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1.Summary of Significant Accounting Policies
Devon Energy Corporation (“Devon”) is a leading independent energy company engaged primarily in the exploration, development and production of oil, natural gas and NGLs. Devon’s operations are concentrated in various North American onshore areas in the U.S. and Canada. Devon also owns natural gas pipelines, plants and treatment facilities in many of its producing areas, making it one of North America's larger processors of natural gas.
Accounting policies used by Devon and its subsidiaries conform to accounting principles generally accepted in the United States of America and reflect industry practices. The more significant of such policies are discussed below.
Principles of Consolidation
The accounts of Devon and its wholly owned and controlled subsidiaries are included in the accompanying financial statements. All significant intercompany accounts and transactions have been eliminated in consolidation.
Use of Estimates
The preparation of financial statements 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:
• proved reserves and related present value of future net revenues;
• the carrying value of oil and gas properties;
• derivative financial instruments;
• the fair value of reporting units and related assessment of goodwill for impairment;
• income taxes;
• asset retirement obligations;
• obligations related to employee pension and postretirement benefits; and
• legal and environmental risks and exposures.
Revenue Recognition and Gas Balancing
Oil, gas and NGL sales are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectability of the revenue is probable. Delivery occurs and title is transferred when production has been delivered to a pipeline, railcar or truck. Cash received relating to future production is deferred and recognized when all revenue recognition criteria are met. Taxes assessed by governmental authorities on oil, gas and NGL sales are presented separately from such revenues in the accompanying comprehensive statements of earnings.
Devon follows the sales method of accounting for gas production imbalances. The volumes of gas sold may differ from the volumes to which Devon is entitled based on its interests in the properties. These differences create imbalances that are recognized as a liability only when the estimated remaining reserves will not be sufficient to enable the underproduced owner to recoup its entitled share through production. The liability is priced based on current market prices. No receivables are recorded for those wells where Devon has taken less than its share of production unless all revenue recognition criteria are met. If an imbalance exists at the time the wells' reserves are depleted, settlements are made among the joint interest owners under a variety of arrangements.
Marketing and midstream revenues are recorded at the time products are sold or services are provided to third parties at a fixed or determinable price, delivery or performance has occurred, title has transferred and collectability of the revenue is probable. Revenues and expenses attributable to oil, gas and NGL purchases, transportation and processing contracts are reported on a gross basis when Devon takes title to the products and has risks and rewards of ownership.
During 2012, 2011 and 2010, no purchaser accounted for more than 10 percent of Devon’s revenues from continuing operations.
Derivative Financial Instruments
Devon is exposed to certain risks relating to its ongoing business operations, including risks related to commodity prices, interest rates and Canadian to U.S. dollar exchange rates. As discussed more fully below, Devon uses derivative instruments primarily to manage commodity price risk and interest rate risk. Devon does not intend to hold or issue derivative financial instruments for speculative trading purposes.
Devon periodically enters into derivative financial instruments with respect to a portion of its oil, gas and NGL production to hedge future prices received. These instruments are used to manage the inherent uncertainty of future revenues due to commodity price volatility. Devon's derivative financial instruments typically include financial price swaps, basis swaps, costless price collars and call options. Under the terms of the price swaps, Devon receives a fixed price for its production and pays a variable market price to the contract counterparty. For the basis swaps, Devon receives a fixed differential between two regional 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. The call options give counterparties the right to purchase production at a predetermined price.
Devon periodically enters into interest rate swaps to manage its exposure to interest rate volatility. Devon's interest rate swaps include contracts in which Devon receives a fixed rate and pays a variable rate on a total notional amount. Devon periodically enters into foreign exchange forward contracts to manage its exposure to fluctuations in exchange rates.
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 earnings unless specific hedge accounting criteria are met. For derivative financial instruments held during the three-year period ended December 31, 2012, Devon chose not to meet the necessary criteria to qualify its derivative financial instruments for hedge accounting treatment. Cash settlements with counterparties on Devon's derivative financial instruments are also recorded in earnings.
By using derivative financial instruments to hedge exposures to changes in commodity prices, interest rates and foreign currency rates, Devon is exposed to credit 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 acceptable 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 certain credit rating levels. The mark-to-market exposure threshold, above which collateral must be posted, decreases as the debt rating falls further below such credit levels. As of December 31, 2012, Devon held $63 million of cash collateral, which represented the estimated fair value of certain derivative positions in excess of Devon’s credit guidelines. The collateral is reported in other current liabilities in the accompanying balance sheet.
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 generally recognized as a component of general and administrative expenses in the accompanying comprehensive statements of earnings over the applicable requisite service periods. As a result of Devon’s strategic repositioning announced in 2009 and the consolidation of its U.S. operations announced in October 2012, certain share based awards were accelerated and recognized as a component of restructuring expense in the accompanying comprehensive statements of earnings.
Generally, Devon uses new shares from approved incentive programs to grant share-based awards and to issue shares upon stock option exercises. Shares repurchased under approved programs are available to be issued as part of Devon’s share based awards. However, Devon has historically cancelled these shares upon repurchase.
Income Taxes
Devon is subject to current income taxes assessed by the federal and various state jurisdictions in the U.S. 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. If the future utilization of some portion of carryforwards is determined to be unlikely, a valuation allowance is provided to reduce the recorded tax benefits from such assets. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.
Devon does not recognize U.S. deferred income taxes on the unremitted earnings of its foreign subsidiaries that are deemed to be indefinitely reinvested. When such earnings are no longer deemed permanently reinvested, Devon recognizes the appropriate deferred, or even current, income tax liabilities.
Devon recognizes the financial statement effects of tax positions when it is more likely than not, based on the technical merits, that the position will be sustained upon examination by a taxing authority. Recognized tax positions are initially and subsequently measured as the largest amount of tax benefit that is more likely than not of being realized upon ultimate settlement with a taxing authority. Liabilities for unrecognized tax benefits related to such tax positions are included in other long-term liabilities unless the tax position is expected to be settled within the upcoming year, in which case the liabilities are included in other current liabilities. Interest and penalties related to unrecognized tax benefits are included in current income tax expense.
Net Earnings (Loss) Per Common Share
Devon’s basic earnings per share amounts have been computed based on the average number of shares of common stock outstanding for the period. Basic earnings per share includes the effect of participating securities, which primarily consist of Devon's outstanding restricted stock awards. Diluted earnings per share is calculated using the treasury stock method to reflect the assumed issuance of common shares for all potentially dilutive securities. Such securities primarily consist of outstanding stock options.
Cash and Cash Equivalents
Devon considers all highly liquid investments with original contractual maturities of three months or less to be cash equivalents.
Investments
Devon periodically invests excess cash in U.S. and Canadian treasury securities and other marketable securities. During 2012 and 2011, Devon invested a portion of its joint venture proceeds and a portion of the International offshore divestiture proceeds into such securities, causing short-term investments to increase.
Devon considers securities with original contractual maturities in excess of three months, but less than one year to be short-term investments. Investments with contractual maturities in excess of one year are classified as long-term, unless such investments are classified as trading or available-for-sale.
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. Such debt securities totaled $64 million and $84 million at December 31, 2012 and 2011, respectively and are included in other long-term assets in the accompanying balance sheet. Devon has the ability to hold the securities until maturity and does not believe the values of its long-term securities are impaired.
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, capitalized costs of oil and gas properties, net of accumulated DD&A and deferred income taxes, may not exceed the full cost “ceiling” at the end of each quarter. The ceiling is calculated separately for each country and is based on the present value of estimated future net cash flows from proved oil and gas reserves, discounted at 10 percent per annum, net of related tax effects. The 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.
Estimated future net cash flows are calculated using end-of-period costs and an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months. 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, 2012, qualified for hedge accounting treatment.
Any excess of the net book value, less related deferred taxes, over the ceiling is written off as an expense. An expense recorded in one period may not be reversed in a subsequent period even though higher commodity prices may have increased the ceiling applicable to the subsequent period.
Capitalized costs are depleted by an equivalent unit-of-production method, converting gas to oil at the ratio of six thousand cubic feet of gas to one barrel of oil. Depletion is calculated using the capitalized costs, including estimated asset retirement costs, plus the estimated future expenditures (based on current costs) to be incurred in developing proved reserves, net of estimated salvage values.
Costs associated with unproved properties are excluded from the depletion calculation until it is determined whether or not proved reserves can be assigned to such properties. Devon assesses its unproved properties for impairment quarterly. Significant unproved properties are assessed individually. Costs of insignificant unproved properties are transferred into the depletion calculation over holding periods ranging from three to four years.
No gain or loss is recognized upon disposal of oil and gas properties unless such disposal significantly alters the relationship between capitalized costs and proved reserves in a particular country.
Depreciation of midstream pipelines are provided on a unit-of-production basis. Depreciation and amortization of other property and equipment, including corporate and other midstream assets and leasehold improvements, are provided using the straight-line method based on estimated useful lives ranging from three to 60 years. Interest costs incurred and attributable to major midstream and corporate construction projects are also capitalized.
Devon recognizes liabilities for retirement obligations associated with tangible long-lived assets, such as producing well sites 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. When the assumptions used to estimate a recorded asset retirement obligation change, a revision is recorded to both the asset retirement obligation and the asset retirement cost. Devon’s asset retirement obligations include estimated environmental remediation costs which arise from normal operations and are associated with the retirement of such long-lived assets. The asset retirement cost is depreciated using a systematic and rational method similar to that used for the associated property and equipment.
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. Such test includes an assessment of qualitative and quantitative factors. The impairment test requires allocating goodwill and all other assets and liabilities to assigned reporting units. The fair value of each reporting unit is estimated and compared to the net book value of the reporting unit. If the estimated fair value of the reporting unit is less than the net book value, including goodwill, then the goodwill is written down to the implied fair value of the goodwill through a charge to expense. Because quoted market prices are not available for Devon's reporting units, the fair values of the reporting units are estimated based upon several valuation analyses, including comparable companies, comparable transactions and premiums paid.
Devon performed annual impairment tests of goodwill in the fourth quarters of 2012, 2011 and 2010. Based on these assessments, no impairment of goodwill was required.
The table below provides a summary of Devon's goodwill, by assigned reporting unit. The increase in Devon’s goodwill from 2011 to 2012 was due to changes in the exchange rate between the U.S. dollar and the Canadian dollar.
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December 31, |
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2012 |
2011 |
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(In millions) |
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U.S. |
$ 3,046
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$ 3,046
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Canada |
3,033 | 2,967 |
Total |
$ 6,079
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$ 6,013
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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 resulting from improper operation of assets 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.
Fair Value Measurements
Certain of Devon's assets and liabilities are measured at fair value at each reporting date. Fair value represents the price that would be received to sell the asset or paid to transfer the liability in an orderly transaction between market participants. This price is commonly referred to as the “exit price.” Fair value measurements are classified according to a hierarchy that prioritizes the inputs underlying the valuation techniques. This hierarchy consists of three broad levels:
· |
Level 1 – Inputs consist of unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. When available, Devon measures fair value using Level 1 inputs because they generally provide the most reliable evidence of fair value. |
· |
Level 2 – Inputs consist of 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 – Inputs are not observable from objective sources and have the lowest priority. The most common Level 3 fair value measurement is an internally developed cash flow model. |
Discontinued Operations
As a result of the November 2009 plan to divest Devon’s offshore assets, all amounts related to Devon's International operations are classified as discontinued operations. The Gulf of Mexico properties that were divested in 2010 do not qualify as discontinued operations under accounting rules. As such, amounts in these notes and the accompanying financial statements that pertain to continuing operations include amounts related to Devon’s offshore Gulf of Mexico operations.
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. Assets and liabilities of the Canadian subsidiaries are translated to U.S. dollars using the applicable exchange rate as of the end of a reporting period. Revenues, expenses and cash flow are translated using an average exchange rate during the reporting period. Translation adjustments have no effect on net income and are included in accumulated other comprehensive earnings in stockholders' equity.
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2.Derivative Financial Instruments
Commodity Derivatives
As of December 31, 2012, Devon had the following open oil derivative positions. Devon’s oil derivatives settle against the average of the prompt month NYMEX West Texas Intermediate futures price.
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Price Swaps |
Price Collars |
Call Options Sold |
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Period |
Volume (Bbls/d) |
Weighted Average Price ($/Bbl) |
Volume (Bbls/d) |
Weighted Average Floor Price ($/Bbl) |
Weighted Average Ceiling Price ($/Bbl) |
Volume (Bbls/d) |
Weighted Average Price ($/Bbl) |
Q1-Q4 2013 |
31,000 |
$104.13 |
45,753 |
$91.19 |
$115.97 |
10,000 |
$120.00 |
Q1-Q4 2014 |
4,000 |
$100.49 |
2,000 |
$90.00 |
$111.13 |
10,000 |
$120.00 |
Basis Swaps |
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Period |
Index |
Volume (Bbls/d) |
Weighted Average Differential to WTI ($/Bbl) |
Q1-Q2 2013 |
Western Canadian Select |
3,000 |
$(19.58) |
As of December 31, 2012, Devon had the following open natural gas derivative positions. The first table presents Devon’s natural gas swaps and collars that settle against the Inside FERC first of the month Henry Hub index. The second table presents Devon’s natural gas swaps and collars that settle against the AECO index.
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Price Swaps |
Price Collars |
Call Options Sold |
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Period |
Volume (MMBtu/d) |
Weighted Average Price ($/MMBtu) |
Volume (MMBtu/d) |
Weighted Average Floor Price ($/MMBtu) |
Weighted Average Ceiling Price ($/MMBtu) |
Volume (MMBtu/d) |
Weighted Average Price ($/MMBtu) |
Q1-Q4 2013 |
560,000 |
$4.18 |
461,370 |
$3.53 |
$4.33 |
— |
— |
Q1-Q4 2014 |
250,000 |
$4.09 |
— |
— |
— |
250,000 |
$5.00 |
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Price Swaps |
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Period |
Volume (MMBtu/d) |
Weighted Average Price ($/MMBtu) |
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Q1-Q4 2013 |
28,435 |
$3.64 |
Basis Swaps |
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Period |
Index |
Volume (MMBtu/d) |
Weighted Average Differential to Henry Hub ($/MMBtu) |
Q1-Q4 2013 |
El Paso Natural Gas |
20,000 |
$(0.12) |
Q1-Q4 2013 |
Panhandle Eastern Pipeline |
20,000 |
$(0.17) |
As of December 31, 2012, Devon had the following open NGL derivative positions. Devon’s NGL swaps settle against the average of the prompt month OPIS Mont Belvieu, Texas hub.
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Price Swaps |
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Period |
Product |
Volume (Bbls/d) |
Weighted Average Floor Price ($/Bbl) |
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Q1-Q4 2013 |
Propane |
822 |
$41.12 |
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Q1-Q4 2013 |
Ethane |
1,973 |
$15.36 |
Basis Swaps |
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Period |
Pay |
Volume (Bbls/d) |
Weighted Average Differential to WTI ($/Bbl) |
Q1-Q4 2013 |
Natural Gasoline |
500 |
$(6.80) |
Interest Rate Derivatives
As of December 31, 2012, Devon had the following open interest rate derivative positions:
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Notional |
Weighted Average Fixed Rate Received |
Variable Rate Paid |
Expiration |
(In millions) |
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$ 750
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3.88% |
Federal funds rate |
July 2013 |
Foreign Currency Derivatives
As of December 31, 2012, Devon had the following open foreign currency derivative positions:
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Forward Contract |
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Currency |
Contract Type |
CAD Notional |
Weighted Average Fixed Rate Received |
Expiration |
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(In millions) |
(CAD-USD) |
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Canadian Dollar |
Sell |
$ 755
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1.005 |
March 2013 |
Financial Statement Presentation
The following table presents the cash settlements and unrealized gains and losses on fair value changes included in the accompanying comprehensive statements of earnings associated with derivative financial instruments.
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Comprehensive Statement of Earnings Caption |
2012 |
2011 |
2010 |
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(In millions) |
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Cash settlements: |
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Commodity derivatives |
Oil, gas and NGL derivatives |
$ 870
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$ 392
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$ 888
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Interest rate derivatives |
Other, net |
14 | 77 | 44 | |
Foreign currency derivatives |
Other, net |
(19) | 16 |
— |
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Total cash settlements |
865 | 485 | 932 | ||
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Unrealized gains (losses): |
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Commodity derivatives |
Oil, gas and NGL derivatives |
(177) | 489 | (77) | |
Interest rate derivatives |
Other, net |
(29) | (88) | (30) | |
Foreign currency derivatives |
Other, net |
1 |
— |
— |
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Total unrealized gains (losses) |
(205) | 401 | (107) | ||
Net gain recognized on comprehensive statements of earnings |
$ 660
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$ 886
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$ 825
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The following table presents the derivative fair values included in the accompanying balance sheets.
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December 31, |
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Balance Sheet Caption |
2012 |
2011 |
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(In millions) |
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Asset derivatives: |
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Commodity derivatives |
Other current assets |
$ 379
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$ 611
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Commodity derivatives |
Other long-term assets |
22 | 17 |
Interest rate derivatives |
Other current assets |
23 | 30 |
Interest rate derivatives |
Other long-term assets |
— |
22 |
Foreign currency derivatives |
Other current assets |
1 |
— |
Total asset derivatives |
$ 425
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$ 680
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Liability derivatives: |
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Commodity derivatives |
Other current liabilities |
$ 3
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$ 82
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Commodity derivatives |
Other long-term liabilities |
29 |
— |
Total liability derivatives |
$ 32
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$ 82
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4.Restructuring Costs
Office Consolidation
In October 2012, Devon announced plans to consolidate its U.S. personnel into a single operations group centrally located at the company’s corporate headquarters in Oklahoma City. As a result, Devon is in the process of closing its office in Houston and transferring operational responsibilities for assets in South Texas, East Texas and Louisiana to Oklahoma City. This initiative is expected to be substantially complete by the end of the first quarter 2013.
Including the $80 million recognized in December of 2012, Devon estimates that it will incur approximately $135 million in restructuring costs in connection with this plan. This estimate includes approximately $85 million of employee severance and relocation costs, $35 million of contract termination and other costs and $15 million of employee retention costs. Approximately $25 million of employee costs relates to accelerated vesting of stock awards, which are non-cash charges. Devon expects to recognize the remainder of the restructuring costs during 2013.
Divestiture of Offshore Assets
In the fourth quarter of 2009, Devon announced plans to divest its offshore assets. As of December 31, 2012, Devon had divested all of its U.S. Offshore and International assets and incurred $196 million of restructuring costs associated with the divestitures.
Financial Statement Presentation
The schedule below summarizes restructuring costs presented in the accompanying comprehensive statements of earnings. Restructuring costs relating to Devon’s discontinued operations totaled $(2) million and $(4) million in 2011 and 2010, respectively. These costs primarily related to cash severance and share-based awards and are not included in the schedule below. There were no costs related to discontinued operations in 2012.
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Year Ended December 31, |
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2012 |
2011 |
2010 |
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(In millions) |
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Office consolidation: |
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|
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Employee severance |
$ 77
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$— |
$— |
Lease obligations |
3 |
— |
— |
Total |
80 |
— |
— |
Offshore divestitures: |
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|
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Employee severance |
(3) | 8 | (27) |
Lease obligations and other |
(3) | (10) | 84 |
Total |
(6) | (2) | 57 |
Restructuring costs |
$ 74
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$ (2)
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$ 57
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Office Consolidation
Employee severance and retention - In the fourth quarter of 2012, Devon recognized $77 million of estimated employee severance costs associated with the office consolidation. This amount was based on estimates of the number employees that would ultimately be impacted by office consolidation and included amounts related to cash severance costs and accelerated vesting of share-based grants.
Lease obligations and other - As of December 31, 2012, Devon incurred $3 million of restructuring costs related to certain office space that is subject to non-cancellable operating lease agreements and that it ceased using as a part of the office consolidation. In 2013 Devon expects to incur approximately $25 million of additional restructuring costs that represent the present value of its future obligations under the leases, net of anticipated sublease income. Devon’s estimate of lease obligations was based upon certain key estimates that could change over the term of the leases. These estimates include the estimated sublease income that it may receive over the term of the leases, as well as the amount of variable operating costs that it will be required to pay under the leases.
Divestiture of Offshore Assets
Lease obligations and other - As a result of the divestitures, Devon ceased using certain office space that was subject to non-cancellable operating lease arrangements. Consequently, in 2010 Devon recognized $70 million of restructuring costs that represented the present value of its future obligations under the leases, net of anticipated sublease income. Devon's estimate of lease obligations was based upon certain key estimates that could change over the term of the leases. These estimates include the estimated sublease income that Devon may receive over the term of the leases, as well as the amount of variable operating costs that Devon will be required to pay under the leases. In addition, Devon recognized $13 million of asset impairment charges for leasehold improvements and furniture associated with the office space that it ceased using.
The schedule below summarizes Devon’s restructuring liabilities. Devon’s restructuring liabilities for cash severance related to its discontinued operations totaled $16 million at December 31, 2010 and are not included in the schedule below. There was no liability related to discontinued operations at the end of 2012 or 2011.
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|
|
|
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Other Current Liabilities |
Other Long-Term Liabilities |
Total |
|
(In millions) |
||
Balance as of December 31, 2010 |
$ 31
|
$ 51
|
$ 82
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Lease obligations - Offshore |
2 | (35) | (33) |
Employee severance - Offshore |
(4) |
— |
(4) |
Balance as of December 31, 2011 |
29 | 16 | 45 |
Employee severance – Office consolidation |
49 |
— |
49 |
Lease obligations - Offshore |
(17) | (7) | (24) |
Employee severance - Offshore |
(9) |
— |
(9) |
Balance as of December 31, 2012 |
$ 52
|
$ 9
|
$ 61
|
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5.Other, net
The components of other, net in the accompanying comprehensive statement of earnings include the following:
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Year Ended December 31, |
||
|
2012 |
2011 |
2010 |
|
(In millions) |
||
Accretion of asset retirement obligations |
$ 110
|
$ 92
|
$ 92
|
Interest rate derivatives |
15 | 11 | (14) |
Foreign currency derivatives |
18 | (16) |
— |
Foreign exchange loss (gain) |
(15) | 25 | (7) |
Interest income |
(36) | (21) | (13) |
Other |
(14) | (101) | (25) |
Other, net |
$ 78
|
$ (10)
|
$ 33
|
During 2011, Devon received $88 million of excess insurance recoveries related to certain weather and operational claims.
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6.Income Taxes
Income Tax Expense (Benefit)
Devon’s income tax components are presented in the following table.
|
Year Ended December 31, |
||
|
2012 |
2011 |
2010 |
|
(In millions) |
||
Current income tax expense (benefit): |
|
|
|
U.S. federal |
$ 60
|
$ (143)
|
$ 244
|
Various states |
(3) | 20 | 16 |
Canada and various provinces |
(5) | (20) | 256 |
Total current tax expense (benefit) |
52 | (143) | 516 |
Deferred income tax expense (benefit): |
|
|
|
U.S. federal |
(188) | 1,986 | 781 |
Various states |
34 | 95 | 21 |
Canada and various provinces |
(30) | 218 | (83) |
Total deferred tax expense (benefit) |
(184) | 2,299 | 719 |
Total income tax expense (benefit) |
$ (132)
|
$ 2,156
|
$ 1,235
|
Total income tax expense (benefit) differed from the amounts computed by applying the U.S. federal income tax rate to earnings from continuing operations before income taxes as a result of the following:
|
Year Ended December 31, |
||
|
2012 |
2011 |
2010 |
|
(In millions) |
||
Expected income tax expense (benefit) based on U.S. statutory tax rate of 35% |
$ (111)
|
$ 1,502
|
$ 1,249
|
Assumed repatriations |
— |
725 | 144 |
State income taxes |
20 | 70 | 31 |
Taxation on Canadian operations |
(19) | (91) | (60) |
Other |
(22) | (50) | (129) |
Total income tax expense (benefit) |
$ (132)
|
$ 2,156
|
$ 1,235
|
During 2011 and 2010, pursuant to the completed and planned divestitures of Devon’s International assets located outside North America, a portion of Devon’s foreign earnings were no longer deemed to be indefinitely reinvested. Accordingly, Devon recognized deferred income tax expense of $725 million and $144 million during 2011 and 2010 respectively, related to assumed repatriations of earnings from its foreign subsidiaries.
Deferred Tax Assets and Liabilities
The tax effects of temporary differences that gave rise to Devon’s deferred tax assets and liabilities are presented below:
|
December 31, |
|
|
2012 |
2011 |
Deferred tax assets: |
(In millions) |
|
Net operating loss carryforwards |
$ 427
|
$ 222
|
Asset retirement obligations |
618 | 447 |
Pension benefit obligations |
129 | 130 |
Alternative minimum tax credits |
198 |
— |
Other |
134 | 117 |
Total deferred tax assets |
1,506 | 916 |
Deferred tax liabilities: |
|
|
Property and equipment |
(4,970) | (4,475) |
Fair value of financial instruments |
(141) | (218) |
Long-term debt |
(198) | (185) |
Taxes on unremitted foreign earnings |
(936) | (936) |
Other |
(76) | (27) |
Total deferred tax liabilities |
(6,321) | (5,841) |
Net deferred tax liability |
$ (4,815)
|
$ (4,925)
|
Devon has recognized $427 million of deferred tax assets related to various carryforwards available to offset future income taxes. The carryforwards consist of $711 million of U.S. federal net operating loss carryforwards, which expire in 2031, $662 million of Canadian net operating loss carryforwards, which expire between 2029 and 2031, and $153 million of state net operating loss carryforwards, which expire primarily between 2013 and 2031. Devon expects the tax benefits from the U.S. federal net operating loss carryforwards to be utilized between 2013 and 2015. Devon expects the tax benefits from the Canadian and state net operating loss carryforwards to be utilized between 2013 and 2017. Such expectations are based upon current estimates of taxable income during these periods, considering limitations on the annual utilization of these benefits as set forth by tax regulations. Significant changes in such estimates caused by variables such as future oil, gas and NGL 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 its tax carryforwards prior to their expiration.
Devon has also recognized a $198 million deferred tax asset related to alternative minimum tax credits which have no expiration date and will be available for use against tax on future taxable income.
As of December 31, 2012, Devon’s unremitted foreign earnings totaled approximately $8.0 billion. Of this amount, approximately $5.5 billion was deemed to be indefinitely reinvested into the development and growth of our Canadian business. Therefore, Devon has not recognized a deferred tax liability for U.S. income taxes associated with such earnings. If such earnings were to be repatriated to the U.S., Devon may be subject to U.S. income taxes and foreign withholding taxes. However, it is not practical to estimate the amount of such additional taxes that may be payable due to the inter-relationship of the various factors involved in making such an estimate.
Devon has deemed the remaining $2.5 billion of unremitted earnings not to be indefinitely reinvested. Consequently, Devon has recognized a $936 million deferred tax liability associated with such unremitted earnings as of December 31, 2012. Although Devon has recognized this deferred tax liability, Devon does not currently expect to repatriate its foreign earnings. This expectation is based on Devon’s current forecasts for both its U.S. and Canadian operations, currently favorable borrowing conditions in the U.S., and existing U.S. income tax laws pertaining to repatriations of foreign earnings.
Unrecognized Tax Benefits
The following table presents changes in Devon's unrecognized tax benefits.
|
December 31, |
|
|
2012 |
2011 |
|
(In millions) |
|
Balance at beginning of year |
$ 165
|
$ 194
|
Tax positions taken in prior periods |
(46) | (3) |
Tax positions taken in current year |
92 | 27 |
Accrual of interest related to tax positions taken |
7 | (7) |
Lapse of statute of limitations |
(3) | (41) |
Settlements |
— |
(5) |
Foreign currency translation |
1 |
— |
Balance at end of year |
$ 216
|
$ 165
|
Devon’s unrecognized tax benefit balance at December 31, 2012 and 2011, included $27 million and $20 million of interest and penalties, respectively. If recognized, $176 million of Devon's unrecognized tax benefits as of December 31, 2012 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 |
2008-2012 |
Various U.S. states |
2008-2012 |
Canada federal |
2004-2012 |
Various Canadian provinces |
2004-2012 |
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.
|
8.Other Comprehensive Earnings
Components of other comprehensive earnings consist of the following:
|
Year Ended December 31, |
||
|
2012 |
2011 |
2010 |
|
(In millions) |
||
Foreign currency translation: |
|
||
Beginning accumulated foreign currency translation |
$ 1,802
|
$ 1,993
|
$ 1,616
|
Change in cumulative translation adjustment |
203 | (200) | 397 |
Income tax benefit (expense) |
(9) | 9 | (20) |
Ending accumulated foreign currency translation |
1,996 | 1,802 | 1,993 |
Pension and postretirement benefit plans: |
|
|
|
Beginning accumulated pension and postretirement benefits |
(227) | (233) | (231) |
Net actuarial loss and prior service cost arising in current year |
(47) | (21) | (33) |
Income tax benefit |
16 | 8 | 11 |
Recognition of net actuarial loss and prior service cost in net earnings |
51 | 30 | 31 |
Income tax expense |
(18) | (11) | (11) |
Ending accumulated pension and postretirement benefits |
(225) | (227) | (233) |
Accumulated other comprehensive earnings, net of tax |
$ 1,771
|
$ 1,575
|
$ 1,760
|
|
9.Supplemental Information to Statements of Cash Flows
|
Year Ended December 31, |
||
|
2012 |
2011 |
2010 |
|
(In millions) |
||
Net decrease (increase) in working capital: |
|
||
Change in accounts receivable |
$ 140
|
$ (185)
|
$ 23
|
Change in other current assets |
(128) | 125 | 21 |
Change in accounts payable |
(8) | 64 | 37 |
Change in revenues and royalties payable |
19 | 144 | 48 |
Change in other current liabilities |
(73) | 37 | (402) |
Net decrease (increase) in working capital |
$ (50)
|
$ 185
|
$ (273)
|
|
|
|
|
Supplementary cash flow data – total operations: |
|
|
|
Interest paid (net of capitalized interest) |
$ 334
|
$ 325
|
$ 359
|
Income taxes paid (received) |
$ 100
|
$ (383)
|
$ 955
|
|
10.Short-Term Investments
The components of short-term investments include the following:
|
December 31, |
|
|
2012 |
2011 |
|
(In millions) |
|
Canadian treasury, agency and provincial securities |
$ 1,865
|
$ 1,155
|
U.S. treasuries |
429 | 201 |
Other |
49 | 147 |
Short-term investments |
$ 2,343
|
$ 1,503
|
|
11. Accounts Receivable
The components of accounts receivable include the following:
|
December 31, |
|
|
2012 |
2011 |
|
(In millions) |
|
Oil, gas and NGL sales |
$ 752
|
$ 928
|
Joint interest billings |
270 | 247 |
Marketing and midstream revenues |
161 | 174 |
Other |
72 | 39 |
Gross accounts receivable |
1,255 | 1,388 |
Allowance for doubtful accounts |
(10) | (9) |
Net accounts receivable |
$ 1,245
|
$ 1,379
|
|
12.Other Current Assets
The components of other current assets include the following:
|
December 31, |
|
|
2012 |
2011 |
|
(In millions) |
|
Derivative financial instruments |
$ 403
|
$ 641
|
Inventories |
110 | 102 |
Income tax receivable |
119 | 35 |
Current assets held for sale |
3 | 21 |
Other |
111 | 69 |
Other current assets |
$ 746
|
$ 868
|
|
13.Property and Equipment
See Note 22 for disclosure of Devon’s capitalized costs related to its oil and gas exploration and development activities.
Sinopec Transaction
In April 2012, Devon closed its joint venture transaction with Sinopec International Petroleum Exploration & Production Corporation. Pursuant to the agreement, Sinopec paid approximately $900 million in cash and received a 33.3 percent interest in five of Devon’s new ventures exploration plays in the U.S. at closing of the transaction. Additionally, Sinopec is required to fund approximately $1.6 billion of Devon’s share of future exploration, development and drilling costs associated with these plays. Devon recognized the cash proceeds received at closing as a reduction to U.S. oil and gas property and equipment. No gain or loss was recognized.
Sumitomo Transaction
In September 2012, Devon closed its joint venture transaction with Sumitomo Corporation. At closing, Sumitomo paid approximately $400 million in cash and received a 30 percent interest in the Cline and Midland-Wolfcamp Shale plays in Texas. Additionally, Sumitomo is required to fund approximately $1.0 billion of Devon’s share of future exploration, development and drilling costs associated with these plays. Devon recognized the cash proceeds received at closing as a reduction to U.S. oil and gas property and equipment. No gain or loss was recognized.
Asset Impairments
In the third and fourth quarters of 2012, Devon recognized asset impairments related to its oil and gas property and equipment and its U.S. midstream assets as presented below.
|
Q3 2012 |
Q4 2012 |
Year Ended December 31, 2012 |
|||
|
Gross |
Net of Taxes |
Gross |
Net of Taxes |
Gross |
Net of Taxes |
|
(In millions) |
|||||
U.S. oil and gas assets |
$ 1,106
|
$ 705
|
$ 687
|
$ 437
|
$ 1,793
|
$ 1,142
|
Canada oil and gas assets |
— |
— |
163 | 122 | 163 | 122 |
Midstream assets |
22 | 14 | 46 | 30 | 68 | 44 |
Total asset impairments |
$ 1,128
|
$ 719
|
$ 896
|
$ 589
|
$ 2,024
|
$ 1,308
|
Oil and Gas Impairments
Under the full-cost method of accounting, capitalized costs of oil and gas properties are subject to a quarterly full cost ceiling test, which is discussed in Note 1.
The oil and gas impairments resulted primarily from declines in the U.S. and Canada full cost ceilings. The lower ceiling values resulted primarily from decreases in the 12-month average trailing prices for oil, natural gas and NGLs, which have reduced proved reserve values.
If pricing conditions do not improve, Devon may incur full cost ceiling impairments related to its oil and gas property and equipment in 2013.
Midstream Impairments
Due to declining natural gas production resulting from low natural gas and NGL prices, Devon determined that the carrying amounts of certain of its midstream facilities were not recoverable from estimated future cash flows. Consequently, the assets were written down to their estimated fair values, which were determined using discounted cash flow models. The fair value of Devon’s midstream assets is considered a Level 3 fair value measurement.
Offshore Divestitures
In November 2009, Devon announced plans to divest its offshore assets. In 2012, Devon completed its planned divestiture program. In aggregate, Devon’s U.S. and International sales generated total proceeds of $10 billion. Assuming repatriation of a portion of the foreign proceeds under current U.S. tax law, the after-tax proceeds from these transactions were approximately $8 billion.
|
14.Debt and Related Expenses
A summary of Devon's debt is as follows:
|
December 31, |
|
|
2012 |
2011 |
|
(In millions) |
|
Commercial paper |
$ 3,189
|
$ 3,726
|
Other debentures and notes: |
|
|
5.625% due January 15, 2014 |
500 | 500 |
Non-interest bearing promissory note due June 29, 2014 |
— |
85 |
2.40% due July 15, 2016 |
500 | 500 |
1.875% due May 15, 2017 |
750 |
— |
8.25% due July 1, 2018 |
125 | 125 |
6.30% due January 15, 2019 |
700 | 700 |
4.00% due July 15, 2021 |
500 | 500 |
3.25% due May 15, 2022 |
1,000 |
— |
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 |
5.60% due July 15, 2041 |
1,250 | 1,250 |
4.75% due May 15, 2042 |
750 |
— |
Net discount on other debentures and notes |
(20) | (6) |
Total debt |
11,644 | 9,780 |
Less amount classified as short-term debt |
3,189 | 3,811 |
Long-term debt |
$ 8,455
|
$ 5,969
|
Debt maturities as of December 31, 2012, excluding premiums and discounts, are as follows (in millions):
2013 |
$ 3,189
|
2014 |
500 |
2015 |
— |
2016 |
500 |
2017 |
750 |
2018 and thereafter |
6,725 |
Total |
$ 11,664
|
Credit Lines
Devon has a $3.0 billion syndicated, unsecured revolving line of credit (the "Senior Credit Facility"). The Senior Credit Facility has an initial maturity date of October 24, 2017. However, prior to the maturity date, Devon has the option to extend the maturity for up to two additional one-year periods, subject to the approval of the lenders.
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 $3.8 million that is payable quarterly in arrears. As of December 31, 2012, there were no borrowings under the Senior Credit Facility.
The Senior Credit Facility contains only one material financial covenant. This covenant requires Devon’s ratio of total funded debt to total capitalization, as defined in the credit agreement, to be no greater than 65 percent. The credit agreement contains definitions of total funded debt and total capitalization that include adjustments to the respective amounts reported in the accompanying financial statements. Also, total capitalization is adjusted to add back noncash financial write-downs such as full cost ceiling impairments or goodwill impairments. As of December 31, 2012, Devon was in compliance with this covenant with a debt-to-capitalization ratio of 25.4 percent.
Commercial Paper
Devon has access to $5.0 billion of short-term credit under its commercial paper program. Commercial paper debt generally has a maturity of between 1 and 90 days, although it can have a maturity of up to 365 days, and bears interest at rates agreed to at the time of the borrowing. The interest rate is generally based on a standard index such as the Federal Funds Rate, LIBOR, or the money market rate as found in the commercial paper market. As of December 31, 2012, Devon’s weighted average borrowing rate on its commercial paper borrowings was 0.37 percent.
Other Debentures and Notes
Following are descriptions of the various other debentures and notes outstanding at December 31, 2012, as listed in the table presented at the beginning of this note.
In 2012, 2011, 2009 and 2002 Devon issued senior notes that are unsecured and unsubordinated obligations of Devon. Devon used the net proceeds to repay outstanding commercial paper and credit facility borrowings. The schedule below summarizes the key terms of these notes ($ in millions).
|
May 2012 |
July 2011 |
January 2009 |
March 2002 |
1.875% due May 15, 2017 |
$ 750
|
$— |
$— |
$— |
3.25% due May 15, 2022 |
1,000 |
— |
— |
— |
4.75% due May 15, 2042 |
750 |
— |
— |
— |
2.40% due July 15, 2016 |
— |
500 |
— |
— |
4.00% due July 15, 2021 |
— |
500 |
— |
— |
5.60% due July 15, 2041 |
— |
1,250 |
— |
— |
5.625% due January 15, 2014 |
— |
— |
500 |
— |
6.30% due January 15, 2019 |
— |
— |
700 |
— |
7.95% due April 15, 2032 |
— |
— |
— |
1,000 |
Discount and issuance costs |
(35) | (29) | (13) | (14) |
Net proceeds |
$ 2,465
|
$ 2,221
|
$ 1,187
|
$ 986
|
Ocean Debt
On April 25, 2003, Devon merged with Ocean Energy, Inc. and assumed certain debt instruments. The table below summarizes the debt assumed that remains outstanding as of December 31, 2012, including the fair value of the debt at April 25, 2003, and the effective interest rate of the debt after determining the fair values using April 25, 2003, market interest rates. The premiums resulting from fair values exceeding face values are being amortized using the effective interest method. Both notes are general unsecured obligations of Devon.
Debt Assumed |
Fair Value of Debt Assumed |
Effective Rate of Debt Assumed |
|
(In millions) |
|
8.250% due July 2018 (principal of $125 million) |
$ 147
|
5.5% |
7.500% due September 2027 (principal of $150 million) |
$ 169
|
6.5% |
7.875% Debentures due September 30, 2031
In October 2001, Devon, through Devon Financing Corporation, U.L.C. (“Devon Financing”), a wholly owned finance subsidiary, sold 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 were used to fund a portion of the acquisition of Anderson Exploration.
Interest Expense
The following schedule includes the components of interest expense.
|
Year Ended December 31, |
||
|
2012 |
2011 |
2010 |
|
(In millions) |
||
Interest based on debt outstanding |
$ 440
|
$ 414
|
$ 408
|
Capitalized interest |
(48) | (72) | (76) |
Early retirement of debt |
— |
— |
19 |
Other |
14 | 10 | 12 |
Interest expense |
$ 406
|
$ 352
|
$ 363
|
|
15.Asset Retirement Obligations
The schedule below summarizes changes in Devon’s asset retirement obligations.
|
Year Ended December 31, |
|
|
2012 |
2011 |
|
(In millions) |
|
Asset retirement obligations as of beginning of period |
$ 1,563
|
$ 1,497
|
Liabilities incurred |
90 | 53 |
Liabilities settled |
(86) | (82) |
Revision of estimated obligation |
420 | 25 |
Liabilities assumed by others |
(23) |
— |
Accretion expense on discounted obligation |
110 | 92 |
Foreign currency translation adjustment |
21 | (22) |
Asset retirement obligations as of end of period |
2,095 | 1,563 |
Less current portion |
99 | 67 |
Asset retirement obligations, long-term |
$ 1,996
|
$ 1,496
|
During 2012, Devon recognized revisions to its asset retirement obligations totaling $420 million. The primary factor contributing to this revision was an overall increase in abandonment cost estimates for certain of its production operations facilities.
|
16.Retirement Plans
Devon has various non-contributory defined benefit pension plans, including qualified plans and nonqualified plans. The qualified plans provide retirement benefits for certain U.S. and Canadian employees meeting certain age and service requirements. Benefits for the qualified plans are based on the employees' years of service and compensation and are funded from assets held in the plans' trusts.
The nonqualified plans provide retirement benefits for certain employees whose benefits under the qualified plans are limited by income tax regulations. The nonqualified plans' benefits are based on the employees' years of service and compensation. For certain nonqualified plans, Devon has established trusts to fund these plans' benefit obligations. The total value of these trusts was $31 million and $32 million at December 31, 2012 and 2011, respectively, and is included in other long-term assets in the accompanying balance sheets. For the remaining nonqualified 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 that provide benefits for substantially all U.S. employees. The plans provide medical and, in some cases, life insurance benefits and are either contributory or non-contributory, depending on the type of plan. Benefit obligations for such plans are estimated based on Devon's future cost-sharing intentions. Devon's funding policy for the 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 funded status of Devon's qualified and nonqualified pension and postretirement benefit plans. The benefit obligation for pension plans represents the projected benefit obligation, while the benefit obligation for the postretirement benefit plans represents the accumulated benefit obligation. The accumulated benefit obligation differs from the projected benefit obligation in that the former includes no assumption about future compensation levels. The accumulated benefit obligation for pension plans was $1.2 billion at December 31, 2012 and 2011. Devon’s benefit obligations and plan assets are measured each year as of December 31. Devon’s 2012 plan settlements relate to a plan amendment which removed a dollar cap on lump sum payments and revised optional forms of payment to include a lump sum distribution feature. Devon’s 2011 pension plan contributions of $454 million presented in the table were primarily discretionary. After these contributions, the projected benefit obligation for Devon’s qualified plans was fully funded as of December 31, 2012 and 2011.
|
Pension Benefits |
Postretirement Benefits |
||
|
2012 | 2011 | 2012 | 2011 |
|
(In millions) |
|||
Change in benefit obligation: |
|
|
|
|
Benefit obligation at beginning of year |
$ 1,303
|
$ 1,124
|
$ 37
|
$ 43
|
Service cost |
43 | 37 | 1 | 1 |
Interest cost |
60 | 60 | 1 | 2 |
Actuarial loss (gain) |
95 | 123 | (4) | (8) |
Plan amendments |
14 |
— |
— |
5 |
Plan curtailments |
(20) |
— |
1 |
— |
Plan settlements |
(93) |
— |
— |
(4) |
Foreign exchange rate changes |
1 | (1) |
— |
— |
Participant contributions |
— |
— |
3 | 3 |
Benefits paid |
(43) | (40) | (5) | (5) |
Benefit obligation at end of year |
1,360 | 1,303 | 34 | 37 |
Change in plan assets: |
|
|
|
|
Fair value of plan assets at beginning of year |
1,187 | 632 |
— |
— |
Actual return on plan assets |
102 | 141 |
— |
— |
Employer contributions |
11 | 454 | 2 | 7 |
Participant contributions |
— |
— |
3 | 3 |
Plan settlements |
(93) |
— |
— |
(5) |
Benefits paid |
(43) | (40) | (5) | (5) |
Foreign exchange rate changes |
1 |
— |
— |
— |
Fair value of plan assets at end of year |
1,165 | 1,187 |
— |
— |
Funded status at end of year |
$ (195)
|
$ (116)
|
$ (34)
|
$ (37)
|
|
|
|
|
|
Amounts recognized in balance sheet: |
|
|
|
|
Noncurrent assets |
$ 62
|
$ 116
|
$— |
$— |
Current liabilities |
(12) | (10) | (3) | (3) |
Noncurrent liabilities |
(245) | (222) | (31) | (34) |
Net amount |
$ (195)
|
$ (116)
|
$ (34)
|
$ (37)
|
|
|
|
|
|
Amounts recognized in accumulated other comprehensive earnings: |
|
|
|
|
Net actuarial loss (gain) |
$ 340
|
$ 348
|
$ (11)
|
$ (9)
|
Prior service cost (credit) |
25 | 18 | (4) | (5) |
Total |
$ 365
|
$ 366
|
$ (15)
|
$ (14)
|
The plan assets for pension benefits in the table above exclude the assets held in trusts for the nonqualified plans. However, employer contributions for pension benefits in the table above include $10 million and $8 million for 2012 and 2011, respectively, which were transferred from the trusts established for the nonqualified plans.
Certain of Devon's pension plans have a projected benefit obligation and accumulated benefit obligation in excess of plan assets at December 31, 2012 and 2011 as presented in the table below.
|
December 31, |
|
|
2012 |
2011 |
|
(In millions) |
|
Projected benefit obligation |
$ 257
|
$ 232
|
Accumulated benefit obligation |
$ 216
|
$ 189
|
Fair value of plan assets |
$— |
$— |
Net Periodic Benefit Cost and Other Comprehensive Earnings
The following table presents the components of net periodic benefit cost and other comprehensive earnings.
|
|
|
|
|
|
|
|
Pension Benefits |
Postretirement Benefits |
||||
|
2012 |
2011 |
2010 |
2012 |
2011 |
2010 |
|
(In millions) |
|||||
Net periodic benefit cost: |
|
|
|
|
|
|
Service cost |
$ 43
|
$ 37
|
$ 33
|
$ 1
|
$ 1
|
$ 1
|
Interest cost |
60 | 60 | 58 | 1 | 2 | 3 |
Expected return on plan assets |
(64) | (42) | (36) |
— |
— |
— |
Curtailment and settlement expense |
26 |
— |
— |
1 | (3) |
— |
Recognition of net actuarial loss (gain) |
24 | 32 | 27 | (1) |
— |
— |
Recognition of prior service cost |
3 | 3 | 3 | (1) | (2) | 1 |
Total net periodic benefit cost |
92 | 90 | 85 | 1 | (2) | 5 |
Other comprehensive loss (earnings): |
|
|
|
|
|
|
Actuarial loss (gain) arising in current year |
37 | 23 | 50 | (4) | (7) | 1 |
Prior service cost (credit) arising in current year |
14 |
— |
4 |
— |
5 | (22) |
Recognition of net actuarial loss, including settlement expense, in net periodic benefit cost |
(45) | (32) | (27) | 1 | 3 |
— |
Recognition of prior service cost, including curtailment, in net periodic benefit cost |
(8) | (3) | (3) | 1 | 2 | (1) |
Total other comprehensive loss (earnings) |
(2) | (12) | 24 | (2) | 3 | (22) |
Total recognized |
$ 90
|
$ 78
|
$ 109
|
$ (1)
|
$ 1
|
$ (17)
|
The following table presents the estimated net actuarial loss and prior service cost that will be amortized from accumulated other comprehensive earnings into net periodic benefit cost during 2013.
|
|
|
|
Pension Benefits |
Postretirement Benefits |
|
(In millions) |
|
Net actuarial loss (gain) |
$ 22
|
$ (1)
|
Prior service cost (credit) |
4 |
— |
Total |
$ 26
|
$ (1)
|
Assumptions
The following table presents the weighted average actuarial assumptions used to determine obligations and periodic costs.
|
Pension Benefits |
Postretirement Benefits |
||||
|
2012 |
2011 |
2010 |
2012 |
2011 |
2010 |
Assumptions to determine benefit obligations: |
|
|
|
|
|
|
Discount rate |
3.85% | 4.65% | 5.50% | 3.30% | 4.25% | 4.90% |
Rate of compensation increase |
4.48% | 4.97% | 6.94% |
N/A |
N/A |
N/A |
Assumptions to determine net periodic benefit cost: |
|
|
|
|
|
|
Discount rate |
4.65% | 5.50% | 6.00% | 4.25% | 4.90% | 5.70% |
Expected return on plan assets |
5.48% | 6.48% | 6.94% |
N/A |
N/A |
N/A |
Rate of compensation increase |
4.97% | 6.94% | 6.95% |
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.
Rate of compensation increase – For measurement of the 2012 benefit obligation for the pension plans, a 4.48 percent compensation increase was assumed.
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. See the pension plan assets section below for more information on Devon's target allocations.
Other assumptions – For measurement of the 2012 benefit obligation for the other postretirement medical plans, an 8.2 percent annual rate of increase in the per capita cost of covered health care benefits was assumed for 2013. The rate was assumed to decrease annually to an ultimate rate of 5 percent 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 changed the postretirement benefits obligation as of December 31, 2012, by $2 million and would change the 2013 service and interest cost components of net periodic benefit cost by less than $1 million.
Pension Plan Assets
Devon's overall investment objective for its pension plans' assets is to achieve stability of the plans’ funded status while providing long-term growth of invested capital and income to ensure benefit payments can be funded when required. To assist in achieving this objective, Devon has established certain investment strategies, including target allocation percentages and permitted and prohibited investments, designed to mitigate risks inherent with investing. Derivatives or other speculative investments considered high risk are generally prohibited. The following table presents Devon’s target allocation for its pension plan assets.
|
|
|
|
December 31, |
|
|
2012 |
2011 |
Fixed income |
70% | 70% |
Equity |
20% | 20% |
Other |
10% | 10% |
The fair values of Devon's pension assets are presented by asset class in the following tables.
|
As of December 31, 2012 |
||||
|
|
|
Fair Value Measurements Using: |
||
|
Actual Allocation |
Total |
Level 1 Inputs |
Level 2 Inputs |
Level 3 Inputs |
|
($ in millions) |
||||
Fixed-income securities: |
|
|
|
|
|
U.S. Treasury obligations |
39.4% | $ 459
|
$ 65
|
$ 394
|
$— |
Corporate bonds |
26.5% | 308 | 256 | 52 |
— |
Other bonds |
2.4% | 28 | 28 |
— |
— |
Total fixed-income securities |
68.3% | 795 | 349 | 446 |
— |
Equity securities: |
|
|
|
|
|
Global (large, mid, small cap) |
20.5% | 239 |
— |
239 |
— |
Other securities: |
|
|
|
|
|
Hedge fund & alternative investments |
10.3% | 120 | 17 |
— |
103 |
Short-term investment funds |
0.9% | 11 |
— |
11 |
— |
Total other securities |
11.2% | 131 | 17 | 11 | 103 |
Total investments |
100.0% | $ 1,165
|
$ 366
|
$ 696
|
$ 103
|
|
As of December 31, 2011 |
||||
|
|
|
Fair Value Measurements Using: |
||
|
Actual Allocation |
Total |
Level 1 Inputs |
Level 2 Inputs |
Level 3 Inputs |
|
($ in millions) |
||||
Fixed-income securities: |
|
|
|
|
|
U.S. Treasury obligations |
43.9% | $ 522
|
$ 27
|
$ 495
|
$— |
Corporate bonds |
24.8% | 294 | 265 | 29 |
— |
Other bonds |
3.1% | 36 | 36 |
— |
— |
Total fixed-income securities |
71.8% | 852 | 328 | 524 |
— |
Equity securities: |
|
|
|
|
|
Global (large, mid, small cap) |
18.0% | 214 |
— |
214 |
— |
Other securities: |
|
|
|
|
|
Hedge fund & alternative investments |
8.9% | 106 | 16 |
— |
90 |
Short-term investment funds |
1.3% | 15 |
— |
15 |
— |
Total other securities |
10.2% | 121 | 16 | 15 | 90 |
Total investments |
100.0% | $ 1,187
|
$ 344
|
$ 753
|
$ 90
|
The following methods and assumptions were used to estimate the fair values in the tables above.
Fixed-income securities – Devon's fixed-income securities consist of U.S. Treasury obligations, bonds issued by investment-grade companies from diverse industries, and asset-backed securities. These 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.
Devon’s fixed income securities also include commingled funds that primarily invest in long-term bonds and U.S. Treasury securities. These fixed income 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.
Equity securities – Devon’s equity securities include a commingled global equity fund that invests in large, mid and small capitalization stocks across the world’s developed and emerging markets. 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.
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 hedge fund and alternative investments include an investment in an actively traded global mutual fund that focuses on alternative investment strategies and a hedge fund of funds that invests both long and short using a variety of investment strategies. Devon's hedge fund of funds is not actively traded and Devon is subject to redemption restrictions with regards to this investment. The fair value of this Level 3 investment represents the fair value as determined by the hedge fund manager.
Included below is a summary of the changes in Devon's Level 3 plan assets (in millions).
December 31, 2010 |
$ 58
|
Purchases |
33 |
Investment returns |
(1) |
December 31, 2011 |
90 |
Purchases |
6 |
Investment returns |
7 |
December 31, 2012 |
$ 103
|
Expected Cash Flows
The following table presents expected cash flow information for Devon's pension and postretirement benefit plans.
|
|
|
|
|
Pension Benefits |
Postretirement Benefits |
|
|
(In millions) |
||
Devon's 2013 contributions |
$ 11
|
$ 3
|
|
Benefit payments: |
|
|
|
2013 |
$ 60
|
$ 3
|
|
2014 |
$ 61
|
$ 3
|
|
2015 |
$ 63
|
$ 3
|
|
2016 |
$ 65
|
$ 3
|
|
2017 |
$ 67
|
$ 3
|
|
2018 to 2022 |
$ 386
|
$ 14
|
Expected contributions included in the table above include amounts related to Devon's qualified plans, nonqualified plans and postretirement plans. Of the benefits expected to be paid in 2013, the $11 million of pension benefits is expected to be funded from the trusts established for the nonqualified plans and the $3 million of 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.
Defined Contribution Plans
Devon maintains several defined contribution plans covering its employees in the U.S. and Canada. Such plans include Devon’s 401(k) plan, enhanced contribution plan and Canadian pension and savings plan. Contributions are primarily based upon percentages of annual compensation and years of service. In addition, each plan is subject to regulatory limitations by each respective government. The following table presents Devon's expense related to these defined contribution plans.
|
Year Ended December 31, |
||
|
2012 |
2011 |
2010 |
|
(In millions) |
||
401(k) and enhanced contribution plans |
$ 36
|
$ 33
|
$ 32
|
Canadian pension and savings plans |
23 | 21 | 17 |
Total |
$ 59
|
$ 54
|
$ 49
|
|
17.Stockholders' Equity
The authorized capital stock of Devon consists of 1 billion shares of common stock, par value $0.10 per share, and 4.5 million shares of preferred stock, par value $1.00 per share. The preferred stock may be issued in one or more series, and the terms and rights of such stock will be determined by the Board of Directors.
Devon's Board of Directors has designated 2.9 million shares of the preferred stock as Series A Junior Participating Preferred Stock (the “Series A Junior Preferred Stock”). At December 31, 2012, there were no shares of Series A Junior Preferred Stock issued or outstanding. The Series A Junior Preferred Stock is entitled to receive cumulative quarterly dividends per share equal to the greater of $1.00 or 100 times the aggregate per share amount of all dividends (other than stock dividends) declared on common stock since the immediately preceding quarterly dividend payment date or, with respect to the first payment date, since the first issuance of Series A Junior Preferred Stock. Holders of the Series A Junior Preferred Stock are entitled to 100 votes per share on all matters submitted to a vote of the stockholders. Devon, at its option, may redeem shares of the Series A Junior Participating Preferred Stock in whole at any time and in part from time to time, at a redemption price equal to 100 times the current per share market price of Devon’s common stock on the date of the mailing of the notice of redemption. The Series A Junior Preferred Stock ranks prior to the common stock but junior to all other classes of Preferred Stock.
Stock Repurchases
In fourth quarter of 2011, Devon completed its 2010 repurchase program. In total, Devon repurchased 49.2 million shares for $3.5 billion, or $71.18 per share.
Dividends
Devon paid common stock dividends of $324 million, $278 million and $281 million in 2012, 2011 and 2010 respectively. The quarterly cash dividend was $0.16 per share in 2010 and the first quarter of 2011. Devon increased the dividend rate to $0.17 per share in the second quarter of 2011 and further increased the dividend rate to $0.20 per share in the first quarter of 2012.
|
18.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. Actual amounts could differ materially from management's estimates.
Royalty Matters
Numerous natural gas producers and related parties, including Devon, have been named in various lawsuits alleging royalty underpayments. The suits allege that the producers and related parties used below-market prices, made improper deductions, used improper measurement techniques and entered into gas purchase and processing arrangements with affiliates that resulted in underpayment of royalties in connection with natural gas and NGLs produced and sold. Devon’s largest exposure for such matters relates to royalties in New Mexico. Devon does not currently believe that it is subject to material exposure with respect to such royalty matters.
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 remediation costs. Devon's monetary exposure for environmental matters is not expected to be material.
Chief Redemption Matters
In 2006, Devon acquired Chief Holdings LLC (“Chief”) from the owners of Chief, including Trevor Rees-Jones, the majority owner of Chief. In 2008, a former owner of Chief filed a petition against Rees-Jones, as the former majority owner of Chief, and Devon, as Chief’s successor pursuant to the 2006 acquisition. The petition claimed, among other things, violations of the Texas Securities Act, fraud and breaches of Rees-Jones’ fiduciary responsibility to the former owner in connection with Chief’s 2004 redemption of the owner’s minority ownership stake in Chief.
On June 20, 2011, a court issued a judgment against Rees-Jones for $196 million, of which $133 million of the judgment was also issued against Devon. Devon does not have a legal right of set off with respect to the judgment. Therefore, it has recorded a $133 million long-term liability relating to the judgment with an offsetting $133 million long-term receivable relating to its right to be indemnified by Rees-Jones and certain other parties pursuant to the indemnification agreement. Both Rees-Jones and Devon appealed the judgment.
In December 2012, the plaintiffs and Rees-Jones reached an agreement in principle to settle all claims related to the 2004 redemption. Under the terms of the agreement, Rees-Jones and Devon will receive full releases for all of the plaintiffs’ claims related to the Chief redemption. All settlement payments will be funded entirely by Rees-Jones. The settlement is contingent upon the execution of a formal settlement agreement and release, which is currently being negotiated by the parties. Devon does not expect to have any net exposure as a result of this matter.
Other Matters
Devon is involved in other various routine legal proceedings incidental to its business. However, to Devon's knowledge, there were no other material pending legal proceedings to which Devon is a party or to which any of its property is subject.
Commitments
The following is a schedule by year of Devon’s commitments that have initial or remaining noncancelable terms in excess of one year as of December 31, 2012.
|
|
|
|
|
|
Year Ending December 31, |
Purchase Obligations |
Drilling and Facility Obligations |
Operational Agreements |
Office and Equipment Leases |
|
|
(In millions) |
||||
2013 |
$ 826
|
$ 777
|
$ 391
|
$ 50
|
|
2014 |
862 | 173 | 406 | 34 | |
2015 |
861 |
— |
391 | 31 | |
2016 |
861 |
— |
340 | 29 | |
2017 |
844 |
— |
342 | 27 | |
Thereafter |
2,741 |
— |
1,626 | 141 | |
Total |
$ 6,995
|
$ 950
|
$ 3,496
|
$ 312
|
Purchase obligation amounts represent contractual commitments primarily to purchase condensate at market prices for use at Devon’s heavy oil projects in Canada. Devon has entered into these agreements because condensate is an integral part of the heavy oil production and transportation processes. Any disruption in Devon’s ability to obtain condensate could negatively affect its ability to produce and transport heavy oil at these locations. Devon’s total obligation related to condensate purchases expires in 2021. The value of the obligation in the table above is based on the contractual volumes and Devon’s internal estimate of future condensate market prices.
Devon has certain drilling and facility obligations under contractual agreements with third-party service providers to procure drilling rigs and other related services for developmental and exploratory drilling and facilities construction.
Devon has certain operational agreements whereby Devon has committed to transport or process certain volumes of oil, gas and NGLs for a fixed fee. Devon has entered into these agreements to aid the movement of its production to downstream markets.
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 $42 million, $42 million and $57 million in 2012, 2011 and 2010, respectively.
|
19.Fair Value Measurements
The following tables provide carrying value and fair value measurement information for certain of Devon's financial assets and liabilities. The carrying values of cash, accounts receivable, other current receivables, accounts payable, other payables and accrued expenses included in the accompanying balance sheets approximated fair value at December 31, 2012 and December 31, 2011. Therefore, such financial assets and liabilities are not presented in the following tables. Additionally, information regarding the fair values of Devon's midstream and pension plan assets is provided in Note 13 and Note 16, respectively.
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using: |
||
|
Carrying Amount |
Total Fair Value |
Level 1 |
Level 2 |
Level 3 |
|
(In millions) |
||||
December 31, 2012 assets (liabilities): |
|
|
|
|
|
Cash equivalents |
$ 4,149
|
$ 4,149
|
$ 200
|
$ 3,949
|
$— |
Short-term investments |
$ 2,343
|
$ 2,343
|
$ 429
|
$ 1,914
|
$— |
Long-term investments |
$ 64
|
$ 64
|
$— |
$— |
$ 64
|
Commodity derivatives |
$ 401
|
$ 401
|
$— |
$ 401
|
$— |
Commodity derivatives |
$ (32)
|
$ (32)
|
$— |
$ (32)
|
$— |
Interest rate derivatives |
$ 23
|
$ 23
|
$— |
$ 23
|
$— |
Foreign currency derivatives |
$ 1
|
$ 1
|
$— |
$ 1
|
$— |
Debt |
$ (11,644)
|
$ (13,435)
|
$— |
$ (13,435)
|
$— |
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using |
||
|
Carrying Amount |
Total Fair Value |
Level 1 |
Level 2 |
Level 3 |
|
(In millions) |
||||
December 31, 2011 assets (liabilities): |
|
|
|
|
|
Cash equivalents |
$ 5,123
|
$ 5,123
|
$ 929
|
$ 4,194
|
$— |
Short-term investments |
$ 1,503
|
$ 1,503
|
$ 201
|
$ 1,302
|
$— |
Long-term investments |
$ 84
|
$ 84
|
$— |
$— |
$ 84
|
Commodity derivatives |
$ 628
|
$ 628
|
$— |
$ 628
|
$— |
Commodity derivatives |
$ (82)
|
$ (82)
|
$— |
$ (82)
|
$— |
Interest rate derivatives |
$ 52
|
$ 52
|
$— |
$ 52
|
$— |
Debt |
$ (9,780)
|
$ (11,380)
|
$— |
$ (11,295)
|
$ (85)
|
The following methods and assumptions were used to estimate the fair values in the tables above.
Level 1 Fair Value Measurements
Cash equivalents and short-term investments — Amounts consist primarily of U.S. and Canadian treasury securities and money market investments. The fair value approximates the carrying value.
Level 2 Fair Value Measurements
Cash equivalents and short-term investments — Amounts consist primarily of Canadian agency and provincial securities and commercial paper investments. The fair value is based upon quotes from independent third parties, which approximate the carrying value.
Commodity, interest rate and foreign currency derivatives — The fair values of commodity, interest rate and foreign currency derivatives are estimated using internal discounted cash flow calculations based upon forward curves and data obtained from independent third parties for contracts with similar terms or data obtained from counterparties to the agreements.
Debt — Devon's debt instruments do not actively trade in an established market. The fair values of its fixed-rate debt are estimated based on rates available for debt with similar terms and maturity. The fair value of Devon’s variable-rate commercial paper and credit facility borrowings are the carrying values.
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 auction failures and the lack of an active market for Devon’s auction rate securities, quoted market prices for these securities were not available. Therefore, Devon used valuation techniques that rely on unobservable inputs to estimate the fair values of its long-term auction rate securities. These inputs were based on continued receipts of principal at par, the collection of all accrued interest to date, the probability of full repayment of the securities considering the U.S. government guarantees substantially all of the underlying student loans, and the AAA credit rating of the securities. 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, 2012 and December 31, 2011.
Debt — Devon's Level 3 debt consisted of a non-interest bearing promissory note. Due to the lack of an active market, quoted marked prices for this note, or similar notes, were not available. Therefore, Devon used valuation techniques that relied on unobservable inputs to estimate the fair value of its promissory note. The fair value of this debt was estimated using internal discounted cash flow calculations based upon estimated future payment schedules and a 3.125 percent interest rate. As a result of using these inputs, Devon concluded the estimated fair value of its non-interest bearing promissory note approximated the carrying value as of December 31, 2011.
Included below is a summary of the changes in Devon's Level 3 fair value measurements.
|
Year Ended December 31, |
|
|
2012 |
2011 |
|
(In millions) |
|
Long-term investments balance at beginning of period |
$ 84
|
$ 94
|
Redemptions of principal |
(20) | (10) |
Long-term investments balance at end of period |
$ 64
|
$ 84
|
|
Year Ended December 31, |
|
|
2012 |
2011 |
|
(In millions) |
|
Debt balance at beginning of period |
$ (85)
|
$ (144)
|
Foreign exchange translation adjustment |
(1) | 1 |
Accretion of promissory note |
3 | (5) |
Redemptions of principal |
83 | 63 |
Debt balance at end of period |
$— |
$ (85)
|
|
20.Discontinued Operations
In March 2012, Devon received $71 million and recognized a loss of $16 million upon closing the divestiture of its operations in Angola, which completed Devon’s offshore divestiture program that was announced in November 2009. In aggregate, Devon’s U.S. and International offshore divestitures generated total proceeds of approximately $10 billion, or $8 billion after-tax, assuming repatriation of a substantial portion of the foreign proceeds under current U.S. tax law.
Revenues related to Devon's discontinued operations totaled $43 million and $693 million during 2011 and 2010, respectively. Devon did not have revenues related to its discontinued operations during 2012. The following table presents the earnings (loss) from Devon’s discontinued operations.
|
Year Ended December 31, |
|||||||
|
2012 |
|
2011 |
|
2010 |
|||
|
|
|
|
|
|
|
|
|
|
|
(In millions) |
||||||
Operating earnings |
$ |
- |
|
$ |
38 |
|
$ |
567 |
Gain (loss) on sale of oil and gas properties |
|
(16) |
|
|
2,552 |
|
|
1,818 |
Earnings (loss) before income taxes |
|
(16) |
|
|
2,590 |
|
|
2,385 |
Income tax expense |
|
5 |
|
|
20 |
|
|
168 |
Earnings (loss) from discontinued operations |
$ |
(21) |
|
$ |
2,570 |
|
$ |
2,217 |
The following table presents the main classes of assets and liabilities associated with Devon’s discontinued operations at December 31, 2011.
|
December 31, 2011 |
|
(In millions) |
Other current assets |
$ 21
|
Property and equipment, net |
132 |
Total assets |
$ 153
|
|
|
Accounts payable |
$ 20
|
Other current liabilities |
28 |
Total liabilities |
$ 48
|
|
21.Segment Information
Devon manages its operations through distinct operating segments, which are defined primarily by geographic areas. For financial reporting purposes, Devon aggregates its U.S. operating segments into one reporting segment due to the similar nature of the businesses. However, Devon's Canadian operating segment is reported as a separate reporting segment primarily due to the significant differences between the U.S. and Canadian 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. Revenues are all from external customers.
|
|
|
|
|
U.S. |
Canada |
Total |
|
(In millions) |
||
Year Ended December 31, 2012: |
|
||
Oil, gas and NGL sales |
$ 4,679
|
$ 2,474
|
$ 7,153
|
Oil, gas and NGL derivatives |
$ 681
|
$ 12
|
$ 693
|
Marketing and midstream revenues |
$ 1,542
|
$ 114
|
$ 1,656
|
Depreciation, depletion and amortization |
$ 1,824
|
$ 987
|
$ 2,811
|
Interest expense |
$ 343
|
$ 63
|
$ 406
|
Asset impairments |
$ 1,861
|
$ 163
|
$ 2,024
|
Loss from continuing operations before income taxes |
$ (263)
|
$ (54)
|
$ (317)
|
Income tax benefit |
$ (97)
|
$ (35)
|
$ (132)
|
Loss from continuing operations |
$ (166)
|
$ (19)
|
$ (185)
|
Property and equipment, net |
$ 18,361
|
$ 8,955
|
$ 27,316
|
Total assets |
$ 24,256
|
$ 19,070
|
$ 43,326
|
Capital expenditures |
$ 6,511
|
$ 1,963
|
$ 8,474
|
|
U.S. |
Canada |
Total |
|
(In millions) |
||
Year Ended December 31, 2011: |
|
|
|
Oil, gas and NGL sales |
$ 5,418
|
$ 2,897
|
$ 8,315
|
Oil, gas and NGL derivative |
$ 881
|
$— |
$ 881
|
Marketing and midstream revenues |
$ 2,059
|
$ 199
|
$ 2,258
|
Depreciation, depletion and amortization |
$ 1,439
|
$ 809
|
$ 2,248
|
Interest expense |
$ 204
|
$ 148
|
$ 352
|
Earnings from continuing operations before income taxes |
$ 3,477
|
$ 813
|
$ 4,290
|
Income tax expense |
$ 1,958
|
$ 198
|
$ 2,156
|
Earnings from continuing operations |
$ 1,519
|
$ 615
|
$ 2,134
|
Property and equipment, net |
$ 16,989
|
$ 7,785
|
$ 24,774
|
Total assets (1) |
$ 22,622
|
$ 18,342
|
$ 40,964
|
Capital expenditures |
$ 6,101
|
$ 1,694
|
$ 7,795
|
Year Ended December 31, 2010: |
|
|
|
Oil, gas and NGL sales |
$ 4,742
|
$ 2,520
|
$ 7,262
|
Oil, gas and NGL derivatives |
$ 809
|
$ 2
|
$ 811
|
Marketing and midstream revenues |
$ 1,742
|
$ 125
|
$ 1,867
|
Depreciation, depletion and amortization |
$ 1,229
|
$ 701
|
$ 1,930
|
Interest expense |
$ 159
|
$ 204
|
$ 363
|
Earnings from continuing operations before income taxes |
$ 2,943
|
$ 625
|
$ 3,568
|
Income tax expense |
$ 1,062
|
$ 173
|
$ 1,235
|
Earnings from continuing operations |
$ 1,881
|
$ 452
|
$ 2,333
|
Property and equipment, net |
$ 12,379
|
$ 7,273
|
$ 19,652
|
Total assets (1) |
$ 18,320
|
$ 13,185
|
$ 31,505
|
Capital expenditures |
$ 4,935
|
$ 1,985
|
$ 6,920
|
____________________________
(1) Amounts in the table above do not include assets held for sale related to Devon’s discontinued operations, which totaled $153 million and $1.4 billion in 2011 and 2010, respectively.
|
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 U.S. 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, 2012 |
||||
|
U.S. Onshore |
U.S. Offshore |
Total |
Canada |
Total |
|
(In millions) |
||||
Property acquisition costs: |
|
||||
Proved properties |
$ 2
|
$— |
$ 2
|
$ 71
|
$ 73
|
Unproved properties |
1,135 |
— |
1,135 | 43 | 1,178 |
Exploration costs |
351 |
— |
351 | 304 | 655 |
Development costs |
4,408 |
— |
4,408 | 1,691 | 6,099 |
Costs incurred |
$ 5,896
|
$— |
$ 5,896
|
$ 2,109
|
$ 8,005
|
|
Year Ended December 31, 2011 |
||||
|
U.S. Onshore |
U.S. Offshore |
Total |
Canada |
Total |
|
(In millions) |
||||
Property acquisition costs: |
|
||||
Proved properties |
$ 34
|
$— |
$ 34
|
$ 14
|
$ 48
|
Unproved properties |
851 |
— |
851 | 88 | 939 |
Exploration costs |
272 |
— |
272 | 266 | 538 |
Development costs |
4,130 |
— |
4,130 | 1,288 | 5,418 |
Costs incurred |
$ 5,287
|
$— |
$ 5,287
|
$ 1,656
|
$ 6,943
|
|
Year Ended December 31, 2010 |
||||
|
U.S. Onshore |
U.S. Offshore |
Total |
Canada |
Total |
|
(In millions) |
||||
Property acquisition costs: |
|
||||
Proved properties |
$ 29
|
$— |
$ 29
|
$ 4
|
$ 33
|
Unproved properties |
592 | 2 | 594 | 590 | 1,184 |
Exploration costs |
339 | 89 | 428 | 260 | 688 |
Development costs |
3,126 | 297 | 3,423 | 1,216 | 4,639 |
Costs incurred |
$ 4,086
|
$ 388
|
$ 4,474
|
$ 2,070
|
$ 6,544
|
Costs incurred in the tables above include additions and revisions to Devon’s asset retirement obligations. The proceeds received from our joint venture transactions have not been netted against the costs incurred. At December 31, 2012 the remaining commitment to fund our future costs associated with these joint venture transactions was approximately $2.3 billion.
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 $359 million, $337 million and $311 million in the years 2012, 2011 and 2010, 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 $36 million, $45 million and $37 million in the years 2012, 2011 and 2010, respectively.
Capitalized Costs
The following tables reflect the aggregate capitalized costs related to oil and gas activities.
|
December 31, 2012 |
||
|
U.S. |
Canada |
Total |
|
(In millions) |
||
Proved properties |
$ 46,570
|
$ 22,840
|
$ 69,410
|
Unproved properties |
1,703 | 1,605 | 3,308 |
Total oil & gas properties |
48,273 | 24,445 | 72,718 |
Accumulated DD&A |
(33,098) | (16,039) | (49,137) |
Net capitalized costs |
$ 15,175
|
$ 8,406
|
$ 23,581
|
|
December 31, 2011 |
||
|
U.S. |
Canada |
Total |
|
(In millions) |
||
Proved properties |
$ 41,397
|
$ 20,299
|
$ 61,696
|
Unproved properties |
2,347 | 1,635 | 3,982 |
Total oil & gas properties |
43,744 | 21,934 | 65,678 |
Accumulated DD&A |
(29,742) | (14,585) | (44,327) |
Net capitalized costs |
$ 14,002
|
$ 7,349
|
$ 21,351
|
The following is a summary of Devon's oil and gas properties not subject to amortization as of December 31, 2012.
|
|
|
|
|
|
|
|
Costs Incurred In |
|||||
|
2012 | 2011 | 2010 |
Prior to 2010 |
Total |
|
|
(In millions) |
|||||
Acquisition costs |
$ 928
|
$ 115
|
$ 788
|
$ 660
|
$ 2,491
|
|
Exploration costs |
228 | 142 | 48 | 1 | 419 | |
Development costs |
227 | 70 |
— |
10 | 307 | |
Capitalized interest |
35 | 36 | 20 |
— |
91 | |
Total oil and gas properties not subject to amortization |
$ 1,418
|
$ 363
|
$ 856
|
$ 671
|
$ 3,308
|
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, 2012 |
||
|
U.S |
Canada |
Total |
|
(In millions) |
||
Oil, gas and NGL sales |
$ 4,679
|
$ 2,474
|
$ 7,153
|
Lease operating expenses |
(1,059) | (1,015) | (2,074) |
Depreciation, depletion and amortization |
(1,563) | (963) | (2,526) |
General and administrative expenses |
(159) | (137) | (296) |
Taxes other than income taxes |
(340) | (55) | (395) |
Asset impairments |
(1,793) | (163) | (1,956) |
Accretion of asset retirement obligations |
(40) | (69) | (109) |
Income tax (expense) benefit |
99 | (3) | 96 |
Results of operations |
$ (176)
|
$ 69
|
$ (107)
|
Depreciation, depletion and amortization per Boe |
$8.55 |
$14.41 |
$10.12 |
|
Year Ended December 31, 2011 |
||
|
U.S |
Canada |
Total |
|
(In millions) |
||
Oil, gas and NGL sales |
$ 5,418
|
$ 2,897
|
$ 8,315
|
Lease operating expenses |
(925) | (926) | (1,851) |
Depreciation, depletion and amortization |
(1,201) | (786) | (1,987) |
General and administrative expenses |
(132) | (119) | (251) |
Taxes other than income taxes |
(357) | (45) | (402) |
Accretion of asset retirement obligations |
(34) | (57) | (91) |
Income tax expense |
(1,005) | (250) | (1,255) |
Results of operations |
$ 1,764
|
$ 714
|
$ 2,478
|
Depreciation, depletion and amortization per Boe |
$6.94 |
$11.74 |
$8.28 |
|
Year Ended December 31, 2010 |
||
|
U.S. |
Canada |
Total |
|
(In millions) |
||
Oil, gas and NGL sales |
$ 4,742
|
$ 2,520
|
$ 7,262
|
Lease operating expenses |
(892) | (797) | (1,689) |
Depreciation, depletion and amortization |
(998) | (677) | (1,675) |
General and administrative expenses |
(133) | (83) | (216) |
Taxes other than income taxes |
(319) | (40) | (359) |
Accretion of asset retirement obligations |
(42) | (50) | (92) |
Income tax expense |
(849) | (246) | (1,095) |
Results of operations |
$ 1,509
|
$ 627
|
$ 2,136
|
Depreciation, depletion and amortization per Boe |
$6.11 |
$10.51 |
$7.36 |
Proved Reserves
The following tables present Devon’s estimated proved reserves by product for each significant country.
|
|
|
|
|
|
|
Oil (MMBbls) |
||||
|
U.S. Onshore |
U.S. Offshore |
Total |
Canada |
Total |
Proved developed and undeveloped reserves: |
|
|
|
|
|
December 31, 2009 |
139 | 33 | 172 | 111 | 283 |
Revisions due to prices |
4 | 1 | 5 | (3) | 2 |
Revisions other than price |
2 | 2 | 4 | (3) | 1 |
Extensions and discoveries |
19 | 1 | 20 | 4 | 24 |
Production |
(14) | (2) | (16) | (16) | (32) |
Sale of reserves |
(2) | (35) | (37) |
— |
(37) |
December 31, 2010 |
148 |
— |
148 | 93 | 241 |
Revisions due to prices |
2 |
— |
2 | 1 | 3 |
Revisions other than price |
(1) |
— |
(1) | (5) | (6) |
Extensions and discoveries |
36 |
— |
36 | 6 | 42 |
Production |
(17) |
— |
(17) | (15) | (32) |
December 31, 2011 |
168 |
— |
168 | 80 | 248 |
Revisions due to prices |
(1) |
— |
(1) | (5) | (6) |
Revisions other than price |
(6) |
— |
(6) | (2) | (8) |
Extensions and discoveries |
65 |
— |
65 | 7 | 72 |
Production |
(21) |
— |
(21) | (15) | (36) |
December 31, 2012 |
205 |
— |
205 | 65 | 270 |
Proved developed reserves as of: |
|
|
|
|
|
December 31, 2009 |
119 | 21 | 140 | 97 | 237 |
December 31, 2010 |
131 |
— |
131 | 82 | 213 |
December 31, 2011 |
146 |
— |
146 | 73 | 219 |
December 31, 2012 |
166 |
— |
166 | 62 | 228 |
Proved developed-producing reserves as of: |
|
|
|
|
|
December 31, 2009 |
112 | 12 | 124 | 85 | 209 |
December 31, 2010 |
123 |
— |
123 | 72 | 195 |
December 31, 2011 |
139 |
— |
139 | 65 | 204 |
December 31, 2012 |
155 |
— |
155 | 56 | 211 |
Proved undeveloped reserves as of: |
|
|
|
|
|
December 31, 2009 |
20 | 12 | 32 | 14 | 46 |
December 31, 2010 |
17 |
— |
17 | 11 | 28 |
December 31, 2011 |
22 |
— |
22 | 7 | 29 |
December 31, 2012 |
39 |
— |
39 | 3 | 42 |
|
|
|
|
|
|
|
Bitumen (MMBbls) |
||||
|
U.S. Onshore |
U.S. Offshore |
Total |
Canada |
Total |
Proved developed and undeveloped reserves: |
|
|
|
|
|
December 31, 2009 |
— |
— |
— |
403 | 403 |
Revisions due to prices |
— |
— |
— |
(21) | (21) |
Revisions other than price |
— |
— |
— |
12 | 12 |
Extensions and discoveries |
— |
— |
— |
55 | 55 |
Production |
— |
— |
— |
(9) | (9) |
December 31, 2010 |
— |
— |
— |
440 | 440 |
Revisions due to prices |
— |
— |
— |
(16) | (16) |
Revisions other than price |
— |
— |
— |
16 | 16 |
Extensions and discoveries |
— |
— |
— |
30 | 30 |
Production |
— |
— |
— |
(13) | (13) |
December 31, 2011 |
— |
— |
— |
457 | 457 |
Revisions due to prices |
— |
— |
— |
14 | 14 |
Revisions other than price |
— |
— |
— |
7 | 7 |
Extensions and discoveries |
— |
— |
— |
67 | 67 |
Production |
— |
— |
— |
(17) | (17) |
December 31, 2012 |
— |
— |
— |
528 | 528 |
Proved developed reserves as of: |
|
|
|
|
|
December 31, 2009 |
— |
— |
— |
52 | 52 |
December 31, 2010 |
— |
— |
— |
44 | 44 |
December 31, 2011 |
— |
— |
— |
90 | 90 |
December 31, 2012 |
— |
— |
— |
99 | 99 |
Proved developed-producing reserves as of: |
|
|
|
|
|
December 31, 2009 |
— |
— |
— |
52 | 52 |
December 31, 2010 |
— |
— |
— |
44 | 44 |
December 31, 2011 |
— |
— |
— |
90 | 90 |
December 31, 2012 |
— |
— |
— |
99 | 99 |
Proved undeveloped reserves as of: |
|
|
|
|
|
December 31, 2009 |
— |
— |
— |
351 | 351 |
December 31, 2010 |
— |
— |
— |
396 | 396 |
December 31, 2011 |
— |
— |
— |
367 | 367 |
December 31, 2012 |
— |
— |
— |
429 | 429 |
|
|
|
|
|
|
|
Gas (Bcf) |
||||
|
U.S. Onshore |
U.S. Offshore |
Total |
Canada |
Total |
Proved developed and undeveloped reserves: |
|
|
|
|
|
December 31, 2009 |
8,127 | 342 | 8,469 | 1,288 | 9,757 |
Revisions due to prices |
449 | 2 | 451 | 21 | 472 |
Revisions other than price |
105 | (26) | 79 | (17) | 62 |
Extensions and discoveries |
1,088 | 7 | 1,095 | 131 | 1,226 |
Purchase of reserves |
12 |
— |
12 | 9 | 21 |
Production |
(699) | (17) | (716) | (214) | (930) |
Sale of reserves |
(17) | (308) | (325) |
— |
(325) |
December 31, 2010 |
9,065 |
— |
9,065 | 1,218 | 10,283 |
Revisions due to prices |
(1) |
— |
(1) | (60) | (61) |
Revisions other than price |
(243) |
— |
(243) | (38) | (281) |
Extensions and discoveries |
1,410 |
— |
1,410 | 58 | 1,468 |
Purchase of reserves |
16 |
— |
16 | 20 | 36 |
Production |
(740) |
— |
(740) | (213) | (953) |
Sale of reserves |
— |
— |
— |
(6) | (6) |
December 31, 2011 |
9,507 |
— |
9,507 | 979 | 10,486 |
Revisions due to prices |
(831) |
— |
(831) | (99) | (930) |
Revisions other than price |
(287) |
— |
(287) | (33) | (320) |
Extensions and discoveries |
1,124 |
— |
1,124 | 34 | 1,158 |
Purchase of reserves |
2 |
— |
2 |
— |
2 |
Production |
(752) |
— |
(752) | (186) | (938) |
Sale of reserves |
(1) |
— |
(1) | (11) | (12) |
December 31, 2012 |
8,762 |
— |
8,762 | 684 | 9,446 |
Proved developed reserves as of: |
|
|
|
|
|
December 31, 2009 |
6,447 | 185 | 6,632 | 1,213 | 7,845 |
December 31, 2010 |
7,280 |
— |
7,280 | 1,144 | 8,424 |
December 31, 2011 |
7,957 |
— |
7,957 | 951 | 8,908 |
December 31, 2012 |
7,391 |
— |
7,391 | 679 | 8,070 |
Proved developed-producing reserves as of: |
|
|
|
|
|
December 31, 2009 |
5,860 | 137 | 5,997 | 1,075 | 7,072 |
December 31, 2010 |
6,702 |
— |
6,702 | 1,031 | 7,733 |
December 31, 2011 |
7,409 |
— |
7,409 | 862 | 8,271 |
December 31, 2012 |
7,091 |
— |
7,091 | 624 | 7,715 |
Proved undeveloped reserves as of: |
|
|
|
|
|
December 31, 2009 |
1,680 | 157 | 1,837 | 75 | 1,912 |
December 31, 2010 |
1,785 |
— |
1,785 | 74 | 1,859 |
December 31, 2011 |
1,550 |
— |
1,550 | 28 | 1,578 |
December 31, 2012 |
1,371 |
— |
1,371 | 5 | 1,376 |
|
|
|
|
|
|
|
Natural Gas Liquids (MMBbls) |
||||
|
U.S. Onshore |
U.S. Offshore |
Total |
Canada |
Total |
Proved developed and undeveloped reserves: |
|
|
|
|
|
December 31, 2009 |
385 | 2 | 387 | 34 | 421 |
Revisions due to prices |
14 |
— |
14 | (1) | 13 |
Revisions other than price |
13 | 3 | 16 | (1) | 15 |
Extensions and discoveries |
68 |
— |
68 | 2 | 70 |
Production |
(28) |
— |
(28) | (4) | (32) |
Sale of reserves |
(3) | (5) | (8) |
— |
(8) |
December 31, 2010 |
449 |
— |
449 | 30 | 479 |
Revisions due to prices |
4 |
— |
4 | (1) | 3 |
Revisions other than price |
1 |
— |
1 |
— |
1 |
Extensions and discoveries |
102 |
— |
102 | 2 | 104 |
Purchase of reserves |
2 |
— |
2 |
— |
2 |
Production |
(33) |
— |
(33) | (4) | (37) |
December 31, 2011 |
525 |
— |
525 | 27 | 552 |
Revisions due to prices |
(19) |
— |
(19) | (5) | (24) |
Revisions other than price |
(13) |
— |
(13) |
— |
(13) |
Extensions and discoveries |
114 |
— |
114 | 2 | 116 |
Production |
(36) |
— |
(36) | (4) | (40) |
December 31, 2012 |
571 |
— |
571 | 20 | 591 |
Proved developed reserves as of: |
|
|
|
|
|
December 31, 2009 |
293 | 1 | 294 | 32 | 326 |
December 31, 2010 |
353 |
— |
353 | 28 | 381 |
December 31, 2011 |
402 |
— |
402 | 26 | 428 |
December 31, 2012 |
431 |
— |
431 | 20 | 451 |
Proved developed-producing reserves as of: |
|
|
|
|
|
December 31, 2009 |
265 | 1 | 266 | 28 | 294 |
December 31, 2010 |
318 |
— |
318 | 26 | 344 |
December 31, 2011 |
372 |
— |
372 | 24 | 396 |
December 31, 2012 |
406 |
— |
406 | 19 | 425 |
Proved undeveloped reserves as of: |
|
|
|
|
|
December 31, 2009 |
92 | 1 | 93 | 2 | 95 |
December 31, 2010 |
96 |
— |
96 | 2 | 98 |
December 31, 2011 |
123 |
— |
123 | 1 | 124 |
December 31, 2012 |
140 |
— |
140 |
— |
140 |
|
Total (MMBoe) (1) |
||||
|
U.S. Onshore |
U.S. Offshore |
Total |
Canada |
Total |
Proved developed and undeveloped reserves: |
|
|
|
|
|
December 31, 2009 |
1,878 | 92 | 1,970 | 763 | 2,733 |
Revisions due to prices |
92 | 1 | 93 | (21) | 72 |
Revisions other than price |
32 | 1 | 33 | 5 | 38 |
Extensions and discoveries |
269 | 2 | 271 | 83 | 354 |
Purchase of reserves |
2 |
— |
2 | 2 | 4 |
Production |
(158) | (5) | (163) | (65) | (228) |
Sale of reserves |
(8) | (91) | (99) | (1) | (100) |
December 31, 2010 |
2,107 |
— |
2,107 | 766 | 2,873 |
Revisions due to prices |
6 |
— |
6 | (27) | (21) |
Revisions other than price |
(41) |
— |
(41) | 6 | (35) |
Extensions and discoveries |
374 |
— |
374 | 47 | 421 |
Purchase of reserves |
5 |
— |
5 | 3 | 8 |
Production |
(173) |
— |
(173) | (67) | (240) |
Sale of reserves |
— |
— |
— |
(1) | (1) |
December 31, 2011 |
2,278 |
— |
2,278 | 727 | 3,005 |
Revisions due to price |
(159) |
— |
(159) | (12) | (171) |
Revisions other than price |
(67) |
— |
(67) | (1) | (68) |
Extensions and discoveries |
367 |
— |
367 | 82 | 449 |
Production |
(183) |
— |
(183) | (67) | (250) |
Sale of reserves |
— |
— |
— |
(2) | (2) |
December 31, 2012 |
2,236 |
— |
2,236 | 727 | 2,963 |
Proved developed reserves as of: |
|
|
|
|
|
December 31, 2009 |
1,486 | 53 | 1,539 | 383 | 1,922 |
December 31, 2010 |
1,696 |
— |
1,696 | 346 | 2,042 |
December 31, 2011 |
1,875 |
— |
1,875 | 348 | 2,223 |
December 31, 2012 |
1,829 |
— |
1,829 | 294 | 2,123 |
Proved developed-producing reserves as of: |
|
|
|
|
|
December 31, 2009 |
1,354 | 35 | 1,389 | 344 | 1,733 |
December 31, 2010 |
1,557 |
— |
1,557 | 314 | 1,871 |
December 31, 2011 |
1,746 |
— |
1,746 | 323 | 2,069 |
December 31, 2012 |
1,743 |
— |
1,743 | 278 | 2,021 |
Proved undeveloped reserves as of: |
|
|
|
|
|
December 31, 2009 |
392 | 39 | 431 | 380 | 811 |
December 31, 2010 |
411 |
— |
411 | 420 | 831 |
December 31, 2011 |
403 |
— |
403 | 379 | 782 |
December 31, 2012 |
407 |
— |
407 | 433 | 840 |
____________________________
(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. Bitumen and natural gas liquids reserves are converted to Boe on a one-to-one basis with oil.
Proved Undeveloped Reserves
The following table presents the changes in Devon’s total proved undeveloped reserves during 2012 (in MMBoe).
|
U.S. |
Canada |
Total |
Proved undeveloped reserves as of December 31, 2011 |
403 | 379 | 782 |
Extensions and discoveries |
134 | 68 | 202 |
Revisions due to prices |
(47) | 9 | (38) |
Revisions other than price |
(10) | (6) | (16) |
Conversion to proved developed reserves |
(73) | (17) | (90) |
Proved undeveloped reserves as of December 31, 2012 |
407 | 433 | 840 |
At December 31, 2012, Devon had 840 MMBoe of proved undeveloped reserves. This represents a 7 percent increase as compared to 2011 and represents 28 percent of its total proved reserves. Drilling and development activities increased Devon’s proved undeveloped reserves 203 MMBoe and resulted in the conversion of 90 MMBoe, or 12 percent, of the 2011 proved undeveloped reserves to proved developed reserves. Costs incurred related to the development and conversion of Devon’s proved undeveloped reserves were $1.3 billion for 2012. Additionally, revisions other than price decreased Devon’s proved undeveloped reserves 16 MMBoe primarily due to its evaluation of certain U.S. onshore dry-gas areas, which it does not expect to develop in the next five years. The largest revisions relate to the dry-gas areas at Carthage in east Texas and the Barnett Shale in north Texas.
A significant amount of Devon’s proved undeveloped reserves at the end of 2012 largely related to its Jackfish operations. At December 31, 2012 and 2011, Devon’s Jackfish proved undeveloped reserves were 429 MMBoe and 367 MMBoe, respectively. Development schedules for the Jackfish reserves are primarily controlled by the need to keep the processing plants at their 35,000 barrel daily facility capacity. Processing plant capacity is controlled by factors such as total steam processing capacity, steam-oil ratios and air quality discharge permits. As a result, these reserves are classified as proved undeveloped for more than five years. Currently, the development schedule for these reserves extends though the year 2031.
Price Revisions
2012 - Reserves decreased 171 MMBoe primarily due to lower gas prices. Of this decrease, 100 MMBoe related to the Barnett Shale and 25 MMBoe related to the Rocky Mountain area.
2011 - Reserves decreased 21 MMBoe due to lower gas prices and higher oil prices. The higher oil prices increased Devon’s Canadian royalty burden, which reduced Devon’s oil reserves.
2010 - Reserves increased 72 MMBoe due to higher gas prices, partially offset by the effect of higher oil prices. The higher oil prices increased Devon’s Canadian royalty burden, which reduced Devon’s oil reserves. Of the 72 MMBoe price revisions, 43 MMBoe related to the Barnett Shale and 22 MMBoe related to the Rocky Mountain area.
Revisions Other Than Price
Total revisions other than price for 2012 and 2011 primarily related to Devon’s evaluation of certain dry gas regions noted in the proved undeveloped reserves discussion above. Total revisions other than price for 2010 primarily related to Devon’s drilling and development in the Barnett Shale.
Extensions and Discoveries
2012 – Of the 449 MMBoe of extensions and discoveries, 151 MMBoe related to the Cana-Woodford Shale, 95 MMBoe related to the Barnett Shale, 72 MMBoe related to the Permian Basin, 67 MMBoe related to Jackfish, 16 MMBoe related to the Rocky Mountain area and 18 MMBoe related to the Granite Wash area.
The 2012 extensions and discoveries included 229 MMBoe related to additions from Devon’s infill drilling activities, including 134 MMBoe at the Cana-Woodford Shale and 82 MMBoe at the Barnett Shale.
2011 – Of the 421 MMBoe of extensions and discoveries, 162 MMBoe related to the Cana-Woodford Shale, 115 MMBoe related to the Barnett Shale, 39 MMBoe related to the Permian Basin, 30 MMBoe related to Jackfish, 19 MMBoe related to the Rocky Mountain area and 17 MMBoe related to the Granite Wash area.
The 2011 extensions and discoveries included 168 MMBoe related to additions from Devon’s infill drilling activities, including 80 MMBoe at the Cana-Woodford Shale and 77 MMBoe at the Barnett Shale.
2010 – Of the 354 MMBoe of extensions and discoveries, 101 MMBoe related to the Cana-Woodford Shale, 87 MMBoe related to the Barnett Shale, 55 MMBoe related to Jackfish, 19 MMBoe related to the Permian Basin, 15 MMBoe related to the Rocky Mountain area and 14 MMBoe related to the Carthage area.
The 2010 extensions and discoveries included 107 MMBoe related to additions from Devon’s infill drilling activities, including 43 MMBoe at the Barnett Shale and 47 MMBoe at the Cana-Woodford Shale.
Sale of Reserves
The 2010 total primarily relates to the divestiture of Devon’s Gulf of Mexico properties.
Standardized Measure
The tables below reflect Devon’s standardized measure of discounted future net cash flows from its proved reserves.
|
|
|
|
|
Year Ended December 31, 2012 |
||
|
U.S. |
Canada |
Total |
|
(In millions) |
||
Future cash inflows |
$ 55,297
|
$ 33,570
|
$ 88,867
|
Future costs: |
|
|
|
Development |
(6,556) | (6,211) | (12,767) |
Production |
(24,265) | (16,611) | (40,876) |
Future income tax expense |
(6,542) | (1,992) | (8,534) |
Future net cash flows |
17,934 | 8,756 | 26,690 |
10% discount to reflect timing of cash flows |
(9,036) | (4,433) | (13,469) |
Standardized measure of discounted future net cash flows |
$ 8,898
|
$ 4,323
|
$ 13,221
|
|
Year Ended December 31, 2011 |
||
|
U.S. |
Canada |
Total |
|
(In millions) |
||
Future cash inflows |
$ 69,305
|
$ 36,786
|
$ 106,091
|
Future costs: |
|
|
|
Development |
(6,817) | (4,678) | (11,495) |
Production |
(26,217) | (15,063) | (41,280) |
Future income tax expense |
(11,432) | (3,763) | (15,195) |
Future net cash flows |
24,839 | 13,282 | 38,121 |
10% discount to reflect timing of cash flows |
(13,492) | (6,785) | (20,277) |
Standardized measure of discounted future net cash flows |
$ 11,347
|
$ 6,497
|
$ 17,844
|
|
Year Ended December 31, 2010 |
||
|
U.S. |
Canada |
Total |
|
(In millions) |
||
Future cash inflows |
$ 58,093
|
$ 35,948
|
$ 94,041
|
Future costs: |
|
|
|
Development |
(6,220) | (4,526) | (10,746) |
Production |
(24,223) | (12,249) | (36,472) |
Future income tax expense |
(8,643) | (4,209) | (12,852) |
Future net cash flows |
19,007 | 14,964 | 33,971 |
10% discount to reflect timing of cash flows |
(10,164) | (7,455) | (17,619) |
Standardized measure of discounted future net cash flows |
$ 8,843
|
$ 7,509
|
$ 16,352
|
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 2012, the future realized prices averaged $86.57 per barrel of oil, $50.24 per barrel of bitumen, $2.28 per Mcf of gas and $29.19 per barrel of natural gas liquids. Of the $12.8 billion of future development costs as of the end of 2012, $2.3 billion, $1.9 billion and $0.8 billion are estimated to be spent in 2013, 2014 and 2015, respectively.
Future development costs include not only development costs, but also future asset retirement costs. Included as part of the $12.8 billion of future development costs are $2.6 billion of future asset retirement costs. Future production costs include general and administrative expenses directly related to oil and gas producing activities. The future income tax expenses have been computed using statutory tax rates, giving effect to allowable tax deductions and tax credits under current laws.
The principal changes in Devon’s standardized measure of discounted future net cash flows are as follows:
|
Year Ended December 31, |
||
|
2012 |
2011 |
2010 |
|
(In millions) |
||
Beginning balance |
$ 17,844
|
$ 16,352
|
$ 11,403
|
Net changes in prices and production costs |
(9,889) | 1,875 | 7,423 |
Oil, gas and NGL sales, net of production costs |
(4,388) | (5,811) | (4,998) |
Changes in estimated future development costs |
(1,094) | (440) | (292) |
Extensions and discoveries, net of future development costs |
4,669 | 3,714 | 3,048 |
Purchase of reserves |
18 | 57 | 23 |
Sales of reserves in place |
(25) | (2) | (815) |
Revisions of quantity estimates |
162 | (228) | 579 |
Previously estimated development costs incurred during the period |
1,321 | 1,302 | 1,559 |
Accretion of discount |
1,420 | 2,248 | 1,487 |
Other, primarily changes in timing and foreign exchange rates |
113 | (294) | (402) |
Net change in income taxes |
3,070 | (929) | (2,663) |
Ending balance |
$ 13,221
|
$ 17,844
|
$ 16,352
|
The following table presents Devon’s estimated pretax cash flow information related to its proved reserves.
|
Year Ended December 31, 2012 |
||
|
U.S. |
Canada |
Total |
Pre-tax future net revenue (1) |
(In millions) |
||
Proved developed reserves |
$ 19,982
|
$ 2,717
|
$ 22,699
|
Proved undeveloped reserves |
4,494 | 8,031 | 12,525 |
Total proved reserves |
$ 24,476
|
$ 10,748
|
$ 35,224
|
Pre-tax 10% present value (1) |
|
|
|
Proved developed reserves |
$ 10,764
|
$ 2,484
|
$ 13,248
|
Proved undeveloped reserves |
1,143 | 2,823 | 3,966 |
Total proved reserves |
$ 11,907
|
$ 5,307
|
$ 17,214
|
____________________________
(1) Estimated pre-tax future net revenue represents estimated future revenue to be generated from the production of proved reserves, net of estimated production and development costs and site restoration and abandonment charges. The amounts shown do not give effect to depreciation, depletion and amortization, asset impairments or non-property related expenses such as debt service and income tax expense.
The present value of after-tax future net revenues discounted at 10 percent per annum (“standardized measure”) was $13.2 billion at the end of 2012. Included as part of standardized measure were discounted future income taxes of $4.0 billion. Excluding these taxes, the present value of Devon’s pre-tax future net revenue (“pre-tax 10 percent present value”) was $17.2 billion. Devon believes the pre-tax 10 percent present value is a useful measure in addition to the after-tax standardized measure. The pre-tax 10 percent present value assists in both the determination of future cash flows of the current reserves as well as in making relative value comparisons among peer companies. The after-tax standardized measure is dependent on the unique tax situation of each individual company, while the pre-tax 10 percent present value is based on prices and discount factors, which are more consistent from company to company.
|
23.Supplemental Quarterly Financial Information (Unaudited)
Following is a summary of Devon’s unaudited interim results of operations.
|
2012 |
||||
|
First Quarter |
Second Quarter |
Third Quarter |
Fourth Quarter |
Full |
|
(In millions, except per share amounts) |
||||
Revenues |
$ 2,497
|
$ 2,559
|
$ 1,865
|
$ 2,581
|
$ 9,502
|
|
|
|
|
|
|
Earnings (loss) from continuing operations before income taxes |
$ 611
|
$ 734
|
$ (1,161)
|
$ (501)
|
$ (317)
|
|
|
|
|
|
|
Earnings (loss) from continuing operations |
$ 414
|
$ 477
|
$ (719)
|
$ (357)
|
$ (185)
|
Loss from discontinued operations |
(21) |
— |
— |
— |
(21) |
Net earnings (loss) |
$ 393
|
$ 477
|
$ (719)
|
$ (357)
|
$ (206)
|
|
|
|
|
|
|
Basic net earnings (loss) per common share: |
|
|
|
|
|
Earnings (loss) from continuing operations |
$ 1.03
|
$ 1.18
|
$ (1.80)
|
$ (0.89)
|
$ (0.47)
|
Earnings (loss) from discontinued operations |
(0.06) |
— |
— |
— |
(0.05) |
Net earnings (loss) |
$ 0.97
|
$ 1.18
|
$ (1.80)
|
$ (0.89)
|
$ (0.52)
|
|
|
|
|
|
|
Diluted net earnings (loss) per common share: |
|
|
|
|
|
Earnings (loss) from continuing operations |
$ 1.03
|
$ 1.18
|
$ (1.80)
|
$ (0.89)
|
$ (0.47)
|
Earnings (loss) from discontinued operations |
(0.06) |
— |
— |
— |
(0.05) |
Net earnings (loss) |
$ 0.97
|
$ 1.18
|
$ (1.80)
|
$ (0.89)
|
$ (0.52)
|
|
|
|
|
|
|
|
2011 |
||||
|
First Quarter |
Second Quarter |
Third Quarter |
Fourth Quarter |
Full |
|
(In millions, except per share amounts) |
||||
Revenues |
$ 2,147
|
$ 3,220
|
$ 3,502
|
$ 2,585
|
$ 11,454
|
|
|
|
|
|
|
Earnings from continuing operations before income taxes |
$ 580
|
$ 1,378
|
$ 1,538
|
$ 794
|
$ 4,290
|
|
|
|
|
|
|
Earnings from continuing operations |
$ 389
|
$ 184
|
$ 1,040
|
$ 521
|
$ 2,134
|
Earnings (loss) from discontinued operations |
27 | 2,559 | (2) | (14) | 2,570 |
Net earnings |
$ 416
|
$ 2,743
|
$ 1,038
|
$ 507
|
$ 4,704
|
|
|
|
|
|
|
Basic net earnings per common share: |
|
|
|
|
|
Earnings from continuing operations |
$ 0.91
|
$ 0.44
|
$ 2.51
|
$ 1.29
|
$ 5.12
|
Earnings (loss) from discontinued operations |
0.06 | 6.06 |
— |
(0.04) | 6.17 |
Net earnings |
$ 0.97
|
$ 6.50
|
$ 2.51
|
$ 1.25
|
$ 11.29
|
|
|
|
|
|
|
Diluted net earnings per common share: |
|
|
|
|
|
Earnings from continuing operations |
$ 0.91
|
$ 0.43
|
$ 2.50
|
$ 1.29
|
$ 5.10
|
Earnings (loss) from discontinued operations |
0.06 | 6.05 |
— |
(0.04) | 6.15 |
Net earnings |
$ 0.97
|
$ 6.48
|
$ 2.50
|
$ 1.25
|
$ 11.25
|
Earnings (Loss) from Continuing Operations
The fourth quarter of 2012 includes U.S. and Canadian asset impairments totaling $0.9 billion ($0.6 billion after income taxes, or $1.46 per diluted share).
The third quarter of 2012 includes U.S. asset impairments totaling $1.1 billion ($0.7 billion after income taxes, or $1.78 per diluted share).
The second quarter of 2011 includes deferred income taxes of $0.7 billion (or $1.71 per diluted share) related to assumed repatriations of foreign earnings that were no longer deemed to be indefinitely reinvested in accordance with accounting principles generally accepted in the U.S.
Earnings (Loss) from Discontinued Operations
The second quarter of 2011 includes the divestiture of Devon’s Brazil operations and the related gain was $2.5 billion ($2.5 billion after income taxes, or $6.01 per diluted share).
|
Principles of Consolidation
The accounts of Devon and its wholly owned and controlled subsidiaries are included in the accompanying financial statements. All significant intercompany accounts and transactions have been eliminated in consolidation.
Use of Estimates
The preparation of financial statements 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:
• proved reserves and related present value of future net revenues;
• the carrying value of oil and gas properties;
• derivative financial instruments;
• the fair value of reporting units and related assessment of goodwill for impairment;
• income taxes;
• asset retirement obligations;
• obligations related to employee pension and postretirement benefits; and
• legal and environmental risks and exposures.
Revenue Recognition and Gas Balancing
Oil, gas and NGL sales are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectability of the revenue is probable. Delivery occurs and title is transferred when production has been delivered to a pipeline, railcar or truck. Cash received relating to future production is deferred and recognized when all revenue recognition criteria are met. Taxes assessed by governmental authorities on oil, gas and NGL sales are presented separately from such revenues in the accompanying comprehensive statements of earnings.
Devon follows the sales method of accounting for gas production imbalances. The volumes of gas sold may differ from the volumes to which Devon is entitled based on its interests in the properties. These differences create imbalances that are recognized as a liability only when the estimated remaining reserves will not be sufficient to enable the underproduced owner to recoup its entitled share through production. The liability is priced based on current market prices. No receivables are recorded for those wells where Devon has taken less than its share of production unless all revenue recognition criteria are met. If an imbalance exists at the time the wells' reserves are depleted, settlements are made among the joint interest owners under a variety of arrangements.
Marketing and midstream revenues are recorded at the time products are sold or services are provided to third parties at a fixed or determinable price, delivery or performance has occurred, title has transferred and collectability of the revenue is probable. Revenues and expenses attributable to oil, gas and NGL purchases, transportation and processing contracts are reported on a gross basis when Devon takes title to the products and has risks and rewards of ownership.
During 2012, 2011 and 2010, no purchaser accounted for more than 10 percent of Devon’s revenues from continuing operations.
Derivative Financial Instruments
Devon is exposed to certain risks relating to its ongoing business operations, including risks related to commodity prices, interest rates and Canadian to U.S. dollar exchange rates. As discussed more fully below, Devon uses derivative instruments primarily to manage commodity price risk and interest rate risk. Devon does not intend to hold or issue derivative financial instruments for speculative trading purposes.
Devon periodically enters into derivative financial instruments with respect to a portion of its oil, gas and NGL production to hedge future prices received. These instruments are used to manage the inherent uncertainty of future revenues due to commodity price volatility. Devon's derivative financial instruments typically include financial price swaps, basis swaps, costless price collars and call options. Under the terms of the price swaps, Devon receives a fixed price for its production and pays a variable market price to the contract counterparty. For the basis swaps, Devon receives a fixed differential between two regional 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. The call options give counterparties the right to purchase production at a predetermined price.
Devon periodically enters into interest rate swaps to manage its exposure to interest rate volatility. Devon's interest rate swaps include contracts in which Devon receives a fixed rate and pays a variable rate on a total notional amount. Devon periodically enters into foreign exchange forward contracts to manage its exposure to fluctuations in exchange rates.
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 earnings unless specific hedge accounting criteria are met. For derivative financial instruments held during the three-year period ended December 31, 2012, Devon chose not to meet the necessary criteria to qualify its derivative financial instruments for hedge accounting treatment. Cash settlements with counterparties on Devon's derivative financial instruments are also recorded in earnings.
By using derivative financial instruments to hedge exposures to changes in commodity prices, interest rates and foreign currency rates, Devon is exposed to credit 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 acceptable 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 certain credit rating levels. The mark-to-market exposure threshold, above which collateral must be posted, decreases as the debt rating falls further below such credit levels. As of December 31, 2012, Devon held $63 million of cash collateral, which represented the estimated fair value of certain derivative positions in excess of Devon’s credit guidelines. The collateral is reported in other current liabilities in the accompanying balance sheet.
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 generally recognized as a component of general and administrative expenses in the accompanying comprehensive statements of earnings over the applicable requisite service periods. As a result of Devon’s strategic repositioning announced in 2009 and the consolidation of its U.S. operations announced in October 2012, certain share based awards were accelerated and recognized as a component of restructuring expense in the accompanying comprehensive statements of earnings.
Generally, Devon uses new shares from approved incentive programs to grant share-based awards and to issue shares upon stock option exercises. Shares repurchased under approved programs are available to be issued as part of Devon’s share based awards. However, Devon has historically cancelled these shares upon repurchase.
Income Taxes
Devon is subject to current income taxes assessed by the federal and various state jurisdictions in the U.S. 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. If the future utilization of some portion of carryforwards is determined to be unlikely, a valuation allowance is provided to reduce the recorded tax benefits from such assets. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.
Devon does not recognize U.S. deferred income taxes on the unremitted earnings of its foreign subsidiaries that are deemed to be indefinitely reinvested. When such earnings are no longer deemed permanently reinvested, Devon recognizes the appropriate deferred, or even current, income tax liabilities.
Devon recognizes the financial statement effects of tax positions when it is more likely than not, based on the technical merits, that the position will be sustained upon examination by a taxing authority. Recognized tax positions are initially and subsequently measured as the largest amount of tax benefit that is more likely than not of being realized upon ultimate settlement with a taxing authority. Liabilities for unrecognized tax benefits related to such tax positions are included in other long-term liabilities unless the tax position is expected to be settled within the upcoming year, in which case the liabilities are included in other current liabilities. Interest and penalties related to unrecognized tax benefits are included in current income tax expense.
Net Earnings (Loss) Per Common Share
Devon’s basic earnings per share amounts have been computed based on the average number of shares of common stock outstanding for the period. Basic earnings per share includes the effect of participating securities, which primarily consist of Devon's outstanding restricted stock awards. Diluted earnings per share is calculated using the treasury stock method to reflect the assumed issuance of common shares for all potentially dilutive securities. Such securities primarily consist of outstanding stock options.
Cash and Cash Equivalents
Devon considers all highly liquid investments with original contractual maturities of three months or less to be cash equivalents.
Investments
Devon periodically invests excess cash in U.S. and Canadian treasury securities and other marketable securities. During 2012 and 2011, Devon invested a portion of its joint venture proceeds and a portion of the International offshore divestiture proceeds into such securities, causing short-term investments to increase.
Devon considers securities with original contractual maturities in excess of three months, but less than one year to be short-term investments. Investments with contractual maturities in excess of one year are classified as long-term, unless such investments are classified as trading or available-for-sale.
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. Such debt securities totaled $64 million and $84 million at December 31, 2012 and 2011, respectively and are included in other long-term assets in the accompanying balance sheet. Devon has the ability to hold the securities until maturity and does not believe the values of its long-term securities are impaired.
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, capitalized costs of oil and gas properties, net of accumulated DD&A and deferred income taxes, may not exceed the full cost “ceiling” at the end of each quarter. The ceiling is calculated separately for each country and is based on the present value of estimated future net cash flows from proved oil and gas reserves, discounted at 10 percent per annum, net of related tax effects. The 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.
Estimated future net cash flows are calculated using end-of-period costs and an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months. 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, 2012, qualified for hedge accounting treatment.
Any excess of the net book value, less related deferred taxes, over the ceiling is written off as an expense. An expense recorded in one period may not be reversed in a subsequent period even though higher commodity prices may have increased the ceiling applicable to the subsequent period.
Capitalized costs are depleted by an equivalent unit-of-production method, converting gas to oil at the ratio of six thousand cubic feet of gas to one barrel of oil. Depletion is calculated using the capitalized costs, including estimated asset retirement costs, plus the estimated future expenditures (based on current costs) to be incurred in developing proved reserves, net of estimated salvage values.
Costs associated with unproved properties are excluded from the depletion calculation until it is determined whether or not proved reserves can be assigned to such properties. Devon assesses its unproved properties for impairment quarterly. Significant unproved properties are assessed individually. Costs of insignificant unproved properties are transferred into the depletion calculation over holding periods ranging from three to four years.
No gain or loss is recognized upon disposal of oil and gas properties unless such disposal significantly alters the relationship between capitalized costs and proved reserves in a particular country.
Depreciation of midstream pipelines are provided on a unit-of-production basis. Depreciation and amortization of other property and equipment, including corporate and other midstream assets and leasehold improvements, are provided using the straight-line method based on estimated useful lives ranging from three to 60 years. Interest costs incurred and attributable to major midstream and corporate construction projects are also capitalized.
Devon recognizes liabilities for retirement obligations associated with tangible long-lived assets, such as producing well sites 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. When the assumptions used to estimate a recorded asset retirement obligation change, a revision is recorded to both the asset retirement obligation and the asset retirement cost. Devon’s asset retirement obligations include estimated environmental remediation costs which arise from normal operations and are associated with the retirement of such long-lived assets. The asset retirement cost is depreciated using a systematic and rational method similar to that used for the associated property and equipment.
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. Such test includes an assessment of qualitative and quantitative factors. The impairment test requires allocating goodwill and all other assets and liabilities to assigned reporting units. The fair value of each reporting unit is estimated and compared to the net book value of the reporting unit. If the estimated fair value of the reporting unit is less than the net book value, including goodwill, then the goodwill is written down to the implied fair value of the goodwill through a charge to expense. Because quoted market prices are not available for Devon's reporting units, the fair values of the reporting units are estimated based upon several valuation analyses, including comparable companies, comparable transactions and premiums paid.
Devon performed annual impairment tests of goodwill in the fourth quarters of 2012, 2011 and 2010. Based on these assessments, no impairment of goodwill was required.
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 resulting from improper operation of assets 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.
Fair Value Measurements
Certain of Devon's assets and liabilities are measured at fair value at each reporting date. Fair value represents the price that would be received to sell the asset or paid to transfer the liability in an orderly transaction between market participants. This price is commonly referred to as the “exit price.” Fair value measurements are classified according to a hierarchy that prioritizes the inputs underlying the valuation techniques. This hierarchy consists of three broad levels:
· |
Level 1 – Inputs consist of unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. When available, Devon measures fair value using Level 1 inputs because they generally provide the most reliable evidence of fair value. |
· |
Level 2 – Inputs consist of 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 – Inputs are not observable from objective sources and have the lowest priority. The most common Level 3 fair value measurement is an internally developed cash flow model. |
Discontinued Operations
As a result of the November 2009 plan to divest Devon’s offshore assets, all amounts related to Devon's International operations are classified as discontinued operations. The Gulf of Mexico properties that were divested in 2010 do not qualify as discontinued operations under accounting rules. As such, amounts in these notes and the accompanying financial statements that pertain to continuing operations include amounts related to Devon’s offshore Gulf of Mexico operations.
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. Assets and liabilities of the Canadian subsidiaries are translated to U.S. dollars using the applicable exchange rate as of the end of a reporting period. Revenues, expenses and cash flow are translated using an average exchange rate during the reporting period. Translation adjustments have no effect on net income and are included in accumulated other comprehensive earnings in stockholders' equity.
|
|
December 31, |
|
|
2012 |
2011 |
|
(In millions) |
|
U.S. |
$ 3,046
|
$ 3,046
|
Canada |
3,033 | 2,967 |
Total |
$ 6,079
|
$ 6,013
|
|
|
Comprehensive Statement of Earnings Caption |
2012 |
2011 |
2010 |
|
|
|
(In millions) |
|||
Cash settlements: |
|
|
|
|
|
Commodity derivatives |
Oil, gas and NGL derivatives |
$ 870
|
$ 392
|
$ 888
|
|
Interest rate derivatives |
Other, net |
14 | 77 | 44 | |
Foreign currency derivatives |
Other, net |
(19) | 16 |
— |
|
Total cash settlements |
865 | 485 | 932 | ||
|
|
|
|
|
|
Unrealized gains (losses): |
|
|
|
|
|
Commodity derivatives |
Oil, gas and NGL derivatives |
(177) | 489 | (77) | |
Interest rate derivatives |
Other, net |
(29) | (88) | (30) | |
Foreign currency derivatives |
Other, net |
1 |
— |
— |
|
Total unrealized gains (losses) |
(205) | 401 | (107) | ||
Net gain recognized on comprehensive statements of earnings |
$ 660
|
$ 886
|
$ 825
|
|
|
December 31, |
|
|
Balance Sheet Caption |
2012 |
2011 |
|
|
(In millions) |
|
Asset derivatives: |
|
|
|
Commodity derivatives |
Other current assets |
$ 379
|
$ 611
|
Commodity derivatives |
Other long-term assets |
22 | 17 |
Interest rate derivatives |
Other current assets |
23 | 30 |
Interest rate derivatives |
Other long-term assets |
— |
22 |
Foreign currency derivatives |
Other current assets |
1 |
— |
Total asset derivatives |
$ 425
|
$ 680
|
|
|
|
|
|
Liability derivatives: |
|
|
|
Commodity derivatives |
Other current liabilities |
$ 3
|
$ 82
|
Commodity derivatives |
Other long-term liabilities |
29 |
— |
Total liability derivatives |
$ 32
|
$ 82
|
|
Price Swaps |
Price Collars |
Call Options Sold |
||||
Period |
Volume (Bbls/d) |
Weighted Average Price ($/Bbl) |
Volume (Bbls/d) |
Weighted Average Floor Price ($/Bbl) |
Weighted Average Ceiling Price ($/Bbl) |
Volume (Bbls/d) |
Weighted Average Price ($/Bbl) |
Q1-Q4 2013 |
31,000 |
$104.13 |
45,753 |
$91.19 |
$115.97 |
10,000 |
$120.00 |
Q1-Q4 2014 |
4,000 |
$100.49 |
2,000 |
$90.00 |
$111.13 |
10,000 |
$120.00 |
Basis Swaps |
|||
Period |
Index |
Volume (Bbls/d) |
Weighted Average Differential to WTI ($/Bbl) |
Q1-Q2 2013 |
Western Canadian Select |
3,000 |
$(19.58) |
|
Price Swaps |
Price Collars |
Call Options Sold |
||||
Period |
Volume (MMBtu/d) |
Weighted Average Price ($/MMBtu) |
Volume (MMBtu/d) |
Weighted Average Floor Price ($/MMBtu) |
Weighted Average Ceiling Price ($/MMBtu) |
Volume (MMBtu/d) |
Weighted Average Price ($/MMBtu) |
Q1-Q4 2013 |
560,000 |
$4.18 |
461,370 |
$3.53 |
$4.33 |
— |
— |
Q1-Q4 2014 |
250,000 |
$4.09 |
— |
— |
— |
250,000 |
$5.00 |
|
Price Swaps |
||
Period |
Volume (MMBtu/d) |
Weighted Average Price ($/MMBtu) |
|
Q1-Q4 2013 |
28,435 |
$3.64 |
Basis Swaps |
|||
Period |
Index |
Volume (MMBtu/d) |
Weighted Average Differential to Henry Hub ($/MMBtu) |
Q1-Q4 2013 |
El Paso Natural Gas |
20,000 |
$(0.12) |
Q1-Q4 2013 |
Panhandle Eastern Pipeline |
20,000 |
$(0.17) |
|
Price Swaps |
||
Period |
Product |
Volume (Bbls/d) |
Weighted Average Floor Price ($/Bbl) |
Q1-Q4 2013 |
Propane |
822 |
$41.12 |
Q1-Q4 2013 |
Ethane |
1,973 |
$15.36 |
Basis Swaps |
|||
Period |
Pay |
Volume (Bbls/d) |
Weighted Average Differential to WTI ($/Bbl) |
Q1-Q4 2013 |
Natural Gasoline |
500 |
$(6.80) |
|
|||
Notional |
Weighted Average Fixed Rate Received |
Variable Rate Paid |
Expiration |
(In millions) |
|
|
|
$ 750
|
3.88% |
Federal funds rate |
July 2013 |
|
|
|||||
Forward Contract |
||||||
Currency |
Contract Type |
CAD Notional |
Weighted Average Fixed Rate Received |
Expiration |
||
|
|
(In millions) |
(CAD-USD) |
|
||
Canadian Dollar |
Sell |
$ 755
|
1.005 |
March 2013 |
|
|
Year Ended December 31, |
||
|
2012 |
2011 |
2010 |
|
(In millions) |
||
Office consolidation: |
|
|
|
Employee severance |
$ 77
|
$— |
$— |
Lease obligations |
3 |
— |
— |
Total |
80 |
— |
— |
Offshore divestitures: |
|
|
|
Employee severance |
(3) | 8 | (27) |
Lease obligations and other |
(3) | (10) | 84 |
Total |
(6) | (2) | 57 |
Restructuring costs |
$ 74
|
$ (2)
|
$ 57
|
|
|
|
|
|
Other Current Liabilities |
Other Long-Term Liabilities |
Total |
|
(In millions) |
||
Balance as of December 31, 2010 |
$ 31
|
$ 51
|
$ 82
|
Lease obligations - Offshore |
2 | (35) | (33) |
Employee severance - Offshore |
(4) |
— |
(4) |
Balance as of December 31, 2011 |
29 | 16 | 45 |
Employee severance – Office consolidation |
49 |
— |
49 |
Lease obligations - Offshore |
(17) | (7) | (24) |
Employee severance - Offshore |
(9) |
— |
(9) |
Balance as of December 31, 2012 |
$ 52
|
$ 9
|
$ 61
|
|
|
Year Ended December 31, |
||
|
2012 |
2011 |
2010 |
|
(In millions) |
||
Accretion of asset retirement obligations |
$ 110
|
$ 92
|
$ 92
|
Interest rate derivatives |
15 | 11 | (14) |
Foreign currency derivatives |
18 | (16) |
— |
Foreign exchange loss (gain) |
(15) | 25 | (7) |
Interest income |
(36) | (21) | (13) |
Other |
(14) | (101) | (25) |
Other, net |
$ 78
|
$ (10)
|
$ 33
|
|
|
Year Ended December 31, |
||
|
2012 |
2011 |
2010 |
|
(In millions) |
||
Current income tax expense (benefit): |
|
|
|
U.S. federal |
$ 60
|
$ (143)
|
$ 244
|
Various states |
(3) | 20 | 16 |
Canada and various provinces |
(5) | (20) | 256 |
Total current tax expense (benefit) |
52 | (143) | 516 |
Deferred income tax expense (benefit): |
|
|
|
U.S. federal |
(188) | 1,986 | 781 |
Various states |
34 | 95 | 21 |
Canada and various provinces |
(30) | 218 | (83) |
Total deferred tax expense (benefit) |
(184) | 2,299 | 719 |
Total income tax expense (benefit) |
$ (132)
|
$ 2,156
|
$ 1,235
|
|
Year Ended December 31, |
||
|
2012 |
2011 |
2010 |
|
(In millions) |
||
Expected income tax expense (benefit) based on U.S. statutory tax rate of 35% |
$ (111)
|
$ 1,502
|
$ 1,249
|
Assumed repatriations |
— |
725 | 144 |
State income taxes |
20 | 70 | 31 |
Taxation on Canadian operations |
(19) | (91) | (60) |
Other |
(22) | (50) | (129) |
Total income tax expense (benefit) |
$ (132)
|
$ 2,156
|
$ 1,235
|
|
December 31, |
|
|
2012 |
2011 |
Deferred tax assets: |
(In millions) |
|
Net operating loss carryforwards |
$ 427
|
$ 222
|
Asset retirement obligations |
618 | 447 |
Pension benefit obligations |
129 | 130 |
Alternative minimum tax credits |
198 |
— |
Other |
134 | 117 |
Total deferred tax assets |
1,506 | 916 |
Deferred tax liabilities: |
|
|
Property and equipment |
(4,970) | (4,475) |
Fair value of financial instruments |
(141) | (218) |
Long-term debt |
(198) | (185) |
Taxes on unremitted foreign earnings |
(936) | (936) |
Other |
(76) | (27) |
Total deferred tax liabilities |
(6,321) | (5,841) |
Net deferred tax liability |
$ (4,815)
|
$ (4,925)
|
|
December 31, |
|
|
2012 |
2011 |
|
(In millions) |
|
Balance at beginning of year |
$ 165
|
$ 194
|
Tax positions taken in prior periods |
(46) | (3) |
Tax positions taken in current year |
92 | 27 |
Accrual of interest related to tax positions taken |
7 | (7) |
Lapse of statute of limitations |
(3) | (41) |
Settlements |
— |
(5) |
Foreign currency translation |
1 |
— |
Balance at end of year |
$ 216
|
$ 165
|
Jurisdiction |
Tax Years Open |
U.S. federal |
2008-2012 |
Various U.S. states |
2008-2012 |
Canada federal |
2004-2012 |
Various Canadian provinces |
2004-2012 |
|
|
Year Ended December 31, |
||
|
2012 |
2011 |
2010 |
|
(In millions) |
||
Foreign currency translation: |
|
||
Beginning accumulated foreign currency translation |
$ 1,802
|
$ 1,993
|
$ 1,616
|
Change in cumulative translation adjustment |
203 | (200) | 397 |
Income tax benefit (expense) |
(9) | 9 | (20) |
Ending accumulated foreign currency translation |
1,996 | 1,802 | 1,993 |
Pension and postretirement benefit plans: |
|
|
|
Beginning accumulated pension and postretirement benefits |
(227) | (233) | (231) |
Net actuarial loss and prior service cost arising in current year |
(47) | (21) | (33) |
Income tax benefit |
16 | 8 | 11 |
Recognition of net actuarial loss and prior service cost in net earnings |
51 | 30 | 31 |
Income tax expense |
(18) | (11) | (11) |
Ending accumulated pension and postretirement benefits |
(225) | (227) | (233) |
Accumulated other comprehensive earnings, net of tax |
$ 1,771
|
$ 1,575
|
$ 1,760
|
|
|
Year Ended December 31, |
||
|
2012 |
2011 |
2010 |
|
(In millions) |
||
Net decrease (increase) in working capital: |
|
||
Change in accounts receivable |
$ 140
|
$ (185)
|
$ 23
|
Change in other current assets |
(128) | 125 | 21 |
Change in accounts payable |
(8) | 64 | 37 |
Change in revenues and royalties payable |
19 | 144 | 48 |
Change in other current liabilities |
(73) | 37 | (402) |
Net decrease (increase) in working capital |
$ (50)
|
$ 185
|
$ (273)
|
|
|
|
|
Supplementary cash flow data – total operations: |
|
|
|
Interest paid (net of capitalized interest) |
$ 334
|
$ 325
|
$ 359
|
Income taxes paid (received) |
$ 100
|
$ (383)
|
$ 955
|
|
|
December 31, |
|
|
2012 |
2011 |
|
(In millions) |
|
Canadian treasury, agency and provincial securities |
$ 1,865
|
$ 1,155
|
U.S. treasuries |
429 | 201 |
Other |
49 | 147 |
Short-term investments |
$ 2,343
|
$ 1,503
|
|
|
December 31, |
|
|
2012 |
2011 |
|
(In millions) |
|
Oil, gas and NGL sales |
$ 752
|
$ 928
|
Joint interest billings |
270 | 247 |
Marketing and midstream revenues |
161 | 174 |
Other |
72 | 39 |
Gross accounts receivable |
1,255 | 1,388 |
Allowance for doubtful accounts |
(10) | (9) |
Net accounts receivable |
$ 1,245
|
$ 1,379
|
|
|
December 31, |
|
|
2012 |
2011 |
|
(In millions) |
|
Derivative financial instruments |
$ 403
|
$ 641
|
Inventories |
110 | 102 |
Income tax receivable |
119 | 35 |
Current assets held for sale |
3 | 21 |
Other |
111 | 69 |
Other current assets |
$ 746
|
$ 868
|
|
|
Q3 2012 |
Q4 2012 |
Year Ended December 31, 2012 |
|||
|
Gross |
Net of Taxes |
Gross |
Net of Taxes |
Gross |
Net of Taxes |
|
(In millions) |
|||||
U.S. oil and gas assets |
$ 1,106
|
$ 705
|
$ 687
|
$ 437
|
$ 1,793
|
$ 1,142
|
Canada oil and gas assets |
— |
— |
163 | 122 | 163 | 122 |
Midstream assets |
22 | 14 | 46 | 30 | 68 | 44 |
Total asset impairments |
$ 1,128
|
$ 719
|
$ 896
|
$ 589
|
$ 2,024
|
$ 1,308
|
|
|
December 31, |
|
|
2012 |
2011 |
|
(In millions) |
|
Commercial paper |
$ 3,189
|
$ 3,726
|
Other debentures and notes: |
|
|
5.625% due January 15, 2014 |
500 | 500 |
Non-interest bearing promissory note due June 29, 2014 |
— |
85 |
2.40% due July 15, 2016 |
500 | 500 |
1.875% due May 15, 2017 |
750 |
— |
8.25% due July 1, 2018 |
125 | 125 |
6.30% due January 15, 2019 |
700 | 700 |
4.00% due July 15, 2021 |
500 | 500 |
3.25% due May 15, 2022 |
1,000 |
— |
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 |
5.60% due July 15, 2041 |
1,250 | 1,250 |
4.75% due May 15, 2042 |
750 |
— |
Net discount on other debentures and notes |
(20) | (6) |
Total debt |
11,644 | 9,780 |
Less amount classified as short-term debt |
3,189 | 3,811 |
Long-term debt |
$ 8,455
|
$ 5,969
|
2013 |
$ 3,189
|
2014 |
500 |
2015 |
— |
2016 |
500 |
2017 |
750 |
2018 and thereafter |
6,725 |
Total |
$ 11,664
|
Debt Assumed |
Fair Value of Debt Assumed |
Effective Rate of Debt Assumed |
|
(In millions) |
|
8.250% due July 2018 (principal of $125 million) |
$ 147
|
5.5% |
7.500% due September 2027 (principal of $150 million) |
$ 169
|
6.5% |
|
Year Ended December 31, |
||
|
2012 |
2011 |
2010 |
|
(In millions) |
||
Interest based on debt outstanding |
$ 440
|
$ 414
|
$ 408
|
Capitalized interest |
(48) | (72) | (76) |
Early retirement of debt |
— |
— |
19 |
Other |
14 | 10 | 12 |
Interest expense |
$ 406
|
$ 352
|
$ 363
|
|
May 2012 |
July 2011 |
January 2009 |
March 2002 |
1.875% due May 15, 2017 |
$ 750
|
$— |
$— |
$— |
3.25% due May 15, 2022 |
1,000 |
— |
— |
— |
4.75% due May 15, 2042 |
750 |
— |
— |
— |
2.40% due July 15, 2016 |
— |
500 |
— |
— |
4.00% due July 15, 2021 |
— |
500 |
— |
— |
5.60% due July 15, 2041 |
— |
1,250 |
— |
— |
5.625% due January 15, 2014 |
— |
— |
500 |
— |
6.30% due January 15, 2019 |
— |
— |
700 |
— |
7.95% due April 15, 2032 |
— |
— |
— |
1,000 |
Discount and issuance costs |
(35) | (29) | (13) | (14) |
Net proceeds |
$ 2,465
|
$ 2,221
|
$ 1,187
|
$ 986
|
|
|
Year Ended December 31, |
|
|
2012 |
2011 |
|
(In millions) |
|
Asset retirement obligations as of beginning of period |
$ 1,563
|
$ 1,497
|
Liabilities incurred |
90 | 53 |
Liabilities settled |
(86) | (82) |
Revision of estimated obligation |
420 | 25 |
Liabilities assumed by others |
(23) |
— |
Accretion expense on discounted obligation |
110 | 92 |
Foreign currency translation adjustment |
21 | (22) |
Asset retirement obligations as of end of period |
2,095 | 1,563 |
Less current portion |
99 | 67 |
Asset retirement obligations, long-term |
$ 1,996
|
$ 1,496
|
|
|
Pension Benefits |
Postretirement Benefits |
||
|
2012 | 2011 | 2012 | 2011 |
|
(In millions) |
|||
Change in benefit obligation: |
|
|
|
|
Benefit obligation at beginning of year |
$ 1,303
|
$ 1,124
|
$ 37
|
$ 43
|
Service cost |
43 | 37 | 1 | 1 |
Interest cost |
60 | 60 | 1 | 2 |
Actuarial loss (gain) |
95 | 123 | (4) | (8) |
Plan amendments |
14 |
— |
— |
5 |
Plan curtailments |
(20) |
— |
1 |
— |
Plan settlements |
(93) |
— |
— |
(4) |
Foreign exchange rate changes |
1 | (1) |
— |
— |
Participant contributions |
— |
— |
3 | 3 |
Benefits paid |
(43) | (40) | (5) | (5) |
Benefit obligation at end of year |
1,360 | 1,303 | 34 | 37 |
Change in plan assets: |
|
|
|
|
Fair value of plan assets at beginning of year |
1,187 | 632 |
— |
— |
Actual return on plan assets |
102 | 141 |
— |
— |
Employer contributions |
11 | 454 | 2 | 7 |
Participant contributions |
— |
— |
3 | 3 |
Plan settlements |
(93) |
— |
— |
(5) |
Benefits paid |
(43) | (40) | (5) | (5) |
Foreign exchange rate changes |
1 |
— |
— |
— |
Fair value of plan assets at end of year |
1,165 | 1,187 |
— |
— |
Funded status at end of year |
$ (195)
|
$ (116)
|
$ (34)
|
$ (37)
|
|
|
|
|
|
Amounts recognized in balance sheet: |
|
|
|
|
Noncurrent assets |
$ 62
|
$ 116
|
$— |
$— |
Current liabilities |
(12) | (10) | (3) | (3) |
Noncurrent liabilities |
(245) | (222) | (31) | (34) |
Net amount |
$ (195)
|
$ (116)
|
$ (34)
|
$ (37)
|
|
|
|
|
|
Amounts recognized in accumulated other comprehensive earnings: |
|
|
|
|
Net actuarial loss (gain) |
$ 340
|
$ 348
|
$ (11)
|
$ (9)
|
Prior service cost (credit) |
25 | 18 | (4) | (5) |
Total |
$ 365
|
$ 366
|
$ (15)
|
$ (14)
|
|
December 31, |
|
|
2012 |
2011 |
|
(In millions) |
|
Projected benefit obligation |
$ 257
|
$ 232
|
Accumulated benefit obligation |
$ 216
|
$ 189
|
Fair value of plan assets |
$— |
$— |
|
|
|
|
|
|
|
|
Pension Benefits |
Postretirement Benefits |
||||
|
2012 |
2011 |
2010 |
2012 |
2011 |
2010 |
|
(In millions) |
|||||
Net periodic benefit cost: |
|
|
|
|
|
|
Service cost |
$ 43
|
$ 37
|
$ 33
|
$ 1
|
$ 1
|
$ 1
|
Interest cost |
60 | 60 | 58 | 1 | 2 | 3 |
Expected return on plan assets |
(64) | (42) | (36) |
— |
— |
— |
Curtailment and settlement expense |
26 |
— |
— |
1 | (3) |
— |
Recognition of net actuarial loss (gain) |
24 | 32 | 27 | (1) |
— |
— |
Recognition of prior service cost |
3 | 3 | 3 | (1) | (2) | 1 |
Total net periodic benefit cost |
92 | 90 | 85 | 1 | (2) | 5 |
Other comprehensive loss (earnings): |
|
|
|
|
|
|
Actuarial loss (gain) arising in current year |
37 | 23 | 50 | (4) | (7) | 1 |
Prior service cost (credit) arising in current year |
14 |
— |
4 |
— |
5 | (22) |
Recognition of net actuarial loss, including settlement expense, in net periodic benefit cost |
(45) | (32) | (27) | 1 | 3 |
— |
Recognition of prior service cost, including curtailment, in net periodic benefit cost |
(8) | (3) | (3) | 1 | 2 | (1) |
Total other comprehensive loss (earnings) |
(2) | (12) | 24 | (2) | 3 | (22) |
Total recognized |
$ 90
|
$ 78
|
$ 109
|
$ (1)
|
$ 1
|
$ (17)
|
|
|
|
|
Pension Benefits |
Postretirement Benefits |
|
(In millions) |
|
Net actuarial loss (gain) |
$ 22
|
$ (1)
|
Prior service cost (credit) |
4 |
— |
Total |
$ 26
|
$ (1)
|
|
Pension Benefits |
Postretirement Benefits |
||||
|
2012 |
2011 |
2010 |
2012 |
2011 |
2010 |
Assumptions to determine benefit obligations: |
|
|
|
|
|
|
Discount rate |
3.85% | 4.65% | 5.50% | 3.30% | 4.25% | 4.90% |
Rate of compensation increase |
4.48% | 4.97% | 6.94% |
N/A |
N/A |
N/A |
Assumptions to determine net periodic benefit cost: |
|
|
|
|
|
|
Discount rate |
4.65% | 5.50% | 6.00% | 4.25% | 4.90% | 5.70% |
Expected return on plan assets |
5.48% | 6.48% | 6.94% |
N/A |
N/A |
N/A |
Rate of compensation increase |
4.97% | 6.94% | 6.95% |
N/A |
N/A |
N/A |
|
As of December 31, 2012 |
||||
|
|
|
Fair Value Measurements Using: |
||
|
Actual Allocation |
Total |
Level 1 Inputs |
Level 2 Inputs |
Level 3 Inputs |
|
($ in millions) |
||||
Fixed-income securities: |
|
|
|
|
|
U.S. Treasury obligations |
39.4% | $ 459
|
$ 65
|
$ 394
|
$— |
Corporate bonds |
26.5% | 308 | 256 | 52 |
— |
Other bonds |
2.4% | 28 | 28 |
— |
— |
Total fixed-income securities |
68.3% | 795 | 349 | 446 |
— |
Equity securities: |
|
|
|
|
|
Global (large, mid, small cap) |
20.5% | 239 |
— |
239 |
— |
Other securities: |
|
|
|
|
|
Hedge fund & alternative investments |
10.3% | 120 | 17 |
— |
103 |
Short-term investment funds |
0.9% | 11 |
— |
11 |
— |
Total other securities |
11.2% | 131 | 17 | 11 | 103 |
Total investments |
100.0% | $ 1,165
|
$ 366
|
$ 696
|
$ 103
|
|
As of December 31, 2011 |
||||
|
|
|
Fair Value Measurements Using: |
||
|
Actual Allocation |
Total |
Level 1 Inputs |
Level 2 Inputs |
Level 3 Inputs |
|
($ in millions) |
||||
Fixed-income securities: |
|
|
|
|
|
U.S. Treasury obligations |
43.9% | $ 522
|
$ 27
|
$ 495
|
$— |
Corporate bonds |
24.8% | 294 | 265 | 29 |
— |
Other bonds |
3.1% | 36 | 36 |
— |
— |
Total fixed-income securities |
71.8% | 852 | 328 | 524 |
— |
Equity securities: |
|
|
|
|
|
Global (large, mid, small cap) |
18.0% | 214 |
— |
214 |
— |
Other securities: |
|
|
|
|
|
Hedge fund & alternative investments |
8.9% | 106 | 16 |
— |
90 |
Short-term investment funds |
1.3% | 15 |
— |
15 |
— |
Total other securities |
10.2% | 121 | 16 | 15 | 90 |
Total investments |
100.0% | $ 1,187
|
$ 344
|
$ 753
|
$ 90
|
December 31, 2010 |
$ 58
|
Purchases |
33 |
Investment returns |
(1) |
December 31, 2011 |
90 |
Purchases |
6 |
Investment returns |
7 |
December 31, 2012 |
$ 103
|
|
|
|
|
|
Pension Benefits |
Postretirement Benefits |
|
|
(In millions) |
||
Devon's 2013 contributions |
$ 11
|
$ 3
|
|
Benefit payments: |
|
|
|
2013 |
$ 60
|
$ 3
|
|
2014 |
$ 61
|
$ 3
|
|
2015 |
$ 63
|
$ 3
|
|
2016 |
$ 65
|
$ 3
|
|
2017 |
$ 67
|
$ 3
|
|
2018 to 2022 |
$ 386
|
$ 14
|
|
Year Ended December 31, |
||
|
2012 |
2011 |
2010 |
|
(In millions) |
||
401(k) and enhanced contribution plans |
$ 36
|
$ 33
|
$ 32
|
Canadian pension and savings plans |
23 | 21 | 17 |
Total |
$ 59
|
$ 54
|
$ 49
|
|
|
|
|
December 31, |
|
|
2012 |
2011 |
Fixed income |
70% | 70% |
Equity |
20% | 20% |
Other |
10% | 10% |
|
|
|
|
|
|
|
Year Ending December 31, |
Purchase Obligations |
Drilling and Facility Obligations |
Operational Agreements |
Office and Equipment Leases |
|
|
(In millions) |
||||
2013 |
$ 826
|
$ 777
|
$ 391
|
$ 50
|
|
2014 |
862 | 173 | 406 | 34 | |
2015 |
861 |
— |
391 | 31 | |
2016 |
861 |
— |
340 | 29 | |
2017 |
844 |
— |
342 | 27 | |
Thereafter |
2,741 |
— |
1,626 | 141 | |
Total |
$ 6,995
|
$ 950
|
$ 3,496
|
$ 312
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using: |
||
|
Carrying Amount |
Total Fair Value |
Level 1 |
Level 2 |
Level 3 |
|
(In millions) |
||||
December 31, 2012 assets (liabilities): |
|
|
|
|
|
Cash equivalents |
$ 4,149
|
$ 4,149
|
$ 200
|
$ 3,949
|
$— |
Short-term investments |
$ 2,343
|
$ 2,343
|
$ 429
|
$ 1,914
|
$— |
Long-term investments |
$ 64
|
$ 64
|
$— |
$— |
$ 64
|
Commodity derivatives |
$ 401
|
$ 401
|
$— |
$ 401
|
$— |
Commodity derivatives |
$ (32)
|
$ (32)
|
$— |
$ (32)
|
$— |
Interest rate derivatives |
$ 23
|
$ 23
|
$— |
$ 23
|
$— |
Foreign currency derivatives |
$ 1
|
$ 1
|
$— |
$ 1
|
$— |
Debt |
$ (11,644)
|
$ (13,435)
|
$— |
$ (13,435)
|
$— |
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using |
||
|
Carrying Amount |
Total Fair Value |
Level 1 |
Level 2 |
Level 3 |
|
(In millions) |
||||
December 31, 2011 assets (liabilities): |
|
|
|
|
|
Cash equivalents |
$ 5,123
|
$ 5,123
|
$ 929
|
$ 4,194
|
$— |
Short-term investments |
$ 1,503
|
$ 1,503
|
$ 201
|
$ 1,302
|
$— |
Long-term investments |
$ 84
|
$ 84
|
$— |
$— |
$ 84
|
Commodity derivatives |
$ 628
|
$ 628
|
$— |
$ 628
|
$— |
Commodity derivatives |
$ (82)
|
$ (82)
|
$— |
$ (82)
|
$— |
Interest rate derivatives |
$ 52
|
$ 52
|
$— |
$ 52
|
$— |
Debt |
$ (9,780)
|
$ (11,380)
|
$— |
$ (11,295)
|
$ (85)
|
|
Year Ended December 31, |
|
|
2012 |
2011 |
|
(In millions) |
|
Long-term investments balance at beginning of period |
$ 84
|
$ 94
|
Redemptions of principal |
(20) | (10) |
Long-term investments balance at end of period |
$ 64
|
$ 84
|
|
Year Ended December 31, |
|
|
2012 |
2011 |
|
(In millions) |
|
Debt balance at beginning of period |
$ (85)
|
$ (144)
|
Foreign exchange translation adjustment |
(1) | 1 |
Accretion of promissory note |
3 | (5) |
Redemptions of principal |
83 | 63 |
Debt balance at end of period |
$— |
$ (85)
|
|
|
Year Ended December 31, |
|||||||
|
2012 |
|
2011 |
|
2010 |
|||
|
|
|
|
|
|
|
|
|
|
|
(In millions) |
||||||
Operating earnings |
$ |
- |
|
$ |
38 |
|
$ |
567 |
Gain (loss) on sale of oil and gas properties |
|
(16) |
|
|
2,552 |
|
|
1,818 |
Earnings (loss) before income taxes |
|
(16) |
|
|
2,590 |
|
|
2,385 |
Income tax expense |
|
5 |
|
|
20 |
|
|
168 |
Earnings (loss) from discontinued operations |
$ |
(21) |
|
$ |
2,570 |
|
$ |
2,217 |
|
December 31, 2011 |
|
(In millions) |
Other current assets |
$ 21
|
Property and equipment, net |
132 |
Total assets |
$ 153
|
|
|
Accounts payable |
$ 20
|
Other current liabilities |
28 |
Total liabilities |
$ 48
|
|
|
|
|
|
|
U.S. |
Canada |
Total |
|
(In millions) |
||
Year Ended December 31, 2012: |
|
||
Oil, gas and NGL sales |
$ 4,679
|
$ 2,474
|
$ 7,153
|
Oil, gas and NGL derivatives |
$ 681
|
$ 12
|
$ 693
|
Marketing and midstream revenues |
$ 1,542
|
$ 114
|
$ 1,656
|
Depreciation, depletion and amortization |
$ 1,824
|
$ 987
|
$ 2,811
|
Interest expense |
$ 343
|
$ 63
|
$ 406
|
Asset impairments |
$ 1,861
|
$ 163
|
$ 2,024
|
Loss from continuing operations before income taxes |
$ (263)
|
$ (54)
|
$ (317)
|
Income tax benefit |
$ (97)
|
$ (35)
|
$ (132)
|
Loss from continuing operations |
$ (166)
|
$ (19)
|
$ (185)
|
Property and equipment, net |
$ 18,361
|
$ 8,955
|
$ 27,316
|
Total assets |
$ 24,256
|
$ 19,070
|
$ 43,326
|
Capital expenditures |
$ 6,511
|
$ 1,963
|
$ 8,474
|
|
U.S. |
Canada |
Total |
|
(In millions) |
||
Year Ended December 31, 2011: |
|
|
|
Oil, gas and NGL sales |
$ 5,418
|
$ 2,897
|
$ 8,315
|
Oil, gas and NGL derivative |
$ 881
|
$— |
$ 881
|
Marketing and midstream revenues |
$ 2,059
|
$ 199
|
$ 2,258
|
Depreciation, depletion and amortization |
$ 1,439
|
$ 809
|
$ 2,248
|
Interest expense |
$ 204
|
$ 148
|
$ 352
|
Earnings from continuing operations before income taxes |
$ 3,477
|
$ 813
|
$ 4,290
|
Income tax expense |
$ 1,958
|
$ 198
|
$ 2,156
|
Earnings from continuing operations |
$ 1,519
|
$ 615
|
$ 2,134
|
Property and equipment, net |
$ 16,989
|
$ 7,785
|
$ 24,774
|
Total assets (1) |
$ 22,622
|
$ 18,342
|
$ 40,964
|
Capital expenditures |
$ 6,101
|
$ 1,694
|
$ 7,795
|
Year Ended December 31, 2010: |
|
|
|
Oil, gas and NGL sales |
$ 4,742
|
$ 2,520
|
$ 7,262
|
Oil, gas and NGL derivatives |
$ 809
|
$ 2
|
$ 811
|
Marketing and midstream revenues |
$ 1,742
|
$ 125
|
$ 1,867
|
Depreciation, depletion and amortization |
$ 1,229
|
$ 701
|
$ 1,930
|
Interest expense |
$ 159
|
$ 204
|
$ 363
|
Earnings from continuing operations before income taxes |
$ 2,943
|
$ 625
|
$ 3,568
|
Income tax expense |
$ 1,062
|
$ 173
|
$ 1,235
|
Earnings from continuing operations |
$ 1,881
|
$ 452
|
$ 2,333
|
Property and equipment, net |
$ 12,379
|
$ 7,273
|
$ 19,652
|
Total assets (1) |
$ 18,320
|
$ 13,185
|
$ 31,505
|
Capital expenditures |
$ 4,935
|
$ 1,985
|
$ 6,920
|
____________________________
(1) Amounts in the table above do not include assets held for sale related to Devon’s discontinued operations, which totaled $153 million and $1.4 billion in 2011 and 2010, respectively
|
|
Year Ended December 31, 2012 |
||||
|
U.S. Onshore |
U.S. Offshore |
Total |
Canada |
Total |
|
(In millions) |
||||
Property acquisition costs: |
|
||||
Proved properties |
$ 2
|
$— |
$ 2
|
$ 71
|
$ 73
|
Unproved properties |
1,135 |
— |
1,135 | 43 | 1,178 |
Exploration costs |
351 |
— |
351 | 304 | 655 |
Development costs |
4,408 |
— |
4,408 | 1,691 | 6,099 |
Costs incurred |
$ 5,896
|
$— |
$ 5,896
|
$ 2,109
|
$ 8,005
|
|
Year Ended December 31, 2011 |
||||
|
U.S. Onshore |
U.S. Offshore |
Total |
Canada |
Total |
|
(In millions) |
||||
Property acquisition costs: |
|
||||
Proved properties |
$ 34
|
$— |
$ 34
|
$ 14
|
$ 48
|
Unproved properties |
851 |
— |
851 | 88 | 939 |
Exploration costs |
272 |
— |
272 | 266 | 538 |
Development costs |
4,130 |
— |
4,130 | 1,288 | 5,418 |
Costs incurred |
$ 5,287
|
$— |
$ 5,287
|
$ 1,656
|
$ 6,943
|
|
Year Ended December 31, 2010 |
||||
|
U.S. Onshore |
U.S. Offshore |
Total |
Canada |
Total |
|
(In millions) |
||||
Property acquisition costs: |
|
||||
Proved properties |
$ 29
|
$— |
$ 29
|
$ 4
|
$ 33
|
Unproved properties |
592 | 2 | 594 | 590 | 1,184 |
Exploration costs |
339 | 89 | 428 | 260 | 688 |
Development costs |
3,126 | 297 | 3,423 | 1,216 | 4,639 |
Costs incurred |
$ 4,086
|
$ 388
|
$ 4,474
|
$ 2,070
|
$ 6,544
|
|
December 31, 2012 |
||
|
U.S. |
Canada |
Total |
|
(In millions) |
||
Proved properties |
$ 46,570
|
$ 22,840
|
$ 69,410
|
Unproved properties |
1,703 | 1,605 | 3,308 |
Total oil & gas properties |
48,273 | 24,445 | 72,718 |
Accumulated DD&A |
(33,098) | (16,039) | (49,137) |
Net capitalized costs |
$ 15,175
|
$ 8,406
|
$ 23,581
|
|
December 31, 2011 |
||
|
U.S. |
Canada |
Total |
|
(In millions) |
||
Proved properties |
$ 41,397
|
$ 20,299
|
$ 61,696
|
Unproved properties |
2,347 | 1,635 | 3,982 |
Total oil & gas properties |
43,744 | 21,934 | 65,678 |
Accumulated DD&A |
(29,742) | (14,585) | (44,327) |
Net capitalized costs |
$ 14,002
|
$ 7,349
|
$ 21,351
|
|
|
|
|
|
|
|
|
Costs Incurred In |
|||||
|
2012 | 2011 | 2010 |
Prior to 2010 |
Total |
|
|
(In millions) |
|||||
Acquisition costs |
$ 928
|
$ 115
|
$ 788
|
$ 660
|
$ 2,491
|
|
Exploration costs |
228 | 142 | 48 | 1 | 419 | |
Development costs |
227 | 70 |
— |
10 | 307 | |
Capitalized interest |
35 | 36 | 20 |
— |
91 | |
Total oil and gas properties not subject to amortization |
$ 1,418
|
$ 363
|
$ 856
|
$ 671
|
$ 3,308
|
|
Year Ended December 31, 2012 |
||
|
U.S |
Canada |
Total |
|
(In millions) |
||
Oil, gas and NGL sales |
$ 4,679
|
$ 2,474
|
$ 7,153
|
Lease operating expenses |
(1,059) | (1,015) | (2,074) |
Depreciation, depletion and amortization |
(1,563) | (963) | (2,526) |
General and administrative expenses |
(159) | (137) | (296) |
Taxes other than income taxes |
(340) | (55) | (395) |
Asset impairments |
(1,793) | (163) | (1,956) |
Accretion of asset retirement obligations |
(40) | (69) | (109) |
Income tax (expense) benefit |
99 | (3) | 96 |
Results of operations |
$ (176)
|
$ 69
|
$ (107)
|
Depreciation, depletion and amortization per Boe |
$8.55 |
$14.41 |
$10.12 |
|
Year Ended December 31, 2011 |
||
|
U.S |
Canada |
Total |
|
(In millions) |
||
Oil, gas and NGL sales |
$ 5,418
|
$ 2,897
|
$ 8,315
|
Lease operating expenses |
(925) | (926) | (1,851) |
Depreciation, depletion and amortization |
(1,201) | (786) | (1,987) |
General and administrative expenses |
(132) | (119) | (251) |
Taxes other than income taxes |
(357) | (45) | (402) |
Accretion of asset retirement obligations |
(34) | (57) | (91) |
Income tax expense |
(1,005) | (250) | (1,255) |
Results of operations |
$ 1,764
|
$ 714
|
$ 2,478
|
Depreciation, depletion and amortization per Boe |
$6.94 |
$11.74 |
$8.28 |
|
Year Ended December 31, 2010 |
||
|
U.S. |
Canada |
Total |
|
(In millions) |
||
Oil, gas and NGL sales |
$ 4,742
|
$ 2,520
|
$ 7,262
|
Lease operating expenses |
(892) | (797) | (1,689) |
Depreciation, depletion and amortization |
(998) | (677) | (1,675) |
General and administrative expenses |
(133) | (83) | (216) |
Taxes other than income taxes |
(319) | (40) | (359) |
Accretion of asset retirement obligations |
(42) | (50) | (92) |
Income tax expense |
(849) | (246) | (1,095) |
Results of operations |
$ 1,509
|
$ 627
|
$ 2,136
|
Depreciation, depletion and amortization per Boe |
$6.11 |
$10.51 |
$7.36 |
|
U.S. |
Canada |
Total |
Proved undeveloped reserves as of December 31, 2011 |
403 | 379 | 782 |
Extensions and discoveries |
134 | 68 | 202 |
Revisions due to prices |
(47) | 9 | (38) |
Revisions other than price |
(10) | (6) | (16) |
Conversion to proved developed reserves |
(73) | (17) | (90) |
Proved undeveloped reserves as of December 31, 2012 |
407 | 433 | 840 |
|
Year Ended December 31, 2012 |
||
|
U.S. |
Canada |
Total |
|
(In millions) |
||
Future cash inflows |
$ 55,297
|
$ 33,570
|
$ 88,867
|
Future costs: |
|
|
|
Development |
(6,556) | (6,211) | (12,767) |
Production |
(24,265) | (16,611) | (40,876) |
Future income tax expense |
(6,542) | (1,992) | (8,534) |
Future net cash flows |
17,934 | 8,756 | 26,690 |
10% discount to reflect timing of cash flows |
(9,036) | (4,433) | (13,469) |
Standardized measure of discounted future net cash flows |
$ 8,898
|
$ 4,323
|
$ 13,221
|
|
Year Ended December 31, 2011 |
||
|
U.S. |
Canada |
Total |
|
(In millions) |
||
Future cash inflows |
$ 69,305
|
$ 36,786
|
$ 106,091
|
Future costs: |
|
|
|
Development |
(6,817) | (4,678) | (11,495) |
Production |
(26,217) | (15,063) | (41,280) |
Future income tax expense |
(11,432) | (3,763) | (15,195) |
Future net cash flows |
24,839 | 13,282 | 38,121 |
10% discount to reflect timing of cash flows |
(13,492) | (6,785) | (20,277) |
Standardized measure of discounted future net cash flows |
$ 11,347
|
$ 6,497
|
$ 17,844
|
|
Year Ended December 31, 2010 |
||
|
U.S. |
Canada |
Total |
|
(In millions) |
||
Future cash inflows |
$ 58,093
|
$ 35,948
|
$ 94,041
|
Future costs: |
|
|
|
Development |
(6,220) | (4,526) | (10,746) |
Production |
(24,223) | (12,249) | (36,472) |
Future income tax expense |
(8,643) | (4,209) | (12,852) |
Future net cash flows |
19,007 | 14,964 | 33,971 |
10% discount to reflect timing of cash flows |
(10,164) | (7,455) | (17,619) |
Standardized measure of discounted future net cash flows |
$ 8,843
|
$ 7,509
|
$ 16,352
|
|
Year Ended December 31, |
||
|
2012 |
2011 |
2010 |
|
(In millions) |
||
Beginning balance |
$ 17,844
|
$ 16,352
|
$ 11,403
|
Net changes in prices and production costs |
(9,889) | 1,875 | 7,423 |
Oil, gas and NGL sales, net of production costs |
(4,388) | (5,811) | (4,998) |
Changes in estimated future development costs |
(1,094) | (440) | (292) |
Extensions and discoveries, net of future development costs |
4,669 | 3,714 | 3,048 |
Purchase of reserves |
18 | 57 | 23 |
Sales of reserves in place |
(25) | (2) | (815) |
Revisions of quantity estimates |
162 | (228) | 579 |
Previously estimated development costs incurred during the period |
1,321 | 1,302 | 1,559 |
Accretion of discount |
1,420 | 2,248 | 1,487 |
Other, primarily changes in timing and foreign exchange rates |
113 | (294) | (402) |
Net change in income taxes |
3,070 | (929) | (2,663) |
Ending balance |
$ 13,221
|
$ 17,844
|
$ 16,352
|
|
Year Ended December 31, 2012 |
||
|
U.S. |
Canada |
Total |
Pre-tax future net revenue (1) |
(In millions) |
||
Proved developed reserves |
$ 19,982
|
$ 2,717
|
$ 22,699
|
Proved undeveloped reserves |
4,494 | 8,031 | 12,525 |
Total proved reserves |
$ 24,476
|
$ 10,748
|
$ 35,224
|
Pre-tax 10% present value (1) |
|
|
|
Proved developed reserves |
$ 10,764
|
$ 2,484
|
$ 13,248
|
Proved undeveloped reserves |
1,143 | 2,823 | 3,966 |
Total proved reserves |
$ 11,907
|
$ 5,307
|
$ 17,214
|
____________________________
(1) Estimated pre-tax future net revenue represents estimated future revenue to be generated from the production of proved reserves, net of estimated production and development costs and site restoration and abandonment charges. The amounts shown do not give effect to depreciation, depletion and amortization, asset impairments or non-property related expenses such as debt service and income tax expense.
|
|
|
|
|
|
|
Oil (MMBbls) |
||||
|
U.S. Onshore |
U.S. Offshore |
Total |
Canada |
Total |
Proved developed and undeveloped reserves: |
|
|
|
|
|
December 31, 2009 |
139 | 33 | 172 | 111 | 283 |
Revisions due to prices |
4 | 1 | 5 | (3) | 2 |
Revisions other than price |
2 | 2 | 4 | (3) | 1 |
Extensions and discoveries |
19 | 1 | 20 | 4 | 24 |
Production |
(14) | (2) | (16) | (16) | (32) |
Sale of reserves |
(2) | (35) | (37) |
— |
(37) |
December 31, 2010 |
148 |
— |
148 | 93 | 241 |
Revisions due to prices |
2 |
— |
2 | 1 | 3 |
Revisions other than price |
(1) |
— |
(1) | (5) | (6) |
Extensions and discoveries |
36 |
— |
36 | 6 | 42 |
Production |
(17) |
— |
(17) | (15) | (32) |
December 31, 2011 |
168 |
— |
168 | 80 | 248 |
Revisions due to prices |
(1) |
— |
(1) | (5) | (6) |
Revisions other than price |
(6) |
— |
(6) | (2) | (8) |
Extensions and discoveries |
65 |
— |
65 | 7 | 72 |
Production |
(21) |
— |
(21) | (15) | (36) |
December 31, 2012 |
205 |
— |
205 | 65 | 270 |
Proved developed reserves as of: |
|
|
|
|
|
December 31, 2009 |
119 | 21 | 140 | 97 | 237 |
December 31, 2010 |
131 |
— |
131 | 82 | 213 |
December 31, 2011 |
146 |
— |
146 | 73 | 219 |
December 31, 2012 |
166 |
— |
166 | 62 | 228 |
Proved developed-producing reserves as of: |
|
|
|
|
|
December 31, 2009 |
112 | 12 | 124 | 85 | 209 |
December 31, 2010 |
123 |
— |
123 | 72 | 195 |
December 31, 2011 |
139 |
— |
139 | 65 | 204 |
December 31, 2012 |
155 |
— |
155 | 56 | 211 |
Proved undeveloped reserves as of: |
|
|
|
|
|
December 31, 2009 |
20 | 12 | 32 | 14 | 46 |
December 31, 2010 |
17 |
— |
17 | 11 | 28 |
December 31, 2011 |
22 |
— |
22 | 7 | 29 |
December 31, 2012 |
39 |
— |
39 | 3 | 42 |
|
|
|
|
|
|
|
Bitumen (MMBbls) |
||||
|
U.S. Onshore |
U.S. Offshore |
Total |
Canada |
Total |
Proved developed and undeveloped reserves: |
|
|
|
|
|
December 31, 2009 |
— |
— |
— |
403 | 403 |
Revisions due to prices |
— |
— |
— |
(21) | (21) |
Revisions other than price |
— |
— |
— |
12 | 12 |
Extensions and discoveries |
— |
— |
— |
55 | 55 |
Production |
— |
— |
— |
(9) | (9) |
December 31, 2010 |
— |
— |
— |
440 | 440 |
Revisions due to prices |
— |
— |
— |
(16) | (16) |
Revisions other than price |
— |
— |
— |
16 | 16 |
Extensions and discoveries |
— |
— |
— |
30 | 30 |
Production |
— |
— |
— |
(13) | (13) |
December 31, 2011 |
— |
— |
— |
457 | 457 |
Revisions due to prices |
— |
— |
— |
14 | 14 |
Revisions other than price |
— |
— |
— |
7 | 7 |
Extensions and discoveries |
— |
— |
— |
67 | 67 |
Production |
— |
— |
— |
(17) | (17) |
December 31, 2012 |
— |
— |
— |
528 | 528 |
Proved developed reserves as of: |
|
|
|
|
|
December 31, 2009 |
— |
— |
— |
52 | 52 |
December 31, 2010 |
— |
— |
— |
44 | 44 |
December 31, 2011 |
— |
— |
— |
90 | 90 |
December 31, 2012 |
— |
— |
— |
99 | 99 |
Proved developed-producing reserves as of: |
|
|
|
|
|
December 31, 2009 |
— |
— |
— |
52 | 52 |
December 31, 2010 |
— |
— |
— |
44 | 44 |
December 31, 2011 |
— |
— |
— |
90 | 90 |
December 31, 2012 |
— |
— |
— |
99 | 99 |
Proved undeveloped reserves as of: |
|
|
|
|
|
December 31, 2009 |
— |
— |
— |
351 | 351 |
December 31, 2010 |
— |
— |
— |
396 | 396 |
December 31, 2011 |
— |
— |
— |
367 | 367 |
December 31, 2012 |
— |
— |
— |
429 | 429 |
|
|
|
|
|
|
|
Gas (Bcf) |
||||
|
U.S. Onshore |
U.S. Offshore |
Total |
Canada |
Total |
Proved developed and undeveloped reserves: |
|
|
|
|
|
December 31, 2009 |
8,127 | 342 | 8,469 | 1,288 | 9,757 |
Revisions due to prices |
449 | 2 | 451 | 21 | 472 |
Revisions other than price |
105 | (26) | 79 | (17) | 62 |
Extensions and discoveries |
1,088 | 7 | 1,095 | 131 | 1,226 |
Purchase of reserves |
12 |
— |
12 | 9 | 21 |
Production |
(699) | (17) | (716) | (214) | (930) |
Sale of reserves |
(17) | (308) | (325) |
— |
(325) |
December 31, 2010 |
9,065 |
— |
9,065 | 1,218 | 10,283 |
Revisions due to prices |
(1) |
— |
(1) | (60) | (61) |
Revisions other than price |
(243) |
— |
(243) | (38) | (281) |
Extensions and discoveries |
1,410 |
— |
1,410 | 58 | 1,468 |
Purchase of reserves |
16 |
— |
16 | 20 | 36 |
Production |
(740) |
— |
(740) | (213) | (953) |
Sale of reserves |
— |
— |
— |
(6) | (6) |
December 31, 2011 |
9,507 |
— |
9,507 | 979 | 10,486 |
Revisions due to prices |
(831) |
— |
(831) | (99) | (930) |
Revisions other than price |
(287) |
— |
(287) | (33) | (320) |
Extensions and discoveries |
1,124 |
— |
1,124 | 34 | 1,158 |
Purchase of reserves |
2 |
— |
2 |
— |
2 |
Production |
(752) |
— |
(752) | (186) | (938) |
Sale of reserves |
(1) |
— |
(1) | (11) | (12) |
December 31, 2012 |
8,762 |
— |
8,762 | 684 | 9,446 |
Proved developed reserves as of: |
|
|
|
|
|
December 31, 2009 |
6,447 | 185 | 6,632 | 1,213 | 7,845 |
December 31, 2010 |
7,280 |
— |
7,280 | 1,144 | 8,424 |
December 31, 2011 |
7,957 |
— |
7,957 | 951 | 8,908 |
December 31, 2012 |
7,391 |
— |
7,391 | 679 | 8,070 |
Proved developed-producing reserves as of: |
|
|
|
|
|
December 31, 2009 |
5,860 | 137 | 5,997 | 1,075 | 7,072 |
December 31, 2010 |
6,702 |
— |
6,702 | 1,031 | 7,733 |
December 31, 2011 |
7,409 |
— |
7,409 | 862 | 8,271 |
December 31, 2012 |
7,091 |
— |
7,091 | 624 | 7,715 |
Proved undeveloped reserves as of: |
|
|
|
|
|
December 31, 2009 |
1,680 | 157 | 1,837 | 75 | 1,912 |
December 31, 2010 |
1,785 |
— |
1,785 | 74 | 1,859 |
December 31, 2011 |
1,550 |
— |
1,550 | 28 | 1,578 |
December 31, 2012 |
1,371 |
— |
1,371 | 5 | 1,376 |
|
|
|
|
|
|
|
Natural Gas Liquids (MMBbls) |
||||
|
U.S. Onshore |
U.S. Offshore |
Total |
Canada |
Total |
Proved developed and undeveloped reserves: |
|
|
|
|
|
December 31, 2009 |
385 | 2 | 387 | 34 | 421 |
Revisions due to prices |
14 |
— |
14 | (1) | 13 |
Revisions other than price |
13 | 3 | 16 | (1) | 15 |
Extensions and discoveries |
68 |
— |
68 | 2 | 70 |
Production |
(28) |
— |
(28) | (4) | (32) |
Sale of reserves |
(3) | (5) | (8) |
— |
(8) |
December 31, 2010 |
449 |
— |
449 | 30 | 479 |
Revisions due to prices |
4 |
— |
4 | (1) | 3 |
Revisions other than price |
1 |
— |
1 |
— |
1 |
Extensions and discoveries |
102 |
— |
102 | 2 | 104 |
Purchase of reserves |
2 |
— |
2 |
— |
2 |
Production |
(33) |
— |
(33) | (4) | (37) |
December 31, 2011 |
525 |
— |
525 | 27 | 552 |
Revisions due to prices |
(19) |
— |
(19) | (5) | (24) |
Revisions other than price |
(13) |
— |
(13) |
— |
(13) |
Extensions and discoveries |
114 |
— |
114 | 2 | 116 |
Production |
(36) |
— |
(36) | (4) | (40) |
December 31, 2012 |
571 |
— |
571 | 20 | 591 |
Proved developed reserves as of: |
|
|
|
|
|
December 31, 2009 |
293 | 1 | 294 | 32 | 326 |
December 31, 2010 |
353 |
— |
353 | 28 | 381 |
December 31, 2011 |
402 |
— |
402 | 26 | 428 |
December 31, 2012 |
431 |
— |
431 | 20 | 451 |
Proved developed-producing reserves as of: |
|
|
|
|
|
December 31, 2009 |
265 | 1 | 266 | 28 | 294 |
December 31, 2010 |
318 |
— |
318 | 26 | 344 |
December 31, 2011 |
372 |
— |
372 | 24 | 396 |
December 31, 2012 |
406 |
— |
406 | 19 | 425 |
Proved undeveloped reserves as of: |
|
|
|
|
|
December 31, 2009 |
92 | 1 | 93 | 2 | 95 |
December 31, 2010 |
96 |
— |
96 | 2 | 98 |
December 31, 2011 |
123 |
— |
123 | 1 | 124 |
December 31, 2012 |
140 |
— |
140 |
— |
140 |
|
Total (MMBoe) (1) |
||||
|
U.S. Onshore |
U.S. Offshore |
Total |
Canada |
Total |
Proved developed and undeveloped reserves: |
|
|
|
|
|
December 31, 2009 |
1,878 | 92 | 1,970 | 763 | 2,733 |
Revisions due to prices |
92 | 1 | 93 | (21) | 72 |
Revisions other than price |
32 | 1 | 33 | 5 | 38 |
Extensions and discoveries |
269 | 2 | 271 | 83 | 354 |
Purchase of reserves |
2 |
— |
2 | 2 | 4 |
Production |
(158) | (5) | (163) | (65) | (228) |
Sale of reserves |
(8) | (91) | (99) | (1) | (100) |
December 31, 2010 |
2,107 |
— |
2,107 | 766 | 2,873 |
Revisions due to prices |
6 |
— |
6 | (27) | (21) |
Revisions other than price |
(41) |
— |
(41) | 6 | (35) |
Extensions and discoveries |
374 |
— |
374 | 47 | 421 |
Purchase of reserves |
5 |
— |
5 | 3 | 8 |
Production |
(173) |
— |
(173) | (67) | (240) |
Sale of reserves |
— |
— |
— |
(1) | (1) |
December 31, 2011 |
2,278 |
— |
2,278 | 727 | 3,005 |
Revisions due to price |
(159) |
— |
(159) | (12) | (171) |
Revisions other than price |
(67) |
— |
(67) | (1) | (68) |
Extensions and discoveries |
367 |
— |
367 | 82 | 449 |
Production |
(183) |
— |
(183) | (67) | (250) |
Sale of reserves |
— |
— |
— |
(2) | (2) |
December 31, 2012 |
2,236 |
— |
2,236 | 727 | 2,963 |
Proved developed reserves as of: |
|
|
|
|
|
December 31, 2009 |
1,486 | 53 | 1,539 | 383 | 1,922 |
December 31, 2010 |
1,696 |
— |
1,696 | 346 | 2,042 |
December 31, 2011 |
1,875 |
— |
1,875 | 348 | 2,223 |
December 31, 2012 |
1,829 |
— |
1,829 | 294 | 2,123 |
Proved developed-producing reserves as of: |
|
|
|
|
|
December 31, 2009 |
1,354 | 35 | 1,389 | 344 | 1,733 |
December 31, 2010 |
1,557 |
— |
1,557 | 314 | 1,871 |
December 31, 2011 |
1,746 |
— |
1,746 | 323 | 2,069 |
December 31, 2012 |
1,743 |
— |
1,743 | 278 | 2,021 |
Proved undeveloped reserves as of: |
|
|
|
|
|
December 31, 2009 |
392 | 39 | 431 | 380 | 811 |
December 31, 2010 |
411 |
— |
411 | 420 | 831 |
December 31, 2011 |
403 |
— |
403 | 379 | 782 |
December 31, 2012 |
407 |
— |
407 | 433 | 840 |
____________________________
(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. Bitumen and natural gas liquids reserves are converted to Boe on a one-to-one basis with oil.
|
|
2012 |
||||
|
First Quarter |
Second Quarter |
Third Quarter |
Fourth Quarter |
Full |
|
(In millions, except per share amounts) |
||||
Revenues |
$ 2,497
|
$ 2,559
|
$ 1,865
|
$ 2,581
|
$ 9,502
|
|
|
|
|
|
|
Earnings (loss) from continuing operations before income taxes |
$ 611
|
$ 734
|
$ (1,161)
|
$ (501)
|
$ (317)
|
|
|
|
|
|
|
Earnings (loss) from continuing operations |
$ 414
|
$ 477
|
$ (719)
|
$ (357)
|
$ (185)
|
Loss from discontinued operations |
(21) |
— |
— |
— |
(21) |
Net earnings (loss) |
$ 393
|
$ 477
|
$ (719)
|
$ (357)
|
$ (206)
|
|
|
|
|
|
|
Basic net earnings (loss) per common share: |
|
|
|
|
|
Earnings (loss) from continuing operations |
$ 1.03
|
$ 1.18
|
$ (1.80)
|
$ (0.89)
|
$ (0.47)
|
Earnings (loss) from discontinued operations |
(0.06) |
— |
— |
— |
(0.05) |
Net earnings (loss) |
$ 0.97
|
$ 1.18
|
$ (1.80)
|
$ (0.89)
|
$ (0.52)
|
|
|
|
|
|
|
Diluted net earnings (loss) per common share: |
|
|
|
|
|
Earnings (loss) from continuing operations |
$ 1.03
|
$ 1.18
|
$ (1.80)
|
$ (0.89)
|
$ (0.47)
|
Earnings (loss) from discontinued operations |
(0.06) |
— |
— |
— |
(0.05) |
Net earnings (loss) |
$ 0.97
|
$ 1.18
|
$ (1.80)
|
$ (0.89)
|
$ (0.52)
|
|
|
|
|
|
|
|
2011 |
||||
|
First Quarter |
Second Quarter |
Third Quarter |
Fourth Quarter |
Full |
|
(In millions, except per share amounts) |
||||
Revenues |
$ 2,147
|
$ 3,220
|
$ 3,502
|
$ 2,585
|
$ 11,454
|
|
|
|
|
|
|
Earnings from continuing operations before income taxes |
$ 580
|
$ 1,378
|
$ 1,538
|
$ 794
|
$ 4,290
|
|
|
|
|
|
|
Earnings from continuing operations |
$ 389
|
$ 184
|
$ 1,040
|
$ 521
|
$ 2,134
|
Earnings (loss) from discontinued operations |
27 | 2,559 | (2) | (14) | 2,570 |
Net earnings |
$ 416
|
$ 2,743
|
$ 1,038
|
$ 507
|
$ 4,704
|
|
|
|
|
|
|
Basic net earnings per common share: |
|
|
|
|
|
Earnings from continuing operations |
$ 0.91
|
$ 0.44
|
$ 2.51
|
$ 1.29
|
$ 5.12
|
Earnings (loss) from discontinued operations |
0.06 | 6.06 |
— |
(0.04) | 6.17 |
Net earnings |
$ 0.97
|
$ 6.50
|
$ 2.51
|
$ 1.25
|
$ 11.29
|
|
|
|
|
|
|
Diluted net earnings per common share: |
|
|
|
|
|
Earnings from continuing operations |
$ 0.91
|
$ 0.43
|
$ 2.50
|
$ 1.29
|
$ 5.10
|
Earnings (loss) from discontinued operations |
0.06 | 6.05 |
— |
(0.04) | 6.15 |
Net earnings |
$ 0.97
|
$ 6.48
|
$ 2.50
|
$ 1.25
|
$ 11.25
|
|
|
|
|
|
|
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|
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|
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