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1.Summary of Significant Accounting Policies
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 through its ownership in EnLink and the General Partner.
Accounting policies used by Devon and its subsidiaries conform to accounting principles generally accepted in the U.S. and reflect industry practices. The more significant of such policies are discussed below.
Principles of Consolidation
The accompanying consolidated financial statements include the accounts of Devon and entities in which it holds a controlling interest. All intercompany transactions have been eliminated. Undivided interests in oil and natural gas exploration and production joint ventures are consolidated on a proportionate basis. Investments in non-controlled entities, over which Devon has the ability to exercise significant influence over operating and financial policies, are accounted for using the equity method. In applying the equity method of accounting, the investments are initially recognized at cost and subsequently adjusted for Devon’s proportionate share of earnings, losses and distributions. Investments accounted for using the equity method and cost method are reported as a component of other long-term assets.
As discussed more fully in Note 2, Devon completed a business combination in 2014 whereby Devon controls both EnLink and the General Partner. Devon controls both the General Partner’s and EnLink’s operations; therefore, the General Partner’s and EnLink’s accounts are included in Devon’s accompanying consolidated financial statements subsequent to the completion of the transaction. The portions of the General Partner’s and EnLink’s net earnings and stockholders’ equity not attributable to Devon’s controlling interest are shown separately as noncontrolling interests in the accompanying consolidated comprehensive statements of earnings and consolidated balance sheets.
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, midstream assets and product and equipment inventories;
• derivative financial instruments;
• the fair value of reporting units and related assessment of goodwill for impairment;
• the fair value of intangible assets other than goodwill;
• income taxes;
• asset retirement obligations;
• obligations related to employee pension and postretirement benefits;
• legal and environmental risks and exposures; and
• general credit risk associated with receivables and other assets.
Revenue Recognition
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 typically 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 consolidated comprehensive statements of earnings.
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 2015, 2014 and 2013, no purchaser accounted for more than 10% of Devon’s operating revenues.
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, interest rate risk and foreign exchange risk. Devon does not intend to issue or hold 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. Additionally, Devon and EnLink periodically enter into derivative financial instruments with respect to a portion of their oil, gas and NGL marketing activities. These instruments are used to manage the inherent uncertainty of future revenues resulting from 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 and foreign exchange forward contracts to manage its exposure to fluctuations in the U.S. and Canadian dollar 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, 2015, 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. Cash settlements that Devon is entitled to are accrued for in other current assets in the accompanying consolidated balance sheets. As of December 31, 2015, Devon accrued $236 million that it received in January 2016 related to cash settlements.
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. As of December 31, 2015 and December 31, 2014, Devon held $75 million and $524 million, respectively, 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 consolidated balance sheets.
General and Administrative Expenses
G&A is 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
Independent of EnLink, Devon grants share-based awards to independent members of its Board of Directors and selected employees. EnLink and the General Partner also grant share-based awards to independent 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 G&A in the accompanying consolidated comprehensive statements of earnings over the applicable requisite service periods. As a result of Devon’s restructuring activity discussed in Note 6, certain share-based awards were accelerated and recognized as a component of restructuring costs in the accompanying consolidated 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 canceled 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 basis. 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.
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 the deferred tax assets is determined to be unlikely, a valuation allowance is provided to reduce the recorded tax benefits from such assets. Devon periodically weighs the positive and negative evidence to determine if it is more likely than not that some or all of the deferred tax assets will be realized. Forming a conclusion that a valuation allowance is not required is difficult when there is negative evidence, such as cumulative losses in recent years. See Note 7 for further discussion.
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 indefinitely 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 Share Attributable to Devon
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, as well as performance-based restricted stock awards that have met the requisite performance targets. 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.
Accounts Receivable
Devon’s accounts receivable balance primarily consists of oil and gas sales receivables, marketing and midstream revenue receivables and joint interest receivables for which Devon does not require collateral security. Devon has established an allowance for bad debts equal to the estimable portions of accounts receivable for which failure to collect is considered probable. When a portion of the receivable is deemed uncollectible, the write-off is made against the allowance.
Investments
Devon periodically invests excess cash in U.S. and Canadian treasury securities and other marketable securities. 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.
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.
Capitalized costs are depleted by an equivalent unit-of-production method, converting gas to oil at the ratio of six Mcf of gas to one Bbl 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.
Sales or dispositions of oil and gas properties are generally accounted for as adjustments to capitalized costs with no gain or loss 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. As discussed more fully in Note 2, the 2014 divestitures of certain Canadian assets significantly altered such relationship, and Devon recognized a gain, which is included as a separate item in the accompanying consolidated comprehensive statements of earnings.
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% 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, 2015 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.
Costs for midstream assets that are in use are depreciated over the assets’ estimated useful lives, using either the unit-of-production or straight-line method. Depreciation and amortization of other property and equipment, including corporate 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 annually, or more frequently if events or changes in circumstances dictate that the carrying value of goodwill may not be recoverable. 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 2015, 2014 and 2013. No impairment of goodwill was required in 2013. However, write-downs were required in 2015 and 2014 based on the annual impairment test. EnLink’s Texas, Louisiana and Crude and Condensate reporting segment goodwill were deemed impaired in 2015, and Devon’s Canadian reporting unit goodwill was deemed impaired in 2014. See Note 12 for further discussion.
Intangible Assets
Unamortized capitalized intangible assets, consisting of EnLink customer relationships, are presented in other long-term assets in the accompanying consolidated balance sheets. These assets are amortized on a straight-line basis over the expected periods of benefits, which range from 10-20 years. During 2015, EnLink’s customer relationships were also evaluated for impairment, and a portion of these intangibles was considered impaired. See Note 12 for further discussion.
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 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. |
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.
Noncontrolling Interests
Noncontrolling interests represent third-party ownership in the net assets of Devon’s consolidated subsidiaries and are presented as a component of equity. Changes in Devon’s ownership interests in subsidiaries that do not result in deconsolidation are recognized in equity.
Recently Issued Accounting Standards
The FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606). This ASU supersedes the revenue recognition requirements in Topic 605, Revenue Recognition and industry-specific guidance in Subtopic 932-605, Extractive Activities – Oil and Gas – Revenue Recognition. This ASU provides guidance concerning the recognition and measurement of revenue from contracts with customers. Its objective is to increase the usefulness of information in the financial statements regarding the nature, timing and uncertainty of revenues. The effective date for ASU 2014-09 was delayed through the issuance of ASU 2015-14, Revenue from Contracts with Customers – Deferral of the Effective Date, to annual and interim periods beginning in 2018 and is required to be adopted using either the retrospective or cumulative effect (modified retrospective) transition method, with early adoption permitted in 2017. Devon is evaluating the impact this ASU will have on its consolidated financial statements and related disclosures and does not plan on early adopting.
The FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis. This ASU provides additional guidance to reporting entities in evaluating whether certain legal entities, such as limited partnerships, limited liability corporations and securitization structures, should be consolidated. The ASU is considered to be an improvement on current accounting requirements as it reduces the number of existing consolidation models. This ASU is effective for Devon beginning January 1, 2016 and will be applied using the retrospective approach. This ASU will not have a material impact on Devon’s consolidated financial statements and related disclosures.
The FASB issued ASU 2015-03, Interest – Imputation of Interest (Topic 835): Simplifying the Presentation of Debt Issuance Costs and ASU 2015-15, Interest – Imputation of Interest (Topic 835): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements. These ASUs require debt issuance costs related to a recognized debt liability, except for those related to revolving credit facilities, to be presented on the balance sheet as a direct deduction from the carrying amount of that debt liability rather than as an asset. These ASUs are effective for Devon beginning January 1, 2016 and will be applied using the retrospective approach. These ASUs will not have a material impact on Devon’s consolidated financial statements and related disclosures.
The FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes. This ASU requires that all deferred tax assets and liabilities, along with any related valuation allowance, be classified as noncurrent on the balance sheet. This ASU is effective for annual and interim periods beginning in 2017 and can be applied prospectively or retrospectively, with early adoption permitted. This ASU will be early-adopted by Devon, effective January 1, 2016 and will be applied using the retrospective approach. This ASU will not have a material impact on Devon’s consolidated financial statements and related disclosures.
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2.Acquisitions and Divestitures
Formation of EnLink and the General Partner
On March 7, 2014, Devon and Crosstex completed a transaction to combine substantially all of Devon’s U.S. midstream assets with Crosstex’s assets to form a midstream business that consists of the General Partner and EnLink, which are both publicly traded.
In exchange for a controlling interest in both EnLink and the General Partner, Devon contributed its equity interest in a newly formed Devon subsidiary, EMH, and $100 million in cash. EMH owned midstream assets in the Barnett Shale in north Texas and the Cana- and Arkoma-Woodford Shales in Oklahoma, as well as an economic interest in Gulf Coast Fractionators in Mont Belvieu, Texas.
This business combination was accounted for using the acquisition method of accounting. Under the acquisition method of accounting, EMH was the accounting acquirer because its parent company, Devon, obtained control of EnLink and the General Partner as a result of the business combination. Consequently, EMH’s assets and liabilities retained their carrying values. Additionally, the Crosstex assets acquired and liabilities assumed by the General Partner and EnLink in the business combination, as well as the General Partner’s noncontrolling interest in EnLink, were recorded at their fair values which were measured as of the acquisition date, March 7, 2014. The excess of the purchase price over the estimated fair values of Crosstex’s net assets acquired was recorded as goodwill.
The following table summarizes the purchase price (millions, except unit price).
Crosstex Energy, Inc. outstanding common shares: |
||||
Held by public shareholders |
48.0 | |||
Restricted shares |
0.4 | |||
Total subject to conversion |
48.4 | |||
Exchange ratio |
1.0 |
x |
||
Converted shares |
48.4 | |||
Crosstex Energy, Inc. common share price (1) |
$ |
37.60 | ||
Crosstex Energy, Inc. consideration |
$ |
1,823 | ||
Fair value of noncontrolling interests in E2 (2) |
18 | |||
Total Crosstex Energy, Inc. consideration and fair value of noncontrolling interests |
$ |
1,841 | ||
Crosstex Energy, LP outstanding units: |
||||
Common units held by public unitholders |
75.1 | |||
Preferred units held by third party (3) |
17.1 | |||
Restricted units |
0.4 | |||
Total |
92.6 | |||
Crosstex Energy, LP common unit price (4) |
$ |
30.51 | ||
Crosstex Energy, LP common units value |
$ |
2,825 | ||
Crosstex Energy, LP outstanding unit options value |
4 | |||
Total fair value of noncontrolling interests in Crosstex Energy, LP (4) |
2,829 | |||
Total consideration and fair value of noncontrolling interests |
$ |
4,670 |
__________________________
(1) The final purchase price is based on the fair value of Crosstex Energy, Inc.’s common shares as of the closing date, March 7, 2014.
(2) Represents the value of noncontrolling interests related to the General Partner’s equity investment in E2.
(3) Crosstex Energy, LP converted the preferred units to common units in February 2014.
(4) The final purchase price is based on the fair value of Crosstex Energy, LP’s common units as of the closing date, March 7, 2014.
The allocation of the purchase price is as follows (millions):
Assets acquired: |
|||
Current assets |
$ |
437 | |
Property, plant and equipment, net |
2,438 | ||
Intangible assets |
569 | ||
Equity investment |
222 | ||
Goodwill (1) |
3,283 | ||
Other long-term assets |
1 | ||
Liabilities assumed: |
|||
Current liabilities |
(515) | ||
Long-term debt |
(1,454) | ||
Deferred income taxes |
(210) | ||
Other long-term liabilities |
(101) | ||
Total consideration and fair value of noncontrolling interests |
$ |
4,670 |
__________________________
(1) Goodwill is the excess of the consideration transferred over the net assets recognized and represents the future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Goodwill is not amortized and is not deductible for tax purposes.
EnLink Acquisitions
The following table presents a summary of EnLink’s acquisition activity for 2015.
Purchase Price |
Allocation |
|||||||||||||
Date |
Acquiree |
Cash |
EnLink Units |
PP&E |
Goodwill |
Intangibles |
Other |
|||||||
January 31 |
LPC |
$108 |
- |
$30 |
$30 |
$43 |
$5 |
|||||||
March 16 |
Coronado |
$240 |
$360 |
$302 |
$18 |
$281 |
$(1) |
|||||||
October 1 |
Matador |
$145 |
- |
$36 |
$9 |
$99 |
$1 |
On January 7, 2016, EnLink also acquired Anadarko Basin gathering and processing midstream assets from Tall Oak for approximately $1.5 billion, subject to certain adjustments. EnLink paid approximately $800 million of cash at the time of closing, primarily funded with the issuance of EnLink preferred units, with another $500 million of cash to be paid within 24 months. The remainder of the purchase price consisted of approximately 15.6 million General Partner common units.
EnLink Dropdowns
In February 2015, EnLink acquired a 25% equity interest in EMH from the General Partner in exchange for units valued at approximately $925 million. In May 2015, EnLink acquired the remaining 25% equity interest in EMH from the General Partner in exchange for units valued at approximately $900 million.
In April 2015, EnLink acquired VEX from Devon for approximately $176 million in cash and equity. EnLink also assumed approximately $35 million in certain future construction costs to expand the system to full capacity. Because Devon controls EnLink and the General Partner, the acquisition of VEX by EnLink from Devon was accounted for as a transfer of net assets between entities under common control.
Devon Acquisitions
On February 28, 2014, Devon completed its acquisition of interests in certain affiliates of GeoSouthern for approximately $6.0 billion. Devon funded the acquisition with cash on hand and debt financing. In connection with the GeoSouthern transaction, Devon acquired approximately 82,000 net acres (unaudited) located in DeWitt and Lavaca counties in south Texas. The transaction was accounted for using the acquisition method, which requires, among other things, that assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date.
The allocation of the purchase price is as follows (millions).
Cash and cash equivalents |
$ |
95 | |
Other current assets |
256 | ||
Proved properties |
5,026 | ||
Unproved properties |
1,007 | ||
Midstream assets |
86 | ||
Current liabilities |
(434) | ||
Long-term liabilities |
(6) | ||
Net assets acquired |
$ |
6,030 |
On December 17, 2015, Devon acquired approximately 253,000 net acres (unaudited) and assets in the Powder River Basin for approximately $499 million. Devon funded the acquisition with $300 million of cash and $199 million of equity. A preliminary allocation of the purchase price at December 31, 2015 was $386 million to unproved properties and $113 million to proved properties and gathering systems.
On January 7, 2016, Devon acquired approximately 80,000 net acres (unaudited) and assets in the STACK play for approximately $1.5 billion. Devon funded the acquisition with $850 million of cash and $659 million of equity.
Pro Forma Financial Information
The following unaudited pro forma financial information has been prepared assuming both the EnLink formation and the GeoSouthern acquisition occurred on January 1, 2013. The pro forma information is not intended to reflect the actual results of operations that would have occurred if the business combination and acquisition had been completed at the dates indicated. In addition, they do not project Devon’s results of operations for any future period.
Year Ended December 31, |
||||||
2014 |
2013 |
|||||
(Millions) |
||||||
Total operating revenues |
$ |
20,213 |
$ |
12,979 | ||
Net earnings |
$ |
1,716 |
$ |
35 | ||
Noncontrolling interests |
$ |
97 |
$ |
45 | ||
Net earnings (loss) attributable to Devon |
$ |
1,619 |
$ |
(10) | ||
Net earnings (loss) per common share attributable to Devon |
$ |
3.94 |
$ |
(0.02) |
Asset Divestitures
During 2014, Devon divested certain properties located throughout Canada and the U.S. as part of its asset portfolio transformation.
Canada
In the second quarter of 2014, Devon sold Canadian conventional assets for $2.8 billion ($3.125 billion Canadian dollars) and recognized a gain totaling $1.1 billion ($0.6 billion after-tax). This gain is included as a separate item in the accompanying consolidated comprehensive statements of earnings. Included in the gain calculation were asset retirement obligations of approximately $700 million assumed by the purchaser as well as the derecognition of approximately $700 million of goodwill allocated to the sold assets. In conjunction with the divestiture, Devon repatriated approximately $2.8 billion of proceeds to the U.S. in the second quarter of 2014, which was utilized to repay commercial paper and term loan balances. Between collecting the divestiture proceeds and repatriating funds to the U.S., Devon recognized an $84 million foreign currency exchange loss and a $29 million foreign exchange currency derivative loss. These losses are included in other nonoperating items in the accompanying consolidated comprehensive statements of earnings.
U.S.
In the third quarter of 2014, Devon sold certain U.S. assets for $2.2 billion. Additionally, approximately $200 million of asset retirement obligations were assumed by the purchaser. No gain or loss was recognized on the sale. These proceeds were used toward the early retirement of $1.9 billion in senior notes in November 2014 as discussed in Note 13.
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3.Derivative Financial Instruments
Commodity Derivatives
As of December 31, 2015, Devon had the following open oil derivative positions. The first table presents Devon’s oil derivatives that settle against the average of the prompt month NYMEX WTI futures price. The second table presents Devon’s oil derivatives that settle against the respective indices noted within the table.
Call Options Sold |
|||||
Period |
Volume (Bbls/d) |
Weighted Average Price ($/Bbl) |
|||
Q1-Q4 2016 |
18,500 |
$ |
73.18 |
Oil Basis Swaps |
|||||||
Period |
Index |
Volume (Bbls/d) |
Weighted Average Differential to WTI ($/Bbl) |
||||
Q1-Q4 2016 |
Western Canadian Select |
5,249 |
$ |
(13.67) | |||
Q1-Q4 2016 |
West Texas Sour |
5,000 |
$ |
(0.53) | |||
Q1-Q4 2016 |
Midland Sweet |
13,000 |
$ |
0.25 |
As of December 31, 2015, Devon had the following open natural gas derivative positions. The first table presents Devon’s natural gas derivatives that settle against the Inside FERC first of the month Henry Hub index. The second table presents Devon’s natural gas derivatives that settle against the respective indices noted within the table.
Price Swaps |
Call Options Sold |
|||||||||
Period |
Volume (MMBtu/d) |
Weighted Average Price ($/MMBtu) |
Volume (MMBtu/d) |
Weighted Average Price ($/MMBtu) |
||||||
Q1-Q4 2016 |
54,650 |
$ |
3.17 |
400,000 |
$ |
4.30 |
Natural Gas Basis Swaps |
|||||||
Period |
Index |
Volume (MMBtu/d) |
Weighted Average Differential to Henry Hub ($/MMBtu) |
||||
Q1-Q4 2016 |
Panhandle Eastern Pipe Line |
175,000 |
$ |
(0.34) |
|||
Q1-Q4 2016 |
El Paso Natural Gas |
125,000 |
$ |
(0.12) |
|||
Q1-Q4 2016 |
Houston Ship Channel |
30,000 |
$ |
0.11 |
|||
Q1-Q4 2016 |
Transco Zone 4 |
70,000 |
$ |
0.01 |
|||
Q1-Q4 2017 |
Panhandle Eastern Pipe Line |
150,000 |
$ |
(0.34) |
|||
Q1-Q4 2017 |
El Paso Natural Gas |
50,000 |
$ |
(0.14) |
|||
Q1-Q4 2017 |
Houston Ship Channel |
35,000 |
$ |
0.06 |
|||
Q1-Q4 2017 |
Transco Zone 4 |
185,000 |
$ |
0.03 |
As of December 31, 2015, EnLink had the following open derivative positions associated with gas processing and fractionation. EnLink’s NGL positions settle by purity product against the average of the prompt month OPIS Mont Belvieu, Texas index. EnLink’s natural gas positions settle against the Henry Hub Gas Daily index.
Period |
Product |
Volume (Total) |
Weighted Average Price Paid |
Weighted Average Price Received |
|||||||
Q1 2016-Q4 2016 |
Ethane |
571 |
MBbls |
$ |
0.29/gal |
Index |
|||||
Q1 2016-Q4 2016 |
Propane |
812 |
MBbls |
Index |
$ |
0.81/gal |
|||||
Q1 2016-Q4 2016 |
Normal Butane |
113 |
MBbls |
Index |
$ |
0.61/gal |
|||||
Q1 2016-Q4 2016 |
Natural Gasoline |
61 |
MBbls |
Index |
$ |
1.02/gal |
|||||
Q1 2016-Q1 2017 |
Natural Gas |
13,829 |
MMBtu/d |
$ |
2.65/MMBtu |
Index |
Interest Rate Derivatives
As of December 31, 2015, Devon had the following open interest rate derivative positions:
Notional |
Rate Received |
Rate Paid |
Expiration |
||||
(Millions) |
|||||||
$ |
100 |
Three Month LIBOR |
0.92% |
December 2016 |
|||
$ |
100 |
1.76% |
Three Month LIBOR |
January 2019 |
|||
$ |
750 |
Three Month LIBOR |
2.98% |
December 2048 (1) |
____________________________
(1) Mandatory settlement in December 2018.
Foreign Currency Derivatives
As of December 31, 2015, Devon had the following open foreign currency derivative position:
Forward Contract |
|||||||||
Currency |
Contract Type |
CAD Notional |
Weighted Average Fixed Rate Received |
Expiration |
|||||
(Millions) |
(CAD-USD) |
||||||||
Canadian Dollar |
Sell |
$ |
3,560 |
0.723 |
March 2016 |
Financial Statement Presentation
The following table presents the net gains and losses by derivative financial instrument type followed by the corresponding individual consolidated comprehensive statements of earnings caption.
Year Ended December 31, |
|||||||||
2015 |
2014 |
2013 |
|||||||
Commodity derivatives: |
(Millions) |
||||||||
Oil, gas and NGL derivatives |
$ |
503 |
$ |
1,989 |
$ |
(191) | |||
Marketing and midstream revenues |
9 | 22 |
— |
||||||
Interest rate derivatives: |
|||||||||
Other nonoperating items |
(20) | (1) |
— |
||||||
Foreign currency derivatives: |
|||||||||
Other nonoperating items |
246 | 60 | 56 | ||||||
Net gains (losses) recognized |
$ |
738 |
$ |
2,070 |
$ |
(135) |
The following table presents the derivative fair values by derivative financial instrument type followed by the corresponding individual consolidated balance sheet caption.
December 31, 2015 |
December 31, 2014 |
||||||
(Millions) |
|||||||
Commodity derivative assets: |
|||||||
Derivatives, at fair value |
$ |
34 |
$ |
1,984 | |||
Other long-term assets |
1 | 11 | |||||
Interest rate derivative assets: |
|||||||
Derivatives, at fair value |
1 | 1 | |||||
Other long-term assets |
1 |
— |
|||||
Foreign currency derivative assets: |
|||||||
Derivatives, at fair value |
8 | 8 | |||||
Total derivative assets |
$ |
45 |
$ |
2,004 | |||
Commodity derivative liabilities: |
|||||||
Other current liabilities |
$ |
14 |
$ |
28 | |||
Other long-term liabilities |
4 | 28 | |||||
Interest rate derivative liabilities: |
|||||||
Other current liabilities |
— |
1 | |||||
Other long-term liabilities |
22 |
— |
|||||
Foreign currency derivative liabilities: |
|||||||
Other current liabilities |
8 |
— |
|||||
Total derivative liabilities |
$ |
48 |
$ |
57 |
|
5. Asset Impairments
The following table presents the asset impairments recognized in 2015, 2014 and 2013.
Year Ended December 31, |
||||||||||
2015 |
2014 |
2013 |
||||||||
(Millions) |
||||||||||
U.S. oil and gas assets |
$ |
17,992 |
$ |
— |
$ |
1,110 | ||||
Canada oil and gas assets |
1,257 |
— |
843 | |||||||
Canada goodwill |
— |
1,941 |
— |
|||||||
EnLink goodwill |
1,328 |
— |
— |
|||||||
EnLink other intangible assets |
223 |
— |
— |
|||||||
Other assets |
20 | 12 | 23 | |||||||
Total asset impairments |
$ |
20,820 |
$ |
1,953 |
$ |
1,976 |
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 from declines in the U.S. and Canada full cost ceilings. The lower ceiling values resulted primarily from significant decreases in the 12-month average trailing prices for oil, bitumen, natural gas and NGLs, which significantly reduced proved reserves values and, to a lesser degree, proved reserves. For further information, see Note 21.
Goodwill and Other Intangible Assets Impairments
In 2015, Devon recognized goodwill and other intangible asset impairments related to EnLink’s business. In 2014, Devon recognized a goodwill impairment related to its Canadian reporting unit. Additional information regarding these impairments is discussed in Note 12.
|
6. Restructuring Costs
Canadian Reduction in Work Force
In 2015, Devon recognized $24 million of employee related and other costs associated with the reduction in work force made subsequent to the completion of the Jackfish development projects and a decrease in planned capital investment resulting from the drop in commodity prices. Devon incurred employee severance, lease obligation and other costs related to the vacated office space as part of the cost reduction plan.
Canadian Divestitures
During 2014, Devon recognized $46 million of employee related and other costs associated with its divestiture of certain Canadian assets. Approximately $15 million of the employee related costs resulted from accelerated vesting of share-based grants, which are noncash charges.
Office Consolidation
Near the end of 2012, Devon consolidated its U.S. personnel into a single operations group centrally located at the company’s corporate headquarters in Oklahoma City. As a result, Devon closed its office in Houston, transferred operational responsibilities for assets in south Texas, east Texas and Louisiana to Oklahoma City and incurred $134 million of restructuring costs associated with the consolidation. The employee severance and retention costs included amounts related to cash severance costs and accelerated vesting of share-based grants. The lease obligations and other costs are associated with certain office space that is subject to non-cancellable operating lease agreements that Devon ceased using as part of the office consolidation.
Due to a lack of demand for vacated office space in which Devon’s remaining leases are located, in 2015, Devon recognized an additional $54 million expense as a result of its inability to fully sublease remaining office space.
Financial Statement Presentation
The following table summarizes restructuring costs presented in the accompanying consolidated comprehensive statements of earnings.
Year Ended December 31, |
||||||||
2015 |
2014 |
2013 |
||||||
(Millions) |
||||||||
Office consolidation and offshore divestiture: |
||||||||
Employee severance and retention |
$ |
- |
$ |
- |
$ |
13 | ||
Lease obligations and other |
54 |
- |
41 | |||||
Canada divestitures: |
||||||||
Employee severance and retention |
11 | 42 |
- |
|||||
Lease obligations and other |
13 | 4 |
- |
|||||
Restructuring costs |
$ |
78 |
$ |
46 |
$ |
54 |
The following table summarizes Devon’s restructuring liabilities.
Other |
Other |
||||||||
Current |
Long-term |
||||||||
Liabilities |
Liabilities |
Total |
|||||||
(Millions) |
|||||||||
Balance as of December 31, 2013 |
$ |
27 |
$ |
18 |
$ |
45 | |||
Changes due to office consolidation and offshore divestiture |
(18) | (11) | (29) | ||||||
Changes due to Canadian divestitures |
4 |
— |
4 | ||||||
Balance as of December 31, 2014 |
13 | 7 | 20 | ||||||
Changes due to office consolidation and offshore divestiture |
1 | 46 | 47 | ||||||
Changes due to Canadian divestitures |
(1) | 10 | 9 | ||||||
Balance as of December 31, 2015 |
$ |
13 |
$ |
63 |
$ |
76 |
|
7.Income Taxes
Income Tax Expense (Benefit)
The following table presents Devon’s income tax components.
Year Ended December 31, |
|||||||||
2015 |
2014 |
2013 |
|||||||
(Millions) |
|||||||||
Current income tax expense (benefit): |
|||||||||
U.S. federal |
$ |
(243) |
$ |
152 |
$ |
73 | |||
Various states |
(8) | 18 | (5) | ||||||
Canada and various provinces |
14 | 307 | 4 | ||||||
Total current tax expense (benefit) |
(237) | 477 | 72 | ||||||
Deferred income tax expense (benefit): |
|||||||||
U.S. federal |
(5,033) | 1,610 | 198 | ||||||
Various states |
(336) | 93 | 59 | ||||||
Canada and various provinces |
(459) | 188 | (160) | ||||||
Total deferred tax expense (benefit) |
(5,828) | 1,891 | 97 | ||||||
Total income tax expense (benefit) |
$ |
(6,065) |
$ |
2,368 |
$ |
169 |
Total income tax expense (benefit) differed from the amounts computed by applying the U.S. federal income tax rate to earnings before income taxes as a result of the following:
Year Ended December 31, |
|||||||||
2015 |
2014 |
2013 |
|||||||
Total income tax expense (benefit) (millions) |
$ |
(6,065) |
$ |
2,368 |
$ |
169 | |||
U.S. statutory income tax rate |
(35)% |
35% | 35% | ||||||
Non-deductible goodwill and intangible impairment |
2% | 23% | 0% | ||||||
Taxation on Canadian operations |
1% |
(4)% |
9% | ||||||
State income taxes |
(1)% |
2% | 23% | ||||||
Repatriations |
0% | 2% | 65% | ||||||
Deferred tax asset valuation allowance |
4% | 0% | 0% | ||||||
Other |
0% | 0% |
(19)% |
||||||
Effective income tax rate |
(29)% |
58% | 113% |
Devon estimates its annual effective income tax rate in recording its provision for income taxes in the various jurisdictions in which it operates. Statutory tax rate changes and other significant or unusual items are recognized as discrete items in the period in which they occur.
Devon and its subsidiaries are subject to U.S. federal income tax as well as income or capital taxes in various state and foreign jurisdictions. Devon’s tax reserves are related to tax years that may be subject to examination by the relevant taxing authority. Devon is under audit in the U.S. and various foreign jurisdictions as part of its normal course of business.
Devon assesses the realizability of its deferred tax assets. If Devon concludes that it is more likely than not that some portion or all of the deferred tax assets will not be realized, the asset is reduced by a valuation allowance. Numerous judgements and assumptions are inherent in the determination of future taxable income, including factors such as future operation conditions (particularly as related to prevailing oil and gas prices) and changing tax laws.
2015
In the third and fourth quarters of 2015, EnLink recorded goodwill and intangibles impairments of approximately $1.6 billion. These impairments are not deductible for purposes of calculating income tax and, therefore, have an impact on the effective tax rate.
During 2015, Devon recorded approximately $18 billion of oil and gas impairments related to its U.S. operations. These impairments resulted in deferred tax assets against which we recognized a $967 million valuation allowance that impacted the effective tax rate and is discussed in the next section.
2014
In the second and fourth quarters of 2014, goodwill was removed in conjunction with the Canadian conventional asset divestitures, and Devon recorded a goodwill impairment in the Canadian reporting unit, respectively. These transactions are not deductible for purposes of calculating income tax and therefore have an impact on the effective tax rate.
Additionally, during 2014, Devon repatriated to the U.S. $2.8 billion of cash relating to the Canadian asset divestiture. In conjunction with the repatriation, Devon recognized approximately $105 million of additional income tax expense for the full year. Prior to the repatriation, Devon had recognized a $143 million deferred income tax liability associated with the planned repatriation. When the repatriation was made, Devon retained a larger property basis in Canada than was previously estimated, resulting in the incremental tax. After the use of foreign tax credits, the current income tax on the repatriation was $67 million.
Furthermore, Devon completed its divestiture program of certain assets in the U.S. In conjunction with the divestiture closing and due to the availability of additional tax deductions, Devon recognized $294 million of current income tax expense. The current tax expense was entirely offset by the recognition of deferred tax benefits.
Devon also recorded a $46 million deferred tax liability in conjunction with the formation of EnLink in 2014.
2013
In the second and fourth quarters of 2013, Devon repatriated to the U.S. a total of $4.3 billion of its cash held outside of the U.S. In the fourth quarter of 2013, Devon announced plans to divest of its Canadian conventional assets. These events resulted in an incremental income tax expense of $97 million. The incremental expense included $180 million of current income tax expense offset by $83 million of deferred income tax benefit. The $83 million deferred tax benefit was comprised of $180 million of deferred tax benefits that offset the incremental current income tax expense and an additional $97 million of deferred income tax expense accrued in the fourth quarter for assumed repatriations.
Deferred Tax Assets and Liabilities
The following table presents the tax effects of temporary differences that gave rise to Devon’s deferred tax assets and liabilities.
December 31, |
||||||
2015 |
2014 |
|||||
Deferred tax assets: |
(Millions) |
|||||
Property and equipment |
$ |
490 |
$ |
- |
||
Asset retirement obligations |
485 | 458 | ||||
Accrued liabilities |
160 | 150 | ||||
Net operating loss carryforwards |
175 | 200 | ||||
Pension benefit obligations |
106 | 113 | ||||
Other |
162 | 180 | ||||
Total deferred tax assets before valuation allowance |
1,578 | 1,101 | ||||
Less: valuation allowance |
(967) |
- |
||||
Net deferred tax assets |
611 | 1,101 | ||||
Deferred tax liabilities: |
||||||
Property and equipment |
(1,187) | (6,940) | ||||
Fair value of financial instruments |
- |
(699) | ||||
Long-term debt |
(36) | (115) | ||||
Other |
(271) | (160) | ||||
Total deferred tax liabilities |
(1,494) | (7,914) | ||||
Net deferred tax liability |
$ |
(883) |
$ |
(6,813) |
At December 31, 2015, Devon has $175 million of deferred tax assets related to various net operating loss carryforwards available to offset future income taxes. The net operating loss carryforwards consist of $495 million of Canadian carryforwards that expire between 2030 and 2035, $275 million of U.S. state carryforwards that expire between 2018 and 2035 and $205 million of carryforwards related to EnLink’s operations that expire between 2028 and 2035. In the current environment, Devon expects the tax benefits from the Canadian and EnLink net operating loss carryforwards to be utilized in 2017 and beyond. Devon also has $6 million of deferred tax assets related to alternative minimum tax credits, which have no expiration date and will be available for use against tax on future taxable income.
At the end of 2015, Devon had deferred tax assets that largely resulted from the full cost impairments recognized during 2015. As a result of the recent cumulative financial losses, Devon recorded a $967 million, or 100%, valuation allowance against the U.S. deferred tax assets as of December 31, 2015. In the event Devon were to determine that it would be able to realize the deferred income tax assets in the future, Devon would adjust the valuation allowance, reducing the provision for income taxes in the period of such adjustment.
As of December 31, 2015, Devon’s unremitted foreign earnings from its other international operations totaled approximately $1.2 billion. All but $37 million of the $1.2 billion was deemed to be indefinitely reinvested into the development and growth of Devon’s 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.
For the remaining $37 million of unremitted earnings deemed not to be indefinitely reinvested, Devon has recognized a $10 million deferred tax liability associated with such unremitted earnings as of December 31, 2015.
Unrecognized Tax Benefits
The following table presents changes in Devon's unrecognized tax benefits.
December 31, |
||||||
2015 |
2014 |
|||||
(Millions) |
||||||
Balance at beginning of year |
$ |
241 |
$ |
243 | ||
Tax positions taken in prior periods |
(19) |
- |
||||
Tax positions taken in current year |
31 |
- |
||||
Accrual of interest related to tax positions taken |
(5) | 2 | ||||
Settlements |
(108) |
- |
||||
Foreign currency translation |
(9) | (4) | ||||
Balance at end of year |
$ |
131 |
$ |
241 |
Devon’s unrecognized tax benefit balance at December 31, 2015 and 2014 included $29 million and $34 million, respectively, of interest and penalties. If recognized, $131 million of Devon's unrecognized tax benefits as of December 31, 2015 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 |
2008-2015 |
|
Various U.S. states |
2008-2015 |
|
Canada Federal |
2003-2015 |
|
Various Canadian provinces |
2003-2015 |
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.
|
9.Other Comprehensive Earnings
Components of other comprehensive earnings consist of the following:
Year Ended December 31, |
|||||||||
2015 |
2014 |
2013 |
|||||||
(Millions) |
|||||||||
Foreign currency translation: |
|||||||||
Beginning accumulated foreign currency translation |
$ |
983 |
$ |
1,448 |
$ |
1,996 | |||
Change in cumulative translation adjustment |
(621) | (499) | (574) | ||||||
Income tax benefit |
62 | 34 | 26 | ||||||
Ending accumulated foreign currency translation |
424 | 983 | 1,448 | ||||||
Pension and postretirement benefit plans: |
|||||||||
Beginning accumulated pension and postretirement benefits |
(204) | (180) | (225) | ||||||
Net actuarial gain (loss) and prior service cost arising in current year |
(5) | (57) | 48 | ||||||
Recognition of net actuarial loss and prior service cost in earnings (1) |
21 | 20 | 24 | ||||||
Income tax benefit (expense) |
(6) | 13 | (27) | ||||||
Ending accumulated pension and postretirement benefits |
(194) | (204) | (180) | ||||||
Accumulated other comprehensive earnings, net of tax |
$ |
230 |
$ |
779 |
$ |
1,268 |
____________________________
|
10.Supplemental Information to Statements of Cash Flows
Year Ended December 31, |
|||||||||
2015 |
2014 |
2013 |
|||||||
(Millions) |
|||||||||
Net change in working capital accounts: |
|||||||||
Accounts receivable |
$ |
942 |
$ |
128 |
$ |
(288) | |||
Income taxes receivable |
384 | (467) | 29 | ||||||
Other current assets |
(57) | (222) | 20 | ||||||
Accounts payable |
(190) | (68) | 26 | ||||||
Revenues and royalties payable |
(526) | 133 | 35 | ||||||
Income taxes payable |
(275) | 30 |
- |
||||||
Other current liabilities |
(579) | 516 | (120) | ||||||
Net change in working capital |
$ |
(301) |
$ |
50 |
$ |
(298) | |||
Interest paid (net of capitalized interest) |
$ |
494 |
$ |
514 |
$ |
406 | |||
Income taxes paid (received) |
$ |
(279) |
$ |
899 |
$ |
13 |
On March 7, 2014, Devon completed a business combination to form EnLink. With the exception of a $100 million cash payment to noncontrolling interests, the business combination was a non-monetary transaction. EnLink’s noncash acquisition activity during 2015 included a portion of the Coronado transaction.
As discussed in Note 2, Devon’s acquisition of certain Powder River Basin assets included noncash common stock issuance totaling $199 million.
|
11. Accounts Receivable
Components of accounts receivable include the following:
December 31, 2015 |
December 31, 2014 |
|||||
(Millions) |
||||||
Oil, gas and NGL sales |
$ |
362 |
$ |
723 | ||
Joint interest billings |
211 | 475 | ||||
Marketing and midstream revenues |
520 | 706 | ||||
Other |
30 | 71 | ||||
Gross accounts receivable |
1,123 | 1,975 | ||||
Allowance for doubtful accounts |
(18) | (16) | ||||
Net accounts receivable |
$ |
1,105 |
$ |
1,959 |
|
12. Goodwill and Other Intangible Assets
Goodwill
The following table presents a summary of Devon's goodwill.
U.S. |
Canada |
EnLink |
Total |
|||||||||
(Millions) |
||||||||||||
Balance as of December 31, 2013 |
$ |
2,618 |
$ |
2,838 |
$ |
402 |
$ |
5,858 | ||||
Acquired during period |
- |
- |
3,283 | 3,283 | ||||||||
Asset divestitures |
- |
(706) |
- |
(706) | ||||||||
Impairment |
- |
(1,941) |
- |
(1,941) | ||||||||
Foreign currency translation adjustments |
- |
(191) |
- |
(191) | ||||||||
Balance as of December 31, 2014 |
$ |
2,618 |
$ |
- |
$ |
3,685 |
$ |
6,303 | ||||
Acquired during period |
- |
- |
57 | 57 | ||||||||
Impairment |
- |
- |
(1,328) | (1,328) | ||||||||
Balance as of December 31, 2015 |
$ |
2,618 |
$ |
- |
$ |
2,414 |
$ |
5,032 | ||||
The following table presents the General Partner’s and EnLink’s goodwill activity by reporting unit.
Texas |
Louisiana |
Oklahoma |
Crude and Condensate |
General Partner |
Total |
|||||||||||||
(Millions) |
||||||||||||||||||
Balance as of December 31, 2013 |
$ |
326 |
$ |
- |
$ |
76 |
$ |
- |
$ |
- |
$ |
402 | ||||||
Acquired during period |
842 | 787 | 114 | 113 | 1,427 | 3,283 | ||||||||||||
Balance as of December 31, 2014 |
$ |
1,168 |
$ |
787 |
$ |
190 |
$ |
113 |
$ |
1,427 |
$ |
3,685 | ||||||
Acquired during period |
28 |
- |
- |
29 |
- |
57 | ||||||||||||
Impairment |
(492) | (787) |
- |
(49) |
- |
(1,328) | ||||||||||||
Balance as of December 31, 2015 |
$ |
704 |
$ |
- |
$ |
190 |
$ |
93 |
$ |
1,427 |
$ |
2,414 |
Acquired During Period
Included in the assets Devon contributed to EMH was $402 million of goodwill. See Note 2 for discussion of acquired goodwill resulting from EnLink’s formation in 2014 and acquisitions in 2015.
Asset Divestitures
In conjunction with the Canadian conventional asset divestitures in 2014, Devon removed $706 million of goodwill, which was allocated to these assets.
Impairment
As further discussed in Note 1, Devon performs an annual impairment test of goodwill at October 31, or more frequently if events or changes in circumstances indicate that the carrying value of a reporting unit may not be recoverable. Sustained weakness in the overall energy sector driven by low commodity prices, together with a decline in EnLink’s unit price, caused a change in circumstances warranting an interim impairment test of EnLink’s reporting units. Furthermore, due to the continued impact of declining commodity prices and EnLink unit price, an update was performed as of December 31, 2015. As a result of these tests, noncash goodwill impairments were recorded related to EnLink’s Texas, Louisiana and Crude and Condensate reporting units in 2015.
In the fourth quarter of 2014, as a result of its annual impairment test of goodwill, Devon concluded the implied fair value of its Canadian goodwill was zero and wrote off the remaining goodwill. This conclusion was largely based on the significant decline in benchmark oil prices, particularly after OPEC’s decision not to reduce its production targets that was announced in late November 2014. Devon’s Canadian goodwill was originally recognized in 2001 as a result of a business combination consisting almost entirely of conventional gas assets that Devon no longer owns.
Other Intangible Assets
During 2015, EnLink’s customer relationships were also evaluated for impairment due to the factors in the aforementioned goodwill impairment analysis. Level 3 fair value measurements were utilized for the impairment analysis of definite-lived intangible assets, which included discounted cash flow estimates, consistent with those utilized in the goodwill impairment assessment. This assessment resulted in a $223 million noncash impairment related to EnLink’s Crude and Condensate customer relationships in 2015.
The following table presents other intangible assets reported in other long-term assets in the accompanying consolidated balance sheets.
December 31, 2015 |
December 31, 2014 |
||||
(Millions) |
|||||
Customer relationships |
$ |
745 |
$ |
569 | |
Accumulated amortization |
(55) | (36) | |||
Net intangibles |
$ |
690 |
$ |
533 |
The weighted-average amortization period for the customer relationships is 12.6 years. Amortization expense for intangibles was approximately $56 million and $36 million for the years ended December 31, 2015 and December 31, 2014, respectively. The remaining aggregate amortization expense is estimated to be approximately $46 million each of the next five years.
|
13.Debt and Related Expenses
A summary of debt is as follows:
December 31, 2015 |
December 31, 2014 |
||||
(Millions) |
|||||
Devon debt |
|||||
Commercial paper |
$ |
626 |
$ |
932 | |
Floating rate due December 15, 2015 |
- |
500 | |||
Floating rate due December 15, 2016 |
350 | 350 | |||
8.25% due July 1, 2018 |
125 | 125 | |||
2.25% due December 15, 2018 |
750 | 750 | |||
6.30% due January 15, 2019 |
700 | 700 | |||
4.00% due July 15, 2021 |
500 | 500 | |||
3.25% due May 15, 2022 |
1,000 | 1,000 | |||
5.85% due December 15, 2025 |
850 |
- |
|||
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 | 750 | |||
5.00% due June 15, 2045 |
750 |
- |
|||
Net discount on debentures and notes |
(28) | (18) | |||
Total Devon debt |
10,023 | 9,239 | |||
EnLink debt |
|||||
Credit facilities |
414 | 237 | |||
2.70% due April 1, 2019 |
400 | 400 | |||
7.125% due June 1, 2022 |
163 | 163 | |||
4.40% due April 1, 2024 |
550 | 550 | |||
4.15% due June 1, 2025 |
750 |
- |
|||
5.60% due April 1, 2044 |
350 | 350 | |||
5.05% due April 1, 2045 |
450 | 300 | |||
Net premium on debentures and notes |
13 | 23 | |||
Total EnLink debt |
3,090 | 2,023 | |||
Total debt |
13,113 | 11,262 | |||
Less amount classified as short-term debt (1) |
976 | 1,432 | |||
Total long-term debt |
$ |
12,137 |
$ |
9,830 |
__________________________
Debt maturities as of December 31, 2015, excluding premiums and discounts, are as follows (millions):
2016 |
$ |
976 |
2017 |
- |
|
2018 |
875 | |
2019 |
1,100 | |
2020 |
414 | |
Thereafter |
9,763 | |
Total |
$ |
13,128 |
Credit Lines
Devon has a $3.0 billion Senior Credit Facility. The maturity date for $30 million of the Senior Credit Facility is October 24, 2017. The maturity date for $164 million of the Senior Credit Facility is October 24, 2018. The maturity date for the remaining $2.8 billion is October 24, 2019. 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, 2015, 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%. The credit agreement contains definitions of total funded debt and total capitalization that include adjustments to the respective amounts reported in the accompanying consolidated 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, 2015, Devon was in compliance with this covenant with a debt-to-capitalization ratio of 23.7%.
Commercial Paper
Devon’s Senior Credit Facility supports its $3.0 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, 2015, Devon’s outstanding commercial paper borrowings had a weighted-average borrowing rate of 0.63%.
Issuance of Senior Notes
In June 2015, Devon issued $750 million of 5.0% senior notes due 2045 that are unsecured and unsubordinated obligations. Devon used the net proceeds to repay the floating rate senior notes that matured on December 15, 2015, as well as outstanding commercial paper balances.
In December 2015, in conjunction with the announcement of the Powder River Basin and STACK acquisitions, Devon issued $850 million of 5.85% senior notes due 2025 that are unsecured and unsubordinated obligations. Devon used the net proceeds to fund the cash portion of these acquisitions.
Retirement of Senior Notes
In November 2014, Devon redeemed $1.9 billion of senior notes prior to their scheduled maturity, primarily with proceeds received from its asset divestitures. The redemption includes the 2.4% $500 million senior notes due 2016, the 1.2% $650 million senior notes due 2016 and the 1.875% $750 million senior notes due 2017. The notes were redeemed for $1.9 billion, which included 100% of the principal amount and a make-whole premium of $40 million. On the date of redemption, these notes also had an unamortized discount of $2 million and unamortized debt issuance costs of $6 million. The make-whole premium, unamortized discounts and debt issuance costs are included in net financing costs on the accompanying 2014 consolidated comprehensive statement of earnings.
Other Debentures and Notes
Following are descriptions of the various other debentures and notes outstanding at December 31, 2015 and 2014, as listed in the table presented at the beginning of this note.
GeoSouthern Debt
In December 2013, in conjunction with the planned GeoSouthern acquisition, Devon issued $2.25 billion aggregate principal amount of fixed and floating rate senior notes. Devon repaid the floating rate senior notes due 2015 upon maturity and redeemed the 1.2% senior notes due December 15, 2016 in November 2014. As of December 31, 2015, the floating rate senior notes due 2016 and the 2.25% senior notes due December 15, 2018 were outstanding. The floating rate senior notes due 2016 bear interest at a rate equal to three-month LIBOR plus 0.54%, which will be reset quarterly.
Other Notes
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, credit facility borrowings and other long-term debt. The schedule below summarizes the key terms of these notes (millions).
Date Issued |
|||||||||||
May 2012 |
July 2011 |
January 2009 |
March 2002 |
||||||||
3.25% due May 15, 2022 |
$ |
1,000 |
$ |
- |
$ |
- |
$ |
- |
|||
4.75% due May 15, 2042 |
750 |
- |
- |
- |
|||||||
4.00% due July 15, 2021 |
- |
500 |
- |
- |
|||||||
5.60% due July 15, 2041 |
- |
1,250 |
- |
- |
|||||||
6.30% due January 15, 2019 |
- |
- |
700 |
- |
|||||||
7.95% due April 15, 2032 |
- |
- |
- |
1,000 | |||||||
Discount and issuance costs |
(28) | (24) | (8) | (14) | |||||||
Net proceeds |
$ |
1,722 |
$ |
1,726 |
$ |
692 |
$ |
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, 2015, 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.
Fair Value of Debt Assumed |
Effective Rate of Debt Assumed |
||||
Debt Assumed |
(Millions) |
||||
8.25% due July 2018 (principal of $125 million) |
$ |
147 | 5.5% | ||
7.50% due September 2027 (principal of $150 million) |
$ |
169 | 6.5% |
7.875% Debentures due September 30, 2031
In October 2001, Devon, through 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 Anderson Exploration acquisition.
EnLink Debt
All of EnLink’s and the General Partner’s debt is non-recourse to Devon.
The table below summarizes the fair value of EnLink’s debt as of March 7, 2014, the formation date of EnLink. The premiums are being amortized using the effective interest method.
March 7, 2014 Fair Value of Debt |
Effective |
|||
(Millions) |
||||
8.875% due February 2018 (principal of $725 million) (1) |
$ |
760 |
7.7% |
|
7.125% due June 2022 (principal of $197 million) |
226 |
5.3% |
||
Credit facilities |
468 | |||
Total long-term debt |
$ |
1,454 |
__________________________
(1) The 2018 senior notes were redeemed on April 18, 2014.
In February 2015, the commitments under EnLink’s $1.0 billion unsecured revolving credit facility were increased to $1.5 billion, and the maturity date was extended by a year to March 6, 2020. As of December 31, 2015, there were $11 million in outstanding letters of credit and $414 million outstanding borrowings, with a weighted-average borrowing rate of 1.7%, under the $1.5 billion credit facility. The General Partner has a $250 million revolving credit facility that will mature on March 7, 2019. As of December 31, 2015, the General Partner had no outstanding borrowings under the $250 million credit facility. EnLink and the General Partner were in compliance with all financial covenants in their respective credit facilities as of December 31, 2015.
In March 2014, EnLink issued $1.2 billion aggregate principal amount of unsecured senior notes, consisting of $400 million of its 2.70% senior notes due 2019, $450 million of its 4.40% senior notes due 2024 and $350 million of its 5.60% senior notes due 2044, at discounts of their face value. EnLink used the net proceeds to redeem the 2018 senior notes, reduce outstanding credit facility borrowings, for capital expenditures and for general operations.
In November 2014, EnLink issued $100 million of its 4.40% senior notes due 2024 and $300 million of its 5.05% senior notes due 2045, at a premium and discount, respectively, of their face value. The 2024 notes were offered as an additional issue of EnLink’s outstanding 4.40% senior notes due 2024, issued in March 2014. The 2024 notes issued in March 2014 and November 2014 are treated as a single class of debt securities and have identical terms, other than the issue date. EnLink used the net proceeds for capital expenditures and for general operations.
In May 2015, EnLink issued $900 million principal amount of unsecured senior notes, consisting of $750 million principal amount of its 4.15% senior notes due 2025 and an additional $150 million principal amount of its 5.05% senior notes due 2045. EnLink used the net proceeds to repay outstanding revolving credit facility borrowings, for capital expenditures and for general operations.
Net Financing Costs
The following schedule includes the components of net financing costs.
Year Ended December 31, |
||||||||
2015 |
2014 |
2013 |
||||||
(Millions) |
||||||||
Interest based on debt outstanding |
$ |
565 |
$ |
532 |
$ |
466 | ||
Early retirement of debt |
- |
48 |
- |
|||||
Capitalized interest |
(62) | (70) | (56) | |||||
Other fees and expenses |
20 | 26 | 27 | |||||
Interest expense |
523 | 536 | 437 | |||||
Interest income |
(6) | (10) | (20) | |||||
Net financing costs |
$ |
517 |
$ |
526 |
$ |
417 |
|
14.Asset Retirement Obligations
The following table presents the changes in asset retirement obligations.
Year Ended December 31, |
||||||
2015 |
2014 |
|||||
(Millions) |
||||||
Asset retirement obligations as of beginning of period |
$ |
1,399 |
$ |
2,228 | ||
Liabilities incurred |
63 | 97 | ||||
Liabilities settled and divested (1) |
(89) | (1,009) | ||||
Revision of estimated obligation |
62 | 70 | ||||
Accretion expense on discounted obligation |
75 | 89 | ||||
Foreign currency translation adjustment |
(96) | (76) | ||||
Asset retirement obligations as of end of period |
1,414 | 1,399 | ||||
Less current portion |
44 | 60 | ||||
Asset retirement obligations, long-term |
$ |
1,370 |
$ |
1,339 |
__________________________
(1) During 2014, Devon reduced its asset retirement obligation by $953 million for those obligations that were assumed by purchasers of Devon’s Canadian and U.S. divested oil and gas properties.
|
15.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 $22 million and $25 million at December 31, 2015 and 2014, respectively and is included in other long-term assets in the accompanying consolidated 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 qualifying U.S. retirees. 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, 2015 and 2014. Devon’s benefit obligations and plan assets are measured each year as of December 31. The projected benefit obligations for Devon’s qualified plans were fully funded as of December 31, 2015 and 2014.
Pension Benefits |
Postretirement Benefits |
|||||||||||
2015 |
2014 |
2015 |
2014 |
|||||||||
(Millions) |
||||||||||||
Change in benefit obligation: |
||||||||||||
Benefit obligation at beginning of year |
$ |
1,377 |
$ |
1,177 |
$ |
24 |
$ |
24 | ||||
Service cost |
33 | 30 | 1 | 1 | ||||||||
Interest cost |
52 | 55 | 1 | 1 | ||||||||
Actuarial loss (gain) |
(68) | 203 | (2) |
- |
||||||||
Plan amendments |
- |
- |
1 |
- |
||||||||
Plan settlements |
- |
(4) |
- |
- |
||||||||
Foreign exchange rate changes |
(6) | (3) |
- |
- |
||||||||
Participant contributions |
- |
- |
2 | 2 | ||||||||
Benefits paid |
(80) | (81) | (4) | (4) | ||||||||
Benefit obligation at end of year |
1,308 | 1,377 | 23 | 24 | ||||||||
Change in plan assets: |
||||||||||||
Fair value of plan assets at beginning of year |
1,149 | 1,006 |
- |
- |
||||||||
Actual return on plan assets |
(16) | 200 |
- |
- |
||||||||
Employer contributions |
11 | 29 | 2 | 2 | ||||||||
Participant contributions |
- |
- |
2 | 2 | ||||||||
Plan settlements |
- |
(4) |
- |
- |
||||||||
Benefits paid |
(80) | (81) | (4) | (4) | ||||||||
Foreign exchange rate changes |
(5) | (1) |
- |
- |
||||||||
Fair value of plan assets at end of year |
1,059 | 1,149 |
- |
- |
||||||||
Funded status at end of year |
$ |
(249) |
$ |
(228) |
$ |
(23) |
$ |
(24) | ||||
Amounts recognized in balance sheet: |
||||||||||||
Other long-term assets |
$ |
2 |
$ |
22 |
$ |
- |
$ |
- |
||||
Other current liabilities |
(12) | (10) | (3) | (3) | ||||||||
Other long-term liabilities |
(239) | (240) | (20) | (21) | ||||||||
Net amount |
$ |
(249) |
$ |
(228) |
$ |
(23) |
$ |
(24) | ||||
Amounts recognized in accumulated other comprehensive earnings: |
||||||||||||
Net actuarial loss (gain) |
$ |
302 |
$ |
317 |
$ |
(11) |
$ |
(11) | ||||
Prior service cost (credit) |
14 | 19 | (6) | (9) | ||||||||
Total |
$ |
316 |
$ |
336 |
$ |
(17) |
$ |
(20) |
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 $11 million and $10 million for 2015 and 2014, 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, 2015 and 2014, as presented in the following table.
December 31, |
||||||
2015 |
2014 |
|||||
(Millions) |
||||||
Projected benefit obligation |
$ |
244 |
$ |
250 | ||
Accumulated benefit obligation |
$ |
199 |
$ |
191 | ||
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 |
|||||||||||||||||
2015 |
2014 |
2013 |
2015 |
2014 |
2013 |
|||||||||||||
(Millions) |
||||||||||||||||||
Net periodic benefit cost: |
||||||||||||||||||
Service cost |
$ |
33 |
$ |
30 |
$ |
36 |
$ |
1 |
$ |
1 |
$ |
1 | ||||||
Interest cost |
52 | 55 | 51 | 1 | 1 | 1 | ||||||||||||
Expected return on plan assets |
(58) | (54) | (62) |
- |
- |
- |
||||||||||||
Curtailment and settlement expense |
- |
1 |
- |
- |
- |
- |
||||||||||||
Recognition of net actuarial loss (gain) (1) |
20 | 18 | 22 | (1) | (1) | (1) | ||||||||||||
Recognition of prior service cost (1) |
4 | 4 | 4 | (2) | (2) | (1) | ||||||||||||
Total net periodic benefit cost (2) |
51 | 54 | 51 | (1) | (1) |
- |
||||||||||||
Other comprehensive loss (earnings): |
||||||||||||||||||
Actuarial loss (gain) arising in current year |
5 | 57 | (39) | (1) |
- |
(3) | ||||||||||||
Prior service cost (credit) arising in current year |
- |
- |
2 | 1 |
- |
(8) | ||||||||||||
Recognition of net actuarial loss, including settlement |
||||||||||||||||||
expense, in net periodic benefit cost |
(20) | (19) | (22) | 1 | 1 | 1 | ||||||||||||
Recognition of prior service cost, including curtailment, |
||||||||||||||||||
in net periodic benefit cost |
(4) | (4) | (4) | 1 | 2 | 1 | ||||||||||||
Total other comprehensive loss (earnings) |
(19) | 34 | (63) | 2 | 3 | (9) | ||||||||||||
Total recognized |
$ |
32 |
$ |
88 |
$ |
(12) |
$ |
1 |
$ |
2 |
$ |
(9) |
__________________________
(1) These net periodic benefit costs were reclassified out of other comprehensive earnings in the current period.
(2) Net periodic benefit cost is a component of G&A on the accompanying consolidated comprehensive statements of earnings.
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 2016.
Pension Benefits |
Postretirement Benefits |
|||||
(Millions) |
||||||
Net actuarial loss (gain) |
$ |
22 |
$ |
(2) | ||
Prior service cost (credit) |
4 | (1) | ||||
Total |
$ |
26 |
$ |
(3) |
Assumptions
The following table presents the weighted-average actuarial assumptions used to determine obligations and periodic costs.
Pension Benefits |
Postretirement Benefits |
|||||||||||||||||
2015 |
2014 |
2013 |
2015 |
2014 |
2013 |
|||||||||||||
Assumptions to determine benefit obligations: |
||||||||||||||||||
Discount rate |
4.25% |
3.90% |
4.80% |
3.63% |
3.25% |
3.65% |
||||||||||||
Rate of compensation increase |
4.49% |
4.49% |
4.48% |
N/A |
N/A |
N/A |
||||||||||||
Assumptions to determine net periodic benefit cost: |
||||||||||||||||||
Discount rate |
3.90% |
4.80% |
3.85% |
3.25% |
3.65% |
3.30% |
||||||||||||
Rate of compensation increase |
4.49% |
4.49% |
4.48% |
N/A |
N/A |
N/A |
||||||||||||
Expected return on plan assets |
5.22% |
5.42% |
5.48% |
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.
At the end of 2015, Devon changed the approach used to measure service and interest costs for pension and other postretirement benefits. For 2015, Devon measured service and interest costs utilizing a single weighted-average discount rate derived from the yield curve used to measure the plan obligations. For 2016, Devon elected to measure service and interest costs by applying the specific spot rates along that yield curve to the plans’ liability cash flows. Devon believes the new approach provides a more precise measurement of service and interest costs by aligning the timing of the plans’ liability cash flows to the corresponding spot rates on the yield curve. This change does not affect the measurement of the plan obligations nor the funded status of the plans. The change in the service and interest costs going forward is not expected to be significant. This change has been accounted for as a change in accounting estimate.
Rate of compensation increase – For measurement of the 2015 benefit obligation for the pension plans, a 4.49% 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.
Mortality rate assumptions – In 2014, the Society of Actuaries issued updated versions of its mortality tables and mortality improvement scale, reflecting the increasing life expectancies in the U.S. While not required to strictly adhere to this data, Devon utilized actuary-produced mortality tables and an improvement scale derived from the updated tables and the actuary’s best estimate of mortality for the population of participants in Devon’s plans.
Other assumptions – For measurement of the 2015 benefit obligation for the other postretirement medical plans, a 7.6% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2016. The rate was assumed to decrease annually to an ultimate rate of 5% in the year 2029 and remain at that level thereafter. Assumed health care cost-trend rates affect the amounts reported for retiree health care costs. A one-percentage-point change in the assumed health care cost-trend rates would have changed the postretirement benefits obligation as of December 31, 2015 by less than $1 million and would change the 2015 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, |
||||||
2015 |
2014 |
|||||
Fixed income |
70% |
70% |
||||
Equity |
20% |
20% |
||||
Other |
10% |
10% |
The following tables present the fair values of Devon's pension assets by asset class.
December 31, 2015 |
|||||||||||||||
Fair Value Measurements Using: |
|||||||||||||||
Actual Allocation |
Total |
Level 1 Inputs |
Level 2 Inputs |
Level 3 Inputs |
|||||||||||
(Millions) |
|||||||||||||||
Fixed-income securities: |
|||||||||||||||
U.S. Treasury obligations |
17% |
$ |
179 |
$ |
88 |
$ |
91 |
$ |
- |
||||||
Corporate bonds |
48% | 507 | 371 | 136 |
- |
||||||||||
Other bonds |
3% | 35 | 35 |
- |
- |
||||||||||
Total fixed-income securities |
68% | 721 | 494 | 227 |
- |
||||||||||
Equity securities: |
|||||||||||||||
Global (large, mid, small cap) |
18% | 186 |
- |
186 |
- |
||||||||||
Other securities: |
|||||||||||||||
Hedge fund and alternative investments |
11% | 120 |
- |
- |
120 | ||||||||||
Short-term investments |
3% | 32 | 6 | 26 |
- |
||||||||||
Total other securities |
14% | 152 | 6 | 26 | 120 | ||||||||||
Total investments |
100% |
$ |
1,059 |
$ |
500 |
$ |
439 |
$ |
120 |
December 31, 2014 |
|||||||||||||||
Fair Value Measurements Using: |
|||||||||||||||
Actual Allocation |
Total |
Level 1 Inputs |
Level 2 Inputs |
Level 3 Inputs |
|||||||||||
(Millions) |
|||||||||||||||
Fixed-income securities: |
|||||||||||||||
U.S. Treasury obligations |
35% |
$ |
405 |
$ |
50 |
$ |
355 |
$ |
- |
||||||
Corporate bonds |
32% | 364 | 269 | 95 |
- |
||||||||||
Other bonds |
3% | 30 | 30 |
- |
- |
||||||||||
Total fixed-income securities |
70% | 799 | 349 | 450 |
- |
||||||||||
Equity securities: |
|||||||||||||||
Global (large, mid, small cap) |
17% | 197 |
- |
197 |
- |
||||||||||
Other securities: |
|||||||||||||||
Hedge fund and alternative investments |
10% | 112 |
- |
- |
112 | ||||||||||
Short-term investments |
3% | 41 | 15 | 26 |
- |
||||||||||
Total other securities |
13% | 153 | 15 | 26 | 112 | ||||||||||
Total investments |
100% |
$ |
1,149 |
$ |
364 |
$ |
673 |
$ |
112 |
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 cash and commingled, short-term investment funds. The short-term investment funds’ 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.
The following table presents a summary of the changes in Devon's Level 3 plan assets (millions).
December 31, 2013 |
$ |
112 | |
Disbursements |
(6) | ||
Investment returns |
6 | ||
December 31, 2014 |
112 | ||
Purchases |
5 | ||
Investment returns |
3 | ||
December 31, 2015 |
$ |
120 |
Expected Cash Flows
The following table presents expected cash flow information for Devon's pension and postretirement benefit plans.
Pension Benefits |
Postretirement Benefits |
|||||
(Millions) |
||||||
Devon's 2016 contributions |
$ |
12 |
$ |
3 | ||
Benefit payments: |
||||||
2016 |
$ |
73 |
$ |
3 | ||
2017 |
$ |
75 |
$ |
3 | ||
2018 |
$ |
77 |
$ |
3 | ||
2019 |
$ |
78 |
$ |
3 | ||
2020 |
$ |
83 |
$ |
2 | ||
2021 to 2025 |
$ |
446 |
$ |
7 |
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 2016, the $12 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
Independent of EnLink, Devon maintains 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. EnLink also maintains a 401(k) plan covering eligible employees. The following table presents expense related to these defined contribution plans.
Year Ended December 31, |
|||||||||
2015 |
2014 |
2013 |
|||||||
(Millions) |
|||||||||
401(k) and enhanced contribution plans |
$ |
63 |
$ |
49 |
$ |
41 |
|||
Canadian pension and savings plans |
16 |
20 |
26 |
||||||
Total |
$ |
79 |
$ |
69 |
$ |
67 |
|
16.Stockholders' Equity
The authorized capital stock of Devon consists of 1.0 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.
Common Stock Issued
In December 2015, Devon issued approximately 7 million shares of common stock as part of the Powder River Basin asset acquisition discussed in Note 2. Additionally, in January 2016, Devon issued approximately 23 million shares of common stock in conjunction with the STACK asset acquisition.
Dividends
Devon paid common stock dividends of $396 million, $386 million and $348 million in 2015, 2014 and 2013, respectively. The quarterly cash dividend was $0.20 per share in the first quarter of 2013. Devon increased the dividend rate to $0.22 per share in the second quarter of 2013 and to $0.24 per share in the second quarter of 2014.
Stock Option Proceeds
Devon received $4 million, $93 million and $3 million from stock option proceeds in 2015, 2014 and 2013, respectively.
|
17.Noncontrolling Interests
Acquisition of Noncontrolling Interests
In March 2014, EnLink was formed as a publicly traded consolidated subsidiary of Devon to provide midstream services to Devon and third parties. Devon obtained approximately 120.5 million units, or a 52% ownership interest, as a result of this transaction. Approximately 92.7 million units were issued to the public for a 41% ownership interest, with the remaining 7% ownership interest held by the General Partner.
Subsidiary Equity Transactions
Through its equity distribution agreements, EnLink has the ability to sell common units through an “at the market” equity offering program. During 2015 and 2014, EnLink issued and sold approximately 1.3 million and 14.8 million common units through its at the market program and general public offerings, generating net proceeds of $25 million and $410 million, respectively. Furthermore, in October 2015, EnLink issued approximately 2.8 million common units in a private placement transaction with the General Partner, generating approximately $50 million in proceeds.
In 2015, Devon conducted an underwritten secondary public offering of 26.2 million common units representing limited partner interests in EnLink, raising net proceeds of $654 million.
As a result of these transactions, the Coronado acquisition and dropdown transactions discussed in Note 2, the ownership of EnLink at December 31, 2015 is approximately:
· |
27% - General Partner (controlled by Devon) |
· |
45% - Public unitholders |
The net gains and losses and related income taxes resulting from these transactions have been recorded as an adjustment to equity, and the change in ownership reflected as an adjustment to noncontrolling interests.
As further discussed in Note 2, in January 2016, EnLink acquired midstream assets in exchange for cash and equity. Subsequent to this transaction, the ownership of the General Partner is approximately:
· |
64% - Devon |
· |
36% - Public unitholders |
Subsequent to this transaction, the ownership of EnLink is approximately:
· |
25% - Devon |
· |
23% - General Partner (controlled by Devon) |
· |
52% - Public unitholders |
Distributions to Noncontrolling Interests
In conjunction with the formation of the General Partner in 2014, Devon made a payment of $100 million to noncontrolling interests. Furthermore, EnLink and the General Partner distributed $254 million and $135 million to non-Devon unitholders during 2015 and 2014, respectively.
|
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 oil, natural gas and NGLs produced and sold. Devon is also involved in governmental agency proceedings and is subject to related contracts and regulatory controls in the ordinary course of business, some that may lead to additional royalty claims. 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.
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 table presents Devon’s commitments that have initial or remaining noncancelable terms in excess of one year as of December 31, 2015.
Year Ending December 31, |
Purchase Obligations |
Drilling and Facility Obligations |
Operational Agreements |
Office and Equipment Leases |
||||
(Millions) |
||||||||
2016 |
$ 557 |
$ 69 |
$ 994 |
$ 70 |
||||
2017 |
703 | 51 | 972 | 58 | ||||
2018 |
791 | 34 | 936 | 76 | ||||
2019 |
803 | 5 | 402 | 68 | ||||
2020 |
845 | 2 | 255 | 42 | ||||
Thereafter |
206 | 28 | 1,042 | 129 | ||||
Total |
$ 3,905 |
$ 189 |
$ 4,601 |
$ 443 |
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 transportation process. Any disruption in Devon’s ability to obtain condensate could negatively affect its ability to 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. The value of the drilling obligations reported is based on gross contractual value.
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 G&A under operating leases, net of sublease income, was $88 million, $64 million and $26 million in 2015, 2014 and 2013, respectively.
|
19.Fair Value Measurements
The following table provides 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 current payables and accrued expenses included in the accompanying consolidated balance sheets approximated fair value at December 31, 2015 and December 31, 2014. Therefore, such financial assets and liabilities are not presented in the following table. Additionally, information regarding the fair values of oil and gas assets, goodwill and other intangible assets and pension plan assets is provided in Note 5, Note 12 and Note 15, respectively.
Fair Value Measurements Using: |
||||||||||||||||
Carrying |
Total Fair |
Level 1 |
Level 2 |
Level 3 |
||||||||||||
Amount |
Value |
Inputs |
Inputs |
Inputs |
||||||||||||
(Millions) |
||||||||||||||||
December 31, 2015 assets (liabilities): |
||||||||||||||||
Cash equivalents |
$ |
1,871 |
$ |
1,871 |
$ |
1,471 |
$ |
400 |
$ |
- |
||||||
Commodity derivatives |
$ |
35 |
$ |
35 |
$ |
- |
$ |
35 |
$ |
- |
||||||
Commodity derivatives |
$ |
(18) |
$ |
(18) |
$ |
- |
$ |
(18) |
$ |
- |
||||||
Interest rate derivatives |
$ |
2 |
$ |
2 |
$ |
- |
$ |
2 |
$ |
- |
||||||
Interest rate derivatives |
$ |
(22) |
$ |
(22) |
$ |
- |
$ |
(22) |
$ |
- |
||||||
Foreign currency derivatives |
$ |
8 |
$ |
8 |
$ |
- |
$ |
8 |
$ |
- |
||||||
Foreign currency derivatives |
$ |
(8) |
$ |
(8) |
$ |
- |
$ |
(8) |
$ |
- |
||||||
Debt |
$ |
(13,113) |
$ |
(11,927) |
$ |
- |
$ |
(11,927) |
$ |
- |
||||||
Capital lease obligations |
$ |
(17) |
$ |
(16) |
$ |
- |
$ |
(16) |
$ |
- |
||||||
December 31, 2014 assets (liabilities): |
||||||||||||||||
Cash equivalents |
$ |
950 |
$ |
950 |
$ |
340 |
$ |
610 |
$ |
- |
||||||
Commodity derivatives |
$ |
1,995 |
$ |
1,995 |
$ |
- |
$ |
1,995 |
$ |
- |
||||||
Commodity derivatives |
$ |
(56) |
$ |
(56) |
$ |
- |
$ |
(56) |
$ |
- |
||||||
Interest rate derivatives |
$ |
1 |
$ |
1 |
$ |
- |
$ |
1 |
$ |
- |
||||||
Interest rate derivatives |
$ |
(1) |
$ |
(1) |
$ |
- |
$ |
(1) |
$ |
- |
||||||
Foreign currency derivatives |
$ |
8 |
$ |
8 |
$ |
- |
$ |
8 |
$ |
- |
||||||
Debt |
$ |
(11,262) |
$ |
(12,472) |
$ |
- |
$ |
(12,472) |
$ |
- |
||||||
Capital lease obligations |
$ |
(20) |
$ |
(20) |
$ |
- |
$ |
(20) |
$ |
- |
The following methods and assumptions were used to estimate the fair values in the tables above.
Level 1 Fair Value Measurements
Cash equivalents — Amounts consist primarily of money market investments. The fair value approximates the carrying value.
Level 2 Fair Value Measurements
Cash equivalents — Amounts consist primarily of commercial paper and Canadian agency and provincial securities investments. The fair value approximates 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 debt are estimated based on rates available for debt with similar terms and maturity. The fair values of commercial paper and credit facility balances are the carrying values.
Capital lease obligations — The fair value was calculated using inputs from third-party banks.
|
20.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 exploration and production 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 U.S. and Canadian segments are both primarily engaged in oil and gas exploration and production activities, and certain information regarding such activities for each segment is included in Note 21.
Devon considers EnLink, combined with the General Partner, to be an operating segment that is distinct from the U.S. and Canadian operating segments. EnLink’s operations consist of midstream assets and operations located across the U.S. Additionally, EnLink has a management team that is primarily responsible for capital and resource allocation decisions. Therefore, EnLink is presented as a separate reporting segment. For the reporting periods prior to the formation of EnLink, Devon has reclassified, from its U.S. segment to the EnLink segment, all asset-level amounts related to the midstream assets that it contributed to EnLink.
U.S.(1) |
Canada |
EnLink(1) |
Eliminations |
Total |
|||||||||||
(Millions) |
|||||||||||||||
Year Ended December 31, 2015: |
|||||||||||||||
Revenues from external customers |
$ |
8,360 |
$ |
1,012 |
$ |
3,773 |
$ |
- |
$ |
13,145 | |||||
Intersegment revenues |
$ |
- |
$ |
- |
$ |
679 |
$ |
(679) |
$ |
- |
|||||
Depreciation, depletion and amortization |
$ |
2,220 |
$ |
522 |
$ |
387 |
$ |
- |
$ |
3,129 | |||||
Asset impairments |
$ |
18,000 |
$ |
1,257 |
$ |
1,563 |
$ |
- |
$ |
20,820 | |||||
Interest expense |
$ |
368 |
$ |
94 |
$ |
107 |
$ |
(46) |
$ |
523 | |||||
Loss before income taxes |
$ |
(18,214) |
$ |
(1,670) |
$ |
(1,384) |
$ |
- |
$ |
(21,268) | |||||
Income tax expense (benefit) |
$ |
(5,650) |
$ |
(445) |
$ |
30 |
$ |
- |
$ |
(6,065) | |||||
Net loss |
$ |
(12,564) |
$ |
(1,225) |
$ |
(1,414) |
$ |
- |
$ |
(15,203) | |||||
Net earnings (loss) attributable to noncontrolling interests |
$ |
1 |
$ |
- |
$ |
(750) |
$ |
- |
$ |
(749) | |||||
Net loss attributable to Devon |
$ |
(12,565) |
$ |
(1,225) |
$ |
(664) |
$ |
- |
$ |
(14,454) | |||||
Property and equipment, net |
$ |
8,811 |
$ |
4,590 |
$ |
5,667 |
$ |
- |
$ |
19,068 | |||||
Total assets |
$ |
14,600 |
$ |
5,464 |
$ |
9,565 |
$ |
(97) |
$ |
29,532 | |||||
Capital expenditures |
$ |
4,575 |
$ |
680 |
$ |
978 |
$ |
- |
$ |
6,233 | |||||
Year Ended December 31, 2014: |
|||||||||||||||
Revenues from external customers |
$ |
14,854 |
$ |
2,063 |
$ |
2,649 |
$ |
- |
$ |
19,566 | |||||
Intersegment revenues |
$ |
- |
$ |
- |
$ |
859 |
$ |
(859) |
$ |
- |
|||||
Depreciation, depletion and amortization |
$ |
2,475 |
$ |
560 |
$ |
284 |
$ |
- |
$ |
3,319 | |||||
Asset impairments |
$ |
12 |
$ |
1,941 |
$ |
- |
$ |
- |
$ |
1,953 | |||||
Gains and losses on asset sales |
$ |
5 |
$ |
(1,077) |
$ |
- |
$ |
- |
$ |
(1,072) | |||||
Interest expense |
$ |
441 |
$ |
85 |
$ |
54 |
$ |
(44) |
$ |
536 | |||||
Earnings (loss) before income taxes |
$ |
4,390 |
$ |
(657) |
$ |
326 |
$ |
- |
$ |
4,059 | |||||
Income tax expense |
$ |
1,797 |
$ |
495 |
$ |
76 |
$ |
- |
$ |
2,368 | |||||
Net earnings (loss) |
$ |
2,593 |
$ |
(1,152) |
$ |
250 |
$ |
- |
$ |
1,691 | |||||
Net earnings attributable to noncontrolling interests |
$ |
1 |
$ |
- |
$ |
83 |
$ |
- |
$ |
84 | |||||
Net earnings (loss) attributable to Devon |
$ |
2,592 |
$ |
(1,152) |
$ |
167 |
$ |
- |
$ |
1,607 | |||||
Property and equipment, net |
$ |
24,463 |
$ |
6,790 |
$ |
5,043 |
$ |
- |
$ |
36,296 | |||||
Total assets |
$ |
32,037 |
$ |
8,517 |
$ |
10,207 |
$ |
(124) |
$ |
50,637 | |||||
Capital expenditures |
$ |
11,214 |
$ |
1,344 |
$ |
1,001 |
$ |
- |
$ |
13,559 | |||||
Year Ended December 31, 2013: |
|||||||||||||||
Revenues from external customers |
$ |
6,807 |
$ |
2,656 |
$ |
934 |
$ |
- |
$ |
10,397 | |||||
Intersegment revenues |
$ |
- |
$ |
- |
$ |
1,362 |
$ |
(1,362) |
$ |
- |
|||||
Depreciation, depletion and amortization |
$ |
1,744 |
$ |
849 |
$ |
187 |
$ |
- |
$ |
2,780 | |||||
Asset impairments |
$ |
1,133 |
$ |
843 |
$ |
- |
$ |
- |
$ |
1,976 | |||||
Interest expense |
$ |
392 |
$ |
80 |
$ |
- |
$ |
(35) |
$ |
437 | |||||
Earnings (loss) before income taxes |
$ |
495 |
$ |
(532) |
$ |
186 |
$ |
- |
$ |
149 | |||||
Income tax expense (benefit) |
$ |
258 |
$ |
(156) |
$ |
67 |
$ |
- |
$ |
169 | |||||
Net earnings (loss) |
$ |
237 |
$ |
(376) |
$ |
119 |
$ |
- |
$ |
(20) | |||||
Property and equipment, net |
$ |
18,201 |
$ |
8,478 |
$ |
1,768 |
$ |
- |
$ |
28,447 | |||||
Total assets |
$ |
27,080 |
$ |
13,560 |
$ |
2,237 |
$ |
- |
$ |
42,877 | |||||
Capital expenditures |
$ |
4,589 |
$ |
1,841 |
$ |
213 |
$ |
- |
$ |
6,643 |
__________________________
|
21.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.
Costs Incurred
The following tables reflect the costs incurred in oil and gas property acquisition, exploration and development activities.
Year Ended December 31, 2015 |
|||||||||
U.S. |
Canada |
Total |
|||||||
(Millions) |
|||||||||
Property acquisition costs: |
|||||||||
Proved properties |
$ |
193 |
$ |
2 |
$ |
195 | |||
Unproved properties |
634 | 83 | 717 | ||||||
Exploration costs |
478 | 109 | 587 | ||||||
Development costs |
3,269 | 402 | 3,671 | ||||||
Costs incurred |
$ |
4,574 |
$ |
596 |
$ |
5,170 | |||
Year Ended December 31, 2014 |
|||||||||
U.S. |
Canada |
Total |
|||||||
(Millions) |
|||||||||
Property acquisition costs: |
|||||||||
Proved properties |
$ |
5,210 |
$ |
- |
$ |
5,210 | |||
Unproved properties |
1,176 | 1 | 1,177 | ||||||
Exploration costs |
270 | 52 | 322 | ||||||
Development costs |
4,400 | 1,063 | 5,463 | ||||||
Costs incurred |
$ |
11,056 |
$ |
1,116 |
$ |
12,172 | |||
Year Ended December 31, 2013 |
|||||||||
U.S. |
Canada |
Total |
|||||||
(Millions) |
|||||||||
Property acquisition costs: |
|||||||||
Proved properties |
$ |
19 |
$ |
3 |
$ |
22 | |||
Unproved properties |
213 | 3 | 216 | ||||||
Exploration costs |
443 | 152 | 595 | ||||||
Development costs |
3,838 | 1,251 | 5,089 | ||||||
Costs incurred |
$ |
4,513 |
$ |
1,409 |
$ |
5,922 |
Costs incurred in the tables above include additions and revisions to Devon’s asset retirement obligations.
Pursuant to the full cost method of accounting, Devon capitalizes certain of its G&A that is related to property acquisition, exploration and development activities. Such capitalized expenses, which are included in the costs shown in the preceding tables, were $372 million, $376 million and $368 million in 2015, 2014 and 2013, 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 $54 million, $45 million and $42 million in 2015, 2014 and 2013, respectively.
Capitalized Costs
The following tables reflect the aggregate capitalized costs related to oil and gas activities.
December 31, 2015 |
|||||||||
U.S. |
Canada |
Total |
|||||||
(Millions) |
|||||||||
Proved properties |
$ |
64,443 |
$ |
13,747 |
$ |
78,190 | |||
Unproved properties |
1,352 | 1,232 | 2,584 | ||||||
Total oil and gas properties |
65,795 | 14,979 | 80,774 | ||||||
Accumulated DD&A |
(58,312) | (11,185) | (69,497) | ||||||
Net capitalized costs |
$ |
7,483 |
$ |
3,794 |
$ |
11,277 | |||
December 31, 2014 |
|||||||||
U.S. |
Canada |
Total |
|||||||
(Millions) |
|||||||||
Proved properties |
$ |
59,849 |
$ |
15,889 |
$ |
75,738 | |||
Unproved properties |
1,460 | 1,292 | 2,752 | ||||||
Total oil and gas properties |
61,309 | 17,181 | 78,490 | ||||||
Accumulated DD&A |
(38,213) | (11,347) | (49,560) | ||||||
Net capitalized costs |
$ |
23,096 |
$ |
5,834 |
$ |
28,930 |
The following table presents a summary of Devon's oil and gas properties not subject to amortization as of December 31, 2015.
Costs Incurred In |
|||||||||||||||
2015 |
2014 |
2013 |
Prior to 2013 |
Total |
|||||||||||
(Millions) |
|||||||||||||||
Acquisition costs |
$ |
672 |
$ |
412 |
$ |
61 |
$ |
510 |
$ |
1,655 | |||||
Exploration costs |
191 | 132 | 69 | 170 | 562 | ||||||||||
Development costs |
9 | 28 | 17 | 128 | 182 | ||||||||||
Capitalized interest |
50 | 37 | 32 | 66 | 185 | ||||||||||
Total oil and gas properties not subject to amortization |
$ |
922 |
$ |
609 |
$ |
179 |
$ |
874 |
$ |
2,584 |
Included in the $2.6 billion of oil and gas properties not subject to amortization are approximately $1.9 billion of costs that Devon deems significant for individual assessment. These costs primarily relate to investments in the Pike thermal oil project in Canada and the newly acquired Powder River Basin assets. Devon anticipates determining its Pike development timeline in mid-2016, with its 50% partner. Based on the development plans, Pike costs will begin to be included in the amortization computation when the first phase of this project is fully approved and Devon subsequently begins recognizing the associated proved reserves. Devon is evaluating and plans to develop the newly acquired Powder River Basin properties over the next four to five years.
Results of Operations
The following tables include revenues and expenses associated with Devon's oil and gas 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 DD&A and after giving effect to permanent differences.
December 31, 2015 |
|||||||||
U.S. |
Canada |
Total |
|||||||
(Millions) |
|||||||||
Oil, gas and NGL sales |
$ |
4,356 |
$ |
1,026 |
$ |
5,382 | |||
Lease operating expenses |
(1,551) | (553) | (2,104) | ||||||
General and administrative expenses |
(196) | (28) | (224) | ||||||
Production and property taxes |
(309) | (33) | (342) | ||||||
Depreciation, depletion and amortization |
(2,107) | (474) | (2,581) | ||||||
Asset impairments |
(17,992) | (1,257) | (19,249) | ||||||
Accretion of asset retirement obligations |
(47) | (27) | (74) | ||||||
Income tax benefit |
5,547 | 314 | 5,861 | ||||||
Results of operations |
$ |
(12,299) |
$ |
(1,032) |
$ |
(13,331) | |||
Depreciation, depletion and amortization per Boe |
$ |
10.21 |
$ |
11.30 |
$ |
10.40 | |||
December 31, 2014 |
|||||||||
U.S. |
Canada |
Total |
|||||||
(Millions) |
|||||||||
Oil, gas and NGL sales |
$ |
7,867 |
$ |
2,043 |
$ |
9,910 | |||
Lease operating expenses |
(1,559) | (773) | (2,332) | ||||||
General and administrative expenses |
(153) | (57) | (210) | ||||||
Production and property taxes |
(466) | (37) | (503) | ||||||
Depreciation, depletion and amortization |
(2,365) | (531) | (2,896) | ||||||
Gain on sale of assets |
- |
1,077 | 1,077 | ||||||
Accretion of asset retirement obligations |
(49) | (39) | (88) | ||||||
Income tax expense |
(1,199) | (568) | (1,767) | ||||||
Results of operations (1) |
$ |
2,076 |
$ |
1,115 |
$ |
3,191 | |||
Depreciation, depletion and amortization per Boe |
$ |
11.41 |
$ |
13.80 |
$ |
11.79 | |||
December 31, 2013 |
|||||||||
U.S. |
Canada |
Total |
|||||||
(Millions) |
|||||||||
Oil, gas and NGL sales |
$ |
5,964 |
$ |
2,558 |
$ |
8,522 | |||
Lease operating expenses |
(1,257) | (1,011) | (2,268) | ||||||
General and administrative expenses |
(125) | (77) | (202) | ||||||
Production and property taxes |
(380) | (59) | (439) | ||||||
Depreciation, depletion and amortization |
(1,640) | (825) | (2,465) | ||||||
Asset impairments |
(1,110) | (843) | (1,953) | ||||||
Accretion of asset retirement obligations |
(47) | (64) | (111) | ||||||
Income tax benefit (expense) |
(510) | 88 | (422) | ||||||
Results of operations |
$ |
895 |
$ |
(233) |
$ |
662 | |||
Depreciation, depletion and amortization per Boe |
$ |
8.69 |
$ |
12.87 |
$ |
9.75 |
__________________________
(1) During 2014, Devon recognized a Canadian goodwill impairment, which is not reflected in these tables. See Note 5 for additional information.
Proved Reserves
The following tables present Devon’s estimated proved reserves by product by country.
Oil (MMBbls) |
|||||||||
U.S. |
Canada |
Total |
|||||||
Proved developed and undeveloped reserves: |
|||||||||
December 31, 2012 |
205 | 65 | 270 | ||||||
Revisions due to prices |
1 | (1) |
- |
||||||
Revisions other than price |
(18) |
- |
(18) | ||||||
Extensions and discoveries |
69 | 7 | 76 | ||||||
Purchase of reserves |
1 |
- |
1 | ||||||
Production |
(28) | (15) | (43) | ||||||
Sale of reserves |
(1) |
- |
(1) | ||||||
December 31, 2013 |
229 | 56 | 285 | ||||||
Revisions due to prices |
(1) |
- |
(1) | ||||||
Revisions other than price |
(38) | 1 | (37) | ||||||
Extensions and discoveries |
94 | 5 | 99 | ||||||
Purchase of reserves |
132 |
- |
132 | ||||||
Production |
(48) | (10) | (58) | ||||||
Sale of reserves |
(17) | (29) | (46) | ||||||
December 31, 2014 |
351 | 23 | 374 | ||||||
Revisions due to prices |
(53) | 4 | (49) | ||||||
Revisions other than price |
(52) | 2 | (50) | ||||||
Extensions and discoveries |
51 | 3 | 54 | ||||||
Purchase of reserves |
5 |
- |
5 | ||||||
Production |
(60) | (10) | (70) | ||||||
December 31, 2015 |
242 | 22 | 264 | ||||||
Proved developed reserves as of: |
|||||||||
December 31, 2012 |
166 | 62 | 228 | ||||||
December 31, 2013 |
194 | 56 | 250 | ||||||
December 31, 2014 |
255 | 23 | 278 | ||||||
December 31, 2015 |
203 | 22 | 225 | ||||||
Proved developed-producing reserves as of: |
|||||||||
December 31, 2012 |
155 | 56 | 211 | ||||||
December 31, 2013 |
178 | 51 | 229 | ||||||
December 31, 2014 |
224 | 19 | 243 | ||||||
December 31, 2015 |
192 | 19 | 211 | ||||||
Proved undeveloped reserves as of: |
|||||||||
December 31, 2012 |
39 | 3 | 42 | ||||||
December 31, 2013 |
35 |
- |
35 | ||||||
December 31, 2014 |
96 |
- |
96 | ||||||
December 31, 2015 |
39 |
- |
39 |
Bitumen (MMBbls) |
|||||||||
U.S. |
Canada |
Total |
|||||||
Proved developed and undeveloped reserves: |
|||||||||
December 31, 2012 |
- |
528 | 528 | ||||||
Revisions due to prices |
- |
(11) | (11) | ||||||
Revisions other than price |
- |
16 | 16 | ||||||
Extensions and discoveries |
- |
38 | 38 | ||||||
Production |
- |
(19) | (19) | ||||||
December 31, 2013 |
- |
552 | 552 | ||||||
Revisions due to prices |
- |
(37) | (37) | ||||||
Revisions other than price |
- |
18 | 18 | ||||||
Extensions and discoveries |
- |
8 | 8 | ||||||
Production |
- |
(20) | (20) | ||||||
December 31, 2014 |
- |
521 | 521 | ||||||
Revisions due to prices |
- |
103 | 103 | ||||||
Revisions other than price |
- |
(84) | (84) | ||||||
Extensions and discoveries |
- |
11 | 11 | ||||||
Production |
- |
(31) | (31) | ||||||
December 31, 2015 |
- |
520 | 520 | ||||||
Proved developed reserves as of: |
|||||||||
December 31, 2012 |
- |
99 | 99 | ||||||
December 31, 2013 |
- |
111 | 111 | ||||||
December 31, 2014 |
- |
137 | 137 | ||||||
December 31, 2015 |
- |
219 | 219 | ||||||
Proved developed-producing reserves as of: |
|||||||||
December 31, 2012 |
- |
99 | 99 | ||||||
December 31, 2013 |
- |
111 | 111 | ||||||
December 31, 2014 |
- |
137 | 137 | ||||||
December 31, 2015 |
- |
219 | 219 | ||||||
Proved undeveloped reserves as of: |
|||||||||
December 31, 2012 |
- |
429 | 429 | ||||||
December 31, 2013 |
- |
441 | 441 | ||||||
December 31, 2014 |
- |
384 | 384 | ||||||
December 31, 2015 |
- |
301 | 301 |
Gas (Bcf) |
|||||||||
U.S. |
Canada |
Total |
|||||||
Proved developed and undeveloped reserves: |
|||||||||
December 31, 2012 |
8,762 | 684 | 9,446 | ||||||
Revisions due to prices |
405 | 161 | 566 | ||||||
Revisions other than price |
(299) | 67 | (232) | ||||||
Extensions and discoveries |
471 | 19 | 490 | ||||||
Purchase of reserves |
1 |
- |
1 | ||||||
Production |
(709) | (165) | (874) | ||||||
Sale of reserves |
(81) | (8) | (89) | ||||||
December 31, 2013 |
8,550 | 758 | 9,308 | ||||||
Revisions due to prices |
191 | 45 | 236 | ||||||
Revisions other than price |
(299) | 4 | (295) | ||||||
Extensions and discoveries |
335 | 8 | 343 | ||||||
Purchase of reserves |
457 |
- |
457 | ||||||
Production |
(660) | (41) | (701) | ||||||
Sale of reserves |
(923) | (738) | (1,661) | ||||||
December 31, 2014 |
7,651 | 36 | 7,687 | ||||||
Revisions due to prices |
(1,412) | (9) | (1,421) | ||||||
Revisions other than price |
(3) | (6) | (9) | ||||||
Extensions and discoveries |
171 |
- |
171 | ||||||
Purchase of reserves |
17 |
- |
17 | ||||||
Production |
(579) | (8) | (587) | ||||||
Sale of reserves |
(37) |
- |
(37) | ||||||
December 31, 2015 |
5,808 | 13 | 5,821 | ||||||
Proved developed reserves as of: |
|||||||||
December 31, 2012 |
7,391 | 679 | 8,070 | ||||||
December 31, 2013 |
7,707 | 752 | 8,459 | ||||||
December 31, 2014 |
6,948 | 36 | 6,984 | ||||||
December 31, 2015 |
5,694 | 13 | 5,707 | ||||||
Proved developed-producing reserves as of: |
|||||||||
December 31, 2012 |
7,091 | 624 | 7,715 | ||||||
December 31, 2013 |
7,425 | 680 | 8,105 | ||||||
December 31, 2014 |
6,746 | 34 | 6,780 | ||||||
December 31, 2015 |
5,546 | 13 | 5,559 | ||||||
Proved undeveloped reserves as of: |
|||||||||
December 31, 2012 |
1,371 | 5 | 1,376 | ||||||
December 31, 2013 |
843 | 6 | 849 | ||||||
December 31, 2014 |
703 |
- |
703 | ||||||
December 31, 2015 |
114 |
- |
114 |
Natural Gas Liquids (MMBbls) |
|||||||||
U.S. |
Canada |
Total |
|||||||
Proved developed and undeveloped reserves: |
|||||||||
December 31, 2012 |
571 | 20 | 591 | ||||||
Revisions due to prices |
8 | 3 | 11 | ||||||
Revisions other than price |
(50) | 3 | (47) | ||||||
Extensions and discoveries |
64 | 1 | 65 | ||||||
Production |
(41) | (4) | (45) | ||||||
December 31, 2013 |
552 | 23 | 575 | ||||||
Revisions due to prices |
7 | 1 | 8 | ||||||
Revisions other than price |
2 |
- |
2 | ||||||
Extensions and discoveries |
47 |
- |
47 | ||||||
Purchase of reserves |
57 |
- |
57 | ||||||
Production |
(50) | (1) | (51) | ||||||
Sale of reserves |
(37) | (23) | (60) | ||||||
December 31, 2014 |
578 |
- |
578 | ||||||
Revisions due to prices |
(119) |
- |
(119) | ||||||
Revisions other than price |
(6) |
- |
(6) | ||||||
Extensions and discoveries |
24 |
- |
24 | ||||||
Purchase of reserves |
1 |
- |
1 | ||||||
Production |
(50) |
- |
(50) | ||||||
December 31, 2015 |
428 |
- |
428 | ||||||
Proved developed reserves as of: |
|||||||||
December 31, 2012 |
431 | 20 | 451 | ||||||
December 31, 2013 |
468 | 23 | 491 | ||||||
December 31, 2014 |
486 |
- |
486 | ||||||
December 31, 2015 |
411 |
- |
411 | ||||||
Proved developed-producing reserves as of: |
|||||||||
December 31, 2012 |
406 | 19 | 425 | ||||||
December 31, 2013 |
442 | 21 | 463 | ||||||
December 31, 2014 |
467 |
- |
467 | ||||||
December 31, 2015 |
393 |
- |
393 | ||||||
Proved undeveloped reserves as of: |
|||||||||
December 31, 2012 |
140 |
- |
140 | ||||||
December 31, 2013 |
84 |
- |
84 | ||||||
December 31, 2014 |
92 |
- |
92 | ||||||
December 31, 2015 |
17 |
- |
17 |
Total (MMBoe) (1) |
|||||||||
U.S. |
Canada |
Total |
|||||||
Proved developed and undeveloped reserves: |
|||||||||
December 31, 2012 |
2,236 | 727 | 2,963 | ||||||
Revisions due to prices |
76 | 18 | 94 | ||||||
Revisions other than price |
(117) | 29 | (88) | ||||||
Extensions and discoveries |
212 | 49 | 261 | ||||||
Purchase of reserves |
1 |
- |
1 | ||||||
Production |
(189) | (64) | (253) | ||||||
Sale of reserves |
(14) | (1) | (15) | ||||||
December 31, 2013 |
2,205 | 758 | 2,963 | ||||||
Revisions due to prices |
38 | (29) | 9 | ||||||
Revisions other than price |
(86) | 21 | (65) | ||||||
Extensions and discoveries |
197 | 14 | 211 | ||||||
Purchase of reserves |
265 |
- |
265 | ||||||
Production |
(207) | (39) | (246) | ||||||
Sale of reserves |
(207) | (176) | (383) | ||||||
December 31, 2014 |
2,205 | 549 | 2,754 | ||||||
Revisions due to prices |
(408) | 106 | (302) | ||||||
Revisions other than price |
(59) | (83) | (142) | ||||||
Extensions and discoveries |
104 | 14 | 118 | ||||||
Purchase of reserves |
9 |
- |
9 | ||||||
Production |
(206) | (42) | (248) | ||||||
Sale of reserves |
(7) |
- |
(7) | ||||||
December 31, 2015 |
1,638 | 544 | 2,182 | ||||||
Proved developed reserves as of: |
|||||||||
December 31, 2012 |
1,829 | 294 | 2,123 | ||||||
December 31, 2013 |
1,947 | 315 | 2,262 | ||||||
December 31, 2014 |
1,900 | 165 | 2,065 | ||||||
December 31, 2015 |
1,563 | 243 | 1,806 | ||||||
Proved developed-producing reserves as of: |
|||||||||
December 31, 2012 |
1,743 | 278 | 2,021 | ||||||
December 31, 2013 |
1,857 | 297 | 2,154 | ||||||
December 31, 2014 |
1,815 | 162 | 1,977 | ||||||
December 31, 2015 |
1,509 | 240 | 1,749 | ||||||
Proved undeveloped reserves as of: |
|||||||||
December 31, 2012 |
407 | 433 | 840 | ||||||
December 31, 2013 |
258 | 443 | 701 | ||||||
December 31, 2014 |
305 | 384 | 689 | ||||||
December 31, 2015 |
75 | 301 | 376 |
_______________________
(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 NGL 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 2015 (MMBoe).
U.S. |
Canada |
Total |
|||||||
Proved undeveloped reserves as of December 31, 2014 |
305 | 384 | 689 | ||||||
Extensions and discoveries |
13 | 11 | 24 | ||||||
Revisions due to prices |
(115) | 80 | (35) | ||||||
Revisions other than price |
(40) | (80) | (120) | ||||||
Conversion to proved developed reserves |
(88) | (94) | (182) | ||||||
Proved undeveloped reserves as of December 31, 2015 |
75 | 301 | 376 |
Proved undeveloped reserves decreased 45% from year-end 2014 to year-end 2015, and the year-end 2015 balance represents 17% of total proved reserves. Drilling and development activities increased Devon’s proved undeveloped reserves 24 MMBoe and resulted in the conversion of 182 MMBoe, or 26%, of the 2014 proved undeveloped reserves to proved developed reserves. Costs incurred to develop and convert Devon’s proved undeveloped reserves were approximately $2.2 billion for 2015. Additionally, revisions other than price decreased Devon’s proved undeveloped reserves 120 MMBoe primarily due to evaluations of certain properties in the U.S. and Canada. The largest revisions, which reduced reserves by 80 MMBoe, relate to evaluations of Jackfish bitumen reserves. Of the 40 MMBoe revisions recorded for U.S. properties, a reduction of approximately 27 MMBoe represents reserves that Devon now does not expect to develop in the next five years, including 20 MMBoe attributable to the Eagle Ford.
A significant amount of Devon’s proved undeveloped reserves at the end of 2015 related to its Jackfish operations. At December 31, 2015 and 2014, Devon’s Jackfish proved undeveloped reserves were 301 MMBoe and 384 MMBoe, respectively. Development schedules for the Jackfish reserves are primarily controlled by the need to keep the processing plants at their 35 MBbl daily facility capacity. Processing plant capacity is controlled by factors such as total steam processing capacity and steam-oil ratios. Furthermore, development of these projects involves the up-front construction of steam injection/distribution and bitumen processing facilities. Due to the large up-front capital investments and large reserves required to provide economic returns, the project conditions meet the specific circumstances requiring a period greater than 5 years for conversion to developed reserves. As a result, these reserves are classified as proved undeveloped for more than five years. Currently, the development schedule for these reserves extends through to 2030. At the end of 2015, approximately 184 MMBoe of proved undeveloped reserves at Jackfish have remained undeveloped for five years or more since the initial booking. No other projects have proved undeveloped reserves that have remained undeveloped more than five years from the initial booking of the reserves. Furthermore, approximately 180 MMBoe of proved undeveloped reserves at Jackfish will require in excess of five years, from the date of this filing, to develop.
Price Revisions
2015 - Reserves decreased 302 MMBoe primarily due to lower commodity prices across all products. The lower bitumen price increased Canadian reserves due to the decline in royalties, which increases Devon’s after-royalty volumes.
2014 - Reserves increased 9 MMBoe primarily due to higher gas prices in the Barnett Shale and the Anadarko Basin, partially offset by higher bitumen prices, which result in lower after-royalty volumes, in Canada.
2013 - Reserves increased 94 MMBoe primarily due to higher gas prices. Of this increase, 43 MMBoe related to the Barnett Shale and 19 MMBoe related to the Rocky Mountain area.
Revisions Other Than Price
Total revisions other than price for 2015 primarily related to evaluations of Eagle Ford and Jackfish. Negative revisions other than price at Jackfish are primarily due to a refined reserves methodology that resulted in a reduced recovery factor. Revisions other than price in 2014 and 2013 primarily related to Devon’s evaluation of certain dry gas regions, with the largest revisions being made in the Cana-Woodford Shale and Barnett Shale.
Extensions and Discoveries
2015 – Of the 118 MMBoe of extensions and discoveries, 38 MMBoe related to the Delaware Basin, 30 MMBoe related to the Anadarko Basin, 21 MMBoe related to the Eagle Ford and 11 MMBoe related to Jackfish.
The 2015 extensions and discoveries included 13 MMBoe related to additions from Devon’s infill drilling activities, primarily consisting of 11 MMBoe at Jackfish.
2014 – Of the 211 MMBoe of extensions and discoveries, 70 MMBoe related to the Permian Basin, 54 MMBoe related to the Eagle Ford, 36 MMBoe related to the Barnett Shale, 14 MMBoe related to the Anadarko Basin, 8 MMBoe related to Jackfish and 14 MMBoe related to the Mississippian-Woodford Trend.
The 2014 extensions and discoveries included 5 MMBoe related to additions from Devon’s infill drilling activities, primarily consisting of 4 MMBoe at the Permian Basin.
2013 – Of the 261 MMBoe of extensions and discoveries, 76 MMBoe related to the Permian Basin, 54 MMBoe related to the Barnett Shale, 42 MMBoe related to the Anadarko Basin, 38 MMBoe related to Jackfish and 32 MMBoe related to the Mississippian-Woodford Trend.
The 2013 extensions and discoveries included 175 MMBoe related to additions from Devon’s infill drilling activities, including 23 MMBoe at the Cana-Woodford Shale, 54 MMBoe at the Barnett Shale, 38 MMBoe at Jackfish, 33 MMBoe at the Permian Basin and 20 MMBoe at the Mississippian-Woodford Trend.
Purchase of Reserves
2015 – Of the 9 MMBoe of reserves purchases, 6 MMBoe related to Devon’s acquisition in the Powder River Basin.
2014 – Of the 265 MMBoe of reserves purchases, 246 MMBoe related to Devon’s GeoSouthern acquisition in the Eagle Ford.
Sale of Reserves
2015 – The 7 MMBoe of reserves sales related to Devon’s asset divestitures in the San Juan Basin.
2014 – The total 383 MMBoe of reserves sales related to Devon’s asset divestitures in the U.S. and Canada.
Standardized Measure
The following tables reflect Devon’s standardized measure of discounted future net cash flows from its proved reserves.
Year Ended December 31, 2015 |
|||||||||
U.S. |
Canada |
Total |
|||||||
(Millions) |
|||||||||
Future cash inflows |
$ |
27,398 |
$ |
13,047 |
$ |
40,445 | |||
Future costs: |
|||||||||
Development |
(3,306) | (2,759) | (6,065) | ||||||
Production |
(17,251) | (6,891) | (24,142) | ||||||
Future income tax expense |
- |
(475) | (475) | ||||||
Future net cash flow |
6,841 | 2,922 | 9,763 | ||||||
10% discount to reflect timing of cash flows |
(1,973) | (1,102) | (3,075) | ||||||
Standardized measure of discounted future net cash flows |
$ |
4,868 |
$ |
1,820 |
$ |
6,688 | |||
Year Ended December 31, 2014 |
|||||||||
U.S. |
Canada |
Total |
|||||||
(Millions) |
|||||||||
Future cash inflows |
$ |
75,847 |
$ |
31,371 |
$ |
107,218 | |||
Future costs: |
|||||||||
Development |
(7,168) | (3,619) | (10,787) | ||||||
Production |
(29,740) | (14,232) | (43,972) | ||||||
Future income tax expense |
(11,021) | (3,026) | (14,047) | ||||||
Future net cash flow |
27,918 | 10,494 | 38,412 | ||||||
10% discount to reflect timing of cash flows |
(12,819) | (5,119) | (17,938) | ||||||
Standardized measure of discounted future net cash flows |
$ |
15,099 |
$ |
5,375 |
$ |
20,474 | |||
Year Ended December 31, 2013 |
|||||||||
U.S. |
Canada |
Total |
|||||||
(Millions) |
|||||||||
Future cash inflows |
$ |
61,983 |
$ |
33,305 |
$ |
95,288 | |||
Future costs: |
|||||||||
Development |
(5,448) | (5,308) | (10,756) | ||||||
Production |
(26,663) | (15,709) | (42,372) | ||||||
Future income tax expense |
(9,046) | (2,327) | (11,373) | ||||||
Future net cash flow |
20,826 | 9,961 | 30,787 | ||||||
10% discount to reflect timing of cash flows |
(10,346) | (4,700) | (15,046) | ||||||
Standardized measure of discounted future net cash flows |
$ |
10,480 |
$ |
5,261 |
$ |
15,741 |
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 2015 estimates, Devon’s future realized prices were assumed to be $44.33 per Bbl of oil, $23.84 per Bbl of bitumen, $2.06 per Mcf of gas and $10.11 per Bbl of NGLs. Of the $6.1 billion of future development costs as of the end of 2015, $0.6 billion, $0.6 billion and $0.4 billion are estimated to be spent in 2016, 2017 and 2018, respectively.
Future development costs include not only development costs but also future asset retirement costs. Included as part of the $6.1 billion of future development costs are $1.2 billion of future asset retirement costs. 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, |
|||||||||
2015 |
2014 |
2013 |
|||||||
(Millions) |
|||||||||
Beginning balance |
$ |
20,474 |
$ |
15,741 |
$ |
13,221 | |||
Net changes in prices and production costs |
(20,756) | 2,561 | 3,018 | ||||||
Oil, bitumen, gas and NGL sales, net of production costs |
(2,704) | (6,865) | (5,613) | ||||||
Changes in estimated future development costs |
1,313 | (768) | 399 | ||||||
Extensions and discoveries, net of future development costs |
1,129 | 4,836 | 4,047 | ||||||
Purchase of reserves |
95 | 6,422 | 14 | ||||||
Sales of reserves in place |
(79) | (2,384) | (44) | ||||||
Revisions of quantity estimates |
(1,451) | (746) | (1,040) | ||||||
Previously estimated development costs incurred during the period |
2,158 | 1,933 | 1,986 | ||||||
Accretion of discount |
567 | 1,746 | 1,940 | ||||||
Foreign exchange and other |
(1,254) | (107) | (583) | ||||||
Net change in income taxes |
7,196 | (1,895) | (1,604) | ||||||
Ending balance |
$ |
6,688 |
$ |
20,474 |
$ |
15,741 |
|
22.Supplemental Quarterly Financial Information (Unaudited)
The following tables present a summary of Devon’s unaudited interim results of operations.
2015 |
|||||||||||||||
First Quarter |
Second Quarter |
Third Quarter |
Fourth Quarter |
Full Year |
|||||||||||
(Millions, except per share amounts) |
|||||||||||||||
Operating revenues |
$ |
3,265 |
$ |
3,393 |
$ |
3,601 |
$ |
2,886 |
$ |
13,145 | |||||
Loss before income taxes |
$ |
(5,624) |
$ |
(4,479) |
$ |
(5,623) |
$ |
(5,542) |
$ |
(21,268) | |||||
Net loss attributable to Devon |
$ |
(3,599) |
$ |
(2,816) |
$ |
(3,507) |
$ |
(4,532) |
$ |
(14,454) | |||||
Basic net loss per share attributable to Devon |
$ |
(8.88) |
$ |
(6.94) |
$ |
(8.64) |
$ |
(11.12) |
$ |
(35.55) | |||||
Diluted net loss per share attributable to Devon |
$ |
(8.88) |
$ |
(6.94) |
$ |
(8.64) |
$ |
(11.12) |
$ |
(35.55) | |||||
2014 |
|||||||||||||||
First Quarter |
Second Quarter |
Third Quarter |
Fourth Quarter |
Full Year |
|||||||||||
(Millions, except per share amounts) |
|||||||||||||||
Operating revenues |
$ |
3,725 |
$ |
4,510 |
$ |
5,336 |
$ |
5,995 |
$ |
19,566 | |||||
Earnings before income taxes |
$ |
560 |
$ |
1,554 |
$ |
1,654 |
$ |
291 |
$ |
4,059 | |||||
Net earnings (loss) attributable to Devon |
$ |
324 |
$ |
675 |
$ |
1,016 |
$ |
(408) |
$ |
1,607 | |||||
Basic net earnings (loss) per share attributable to Devon |
$ |
0.80 |
$ |
1.65 |
$ |
2.48 |
$ |
(1.01) |
$ |
3.93 | |||||
Diluted net earnings (loss) per share attributable to Devon |
$ |
0.79 |
$ |
1.64 |
$ |
2.47 |
$ |
(1.01) |
$ |
3.91 |
Net Earnings (Loss) Attributable to Devon
The 2015 quarterly results include asset impairments of $5.5 billion (or $13.46 per diluted share), $4.2 billion (or $10.27 per diluted share), $5.9 billion ($14.41 per diluted share) and $5.3 billion (or $13.09 per diluted share) for the first quarter through the fourth quarter of 2015, respectively, as discussed in Note 5.
The fourth quarter of 2014 includes asset impairments of $1.9 billion (or $4.79 per diluted share) as discussed in Note 5.
|
Principles of Consolidation
The accompanying consolidated financial statements include the accounts of Devon and entities in which it holds a controlling interest. All intercompany transactions have been eliminated. Undivided interests in oil and natural gas exploration and production joint ventures are consolidated on a proportionate basis. Investments in non-controlled entities, over which Devon has the ability to exercise significant influence over operating and financial policies, are accounted for using the equity method. In applying the equity method of accounting, the investments are initially recognized at cost and subsequently adjusted for Devon’s proportionate share of earnings, losses and distributions. Investments accounted for using the equity method and cost method are reported as a component of other long-term assets.
As discussed more fully in Note 2, Devon completed a business combination in 2014 whereby Devon controls both EnLink and the General Partner. Devon controls both the General Partner’s and EnLink’s operations; therefore, the General Partner’s and EnLink’s accounts are included in Devon’s accompanying consolidated financial statements subsequent to the completion of the transaction. The portions of the General Partner’s and EnLink’s net earnings and stockholders’ equity not attributable to Devon’s controlling interest are shown separately as noncontrolling interests in the accompanying consolidated comprehensive statements of earnings and consolidated balance sheets.
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, midstream assets and product and equipment inventories;
• derivative financial instruments;
• the fair value of reporting units and related assessment of goodwill for impairment;
• the fair value of intangible assets other than goodwill;
• income taxes;
• asset retirement obligations;
• obligations related to employee pension and postretirement benefits;
• legal and environmental risks and exposures; and
• general credit risk associated with receivables and other assets.
Revenue Recognition
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 typically 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 consolidated comprehensive statements of earnings.
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 2015, 2014 and 2013, no purchaser accounted for more than 10% of Devon’s operating revenues.
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, interest rate risk and foreign exchange risk. Devon does not intend to issue or hold 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. Additionally, Devon and EnLink periodically enter into derivative financial instruments with respect to a portion of their oil, gas and NGL marketing activities. These instruments are used to manage the inherent uncertainty of future revenues resulting from 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 and foreign exchange forward contracts to manage its exposure to fluctuations in the U.S. and Canadian dollar 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, 2015, 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. Cash settlements that Devon is entitled to are accrued for in other current assets in the accompanying consolidated balance sheets. As of December 31, 2015, Devon accrued $236 million that it received in January 2016 related to cash settlements.
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. As of December 31, 2015 and December 31, 2014, Devon held $75 million and $524 million, respectively, 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 consolidated balance sheets.
General and Administrative Expenses
G&A is 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
Independent of EnLink, Devon grants share-based awards to independent members of its Board of Directors and selected employees. EnLink and the General Partner also grant share-based awards to independent 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 G&A in the accompanying consolidated comprehensive statements of earnings over the applicable requisite service periods. As a result of Devon’s restructuring activity discussed in Note 6, certain share-based awards were accelerated and recognized as a component of restructuring costs in the accompanying consolidated 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 canceled 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 basis. 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.
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 the deferred tax assets is determined to be unlikely, a valuation allowance is provided to reduce the recorded tax benefits from such assets. Devon periodically weighs the positive and negative evidence to determine if it is more likely than not that some or all of the deferred tax assets will be realized. Forming a conclusion that a valuation allowance is not required is difficult when there is negative evidence, such as cumulative losses in recent years. See Note 7 for further discussion.
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 indefinitely 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 Share Attributable to Devon
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, as well as performance-based restricted stock awards that have met the requisite performance targets. 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.
Accounts Receivable
Devon’s accounts receivable balance primarily consists of oil and gas sales receivables, marketing and midstream revenue receivables and joint interest receivables for which Devon does not require collateral security. Devon has established an allowance for bad debts equal to the estimable portions of accounts receivable for which failure to collect is considered probable. When a portion of the receivable is deemed uncollectible, the write-off is made against the allowance.
Investments
Devon periodically invests excess cash in U.S. and Canadian treasury securities and other marketable securities. 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.
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.
Capitalized costs are depleted by an equivalent unit-of-production method, converting gas to oil at the ratio of six Mcf of gas to one Bbl 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.
Sales or dispositions of oil and gas properties are generally accounted for as adjustments to capitalized costs with no gain or loss 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. As discussed more fully in Note 2, the 2014 divestitures of certain Canadian assets significantly altered such relationship, and Devon recognized a gain, which is included as a separate item in the accompanying consolidated comprehensive statements of earnings.
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% 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, 2015 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.
Costs for midstream assets that are in use are depreciated over the assets’ estimated useful lives, using either the unit-of-production or straight-line method. Depreciation and amortization of other property and equipment, including corporate 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 annually, or more frequently if events or changes in circumstances dictate that the carrying value of goodwill may not be recoverable. 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 2015, 2014 and 2013. No impairment of goodwill was required in 2013. However, write-downs were required in 2015 and 2014 based on the annual impairment test. EnLink’s Texas, Louisiana and Crude and Condensate reporting segment goodwill were deemed impaired in 2015, and Devon’s Canadian reporting unit goodwill was deemed impaired in 2014. See Note 12 for further discussion.
Intangible Assets
Unamortized capitalized intangible assets, consisting of EnLink customer relationships, are presented in other long-term assets in the accompanying consolidated balance sheets. These assets are amortized on a straight-line basis over the expected periods of benefits, which range from 10-20 years. During 2015, EnLink’s customer relationships were also evaluated for impairment, and a portion of these intangibles was considered impaired. See Note 12 for further discussion.
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.
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.
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 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. |
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.
Noncontrolling Interests
Noncontrolling interests represent third-party ownership in the net assets of Devon’s consolidated subsidiaries and are presented as a component of equity. Changes in Devon’s ownership interests in subsidiaries that do not result in deconsolidation are recognized in equity.
Recently Issued Accounting Standards
The FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606). This ASU supersedes the revenue recognition requirements in Topic 605, Revenue Recognition and industry-specific guidance in Subtopic 932-605, Extractive Activities – Oil and Gas – Revenue Recognition. This ASU provides guidance concerning the recognition and measurement of revenue from contracts with customers. Its objective is to increase the usefulness of information in the financial statements regarding the nature, timing and uncertainty of revenues. The effective date for ASU 2014-09 was delayed through the issuance of ASU 2015-14, Revenue from Contracts with Customers – Deferral of the Effective Date, to annual and interim periods beginning in 2018 and is required to be adopted using either the retrospective or cumulative effect (modified retrospective) transition method, with early adoption permitted in 2017. Devon is evaluating the impact this ASU will have on its consolidated financial statements and related disclosures and does not plan on early adopting.
The FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis. This ASU provides additional guidance to reporting entities in evaluating whether certain legal entities, such as limited partnerships, limited liability corporations and securitization structures, should be consolidated. The ASU is considered to be an improvement on current accounting requirements as it reduces the number of existing consolidation models. This ASU is effective for Devon beginning January 1, 2016 and will be applied using the retrospective approach. This ASU will not have a material impact on Devon’s consolidated financial statements and related disclosures.
The FASB issued ASU 2015-03, Interest – Imputation of Interest (Topic 835): Simplifying the Presentation of Debt Issuance Costs and ASU 2015-15, Interest – Imputation of Interest (Topic 835): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements. These ASUs require debt issuance costs related to a recognized debt liability, except for those related to revolving credit facilities, to be presented on the balance sheet as a direct deduction from the carrying amount of that debt liability rather than as an asset. These ASUs are effective for Devon beginning January 1, 2016 and will be applied using the retrospective approach. These ASUs will not have a material impact on Devon’s consolidated financial statements and related disclosures.
The FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes. This ASU requires that all deferred tax assets and liabilities, along with any related valuation allowance, be classified as noncurrent on the balance sheet. This ASU is effective for annual and interim periods beginning in 2017 and can be applied prospectively or retrospectively, with early adoption permitted. This ASU will be early-adopted by Devon, effective January 1, 2016 and will be applied using the retrospective approach. This ASU will not have a material impact on Devon’s consolidated financial statements and related disclosures.
|
Purchase Price |
Allocation |
|||||||||||||
Date |
Acquiree |
Cash |
EnLink Units |
PP&E |
Goodwill |
Intangibles |
Other |
|||||||
January 31 |
LPC |
$108 |
- |
$30 |
$30 |
$43 |
$5 |
|||||||
March 16 |
Coronado |
$240 |
$360 |
$302 |
$18 |
$281 |
$(1) |
|||||||
October 1 |
Matador |
$145 |
- |
$36 |
$9 |
$99 |
$1 |
Crosstex Energy, Inc. outstanding common shares: |
||||
Held by public shareholders |
48.0 | |||
Restricted shares |
0.4 | |||
Total subject to conversion |
48.4 | |||
Exchange ratio |
1.0 |
x |
||
Converted shares |
48.4 | |||
Crosstex Energy, Inc. common share price (1) |
$ |
37.60 | ||
Crosstex Energy, Inc. consideration |
$ |
1,823 | ||
Fair value of noncontrolling interests in E2 (2) |
18 | |||
Total Crosstex Energy, Inc. consideration and fair value of noncontrolling interests |
$ |
1,841 | ||
Crosstex Energy, LP outstanding units: |
||||
Common units held by public unitholders |
75.1 | |||
Preferred units held by third party (3) |
17.1 | |||
Restricted units |
0.4 | |||
Total |
92.6 | |||
Crosstex Energy, LP common unit price (4) |
$ |
30.51 | ||
Crosstex Energy, LP common units value |
$ |
2,825 | ||
Crosstex Energy, LP outstanding unit options value |
4 | |||
Total fair value of noncontrolling interests in Crosstex Energy, LP (4) |
2,829 | |||
Total consideration and fair value of noncontrolling interests |
$ |
4,670 |
__________________________
(1) The final purchase price is based on the fair value of Crosstex Energy, Inc.’s common shares as of the closing date, March 7, 2014.
(2) Represents the value of noncontrolling interests related to the General Partner’s equity investment in E2.
(3) Crosstex Energy, LP converted the preferred units to common units in February 2014.
(4) The final purchase price is based on the fair value of Crosstex Energy, LP’s common units as of the closing date, March 7, 2014.
Assets acquired: |
|||
Current assets |
$ |
437 | |
Property, plant and equipment, net |
2,438 | ||
Intangible assets |
569 | ||
Equity investment |
222 | ||
Goodwill (1) |
3,283 | ||
Other long-term assets |
1 | ||
Liabilities assumed: |
|||
Current liabilities |
(515) | ||
Long-term debt |
(1,454) | ||
Deferred income taxes |
(210) | ||
Other long-term liabilities |
(101) | ||
Total consideration and fair value of noncontrolling interests |
$ |
4,670 |
__________________________
(1) Goodwill is the excess of the consideration transferred over the net assets recognized and represents the future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Goodwill is not amortized and is not deductible for tax purposes.
Cash and cash equivalents |
$ |
95 | |
Other current assets |
256 | ||
Proved properties |
5,026 | ||
Unproved properties |
1,007 | ||
Midstream assets |
86 | ||
Current liabilities |
(434) | ||
Long-term liabilities |
(6) | ||
Net assets acquired |
$ |
6,030 |
Year Ended December 31, |
||||||
2014 |
2013 |
|||||
(Millions) |
||||||
Total operating revenues |
$ |
20,213 |
$ |
12,979 | ||
Net earnings |
$ |
1,716 |
$ |
35 | ||
Noncontrolling interests |
$ |
97 |
$ |
45 | ||
Net earnings (loss) attributable to Devon |
$ |
1,619 |
$ |
(10) | ||
Net earnings (loss) per common share attributable to Devon |
$ |
3.94 |
$ |
(0.02) |
|
The following table presents the net gains and losses by derivative financial instrument type followed by the corresponding individual consolidated comprehensive statements of earnings caption.
Year Ended December 31, |
|||||||||
2015 |
2014 |
2013 |
|||||||
Commodity derivatives: |
(Millions) |
||||||||
Oil, gas and NGL derivatives |
$ |
503 |
$ |
1,989 |
$ |
(191) | |||
Marketing and midstream revenues |
9 | 22 |
— |
||||||
Interest rate derivatives: |
|||||||||
Other nonoperating items |
(20) | (1) |
— |
||||||
Foreign currency derivatives: |
|||||||||
Other nonoperating items |
246 | 60 | 56 | ||||||
Net gains (losses) recognized |
$ |
738 |
$ |
2,070 |
$ |
(135) |
The following table presents the derivative fair values by derivative financial instrument type followed by the corresponding individual consolidated balance sheet caption.
December 31, 2015 |
December 31, 2014 |
||||||
(Millions) |
|||||||
Commodity derivative assets: |
|||||||
Derivatives, at fair value |
$ |
34 |
$ |
1,984 | |||
Other long-term assets |
1 | 11 | |||||
Interest rate derivative assets: |
|||||||
Derivatives, at fair value |
1 | 1 | |||||
Other long-term assets |
1 |
— |
|||||
Foreign currency derivative assets: |
|||||||
Derivatives, at fair value |
8 | 8 | |||||
Total derivative assets |
$ |
45 |
$ |
2,004 | |||
Commodity derivative liabilities: |
|||||||
Other current liabilities |
$ |
14 |
$ |
28 | |||
Other long-term liabilities |
4 | 28 | |||||
Interest rate derivative liabilities: |
|||||||
Other current liabilities |
— |
1 | |||||
Other long-term liabilities |
22 |
— |
|||||
Foreign currency derivative liabilities: |
|||||||
Other current liabilities |
8 |
— |
|||||
Total derivative liabilities |
$ |
48 |
$ |
57 |
Call Options Sold |
|||||
Period |
Volume (Bbls/d) |
Weighted Average Price ($/Bbl) |
|||
Q1-Q4 2016 |
18,500 |
$ |
73.18 |
Oil Basis Swaps |
|||||||
Period |
Index |
Volume (Bbls/d) |
Weighted Average Differential to WTI ($/Bbl) |
||||
Q1-Q4 2016 |
Western Canadian Select |
5,249 |
$ |
(13.67) | |||
Q1-Q4 2016 |
West Texas Sour |
5,000 |
$ |
(0.53) | |||
Q1-Q4 2016 |
Midland Sweet |
13,000 |
$ |
0.25 |
Price Swaps |
Call Options Sold |
|||||||||
Period |
Volume (MMBtu/d) |
Weighted Average Price ($/MMBtu) |
Volume (MMBtu/d) |
Weighted Average Price ($/MMBtu) |
||||||
Q1-Q4 2016 |
54,650 |
$ |
3.17 |
400,000 |
$ |
4.30 |
Natural Gas Basis Swaps |
|||||||
Period |
Index |
Volume (MMBtu/d) |
Weighted Average Differential to Henry Hub ($/MMBtu) |
||||
Q1-Q4 2016 |
Panhandle Eastern Pipe Line |
175,000 |
$ |
(0.34) |
|||
Q1-Q4 2016 |
El Paso Natural Gas |
125,000 |
$ |
(0.12) |
|||
Q1-Q4 2016 |
Houston Ship Channel |
30,000 |
$ |
0.11 |
|||
Q1-Q4 2016 |
Transco Zone 4 |
70,000 |
$ |
0.01 |
|||
Q1-Q4 2017 |
Panhandle Eastern Pipe Line |
150,000 |
$ |
(0.34) |
|||
Q1-Q4 2017 |
El Paso Natural Gas |
50,000 |
$ |
(0.14) |
|||
Q1-Q4 2017 |
Houston Ship Channel |
35,000 |
$ |
0.06 |
|||
Q1-Q4 2017 |
Transco Zone 4 |
185,000 |
$ |
0.03 |
Period |
Product |
Volume (Total) |
Weighted Average Price Paid |
Weighted Average Price Received |
|||||||
Q1 2016-Q4 2016 |
Ethane |
571 |
MBbls |
$ |
0.29/gal |
Index |
|||||
Q1 2016-Q4 2016 |
Propane |
812 |
MBbls |
Index |
$ |
0.81/gal |
|||||
Q1 2016-Q4 2016 |
Normal Butane |
113 |
MBbls |
Index |
$ |
0.61/gal |
|||||
Q1 2016-Q4 2016 |
Natural Gasoline |
61 |
MBbls |
Index |
$ |
1.02/gal |
|||||
Q1 2016-Q1 2017 |
Natural Gas |
13,829 |
MMBtu/d |
$ |
2.65/MMBtu |
Index |
Notional |
Rate Received |
Rate Paid |
Expiration |
||||
(Millions) |
|||||||
$ |
100 |
Three Month LIBOR |
0.92% |
December 2016 |
|||
$ |
100 |
1.76% |
Three Month LIBOR |
January 2019 |
|||
$ |
750 |
Three Month LIBOR |
2.98% |
December 2048 (1) |
____________________________
(1) Mandatory settlement in December 2018.
Forward Contract |
|||||||||
Currency |
Contract Type |
CAD Notional |
Weighted Average Fixed Rate Received |
Expiration |
|||||
(Millions) |
(CAD-USD) |
||||||||
Canadian Dollar |
Sell |
$ |
3,560 |
0.723 |
March 2016 |
|
Year Ended December 31, |
||||||||||
2015 |
2014 |
2013 |
||||||||
(Millions) |
||||||||||
U.S. oil and gas assets |
$ |
17,992 |
$ |
— |
$ |
1,110 | ||||
Canada oil and gas assets |
1,257 |
— |
843 | |||||||
Canada goodwill |
— |
1,941 |
— |
|||||||
EnLink goodwill |
1,328 |
— |
— |
|||||||
EnLink other intangible assets |
223 |
— |
— |
|||||||
Other assets |
20 | 12 | 23 | |||||||
Total asset impairments |
$ |
20,820 |
$ |
1,953 |
$ |
1,976 |
|
Year Ended December 31, |
||||||||
2015 |
2014 |
2013 |
||||||
(Millions) |
||||||||
Office consolidation and offshore divestiture: |
||||||||
Employee severance and retention |
$ |
- |
$ |
- |
$ |
13 | ||
Lease obligations and other |
54 |
- |
41 | |||||
Canada divestitures: |
||||||||
Employee severance and retention |
11 | 42 |
- |
|||||
Lease obligations and other |
13 | 4 |
- |
|||||
Restructuring costs |
$ |
78 |
$ |
46 |
$ |
54 |
Other |
Other |
||||||||
Current |
Long-term |
||||||||
Liabilities |
Liabilities |
Total |
|||||||
(Millions) |
|||||||||
Balance as of December 31, 2013 |
$ |
27 |
$ |
18 |
$ |
45 | |||
Changes due to office consolidation and offshore divestiture |
(18) | (11) | (29) | ||||||
Changes due to Canadian divestitures |
4 |
— |
4 | ||||||
Balance as of December 31, 2014 |
13 | 7 | 20 | ||||||
Changes due to office consolidation and offshore divestiture |
1 | 46 | 47 | ||||||
Changes due to Canadian divestitures |
(1) | 10 | 9 | ||||||
Balance as of December 31, 2015 |
$ |
13 |
$ |
63 |
$ |
76 |
|
Year Ended December 31, |
|||||||||
2015 |
2014 |
2013 |
|||||||
(Millions) |
|||||||||
Current income tax expense (benefit): |
|||||||||
U.S. federal |
$ |
(243) |
$ |
152 |
$ |
73 | |||
Various states |
(8) | 18 | (5) | ||||||
Canada and various provinces |
14 | 307 | 4 | ||||||
Total current tax expense (benefit) |
(237) | 477 | 72 | ||||||
Deferred income tax expense (benefit): |
|||||||||
U.S. federal |
(5,033) | 1,610 | 198 | ||||||
Various states |
(336) | 93 | 59 | ||||||
Canada and various provinces |
(459) | 188 | (160) | ||||||
Total deferred tax expense (benefit) |
(5,828) | 1,891 | 97 | ||||||
Total income tax expense (benefit) |
$ |
(6,065) |
$ |
2,368 |
$ |
169 |
Year Ended December 31, |
|||||||||
2015 |
2014 |
2013 |
|||||||
Total income tax expense (benefit) (millions) |
$ |
(6,065) |
$ |
2,368 |
$ |
169 | |||
U.S. statutory income tax rate |
(35)% |
35% | 35% | ||||||
Non-deductible goodwill and intangible impairment |
2% | 23% | 0% | ||||||
Taxation on Canadian operations |
1% |
(4)% |
9% | ||||||
State income taxes |
(1)% |
2% | 23% | ||||||
Repatriations |
0% | 2% | 65% | ||||||
Deferred tax asset valuation allowance |
4% | 0% | 0% | ||||||
Other |
0% | 0% |
(19)% |
||||||
Effective income tax rate |
(29)% |
58% | 113% |
December 31, |
||||||
2015 |
2014 |
|||||
Deferred tax assets: |
(Millions) |
|||||
Property and equipment |
$ |
490 |
$ |
- |
||
Asset retirement obligations |
485 | 458 | ||||
Accrued liabilities |
160 | 150 | ||||
Net operating loss carryforwards |
175 | 200 | ||||
Pension benefit obligations |
106 | 113 | ||||
Other |
162 | 180 | ||||
Total deferred tax assets before valuation allowance |
1,578 | 1,101 | ||||
Less: valuation allowance |
(967) |
- |
||||
Net deferred tax assets |
611 | 1,101 | ||||
Deferred tax liabilities: |
||||||
Property and equipment |
(1,187) | (6,940) | ||||
Fair value of financial instruments |
- |
(699) | ||||
Long-term debt |
(36) | (115) | ||||
Other |
(271) | (160) | ||||
Total deferred tax liabilities |
(1,494) | (7,914) | ||||
Net deferred tax liability |
$ |
(883) |
$ |
(6,813) |
December 31, |
||||||
2015 |
2014 |
|||||
(Millions) |
||||||
Balance at beginning of year |
$ |
241 |
$ |
243 | ||
Tax positions taken in prior periods |
(19) |
- |
||||
Tax positions taken in current year |
31 |
- |
||||
Accrual of interest related to tax positions taken |
(5) | 2 | ||||
Settlements |
(108) |
- |
||||
Foreign currency translation |
(9) | (4) | ||||
Balance at end of year |
$ |
131 |
$ |
241 |
Jurisdiction |
Tax Years Open |
|
U.S. Federal |
2008-2015 |
|
Various U.S. states |
2008-2015 |
|
Canada Federal |
2003-2015 |
|
Various Canadian provinces |
2003-2015 |
|
Year Ended December 31, |
|||||||||
2015 |
2014 |
2013 |
|||||||
(Millions) |
|||||||||
Foreign currency translation: |
|||||||||
Beginning accumulated foreign currency translation |
$ |
983 |
$ |
1,448 |
$ |
1,996 | |||
Change in cumulative translation adjustment |
(621) | (499) | (574) | ||||||
Income tax benefit |
62 | 34 | 26 | ||||||
Ending accumulated foreign currency translation |
424 | 983 | 1,448 | ||||||
Pension and postretirement benefit plans: |
|||||||||
Beginning accumulated pension and postretirement benefits |
(204) | (180) | (225) | ||||||
Net actuarial gain (loss) and prior service cost arising in current year |
(5) | (57) | 48 | ||||||
Recognition of net actuarial loss and prior service cost in earnings (1) |
21 | 20 | 24 | ||||||
Income tax benefit (expense) |
(6) | 13 | (27) | ||||||
Ending accumulated pension and postretirement benefits |
(194) | (204) | (180) | ||||||
Accumulated other comprehensive earnings, net of tax |
$ |
230 |
$ |
779 |
$ |
1,268 |
____________________________
|
Year Ended December 31, |
|||||||||
2015 |
2014 |
2013 |
|||||||
(Millions) |
|||||||||
Net change in working capital accounts: |
|||||||||
Accounts receivable |
$ |
942 |
$ |
128 |
$ |
(288) | |||
Income taxes receivable |
384 | (467) | 29 | ||||||
Other current assets |
(57) | (222) | 20 | ||||||
Accounts payable |
(190) | (68) | 26 | ||||||
Revenues and royalties payable |
(526) | 133 | 35 | ||||||
Income taxes payable |
(275) | 30 |
- |
||||||
Other current liabilities |
(579) | 516 | (120) | ||||||
Net change in working capital |
$ |
(301) |
$ |
50 |
$ |
(298) | |||
Interest paid (net of capitalized interest) |
$ |
494 |
$ |
514 |
$ |
406 | |||
Income taxes paid (received) |
$ |
(279) |
$ |
899 |
$ |
13 |
|
December 31, 2015 |
December 31, 2014 |
|||||
(Millions) |
||||||
Oil, gas and NGL sales |
$ |
362 |
$ |
723 | ||
Joint interest billings |
211 | 475 | ||||
Marketing and midstream revenues |
520 | 706 | ||||
Other |
30 | 71 | ||||
Gross accounts receivable |
1,123 | 1,975 | ||||
Allowance for doubtful accounts |
(18) | (16) | ||||
Net accounts receivable |
$ |
1,105 |
$ |
1,959 |
|
U.S. |
Canada |
EnLink |
Total |
|||||||||
(Millions) |
||||||||||||
Balance as of December 31, 2013 |
$ |
2,618 |
$ |
2,838 |
$ |
402 |
$ |
5,858 | ||||
Acquired during period |
- |
- |
3,283 | 3,283 | ||||||||
Asset divestitures |
- |
(706) |
- |
(706) | ||||||||
Impairment |
- |
(1,941) |
- |
(1,941) | ||||||||
Foreign currency translation adjustments |
- |
(191) |
- |
(191) | ||||||||
Balance as of December 31, 2014 |
$ |
2,618 |
$ |
- |
$ |
3,685 |
$ |
6,303 | ||||
Acquired during period |
- |
- |
57 | 57 | ||||||||
Impairment |
- |
- |
(1,328) | (1,328) | ||||||||
Balance as of December 31, 2015 |
$ |
2,618 |
$ |
- |
$ |
2,414 |
$ |
5,032 | ||||
December 31, 2015 |
December 31, 2014 |
||||
(Millions) |
|||||
Customer relationships |
$ |
745 |
$ |
569 | |
Accumulated amortization |
(55) | (36) | |||
Net intangibles |
$ |
690 |
$ |
533 |
Texas |
Louisiana |
Oklahoma |
Crude and Condensate |
General Partner |
Total |
|||||||||||||
(Millions) |
||||||||||||||||||
Balance as of December 31, 2013 |
$ |
326 |
$ |
- |
$ |
76 |
$ |
- |
$ |
- |
$ |
402 | ||||||
Acquired during period |
842 | 787 | 114 | 113 | 1,427 | 3,283 | ||||||||||||
Balance as of December 31, 2014 |
$ |
1,168 |
$ |
787 |
$ |
190 |
$ |
113 |
$ |
1,427 |
$ |
3,685 | ||||||
Acquired during period |
28 |
- |
- |
29 |
- |
57 | ||||||||||||
Impairment |
(492) | (787) |
- |
(49) |
- |
(1,328) | ||||||||||||
Balance as of December 31, 2015 |
$ |
704 |
$ |
- |
$ |
190 |
$ |
93 |
$ |
1,427 |
$ |
2,414 |
|
December 31, 2015 |
December 31, 2014 |
||||
(Millions) |
|||||
Devon debt |
|||||
Commercial paper |
$ |
626 |
$ |
932 | |
Floating rate due December 15, 2015 |
- |
500 | |||
Floating rate due December 15, 2016 |
350 | 350 | |||
8.25% due July 1, 2018 |
125 | 125 | |||
2.25% due December 15, 2018 |
750 | 750 | |||
6.30% due January 15, 2019 |
700 | 700 | |||
4.00% due July 15, 2021 |
500 | 500 | |||
3.25% due May 15, 2022 |
1,000 | 1,000 | |||
5.85% due December 15, 2025 |
850 |
- |
|||
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 | 750 | |||
5.00% due June 15, 2045 |
750 |
- |
|||
Net discount on debentures and notes |
(28) | (18) | |||
Total Devon debt |
10,023 | 9,239 | |||
EnLink debt |
|||||
Credit facilities |
414 | 237 | |||
2.70% due April 1, 2019 |
400 | 400 | |||
7.125% due June 1, 2022 |
163 | 163 | |||
4.40% due April 1, 2024 |
550 | 550 | |||
4.15% due June 1, 2025 |
750 |
- |
|||
5.60% due April 1, 2044 |
350 | 350 | |||
5.05% due April 1, 2045 |
450 | 300 | |||
Net premium on debentures and notes |
13 | 23 | |||
Total EnLink debt |
3,090 | 2,023 | |||
Total debt |
13,113 | 11,262 | |||
Less amount classified as short-term debt (1) |
976 | 1,432 | |||
Total long-term debt |
$ |
12,137 |
$ |
9,830 |
__________________________
2016 |
$ |
976 |
2017 |
- |
|
2018 |
875 | |
2019 |
1,100 | |
2020 |
414 | |
Thereafter |
9,763 | |
Total |
$ |
13,128 |
Fair Value of Debt Assumed |
Effective Rate of Debt Assumed |
||||
Debt Assumed |
(Millions) |
||||
8.25% due July 2018 (principal of $125 million) |
$ |
147 | 5.5% | ||
7.50% due September 2027 (principal of $150 million) |
$ |
169 | 6.5% |
Year Ended December 31, |
||||||||
2015 |
2014 |
2013 |
||||||
(Millions) |
||||||||
Interest based on debt outstanding |
$ |
565 |
$ |
532 |
$ |
466 | ||
Early retirement of debt |
- |
48 |
- |
|||||
Capitalized interest |
(62) | (70) | (56) | |||||
Other fees and expenses |
20 | 26 | 27 | |||||
Interest expense |
523 | 536 | 437 | |||||
Interest income |
(6) | (10) | (20) | |||||
Net financing costs |
$ |
517 |
$ |
526 |
$ |
417 |
Date Issued |
|||||||||||
May 2012 |
July 2011 |
January 2009 |
March 2002 |
||||||||
3.25% due May 15, 2022 |
$ |
1,000 |
$ |
- |
$ |
- |
$ |
- |
|||
4.75% due May 15, 2042 |
750 |
- |
- |
- |
|||||||
4.00% due July 15, 2021 |
- |
500 |
- |
- |
|||||||
5.60% due July 15, 2041 |
- |
1,250 |
- |
- |
|||||||
6.30% due January 15, 2019 |
- |
- |
700 |
- |
|||||||
7.95% due April 15, 2032 |
- |
- |
- |
1,000 | |||||||
Discount and issuance costs |
(28) | (24) | (8) | (14) | |||||||
Net proceeds |
$ |
1,722 |
$ |
1,726 |
$ |
692 |
$ |
986 |
March 7, 2014 Fair Value of Debt |
Effective |
|||
(Millions) |
||||
8.875% due February 2018 (principal of $725 million) (1) |
$ |
760 |
7.7% |
|
7.125% due June 2022 (principal of $197 million) |
226 |
5.3% |
||
Credit facilities |
468 | |||
Total long-term debt |
$ |
1,454 |
__________________________
(1) The 2018 senior notes were redeemed on April 18, 2014.
|
Year Ended December 31, |
||||||
2015 |
2014 |
|||||
(Millions) |
||||||
Asset retirement obligations as of beginning of period |
$ |
1,399 |
$ |
2,228 | ||
Liabilities incurred |
63 | 97 | ||||
Liabilities settled and divested (1) |
(89) | (1,009) | ||||
Revision of estimated obligation |
62 | 70 | ||||
Accretion expense on discounted obligation |
75 | 89 | ||||
Foreign currency translation adjustment |
(96) | (76) | ||||
Asset retirement obligations as of end of period |
1,414 | 1,399 | ||||
Less current portion |
44 | 60 | ||||
Asset retirement obligations, long-term |
$ |
1,370 |
$ |
1,339 |
__________________________
(1) During 2014, Devon reduced its asset retirement obligation by $953 million for those obligations that were assumed by purchasers of Devon’s Canadian and U.S. divested oil and gas properties.
|
Pension Benefits |
Postretirement Benefits |
|||||||||||
2015 |
2014 |
2015 |
2014 |
|||||||||
(Millions) |
||||||||||||
Change in benefit obligation: |
||||||||||||
Benefit obligation at beginning of year |
$ |
1,377 |
$ |
1,177 |
$ |
24 |
$ |
24 | ||||
Service cost |
33 | 30 | 1 | 1 | ||||||||
Interest cost |
52 | 55 | 1 | 1 | ||||||||
Actuarial loss (gain) |
(68) | 203 | (2) |
- |
||||||||
Plan amendments |
- |
- |
1 |
- |
||||||||
Plan settlements |
- |
(4) |
- |
- |
||||||||
Foreign exchange rate changes |
(6) | (3) |
- |
- |
||||||||
Participant contributions |
- |
- |
2 | 2 | ||||||||
Benefits paid |
(80) | (81) | (4) | (4) | ||||||||
Benefit obligation at end of year |
1,308 | 1,377 | 23 | 24 | ||||||||
Change in plan assets: |
||||||||||||
Fair value of plan assets at beginning of year |
1,149 | 1,006 |
- |
- |
||||||||
Actual return on plan assets |
(16) | 200 |
- |
- |
||||||||
Employer contributions |
11 | 29 | 2 | 2 | ||||||||
Participant contributions |
- |
- |
2 | 2 | ||||||||
Plan settlements |
- |
(4) |
- |
- |
||||||||
Benefits paid |
(80) | (81) | (4) | (4) | ||||||||
Foreign exchange rate changes |
(5) | (1) |
- |
- |
||||||||
Fair value of plan assets at end of year |
1,059 | 1,149 |
- |
- |
||||||||
Funded status at end of year |
$ |
(249) |
$ |
(228) |
$ |
(23) |
$ |
(24) | ||||
Amounts recognized in balance sheet: |
||||||||||||
Other long-term assets |
$ |
2 |
$ |
22 |
$ |
- |
$ |
- |
||||
Other current liabilities |
(12) | (10) | (3) | (3) | ||||||||
Other long-term liabilities |
(239) | (240) | (20) | (21) | ||||||||
Net amount |
$ |
(249) |
$ |
(228) |
$ |
(23) |
$ |
(24) | ||||
Amounts recognized in accumulated other comprehensive earnings: |
||||||||||||
Net actuarial loss (gain) |
$ |
302 |
$ |
317 |
$ |
(11) |
$ |
(11) | ||||
Prior service cost (credit) |
14 | 19 | (6) | (9) | ||||||||
Total |
$ |
316 |
$ |
336 |
$ |
(17) |
$ |
(20) |
December 31, |
||||||
2015 |
2014 |
|||||
(Millions) |
||||||
Projected benefit obligation |
$ |
244 |
$ |
250 | ||
Accumulated benefit obligation |
$ |
199 |
$ |
191 | ||
Fair value of plan assets |
$ |
- |
$ |
- |
Pension Benefits |
Postretirement Benefits |
|||||||||||||||||
2015 |
2014 |
2013 |
2015 |
2014 |
2013 |
|||||||||||||
(Millions) |
||||||||||||||||||
Net periodic benefit cost: |
||||||||||||||||||
Service cost |
$ |
33 |
$ |
30 |
$ |
36 |
$ |
1 |
$ |
1 |
$ |
1 | ||||||
Interest cost |
52 | 55 | 51 | 1 | 1 | 1 | ||||||||||||
Expected return on plan assets |
(58) | (54) | (62) |
- |
- |
- |
||||||||||||
Curtailment and settlement expense |
- |
1 |
- |
- |
- |
- |
||||||||||||
Recognition of net actuarial loss (gain) (1) |
20 | 18 | 22 | (1) | (1) | (1) | ||||||||||||
Recognition of prior service cost (1) |
4 | 4 | 4 | (2) | (2) | (1) | ||||||||||||
Total net periodic benefit cost (2) |
51 | 54 | 51 | (1) | (1) |
- |
||||||||||||
Other comprehensive loss (earnings): |
||||||||||||||||||
Actuarial loss (gain) arising in current year |
5 | 57 | (39) | (1) |
- |
(3) | ||||||||||||
Prior service cost (credit) arising in current year |
- |
- |
2 | 1 |
- |
(8) | ||||||||||||
Recognition of net actuarial loss, including settlement |
||||||||||||||||||
expense, in net periodic benefit cost |
(20) | (19) | (22) | 1 | 1 | 1 | ||||||||||||
Recognition of prior service cost, including curtailment, |
||||||||||||||||||
in net periodic benefit cost |
(4) | (4) | (4) | 1 | 2 | 1 | ||||||||||||
Total other comprehensive loss (earnings) |
(19) | 34 | (63) | 2 | 3 | (9) | ||||||||||||
Total recognized |
$ |
32 |
$ |
88 |
$ |
(12) |
$ |
1 |
$ |
2 |
$ |
(9) |
__________________________
(1) These net periodic benefit costs were reclassified out of other comprehensive earnings in the current period.
(2) Net periodic benefit cost is a component of G&A on the accompanying consolidated comprehensive statements of earnings.
Pension Benefits |
Postretirement Benefits |
|||||
(Millions) |
||||||
Net actuarial loss (gain) |
$ |
22 |
$ |
(2) | ||
Prior service cost (credit) |
4 | (1) | ||||
Total |
$ |
26 |
$ |
(3) |
Pension Benefits |
Postretirement Benefits |
|||||||||||||||||
2015 |
2014 |
2013 |
2015 |
2014 |
2013 |
|||||||||||||
Assumptions to determine benefit obligations: |
||||||||||||||||||
Discount rate |
4.25% |
3.90% |
4.80% |
3.63% |
3.25% |
3.65% |
||||||||||||
Rate of compensation increase |
4.49% |
4.49% |
4.48% |
N/A |
N/A |
N/A |
||||||||||||
Assumptions to determine net periodic benefit cost: |
||||||||||||||||||
Discount rate |
3.90% |
4.80% |
3.85% |
3.25% |
3.65% |
3.30% |
||||||||||||
Rate of compensation increase |
4.49% |
4.49% |
4.48% |
N/A |
N/A |
N/A |
||||||||||||
Expected return on plan assets |
5.22% |
5.42% |
5.48% |
N/A |
N/A |
N/A |
December 31, 2015 |
|||||||||||||||
Fair Value Measurements Using: |
|||||||||||||||
Actual Allocation |
Total |
Level 1 Inputs |
Level 2 Inputs |
Level 3 Inputs |
|||||||||||
(Millions) |
|||||||||||||||
Fixed-income securities: |
|||||||||||||||
U.S. Treasury obligations |
17% |
$ |
179 |
$ |
88 |
$ |
91 |
$ |
- |
||||||
Corporate bonds |
48% | 507 | 371 | 136 |
- |
||||||||||
Other bonds |
3% | 35 | 35 |
- |
- |
||||||||||
Total fixed-income securities |
68% | 721 | 494 | 227 |
- |
||||||||||
Equity securities: |
|||||||||||||||
Global (large, mid, small cap) |
18% | 186 |
- |
186 |
- |
||||||||||
Other securities: |
|||||||||||||||
Hedge fund and alternative investments |
11% | 120 |
- |
- |
120 | ||||||||||
Short-term investments |
3% | 32 | 6 | 26 |
- |
||||||||||
Total other securities |
14% | 152 | 6 | 26 | 120 | ||||||||||
Total investments |
100% |
$ |
1,059 |
$ |
500 |
$ |
439 |
$ |
120 |
December 31, 2014 |
|||||||||||||||
Fair Value Measurements Using: |
|||||||||||||||
Actual Allocation |
Total |
Level 1 Inputs |
Level 2 Inputs |
Level 3 Inputs |
|||||||||||
(Millions) |
|||||||||||||||
Fixed-income securities: |
|||||||||||||||
U.S. Treasury obligations |
35% |
$ |
405 |
$ |
50 |
$ |
355 |
$ |
- |
||||||
Corporate bonds |
32% | 364 | 269 | 95 |
- |
||||||||||
Other bonds |
3% | 30 | 30 |
- |
- |
||||||||||
Total fixed-income securities |
70% | 799 | 349 | 450 |
- |
||||||||||
Equity securities: |
|||||||||||||||
Global (large, mid, small cap) |
17% | 197 |
- |
197 |
- |
||||||||||
Other securities: |
|||||||||||||||
Hedge fund and alternative investments |
10% | 112 |
- |
- |
112 | ||||||||||
Short-term investments |
3% | 41 | 15 | 26 |
- |
||||||||||
Total other securities |
13% | 153 | 15 | 26 | 112 | ||||||||||
Total investments |
100% |
$ |
1,149 |
$ |
364 |
$ |
673 |
$ |
112 |
December 31, 2013 |
$ |
112 | |
Disbursements |
(6) | ||
Investment returns |
6 | ||
December 31, 2014 |
112 | ||
Purchases |
5 | ||
Investment returns |
3 | ||
December 31, 2015 |
$ |
120 |
Pension Benefits |
Postretirement Benefits |
|||||
(Millions) |
||||||
Devon's 2016 contributions |
$ |
12 |
$ |
3 | ||
Benefit payments: |
||||||
2016 |
$ |
73 |
$ |
3 | ||
2017 |
$ |
75 |
$ |
3 | ||
2018 |
$ |
77 |
$ |
3 | ||
2019 |
$ |
78 |
$ |
3 | ||
2020 |
$ |
83 |
$ |
2 | ||
2021 to 2025 |
$ |
446 |
$ |
7 |
Year Ended December 31, |
|||||||||
2015 |
2014 |
2013 |
|||||||
(Millions) |
|||||||||
401(k) and enhanced contribution plans |
$ |
63 |
$ |
49 |
$ |
41 |
|||
Canadian pension and savings plans |
16 |
20 |
26 |
||||||
Total |
$ |
79 |
$ |
69 |
$ |
67 |
December 31, |
||||||
2015 |
2014 |
|||||
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 |
||||
(Millions) |
||||||||
2016 |
$ 557 |
$ 69 |
$ 994 |
$ 70 |
||||
2017 |
703 | 51 | 972 | 58 | ||||
2018 |
791 | 34 | 936 | 76 | ||||
2019 |
803 | 5 | 402 | 68 | ||||
2020 |
845 | 2 | 255 | 42 | ||||
Thereafter |
206 | 28 | 1,042 | 129 | ||||
Total |
$ 3,905 |
$ 189 |
$ 4,601 |
$ 443 |
|
Fair Value Measurements Using: |
||||||||||||||||
Carrying |
Total Fair |
Level 1 |
Level 2 |
Level 3 |
||||||||||||
Amount |
Value |
Inputs |
Inputs |
Inputs |
||||||||||||
(Millions) |
||||||||||||||||
December 31, 2015 assets (liabilities): |
||||||||||||||||
Cash equivalents |
$ |
1,871 |
$ |
1,871 |
$ |
1,471 |
$ |
400 |
$ |
- |
||||||
Commodity derivatives |
$ |
35 |
$ |
35 |
$ |
- |
$ |
35 |
$ |
- |
||||||
Commodity derivatives |
$ |
(18) |
$ |
(18) |
$ |
- |
$ |
(18) |
$ |
- |
||||||
Interest rate derivatives |
$ |
2 |
$ |
2 |
$ |
- |
$ |
2 |
$ |
- |
||||||
Interest rate derivatives |
$ |
(22) |
$ |
(22) |
$ |
- |
$ |
(22) |
$ |
- |
||||||
Foreign currency derivatives |
$ |
8 |
$ |
8 |
$ |
- |
$ |
8 |
$ |
- |
||||||
Foreign currency derivatives |
$ |
(8) |
$ |
(8) |
$ |
- |
$ |
(8) |
$ |
- |
||||||
Debt |
$ |
(13,113) |
$ |
(11,927) |
$ |
- |
$ |
(11,927) |
$ |
- |
||||||
Capital lease obligations |
$ |
(17) |
$ |
(16) |
$ |
- |
$ |
(16) |
$ |
- |
||||||
December 31, 2014 assets (liabilities): |
||||||||||||||||
Cash equivalents |
$ |
950 |
$ |
950 |
$ |
340 |
$ |
610 |
$ |
- |
||||||
Commodity derivatives |
$ |
1,995 |
$ |
1,995 |
$ |
- |
$ |
1,995 |
$ |
- |
||||||
Commodity derivatives |
$ |
(56) |
$ |
(56) |
$ |
- |
$ |
(56) |
$ |
- |
||||||
Interest rate derivatives |
$ |
1 |
$ |
1 |
$ |
- |
$ |
1 |
$ |
- |
||||||
Interest rate derivatives |
$ |
(1) |
$ |
(1) |
$ |
- |
$ |
(1) |
$ |
- |
||||||
Foreign currency derivatives |
$ |
8 |
$ |
8 |
$ |
- |
$ |
8 |
$ |
- |
||||||
Debt |
$ |
(11,262) |
$ |
(12,472) |
$ |
- |
$ |
(12,472) |
$ |
- |
||||||
Capital lease obligations |
$ |
(20) |
$ |
(20) |
$ |
- |
$ |
(20) |
$ |
- |
|
U.S.(1) |
Canada |
EnLink(1) |
Eliminations |
Total |
|||||||||||
(Millions) |
|||||||||||||||
Year Ended December 31, 2015: |
|||||||||||||||
Revenues from external customers |
$ |
8,360 |
$ |
1,012 |
$ |
3,773 |
$ |
- |
$ |
13,145 | |||||
Intersegment revenues |
$ |
- |
$ |
- |
$ |
679 |
$ |
(679) |
$ |
- |
|||||
Depreciation, depletion and amortization |
$ |
2,220 |
$ |
522 |
$ |
387 |
$ |
- |
$ |
3,129 | |||||
Asset impairments |
$ |
18,000 |
$ |
1,257 |
$ |
1,563 |
$ |
- |
$ |
20,820 | |||||
Interest expense |
$ |
368 |
$ |
94 |
$ |
107 |
$ |
(46) |
$ |
523 | |||||
Loss before income taxes |
$ |
(18,214) |
$ |
(1,670) |
$ |
(1,384) |
$ |
- |
$ |
(21,268) | |||||
Income tax expense (benefit) |
$ |
(5,650) |
$ |
(445) |
$ |
30 |
$ |
- |
$ |
(6,065) | |||||
Net loss |
$ |
(12,564) |
$ |
(1,225) |
$ |
(1,414) |
$ |
- |
$ |
(15,203) | |||||
Net earnings (loss) attributable to noncontrolling interests |
$ |
1 |
$ |
- |
$ |
(750) |
$ |
- |
$ |
(749) | |||||
Net loss attributable to Devon |
$ |
(12,565) |
$ |
(1,225) |
$ |
(664) |
$ |
- |
$ |
(14,454) | |||||
Property and equipment, net |
$ |
8,811 |
$ |
4,590 |
$ |
5,667 |
$ |
- |
$ |
19,068 | |||||
Total assets |
$ |
14,600 |
$ |
5,464 |
$ |
9,565 |
$ |
(97) |
$ |
29,532 | |||||
Capital expenditures |
$ |
4,575 |
$ |
680 |
$ |
978 |
$ |
- |
$ |
6,233 | |||||
Year Ended December 31, 2014: |
|||||||||||||||
Revenues from external customers |
$ |
14,854 |
$ |
2,063 |
$ |
2,649 |
$ |
- |
$ |
19,566 | |||||
Intersegment revenues |
$ |
- |
$ |
- |
$ |
859 |
$ |
(859) |
$ |
- |
|||||
Depreciation, depletion and amortization |
$ |
2,475 |
$ |
560 |
$ |
284 |
$ |
- |
$ |
3,319 | |||||
Asset impairments |
$ |
12 |
$ |
1,941 |
$ |
- |
$ |
- |
$ |
1,953 | |||||
Gains and losses on asset sales |
$ |
5 |
$ |
(1,077) |
$ |
- |
$ |
- |
$ |
(1,072) | |||||
Interest expense |
$ |
441 |
$ |
85 |
$ |
54 |
$ |
(44) |
$ |
536 | |||||
Earnings (loss) before income taxes |
$ |
4,390 |
$ |
(657) |
$ |
326 |
$ |
- |
$ |
4,059 | |||||
Income tax expense |
$ |
1,797 |
$ |
495 |
$ |
76 |
$ |
- |
$ |
2,368 | |||||
Net earnings (loss) |
$ |
2,593 |
$ |
(1,152) |
$ |
250 |
$ |
- |
$ |
1,691 | |||||
Net earnings attributable to noncontrolling interests |
$ |
1 |
$ |
- |
$ |
83 |
$ |
- |
$ |
84 | |||||
Net earnings (loss) attributable to Devon |
$ |
2,592 |
$ |
(1,152) |
$ |
167 |
$ |
- |
$ |
1,607 | |||||
Property and equipment, net |
$ |
24,463 |
$ |
6,790 |
$ |
5,043 |
$ |
- |
$ |
36,296 | |||||
Total assets |
$ |
32,037 |
$ |
8,517 |
$ |
10,207 |
$ |
(124) |
$ |
50,637 | |||||
Capital expenditures |
$ |
11,214 |
$ |
1,344 |
$ |
1,001 |
$ |
- |
$ |
13,559 | |||||
Year Ended December 31, 2013: |
|||||||||||||||
Revenues from external customers |
$ |
6,807 |
$ |
2,656 |
$ |
934 |
$ |
- |
$ |
10,397 | |||||
Intersegment revenues |
$ |
- |
$ |
- |
$ |
1,362 |
$ |
(1,362) |
$ |
- |
|||||
Depreciation, depletion and amortization |
$ |
1,744 |
$ |
849 |
$ |
187 |
$ |
- |
$ |
2,780 | |||||
Asset impairments |
$ |
1,133 |
$ |
843 |
$ |
- |
$ |
- |
$ |
1,976 | |||||
Interest expense |
$ |
392 |
$ |
80 |
$ |
- |
$ |
(35) |
$ |
437 | |||||
Earnings (loss) before income taxes |
$ |
495 |
$ |
(532) |
$ |
186 |
$ |
- |
$ |
149 | |||||
Income tax expense (benefit) |
$ |
258 |
$ |
(156) |
$ |
67 |
$ |
- |
$ |
169 | |||||
Net earnings (loss) |
$ |
237 |
$ |
(376) |
$ |
119 |
$ |
- |
$ |
(20) | |||||
Property and equipment, net |
$ |
18,201 |
$ |
8,478 |
$ |
1,768 |
$ |
- |
$ |
28,447 | |||||
Total assets |
$ |
27,080 |
$ |
13,560 |
$ |
2,237 |
$ |
- |
$ |
42,877 | |||||
Capital expenditures |
$ |
4,589 |
$ |
1,841 |
$ |
213 |
$ |
- |
$ |
6,643 |
__________________________
|
Year Ended December 31, 2015 |
|||||||||
U.S. |
Canada |
Total |
|||||||
(Millions) |
|||||||||
Property acquisition costs: |
|||||||||
Proved properties |
$ |
193 |
$ |
2 |
$ |
195 | |||
Unproved properties |
634 | 83 | 717 | ||||||
Exploration costs |
478 | 109 | 587 | ||||||
Development costs |
3,269 | 402 | 3,671 | ||||||
Costs incurred |
$ |
4,574 |
$ |
596 |
$ |
5,170 | |||
Year Ended December 31, 2014 |
|||||||||
U.S. |
Canada |
Total |
|||||||
(Millions) |
|||||||||
Property acquisition costs: |
|||||||||
Proved properties |
$ |
5,210 |
$ |
- |
$ |
5,210 | |||
Unproved properties |
1,176 | 1 | 1,177 | ||||||
Exploration costs |
270 | 52 | 322 | ||||||
Development costs |
4,400 | 1,063 | 5,463 | ||||||
Costs incurred |
$ |
11,056 |
$ |
1,116 |
$ |
12,172 | |||
Year Ended December 31, 2013 |
|||||||||
U.S. |
Canada |
Total |
|||||||
(Millions) |
|||||||||
Property acquisition costs: |
|||||||||
Proved properties |
$ |
19 |
$ |
3 |
$ |
22 | |||
Unproved properties |
213 | 3 | 216 | ||||||
Exploration costs |
443 | 152 | 595 | ||||||
Development costs |
3,838 | 1,251 | 5,089 | ||||||
Costs incurred |
$ |
4,513 |
$ |
1,409 |
$ |
5,922 |
December 31, 2015 |
|||||||||
U.S. |
Canada |
Total |
|||||||
(Millions) |
|||||||||
Proved properties |
$ |
64,443 |
$ |
13,747 |
$ |
78,190 | |||
Unproved properties |
1,352 | 1,232 | 2,584 | ||||||
Total oil and gas properties |
65,795 | 14,979 | 80,774 | ||||||
Accumulated DD&A |
(58,312) | (11,185) | (69,497) | ||||||
Net capitalized costs |
$ |
7,483 |
$ |
3,794 |
$ |
11,277 | |||
December 31, 2014 |
|||||||||
U.S. |
Canada |
Total |
|||||||
(Millions) |
|||||||||
Proved properties |
$ |
59,849 |
$ |
15,889 |
$ |
75,738 | |||
Unproved properties |
1,460 | 1,292 | 2,752 | ||||||
Total oil and gas properties |
61,309 | 17,181 | 78,490 | ||||||
Accumulated DD&A |
(38,213) | (11,347) | (49,560) | ||||||
Net capitalized costs |
$ |
23,096 |
$ |
5,834 |
$ |
28,930 |
Costs Incurred In |
|||||||||||||||
2015 |
2014 |
2013 |
Prior to 2013 |
Total |
|||||||||||
(Millions) |
|||||||||||||||
Acquisition costs |
$ |
672 |
$ |
412 |
$ |
61 |
$ |
510 |
$ |
1,655 | |||||
Exploration costs |
191 | 132 | 69 | 170 | 562 | ||||||||||
Development costs |
9 | 28 | 17 | 128 | 182 | ||||||||||
Capitalized interest |
50 | 37 | 32 | 66 | 185 | ||||||||||
Total oil and gas properties not subject to amortization |
$ |
922 |
$ |
609 |
$ |
179 |
$ |
874 |
$ |
2,584 |
December 31, 2015 |
|||||||||
U.S. |
Canada |
Total |
|||||||
(Millions) |
|||||||||
Oil, gas and NGL sales |
$ |
4,356 |
$ |
1,026 |
$ |
5,382 | |||
Lease operating expenses |
(1,551) | (553) | (2,104) | ||||||
General and administrative expenses |
(196) | (28) | (224) | ||||||
Production and property taxes |
(309) | (33) | (342) | ||||||
Depreciation, depletion and amortization |
(2,107) | (474) | (2,581) | ||||||
Asset impairments |
(17,992) | (1,257) | (19,249) | ||||||
Accretion of asset retirement obligations |
(47) | (27) | (74) | ||||||
Income tax benefit |
5,547 | 314 | 5,861 | ||||||
Results of operations |
$ |
(12,299) |
$ |
(1,032) |
$ |
(13,331) | |||
Depreciation, depletion and amortization per Boe |
$ |
10.21 |
$ |
11.30 |
$ |
10.40 | |||
December 31, 2014 |
|||||||||
U.S. |
Canada |
Total |
|||||||
(Millions) |
|||||||||
Oil, gas and NGL sales |
$ |
7,867 |
$ |
2,043 |
$ |
9,910 | |||
Lease operating expenses |
(1,559) | (773) | (2,332) | ||||||
General and administrative expenses |
(153) | (57) | (210) | ||||||
Production and property taxes |
(466) | (37) | (503) | ||||||
Depreciation, depletion and amortization |
(2,365) | (531) | (2,896) | ||||||
Gain on sale of assets |
- |
1,077 | 1,077 | ||||||
Accretion of asset retirement obligations |
(49) | (39) | (88) | ||||||
Income tax expense |
(1,199) | (568) | (1,767) | ||||||
Results of operations (1) |
$ |
2,076 |
$ |
1,115 |
$ |
3,191 | |||
Depreciation, depletion and amortization per Boe |
$ |
11.41 |
$ |
13.80 |
$ |
11.79 | |||
December 31, 2013 |
|||||||||
U.S. |
Canada |
Total |
|||||||
(Millions) |
|||||||||
Oil, gas and NGL sales |
$ |
5,964 |
$ |
2,558 |
$ |
8,522 | |||
Lease operating expenses |
(1,257) | (1,011) | (2,268) | ||||||
General and administrative expenses |
(125) | (77) | (202) | ||||||
Production and property taxes |
(380) | (59) | (439) | ||||||
Depreciation, depletion and amortization |
(1,640) | (825) | (2,465) | ||||||
Asset impairments |
(1,110) | (843) | (1,953) | ||||||
Accretion of asset retirement obligations |
(47) | (64) | (111) | ||||||
Income tax benefit (expense) |
(510) | 88 | (422) | ||||||
Results of operations |
$ |
895 |
$ |
(233) |
$ |
662 | |||
Depreciation, depletion and amortization per Boe |
$ |
8.69 |
$ |
12.87 |
$ |
9.75 |
__________________________
(1) During 2014, Devon recognized a Canadian goodwill impairment, which is not reflected in these tables. See Note 5 for additional information.
Oil (MMBbls) |
|||||||||
U.S. |
Canada |
Total |
|||||||
Proved developed and undeveloped reserves: |
|||||||||
December 31, 2012 |
205 | 65 | 270 | ||||||
Revisions due to prices |
1 | (1) |
- |
||||||
Revisions other than price |
(18) |
- |
(18) | ||||||
Extensions and discoveries |
69 | 7 | 76 | ||||||
Purchase of reserves |
1 |
- |
1 | ||||||
Production |
(28) | (15) | (43) | ||||||
Sale of reserves |
(1) |
- |
(1) | ||||||
December 31, 2013 |
229 | 56 | 285 | ||||||
Revisions due to prices |
(1) |
- |
(1) | ||||||
Revisions other than price |
(38) | 1 | (37) | ||||||
Extensions and discoveries |
94 | 5 | 99 | ||||||
Purchase of reserves |
132 |
- |
132 | ||||||
Production |
(48) | (10) | (58) | ||||||
Sale of reserves |
(17) | (29) | (46) | ||||||
December 31, 2014 |
351 | 23 | 374 | ||||||
Revisions due to prices |
(53) | 4 | (49) | ||||||
Revisions other than price |
(52) | 2 | (50) | ||||||
Extensions and discoveries |
51 | 3 | 54 | ||||||
Purchase of reserves |
5 |
- |
5 | ||||||
Production |
(60) | (10) | (70) | ||||||
December 31, 2015 |
242 | 22 | 264 | ||||||
Proved developed reserves as of: |
|||||||||
December 31, 2012 |
166 | 62 | 228 | ||||||
December 31, 2013 |
194 | 56 | 250 | ||||||
December 31, 2014 |
255 | 23 | 278 | ||||||
December 31, 2015 |
203 | 22 | 225 | ||||||
Proved developed-producing reserves as of: |
|||||||||
December 31, 2012 |
155 | 56 | 211 | ||||||
December 31, 2013 |
178 | 51 | 229 | ||||||
December 31, 2014 |
224 | 19 | 243 | ||||||
December 31, 2015 |
192 | 19 | 211 | ||||||
Proved undeveloped reserves as of: |
|||||||||
December 31, 2012 |
39 | 3 | 42 | ||||||
December 31, 2013 |
35 |
- |
35 | ||||||
December 31, 2014 |
96 |
- |
96 | ||||||
December 31, 2015 |
39 |
- |
39 |
Bitumen (MMBbls) |
|||||||||
U.S. |
Canada |
Total |
|||||||
Proved developed and undeveloped reserves: |
|||||||||
December 31, 2012 |
- |
528 | 528 | ||||||
Revisions due to prices |
- |
(11) | (11) | ||||||
Revisions other than price |
- |
16 | 16 | ||||||
Extensions and discoveries |
- |
38 | 38 | ||||||
Production |
- |
(19) | (19) | ||||||
December 31, 2013 |
- |
552 | 552 | ||||||
Revisions due to prices |
- |
(37) | (37) | ||||||
Revisions other than price |
- |
18 | 18 | ||||||
Extensions and discoveries |
- |
8 | 8 | ||||||
Production |
- |
(20) | (20) | ||||||
December 31, 2014 |
- |
521 | 521 | ||||||
Revisions due to prices |
- |
103 | 103 | ||||||
Revisions other than price |
- |
(84) | (84) | ||||||
Extensions and discoveries |
- |
11 | 11 | ||||||
Production |
- |
(31) | (31) | ||||||
December 31, 2015 |
- |
520 | 520 | ||||||
Proved developed reserves as of: |
|||||||||
December 31, 2012 |
- |
99 | 99 | ||||||
December 31, 2013 |
- |
111 | 111 | ||||||
December 31, 2014 |
- |
137 | 137 | ||||||
December 31, 2015 |
- |
219 | 219 | ||||||
Proved developed-producing reserves as of: |
|||||||||
December 31, 2012 |
- |
99 | 99 | ||||||
December 31, 2013 |
- |
111 | 111 | ||||||
December 31, 2014 |
- |
137 | 137 | ||||||
December 31, 2015 |
- |
219 | 219 | ||||||
Proved undeveloped reserves as of: |
|||||||||
December 31, 2012 |
- |
429 | 429 | ||||||
December 31, 2013 |
- |
441 | 441 | ||||||
December 31, 2014 |
- |
384 | 384 | ||||||
December 31, 2015 |
- |
301 | 301 |
Gas (Bcf) |
|||||||||
U.S. |
Canada |
Total |
|||||||
Proved developed and undeveloped reserves: |
|||||||||
December 31, 2012 |
8,762 | 684 | 9,446 | ||||||
Revisions due to prices |
405 | 161 | 566 | ||||||
Revisions other than price |
(299) | 67 | (232) | ||||||
Extensions and discoveries |
471 | 19 | 490 | ||||||
Purchase of reserves |
1 |
- |
1 | ||||||
Production |
(709) | (165) | (874) | ||||||
Sale of reserves |
(81) | (8) | (89) | ||||||
December 31, 2013 |
8,550 | 758 | 9,308 | ||||||
Revisions due to prices |
191 | 45 | 236 | ||||||
Revisions other than price |
(299) | 4 | (295) | ||||||
Extensions and discoveries |
335 | 8 | 343 | ||||||
Purchase of reserves |
457 |
- |
457 | ||||||
Production |
(660) | (41) | (701) | ||||||
Sale of reserves |
(923) | (738) | (1,661) | ||||||
December 31, 2014 |
7,651 | 36 | 7,687 | ||||||
Revisions due to prices |
(1,412) | (9) | (1,421) | ||||||
Revisions other than price |
(3) | (6) | (9) | ||||||
Extensions and discoveries |
171 |
- |
171 | ||||||
Purchase of reserves |
17 |
- |
17 | ||||||
Production |
(579) | (8) | (587) | ||||||
Sale of reserves |
(37) |
- |
(37) | ||||||
December 31, 2015 |
5,808 | 13 | 5,821 | ||||||
Proved developed reserves as of: |
|||||||||
December 31, 2012 |
7,391 | 679 | 8,070 | ||||||
December 31, 2013 |
7,707 | 752 | 8,459 | ||||||
December 31, 2014 |
6,948 | 36 | 6,984 | ||||||
December 31, 2015 |
5,694 | 13 | 5,707 | ||||||
Proved developed-producing reserves as of: |
|||||||||
December 31, 2012 |
7,091 | 624 | 7,715 | ||||||
December 31, 2013 |
7,425 | 680 | 8,105 | ||||||
December 31, 2014 |
6,746 | 34 | 6,780 | ||||||
December 31, 2015 |
5,546 | 13 | 5,559 | ||||||
Proved undeveloped reserves as of: |
|||||||||
December 31, 2012 |
1,371 | 5 | 1,376 | ||||||
December 31, 2013 |
843 | 6 | 849 | ||||||
December 31, 2014 |
703 |
- |
703 | ||||||
December 31, 2015 |
114 |
- |
114 |
Natural Gas Liquids (MMBbls) |
|||||||||
U.S. |
Canada |
Total |
|||||||
Proved developed and undeveloped reserves: |
|||||||||
December 31, 2012 |
571 | 20 | 591 | ||||||
Revisions due to prices |
8 | 3 | 11 | ||||||
Revisions other than price |
(50) | 3 | (47) | ||||||
Extensions and discoveries |
64 | 1 | 65 | ||||||
Production |
(41) | (4) | (45) | ||||||
December 31, 2013 |
552 | 23 | 575 | ||||||
Revisions due to prices |
7 | 1 | 8 | ||||||
Revisions other than price |
2 |
- |
2 | ||||||
Extensions and discoveries |
47 |
- |
47 | ||||||
Purchase of reserves |
57 |
- |
57 | ||||||
Production |
(50) | (1) | (51) | ||||||
Sale of reserves |
(37) | (23) | (60) | ||||||
December 31, 2014 |
578 |
- |
578 | ||||||
Revisions due to prices |
(119) |
- |
(119) | ||||||
Revisions other than price |
(6) |
- |
(6) | ||||||
Extensions and discoveries |
24 |
- |
24 | ||||||
Purchase of reserves |
1 |
- |
1 | ||||||
Production |
(50) |
- |
(50) | ||||||
December 31, 2015 |
428 |
- |
428 | ||||||
Proved developed reserves as of: |
|||||||||
December 31, 2012 |
431 | 20 | 451 | ||||||
December 31, 2013 |
468 | 23 | 491 | ||||||
December 31, 2014 |
486 |
- |
486 | ||||||
December 31, 2015 |
411 |
- |
411 | ||||||
Proved developed-producing reserves as of: |
|||||||||
December 31, 2012 |
406 | 19 | 425 | ||||||
December 31, 2013 |
442 | 21 | 463 | ||||||
December 31, 2014 |
467 |
- |
467 | ||||||
December 31, 2015 |
393 |
- |
393 | ||||||
Proved undeveloped reserves as of: |
|||||||||
December 31, 2012 |
140 |
- |
140 | ||||||
December 31, 2013 |
84 |
- |
84 | ||||||
December 31, 2014 |
92 |
- |
92 | ||||||
December 31, 2015 |
17 |
- |
17 |
Total (MMBoe) (1) |
|||||||||
U.S. |
Canada |
Total |
|||||||
Proved developed and undeveloped reserves: |
|||||||||
December 31, 2012 |
2,236 | 727 | 2,963 | ||||||
Revisions due to prices |
76 | 18 | 94 | ||||||
Revisions other than price |
(117) | 29 | (88) | ||||||
Extensions and discoveries |
212 | 49 | 261 | ||||||
Purchase of reserves |
1 |
- |
1 | ||||||
Production |
(189) | (64) | (253) | ||||||
Sale of reserves |
(14) | (1) | (15) | ||||||
December 31, 2013 |
2,205 | 758 | 2,963 | ||||||
Revisions due to prices |
38 | (29) | 9 | ||||||
Revisions other than price |
(86) | 21 | (65) | ||||||
Extensions and discoveries |
197 | 14 | 211 | ||||||
Purchase of reserves |
265 |
- |
265 | ||||||
Production |
(207) | (39) | (246) | ||||||
Sale of reserves |
(207) | (176) | (383) | ||||||
December 31, 2014 |
2,205 | 549 | 2,754 | ||||||
Revisions due to prices |
(408) | 106 | (302) | ||||||
Revisions other than price |
(59) | (83) | (142) | ||||||
Extensions and discoveries |
104 | 14 | 118 | ||||||
Purchase of reserves |
9 |
- |
9 | ||||||
Production |
(206) | (42) | (248) | ||||||
Sale of reserves |
(7) |
- |
(7) | ||||||
December 31, 2015 |
1,638 | 544 | 2,182 | ||||||
Proved developed reserves as of: |
|||||||||
December 31, 2012 |
1,829 | 294 | 2,123 | ||||||
December 31, 2013 |
1,947 | 315 | 2,262 | ||||||
December 31, 2014 |
1,900 | 165 | 2,065 | ||||||
December 31, 2015 |
1,563 | 243 | 1,806 | ||||||
Proved developed-producing reserves as of: |
|||||||||
December 31, 2012 |
1,743 | 278 | 2,021 | ||||||
December 31, 2013 |
1,857 | 297 | 2,154 | ||||||
December 31, 2014 |
1,815 | 162 | 1,977 | ||||||
December 31, 2015 |
1,509 | 240 | 1,749 | ||||||
Proved undeveloped reserves as of: |
|||||||||
December 31, 2012 |
407 | 433 | 840 | ||||||
December 31, 2013 |
258 | 443 | 701 | ||||||
December 31, 2014 |
305 | 384 | 689 | ||||||
December 31, 2015 |
75 | 301 | 376 |
_______________________
(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 NGL reserves are converted to Boe on a one-to-one basis with oil.
U.S. |
Canada |
Total |
|||||||
Proved undeveloped reserves as of December 31, 2014 |
305 | 384 | 689 | ||||||
Extensions and discoveries |
13 | 11 | 24 | ||||||
Revisions due to prices |
(115) | 80 | (35) | ||||||
Revisions other than price |
(40) | (80) | (120) | ||||||
Conversion to proved developed reserves |
(88) | (94) | (182) | ||||||
Proved undeveloped reserves as of December 31, 2015 |
75 | 301 | 376 |
Year Ended December 31, 2015 |
|||||||||
U.S. |
Canada |
Total |
|||||||
(Millions) |
|||||||||
Future cash inflows |
$ |
27,398 |
$ |
13,047 |
$ |
40,445 | |||
Future costs: |
|||||||||
Development |
(3,306) | (2,759) | (6,065) | ||||||
Production |
(17,251) | (6,891) | (24,142) | ||||||
Future income tax expense |
- |
(475) | (475) | ||||||
Future net cash flow |
6,841 | 2,922 | 9,763 | ||||||
10% discount to reflect timing of cash flows |
(1,973) | (1,102) | (3,075) | ||||||
Standardized measure of discounted future net cash flows |
$ |
4,868 |
$ |
1,820 |
$ |
6,688 | |||
Year Ended December 31, 2014 |
|||||||||
U.S. |
Canada |
Total |
|||||||
(Millions) |
|||||||||
Future cash inflows |
$ |
75,847 |
$ |
31,371 |
$ |
107,218 | |||
Future costs: |
|||||||||
Development |
(7,168) | (3,619) | (10,787) | ||||||
Production |
(29,740) | (14,232) | (43,972) | ||||||
Future income tax expense |
(11,021) | (3,026) | (14,047) | ||||||
Future net cash flow |
27,918 | 10,494 | 38,412 | ||||||
10% discount to reflect timing of cash flows |
(12,819) | (5,119) | (17,938) | ||||||
Standardized measure of discounted future net cash flows |
$ |
15,099 |
$ |
5,375 |
$ |
20,474 | |||
Year Ended December 31, 2013 |
|||||||||
U.S. |
Canada |
Total |
|||||||
(Millions) |
|||||||||
Future cash inflows |
$ |
61,983 |
$ |
33,305 |
$ |
95,288 | |||
Future costs: |
|||||||||
Development |
(5,448) | (5,308) | (10,756) | ||||||
Production |
(26,663) | (15,709) | (42,372) | ||||||
Future income tax expense |
(9,046) | (2,327) | (11,373) | ||||||
Future net cash flow |
20,826 | 9,961 | 30,787 | ||||||
10% discount to reflect timing of cash flows |
(10,346) | (4,700) | (15,046) | ||||||
Standardized measure of discounted future net cash flows |
$ |
10,480 |
$ |
5,261 |
$ |
15,741 |
Year Ended December 31, |
|||||||||
2015 |
2014 |
2013 |
|||||||
(Millions) |
|||||||||
Beginning balance |
$ |
20,474 |
$ |
15,741 |
$ |
13,221 | |||
Net changes in prices and production costs |
(20,756) | 2,561 | 3,018 | ||||||
Oil, bitumen, gas and NGL sales, net of production costs |
(2,704) | (6,865) | (5,613) | ||||||
Changes in estimated future development costs |
1,313 | (768) | 399 | ||||||
Extensions and discoveries, net of future development costs |
1,129 | 4,836 | 4,047 | ||||||
Purchase of reserves |
95 | 6,422 | 14 | ||||||
Sales of reserves in place |
(79) | (2,384) | (44) | ||||||
Revisions of quantity estimates |
(1,451) | (746) | (1,040) | ||||||
Previously estimated development costs incurred during the period |
2,158 | 1,933 | 1,986 | ||||||
Accretion of discount |
567 | 1,746 | 1,940 | ||||||
Foreign exchange and other |
(1,254) | (107) | (583) | ||||||
Net change in income taxes |
7,196 | (1,895) | (1,604) | ||||||
Ending balance |
$ |
6,688 |
$ |
20,474 |
$ |
15,741 |
|
2015 |
|||||||||||||||
First Quarter |
Second Quarter |
Third Quarter |
Fourth Quarter |
Full Year |
|||||||||||
(Millions, except per share amounts) |
|||||||||||||||
Operating revenues |
$ |
3,265 |
$ |
3,393 |
$ |
3,601 |
$ |
2,886 |
$ |
13,145 | |||||
Loss before income taxes |
$ |
(5,624) |
$ |
(4,479) |
$ |
(5,623) |
$ |
(5,542) |
$ |
(21,268) | |||||
Net loss attributable to Devon |
$ |
(3,599) |
$ |
(2,816) |
$ |
(3,507) |
$ |
(4,532) |
$ |
(14,454) | |||||
Basic net loss per share attributable to Devon |
$ |
(8.88) |
$ |
(6.94) |
$ |
(8.64) |
$ |
(11.12) |
$ |
(35.55) | |||||
Diluted net loss per share attributable to Devon |
$ |
(8.88) |
$ |
(6.94) |
$ |
(8.64) |
$ |
(11.12) |
$ |
(35.55) | |||||
2014 |
|||||||||||||||
First Quarter |
Second Quarter |
Third Quarter |
Fourth Quarter |
Full Year |
|||||||||||
(Millions, except per share amounts) |
|||||||||||||||
Operating revenues |
$ |
3,725 |
$ |
4,510 |
$ |
5,336 |
$ |
5,995 |
$ |
19,566 | |||||
Earnings before income taxes |
$ |
560 |
$ |
1,554 |
$ |
1,654 |
$ |
291 |
$ |
4,059 | |||||
Net earnings (loss) attributable to Devon |
$ |
324 |
$ |
675 |
$ |
1,016 |
$ |
(408) |
$ |
1,607 | |||||
Basic net earnings (loss) per share attributable to Devon |
$ |
0.80 |
$ |
1.65 |
$ |
2.48 |
$ |
(1.01) |
$ |
3.93 | |||||
Diluted net earnings (loss) per share attributable to Devon |
$ |
0.79 |
$ |
1.64 |
$ |
2.47 |
$ |
(1.01) |
$ |
3.91 |
|
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