UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

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

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

Definitions

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

     “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.

     “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, 2005 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.

     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 during the year 2006.

     Also, the financial results of Devon’s foreign operations are subject to currency exchange rate risks. 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 $0.87 U.S. dollar to $1.00 Canadian dollar. The actual 2006 exchange rate may vary materially from this estimate. Such variations could have a material effect on these forward-looking estimates.

     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, 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 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 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 2006 will be substantially similar to those of 2005, unless otherwise noted.

Geographic Reporting Areas for 2006

     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 2006 Potential Operating Items

     Oil, Gas and NGL Production Set forth in the following paragraphs are individual estimates of oil, gas and NGL production for 2006. On a combined basis, Devon estimates its 2006 oil, gas and NGL production will total approximately 217 MMBoe. Of this total, approximately 95% is estimated to be produced from reserves classified as “proved” at December 31, 2005.

     Oil Production Oil production in 2006 is expected to total approximately 58 MMBbls. Of this total, approximately 99% is estimated to be produced from reserves classified as “proved” at December 31, 2005. The expected production by area is as follows:

		(MMBbls)
United States Onshore			11
United States Offshore			9
Canada			14
International			24

     Oil Prices Devon has not fixed the price it will receive on any of its 2006 oil production. Devon’s 2006 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		86% to 94%
United States Offshore		86% to 94%
Canada		65% to 75%
International		80% to 88%

     Gas Production Gas production in 2006 is expected to total approximately 820 Bcf. Of this total, approximately 94% is estimated to be produced from reserves classified as “proved” at December 31, 2005. The expected production by area is as follows:

		(Bcf)
United States Onshore			492
United States Offshore			75
Canada			243
International			10

     Gas Prices – Fixed The price for approximately 2% of Devon’s estimated 2006 natural gas production has been fixed via various fixed-price physical delivery contracts 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 expected Btu content of the gas hedged.

										Months of
		Mcf/Day				Price/Mcf				Production
Canada			38,578			$	3.33			Jan – Dec
International			12,000			$	2.15			Jan – Dec

     Gas Prices – Floating For the natural gas production for which prices have not been fixed, Devon’s 2006 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		74% to 84%
United States Offshore		92% to 102%
Canada		80% to 90%
International		50% to 70%

     NGL Production Devon expects its 2006 production of NGLs to total approximately 22 MMBbls. Of this total, 97% is estimated to be produced from reserves classified as “proved” at December 31, 2005. The expected production by area is as follows:

		(MMBbls)
United States Onshore			17
United States Offshore			1
Canada			4

     Marketing and Midstream Revenues and Expenses 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 2006 marketing and midstream revenues will be between $1.74 billion and $2.20 billion, and marketing and midstream expenses will be between $1.38 billion and $1.80 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 the property base, changes in the general price level of services and materials that are used in the operation of the properties, the amount of repair and workover activity required and changes in production tax rates. 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 2006 lease operating expenses (including transportation costs) will be between $1.43 billion and $1.50 billion and production taxes will be between 3.25% and 3.75% of consolidated oil, natural gas and NGL revenues.

     Depreciation, Depletion and Amortization (“DD&A”) The 2006 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 2006 compared to the costs incurred for such efforts, and the revisions to Devon’s year-end 2005 reserve estimates that, based on prior experience, are likely to be made during 2006.

     Given these uncertainties, Devon expects its oil and gas property related DD&A rate will be between $9.30 per Boe and $9.50 per Boe. Based on these DD&A rates and the production estimates set forth earlier, oil and gas property related DD&A expense for 2006 is expected to be between $2.02 billion and $2.06 billion.

     Additionally, Devon expects its depreciation and amortization expense related to non-oil and gas property fixed assets to total between $170 million and $180 million.

     Accretion of Asset Retirement Obligation The 2006 accretion of asset retirement obligation is expected to be between $48 million and $53 million.

     General and Administrative Expenses (“G&A”) Devon’s G&A includes employee compensation and benefits costs and the costs of many different goods and services used in support of its business. G&A varies with the level of Devon’s operating activities and the related staffing and professional services requirements. In addition, employee compensation and benefits costs vary due to various market factors that affect the level and type of compensation and benefits offered to employees. Also, goods and services are subject to general price level increases or decreases. Therefore, significant variances in any of these factors from current expectations could cause actual G&A to vary materially from the estimate.

     Given these limitations, consolidated G&A in 2006 is expected to be between $360 million and $380 million. This estimate includes $35 million of expenses related to restricted stock compensation costs, net of related capitalization in accordance with the full cost method of accounting for oil and gas properties. This estimate also includes $35 million of expenses related to stock option compensation costs, net of related capitalization. Stock option costs are being expensed beginning January 1, 2006.

     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 2006 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.

     Based on the information related to interest expense set forth below and assuming no material changes in Devon’s levels of indebtedness or prevailing interest rates, Devon expects its 2006 interest expense (net of amounts capitalized) will be between $385 million and $395 million. Details of this estimate are discussed in the following paragraphs.

     The interest expense in 2006 related to Devon’s fixed-rate debt, including net accretion of related discounts, will be approximately $410 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
2.75% notes due in August 2006		$	500			LIBOR less 26.8 basis points
6.55% senior notes due in August 2006		$172 1				Banker’s Acceptance plus 340 basis points
4.375% senior notes due in October 2007		$	400			LIBOR plus 40 basis points

     Based on future LIBOR rates as of January 31, 2006, interest expense on its floating rate debt, including net amortization of premiums, is expected to total between $35 million and $45 million in 2006.

     Devon’s interest expense totals include 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 2006 interest expense. Also, Devon expects to capitalize between $65 million and $75 million of interest during 2006.

     Effects of Changes in Foreign Currency Rates Foreign currency gains or losses are not expected to be material in 2006.

     Other Revenues Devon’s other revenues in 2006 are expected to be between $155 million and $175 million.

     Devon maintains a comprehensive insurance program that includes coverage for physical damage to its offshore facilities caused by hurricanes. Its insurance program also includes substantial business interruption coverage which Devon expects to utilize to recover costs associated with the suspended production related to hurricanes that struck the Gulf of Mexico in the third quarter of 2005. Under the terms of the insurance program, Devon is entitled to be reimbursed for the portion of production suspended longer than forty-five days, subject to upper limits to oil and natural gas prices. Also, the terms of the insurance include a standard, per-event deductible of $1 million for offshore losses as well as a $15 million aggregate annual deductible. Based on current estimates of physical damage and the anticipated length of time Devon will have production suspended, Devon expects its policy claims will exceed repair costs and deductible amounts. As a result, 2006 and 2007 other revenues are expected to include more than $150 million for anticipated insurance proceeds in excess of repair costs. This estimate is dependent upon several variables, including the actual amount of time that production is suspended, the actual prices in effect while production is suspended and the timing of collections of insurance proceeds. Based on current estimates of the timing of collections of insurance proceeds, Devon expects 2006 other revenues will include $50 million to $70 million for anticipated insurance proceeds, with the balance to be recorded in 2007. Significant variances in any of these factors from current estimates could cause actual 2006 other revenues to vary materially from the estimate.

     Income Taxes Devon’s financial income tax rate in 2006 will vary materially depending on the actual amount of financial pre-tax earnings. The tax rate for 2006 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 2006’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 2006 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 2006’s financial income tax rates.

Year 2006 Potential Capital Sources, Uses and Liquidity

     Capital Expenditures 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.

     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 2006 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 2006 capital expenditures for drilling and development efforts, plus related facilities, to total between $4.275 billion and $4.470 billion. These amounts include between $1.205 billion and $1.265 billion for drilling and facilities costs related to reserves classified as proved as of year-end 2005. In addition, these amounts include between $2.090 billion and $2.175 billion for other production capital and between $980 million and $1.030 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.

     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		$	370-$390			$	85-$95			$	530-$550			$	220-$230			$	1,205-$1,265
Other production capital		$	1,380-$1,430			$	120-$130			$	570-$590			$	20-$25			$	2,090-$2,175
Exploration capital		$	260-$270			$	250-$270			$	200-$210			$	270-$280			$	980-$1,030
Total		$	2,010-$2,090			$	455-$495			$	1,300-$1,350			$	510-$535			$	4,275-$4,470

     In addition to the above expenditures for drilling, development and facilities, Devon expects to spend between $255 million to $275 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 $230 million and $240 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 $35 million and $45 million for plugging and abandonment charges, and to spend between $130 million and $140 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 443 million shares of common stock outstanding as of December 31, 2005, dividends are expected to approximate $133 million. Also, Devon has $150 million of 6.49% cumulative preferred stock upon which it will pay $10 million of dividends in 2006.

     On August 3, 2005, Devon announced its intention to buy back up to 50 million shares of its common stock. This 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. As of January 31, 2006, Devon had repurchased 2.2 million shares under the program for $134 million.

     Capital Resources and Liquidity Devon’s estimated 2006 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 (which totaled $1.3 billion at the end of 2005) and operating cash flow. The remainder, if any, could be funded with borrowings from Devon’s credit facility. The amount of operating cash flow to be generated during 2006 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 2006 without the use of the available credit facility.

     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.

Summary of 2006 Forward-Looking Estimates

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

Oil production (MMBbls)
U.S. Onshore			11
U.S. Offshore			9
Canada			14
International			24
Total			58
Gas production (Bcf)
U.S. Onshore			492
U.S. Offshore			75
Canada			243
International			10
Total			820
NGL production (MMBbls)
U.S. Onshore			17
U.S. Offshore			1
Canada			4
Total			22
Total production (MMBoe)
U.S. Onshore			110
U.S. Offshore			22
Canada			59
International			26
Total			217

		As a % of NYMEX Range
		Low				High
Oil floating price differentials
U.S. Onshore			86	%			94	%
U.S. Offshore			86	%			94	%
Canada			65	%			75	%
International			80	%			88	%
Gas floating price differentials
U.S. Onshore			74	%			84	%
U.S. Offshore			92	%			102	%
Canada			80	%			90	%
International			50	%			70	%

Price

Months of

Mcf/Day

Per Mcf

Production

Gas fixed-price contracts

Canada

38,578

$

3.33

Jan – Dec

International

12,000

$

2.15

Jan – Dec

		Range
		Low				High
Marketing and midstream ($ in millions)
Revenues		$	1,740			$	2,200
Expenses		$	1,380			$	1,800
Margin		$	360			$	400
Production and operating expenses ($ in millions)
LOE		$	1,430			$	1,500
Production taxes			3.25	%			3.75	%
DD&A ($ in millions)
Oil and gas DD&A		$	2,020			$	2,060
Non-oil and gas DD&A		$	170			$	180
Total DD&A		$	2,190			$	2,240
Oil and gas DD&A per Boe		$	9.30			$	9.50
Other ($ in millions)
Accretion of ARO		$	48			$	53
G&A		$	360			$	380
Interest expense		$	385			$	395
Other revenues		$	155			$	175
Income tax rates
Current			20	%			30	%
Deferred			5	%			15	%
Total tax rate			25	%			45	%

		Range
		Low				High
Production capital related to proved reserves ($ in millions)
U.S. Onshore		$	370			$	390
U.S. Offshore			85				95
Canada			530				550
International			220				230
Total		$	1,205			$	1,265
Other production capital ($ in millions)
U.S. Onshore		$	1,380			$	1,430
U.S. Offshore			120				130
Canada			570				590
International			20				25
Total		$	2,090			$	2,175
Exploration capital ($ in millions)
U.S. Onshore		$	260			$	270
U.S. Offshore			250				270
Canada			200				210
International			270				280
Total		$	980			$	1,030
Total drilling and facility capital ($ in millions)
U.S. Onshore		$	2,010			$	2,090
U.S. Offshore			455				495
Canada			1,300				1,350
International			510				535
Total		$	4,275			$	4,470
Other capital ($ in millions)
Marketing & midstream		$	255			$	275
Capitalized G&A			230				240
Capitalized interest			65				75
Plugging and abandonment			35				45
Non-oil and gas			130				140
Total		$	715			$	775

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 1, 2006

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