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DEVON ENERGY REPORTS RECORD 2003 OIL AND GAS PRODUCTION, EARNINGS,
EARNINGS PER SHARE and YEAR-END RESERVES

OKLAHOMA CITY — February 5, 2004 — Devon Energy Corporation (AMEX: DVN, TSX: NSX) today reported that net earnings climbed more than 1,500 percent, making 2003 the most profitable year in the company’s history. Devon reported net earnings of $1.7 billion, or $8.32 per common share ($8.07 per diluted common share) for the year ended December 31, 2003. Devon’s 2002 net earnings were $104 million, or 61 cents per diluted common share. A 21 percent increase in oil and natural gas production and sharply higher oil and gas prices drove the earnings increase.

For the fourth quarter of 2003, the company reported net earnings of $543 million, or $2.32 per common share ($2.25 per diluted common share). These results included $218 million attributable to lower Canadian income tax rates partially offset by a $74 million after-tax reduction in the carrying value of miscellaneous international oil and gas properties. Devon reported net earnings of $84 million, or 52 cents per diluted common share in the fourth quarter of 2002.

The most significant event for the company in 2003 was the merger with Ocean Energy in April. The integration of the two companies was substantially accomplished by year-end. Devon also reported several notable operational accomplishments in 2003:

•

The company drilled 2,116 successful wells in 2003, a 32% increase over 2002.

•

In the Barnett Shale in north Texas, Devon added 350 producing wells and increased its net gas production by over 20 percent to approximately 575 million cubic feet equivalent per day. Horizontal wells, which now account for just 53 of Devon’s more than 1,600 producing wells in the Barnett Shale, will be the focus of future Barnett expansion.

•

In Canada, Devon initiated its 300 million barrel potential Jackfish thermal heavy oil project. Jackfish is designed to produce approximately 35,000 barrels per day of crude oil from the vast Alberta oil sands.

•

In the deepwater Gulf of Mexico, the company drilled two exploratory discoveries at Sturgis and St. Malo. The St. Malo discovery and Devon’s 2002 Cascade discovery are located in the emerging lower Tertiary trend. The lower Tertiary trend may prove to hold significant reserve growth potential for the industry. Devon has a substantial acreage position in the

trend and has identified many additional prospects with characteristics similar to St. Malo and Cascade.

•

Devon initiated production from the Southern Expansion Area of the Zafiro Field in Equatorial Guinea. This increased the company’s net production at Zafiro by about 15,000 barrels to more than 50,000 barrels per day.

•

Offshore China, the Devon-operated Panyu field commenced production into a floating production, storage and offloading vessel. Devon’s share of field production is expected to reach 16,000 barrels per day in 2004. Devon brought Panyu to production in less than two years following the Chinese government’s approval of the project.

•

Devon’s marketing and midstream operations contributed to outstanding results in 2003. Record revenue led to a record operating margin of $286 million. Devon is one of the largest independent midstream operators in the United States.

“We hit our production growth targets and now Devon’s oil and gas property base is delivering record volumes at a time when oil, natural gas and natural gas liquids prices are very healthy,” said J. Larry Nichols, chairman and chief executive officer. “Numerous operating achievements accompanied our stellar financial results. High-impact exploration yielded significant discoveries and our marketing and midstream operations had its best year ever. Record earnings allowed us to fund our entire $2.5 billion drilling and facilities budget while generating more than $1 billion for debt retirement.”

Combined sales of oil, gas and natural gas liquids increased 78 percent in the year ended December 31, 2003, to $5.9 billion. The increase was attributable to rising production and higher product prices.

Devon increased production 21 percent to a record 228 million barrels of oil equivalent (MMBoe) in 2003. The increase reflects Devon’s larger producing base following the April 2003 merger with Ocean Energy and growth from development projects in North America, West Africa and China.

The average price realized by Devon for its 2003 natural gas production increased 61 percent to $4.51 per thousand cubic feet from $2.80 per thousand cubic feet in 2002. Devon’s average realized price for oil increased 18 percent to $25.63 per barrel in 2003 compared with $21.71 per barrel in 2002. The company’s average realized price for natural gas liquids increased 33 percent to $18.65 per barrel in 2003, compared with $14.05 per barrel in 2002.

Higher natural gas and natural gas liquids prices also led to increased marketing and midstream revenue. Marketing and midstream revenue increased to $1.5 billion in 2003, up from $1.0 billion in 2002. Total revenues, including marketing and midstream, climbed 70 percent in 2003, to $7.4 billion.

Devon’s merger with Ocean Energy in April 2003 significantly increased the size and scope of the company’s operations. This is reflected in higher operating costs and expenses.

Lease operating expenses increased 40 percent to $871 million. On a unit of production basis, lease operating expenses increased 16 percent to $3.83 per barrel of oil equivalent (Boe).

Higher lease fuel costs, chemicals costs and the effects of the strengthening Canadian dollar contributed to the increase in unit costs.

Marketing and midstream operating costs for 2003 increased 45 percent to $1.2 billion. The increase in expenses was primarily a result of higher natural gas prices. The increase in costs was more than offset by a related increase in marketing and midstream revenue.

Depreciation, depletion and amortization expense (DD&A) increased 48 percent in 2003, to $1.8 billion. The increase was driven by the increase in oil and gas production and by a higher DD&A rate. Devon’s DD&A rate increased 22 percent in 2003, to $7.87 per Boe. The combined DD&A rate includes depreciation of Devon’s midstream and corporate assets in addition to depletion of its oil and gas properties.

General and administrative expense (G&A) also increased in 2003, by 40 percent to $307 million. G&A expense included $4 million related to personnel severance costs in the fourth quarter and $14 million attributable to office closings in previous quarters. G&A expense also included a $15 million non-cash charge related to changes in the value of obligations in certain compensation plans. This charge is offset by increases in other income and comprehensive earnings.

Income tax expense in 2003 was $514 million, or 23 percent of pre-tax income. Of the total, $321 million was deferred income tax expense, not requiring the current use of cash. Full year and fourth quarter 2003 income tax expense included a $218 million deferred tax benefit attributable to prior years. This is the impact of a reduction in Canadian tax rates on deferred tax liabilities recorded at the beginning of 2003.

Cash flow before balance sheet changes increased 102 percent to a record high $3.9 billion in 2003. Cash on hand climbed to $1.3 billion at year-end. The company expects to utilize the accumulated cash to retire long-term debt of $338 million in 2004 and $920 million in 2005.

The company’s estimated proved oil and gas reserves were 2,089 MMBoe at December 31, 2003. This is a 30 percent increase over year-end 2002 estimated proved reserves of 1,609 MMBoe. Devon acquired 556 MMBoe in 2003, predominately through its merger with Ocean Energy in April. Devon added another 188 MMBoe through successful drilling (discoveries and extensions). Oil and gas produced during 2003 decreased total proved reserves by 228 MMBoe, and revisions to prior estimates reduced the total by another 11 MMBoe. Devon also sold non-core properties in 2003 with associated proved reserves of 25 MMBoe. Natural gas is converted to its oil equivalent on the basis of six thousand cubic feet of gas to one barrel of oil.

Proved reserves at December 31, 2003, are composed of 661 million barrels of crude oil, 7.3 trillion cubic feet of natural gas and 209 million barrels of natural gas liquids. These quantities had a combined estimated pre-tax present value, discounted at 10 percent, of $23 billion. This compares to year-end 2002 estimated pre-tax discounted value of $15 billion.

Proved developed reserves represented 76 percent of total proved reserves at year-end 2003. This compares to 73 percent of total proved reserves at December 31, 2002.

Devon’s reported net earnings include items of income and expense that are excluded by certain securities analysts in their published estimates of the company’s financial results. Such items and their effects upon full year and fourth quarter 2003 reported earnings were as follows:

•

General and administrative expenses attributable to closing Devon’s office in The Woodlands, Texas, decreased full year pre-tax earnings by $11 million ($7 million after tax).

•

Merger costs decreased full year pre-tax earnings by $7 million ($4 million after tax).

•

Reduction in carrying value of miscellaneous international oil and gas properties decreased full year and fourth quarter 2003 pre-tax earnings by $111 million ($74 million after tax).

•

Effects of changes in foreign currency exchange rates increased full year and fourth quarter earnings. The amounts of such full year and fourth quarter earnings increases were $69 million pre-tax ($48 million after tax) and $17 million pre-tax ($12 million after tax), respectively. This is primarily related to U.S. dollar denominated debt in Canada.

•

A change in fair value of financial instruments not associated with hedges increased full year earnings and decreased fourth quarter earnings. For the full year 2003, the increase was $1 million pre-tax ($1 million after tax). In the fourth quarter, the decrease to earnings was $7 million pre-tax ($4 million after tax).

•

A deferred tax benefit attributable to lower Canadian income tax rates increased full year and fourth quarter 2003 net earnings by $218 million.

•

The cumulative effect of adopting SFAS No. 143 on January 1, 2003, increased 2003 net earnings $16 million. SFAS No. 143 concerns costs associated with the retirement of long-lived assets such as well sites, offshore production platforms and natural gas processing plants.

In aggregate, these items increased 2003 net earnings by $199 million, or 95 cents per common share (91 cents per diluted common share). For the fourth quarter of 2003, the applicable items increased net earnings by $152 million, or 65 cents per common share (63 cents per diluted common share).

Devon will discuss its 2003 financial and operating results in a conference call webcast today. The webcast will begin at 10 a.m. Central Time (11 a.m. Eastern Time). The webcast may be accessed from Devon’s internet home page at www.devonenergy.com

This press release includes “forward-looking statements” as defined by the Securities and Exchange Commission. Such statements are those concerning the strategic plans, expectations and objectives for future operations. All statements, other than statements of historical facts, included in this press release that address activities, events or developments that the company expects, believes or anticipates will or may occur in the future are forward-looking statements. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the company. Statements regarding future production are subject to all of the risks and uncertainties normally incident to the exploration for and development and production of oil and gas. These risks include, but are not limited to, inflation or lack of availability of goods and services, environmental risks, drilling risks and regulatory changes. Investors are cautioned that any such statements are not guarantees of future performance and that actual results or developments may differ materially from those projected in the forward-looking statements.

Devon Energy Corporation is an Oklahoma City-based independent energy company engaged in oil and gas exploration, production and property acquisitions. Devon is the largest U.S.-based independent oil and gas producer and is included in the S&P 500 Index. For more information about Devon, please visit our website at www.devonenergy.com.


PRODUCTION DATA (Unaudited)		Year Ended				Quarter Ended
(net of royalties)		December 31,				December 31,

		2003		2002		2003		2002

Total Period Production
Natural Gas (Bcf)
	U.S.		589.3		482.2		160.9		117.1
	Canada		267.4		278.9		67.8		67.9
	International		6.7		—		3.5		—

	Total Natural Gas		863.4		761.1		232.2		185.0

Oil (MMBbls)
	U.S.		31.1		23.8		8.8		5.4
	Canada		13.5		15.8		3.5		3.6
	International		17.3		2.3		7.0		0.8

	Total Oil		61.9		41.9		19.3		9.8

Natural Gas Liquids (MMBbls)
	U.S.		16.7		14.4		4.7		3.8
	Canada		5.0		5.2		1.2		1.1
	International		0.2		—		0.1		—

	Total Natural Gas Liquids		21.9		19.6		6.0		4.9

Oil Equivalent (MMBoe)
	U.S.		146.0		118.5		40.3		28.7
	Canada		63.1		67.5		16.0		16.0
	International		18.6		2.3		7.7		0.8

	Total Oil Equivalent		227.7		188.3		64.0		45.5

Natural Gas Equivalent (Bcfe)
	U.S.		876.0		711.4		241.9		172.3
	Canada		378.6		404.9		96.0		96.1
	International		111.6		13.8		46.1		4.8

	Total Natural Gas Equivalent		1,366.2		1,130.1		384.0		273.2

Average Daily Production
Natural Gas (MMcf)
	U.S.		1,614.4		1,321.0		1,748.4		1,272.4
	Canada		732.7		764.1		737.3		738.2
	International		18.3		—		37.8		—

	Total Natural Gas		2,365.4		2,085.1		2,523.5		2,010.6

Oil (MBbls)
	U.S.		85.3		65.3		95.9		58.5
	Canada		36.9		43.2		37.4		39.2
	International		47.5		6.2		76.5		8.4

	Total Oil		169.7		114.7		209.8		106.1

Natural Gas Liquids (MBbls)
	U.S.		45.8		39.4		50.5		41.3
	Canada		13.6		14.3		13.8		12.2
	International		0.5		—		0.9		—

	Total Natural Gas Liquids		59.9		53.7		65.2		53.5

Oil Equivalent (MBoe)
	U.S.		400.2		324.8		437.8		311.9
	Canada		172.6		184.9		174.1		174.4
	International		51.0		6.2		83.7		8.4

	Total Oil Equivalent		623.8		515.9		695.6		494.7

Natural Gas Equivalent (MMcfe)
	U.S.		2,401.0		1,949.0		2,626.8		1,871.2
	Canada		1,035.7		1,109.3		1,044.5		1,046.6
	International		306.3		37.8		502.2		50.4

	Natural Gas Equivalent		3,743.0		3,096.1		4,173.5		2,968.2


REALIZED PRICE DATA (Unaudited)		Year Ended				Quarter Ended
(average realized prices in $US)		December 31,				December 31,

		2003		2002		2003		2002

Realized Prices
Natural Gas ($/Mcf)
	U.S.	$	4.50	$	2.91	$	4.15	$	3.38
	Canada	$	4.57	$	2.62	$	4.23	$	3.38
	International	$	3.47	$	—	$	3.41	$	—

	Total Natural Gas	$	4.51	$	2.80	$	4.16	$	3.38

Oil ($/Bbl)
	U.S.	$	27.64	$	21.99	$	26.77	$	23.50
	Canada	$	23.54	$	21.00	$	22.51	$	21.05
	International	$	23.64	$	23.70	$	24.14	$	25.92

	Total Oil	$	25.63	$	21.71	$	25.05	$	22.79

Natural Gas Liquids ($/Bbl)
	U.S.	$	17.31	$	13.37	$	17.87	$	15.27
	Canada	$	23.08	$	15.93	$	23.00	$	19.09
	International	$	21.45	$	—	$	21.65	$	—

	Total Natural Gas Liquids	$	18.65	$	14.05	$	19.01	$	16.14

Oil Equivalent ($/Boe)
	U.S.	$	26.02	$	17.87	$	24.50	$	20.20
	Canada	$	26.25	$	16.96	$	24.55	$	20.38
	International	$	23.45	$	23.70	$	23.84	$	25.92

	Total Oil Equivalent	$	25.88	$	17.61	$	24.44	$	20.36

Natural Gas Equivalent ($/Mcfe)
	U.S.	$	4.34	$	2.98	$	4.08	$	3.37
	Canada	$	4.37	$	2.83	$	4.09	$	3.40
	International	$	3.91	$	3.95	$	3.97	$	4.32

	Total Natural Gas Equivalent	$	4.31	$	2.94	$	4.07	$	3.39


PRICE DIFFERENTIALS, EXCLUDING EFFECTS OF HEDGES		Year Ended						Quarter Ended
(floating price differentials from benchmark prices in US$)		December 31,						December 31,

		2003			2002			2003			2002

Price Differentials
Natural Gas ($/Mcf)
	U.S.	$	(0.60	)	$	(0.50	)	$	(0.42	)	$	(0.61	)
	Canada	$	(0.52	)	$	(0.56	)	$	(0.20	)	$	(0.49	)
	International	$	(1.92	)	$	—		$	(1.17	)	$	—

	Total Natural Gas	$	(0.59	)	$	(0.52	)	$	(0.35	)	$	(0.57	)

Oil ($/Bbl)
	U.S.	$	(1.70	)	$	(2.72	)	$	(2.08	)	$	(1.99	)
	Canada	$	(5.46	)	$	(4.66	)	$	(6.48	)	$	(6.47	)
	International	$	(4.90	)	$	(2.39	)	$	(4.01	)	$	(2.26	)

	Total Oil	$	(3.41	)	$	(3.48	)	$	(3.57	)	$	(3.66	)


CONSOLIDATED STATEMENTS OF OPERATIONS		Year Ended						Unaudited Quarter
(US$ in millions, except per share data)		December 31,						Ended December 31,

		2003			2002			2003			2002

Revenues
	Oil sales	$	1,588		$	909		$	484		$	222
	Gas sales		3,897			2,133			966			625
	Natural gas liquids sales		407			275			114			79
	Marketing & midstream revenues		1,460			999			357			307

	Total revenues		7,352			4,316			1,921			1,233

Operating Costs and Expenses
	Lease operating costs		871			621			245			153
	Transportation costs		207			154			58			39
	Production taxes		204			111			52			31
	Marketing & midstream operating costs and expenses		1,174			808			273			249
	Depreciation, depletion and amortization of property & equipment		1,793			1,211			562			295
	Accretion of asset retirement obligation		36			—			10			—
	General & administrative expenses		307			219			86			68
	Expenses related to mergers		7			—			—			—
	Reduction of carrying value of oil & gas properties		111			651			111			—

	Total operating costs and expenses		4,710			3,775			1,397			835

Earnings from operations			2,642			541			524			398

Other Income (Expense)
	Interest expense		(502	)		(533	)		(122	)		(131	)
	Dividends on subsidiary’s preferred stock		(2	)		—			(1	)		—
	Effects of changes in foreign currency exchange rates		69			1			17			1
	Change in fair value of financial instruments		1			28			(7	)		—
	Other income		37			34			8			11
	Impairment of ChevronTexaco common stock		—			(205	)		—			(205	)

	Net other expense		(397	)		(675	)		(105	)		(324	)

Earnings (loss) from continuing operations before income taxes & cumulative effect of change in accounting principle			2,245			(134	)		419			74

Income Tax Expense (Benefit)
	Current		193			23			28			(99	)
	Deferred		321			(216	)		(152	)		78

	Total income tax expense (benefit)		514			(193	)		(124	)		(21	)

Earnings from continuing operations before cumulative effect of change in accounting principle			1,731			59			543			95

Discontinued Operations
	Results of operations		—			23			—			2
	Gain (loss) on sale		—			31			—			(12	)
	Income tax expense		—			9			—			1

	Results of discontinued operations		—			45			—			(11	)

	Earnings before cumulative effect of change in accounting principle		1,731			104			543			84

Cumulative effect of change in accounting principle			16			—			—			—

Net earnings			1,747			104			543			84

Dividends on preferred stock			10			10			3			3

Net earnings applicable to common stockholders		$	1,737		$	94		$	540		$	81

Net earnings per weighted average common share outstanding
	Basic	$	8.32		$	0.61		$	2.32		$	0.52
	Diluted	$	8.07		$	0.61		$	2.25		$	0.52
Basic weighted average shares outstanding			209			155			233			157
Diluted weighted average shares outstanding			217			156			242			163


CONSOLIDATED BALANCE SHEETS
(US$ in millions)		December 31,			December 31,

		2003			2002

Assets
Current assets
	Cash and cash equivalents		1,273			292
	Accounts receivable		946			639
	Inventories		72			26
	Fair value of financial instruments		13			4
	Income taxes receivable		11			56
	Assets of discontinued operations		—			7
	Investments and other current assets		49			40

	Total current assets		2,364			1,064

Property and equipment, at cost			28,546			18,786
	Less accumulated depreciation, depletion and amortization		10,212			7,934

	Net property and equipment		18,334			10,852

Investment in ChevronTexaco Corporation common stock			613			472
Fair value of financial instruments			14			1
Goodwill			5,477			3,555
Other assets			360			281

	Total assets	$	27,162		$	16,225

Liabilities and Stockholders’ Equity
Current liabilities
	Accounts payable		1,174			637
	Income taxes payable		15			9
	Current portion of long-term debt		338			—
	Accrued interest payable		130			119
	Deferred revenue		56			—
	Merger related expenses payable		21			12
	Fair value of financial instruments		153			151
	Current portion of asset retirement obligation		42			—
	Accrued expenses and other current liabilities		142			114

	Total current liabilities		2,071			1,042

Other liabilities			349			323
Asset retirement obligation, long-term			629			—
Debentures exchangeable into shares of ChevronTexaco Corporation common stock			677			662
Other long-term debt			7,903			6,900
Preferred stock of subsidiary			55			—
Fair value of financial instruments			52			18
Deferred income taxes			4,370			2,627

Stockholders’ equity
	Preferred stock		1			1
	Common stock		24			16
	Additional paid-in capital		9,066			5,178
	Retained earnings (accumulated deficit)		1,614			(84	)
	Accumulated other comprehensive income (loss)		569			(267	)
	Other		(32	)		(3	)
	Treasury stock, at cost		(186	)		(188	)

Stockholders’ Equity		$	11,056		$	4,653

Total Liabilities & Stockholders’ Equity		$	27,162		$	16,225

Common Shares Outstanding			236			157


CONSOLIDATED STATEMENTS OF CASH FLOWS
(US$ in millions)		Year Ended December 31,

		2003			2002

Cash Flows From Operating Activities
	Earnings from continuing operations	$	1,731		$	59
	Depreciation, depletion and amortization of property and equipment		1,793			1,211
	Accretion of asset retirement obligation		36			—
	Accretion of discounts on long-term debt, net		19			33
	Effects of changes in foreign currency exchange rates		(69	)		(1	)
	Change in fair value of derivative instruments		(1	)		(28	)
	Reduction of carrying value of oil and gas properties		111			651
	Impairment of ChevronTexaco Corporation common stock		—			205
	Loss (gain) on sale of assets		7			(2	)
	Deferred income tax expense (benefit)		321			(216	)
	Other		(48	)		(9	)
Changes in assets and liabilities, net of acquisitions of businesses
	Accounts receivable		(164	)		(80	)
	Inventories		(8	)		10
	Investments and other current assets		(26	)		12
	Accounts payable		42			(74	)
	Income taxes payable		62			21
	Accrued interest and expenses		39			36
	Deferred revenue		(41	)		(46	)
	Long-term other liabilities		(36	)		(56	)

Net cash provided by continuing operations			3,768			1,726

	Net cash provided by discontinued operations		—			28
Net cash provided by operating activities		$	3,768		$	1,754

Cash Flows From Investing Activities
	Proceeds from sales of property and equipment	$	179		$	1,067
	Capital expenditures		(2,587	)		(3,426	)
	Discontinued operations		—			316
	Other		(24	)		(3	)

Net cash used in investing activities		$	(2,432	)	$	(2,046	)

Cash Flows From Financing Activities
	Proceeds from borrowings of long-term debt, net of issuance costs	$	597		$	6,067
	Principal payments on long-term debt		(1,118	)		(5,657	)
	Issuance of common stock, net of issuance costs		155			32
	Dividends paid on common stock		(39	)		(31	)
	Dividends paid on preferred stock		(10	)		(10	)
	Decrease in long-term liabilities		1			—

Net cash (used in) provided by financing activities		$	(414	)	$	401

Effect of exchange rate changes on cash			59			—

Net increase in cash and cash equivalents			981			109

Cash and cash equivalents at beginning of period			292			183

Cash and cash equivalents at end of period			1,273			292


RESERVE RECONCILIATION
		Total												Domestic

		Oil			Gas			NGLs			Total			Oil			Gas			NGLs			Total
		(MMBbls)			(Bcf)			(MMBbls)			(MMboe)			(MMBbls)			(Bcf)			(MMBbls)			(MMboe)

As of December 31, 2002:
	Proved developed		260			4,618			150			1,180			135			2,802			117			719
	Proved undeveloped		184			1,218			42			429			12			750			29			166

Total proved			444			5,836			192			1,609			147			3,552			146			885

Production			(62	)		(863	)		(22	)		(228	)		(31	)		(589	)		(17	)		(146	)
Discoveries and extensions			29			834			20			188			12			510			14			111
Divestitures			(3	)		(132	)		—			(25	)		(2	)		(120	)		—			(22	)
Acquisitions			262			1,650			19			556			92			1,474			19			357
Revisions			(9	)		(9	)		—			(11	)		(6	)		57			(1	)		2
As of December 31, 2003:
	Proved developed		408			5,980			179			1,584			171			3,935			136			964
	Proved undeveloped		253			1,336			30			505			41			949			25			223

Total proved			661			7,316			209			2,089			212			4,884			161			1,187


		Canada												International

		Oil			Gas			NGLs			Total			Oil			Gas			NGLs		Total
		(MMBbls)			(Bcf)			(MMBbls)			(MMboe)			(MMBbls)			(Bcf)			(MMBbls)		(MMboe)

As of December 31, 2002:
	Proved developed		119			1,816			33			455			6			—			—		6
	Proved undeveloped		30			468			13			121			142			—			—		142

Total proved			149			2,284			46			576			148			—			—		148

Production			(14	)		(267	)		(5	)		(63	)		(17	)		(7	)		—		(19	)
Discoveries and extensions			16			324			6			76			1			—			—		1
Divestitures			(1	)		(12	)		—			(3	)		—			—			—		—
Acquisitions			2			1			—			2			168			175			—		197
Revisions			(4	)		(33	)		1			(9	)		1			(33	)		—		(4	)
As of December 31, 2003:
	Proved developed		123			1,964			43			493			114			81			—		127
	Proved undeveloped		25			333			5			86			187			54			—		196

Total proved			148			2,297			48			579			301			135			—		323


COSTS INCURRED		Total					Domestic

(US$ in millions)		Year Ended December 31,					Year Ended December 31,

		2003			2002		2003			2002

Property Acquisition Costs:
	Total proved	$	4,209		$	1,538	$	2,582		$	1,536

	Unproved:
	Business combinations		1,063			639		551			639
	Other acquisitions		87			64		48			27

	Total unproved	$	1,150		$	703	$	599		$	666

Exploration Costs		$	714		$	383	$	343		$	161

Development Costs		$	1,853		$	1,140	$	1,191		$	808

Finding and Development Costs		$	7,926		$	3,764	$	4,715		$	3,171

	Asset retirement costs — business combinations		134			—		115			—
	Asset retirement costs — drilling		48			—		24			—
	Less: Actual retirement expenditures		(37	)		—		(22	)		—

Costs Incurred		$	8,071		$	3,764	$	4,832		$	3,171


		Canada					International

		Year Ended December 31,					Year Ended December 31,

		2003			2002		2003			2002

Property Acquisition Costs:
	Total proved	$	26		$	2	$	1,601		$	—

	Unproved:
	Business combinations		—			—		512			—
	Other acquisitions		39			28		—			9

	Total unproved	$	39		$	28	$	512		$	9

Exploration Costs		$	214		$	207	$	157		$	15

Development Costs		$	488		$	299	$	174		$	33

Finding and Development Costs		$	767		$	536	$	2,444		$	57

	Asset retirement costs — business combinations		—			—		19			—
	Asset retirement costs — drilling		17			—		7			—
	Less: Actual retirement expenditures		(14	)		—		(1	)		—

Costs Incurred		$	770		$	536	$	2,469		$	57

Pursuant to the full cost method of accounting, Devon capitalizes certain general and administrative expenses which are related to property acquisition, exploration and development activities. Such capitalized expenses, which are included in the costs shown in the preceding tables, were $140 million and $97 million in the years 2003 and 2002, respectively. In addition, Devon capitalizes certain interest expenses which are related to property development activities. Such capitalized expenses, which are also included in the costs shown in the preceding tables, were $50 million and $4 million in the years 2003 and 2002, respectively.


EXPLORATION AND DEVELOPMENT WELLS		Year Ended December 31,

		2003			2002

Exploration Wells Drilled
	U.S		44			39
	Canada		244			233
	International		5			4

	Total		293			276

Exploration Wells Success Rate
	U.S		50	%		54	%
	Canada		86	%		84	%
	International		—	%		—	%

	Total		79	%		79	%

Development Wells Drilled
	U.S		1,281			940
	Canada		606			428
	International		49			41

	Total		1,936			1,409

Development Wells Success Rate
	U.S		98	%		99	%
	Canada		97	%		95	%
	International		98	%		100	%

	Total		97	%		98	%

Total Wells Drilled
	U.S		1,325			979
	Canada		850			661
	International		54			45

	Total		2,229			1,685

Total Wells Success Rate
	U.S		96	%		97	%
	Canada		94	%		91	%
	International		89	%		91	%

	Total		95	%		95	%

The United States Securities and Exchange Commission has recently adopted new disclosure requirements for public companies such as Devon. One provision of these disclosure requirements concerns references to Non-GAAP financial measures. (GAAP refers to accounting principles generally accepted in the United States.) Non-GAAP financial measures may be provided if the company explains the relevance of the information. The company must also reconcile the Non-GAAP financial Measure to related GAAP information. Cash flow before balance sheet changes is a Non-GAAP financial measure provided by Devon in this earnings release. Devon believes cash flow before balance sheet changes is relevant because it is a measure of cash available to fund the company’s capital expenditures and to service its debt and other obligations. Cash flow before balance sheet changes is also important to certain financial analysts who provide estimates of Devon’s quarterly financial results to investors.


		20 North Broadway		Telephone: (405) 235-3611
		Oklahoma City, Oklahoma 73102-8260		Fax: (405) 552-4667


Investor contact:		Zack Hager
		(405) 552-4526

Media contact:		Brian Engel
		(405) 228-7750


BENCHMARK PRICES	Year Ended				Quarter Ended
(US$)	December 31,				December 31,

	2003		2002		2003		2002

Benchmark Prices
Natural Gas ($/Mcf) — Henry Hub	$	5.38	$	3.22	$	4.58	$	3.99
Oil ($/Bbl) — West Texas Intermediate (Cushing)	$	31.08	$	26.10	$	31.22	$	28.21


COMPANY OPERATED RIGS		At December 31,

		2003		2002

Number of Company Operated Rigs Running
	U.S		40		27
	Canada		35		32
	International		4		1

	Total		79		60


RECONCILIATION TO GAAP INFORMATION		Year Ended				Unaudited Quarter Ended
(US$ in millions)		December 31,				December 31,

		2003		2002		2003		2002

Net Cash Provided By Operating Activities		$	3,768	$	1,754	$	988	$	578

	Changes in assets and liabilities, net of effects of acquisitions of businesses		132		177		61		166

Cash flow before balance sheet changes		$	3,900	$	1,931	$	1,049	$	744