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		001-32318		73-1567067
(State or Other Jurisdiction of Incorporation or Organization)		(Commission File Number)		(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 2006 forward-looking estimates in a Current Report on Form 8-K dated February 1, 2006, and also in its 2005 Annual Report on Form 10-K. In its Current Report on Form 8-K dated May 3, 2006, Devon updated certain of its 2006 forward-looking estimates for the $2.2 billion acquisition of properties from Chief Holdings LLC (“Chief”) and other factors. In its Current Report on 8-K dated August 2, 2006 Devon again updated certain of its 2006 forward-looking estimates. In this document, Devon has again updated certain of these 2006 forward-looking estimates. The updated estimates and the reasons therefore, 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:

     “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.

     “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.

     “Mcf” means one thousand cubic feet.

     “MMcf” means one million 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 Devon 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 estimates do not include any financial and operating effects of potential property acquisitions or divestitures which may occur during the remainder of 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 2006 exchange rate of $0.88 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 and natural gas 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. Devon estimates, on a combined basis, that its 2006 oil, gas, and NGL production will total approximately 218 MMBoe.

     Oil Production Oil production in 2006 is expected to total approximately 59 MMBbls. The expected production by area is as follows:

		(MMBbls)
United States Onshore			11
United States Offshore			8
Canada			14
International			26

     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		90% to 98%
Canada		65% to 75%
International		87% to 95%

     Gas Production Gas production in 2006 is expected to total approximately 817 Bcf. The expected production by area is as follows:

		(Bcf)
United States Onshore			491
United States Offshore			78
Canada			239
International			9

     Gas Prices 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.

     During the first nine months of 2006, Devon had approximately 63 MMcf per day of gas production that was subject to fixed-price contracts. During the last three months of 2006, Devon will have approximately 89 MMcf per day of gas production that is subject to either fixed-price contracts, swaps, floors or collars. These amounts represent approximately 3% of Devon’s estimated gas production for 2006. Therefore, these various pricing arrangements are not expected to have a material impact on the ranges of estimated gas price realizations set forth in the following table.

		Expected Range of Gas Prices
		as a % of NYMEX Price
United States Onshore		74% to 84%
United States Offshore		94% to 104%
Canada		80% to 90%
International		85% to 105%

     NGL Production Devon expects its 2006 production of NGLs to total approximately 23 MMBbls. The expected production by area is as follows:

		(MMBbls)
United States Onshore			18
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. Devon’s most recent estimate for marketing and midstream revenues was between $1.77 billion and $2.00 billion, and the most recent estimate for marketing and midstream expenses was between $1.35 billion and $1.56 billion. Due to a decrease in estimates for natural gas prices and an increase in estimates for NGL prices and gas processing margins, Devon now estimates that its marketing and midstream revenues will be between $1.67 billion and $1.90 billion, and marketing and midstream expenses will be between $1.225 billion and $1.435 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 $1.44 billion and $1.51 billion. Additionally, Devon estimates its production taxes for 2006 to be between 3.6% and 4.0% 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 $10.30 per Boe and $10.70 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 $2.245 billion and $2.330 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.

     Devon’s most recent estimate of consolidated G&A in 2006 was between $370 million and $390 million. Due to increases in employee compensation costs, Devon now estimates its consolidated G&A for 2006 to be between $395 million and $405 million. This estimate includes $40 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 $26 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.

     During the first nine months of 2006, Devon reduced the carrying value of its Nigerian and Brazilian oil and gas properties by $85 million and $16 million, respectively, due to unsuccessful exploratory drilling results. Additionally, during the third quarter of 2006, Devon reduced the carrying value of its Egyptian and Russian oil and gas properties by $31 million and $20 million, respectively, due to the costs to be recovered, as defined above, being higher than the full cost ceiling for each country. The Egyptian reduction resulted from unsuccessful exploratory activities, and the Russian reduction resulted from a decline in future net cash flows. It is not possible to predict whether Devon will incur other reductions in carrying value 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.

     Devon’s most recent estimate of its 2006 interest expense (net of amounts capitalized) was between $435 million and $445 million. Devon has determined that these estimates should be decreased primarily due to an increase in capitalized interest and decreases in anticipated prevailing floating interest rates. Therefore, 2006 interest expense is now estimated to be between $420 million and $430 million.

     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 used variable-rate commercial paper to fund a portion of the Chief acquisition. Also, 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
		(In millions)
Commercial Paper		$	1,439	1		Various 2
4.375% senior notes due in Oct 2007		$	400			LIBOR plus 40 basis points

     Devon’s most recent estimate for interest expense on its floating rate debt was between $85 million and $95 million. Based on estimates of future LIBOR rates as of September 30, 2006, interest expense on floating rate debt, including net amortization of premiums, is now expected to total between $80 million and $90 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.

     Devon’s previous estimates were to capitalize between $65 million and $75 million of interest during 2006. Due to an increase in costs related to major development projects, capitalized interest for 2006 is now estimated to be between $75 million and $85 million.

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

     Other Revenues Devon estimates that its other revenues in 2006 will be between $80 million and $100 million.

     Historically, Devon maintained a comprehensive insurance program that included coverage for physical damage to its offshore facilities caused by hurricanes. Devon’s historical insurance program also included substantial business interruption coverage which Devon is utilizing 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 this insurance program, Devon was 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 included 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 recoveries will exceed repair costs and deductible amounts. This expectation is based upon several variables, including the $467 million received in the third quarter of 2006 as a full settlement of the amount due from our primary

insurers. As of September 30, 2006, $135 million of these proceeds had been utilized as reimbursement of past repair costs and deductible amounts. The remaining proceeds of $332 million will be utilized as reimbursement of Devon’s anticipated future repair costs. Should Devon’s total policy recoveries, including the partial settlements already received exceed all repair costs and deductible amounts, such excess will be recognized as other income in the statement of operations in the period in which such determination can be made. Currently, Devon believes it is possible that the ultimate amount of such excess will not be known until 2007. Therefore, Devon expects such excess will not be recordable as other revenues until 2007.

     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 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 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.

     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 $4.745 billion and $4.940 billion. These amounts include between $1.375 billion and $1.435 billion for drilling and facilities costs related to reserves classified as proved as of year-end 2005. In addition, these amounts include between $2.280 billion and $2.375 billion for other production capital and between $1.090 billion and $1.130 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. These amounts do not include the $2.2 billion Chief acquisition.

		United				United
		States				States								Inter-
		Onshore				Offshore				Canada				national				Total
										(In millions)
Production capital related to proved reserves		$	430-$   450			$	85-$  95			$	580-$   600			$	280-$290			$	1,375-$1,435
Other production capital		$	1,560-$1,620			$	130-$140			$	570-$   590			$	20-$  25			$	2,280-$2,375
Exploration capital		$	300-$   310			$	310-$320			$	180-$   190			$	300-$310			$	1,090-$1,130
Total		$	2,290-$2,380			$	525-$555			$	1,330-$1,380			$	600-$625			$	4,745-$4,940

     In addition to the above expenditures for drilling, development and facilities, Devon expects to spend between $330 million to $380 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 $250 million and $260 million of G&A expenses in accordance with the full cost method of accounting and to capitalize between $75 million and $85 million of interest. Devon also expects to pay between $50 million and $60 million for plugging and abandonment charges, and to spend between $170 million and $180 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 $0.1125 per share quarterly dividend rate and 442 million shares of common stock outstanding as of September 30, 2006, dividends are expected to approximate $198 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. As of November 1, 2006, Devon had repurchased 6.5 million shares under the program for $387 million. As a result of the Chief acquisition, this repurchase program has been suspended and will be reevaluated at a later date.

     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. In addition, Devon utilized approximately $718 million of cash and approximately $1.4 billion of borrowings under its commercial paper program to fund the Chief acquisition price. Any remaining cash uses could be funded with borrowings from the available capacity under Devon’s credit facility, which was $765 million at September 30, 2006. 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.

     If significant other acquisitions or other unplanned capital requirements arise during the year, Devon could utilize its existing credit facility and/or seek to establish and utilize other sources of financing.

Summary of 2006 Forward-Looking Estimates

     The tables below summarize Devon’s 2006 forward-looking estimates.

Oil production (MMBbls)
U.S. Onshore			11
U.S. Offshore			8
Canada			14
International			26
Total			59
Gas production (Bcf)
U.S. Onshore			491
U.S. Offshore			78
Canada			239
International			9
Total			817
NGL production (MMBbls)
U.S. Onshore			18
U.S. Offshore			1
Canada			4
International			—
Total			23
Total production (MMBoe)
U.S. Onshore			111
U.S. Offshore			22
Canada			58
International			27
Total			218

		As % of NYMEX Range
		Low				High
Oil floating price differentials
U.S. Onshore			86	%			94	%
U.S. Offshore			90	%			98	%
Canada			65	%			75	%
International			87	%			95	%
Gas floating price differentials
U.S. Onshore			74	%			84	%
U.S. Offshore			94	%			104	%
Canada			80	%			90	%
International			85	%			105	%

		Range
		Low				High
Marketing and midstream ($ in millions)
Revenues		$	1,670			$	1,900
Expenses		$	1,225			$	1,435
Operating profit		$	445			$	465
Production and operating expenses ($ in millions)
LOE		$	1,440			$	1,510
Production taxes			3.6	%			4.0	%
DD&A ($ in millions)
Oil and gas DD&A		$	2,245			$	2,330
Non-oil and gas DD&A		$	170			$	180
Total DD&A		$	2,415			$	2,510
Oil and gas DD&A per Boe		$	10.30			$	10.70
Other ($ in millions)
Accretion of ARO		$	48			$	53
G&A		$	395			$	405
Interest expense		$	420			$	430
Other revenues		$	80			$	100
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		$	430			$	450
U.S. Offshore		$	85			$	95
Canada		$	580			$	600
International		$	280			$	290
Total		$	1,375			$	1,435
Other production capital ($ in millions)
U.S. Onshore		$	1,560			$	1,620
U.S. Offshore		$	130			$	140
Canada		$	570			$	590
International		$	20			$	25
Total		$	2,280			$	2,375
Exploration capital ($ in millions)
U.S. Onshore		$	300			$	310
U.S. Offshore		$	310			$	320
Canada		$	180			$	190
International		$	300			$	310
Total		$	1,090			$	1,130
Total drilling and facility capital ($ in millions)
U.S. Onshore		$	2,290			$	2,380
U.S. Offshore		$	525			$	555
Canada		$	1,330			$	1,380
International		$	600			$	625
Total		$	4,745			$	4,940
Other capital ($ in millions)
Marketing & midstream		$	330			$	380
Capitalized G&A		$	250			$	260
Capitalized interest		$	75			$	85
Plugging and abandonment		$	50			$	60
Non-oil and gas		$	170			$	180
Total		$	875			$	965

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: November 1, 2006