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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 oil and gas exploration, development and production, and the acquisition of 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.
Devon also has offshore operations located in the Gulf of Mexico and certain countries outside North America, including Azerbaijan, Brazil and China. In November 2009, Devon announced plans to strategically reposition itself as a high-growth, North American onshore exploration and production company. As part of this strategic repositioning, Devon plans to bring forward the value of its offshore assets by divesting them. In 2008 and 2007 prior to these plans, Devon sold its assets in Egypt and West Africa. These divestiture activities are described more fully in Note 18.
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;
• asset retirement obligations;
• income taxes;
• derivative financial instruments;
• 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. Devon's largest areas of risk exposure relate 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. 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.
Devonperiodically enters into derivative financial instruments with respect to a portion of its oil and gas production that hedge the future prices received. These instruments are used to manage the inherent uncertainty of future revenues due to oil and gas price volatility. Devon's derivative financial instruments include financial price swaps, basis swaps and costless price collars. Under the terms of the price swaps, Devon will receive a fixed price for its production and pay 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.
Devonperiodically 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. If such criteria are met for cash flow hedges, the effective portion of the change in the fair value is recorded directly to accumulated other comprehensive income, a component of stockholders' equity, until the hedged transaction occurs. The ineffective portion of the change in fair value is recorded in the statement of operations. If such criteria are met for fair value hedges, the change in the fair value is recorded in the statement of operations with an offsetting amount recorded for the change in fair value of the hedged item. Cash settlements with counterparties to Devon's derivative financial instruments are also recorded in the statement of operations.
A derivative financial instrument qualifies for hedge accounting treatment if Devon designates the instrument as such on the date the derivative contract is entered into or the date of a business combination or other transaction that includes derivative contracts. Additionally, Devon must document the relationship between the hedging instrument and hedged item, as well as the risk-management objective and strategy for undertaking the instrument. Devon must also assess, both at the instrument's inception and on an ongoing basis, whether the derivative is highly effective in offsetting the change in cash flow of the hedged item. For derivative financial instruments held during the three-year period ended December 31, 2009, Devon chose not to meet the necessary criteria to qualify its derivative financial instruments for hedge accounting treatment.
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, 2009, 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. Devon does not hold or issue derivative financial instruments for speculative trading purposes.
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 is 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.
Discontinued Operations
As previously discussed, Devon is in the process of divesting its offshore assets in the Gulf of Mexico and certain International locations outside North America and previously sold its assets in Africa in 2008 and 2007. As a result of these divestitures and planned divestitures, all amounts related to Devon's International operations are classified as discontinued operations. The Gulf of Mexico properties being divested do not qualify as discontinued operations under accounting rules. As such, amounts included in the accompanying consolidated financial statements and these notes that pertain to continuing operations include amounts related to Devon’s offshore Gulf of Mexico operations.
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. Costs included in future net revenues are determined in a similar manner. 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, 2009 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 oil and gas 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 average holding periods ranging from three years for onshore properties to seven years for offshore properties.
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.
Devonrecognizes 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 $115 million and $122 million at December 31, 2009 and 2008, 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, 2009, issuers have redeemed $37 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, 2009. 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.
Devonperformed annual impairment tests of goodwill in the fourth quarters of 2009, 2008 and 2007. 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, 2009 and 2008. The increase in goodwill from 2008 to 2009 is due to changes in the exchange rate between the U.S. dollar and the Canadian dollar.
| December 31, | |
| 2009 | 2008 |
| (In millions) | |
United States......................................................................... | $ 3,046 | $ 3,046 |
Canada................................................................................... | 2,884 | 2,465 |
Total (continuing operations)........................................... | $ 5,930 | $ 5,511 |
International (assets held for sale).................................... | $ 68 | $ 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 income in stockholders' equity. The following table presents the balances of Devon's cumulative translation adjustments included in accumulated other comprehensive income (in millions).
December 31, 2006..................................................................... | $ 1,219 |
December 31, 2007..................................................................... | $ 2,566 |
December 31, 2008..................................................................... | $ 685 |
December 31, 2009..................................................................... | $ 1,616 |
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 revenues 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 revenues 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 gas and NGL purchase, transportation and processing contracts are reported on a gross basis when Devon takes title to the products and has risks and rewards of ownership.
Major Purchasers
During 2009, 2008 and 2007, 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 or restructuring costs in the accompanying statements of operations over the applicable requisite service periods. Generally, Devon uses new shares to grant share-based awards and to issue shares upon stock option exercises.
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 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 accrued expenses and other current liabilities. Interest and penalties related to unrecognized tax benefits are included in income tax expense. Additional information regarding Devon's unrecognized tax benefits, including changes in such amounts during 2009 and 2008, is provided in Note 17.
Pursuant to the planned divestitures of its International assets located outside North America, Devon expects to repatriate the earnings from the foreign subsidiaries that own the assets. As a result, Devon has recognized U.S. deferred income taxes on its foreign earnings as of December 31, 2009.
Net (Loss) Earnings 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.
Statements of Cash Flows
For purposes of the consolidated statements of cash flows, Devon considers all highly liquid investments with original contractual maturities of three months or less to be cash equivalents.
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The components of accounts receivable include the following:
| December 31, | |
| 2009 | 2008 |
| (In millions) | |
Oil, gas and NGL revenues................................................................................ | $ 752 | $ 711 |
Joint interest billings............................................................................................ | 151 | 241 |
Marketing and midstream revenues................................................................ | 188 | 153 |
Production tax credits........................................................................................ | 110 | 170 |
Other...................................................................................................................... | 19 | 30 |
Gross accounts receivable............................................................................... | 1,220 | 1,305 |
Allowance for doubtful accounts.................................................................... | (12) | (5) |
Net accounts receivable................................................................................... | $ 1,208 | $ 1,300 |
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3. Derivative Financial Instruments
As discussed in Note 1, Devon periodically enters into commodity and interest rate derivative financial instruments. Also, during the first eight months of 2008 and all of 2007, Devon held an embedded option derivative related to the fair value of its debentures exchangeable into shares of Chevron common stock.
The following table presents the fair values of derivative assets and liabilities included in the accompanying consolidated balance sheets. None of Devon's derivative instruments included in the table have been designated as hedging instruments.
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Balance Sheet Caption | Asset Derivatives | Liability Derivatives |
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| (In millions) | |
December 31, 2009: |
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Gas price swaps................ | Derivative financial instruments, current.............................. | $ 169 | $ — |
Gas basis swaps................ | Derivative financial instruments, current.............................. | 3 | — |
Oil price collars.................. | Other current liabilities.............................................................. | — | 38 |
Interest rate swaps........... | Derivative financial instruments, current.............................. | 39 | — |
Interest rate swaps........... | Other long-term assets.............................................................. | 131 | — |
Total derivatives.............................................................................................................................. | $ 342 | $ 38 | |
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December 31, 2008: |
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Gas price collars................ | Derivative financial instruments, current.............................. | $ 255 | $ — |
Interest rate swaps........... | Derivative financial instruments, current.............................. | 27 | — |
Interest rate swaps........... | Other long-term assets.............................................................. | 77 | — |
Total derivatives.............................................................................................................................. | $ 359 | $ — |
The following table presents the cash settlements and unrealized gains and losses on fair value changes included in the accompanying statements of operations associated with these derivative financial instruments. None of Devon's derivative instruments included in the table have been designated as hedging instruments.
| Statement of Operations Caption | 2009 | 2008 | 2007 |
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| (In millions) | ||
Cash settlements: |
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Gas price collars.............. | Net gain (loss) on oil and gas derivative financial instruments.................................................................... |
$ 450 |
$ (221) |
$ 2 |
Gas price swaps.............. | Net gain (loss) on oil and gas derivative financial instruments.................................................................... |
55 |
(203) |
38 |
Oil price collars................ | Net gain (loss) on oil and gas derivative financial instruments.................................................................... |
— |
27 |
— |
Interest rate swaps......... | Change in fair value of other financial instruments | 40 | 1 | — |
Total cash settlements................................................................................................. | 545 | (396) | 40 | |
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Unrealized (losses) gains: |
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Gas price collars.............. | Net gain (loss) on oil and gas derivative financial instruments.................................................................... |
(255) |
255 |
(4) |
Gas price swaps.............. | Net gain (loss) on oil and gas derivative financial instruments.................................................................... |
169 |
(12) |
(22) |
Gas basis swaps.............. | Net gain (loss) on oil and gas derivative financial instruments.................................................................... |
3 |
— |
— |
Oil price collars................ | Net gain (loss) on oil and gas derivative financial instruments.................................................................... |
(38) |
— |
— |
Interest rate swaps......... | Change in fair value of other financial instruments | 66 | 104 | 1 |
Embedded option........... | Change in fair value of other financial instruments | — | 109 | (248) |
Total unrealized (losses) gains.................................................................................... | (55) | 456 | (273) | |
Net gain (loss) recognized on statement of operations............................................... | $ 490 | $ 60 | $ (233) |
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The components of other current assets include the following:
| December 31, | |
| 2009 | 2008 |
| (In millions) | |
Inventories........................................................................................................... | $ 182 | $ 142 |
Prepaid assets...................................................................................................... | 33 | 36 |
Income taxes receivable.................................................................................... | 53 | 333 |
Other...................................................................................................................... | 2 | 4 |
Other current assets.......................................................................................... | $ 270 | $ 515 |
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Property and equipment consists of the following:
| December 31, | |
| 2009 | 2008 |
| (In millions) | |
Oil and gas properties: |
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Subject to amortization................................................................................... | $ 52,352 | $ 45,678 |
Not subject to amortization............................................................................ | 4,078 | 4,248 |
Total.................................................................................................................... | 56,430 | 49,926 |
Accumulated depreciation, depletion and amortization............................. | (40,312) | (30,260) |
Net oil and gas properties............................................................................. | 16,118 | 19,666 |
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Other property and equipment......................................................................... | 4,045 | 3,465 |
Accumulated depreciation and amortization............................................... | (1,396) | (1,100) |
Net other property and equipment............................................................. | 2,649 | 2,365 |
Property and equipment, net of accumulated depreciation, depletion and amortization............................................................................ |
$ 18,767 |
$ 22,031 |
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.
The following is a summary of Devon's oil and gas properties not subject to amortization as of December 31, 2009. The $4.1 billion total includes $2.1 billion related to Devon’s U.S. Offshore assets that are expected to be sold by the end of 2010. Evaluation of most of the remaining $2.0 billion of properties, and therefore the inclusion of their costs in amortized capital costs, is expected to be completed within three to seven years.
| Costs Incurred In | ||||
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2009 |
2008 |
2007 | Prior to 2007 |
Total |
| (In millions) | ||||
Acquisition costs...................................................................... | $ 129 | $ 1,567 | $ 126 | $ 780 | $ 2,602 |
Exploration costs..................................................................... | 223 | 303 | 56 | 174 | 756 |
Development costs.................................................................. | 326 | 169 | 34 | 22 | 551 |
Capitalized interest.................................................................. | 74 | 54 | 37 | 4 | 169 |
Total oil and gas properties not subject to amortization | $ 752 | $ 2,093 | $ 253 | $ 980 | $ 4,078 |
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A summary of Devon's debt is as follows:
| December 31, | |
| 2009 | 2008 |
| (In millions) | |
Commercial paper.............................................................................................. | $ 1,432 | $ 1,005 |
Other debentures and notes: |
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10.125% retired on November 15, 2009...................................................... | — | 177 |
6.875% due September 30, 2011................................................................... | 1,750 | 1,750 |
7.25% due October 1, 2011............................................................................ | 350 | 350 |
5.625% due January 15, 2014....................................................................... | 500 | — |
8.25% due July 1, 2018................................................................................... | 125 | 125 |
6.30% due January 15, 2019.......................................................................... | 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.................................................................................................................... | 10 | 10 |
Net premium on other debentures and notes............................................... | 12 | 24 |
| 7,279 | 5,841 |
Less amount classified as short-term debt..................................................... | 1,432 | 180 |
Long-term debt.................................................................................................... | $ 5,847 | $ 5,661 |
Debt maturities as of December 31, 2009, excluding premiums and discounts, are as follows (in millions):
2010...................................................................................................................... | $ 1,432 |
2011...................................................................................................................... | 2,100 |
2012...................................................................................................................... | 10 |
2013...................................................................................................................... | — |
2014...................................................................................................................... | 500 |
2015 and thereafter............................................................................................ | 3,225 |
Total.................................................................................................................... | $ 7,267 |
Credit Lines
Devon has a $2.65 billion syndicated, unsecured revolving line of credit (the "Senior Credit Facility"). The maturity date for $2.15 billion of the Senior Credit Facility is April 7, 2013. The maturity date for the remaining $0.5 billion 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, 2009, there were no borrowings under the Senior Credit Facility.
Following the maturity of an unused $700 million short-term facility on November 3, 2009, Devon established a new $700 million 364-day, syndicated, unsecured revolving senior credit facility (the "Short-Term Facility"). The Short-Term Facility provides Devon with incremental liquidity for near-term capital expenditures.
The Short-Term Facility matures on November 2, 2010. On the maturity date, all amounts outstanding will be due and payable at that time. Amounts borrowed under the Short-Term Facility bear interest at various fixed rate options for periods of up to 12 months. Such rates are generally based on LIBOR or the prime rate. The Short-Term Facility provides for an annual facility fee of approximately $1.75 million that is payable quarterly in arrears. As of December 31, 2009, there were no borrowings under the Short-Term Facility.
The Senior Credit Facility and Short-Term Facility contain 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, 2009, Devon was in compliance with this covenant. Devon’s debt-to-capitalization ratio at December 31, 2009, as calculated pursuant to the terms of the agreement, was 20.5%.
The following schedule summarizes the capacity of Devon's credit facilities by maturity date, as well as its available capacity as of December 31, 2009.
| Amount |
| (In millions) |
Senior Credit Facility: |
|
April 7, 2012 maturity.................................................................... | $ 500 |
April 7, 2013 maturity.................................................................... | 2,150 |
Total Senior Credit Facility.............................................................. | 2,650 |
Short-Term Facility – November 2, 2010 maturity.................... | 700 |
Total credit facilities......................................................................... | 3,350 |
Less: |
|
Outstanding credit facility borrowings......................................... | — |
Outstanding commercial paper borrowings................................ | 1,432 |
Outstanding letters of credit.......................................................... | 87 |
Total available capacity.................................................................. | $ 1,831 |
Commercial Paper
Devon also has access to short-term credit under its commercial paper program. Total borrowings under the commercial paper program may not exceed $2.85 billion. Also, any borrowings under the commercial paper program reduce available capacity under the Senior Credit Facility or the Short-Term 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. As of December 31, 2009, Devon had $1.4 billion of commercial paper debt outstanding at an average rate of 0.29%. The average borrowing rate for Devon's $1.0 billion of commercial paper debt outstanding at December 31, 2008 was 3.00%.
Other Debentures and Notes
Following are descriptions of the various other debentures and notes outstanding at December 31, 2009, as listed in the table presented at the beginning of this note.
Ocean Debt
As a result of the merger with Ocean Energy, Inc., which closed April 25, 2003, Devon assumed $1.8 billion of debt. The table below summarizes the debt assumed that remains outstanding, 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) |
|
7.250% due October 2011 (principal of $350 million)........................... | $ 406 | 4.9% |
8.250% due July 2018 (principal of $125 million).................................. | $ 147 | 5.5% |
7.500% due September 2027 (principal of $150 million)...................... | $ 169 | 6.5% |
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.
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 between 2007 and 2009.
| Year Ended December 31, | ||
| 2009 | 2008 | 2007 |
| (In millions) | ||
Interest based on debt outstanding............................................ | $ 437 | $ 426 | $ 508 |
Capitalized interest........................................................................ | (94) | (111) | (102) |
Other................................................................................................. | 6 | 14 | 24 |
Total interest expense................................................................. | $ 349 | $ 329 | $ 430 |
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7. Asset Retirement Obligations
Following is a reconciliation of the asset retirement obligations for the years ended December 31, 2009 and 2008.
| Year Ended December 31, | |
| 2009 | 2008 |
| (In millions) | |
Asset retirement obligations as of beginning of year.................................... | $ 1,387 | $ 1,245 |
Liabilities incurred............................................................................................. | 56 | 59 |
Liabilities settled................................................................................................ | (123) | (86) |
Revision of estimated obligation................................................................... | 33 | 225 |
Liabilities assumed by others.......................................................................... | (30) | — |
Accretion expense on discounted obligation............................................... | 91 | 80 |
Foreign currency translation adjustment...................................................... | 99 | (136) |
Asset retirement obligations as of end of year.............................................. | 1,513 | 1,387 |
Less current portion............................................................................................ | 95 | 138 |
Asset retirement obligations, long-term........................................................... | $ 1,418 | $ 1,249 |
During 2009 and 2008, Devon recognized revisions to its asset retirement obligations totaling $33 million and $225 million, respectively. The primary factors causing the 2009 fair value increase were an overall increase in abandonment cost estimates, partially offset by an increase in the discount rate used to calculate the present value of the obligations. The primary factors causing the 2008 fair value increase were an overall increase in abandonment cost estimates and a decrease in the discount rate used to present value the obligations. In addition, higher abandonment cost estimates related to certain offshore platforms that were destroyed by Hurricane Ike resulted in an $82 million increase in 2008. See additional discussion regarding this revision in Note 10 – Hurricane Contingencies.
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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 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.
Devon's funding policy regarding the Qualified Plans is to contribute the amount of funds necessary for the Qualified Plans' assets to approximately equal the present value of benefits earned by the participants, as calculated in accordance with the provisions of the Pension Protection Act. As of December 31, 2009 and 2008, the fair values of the Qualified Plans' assets were $532 million and $430 million, respectively. The assets were $164 million less and $209 million less, respectively, than the related accumulated benefit obligation. The amount of contributions required during future periods will depend on investment returns from the plan assets during the same period as well as changes in long-term interest rates.
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 $39 million and $50 million at December 31, 2009 and 2008, respectively, and is included in noncurrent other assets in the 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 for 2009 and 2008. 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, 2009 and 2008 was $873 million and $795 million, respectively. Devon’s benefit obligations and plan assets are measured each year as of December 31.
|
Pension Benefits | Other Postretirement Benefits | ||
| 2009 | 2008 | 2009 | 2008 |
| (In millions) | |||
Change in benefit obligation: |
|
|
|
|
Benefit obligation at beginning of year...................... | $ 931 | $ 849 | $ 56 | $ 71 |
Service cost...................................................................... | 43 | 41 | 1 | 1 |
Interest cost...................................................................... | 58 | 54 | 3 | 4 |
Actuarial loss (gain)........................................................ | 4 | 17 | 7 | (15) |
Curtailment (gain) loss................................................... | (26) | — | 1 | — |
Plan amendments........................................................... | — | 9 | — | — |
Foreign exchange rate changes.................................... | 5 | (6) | — | — |
Participant contributions............................................... | — | — | 2 | 2 |
Benefits paid.................................................................... | (35) | (33) | (6) | (7) |
Benefit obligation at end of year................................. | 980 | 931 | 64 | 56 |
|
|
|
|
|
Change in plan assets: |
|
|
|
|
Fair value of plan assets at beginning of year........... | 430 | 619 | — | — |
Actual return on plan assets.......................................... | 80 | (178) | — | — |
Employer contributions................................................. | 55 | 25 | 4 | 5 |
Participant contributions............................................... | — | — | 2 | 2 |
Benefits paid.................................................................... | (35) | (33) | (6) | (7) |
Foreign exchange rate changes.................................... | 2 | (3) | — | — |
Fair value of plan assets at end of year...................... | 532 | 430 | — | — |
|
|
|
|
|
Funded status at end of year.......................................... | $ (448) | $ (501) | $ (64) | $ (56) |
|
|
|
|
|
Amounts recognized in balance sheet: |
|
|
|
|
Noncurrent assets............................................................ | $ 2 | $ 2 | $ — | $ — |
Current liabilities............................................................. | (8) | (10) | (5) | (5) |
Noncurrent liabilities....................................................... | (442) | (493) | (59) | (51) |
Net amount...................................................................... | $ (448) | $ (501) | $ (64) | $ (56) |
|
|
|
|
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Amounts recognized in accumulated other comprehensive income: |
|
|
|
|
Net actuarial loss (gain)............................................... | $ 334 | $ 440 | $ (6) | $ (13) |
Prior service cost............................................................ | 20 | 28 | 11 | 13 |
Total................................................................................ | $ 354 | $ 468 | $ 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 $9 million for both 2009 and 2008, 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, 2009 and 2008 as presented in the table below.
| December 31, | |
| 2009 | 2008 |
| (In millions) | |
Projected benefit obligation................................................................ | $ 967 | $ 921 |
Accumulated benefit obligation......................................................... | $ 860 | $ 784 |
Fair value of plan assets...................................................................... | $ 517 | $ 417 |
The plan assets included in the above table exclude the Supplemental Plan trusts, which had a total value of $39 million and $50 million at December 31, 2009 and 2008, respectively.
Net Periodic Benefit Cost and Other Comprehensive Income
The following table presents the components of net periodic benefit cost and other comprehensive income for Devon's pension and other postretirement benefit plans for 2009, 2008 and 2007.
|
Pension Benefits | Other Postretirement Benefits | ||||
| 2009 | 2008 | 2007 | 2009 | 2008 | 2007 |
| (In millions) | |||||
Net periodic benefit cost: |
|
|
|
|
|
|
Service cost................................................................. | $ 43 | $ 41 | $ 30 | $ 1 | $ 1 | $ 1 |
Interest cost................................................................. | 58 | 54 | 46 | 3 | 4 | 3 |
Expected return on plan assets................................ | (35) | (50) | (49) | — | — | — |
Curtailment and settlement expense...................... | 5 | — | 1 | 1 | — | — |
Plan amendment........................................................ | — | — | — | — | — | 1 |
Recognition of net actuarial loss (gain)................. | 45 | 14 | 12 | (1) | — | 1 |
Recognition of prior service cost............................. | 3 | 2 | 1 | 2 | 2 | — |
Total net periodic benefit cost............................... | 119 | 61 | 41 | 6 | 7 | 6 |
Other comprehensive income |
|
|
|
|
|
|
Actuarial (gain) loss arising in current year........... | (66) | 245 | 54 | 7 | (15) | (3) |
Prior service cost arising in current year................. | — | 9 | 17 | — | — | 22 |
Recognition of net actuarial (loss) gain in net periodic benefit cost................................................ |
(45) |
(14) |
(12) |
1 |
— |
(1) |
Recognition of prior service cost, including curtailment, in net periodic benefit cost............... |
(8) |
(2) |
(1) |
(2) |
(2) |
— |
Curtailment of pension benefits.............................. | — | — | (16) | — | — | — |
Change in additional minimum pension liability. | — | — | — | — | — | — |
Total other comprehensive income (loss)............ | (119) | 238 | 42 | 6 | (17) | 18 |
Total recognized........................................................... | $ — | $ 299 | $ 83 | $ 12 | $ (10) | $ 24 |
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 income into net periodic benefit cost during 2010.
|
Pension Benefits | Other Postretirement Benefits |
| (In millions) | |
Net actuarial loss.................................................................. | $ 27 | $ — |
Prior service cost................................................................... | 3 | 1 |
Total..................................................................................... | $ 30 | $ 1 |
Assumptions
The following table presents the weighted average actuarial assumptions that were used to determine benefit obligations and net periodic benefit costs for 2009, 2008 and 2007.
|
Pension Benefits | Other Postretirement Benefits | ||||
| 2009 | 2008 | 2007 | 2009 | 2008 | 2007 |
|
| |||||
Assumptions to determine benefit obligations: |
|
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|
|
|
|
Discount rate....................................................................... | 6.00% | 6.00% | 6.22% | 5.70% | 6.00% | 6.00% |
Rate of compensation increase....................................... | 6.95% | 7.00% | 7.00% | N/A | N/A | N/A |
Assumptions to determine net periodic benefit cost: |
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|
|
|
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Discount rate....................................................................... | 6.00% | 6.18% | 5.96% | 6.00% | 6.00% | 5.75% |
Expected return on plan assets........................................ | 7.18% | 8.40% | 8.40% | N/A | N/A | N/A |
Rate of compensation increase....................................... | 6.95% | 7.00% | 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, such as Moody's Aa, are considered when selecting the discount rate.
Rate of compensation increase – For measurement of the 2009 benefit obligation for the pension plans, the 6.95% 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 2009 benefit obligation for the other postretirement medical plans, an 8.5% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2010. 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, 2009 other postretirement benefits obligation and the 2010 service and interest cost components of net periodic benefit cost.
| One Percent Increase | One Percent Decrease |
| (In millions) | |
Effect on benefit obligation........................................................ | $ 5 | $ (4) |
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 2009, Devon's target allocations for plan assets are 47.5% for equity securities, 40% for fixed-income securities and 12.5% for other investment types. At the end of 2008, Devon's target allocation was 60% for equity securities and 40% for fixed income securities. The fair values of Devon's pension assets at December 31, 2009 and 2008, are presented by asset class in the following tables.
| As of December 31, 2009 | ||||
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| Fair Value Measurements Using: | ||
| Actual Allocation | Total | Quoted Prices in Active Markets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) |
| (In millions) | ||||
Equity securities: |
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|
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: |
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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: |
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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 |
| As of December 31, 2008 | ||||
|
|
| Fair Value Measurements Using: | ||
| Actual Allocation | Total | Quoted Prices in Active Markets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) |
| (In millions) | ||||
Equity securities: |
|
|
|
|
|
United States large cap............................. | 25.8% | $ 111 | $ — | $ 111 | $ — |
United States small cap............................ | 14.9% | 64 | 64 | — | — |
International large cap............................. | 14.0% | 60 | 34 | 26 | — |
Total equity securities............................... | 54.7% | 235 | 98 | 137 | — |
Fixed-income securities: |
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Corporate bonds........................................ | 29.1% | 125 | 125 | — | — |
United States Treasury obligations........ | 8.8% | 38 | 38 | — | — |
Other bonds................................................ | 3.0% | 13 | 13 | — | — |
Total fixed-income securities.................. | 40.9% | 176 | 176 | — | — |
Other securities – Short-term investment funds.................. |
4.4% |
19 |
— |
19 |
— |
Total investments........................................ | 100.0% | $ 430 | $ 274 | $ 156 | $ — |
The following methods and assumptions were used to estimate the fair values of the assets and liabilities 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.
The change in Devon's Level 3 plan assets between 2008 and 2009 related entirely to purchases made in 2009.
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 2010 contributions | $ 34 | $ 5 |
Benefit payments: |
|
|
2010............................................................................................. | $ 39 | $ 5 |
2011............................................................................................. | $ 41 | $ 5 |
2012............................................................................................. | $ 45 | $ 6 |
2013............................................................................................. | $ 49 | $ 6 |
2014............................................................................................. | $ 53 | $ 6 |
2015 to 2019.............................................................................. | $ 338 | $ 29 |
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 2010, $7 million of pension benefits is expected to be funded from the trusts established for the Supplemental Plans and all $5 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.
In 2007, Devon adopted an enhanced defined contribution structure related to its 401(k) Plan effective January 1, 2008. Participants who elected to participate in this enhanced defined contribution structure, as well as all employees hired on or after October 1, 2007, continue to receive a discretionary match of a percentage of their contributions to the 401(k) Plan. These 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 during 2009, 2008 and 2007.
| Year Ended December 31, | ||
| 2009 | 2008 | 2007 |
| (In millions) | ||
401(k) plan.................................................................... | $ 20 | $ 21 | $ 18 |
Enhanced contribution plan...................................... | 14 | 12 | — |
Canadian pension and savings plans....................... | 15 | 16 | 14 |
Total expense.......................................................... | $ 49 | $ 49 | $ 32 |
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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, 2009, 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 200 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 200 votes per share (subject to adjustment to prevent dilution) on all matters submitted to a vote of the stockholders. The Series A Junior Preferred Stock is neither redeemable nor convertible. The Series A Junior Preferred Stock ranks prior to the common stock but junior to all other classes of Preferred Stock.
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.
Stock Repurchases
Devon’s Board of Directors previously 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, and no new plans have been authorized. Devon's Board of Directors also approved a separate 50 million share repurchase program in August 2005, which expired on December 31, 2007.
During 2007 and 2008, Devon repurchased 10.6 million shares at a total cost of $1.0 billion, or an average of $93.76 per share, under its repurchase programs. No shares were repurchased in 2009. The following table summarizes Devon's repurchases under approved plans during 2008 and 2007 (amounts and shares in millions).
| 2008 | 2007 | ||||
Repurchase Program | Amount | Shares | Per Share | Amount | Shares | Per Share |
Annual program...... | $ 178 | 2.0 | $ 87.83 | $ — | — | $ — |
2007 program.......... | 487 | 4.5 | $ 109.25 | 326 | 4.1 | $ 79.80 |
Totals...................... | $ 665 | 6.5 | $ 102.56 | $ 326 | 4.1 | $ 79.80 |
Dividends
Devon paid common stock dividends of $284 million (or $0.64 per share), $284 million (or $0.64 per share) and $249 million (or $0.56 per share) in 2009, 2008 and 2007 respectively. Devon paid dividends of $5 million in 2008 and $10 million in 2007 to preferred stockholders. The decrease in preferred stock dividend in 2008 is due to the redemption of the preferred stock in the second quarter of 2008.
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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.
In 1995, the United States Congress passed the Deep Water Royalty Relief Act. The intent of this legislation was to encourage deep water exploration in the Gulf of Mexico by providing relief from the obligation to pay royalties on certain federal leases. Deep water leases issued in certain years by the Minerals Management Service (the "MMS") have 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. Additionally, in January 2009 a federal appellate court upheld this district court ruling. 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.
Prior to September 30, 2009, 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 the third quarter of 2009. The $84 million expense reduction is included in other income in the accompanying 2009 consolidated statement of operations.
Hurricane Contingencies
Prior to September 1, 2006, Devon maintained a comprehensive insurance program that included coverage for physical damage to its offshore facilities caused by hurricanes. This program also included substantial business interruption coverage, which entitled Devon to be reimbursed for the portion of production suspended longer than forty-five days, subject to upper limits to oil and gas prices. Also, the terms of the historical insurance included a standard, per-event deductible of $1 million for offshore losses as well as a $15 million aggregate annual deductible.
Devon suffered insured damages in the third quarter of 2005 related to hurricanes that struck the Gulf of Mexico. During 2006 and 2007, Devon received $480 million as a full settlement of the amount due from its primary insurers and certain of its secondary insurers. During the fourth quarter of 2008, Devon received $106 million as full settlement of the amount due from its remaining secondary insurers. Devon's claims under its then existing insurance arrangements included both physical damages and business interruption claims. Devon used $424 million of these proceeds as reimbursement of repair costs and deductible amounts, resulting in excess recoveries. The $162 million of excess recoveries was recorded as other income in the accompanying consolidated statement of operations for 2008.
The policy underlying the insurance program terms described above expired on August 31, 2006. Due to significant changes in the insurance marketplace, Devon no longer has coverage for damage that may be caused by named windstorms in the Gulf of Mexico. As a result, Devon's current insurance program includes coverage for physical damage and business interruption but does not have such coverage for damages or business interruption caused from named windstorms in the Gulf of Mexico.
During the third quarter of 2008, Hurricanes Ike and Gustav damaged certain of Devon's oil and gas facilities and transportation systems in the Gulf of Mexico. These damages relate to both production operations that have been repaired and restored and production operations that will not be restored. These damages are uninsured losses because they resulted from named windstorms in the Gulf of Mexico.
For the damaged facilities and transportation systems which have been repaired or restored, Devon recognized a loss of $31 million in 2008. This loss is included in lease operating expenses in the accompanying consolidated statement of operations. The facilities for which Devon did not restore production operations consisted of certain platforms that were completely destroyed. Devon began performing asset retirement activities associated with the destroyed platforms and related wells in 2008. The time and effort required to complete such activities is expected to be significant due to the hazardous conditions created by the hurricanes. As a result, the estimated costs to complete the asset retirement activities were $82 million higher than Devon's previously estimated asset retirement obligations related to the destroyed platforms and related wells. Therefore, in 2008, Devon increased its asset retirement obligations by $82 million with a corresponding increase to oil and gas property and equipment in the accompanying consolidated balance sheet.
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
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 $3.2 billion total of "Drilling and Facility Obligations" in the table below is $1.4 billion that relates to long-term contracts for three deepwater drilling rigs and certain other contracts for onshore drilling and facility obligations in which drilling or facilities construction has not commenced. The $1.4 billion represents the gross commitment under these contracts. Devon's ultimate payment for these commitments will be reduced by any amounts billed to its partners until Devon sells the associated offshore properties. Payments for these commitments, net of amounts billed to partners, will be capitalized as a component of oil and gas properties.
Additionally, Devon's commitment under these contracts may be further reduced if the buyers of its offshore assets assume all or a portion of the obligations. If the buyers do not assume these obligations, Devon will attempt to sublease the rigs to reduce its commitment. However, if the buyers do not assume the obligations and Devon is not able to sublease the rigs, Devon would be contractually committed to the amounts related to the remaining lease periods.
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 the majority of 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 $56 million, $44 million and $42 million in 2009, 2008 and 2007, respectively.
Devon assumed two offshore platform spar leases through the 2003 Ocean merger. The spars are being used in the development of the Nansen and Boomvang fields in the Gulf of Mexico. The Boomvang field was divested as part of the 2005 property divestiture program. The Nansen operating lease is for a 20-year term and contains various options whereby Devon may purchase the lessors' interests in the spar. Total rental expense included in lease operating expenses under the Nansen operating lease was $12 million in 2009, 2008 and 2007. Devon has guaranteed that the Nansen spar will have a residual value at the end of the operating lease equal to at least 10% of the fair value of the spar at the inception of the lease. The total guaranteed value is $14 million in 2022. However, such amount may be reduced under the terms of the lease agreement. As a result of the sale of the Boomvang field, Devon is subleasing the Boomvang Spar. If the sublessee were to default on its obligation, Devon would continue to be obligated to pay the periodic lease payments and any guaranteed value required at the end of the term.
Devon has a floating, production, storage and offloading facility ("FPSO") that is being used in the Panyu project offshore China and is being leased under operating lease arrangements. This lease expires in September 2018. Devon is also leasing an FPSO that is being used in the Polvo project offshore Brazil. This lease expires in 2014. Devon has also leased an FPSO that will be used when production from its Cascade development in the Gulf of Mexico begins in 2010. This lease expires in 2015. Total rental expense included in lease operating expenses for these FPSO's was $36 million, $25 million and $17 million in 2009, 2008 and 2007, respectively. Devon expects the eventual buyers of these offshore assets will assume the FPSO leases. However, the amounts in the schedule below reflect its full commitments under the leases.
The following is a schedule by year of 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, 2009. The schedule includes separate amounts for Devon's continuing and discontinued operations.
Year Ending December 31, | Drilling and Facility Obligations |
Firm Transportation Agreements |
Office and Equipment Leases |
Spar Leases |
FPSO Leases |
| (In millions) | ||||
Continuing operations: |
|
|
|
|
|
2010............................................................ | $ 992 | $ 298 | $ 57 | $ 11 | $ 58 |
2011............................................................ | 516 | 267 | 54 | 11 | 37 |
2012............................................................ | 302 | 241 | 40 | 22 | 38 |
2013............................................................ | 257 | 217 | 34 | 13 | 38 |
2014............................................................ | 97 | 202 | 15 | 27 | 38 |
Thereafter................................................... | 1 | 714 | 147 | 78 | 16 |
Total............................................................ | 2,165 | 1,939 | 347 | 162 | 225 |
Discontinued operations: |
|
|
|
|
|
2010............................................................ | 622 | — | 15 | — | 37 |
2011............................................................ | 182 | — | — | — | 37 |
2012............................................................ | 170 | — | — | — | 37 |
2013............................................................ | 110 | — | — | — | 37 |
2014............................................................ | — | — | — | — | 23 |
Thereafter................................................... | — | — | — | — | 29 |
Total............................................................ | 1,084 | — | 15 | — | 200 |
Total operations.......................................... | $ 3,249 | $ 1,939 | $ 362 | $ 162 | $ 425 |
|
Certain of Devon's assets and liabilities are reported at fair value in the accompanying balance sheets. Such assets and liabilities include amounts for both financial and nonfinancial instruments. The following tables provide fair value measurement information for such assets and liabilities as of December 31, 2009 and 2008.
The carrying values of cash and cash equivalents, accounts receivable and accounts payable (including income taxes payable and accrued expenses) included in the accompanying consolidated balance sheets approximated fair value at December 31, 2009 and 2008. 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.
| As of December 31, 2009 | ||||
|
|
| Fair Value Measurements Using: | ||
| Carrying Amount | Total Fair Value | Quoted Prices in Active Markets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) |
| (In millions) | ||||
Financial assets (liabilities): |
|
|
|
|
|
Gas price swaps...................................... | $ 169 | $ 169 | $ — | $ 169 | $ — |
Gas basis swaps..................................... | $ 3 | $ 3 | $ — | $ 3 | $ — |
Oil price collars....................................... | $ (38) | $ (38) | $ — | $ (38) | $ — |
Interest rate swaps................................. | $ 170 | $ 170 | $ — | $ 170 | $ — |
Debt.......................................................... | $ (7,279) | $ (8,214) | $ (1,432) | $ (6,782) | $ — |
Long-term investments......................... | $ 115 | $ 115 | $ — | $ — | $ 115 |
Asset retirement obligations (1)............... | $ (1,622) | $ (1,622) | $ — | $ — | $ (1,622) |
| As of December 31, 2008 | ||||
|
|
| Fair Value Measurements Using: | ||
| Carrying Amount | Total Fair Value | Quoted Prices in Active Markets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) |
| (In millions) | ||||
Financial assets (liabilities): |
|
|
|
|
|
Gas price collars..................................... | $ 255 | $ 255 | $ — | $ 255 | $ — |
Interest rate swaps................................. | $ 104 | $ 104 | $ — | $ 104 | $ — |
Debt.......................................................... | $ (5,841) | $ (6,106) | $ (1,005) | $ (5,101) | $ — |
Long-term investments......................... | $ 122 | $ 122 | $ — | $ — | $ 122 |
Asset retirement obligations (1)............... | $ (1,485) | $ (1,485) | $ — | $ — | $ (1,485) |
____________________________
(1) Includes $109 million and $98 million of asset retirement obligations related to Devon’s discontinued operations at December 31, 2009 and 2008, respectively.
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.
Level 2 Fair Value Measurements
Oil and gas price swaps, basis swaps and collars — The fair values of the oil and gas price collars, gas swaps and gas basis swaps 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 LIBOR and money market futures 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 swaps — The fair values of the interest rate swaps 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 primarily using LIBOR and money market futures rates. 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 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
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, 2009 and December 31, 2008. Therefore, Devon used valuation techniques that rely on unobservable, or Level 3, 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, 2009 and December 31, 2008. At this time, Devon does not believe the values of its long-term securities are impaired. The changes in these Level 3 assets during 2008 and 2009 consisted entirely of redemptions of principal.
Asset retirement obligations — The fair values of the asset retirement obligations are estimated using internal discounted cash flow calculations based upon Devon's estimates of future retirement costs. Reconciliations of the beginning and ending balances of Devon's asset retirement obligations, including revisions of the estimated fair values in 2009 and 2008, are presented in Note 7.
|
In the fourth quarter of 2009, Devon recognized $153 million of estimated employee severance costs associated with the planned divestitures of its offshore assets that was announced in November 2009. This amount was based on estimates of the number of employees that will ultimately be impacted by the divestitures, and includes $63 million related to accelerated vesting of share-based grants. Of the $153 million total, $105 million relates to Devon's U.S. Offshore operations and the remainder relates to its International discontinued operations.
As of the date these financial statements were prepared, only one of the properties Devon intends to sell had actually been sold. Furthermore, the vast majority of employees will not be impacted by the divestitures until the properties are sold. Therefore, Devon's estimate of employee severance costs recognized in the fourth quarter of 2009 was based upon certain key estimates that could change as properties are sold. These estimates include the number of impacted employees, the number of employees offered comparable positions with the buyers and the date of separation for impacted employees.
|
14. Other Financial Instruments
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 exchange requests during 2008 and 2007 by paying $1.0 billion during 2008 and $0.2 billion during 2007. 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.
The shares of Chevron common stock and the exchange option embedded in the debt were always recorded on Devon’s balance sheet at fair value. However, pursuant to accounting rules prior to January 1, 2007, only the change in fair value of the embedded option had historically been included in Devon’s results of operations. Conversely, the change in fair value of the Chevron common stock had not been included in Devon's results of operations, but instead had been recorded directly to stockholders' equity as part of "accumulated other comprehensive income." Effective January 1, 2007, under new accounting rules, Devon elected to begin recognizing the change in fair value of the Chevron common stock in its results of operations. Accordingly, beginning with the first quarter of 2007, the change in fair value of the Chevron common stock owned by Devon, along with the change in fair value of the related exchange option, were both included in Devon’s results of operations. Also, as a result of this change, Devon reclassified $364 million of after-tax unrealized gains related to Devon’s investment in Chevron common stock from accumulated other comprehensive income to retained earnings in the first quarter of 2007.
The following table presents the changes in fair value and cash settlements related to Devon’s other financial instruments, as well as its investment in Chevron Common Stock as presented in the accompanying consolidated statements of operations.
| Year Ended December 31, | ||
| 2009 | 2008 | 2007 |
| (In millions) | ||
(Gains) and losses from: |
|
|
|
Interest rate swaps – fair value changes (See Note 3)................ | $ (66) | $ (104) | $ (1) |
Interest rate swaps – settlements (See Note 3)............................ | (40) | (1) | — |
Chevron common stock.................................................................. | — | 363 | (281) |
Option embedded in exchangeable debentures.......................... | — | (109) | 248 |
Total................................................................................................ | $ (106) | $ 149 | $ (34) |
|
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 | Net of Taxes |
Gross | Net of 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 income include the following:
| Year Ended December 31, | ||
| 2009 | 2008 | 2007 |
| (In millions) | ||
Interest and dividend income............................................. | $ 8 | $ 54 | $ 48 |
Reduction of deep water royalties (see Note 10)............ | 84 | — | — |
Hurricane insurance proceeds (see Note 10).................... | — | 162 | — |
Other........................................................................................ | (24) | 1 | 3 |
Total................................................................................. | $ 68 | $ 217 | $ 51 |
|
Income Tax (Benefit) Expense
The (loss) earnings from continuing operations before income taxes and the components of income tax (benefit) expense for the years 2009, 2008 and 2007 were as follows:
| Year Ended December 31, | ||
| 2009 | 2008 | 2007 |
| (In millions) | ||
(Loss) earnings from continuing operations before income taxes: |
|
|
|
U.S.................................................................................................. | $ (4,961) | $ (2,190) | $ 2,642 |
Canada.......................................................................................... | 435 | (1,970) | 685 |
Total............................................................................................... | $ (4,526) | $ (4,160) | $ 3,327 |
Current income tax expense: |
|
|
|
U.S. federal................................................................................... | $ 45 | $ 258 | $ 83 |
Various states............................................................................... | 18 | 31 | 17 |
Canada and various provinces................................................. | 178 | 152 | 135 |
Total current tax expense.......................................................... | 241 | 441 | 235 |
Deferred income tax (benefit) expense: |
|
|
|
U.S. federal................................................................................... | (1,846) | (875) | 745 |
Various states............................................................................... | (111) | (65) | 28 |
Canada and various provinces................................................. | (57) | (622) | (166) |
Total deferred tax (benefit) expense........................................ | (2,014) | (1,562) | 607 |
Total income tax (benefit) expense........................................... | $ (1,773) | $ (1,121) | $ 842 |
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 (benefit) expense differed from the amounts computed by applying the U.S. federal income tax rate to (loss) earnings from continuing operations before income taxes as a result of the following:
| Year Ended December 31, | ||
| 2009 | 2008 | 2007 |
| (In millions) | ||
Expected income tax (benefit) expense based on U.S. statutory tax rate of 35%............................................................. |
$ (1,584) |
$ (1,456) |
$ 1,164 |
State income taxes......................................................................... | (99) | (29) | 30 |
Taxation on Canadian operations.............................................. | (31) | 227 | (10) |
Repatriations and tax policy election changes......................... | — | 312 | — |
Canadian statutory rate reduction.............................................. | — | — | (261) |
Other................................................................................................. | (59) | (175) | (81) |
Total income tax (benefit) expense........................................ | $ (1,773) | $ (1,121) | $ 842 |
During 2008, Devon repatriated $2.6 billion from certain foreign subsidiaries to the United States. Also in the second quarter of 2008, Devon made certain tax policy election changes to minimize the taxes Devon 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 repatriations, as well as the tax policy election changes, Devon recognized additional tax expense of $312 million during 2008. Of the $312 million, $295 million was recognized as current income tax expense, and $17 million was recognized as deferred tax expense.
In 2007, deferred income taxes were reduced $261 million due to a Canadian statutory rate reduction that was enacted in that year.
Deferred Tax Assets and Liabilities
The tax effects of temporary differences that gave rise to significant portions of the deferred tax assets and liabilities at December 31, 2009 and 2008 are presented below:
| December 31, | |
| 2009 | 2008 |
| (In millions) | |
Deferred tax assets: |
|
|
Net operating loss carryforwards................................................... | $ 11 | $ 13 |
Asset retirement obligations............................................................ | 474 | 442 |
Pension benefit obligations............................................................. | 130 | 172 |
Other.................................................................................................... | 133 | 74 |
Total deferred tax assets............................................................. | 748 | 701 |
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............ |
(2,315) |
(4,163) |
Fair value of financial instruments................................................ | (108) | (132) |
Long-term debt.................................................................................. | (162) | (69) |
Other.................................................................................................... | (62) | — |
Total deferred tax liabilities............................................................ | (2,647) | (4,364) |
Net deferred tax liability............................................................... | $ (1,899) | $ (3,663) |
As shown in the above table, Devon has recognized $748 million of deferred tax assets as of December 31, 2009. Included in total deferred tax assets is $11 million related to various carryforwards available to offset future income taxes. The carryforwards consist of $151 million of state net operating loss carryforwards, which expire primarily between 2010 and 2029. 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 net operating loss carryforwards to be utilized between 2010 and 2014. Such expectation is based upon current estimates of taxable income during this period, 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.
Unrecognized Tax Benefits
The following table presents changes in Devon's unrecognized tax benefits for the year ended December 31, 2009 (in millions).
Balance as of December 31, 2008............................................................. | $ 260 |
Increases (decreases) due to: |
|
Tax positions taken in current year......................................................... | 20 |
Accrual of interest related to tax positions taken.................................. | 7 |
Lapse of statute of limitations.................................................................. | (15) |
Settlements................................................................................................... | (5) |
Foreign currency translation...................................................................... | 5 |
Balance as of December 31, 2009............................................................. | $ 272 |
Devon’s unrecognized tax benefit balance at December 31, 2009 and 2008 included $35 million and $29 million of interest and penalties, respectively. If recognized, all of Devon's unrecognized tax benefits as of December 31, 2009 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............................................................................................. | 2005-2009 |
Various U.S. states................................................................................ | 2005-2009 |
Canada federal...................................................................................... | 2001-2009 |
Various Canadian provinces............................................................... | 2001-2009 |
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.
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For the three-year period ended December 31, 2009, Devon's discontinued operations include amounts related to its assets in Azerbaijan, Brazil, China and other minor International properties that it is in the process of divesting. Additionally, during 2007 and 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.
Devon's African sales generated total proceeds of $3.0 billion. The following table presents the gains on the African divestiture transactions by year.
| Year Ended December 31, | |||||
| 2009 | 2008 | 2007 | |||
|
Gross | Net of Taxes |
Gross | Net of Taxes |
Gross | Net of Taxes |
| (In millions) | |||||
Egypt........................................................................ | $ — | $ — | $ — | $ — | $ 90 | $ 90 |
Equatorial Guinea................................................. | — | — | 619 | 544 | — | — |
Gabon...................................................................... | — | — | 117 | 122 | — | — |
Cote d’Ivoire.......................................................... | 17 | 17 | 83 | 95 | — | — |
Other........................................................................ | — | — | — | 8 | — | — |
Total...................................................................... | $ 17 | $ 17 | $ 819 | $ 769 | $ 90 | $ 90 |
Revenues related to Devon's discontinued operations totaled $945 million, $1.7 billion and $2.2 billion during 2009, 2008 and 2007, respectively. Earnings from discontinued operations before income taxes totaled $322 million, $1.3 billion and $1.6 billion during 2009, 2008 and 2007, respectively.
The following table presents the main classes of assets and liabilities associated with Devon's discontinued operations as of December 31, 2009 and 2008.
| December 31, | |
| 2009 | 2008 |
| (In millions) | |
Assets: |
|
|
Cash and cash equivalents............................................................ | $ 365 | $ 189 |
Accounts receivable........................................................................ | 165 | 112 |
Other current assets......................................................................... | 127 | 91 |
Current assets................................................................................. | $ 657 | $ 392 |
|
|
|
Property and equipment, net of accumulated depreciation, depletion and amortization......................................................... |
$ 1,099 |
$ 954 |
Goodwill............................................................................................ | 68 | 68 |
Other long-term assets.................................................................... | 83 | 106 |
Total long-term assets.................................................................. | $ 1,250 | $ 1,128 |
|
|
|
Liabilities: |
|
|
Accounts payable........................................................................... | $ 158 | $ 220 |
Other current liabilities.................................................................... | 76 | 145 |
Current liabilities............................................................................ | $ 234 | $ 365 |
|
|
|
Asset retirement obligations, long-term....................................... | $ 109 | $ 98 |
Deferred income taxes................................................................... | 101 | 65 |
Other liabilities................................................................................. | 3 | 3 |
Long-term liabilities...................................................................... | $ 213 | $ 166 |
Reductions of Carrying Value of Oil and Gas Properties
During 2009, 2008 and 2007, 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 | 2007 | |||
|
Gross | Net of Taxes |
Gross | Net of Taxes |
Gross | Net of Taxes |
| (In millions) | (In millions) | (In millions) | |||
Brazil........................................................................ | $ 103 | $ 103 | $ 437 | $ 437 | $ — | $ — |
Nigeria...................................................................... | — | — | — | — | 68 | 13 |
Other........................................................................ | 5 | 2 | 57 | 28 | — | — |
Total...................................................................... | $ 108 | $ 105 | $ 494 | $ 465 | $ 68 | $ 13 |
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.
Based on unsuccessful drilling activities in Nigeria, Devon reduced the carrying value of its Nigerian oil and gas properties in 2007.
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Devon manages its operations through seven 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 business. 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 2009, 2008 and 2007. The revenues reported are all from external customers.
| U.S. | Canada | International | Total |
| (In millions) | |||
As of December 31, 2009: |
|
|
|
|
Current assets, including current assets held for sale.............. | $ 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, including long-term assets held for sale............. | 674 | 73 | 1,250 | 1,997 |
Total assets................................................................................ | $ 18,368 | $ 9,411 | $ 1,907 | $ 29,686 |
Current liabilities, including current liabilities held for sale.... |
$ 2,993 |
$ 575 |
$ 234 |
$ 3,802 |
Long-term debt.............................................................................. | 2,866 | 2,981 | — | 5,847 |
Asset retirement obligations, long-term..................................... | 754 | 664 | — | 1,418 |
Other liabilities, including long-term liabilities held for sale... | 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 |
Net gain on oil and gas derivative financial instruments..... | 382 | 2 | 384 |
Marketing and midstream revenues........................................ | 1,498 | 36 | 1,534 |
Total revenues.......................................................................... | 5,838 | 2,177 | 8,015 |
Expenses and other income, 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 |
Change in fair value of other financial instruments............. | (106) | — | (106) |
Reduction of carrying value of oil and gas properties......... | 6,408 | — | 6,408 |
Other (income) expense, net..................................................... | (92) | 24 | (68) |
Total expenses and other income, 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 | International | Total |
| (In millions) | |||
As of December 31, 2008: |
|
|
|
|
Current assets, including current assets held for sale.............. | $ 1,925 | $ 367 | $ 392 | $ 2,684 |
Property and equipment, net...................................................... | 17,676 | 4,355 | — | 22,031 |
Goodwill.......................................................................................... | 3,046 | 2,465 | — | 5,511 |
Other assets, including long-term assets held for sale............. | 482 | 72 | 1,128 | 1,682 |
Total assets............................................................................... | $ 23,129 | $ 7,259 | $ 1,520 | $ 31,908 |
Current liabilities, including current liabilities held for sale.... |
$ 2,227 |
$ 543 |
$ 365 |
$ 3,135 |
Long-term debt.............................................................................. | 2,683 | 2,978 | — | 5,661 |
Asset retirement obligations, long-term..................................... | 694 | 555 | — | 1,249 |
Other liabilities, including long-term liabilities held for sale... | 983 | 40 | 166 | 1,189 |
Deferred income taxes................................................................. | 2,734 | 880 | — | 3,614 |
Stockholders' equity..................................................................... | 13,808 | 2,263 | 989 | 17,060 |
Total liabilities and stockholders' equity.............................. | $ 23,129 | $ 7,259 | $ 1,520 | $ 31,908 |
| U.S. | Canada | Total |
| (In millions) | ||
Year Ended December 31, 2008: |
|
|
|
Revenues: |
|
|
|
Oil, gas and NGL sales............................................................... | $ 8,206 | $ 3,514 | $ 11,720 |
Net loss on oil and gas derivative financial instruments...... | (154) | — | (154) |
Marketing and midstream revenues........................................ | 2,247 | 45 | 2,292 |
Total revenues.......................................................................... | 10,299 | 3,559 | 13,858 |
Expenses and other income, 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 |
Change in fair value of other financial instruments............. | 149 | — | 149 |
Reduction of carrying value of oil and gas properties......... | 6,538 | 3,353 | 9,891 |
Other income, net........................................................................ | (203) | (14) | (217) |
Total expenses and other income, 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 |
| U.S. | Canada | Total |
| (In millions) | ||
Year Ended December 31, 2007: |
|
|
|
Revenues: |
|
|
|
Oil, gas and NGL sales............................................................... | $ 5,814 | $ 2,411 | $ 8,225 |
Net gain on oil and gas derivative financial instruments..... | 14 | — | 14 |
Marketing and midstream revenues........................................ | 1,693 | 43 | 1,736 |
Total revenues.......................................................................... | 7,521 | 2,454 | 9,975 |
Expenses and other income, net: |
|
|
|
Lease operating expenses.......................................................... | 905 | 627 | 1,532 |
Taxes other than income taxes................................................ | 327 | 31 | 358 |
Marketing and midstream operating costs and expenses... | 1,200 | 17 | 1,217 |
Depreciation, depletion and amortization of oil and gas properties............................................................................ |
1,672 |
740 |
2,412 |
Depreciation and amortization of non-oil and gas properties................................................................................... |
180 |
21 |
201 |
Accretion of asset retirement obligations............................... | 38 | 32 | 70 |
General and administrative expenses..................................... | 395 | 118 | 513 |
Interest expense.......................................................................... | 228 | 202 | 430 |
Change in fair value of other financial instruments............. | (32) | (2) | (34) |
Other income, net........................................................................ | (34) | (17) | (51) |
Total expenses and other income, net................................. | 4,879 | 1,769 | 6,648 |
Earnings from continuing operations before income taxes.. | 2,642 | 685 | 3,327 |
Income tax expense (benefit): |
|
|
|
Current.......................................................................................... | 100 | 135 | 235 |
Deferred........................................................................................ | 773 | (166) | 607 |
Total income tax expense (benefit)...................................... | 873 | (31) | 842 |
Earnings from continuing operations........................................ | $ 1,769 | $ 716 | $ 2,485 |
|
|
|
|
Capital expenditures, before revision of future asset retirement obligations....................................................... |
$ 4,522 |
$ 1,350 |
$ 5,872 |
Revision of future asset retirement obligations....................... | 210 | 99 | 309 |
Capital expenditures, continuing operations........................... | $ 4,732 | $ 1,449 | $ 6,181 |
|
21. Supplemental Information to Statements of Cash Flows
Additional information related to Devon’s 2009, 2008 and 2007 statements of cash flows are presented below:
| Year Ended December 31, | ||
| 2009 | 2008 | 2007 |
| (In millions) | ||
Net decrease (increase) in working capital: |
|
|
|
Decrease (increase) in accounts receivable.............................................. | $ 142 | $ 187 | $ (286) |
Decrease (increase) in other current assets............................................... | 212 | (46) | (31) |
(Decrease) increase in accounts payable................................................. | (91) | 159 | 45 |
Increase in revenues and royalties due to others.................................... | — | 11 | 79 |
Decrease in income taxes payable............................................................ | (48) | (309) | (80) |
Decrease in other current liabilities............................................................ | (66) | (209) | (239) |
Net decreases (increase) in working capital.......................................... | $ 149 | $ (207) | $ (512) |
|
|
|
|
Supplementary cash flow data: |
|
|
|
Interest paid (net of capitalized interest).................................................. | $ 314 | $ 336 | $ 406 |
Income taxes paid (continuing and discontinued operations)............. | $ 68 | $ 1,436 | $ 588 |
|
|
|
|
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, 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, 2007 | ||||
| U.S. Onshore | U.S. Offshore | Total U.S. |
Canada | North America |
Property acquisition costs: | (In millions) | ||||
Proved properties.......................................................... | $ 3 | $ — | $ 3 | $ 7 | $ 10 |
Unproved properties..................................................... | 77 | 79 | 156 | 49 | 205 |
Exploration costs............................................................ | 195 | 374 | 569 | 211 | 780 |
Development costs......................................................... | 3,183 | 359 | 3,542 | 1,098 | 4,640 |
Costs incurred............................................................. | $ 3,458 | $ 812 | $ 4,270 | $ 1,365 | $ 5,635 |
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 $332 million, $337 million and $277 million in the years 2009, 2008 and 2007, 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 $74 million, $71 million and $48 million in the years 2009, 2008 and 2007, 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, 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 | (220) | 1,580 |
Results of operations............................................................. | $ (3,350) | $ 514 | $ (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 |
| Year Ended December 31, 2007 | ||
| United States |
Canada | North America |
| (In millions) | ||
Oil, gas and NGL sales........................................................... | $ 5,814 | $ 2,411 | $ 8,225 |
Lease operating expenses..................................................... | (905) | (627) | (1,532) |
Taxes other than income taxes........................................... | (312) | (31) | (343) |
Depreciation, depletion and amortization......................... | (1,672) | (740) | (2,412) |
Accretion of asset retirement obligations........................... | (38) | (32) | (70) |
General and administrative expenses................................. | (143) | (76) | (219) |
Income tax expense.............................................................. | (966) | (49) | (1,015) |
Results of operations............................................................. | $ 1,778 | $ 856 | $ 2,634 |
Depreciation, depletion and amortization per Boe.......... | $ 11.44 | $ 12.73 | $ 11.81 |
In 2007, the total and Canadian income tax amounts in the table above were reduced by $261 million due to statutory rate reductions that were enacted in that year.
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, 2009. 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, 2006........................................................ | 127 | 43 | 170 | 329 | 499 |
Revisions due to prices................................................. | 4 | — | 4 | 16 | 20 |
Revisions other than price........................................... | 3 | 3 | 6 | 13 | 19 |
Extensions and discoveries......................................... | 8 | 1 | 9 | 46 | 55 |
Purchase of reserves..................................................... | 1 | — | 1 | — | 1 |
Production...................................................................... | (11) | (8) | (19) | (16) | (35) |
Sale of reserves.............................................................. | (1) | — | (1) | — | (1) |
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 |
Proved developed reserves as of: |
|
|
|
|
|
December 31, 2006...................................................... | 116 | 31 | 147 | 112 | 259 |
December 31, 2007...................................................... | 122 | 26 | 148 | 195 | 343 |
December 31, 2008...................................................... | 111 | 22 | 133 | 110 | 243 |
December 31, 2009...................................................... | 119 | 21 | 140 | 149 | 289 |
Proved undeveloped reserves as of: |
|
|
|
|
|
December 31, 2006...................................................... | 11 | 12 | 23 | 217 | 240 |
December 31, 2007...................................................... | 9 | 13 | 22 | 193 | 215 |
December 31, 2008...................................................... | 22 | 12 | 34 | 24 | 58 |
December 31, 2009...................................................... | 20 | 12 | 32 | 365 | 397 |
| Gas (Bcf) | ||||
| U.S. Onshore | U.S. Offshore | Total U.S. |
Canada | North America |
Proved developed and undeveloped reserves: |
|
|
|
|
|
December 31, 2006........................................................ | 5,979 | 376 | 6,355 | 1,896 | 8,251 |
Revisions due to prices................................................. | 117 | 2 | 119 | 50 | 169 |
Revisions other than price........................................... | 175 | (1) | 174 | (19) | 155 |
Extensions and discoveries......................................... | 1,055 | 78 | 1,133 | 139 | 1,272 |
Purchase of reserves..................................................... | 10 | — | 10 | 5 | 15 |
Production...................................................................... | (558) | (77) | (635) | (227) | (862) |
Sale of reserves.............................................................. | (13) | — | (13) | — | (13) |
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 |
Proved developed reserves as of: |
|
|
|
|
|
December 31, 2006...................................................... | 4,672 | 244 | 4,916 | 1,560 | 6,476 |
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 |
Proved undeveloped reserves as of: |
|
|
|
|
|
December 31, 2006...................................................... | 1,307 | 132 | 1,439 | 336 | 1,775 |
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 |
| Natural Gas Liquids (MMBbls) | ||||
| U.S. Onshore | U.S. Offshore | Total U.S. |
Canada | North America |
Proved developed and undeveloped reserves: |
|
|
|
|
|
December 31, 2006........................................................ | 230 | 3 | 233 | 42 | 275 |
Revisions due to prices................................................. | 5 | — | 5 | — | 5 |
Revisions other than price........................................... | 22 | (1) | 21 | (1) | 20 |
Extensions and discoveries......................................... | 45 | — | 45 | 2 | 47 |
Purchase of reserves..................................................... | — | — | — | — | — |
Production...................................................................... | (21) | (1) | (22) | (4) | (26) |
Sale of 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 |
Proved developed reserves as of: |
|
|
|
|
|
December 31, 2006...................................................... | 194 | 2 | 196 | 33 | 229 |
December 31, 2007...................................................... | 243 | 1 | 244 | 30 | 274 |
December 31, 2008...................................................... | 260 | 1 | 261 | 31 | 292 |
December 31, 2009...................................................... | 293 | 1 | 294 | 32 | 326 |
Proved undeveloped reserves as of: |
|
|
|
|
|
December 31, 2006...................................................... | 36 | 1 | 37 | 9 | 46 |
December 31, 2007...................................................... | 38 | — | 38 | 9 | 47 |
December 31, 2008...................................................... | 55 | 1 | 56 | 4 | 60 |
December 31, 2009...................................................... | 92 | 1 | 93 | 2 | 95 |
| Total (MMBoe) (1) | ||||
| U.S. Onshore | U.S. Offshore | Total U.S. |
Canada | North America |
Proved developed and undeveloped reserves: |
|
|
|
|
|
December 31, 2006........................................................ | 1,353 | 109 | 1,462 | 687 | 2,149 |
Revisions due to prices................................................. | 28 | 1 | 29 | 25 | 54 |
Revisions other than price........................................... | 55 | 1 | 56 | 7 | 63 |
Extensions and discoveries......................................... | 228 | 14 | 242 | 72 | 314 |
Purchase of reserves..................................................... | 2 | — | 2 | 1 | 3 |
Production...................................................................... | (124) | (22) | (146) | (58) | (204) |
Sale of reserves.............................................................. | (3) | — | (3) | — | (3) |
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 |
Proved developed reserves as of: |
|
|
|
|
|
December 31, 2006...................................................... | 1,089 | 74 | 1,163 | 405 | 1,568 |
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 |
Proved undeveloped reserves as of: |
|
|
|
|
|
December 31, 2006...................................................... | 264 | 35 | 299 | 282 | 581 |
December 31, 2007...................................................... | 249 | 44 | 293 | 258 | 551 |
December 31, 2008...................................................... | 328 | 42 | 370 | 54 | 424 |
December 31, 2009...................................................... | 392 | 39 | 431 | 380 | 811 |
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(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.
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.
Price Revisions
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 steam-assisted gravity drainage project in Canada.
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
The 2009 total revision included 48 MMBoe related to the Barnett Shale. The 2008 total included performance revisions of 22 MMBoe in the Barnett Shale. The 2007 total included performance revisions of 39 MMBoe at the Barnett Shale, 13 MMBoe at Jackfish and 13 MMBoe at Carthage.
Extensions and Discoveries
2009 – Of the 458 MMBoe of 2009 extensions and discoveries, 204 MMBoe related to the Barnett Shale area in Texas, 118 MMBoe related to Jackfish, 49 MMBoe related to the Cana-Woodford Shale area in western Oklahoma, 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 in east Texas, 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.
2007 – Of the 314 MMBoe of 2007 extensions and discoveries, 119 MMBoe related to the Barnett Shale, 34 MMBoe related to Carthage, 22 MMBoe related to Jackfish, 20 MMBoe related to Lloydminster, 17 MMBoe related to Washakie and 15 MMBoe related to the Arkoma-Woodford Shale.
The 2007 extensions and discoveries included 154 MMBoe related to additions from Devon’s infill drilling activities, including 96 MMBoe at the Barnett Shale and 19 MMBoe at Lloydminster.
Purchase of Reserves
The 2008 total included 34 MMBoe located in Utah and 27 MMBoe located in the Permian Basin.
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 2009, 2008 and 2007.
| 2009 | 2008 | 2007 | |||
| Prepared | Audited | Prepared | Audited | Prepared | Audited |
U.S. Onshore........................... | — | 93% | — | 92% | — | 88% |
U.S. Offshore.......................... | 100% | — | 100% | — | 100% | — |
U.S.......................................... | 5% | 89% | 5% | 87% | 6% | 82% |
Canada................................... | — | 91% | — | 78% | 34% | 51% |
North America..................... | 3% | 89% | 4% | 85% | 15% | 73% |
"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. 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 principles.
The domestic reserves were evaluated by the independent petroleum consultants of LaRoche Petroleum Consultants, Ltd. and Ryder Scott Company, L.P. in each of the years presented. 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, 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, 2007 | ||
| United States |
Canada | North America |
| (In millions) | ||
Future cash inflows........................................................................... | $ 72,109 | $ 28,684 | $ 100,793 |
Future costs: |
|
|
|
Development.................................................................................... | (5,673) | (3,380) | (9,053) |
Production........................................................................................ | (24,606) | (10,941) | (35,547) |
Future income tax expense............................................................. | (12,704) | (3,570) | (16,274) |
Future net cash flows........................................................................ | 29,126 | 10,793 | 39,919 |
10% discount to reflect timing of cash flows............................... | (14,312) | (5,025) | (19,337) |
Standardized measure of discounted future net cash flows..... | $ 14,814 | $ 5,768 | $ 20,582 |
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 2009, the prices averaged $47.80 per barrel of oil, $3.12 per Mcf of gas and $22.78 per barrel of natural gas liquids. Of the $10.9 billion of future development costs as of the end of 2009, $2.0 billion, $1.6 billion and $0.9 billion are estimated to be spent in 2010, 2011 and 2012, respectively.
Future development costs include not only development costs, but also future dismantlement, abandonment and rehabilitation costs. Included as part of the $10.9 billion of future development costs are $1.1 billion 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, | ||
| 2009 | 2008 | 2007 |
| (In millions) | ||
Beginning balance....................................................................... | $ 9,393 | $ 20,582 | $ 13,474 |
Oil, gas and NGL sales, net of production costs..................... | (3,915) | (9,177) | (6,131) |
Net changes in prices and production costs............................ | (1,672) | (13,839) | 7,896 |
Extensions and discoveries, net of future development costs............................................................................................. | 2,378 | 1,729 | 4,130 |
Purchase of reserves, net of future development costs......... | 6 | 214 | 50 |
Development costs incurred that reduced future development costs.................................................................... |
1,012 |
1,660 |
1,559 |
Revisions of quantity estimates................................................ | 4,051 | (1,294) | 564 |
Sales of reserves in place............................................................ | (37) | (2) | (51) |
Accretion of discount.................................................................. | 1,281 | 2,894 | 1,933 |
Net change in income taxes....................................................... | (51) | 4,934 | (2,494) |
Other, primarily changes in timing and foreign exchange rates........................................................................... |
(1,043) |
1,692 |
(348) |
Ending balance............................................................................. | $ 11,403 | $ 9,393 | $ 20,582 |
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23. Supplemental Quarterly Financial Information (Unaudited)
Following is a summary of the unaudited interim results of operations for the years ended December 31, 2009 and 2008.
| 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.......... | $ (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) |
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|
|
|
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) |
|
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|
|
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|
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) |
| 2008 | ||||
| First Quarter | Second Quarter | Third Quarter | Fourth Quarter | Full Year |
| (In millions, except per share amounts) | ||||
Revenues..................................................................... | $ 2,503 | $ 3,152 | $ 5,651 | $ 2,552 | $ 13,858 |
|
|
|
|
|
|
Earnings (loss) from continuing operations........... | $ 415 | $ 423 | $ 2,393 | (6,270) | $ (3,039) |
Earnings (loss) from discontinued operations....... | 334 | 878 | 225 | (546) | 891 |
Net earnings (loss)...................................................... | $ 749 | $ 1,301 | $ 2,618 | (6,816) | $ (2,148) |
|
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|
|
|
|
Basic net earnings (loss) per common share: |
|
|
|
|
|
Earnings (loss) from continuing operations......... | $ 0.93 | $ 0.94 | $ 5.42 | $ (14.19) | $ (6.86) |
Earnings (loss) from discontinued operations..... | 0.75 | 1.97 | 0.51 | (1.23) | 2.01 |
Net earnings (loss).................................................... | $ 1.68 | $ 2.91 | $ 5.93 | $ (15.42) | $ (4.85) |
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|
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|
Diluted net earnings (loss) per common share: |
|
|
|
|
|
Earnings (loss) from continuing operations......... | $ 0.92 | $ 0.93 | $ 5.37 | $ (14.19) | $ (6.86) |
Earnings (loss) from discontinued operations..... | 0.74 | 1.95 | 0.51 | (1.23) | 2.01 |
Net earnings (loss).................................................... | $ 1.66 | $ 2.88 | $ 5.88 | $ (15.42) | $ (4.85) |
Earnings (Loss) from Continuing Operations
The first quarter of 2009 includes a reduction of the carrying values of United States oil and gas properties totaling $6.4 billion ($4.1 billion 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).
The first and second quarters of 2008 include unrealized losses on Devon’s commodity hedges of $780 million ($499 million after income taxes, or $1.11 per diluted share) and $912 million ($584 million after income taxes, or $1.30 per diluted share), respectively, as a result of increases in gas prices subsequent to the trade dates. The third quarter of 2008 includes a net unrealized gain of $1.8 billion ($1.2 billion after income taxes, or $2.63 per diluted share), resulting from a decrease in gas prices.
The second quarter of 2008 includes an increase to income tax expense of $312 million (or $0.70 per diluted share) due to repatriations from certain foreign subsidiaries to the United States and tax policy election changes.
The fourth quarter of 2008 includes reductions of the carrying values of United States and Canadian oil and gas properties totaling $9.9 billion ($6.7 billion after income taxes, or $15.06 per diluted share).
Earnings (Loss) from Discontinued Operations
The first quarter of 2009 includes reductions of the carrying values of oil and gas properties totaling $108 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).
The second quarter of 2008 includes a $623 million gain ($529 million after income taxes, or $1.17 per diluted share) as a result of completing the sale of Devon's Equatorial Guinea operations. Also, during the second quarter of 2008, Devon closed the sale of its Gabon operations, which resulted in a $114 million gain ($111 million after income taxes, or $0.25 per diluted share).
The third quarter of 2008 includes an $83 million gain ($101 million after income taxes, or $0.23 per diluted share) as a result of completing the sale of Devon’s assets in Cote d'Ivoire.
The fourth quarter of 2008 includes reductions of the carrying values of oil and gas properties totaling $494 million ($465 million after income taxes, or $1.05 per diluted share).