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 September 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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

The number of shares outstanding of Registrant’s common stock, par value $0.10, as of September 30, 2005, was 444,300,000.

[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 September 30, 2005 (Unaudited) and December 31, 2004		6

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

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

	Consolidated Statements of Cash Flows (Unaudited) for the Nine Months Ended September 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		23

Item 3.	Quantitative and Qualitative Disclosures About Market Risk		36

Item 4.	Controls and Procedures		39

	Part II. Other Information

Item 1.	Legal Proceedings		40

Item 2.	Unregistered Sales of Equity Securities, Use of Proceeds and Issuer Purchases of Equity Securities		40

Item 6.	Exhibits		41
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

September 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


	September 30,			December 31,
	2005			2004
	(Unaudited)
	(In millions, except share data)
ASSETS
Current assets:
Cash and cash equivalents	$	1,095		$	1,152
Short-term investments		791			967
Accounts receivable		1,516			1,320
Fair value of derivative financial instruments		—			1
Deferred income taxes		180			289
Other current assets		177			143

Total current assets		3,759			3,872

Property and equipment, at cost, based on the full cost method of accounting for oil and gas properties ($3,207 and $3,187 excluded from amortization in 2005 and 2004, respectively)		33,313			32,114
Less accumulated depreciation, depletion and amortization		14,591			12,768

		18,722			19,346
Investment in Chevron Corporation common stock, at fair value		918			745
Fair value of derivative financial instruments		—			8
Goodwill		5,729			5,637
Other assets		395			417

Total assets	$	29,523		$	30,025


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable:
Trade	$	970		$	715
Revenues and royalties due to others		519			487
Income taxes payable		108			223
Current portion of long-term debt		900			933
Accrued interest payable		94			139
Fair value of derivative financial instruments		271			399
Current portion of asset retirement obligation		56			46
Accrued expenses and other current liabilities		160			158

Total current liabilities		3,078			3,100

Debentures exchangeable into shares of Chevron Corporation common stock		705			692
Other long-term debt		5,252			6,339
Fair value of derivative financial instruments		191			72
Asset retirement obligation, long-term		617			693
Other liabilities		363			366
Deferred income taxes		5,373			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 454,716,000 in 2005 and 483,909,000 in 2004		45			48
Additional paid-in capital		7,645			9,087
Retained earnings		5,543			3,693
Accumulated other comprehensive income		1,343			930
Deferred compensation and other		(66	)		(85	)
Treasury stock at cost: 10,416,000 shares in 2005		(567	)		—

Total stockholders’ equity		13,944			13,674

Total liabilities and stockholders’ equity	$	29,523		$	30,025

See accompanying notes to consolidated financial statements.

6

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
				(Unaudited)
	(In millions, except per share amounts)
Revenues:
Oil sales	$	643		$	559		$	1,908		$	1,679
Gas sales		1,466			1,147			3,913			3,450
NGL sales		190			153			492			393
Marketing and midstream revenues		405			408			1,210			1,202

Total revenues		2,704			2,267			7,523			6,724

Expenses and other income, net:
Lease operating expenses		319			323			1,005			939
Production taxes		81			48			234			182
Marketing and midstream operating costs and expenses		294			319			921			949
Depreciation, depletion and amortization of oil and gas properties		493			532			1,528			1,587
Depreciation and amortization of non-oil and gas properties		40			40			119			109
Accretion of asset retirement obligation		12			11			35			32
General and administrative expenses		70			59			206			206
Interest expense		164			109			428			361
Effects of changes in foreign currency exchange rates		(15	)		(21	)		(4	)		(6	)
Change in fair value of derivative financial instruments		134			47			168			54
Other income, net		(27	)		(17	)		(179	)		(54	)

Total expenses and other income, net		1,565			1,450			4,461			4,359
Earnings before income tax expense		1,139			817			3,062			2,365
Income tax expense:
Current		203			168			832			568
Deferred		192			132			270			284

Total income tax expense		395			300			1,102			852

Net earnings		744			517			1,960			1,513
Preferred stock dividends		2			2			7			7

Net earnings applicable to common stockholders	$	742		$	515		$	1,953		$	1,506


Net earnings per average common share outstanding:
Basic	$	1.66		$	1.06		$	4.22		$	3.13


Diluted	$	1.63		$	1.03		$	4.15		$	3.04


Weighted average common shares outstanding — basic		446			485			463			482

Weighted average common shares outstanding — diluted		454			500			471			498

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)
Nine Months Ended September 30, 2005
Balance as of December 31, 2004	$	1		48			9,087			3,693			930			(85	)		—			13,674
Comprehensive income:
Net earnings		—		—			—			1,960			—			—			—			1,960
Other comprehensive income (loss), net of tax:
Foreign currency translation adjustments		—		—			—			—			193			—			—			193
Reclassification adjustment for derivative losses reclassified into earnings		—		—			—			—			335			—			—			335
Change in fair value of derivative financial instruments		—		—			—			—			(226	)		—			—			(226	)
Unrealized gain on marketable securities		—		—			—			—			111			—			—			111

Other comprehensive income																						413

Comprehensive income																						2,373
Stock issued		—		1			116			—			—			—			—			117
Stock repurchased		—		(4	)		(1,558	)		—			—			—			(567	)		(2,129	)
Dividends on common stock		—		—			—			(103	)		—			—			—			(103	)
Dividends on preferred stock		—		—			—			(7	)		—			—			—			(7	)
Amortization of restricted stock awards		—		—			—			—			—			19			—			19

Balance as of September 30, 2005	$	1		45			7,645			5,543			1,343			(66	)		(567	)		13,944


Nine Months Ended September 30, 2004
Balance as of December 31, 2003	$	1		47			9,043			1,614			569			(32	)		(186	)		11,056
Comprehensive income:
Net earnings		—		—			—			1,513			—			—			—			1,513
Other comprehensive income (loss), net of tax:
Foreign currency translation adjustments		—		—			—			—			129			—			—			129
Reclassification adjustment for derivative losses reclassified into oil and gas sales		—		—			—			—			223			—			—			223
Change in fair value of derivative financial instruments		—		—			—			—			(564	)		—			—			(564	)
Unrealized gain on marketable securities		—		—			—			—			94			—			—			94

Other comprehensive loss																						(118	)

Comprehensive income																						1,395
Stock issued		—		2			237			—			—			—			38			277
Dividends on common stock		—		—			—			(73	)		—			—			—			(73	)
Dividends on preferred stock		—		—			—			(7	)		—			—			—			(7	)
Amortization of restricted stock awards		—		—			—			—			—			7			—			7

Balance as of September 30, 2004	$	1		49			9,280			3,047			451			(25	)		(148	)		12,655

See accompanying notes to consolidated financial statements.

8

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Nine Months Ended
	September 30,
	2005			2004
	(Unaudited)
	(In millions)
Cash flows from operating activities:
Net earnings	$	1,960		$	1,513
Adjustments to reconcile net earnings to net cash provided by operating activities:
Depreciation, depletion and amortization		1,647			1,696
Accretion of asset retirement obligation		35			32
Amortization of premiums on long-term debt, net		(2	)		(4	)
Effects of changes in foreign currency exchange rates		(4	)		(6	)
Non-cash change in fair value of derivative financial instruments		156			54
Deferred income tax expense		270			284
Net gain on sales of non-oil and gas property and equipment		(145	)		(4	)
Other		39			45
Changes in assets and liabilities:
(Increase) decrease in:
Accounts receivable		(164	)		(142	)
Other current assets		(33	)		(22	)
Long-term other assets		28			—
Increase (decrease) in:
Accounts payable		133			176
Income taxes payable		(116	)		212
Accrued interest and expenses		(53	)		(129	)
Long-term debt, including current maturities		(67	)		12
Long-term other liabilities		(32	)		(25	)

Net cash provided by operating activities		3,652			3,692

Cash flows from investing activities:
Proceeds from sale of property and equipment		2,150			20
Capital expenditures		(2,923	)		(2,402	)
Purchases of short-term investments		(3,501	)		(2,442	)
Sales of short-term investments		3,677			2,192

Net cash used in investing activities		(597	)		(2,632	)

Cash flows from financing activities:
Principal payments on long-term debt		(1,023	)		(972	)
Issuance of common stock, net of issuance costs		117			220
Repurchase of common stock		(2,129	)		—
Dividends paid on common stock		(103	)		(73	)
Dividends paid on preferred stock		(7	)		(7	)

Net cash used in financing activities		(3,145	)		(832	)

Effect of exchange rate changes on cash		33			10

Net (decrease) increase in cash and cash equivalents		(57	)		238
Cash and cash equivalents at beginning of period		1,152			932

Cash and cash equivalents at end of period	$	1,095		$	1,170

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 September 30, 2005, and the results of their operations and their cash flows for the three-month and nine-month periods ended September 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 losses of $134 million and $47 million in the third quarter of 2005 and 2004, respectively, and losses of $168 million and $54 million in the nine-month periods ended September 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 do qualify as hedges.

Included in the 2005 amounts are $45 million in losses related to certain derivative financial instruments that no longer qualify for hedge accounting. In the third quarter of 2005, certain oil derivatives ceased to qualify for hedge accounting because the hedged production exceeded actual and projected production under these contracts. The lower than expected production was caused primarily by hurricanes that affected offshore oil production in the Gulf of Mexico. Because these contracts no longer qualify for hedge accounting, Devon recognized in the third quarter of 2005 a $32 million loss for anticipated fourth quarter settlements and $13 million of third quarter 2005 settlements under these oil derivatives as change in fair value of derivative financial instruments in the accompanying statement of operations.

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.

As of September 30, 2005, $234 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 three months (the remaining term of Devon’s derivative instruments). This amount assumes no changes in forward commodity prices from the September 30, 2005 forward prices. Transactions and events expected to occur over the next three 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.

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 nine-month periods ended September 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 September 30, 2005:
Basic earnings per share	$	742		446	$	1.66

Dilutive effect of potential common shares issuable upon the exercise of outstanding stock options		—		8

Diluted earnings per share	$	742		454	$	1.63


Three Months Ended September 30, 2004:
Basic earnings per share	$	515		485	$	1.06

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 $1 million)		2		9
Potential common shares issuable upon the exercise of outstanding stock options		—		6

Diluted earnings per share	$	517		500	$	1.03


Nine Months Ended September 30, 2005:
Basic earnings per share	$	1,953		463	$	4.22

Dilutive effect of potential common shares issuable upon the exercise of outstanding stock options		—		8

Diluted earnings per share	$	1,953		471	$	4.15


Nine Months Ended September 30, 2004:
Basic earnings per share	$	1,506		482	$	3.13

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)		7		9
Potential common shares issuable upon the exercise of outstanding stock options		—		7

Diluted earnings per share	$	1,513		498	$	3.04

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

11

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

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					For the Nine Months Ended
	September 30,					September 30,
	2005			2004		2005			2004
Options excluded from dilution calculation (in millions)		—	⁽¹⁾		2		—	⁽¹⁾		2
Range of exercise prices	$	60.77 - $68.64		$	34.27 - $44.83	$	50.68 - $68.64		$	31.94 - $44.83
Weighted average exercise price	$	61.17		$	37.72	$	54.26		$	37.09


⁽¹⁾		Actual amount of options excluded from the three-months and nine-months ended 2005 dilution calculations are 4,000 shares and 7,000 shares, respectively.

The excluded options for 2005 expire between June 29, 2010 and September 29, 2013.

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 nine-month periods ended September 30, 2005 and 2004 would have differed from the amounts actually reported as shown in the following table.


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
	(In millions, except per share amounts)
Net earnings available to common stockholders, as reported	$	742		$	515		$	1,953		$	1,506
Add stock-based employee compensation expense included in reported earnings, net of related tax expense		4			1			13			5
Deduct total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax expense		(10	)		(6	)		(30	)		(19	)

Net earnings available to common stockholders, pro forma	$	736		$	510		$	1,936		$	1,492


Net earnings per share available to common stockholders:
As reported:
Basic	$	1.66		$	1.06		$	4.22		$	3.13
Diluted	$	1.63		$	1.03		$	4.15		$	3.04
Pro forma:
Basic	$	1.65		$	1.05		$	4.18		$	3.11
Diluted	$	1.62		$	1.02		$	4.11		$	3.02

12

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

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 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. On August 2, 2005, Devon completed this stock buyback program at a total cost of $2.3 billion, or $46.69 per share. Of these amounts, 44.6 million shares were repurchased at a total cost of $2.1 billion during the nine months ended September 30, 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 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. During the third quarter of 2005, Devon did not purchase shares under the new program. Devon began purchasing shares under the new program in the fourth quarter of 2005. As of November 2, 2005, Devon has repurchased 2.2 million shares at a cost of $132 million, or $60.26 per share, under the program announced on August 3, 2005.

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


	Nine Months Ended
	September 30,
	2005			2004
	(In millions)
Shares outstanding, beginning of period		484			472
Exercise of stock options		5			12
Shares repurchased		(45	)		—
Conversion of subsidiary’s preferred stock		—			2

Shares outstanding, end of period		444			486

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

13

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

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

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

On September 12, 2005, Devon redeemed the $400 million 6.75% notes due 2011, using cash on hand. Devon incurred a $51 million premium in conjunction with the early retirement. The $51 million premium is included in interest expense in the accompanying 2005 statement of operations. The after-tax effect of the $51 million premium was $34 million.

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.

6. Supplemental Cash Flow Information

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


	Nine Months Ended
	September 30,
	2005		2004
	(In millions)
Interest paid	$	581	$	408
Income taxes	$	885	$	319

14

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

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 September 30, 2005 and 2004, and changes during each of the nine 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		215			177			—			173			565
Deferred taxes		(22	)		(68	)		—			(62	)		(152	)

2005 activity, net of deferred taxes		193			109			—			111			413

Balance as of September 30, 2005	$	1,248			(177	)		(13	)		285			1,343


Balance as of December 31, 2003	$	667			(135	)		(52	)		89			569
2004 activity		140			(571	)		—			149			(282	)
Deferred taxes		(11	)		230			—			(55	)		164

2004 activity, net of deferred taxes		129			(341	)		—			94			(118	)

Balance as of September 30, 2004	$	796			(476	)		(52	)		183			451

8. Other Income

The components of other income included the following:


	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2005			2004		2005			2004
				(In millions)
Interest and dividend income	$	22		$	12	$	73		$	31
Net (loss) gain on sales of non-oil and gas property and equipment		(5	)		—		145			4
Gain (loss) on early settlement of derivative financial instruments		7			—		(48	)		—
Other		3			5		9			19

Other income, net	$	27		$	17	$	179		$	54

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 such property divestitures and received $2.0 billion of gross proceeds, net of all purchase price adjustments, through the first nine months of 2005. After-tax, the proceeds are approximately $1.8 billion. Certain information regarding these sales is included in the following table.

15

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


	United States		Canada		Total
			($ in millions)
Gross proceeds	$	966	$	1,037	$	2,003
After-tax proceeds	$	760	$	1,035	$	1,795
Asset retirement obligations assumed by purchasers	$	159	$	38	$	197
Reserves sold (MMBoe)		89		79		168

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.

Net Periodic Cost

The following table presents the plans’ net periodic benefit cost for the three-month and nine-month periods ended September 30, 2005 and 2004.


													Other
	Pension Benefits												Post Retirement Benefits
	Three Months						Nine Months						Three Months				Nine Months
	Ended						Ended						Ended				Ended
	September 30,						September 30,						September 30,				September 30,
	2005			2004			2005			2004			2005		2004		2005		2004
	(In millions)
Components of net periodic benefit cost:
Service cost	$	5		$	4		$	15		$	12		$	—	$	—	$	—	$	—
Interest cost		8			8			24			24			1		1		3		3
Expected return on plan assets		(9	)		(8	)		(27	)		(24	)		—		—		—		—
Recognized net actuarial loss		2			2			6			6			—		—		—		—

Net periodic benefit cost	$	6		$	6		$	18		$	18		$	1	$	1	$	3	$	3

Employer Contributions

Devon previously disclosed in its 2004 financial statements that it expected to contribute $6 million to the Qualified and Supplemental Plans and $6 million to the Postretirement Plans in 2005. Devon presently anticipates contributing an additional $72 million to the Qualified and Supplemental Plans in 2005 for a total of $78 million. As of September 30, 2005, Devon has contributed $4 million to the Qualified and Supplemental Plans and $5 million to the Postretirement Plans.

16

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.


					Inter-
	U.S.		Canada		national		Total
			(In millions)
As of September 30, 2005:
Current assets	$	1,905		934		920		3,759
Property and equipment, net of accumulated depreciation, depletion and amortization		10,504		5,711		2,507		18,722
Goodwill		3,061		2,600		68		5,729
Other assets		1,279		18		16		1,313

Total assets	$	16,749		9,263		3,511		29,523


Current liabilities	$	1,889		883		306		3,078
Long-term debt		2,986		2,971		—		5,957
Asset retirement obligation, long-term		324		257		36		617
Other liabilities		523		13		18		554
Deferred income taxes		3,023		1,939		411		5,373
Stockholders’ equity		8,004		3,200		2,740		13,944

Total liabilities and stockholders’ equity	$	16,749		9,263		3,511		29,523


							Inter-
	U.S.			Canada			national			Total
	(In millions)
Three Months Ended September 30, 2005:
Revenues:
Oil sales	$	259			107			277			643
Gas sales		990			465			11			1,466
NGL sales		135			53			2			190
Marketing and midstream revenues		402			3			—			405

Total revenues		1,786			628			290			2,704


Expenses and other income, net:
Lease operating expenses		174			117			28			319
Production taxes		65			1			15			81
Marketing and midstream operating costs and expenses		292			2			—			294
Depreciation, depletion and amortization of oil and gas properties		267			149			77			493
Depreciation and amortization of non-oil and gas properties		35			4			1			40
Accretion of asset retirement obligation		6			5			1			12
General and administrative expenses		60			14			(4	)		70
Interest expense		49			115			—			164
Effects of changes in foreign currency exchange rates		—			(15	)		—			(15	)
Change in fair value of derivative financial instruments		122			12			—			134
Other income, net		(17	)		(6	)		(4	)		(27	)

Total expenses and other income, net		1,053			398			114			1,565
Earnings before income tax expense		733			230			176			1,139
Income tax expense (benefit):
Current		126			11			66			203
Deferred		119			75			(2	)		192

Total income tax expense		245			86			64			395

Net earnings		488			144			112			744
Preferred stock dividends		2			—			—			2

Net earnings applicable to common stockholders	$	486			144			112			742


Capital expenditures	$	544			334			69			947

17

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


							Inter-
	U.S.			Canada			national			Total
				(In millions)
Three Months Ended September 30, 2004:
Revenues:
Oil sales	$	235			83			241			559
Gas sales		786			352			9			1,147
NGL sales		114			37			2			153
Marketing and midstream revenues		405			3			—			408

Total revenues		1,540			475			252			2,267

Expenses and other income, net:
Lease operating expenses		186			108			29			323
Production taxes		39			1			8			48
Marketing and midstream operating costs and expenses		317			2			—			319
Depreciation, depletion and amortization of oil and gas properties		309			127			96			532
Depreciation and amortization of non-oil and gas properties		36			3			1			40
Accretion of asset retirement obligation		7			4			—			11
General and administrative expenses		46			12			1			59
Interest expense		42			67			—			109
Effects of changes in foreign currency exchange rates		—			(21	)		—			(21	)
Change in fair value of derivative financial instruments		48			(1	)		—			47
Other income, net		(11	)		(5	)		(1	)		(17	)

Total expenses and other income, net		1,019			297			134			1,450
Earnings before income tax expense		521			178			118			817
Income tax expense (benefit):
Current		85			22			61			168
Deferred		90			48			(6	)		132

Total income tax expense		175			70			55			300

Net earnings		346			108			63			517
Preferred stock dividends		2			—			—			2

Net earnings applicable to common stockholders	$	344			108			63			515


Capital expenditures	$	502			175			70			747

18

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


							Inter-
	U.S.			Canada			national			Total
				(In millions)
Nine Months Ended September 30, 2005:
Revenues:
Oil sales	$	828			268			812			1,908
Gas sales		2,641			1,240			32			3,913
NGL sales		348			138			6			492
Marketing and midstream revenues		1,201			9			—			1,210

Total revenues		5,018			1,655			850			7,523

Expenses and other income, net:
Lease operating expenses		538			370			97			1,005
Production taxes		189			5			40			234
Marketing and midstream operating costs and expenses		917			4			—			921
Depreciation, depletion and amortization of oil and gas properties		856			427			245			1,528
Depreciation and amortization of non-oil and gas properties		104			11			4			119
Accretion of asset retirement obligation		20			13			2			35
General and administrative expenses		177			41			(12	)		206
Interest expense		180			248			—			428
Effects of changes in foreign currency exchange rates		—			(2	)		(2	)		(4	)
Change in fair value of derivative financial instruments		158			10			—			168
Other income, net		(169	)		(3	)		(7	)		(179	)

Total expenses and other income, net		2,970			1,124			367			4,461
Earnings before income tax expense		2,048			531			483			3,062
Income tax expense (benefit):
Current		588			50			194			832
Deferred		132			159			(21	)		270

Total income tax expense		720			209			173			1,102

Net earnings		1,328			322			310			1,960
Preferred stock dividends		7			—			—			7

Net earnings applicable to common stockholders	$	1,321			322			310			1,953


Capital expenditures	$	1,496			1,267			160			2,923

19

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


							Inter-
	U.S.			Canada			national			Total
				(In millions)
Nine Months Ended September 30, 2004:
Revenues:
Oil sales	$	741			236			702			1,679
Gas sales		2,377			1,049			24			3,450
NGL sales		290			98			5			393
Marketing and midstream revenues		1,193			9			—			1,202

Total revenues		4,601			1,392			731			6,724

Expenses and other income, net:
Lease operating expenses		531			319			89			939
Production taxes		158			4			20			182
Marketing and midstream operating costs and expenses		945			4			—			949
Depreciation, depletion and amortization of oil and gas properties		935			369			283			1,587
Depreciation and amortization of non-oil and gas properties		95			10			4			109
Accretion of asset retirement obligation		21			10			1			32
General and administrative expenses		161			43			2			206
Interest expense		150			210			1			361
Effects of changes in foreign currency exchange rates		—			(5	)		(1	)		(6	)
Change in fair value of derivative financial instruments		56			(2	)		—			54
Other income, net		(39	)		(10	)		(5	)		(54	)

Total expenses and other income, net		3,013			952			394			4,359
Earnings before income tax expense		1,588			440			337			2,365
Income tax expense (benefit):
Current		380			42			146			568
Deferred		189			104			(9	)		284

Total income tax expense		569			146			137			852

Net earnings		1,019			294			200			1,513
Preferred stock dividends		7			—			—			7

Net earnings applicable to common stockholders	$	1,012			294			200			1,506


Capital expenditures	$	1,404			743			255			2,402

20

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 September 30, 2005, Devon’s consolidated balance sheet included $4 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

21

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

proceedings. Trial is set for February 2007 if the suit continues to advance. Devon believes that it has acted reasonably, has legitimate and strong defenses to all allegations in the suit, and has paid royalties in good faith. Devon does not currently believe that it is subject to material exposure in association with this lawsuit and no liability has been recorded in connection therewith.

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 been resolved for amounts immaterial to Devon.

Equatorial Guinea Investigation

As previously disclosed by Devon, the SEC has been conducting an inquiry into payments made to the government of Equatorial Guinea, and to officials and persons affiliated with officials of the government of Equatorial Guinea. On August 9, 2005, Devon received a subpoena issued by the SEC pursuant to a formal order of investigation. Devon has cooperated fully with the SEC’s previous requests for information in this inquiry and plans to continue to work with the SEC in connection with its formal investigation.

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.

Hurricane Contingencies

Devon maintains a comprehensive insurance program that includes coverage for physical damage to its offshore facilities caused by hurricanes. Its insurance program also includes substantial business interruption coverage which Devon expects to utilize to recover costs associated with the suspended production. Under the terms of the insurance program, Devon is entitled to be reimbursed for the portion of production suspended longer than forty-five days, subject to upper limits to oil and natural gas prices. Also, the terms of the insurance include a standard, per-event deductible of $1 million for offshore losses as well as a $15 million aggregate annual deductible. Devon expects its insurance claims will exceed these deductible amounts. However, based on current estimates of physical damage and the anticipated length of time Devon will have its production suspended, Devon expects its policy limits will be sufficient to cover all costs beyond these deductible amounts.

22

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 nine-month periods ended September 30, 2005, compared to the three-month and nine-month periods ended September 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 third quarter of 2005 were $744 million, or $1.63 per diluted share. This compares to net earnings of $517 million, or $1.03 per diluted share for the third quarter of 2004. Net earnings for the first nine months of 2005 were $2.0 billion, or $4.15 per diluted share. This compares to net earnings of $1.5 billion, or $3.04 per diluted share for the first nine months of 2004. Positive factors driving the increase in the 2005 third quarter and first nine months 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 due to 2005 property divestitures, a loss on oil hedges related to such divestitures, deferred production from the effects of hurricanes, additional interest expense related to the early redemption of $827 million of long-term debt, additional income tax expense on the repatriation of earnings from Canadian operations and higher operating expenses.

Cash flow from operations was relatively flat at $3.7 billion in the first nine months of 2004 and the first nine months of 2005. Although net earnings increased, 2005 cash flow from operations was negatively impacted by higher payments for current income taxes due to the taxable gains from property divestitures and the payment of five years of accumulated interest upon 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 nine months of 2005. These sources of cash allowed Devon to fund $2.9 billion of capital expenditures, repurchase $2.1 billion in common stock and repay $1.0 billion in debt during the first nine months of 2005. On August 2, 2005, Devon completed its previously announced plan to repurchase 50 million shares, and the total cost of the repurchases was $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. As of November 2, 2005, Devon has repurchased 2.2 million shares under the new share repurchase program.

Devon 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. During the first nine months of 2005, Devon sold all of the properties offered for sale. Gross proceeds from the divestitures totaled approximately $2.0 billion net of all purchase price adjustments. After-tax, the proceeds were approximately $1.8 billion.

During the first nine months of 2005, Devon drilled 228 exploration wells, of which 86% were completed as successful, and 1,609 development wells, of which 99% were completed as successful. As a result of this exploration and development activity, Devon has recorded 260 million barrels of proved reserves in the first nine months 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.

23

Results of Operations

Total revenues increased $437 million, or 19%, in the third quarter of 2005, and $799 million, or 12%, in the first nine months 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, effects of hurricanes and natural declines partially offset by new drilling and development.

Oil, natural gas and NGL revenues were up $440 million, or 24%, for the third quarter of 2005 compared to the third quarter of 2004, and $791 million, or 14%, for the first nine months of 2005 compared to the first nine months of 2004. The three-month and nine-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 September 30,							Nine Months Ended September 30,
	2005		2004		Change ²			2005		2004		Change ²
Production
Oil (MMBbls)		15		19		-23	%		50		59		-16	%
Gas (Bcf)		205		222		-7	%		628		668		-6	%
NGLs (MMBbls)		6		6		-6	%		18		18		-1	%

Oil, Gas and NGLs (MMBoe)¹		55		62		-12	%		173		189		-8	%

Average Prices
Oil (Per Bbl)	$	43.45	$	29.19		+49	%	$	38.10	$	28.32		+35	%
Gas (Per Mcf)		7.13		5.17		+38	%		6.23		5.17		+21	%
NGLs (Per Bbl)		32.23		24.36		+32	%		27.48		21.72		+27	%

Oil, Gas and NGLs (Per Boe)¹		41.81		29.78		+40	%		36.55		29.27		+25	%

Revenues ($ in millions)
Oil	$	643	$	559		+15	%	$	1,908	$	1,679		+14	%
Gas		1,466		1,147		+28	%		3,913		3,450		+13	%
NGLs		190		153		+24	%		492		393		+25	%

Combined	$	2,299	$	1,859		+24	%	$	6,313	$	5,522		+14	%

24


	Domestic
	Three Months Ended September 30,							Nine Months Ended September 30,
	2005		2004		Change ²			2005		2004		Change ²
Production
Oil (MMBbls)		5		7		-26	%		20		24		-17	%
Gas (Bcf)		136		150		-9	%		421		452		-7	%
NGLs (MMBbls)		4		5		-9	%		14		14		-4	%

Oil, Gas and NGLs (MMBoe)¹		32		37		-12	%		104		114		-9	%

Average Prices
Oil (Per Bbl)	$	46.48	$	31.27		+49	%	$	40.85	$	30.45		+34	%
Gas (Per Mcf)		7.25		5.24		+38	%		6.27		5.26		+19	%
NGLs (Per Bbl)		29.93		23.04		+30	%		25.23		20.28		+24	%

Oil, Gas and NGLs (Per Boe)¹		42.14		30.29		+39	%		36.61		29.89		+22	%

Revenues ($ in millions)
Oil	$	259	$	235		+10	%	$	828	$	741		+12	%
Gas		990		786		+26	%		2,641		2,377		+11	%
NGLs		135		114		+19	%		348		290		+20	%

Combined	$	1,384	$	1,135		+22	%	$	3,817	$	3,408		+12	%


	Canada
	Three Months Ended September 30,							Nine Months Ended September 30,
	2005		2004		Change ²			2005		2004		Change ²
Production
Oil (MMBbls)		4		4		-10	%		10		10		-5	%
Gas (Bcf)		67		70		-5	%		200		209		-4	%
NGLs (MMBbls)		2		1		+4	%		4		4		+8	%

Oil, Gas and NGLs (MMBoe)¹		16		17		-5	%		47		49		-3	%

Average Prices
Oil (Per Bbl)	$	33.89	$	23.71		+43	%	$	27.15	$	22.75		+19	%
Gas (Per Mcf)		6.97		5.02		+39	%		6.21		5.04		+23	%
NGLs (Per Bbl)		40.86		29.71		+38	%		35.76		27.52		+30	%

Oil, Gas and NGLs (Per Boe)¹		40.12		28.74		+40	%		35.02		28.43		+23	%

Revenues ($ in millions)
Oil	$	107	$	83		+28	%	$	268	$	236		+14	%
Gas		465		352		+32	%		1,240		1,049		+18	%
NGLs		53		37		+43	%		138		98		+41	%

Combined	$	625	$	472		+32	%	$	1,646	$	1,383		+19	%

25


	International
	Three Months Ended September 30,							Nine Months Ended September 30,
	2005		2004		Change ²			2005		2004		Change ²
Production
Oil (MMBbls)		6		8		-26	%		20		25		-19	%
Gas (Bcf)		2		2		+23	%		7		7		+7	%
NGLs (MMBbls)		—		—		+4	%		—		—		+4	%

Oil, Gas and NGLs (MMBoe)¹		7		8		-23	%		22		26		-18	%

Average Prices
Oil (Per Bbl)	$	45.62	$	29.63		+54	%	$	40.72	$	28.56		+43	%
Gas (Per Mcf)		4.65		4.73		-2	%		4.18		3.37		+24	%
NGLs (Per Bbl)		21.07		21.11		—			23.36		21.12		+11	%

Oil, Gas and NGLs (Per Boe)¹		44.20		29.50		+50	%		39.60		28.11		+41	%

Revenues ($ in millions)
Oil	$	277	$	241		+15	%	$	812	$	702		+16	%
Gas		11		9		+21	%		32		24		+32	%
NGLs		2		2		+4	%		6		5		+15	%

Combined	$	290	$	252		+15	%	$	850	$	731		+16	%


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.

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 nine-month periods ended September 30, 2005 and 2004.


	With Hedges				Without Hedges
	Three Months Ended				Three Months Ended
	September 30,				September 30,
	2005		2004		2005		2004
Oil (per Bbl)	$	43.45	$	29.19	$	56.51	$	39.06
Gas (per Mcf)	$	7.13	$	5.17	$	7.25	$	5.23
NGLs (per Bbl)	$	32.23	$	24.36	$	32.23	$	24.36
Oil, Gas and NGLs (per Boe)	$	41.81	$	29.78	$	45.82	$	33.04


	With Hedges				Without Hedges
	Nine Months Ended				Nine Months Ended
	September 30,				September 30,
	2005		2004		2005		2004
Oil (per Bbl)	$	38.10	$	28.32	$	47.83	$	34.64
Gas (per Mcf)	$	6.23	$	5.17	$	6.32	$	5.22
NGLs (per Bbl)	$	27.48	$	21.72	$	27.48	$	21.72
Oil, Gas and NGLs (per Boe)	$	36.55	$	29.72	$	39.73	$	31.45

26

Oil Revenues. Oil revenues increased $84 million in the third quarter of 2005. Oil revenues increased $211 million due to a $14.26 per barrel increase in Devon’s realized average price of oil. A decrease in the third quarter 2005 production of 4 million barrels caused oil revenues to decrease by $127 million. Production lost from the 2005 property divestitures accounted for 2 million barrels of the decrease. Devon also suspended certain domestic oil production in the third quarters of 2005 and 2004 due to the effects of Hurricanes Katrina, Rita, Dennis and Ivan. The 2005 quarter over 2004 quarter impact accounted for 1 million barrels of deferred oil production. The remainder of the decrease is due to certain international properties for which we are receiving fewer volumes after recovering our costs under the production sharing contracts partially offset by new drilling and development.

Oil revenues increased $229 million in the first nine months of 2005. Oil revenues increased $490 million due to a $9.78 per barrel increase in Devon’s realized average price of oil. A decrease in production of 9 million barrels caused oil revenues to decrease by $261 million. Production lost from the 2005 property divestitures caused a decrease of 5 million barrels. Suspended domestic oil production due to the effects of Hurricanes Katrina, Rita, Dennis and Ivan was 1 million barrels greater in 2005. In addition, production decreased due to certain international properties for which we are receiving fewer volumes after recovering our costs under the production sharing contracts.

Gas Revenues. Gas revenues increased $319 million in the third quarter of 2005. Gas revenues increased $403 million due to a $1.96 per Mcf increase in Devon’s realized average price of gas. A decrease in production of 17 Bcf caused gas revenues to decrease by $84 million. Production lost from the 2005 property divestitures caused a decrease of 29 Bcf. Devon also suspended certain domestic gas production in the third quarters of 2005 and 2004, respectively, due to the effects of Hurricanes Katrina, Rita, Dennis and Ivan. The quarter over quarter impact accounted for 5 Bcf of deferred production. These decreases were partially offset by new drilling and development and increased performance in U.S. offshore and onshore properties.

Gas revenues increased $463 million in the first nine months of 2005. Gas revenues increased $665 million due to a $1.06 per Mcf increase in Devon’s realized average price of gas. A decrease in production of 40 Bcf caused gas revenues to decrease by $202 million. Production lost from the 2005 property divestitures caused a decrease of 62 Bcf. Suspended domestic gas production due to the effects of Hurricanes Katrina, Rita, Dennis and Ivan was 5 Bcf greater 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 $37 million in the third quarter of 2005. A $7.87 per barrel increase in Devon’s realized average NGL price in the third quarter of 2005 increased NGL revenues by $46 million. A slight decrease in production due to 2005 property divestitures and the effects of Hurricanes Katrina, Rita and Dennis caused NGL revenues to decrease by $9 million.

NGL revenues increased $99 million in the first nine months of 2005. A $5.76 per barrel increase in Devon’s realized average NGL price in the first nine months of 2005 increased NGL revenues by $103 million. A slight decrease in production due to 2005 property divestitures and the effects of Hurricanes Katrina, Rita and Dennis caused NGL revenues to decrease by $4 million.

Marketing and Midstream Revenues. Marketing and midstream revenues decreased $3 million in the third quarter of 2005. Revenues decreased $110 million due to the sale of certain assets in 2004 and 2005. Also, revenues decreased $35 million due to lower NGL marketed volumes resulting from the effects of Hurricane Rita. These decreases were partially offset by a $30 million increase due to higher third-party volumes and a $112 million increase due to higher natural gas and NGL prices.

Marketing and midstream revenues increased $8 million in the first nine months of 2005. Revenues increased $230 million due to higher natural gas and NGL prices and $87 million due to higher

27

gas pipeline volumes. These increases were partially offset by a $35 million decrease caused by lower NGL marketed volumes due to Hurricane Rita and the $274 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							Nine Months Ended
	September 30,							September 30,
	2005		2004		Change ¹			2005		2004		Change ¹
Expenses ($ in millions)
Lease operating expenses	$	319	$	323		-1	%	$	1,005	$	939		+7	%
Production taxes		81		48		+67	%		234		182		+29	%

Total production and operating expenses	$	400	$	371		+8	%	$	1,239	$	1,121		+11	%


Expenses Per Boe
Lease operating expenses	$	5.80	$	5.17		+12	%	$	5.82	$	4.98		+17	%
Production taxes		1.48		0.78		+90	%		1.36		0.96		+42	%

Total production and operating expenses	$	7.28	$	5.95		+22	%	$	7.18	$	5.94		+21	%


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 decreased $4 million in the third quarter of 2005. Lease operating costs decreased $54 million due to properties that were sold in 2005. The decrease was partially offset by increases 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 third quarter 2004 to third quarter 2005, resulted in a $9 million increase in costs.

Lease operating expenses increased $66 million in the first nine months 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 nine months of 2004 to the first nine months of 2005, resulted in a $26 million increase in costs. Partially offsetting these increases was a decrease of $90 million for lease operating expenses related to properties that were sold in 2005.

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

Production taxes increased $33 million in third quarter of 2005 and $52 million in the first nine months of 2005. Production taxes increased generally due to higher oil, gas and NGL revenues, as well as higher Russian export tax rates. The third quarter increase also resulted from an $18 million adjustment recognized in the third quarter of 2004, but related to prior periods, for severance tax rate reductions on wells in the Barnett Shale.

28

Marketing and Midstream Operating Costs and Expenses. Marketing and midstream operating costs and expenses decreased $25 million in the third quarter of 2005. The sale of certain assets in 2004 and 2005 caused costs and expenses to decrease $96 million. Also, costs and expenses decreased $32 million due to lower NGL marketed volumes resulting from the effects of Hurricane Rita. These decreases were partially offset by a $26 million increase due to higher third-party volumes and a $77 million increase primarily due to higher natural gas and NGL purchase prices.

Marketing and midstream operating costs and expenses decreased $28 million in the first nine months of 2005. The sale of certain assets in 2004 and 2005 caused costs and expenses to decrease $243 million. Also, Hurricane Rita caused a $32 million decrease due to lower NGL marketed volumes. These decreases were partially offset by a $165 million increase due to higher natural gas and NGL purchase prices and a $82 million increase due to 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 $39 million in the third quarter of 2005. DD&A decreased $63 million due to a 12% decrease in the combined oil, gas and NGL production in the third quarter of 2005. This decrease was partially offset by an increase in the combined U.S., Canadian and international DD&A rate from $8.53 per Boe in the third quarter of 2004 to $8.96 per Boe in the third quarter of 2005 which caused oil and gas property DD&A to increase by $24 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 third quarter 2004 rate of $8.53.

Oil and gas property DD&A decreased $59 million in the first nine months of 2005. DD&A decreased $134 million due to an 8% decrease in the combined oil, gas and NGL production in the first nine months of 2005. This decrease was partially offset by an increase in the combined U.S., Canadian and international DD&A rate from $8.41 per Boe in the first nine months of 2004 to $8.85 per Boe in the first nine months of 2005 which caused oil and gas property DD&A to increase by $75 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.

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.

29


	Three Months						Nine Months
	Ended						Ended
	September 30,						September 30,
	2005			2004			2005			2004
				(In millions)
Gross G&A	$	140		$	124		$	420		$	400
Capitalized G&A		(44	)		(40	)		(135	)		(125	)
Reimbursed G&A		(26	)		(25	)		(79	)		(69	)


Net G&A	$	70		$	59		$	206		$	206

Gross G&A increased $16 million in the third quarter of 2005 and $20 million in the first nine months of 2005 compared to the same periods of 2004. Increases in compensation and benefits were the primary causes of the increases for both the third quarter and the nine-month periods. Also, changes in the Canadian-to-U.S. dollar exchange rate, from the first nine months of 2004 to the same period of 2005, resulted in an $8 million increase in costs.

Capitalized G&A increased $4 million and $10 million in the third quarter and first nine months of 2005, respectively, due to increases in capitalizable salaries and benefits. The $1 million and $10 million increases in reimbursed G&A during the third quarter and first nine months of 2005, respectively, are primarily related to an increase in reimbursement rates.

Interest Expense. The following schedule includes the components of interest expense for the third quarter and first nine months of 2005 and 2004.


	Three Months						Nine Months
	Ended						Ended
	September 30,						September 30,
	2005			2004			2005			2004
				(In millions)
Interest based on debt outstanding	$	126		$	124		$	391		$	384
Amortization of discounts/premiums		1			1			2			1
Facility and agency fees		1			—			2			1
Amortization of capitalized loan costs		—			1			6			22
Capitalized interest		(16	)		(18	)		(53	)		(52	)
Loss on extinguishment of debt		51			—			76			—
Other		1			1			4			5


Total interest expense	$	164		$	109		$	428		$	361

The average debt balance decreased from $7.9 billion in the third quarter of 2004 to $7.2 billion in the 2005 quarter due to debt repayments during 2004 and 2005. This decrease in debt outstanding caused interest expense to decrease $12 million. This decrease in interest expense was offset by a $14 million increase due to higher floating rates in 2005. The average interest rate on outstanding debt increased from 6.2% in the third quarter of 2004 to 6.9% in the third quarter of 2005.

Other items included in interest expense that are not related to the debt balance outstanding were $53 million higher in the third quarter of 2005. Of this increase, $51 million related to the premium incurred for the early redemption of the $400 million 6.75% notes due March 15, 2011.

The average debt balance decreased from $8.3 billion in the first nine months of 2004 to $7.7 billion in the first nine months of 2005 due to debt repayments during 2004 and 2005. This decrease in debt outstanding caused interest expense to decrease $28 million. This decrease in interest expense was offset by a $35 million increase due to higher floating rates in 2005. The average interest rate on outstanding debt increased from 6.2% in the first nine months of 2004 to 6.8% in the first nine months of 2005.

30

Other items included in interest expense that are not related to the debt balance outstanding were $60 million higher in the first nine months of 2005. Of this increase, $51 million related to the early retirement premium for the redemption of the $400 million 6.75% notes and $25 million related to the loss on the early redemption of the zero coupon convertible senior debentures. In conjunction with the early redemption of the senior debentures, 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.

Effects of Changes in Foreign Currency Exchange Rates. Devon’s Canadian subsidiary had $400 million 6.75% senior notes which were denominated in U.S. dollars. Changes in the exchange rate between the U.S. dollar and the Canadian dollar while the notes were outstanding increased or decreased 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.

The changes in the Canadian-to-U.S. dollar exchange rate from $0.8308 at December 31, 2004 and $0.8159 at June 30, 2005 to $0.8503 at the redemption date of the Canadian senior notes and $0.8613 at September 30, 2005 resulted in gains of $15 million and $9 million in the third quarter and the first nine months of 2005, respectively. Also in 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 2005. The changes in the Canadian-to-U.S. dollar exchange rate from $0.7738 at December 31, 2003 and $0.7460 at June 30, 2004 to $0.7912 at September 30, 2004 resulted in gains of $21 million and $5 million in the third quarter and first nine months of 2004, respectively.

Changes in Fair Value of Derivative Financial Instruments. The loss associated with the change in fair value of derivative financial instruments increased $87 million in the third quarter of 2005 and increased $114 million in the first nine months of 2005. Changes in the fair value of the option embedded in the debentures exchangeable into shares of Chevron Corporation common stock increased $43 million and $68 million in the third quarter and the first nine months of 2005, respectively. Also, during the third quarter of 2005, Devon recognized a $45 million loss on certain oil derivative financial instruments that no longer qualify for hedge accounting because the hedged production exceeded actual and projected production under these contracts. The lower than expected production was caused primarily by hurricanes that affected offshore production in the Gulf of Mexico.

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


	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2005			2004		2005			2004
				(In millions)
Interest and dividend income	$	22		$	12	$	73		$	31
Net (loss) gain on sales of non-oil and gas property and equipment		(5	)		—		145			4
Gain (loss) on early settlement of derivative financial instruments		7			—		(48	)		—
Other		3			5		9			19

Other income, net	$	27		$	17	$	179		$	54

31

The increases in interest and dividend income in the third quarter and first nine months of 2005 were primarily due to an increase in cash and short-term investment balances and higher interest rates.

The increase in the net gain on sales of non-oil and gas property and equipment in the first nine months of 2005 is related to the sale of certain midstream assets in January 2005.

The loss on derivative financial instruments in the first nine months of 2005 related to commodity hedges and interest rate swaps 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. The early settlement of the interest rate swaps in 2005 related to the fixed-to-floating interest rate swaps that were settled in conjunction with the early redemption of the $400 million 6.75% senior notes in September 2005.

Income Taxes. During interim periods, income tax expense is based on the estimated effective income tax rates that are expected for the entire fiscal year from Devon’s applicable tax jurisdictions. The estimated effective tax rate was 35% in the third quarter of 2005 and 37% in the third quarter of 2004. The estimated effective tax rate was 36% in the first nine months of both 2005 and 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 was 35%.

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


	Nine Months Ended
	September 30,
	2005			2004
	(In millions)
Cash provided by (used in):
Operating activities	$	3,652		$	3,692
Investing activities		(597	)		(2,632	)
Financing activities		(3,145	)		(832	)
Effect of exchange rate changes		33			10

Net (decrease) increase in cash and cash equivalents	$	(57	)	$	238

Cash and cash equivalents at end of period	$	1,095		$	1,170

Short-term investments at end of period	$	791		$	591

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 nine months of 2005. Operating cash flow remained constant at $3.7 billion in the first nine months of 2005 compared to the first nine months of 2004. Although net earnings increased $447 million from 2004 to 2005, cash paid for taxes increased $566 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 in the second quarter of 2005. This $75 million equals the amount of interest accrued on these debentures since their issuance in June 2000.

32

Cash Flows from Investing Activities

Net cash used in investing activities was $597 million in the first nine months of 2005 compared to net cash used of $2.6 billion in the first nine months of 2004. The decrease in net cash used in investing activities was primarily related to an increase in proceeds from the sale of property and equipment partially offset by an increase in capital expenditures.

Capital expenditures in the first nine months of 2005 were $2.9 billion. This total includes $2.8 billion for the acquisition, drilling or development of oil and gas properties. These amounts compare to capital expenditures of $2.4 billion in the first nine months of 2004 which included $2.3 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 nine months of 2005 and first nine months 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 nine months of 2005 was $3.1 billion compared to $832 million in the first nine months of 2004. The increase in cash used in financing activities from 2004 to 2005 was primarily related to repurchases of common stock in 2005. In conjunction with the stock buyback program announced September 27, 2004, Devon repurchased during the first nine months of 2005 approximately 44.6 million shares at a total cost of $2.1 billion, or $47.69 per share. 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 $2.3 billion, or $46.69 per share.

During the first nine months of 2005, Devon paid $1.0 billion to redeem the zero coupon convertible debentures and the $400 million 6.75% notes due in March 2011 before their scheduled maturities, and to retire the $125 million 7.625% notes and the $143 million ($175 million Canadian) 7.25% senior notes upon their scheduled maturities in July 2005. During the first nine months of 2004, Devon paid $972 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 balance outstanding on the $3 billion term loan credit facility.

Devon received $117 million and $220 million from shares issued for stock options exercised during 2005 and 2004, respectively.

Devon’s common stock dividends were $103 million and $73 million in the first nine months of 2005 and 2004, respectively. Devon also paid $7 million of preferred stock dividends in the first nine months 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 September 30, 2005, Devon’s unrestricted cash and cash equivalents and short-term investments totaled $1.9 billion. During the first nine months of 2005 and 2004, such balances decreased $233 million and increased $488 million, respectively.

33

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 divestitures of certain non-core oil and gas properties that were completed in the third quarter of 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.

Furthermore, we expect no material impact on our liquidity as a result of the effects of hurricanes on our operations. Devon maintains a comprehensive insurance program that includes coverage for physical damage to its offshore facilities caused by hurricanes. Its insurance program also includes substantial business interruption coverage which Devon expects to utilize to recover costs associated with the suspended production. Under the terms of the insurance program, Devon is entitled to be reimbursed for the portion of production suspended longer than forty-five days, subject to upper limits to oil and natural gas prices. Also, the terms of the insurance include a standard, per-event deductible of $1 million for offshore losses as well as a $15 million aggregate annual deductible. Devon expects its insurance claims will exceed these deductible amounts. However, based on current estimates of physical damage and the anticipated length of time Devon will have its production suspended, Devon expects its policy limits will be sufficient to cover all costs beyond these deductible amounts.

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 September 30, 2005.


			Price		Fixed-Price
	Price		Swap		Physical
	Collars		Contracts		Delivery Contracts		Total
Oil production (MMBbls)
2005 (last three months of the year)		4		2		—		6
Natural gas production (Bcf)
2005 (last three months of the year)		3		1		5		9
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.

34

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 September 30, 2005, there were no borrowings under the Senior Credit Facility. The available capacity under the Senior Credit Facility as of September 30, 2005, net of $259 million of outstanding letters of credit, was approximately $1.2 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 September 30, 2005, Devon’s ratio as calculated pursuant to this covenant was 29.2%.

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 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 September 30, 2005.

35

Common Stock Buyback Programs

On August 3, 2005, Devon announced that it completed the 50 million stock repurchase program authorized in 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. As of November 2, 2005, Devon had repurchased 2.2 million shares under the new program for $132 million.

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.

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 September 30, 2005, there have been no material changes in Devon’s market risk exposure except as discussed below regarding commodity price 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

36

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 September 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	Oct - Dec
Canada		3,000	$	27.13	Oct - Dec
International		6,000	$	25.88	Oct - Dec

Gas Production

Months of

Area

Mcf/Day

Price/Mcf

Production

United States Onshore

7,285

$

3.40

Oct - 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

37

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 September 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	Oct - Dec
Canada		15,000	$	22.00	$	28.28	Oct - Dec
International		15,000	$	23.50	$	29.61	Oct - Dec

Gas Production

Weighted Average

Floor

Ceiling

Price Per

Months of

Area

MMBtu/Day

MMBtu

Production

United States Offshore

40,000

$

3.50

$

7.50

Oct - 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 September 30, 2005, a 10% increase in the underlying commodity prices would have increased the net liabilities recorded for Devon’s commodity hedging instruments by $33 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.

38

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

39

Part II. Other Information

Item 1. Legal Proceedings

As previously disclosed by Devon, the SEC has been conducting an inquiry into payments made to the government of Equatorial Guinea, and to officials and persons affiliated with officials of the government of Equatorial Guinea. On August 9, 2005, Devon received a subpoena issued by the SEC pursuant to a formal order of investigation. Devon has cooperated fully with the SEC’s previous requests for information in this inquiry and plans to continue to work with the SEC in connection with its formal investigation.

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 third 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⁾
July		9,249,400	$	54.14		9,249,400		1,516,000
August		1,163,400	$	57.21		1,163,400		—
September		—				—		—

Total		10,412,800	$	54.49		10,412,800


⁽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. No shares were repurchased under this plan during the third quarter of 2005.

Item 3. Defaults Upon Senior Securities

None

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

None

Item 5. Other Information

None

40

Item 6. Exhibits

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


Exhibit
Number

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.

41

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: November 3, 2005		/s/ Danny J. Heatly

		Danny J. Heatly
		Vice President — Accounting and
		Chief Accounting Officer

42

INDEX TO EXHIBITS


Exhibit
Number

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.

Devon Energy - 10-Q quarterly report FY

What is the market capitalization of a company?

DISCLAIMER

Contact

Links