Devon Energy - 10-Q quarterly report FY

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, 2005

or


o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File No. 000-32318

Devon Energy Corporation

(Exact Name of Registrant as Specified in its Charter)


Delaware (State or Other Jurisdiction of Incorporation or Organization)		73-1567067 (I.R.S. Employer Identification Number)


20 North Broadway Oklahoma City, Oklahoma (Address of Principal Executive Offices)		73102-8260 (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 an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes þ No o

The number of shares outstanding of Registrant’s common stock, par value $0.10, as of June 30, 2005, was 453,218,000.

[This page intentionally left blank.]

2

DEVON ENERGY CORPORATION

Index to Form 10-Q Quarterly Report
to the Securities and Exchange Commission


	Page
	No.
Part I. Financial Information

Item 1. Consolidated Financial Statements

Consolidated Balance Sheets as of June 30, 2005 (Unaudited) and December 31, 2004		6

Consolidated Statements of Operations (Unaudited) for the Three Months and Six Months Ended June 30, 2005 and 2004		7

Consolidated Statements of Stockholders’ Equity and Comprehensive Income (Unaudited) for the Six Months Ended June 30, 2005 and 2004		8

Consolidated Statements of Cash Flows (Unaudited) for the Six Months Ended June 30, 2005 and 2004		9

Notes to Consolidated Financial Statements (Unaudited)		10

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		24

Item 3. Quantitative and Qualitative Disclosures About Market Risk		37

Item 4. Controls and Procedures		40

Part II. Other Information

Item 2. Unregistered Sales of Equity Securities, Use of Proceeds and Issuer Purchases of Equity Securities		41

Item 4. Submission of Matters to a Vote of Security Holders		41

Item 6. Exhibits		43
Form of Award Agreement
Form of Award Agreement
Form of Award 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

3

DEFINITIONS

As used in this document:

“AECO” means the price of gas delivered onto the NOVA Gas Transmission Ltd. System.

“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.

“Brent” means pricing point for selling North Sea crude oil.

“Btu” means British Thermal units, a measure of heating value.

“Inside FERC” refers to the publication Inside F.E.R.C.’s Gas Market Report.

“LIBOR” means London Interbank Offered Rate.

“MBbls” means thousand barrels.

“MMBbls” means million barrels.

“MBoe” means thousand Boe.

“MMBoe” means million Boe.

“MMBtu” means million Btu.

“Mcf” means thousand cubic feet.

“MMcf” means million cubic feet.

“NGL” or “NGLs” means natural gas liquids.

“NYMEX” means New York Mercantile Exchange.

“Oil” includes crude oil and condensate.

“Domestic” means the properties of Devon in the onshore continental United States and the offshore 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.

4

DEVON ENERGY CORPORATION

PART I. FINANCIAL INFORMATION

ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2005 and 2004

(Forming a part of Form 10-Q Quarterly Report
to the Securities and Exchange Commission)

5

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


	June 30,			December 31,
	2005			2004
	(Unaudited)
	(In millions, except share data)
ASSETS
Current assets:
Cash and cash equivalents	$	2,227		$	1,152
Short-term investments		549			967
Accounts receivable		1,308			1,320
Fair value of derivative financial instruments		—			1
Deferred income taxes		248			289
Other current assets		149			143

Total current assets		4,481			3,872

Property and equipment, at cost, based on the full cost method of accounting for oil and gas properties ($2,982 and $3,187 excluded from amortization in 2005 and 2004, respectively)		31,819			32,114
Less accumulated depreciation, depletion and amortization		13,793			12,768

		18,026			19,346
Investment in Chevron Corporation common stock, at fair value		793			745
Fair value of derivative financial instruments		—			8
Goodwill		5,592			5,637
Other assets		378			417

Total assets	$	29,270		$	30,025

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable:
Trade	$	900		$	715
Revenues and royalties due to others		470			487
Income taxes payable		148			223
Current portion of long-term debt		906			933
Accrued interest payable		144			139
Fair value of derivative financial instruments		376			399
Current portion of asset retirement obligation		49			46
Accrued expenses and other current liabilities		192			158

Total current liabilities		3,185			3,100

Debentures exchangeable into shares of Chevron Corporation common stock		700			692
Other long-term debt		5,917			6,339
Fair value of derivative financial instruments		101			72
Asset retirement obligation, long-term		667			693
Other liabilities		377			366
Deferred income taxes		5,024			5,089
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 453,218,000 in 2005 and 483,909,000 in 2004		45			48
Additional paid-in capital		7,609			9,087
Retained earnings		4,834			3,693
Accumulated other comprehensive income		882			930
Deferred compensation and other		(72	)		(85	)

Total stockholders’ equity		13,299			13,674

Total liabilities and stockholders’ equity	$	29,270		$	30,025

See accompanying notes to consolidated financial statements.

6

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
				(Unaudited)
	(In millions, except per share amounts)
Revenues:
Oil sales	$	650		$	539		$	1,265		$	1,120
Gas sales		1,272			1,181			2,447			2,302
NGL sales		157			122			302			241
Marketing and midstream revenues		389			377			805			794

Total revenues		2,468			2,219			4,819			4,457

Expenses and other income, net:
Lease operating expenses		338			306			686			616
Production taxes		75			71			153			133
Marketing and midstream operating costs and expenses		296			299			627			630
Depreciation, depletion and amortization of oil and gas properties		494			517			1,035			1,055
Depreciation and amortization of non-oil and gas properties		41			35			79			69
Accretion of asset retirement obligation		11			10			23			22
General and administrative expenses		78			70			136			147
Interest expense		146			134			264			252
Effects of changes in foreign currency exchange rates		11			9			11			15
Change in fair value of derivative financial instruments		(18	)		11			34			7
Other income, net		(14	)		(15	)		(152	)		(37	)

Total expenses and other income, net		1,458			1,447			2,896			2,909
Earnings before income tax expense		1,010			772			1,923			1,548
Income tax expense:
Current		277			198			629			401
Deferred		80			72			78			151

Total income tax expense		357			270			707			552

Net earnings		653			502			1,216			996
Preferred stock dividends		3			3			5			5

Net earnings applicable to common stockholders	$	650		$	499		$	1,211		$	991


Net earnings per average common share outstanding:
Basic	$	1.40		$	1.04		$	2.57		$	2.06


Diluted	$	1.38		$	1.01		$	2.53		$	2.01


Weighted average common shares outstanding — basic		464			482			472			480

Weighted average common shares outstanding — diluted		471			498			479			495

See accompanying notes to consolidated financial statements.

7

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND
COMPREHENSIVE INCOME

(Unaudited)


												Accumulated
						Additional						Other			Deferred						Total
	Preferred		Common			Paid-In			Retained			Comprehensive			Compensation			Treasury			Stockholders’
	Stock		Stock			Capital			Earnings			Income			and Other			Stock			Equity
									(In millions)
Six Months Ended June 30, 2005
Balance as of December 31, 2004	$	1		48			9,087			3,693			930			(85	)		—			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	)
Amortization of restricted stock awards		—		—			—			—			—			13			—			13

Balance as of June 30, 2005	$	1		45			7,609			4,834			882			(72	)		—			13,299


Six Months Ended June 30, 2004
Balance as of December 31, 2003	$	1		47			9,043			1,614			569			(32	)		(186	)		11,056
Comprehensive income:
Net earnings		—		—			—			996			—			—			—			996
Other comprehensive income (loss), net of tax:
Foreign currency translation adjustments		—		—			—			—			(157	)		—			—			(157	)
Reclassification adjustment for derivative losses reclassified into oil and gas sales		—		—			—			—			111			—			—			111
Change in fair value of derivative financial instruments		—		—			—			—			(274	)		—			—			(274	)
Unrealized gain on marketable securities		—		—			—			—			34			—			—			34

Other comprehensive loss																						(286	)

Comprehensive income																						710
Stock issued		—		2			186			—			—			—			56			244
Dividends on common stock		—		—			—			(48	)		—			—			—			(48	)
Dividends on preferred stock		—		—			—			(5	)		—			—			—			(5	)
Amortization of restricted stock awards		—		—			—			—			—			6			—			6

Balance as of June 30, 2004	$	1		49			9,229			2,557			283			(26	)		(130	)		11,963

See accompanying notes to consolidated financial statements.

8

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Six Months Ended June 30,
	2005			2004
	(Unaudited)
	(In millions)
Cash flows from operating activities:
Net earnings	$	1,216		$	996
Adjustments to reconcile net earnings to net cash provided by operating activities:
Depreciation, depletion and amortization		1,114			1,124
Accretion of asset retirement obligation		23			22
Amortization of premiums on long-term debt, net		(2	)		(3	)
Effects of changes in foreign currency exchange rates		11			15
Change in fair value of derivative financial instruments		34			7
Deferred income tax expense		78			151
Net gain on sales of non-oil and gas property and equipment		(150	)		(4	)
Other		29			35
Changes in assets and liabilities:
(Increase) decrease in:
Accounts receivable		9			(161	)
Other current assets		(6	)		(27	)
Long-term other assets		35			—
Increase (decrease) in:
Accounts payable		112			134
Income taxes payable		(75	)		157
Accrued interest and expenses		46			(81	)
Long-term debt, including current maturities		(67	)		8
Long-term other liabilities		(22	)		(13	)

Net cash provided by operating activities		2,385			2,360

Cash flows from investing activities:
Proceeds from sale of property and equipment		2,161			20
Capital expenditures		(1,976	)		(1,655	)
Purchases of short-term investments		(2,765	)		(1,627	)
Sales of short-term investments		3,183			1,603

Net cash provided by (used in) investing activities		603			(1,659	)

Cash flows from financing activities:
Principal payments on long-term debt		(354	)		(971	)
Issuance of common stock, net of issuance costs		81			188
Repurchase of common stock		(1,562	)		—
Dividends paid on common stock		(70	)		(48	)
Dividends paid on preferred stock		(5	)		(5	)

Net cash used in financing activities		(1,910	)		(836	)

Effect of exchange rate changes on cash		(3	)		(15	)

Net increase (decrease) in cash and cash equivalents		1,075			(150	)
Cash and cash equivalents at beginning of period		1,152			932

Cash and cash equivalents at end of period	$	2,227		$	782

See accompanying notes to consolidated financial statements.

9

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 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 2004 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, 2005, and the results of their operations and their cash flows for the three-month and six-month periods ended June 30, 2005 and 2004.

Certain prior period amounts have been reclassified to conform to the current period presentation.

2. Derivative Instruments

Devon recorded in its consolidated statements of operations a gain of $18 million and a loss of $11 million in the second quarter of 2005 and 2004, respectively, and losses of $34 million and $7 million in the six-month periods ended June 30, 2005 and 2004, respectively, for the change in fair value of derivative financial instruments that do not qualify for hedge accounting treatment, as well as the ineffectiveness of derivatives that qualify as hedges.

As of June 30, 2005, $364 million of pre-tax accumulated net deferred losses on derivative instruments in accumulated other comprehensive income are expected to be reclassified to oil and gas sales during the next six months assuming no change in forward commodity prices from the June 30, 2005 forward prices. Transactions and events expected to occur over the next six months that will necessitate reclassifying these derivatives’ losses to earnings are primarily the production and sale of oil and gas, which includes the production hedged under the various derivative instruments. As of June 30, 2005, the maximum term over which Devon has hedged exposures to the variability of cash flows for commodity price risk under its various derivative instruments is six months.

In the first half of 2005, Devon recognized a $55 million loss on certain derivative financial instruments that no longer qualified for hedge accounting and were settled prior to the end of their original term. These commodity instruments 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. These losses are presented in other income in the accompanying 2005 statement of operations.

10

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

3. 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, 2005 and 2004.


	Net Earnings		Weighted
	Applicable to		Average		Net
	Common		Common Shares		Earnings
	Stockholders		Outstanding		Per Share
	(In millions, except per share amounts)
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


Three Months Ended June 30, 2004:
Basic earnings per share	$	499		482	$	1.04

Dilutive effect of:
Potential common shares issuable upon conversion of senior convertible debentures (the increase in net earnings is net of income tax expense of $1 million)		2		9
Potential common shares issuable upon the exercise of outstanding stock options		—		7

Diluted earnings per share	$	501		498	$	1.01

11

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


	Net Earnings		Weighted
	Applicable to		Average		Net
	Common		Common Shares		Earnings
	Stockholders		Outstanding		Per Share
	(In millions, except per share amounts)
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


Six Months Ended June 30, 2004:
Basic earnings per share	$	991		480	$	2.06

Dilutive effect of:
Potential common shares issuable upon conversion of senior convertible debentures (the increase in net earnings is net of income tax expense of $3 million)		5		9
Potential common shares issuable upon the exercise of outstanding stock options		—		6

Diluted earnings per share	$	996		495	$	2.01

The senior convertible debentures that were retired in June 2005 prior to their stated maturity were not included in the dilution calculation for the three and six month periods ended June 30, 2005, because the inclusion was anti-dilutive.

Certain options to purchase shares of Devon’s common stock have been excluded from the dilution calculations because the options’ exercise price exceeded the average market price of Devon’s common stock during the applicable period. The following information relates to these options.


	For the Three Months Ended June 30,					For the Six Months Ended June 30,
	2005			2004		2005			2004
Options excluded from dilution calculation (in millions)		—	⁽¹⁾		2		—	⁽¹⁾		2
Range of exercise prices	$	47.55 - $50.68		$	31.94 - $44.83	$	45.90 - $50.68		$	29.68 - $44.83
Weighted average exercise price	$	48.55		$	37.44	$	47.30		$	36.46


⁽¹⁾		Actual amount of options excluded from the three-months and six-months ended 2005 dilution calculations are 36,000 shares and 84,000 shares, respectively.

The excluded options for 2005 expire between February 27, 2010 and June 7, 2013.

12

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Devon applies the intrinsic value-based method of accounting prescribed by Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations, in accounting for its fixed plan stock options. As such, compensation expense is recorded on the date of grant only if the current market price of the underlying stock exceeded the exercise price. SFAS No. 123, Accounting for Stock-Based Compensation, (“SFAS No. 123”) established accounting and disclosure requirements using a fair value-based method of accounting for stock-based employee compensation plans. As allowed by SFAS No. 123, Devon has elected to continue to apply the intrinsic value-based method of accounting described above, and has adopted the disclosure requirements of SFAS No. 123.

Had Devon elected the fair value provisions of SFAS No. 123 and recognized compensation expense over the vesting period based on the fair value of the stock options granted as of their grant date, Devon’s pro forma net earnings and pro forma net earnings per share for the three-month and six-month periods ended June 30, 2005 and 2004 would have differed from the amounts actually reported as shown in the following table.


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
	(In millions, except per share amounts)
Net earnings available to common stockholders, as reported	$	650		$	499		$	1,211		$	991
Add stock-based employee compensation expense included in reported earnings, net of related tax expense		5			2			9			4
Deduct total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax expense		(10	)		(6	)		(20	)		(12	)

Net earnings available to common stockholders, pro forma	$	645		$	495		$	1,200		$	983


Net earnings per share available to common stockholders:
As reported:
Basic	$	1.40		$	1.04		$	2.57		$	2.06
Diluted	$	1.38		$	1.01		$	2.53		$	2.01
Pro forma:
Basic	$	1.39		$	1.02		$	2.54		$	2.05
Diluted	$	1.37		$	0.99		$	2.50		$	2.00

In December 2004, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 123(R), “Share-Based Payment”, (“SFAS No. 123(R)”) which is a revision of SFAS No. 123 and supersedes APB Opinion No. 25 regarding stock-based employee compensation plans. APB Opinion No. 25 requires recognition of compensation expense only if the current market price of the underlying stock exceeded the stock option exercise price on the date of grant. Additionally, SFAS No. 123 established fair value-based accounting for stock-based employee compensation plans but allowed pro forma disclosure as an alternative to financial statement recognition. SFAS No. 123(R) requires all 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. Also, pro forma disclosure of the income statement effects of share-based payments is no longer an alternative. Devon will adopt the provisions of SFAS No. 123(R) in the first quarter of 2006 and anticipates adopting SFAS No. 123(R) using the modified prospective method. Under this method, Devon will recognize compensation expense for all stock-based awards granted or modified on or after January 1, 2006, as well as any previously granted awards that are not fully vested as of January 1, 2006. Compensation expense will be measured based on the fair value of the awards previously calculated in developing the pro forma disclosures in accordance with the provisions of SFAS No. 123. Devon is currently assessing the impact of adopting SFAS No. 123(R) on its consolidated results of operations. However, Devon does not expect such impact to be

13

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

material upon adoption in the first quarter of 2006.

4. Common Stock

On September 27, 2004, Devon announced a stock buyback program to repurchase up to 50 million shares of its common stock. During the six month period ended June 30, 2005, Devon repurchased approximately 34.2 million shares at a total cost of $1.6 billion, or $45.62 per share. As of June 30, 2005, Devon had repurchased approximately 39.2 million shares under the program at a total cost of $1.8 billion, or $44.62 per share. On August 2, 2005, Devon completed this stock buyback program at a total cost of $2.3 billion, or $46.69 per share.

On August 3, 2005, Devon announced that its board of directors had authorized the repurchase of up to an additional 50 million shares of its common stock. This second stock repurchase program is planned to extend through 2007. Shares may be purchased from time to time depending upon market conditions. Devon plans to repurchase shares in the open market and in privately negotiated transactions.

The following is a summary of the changes in Devon’s common shares outstanding for the first half of 2005 and 2004.


	Six Months Ended
	June 30,
	2005			2004
	(In millions)
Shares outstanding, beginning of period		484			472
Exercise of stock options		3			9
Shares repurchased and retired		(34	)		—
Conversion of subsidiary’s preferred stock		—			2

Shares outstanding, end of period		453			483

In January 2004, 38,000 shares of convertible preferred stock of Ocean Energy, Inc., which became a subsidiary of Devon in the April 2003 Ocean merger, were canceled and converted to 2,197,160 shares of Devon common stock pursuant to an automatic conversion feature of the preferred stock. The automatic conversion feature was triggered when the closing price of Devon common stock equaled or exceeded the forced conversion price of $26.20 for 20 consecutive trading days.

5. Debt

Zero Coupon Convertible Debentures

In June 2000, Devon privately sold zero coupon convertible senior debentures. In May 2005, Devon announced its intention to redeem the debentures on June 27, 2005. Prior to redemption the majority of the debentures were surrendered by holders for conversion. Devon’s obligation to settle the conversions and redeem the debentures totaled $452 million and was satisfied with cash on hand.

The total cash payments to settle the conversions and redeem the debentures exceeded the accreted value of the debentures by $25 million. This $25 million excess as well as $5 million of unamortized issuance costs, are included in interest expense in the accompanying 2005 statements of operations. The after-tax effect of the $25 million excess and the $5 million of unamortized issuance costs was $19 million.

14

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

$400 million 6.75% Senior Notes due March 15, 2011

Devon announced on August 3, 2005 that it intends to redeem all of its $400 million principal amount 6.75 percent notes due 2011, using cash on hand. Under the terms of these securities, the redemption price will be calculated utilizing the comparable Treasury Yield, as defined in the prospectus, plus 25 basis points. The ultimate redemption price will be dependent upon the comparable Treasury Yield on the third business day preceding the redemption date of September 9, 2005. However, based on the comparable Treasury Yield on July 29, 2005, Devon would expect to incur a $46 million early retirement premium in the third quarter of 2005 upon the early redemption of these notes.

In conjunction with this planned redemption, Devon reclassified the $400 million notes from other long-term debt to current portion of long-term debt in the June 30, 2005 balance sheet. In May 2005, Devon settled the interest rate swaps related to these notes. A $7 million gain resulting from this early settlement has been deferred and will be recognized as other income upon the early redemption of these notes.

6. Supplemental Cash Flow Information

Cash payments for interest and income taxes in the first six months of 2005 and 2004 are presented below:


	Six Months Ended
	June 30,
	2005		2004
	(In millions)
Interest paid	$	353	$	245
Income taxes	$	663	$	221

7. 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, 2005 and 2004, and changes during each of the six months then ended, is presented in the following table.


	Foreign			Change in			Minimum			Unrealized
	Currency			Fair Value of			Pension			Gain on
	Translation			Financial			Liability			Marketable
	Adjustments			Instruments			Adjustments			Securities			Total
	(In millions)
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


Balance as of December 31, 2003	$	667			(135	)		(52	)		89			569
2004 activity		(181	)		(271	)		—			54			(398	)
Deferred taxes		24			108			—			(20	)		112

2004 activity, net of deferred taxes		(157	)		(163	)		—			34			(286	)

Balance as of June 30, 2004	$	510			(298	)		(52	)		123			283

15

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

8. Other Income

The components of other income included the following:


	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2005			2004		2005			2004
	(In millions)
Interest and dividend income	$	25		$	9	$	51		$	19
Net gain on sales of non-oil and gas property and equipment		—			1		150			4
Loss on derivative financial instruments		(16	)		—		(55	)		—
Other		5			5		6			14

Other income, net	$	14		$	15	$	152		$	37

9. Oil and Gas Property Divestitures

In September 2004, Devon announced its plans to divest certain non-core oil and gas properties in the offshore Gulf of Mexico and onshore in the United States and Canada. Devon has closed all property divestitures except one minor package and received $2.0 billion of gross proceeds, net of all purchase price adjustments, through the first-half of 2005. After-tax, the proceeds are approximately $1.8 billion. Certain information regarding these sales is included in the following table.


	United States		Canada		Total
	($ in millions)
Gross proceeds	$	945	$	1,043	$	1,988
After-tax proceeds	$	739	$	1,041	$	1,780
Asset retirement obligations assumed by purchasers	$	76	$	38	$	114
Reserves sold (MMBoe)		85		79		164

Under full cost accounting rules, a gain or loss on the sale or other disposition of oil and gas properties is not recognized unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center. Because the divestitures that closed in 2005 did not significantly alter such relationship, Devon did not recognize a gain or loss on these divestitures. Therefore, the proceeds from these transactions were recognized as an adjustment of capitalized costs in the respective cost centers.

10. 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.

16

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, 2005 and 2004.


													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,
	2005			2004			2005			2004			2005		2004		2005		2004
	(In millions)
Components of net periodic benefit cost:
Service cost	$	5		$	4		$	10		$	8		$	—	$	—	$	—	$	—
Interest cost		8			8			16			16			1		1		2		2
Expected return on plan assets		(9	)		(8	)		(18	)		(16	)		—		—		—		—
Recognized net actuarial loss		2			2			4			4			—		—		—		—

Net periodic benefit cost	$	6		$	6		$	12		$	12		$	1	$	1	$	2	$	2

Employer Contributions

Devon previously disclosed in its financial statements for the year ended December 31, 2004, that it expected to contribute $6 million to the Qualified and Supplemental Plans and $6 million to the Postretirement Plans in 2005. Such expectations have not changed. As of June 30, 2005, Devon has contributed $3 million to the Qualified and Supplemental Plans and $3 million to the Postretirement Plans.

17

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

11. Segment Information

Following is certain financial information regarding Devon’s reporting segments. The revenues reported are all from external customers.


	U.S.		Canada		Inter- national		Total
	(In millions)
As of June 30, 2005:
Current assets	$	2,250		1,386		845		4,481
Property and equipment, net of accumulated depreciation, depletion and amortization		10,381		5,138		2,507		18,026
Goodwill		3,061		2,463		68		5,592
Other assets		1,139		18		14		1,171

Total assets	$	16,831		9,005		3,434		29,270


Current liabilities	$	1,619		1,253		313		3,185
Long-term debt		3,484		3,133		—		6,617
Asset retirement obligation, long-term		404		231		32		667
Other liabilities		423		35		20		478
Deferred income taxes		2,881		1,730		413		5,024
Stockholders’ equity		8,020		2,623		2,656		13,299

Total liabilities and stockholders’ equity	$	16,831		9,005		3,434		29,270


	U.S.			Canada		Inter- national			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	$	517			548		44			1,109

18

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


	U.S.			Canada			Inter- national			Total
	(In millions)
Three Months Ended June 30, 2004:
Revenues:
Oil sales	$	246			73			220			539
Gas sales		810			366			5			1,181
NGL sales		91			30			1			122
Marketing and midstream revenues		374			3			—			377

Total revenues		1,521			472			226			2,219

Expenses and other income, net:
Lease operating expenses		173			102			31			306
Production taxes		63			2			6			71
Marketing and midstream operating costs and expenses		298			1			—			299
Depreciation, depletion and amortization of oil and gas properties		311			123			83			517
Depreciation and amortization of non-oil and gas properties		30			4			1			35
Accretion of asset retirement obligation		6			4			—			10
General and administrative expenses		51			18			1			70
Interest expense		60			73			1			134
Effects of changes in foreign currency exchange rates		—			9			—			9
Change in fair value of derivative financial instruments		13			(2	)		—			11
Other income, net		(12	)		(2	)		(1	)		(15	)

Total expenses and other income, net		993			332			122			1,447
Earnings before income tax expense		528			140			104			772
Income tax expense:
Current		152			5			41			198
Deferred		52			19			1			72

Total income tax expense		204			24			42			270

Net earnings		324			116			62			502
Preferred stock dividends		3			—			—			3

Net earnings applicable to common stockholders	$	321			116			62			499


Capital expenditures	$	429			274			62			765

19

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


	U.S.			Canada			Inter- national			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	$	952			933			91			1,976

20

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)


	U.S.			Canada			Inter- national			Total
				(In millions)
Six Months Ended June 30, 2004:
Revenues:
Oil sales	$	506			152			462			1,120
Gas sales		1,591			697			14			2,302
NGL sales		177			61			3			241
Marketing and midstream revenues		788			6			—			794

Total revenues		3,062			916			479			4,457

Expenses and other income, net:
Lease operating expenses		344			211			61			616
Production taxes		119			3			11			133
Marketing and midstream operating costs and expenses		628			2			—			630
Depreciation, depletion and amortization of oil and gas properties		626			242			187			1,055
Depreciation and amortization of non-oil and gas properties		60			7			2			69
Accretion of asset retirement obligation		14			7			1			22
General and administrative expenses		115			30			2			147
Interest expense		109			142			1			252
Effects of changes in foreign currency exchange rates		—			15			—			15
Change in fair value of derivative financial instruments		8			(1	)		—			7
Other income, net		(28	)		(5	)		(4	)		(37	)

Total expenses and other income, net		1,995			653			261			2,909
Earnings before income tax expense		1,067			263			218			1,548
Income tax expense (benefit):
Current		296			20			85			401
Deferred		99			56			(4	)		151

Total income tax expense		395			76			81			552

Net earnings		672			187			137			996
Preferred stock dividends		5			—			—			5

Net earnings applicable to common stockholders	$	667			187			137			991


Capital expenditures	$	902			568			185			1,655

21

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

12. 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 June 30, 2005, 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. Trial is set for February 2007 if the suit continues to advance. Devon believes that it has

22

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

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.

Devon has been a defendant in certain private royalty owner litigation filed in Wyoming regarding deductibility of certain post production costs from royalties payable by Devon. A significant portion of such production is, or will be, transported through facilities owned by Thunder Creek Gas Services, L.L.C., of which Devon owns a 75% interest. At this time, all of the litigation has either been resolved, or is expected to soon be resolved, for amounts immaterial to Devon. Devon believes that it has acted reasonably and paid royalties in good faith and in accordance with its obligations under its oil and gas leases and applicable law, and Devon does not believe that it is subject to material exposure in association with this litigation.

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.

23

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, 2005, compared to the three-month and six-month periods ended June 30, 2004, and in financial condition since December 31, 2004. It is presumed that readers have read or have access to Devon’s 2004 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.

Overview

Net earnings for the second quarter of 2005 were $653 million, or $1.38 per diluted share. This compares to net earnings of $502 million, or $1.01 per diluted share for the second quarter of 2004. Net earnings for the first half of 2005 were $1.2 billion, or $2.53 per diluted share. This compares to net earnings of $996 million, or $2.01 per diluted share for the first half of 2004. Positive factors driving the increase in the 2005 second quarter and first half net earnings include increases in prices of oil, natural gas and NGLs and a first-quarter 2005 net gain from the sale of certain midstream assets. These increases were partially offset by a decline in production primarily due to divestitures in 2005, a loss on oil hedges related to such divestitures, additional interest expense related to the redemption of zero coupon convertible debentures, additional income tax expense on the repatriation of earnings from Canadian operations and higher operating expenses.

Cash flow from operations was relatively flat at $2.4 billion in the first half of 2004 and the first half of 2005. Although net earnings increased, 2005 cash flow from operations was negatively impacted by higher payments for current income taxes and the $100 million payment of interest in conjunction with the redemption of the zero coupon convertible debentures. In addition to cash flow from operations, we received $2.0 billion from the sale of oil and gas properties and $0.2 billion from the sale of certain midstream assets in the first half of 2005. These sources of cash allowed Devon to fund $2.0 billion of capital expenditures, repurchase $1.6 billion in common stock, redeem our zero coupon convertible debentures for $452 million and add $657 million to cash and short-term investments during the first half of 2005. Devon announced in September 2004 its plan to purchase up to 50 million shares of its common stock. On August 2, 2005, Devon completed its repurchase of 50 million shares at a total cost of $2.3 billion. On August 3, 2005, Devon announced that its board of directors authorized the repurchase of up to an additional 50 million shares of its common stock.

Devon also announced in September 2004 its plans to divest certain non-core oil and gas properties in the offshore Gulf of Mexico and onshore in the United States and Canada. As of June 30, 2005 Devon has sold all of the properties offered for sale except for one minor package. Gross proceeds from the divestitures totaled approximately $2.0 billion, net of all purchase price adjustments, in the first half of 2005. After-tax, the proceeds were approximately $1.8 billion.

During the first half of 2005, Devon drilled 180 exploration wells, of which 89% were completed as successful, and 998 development wells, of which 99% were completed as successful. As a result of this exploration and development activity, Devon has recorded 193 million barrels of proved reserves in the first half of 2005.

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 2004 Annual Report on Form 10-K.

24

Results of Operations

Total revenues increased $249 million, or 11%, in the second quarter of 2005, and $362 million, or 8%, in the first half of 2005 compared to the corresponding 2004 periods. These increases resulted from increases in oil, natural gas and NGL realized prices, partially offset by decreases in total production. The decreases in production were primarily the result of property divestitures and natural declines partially offset by new drilling and development.

Oil, natural gas and NGL revenues were up $237 million, or 13%, for the second quarter of 2005 compared to the second quarter of 2004, and $351 million, or 10%, for the first half of 2005 compared to the first half of 2004. The three-month and six-month comparisons of production and price changes are shown in the following tables. (Note: Unless otherwise stated, all dollar amounts are expressed in U.S. dollars.)


	Total
	Three Months Ended June 30,							Six Months Ended June 30,
	2005		2004		Change ²			2005		2004		Change ²
Production
Oil (MMBbls)		17		19		-9	%		35		40		-12	%
Gas (Bcf)		209		223		-7	%		423		446		-5	%
NGLs (MMBbls)		6		6		+3	%		12		12		+1	%
Oil, Gas and NGLs (MMBoe)¹		59		62		-6	%		118		126		-7	%

Average Prices
Oil (Per Bbl)	$	37.28	$	28.04		+33	%	$	35.86	$	27.91		+28	%
Gas (Per Mcf)		6.09		5.29		+15	%		5.79		5.17		+12	%
NGLs (Per Bbl)		25.99		20.89		+24	%		25.15		20.32		+24	%
Oil, Gas and NGLs (Per Boe)¹		35.66		29.58		+21	%		34.09		29.02		+17	%

Revenues ($ in millions)
Oil	$	650	$	539		+21	%	$	1,265	$	1,120		+13	%
Gas		1,272		1,181		+8	%		2,447		2,302		+6	%
NGLs		157		122		+29	%		302		241		+25	%

Combined	$	2,079	$	1,842		+13	%	$	4,014	$	3,663		+10	%


	Domestic
	Three Months Ended June 30,							Six Months Ended June 30,
	2005		2004		Change ²			2005		2004		Change ²
Production
Oil (MMBbls)		7		8		-15	%		15		17		-13	%
Gas (Bcf)		140		150		-7	%		285		303		-6	%
NGLs (MMBbls)		5		5		-1	%		10		10		-1	%
Oil, Gas and NGLs (MMBoe)¹		35		38		-8	%		72		77		-7	%

Average Prices
Oil (Per Bbl)	$	40.18	$	30.23		+33	%	$	38.70	$	30.08		+29	%
Gas (Per Mcf)		6.17		5.39		+14	%		5.80		5.27		+10	%
NGLs (Per Bbl)		23.73		19.33		+23	%		22.95		18.83		+22	%
Oil, Gas and NGLs (Per Boe)¹		35.88		30.29		+18	%		34.07		29.70		+15	%

Revenues ($ in millions)
Oil	$	278	$	246		+13	%	$	569	$	506		+12	%
Gas		862		810		+6	%		1,651		1,591		+4	%
NGLs		110		91		+22	%		213		177		+21	%

Combined	$	1,250	$	1,147		+9	%	$	2,433	$	2,274		+7	%

25


	Canada
	Three Months Ended June 30,							Six Months Ended June 30,
	2005		2004		Change ²			2005		2004		Change ²
Production
Oil (MMBbls)		3		3		+2	%		6		7		-2	%
Gas (Bcf)		67		71		-6	%		133		138		-4	%
NGLs (MMBbls)		1		1		+20	%		2		2		+11	%
Oil, Gas and NGLs (MMBoe)¹		16		16		-3	%		31		32		-2	%

Average Prices
Oil (Per Bbl)	$	24.05	$	21.49		+12	%	$	23.98	$	22.27		+8	%
Gas (Per Mcf)		5.98		5.16		+16	%		5.83		5.04		+16	%
NGLs (Per Bbl)		34.28		27.54		+24	%		33.16		26.33		+26	%
Oil, Gas and NGLs (Per Boe)¹		33.20		28.74		+15	%		32.50		28.27		+15	%

Revenues ($ in millions)
Oil	$	83	$	73		+14	%	$	161	$	152		+5	%
Gas		400		366		+9	%		775		697		+11	%
NGLs		45		30		+50	%		85		61		+39	%

Combined	$	528	$	469		+13	%	$	1,021	$	910		+12	%


	International
	Three Months Ended June 30,							Six Months Ended June 30,
	2005		2004		Change ²			2005		2004		Change ²
Production
Oil (MMBbls)		7		8		-8	%		14		16		-16	%
Gas (Bcf)		2		2		+14	%		5		5		—
NGLs (MMBbls)		—		—		+14	%		—		—		+4	%
Oil, Gas and NGLs (MMBoe)¹		8		8		-6	%		15		17		-15	%

Average Prices
Oil (Per Bbl)	$	40.91	$	28.63		+43	%	$	38.59	$	28.03		+38	%
Gas (Per Mcf)		4.08		2.43		+68	%		3.95		2.84		+39	%
NGLs (Per Bbl)		21.16		21.19		—			24.56		21.12		+16	%
Oil, Gas and NGLs (Per Boe)¹		39.82		27.95		+42	%		37.58		27.44		+37	%

Revenues ($ in millions)
Oil	$	289	$	220		+32	%	$	535	$	462		+16	%
Gas		10		5		+92	%		21		14		+39	%
NGLs		2		1		+14	%		4		3		+21	%

Combined	$	301	$	226		+33	%	$	560	$	479		+17	%


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. The respective prices of oil, gas and NGLs are affected by market and other factors in addition to relative energy content.

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.

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The average sales prices per unit of production shown in the preceding tables include the effect of Devon’s hedging activities. Following is a comparison of Devon’s average sales prices with and without the effect of hedges for the three-month and six-month periods ended June 30, 2005 and 2004.


	With Hedges				Without Hedges
	Three Months Ended				Three Months Ended
	June 30,				June 30,
	2005		2004		2005		2004
Oil (per Bbl)	$	37.28	$	28.04	$	46.00	$	33.94
Gas (per Mcf)	$	6.09	$	5.29	$	6.18	$	5.35
NGLs (per Bbl)	$	25.99	$	20.89	$	25.99	$	20.89
Oil, Gas and NGLs (per Boe)	$	35.66	$	29.58	$	38.61	$	31.62


	With Hedges				Without Hedges
	Six Months Ended				Six Months Ended
	June 30,				June 30,
	2005		2004		2005		2004
Oil (per Bbl)	$	35.86	$	27.91	$	44.19	$	32.52
Gas (per Mcf)	$	5.79	$	5.17	$	5.87	$	5.23
NGLs (per Bbl)	$	25.15	$	20.32	$	25.15	$	20.32
Oil, Gas and NGLs (per Boe)	$	34.09	$	29.02	$	36.89	$	30.67

Oil Revenues. Oil revenues increased $111 million in the second quarter of 2005. Oil revenues increased $161 million due to a $9.24 per barrel increase in Devon’s realized average price of oil. A decrease in the second quarter 2005 production of 2 million barrels caused oil revenues to decrease by $50 million. Production lost from the 2005 property divestitures accounted for substantially all the production decrease.

Oil revenues increased $145 million in the first half of 2005. Oil revenues increased $280 million due to a $7.95 per barrel increase in Devon’s realized average price of oil. A decrease in production of 5 million barrels caused oil revenues to decrease by $135 million. Production lost from the 2005 property divestitures caused a decrease of 2 million barrels. 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 in the second quarter of 2004. Also, natural production declines on U.S. onshore and offshore properties that were sold in 2005 contributed to the decrease in volumes.

Gas Revenues. Gas revenues increased $91 million in the second quarter of 2005. Gas revenues increased $167 million due to a $0.80 per Mcf increase in Devon’s realized average price of gas. A decrease in production of 14 Bcf caused gas revenues to decrease by $76 million. Production lost from the 2005 property divestitures caused a decrease of 24 Bcf. This decrease was partially offset by new drilling and development and increased performance in U.S. offshore and onshore properties.

Gas revenues increased $145 million in the first half of 2005. Gas revenues increased $263 million due to a $0.62 per Mcf increase in Devon’s realized average price of gas. A decrease in production of 23 Bcf caused gas revenues to decrease by $118 million. Production lost from the 2005 property divestitures caused a decrease of 33 Bcf. Production also decreased due to natural production declines on U.S. onshore and offshore properties that were sold in 2005. 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 $35 million in the second quarter of 2005. A $5.10 per barrel increase in Devon’s realized average NGL price in the second quarter of 2005 increased NGL revenues by $31 million. A slight increase in production caused NGL revenues to increase by $4 million.

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NGL revenues increased $61 million in the first half of 2005. A $4.83 per barrel increase in Devon’s realized average NGL price in the first half of 2005 increased NGL revenues by $58 million. A slight increase in production caused NGL revenues to increase by $3 million.

Marketing and Midstream Revenues. Marketing and midstream revenues increased $12 million, in the second quarter of 2005. Revenues increased $111 million due to higher natural gas and NGL prices and higher gas sales and gas pipeline volumes. This was partially offset by a $99 million decrease in revenues caused by the sale of certain assets in 2004 and 2005.

Marketing and midstream revenues increased $11 million in the first half of 2005. Revenues increased $177 million due to higher natural gas and NGL prices and higher gas pipeline volumes. This was partially offset by a $166 million decrease in revenues caused by the sale of certain assets in 2004 and 2005.

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.


	Total
	Three Months Ended June 30,							Six Months Ended June 30,
	2005		2004		Change ¹			2005		2004		Change ¹
Expenses ($ in millions)
Lease operating expenses	$	338	$	306		+10	%	$	686	$	616		+11	%
Production taxes		75		71		+6	%		153		133		+15	%

Total production and operating expenses	$	413	$	377		+10	%	$	839	$	749		+12	%


Expenses Per Boe
Lease operating expenses	$	5.80	$	4.92		+18	%	$	5.83	$	4.88		+19	%
Production taxes		1.29		1.14		+13	%		1.30		1.06		+23	%

Total production and operating expenses	$	7.09	$	6.06		+17	%	$	7.13	$	5.94		+20	%


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 $32 million in the second quarter of 2005. The increase in lease operating expenses was primarily due to an increase in well workover expenses, ad valorem taxes, power, fuel and repairs and maintenance costs. With the continuing strength of commodity prices, workovers and repairs and maintenance costs have been performed to either maintain or improve production volumes. The higher commodity prices also resulted in increased power and fuel costs. Additionally, changes in the Canadian-to-U.S. dollar exchange rate, from second quarter 2004 to second quarter 2005, resulted in a $10 million increase in costs. Partially offsetting these increases was a decrease of $32 million for lease operating expenses related to properties that were sold in 2005.

Lease operating expenses increased $70 million in the first half of 2005. The increase in lease operating expenses was primarily due to an increase in well workover expenses, ad valorem taxes, power, fuel and repairs and maintenance costs. Additionally, changes in the Canadian-to-U.S. dollar exchange rate, from the first half of 2004 to the first half of 2005, resulted in a $19 million increase in costs. Partially offsetting these increases was a decrease of $32 million for lease operating expenses related to properties that were sold in 2005.

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The increase in lease operating expenses per Boe for the second quarter of 2005 and the first half of 2005 is primarily related to changes in the Canadian-to-U.S. dollar exchange rate as well as increased power, fuel and repairs and maintenance costs.

Production taxes increased $4 million in second quarter of 2005 and $20 million in the first half of 2005. Production taxes increased generally due to higher oil, gas and NGL revenues. Production taxes were further increased $9 million in the first half of 2005 as a result of retroactive adjustments to prior year’s taxes as a result of recent regulatory rulings and $8 million due to higher Russian export rates.

Marketing and Midstream Operating Costs and Expenses. Marketing and midstream operating costs and expenses decreased $3 million in the second quarter of 2005. The sale of certain assets in 2004 and 2005 caused costs and expenses to decrease $89 million. This was partially offset by increases due to higher natural gas and NGL purchase prices and higher gas sales and gas pipeline volumes.

Marketing and midstream operating costs and expenses decreased $3 million in the first half of 2005. The sale of certain assets in 2004 and 2005 caused costs and expenses to decrease $147 million. This was partially offset by increases due to higher natural gas and NGL purchase prices and higher gas pipeline 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 decreased $23 million in the second quarter of 2005. DD&A decreased $33 million due to a 6% decrease in the combined oil, gas and NGL production in the second quarter of 2005. This decrease was partially offset by an increase in the combined U.S., Canadian and international DD&A rate from $8.29 per Boe in the second quarter of 2004 to $8.48 per Boe in the second quarter of 2005 which caused oil and gas property DD&A to increase by $10 million. Changes in the Canadian-to-U.S. dollar exchange rate and rising costs in 2004 were the primary factors contributing to the DD&A rate increase. These and other factors caused the rate to increase to $8.95 in the fourth quarter of 2004 compared to the second quarter 2004 rate of $8.29. The decrease in the rate from the fourth quarter of 2004 to the second quarter of 2005 is primarily due to the effects of the 2005 property divestitures.

Oil and gas property DD&A decreased $20 million in the first half of 2005. DD&A decreased $71 million due to a 7% decrease in the combined oil, gas and NGL production in the first half of 2005. This decrease was partially offset by an increase in the combined U.S., Canadian and international DD&A rate from $8.35 per Boe in the first half of 2004 to $8.79 per Boe in the first half of 2005 which caused oil and gas property DD&A to increase by $51 million. Changes in the Canadian-to-U.S. dollar exchange rate and rising costs in 2004 were the primary factors contributing to the DD&A rate increase.

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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,
	2005			2004			2005			2004
	(In millions)
Gross G&A	$	148		$	135		$	280		$	276
Capitalized G&A		(45	)		(42	)		(92	)		(84	)
Reimbursed G&A		(25	)		(23	)		(52	)		(45	)


Net G&A	$	78		$	70		$	136		$	147

Gross G&A increased $13 million in the second quarter of 2005 compared to the same period of 2004. Increases in compensation and benefits and charitable giving caused a combined increase of $13 million. This was partially offset by a decrease in rent expense due to the abandonment of certain Canadian office space in the second quarter of 2004. Devon incurred a $5 million charge in the second quarter of 2004 related to the abandonment. Also, changes in the Canadian-to-U.S. dollar exchange rate, from the second quarter 2004 to the same period of 2005, resulted in a $3 million increase in costs.

Gross G&A increased $4 million from the first half of 2005 compared to the same period of 2004. Decreases in compensation and benefits and rent expense caused a combined decrease of $6 million. This was partially offset by an increase in charitable giving. Also, changes in the Canadian-to-U.S. dollar exchange rate, from the first half of 2004 to the same period of 2005, resulted in a $5 million increase in costs.

Capitalized G&A increased $3 million and $8 million in the second quarter and first half of 2005, respectively, due to increases in capitalizable salaries and benefits. The $2 million and $7 million increases in reimbursed G&A during the second quarter and first half of 2005, respectively, are primarily related to an increase in the number of wells operated by Devon as a result of new drilling and development.

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Interest Expense. The following schedule includes the components of interest expense for the second quarter and first half of 2005 and 2004.


	Three Months						Six Months
	Ended June 30,						Ended June 30,
	2005			2004			2005			2004
				(In millions)
Interest based on debt outstanding	$	133		$	128		$	265		$	260
Amortization of discounts/premiums		—			1			1			1
Facility and agency fees		1			1			1			1
Amortization of capitalized loan costs		5			18			6			21
Capitalized interest		(18	)		(17	)		(37	)		(34	)
Loss on extinguishment of debt		25			—			25			—
Other		—			3			3			3


Total interest expense	$	146		$	134		$	264		$	252

The average debt balance decreased from $8.1 billion in the second quarter of 2004 to $7.8 billion in the 2005 quarter due to debt repayments during 2004 and 2005. This decrease in debt outstanding caused interest expense to decrease $3 million. This decrease in interest expense was offset by $8 million due to higher floating rates in 2005. The average interest rate on outstanding debt increased from 6.4% in the second quarter of 2004 to 6.8% in the second quarter of 2005.

Other items included in interest expense that are not related to the debt balance outstanding were $7 million higher in the second quarter and first half of 2005. Of this increase, $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. This was partially offset by $16 million in expenses related to the early repayment of the outstanding balance under the $3 billion term loan credit facility in which Devon expensed the remaining unamortized issuance costs in the second quarter of 2004.

The average debt balance decreased from $8.4 billion in the first half of 2004 to $7.9 billion in the first half of 2005 due to debt repayments during 2004 and 2005. This decrease in debt outstanding caused interest expense to decrease $17 million. This decrease in interest expense was offset by $22 million due to higher floating rates in 2005. The average interest rate on outstanding debt increased from 6.2% in the first half of 2004 to 6.8% in the first half of 2005.

Effects of Changes in Foreign Currency Exchange Rates. Devon’s Canadian subsidiary has certain fixed-rate senior notes which are denominated in U.S. dollars. Changes in the exchange rate between the U.S. dollar and the Canadian dollar while the notes are outstanding increase or decrease the expected amount of Canadian dollars eventually required to repay the notes. In addition, Devon’s Canadian subsidiary has cash and other working capital amounts denominated in U.S. dollars which also fluctuate in value with changes in the exchange rate. Such changes in the Canadian dollar equivalent balance of the debt and working capital balances are required to be included in determining net earnings for the period in which the exchange rate changes. In the second quarter of 2005, our Canadian subsidiary purchased U.S. dollars related to our repatriation of $535 million of earnings from our Canadian operation to the U.S. As a result of a decrease in the Canadian-to-U.S. dollar exchange rate while these U.S. dollars were held, we recognized a $7 million loss in the second quarter of 2005.

The decreases in the Canadian-to-U.S. dollar exchange rate from $0.8308 at December 31, 2004 and $0.8267 at March 31, 2005 to $0.8159 at June 30, 2005 resulted in losses of $5 million and $6 million in the second quarter and the first half of 2005, respectively. The decreases in the Canadian-to-U.S. dollar exchange rate from $0.7738 at December 31, 2003 and $0.7631 at March 31, 2004 to $0.7460 at June 30, 2004 resulted in losses of $9 million and $15 million in the second quarter and first half of

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2004, respectively.

Changes in Fair Value of Derivative Financial Instruments. The change in fair value of derivative financial instruments decreased $29 million in the second quarter of 2005 and increased $27 million in the first half of 2005 primarily due to the changes in the fair value of the option embedded in the debentures exchangeable into shares of Chevron Corporation common stock.

Other Income, net. The following schedule includes the components of other income for the three and six months periods ended June 30.


	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2005			2004		2005			2004
				(In millions)
Interest and dividend income	$	25		$	9	$	51		$	19
Net gain on sales of non-oil and gas property and equipment		—			1		150			4
Loss on derivative financial instruments		(16	)		—		(55	)		—
Other		5			5		6			14

Other income, net	$	14		$	15	$	152		$	37

The increases in interest and dividend income in the second quarter and first half of 2005 were primarily due to an increase in 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 35% in the second quarters of both 2005 and 2004. The estimated effective tax rate was 37% in the first half of 2005 and 36% in the first half of 2004.

The first half of 2005 rate was higher than the statutory federal tax rate primarily due to the $28 million tax effect of the repatriation of $535 million of earnings from our Canadian operations. Excluding the effect of the repatriation, the effective tax rate decreased to 35%.

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Capital Expenditures 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,
	2005			2004
	(In millions)
Cash provided by (used in):
Operating activities	$	2,385		$	2,360
Investing activities		603			(1,659	)
Financing activities		(1,910	)		(836	)
Effect of exchange rate changes		(3	)		(15	)

Net increase (decrease) in cash and cash equivalents	$	1,075		$	(150	)

Cash and cash equivalents at end of period	$	2,227		$	782

Short-term investments at end of period	$	549		$	365

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 2005. Operating cash flow remained constant at $2.4 billion in the first half of 2005 compared to the first half of 2004. Although net earnings increased $220 million from 2004 to 2005, cash paid for taxes increased $442 million between the two periods. Also, 2005 operating cash flow includes $75 million for the payment of interest related to the redemption of the zero coupon convertible debentures. This $75 million equals the amount of interest accrued on these debentures since their issuance in June 2000.

Cash Flows from Investing Activities

Net cash provided by investing activities was $603 million in the first half of 2005 compared to net cash used of $1.7 billion in the first half of 2004. The decrease in cash used in investing activities was primarily related to an increase in proceeds from the sale of property and equipment.

Capital expenditures in the first half of 2005 were $2.0 billion. This total includes $1.9 billion for the acquisition, drilling or development of oil and gas properties. These amounts compare to capital expenditures of $1.7 billion in the first half of 2004 which included $1.6 billion for the acquisition, drilling or development of oil and gas properties.

Proceeds from sales of property and equipment, net of all purchase price adjustments, were $2.2 billion and $20 million in the first half of 2005 and first half of 2004, respectively. The increase in proceeds was due to the sale of oil and gas properties in conjunction with the divestiture program announced on September 27, 2004, as well as certain non-core midstream assets.

Cash Flows from Financing Activities

Net cash used in financing activities during the first half of 2005 was $1.9 billion compared to $836 million in the first half of 2004. The increase in cash used in financing activities from 2004 to 2005 was primarily related to repurchases of common stock in 2005, partially offset by a decrease in payments on debt. In conjunction with the stock buyback program announced September 27, 2004, Devon repurchased approximately 34.2 million shares at a total cost of $1.6 billion, or $45.62 per share, during the first half of 2005. On August 2, 2005, Devon completed its repurchase of the planned 10 percent of its common stock, or approximately 50 million shares, under this stock buyback program at a total cost of

33

$2.3 billion.

During the first half of 2005, Devon paid $452 million to redeem the zero coupon convertible debentures. During the first half of 2004, Devon paid $971 million to retire the $211 million 6.75% notes due February 15, 2004, the $125 million 8.05% notes due June 15, 2004 and the remaining $635 million outstanding on the $3 billion term loan credit facility.

Devon received $81 million and $188 million from shares issued for stock options exercised during 2005 and 2004, respectively.

Devon’s common stock dividends were $70 million and $48 million in the first half of 2005 and 2004, respectively. Devon also paid $5 million of preferred stock dividends in the first half of 2005 and 2004. The increase in common stock dividends from 2004 to 2005 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. In 2005, Devon increased its quarterly dividend rate from $0.05 per share to $0.075 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, 2005, Devon’s unrestricted cash and cash equivalents and short-term investments totaled $2.8 billion. During the first half of 2005 and 2004, such balances increased $657 million and decreased $126 million, respectively.

Historically, Devon’s 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. Another major source of liquidity in 2005 relates to proceeds from Devon’s divestiture of certain non-core oil and gas properties that was announced in September 2004. All but one minor package of properties were sold by June 30, 2005. After-tax sale proceeds, net of all purchase price adjustments, from the divestiture program are approximately $1.8 billion. We expect the combination of these sources of capital will be more than adequate to fund future capital expenditures, our common stock buyback program, debt repayments and other contractual commitments.

Operating Cash Flow

Devon’s 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.

To mitigate some of the risk inherent in oil and natural gas prices, Devon has utilized price collars to set minimum and maximum prices on a portion of its production. Additionally, we have entered into various financial price swap contracts and fixed-price physical delivery contracts to fix the price to be received for a portion of future oil and natural gas production. The table below provides the volumes associated with these various arrangements as of June 30, 2005.

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			Price		Fixed-Price
	Price		Swap		Physical
	Collars		Contracts		Delivery Contracts		Total
Oil production (MMBbls)
2005 (last six months of the year)		9		3		—		12
Natural gas production (Bcf)
2005 (last six months of the year)		7		2		9		18
2006		—		—		18		18

In addition to the above quantities, we have fixed-price physical delivery contracts covering Canadian natural gas production for the years 2007 through 2011 ranging from 7 Bcf to 14 Bcf per year. Also, Devon has a fixed-price physical delivery contract covering 4 Bcf and 3 Bcf of International natural gas production in 2007 and 2008, respectively.

It is our policy to only enter into derivative contracts with investment grade rated counterparties deemed by management as competent and competitive market makers. Devon does not hold or issue derivative instruments for speculative trading purposes.

Credit Lines

Another source of liquidity is our $1.5 billion five-year, syndicated, unsecured revolving line of credit (the “Senior Credit Facility”). The Senior Credit Facility includes (i) a five-year revolving Canadian subfacility in a maximum amount of U.S. $500 million and (ii) a $1 billion sublimit for the issuance of letters of credit, including letters of credit under the Canadian subfacility.

The Senior Credit Facility matures on April 8, 2010, and all amounts outstanding will be due and payable at that time unless the maturity is extended. Prior to each April 8 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 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. Devon may also elect to borrow at the prime rate. The Senior Credit Facility currently provides for an annual facility fee of $1.9 million that is payable quarterly in arrears.

As of June 30, 2005, there were no borrowings under the Senior Credit Facility. The available capacity under the Senior Credit Facility as of June 30, 2005, net of $242 million of outstanding letters of credit, was approximately $1.3 billion.

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, 2005, Devon’s ratio as calculated pursuant to this covenant was 32.3%.

Our access to funds from the Senior Credit Facility is not restricted under any “material adverse condition” 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

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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 $725 million. 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 had no commercial paper debt outstanding at June 30, 2005.

Common Stock Buyback Program

On August 3, 2005, Devon announced that it completed the 50 million stock repurchase program announced on September 27, 2004. Also on August 3, 2005, Devon announced that its board of directors had authorized the repurchase of up to an additional 50 million shares of its common stock. This stock repurchase program is planned to extend through 2007. Shares may be purchased from time to time depending upon market conditions. Devon plans to repurchase shares in the open market and in privately negotiated transactions.

Impact of Recently Issued Accounting Standards Not Yet Adopted

In December 2004, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 123(R), “Share-Based Payment”, (“SFAS No. 123(R)”) which is a revision of SFAS No. 123 and supersedes APB Opinion No. 25 regarding stock-based employee compensation plans. APB Opinion No. 25 requires recognition of compensation expense only if the current market price of the underlying stock exceeded the stock option exercise price on the date of grant. Additionally, SFAS No. 123 established fair value-based accounting for stock-based employee compensation plans but allowed pro forma disclosure as an alternative to financial statement recognition. SFAS No. 123(R) requires all 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. Also, pro forma disclosure of the income statement effects of share-based payments is no longer an alternative. We will adopt the provisions of SFAS No. 123(R) in the first quarter of 2006 and anticipate adopting SFAS No. 123(R) using the modified prospective method. Under this method, we will recognize compensation expense for all stock-based awards granted or modified on or after January 1, 2006, as well as any previously granted awards that are not fully vested as of January 1, 2006. Compensation expense will be measured based on the fair value of the awards previously calculated in developing the pro forma disclosures in accordance with the provisions of SFAS No. 123. We are currently assessing the impact of adopting SFAS No. 123(R) on our consolidated results of operations. However, we do not expect such impact to be material upon adoption in the first quarter of 2006.

In March 2005, the FASB issued FASB Interpretation (“FIN”) No. 47, “Accounting for Conditional Asset Retirement Obligations.” The interpretation clarifies the requirement to record abandonment liabilities stemming from legal obligations when the retirement depends on a conditional future event. FIN No. 47 requires that the uncertainty about the timing or method of settlement of a conditional retirement obligation be factored into the measurement of the liability when sufficient information exists. FIN No. 47 is effective for fiscal years ending after December 15, 2005. Devon does not expect FIN No. 47 will have a material impact on its financial statements.

SEC Inquiry Relating to Equatorial Guinea

On August 6, 2004, the SEC notified Devon that it was conducting an inquiry into payments made to the government of Equatorial Guinea, or to officials and persons affiliated with officials of the

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government of Equatorial Guinea. This inquiry follows an investigation and public hearing conducted by the United States Senate Permanent Subcommittee on Investigations, which reviewed the transactions of various foreign governments, including that of Equatorial Guinea, with Riggs Bank. The investigation and hearing also reviewed the operations of those U.S. oil companies having interests in Equatorial Guinea, including Devon. Devon is cooperating with the SEC inquiry.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The information included in “Quantitative and Qualitative Disclosures About Market Risk” in Item 7A of Devon’s 2004 Annual Report on Form 10-K is incorporated herein by reference. Such information includes a description of Devon’s potential exposure to market risks, including commodity price risk, interest rate risk and foreign currency risk. As of June 30, 2005, there have been no material changes in Devon’s market risk exposure except as discussed below regarding commodity price and interest rate risk.

Commodity Price Risk

Our major market risk exposure is in the pricing applicable to our oil, gas and NGL production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our U.S. and Canadian natural gas and NGL production. Pricing for oil, gas and NGL production has been volatile and unpredictable for several years.

Devon periodically enters into financial hedging activities with respect to a portion of its projected oil and natural gas production through various financial transactions which hedge the future prices received. These transactions include financial price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty, and costless price collars that set a floor and ceiling price for the hedged production. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, Devon and the counterparty to the collars will settle the difference. These financial hedging activities are intended to support oil and natural gas prices at targeted levels and to manage Devon’s exposure to oil and gas price fluctuations.

Devon’s total hedged positions on future production as of June 30, 2005 are set forth in the following tables.

Price Swaps

Through various price swaps, we have fixed the price we will receive on a portion of our oil and natural gas production in 2005. The following tables include information on this fixed-price production by area. Where necessary, the oil and gas prices related to these swaps have been adjusted for certain transportation costs that are netted against the price recorded by Devon, and the gas price has also been adjusted for the Btu content of the production that has been hedged.

Oil Production


					Months of
Area	Bbls/Day		Price/Bbl		Production
United States Offshore		8,000	$	27.14	Jul — Dec
Canada		3,000	$	27.13	Jul — Dec
International		6,000	$	25.88	Jul — Dec

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Gas Production

Months of

Area

Mcf/Day

Price/Mcf

Production

United States Onshore

7,285

$

3.40

Jul — Dec

Costless Price Collars

We have also entered into costless price collars that set a floor and ceiling price for a portion of our 2005 oil production that is otherwise subject to floating prices. The floor and ceiling prices related to domestic and Canadian oil production are based on the NYMEX price. The floor and ceiling prices related to international oil production are based on the Brent price. If the NYMEX or Brent price is outside of the ranges set by the floor and ceiling prices in the various collars, Devon and the counterparty to the collars will settle the difference. As long as Devon meets the ongoing requirements of hedge accounting for its derivatives, any such settlements will either increase or decrease Devon’s oil revenues for the period. Because our oil volumes are often sold at prices that differ from the NYMEX or Brent price due to differing quality (i.e., sweet crude versus heavy or sour crude) and transportation costs from different geographic areas, the floor and ceiling prices of the various collars do not reflect actual limits of Devon’s realized prices for the production volumes related to the collars.

We have also entered into costless price collars that set a floor and ceiling price for a portion of our 2005 natural gas production that otherwise is subject to floating prices. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, Devon and the counterparty to the collars will settle the difference. Any such settlements will either increase or decrease Devon’s gas revenues for the period. Because Devon’s gas volumes are often sold at prices that differ from the related regional indices, and due to differing Btu contents of gas produced, the floor and ceiling prices of the various collars do not reflect actual limits of Devon’s realized prices for the production volumes related to the collars.

To simplify presentation, our costless collars as of June 30, 2005 have been aggregated in the following tables according to similar floor prices and similar ceiling prices. The floor and ceiling prices shown are weighted averages of the various collars in each aggregated group.

The international oil prices shown in the following table have been adjusted to a NYMEX-based price, using our estimates of 2005 differentials between NYMEX and the Brent price upon which the collars are based.

The natural gas prices shown in the following table have been adjusted to a NYMEX-based price, using our estimates of future differentials between NYMEX and the specific regional indices upon which the collars are based. The floor and ceiling prices related to the collars are based on various regional first-of-the-month price indices as published monthly by Inside FERC.

Oil Production


			Weighted Average
			Floor		Ceiling
			Price Per		Price Per		Months of
Area	Bbls/Day		Bbl		Bbl		Production
United States Offshore		17,000	$	22.00	$	27.62	Jul — Dec
Canada		15,000	$	22.00	$	28.28	Jul — Dec
International		15,000	$	23.50	$	29.61	Jul — Dec

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Gas Production

Weighted Average

Floor

Ceiling

Price Per

Months of

Area

MMBtu/Day

MMBtu

Production

United States Offshore

40,000

$

3.50

$

7.50

Jul — Dec

Devon uses a sensitivity analysis technique to evaluate the hypothetical effect that changes in the market value of oil and gas may have on the fair value of its commodity hedging instruments. At June 30, 2005, a 10% increase in the underlying commodity prices would have increased the net liabilities recorded for Devon’s commodity hedging instruments by $61 million.

Fixed-Price Physical Delivery Contracts

In addition to the commodity hedging instruments described above, Devon also manages its exposure to oil and gas price risks by periodically entering into fixed-price contracts. We have fixed-price physical delivery contracts for the years 2005 through 2011 covering Canadian natural gas production ranging from 7 Bcf to 14 Bcf per year. We also have fixed-price physical delivery contracts for the years 2005 through 2008 covering International natural gas production of 4 Bcf per year, except in 2008 when the volume drops to 3 Bcf.

Interest Rate Risk

In the second quarter of 2005, we settled the fixed-to-floating interest rate swaps related to the 6.75% senior notes due 2011. The $7 million gain in conjunction with this early settlement was deferred and will be recognized as other income upon the redemption of these notes on September 9, 2005.

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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, 2005 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 2005 that has materially affected, or is reasonably likely to materially affect, Devon’s internal control over financial reporting.

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Part II. Other Information

Item 1. Legal Proceedings

None

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 2005.


					Total Number of		Maximum Number of
	Total Number		Average Price		Shares Purchased as		Shares that May Yet Be
	of Shares		Paid per		Part of Publicly Announced		Purchased Under the
Period	Purchased		Share		Plans or Programs ⁽¹⁾		Plans or Programs⁽¹⁾
April		6,918,900	$	46.64		6,918,900		25,352,600
May		6,374,600	$	44.08		6,374,600		18,978,000
June		8,212,600	$	48.81		8,212,600		10,765,400

Total		21,506,100	$	46.71		21,506,100


⁽¹⁾		On September 27, 2004, Devon announced its plan to repurchase up to 50 million shares of its common shares. All repurchases under the program, which totaled 49,647,400 shares, were completed on August 2, 2005.

		On August 3, 2005, Devon announced that its board of directors had authorized the repurchase of up to an additional 50 million shares of its common stock. This stock repurchase program is planned to extend through 2007.

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 8, 2005.

(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 8, 2005 meeting and all nominees were elected.

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(c) A total of 427,025,613 shares of Devon’s common stock outstanding and entitled to vote were present at the June 8, 2005 meeting in person or by proxy, representing approximately 90.53% of the total outstanding shares. The matters voted upon were as follows:

1. The election of three Directors to serve on Devon’s Board of Directors until the 2008 Annual Meeting of Stockholders. The vote tabulation with respect to each nominee was as follows:


			Authority
Nominee	For		Withheld
John A. Hill		422,091,374		4,934,239
William J. Johnson		420,806,323		6,219,290
Robert A. Mosbacher, Jr.		420,656,612		6,363,001

2. Ratification of KPMG LLP as the Company’s Independent Auditors for 2005. The results of the votes were as follows:


FOR:			417,554,364
AGAINST:			6,649,656
ABSTAIN:			2,821,593

3. Adoption of the Company’s 2005 Long-Term Incentive Plan. The results of the vote were as follows:


FOR:			289,734,386
AGAINST:			84,094,554
ABSTAIN:			3,068,504

4. Stockholder Proposal for a Director Election Vote Standard. The proponent of this proposal, the United Association of Journeymen and Apprentices of the Plumbing and Pipe Fitting Industry of the United States and Canada, declined to present the proposal for a vote at the meeting.

Item 5. Other Information

None

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Item 6. Exhibits

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


Exhibit
Number
10.39		Form of Award Agreement between Registrant and Stephen J. Hadden, Brian J. Jennings, Duke R. Ligon, Marian J. Moon, J. Larry Nichols, John Richels and Darryl G. Smette for stock options granted under the 2005 Long-Term Incentive Plan.

10.40		Form of Award Agreement between Registrant and all non-management Directors for stock options granted under the 2005 Long-Term Incentive Plan.

10.41		Form of Award Agreement between Registrant and Stephen J. Hadden, Brian J. Jennings, Duke R. Ligon, Marian J. Moon, J. Larry Nichols, John Richels, Darryl G. Smette and all non-management Directors for restricted stock awards under the 2005 Long-Term Incentive Plan.

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.

43

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, 2005	/s/ Danny J. Heatly
	Danny J. Heatly
	Vice President — Accounting and Chief Accounting Officer

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INDEX TO EXHIBITS


Exhibit
Number
10.39		Form of Award Agreement between Registrant and Stephen J. Hadden, Brian J. Jennings, Duke R. Ligon, Marian J. Moon, J. Larry Nichols, John Richels and Darryl G. Smette for stock options granted under the 2005 Long-Term Incentive Plan.

10.40		Form of Award Agreement between Registrant and all non-management Directors for stock options granted under the 2005 Long-Term Incentive Plan.

10.41		Form of Award Agreement between Registrant and Stephen J. Hadden, Brian J. Jennings, Duke R. Ligon, Marian J. Moon, J. Larry Nichols, John Richels, Darryl G. Smette and all non-management Directors for restricted stock awards under the 2005 Long-Term Incentive Plan.

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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