DEVON ENERGY CORP/DE - 10-Q Quarterly Report

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 March 31, 2005


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

20 North Broadway
Oklahoma City, Oklahoma		73102-8260
(Address of Principal Executive Offices)		(Zip Code)

Registrant’s telephone number, including area code:
(405) 235-3611

Former name, former address and former fiscal year, if changed from last report.
Not applicable

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

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

The number of shares outstanding of Registrant’s common stock, par value $0.10, as of March 31, 2005, was 473,735,159.

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.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


	March 31,			December 31,
	2005			2004
	(Unaudited)
	(In millions, except share data)
ASSETS
Current assets:
Cash and cash equivalents	$	1,499		$	1,152
Short-term investments		1,033			967
Accounts receivable		1,364			1,320
Fair value of derivative financial instruments		—			1
Deferred income taxes		317			289
Other current assets		152			143

Total current assets		4,365			3,872

Property and equipment, at cost, based on the full cost method of accounting for oil and gas properties ($3,123 and $3,187 excluded from amortization in 2005 and 2004, respectively)		32,795			32,114
Less accumulated depreciation, depletion and amortization		13,316			12,768

		19,479			19,346
Investment in ChevronTexaco Corporation common stock, at fair value		827			745
Fair value of derivative financial instruments		—			8
Goodwill		5,624			5,637
Other assets		381			417

Total assets	$	30,676		$	30,025

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable:
Trade	$	937		$	715
Revenues and royalties due to others		451			487
Income taxes payable		428			223
Current portion of long-term debt		932			933
Accrued interest payable		97			139
Fair value of derivative financial instruments		562			399
Current portion of asset retirement obligation		68			46
Accrued expenses and other current liabilities		285			158

Total current liabilities		3,760			3,100

Debentures exchangeable into shares of ChevronTexaco Corporation common stock		696			692
Other long-term debt		6,312			6,339
Fair value of derivative financial instruments		129			72
Asset retirement obligation, long-term		685			693
Other liabilities		379			366
Deferred income taxes		5,081			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 473,735,159 in 2005 and 483,909,000 in 2004		47			48
Additional paid-in capital		8,588			9,087
Retained earnings		4,218			3,693
Accumulated other comprehensive income		858			930
Deferred compensation and other		(78	)		(85	)

Total stockholders’ equity		13,634			13,674

Total liabilities and stockholders’ equity	$	30,676		$	30,025

See accompanying notes to consolidated financial statements.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS


	Three Months Ended March 31,
	2005			2004
	(Unaudited)
	(In millions, except per share amounts)
Revenues:
Oil sales	$	615		$	581
Gas sales		1,175			1,121
NGL sales		145			119
Marketing and midstream revenues		416			417

Total revenues		2,351			2,238

Expenses and other income, net:
Lease operating expenses		348			310
Production taxes		78			62
Marketing and midstream operating costs and expenses		331			332
Depreciation, depletion and amortization of oil and gas properties		541			538
Depreciation and amortization of non-oil and gas properties		38			34
Accretion of asset retirement obligation		12			11
General and administrative expenses		58			77
Interest expense		118			118
Effects of changes in foreign currency exchange rates		—			6
Change in fair value of derivative financial instruments		52			(4	)
Other income, net		(138	)		(22	)

Total expenses and other income, net		1,438			1,462
Earnings before income tax expense		913			776
Income tax expense (benefit):
Current		352			203
Deferred		(2	)		79

Total income tax expense		350			282

Net earnings		563			494
Preferred stock dividends		2			2

Net earnings applicable to common stockholders	$	561		$	492


Net earnings per average common share outstanding:
Basic	$	1.17		$	1.03


Diluted	$	1.14		$	1.00


Weighted average common shares outstanding – basic		480			478

Weighted average common shares outstanding – diluted		496			493

See accompanying notes to consolidated financial statements.

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)
Three Months Ended March 31, 2005
Balance as of December 31, 2004	$	1		48			9,087			3,693			930			(85	)		—			13,674
Comprehensive income:
Net earnings		—		—			—			563			—			—			—			563
Other comprehensive income (loss), net of tax:
Foreign currency translation adjustments¹		—		—			—			—			(26	)		—			—			(26	)
Reclassification adjustment for derivative losses reclassified into oil and gas sales²		—		—			—			—			92			—			—			92
Change in fair value of derivative financial instruments³		—		—			—			—			(191	)		—			—			(191	)
Unrealized gain on marketable securities⁴		—		—			—			—			53			—			—			53

Other comprehensive loss																						(72	)

Comprehensive income																						491
Stock issued		—		—			57			—			—			—			—			57
Stock repurchased and retired		—		(1	)		(556	)		—			—			—			—			(557	)
Dividends on common stock		—		—			—			(36	)		—			—			—			(36	)
Dividends on preferred stock		—		—			—			(2	)		—			—			—			(2	)
Amortization of restricted stock awards		—		—			—			—			—			7			—			7

Balance as of March 31, 2005	$	1		47			8,588			4,218			858			(78	)		—			13,634


Three Months Ended March 31, 2004
Balance as of December 31, 2003	$	1		47			9,043			1,614			569			(32	)		(186	)		11,056
Comprehensive income:
Net earnings		—		—			—			494			—			—			—			494
Other comprehensive income (loss), net of tax:
Foreign currency translation adjustments⁵		—		—			—			—			(61	)		—			—			(61	)
Reclassification adjustment for derivative losses reclassified into oil and gas sales⁶		—		—			—			—			43			—			—			43
Change in fair value of derivative financial instruments⁷		—		—			—			—			(148	)		—			—			(148	)
Unrealized gain on marketable securities⁸		—		—			—			—			6			—			—			6

Other comprehensive loss																						(160	)

Comprehensive income																						334
Stock issued		—		1			107			—			—			—			—			108
Conversion of preferred stock of a subsidiary		—		—			—			—			—			—			56			56
Dividends on common stock		—		—			—			(24	)		—			—			—			(24	)
Dividends on preferred stock		—		—			—			(2	)		—			—			—			(2	)
Amortization of restricted stock awards		—		—			—			—			—			2			—			2

Balance as of March 31, 2004	$	1		48			9,150			2,082			409			(30	)		(130	)		11,530


¹ net of income tax benefit of:	$	2

² net of income tax expense of:		(50	)

³ net of income tax benefit of:		103

⁴ net of income tax expense of:		(30	)

⁵ net of income tax benefit of:		7

⁶ net of income tax expense of:		(29	)

⁷net of income tax benefit of:		95

⁸ net of income tax expense of:		(4	)

See accompanying notes to consolidated financial statements.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Three Months Ended March 31,
	2005			2004
	(Unaudited)
	(In millions)
Cash flows from operating activities:
Net earnings	$	563		$	494
Adjustments to reconcile net earnings to net cash provided by operating activities:
Depreciation, depletion and amortization		579			572
Accretion of asset retirement obligation		12			11
Accretion of discounts on long-term debt, net		3			4
Effects of changes in foreign currency exchange rates		—			6
Change in fair value of derivative financial instruments		52			(4	)
Deferred income tax (benefit) expense		(2	)		79
Gain on sale of non-oil and gas property and equipment		(150	)		(4	)
Other		12			8
Changes in assets and liabilities:
(Increase) decrease in:
Accounts receivable		(44	)		(117	)
Other current assets		(8	)		3
Long-term other assets		32			—
Increase (decrease) in:
Accounts payable		51			102
Income taxes payable		205			194
Accrued interest and expenses		82			(112	)
Long-term other liabilities		1			(13	)

Net cash provided by operating activities		1,388			1,223

Cash flows from investing activities:
Proceeds from sale of property and equipment		432			11
Capital expenditures		(867	)		(890	)
Purchases of short-term investments		(1,147	)		(731	)
Sales of short-term investments		1,081			693

Net cash used in investing activities		(501	)		(917	)

Cash flows from financing activities:
Principal payments on long-term debt		—			(211	)
Issuance of common stock, net of issuance costs		57			108
Repurchase of common stock		(557	)		—
Dividends paid on common stock		(36	)		(24	)
Dividends paid on preferred stock		(2	)		(2	)

Net cash used in financing activities		(538	)		(129	)

Effect of exchange rate changes on cash		(2	)		(7	)

Net increase in cash and cash equivalents		347			170
Cash and cash equivalents at beginning of period		1,152			932

Cash and cash equivalents at end of period	$	1,499		$	1,102

See accompanying notes to consolidated financial statements.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

1. Summary of Significant Accounting Policies

The accompanying consolidated financial statements and notes thereto of Devon Energy Corporation (“Devon”) have been prepared pursuant to the rules and regulations of the 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 March 31, 2005, and the results of their operations and their cash flows for the three-month periods ended March 31, 2005 and 2004.

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

2. Derivative Instruments

Devon recorded in its consolidated statements of operations a loss of $52 million in the first quarter of 2005 and a gain of $4 million in the first quarter of 2004 for the change in fair value of derivative financial instruments that do not qualify for hedge accounting treatment, as well as the ineffectiveness of derivatives that qualify as hedges.

As of March 31, 2005, $548 million of 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 nine months assuming no change in forward commodity prices from the March 31, 2005 forward prices. Transactions and events expected to occur over the next nine months that will necessitate reclassifying these derivatives’ losses to earnings are primarily the production and sale of oil and gas, which includes the production hedged under the various derivative instruments. As of March 31, 2005, the maximum term over which Devon has hedged exposures to the variability of cash flows for commodity price risk under its various derivative instruments is nine months.

In March 2005, Devon recognized a $39 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 from properties sold as part of our property divestiture program. This loss is presented in other income in the accompanying 2005 statement of operations. Concurrent with the closings of certain Canadian property sales in the second quarter of 2005, Devon also expects hedges covering 3,000 barrels per day of oil production will no longer qualify for hedge accounting and will also be settled early. The amount of the related loss or hedge ineffectiveness that Devon may incur as a result of these Canadian divestitures will depend not only on the timing of the property sales but also on the forward prices in effect at that time. Under market conditions existing as of May 3, 2005, Devon would expect to record a loss of approximately $16 million in the second quarter of 2005.

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 periods ended March 31, 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 March 31, 2005:
Basic earnings per share	$	561		480	$	1.17

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 $2 million)		2		9
Potential common shares issuable upon the exercise of outstanding stock options		—		7

Diluted earnings per share	$	563		496	$	1.14


Three Months Ended March 31, 2004:
Basic earnings per share	$	492		478	$	1.03

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

Diluted earnings per share	$	494		493	$	1.00

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 March 31,
	2005			2004
Options excluded from dilution calculation (in millions)		—	⁽¹⁾		2
Range of exercise prices	$	44.13 - $47.75		$	28.34 - $44.83
Weighted average exercise price	$	46.68		$	33.62

⁽¹⁾ Actual amount of options excluded from the 2005 dilution calculation is 35,000 shares.

The excluded options for 2005 expire between September 17, 2007 and March 30, 2010.

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

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

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 first quarter 2005 and 2004 pro forma net earnings and pro forma net earnings per share would have differed from the amounts actually reported as shown in the following table.


	Three Months Ended
	March 31,
	2005			2004
	(In millions, except per share amounts)
Net earnings available to common stockholders, as reported	$	561		$	492
Add stock-based employee compensation expense included in reported net earnings, net of related tax expense		4			1
Deduct total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax expense		(10	)		(6	)

Net earnings available to common stockholders, pro forma	$	555		$	487


Net earnings per share available to common stockholders:
As reported:
Basic	$	1.17		$	1.03
Diluted	$	1.14		$	1.00
Pro forma:
Basic	$	1.16		$	1.02
Diluted	$	1.12		$	0.99

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. During the first quarter of 2005, Devon repurchased approximately

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

12.7 million shares at a total cost of $557 million, or $43.78 per share. As of March 31, 2005, Devon had repurchased approximately 17.7 million shares under the program at a total cost of $746 million, or $42.09 per share. Devon intends to continue repurchasing its shares in the open market and in privately negotiated transactions, depending upon market conditions. The stock repurchase program may be discontinued at any time.

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


	Three Months Ended March 31,
	2005			2004
	(In millions)
Shares outstanding, beginning of period		484			472
Exercise of stock options		3			5
Shares repurchased and retired		(13	)		—
Conversion of subsidiary’s preferred stock		—			2

Shares outstanding, end of period		474			479

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

5. Supplemental Cash Flow Information

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


	Three Months Ended
	March 31,
	2005		2004
	(In millions)
Interest paid	$	178	$	165
Income taxes	$	125	$	—

6. Other Income

The components of other income included the following:


	Three Months Ended
	March 31,
	2005			2004
	(In millions)
Interest and dividend income	$	26		$	10
Gain on sales of non-oil and gas property and equipment		150			4
Loss on derivative financial instruments		(39	)		—
Other		1			8

Other income, net	$	138		$	22

7. 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. As of May 4, 2005, Devon

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

has entered into purchase and sale agreements for all of the properties offered for sale. Based on these agreements, Devon expects gross proceeds from the divestitures to total approximately $2.3 billion. After-tax, the proceeds are estimated to be approximately $2.0 billion. The property sales that closed in the first quarter of 2005 generated approximately $270 million of gross proceeds. The remaining sales are expected to close in the second quarter of 2005.

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 the first quarter of 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. Devon also does not expect that the divestitures scheduled to close in the second quarter of 2005 will result in a gain or loss. However, the ultimate determination of whether a gain or loss will be recognized for the second quarter divestitures will depend on, among other factors, the actual amounts received at the closings of these divestitures.

8. 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 quarters ended March 31, 2005 and 2004.


							Other
							Postretirement
	Pension Benefits						Benefits
	Three Months						Three Months
	Ended March 31,						Ended March 31,
	2005			2004			2005		2004
				(In millions)
Components of net periodic benefit cost:
Service cost	$	5			4			—		—
Interest cost		8			8			1		1
Expected return on plan assets		(9	)		(8	)		—		—
Recognized net actuarial loss		2			2			—		—

Net periodic benefit cost	$	6			6			1		1

Employer Contributions

Devon previously disclosed in its financial statements for the year ended December 31, 2004, that it expected to contribute $6 million to the Qualified and Supplemental Plans and $6 million to the Postretirement Plans in 2005. As of March 31, 2005, Devon has contributed $1 million to the Qualified and Supplemental Plans and $2 million to the Postretirement Plans.

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

9. 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 March 31, 2005:
Current assets	$	2,498		1,137		730		4,365
Property and equipment, net of accumulated depreciation, depletion and amortization		10,903		6,015		2,561		19,479
Goodwill		3,061		2,495		68		5,624
Other assets		1,179		20		9		1,208

Total assets	$	17,641		9,667		3,368		30,676


Current liabilities		2,379		935		446		3,760
Long-term debt		3,474		3,534		—		7,008
Asset retirement obligation, long-term		394		256		35		685
Other liabilities		457		33		18		508
Deferred income taxes		2,852		1,804		425		5,081
Stockholders’ equity		8,085		3,105		2,444		13,634

Total liabilities and stockholders’ equity	$	17,641		9,667		3,368		30,676


							Inter-
	U.S.			Canada			national			Total
	(In millions)
Three Months Ended March 31, 2005:
Revenues:
Oil sales	$	291			78			246			615
Gas sales		789			375			11			1,175
NGL sales		103			40			2			145
Marketing and midstream revenues		413			3			—			416

Total revenues		1,596			496			259			2,351

Expenses and other income, net:
Lease operating expenses		190			125			33			348
Production taxes		65			2			11			78
Marketing and midstream operating costs and expenses		330			1			—			331
Depreciation, depletion and amortization of oil and gas properties		307			144			90			541
Depreciation and amortization of non-oil and gas properties		34			3			1			38
Accretion of asset retirement obligation		7			4			1			12
General and administrative expenses		55			10			(7	)		58
Interest expense		51			67			—			118
Effects of changes in foreign currency exchange rates		—			1			(1	)		—
Change in fair value of derivative financial instruments		54			(2	)		—			52
Other income, net		(130	)		(6	)		(2	)		(138	)

Total expenses and other income, net		963			349			126			1,438

Earnings before income tax expense		633			147			133			913
Income tax expense (benefit):
Current		273			27			52			352
Deferred		(29	)		33			(6	)		(2	)

Total income tax expense		244			60			46			350
Net earnings		389			87			87			563
Preferred stock dividends		2			—			—			2

Net earnings applicable to common stockholders	$	387			87			87			561


Capital expenditures	$	435			385			47			867

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


							Inter-
	U.S.			Canada			national			Total
	(In millions)
Three Months Ended March 31, 2004:
Revenues:
Oil sales	$	260			79			242			581
Gas sales		781			331			9			1,121
NGL sales		86			31			2			119
Marketing and midstream revenues		414			3			—			417

Total revenues		1,541			444			253			2,238

Expenses and other income, net:
Lease operating expenses		171			109			30			310
Production taxes		57			1			4			62
Marketing and midstream operating costs and expenses		330			2			—			332
Depreciation, depletion and amortization of oil and gas properties		315			119			104			538
Depreciation and amortization of non-oil and gas properties		30			3			1			34
Accretion of asset retirement obligation		7			4			—			11
General and administrative expenses		64			12			1			77
Interest expense		47			71			—			118
Effects of changes in foreign currency exchange rates		—			6			—			6
Change in fair value of derivative financial instruments		(5	)		1			—			(4	)
Other income, net		(16	)		(4	)		(2	)		(22	)

Total expenses and other income, net		1,000			324			138			1,462

Earnings before income tax expense		541			120			115			776
Income tax expense (benefit):
Current		144			15			44			203
Deferred		47			36			(4	)		79

Total income tax expense		191			51			40			282

Net earnings		350			69			75			494
Preferred stock dividends		2			—			—			2

Net earnings applicable to common stockholders	$	348			69			75			492


Capital expenditures	$	473			294			123			890

10. Commitments and Contingencies

Devon is party to various legal actions arising in the normal course of business. Matters that are probable of unfavorable outcome to Devon and which can be reasonably estimated are accrued. Such accruals are based on information known about the matters, Devon’s estimates of the outcomes of such matters and its experience in contesting, litigating and settling similar matters. None of the actions are believed by management to involve future amounts that would be material to Devon’s financial position or results of operations after consideration of recorded accruals although actual amounts could differ materially from management’s estimate.

Environmental Matters

Devon is subject to certain laws and regulations relating to environmental remediation activities associated with past operations, such as the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) and similar state statutes. In response to liabilities associated with these activities, accruals have been established when reasonable estimates are possible. Such accruals primarily include estimated costs associated with remediation. Devon has not used discounting in determining its accrued liabilities for environmental remediation, and no material claims for possible recovery from third party insurers or other parties related to environmental costs have been recognized in Devon’s consolidated financial statements. Devon adjusts the accruals when new remediation responsibilities are

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

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 March 31, 2005, Devon’s consolidated balance sheet included $5 million of non-current accrued liabilities, reflected in “Other liabilities,” related to these and other environmental remediation liabilities. Devon does not currently believe there is a reasonable possibility of incurring additional material costs in excess of the current accruals recognized for such environmental remediation activities. With respect to the sites in which Devon subsidiaries are PRPs, Devon’s conclusion is based in large part on (i) Devon’s participation in consent decrees with both other PRPs and the Environmental Protection Agency, which provide for performing the scope of work required for remediation and contain covenants not to sue as protection to the PRPs, (ii) participation in groups as a de minimis PRP, and (iii) the availability of other defenses to liability. As a result, Devon’s monetary exposure is not expected to be material.

Royalty Matters

Numerous gas producers and related parties, including Devon, have been named in various lawsuits alleging violation of the federal False Claims Act. The suits allege that the producers and related parties used below-market prices, improper deductions, improper measurement techniques and transactions with affiliates which resulted in underpayment of royalties in connection with natural gas and natural gas liquids produced and sold from federal and Indian owned or controlled lands. The principal suit in which Devon is a defendant is United States ex rel. Wright v. Chevron USA, Inc. et al. (the “Wright case”). The suit was originally filed in August 1996 in the United States District Court for the Eastern District of Texas, but was consolidated in October 2000 with the other suits for pre-trial proceedings in the United States District Court for the District of Wyoming. On July 10, 2003, the District of Wyoming remanded the Wright case back to the Eastern District of Texas to resume proceedings. Trial is set for February 2007 if the suit continues to advance. Devon believes that it has 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 is 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. Devon believes that it has acted reasonably and paid royalties in good faith and in accordance with its obligations under its oil and gas leases and applicable law, and Devon does not believe that it is subject to material exposure in association with this litigation.

Other Matters

Devon is involved in other various routine legal proceedings incidental to its business. However, to Devon’s knowledge as of the date of this report, there were no other material pending legal proceedings to which Devon is a party or to which any of its property is subject.

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-months ended March 31, 2005, compared to the three-months ended March 31, 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 first quarter of 2005 were $563 million, or $1.14 per diluted share. This compares to net earnings of $494 million, or $1.00 per diluted share for the first quarter of 2004. Positive factors driving the increase in first quarter net earnings include increases in prices of oil, natural gas and NGLs and a net gain from the sale of certain midstream assets. These increases were partially offset by a decline in production, higher operating expenses, additional income tax expense on the planned repatriation of earnings from Canadian operations and a loss on oil hedges related to U.S. oil and gas property divestitures.

Cash flow from operations increased from $1.2 billion in the first quarter of 2004 to $1.4 billion in the first quarter of 2005. Additionally, we received $432 million from the sale of oil and gas properties and certain midstream assets in the first quarter of 2005. These sources of cash allowed Devon to fund $867 million of capital expenditures, repurchase $557 million in common stock and add $413 million to cash and short-term investments during the first quarter of 2005. Devon announced in September 2004 its plan to purchase up to 50 million shares of its common stock. Through March 31, 2005, approximately 17.7 million common shares have been repurchased at a total cost of $746 million.

Devon also announced in September 2004 its plans to divest certain non-core oil and gas properties in the offshore Gulf of Mexico and onshore in the United States and Canada. As of May 4, 2005, Devon has entered into purchase and sale agreements for all of the properties offered for sale. Based on these agreements, Devon expects gross proceeds from the divestitures to total approximately $2.3 billion. After-tax, the proceeds are estimated to be approximately $2.0 billion. The property sales that closed in the first quarter of 2005 generated approximately $270 million of gross proceeds. The remaining sales are expected to close in the second quarter of 2005.

During the first quarter of 2005, Devon drilled 129 exploration wells, of which 89% were completed as successful, and 556 development wells, of which 99% were completed as successful.

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.

Results of Operations

Total revenues increased $113 million, or 5%, in the first quarter of 2005. This was the result of increases in oil, gas and NGL realized prices, partially offset by decreases in oil, gas and NGL production.

Oil, gas and NGL revenues were up $114 million, or 6%, for the first quarter of 2005 compared to the first quarter of 2004. The quarterly 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 March 31,
	2005		2004		Change²
Production
Oil (MMBbls)		18		21		-15	%
Gas (Bcf)		214		222		-4	%
NGLs (MMBbls)		6		6		-1	%
Oil, Gas and NGLs (MMBoe)¹		59		64		-7	%

Average Prices
Oil (Per Bbl)	$	34.47	$	27.78		+24	%
Gas (Per Mcf)		5.50		5.05		+9	%
NGLs (Per Bbl)		24.30		19.78		+23	%
Oil, Gas and NGLs (Per Boe)¹		32.56		28.47		+14	%

Revenues ($ in millions)
Oil	$	615	$	581		+6	%
Gas		1,175		1,121		+5	%
NGLs		145		119		+22	%

Combined	$	1,935	$	1,821		+6	%


	Domestic
	Three Months Ended March 31,
	2005		2004		Change ²
Production
Oil (MMBbls)		8		9		-10	%
Gas (Bcf)		145		152		-5	%
NGLs (MMBbls)		5		5		-1	%
Oil, Gas and NGLs (MMBoe)¹		37		39		-6	%

Average Prices
Oil (Per Bbl)	$	37.39	$	29.95		+25	%
Gas (Per Mcf)		5.45		5.14		+6	%
NGLs (Per Bbl)		22.17		18.34		+21	%
Oil, Gas and NGLs (Per Boe)¹		32.35		29.12		+11	%

Revenues ($ in millions)
Oil	$	291	$	260		+12	%
Gas		789		781		+1	%
NGLs		103		86		+19	%

Combined	$	1,183	$	1,127		+5	%


	Canada
	Three Months Ended March 31,
	2005		2004		Change ²
Production
Oil (MMBbls)		3		3		-6	%
Gas (Bcf)		66		67		-2	%
NGLs (MMBbls)		1		1		+2	%
Oil, Gas and NGLs (MMBoe)¹		15		16		-2	%

Average Prices
Oil (Per Bbl)	$	23.91	$	23.03		+4	%
Gas (Per Mcf)		5.68		4.92		+15	%
NGLs (Per Bbl)		31.98		25.25		+27	%
Oil, Gas and NGLs (Per Boe)¹		31.78		27.78		+14	%

Revenues ($ in millions)
Oil	$	78	$	79		-2	%
Gas		375		331		+14	%
NGLs		40		31		+29	%

Combined	$	493	$	441		+12	%


	International
	Three Months Ended March 31,
	2005		2004		Change ²
Production
Oil (MMBbls)		7		9		-23	%
Gas (Bcf)		3		3		-10	%
NGLs (MMBbls)		—		—		-4	%
Oil, Gas and NGLs (MMBoe)¹		7		9		-22	%

Average Prices
Oil (Per Bbl)	$	36.16	$	27.51		+31	%
Gas (Per Mcf)		3.83		3.14		+22	%
NGLs (Per Bbl)		28.13		21.06		+34	%
Oil, Gas and NGLs (Per Boe)¹		35.26		26.99		+31	%

Revenues ($ in millions)
Oil	$	246	$	242		+2	%
Gas		11		9		+10	%
NGLs		2		2		+28	%

Combined	$	259	$	253		+2	%

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-months ended March 31, 2005 and 2004.


	With Hedges				Without Hedges
	Three Months Ended				Three Months Ended
	March 31,				March 31,
	2005		2004		2005		2004
Oil (per Bbl)	$	34.47	$	27.78	$	42.41	$	31.22
Gas (per Mcf)	$	5.50	$	5.05	$	5.56	$	5.09
NGLs (per Bbl)	$	24.30	$	19.78	$	24.30	$	19.78
Oil, Gas and NGLs (per Boe)	$	32.56	$	28.47	$	35.21	$	29.74

Oil Revenues. Oil revenues increased $34 million in the first quarter of 2005. Oil revenues increased $119 million due to a $6.69 per barrel increase in Devon’s realized average price of oil. A decrease in 2005’s production of 3 million barrels caused oil revenues to decrease by $85 million. The decrease in production is primarily related to certain international properties for which we are receiving fewer volumes after recovering our costs under the production sharing contracts in the second quarter of 2004. Also, natural production declines on Devon’s domestic properties contributed to the decrease in volumes.

Gas Revenues. Gas revenues increased $54 million in the first quarter of 2005. Gas revenues increased $96 million due to a $0.45 per Mcf increase in Devon’s realized average price of gas. A decrease in production of 8 Bcf caused gas revenues to decrease by $42 million. The production decrease was primarily related to natural production declines on U.S. onshore and offshore properties which are being sold in 2005. New drilling and development in Devon’s domestic properties partially offset these production decreases.

NGL Revenues. NGL revenues increased $26 million in the first quarter of 2005 due to a $4.52 per barrel increase in Devon’s realized average NGL price. Production was constant at 6 million barrels in each quarter.

Marketing and Midstream Revenues. Marketing and midstream revenues decreased $1 million in the first quarter of 2005. The sale of certain assets in 2004 and 2005 caused revenues to decrease $67 million. This was partially offset by increases due to higher natural gas and NGL prices and higher gas pipeline volumes.

Oil, Gas and NGL Production and Operating Expenses. The components of oil, gas and NGL production and operating expenses are set forth in the following tables.


	Three Months Ended
	March 31,
	2005		2004		Change ¹
Expenses ($ in millions)
Lease operating expenses	$	348	$	310		+12	%
Production taxes		78		62		+25	%

Total production and operating expenses	$	426	$	372		+14	%


Expenses Per Boe
Lease operating expenses	$	5.85	$	4.84		+21	%
Production taxes		1.31		0.98		+34	%

Total production and operating expenses	$	7.16	$	5.82		+23	%

All percentage changes included in this table are based on actual figures and are not calculated using the rounded figures included in this table.

Lease operating expenses increased $38 million in the first quarter of 2005. The increase in lease operating expenses was due to an increase in well workover expenses, ad valorem taxes, power, fuel and repairs and maintenance costs. With the continuing strength of commodity prices, workovers and repairs and maintenance costs have been performed to either maintain or improve production volumes. The higher commodity prices also resulted in increased power and fuel costs. Additionally, changes in the Canadian-to-U.S. dollar exchange rate, from first quarter 2004 to first quarter 2005, resulted in a $9 million increase in costs.

Production taxes increased $16 million in the first quarter of 2005. Production taxes increased generally due to higher oil, gas and NGL revenues in the 2005 quarter. Production taxes were further increased $9 million as a result of retroactive adjustments to prior years’ taxes as a result of recent regulatory rulings and $5 million due to higher Russian export rates.

Marketing and Midstream Operating Costs and Expenses. Marketing and midstream operating costs and expenses decreased $1 million in the first quarter of 2005. The sale of certain assets in 2004 and 2005 caused costs and expenses to decrease $59 million. This was partially offset by increases due to higher natural gas and NGL purchase prices and higher gas pipeline volumes.

Depreciation, Depletion and Amortization Expense (“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 related DD&A increased $3 million in the first quarter of 2005. An increase in the combined U.S., Canadian and international DD&A rate from $8.42 per Boe in the first quarter of 2004 to $9.10 per Boe in the first quarter of 2005 caused oil and gas property related DD&A to increase by $40 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 first quarter 2004 rate of $8.42.

The increase in DD&A expense caused by the increase in the DD&A rate was partially offset by a 7% decrease in combined oil, gas and NGL production in the first quarter of 2005, which resulted in a $37 million decrease in oil and gas property related DD&A.

General and Administrative Expenses (“G&A”). Devon’s net G&A consists of three primary components. The largest of these components is the gross amount of expenses incurred for personnel costs, office expenses, professional fees and other G&A items. The gross amount of these expenses is partially reduced by two components. One is the amount of G&A capitalized pursuant to the full-cost method of accounting related to exploration and development activities. The other is the amount of G&A reimbursed by working interest owners of properties for which Devon serves as the operator. These reimbursements are received during both the drilling and operational stages of a property’s life. The gross amount of G&A incurred, less the amounts capitalized and reimbursed, is recorded as net G&A in the consolidated statements of operations. Net G&A includes expenses related to oil, gas and NGL exploration and production activities, as well as marketing and midstream activities. See the following table for a summary of G&A expenses by component.


	Three Months Ended
	March 31,
	2005			2004
	(In millions)
Gross G&A	$	132		$	141
Capitalized G&A		(47	)		(42	)
Reimbursed G&A		(27	)		(22	)


Net G&A	$	58		$	77

Gross G&A decreased $9 million in the first quarter of 2005 compared to the same period of 2004 primarily due to a decrease in deferred compensation benefit costs.

Capitalized G&A increased $5 million in the first quarter of 2005 compared to the same period of 2004. The increase was due to increases in capitalizable salaries and benefits. The $5 million increase in reimbursed G&A during the same period is primarily related to an increase in the number of wells operated by Devon as a result of new drilling and development.

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


	Three Months Ended
	March 31,
	2005			2004
	(In millions)
Interest based on debt outstanding	$	132		$	132
Amortization of discounts/premiums		1			1
Amortization of capitalized loan costs		1			2
Capitalized interest		(19	)		(17	)
Other		3			—


Total interest expense	$	118		$	118

The average debt balance decreased from $8.8 billion in the first quarter of 2004 to $8.0 billion in the 2005 quarter due to debt repayments during 2004. This decrease in debt outstanding caused interest expense to decrease $14 million. This decrease in interest expense was offset by higher rates in 2005. The average interest rate on outstanding debt increased from 6.0% in the first quarter of 2004 to 6.7% in the first quarter of 2005.

Other items included in interest expense that are not related to the debt balance outstanding were essentially flat in the first quarter of 2005.

Effects of Changes in Foreign Currency Exchange Rates. Devon’s Canadian subsidiary has certain fixed-rate senior notes which are denominated in U.S. dollars. Changes in the exchange rate between the U.S. dollar and the Canadian dollar while the notes are outstanding increase or decrease the expected amount of Canadian dollars eventually required to repay the notes. In addition, Devon’s Canadian subsidiary has cash and other working capital amounts denominated in U.S. dollars which also fluctuate in value with changes in the exchange rate. Such changes in the Canadian dollar equivalent balance of the debt and working capital balances are required to be included in determining net earnings for the period in which the exchange rate changes. The decrease in the Canadian-to-U.S. dollar exchange rate from $0.8308 at December 31, 2004 to $0.8267 at March 31, 2005 resulted in a $1 million loss. The decrease in the Canadian-to-U.S. dollar exchange rate from $0.7738 at December 31, 2003 to $0.7631 at March 31, 2004 resulted in a $6 million loss.

Change in Fair Value of Derivative Financial Instruments. The change in fair value of derivative instruments increased $56 million primarily due to the increase in the fair value of the option embedded in the debentures exchangeable into shares of ChevronTexaco common stock.

Other Income, net. The following schedule includes the components of other income for the first quarters of 2005 and 2004.


	Three Months Ended
	March 31,
	2005			2004
	(In millions)
Interest and dividend income	$	26		$	10
Gain on sales of non-oil and gas property and equipment		150			4
Loss on derivative financial instruments		(39	)		—
Other		1			8


Total other income	$	138		$	22

The increase in interest and dividend income in the first quarter of 2005 was primarily due to an increase in cash and short-term investment balances. An increase in interest rates on short-term investments also contributed to the increase.

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

Income Taxes. During interim periods, income tax expense is generally based on the estimated effective income tax rate that is expected for the entire fiscal year. The estimated effective tax rate in the first quarter of 2005 was 38% compared to 36% in the first quarter of 2004.

The 2005 rate was higher than the statutory federal tax rate primarily due to the $32 million tax effect of the planned repatriation of $500 million of earnings from our Canadian operations. Excluding the effect of the repatriation, the effective tax rate decreased to 35%.

Capital Resources 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


	Three Months Ended
	March 31,
	2005			2004
	(In millions)
Cash provided by (used in):
Operating activities	$	1,388		$	1,223
Investing activities		(501	)		(917	)
Financing activities		(538	)		(129	)
Effect of exchange rate changes		(2	)		(7	)

Net increase in cash and cash equivalents	$	347		$	170

Cash and cash equivalents at end of period	$	1,499		$	1,102

Short-term investments at end of period	$	1,033		$	379

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 quarter of 2005. Operating cash flow in the first three months of 2005 was $1.4 billion, compared to $1.2 billion in the first three months of 2004. The increase in operating cash flow in the first three months of 2005 was primarily caused by the increase in revenues, partially offset by increased expenses, as discussed in the “Results of Operations” section of this report.

Cash Flows from Investing Activities

Net cash used in investing activities was $501 million in the 2005 quarter compared to $917 million in the 2004 quarter. The decrease in cash used in investing activities was primarily related to an increase in proceeds from the sale of property and equipment.

Capital expenditures in the 2005 quarter were $867 million. This total includes $846 million for the acquisition, drilling or development of oil and gas properties. These amounts compare to capital expenditures of $890 million in the 2004 quarter which included $849 million for the acquisition, drilling or development of oil and gas properties.

Proceeds from sales of property and equipment were $432 million and $11 million in the 2005 and 2004 quarters, respectively. The increase in proceeds was due to the sale of midstream assets as well as oil and gas properties in conjunction with the divestiture program announced on September 27, 2004.

Cash Flows from Financing Activities

Net cash used in financing activities during the 2005 quarter was $538 million compared to $129 million in the 2004 quarter. The increase in cash used in financing activities from 2004 to 2005 was primarily related to repurchases of common stock. In conjunction with the stock buyback program announced September 27, 2004, Devon repurchased approximately 12.7 million shares at a total cost of $557 million during the first quarter of 2005.

In the first quarter of 2004, Devon retired $211 million of 6.75% notes due February 15, 2004.

Devon received $57 million and $108 million from shares issued for employee stock options

exercised during 2005 and 2004, respectively.

Devon’s common stock dividends were $36 million and $24 million in the 2005 and 2004 quarters, respectively. Devon also paid $2 million of preferred stock dividends in 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. Effective with the first quarter 2005 dividend payment, 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 March 31, 2005, Devon’s unrestricted cash and cash equivalents and short-term investments totaled $2.5 billion. During the first quarter of 2005 and 2004, such balances increased $413 million and $208 million, respectively.

Historically, Devon’s primary source of capital and liquidity has been operating cash flow. Additionally, we maintain a revolving line of credit and a commercial paper program which can be accessed as needed to supplement operating cash flow. Other available sources of capital and liquidity include the issuance of equity securities and long-term debt. Another major source of liquidity in 2005 will be proceeds from Devon’s plan to divest certain non-core oil and gas properties that was announced in September 2004. Purchase and sale agreements have been signed for all of the properties offered for sale. After-tax sale proceeds from the divestiture program are expected to be approximately $2.0 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, and other contractual commitments.

Operating Cash Flow

Devon’s operating cash flow is sensitive to many variables, the most volatile of which is pricing of the oil, natural gas and NGLs produced. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict.

To mitigate some of the risk inherent in oil and natural gas prices, Devon has utilized price collars to set minimum and maximum prices on a portion of its production. Additionally, we have entered into various financial price swap contracts and fixed-price physical delivery contracts to fix the price to be received for a portion of future oil and natural gas production. The table below provides the volumes associated with these various arrangements as of March 31, 2005.


			Price		Fixed-Price
	Price		Swap		Physical
	Collars		Contracts		Delivery Contracts		Total
Oil production (MMBbls)
2005		13		5		—		18
Natural gas production (Bcf)
2005		21		2		14		37
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 8 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. From 2012 through 2016, we have Canadian natural gas

volumes subject to fixed-price contracts, but the yearly volumes are less than 1 Bcf.

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 March 31, 2005, there were no borrowings under the Senior Credit Facility. The available capacity under the Senior Credit Facility as of March 31, 2005, net of $244 million of outstanding letters of credit, was approximately $1.3 billion.

The Senior Credit Facility contains only one material financial covenant. This covenant requires Devon to maintain a ratio of total funded debt to total capitalization of no more than 65%. The credit agreement contains definitions of total funded debt and total capitalization that include adjustments to the respective amounts reported in Devon’s consolidated financial statements. Per the agreement, total funded debt excludes the debentures that are exchangeable into shares of ChevronTexaco 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 March 31, 2005, Devon’s ratio as calculated pursuant to this covenant was 33.1%.

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 March 31, 2005.

Revisions to 2005 Estimates

On March 9, 2005, Devon filed a Form 10-K that provided forward-looking estimates for the year 2005. Full-year revisions of those previous estimates are provided herein. The revised estimates reflect the impact of Devon’s properties that have been designated for sale. The full-year revisions also include adjustments to previous estimates, when required, to reflect actual year-to-date results. Devon is not updating the 2005 estimates related to properties that are not being sold. Devon is providing below more information relating to its expected income tax rates for the year 2005.

The forward-looking statements provided in this discussion are based on management’s examination of historical operating trends, the information which was used to prepare the December 31, 2004 reserve reports and other data in our possession or available from third parties. Devon cautions that its future oil, natural gas and NGL production, revenues and expenses are subject to all of the risks and uncertainties normally incident to the exploration for and development, production and sale of oil, gas and NGLs. These risks include, but are not limited to, price volatility, inflation or lack of availability of goods and services, environmental risks, drilling risks, regulatory changes, the uncertainty inherent in estimating future oil and gas production or reserves, and other risks as outlined below.

Specific Assumptions and Risks Related to Production Estimates

Estimates for Devon’s future production of oil, natural gas and NGLs are based on the assumption that market demand and prices will continue at levels that allow for profitable production of these products. There can be no assurance of such stability. Most of our Canadian production of oil, natural gas and NGLs is subject to government royalties that fluctuate with prices. Thus, price fluctuations can affect reported production.

The production, transportation, processing and marketing of oil, natural gas and NGLs are complex processes which are subject to disruption from many causes. These causes include transportation and processing availability, mechanical failure, human error, meteorological events including, but not limited to, hurricanes, and numerous other factors. The following forward-looking statements were prepared assuming demand, curtailment, producibility and general market conditions for Devon’s oil, natural gas and NGLs during 2005 will be substantially similar to those of 2004, unless otherwise noted.

Unless otherwise noted, all of the following dollar amounts are expressed in U.S. dollars. Amounts related to Canadian operations have been converted to U.S. dollars using a projected average 2005 exchange rate of $0.82 U.S. to $1.00 Canadian. The actual 2005 exchange rate may vary materially from this estimate. Such variations could have a material effect on the following estimates.

Income Taxes

In the aforementioned forward-looking estimates that were provided in Devon’s 2004 Form 10-K, Devon estimated its consolidated financial income tax rate in 2005 would be between 25% and 45%. The current income tax rate was estimated to be between 20% and 30%, and the deferred income tax rate was estimated to be between 5% and 15%. Excluding the impact of taxable gains from the property divestitures discussed below and the sale of midstream assets, Devon still expects its 2005 financial current, deferred and total income tax rates for 2005 to be within the previously estimated ranges.

However, because such property divestitures are expected to result in close to $350 million of current income taxes in 2005, Devon estimates that, including the effect of the divestitures, substantially all of its reported income tax rate will consist of current income taxes. This is evidenced by the fact that Devon’s first quarter 2005 income tax expense of $350 million consisted of $352 million of current income tax expense and $2 million of deferred income tax benefit.

Property Acquisitions and Divestitures

During 2005, Devon will sell certain oil and gas properties (the “Disposition Properties”) which are predominantly properties that are either outside of our core-operating areas or otherwise do not fit our current strategic objectives. The Disposition Properties are located in the U.S. and Canada. As of May 4, 2005, Devon has entered into purchase and sale agreements for all of the properties offered for sale. Based on these agreements, Devon expects gross proceeds from the divestitures to total approximately $2.3 billion. After-tax, the proceeds are estimated to be approximately $2.0 billion. The property sales that closed in the first quarter of 2005 generated approximately $270 million of gross proceeds. The remaining sales are expected to close in the second quarter of 2005.

The Disposition Properties’ actual contributions to our 2005 operating results will depend upon the timing of the dispositions. The actual first quarter and estimated second quarter 2005 results from the Disposition Properties are as follows:


	Actual Production - 1^st Quarter 2005
	Oil		Gas		NGLs		Total
	(MMBbls)		(Bcf)		(MMBbls)		MMBoe
United States Onshore		0.5		6.6		0.3		1.9
United States Offshore		1.5		9.2		0.1		3.2
Canada		0.4		8.1		0.1		1.8

Total		2.4		23.9		0.5		6.9


	Estimated Production - 2^nd Quarter 2005
	Oil		Gas		NGLs		Total
	(MMBbls)		(Bcf)		(MMBbls)		MMBoe
United States Onshore		—		0.8		—		0.2
United States Offshore		0.4		2.4		—		0.9
Canada		0.3		5.6		0.1		1.2

Total		0.7		8.8		0.1		2.3


	Actual Expense		Estimated Expense
	1^st Quarter 2005		2^nd Quarter 2005
	(In millions)
Lease operating expenses	$	56	$	20
DD&A expenses	$	59	$	20

Not included in these estimates is the effect of any nonqualifying hedges or hedge ineffectiveness of outstanding commodity price hedges as a result of the dispositions. In March 2005, Devon recognized a $39 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 hedges related to 5,000 barrels per day of U.S. oil production from properties sold as part of our property divestiture program. Concurrent with the closings of certain Canadian property sales in the second quarter of 2005, Devon also expects hedges covering 3,000 barrels per day of oil production will no longer qualify for hedge accounting and will also be settled early. The amount of the related loss or hedge ineffectiveness that Devon may incur as a result of these Canadian divestitures will depend not only on the timing of the property sales but also on the forward prices in effect at that time. Under market conditions existing as of May 3, 2005, Devon would expect to record a loss of approximately $16 million in the second quarter of 2005.

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.

SEC Inquiry Relating to Equatorial Guinea

On August 6, 2004, the SEC notified Devon that it was conducting an inquiry into payments made to the government of Equatorial Guinea, or to officials and persons affiliated with officials of the government of Equatorial Guinea. This inquiry follows an investigation and public hearing conducted by the United States Senate Permanent Subcommittee on Investigations, which reviewed the transactions of various foreign governments, including that of Equatorial Guinea, with Riggs Bank. The investigation and hearing also reviewed the operations of those U.S. oil companies having interests in Equatorial Guinea, including Devon. Devon is cooperating with the SEC inquiry.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The information included in “Quantitative and Qualitative Disclosures About Market Risk” in Item 7A of Devon’s 2004 Annual Report on Form 10-K is incorporated herein by reference. Such information includes a description of Devon’s potential exposure to market risks, including commodity price risk, interest rate risk and foreign currency risk. As of March 31, 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 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 March 31, 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	Apr - Dec
Canada		6,000	$	27.26	Apr - Dec
International		6,000	$	25.88	Apr - Dec

Gas Production

Months of

Area

Mcf/Day

Price/Mcf

Production

United States Onshore

7,343

3.40

Apr - Dec

Costless Price Collars

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

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

To simplify presentation, our costless collars as of March 31, 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	Apr - Dec
Canada		15,000	$	22.00	$	28.28	Apr - Dec
International		15,000	$	23.92	$	30.03	Apr - Dec

Gas Production


			Weighted Average
			Floor		Ceiling
			Price Per		Price Per		Months of
Area	MMBtu/Day		MMBtu		MMBtu		Production
United States Onshore		40,000	$	4.14	$	7.10	Apr - Jun
United States Offshore		40,000	$	3.50	$	7.50	Apr - Dec
United States Offshore		70,000	$	4.09	$	7.00	Apr - Jun

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 March 31, 2005, a 10% increase in the underlying commodity prices would have increased the net liabilities recorded for Devon’s commodity hedging instruments by $123 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 8 Bcf to 14 Bcf per year. From 2012 through 2016, Devon also has Canadian gas volumes subject to fixed-price contracts, but the yearly volumes are less than 1 Bcf.

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.

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 March 31, 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 first quarter of 2005 that has materially affected, or is reasonably likely to materially affect, Devon’s internal control over financial reporting.

Part II. Other Information

Item 1. Legal Proceedings

None

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

The following table sets forth information with respect to repurchases by Devon of its shares of common stock during the first quarter of 2005.


					Total Number of		Maximum Number of
	Total Number		Average Price		Shares Purchased as		Shares that May Yet
	of Shares		Paid per		Part of Publicly Announced		Be Purchased Under
Period	Purchased		Share		Plans or Programs ⁽¹⁾		the Plans or Programs
January		2,500,000	$	38.25		2,500,000		42,500,000
February		5,000,000	$	43.21		5,000,000		37,500,000
March		5,228,500	$	46.98		5,228,500		32,271,500

Total		12,728,500	$	43.78		12,728,500

⁽¹⁾

On September 27, 2004, Devon announced its plan to repurchase up to 50 million shares of its common shares. The repurchase program does not obligate Devon to acquire any specific number of shares and may be discontinued at any time. All repurchases under the program shall be completed on or before December 31, 2006.

Item 3. Defaults Upon Senior Securities

None

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

None

Item 5. Other Information

None

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.

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: May 4, 2005		/s/ Danny J. Heatly

		Danny J. Heatly
		Vice President – Accounting

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		Page
		No.
Part I. Financial Information

Item 1.	Consolidated Financial Statements

	Consolidated Balance Sheets, March 31, 2005 (Unaudited) and December 31, 2004		6

	Consolidated Statements of Operations (Unaudited) for the Three Months Ended March 31, 2005 and 2004		7

	Consolidated Statements of Stockholders’ Equity and Comprehensive Income (Unaudited) for the Three Months Ended March 31, 2005 and 2004		8

	Consolidated Statements of Cash Flows (Unaudited) for the Three Months Ended March 31, 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		18

Item 3.	Quantitative and Qualitative Disclosures About Market Risk		30

Item 4.	Controls and Procedures		33

Part II. Other Information

Item 2.	Unregistered Sales of Equity Securities, Use of Proceeds and Issuer Purchases of Equity Securities		34

Item 6.	Exhibits		35
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


Exhibit
Number		Description
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.