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1. Summary of Significant Accounting Policies
Accounting policies used by Devon Energy Corporation and subsidiaries ("Devon") reflect industry practices and conform to accounting principles generally accepted in the United States of America. The more significant of such policies are discussed below
Nature of Business and Principles of Consolidation
Devon is engaged primarily in the acquisition, exploration, development and production of oil and gas properties. Such activities are concentrated in the following North American onshore geographic areas:
• the Mid-Continent area of the central and southern United States, principally in north and east Texas, as well as Oklahoma;
• the Permian Basin within Texas and New Mexico;
• the Rocky Mountains area of the United States stretching from the Canadian border into northern New Mexico;
• the onshore areas of the Gulf Coast, principally in south Texas and south Louisiana; and
• the provinces of Alberta, British Columbia and Saskatchewan in Canada.
In November 2009, Devon announced plans to strategically reposition itself as a North American onshore exploration and development company. During 2010, Devon divested its properties in the Gulf of Mexico, Azerbaijan, China and other International regions. Additionally, Devon has entered into agreements to sell its remaining offshore assets in Brazil and Angola. These activities are more fully described in Note 5.
Devon also has marketing and midstream operations that perform various activities to support the oil and gas operations of Devon and unrelated third parties. Such activities include marketing gas, crude oil and NGLs, as well as constructing and operating pipelines, storage and treating facilities and natural gas processing plants.
The accounts of Devon's controlled subsidiaries are included in the accompanying consolidated financial statements. All significant intercompany accounts and transactions have been eliminated in consolidation.
.
Use of Estimates in the Preparation of Financial Statements
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual amounts could differ from these estimates, and changes in these estimates are recorded when known. Significant items subject to such estimates and assumptions include the following:
• estimates of proved reserves and related estimates of the present value of future net revenues;
• the carrying value of oil and gas properties;
• estimates of the fair value of reporting units and related assessment of goodwill for impairment;
• derivative financial instruments;
• income taxes;
• asset retirement obligations;
• obligations related to employee pension and postretirement benefits; and
• legal and environmental risks and exposures.
Derivative Financial Instruments
Devon is exposed to certain risks relating to its ongoing business operations, including risks related to commodity prices, interest rates and Canadian to U.S. dollar exchange rates. As discussed more fully below, Devon uses derivative instruments primarily to manage commodity price risk and interest rate risk. Devon does not hold or issue derivative financial instruments for speculative trading purposes. Besides these derivative instruments, Devon also had an embedded option derivative related to the fair value of its debentures exchangeable into shares of Chevron common stock. Devon ceased to have this option when the exchangeable debentures matured on August 15, 2008.
Devon periodically enters into derivative financial instruments with respect to a portion of its oil, gas and NGL production that hedge the future prices received. These instruments are used to manage the inherent uncertainty of future revenues due to commodity price volatility. Devon's derivative financial instruments include financial price swaps, basis swaps, costless price collars and call options. Under the terms of the price swaps, Devon receives a fixed price for its production and pays a variable market price to the contract counterparty. For the basis swaps, Devon receives a fixed differential between two regional gas index prices and pays a variable differential on the same two index prices to the contract counterparty. The price collars set a floor and ceiling price for the hedged production. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, Devon will cash-settle the difference with the counterparty to the collars. Under the terms of a call option, Devon received a cash premium for selling call options. The call options then give the counterparty the right to place us into a price swap at a predetermined fixed price.
Devon periodically enters into interest rate swaps to manage its exposure to interest rate volatility. Devon's interest rate swaps include contracts in which Devon receives a fixed rate and pays a variable rate on a total notional amount. Devon also has forward starting swaps. Under the terms of the forward starting swaps, Devon will net settle these contracts in September 2011 or sooner should Devon elect. The net settlement amount will be based upon Devon paying a fixed rate and receiving a floating rate that is based upon the three-month LIBOR. The difference between the fixed and floating rate will be applied to the notional amount for the 30-year period from September 30, 2011 to September 30, 2041.
All derivative financial instruments are recognized at their current fair value as either assets or liabilities in the balance sheet. Changes in the fair value of these derivative financial instruments are recorded in the statement of operations unless specific hedge accounting criteria are met. For derivative financial instruments held during the three-year period ended December 31, 2010, Devon chose not to meet the necessary criteria to qualify its derivative financial instruments for hedge accounting treatment. Cash settlements with counterparties to Devon's derivative financial instruments are also recorded in the statement of operations.
By using derivative financial instruments to hedge exposures to changes in commodity prices and interest rates, Devon exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. To mitigate this risk, the hedging instruments are placed with a number of counterparties whom Devon believes are minimal credit risks. It is Devon's policy to enter into derivative contracts only with investment grade rated counterparties deemed by management to be competent and competitive market makers. Additionally, Devon's derivative contracts generally require cash collateral to be posted if either its or the counterparty's credit rating falls below investment grade. The mark-to-market exposure threshold, above which collateral must be posted, decreases as the debt rating falls further below investment grade. Such thresholds generally range from zero to $50 million for the majority of our contracts. As of December 31, 2010, the credit ratings of all Devon's counterparties were investment grade.
Market risk is the change in the value of a derivative financial instrument that results from a change in commodity prices, interest rates or other relevant underlyings. The market risks associated with commodity price and interest rate contracts are managed by establishing and monitoring parameters that limit the types and degree of market risk that may be undertaken. The oil and gas reference prices upon which the commodity instruments are based reflect various market indices that have a high degree of historical correlation with actual prices received by Devon.
See Note 3 for the amounts included in Devon's accompanying consolidated balance sheets and consolidated statements of operations associated with its derivative financial instruments.
Fair Value Measurements
Certain of Devon's assets and liabilities are measured at fair value at each reporting date. Fair value represents the price that would be received to sell the asset or paid to transfer the liability in an orderly transaction between market participants. This price is commonly referred to as the "exit price".
Fair value measurements are classified according to a hierarchy that prioritizes the inputs underlying the valuation techniques. This hierarchy consists of three broad levels. Level 1 inputs on the hierarchy consist of unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. Level 2 measurements are based on inputs other than quoted prices that are generally observable for the asset or liability. Common examples of Level 2 inputs include quoted prices for similar assets and liabilities in active markets or quoted prices for identical assets and liabilities in markets not considered to be active. Level 3 measurements have the lowest priority and are based upon inputs that are not observable from objective sources. The most common Level 3 fair value measurement is an internally developed cash flow model. Devon uses appropriate valuation techniques based on the available inputs to measure the fair values of its assets and liabilities. When available, Devon measures fair value using Level 1 inputs because they generally provide the most reliable evidence of fair value.
See Note 11 for fair value measurements included in Devon's accompanying consolidated balance sheets.
Discontinued Operations
As a result of the November 2009 plan to divest Devon's offshore assets, all amounts related to Devon's International operations are classified as discontinued operations. The Gulf of Mexico properties that were divested in 2010 do not qualify as discontinued operations under accounting rules. As such, amounts in these notes and the accompanying consolidated financial statements that pertain to continuing operations include amounts related to Devon's offshore Gulf of Mexico operations. See Note 5 for additional details of the offshore divestiture program.
The captions assets held for sale and liabilities associated with assets held for sale in the accompanying consolidated balance sheets present the assets and liabilities associated with Devon's discontinued operations. Devon measures its assets held for sale at the lower of its carrying amount or estimated fair value less costs to sell. Additionally, Devon does not recognize depreciation, depletion and amortization on its long-lived assets held for sale.
Property and Equipment
Devon follows the full cost method of accounting for its oil and gas properties. Accordingly, all costs incidental to the acquisition, exploration and development of oil and gas properties, including costs of undeveloped leasehold, dry holes and leasehold equipment, are capitalized. Internal costs incurred that are directly identified with acquisition, exploration and development activities undertaken by Devon for its own account, and that are not related to production, general corporate overhead or similar activities, are also capitalized. Interest costs incurred and attributable to unproved oil and gas properties under current evaluation and major development projects of oil and gas properties are also capitalized. All costs related to production activities, including workover costs incurred solely to maintain or increase levels of production from an existing completion interval, are charged to expense as incurred.
Under the full cost method of accounting, the net book value of oil and gas properties, less related deferred income taxes, may not exceed a calculated "ceiling." The ceiling limitation is the estimated after-tax future net revenues, discounted at 10% per annum, from proved oil, gas and NGL reserves plus the cost of properties not subject to amortization. Estimated future net revenues exclude future cash outflows associated with settling asset retirement obligations included in the net book value of oil and gas properties. Such limitations are imposed separately on a country-by-country basis and are tested quarterly.
Future net revenues are calculated using prices that represent the average of the first-day-of-the-month price for the 12-month period prior to the end of the period. Prior to December 31, 2009, prices and costs used to calculate future net revenues were those as of the end of the appropriate quarterly period. Prices are held constant indefinitely and are not changed except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including derivative contracts in place that qualify for hedge accounting treatment. None of Devon's derivative contracts held during the three-year period ended December 31, 2010 qualified for hedge accounting treatment.
Any excess of the net book value, less related deferred taxes, over the ceiling is written off as an expense. An expense recorded in one period may not be reversed in a subsequent period even though higher commodity prices may have increased the ceiling applicable to the subsequent period.
Capitalized costs are depleted by an equivalent unit-of-production method, converting gas to oil at the ratio of six thousand cubic feet of gas to one barrel of oil. Depletion is calculated using the capitalized costs, including estimated asset retirement costs, plus the estimated future expenditures (based on current costs) to be incurred in developing proved reserves, net of estimated salvage values.
Costs associated with unproved properties are excluded from the depletion calculation until it is determined whether or not proved reserves can be assigned to such properties. Devon assesses its unproved properties for impairment quarterly. Significant unproved properties are assessed individually. Costs of insignificant unproved properties are transferred into the depletion calculation over holding periods ranging from three to five years.
No gain or loss is recognized upon disposal of oil and gas properties unless such disposal significantly alters the relationship between capitalized costs and proved reserves in a particular country.
Depreciation of midstream pipelines are provided on a unit-of-production basis. Depreciation and amortization of other property and equipment, including corporate and other midstream assets and leasehold improvements, are provided using the straight-line method based on estimated useful lives ranging from three to 39 years. Interest costs incurred and attributable to major midstream and corporate construction projects are also capitalized.
Devon recognizes liabilities for retirement obligations associated with tangible long-lived assets, such as producing well sites, offshore production platforms, and midstream pipelines and processing plants when there is a legal obligation associated with the retirement of such assets and the amount can be reasonably estimated. The initial measurement of an asset retirement obligation is recorded as a liability at its fair value, with an offsetting asset retirement cost recorded as an increase to the associated property and equipment on the consolidated balance sheet. If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement cost. The asset retirement cost is depreciated using a systematic and rational method similar to that used for the associated property and equipment.
Investments
Devon reports its investments and other marketable securities at fair value, except for debt securities in which management has the ability and intent to hold until maturity.
Devon's primary investments consist of auction rate securities that totaled $94 million and $115 million at December 31, 2010 and 2009, respectively. These securities are rated AAA—the highest rating—by one or more rating agencies and are collateralized by student loans that are substantially guaranteed by the United States government. Although Devon's auction rate securities generally have contractual maturities of more than 20 years, the underlying interest rates on such securities are scheduled to reset every seven to 28 days. Therefore, these auction rate securities were generally priced and subsequently traded as short-term investments because of the interest rate reset feature.
Since February 8, 2008, Devon has experienced difficulty selling its securities due to the failure of the auction mechanism, which provided liquidity to these securities. An auction failure means that the parties wishing to sell securities could not do so. The securities for which auctions have failed will continue to accrue interest and be auctioned every seven to 28 days until the auction succeeds, the issuer calls the securities or the securities mature.
From February 2008, when auctions began failing, to December 31, 2010, issuers have redeemed $58 million of Devon's auction rate securities holdings at par. However, based on continued auction failures and the current market for Devon's auction rate securities, Devon has classified its auction rate securities as long-term investments as of December 31, 2010. These securities are included in other long-term assets in the accompanying consolidated balance sheet. Devon has the ability to hold the securities until maturity. At this time, Devon does not believe the values of its long-term securities are impaired.
Goodwill
Goodwill represents the excess of the purchase price of business combinations over the fair value of the net assets acquired and is tested for impairment at least annually. The impairment test requires allocating goodwill and all other assets and liabilities to assigned reporting units. The fair value of each reporting unit is estimated and compared to the net book value of the reporting unit. If the estimated fair value of the reporting unit is less than the net book value, including goodwill, then the goodwill is written down to the implied fair value of the goodwill through a charge to expense. Because quoted market prices are not available for Devon's reporting units, the fair values of the reporting units are estimated based upon several valuation analyses, including comparable companies, comparable transactions and premiums paid.
Devon performed annual impairment tests of goodwill in the fourth quarters of 2010, 2009 and 2008. Based on these assessments, no impairment of goodwill was required.
The table below provides a summary of Devon's goodwill, by assigned reporting unit, as of December 31, 2010 and 2009. The increase in Devon's continuing operations goodwill from 2009 to 2010 is due to changes in the exchange rate between the U.S. dollar and the Canadian dollar. Devon removed all its International goodwill in conjunction with the Azerbaijan divestiture that closed in 2010. Such goodwill was presented in long-term assets held for sale in the accompanying December 31, 2009 consolidated balance sheet.
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December 31, | |
|
2010 |
2009 |
|
(In millions) | |
United States |
$ 3,046 |
$ 3,046 |
Canada |
3,034 |
2,884 |
Total (continuing operations) |
$ 6,080 |
$ 5,930 |
International (assets held for sale) |
$ — |
$ 68 |
Foreign Currency Translation Adjustments
The U.S. dollar is the functional currency for Devon's consolidated operations except its Canadian subsidiaries, which use the Canadian dollar as the functional currency. Therefore, the assets and liabilities of Devon's Canadian subsidiaries are translated into U.S. dollars based on the current exchange rate in effect at the balance sheet dates. Canadian income and expenses are translated at average rates for the periods presented. Translation adjustments have no effect on net income and are included in accumulated other comprehensive earnings in stockholders' equity. The following table presents the balances of Devon's cumulative translation adjustments included in accumulated other comprehensive earnings (in millions).
December 31, 2007 |
$ 2,566 |
December 31, 2008 |
$ 685 |
December 31, 2009 |
$ 1,616 |
December 31, 2010 |
$ 1,993 |
Commitments and Contingencies
Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Liabilities for environmental remediation or restoration claims are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. Expenditures related to such environmental matters are expensed or capitalized in accordance with Devon's accounting policy for property and equipment. Reference is made to Note 10 for a discussion of amounts recorded for these liabilities.
Revenue Recognition and Gas Balancing
Oil, gas and NGL sales are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectability of the revenue is probable. Delivery occurs and title is transferred when production has been delivered to a pipeline, railcar or truck or a tanker lifting has occurred. Cash received relating to future production is deferred and recognized when all revenue recognition criteria are met. Taxes assessed by governmental authorities on oil, gas and NGL sales are presented separately from such revenues in the accompanying consolidated statements of operations.
Devon follows the sales method of accounting for gas production imbalances. The volumes of gas sold may differ from the volumes to which Devon is entitled based on its interests in the properties. These differences create imbalances that are recognized as a liability only when the estimated remaining reserves will not be sufficient to enable the underproduced owner to recoup its entitled share through production. The liability is priced based on current market prices. No receivables are recorded for those wells where Devon has taken less than its share of production unless all revenue recognition criteria are met. If an imbalance exists at the time the wells' reserves are depleted, settlements are made among the joint interest owners under a variety of arrangements.
Marketing and midstream revenues are recorded at the time products are sold or services are provided to third parties at a fixed or determinable price, delivery or performance has occurred, title has transferred and collectability of the revenue is probable. Revenues and expenses attributable to oil, gas and NGL purchases, transportation and processing contracts are reported on a gross basis when Devon takes title to the products and has risks and rewards of ownership.
During 2010, 2009 and 2008, no purchaser accounted for more than 10% of Devon's revenues from continuing operations.
General and Administrative Expenses
General and administrative expenses are reported net of amounts reimbursed by working interest owners of the oil and gas properties operated by Devon and net of amounts capitalized pursuant to the full cost method of accounting.
Share Based Compensation
Devon grants stock options, restricted stock awards and other types of share-based awards to members of its Board of Directors and selected employees. All such awards are measured at fair value on the date of grant and are recognized as a component of general and administrative expenses in the accompanying statements of operations over the applicable requisite service periods. As a result of Devon's strategic repositioning announced in 2009, certain share based awards were accelerated and recognized as a component of restructuring expense in the accompanying 2010 and 2009 statements of operations.
Generally, Devon uses new shares to grant share-based awards and to issue shares upon stock option exercises. Shares repurchased under approved programs are available to be issued as part of Devon's share based awards. However, Devon has historically cancelled these shares upon repurchase.
Income Taxes
Devon is subject to current income taxes assessed by the federal and various state jurisdictions in the United States and by other foreign jurisdictions. In addition, Devon accounts for deferred income taxes related to these jurisdictions using the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases. Deferred tax assets are also recognized for the future tax benefits attributable to the expected utilization of existing tax net operating loss carryforwards and other types of carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.
Devon does not recognize United States deferred income taxes on the unremitted earnings of its foreign subsidiaries that are deemed to be permanently reinvested. When such earnings are no longer deemed permanently reinvested, Devon recognizes the appropriate deferred income tax liabilities.
Devon recognizes the financial statement effects of tax positions when it is more likely than not, based on the technical merits, that the position will be sustained upon examination by a taxing authority. Recognized tax positions are initially and subsequently measured as the largest amount of tax benefit that is more likely than not of being realized upon ultimate settlement with a taxing authority. Liabilities for unrecognized tax benefits related to such tax positions are included in other long-term liabilities unless the tax position is expected to be settled within the upcoming year, in which case the liabilities are included in other current liabilities. Interest and penalties related to unrecognized tax benefits are included in current income tax expense. Additional information regarding Devon's unrecognized tax benefits, including changes in such amounts during 2010 and 2009, is provided in Note 17.
Net Earnings (Loss) Per Common Share
Devon's basic earnings per share amounts have been computed based on the average number of shares of common stock outstanding for the period. Basic earnings per share includes the effect of participating securities, which primarily consist of Devon's outstanding restricted stock awards. Diluted earnings per share is calculated using the treasury stock method to reflect the potential dilution that could occur if Devon's dilutive outstanding stock options were exercised.
Cash and Cash Equivalents
Devon considers all highly liquid investments with original contractual maturities of three months or less to be cash equivalents.
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2. Accounts Receivable
The components of accounts receivable include the following:
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December 31, | |
|
2010 |
2009 |
|
(In millions) | |
Oil, gas and NGL sales |
$ 786 |
$ 752 |
Joint interest billings |
182 |
151 |
Marketing and midstream revenues |
163 |
188 |
Production tax credits |
46 |
110 |
Other |
35 |
19 |
Gross accounts receivable |
1,212 |
1,220 |
Allowance for doubtful accounts |
(10) |
(12) |
Net accounts receivable |
$ 1,202 |
$ 1,208 |
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3. Derivative Financial Instruments
The following table presents the derivative fair values included in the accompanying consolidated balance sheets. Devon has elected not to designate any of its derivative instruments for hedge accounting treatment.
December 31, | ||||
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Balance Sheet Caption |
2010 |
2009 | |
|
|
(In millions) | ||
Asset derivatives: |
|
|
| |
Commodity derivatives |
Other current assets |
$ 248 |
$ 172 | |
Commodity derivatives |
Other long-term assets |
1 |
— | |
Interest rate derivatives |
Other current assets |
100 |
39 | |
Interest rate derivatives |
Other long-term assets |
40 |
131 | |
Total asset derivatives |
$ 389 |
$ 342 |
Liability derivatives: |
|
|
|
Commodity derivatives |
Other current liabilities |
$ 50 |
$ 38 |
Commodity derivatives |
Other long-term liabilities |
142 |
— |
Total liability derivatives |
$ 192 |
$ 38 |
The following table presents the cash settlements and unrealized gains and losses on fair value changes included in the accompanying consolidated statements of operations associated with these derivative financial instruments.
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Statement of Operations Caption |
2010 |
2009 |
2008 |
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(In millions) | ||
Cash settlements: |
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Commodity derivatives |
Oil, gas and NGL derivatives |
$ 888 |
$ 505 |
$ (397) |
Interest rate derivatives |
Interest-rate and other financial instruments |
44 |
40 |
1 |
Total cash settlements |
932 |
545 |
(396) | |
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Unrealized gains (losses): |
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Commodity derivatives |
Oil, gas and NGL derivatives |
(77) |
(121) |
243 |
Interest rate derivatives |
Interest-rate and other financial instruments |
(30) |
66 |
104 |
Embedded option |
Interest-rate and other financial instruments |
— |
— |
109 |
Total unrealized gains (losses) |
(107) |
(55) |
456 | |
Net gain recognized on statement of operations |
$ 825 |
$ 490 |
$ 60 |
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4. Other Current Assets
The components of other current assets include the following:
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December 31, | |
|
2010 |
2009 |
|
(In millions) | |
Derivative financial instruments |
$ 348 |
$ 211 |
Income tax receivable |
270 |
53 |
Short-term investments |
145 |
— |
Inventories |
120 |
182 |
Other |
41 |
35 |
Other current assets |
$ 924 |
$ 481 |
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5. Property and Equipment
Property and equipment consists of the following:
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December 31, | |
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2010 |
2009 |
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(In millions) | |
Oil and gas properties: |
|
|
Subject to amortization |
$ 56,012 |
$ 52,352 |
Not subject to amortization |
3,434 |
4,078 |
Total |
59,446 |
56,430 |
Accumulated depreciation, depletion and amortization |
(42,676) |
(40,312) |
Net oil and gas properties |
16,770 |
16,118 |
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|
|
Other property and equipment |
4,429 |
4,045 |
Accumulated depreciation and amortization |
(1,547) |
(1,396) |
Net other property and equipment |
2,882 |
2,649 |
Property and equipment, net |
$ 19,652 |
$ 18,767 |
The following is a summary of Devon's oil and gas properties not subject to amortization as of December 31, 2010.
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Costs Incurred In | ||||
|
2010 |
2009 |
2008 |
Prior to 2008 |
Total |
|
(In millions) | ||||
Acquisition costs |
$ 1,188 |
$ 121 |
$ 1,049 |
$ 671 |
$ 3,029 |
Exploration costs |
130 |
40 |
39 |
5 |
214 |
Development costs |
159 |
1 |
9 |
— |
169 |
Capitalized interest |
22 |
— |
— |
— |
22 |
Total oil and gas properties not subject to amortization |
$ 1,499 |
$ 162 |
$ 1,097 |
$ 676 |
$ 3,434 |
Offshore Divestitures
In November 2009, Devon announced plans to reposition itself strategically as a North America onshore exploration and production company. As part of this strategic repositioning, Devon is bringing forward the value of its offshore assets by divesting them.
Closed Transactions
The following table presents Devon's offshore divestiture transactions that closed in 2010. Gross proceeds represent contract prices based upon a January 1, 2010 effective date for the Gulf of Mexico and Azerbaijan divestitures, a May 1, 2010 effective date for the China – Panyu divestiture and a September 1, 2010 effective date for the China-Exploration divestiture. After-tax proceeds represent gross proceeds adjusted for customary purchase price adjustments, selling costs and income taxes. The purchase price adjustments consist primarily of net cash flow subsequent to the effective date of the divestitures. Proved reserves in the following table are based upon estimated proved reserves as of the divestiture dates.
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Gross Proceeds |
After-Tax Proceeds |
Proved Reserves |
|
(In millions) |
(MMBoe) (Unaudited) | |
Gulf of Mexico (continuing operations) |
$ 4,145 |
$ 3,222 |
91 |
Azerbaijan (discontinued operations) |
2,000 |
1,925 |
56 |
China – Panyu (discontinued operations) |
515 |
405 |
13 |
China – Exploration (discontinued operations) |
77 |
59 |
— |
Other (discontinued operations) |
38 |
38 |
20 |
Total |
$ 6,775 |
$ 5,649 |
180 |
Proceeds from these divestitures are being used to retire debt and repurchase Devon common shares. Additionally, Devon is using divestiture proceeds to fund North America Onshore exploration and development opportunities, including a joint-venture investment in the Pike oil sands discussed below.
Under full cost accounting rules, sales or other dispositions of oil and gas properties are generally accounted for as adjustments to capitalized costs, with no recognition of gain or loss. However, if not recognizing a gain or loss on the disposition would otherwise significantly alter the relationship between a cost center's capitalized costs and proved reserves, then a gain or loss must be recognized.
The Gulf of Mexico divestitures presented above did not significantly alter such relationship for Devon's United States cost center. Therefore, Devon did not recognize a gain in connection with the Gulf of Mexico divestitures. The Azerbaijan divestiture included all of Devon's properties in its Azerbaijan cost center. As a result, Devon recognized a $1,543 million ($1,524 million after-tax) gain during 2010 in connection with the Azerbaijan divestiture. Panyu was Devon's only producing property in its China cost center. As a result, Devon recognized a $308 million ($235 million after-tax) gain in connection with the Panyu divestiture in 2010. These gains are included in "earnings from discontinued operations" in the accompanying 2010 consolidated statement of operations.
Pending Transactions
Devon has entered into agreements to sell its remaining offshore assets in Brazil and Angola and is waiting for the respective governments to approve the divestitures. The Brazil divestiture is valued at $3.2 billion, and Devon expects to record a gain upon the close of this transaction. For the Angola divestiture, Devon will receive $70 million at closing, and has the potential to receive future consideration that is contingent upon the buyer achieving certain milestones.
Deepwater Drilling Rigs
As part of its offshore operations, Devon was leasing three deepwater drilling rigs. The Seadrill West Sirius and Ocean Endeavor deepwater drilling rigs were used in Devon's Gulf of Mexico operations. The Transocean Deepwater Discovery is currently being used in Devon's operations in Brazil.
In conjunction with the deepwater Gulf of Mexico divestiture that closed in the second quarter of 2010, the buyer assumed Devon's lease and remaining commitments for the Seadrill West Sirius rig. Subsequent to closing all its Gulf of Mexico divestitures, Devon agreed to pay $31 million to the owner of the Ocean Endeavor rig to terminate the lease. The $31 million lease termination cost is included in oil and gas property and equipment in the accompanying December 31, 2010, consolidated balance sheet. The buyer of Devon's assets in Brazil will assume Devon's lease and remaining commitments for the Transocean Deepwater Discovery rig when the divestiture transaction closes.
Oil Sands Joint Venture
In conjunction with certain offshore divestitures in the second quarter of 2010, Devon formed a heavy oil joint venture to operate and develop the Pike oil sands leases in Alberta, Canada. As a result, Devon acquired a 50 percent interest in the Pike oil sands leases for $500 million. Devon will also fund $155 million of Canadian dollar capital costs on behalf of its joint-venture partner in the form of a non-interest bearing promissory note. The majority of the capital costs are expected to be paid during 2011 and 2012. See Note 6 for more information regarding the promissory note.
Reductions of Carrying Value
In the first quarter of 2009 and the fourth quarter of 2008, Devon reduced the carrying values of its oil and gas properties due to full cost ceiling limitations. These reductions are discussed in Note 15.
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6. Debt and Related Expenses
A summary of Devon's debt is as follows:
|
December 31, | |
|
2010 |
2009 |
|
(In millions) | |
Commercial paper |
$ — |
$ 1,432 |
Other debentures and notes: |
|
|
7.25% retired on June 25, 2010 |
— |
350 |
6.875% due September 30, 2011 |
1,750 |
1,750 |
5.625% due January 15, 2014 |
500 |
500 |
Non-interest bearing promissory note due June 29, 2014 |
144 |
— |
8.25% due July 1, 2018 |
125 |
125 |
6.30% due January 15, 2019 |
700 |
700 |
7.50% due September 15, 2027 |
150 |
150 |
7.875% due September 30, 2031 |
1,250 |
1,250 |
7.95% due April 15, 2032 |
1,000 |
1,000 |
Other |
9 |
10 |
Net premium on other debentures and notes |
2 |
12 |
Total debt |
5,630 |
7,279 |
Less amount classified as short-term debt |
1,811 |
1,432 |
Long-term debt |
$ 3,819 |
$ 5,847 |
Debt maturities as of December 31, 2010, excluding premiums and discounts, are as follows (in millions):
2011 |
$ 1,812 |
2012 |
9 |
2013 |
— |
2014 |
582 |
2015 |
— |
2016 and thereafter |
3,225 |
Total |
$ 5,628 |
Credit Lines
Devon has a $2,650 million syndicated, unsecured revolving line of credit (the "Senior Credit Facility"). The maturity date for $2,187 million of the Senior Credit Facility is April 7, 2013. The maturity date for the remaining $463 million is April 7, 2012. All amounts outstanding will be due and payable on the respective maturity dates unless the maturity is extended. Prior to each April 7 anniversary date, Devon has the option to extend the maturity of the Senior Credit Facility for one year, subject to the approval of the lenders. The Senior Credit Facility includes a revolving Canadian subfacility in a maximum amount of U.S. $500 million.
Amounts borrowed under the Senior Credit Facility may, at the election of Devon, bear interest at various fixed rate options for periods of up to twelve months. Such rates are generally less than the prime rate. However, Devon may elect to borrow at the prime rate. The Senior Credit Facility currently provides for an annual facility fee of $1.9 million that is payable quarterly in arrears. As of December 31, 2010, there were no borrowings under the Senior Credit Facility.
The Senior Credit Facility contains only one material financial covenant. This covenant requires Devon's ratio of total funded debt to total capitalization to be less than 65%. The credit agreement contains definitions of total funded debt and total capitalization that include adjustments to the respective amounts reported in the consolidated financial statements. Also, total capitalization is adjusted to add back noncash financial writedowns such as full cost ceiling impairments or goodwill impairments. As of December 31, 2010, Devon was in compliance with this covenant. Devon's debt-to-capitalization ratio at December 31, 2010, as calculated pursuant to the terms of the agreement, was 15.1%.
The following schedule summarizes the capacity of Devon's Senior Credit Facility by maturity date, as well as its available capacity as of December 31, 2010 (in millions).
April 7, 2012 maturity |
$ 463 |
April 7, 2013 maturity |
2,187 |
Total Senior Credit Facility |
2,650 |
Less: |
|
Outstanding Senior Credit Facility borrowings |
— |
Outstanding commercial paper borrowings |
— |
Outstanding letters of credit |
38 |
Total available capacity |
$ 2,612 |
Commercial Paper
Devon also has access to approximately $2,200 million of short-term credit under its commercial paper program. Any borrowings under the commercial paper program reduce available capacity under the Senior Credit Facility on a dollar-for-dollar basis. Commercial paper debt generally has a maturity of between one and 90 days, although it can have a maturity of up to 365 days, and bears interest at rates agreed to at the time of the borrowing. The interest rate is based on a standard index such as the Federal Funds Rate, LIBOR, or the money market rate as found on the commercial paper market.
During the first half of 2010, Devon repaid $1,432 million of commercial paper borrowings primarily with proceeds received from its Gulf of Mexico property divestitures. At December 31, 2010, Devon had no outstanding commercial paper borrowings. The average borrowing rate for Devon's $1,432 million of commercial paper borrowings at December 31, 2009 was 0.29%.
$350 Million 7.25% Senior Notes Due October 1, 2011
On June 25, 2010, Devon redeemed $350 million of 7.25% senior notes prior to their scheduled maturity of October 1, 2011, primarily with proceeds received from its Gulf of Mexico divestitures. The notes were redeemed for $384 million, which represented 100 percent of the principal amount, a make-whole premium of $28 million and $6 million of accrued and unpaid interest. On the date of redemption, these notes also had an unamortized premium of $9 million. The $28 million make-whole premium and $9 million amortization of the remaining premium are included in interest expense in the accompanying 2010 consolidated statements of operations.
Non-Interest Bearing Promissory Note Due June 29, 2014
On June 29, 2010, Devon issued a four-year $155 million Canadian dollar non-interest bearing promissory note in connection with the formation of the Pike oil sands joint venture described in Note 5. The present value of the note was $139 million on the issue date based upon an effective interest rate of 3.125%. At December 31, 2010, the note had a carrying value of $144 million, of which $62 million is presented as short-term debt and the remainder is presented as long-term debt in the accompanying consolidated balance sheet.
Other Debentures and Notes
Following are descriptions of the various other debentures and notes outstanding at December 31, 2010, as listed in the table presented at the beginning of this note.
6.875% Notes due September 30, 2011 and 7.875% Debentures due September 30, 2031
On October 3, 2001, Devon, through Devon Financing Corporation, U.L.C. ("Devon Financing"), a wholly-owned finance subsidiary, sold these notes and debentures, which are unsecured and unsubordinated obligations of Devon Financing. Devon has fully and unconditionally guaranteed on an unsecured and unsubordinated basis the obligations of Devon Financing under the debt securities. The proceeds from the issuance of these debt securities were used to fund a portion of the acquisition of Anderson Exploration.
5.625% Notes due January 15, 2014 and 6.30% Notes due January 15, 2019
On January 9, 2009, Devon sold these notes, which are unsecured and unsubordinated obligations of Devon. The net proceeds from issuance of this debt were used primarily to repay Devon's outstanding commercial paper as of December 31, 2008.
Ocean Debt
As a result of the April 25, 2003 merger with Ocean Energy, Inc., Devon assumed certain debt instruments that remain outstanding at December 31, 2010. The table below summarizes the debt assumed, the fair value of the debt at April 25, 2003, and the effective interest rate of the debt assumed after determining the fair values of the respective notes using April 25, 2003, market interest rates. The premiums resulting from fair values exceeding face values are being amortized using the effective interest method. All of the notes are general unsecured obligations of Devon.
Debt Assumed |
Fair Value of Debt Assumed |
Effective Rate of Debt Assumed |
|
(In millions) |
|
8.250% due July 2018 (principal of $125 million) |
$ 147 |
5.5% |
7.500% due September 2027 (principal of $150 million) |
$ 169 |
6.5% |
7.95% Notes due April 15, 2032
On March 25, 2002, Devon sold these notes, which are unsecured and unsubordinated obligations of Devon. The net proceeds received, after discounts and issuance costs, were $986 million and were used to retire other indebtedness.
Interest Expense
The following schedule includes the components of interest expense.
|
Year Ended December 31, | ||
|
2010 |
2009 |
2008 |
|
(In millions) | ||
Interest based on debt outstanding |
$ 408 |
$ 437 |
$ 426 |
Capitalized interest |
(76) |
(94) |
(111) |
Early retirement of debt |
19 |
— |
— |
Other |
12 |
6 |
14 |
Total |
$ 363 |
$ 349 |
$ 329 |
|
7. Asset Retirement Obligations
The schedule below summarizes changes in Devon's asset retirement obligations.
|
Year Ended December 31, | |
|
2010 |
2009 |
|
(In millions) | |
Asset retirement obligations as of beginning of year |
$ 1,513 |
$ 1,387 |
Liabilities incurred |
55 |
56 |
Liabilities settled |
(129) |
(123) |
Revision of estimated obligation |
194 |
33 |
Liabilities assumed by others |
(269) |
(30) |
Accretion expense on discounted obligation |
92 |
91 |
Foreign currency translation adjustment |
41 |
99 |
Asset retirement obligations as of end of year |
1,497 |
1,513 |
Less current portion |
74 |
95 |
Asset retirement obligations, long-term |
$ 1,423 |
$ 1,418 |
During 2010 and 2009, Devon recognized revisions to its asset retirement obligations totaling $194 million and $33 million, respectively. The primary factors causing the 2010 and 2009 increases were an overall increase in abandonment cost estimates and a decrease in the discount rate used to present value the obligations.
During 2010, Devon reduced its asset retirement obligations by $269 million primarily for those obligations that were assumed by purchasers of Devon's Gulf of Mexico oil and gas properties.
|
8. Retirement Plans
Devon has various non-contributory defined benefit pension plans, including qualified plans ("Qualified Plans") and nonqualified plans ("Supplemental Plans"). The Qualified Plans provide retirement benefits for certain U.S. and Canadian employees meeting certain age and service requirements. Benefits for the Qualified Plans are based on the employees' years of service and compensation and are funded from assets held in the plans' trusts.
The Supplemental Plans provide retirement benefits for certain employees whose benefits under the Qualified Plans are limited by income tax regulations. The Supplemental Plans' benefits are based on the employees' years of service and compensation. For certain Supplemental Plans, Devon has established trusts to fund these plans' benefit obligations. The total value of these trusts was $36 million and $39 million at December 31, 2010 and 2009, respectively, and is included in other long-term assets in the accompanying consolidated balance sheets. For the remaining Supplemental Plans for which trusts have not been established, benefits are funded from Devon's available cash and cash equivalents.
Devon also has defined benefit postretirement plans ("Postretirement Plans") that provide benefits for substantially all U.S. employees. The Postretirement Plans provide medical and, in some cases, life insurance benefits and are, depending on the type of plan, either contributory or non-contributory. Benefit obligations for the Postretirement Plans are estimated based on Devon's future cost-sharing intentions. Devon's funding policy for the Postretirement Plans is to fund the benefits as they become payable with available cash and cash equivalents.
Benefit Obligations and Funded Status
The following table presents the status of Devon's pension and other postretirement benefit plans. The benefit obligation for pension plans represents the projected benefit obligation, while the benefit obligation for the postretirement benefit plans represents the accumulated benefit obligation. The accumulated benefit obligation differs from the projected benefit obligation in that the former includes no assumption about future compensation levels. The accumulated benefit obligation for pension plans at December 31, 2010 and 2009 was $1,010 million and $873 million, respectively. Devon's benefit obligations and plan assets are measured each year as of December 31.
|
Pension Benefits |
Other Postretirement Benefits | ||
|
2010 |
2009 |
2010 |
2009 |
|
(In millions) | |||
Change in benefit obligation: |
|
|
|
|
Benefit obligation at beginning of year |
$ 980 |
$ 931 |
$ 64 |
$ 56 |
Service cost |
33 |
43 |
1 |
1 |
Interest cost |
58 |
58 |
3 |
3 |
Actuarial loss (gain) |
82 |
4 |
1 |
7 |
Curtailment (gain) loss |
— |
(26) |
— |
1 |
Plan amendments |
5 |
— |
(22) |
— |
Foreign exchange rate changes |
2 |
5 |
— |
— |
Participant contributions |
— |
— |
2 |
2 |
Benefits paid |
(36) |
(35) |
(6) |
(6) |
Benefit obligation at end of year |
1,124 |
980 |
43 |
64 |
|
|
|
|
|
Change in plan assets: |
|
|
|
|
Fair value of plan assets at beginning of year |
532 |
430 |
— |
— |
Actual return on plan assets |
69 |
80 |
— |
— |
Employer contributions |
66 |
55 |
4 |
4 |
Participant contributions |
— |
— |
2 |
2 |
Benefits paid |
(36) |
(35) |
(6) |
(6) |
Foreign exchange rate changes |
1 |
2 |
— |
— |
Fair value of plan assets at end of year |
632 |
532 |
— |
— |
|
|
|
|
|
Funded status at end of year |
$ (492) |
$ (448) |
$ (43) |
$ (64) |
|
|
|
|
|
Amounts recognized in balance sheet: |
|
|
|
|
Noncurrent assets |
$ 2 |
$ 2 |
$ — |
$ — |
Current liabilities |
(9) |
(8) |
(4) |
(5) |
Noncurrent liabilities |
(485) |
(442) |
(39) |
(59) |
Net amount |
$ (492) |
$ (448) |
$ (43) |
$ (64) |
|
|
|
|
|
Amounts recognized in accumulated other comprehensive earnings: |
|
|
|
|
Net actuarial loss (gain) |
$ 357 |
$ 334 |
$ (5) |
$ (6) |
Prior service cost (credit) |
21 |
20 |
(12) |
11 |
Total |
$ 378 |
$ 354 |
$ (17) |
$ 5 |
The plan assets for pension benefits in the table above exclude the assets held in trusts for the Supplemental Plans. However, employer contributions for pension benefits in the table above include $8 million and $9 million for 2010 and 2009, respectively, which were transferred from the trusts established for the Supplemental Plans.
Certain of Devon's pension plans have a projected benefit obligation and accumulated benefit obligation in excess of plan assets at December 31, 2010 and 2009 as presented in the table below.
|
December 31, | |
|
2010 |
2009 |
|
(In millions) | |
Projected benefit obligation |
$ 1,110 |
$ 967 |
Accumulated benefit obligation |
$ 996 |
$ 860 |
Fair value of plan assets |
$ 616 |
$ 517 |
The plan assets included in the above table exclude the Supplemental Plan trusts, which had a total value of $36 million and $39 million at December 31, 2010 and 2009, respectively.
Net Periodic Benefit Cost and Other Comprehensive Earnings
The following table presents the components of net periodic benefit cost and other comprehensive earnings for Devon's pension and other postretirement benefit plans.
|
Pension Benefits |
Other Postretirement Benefits | ||||
|
2010 |
2009 |
2008 |
2010 |
2009 |
2008 |
|
(In millions) | |||||
Net periodic benefit cost: |
|
|
|
|
|
|
Service cost |
$ 33 |
$ 43 |
$ 41 |
$ 1 |
$ 1 |
$ 1 |
Interest cost |
58 |
58 |
54 |
3 |
3 |
4 |
Expected return on plan assets |
(37) |
(35) |
(50) |
— |
— |
— |
Curtailment and settlement expense |
— |
5 |
— |
— |
1 |
— |
Recognition of net actuarial loss (gain) |
28 |
45 |
14 |
— |
(1) |
— |
Recognition of prior service cost |
3 |
3 |
2 |
1 |
2 |
2 |
Total net periodic benefit cost |
85 |
119 |
61 |
5 |
6 |
7 |
Other comprehensive earnings: |
|
|
|
|
|
|
Actuarial (gain) loss arising in current year |
49 |
(66) |
245 |
1 |
7 |
(15) |
Prior service cost (credit) arising in current year... |
5 |
— |
9 |
(22) |
— |
— |
Recognition of net actuarial (loss) gain in net periodic benefit cost |
(27) |
(45) |
(14) |
— |
1 |
— |
Recognition of prior service cost, including curtailment, in net periodic benefit cost |
(3) |
(8) |
(2) |
(1) |
(2) |
(2) |
Total other comprehensive earnings (loss) |
24 |
(119) |
238 |
(22) |
6 |
(17) |
Total recognized |
$ 109 |
$ — |
$ 299 |
$ (17) |
$ 12 |
$ (10) |
The following table presents the estimated net actuarial loss and prior service cost for the pension and other postretirement plans that will be amortized from accumulated other comprehensive earnings into net periodic benefit cost during 2011.
|
Pension Benefits |
Other Postretirement Benefits |
|
(In millions) | |
Net actuarial loss |
$ 32 |
$ — |
Prior service cost (credit) |
3 |
(2) |
Total |
$ 35 |
$ (2) |
Assumptions
The following table presents the weighted average actuarial assumptions that were used to determine benefit obligations and net periodic benefit costs.
|
Pension Benefits |
Other Postretirement Benefits | ||||
|
2010 |
2009 |
2008 |
2010 |
2009 |
2008 |
|
| |||||
Assumptions to determine benefit obligations: |
|
|
|
|
|
|
Discount rate |
5.50% |
6.00% |
6.00% |
4.90% |
5.70% |
6.00% |
Rate of compensation increase |
6.94% |
6.95% |
7.00% |
N/A |
N/A |
N/A |
Assumptions to determine net periodic benefit cost: |
|
|
|
|
|
|
Discount rate |
6.00% |
6.00% |
6.18% |
5.70% |
6.00% |
6.00% |
Expected return on plan assets |
6.94% |
7.18% |
8.40% |
N/A |
N/A |
N/A |
Rate of compensation increase |
6.94% |
6.95% |
7.00% |
N/A |
N/A |
N/A |
Discount rate – Future pension and postretirement obligations are discounted at the end of each year based on the rate at which obligations could be effectively settled, considering the timing of estimated future cash flows related to the plans. This rate is based on high-quality bond yields, after allowing for call and default risk. High quality corporate bond yield indices are considered when selecting the discount rate.
Rate of compensation increase – For measurement of the 2010 benefit obligation for the pension plans, the 6.94% compensation increase in the table above represents the assumed increase through 2011. The rate was assumed to decrease to 5% in the year 2012 and remain at that level thereafter.
Expected return on plan assets – The expected rate of return on plan assets was determined by evaluating input from external consultants and economists as well as long-term inflation assumptions. Devon expects the long-term asset allocation to approximate the targeted allocation. Therefore, the expected long-term rate of return on plan assets is based on the target allocation of investment types in such assets. See plan assets discussion below for more information on Devon's target allocations.
Other assumptions – For measurement of the 2010 benefit obligation for the other postretirement medical plans, an 8.3% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2011. The rate was assumed to decrease annually to an ultimate rate of 5% in the year 2029 and remain at that level thereafter. Assumed health care cost-trend rates affect the amounts reported for retiree health care costs. A one-percentage-point change in the assumed health care cost-trend rates would have the following effects on the December 31, 2010 other postretirement benefits obligation and the 2011 service and interest cost components of net periodic benefit cost.
|
One Percent Increase |
One Percent Decrease |
|
(In millions) | |
Effect on benefit obligation |
$ 2 |
$ (2) |
Effect on service and interest costs |
$ — |
$ — |
Pension Plan Assets
Devon's overall investment objective for its pension plans' assets is to achieve long-term growth of invested capital and income to ensure benefit payments can be funded when required. To assist in achieving this objective, Devon has established certain investment strategies, including target allocation percentages and permitted and prohibited investments, designed to mitigate risks inherent with investing.
The vast majority of Devon's plan assets are invested in diversified asset types to generate long-term growth and income. The remaining plan assets, generally less than 5%, are invested in assets that can be used for near-term benefit payments. Derivatives or other speculative investments considered high risk are generally prohibited.
At the end of 2010 and 2009, Devon's target allocations for plan assets were 47.5% for equity securities, 40% for fixed-income securities and 12.5% for other investment types. The fair values of Devon's pension assets at December 31, 2010 and 2009 are presented by asset class in the following tables.
|
As of December 31, 2010 | ||||
|
|
|
Fair Value Measurements Using: | ||
|
Actual Allocation |
Total |
Level 1 Inputs |
Level 2 Inputs |
Level 3 Inputs |
|
($ In millions) | ||||
Equity securities: |
|
|
|
|
|
United States large cap |
22.3% |
$ 141 |
$ — |
$ 141 |
$ — |
United States small cap |
14.1% |
89 |
89 |
— |
— |
International large cap |
14.4% |
91 |
50 |
41 |
— |
Total equity securities |
50.8% |
321 |
139 |
182 |
— |
Fixed-income securities: |
|
|
|
|
|
Corporate bonds |
22.0% |
139 |
139 |
— |
— |
United States Treasury obligations |
10.9% |
69 |
69 |
— |
— |
Other bonds |
4.6% |
29 |
29 |
— |
— |
Total fixed-income securities |
37.5% |
237 |
237 |
— |
— |
Other securities: |
|
|
|
|
|
Short-term investment funds |
2.5% |
16 |
— |
16 |
— |
Hedge funds |
9.2% |
58 |
— |
— |
58 |
Total other securities |
11.7% |
74 |
— |
16 |
58 |
Total investments |
100.0% |
$ 632 |
$ 376 |
$ 198 |
$ 58 |
|
As of December 31, 2009 | ||||
|
|
|
Fair Value Measurements Using: | ||
|
Actual Allocation |
Total |
Level 1 Inputs |
Level 2 Inputs |
Level 3 Inputs |
|
(In millions) | ||||
Equity securities: |
|
|
|
|
|
United States large cap |
18.8% |
$ 100 |
$ — |
$ 100 |
$ — |
United States small cap |
15.2% |
81 |
81 |
— |
— |
International large cap |
15.2% |
81 |
44 |
37 |
— |
Total equity securities |
49.2% |
262 |
125 |
137 |
— |
Fixed-income securities: |
|
|
|
|
|
Corporate bonds |
25.1% |
133 |
133 |
— |
— |
United States Treasury obligations |
9.8% |
52 |
52 |
— |
— |
Other bonds |
3.9% |
21 |
21 |
— |
— |
Total fixed-income securities |
38.8% |
206 |
206 |
— |
— |
Other securities: |
|
|
|
|
|
Short-term investment funds |
2.4% |
13 |
— |
13 |
— |
Hedge funds |
9.6% |
51 |
— |
— |
51 |
Total other securities |
12.0% |
64 |
— |
13 |
51 |
Total investments |
100.0% |
$ 532 |
$ 331 |
$ 150 |
$ 51 |
The following methods and assumptions were used to estimate the fair values of the assets in the tables above.
Equity securities – Devon's equity securities consist of investments in United States large and small capitalization companies and international large capitalization companies. These equity securities are actively traded securities that can be redeemed upon demand. The fair values of these Level 1 securities are based upon quoted market prices.
Devon's equity securities also include commingled funds that invest in large capitalization companies. These equity securities can be redeemed on demand but are not actively traded. The fair values of these Level 2 securities are based upon the net asset values provided by the investment managers.
Fixed-income securities – Devon's fixed-income securities consist of bonds issued by investment-grade companies from diverse industries, United States Treasury obligations and asset-backed securities. Devon's fixed-income securities are actively traded securities that can be redeemed upon demand. The fair values of these Level 1 securities are based upon quoted market prices.
Other securities – Devon's other securities include commingled, short-term investment funds. These securities can be redeemed on demand but are not actively traded. The fair values of these Level 2 securities are based upon the net asset values provided by investment managers.
Devon's other securities also include a hedge fund of funds that invests both long and short using a variety of investment strategies. Management of the hedge fund has the ability to shift investments from value to growth strategies, from small to large capitalization stocks, and from a net long position to a net short position. Devon's hedge fund is not actively traded and Devon is subject to redemption restrictions with regards to this investment. The fair value of this Level 3 investment represents the fair value as determined by the hedge fund manager.
Included below is a summary of the changes in Devon's Level 3 plan assets.
|
Hedge Funds |
|
(In millions) |
December 31, 2008 |
$ — |
Purchases |
51 |
December 31, 2009 |
51 |
Purchases |
3 |
Investment returns |
4 |
December 31, 2010 |
$ 58 |
Expected Cash Flows
The following table presents expected cash flow information for Devon's pension and other postretirement benefit plans.
|
Pension Benefits |
Other Postretirement Benefits |
|
(In millions) | |
Devon's 2011 contributions |
$ 93 |
$ 4 |
Benefit payments: |
|
|
2011 |
$ 42 |
$ 4 |
2012 |
$ 45 |
$ 4 |
2013 |
$ 49 |
$ 4 |
2014 |
$ 52 |
$ 4 |
2015 |
$ 54 |
$ 4 |
2016 to 2020 |
$ 328 |
$ 21 |
Expected contributions included in the table above include amounts related to Devon's Qualified Plans, Supplemental Plans and Postretirement Plans. Of the benefits expected to be paid in 2011, $9 million of pension benefits is expected to be funded from the trusts established for the Supplemental Plans and all $4 million of other postretirement benefits is expected to be funded from Devon's available cash and cash equivalents. Expected employer contributions and benefit payments for other postretirement benefits are presented net of employee contributions.
Other Benefit Plans
Devon's 401(k) Plan covers all its employees in the United States. At its discretion, Devon may match a certain percentage of the employees' contributions to the plan. The matching percentage is determined annually by the Board of Directors.
Devon also has an enhanced defined contribution structure related to its 401(k) Plan. Participants who elected to participate in this enhanced defined contribution structure when it was established, as well as all employees hired after the enhanced defined contribution structure was established, receive a discretionary match of a percentage of their contributions to the 401(k) Plan. The participants also receive additional, nondiscretionary contributions by Devon calculated as a percentage of annual compensation. The percentage will vary based on the employees' years of service.
Devon has defined contribution pension plans for its Canadian employees. Devon makes a contribution to each employee that is based upon the employee's base compensation and classification. Such contributions are subject to maximum amounts allowed under the Income Tax Act (Canada). Devon also has a savings plan for its Canadian employees. Under the savings plan, Devon contributes a base percentage amount to all employees and the employee may elect to contribute an additional percentage amount (up to a maximum amount) which is matched by additional Devon contributions.
The following table presents Devon's expense related to these defined contribution plans.
|
Year Ended December 31, | ||
|
2010 |
2009 |
2008 |
|
(In millions) | ||
401(k) plan |
$ 18 |
$ 20 |
$ 21 |
Enhanced contribution plan |
14 |
14 |
12 |
Canadian pension and savings plans |
17 |
15 |
16 |
Total expense |
$ 49 |
$ 49 |
$ 49 |
|
9. Stockholders' Equity
The authorized capital stock of Devon consists of 1 billion shares of common stock, par value $0.10 per share, and 4.5 million shares of preferred stock, par value $1.00 per share. The preferred stock may be issued in one or more series, and the terms and rights of such stock will be determined by the Board of Directors.
Devon's Board of Directors has designated 2.9 million shares of the preferred stock as Series A Junior Participating Preferred Stock (the "Series A Junior Preferred Stock"). At December 31, 2010, there were no shares of Series A Junior Preferred Stock issued or outstanding. The Series A Junior Preferred Stock is entitled to receive cumulative quarterly dividends per share equal to the greater of $1.00 or 100 times the aggregate per share amount of all dividends (other than stock dividends) declared on common stock since the immediately preceding quarterly dividend payment date or, with respect to the first payment date, since the first issuance of Series A Junior Preferred Stock. Holders of the Series A Junior Preferred Stock are entitled to 100 votes per share on all matters submitted to a vote of the stockholders. The Corporation, at its option, may redeem shares of the Series A Junior Participating Preferred Stock in whole at any time and in part from time to time, at a redemption price equal to 100 times the current per share market price of the Common Stock on the date of the mailing of the notice of redemption. The Series A Junior Preferred Stock ranks prior to the common stock but junior to all other classes of Preferred Stock.
Stock Repurchases
During 2010, Devon's Board of Directors announced a share repurchase program that authorizes the repurchase of up to $3,500 million of its common shares. This program, which expires December 31, 2011, was created as a result of the success experienced from the offshore divestiture program described in Note 5.
During 2008, Devon's Board of Directors approved an ongoing, annual stock repurchase program to minimize dilution resulting from restricted stock issued to, and options exercised by, employees. Also, Devon's Board of Directors approved a program in 2007 to repurchase up to 50 million shares. This program was created as a potential use of the proceeds received from Devon's West African property divestitures. Both of these plans expired on December 31, 2009.
The following table summarizes Devon's repurchases under approved plans (amounts and shares in millions).
|
2010 |
2008 | ||||
Repurchase Program |
Amount |
Shares |
Per Share |
Amount |
Shares |
Per Share |
2010 program |
$ 1,201 |
18.3 |
$ 65.58 |
$ — |
— |
$ — |
Annual program |
— |
— |
— |
178 |
2.0 |
$ 87.83 |
2007 program |
— |
— |
— |
487 |
4.5 |
$ 109.25 |
Totals |
$ 1,201 |
18.3 |
$ 65.58 |
$ 665 |
6.5 |
$ 102.56 |
Preferred Stock Redemption
On June 20, 2008, Devon redeemed all 1.5 million outstanding shares of its 6.49% Series A cumulative preferred stock. Each share of preferred stock was redeemed for cash at a redemption price of $100 per share, plus accrued and unpaid dividends up to the redemption date.
Dividends
Devon paid common stock dividends of $281 million (or $0.64 per share) in 2010 and $284 million (or $0.64 per share) in both 2009 and 2008, respectively. Devon paid dividends of $5 million in 2008 to preferred stockholders.
|
10. Commitments and Contingencies
Devon is party to various legal actions arising in the normal course of business. Matters that are probable of unfavorable outcome to Devon and which can be reasonably estimated are accrued. Such accruals are based on information known about the matters, Devon's estimates of the outcomes of such matters and its experience in contesting, litigating and settling similar matters. None of the actions are believed by management to involve future amounts that would be material to Devon's financial position or results of operations after consideration of recorded accruals although actual amounts could differ materially from management's estimate.
Environmental Matters
Devon is subject to certain laws and regulations relating to environmental remediation activities associated with past operations, such as the Comprehensive Environmental Response, Compensation, and Liability Act and similar state statutes. In response to liabilities associated with these activities, loss accruals primarily consist of estimated uninsured costs associated with remediation. Devon's monetary exposure for environmental matters is not expected to be material.
Royalty Matters
Numerous natural gas producers and related parties, including Devon, have been named in various lawsuits alleging violation of the federal False Claims Act. The suits allege that the producers and related parties used below-market prices, improper deductions, improper measurement techniques and transactions with affiliates, which resulted in underpayment of royalties in connection with natural gas and NGLs produced and sold from federal and Indian owned or controlled lands. Devon does not currently believe that it is subject to material exposure with respect to such royalty matters.
Other Matters
Devon is involved in other various routine legal proceedings incidental to its business. However, to Devon's knowledge, there were no other material pending legal proceedings to which Devon is a party or to which any of its property is subject.
Commitments
The following is a schedule by year of purchase obligations, future minimum payments for drilling and facility obligations, firm transportation agreements and leases that have initial or remaining noncancelable lease terms in excess of one year as of December 31, 2010. The schedule includes separate amounts for Devon's continuing and discontinued operations.
Year Ending December 31, |
Purchase Obligations |
Drilling and Facility Obligations |
Firm Transportation Agreements |
Office and Equipment Leases |
FPSO Lease |
|
(In millions) | ||||
Continuing operations: |
|
|
|
|
|
2011 |
$ 551 |
$ 747 |
$ 282 |
$ 58 |
$ — |
2012 |
708 |
280 |
254 |
56 |
— |
2013 |
763 |
130 |
233 |
48 |
— |
2014 |
784 |
6 |
218 |
39 |
— |
2015 |
784 |
— |
190 |
38 |
— |
Thereafter |
4,120 |
— |
557 |
250 |
— |
Total |
7,710 |
1,163 |
1,734 |
489 |
— |
Discontinued operations: |
|
|
|
|
|
2011 |
— |
314 |
— |
9 |
29 |
2012 |
— |
171 |
— |
— |
29 |
2013 |
— |
110 |
— |
— |
29 |
2014 |
— |
— |
— |
— |
15 |
Total |
— |
595 |
— |
9 |
102 |
Total operations |
$ 7,710 |
$ 1,758 |
$ 1,734 |
$ 498 |
$ 102 |
Devon has certain purchase obligations related to its thermal heavy oil projects in Canada to purchase condensate at market prices. Devon entered into these agreements because the condensate is an integral part of the thermal heavy oil production process and any disruption in Devon's ability to obtain condensate could negatively affect its ability to produce and transport heavy oil at these locations. Devon's total obligation related to condensate purchases expires in 2021. The value of these purchase obligations presented in the table above is based on the contractual volumes and Devon's internal estimate of future condensate market prices.
Devon has certain drilling and facility obligations under contractual agreements with third-party service providers to procure drilling rigs and other related services for developmental and exploratory drilling and facilities construction. Included in the discontinued operations obligations are amounts related to a long-term contract for a deepwater drilling rig being used in Brazil. Devon's lease and remaining commitments for this rig will be assumed by the buyer of its assets in Brazil when the associated divestiture transaction closes.
Devon has certain firm transportation agreements that represent "ship or pay" arrangements whereby Devon has committed to ship certain volumes of oil, gas and NGLs for a fixed transportation fee. Devon has entered into these agreements to aid the movement of its production to market. Devon expects to have sufficient production to utilize these transportation services.
Devon leases certain office space and equipment under operating lease arrangements. Total rental expense included in general and administrative expenses under operating leases, net of sub-lease income, was $57 million, $56 million and $44 million in 2010, 2009 and 2008, respectively.
Devon has a floating, production, storage and offloading facility ("FPSO") that is being used in the Polvo project offshore Brazil and is being leased under operating lease arrangements. This lease will be assumed by the buyer when the associated divestiture transaction closes. However, the amounts in the table above reflect Devon's full commitments under the lease. Total rental expense included in lease operating expenses for Devon's FPSO's was $25 million, $36 million and $25 million in 2010, 2009 and 2008, respectively.
|
Certain of Devon's assets and liabilities are reported at fair value in the accompanying consolidated balance sheets. Such assets and liabilities include amounts for both financial and nonfinancial instruments. The following tables provide carrying value and fair value measurement information for Devon's financial assets and liabilities.
The carrying values of cash and cash equivalents, accounts receivable and accounts payable (including income taxes payable and other accrued expenses) included in the accompanying consolidated balance sheets approximated fair value at December 31, 2010 and 2009. These assets and liabilities are not presented in the following tables.
Information regarding the fair values of Devon's pension plan assets is provided in Note 8.
|
|
|
Fair Value Measurements Using: | ||
|
Carrying Amount |
Total Fair Value |
Level 1 Inputs |
Level 2 Inputs |
Level 3 Inputs |
|
(In millions) | ||||
December 31, 2010 assets (liabilities): |
|
|
|
|
|
Commodity asset derivatives |
$ 249 |
$ 249 |
$ — |
$ 249 |
$ — |
Commodity liability derivatives |
$ (192) |
$ (192) |
$ — |
$ (192) |
$ — |
Interest rate derivatives |
$ 140 |
$ 140 |
$ — |
$ 140 |
$ — |
Debt |
$ (5,630) |
$ (6,629) |
$ — |
$ (6,485) |
$ (144) |
Long-term investments |
$ 94 |
$ 94 |
$ — |
$ — |
$ 94 |
Short-term investments |
$ 145 |
$ 145 |
$ 145 |
$ — |
$ — |
December 31, 2009 assets (liabilities): |
|
|
|
|
|
Commodity asset derivatives |
$ 172 |
$ 172 |
$ — |
$ 172 |
$ — |
Commodity liability derivatives |
$ (38) |
$ (38) |
$ — |
$ (38) |
$ — |
Interest rate derivatives |
$ 170 |
$ 170 |
$ — |
$ 170 |
$ — |
Debt |
$ (7,279) |
$ (8,214) |
$ (1,432) |
$ (6,782) |
$ — |
Long-term investments |
$ 115 |
$ 115 |
$ — |
$ — |
$ 115 |
The following methods and assumptions were used to estimate the fair values of the assets and liabilities in the tables above.
Level 1 Fair Value Measurements
Debt — The fair value of Devon's variable-rate commercial paper borrowings is the carrying value.
Short-term investments — Devon's short-term investments consist entirely of United States Treasury bills with maturities over 90 days.
Level 2 Fair Value Measurements
Commodity derivatives — The fair values of commodity derivatives are estimated using internal discounted cash flow calculations based upon forward commodity price curves, quotes obtained from brokers for contracts with similar terms or quotes obtained from counterparties to the agreements. The most significant input to the cash flow calculations is Devon's estimate of future commodity prices. Devon bases its estimate of future prices upon published forward commodity price curves such as the Inside FERC Henry Hub forward curve for gas instruments and the NYMEX West Texas Intermediate forward curve for oil instruments. Another key input to the cash flow calculations is Devon's estimate of volatility for these forward curves, which is based primarily upon implied volatility. The resulting estimated future cash inflows or outflows over the lives of the contracts are discounted primarily using United States Treasury bill rates. These pricing and discounting inputs are sensitive to the period of the contract, as well as changes in forward prices and regional price differentials.
Interest rate derivatives — The fair values of the interest rate derivatives are estimated using internal discounted cash flow calculations based upon forward interest-rate yield curves or quotes obtained from counterparties to the agreements. The most significant input to Devon's cash flow calculations is its estimate of future interest rate yields. Devon bases its estimate of future yields upon its own internal model that utilizes forward curves such as the LIBOR or the Federal Funds Rate provided by third parties. The resulting estimated future cash inflows or outflows over the lives of the contracts are discounted using the LIBOR and money market futures rate. These yield and discounting inputs are sensitive to the period of the contract, as well as changes in forward interest rate yields.
Debt — Devon's Level 2 fixed-rate debt instruments do not actively trade in an established market. The fair values of this debt are estimated by discounting the principal and interest payments at rates available for debt with similar terms and maturity.
Level 3 Fair Value Measurements
Debt — Devon's Level 3 debt consisted of the non-interest bearing promissory note discussed in Note 5. Due to the lack of an active market for Devon's promissory note, quoted marked prices for this note were not available. Therefore, Devon used valuation techniques that rely on unobservable inputs to estimate the fair value of its promissory note. The fair value of this debt is estimated using internal discounted cash flow calculations based upon estimated future payment schedules and a 3.125% interest rate. As a result of using these inputs, Devon concluded the estimated fair value of its non-interest bearing promissory note approximated the carrying value as of December 31, 2010.
Long-term investments — Devon's long-term investments presented in the tables above consisted entirely of auction rate securities. Due to the auction failures discussed in Note 1 and the lack of an active market for Devon's auction rate securities, quoted market prices for these securities were not available as of December 31, 2010 and December 31, 2009. Therefore, Devon used valuation techniques that rely on unobservable inputs to estimate the fair values of its long-term auction rate securities. These inputs were based on the AAA credit rating of the securities, the probability of full repayment of the securities considering the United States government guarantees of substantially all of the underlying student loans, the collection of all accrued interest to date and continued receipts of principal at par. As a result of using these inputs, Devon concluded the estimated fair values of its long-term auction rate securities approximated the par values as of December 31, 2010 and December 31, 2009. At this time, Devon does not believe the values of its long-term securities are impaired.
Included below is a summary of the changes in Devon's Level 3 fair value measurements.
|
Debt |
Long-Term Investments |
|
(In millions) | |
December 31, 2008 |
$ — |
$ 122 |
Redemptions of principal |
— |
(7) |
December 31, 2009 |
— |
115 |
Issuance of promissory note |
(139) |
— |
Foreign exchange translation adjustment |
(9) |
— |
Accretion of promissory note |
(3) |
— |
Redemptions of principal |
7 |
(21) |
December 31, 2010 |
$ (144) |
$ 94 |
|
13. Restructuring Costs
Employee Severance
In the fourth quarter of 2009, Devon recognized $153 million of estimated employee severance costs associated with the planned divestiture of its offshore assets that was announced in November 2009. This amount was based on estimates of the number of employees that would ultimately be impacted by the divestitures and included amounts related to cash severance costs and accelerated vesting of share-based grants. Of the $153 million total, $105 million related to Devon's U.S. Offshore operations and the remainder related to its International discontinued operations.
As discussed in Note 5, during 2010 Devon divested all of its U.S. Offshore assets and a significant part of its International assets. As a result of these divestitures and associated employee terminations, Devon decreased its estimate of employee severance costs in 2010 by $31 million. More offshore employees than previously estimated received comparable positions with either the purchaser of the properties or in Devon's U.S. Onshore operations, and this caused the $31 million decrease to the severance estimate. This decrease includes $27 million related to Devon's U.S. Offshore operations and $4 million related to its International discontinued operations.
Lease Obligations
As a result of the divestitures discussed above, Devon ceased using certain office space that was subject to non-cancellable operating lease arrangements. Consequently, in 2010, Devon recognized $70 million of restructuring costs that represent the present value of its future obligations under the leases, net of anticipated sublease income. Devon's estimate of lease obligations was based upon certain key estimates that could change over the term of the leases. These estimates include the estimated sublease income that Devon may receive over the term of the leases, as well as the amount of variable operating costs that Devon will be required to pay under the leases.
Asset Impairments
In 2010, Devon recognized $11 million of asset impairment charges for leasehold improvements and furniture associated with the office space it ceased using.
Financial Statement Presentation
The schedule below summarizes the components of restructuring costs in the accompanying consolidated statements of operations.
|
Year Ended December 31, 2010 |
Year Ended December 31, 2009 | ||||
|
Continuing Operations |
Discontinued Operations |
Total |
Continuing Operations |
Discontinued Operations |
Total |
|
(In millions) | |||||
Cash severance |
$ (17) |
$ 1 |
$ (16) |
$ 66 |
$ 24 |
$ 90 |
Share-based awards |
(10) |
(5) |
(15) |
39 |
24 |
63 |
Lease obligations |
70 |
— |
70 |
— |
— |
— |
Asset impairments |
11 |
— |
11 |
— |
— |
— |
Other |
3 |
— |
3 |
— |
— |
— |
Restructuring costs |
$ 57 |
$ (4) |
$ 53 |
$ 105 |
$ 48 |
$ 153 |
Amounts related to cash severance and lease obligations are accrued for in other current liabilities and other long-term liabilities in the accompanying consolidated balance sheets, while amounts related to accelerated share-based awards are recorded as a reduction to Devon's additional paid-in capital in the accompanying consolidated balance sheets. The schedule below summarizes activity and liability balances associated with Devon's restructuring liabilities.
|
Other Current Liabilities |
Other Long-Term Liabilities | ||||
|
Continuing Operations |
Discontinued Operations |
Total |
Continuing Operations |
Discontinued Operations |
Total |
|
(In millions) | |||||
Balance as of December 31, 2008 |
$ — |
$ — |
$ — |
$ — |
$ — |
$ — |
Cash severance accrual |
61 |
23 |
84 |
— |
— |
— |
Balance as of December 31, 2009 |
61 |
23 |
84 |
— |
— |
— |
Lease obligations incurred |
17 |
— |
17 |
50 |
— |
50 |
Cash severance paid |
(30) |
(8) |
(38) |
— |
— |
— |
Cash severance revision |
(17) |
1 |
(16) |
— |
— |
— |
Other |
— |
— |
— |
1 |
— |
1 |
Balance as of December 31, 2010 |
$ 31 |
$ 16 |
$ 47 |
$ 51 |
$ — |
$ 51 |
|
14. Interest-Rate and Other Financial Instruments
The following table presents the changes in fair value and cash settlements related to Devon's interest-rate and other financial instruments presented in the accompanying consolidated statements of operations.
|
Year Ended December 31, | ||
|
2010 |
2009 |
2008 |
|
(In millions) | ||
(Gains) and losses from: |
|
|
|
Interest rate swaps – settlements (See Note 3) |
$ (44) |
$ (40) |
$ (1) |
Interest rate swaps – fair value changes (See Note 3) |
30 |
(66) |
(104) |
Chevron common stock |
— |
— |
363 |
Option embedded in exchangeable debentures |
— |
— |
(109) |
Total |
$ (14) |
$ (106) |
$ 149 |
Until October 31, 2008, Devon owned 14.2 million shares of Chevron common stock. These shares were held in connection with debt owed by Devon that contained an exchange option. The exchange option allowed the debt holders, prior to the debt's maturity of August 15, 2008, to exchange the debt for shares of Chevron common stock owned by Devon. However, Devon had the option to settle any exchanges with cash equal to the market value of Chevron common stock at the time of the exchange. Devon settled remaining exchange requests during 2008 by paying $1.0 billion. On October 31, 2008, Devon transferred its 14.2 million shares of Chevron common stock to Chevron. In exchange, Devon received Chevron's interest in the Drunkard's Wash coalbed natural gas field in east-central Utah and $280 million in cash.
|
15. Reduction of Carrying Value of Oil and Gas Properties
During 2009 and 2008, Devon reduced the carrying values of certain of its oil and gas properties due to full cost ceiling limitations. A summary of these reductions and additional discussion is provided below.
|
Year Ended December 31, | |||
|
2009 |
2008 | ||
|
Gross |
After Taxes |
Gross |
After Taxes |
|
(In millions) | |||
|
|
|
|
|
United States |
$ 6,408 |
$ 4,085 |
$ 6,538 |
$ 4,168 |
Canada |
— |
— |
3,353 |
2,488 |
Total |
$ 6,408 |
$ 4,085 |
$ 9,891 |
$ 6,656 |
The 2009 reduction was recognized in the first quarter and the 2008 reductions were recognized in the fourth quarter. The reductions resulted from significant decreases in each country's full cost ceiling compared to the immediately preceding quarter. The lower United States ceiling value in the first quarter of 2009 largely resulted from the effects of declining natural gas prices subsequent to December 31, 2008. The lower ceiling values in the fourth quarter of 2008 largely resulted from the effects of sharp declines in oil, gas and NGL prices compared to September 30, 2008.
|
The components of other, net in the accompanying consolidated statements of operations include the following:
|
Year Ended December 31, | ||
|
2010 |
2009 |
2008 |
|
(In millions) | ||
Interest and dividend income |
$ (13) |
$ (8) |
$ (54) |
Deep water royalties |
— |
(84) |
— |
Hurricane insurance proceeds |
— |
— |
(162) |
Other |
(32) |
24 |
(1) |
Total |
$ (45) |
$ (68) |
$ (217) |
Deep water Gulf of Mexico leases issued in certain years by the Minerals Management Service (the "MMS") contained price thresholds, such that if the market prices for oil or gas exceeded the thresholds for a given year, royalty relief would not be granted for that year. In October 2007, a federal district court ruled in favor of a plaintiff who had challenged the legality of including price thresholds in deep water leases. This judgment was later appealed to the United States Supreme Court, which, in October 2009, declined to review the appellate court's ruling. The Supreme Court's decision ended the MMS's judicial course to enforce the price thresholds. At the time of the Supreme Court's decision, Devon had $84 million accrued for potential royalties on various deep water leases. Based upon the Supreme Court's decision, Devon reduced to zero the $84 million loss contingency accrual in 2009.
In 2008, Devon recognized $162 million of excess insurance recoveries for damages suffered in 2005 related to hurricanes that struck the Gulf of Mexico. The excess recoveries resulted from business interruption claims on policies that were in effect when the 2005 hurricanes occurred.
|
17. Income Taxes
Income Tax Expense (Benefit)
The earnings (loss) from continuing operations before income taxes and the components of income tax expense (benefit) were as follows:
|
Year Ended December 31, | ||
|
2010 |
2009 |
2008 |
|
(In millions) | ||
Earnings (loss) from continuing operations before income taxes: |
|
|
|
U.S |
$ 2,943 |
$ (4,961) |
$ (2,190) |
Canada |
625 |
435 |
(1,970) |
Total |
$ 3,568 |
$ (4,526) |
$ (4,160) |
Current income tax expense: |
|
|
|
U.S. federal |
$ 244 |
$ 45 |
$ 258 |
Various states |
16 |
18 |
31 |
Canada and various provinces |
256 |
178 |
152 |
Total current tax expense |
516 |
241 |
441 |
Deferred income tax expense (benefit): |
|
|
|
U.S. federal |
781 |
(1,846) |
(875) |
Various states |
21 |
(111) |
(65) |
Canada and various provinces |
(83) |
(57) |
(622) |
Total deferred tax expense (benefit) |
719 |
(2,014) |
(1,562) |
Total income tax expense (benefit) |
$ 1,235 |
$ (1,773) |
$ (1,121) |
The taxes on the results of discontinued operations presented in the accompanying consolidated statements of operations were all related to Devon's international operations outside North America.
Total income tax expense (benefit) differed from the amounts computed by applying the U.S. federal income tax rate to earnings (loss) from continuing operations before income taxes as a result of the following:
|
Year Ended December 31, | ||
|
2010 |
2009 |
2008 |
|
(In millions) | ||
Expected income tax expense (benefit) based on U.S. statutory tax rate of 35% |
$ 1,249 |
$ (1,584) |
$ (1,456) |
Repatriations and assumed repatriations |
144 |
55 |
312 |
State income taxes |
31 |
(99) |
(29) |
Taxation on Canadian operations |
(60) |
(31) |
227 |
Other |
(129) |
(114) |
(175) |
Total income tax expense (benefit) |
$ 1,235 |
$ (1,773) |
$ (1,121) |
During 2010 and 2009, pursuant to the completed and planned divestitures of its International assets located outside North America, a portion of Devon's foreign earnings were no longer deemed to be permanently reinvested. Accordingly, Devon recognized deferred tax expense of $144 million and $55 million during 2010 and 2009, respectively, related to assumed repatriations of earnings from certain of its foreign subsidiaries.
During 2008, Devon recognized $312 million of additional income tax expense that resulted from two related factors associated with its foreign operations. First, during 2008, Devon repatriated $2.6 billion from certain foreign subsidiaries to the United States. Second, Devon made certain tax policy election changes in the second quarter of 2008 to minimize the taxes it otherwise would pay for the cash repatriations, as well as the taxable gains associated with the sales of assets in West Africa. As a result of the repatriation and tax policy election changes, Devon recognized $295 million of additional current tax expense and $17 million of additional deferred tax expense.
Deferred Tax Assets and Liabilities
The tax effects of temporary differences that gave rise to significant portions of the deferred tax assets and liabilities are presented below:
|
December 31, | |
|
2010 |
2009 |
|
(In millions) | |
Deferred tax assets: |
|
|
Net operating loss carryforwards |
$ 159 |
$ 11 |
Asset retirement obligations |
494 |
474 |
Pension benefit obligations |
133 |
130 |
Other |
171 |
133 |
Total deferred tax assets |
957 |
748 |
Deferred tax liabilities: |
|
|
Property and equipment, principally due to nontaxable business combinations, differences in depreciation, and the expensing of intangible drilling costs for tax purposes |
(3,130) |
(2,315) |
Fair value of financial instruments |
(70) |
(108) |
Long-term debt |
(198) |
(162) |
Taxes on unremitted foreign earnings ( |
(211) |
(55) |
Other |
(20) |
(7) |
Total deferred tax liabilities |
(3,629) |
(2,647) |
Net deferred tax liability |
$ (2,672) |
$ (1,899) |
As shown in the above table, Devon has recognized $957 million of deferred tax assets as of December 31, 2010. Included in total deferred tax assets is $159 million related to various carryforwards available to offset future income taxes. The carryforwards consist of $538 million of Canadian net operating loss carryforwards, which expire between 2023 and 2030, and $161 million of state net operating loss carryforwards, which expire primarily between 2011 and 2024. The tax benefits of carryforwards are recorded as an asset to the extent that management assesses the utilization of such carryforwards to be "more likely than not." When the future utilization of some portion of the carryforwards is determined not to be "more likely than not," a valuation allowance is provided to reduce the recorded tax benefits from such assets.
Devon expects the tax benefits from the Canadian net operating loss carryforward to be utilized between 2011 and 2016. Also, Devon expects the tax benefits from the state net operating loss carryforwards to be utilized between 2012 and 2015. Such expectations are based upon current estimates of taxable income during these periods, considering limitations on the annual utilization of these benefits as set forth by tax regulations. Significant changes in such estimates caused by variables such as future oil and gas prices or capital expenditures could alter the timing of the eventual utilization of such carryforwards. There can be no assurance that Devon will generate any specific level of continuing taxable earnings. However, management believes that Devon's future taxable income will more likely than not be sufficient to utilize substantially all its tax carryforwards prior to their expiration.
As of December 31, 2010, approximately $4.3 billion of Devon's unremitted earnings from its foreign subsidiaries were deemed to be permanently reinvested. As a result, Devon has not recognized a deferred tax liability for United States income taxes associated with such earnings. If such earnings were to be remitted to the United States, Devon may be subject to United States income taxes and foreign withholding taxes. However, it is not practical to estimate the amount of additional taxes that may be payable due to the inter-relationship of the various factors involved in making such an estimate.
Unrecognized Tax Benefits
The following table presents changes in Devon's unrecognized tax benefits (in millions).
|
2010 |
2009 |
|
(In millions) | |
Balance at beginning of year |
$ 272 |
$ 260 |
Tax positions taken in prior periods |
40 |
— |
Tax positions taken in current year |
5 |
20 |
Accrual of interest related to tax positions taken |
9 |
7 |
Lapse of statute of limitations |
(5) |
(15) |
Settlements |
(129) |
(5) |
Foreign currency translation |
2 |
5 |
Balance at end of year |
$ 194 |
$ 272 |
Devon's unrecognized tax benefit balance at December 31, 2010 and 2009 included $27 million and $35 million of interest and penalties, respectively. If recognized, all of Devon's unrecognized tax benefits as of December 31, 2010 would affect Devon's effective income tax rate.
Included below is a summary of the tax years, by jurisdiction, that remain subject to examination by taxing authorities.
Jurisdiction |
Tax Years Open |
U.S. federal |
2005-2010 |
Various U.S. states |
2005-2010 |
Canada federal |
2003-2010 |
Various Canadian provinces |
2003-2010 |
Certain statute of limitation expirations are scheduled to occur in the next twelve months. However, Devon is currently in various stages of the administrative review process for certain open tax years. In addition, Devon is currently subject to various income tax audits that have not reached the administrative review process. As a result, Devon cannot reasonably anticipate the extent that the liabilities for unrecognized tax benefits will increase or decrease within the next twelve months.
|
18. Discontinued Operations
For the three-year period ended December 31, 2010, Devon's discontinued operations include amounts related to its assets in Azerbaijan, Brazil, China, Angola and other minor International properties. Additionally, during 2008, Devon's discontinued operations included amounts related to its assets in Egypt and West Africa, including Equatorial Guinea, Cote d'Ivoire, Gabon and other countries in the region, until they were sold.
Revenues related to Devon's discontinued operations totaled $693 million, $945 million and $1,702 million during 2010, 2009 and 2008, respectively. Earnings from discontinued operations before income taxes totaled $2,385 million, $322 million and $1,258 million during 2010, 2009 and 2008, respectively. Earnings before income taxes in each of these years were largely impacted by gains on the divestiture transactions. The following table presents the gains on the divestitures by year.
|
Year Ended December 31, | |||||
|
2010 |
2009 |
2008 | |||
|
Gross |
After Taxes |
Gross |
After Taxes |
Gross |
After Taxes |
|
(In millions) | |||||
Azerbaijan |
$ 1,543 |
$ 1,524 |
$ — |
$ — |
$ — |
$ — |
China - Panyu |
308 |
235 |
— |
— |
— |
— |
Equatorial Guinea |
— |
— |
— |
— |
619 |
544 |
Gabon |
— |
— |
— |
— |
117 |
122 |
Cote d'Ivoire |
— |
— |
17 |
17 |
83 |
95 |
Other |
(33) |
(27) |
— |
— |
— |
8 |
Total |
$ 1,818 |
$ 1,732 |
$ 17 |
$ 17 |
$ 819 |
$ 769 |
The following table presents the main classes of assets and liabilities associated with Devon's discontinued operations.
|
December 31, | |
|
2010 |
2009 |
|
(In millions) | |
Cash and cash equivalents |
$ 424 |
$ 365 |
Accounts receivable |
43 |
165 |
Other current assets |
96 |
127 |
Current assets |
$ 563 |
$ 657 |
|
|
|
Property and equipment, net |
$ 848 |
$ 1,099 |
Goodwill |
— |
68 |
Other long-term assets |
11 |
83 |
Total long-term assets |
$ 859 |
$ 1,250 |
|
|
|
Accounts payable |
$ 260 |
$ 158 |
Other current liabilities |
45 |
76 |
Current liabilities |
$ 305 |
$ 234 |
|
|
|
Asset retirement obligations |
$ 24 |
$ 109 |
Deferred income taxes |
2 |
101 |
Other liabilities |
— |
3 |
Long-term liabilities |
$ 26 |
$ 213 |
Reductions of Carrying Value of Oil and Gas Properties
During 2009 and 2008, Devon reduced the carrying values of certain of its oil and gas properties that are now held for sale. These reductions primarily resulted from full cost ceiling limitations. A summary of these reductions and additional discussion is provided below.
|
Year Ended December 31, | ||||
|
2009 |
2008 | |||
|
Gross |
After Taxes |
Gross |
After Taxes | |
|
(In millions) |
(In millions) | |||
Brazil |
$ 103 |
$ 103 |
$ 437 |
$ 437 | |
Other |
6 |
2 |
57 |
28 | |
Total |
$ 109 |
$ 105 |
$ 494 |
$ 465 | |
Brazil's 2009 reduction resulted largely from an exploratory well drilled at the BM-BAR-3 block in the offshore Barreirinhas Basin. After drilling this well in the first quarter of 2009, Devon concluded that the well did not have adequate reserves for commercial viability. As a result, the seismic, leasehold and drilling costs associated with this well contributed to the reduction recognized in the first quarter of 2009.
Brazil's 2008 reduction was recognized in the fourth quarter of 2008 and resulted primarily from a significant decrease in its full cost ceiling. The lower ceiling value largely resulted from the effects of sharp declines in oil prices compared to previous quarter-end prices.
|
20. Segment Information
Devon manages its North American onshore operations through six distinct operating segments, or divisions, which are defined primarily by geographic areas. For financial reporting purposes, Devon aggregates its United States divisions into one reporting segment due to the similar nature of the businesses. However, Devon's Canadian and International divisions are reported as separate reporting segments primarily due to significant differences in the respective regulatory environments.
Devon's segments are all primarily engaged in oil and gas producing activities, and certain information regarding such activities for each segment is included in Note 22. Following is certain financial information regarding Devon's segments for 2010, 2009 and 2008. The revenues reported are all from external customers.
|
U.S. |
Canada |
International |
Total |
|
(In millions) | |||
As of December 31, 2010: |
|
|
|
|
Current assets |
$ 2,473 |
$ 2,519 |
$ 563 |
$ 5,555 |
Property and equipment, net |
12,379 |
7,273 |
— |
19,652 |
Goodwill |
3,046 |
3,034 |
— |
6,080 |
Other assets |
422 |
359 |
859 |
1,640 |
Total assets |
$ 18,320 |
$ 13,185 |
$ 1,422 |
$ 32,927 |
Current liabilities |
$ 1,701 |
$ 2,577 |
$ 305 |
$ 4,583 |
Long-term debt |
2,502 |
1,317 |
— |
3,819 |
Asset retirement obligations |
566 |
857 |
— |
1,423 |
Other liabilities |
1,005 |
62 |
26 |
1,093 |
Deferred income taxes |
1,571 |
1,185 |
— |
2,756 |
Stockholders' equity |
10,975 |
7,187 |
1,091 |
19,253 |
Total liabilities and stockholders' equity |
$ 18,320 |
$ 13,185 |
$ 1,422 |
$ 32,927 |
|
U.S. |
Canada |
Total |
|
(In millions) | ||
Year Ended December 31, 2010: |
|
|
|
Revenues: |
|
|
|
Oil, gas and NGL sales |
$ 4,742 |
$ 2,520 |
$ 7,262 |
Oil, gas and NGL derivatives |
809 |
2 |
811 |
Marketing and midstream revenues |
1,742 |
125 |
1,867 |
Total revenues |
7,293 |
2,647 |
9,940 |
Expenses and other, net: |
|
|
|
Lease operating expenses |
892 |
797 |
1,689 |
Taxes other than income taxes |
341 |
39 |
380 |
Marketing and midstream operating costs and expenses... |
1,256 |
101 |
1,357 |
Depreciation, depletion and amortization of oil and gas properties |
998 |
677 |
1,675 |
Depreciation and amortization of non-oil and gas properties |
231 |
24 |
255 |
Accretion of asset retirement obligations |
42 |
50 |
92 |
General and administrative expenses |
433 |
130 |
563 |
Restructuring costs |
57 |
— |
57 |
Interest expense |
159 |
204 |
363 |
Interest-rate and other financial instruments |
(14) |
— |
(14) |
Other, net |
(45) |
— |
(45) |
Total expenses and other, net |
4,350 |
2,022 |
6,372 |
Earnings from continuing operations before income taxes.. |
2,943 |
625 |
3,568 |
Income tax expense (benefit): |
|
|
|
Current |
260 |
256 |
516 |
Deferred |
802 |
(83) |
719 |
Total income tax expense |
1,062 |
173 |
1,235 |
Earnings from continuing operations |
$ 1,881 |
$ 452 |
$ 2,333 |
|
|
|
|
Capital expenditures, before revision of future asset retirement obligations |
$ 4,935 |
$ 1,985 |
$ 6,920 |
Revision of future asset retirement obligations |
72 |
122 |
194 |
Capital expenditures, continuing operations |
$ 5,007 |
$ 2,107 |
$ 7,114 |
|
U.S. |
Canada |
International |
Total |
|
(In millions) | |||
As of December 31, 2009: |
|
|
|
|
Current assets |
$ 1,449 |
$ 886 |
$ 657 |
$ 2,992 |
Property and equipment, net |
13,199 |
5,568 |
— |
18,767 |
Goodwill |
3,046 |
2,884 |
— |
5,930 |
Other assets |
674 |
73 |
1,250 |
1,997 |
Total assets |
$ 18,368 |
$ 9,411 |
$ 1,907 |
$ 29,686 |
Current liabilities |
$ 2,993 |
$ 575 |
$ 234 |
$ 3,802 |
Long-term debt |
2,866 |
2,981 |
— |
5,847 |
Asset retirement obligations |
754 |
664 |
— |
1,418 |
Other liabilities |
890 |
47 |
213 |
1,150 |
Deferred income taxes |
860 |
1,039 |
— |
1,899 |
Stockholders' equity |
10,005 |
4,105 |
1,460 |
15,570 |
Total liabilities and stockholders' equity |
$ 18,368 |
$ 9,411 |
$ 1,907 |
$ 29,686 |
|
U.S. |
Canada |
Total |
|
(In millions) | ||
Year Ended December 31, 2009: |
|
|
|
Revenues: |
|
|
|
Oil, gas and NGL sales |
$ 3,958 |
$ 2,139 |
$ 6,097 |
Oil, gas and NGL derivatives |
382 |
2 |
384 |
Marketing and midstream revenues |
1,498 |
36 |
1,534 |
Total revenues |
5,838 |
2,177 |
8,015 |
Expenses and other, net: |
|
|
|
Lease operating expenses |
997 |
673 |
1,670 |
Taxes other than income taxes |
278 |
36 |
314 |
Marketing and midstream operating costs and expenses... |
1,004 |
18 |
1,022 |
Depreciation, depletion and amortization of oil and gas properties |
1,247 |
585 |
1,832 |
Depreciation and amortization of non-oil and gas properties |
251 |
25 |
276 |
Accretion of asset retirement obligations |
53 |
38 |
91 |
General and administrative expenses |
529 |
119 |
648 |
Restructuring costs |
105 |
— |
105 |
Interest expense |
125 |
224 |
349 |
Interest-rate and other financial instruments |
(106) |
— |
(106) |
Reduction of carrying value of oil and gas properties |
6,408 |
— |
6,408 |
Other, net |
(92) |
24 |
(68) |
Total expenses and other, net |
10,799 |
1,742 |
12,541 |
(Loss) earnings from continuing operations before income taxes |
(4,961) |
435 |
(4,526) |
Income tax (benefit) expense: |
|
|
|
Current |
63 |
178 |
241 |
Deferred |
(1,957) |
(57) |
(2,014) |
Total income tax (benefit) expense |
(1,894) |
121 |
(1,773) |
(Loss) earnings from continuing operations |
$ (3,067) |
$ 314 |
$ (2,753) |
|
|
|
|
Capital expenditures, before revision of future asset retirement obligations |
$ 3,536 |
$ 1,114 |
$ 4,650 |
Revision of future asset retirement obligations |
48 |
(15) |
33 |
Capital expenditures, continuing operations |
$ 3,584 |
$ 1,099 |
$ 4,683 |
|
U.S. |
Canada |
Total |
|
(In millions) | ||
Year Ended December 31, 2008: |
|
|
|
Revenues: |
|
|
|
Oil, gas and NGL sales |
$ 8,206 |
$ 3,514 |
$ 11,720 |
Oil, gas and NGL derivatives |
(154) |
— |
(154) |
Marketing and midstream revenues |
2,247 |
45 |
2,292 |
Total revenues |
10,299 |
3,559 |
13,858 |
Expenses and other, net: |
|
|
|
Lease operating expenses |
1,075 |
776 |
1,851 |
Taxes other than income taxes |
438 |
38 |
476 |
Marketing and midstream operating costs and expenses... |
1,593 |
18 |
1,611 |
Depreciation, depletion and amortization of oil and gas properties |
1,998 |
950 |
2,948 |
Depreciation and amortization of non-oil and gas properties |
229 |
26 |
255 |
Accretion of asset retirement obligations |
42 |
38 |
80 |
General and administrative expenses |
513 |
132 |
645 |
Interest expense |
117 |
212 |
329 |
Interest-rate and other financial instruments |
149 |
— |
149 |
Reduction of carrying value of oil and gas properties |
6,538 |
3,353 |
9,891 |
Other, net |
(203) |
(14) |
(217) |
Total expenses and other, net |
12,489 |
5,529 |
18,018 |
Loss from continuing operations before income taxes |
(2,190) |
(1,970) |
(4,160) |
Income tax (benefit) expense: |
|
|
|
Current |
289 |
152 |
441 |
Deferred |
(940) |
(622) |
(1,562) |
Total income tax benefit |
(651) |
(470) |
(1,121) |
Loss from continuing operations |
$ (1,539) |
$ (1,500) |
$ (3,039) |
|
|
|
|
Capital expenditures, before revision of future asset retirement obligations |
$ 8,313 |
$ 1,639 |
$ 9,952 |
Revision of future asset retirement obligations |
152 |
73 |
225 |
Capital expenditures, continuing operations |
$ 8,465 |
$ 1,712 |
$ 10,177 |
|
21. Supplemental Information to Statements of Cash Flows
Information related to Devon's cash flows are presented below:
|
Year Ended December 31, | ||
|
2010 |
2009 |
2008 |
|
(In millions) | ||
Net decrease (increase) in working capital: |
|
|
|
Decrease in accounts receivable |
$ 23 |
$ 142 |
$ 187 |
Decrease (increase) in other current assets |
21 |
212 |
(46) |
Increase (decrease) in accounts payable |
37 |
(91) |
159 |
Increase in revenues and royalties due to others |
48 |
— |
11 |
Decrease in income taxes payable |
(203) |
(48) |
(309) |
Decrease in other current liabilities |
(199) |
(66) |
(209) |
Net (increase) decrease in working capital |
$ (273) |
$ 149 |
$ (207) |
|
|
|
|
Supplementary cash flow data – total operations: |
|
|
|
Interest paid (net of capitalized interest) |
$ 359 |
$ 314 |
$ 336 |
Income taxes paid |
$ 955 |
$ 68 |
$ 1,436 |
|
|
|
|
Noncash investing activity – exchange of investment in Chevron common stock for oil and gas properties |
$ — |
$ — |
$ 610 |
|
22. Supplemental Information on Oil and Gas Operations (Unaudited)
Supplemental unaudited information regarding Devon's oil and gas activities is presented in this note. The information is provided separately by country and continent. Additionally, the costs incurred and reserves information for the United States is segregated between Devon's onshore and offshore operations. Unless otherwise noted, this supplemental information excludes amounts for all periods presented related to Devon's discontinued operations.
Costs Incurred
The following tables reflect the costs incurred in oil and gas property acquisition, exploration, and development activities.
|
Year Ended December 31, 2010 | ||||
|
U.S. Onshore |
U.S. Offshore |
Total U.S. |
Canada |
North America |
Property acquisition costs: |
(In millions) | ||||
Proved properties |
$ 29 |
$ — |
$ 29 |
$ 4 |
$ 33 |
Unproved properties |
592 |
2 |
594 |
590 |
1,184 |
Exploration costs |
339 |
89 |
428 |
260 |
688 |
Development costs |
3,126 |
297 |
3,423 |
1,216 |
4,639 |
Costs incurred |
$ 4,086 |
$ 388 |
$ 4,474 |
$ 2,070 |
$ 6,544 |
|
Year Ended December 31, 2009 | ||||
|
U.S. Onshore |
U.S. Offshore |
Total U.S. |
Canada |
North America |
Property acquisition costs: |
(In millions) | ||||
Proved properties |
$ 17 |
$ — |
$ 17 |
$ 18 |
$ 35 |
Unproved properties |
52 |
11 |
63 |
72 |
135 |
Exploration costs |
122 |
260 |
382 |
152 |
534 |
Development costs |
2,011 |
537 |
2,548 |
835 |
3,383 |
Costs incurred |
$ 2,202 |
$ 808 |
$ 3,010 |
$ 1,077 |
$ 4,087 |
|
Year Ended December 31, 2008 | ||||
|
U.S. Onshore |
U.S. Offshore |
Total U.S. |
Canada |
North America |
Property acquisition costs: |
(In millions) | ||||
Proved properties |
$ 822 |
$ — |
$ 822 |
$ — |
$ 822 |
Unproved properties |
1,226 |
185 |
1,411 |
352 |
1,763 |
Exploration costs |
206 |
638 |
844 |
173 |
1,017 |
Development costs |
4,182 |
551 |
4,733 |
1,131 |
5,864 |
Costs incurred |
$ 6,436 |
$ 1,374 |
$ 7,810 |
$ 1,656 |
$ 9,466 |
Pursuant to the full cost method of accounting, Devon capitalizes certain of its general and administrative expenses that are related to property acquisition, exploration and development activities. Such capitalized expenses, which are included in the costs shown in the preceding tables, were $311 million, $332 million and $337 million in the years 2010, 2009 and 2008, respectively. Also, Devon capitalizes interest costs incurred and attributable to unproved oil and gas properties and major development projects of oil and gas properties. Capitalized interest expenses, which are included in the costs shown in the preceding tables, were $37 million, $74 million and $71 million in the years 2010, 2009 and 2008, respectively.
Results of Operations
The following tables include revenues and expenses directly associated with Devon's oil and gas producing activities, including general and administrative expenses directly related to such producing activities. They do not include any allocation of Devon's interest costs or general corporate overhead and, therefore, are not necessarily indicative of the contribution to net earnings of Devon's oil and gas operations. Income tax expense has been calculated by applying statutory income tax rates to oil, gas and NGL sales after deducting costs, including depreciation, depletion and amortization and after giving effect to permanent differences.
|
Year Ended December 31, 2010 | ||
|
United States |
Canada |
North America |
|
(In millions) | ||
Oil, gas and NGL sales |
$ 4,742 |
$ 2,520 |
$ 7,262 |
Lease operating expenses |
(892) |
(797) |
(1,689) |
Taxes other than income taxes |
(319) |
(40) |
(359) |
Depreciation, depletion and amortization |
(998) |
(677) |
(1,675) |
Accretion of asset retirement obligations |
(42) |
(50) |
(92) |
General and administrative expenses |
(133) |
(83) |
(216) |
Income tax expense |
(849) |
(246) |
(1,095) |
Results of operations |
$ 1,509 |
$ 627 |
$ 2,136 |
Depreciation, depletion and amortization per Boe |
$ 6.11 |
$ 10.51 |
$ 7.36 |
|
Year Ended December 31, 2009 | ||
|
United States |
Canada |
North America |
|
(In millions) | ||
Oil, gas and NGL sales |
$ 3,958 |
$ 2,139 |
$ 6,097 |
Lease operating expenses |
(997) |
(673) |
(1,670) |
Taxes other than income taxes |
(258) |
(35) |
(293) |
Depreciation, depletion and amortization |
(1,247) |
(585) |
(1,832) |
Accretion of asset retirement obligations |
(53) |
(38) |
(91) |
General and administrative expenses |
(145) |
(74) |
(219) |
Reduction of carrying value of oil and gas properties |
(6,408) |
— |
(6,408) |
Income tax benefit (expense) |
1,800 |
(210) |
1,580 |
Results of operations |
$ (3,350) |
$ 524 |
$ (2,836) |
Depreciation, depletion and amortization per Boe |
$ 7.47 |
$ 8.84 |
$ 7.86 |
|
Year Ended December 31, 2008 | ||
|
United States |
Canada |
North America |
|
(In millions) | ||
Oil, gas and NGL sales |
$ 8,206 |
$ 3,514 |
$ 11,720 |
Lease operating expenses |
(1,075) |
(776) |
(1,851) |
Taxes other than income taxes |
(420) |
(37) |
(457) |
Depreciation, depletion and amortization |
(1,998) |
(950) |
(2,948) |
Accretion of asset retirement obligations |
(42) |
(38) |
(80) |
General and administrative expenses |
(148) |
(87) |
(235) |
Reduction of carrying value of oil and gas properties |
(6,538) |
(3,353) |
(9,891) |
Income tax benefit |
719 |
405 |
1,124 |
Results of operations |
$ (1,296) |
$ (1,322) |
$ (2,618) |
Depreciation, depletion and amortization per Boe |
$ 12.31 |
$ 15.59 |
$ 13.20 |
Proved Reserves
The following tables present Devon's estimated proved developed and proved undeveloped reserves by product for each significant country for the three years ended December 31, 2010. The significant changes in Devon's reserves are discussed following the tables.
|
Oil (MMBbls) | ||||
|
U.S. Onshore |
U.S. Offshore |
Total U.S. |
Canada |
North America |
Proved developed and undeveloped reserves: |
|
|
|
|
|
December 31, 2007 |
131 |
39 |
170 |
388 |
558 |
Revisions due to prices |
(17) |
(3) |
(20) |
(349) |
(369) |
Revisions other than price |
2 |
3 |
5 |
2 |
7 |
Extensions and discoveries |
11 |
1 |
12 |
120 |
132 |
Purchase of reserves |
18 |
— |
18 |
— |
18 |
Production |
(11) |
(6) |
(17) |
(22) |
(39) |
Sale of reserves |
(1) |
— |
(1) |
(5) |
(6) |
December 31, 2008 |
133 |
34 |
167 |
134 |
301 |
Revisions due to prices |
9 |
2 |
11 |
291 |
302 |
Revisions other than price |
— |
1 |
1 |
(8) |
(7) |
Extensions and discoveries |
9 |
2 |
11 |
122 |
133 |
Purchase of reserves |
— |
— |
— |
— |
— |
Production |
(12) |
(5) |
(17) |
(25) |
(42) |
Sale of reserves |
— |
(1) |
(1) |
— |
(1) |
December 31, 2009 |
139 |
33 |
172 |
514 |
686 |
Revisions due to prices |
4 |
1 |
5 |
(24) |
(19) |
Revisions other than price |
2 |
2 |
4 |
9 |
13 |
Extensions and discoveries |
19 |
1 |
20 |
59 |
79 |
Purchase of reserves |
— |
— |
— |
— |
— |
Production |
(14) |
(2) |
(16) |
(25) |
(41) |
Sale of reserves |
(2) |
(35) |
(37) |
— |
(37) |
December 31, 2010 |
148 |
— |
148 |
533 |
681 |
Proved developed reserves as of: |
|
|
|
|
|
December 31, 2007 |
122 |
26 |
148 |
195 |
343 |
December 31, 2008 |
111 |
22 |
133 |
110 |
243 |
December 31, 2009 |
119 |
21 |
140 |
149 |
289 |
December 31, 2010 |
131 |
— |
131 |
126 |
257 |
Proved undeveloped reserves as of: |
|
|
|
|
|
December 31, 2007 |
9 |
13 |
22 |
193 |
215 |
December 31, 2008 |
22 |
12 |
34 |
24 |
58 |
December 31, 2009 |
20 |
12 |
32 |
365 |
397 |
December 31, 2010 |
17 |
— |
17 |
407 |
424 |
|
Gas (Bcf) | ||||
|
U.S. Onshore |
U.S. Offshore |
Total U.S. |
Canada |
North America |
Proved developed and undeveloped reserves: |
|
|
|
|
|
December 31, 2007 |
6,765 |
378 |
7,143 |
1,844 |
8,987 |
Revisions due to prices |
(367) |
(2) |
(369) |
(219) |
(588) |
Revisions other than price |
85 |
21 |
106 |
(12) |
94 |
Extensions and discoveries |
1,916 |
50 |
1,966 |
111 |
2,077 |
Purchase of reserves |
250 |
— |
250 |
2 |
252 |
Production |
(669) |
(57) |
(726) |
(212) |
(938) |
Sale of reserves |
(1) |
— |
(1) |
(4) |
(5) |
December 31, 2008 |
7,979 |
390 |
8,369 |
1,510 |
9,879 |
Revisions due to prices |
(661) |
(4) |
(665) |
(29) |
(694) |
Revisions other than price |
119 |
(62) |
57 |
(14) |
43 |
Extensions and discoveries |
1,387 |
64 |
1,451 |
67 |
1,518 |
Purchase of reserves |
1 |
— |
1 |
6 |
7 |
Production |
(698) |
(45) |
(743) |
(223) |
(966) |
Sale of reserves |
— |
(1) |
(1) |
(29) |
(30) |
December 31, 2009 |
8,127 |
342 |
8,469 |
1,288 |
9,757 |
Revisions due to prices |
449 |
2 |
451 |
21 |
472 |
Revisions other than price |
105 |
(26) |
79 |
(17) |
62 |
Extensions and discoveries |
1,088 |
7 |
1,095 |
131 |
1,226 |
Purchase of reserves |
12 |
— |
12 |
9 |
21 |
Production |
(699) |
(17) |
(716) |
(214) |
(930) |
Sale of reserves |
(17) |
(308) |
(325) |
— |
(325) |
December 31, 2010 |
9,065 |
— |
9,065 |
1,218 |
10,283 |
Proved developed reserves as of: |
|
|
|
|
|
December 31, 2007 |
5,547 |
196 |
5,743 |
1,506 |
7,249 |
December 31, 2008 |
6,469 |
212 |
6,681 |
1,357 |
8,038 |
December 31, 2009 |
6,447 |
185 |
6,632 |
1,213 |
7,845 |
December 31, 2010 |
7,280 |
— |
7,280 |
1,144 |
8,424 |
Proved undeveloped reserves as of: |
|
|
|
|
|
December 31, 2007 |
1,218 |
182 |
1,400 |
338 |
1,738 |
December 31, 2008 |
1,510 |
178 |
1,688 |
153 |
1,841 |
December 31, 2009 |
1,680 |
157 |
1,837 |
75 |
1,912 |
December 31, 2010 |
1,785 |
— |
1,785 |
74 |
1,859 |
|
Natural Gas Liquids (MMBbls) | ||||
|
U.S. Onshore |
U.S. Offshore |
Total U.S. |
Canada |
North America |
Proved developed and undeveloped reserves: |
|
|
|
|
|
December 31, 2007 |
281 |
1 |
282 |
39 |
321 |
Revisions due to prices |
(18) |
— |
(18) |
(2) |
(20) |
Revisions other than price |
5 |
1 |
6 |
— |
6 |
Extensions and discoveries |
65 |
— |
65 |
2 |
67 |
Purchase of reserves |
6 |
— |
6 |
— |
6 |
Production |
(24) |
— |
(24) |
(4) |
(28) |
Sale of reserves |
— |
— |
— |
— |
— |
December 31, 2008 |
315 |
2 |
317 |
35 |
352 |
Revisions due to prices |
(11) |
— |
(11) |
2 |
(9) |
Revisions other than price |
36 |
1 |
37 |
— |
37 |
Extensions and discoveries |
70 |
— |
70 |
1 |
71 |
Purchase of reserves |
— |
— |
— |
— |
— |
Production |
(25) |
(1) |
(26) |
(4) |
(30) |
Sale of reserves |
— |
— |
— |
— |
— |
December 31, 2009 |
385 |
2 |
387 |
34 |
421 |
Revisions due to prices |
14 |
— |
14 |
(1) |
13 |
Revisions other than price |
13 |
3 |
16 |
(1) |
15 |
Extensions and discoveries |
68 |
— |
68 |
2 |
70 |
Purchase of reserves |
— |
— |
— |
— |
— |
Production |
(28) |
— |
(28) |
(4) |
(32) |
Sale of reserves |
(3) |
(5) |
(8) |
— |
(8) |
December 31, 2010 |
449 |
— |
449 |
30 |
479 |
Proved developed reserves as of: |
|
|
|
|
|
December 31, 2007 |
243 |
1 |
244 |
30 |
274 |
December 31, 2008 |
260 |
1 |
261 |
31 |
292 |
December 31, 2009 |
293 |
1 |
294 |
32 |
326 |
December 31, 2010 |
353 |
— |
353 |
28 |
381 |
Proved undeveloped reserves as of: |
|
|
|
|
|
December 31, 2007 |
38 |
— |
38 |
9 |
47 |
December 31, 2008 |
55 |
1 |
56 |
4 |
60 |
December 31, 2009 |
92 |
1 |
93 |
2 |
95 |
December 31, 2010 |
96 |
— |
96 |
2 |
98 |
|
Total (MMBoe) (1) | ||||
|
U.S. Onshore |
U.S. Offshore |
Total U.S. |
Canada |
North America |
Proved developed and undeveloped reserves: |
|
|
|
|
|
December 31, 2007 |
1,539 |
103 |
1,642 |
734 |
2,376 |
Revisions due to prices |
(97) |
(3) |
(100) |
(387) |
(487) |
Revisions other than price |
21 |
7 |
28 |
— |
28 |
Extensions and discoveries |
395 |
10 |
405 |
141 |
546 |
Purchase of reserves |
66 |
— |
66 |
— |
66 |
Production |
(146) |
(16) |
(162) |
(61) |
(223) |
Sale of reserves |
(1) |
— |
(1) |
(6) |
(7) |
December 31, 2008 |
1,777 |
101 |
1,878 |
421 |
2,299 |
Revisions due to prices |
(113) |
1 |
(112) |
289 |
177 |
Revisions other than price |
57 |
(8) |
49 |
(11) |
38 |
Extensions and discoveries |
311 |
12 |
323 |
135 |
458 |
Purchase of reserves |
— |
— |
— |
1 |
1 |
Production |
(154) |
(13) |
(167) |
(66) |
(233) |
Sale of reserves |
— |
(1) |
(1) |
(6) |
(7) |
December 31, 2009 |
1,878 |
92 |
1,970 |
763 |
2,733 |
Revisions due to prices |
92 |
1 |
93 |
(21) |
72 |
Revisions other than price |
32 |
1 |
33 |
5 |
38 |
Extensions and discoveries |
269 |
2 |
271 |
83 |
354 |
Purchase of reserves |
2 |
— |
2 |
2 |
4 |
Production |
(158) |
(5) |
(163) |
(65) |
(228) |
Sale of reserves |
(8) |
(91) |
(99) |
(1) |
(100) |
December 31, 2010 |
2,107 |
— |
2,107 |
766 |
2,873 |
Proved developed reserves as of: |
|
|
|
|
|
December 31, 2007 |
1,290 |
59 |
1,349 |
476 |
1,825 |
December 31, 2008 |
1,449 |
59 |
1,508 |
367 |
1,875 |
December 31, 2009 |
1,486 |
53 |
1,539 |
383 |
1,922 |
December 31, 2010 |
1,696 |
— |
1,696 |
346 |
2,042 |
Proved undeveloped reserves as of: |
|
|
|
|
|
December 31, 2007 |
249 |
44 |
293 |
258 |
551 |
December 31, 2008 |
328 |
42 |
370 |
54 |
424 |
December 31, 2009 |
392 |
39 |
431 |
380 |
811 |
December 31, 2010 |
411 |
— |
411 |
420 |
831 |
____________________________
(1) Gas reserves are converted to Boe at the rate of six Mcf per Bbl of oil, based upon the approximate relative energy content of gas and oil. This rate is not necessarily indicative of the relationship of natural gas and oil prices. Natural gas liquids reserves are converted to Boe on a one-to-one basis with oil.
Price Revisions
2010 - Reserves increased 72 MMBoe due to higher gas prices, partially offset by the effect of higher oil prices. The higher oil prices increased Devon's Canadian royalty burden, which reduced Devon's oil reserves. Of the 72 MMBoe price revisions, 43 MMBoe related to the Barnett Shale in north Texas and 22 MMBoe related to the Rocky Mountain area.
2009 – Reserves increased 177 MMBoe due to higher oil prices, partially offset by lower gas prices. The increase in oil reserves primarily related to Devon's Jackfish thermal heavy oil reserves in Canada. At the end of 2008, 331 MMBoe of reserves related to Jackfish were not considered proved. However, due to higher prices, these reserves were considered proved as of December 31, 2009. Significantly lower gas prices caused Devon's reserves to decrease 116 MMBoe, which primarily related to its United States reserves.
2008 – Due to significantly lower oil, gas and NGL prices as of December 31, 2008 compared to December 31, 2007, 487 MMBoe of reserves were not considered proved as of December 31, 2008. Of the 487 MMBoe price revisions, 331 MMBoe related to Jackfish.
The 487 MMBoe price revision also included 28 MMBoe related to Devon's proved reserves in the Canadian province of Alberta. In December 2008, the provincial government of Alberta enacted a new royalty regime. The new regime for conventional oil, gas, NGL and heavy oil production was effective January 1, 2009. As a result of the newly enacted royalties, Devon's proved reserves decreased as of December 31, 2008.
Revisions Other Than Price
Total revisions other than price for 2010, 2009 and 2008 primarily related to Devon's drilling and development in the Barnett Shale.
Extensions and Discoveries
2010 – Of the 354 MMBoe of 2010 extensions and discoveries, 101 MMBoe related to the Cana-Woodford Shale in western Oklahoma, 87 MMBoe related to the Barnett Shale, 55 MMBoe related to Jackfish, 19 MMBoe related to the Permian Basin, 15 MMBoe related to the Rocky Mountain area and 14 MMBoe related to the Carthage area in east Texas.
The 2010 extensions and discoveries included 107 MMBoe related to additions from Devon's infill drilling activities, including 43 MMBoe at the Barnett Shale and 47 MMBoe at the Cana-Woodford Shale.
2009 – Of the 458 MMBoe of 2009 extensions and discoveries, 204 MMBoe related to the Barnett Shale, 118 MMBoe related to Jackfish, 49 MMBoe related to the Cana-Woodford Shale, 14 MMBoe related to the Rocky Mountain area, 11 MMBoe related to Deepwater Production in the Gulf, 8 MMBoe related to the Carthage conventional area, and 7 MMBoe related to the Haynesville Shale area in east Texas.
The 2009 extensions and discoveries included 371 MMBoe related to additions from Devon's infill drilling activities, including 203 MMBoe at the Barnett Shale, 118 MMBoe at Jackfish and 24 MMBoe at the Cana-Woodford Shale.
2008 – Of the 546 MMBoe of 2008 extensions and discoveries, 252 MMBoe related to the Barnett Shale, 101 MMBoe related to Jackfish, 44 MMBoe related to Carthage conventional, 21 MMBoe related to the Cana-Woodford Shale, 19 MMBoe related to the Lloydminster heavy oil development in Canada and 17 MMBoe related to the Arkoma-Woodford Shale area in southeastern Oklahoma.
The 2008 extensions and discoveries included 420 MMBoe related to additions from Devon's infill drilling activities, including 243 MMBoe at the Barnett Shale, 101 MMBoe at Jackfish, 22 MMBoe at Carthage conventional, 18 MMBoe at Lloydminster and 11 MMBoe at the Cana-Woodford Shale.
Purchase of Reserves
The 2008 total included 34 MMBoe located in Utah and 27 MMBoe located in the Permian Basin.
Sale of Reserves
The 2010 total primarily relates to the divestiture of Devon's Gulf of Mexico properties.
SEC's Modernization of Oil and Gas Reporting
At the end of 2009, Devon adopted the SEC's Modernization of Oil and Gas Reporting, as well as the conforming rule changes issued by the Financial Accounting Standards Board. Upon adoption, the two primary rule changes that impacted Devon's year-end reserves estimates were those related to assumptions for pricing and reasonable certainty.
The SEC's prior rules required proved reserve estimates to be calculated using prices as of the end of the period and held constant over the life of the reserves. The revised rules require reserves estimates to be calculated using an average of the first-day-of-the-month price for the preceding 12-month period.
The revised rules amend the definition of proved reserves to permit the use of reliable technologies to establish the reasonable certainty of proved reserves. This revision includes provisions for establishing levels of lowest known hydrocarbons and highest known oil through reliable technology other than well penetrations. This revision also allows proved reserves to be claimed beyond development spacing areas that are immediately adjacent to developed spacing areas if economic producibility can be established with reasonable certainty based on reliable technologies. As a result of adopting these provisions of the new rules, Devon's 2009 reserves increased approximately 65 MMBoe, or 2%. This increase is included in the 2009 extensions and discoveries total.
Prepared and Audited Reserves
Set forth below is a summary of the reserves that were evaluated, either by preparation or audit, by independent petroleum consultants for each of the years ended 2010, 2009 and 2008.
|
2010 |
2009 |
2008 | |||
|
Prepared |
Audited |
Prepared |
Audited |
Prepared |
Audited |
U.S. Onshore. |
— |
94% |
— |
93% |
— |
92% |
U.S. Offshore. |
N/A |
N/A |
100% |
— |
100% |
— |
U.S.. |
— |
94% |
5% |
89% |
5% |
87% |
Canada |
— |
89% |
— |
91% |
— |
78% |
North America. |
— |
93% |
3% |
89% |
4% |
85% |
____________________________
N/A Not applicable – Devon sold its U.S. Offshore properties during 2010.
"Prepared" reserves are those quantities of reserves that were prepared by an independent petroleum consultant. "Audited" reserves are those quantities of reserves that were estimated by Devon employees and audited by an independent petroleum consultant. The Society of Petroleum Engineers' definition of an audit is an examination of a company's proved oil and gas reserves and net cash flow by an independent petroleum consultant that is conducted for the purpose of expressing an opinion as to whether such estimates, in aggregate, are reasonable and have been estimated and presented in conformity with generally accepted petroleum engineering and evaluation methods and procedures.
In 2010, the U.S. reserves were evaluated by the independent petroleum consultants of LaRoche Petroleum Consultants, Ltd. In 2009 and 2008, the U.S. reserves were evaluated by the independent petroleum consultants of LaRoche Petroleum Consultants, Ltd. and Ryder Scott Company, L.P. The Canadian reserves were evaluated by the independent petroleum consultants of AJM Petroleum Consultants in each of the years presented.
Standardized Measure
The tables below reflect the standardized measure of discounted future net cash flows related to Devon's interest in proved reserves.
|
Year Ended December 31, 2010 | ||
|
United States |
Canada |
North America |
|
(In millions) | ||
Future cash inflows |
$ 58,093 |
$ 35,948 |
$ 94,041 |
Future costs: |
|
|
|
Development |
(6,220) |
(4,526) |
(10,746) |
Production |
(24,223) |
(12,249) |
(36,472) |
Future income tax expense |
(8,643) |
(4,209) |
(12,852) |
Future net cash flows |
19,007 |
14,964 |
33,971 |
10% discount to reflect timing of cash flows |
(10,164) |
(7,455) |
(17,619) |
Standardized measure of discounted future net cash flows |
$ 8,843 |
$ 7,509 |
$ 16,352 |
|
Year Ended December 31, 2009 | ||
|
United States |
Canada |
North America |
|
(In millions) | ||
Future cash inflows |
$ 44,571 |
$ 28,442 |
$ 73,013 |
Future costs: |
|
|
|
Development |
(6,814) |
(4,132) |
(10,946) |
Production |
(22,184) |
(9,847) |
(32,031) |
Future income tax expense |
(3,572) |
(3,408) |
(6,980) |
Future net cash flows |
12,001 |
11,055 |
23,056 |
10% discount to reflect timing of cash flows |
(6,121) |
(5,532) |
(11,653) |
Standardized measure of discounted future net cash flows |
$ 5,880 |
$ 5,523 |
$ 11,403 |
|
Year Ended December 31, 2008 | ||
|
United States |
Canada |
North America |
|
(In millions) | ||
Future cash inflows |
$ 51,284 |
$ 11,459 |
$ 62,743 |
Future costs: |
|
|
|
Development |
(6,887) |
(1,623) |
(8,510) |
Production |
(24,113) |
(5,742) |
(29,855) |
Future income tax expense |
(5,585) |
(942) |
(6,527) |
Future net cash flows |
14,699 |
3,152 |
17,851 |
10% discount to reflect timing of cash flows |
(7,318) |
(1,140) |
(8,458) |
Standardized measure of discounted future net cash flows |
$ 7,381 |
$ 2,012 |
$ 9,393 |
Future cash inflows, development costs and production costs were computed using the same assumptions for prices and costs that were used to estimate Devon's proved oil and gas reserves at the end of each year. For 2010, the prices averaged $59.94 per barrel of oil, $3.73 per Mcf of gas and $31.11 per barrel of natural gas liquids. Of the $10,746 million of future development costs as of the end of 2010, $1,418 million, $1,447 million and $972 million are estimated to be spent in 2011, 2012 and 2013, respectively.
Future development costs include not only development costs, but also future dismantlement, abandonment and rehabilitation costs. Included as part of the $10,746 million of future development costs are $2,263 million of future dismantlement, abandonment and rehabilitation costs.
Future production costs include general and administrative expenses directly related to oil and gas producing activities. Future income tax expenses are computed by applying the appropriate statutory tax rates to the future pre-tax net cash flows relating to proved reserves, net of the tax basis of the properties involved. The future income tax expenses give effect to permanent differences and tax credits, but do not reflect the impact of future operations.
The principal changes in the standardized measure of discounted future net cash flows attributable to Devon's proved reserves are as follows:
|
Year Ended December 31, | ||
|
2010 |
2009 |
2008 |
|
(In millions) | ||
Beginning balance |
$ 11,403 |
$ 9,393 |
$ 20,582 |
Oil, gas and NGL sales, net of production costs |
(4,982) |
(3,915) |
(9,177) |
Net changes in prices and production costs |
7,423 |
(1,672) |
(13,839) |
Extensions and discoveries, net of future development costs |
3,048 |
2,378 |
1,729 |
Purchase of reserves, net of future development costs |
23 |
6 |
214 |
Development costs incurred that reduced future development costs |
1,559 |
1,012 |
1,660 |
Revisions of quantity estimates |
287 |
4,051 |
(1,294) |
Sales of reserves in place |
(815) |
(37) |
(2) |
Accretion of discount |
1,487 |
1,281 |
2,894 |
Net change in income taxes |
(2,663) |
(51) |
4,934 |
Other, primarily changes in timing and foreign exchange rates |
(418) |
(1,043) |
1,692 |
Ending balance |
$ 16,352 |
$ 11,403 |
$ 9,393 |
|
23. Supplemental Quarterly Financial Information (Unaudited)
Following is a summary of the unaudited interim results of operations for the years ended December 31, 2010 and 2009.
|
2010 | |||||
|
First Quarter |
Second Quarter |
Third Quarter |
Fourth Quarter |
Full Year | |
|
(In millions, except per share amounts) | |||||
Revenues |
$ 3,220 |
$ 2,232 |
$ 2,353 |
$ 2,135 |
$ 9,940 | |
|
|
|
|
|
| |
Earnings from continuing operations before income taxes |
$ 1,588 |
$ 613 |
$ 699 |
$ 668 |
$ 3,568 | |
|
|
|
|
|
| |
Earnings from continuing operations |
$ 1,074 |
$ 352 |
$ 429 |
$ 478 |
$ 2,333 | |
Earnings from discontinued operations |
118 |
354 |
1,661 |
84 |
2,217 | |
Net earnings |
$ 1,192 |
$ 706 |
$ 2,090 |
$ 562 |
$ 4,550 | |
|
|
|
|
|
| |
Basic net earnings per common share: |
|
|
|
|
| |
Earnings from continuing operations |
$ 2.40 |
$ 0.79 |
$ 0.99 |
$ 1.10 |
$ 5.31 | |
Earnings from discontinued operations |
0.27 |
0.80 |
3.82 |
0.20 |
5.04 | |
Net earnings |
$ 2.67 |
$ 1.59 |
$ 4.81 |
$ 1.30 |
$ 10.35 | |
|
|
|
|
|
| |
Diluted net earnings per common share: |
|
|
|
|
| |
Earnings from continuing operations |
$ 2.39 |
$ 0.79 |
$ 0.98 |
$ 1.10 |
$ 5.29 | |
Earnings from discontinued operations |
0.27 |
0.79 |
3.81 |
0.19 |
5.02 | |
Net earnings |
$ 2.66 |
$ 1.58 |
$ 4.79 |
$ 1.29 |
$ 10.31 | |
|
2009 | ||||
|
First Quarter |
Second Quarter |
Third Quarter |
Fourth Quarter |
Full Year |
|
(In millions, except per share amounts) | ||||
Revenues |
$ 1,900 |
$ 1,822 |
$ 1,848 |
$ 2,445 |
$ 8,015 |
|
|
|
|
|
|
(Loss) earnings from continuing operations before income taxes |
$ (6,162) |
$ 299 |
$ 471 |
$ 866 |
$ (4,526) |
|
|
|
|
|
|
(Loss) earnings from continuing operations |
$ (3,882) |
$ 190 |
$ 382 |
$ 557 |
$ (2,753) |
(Loss) earnings from discontinued operations |
(77) |
124 |
117 |
110 |
274 |
Net (loss) earnings |
$ (3,959) |
$ 314 |
$ 499 |
$ 667 |
$ (2,479) |
|
|
|
|
|
|
Basic net (loss) earnings per common share: |
|
|
|
|
|
(Loss) earnings from continuing operations |
$ (8.74) |
$ 0.43 |
$ 0.86 |
$ 1.25 |
$ (6.20) |
(Loss) earnings from discontinued operations |
(0.18) |
0.28 |
0.27 |
0.25 |
0.62 |
Net (loss) earnings |
$ (8.92) |
$ 0.71 |
$ 1.13 |
$ 1.50 |
$ (5.58) |
|
|
|
|
|
|
Diluted net (loss) earnings per common share: |
|
|
|
|
|
(Loss) earnings from continuing operations |
$ (8.74) |
$ 0.42 |
$ 0.86 |
$ 1.25 |
$ (6.20) |
(Loss) earnings from discontinued operations |
(0.18) |
0.28 |
0.26 |
0.24 |
0.62 |
Net (loss) earnings |
$ (8.92) |
$ 0.70 |
$ 1.12 |
$ 1.49 |
$ (5.58) |
Earnings (Loss) from Continuing Operations
The third quarter of 2010 includes restructuring costs that relate to Devon's offshore asset divestitures and total $63 million ($40 million after income taxes, or $0.09 per diluted share).
The first quarter of 2009 includes a reduction of the carrying values of United States oil and gas properties totaling $6,408 million ($4,085 million after income taxes, or $9.20 per diluted share).
The fourth quarter of 2009 includes restructuring costs that relate to Devon's planned asset divestitures and total $105 million ($67 million after income taxes, or $0.15 per diluted share).
Earnings (Loss) from Discontinued Operations
The second quarter of 2010 includes the divestiture of our Panyu operations in China and the related gain was $308 million ($235 million after income taxes, or $0.52 per diluted share).
The third quarter of 2010 includes the divestiture of our Azerbaijan operations and the related gain was $1.541 million ($1.522 million after income taxes, or $3.49 per diluted share).
The first quarter of 2009 includes reductions of the carrying values of oil and gas properties totaling $109 million ($105 million after income taxes, or $0.24 per diluted share).
The fourth quarter of 2009 includes restructuring costs that relate to Devon's planned asset divestitures and total $48 million ($31 million after income taxes, or $0.07 per diluted share).
|
Nature of Business and Principles of Consolidation
Devon is engaged primarily in the acquisition, exploration, development and production of oil and gas properties. Such activities are concentrated in the following North American onshore geographic areas:
• the Mid-Continent area of the central and southern United States, principally in north and east Texas, as well as Oklahoma;
• the Permian Basin within Texas and New Mexico;
• the Rocky Mountains area of the United States stretching from the Canadian border into northern New Mexico;
• the onshore areas of the Gulf Coast, principally in south Texas and south Louisiana; and
• the provinces of Alberta, British Columbia and Saskatchewan in Canada.
In November 2009, Devon announced plans to strategically reposition itself as a North American onshore exploration and development company. During 2010, Devon divested its properties in the Gulf of Mexico, Azerbaijan, China and other International regions. Additionally, Devon has entered into agreements to sell its remaining offshore assets in Brazil and Angola. These activities are more fully described in Note 5.
Devon also has marketing and midstream operations that perform various activities to support the oil and gas operations of Devon and unrelated third parties. Such activities include marketing gas, crude oil and NGLs, as well as constructing and operating pipelines, storage and treating facilities and natural gas processing plants.
The accounts of Devon's controlled subsidiaries are included in the accompanying consolidated financial statements. All significant intercompany accounts and transactions have been eliminated in consolidation.
Use of Estimates in the Preparation of Financial Statements
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual amounts could differ from these estimates, and changes in these estimates are recorded when known. Significant items subject to such estimates and assumptions include the following:
• estimates of proved reserves and related estimates of the present value of future net revenues;
• the carrying value of oil and gas properties;
• estimates of the fair value of reporting units and related assessment of goodwill for impairment;
• derivative financial instruments;
• income taxes;
• asset retirement obligations;
• obligations related to employee pension and postretirement benefits; and
• legal and environmental risks and exposures.
Derivative Financial Instruments
Devon is exposed to certain risks relating to its ongoing business operations, including risks related to commodity prices, interest rates and Canadian to U.S. dollar exchange rates. As discussed more fully below, Devon uses derivative instruments primarily to manage commodity price risk and interest rate risk. Devon does not hold or issue derivative financial instruments for speculative trading purposes. Besides these derivative instruments, Devon also had an embedded option derivative related to the fair value of its debentures exchangeable into shares of Chevron common stock. Devon ceased to have this option when the exchangeable debentures matured on August 15, 2008.
Devon periodically enters into derivative financial instruments with respect to a portion of its oil, gas and NGL production that hedge the future prices received. These instruments are used to manage the inherent uncertainty of future revenues due to commodity price volatility. Devon's derivative financial instruments include financial price swaps, basis swaps, costless price collars and call options. Under the terms of the price swaps, Devon receives a fixed price for its production and pays a variable market price to the contract counterparty. For the basis swaps, Devon receives a fixed differential between two regional gas index prices and pays a variable differential on the same two index prices to the contract counterparty. The price collars set a floor and ceiling price for the hedged production. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, Devon will cash-settle the difference with the counterparty to the collars. Under the terms of a call option, Devon received a cash premium for selling call options. The call options then give the counterparty the right to place us into a price swap at a predetermined fixed price.
Devon periodically enters into interest rate swaps to manage its exposure to interest rate volatility. Devon's interest rate swaps include contracts in which Devon receives a fixed rate and pays a variable rate on a total notional amount. Devon also has forward starting swaps. Under the terms of the forward starting swaps, Devon will net settle these contracts in September 2011 or sooner should Devon elect. The net settlement amount will be based upon Devon paying a fixed rate and receiving a floating rate that is based upon the three-month LIBOR. The difference between the fixed and floating rate will be applied to the notional amount for the 30-year period from September 30, 2011 to September 30, 2041.
All derivative financial instruments are recognized at their current fair value as either assets or liabilities in the balance sheet. Changes in the fair value of these derivative financial instruments are recorded in the statement of operations unless specific hedge accounting criteria are met. For derivative financial instruments held during the three-year period ended December 31, 2010, Devon chose not to meet the necessary criteria to qualify its derivative financial instruments for hedge accounting treatment. Cash settlements with counterparties to Devon's derivative financial instruments are also recorded in the statement of operations.
By using derivative financial instruments to hedge exposures to changes in commodity prices and interest rates, Devon exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. To mitigate this risk, the hedging instruments are placed with a number of counterparties whom Devon believes are minimal credit risks. It is Devon's policy to enter into derivative contracts only with investment grade rated counterparties deemed by management to be competent and competitive market makers. Additionally, Devon's derivative contracts generally require cash collateral to be posted if either its or the counterparty's credit rating falls below investment grade. The mark-to-market exposure threshold, above which collateral must be posted, decreases as the debt rating falls further below investment grade. Such thresholds generally range from zero to $50 million for the majority of our contracts. As of December 31, 2010, the credit ratings of all Devon's counterparties were investment grade.
Market risk is the change in the value of a derivative financial instrument that results from a change in commodity prices, interest rates or other relevant underlyings. The market risks associated with commodity price and interest rate contracts are managed by establishing and monitoring parameters that limit the types and degree of market risk that may be undertaken. The oil and gas reference prices upon which the commodity instruments are based reflect various market indices that have a high degree of historical correlation with actual prices received by Devon.
See Note 3 for the amounts included in Devon's accompanying consolidated balance sheets and consolidated statements of operations associated with its derivative financial instruments.
Fair Value Measurements
Certain of Devon's assets and liabilities are measured at fair value at each reporting date. Fair value represents the price that would be received to sell the asset or paid to transfer the liability in an orderly transaction between market participants. This price is commonly referred to as the "exit price".
Fair value measurements are classified according to a hierarchy that prioritizes the inputs underlying the valuation techniques. This hierarchy consists of three broad levels. Level 1 inputs on the hierarchy consist of unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. Level 2 measurements are based on inputs other than quoted prices that are generally observable for the asset or liability. Common examples of Level 2 inputs include quoted prices for similar assets and liabilities in active markets or quoted prices for identical assets and liabilities in markets not considered to be active. Level 3 measurements have the lowest priority and are based upon inputs that are not observable from objective sources. The most common Level 3 fair value measurement is an internally developed cash flow model. Devon uses appropriate valuation techniques based on the available inputs to measure the fair values of its assets and liabilities. When available, Devon measures fair value using Level 1 inputs because they generally provide the most reliable evidence of fair value.
See Note 11 for fair value measurements included in Devon's accompanying consolidated balance sheets.
Discontinued Operations
As a result of the November 2009 plan to divest Devon's offshore assets, all amounts related to Devon's International operations are classified as discontinued operations. The Gulf of Mexico properties that were divested in 2010 do not qualify as discontinued operations under accounting rules. As such, amounts in these notes and the accompanying consolidated financial statements that pertain to continuing operations include amounts related to Devon's offshore Gulf of Mexico operations. See Note 5 for additional details of the offshore divestiture program.
The captions assets held for sale and liabilities associated with assets held for sale in the accompanying consolidated balance sheets present the assets and liabilities associated with Devon's discontinued operations. Devon measures its assets held for sale at the lower of its carrying amount or estimated fair value less costs to sell. Additionally, Devon does not recognize depreciation, depletion and amortization on its long-lived assets held for sale.
Property and Equipment
Devon follows the full cost method of accounting for its oil and gas properties. Accordingly, all costs incidental to the acquisition, exploration and development of oil and gas properties, including costs of undeveloped leasehold, dry holes and leasehold equipment, are capitalized. Internal costs incurred that are directly identified with acquisition, exploration and development activities undertaken by Devon for its own account, and that are not related to production, general corporate overhead or similar activities, are also capitalized. Interest costs incurred and attributable to unproved oil and gas properties under current evaluation and major development projects of oil and gas properties are also capitalized. All costs related to production activities, including workover costs incurred solely to maintain or increase levels of production from an existing completion interval, are charged to expense as incurred.
Under the full cost method of accounting, the net book value of oil and gas properties, less related deferred income taxes, may not exceed a calculated "ceiling." The ceiling limitation is the estimated after-tax future net revenues, discounted at 10% per annum, from proved oil, gas and NGL reserves plus the cost of properties not subject to amortization. Estimated future net revenues exclude future cash outflows associated with settling asset retirement obligations included in the net book value of oil and gas properties. Such limitations are imposed separately on a country-by-country basis and are tested quarterly.
Future net revenues are calculated using prices that represent the average of the first-day-of-the-month price for the 12-month period prior to the end of the period. Prior to December 31, 2009, prices and costs used to calculate future net revenues were those as of the end of the appropriate quarterly period. Prices are held constant indefinitely and are not changed except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including derivative contracts in place that qualify for hedge accounting treatment. None of Devon's derivative contracts held during the three-year period ended December 31, 2010 qualified for hedge accounting treatment.
Any excess of the net book value, less related deferred taxes, over the ceiling is written off as an expense. An expense recorded in one period may not be reversed in a subsequent period even though higher commodity prices may have increased the ceiling applicable to the subsequent period.
Capitalized costs are depleted by an equivalent unit-of-production method, converting gas to oil at the ratio of six thousand cubic feet of gas to one barrel of oil. Depletion is calculated using the capitalized costs, including estimated asset retirement costs, plus the estimated future expenditures (based on current costs) to be incurred in developing proved reserves, net of estimated salvage values.
Costs associated with unproved properties are excluded from the depletion calculation until it is determined whether or not proved reserves can be assigned to such properties. Devon assesses its unproved properties for impairment quarterly. Significant unproved properties are assessed individually. Costs of insignificant unproved properties are transferred into the depletion calculation over holding periods ranging from three to five years.
No gain or loss is recognized upon disposal of oil and gas properties unless such disposal significantly alters the relationship between capitalized costs and proved reserves in a particular country.
Depreciation of midstream pipelines are provided on a unit-of-production basis. Depreciation and amortization of other property and equipment, including corporate and other midstream assets and leasehold improvements, are provided using the straight-line method based on estimated useful lives ranging from three to 39 years. Interest costs incurred and attributable to major midstream and corporate construction projects are also capitalized.
Devon recognizes liabilities for retirement obligations associated with tangible long-lived assets, such as producing well sites, offshore production platforms, and midstream pipelines and processing plants when there is a legal obligation associated with the retirement of such assets and the amount can be reasonably estimated. The initial measurement of an asset retirement obligation is recorded as a liability at its fair value, with an offsetting asset retirement cost recorded as an increase to the associated property and equipment on the consolidated balance sheet. If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement cost. The asset retirement cost is depreciated using a systematic and rational method similar to that used for the associated property and equipment.
Investments
Devon reports its investments and other marketable securities at fair value, except for debt securities in which management has the ability and intent to hold until maturity.
Devon's primary investments consist of auction rate securities that totaled $94 million and $115 million at December 31, 2010 and 2009, respectively. These securities are rated AAA—the highest rating—by one or more rating agencies and are collateralized by student loans that are substantially guaranteed by the United States government. Although Devon's auction rate securities generally have contractual maturities of more than 20 years, the underlying interest rates on such securities are scheduled to reset every seven to 28 days. Therefore, these auction rate securities were generally priced and subsequently traded as short-term investments because of the interest rate reset feature.
Since February 8, 2008, Devon has experienced difficulty selling its securities due to the failure of the auction mechanism, which provided liquidity to these securities. An auction failure means that the parties wishing to sell securities could not do so. The securities for which auctions have failed will continue to accrue interest and be auctioned every seven to 28 days until the auction succeeds, the issuer calls the securities or the securities mature.
From February 2008, when auctions began failing, to December 31, 2010, issuers have redeemed $58 million of Devon's auction rate securities holdings at par. However, based on continued auction failures and the current market for Devon's auction rate securities, Devon has classified its auction rate securities as long-term investments as of December 31, 2010. These securities are included in other long-term assets in the accompanying consolidated balance sheet. Devon has the ability to hold the securities until maturity. At this time, Devon does not believe the values of its long-term securities are impaired.
Goodwill
Goodwill represents the excess of the purchase price of business combinations over the fair value of the net assets acquired and is tested for impairment at least annually. The impairment test requires allocating goodwill and all other assets and liabilities to assigned reporting units. The fair value of each reporting unit is estimated and compared to the net book value of the reporting unit. If the estimated fair value of the reporting unit is less than the net book value, including goodwill, then the goodwill is written down to the implied fair value of the goodwill through a charge to expense. Because quoted market prices are not available for Devon's reporting units, the fair values of the reporting units are estimated based upon several valuation analyses, including comparable companies, comparable transactions and premiums paid.
Devon performed annual impairment tests of goodwill in the fourth quarters of 2010, 2009 and 2008. Based on these assessments, no impairment of goodwill was required.
The table below provides a summary of Devon's goodwill, by assigned reporting unit, as of December 31, 2010 and 2009. The increase in Devon's continuing operations goodwill from 2009 to 2010 is due to changes in the exchange rate between the U.S. dollar and the Canadian dollar. Devon removed all its International goodwill in conjunction with the Azerbaijan divestiture that closed in 2010. Such goodwill was presented in long-term assets held for sale in the accompanying December 31, 2009 consolidated balance sheet.
|
December 31, | |
|
2010 |
2009 |
|
(In millions) | |
United States |
$ 3,046 |
$ 3,046 |
Canada |
3,034 |
2,884 |
Total (continuing operations) |
$ 6,080 |
$ 5,930 |
International (assets held for sale) |
$ — |
$ 68 |
Foreign Currency Translation Adjustments
The U.S. dollar is the functional currency for Devon's consolidated operations except its Canadian subsidiaries, which use the Canadian dollar as the functional currency. Therefore, the assets and liabilities of Devon's Canadian subsidiaries are translated into U.S. dollars based on the current exchange rate in effect at the balance sheet dates. Canadian income and expenses are translated at average rates for the periods presented. Translation adjustments have no effect on net income and are included in accumulated other comprehensive earnings in stockholders' equity. The following table presents the balances of Devon's cumulative translation adjustments included in accumulated other comprehensive earnings (in millions).
December 31, 2007 |
$ 2,566 |
December 31, 2008 |
$ 685 |
December 31, 2009 |
$ 1,616 |
December 31, 2010 |
$ 1,993 |
Commitments and Contingencies
Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Liabilities for environmental remediation or restoration claims are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. Expenditures related to such environmental matters are expensed or capitalized in accordance with Devon's accounting policy for property and equipment. Reference is made to Note 10 for a discussion of amounts recorded for these liabilities.
Revenue Recognition and Gas Balancing
Oil, gas and NGL sales are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectability of the revenue is probable. Delivery occurs and title is transferred when production has been delivered to a pipeline, railcar or truck or a tanker lifting has occurred. Cash received relating to future production is deferred and recognized when all revenue recognition criteria are met. Taxes assessed by governmental authorities on oil, gas and NGL sales are presented separately from such revenues in the accompanying consolidated statements of operations.
Devon follows the sales method of accounting for gas production imbalances. The volumes of gas sold may differ from the volumes to which Devon is entitled based on its interests in the properties. These differences create imbalances that are recognized as a liability only when the estimated remaining reserves will not be sufficient to enable the underproduced owner to recoup its entitled share through production. The liability is priced based on current market prices. No receivables are recorded for those wells where Devon has taken less than its share of production unless all revenue recognition criteria are met. If an imbalance exists at the time the wells' reserves are depleted, settlements are made among the joint interest owners under a variety of arrangements.
Marketing and midstream revenues are recorded at the time products are sold or services are provided to third parties at a fixed or determinable price, delivery or performance has occurred, title has transferred and collectability of the revenue is probable. Revenues and expenses attributable to oil, gas and NGL purchases, transportation and processing contracts are reported on a gross basis when Devon takes title to the products and has risks and rewards of ownership.
During 2010, 2009 and 2008, no purchaser accounted for more than 10% of Devon's revenues from continuing operations.
General and Administrative Expenses
General and administrative expenses are reported net of amounts reimbursed by working interest owners of the oil and gas properties operated by Devon and net of amounts capitalized pursuant to the full cost method of accounting.
Share Based Compensation
Devon grants stock options, restricted stock awards and other types of share-based awards to members of its Board of Directors and selected employees. All such awards are measured at fair value on the date of grant and are recognized as a component of general and administrative expenses in the accompanying statements of operations over the applicable requisite service periods. As a result of Devon's strategic repositioning announced in 2009, certain share based awards were accelerated and recognized as a component of restructuring expense in the accompanying 2010 and 2009 statements of operations.
Generally, Devon uses new shares to grant share-based awards and to issue shares upon stock option exercises. Shares repurchased under approved programs are available to be issued as part of Devon's share based awards. However, Devon has historically cancelled these shares upon repurchase.
Income Taxes
Devon is subject to current income taxes assessed by the federal and various state jurisdictions in the United States and by other foreign jurisdictions. In addition, Devon accounts for deferred income taxes related to these jurisdictions using the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases. Deferred tax assets are also recognized for the future tax benefits attributable to the expected utilization of existing tax net operating loss carryforwards and other types of carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.
Devon does not recognize United States deferred income taxes on the unremitted earnings of its foreign subsidiaries that are deemed to be permanently reinvested. When such earnings are no longer deemed permanently reinvested, Devon recognizes the appropriate deferred income tax liabilities.
Devon recognizes the financial statement effects of tax positions when it is more likely than not, based on the technical merits, that the position will be sustained upon examination by a taxing authority. Recognized tax positions are initially and subsequently measured as the largest amount of tax benefit that is more likely than not of being realized upon ultimate settlement with a taxing authority. Liabilities for unrecognized tax benefits related to such tax positions are included in other long-term liabilities unless the tax position is expected to be settled within the upcoming year, in which case the liabilities are included in other current liabilities. Interest and penalties related to unrecognized tax benefits are included in current income tax expense. Additional information regarding Devon's unrecognized tax benefits, including changes in such amounts during 2010 and 2009, is provided in Note 17.
Net Earnings (Loss) Per Common Share
Devon's basic earnings per share amounts have been computed based on the average number of shares of common stock outstanding for the period. Basic earnings per share includes the effect of participating securities, which primarily consist of Devon's outstanding restricted stock awards. Diluted earnings per share is calculated using the treasury stock method to reflect the potential dilution that could occur if Devon's dilutive outstanding stock options were exercised.
Cash and Cash Equivalents
Devon considers all highly liquid investments with original contractual maturities of three months or less to be cash equivalents.
|
|
December 31, | |
|
2010 |
2009 |
|
(In millions) | |
United States |
$ 3,046 |
$ 3,046 |
Canada |
3,034 |
2,884 |
Total (continuing operations) |
$ 6,080 |
$ 5,930 |
International (assets held for sale) |
$ — |
$ 68 |
December 31, 2007 |
$ 2,566 |
December 31, 2008 |
$ 685 |
December 31, 2009 |
$ 1,616 |
December 31, 2010 |
$ 1,993 |
|
|
December 31, | |
|
2010 |
2009 |
|
(In millions) | |
Oil, gas and NGL sales |
$ 786 |
$ 752 |
Joint interest billings |
182 |
151 |
Marketing and midstream revenues |
163 |
188 |
Production tax credits |
46 |
110 |
Other |
35 |
19 |
Gross accounts receivable |
1,212 |
1,220 |
Allowance for doubtful accounts |
(10) |
(12) |
Net accounts receivable |
$ 1,202 |
$ 1,208 |
|
December 31, | ||||
|
Balance Sheet Caption |
2010 |
2009 | |
|
|
(In millions) | ||
Asset derivatives: |
|
|
| |
Commodity derivatives |
Other current assets |
$ 248 |
$ 172 | |
Commodity derivatives |
Other long-term assets |
1 |
— | |
Interest rate derivatives |
Other current assets |
100 |
39 | |
Interest rate derivatives |
Other long-term assets |
40 |
131 | |
Total asset derivatives |
$ 389 |
$ 342 |
Liability derivatives: |
|
|
|
Commodity derivatives |
Other current liabilities |
$ 50 |
$ 38 |
Commodity derivatives |
Other long-term liabilities |
142 |
— |
Total liability derivatives |
$ 192 |
$ 38 |
|
Statement of Operations Caption |
2010 |
2009 |
2008 |
|
|
(In millions) | ||
Cash settlements: |
|
|
|
|
Commodity derivatives |
Oil, gas and NGL derivatives |
$ 888 |
$ 505 |
$ (397) |
Interest rate derivatives |
Interest-rate and other financial instruments |
44 |
40 |
1 |
Total cash settlements |
932 |
545 |
(396) | |
|
|
|
|
|
Unrealized gains (losses): |
|
|
|
|
Commodity derivatives |
Oil, gas and NGL derivatives |
(77) |
(121) |
243 |
Interest rate derivatives |
Interest-rate and other financial instruments |
(30) |
66 |
104 |
Embedded option |
Interest-rate and other financial instruments |
— |
— |
109 |
Total unrealized gains (losses) |
(107) |
(55) |
456 | |
Net gain recognized on statement of operations |
$ 825 |
$ 490 |
$ 60 |
|
|
December 31, | |
|
2010 |
2009 |
|
(In millions) | |
Derivative financial instruments |
$ 348 |
$ 211 |
Income tax receivable |
270 |
53 |
Short-term investments |
145 |
— |
Inventories |
120 |
182 |
Other |
41 |
35 |
Other current assets |
$ 924 |
$ 481 |
|
|
December 31, | |
|
2010 |
2009 |
|
(In millions) | |
Oil and gas properties: |
|
|
Subject to amortization |
$ 56,012 |
$ 52,352 |
Not subject to amortization |
3,434 |
4,078 |
Total |
59,446 |
56,430 |
Accumulated depreciation, depletion and amortization |
(42,676) |
(40,312) |
Net oil and gas properties |
16,770 |
16,118 |
|
|
|
Other property and equipment |
4,429 |
4,045 |
Accumulated depreciation and amortization |
(1,547) |
(1,396) |
Net other property and equipment |
2,882 |
2,649 |
Property and equipment, net |
$ 19,652 |
$ 18,767 |
|
Costs Incurred In | ||||
|
2010 |
2009 |
2008 |
Prior to 2008 |
Total |
|
(In millions) | ||||
Acquisition costs |
$ 1,188 |
$ 121 |
$ 1,049 |
$ 671 |
$ 3,029 |
Exploration costs |
130 |
40 |
39 |
5 |
214 |
Development costs |
159 |
1 |
9 |
— |
169 |
Capitalized interest |
22 |
— |
— |
— |
22 |
Total oil and gas properties not subject to amortization |
$ 1,499 |
$ 162 |
$ 1,097 |
$ 676 |
$ 3,434 |
|
Gross Proceeds |
After-Tax Proceeds |
Proved Reserves |
|
(In millions) |
(MMBoe) (Unaudited) | |
Gulf of Mexico (continuing operations) |
$ 4,145 |
$ 3,222 |
91 |
Azerbaijan (discontinued operations) |
2,000 |
1,925 |
56 |
China – Panyu (discontinued operations) |
515 |
405 |
13 |
China – Exploration (discontinued operations) |
77 |
59 |
— |
Other (discontinued operations) |
38 |
38 |
20 |
Total |
$ 6,775 |
$ 5,649 |
180 |
|
|
December 31, | |
|
2010 |
2009 |
|
(In millions) | |
Commercial paper |
$ — |
$ 1,432 |
Other debentures and notes: |
|
|
7.25% retired on June 25, 2010 |
— |
350 |
6.875% due September 30, 2011 |
1,750 |
1,750 |
5.625% due January 15, 2014 |
500 |
500 |
Non-interest bearing promissory note due June 29, 2014 |
144 |
— |
8.25% due July 1, 2018 |
125 |
125 |
6.30% due January 15, 2019 |
700 |
700 |
7.50% due September 15, 2027 |
150 |
150 |
7.875% due September 30, 2031 |
1,250 |
1,250 |
7.95% due April 15, 2032 |
1,000 |
1,000 |
Other |
9 |
10 |
Net premium on other debentures and notes |
2 |
12 |
Total debt |
5,630 |
7,279 |
Less amount classified as short-term debt |
1,811 |
1,432 |
Long-term debt |
$ 3,819 |
$ 5,847 |
2011 |
$ 1,812 |
2012 |
9 |
2013 |
— |
2014 |
582 |
2015 |
— |
2016 and thereafter |
3,225 |
Total |
$ 5,628 |
April 7, 2012 maturity |
$ 463 |
April 7, 2013 maturity |
2,187 |
Total Senior Credit Facility |
2,650 |
Less: |
|
Outstanding Senior Credit Facility borrowings |
— |
Outstanding commercial paper borrowings |
— |
Outstanding letters of credit |
38 |
Total available capacity |
$ 2,612 |
Debt Assumed |
Fair Value of Debt Assumed |
Effective Rate of Debt Assumed |
|
(In millions) |
|
8.250% due July 2018 (principal of $125 million) |
$ 147 |
5.5% |
7.500% due September 2027 (principal of $150 million) |
$ 169 |
6.5% |
|
Year Ended December 31, | ||
|
2010 |
2009 |
2008 |
|
(In millions) | ||
Interest based on debt outstanding |
$ 408 |
$ 437 |
$ 426 |
Capitalized interest |
(76) |
(94) |
(111) |
Early retirement of debt |
19 |
— |
— |
Other |
12 |
6 |
14 |
Total |
$ 363 |
$ 349 |
$ 329 |
|
|
Year Ended December 31, | |
|
2010 |
2009 |
|
(In millions) | |
Asset retirement obligations as of beginning of year |
$ 1,513 |
$ 1,387 |
Liabilities incurred |
55 |
56 |
Liabilities settled |
(129) |
(123) |
Revision of estimated obligation |
194 |
33 |
Liabilities assumed by others |
(269) |
(30) |
Accretion expense on discounted obligation |
92 |
91 |
Foreign currency translation adjustment |
41 |
99 |
Asset retirement obligations as of end of year |
1,497 |
1,513 |
Less current portion |
74 |
95 |
Asset retirement obligations, long-term |
$ 1,423 |
$ 1,418 |
|
|
Pension Benefits |
Other Postretirement Benefits | ||
|
2010 |
2009 |
2010 |
2009 |
|
(In millions) | |||
Change in benefit obligation: |
|
|
|
|
Benefit obligation at beginning of year |
$ 980 |
$ 931 |
$ 64 |
$ 56 |
Service cost |
33 |
43 |
1 |
1 |
Interest cost |
58 |
58 |
3 |
3 |
Actuarial loss (gain) |
82 |
4 |
1 |
7 |
Curtailment (gain) loss |
— |
(26) |
— |
1 |
Plan amendments |
5 |
— |
(22) |
— |
Foreign exchange rate changes |
2 |
5 |
— |
— |
Participant contributions |
— |
— |
2 |
2 |
Benefits paid |
(36) |
(35) |
(6) |
(6) |
Benefit obligation at end of year |
1,124 |
980 |
43 |
64 |
|
|
|
|
|
Change in plan assets: |
|
|
|
|
Fair value of plan assets at beginning of year |
532 |
430 |
— |
— |
Actual return on plan assets |
69 |
80 |
— |
— |
Employer contributions |
66 |
55 |
4 |
4 |
Participant contributions |
— |
— |
2 |
2 |
Benefits paid |
(36) |
(35) |
(6) |
(6) |
Foreign exchange rate changes |
1 |
2 |
— |
— |
Fair value of plan assets at end of year |
632 |
532 |
— |
— |
|
|
|
|
|
Funded status at end of year |
$ (492) |
$ (448) |
$ (43) |
$ (64) |
|
|
|
|
|
Amounts recognized in balance sheet: |
|
|
|
|
Noncurrent assets |
$ 2 |
$ 2 |
$ — |
$ — |
Current liabilities |
(9) |
(8) |
(4) |
(5) |
Noncurrent liabilities |
(485) |
(442) |
(39) |
(59) |
Net amount |
$ (492) |
$ (448) |
$ (43) |
$ (64) |
|
|
|
|
|
Amounts recognized in accumulated other comprehensive earnings: |
|
|
|
|
Net actuarial loss (gain) |
$ 357 |
$ 334 |
$ (5) |
$ (6) |
Prior service cost (credit) |
21 |
20 |
(12) |
11 |
Total |
$ 378 |
$ 354 |
$ (17) |
$ 5 |
|
December 31, | |
|
2010 |
2009 |
|
(In millions) | |
Projected benefit obligation |
$ 1,110 |
$ 967 |
Accumulated benefit obligation |
$ 996 |
$ 860 |
Fair value of plan assets |
$ 616 |
$ 517 |
|
Pension Benefits |
Other Postretirement Benefits | ||||
|
2010 |
2009 |
2008 |
2010 |
2009 |
2008 |
|
(In millions) | |||||
Net periodic benefit cost: |
|
|
|
|
|
|
Service cost |
$ 33 |
$ 43 |
$ 41 |
$ 1 |
$ 1 |
$ 1 |
Interest cost |
58 |
58 |
54 |
3 |
3 |
4 |
Expected return on plan assets |
(37) |
(35) |
(50) |
— |
— |
— |
Curtailment and settlement expense |
— |
5 |
— |
— |
1 |
— |
Recognition of net actuarial loss (gain) |
28 |
45 |
14 |
— |
(1) |
— |
Recognition of prior service cost |
3 |
3 |
2 |
1 |
2 |
2 |
Total net periodic benefit cost |
85 |
119 |
61 |
5 |
6 |
7 |
Other comprehensive earnings: |
|
|
|
|
|
|
Actuarial (gain) loss arising in current year |
49 |
(66) |
245 |
1 |
7 |
(15) |
Prior service cost (credit) arising in current year... |
5 |
— |
9 |
(22) |
— |
— |
Recognition of net actuarial (loss) gain in net periodic benefit cost |
(27) |
(45) |
(14) |
— |
1 |
— |
Recognition of prior service cost, including curtailment, in net periodic benefit cost |
(3) |
(8) |
(2) |
(1) |
(2) |
(2) |
Total other comprehensive earnings (loss) |
24 |
(119) |
238 |
(22) |
6 |
(17) |
Total recognized |
$ 109 |
$ — |
$ 299 |
$ (17) |
$ 12 |
$ (10) |
|
Pension Benefits |
Other Postretirement Benefits |
|
(In millions) | |
Net actuarial loss |
$ 32 |
$ — |
Prior service cost (credit) |
3 |
(2) |
Total |
$ 35 |
$ (2) |
|
Pension Benefits |
Other Postretirement Benefits | ||||
|
2010 |
2009 |
2008 |
2010 |
2009 |
2008 |
|
| |||||
Assumptions to determine benefit obligations: |
|
|
|
|
|
|
Discount rate |
5.50% |
6.00% |
6.00% |
4.90% |
5.70% |
6.00% |
Rate of compensation increase |
6.94% |
6.95% |
7.00% |
N/A |
N/A |
N/A |
Assumptions to determine net periodic benefit cost: |
|
|
|
|
|
|
Discount rate |
6.00% |
6.00% |
6.18% |
5.70% |
6.00% |
6.00% |
Expected return on plan assets |
6.94% |
7.18% |
8.40% |
N/A |
N/A |
N/A |
Rate of compensation increase |
6.94% |
6.95% |
7.00% |
N/A |
N/A |
N/A |
|
One Percent Increase |
One Percent Decrease |
|
(In millions) | |
Effect on benefit obligation |
$ 2 |
$ (2) |
Effect on service and interest costs |
$ — |
$ — |
|
As of December 31, 2010 | ||||
|
|
|
Fair Value Measurements Using: | ||
|
Actual Allocation |
Total |
Level 1 Inputs |
Level 2 Inputs |
Level 3 Inputs |
|
($ In millions) | ||||
Equity securities: |
|
|
|
|
|
United States large cap |
22.3% |
$ 141 |
$ — |
$ 141 |
$ — |
United States small cap |
14.1% |
89 |
89 |
— |
— |
International large cap |
14.4% |
91 |
50 |
41 |
— |
Total equity securities |
50.8% |
321 |
139 |
182 |
— |
Fixed-income securities: |
|
|
|
|
|
Corporate bonds |
22.0% |
139 |
139 |
— |
— |
United States Treasury obligations |
10.9% |
69 |
69 |
— |
— |
Other bonds |
4.6% |
29 |
29 |
— |
— |
Total fixed-income securities |
37.5% |
237 |
237 |
— |
— |
Other securities: |
|
|
|
|
|
Short-term investment funds |
2.5% |
16 |
— |
16 |
— |
Hedge funds |
9.2% |
58 |
— |
— |
58 |
Total other securities |
11.7% |
74 |
— |
16 |
58 |
Total investments |
100.0% |
$ 632 |
$ 376 |
$ 198 |
$ 58 |
|
As of December 31, 2009 | ||||
|
|
|
Fair Value Measurements Using: | ||
|
Actual Allocation |
Total |
Level 1 Inputs |
Level 2 Inputs |
Level 3 Inputs |
|
(In millions) | ||||
Equity securities: |
|
|
|
|
|
United States large cap |
18.8% |
$ 100 |
$ — |
$ 100 |
$ — |
United States small cap |
15.2% |
81 |
81 |
— |
— |
International large cap |
15.2% |
81 |
44 |
37 |
— |
Total equity securities |
49.2% |
262 |
125 |
137 |
— |
Fixed-income securities: |
|
|
|
|
|
Corporate bonds |
25.1% |
133 |
133 |
— |
— |
United States Treasury obligations |
9.8% |
52 |
52 |
— |
— |
Other bonds |
3.9% |
21 |
21 |
— |
— |
Total fixed-income securities |
38.8% |
206 |
206 |
— |
— |
Other securities: |
|
|
|
|
|
Short-term investment funds |
2.4% |
13 |
— |
13 |
— |
Hedge funds |
9.6% |
51 |
— |
— |
51 |
Total other securities |
12.0% |
64 |
— |
13 |
51 |
Total investments |
100.0% |
$ 532 |
$ 331 |
$ 150 |
$ 51 |
|
Hedge Funds |
|
(In millions) |
December 31, 2008 |
$ — |
Purchases |
51 |
December 31, 2009 |
51 |
Purchases |
3 |
Investment returns |
4 |
December 31, 2010 |
$ 58 |
|
Pension Benefits |
Other Postretirement Benefits |
|
(In millions) | |
Devon's 2011 contributions |
$ 93 |
$ 4 |
Benefit payments: |
|
|
2011 |
$ 42 |
$ 4 |
2012 |
$ 45 |
$ 4 |
2013 |
$ 49 |
$ 4 |
2014 |
$ 52 |
$ 4 |
2015 |
$ 54 |
$ 4 |
2016 to 2020 |
$ 328 |
$ 21 |
|
Year Ended December 31, | ||
|
2010 |
2009 |
2008 |
|
(In millions) | ||
401(k) plan |
$ 18 |
$ 20 |
$ 21 |
Enhanced contribution plan |
14 |
14 |
12 |
Canadian pension and savings plans |
17 |
15 |
16 |
Total expense |
$ 49 |
$ 49 |
$ 49 |
|
|
2010 |
2008 | ||||
Repurchase Program |
Amount |
Shares |
Per Share |
Amount |
Shares |
Per Share |
2010 program |
$ 1,201 |
18.3 |
$ 65.58 |
$ — |
— |
$ — |
Annual program |
— |
— |
— |
178 |
2.0 |
$ 87.83 |
2007 program |
— |
— |
— |
487 |
4.5 |
$ 109.25 |
Totals |
$ 1,201 |
18.3 |
$ 65.58 |
$ 665 |
6.5 |
$ 102.56 |
|
Year Ending December 31, |
Purchase Obligations |
Drilling and Facility Obligations |
Firm Transportation Agreements |
Office and Equipment Leases |
FPSO Lease |
|
(In millions) | ||||
Continuing operations: |
|
|
|
|
|
2011 |
$ 551 |
$ 747 |
$ 282 |
$ 58 |
$ — |
2012 |
708 |
280 |
254 |
56 |
— |
2013 |
763 |
130 |
233 |
48 |
— |
2014 |
784 |
6 |
218 |
39 |
— |
2015 |
784 |
— |
190 |
38 |
— |
Thereafter |
4,120 |
— |
557 |
250 |
— |
Total |
7,710 |
1,163 |
1,734 |
489 |
— |
Discontinued operations: |
|
|
|
|
|
2011 |
— |
314 |
— |
9 |
29 |
2012 |
— |
171 |
— |
— |
29 |
2013 |
— |
110 |
— |
— |
29 |
2014 |
— |
— |
— |
— |
15 |
Total |
— |
595 |
— |
9 |
102 |
Total operations |
$ 7,710 |
$ 1,758 |
$ 1,734 |
$ 498 |
$ 102 |
|
|
|
|
Fair Value Measurements Using: | ||
|
Carrying Amount |
Total Fair Value |
Level 1 Inputs |
Level 2 Inputs |
Level 3 Inputs |
|
(In millions) | ||||
December 31, 2010 assets (liabilities): |
|
|
|
|
|
Commodity asset derivatives |
$ 249 |
$ 249 |
$ — |
$ 249 |
$ — |
Commodity liability derivatives |
$ (192) |
$ (192) |
$ — |
$ (192) |
$ — |
Interest rate derivatives |
$ 140 |
$ 140 |
$ — |
$ 140 |
$ — |
Debt |
$ (5,630) |
$ (6,629) |
$ — |
$ (6,485) |
$ (144) |
Long-term investments |
$ 94 |
$ 94 |
$ — |
$ — |
$ 94 |
Short-term investments |
$ 145 |
$ 145 |
$ 145 |
$ — |
$ — |
December 31, 2009 assets (liabilities): |
|
|
|
|
|
Commodity asset derivatives |
$ 172 |
$ 172 |
$ — |
$ 172 |
$ — |
Commodity liability derivatives |
$ (38) |
$ (38) |
$ — |
$ (38) |
$ — |
Interest rate derivatives |
$ 170 |
$ 170 |
$ — |
$ 170 |
$ — |
Debt |
$ (7,279) |
$ (8,214) |
$ (1,432) |
$ (6,782) |
$ — |
Long-term investments |
$ 115 |
$ 115 |
$ — |
$ — |
$ 115 |
|
Debt |
Long-Term Investments |
|
(In millions) | |
December 31, 2008 |
$ — |
$ 122 |
Redemptions of principal |
— |
(7) |
December 31, 2009 |
— |
115 |
Issuance of promissory note |
(139) |
— |
Foreign exchange translation adjustment |
(9) |
— |
Accretion of promissory note |
(3) |
— |
Redemptions of principal |
7 |
(21) |
December 31, 2010 |
$ (144) |
$ 94 |
|
|
Year Ended December 31, 2010 |
Year Ended December 31, 2009 | ||||
|
Continuing Operations |
Discontinued Operations |
Total |
Continuing Operations |
Discontinued Operations |
Total |
|
(In millions) | |||||
Cash severance |
$ (17) |
$ 1 |
$ (16) |
$ 66 |
$ 24 |
$ 90 |
Share-based awards |
(10) |
(5) |
(15) |
39 |
24 |
63 |
Lease obligations |
70 |
— |
70 |
— |
— |
— |
Asset impairments |
11 |
— |
11 |
— |
— |
— |
Other |
3 |
— |
3 |
— |
— |
— |
Restructuring costs |
$ 57 |
$ (4) |
$ 53 |
$ 105 |
$ 48 |
$ 153 |
|
Other Current Liabilities |
Other Long-Term Liabilities | ||||
|
Continuing Operations |
Discontinued Operations |
Total |
Continuing Operations |
Discontinued Operations |
Total |
|
(In millions) | |||||
Balance as of December 31, 2008 |
$ — |
$ — |
$ — |
$ — |
$ — |
$ — |
Cash severance accrual |
61 |
23 |
84 |
— |
— |
— |
Balance as of December 31, 2009 |
61 |
23 |
84 |
— |
— |
— |
Lease obligations incurred |
17 |
— |
17 |
50 |
— |
50 |
Cash severance paid |
(30) |
(8) |
(38) |
— |
— |
— |
Cash severance revision |
(17) |
1 |
(16) |
— |
— |
— |
Other |
— |
— |
— |
1 |
— |
1 |
Balance as of December 31, 2010 |
$ 31 |
$ 16 |
$ 47 |
$ 51 |
$ — |
$ 51 |
|
|
Year Ended December 31, | ||
|
2010 |
2009 |
2008 |
|
(In millions) | ||
(Gains) and losses from: |
|
|
|
Interest rate swaps – settlements (See Note 3) |
$ (44) |
$ (40) |
$ (1) |
Interest rate swaps – fair value changes (See Note 3) |
30 |
(66) |
(104) |
Chevron common stock |
— |
— |
363 |
Option embedded in exchangeable debentures |
— |
— |
(109) |
Total |
$ (14) |
$ (106) |
$ 149 |
|
|
Year Ended December 31, | |||
|
2009 |
2008 | ||
|
Gross |
After Taxes |
Gross |
After Taxes |
|
(In millions) | |||
|
|
|
|
|
United States |
$ 6,408 |
$ 4,085 |
$ 6,538 |
$ 4,168 |
Canada |
— |
— |
3,353 |
2,488 |
Total |
$ 6,408 |
$ 4,085 |
$ 9,891 |
$ 6,656 |
|
|
Year Ended December 31, | ||
|
2010 |
2009 |
2008 |
|
(In millions) | ||
Interest and dividend income |
$ (13) |
$ (8) |
$ (54) |
Deep water royalties |
— |
(84) |
— |
Hurricane insurance proceeds |
— |
— |
(162) |
Other |
(32) |
24 |
(1) |
Total |
$ (45) |
$ (68) |
$ (217) |
|
|
Year Ended December 31, | ||
|
2010 |
2009 |
2008 |
|
(In millions) | ||
Earnings (loss) from continuing operations before income taxes: |
|
|
|
U.S |
$ 2,943 |
$ (4,961) |
$ (2,190) |
Canada |
625 |
435 |
(1,970) |
Total |
$ 3,568 |
$ (4,526) |
$ (4,160) |
Current income tax expense: |
|
|
|
U.S. federal |
$ 244 |
$ 45 |
$ 258 |
Various states |
16 |
18 |
31 |
Canada and various provinces |
256 |
178 |
152 |
Total current tax expense |
516 |
241 |
441 |
Deferred income tax expense (benefit): |
|
|
|
U.S. federal |
781 |
(1,846) |
(875) |
Various states |
21 |
(111) |
(65) |
Canada and various provinces |
(83) |
(57) |
(622) |
Total deferred tax expense (benefit) |
719 |
(2,014) |
(1,562) |
Total income tax expense (benefit) |
$ 1,235 |
$ (1,773) |
$ (1,121) |
|
Year Ended December 31, | ||
|
2010 |
2009 |
2008 |
|
(In millions) | ||
Expected income tax expense (benefit) based on U.S. statutory tax rate of 35% |
$ 1,249 |
$ (1,584) |
$ (1,456) |
Repatriations and assumed repatriations |
144 |
55 |
312 |
State income taxes |
31 |
(99) |
(29) |
Taxation on Canadian operations |
(60) |
(31) |
227 |
Other |
(129) |
(114) |
(175) |
Total income tax expense (benefit) |
$ 1,235 |
$ (1,773) |
$ (1,121) |
|
December 31, | |
|
2010 |
2009 |
|
(In millions) | |
Deferred tax assets: |
|
|
Net operating loss carryforwards |
$ 159 |
$ 11 |
Asset retirement obligations |
494 |
474 |
Pension benefit obligations |
133 |
130 |
Other |
171 |
133 |
Total deferred tax assets |
957 |
748 |
Deferred tax liabilities: |
|
|
Property and equipment, principally due to nontaxable business combinations, differences in depreciation, and the expensing of intangible drilling costs for tax purposes |
(3,130) |
(2,315) |
Fair value of financial instruments |
(70) |
(108) |
Long-term debt |
(198) |
(162) |
Taxes on unremitted foreign earnings ( |
(211) |
(55) |
Other |
(20) |
(7) |
Total deferred tax liabilities |
(3,629) |
(2,647) |
Net deferred tax liability |
$ (2,672) |
$ (1,899) |
|
2010 |
2009 |
|
(In millions) | |
Balance at beginning of year |
$ 272 |
$ 260 |
Tax positions taken in prior periods |
40 |
— |
Tax positions taken in current year |
5 |
20 |
Accrual of interest related to tax positions taken |
9 |
7 |
Lapse of statute of limitations |
(5) |
(15) |
Settlements |
(129) |
(5) |
Foreign currency translation |
2 |
5 |
Balance at end of year |
$ 194 |
$ 272 |
Jurisdiction |
Tax Years Open |
U.S. federal |
2005-2010 |
Various U.S. states |
2005-2010 |
Canada federal |
2003-2010 |
Various Canadian provinces |
2003-2010 |
|
|
Year Ended December 31, | |||||
|
2010 |
2009 |
2008 | |||
|
Gross |
After Taxes |
Gross |
After Taxes |
Gross |
After Taxes |
|
(In millions) | |||||
Azerbaijan |
$ 1,543 |
$ 1,524 |
$ — |
$ — |
$ — |
$ — |
China - Panyu |
308 |
235 |
— |
— |
— |
— |
Equatorial Guinea |
— |
— |
— |
— |
619 |
544 |
Gabon |
— |
— |
— |
— |
117 |
122 |
Cote d'Ivoire |
— |
— |
17 |
17 |
83 |
95 |
Other |
(33) |
(27) |
— |
— |
— |
8 |
Total |
$ 1,818 |
$ 1,732 |
$ 17 |
$ 17 |
$ 819 |
$ 769 |
|
December 31, | |
|
2010 |
2009 |
|
(In millions) | |
Cash and cash equivalents |
$ 424 |
$ 365 |
Accounts receivable |
43 |
165 |
Other current assets |
96 |
127 |
Current assets |
$ 563 |
$ 657 |
|
|
|
Property and equipment, net |
$ 848 |
$ 1,099 |
Goodwill |
— |
68 |
Other long-term assets |
11 |
83 |
Total long-term assets |
$ 859 |
$ 1,250 |
|
|
|
Accounts payable |
$ 260 |
$ 158 |
Other current liabilities |
45 |
76 |
Current liabilities |
$ 305 |
$ 234 |
|
|
|
Asset retirement obligations |
$ 24 |
$ 109 |
Deferred income taxes |
2 |
101 |
Other liabilities |
— |
3 |
Long-term liabilities |
$ 26 |
$ 213 |
|
Year Ended December 31, | ||||
|
2009 |
2008 | |||
|
Gross |
After Taxes |
Gross |
After Taxes | |
|
(In millions) |
(In millions) | |||
Brazil |
$ 103 |
$ 103 |
$ 437 |
$ 437 | |
Other |
6 |
2 |
57 |
28 | |
Total |
$ 109 |
$ 105 |
$ 494 |
$ 465 | |
|
|
U.S. |
Canada |
International |
Total |
|
(In millions) | |||
As of December 31, 2010: |
|
|
|
|
Current assets |
$ 2,473 |
$ 2,519 |
$ 563 |
$ 5,555 |
Property and equipment, net |
12,379 |
7,273 |
— |
19,652 |
Goodwill |
3,046 |
3,034 |
— |
6,080 |
Other assets |
422 |
359 |
859 |
1,640 |
Total assets |
$ 18,320 |
$ 13,185 |
$ 1,422 |
$ 32,927 |
Current liabilities |
$ 1,701 |
$ 2,577 |
$ 305 |
$ 4,583 |
Long-term debt |
2,502 |
1,317 |
— |
3,819 |
Asset retirement obligations |
566 |
857 |
— |
1,423 |
Other liabilities |
1,005 |
62 |
26 |
1,093 |
Deferred income taxes |
1,571 |
1,185 |
— |
2,756 |
Stockholders' equity |
10,975 |
7,187 |
1,091 |
19,253 |
Total liabilities and stockholders' equity |
$ 18,320 |
$ 13,185 |
$ 1,422 |
$ 32,927 |
|
U.S. |
Canada |
International |
Total |
|
(In millions) | |||
As of December 31, 2009: |
|
|
|
|
Current assets |
$ 1,449 |
$ 886 |
$ 657 |
$ 2,992 |
Property and equipment, net |
13,199 |
5,568 |
— |
18,767 |
Goodwill |
3,046 |
2,884 |
— |
5,930 |
Other assets |
674 |
73 |
1,250 |
1,997 |
Total assets |
$ 18,368 |
$ 9,411 |
$ 1,907 |
$ 29,686 |
Current liabilities |
$ 2,993 |
$ 575 |
$ 234 |
$ 3,802 |
Long-term debt |
2,866 |
2,981 |
— |
5,847 |
Asset retirement obligations |
754 |
664 |
— |
1,418 |
Other liabilities |
890 |
47 |
213 |
1,150 |
Deferred income taxes |
860 |
1,039 |
— |
1,899 |
Stockholders' equity |
10,005 |
4,105 |
1,460 |
15,570 |
Total liabilities and stockholders' equity |
$ 18,368 |
$ 9,411 |
$ 1,907 |
$ 29,686 |
|
U.S. |
Canada |
Total |
|
(In millions) | ||
Year Ended December 31, 2010: |
|
|
|
Revenues: |
|
|
|
Oil, gas and NGL sales |
$ 4,742 |
$ 2,520 |
$ 7,262 |
Oil, gas and NGL derivatives |
809 |
2 |
811 |
Marketing and midstream revenues |
1,742 |
125 |
1,867 |
Total revenues |
7,293 |
2,647 |
9,940 |
Expenses and other, net: |
|
|
|
Lease operating expenses |
892 |
797 |
1,689 |
Taxes other than income taxes |
341 |
39 |
380 |
Marketing and midstream operating costs and expenses... |
1,256 |
101 |
1,357 |
Depreciation, depletion and amortization of oil and gas properties |
998 |
677 |
1,675 |
Depreciation and amortization of non-oil and gas properties |
231 |
24 |
255 |
Accretion of asset retirement obligations |
42 |
50 |
92 |
General and administrative expenses |
433 |
130 |
563 |
Restructuring costs |
57 |
— |
57 |
Interest expense |
159 |
204 |
363 |
Interest-rate and other financial instruments |
(14) |
— |
(14) |
Other, net |
(45) |
— |
(45) |
Total expenses and other, net |
4,350 |
2,022 |
6,372 |
Earnings from continuing operations before income taxes.. |
2,943 |
625 |
3,568 |
Income tax expense (benefit): |
|
|
|
Current |
260 |
256 |
516 |
Deferred |
802 |
(83) |
719 |
Total income tax expense |
1,062 |
173 |
1,235 |
Earnings from continuing operations |
$ 1,881 |
$ 452 |
$ 2,333 |
|
|
|
|
Capital expenditures, before revision of future asset retirement obligations |
$ 4,935 |
$ 1,985 |
$ 6,920 |
Revision of future asset retirement obligations |
72 |
122 |
194 |
Capital expenditures, continuing operations |
$ 5,007 |
$ 2,107 |
$ 7,114 |
|
U.S. |
Canada |
Total |
|
(In millions) | ||
Year Ended December 31, 2009: |
|
|
|
Revenues: |
|
|
|
Oil, gas and NGL sales |
$ 3,958 |
$ 2,139 |
$ 6,097 |
Oil, gas and NGL derivatives |
382 |
2 |
384 |
Marketing and midstream revenues |
1,498 |
36 |
1,534 |
Total revenues |
5,838 |
2,177 |
8,015 |
Expenses and other, net: |
|
|
|
Lease operating expenses |
997 |
673 |
1,670 |
Taxes other than income taxes |
278 |
36 |
314 |
Marketing and midstream operating costs and expenses... |
1,004 |
18 |
1,022 |
Depreciation, depletion and amortization of oil and gas properties |
1,247 |
585 |
1,832 |
Depreciation and amortization of non-oil and gas properties |
251 |
25 |
276 |
Accretion of asset retirement obligations |
53 |
38 |
91 |
General and administrative expenses |
529 |
119 |
648 |
Restructuring costs |
105 |
— |
105 |
Interest expense |
125 |
224 |
349 |
Interest-rate and other financial instruments |
(106) |
— |
(106) |
Reduction of carrying value of oil and gas properties |
6,408 |
— |
6,408 |
Other, net |
(92) |
24 |
(68) |
Total expenses and other, net |
10,799 |
1,742 |
12,541 |
(Loss) earnings from continuing operations before income taxes |
(4,961) |
435 |
(4,526) |
Income tax (benefit) expense: |
|
|
|
Current |
63 |
178 |
241 |
Deferred |
(1,957) |
(57) |
(2,014) |
Total income tax (benefit) expense |
(1,894) |
121 |
(1,773) |
(Loss) earnings from continuing operations |
$ (3,067) |
$ 314 |
$ (2,753) |
|
|
|
|
Capital expenditures, before revision of future asset retirement obligations |
$ 3,536 |
$ 1,114 |
$ 4,650 |
Revision of future asset retirement obligations |
48 |
(15) |
33 |
Capital expenditures, continuing operations |
$ 3,584 |
$ 1,099 |
$ 4,683 |
|
U.S. |
Canada |
Total |
|
(In millions) | ||
Year Ended December 31, 2008: |
|
|
|
Revenues: |
|
|
|
Oil, gas and NGL sales |
$ 8,206 |
$ 3,514 |
$ 11,720 |
Oil, gas and NGL derivatives |
(154) |
— |
(154) |
Marketing and midstream revenues |
2,247 |
45 |
2,292 |
Total revenues |
10,299 |
3,559 |
13,858 |
Expenses and other, net: |
|
|
|
Lease operating expenses |
1,075 |
776 |
1,851 |
Taxes other than income taxes |
438 |
38 |
476 |
Marketing and midstream operating costs and expenses... |
1,593 |
18 |
1,611 |
Depreciation, depletion and amortization of oil and gas properties |
1,998 |
950 |
2,948 |
Depreciation and amortization of non-oil and gas properties |
229 |
26 |
255 |
Accretion of asset retirement obligations |
42 |
38 |
80 |
General and administrative expenses |
513 |
132 |
645 |
Interest expense |
117 |
212 |
329 |
Interest-rate and other financial instruments |
149 |
— |
149 |
Reduction of carrying value of oil and gas properties |
6,538 |
3,353 |
9,891 |
Other, net |
(203) |
(14) |
(217) |
Total expenses and other, net |
12,489 |
5,529 |
18,018 |
Loss from continuing operations before income taxes |
(2,190) |
(1,970) |
(4,160) |
Income tax (benefit) expense: |
|
|
|
Current |
289 |
152 |
441 |
Deferred |
(940) |
(622) |
(1,562) |
Total income tax benefit |
(651) |
(470) |
(1,121) |
Loss from continuing operations |
$ (1,539) |
$ (1,500) |
$ (3,039) |
|
|
|
|
Capital expenditures, before revision of future asset retirement obligations |
$ 8,313 |
$ 1,639 |
$ 9,952 |
Revision of future asset retirement obligations |
152 |
73 |
225 |
Capital expenditures, continuing operations |
$ 8,465 |
$ 1,712 |
$ 10,177 |
|
|
Year Ended December 31, | ||
|
2010 |
2009 |
2008 |
|
(In millions) | ||
Net decrease (increase) in working capital: |
|
|
|
Decrease in accounts receivable |
$ 23 |
$ 142 |
$ 187 |
Decrease (increase) in other current assets |
21 |
212 |
(46) |
Increase (decrease) in accounts payable |
37 |
(91) |
159 |
Increase in revenues and royalties due to others |
48 |
— |
11 |
Decrease in income taxes payable |
(203) |
(48) |
(309) |
Decrease in other current liabilities |
(199) |
(66) |
(209) |
Net (increase) decrease in working capital |
$ (273) |
$ 149 |
$ (207) |
|
|
|
|
Supplementary cash flow data – total operations: |
|
|
|
Interest paid (net of capitalized interest) |
$ 359 |
$ 314 |
$ 336 |
Income taxes paid |
$ 955 |
$ 68 |
$ 1,436 |
|
|
|
|
Noncash investing activity – exchange of investment in Chevron common stock for oil and gas properties |
$ — |
$ — |
$ 610 |
|
|
Year Ended December 31, 2010 | ||||
|
U.S. Onshore |
U.S. Offshore |
Total U.S. |
Canada |
North America |
Property acquisition costs: |
(In millions) | ||||
Proved properties |
$ 29 |
$ — |
$ 29 |
$ 4 |
$ 33 |
Unproved properties |
592 |
2 |
594 |
590 |
1,184 |
Exploration costs |
339 |
89 |
428 |
260 |
688 |
Development costs |
3,126 |
297 |
3,423 |
1,216 |
4,639 |
Costs incurred |
$ 4,086 |
$ 388 |
$ 4,474 |
$ 2,070 |
$ 6,544 |
|
Year Ended December 31, 2009 | ||||
|
U.S. Onshore |
U.S. Offshore |
Total U.S. |
Canada |
North America |
Property acquisition costs: |
(In millions) | ||||
Proved properties |
$ 17 |
$ — |
$ 17 |
$ 18 |
$ 35 |
Unproved properties |
52 |
11 |
63 |
72 |
135 |
Exploration costs |
122 |
260 |
382 |
152 |
534 |
Development costs |
2,011 |
537 |
2,548 |
835 |
3,383 |
Costs incurred |
$ 2,202 |
$ 808 |
$ 3,010 |
$ 1,077 |
$ 4,087 |
|
Year Ended December 31, 2008 | ||||
|
U.S. Onshore |
U.S. Offshore |
Total U.S. |
Canada |
North America |
Property acquisition costs: |
(In millions) | ||||
Proved properties |
$ 822 |
$ — |
$ 822 |
$ — |
$ 822 |
Unproved properties |
1,226 |
185 |
1,411 |
352 |
1,763 |
Exploration costs |
206 |
638 |
844 |
173 |
1,017 |
Development costs |
4,182 |
551 |
4,733 |
1,131 |
5,864 |
Costs incurred |
$ 6,436 |
$ 1,374 |
$ 7,810 |
$ 1,656 |
$ 9,466 |
|
Year Ended December 31, 2010 | ||
|
United States |
Canada |
North America |
|
(In millions) | ||
Oil, gas and NGL sales |
$ 4,742 |
$ 2,520 |
$ 7,262 |
Lease operating expenses |
(892) |
(797) |
(1,689) |
Taxes other than income taxes |
(319) |
(40) |
(359) |
Depreciation, depletion and amortization |
(998) |
(677) |
(1,675) |
Accretion of asset retirement obligations |
(42) |
(50) |
(92) |
General and administrative expenses |
(133) |
(83) |
(216) |
Income tax expense |
(849) |
(246) |
(1,095) |
Results of operations |
$ 1,509 |
$ 627 |
$ 2,136 |
Depreciation, depletion and amortization per Boe |
$ 6.11 |
$ 10.51 |
$ 7.36 |
|
Year Ended December 31, 2009 | ||
|
United States |
Canada |
North America |
|
(In millions) | ||
Oil, gas and NGL sales |
$ 3,958 |
$ 2,139 |
$ 6,097 |
Lease operating expenses |
(997) |
(673) |
(1,670) |
Taxes other than income taxes |
(258) |
(35) |
(293) |
Depreciation, depletion and amortization |
(1,247) |
(585) |
(1,832) |
Accretion of asset retirement obligations |
(53) |
(38) |
(91) |
General and administrative expenses |
(145) |
(74) |
(219) |
Reduction of carrying value of oil and gas properties |
(6,408) |
— |
(6,408) |
Income tax benefit (expense) |
1,800 |
(210) |
1,580 |
Results of operations |
$ (3,350) |
$ 524 |
$ (2,836) |
Depreciation, depletion and amortization per Boe |
$ 7.47 |
$ 8.84 |
$ 7.86 |
|
Year Ended December 31, 2008 | ||
|
United States |
Canada |
North America |
|
(In millions) | ||
Oil, gas and NGL sales |
$ 8,206 |
$ 3,514 |
$ 11,720 |
Lease operating expenses |
(1,075) |
(776) |
(1,851) |
Taxes other than income taxes |
(420) |
(37) |
(457) |
Depreciation, depletion and amortization |
(1,998) |
(950) |
(2,948) |
Accretion of asset retirement obligations |
(42) |
(38) |
(80) |
General and administrative expenses |
(148) |
(87) |
(235) |
Reduction of carrying value of oil and gas properties |
(6,538) |
(3,353) |
(9,891) |
Income tax benefit |
719 |
405 |
1,124 |
Results of operations |
$ (1,296) |
$ (1,322) |
$ (2,618) |
Depreciation, depletion and amortization per Boe |
$ 12.31 |
$ 15.59 |
$ 13.20 |
|
2010 |
2009 |
2008 | |||
|
Prepared |
Audited |
Prepared |
Audited |
Prepared |
Audited |
U.S. Onshore. |
|
94% |
|
93% |
|
92% |
U.S. Offshore. |
N/A |
N/A |
100% |
|
100% |
|
U.S.. |
|
94% |
5% |
89% |
5% |
87% |
Canada |
|
89% |
|
91% |
|
78% |
North America. |
|
93% |
3% |
89% |
4% |
85% |
____________________________
N/A Not applicable Devon sold its U.S. Offshore properties during 2010.
|
Year Ended December 31, 2010 | ||
|
United States |
Canada |
North America |
|
(In millions) | ||
Future cash inflows |
$ 58,093 |
$ 35,948 |
$ 94,041 |
Future costs: |
|
|
|
Development |
(6,220) |
(4,526) |
(10,746) |
Production |
(24,223) |
(12,249) |
(36,472) |
Future income tax expense |
(8,643) |
(4,209) |
(12,852) |
Future net cash flows |
19,007 |
14,964 |
33,971 |
10% discount to reflect timing of cash flows |
(10,164) |
(7,455) |
(17,619) |
Standardized measure of discounted future net cash flows |
$ 8,843 |
$ 7,509 |
$ 16,352 |
|
Year Ended December 31, 2009 | ||
|
United States |
Canada |
North America |
|
(In millions) | ||
Future cash inflows |
$ 44,571 |
$ 28,442 |
$ 73,013 |
Future costs: |
|
|
|
Development |
(6,814) |
(4,132) |
(10,946) |
Production |
(22,184) |
(9,847) |
(32,031) |
Future income tax expense |
(3,572) |
(3,408) |
(6,980) |
Future net cash flows |
12,001 |
11,055 |
23,056 |
10% discount to reflect timing of cash flows |
(6,121) |
(5,532) |
(11,653) |
Standardized measure of discounted future net cash flows |
$ 5,880 |
$ 5,523 |
$ 11,403 |
|
Year Ended December 31, 2008 | ||
|
United States |
Canada |
North America |
|
(In millions) | ||
Future cash inflows |
$ 51,284 |
$ 11,459 |
$ 62,743 |
Future costs: |
|
|
|
Development |
(6,887) |
(1,623) |
(8,510) |
Production |
(24,113) |
(5,742) |
(29,855) |
Future income tax expense |
(5,585) |
(942) |
(6,527) |
Future net cash flows |
14,699 |
3,152 |
17,851 |
10% discount to reflect timing of cash flows |
(7,318) |
(1,140) |
(8,458) |
Standardized measure of discounted future net cash flows |
$ 7,381 |
$ 2,012 |
$ 9,393 |
|
Year Ended December 31, | ||
|
2010 |
2009 |
2008 |
|
(In millions) | ||
Beginning balance |
$ 11,403 |
$ 9,393 |
$ 20,582 |
Oil, gas and NGL sales, net of production costs |
(4,982) |
(3,915) |
(9,177) |
Net changes in prices and production costs |
7,423 |
(1,672) |
(13,839) |
Extensions and discoveries, net of future development costs |
3,048 |
2,378 |
1,729 |
Purchase of reserves, net of future development costs |
23 |
6 |
214 |
Development costs incurred that reduced future development costs |
1,559 |
1,012 |
1,660 |
Revisions of quantity estimates |
287 |
4,051 |
(1,294) |
Sales of reserves in place |
(815) |
(37) |
(2) |
Accretion of discount |
1,487 |
1,281 |
2,894 |
Net change in income taxes |
(2,663) |
(51) |
4,934 |
Other, primarily changes in timing and foreign exchange rates |
(418) |
(1,043) |
1,692 |
Ending balance |
$ 16,352 |
$ 11,403 |
$ 9,393 |
|
Oil (MMBbls) | ||||
|
U.S. Onshore |
U.S. Offshore |
Total U.S. |
Canada |
North America |
Proved developed and undeveloped reserves: |
|
|
|
|
|
December 31, 2007 |
131 |
39 |
170 |
388 |
558 |
Revisions due to prices |
(17) |
(3) |
(20) |
(349) |
(369) |
Revisions other than price |
2 |
3 |
5 |
2 |
7 |
Extensions and discoveries |
11 |
1 |
12 |
120 |
132 |
Purchase of reserves |
18 |
— |
18 |
— |
18 |
Production |
(11) |
(6) |
(17) |
(22) |
(39) |
Sale of reserves |
(1) |
— |
(1) |
(5) |
(6) |
December 31, 2008 |
133 |
34 |
167 |
134 |
301 |
Revisions due to prices |
9 |
2 |
11 |
291 |
302 |
Revisions other than price |
— |
1 |
1 |
(8) |
(7) |
Extensions and discoveries |
9 |
2 |
11 |
122 |
133 |
Purchase of reserves |
— |
— |
— |
— |
— |
Production |
(12) |
(5) |
(17) |
(25) |
(42) |
Sale of reserves |
— |
(1) |
(1) |
— |
(1) |
December 31, 2009 |
139 |
33 |
172 |
514 |
686 |
Revisions due to prices |
4 |
1 |
5 |
(24) |
(19) |
Revisions other than price |
2 |
2 |
4 |
9 |
13 |
Extensions and discoveries |
19 |
1 |
20 |
59 |
79 |
Purchase of reserves |
— |
— |
— |
— |
— |
Production |
(14) |
(2) |
(16) |
(25) |
(41) |
Sale of reserves |
(2) |
(35) |
(37) |
— |
(37) |
December 31, 2010 |
148 |
— |
148 |
533 |
681 |
Proved developed reserves as of: |
|
|
|
|
|
December 31, 2007 |
122 |
26 |
148 |
195 |
343 |
December 31, 2008 |
111 |
22 |
133 |
110 |
243 |
December 31, 2009 |
119 |
21 |
140 |
149 |
289 |
December 31, 2010 |
131 |
— |
131 |
126 |
257 |
Proved undeveloped reserves as of: |
|
|
|
|
|
December 31, 2007 |
9 |
13 |
22 |
193 |
215 |
December 31, 2008 |
22 |
12 |
34 |
24 |
58 |
December 31, 2009 |
20 |
12 |
32 |
365 |
397 |
December 31, 2010 |
17 |
— |
17 |
407 |
424 |
|
Gas (Bcf) | ||||
|
U.S. Onshore |
U.S. Offshore |
Total U.S. |
Canada |
North America |
Proved developed and undeveloped reserves: |
|
|
|
|
|
December 31, 2007 |
6,765 |
378 |
7,143 |
1,844 |
8,987 |
Revisions due to prices |
(367) |
(2) |
(369) |
(219) |
(588) |
Revisions other than price |
85 |
21 |
106 |
(12) |
94 |
Extensions and discoveries |
1,916 |
50 |
1,966 |
111 |
2,077 |
Purchase of reserves |
250 |
— |
250 |
2 |
252 |
Production |
(669) |
(57) |
(726) |
(212) |
(938) |
Sale of reserves |
(1) |
— |
(1) |
(4) |
(5) |
December 31, 2008 |
7,979 |
390 |
8,369 |
1,510 |
9,879 |
Revisions due to prices |
(661) |
(4) |
(665) |
(29) |
(694) |
Revisions other than price |
119 |
(62) |
57 |
(14) |
43 |
Extensions and discoveries |
1,387 |
64 |
1,451 |
67 |
1,518 |
Purchase of reserves |
1 |
— |
1 |
6 |
7 |
Production |
(698) |
(45) |
(743) |
(223) |
(966) |
Sale of reserves |
— |
(1) |
(1) |
(29) |
(30) |
December 31, 2009 |
8,127 |
342 |
8,469 |
1,288 |
9,757 |
Revisions due to prices |
449 |
2 |
451 |
21 |
472 |
Revisions other than price |
105 |
(26) |
79 |
(17) |
62 |
Extensions and discoveries |
1,088 |
7 |
1,095 |
131 |
1,226 |
Purchase of reserves |
12 |
— |
12 |
9 |
21 |
Production |
(699) |
(17) |
(716) |
(214) |
(930) |
Sale of reserves |
(17) |
(308) |
(325) |
— |
(325) |
December 31, 2010 |
9,065 |
— |
9,065 |
1,218 |
10,283 |
Proved developed reserves as of: |
|
|
|
|
|
December 31, 2007 |
5,547 |
196 |
5,743 |
1,506 |
7,249 |
December 31, 2008 |
6,469 |
212 |
6,681 |
1,357 |
8,038 |
December 31, 2009 |
6,447 |
185 |
6,632 |
1,213 |
7,845 |
December 31, 2010 |
7,280 |
— |
7,280 |
1,144 |
8,424 |
Proved undeveloped reserves as of: |
|
|
|
|
|
December 31, 2007 |
1,218 |
182 |
1,400 |
338 |
1,738 |
December 31, 2008 |
1,510 |
178 |
1,688 |
153 |
1,841 |
December 31, 2009 |
1,680 |
157 |
1,837 |
75 |
1,912 |
December 31, 2010 |
1,785 |
— |
1,785 |
74 |
1,859 |
|
Natural Gas Liquids (MMBbls) | ||||
|
U.S. Onshore |
U.S. Offshore |
Total U.S. |
Canada |
North America |
Proved developed and undeveloped reserves: |
|
|
|
|
|
December 31, 2007 |
281 |
1 |
282 |
39 |
321 |
Revisions due to prices |
(18) |
— |
(18) |
(2) |
(20) |
Revisions other than price |
5 |
1 |
6 |
— |
6 |
Extensions and discoveries |
65 |
— |
65 |
2 |
67 |
Purchase of reserves |
6 |
— |
6 |
— |
6 |
Production |
(24) |
— |
(24) |
(4) |
(28) |
Sale of reserves |
— |
— |
— |
— |
— |
December 31, 2008 |
315 |
2 |
317 |
35 |
352 |
Revisions due to prices |
(11) |
— |
(11) |
2 |
(9) |
Revisions other than price |
36 |
1 |
37 |
— |
37 |
Extensions and discoveries |
70 |
— |
70 |
1 |
71 |
Purchase of reserves |
— |
— |
— |
— |
— |
Production |
(25) |
(1) |
(26) |
(4) |
(30) |
Sale of reserves |
— |
— |
— |
— |
— |
December 31, 2009 |
385 |
2 |
387 |
34 |
421 |
Revisions due to prices |
14 |
— |
14 |
(1) |
13 |
Revisions other than price |
13 |
3 |
16 |
(1) |
15 |
Extensions and discoveries |
68 |
— |
68 |
2 |
70 |
Purchase of reserves |
— |
— |
— |
— |
— |
Production |
(28) |
— |
(28) |
(4) |
(32) |
Sale of reserves |
(3) |
(5) |
(8) |
— |
(8) |
December 31, 2010 |
449 |
— |
449 |
30 |
479 |
Proved developed reserves as of: |
|
|
|
|
|
December 31, 2007 |
243 |
1 |
244 |
30 |
274 |
December 31, 2008 |
260 |
1 |
261 |
31 |
292 |
December 31, 2009 |
293 |
1 |
294 |
32 |
326 |
December 31, 2010 |
353 |
— |
353 |
28 |
381 |
Proved undeveloped reserves as of: |
|
|
|
|
|
December 31, 2007 |
38 |
— |
38 |
9 |
47 |
December 31, 2008 |
55 |
1 |
56 |
4 |
60 |
December 31, 2009 |
92 |
1 |
93 |
2 |
95 |
December 31, 2010 |
96 |
— |
96 |
2 |
98 |
|
Total (MMBoe) (1) | ||||
|
U.S. Onshore |
U.S. Offshore |
Total U.S. |
Canada |
North America |
Proved developed and undeveloped reserves: |
|
|
|
|
|
December 31, 2007 |
1,539 |
103 |
1,642 |
734 |
2,376 |
Revisions due to prices |
(97) |
(3) |
(100) |
(387) |
(487) |
Revisions other than price |
21 |
7 |
28 |
— |
28 |
Extensions and discoveries |
395 |
10 |
405 |
141 |
546 |
Purchase of reserves |
66 |
— |
66 |
— |
66 |
Production |
(146) |
(16) |
(162) |
(61) |
(223) |
Sale of reserves |
(1) |
— |
(1) |
(6) |
(7) |
December 31, 2008 |
1,777 |
101 |
1,878 |
421 |
2,299 |
Revisions due to prices |
(113) |
1 |
(112) |
289 |
177 |
Revisions other than price |
57 |
(8) |
49 |
(11) |
38 |
Extensions and discoveries |
311 |
12 |
323 |
135 |
458 |
Purchase of reserves |
— |
— |
— |
1 |
1 |
Production |
(154) |
(13) |
(167) |
(66) |
(233) |
Sale of reserves |
— |
(1) |
(1) |
(6) |
(7) |
December 31, 2009 |
1,878 |
92 |
1,970 |
763 |
2,733 |
Revisions due to prices |
92 |
1 |
93 |
(21) |
72 |
Revisions other than price |
32 |
1 |
33 |
5 |
38 |
Extensions and discoveries |
269 |
2 |
271 |
83 |
354 |
Purchase of reserves |
2 |
— |
2 |
2 |
4 |
Production |
(158) |
(5) |
(163) |
(65) |
(228) |
Sale of reserves |
(8) |
(91) |
(99) |
(1) |
(100) |
December 31, 2010 |
2,107 |
— |
2,107 |
766 |
2,873 |
Proved developed reserves as of: |
|
|
|
|
|
December 31, 2007 |
1,290 |
59 |
1,349 |
476 |
1,825 |
December 31, 2008 |
1,449 |
59 |
1,508 |
367 |
1,875 |
December 31, 2009 |
1,486 |
53 |
1,539 |
383 |
1,922 |
December 31, 2010 |
1,696 |
— |
1,696 |
346 |
2,042 |
Proved undeveloped reserves as of: |
|
|
|
|
|
December 31, 2007 |
249 |
44 |
293 |
258 |
551 |
December 31, 2008 |
328 |
42 |
370 |
54 |
424 |
December 31, 2009 |
392 |
39 |
431 |
380 |
811 |
December 31, 2010 |
411 |
— |
411 |
420 |
831 |
____________________________
(1) Gas reserves are converted to Boe at the rate of six Mcf per Bbl of oil, based upon the approximate relative energy content of gas and oil. This rate is not necessarily indicative of the relationship of natural gas and oil prices. Natural gas liquids reserves are converted to Boe on a one-to-one basis with oil.
|
|
2010 | |||||
|
First Quarter |
Second Quarter |
Third Quarter |
Fourth Quarter |
Full Year | |
|
(In millions, except per share amounts) | |||||
Revenues |
$ 3,220 |
$ 2,232 |
$ 2,353 |
$ 2,135 |
$ 9,940 | |
|
|
|
|
|
| |
Earnings from continuing operations before income taxes |
$ 1,588 |
$ 613 |
$ 699 |
$ 668 |
$ 3,568 | |
|
|
|
|
|
| |
Earnings from continuing operations |
$ 1,074 |
$ 352 |
$ 429 |
$ 478 |
$ 2,333 | |
Earnings from discontinued operations |
118 |
354 |
1,661 |
84 |
2,217 | |
Net earnings |
$ 1,192 |
$ 706 |
$ 2,090 |
$ 562 |
$ 4,550 | |
|
|
|
|
|
| |
Basic net earnings per common share: |
|
|
|
|
| |
Earnings from continuing operations |
$ 2.40 |
$ 0.79 |
$ 0.99 |
$ 1.10 |
$ 5.31 | |
Earnings from discontinued operations |
0.27 |
0.80 |
3.82 |
0.20 |
5.04 | |
Net earnings |
$ 2.67 |
$ 1.59 |
$ 4.81 |
$ 1.30 |
$ 10.35 | |
|
|
|
|
|
| |
Diluted net earnings per common share: |
|
|
|
|
| |
Earnings from continuing operations |
$ 2.39 |
$ 0.79 |
$ 0.98 |
$ 1.10 |
$ 5.29 | |
Earnings from discontinued operations |
0.27 |
0.79 |
3.81 |
0.19 |
5.02 | |
Net earnings |
$ 2.66 |
$ 1.58 |
$ 4.79 |
$ 1.29 |
$ 10.31 | |
|
2009 | ||||
|
First Quarter |
Second Quarter |
Third Quarter |
Fourth Quarter |
Full Year |
|
(In millions, except per share amounts) | ||||
Revenues |
$ 1,900 |
$ 1,822 |
$ 1,848 |
$ 2,445 |
$ 8,015 |
|
|
|
|
|
|
(Loss) earnings from continuing operations before income taxes |
$ (6,162) |
$ 299 |
$ 471 |
$ 866 |
$ (4,526) |
|
|
|
|
|
|
(Loss) earnings from continuing operations |
$ (3,882) |
$ 190 |
$ 382 |
$ 557 |
$ (2,753) |
(Loss) earnings from discontinued operations |
(77) |
124 |
117 |
110 |
274 |
Net (loss) earnings |
$ (3,959) |
$ 314 |
$ 499 |
$ 667 |
$ (2,479) |
|
|
|
|
|
|
Basic net (loss) earnings per common share: |
|
|
|
|
|
(Loss) earnings from continuing operations |
$ (8.74) |
$ 0.43 |
$ 0.86 |
$ 1.25 |
$ (6.20) |
(Loss) earnings from discontinued operations |
(0.18) |
0.28 |
0.27 |
0.25 |
0.62 |
Net (loss) earnings |
$ (8.92) |
$ 0.71 |
$ 1.13 |
$ 1.50 |
$ (5.58) |
|
|
|
|
|
|
Diluted net (loss) earnings per common share: |
|
|
|
|
|
(Loss) earnings from continuing operations |
$ (8.74) |
$ 0.42 |
$ 0.86 |
$ 1.25 |
$ (6.20) |
(Loss) earnings from discontinued operations |
(0.18) |
0.28 |
0.26 |
0.24 |
0.62 |
Net (loss) earnings |
$ (8.92) |
$ 0.70 |
$ 1.12 |
$ 1.49 |
$ (5.58) |
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