 shares and 84,000 shares, respectively, were excluded from the diluted earnings per share calculations.
Change in Accounting Principle
     Effective January 1, 2006, Devon adopted Statement of Financial Accounting Standard No. 123(R), Share-Based Payment , (“SFAS No. 123(R)”), using the modified prospective transition method. SFAS No. 123(R) requires equity-classified share-based payments to employees, including grants of employee stock options, to be valued at fair value on the date of grant and to be expensed over the applicable vesting period. Under the modified prospective transition method, share-based awards granted or modified on or after January 1, 2006, are recognized in compensation expense over the applicable vesting period. Also, any previously granted awards that are not fully vested as of January 1, 2006 are recognized as compensation expense over the remaining vesting period. No retroactive or cumulative effect adjustments were required upon Devon’s adoption of SFAS No. 123(R).
     Prior to adopting SFAS No. 123(R), Devon accounted for its fixed-plan employee stock options using the intrinsic-value based method prescribed by Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees, (“APB No. 25”) and related interpretations. This method required compensation expense to be recorded on the date of grant only if the current market price of the underlying stock exceeded the exercise price.
     Had Devon elected the fair value provisions of SFAS No. 123(R), Devon’s 2005 net earnings and net earnings per share would have differed from the amounts actually reported as shown in the following table.
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
 	 	 	 	 	 	 	 	 	
 	 	Three Months	 	 	Six Months	 	
 	 	Ended June 30,	 	 	Ended June 30,	 	
 	 	2005	 	 	2005	 	
 	 	(In millions, except per share amounts)	 	
Net earnings available to common stockholders, as reported	 	$	650	 	 	 	1,211	 	
Add share-based employee compensation expense included in reported earnings, net of related tax expense	 	 	5	 	 	 	9	 	
Deduct total share-based employee compensation expense determined under fair value based method for all awards, net of related tax expense	 	 	(10	)	 	 	(20	)	
 	 	 	 	 	 	 	
Net earnings available to common stockholders, pro forma	 	$	645	 	 	 	1,200	 	

Net earnings per share available to common stockholders:	 	 	 	 	 	 	 	 	
As reported:	 	 	 	 	 	 	 	 	
Basic	 	$	1.40	 	 	 	2.57	 	
Diluted	 	$	1.38	 	 	 	2.53	 	
Pro forma:	 	 	 	 	 	 	 	 	
Basic	 	$	1.39	 	 	 	2.54	 	
Diluted	 	$	1.37	 	 	 	2.52	 	
     As a result of adopting SFAS No. 123(R) on January 1, 2006, Devon’s earnings before income tax expense for the three-month and six-month periods ended June 30, 2006 were $5 million and $11 million lower, respectively, than if Devon had continued to account for share-based compensation under APB No. 25. Also as a result of the adoption, net earnings for the three-month and six-month periods ended June 30, 2006 were $3 million and $7 million lower, respectively, and the related basic and diluted earnings per share were approximately $0.01 per share lower for each 2006 period. Prior to the adoption of SFAS No. 123(R), Devon presented all tax benefits of deductions resulting from the exercise of stock options as operating cash inflows in the statement of cash flows. SFAS No. 123(R) requires the cash inflows resulting from tax deductions in excess of the compensation expense recognized for those stock options (“excess tax benefits”) to be classified as financing cash inflows. As required by SFAS No. 123(R), Devon recognized $7 million of excess tax benefits as financing cash inflows for the six months ended June 30, 2006.
Impact of Recently Issued Accounting Standards Not Yet Adopted
     In June 2006, the FASB issued FASB Interpretation Number 48, “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109.” This Interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes.” This Interpretation is effective for fiscal years beginning after December 15, 2006. Devon is currently assessing the effect of this Interpretation on its financial statements.
2. Comprehensive Income or Loss
     Devon’s comprehensive income or loss information is included in the accompanying consolidated statements of stockholders’ equity and comprehensive income. A summary of accumulated other comprehensive income as of June 30, 2006 and 2005, and changes during each of the six months then ended, is presented in the following table.
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Change in	 	 	 	 	 	 	 	 	 	 	
 	 	Foreign	 	 	Fair Value	 	 	Minimum	 	 	Unrealized	 	 	 	 	
 	 	Currency	 	 	of	 	 	Pension	 	 	Gain on	 	 	 	 	
 	 	Translation	 	 	Financial	 	 	Liability	 	 	Marketable	 	 	 	 	
 	 	Adjustments	 	 	Instruments	 	 	Adjustments	 	 	Securities	 	 	Total	 	
 	 	(In millions)	 	
Balance as of December 31, 2005	 	$	1,217	 	 	 	3	 	 	 	(18	)	 	 	212	 	 	 	1,414	 	
2006 activity	 	 	304	 	 	 	(1	)	 	 	—	 	 	 	75	 	 	 	378	 	
Deferred taxes	 	 	7	 	 	 	—	 	 	 	—	 	 	 	(27	)	 	 	(20	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
2006 activity, net of deferred taxes	 	 	311	 	 	 	(1	)	 	 	—	 	 	 	48	 	 	 	358	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance as of June 30, 2006	 	$	1,528	 	 	 	2	 	 	 	(18	)	 	 	260	 	 	 	1,772	 	

Balance as of December 31, 2004	 	$	1,055	 	 	 	(286	)	 	 	(13	)	 	 	174	 	 	 	930	 	
2005 activity	 	 	(110	)	 	 	35	 	 	 	—	 	 	 	48	 	 	 	(27	)	
Deferred taxes	 	 	10	 	 	 	(14	)	 	 	—	 	 	 	(17	)	 	 	(21	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
2005 activity, net of deferred taxes	 	 	(100	)	 	 	21	 	 	 	—	 	 	 	31	 	 	 	(48	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Balance as of June 30, 2005	 	$	955	 	 	 	(265	)	 	 	(13	)	 	 	205	 	 	 	882	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
3. Supplemental Cash Flow Information
     Cash payments for interest and income taxes in the first six months of 2006 and 2005 are presented below:
 	 	 	 	 	 	 	 	 	
 	 	Six Months	
 	 	Ended June 30,	
 	 	2006	 	2005	
 	 	(In millions)	
Interest paid	 	$	232	 	 	 	353	 	
Income taxes	 	$	608	 	 	 	663	 	
4. Property and Equipment and Asset Retirement Obligations
Chief Acquisition
     On June 29, 2006, Devon completed its acquisition of privately-owned Chief Holdings LLC (“Chief”). Devon paid $2.0 billion in cash and assumed approximately $0.2 billion of net liabilities in the transaction for a total purchase price of $2.2 billion. Devon funded the acquisition price, and the immediate retirement of $180 million of assumed debt, with $718 million of cash on hand and approximately $1.4 billion of borrowings issued under its commercial paper program. Devon estimates that the acquired properties include proved reserves of 598.2 billion cubic feet of natural gas equivalent and leasehold totaling 169,000 net acres located in the Barnett Shale area of Texas. Devon preliminarily allocated approximately $1.0 billion of the purchase price to proved reserves and approximately $1.2 billion to unproved properties.
Asset Retirement Obligations
     The following is a summary of the changes in Devon’s asset retirement obligation for the first half of 2006 and 2005.
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
 	 	 	 	 	 	 	 	 	
 	 	Six Months Ended June 30,	 	
 	 	2006	 	 	2005	 	
 	 	(In millions)	 	
Asset retirement obligation as of beginning of period	 	$	668	 	 	 	739	 	
Liabilities incurred	 	 	25	 	 	 	23	 	
Liabilities settled	 	 	(29	)	 	 	(23	)	
Liabilities assumed by others	 	 	—	 	 	 	(115	)	
Revision of estimated obligation	 	 	138	 	 	 	74	 	
Accretion expense on discounted obligation	 	 	24	 	 	 	23	 	
Foreign currency translation adjustment	 	 	13	 	 	 	(5	)	
 	 	 	 	 	 	 	
Asset retirement obligation as of end of period	 	 	839	 	 	 	716	 	
Less current portion	 	 	73	 	 	 	49	 	
 	 	 	 	 	 	 	
Asset retirement obligation, long-term	 	$	766	 	 	 	667	 	
 	 	 	 	 	 	 	
5. Debt
New Credit Facility
     In April 2006, Devon replaced its existing $1.5 billion five-year unsecured revolving credit facility with a $2.0 billion five-year, syndicated, unsecured revolving line of credit (the “Senior Credit Facility”). In June 2006, Devon amended its Senior Credit Facility to increase the aggregate commitment amount under the Senior Credit Facility from $2.0 billion to $2.5 billion. The amendment also added the right to increase the aggregate commitment further to $3.0 billion, under the same terms and conditions, should Devon deem any additional increase necessary.
     The Senior Credit Facility includes a five-year revolving Canadian subfacility in a maximum amount of U.S. $500 million.
     The Senior Credit Facility matures on April 7, 2011, and all amounts outstanding will be due and payable at that time unless the maturity is extended. Prior to each April 7 anniversary date, Devon has the option to extend the maturity of the Senior Credit Facility for one year, subject to the approval of the lenders.
     Amounts borrowed under the Senior Credit Facility may, at Devon’s election, bear interest at various fixed rate options for periods of up to twelve months. Such rates are generally less than the prime rate. Devon may also elect to borrow at the prime rate. The Senior Credit Facility currently provides for an annual facility fee of $2.3 million that is payable quarterly in arrears.
     As of June 30, 2006, there were no borrowings under the Senior Credit Facility. The available capacity under the Senior Credit Facility as of June 30, 2006, net of $287 million of outstanding letters of credit and $1.4 billion of outstanding commercial paper, was approximately $788 million.
     The Senior Credit Facility contains only one material financial covenant. This covenant requires Devon to maintain a ratio of total funded debt to total capitalization, as defined in the credit agreement, of no more than 65%. As of June 30, 2006, Devon was in compliance with such covenants and restrictions. Devon’s debt-to-capitalization ratio at June 30, 2006, as calculated pursuant to the terms of the agreement, was 29.3%.
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Commercial Paper
     On June 28, 2006, Devon commenced issuing commercial paper under its program. Devon may borrow up to $2.0 billion under the commercial paper program. Also, any borrowings under the commercial paper program reduce available capacity under the Senior Credit Facility on a dollar-for-dollar basis. Commercial paper debt generally has a maturity of between one to 90 days, although it can have a maturity of up to 365 days, and bears interest at rates agreed to at the time of the borrowing. The interest rate is based on a standard index such as the Federal Funds Rate, London Interbank Offered Rate (LIBOR), or the money market rate as found in the commercial paper market. As of June 30, 2006, Devon had $1.4 billion of commercial paper outstanding at an average rate of 5.45%. The $1.4 billion of commercial paper is classified as current in the accompanying consolidated balance sheet.
6. Income Taxes
     During the second quarter of 2006, the Canadian Federal and Alberta provincial governments enacted statutory rate reductions. As a result of these rate reductions, Devon recorded a $243 million deferred tax benefit in such quarter. Also during the second quarter of 2006, the state of Texas enacted a new income-based tax that replaces a previous franchise tax. The new tax is effective January 1, 2007. As a result of the enactment of the new tax in the second quarter of 2006, Devon recorded $39 million of deferred tax expense in such quarter.
7. Stockholders’ Equity
     The following is a summary of the changes in Devon’s common shares outstanding for the first half of 2006 and 2005.
 	 	 	 	 	 	 	 	 	
 	 	Six Months Ended	
 	 	June 30,	
 	 	2006	 	2005	
 	 	(In millions)	
Shares outstanding, beginning of period	 	 	443	 	 	 	484	 	
Exercise of stock options	 	 	1	 	 	 	3	 	
Shares repurchased and retired	 	 	(4	)	 	 	(34	)	
Grant of restricted stock awards	 	 	1	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	
Shares outstanding, end of period	 	 	441	 	 	 	453	 	
 	 	 	 	 	 	 	 	 	
     The shares repurchased in 2006 were repurchased at a cost of $253 million, or $59.61, per share. The shares repurchased in 2005 were repurchased at a cost of $1.6 billion, or $45.62, per share.
     On August 3, 2005, Devon announced that its board of directors had authorized the repurchase of up to 50 million shares of our common stock. As of August 1, 2006, Devon had repurchased 6.5 million shares under this program for $387 million, or $59.80 per share. As a result of the Chief acquisition (see Note 4), this repurchase program has been suspended and will be reevaluated at a later date.
Share-Based Compensation Plans
     As discussed in Note 1, on January 1, 2006, Devon changed its method of accounting for share-based compensation from the APB No. 25 intrinsic value accounting method to the fair value recognition provisions of SFAS No. 123(R). Currently, Devon’s share-based compensation includes amounts related to grants of nonqualified and incentive stock options, restricted stock awards and restricted stock units.
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
     The following table is a summary of the effects of share-based compensation included in Devon’s accompanying statement of operations.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Three Months	 	Six Months	
 	 	Ended June 30,	 	Ended June 30,	
 	 	2006	 	2005	 	2006	 	2005	
 	 	(In millions)	
Gross general and administrative expense	 	$	17	 	 	 	7	 	 	 	37	 	 	 	14	 	
Share-based compensation expense capitalized pursuant to the full cost method of accounting for oil and gas properties	 	$	5	 	 	 	—	 	 	 	10	 	 	 	—	 	
Related income tax benefit	 	$	5	 	 	 	3	 	 	 	10	 	 	 	5	 	
     Devon estimates the fair values of stock options granted using a Black-Scholes option valuation model, which requires Devon to make several assumptions. The volatility of Devon’s common stock is based on the historical volatility of the market price of Devon’s common stock over a period of time equal to the expected term of the option and ending on the grant date. The dividend yield is based on Devon’s historical and current yield in effect at the date of grant. The risk-free interest rate is based on the U.S. Treasury yield for the expected term of the option at the date of grant. The expected term of the options is based on historical exercise and termination experience for various groups of employees and directors. Each group is determined based on the similarity of their historical exercise and termination behavior.
     Included in the following table is a summary of the grant-date fair values of stock options granted and the related assumptions. All such amounts represent the weighted-average amounts for each period.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Three Months	 	Six Months	
 	 	Ended June 30,	 	Ended June 30,	
 	 	2006	 	2005	 	2006	 	2005	
Grant-date fair value	 	$	20.63	 	 	 	15.68	 	 	 	19.94	 	 	 	15.04	 	
Volatility factor	 	 	33.2	%	 	 	34.0	%	 	 	31.8	%	 	 	33.7	%	
Dividend yield	 	 	0.5	%	 	 	0.7	%	 	 	0.4	%	 	 	0.7	%	
Risk-free interest rate	 	 	5.2	%	 	 	3.8	%	 	 	5.0	%	 	 	3.9	%	
Expected term (in years)	 	 	5.0	 	 	 	4.9	 	 	 	4.5	 	 	 	4.6	 	
     Devon estimates the fair values of restricted stock awards and units as the closing price of Devon’s common stock on the grant date of the award or unit.
     A summary of Devon’s outstanding stock options as of June 30, 2006, including changes during the six months then ended, is presented below.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	Weighted	 	 	
 	 	 	 	 	 	Weighted	 	Average	 	 	
 	 	 	 	 	 	Average	 	Remaining	 	Aggregate	
 	 	 	 	 	 	Exercise	 	Contractual	 	Intrinsic	
 	 	Options	 	Price	 	Term	 	Value	
 	 	(In thousands)	 	 	 	 	 	(In Years)	 	(In millions)	
Outstanding at December 31, 2005	 	 	16,732	 	 	$	32.74	 	 	 	 	 	 	 	 	 	
Granted	 	 	152	 	 	$	60.25	 	 	 	 	 	 	 	 	 	
Exercised	 	 	(1,102	)	 	$	24.95	 	 	 	 	 	 	 	 	 	
Forfeited	 	 	(298	)	 	$	49.08	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Outstanding at June 30, 2006	 	 	15,484	 	 	$	33.25	 	 	 	4.3	 	 	$	435	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Vested and expected to vest at June 30, 2006	 	 	15,026	 	 	$	32.65	 	 	 	4.3	 	 	$	430	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Exercisable at June 30, 2006	 	 	9,853	 	 	$	25.19	 	 	 	4.0	 	 	$	348	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
     A summary of Devon’s unvested restricted stock awards as of June 30, 2006, including changes during the six months then ended, is presented below.
 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Weighted	
 	 	Restricted	 	Average	
 	 	Stock	 	Grant-Date	
 	 	Awards	 	Fair Value	
 	 	(In thousands)	 	 	 	 	
Unvested at December 31, 2005	 	 	3,187	 	 	$	46.80	 	
Granted	 	 	831	 	 	$	55.96	 	
Vested	 	 	(87	)	 	$	27.01	 	
Forfeited	 	 	(106	)	 	$	47.43	 	
 	 	 	 	 	 	 	 	 	
Unvested at June 30, 2006	 	 	3,825	 	 	$	49.22	 	
 	 	 	 	 	 	 	 	 	
     The aggregate intrinsic value of options exercised and the aggregate fair value of restricted stock awards vested are summarized in the table below.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Three Months	 	Six Months	
 	 	Ended June 30,	 	Ended June 30,	
 	 	2006	 	2005	 	2006	 	2005	
 	 	(In millions)	
Intrinsic value of stock options exercised	 	$	11	 	 	 	25	 	 	 	43	 	 	 	80	 	
Fair value of restricted stock awards vested	 	$	1	 	 	 	1	 	 	 	7	 	 	 	5	 	
     As of June 30, 2006, Devon’s unrecognized compensation costs related to unvested stock options and restricted stock awards were $55 million and $160 million, respectively. Such costs are expected to be recognized over weighted-average periods of 1.9 years and 2.7 years, respectively.
8. Other Income
     The components of other income include the following:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Three Months	 	Six Months	
 	 	Ended June 30,	 	Ended June 30,	
 	 	2006	 	 	2005	 	 	2006	 	 	2005	 	
 	 	(In millions)	 	
Interest and dividend income	 	$	28	 	 	 	25	 	 	 	56	 	 	 	51	 	
Net gain on sales of non-oil and gas property and equipment	 	 	1	 	 	 	—	 	 	 	5	 	 	 	150	 	
Loss on derivative financial instruments	 	 	—	 	 	 	(16	)	 	 	—	 	 	 	(55	)	
Other	 	 	1	 	 	 	5	 	 	 	(3	)	 	 	6	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Other income, net	 	$	30	 	 	 	14	 	 	 	58	 	 	 	152	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
9. Retirement Plans
     Devon has various non-contributory defined benefit pension plans, including qualified plans (“Qualified Plans”) and nonqualified plans (“Supplemental Plans”). The Qualified Plans provide retirement benefits for U.S. and Canadian employees meeting certain age and service requirements. The Supplemental Plans provide retirement benefits for certain employees whose benefits under the Qualified Plans are limited by income tax regulations. Devon also has defined benefit postretirement plans (“Postretirement Plans”) which provide benefits for substantially all employees. The Postretirement Plans provide medical and, in some cases, life insurance benefits and are, depending on the type of plan, either contributory or non-contributory.
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Net Periodic Cost
     The following table presents the plans’ net periodic benefit cost for the three-month and six-month periods ended June 30, 2006 and 2005.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	Other	 	
 	 	Pension Benefits	 	 	Post Retirement Benefits	 	
 	 	Three Months	 	 	Six Months	 	 	Three Months	 	 	Six Months	 	
 	 	Ended June 30,	 	 	Ended June 30,	 	 	Ended June 30,	 	 	Ended June 30,	 	
 	 	2006	 	 	2005	 	 	2006	 	 	2005	 	 	2006	 	 	2005	 	 	2006	 	 	2005	 	
 	 	(In millions)	 	
Components of net periodic benefit cost:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Service cost	 	$	6	 	 	 	5	 	 	 	12	 	 	 	10	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Interest cost	 	 	10	 	 	 	8	 	 	 	20	 	 	 	16	 	 	 	1	 	 	 	1	 	 	 	2	 	 	 	2	 	
Expected return on plan assets	 	 	(11	)	 	 	(9	)	 	 	(22	)	 	 	(18	)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Recognized net actuarial loss	 	 	3	 	 	 	2	 	 	 	6	 	 	 	4	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net periodic benefit cost	 	$	8	 	 	 	6	 	 	 	16	 	 	 	12	 	 	 	1	 	 	 	1	 	 	 	2	 	 	 	2	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Employer Contributions
     Devon previously disclosed in its financial statements for the year ended December 31, 2005, that it expected to contribute $7 million to the Qualified and Supplemental Plans in 2006 and $5 million to the Postretirement Plans in 2006. As of June 30, 2006, Devon has contributed $3 million to the Qualified and Supplemental Plans and $3 million to the Postretirement Plans.
10. Commitments and Contingencies
     Devon is party to various legal actions arising in the normal course of business. Matters that are probable of unfavorable outcome to Devon and which can be reasonably estimated are accrued. Such accruals are based on information known about the matters, Devon’s estimates of the outcomes of such matters and its experience in contesting, litigating and settling similar matters. None of the actions are believed by management to involve future amounts that would be material to Devon’s financial position or results of operations after consideration of recorded accruals although actual amounts could differ materially from management’s estimate.
Environmental Matters
     Devon is subject to certain laws and regulations relating to environmental remediation activities associated with past operations, such as the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) and similar state statutes. In response to liabilities associated with these activities, accruals have been established when reasonable estimates are possible. Such accruals primarily include estimated costs associated with remediation. Devon has not used discounting in determining its accrued liabilities for environmental remediation, and no material claims for possible recovery from third party insurers or other parties related to environmental costs have been recognized in Devon’s consolidated financial statements. Devon adjusts the accruals when new remediation responsibilities are discovered and probable costs become estimable, or when current remediation estimates must be adjusted to reflect new information.
     Certain of Devon’s subsidiaries acquired in past mergers are involved in matters in which it has been alleged that such subsidiaries are potentially responsible parties (“PRPs”) under CERCLA or similar state legislation with respect to various waste disposal areas owned or operated by third parties. As of
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
June 30, 2006, Devon’s consolidated balance sheet included $5 million of non-current accrued liabilities, reflected in “Other liabilities,” related to these and other environmental remediation liabilities. Devon does not currently believe there is a reasonable possibility of incurring additional material costs in excess of the current accruals recognized for such environmental remediation activities. With respect to the sites in which Devon subsidiaries are PRPs, Devon’s conclusion is based in large part on (i) Devon’s participation in consent decrees with both other PRPs and the Environmental Protection Agency, which provide for performing the scope of work required for remediation and contain covenants not to sue as protection to the PRPs, (ii) participation in groups as a de minimis PRP, and (iii) the availability of other defenses to liability. As a result, Devon’s monetary exposure is not expected to be material.
Royalty Matters
     Numerous gas producers and related parties, including Devon, have been named in various lawsuits alleging violation of the federal False Claims Act. The suits allege that the producers and related parties used below-market prices, improper deductions, improper measurement techniques and transactions with affiliates which resulted in underpayment of royalties in connection with natural gas and natural gas liquids produced and sold from federal and Indian owned or controlled lands. The principal suit in which Devon is a defendant is United States ex rel. Wright v. Chevron USA, Inc. et al. (the “ Wright case”). The suit was originally filed in August 1996 in the United States District Court for the Eastern District of Texas, but was consolidated in October 2000 with the other suits for pre-trial proceedings in the United States District Court for the District of Wyoming. On July 10, 2003, the District of Wyoming remanded the Wright case back to the Eastern District of Texas to resume proceedings. On February 1, 2006, the Court entered a scheduling order in which trial is set for November 2007 if the suit continues to advance. Devon believes that it has acted reasonably, has legitimate and strong defenses to all allegations in the suit, and has paid royalties in good faith. Devon does not currently believe that it is subject to material exposure in association with this lawsuit and no liability has been recorded in connection therewith.
     In 1995, the United States Congress passed the Deep Water Royalty Relief Act (the “DWRRA”). The intent of the DWRRA was to encourage deep water exploration in the Gulf of Mexico by providing relief from the obligation to pay royalties on certain federal leases. The DWRRA granted royalty relief, without regard to the market prices of oil or natural gas, with respect to leases issued between November 28, 1995 and November 28, 2000. However, in regulations promulgated by the Minerals Management Service (the “MMS”) subsequent to the passage of the DWRRA, the MMS imposed price thresholds on certain of these deep water leases issued in 1996, 1997 and 2000, such that if the market prices for oil or natural gas exceeded the thresholds for a given year, royalty relief would not be granted for that year.
     The MMS has issued an order to Devon and other oil and gas producers to pay royalties on production from these leases issued in 1996, 1997 and 2000 due to market prices exceeding the price thresholds in recent years. Devon and certain other oil and gas producers have filed Administrative Appeals with the MMS contesting the MMS’ orders. In March 2006, one oil and gas producer filed suit in Federal court against the Department of Interior challenging the MMS’ authority to suspend royalty relief on the subject leases. Subsequently, in June 2006, such producer announced that it and the Department of Interior had agreed to ask the court to postpone the entry of a scheduling order while the two parties undertake efforts to mediate the disagreement.
     Devon does not believe that the MMS has the legal authority to suspend the royalty relief granted by the DWRRA. This is based in part on prior successful litigation against the Department of Interior and the MMS involving similar issues related to the DWRRA. Accordingly, Devon has not accrued for any
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
such royalties in its consolidated financial statements. If it were to be found that the MMS’ regulations are valid, Devon estimates that as of June 30, 2006, it would owe royalties and interest totaling $14 million for production from properties obtained in the leases issued in 1996, 1997 and 2000.
     Deep water leases issued in 1998 and 1999 did not include price thresholds. However, numerous government officials have recently called for the renegotiation of the leases issued in 1998 and 1999, with the renegotiated terms to include price thresholds. Legislation has been discussed that would prohibit companies from bidding on new leases if they have not paid royalties on properties obtained in 1998 and 1999 leases. In June and July 2006, the MMS issued letters to Devon and other oil and gas producers who acquired leases issued in 1998 and 1999. In such letters, the MMS acknowledges that the 1998 and 1999 leases do not include price thresholds, but maintains that such omission was an error on its part and was not its intention. While the MMS has confirmed that it will continue to honor the terms of these leases as issued, it notes the concerns being expressed by Congress and has invited Devon and the other affected oil and gas producers to renegotiate the terms and conditions of the 1998 and 1999 leases to add price threshold provisions. Devon has not yet met with the MMS on this issue and will not determine its course of action until such a meeting takes place. However, if Devon were to agree to renegotiate the terms of its 1998 and 1999 leases to include price threshold provisions, Devon would expect that such provisions would only be effective on a prospective basis.
Equatorial Guinea Investigation
     The SEC has been conducting an inquiry into payments made to the government of Equatorial Guinea, and to officials and persons affiliated with officials of the government of Equatorial Guinea. On August 9, 2005, Devon received a subpoena issued by the SEC pursuant to a formal order of investigation. Devon has cooperated fully with the SEC’s previous requests for information in this inquiry and plans to continue to work with the SEC in connection with its formal investigation.
Hurricane Contingencies
     Devon maintains a comprehensive insurance program that includes coverage for physical damage to its offshore facilities caused by hurricanes. Devon’s insurance program also includes substantial business interruption coverage which Devon expects to utilize to recover costs associated with the suspended production related to hurricanes that struck the Gulf of Mexico in the third quarter of 2005. Under the terms of the insurance program, Devon is entitled to be reimbursed for the portion of production suspended longer than forty-five days, subject to upper limits to oil and natural gas prices. Also, the terms of the insurance include a standard, per-event deductible of $1 million for offshore losses as well as a $15 million aggregate annual deductible. Based on current estimates of physical damage and the anticipated length of time Devon will have production suspended, Devon expects its policy recoveries will exceed repair costs and deductible amounts. This expectation is based upon several variables, including the amount of partial settlements that have been agreed to in July 2006. Should Devon’s total policy recoveries exceed repair costs and deductible amounts, the excess will be recognized as other income in the statement of operations.
     The policy underlying the insurance program terms described above expires on August 31, 2006. Devon is currently working with its insurers to renew this policy and continue an insurance program that includes comprehensive coverage, including business interruption and physical damage coverage, for its business. Although Devon has not finalized the exact terms of its new coverage, it expects the new policy terms related to damage from named windstorms in the Gulf of Mexico will be materially different from the terms of its existing coverage. Devon expects the new coverage will include reduced coverage limits and higher deductibles and retention amounts as compared to those currently in effect.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Other Matters
     Devon is involved in other various routine legal proceedings incidental to its business. However, to Devon’s knowledge as of the date of this report, there were no other material pending legal proceedings to which Devon is a party or to which any of its property is subject.
11. Reduction of Carrying Value of Oil and Gas Properties
     During the second quarter of 2006, Devon drilled two unsuccessful exploratory wells in Brazil and determined that the capitalized costs related to these two wells should be impaired. Therefore, in the second quarter of 2006, Devon recognized a $16 million impairment of its investment in Brazil equal to the costs to drill the two dry holes and a proportionate share of block-related costs. There is no tax benefit related to this impairment. The two wells were unrelated to Devon’s Polvo development project in Brazil.
     Devon has committed to drill four wells in Nigeria. The first two wells were unsuccessful. After drilling the second unsuccessful well in the first quarter of 2006, Devon determined that the capitalized costs related to these two wells should be impaired. Therefore, in the first quarter of 2006, Devon recognized an $85 million impairment of its investment in Nigeria equal to the costs to drill the two dry holes and a proportionate share of block-related costs. There is no tax benefit related to this impairment.
12. Segment Information
     Following is certain financial information regarding Devon’s reporting segments. The revenues reported are all from external customers.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	U.S.	 	 	Canada	 	 	International	 	 	Total	 	
 	 	 	 	 	 	(In millions)	 	 	 	 	 	
As of June 30, 2006:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Current assets	 	$	1,097	 	 	 	892	 	 	 	1,056	 	 	 	3,045	 	
Property and equipment, net of accumulated depreciation, depletion and amortization	 	 	14,048	 	 	 	6,873	 	 	 	2,398	 	 	 	23,319	 	
Goodwill	 	 	3,057	 	 	 	2,698	 	 	 	68	 	 	 	5,823	 	
Other assets	 	 	1,291	 	 	 	16	 	 	 	24	 	 	 	1,331	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total assets	 	$	19,493	 	 	 	10,479	 	 	 	3,546	 	 	 	33,518	 	

Current liabilities	 	$	3,159	 	 	 	815	 	 	 	224	 	 	 	4,198	 	
Long-term debt	 	 	2,984	 	 	 	2,972	 	 	 	—	 	 	 	5,956	 	
Asset retirement obligation, long-term	 	 	360	 	 	 	364	 	 	 	42	 	 	 	766	 	
Other liabilities	 	 	522	 	 	 	11	 	 	 	20	 	 	 	553	 	
Deferred income taxes	 	 	3,271	 	 	 	1,892	 	 	 	389	 	 	 	5,552	 	
Stockholders’ equity	 	 	9,197	 	 	 	4,425	 	 	 	2,871	 	 	 	16,493	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total liabilities and stockholders’ equity	 	$	19,493	 	 	 	10,479	 	 	 	3,546	 	 	 	33,518	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	U.S.	 	 	Canada	 	 	International	 	 	Total	 	
 	 	 	 	 	 	(In millions)	 	 	 	 	 	
Three Months Ended June 30, 2006:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Revenues:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oil sales	 	$	334	 	 	 	167	 	 	 	356	 	 	 	857	 	
Gas sales	 	 	802	 	 	 	358	 	 	 	10	 	 	 	1,170	 	
NGL sales	 	 	139	 	 	 	54	 	 	 	—	 	 	 	193	 	
Marketing and midstream revenues	 	 	383	 	 	 	8	 	 	 	6	 	 	 	397	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total revenues	 	 	1,658	 	 	 	587	 	 	 	372	 	 	 	2,617	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Expenses and other income, net:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Lease operating expenses	 	 	198	 	 	 	134	 	 	 	30	 	 	 	362	 	
Production taxes	 	 	58	 	 	 	1	 	 	 	27	 	 	 	86	 	
Marketing and midstream operating costs and expenses	 	 	283	 	 	 	2	 	 	 	3	 	 	 	288	 	
Depreciation, depletion and amortization of oil and gas properties	 	 	304	 	 	 	170	 	 	 	82	 	 	 	556	 	
Depreciation and amortization of non-oil and gas properties	 	 	38	 	 	 	4	 	 	 	1	 	 	 	43	 	
Accretion of asset retirement obligation	 	 	6	 	 	 	6	 	 	 	1	 	 	 	13	 	
General and administrative expenses	 	 	71	 	 	 	21	 	 	 	(2	)	 	 	90	 	
Interest expense	 	 	46	 	 	 	56	 	 	 	—	 	 	 	102	 	
Effects of changes in foreign currency exchange rates	 	 	—	 	 	 	1	 	 	 	(1	)	 	 	—	 	
Change in fair value of derivative financial instruments	 	 	47	 	 	 	—	 	 	 	—	 	 	 	47	 	
Reduction of carrying value of oil and gas properties	 	 	—	 	 	 	—	 	 	 	16	 	 	 	16	 	
Other income, net	 	 	(17	)	 	 	(6	)	 	 	(7	)	 	 	(30	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total expenses and other income, net	 	 	1,034	 	 	 	389	 	 	 	150	 	 	 	1,573	 	
Earnings before income tax expense (benefit)	 	 	624	 	 	 	198	 	 	 	222	 	 	 	1,044	 	
Income tax expense (benefit):	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Current	 	 	84	 	 	 	37	 	 	 	77	 	 	 	198	 	
Deferred	 	 	199	 	 	 	(196	)	 	 	(16	)	 	 	(13	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total income tax expense (benefit)	 	 	283	 	 	 	(159	)	 	 	61	 	 	 	185	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Net earnings	 	 	341	 	 	 	357	 	 	 	161	 	 	 	859	 	
Preferred stock dividends	 	 	3	 	 	 	—	 	 	 	—	 	 	 	3	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Net earnings applicable to common stockholders	 	$	338	 	 	 	357	 	 	 	161	 	 	 	856	 	

Capital expenditures	 	$	3,094	 	 	 	324	 	 	 	102	 	 	 	3,520	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	U.S.	 	 	Canada	 	 	International	 	 	Total	 	
 	 	 	 	 	 	(In millions)	 	 	 	 	 	
Three Months Ended June 30, 2005:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Revenues:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oil sales	 	$	278	 	 	 	83	 	 	 	289	 	 	 	650	 	
Gas sales	 	 	862	 	 	 	400	 	 	 	10	 	 	 	1,272	 	
NGL sales	 	 	110	 	 	 	45	 	 	 	2	 	 	 	157	 	
Marketing and midstream revenues	 	 	386	 	 	 	3	 	 	 	—	 	 	 	389	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total revenues	 	 	1,636	 	 	 	531	 	 	 	301	 	 	 	2,468	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Expenses and other income, net:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Lease operating expenses	 	 	174	 	 	 	128	 	 	 	36	 	 	 	338	 	
Production taxes	 	 	59	 	 	 	2	 	 	 	14	 	 	 	75	 	
Marketing and midstream operating costs and expenses	 	 	295	 	 	 	1	 	 	 	—	 	 	 	296	 	
Depreciation, depletion and amortization of oil and gas properties	 	 	282	 	 	 	134	 	 	 	78	 	 	 	494	 	
Depreciation and amortization of non-oil and gas properties	 	 	35	 	 	 	4	 	 	 	2	 	 	 	41	 	
Accretion of asset retirement obligation	 	 	7	 	 	 	4	 	 	 	—	 	 	 	11	 	
General and administrative expenses	 	 	62	 	 	 	17	 	 	 	(1	)	 	 	78	 	
Interest expense	 	 	80	 	 	 	66	 	 	 	—	 	 	 	146	 	
Effects of changes in foreign currency exchange rates	 	 	—	 	 	 	12	 	 	 	(1	)	 	 	11	 	
Change in fair value of derivative financial instruments	 	 	(18	)	 	 	—	 	 	 	—	 	 	 	(18	)	
Other income, net	 	 	(22	)	 	 	9	 	 	 	(1	)	 	 	(14	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total expenses and other income, net	 	 	954	 	 	 	377	 	 	 	127	 	 	 	1,458	 	
Earnings before income tax expense	 	 	682	 	 	 	154	 	 	 	174	 	 	 	1,010	 	
Income tax expense (benefit):	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Current	 	 	189	 	 	 	12	 	 	 	76	 	 	 	277	 	
Deferred	 	 	42	 	 	 	51	 	 	 	(13	)	 	 	80	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total income tax expense	 	 	231	 	 	 	63	 	 	 	63	 	 	 	357	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Net earnings	 	 	451	 	 	 	91	 	 	 	111	 	 	 	653	 	
Preferred stock dividends	 	 	3	 	 	 	—	 	 	 	—	 	 	 	3	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Net earnings applicable to common stockholders	 	$	448	 	 	 	91	 	 	 	111	 	 	 	650	 	

Capital expenditures	 	$	544	 	 	 	477	 	 	 	37	 	 	 	1,058	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	U.S.	 	 	Canada	 	 	International	 	 	Total	 	
 	 	 	 	 	 	(In millions)	 	 	 	 	 	
Six Months Ended June 30, 2006:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Revenues:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oil sales	 	$	628	 	 	 	289	 	 	 	655	 	 	 	1,572	 	
Gas sales	 	 	1,721	 	 	 	793	 	 	 	20	 	 	 	2,534	 	
NGL sales	 	 	263	 	 	 	106	 	 	 	—	 	 	 	369	 	
Marketing and midstream revenues	 	 	833	 	 	 	15	 	 	 	11	 	 	 	859	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total revenues	 	 	3,445	 	 	 	1,203	 	 	 	686	 	 	 	5,334	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Expenses and other income, net:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Lease operating expenses	 	 	394	 	 	 	258	 	 	 	59	 	 	 	711	 	
Production taxes	 	 	124	 	 	 	3	 	 	 	42	 	 	 	169	 	
Marketing and midstream operating costs and expenses	 	 	618	 	 	 	5	 	 	 	4	 	 	 	627	 	
Depreciation, depletion and amortization of oil and gas properties	 	 	585	 	 	 	320	 	 	 	158	 	 	 	1,063	 	
Depreciation and amortization of non-oil and gas properties	 	 	75	 	 	 	8	 	 	 	2	 	 	 	85	 	
Accretion of asset retirement obligation	 	 	12	 	 	 	10	 	 	 	2	 	 	 	24	 	
General and administrative expenses	 	 	141	 	 	 	42	 	 	 	(3	)	 	 	180	 	
Interest expense	 	 	88	 	 	 	115	 	 	 	—	 	 	 	203	 	
Effects of changes in foreign currency exchange rates	 	 	—	 	 	 	1	 	 	 	(2	)	 	 	(1	)	
Change in fair value of derivative financial instruments	 	 	61	 	 	 	(2	)	 	 	—	 	 	 	59	 	
Reduction of carrying value of oil and gas properties	 	 	—	 	 	 	—	 	 	 	101	 	 	 	101	 	
Other income, net	 	 	(33	)	 	 	(12	)	 	 	(13	)	 	 	(58	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total expenses and other income, net	 	 	2,065	 	 	 	748	 	 	 	350	 	 	 	3,163	 	
Earnings before income tax expense (benefit)	 	 	1,380	 	 	 	455	 	 	 	336	 	 	 	2,171	 	
Income tax expense (benefit):	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Current	 	 	266	 	 	 	88	 	 	 	148	 	 	 	502	 	
Deferred	 	 	295	 	 	 	(153	)	 	 	(32	)	 	 	110	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total income tax expense (benefit)	 	 	561	 	 	 	(65	)	 	 	116	 	 	 	612	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Net earnings	 	 	819	 	 	 	520	 	 	 	220	 	 	 	1,559	 	
Preferred stock dividends	 	 	5	 	 	 	—	 	 	 	—	 	 	 	5	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Net earnings applicable to common stockholders	 	$	814	 	 	 	520	 	 	 	220	 	 	 	1,554	 	

Capital expenditures	 	$	3,826	 	 	 	970	 	 	 	258	 	 	 	5,054	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	U.S.	 	 	Canada	 	 	International	 	 	Total	 	
 	 	 	 	 	 	(In millions)	 	 	 	 	 	
Six Months Ended June 30, 2005:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Revenues:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oil sales	 	$	569	 	 	 	161	 	 	 	535	 	 	 	1,265	 	
Gas sales	 	 	1,651	 	 	 	775	 	 	 	21	 	 	 	2,447	 	
NGL sales	 	 	213	 	 	 	85	 	 	 	4	 	 	 	302	 	
Marketing and midstream revenues	 	 	799	 	 	 	6	 	 	 	—	 	 	 	805	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total revenues	 	 	3,232	 	 	 	1,027	 	 	 	560	 	 	 	4,819	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Expenses and other income, net:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Lease operating expenses	 	 	364	 	 	 	253	 	 	 	69	 	 	 	686	 	
Production taxes	 	 	124	 	 	 	4	 	 	 	25	 	 	 	153	 	
Marketing and midstream operating costs and expenses	 	 	625	 	 	 	2	 	 	 	—	 	 	 	627	 	
Depreciation, depletion and amortization of oil and gas properties	 	 	589	 	 	 	278	 	 	 	168	 	 	 	1,035	 	
Depreciation and amortization of non-oil and gas properties	 	 	69	 	 	 	7	 	 	 	3	 	 	 	79	 	
Accretion of asset retirement obligation	 	 	14	 	 	 	8	 	 	 	1	 	 	 	23	 	
General and administrative expenses	 	 	117	 	 	 	27	 	 	 	(8	)	 	 	136	 	
Interest expense	 	 	131	 	 	 	133	 	 	 	—	 	 	 	264	 	
Effects of changes in foreign currency exchange rates	 	 	—	 	 	 	13	 	 	 	(2	)	 	 	11	 	
Change in fair value of derivative financial instruments	 	 	36	 	 	 	(2	)	 	 	—	 	 	 	34	 	
Other income, net	 	 	(152	)	 	 	3	 	 	 	(3	)	 	 	(152	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total expenses and other income, net	 	 	1,917	 	 	 	726	 	 	 	253	 	 	 	2,896	 	
Earnings before income tax expense	 	 	1,315	 	 	 	301	 	 	 	307	 	 	 	1,923	 	
Income tax expense (benefit):	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Current	 	 	462	 	 	 	39	 	 	 	128	 	 	 	629	 	
Deferred	 	 	13	 	 	 	84	 	 	 	(19	)	 	 	78	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total income tax expense	 	 	475	 	 	 	123	 	 	 	109	 	 	 	707	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Net earnings	 	 	840	 	 	 	178	 	 	 	198	 	 	 	1,216	 	
Preferred stock dividends	 	 	5	 	 	 	—	 	 	 	—	 	 	 	5	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Net earnings applicable to common stockholders	 	$	835	 	 	 	178	 	 	 	198	 	 	 	1,211	 	

Capital expenditures	 	$	1,035	 	 	 	962	 	 	 	90	 	 	 	2,087	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
     The following discussion addresses material changes in results of operations for the three-month and six-month periods ended June 30, 2006, compared to the three-month and six-month periods ended June 30, 2005, and in financial condition since December 31, 2005. It is presumed that readers have read or have access to Devon’s 2005 Annual Report on Form 10-K which includes disclosures regarding critical accounting policies as part of Management’s Discussion and Analysis of Financial Condition and Results of Operations. Unless otherwise stated, all dollar amounts are expressed in U.S. dollars.
Overview
     We continued to execute our strategy to increase value per share. On June 29, 2006, we completed our acquisition of privately-owned Chief Holdings LLC (“Chief”). We paid $2.0 billion in cash and assumed approximately $0.2 billion of net liabilities in the transaction. We funded the acquisition price, and the immediate retirement of $180 million of assumed debt, with $718 million of cash on hand and approximately $1.4 billion of borrowings issued under our commercial paper program. We estimate that the acquired properties include proved reserves of 598.2 billion cubic feet of natural gas equivalent and leasehold totaling 169,000 net acres located in the Barnett Shale area of Texas. We preliminarily allocated approximately $1.0 billion of the purchase price to proved reserves and approximately $1.2 billion to unproved properties. The Chief acquisition had a minimal impact on our second quarter 2006 results of operations since it closed on June 29, 2006.
     The following summarizes our performance for the three-months and six-months ended 2006 compared to the three-months and six-months ended 2005:

 	•	 	Net earnings for the second quarter and first half of 2006 increased 31% and 28%, respectively	
 		
 	•	 	Earnings per diluted share for the second quarter and first half of 2006 rose 39% and 37%, respectively	
 		
 	•	 	Net cash provided by operating activities for the first half of 2006 increased 18% to $2.8 billion	
 		
 	•	 	Combined realized price for oil, gas and NGLs for the second quarter and first half of 2006 climbed 18% and 27%, respectively	
 		
 	•	 	Marketing and midstream operating profit for the second quarter and first half of 2006 rose 17% and 30%, respectively	
 		
 	•	 	Production decreased 2% for the second quarter, and was unchanged for the first half of 2006, excluding the effects of our 2005 sales of non-core properties and production suspended due to hurricanes	
 		
 	•	 	Per unit operating costs increased 18% and 17% for the second quarter and first half of 2006, respectively, due to cost inflation driven by commodity price increases and due to the weakened U.S. dollar compared to the Canadian dollar	
 		
 	•	 	Deferred income taxes in the second quarter and first half of 2006 include a $204 million net benefit due to the effects of statutory rate reductions enacted by the Canadian Federal and Alberta provincial governments, partially offset by a new income-based tax enacted by the state of Texas	
     A more complete overview and discussion of full year expectations can be found in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Devon’s 2005 Annual Report on Form 10-K and in a Form 8-K dated August 2, 2006 that includes certain updated 2006 estimates.
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Results of Operations
     Oil, gas and NGL revenues increased $141 million, or 7%, for the second quarter of 2006 compared to the second quarter of 2005, and $461 million, or 11%, for the first half of 2006 compared to the first half of 2005. The three-month and six-month comparisons of production and price changes are shown in the following tables.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Total	 	
 	 	Three Months Ended June 30,	 	 	Six Months Ended June 30,	 	
 	 	2006	 	 	2005	 	 	Change 2	 	 	2006	 	 	2005	 	 	Change 2	 	
Production	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oil (MMBbls)	 	 	14	 	 	 	17	 	 	 	-23	%	 	 	27	 	 	 	35	 	 	 	-24	%	
Gas (Bcf)	 	 	201	 	 	 	209	 	 	 	-4	%	 	 	392	 	 	 	423	 	 	 	-7	%	
NGLs (MMBbls)	 	 	6	 	 	 	6	 	 	 	-6	%	 	 	12	 	 	 	12	 	 	 	-4	%	
Oil, Gas and NGLs (MMBoe) 1	 	 	53	 	 	 	59	 	 	 	-10	%	 	 	104	 	 	 	118	 	 	 	-12	%	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Average Prices	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oil (Per Bbl)	 	$	63.69	 	 	 	37.28	 	 	 	+71	%	 	$	58.53	 	 	 	35.86	 	 	 	+63	%	
Gas (Per Mcf)	 	 	5.83	 	 	 	6.09	 	 	 	-4	%	 	 	6.46	 	 	 	5.79	 	 	 	+12	%	
NGLs (Per Bbl)	 	 	33.83	 	 	 	25.99	 	 	 	+30	%	 	 	31.98	 	 	 	25.15	 	 	 	+27	%	
Oil, Gas and NGLs (Per Boe) 1	 	 	42.19	 	 	 	35.66	 	 	 	+18	%	 	 	43.14	 	 	 	34.09	 	 	 	+27	%	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Revenues ($ in millions)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oil	 	$	857	 	 	 	650	 	 	 	+32	%	 	$	1,572	 	 	 	1,265	 	 	 	+24	%	
Gas	 	 	1,170	 	 	 	1,272	 	 	 	-8	%	 	 	2,534	 	 	 	2,447	 	 	 	+4	%	
NGLs	 	 	193	 	 	 	157	 	 	 	+23	%	 	 	369	 	 	 	302	 	 	 	+22	%	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Combined	 	$	2,220	 	 	 	2,079	 	 	 	+7	%	 	$	4,475	 	 	 	4,014	 	 	 	+11	%	

 	 	Domestic	 	
 	 	Three Months Ended June 30,	 	 	Six Months Ended June 30,	 	
 	 	2006	 	 	2005	 	 	Change 2	 	 	2006	 	 	2005	 	 	Change 2	 	
Production	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oil (MMBbls)	 	 	5	 	 	 	7	 	 	 	-27	%	 	 	10	 	 	 	15	 	 	 	-32	%	
Gas (Bcf)	 	 	136	 	 	 	140	 	 	 	-3	%	 	 	266	 	 	 	285	 	 	 	-7	%	
NGLs (MMBbls)	 	 	4	 	 	 	5	 	 	 	-3	%	 	 	10	 	 	 	10	 	 	 	-2	%	
Oil, Gas and NGLs (MMBoe) 1	 	 	32	 	 	 	35	 	 	 	-8	%	 	 	63	 	 	 	72	 	 	 	-11	%	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Average Prices	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oil (Per Bbl)	 	$	66.05	 	 	 	40.18	 	 	 	+64	%	 	$	62.39	 	 	 	38.70	 	 	 	+61	%	
Gas (Per Mcf)	 	 	5.91	 	 	 	6.17	 	 	 	-4	%	 	 	6.47	 	 	 	5.80	 	 	 	+12	%	
NGLs (Per Bbl)	 	 	30.88	 	 	 	23.73	 	 	 	+30	%	 	 	28.86	 	 	 	22.95	 	 	 	+26	%	
Oil, Gas and NGLs (Per Boe) 1	 	 	39.61	 	 	 	35.88	 	 	 	+10	%	 	 	41.14	 	 	 	34.07	 	 	 	+21	%	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Revenues ($ in millions)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oil	 	$	334	 	 	 	278	 	 	 	+20	%	 	$	628	 	 	 	569	 	 	 	+10	%	
Gas	 	 	802	 	 	 	862	 	 	 	-7	%	 	 	1,721	 	 	 	1,651	 	 	 	+4	%	
NGLs	 	 	139	 	 	 	110	 	 	 	+26	%	 	 	263	 	 	 	213	 	 	 	+23	%	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Combined	 	$	1,275	 	 	 	1,250	 	 	 	+2	%	 	$	2,612	 	 	 	2,433	 	 	 	+7	%	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
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 	 	Canada	 	
 	 	Three Months Ended June 30,	 	 	Six Months Ended June 30,	 	
 	 	2006	 	 	2005	 	 	Change 2	 	 	2006	 	 	2005	 	 	Change 2	 	
Production	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oil (MMBbls)	 	 	3	 	 	 	3	 	 	 	-12	%	 	 	6	 	 	 	6	 	 	 	-7	%	
Gas (Bcf)	 	 	63	 	 	 	67	 	 	 	-6	%	 	 	122	 	 	 	133	 	 	 	-8	%	
NGLs (MMBbls)	 	 	1	 	 	 	1	 	 	 	-9	%	 	 	2	 	 	 	2	 	 	 	-5	%	
Oil, Gas and NGLs (MMBoe) 1	 	 	15	 	 	 	16	 	 	 	-8	%	 	 	29	 	 	 	31	 	 	 	-8	%	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Average Prices	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oil (Per Bbl)	 	$	54.52	 	 	 	24.05	 	 	 	+127	%	 	$	46.14	 	 	 	23.98	 	 	 	+92	%	
Gas (Per Mcf)	 	 	5.70	 	 	 	5.98	 	 	 	-5	%	 	 	6.51	 	 	 	5.83	 	 	 	+12	%	
NGLs (Per Bbl)	 	 	44.87	 	 	 	34.28	 	 	 	+31	%	 	 	43.70	 	 	 	33.16	 	 	 	+32	%	
Oil, Gas and NGLs (Per Boe) 1	 	 	39.31	 	 	 	33.20	 	 	 	+18	%	 	 	40.99	 	 	 	32.50	 	 	 	+26	%	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Revenues ($ in millions)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oil	 	$	167	 	 	 	83	 	 	 	+101	%	 	$	289	 	 	 	161	 	 	 	+80	%	
Gas	 	 	358	 	 	 	400	 	 	 	-11	%	 	 	793	 	 	 	775	 	 	 	+2	%	
NGLs	 	 	54	 	 	 	45	 	 	 	+20	%	 	 	106	 	 	 	85	 	 	 	+25	%	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Combined	 	$	579	 	 	 	528	 	 	 	+9	%	 	$	1,188	 	 	 	1,021	 	 	 	+16	%	

 	 	International	 	
 	 	Three Months Ended June 30,	 	 	Six Months Ended June 30,	 	
 	 	2006	 	 	2005	 	 	Change 2	 	 	2006	 	 	2005	 	 	Change 2	 	
Production	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oil (MMBbls)	 	 	6	 	 	 	7	 	 	 	-25	%	 	 	11	 	 	 	14	 	 	 	-24	%	
Gas (Bcf)	 	 	2	 	 	 	2	 	 	 	-8	%	 	 	4	 	 	 	5	 	 	 	-13	%	
NGLs (MMBbls)	 	 	—	 	 	 	—	 	 	 	N/M	 	 	 	—	 	 	 	—	 	 	 	N/M	 	
Oil, Gas and NGLs (MMBoe) 1	 	 	6	 	 	 	8	 	 	 	-25	%	 	 	12	 	 	 	15	 	 	 	-24	%	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Average Prices	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oil (Per Bbl)	 	$	66.72	 	 	 	40.91	 	 	 	+63	%	 	$	62.22	 	 	 	38.59	 	 	 	+61	%	
Gas (Per Mcf)	 	 	4.65	 	 	 	4.08	 	 	 	+14	%	 	 	4.43	 	 	 	3.95	 	 	 	+12	%	
NGLs (Per Bbl)	 	 	—	 	 	 	21.16	 	 	 	N/M	 	 	 	—	 	 	 	24.56	 	 	 	N/M	 	
Oil, Gas and NGLs (Per Boe) 1	 	 	64.17	 	 	 	39.82	 	 	 	+61	%	 	 	59.86	 	 	 	37.58	 	 	 	+59	%	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Revenues ($ in millions)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oil	 	$	356	 	 	 	289	 	 	 	+23	%	 	$	655	 	 	 	535	 	 	 	+22	%	
Gas	 	 	10	 	 	 	10	 	 	 	+5	%	 	 	20	 	 	 	21	 	 	 	-2	%	
NGLs	 	 	—	 	 	 	2	 	 	 	N/M	 	 	 	—	 	 	 	4	 	 	 	N/M	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Combined	 	$	366	 	 	 	301	 	 	 	+22	%	 	$	675	 	 	 	560	 	 	 	+21	%	

			
1	 	Gas volumes are converted to Boe or MMBoe at the rate of six Mcf of gas per barrel of oil, based upon the approximate relative energy content of natural gas and oil, which rate is not necessarily indicative of the relationship of oil and gas prices. NGL volumes are converted to Boe on a one-to-one basis with oil.	
 		
2	 	All percentage changes included in this table are based on actual figures and are not calculated using the rounded figures included in this table.	
N/M Not meaningful.
     The 2005 average sales prices per unit of production shown in the preceding tables include the effect of our hedging activities. All of our commodity hedges expired prior to the beginning of 2006. Included below is a comparison of our average sales prices with and without the effect of hedges for the three-months and six-months ended June 30, 2005.
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 	 	Three Months Ended	 	Six Months Ended	
 	 	June 30, 2005	 	June 30, 2005	
 	 	With	 	Without	 	With	 	Without	
 	 	Hedges	 	Hedges	 	Hedges	 	Hedges	
Oil (per Bbl)	 	$	37.28	 	 	 	46.00	 	 	 	35.86	 	 	 	44.19	 	
Gas (per Mcf)	 	$	6.09	 	 	 	6.18	 	 	 	5.79	 	 	 	5.87	 	
NGLs (per Bbl)	 	$	25.99	 	 	 	25.99	 	 	 	25.15	 	 	 	25.15	 	
Oil, Gas and NGLs (per Boe)	 	$	35.66	 	 	 	38.61	 	 	 	34.09	 	 	 	36.89	 	
Oil Revenues
     Oil revenues increased $207 million in the second quarter of 2006. Oil revenues increased $355 million due to a $26.41 per barrel increase in our realized average price of oil. A three million barrel decrease in production caused oil revenues to decrease by $148 million. Production lost from the 2005 property divestitures accounted for one million barrels of the decrease. We also suspended certain domestic oil production in 2005 and 2006 due to the effects of Hurricanes Katrina, Rita, Dennis and Ivan. Compared to the second quarter of 2005, there were one million additional barrels of suspended production in the second quarter of 2006 due to the hurricanes. The remaining one million barrel decrease in 2006 is primarily due to certain international properties for which we are receiving fewer volumes after recovering our costs under the production sharing contracts. Operating issues also contributed to the decrease.
     Oil revenues increased $307 million in the first half of 2006. Oil revenues increased $609 million due to a $22.67 per barrel increase in our realized average price of oil. An eight million barrel decrease in production caused oil revenues to decrease by $302 million. Production lost from the 2005 property divestitures caused a decrease of three million barrels. Compared to the first half of 2005, there were one million additional barrels of suspended production in the first half of 2006 due to the previously mentioned hurricanes. In addition, production decreased due to certain international properties for which we are receiving fewer volumes after recovering our costs under applicable production sharing contracts. Operating issues also contributed to the decrease.
Gas Revenues
     Gas revenues decreased $102 million in the second quarter of 2006. Gas revenues decreased $52 million due to a $0.26 per Mcf decrease in our realized average price of gas. A decrease in production of eight Bcf caused gas revenues to decrease by $50 million. Production lost from the 2005 property divestitures caused a decrease of eight Bcf. Compared to the second quarter of 2005, there was an additional seven Bcf of suspended production in the second quarter of 2006 due to the previously mentioned hurricanes. This decrease was partially offset by new drilling and development and increased performance in U.S. offshore and onshore properties.
     Gas revenues increased $87 million in the first half of 2006. Gas revenues increased $264 million due to a $0.67 per Mcf increase in our realized average price of gas. A decrease in production of 31 Bcf caused gas revenues to decrease by $177 million. Production lost from the 2005 property divestitures caused a decrease of 33 Bcf. Compared to the first half of 2005, there was an additional 17 Bcf of suspended production in the first half of 2006 due to the previously mentioned hurricanes. These decreases were partially offset by production increases resulting from new drilling and development in U.S. offshore and onshore properties.
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NGL Revenues
     NGL revenues increased $36 million in the second quarter of 2006. A $7.84 per barrel increase in our realized average NGL price in the second quarter of 2006 increased NGL revenues by $45 million. A slight decrease in production caused NGL revenues to decrease by $8 million.
     NGL revenues increased $67 million in the first half of 2006. A $6.83 per barrel increase in our realized average NGL price in the first half of 2006 increased NGL revenues by $79 million. A slight decrease in production caused NGL revenues to decrease by $12 million.
Marketing and Midstream Revenues
     Marketing and midstream revenues increased $8 million, in the second quarter of 2006. Revenues increased $11 million primarily due to higher NGL prices. This increase was partially offset by lower gas sales volumes, which caused revenues to decrease $3 million.
     Marketing and midstream revenues increased $54 million in the first half of 2006. Revenues increased $96 million primarily due to higher NGL and gas prices. This was partially offset by lower gas sales volumes, which caused revenues to decrease $42 million.
Oil, Gas and NGL Production and Operating Expenses
     The components of oil, gas and NGL production and operating expenses are set forth in the following tables.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Three Months Ended June 30,	 	 	Six Months Ended June 30,	 	
 	 	2006	 	 	2005	 	 	Change 1	 	 	2006	 	 	2005	 	 	Change 1	 	
Expenses ($ in millions)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Lease operating expenses	 	$	362	 	 	 	338	 	 	 	+7	%	 	$	711	 	 	 	686	 	 	 	+4	%	
Production taxes	 	 	86	 	 	 	75	 	 	 	+15	%	 	 	169	 	 	 	153	 	 	 	+11	%	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total production and operating expenses	 	$	448	 	 	 	413	 	 	 	+8	%	 	$	880	 	 	 	839	 	 	 	+5	%	

Expenses Per Boe	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Lease operating expenses	 	$	6.87	 	 	 	5.80	 	 	 	+18	%	 	$	6.85	 	 	 	5.83	 	 	 	+17	%	
Production taxes	 	 	1.65	 	 	 	1.29	 	 	 	+28	%	 	 	1.63	 	 	 	1.30	 	 	 	+25	%	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total production and operating expenses	 	$	8.52	 	 	 	7.09	 	 	 	+20	%	 	$	8.48	 	 	 	7.13	 	 	 	+19	%	

			
1	 	All percentage changes included in this table are based on actual figures and are not calculated using the rounded figures included in this table.	
     Lease operating expenses increased $24 million in the second quarter of 2006. The increase in lease operating expense was largely caused by higher commodity prices. With the overall increase in oil, gas and NGL prices, more well workovers and repairs and maintenance costs were performed to either maintain or improve production volumes. Such costs also increased due to inflationary pressure driven by higher commodity prices. Commodity price increases also caused such operating costs as ad valorem taxes, power and fuel costs to rise. Additionally, changes in the Canadian-to-U.S. dollar exchange rate resulted in a $13 million increase in costs. Partially offsetting these increases was a decrease of $20 million in lease operating expenses related to properties that were sold in 2005.
     Lease operating expenses increased $25 million in the first half of 2006. As discussed in the previous paragraph, the increase in lease operating expense for the first half of 2006 was largely caused by higher commodity prices. Additionally, changes in the Canadian-to-U.S. dollar exchange rate resulted
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in a $20 million increase in costs. Partially offsetting these increases was a decrease of $76 million in lease operating expenses related to properties that were sold in 2005.
     The increases described above were also the primary factors causing lease operating expenses per Boe to increase during the second quarter and first half of 2006. Although we divested properties that had higher per-unit operating costs, the cost escalation largely related to higher commodity prices and the weaker U.S. dollar compared to the Canadian dollar had a greater effect on our per unit costs than the property divestitures.
     Production taxes increased $11 million in the second quarter of 2006 and $16 million in the first half of 2006. The majority of our production taxes are assessed on our onshore domestic properties. In the U.S., most of the production taxes are based on a fixed percentage of revenues. Therefore, the 2% and 7% increases in domestic oil, gas and NGL revenues in the second quarter and first half of 2006, respectively, were the primary causes of the production tax increases. The remainder of the increase was primarily due to a new Chinese “Special Petroleum Gain” tax based on higher oil prices. In the second quarter of 2006, we recorded $9 million from this new tax.
Marketing and Midstream Operating Costs and Expenses
     Marketing and midstream operating costs and expenses decreased $8 million in the second quarter of 2006. Expenses decreased $12 million primarily due to lower gas sales volumes. This was partially offset by an $4 million increase in costs and expenses primarily due to higher NGL prices.
     Marketing and midstream operating costs and expenses remained consistent in the first half of 2006. Expenses increased $45 million primarily due to higher NGL and gas purchase prices. This was completely offset by lower gas sales volumes.
Depreciation, Depletion and Amortization Expenses (“DD&A”)
     DD&A of oil and gas properties is calculated as the percentage of total proved reserve volumes produced during the year, multiplied by the net capitalized investment plus future development costs in those reserves (the “depletable base”). Generally, if reserve volumes are revised up or down, then the DD&A rate per unit of production will change inversely. However, if the depletable base changes, then the DD&A rate moves in the same direction. The per unit DD&A rate is not affected by production volumes. Absolute or total DD&A, as opposed to the rate per unit of production, generally moves in the same direction as production volumes. Oil and gas property DD&A is calculated separately on a country-by-country basis.
     Oil and gas property DD&A increased $62 million in the second quarter of 2006. DD&A increased $109 million due to an increase in the combined U.S., Canadian and international DD&A rate from $8.48 per Boe in the second quarter of 2005 to $10.56 per Boe in the second quarter of 2006. This increase was partially offset by a 10% decrease in the combined oil, gas and NGL production in the second quarter of 2006 which caused oil and gas property DD&A to decrease by $47 million. The primary factors contributing to the DD&A rate increase were changes in the Canadian-to-U.S. dollar exchange rate and inflationary pressure on both the costs incurred in the prior twelve months as well as the estimated development costs to be spent in future periods on proved undeveloped reserves. In addition, the DD&A rate also increased as a result of unproved costs which, in the second quarter of 2005, were not being amortized but were subsequently transferred to the depletable base as a result of drilling activities.
     Oil and gas property DD&A increased $28 million in the first half of 2006. DD&A increased $151 million due to an increase in the combined U.S., Canadian and international DD&A rate from $8.79 per Boe in the first half of 2005 to $10.25 per Boe in the first half of 2006. This increase was partially
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offset by a 12% decrease in the combined oil, gas and NGL production in the first half of 2006 which caused oil and gas property DD&A to decrease by $123 million. The primary factors contributing to the DD&A rate increase were changes in the Canadian-to-U.S. dollar exchange rate and inflationary pressure on both the costs incurred in the prior twelve months as well as the estimated development costs to be spent in future periods on proved undeveloped reserves. In addition, the DD&A rate also increased as a result of unproved costs which, in the first half of 2005, were not being amortized but were subsequently transferred to the depletable base as a result of drilling activities.
General and Administrative Expenses (“G&A”)
     Devon’s net G&A consists of three primary components. The largest of these components is the gross amount of expenses incurred for personnel costs, office expenses, professional fees and other G&A items. The gross amount of these expenses is partially reduced by two components. One is the amount of G&A capitalized pursuant to the full cost method of accounting related to exploration and development activities. The other is the amount of G&A reimbursed by working interest owners of properties for which Devon serves as the operator. These reimbursements are received during both the drilling and operational stages of a property’s life. The gross amount of G&A incurred, less the amounts capitalized and reimbursed, is recorded as net G&A in the consolidated statements of operations. Net G&A includes expenses related to oil, gas and NGL exploration and production activities, as well as marketing and midstream activities. See the following table for a summary of G&A expenses by component.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Three Months	 	 	Six Months	 	
 	 	Ended June 30,	 	 	Ended June 30,	 	
 	 	2006	 	 	2005	 	 	2006	 	 	2005	 	
 	 	 	 	 	 	(In millions)	 	 	 	 	 	
Gross G&A	 	$	175	 	 	 	148	 	 	 	348	 	 	 	280	 	
Capitalized G&A	 	 	(62	)	 	 	(45	)	 	 	(119	)	 	 	(92	)	
Reimbursed G&A	 	 	(23	)	 	 	(25	)	 	 	(49	)	 	 	(52	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Net G&A	 	$	90	 	 	 	78	 	 	 	180	 	 	 	136	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
     Gross G&A increased $27 million in the second quarter of 2006 compared to the same period of 2005. Higher employee compensation and benefits costs caused gross G&A to increase $21 million. Of this increase, $7 million represented stock option expense recognized pursuant to our adoption of Statement of Financial Accounting Standard No. 123(R), Share Based Payment, in the first quarter of 2006, and $3 million represented an increase in restricted stock expense due to our grants subsequent to the second quarter of 2005. In addition, changes in the Canadian-to-U.S. dollar exchange rate caused a $4 million increase in costs.
     Gross G&A increased $68 million from the first half of 2006 compared to the same period of 2005. Higher employee compensation and benefits costs caused gross G&A to increase $47 million. Of this increase, $15 million represented stock option expense recognized pursuant to our adoption of Statement of Financial Accounting Standard No. 123(R), Share Based Payment, in the first quarter of 2006, and $8 million represented an increase in restricted stock expense due to our grants subsequent to the second quarter of 2005. In addition, changes in the Canadian-to-U.S. dollar exchange rate caused a $7 million increase in costs.
     Capitalized G&A increased $17 million and $27 million in the second quarter and first half of 2006, respectively, primarily due to increases in capitalizable salaries and benefits.
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Interest Expense
     The following schedule includes the components of interest expense for the second quarter and first half of 2006 and 2005.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Three Months	 	 	Six Months	 	
 	 	Ended June 30,	 	 	Ended June 30,	 	
 	 	2006	 	 	2005	 	 	2006	 	 	2005	 	
 	 	 	 	 	 	(In millions)	 	 	 	 	 	
Interest based on debt outstanding	 	$	118	 	 	 	133	 	 	 	233	 	 	 	265	 	
Amortization of discounts/premiums	 	 	2	 	 	 	—	 	 	 	4	 	 	 	1	 	
Facility and agency fees	 	 	1	 	 	 	1	 	 	 	1	 	 	 	1	 	
Amortization of capitalized loan costs	 	 	—	 	 	 	5	 	 	 	1	 	 	 	6	 	
Capitalized interest	 	 	(20	)	 	 	(18	)	 	 	(36	)	 	 	(37	)	
Loss on extinguishment of debt	 	 	—	 	 	 	25	 	 	 	—	 	 	 	25	 	
Other	 	 	1	 	 	 	—	 	 	 	—	 	 	 	3	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total interest expense	 	$	102	 	 	 	146	 	 	 	203	 	 	 	264	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
     The average debt balance decreased from $7.8 billion in the second quarter of 2005 to $6.7 billion in the second quarter of 2006 due to debt repayments during 2005. This decrease in debt outstanding caused interest expense to decrease $20 million. This decrease in interest expense was partially offset by $5 million of additional interest due to higher floating rates in 2006. The average interest rate on outstanding debt increased from 6.8% in the second quarter of 2005 to 7.0% in the second quarter of 2006.
     The average debt balance decreased from $7.9 billion in the first half of 2005 to $6.7 billion in the first half of 2006 due to debt repayments during 2005. This decrease in debt outstanding caused interest expense to decrease $43 million. This decrease in interest expense was partially offset by $11 million of additional interest due to higher floating rates in 2006. The average interest rate on outstanding debt increased from 6.8% in the first half of 2005 to 7.0% in the first half of 2006.
     Other items included in interest expense that are not related to the debt balance outstanding were $29 million lower in the second quarter and the first half of 2006. Of this decrease, $25 million related to the loss on the early redemption of the zero coupon convertible senior debentures during the second quarter of 2005. In conjunction with this early redemption, Devon also expensed $5 million in remaining unamortized issuance costs during the second quarter of 2005.
Changes in Fair Value of Derivative Financial Instruments
     The following schedule includes the components of the change in fair value of derivative financial instruments for the second quarter and first half of 2006 and 2005.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Three Months	 	 	Six Months	 	
 	 	Ended June 30,	 	 	Ended June 30,	 	
 	 	2006	 	 	2005	 	 	2006	 	 	2005	 	
 	 	 	 	 	 	(In millions)	 	 	 	 	 	
Change in fair value of the option embedded in debentures exchangeable into shares of Chevron Corporation common stock	 	$	47	 	 	 	(22	)	 	 	61	 	 	 	29	 	
Ineffectiveness of commodity hedges	 	 	—	 	 	 	3	 	 	 	—	 	 	 	6	 	
Other	 	 	—	 	 	 	1	 	 	 	(2	)	 	 	(1	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	$	47	 	 	 	(18	)	 	 	59	 	 	 	34	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
     The fair value of the option embedded in debentures exchangeable into shares of Chevron Corporation common stock is driven primarily by the price of Chevron Corporation’s common stock. As
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a result, increases or decreases in the price of such common stock generally will cause the fair value of this embedded option to increase or decrease in a like manner.
Reduction of Carrying Value of Oil and Gas Properties
     During the second quarter of 2006, we drilled two unsuccessful exploratory wells in Brazil and determined that the capitalized costs related to these two wells should be impaired. Therefore, in the second quarter of 2006, we recognized a $16 million impairment of our investment in Brazil equal to the costs to drill the two dry holes and a proportionate share of block-related costs. There is no tax benefit related to this impairment. The two wells were unrelated to our Polvo development project in Brazil.
     We have committed to drill four wells in Nigeria. The first two wells were unsuccessful. After drilling the second unsuccessful well in the first quarter of 2006, we determined that the capitalized costs related to these two wells should be impaired. Therefore, in the first quarter of 2006, we recognized an $85 million impairment of our investment in Nigeria equal to the costs to drill the two dry holes and a proportionate share of block-related costs. There is no tax benefit related to this impairment.
Other Income, net
     The following schedule includes the components of other income for the three and six months periods ended June 30.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Three Months	 	 	Six Months	 	
 	 	Ended June 30,	 	 	Ended June 30,	 	
 	 	2006	 	 	2005	 	 	2006	 	 	2005	 	
 	 	 	 	 	 	(In millions)	 	 	 	 	 	
Interest and dividend income	 	$	28	 	 	 	25	 	 	 	56	 	 	 	51	 	
Net gain on sales of non-oil and gas property and equipment	 	 	1	 	 	 	—	 	 	 	5	 	 	 	150	 	
Loss on derivative financial instruments	 	 	—	 	 	 	(16	)	 	 	—	 	 	 	(55	)	
Other	 	 	1	 	 	 	5	 	 	 	(3	)	 	 	6	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Other income, net	 	$	30	 	 	 	14	 	 	 	58	 	 	 	152	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
     The increases in interest and dividend income in the second quarter and first half of 2006 were primarily due to an increase in interest rates on cash and short-term investment balances.
     The increase in the net gain on sales of non-oil and gas property and equipment in the first half of 2005 is related to the sale of certain midstream assets in January 2005.
     The losses on derivative financial instruments in the second quarter and first half of 2005 related to hedges that no longer qualified for hedge accounting and were settled prior to the end of their original term. These commodity hedges related to 5,000 barrels per day of U.S. oil production and 3,000 barrels per day of Canadian oil production from properties sold as part of our property divestiture program.
Income Taxes
     During interim periods, income tax expense is based on the estimated effective income tax rate that is expected for the entire fiscal year. The estimated effective tax rate was 18% in the second quarter of 2006 and 35% in the second quarter of 2005. The estimated effective tax rate was 28% in the first half of 2006 and 37% in the first half of 2005.
     The rates for the second quarter and first half of 2006 were lower than the statutory federal tax rate primarily due to the effects of tax law changes. During the second quarter of 2006, the Canadian Federal and Alberta provincial governments enacted statutory rate reductions. As a result, we recorded a
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$243 million deferred tax benefit in such quarter. Also during the second quarter of 2006, the state of Texas enacted a new income-based tax that replaces a previous franchise tax. The new tax is effective January 1, 2007. As a result of the enactment of the tax in the second quarter of 2006, we recorded $39 million of deferred tax expense in such quarter. Excluding the effects of these statutory tax rate changes and the effects of the oil and gas property impairments with no related tax benefits which were previously discussed, the effective rates were 36% for both the second quarter and first half of 2006.
Capital Resources, Uses and Liquidity
     The following discussion of liquidity and capital resources should be read in conjunction with the consolidated statements of cash flows included in Part 1, Item 1.
Sources and Uses of Cash
 	 	 	 	 	 	 	 	 	
 	 	Six Months Ended June 30,	 	
 	 	2006	 	 	2005	 	
 	 	(In millions)	 	
Cash provided by (used in):	 	 	 	 	 	 	 	 	
Operating activities	 	$	2,818	 	 	 	2,385	 	
Investing activities	 	 	(4,341	)	 	 	603	 	
Financing activities	 	 	921	 	 	 	(1,910	)	
Effect of exchange rate changes	 	 	26	 	 	 	(3	)	
 	 	 	 	 	 	 	
Net (decrease) increase in cash and cash equivalents	 	$	(576	)	 	 	1,075	 	
 	 	 	 	 	 	 	
Cash and cash equivalents at end of period	 	$	1,030	 	 	 	2,227	 	
 	 	 	 	 	 	 	
Short-term investments at end of period	 	$	332	 	 	 	549	 	
 	 	 	 	 	 	 	
Cash Flows from Operating Activities
     Net cash provided by operating activities (“operating cash flow”) continued to be a primary source of capital and liquidity in the first half of 2006. The increase in operating cash flow in the first half of 2006 was primarily caused by the increase in net earnings as discussed in the “Results of Operations” section of this report.
Cash Flows from Investing Activities
      Capital Expenditures. Cash used for capital expenditures in the first half of 2006 was $4.7 billion. This total includes $4.5 billion for the acquisition, drilling or development of oil and gas properties, including $2.0 billion related to the acquisition of the Chief properties. These amounts compare to cash used for capital expenditures of $2.0 billion in the first half of 2005 which included $1.9 billion for the acquisition, drilling or development of oil and gas properties.
      Proceeds from the Sale of Property and Equipment. We generated sale proceeds of $26 million and $2.2 billion in the first half of 2006 and 2005, respectively. The decrease in proceeds in 2006 was largely due to our 2005 divesture program in which we sold non-core oil and gas properties as well as non-core midstream assets.
Cash Flows from Financing Activities
      Debt Borrowings. During the second quarter of 2006, we issued $1.4 billion of commercial paper to partially fund the Chief acquisition.
      Debt Repayments. During the first half of 2006, we paid $180 million to retire the debt assumed through the Chief acquisition and made other payments totaling $28 million. During the first half of
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2005, we paid $452 million to redeem the zero coupon convertible debentures.
      Stock Repurchases. During the first half of 2006, we repurchased 4.2 million shares at a cost of $253 million. This compares to the repurchase of 34.2 million shares for $1.6 billion in the first half of 2005.
      Issuance of Common Stock. We received proceeds of $27 million and $81 million from shares issued primarily from the exercise of employee stock options in the first half of 2006 and 2005, respectively.
      Dividends. Devon’s common stock dividends were $99 million and $70 million in the first half of 2006 and 2005, respectively. We also paid $5 million of preferred stock dividends in 2006 and 2005. The increase in common stock dividends from 2005 to 2006 was primarily related to a 50% increase in the quarterly dividend rate which was partially offset by a decrease in the number of shares outstanding. Effective with the first quarter 2006 dividend payment, Devon increased its quarterly dividend rate from $0.075 per share to $0.1125 per share. The decrease in shares outstanding was primarily related to share repurchases partially offset by shares issued for stock option exercises.
Liquidity
     At June 30, 2006, our unrestricted cash and cash equivalents and short-term investments totaled $1.4 billion. During the first half of 2006 and 2005, such balances decreased $924 million and increased $657 million, respectively. The decrease in 2006 was primarily driven by the use of cash on hand to partially fund the Chief acquisition.
     Historically, our primary source of capital and liquidity has been operating cash flow. Additionally, we maintain a revolving line of credit and a commercial paper program which can be accessed as needed to supplement operating cash flow. Other available sources of capital and liquidity include the issuance of equity securities and long-term debt. We expect the combination of these sources of capital will be more than adequate to fund future capital expenditures and other contractual commitments.
Operating Cash Flow
     Our operating cash flow is sensitive to many variables, the most volatile of which is pricing of the oil, natural gas and NGLs produced. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict. We expect operating cash flow to continue to be our primary source of liquidity.
Credit Lines
     Another source of liquidity is our $2.5 billion five-year, syndicated, unsecured revolving line of credit (the “Senior Credit Facility”). The Senior Credit Facility also includes the right to increase the aggregate commitment further to $3.0 billion should we deem any additional increase necessary.
     The Senior Credit Facility includes a five-year revolving Canadian subfacility in a maximum amount of U.S. $500 million.
     The Senior Credit Facility matures on April 7, 2011, and all amounts outstanding will be due and payable at that time unless the maturity is extended. Prior to each April 7 anniversary date, we have the option to extend the maturity of the Senior Credit Facility for one year, subject to the approval of the lenders.
     Amounts borrowed under the Senior Credit Facility may, at our election, bear interest at various
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fixed rate options for periods of up to twelve months. Such rates are generally less than the prime rate. We may also elect to borrow at the prime rate. The Senior Credit Facility currently provides for an annual facility fee of $2.3 million that is payable quarterly in arrears.
     As of June 30, 2006, there were no borrowings under the Senior Credit Facility. The available capacity under the Senior Credit Facility as of June 30, 2006, net of $287 million of outstanding letters of credit and $1.4 billion of outstanding commercial paper, was approximately $788 million.
     The Senior Credit Facility contains only one material financial covenant. This covenant requires Devon to maintain a ratio of total funded debt to total capitalization of no more than 65%. The credit agreement contains definitions of total funded debt and total capitalization that include adjustments to the respective amounts reported in Devon’s consolidated financial statements. Per the agreement, total funded debt excludes the debentures that are exchangeable into shares of Chevron Corporation common stock. Also, total capitalization is adjusted to add back noncash financial writedowns such as full cost ceiling property impairments or goodwill impairments. As of June 30, 2006, Devon’s ratio as calculated pursuant to this covenant was 29.3%.
     Our access to funds from the Senior Credit Facility is not restricted under any “material adverse effect” clauses. It is not uncommon for credit agreements to include such clauses. These clauses can remove the obligation of the banks to fund the credit line if any condition or event would reasonably be expected to have a material and adverse effect on the borrower’s financial condition, operations, properties or business considered as a whole, the borrower’s ability to make timely debt payments, or the enforceability of material terms of the credit agreement. While our Senior Credit Facility includes covenants that require Devon to report a condition or event having a material adverse effect on Devon, the obligation of the banks to fund the Senior Credit Facility is not conditioned on the absence of a material adverse effect.
     We also have access to short-term credit under our commercial paper program. Total borrowings under the commercial paper program may not exceed $2.0 billion. Also, any borrowings under the commercial paper program reduce available capacity under the Senior Credit Facility on a dollar-for-dollar basis. Commercial paper debt generally has a maturity of between seven to 90 days, although it can have a maturity of up to 365 days.
     We used approximately $1.4 billion of borrowings under our commercial paper program to fund a portion of the Chief acquisition which closed on June 29, 2006.
Common Stock Repurchase Program
     On August 3, 2005, we announced that our board of directors had authorized the repurchase of up to 50 million shares of our common stock. As of August 3, 2006, we had repurchased 6.5 million shares under this program for $387 million, or $59.80 per share. As a result of the Chief acquisition, this repurchase program has been suspended and will be reevaluated at a later date.
Impact of Recently Issued Accounting Standards Not Yet Adopted
     In June 2006, the FASB issued FASB Interpretation Number 48, “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109.” This Interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes.” This Interpretation is effective for fiscal years beginning after December 15, 2006. We are currently assessing the effect of this Interpretation on our financial statements.
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Item 3.	 	Quantitative and Qualitative Disclosures About Market Risk	
     There have been no material changes to the information included in Item 7A. “Quantitative and Qualitative Disclosures About Market Risk” in our 2005 Annual Report on Form 10-K.

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.
     Based on their evaluation, Devon’s principal executive and principal financial officers have concluded that Devon’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) were effective as of June 30, 2006 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 was no change in Devon’s internal control over financial reporting during the second quarter of 2006 that has materially affected, or is reasonably likely to materially affect, Devon’s 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 2005 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 2005 Annual Report on Form 10-K.

Item 2.	 	Unregistered Sales of Equity Securities, Use of Proceeds and Issuer Purchases of Equity Securities	
     The following table sets forth information with respect to repurchases by Devon of its shares of common stock during the second quarter of 2006.
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	Total Number of	 	Maximum Number of	
 	 	Total Number	 	Average Price	 	Shares Purchased as	 	Shares that May Yet	
 	 	of Shares	 	Paid per	 	Part of Publicly Announced	 	Be Purchased Under	
Period	 	Purchased	 	Share	 	Plans or Programs (1)	 	the Plans or Programs (1)	
April	 	 	—	 	 	$  	—	 	 	 	—	 	 	 	43,533,001	 	
May	 	 	—	 	 	$  	—	 	 	 	—	 	 	 	43,533,001	 	
June	 	 	—	 	 	$  	—	 	 	 	—	 	 	 	43,533,001	 	
Total	 	 	—	 	 	$  	—	 	 	 	—	 	 	 	 	 	

(1)	 	On August 3, 2005, Devon announced that its board of directors had authorized the repurchase of up to 50 million shares of its common stock. This stock repurchase program has been suspended and will be reevaluated at a later date.	

Item 3.	 	Defaults Upon Senior Securities	
     None

Item 4.	 	Submission of Matters to a Vote of Security Holders	
     (a) Devon’s Annual Meeting of Stockholders was held in Oklahoma City, Oklahoma at 8:00 a.m., local time, on Wednesday, June 7, 2006.
     (b) Proxies for the meeting were solicited pursuant to Regulation 14 under the Securities Exchange Act of 1934, as amended. There was no solicitation in opposition to the nominees for election as Directors as listed in the Proxy Statement for the June 7, 2006 meeting and all nominees were elected.
     (c) A total of 393,344,998 shares of Devon’s common stock outstanding and entitled to vote were present at the June 7, 2006 meeting in person or by proxy, representing approximately 89.4% of the total outstanding shares. The matters voted upon were as follows:
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     1. The election of four Directors to serve on Devon’s Board of Directors until the 2009 Annual Meeting of Stockholders. The vote tabulation with respect to each nominee was as follows:
 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Authority	
Nominee	 	For	 	Withheld	
Robert L. Howard	 	 	385,490,893	 	 	 	7,854,105	 	
Michael M. Kanovsky	 	 	383,338,367	 	 	 	9,548,649	 	
J. Todd Mitchell	 	 	384,982,808	 	 	 	7,904,208	 	
J. Larry Nichols	 	 	380,789,729	 	 	 	12,097,287	 	
     2. Ratification of KPMG LLP as the Company’s Independent Auditors for 2006. The results of the votes were as follows:
 	 	 	 	 	
FOR:	 	 	381,271,601	 	
AGAINST:	 	 	9,729,001	 	
ABSTAIN:	 	 	2,182,554	 	
     3. Adoption of the Amendment to the Devon Energy Corporation 2005 Long-Term Incentive Plan. The results of the vote were as follows:
 	 	 	 	 	
FOR:	 	 	327,647,941	 	
AGAINST:	 	 	17,891,573	 	
ABSTAIN:	 	 	2,644,853	 	
BROKER NON-VOTES:	 	 	45,160,631	 	

Item 5.	 	Other Information	
     None
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Item 6.	 	Exhibits	
     (a)  Exhibits required by Item 601 of Regulation S-K are as follows:
 	 	 	 	 	
Exhibit	 	 	
Number	 	Description	
 	4.4	 	 	Amendment to Rights Agreement, dated as of August 1, 2006, by and between Registrant and UMB Bank, n.a.	
 	 	 	 	 	
 	31.1	 	 	Certification of J. Larry Nichols, Chief Executive Officer of Registrant, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.	
 	 	 	 	 	
 	31.2	 	 	Certification of Brian J. Jennings, Chief Financial Officer of Registrant, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.	
 	 	 	 	 	
 	32.1	 	 	Certification of J. Larry Nichols, Chief Executive Officer of Registrant, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.	
 	 	 	 	 	
 	32.2	 	 	Certification of Brian J. Jennings, Chief Financial Officer of Registrant, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.	
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 3, 2006	 	/s/ Danny J. Heatly
 
Danny J. Heatly	 	 	
 	 	Vice President – Accounting and Chief Accounting Officer	 	 	
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INDEX TO EXHIBITS
 	 	 	 	 	
Exhibit	 	 	
Number	 	Description	
 	4.4	 	 	Amendment to Rights Agreement, dated as of August 1, 2006, by and between Registrant and UMB Bank, n.a.	
 	 	 	 	 	
 	31.1	 	 	Certification of J. Larry Nichols, Chief Executive Officer of Registrant, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.	
 	 	 	 	 	
 	31.2	 	 	Certification of Brian J. Jennings, Chief Financial Officer of Registrant, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.	
 	 	 	 	 	
 	32.1	 	 	Certification of J. Larry Nichols, Chief Executive Officer of Registrant, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.	
 	 	 	 	 	
 	32.2	 	 	Certification of Brian J. Jennings, Chief Financial Officer of Registrant, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.	
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Exhibit 4.4
AMENDMENT TO RIGHTS AGREEMENT
     This AMENDMENT, dated as of August 1, 2006, to the Rights Agreement (as defined below) is by and between Devon Energy Corporation (the “Company”) and UMB Bank, n.a. (“UMB”), as successor Rights Agent.
     WHEREAS, the Company entered into a Rights Agreement, dated as of August 17, 1999, as amended May 25, 2000, October 4, 2001 and September 13, 2002 (as heretofore amended, the “Rights Agreement”), with Fleet National Bank (f/k/a BankBoston, N.A.) as the initial rights agent;
     WHEREAS, by the amendment to the Rights Agreement dated September 13, 2002, Wachovia Bank, N.A., was appointed rights agent and was serving immediately prior to this Amendment (the “Predecessor Agent”)
     WHEREAS, the Company has given the Predecessor Agent proper notice of removal as rights agent under Section 21 of the Rights Agreement and desires to appoint UMB as the successor rights agent under the Rights Agreement; and
     WHEREAS, pursuant to Section 27 of the Rights Agreement, the Company may from time to time supplement or amend the Rights Agreement in accordance with the provisions of Section 27 thereof;
     NOW, THEREFORE, the Company and UMB hereby agree as follows, and the Rights Agreement is hereby amended as follows:
     1. The Company appoints UMB, and UMB accepts such appointment, as successor rights agent under the Rights Agreement, to serve in that capacity for the consideration and subject to all of the terms and conditions of the Rights Agreement.
     2. UMB represents that it is, or is an affiliate of, a corporation or trust company organized and doing business under the laws of the United States, in good standing, which is authorized under such laws to exercise corporate trust or stock transfer powers and is subject to supervision or examination by federal or state authority and has, as of the date hereof, a combined capital and surplus of at least $100,000,000.
     3. From and after the date hereof, all references in the Rights Agreement (including the exhibits thereto) to the Predecessor Agent or to the “Rights Agent” shall be deemed to be references to UMB.
     4. The notice address of the Rights Agent set forth in Section 26 of the Rights Agreement is deleted in its entirety and replaced with the following:
UMB Bank, n.a.
2401 Grand Blvd., Suite 200
Kansas City, Missouri 64108
Attention: Corporate Trust

 

     IN WITNESS WHEREOF, this Amendment has been duly executed by the Company and the Rights Agent as of the day and year first above written.
 	 	 	 	 	
 	DEVON ENERGY CORPORATION
 	 	
 	By:  	/s/ Marian J. Moon  	 	
 	Name:  	Marian J. Moon 		
 	Title:  	Senior Vice President 		
 	
 	UMB BANK, n.a.
(as Rights Agent)
 	 	
 	By:  	/s/ Mark B. Flannagan  	 	
 	Name:  	Mark B. Flannagan 		
 	Title:  	Vice President 		
 	
     I, Janice A. Dobbs, Secretary of Devon Energy Corporation, hereby certify that Marian J. Moon is a Senior Vice President of Devon Energy Corporation and the signature appearing above is her genuine signature.

Dated: August 1, 2006 	/s/ Janice A. Dobbs  	 	
 	Janice A. Dobbs 	 	
 	Secretary 	 	

  

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, J. Larry Nichols, 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 2, 2006
 	 	 	 	 	
 	 	/s/ J. Larry Nichols	 	 	
 	 	 
J. Larry Nichols	 	 	
 	 	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, Brian J. Jennings, 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 2, 2006
 	 	 	 	 	
 	 	/s/ Brian J. Jennings	 	 	
 	 	 
Brian J. Jennings	 	 	
 	 	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, 2006 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, J. Larry Nichols, 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/ J. Larry Nichols	 	 	
 
J. Larry Nichols	 	 	
Chief Executive Officer	 	 	
August 2, 2006	 	 	

 

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, 2006 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Brian J. Jennings, 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/ Brian J. Jennings	 	 	
 
Brian J. Jennings	 	 	
Chief Financial Officer	 	 	
August 2, 2006