e10vq

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


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.

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.

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.

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.

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.

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.

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

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.

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.

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.

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%.

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.

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

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.

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

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

DEVON ENERGY CORPORATION AND SUBSIDIARIES
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.

DEVON ENERGY CORPORATION AND SUBSIDIARIES
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

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

DEVON ENERGY CORPORATION AND SUBSIDIARIES
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

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

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

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.

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	%


	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.


	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.

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

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

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.

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

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

$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

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

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.

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.


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.

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:

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


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

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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		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