UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

DEVON ENERGY CORPORATION

(Exact Name of Registrant as Specified in its Charter)

DELAWARE (State or Other Jurisdiction of Incorporation or Organization)		001-32318 (Commission File Number)		73-1567067 (IRS Employer Identification Number)

20 NORTH BROADWAY, OKLAHOMA CITY, OK (Address of Principal Executive Offices)		73102                            (Zip Code)

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

     Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

 

 

Item 8.01. Other Events

     Devon reported its original 2005 forward-looking estimates in a Current Report on Form 8-K dated February 2, 2005, and also in its 2004 Annual Report on Form 10-K. Devon updated certain of the original 2005 forward-looking estimates in its March 31, 2005 Quarterly Report on Form 10-Q filed on May 5, 2005. Following the end of its second quarter, Devon has again updated certain of these 2005 forward-looking estimates. The updated estimates, along with the estimates that have not changed, are presented in the following pages.

Definitions

     The following discussion includes references to various abbreviations relating to volumetric production terms and other defined terms. These definitions are as follows:

     “AECO” means the price of gas delivered onto the NOVA Gas Transmission Ltd. System.

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

     “Bcf” means billion cubic feet.

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

     “Brent” means pricing point for selling North Sea crude oil.

     “Btu” means British thermal units, a measure of heating value.

     “Inside FERC” refers to the publication Inside F.E.R.C.’s Gas Market Report.

     “LIBOR” means London Interbank Offered Rate.

     “MMBbls” means one million Bbls.

     “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.

Forward-Looking Estimates

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

     Additionally, Devon cautions that its future marketing and midstream revenues and expenses are subject to all of the risks and uncertainties normally incident to the marketing and midstream business. These risks include, but are not limited to, price volatility, environmental risks, regulatory changes, the uncertainty inherent in estimating future processing volumes and pipeline throughput, cost of goods and services and other risks as outlined below.

     Also, the financial results of Devon’s foreign operations are subject to currency exchange rate risks. Additional risks are discussed below in the context of line items most affected by such risks.

     A summary of these forward-looking estimates is included at the end of this document.

     Specific Assumptions and Risks Related to Price and Production Estimates Prices for oil, natural gas and NGLs are determined primarily by prevailing market conditions. Market conditions for these products are influenced by regional and worldwide economic conditions, weather and other local market conditions. These factors are beyond Devon’s control and are difficult to predict. In addition to volatility in general, Devon’s oil, gas and NGL prices may vary considerably due to differences between regional markets, differing quality of oil produced (i.e., sweet crude versus heavy or sour crude), differing Btu contents of gas produced, transportation availability and costs and demand for the various products derived from oil, natural gas and NGLs. Substantially all of Devon’s revenues are attributable to sales, processing and transportation of these three commodities. Consequently, Devon’s financial results and resources are highly influenced by price volatility.

     Estimates for Devon’s future production of oil, natural gas and NGLs are based on the assumption that market demand and prices for oil, gas and NGLs will continue at levels that allow for profitable production of these products. There can be no assurance of such stability. Most of Devon’s Canadian production of oil, natural gas and NGLs is subject to government royalties that fluctuate with prices. Thus, price fluctuations can affect reported production. Also, Devon’s international production of oil, natural gas and NGLs is governed by payout agreements with the governments of the countries in which Devon operates. If the payout under these agreements is attained earlier than projected, Devon’s net production and proved reserves in such areas could be reduced.

     Estimates for Devon’s future processing and transport of oil, natural gas and NGLs are based on the assumption that market demand and prices for oil, gas and NGLs will continue at levels that allow for profitable processing and transport of these products. There can be no assurance of such stability.

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

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

     Though Devon has completed several major property acquisitions and dispositions in recent years, these transactions are opportunity driven. Thus, the following forward-looking data excludes the financial and operating effects of potential property acquisitions or divestitures, except as discussed in “Property Acquisitions and Divestitures,” during the year 2005. The

timing and ultimate results of such acquisition and divestiture activity is difficult to predict, and may vary materially from that discussed in this report.

Geographic Reporting Areas for 2005

     The following estimates of production, average price differentials compared to industry benchmarks and capital expenditures are provided separately for each of the following geographic areas:

	•		the United States Onshore;
	•		the United States Offshore, which encompasses all oil and gas properties in the Gulf of Mexico;
	•		Canada; and
	•		International, which encompasses all oil and gas properties that lie outside of the United States and Canada.

Year 2005 Potential Operating Items

     In September 2004, Devon announced its plans to divest certain non-core oil and gas properties during 2005. During the first six months of 2005, all of such properties were sold with the exception of one minor package of properties.

     The estimates related to oil, gas and NGL production, operating costs and DD&A set forth in the following paragraphs are based on estimates for Devon’s properties other than those that have been sold pursuant to this divestiture program (See “Property Acquisitions and Divestitures”). Therefore, the following estimates exclude the results for the entire year from the properties that have been sold.

     Oil, Gas and NGL Production Set forth in the following paragraphs are individual estimates of Devon’s oil, gas and NGL production for 2005. On a combined basis, Devon estimates its 2005 oil, gas and NGL production will total 220 MMBoe.

     Oil Production Devon expects its oil production in 2005 to total 62 MMBbls. The expected production by area is as follows:

		(MMBbls)
United States Onshore			12
United States Offshore			11
Canada			12
International			27

     Oil Prices — Fixed Through various price swaps, Devon has fixed the price it will receive in 2005 on a portion of its oil production. The following table includes information on this fixed-price production by area. Where necessary, the prices have been adjusted for certain transportation costs that are netted against the prices recorded by Devon.

										Months of
		Bbls/Day				Price/Bbl				Production
United States Offshore			8,000			$	27.14			Jan – Dec
Canada			3,000			$	27.13			Jan – Dec
International			6,000			$	25.88			Jan – Dec

     Oil Prices — Floating Devon’s 2005 average prices for each of its areas are expected to differ from the NYMEX price as set forth in the following table. The NYMEX price is the monthly average of settled prices on each trading day for benchmark West Texas Intermediate crude oil delivered at Cushing, Oklahoma.

		Expected Range of Oil Prices
		as a % of NYMEX Price
United States Onshore		88% to 93%
United States Offshore		88% to 93%
Canada		70% to 76%
International		84% to 90%

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

     The international oil prices shown in the following table have been adjusted to a NYMEX-based price, using Devon’s estimates of 2005 differentials between NYMEX and the Brent price upon which the collars are based.

     To simplify presentation, Devon’s costless collars as of December 31, 2004, 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.

						Weighted Average
						Floor				Ceiling
						Price				Price				Months of
		Bbls/Day				Per Bbl				Per Bbl				Production
United States Offshore			17,000			$	22.00			$	27.62			Jan – Dec
Canada			15,000			$	22.00			$	28.28			Jan – Dec
International			15,000			$	23.23			$	29.34			Jan – Dec

     Gas Production Devon expects its 2005 gas production to total 807 Bcf. The expected production by area is as follows:

		(Bcf)
United States Onshore			455
United States Offshore			92
Canada			250
International			10

     Gas Prices — Fixed Through various price swaps and fixed-price physical delivery contracts, Devon has fixed the price it will receive in 2005 on a portion of its natural gas production. The following table includes information on this fixed-price production by area. Where necessary, the prices have been adjusted for certain transportation costs that are netted against the prices recorded by Devon, and the prices have also been adjusted for the Btu content of the gas hedged.

										Months of
		Mcf/Day				Price/Mcf				Production
United States Onshore			7,343			$	3.40			Jan – Dec
Canada			38,578			$	2.89			Jan – Jun
Canada			38,578			$	2.96			Jul – Dec
International			12,000			$	2.35			Jan – Dec

     Gas Prices — Floating For the natural gas production for which prices have not been fixed, Devon’s 2005 average prices for each of its areas are expected to differ from the NYMEX price as set forth in the following table. The NYMEX price is determined to be the first-of-month South Louisiana Henry Hub price index as published monthly in Inside FERC.

		Expected Range of Gas Prices
		as a % of NYMEX Price
United States Onshore		81% to 90%
United States Offshore		100% to 107%
Canada		86% to 94%
International		70% to 80%

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

     The prices shown in the following table have been adjusted to a NYMEX-based price, using Devon’s estimates of 2005 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.

     To simplify presentation, Devon’s costless collars 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.

						Weighted
						Average
						Floor				Ceiling
						Price				Price
		MMBtu/				per				per				Months of
		Day				MMBtu				MMBtu				Production
United States Onshore			40,000			$	4.28			$	7.23			Jan – Jun
United States Offshore			40,000			$	3.50			$	7.50			Jan – Dec
United States Offshore			70,000			$	4.09			$	7.00			Jan – Jun

     NGL Production Devon expects its 2005 production of NGLs to total 23 MMBbls. The expected production by area is as follows:

		(MMBbls)
United States Onshore			17
United States Offshore			1
Canada			5

     Marketing and Midstream Revenues and Expenses Devon’s marketing and midstream revenues and expenses are derived primarily from its natural gas processing plants and natural gas transport pipelines. These revenues and expenses vary in response to several factors. The factors include, but are not limited to, changes in production from wells connected to the pipelines and related processing plants, changes in the absolute and relative prices of natural gas and NGLs, provisions of the contract agreements and the amount of repair and workover activity required to maintain anticipated processing levels.

     These factors, coupled with uncertainty of future natural gas and NGL prices, increase the uncertainty inherent in estimating future marketing and midstream revenues and expenses. Given these uncertainties, Devon estimates that 2005 marketing and midstream revenues will be between $1.49 billion and $1.61 billion, and marketing and midstream expenses will be between $1.16 billion and $1.26 billion.

     Production and Operating Expenses Devon’s production and operating expenses include lease operating expenses, transportation costs and production taxes. These expenses vary in response to several factors. Among the most significant of these factors are additions to or deletions from Devon’s property base, changes in production tax rates, changes in the general price level of services and materials that are used in the operation of the properties and the amount of repair and workover activity required. Oil, natural gas and NGL prices also have an effect on lease operating expenses and impact the economic feasibility of planned workover projects.

     Given these uncertainties, Devon estimates that 2005 lease operating expenses (including transportation costs) will be between $1.20 billion and $1.27 billion and production taxes will be between 3.25% and 3.75% of consolidated oil, natural gas and NGL revenues, excluding the effect on revenues from hedges, upon which production taxes are not incurred.

     Depreciation, Depletion and Amortization (“DD&A”) The 2005 oil and gas property DD&A rate will depend on various factors. Most notable among such factors are the amount of proved reserves that will be added from drilling or acquisition efforts in 2005 compared to the costs incurred for such efforts, and the revisions to Devon’s year-end 2004 reserve estimates that, based on prior experience, are likely to be made during 2005.

     Given these uncertainties, Devon expects its oil and gas property related DD&A rate will be between $8.60 per Boe and $9.00 per Boe. Based on these DD&A rates and the production estimates set forth earlier, oil and gas property related DD&A expense for 2005 is expected to be between $1.89 billion and $1.97 billion.

     Additionally, Devon expects its depreciation and amortization expense related to non-oil and gas property fixed assets to total between $155 million and $165 million.

     Accretion of Asset Retirement Obligation Devon expects its 2005 accretion of its asset retirement obligation to be between $45 million and $50 million.

     General and Administrative Expenses (“G&A”) Devon’s G&A includes the costs of many different goods and services used in support of its business. These goods and services are subject to general price level increases or decreases. In addition, Devon’s G&A varies with its level of activity and the related staffing needs as well as with the amount of professional services required during any given period. Should Devon’s needs or the prices of the required goods and services differ significantly from current expectations, actual G&A could vary materially from the estimate.

     Given these limitations, consolidated G&A in 2005 is expected to be between $275 million and $295 million.

     Reduction of Carrying Value of Oil and Gas Properties Devon follows the full cost method of accounting for its oil and gas properties. Under the full cost method, Devon’s 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 plus the cost of properties not subject to amortization. The ceiling is imposed separately by country. In calculating future net revenues, current prices and costs used are those as of the end of the appropriate quarterly period. These prices are not changed except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts. Such contracts include derivatives accounted for as cash flow hedges. 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. 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.

     Because the ceiling calculation dictates that prices in effect as of the last day of the applicable quarter are held constant indefinitely, and requires a 10% discount factor, the resulting value is not indicative of the true fair value of the reserves. Oil and natural gas prices have historically been cyclical and, on any particular day at the end of a quarter, can be either substantially higher or lower than Devon’s long-term price forecast that is a barometer for true fair value. Therefore, oil and gas property writedowns that result from applying the full cost ceiling limitation, and that are caused by fluctuations in price as opposed to reductions to the underlying quantities of reserves, should not be viewed as absolute indicators of a reduction of the ultimate value of the related reserves.

     Because of the volatile nature of oil and gas prices, it is not possible to predict whether Devon will incur a full cost writedown in future periods.

     Interest Expense Future interest rates and debt outstanding have a significant effect on Devon’s interest expense. Devon can only marginally influence the prices it will receive in 2005

from sales of oil, natural gas and NGLs and the resulting cash flow. These factors increase the margin of error inherent in estimating future interest expense. Other factors which affect interest expense, such as the amount and timing of capital expenditures, are within Devon’s control.

     The interest expense in 2005 related to Devon’s fixed-rate debt, including net accretion of related discounts, will be approximately $420 million. This fixed-rate debt removes the uncertainty of future interest rates from some, but not all, of Devon’s long-term debt. Devon’s floating rate debt is discussed in the following paragraphs.

     Devon has various debt instruments which have been converted to floating rate debt through the use of interest rate swaps. Devon’s floating rate debt is as follows:

		Notional
Debt Instrument		Amount				Floating Rate
7.625% senior notes due July 2005		$	125			LIBOR plus 237 basis points
10.25% bonds due November 2005		$	235			LIBOR plus 711 basis points
2.75% notes due in 2006		$	500			LIBOR less 26.8 basis points
6.55% senior notes due in 2006		$	163	1		Banker’s Acceptance plus 340 basis points
4.375% senior notes due in 2007		$	400			LIBOR plus 40 basis points
6.75% senior notes due in 2011 2		$	400			LIBOR plus 197 basis points

     Based on future LIBOR rates as of August 2, 2005, interest expense on its floating rate debt, including net amortization of premiums, is expected to total between $85 million and $95 million in 2005.

     Devon’s interest expense totals have historically included payments of facility and agency fees, amortization of debt issuance costs, the effect of interest rate swaps not accounted for as hedges, and other miscellaneous items not related to the debt balances outstanding. Devon expects between $75 million and $85 million of such items to be included in its 2005 interest expense. This estimate includes the $25 million loss and $5 million expense of remaining unamortized debt issuance costs recognized in conjunction with the early redemption of the zero coupon convertible debentures in June 2005. This estimate also includes an estimated early retirement premium of $46 million related to our recent announcement that we are redeeming the $400 million 6.75% senior notes in the third quarter of 2005. Also, Devon expects to capitalize between $65 million and $75 million of interest during 2005.

     Based on the information related to interest expense set forth herein and assuming no material changes in Devon’s levels of indebtedness or prevailing interest rates, other than the planned retirement of debt in 2005, Devon expects its 2005 interest expense will be between $515 million and $525 million.

     Effects of Changes in Foreign Currency Rates Devon’s Canadian subsidiary has $400 million of fixed-rate senior notes which are denominated in U.S. dollars and mature in 2011. As stated above, Devon recently announced its intention to redeem this debt on September 9, 2005. Changes in the exchange rate between the U.S. dollar and the Canadian dollar during 2005 prior to the date the debt is redeemed will 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 difficult to estimate the effect which will be recorded in 2005. However, based on the December 31, 2004, Canadian-to-U.S. dollar exchange rate of $0.8308 and Devon’s forecast of the 2005 rate through the anticipated redemption date of $0.8200, Devon expects to record an expense of approximately $10 million. The actual 2005 effect will depend on the exchange rate as of the actual redemption date.

     Other Revenues Devon’s other revenues in 2005 are expected to be between $190 million and $200 million. Included as part of other revenues is a $150 million gain on the sale of certain assets in the first half of 2005. The range of $190 million to $200 million also includes the $55 million loss from early settlements or hedge ineffectiveness of outstanding commodity price hedges as a result of the property dispositions in the first half of 2005.

     Income Taxes Devon’s financial income tax rate in 2005 will vary materially depending on the actual amount of financial pre-tax earnings. The tax rate for 2005 will be significantly affected by the proportional share of consolidated pre-tax earnings generated by U.S., Canadian and International operations due to the different tax rates of each country. There are certain tax deductions and credits that will have a fixed impact on 2005’s income tax expense regardless of the level of pre-tax earnings that are produced.

     Given the uncertainty of pre-tax earnings, Devon expects that its consolidated financial income tax rate in 2005 will be between 25% and 45%. The current income tax rate is expected to be between 25% and 35%. The deferred income tax rate is expected to be between 0% and 10%. Significant changes in estimated capital expenditures, production levels of oil, gas and NGLs, the prices of such products, marketing and midstream revenues, or any of the various expense items could materially alter the effect of the aforementioned tax deductions and credits on 2005’s financial income tax rates.

     As discussed elsewhere in this document, during the first half of 2005, Devon sold certain of its non-core oil and gas properties for approximately $2.0 billion. Under the provisions of the full cost method of accounting that Devon follows, no financial gain or loss was recognized from these property sales. Rather, the proceeds were credited against the oil and gas property balance. However, for federal and state income tax purposes, gains will be recognized from these sales, and Devon will pay approximately $208 million of related income taxes in 2005. Because no gain from the sales is recognized for financial reporting purposes, the $208 million of current income tax expense will be offset by a like amount of deferred income tax benefit, resulting in no net impact on total income tax expense as reported in Devon’s consolidated statement of operations.

     Excluding the $208 million of current tax expense and deferred tax benefit recognized from the property sales, Devon estimates that its consolidated financial income tax rate in 2005 will be between 25% and 45%. The current income tax rate is expected to be between 20% and 30%. The deferred income tax rate is expected to be between 5% and 15%.

     Property Acquisitions and Divestitures During the first half of 2005, Devon sold certain oil and gas properties (the “Disposition Properties”) which were predominantly properties that were either outside of our core operating areas or otherwise did not fit our current strategic objectives. The Disposition Properties were located in the U.S. and Canada. As of June 30, 2005, Devon had completed the sale of all of the Disposition Properties except for one minor package. Devon received proceeds from the divestitures of approximately $2.0 billion, net of all purchase price adjustments. After-tax, the proceeds were approximately $1.8 billion.

     The Disposition Properties’ actual contributions to our 2005 operating results are as follows:

		Production
		Oil				Gas				NGLs				Total
		(MMBbls)				(Bcf)				(MMBbls)				MMBoe
United States Onshore			0.5				7.4				0.3				2.0
United States Offshore			2.5				11.6				0.2				4.6
Canada			0.7				14.2				0.1				3.2
Total			3.7				33.2				0.6				9.8

		Expenses
		(In millions)
Lease operating expenses		$	76
DD&A		$	84
Other		$	55

     The above $55 million “other expense” relates to losses recognized on certain derivative financial instruments that no longer qualified for hedge accounting and were settled prior to the end of their original term. These commodity hedges related to 5,000 barrels per day of U.S. oil production and 3,000 barrels per day of Canadian oil production from properties sold as part of our property divestiture program.

Year 2005 Potential Capital Sources, Uses and Liquidity

     Capital Expenditures Devon’s capital expenditures budget is based on an expected range of future oil, natural gas and NGL prices as well as the expected costs of the capital additions. Should actual prices received differ materially from Devon’s price expectations for its future production, some projects may be accelerated or deferred and, consequently, may increase or decrease total 2005 capital expenditures. In addition, if the actual material or labor costs of the budgeted items vary significantly from the anticipated amounts, actual capital expenditures could vary materially from Devon’s estimates.

     Given the limitations discussed, the company expects its 2005 capital expenditures for drilling and development efforts, plus related facilities, to total between $3.23 billion and $3.42 billion. These amounts include between $635 million and $715 million for drilling and facilities costs related to reserves classified as proved as of year-end 2004. In addition, these amounts include between $1.61 billion and $1.69 billion for other production capital and between $980 million and $1.02 billion for exploration capital. Other production capital includes development drilling that does not offset currently productive units and for which there is not a certainty of continued production from a known productive formation. Exploration capital includes exploratory drilling to find and produce oil or gas in previously untested fault blocks or new reservoirs. These capital amounts exclude the previously announced $200 million purchase of predominantly unproved properties in the Iron River area of east central Alberta.

     The following table shows expected drilling, development and facilities expenditures by geographic area.

		United				United
		States				States								Inter-
		Onshore				Offshore				Canada				national				Total
		(In millions)
Production capital related to proved reserves		$	389-$    394			$	80-$  90			$	81-$      91			$	85-$140			$	635-$    715
Other production capital		$	755-$    805			$	30-$  40			$	800-$    810			$	25-$  35			$	1,610-$1,690
Exploration capital		$	195-$    205			$	275-$280			$	390-$    400			$	120-$130			$	980-$1,015
Total		$	1,339-$1,404			$	385-$410			$	1,271-$1,301			$	230-$305			$	3,225-$3,420

     In addition to the above expenditures for drilling, development and facilities, Devon expects to spend between $140 million to $150 million on its marketing and midstream assets, which include its oil pipelines, gas processing plants, CO₂ removal facilities and gas transport pipelines. Devon also expects to capitalize between $175 million and $185 million of G&A expenses in accordance with the full cost method of accounting and to capitalize between $65 million and $75 million of interest. Devon also expects to pay between $30 million and $40 million for plugging and abandonment charges, and to spend between $70 million and $80 million for other non-oil and gas property fixed assets.

     Other Cash Uses Devon’s management expects the policy of paying a quarterly common stock dividend to continue. With the current $0.075 per share quarterly dividend rate and 453 million shares of common stock outstanding as of June 30, 2005, dividends are expected to approximate $138 million. Also, Devon has $150 million of 6.49% cumulative preferred stock upon which it will pay $10 million of dividends in 2005.

     On September 27, 2004, Devon announced its intention to buy back up to 50 million shares of its common stock in conjunction with a stock buyback program. On August 2, 2005, Devon completed its repurchase of 50 million shares at a total cost of $2.3 billion. On August 3, 2005, Devon announced that its board of directors authorized the repurchase of up to an additional 50 million shares of its common stock. This second stock repurchase program is planned to extend through 2007. Shares may be purchased from time to time depending upon market conditions. Devon plans to repurchase shares in the open market and in privately negotiated transactions.

     Capital Resources and Liquidity Devon’s estimated 2005 cash uses, including its drilling and development activities and repurchase of common stock, are expected to be funded primarily through a combination of working capital, operating cash flow and the $1.8 billion of after-tax proceeds from the property divestitures completed in the first half of the year. The remainder, if any, would be funded with borrowings from Devon’s credit facility. The amount of operating cash flow to be generated during 2005 is uncertain due to the factors affecting revenues and expenses as previously cited. However, Devon expects its combined capital resources to be more than adequate to fund its anticipated capital expenditures and other cash uses for 2005 without the use of the available credit facility.

     As of June 30, 2005, Devon had $2.8 billion of cash and short-term investments on hand. If significant acquisitions or other unplanned capital requirements arise during the remainder of the year, Devon could utilize its existing credit facilities and/or seek to establish and utilize other sources of financing.

Year 2005 Summary

     The following summary includes estimates for Devon’s retained properties and actual results for the divestiture properties sold during the first six months of 2005.

		Retained				Divestiture				Combined
		Properties				Properties(1)				Properties
		(Estimated)				(Actual)				(Estimated)
Oil production (MMBbls)
U.S. Onshore			12				—				12
U.S. Offshore			11				3				14
Canada			12				1				13
International			27				—				27
Total			62				4				66
Gas production (Bcf)
U.S. Onshore			455				8				463
U.S. Offshore			92				11				103
Canada			250				14				264
International			10				—				10
Total			807				33				840
NGL production (MMBbls)
U.S. Onshore			17				1				18
U.S. Offshore			1				—				1
Canada			5				—				5
International			—				—				—
Total			23				1				24
Total production (MMBoe)
U.S. Onshore			105				2				107
U.S. Offshore			27				5				32
Canada			59				3				62
International			29				—				29
Total			220				10				230

The following tables on this page relate only to Devon’s retained properties.

		As a % of NYMEX Range
		Low				High
Oil floating price differentials
U.S. Onshore			88	%			93	%
U.S. Offshore			88	%			93	%
Canada			70	%			76	%
International			84	%			90	%

Gas floating price differentials
U.S. Onshore			81	%			90	%
U.S. Offshore			100	%			107	%
Canada			86	%			94	%
International			70	%			80	%

						Price				Months of
		Bbls/Day				Per Bbl				Production
Oil swaps
U.S. Offshore			8,000			$	27.14			Jan – Dec
Canada			3,000			$	27.13			Jan – Dec
International			6,000			$	25.88			Jan – Dec

						Price				Months of
		Mcf/Day				Per Mcf				Production
Gas fixed-price contracts and swaps
U.S. Onshore			7,343			$	3.40			Jan – Dec
Canada			38,578			$	2.89			Jan – Jun
Canada			38,578			$	2.96			Jul – Dec
International			12,000			$	2.35			Jan – Dec

						Weighted Average
						Floor Price				Ceiling Price				Months of
		Bbls/Day				Per Bbl				Per Bbl				Production
Oil collars
U.S. Offshore			17,000			$	22.00			$	27.62			Jan – Dec
Canada			15,000			$	22.00			$	28.28			Jan – Dec
International			15,000			$	23.23			$	29.34			Jan – Dec

						Weighted Average
						Floor Price				Ceiling Price				Months of
		MMBtu/Day				Per MMBtu				Per MMBtu				Production
Gas collars
U.S. Onshore			40,000			$	4.28			$	7.23			Jan – Jun
U.S. Offshore			40,000			$	3.50			$	7.50			Jan – Dec
U.S. Offshore			70,000			$	4.09			$	7.00			Jan – Jun
International

		Retained Properties								Divestiture				Combined Properties
		Range								Properties				Range
		Low				High				Actual				Low				High
Marketing and midstream ($ in millions)
Revenues														$	1,490			$	1,610
Expenses														$	1,160			$	1,260
Margin														$	330			$	350
Production and operating expenses ($ in millions)
LOE		$	1,200			$	1,270			$	76			$	1,276			$	1,346
Production taxes			3.25	%			3.75	%			1.50	%			3.25	%			3.75	%
DD&A ($ in millions)
Oil and gas DD&A		$	1,890			$	1,970			$	84			$	1,974			$	2,054
Non-oil and gas DD&A		$	155			$	165				—			$	155			$	165
Total DD&A		$	2,045			$	2,135			$	84			$	2,129			$	2,219
Oil and gas DD&A per Boe		$	8.60			$	9.00			$	8.52			$	8.59			$	8.93
Other ($ in millions)
Accretion of ARO														$	45			$	50
G&A														$	275			$	295
Interest expense														$	515			$	525
Effects of changes in foreign currency rates														$	10			$	10
Other revenues														$	190			$	200
Income tax rates
Current (1)															25	%			35	%
Deferred (1)															0	%			10	%
Total tax rate															25	%			45	%

		Retained Properties								Divestiture				Combined Properties
		Range								Properties				Range
		Low				High				Actual				Low				High
Production capital related to proved reserves ($ in millions)
U.S. Onshore		$	389			$	394			$	1			$	390			$	395
U.S. Offshore		$	80			$	90			$	15			$	95			$	105
Canada		$	81			$	91			$	4			$	85			$	95
International		$	85			$	140			$	—			$	85			$	140
Total		$	635			$	715			$	20			$	655			$	735
Other production capital ($ in millions)
U.S. Onshore		$	755			$	805			$	—			$	755			$	805
U.S. Offshore		$	30			$	40			$	—			$	30			$	40
Canada		$	800			$	810			$	—			$	800			$	810
International		$	25			$	35			$	—			$	25			$	35
Total		$	1,610			$	1,690			$	—			$	1,610			$	1,690
Exploration capital ($ in millions)
U.S. Onshore		$	195			$	205			$	—			$	195			$	205
U.S. Offshore		$	275			$	280			$	—			$	275			$	280
Canada		$	390			$	400			$	—			$	390			$	400
International		$	120			$	130			$	—			$	120			$	130
Total		$	980			$	1,015			$	—			$	980			$	1,015
Total drilling and facility capital ($ in millions)
U.S. Onshore		$	1,339			$	1,404			$	1			$	1,340			$	1,405
U.S. Offshore		$	385			$	410			$	15			$	400			$	425
Canada		$	1,271			$	1,301			$	4			$	1,275			$	1,305
International		$	230			$	305			$	—			$	230			$	305
Total		$	3,225			$	3,420			$	20			$	3,245			$	3,440
Other capital ($ in millions)
Marketing & midstream		$	140			$	150			$	—			$	140			$	150
Capitalized G&A		$	175			$	185			$	—			$	175			$	185
Capitalized interest		$	65			$	75			$	—			$	65			$	75
Plugging and abandonment		$	30			$	40			$	—			$	30			$	40
Non-oil and gas		$	70			$	80			$	—			$	70			$	80
Total		$	480			$	530			$	—			$	480			$	530

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 hereto duly authorized.

Date: August 4, 2005