DEVON ENERGY CORP/DE, 10-K filed on 2/17/2016
Annual Report
Document And Entity Information (USD $)
In Billions, except Share data in Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Feb. 10, 2016
Jun. 30, 2015
Document And Entity Information [Abstract]
 
 
 
Document Type
10-K 
 
 
Document Period End Date
Dec. 31, 2015 
 
 
Amendment Flag
false 
 
 
Entity Registrant Name
DEVON ENERGY CORP/DE 
 
 
Entity Central Index Key
0001090012 
 
 
Entity Current Reporting Status
Yes 
 
 
Entity Voluntary Filers
No 
 
 
Entity Well-known Seasoned Issuer
Yes 
 
 
Current Fiscal Year End Date
--12-31 
 
 
Document Fiscal Year Focus
2015 
 
 
Entity Filer Category
Large Accelerated Filer 
 
 
Document Fiscal Period Focus
FY 
 
 
Entity Public Float
 
 
$ 24.3 
Entity Common Stock, Shares Outstanding
 
441.3 
 
Consolidated Comprehensive Statements Of Earnings (USD $)
In Millions, except Per Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Consolidated Comprehensive Statements Of Earnings [Abstract]
 
 
 
Oil, gas and NGL sales
$ 5,382 
$ 9,910 
$ 8,522 
Oil, gas and NGL derivatives
503 
1,989 
(191)
Marketing and midstream revenues
7,260 
7,667 
2,066 
Total operating revenues
13,145 
19,566 
10,397 
Lease operating expenses
2,104 
2,332 
2,268 
Marketing and midstream operating expenses
6,420 
6,815 
1,553 
General and administrative expenses
855 
847 
617 
Production and property taxes
388 
535 
461 
Depreciation, depletion and amortization
3,129 
3,319 
2,780 
Asset impairments
20,820 
1,953 
1,976 
Restructuring costs
78 
46 
54 
Gains and losses on asset sales
 
(1,072)
Other operating items
78 
93 
112 
Total operating expenses
33,872 
14,868 
9,830 
Operating income (loss)
(20,727)
4,698 
567 
Net financing costs
517 
526 
417 
Other nonoperating items
24 
113 
Earnings (loss) before income taxes
(21,268)
4,059 
149 
Income tax expense (benefit)
(6,065)
2,368 
169 
Net earnings (loss)
(15,203)
1,691 
(20)
Net earnings (loss) attributable to noncontrolling interests
(749)
84 
 
Net earnings (loss) attributable to Devon
(14,454)
1,607 
(20)
Net earnings (loss) per share attributable to Devon:
 
 
 
Basic
$ (35.55)
$ 3.93 
$ (0.06)
Diluted
$ (35.55)
$ 3.91 
$ (0.06)
Comprehensive earnings (loss):
 
 
 
Net earnings (loss)
(15,203)
1,691 
(20)
Other comprehensive earnings (loss), net of tax:
 
 
 
Foreign currency translation
(559)
(465)
(548)
Pension and postretirement plans
10 
(24)
45 
Other comprehensive loss, net of tax
(549)
(489)
(503)
Comprehensive earnings (loss)
(15,752)
1,202 
(523)
Comprehensive earnings (loss) attributable to noncontrolling interests
(749)
84 
 
Comprehensive earnings (loss) attributable to Devon
$ (15,003)
$ 1,118 
$ (523)
Consolidated Statements Of Cash Flows (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Cash flows from operating activities:
 
 
 
Net earnings (loss)
$ (15,203)
$ 1,691 
$ (20)
Adjustments to reconcile net earnings (loss) to net cash from operating activities:
 
 
 
Depreciation, depletion and amortization
3,129 
3,319 
2,780 
Asset impairments
20,820 
1,953 
1,976 
Gains and losses on asset sales
 
(1,072)
Deferred income tax expense (benefit)
(5,828)
1,891 
97 
Derivatives and other financial instruments
(738)
(2,070)
135 
Cash settlements on derivatives and financial instruments
2,688 
104 
277 
Other noncash charges
537 
457 
309 
Net change in working capital
(301)
50 
(298)
Change in long-term other assets
285 
(421)
10 
Change in long-term other liabilities
(6)
79 
161 
Net cash from operating activities
5,383 
5,981 
5,436 
Cash flows from investing activities:
 
 
 
Capital expenditures
(5,308)
(6,988)
(6,502)
Acquisitions of property, equipment and businesses
(1,107)
(6,462)
(256)
Divestitures of property and equipment
107 
5,120 
419 
Purchases of short-term investments
 
 
(1,076)
Redemptions of short-term investments
 
 
3,419 
Redemptions of long-term investments
 
57 
 
Other
(16)
89 
(3)
Net cash from investing activities
(6,324)
(8,184)
(3,999)
Cash flows from financing activities:
 
 
 
Borrowings of long-term debt, net of issuance costs
4,772 
5,340 
2,233 
Repayments of long-term debt
(2,634)
(7,189)
 
Net short-term debt repayments
(307)
(385)
(1,872)
Stock option exercises
93 
Sale of subsidiary units
654 
 
 
Issuance of subsidiary units
25 
410 
 
Dividends paid on common stock
(396)
(386)
(348)
Distributions to noncontrolling interests
(254)
(235)
 
Other
(16)
(2)
Net cash from financing activities
1,848 
(2,354)
20 
Effect of exchange rate changes on cash
(77)
(29)
(28)
Net change in cash and cash equivalents
830 
(4,586)
1,429 
Cash and cash equivalents at beginning of period
1,480 
6,066 
4,637 
Cash and cash equivalents at end of period
$ 2,310 
$ 1,480 
$ 6,066 
Consolidated Balance Sheets (USD $)
In Millions, unless otherwise specified
Dec. 31, 2015
Dec. 31, 2014
Current assets:
 
 
Cash and cash equivalents
$ 2,310 
$ 1,480 
Accounts receivable
1,105 
1,959 
Derivatives, at fair value
43 
1,993 
Income taxes receivable
147 
522 
Other current assets
421 
544 
Total current assets
4,026 
6,498 
Oil and gas, based on full cost accounting:
 
 
Subject to amortization
78,190 
75,738 
Not subject to amortization
2,584 
2,752 
Total oil and gas
80,774 
78,490 
Midstream and other
10,380 
9,695 
Total property and equipment, at cost
91,154 
88,185 
Less accumulated depreciation, depletion and amortization
(72,086)
(51,889)
Property and equipment, net
19,068 
36,296 
Goodwill
5,032 
6,303 
Other long-term assets
1,406 
1,540 
Total assets
29,532 
50,637 
Current liabilities:
 
 
Accounts payable
906 
1,400 
Revenues and royalties payable
763 
1,193 
Short-term debt
976 1
1,432 1
Deferred income taxes
 
730 
Other current liabilities
650 
1,180 
Total current liabilities
3,295 
5,935 
Long-term debt
12,137 
9,830 
Asset retirement obligations
1,370 
1,339 
Other long-term liabilities
853 
948 
Deferred income taxes
888 
6,244 
Stockholders' equity:
 
 
Common stock, $0.10 par value. Authorized 1.0 billion shares; issued 418 million and 409 million shares in 2015 and 2014, respectively
42 
41 
Additional paid-in capital
4,996 
4,088 
Retained earnings
1,781 
16,631 
Accumulated other comprehensive earnings
230 
779 
Total stockholders' equity attributable to Devon
7,049 
21,539 
Noncontrolling interests
3,940 
4,802 
Total stockholders' equity
10,989 
26,341 
Commitments and contingencies (Note 18)
   
   
Total liabilities and stockholders' equity
$ 29,532 
$ 50,637 
Consolidated Balance Sheets (Parenthetical) (USD $)
Dec. 31, 2015
Dec. 31, 2014
Consolidated Balance Sheets [Abstract]
 
 
Common stock, par value (in dollars per share)
$ 0.10 
$ 0.10 
Common stock, shares authorized (in shares)
1,000,000,000 
1,000,000,000 
Common stock, shares issued (in shares)
418,000,000 
409,000,000 
Consolidated Statements Of Stockholders' Equity (USD $)
In Millions, except Share data
Common Stock [Member]
Additional Paid-In Capital [Member]
Retained Earnings [Member]
Accumulated Other Comprehensive Earnings [Member]
Treasury Stock [Member]
Noncontrolling Interests [Member]
Total
Balance, at Dec. 31, 2012
$ 41 
$ 3,688 
$ 15,778 
$ 1,771 
 
 
$ 21,278 
Balance, shares, at Dec. 31, 2012
406,000,000 
 
 
 
 
 
 
Net earnings (loss)
 
 
(20)
 
 
 
(20)
Other comprehensive loss, net of tax
 
 
 
(503)
 
 
(503)
Stock option exercises
 
 
 
 
 
Common stock repurchased
 
 
 
 
(36)
 
(36)
Common stock retired
 
(36)
 
 
36 
 
 
Common stock dividends
 
 
(348)
 
 
 
(348)
Share-based compensation
 
121 
 
 
 
 
121 
Share-based compensation tax benefits (expense)
 
 
 
 
 
Balance, at Dec. 31, 2013
41 
3,780 
15,410 
1,268 
 
 
20,499 
Balance, shares, at Dec. 31, 2013
406,000,000 
 
 
 
 
 
 
Net earnings (loss)
 
 
1,607 
 
 
84 
1,691 
Other comprehensive loss, net of tax
 
 
 
(489)
 
 
(489)
Stock option exercises
 
93 
 
 
 
 
93 
Stock option exercises, shares
1,000,000 
 
 
 
 
 
 
Restricted stock grants, net of cancellations, shares
2,000,000 
 
 
 
 
 
 
Common stock repurchased
 
 
 
 
(27)
 
(27)
Common stock retired
 
(27)
 
 
27 
 
 
Common stock dividends
 
 
(386)
 
 
 
(386)
Share-based compensation
 
151 
 
 
 
 
151 
Share-based compensation tax benefits (expense)
 
(3)
 
 
 
 
(3)
Acquisition of noncontrolling interests
 
 
 
 
 
4,670 
4,670 
Subsidiary equity transactions
 
93 
 
 
 
277 
370 
Distributions to noncontrolling interests
 
 
 
 
 
(235)
(235)
Other
 
 
 
 
Balance, at Dec. 31, 2014
41 
4,088 
16,631 
779 
 
4,802 
26,341 
Balance, shares, at Dec. 31, 2014
409,000,000 
 
 
 
 
 
 
Net earnings (loss)
 
 
(14,454)
 
 
(749)
(15,203)
Other comprehensive loss, net of tax
 
 
 
(549)
 
 
(549)
Stock option exercises
 
 
 
 
 
Restricted stock grants, net of cancellations, shares
2,000,000 
 
 
 
 
 
 
Common stock repurchased
 
 
 
 
(35)
 
(35)
Common stock retired
 
(35)
 
 
35 
 
 
Common stock dividends
 
 
(396)
 
 
 
(396)
Common stock issued
198 
 
 
 
 
199 
Common stock issued, shares
7,000,000 
 
 
 
 
 
 
Share-based compensation
 
165 
 
 
 
 
165 
Share-based compensation tax benefits (expense)
 
(9)
 
 
 
 
(9)
Subsidiary equity transactions
 
585 
 
 
 
141 
726 
Distributions to noncontrolling interests
 
 
 
 
 
(254)
(254)
Balance, at Dec. 31, 2015
$ 42 
$ 4,996 
$ 1,781 
$ 230 
 
$ 3,940 
$ 10,989 
Balance, shares, at Dec. 31, 2015
418,000,000 
 
 
 
 
 
 
Summary Of Significant Accounting Policies
Summary Of Significant Accounting Policies

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 1 – Inputs consist of unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. When available, Devon measures fair value using Level 1 inputs because they generally provide the most reliable evidence of fair value.

·

Level 2 – Inputs consist of quoted prices that are generally observable for the asset or liability. Common examples of Level 2 inputs include quoted prices for similar assets and liabilities in active markets or quoted prices for identical assets and liabilities in markets not considered to be active.

·

Level 3 – Inputs are not observable from objective sources and have the lowest priority. The most common Level 3 fair value measurement is an internally developed cash flow model.

 

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.

 

 

Acquisitions And Divestitures
Acquisitions And Divestitures

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

 

 

 

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

 

 

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
(Millions)

 

Allocation
(Millions)

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.

 

Derivative Financial Instruments
Derivative Financial Instruments

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

 

 

 

 

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

 

 

 

 

 

11 

Interest rate derivative assets:

 

 

 

 

 

 

 

Derivatives, at fair value

 

 

 

 

 

Other long-term assets

 

 

 

 

 

 —

Foreign currency derivative assets:

 

 

 

 

 

 

 

Derivatives, at fair value

 

 

 

 

 

Total derivative assets

 

 

$

45 

 

$

2,004 

 

 

 

 

 

 

 

 

Commodity derivative liabilities:

 

 

 

 

 

 

 

Other current liabilities

 

 

$

14 

 

$

28 

Other long-term liabilities

 

 

 

 

 

28 

Interest rate derivative liabilities:

 

 

 

 

 

 

 

Other current liabilities

 

 

 

 —

 

 

Other long-term liabilities

 

 

 

22 

 

 

 —

Foreign currency derivative liabilities:

 

 

 

 

 

 

 

Other current liabilities

 

 

 

 

 

 —

Total derivative liabilities

 

 

$

48 

 

$

57 

 

Share-Based Compensation
Share-Based Compensation

4.Share-Based Compensation

 

In the second quarter of 2015, Devon’s stockholders approved the 2015 Long-Term Incentive Plan. The 2015 Plan replaces the 2009 Long-Term Incentive Plan, as amended. From the effective date of the 2015 Plan, no further awards may be made under the 2009 Plan, and awards previously granted will continue to be governed by the terms of the 2009 Plan. Subject to the terms of the 2015 Plan, awards may be made under the 2015 Plan for a total of 28 million shares of Devon common stock, plus the number of shares available for issuance under the 2009 Plan (including shares subject to outstanding awards under the 2009 Plan that are subsequently forfeited, canceled or expire). The 2015 Plan authorizes the Compensation Committee, which consists of independent, non-management members of Devon’s Board of Directors, to grant nonqualified and incentive stock options, restricted stock awards or units, Canadian restricted stock units, performance awards or units and stock appreciation rights to eligible employees. The 2015 Plan also authorizes the grant of nonqualified stock options, restricted stock awards or units and stock appreciation rights to non-employee directors. To calculate the number of shares that may be granted in awards under the 2015 Plan, options and stock appreciation rights represent one share and other awards represent three shares.

 

Devon also has a stock option plan that was adopted in 2005 under which stock options were issued to certain employees. Options granted under this plan remain exercisable by the employees owning such options, but no new options or restricted stock awards will be granted under this plan.

 

Devon did not have an annual long-term incentive grant in 2013 due to revisions in the timing of the employee compensation cycle. The annual long-term incentive grant related to 2013 performance was granted in February 2014.

 

The following table presents the effects of share-based compensation included in Devon's accompanying consolidated comprehensive statements of earnings. Gross G&A for the years ended December 31, 2015 and 2014 includes $31 million and $17 million, respectively, of unit-based compensation related to grants made under EnLink’s long-term incentive plans.

 

The vesting for certain share-based awards was accelerated in 2014 in conjunction with the divestiture of Devon’s Canadian conventional assets.  For the year ended December 31, 2014, approximately $15 million of associated expense for these accelerated awards is included in restructuring costs in the accompanying consolidated comprehensive statements of earnings.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31,

 

 

2015

 

2014

 

2013

 

 

 

 

 

 

 

 

 

 

 

 

(Millions)

Gross general and administrative expense for share-based compensation

 

$

225 

 

$

199 

 

$

157 

Share-based compensation expense capitalized pursuant to the

 

 

 

 

 

 

 

 

 

 full cost method of accounting for oil and gas properties

 

$

63 

 

$

53 

 

$

60 

Related income tax benefit

 

$

45 

 

$

42 

 

$

29 

 

 

The following table presents a summary of Devon’s unvested restricted stock awards and units, performance-based restricted stock awards and performance share units granted under the plans.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Restricted Stock

 

Performance-Based

 

Performance

 

 

Awards and Units

 

Restricted Stock Awards

 

Share Units

 

 

Awards and Units

 

 

 

Weighted Average Grant-Date Fair Value

 

Awards

 

 

 

Weighted Average Grant-Date Fair Value

 

Units

 

 

 

Weighted Average Grant-Date Fair Value

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Thousands, except fair value data)

Unvested at 12/31/14

 

4,304 

 

 

$

60.85 

 

380 

 

 

$

59.41 

 

1,477 

 

 

$

70.90 

Granted

 

2,771 

 

 

$

63.57 

 

236 

 

 

$

62.02 

 

786 

 

 

$

84.14 

Vested

 

(1,834)

 

 

$

60.33 

 

(153)

 

 

$

59.49 

 

(337)

 

 

$

66.00 

Forfeited

 

(503)

 

 

$

62.22 

 

(29)

 

 

$

64.18 

 

(67)

 

 

$

79.20 

Unvested at 12/31/15

 

4,738 

 

 

$

62.49 

 

434 

 

 

$

60.48 

 

1,859 

 

(1)

$

76.17 

____________________________

(1)

A maximum of 3.7 million common shares could be awarded based upon Devon’s final TSR ranking.

 

The following table presents the aggregate fair value of awards and units that vested during the indicated period.

 

 

 

 

 

 

 

 

 

 

 

 

 

2015

 

2014

 

2013

 

 

 

 

 

 

 

 

 

 

 

 

(Millions)

Restricted stock awards and units

 

$

101 

 

$

112 

 

$

141 

Performance-based restricted stock awards

 

$

 

$

10 

 

$

Performance share units

 

$

22 

 

$

 -

 

$

 -

 

 

The following table presents the unrecognized compensation cost and the related weighted average recognition period associated with unvested awards and units as of December 31, 2015.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Performance-Based

 

 

 

 

 

Restricted Stock

 

Restricted Stock

 

Performance

 

 

Awards and Units

 

Awards

 

Share Units

Unrecognized compensation cost (millions)

 

$

198 

 

$

 

$

45 

Weighted average period for recognition (years)

 

 

2.5 

 

 

2.6 

 

 

1.8 

 

 

Restricted Stock Awards and Units

 

Restricted stock awards and units are subject to the terms, conditions, restrictions and limitations, if any, that the Compensation Committee deems appropriate, including restrictions on continued employment. Generally, the service requirement for vesting ranges from zero to four years. During the vesting period, recipients of restricted stock awards receive dividends that are not subject to restrictions or other limitations. Devon estimates the fair values of restricted stock awards and units as the closing price of Devon's common stock on the grant date of the award or unit, which is expensed over the applicable vesting period.

 

Performance-Based Restricted Stock Awards

 

Performance-based restricted stock awards are granted to certain members of Devon’s senior management. Vesting of the awards is dependent on Devon meeting certain internal performance targets and the recipient meeting certain service requirements. Generally, the service requirement for vesting ranges from zero to four years. In order for awards to vest, the performance target must be met in the first year, and if met, recipients are entitled to dividends on the awards over the remaining service vesting period. If the performance target and service period requirements are not met, the award does not vest. Devon estimates the fair values of the awards as the closing price of Devon's common stock on the grant date of the award, which is expensed over the applicable vesting period.

 

 

Performance Share Units  

 

Performance share units are granted to certain members of Devon’s senior management. Each unit that vests entitles the recipient to one share of Devon common stock. The vesting of these units is based on comparing Devon’s TSR to the TSR of a predetermined group of fourteen peer companies over the specified two- or three-year performance period. The vesting of units may be between zero and 200% of the units granted depending on Devon’s TSR as compared to the peer group on the vesting date.

 

At the end of the vesting period, recipients receive dividend equivalents with respect to the number of units vested. The fair value of each performance share unit is estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all grants made under the plan: (i) a risk-free interest rate based on U.S. Treasury rates as of the grant date; (ii) a volatility assumption based on the historical realized price volatility of Devon and the designated peer group; and (iii) an estimated ranking of Devon among the designated peer group. The fair value of the unit on the date of grant is expensed over the applicable vesting period. The following table presents the assumptions related to performance share units granted.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2015

 

2014

 

2013

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Grant-date fair value

$

81.99 

-

$

85.05 

 

$

70.18 

-

$

81.05 

 

$

61.27 

-

$

63.48 

Risk-free interest rate

1.06%

 

0.54%

 

 

0.26% 

-

 

0.36% 

Volatility factor

26.2%

 

28.8%

 

30.3%

Contractual term (years)

2.89

 

2.89

 

3.0

 

Stock Options 

 

In accordance with Devon’s incentive plans, the exercise price of stock options granted may not be less than the market value of the stock at the date of grant. In addition, options granted are exercisable during a period established for each grant, which may not exceed eight years from the date of grant. The recipient must pay the exercise price in cash or in common stock, or a combination thereof, at the time that the option is exercised. Generally, the service requirement for vesting ranges from zero to four years. The fair value of stock options on the date of grant is expensed over the applicable vesting period. Devon estimates the fair values of stock options granted using a Black-Scholes option valuation model, which requires Devon to make several assumptions, including a volatility factor, dividend yield rate, risk-free interest rate and expected term.  No stock options were granted in 2015, 2014 and 2013. The following table presents a summary of Devon's outstanding stock options.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Weighted Average

 

 

 

 

 

 

Options

 

Exercise Price

 

 

Remaining Term

 

Intrinsic Value

 

 

 

(Thousands)

 

 

 

 

 

(Years)

 

(Millions)

Outstanding at December 31, 2014

 

 

4,218 

 

$

70.56 

 

 

 

 

 

 

 Granted

 

 

 -

 

$

 -

 

 

 

 

 

 

 Exercised

 

 

(63)

 

$

64.25 

 

 

 

 

 

 

 Expired

 

 

(680)

 

$

84.36 

 

 

 

 

 

 

 Forfeited

 

 

(27)

 

$

66.71 

 

 

 

 

 

 

Outstanding at December 31, 2015

 

 

3,448 

 

$

67.98 

 

 

2.41 

 

$

 -

Vested and expected to vest at December 31, 2015

 

 

3,448 

 

$

67.98 

 

 

2.41 

 

$

 -

Exercisable at December 31, 2015

 

 

3,448 

 

$

67.98 

 

 

2.41 

 

$

 -

 

The aggregate intrinsic value of stock options that were exercised during 2015, 2014 and 2013 was $0.2 million, $9 million and $0.3 million, respectively. As of December 31, 2015, Devon had no unrecognized compensation cost related to unvested stock options.

 

EnLink Share-Based Awards

 

    In March 2015, the General Partner and EnLink issued restricted incentive units as bonus payments to officers and certain employees for 2014. The combined grant fair value was $7 million, and the total cost was recognized in the first quarter of 2015 due to the awards vesting immediately.

 

    The following table presents a summary of the unrecognized compensation cost and the related weighted average recognition period associated with the General Partner’s and EnLink’s unvested restricted incentive units and performance units as of December 31, 2015.

   

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

General Partner

 

EnLink

 

 

Restricted

 

Performance

 

Restricted

 

Performance

 

 

Incentive Units

 

Units

 

Incentive Units

 

Units

Unrecognized compensation cost (millions)

 

$

17 

 

$

 

$

16 

 

$

Weighted average period for recognition (years)

 

 

1.6 

 

 

2.0 

 

 

1.6 

 

 

2.0 

 

Asset Impairments
Asset Impairments

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.

 

Restructuring Costs
Restructuring Costs

 

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 

 

 

 

 

 -

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

  

 

 

 

 —

 

 

Balance as of December 31, 2014

  

 

13 

  

 

  

 

20 

Changes due to office consolidation and offshore divestiture

 

 

 

 

46 

 

 

47 

Changes due to Canadian divestitures

 

 

(1)

 

 

10 

 

 

Balance as of December 31, 2015

  

$

13 

  

$

63 

  

$

76 

 

Income Taxes
Income Taxes

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 

 

 

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)

 

 

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.

Net Earnings (Loss) Per Share Attributable To Devon
Net Earnings (Loss) Per Share Attributable To Devon

 

8.Net Earnings (Loss) Per Share Attributable to Devon    

 

The following table reconciles net earnings (loss) attributable to Devon and weighted-average common shares outstanding used in the calculations of basic and diluted net earnings per share.

 

 

 

 

 

 

 

 

 

 

 

 

  

 

 

 

 

 

 

 

 

 

 

Year Ended December 31,

 

 

2015

 

2014

 

2013

 

 

 

 

 

 

 

 

 

 

 

  

(Millions, except per share amounts)

Net earnings (loss):

 

 

 

 

 

 

 

 

 

Net earnings (loss) attributable to Devon

 

$

(14,454)

 

$

1,607 

 

$

(20)

Attributable to participating securities

 

 

(5)

 

 

(17)

 

 

(2)

Basic and diluted earnings (loss)

 

$

(14,459)

 

$

1,590 

 

$

(22)

Common shares:

 

 

 

 

 

 

 

 

 

Common shares outstanding - total

 

 

412 

 

 

409 

 

 

406 

Attributable to participating securities

 

 

(5)

 

 

(4)

 

 

(4)

Common shares outstanding - basic

 

 

407 

 

 

405 

 

 

402 

Dilutive effect of potential common shares issuable

 

 

 -

 

 

 

 

 -

Common shares outstanding - diluted

 

 

407 

 

 

407 

 

 

402 

 

 

 

 

 

 

 

 

 

 

Net earnings (loss) per share attributable to Devon:

 

 

 

 

 

 

 

 

 

Basic

 

$

(35.55)

 

$

3.93 

 

$

(0.06)

Diluted

 

$

(35.55)

 

$

3.91 

 

$

(0.06)

Antidilutive options (1)

 

 

 

 

 

 

____________________________

(1)  Amounts represent options to purchase shares of Devon’s common stock that are excluded from the diluted net earnings per share calculations because the options are antidilutive.

 

Other Comprehensive Earnings
Other Comprehensive Earnings

 

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 

____________________________

(1)

These accumulated other comprehensive earnings components are included in the computation of net periodic benefit cost, which is a component of G&A on the accompanying consolidated comprehensive statements of earnings. See Note 15 for additional details.

 

Supplemental Information To Statements Of Cash Flows
Supplemental Information To Statements Of Cash Flows

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.

Accounts Receivable
Accounts Receivable

 

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 

 

Goodwill And Other Intangible Assets
Goodwill And Other Intangible Assets

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. 

Asset Retirement Obligations
Asset Retirement Obligations

 

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.

Retirement Plans
Retirement Plans

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 

 

 

 

 

Interest cost

 

 

52 

 

 

55 

 

 

 

 

Actuarial loss (gain)

 

 

(68)

 

 

203 

 

 

(2)

 

 

 -

Plan amendments

 

 

 -

 

 

 -

 

 

 

 

 -

Plan settlements

 

 

 -

 

 

(4)

 

 

 -

 

 

 -

Foreign exchange rate changes

 

 

(6)

 

 

(3)

 

 

 -

 

 

 -

Participant contributions

 

 

 -

 

 

 -

 

 

 

 

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 

 

 

 

 

Participant contributions

 

 

 -

 

 

 -

 

 

 

 

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

 

$

 

$

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 

 

$

 

$

 

$

Interest cost

 

 

52 

 

 

55 

 

 

51 

 

 

 

 

 

 

Expected return on plan assets

 

 

(58)

 

 

(54)

 

 

(62)

 

 

 -

 

 

 -

 

 

 -

Curtailment and settlement expense

 

 

 -

 

 

 

 

 -

 

 

 -

 

 

 -

 

 

 -

Recognition of net actuarial loss (gain) (1)

 

 

20 

 

 

18 

 

 

22 

 

 

(1)

 

 

(1)

 

 

(1)

Recognition of prior service cost (1)

 

 

 

 

 

 

 

 

(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

 

 

 

 

57 

 

 

(39)

 

 

(1)

 

 

 -

 

 

(3)

Prior service cost (credit) arising in current year

 

 

 -

 

 

 -

 

 

 

 

 

 

 -

 

 

(8)

Recognition of net actuarial loss, including settlement

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

expense, in net periodic benefit cost

 

 

(20)

 

 

(19)

 

 

(22)

 

 

 

 

 

 

Recognition of prior service cost, including curtailment,

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

in net periodic benefit cost

 

 

(4)

 

 

(4)

 

 

(4)

 

 

 

 

 

 

Total other comprehensive loss (earnings)

 

 

(19)

 

 

34 

 

 

(63)

 

 

 

 

 

 

(9)

Total recognized

 

$

32 

 

$

88 

 

$

(12)

 

$

 

$

 

$

(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)

 

 

 

 

(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 

 

 

 

 

26 

 

 

 -

Total other securities

 

 

14% 

 

 

152 

 

 

 

 

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

 

 

December 31, 2014

 

 

112 

Purchases

 

 

Investment returns

 

 

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 

 

$

Benefit payments:

 

 

 

 

 

 

2016

 

$

73 

 

$

2017

 

$

75 

 

$

2018

 

$

77 

 

$

2019

 

$

78 

 

$

2020

 

$

83 

 

$

2021 to 2025

 

$

446 

 

$

 

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

 

Stockholders' Equity
Stockholders' Equity

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.

 

Noncontrolling Interests
Noncontrolling interests

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:

 

·

28% - Devon

·

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.

 

Commitments And Contingencies
Commitments And Contingencies

 

 

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 

 

 

402 

 

68 

2020

 

845 

 

 

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.   

 

 

Fair Value Measurements
Fair Value Measurements

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

 

$

 

$

 

 

$

 -

 

$

 

$

 -

Interest rate derivatives

 

$

(22)

 

$

(22)

 

 

$

 -

 

$

(22)

 

$

 -

Foreign currency derivatives

 

$

 

$

 

 

$

 -

 

$

 

$

 -

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

 

$

 

$

 

 

$

 -

 

$

 

$

 -

Interest rate derivatives

 

$

(1)

 

$

(1)

 

 

$

 -

 

$

(1)

 

$

 -

Foreign currency derivatives

 

$

 

$

 

 

$

 -

 

$

 

$

 -

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.

Segment Information
Segment Information

 

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

 

$

 

$

 -

 

$

(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

 

$

 

$

(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

 

$

 

$

 -

 

$

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 

__________________________

(1)

Due to Devon’s control of EnLink through its control of the General Partner, the acquisition of VEX by EnLink from Devon in the second quarter of 2015 was considered a transfer of net assets between entities under common control, and EnLink was required to recast its financial statements as of December 31, 2015 to include the activities of such assets from the date of common control. Therefore, the results of VEX have been moved from the U.S. segment to the EnLink segment for the recasted periods.

 

  

Supplemental Information On Oil And Gas Operations
Supplemental Information on Oil and Gas Operations

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 

 

$

 

$

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 

 

 

 

 

1,177 

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 

 

$

 

$

22 

Unproved properties

 

 

213 

 

 

 

 

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

 

 

 

 

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)

 

 

 -

Revisions other than price

 

 

(18)

 

 

 -

 

 

(18)

Extensions and discoveries

 

 

69 

 

 

 

 

76 

Purchase of reserves

 

 

 

 

 -

 

 

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)

 

 

 

 

(37)

Extensions and discoveries

 

 

94 

 

 

 

 

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)

 

 

 

 

(49)

Revisions other than price

 

 

(52)

 

 

 

 

(50)

Extensions and discoveries

 

 

51 

 

 

 

 

54 

Purchase of reserves

 

 

 

 

 -

 

 

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 

 

 

 

 

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

 

 

 -

 

 

 

 

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

 

 

 

 

 -

 

 

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)

 

 

 

 

(295)

Extensions and discoveries

 

 

335 

 

 

 

 

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 

 

 

 

 

1,376 

December 31, 2013

 

 

843 

 

 

 

 

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

 

 

 

 

 

 

11 

Revisions other than price

 

 

(50)

 

 

 

 

(47)

Extensions and discoveries

 

 

64 

 

 

 

 

65 

Production

 

 

(41)

 

 

(4)

 

 

(45)

December 31, 2013

 

 

552 

 

 

23 

 

 

575 

Revisions due to prices

 

 

 

 

 

 

Revisions other than price

 

 

 

 

 -

 

 

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

 

 

 

 

 -

 

 

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

 

 

 

 

 -

 

 

Production

 

 

(189)

 

 

(64)

 

 

(253)

Sale of reserves

 

 

(14)

 

 

(1)

 

 

(15)

December 31, 2013

 

 

2,205 

 

 

758 

 

 

2,963 

Revisions due to prices

 

 

38 

 

 

(29)

 

 

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

 

 

 

 

 -

 

 

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

 

2015Of 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 

 

 

Supplemental Quarterly Financial Information
Supplemental Quarterly Financial Information

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.    

 

 

 

 

Summary Of Significant Accounting Policies (Policies)

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 1 – Inputs consist of unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. When available, Devon measures fair value using Level 1 inputs because they generally provide the most reliable evidence of fair value.

·

Level 2 – Inputs consist of quoted prices that are generally observable for the asset or liability. Common examples of Level 2 inputs include quoted prices for similar assets and liabilities in active markets or quoted prices for identical assets and liabilities in markets not considered to be active.

·

Level 3 – Inputs are not observable from objective sources and have the lowest priority. The most common Level 3 fair value measurement is an internally developed cash flow model.

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.

 

Acquisitions And Divestitures (Tables)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Purchase Price
(Millions)

 

Allocation
(Millions)

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

 

 

 

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

 

 

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)

 

Derivative Financial Instruments (Tables)

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

 

 

 

 

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

 

 

 

 

 

11 

Interest rate derivative assets:

 

 

 

 

 

 

 

Derivatives, at fair value

 

 

 

 

 

Other long-term assets

 

 

 

 

 

 —

Foreign currency derivative assets:

 

 

 

 

 

 

 

Derivatives, at fair value

 

 

 

 

 

Total derivative assets

 

 

$

45 

 

$

2,004 

 

 

 

 

 

 

 

 

Commodity derivative liabilities:

 

 

 

 

 

 

 

Other current liabilities

 

 

$

14 

 

$

28 

Other long-term liabilities

 

 

 

 

 

28 

Interest rate derivative liabilities:

 

 

 

 

 

 

 

Other current liabilities

 

 

 

 —

 

 

Other long-term liabilities

 

 

 

22 

 

 

 —

Foreign currency derivative liabilities:

 

 

 

 

 

 

 

Other current liabilities

 

 

 

 

 

 —

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

 

Share-Based Compensation (Tables)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31,

 

 

2015

 

2014

 

2013

 

 

 

 

 

 

 

 

 

 

 

 

(Millions)

Gross general and administrative expense for share-based compensation

 

$

225 

 

$

199 

 

$

157 

Share-based compensation expense capitalized pursuant to the

 

 

 

 

 

 

 

 

 

 full cost method of accounting for oil and gas properties

 

$

63 

 

$

53 

 

$

60 

Related income tax benefit

 

$

45 

 

$

42 

 

$

29 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Restricted Stock

 

Performance-Based

 

Performance

 

 

Awards and Units

 

Restricted Stock Awards

 

Share Units

 

 

Awards and Units

 

 

 

Weighted Average Grant-Date Fair Value

 

Awards

 

 

 

Weighted Average Grant-Date Fair Value

 

Units

 

 

 

Weighted Average Grant-Date Fair Value

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Thousands, except fair value data)

Unvested at 12/31/14

 

4,304 

 

 

$

60.85 

 

380 

 

 

$

59.41 

 

1,477 

 

 

$

70.90 

Granted

 

2,771 

 

 

$

63.57 

 

236 

 

 

$

62.02 

 

786 

 

 

$

84.14 

Vested

 

(1,834)

 

 

$

60.33 

 

(153)

 

 

$

59.49 

 

(337)

 

 

$

66.00 

Forfeited

 

(503)

 

 

$

62.22 

 

(29)

 

 

$

64.18 

 

(67)

 

 

$

79.20 

Unvested at 12/31/15

 

4,738 

 

 

$

62.49 

 

434 

 

 

$

60.48 

 

1,859 

 

(1)

$

76.17 

____________________________

(1)

A maximum of 3.7 million common shares could be awarded based upon Devon’s final TSR ranking.

 

 

 

 

 

 

 

 

 

 

 

 

2015

 

2014

 

2013

 

 

 

 

 

 

 

 

 

 

 

 

(Millions)

Restricted stock awards and units

 

$

101 

 

$

112 

 

$

141 

Performance-based restricted stock awards

 

$

 

$

10 

 

$

Performance share units

 

$

22 

 

$

 -

 

$

 -

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2015

 

2014

 

2013

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Grant-date fair value

$

81.99 

-

$

85.05 

 

$

70.18 

-

$

81.05 

 

$

61.27 

-

$

63.48 

Risk-free interest rate

1.06%

 

0.54%

 

 

0.26% 

-

 

0.36% 

Volatility factor

26.2%

 

28.8%

 

30.3%

Contractual term (years)

2.89

 

2.89

 

3.0

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Weighted Average

 

 

 

 

 

 

Options

 

Exercise Price

 

 

Remaining Term

 

Intrinsic Value

 

 

 

(Thousands)

 

 

 

 

 

(Years)

 

(Millions)

Outstanding at December 31, 2014

 

 

4,218 

 

$

70.56 

 

 

 

 

 

 

 Granted

 

 

 -

 

$

 -

 

 

 

 

 

 

 Exercised

 

 

(63)

 

$

64.25 

 

 

 

 

 

 

 Expired

 

 

(680)

 

$

84.36 

 

 

 

 

 

 

 Forfeited

 

 

(27)

 

$

66.71 

 

 

 

 

 

 

Outstanding at December 31, 2015

 

 

3,448 

 

$

67.98 

 

 

2.41 

 

$

 -

Vested and expected to vest at December 31, 2015

 

 

3,448 

 

$

67.98 

 

 

2.41 

 

$

 -

Exercisable at December 31, 2015

 

 

3,448 

 

$

67.98 

 

 

2.41 

 

$

 -

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Performance-Based

 

 

 

 

 

Restricted Stock

 

Restricted Stock

 

Performance

 

 

Awards and Units

 

Awards

 

Share Units

Unrecognized compensation cost (millions)

 

$

198 

 

$

 

$

45 

Weighted average period for recognition (years)

 

 

2.5 

 

 

2.6 

 

 

1.8 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

General Partner

 

EnLink

 

 

Restricted

 

Performance

 

Restricted

 

Performance

 

 

Incentive Units

 

Units

 

Incentive Units

 

Units

Unrecognized compensation cost (millions)

 

$

17 

 

$

 

$

16 

 

$

Weighted average period for recognition (years)

 

 

1.6 

 

 

2.0 

 

 

1.6 

 

 

2.0 

 

Asset Impairments (Tables)
Schedule Of Asset Impairments

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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 

 

 

Restructuring Costs (Tables)

 

 

 

 

 

 

 

 

 

 

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 

 

 

 

 

 -

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

  

 

 

 

 —

 

 

Balance as of December 31, 2014

  

 

13 

  

 

  

 

20 

Changes due to office consolidation and offshore divestiture

 

 

 

 

46 

 

 

47 

Changes due to Canadian divestitures

 

 

(1)

 

 

10 

 

 

Balance as of December 31, 2015

  

$

13 

  

$

63 

  

$

76 

 

Income Taxes (Tables)

 

 

 

 

 

 

 

 

 

 

 

 

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 

 

 

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)

 

 

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

 

Net Earnings (Loss) Per Share Attributable To Devon (Tables)
Net Earnings (Loss) Per Share Computations

 

  

 

 

 

 

 

 

 

 

 

 

Year Ended December 31,

 

 

2015

 

2014

 

2013

 

 

 

 

 

 

 

 

 

 

 

  

(Millions, except per share amounts)

Net earnings (loss):

 

 

 

 

 

 

 

 

 

Net earnings (loss) attributable to Devon

 

$

(14,454)

 

$

1,607 

 

$

(20)

Attributable to participating securities

 

 

(5)

 

 

(17)

 

 

(2)

Basic and diluted earnings (loss)

 

$

(14,459)

 

$

1,590 

 

$

(22)

Common shares:

 

 

 

 

 

 

 

 

 

Common shares outstanding - total

 

 

412 

 

 

409 

 

 

406 

Attributable to participating securities

 

 

(5)

 

 

(4)

 

 

(4)

Common shares outstanding - basic

 

 

407 

 

 

405 

 

 

402 

Dilutive effect of potential common shares issuable

 

 

 -

 

 

 

 

 -

Common shares outstanding - diluted

 

 

407 

 

 

407 

 

 

402 

 

 

 

 

 

 

 

 

 

 

Net earnings (loss) per share attributable to Devon:

 

 

 

 

 

 

 

 

 

Basic

 

$

(35.55)

 

$

3.93 

 

$

(0.06)

Diluted

 

$

(35.55)

 

$

3.91 

 

$

(0.06)

Antidilutive options (1)

 

 

 

 

 

 

____________________________

(1)  Amounts represent options to purchase shares of Devon’s common stock that are excluded from the diluted net earnings per share calculations because the options are antidilutive.

Other Comprehensive Earnings (Tables)
Components Of Other Comprehensive Earnings

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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 

____________________________

(1)

These accumulated other comprehensive earnings components are included in the computation of net periodic benefit cost, which is a component of G&A on the accompanying consolidated comprehensive statements of earnings. See Note 15 for additional details.

Supplemental Information To Statements Of Cash Flows (Tables)
Schedule Of 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 

 

Accounts Receivable (Tables)
Schedule Of Components Of Accounts Receivable

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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 

 

Goodwill And Other Intangible Assets (Tables)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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 

 

Asset Retirement Obligations (Tables)
Summary Of 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.

Retirement Plans (Tables)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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 

 

 

 

 

Interest cost

 

 

52 

 

 

55 

 

 

 

 

Actuarial loss (gain)

 

 

(68)

 

 

203 

 

 

(2)

 

 

 -

Plan amendments

 

 

 -

 

 

 -

 

 

 

 

 -

Plan settlements

 

 

 -

 

 

(4)

 

 

 -

 

 

 -

Foreign exchange rate changes

 

 

(6)

 

 

(3)

 

 

 -

 

 

 -

Participant contributions

 

 

 -

 

 

 -

 

 

 

 

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 

 

 

 

 

Participant contributions

 

 

 -

 

 

 -

 

 

 

 

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

 

$

 

$

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 

 

$

 

$

 

$

Interest cost

 

 

52 

 

 

55 

 

 

51 

 

 

 

 

 

 

Expected return on plan assets

 

 

(58)

 

 

(54)

 

 

(62)

 

 

 -

 

 

 -

 

 

 -

Curtailment and settlement expense

 

 

 -

 

 

 

 

 -

 

 

 -

 

 

 -

 

 

 -

Recognition of net actuarial loss (gain) (1)

 

 

20 

 

 

18 

 

 

22 

 

 

(1)

 

 

(1)

 

 

(1)

Recognition of prior service cost (1)

 

 

 

 

 

 

 

 

(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

 

 

 

 

57 

 

 

(39)

 

 

(1)

 

 

 -

 

 

(3)

Prior service cost (credit) arising in current year

 

 

 -

 

 

 -

 

 

 

 

 

 

 -

 

 

(8)

Recognition of net actuarial loss, including settlement

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

expense, in net periodic benefit cost

 

 

(20)

 

 

(19)

 

 

(22)

 

 

 

 

 

 

Recognition of prior service cost, including curtailment,

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

in net periodic benefit cost

 

 

(4)

 

 

(4)

 

 

(4)

 

 

 

 

 

 

Total other comprehensive loss (earnings)

 

 

(19)

 

 

34 

 

 

(63)

 

 

 

 

 

 

(9)

Total recognized

 

$

32 

 

$

88 

 

$

(12)

 

$

 

$

 

$

(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)

 

 

 

 

(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 

 

 

 

 

26 

 

 

 -

Total other securities

 

 

14% 

 

 

152 

 

 

 

 

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

 

 

December 31, 2014

 

 

112 

Purchases

 

 

Investment returns

 

 

December 31, 2015

 

$

120 

 

 

 

 

 

 

 

 

 

 

Pension Benefits

 

Postretirement Benefits

 

 

 

 

 

 

 

 

 

(Millions)

Devon's 2016 contributions

 

$

12 

 

$

Benefit payments:

 

 

 

 

 

 

2016

 

$

73 

 

$

2017

 

$

75 

 

$

2018

 

$

77 

 

$

2019

 

$

78 

 

$

2020

 

$

83 

 

$

2021 to 2025

 

$

446 

 

$

 

 

 

 

 

 

 

 

 

 

 

 

 

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%

 

Commitments And Contingencies (Tables)
Schedule Of Commitments And Contingencies

 

 

 

 

 

 

 

 

 

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 

 

 

402 

 

68 

2020

 

845 

 

 

255 

 

42 

Thereafter

 

206 

 

28 

 

1,042 

 

129 

Total

 

$                 3,905

 

$                     189

 

$                   4,601

 

$                      443

 

Fair Value Measurements (Tables)
Schedule Of Carrying Value And Fair Value Measurement Information For Financial Assets And Liabilities

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

$

 

$

 

 

$

 -

 

$

 

$

 -

Interest rate derivatives

 

$

(22)

 

$

(22)

 

 

$

 -

 

$

(22)

 

$

 -

Foreign currency derivatives

 

$

 

$

 

 

$

 -

 

$

 

$

 -

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

 

$

 

$

 

 

$

 -

 

$

 

$

 -

Interest rate derivatives

 

$

(1)

 

$

(1)

 

 

$

 -

 

$

(1)

 

$

 -

Foreign currency derivatives

 

$

 

$

 

 

$

 -

 

$

 

$

 -

Debt

 

$

(11,262)

 

$

(12,472)

 

 

$

 -

 

$

(12,472)

 

$

 -

Capital lease obligations

 

$

(20)

 

$

(20)

 

 

$

 -

 

$

(20)

 

$

 -

 

Segment Information (Tables)
Condensed Statements Of Comprehensive Earnings And Balance Sheets Of Reportable Segments

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

   

 

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

 

$

 

$

 -

 

$

(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

 

$

 

$

(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

 

$

 

$

 -

 

$

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 

__________________________

(1)

Due to Devon’s control of EnLink through its control of the General Partner, the acquisition of VEX by EnLink from Devon in the second quarter of 2015 was considered a transfer of net assets between entities under common control, and EnLink was required to recast its financial statements as of December 31, 2015 to include the activities of such assets from the date of common control. Therefore, the results of VEX have been moved from the U.S. segment to the EnLink segment for the recasted periods.

 

Supplemental Information On Oil And Gas Operations (Tables)

 

 

 

 

 

 

 

 

 

 

 

 

Year Ended December 31, 2015

 

 

U.S.

 

Canada

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

(Millions)

Property acquisition costs:

 

 

 

 

 

 

 

 

 

Proved properties

 

$

193 

 

$

 

$

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 

 

 

 

 

1,177 

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 

 

$

 

$

22 

Unproved properties

 

 

213 

 

 

 

 

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

 

 

 

 

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)

 

 

 -

Revisions other than price

 

 

(18)

 

 

 -

 

 

(18)

Extensions and discoveries

 

 

69 

 

 

 

 

76 

Purchase of reserves

 

 

 

 

 -

 

 

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)

 

 

 

 

(37)

Extensions and discoveries

 

 

94 

 

 

 

 

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)

 

 

 

 

(49)

Revisions other than price

 

 

(52)

 

 

 

 

(50)

Extensions and discoveries

 

 

51 

 

 

 

 

54 

Purchase of reserves

 

 

 

 

 -

 

 

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 

 

 

 

 

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

 

 

 -

 

 

 

 

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

 

 

 

 

 -

 

 

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)

 

 

 

 

(295)

Extensions and discoveries

 

 

335 

 

 

 

 

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 

 

 

 

 

1,376 

December 31, 2013

 

 

843 

 

 

 

 

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

 

 

 

 

 

 

11 

Revisions other than price

 

 

(50)

 

 

 

 

(47)

Extensions and discoveries

 

 

64 

 

 

 

 

65 

Production

 

 

(41)

 

 

(4)

 

 

(45)

December 31, 2013

 

 

552 

 

 

23 

 

 

575 

Revisions due to prices

 

 

 

 

 

 

Revisions other than price

 

 

 

 

 -

 

 

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

 

 

 

 

 -

 

 

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

 

 

 

 

 -

 

 

Production

 

 

(189)

 

 

(64)

 

 

(253)

Sale of reserves

 

 

(14)

 

 

(1)

 

 

(15)

December 31, 2013

 

 

2,205 

 

 

758 

 

 

2,963 

Revisions due to prices

 

 

38 

 

 

(29)

 

 

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

 

 

 

 

 -

 

 

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 

 

Supplemental Quarterly Financial Information (Tables)
Schedule Of 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 

 

Summary Of Significant Accounting Policies (Narrative) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Summary Of Significant Accounting Policies [Line Items]
 
 
 
Accrued derivative receivable
$ 236 
 
 
Derivative collateral held
$ 75 
$ 524 
 
Major Customer Accounting For More Than 10 Percent Of Operating Revenues [Member]
 
 
 
Summary Of Significant Accounting Policies [Line Items]
 
 
 
Concentration risk percentage
0.00% 
0.00% 
0.00% 
Minimum [Member]
 
 
 
Summary Of Significant Accounting Policies [Line Items]
 
 
 
Finite lived intangible asset useful life
10 years 
 
 
Depletion calculation holding period
3 years 
 
 
Property, plant and equipment, useful life
3 years 
 
 
Maximum [Member]
 
 
 
Summary Of Significant Accounting Policies [Line Items]
 
 
 
Finite lived intangible asset useful life
20 years 
 
 
Depletion calculation holding period
4 years 
 
 
Property, plant and equipment, useful life
60 years 
 
 
Acquisitions And Divestitures (Narrative) (Details)
Share data in Millions, unless otherwise specified
1 Months Ended 3 Months Ended 12 Months Ended 3 Months Ended 0 Months Ended 12 Months Ended 0 Months Ended 12 Months Ended 0 Months Ended 12 Months Ended 0 Months Ended 1 Months Ended 0 Months Ended 12 Months Ended 0 Months Ended 1 Months Ended 0 Months Ended 12 Months Ended 0 Months Ended
Nov. 30, 2014
USD ($)
Jun. 30, 2014
USD ($)
Dec. 31, 2015
USD ($)
Dec. 31, 2014
USD ($)
Dec. 31, 2013
USD ($)
Jun. 30, 2014
Foreign Currency Derivatives [Member]
USD ($)
Jun. 30, 2014
Canadian Conventional Assets [Member]
USD ($)
Jun. 30, 2014
Canadian Conventional Assets [Member]
CAD ($)
Sep. 30, 2014
U.S. Assets [Member]
USD ($)
Mar. 7, 2014
General Partner And EnLink [Member]
USD ($)
Dec. 31, 2015
General Partner And EnLink [Member]
Feb. 28, 2014
GeoSouthern Intermediate Holdings, LLC [Member]
USD ($)
Dec. 31, 2015
GeoSouthern Intermediate Holdings, LLC [Member]
Feb. 28, 2014
GeoSouthern Intermediate Holdings, LLC [Member]
USD ($)
acre
Dec. 17, 2015
Powder River Basin
USD ($)
Dec. 31, 2015
Powder River Basin
USD ($)
Dec. 17, 2015
Powder River Basin
acre
Dec. 17, 2015
Powder River Basin
Common Stock [Member]
Equity Issued in Business Combination [Member]
USD ($)
Dec. 31, 2015
Powder River Basin
Common Stock [Member]
Equity Issued in Business Combination [Member]
Jan. 7, 2016
Anadarko Basin STACK [Member]
Subsequent Event [Member]
USD ($)
Dec. 31, 2015
Anadarko Basin STACK [Member]
Subsequent Event [Member]
Jan. 7, 2016
Anadarko Basin STACK [Member]
Subsequent Event [Member]
acre
Jan. 7, 2016
Anadarko Basin STACK [Member]
Subsequent Event [Member]
Common Stock [Member]
Equity Issued in Business Combination [Member]
USD ($)
Apr. 30, 2015
EnLink [Member]
Victoria Express Pipeline [Member]
USD ($)
May 31, 2015
EnLink [Member]
EnLink Midstream Holdings [Member]
USD ($)
Feb. 28, 2015
EnLink [Member]
EnLink Midstream Holdings [Member]
USD ($)
Jan. 7, 2016
EnLink [Member]
Anadarko Basin [Member]
Subsequent Event [Member]
USD ($)
Dec. 31, 2015
EnLink [Member]
Anadarko Basin [Member]
Subsequent Event [Member]
Jan. 7, 2016
EnLink [Member]
Anadarko Basin [Member]
Subsequent Event [Member]
USD ($)
Jan. 7, 2016
General Partner [Member]
Anadarko Basin [Member]
Subsequent Event [Member]
Common Stock [Member]
Equity Issued in Business Combination [Member]
Business Acquisition [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Close date of acquisition
 
 
 
 
 
 
 
 
 
 
Mar. 07, 2014 
 
Feb. 28, 2014 
 
 
Dec. 17, 2015 
 
 
 
 
Jan. 07, 2016 
 
 
 
 
 
 
Jan. 07, 2016 
 
 
Ownership interest percentage acquired
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
25.00% 
25.00% 
 
 
 
 
Aggregate purchase price
 
 
 
 
 
 
 
 
 
 
 
$ 6,000,000,000 
 
 
$ 499,000,000 
 
 
 
 
$ 1,500,000,000 
 
 
 
$ 176,000,000 
 
 
$ 1,500,000,000 
 
 
 
Unproved properties
 
 
 
 
 
 
 
 
 
 
 
 
 
1,007,000,000 
 
386,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Proved properties
 
 
 
 
 
 
 
 
 
 
 
 
 
5,026,000,000 
 
113,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Equity units value
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
199,000,000 
 
 
 
 
659,000,000 
 
900,000,000 
925,000,000 
 
 
 
 
Units issued for acquisition
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
7.0 
 
 
 
 
 
 
 
 
 
 
15.6 
Cash payment to acquire interest
 
 
 
 
 
 
 
 
 
100,000,000 
 
 
 
 
300,000,000 
 
 
 
 
850,000,000 
 
 
 
 
 
 
800,000,000 
 
 
 
Amount committed to pay
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
500,000,000 
 
Commitment to pay cash due date
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
24 months 
 
 
 
Number of net acres acquired
 
 
 
 
 
 
 
 
 
 
 
 
 
82,000 
 
 
253,000 
 
 
 
 
80,000 
 
 
 
 
 
 
 
 
Gains and losses on assets sales
 
 
 
1,072,000,000 
(9,000,000)
 
1,100,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Gains and losses on assets sales after tax
 
 
 
 
 
 
600,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Asset retirement obligation settled and divested
 
 
89,000,000 1
1,009,000,000 1
 
 
700,000,000 
 
200,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Derecognition in goodwill allocated to sold assets
 
 
 
 
 
 
(700,000,000)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Foreign currency exchange loss
 
(84,000,000)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Loss on derivative
 
 
 
 
 
29,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Foreign earnings repatriated
 
2,800,000,000 
 
2,800,000,000 
4,300,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Early retirement of senior notes
1,900,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Estimated construction costs assumed
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
35,000,000 
 
 
 
 
 
 
Proceeds from property and equipment divestitures
 
 
$ 107,000,000 
$ 5,120,000,000 
$ 419,000,000 
 
$ 2,800,000,000 
$ 3,125,000,000 
$ 2,200,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Acquisitions And Divestitures (Schedule of EnLink's Acquisition Activity) (Details) (USD $)
In Millions, unless otherwise specified
0 Months Ended 0 Months Ended 0 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Jan. 31, 2015
EnLink [Member]
LPC [Member]
Jan. 31, 2015
EnLink [Member]
LPC [Member]
Mar. 16, 2015
EnLink [Member]
Coronado [Member]
Mar. 16, 2015
EnLink [Member]
Coronado [Member]
Oct. 1, 2015
EnLink [Member]
Matador [Member]
Oct. 1, 2015
EnLink [Member]
Matador [Member]
Business Acquisition [Line Items]
 
 
 
 
 
 
 
 
 
Cash payment to acquire interest
 
 
 
$ 108 
 
$ 240 
 
$ 145 
 
Common units value
 
 
 
 
 
360 
 
 
 
PP&E
 
 
 
 
30 
 
302 
 
36 
Goodwill
5,032 
6,303 
5,858 
 
30 
 
18 
 
Intangibles
 
 
 
 
43 
 
281 
 
99 
Current assets
 
 
 
 
 
 
 
Current liabilities
 
 
 
 
 
 
$ (1)
 
 
Acquisitions And Divestitures (Schedule Of Purchase Price Allocation For GeoSouthern Intermediate Holdings) (Details) (GeoSouthern Intermediate Holdings, LLC [Member], USD $)
In Millions, unless otherwise specified
Feb. 28, 2014
GeoSouthern Intermediate Holdings, LLC [Member]
 
Business Acquisition [Line Items]
 
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 
Derivative Financial Instruments (Schedule Of Open Oil Derivative Positions) (Details)
12 Months Ended
Dec. 31, 2015
bbl
NYMEX West Texas Intermediate Call Options Sold Oil Q1-Q4 2016 [Member]
 
Derivatives, Fair Value [Line Items]
 
Volume Per Day (Bbls/d)
18,500 
Weighted Average Call Option Sold Price
73.18 
Western Canadian Select Basis Swaps Oil Q1 - Q4 2016 [Member]
 
Derivatives, Fair Value [Line Items]
 
Volume Per Day (Bbls/d)
5,249 
Weighted Average Differential To WTI
(13.67)
West Texas Sour Basis Swaps Oil Q1-Q4 2016 [Member]
 
Derivatives, Fair Value [Line Items]
 
Volume Per Day (Bbls/d)
5,000 
Weighted Average Differential To WTI
(0.53)
Midland Sweet Basis Swaps Oil Q1-Q4 2016 [Member]
 
Derivatives, Fair Value [Line Items]
 
Volume Per Day (Bbls/d)
13,000 
Weighted Average Differential To WTI
0.25 
Derivative Financial Instruments (Schedule Of Open Natural Gas Derivative Positions) (Details)
12 Months Ended
Dec. 31, 2015
MMBTU
FERC Henry Hub Price Swaps Natural Gas Q1-Q4 2016 [Member]
 
Derivatives, Fair Value [Line Items]
 
Volume Per Day (MMBtu/d)
54,650 
Weighted Average Price Swap
3.17 
FERC Henry Hub Call Options Sold Natural Gas Q1-Q4 2016 [Member]
 
Derivatives, Fair Value [Line Items]
 
Volume Per Day (MMBtu/d)
400,000 
Weighted Average Call Option Sold Price
4.30 
PEPL Basis Swaps Natural Gas Q1-Q4 2016 [Member]
 
Derivatives, Fair Value [Line Items]
 
Volume Per Day (MMBtu/d)
175,000 
Weighted Average Differential To Henry Hub
(0.34)
El Paso Natural Gas Basis Swaps Q1-Q4 2016 [Member
 
Derivatives, Fair Value [Line Items]
 
Volume Per Day (MMBtu/d)
125,000 
Weighted Average Differential To Henry Hub
(0.12)
Houston Ship Channel Natural Gas Basis Swaps Q1-Q4 2016 [Member]
 
Derivatives, Fair Value [Line Items]
 
Volume Per Day (MMBtu/d)
30,000 
Weighted Average Differential To Henry Hub
0.11 
Transco Zone 4 Natural Gas Basis Swaps Q1-Q4 2016 [Member]
 
Derivatives, Fair Value [Line Items]
 
Volume Per Day (MMBtu/d)
70,000 
Weighted Average Differential To Henry Hub
0.01 
PEPL Basis Swaps Natural Gas Q1-Q4 2017 [Member]
 
Derivatives, Fair Value [Line Items]
 
Volume Per Day (MMBtu/d)
150,000 
Weighted Average Differential To Henry Hub
(0.34)
El Paso Natural Gas Basis Swaps Q1-Q4 2017 [Member]
 
Derivatives, Fair Value [Line Items]
 
Volume Per Day (MMBtu/d)
50,000 
Weighted Average Differential To Henry Hub
(0.14)
Houston Ship Channel Natural Gas Basis Swaps Q1-Q4 2017 [Member]
 
Derivatives, Fair Value [Line Items]
 
Volume Per Day (MMBtu/d)
35,000 
Weighted Average Differential To Henry Hub
0.06 
Transco Zone 4 Natural Gas Basis Swaps Q1-Q4 2017 [Member]
 
Derivatives, Fair Value [Line Items]
 
Volume Per Day (MMBtu/d)
185,000 
Weighted Average Differential To Henry Hub
0.03 
Derivative Financial Instruments (Schedule Of Open Interest Rate Swap Derivative Positions) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Interest Rate Contract 0.92% Expiration December 2016 [Member]
 
Derivative [Line Items]
 
Notional
$ 100 
Rate Received
Three Month LIBOR 
Rate Paid, percent
0.92% 
Expiration
Dec. 31, 2016 
Interest Rate Contract 1.76% Expiration January 2019 [Member]
 
Derivative [Line Items]
 
Notional
100 
Rate Received, percent
1.76% 
Rate Paid
Three Month LIBOR 
Expiration
Jan. 31, 2019 
Interest Rate Contract 2.98% Expiration December 2048 [Member]
 
Derivative [Line Items]
 
Notional
$ 750 
Rate Received
Three Month LIBOR 
Rate Paid, percent
2.98% 
Expiration
Dec. 31, 2018 
Reference period end date
Dec. 31, 2048 1
Derivative Financial Instruments (Schedule Of Open Foreign Exchange Rate Derivative Positions) (Details) (Forward Contract Expiration March 2016 [Member], CAD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Forward Contract Expiration March 2016 [Member]
 
Derivative [Line Items]
 
Currency
Canadian Dollar 
CAD Notional
$ 3,560 
Weighted Average Fixed Rate Received
0.723 
Expiration
Mar. 31, 2016 
Derivative Financial Instruments (Schedule Of Derivative Financial Instruments Included In The Consolidated Comprehensive Statements Of Earnings) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Derivatives, Fair Value [Line Items]
 
 
 
Net gains (losses) recognized in consolidated comprehensive statements of earnings
$ 738 
$ 2,070 
$ (135)
Commodity Derivatives [Member] |
Oil, Gas And NGL Derivatives [Member]
 
 
 
Derivatives, Fair Value [Line Items]
 
 
 
Net gains (losses) recognized in consolidated comprehensive statements of earnings
503 
1,989 
(191)
Commodity Derivatives [Member] |
Marketing And Midstream Revenues [Member]
 
 
 
Derivatives, Fair Value [Line Items]
 
 
 
Net gains (losses) recognized in consolidated comprehensive statements of earnings
22 
 
Interest Rate Derivatives [Member] |
Other Nonoperating Items [Member]
 
 
 
Derivatives, Fair Value [Line Items]
 
 
 
Net gains (losses) recognized in consolidated comprehensive statements of earnings
(20)
(1)
 
Foreign Currency Derivatives [Member] |
Other Nonoperating Items [Member]
 
 
 
Derivatives, Fair Value [Line Items]
 
 
 
Net gains (losses) recognized in consolidated comprehensive statements of earnings
$ 246 
$ 60 
$ 56 
Derivative Financial Instruments (Schedule Of Derivative Financial Instruments Included In The Consolidated Balance Sheets) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2015
Dec. 31, 2014
Derivatives, Fair Value [Line Items]
 
 
Fair value of derivative assets
$ 45 
$ 2,004 
Fair value of derivative liabilities
48 
57 
Commodity Derivatives [Member] |
Derivatives, At Fair Value [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Fair value of derivative assets
34 
1,984 
Commodity Derivatives [Member] |
Other Long-Term Assets [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Fair value of derivative assets
11 
Commodity Derivatives [Member] |
Other Current Liabilities [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Fair value of derivative liabilities
14 
28 
Commodity Derivatives [Member] |
Other Long-Term Liabilities [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Fair value of derivative liabilities
28 
Interest Rate Derivatives [Member] |
Derivatives, At Fair Value [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Fair value of derivative assets
Interest Rate Derivatives [Member] |
Other Long-Term Assets [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Fair value of derivative assets
 
Interest Rate Derivatives [Member] |
Other Current Liabilities [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Fair value of derivative liabilities
 
Interest Rate Derivatives [Member] |
Other Long-Term Liabilities [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Fair value of derivative liabilities
22 
 
Foreign Currency Derivatives [Member] |
Derivatives, At Fair Value [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Fair value of derivative assets
Foreign Currency Derivatives [Member] |
Other Current Liabilities [Member]
 
 
Derivatives, Fair Value [Line Items]
 
 
Fair value of derivative liabilities
$ 8 
 
Share-Based Compensation (Narrative) (Details) (USD $)
In Millions, except Share data, unless otherwise specified
12 Months Ended 3 Months Ended 12 Months Ended 3 Months Ended 12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Jun. 30, 2015
2015 Long-Term Incentive Plan [Member]
Dec. 31, 2015
Stock Options [Member]
Dec. 31, 2014
Stock Options [Member]
Dec. 31, 2013
Stock Options [Member]
Dec. 31, 2015
Performance Share Units [Member]
item
Dec. 31, 2015
EnLink [Member]
Dec. 31, 2014
EnLink [Member]
Mar. 31, 2015
General Partner And EnLink [Member]
Restricted Stock Awards And Units [Member]
Dec. 31, 2015
Minimum [Member]
Stock Options [Member]
Dec. 31, 2015
Minimum [Member]
Restricted Stock Awards And Units [Member]
Dec. 31, 2015
Minimum [Member]
Performance-Based Restricted Stock Awards [Member]
Dec. 31, 2015
Minimum [Member]
Performance Share Units [Member]
Dec. 31, 2015
Maximum [Member]
Stock Options [Member]
Dec. 31, 2015
Maximum [Member]
Restricted Stock Awards And Units [Member]
Dec. 31, 2015
Maximum [Member]
Performance-Based Restricted Stock Awards [Member]
Dec. 31, 2015
Maximum [Member]
Performance Share Units [Member]
Dec. 31, 2014
Accelerated Vesting Of Share-Based Grants For Employees [Member]
Canadian Divestitures [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Vesting period
 
 
 
 
 
 
 
 
 
 
 
0 years 
0 years 
0 years 
 
4 years 
4 years 
4 years 
 
 
Unit-based compensation
$ 225 
$ 199 
$ 157 
 
 
 
 
 
$ 31 
$ 17 
$ 7 
 
 
 
 
 
 
 
 
 
Unrecognized compensation cost
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Restructuring charges
78 
46 
54 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
15 
Number of predetermined peer companies to compare against Devon's total shareholder's return for Performance awards
 
 
 
 
 
 
 
14 
 
 
 
 
 
 
 
 
 
 
 
 
Comparison period of peer companies for performance awards
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2 years 
 
 
 
3 years 
 
Percentage of vesting units to units granted
 
 
 
 
 
 
 
 
 
 
 
 
 
 
0.00% 
 
 
 
200.00% 
 
Shares authorized for issuance
 
 
 
28,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of shares used to calculate shares that may be granted under the Long-Term Incentive Plan, options and stock appreciation rights
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of shares used to calculate shares that may be granted under the Long-Term Incentive Plan, other awards
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Expiration duration of options
 
 
 
 
8 years 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Options, Granted
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Aggregate intrinsic value
 
 
 
 
$ 0.2 
$ 9.0 
$ 0.3 
 
 
 
 
 
 
 
 
 
 
 
 
 
Share-Based Compensation (Schedule Of The Effects Of Share Based Compensation Included In The Consolidated Comprehensive Statement Of Earnings) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Share-based Compensation [Abstract]
 
 
 
Gross general and administrative expense for share-based compensation
$ 225 
$ 199 
$ 157 
Share-based compensation expense capitalized pursuant to the full cost method of accounting for oil and gas properties
63 
53 
60 
Related income tax benefit
$ 45 
$ 42 
$ 29 
Share-Based Compensation (Summary Of Unvested Restricted Stock Awards and Units, Performance-Based Restricted Stock Awards And Performance Share Units) (Details) (USD $)
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Restricted Stock Awards And Units [Member]
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
Unvested at December 31, 2014
4,304,000 
 
 
Granted, awards and units
2,771,000 
 
 
Vested, awards and units
(1,834,000)
 
 
Forfeited, awards and units
(503,000)
 
 
Unvested at December 31, 2015
4,738,000 
 
 
Unvested weighted average grant-date fair value at December 31, 2014
$ 60.85 
 
 
Granted, weighted average grant-date fair value
$ 63.57 
 
 
Vested, weighted average grant-date fair value
$ 60.33 
 
 
Forfeited, weighted average grant-date fair value
$ 62.22 
 
 
Unvested weighted average grant-date fair value at December 31, 2015
$ 62.49 
 
 
Performance-Based Restricted Stock Awards [Member]
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
Unvested at December 31, 2014
380,000 
 
 
Granted, awards and units
236,000 
 
 
Vested, awards and units
(153,000)
 
 
Forfeited, awards and units
(29,000)
 
 
Unvested at December 31, 2015
434,000 
 
 
Unvested weighted average grant-date fair value at December 31, 2014
$ 59.41 
 
 
Granted, weighted average grant-date fair value
$ 62.02 
 
 
Vested, weighted average grant-date fair value
$ 59.49 
 
 
Forfeited, weighted average grant-date fair value
$ 64.18 
 
 
Unvested weighted average grant-date fair value at December 31, 2015
$ 60.48 
 
 
Performance Share Units [Member]
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
Unvested at December 31, 2014
1,477,000 
 
 
Granted, awards and units
786,000 
 
 
Vested, awards and units
(337,000)
 
 
Forfeited, awards and units
(67,000)
 
 
Unvested at December 31, 2015
1,859,000 1
 
 
Unvested weighted average grant-date fair value at December 31, 2014
$ 70.90 
 
 
Granted, weighted average grant-date fair value
$ 84.14 
 
 
Vested, weighted average grant-date fair value
$ 66.00 
 
 
Forfeited, weighted average grant-date fair value
$ 79.20 
 
 
Unvested weighted average grant-date fair value at December 31, 2015
$ 76.17 
 
 
Maximum [Member] |
Performance Share Units [Member]
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
Granted, weighted average grant-date fair value
$ 85.05 
$ 81.05 
$ 63.48 
Maximum common shares that could be awarded based upon total shareholder return
3,700,000 
 
 
Share-Based Compensation (Schedule Of Aggregate Fair Value Restricted Stock, Performance-Based Restricted Stock And Performance Shares, Awards And Units) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Restricted Stock Awards And Units [Member]
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
Aggregate fair value of awards and units, vested
$ 101 
$ 112 
$ 141 
Performance-Based Restricted Stock Awards [Member]
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
Aggregate fair value of awards and units, vested
10 
Performance Share Units [Member]
 
 
 
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
 
 
 
Aggregate fair value of awards and units, vested
$ 22 
 
 
Share-Based Compensation (Summary of Unrecognized Compensation Cost And Weighted Average Period For Recognition) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Restricted Stock Awards And Units [Member]
 
Unrecognized Compensation And Weighted Average Recognition [Line Items]
 
Unrecognized compensation cost (millions)
$ 198 
Weighted average period for recognition (years)
2 years 6 months 
Performance-Based Restricted Stock Awards [Member]
 
Unrecognized Compensation And Weighted Average Recognition [Line Items]
 
Unrecognized compensation cost (millions)
Weighted average period for recognition (years)
2 years 7 months 6 days 
Performance Share Units [Member]
 
Unrecognized Compensation And Weighted Average Recognition [Line Items]
 
Unrecognized compensation cost (millions)
$ 45 
Weighted average period for recognition (years)
1 year 9 months 18 days 
Share-Based Compensation (Summary Of Outstanding Stock Options, Including Changes During The Year) (Details) (Stock Options [Member], USD $)
In Thousands, except Per Share data, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Stock Options [Member]
 
Outstanding at December 31, 2014
4,218 
Options, Exercised
(63)
Options, Expired
(680)
Options, Forfeited
(27)
Outstanding at December 31, 2015
3,448 
Vested and expected to vest, options
3,448 
Exercisable, options
3,448 
Weighted average exercise price, Outstanding, December 31, 2014
$ 70.56 
Exercised, weighted average exercise price
$ 64.25 
Expired, weighted average exercise price
$ 84.36 
Forfeited, weighted average exercise price
$ 66.71 
Weighted average exercise price, Outstanding, December 31, 2015
$ 67.98 
Vested and expected to vest, weighted average exercise price
$ 67.98 
Exercisable, weighted average exercise price
$ 67.98 
Outstanding, weighted average remaining term
2 years 4 months 28 days 
Vested and expected to vest, weighted average remaining term
2 years 4 months 28 days 
Exercisable, weighted average remaining term
2 years 4 months 28 days 
Asset Impairments (Schedule of Asset Impairments) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 12 Months Ended
Dec. 31, 2015
Sep. 30, 2015
Jun. 30, 2015
Mar. 31, 2015
Dec. 31, 2014
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Impaired Long-Lived Assets Held and Used [Line Items]
 
 
 
 
 
 
 
 
Asset impairment charges
$ 5,300 
$ 5,900 
$ 4,200 
$ 5,500 
$ 1,900 
$ 20,820 
$ 1,953 
$ 1,976 
Goodwill, impairment loss
 
 
 
 
 
1,328 
1,941 
 
U.S. Oil And Gas Assets [Member]
 
 
 
 
 
 
 
 
Impaired Long-Lived Assets Held and Used [Line Items]
 
 
 
 
 
 
 
 
Asset impairment charges
 
 
 
 
 
17,992 
 
1,110 
Canada Oil And Gas Assets [Member]
 
 
 
 
 
 
 
 
Impaired Long-Lived Assets Held and Used [Line Items]
 
 
 
 
 
 
 
 
Asset impairment charges
 
 
 
 
 
1,257 
 
843 
Other Assets [Member]
 
 
 
 
 
 
 
 
Impaired Long-Lived Assets Held and Used [Line Items]
 
 
 
 
 
 
 
 
Asset impairment charges
 
 
 
 
 
20 
12 
23 
EnLink [Member]
 
 
 
 
 
 
 
 
Impaired Long-Lived Assets Held and Used [Line Items]
 
 
 
 
 
 
 
 
Goodwill, impairment loss
 
 
 
 
 
1,328 
 
 
Impairment of intangible assets
 
 
 
 
 
223 
 
 
Canada [Member]
 
 
 
 
 
 
 
 
Impaired Long-Lived Assets Held and Used [Line Items]
 
 
 
 
 
 
 
 
Goodwill, impairment loss
 
 
 
 
 
 
$ 1,941 
 
Restructuring Costs (Narrative) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Restructuring Cost and Reserve [Line Items]
 
 
 
Restructuring charges
$ 78 
$ 46 
$ 54 
Office Consolidation [Member]
 
 
 
Restructuring Cost and Reserve [Line Items]
 
 
 
Restructuring costs incurred to date
 
 
134 
Employee Related And Other Costs [Member]
 
 
 
Restructuring Cost and Reserve [Line Items]
 
 
 
Restructuring charges
24 
 
 
Employee Related And Other Costs [Member] |
Canadian Divestitures [Member]
 
 
 
Restructuring Cost and Reserve [Line Items]
 
 
 
Restructuring charges
 
46 
 
Accelerated Vesting Of Share-Based Grants For Employees [Member] |
Canadian Divestitures [Member]
 
 
 
Restructuring Cost and Reserve [Line Items]
 
 
 
Restructuring charges
 
15 
 
Lease Obligations [Member] |
Office Consolidation [Member]
 
 
 
Restructuring Cost and Reserve [Line Items]
 
 
 
Restructuring charges
$ 54 
 
 
Restructuring Costs (Schedule Of The Components Of Restructuring Costs Included In The Comprehensive Consolidated Statements Of Earnings) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Restructuring Cost and Reserve [Line Items]
 
 
 
Restructuring costs
$ 78 
$ 46 
$ 54 
Employee Severance And Retention [Member] |
Canadian Divestitures [Member]
 
 
 
Restructuring Cost and Reserve [Line Items]
 
 
 
Restructuring costs
11 
42 
 
Employee Severance And Retention [Member] |
Office Consolidation And Offshore Divestiture [Member]
 
 
 
Restructuring Cost and Reserve [Line Items]
 
 
 
Restructuring costs
 
 
13 
Lease Obligations And Other [Member] |
Canadian Divestitures [Member]
 
 
 
Restructuring Cost and Reserve [Line Items]
 
 
 
Restructuring costs
13 
 
Lease Obligations And Other [Member] |
Office Consolidation And Offshore Divestiture [Member]
 
 
 
Restructuring Cost and Reserve [Line Items]
 
 
 
Restructuring costs
$ 54 
 
$ 41 
Restructuring Costs (Schedule Of The Activity And Balances Associated With Restructuring Liabilities) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2015
Other Current Liabilities [Member]
Dec. 31, 2014
Other Current Liabilities [Member]
Dec. 31, 2013
Other Current Liabilities [Member]
Dec. 31, 2015
Other Long-Term Liabilities [Member]
Dec. 31, 2014
Other Long-Term Liabilities [Member]
Dec. 31, 2013
Other Long-Term Liabilities [Member]
Dec. 31, 2015
Canadian Divestitures [Member]
Dec. 31, 2014
Canadian Divestitures [Member]
Dec. 31, 2015
Canadian Divestitures [Member]
Other Current Liabilities [Member]
Dec. 31, 2014
Canadian Divestitures [Member]
Other Current Liabilities [Member]
Dec. 31, 2015
Canadian Divestitures [Member]
Other Long-Term Liabilities [Member]
Dec. 31, 2015
Office Consolidation And Offshore Divestiture [Member]
Dec. 31, 2014
Office Consolidation And Offshore Divestiture [Member]
Dec. 31, 2015
Office Consolidation And Offshore Divestiture [Member]
Other Current Liabilities [Member]
Dec. 31, 2014
Office Consolidation And Offshore Divestiture [Member]
Other Current Liabilities [Member]
Dec. 31, 2015
Office Consolidation And Offshore Divestiture [Member]
Other Long-Term Liabilities [Member]
Dec. 31, 2014
Office Consolidation And Offshore Divestiture [Member]
Other Long-Term Liabilities [Member]
Restructuring Cost and Reserve [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Beginning balance
$ 76 
$ 20 
$ 45 
$ 13 
$ 13 
$ 27 
$ 63 
$ 7 
$ 18 
 
 
 
 
 
 
 
 
 
 
 
Restructuring reserve activity
 
 
 
 
 
 
 
 
 
(1)
10 
47 
(29)
(18)
46 
(11)
Ending balance
$ 76 
$ 20 
$ 45 
$ 13 
$ 13 
$ 27 
$ 63 
$ 7 
$ 18 
 
 
 
 
 
 
 
 
 
 
 
Income Taxes (Narrative) (Details) (USD $)
3 Months Ended 12 Months Ended 12 Months Ended 6 Months Ended 12 Months Ended
Dec. 31, 2015
Sep. 30, 2015
Jun. 30, 2015
Mar. 31, 2015
Dec. 31, 2014
Jun. 30, 2014
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2013
$83 Million Deferred Tax Benefit Component [Member]
Dec. 31, 2013
$83 Million Deferred Tax Benefit Component Offsetting Expense Component[Member]
Dec. 31, 2015
Full Cost Impairments Recognized [Member]
Dec. 31, 2014
Assumed Repatriations Of Foreign Earnings [Member]
Dec. 31, 2014
Repatriated Foreign Earnings [Member]
Dec. 31, 2013
Repatriated Foreign Earnings [Member]
Dec. 31, 2015
Canada Federal [Member]
Dec. 31, 2015
Various U.S. States [Member]
Dec. 31, 2015
EnLink [Member]
Dec. 31, 2014
EnLink [Member]
Dec. 31, 2015
Minimum [Member]
Canada Federal [Member]
Dec. 31, 2015
Minimum [Member]
Various U.S. States [Member]
Dec. 31, 2015
Minimum [Member]
EnLink [Member]
Dec. 31, 2015
Minimum [Member]
EnLink [Member]
Canada Federal [Member]
Dec. 31, 2015
Maximum [Member]
Canada Federal [Member]
Dec. 31, 2015
Maximum [Member]
Various U.S. States [Member]
Dec. 31, 2015
Maximum [Member]
EnLink [Member]
Dec. 31, 2014
U.S. Asset Divestiture [Member]
Dec. 31, 2015
U.S. Oil And Gas Assets [Member]
Dec. 31, 2013
U.S. Oil And Gas Assets [Member]
Dec. 31, 2015
U.S. Oil And Gas Operations [Member]
Income Tax [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Goodwill and intangibles impairments
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
$ 1,600,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
Asset impairments
5,300,000,000 
5,900,000,000 
4,200,000,000 
5,500,000,000 
1,900,000,000 
 
20,820,000,000 
1,953,000,000 
1,976,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
17,992,000,000 
1,110,000,000 
18,000,000,000 
Current income tax expense (benefit)
 
 
 
 
 
 
(237,000,000)
477,000,000 
72,000,000 
 
 
 
 
105,000,000 
180,000,000 
 
 
 
 
 
 
 
 
 
 
 
294,000,000 
 
 
 
Income tax expense (benefit)
 
 
 
 
 
 
(6,065,000,000)
2,368,000,000 
169,000,000 
 
 
 
 
 
97,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Deferred income tax expense (benefit)
 
 
 
 
 
 
(5,828,000,000)
1,891,000,000 
97,000,000 
(180,000,000)
97,000,000 
 
 
 
(83,000,000)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Current income tax expense (benefit) on repatriation after foreign tax credits
 
 
 
 
 
 
 
67,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Foreign earnings repatriated
 
 
 
 
 
2,800,000,000 
 
2,800,000,000 
4,300,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Deferred tax liabilities, taxes on unremitted foreign earnings
10,000,000 
 
 
 
 
 
10,000,000 
 
 
 
 
 
143,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Deferred tax liability, other
271,000,000 
 
 
 
160,000,000 
 
271,000,000 
160,000,000 
 
 
 
 
 
 
 
 
 
 
46,000,000 
 
 
 
 
 
 
 
 
 
 
 
Unremitted foreign earnings
1,200,000,000 
 
 
 
 
 
1,200,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Unremitted earnings from subsidiaries not to be permanently reinvested
37,000,000 
 
 
 
 
 
37,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net operating loss carryforwards
175,000,000 
 
 
 
200,000,000 
 
175,000,000 
200,000,000 
 
 
 
 
 
 
 
 
275,000,000 
205,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
Deferred tax assets, Canadian net operating loss carryforward
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
495,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating loss carryforward, expiration date
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Dec. 31, 2030 
Dec. 31, 2018 
Dec. 31, 2028 
 
Dec. 31, 2035 
Dec. 31, 2035 
Dec. 31, 2035 
 
 
 
 
Operating loss carryforward, utilization period
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Dec. 31, 2017 
 
 
 
 
 
 
 
Deferred tax assets, alternative minimum tax credits
6,000,000 
 
 
 
 
 
6,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Deferred tax assets, before valuation allowance
1,578,000,000 
 
 
 
1,101,000,000 
 
1,578,000,000 
1,101,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Deferred tax assets, valuation allowance
967,000,000 
 
 
 
 
 
967,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Valuation allowance against U.S. deferred tax assets, percent
 
 
 
 
 
 
4.00% 
0.00% 
0.00% 
 
 
100.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Unrecognized tax benefits, interest and penalties
29,000,000 
 
 
 
34,000,000 
 
29,000,000 
34,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Unrecognized tax benefit that would impact effective tax rate
$ 131,000,000 
 
 
 
 
 
$ 131,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income Taxes (Schedule Of Income Tax Expense (Benefit)) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Current income tax expense (benefit):
 
 
 
United States federal, current income tax expense (benefit)
$ (243)
$ 152 
$ 73 
Various states, current income tax expense (benefit)
(8)
18 
(5)
Canada and various provinces, current income tax expense (benefit)
14 
307 
Total current tax expense (benefit)
(237)
477 
72 
Deferred income tax expense (benefit):
 
 
 
United States federal, deferred income tax expense (benefit)
(5,033)
1,610 
198 
Various states, deferred income tax expense (benefit)
(336)
93 
59 
Canada and various provinces, deferred income tax expense (benefit)
(459)
188 
(160)
Total deferred tax expense (benefit)
(5,828)
1,891 
97 
Total income tax expense (benefit)
$ (6,065)
$ 2,368 
$ 169 
Income Taxes (Schedule Of Effective Income Tax Rate Reconciliation) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Income Taxes [Abstract]
 
 
 
Total income tax expense (benefit)
$ (6,065)
$ 2,368 
$ 169 
U.S. statutory income tax rate
(35.00%)
35.00% 
35.00% 
Non-deductible goodwill and intangibles impairment
2.00% 
23.00% 
0.00% 
Taxation on Canadian operations
1.00% 
(4.00%)
9.00% 
State income taxes
(1.00%)
2.00% 
23.00% 
Repatriations
0.00% 
2.00% 
65.00% 
Deferred tax asset valuation allowance
4.00% 
0.00% 
0.00% 
Other
0.00% 
0.00% 
(19.00%)
Effective income tax rate
(29.00%)
58.00% 
113.00% 
Income Taxes (Schedule Of Deferred Tax Assets And Liabilities) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2015
Dec. 31, 2014
Income Taxes [Abstract]
 
 
Deferred tax assets, property and equipment
$ 490 
 
Deferred tax assets, asset retirement obligations
485 
458 
Deferred tax assets, accrued liabilities
160 
150 
Deferred tax assets, net operating loss carryforwards
175 
200 
Deferred tax assets, pension benefit obligations
106 
113 
Deferred tax assets, 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)
Deferred tax liabilities, fair value of financial instruments
 
(699)
Deferred tax liabilities, long-term debt
(36)
(115)
Deferred tax liabilities, other
(271)
(160)
Total deferred tax liabilities
(1,494)
(7,914)
Net deferred tax liabilities
$ (883)
$ (6,813)
Income Taxes (Schedule Of Changes In Unrecognized Tax Benefits) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Income Taxes [Abstract]
 
 
Unrecognized tax benefits, Balance at beginning of year
$ 241 
$ 243 
Unrecognized tax benefits, Tax positions taken in prior periods
(19)
 
Unrecognized tax benefits, Tax positions taken in current year
31 
 
Unrecognized tax benefits, Accrual of interest related to tax positions taken
(5)
Unrecognized tax benefits, Settlements
(108)
 
Unrecognized tax benefits, Foreign currency translation
(9)
(4)
Unrecognized tax benefits, Balance at end of year
$ 131 
$ 241 
Income Taxes (Summary Of The Tax Years By Jurisdiction That Remain Subject To Examination By Taxing Authorities) (Details)
12 Months Ended
Dec. 31, 2015
United States Federal [Member] |
Minimum [Member]
 
Tax years open
2008 
United States Federal [Member] |
Maximum [Member]
 
Tax years open
2015 
Various U.S. States [Member] |
Minimum [Member]
 
Tax years open
2008 
Various U.S. States [Member] |
Maximum [Member]
 
Tax years open
2015 
Canada Federal [Member] |
Minimum [Member]
 
Tax years open
2003 
Canada Federal [Member] |
Maximum [Member]
 
Tax years open
2015 
Various Canadian Provinces [Member] |
Minimum [Member]
 
Tax years open
2003 
Various Canadian Provinces [Member] |
Maximum [Member]
 
Tax years open
2015 
Net Earnings (Loss) Per Share Attributable To Devon (Earnings Per Share Computations) (Details) (USD $)
In Millions, except Per Share data, unless otherwise specified
3 Months Ended 12 Months Ended
Dec. 31, 2015
Sep. 30, 2015
Jun. 30, 2015
Mar. 31, 2015
Dec. 31, 2014
Sep. 30, 2014
Jun. 30, 2014
Mar. 31, 2014
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Net earnings (loss):
 
 
 
 
 
 
 
 
 
 
 
Net earnings (loss) attributable to Devon
$ (4,532)
$ (3,507)
$ (2,816)
$ (3,599)
$ (408)
$ 1,016 
$ 675 
$ 324 
$ (14,454)
$ 1,607 
$ (20)
Attributable to participating securities
 
 
 
 
 
 
 
 
(5)
(17)
(2)
Basic and diluted earnings (loss)
 
 
 
 
 
 
 
 
$ (14,459)
$ 1,590 
$ (22)
Common shares:
 
 
 
 
 
 
 
 
 
 
 
Common shares outstanding - total
 
 
 
 
 
 
 
 
412 
409 
406 
Attributable to participating securities
 
 
 
 
 
 
 
 
(5)
(4)
(4)
Common shares outstanding - basic
 
 
 
 
 
 
 
 
407 
405 
402 
Dilutive effect of potential common shares issuable
 
 
 
 
 
 
 
 
 
 
Common shares outstanding - diluted
 
 
 
 
 
 
 
 
407 
407 
402 
Net earnings (loss) per share attributable to Devon:
 
 
 
 
 
 
 
 
 
 
 
Basic
$ (11.12)
$ (8.64)
$ (6.94)
$ (8.88)
$ (1.01)
$ 2.48 
$ 1.65 
$ 0.80 
$ (35.55)
$ 3.93 
$ (0.06)
Diluted
$ (11.12)
$ (8.64)
$ (6.94)
$ (8.88)
$ (1.01)
$ 2.47 
$ 1.64 
$ 0.79 
$ (35.55)
$ 3.91 
$ (0.06)
Antidilutive options
 
 
 
 
 
 
 
 
1
1
1
Other Comprehensive Earnings (Components Of Other Comprehensive Earnings) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
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
21 1
20 1
24 1
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 
Supplemental Information To Statements Of Cash Flows (Schedule Of Supplemental Information To Statements Of Cash Flows) (Narrative) (Details) (USD $)
In Millions, unless otherwise specified
0 Months Ended
Mar. 7, 2014
General Partner And EnLink [Member]
Dec. 17, 2015
Powder River Basin
Dec. 17, 2015
Equity Issued in Business Combination [Member]
Powder River Basin
Common Stock [Member]
Supplemental Cash Flow [Line Items]
 
 
 
Cash payment to acquire interest
$ 100 
$ 300 
 
Noncash common stock issuance in acquisition, value
 
 
$ 199 
Supplemental Information To Statements Of Cash Flows (Schedule Of Supplemental Information To Statements Of Cash Flows) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
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 
Accounts Receivable (Schedule Of Components Of Accounts Receivable) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2015
Dec. 31, 2014
Accounts, Notes, Loans and Financing Receivable [Line Items]
 
 
Joint interest billings
$ 211 
$ 475 
Other
30 
71 
Gross accounts receivable
1,123 
1,975 
Allowance for doubtful accounts
(18)
(16)
Net accounts receivable
1,105 
1,959 
Oil, Gas And NGL Sales [Member]
 
 
Accounts, Notes, Loans and Financing Receivable [Line Items]
 
 
Gross accounts receivable
362 
723 
Marketing And Midstream Revenues [Member]
 
 
Accounts, Notes, Loans and Financing Receivable [Line Items]
 
 
Gross accounts receivable
$ 520 
$ 706 
Goodwill And Other Intangible Assets (Narrative) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Goodwill [Line Items]
 
 
 
Goodwill
$ 5,032 
$ 6,303 
$ 5,858 
Removal of goodwill for asset divestitures
 
706 
 
Goodwill impairments
1,328 
1,941 
 
Amortization expense, next five years
46 
 
 
EnLink Midstream Holdings [Member]
 
 
 
Goodwill [Line Items]
 
 
 
Goodwill
 
 
402 
EnLink [Member]
 
 
 
Goodwill [Line Items]
 
 
 
Goodwill impairments
1,328 
 
 
Impairment of noncash other intangible assets
223 
 
 
Customer Relationships [Member]
 
 
 
Goodwill [Line Items]
 
 
 
Weighted average amortization period
12 years 7 months 6 days 
 
 
Amortization expense of intangible assets
56 
36 
 
Canada [Member]
 
 
 
Goodwill [Line Items]
 
 
 
Goodwill
 
2,838 
Removal of goodwill for asset divestitures
 
706 
 
Goodwill impairments
 
$ 1,941 
 
Goodwill And Other Intangible Assets (Summary Of Goodwill) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Goodwill [Line Items]
 
 
 
Goodwill
$ 5,032 
$ 6,303 
$ 5,858 
Acquired during period
57 
3,283 
 
Asset divestitures
 
(706)
 
Impairment loss
(1,328)
(1,941)
 
Translation adjustments
 
(191)
 
United States [Member]
 
 
 
Goodwill [Line Items]
 
 
 
Goodwill
2,618 
2,618 
2,618 
Canada [Member]
 
 
 
Goodwill [Line Items]
 
 
 
Goodwill
 
2,838 
Asset divestitures
 
(706)
 
Impairment loss
 
(1,941)
 
Translation adjustments
 
(191)
 
EnLink [Member]
 
 
 
Goodwill [Line Items]
 
 
 
Goodwill
2,414 
3,685 
402 
Acquired during period
57 
3,283 
 
Impairment loss
$ (1,328)
 
 
Goodwill And Other Intangible Assets (Schedule Of Other Intangible Assets) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2015
Dec. 31, 2014
Goodwill And Other Intangible Assets [Abstract]
 
 
Customer relationships
$ 745 
$ 569 
Accumulated amortization
(55)
(36)
Net intangibles
$ 690 
$ 533 
Asset Retirement Obligations (Summary Of Changes In Asset Retirement Obligations) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Asset Retirement Obligations [Line Items]
 
 
Asset retirement obligations as of beginning of period
$ 1,399 
$ 2,228 
Liabilities incurred
63 
97 
Liabilities settled and divested
(89)1
(1,009)1
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 
Canadian And U.S. Oil And Gas Properties [Member]
 
 
Asset Retirement Obligations [Line Items]
 
 
Liabilities settled and divested
 
$ (953)
Retirement Plans (Narrative) (Details) (USD $)
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Value of trusts established for certain supplemental plans
$ 22,000,000 
$ 25,000,000 
 
Effect on accumulated postretirement benefit obligation of 1% change in assumed health care cost rates
1,000,000 
 
 
Effect on service cost and interest costs of 1% change in assumed health care cost rates
1,000,000 
 
 
Pension benefits to be funded from the trust
12,000,000 
 
 
Postretirement benefits expected to be funded from cash and cash equivalents
3,000,000 
 
 
Pension Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Accumulated benefit obligation
1,200,000,000 
1,200,000,000 
 
Employer contributions transferred from trusts
$ 11,000,000 
$ 10,000,000 
 
Assumed compensation increase percentage
4.49% 
4.49% 
4.48% 
Postretirement Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Defined benefit plan health care cost trend rate assumed for next fiscal year
7.60% 
 
 
Defined benefit plan ultimate health care cost trend rate
5.00% 
 
 
Retirement Plans (Schedule Of Changes In Defined Benefit Plan Obligations) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Pension Benefits [Member]
 
 
 
Change in benefit obligation:
 
 
 
Benefit obligation at beginning of year
$ 1,377 
$ 1,177 
 
Service cost
33 
30 
36 
Interest cost
52 
55 
51 
Actuarial loss (gain)
(68)
203 
 
Plan settlements
   
(4)
 
Foreign exchange rate changes
(6)
(3)
 
Benefits paid
(80)
(81)
 
Benefit obligation at end of year
1,308 
1,377 
1,177 
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 
 
Plan settlements
   
(4)
 
Benefits paid
(80)
(81)
 
Foreign exchange rate changes
(5)
(1)
 
Fair value of plan assets at end of year
1,059 
1,149 
1,006 
Funded status at end of year
(249)
(228)
 
Amounts recognized in balance sheet:
 
 
 
Other long-term assets
22 
 
Other current liabilities
(12)
(10)
 
Other long-term liabilities
(239)
(240)
 
Net amount
(249)
(228)
 
Amounts recognized in accumulated other comprehensive earnings:
 
 
 
Net actuarial loss (gain)
302 
317 
 
Post service cost (credit)
14 
19 
 
Total
316 
336 
 
Postretirement Benefits [Member]
 
 
 
Change in benefit obligation:
 
 
 
Benefit obligation at beginning of year
24 
24 
 
Service cost
Interest cost
Actuarial loss (gain)
(2)
 
 
Plan amendments
 
 
Plan settlements
   
   
 
Participant contributions
 
Benefits paid
(4)
(4)
 
Benefit obligation at end of year
23 
24 
24 
Change in plan assets:
 
 
 
Employer contributions
 
Participant contributions
 
Plan settlements
   
   
 
Benefits paid
(4)
(4)
 
Funded status at end of year
(23)
(24)
 
Amounts recognized in balance sheet:
 
 
 
Other current liabilities
(3)
(3)
 
Other long-term liabilities
(20)
(21)
 
Net amount
(23)
(24)
 
Amounts recognized in accumulated other comprehensive earnings:
 
 
 
Net actuarial loss (gain)
(11)
(11)
 
Post service cost (credit)
(6)
(9)
 
Total
$ (17)
$ (20)
 
Retirement Plans (Schedule Of Projected Benefit Obligation And Accumulated Benefit Obligation In Excess Of Plan Assets) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2015
Dec. 31, 2014
Retirement Plans [Abstract]
 
 
Projected benefit obligation
$ 244 
$ 250 
Accumulated benefit obligation
199 
191 
Fair value of plan assets
   
   
Retirement Plans (Schedule Of Net Periodic Benefit Cost And Other Comprehensive Loss (Earnings) For Pension And Other Postretirement Benefit Plans) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Pension Benefits [Member]
 
 
 
Net periodic benefit cost:
 
 
 
Service cost
$ 33 
$ 30 
$ 36 
Interest cost
52 
55 
51 
Expected return on plan assets
(58)
(54)
(62)
Curtailment and settlement expense
 
 
Recognition of net actuarial loss (gain)
20 1
18 1
22 1
Recognition of prior service cost
1
1
1
Total net periodic benefit cost
51 2
54 2
51 2
Other comprehensive loss (earnings):
 
 
 
Actuarial loss (gain) arising in current year
57 
(39)
Prior service cost (credit) arising in current year
 
 
Recognition of net actuarial loss, including settlement expense, in net periodic benefit cost
(20)
(19)
(22)
Recognition of prior service cost, including curtailment, in net periodic benefit cost
(4)
(4)
(4)
Total other comprehensive loss (earnings)
(19)
34 
(63)
Total recognized
32 
88 
(12)
Postretirement Benefits [Member]
 
 
 
Net periodic benefit cost:
 
 
 
Service cost
Interest cost
Recognition of net actuarial loss (gain)
(1)1
(1)1
(1)1
Recognition of prior service cost
(2)1
(2)1
(1)1
Total net periodic benefit cost
(1)2
(1)2
 
Other comprehensive loss (earnings):
 
 
 
Actuarial loss (gain) arising in current year
(1)
 
(3)
Prior service cost (credit) arising in current year
 
(8)
Recognition of net actuarial loss, including settlement expense, in net periodic benefit cost
Recognition of prior service cost, including curtailment, in net periodic benefit cost
Total other comprehensive loss (earnings)
(9)
Total recognized
$ 1 
$ 2 
$ (9)
Retirement Plans (Schedule Of Estimated Net Actuarial Loss And Prior Service Cost For The Pension And Other Postretirement Plans That Will Be Amortized From Accumulated Other Comprehensive Income Into Net Periodic Benefit Cost During 2016) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Pension Benefits [Member]
 
Defined Benefit Plan Disclosure [Line Items]
 
Net actuarial loss (gain)
$ 22 
Prior service cost (credit)
Total
26 
Postretirement Benefits [Member]
 
Defined Benefit Plan Disclosure [Line Items]
 
Net actuarial loss (gain)
(2)
Prior service cost (credit)
(1)
Total
$ (3)
Retirement Plans (Schedule Of Weighted Average Actuarial Assumptions Used To Determine Benefit Obligations And Net Periodic Benefit Costs) (Details)
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Pension Benefits [Member]
 
 
 
Assumptions to determine benefit obligations:
 
 
 
Discount rate
4.25% 
3.90% 
4.80% 
Rate of compensation increase
4.49% 
4.49% 
4.48% 
Assumptions to determine net periodic benefit cost:
 
 
 
Discount rate
3.90% 
4.80% 
3.85% 
Rate of compensation increase
4.49% 
4.49% 
4.48% 
Expected return on plan assets
5.22% 
5.42% 
5.48% 
Postretirement Benefits [Member]
 
 
 
Assumptions to determine benefit obligations:
 
 
 
Discount rate
3.63% 
3.25% 
3.65% 
Assumptions to determine net periodic benefit cost:
 
 
 
Discount rate
3.25% 
3.65% 
3.30% 
Retirement Plans (Schedule Of Pension Plan Assets Target Allocation) (Details)
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Fixed Income [Member]
 
 
Target plan asset allocations
70.00% 
70.00% 
Equity Securities [Member]
 
 
Target plan asset allocations
20.00% 
20.00% 
Other Securities [Member]
 
 
Target plan asset allocations
10.00% 
10.00% 
Retirement Plans (Schedule of Fair Value of Pension Assets By Asset Class) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Level 3 Inputs [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
$ 120 
$ 112 
$ 112 
Pension Benefits [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Actual allocation
100.00% 
100.00% 
 
Fair value of plan assets
1,059 
1,149 
1,006 
Pension Benefits [Member] |
Level 1 Inputs [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
500 
364 
 
Pension Benefits [Member] |
Level 2 Inputs [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
439 
673 
 
Pension Benefits [Member] |
Level 3 Inputs [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
120 
112 
 
Pension Benefits [Member] |
Fixed Income Securities [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Actual allocation
68.00% 
70.00% 
 
Fair value of plan assets
721 
799 
 
Pension Benefits [Member] |
Fixed Income Securities [Member] |
Level 1 Inputs [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
494 
349 
 
Pension Benefits [Member] |
Fixed Income Securities [Member] |
Level 2 Inputs [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
227 
450 
 
Pension Benefits [Member] |
United States Treasuries [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Actual allocation
17.00% 
35.00% 
 
Fair value of plan assets
179 
405 
 
Pension Benefits [Member] |
United States Treasuries [Member] |
Level 1 Inputs [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
88 
50 
 
Pension Benefits [Member] |
United States Treasuries [Member] |
Level 2 Inputs [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
91 
355 
 
Pension Benefits [Member] |
Corporate Bonds [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Actual allocation
48.00% 
32.00% 
 
Fair value of plan assets
507 
364 
 
Pension Benefits [Member] |
Corporate Bonds [Member] |
Level 1 Inputs [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
371 
269 
 
Pension Benefits [Member] |
Corporate Bonds [Member] |
Level 2 Inputs [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
136 
95 
 
Pension Benefits [Member] |
Other Bonds [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Actual allocation
3.00% 
3.00% 
 
Fair value of plan assets
35 
30 
 
Pension Benefits [Member] |
Other Bonds [Member] |
Level 1 Inputs [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
35 
30 
 
Pension Benefits [Member] |
Equity Securities [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Actual allocation
18.00% 
17.00% 
 
Fair value of plan assets
186 
197 
 
Pension Benefits [Member] |
Equity Securities [Member] |
Level 2 Inputs [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
186 
197 
 
Pension Benefits [Member] |
Other Securities [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Actual allocation
14.00% 
13.00% 
 
Fair value of plan assets
152 
153 
 
Pension Benefits [Member] |
Other Securities [Member] |
Level 1 Inputs [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
15 
 
Pension Benefits [Member] |
Other Securities [Member] |
Level 2 Inputs [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
26 
26 
 
Pension Benefits [Member] |
Other Securities [Member] |
Level 3 Inputs [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
120 
112 
 
Pension Benefits [Member] |
Hedge Fund And Alternative Investments [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Actual allocation
11.00% 
10.00% 
 
Fair value of plan assets
120 
112 
 
Pension Benefits [Member] |
Hedge Fund And Alternative Investments [Member] |
Level 3 Inputs [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
120 
112 
 
Pension Benefits [Member] |
Short-Term Investments [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Actual allocation
3.00% 
3.00% 
 
Fair value of plan assets
32 
41 
 
Pension Benefits [Member] |
Short-Term Investments [Member] |
Level 1 Inputs [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
15 
 
Pension Benefits [Member] |
Short-Term Investments [Member] |
Level 2 Inputs [Member]
 
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
 
Fair value of plan assets
$ 26 
$ 26 
 
Retirement Plans (Schedule of Changes In Level 3 Plan Assets) (Details) (Level 3 Inputs [Member], USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Level 3 Inputs [Member]
 
 
Defined Benefit Plan Disclosure [Line Items]
 
 
Fair value of plan assets at beginning of year
$ 112 
$ 112 
Purchases (Disbursements)
(6)
Investment returns
Fair value of plan assets at end of year
$ 120 
$ 112 
Retirement Plans (Schedule Of Expected Cash Flow Information For Pension And Other Postretirement Benefit Plans) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Pension Benefits [Member]
 
Defined Benefit Plan Disclosure [Line Items]
 
Devon's 2016 contributions
$ 12 
Benefit payments:
 
2016
73 
2017
75 
2018
77 
2019
78 
2020
83 
2021 to 2025
446 
Postretirement Benefits [Member]
 
Defined Benefit Plan Disclosure [Line Items]
 
Devon's 2016 contributions
Benefit payments:
 
2016
2017
2018
2019
2020
2021 to 2025
$ 7 
Stockholders' Equity (Narrative) (Details) (USD $)
In Millions, except Share data, unless otherwise specified
3 Months Ended 12 Months Ended 1 Months Ended
Jun. 30, 2014
Jun. 30, 2013
Mar. 31, 2013
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Dec. 31, 2015
Equity Issued in Business Combination [Member]
Common Stock [Member]
Powder River Basin
Jan. 31, 2016
Equity Issued in Business Combination [Member]
Common Stock [Member]
Anadarko Basin STACK [Member]
Subsequent Event [Member]
Stockholders Equity [Line Items]
 
 
 
 
 
 
 
 
Common stock, shares authorized (in shares)
 
 
 
1,000,000,000 
1,000,000,000 
 
 
 
Common stock, par value (in dollars per share)
 
 
 
$ 0.10 
$ 0.10 
 
 
 
Preferred Stock, Par or Stated Value Per Share
 
 
 
$ 1.00 
 
 
 
 
Preferred Stock, Shares Authorized
 
 
 
4,500,000 
 
 
 
 
Units issued for acquisition
 
 
 
 
 
 
7,000,000 
23,000,000 
Payments of ordinary dividends
 
 
 
$ 396 
$ 386 
$ 348 
 
 
Dividends paid per share
$ 0.24 
$ 0.22 
$ 0.20 
 
 
 
 
 
Proceeds from stock option exercises
 
 
 
$ 4 
$ 93 
$ 3 
 
 
Noncontrolling Interests (Narrative) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended 1 Months Ended 12 Months Ended 12 Months Ended 1 Months Ended 0 Months Ended 1 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Oct. 31, 2015
EnLink [Member]
Dec. 31, 2015
EnLink [Member]
Dec. 31, 2015
EnLink [Member]
Equity Distribution Agreements [Member]
Dec. 31, 2014
EnLink [Member]
Equity Distribution Agreements [Member]
Dec. 31, 2015
Public Unitholders Interest In EnLink [Member]
Dec. 31, 2015
General Partner And EnLink [Member]
Dec. 31, 2014
General Partner And EnLink [Member]
Dec. 31, 2015
General Partner Interest In EnLink [Member]
Mar. 31, 2014
EnLink [Member]
Oct. 31, 2015
EnLink [Member]
General Partner [Member]
Mar. 31, 2014
EnLink [Member]
Public Unitholders [Member]
Mar. 31, 2014
EnLink [Member]
Public Unitholders Interest In EnLink [Member]
Mar. 31, 2014
EnLink [Member]
General Partner Interest In EnLink [Member]
Mar. 7, 2014
General Partner And EnLink [Member]
Jan. 31, 2016
Subsequent Event [Member]
EnLink [Member]
Jan. 31, 2016
Subsequent Event [Member]
General Partner [Member]
Jan. 31, 2016
Subsequent Event [Member]
Public Unitholders Interest In General Partner [Member]
Jan. 31, 2016
Subsequent Event [Member]
Public Unitholders Interest In EnLink [Member]
Jan. 31, 2016
Subsequent Event [Member]
General Partner Interest In EnLink [Member]
Noncontrolling Interest [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Number of units sold to public for interests in EnLink
26.2 
 
 
 
1.3 
14.8 
 
 
 
 
120.5 
 
92.7 
 
 
 
 
 
 
 
 
Sale of investment in EnLink
$ 654 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net proceeds of common units sold
25 
410 
 
 
25 
410 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Ownership percentage by noncontrolling owners
 
 
 
 
 
 
45.00% 
 
 
27.00% 
 
 
 
41.00% 
7.00% 
 
 
 
36.00% 
52.00% 
23.00% 
Percentage of ownership after stock transactions
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
25.00% 
64.00% 
 
 
 
Ownership interest by Devon
 
 
 
28.00% 
 
 
 
 
 
 
52.00% 
 
 
 
 
 
 
 
 
 
 
Common units issued in private placement
 
 
 
 
 
 
 
 
 
 
 
2.8 
 
 
 
 
 
 
 
 
 
Proceeds of private placement transaction
 
 
50 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash payment to acquire interest
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
100 
 
 
 
 
 
Distributions to unitholders other than Devon
$ 254 
$ 235 
 
 
 
 
 
$ 254 
$ 135 
 
 
 
 
 
 
 
 
 
 
 
 
Commitments And Contingencies (Narrative) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Commitments And Contingencies [Abstract]
 
 
 
Obligation related to the purchase of condensate, year of expiration
2021 
 
 
Total rental expense, including certain office space and equipment under operating lease agreements, net of sub-lease income
$ 88 
$ 64 
$ 26 
Commitments And Contingencies (Schedule Of Commitments And Contingencies) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2015
Purchase Obligations [Member]
 
Long-term Purchase Commitment [Line Items]
 
2016
$ 557 
2017
703 
2018
791 
2019
803 
2020
845 
Thereafter
206 
Total
3,905 
Drilling And Facility Obligations [Member]
 
Long-term Purchase Commitment [Line Items]
 
2016
69 
2017
51 
2018
34 
2019
2020
Thereafter
28 
Total
189 
Operational Agreements [Member]
 
Long-term Purchase Commitment [Line Items]
 
2016
994 
2017
972 
2018
936 
2019
402 
2020
255 
Thereafter
1,042 
Total
4,601 
Office And Equipment Leases [Member]
 
Long-term Purchase Commitment [Line Items]
 
2016
70 
2017
58 
2018
76 
2019
68 
2020
42 
Thereafter
129 
Total
$ 443 
Fair Value Measurements (Schedule Of Carrying Value And Fair Value Measurement Information For Financial Assets And Liabilities) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2015
Dec. 31, 2014
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Derivatives, assets
$ 45 
$ 2,004 
Derivatives, liabilities
(48)
(57)
Carrying Amount [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Cash equivalents
1,871 
950 
Debt
(13,113)
(11,262)
Capital lease obligations
(17)
(20)
Total Fair Value [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Cash equivalents
1,871 
950 
Debt
(11,927)
(12,472)
Capital lease obligations
(16)
(20)
Level 1 Inputs [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Cash equivalents
1,471 
340 
Level 2 Inputs [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Cash equivalents
400 
610 
Debt
(11,927)
(12,472)
Capital lease obligations
(16)
(20)
Commodity Derivatives [Member] |
Carrying Amount [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Derivatives, assets
35 
1,995 
Derivatives, liabilities
(18)
(56)
Commodity Derivatives [Member] |
Total Fair Value [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Derivatives, assets
35 
1,995 
Derivatives, liabilities
(18)
(56)
Commodity Derivatives [Member] |
Level 2 Inputs [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Derivatives, assets
35 
1,995 
Derivatives, liabilities
(18)
(56)
Interest Rate Derivatives [Member] |
Carrying Amount [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Derivatives, assets
Derivatives, liabilities
(22)
(1)
Interest Rate Derivatives [Member] |
Total Fair Value [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Derivatives, assets
Derivatives, liabilities
(22)
(1)
Interest Rate Derivatives [Member] |
Level 2 Inputs [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Derivatives, assets
Derivatives, liabilities
(22)
(1)
Foreign Currency Derivatives [Member] |
Carrying Amount [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Derivatives, assets
Derivatives, liabilities
(8)
 
Foreign Currency Derivatives [Member] |
Total Fair Value [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Derivatives, assets
Derivatives, liabilities
(8)
 
Foreign Currency Derivatives [Member] |
Level 2 Inputs [Member]
 
 
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
 
 
Derivatives, assets
Derivatives, liabilities
$ (8)
 
Segment information (Condensed Statements Of Comprehensive Earnings And Balance Sheets Of Reportable Segments) (Details) (USD $)
In Millions, unless otherwise specified
3 Months Ended 12 Months Ended
Dec. 31, 2015
Sep. 30, 2015
Jun. 30, 2015
Mar. 31, 2015
Dec. 31, 2014
Sep. 30, 2014
Jun. 30, 2014
Mar. 31, 2014
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Revenues from external customers
$ 2,886 
$ 3,601 
$ 3,393 
$ 3,265 
$ 5,995 
$ 5,336 
$ 4,510 
$ 3,725 
$ 13,145 
$ 19,566 
$ 10,397 
Depreciation, depletion and amortization
 
 
 
 
 
 
 
 
3,129 
3,319 
2,780 
Asset impairments
5,300 
5,900 
4,200 
5,500 
1,900 
 
 
 
20,820 
1,953 
1,976 
Gains and losses on asset sales
 
 
 
 
 
 
 
 
 
(1,072)
Interest expense
 
 
 
 
 
 
 
 
523 
536 
437 
Earnings (loss) before income taxes
(5,542)
(5,623)
(4,479)
(5,624)
291 
1,654 
1,554 
560 
(21,268)
4,059 
149 
Income tax expense (benefit)
 
 
 
 
 
 
 
 
(6,065)
2,368 
169 
Net earnings (loss)
 
 
 
 
 
 
 
 
(15,203)
1,691 
(20)
Net earnings (loss) attributable to noncontrolling interests
 
 
 
 
 
 
 
 
(749)
84 
 
Net earnings (loss) attributable to Devon
(4,532)
(3,507)
(2,816)
(3,599)
(408)
1,016 
675 
324 
(14,454)
1,607 
(20)
Property and equipment, net
19,068 
 
 
 
36,296 
 
 
 
19,068 
36,296 
28,447 
Total assets
29,532 
 
 
 
50,637 
 
 
 
29,532 
50,637 
42,877 
Capital expenditures
 
 
 
 
 
 
 
 
6,233 
13,559 
6,643 
Eliminations [Member]
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Interest expense
 
 
 
 
 
 
 
 
(46)
(44)
(35)
Total assets
(97)
 
 
 
(124)
 
 
 
(97)
(124)
 
Eliminations [Member] |
Intersegment [Member]
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Revenues from external customers
 
 
 
 
 
 
 
 
(679)
(859)
(1,362)
United States [Member]
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Number of reportable segments
 
 
 
 
 
 
 
 
 
 
United States [Member] |
Operating Segments [Member]
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Revenues from external customers
 
 
 
 
 
 
 
 
8,360 1
14,854 1
6,807 1
Depreciation, depletion and amortization
 
 
 
 
 
 
 
 
2,220 1
2,475 1
1,744 1
Asset impairments
 
 
 
 
 
 
 
 
18,000 1
12 1
1,133 1
Gains and losses on asset sales
 
 
 
 
 
 
 
 
 
1
 
Interest expense
 
 
 
 
 
 
 
 
368 1
441 1
392 1
Earnings (loss) before income taxes
 
 
 
 
 
 
 
 
(18,214)1
4,390 1
495 1
Income tax expense (benefit)
 
 
 
 
 
 
 
 
(5,650)1
1,797 1
258 1
Net earnings (loss)
 
 
 
 
 
 
 
 
(12,564)1
2,593 1
237 1
Net earnings (loss) attributable to noncontrolling interests
 
 
 
 
 
 
 
 
1
1
 
Net earnings (loss) attributable to Devon
 
 
 
 
 
 
 
 
(12,565)1
2,592 1
 
Property and equipment, net
8,811 1
 
 
 
24,463 1
 
 
 
8,811 1
24,463 1
18,201 1
Total assets
14,600 1
 
 
 
32,037 1
 
 
 
14,600 1
32,037 1
27,080 1
Capital expenditures
 
 
 
 
 
 
 
 
4,575 1
11,214 1
4,589 1
Canada [Member] |
Operating Segments [Member]
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Revenues from external customers
 
 
 
 
 
 
 
 
1,012 
2,063 
2,656 
Depreciation, depletion and amortization
 
 
 
 
 
 
 
 
522 
560 
849 
Asset impairments
 
 
 
 
 
 
 
 
1,257 
1,941 
843 
Gains and losses on asset sales
 
 
 
 
 
 
 
 
 
(1,077)
 
Interest expense
 
 
 
 
 
 
 
 
94 
85 
80 
Earnings (loss) before income taxes
 
 
 
 
 
 
 
 
(1,670)
(657)
(532)
Income tax expense (benefit)
 
 
 
 
 
 
 
 
(445)
495 
(156)
Net earnings (loss)
 
 
 
 
 
 
 
 
(1,225)
(1,152)
(376)
Net earnings (loss) attributable to Devon
 
 
 
 
 
 
 
 
(1,225)
(1,152)
 
Property and equipment, net
4,590 
 
 
 
6,790 
 
 
 
4,590 
6,790 
8,478 
Total assets
5,464 
 
 
 
8,517 
 
 
 
5,464 
8,517 
13,560 
Capital expenditures
 
 
 
 
 
 
 
 
680 
1,344 
1,841 
General Partner And EnLink [Member] |
Operating Segments [Member]
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Revenues from external customers
 
 
 
 
 
 
 
 
3,773 1
2,649 1
934 1
Depreciation, depletion and amortization
 
 
 
 
 
 
 
 
387 1
284 1
187 1
Asset impairments
 
 
 
 
 
 
 
 
1,563 1
 
 
Interest expense
 
 
 
 
 
 
 
 
107 1
54 1
 
Earnings (loss) before income taxes
 
 
 
 
 
 
 
 
(1,384)1
326 1
186 1
Income tax expense (benefit)
 
 
 
 
 
 
 
 
30 1
76 1
67 1
Net earnings (loss)
 
 
 
 
 
 
 
 
(1,414)1
250 1
119 1
Net earnings (loss) attributable to noncontrolling interests
 
 
 
 
 
 
 
 
(750)1
83 1
 
Net earnings (loss) attributable to Devon
 
 
 
 
 
 
 
 
(664)1
167 1
 
Property and equipment, net
5,667 1
 
 
 
5,043 1
 
 
 
5,667 1
5,043 1
1,768 1
Total assets
9,565 1
 
 
 
10,207 1
 
 
 
9,565 1
10,207 1
2,237 1
Capital expenditures
 
 
 
 
 
 
 
 
978 1
1,001 1
213 1
General Partner And EnLink [Member] |
Operating Segments [Member] |
Intersegment [Member]
 
 
 
 
 
 
 
 
 
 
 
Segment Reporting Information [Line Items]
 
 
 
 
 
 
 
 
 
 
 
Revenues from external customers
 
 
 
 
 
 
 
 
$ 679 1
$ 859 1
$ 1,362 1
Supplemental Information On Oil And Gas Operations (Narrative) (Details) (USD $)
12 Months Ended 12 Months Ended 12 Months Ended
Dec. 31, 2015
MMBoe
Dec. 31, 2014
MMBoe
Dec. 31, 2013
MMBoe
Dec. 31, 2012
MMBoe
Dec. 31, 2018
Forecast [Member]
Dec. 31, 2017
Forecast [Member]
Dec. 31, 2016
Forecast [Member]
Dec. 31, 2015
Delaware Basin [Member]
MMBoe
Dec. 31, 2015
Jackfish [Member]
MMBoe
Dec. 31, 2014
Jackfish [Member]
MMBoe
Dec. 31, 2013
Jackfish [Member]
MMBoe
Dec. 31, 2014
Barnett Shale [Member]
MMBoe
Dec. 31, 2013
Barnett Shale [Member]
MMBoe
Dec. 31, 2015
Anadarko Basin [Member]
MMBoe
Dec. 31, 2014
Anadarko Basin [Member]
MMBoe
Dec. 31, 2013
Anadarko Basin [Member]
MMBoe
Dec. 31, 2013
Rocky Mountain [Member]
MMBoe
Dec. 31, 2013
Cana-Woodford Shale [Member]
MMBoe
Dec. 31, 2014
Permian Basin [Member]
MMBoe
Dec. 31, 2013
Permian Basin [Member]
MMBoe
Dec. 31, 2015
Eagle Ford [Member]
MMBoe
Dec. 31, 2014
Eagle Ford [Member]
MMBoe
Dec. 31, 2015
Powder River Basin
MMBoe
Dec. 31, 2015
Powder River Basin
Minimum [Member]
Dec. 31, 2015
Powder River Basin
Maximum [Member]
Dec. 31, 2015
San Juan Basin [Member]
MMBoe
Dec. 31, 2014
Mississippian-Woodford Trend [Member]
MMBoe
Dec. 31, 2013
Mississippian-Woodford Trend [Member]
MMBoe
Dec. 31, 2015
Pike And Powder River Basin [Member]
Costs Deemed For Individual Assessment [Member]
Dec. 31, 2015
United States [Member]
MMBoe
Dec. 31, 2014
United States [Member]
MMBoe
Dec. 31, 2013
United States [Member]
MMBoe
Dec. 31, 2012
United States [Member]
MMBoe
Dec. 31, 2015
Oil and Gas Properties [Member]
Dec. 31, 2014
Oil and Gas Properties [Member]
Dec. 31, 2013
Oil and Gas Properties [Member]
Reserve Quantities [Line Items]
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Capitalized general and administrative expenses
$ 372,000,000 
$ 376,000,000 
$ 368,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Capitalized interest costs
62,000,000 
70,000,000 
56,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
54,000,000 
45,000,000 
42,000,000 
Oil and gas properties not subject to amortization
2,584,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1,900,000,000 
 
 
 
 
 
 
 
Years until development and evaluation will be complete
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
4 years 
5 years 
 
 
 
 
 
 
 
 
 
 
 
Proved undeveloped reserves (MMBoe)
376 1
689 1
701 1
840 1
 
 
 
 
301 
384 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
75 1
305 1
258 1
407 1
 
 
 
Increase (decrease) in proved undeveloped reserves
(45.00%)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Proved undeveloped reserves as a percentage of total proved reserves
17.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Increase (decrease) in proved undeveloped reserves due to drilling and development activities (MMBoe)
24 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Proved undeveloped reserves, conversion to proved developed reserves (MMBoe)
182 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
88 
 
 
 
 
 
 
Proved undeveloped reserves, revisions other than price (MMBoe)
(120)
 
 
 
 
 
 
 
(80)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(40)
 
 
 
 
 
 
Proved undeveloped reserves to proved developed reserves, conversion, percentage
26.00% 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Proved developed and undeveloped reserves, revisions other than price (MMBoe)
(142)1
(65)1
(88)1
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(59)1
(86)1
(117)1
 
 
 
 
Cost incurred related to development and conversion
2,200,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Daily barrel facility capacity (MBbls/d)
 
 
 
 
 
 
 
 
35 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year development schedule will be complete
 
 
 
 
 
 
 
 
Dec. 31, 2030 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Proved undeveloped reserves, remaining undeveloped 5 years or more after initial booking (energy)
 
 
 
 
 
 
 
 
184 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Proved undeveloped reseve, requiring excess of five years to develop
 
 
 
 
 
 
 
 
180 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Proved undeveloped reserves not expected to be developed within next 5 years (energy)
27 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
20 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Proved developed and undeveloped reserves, revisions due to prices (MMBoe)
(302)1
1
94 1
 
 
 
 
 
 
 
 
 
43 
 
 
 
19 
 
 
 
 
 
 
 
 
 
 
 
 
(408)1
38 1
76 1
 
 
 
 
Proved developed and undeveloped reserves, extension and discoveries (MMBoe)
118 1
211 1
261 1
 
 
 
 
38 
11 
38 
36 
54 
30 
14 
42 
 
 
70 
76 
21 
54 
 
 
 
 
14 
32 
 
104 1
197 1
212 1
 
 
 
 
Proved developed and undeveloped reserves, extensions and discoveries related to additions from infill drilling activities (MMBoe)
13 
175 
 
 
 
 
 
11 
 
38 
 
54 
 
 
 
 
23 
33 
 
 
 
 
 
 
 
20 
 
 
 
 
 
 
 
 
Proved developed and undeveloped reserves, purchase of reserves (MMBoe)
1
265 1
1
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
246 
 
 
 
 
 
 
1
265 1
1
 
 
 
 
Proved developed and undeveloped reserves, sale of reserves (MMBoe)
(7)1
(383)1
(15)1
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(7)
 
 
 
(7)1
(207)1
(14)1
 
 
 
 
Average estimated future realized price per barrel of oil used to estimate future cash inflows for proved oil reserves
44.33 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Average estimated future realized price per barrel of bitumen used to estimate future cash inflows for proved bitumen reserves
23.84 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Average estimated future realized price per Mcf of gas used to estimate future cash inflows for proved gas reserves
2.06 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Average estimated future realized price per barrel of natural gas liquids used to estimate future cash inflows for proved NGL reserves
10.11 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Future development costs
6,065,000,000 
10,787,000,000 
10,756,000,000 
 
400,000,000 
600,000,000 
600,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
3,306,000,000 
7,168,000,000 
5,448,000,000 
 
 
 
 
Future dismantlement, abandonment and rehabilitation costs
$ 1,200,000,000 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Supplemental Information On Oil And Gas Operations (Costs Incurred) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Property acquisition costs:
 
 
 
Proved properties
$ 195 
$ 5,210 
$ 22 
Unproved properties
717 
1,177 
216 
Exploration costs
587 
322 
595 
Development costs
3,671 
5,463 
5,089 
Costs incurred
5,170 
12,172 
5,922 
United States [Member]
 
 
 
Property acquisition costs:
 
 
 
Proved properties
193 
5,210 
19 
Unproved properties
634 
1,176 
213 
Exploration costs
478 
270 
443 
Development costs
3,269 
4,400 
3,838 
Costs incurred
4,574 
11,056 
4,513 
Canada [Member]
 
 
 
Property acquisition costs:
 
 
 
Proved properties
 
Unproved properties
83 
Exploration costs
109 
52 
152 
Development costs
402 
1,063 
1,251 
Costs incurred
$ 596 
$ 1,116 
$ 1,409 
Supplemental Information On Oil And Gas Operations (Capitalized Costs) (Details) (USD $)
In Millions, unless otherwise specified
Dec. 31, 2015
Dec. 31, 2014
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
 
 
Proved properties
$ 78,190 
$ 75,738 
Unproved properties
2,584 
2,752 
Total oil and gas properties
80,774 
78,490 
Accumulated DD&A
(69,497)
(49,560)
Net capitalized costs
11,277 
28,930 
United States [Member]
 
 
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
 
 
Proved properties
64,443 
59,849 
Unproved properties
1,352 
1,460 
Total oil and gas properties
65,795 
61,309 
Accumulated DD&A
(58,312)
(38,213)
Net capitalized costs
7,483 
23,096 
Canada [Member]
 
 
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
 
 
Proved properties
13,747 
15,889 
Unproved properties
1,232 
1,292 
Total oil and gas properties
14,979 
17,181 
Accumulated DD&A
(11,185)
(11,347)
Net capitalized costs
$ 3,794 
$ 5,834 
Supplemental Information On Oil And Gas Operations (Oil And Gas Properties Not Subject To Amortization) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
 
Acquisition costs
$ 1,655 
Exploration costs
562 
Development costs
182 
Capitalized interest
185 
Total oil and gas properties not subject to amortization
2,584 
2015 [Member]
 
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
 
Acquisition costs
672 
Exploration costs
191 
Development costs
Capitalized interest
50 
Total oil and gas properties not subject to amortization
922 
2014 [Member]
 
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
 
Acquisition costs
412 
Exploration costs
132 
Development costs
28 
Capitalized interest
37 
Total oil and gas properties not subject to amortization
609 
2013 [Member]
 
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
 
Acquisition costs
61 
Exploration costs
69 
Development costs
17 
Capitalized interest
32 
Total oil and gas properties not subject to amortization
179 
Prior to 2013 [Member]
 
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
 
Acquisition costs
510 
Exploration costs
170 
Development costs
128 
Capitalized interest
66 
Total oil and gas properties not subject to amortization
$ 874 
Supplemental Information On Oil And Gas Operations (Results Of Operations) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
 
 
 
Oil, gas and NGL sales
$ 5,382 
$ 9,910 
$ 8,522 
Lease operating expenses
(2,104)
(2,332)
(2,268)
General and administrative expenses
(224)
(210)
(202)
Production and property taxes
(342)
(503)
(439)
Depreciation, depletion and amortization
(2,581)
(2,896)
(2,465)
Asset impairments
(19,249)
 
(1,953)
Gain on sale of assets
 
1,077 
 
Accretion of asset retirement obligations
(74)
(88)
(111)
Income tax benefit (expense)
5,861 
(1,767)
(422)
Results of operations
(13,331)
3,191 1
662 
Depreciation, depletion and amortization per Boe
10.40 
11.79 
9.75 
United States [Member]
 
 
 
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
 
 
 
Oil, gas and NGL sales
4,356 
7,867 
5,964 
Lease operating expenses
(1,551)
(1,559)
(1,257)
General and administrative expenses
(196)
(153)
(125)
Production and property taxes
(309)
(466)
(380)
Depreciation, depletion and amortization
(2,107)
(2,365)
(1,640)
Asset impairments
(17,992)
 
(1,110)
Accretion of asset retirement obligations
(47)
(49)
(47)
Income tax benefit (expense)
5,547 
(1,199)
(510)
Results of operations
(12,299)
2,076 1
895 
Depreciation, depletion and amortization per Boe
10.21 
11.41 
8.69 
Canada [Member]
 
 
 
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
 
 
 
Oil, gas and NGL sales
1,026 
2,043 
2,558 
Lease operating expenses
(553)
(773)
(1,011)
General and administrative expenses
(28)
(57)
(77)
Production and property taxes
(33)
(37)
(59)
Depreciation, depletion and amortization
(474)
(531)
(825)
Asset impairments
(1,257)
 
(843)
Gain on sale of assets
 
1,077 
 
Accretion of asset retirement obligations
(27)
(39)
(64)
Income tax benefit (expense)
314 
(568)
88 
Results of operations
$ (1,032)
$ 1,115 1
$ (233)
Depreciation, depletion and amortization per Boe
11.30 
13.80 
12.87 
Supplemental Information On Oil And Gas Operations (Proved Oil Reserves) (Details)
12 Months Ended
Dec. 31, 2015
MMBbls
Dec. 31, 2014
MMBbls
Dec. 31, 2013
MMBbls
Dec. 31, 2012
MMBbls
Reserve Quantities [Line Items]
 
 
 
 
Conversion rate of gas reserves from barrels of oil to Boe
 
 
 
Oil [Member]
 
 
 
 
Reserve Quantities [Line Items]
 
 
 
 
Proved developed and undeveloped reserves, beginning balance
374 
285 
270 
 
Proved developed and undeveloped reserves, revisions due to prices
(49)
(1)
 
 
Proved developed and undeveloped reserves, revisions other than price
(50)
(37)
(18)
 
Proved developed and undeveloped reserves, extensions and discoveries
54 
99 
76 
 
Proved developed and undeveloped reserves, purchase of reserves
132 
 
Proved developed and undeveloped reserves, production
(70)
(58)
(43)
 
Proved developed and undeveloped reserves, sale of reserves
 
(46)
(1)
 
Proved developed and undeveloped reserves, ending balance
264 
374 
285 
 
Proved developed reserves
225 
278 
250 
228 
Proved developed producing reserves
211 
243 
229 
211 
Proved undeveloped reserves
39 
96 
35 
42 
Oil [Member] |
United States [Member]
 
 
 
 
Reserve Quantities [Line Items]
 
 
 
 
Proved developed and undeveloped reserves, beginning balance
351 
229 
205 
 
Proved developed and undeveloped reserves, revisions due to prices
(53)
(1)
 
Proved developed and undeveloped reserves, revisions other than price
(52)
(38)
(18)
 
Proved developed and undeveloped reserves, extensions and discoveries
51 
94 
69 
 
Proved developed and undeveloped reserves, purchase of reserves
132 
 
Proved developed and undeveloped reserves, production
(60)
(48)
(28)
 
Proved developed and undeveloped reserves, sale of reserves
 
(17)
(1)
 
Proved developed and undeveloped reserves, ending balance
242 
351 
229 
 
Proved developed reserves
203 
255 
194 
166 
Proved developed producing reserves
192 
224 
178 
155 
Proved undeveloped reserves
39 
96 
35 
39 
Oil [Member] |
Canada [Member]
 
 
 
 
Reserve Quantities [Line Items]
 
 
 
 
Proved developed and undeveloped reserves, beginning balance
23 
56 
65 
 
Proved developed and undeveloped reserves, revisions due to prices
 
(1)
 
Proved developed and undeveloped reserves, revisions other than price
 
 
Proved developed and undeveloped reserves, extensions and discoveries
 
Proved developed and undeveloped reserves, production
(10)
(10)
(15)
 
Proved developed and undeveloped reserves, sale of reserves
 
(29)
 
 
Proved developed and undeveloped reserves, ending balance
22 
23 
56 
 
Proved developed reserves
22 
23 
56 
62 
Proved developed producing reserves
19 
19 
51 
56 
Proved undeveloped reserves
 
 
 
Supplemental Information On Oil And Gas Operations (Proved Bitumen Reserves) (Details)
12 Months Ended
Dec. 31, 2015
MMBbls
Dec. 31, 2014
MMBbls
Dec. 31, 2013
MMBbls
Dec. 31, 2012
MMBbls
Reserve Quantities [Line Items]
 
 
 
 
Conversion rate of gas reserves from barrels of oil to Boe
 
 
 
Bitumen [Member]
 
 
 
 
Reserve Quantities [Line Items]
 
 
 
 
Proved developed and undeveloped reserves, beginning balance
521 
552 
528 
 
Proved developed and undeveloped reserves, revisions due to prices
103 
(37)
(11)
 
Proved developed and undeveloped reserves, revisions other than price
(84)
18 
16 
 
Proved developed and undeveloped reserves, extensions and discoveries
11 
38 
 
Proved developed and undeveloped reserves, production
(31)
(20)
(19)
 
Proved developed and undeveloped reserves, ending balance
520 
521 
552 
 
Proved developed reserves
219 
137 
111 
99 
Proved developed producing reserves
219 
137 
111 
99 
Proved undeveloped reserves
301 
384 
441 
429 
Bitumen [Member] |
Canada [Member]
 
 
 
 
Reserve Quantities [Line Items]
 
 
 
 
Proved developed and undeveloped reserves, beginning balance
521 
552 
528 
 
Proved developed and undeveloped reserves, revisions due to prices
103 
(37)
(11)
 
Proved developed and undeveloped reserves, revisions other than price
(84)
18 
16 
 
Proved developed and undeveloped reserves, extensions and discoveries
11 
38 
 
Proved developed and undeveloped reserves, production
(31)
(20)
(19)
 
Proved developed and undeveloped reserves, ending balance
520 
521 
552 
 
Proved developed reserves
219 
137 
111 
99 
Proved developed producing reserves
219 
137 
111 
99 
Proved undeveloped reserves
301 
384 
441 
429 
Supplemental Information On Oil And Gas Operations (Proved Natural Gas Reserves) (Details)
12 Months Ended
Dec. 31, 2015
MMcf
Dec. 31, 2014
MMcf
Dec. 31, 2013
MMcf
Dec. 31, 2012
MMcf
Reserve Quantities [Line Items]
 
 
 
 
Conversion rate of gas reserves from barrels of oil to Boe
 
 
 
Natural Gas [Member]
 
 
 
 
Reserve Quantities [Line Items]
 
 
 
 
Proved developed and undeveloped reserves, beginning balance
7,687,000 
9,308,000 
9,446,000 
 
Proved developed and undeveloped reserves, revisions due to prices
(1,421,000)
236,000 
566,000 
 
Proved developed and undeveloped reserves, revisions other than price
(9,000)
(295,000)
(232,000)
 
Proved developed and undeveloped reserves, extensions and discoveries
171,000 
343,000 
490,000 
 
Proved developed and undeveloped reserves, purchase of reserves
17,000 
457,000 
1,000 
 
Proved developed and undeveloped reserves, production
(587,000)
(701,000)
(874,000)
 
Proved developed and undeveloped reserves, sale of reserves
(37,000)
(1,661,000)
(89,000)
 
Proved developed and undeveloped reserves, ending balance
5,821,000 
7,687,000 
9,308,000 
 
Proved developed reserves
5,707,000 
6,984,000 
8,459,000 
8,070,000 
Proved developed producing reserves
5,559,000 
6,780,000 
8,105,000 
7,715,000 
Proved undeveloped reserves
114,000 
703,000 
849,000 
1,376,000 
Natural Gas [Member] |
United States [Member]
 
 
 
 
Reserve Quantities [Line Items]
 
 
 
 
Proved developed and undeveloped reserves, beginning balance
7,651,000 
8,550,000 
8,762,000 
 
Proved developed and undeveloped reserves, revisions due to prices
(1,412,000)
191,000 
405,000 
 
Proved developed and undeveloped reserves, revisions other than price
(3,000)
(299,000)
(299,000)
 
Proved developed and undeveloped reserves, extensions and discoveries
171,000 
335,000 
471,000 
 
Proved developed and undeveloped reserves, purchase of reserves
17,000 
457,000 
1,000 
 
Proved developed and undeveloped reserves, production
(579,000)
(660,000)
(709,000)
 
Proved developed and undeveloped reserves, sale of reserves
(37,000)
(923,000)
(81,000)
 
Proved developed and undeveloped reserves, ending balance
5,808,000 
7,651,000 
8,550,000 
 
Proved developed reserves
5,694,000 
6,948,000 
7,707,000 
7,391,000 
Proved developed producing reserves
5,546,000 
6,746,000 
7,425,000 
7,091,000 
Proved undeveloped reserves
114,000 
703,000 
843,000 
1,371,000 
Natural Gas [Member] |
Canada [Member]
 
 
 
 
Reserve Quantities [Line Items]
 
 
 
 
Proved developed and undeveloped reserves, beginning balance
36,000 
758,000 
684,000 
 
Proved developed and undeveloped reserves, revisions due to prices
(9,000)
45,000 
161,000 
 
Proved developed and undeveloped reserves, revisions other than price
(6,000)
4,000 
67,000 
 
Proved developed and undeveloped reserves, extensions and discoveries
 
8,000 
19,000 
 
Proved developed and undeveloped reserves, production
(8,000)
(41,000)
(165,000)
 
Proved developed and undeveloped reserves, sale of reserves
 
(738,000)
(8,000)
 
Proved developed and undeveloped reserves, ending balance
13,000 
36,000 
758,000 
 
Proved developed reserves
13,000 
36,000 
752,000 
679,000 
Proved developed producing reserves
13,000 
34,000 
680,000 
624,000 
Proved undeveloped reserves
 
 
6,000 
5,000 
Supplemental Information On Oil And Gas Operations (Proved Natural Gas Liquids Reserves) (Details)
12 Months Ended
Dec. 31, 2015
MMBbls
Dec. 31, 2014
MMBbls
Dec. 31, 2013
MMBbls
Dec. 31, 2012
MMBbls
Reserve Quantities [Line Items]
 
 
 
 
Conversion rate of gas reserves from barrels of oil to Boe
 
 
 
Natural Gas Liquids [Member]
 
 
 
 
Reserve Quantities [Line Items]
 
 
 
 
Proved developed and undeveloped reserves, beginning balance
578 
575 
591 
 
Proved developed and undeveloped reserves, revisions due to prices
(119)
11 
 
Proved developed and undeveloped reserves, revisions other than price
(6)
(47)
 
Proved developed and undeveloped reserves, extensions and discoveries
24 
47 
65 
 
Proved developed and undeveloped reserves, purchase of reserves
57 
 
 
Proved developed and undeveloped reserves, production
(50)
(51)
(45)
 
Proved developed and undeveloped reserves, sale of reserves
 
(60)
 
 
Proved developed and undeveloped reserves, ending balance
428 
578 
575 
 
Proved developed reserves
411 
486 
491 
451 
Proved developed producing reserves
393 
467 
463 
425 
Proved undeveloped reserves
17 
92 
84 
140 
Natural Gas Liquids [Member] |
United States [Member]
 
 
 
 
Reserve Quantities [Line Items]
 
 
 
 
Proved developed and undeveloped reserves, beginning balance
578 
552 
571 
 
Proved developed and undeveloped reserves, revisions due to prices
(119)
 
Proved developed and undeveloped reserves, revisions other than price
(6)
(50)
 
Proved developed and undeveloped reserves, extensions and discoveries
24 
47 
64 
 
Proved developed and undeveloped reserves, purchase of reserves
57 
 
 
Proved developed and undeveloped reserves, production
(50)
(50)
(41)
 
Proved developed and undeveloped reserves, sale of reserves
 
(37)
 
 
Proved developed and undeveloped reserves, ending balance
428 
578 
552 
 
Proved developed reserves
411 
486 
468 
431 
Proved developed producing reserves
393 
467 
442 
406 
Proved undeveloped reserves
17 
92 
84 
140 
Natural Gas Liquids [Member] |
Canada [Member]
 
 
 
 
Reserve Quantities [Line Items]
 
 
 
 
Proved developed and undeveloped reserves, beginning balance
 
23 
20 
 
Proved developed and undeveloped reserves, revisions due to prices
 
 
Proved developed and undeveloped reserves, revisions other than price
 
 
 
Proved developed and undeveloped reserves, extensions and discoveries
 
 
 
Proved developed and undeveloped reserves, production
 
(1)
(4)
 
Proved developed and undeveloped reserves, sale of reserves
 
(23)
 
 
Proved developed and undeveloped reserves, ending balance
 
 
23 
 
Proved developed reserves
 
 
23 
20 
Proved developed producing reserves
 
 
21 
19 
Supplemental Information On Oil And Gas Operations (Proved Total MMBoe Reserves) (Details)
12 Months Ended
Dec. 31, 2015
MMBoe
Mcf
Dec. 31, 2014
MMBoe
Dec. 31, 2013
MMBoe
Dec. 31, 2012
MMBoe
Reserve Quantities [Line Items]
 
 
 
 
Proved developed and undeveloped reserves, beginning balance (MMBoe)
2,754 1
2,963 1
2,963 1
 
Proved developed and undeveloped reserves, revisions due to prices (MMBoe)
(302)1
1
94 1
 
Proved developed and undeveloped reserves, revisions other than price (MMBoe)
(142)1
(65)1
(88)1
 
Proved developed and undeveloped reserves, extension and discoveries (MMBoe)
118 1
211 1
261 1
 
Proved developed and undeveloped reserves, purchase of reserves (MMBoe)
1
265 1
1
 
Proved developed and undeveloped reserves, production (MMBoe)
(248)1
(246)1
(253)1
 
Proved developed and undeveloped reserves, sale of reserves (MMBoe)
(7)1
(383)1
(15)1
 
Proved developed and undeveloped reserves, ending balance (MMBoe)
2,182 1
2,754 1
2,963 1
 
Proved developed reserves (MMBoe)
1,806 1
2,065 1
2,262 1
2,123 1
Proved developed producing reserves (MMBoe)
1,749 1
1,977 1
2,154 1
2,021 1
Proved undeveloped reserves (MMBoe)
376 1
689 1
701 1
840 1
Conversion rate of gas reserves from barrels of oil to Boe
 
 
 
United States [Member]
 
 
 
 
Reserve Quantities [Line Items]
 
 
 
 
Proved developed and undeveloped reserves, beginning balance (MMBoe)
2,205 1
2,205 1
2,236 1
 
Proved developed and undeveloped reserves, revisions due to prices (MMBoe)
(408)1
38 1
76 1
 
Proved developed and undeveloped reserves, revisions other than price (MMBoe)
(59)1
(86)1
(117)1
 
Proved developed and undeveloped reserves, extension and discoveries (MMBoe)
104 1
197 1
212 1
 
Proved developed and undeveloped reserves, purchase of reserves (MMBoe)
1
265 1
1
 
Proved developed and undeveloped reserves, production (MMBoe)
(206)1
(207)1
(189)1
 
Proved developed and undeveloped reserves, sale of reserves (MMBoe)
(7)1
(207)1
(14)1
 
Proved developed and undeveloped reserves, ending balance (MMBoe)
1,638 1
2,205 1
2,205 1
 
Proved developed reserves (MMBoe)
1,563 1
1,900 1
1,947 1
1,829 1
Proved developed producing reserves (MMBoe)
1,509 1
1,815 1
1,857 1
1,743 1
Proved undeveloped reserves (MMBoe)
75 1
305 1
258 1
407 1
Canada [Member]
 
 
 
 
Reserve Quantities [Line Items]
 
 
 
 
Proved developed and undeveloped reserves, beginning balance (MMBoe)
549 1
758 1
727 1
 
Proved developed and undeveloped reserves, revisions due to prices (MMBoe)
106 1
(29)1
18 1
 
Proved developed and undeveloped reserves, revisions other than price (MMBoe)
(83)1
21 1
29 1
 
Proved developed and undeveloped reserves, extension and discoveries (MMBoe)
14 1
14 1
49 1
 
Proved developed and undeveloped reserves, production (MMBoe)
(42)1
(39)1
(64)1
 
Proved developed and undeveloped reserves, sale of reserves (MMBoe)
 
(176)1
(1)1
 
Proved developed and undeveloped reserves, ending balance (MMBoe)
544 1
549 1
758 1
 
Proved developed reserves (MMBoe)
243 1
165 1
315 1
294 1
Proved developed producing reserves (MMBoe)
240 1
162 1
297 1
278 1
Proved undeveloped reserves (MMBoe)
301 1
384 1
443 1
433 1
Supplemental Information On Oil And Gas Operations (Proved Undeveloped Reserves) (Details)
12 Months Ended
Dec. 31, 2015
MMBoe
Dec. 31, 2013
MMBoe
Dec. 31, 2012
MMBoe
Reserve Quantities [Line Items]
 
 
 
Proved undeveloped reserves (MMBoe) beginning balance
689 1
701 1
840 1
Proved undeveloped reserves, extensions and discoveries
24 
 
 
Proved undeveloped reserves, revisions due to prices
(35)
 
 
Proved undeveloped reserves, revisions other than price
(120)
 
 
Proved undeveloped reserves, conversion to proved developed reserves
(182)
 
 
Proved undeveloped reserves (MMBoe) ending balance
376 1
701 1
840 1
United States [Member]
 
 
 
Reserve Quantities [Line Items]
 
 
 
Proved undeveloped reserves (MMBoe) beginning balance
305 1
258 1
407 1
Proved undeveloped reserves, extensions and discoveries
13 
 
 
Proved undeveloped reserves, revisions due to prices
(115)
 
 
Proved undeveloped reserves, revisions other than price
(40)
 
 
Proved undeveloped reserves, conversion to proved developed reserves
(88)
 
 
Proved undeveloped reserves (MMBoe) ending balance
75 1
258 1
407 1
Canada [Member]
 
 
 
Reserve Quantities [Line Items]
 
 
 
Proved undeveloped reserves (MMBoe) beginning balance
384 1
443 1
433 1
Proved undeveloped reserves, extensions and discoveries
11 
 
 
Proved undeveloped reserves, revisions due to prices
80 
 
 
Proved undeveloped reserves, revisions other than price
(80)
 
 
Proved undeveloped reserves, conversion to proved developed reserves
(94)
 
 
Proved undeveloped reserves (MMBoe) ending balance
301 1
443 1
433 1
Supplemental Information On Oil And Gas Operations (Schedule Of Principal Changes In The Standardized Measure Of Discounted Future Net Cash Flows Attributable To Proved Reserves) (Details) (USD $)
In Millions, unless otherwise specified
12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Supplemental Information On Oil And Gas Operations [Abstract]
 
 
 
Standardized measure of discounted future net cash flows, 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)
Standardized measure of discounted future net cash flows, ending balance
$ 6,688 
$ 20,474 
$ 15,741 
Supplemental Quarterly Financial Information (Narrative) (Details) (USD $)
In Millions, except Per Share data, unless otherwise specified
3 Months Ended 12 Months Ended
Dec. 31, 2015
Sep. 30, 2015
Jun. 30, 2015
Mar. 31, 2015
Dec. 31, 2014
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Quarterly Financial Data [Abstract]
 
 
 
 
 
 
 
 
Asset impairments
$ 5,300 
$ 5,900 
$ 4,200 
$ 5,500 
$ 1,900 
$ 20,820 
$ 1,953 
$ 1,976 
Asset impairment per diluted share
$ 13.09 
$ 14.41 
$ 10.27 
$ 13.46 
$ 4.79 
 
 
 
Supplemental Quarterly Financial Information (Schedule Of Unaudited Interim Results Of Operations) (Details) (USD $)
In Millions, except Per Share data, unless otherwise specified
3 Months Ended 12 Months Ended
Dec. 31, 2015
Sep. 30, 2015
Jun. 30, 2015
Mar. 31, 2015
Dec. 31, 2014
Sep. 30, 2014
Jun. 30, 2014
Mar. 31, 2014
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Quarterly Financial Data [Abstract]
 
 
 
 
 
 
 
 
 
 
 
Operating revenues
$ 2,886 
$ 3,601 
$ 3,393 
$ 3,265 
$ 5,995 
$ 5,336 
$ 4,510 
$ 3,725 
$ 13,145 
$ 19,566 
$ 10,397 
Earnings (loss) before income taxes
(5,542)
(5,623)
(4,479)
(5,624)
291 
1,654 
1,554 
560 
(21,268)
4,059 
149 
Net earnings (loss) attributable to Devon
$ (4,532)
$ (3,507)
$ (2,816)
$ (3,599)
$ (408)
$ 1,016 
$ 675 
$ 324 
$ (14,454)
$ 1,607 
$ (20)
Basic net earnings (loss) per share attributable to Devon
$ (11.12)
$ (8.64)
$ (6.94)
$ (8.88)
$ (1.01)
$ 2.48 
$ 1.65 
$ 0.80 
$ (35.55)
$ 3.93 
$ (0.06)
Diluted net earnings (loss) per share attributable to Devon
$ (11.12)
$ (8.64)
$ (6.94)
$ (8.88)
$ (1.01)
$ 2.47 
$ 1.64 
$ 0.79 
$ (35.55)
$ 3.91 
$ (0.06)