DEVON ENERGY CORP/DE - 10-Q Quarterly Report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


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

		For the Quarterly Period Ended June 30, 2003

		or

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

Commission File No. 000-30176

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 x No o

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

The number of shares outstanding of Registrant’s common stock, par value $.10, as of July 31, 2003, was 231,880,000.

[This page intentionally left blank.]

TABLE OF CONTENTS


PART I. FINANCIAL INFORMATION
	ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS
		CONSOLIDATED BALANCE SHEETS
		CONSOLIDATED STATEMENTS OF OPERATIONS
		CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
		CONSOLIDATED STATEMENTS OF CASH FLOWS
		NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
	Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
	Item 3. Quantitative and Qualitative Disclosures About Market Risk
	Item 4. Controls and Procedures
Part II. Other Information
	Item 4. Submission of Matters to a Vote of Security Holders
	Item 6. Exhibits and Reports on Form 8-K
EX-10.1 First Amendment to Credit Agreement
EX-10.2 First Amendment to Canadian Credit Agrmt.
EX-10.3 Amendment No. 1 to Credit Agreement
EX-31.1 Certification of CEO Pursuant to Sec. 302
EX-31.2 Certification of CFO Pursuant to Sec. 302
EX-32.1 Certification of CEO Pursuant to Sec. 906
EX-32.2 Certification of CFO Pursuant to Sec. 906

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


		Page
		No.

	Part I. Financial Information		5
Item 1.	Consolidated Financial Statements
	Consolidated Balance Sheets, June 30, 2003 (Unaudited) and December 31, 2002		6
	Consolidated Statements of Operations (Unaudited) for the Three Months and Six Months Ended June 30, 2003 and 2002		7
	Consolidated Statements of Comprehensive Income (Unaudited) for the Three Months and Six Months Ended June 30, 2003 and 2002		8
	Consolidated Statements of Cash Flows (Unaudited) for the Six Months Ended June 30, 2003 and 2002		9
	Notes to Consolidated Financial Statements		10
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		29
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		45
Item 4.	Controls and Procedures		51
	Part II. Other Information
Item 4.	Submission of Matters to a Vote of Security Holders		52
Item 6.	Exhibits and Reports on Form 8-K		54

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 one billion cubic feet.

“Boe” means barrel of oil equivalent, determined by using the ratio of one Bbl or 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.

“MMBbls” means one million barrels.

“MMBoe” means one million Boe.

“MMBtu” means one million Btu.

“Mcf” means one thousand cubic feet.

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

“NYMEX” means New York Mercantile Exchange.

“Oil” includes crude oil and condensate.

DEVON ENERGY CORPORATION

PART I. FINANCIAL INFORMATION

ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2003 and 2002

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

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


					June 30,			December 31,
					2003			2002

					(Unaudited)
					(In millions, except share data)
				ASSETS
Current assets:
	Cash and cash equivalents				$	724		$	292
	Accounts receivable					965			639
	Inventories					71			26
	Fair value of financial instruments					11			4
	Income taxes receivable					11			56
	Assets of discontinued operations					—			7
	Investments and other current assets					57			40

			Total current assets			1,839			1,064

Property and equipment, at cost, based on the full cost method of accounting for oil and gas properties ($3,296 and $2,289 excluded from amortization in 2003 and 2002, respectively)						26,598			18,786
	Less accumulated depreciation, depletion and amortization					9,006			7,934

						17,592			10,852
Investment in ChevronTexaco Corporation common stock at fair value						512			472
Fair value of financial instruments						4			1
Goodwill						5,324			3,555
Other assets						340			281

			Total assets		$	25,611		$	16,225

				LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
	Accounts payable:
		Trade				651			376
		Revenues and royalties due to others				278			261
	Income taxes payable					75			9
	Current portion of long-term debt					575			—
	Accrued interest payable					147			119
	Merger related expenses payable					58			12
	Fair value of financial instruments					262			151
	Current portion of asset retirement obligation					33			—
	Accrued expenses and other current liabilities					131			114

			Total current liabilities			2,210			1,042

Other liabilities						395			323
Asset retirement obligation, long-term						612			—
Debentures exchangeable into shares of ChevronTexaco Corporation common stock						669			662
Other long-term debt						7,830			6,900
Preferred stock of a subsidiary						55			—
Deferred revenue						88			—
Fair value of financial instruments						24			18
Deferred income taxes						4,076			2,627
Stockholders’ equity:
	Preferred stock of $1.00 par value ($100 liquidation value) Authorized 4,500,000 shares; issued 1,500,000 in 2003 and 2002					1			1
	Common stock of $0.10 par value Authorized 800,000,000 shares; issued 235,538,000 in 2003 and 160,461,000 in 2002					24			16
	Additional paid-in capital					8,878			5,178
	Retained earnings (accumulated deficit)					688			(84	)
	Accumulated other comprehensive income (loss)					249			(267	)
	Other					(1	)		(3	)
	Treasury stock at cost: 3,700,000 shares in 2003 and 3,704,000 shares in 2002					(187	)		(188	)

			Total stockholders’ equity			9,652			4,653

			Total liabilities and stockholders’ equity		$	25,611		$	16,225

See accompanying notes to consolidated financial statements.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS


			Three Months Ended						Six Months Ended
			June 30,						June 30,

			2003			2002			2003			2002

						(Unaudited)
			(In millions, except per share amounts)
Revenues
	Oil sales		$	379		$	248		$	635		$	470
	Gas sales			1,007			562			1,881			1,028
	Natural gas liquids sales			92			72			199			127
	Marketing and midstream revenues			335			267			769			427

		Total revenues		1,813			1,149			3,484			2,052

Production and operating costs and expenses
	Lease operating expenses			223			162			388			316
	Transportation costs			51			38			92			76
	Production taxes			51			33			98			55
	Marketing and midstream operating costs and expenses			277			222			633			347
	Depreciation, depletion and amortization of property and equipment			427			323			723			634
	Accretion of asset retirement obligation			9			—			16			—
	General and administrative expenses			93			54			142			104
	Expenses related to mergers			7			—			7			—
	Reduction of carrying value of oil and gas properties			—			651			—			651

		Total production and operating costs and expenses		1,138			1,483			2,099			2,183

Earnings (loss) from operations				675			(334	)		1,385			(131	)
Other income (expenses)
	Interest expense			(130	)		(148	)		(260	)		(272	)
	Dividends on subsidiary’s preferred stock			(1	)		—			(1	)		—
	Effects of changes in foreign currency exchange rates			29			18			51			17
	Change in fair value of financial instruments			(1	)		24			9			7
	Other income			17			6			25			21

		Net other expenses		(86	)		(100	)		(176	)		(227	)

Earnings (loss) from continuing operations before income tax expense and cumulative effect of change in accounting principle				589			(434	)		1,209			(358	)
Income tax expense (benefit)
	Current			89			77			124			86
	Deferred			144			(305	)		309			(296	)

		Total income tax expense (benefit)		233			(228	)		433			(210	)

Earnings (loss) from continuing operations before cumulative effect of change in accounting principle				356			(206	)		776			(148	)
Discontinued operations
	Results of discontinued operations before income taxes			—			104			—			112
	Total income tax expense			—			2			—			6

		Net results of discontinued operations		—			102			—			106

Earnings (loss) before cumulative effect of change in accounting principle				356			(104	)		776			(42	)
Cumulative effect of change in accounting principle, net of income tax expense of $10 million				—			—			16			—

Net earnings (loss)				356			(104	)		792			(42	)
Preferred stock dividends				3			3			5			5

Net earnings (loss) applicable to common stockholders			$	353		$	(107	)	$	787		$	(47	)

Basic earnings (loss) per share:
	Earnings (loss) from continuing operations		$	1.67		$	(1.33	)	$	4.18		$	(1.01	)
	Net results of discontinued operations			—			0.65			—			0.70
	Cumulative effect of change in accounting principle			—			—			0.09			—

	Net earnings (loss) applicable to common stockholders		$	1.67		$	(0.68	)	$	4.27		$	(0.31	)

Diluted earnings (loss) per share:
	Earnings (loss) from continuing operations		$	1.62		$	(1.33	)	$	4.03		$	(1.01	)
	Net results of discontinued operations			—			0.65			—			0.70
	Cumulative effect of change in accounting principle			—			—			0.08			—

	Net earnings (loss) applicable to common stockholders		$	1.62		$	(0.68	)	$	4.11		$	(0.31	)

Weighted average common shares outstanding — basic				212			157			184			153

Weighted average common shares outstanding — diluted				221			163			193			159

See accompanying notes to consolidated financial statements.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


		Three Months Ended						Six Months Ended
		June 30,						June 30,

		2003			2002			2003			2002

		(Unaudited)
		(In millions)
Net earnings (loss)		$	356		$	(104	)	$	792		$	(42	)
Other comprehensive income (loss), net of tax:
	Foreign currency translation adjustments		248			202			541			200
	Reclassification adjustment for derivative losses (gains) reclassified into oil and gas sales		48			1			131			(41	)
	Change in fair value of outstanding hedging positions		(70	)		4			(182	)		(124	)
	Unrealized gains (losses) on marketable securities		34			(8	)		26			(5	)

Comprehensive income (loss)		$	616		$	95		$	1,308		$	(12	)

See accompanying notes to consolidated financial statements.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS


					Six Months Ended June 30,

					2003			2002

					(Unaudited)
					(In millions)
Cash flows from operating activities
	Earnings (loss) from continuing operations				$	776		$	(148	)
	Adjustments to reconcile earnings (loss) from continuing operations to net cash provided by operating activities:
		Depreciation, depletion and amortization of property and equipment				723			634
		Accretion of asset retirement obligation				16			—
		Accretion of discounts on long-term debt, net				12			16
		Reduction of carrying value of oil and gas properties				—			651
		Effects of changes in foreign currency exchange rates				(51	)		(17	)
		Change in fair value of derivative instruments				(9	)		(7	)
		Deferred income tax expense (benefit)				309			(296	)
		Operating cash flows of discontinued operations				—			33
		Gain on sale of assets				(2	)		(2	)
		Other				(16	)		(10	)
		Changes in assets and liabilities, net of acquisitions of businesses:
			(Increase) decrease in:
				Accounts receivable		(194	)		(33	)
				Inventories		(7	)		14
				Investments and other current assets		(9	)		(25	)
			Increase (decrease) in:
				Accounts payable		44			(66	)
				Income taxes payable		119			142
				Accrued interest and expenses		87			40
				Deferred revenue		(14	)		(33	)
				Long-term other liabilities		(18	)		(5	)

				Net cash provided by operating activities		1,766			888

Cash flows from investing activities
	Proceeds from sale of property and equipment					31			1,036
	Capital expenditures, including acquisitions of businesses					(1,100	)		(2,563	)
	Discontinued operations					—			(15	)
	Other					12			—

				Net cash used in investing activities		(1,057	)		(1,542	)

Cash flows from financing activities
	Proceeds from borrowings of long-term debt, net of issuance costs					50			4,730
	Principal payments on long-term debt					(380	)		(3,840	)
	Issuance of common stock, net of issuance costs					38			18
	Dividends paid on common stock					(16	)		(16	)
	Dividends paid on preferred stock					(5	)		(5	)

				Net cash (used in) provided by financing activities		(313	)		887

Effect of exchange rate changes on cash						36			(1	)

Net increase in cash and cash equivalents						432			232
Cash and cash equivalents at beginning of period						292			183

Cash and cash equivalents at end of period					$	724		$	415

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 2002 Annual Report on Form 10-K.

In the opinion of Devon’s management, all adjustments (all of which are normal and recurring) have been made which are necessary to fairly state the consolidated financial position of Devon and its subsidiaries as of June 30, 2003, and the results of their operations and their cash flows for the three-month and six-month periods ended June 30, 2003 and 2002. Certain of the 2002 amounts in the accompanying consolidated financial statements have been reclassified to conform to the 2003 presentation.

2. Business Combinations and Pro Forma Information

Ocean Energy Inc.

On April 25, 2003, Devon completed its merger with Ocean Energy Inc. (“Ocean”). In the transaction, Devon issued 0.414 shares of its common stock for each outstanding share of Ocean common stock (or a total of approximately 74 million shares). Also, Devon assumed approximately $1.8 billion of debt (current and long-term) from Ocean.

Devon acquired Ocean for the significant development projects and exploration prospects in both the deepwater Gulf of Mexico and international, and the expanded exposure to both the Gulf of Mexico and international markets.

The calculation of the purchase price and the preliminary allocation to assets and liabilities as of April 25, 2003, are shown below. The purchase price allocation is preliminary because certain items such as the determination of the final tax bases and the fair value of certain assets and liabilities as of the acquisition date have not been completed.

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


				(In millions,
				except share
				price)
Calculation and preliminary allocation of purchase price:
	Shares of Devon common stock issued to Ocean stockholders				74
	Average Devon stock price			$	48.05

	Fair value of common stock issued			$	3,546
	Plus estimated merger costs incurred				100
	Plus fair value of Ocean convertible preferred stock assumed by a Devon subsidiary				64
	Plus fair value of Ocean employee stock options assumed by Devon				124

			Total purchase price		3,834
	Plus fair value of liabilities assumed by Devon:
		Current liabilities			638
		Long-term debt			1,436
		Deferred revenue			97
		Asset retirement obligation, long-term			121
		Other noncurrent liabilities			72
		Deferred income taxes			829

			Total purchase price plus liabilities assumed	$	7,027

	Fair value of assets acquired by Devon:
		Current assets			268
		Proved oil and gas properties			4,131
		Unproved oil and gas properties			1,060
		Other property and equipment			79
		Other noncurrent assets			38
		Goodwill (none deductible for income taxes)			1,451

			Total fair value of assets acquired	$	7,027

Pro Forma Information

Set forth in the following table is certain unaudited pro forma financial information for the six-month periods ended June 30, 2003 and 2002. The information for the six-month periods ended June 30, 2003 and 2002, has been prepared assuming the Ocean merger and the January 24, 2002, Mitchell Energy & Development Corp. merger were consummated on January 1, 2002. All pro forma information is based on estimates and assumptions deemed appropriate by Devon. The pro forma information is presented for illustrative purposes only. If the transactions had occurred in the past, Devon’s operating results might have been different from those presented in the following table. The pro forma information should not be relied upon as an indication of the operating results that Devon would have achieved if the transactions had occurred on January 1, 2002. The pro forma information also should not be used as an indication of the future results that Devon will achieve after the transactions.

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


			Pro Forma Information
			Six Months Ended June 30,

			2003			2002

			(In millions, except per
			share amounts and
			production volumes)
Revenues
	Oil sales		$	886		$	755
	Gas sales			2,139			1,263
	Natural gas liquids sales			207			144
	Marketing and midstream revenues			769			499

		Total revenues		4,001			2,661

Production and operating costs and expenses
	Lease operating expenses			465			420
	Transportation costs			104			92
	Production taxes			112			72
	Marketing and midstream operating costs and expenses			633			414
	Depreciation, depletion and amortization of property and equipment			915			976
	Accretion of asset retirement obligation			18			—
	General and administrative expenses			175			159
	Reduction of carrying value of oil and gas properties			—			651

		Total production and operating costs and expenses		2,422			2,784

Earnings (loss) from operations				1,579			(123	)
Other income (expenses)
	Interest expense			(273	)		(290	)
	Dividends on subsidiary’s preferred stock			(1	)		(2	)
	Effects of changes in foreign currency exchange rates			51			18
	Change in fair value of financial instruments			9			7
	Other income			26			20

		Net other expenses		(188	)		(247	)

Earnings (loss) from continuing operations before income tax expense and cumulative effect of change in accounting principle				1,391			(370	)
Income tax expense (benefit)
	Current			149			100
	Deferred			359			(304	)

		Total income tax expense (benefit)		508			(204	)

Earnings (loss) from continuing operations before cumulative effect of change in accounting principle				883			(166	)
Discontinued operations
	Results of discontinued operations before income taxes			—			112
	Total income tax expense			—			6

		Net results of discontinued operations		—			106

Earnings (loss) before cumulative effect of change in accounting principle				883			(60	)
Cumulative effect of change in accounting principle, net of income tax expense of $19 million				29			—

Net earnings (loss)				912			(60	)
Preferred stock dividends				5			5

Net earnings (loss) applicable to common stockholders			$	907		$	(65	)

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


Basic earnings (loss) per share:
	Earnings (loss) from continuing operations	$	3.81	$	(0.75	)
	Net results of discontinued operations		—		0.47
	Cumulative effect of change in accounting principle		0.12		—

	Net earnings (loss) applicable to common stockholders	$	3.93	$	(0.28	)

Diluted earnings (loss) per share:
	Earnings (loss) from continuing operations	$	3.69	$	(0.75	)
	Net results of discontinued operations		—		0.47
	Cumulative effect of change in accounting principle		0.12		—

	Net earnings (loss) applicable to common stockholders	$	3.81	$	(0.28	)

Weighted average common shares outstanding — basic			231		225

Weighted average common shares outstanding — diluted			239		235

Production volumes:
	Oil (MMBbls)		34		37
	Gas (Bcf)		447		476
	NGLs (MMBbls)		11		11
	MMBoe		119		128

3. Debt

Amendment of Existing Credit Facilities

Devon has $1 billion of unsecured long-term credit facilities (the “Credit Facilities”). The Credit Facilities include a U.S. facility of $725 million (the “U.S. Facility”) and a Canadian facility of $275 million (the “Canadian Facility”). The $725 million U.S. Facility consists of a Tranche A facility of $200 million and a Tranche B facility of $525 million.

The Tranche A facility matures on October 15, 2004. Devon may borrow funds under the Tranche B facility until June 2, 2004 (the “Tranche B Revolving Period”). Devon may request that the Tranche B Revolving Period be extended an additional 364 days by notifying the agent bank of such request between 30 and 60 days prior to the end of the Tranche B Revolving Period. On June 2, 2004, at the end of the Tranche B Revolving Period, Devon may convert the then outstanding balance under the Tranche B facility to a one-year term loan by paying the Agent a fee of 25 basis points. The applicable borrowing rate would be at LIBOR plus 112.5 basis points. On June 30, 2003, there were no borrowings outstanding under the $725 million U.S. Facility. The available capacity under the U.S. Facility as of July 31, 2003, net of outstanding letters of credit, was approximately $591 million.

Devon may borrow funds under the $275 million Canadian Facility until June 2, 2004 (the “Canadian Facility Revolving Period”). Devon may request that the Canadian Facility Revolving Period be extended an additional 364 days by notifying the agent bank of such request between 30 and 60 days prior to the end of the Canadian Facility Revolving Period. Debt outstanding as of the end of the Canadian Facility Revolving Period is payable in semiannual installments of 2.5% each for the following five years, with the final installment due five years and one day following the end of the Canadian Facility Revolving Period. On June 30, 2003, there were no borrowings under the $275 million Canadian facility. The available capacity under the Canadian Facility as of July 31, 2003, net of outstanding letters of credit, was approximately $207 million.

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

Under the terms of the Credit Facilities, Devon has the right to reallocate up to $100 million of the unused Tranche B facility maximum credit amount to the Canadian Facility. Conversely, Devon also has the right to reallocate up to $100 million of unused Canadian Facility maximum credit amount to the Tranche B Facility.

Amounts borrowed under the Credit Facilities bear interest at various fixed rate options that Devon may elect for periods up to six months. Such rates are generally less than the prime rate. Devon may also elect to borrow at the prime rate. The Credit Facilities provide for an annual facility fee of $1.4 million that is payable quarterly in arrears.

The agreements governing the Credit Facilities contain certain covenants and restrictions, including a maximum allowed debt-to-capitalization ratio of 65% as defined in the agreements. As of June 30, 2003, Devon’s debt-to-capitalization ratio as defined in the agreements was 44.4%.

Debt Securities

On August 4, 2003, Devon issued $500 million of 2.75% notes due August 1, 2006. The debt securities are unsecured obligations of Devon and are redeemable at the option of Devon, in whole or in part, at any time at a redemption price equal to the greater of 100% of the principal amount of the notes outstanding plus accrued and unpaid interest to the redemption date or the sum of the present values of the remaining scheduled payments of principal and interest thereon (exclusive of interest accrued to the date of redemption) from the redemption date to the maturity date plus accrued and unpaid interest to the redemption date. The proceeds from the issuance of these debt securities, net of discounts and issuance costs, of $498 million were used to repay amounts outstanding under the $3 billion senior unsecured term loan credit facility.

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

Ocean Debt

In connection with the Ocean merger, Devon assumed $1.8 billion of debt. A summary of this debt is as follows:


		Fair Value of Debt
		Assumed

		(In millions)
Revolving credit line		$	160
Note payable			50
Senior notes and senior subordinated notes:
	7.875% due August 2003 (principal of $100 million)		102
	7.625% due July 2005 (principal of $125 million)		139
	7.500% due September 2007 (principal of $150 million)		169
	4.375% due October 2007 (principal of $400 million)		410
	8 375% due July 2008 (principal of $200 million)		208
	7.250% due September 2011 (principal of $350 million)		406
	8.250% due July 2018 (principal of $125 million)		147
	Other		6

			1,797
Less amount classified as current			361

Long-term debt		$	1,436

Change of control provisions required the outstanding borrowings under the credit facility and note payable to be fully paid immediately. Additionally, Devon was required to extend purchase offers for certain senior notes and the senior subordinated notes. As a result of these purchase offers, which expired on June 13, 2003, Devon paid $118 million for the aggregate principal amount tendered. The purchase price for each offer was 101 percent of the principal amount of the notes tendered plus accrued and unpaid interest to and including the purchase date. All notes that were not tendered remain outstanding except as described below.

Included in the $118 million of debt retired pursuant to the purchase offer were $13 million of the 8.375% notes and $57 million of the 7.875% notes. The remaining $195 million of 8.375% notes were called and redeemed on July 1, 2003. Additionally, the remaining $43 million of 7.875% senior notes were paid August 1, 2003, when they were due.

4. Derivative Instruments and Hedging Activities

Devon has periodically entered into oil and gas financial instruments and foreign exchange rate swaps to manage its exposure to oil and gas price volatility. The foreign exchange rate swaps mitigate the effect of volatility in the Canadian-to-U.S. dollar exchange rate on certain Canadian gas revenues that are based on U.S. dollar prices. Devon has also entered into interest rate swaps to manage its exposure to interest rate volatility. The interest rate swaps mitigate either the effects on interest expense for variable-rate debt instruments, or the debt fair values for fixed-rate debt. It is Devon’s policy to only enter into derivative contracts with investment grade rated counterparties deemed by management to be competent and competitive market makers. The oil and gas reference prices upon which the price hedging instruments are based reflect

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

various market indices that have a high degree of historical correlation with actual prices received by Devon.

As of June 30, 2003, $251 million of net deferred losses on derivative instruments in “accumulated other comprehensive income (loss)” are expected to be reclassified to earnings from operations during the next 12 months assuming no change in commodity prices from the June 30, 2003 level. The transactions and events expected to occur over the next 12 months that will necessitate reclassifying these derivatives’ losses to earnings from operations are primarily the production and sale of the hedged oil and gas quantities. The maximum term over which Devon is hedging exposures to the variability of cash flows for commodity price risk is 30 months.

Devon recorded in its statements of operations a loss of $1 million and a gain of $24 million in the second quarter of 2003 and 2002, respectively, and gains of $9 million and $7 million in the six-month periods ended June 30, 2003 and 2002, respectively, for the change in fair value of derivative instruments that do not qualify for hedge accounting treatment, as well as the ineffectiveness of derivatives that do qualify as hedges.

5. Asset Retirement Obligations

Effective January 1, 2003, Devon adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (SFAS No. 143) using a cumulative effect approach to recognize transition amounts for asset retirement obligations, asset retirement costs and accumulated depreciation. SFAS No. 143 requires liability recognition for retirement obligations associated with tangible long-lived assets, such as producing well sites, offshore production platforms, and natural gas processing plants. The obligations included within the scope of SFAS No. 143 are those for which a company faces a legal obligation for settlement. The initial measurement of the asset retirement obligation is fair value, defined as “the price that an entity would have to pay a willing third party of comparable credit standing to assume the liability in a current transaction other than in a forced or liquidation sale.”

The asset retirement cost equal to the fair value of the retirement obligation is capitalized as part of the cost of the related long-lived asset and allocated to expense using a systematic and rational method.

Devon previously estimated costs of dismantlement, removal, site reclamation, and other similar activities in the total costs that are subject to depreciation, depletion, and amortization. However, Devon did not record a separate asset or liability for such amounts. Upon adoption, Devon recorded a cumulative-effect-type adjustment for an increase to net earnings of $16 million net of deferred taxes of $10 million. Additionally, Devon established an asset retirement obligation of $453 million, an increase to property and equipment of $400 million and a decrease in accumulated DD&A of $79 million.

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

Following is a reconciliation of the asset retirement obligation from December 31, 2002 to June 30, 2003.


		(In millions)

Asset retirement obligation as of December 31, 2002		$	—
	Cumulative effect of change in accounting principle		453
	Asset retirement obligation assumed from Ocean merger		134
	Liabilities incurred		25
	Liabilities settled		(13	)
	Accretion expense		16
	Foreign currency translation adjustment		30

Asset retirement obligation as of June 30, 2003			645
Less current portion			33

Asset retirement obligation, long-term		$	612

Following is a reconciliation of reported net income and the related earnings per share amounts assuming the provisions of SFAS No. 143 had been adopted as of January 1, 2000.


			For the Year Ended December 31,

			2002			2001			2000

			(In millions, except per share amounts)
Net earnings applicable to common stockholders, as reported			$	94		$	93		$	720
Net change in depreciation, depletion and amortization of property and equipment due to adoption of SFAS No. 143				16			30			26
Less accretion of asset retirement obligation				(25	)		(15	)		(10	)
Deferred taxes				4			(6	)		(6	)

		Effect on net earnings		(5	)		9			10

Net earnings applicable to common stockholders, as adjusted			$	89		$	102		$	730

Basic earnings per share:
	Net earnings applicable to common stockholders, as reported		$	0.61		$	0.73		$	5.66
	Effect on net earnings			(0.03	)		0.07			0.08

	Net earnings applicable to common stockholders, as adjusted		$	0.58		$	0.80		$	5.74

Diluted earnings per share:
	Net earnings applicable to common stockholders, as reported		$	0.61		$	0.72		$	5.50
	Effect on net earnings			(0.03	)		0.07			0.08

	Net earnings applicable to common stockholders, as adjusted		$	0.58		$	0.79		$	5.58

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


			For Three Months
			Ended June 30,

			2003		2002

			(In millions, except)
			(per share amounts)
Net earnings (loss) applicable to common stockholders, as reported			$	353	$	(107	)
Net change in depreciation, depletion and amortization of property and equipment due to adoption of SFAS No. 143				—		4
Less accretion of asset retirement obligation				—		(7	)
Deferred taxes				—		1

		Effect on net earnings		—		(2	)

Net earnings (loss) applicable to common stockholders, as adjusted			$	353	$	(109	)

Basic earnings (loss) per share:
	Net earnings (loss) applicable to common stockholders, as reported		$	1.67	$	(0.68	)
	Effect on net earnings			—		(0.01	)

	Net earnings (loss) applicable to common stockholders, as adjusted		$	1.67	$	(0.69	)

Diluted earnings (loss) per share:
	Net earnings (loss) applicable to common stockholders, as reported		$	1.62	$	(0.68	)
	Effect on net earnings			—		(0.01	)

	Net earnings (loss) applicable to common stockholders, as adjusted		$	1.62	$	(0.69	)


			For Six Months
			Ended June 30,

			2003			2002

			(In millions, except per share amounts)
Net earnings (loss) applicable to common stockholders, as reported			$	787		$	(47	)
Less cumulative effect of change in accounting principle				(16	)		—
Net change in depreciation, depletion and amortization of property and equipment due to adoption of SFAS No. 143				—			8
Less accretion of asset retirement obligation				—			(11	)
Deferred taxes				—			1

		Effect on net earnings		(16	)		(2	)

Net earnings (loss) applicable to common stockholders, as adjusted			$	771		$	(49	)

Basic earnings (loss) per share:
	Net earnings (loss) applicable to common stockholders, as reported		$	4.27		$	(0.31	)
	Effect on net earnings			(0.09	)		(0.01	)

	Net earnings (loss) applicable to common stockholders, as adjusted		$	4.18		$	(0.32	)

Diluted earnings (loss) per share:
	Net earnings (loss) applicable to common stockholders, as reported		$	4.11		$	(0.31	)
	Effect on net earnings			(0.08	)		(0.01	)

	Net earnings (loss) applicable to common stockholders, as adjusted		$	4.03		$	(0.32	)

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

Following is a summary of the asset retirement obligation assuming the provisions of SFAS No. 143 had been adopted as of January 1, 2000.


		(In millions)

Asset retirement obligation as of:
	January 1, 2000	$	163
	December 31, 2000		244
	December 31, 2001		397
	December 31, 2002		453
	June 30, 2003		645

6. Earnings Per Share

The following table reconciles the net earnings and common shares outstanding used in the calculations of basic and diluted earnings per share for the three-month and six-month periods ended June 30, 2003. The diluted loss per share calculations for the three-month and six-month periods ended June 30, 2002 produced results that are anti-dilutive. (The diluted calculation for the three months ended June 30, 2002 reduced the net loss by $2 million and increased the common shares outstanding by 6 million shares. The diluted calculation for the six months ended June 30, 2002 reduced the net loss by $5 million and increased the common shares outstanding by 6 million shares.) Therefore, the reported diluted loss per share amounts for the three-month and six-month periods ended June 30, 2002 in the accompanying consolidated statements of operations are the same as the basic loss per share amounts.


			Net Earnings				Net
			Applicable		Common		Earnings
			to Common		Shares		Per
			Stockholders		Outstanding		Share

			(In millions)

Three Months Ended June 30, 2003:
	Basic earnings per share		$	353		212	$	1.67

	Dilutive effect of:
		Potential common shares issuable upon conversion of senior convertible debentures (the increase in net earnings is net of income tax expense of $1 million)		2		4
		Potential common shares issuable upon conversion of preferred stock of subsidiary		1		1
		Potential common shares issuable upon the exercise of outstanding stock options		—		4

	Diluted earnings per share		$	356		221	$	1.62

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


			Net Earnings				Net
			Applicable		Common		Earnings
			to Common		Shares		Per
			Stockholders		Outstanding		Share

			(In millions)

Six Months Ended June 30, 2003:
	Basic earnings per share		$	787		184	$	4.27

	Dilutive effect of:
		Potential common shares issuable upon conversion of senior convertible debentures (the increase in net earnings is net of income tax expense of $3 million)		5		4
		Potential common shares issuable upon conversion of preferred stock of subsidiary		1		1
		Potential common shares issuable upon the exercise of outstanding stock options		—		4

	Diluted earnings per share		$	793		193	$	4.11

All options to purchase Devon common stock were excluded from the diluted earnings per share calculations for the 2002 periods because of the anti-dilutive effect of such options.

Certain options to purchase shares of Devon’s common stock have been excluded from the 2003 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		For the Six
	Months Ended		Months Ended
	June 30, 2003		June 30, 2003

Options excluded from dilution calculation (in millions)		3		5
Range of exercise prices	$	50.85 - $89.66	$	49.04 - $89.66
Weighted average exercise price	$	58.05	$	55.43

The excluded options for 2003 expire between July 1, 2003 and December 2, 2012.

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 would be 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, established accounting and disclosure requirements using a fair value-based method of accounting for stock-based employee compensation plans. As allowed by SFAS No. 123, Devon has elected to continue to apply the intrinsic value-based method of accounting described above, and has adopted the disclosure requirements of SFAS No. 123.

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

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 second quarter and first six months 2003 and 2002 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						Six Months
			Ended June 30,						Ended June 30,

			2003			2002			2003			2002

			(In millions, except per share amounts)
Net earnings (loss) available to common stockholders, as reported			$	353		$	(107	)	$	787		$	(47	)
Total stock-based employee compensation expense determined under the fair value based method for all awards, net of related tax effects				(5	)		(3	)		(10	)		(6	)

Net earnings (loss) available to common stockholders, pro forma			$	348		$	(110	)	$	777		$	(53	)

Net earnings (loss) per share available to common stockholders:
	As reported:
		Basic	$	1.67		$	(0.68	)	$	4.27		$	(0.31	)
		Diluted	$	1.62		$	(0.68	)	$	4.11		$	(0.31	)
	Pro forma:
		Basic	$	1.65		$	(0.70	)	$	4.22		$	(0.35	)
		Diluted	$	1.60		$	(0.70	)	$	4.06		$	(0.35	)

7. Supplemental Cash Flow Information

Cash payments (refunds) for interest and income taxes in the first six months of 2003 and 2002 are presented below:


	Six Months Ended
	June 30,

	2003		2002

	(In millions)
Interest paid	$	249	$	323
Income taxes paid (refunded)	$	15	$	(86	)

The 2003 Ocean merger and the 2002 Mitchell merger involved non-cash consideration as presented below:


	Ocean		Mitchell
	Merger		Merger

	(In millions)
Value of common stock issued	$	3,546	$	1,512
Convertible preferred stock assumed		64		—
Employee stock options assumed		124		27
Liabilities assumed		2,364		824
Deferred tax liability created		829		796

Assets acquired with non-cash consideration	$	6,927	$	3,159

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

8. Segment Information

Devon manages its business by country. As such, Devon identifies its reporting segments based on geographic areas. Devon has three reporting segments: its operations in the U.S., its operations in Canada and its international operations outside of North America. Substantially all of these segments’ operations involve oil and gas producing and marketing and midstream activities. Following is certain financial information regarding Devon’s segments. The revenues reported are all from external customers.


							Inter-
			U.S.		Canada		national		Total

			(In millions)
As of June 30, 2003:
	Current assets		$	1,219	$	401	$	219	$	1,839
	Property and equipment, net of accumulated depreciation, depletion and amortization			10,421		4,486		2,685		17,592
	Investment in ChevronTexaco Corporation common stock			512		—		—		512
	Goodwill			3,017		2,239		68		5,324
	Other assets			297		29		18		344

		Total assets	$	15,466	$	7,155	$	2,990	$	25,611

	Current liabilities			1,676		392		142		2,210
	Other liabilities			389		4		2		395
	Asset retirement obligation, long-term			376		217		19		612
	Debentures exchangeable into shares of ChevronTexaco Corporation common stock			669		—		—		669
	Other long-term debt			3,773		4,057		—		7,830
	Preferred stock of a subsidiary			55		—		—		55
	Deferred revenue			88		—		—		88
	Fair value of financial instruments			17		7		—		24
	Deferred income taxes			2,084		1,523		469		4,076
	Stockholders’ equity			6,339		955		2,358		9,652

		Total liabilities and stockholders’ equity	$	15,466	$	7,155	$	2,990	$	25,611

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


										Inter-
				U.S.			Canada			national			Total

				(In millions)
Three Months Ended June 30, 2003:
	Revenues
		Oil sales		$	219		$	77		$	83		$	379
		Gas sales			692			311			4			1,007
		Natural gas liquids sales			64			27			1			92
		Marketing and midstream revenues			331			4			—			335

			Total revenues		1,306			419			88			1,813

	Production and operating costs and expenses
		Lease operating expenses			125			79			19			223
		Transportation costs			34			16			1			51
		Production taxes			49			—			2			51
		Marketing and midstream operating costs and expenses			275			2			—			277
		Depreciation, depletion and amortization of property and equipment			289			95			43			427
		Accretion of asset retirement obligation			6			3			—			9
		General and administrative expenses			77			11			5			93
		Expenses related to mergers			7			—			—			7

			Total production and operating costs and expenses		862			206			70			1,138

	Earnings from operations				444			213			18			675
	Other income (expenses)
		Interest expense			(54	)		(72	)		(4	)		(130	)
		Dividends on subsidiary’s preferred stock			(1	)		—			—			(1	)
		Effects of changes in foreign currency exchange rates			—			28			1			29
		Change in fair value of financial instruments			3			(4	)		—			(1	)
		Other income			12			3			2			17

			Net other expenses		(40	)		(45	)		(1	)		(86	)

	Earnings from continuing operations before income tax expense				404			168			17			589
	Income tax expense
		Current			80			—			9			89
		Deferred			81			63			—			144

			Total income tax expense		161			63			9			233

	Net earnings				243			105			8			356
	Preferred stock dividends				3			—			—			3

	Net earnings applicable to common stockholders			$	240		$	105		$	8		$	353

	Capital expenditures			$	427		$	108		$	53		$	588

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


										Inter
				U.S.			Canada			national		Total

				(In millions)
Three Months Ended June 30, 2002:
	Revenues
		Oil sales		$	148		$	90		$	10	$	248
		Gas sales			377			185			—		562
		Natural gas liquids sales			51			21			—		72
		Marketing and midstream revenues			262			5			—		267

			Total revenues		838			301			10		1,149

	Production and operating costs and expenses
		Lease operating expenses			96			62			4		162
		Transportation costs			26			12			—		38
		Production taxes			31			2			—		33
		Marketing and midstream operating costs and expenses			218			4			—		222
		Depreciation, depletion and amortization of property and equipment			220			102			1		323
		General and administrative expenses			42			9			3		54
		Reduction of carrying value of oil and gas properties			—			651			—		651

			Total production and operating costs and expenses		633			842			8		1,483

	Earnings (loss) from operations				205			(541	)		2		(334	)
	Other income (expenses)
		Interest expense			(73	)		(75	)		—		(148	)
		Effects of changes in foreign currency exchange rates			—			17			1		18
		Change in fair value of financial instruments			25			(1	)		—		24
		Other income			6			(1	)		1		6

			Net other income (expenses)		(42	)		(60	)		2		(100	)

	Earnings (loss) from continuing operations before income tax expense				163			(601	)		4		(434	)
	Income tax expense (benefit)
		Current			68			8			1		77
		Deferred			(47	)		(259	)		1		(305	)

			Total income tax expense (benefit)		21			(251	)		2		(228	)

	Earnings (loss) from continuing operations				142			(350	)		2		(206	)
	Discontinued operations
		Results of discontinued operations before income taxes			—			—			104		104
		Total income tax expense			—			—			2		2

			Net results of discontinued operations		—			—			102		102

	Net earnings (loss)				142			(350	)		104		(104	)
	Preferred stock dividends				3			—			—		3

	Net earnings (loss) applicable to common stockholders			$	139		$	(350	)	$	104	$	(107	)

	Capital expenditures			$	302		$	56		$	27	$	385

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


											Inter
					U.S.			Canada			national			Total

					(In millions)
Six Months Ended June 30, 2003:
		Revenues
			Oil sales		$	382		$	161		$	92		$	635
			Gas sales			1,249			628			4			1,881
			Natural gas liquids sales			138			60			1			199
			Marketing and midstream revenues			761			8			—			769

				Total revenues		2,530			857			97			3,484

		Production and operating costs and expenses
			Lease operating expenses			215			152			21			388
			Transportation costs			60			31			1			92
			Production taxes			95			1			2			98
			Marketing and midstream operating costs and expenses			629			4			—			633
			Depreciation, depletion and amortization of property and equipment			502			176			45			723
			Accretion of asset retirement obligation			10			6			—			16
			General and administrative expenses			114			21			7			142
			Expenses related to mergers			7			—			—			7

				Total production and operating costs and expenses		1,632			391			76			2,099

		Earnings from operations				898			466			21			1,385
		Other income (expenses)
			Interest expense			(110	)		(144	)		(6	)		(260	)
			Dividends on subsidiary’s preferred stock			(1	)		—			—			(1	)
			Effects of changes in foreign currency exchange rates			—			50			1			51
			Change in fair value of financial instruments			11			(2	)		—			9
			Other income			14			5			6			25

				Net other income (expenses)		(86	)		(91	)		1			(176	)

		Earnings from continuing operations before income tax expense and cumulative effect of change in accounting principle				812			375			22			1,209
		Income tax expense
			Current			103			11			10			124
			Deferred			155			153			1			309

				Total income tax expense		258			164			11			433

	Earnings from continuing operations before cumulative effect of change in accounting principle					554			211			11			776
		Cumulative effect of change in accounting principle				11			5			—			16

		Net earnings				565			216			11			792
		Preferred stock dividends				5			—			—			5

		Net earnings applicable to common stockholders			$	560		$	216		$	11		$	787

		Capital expenditures			$	669		$	348		$	83		$	1,100

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


										Inter
				U.S.			Canada			national			Total

				(In millions)
Six Months Ended June 30, 2002:
	Revenues
		Oil sales		$	278		$	172		$	20		$	470
		Gas sales			680			348			—			1,028
		Natural gas liquids sales			86			41			—			127
		Marketing and midstream revenues			420			7			—			427

			Total revenues		1,464			568			20			2,052

	Production and operating costs and expenses
		Lease operating expenses			187			123			6			316
		Transportation costs			48			28			—			76
		Production taxes			52			3			—			55
		Marketing and midstream operating costs and expenses			343			4			—			347
		Depreciation, depletion and amortization of property and equipment			424			208			2			634
		General and administrative expenses			77			18			9			104
		Reduction of carrying value of oil and gas properties			—			651			—			651

			Total production and operating costs and expenses		1,131			1,035			17			2,183

	Earnings (loss) from operations				333			(467	)		3			(131	)
	Other income (expenses)
		Interest expense			(122	)		(148	)		(2	)		(272	)
		Effects of changes in foreign currency exchange rates			—			17			—			17
		Change in fair value of financial instruments			5			2			—			7
		Other income			15			2			4			21

			Net other income (expenses)		(102	)		(127	)		2			(227	)

	Earnings (loss) from continuing operations before income tax expense				231			(594	)		5			(358	)
	Income tax expense (benefit)
		Current			74			9			3			86
		Deferred			(42	)		(256	)		2			(296	)

			Total income tax expense (benefit)		32			(247	)		5			(210	)

	Earnings (loss) from continuing operations				199			(347	)		—			(148	)
	Discontinued operations
		Results of discontinued operations before income taxes			—			—			112			112
		Total income tax expense			—			—			6			6

			Net results of discontinued operations		—			—			106			106

	Net earnings (loss)				199			(347	)		106			(42	)
	Preferred stock dividends				5			—			—			5

	Net earnings (loss) applicable to common stockholders			$	194		$	(347	)	$	106		$	(47	)

	Capital expenditures, including acquisitions of businesses			$	2,224		$	295		$	44		$	2,563

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

9. 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 from management’s estimate.

Environmental Matters

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

Certain of Devon’s subsidiaries acquired in past mergers are involved in matters in which it has been alleged that such subsidiaries are potentially responsible parties (“PRPs”) under CERCLA or similar state legislation with respect to various waste disposal areas owned or operated by third parties. As of June 30, 2003, Devon’s consolidated balance sheet included $7 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

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

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. 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. The plaintiffs in these lawsuits propose to expand them into county or state-wide class actions relating specifically to transportation and related costs associated with Devon’s Wyoming gas production. 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-month and six-month periods ended June 30, 2003, compared to the three-month and six-month periods ended June 30, 2002, and in financial condition since December 31, 2002. It is presumed that readers have read or have access to Devon’s 2002 Annual Report on Form 10-K which includes disclosures regarding critical accounting policies as part of Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Overview

Net earnings for the second quarter of 2003 were $356 million, or $1.62 per share. This compares to a net loss of $104 million, or $0.68 per share for the second quarter of 2002. Net earnings for the first half of 2003 were $792 million, or $4.11 per share. This compares to a net loss of $42 million, or $0.31 per share for the first half of 2002. The increases in second quarter and first half earnings were due to increases in both production and prices of oil, natural gas and NGLs and the fact that 2002 earnings were adversely impacted by a $371 million after-tax reduction in the carrying value of oil and gas properties.

Results of Operations

Total revenues increased $664 million, or 58%, in the second quarter of 2003, and $1.4 billion, or 70%, in the first half of 2003. This was the result of increases in both production and prices of oil, gas and NGLs as well as an increase in marketing and midstream revenues. The increase in production was primarily the result of the April 2003 Ocean merger and the January 2002 Mitchell merger, partially offset by property divestitures which occurred in 2002.

Oil, gas and NGL revenues were up $596 million, or 67%, for the second quarter of 2003 compared to the second quarter of 2002, and $1.1 billion, or 67%, for the first half of 2003 compared to the first half of 2002. The three-month and six-month periods’ comparison of production and price changes are shown in the following tables. (Note: Unless otherwise stated, all dollar amounts are expressed in U.S. dollars.)


		Total

		Three Months Ended June 30,							Six Months Ended June 30,

		2003		2002		Change²			2003		2002		Change²

Production
	Oil (MMBbls)		15		11		+34	%		24		23		+4	%
	Gas (Bcf)		216		198		+9	%		397		391		+1	%
	NGLs (MMBbls)		5		5		-2	%		10		10		+4	%
	Oil, Gas and NGLs (MMBoe)¹		56		49		+13	%		100		98		+2	%
Average Prices
	Oil (Per Bbl)	$	25.42	$	22.43		+13	%	$	26.44	$	20.45		+29	%
	Gas (Per Mcf)		4.67		2.84		+64	%		4.74		2.63		+80	%
	NGLs (Per Bbl)		17.88		13.61		+31	%		19.50		12.97		+50	%
	Oil, Gas and NGLs (Per Boe)¹		26.39		17.88		+48	%		27.07		16.59		+63	%
Revenues ($ in millions)
	Oil	$	379	$	248		+52	%	$	635	$	470		+35	%
	Gas		1,007		562		+79	%		1,881		1,028		+83	%
	NGLs		92		72		+28	%		199		127		+57	%

	Combined	$	1,478	$	882		+67	%	$	2,715	$	1,625		+67	%


		Domestic

		Three Months Ended June 30,							Six Months Ended June 30,

		2003		2002		Change²			2003		2002		Change²

Production
	Oil (MMBbls)		8		6		+20	%		13		13		+1	%
	Gas (Bcf)		148		127		+17	%		266		247		+8	%
	NGLs (MMBbls)		4		4		-2	%		8		7		+11	%
	Oil, Gas and NGLs (MMBoe)¹		37		31		+15	%		66		61		+6	%
Average Prices
	Oil (Per Bbl)	$	27.42	$	22.32		+23	%	$	28.46	$	20.81		+37	%
	Gas (Per Mcf)		4.68		2.97		+57	%		4.70		2.75		+71	%
	NGLs (Per Bbl)		16.55		12.91		+28	%		18.12		12.52		+45	%
	Oil, Gas and NGLs (Per Boe)¹		26.70		18.16		+47	%		27.08		17.01		+59	%
Revenues ($ in millions)
	Oil	$	219	$	148		+48	%	$	382	$	278		+38	%
	Gas		692		377		+84	%		1,249		680		+84	%
	NGLs		64		51		+26	%		138		86		+61	%

	Combined	$	975	$	576		+69	%	$	1,769	$	1,044		+69	%


		Canada

		Three Months Ended June 30,							Six Months Ended June 30,

		2003		2002		Change²			2003		2002		Change²

Production
	Oil (MMBbls)		3		4		-20	%		7		9		-24	%
	Gas (Bcf)		67		71		-7	%		130		144		-10	%
	NGLs (MMBbls)		1		1		-7	%		2		3		-13	%
	Oil, Gas and NGLs (MMBoe)¹		15		17		-10	%		30		36		-14	%
Average Prices
	Oil (Per Bbl)	$	23.88	$	22.51		+6	%	$	24.39	$	19.77		+23	%
	Gas (Per Mcf)		4.67		2.60		+80	%		4.85		2.41		+101	%
	NGLs (Per Bbl)		21.98		15.72		+40	%		23.67		14.03		+69	%
	Oil, Gas and NGLs (Per Boe)¹		26.68		17.21		+55	%		27.63		15.74		+76	%
Revenues ($ in millions)
	Oil	$	77	$	90		-15	%	$	161	$	172		-7	%
	Gas		311		185		+68	%		628		348		+80	%
	NGLs		27		21		+30	%		60		41		+46	%

	Combined	$	415	$	296		+40	%	$	849	$	561		+51	%


		International

		Three Months Ended June 30,							Six Months Ended June 30,

		2003		2002		Change²			2003		2002		Change²

Production
	Oil (MMBbls)		4		1		+750	%		4		1		+335	%
	Gas (Bcf)		1		—		+100	%		1		—		+100	%
	NGLs (MMBbls)		—		—		—			—		—		—
	Oil, Gas and NGLs (MMBoe)¹		4		1		+810	%		4		1		+363	%
Average Prices
	Oil (Per Bbl)	$	22.45	$	23.40		-4	%	$	23.00	$	21.88		+5	%
	Gas (Per Mcf)		3.45		—		N/M			3.45		—		N/M
	NGLs (Per Bbl)		21.30		—		N/M			21.30		—		N/M
	Oil, Gas and NGLs (Per Boe)¹		23.40		23.40		-4	%		22.87		21.88		+5	%
Revenues ($ in millions)
	Oil	$	83	$	10		+716	%	$	92	$	20		+357	%
	Gas		4		—		N/M			4		—		N/M
	NGLs		1		—		N/M			1		—		N/M

	Combined	$	88	$	10		+768	%	$	97	$	20		+384	%

		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.

		N/M Not meaningful.

The average sales prices per unit of production shown in the preceding tables include the effect of Devon’s hedging activities. Following is a comparison of Devon’s average sales prices with and without the effect of hedges for the three-month and six-month periods ended June 30, 2003 and 2002.


	With Hedges				Without Hedges

	Three Months Ended				Three Months Ended
	June 30,				June 30,

	2003		2002		2003		2002

Oil (per Bbl)	$	25.42	$	22.43	$	26.35	$	22.95
Gas (per Mcf)	$	4.67	$	2.84	$	5.01	$	2.88
NGLs (per Bbl)	$	17.88	$	13.61	$	17.88	$	13.61
Oil, Gas and NGLs (per Boe)	$	26.39	$	17.88	$	27.95	$	18.11


	With Hedges				Without Hedges

	Six Months Ended June 30,				Six Months Ended June 30,

	2003		2002		2003		2002

Oil (per Bbl)	$	26.44	$	20.45	$	28.06	$	20.77
Gas (per Mcf)	$	4.74	$	2.63	$	5.24	$	2.64
NGLs (per Bbl)	$	19.50	$	12.97	$	19.50	$	12.97
Oil, Gas and NGLs (per Boe)	$	27.07	$	16.59	$	29.40	$	16.64

Oil Revenues. Oil revenues increased $131 million, or 52%, in the second quarter of 2003. An increase in 2003’s production of 4 million barrels, or 34%, caused oil revenues to

increase by $85 million. The April 2003 Ocean merger accounted for 6 million barrels of increased production, partially offset by production lost from the 2002 property divestitures of 2 million barrels. Oil revenues increased $46 million due to a $2.99 increase in the average price of oil.

Oil revenues increased $165 million, or 35%, in the first half of 2003. An increase in production of 1 million barrels, or 4%, caused oil revenues to increase by $21 million. The April 2003 Ocean merger accounted for 6 million barrels of increased production, partially offset by production lost from the 2002 property divestitures of 5 million barrels. Oil revenues increased $144 million due to a $5.99 increase in the average price of oil.

Gas Revenues. Gas revenues increased $445 million, or 79%, in the second quarter of 2003. An increase in production of 18 Bcf, or 9%, caused gas revenues to increase by $50 million. The April 2003 Ocean merger accounted for 30 Bcf of increased production, partially offset by production lost from the 2002 property divestitures of 15 Bcf. The remaining production increase was primarily related to new drilling and development in the Barnett Shale properties acquired in the January 2002 Mitchell merger. Gas revenues increased $395 million due to a $1.83 increase in the average price of gas.

Gas revenues increased $853 million, or 83%, in the first half of 2003. A $2.11 per Mcf increase in the average gas price in the first half of 2003 caused revenues to increase $839 million. An increase in production of 6 Bcf, or 1%, caused gas revenues to increase by $14 million. The April 2003 Ocean merger and January 2002 Mitchell acquisition accounted for 30 Bcf and 11 Bcf of increased production, respectively, partially offset by production lost from the 2002 property divestitures of 32 Bcf, as well as declines of 6 Bcf resulting from increased Canadian royalty rates which are paid in-kind and increase as gas prices increase.

NGL Revenues. NGL revenues increased $20 million in the second quarter of 2003. A $4.27 per barrel increase in the average NGL price in the second quarter of 2003 increased NGL revenues by $21 million. The effect of the price increase was partially offset by a 121,000 barrel decrease in 2003 production. The production decrease was primarily related to 2002 property divestitures partially offset by production from the April 2003 Ocean merger.

NGL revenues increased $72 million in the first half of 2003. Production from the first half of 2003 was consistent with the first half of 2002. NGL revenues increased $72 million due to a $6.53 increase in the average NGL price.

Marketing and Midstream Revenues. Marketing and midstream revenues increased $68 million, or 26%, in the second quarter of 2003, which was primarily the result of an increase in gas and NGL prices. Third-party processed NGL volumes remained relatively steady, as the net effect of a decline in volumes due to the disposition of certain processing plants was offset by an increase in volumes from new drilling and development in the Barnett Shale.

Marketing and midstream revenues increased $342 million, or 80%, in the first half of 2003. Of this total increase, $178 million was the result of an increase in gas and NGL prices. An increase in third-party processed NGL volumes caused the remaining increase in first half 2003 revenues. The increase in volumes was primarily related to new drilling and development in the Barnett Shale and an additional 24 days of production in 2003 due to the timing of the

January 2002 Mitchell merger, partially offset by volumes lost as a result of processing plant dispositions.

Production and Operating Expenses. The components of production and operating expenses are set forth in the following tables.


		Total

		Three Months Ended June 30,							Six Months Ended June 30,

		2003		2002		Change¹			2003		2002		Change¹

Expenses ($ in Millions)
	Lease operating expenses	$	223	$	162		+37	%	$	388	$	316		+23	%
	Transportation costs		51		38		+36	%		92		76		+22	%
	Production taxes		51		33		+53	%		98		55		+77	%

	Total production and operating expenses	$	325	$	233		+39	%	$	578	$	447		+29	%

Expenses Per Boe
	Lease operating expenses	$	3.98	$	3.29		+21	%	$	3.87	$	3.23		+20	%
	Transportation costs		0.91		0.76		+20	%		0.91		0.77		+18	%
	Production taxes		0.90		0.67		+34	%		0.97		0.56		+73	%

	Total production and operating expenses	$	5.79	$	4.72		+23	%	$	5.75	$	4.56		+26	%

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 $61 million in the second quarter of 2003. The April 2003 Ocean merger accounted for $50 million of the increase. The historical Devon lease operating expenses increased $25 million, due to an increase in well workover expenses and increased power, fuel, casualty insurance and repairs and maintenance costs. Additionally, changes in the Canadian-to-U.S. dollar exchange rate resulted in an $8 million increase in costs. These increases were partially offset by a decrease of $22 million due to the 2002 property divestitures.

Lease operating expenses increased $72 million in the first half of 2003. The April 2003 Ocean merger accounted for $50 million of the increase. The historical Devon lease operating expenses increased $63 million, due to an increase in well workover expenses and increased power, fuel, casualty insurance and repairs and maintenance costs. Additionally, changes in the Canadian-to-U.S. dollar exchange rate resulted in a $12 million increase in costs. These increases were partially offset by a decrease of $53 million due to the 2002 property divestitures.

Transportation costs increased $13 million in the second quarter of 2003 and $16 million in the first half of 2003. The April 2003 Ocean merger accounted for $9 million of the increase in both periods, while the remainder of the increases was due primarily to an increase in gas production in higher cost areas.

Production taxes increased $18 million in second quarter of 2003 and $43 million in the first half of 2003. The majority of Devon’s production taxes are assessed on its onshore domestic properties. In the U.S., most of the production taxes are based on a fixed percentage of

revenues. Therefore, the 69% increases in both second quarter and first half 2003 domestic oil, gas and NGL revenues were the primary causes of the production tax increases.

Marketing and Midstream Operating Costs and Expenses. Marketing and midstream operating costs and expenses, which increased $55 million, or 25%, in the second quarter of 2003, was primarily the result of an increase in prices paid for gas and NGLs. Third-party processed NGL volumes remained relatively steady, as the net effect of a decline in volumes from the disposition of certain processing plants was offset by an increase in volumes from new drilling and development in the Barnett Shale.

Marketing and midstream operating costs and expenses increased $286 million, or 82%, in the first half of 2003. Of this total increase, $136 million was the result of an increase in prices paid for gas and NGLs. An increase in third-party processed NGL volumes caused the remaining increase in first half 2003 revenues. The increase in volumes was primarily related to new drilling and development in the Barnett Shale and an additional 24 days of production in 2003 due to the timing of the January 2002 Mitchell acquisition. These increases were partially offset by volumes lost as a result of processing plant dispositions.

Depreciation, Depletion and Amortization Expenses (“DD&A”). Oil and gas property related DD&A increased $99 million, or 34%, from $296 million in the second quarter of 2002 to $395 million in the second quarter of 2003. Oil and gas property related DD&A expense increased $40 million due to the 13% increase in combined oil, gas and NGLs production in 2003. Additionally, an increase in the combined U.S., Canadian and international DD&A rate from $5.99 per Boe in 2002 to $7.06 per Boe in 2003 caused oil and gas property related DD&A to increase by $59 million. The increase in the DD&A rate is primarily related to the April 2003 Ocean merger.

Oil and gas property related DD&A increased $77 million, or 13%, from $586 million in the first half of 2002 to $663 million in the first half of 2003. Oil and gas property related DD&A expense increased $14 million due to the 2% increase in combined oil, gas and NGLs production in 2003. Additionally, an increase in the combined U.S., Canadian and international DD&A rate from $5.98 per Boe in 2002 to $6.62 per Boe in 2003 caused oil and gas property related DD&A to increase by $63 million. The increase in the DD&A rate is primarily related to the April 2003 Ocean merger.

Non-oil and gas property DD&A expense increased $5 million from $27 million in the second quarter of 2002 compared to $32 million the second quarter of 2003. Depreciation of equipment acquired in the April 2003 Ocean merger accounted for the increase. Non-oil and gas property DD&A expense increased $12 million from $48 million in the first half of 2002 compared to $60 million the first half of 2003. Depreciation of equipment acquired in the April 2003 Ocean merger and marketing and midstream assets acquired in the January 2002 Mitchell merger accounted for the increase.

Accretion of Asset Retirement Liability. Effective January 1, 2003, Devon adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (SFAS No. 143) using a cumulative effect approach to recognize transition amounts for asset retirement obligations, asset retirement costs and accumulated depreciation. SFAS No. 143 requires liability recognition for retirement obligations associated with tangible long-lived assets,

such as producing well sites, offshore production platforms, and natural gas processing plants. The obligations included within the scope of SFAS No. 143 are those for which a company faces a legal obligation for settlement. The initial measurement of the asset retirement obligation is fair value, defined as “the price that an entity would have to pay a willing third party of comparable credit standing to assume the liability in a current transaction other than in a forced or liquidation sale.”

As required by SFAS No. 143, Devon recorded $9 million and $16 million of accretion expense during the second quarter and first half of 2003, respectively.

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 offsetting components. One is the amount of G&A capitalized pursuant to the full-cost method of accounting. 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. The following table is a summary of G&A expenses by component for the second quarter and first half of 2003 and 2002.


		Three Months						Six Months
		Ended June 30,						Ended June 30,

		2003			2002			2003			2002

		(In millions)
Gross G&A		$	151		$	99		$	235		$	190
Capitalized G&A			(38	)		(27	)		(57	)		(49	)
Reimbursed G&A			(20	)		(18	)		(36	)		(37	)

	Net G&A	$	93		$	54		$	142		$	104

Net G&A increased $39 million and $38 million, or 72% and 36%, in the second quarter and first half of 2003 compared to the same periods of 2002, respectively. Gross G&A increased $52 million and $45 million, or 53% and 24%, in the second quarter and first half of 2003 compared to the same periods of 2002, respectively. The increase in gross expenses in both periods of 2003 was primarily related to the increased activities resulting from the April 2003 Ocean merger, which added $37 million in gross costs, and $8 million of costs incurred in the 2003 second quarter related to closing Devon’s office in The Woodlands, Texas. The second quarter 2003 gross costs also included an additional $10 million related to a change in the value of investments in certain compensation plans partially offset by lower professional fees.

The increases in capitalized G&A of $11 million and $8 million in the second quarter and first half of 2003, respectively, primarily related to the April 2003 Ocean merger. Reimbursed G&A increased $2 million and decreased $1 million in the second quarter and first half of 2003, respectively. Changes in the reimbursed amounts were primarily related to the April 2003 Ocean merger, offset by a decline in reimbursements related to the 2002 property divestitures.

Reduction of carrying value of oil and gas properties. Under the full cost method of accounting, the net book value of oil and gas properties less related deferred income taxes (the “costs to be recovered”), may not exceed a calculated “full cost ceiling.” The ceiling limitation is the discounted estimated after-tax future net revenues from oil and gas properties. The ceiling is imposed separately by country. In calculating future net revenues, current prices and costs are generally held constant indefinitely. Therefore, the ceiling limitation is not necessarily indicative of the properties’ fair value. The costs to be recovered are compared to the ceiling on a quarterly basis. If the costs to be recovered exceed the ceiling, the excess is written off as an expense, except as discussed in the following paragraph.

If, subsequent to the end of the quarter but prior to the applicable financial statements being published, prices increase to levels such that the ceiling would exceed the costs to be recovered, a writedown otherwise indicated at the end of the quarter is not required to be recorded. A writedown indicated at the end of a quarter is also not required if the value of additional reserves proved up on properties after the end of the quarter but prior to the publishing of the financial statements would result in the ceiling exceeding the costs to be recovered, as long as the properties were owned at the end of the quarter.

An expense recorded in one period may not be reversed in a subsequent period even though higher oil and gas prices may have increased the ceiling applicable to the subsequent period.

Based on oil and natural gas cash market prices as of June 30, 2002, Devon’s Canadian costs to be recovered exceeded the related ceiling value by $371 million. This after-tax amount resulted in a pre-tax reduction of the carrying value of Devon’s Canadian oil and gas properties of $651 million in the second quarter of 2002. This reduction was the result of a sharp drop in Canadian gas prices during the last half of June 2002. The June 30, 2002 reference prices used in the Canadian ceiling calculation, expressed in Canadian dollars, were a NYMEX price of C$40.79 per barrel of oil and an AECO price of C$2.17 per Mcf. The cash market prices of natural gas increased during the month of July 2002 prior to Devon’s release of its second quarter results, but the increase was not sufficient to offset the entire reduction calculated as of June 30, 2002.

Interest Expense. Interest expense decreased $18 million, or 12%, in the second quarter of 2003. The average debt balance increased from $8.9 billion in second quarter of 2002 to $9.1 billion in the 2003 quarter, causing interest expense to increase $3 million. The average interest rate on outstanding debt remained steady at 6.0% for the 2002 and 2003 quarters. Other items included in interest expense that are not related to the debt balance outstanding were $21 million lower in the second quarter of 2003. Of this decrease, $11 million related to the capitalization of interest and $8 million related to the loss on the early extinguishment of 8.75% senior notes in the 2002 quarter. The increase in interest capitalized was primarily related to additional unproved properties acquired from the April 2003 Ocean merger.

Interest expense decreased $12 million, or 4%, in the first half of 2003. The average debt balance decreased from $8.6 billion in the first half of 2002 to $8.5 billion in the first half of 2003, causing interest expense to decrease $2 million. The average interest rate on outstanding debt increased from 5.9% in the first half of 2002 to 6.1% in the first half of 2003, due to debt

assumed in the April 2003 Ocean merger, causing interest expense to increase $10 million. Other items included in interest expense that are not related to the debt balance outstanding were $20 million lower in the second quarter of 2003. Of this decrease, $11 million related to the capitalization of interest and $8 million related to the loss on the early extinguishment of 8.75% senior notes in 2002.

The following schedule includes the components of interest expense for the second quarter and first half of 2003 and 2002.


		Three Months						Six Months
		Ended June 30,						Ended June 30,

		2003			2002			2003			2002

		(In millions)
Interest based on debt outstanding		$	137		$	134		$	260		$	252
Amortization of discounts/premiums			—			3			3			6
Facility and agency fees			1			—			1			1
Amortization of capitalized loan costs			4			2			7			3
Capitalized interest			(12	)		(1	)		(13	)		(2	)
Loss on early debt retirement			—			8			—			8
Other			—			2			2			4

	Total interest expense	$	130		$	148		$	260		$	272

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 increases in the Canadian-to-U.S. dollar exchange rates from $0.6331 at December 31, 2002 and $0.6806 at March 31, 2003 to $0.7378 at June 30, 2003 resulted in a $28 million gain and $50 million gain in the second quarter and first half of 2003, respectively. The increases in the Canadian-to-U.S. dollar exchange rates from $0.6279 at December 31, 2001 and $0.6275 at March 31, 2002 to $0.6585 at June 30, 2002 resulted in a $17 million gain in both the second quarter and first half of 2002.

Income Taxes. During interim periods, income tax expense is based on the estimated effective income tax rate that is expected for the entire fiscal year. The estimated effective tax rate in the second quarter of 2003 was an expense of 39% compared to a benefit of 52% in the second quarter of 2002. The estimated effective tax rate was an expense of 36% in the first half of 2003 compared to a benefit of 59% in the first half of 2002. Excluding the effect of the 2002 reduction of carrying value of Canadian oil and gas properties, the effective tax rate was 24% and 24% in the second quarter and first half of 2002, respectively.

The 2003 rate was higher than the statutory federal tax rate due to the effect of state and foreign income taxes. The 2002 rate, excluding the Canadian writedown, was lower than the statutory federal tax rate primarily due to the tax benefits of certain foreign deductions.

Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes (“SFAS No. 109”), requires that the tax benefit of available tax carryforwards be recorded as an asset to the extent that management assesses the utilization of such carryforwards to be “more likely than not”. When the future utilization of some portion of the carryforwards is determined not to be “more likely than not”, SFAS No. 109 requires that a valuation allowance be provided to reduce the recorded tax benefits from such assets.

Included as deferred tax assets at June 30, 2003, were the tax effect of approximately $755 million of tax related carryforwards. The carryforwards include U.S. federal net operating loss carryforwards, the majority of which do not begin to expire until 2008, U.S. state net operating loss carryforwards which expire primarily between 2003 and 2014, Canadian carryforwards which expire primarily in 2009, International carryforwards which have no expiration and minimum tax credits which have no expiration. Devon expects the tax benefits from the net operating loss carryforwards to be utilized between 2003 and 2010. Such expectation is based upon current estimates of taxable income during this period, considering limitations on the annual utilization of these benefits as set forth by federal tax regulations. Significant changes in such estimates caused by variables such as future oil and gas prices or capital expenditures could alter the timing of the eventual utilization of such carryforwards. There can be no assurance that Devon will generate any specific level of continuing taxable earnings. However, Devon’s management believes that future taxable income will more likely than not be sufficient to utilize substantially all its tax carryforwards prior to their expirations.

Results of Discontinued Operations. Under the provisions of SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, Devon reclassified its Indonesian, Argentine and Egyptian activities as discontinued operations. The decrease in earnings from discontinued operations before income taxes and the related income taxes from second quarter and first half 2002 to second quarter and first half 2003 was primarily due to the sale of these operations during 2002.

Cumulative Effect of Change in Accounting Principle. At the time of adoption of SFAS No. 143 Devon recorded a cumulative-effect-type adjustment for a charge to net earnings of $16 million net of deferred taxes of $10 million.

Capital Expenditures, Capital Resources and Liquidity

The following discussion of capital expenditures, capital resources and liquidity should be read in conjunction with the consolidated statements of cash flows included in Part 1, Item 1.

Capital Expenditures. Cash payments for capital expenditures were $1.1 billion for the first six months of 2003. This total includes $997 million for the acquisition, drilling or development of oil and gas properties. These amounts compare to cash payments for capital expenditures for the first half of 2002 of $2.6 billion. This total includes $1.7 billion related to the January 2002 Mitchell merger and $840 million for the acquisition, drilling or development of oil and gas properties.

The April 2003 Ocean merger did not affect cash paid for 2003 capital expenditures because the consideration given was Devon common stock. This differs from the January 2002

Mitchell merger, in which the consideration given was both Devon common stock and cash, and therefore, the Mitchell merger did have an impact on capital expenditures paid in cash.

Other Cash Uses. Devon’s common stock dividends were $16 million in each of the first six months of 2003 and 2002. Devon also paid $5 million of preferred stock dividends in each of the first six months of 2003 and 2002.

Capital Resources and Liquidity. Devon’s primary source of liquidity has historically been net cash provided by operating activities (“operating cash flow”). This source has been supplemented as needed by accessing credit lines and commercial paper markets and issuing equity securities and long-term debt securities.

Operating Cash Flow

Net cash provided by operating activities (“operating cash flow”) continued to be a primary source of capital and liquidity in the first half of 2003. Operating cash flow in the first half of 2003 was $1.8 billion, compared to $888 million in the first half of 2002. The increase in operating cash flow in the first half of 2003 was primarily caused by the increase in revenues, partially offset by increased expenses, as discussed earlier in this section.

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 conditions, weather and other substantially variable factors influence market conditions for these products. These factors are beyond Devon’s control and are difficult to predict.

To mitigate some of the risk inherent in oil and natural gas prices, Devon has entered into various financial price swaps and collars and fixed-price physical delivery contracts . Additionally, Devon has utilized price collars to set minimum and maximum prices on a portion of its production. The table below provides the future volumes associated with these various arrangements as of July 31, 2003.


						Fixed-Price
						Physical
		Price		Price Swap		Delivery
		Collars		Contracts		Contracts		Total

Oil production (MMBbls)
	2003		20		6		—		26
	2004		23		—		—		23
Natural gas production (Bcf)
	2003		164		51		8		223
	2004		194		3		16		213
	2005		—		3		14		17

In addition to the above quantities, Devon also has fixed-price physical delivery contracts for the years 2006 through 2011, covering Canadian natural gas production ranging from 8 Bcf to 14 Bcf per year. Thereafter, Devon also has Canadian gas volumes subject to fixed-price contracts in the years from 2012 through 2016, but the yearly volumes are less than 1 Bcf.

By removing the price volatility from the above volumes of oil and natural gas production, Devon has mitigated, but not eliminated, the potential negative effect on operating cash flow of declining prices in exchange for limiting the potential benefit from any future oil and gas price increases.

It is Devon’s 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.

In December 2002, Devon announced that its capital expenditure budget for the year 2003 was approximately $1.8 billion. This includes capital for all areas, including exploration and development, marketing and midstream operations, capitalized G&A expense and other areas. As a result of the April 25, 2003 Ocean merger, Devon’s expected capital expenditures will be approximately $2.4 billion in 2003. This capital budget represents the largest planned use of available operating cash flow. To a certain degree, the ultimate timing of these capital expenditures is within Devon’s control. Therefore, if oil and natural gas prices decline to levels below its acceptable levels, Devon could choose to defer a portion of these planned 2003 capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity. Based upon current oil and gas price expectations for 2003, Devon anticipates that its operating cash flow will exceed its planned capital expenditures and other cash requirements for the year. Devon currently intends to accumulate any excess cash to fund current and future years’ debt maturities. Additional alternatives could be considered based upon the actual amount, if any, of such excess cash.

Credit Lines

Other sources of liquidity are Devon’s revolving lines of credit (the “Credit Facilities”). The Credit Facilities include a U.S. facility of $725 million (the “U.S. Facility”) and a Canadian facility of $275 million (the “Canadian Facility”).

The $725 million U.S. Facility consists of a Tranche A facility of $200 million and a Tranche B facility of $525 million. The Tranche A facility matures on October 15, 2004. Devon may borrow funds under the Tranche B facility until June 2, 2004 (the “Tranche B Revolving Period”). Devon may request that the Tranche B Revolving Period be extended an additional 364 days by notifying the agent bank of such request between 30 and 60 days prior to the end of the Tranche B Revolving Period. On June 2, 2004, at the end of the Tranche B Revolving Period, Devon may convert the then outstanding balance under the Tranche B facility to a one-year term loan by paying the Agent a fee of 25 basis points. The applicable borrowing rate would be at LIBOR plus 112.5 basis points. On June 30, 2003, there were no borrowings outstanding under the $725 million U.S. Facility. The available capacity under the U.S. Facility as of July 31, 2003, net of outstanding letters of credit, was $591 million.

Devon also has access to short-term credit under its commercial paper program. Total borrowings under the U.S. Facility and the commercial paper program may not exceed $725 million. Commercial paper debt generally has a maturity of between seven to 90 days, although it can have a maturity of up to 365 days. Devon had no commercial paper debt outstanding at June 30, 2003.

As of June 30, 2003, Devon had $1.1 billion outstanding under its $3 billion senior unsecured term loan credit facility. This credit facility, which was entered into in October 2001, has a term of five years. Subsequent to repayments of amounts outstanding using the proceeds of the debt securities issued on August 4, 2003, this credit facility’s remaining balance of $635 million is due October 15, 2006. This credit facility includes various rate options which can be elected by Devon, including a rate based on LIBOR plus a margin. As of July 31, 2003, the average interest rate on this facility was 2.11%.

In conjunction with the notes offering, Devon also entered into a $500 million interest rate swap. The swap will effectively convert Devon’s interest rate on the $500 million of newly issued debt from the fixed rate of 2.75% to a floating rate of LIBOR less 26.8 basis points. The use of the new debt’s proceeds to repay amounts outstanding under the term loan credit facility, combined with the interest rate swap, has reduced the effective interest rate on approximately $500 million of floating rate debt by approximately 115 basis points including the effects of issuance costs.

Devon’s $1 billion revolving credit facilities and its $3 billion senior unsecured term loan credit facility each contain 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 agreements contain definitions of total funded debt and total capitalization that include adjustments to the respective amounts reported in Devon’s consolidated financial statements. Per the agreements, 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 June 30, 2003, Devon’s ratio of total funded debt to total capitalization, as defined in its credit agreements, was 44.4%.

A summary of Devon’s contractual obligations as of June 30, 2003, is provided in the following table.


		Payments Due By Year

												After
		2003		2004		2005		2006		2007		2007		Total

		(In millions)
Long-term debt		$	230		337		472		1,261		400		6,314		9,014
Operating leases			24		54		47		42		36		350		553
Drilling obligations			76		34		37		1		—		—		148
Firm transportation agreements			53		88		55		47		39		205		487
Other			5		7		7		7		5		25		56

	Total	$	388		520		618		1,358		480		6,894		10,258

Firm transportation agreements represent “ship or pay” arrangements whereby Devon has committed to ship certain volumes of gas for a fixed transportation fee. Devon has entered into these agreements to ensure that Devon can get its gas production to market. Devon expects to have sufficient volumes to ship to satisfy the firm transportation agreements, so that Devon will be receiving equivalent value for the firm transportation payments that it will make.

The above table does not include $163 million of letters of credit that have been issued by commercial banks on Devon’s behalf which, if funded, would become borrowings under Devon’s revolving credit facility. Most of these letters of credit have been granted by Devon’s financial institutions to support Devon’s International and Canadian drilling commitments. The $9.0 billion of long-term debt shown in the table excludes $58 million of premiums and a $2 million fair value adjustment, both of which are included in the June 30, 2003, book balance of the debt.

Impact of Recently Issued Accounting Standards Not Yet Adopted

In January 2003, the Financial Accounting Standards Board (FASB) issued Interpretation No. 46, Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin No. 51, (“Interpretation No. 46”). Interpretation No. 46 requires a company to consolidate a variable interest entity if the company has a variable interest (or combination of variable interests) that will absorb a majority of the entity’s expected losses if they occur, receive a majority of the entity’s expected residual returns if they occur, or both. A direct or indirect ability to make decisions that significantly affect the results of the activities of a variable interest entity is a strong indication that a company has one or both of the characteristics that would require consolidation of the variable interest

entity. Interpretation No. 46 also requires additional disclosures regarding variable interest entities. The new interpretation is effective immediately for variable interest entities created after January 31, 2003, and is effective in the first interim or annual period beginning after June 15, 2003, for variable interest entities in which a company holds a variable interest that it acquired before February 1, 2003. Devon owns no interests in variable interest entities; therefore Interpretation No. 46 will not affect Devon’s consolidated financial statements.

During April 2003, the FASB issued Statement No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities, (“SFAS No. 149”). SFAS No. 149 amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS No. 133. SFAS No. 149 is generally effective for contracts entered into or modified after June 30, 2003, and for hedging relationships designated after June 30, 2003. The guidance should be applied prospectively. Devon will follow the guidance of SFAS No. 149 and expects that it will have no impact on its financial statements.

On May 15, 2003, the FASB issued Statement No. 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity, (“SFAS No. 150”). SFAS No. 150 requires issuers to classify as liabilities (or assets in some circumstance) three classes of freestanding financial instruments that embody obligations for the issuer. Generally, SFAS No. 150 is effective for financial instruments entered into or modified after May 31, 2003 and is otherwise effective at the beginning of the first interim period beginning after June 15, 2003. Devon currently has no financial instruments within the scope of SFAS No. 150.

Change to Critical Accounting Policy

In May 2003, the SEC issued Staff Accounting Bulletin No. 103, Update of Codification of Staff Accounting Bulletins, (“SAB No. 103”) to comprehensively update the existing codification of all staff accounting bulletins. In SAB No. 103, the SEC provided new guidance regarding the calculation of the “ceiling” or limitation on the amount of properties that can be capitalized on the balance sheet under the full cost method of accounting for oil and gas properties. The ceiling calculation dictates that prices and costs in effect as of the last day of the period are generally held constant indefinitely. In SAB No. 103, the SEC expressed its view that the use of end-of-period prices, as adjusted for cash flow hedges, represents the best measure of estimated future cash flows used in calculating the ceiling limitation. Therefore, consistent with the guidance in SAB No. 103, Devon now adjusts the end-of-period price by the effect of cash flow hedges.

SEC Staff View—Intangible Assets

Devon understands that over the past several months, certain oil and gas registrants (other than Devon) have received comment letters from the SEC staff questioning the accounting and presentation of oil and gas related assets, specifically the presentation of drilling and producing rights. Although Devon has been informed that the SEC staff agrees that current accounting principles for oil and gas producers are unaffected by FASB Statement No. 141, Business Combinations, and FASB Statement No. 142, Goodwill and Other Intangible Assets

(Statement No. 142) with respect to measurement issues, Devon understands that the SEC staff has expressed a view that oil and gas producers should present oil and gas intangible assets separately pursuant to the guidance in Statement No. 142 with the attendant disclosures. Current practice for Devon and the industry generally is to present all oil and gas related assets in property and equipment on the balance sheet as prescribed by pre-existing guidance for accounting for oil and gas producing activities.

Devon further understands the SEC has requested the FASB’s Emerging Issues Task Force (EITF) to reconcile this perceived conflict within the related FASB statements. If the SEC staff’s view prevails after any additional consideration by the EITF, Devon would be required to reclassify significant amounts from property and equipment to separate intangible asset classifications on the consolidated balance sheet and to provide disclosures regarding the intangible assets. Devon’s equity, operations and cash flows would not be affected.

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 2002 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. The following information updates Devon’s commodity price risk and foreign currency risk exposure as of July 31, 2003 and interest rate risk exposure as of August 5, 2003 for changes from that disclosed in the 2002 Form 10-K and the May 8, 2003 Current Report on Form 8-K.

Commodity Price Risk

Devon’s major market risk exposure is in the pricing applicable to its oil, gas and NGLs production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to its 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 Devon will receive a fixed price for its 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 does not hold or issue derivative instruments for speculative trading purposes.

Devon’s total hedged positions on future production as of July 31, 2003 are set forth in the following tables.

Price Swaps

Through various price swaps, Devon has fixed the price it will receive on a portion of its oil and natural gas production in 2003 through 2005. The following tables include information on this fixed-price production by area. Where necessary, the prices related to these swaps have been adjusted for certain transportation costs that are netted against the price recorded by Devon, and the price has also been adjusted for the Btu content of the gas production that has been hedged.

Oil Production

2003

Months of

Area

Bbls/Day

Price/Bbl

Production

International

35,000

25.82

Jul - Dec

Gas Production

2003

Months of

Area

Mcf/Day

Price/Mcf

Production

United States

97,389

3.21

Jul - Dec

United States

178,770

4.47

Jul - Dec

2004

Months of

Area

Mcf/Day

Price/Mcf

Production

United States

8,435

3.55

Jan - Dec

2005

Months of

Area

Mcf/Day

Price/Mcf

Production

United States

7,343

3.40

Jan - Dec

Costless Price Collars

Devon has also entered into costless price collars that set a floor and ceiling price for a portion of its 2003 and 2004 oil production that otherwise is 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. Any such settlements will either increase or decrease Devon’s oil revenues for the period. Because Devon’s oil volumes are often sold at prices that differ from the NYMEX or Brent price due to differing quality (i.e., sweet crude versus 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.

Devon has also entered into costless price collars that set a floor and ceiling price for a portion of its 2003 and 2004 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, Devon’s costless collars as of July 31, 2003 have been aggregated in the following table 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 tables have been adjusted to a NYMEX-based price, using Devon’s estimates of future differentials between NYMEX and the Brent price upon which the collars are based.

The natural gas prices shown in the following tables have been adjusted to a NYMEX-based price, using Devon’s 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 domestic collars are based on various regional first-of-the-month price indices as published monthly by Inside FERC. The floor and ceiling prices related to the Canadian collars are based on the AECO index as published by the Canadian Gas Price Reporter.

Oil Production


	2003

			Weighted Average

			Floor		Ceiling
			Price Per		Price Per		Months of
Area (Range of Floor Prices/Ceiling Prices)	Bbls/Day		Bbl		Bbl		Production

United States ($22.00 - $22.75/$27.05 - $28.10)		12,000	$	22.25	$	27.60	Jul - Dec
United States ($20.00 - $23.50/$28.25 - $30.00)		14,000	$	22.13	$	28.86	Jul - Dec
United States ($23.50 - $23.50/$28.25 - $30.75)		6,000	$	23.50	$	29.31	Jul - Dec
Canada ($21.00 - $22.00/$26.60 - $27.50)		10,000	$	21.80	$	27.11	Jul - Dec
Canada ($20.00 - $22.75/$27.75 - $28.15)		7,000	$	21.57	$	27.87	Jul - Dec
Canada ($22.75 - $23.50/$28.35 - $29.25)		6,000	$	23.21	$	28.73	Jul - Dec
Canada ($23.50 - $23.50/$28.80 - $29.75)		3,000	$	23.50	$	29.18	Jul - Dec


	2004

			Weighted Average

			Floor		Ceiling
			Price		Price Per		Months of
Area (Range of Floor Prices/Ceiling Prices)	Bbls/Day		Per Bbl		Bbl		Production

United States ($20.00 - $21.50/$26.50 - $28.00)		5,000	$	20.80	$	27.57	Jan - Dec
United States ($20.00 - $22.00/$28.35 - $29.75)		10,000	$	21.55	$	29.25	Jan - Dec
United States ($22.00 - $22.00/$30.00 - $30.75)		6,000	$	22.00	$	30.42	Jan - Dec
Canada ($20.00 - $21.50/$26.50 - $27.70)		3,000	$	20.50	$	27.07	Jan - Dec
Canada ($20.00 - $22.00/$28.00 - $29.20)		5,000	$	21.10	$	28.69	Jan - Dec
Canada ($22.00 - $22.00/$29.80 - $30.75)		4,000	$	22.00	$	30.30	Jan - Dec
International ($22.25 - $22.25/$30.05 - $30.70)		12,000	$	22.25	$	30.45	Jan - Dec
International ($22.25 - $22.25/$30.75 - $31.45)		15,000	$	22.25	$	31.02	Jan - Dec
International ($22.25 - $22.25/$31.50 - $31.50)		4,000	$	22.25	$	31.50	Jan - Dec

Gas Production


	2003

			Weighted Average

			Floor		Ceiling
			Price Per		Price Per		Months of
Area (Range of Floor Prices/Ceiling Prices)	MMBtu/Day		MMBtu		MMBtu		Production

United States ($3.00 - $3.28/$4.02 - $4.26)		130,000	$	3.12	$	4.11	Jul - Dec
United States ($3.29 - $3.52/$4.25 - $4.56)		110,000	$	3.40	$	4.41	Jul - Dec
United States ($3.25 - $3.28/$4.65 - $4.93)		70,000	$	3.27	$	4.80	Jul - Dec
United States ($3.75 - $3.75/$5.23 - $5.23)		20,000	$	3.75	$	5.23	Sept - Oct
United States ($3.75 - $3.75/$5.15 - $5.33)		50,000	$	3.75	$	5.26	Jul - Dec
United States ($3.28 - $3.28/$5.53 - $5.93)		55,000	$	3.28	$	5.74	Jul - Dec
United States ($3.50 - $4.20/$5.15 - $7.65)		75,000	$	3.87	$	6.26	Jul - Sept
United States ($3.28 - $3.28/$6.23 - $6.53)		40,000	$	3.28	$	6.38	Jul - Dec
Canada ($3.55 - $4.00/$4.37 - $5.54)		90,000	$	3.62	$	4.50	Jul - Dec
Canada ($4.01 - $4.02/$5.97 - $6.76)		40,000	$	4.02	$	6.35	Jul - Dec
Canada ($3.84 - $4.04/$6.91 - $7.51)		50,000	$	3.91	$	7.19	Jul - Dec
Canada ($3.73 - $4.04/$7.62 - $8.08)		50,000	$	3.94	$	7.80	Jul - Dec
Canada ($4.13 - $4.16/$8.20 - $10.25)		60,000	$	4.15	$	8.87	Jul - Oct


	2004

			Weighted Average

			Floor		Ceiling
			Price Per		Price Per		Months of
Area (Range of Floor Prices/Ceiling Prices)	MMBtu/Day		MMBtu		MMBtu		Production

United States ($3.28 - $3.50/$5.00 - $5.81)		50,000	$	3.37	$	5.62	Jan - Dec
United States ($3.25 - $4.25/$5.95 - $7.20)		120,000	$	3.80	$	6.58	Jan - Dec
United States ($3.28 - $4.00/$7.40 - $7.75)		75,000	$	3.63	$	7.55	Jan - Dec
United States ($3.50 - $4.03/$7.90 - $8.80)		70,000	$	3.83	$	8.25	Jan - Dec
Canada ($3.66 - $3.75/$5.77 - $6.15)		30,000	$	3.72	$	5.94	Jan - Dec
Canada ($3.62 - $3.72/$6.40 - $6.80)		30,000	$	3.66	$	6.62	Jan - Dec
Canada ($3.54 - $3.68/$7.52 - $7.81)		60,000	$	3.59	$	7.70	Jan - Dec
Canada ($3.53 - $3.78/$8.16 - $8.61)		70,000	$	3.61	$	8.33	Jan - Dec
Canada ($3.53 - $3.61/$8.85 - $9.42)		25,000	$	3.58	$	9.26	Jan - Dec

Three-Way Collars

Devon has also assumed a number of oil and gas three’way collars from Ocean. A three-way collar is a combination of options—a sold put, a purchased put and a sold call. The purchased put establishes a floor price, unless the market price falls below the sold put, at which point the floor price would be NYMEX or Brent plus the difference between the purchased put and the sold put strike prices. The sold call establishes a ceiling price.

The prices related to domestic oil production are based on the NYMEX price, and the 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. Any such settlements will either increase or decrease Devon’s oil revenues for the period. Because Devon’s oil volumes are often sold at prices that differ from the NYMEX or Brent price due to differing quality (i.e., sweet crude versus 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.

The prices related to natural gas production are based on the NYMEX price. If the NYMEX 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. 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 NYMEX price 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, Devon’s three-way collars as of July 31, 2003, have been aggregated in the following tables according to similar sold call prices. The sold call prices shown are weighted averages of the various collars in each aggregated group. The sold put price and the purchased put price are $19.00 per Bbl and $23.00 per Bbl, respectively, for each domestic oil collar. The sold put price and the purchased put price are $21.00 per Bbl and $25.00 per Bbl, respectively, for each international oil collar. The sold put price and the purchased put price are $2.50 per MMBtu and $3.50 per MMBtu, respectively, for each gas collar.

Oil Production


	2003

			Weighted Average

			Sold Put		Purchased		Sold Call
Area (Range of Sold			Price Per		Put Price		Price Per		Months of
Call Prices)	Bbls/Day		Bbl		Per Bbl		Bbl		Production

United States ($27.25 - $29.00)		43,000	$	19.00	$	23.00	$	27.98	Jul - Dec
International ($29.13 - $29.30)		10,000	$	21.00	$	25.00	$	29.22	Jul - Dec

Gas Production

2003

Weighted Average

Sold Put

Purchased

Price

Put Price

Sold Call

Area (Range of Sold Call

MMBtu/

Per

Price Per

Months of

Prices)

Day

MMBtu

Production

United States ($4.51 - $4.52)

50,000

2.50

3.50

4.52

Jul - Dec

United States ($5.18 - $5.53)

70,000

2.50

3.50

5.34

Jul - Dec

Devon uses a sensitivity analysis technique to evaluate the hypothetical effect that changes in the market value of oil and gas may have on the fair value of its commodity hedging instruments. At July 31, 2003, a 10% increase in the underlying commodities’ prices would have reduced the fair value of Devon’s commodity hedging instruments by $101 million.

Interest Rate Risk

At August 5, 2003, Devon had debt outstanding of $8.9 billion. Of this amount, $8.2 billion, or 92%, bears interest at fixed rates averaging 6.6%. The remaining $0.7 billion of debt outstanding bears interest at floating rates which averaged 2.1%.

The terms of Devon’s various floating rate debt facilities (revolving credit facilities and term loan credit facility) allow interest rates to be fixed at Devon’s option for periods of between seven to 180 days. A 10% increase in short-term interest rates on the floating-rate debt outstanding as of July 31, 2003 would equal approximately 21 basis points. Such an increase in interest rates would increase Devon’s 2003 interest expense by approximately $1 million assuming borrowed amounts remain outstanding for the remainder of 2003.

Devon has also entered into a floating-to-fixed interest rate swap and fixed-to-floating interest rate swaps to manage its exposure to interest rate volatility. Under the floating-to-fixed interest rate swap, Devon will record a fixed rate of 6.4% on $89 million of debt in 2003 through 2006 and 6.3% on $28 million of debt in 2007. Assuming index interest rates remain constant, under the fixed-to-floating interest rate swaps, Devon will record a floating rate of 1.8% on $1.1 billion of debt in 2003 through 2004, 1.5% on $1.0 billion of debt in 2005, 1.2% on $0.9 billion of debt in 2006 and 1.5% on $0.4 billion of debt in 2007. The amount of gains or losses realized from such swaps are included as increases or decreases to interest expense.

Devon uses a sensitivity analysis technique to evaluate the hypothetical effect that changes in interest rates may have on the fair value of its interest rate swap instruments. At August 5, 2003, a 10% increase in the underlying interest rates would have decreased the fair value of Devon’s interest rate swaps by $6 million.

The above sensitivity analysis for interest rate risk excludes accounts receivable, accounts payable and accrued liabilities because of the short-term maturity of such instruments.

Foreign Currency Risk

Devon’s Canadian subsidiary has $400 million of 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 between the beginning and end of a reporting period increase or decrease the Canadian dollar equivalent balance of this debt. Such changes in the Canadian dollar equivalent balance of the debt are required to be included in determining net earnings for the period in which the exchange rate changes. Because of the variability of the exchange rate, it is not possible to estimate the effect which will be recorded in 2003. However, based on the June 30, 2003, Canadian-to-U.S. dollar exchange rate of $0.7378, for every $0.01 change in the exchange rate, Devon will record an effect (either income or expense) of approximately $8 million Canadian dollars during the last six months of 2003. The resulting revenue or expense in U.S. dollars will depend on the currency exchange rate in effect throughout the year. The $400 million becomes due in March 2011. Until then, the gains or losses caused by the exchange rate fluctuations have no effect on cash flow.

Devon also has Canadian and U.S. dollar foreign currency exchange rate swaps. A portion of Devon’s Canadian gas sales is based on U.S. dollar prices. Therefore, currency

fluctuations between the Canadian and U.S. dollars impact the amount of Canadian dollars received by Devon’s Canadian subsidiaries for this gas production. These foreign currency exchange rate swaps mitigate the effect of volatility in the Canadian-to-U.S. dollar exchange rate on Canadian gas revenues. Under these swap agreements, for the last half of 2003, Devon will sell $6 million at average Canadian-to-U.S. exchange rates of $0.676, and buy the same amount of dollars at the floating exchange rate. The amount of gains or losses realized from such swaps are included as increases or decreases to realized gas sales. At the June 30, 2003 exchange rate, these swaps would result in an increase to gas sales during the last six months of 2003 of approximately $1 million. A 10% decrease in the Canadian-to-U.S. dollar exchange rate would result in a decrease to gas sales during the last six months of 2003 of approximately $1 million.

Item 4. Controls and Procedures

Disclosure Controls and Procedures

We maintain disclosure controls and procedures designed to ensure that information required to be disclosed in our filings under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Our principal executive and financial officers have evaluated our disclosure controls and procedures and have determined that such disclosure controls and procedures were effective as of the end of the period covered by this Quarterly Report on Form 10-Q.

Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the period covered by this report that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Part II. Other Information

Item 1. Legal Proceedings

None

Item 2. Changes in Securities

None

Item 3. Defaults Upon Senior Securities

None

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

(a) Devon’s special meeting of stockholders was held in Oklahoma City, Oklahoma at 10:00 a.m. local time, on Friday April 25, 2003.

Devon’s annual meeting of stockholders was held in Oklahoma City, Oklahoma at 10:00 a.m. local time, on Wednesday June 11, 2003.

(b) Proxies for the meetings were solicited pursuant to Regulation 14 under the Securities Exchange Act of 1934, as amended. There was no solicitation in opposition to the nominees for election as directors as listed in the proxy statement for the June 11, 2003 meeting and all nominees were elected.

(c) A total of 126,180,427 shares of Devon’s common stock outstanding and entitled to vote were present at the April 25, 2003 meeting in person or by proxy, representing approximately 81% percent of the total outstanding. The matters voted upon were as follows:

1. Approval of the issuance of Devon Energy Corporation common stock pursuant to the Agreement and Plan of Merger, dated as of February 23, 2003, by and among Devon Energy Corporation, Devon NewCo Corporation and Ocean Energy, Inc., as it may be amended from time to time. The results of the votes taken at such meeting were as follows:


FOR			124,693,419
AGAINST			597,034
ABSTAIN			889,974

2. Adoption of the Devon Energy Corporation 2003 Long-Term Incentive Plan, subject to the consummation of the merger contemplated by the Agreement and Plan

of Merger, dated as of February 23, 2003, by and among Devon Energy Corporation, Devon NewCo Corporation and Ocean Energy, Inc., as it may be amended from time to time. The results of the votes taken at such meeting were as follows:


FOR			92,713,689
AGAINST			32,414,960
ABSTAIN			1,051,778

Out of a total of 229,304,496 shares of Devon’s common stock outstanding and entitled to vote at the June 11, 2003 meeting, 210,134,010 shares were present at the meeting in person or by proxy, representing approximately 92 percent of the total outstanding. The matters voted upon were as follows:

1. Approval of an amendment to the Restated Certificate of Incorporation of Devon Energy Corporation to increase the number of authorized shares of common stock from four hundred million to eight hundred million. The results of the votes taken at such meeting were as follows:


FOR			195,384,831
AGAINST			12,981,761
ABSTAIN			1,767,418

2. The election of four directors to serve on Devon’s board of directors until the 2006 annual meeting of stockholders. The vote tabulation with respect to each nominee was as follows:


			Authority
Nominee	For		Withheld

Robert L. Howard		206,964,530		3,169,480
Michael M. Kanovsky		206,989,495		3,144,515
J. Todd Mitchell		206,990,741		3,143,269
J. Larry Nichols		205,916,715		4,217,295

Item 5. Other Information

None

Item 6. Exhibits and Reports on Form 8-K

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


Exhibit
Number

10.1		First Amendment to Amended and Restated U.S. Credit Agreement dated June 5, 2003 by and among Registrant, Bank of America, N.A., individually and as administrative agent, and the U.S. Lenders party to this Amendment

10.2		First Amendment to Amended and Restated Canadian Credit Agreement dated June 5, 2003 among Northstar Energy Corporation and Devon Canada Corporation, as Canadian Borrowers, Bank of America, N.A. acting through its Canadian Branch, as Administrative Agent, and Certain Financial Institutions, as Lenders

10.3		Amendment No. 1 to the Credit Agreement dated as of May 30, 2003, by and among Devon Energy Corporation, Devon Financing Corporation, U.L.C., UBS AG, Stamford Branch (as Administrative Agent), and the lenders signatory thereto

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 2003

31.2		Certification of William T. Vaughn, 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 2003

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 2003

32.2		Certification of William T. Vaughn, 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 2003

(b) Reports on Form 8-K

A Report on Form 8-K was filed April 2, 2003 to announce a letter agreement amending the Agreement and Plan of Merger for the Ocean Energy, Inc. merger.

A Report on Form 8-K was filed April 14, 2003 to announce the issuance of a supplement to the proxy statement/prospectus dated March 20, 2003.

A Report on Form 8-K was filed April 25, 2003 to announce the completion of the Ocean Energy, Inc. merger and to file the appropriate financial statements and pro forma information required under Item 7 of Form 8-K.

A Report on Form 8-K was filed May 8, 2003 to update Devon’s 2003 forward-looking estimates.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


		DEVON ENERGY CORPORATION

Date: August 13, 2003		/s/ Danny J. Heatly

		Danny J. Heatly Vice President — Accounting

INDEX TO EXHIBITS


Exhibit Number		Description

10.1		First Amendment to Amended and Restated U.S. Credit Agreement dated June 5, 2003 by and among Registrant, Bank of America, N.A., individually and as administrative agent, and the U.S. Lenders party to this Amendment

10.2		First Amendment to Amended and Restated Canadian Credit Agreement dated June 5, 2003 among Northstar Energy Corporation and Devon Canada Corporation, as Canadian Borrowers, Bank of America, N.A. acting through its Canadian Branch, as Administrative Agent, and Certain Financial Institutions, as Lenders

10.3		Amendment No. 1 to the Credit Agreement dated as of May 30, 2003, by and among Devon Energy Corporation, Devon Financing Corporation, U.L.C., UBS AG, Stamford Branch (as Administrative Agent), and the lenders signatory thereto

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 2003

31.2		Certification of William T. Vaughn, 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 2003

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 2003

32.2		Certification of William T. Vaughn, 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 2003


	A Report on Form 8-K was filed April 2, 2003 to announce a letter agreement amending the Agreement and Plan of Merger for the Ocean Energy, Inc. merger.

	A Report on Form 8-K was filed April 14, 2003 to announce the issuance of a supplement to the proxy statement/prospectus dated March 20, 2003.