UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

FORM 8-K

CURRENT REPORT

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

Date of Report (Date of earliest event report): February 2, 2005

DEVON ENERGY CORPORATION

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:

Table of Contents

Item 8.01. Other Events

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.

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.

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     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 2005 will be substantially similar to those of 2004, unless otherwise noted.

     Unless otherwise noted, all of the following dollar amounts are expressed in U.S. dollars. Amounts related to Canadian operations have been converted to U.S. dollars using a projected average 2005 exchange rate of $0.82 U.S. 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.

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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:

Year 2005 Potential Operating Items

     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 designated for possible sale (See “Property Acquisitions and Divestitures”). Therefore, the following estimates exclude the results of the potential sale properties for the entire year.

     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 217 MMBoe. Of this total, approximately 92% is estimated to be produced from reserves classified as “proved” at December 31, 2004.

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     Oil Production Devon expects its oil production in 2005 to total 60 MMBbls. Of this total, approximately 95% is estimated to be produced from reserves classified as “proved” at December 31, 2004. The expected production by area is as follows:

     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.

     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.

     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.

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     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.

     Gas Production Devon expects its 2005 gas production to total 804 Bcf. Of this total, approximately 90% is estimated to be produced from reserves classified as “proved” at December 31, 2004. The expected production by area is as follows:

     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.

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     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.

     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.

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     NGL Production Devon expects its 2005 production of NGLs to total 23 MMBbls. Of this total, 93% is estimated to be produced from reserves classified as “proved” at December 31, 2004. The expected production by area is as follows:

     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 $1.26 billion and $1.40 billion, and marketing and midstream expenses will be between $1.00 billion and $1.10 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 $1.155 billion and $1.225 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, oil and gas property related DD&A expense for 2005 is expected to be between $1.86 billion and $1.94 billion. Based on these DD&A amounts and the production estimates set forth earlier, Devon expects its oil and gas property related DD&A rate will be between $8.60 per Boe and $9.00 per Boe.

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     Additionally, Devon expects its depreciation and amortization expense related to non-oil and gas property fixed assets to total between $150 million and $160 million.

     Accretion of Asset Retirement Obligation Devon expects its 2005 accretion of its asset retirement obligation to be between $40 million and $45 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.

     The planned property dispositions have further added to the uncertainties around G&A estimates. Devon is currently in the process of determining the appropriate staffing needs subsequent to the dispositions. Specifically excluded from these estimates are both severance related costs and the cost savings that would result from an expected reduction of headcount. Any cost savings from these reductions will be dependent not only on the level of staff reductions, but also on the timing. As a result, until this process is complete, actual 2005 G&A could vary materially from current estimates.

     Given these limitations, consolidated G&A in 2005 is expected to be between $260 million and $280 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.

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     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 $430 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:

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     ¹ _{Converted from $200 million Canadian dollars at a Canadian-to-U.S. dollar exchange rate of $0.8308 as of December 31, 2004.}

     Based on future LIBOR rates as of January 31, 2005, interest expense on its floating rate debt, including net amortization of premiums, is expected to total between $75 million and $85 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 $5 million and $15 million of such items to be included in its 2005 interest expense. 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 retirement of debt due to mature in 2005, Devon expects its 2005 interest expense will be between $445 million and $455 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. Changes in the exchange rate between the U.S. dollar and the Canadian dollar during 2005 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

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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 2005 rate of $0.8200, Devon expects to record an expense of approximately $5 million. The actual 2005 effect will depend on the exchange rate as of December 31, 2005.

     Other Revenues Devon’s other revenues in 2005 are expected to be between $260 million and $270 million. Included as part of other revenues is a $150 million gain on the sale of certain assets in the first quarter of 2005.

     Other revenues do not include the effect of any early settlements or hedge ineffectiveness of outstanding commodity price hedges as a result of the property dispositions. The amount of any settlement gain or loss or hedge ineffectiveness will depend not only on the timing of the sales but also on the forward prices in effect at that time. As a result, Devon is unable to predict the effect that these early settlements or hedge ineffectiveness may have on its earnings. Under current market conditions, Devon would expect to record a loss on these early settlements or hedge ineffectiveness.

     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 its pre-tax earnings amount, 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%. 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.

     Property Acquisitions and Divestitures Though Devon has completed several major property acquisitions in recent years, these transactions are opportunity driven. Thus, Devon does not “budget,” nor can it reasonably predict, the timing or size of such possible acquisitions, if any.

     During 2005, Devon contemplates the disposition of certain oil and gas properties (the “Disposition Properties”). The Disposition Properties are predominantly properties that are either outside of Devon’s core-operating areas or otherwise do not fit Devon’s current strategic objectives. The Disposition Properties are located in the U.S. and Canada. At this time, Devon is in the early stages of the disposition process, and it is impossible to identify when, or if, the dispositions will occur.

     The estimates of Devon’s 2005 results previously set forth exclude any results from the Disposition Properties. The Disposition Properties’ actual contributions to Devon’s 2005 operating results will depend upon the timing of the dispositions. The estimated first quarter 2005 results from the Disposition Properties (which are not included in the previous 2005 estimates in this report) are as follows:

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     Not included in these estimates is the effect of any early settlements of outstanding commodity price hedges as a result of the dispositions. The amount of any gain or loss will depend not only on the timing of the sales but also on the forward prices in effect at that time. As a result, Devon is unable to predict the effect that these early settlements may have on its earnings. Under current market conditions, Devon would expect to record a loss on these early settlements.

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 $2.6 billion and $3.0 billion. These amounts include between $390 million and $450 million for drilling and facilities costs related to reserves classified as proved as of year-end 2004. In addition, these amounts include between $1.345 billion and $1.555 billion for other production capital and between $865 million and $995 million 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.

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

     In addition to the above expenditures for drilling and development, Devon expects to spend between $85 million to $95 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 $165 million and $175 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 $25 million and $30 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 $0.05 per share quarterly dividend rate and 484 million shares of common stock outstanding as of December 31, 2004, dividends are expected to approximate $97 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. The shares will be repurchased with cash flow from operations and proceeds from its planned property divestitures. As of January 31, 2005, Devon has repurchased 7.5 million shares at a total cost of $279 million or $37.16 per share.

     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 proceeds from its planned property divestitures, with the remainder, if any, 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. As of December 31, 2004, Devon had $2.1 billion of cash on hand and $1.3 billion available under its $1.5 billion of credit facilities, net of $0.2 billion of outstanding letters of credit. If significant acquisitions or other unplanned capital requirements arise during the year, Devon could utilize its existing credit facilities and/or seek to establish and utilize other sources of financing.

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     The following summary is based on estimates for Devon’s properties other than those that have been designated for possible sale (See “Property Acquisitions and Divestitures”). Therefore, the following estimates exclude the results of the potential sale properties for the entire year.

     With the exception of per-unit dollar amounts, the following dollar amounts are expressed in millions.

Summary of 2005 Forward-Looking Estimates

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Summary of 2005 Forward-Looking Estimates (Continued)

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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: February 2, 2005

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