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, 2006

or

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

Commission File No. 001-32318

Devon Energy Corporation

(Exact Name of Registrant as Specified in its Charter)

Delaware (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 a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer þ Accelerated filer o Non-accelerated filer o

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

     The number of shares outstanding of Registrant’s common stock, par value $0.10, as of March 31, 2006, was 439,987,000.

[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, March 31, 2006 (Unaudited) and December 31, 2005		6
	Consolidated Statements of Operations (Unaudited) for the Three Months Ended March 31, 2006 and 2005		7
	Consolidated Statements of Stockholders’ Equity and Comprehensive Income (Unaudited) for the Three Months Ended March 31, 2006 and 2005		8
	Consolidated Statements of Cash Flows (Unaudited) for the Three Months Ended March 31, 2006 and 2005		9
	Notes to Consolidated Financial Statements (Unaudited)		10
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		21
Item 4.	Controls and Procedures		31
Part II. Other Information
Item 2.	Unregistered Sales of Equity Securities, Use of Proceeds and Issuer Purchases of Equity Securities		33
Item 6.	Exhibits		34
SIGNATURES.			34
Amended and Restated Credit Agreement
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO Pursuant to Section 906
Certification of CFO Pursuant to Section 906

3

DEFINITIONS

     As used in this document:

     “Bbl” or “Bbls” means barrel or barrels.

     “Bcf” means billion cubic feet.

     “Boe” means barrel of oil equivalent, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of gas.

     “MMBbls” means million barrels.

     “MMBoe” means million Boe.

     “Mcf” means thousand cubic feet.

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

     “Oil” includes crude oil and condensate.

     “SEC” means United States Securities and Exchange Commission.

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

     “United States Onshore” means the properties of Devon in the continental United States.

     “United States Offshore” means the properties of Devon in the Gulf of Mexico.

     “Canada” means the division of Devon encompassing oil and gas properties located in Canada.

     “International” means the division of Devon encompassing oil and gas properties that lie outside the United States and Canada.

4

DEVON ENERGY CORPORATION

PART I. FINANCIAL INFORMATION

ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2006 and 2005

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

5

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	March 31,			December 31,
	2006			2005
	(Unaudited)
	(In millions, except share data)
ASSETS
Current assets:
Cash and cash equivalents	$	1,494			1,606
Short-term investments		734			680
Accounts receivable		1,320			1,601
Deferred income taxes		69			158
Other current assets		177			161
Total current assets		3,794			4,206
Property and equipment, at cost, based on the full cost method of accounting for oil and gas properties ($3,169 and $2,747 excluded from amortization in 2006 and 2005, respectively)		35,673			34,246
Less accumulated depreciation, depletion and amortization		15,650			15,114
		20,023			19,132
Investment in Chevron Corporation common stock, at fair value		822			805
Goodwill		5,702			5,705
Other assets		424			425
Total assets	$	30,765			30,273
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable:
Trade	$	1,139			947
Revenues and royalties due to others		500			666
Income taxes payable		412			293
Current portion of long-term debt		665			662
Accrued interest payable		82			127
Fair value of derivative financial instruments		16			18
Current portion of asset retirement obligation		51			50
Accrued expenses and other current liabilities		62			171
Total current liabilities		2,927			2,934
Debentures exchangeable into shares of Chevron Corporation common stock		713			709
Other long-term debt		5,241			5,248
Fair value of derivative financial instruments		138			125
Asset retirement obligation, long-term		634			618
Other liabilities		371			372
Deferred income taxes		5,439			5,405
Stockholders’ equity:
Preferred stock of $1.00 par value.
Authorized 4,500,000 shares; issued 1,500,000 ($150 million aggregate liquidation value)		1			1
Common stock of $0.10 par value.
Authorized 800,000,000 shares; issued 440,292,000 in 2006 and 443,488,000 in 2005		44			44
Additional paid-in capital		6,733			6,928
Retained earnings		7,126			6,477
Accumulated other comprehensive income		1,416			1,414
Treasury stock, at cost: 305,000 shares in 2006 and 37,000 shares in 2005		(18	)		(2	)
Total stockholders’ equity		15,302			14,862
Total liabilities and stockholders’ equity	$	30,765			30,273

See accompanying notes to consolidated financial statements.

6

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)

	Three Months Ended March 31,
	2006			2005
	(In millions, except per share amounts)
Revenues:
Oil sales	$	715			615
Gas sales		1,364			1,175
NGL sales		176			145
Marketing and midstream revenues		462			416
Total revenues		2,717			2,351
Expenses and other income, net:
Lease operating expenses		349			348
Production taxes		83			78
Marketing and midstream operating costs and expenses		339			331
Depreciation, depletion and amortization of oil and gas properties		507			541
Depreciation and amortization of non-oil and gas properties		42			38
Accretion of asset retirement obligation		11			12
General and administrative expenses		90			58
Interest expense		101			118
Effects of changes in foreign currency exchange rates		(1	)		—
Change in fair value of derivative financial instruments		12			52
Reduction of carrying value of oil and gas properties		85			—
Other income, net		(28	)		(138	)
Total expenses and other income, net		1,590			1,438
Earnings before income tax expense		1,127			913
Income tax expense (benefit):
Current		304			352
Deferred		123			(2	)
Total income tax expense		427			350
Net earnings		700			563
Preferred stock dividends		2			2
Net earnings applicable to common stockholders	$	698			561
Net earnings per common share outstanding:
Basic	$	1.58			1.17
Diluted	$	1.56			1.14
Weighted average common shares outstanding:
Basic		442			480
Diluted		449			496

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						Total
	Preferred		Common			Paid-In			Retained			Comprehensive			Treasury			Stockholders’
	Stock		Stock			Capital			Earnings			Income			Stock			Equity
	(In millions)
Three Months Ended March 31, 2006
Balance as of December 31, 2005	$	1		44			6,928			6,477			1,414			(2	)		14,862
Comprehensive income:
Net earnings		—		—			—			700			—			—			700
Other comprehensive income (loss), net of tax:
Foreign currency translation adjustments		—		—			—			—			(8	)		—			(8	)
Change in fair value of derivative financial instruments		—		—			—			—			(1	)		—			(1	)
Unrealized gain on marketable securities		—		—			—			—			11			—			11
Other comprehensive gain																			2
Comprehensive income																			702
Stock issued		—		—			19			—			—			—			19
Stock repurchased and retired		—		—			(238	)		—			—			(15	)		(253	)
Dividends on common stock		—		—			—			(49	)		—			—			(49	)
Dividends on preferred stock		—		—			—			(2	)		—			—			(2	)
Grant of restricted stock awards, net of cancellations		—		—			1			—			—			(1	)		—
Stock option and restricted stock expense		—		—			19			—			—			—			19
Excess tax benefits related to stock-based compensation		—		—			4			—			—			—			4
Balance as of March 31, 2006	$	1		44			6,733			7,126			1,416			(18	)		15,302
Three Months Ended March 31, 2005
Balance as of December 31, 2004	$	1		48			9,002			3,693			930			—			13,674
Comprehensive income:
Net earnings		—		—			—			563			—			—			563
Other comprehensive income (loss), net of tax:
Foreign currency translation adjustments		—		—			—			—			(26	)		—			(26	)
Reclassification adjustment for derivative losses reclassified into earnings		—		—			—			—			92			—			92
Change in fair value of derivative financial instruments		—		—			—			—			(191	)		—			(191	)
Unrealized gain on marketable securities		—		—			—			—			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	)
Restricted stock expense		—		—			7			—			—			—			7
Balance as of March 31, 2005	$	1		47			8,510			4,218			858			—			13,634

See accompanying notes to consolidated financial statements.

8

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Three Months Ended March 31,
	2006			2005
	(In millions)
Cash flows from operating activities:
Net earnings	$	700			563
Adjustments to reconcile net earnings to net cash provided by operating activities:
Depreciation, depletion and amortization		549			579
Deferred income tax expense (benefit)		123			(2	)
Net gain on sales of non-oil and gas property and equipment		(5	)		(150	)
Reduction of carrying value of oil and gas properties		85			—
Other non-cash charges to net earnings		40			75
Changes in assets and liabilities:
(Increase) decrease in:
Accounts receivable		283			(44	)
Other current assets		(15	)		(8	)
Long-term other assets		(18	)		32
Increase (decrease) in:
Accounts payable		(169	)		51
Income taxes payable		115			205
Long-term debt, including current maturities		—			4
Accrued interest and expenses		(160	)		82
Long-term other liabilities		(6	)		1
Net cash provided by operating activities		1,522			1,388
Cash flows from investing activities:
Proceeds from sale of property and equipment		19			432
Capital expenditures		(1,317	)		(867	)
Purchases of short-term investments		(495	)		(1,147	)
Sales of short-term investments		441			1,081
Net cash used in investing activities		(1,352	)		(501	)
Cash flows from financing activities:
Principal payments on long-term debt		(3	)		—
Proceeds from exercise of stock options		19			57
Repurchase of common stock		(252	)		(557	)
Excess tax benefits related to stock-based compensation		4			—
Dividends paid on common stock		(49	)		(36	)
Dividends paid on preferred stock		(2	)		(2	)
Net cash used in financing activities		(283	)		(538	)
Effect of exchange rate changes on cash		1			(2	)
Net (decrease) increase in cash and cash equivalents		(112	)		347
Cash and cash equivalents at beginning of period		1,606			1,152
Cash and cash equivalents at end of period	$	1,494			1,499

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 2005 Annual Report on Form 10-K.

     In the opinion of Devon’s management, all adjustments (all of which are normal and recurring) have been made which are necessary to fairly state the consolidated financial position of Devon and its subsidiaries as of March 31, 2006, and the results of their operations and their cash flows for the three-month periods ended March 31, 2006 and 2005. Certain prior period amounts have been reclassified to conform to the current period presentation.

Earnings Per Share

     The following table reconciles the net earnings and common shares outstanding used in the calculations of basic and diluted earnings per share for the three-month periods ended March 31, 2006 and 2005.

	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, 2006:
Basic earnings per share	$	698		442	$	1.58
Dilutive effect of:
Potential common shares issuable upon the exercise of outstanding stock options		—		7
Diluted earnings per share	$	698		449	$	1.56
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

     Certain options to purchase shares of Devon’s common stock have been excluded from the dilution calculations because the options are antidilutive. During the first quarter of 2006 and 2005, 2.6 million shares and 35,000 shares, respectively, were excluded from the diluted earnings per share calculations.

10

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

Change in Accounting Principle

     Effective January 1, 2006, Devon adopted Statement of Financial Accounting Standard No. 123(R), Share-Based Payment, (“SFAS No. 123(R)”), using the modified prospective transition method. SFAS No. 123(R) requires equity-classified share-based payments to employees, including grants of employee stock options, to be valued at fair value on the date of grant and to be expensed over the applicable vesting period. Under the modified prospective transition method, share-based awards granted or modified on or after January 1, 2006, are recognized in compensation expense over the applicable vesting period. Also, any previously granted awards that are not fully vested as of January 1, 2006 are recognized as compensation expense over the remaining vesting period. No retroactive or cumulative effect adjustments were required upon Devon’s adoption of SFAS No. 123(R).

     Prior to adopting SFAS No. 123(R), Devon accounted for its fixed-plan employee stock options using the intrinsic-value based method prescribed by Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees, (“APB No. 25”) and related interpretations. This method required compensation expense to be recorded on the date of grant only if the current market price of the underlying stock exceeded the exercise price.

     Had Devon elected the fair value provisions of SFAS No. 123(R), Devon’s 2005 net earnings and net earnings per share would have differed from the amounts actually reported as shown in the following table.

	Three Months Ended
	March 31, 2005
	(In millions, except per
	share amounts)
Net earnings available to common stockholders, as reported	$	561
Add share-based employee compensation expense included in reported net earnings, net of related tax expense		4
Deduct total stock-based employee compensation expense determined under fair value based method for all awards (see note 5), net of related tax expense		(10	)
Net earnings available to common stockholders, pro forma	$	555
Net earnings per share available to common stockholders:
As reported:
Basic	$	1.17
Diluted	$	1.14
Pro forma:
Basic	$	1.16
Diluted	$	1.13

     As a result of adopting SFAS No. 123(R) on January 1, 2006, Devon’s earnings before income tax expense and net earnings for the three-month period ended March 31, 2006 were $6 million and $4 million lower, respectively, than if Devon had continued to account for share-based compensation under APB No. 25. Also, basic and diluted earnings per share were approximately $0.01 per share lower as a result of the adoption. Prior to the adoption of SFAS No. 123(R), Devon presented all tax benefits of deductions resulting from the exercise of stock options as operating cash inflows in the statement of cash flows. SFAS No. 123(R) requires the cash inflows resulting from tax deductions in excess of the compensation expense recognized for those stock options (“excess tax benefits”) to be classified as financing cash inflows. As required by SFAS No. 123(R), Devon recognized $4 million of excess tax benefits as financing cash inflows for the three months ended March 31, 2006.

11

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

2. Comprehensive Income or Loss

     Devon’s comprehensive income or loss information is included in the accompanying consolidated statements of stockholders’ equity and comprehensive income. A summary of accumulated other comprehensive income as of March 31, 2006 and 2005, and changes during each of the three 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, 2005	$	1,217			3			(18	)		212			1,414
2006 activity		(9	)		(1	)		—			17			7
Deferred taxes		1			—			—			(6	)		(5	)
2006 activity, net of deferred taxes		(8	)		(1	)		—			11			2
Balance as of March 31, 2006	$	1,209			2			(18	)		223			1,416
Balance as of December 31, 2004	$	1,055			(286	)		(13	)		174			930
2005 activity		(28	)		(152	)		—			82			(98	)
Deferred taxes		2			53			—			(29	)		26
2005 activity, net of deferred taxes		(26	)		(99	)		—			53			(72	)
Balance as of March 31, 2005	$	1,029			(385	)		(13	)		227			858

3. Supplemental Cash Flow Information

     Cash payments for interest and income taxes in the first three months of 2006 and 2005 are presented below:

	Three Months Ended
	March 31,
	2006		2005
	(In millions)
Interest paid	$	159		178
Income taxes	$	160		125

4. Debt

New Credit Facility

     In April 2006, Devon replaced its existing $1.5 billion five-year unsecured revolving credit facility with a $2.0 billion five-year, syndicated, unsecured revolving line of credit (the “Senior Credit Facility”). The Senior Credit Facility includes a five-year revolving Canadian subfacility in a maximum amount of U.S. $500 million.

     The Senior Credit Facility matures on April 7, 2011, and all amounts outstanding will be due and payable at that time unless the maturity is extended. Prior to each April 7 anniversary date, Devon has the option to extend the maturity of the Senior Credit Facility for one year, subject to the approval of the lenders.

     Devon has the right to increase the aggregate commitment amount under the Senior Credit Facility

12

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

from $2.0 billion to $2.5 billion by requesting one or more lenders to increase their respective commitments or adding one or more additional lenders to the syndicate group. Devon expects to work with its lenders to increase the aggregate commitment amount in conjunction with the expected close of the Chief acquisition in the second quarter of this year (see Note 11). However, there is no guarantee that Devon will be successful in increasing the aggregate commitment amount.

     Amounts borrowed under the Senior Credit Facility may, at Devon’s election, bear interest at various fixed rate options for periods of up to twelve months. Such rates are generally less than the prime rate. Devon may also elect to borrow at the prime rate. The Senior Credit Facility currently provides for an annual facility fee of $1.8 million that is payable quarterly in arrears.

     As of April 30, 2006, there were no borrowings under the Senior Credit Facility. The available capacity under the Senior Credit Facility as of April 30, 2006, net of $356 million of outstanding letters of credit, was approximately $1.6 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, as defined in the credit agreement, of no more than 65%.

5. Stockholders’ Equity

     The following is a summary of the changes in Devon’s common shares outstanding for the three months ended March 31, 2006 and 2005:

	Three Months Ended
	March 31,
	2006			2005
	(In millions)
Shares outstanding, beginning of period		443			484
Exercise of stock options		1			3
Shares repurchased and retired		(4	)		(13	)
Shares outstanding, end of period		440			474

     The shares repurchased in 2006 were repurchased at a cost of $253 million, or $59.61, per share. The shares repurchased in 2005 were repurchased at a cost of $557 million, or $43.78, per share.

     On August 3, 2005, Devon announced that its board of directors had authorized the repurchase of up to 50 million shares of our common stock. As of May 2, 2006, Devon had repurchased 6.5 million shares under this program for $387 million, or $59.80 per share. As a result of the Chief acquisition (see Note 11), this repurchase program has been suspended and will be reevaluated later in 2006.

Stock-Based Compensation Plans

     As discussed in Note 1, on January 1, 2006, Devon changed its method of accounting for share-based compensation from the APB No. 25 intrinsic value accounting method to the fair value recognition provisions of SFAS No. 123(R). During the first three months of 2006 and 2005, Devon’s stock-based compensation expense was $19 million and $7 million, respectively. The related tax benefit recognized in our statement of operations for such compensation expense was $5 million and $2 million, respectively. During the first three months of 2006, Devon capitalized $5 million of its stock-based compensation pursuant to the full cost method of accounting for oil and gas properties.

13

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

     Devon estimates the fair values of stock options granted using a Black-Scholes option valuation model, which requires Devon to make several assumptions. The volatility of Devon’s common stock is based on the historical volatility of the market price of Devon’s common stock over a period of time equal to the expected term of the option and ending on the grant date. The dividend yield is based on Devon’s historical and current yield in effect at the date of grant. The risk-free interest rate is based on the U.S. Treasury yield for the expected term of the option at the date of grant. The expected term of the options is based on historical exercise and termination experience for various groups of employees and directors. Each group is determined based on the similarity of their historical exercise and termination behavior.

     The assumptions presented in the following table represent the weighted-average amounts for the period. The weighted average grant-date fair values of stock options granted during the first three months of 2006 and 2005 were $19.36 and $14.04, respectively.

	Three Months Ended
	March 31,
	2006			2005
Volatility factor		30.7	%		33.3	%
Dividend yield		0.3	%		0.6	%
Risk-free interest rate		4.9	%		4.1	%
Expected term (in years)		4.0			4.0

     A summary of Devon’s outstanding stock options as of March 31, 2006, and changes during the three months then ended, is presented below.

						Weighted
				Weighted		Average
				Average		Remaining		Aggregate
				Exercise		Contractual		Intrinsic
	Options			Price		Term		Value
	(In thousands)					(In Years)		(In millions)
Outstanding at December 31, 2005		16,732		$	32.74
Granted		83		$	62.57
Exercised		(785	)	$	25.05
Forfeited		(224	)	$	48.41
Outstanding at March 31, 2006		15,806		$	33.06		4.5	$	457
Exercisable at March 31, 2006		10,132		$	25.06		4.2	$	366

     A summary of Devon’s unvested restricted stock awards as of March 31, 2006, and changes during the three months then ended, is presented below.

				Weighted
	Restricted			Average
	Stock			Grant-Date
	Awards			Fair Value
	(In thousands)
Unvested at December 31, 2005		3,187		$	46.80
Granted		27		$	61.82
Vested		(73	)	$	23.92
Forfeited		(42	)	$	47.38
Unvested at March 31, 2006		3,099		$	47.46

     The total intrinsic value of options exercised during the three months ended March 31, 2006 and

14

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

2005, was $31 million and $55 million, respectively. The total fair value of shares vested during the three months ended March 31, 2006 and 2005, was $7 million and $4 million, respectively. As of March 31, 2006, Devon’s unrecognized compensation costs related to unvested stock options and restricted stock awards were $62 million and $121 million, respectively. Such costs are expected to be recognized over weighted-average periods of 1.4 years and 1.8 years, respectively.

6. Other Income

     The components of other income included the following:

	Three Months Ended
	March 31,
	2006			2005
	(In millions)
Interest and dividend income	$	28			26
Net gain on sales of non-oil and gas property and equipment		5			150
Loss on derivative financial instruments		—			(39	)
Other		(5	)		1
Other income, net	$	28			138

7. 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, 2006 and 2005.

							Other
							Postretirement
	Pension Benefits						Benefits
	Three Months						Three Months
	Ended March 31,						Ended March 31,
	2006			2005			2006		2005
	(In millions)
Components of net periodic benefit cost:
Service cost	$	6			5			—		—
Interest cost		10			8			1		1
Expected return on plan assets		(11	)		(9	)		—		—
Recognized net actuarial loss		3			2			—		—
Net periodic benefit cost	$	8			6			1		1

Employer Contributions

     Devon previously disclosed in its financial statements for the year ended December 31, 2005, that it expected to contribute $7 million to the Qualified and Supplemental Plans in 2006 and $5 million to the

15

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

Postretirement Plans in 2006. As of March 31, 2006, Devon has contributed $1 million to the Qualified and Supplemental Plans and $2 million to the Postretirement Plans.

8. 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 March 31, 2006, 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

16

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

the Wright case back to the Eastern District of Texas to resume proceedings. On February 1, 2006, the Court entered a scheduling order in which trial is set for November 2007 if the suit continues to advance. Devon believes that it has acted reasonably, has legitimate and strong defenses to all allegations in the suit, and has paid royalties in good faith. Devon does not currently believe that it is subject to material exposure in association with this lawsuit and no liability has been recorded in connection therewith.

     In 1995, the United States Congress passed the Deep Water Royalty Relief Act (the “DWRRA”). The intent of the DWRRA was to encourage deep water exploration in the Gulf of Mexico by providing relief from the obligation to pay royalties on certain federal leases. The DWRRA granted royalty relief, without regard to the market prices of oil or natural gas, with respect to leases issued between November 28, 1995 and November 28, 2000. However, in regulations promulgated by the Minerals Management Service (the “MMS”) subsequent to the passage of the DWRRA, the MMS imposed price thresholds on these deep water leases such that if the market prices for oil or natural gas exceeded the thresholds, royalty relief would not be granted.

     The MMS has issued an order to Devon and other oil and gas producers to pay royalties on these deep water leases due to market prices exceeding the price thresholds in recent years. Devon and certain other oil and gas producers have filed Administrative Appeals with the MMS contesting the MMS’ orders. One oil and gas producer has filed suit in Federal court against the Department of Interior challenging the MMS’ authority to suspend royalty relief on the subject leases.

     Devon does not believe that the MMS has the legal authority to suspend the royalty relief granted by the DWRRA. This is based in part on prior successful litigation against the Department of Interior and the MMS involving similar issues related to the DWRRA. Accordingly, Devon has not accrued for any such royalties in its consolidated financial statements. If it were to be found that the MMS’ regulations are valid, Devon estimates that as of March 31, 2006, it would owe royalties and interest totaling $133 million.

Equatorial Guinea Investigation

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

Hurricane Contingencies

     Devon maintains a comprehensive insurance program that includes coverage for physical damage to its offshore facilities caused by hurricanes. Devon’s insurance program also includes substantial business interruption coverage which Devon expects to utilize to recover costs associated with the suspended production related to hurricanes that struck the Gulf of Mexico in the third quarter of 2005. Under the terms of the insurance program, Devon is entitled to be reimbursed for the portion of production suspended longer than forty-five days, subject to upper limits to oil and natural gas prices. Also, the terms of the insurance include a standard, per-event deductible of $1 million for offshore losses as well as a $15 million aggregate annual deductible. Based on current estimates of physical damage and the anticipated length of time Devon will have production suspended, Devon expects its policy settlements will exceed repair costs and deductible amounts. This expectation is based upon several variables, including the actual amount of time that production is suspended, the actual prices in effect while production is suspended and the timing of collections of insurance proceeds. Should Devon’s policy

17

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

settlements exceed repair costs and deductible amounts, the excess will be recognized as other income in the statement of operations.

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.

9. Reduction of Carrying Value of Oil and Gas Properties

     Currently, Devon has commitments to drill four wells in Nigeria. The first two wells were unsuccessful. After drilling the second unsuccessful well in the first quarter of 2006, Devon determined that the capitalized costs related to these two wells should be impaired. Therefore, in the first quarter of 2006, Devon recognized an $85 million impairment of its investment in Nigeria equal to the costs to drill the two dry holes and a proportionate share of block-related costs. There is no tax benefit related to this impairment.

10. 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, 2006:
Current assets	$	1,840		957		997		3,794
Property and equipment, net of accumulated depreciation, depletion and amortization		11,277		6,350		2,396		20,023
Goodwill		3,057		2,577		68		5,702
Other assets		1,214		17		15		1,246
Total assets	$	17,388		9,901		3,476		30,765
Current liabilities		1,751		898		278		2,927
Long-term debt		2,982		2,972		—		5,954
Asset retirement obligation, long-term		321		272		41		634
Other liabilities		479		10		20		509
Deferred income taxes		3,052		2,000		387		5,439
Stockholders’ equity		8,803		3,749		2,750		15,302
Total liabilities and stockholders’ equity	$	17,388		9,901		3,476		30,765

18

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

							Inter-
	U.S.			Canada			national			Total
	(In millions)
Three Months Ended March 31, 2006:
Revenues:
Oil sales	$	294			122			299			715
Gas sales		919			435			10			1,364
NGL sales		124			52			—			176
Marketing and midstream revenues		450			7			5			462
Total revenues		1,787			616			314			2,717
Expenses and other income, net:
Lease operating expenses		196			124			29			349
Production taxes		66			2			15			83
Marketing and midstream operating costs and expenses		335			3			1			339
Depreciation, depletion and amortization of oil and gas properties		281			150			76			507
Depreciation and amortization of non-oil and gas properties		37			4			1			42
Accretion of asset retirement obligation		6			4			1			11
General and administrative expenses		70			21			(1	)		90
Interest expense		42			59			—			101
Effects of changes in foreign currency exchange rates		—			—			(1	)		(1	)
Change in fair value of derivative financial instruments		14			(2	)		—			12
Reduction of carrying value of oil and gas properties		—			—			85			85
Other income, net		(16	)		(6	)		(6	)		(28	)
Total expenses and other income, net		1,031			359			200			1,590
Earnings before income tax expense		756			257			114			1,127
Income tax expense (benefit):
Current		182			51			71			304
Deferred		96			43			(16	)		123
Total income tax expense		278			94			55			427
Net earnings		478			163			59			700
Preferred stock dividends		2			—			—			2
Net earnings applicable to common stockholders	$	476			163			59			698
Capital expenditures	$	732			646			156			1,534

19

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

							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	$	491			485			53			1,029

11. Pending Acquisition

     On May 2, 2006, Devon announced that it will acquire the oil and gas properties of privately-owned Chief Holdings LLC (“Chief”) for $2.2 billion in cash, including assumed liabilities. Devon expects to fund the acquisition with approximately $900 million of cash on hand and approximately $1.3 billion of short-term borrowings under its commercial paper program. Devon estimates that the acquired properties include proved reserves of 617 billion cubic feet of natural gas equivalent and leasehold totaling 169,000 net acres located in the Barnett Shale area of Texas. Devon expects to allocate approximately $1.0 billion of the purchase price to proved reserves and approximately $1.2 billion to unproved properties. The acquisition is expected to close near the end of the second quarter of 2006.

     The transaction is subject to expiration of the Hart-Scott-Rodino waiting period. It is also subject to other customary closing conditions.

20

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, 2006, compared to the three months ended March 31, 2005, and in financial condition since December 31, 2005. It is presumed that readers have read or have access to Devon’s 2005 Annual Report on Form 10-K which includes disclosures regarding critical accounting policies as part of Management’s Discussion and Analysis of Financial Condition and Results of Operations. Unless otherwise stated, all dollar amounts are expressed in U.S. dollars.

Overview

     We continued to execute our strategy to increase value per share. The following summarizes our performance for the first quarter of 2006 compared to the first quarter of 2005:

• Net earnings for the quarter increased 24% to $700 million

• Earnings per share rose 37% to $1.56 per diluted share

• Net cash provided by operating activities climbed 10% to $1.5 billion

• Combined realized price for oil, gas and NGLs climbed 35% to $44.11

• Marketing and midstream operating profit rose 45% to $123 million

• Production increased 2% excluding the effects of our 2005 sales of non-core properties and production suspended due to hurricanes

• Per unit operating costs increased 17% to $6.83 per Boe due to cost inflation resulting from the increase in commodity prices and the weakened U.S. dollar compared to the Canadian dollar

     In addition, capital expenditures for oil and gas exploration and development activities were $1.4 billion during the first quarter of 2006. During this same period, estimated proved reserves increased 20 million Boe due to drilling discoveries and extensions and performance revisions.

     On May 2, 2006, we announced that we will acquire the oil and gas properties of privately-owned Chief Holdings LLC (“Chief”) for $2.2 billion in cash, including assumed liabilities. We expect to fund the acquisition with approximately $900 million of cash on hand and approximately $1.3 billion of short-term borrowings under our commercial paper program. We estimate that the acquired properties include proved reserves of 617 billion cubic feet of natural gas equivalent and leasehold totaling 169,000 net acres located in the Barnett Shale area of Texas. We expect to allocate approximately $1.0 billion of the purchase price to proved reserves and approximately $1.2 billion to unproved properties. The acquisition is expected to close near the end of the second quarter of 2006.

     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 our 2005 Annual Report on Form 10-K.

Results of Operations

Revenues

     Oil, gas and NGL revenues increased $320 million, or 17%, for the first quarter of 2006 compared to the first quarter of 2005. The quarterly comparisons of production and price changes are shown in the following tables.

21

	Total
	Three Months Ended March 31,
	2006		2005		Change 2
Production
Oil (MMBbls)		13		18		-25	%
Gas (Bcf)		191		214		-11	%
NGLs (MMBbls)		6		6		-2	%
Oil, Gas and NGLs (MMBoe)1		51		59		-14	%
Average Prices
Oil (Per Bbl)	$	53.35		34.47		+55	%
Gas (Per Mcf)	$	7.13		5.50		+30	%
NGLs (Per Bbl)	$	30.18		24.30		+24	%
Oil, Gas and NGLs (Per Boe)1	$	44.11		32.56		+35	%
Revenues ($ in millions)
Oil	$	715		615		+16	%
Gas		1,364		1,175		+16	%
NGLs		176		145		+21	%
Combined	$	2,255		1,935		+17	%

	Domestic
	Three Months Ended March 31,
	2006		2005		Change 2
Production
Oil (MMBbls)		5		8		-36	%
Gas (Bcf)		130		145		-10	%
NGLs (MMBbls)		5		5		-1	%
Oil, Gas and NGLs (MMBoe)1		31		37		-14	%
Average Prices
Oil (Per Bbl)	$	58.70		37.39		+57	%
Gas (Per Mcf)	$	7.07		5.45		+30	%
NGLs (Per Bbl)	$	26.89		22.17		+21	%
Oil, Gas and NGLs (Per Boe)1	$	42.72		32.35		+32	%
Revenues ($ in millions)
Oil	$	294		291		+1	%
Gas		919		789		+16	%
NGLs		124		103		+20	%
Combined	$	1,337		1,183		+13	%

22

	Canada
	Three Months Ended March 31,
	2006		2005		Change 2
Production
Oil (MMBbls)		3		3		-1	%
Gas (Bcf)		59		66		-11	%
NGLs (MMBbls)		1		1		-2	%
Oil, Gas and NGLs (MMBoe)1		14		15		-8	%
Average Prices
Oil (Per Bbl)	$	38.14		23.91		+59	%
Gas (Per Mcf)	$	7.37		5.68		+30	%
NGLs (Per Bbl)	$	42.56		31.98		+33	%
Oil, Gas and NGLs (Per Boe)1	$	42.73		31.78		+34	%
Revenues ($ in millions)
Oil	$	122		78		+58	%
Gas		435		375		+16	%
NGLs		52		40		+30	%
Combined	$	609		493		+24	%

	International
	Three Months Ended March 31,
	2006		2005		Change 2
Production
Oil (MMBbls)		5		7		-24	%
Gas (Bcf)		2		3		-18	%
NGLs (MMBbls)		—		—		N/	M
Oil, Gas and NGLs (MMBoe)1		6		7		-24	%
Average Prices
Oil (Per Bbl)	$	57.60		36.16		+59	%
Gas (Per Mcf)	$	4.21		3.83		+10	%
NGLs (Per Bbl)	$	—		28.13		N/	M
Oil, Gas and NGLs (Per Boe)1	$	55.43		35.26		+57	%
Revenues ($ in millions)
Oil	$	299		246		+22	%
Gas		10		11		-10	%
NGLs		—		2		N/	M
Combined	$	309		259		+19	%

1	Gas volumes are converted to Boe or MMBoe at the rate of six Mcf of gas per barrel of oil, based upon the approximate relative energy content of natural gas and oil, which rate is not necessarily indicative of the relationship of oil and gas prices. NGL volumes are converted to Boe on a one-to-one basis with oil.
2	All percentage changes included in this table are based on actual figures and are not calculated using the rounded figures included in this table.
N/M	Not meaningful.

     The 2005 average sales prices per unit of production shown in the preceding tables include the effect of our hedging activities. All of our commodity hedges expired prior to the beginning of 2006. Included below is a comparison of our average sales prices with and without the effect of hedges for the three-months ended March 31, 2005.

23

	Three Months Ended
	March 31, 2005
	With		Without
	Hedges		Hedges
Oil (per Bbl)	$	34.47		42.41
Gas (per Mcf)	$	5.50		5.56
NGLs (per Bbl)	$	24.30		24.30
Oil, Gas and NGLs (per Boe)	$	32.56		35.21

Oil Revenues

     Oil revenues increased $100 million in the first quarter of 2006. Oil revenues increased $253 million due to an $18.88 per barrel increase in our realized average price of oil. A five million barrel decrease in production caused oil revenues to decrease by $153 million. Production lost from the 2005 property divestitures accounted for two million barrels of the decrease. We also suspended certain domestic oil production in 2005 and 2006 due to the effects of Hurricanes Katrina, Rita, Dennis and Ivan. The quarter over quarter impact accounted for an additional one million barrels of suspended production in 2006 than in 2005. 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.

Gas Revenues

     Gas revenues increased $189 million in the first quarter of 2006. Gas revenues increased $312 million due to a $1.63 per Mcf increase in our realized average price of gas. A decrease in production of 23 Bcf caused gas revenues to decrease by $123 million. Production lost from the 2005 property divestitures caused a decrease of 24 Bcf. We also suspended certain domestic gas production in 2005 and 2006 due to the effects of Hurricanes Katrina, Rita, Dennis and Ivan. The quarter over quarter impact accounted for an additional 10 Bcf of suspended production in 2006 than in 2005. These decreases were partially offset by new drilling and development and increased performance in U.S. offshore and onshore and Canadian properties.

NGL Revenues

     NGL revenues increased $31 million in the first quarter of 2006 due to a $5.88 per barrel increase in our realized average NGL price. Production was six million barrels in each quarter.

Marketing and Midstream Revenues

     Marketing and midstream revenues increased $46 million in the first quarter of 2006. Revenues increased $89 million primarily due to higher natural gas and NGL prices. This was partially offset by lower NGL marketed volumes, which caused revenues to decrease $42 million, and lower processing fees.

24

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 schedule.

	Three Months Ended
	March 31,
	2006		2005		Change 1
Expenses ($ in millions):
Lease operating expenses	$	349		348		+0	%
Production taxes		83		78		+6	%
Total production and operating expenses	$	432		426		+1	%
Expenses Per Boe:
Lease operating expenses	$	6.83		5.85		+17	%
Production taxes		1.62		1.31		+23	%
Total production and operating expenses	$	8.45		7.16		+18	%

¹ All percentage changes included in this table are based on actual figures and are not calculated using the rounded figures included in this table.

     Lease operating expenses increased $1 million in the first quarter of 2006. The increase in lease operating expense was largely caused by higher commodity prices. With the increase in oil, gas and NGL prices, more well workovers and repairs and maintenance costs were performed to either maintain or improve production volumes. Such costs also increased due to inflationary pressure driven by higher commodity prices. Other costs, including ad valorem taxes, power and fuel costs, also increased primarily as a result of higher commodity prices. Additionally, changes in the Canadian-to-U.S. dollar exchange rate resulted in a $7 million increase in costs. Partially offsetting these increases was a decrease of $56 million in lease operating expenses related to properties that were sold in 2005.

     The increases described above were also the primary factors causing lease operating expenses per Boe to increase. Although we divested properties that had higher per-unit operating costs, the cost escalation largely related to higher commodity prices and the weaker U.S. dollar compared to the Canadian dollar had a greater effect on our per unit costs than the property divestitures.

     Production taxes increased $5 million in the first quarter of 2006. The majority of our production taxes are assessed on our onshore domestic properties. In the U.S., most of the production taxes are based on a fixed percentage of revenues. Therefore, the 13% increase in domestic oil, gas and NGL revenues was the primary cause of the production tax increase. This increase was partially offset by a decrease resulting from a $9 million retroactive adjustment recorded in the first quarter of 2005 as a result of regulatory rulings.

Marketing and Midstream Operating Costs and Expenses

     Marketing and midstream operating costs and expenses increased $8 million in the first quarter of 2006. Expenses increased $48 million primarily due to higher natural gas and NGL purchase prices and $1 million due to higher processing costs. This was partially offset by lower NGL marketed volumes, which caused expenses to decrease $41 million.

Depreciation, Depletion and Amortization Expense (“DD&A”)

     DD&A of oil and gas properties is calculated by multiplying the percentage of total proved reserve volumes produced during the period, by the “depletable base”. The depletable base represents the net

25

capitalized investment plus future development costs in those reserves. 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 decreased $34 million in the first quarter of 2006. DD&A decreased $76 million due to a 14% decrease in the combined oil, gas and NGL production in the first quarter of 2006. This decrease was partially offset by an increase in the consolidated DD&A rate from $9.10 per Boe in the first quarter of 2005 to $9.92 per Boe in the first quarter of 2006 which caused oil and gas property related DD&A to increase by $42 million. The rate decreased due to the effect of property divestitures which occurred subsequent to March 31, 2005. This decrease was more than offset by increases caused by the effects of changes in the Canadian-to-U.S. dollar exchange rate and inflationary pressure on costs incurred subsequent to March 31, 2005 as well as estimated development costs to be spent in future periods on proved undeveloped reserves.

General and Administrative Expenses (“G&A”)

     Our 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 we serve 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 schedule for a summary of G&A expenses by component.

	Three Months Ended
	March 31,
	2006			2005
	(In millions)
Gross G&A	$	173			132
Capitalized G&A		(57	)		(47	)
Reimbursed G&A		(26	)		(27	)
Net G&A	$	90			58

     Gross G&A increased $41 million in the first quarter of 2006 compared to the same period of 2005. Higher employee compensation and benefits costs caused gross G&A to increase $27 million. Of this increase, $9 million represented stock option expense recognized in the first quarter of 2006 pursuant to our adoption of Statement of Financial Accounting Standard No. 123(R), Share Based Payment, and $4 million represented an increase in restricted stock expense due to our grants subsequent to the first quarter of 2005. In addition, changes in the Canadian-to-U.S. dollar exchange rate caused a $3 million increase in costs.

     Capitalized G&A increased $10 million in the first quarter of 2006 compared to the same period of 2005. The increase was primarily due to the increases in capitalizable salaries and benefits discussed above.

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Interest Expense

     The following schedule includes the components of interest expense for the first quarters of 2006 and 2005.

	Three Months Ended
	March 31,
	2006			2005
	(In millions)
Interest based on debt outstanding	$	115			132
Amortization of discounts/premiums		2			1
Amortization of capitalized loan costs		1			1
Capitalized interest		(16	)		(19	)
Other		(1	)		3
Total interest expense	$	101			118

     The average debt balance decreased from $8.0 billion in the first quarter of 2005 to $6.7 billion in the first quarter of 2006 due to debt repayments during 2005. This decrease in debt outstanding caused interest expense to decrease $23 million. This decrease in interest expense was partially offset by $6 million of additional interest due to higher floating rates in 2006. The average interest rate on outstanding debt increased from 6.7% in the first quarter of 2005 to 7.0% in the first quarter of 2006.

Change in Fair Value of Derivative Financial Instruments

     The following schedule includes the components of the change in fair value of derivative financial instruments for the first quarters of 2006 and 2005.

	Three Months Ended
	March 31,
	2006			2005
	(In millions)
Change in fair value of the option embedded in debentures exchangeable into shares of Chevron Corporation common stock	$	14			51
Ineffectiveness of commodity hedges		—			3
Other		(2	)		(2	)
Total	$	12			52

     The fair value of the option embedded in debentures exchangeable into shares of Chevron Corporation common stock is driven primarily by the price of Chevron Corporation’s common stock. As a result, increases or decreases in the price of such common stock generally will cause the fair value of this embedded option to increase or decrease in a like manner.

Reduction of Carrying Value of Oil and Gas Properties

     Currently, we have commitments to drill four wells in Nigeria. The first two wells were unsuccessful. After drilling the second unsuccessful well in the first quarter of 2006, we determined that the capitalized costs related to these two wells should be impaired. Therefore, in the first quarter of 2006, we recognized an $85 million impairment of our investment in Nigeria equal to the costs to drill the two dry holes and a proportionate share of block-related costs. There is no tax benefit related to this impairment.

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Other Income, net

     The following schedule includes the components of other income for the first quarters of 2006 and 2005.

	Three Months Ended
	March 31,
	2006			2005
	(In millions)
Interest and dividend income	$	28			26
Net gains on sales of non-oil and gas property and equipment		5			150
Loss on derivative financial instruments		—			(39	)
Other		(5	)		1
Total other income	$	28			138

     The increase in interest and dividend income in the first quarter of 2006 was primarily due to an increase in short-term interest rates, partially offset by lower cash and short-term investment balances.

     The decrease in the net gains on sales of non-oil and gas property and equipment is primarily due to the sale of certain midstream assets in January 2005.

     In March 2005, we 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 2005 property divestiture program.

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 was 38% in the first quarter of 2006 and the first quarter of 2005, respectively.

     The 2006 rate was higher than the statutory federal rate of 35% primarily due to the $85 million reduction of carrying value for Nigeria. We did not recognize a tax benefit on this reduction in carrying value due to the uncertainty of recognizing future taxable earnings in the Nigerian tax jurisdiction. Excluding the effect of this reduction of carrying value, the effective tax rate was 35%.

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

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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,
	2006			2005
	(In millions)
Cash provided by (used in):
Operating activities	$	1,522			1,388
Investing activities		(1,352	)		(501	)
Financing activities		(283	)		(538	)
Effect of exchange rate changes		1			(2	)
Net (decrease) increase in cash and cash equivalents	$	(112	)		347
Cash and cash equivalents at end of period	$	1,494			1,499
Short-term investments at end of period	$	734			1,033

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 2006. The increase in operating cash flow in the first three months of 2005 was primarily caused by the increase in net earnings as discussed in the “Results of Operations” section of this report.

Cash Flows from Investing Activities

     Capital Expenditures. Cash used for capital expenditures in the 2006 quarter was $1.3 billion. This total includes $1.2 billion for the acquisition, drilling or development of oil and gas properties. These amounts compare to cash used for capital expenditures of $867 million in the 2005 quarter which included $846 million for the acquisition, drilling or development of oil and gas properties.

     Proceeds from the Sale of Property and Equipment. We generated sale proceeds of $19 million and $432 million in the 2006 and 2005 quarters, respectively. The decrease in proceeds was largely due to our 2005 divesture program in which we sold non-core oil and gas properties as well as non-core midstream assets.

Cash Flows from Financing Activities

     Stock Repurchases. During the first quarter of 2006, we repurchased 4.2 million shares at a cost of $253 million. This compares to the repurchase of 12.7 million shares for $557 million in the first quarter of 2005.

     Issuance of Common Stock. We received proceeds of $19 million and $57 million from shares issued primarily from the exercise of employee stock options in the first quarter of 2006 and 2005, respectively.

     Dividends. Devon’s common stock dividends were $49 million and $36 million in the 2006 and 2005 quarters, respectively. Devon also paid $2 million of preferred stock dividends in 2006 and 2005. The increase in common stock dividends from 2005 to 2006 was primarily related to a 50% increase in the quarterly dividend rate which was partially offset by a decrease in the number of shares outstanding. Effective with the first quarter 2006 dividend payment, Devon increased its quarterly dividend rate from $0.075 per share to $0.1125 per share. The decrease in shares outstanding was primarily related to share

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repurchases partially offset by shares issued for stock option exercises.

Liquidity

     At March 31, 2006, our unrestricted cash and cash equivalents and short-term investments totaled $2.2 billion. During the first quarter of 2006 and 2005, such balances decreased $58 million and increased $413 million, respectively.

     Historically, our primary source of capital and liquidity has been operating cash flow. Additionally, we maintain a revolving line of credit and a commercial paper program which can be accessed as needed to supplement operating cash flow. Other available sources of capital and liquidity include the issuance of equity securities and long-term debt. We expect the combination of these sources of capital will be more than adequate to fund future capital expenditures and other contractual commitments.

Operating Cash Flow

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

Credit Lines

     Another source of liquidity is our $2.0 billion five-year, syndicated, unsecured revolving line of credit (the “Senior Credit Facility”). The Senior Credit Facility includes a five-year revolving Canadian subfacility in a maximum amount of U.S. $500 million.

     The Senior Credit Facility matures on April 7, 2011, and all amounts outstanding will be due and payable at that time unless the maturity is extended. Prior to each April 7 anniversary date, we have the option to extend the maturity of the Senior Credit Facility for one year, subject to the approval of the lenders.

     We have the right to increase the aggregate commitment amount under the Senior Credit Facility from $2.0 billion to $2.5 billion by requesting one or more lenders to increase their respective commitments or adding one or more additional lenders to the syndicate group. We expect to work with our lenders to increase the aggregate commitment amount in conjunction with the expected close of the Chief acquisition in the second quarter of this year. However, there is no guarantee that we will be successful in increasing the aggregate commitment amount.

     Amounts borrowed under the Senior Credit Facility may, at our election, bear interest at various fixed rate options for periods of up to twelve months. Such rates are generally less than the prime rate. We may also elect to borrow at the prime rate. The Senior Credit Facility currently provides for an annual facility fee of $1.8 million that is payable quarterly in arrears.

     As of April 30, 2006, there were no borrowings under the Senior Credit Facility. The available capacity under the Senior Credit Facility as of April 30, 2006, net of $356 million of outstanding letters of credit, was approximately $1.6 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

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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 March 31, 2006, Devon’s ratio as calculated pursuant to this covenant was 26.3%.

     Our access to funds from the Senior Credit Facility is not restricted under any “material adverse effect” clauses. It is not uncommon for credit agreements to include such clauses. These clauses can remove the obligation of the banks to fund the credit line if any condition or event would reasonably be expected to have a material and adverse effect on the borrower’s financial condition, operations, properties or business considered as a whole, the borrower’s ability to make timely debt payments, or the enforceability of material terms of the credit agreement. While our Senior Credit Facility includes covenants that require Devon to report a condition or event having a material adverse effect on Devon, the obligation of the banks to fund the Senior Credit Facility is not conditioned on the absence of a material adverse effect.

     We also have access to short-term credit under our commercial paper program. Total borrowings under the commercial paper program may not exceed $1.5 billion. Also, any borrowings under the commercial paper program reduce available capacity under the Senior Credit Facility on a dollar-for-dollar basis. Commercial paper debt generally has a maturity of between seven to 90 days, although it can have a maturity of up to 365 days. We had no commercial paper debt outstanding at April 30, 2006.

     We intend to use approximately $1.3 billion of short-term borrowings under our commercial paper program to fund a portion of the $2.2 billion acquisition of Chief which is expected to close near the end of the second quarter of 2006.

Common Stock Repurchase Program

     On August 3, 2005, we announced that our board of directors had authorized the repurchase of up to 50 million shares of our common stock. As of May 2, 2006, we had repurchased 6.5 million shares under this program for $387 million, or $59.80 per share. As a result of the Chief acquisition, this repurchase program has been suspended and will be reevaluated later in 2006.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

     There have been no material changes to the information included in Item 7A. “Quantitative and Qualitative Disclosures About Market Risk” in our 2005 Annual Report on Form 10-K.

Item 4. Controls and Procedures

Disclosure Controls and Procedures

     We have established disclosure controls and procedures to ensure that material information relating to Devon, including its consolidated subsidiaries, is made known to the officers who certify Devon’s financial reports and to other members of senior management and the Board of Directors.

     Based on their evaluation, Devon’s principal executive and principal financial officers have concluded that Devon’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) were effective as of March 31, 2006 to ensure that the information required to be disclosed by Devon in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms.

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Changes in Internal Control Over Financial Reporting

     There was no change in Devon’s internal control over financial reporting during the first quarter of 2006 that has materially affected, or is reasonably likely to materially affect, Devon’s internal control over financial reporting.

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Part II. Other Information

Item 1. Legal Proceedings

     There have been no material changes to the information included in Item 3. “Legal Proceedings” in our 2005 Annual Report on Form 10-K.

Item 1A. Risk Factors

     There have been no material changes to the information included in Item 1A. “Risk Factors” in our 2005 Annual Report on Form 10-K.

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

     The following table sets forth information with respect to repurchases by Devon of its shares of common stock during the first quarter of 2006.

					Total Number of		Maximum Number of
	Total Number		Average Price		Shares Purchased as		Shares that May Yet
	of Shares		Paid per		Part of Publicly Announced		Be Purchased Under
Period	Purchased		Share		Plans or Programs (1)		the Plans or Programs
January		—	$	—		—		47,774,400
February		2,188,700	$	60.63		2,188,700		45,585,700
March		2,052,699	$	58.52		2,052,699		43,533,001
Total		4,241,399	$	59.61		4,241,399

⁽¹⁾ On August 3, 2005, 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. The repurchase program is planned to extend through 2007.

Item 3. Defaults Upon Senior Securities

     None

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

     None

Item 5. Other Information

     None

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Item 6. Exhibits

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

Exhibit
Number
10.1	Amended and Restated Credit Agreement dated March 24, 2006, effective as of April 7, 2006 among Registrant as US Borrower, Northstar Energy Corporation and Devon Canada Corporation as Canadian Borrowers, Bank of America, N.A. as Administrative Agent, Swing Line Lender and L/C Issuer, JPMorgan Chase Bank, N.A. as Syndication Agent, Bank of Montreal D/B/A “Harris Nesbitt”, Royal Bank of Canada, Wachovia Bank, National Association as Co-Documentation Agents and The Other Lenders Party Hereto, Banc of America Securities LLC and J.P. Morgan Securities Inc., as Joint Lead Arrangers and Book Managers for the $2.0 billion five-year revolving credit facility.
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, 2006	/s/ Danny J. Heatly
	Danny J. Heatly
	Vice President – Accounting and
	Chief Accounting Officer

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INDEX TO EXHIBITS

Exhibit
Number	Description
10.1	Amended and Restated Credit Agreement dated March 24, 2006, effective as of April 7, 2006 among Registrant as US Borrower, Northstar Energy Corporation and Devon Canada Corporation as Canadian Borrowers, Bank of America, N.A. as Administrative Agent, Swing Line Lender and L/C Issuer, JPMorgan Chase Bank, N.A. as Syndication Agent, Bank of Montreal D/B/A “Harris Nesbitt”, Royal Bank of Canada, Wachovia Bank, National Association as Co-Documentation Agents and The Other Lenders Party Hereto, Banc of America Securities LLC and J.P. Morgan Securities Inc., as Joint Lead Arrangers and Book Managers for the $2.0 billion five-year revolving credit facility.
31.1	Certification of J. Larry Nichols, Chief Executive Officer of Registrant, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of Brian J. Jennings, Chief Financial Officer of Registrant, pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification of J. Larry Nichols, Chief Executive Officer of Registrant, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	Certification of Brian J. Jennings, Chief Financial Officer of Registrant, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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