Document and Entity Information
Document and Entity Information - USD ($) | 12 Months Ended | ||
Dec. 31, 2016 | Feb. 21, 2017 | Jun. 30, 2016 | |
Document And Entity Information [Abstract] | |||
Document Type | 10-K | ||
Amendment Flag | false | ||
Document Period End Date | Dec. 31, 2016 | ||
Document Fiscal Year Focus | 2,016 | ||
Document Fiscal Period Focus | FY | ||
Entity Registrant Name | SOUTHWESTERN ENERGY CO | ||
Entity Central Index Key | 7,332 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Public Float | $ 4,913,492,123 | ||
Entity Common Stock, Shares Outstanding | 497,953,968 | ||
Trading Symbol | SWN |
CONSOLIDATED STATEMENTS OF OPER
CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Operating Revenues: | |||
Gas sales | $ 1,273 | $ 1,946 | $ 2,827 |
Oil sales | 69 | 76 | 19 |
NGL sales | 92 | 73 | 3 |
Marketing | 864 | 863 | 996 |
Gas gathering | 138 | 175 | 193 |
Total Operating Revenues | 2,436 | 3,133 | 4,038 |
Operating Costs and Expenses: | |||
Marketing purchases | 864 | 852 | 980 |
Operating expenses | 592 | 689 | 427 |
General and administrative expenses | 247 | 246 | 221 |
Restructuring charges | 78 | ||
Depreciation, depletion and amortization | 436 | 1,091 | 942 |
Impairment of natural gas and oil properties | 2,321 | 6,950 | |
Gain on sale of assets, net | (283) | ||
Taxes, other than income taxes | 93 | 110 | 95 |
Total Operating Costs and Expenses | 4,631 | 9,655 | 2,665 |
Operating Income (Loss) | (2,195) | (6,522) | 1,373 |
Interest Expense: | |||
Interest on debt | 226 | 200 | 101 |
Other interest charges | 14 | 60 | 13 |
Interest capitalized | (152) | (204) | (55) |
Total Interest Expense | 88 | 56 | 59 |
Gain (Loss) on Derivatives | (339) | 47 | 139 |
Loss on Early Extinguishment of Debt | (51) | ||
Other Income (Loss), Net | 1 | (30) | (4) |
Income (Loss) Before Income Taxes | (2,672) | (6,561) | 1,449 |
Provision (Benefit) for Income Taxes: | |||
Current | (7) | (2) | 21 |
Deferred | (22) | (2,003) | 504 |
Provision (Benefit) for Income Taxes | (29) | (2,005) | 525 |
Net Income (Loss) | (2,643) | (4,556) | 924 |
Mandatory convertible preferred stock dividend | 108 | 106 | |
Net Income (Loss) Attributable to Common Stock | $ (2,751) | $ (4,662) | $ 924 |
Earnings (Loss) Per Common Share: | |||
Basic | $ (6.32) | $ (12.25) | $ 2.63 |
Diluted | $ (6.32) | $ (12.25) | $ 2.62 |
Weighted Average Common Shares Outstanding: | |||
Basic | 435,337,402 | 380,521,039 | 351,446,747 |
Diluted | 435,337,402 | 380,521,039 | 352,410,683 |
CONSOLIDATED STATEMENTS OF COMP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | ||
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) [Abstract] | ||||
Net income (loss) | $ (2,643) | $ (4,556) | $ 924 | |
Change in derivatives: | ||||
Settlements | [1] | (128) | 16 | |
Ineffectiveness | 1 | |||
Change in fair value of derivative instruments | [2] | 29 | 73 | |
Total change in derivatives | (98) | 89 | ||
Change in value of pension and other postretirement liabilities: | ||||
Amortization of prior service cost and net loss included in net periodic pension cost | [3] | 13 | 2 | |
Net gain (loss) incurred in period | [4] | (7) | (3) | (15) |
Total change in value of pension and other postretirement liabilities | 6 | (1) | (15) | |
Change in currency translation adjustment | 3 | (11) | (8) | |
Comprehensive income (loss) | $ (2,634) | $ (4,666) | $ 990 | |
[1] | Net of ($81) million and $10 million in taxes for the years ended December 31, 2015 and 2014, respectively. | |||
[2] | Net of $16 million and $49 million in taxes for the years ended December 31, 2015 and 2014, respectively. | |||
[3] | Net of $8 million in taxes for the year ended December 31, 2016. | |||
[4] | Net of ($4) million and ($10) million in taxes for the years ended December 31, 2016 and 2014, respectively. |
CONSOLIDATED STATEMENTS OF COM4
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Parenthetical) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) [Abstract] | |||
Settlements, tax | $ (81) | $ 10 | |
Change in fair value of derivative instruments, tax | $ 16 | 49 | |
Amortization of prior service cost and net loss included in net periodic pension cost, tax | $ 8 | ||
Net gain (loss) incurred in period, tax | $ (4) | $ (10) |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Current assets: | ||
Cash and cash equivalents | $ 1,423 | $ 15 |
Accounts receivable, net | 363 | 327 |
Derivative assets | 51 | 3 |
Other current assets | 35 | 48 |
Total current assets | 1,872 | 393 |
Natural gas and oil properties, using the full cost method, including $2,105 million as of December 31, 2016 and $3,727 million as of December 31, 2015 excluded from amortization | 22,653 | 22,478 |
Gathering systems | 1,299 | 1,280 |
Other | 537 | 606 |
Less: Accumulated depreciation, depletion and amortization | (19,534) | (16,821) |
Total property and equipment, net | 4,955 | 7,543 |
Other long-term assets | 249 | 150 |
TOTAL ASSETS | 7,076 | 8,086 |
Current liabilities: | ||
Short-term debt | 41 | 1 |
Accounts payable | 473 | 513 |
Taxes payable | 59 | 64 |
Interest payable | 74 | 75 |
Dividends payable | 27 | 27 |
Derivative liabilities | 355 | 3 |
Other current liabilities | 35 | 24 |
Total current liabilities | 1,064 | 707 |
Long-term debt | 4,612 | 4,704 |
Pension and other postretirement liabilities | 49 | 50 |
Other long-term liabilities | 434 | 343 |
Total long-term liabilities | 5,095 | 5,097 |
Commitments and contingencies (see Note 8) | ||
Equity: | ||
Common stock, $0.01 par value; 1,250,000,000 shares authorized; issued 495,248,369 shares as of December 31, 2016 (does not include 2,751,410 shares issued on January 17, 2017 on account of a dividend declared on December 12, 2016) and 390,138,549 as of December 31, 2015 | 5 | 4 |
Preferred stock, $0.01 par value, 10,000,000 shares authorized, 6.25% Series B Mandatory Convertible, $1,000 per share liquidation preference, 1,725,000 shares issued and outstanding as of December 31, 2016 and 2015, conversion in January 2018 | ||
Additional paid-in capital | 4,677 | 3,409 |
Accumulated deficit | (3,725) | (1,082) |
Accumulated other comprehensive loss | (39) | (48) |
Common stock in treasury, 31,269 and 47,149 shares as of December 31, 2016 and 2015, respectively | (1) | (1) |
Total equity | 917 | 2,282 |
TOTAL LIABILITIES AND EQUITY | $ 7,076 | $ 8,086 |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions | Jan. 17, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Natural gas and oil properties, using the full cost method, costs excluded from amortization | $ 2,105 | $ 3,727 | |
Common stock, par value | $ 0.01 | $ 0.01 | |
Common stock, shares authorized | 1,250,000,000 | 1,250,000,000 | |
Common stock, shares issued | 495,248,369 | 390,138,549 | |
Common stock, shares issued as stock dividend | 7,166,389 | ||
Common stock, date dividend to be paid | Jan. 17, 2017 | ||
Common stock, date dividend declared | Dec. 12, 2016 | ||
Treasury stock, shares | 31,269 | 47,149 | |
Subsequent Event [Member] | |||
Common stock, shares issued | 2,751,410 | ||
Common stock, shares issued as stock dividend | 2,751,410 | ||
Series B Preferred Stock [Member] | |||
Preferred stock, par value | $ 0.01 | $ 0.01 | |
Preferred stock, shares authorized | 10,000,000 | 10,000,000 | |
Preferred stock, dividend rate | 6.25% | 6.25% | |
Liquidation preference per share | $ 1,000 | $ 1,000 | |
Preferred stock, shares issued | 1,725,000 | 1,725,000 | |
Preferred stock, shares outstanding | 1,725,000 | 1,725,000 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Cash Flows From Operating Activities: | |||
Net income (loss) | $ (2,643) | $ (4,556) | $ 924 |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||
Depreciation, depletion and amortization | 436 | 1,092 | 942 |
Impairment of natural gas and oil properties | 2,321 | 6,950 | |
Amortization of debt issuance costs | 14 | 53 | 10 |
Deferred income taxes | (22) | (2,003) | 504 |
(Gain) loss on derivatives, net of settlement | 373 | 155 | (130) |
Stock-based compensation | 29 | 26 | 18 |
Gain on sale of assets, net | (283) | ||
Restructuring charges | 30 | ||
Loss on early extinguishment of debt | 51 | ||
Other | 8 | 34 | 2 |
Change in assets and liabilities: | |||
Accounts receivable | (30) | 203 | (66) |
Accounts payable | (69) | (78) | 84 |
Taxes payable | (5) | (28) | 24 |
Interest payable | 9 | ||
Other assets and liabilities | 5 | 6 | 23 |
Net cash provided by operating activities | 498 | 1,580 | 2,335 |
Cash Flows From Investing Activities: | |||
Capital investments | (593) | (1,798) | (2,043) |
Acquisitions | (579) | (5,298) | |
Proceeds from sale of property and equipment | 430 | 729 | 43 |
Other | 1 | 10 | 10 |
Net cash used in investing activities | (162) | (1,638) | (7,288) |
Cash Flows From Financing Activities: | |||
Payments on current portion of long-term debt | (1) | (1) | (1) |
Payments on long-term debt | (1,175) | (500) | |
Payments on short-term debt | (4,500) | ||
Payments on revolving credit facility | (3,268) | (3,024) | (5,179) |
Borrowings under revolving credit facility | 3,152 | 2,840 | 5,196 |
Payments on commercial paper | (242) | (7,988) | |
Borrowings under commercial paper | 242 | 7,988 | |
Change in bank drafts outstanding | (20) | 12 | 11 |
Proceeds from issuance of long-term debt | 1,191 | 2,950 | 500 |
Proceeds from issuance of short-term debt | 4,500 | ||
Debt issuance costs | (17) | (20) | (56) |
Proceeds from exercise of common stock options | 12 | ||
Proceeds from issuance of common stock | 1,247 | 669 | |
Proceeds from issuance of mandatory convertible preferred stock | 1,673 | ||
Preferred stock dividend | (27) | (79) | |
Cash paid for tax withholding | (9) | ||
Other | (1) | ||
Net cash provided by financing activities | 1,072 | 20 | 4,983 |
Increase (decrease) in cash and cash equivalents | 1,408 | (38) | 30 |
Cash and cash equivalents at beginning of year | 15 | 53 | 23 |
Cash and cash equivalents at end of year | $ 1,423 | $ 15 | $ 53 |
CONSOLIDATED STATEMENT OF CHANG
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY - USD ($) $ in Millions | Common Stock [Member] | Preferred Stock [Member]Series B Preferred Stock [Member] | Additional Paid-In Capital [Member]Series B Preferred Stock [Member] | Additional Paid-In Capital [Member] | Retained Earnings (Accumulated Deficit) [Member] | Accumulated Other Comprehensive Income (Loss) [Member] | Common Stock in Treasury [Member] | Series B Preferred Stock [Member] | Total | |
Balance, shares at Dec. 31, 2013 | 352,938,584 | |||||||||
Balance at Dec. 31, 2013 | $ 4 | $ 969 | $ 2,653 | $ (4) | $ 3,622 | |||||
Comprehensive income (loss): | ||||||||||
Net income (loss) | 924 | 924 | ||||||||
Other comprehensive income (loss) | 66 | 66 | ||||||||
Comprehensive income (loss) | 990 | |||||||||
Stock-based compensation | 38 | 38 | ||||||||
Exercise of stock options, shares | 402,190 | |||||||||
Exercise of stock options | 12 | 12 | ||||||||
Issuance of restricted stock, shares | 1,299,367 | |||||||||
Cancellation of restricted stock, shares | (140,703) | |||||||||
Tax withholding - stock compensation, shares | (12,133) | |||||||||
Issuance of stock awards, shares | 1,687 | |||||||||
Balance, shares at Dec. 31, 2014 | 354,488,992 | |||||||||
Balance at Dec. 31, 2014 | $ 4 | 1,019 | 3,577 | 62 | 4,662 | |||||
Comprehensive income (loss): | ||||||||||
Net income (loss) | (4,556) | (4,556) | ||||||||
Other comprehensive income (loss) | (110) | (110) | ||||||||
Comprehensive income (loss) | (4,666) | |||||||||
Stock-based compensation | 48 | 48 | ||||||||
Preferred stock dividend | (106) | (106) | ||||||||
Issuance of stock, shares | 30,000,000 | 1,725,000 | ||||||||
Issuance of stock | $ 1,673 | 669 | $ 1,673 | 669 | ||||||
Issuance of restricted stock, shares | 5,821,125 | |||||||||
Cancellation of restricted stock, shares | (103,162) | |||||||||
Treasury stock - non-qualified plan | $ (1) | (1) | ||||||||
Tax withholding - stock compensation, shares | (73,869) | |||||||||
Issuance of stock awards, shares | 5,463 | |||||||||
Balance, shares at Dec. 31, 2015 | 390,138,549 | 1,725,000 | ||||||||
Balance at Dec. 31, 2015 | $ 4 | 3,409 | (1,082) | (48) | (1) | 2,282 | ||||
Comprehensive income (loss): | ||||||||||
Non-controlling interest | 3 | 3 | ||||||||
Net income (loss) | (2,643) | (2,643) | ||||||||
Other comprehensive income (loss) | 9 | 9 | ||||||||
Comprehensive income (loss) | (2,634) | |||||||||
Stock-based compensation | 58 | 58 | ||||||||
Preferred stock dividend, shares | [1] | 7,166,389 | ||||||||
Preferred stock dividend | [1] | (27) | (27) | |||||||
Exercise of stock options, shares | 44,880 | |||||||||
Issuance of stock, shares | 98,900,000 | |||||||||
Issuance of stock | $ 1 | 1,246 | 1,247 | |||||||
Issuance of restricted stock, shares | 87,472 | |||||||||
Cancellation of restricted stock, shares | (165,483) | |||||||||
Tax withholding - stock compensation, shares | (929,252) | |||||||||
Tax withholding - stock compensation | (9) | (9) | ||||||||
Issuance of stock awards, shares | 5,814 | |||||||||
Balance, shares at Dec. 31, 2016 | 495,248,369 | 1,725,000 | ||||||||
Balance at Dec. 31, 2016 | $ 5 | $ 4,677 | $ (3,725) | $ (39) | $ (1) | $ 917 | ||||
[1] | Does not include 2,751,410 shares issued on January 17, 2017 and distributed to holders of the Company's mandatory convertible preferred stock. |
CONSOLIDATED STATEMENT OF CHAN9
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY (Parenthetical) - shares | Jan. 17, 2017 | Dec. 31, 2016 |
Common stock, shares issued as stock dividend | 7,166,389 | |
Common stock, date dividend declared | Dec. 12, 2016 | |
Subsequent Event [Member] | ||
Common stock, shares issued as stock dividend | 2,751,410 |
Organization And Summary Of Sig
Organization And Summary Of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2016 | |
Organization And Summary Of Significant Accounting Policies [Abstract] | |
Organization And Summary Of Significant Accounting Policies | (1) ORGANIZATION AND SU MMARY OF SIGNIFICANT ACCOUNTING POLICIES Nature of Operations Southwestern Energy Company (including its subsidiaries, collectively “Southwestern” or the “Company”) is an independent energy company engaged in natural gas , oil and NGL exploration, development and production (“E&P”). The Company is also focused on creating and capturing additional value through its natural gas gathering and marketing businesses (“Midstream Services”). Southwestern conducts most of its businesses through subsidiaries and operates principally in two segments: E&P and Midstream Services . Exploration and Production. Southwestern’s primary business is the exploration for and production of natural gas, oil and NGLs, with current operations principally focused on the development of unconventional natural gas reservoirs located in Pennsylvania, West Virginia and Arkansas. The Company’s operations in northeast Pennsylvania, herein referred to as “Northeast Appalachia,” are primarily focused on the unconventional natural gas reservoir known as the Marcellus Shale. Operations in West Virginia and southwest Pennsylvania, herein referred to as “Southwest Appalachia,” are focused on the Marcellus Shale, the Utica and the Upper Devonian unconventional natural gas and oil reservoirs. Collectively, Southwestern refers to its properties located in Pennsylvania and West Virginia as the “Appalachian Basin.” The Company’s operations in Arkansas are primarily focused on an unconventional natural gas reservoir known as the Fayetteville Shale. Southwestern has activities ongoing in Colorado and Louisiana, along with other areas in which it is currently assessing new development opportunities. The Company also has drilling rigs located in Pennsylvania, West Virginia and Arkansas and provides oilfield products and services, principally serving its E&P operations. Midstream Services. Through the Company’s affiliated midstream subsidiaries, Southwestern engages in natural gas gathering activities in Arkansas and Louisiana. These activities primarily support the Company’s E&P operations and generate revenue from fees associated with the gathering of natural gas. Southwestern’s marketing activities capture opportunities that arise through the marketing and transportation of the natural gas, oil and NGLs produced in its E&P operations. Basis of Presentation The consolidated financial statements included in this Annual Report present the Company’s financial position, results of operations and cash flows for the periods presented in accordance with accounting principles generally accepted in the United States (“GAAP”). The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the financial statements, and the amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The Company evaluates subsequent events through the date the financial statements are issued. Certain reclassifications have been made to the prior year financial s tatements to conform to the 2016 presentation. The effects of the reclassifications were not material to the Company’s consolidated financial statements. See Note 1 – New Accounting Standards Implemented in this Report for additional information regarding the reclassifications. Principles of Consolidation The consolidated financial statements include the accounts of Southwestern and its wholly-owned subsidiaries. All significant intercompany accounts and transactions have been eliminated. In 2015, the Company purchased an 86% ownership in a limited partnership which owns and operates a gathering system in Northeast Appalachia as part of the WPX Property Acquisition (as defined and discussed in Note 3 ). Because the Company owns a controlling interest in the partnership, the operating and financial results are consolidated with the Company’s E&P segment results. The investor’s share of the partnership activity is reported in retained earnings in the consolidated financial statements. Net income attributable to noncontrolling interest for the year s ended December 31, 2016 and 2015 was insignificant . Revenue Recognition Natural gas and liquid sales. Natural gas and liquid sales are recognized when the products are sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectability of the revenue is reasonably assured. The Company uses the entitlement method that requires revenue recognition for the Company’s net revenue interest of sales from its properties. Accordingly, natural gas and liquid sales are not recognized for deliveries in excess of the Company’s net revenue interest, while natural gas and liquid sales are recognized for any under-delivered volumes. Production imbalances are generally recorded at estimated sales prices of the anticipated future settlements of the imbalances. The Company had no significant production imbalances at December 31, 2016 or 2015. Marketing. The Company generally markets its natural gas and liquids, as well as some products produced by third parties, to marketers, local distribution companies and end-users, pursuant to a variety of contracts. Marketing revenues are recognized when delivery has occurred, title has transferred, the price is fixed or determinable and collectability of the revenue is reasonably assured. Gas gathering. In certain areas, the Company gathers its natural gas as well as some natural gas produced by third parties pursuant to a variety of contracts. Gas gathering revenues are recognized when the service is performed, the price is fixed or determinable and collectability of the revenue is reasonably assured. Cash and Cash Equivalents Cash and cash equivalents are defined by the Company as short-term, highly liquid investments that have an original maturity of three months or less and deposits in money market mutual funds that are readily convertible into cash. Management considers cash and cash equivalents to have minimal credit and market risk as the Company monitors the credit status of the financial institutions holding its cash and marketable securities . The following table presents a summary of cash and cash equivalents as of December 31, 2016 and December 31, 2015: For the years ended December 31, 2016 2015 (in millions) Cash $ 254 $ 15 Marketable Securities (1) 1,169 – Total $ 1,423 $ 15 (1) Consists of government stable value money market funds . Certain of the Company’s cash accounts are zero-balance controlled disbursement accounts. The Company presents the outstanding checks written against these zero-balance accounts as a component of accounts payable in the accompanying consolidated balance sheets. Outstanding checks included as a component of accounts payable totale d $ 8 m illion and $ 29 million as of December 31, 2016 and 2015 , respectively. Property, Depreciation, Depletion and Amortization Natural Gas and Oil Properties. The Company utilizes the full cost method of accounting for costs related to the exploration, development and acquisition of natural gas and oil properties . Under this method, all such costs (productive and nonproductive), including salari es, benefits and other internal costs directly attributable to these activiti es are capitalized on a country-by- country basis and amortized over the estimated lives of the properties using the units-of-production method. These capitalized costs are subject to a ceiling test that limits such pooled costs , net of applicable deferred taxes, to the aggregate of the present valu e of future net revenues attributable to proved natural gas, oil and NGL reserves discounted at 10% (standardized measure) . Any costs in excess of the ceiling are writ ten off as a non-cash expense. The expense may not be reversed in future periods, even though higher natural gas , oil and NGL prices may subsequently increase the ceiling. C ompanies using the full cost method are required to use the average quoted price from the first day of each month from the previous 12 months, including the impact of derivatives designated for hedge accounting, to calculate the ceiling value of their reserves. Decreases in market prices as well as changes in production rates, levels of reserves, evaluation of costs excluded from amortization, future development costs and production costs could result in future ceiling test impairments. Costs associated with unevaluated properties are excluded from the amortization base until the properties are evaluated or impairment is indicated. The costs associated with unevaluated leasehold acreage and related seismic data, wells currently drilling and related capitalized interest are initially excluded from the amortization base. Leasehold costs are either transferred to the amortization base with the costs of drilling a well on the lease or are assessed at least annually for possible impairment or reduction in value. The Company’s decision to withhold costs from amortization and the timing of the transfer of those costs into the amortization base involves a significant amount of judgment and may be subject to changes over time based on several factors, including drilling plans, availability of capital, project economics and drilling results from adjacent acreage. At December 31, 2016, the Company had a total of $2,105 million of costs excluded from the amortization base, all of which related to its properties in the United States. Inclusion of some or all of these costs in the Company’s United States properties in the future, without adding any associated reserves, could result in additional ceiling test impairments. In the first, second, and third quarters of 2016, the Company’s net book value of its United States and Canada natural gas and oil properties exceeded the ceiling by approximately $641 million (net of tax) at March 31, 2016, $297 million (net of tax) at June 30, 2016 and $506 million (net of tax) at September 30, 2016, resulting in non-cash ceiling test impairments in each of those quarters. Using the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas o f $2.48 per MMBtu, West Texas Intermediate oil of $39.25 per barrel and NGLs of $6.74 per barrel , adjusted for market differentials, the Company’s net book value of its United States natural gas and oil properties did not exceed the ceiling amount and did not result in a ceiling test impairment at December 31, 2016 . The Company had no derivative positions that were designated for hedge accounting as of December 31, 2016 . In the second and third quarters of 2015, the net book value of the Company’s United States natural gas and oil properties exceeded the ceiling by $944 million (net of tax) at June 30, 2015 and $1,746 million (net of tax) at September 30, 2015 and resulted in non-cash ceiling test impairments. Cash flow hedges of natural gas production in place increased the ceiling amount by approximately $60 million and $40 million as of June 30, 2015 and September 30, 2015, respectively. Using the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $ 2.59 per MMBtu , West Texas Intermediate oil of $ 46.79 per barrel and NGLs of $ 6.82 per barrel , adjusted for market differentials, the Company’s net book value of its United States natural gas and oil properties exceeded the ceiling by $1,586 million (net of tax) at December 31, 2015 and resulted in a non-cash ceiling test impairment . The Company had no derivative positions that were designated for hedge accounting as of December 31, 2015. At December 31, 201 4 , the ceiling value of the Company’s reserves was calculated based upon the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $ 4.35 per MMBtu , for West Texas Intermediate oil of $ 91.48 per barrel and NGLs of $23.79 per barrel , ad justed for market differentials. The Company’s net book value of its natural gas and oil properties did not exceed the ceiling amount and did not result in a ceiling test impairment at December 31, 2014. Gathering Systems . The Company’s investment in gathering systems is primarily in a system serving its Fayetteville Shale operations in Arkansas . These assets are being depreciated on a straight-line basis ove r 25 ye ars. Capitalized Interest. Interest is capitalized on the cost of unevaluated natural gas and oil properties that are excluded from amortization and are actively being evaluated. Asset Retirement Obligations . The Company owns natural gas and oil properties , which require expenditures to plug and abandon the wells and reclaim the associated pads when the wells are no longer producing . An asset retirement obligation associated with the retirement of a tangible long-lived asset is recognized as a liability in the period incurred or when it becomes determinable, with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the asset retirement cost, is depreciated over the useful life of the asset. The asset retirement obligation is recorded at its estimated fair value , and accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. Impairment of long-lived assets. The carrying value of non-full cost pool long-lived assets is evaluated for recoverability whenever events or changes in circumstances indicate that it may not be recoverable. I ntangible assets . The carrying value of intangible assets are evaluated for recoverability whenever events or changes in circumstances indicate that it may not be recoverable. Intangible assets are amortized over their useful life. Income Taxes The Company follows the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recorded for the estimated future tax consequences attributable to the differences between the financial carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using the tax rate expected to be in effect for the year in which those temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the year of the enacted rate change. Deferred income taxes are provided to recognize the income tax effect of reporting certain transactions in different years for income tax and financial reporting purposes. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized. The Company accounts for uncertainty in income taxes using a recognition and measurement threshold for tax positions taken or expected to be taken in a tax return. The tax benefit from an uncertain tax position is recognized when it is more likely than not that the position will be sustained upon examination by taxing authorities based on technical merits of the position. The amount of the tax benefit recognized is the largest amount of the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. The effective tax rate and the tax basis of assets and liabilities reflect management’s estimates of the ultimate outcome of various tax uncertainties. The Company recognizes penalties and interest related to uncertain tax positions within the provision (benefit) for income taxes line in the accompanying consolidated statements of operations. Additional information regarding uncertain tax positions can be found in Note 9 – Income Taxes . Derivative Financial Instruments The Company uses derivative financial instruments to manage defined commodity price risks and does not use them for speculative trading purposes. The Company uses fixed price swap agreements and options to financially protect sales of natural gas. Gains and losses result ing from the settlement of derivative contracts have been recognized in gas sales if designated for hedge accounting treatment or gain (loss) on derivative s if not designated for hedge accounting treatment in the consolidated statements of operations when the contracts expire and the related physical transactions of the commodity hedged are recognized. Changes in the fair value of derivative instruments designated as cash flow hedges and not settled are included in other comprehensive income (loss) to the extent that they are effective in offsetting the changes in the cash flows of the hedged item. In contrast, gains and losses from the ineffective portion of derivative contracts designated for hedge accounting trea tment are recognized currently and have an inconsequential impact in the consolidated statement of operations . Gains and losses from the unsettled portion of derivative contracts not designated for hedge accounting treatment are recognized in gain (loss) on derivatives in the consolidated statement of operations. See Note 4 – Derivatives and Risk Management and Note 6 – Fair Value Measurements for a discussion of the Company’s hedging activities. Earnings Per Share Basic earnings per common share is computed by dividing net income (loss) attributable to common stock by the weighted average number of common sha res outstanding during the reportable period . Th e diluted earnings per share calculation adds to the weighted average number of common shares outstanding : the incremental shares that would have been outstanding assuming the exe rcise of dilutive stock options, the vesting of unvested res tricted shares of common stock, performance units, the assumed conversion of mandatory convertible preferred stock and the shares of common stock declared as a preferred stock dividend. An antidilutive impact is an increase in earnings per share or a reduction in net loss per share resulting from the conversion, exercise, or contingent issuance of certain securities. In July 2016, the Company completed an underwritten public offering of 98,900,000 shares of its common stock, with an offering price to the public of $13.00 per share. Net proceeds from the common stock offering were approximately $1,247 million, after underwriting discount and offering expenses. The proceeds from the offering were used to repay $375 million of the $750 million term loan entered into in November 2015 and to settle certain tender offers by purchasing an aggregate principal amount of approximately $700 million of the Company’s outstanding senior notes due in the first quarter of 2018. The remaining proceeds of the offering have been or will be used for general corporate purposes. In January 2015, the Company completed concurrent underwritten public offerings of 30,000,000 shares of its common stock and 34,500,000 depositary shares (both share counts include shares issued as a result of the underwriters exercising their options to purchase additional shares). The common stock offering was priced at $23.00 per share. Net proceeds from the common stock offering were approximately $669 million, after underwriting discount and offering expenses. Net proceeds from the depositary share offering were approximately $1.7 billion, after underwriting discount and offering expenses. Each depositary share represents a 1/20th interest in a share of the Company’s mandatory convertible preferred stock, with a liquidation preference of $1,000 per share (equivalent to a $50 liquidation preference per depositary share). The proceeds from the offerings were used to partially repay borrowings under the Company’s $4.5 billion 364 -day bridge facility with the remaining balance of the bridge facility fully repaid with proceeds from the Company’s January 2015 public offering of $2.2 billion in long-term senior notes. The mandatory convertible preferred stock entitles the holder to a proportional fractional interest in the rights and preferences of the convertible preferred stock, including conversion, dividend, liquidation and voting rights. Unless converted earlier at the option of the holders, on or around January 15, 2018 each share of convertible preferred stock will automatically convert into between 37.0028 and 43.4782 shares of the Company’s common stock (correspondingly, each depositary share will convert into between 1.85014 and 2.17391 shares of the Company’s common stock), subject to customary anti-dilution adjustments, depending on the volume-weighted average price of the Company’s common stock over a 20 trading day averaging period immediately prior to that date. The total potential shares of common stock resulting from the conversion will range from 63,829,830 to 74,999,895 shares. The mandatory convertible preferred stock has the non-forfeitable right to participate on an as-converted basis at the conversion rate then in effect in any common stock dividends declared and as such, is considered a participating security. Accordingly, it is included in the computation of basic and diluted earnings per share, pursuant to the two-class method. In the calculation of basic earnings per share attributable to common shareholders, participating securities are allocated earnings based on actual dividend distributions received plus a proportionate share of undistributed net income attributable to common shareholders, if any, after recognizing distributed earnings. The Company’s participating securities do not participate in undistributed net losses because they are not contractually obligated to do so. On December 12, 2016 , the Company declared its quarterly dividend, payable to holders of the mandatory convertible preferred stock, and announced that it would pay the quarterly dividend in stock, in lieu of cash, to the extent permitted by the certificate of designations for the Series B preferred stock. The Company issued 2,751,410 shares of common stock on January 17, 2017 in payment for the dividend. Dividends declared in the first, second and third quarters of 2016 also were settled in common stock for a total of 7,166,389 shares, while the dividend declared in December 2015 was paid in cash in January 2016. The following table presents the computation of earnings per share for the years ended December 31, 2016, 2015 and 2014: For the years ended December 31, 2016 2015 2014 (in millions, except share/per share amounts) Net income (loss) $ (2,643) $ (4,556) $ 924 Mandatory convertible preferred stock dividend 108 106 – Net income (loss) attributable to common stock $ (2,751) $ (4,662) $ 924 Number of common shares: Weighted average outstanding 435,337,402 380,521,039 351,446,747 Issued upon assumed exercise of outstanding stock options – – 241,603 Effect of issuance of non-vested restricted common stock – – 448,415 Effect of issuance of non-vested performance units – – 273,918 Effect of issuance of mandatory convertible preferred stock – – – Effect of declaration of preferred stock dividends – – – Weighted average and potential dilutive outstanding 435,337,402 380,521,039 352,410,683 Earnings (loss) per common share: Basic $ (6.32) $ (12.25) $ 2.63 Diluted $ (6.32) $ (12.25) $ 2.62 The following table presents the common stock shares equivalent excluded from the calculation of diluted earnings per share for the years ended December 31, 2016, 2015 and 2014 , as they would have had an antidilutive effect: For the years ended December 31, 2016 2015 2014 Unvested stock options 3,692,697 3,835,234 1,446,004 Unvested share-based payment 959,233 1,990,383 29,879 Performance units 884,644 140,414 – Mandatory convertible preferred stock 74,999,895 70,890,312 – Declared and unpaid preferred stock dividends 2,751,410 – – Total 83,287,879 76,856,343 1,475,883 Supplemental Disclosures of Cash Flow Information The following table provides additional information concerning interest and income taxes paid as well as changes in noncash investing activities for the years ended December 31, 2016, 2015, and 2014: For the years ended December 31, 201 6 201 5 201 4 (in millions) Cash paid during the year for interest, net of amounts capitalized $ 75 $ 6 $ 50 Cash paid (received) during the year for income taxes (15) (6) 28 Increase (decrease) in noncash property additions 55 (10) 174 Stock-Based Compensation The Company accounts for stock-based compensation transactions using a fair value method and recognizes an amount equal to the fair value of the stock options and stock-based payment cost in either the consolidated statement of operations or capitalizes the cost into natural gas and oil properties or gathering systems included in property and equipment. Costs are capitalized when they are directly related to the acquisition, exploration and development activities of the Company’s natural gas and oil properties or directly related to the construction of the Company’s gathering systems. Treasury Stock The Company maintains a non-qualified deferred compensation supplemental retirement savings plan for certain key employees whereby participants may elect to defer and contribute a portion of their compensation to a Rabbi Trust, as permitted by the plan. The Company includes the assets and liabilit ies of its supplemental retirement savings plan in its consolidated balance sheet. Shares of the Company’s common stock purchased under the non-qualified deferred compensation arrangement are held in the Rabbi Trust , are presented as treasury stock and are carried at cost. As of December 31, 201 6 , 31,269 shares were accounted for as treasury stock, compared to 47,149 shares at December 31, 2015 . Foreign Currency Translation The Company has designated the Canadian dollar as the functional currency for our activities in Canada. The cumulative translation effects of translating the accounts from the functional currency into the U.S. dollar at current exchange rates are included as a separate component of other comprehensive income within stockholders ’ equity. New Accounting Standards Implemented in this Report In September 2015, the FASB issued Accounting Standards Update No. 2015-16, Business Combinations (Topic 805) (“Update 2015-16”), which seeks to reduce the complexity of amounts recognized in a business combination. The amendments in Update 2015-16 require that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The amendments in Update 2015-16 require that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. The amendments in Update 2015-16 require an entity to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. The amendments in Update 2015-16 are effective for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years. The Company adopted this update in the first quarter of 2016 resulting in no impact on its consolidated results of operations, financial position and cash flows. In May 2015, the FASB issued Accounting Standards Update No. 2015-07, Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (Or Its Equivalent) (“Update 2015-07”), which amends ASC 820, Fair Value Measurement. The standard removes the requirement to categorize within the fair value hierarchy investments for which fair value is measured using the net asset value per share practical expedient and removes certain related disclosure requirements. The amendments in Update 2015-07 are effective for reporting periods beginning after December 15, 2015, with early adoption permitted. The Company adopted this update in the first quarter of 2016 resulting in no impact on its consolidated results of operations, financial position and cash flows. As a result of adoption, certain of the Company’s pension plan assets measured using net asset value as a practical expedient have not been classified in the fair value hierarchy in Note 11 – Retirement and Employee Benefit Plans. In April 2015, the FASB issued Accounting Standards Update No. 2015-03, Interest-Imputation of Interest (Subtopic 835-30) (“Update 2015-03”), in an effort to simplify presentation of debt issuance costs. Update 2015-03 required that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs was not affected by the amendments in this Update. Entities were required to apply the amendments in Update 2015-03 on a retrospective basis, with the balance sheet of each individual period presented adjusted to reflect the period-specific effects of applying the new guidance. In August 2015, the FASB issued Accounting Standards Update No. 2015-15, Interest-Imputation of Interest (Subtopic 835-30) (“Update 2015-15”), which addresse d the presentation or subsequent measurement of debt issuance costs related to line-of-credit arrangements, given the absence of authoritative guidance within Update 2015-03 for debt issuance costs related to line-of-credit arrangements. For public entities, Update 2015-03 and Update 2015-15 are effective for annual reporting periods beginning after December 15, 2015, including interim periods within that reporting period. The Company adopted this update in the first quarter of 2016 resulting in an immaterial impact on its consolidated financial positi on. The Company had $24 million in unamortized debt expense that was classified as a long-term asset at December 31, 2015, which is now presented as a contra-liability as a result of adoption. In November 2014, the FASB issued Accounting Standards Update No. 2014-16, Derivatives and Hedging – Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share Is More Akin to Debt or to Equity (Subtopic 815-15) (“Update 2014-16”), which addressed diversity in practice related to the determination of whether derivative features embedded in hybrid instruments issued in the form of a share should be bifurcated and accounted for separately. For public entities, Update 2014-16 was effective for annual reporting periods beginning after December 15, 2015 including interim periods within that reporting period. The Company adopted this update in the first quarter of 2016 resulting in no impact on its consolidated results of operations, financial position and cash flows. In August 2014, the FASB issued Accounting Standards Update No. 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (Subtopic 205 - 40 ) (“Update 2014-1 5 ”), which requires management to assess a company’s ability to continue as a going concern and to provide related footnote disclosures in certain circumstances. For public entities, Update 2014-1 5 wa s effective for annual reporting periods ending after December 15, 201 6 . The Company adopted this update in the first quarter of 2016 resulting in no impact on its consolidated results of operations, financial position , cash flows and disclosures. New Accounting Standards Not Yet Implemented in this Report In August 2016, the FASB issued Accounting Standards Update No. 2016-15, Statement of Cash Flows (Topic 230) (“Update 2016-15”), which seeks to reduce the existing diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. For public entities, Update 2016-15 becomes effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, with early adoption permitted. The Company is currently evaluating the provisions of Update 2016-15 and assessing the impact, if any, it may have on its consolidated results o |
Reduction In Workforce
Reduction In Workforce | 12 Months Ended |
Dec. 31, 2016 | |
Reduction In Workforce [Abstract] | |
Reduction In Workforce | (2 ) REDUCTION IN WORKFORCE In January 2016, the Company announced a 40% workforce reduction as a result of lower anticipated drilling activity. This reduction was substantially completed in the first quarter of 2016. In April 2016, the Company also partially restructured executive management, which was substantially completed in the second quarter of 2016. The following table presents a summary of the restructuring charges for the year ended December 31, 2016: (in millions) Severance (including payroll taxes) $ 44 Stock-based compensation 24 Pension and other post retirement benefits (1) 5 Other benefits 3 Outplacement services, other 2 Total restructuring charges (2) $ 78 (1) Includes non-cash charges related to the curtailment and settlement of the pension and other postretirement benefit plans. See Note 12 for additional details regarding the Company’s retirement and employee benefit plans. (2) Total restructuring charges were $75 million and $3 million for the Company’s E&P and Midstream Services segments, respectively. The following table presents a summary of liabilities associated with the Company’s restructuring activities for the year ended December 31, 2016, which are reflected in accounts payable on the unaudited condensed consolidated balance sheet: (in millions) Liability at December 31, 2015 $ – Additions 49 Distributions (48) Liability at December 31, 2016 $ 1 Severance payments and other separation costs related to restructuring were substantially completed by the end of 2016. |
Acquisitions And Divestitures
Acquisitions And Divestitures | 12 Months Ended |
Dec. 31, 2016 | |
Acquisitions And Divestitures [Abstract] | |
Acquisitions And Divestitures | ( 3 ) ACQ UISITIONS AND DIVESTITURES In September 2016, the Company sold approximately 55,000 net acres in West Virginia for approximately $422 million, which reflects customary adjustments at closing and is subject to customary post-closing adjustments. The Company accounted for the sale of these natural gas and oil properties as adjustments to capitalized costs, with no recognition of gain or loss as the sales did not involve a significant change in proved reserves or significantly alter the relationship between costs and proved reserves. In September 2016, $48 million of the net proceeds was used to repay borrowings under the Company’s term loan entered into in November 2015. The Company intends to use the remaining net proceeds from the sale for general corporate purposes, including to fund capital projects. In May 2015, the Company sold conventional oil and gas assets located in East Texas and the Arkoma Basin for approximately $211 million. The Company also accounted for the sale of these natural gas and oil properties as adjustments to capitalized costs, with no recognition of gain or loss as the sales did not involve a significant change in proved reserves or significantly alter the relationship between costs and proved reserves . The proceeds from the transaction were used to reduce the Company’s debt. Approximately $205 million of the proceeds received were recorded as a reduction of the capitalized costs of the Company’s natural gas and oil properties in the United States pursuant to the full cost method of accounting. In April 2015, the Company sold its gathering assets located in Bradford and Lycoming counties in northeast Pennsylvania for an adjusted sales price of approximately $489 million. The net book value of these assets was $206 million and was held in the Midstream Services segment as of the closing date. A gain on sale of $283 million was recognized and wa s included in gain on sale of assets, net on the consolidated statement of operations. The assets include d approximately 100 miles of natural gas gathering pipelines, with nearly 600 million cubic feet per day of capacity. The proceeds from the transaction were used to substantially repay borrowings under the Company’s $500 million term loan facility that would have matured in December 2016 . In January 2015, the Company completed an acquisition of certain natural gas and oil assets including approximately 46,700 net acres in northeast Pennsylvania from WPX Energy, Inc. for an adjusted purchase price of $270 million (the “WPX Property Acquisition”). This acreage was producing approximately 50 million net cubic feet of gas per day from 63 operated horizontal wells as of December 2014. As part of this transaction, the Company assumed firm transportation capacity of 260 million cubic feet of gas per day predominantly on the Millennium pipeline. The firm transport is being amortized over 19 years. As of December 31, 2016 and 2015 the Company has amortiz ed $ 17 m illion and $8 million , respectively. This transaction was funded with the revolving credit facility and was accounted for as a business combination. The following table summarizes the consideration paid for the WPX Property Acquisition and the fair value of the assets acquired and liabilities assumed as of the acquisition date: (in millions) Consideration: Cash $ 270 Recognized amounts of identifiable assets acquired and liabilities assumed: Assets acquired: Proved natural gas and oil properties 31 Unproved natural gas and oil properties 114 Intangible asset 109 Gathering system 22 Other 1 Total assets acquired 277 Liabilities assumed: Asset retirement obligations (7) Total liabilities assumed (7) $ 270 In January 2015, the Company completed an acquisition of certain natural gas and oil assets from Statoil ASA including approximately 30,000 net acres in West Virginia and southwest Pennsylvania for $357 million, which was comprise d of approximately 20% of Statoil’s interests in the properties , (the “Statoil Property Acquisition”). All of these assets we re also assets in which the Company ha d acquired interests under the Chesapeake Property Acquisition as defined below . This transaction was funded with the revolving credit facility and was accounted for as a business combination. The Company allocated the purchase price to natural gas and oil properties, based on the respective fair values of the assets acquired. In December 2014 , the Company completed an acquisition of certain gas and oil assets from Chesapeake Energy Corporation covering approximately 413,000 net acres in West Virginia and southwest Pennsylvania targeting natural gas, oil and NGLs contained in the Upper Devonian, Marcellus and Utica Shales for approximately $5.0 billion (the “Chesapeake Property Acquisition”) . The transac tion was temporarily financed using a $4.5 billion 364 -day senior unsecured bridge term loan credit facility and a $500 million two -year unsecured term loan. The Company repaid all principal and interest outstanding on the $4.5 billion bridge facility in January 2015 after permanent financing was finalized , and as a result expensed $47 million of short-term unamortized debt issuance costs related to the bridge facility in January 2015 , recognized in other interest charges on the consolidated statement of operations. The term loan facility was repaid in full in April 2015 with proceeds from the divestiture of the Company’s northeastern Pennsylvania gathering assets and borrowings under the revolving credit facility. The following table summarizes the consideration paid for the Chesapeake Property Acquisition and the fair value of the assets acquired and liabilities assumed as of the acquisition date, updated for subsequent customary post-closing adjustments: (in (( (in millions) Consideration: Cash $ 4,949 Recognized amounts of identifiable assets acquired and liabilities assumed: Assets acquired: Proved natural gas and oil properties 1,418 Unproved natural gas and oil properties 3,573 Other property and equipment 33 Inventory 3 Total assets acquired 5,027 Liabilities assumed: Asset retirement obligations (42) Other liabilities (36) Total liabilities assumed (78) $ 4,949 The Company recorded the assets acquired and liabilities assumed in the Chesapeake Property Acquisition at their estimated fair value of approximately $5.0 billion, which the Company consider ed to be representative of the price paid by a typical market participant. This measurement resulted in no goodwill or bargain purchase being recognized. In addition, the Company included $1 million in general and administrative expenses and $5 million in interest expense for fees related to the Chesapeake Property Acquisition on its consolidated statement of operations for the year ended December 31, 2014. The Company included $47 million in other current assets and $1 million in other assets for unamortized fees related to the bridge facility and term loan facility, respectively, for the Chesapeake Property Acquisition on its consolidated balance sheet as of December 31, 2014. The results of operations of the Chesapeake Property Acquisition have been included in the Company’s consolidated financial statements since the December 22, 2014 closing date, including approximately $10 million of total revenue and $2 million of operating income for the year ended December 31, 2014. Summarized below are the consolidated res ults of operations for the year ended December 31, 2014 on an unaudited pro forma basis, as if the acquisition and related financing had occurred on January 1, 201 3 . The unaudited pro forma financial information was derived from the historical consolidated statement of operations of the Company and the statement of revenues and direct operating expenses for the Chesapeake Property Acquisition properties. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the acquisition and related financing occurred on the basis assumed above, nor is such information indicative of the Company’s expected future results of operations. The unaudited pro forma financial information excludes the WPX Property and Statoil Property Acquisitions as the impacts are immaterial. For the years ended December 31, 2014 2013 (unaudited) Revenues (in millions) $ 4,439 $ 3,713 Net Income attributable to common stock (in millions) 803 594 Earnings per share: Basic $ 2.11 $ 1.56 Diluted 2.10 1.56 The above acquisitions qualified as business combinations, and as a result, the Company estimated the fair value of the assets acquired and liabilities assumed as of the acquisition date. The fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements also utilize assumptions of market participants. The Company used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of natural gas , oil and NGL reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. These assumptions represent Level 3 inputs, as defined in Note 6 – Fair Value Measurements. |
Derivatives And Risk Management
Derivatives And Risk Management | 12 Months Ended |
Dec. 31, 2016 | |
Derivatives And Risk Management [Abstract] | |
Derivatives And Risk Management | (4) DERIVATIVE S AND RISK MANAGEMENT The Company is exposed to volatility in market prices and basis differentials for natural gas, oil and NGLs which impacts the predictability of its cash flows related to the sale of those commodities. These risks are managed by the Company’s use of certain derivative financial instruments. As of December 31, 2016, the Company’s derivative financial instruments consisted of fixed price swaps , two-way costless collars, three-way costless collars, basis swaps, sold call options and interest rate swaps. During 2016, the Company settled all of its purchased put options. The Company had basis swaps and sold call options as of December 31, 2015. A description of the Company’s derivative financial instruments is provided below: Fixed price swaps The Company receives a fixed price for the contract and pays a floating market price to the counterparty. Purchased put options The Company purchases put options based on an index price from the counterparty by payment of a cash premium. If the index price is lower than the put’s strike price at the time of settlement, the Company receives from the counterparty such difference between the index price and the purchased put strike price . If the market price settles above the put’s strike price, no payment is due from either party. Two-way costless collars Arrangements that contain a fixed floor price (purchased put option) and a fixed ceiling price (sold call option) based on an index price which, in aggregate, have no net cost. At the contract settlement date, (1) if the index price is higher than the ceiling price, the Company pays the counterparty the difference between the index price and ceiling price, (2) if the index price is between the floor and ceiling price s , no payments are due from either party, and (3) if the index price is below the floor price, the Company will receive the difference between the floor price and the index price. Three-way costless collars Arrangements that contain a purchased put option, a sold call option and a sold put option based on an index price which, in aggregate, have no net cost. At the contract settlement date, (1) if the index price is higher than the sold call strike price , the Company pays the counterparty the difference between the index price and sold call strike price, (2) if the index price is between the purchased put strike price and the sold call strike price, no payments are due from either party, (3) if the index price is between the sold put strike price and the purchased put strike price, the Company will receive the difference between the purchased put strike price and the index price, and (4) if the index price is below the sold put strike price, the Company will receive the difference between the purchased put strike price and the sold put strike price. Basis swaps Arrangements that guarantee a price differential for natural gas from a specified delivery point. The Company receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract. Sold call options The Company sells call options in exchange for a premium. If the market price exceeds the strike price of the call option at the time of settlement, the Company pays the counterparty such excess on sold call options. If the market price settles below the call’s strike price, no payment is due from either party. Interest rate swaps Interest rate swaps are used to fix or float interest rates on existing or anticipated indebtedness. The purpose of these instruments is to manage the Company’s existing or anticipated exposure to unfavorable interest rate changes. The Company utilizes counterparties for its derivative instruments that it believes are creditworthy at the time the transactions are entered into , and the Company closely monitors the credit ratings of these counterparties. Additionally, the Company performs both quantitative and qualitative assessments of these counterparties based on their credit ratings and credit default swap rates where applicable. However, the events in the financial markets in recent years demonstrate there can be no assurance that a counterparty will be able to meet its obligations to the Company. The following table provides information about the Company’s financial instruments that are sensitive to changes in commodity prices and that are used to protect the Company’s exposure. None of the financial instruments below are designated for hedge accounting treatment. The table presents the notional amount in Bcf, the weighted average contract prices and the fair value by expected maturit y dates as of December 31, 2016: Weighted Average Price per MMBtu Volume (Bcf) Swaps Sold Puts Purchased Puts Sold Calls Basis Differential Fai r value at December 31, 2016 ( in millions) Financial protection on production 2017 Fixed price swaps 322 $ 3.07 $ – $ – $ – $ – $ (175) Two-way costless collars 103 – – 2.94 3.38 – (42) Three-way costless collars 135 – 2.29 2.97 3.30 – (59) Basis swaps 132 – – – – (0.87) 19 Total 692 $ (257) 2018 Fixed price swaps 18 $ 3.00 $ – $ – $ – $ – $ (2) Two-way costless collars 14 – – 3.00 3.46 – (6) Three-way costless collars 208 – 2.37 2.96 3.37 – (20) Basis swaps 16 – – – – (0.94) (4) Total 256 $ (32) 2019 Three-way costless collars 62 $ – $ 2.50 $ 2.92 $ 3.35 $ – $ (2) Total 62 $ (2) Sold call options 2017 86 $ – $ – $ – $ 3.25 $ – $ (46) 2018 63 – – – 3.50 – (18) 2019 52 – – – 3.50 – (11) 2020 32 – – – 3.75 – (6) Total 233 $ (81) The balance sheet classification of the assets and liabilities related to derivative financial instruments (none of which are designated for hedge accounting treatment) are summarized below as of December 31, 2016 and 2015: Derivative Assets Balance Sheet Classification Fair Value December 31, 2016 December 31, 2015 (in millions) Derivatives not designated as hedging instruments: Two-way costless collars Derivative assets $ 8 $ – Three-way costless collars Derivative assets 11 – Basis swaps Derivative assets 32 3 Fixed price swaps Other long-term assets 1 – Two-way costless collars Other long-term assets 2 – Three-way costless collars Other long-term assets 100 – Basis swaps Other long-term assets 1 – Total derivative assets $ 155 $ 3 Derivative Liabilities Balance Sheet Classification Fair Value December 31, 2016 December 31, 2015 (in millions) Derivatives not designated as hedging instruments: Fixed price swaps Derivative liabilities $ 175 – Two-way costless collars Derivative liabilities 49 – Three-way costless collars Derivative liabilities 70 – Basis swaps Derivative liabilities 13 – Sold call options Derivative liabilities 46 – Interest rate swaps Derivative liabilities 2 3 Fixed price swaps Other long-term liabilities 3 – Two-way costless collars Other long-term liabilities 9 – Three-way costless collars Other long-term liabilities 122 – Basis swaps Other long-term liabilities 5 – Sold call options Other long-term liabilities 35 – Interest rate swaps Other long-term liabilities 1 2 Total derivative liabilities $ 530 $ 5 At December 31, 2016, the net fair value of the Company’s financial instruments related to natural gas was a $ 372 million liability . The net fair value of the Company’s interest rate swaps was a $ 3 million liability as of December 31, 2016. Derivative Contracts Not Designated for Hedge Accounting As of December 31, 2016, the Company had no positions designated for hedge accounting treatment. Gains and losses on derivatives that are not designated for hedge accounting treatment, or that do not meet hedge accounting requirements, are recorded as a component of gain (loss) on derivatives on the consolidated statements of operations. Accordingly, the gain (loss) on derivatives component of the statement of operations reflects the gains and losses on both settled and unsettled derivatives. The Company calculates gains and losses on settled derivatives as the summation of gains and losses on positions which have settled within the reporting period. Only the settled gains and losses are included in the Company’s realized commodity price calculations. The Company is a party to interest rate swaps that were entered into to mitigate the Company’s exposure to volatility in interest rates. The interest rate swaps have a notional amount of $ 170 million and expire in June 2020 . The Company did not designate the interest rate swaps for hedge accounting treatment. Changes in the fair value of the interest rate swaps are included in gain (loss) on derivatives on the consolidated statements of operations. The following tables summarize the before - tax effect of fixed price swaps, purchased put options, two-way costless collars, three-way costless collars, basis swaps, sold call options and interest rate swaps not designated for hedge accounting on the consolidated statements of operations for the years e nded December 31, 2016 and 2015: Gain (Loss) on Derivatives, Unsettled Recognized in Earnings Consolidated Statement of Operations For the years ended Classification of Gain (Loss) December 31, Derivative Instrument on Derivatives, Unsettled 2016 2015 (in millions) Fixed price swaps Gain (Loss) on Derivatives $ (177) $ (164) Two-way costless collars Gain (Loss) on Derivatives (48) – Three-way costless collars Gain (Loss) on Derivatives (81) – Basis swaps Gain (Loss) on Derivatives 12 (2) Sold call options Gain (Loss) on Derivatives (81) 13 Interest rate swaps Gain (Loss) on Derivatives 2 (2) Total loss on unsettled derivatives $ (373) $ (155) Gain (Loss) on Derivatives, Settled (1) Recognized in Earnings Consolidated Statement of Operations For the years ended Classification of Gain (Loss) December 31, Derivative Instrument on Derivatives, Settled 2016 2015 (in millions) Fixed price swaps Gain (Loss) on Derivatives $ – $ 208 Purchased put options Gain (Loss) on Derivatives 11 – Two-way costless collars Gain (Loss) on Derivatives 3 – Three-way costless collars Gain (Loss) on Derivatives 1 – Basis swaps Gain (Loss) on Derivatives 21 (2) Interest rate swaps Gain (Loss) on Derivatives (2) (4) Total gain on settled derivatives (2) $ 34 $ 202 Total gain (loss) on derivatives $ (339) $ 47 (1) The Company calculates gain (loss) on derivatives, settled, as the summation of gains and losses on positions that have settled within the period. (2) Excluding interest rate swaps, these amounts are included, along with gas sales revenues, in the calculation of the Company’s realized natural gas price. Derivative Contracts Designated for Hedge Accounting All derivatives are recognized in the balance sheet as either an asset or liability and are measured at fair value , other than transactions for which normal purchase/normal sale is applied. Certain criteria must be satisfied in order for derivative financial instruments to be designated for hedge accounting. U nrealized gains and losses related to unsettled derivatives that have been designated for hedge accounting are recorded in either earnings or as a component of other comprehensive income until settled. In the period of settlement, the Company recognizes the gains and losses from these qualifying hedges in gas sales revenues. As of December 31, 2016, the Company had no positions designated for hedge accounting treatment. In 2015, the Company had certain fixed price swaps that were designated for hedge accounting. For the year ended December 31, 2015, the Company reported pre-tax gains in other comprehensive income of $45 million related to the effective portion of the unsettled fixed price swaps. The ineffective portion of those fixed price swaps was recognized in earnings and had an inconsequential impact to the consolidated statement of operations for the year ended December 31, 2015. For the year ended December 31, 2015, pre-tax gains of $209 million on settled fixed price swaps were transferred from other comprehensive income into gas sales revenues in the consolidated statement of operations. |
Reclassifications From Accumula
Reclassifications From Accumulated Other Comprehensive Income (Loss) | 12 Months Ended |
Dec. 31, 2016 | |
Reclassifications From Accumulated Other Comprehensive Income (Loss) [Abstract] | |
Reclassifications From Accumulated Other Comprehensive Income (Loss) | (5 ) RECLASSIFI CATIONS FROM ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) The following tables detail the components of accumulated other comprehensive income (loss) , net of related tax effects , for the year ended December 31, 2016: For the year ended December 31, 2016 Pension and Other Postretirement Foreign Currency Total (in millions) Beginning balance, December 31, 2015 $ (25) $ (23) $ (48) Other comprehensive income (loss) before reclassifications (7) 3 (4) Amounts reclassified from other comprehensive income (loss) (2) 13 – 13 Net current-period other comprehensive income (loss) 6 3 9 Ending balance, December 31, 2016 $ (19) $ (20) $ (39) (1) See separate table below for details about these reclassifications. Details about Accumulated Other Comprehensive Income Affected Line Item in the Consolidated Statement of Operations Amount Reclassified from Accumulated Other Comprehensive Income For the year ended December 31, 2016 (in millions) Pension and other postretirement: Amortization of prior service cost and net loss (1) General and administrative expenses $ 21 Provision (benefit) for income taxes 8 Net income (loss) $ 13 Total reclassifications for the period Net income (loss) $ 13 See Note 11 for additional details regarding the Company’s retirement and employee benefit plans. |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2016 | |
Fair Value Measurements [Abstract] | |
Fair Value Measurements | ( 6 ) FAIR VALUE MEASU REMENTS The carrying amounts and estimated fair values of the Company’s financial instruments as of December 31, 2016 and 2015 were as follows: December 31, 2016 December 31, 2015 Carrying Fair Carrying Fair Amount Value Amount Value (in millions) Cash and cash equivalents $ 1,423 $ 1,423 $ 15 $ 15 Credit facility – – 116 116 Term loan facility due December 2020 (1) 327 327 750 750 Term loan facility due December 2020 (1) 1,191 1,191 – – Senior notes 3,166 3,182 3,867 2,672 Derivative instruments, net (375) (375) (2) (2) (1) The maturity date will accelerate to October 2019 if, by that date, the Company has not amended, redeemed or refinanced at least $765 million of its senior notes due in January 2020 . The carrying values of cash and cash equivalents, accounts receivable, other current assets, accounts payable and other current liabilities on the consolidated balance sheets approximate fair value because of their short-term nature. For debt and derivative instruments, the following methods and assumptions were used to estimate fair value: Debt: The fair values of the Company’s senior notes were based on the market value of the Company’s publicly traded debt as determined based on the yield of the Company’s senior notes. The carrying values of the borrowings under the Company’s term loan facilities and unsecured revolving credit facility approximate fair value because the interest rate is variable and reflective of market rates. The Company considers the fair value of its debt to be a Level 2 measurement on the fair value hierarchy. Derivative Instruments: The fair value of all derivative instruments is the amount at which the instrument could be exchanged currently between willing parties. The amounts are based on quoted market prices, best estimates obtained from counterparties and an option pricing model, when necessary, for price option contracts. The fair value hierarchy prioritizes the inputs to valuation techniques used to measure fair value. As presented in the tables below, this hierarchy consists of three broad levels: Level 1 valuations – Consist of unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. Level 2 valuations – Consist of quoted market information for the calculation of fair market value. Level 3 valuations – Consist of internal estimates and have the lowest priority. The Company has classified its derivatives into these levels depending upon the data utilized to determine their fair values. The Company’s fixed price swaps (Level 2) are estimated using third-party discounted cash flow calculations using the NYMEX futures index. The Company utilized discounted cash flow models for valuing its interest rate derivatives (Level 2). The net derivative values attributable to the Company’s interest rate derivative contracts as of December 31, 2016 are based on (i) the contracted notional amounts, (ii) active market-quoted London Interbank Offered Rate (“LIBOR”) yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve. The Company’s sold call options, purchased put options, two-way costless collars and three-way costless collars (Level 3) are valued using the Black-Scholes model, an industry standard option valuation model that takes into account inputs such as contract terms, including maturity, and market parameters, including assumptions of the NYMEX futures index, interest rates, volatility and credit worthiness. The Company’s basis swaps (Level 3) are estimated using third-party calculations based upon forward commodity price curves. Inputs to the Black-Scholes model, including the volatility input, which is the significant unobservable input for Level 3 fair value measurements, are obtained from a third-party pricing source, with independent verification of the most significant inputs on a monthly basis. An increase (decrease) in volatility would result in an increase (decrease) in fair value measurement, respectively. Assets and liabilities measured at fair value on a recurring basis are summarized below (in millions): December 31, 2016 Fair Value Measurements Using: Quoted Prices Significant in Active Significant Other Unobservable Markets Observable Inputs Inputs Assets (Liabilities) (Level 1) (Level 2) (Level 3) at Fair Value Fixed price swap assets $ – $ 1 $ – $ 1 Two-way costless collars assets – – 10 10 Three-way costless collars assets – – 111 111 Basis swap assets – – 33 33 Fixed price swap liabilities – (178) – (178) Two-way costless collars liabilities – – (58) (58) Three-way costless collars liabilities – – (192) (192) Basis swap liabilities – – (18) (18) Sold call option liabilities – – (81) (81) Interest rate swap liabilities – (3) – (3) Total $ – $ (180) $ (195) $ (375) December 31, 2015 Fair Value Measurements Using: Quoted Prices Significant Other Significant in Active Markets Observable Inputs Unobservable Inputs Assets (Liabilities) (Level 1) (Level 2) (Level 3) at Fair Value Basis swap assets $ – $ – $ 3 $ 3 Interest rate swap liabilities – (5) – (5) Total $ – $ (5) $ 3 $ (2) The table below presents reconciliations for the change in net fair value of derivative assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the years ended December 31, 2016 and 2015. The fair values of Level 3 derivative instruments are estimated using proprietary valuation models that utilize both market observable and unobservable parameters. Level 3 instruments presented in the table consist of net derivatives valued using pricing models incorporating assumptions that, in the Company’s judgment, reflect reasonable assumptions a marketplace participant would have used as of December 31, 2016 and 2015. For the years ended December 31, 2016 2015 (in millions) Balance at beginning of period $ 3 $ (8) Total gains (losses): Included in earnings (162) 9 Settlements (36) 2 Transfers into/out of Level 3 – – Balance at end of period $ (195) $ 3 Change in gains (losses) included in earnings relating to derivatives still held as of December 31 $ (198) $ 11 See Note 11 – Retirement and Employee Benefit Plans for a discussion of the fair value measurement of the Company’s pension plan assets. |
Debt
Debt | 12 Months Ended |
Dec. 31, 2016 | |
Debt [Abstract] | |
Debt | (7 ) D EBT The components of debt as of December 31, 2016 and 2015 consisted of the following: December 31, 2016 Debt Instrument Unamortized Issuance Cost Unamortized Debt Discount Total (in millions) Short-term debt: 7.35% Senior Notes due October 2017 $ 15 $ – $ – $ 15 7.125% Senior Notes due October 2017 25 – – 25 7.15% Senior Notes due June 2018 1 – – 1 Total short-term debt $ 41 $ – $ – $ 41 Long-term debt: Variable rate ( 3.220% at December 31, 2016) term loan facility, due December 2020 (1) 327 (2) – 325 Variable rate ( 3.220% at December 31, 2016) term loan facility, due December 2020 (2) 1,191 (10) – 1,181 3.30% Senior Notes due January 2018 (3) (4) 38 – – 38 7.50% Senior Notes due February 2018 (3) 212 – – 212 7.15% Senior Notes due June 2018 25 – – 25 4.05% Senior Notes due January 2020 (4) 850 (5) – 845 4.10% Senior Notes due March 2022 1,000 (4) (1) 995 4.95% Senior Notes due January 2025 (4) 1,000 (7) (2) 991 Total long-term debt $ 4,643 $ (28) $ (3) $ 4,612 Total debt $ 4,684 $ (28) $ (3) $ 4,653 (1) In July 2016, $375 million was repaid on the term loan facility, extending the maturity from November 2018 to December 2020, which will accelerate to October 2019 if, by that date, the Company has not amended, redeemed or refinanced at least $765 million of its senior notes due in January 2020 . In September 2016, an additional $48 million was repaid. (2) The maturity date will accelerate to October 2019 if, by that date, the Company has not amended, redeemed or refinanced at least $765 million of its senior notes due in January 2020. (3) In July 2016, the Company purchased approximately $312 million of the 3.30% Senior Notes due January 2018 and $388 million of the 7.50% Senior Notes due February 2018. (4) In February and June 2016, Moody’s and S&P downgraded certain senior notes, increasing the interest rates by 175 basis points effective July 2016. As a result of the downgrades, interest rates increased to 5.05% for the 2018 Notes, 5.80% for the 2020 Notes and 6.70% for the 2025 Notes. December 31, 2015 Debt Instrument Unamortized Issuance Cost Unamortized Debt Discount Total (in millions) Short-term debt: 7.15% Senior Notes due June 2018 $ 1 $ – $ – $ 1 Total short-term debt $ 1 $ – $ – $ 1 Long-term debt: Variable rate ( 1.886% at December 31, 2015) credit facility, expires December 2018 116 – – 116 Variable rate ( 1.775% at December 31, 2015) term loan facility, due November 2018 750 (3) – 747 7.35% Senior Notes due October 2017 15 – – 15 7.125% Senior Notes due October 2017 25 – – 25 3.30% Senior Notes due January 2018 350 (2) – 348 7.50% Senior Notes due February 2018 600 (2) – 598 7.15% Senior Notes due June 2018 26 – – 26 4.05% Senior Notes due January 2020 850 (5) (1) 844 4.10% Senior Notes due March 2022 1,000 (5) (1) 994 4.95% Senior Notes due January 2025 1,000 (7) (2) 991 Total long-term debt $ 4,732 $ (24) $ (4) $ 4,704 Total debt $ 4,733 $ (24) $ (4) $ 4,705 The following is a summary of scheduled debt maturities by year as of December 31, 2016 (in millions): 2017 $ 41 20 18 275 2019 – 2020 2,368 2021 – Thereafter 2,000 $ 4,684 2016 Credit Facility In June 2016, the Company reduced its existing $2.0 billion unsecured revolving credit facility to $66 million and entered into a new credit agreement for $1,934 million, consisting of a $1,191 million secured term loan and a new $743 million unsecured revolving credit facility, which matures in December 2020 . The maturity date will accelerate to October 2019 if, by that date, the Company has not amended, redeemed or refinanced at least $765 million of its senior n otes due January 2020 . The $1,191 million secured term loan is fully drawn, with approximately $285 million of this balance used to pay down the previous revolving credit facility balance in its entirety. As of December 31, 2016, there were no borrowings under either revolving credit facility ; however, $174 million in letters of credit was outstanding against the 2016 revolving credit facility. Loans under the 2016 credit agreement are subject to varying rates of interest based on whether the loan is a Eurodollar loan or an alternate base rate loan. Eurodollar loans bear interest at the Eurodollar rate, which is adjusted LIBOR plus applicable margins ranging from 1.750% to 2.500% . Alternate base rate loans bear interest at the alternate base rate plus the applicable margin ranging from 0.750% to 1.500% . The interest rate on the term loan facility is determined based upon the Company’s public debt ratings and was 250 basis points over LIBOR as of December 31, 2016. The new term loan and revolving credit facility contain financial covenants that impose certain restrictions on the Company. Under the new credit agreement, the Company must maintain a minimum interest coverage of 0.75x in 2016, increasing by 0.25x increments per year to 1.50x in 2019 and 2020. The Company is also subject to a minimum liquidity requirement of $300 million, which could be increased up to $500 million upon certain conditions, as well as an anti-hoarding provision, requiring unrestricted cash in excess of $100 million to pay down any amounts borrowed under the new revolving credit facility. The financial covenant with respect to minimum interest coverage consists of EBITDAX divided by consolidated interest expense. EBITDAX , as defined in our 2016 credit agreement, excludes the effects of interest expense, income taxes, depreciation, depletion and amortization, any non-cash impacts from impairments, certain non-cash hedging activities, stock-based compensation expense, non-cash gains or losses on asset sales, unamortized issuance cost, unamortized debt discount and certain restructuring costs. Collateral for the new secured term loan is principally the Company’s E&P properties in the Fayetteville Shale area , the equity of its subsidiaries and cash and marketable securities on hand , and the new credit agreement requires a minimum collateral coverage ratio of 1.50x for the 2016 secured term loan. This collateral also may support all or a part of revolving credit extensions depending on restrictions in the Company’s senior notes indentures. As of December 31, 2016, the Company was in compliance with all of the covenants of this credit agreement. Although the Company does not anticipate any violations of the financial covenants, its ability to comply with these covenants is dependent upon the success of its exploration and development program and upon factors beyond the Company’s control, such as the market prices for natural gas , oil and NGLs . 2013 Credit Facility In December 2013, the Company entered into a credit agreement that exchanged its previous revolving credit facility. Under the revolving credit facility, the Company had a borrowing capacity of $2.0 billion. The revolving credit facility was unsecured and was not guaranteed by any subsidiaries. In June 2016, this credit facility was substantially exchanged for a new credit facility comprised of a $1,191 million secured term loan and a new $743 million revolving credit facility. The borrowing capacity of the original 2013 credit agreement was reduced from $2.0 billion to $66 million, remains unsecured and the maturity remains December 2018 . As of December 31, 2016, there were no borrowings under this facility. The existing unsecured 2013 revolving credit facility includes a financial covenant under which the Company may not have total debt in excess of 60% of its total adjusted book capital. This financial covenant with respect to capitalization percentages excludes the effects of any full cost ceiling impairments, certain hedging activities and the Company’s pension and other postretirement liabilities. At December 31, 2016, the Company’s adjusted book capital was 34% debt and 66% equity. 2015 Term Facility In November 2015, the Company entered into a $750 million unsecured three -year term loan credit agreement with various lenders that was utilized to repay borrowings under the revolving credit facility. The interest rate on the term loan facility is determined based upon the Company’s public debt ratings from Moody’s and S&P and was 250 basis points over LIBOR as of December 31, 2016. The term loan facility requires prepayment under certain circumstances from the net cash proceeds of sales of equity or certain assets and borrowings outside the ordinary course of business. In June 2016, this term loan agreement was amended to extend the maturity date upon a repayment threshold. From the net proceeds of the July 2016 equity offering, the Company repaid $375 million of the $750 million unsecured term loan, which had the effect of extending the term loan maturity from November 2018 to December 2020 , which will accelerate to October 2019 if, by that date, the Company has not amended, redeemed or refinanced at least $765 million of its s enior n otes due in January 2020 . As a result of the repayment, the Company expensed $3 million of unamortized debt issuance costs, recognized in other interest charges on the consolidated statement of operations for the year ended December 31, 2016. In September 2016, the Company repaid an additional $48 million from the proceeds received from the closing of the sale of approximately 55,000 net acres in West Virginia to Antero Resources Corporation, resulting in an additional $0.4 million of interest expense related to unamortized debt issuance costs. Commercial Paper In April 2015, the Company entered into a commercial paper program which allowed it to issue up to $2.0 billion in commercial paper, provided that outstanding borrowings from its commercial paper program, combined with outstanding borrowings under our revolving credit facility, not exceed $2.0 billion. The commercial paper issuance had terms of up to 397 days and carried interest at rates agreed upon at the time of each issuance. As of December 31, 2016 and 2015, the Company had no outstanding issuances under its commercial paper program , respectively, and had no current plans of further utilizing the commercial paper market. Senior Notes In July 2016, the Company used a portion of the proceeds from the July 2016 equity offering to settle certain tender offers by purchasing an aggregate principal amount of approximately $700 million of the Company’s outstanding senior notes due in the first quarter of 2018, resulting in a loss of $51 million for the early retirement and redemption of these senior notes including $50 million of premiums paid. Additionally, the Company expensed $2 million of unamortized debt issuance costs and debt discounts, recognized in other interest charges. In January 2015, the Company completed a public offering of $350 million aggregate principal amount of its 3.30% senior notes due 2018 (the “2018 Notes”), $850 million aggregate principal amount of its 4.05% senior notes due 2020 (the “2020 Notes”) and $1.0 billion aggregate principal amount of its 4.95% senior notes due 2025 (the “2025 Notes” together with the 2018 and 2020 Notes, the “Notes”), with net proceeds from the offering totaling approximately $2.2 billion after underwriting discounts and offering expenses. The proceeds from this offering were used to repay the remaining principal and interest outstanding under the Company’s $4.5 billion 364 -day bridge term loan facility, which was first reduced with proceeds from the Company’s concurrent underwritten public offerings of common and preferred stock, and were also used to repay a portion of amounts outstanding under the Company’s revolving credit facility. As a result of this repayment, the Company expensed $47 million of short-term unamortized debt issuance costs related to the bridge facility in January 2015 , recognized in other interest charges on the consolidated statement of operations for the year ended December 31, 2016. The Notes were sold to the public at a price of 99.949% of their face value for the 2018 Notes, 99.897% of their face value for the 2020 Notes and 99.782% of their face value for the 2025 Notes. The interest rates on the Notes are determined based upon the public bond ratings from Moody’s and S&P. Downgrades on the Notes from either rating agency increase interest costs by 25 basis points per downgrade level and upgrades decrease interest costs by 25 basis points per upgrade level , up to the stated coupon rate, on the following semi-annual bond interest payment. In February and June 2016, Moody’s and S&P downgraded the Notes, increasing the interest rates by 175 basis points effective July 2016. As a result of these downgrades, interest rates increased to 5.05% for the 2018 Notes, 5.80% for the 2020 Notes and 6.70% for the 2025 Notes. In the event of future downgrades, the coupons for this series of notes are capped at 5.30% , 6.05% and 6.95% , respectively. The first coupon payment to the bondholders at the higher interest rates was paid in January 2017. Chesapeake Property Acquisition Financing On December 19, 2014, the Company entered into a $4.5 billion unsecured 364 -day bridge term loan credit agreement with various lenders. The bridge facility require d prepayments under certain circumstances from the net cash proceeds of sales of equity or certain assets and borrowings outside the ordinary course of business or for specified uses. The Company repaid the $4.5 billion outstanding and terminated the bridge facility in January 2015 with net proceeds of $669 million and $1.7 billion from common stock and depositary share offerings, respectively, and $2.2 billion from senior note offerings with the difference utilized to pay down amounts under the revolving credit facility. |
Commitments And Contingencies
Commitments And Contingencies | 12 Months Ended |
Dec. 31, 2016 | |
Commitments And Contingencies [Abstract] | |
Commitments And Contingencies | (8 ) COMM ITMENTS AND CONTINGENCIES Operating Commitments and Contingencies As of December 31, 2016, the Company’s contractual obligations for demand and similar charges under firm transportation and gathering agreements to guarantee access capacity on natural gas and liquids pipelines and gathering systems totaled approxim ately $8.4 billion , $3.4 billion of which related to access capacity on future pipeline and gathering infrastructure projects that still require the granting of regulatory approvals and additional construction efforts. The Company also had guarantee obligations of up to $862 million of that amount. As of December 31, 2016, future payments under non-cancelable firm transportation and gathering agreements are as follows: Payments Due by Period Total Less than 1 Year 1 to 3 Years 3 to 5 Years 5 to 8 years More than 8 Years (in millions) Infrastructure Currently in Service $ 5,067 $ 612 $ 1,158 $ 825 $ 829 $ 1,643 Pending Regulatory Approval and/or Construction (1) 3,362 15 326 450 678 1,893 Total Transportation Charges $ 8,429 $ 627 $ 1,484 $ 1,275 $ 1,507 $ 3,536 (1) Based on the estimated in-service dates as of December 31, 2016. The Com pany has 13 leases for pressure pumping equipment for its E&P operations under leases that expire between December 2017 and January 2018 . The Company’s current aggregate annual payment un der the leases is approximately $ 8 million. Certain of these leases provide for a residual value guarantee for any deficiency if the equipment is sold for less than the sale option amount ( recognized as a liability of approximately $4 million at December 31, 2016 ) . The Company has 7 leases for drilling rigs for its E&P operations that expire through 2021 with a current aggregate annual payment of approximately $13 million. The lease payments for the pressure pumping equipment, as well as other operating expenses for the Company’s drilling operations, are capitalized to natural gas and oil properties and are partially offset by billings to third-party working interest owners for their share of fracture stage charges. The Company leases compressors, aircraft, vehicles, office space and equipment under non-cancelable operating leases expiring through 2027 . As of December 31, 2016, future minimum payments under these non-cancelable leases accounted for as operating leases are approximately $ 66 million in 2017, $ 52 million in 2018, $ 45 million in 2019, $ 35 million in 2020 , $ 17 million in 202 1 and $14 million thereafter . The Company also has commitments for compression services related to its Midstream Services and E&P segments. As of December 31, 2016, future minimum payments under these non-cancelable agreements are approximately $ 16 million in 2017, $ 7 million in 2018 and $ 3 million in 2019 . Environmental Risk The Company is subject to laws and regulations relating to the protection of the environment. Environmental and cleanup related costs of a non-capital nature are accrued when it is both probable that a liability has been incurred and when the amount can be reasonably estimated. Management believes any future remediation or other compliance related costs will not have a material effect on the financial position or results of operations of the Company. Litigat ion The Company is subject to various litigation, claims and proceedings that have arisen in the ordinary course of business, such as for alleged breaches of contract, miscalculation of royalties, and pollution, contamination or nuisance. Management believes that such litigation, claims and proceedings, individually or in aggregate and after taking into account insurance, are not likely to have a material adverse impact on the Company’s financial position, results of operations or cash flows. Many of these matters are in early stages, so the allegations and the damage theories have not been fully developed, and are all subject to inherent uncertainties; therefore, management’s view may change in the future. If an unfavorable final outcome were to occur, there exists the possibility of a material impact on the Company’s financial position, results of operations or cash flows for the period in which the effect becomes reasonably estimable. The Company accrues for such items when a liability is both probable and the amount can be reasonably estimated. Berry-Helfand (Tovah Energy) In February 2009, one of the Company’s subsidiaries was added as a defendant in a case then styled Tovah Energy, LLC and Toby Berry-Helfand v. David Michael Grimes, et al., then pending in the 273rd District Court in Shelby County, Texas. The plaintiff alleged that the subsidiary used information provided by the plaintiff under a confidentiality agreement, which she claimed, among other things, breached the agreement and constituted a trade secret. Following a trial in December 2010, the court awarded approximately $11 million in actual damages and approximately $24 million in disgorgement of profits, along with interest and attorneys’ fees. Both sides appealed, and in July 2013 the Texas Court of Appeals for the Twelfth District reversed on all claims except misappropriation of trade secrets, reduced the judgment to the actual damages award, along with interest and attorneys’ fees, and ordered the case remanded for an award of attorneys’ fees to the Company’s subsidiary on one of the claims on which judgment was reversed. Both parties petitioned the Supreme Court of Texas for review. In June 2016, the Supreme Court ruled that insufficient evidence supported the damage award and remanded the case for a new trial. The parties subsequently reached a settlement, the amount of which is reflected in the Company’s financial statements as of, and for the period ended, December 31, 2016. Arkansas Royalty Litigation Certain of the Company’s subsidiaries are defendants in three cases, two filed in Arkansas state court in 2010 and 2013 and one in federal court in 2014, on behalf of putative classes of royalty owners on some of the Company’s leases located in Arkansas. The chief complaint in all three cases is that one of the Company’s subsidiaries underpaid the royalty owners by, among other things, deducting from royalty payments costs for gathering, transportation, and compression of natural gas in excess of what is permitted by the relevant leases. In September and October 2014 the judges in the two Arkansas state actions entered orders certifying classes of royalty owners who are citizens of Arkansas. In November 2015, the court in the federal case denied the plaintiff’s motion to certify a class of royalty owners not included in either of the two state cases. In April 2016, the court certified a broader class that includes Arkansas residents and citizens. Class members were notified of the pending action in late 2016, and the period to “opt out” of the class has expired. The plaintiff in the federal case presented two alternative damages theories. Under one theory, plaintiffs have asserted that obligations to affiliates are not “incurred” and therefore the exploration and production subsidiary was not entitled to deduct any post-production costs; the federal court has granted partial summary judgment for the Company’s subsidiaries on this theory. Under another theory, plaintiffs assert that the gathering and treating rates the Company deducted from royalty payments exceeded the affiliates’ actual costs or otherwise were not reasonable. The plaintiffs have not disclosed a specific damage calculation for any putative class, but based on the class representative’s disclosure regarding the calculation of claimed damages, class-wide damages could exceed $100 million. The court has set a trial date in the second quarter of 2017. The Company h as moved for summary judgment on all claims, which remains pending before the trial judge. The Company’s subsidiaries appealed the class certification orders in the state cases. In December 2016 the Arkansas Supreme Court affirmed the certifications. These cases are now before the Arkansas trial judges. The precise configuration of the classes has not been determined, particularly in light of the overlapping composition of the class in the federal case. No date for trial has been set. In addition, in September 2015 three cases were filed in Arkansas state court on behalf of a total of 248 individually named plaintiffs. Each case asserts complaints that are in substance virtually identical to the above-described case. The Company and its subsidiaries have removed two of the cases to federal court, and those cases have been assigned to the court in which the above-described federal case is pending. All three cases have been stayed. Management believes that, in all of the above cases, the deductions from royalty payments as calculated are permitted and intends to defend the cases vigorously. The Company’s assessment may change in the future due to the occurrence of certain events, such as adverse judgments, and such a re-assessment could lead to the determination that the potential liability is probable and could be material to the Company’s results of operations, financial position or cash flows. Indemnifications The Company provides certain indemnifications in relation to dispositions of assets. These indemnifications typically relate to disputes, litigation or tax matters existing at the date of disposition. No liability has been recognized in connection with these indemnifications . |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2016 | |
Income Taxes [Abstract] | |
Income Taxes | (9 ) INCO ME TAXES The provision (benefit) for income taxes included the following components: 2016 2015 2014 (in millions) Current: Federal $ (6) $ 1 $ 11 State (1) (3) 10 (7) (2) 21 Deferred: Federal (22) (1,697) 501 State – (304) 2 Foreign – (2) 1 (22) (2,003) 504 Provision (benefit) for income taxes $ (29) $ (2,005) $ 525 The provision for income taxes was an effective rate of 1 % in 2016 , 31 % in 201 5 and 36 % in 201 4 . The following reconciles the provision for income taxes included in the consolidated statements of operations with the provision which would result from application of the statutory federal tax rate to pre-tax financial income: 2016 2015 2014 (in millions) Expected provision (benefit) at federal statutory rate $ (935) $ (2,296) $ 507 Increase (decrease) resulting from: State income taxes, net of federal income tax effect (79) (194) 58 Nondeductible expenses – – 3 State rate redetermination – – (48) Change in uncertain tax positions (19) (7) – Change in valuation allowance 1,002 495 5 Other 2 (3) – Provision (benefit) for income taxes $ (29) $ (2,005) $ 525 Our effective tax rate decreased in 2016 , as compared with 2015, primarily due to the recognition of a valuation allowance in the fourth quarter of 2015 that persisted throughout 2016 . The components of the Company’s deferred tax balances as of December 31, 2016 and 2015 were as follows: 2016 2015 (in millions) Deferred tax liabilities: Differences between book and tax basis of property $ 81 $ 216 Other 1 2 82 218 Deferred tax assets: Accrued compensation 38 19 Alternative minimum tax credit carryforward 100 125 Accrued pension costs 19 19 Asset retirement obligations 53 77 Net operating loss carryforward 1,177 445 Derivative activity 142 – Other 29 26 1,558 711 Valuation allowance (1,476) (493) Net deferred tax liability $ – $ – In 2016, the Company paid less than $1 million in state income taxes and received $15 million in federal income tax refunds. In 2015, the Company paid less than $1 million in state income taxes and did not pay federal income taxes. The Company’s net operating loss carryforward as of December 31, 2016 was $3.2 b illion and $2.2 b illion for federal and state reporting purposes, respectively, the majority of which will expire between 2029 and 2036 . Additionally, the Company has an income tax net operating loss carryforward related to its Canadian operations of $ 35 million, with expiration dates of 2030 through 2036 . The C ompany also had an alternative minimum tax credit carryforward of $100 million and a statutory depletion carryforward of $13 million as of December 31, 2016. A valuation allowance for deferred tax assets, including net operating losses, is recognized when it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized. To assess the likelihood, the Company uses estimates and judgment regarding future taxable income, and considers the tax consequences in the jurisdiction where such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include current financial position, results of operations, both actual and forecasted, the reversal of deferred tax liabilities, and tax planning strategies as well as current and forecasted business economics of the oil and gas industry. Due to the continued write-downs of the carr ying value of natural gas and oil properties, the Company maintained its net deferred tax asset position at December 31, 2016. The Company believe s it is more likely than not that these deferred tax assets will not be realized and recorded a $ 983 million increase in valuation allowance for the year ended December 31, 2016, reflected as a component of income tax expense. Management assesses available positive and negative evidence to estimate whether sufficient future taxable income will be generated to permit the use of deferred tax assets. In management’s view, the cumulative loss incurred over the three-year period ending December 31, 2016, outweighs any positive factors, such as the possibility of future growth. The amount of the deferred tax asset considered realizable, however, could be adjusted if estimates of future taxable income are increased or if objective negative evidence in the form of cumulative losses is no longer present and additional weight is given to subjective evidence such as future expected growth . Deferred tax assets relating to tax benefits of employee stock option grants have been reduced to reflect exercises. Some exercises resulted in tax deductions in excess of previously recorded benefits based on the option value at the time of the grant (“windfalls”). Although these additional tax benefits or “windfalls” are reflected in net operating loss carryforwards, the additional tax benefit associated with the windfall is not recognized until the deduction reduces taxes payable. Accordingly, since the tax benefit does not reduce the Company’s current taxes payable in 2016 due to net operating loss carryforwards, these “windfall” tax benefits are not reflected in its net operating losses in deferred tax assets for 201 6 . Windfalls included in net operating loss carryforwards but not reflected in deferred tax assets for 2016 were $ 149 million . A tax position must meet certain thresholds for any of the benefit of the uncertain tax position to be recognized in the financial statements. As of December 31, 2016, the amount of unrecognized tax benefits related to alternative minimum tax was $17 million. The uncertain tax position identified would not have a material effect on the effective tax rate. No material changes to the current uncertain tax position are expected within the next 12 months. As of December 31, 2016, the Company had accrued a liability of less than $1 million of interest related to this uncertain tax position. The Company recognizes penalties and interest related to uncertain tax positions in income tax expense. A reconciliation of the beginning and ending balances of unrecognized tax benefits is as follows: 2016 2015 (in millions) Unrecognized tax benefits at beginning of period $ 37 $ 44 Additions based on tax positions related to the current year – 7 Additions to tax positions of prior years – – Reductions to tax positions of prior years (20) (14) Unrecognized tax benefits at end of period $ 17 $ 37 The Internal Revenue Service is currently auditing the Company’s federal income tax return for 2014. The income tax years 2013 to 2016 remain open to examination by the major taxing jurisdictions to which the Company is subject . |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2016 | |
Asset Retirement Obligations [Abstract] | |
Asset Retirement Obligations | (10 ) ASSET RETIREM ENT OBLIGATIONS The following table summarizes the Company’s 201 6 and 201 5 activity related to asset retirement obligations: 2016 2015 (in millions) Asset retirement obligation at January 1 $ 201 $ 207 Accretion of discount 10 11 Obligations incurred 1 17 Obligations settled/removed (1) (45) (30) Revisions of estimates (2) (26) (4) Asset retirement obligation at December 31 $ 141 $ 201 Current liability 6 10 Long-term liability 135 191 Asset retirement obligation at December 31 $ 141 $ 201 (1) Obligations settled/removed include $35 million and $25 million related to asset divestitures in 2016 and 2015, respectively. (2) Estimates in the costs to retire wells and well pads were revised downward based on internal estimates of future obligation requirements and updated third-party cost quotes. |
Retirement And Employee Benefit
Retirement And Employee Benefit Plans | 12 Months Ended |
Dec. 31, 2016 | |
Retirement And Employee Benefit Plans [Abstract] | |
Retirement And Employee Benefit Plans | (11 ) RETIREMENT AND EMPLOYEE BENEFIT PLANS 401(k) Defined Contribution Plan The Company has a 401(k) defined contribution plan covering eligible employees. The Company expensed $ 4 million, $ 3 million and $ 3 million of contribution expense in 2016, 2015 and 2014, respectively. Additionally, the Company capitalized $ 2 million, $ 4 million and $ 3 million of contributions in 2016, 2015 and 2014, respectively, directly related to the acquisition, exploration and development activities of the Company’s natural gas and oil properties or directly related to the construction of the Company’s gathering systems. Defined Benefit Pension and Other Postretirement Plans Prior to January 1, 1998, the Company maintained a traditional defined benefit plan with benefits payable based upon average final compensation and years of service. Effective January 1, 1998, the Company amended its pension plan to become a “cash balance” plan on a prospective basis for its non-bargaining employees. A cash balance plan provides benefits based upon a fixed percentage of an employee’s annual compensation. The Company’s funding policy is to contribute amounts which are actuarially determined to provide the plans with sufficient assets to meet future benefit payment requirements and which are tax deductible. The postretirement benefit plan provides contributory health care and life insurance benefits. Employees become eligible for these benefits if they meet age and service requirements. Generally, the benefits paid are a stated percentage of medical expenses reduced by deductibles and other coverages. Substantially all employees are covered by the Company’s defined benefit pension and postretirement benefit plans. The Company accounts for its defined benefit pension and other postretirement plans by recognizing the funded status of each defined pension benefit plan and other postretirement benefit plan on the Company’s balance sheet. In the event a plan is overfunded, the Company recognizes an asset. Conversely, if a plan is underfunded, the Company recognizes a liability. In January 2016, the Company initiated a reduction in workforce that was effectively completed by the end of the first quarter. As a result of the workforce reduction, the Company recognized a $1 million non-cash curtailment loss related to its pension plan for both the curtailment-related decrease to the benefit obligation and the recognition of the proportionate share of unrecognized prior service cost and net loss from other comprehensive income (loss) in the second quarter of 2016. For the year ended December 31, 2016, the Company recognized a non-cash settlement loss of $11 million related to a total of $37 million of lump sum payments from the pension plan. Additionally, the Company recognized a non-cash curtailment gain of $6 million related to its other postretirement benefit plan in the first quarter of 2016. The following provides a reconciliation of the changes in the plans’ benefit ob ligations, fair value of assets and funded status as of December 31, 2016 and 2015: Other Postretirement Pension Benefits Benefits 2016 2015 2016 2015 (in millions) Change in benefit obligations: Benefit obligation at January 1 $ 138 $ 134 $ 20 $ 18 Service cost 11 16 2 3 Interest cost 5 6 1 1 Participant contributions – – – – Actuarial loss (gain) 14 (7) (2) (2) Benefits paid (3) (11) (1) – Plan amendments – – – – Curtailments (8) – (7) – Settlements (40) – – – Benefit obligation at December 31 $ 117 $ 138 $ 13 $ 20 Other Postretirement Pension Benefits Benefits 2016 2015 2016 2015 (in millions) Change in plan assets: Fair value of plan assets at January 1 $ 108 $ 108 $ – $ – Actual return on plan assets 3 (1) – – Employer contributions 10 12 1 – Participant contributions – – – – Benefits paid (3) (11) (1) – Settlements (37) – – – Fair value of plan assets at December 31 $ 81 $ 108 $ – $ – Funded status of plans at December 31 $ (36) $ (30) $ (13) $ (20) The Company uses a December 31 measurement date for all of its plans and had liabilities recorded for the underfunded status for each period as presented above. The change in accumulated other comprehensive income related to the pension plans was a gain of $ 7 million ($ 4 million after tax) for the year ended December 31, 2016 and a loss of $ 2 million ($ 2 million after tax) for the year ended December 31, 2015. The change in accumulated other comprehensive income related to the other postretirement benefit plan was a gain of $ 3 million ($ 2 million after tax) for the year ended December 31, 2016 and a gain of $ 1 million ($ 1 million after tax) for the year ended December 31, 2015. Included in accumulated other comprehensive income as of December 31, 2016 and 2015 was a $ 31 million loss ($ 19 million net of tax) and a $ 42 million loss ($ 25 million net of tax ), respectively, related to the Company’s pension and other postretirement benefit plans. For the year ended December 31, 2016, $6 million was classified to accumulated other comprehensive income , primarily driven by actuarial loss adjustments. Amortization of prior period service cost reclassified from accumulated other comprehensive income to general and administrative expenses for the year was immaterial. The amount in accumulated other comprehensive income that is expected to be recognized as a component of net periodic benefit cost during 2017 is a $ 1 million net loss. The pension plans’ projected benefit obligation, accumulated benefit obligation and fair value of plan assets as of December 31, 2016 and 2015 are as follows: 2016 2015 (in millions) Projected benefit obligation $ 117 $ 138 Accumulated benefit obligation 116 135 Fair value of plan assets 81 108 Pension and other postretirement benefit costs include the following components for 201 6 , 201 5 and 201 4 : Other Postretirement Pension Benefits Benefits 2016 2015 2014 2016 2015 2014 (in millions) Service cost $ 11 $ 16 $ 13 $ 2 $ 3 $ 2 Interest cost 5 6 5 1 1 1 Expected return on plan assets (6) (9) (7) – – – Amortization of transition obligation – – – – – – Amortization of prior service cost – – – – – – Amortization of net loss 2 2 1 – – – Net periodic benefit cost 12 15 12 3 4 3 Curtailment loss 1 – – (6) – – Settlement loss 11 – – – – – Total benefit cost (benefit) $ 24 $ 15 $ 12 $ (3) $ 4 $ 3 Amounts recognized in other comprehensive income for the year ended December 31, 201 6 were as follows: Pension Benefits Other Postretirement Benefits (in millions) Net actuarial (loss) gain arising during the year $ (13) $ 2 Amortization of prior service cost – – Amortization of net loss 20 – Settlements – 1 Tax effect (3) (1) $ 4 $ 2 The assumptions used in the measurement of the Company’s benefit obligations as of December 31, 2016 and 2015 are as follows: Pension Benefits Other Postretirement Benefits 2016 2015 2016 2015 Discount rate 4.20 % 4.60 % 4.20 % 4.60 % Rate of compensation increase 3.50 % 3.50 % n/a n/a % The assumptions used in the measurement of the Company’s net periodic benefit cost for 2016, 2015 and 2014 are as follows: Pension Benefits Other Postretirement Benefits 2016 2015 2014 2016 2015 2014 Discount rate 4.20 % 4.25 % 5.00 % 4.20 % 4.25 % 5.00 % Expected return on plan assets 7.00 % 7.00 % 7.00 % n/a n/a n/a Rate of compensation increase 3.50 % 4.50 % 4.50 % n/a n/a n/a The expected return on plan assets for the various benefit plans is based upon a review of the historical returns experienced, combined with the future expected returns based upon the asset allocation strategy employed. The plans seek to achieve an adequate return to fund the obligations in a manner consistent with the federal standards of the Employee Retirement Income Security Act and with a prudent level of diversification. For measurement purposes, the following trend rates were assumed for 2016 and 2015: 2016 2015 Health care cost trend assumed for next year 7% 8% Rate to which the cost trend is assumed to decline 5% 5% Year that the rate reaches the ultimate trend rate 2034 2034 Assumed health care cost trend rates have a significant effect on the amounts for the health care plans. A one percentage point change in assumed health care cost trend rates would have the following effects: 1% Increase 1% Decrease (in millions) Effect on the total service and interest cost components $ – $ – Effect on postretirement benefit obligations $ 2 $ (2) Pension Payments and Asset Management In 2016, the Company contributed $ 1 0 million to its pension plans and $ 1 million to its other postretirement benefit plan. The Company expects to contribute $15 million to its pension and other postretirement benefit plans in 2017 . The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid: Pension Benefits Other Postretirement Benefits (in millions) 2017 $ 8 2017 $ 1 2018 6 2018 1 2019 6 2019 1 2020 7 2020 1 2021 8 2021 1 Years 2022-2026 46 Years 2022-2026 6 The Company’s overall investment strategy is to provide an adequate pool of assets to support both the long-term growth of plan assets and to ensure adequate liquidity exists for the near-term payment of benefit obligations to participants, retirees and beneficiaries. The Benefits Administration Committee of the Company administers the Company’s pension plan assets. The Benefits Administration Committee believes long-term investment performance is a function of asset-class mix and restricts the composition of pension plan assets to a combination of cash and cash equivalents, domestic equity markets, international equity markets or investment grade fixed income assets. The table below presents the allocations targeted by the Benefits Administration Committee and the actual weighted-average asset allocation of the Company’s pension plan as of December 31, 201 6 , by asset category. The asset allocation targets are subject to change and the Benefits Administration Committee allows for its actual allocations to deviate from target as a result of current and anticipated market conditions. Plan assets are periodically balanced whenever the allocation to any asset class falls outside of the specified range. Pension Plan Asset Allocations Asset category: Target Actual Equity securities: U.S. Equity (1) 35 % 36 % Non-U.S. Developed Equity (2) 30 % 28 % Emerging Markets Equity (3) 5 % 6 % Opportunistic (4) – % – % Fixed income (5) 28 % 25 % Cash (6) 2 % 5 % Total 100 % 100 % (1) I ncludes the following equity securities in the table below: U.S. large cap growth equity, U.S. large cap value equity, U.S. large cap core equity, and U.S. small cap equity. (2) I ncludes Non-U.S. equity securities in the table below. (3) I ncludes e merging markets equity securities below. (4) I ncludes none of the securities in the table below. (5) I ncludes f ixed income pension plan assets in the table below. (6) I ncludes Cash and cash equivalents pension plan assets in the table below. Utilizing the fair value hierarchy described in Note 6 – Fair Value Measurements , the Company’s fair value measurement of pension plan assets as of December 31, 201 6 is as follows: Total Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) (in millions) Measured within fair value hierarchy Equity securities: U.S. large cap growth equity (1) $ 6 $ 6 $ – $ – U.S. large cap value equity (2) 6 6 – – U.S. small cap equity (3) 3 3 – – Non-U.S. equity (4) 23 23 – – Emerging markets equity (5) 4 4 – – Fixed income ( 6 ) 21 21 – – Cash and cash equivalents 4 4 – – Total measured within fair value hierarchy $ 67 $ 67 $ – $ – Measured at net asset value (7) Equity securities: U.S. large cap core equity ( 8 ) 14 Total measured at net asset value $ 14 Total plan assets at fair value $ 81 (1) Mutual fund that seeks to invest in a diversified portfolio of stocks with price appreciation growth opportunities. (2) Mutual fund that seeks to invest in a diversified portfolio of stocks that will increase in value over the long-term as well as provide current income. (3) Mutual fund that seeks to invest in a diversified portfolio of stocks with small market capitalizations. (4) Mutual funds that invest primarily in equity securities of companies domiciled outside of the United States, primarily in developed markets. (5) An institutional fund that invests primarily in the equity securities of companies domiciled in emerging markets. (6) Institutional funds that seek an investment return that approximates, as closely as practicable, before expenses, the performance of the Barclays U.S. Intermediate Credit Bond Index over the long term and the Barclays Long U.S. Corporate Bond Index over the long-term . (7) Plan assets for which fair value was measured using net asset value as a practical expedient. (8) An institutional fund that seeks to replicate the performance of the S&P 500 Index before fees. Utilizing the fair value hierarchy described in Note 6 – Fair Value Measurements , the Company’s fair value measurement of pension plan assets at December 31, 201 5 is as follows: Total Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) (in millions) Measured within fair value hierarchy Equity securities: U.S. large cap growth equity (1) $ 9 $ 9 $ – $ – U.S. large cap value equity (2) 9 9 – – U.S. small cap equity (3) 3 3 – – Non-U.S. equity (4) 31 31 – – Emerging markets equity (5) 5 5 – – Cash and cash equivalents 2 2 – – Total measured within fair value hierarchy $ 59 $ 59 $ – $ – Measured at net asset value (6) Equity securities: U.S. large cap core equity (7) 18 Fixed income (8) 31 Total measured at net asset value $ 49 Total plan assets at fair value $ 108 (1) Mutual fund that seeks to invest in a diversified portfolio of stocks with price appreciation growth opportunities. (2) Mutual fund that seeks to invest in a diversified portfolio of stocks that will increase in value over the long-term as well as provide current income. (3) Mutual fund that seeks to invest in a diversified portfolio of stocks with small market capitalizations. (4) Mutual funds that invest primarily in equity securities of companies domiciled outside of the United States, primarily in developed markets. (5) An institutional fund that invests primarily in the equity securities of companies domiciled in emerging markets. (6) Plan assets for which fair value was measured using net asset value as a practical expedient. (7) An institutional fund that seeks to replicate the performance of the S&P 500 Index before fees. (8) An institutional fund that seeks an investment return that approximates, as closely as practicable, before expenses, the performance of the Barclays U.S. Intermediate Credit Bond Index over the long term and the Barclays Long U.S. Corporate Bond Index over the long-term. The Company’s pension plan assets that are classified as Level 1 are the investments compris ed of either cash or investments in open-ended mutual funds which produce a daily net asset value that is validated with a sufficient level of observable activity to support classification of the fa ir value measurement as Level 1. Due to the Company’s implementation of Accounting Standards Update No. 2015-07, assets measured using net asset value as a practical expedient have not been classified in the fair value hierarchy. No concentration of risk arising within or across categories of plan assets exists due to any significant investments in a single entity, industry, country or investment fund. |
Stock-Based Compensation
Stock-Based Compensation | 12 Months Ended |
Dec. 31, 2016 | |
Stock-Based Compensation [Abstract] | |
Stock-Based Compensation | (12 ) STOCK-BASE D COMPENSATION The Southwestern Energy Company 2013 Incentive Plan was adopted in February 2013 , approved by stockholders in May 2013 and amended and restated per stockholders’ approval in May 2016 ( the “2013 Plan”). The 2013 Plan provides for the compensation of officers, key employees and eligible non-employee directors of the Company and its subsidiaries. The 2013 Plan replaced the Southwestern Energy Company 2004 Stock Incentive Plan, the Southwestern Energy Company 2000 Stock Incentive Plan (“2000 Plan”) and the Southwestern Energy Company 2002 Employee Stock Incentive Plan (“2002 Plan”) but did not affect prior awards under those plans which remained valid and some of which are still outstanding. The awards under the prior plans have been adjusted for stock splits as permitted under such plans. The 2013 Plan provides for grants of options, stock appreciation rights, and shares of restricted stock and restricted stock units to employees, officers and directors that , in the aggregate , do not exceed 33,850,000 shares . The types of incentives that may be awarded are comprehensive and are intended to enable the Company’s board of directors to structure the most appropriate incentives and to address changes in income tax laws which may be enacted over the term of the 2013 Plan. As initially adopte d, the 2004 Plan, the 2000 Plan and the 2002 Plan provided for grants of options, stock appreciation rights, shares of phantom stock and shares of restricted stock that , in the aggregate , did not exceed 16,800,000 , 1,250,000 and 300,000 shares, respectively, to employees who are not officers or directors of the Company under provisions of Section 16 of the Securities Exchange Act of 1934, as amended. The Company may utilize treasury shares, if available, or authorized but unissued shares when a stock option is exercised or when restricted stock is granted. The Company measures the cost of employee services received in exchange for an award of equity instruments based on the grant date fair value of the award. All options are issued at fair market value at the date of grant and expire seven years from the date of grant for awards under both the 2013 Plan and the 2004 Plan and ten years from the date of grant for awards under all other plans. Generally, stock options granted to employees and directors vest ratably over three years from the grant date. The Company issues shares of restricted stock to employees and directors which generally vest over four years. The Company recognizes stock-based compensation expense on a straight-line basis over the requisite service period of the individual grants with the exception of awards granted to participants who have reached retirement age or will reach retirement age during the vesting period. Restricted stock and stock options granted to participants on or after December 6, 2013 immediately vest upon death, disability or retirement (subject to a minimum of three years of service). In January 2016, the Company announced a 40% workforce reduction that was substantially concluded by the end of March 2016. In April 2016, the Company also partially restructured executive management, which was substantially completed in the second quarter of 2016. Affected employees were offered a severance package that included, if applicable, amendments to certain outstanding equity awards that modified forfeiture provisions up on separation from the Company. As a result, certain unvested stock-based equity awards became fully vested at the time of separation. These shares were revalued and recognized immediately as a component of restructuring charges on the Company’s unaudited consolidated statement of operations. The unvested portion of equity-based performance units was forfeited upon separation from the Company. Stock Options The Company recorded the following compensation costs related to stock options for the years ended December 31, 2016, 2015 and 2014: 2016 2015 2014 (in millions) Stock-based compensation cost related to stock options – general and administrative expense (1) $ 6 $ 5 $ 5 Stock-based compensation cost related to stock options – capitalized $ 1 $ 3 $ 4 (1) Includes less than $1 million and $1 million related to the reduction in workforce and executive management restructuring, respectively, for the year ended December 31, 2016. The Company also recorded a deferred tax asset of $ 2 million, $ 2 million and $ 3 million related to stock options in 2016, 2015 and 201 4, respectively . U nrecognized compensation cost related to the Company’s unvested stock options totaled $ 4 million at December 31, 2016. This cost is expected to be recognized over a weighted-average period of 2 y ears. The fair value of stock options is estimated on the date of the grant using a Black-Scholes valuation model that uses the weighted average assumptions noted in the following table. Expected volatility is based on historical volatility of the Company’s common stock and other factors. The Company uses historical data on the exercise of stock options, post - vesting forfeitures and other factors to estimate the expected term of the stock-based payments granted. The risk - free interest rate is based on the U.S. Treasury yield curve in effect at the time of grant. Assumptions 2016 2015 2014 Risk-free interest rate 1.4% 1.7% 1.6% Expected dividend yield – – – Expected volatility 41.0% 36.0% 32.5% Expected term 5 years 5 years 5 years The following tables summarize stock option activity for the years 201 6 , 201 5 and 201 4, and provide information for options outstanding at December 31 of each year : 2016 2015 2014 Weighted Weighted Weighted Average Average Average Number Exercise Number Exercise Number Exercise of Shares Price of Shares Price of Shares Price (in thousands) (in thousands) (in thousands) Options outstanding at January 1 5,623 $ 24.57 3,622 $ 35.41 3,313 $ 35.70 Granted (1) 155 8.60 2,401 9.47 835 32.31 Exercised (45) 7.74 – – (402) 30.60 Forfeited or expired (317) 38.01 (400) 32.20 (124) 37.80 Options outstanding at December 31 5,416 $ 23.46 5,623 $ 24.57 3,622 $ 35.41 (1) Shares granted in 2016 are considerably lower than historical norms. In 2016, the Company changed the grant date of its annual stock option awards from December to the following February. Options Outstanding Options Exercisable Weighted Weighted Options Weighted Average Options Weighted Average Outstanding at Average Remaining Aggregate Exercisable at Average Remaining Aggregate Range of December 31, Exercise Contractual Intrinsic December 31, Exercise Contractual Intrinsic Exercise Prices 2016 Price Life Value 2016 Price Life Value (in thousands) (years) ( in millions) (in thousands) (years) (in millions) $7.74 - $29.69 2,501 9.54 5.9 781 9.77 5.8 $30.59 - $35.91 1,384 32.32 3.9 1,146 32.68 3.7 $36.22 - $39.68 1,402 37.49 2.4 1,402 37.49 2.4 $40.15 - $51.47 129 45.79 3.3 99 45.57 3.0 5,416 $ 23.46 4.4 $ 7 3,428 $ 29.80 3.6 $ 2 The weighted-average grant date fair value of options granted during the years 2016, 2015 and 2014 was $3.22 , $3.16 and $10.16 , respectively. The total intrinsic value of options exercised during 2016 and 2014 was less than $1 million and $ 4 million , respectively . There were no options exercised in 2015. Restricted Stock The Company recorded the following compensation costs related to restricted stock grants for the years ended December 31, 2016, 2015 and 2014: 2016 2015 2014 (in millions) Stock-based compensation cost related to restricted stock grants – general and administrative expense (1) $ 33 $ 14 $ 10 Stock-based compensation cost related to restricted stock grants – capitalized $ 8 $ 16 $ 12 (1) Includes $16 million and $1 million related to the reduction in workforce and executive management restructuring, respectively, for the year ended December 31, 2016. The Company also recorded a deferred tax asset of $ 12 million related to restricted stock for the year ended December 31, 201 6 , compared to a deferred tax asset of $ 11 million for 201 5 and a deferred tax liability of $ 10 million for 201 4 . As of December 31, 201 6 , there was $ 37 million of total unrecognized compensation cost related to unvested shares of restricted stock that is expected to be recognized over a weighted-average period of 2 years . The following table summarizes the restricted stock activity for the years 201 6 , 201 5 and 201 4, and provides information for restricted stock outstanding at December 31 of each year : 2016 2015 2014 Number of Shares Weighted Average Fair Value Number of Shares Weighted Average Fair Value Number of Shares Weighted Average Fair Value (in thousands) (in thousands) (in thousands) Unvested shares at January 1 7,222 $ 13.24 2,376 $ 34.00 1,771 $ 37.55 Granted (1) 81 8.56 5,822 8.07 1,295 30.89 Vested (2) (3,817) 11.34 (873) 33.33 (548) 37.12 Forfeited (165) 12.05 (103) 29.14 (142) 37.91 Unvested shares at December 31 3,321 $ 11.85 7,222 $ 13.24 2,376 $ 34.00 (1) Shares granted in 2016 are considerably lower than historical norms. In 2016, the Company changed the grant date of its annual restricted stock awards from December to the following February. (2) Includes 2,059,626 shares and 151,575 shares related to reduction in workforce and executive management restructuring, respectively, for the year ended December 31, 2016. The fair values of the grants were $ 1 million for 201 6 , $ 47 million for 201 5 and $ 40 million for 201 4 . The total fair value of shares vested were $ 43 million for 201 6 , $ 29 million for 201 5 and $ 20 million for 201 4 . Equity-Classified Performance Units The Company recorded compensation costs related to equity-classified performance units for the years ended December 31, 2016, 2015 and 2014. The performance units awarded in 2013 and 2014 included a market condition based on relative Total Shareholder Return (“TSR”) and a performance condition based on the Company’s Present Value Index (“PVI”), collectively the “Performance Measures.” The fair value of the TSR market condition is based on a Monte Carlo model and is amortized to compensation expense on a straight-line basis over the vesting period of the award. The fair value of the PVI performance condition is based on economic analysis for each investment opportunity based upon the expected present value added for each dollar to be invested and amortized to compensation expense on a straight line basis over the vesting period of the award. The performance units awarded in 2016 and 2015 are based exclusively on TSR. The grant date fair value is calculated using the applicable Performance Measures and the closing price of the Company’s common stock at the grant date. 2016 2015 2014 (in millions) Stock-based compensation cost related to performance units – general and administrative expense (1) $ 9 $ 6 $ 3 Stock-based compensation cost related to performance units – capitalized $ 1 $ 4 $ 2 (1) Includes less than $1 million and $1 million related to reduction in workforce and executive management restructuring, respectively, for the year ended December 31, 2016. The Company also recorded a deferred tax asset of $4 million related to equity-based performance units for the year ended December 31, 2016, compared to deferred tax assets of $4 million and $2 million in 2015 and 2014, respectively. As of December 31, 2016, there was $9 million of total unrecognized compensation cost related to unvested equity-based performance units that is expected to be recognized over a weighted-average period of 2 years . The following table summarizes performance unit activity to be paid out in Company stock for the years ended December 31, 201 6, 2015 and 2014, and provides information for unvest ed units as of December 31, 2016, 2015 and 2014: 2016 2015 2014 Number of Units (1) Weighted Average Fair Value Number of Units (1) Weighted Average Fair Value Number of Units (1) Weighted Average Fair Value (in thousands) (in thousands) (in thousands) Unvested shares at January 1 407 $ 36.65 223 $ 40.44 – $ – Granted 1,503 8.60 443 35.22 359 40.44 Vested (2) (889) 12.78 (259) 37.46 (111) 40.44 Forfeited (3) (302) 11.26 – – (25) 40.44 Unvested shares at December 31 719 $ 11.46 407 $ 36.65 223 $ 40.44 (1) These amounts reflect the number of performance units granted in thousands. The actual payout in shares may range from a minimum of zero shares to a maximum of two shares contingent upon the actual performance against the Performance Measures. The performance units have a three -year vesting term and the actual disbursement of shares, if any, is not determined until March following the end of the three-year vesting period. (2) Includes 22,918 units and 37,590 units related to the reduction in workforce and executive management restructuring, respectively, for the year ended December 31, 2016. (3) Includes 87,595 units and 195,834 units related to the reduction in workforce and executive management restructuring, respectively, for the year ended December 31, 2016. Liability-Classified Performance Units Prior to 2013, certain employees were provided performance units vesting equally over three years that were settled in cash. The payout of these units was based on certain metrics, such as total shareholder return and reserve replacement efficiency, compared to a predetermined group of peer companies and Company goals. At the end of each performance period, the value of the vested performance units, if any, would be paid in cash. In the first quarter of 2016, the Company completed the final payout under these performance unit agreements . |
Segment Information
Segment Information | 12 Months Ended |
Dec. 31, 2016 | |
Segment Information [Abstract] | |
Segment Information | (13 ) SEGME NT INFORMATION The Company’s reportable business segments have been identified based on the differences in products or services provided. Revenues for the E&P segment are derived from the production and sale of natural gas and liquids . The Midstream Services segment generates revenue through the marketing of both Company and third-party produced natural gas and liquids volumes and through gathering fees associated with the transportation of natural gas to market. Summarized financial information for the Company’s reportable segments is shown in the following t able. The accounting policies of the segments are the same as those described in Note 1 – Organization and Summary of Significant Accounting Policies . Management evaluates the performance of its segments based on operating income, defined as operating revenues less operating costs . Income before income taxes, for the purpose of reconciling the operating income amount shown below to consolidated income before income taxes, is the sum of operating income, interest expense , gain (loss ) on derivatives, loss on early extinguishment of debt and other income (loss) . The “Other” column includes items not related to the Company’s reportable segments , including real estate and corporate items. Exploration and Midstream Production Services Other Total (in millions) 2016 Revenues from external customers $ 1,435 $ 1,001 $ – $ 2,436 Intersegment revenues (22) 1,568 – 1,546 Depreciation, depletion and amortization expense 371 65 – 436 Impairment of natural gas and oil properties 2,321 – – 2,321 Operating income (loss) (2,404) (1) 209 (2) – (2,195) Interest expense (3) 87 1 – 88 Gain (loss) on derivatives (338) (1) – (339) Loss on early extinguishment of debt – – (51) (51) Other income ( loss ) , net 5 (2) (2) 1 Provision (benefit) for income taxes (3) (29) – – (29) Assets 4,178 (4) 1,331 1,567 (5) 7,076 Capital investments (6 ) 623 21 4 648 2015 Revenues from external customers $ 2,095 $ 1,038 $ – $ 3,133 Intersegment revenues (21) 2,081 – 2,060 Depreciation, depletion and amortization expense 1,028 62 1 1,091 Impairment of natural gas and oil properties 6,950 – – 6,950 Operating income (loss) (7,104) 583 (7 ) (1) (6,522) Interest expense (3) 47 9 – 56 Gain (loss) on derivatives 51 – (4) 47 Other loss, net (21) (9) – (30) Provision (benefit) for income taxes (3) (2,273) 268 – (2,005) Assets 6,588 (4) 1,290 208 8,086 Capital investments (6 ) 2,258 167 12 2,437 2014 Revenues from external customers $ 2,850 $ 1,188 $ – $ 4,038 Intersegment revenues 12 3,170 – 3,182 Depreciation, depletion and amortization expense 884 58 – 942 Operating income (loss) 1,013 361 (1) 1,373 Interest expense (3) 47 12 – 59 Gain (loss) on derivatives 142 (1) (2) 139 Other loss, net (3) (1) – (4) Provision for income taxes (3) 402 123 – 525 Assets 13,018 (4) 1,554 343 14,915 Capital investments (6 ) 7,254 144 49 7,447 (1) Operating loss for the E&P segment includes $86 million related to restructuring and other one-time charges for the year ended December 31, 2016. (2) Operatin g income f or the Midstream Services segment includes $3 million related to restructuring charges for the year ended December 31, 2016. (3) Interest expense and the provision (benefit) for income taxes by segment are an allocation of corporate amounts as they are incurred at the corporate level. (4) Includes office, technology, drilling rigs and other ancillary equipment not directly related to natural gas and oil property acquisition, exploration and development activities. (5) Other assets represent corporate assets not allocated to segments and assets for non-reportable segments. At December 31, 2016, other assets includes approximately $1.4 billion in cash and cash equivalents . (6) Capital investments include a n increase of $ 43 millio n for 201 6, a decrease of $ 33 million for 2015 and an increase of $ 155 million for 201 4 related to the change in accrued expenditures between years. (7) Operating income (loss) for the Midstream Services segment includes a $277 million gain on sale of assets for the year ended December 31, 2015. Included in intersegment revenues of the Midstream Services segment are $ 1. 3 b illion , $ 1.8 billion and $ 2.8 billion for 201 6 , 201 5 and 201 4 , respectively, for marketing of the Company’s E&P sales. Corporate assets include cash and cash equivalents, furniture and fixtures and other costs. Corporate general and administrative costs, depreciation expense and taxes other than incom e are allocated to the segments . |
Subsequent Events
Subsequent Events | 12 Months Ended |
Dec. 31, 2016 | |
Subsequent Events [Abstract] | |
Subsequent Events | (14 ) SUBSEQU ENT EVENTS None. |
Supplemental Quarterly Results
Supplemental Quarterly Results | 12 Months Ended |
Dec. 31, 2016 | |
Supplemental Quarterly Results [Abstract] | |
Supplemental Quarterly Results | SUPPLEMENTAL QUARTE R LY RESULTS (UNAUDITED) The following is a summary of the quarterly results of operations for the years ended December 31, 201 6 and 201 5 : 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter (in millions, except per share amounts) 2016 Operating revenues $ 579 $ 522 $ 651 $ 684 Operating income (loss) (1) (1,100) (492) (725) 122 Net loss attributable to common stock (1,159) (620) (735) (237) Loss per share - Basic (3.03) (1.61) (1.52) (0.48) Loss per share - Diluted (3.03) (1.61) (1.52) (0.48) 2015 Operating revenues $ 933 $ 764 $ 749 $ 687 Operating income (loss) (1) 165 (1,284) (2,842) (2,561) Net income (loss) attributable to common stock (2) 46 (815) (1,766) (2,134) Earnings (Loss) per share - Basic 0.12 (2.13) (4.62) (5.58) Earnings (Loss) per share - Diluted 0.12 (2.13) (4.62) (5.58) (1) The operating losses for the first, second and third quarters of 2016 included non-cash full cost impairments of natural gas and oil properties of $1,034 million, $470 million, and $817 million, respectively. There was no full cost impairment in the fourth quarter of 2016. The operating losses for the second, third and fourth quarters of 2015 included non-cash full cost impairments of natural gas and oil properties of $1,535 million, $2,839 million and $2,576 million, respectively. (2) Net income attributable to common stock was reduced by $7 million in the first quarter of 2015 to recognize the portion of the Company’s net income that would be distributed to the holders of preferred securities (mandatory convertible preferred stock) at year-end. However, as a result of the Company’s net loss in the second quarter that persisted for the year ended December 31, 2015, participating securities were ultimately not entitled to receive a distribution. |
Supplemental Oil And Gas Disclo
Supplemental Oil And Gas Disclosures | 12 Months Ended |
Dec. 31, 2016 | |
Supplemental Oil And Gas Disclosures [Abstract] | |
Supplemental Oil And Gas Disclosures | SUPPLEMENTA L OIL AND GAS DISCLOSURES (UNAUDITED) The Company’s operating natural gas and oil properties are located solely in the United States . The Company also has licenses to properties in Canada , the development of which is subject to an indefinite moratorium. See “Our Operations — Other — New Brunswick, Canada” in Item 1 of Part 1 of this Annual Report. Net Capitalized Costs The following table shows the capitalized costs of natural gas and oil properties and the related accumulated depreciation, depletion and amortization as of December 31, 2016 and 2015: 2016 2015 (in millions) Proved properties $ 20,548 $ 18,751 Unproved properties 2,105 3,727 Total capitalized costs 22,653 22,478 Less: Accumulated depreciation, depletion and amortization (18,897) (16,248) Net capitalized costs $ 3,756 $ 6,230 Natural gas and oil properties not subject to amortization represent investments in unproved properties and major development projects in which the Company own s an interest. These unproved property costs include unevaluated costs associated with leasehold or drilling interests and unevaluated costs associated with wells in progress . The table below sets forth the composition of net unevaluated costs excluded from amortization as of December 31, 201 6: 2016 2015 2014 Prior Total (in millions) Property acquisition costs $ 22 $ 213 $ 1,501 $ 54 $ 1,790 Exploration and development costs 55 64 24 16 159 Capitalized interest 70 55 10 21 156 $ 147 $ 332 $ 1,535 $ 91 $ 2,105 Of the total net unevaluated costs excluded from amortization as of December 31, 201 6 , approximately $1.6 billion is related to the Chesapeake and Statoil Property Acquisition s , approximately $ 100 million is related to the acquisition of undeveloped properties outside the Appalachian Basin and the Fayetteville Shale , excluding licenses in Canada subject to an indefinite moratorium , and approximately $ 94 million is related to the acquisition of the Company’s undeveloped properties in Northeast Appalachia . Additionally, the Company has approximately $ 113 millio n of unevaluated costs related to costs of wells in progress. The remaining cos ts excluded from amortization are related to properties which are not individually significant and on which the evaluation process has not been completed. The timing and amount of property acquisition and seismic costs included in the amortization computation will depend on the location and timing of drilling wells, r esults of drilling and other assessments. The Company is, therefore, unable to estimate when these costs will be included in the amortization computation. Costs Incurred in Natural Gas and Oil Exploration and Development The table below sets forth capitalized costs incurred in natural gas and oil property acquisition, exploration and development activities: 201 6 201 5 201 4 (in millions, except per Mcfe amounts) Proved property acquisition costs $ – $ 81 $ 1,455 Unproved property acquisition costs 171 692 3,934 Exploration costs 17 50 232 Development costs 433 1,417 1,600 Capitalized costs incurred 621 2,240 7,221 Full cost pool amortization per Mcfe $ 0.38 $ 1.00 $ 1.10 Capitalized interest is included as part of the cost of natural gas and oil properties. The Company capitalized $152 million , $ 204 million and $ 55 million during 201 6, 2015 and 2014 , respectively, based on the Company’s weighted average cost of borrowings used to finance expenditures. In addition to capitalized interest, the Company capitalize d internal costs totaling $112 mi llion, $307 million and $320 million during 2016, 2015 and 2014, respectively, which were directly related to the acquisition, exploration and development of t he Company’s natural gas and oil properties . Included in these amounts are internal costs from the Company’s subsidiaries involved with vertical integration of the Company’s exploration and develop ment activities, which totaled $19 million , $118 million and $123 million during 2016, 2015 and 2014 , respectively. All internal costs are included in the Company’s cost of natural gas and oil properties. Results of Operations from Natural Gas and Oil Producing Activities The table below sets forth the results of operations from natural gas and oil producing activities: 2016 2015 2014 (in millions) Sales $ 1,413 $ 2,074 $ 2,862 Production (lifting) costs (839) (989) (776) Depreciation, depletion and amortization (371) (1,028) (884) Impairment of natural gas and oil properties (2,321) (6,950) – (2,118) (6,893) 1,202 Provision (benefit) for income taxes – (1) (2,619) 457 Results of operations ( 2 ) $ (2,118) $ (4,274) $ 745 (1) Prior to the Company’s recognition of a valuation allowance in 2016, the Company recognized an income tax benefit of $805 million . (2) Results of operations exclude the gain (loss) on unsettled commodity derivative instruments. See Note 4 - Derivatives and Risk Management The results of operations shown above exclude gene ral and administrative expenses and interest expense and are not necessarily indicative of the contribution made by the Company’s natural gas and oil operations to its consolidated operating results. Income tax expense is calculated by applying the statutory tax rates to the revenues less costs, including depreciation, depletion and amortization, and after giving effect to permanent differences and tax credits. Natural Gas and Oil Reserve Quantities The Company engaged the services of Netherland, Sewell & Associates, Inc., or NSAI , an independent petroleum engineering firm, to audit the reserves estimated by the Company’s reservoir engineers. In conducting its audit, the engineers and geologists of NSAI studied the Company’s major properties in detail and independentl y developed reserve estimates. NSAI’s audit consists primarily of substantive testing, which includes a detailed review of the Company’s major properties , and accounted for approximately 99% , 100% and 97% of the present worth of the Company’s total proved reserves as of December 31, 201 6 , 201 5 and 201 4 , respectively. A reserve audit is not the same as a financial audit , and a reserve audit is less rigorous in nature than a reserve report prepared by an independent petroleum engineering firm containing its own estimate of reserves. Reserve estimates are inherently imprecise , and the Company’s reserve estimates are generally based upon extrapolation of historical production trends, historical prices of natural gas and crude oil and analogy to similar properties and volumetric calculations. Accordingly, the Company’s estimates are expected to change, and such changes could be material and occur in the near term as future information becomes available. For more information over reserves, refer to the table titled “Changes in Proved Undeveloped Reserves (Bcfe)” in “Business – Exploration and Production” in Item 1 of this Annual Report. The following table summarizes the changes in the Company’s proved natural gas , oil and NGL reserves for 201 6 , 2 01 5 and 201 4, all of which were located in the United States: 2016 2015 2014 Natural Natural Natural Gas Oil NGL Gas Oil NGL Gas Oil NGL (Bcf) (MBbls) (MBbls) (Bcf) (MBbls) (MBbls) (Bcf) (MBbls) (MBbls) Proved reserves, beginning of year 5,917 8,753 40,947 9,809 37,615 118,699 6,974 373 – Revisions of previous estimates (446) 1,564 13,794 (3,458) (28,394) (75,664) 542 (14) 66 Extensions, discoveries and other additions 198 2,417 11,576 546 1,367 6,274 1,692 250 48 Production (788) (2,192) (12,372) (899) (2,265) (10,702) (766) (235) (231) Acquisition of reserves in place – – – 97 525 2,340 1,367 37,246 118,816 Disposition of reserves in place (15) (19) (14) (178) (95) – – (5) – Proved reserves, end of year 4,866 10,523 53,931 5,917 8,753 40,947 9,809 37,615 118,699 Proved developed reserves: Beginning of year 5,474 8,753 40,947 5,675 7,445 38,632 4,237 372 – End of year 4,789 10,523 53,931 5,474 8,753 40,947 5,675 7,445 38,632 Proved undeveloped reserves: Beginning of year 443 – – 4,134 30,170 80,067 2,737 1 – End of year 77 – – 443 – – 4,134 30,170 80,067 The Company’s estimated proved natural gas , oil and NGL reserves were 5,253 Bcfe at December 31, 201 6 , compared to 6,215 Bcfe at December 31, 201 5. The decrease in the Company's reserves in 2016 was primarily due to the decrease in commodity prices . The significant decrease in the Company's reserves in 2015 was primarily due to the decrease in commodity prices. The significant increase in the Company's reserves in 2014 was primarily due to the acquisition of approximately 413,000 net acres in Southwest Appalachia, successful development drilling programs in the Fayetteville Shale and Northeast Appalachia and upward performance revisions in Northeast Appalachia. In 2014, the Company replaced 550% of its production volumes with proved reserve additions and proved reserve additions as a result of acquisitions primarily associated with acreage in Southwest Appalachia. The following table summarizes the changes in reserves for 2014, 20 15 and 2016: Appalachia Fayetteville Total Northeast Southwest Shale Other (1) (in Bcfe) December 31, 2013 6,976 1,963 – 4,795 218 Production (768) (254) (3) (494) (17) Disposition of reserves in place – – – – – Acquisition of reserves in place 2,303 1 2,300 – 2 Net revisions Price revisions 54 10 – 38 6 Performance and production revisions 489 636 – (126) (21) Total net revisions 543 646 – (88) (15) Reserve additions Proved developed 531 246 – 283 2 Proved undeveloped 1,162 589 – 573 – Total reserve additions 1,693 835 – 856 2 December 31, 2014 10,747 3,191 2,297 5,069 190 Production (976) (360) (143) (465) (8) Disposition of reserves in place (180) – – – (180) Acquisition of reserves in place 115 80 35 – – Net revisions Price revisions (5,718) (2,315) (1,875) (1,496) (32) Performance and production revisions 1,635 1,383 209 10 33 Total net revisions (4,083) (932) (1,666) (1,486) 1 Reserve additions Proved developed 416 202 84 129 1 Proved undeveloped 176 138 4 34 – Total reserve additions 592 340 88 163 1 December 31, 2015 6,215 2,319 611 3,281 4 Production (875) (350) (148) (375) (2) Disposition of reserves in place (15) – (15) – – Acquisition of reserves in place – – – – – Net revisions Price revisions (1,037) (794) (127) (116) – Performance and production revisions 683 318 199 163 3 Total net revisions (354) (476) 72 47 3 Reserve additions Proved developed 257 81 157 19 – Proved undeveloped 25 – – 25 – Total reserve additions 282 81 157 44 – December 31, 2016 5,253 1,574 677 2,997 5 (1) Other includes properties outside of the Appalachian Basin and Fayetteville Shale along with Ark-La-Tex properties divested in May 2015. The Company's December 31, 2016 proved reserves included 77 Bcfe of proved undeveloped reserves from 15 locations that had a positive present value on an undiscounted basis in compliance with proved reserve requirements, but do not have a positive present value when discounted at 10% . These properties had a negative present value of $11 million when discounted at 10% . The Company made a final investment decision and is committed to developing these reserves within the next five years from the date of initial booking . The Company's December 31, 2015 proved reserves included 217 Bcfe of proved undeveloped reserves from 75 locations that had a positive present value on an undiscounted basis in compliance with proved reserve requirements, but that have a negative $34 million present value when discounted at 10% . The Company's December 31, 2014 proved reserves included 181 Bcfe of proved undeveloped reserves from 60 locations that had a positive present value on an undiscounted basis in compliance with proved reserve requirements, but that have a negative $28 million present v alue when discounted at 10% . The Company has no reserves from synthetic gas, synthetic oil or nonrenewable natural resources intended to be upgraded into synthetic gas or oil. The Company used standard engineering and geoscience methods, or a combination of methodologies in determining estimates of material properties, including performance and test date analysis , offset statistical analogy of performance data, volumetric evaluation, including analysis of petrophysical parameters (including porosity, net pay, fluid saturations (i.e., water, oil and gas) and permeability) in combination with estimated reservoir parameters (including reservoir temperature and pressure, formation depth and formation volume factors), geological analysis, including structure and isopach maps and seismic analysis, including review of 2-D and 3-D data to ascertain faults, closure and other factors. Standardized Measure of Discounted Future Net Cash Flows The following standardized measures of discounted future net cash flows relating to proved natural gas , oil and NGL reserves as of December 31, 2016, 2015 and 2014 are calculated after income taxes , discounted using a 10 % annual discount rate and do not purport to present the fair market value the Company’s proved gas , oil and NGL reserves: 2016 2015 2014 (in millions) Future cash inflows $ 9,064 $ 11,887 $ 41,812 Future production costs (5,880) (7,376) (16,477) Future development costs (1) (485) (792) (5,750) Future income tax expense (2) – – (4,743) Future net cash flows 2,699 3,719 14,842 10% annual discount for estimated timing of cash flows (1,034) (1,302) (7,299) Standardized measure of discounted future net cash flows $ 1,665 $ 2,417 $ 7,543 (1) Includes abandonment costs. (2) The December 31, 2016 and 2015 standardized measure computation does not have future income taxes because the Company’s tax basis in the associated oil and gas properties exceeded expected pre-tax cash inflows. Future net cash flows are not permitted to be increased by excess tax basis. Under the standardized measure, future cash inflows were estimated by applying an average price from the first day of each month from the previous 12 months, adjusted for known contractual changes, to the estimated future production of year-end proved reserves. Prices used for the standardized measure above were $2 .48 per MMBtu for natural gas, $ 39.25 per barrel for oil and $ 6.74 per barrel for NGLs in 2016, $ 2.59 per MMBtu for natural gas, $ 46.79 per barrel for oil and $6.82 per barrel for NGLs in 2015, and $ 4.35 per MMBtu for natural gas, $ 91.48 per barrel for oil and $23.79 per barrel for NGLs in 2014. Future cash inflows were reduced by estimated future production and development costs based on year-end costs to determine pre-tax cash inflows. Future income taxes were computed by applying the year-end statutory rate to the excess of pre-tax cash inflows over the Company’s tax basis in the associated proved gas and oil properties after giving effect to permanent differences and tax credits. Following is an analysis of changes in the standardized measure during 2016, 2015 and 2014: 2016 2015 2014 (in millions) Standardized measure, beginning of year $ 2,417 $ 7,543 $ 3,736 Sales and transfers of natural gas and oil produced, net of production costs (574) (1,082) (2,084) Net changes in prices and production costs (415) (8,075) 1,192 Extensions, discoveries, and other additions, net of future production and development costs 45 162 1,049 Acquisition of reserves in place – 28 1,897 Sales of reserves in place (10) (244) – Revisions of previous quantity estimates (140) (1,385) 622 Accretion of discount 242 946 513 Net change in income taxes – 1,915 (522) Changes in estimated future development costs 71 2,007 110 Previously estimated development costs incurred during the year 114 875 815 Changes in production rates (timing) and other (85) (273) 215 Standardized measure, end of year $ 1,665 $ 2,417 $ 7,543 |
Organization And Summary Of S26
Organization And Summary Of Significant Accounting Policies (Policy) | 12 Months Ended |
Dec. 31, 2016 | |
Organization And Summary Of Significant Accounting Policies [Abstract] | |
Nature Of Operations | Nature of Operations Southwestern Energy Company (including its subsidiaries, collectively “Southwestern” or the “Company”) is an independent energy company engaged in natural gas , oil and NGL exploration, development and production (“E&P”). The Company is also focused on creating and capturing additional value through its natural gas gathering and marketing businesses (“Midstream Services”). Southwestern conducts most of its businesses through subsidiaries and operates principally in two segments: E&P and Midstream Services . Exploration and Production. Southwestern’s primary business is the exploration for and production of natural gas, oil and NGLs, with current operations principally focused on the development of unconventional natural gas reservoirs located in Pennsylvania, West Virginia and Arkansas. The Company’s operations in northeast Pennsylvania, herein referred to as “Northeast Appalachia,” are primarily focused on the unconventional natural gas reservoir known as the Marcellus Shale. Operations in West Virginia and southwest Pennsylvania, herein referred to as “Southwest Appalachia,” are focused on the Marcellus Shale, the Utica and the Upper Devonian unconventional natural gas and oil reservoirs. Collectively, Southwestern refers to its properties located in Pennsylvania and West Virginia as the “Appalachian Basin.” The Company’s operations in Arkansas are primarily focused on an unconventional natural gas reservoir known as the Fayetteville Shale. Southwestern has activities ongoing in Colorado and Louisiana, along with other areas in which it is currently assessing new development opportunities. The Company also has drilling rigs located in Pennsylvania, West Virginia and Arkansas and provides oilfield products and services, principally serving its E&P operations. Midstream Services. Through the Company’s affiliated midstream subsidiaries, Southwestern engages in natural gas gathering activities in Arkansas and Louisiana. These activities primarily support the Company’s E&P operations and generate revenue from fees associated with the gathering of natural gas. Southwestern’s marketing activities capture opportunities that arise through the marketing and transportation of the natural gas, oil and NGLs produced in its E&P operations. |
Basis Of Presentation | Basis of Presentation The consolidated financial statements included in this Annual Report present the Company’s financial position, results of operations and cash flows for the periods presented in accordance with accounting principles generally accepted in the United States (“GAAP”). The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the financial statements, and the amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The Company evaluates subsequent events through the date the financial statements are issued. Certain reclassifications have been made to the prior year financial s tatements to conform to the 2016 presentation. The effects of the reclassifications were not material to the Company’s consolidated financial statements. See Note 1 – New Accounting Standards Implemented in this Report for additional information regarding the reclassifications. |
Principles Of Consolidation | Principles of Consolidation The consolidated financial statements include the accounts of Southwestern and its wholly-owned subsidiaries. All significant intercompany accounts and transactions have been eliminated. In 2015, the Company purchased an 86% ownership in a limited partnership which owns and operates a gathering system in Northeast Appalachia as part of the WPX Property Acquisition (as defined and discussed in Note 3 ). Because the Company owns a controlling interest in the partnership, the operating and financial results are consolidated with the Company’s E&P segment results. The investor’s share of the partnership activity is reported in retained earnings in the consolidated financial statements. Net income attributable to noncontrolling interest for the year s ended December 31, 2016 and 2015 was insignificant . |
Revenue Recognition | Revenue Recognition Natural gas and liquid sales. Natural gas and liquid sales are recognized when the products are sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectability of the revenue is reasonably assured. The Company uses the entitlement method that requires revenue recognition for the Company’s net revenue interest of sales from its properties. Accordingly, natural gas and liquid sales are not recognized for deliveries in excess of the Company’s net revenue interest, while natural gas and liquid sales are recognized for any under-delivered volumes. Production imbalances are generally recorded at estimated sales prices of the anticipated future settlements of the imbalances. The Company had no significant production imbalances at December 31, 2016 or 2015. Marketing. The Company generally markets its natural gas and liquids, as well as some products produced by third parties, to marketers, local distribution companies and end-users, pursuant to a variety of contracts. Marketing revenues are recognized when delivery has occurred, title has transferred, the price is fixed or determinable and collectability of the revenue is reasonably assured. Gas gathering. In certain areas, the Company gathers its natural gas as well as some natural gas produced by third parties pursuant to a variety of contracts. Gas gathering revenues are recognized when the service is performed, the price is fixed or determinable and collectability of the revenue is reasonably assured. |
Cash And Cash Equivalents | Cash and Cash Equivalents Cash and cash equivalents are defined by the Company as short-term, highly liquid investments that have an original maturity of three months or less and deposits in money market mutual funds that are readily convertible into cash. Management considers cash and cash equivalents to have minimal credit and market risk as the Company monitors the credit status of the financial institutions holding its cash and marketable securities . The following table presents a summary of cash and cash equivalents as of December 31, 2016 and December 31, 2015: For the years ended December 31, 2016 2015 (in millions) Cash $ 254 $ 15 Marketable Securities (1) 1,169 – Total $ 1,423 $ 15 (1) Consists of government stable value money market funds . Certain of the Company’s cash accounts are zero-balance controlled disbursement accounts. The Company presents the outstanding checks written against these zero-balance accounts as a component of accounts payable in the accompanying consolidated balance sheets. Outstanding checks included as a component of accounts payable totale d $ 8 m illion and $ 29 million as of December 31, 2016 and 2015 , respectively. |
Property, Depreciation, Depletion And Amortization | Property, Depreciation, Depletion and Amortization Natural Gas and Oil Properties. The Company utilizes the full cost method of accounting for costs related to the exploration, development and acquisition of natural gas and oil properties . Under this method, all such costs (productive and nonproductive), including salari es, benefits and other internal costs directly attributable to these activiti es are capitalized on a country-by- country basis and amortized over the estimated lives of the properties using the units-of-production method. These capitalized costs are subject to a ceiling test that limits such pooled costs , net of applicable deferred taxes, to the aggregate of the present valu e of future net revenues attributable to proved natural gas, oil and NGL reserves discounted at 10% (standardized measure) . Any costs in excess of the ceiling are writ ten off as a non-cash expense. The expense may not be reversed in future periods, even though higher natural gas , oil and NGL prices may subsequently increase the ceiling. C ompanies using the full cost method are required to use the average quoted price from the first day of each month from the previous 12 months, including the impact of derivatives designated for hedge accounting, to calculate the ceiling value of their reserves. Decreases in market prices as well as changes in production rates, levels of reserves, evaluation of costs excluded from amortization, future development costs and production costs could result in future ceiling test impairments. Costs associated with unevaluated properties are excluded from the amortization base until the properties are evaluated or impairment is indicated. The costs associated with unevaluated leasehold acreage and related seismic data, wells currently drilling and related capitalized interest are initially excluded from the amortization base. Leasehold costs are either transferred to the amortization base with the costs of drilling a well on the lease or are assessed at least annually for possible impairment or reduction in value. The Company’s decision to withhold costs from amortization and the timing of the transfer of those costs into the amortization base involves a significant amount of judgment and may be subject to changes over time based on several factors, including drilling plans, availability of capital, project economics and drilling results from adjacent acreage. At December 31, 2016, the Company had a total of $2,105 million of costs excluded from the amortization base, all of which related to its properties in the United States. Inclusion of some or all of these costs in the Company’s United States properties in the future, without adding any associated reserves, could result in additional ceiling test impairments. In the first, second, and third quarters of 2016, the Company’s net book value of its United States and Canada natural gas and oil properties exceeded the ceiling by approximately $641 million (net of tax) at March 31, 2016, $297 million (net of tax) at June 30, 2016 and $506 million (net of tax) at September 30, 2016, resulting in non-cash ceiling test impairments in each of those quarters. Using the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas o f $2.48 per MMBtu, West Texas Intermediate oil of $39.25 per barrel and NGLs of $6.74 per barrel , adjusted for market differentials, the Company’s net book value of its United States natural gas and oil properties did not exceed the ceiling amount and did not result in a ceiling test impairment at December 31, 2016 . The Company had no derivative positions that were designated for hedge accounting as of December 31, 2016 . In the second and third quarters of 2015, the net book value of the Company’s United States natural gas and oil properties exceeded the ceiling by $944 million (net of tax) at June 30, 2015 and $1,746 million (net of tax) at September 30, 2015 and resulted in non-cash ceiling test impairments. Cash flow hedges of natural gas production in place increased the ceiling amount by approximately $60 million and $40 million as of June 30, 2015 and September 30, 2015, respectively. Using the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $ 2.59 per MMBtu , West Texas Intermediate oil of $ 46.79 per barrel and NGLs of $ 6.82 per barrel , adjusted for market differentials, the Company’s net book value of its United States natural gas and oil properties exceeded the ceiling by $1,586 million (net of tax) at December 31, 2015 and resulted in a non-cash ceiling test impairment . The Company had no derivative positions that were designated for hedge accounting as of December 31, 2015. At December 31, 201 4 , the ceiling value of the Company’s reserves was calculated based upon the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $ 4.35 per MMBtu , for West Texas Intermediate oil of $ 91.48 per barrel and NGLs of $23.79 per barrel , ad justed for market differentials. The Company’s net book value of its natural gas and oil properties did not exceed the ceiling amount and did not result in a ceiling test impairment at December 31, 2014. Gathering Systems . The Company’s investment in gathering systems is primarily in a system serving its Fayetteville Shale operations in Arkansas . These assets are being depreciated on a straight-line basis ove r 25 ye ars. Capitalized Interest. Interest is capitalized on the cost of unevaluated natural gas and oil properties that are excluded from amortization and are actively being evaluated. Asset Retirement Obligations . The Company owns natural gas and oil properties , which require expenditures to plug and abandon the wells and reclaim the associated pads when the wells are no longer producing . An asset retirement obligation associated with the retirement of a tangible long-lived asset is recognized as a liability in the period incurred or when it becomes determinable, with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the asset retirement cost, is depreciated over the useful life of the asset. The asset retirement obligation is recorded at its estimated fair value , and accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. Impairment of long-lived assets. The carrying value of non-full cost pool long-lived assets is evaluated for recoverability whenever events or changes in circumstances indicate that it may not be recoverable. I ntangible assets . The carrying value of intangible assets are evaluated for recoverability whenever events or changes in circumstances indicate that it may not be recoverable. Intangible assets are amortized over their useful life. |
Income Taxes | Income Taxes The Company follows the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recorded for the estimated future tax consequences attributable to the differences between the financial carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using the tax rate expected to be in effect for the year in which those temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the year of the enacted rate change. Deferred income taxes are provided to recognize the income tax effect of reporting certain transactions in different years for income tax and financial reporting purposes. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized. The Company accounts for uncertainty in income taxes using a recognition and measurement threshold for tax positions taken or expected to be taken in a tax return. The tax benefit from an uncertain tax position is recognized when it is more likely than not that the position will be sustained upon examination by taxing authorities based on technical merits of the position. The amount of the tax benefit recognized is the largest amount of the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. The effective tax rate and the tax basis of assets and liabilities reflect management’s estimates of the ultimate outcome of various tax uncertainties. The Company recognizes penalties and interest related to uncertain tax positions within the provision (benefit) for income taxes line in the accompanying consolidated statements of operations. Additional information regarding uncertain tax positions can be found in Note 9 – Income Taxes . |
Derivative Financial Instruments | Derivative Financial Instruments The Company uses derivative financial instruments to manage defined commodity price risks and does not use them for speculative trading purposes. The Company uses fixed price swap agreements and options to financially protect sales of natural gas. Gains and losses result ing from the settlement of derivative contracts have been recognized in gas sales if designated for hedge accounting treatment or gain (loss) on derivative s if not designated for hedge accounting treatment in the consolidated statements of operations when the contracts expire and the related physical transactions of the commodity hedged are recognized. Changes in the fair value of derivative instruments designated as cash flow hedges and not settled are included in other comprehensive income (loss) to the extent that they are effective in offsetting the changes in the cash flows of the hedged item. In contrast, gains and losses from the ineffective portion of derivative contracts designated for hedge accounting trea tment are recognized currently and have an inconsequential impact in the consolidated statement of operations . Gains and losses from the unsettled portion of derivative contracts not designated for hedge accounting treatment are recognized in gain (loss) on derivatives in the consolidated statement of operations. See Note 4 – Derivatives and Risk Management and Note 6 – Fair Value Measurements for a discussion of the Company’s hedging activities. |
Earnings Per Share | Earnings Per Share Basic earnings per common share is computed by dividing net income (loss) attributable to common stock by the weighted average number of common sha res outstanding during the reportable period . Th e diluted earnings per share calculation adds to the weighted average number of common shares outstanding : the incremental shares that would have been outstanding assuming the exe rcise of dilutive stock options, the vesting of unvested res tricted shares of common stock, performance units, the assumed conversion of mandatory convertible preferred stock and the shares of common stock declared as a preferred stock dividend. An antidilutive impact is an increase in earnings per share or a reduction in net loss per share resulting from the conversion, exercise, or contingent issuance of certain securities. In July 2016, the Company completed an underwritten public offering of 98,900,000 shares of its common stock, with an offering price to the public of $13.00 per share. Net proceeds from the common stock offering were approximately $1,247 million, after underwriting discount and offering expenses. The proceeds from the offering were used to repay $375 million of the $750 million term loan entered into in November 2015 and to settle certain tender offers by purchasing an aggregate principal amount of approximately $700 million of the Company’s outstanding senior notes due in the first quarter of 2018. The remaining proceeds of the offering have been or will be used for general corporate purposes. In January 2015, the Company completed concurrent underwritten public offerings of 30,000,000 shares of its common stock and 34,500,000 depositary shares (both share counts include shares issued as a result of the underwriters exercising their options to purchase additional shares). The common stock offering was priced at $23.00 per share. Net proceeds from the common stock offering were approximately $669 million, after underwriting discount and offering expenses. Net proceeds from the depositary share offering were approximately $1.7 billion, after underwriting discount and offering expenses. Each depositary share represents a 1/20th interest in a share of the Company’s mandatory convertible preferred stock, with a liquidation preference of $1,000 per share (equivalent to a $50 liquidation preference per depositary share). The proceeds from the offerings were used to partially repay borrowings under the Company’s $4.5 billion 364 -day bridge facility with the remaining balance of the bridge facility fully repaid with proceeds from the Company’s January 2015 public offering of $2.2 billion in long-term senior notes. The mandatory convertible preferred stock entitles the holder to a proportional fractional interest in the rights and preferences of the convertible preferred stock, including conversion, dividend, liquidation and voting rights. Unless converted earlier at the option of the holders, on or around January 15, 2018 each share of convertible preferred stock will automatically convert into between 37.0028 and 43.4782 shares of the Company’s common stock (correspondingly, each depositary share will convert into between 1.85014 and 2.17391 shares of the Company’s common stock), subject to customary anti-dilution adjustments, depending on the volume-weighted average price of the Company’s common stock over a 20 trading day averaging period immediately prior to that date. The total potential shares of common stock resulting from the conversion will range from 63,829,830 to 74,999,895 shares. The mandatory convertible preferred stock has the non-forfeitable right to participate on an as-converted basis at the conversion rate then in effect in any common stock dividends declared and as such, is considered a participating security. Accordingly, it is included in the computation of basic and diluted earnings per share, pursuant to the two-class method. In the calculation of basic earnings per share attributable to common shareholders, participating securities are allocated earnings based on actual dividend distributions received plus a proportionate share of undistributed net income attributable to common shareholders, if any, after recognizing distributed earnings. The Company’s participating securities do not participate in undistributed net losses because they are not contractually obligated to do so. On December 12, 2016 , the Company declared its quarterly dividend, payable to holders of the mandatory convertible preferred stock, and announced that it would pay the quarterly dividend in stock, in lieu of cash, to the extent permitted by the certificate of designations for the Series B preferred stock. The Company issued 2,751,410 shares of common stock on January 17, 2017 in payment for the dividend. Dividends declared in the first, second and third quarters of 2016 also were settled in common stock for a total of 7,166,389 shares, while the dividend declared in December 2015 was paid in cash in January 2016. The following table presents the computation of earnings per share for the years ended December 31, 2016, 2015 and 2014: For the years ended December 31, 2016 2015 2014 (in millions, except share/per share amounts) Net income (loss) $ (2,643) $ (4,556) $ 924 Mandatory convertible preferred stock dividend 108 106 – Net income (loss) attributable to common stock $ (2,751) $ (4,662) $ 924 Number of common shares: Weighted average outstanding 435,337,402 380,521,039 351,446,747 Issued upon assumed exercise of outstanding stock options – – 241,603 Effect of issuance of non-vested restricted common stock – – 448,415 Effect of issuance of non-vested performance units – – 273,918 Effect of issuance of mandatory convertible preferred stock – – – Effect of declaration of preferred stock dividends – – – Weighted average and potential dilutive outstanding 435,337,402 380,521,039 352,410,683 Earnings (loss) per common share: Basic $ (6.32) $ (12.25) $ 2.63 Diluted $ (6.32) $ (12.25) $ 2.62 The following table presents the common stock shares equivalent excluded from the calculation of diluted earnings per share for the years ended December 31, 2016, 2015 and 2014 , as they would have had an antidilutive effect: For the years ended December 31, 2016 2015 2014 Unvested stock options 3,692,697 3,835,234 1,446,004 Unvested share-based payment 959,233 1,990,383 29,879 Performance units 884,644 140,414 – Mandatory convertible preferred stock 74,999,895 70,890,312 – Declared and unpaid preferred stock dividends 2,751,410 – – Total 83,287,879 76,856,343 1,475,883 |
Supplemental Disclosures Of Cash Flow Information | Supplemental Disclosures of Cash Flow Information The following table provides additional information concerning interest and income taxes paid as well as changes in noncash investing activities for the years ended December 31, 2016, 2015, and 2014: For the years ended December 31, 201 6 201 5 201 4 (in millions) Cash paid during the year for interest, net of amounts capitalized $ 75 $ 6 $ 50 Cash paid (received) during the year for income taxes (15) (6) 28 Increase (decrease) in noncash property additions 55 (10) 174 |
Stock-Based Compensation | Stock-Based Compensation The Company accounts for stock-based compensation transactions using a fair value method and recognizes an amount equal to the fair value of the stock options and stock-based payment cost in either the consolidated statement of operations or capitalizes the cost into natural gas and oil properties or gathering systems included in property and equipment. Costs are capitalized when they are directly related to the acquisition, exploration and development activities of the Company’s natural gas and oil properties or directly related to the construction of the Company’s gathering systems. |
Treasury Stock | Treasury Stock The Company maintains a non-qualified deferred compensation supplemental retirement savings plan for certain key employees whereby participants may elect to defer and contribute a portion of their compensation to a Rabbi Trust, as permitted by the plan. The Company includes the assets and liabilit ies of its supplemental retirement savings plan in its consolidated balance sheet. Shares of the Company’s common stock purchased under the non-qualified deferred compensation arrangement are held in the Rabbi Trust , are presented as treasury stock and are carried at cost. As of December 31, 201 6 , 31,269 shares were accounted for as treasury stock, compared to 47,149 shares at December 31, 2015 . |
Foreign Currency Translation | Foreign Currency Translation The Company has designated the Canadian dollar as the functional currency for our activities in Canada. The cumulative translation effects of translating the accounts from the functional currency into the U.S. dollar at current exchange rates are included as a separate component of other comprehensive income within stockholders ’ equity. |
New Accounting Standards Implemented In This Report | New Accounting Standards Implemented in this Report In September 2015, the FASB issued Accounting Standards Update No. 2015-16, Business Combinations (Topic 805) (“Update 2015-16”), which seeks to reduce the complexity of amounts recognized in a business combination. The amendments in Update 2015-16 require that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The amendments in Update 2015-16 require that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. The amendments in Update 2015-16 require an entity to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. The amendments in Update 2015-16 are effective for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years. The Company adopted this update in the first quarter of 2016 resulting in no impact on its consolidated results of operations, financial position and cash flows. In May 2015, the FASB issued Accounting Standards Update No. 2015-07, Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (Or Its Equivalent) (“Update 2015-07”), which amends ASC 820, Fair Value Measurement. The standard removes the requirement to categorize within the fair value hierarchy investments for which fair value is measured using the net asset value per share practical expedient and removes certain related disclosure requirements. The amendments in Update 2015-07 are effective for reporting periods beginning after December 15, 2015, with early adoption permitted. The Company adopted this update in the first quarter of 2016 resulting in no impact on its consolidated results of operations, financial position and cash flows. As a result of adoption, certain of the Company’s pension plan assets measured using net asset value as a practical expedient have not been classified in the fair value hierarchy in Note 11 – Retirement and Employee Benefit Plans. In April 2015, the FASB issued Accounting Standards Update No. 2015-03, Interest-Imputation of Interest (Subtopic 835-30) (“Update 2015-03”), in an effort to simplify presentation of debt issuance costs. Update 2015-03 required that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs was not affected by the amendments in this Update. Entities were required to apply the amendments in Update 2015-03 on a retrospective basis, with the balance sheet of each individual period presented adjusted to reflect the period-specific effects of applying the new guidance. In August 2015, the FASB issued Accounting Standards Update No. 2015-15, Interest-Imputation of Interest (Subtopic 835-30) (“Update 2015-15”), which addresse d the presentation or subsequent measurement of debt issuance costs related to line-of-credit arrangements, given the absence of authoritative guidance within Update 2015-03 for debt issuance costs related to line-of-credit arrangements. For public entities, Update 2015-03 and Update 2015-15 are effective for annual reporting periods beginning after December 15, 2015, including interim periods within that reporting period. The Company adopted this update in the first quarter of 2016 resulting in an immaterial impact on its consolidated financial positi on. The Company had $24 million in unamortized debt expense that was classified as a long-term asset at December 31, 2015, which is now presented as a contra-liability as a result of adoption. In November 2014, the FASB issued Accounting Standards Update No. 2014-16, Derivatives and Hedging – Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share Is More Akin to Debt or to Equity (Subtopic 815-15) (“Update 2014-16”), which addressed diversity in practice related to the determination of whether derivative features embedded in hybrid instruments issued in the form of a share should be bifurcated and accounted for separately. For public entities, Update 2014-16 was effective for annual reporting periods beginning after December 15, 2015 including interim periods within that reporting period. The Company adopted this update in the first quarter of 2016 resulting in no impact on its consolidated results of operations, financial position and cash flows. In August 2014, the FASB issued Accounting Standards Update No. 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (Subtopic 205 - 40 ) (“Update 2014-1 5 ”), which requires management to assess a company’s ability to continue as a going concern and to provide related footnote disclosures in certain circumstances. For public entities, Update 2014-1 5 wa s effective for annual reporting periods ending after December 15, 201 6 . The Company adopted this update in the first quarter of 2016 resulting in no impact on its consolidated results of operations, financial position , cash flows and disclosures. |
New Accounting Standards Not Yet Implemented In This Report | New Accounting Standards Not Yet Implemented in this Report In August 2016, the FASB issued Accounting Standards Update No. 2016-15, Statement of Cash Flows (Topic 230) (“Update 2016-15”), which seeks to reduce the existing diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. For public entities, Update 2016-15 becomes effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, with early adoption permitted. The Company is currently evaluating the provisions of Update 2016-15 and assessing the impact, if any, it may have on its consolidated results of operations, financial position or cash flows. In March 2016, the FASB issued Accounting Standards Update No. 2016-09, Compensation – Stock Compensation (Topic 718) (“Update 2016-09”), which seeks to simplify accounting for share-based payment transactions including income tax consequences, classification of awards as either equity or liabilities, and the classification on the statement of cash flows. For public entities, Update 2016-09 becomes effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years, with early adoption permitted. The Company expects to adopt this guidance effective January 1, 2017. The recognition of previously unrecognized windfall tax benefits is expected to result in a cumulative-effect adjustment of approximately $149 million, which would increase net deferred tax assets and increase the valuation allowance by the same amount as of the beginning of 2017. The remaining provisions of this amendment are not expected to have a material effect on the consolidated results of operations, financial position or cash flows. In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (Topic 842) (“Update 2016-02”), which seeks to increase transparency and comparability among organizations by, among other things, recognizing lease assets and lease liabilities on the balance sheet for leases classified as operating leases under previous GAAP and disclosing key information about leasing arrangements. In 2016, the Company made progress on contract reviews, drafting its accounting policies and evaluating the new disclosure requirements. The Company will continue assessing the effect that the updated standard may have on its consolidated financial statements and related disclosures, and anticipates that its assessment will be complete in 2018. For public entities, Update 2016-02 becomes effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, with early adoption permitted. In May 2014, the FASB issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“Update 2014-09”), which seeks to provide clarity for recognizing revenue. The new standard removes inconsistencies in existing standards, changes the way companies recognize revenu e from contracts with customers and increases disclosure requirements. The codification was amended through additional ASUs and, as amended, requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitle d to in exchange for those goods or services. The standard is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet. The Company has not yet selected a transition method. The Company has a team in place to analyze the impact of Update 2014-09, and the related ASU's, across all revenue streams to evaluate the impact of the new standard on revenue contracts. This includes reviewing current accounting policies and practices to identify potential differences that would result from applying the requirements under the new standard. In 2016, the Company made progress on contract reviews, drafting its accounting policies and evaluating the new disclosure requirements. The Company expects to complete its evaluations of the impacts of the accounting and disclosure requirements on its business processes, controls and systems in the second half of 2017. For public entities, the new standard is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. |
Organization And Summary Of S27
Organization And Summary Of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Organization And Summary Of Significant Accounting Policies [Abstract] | |
Summary Of Cash And Cash Equivalents | For the years ended December 31, 2016 2015 (in millions) Cash $ 254 $ 15 Marketable Securities (1) 1,169 – Total $ 1,423 $ 15 (1) Consists of government stable value money market funds . |
Schedule Of Earnings Per Share | For the years ended December 31, 2016 2015 2014 (in millions, except share/per share amounts) Net income (loss) $ (2,643) $ (4,556) $ 924 Mandatory convertible preferred stock dividend 108 106 – Net income (loss) attributable to common stock $ (2,751) $ (4,662) $ 924 Number of common shares: Weighted average outstanding 435,337,402 380,521,039 351,446,747 Issued upon assumed exercise of outstanding stock options – – 241,603 Effect of issuance of non-vested restricted common stock – – 448,415 Effect of issuance of non-vested performance units – – 273,918 Effect of issuance of mandatory convertible preferred stock – – – Effect of declaration of preferred stock dividends – – – Weighted average and potential dilutive outstanding 435,337,402 380,521,039 352,410,683 Earnings (loss) per common share: Basic $ (6.32) $ (12.25) $ 2.63 Diluted $ (6.32) $ (12.25) $ 2.62 |
Schedule Of Antidilutive Securities Excluded From Computation Of Earnings Per Share | For the years ended December 31, 2016 2015 2014 Unvested stock options 3,692,697 3,835,234 1,446,004 Unvested share-based payment 959,233 1,990,383 29,879 Performance units 884,644 140,414 – Mandatory convertible preferred stock 74,999,895 70,890,312 – Declared and unpaid preferred stock dividends 2,751,410 – – Total 83,287,879 76,856,343 1,475,883 |
Schedule Of Supplemental Disclosures Of Cash Flow Information | For the years ended December 31, 201 6 201 5 201 4 (in millions) Cash paid during the year for interest, net of amounts capitalized $ 75 $ 6 $ 50 Cash paid (received) during the year for income taxes (15) (6) 28 Increase (decrease) in noncash property additions 55 (10) 174 |
Reduction In Workforce (Tables)
Reduction In Workforce (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Reduction In Workforce [Abstract] | |
Summary Of Restructuring Charges | (in millions) Severance (including payroll taxes) $ 44 Stock-based compensation 24 Pension and other post retirement benefits (1) 5 Other benefits 3 Outplacement services, other 2 Total restructuring charges (2) $ 78 (1) Includes non-cash charges related to the curtailment and settlement of the pension and other postretirement benefit plans. See Note 12 for additional details regarding the Company’s retirement and employee benefit plans. (2) Total restructuring charges were $75 million and $3 million for the Company’s E&P and Midstream Services segments, respectively. |
Summary Of Liabilities Associated With Restructuring Activities | (in millions) Liability at December 31, 2015 $ – Additions 49 Distributions (48) Liability at December 31, 2016 $ 1 |
Acquisitions And Divestitures (
Acquisitions And Divestitures (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
WPX Property Acquisition [Member] | |
Business Acquisition [Line Items] | |
Summary Of Consideration Paid And Fair Value Of Assets Acquired And Liabilities Assumed | (in millions) Consideration: Cash $ 270 Recognized amounts of identifiable assets acquired and liabilities assumed: Assets acquired: Proved natural gas and oil properties 31 Unproved natural gas and oil properties 114 Intangible asset 109 Gathering system 22 Other 1 Total assets acquired 277 Liabilities assumed: Asset retirement obligations (7) Total liabilities assumed (7) $ 270 |
Chesapeake Property Acquisition [Member] | |
Business Acquisition [Line Items] | |
Summary Of Consideration Paid And Fair Value Of Assets Acquired And Liabilities Assumed | (in (( (in millions) Consideration: Cash $ 4,949 Recognized amounts of identifiable assets acquired and liabilities assumed: Assets acquired: Proved natural gas and oil properties 1,418 Unproved natural gas and oil properties 3,573 Other property and equipment 33 Inventory 3 Total assets acquired 5,027 Liabilities assumed: Asset retirement obligations (42) Other liabilities (36) Total liabilities assumed (78) $ 4,949 |
Summary Of Consolidated Results Of Operations On Pro Forma Basis | For the years ended December 31, 2014 2013 (unaudited) Revenues (in millions) $ 4,439 $ 3,713 Net Income attributable to common stock (in millions) 803 594 Earnings per share: Basic $ 2.11 $ 1.56 Diluted 2.10 1.56 |
Derivatives And Risk Manageme30
Derivatives And Risk Management (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Derivatives And Risk Management [Abstract] | |
Schedule Of Derivative Instruments, Notional Amount In BCF, Weighted Average Contract Prices And Fair Value | Weighted Average Price per MMBtu Volume (Bcf) Swaps Sold Puts Purchased Puts Sold Calls Basis Differential Fai r value at December 31, 2016 ( in millions) Financial protection on production 2017 Fixed price swaps 322 $ 3.07 $ – $ – $ – $ – $ (175) Two-way costless collars 103 – – 2.94 3.38 – (42) Three-way costless collars 135 – 2.29 2.97 3.30 – (59) Basis swaps 132 – – – – (0.87) 19 Total 692 $ (257) 2018 Fixed price swaps 18 $ 3.00 $ – $ – $ – $ – $ (2) Two-way costless collars 14 – – 3.00 3.46 – (6) Three-way costless collars 208 – 2.37 2.96 3.37 – (20) Basis swaps 16 – – – – (0.94) (4) Total 256 $ (32) 2019 Three-way costless collars 62 $ – $ 2.50 $ 2.92 $ 3.35 $ – $ (2) Total 62 $ (2) Sold call options 2017 86 $ – $ – $ – $ 3.25 $ – $ (46) 2018 63 – – – 3.50 – (18) 2019 52 – – – 3.50 – (11) 2020 32 – – – 3.75 – (6) Total 233 $ (81) |
Balance Sheet Classification Of Derivative Financial Instruments | Derivative Assets Balance Sheet Classification Fair Value December 31, 2016 December 31, 2015 (in millions) Derivatives not designated as hedging instruments: Two-way costless collars Derivative assets $ 8 $ – Three-way costless collars Derivative assets 11 – Basis swaps Derivative assets 32 3 Fixed price swaps Other long-term assets 1 – Two-way costless collars Other long-term assets 2 – Three-way costless collars Other long-term assets 100 – Basis swaps Other long-term assets 1 – Total derivative assets $ 155 $ 3 Derivative Liabilities Balance Sheet Classification Fair Value December 31, 2016 December 31, 2015 (in millions) Derivatives not designated as hedging instruments: Fixed price swaps Derivative liabilities $ 175 – Two-way costless collars Derivative liabilities 49 – Three-way costless collars Derivative liabilities 70 – Basis swaps Derivative liabilities 13 – Sold call options Derivative liabilities 46 – Interest rate swaps Derivative liabilities 2 3 Fixed price swaps Other long-term liabilities 3 – Two-way costless collars Other long-term liabilities 9 – Three-way costless collars Other long-term liabilities 122 – Basis swaps Other long-term liabilities 5 – Sold call options Other long-term liabilities 35 – Interest rate swaps Other long-term liabilities 1 2 Total derivative liabilities $ 530 $ 5 |
Summary Of Before Tax Effect Of Fair Value Hedges Not Designated For Hedge Accounting | Gain (Loss) on Derivatives, Unsettled Recognized in Earnings Consolidated Statement of Operations For the years ended Classification of Gain (Loss) December 31, Derivative Instrument on Derivatives, Unsettled 2016 2015 (in millions) Fixed price swaps Gain (Loss) on Derivatives $ (177) $ (164) Two-way costless collars Gain (Loss) on Derivatives (48) – Three-way costless collars Gain (Loss) on Derivatives (81) – Basis swaps Gain (Loss) on Derivatives 12 (2) Sold call options Gain (Loss) on Derivatives (81) 13 Interest rate swaps Gain (Loss) on Derivatives 2 (2) Total loss on unsettled derivatives $ (373) $ (155) Gain (Loss) on Derivatives, Settled (1) Recognized in Earnings Consolidated Statement of Operations For the years ended Classification of Gain (Loss) December 31, Derivative Instrument on Derivatives, Settled 2016 2015 (in millions) Fixed price swaps Gain (Loss) on Derivatives $ – $ 208 Purchased put options Gain (Loss) on Derivatives 11 – Two-way costless collars Gain (Loss) on Derivatives 3 – Three-way costless collars Gain (Loss) on Derivatives 1 – Basis swaps Gain (Loss) on Derivatives 21 (2) Interest rate swaps Gain (Loss) on Derivatives (2) (4) Total gain on settled derivatives (2) $ 34 $ 202 Total gain (loss) on derivatives $ (339) $ 47 (1) The Company calculates gain (loss) on derivatives, settled, as the summation of gains and losses on positions that have settled within the period. (2) Excluding interest rate swaps, these amounts are included, along with gas sales revenues, in the calculation of the Company’s realized natural gas price. |
Reclassifications From Accumu31
Reclassifications From Accumulated Other Comprehensive Income (Loss) (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Reclassifications From Accumulated Other Comprehensive Income (Loss) [Abstract] | |
Components Of Accumulated Other Comprehensive Income (Loss) | For the year ended December 31, 2016 Pension and Other Postretirement Foreign Currency Total (in millions) Beginning balance, December 31, 2015 $ (25) $ (23) $ (48) Other comprehensive income (loss) before reclassifications (7) 3 (4) Amounts reclassified from other comprehensive income (loss) (2) 13 – 13 Net current-period other comprehensive income (loss) 6 3 9 Ending balance, December 31, 2016 $ (19) $ (20) $ (39) (1) See separate table below for details about these reclassifications. |
Amounts Reclassified From Accumulated Other Comprehensive Income (Loss) | Details about Accumulated Other Comprehensive Income Affected Line Item in the Consolidated Statement of Operations Amount Reclassified from Accumulated Other Comprehensive Income For the year ended December 31, 2016 (in millions) Pension and other postretirement: Amortization of prior service cost and net loss (1) General and administrative expenses $ 21 Provision (benefit) for income taxes 8 Net income (loss) $ 13 Total reclassifications for the period Net income (loss) $ 13 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Fair Value Measurements [Abstract] | |
Carrying Amount And Estimated Fair Values Of Financial Instruments | December 31, 2016 December 31, 2015 Carrying Fair Carrying Fair Amount Value Amount Value (in millions) Cash and cash equivalents $ 1,423 $ 1,423 $ 15 $ 15 Credit facility – – 116 116 Term loan facility due December 2020 (1) 327 327 750 750 Term loan facility due December 2020 (1) 1,191 1,191 – – Senior notes 3,166 3,182 3,867 2,672 Derivative instruments, net (375) (375) (2) (2) (1) The maturity date will accelerate to October 2019 if, by that date, the Company has not amended, redeemed or refinanced at least $765 million of its senior notes due in January 2020 . |
Summary Of Assets And Liabilities Measured At Fair Value On Recurring Basis | December 31, 2016 Fair Value Measurements Using: Quoted Prices Significant in Active Significant Other Unobservable Markets Observable Inputs Inputs Assets (Liabilities) (Level 1) (Level 2) (Level 3) at Fair Value Fixed price swap assets $ – $ 1 $ – $ 1 Two-way costless collars assets – – 10 10 Three-way costless collars assets – – 111 111 Basis swap assets – – 33 33 Fixed price swap liabilities – (178) – (178) Two-way costless collars liabilities – – (58) (58) Three-way costless collars liabilities – – (192) (192) Basis swap liabilities – – (18) (18) Sold call option liabilities – – (81) (81) Interest rate swap liabilities – (3) – (3) Total $ – $ (180) $ (195) $ (375) December 31, 2015 Fair Value Measurements Using: Quoted Prices Significant Other Significant in Active Markets Observable Inputs Unobservable Inputs Assets (Liabilities) (Level 1) (Level 2) (Level 3) at Fair Value Basis swap assets $ – $ – $ 3 $ 3 Interest rate swap liabilities – (5) – (5) Total $ – $ (5) $ 3 $ (2) |
Reconciliations For Change In Net Fair Value Of Derivative Assets And Liabilities Measured At Fair Value On A Recurring Basis Using Significant Unobservable Inputs (Level 3) | For the years ended December 31, 2016 2015 (in millions) Balance at beginning of period $ 3 $ (8) Total gains (losses): Included in earnings (162) 9 Settlements (36) 2 Transfers into/out of Level 3 – – Balance at end of period $ (195) $ 3 Change in gains (losses) included in earnings relating to derivatives still held as of December 31 $ (198) $ 11 |
Debt (Tables)
Debt (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Debt [Abstract] | |
Components Of Debt | December 31, 2016 Debt Instrument Unamortized Issuance Cost Unamortized Debt Discount Total (in millions) Short-term debt: 7.35% Senior Notes due October 2017 $ 15 $ – $ – $ 15 7.125% Senior Notes due October 2017 25 – – 25 7.15% Senior Notes due June 2018 1 – – 1 Total short-term debt $ 41 $ – $ – $ 41 Long-term debt: Variable rate ( 3.220% at December 31, 2016) term loan facility, due December 2020 (1) 327 (2) – 325 Variable rate ( 3.220% at December 31, 2016) term loan facility, due December 2020 (2) 1,191 (10) – 1,181 3.30% Senior Notes due January 2018 (3) (4) 38 – – 38 7.50% Senior Notes due February 2018 (3) 212 – – 212 7.15% Senior Notes due June 2018 25 – – 25 4.05% Senior Notes due January 2020 (4) 850 (5) – 845 4.10% Senior Notes due March 2022 1,000 (4) (1) 995 4.95% Senior Notes due January 2025 (4) 1,000 (7) (2) 991 Total long-term debt $ 4,643 $ (28) $ (3) $ 4,612 Total debt $ 4,684 $ (28) $ (3) $ 4,653 (1) In July 2016, $375 million was repaid on the term loan facility, extending the maturity from November 2018 to December 2020, which will accelerate to October 2019 if, by that date, the Company has not amended, redeemed or refinanced at least $765 million of its senior notes due in January 2020 . In September 2016, an additional $48 million was repaid. (2) The maturity date will accelerate to October 2019 if, by that date, the Company has not amended, redeemed or refinanced at least $765 million of its senior notes due in January 2020. (3) In July 2016, the Company purchased approximately $312 million of the 3.30% Senior Notes due January 2018 and $388 million of the 7.50% Senior Notes due February 2018. (4) In February and June 2016, Moody’s and S&P downgraded certain senior notes, increasing the interest rates by 175 basis points effective July 2016. As a result of the downgrades, interest rates increased to 5.05% for the 2018 Notes, 5.80% for the 2020 Notes and 6.70% for the 2025 Notes. December 31, 2015 Debt Instrument Unamortized Issuance Cost Unamortized Debt Discount Total (in millions) Short-term debt: 7.15% Senior Notes due June 2018 $ 1 $ – $ – $ 1 Total short-term debt $ 1 $ – $ – $ 1 Long-term debt: Variable rate ( 1.886% at December 31, 2015) credit facility, expires December 2018 116 – – 116 Variable rate ( 1.775% at December 31, 2015) term loan facility, due November 2018 750 (3) – 747 7.35% Senior Notes due October 2017 15 – – 15 7.125% Senior Notes due October 2017 25 – – 25 3.30% Senior Notes due January 2018 350 (2) – 348 7.50% Senior Notes due February 2018 600 (2) – 598 7.15% Senior Notes due June 2018 26 – – 26 4.05% Senior Notes due January 2020 850 (5) (1) 844 4.10% Senior Notes due March 2022 1,000 (5) (1) 994 4.95% Senior Notes due January 2025 1,000 (7) (2) 991 Total long-term debt $ 4,732 $ (24) $ (4) $ 4,704 Total debt $ 4,733 $ (24) $ (4) $ 4,705 |
Schedule Of Long Term Debt Maturities | 2017 $ 41 20 18 275 2019 – 2020 2,368 2021 – Thereafter 2,000 $ 4,684 |
Commitments And Contingencies (
Commitments And Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Commitments And Contingencies [Abstract] | |
Schedule Of Future Obligation Under Transportation Agreements | Payments Due by Period Total Less than 1 Year 1 to 3 Years 3 to 5 Years 5 to 8 years More than 8 Years (in millions) Infrastructure Currently in Service $ 5,067 $ 612 $ 1,158 $ 825 $ 829 $ 1,643 Pending Regulatory Approval and/or Construction (1) 3,362 15 326 450 678 1,893 Total Transportation Charges $ 8,429 $ 627 $ 1,484 $ 1,275 $ 1,507 $ 3,536 (1) Based on the estimated in-service dates as of December 31, 2016. |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Income Taxes [Abstract] | |
Provision (Benefit) For Income Taxes | 2016 2015 2014 (in millions) Current: Federal $ (6) $ 1 $ 11 State (1) (3) 10 (7) (2) 21 Deferred: Federal (22) (1,697) 501 State – (304) 2 Foreign – (2) 1 (22) (2,003) 504 Provision (benefit) for income taxes $ (29) $ (2,005) $ 525 |
Reconciliation Of Provision For Income Taxes | 2016 2015 2014 (in millions) Expected provision (benefit) at federal statutory rate $ (935) $ (2,296) $ 507 Increase (decrease) resulting from: State income taxes, net of federal income tax effect (79) (194) 58 Nondeductible expenses – – 3 State rate redetermination – – (48) Change in uncertain tax positions (19) (7) – Change in valuation allowance 1,002 495 5 Other 2 (3) – Provision (benefit) for income taxes $ (29) $ (2,005) $ 525 |
Components Of Deferred Tax Balances | 2016 2015 (in millions) Deferred tax liabilities: Differences between book and tax basis of property $ 81 $ 216 Other 1 2 82 218 Deferred tax assets: Accrued compensation 38 19 Alternative minimum tax credit carryforward 100 125 Accrued pension costs 19 19 Asset retirement obligations 53 77 Net operating loss carryforward 1,177 445 Derivative activity 142 – Other 29 26 1,558 711 Valuation allowance (1,476) (493) Net deferred tax liability $ – $ – |
Reconciliation Of Beginning And Ending Balances Of Unrecognized Tax Benefits | 2016 2015 (in millions) Unrecognized tax benefits at beginning of period $ 37 $ 44 Additions based on tax positions related to the current year – 7 Additions to tax positions of prior years – – Reductions to tax positions of prior years (20) (14) Unrecognized tax benefits at end of period $ 17 $ 37 |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Asset Retirement Obligations [Abstract] | |
Schedule Of Asset Retirement Obligations | 2016 2015 (in millions) Asset retirement obligation at January 1 $ 201 $ 207 Accretion of discount 10 11 Obligations incurred 1 17 Obligations settled/removed (1) (45) (30) Revisions of estimates (2) (26) (4) Asset retirement obligation at December 31 $ 141 $ 201 Current liability 6 10 Long-term liability 135 191 Asset retirement obligation at December 31 $ 141 $ 201 (1) Obligations settled/removed include $35 million and $25 million related to asset divestitures in 2016 and 2015, respectively. (2) Estimates in the costs to retire wells and well pads were revised downward based on internal estimates of future obligation requirements and updated third-party cost quotes. |
Retirement And Employee Benef37
Retirement And Employee Benefit Plans (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Retirement And Employee Benefit Plans [Abstract] | |
Changes In Plans Benefit Obligations, Fair Value Of Assets, And Funded Status | Other Postretirement Pension Benefits Benefits 2016 2015 2016 2015 (in millions) Change in benefit obligations: Benefit obligation at January 1 $ 138 $ 134 $ 20 $ 18 Service cost 11 16 2 3 Interest cost 5 6 1 1 Participant contributions – – – – Actuarial loss (gain) 14 (7) (2) (2) Benefits paid (3) (11) (1) – Plan amendments – – – – Curtailments (8) – (7) – Settlements (40) – – – Benefit obligation at December 31 $ 117 $ 138 $ 13 $ 20 Other Postretirement Pension Benefits Benefits 2016 2015 2016 2015 (in millions) Change in plan assets: Fair value of plan assets at January 1 $ 108 $ 108 $ – $ – Actual return on plan assets 3 (1) – – Employer contributions 10 12 1 – Participant contributions – – – – Benefits paid (3) (11) (1) – Settlements (37) – – – Fair value of plan assets at December 31 $ 81 $ 108 $ – $ – Funded status of plans at December 31 $ (36) $ (30) $ (13) $ (20) |
Projected Benefit Obligation, Accumulated Benefit Obligation, And Fair Value Of Plan Assets | 2016 2015 (in millions) Projected benefit obligation $ 117 $ 138 Accumulated benefit obligation 116 135 Fair value of plan assets 81 108 |
Pension And Other Postretirement Benefit Costs | Other Postretirement Pension Benefits Benefits 2016 2015 2014 2016 2015 2014 (in millions) Service cost $ 11 $ 16 $ 13 $ 2 $ 3 $ 2 Interest cost 5 6 5 1 1 1 Expected return on plan assets (6) (9) (7) – – – Amortization of transition obligation – – – – – – Amortization of prior service cost – – – – – – Amortization of net loss 2 2 1 – – – Net periodic benefit cost 12 15 12 3 4 3 Curtailment loss 1 – – (6) – – Settlement loss 11 – – – – – Total benefit cost (benefit) $ 24 $ 15 $ 12 $ (3) $ 4 $ 3 |
Amounts Recognized In Other Comprehensive Income | Pension Benefits Other Postretirement Benefits (in millions) Net actuarial (loss) gain arising during the year $ (13) $ 2 Amortization of prior service cost – – Amortization of net loss 20 – Settlements – 1 Tax effect (3) (1) $ 4 $ 2 |
Schedule Of Assumptions Used | The assumptions used in the measurement of the Company’s benefit obligations as of December 31, 2016 and 2015 are as follows: Pension Benefits Other Postretirement Benefits 2016 2015 2016 2015 Discount rate 4.20 % 4.60 % 4.20 % 4.60 % Rate of compensation increase 3.50 % 3.50 % n/a n/a % The assumptions used in the measurement of the Company’s net periodic benefit cost for 2016, 2015 and 2014 are as follows: Pension Benefits Other Postretirement Benefits 2016 2015 2014 2016 2015 2014 Discount rate 4.20 % 4.25 % 5.00 % 4.20 % 4.25 % 5.00 % Expected return on plan assets 7.00 % 7.00 % 7.00 % n/a n/a n/a Rate of compensation increase 3.50 % 4.50 % 4.50 % n/a n/a n/a |
Schedule Of Health Care Cost Trend Rates | 2016 2015 Health care cost trend assumed for next year 7% 8% Rate to which the cost trend is assumed to decline 5% 5% Year that the rate reaches the ultimate trend rate 2034 2034 |
One Percentage Point Change In Assumed Health Care Cost Trend Rates | 1% Increase 1% Decrease (in millions) Effect on the total service and interest cost components $ – $ – Effect on postretirement benefit obligations $ 2 $ (2) |
Schedule Of Expected Benefit Payments | Pension Benefits Other Postretirement Benefits (in millions) 2017 $ 8 2017 $ 1 2018 6 2018 1 2019 6 2019 1 2020 7 2020 1 2021 8 2021 1 Years 2022-2026 46 Years 2022-2026 6 |
Schedule Of Allocation Of Plan Assets | Pension Plan Asset Allocations Asset category: Target Actual Equity securities: U.S. Equity (1) 35 % 36 % Non-U.S. Developed Equity (2) 30 % 28 % Emerging Markets Equity (3) 5 % 6 % Opportunistic (4) – % – % Fixed income (5) 28 % 25 % Cash (6) 2 % 5 % Total 100 % 100 % (1) I ncludes the following equity securities in the table below: U.S. large cap growth equity, U.S. large cap value equity, U.S. large cap core equity, and U.S. small cap equity. (2) I ncludes Non-U.S. equity securities in the table below. (3) I ncludes e merging markets equity securities below. (4) I ncludes none of the securities in the table below. (5) I ncludes f ixed income pension plan assets in the table below. (6) I ncludes Cash and cash equivalents pension plan assets in the table below. |
Fair Value Measurement Of Pension Plan Assets | Total Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) (in millions) Measured within fair value hierarchy Equity securities: U.S. large cap growth equity (1) $ 6 $ 6 $ – $ – U.S. large cap value equity (2) 6 6 – – U.S. small cap equity (3) 3 3 – – Non-U.S. equity (4) 23 23 – – Emerging markets equity (5) 4 4 – – Fixed income ( 6 ) 21 21 – – Cash and cash equivalents 4 4 – – Total measured within fair value hierarchy $ 67 $ 67 $ – $ – Measured at net asset value (7) Equity securities: U.S. large cap core equity ( 8 ) 14 Total measured at net asset value $ 14 Total plan assets at fair value $ 81 (1) Mutual fund that seeks to invest in a diversified portfolio of stocks with price appreciation growth opportunities. (2) Mutual fund that seeks to invest in a diversified portfolio of stocks that will increase in value over the long-term as well as provide current income. (3) Mutual fund that seeks to invest in a diversified portfolio of stocks with small market capitalizations. (4) Mutual funds that invest primarily in equity securities of companies domiciled outside of the United States, primarily in developed markets. (5) An institutional fund that invests primarily in the equity securities of companies domiciled in emerging markets. (6) Institutional funds that seek an investment return that approximates, as closely as practicable, before expenses, the performance of the Barclays U.S. Intermediate Credit Bond Index over the long term and the Barclays Long U.S. Corporate Bond Index over the long-term . (7) Plan assets for which fair value was measured using net asset value as a practical expedient. (8) An institutional fund that seeks to replicate the performance of the S&P 500 Index before fees. Utilizing the fair value hierarchy described in Note 6 – Fair Value Measurements , the Company’s fair value measurement of pension plan assets at December 31, 201 5 is as follows: Total Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) (in millions) Measured within fair value hierarchy Equity securities: U.S. large cap growth equity (1) $ 9 $ 9 $ – $ – U.S. large cap value equity (2) 9 9 – – U.S. small cap equity (3) 3 3 – – Non-U.S. equity (4) 31 31 – – Emerging markets equity (5) 5 5 – – Cash and cash equivalents 2 2 – – Total measured within fair value hierarchy $ 59 $ 59 $ – $ – Measured at net asset value (6) Equity securities: U.S. large cap core equity (7) 18 Fixed income (8) 31 Total measured at net asset value $ 49 Total plan assets at fair value $ 108 (1) Mutual fund that seeks to invest in a diversified portfolio of stocks with price appreciation growth opportunities. (2) Mutual fund that seeks to invest in a diversified portfolio of stocks that will increase in value over the long-term as well as provide current income. (3) Mutual fund that seeks to invest in a diversified portfolio of stocks with small market capitalizations. (4) Mutual funds that invest primarily in equity securities of companies domiciled outside of the United States, primarily in developed markets. (5) An institutional fund that invests primarily in the equity securities of companies domiciled in emerging markets. (6) Plan assets for which fair value was measured using net asset value as a practical expedient. (7) An institutional fund that seeks to replicate the performance of the S&P 500 Index before fees. (8) An institutional fund that seeks an investment return that approximates, as closely as practicable, before expenses, the performance of the Barclays U.S. Intermediate Credit Bond Index over the long term and the Barclays Long U.S. Corporate Bond Index over the long-term. |
Stock-Based Compensation (Table
Stock-Based Compensation (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Disclosure of Compensation Related Costs, Share-based Payments [Line Items] | |
Schedule Of Valuation Assumptions | Assumptions 2016 2015 2014 Risk-free interest rate 1.4% 1.7% 1.6% Expected dividend yield – – – Expected volatility 41.0% 36.0% 32.5% Expected term 5 years 5 years 5 years |
Summary Of Stock Option Activity | 2016 2015 2014 Weighted Weighted Weighted Average Average Average Number Exercise Number Exercise Number Exercise of Shares Price of Shares Price of Shares Price (in thousands) (in thousands) (in thousands) Options outstanding at January 1 5,623 $ 24.57 3,622 $ 35.41 3,313 $ 35.70 Granted (1) 155 8.60 2,401 9.47 835 32.31 Exercised (45) 7.74 – – (402) 30.60 Forfeited or expired (317) 38.01 (400) 32.20 (124) 37.80 Options outstanding at December 31 5,416 $ 23.46 5,623 $ 24.57 3,622 $ 35.41 Shares granted in 2016 are considerably lower than historical norms. In 2016, the Company changed the grant date of its annual stock option awards from December to the following February. |
Summary Of Stock Options Outstanding And Options Exercisable | Options Outstanding Options Exercisable Weighted Weighted Options Weighted Average Options Weighted Average Outstanding at Average Remaining Aggregate Exercisable at Average Remaining Aggregate Range of December 31, Exercise Contractual Intrinsic December 31, Exercise Contractual Intrinsic Exercise Prices 2016 Price Life Value 2016 Price Life Value (in thousands) (years) ( in millions) (in thousands) (years) (in millions) $7.74 - $29.69 2,501 9.54 5.9 781 9.77 5.8 $30.59 - $35.91 1,384 32.32 3.9 1,146 32.68 3.7 $36.22 - $39.68 1,402 37.49 2.4 1,402 37.49 2.4 $40.15 - $51.47 129 45.79 3.3 99 45.57 3.0 5,416 $ 23.46 4.4 $ 7 3,428 $ 29.80 3.6 $ 2 |
Summary Of Restricted Stock Activity | 2016 2015 2014 Number of Shares Weighted Average Fair Value Number of Shares Weighted Average Fair Value Number of Shares Weighted Average Fair Value (in thousands) (in thousands) (in thousands) Unvested shares at January 1 7,222 $ 13.24 2,376 $ 34.00 1,771 $ 37.55 Granted (1) 81 8.56 5,822 8.07 1,295 30.89 Vested (2) (3,817) 11.34 (873) 33.33 (548) 37.12 Forfeited (165) 12.05 (103) 29.14 (142) 37.91 Unvested shares at December 31 3,321 $ 11.85 7,222 $ 13.24 2,376 $ 34.00 (1) Shares granted in 2016 are considerably lower than historical norms. In 2016, the Company changed the grant date of its annual restricted stock awards from December to the following February. (2) Includes 2,059,626 shares and 151,575 shares related to reduction in workforce and executive management restructuring, respectively, for the year ended December 31, 2016. |
Summary Of Equity-Classified Performance Units Activity | 2016 2015 2014 Number of Units (1) Weighted Average Fair Value Number of Units (1) Weighted Average Fair Value Number of Units (1) Weighted Average Fair Value (in thousands) (in thousands) (in thousands) Unvested shares at January 1 407 $ 36.65 223 $ 40.44 – $ – Granted 1,503 8.60 443 35.22 359 40.44 Vested (2) (889) 12.78 (259) 37.46 (111) 40.44 Forfeited (3) (302) 11.26 – – (25) 40.44 Unvested shares at December 31 719 $ 11.46 407 $ 36.65 223 $ 40.44 (1) These amounts reflect the number of performance units granted in thousands. The actual payout in shares may range from a minimum of zero shares to a maximum of two shares contingent upon the actual performance against the Performance Measures. The performance units have a three -year vesting term and the actual disbursement of shares, if any, is not determined until March following the end of the three-year vesting period. (2) Includes 22,918 units and 37,590 units related to the reduction in workforce and executive management restructuring, respectively, for the year ended December 31, 2016. (3) Includes 87,595 units and 195,834 units related to the reduction in workforce and executive management restructuring, respectively, for the year ended December 31, 2016. |
Unvested Stock Options [Member] | |
Disclosure of Compensation Related Costs, Share-based Payments [Line Items] | |
Schedule Of Stock-Based Compensation Costs | 2016 2015 2014 (in millions) Stock-based compensation cost related to stock options – general and administrative expense (1) $ 6 $ 5 $ 5 Stock-based compensation cost related to stock options – capitalized $ 1 $ 3 $ 4 (1) Includes less than $1 million and $1 million related to the reduction in workforce and executive management restructuring, respectively, for the year ended December 31, 2016. |
Restricted Stock [Member] | |
Disclosure of Compensation Related Costs, Share-based Payments [Line Items] | |
Schedule Of Stock-Based Compensation Costs | 2016 2015 2014 (in millions) Stock-based compensation cost related to restricted stock grants – general and administrative expense (1) $ 33 $ 14 $ 10 Stock-based compensation cost related to restricted stock grants – capitalized $ 8 $ 16 $ 12 (1) Includes $16 million and $1 million related to the reduction in workforce and executive management restructuring, respectively, for the year ended December 31, 2016. |
Equity-Classified Performance Units [Member] | |
Disclosure of Compensation Related Costs, Share-based Payments [Line Items] | |
Schedule Of Stock-Based Compensation Costs | 2016 2015 2014 (in millions) Stock-based compensation cost related to performance units – general and administrative expense (1) $ 9 $ 6 $ 3 Stock-based compensation cost related to performance units – capitalized $ 1 $ 4 $ 2 (1) Includes less than $1 million and $1 million related to reduction in workforce and executive management restructuring, respectively, for the year ended December 31, 2016. |
Segment Information (Tables)
Segment Information (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Segment Information [Abstract] | |
Summary Financial Information For Company's Reportable Segments | Exploration and Midstream Production Services Other Total (in millions) 2016 Revenues from external customers $ 1,435 $ 1,001 $ – $ 2,436 Intersegment revenues (22) 1,568 – 1,546 Depreciation, depletion and amortization expense 371 65 – 436 Impairment of natural gas and oil properties 2,321 – – 2,321 Operating income (loss) (2,404) (1) 209 (2) – (2,195) Interest expense (3) 87 1 – 88 Gain (loss) on derivatives (338) (1) – (339) Loss on early extinguishment of debt – – (51) (51) Other income ( loss ) , net 5 (2) (2) 1 Provision (benefit) for income taxes (3) (29) – – (29) Assets 4,178 (4) 1,331 1,567 (5) 7,076 Capital investments (6 ) 623 21 4 648 2015 Revenues from external customers $ 2,095 $ 1,038 $ – $ 3,133 Intersegment revenues (21) 2,081 – 2,060 Depreciation, depletion and amortization expense 1,028 62 1 1,091 Impairment of natural gas and oil properties 6,950 – – 6,950 Operating income (loss) (7,104) 583 (7 ) (1) (6,522) Interest expense (3) 47 9 – 56 Gain (loss) on derivatives 51 – (4) 47 Other loss, net (21) (9) – (30) Provision (benefit) for income taxes (3) (2,273) 268 – (2,005) Assets 6,588 (4) 1,290 208 8,086 Capital investments (6 ) 2,258 167 12 2,437 2014 Revenues from external customers $ 2,850 $ 1,188 $ – $ 4,038 Intersegment revenues 12 3,170 – 3,182 Depreciation, depletion and amortization expense 884 58 – 942 Operating income (loss) 1,013 361 (1) 1,373 Interest expense (3) 47 12 – 59 Gain (loss) on derivatives 142 (1) (2) 139 Other loss, net (3) (1) – (4) Provision for income taxes (3) 402 123 – 525 Assets 13,018 (4) 1,554 343 14,915 Capital investments (6 ) 7,254 144 49 7,447 (1) Operating loss for the E&P segment includes $86 million related to restructuring and other one-time charges for the year ended December 31, 2016. (2) Operatin g income f or the Midstream Services segment includes $3 million related to restructuring charges for the year ended December 31, 2016. (3) Interest expense and the provision (benefit) for income taxes by segment are an allocation of corporate amounts as they are incurred at the corporate level. (4) Includes office, technology, drilling rigs and other ancillary equipment not directly related to natural gas and oil property acquisition, exploration and development activities. (5) Other assets represent corporate assets not allocated to segments and assets for non-reportable segments. At December 31, 2016, other assets includes approximately $1.4 billion in cash and cash equivalents . (6) Capital investments include a n increase of $ 43 millio n for 201 6, a decrease of $ 33 million for 2015 and an increase of $ 155 million for 201 4 related to the change in accrued expenditures between years. (7) Operating income (loss) for the Midstream Services segment includes a $277 million gain on sale of assets for the year ended December 31, 2015. |
Supplemental Quarterly Results
Supplemental Quarterly Results (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Supplemental Quarterly Results [Abstract] | |
Schedule Of Quarterly Financial Information | 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter (in millions, except per share amounts) 2016 Operating revenues $ 579 $ 522 $ 651 $ 684 Operating income (loss) (1) (1,100) (492) (725) 122 Net loss attributable to common stock (1,159) (620) (735) (237) Loss per share - Basic (3.03) (1.61) (1.52) (0.48) Loss per share - Diluted (3.03) (1.61) (1.52) (0.48) 2015 Operating revenues $ 933 $ 764 $ 749 $ 687 Operating income (loss) (1) 165 (1,284) (2,842) (2,561) Net income (loss) attributable to common stock (2) 46 (815) (1,766) (2,134) Earnings (Loss) per share - Basic 0.12 (2.13) (4.62) (5.58) Earnings (Loss) per share - Diluted 0.12 (2.13) (4.62) (5.58) (1) The operating losses for the first, second and third quarters of 2016 included non-cash full cost impairments of natural gas and oil properties of $1,034 million, $470 million, and $817 million, respectively. There was no full cost impairment in the fourth quarter of 2016. The operating losses for the second, third and fourth quarters of 2015 included non-cash full cost impairments of natural gas and oil properties of $1,535 million, $2,839 million and $2,576 million, respectively. (2) Net income attributable to common stock was reduced by $7 million in the first quarter of 2015 to recognize the portion of the Company’s net income that would be distributed to the holders of preferred securities (mandatory convertible preferred stock) at year-end. However, as a result of the Company’s net loss in the second quarter that persisted for the year ended December 31, 2015, participating securities were ultimately not entitled to receive a distribution. |
Supplemental Oil And Gas Disc41
Supplemental Oil And Gas Disclosures (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Oil and Gas Exploration and Production Industries Disclosures [Line Items] | |
Capitalized Costs Relating To Oil And Gas Producing Activities Disclosure | 2016 2015 (in millions) Proved properties $ 20,548 $ 18,751 Unproved properties 2,105 3,727 Total capitalized costs 22,653 22,478 Less: Accumulated depreciation, depletion and amortization (18,897) (16,248) Net capitalized costs $ 3,756 $ 6,230 |
Composition Of Net Unevaluated Costs Excluded From Amortization | 2016 2015 2014 Prior Total (in millions) Property acquisition costs $ 22 $ 213 $ 1,501 $ 54 $ 1,790 Exploration and development costs 55 64 24 16 159 Capitalized interest 70 55 10 21 156 $ 147 $ 332 $ 1,535 $ 91 $ 2,105 |
Cost Incurred In Oil And Gas Property Acquisition, Exploration, And Development Activities Disclosure | 201 6 201 5 201 4 (in millions, except per Mcfe amounts) Proved property acquisition costs $ – $ 81 $ 1,455 Unproved property acquisition costs 171 692 3,934 Exploration costs 17 50 232 Development costs 433 1,417 1,600 Capitalized costs incurred 621 2,240 7,221 Full cost pool amortization per Mcfe $ 0.38 $ 1.00 $ 1.10 |
Results Of Operations For Oil And Gas Producing Activities Disclosure | 2016 2015 2014 (in millions) Sales $ 1,413 $ 2,074 $ 2,862 Production (lifting) costs (839) (989) (776) Depreciation, depletion and amortization (371) (1,028) (884) Impairment of natural gas and oil properties (2,321) (6,950) – (2,118) (6,893) 1,202 Provision (benefit) for income taxes – (1) (2,619) 457 Results of operations ( 2 ) $ (2,118) $ (4,274) $ 745 (1) Prior to the Company’s recognition of a valuation allowance in 2016, the Company recognized an income tax benefit of $805 million . (2) Results of operations exclude the gain (loss) on unsettled commodity derivative instruments. See Note 4 - Derivatives and Risk Management |
Summary Of Changes in Reserves | Appalachia Fayetteville Total Northeast Southwest Shale Other (1) (in Bcfe) December 31, 2013 6,976 1,963 – 4,795 218 Production (768) (254) (3) (494) (17) Disposition of reserves in place – – – – – Acquisition of reserves in place 2,303 1 2,300 – 2 Net revisions Price revisions 54 10 – 38 6 Performance and production revisions 489 636 – (126) (21) Total net revisions 543 646 – (88) (15) Reserve additions Proved developed 531 246 – 283 2 Proved undeveloped 1,162 589 – 573 – Total reserve additions 1,693 835 – 856 2 December 31, 2014 10,747 3,191 2,297 5,069 190 Production (976) (360) (143) (465) (8) Disposition of reserves in place (180) – – – (180) Acquisition of reserves in place 115 80 35 – – Net revisions Price revisions (5,718) (2,315) (1,875) (1,496) (32) Performance and production revisions 1,635 1,383 209 10 33 Total net revisions (4,083) (932) (1,666) (1,486) 1 Reserve additions Proved developed 416 202 84 129 1 Proved undeveloped 176 138 4 34 – Total reserve additions 592 340 88 163 1 December 31, 2015 6,215 2,319 611 3,281 4 Production (875) (350) (148) (375) (2) Disposition of reserves in place (15) – (15) – – Acquisition of reserves in place – – – – – Net revisions Price revisions (1,037) (794) (127) (116) – Performance and production revisions 683 318 199 163 3 Total net revisions (354) (476) 72 47 3 Reserve additions Proved developed 257 81 157 19 – Proved undeveloped 25 – – 25 – Total reserve additions 282 81 157 44 – December 31, 2016 5,253 1,574 677 2,997 5 (1) Other includes properties outside of the Appalachian Basin and Fayetteville Shale along with Ark-La-Tex properties divested in May 2015. |
Standardized Measure Of Discounted Future Cash Flows Relating To Proved Reserves Disclosure | 2016 2015 2014 (in millions) Future cash inflows $ 9,064 $ 11,887 $ 41,812 Future production costs (5,880) (7,376) (16,477) Future development costs (1) (485) (792) (5,750) Future income tax expense (2) – – (4,743) Future net cash flows 2,699 3,719 14,842 10% annual discount for estimated timing of cash flows (1,034) (1,302) (7,299) Standardized measure of discounted future net cash flows $ 1,665 $ 2,417 $ 7,543 (1) Includes abandonment costs. (2) The December 31, 2016 and 2015 standardized measure computation does not have future income taxes because the Company’s tax basis in the associated oil and gas properties exceeded expected pre-tax cash inflows. Future net cash flows are not permitted to be increased by excess tax basis. |
Schedule Of Analysis Of Changes In Standardized Measure | 2016 2015 2014 (in millions) Standardized measure, beginning of year $ 2,417 $ 7,543 $ 3,736 Sales and transfers of natural gas and oil produced, net of production costs (574) (1,082) (2,084) Net changes in prices and production costs (415) (8,075) 1,192 Extensions, discoveries, and other additions, net of future production and development costs 45 162 1,049 Acquisition of reserves in place – 28 1,897 Sales of reserves in place (10) (244) – Revisions of previous quantity estimates (140) (1,385) 622 Accretion of discount 242 946 513 Net change in income taxes – 1,915 (522) Changes in estimated future development costs 71 2,007 110 Previously estimated development costs incurred during the year 114 875 815 Changes in production rates (timing) and other (85) (273) 215 Standardized measure, end of year $ 1,665 $ 2,417 $ 7,543 |
United States [Member] | |
Oil and Gas Exploration and Production Industries Disclosures [Line Items] | |
Summary Of Changes in Reserves | 2016 2015 2014 Natural Natural Natural Gas Oil NGL Gas Oil NGL Gas Oil NGL (Bcf) (MBbls) (MBbls) (Bcf) (MBbls) (MBbls) (Bcf) (MBbls) (MBbls) Proved reserves, beginning of year 5,917 8,753 40,947 9,809 37,615 118,699 6,974 373 – Revisions of previous estimates (446) 1,564 13,794 (3,458) (28,394) (75,664) 542 (14) 66 Extensions, discoveries and other additions 198 2,417 11,576 546 1,367 6,274 1,692 250 48 Production (788) (2,192) (12,372) (899) (2,265) (10,702) (766) (235) (231) Acquisition of reserves in place – – – 97 525 2,340 1,367 37,246 118,816 Disposition of reserves in place (15) (19) (14) (178) (95) – – (5) – Proved reserves, end of year 4,866 10,523 53,931 5,917 8,753 40,947 9,809 37,615 118,699 Proved developed reserves: Beginning of year 5,474 8,753 40,947 5,675 7,445 38,632 4,237 372 – End of year 4,789 10,523 53,931 5,474 8,753 40,947 5,675 7,445 38,632 Proved undeveloped reserves: Beginning of year 443 – – 4,134 30,170 80,067 2,737 1 – End of year 77 – – 443 – – 4,134 30,170 80,067 |
Organization And Summary Of S42
Organization And Summary Of Significant Accounting Policies (Narrative) (Details) | Jan. 17, 2017shares | Dec. 19, 2014USD ($) | Sep. 30, 2016USD ($) | Jul. 31, 2016USD ($)$ / sharesshares | Nov. 30, 2015 | Jan. 31, 2015USD ($)$ / sharesshares | Mar. 31, 2017USD ($) | Dec. 31, 2016USD ($)$ / shares$ / bbl$ / MMBTUshares | Dec. 31, 2015USD ($)$ / shares$ / bbl$ / MMBTUshares | Dec. 31, 2014USD ($)$ / bbl$ / MMBTUshares | Dec. 31, 2013USD ($) | Dec. 31, 2016USD ($)$ / sharesshares | Jun. 30, 2016USD ($) | Mar. 31, 2016USD ($) | Sep. 30, 2015USD ($) | Jun. 30, 2015USD ($) |
Organization, Consolidation and Presentation of Financial Statements [Line Items] | ||||||||||||||||
Asset Retirement Obligation, Period Increase (Decrease) | $ 141,000,000 | $ 201,000,000 | ||||||||||||||
Outstanding checks included in accounts payable | $ 8,000,000 | $ 29,000,000 | $ 8,000,000 | |||||||||||||
Natural gas, oil and NGL reserves discount | 10.00% | 10.00% | 10.00% | |||||||||||||
Period of time needed to calculate ceiling value of reserves | 12 months | 12 months | 12 months | |||||||||||||
Net unevaluated costs excluded from amortization | $ 147,000,000 | $ 332,000,000 | $ 1,535,000,000 | $ 91,000,000 | $ 2,105,000,000 | |||||||||||
Impairment of natural gas and oil properties, net of tax | $ 506,000,000 | $ 297,000,000 | $ 641,000,000 | $ 1,746,000,000 | $ 944,000,000 | |||||||||||
Cash flow hedges impact on ceiling value, net of tax | $ 40,000,000 | $ 60,000,000 | ||||||||||||||
Amount recognized is the largest amount of tax benefit, threshold | 50.00% | |||||||||||||||
Payments on long-term debt | $ 1,175,000,000 | $ 500,000,000 | ||||||||||||||
Common stock, date dividend declared | Dec. 12, 2016 | |||||||||||||||
Common stock, shares issued as stock dividend | shares | 7,166,389 | |||||||||||||||
Common stock, date dividend to be paid | Jan. 17, 2017 | |||||||||||||||
Antidilutive securities excluded from computation of earnings per share, shares | shares | 83,287,879 | 76,856,343 | 1,475,883 | |||||||||||||
Number of common shares: Effect of issuance of non-vested performance units | shares | 273,918 | |||||||||||||||
Treasury stock, shares | shares | 31,269 | 47,149 | 31,269 | |||||||||||||
Unamortized debt expense | $ 28,000,000 | $ 24,000,000 | $ 28,000,000 | |||||||||||||
Accounting Standards Update 2016-09 [Member] | Scenario, Forecast [Member] | ||||||||||||||||
Organization, Consolidation and Presentation of Financial Statements [Line Items] | ||||||||||||||||
Unrecognized windfall tax benefits, cumulative-effect adjustment | $ 149,000,000 | |||||||||||||||
Long-term Debt [Member] | ||||||||||||||||
Organization, Consolidation and Presentation of Financial Statements [Line Items] | ||||||||||||||||
Unamortized debt expense | 28,000,000 | 24,000,000 | 28,000,000 | |||||||||||||
Long-term Debt [Member] | Term Loan 1 due December 2020 [Member] | ||||||||||||||||
Organization, Consolidation and Presentation of Financial Statements [Line Items] | ||||||||||||||||
Payments on long-term debt | 48,000,000 | $ 375,000,000 | ||||||||||||||
Debt instrument face amount | 750,000,000 | 750,000,000 | ||||||||||||||
Debt instrument, term | 3 years | |||||||||||||||
Unamortized debt expense | $ 400,000 | 2,000,000 | 3,000,000 | $ 2,000,000 | ||||||||||||
Senior Notes [Member] | ||||||||||||||||
Organization, Consolidation and Presentation of Financial Statements [Line Items] | ||||||||||||||||
Purchase of note principal | 700,000,000 | |||||||||||||||
Proceeds from issuance of debt | $ 2,200,000,000 | $ 2,200,000,000 | ||||||||||||||
Unamortized debt expense | $ 2,000,000 | |||||||||||||||
Bridge Loan [Member] | ||||||||||||||||
Organization, Consolidation and Presentation of Financial Statements [Line Items] | ||||||||||||||||
Bridge loan | $ 4,500,000,000 | $ 4,500,000,000 | $ 4,500,000,000 | |||||||||||||
Debt instrument, term | 364 days | 364 days | 364 days | |||||||||||||
NGL [Member] | ||||||||||||||||
Organization, Consolidation and Presentation of Financial Statements [Line Items] | ||||||||||||||||
Impairment of natural gas and oil properties, net of tax | $ 1,586,000,000 | |||||||||||||||
Full cost ceiling test, price | $ / bbl | 6.74 | 6.82 | 23.79 | |||||||||||||
United States [Member] | ||||||||||||||||
Organization, Consolidation and Presentation of Financial Statements [Line Items] | ||||||||||||||||
Net unevaluated costs excluded from amortization | $ 2,105,000,000 | |||||||||||||||
Henry Hub Natural Gas [Member] | ||||||||||||||||
Organization, Consolidation and Presentation of Financial Statements [Line Items] | ||||||||||||||||
Full cost ceiling test, price | $ / MMBTU | 2.48 | 2.59 | 4.35 | |||||||||||||
West Texas Intermediate Oil [Member] | ||||||||||||||||
Organization, Consolidation and Presentation of Financial Statements [Line Items] | ||||||||||||||||
Full cost ceiling test, price | $ / bbl | 39.25 | 46.79 | 91.48 | |||||||||||||
Gathering Systems [Member] | ||||||||||||||||
Organization, Consolidation and Presentation of Financial Statements [Line Items] | ||||||||||||||||
Straight-line depreciation period | 25 years | |||||||||||||||
Common Stock [Member] | ||||||||||||||||
Organization, Consolidation and Presentation of Financial Statements [Line Items] | ||||||||||||||||
Shares issued | shares | 98,900,000 | 30,000,000 | ||||||||||||||
Price per share | $ / shares | $ 13 | $ 23 | ||||||||||||||
Proceeds from issuance of shares | $ 1,247,000,000 | $ 669,000,000 | ||||||||||||||
Depositary Shares [Member] | ||||||||||||||||
Organization, Consolidation and Presentation of Financial Statements [Line Items] | ||||||||||||||||
Shares issued | shares | 34,500,000 | |||||||||||||||
Proceeds from issuance of shares | $ 1,700,000,000 | |||||||||||||||
Depositary shares conversion rate | 0.05% | |||||||||||||||
Liquidation preference per share | $ / shares | $ 50 | |||||||||||||||
Series B Preferred Stock [Member] | ||||||||||||||||
Organization, Consolidation and Presentation of Financial Statements [Line Items] | ||||||||||||||||
Liquidation preference per share | $ / shares | $ 1,000 | $ 1,000 | $ 1,000 | $ 1,000 | ||||||||||||
Trading day period | 20 days | |||||||||||||||
Minimum [Member] | Depositary Shares [Member] | ||||||||||||||||
Organization, Consolidation and Presentation of Financial Statements [Line Items] | ||||||||||||||||
Shares issued upon conversion | shares | 1.85014 | 1.85014 | ||||||||||||||
Minimum [Member] | Series B Preferred Stock [Member] | ||||||||||||||||
Organization, Consolidation and Presentation of Financial Statements [Line Items] | ||||||||||||||||
Shares issued upon conversion | shares | 37.0028 | 37.0028 | ||||||||||||||
Potential number of shares issued upon conversion | shares | 63,829,830 | |||||||||||||||
Maximum [Member] | Depositary Shares [Member] | ||||||||||||||||
Organization, Consolidation and Presentation of Financial Statements [Line Items] | ||||||||||||||||
Shares issued upon conversion | shares | 2.17391 | 2.17391 | ||||||||||||||
Maximum [Member] | Series B Preferred Stock [Member] | ||||||||||||||||
Organization, Consolidation and Presentation of Financial Statements [Line Items] | ||||||||||||||||
Shares issued upon conversion | shares | 43.4782 | 43.4782 | ||||||||||||||
Potential number of shares issued upon conversion | shares | 74,999,895 | |||||||||||||||
WPX Property Acquisition [Member] | ||||||||||||||||
Organization, Consolidation and Presentation of Financial Statements [Line Items] | ||||||||||||||||
Percentage of interest acquired | 86.00% | |||||||||||||||
Subsequent Event [Member] | ||||||||||||||||
Organization, Consolidation and Presentation of Financial Statements [Line Items] | ||||||||||||||||
Common stock, shares issued as stock dividend | shares | 2,751,410 |
Organization And Summary Of S43
Organization And Summary Of Significant Accounting Policies (Summary Of Cash And Cash Equivalents) (Details) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Organization And Summary Of Significant Accounting Policies [Abstract] | ||||
Cash | $ 254 | $ 15 | ||
Marketable securities | 1,169 | |||
Total | $ 1,423 | $ 15 | $ 53 | $ 23 |
Organization And Summary Of S44
Organization And Summary Of Significant Accounting Policies (Schedule Of Earnings Per Share) (Details) - USD ($) $ / shares in Units, $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Organization And Summary Of Significant Accounting Policies [Abstract] | |||||||||||
Net income (loss) | $ (2,643) | $ (4,556) | $ 924 | ||||||||
Mandatory convertible preferred stock dividend | 108 | 106 | |||||||||
Net Income (Loss) Attributable to Common Stock | $ (237) | $ (735) | $ (620) | $ (1,159) | $ (2,134) | $ (1,766) | $ (815) | $ 46 | $ (2,751) | $ (4,662) | $ 924 |
Number of common shares: Weighted average outstanding | 435,337,402 | 380,521,039 | 351,446,747 | ||||||||
Number of common shares: Issued upon assumed exercise of outstanding stock options | 241,603 | ||||||||||
Number of common shares: Effect of issuance of non-vested restricted common stock | 448,415 | ||||||||||
Number of common shares: Effect of issuance of non-vested performance units | 273,918 | ||||||||||
Number of common shares: Weighted average and potential dilutive outstanding | 435,337,402 | 380,521,039 | 352,410,683 | ||||||||
Basic | $ (0.48) | $ (1.52) | $ (1.61) | $ (3.03) | $ (5.58) | $ (4.62) | $ (2.13) | $ 0.12 | $ (6.32) | $ (12.25) | $ 2.63 |
Diluted | $ (0.48) | $ (1.52) | $ (1.61) | $ (3.03) | $ (5.58) | $ (4.62) | $ (2.13) | $ 0.12 | $ (6.32) | $ (12.25) | $ 2.62 |
Organization And Summary Of S45
Organization And Summary Of Significant Accounting Policies (Schedule Of Antidilutive Securities Excluded From Computation Of Earnings Per Share) (Details) - shares | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | |||
Antidilutive securities excluded from computation of earnings per share, shares | 83,287,879 | 76,856,343 | 1,475,883 |
Unvested Stock Options [Member] | |||
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | |||
Antidilutive securities excluded from computation of earnings per share, shares | 3,692,697 | 3,835,234 | 1,446,004 |
Restricted Stock [Member] | |||
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | |||
Antidilutive securities excluded from computation of earnings per share, shares | 959,233 | 1,990,383 | 29,879 |
Performance Units [Member] | |||
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | |||
Antidilutive securities excluded from computation of earnings per share, shares | 884,644 | 140,414 | |
Mandatory Convertible Preferred Stock [Member] | |||
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | |||
Antidilutive securities excluded from computation of earnings per share, shares | 74,999,895 | 70,890,312 | |
Declared And Unpaid Preferred Stock Dividends [Member] | |||
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | |||
Antidilutive securities excluded from computation of earnings per share, shares | 2,751,410 |
Organization And Summary Of S46
Organization And Summary Of Significant Accounting Policies (Schedule Of Supplemental Disclosures Of Cash Flow Information) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Organization And Summary Of Significant Accounting Policies [Abstract] | |||
Cash paid during the year for interest, net of amounts capitalized | $ 75 | $ 6 | $ 50 |
Cash paid (received) during the year for income taxes | (15) | (6) | 28 |
Increase (decrease) in noncash property additions | $ 55 | $ (10) | $ 174 |
Reduction In Workforce (Narrati
Reduction In Workforce (Narrative) (Details) | 1 Months Ended | 3 Months Ended |
Jan. 31, 2016 | Mar. 31, 2016 | |
Workforce Reduction [Member] | ||
Restructuring Cost and Reserve [Line Items] | ||
Positions eliminated, percent | 40.00% | 40.00% |
Reduction In Workforce (Summary
Reduction In Workforce (Summary Of Restructuring Charges) (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2016USD ($) | |
Restructuring Cost and Reserve [Line Items] | |
Severance (including payroll taxes) | $ 44 |
Stock-based compensation | 24 |
Pension and other postretirement benefits | 5 |
Other benefits | 3 |
Outplacement services, other | 2 |
Total restructuring charges | 78 |
Midstream Services [Member] | |
Restructuring Cost and Reserve [Line Items] | |
Total restructuring charges | 3 |
Workforce Reduction [Member] | Exploration and Production [Member] | |
Restructuring Cost and Reserve [Line Items] | |
Total restructuring charges | 75 |
Workforce Reduction [Member] | Midstream Services [Member] | |
Restructuring Cost and Reserve [Line Items] | |
Total restructuring charges | $ 3 |
Reduction In Workforce (Summa49
Reduction In Workforce (Summary Of Liabilities Associated With Restructuring Activities) (Details) - Workforce Reduction [Member] $ in Millions | 12 Months Ended |
Dec. 31, 2016USD ($) | |
Restructuring Cost and Reserve [Line Items] | |
Liability at December 31, 2015 | |
Additions | 49 |
Distributions | (48) |
Liability at December 31, 2016 | $ 1 |
Acquisitions And Divestitures50
Acquisitions And Divestitures (Narrative) (Details) ft³ in Millions, $ in Millions | Dec. 19, 2014USD ($) | Sep. 30, 2016USD ($)a | Jul. 31, 2016USD ($) | Nov. 30, 2015USD ($) | May 31, 2015USD ($) | Apr. 30, 2015USD ($)mift³ | Jan. 31, 2015USD ($)a | Dec. 31, 2014USD ($)aft³ | Dec. 31, 2016USD ($) | Sep. 30, 2016USD ($)a | Jun. 30, 2016USD ($) | Mar. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Sep. 30, 2015USD ($) | Jun. 30, 2015USD ($) | Mar. 31, 2015USD ($) | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($)aitemft³ |
Business Acquisition [Line Items] | |||||||||||||||||||
Payments on long-term debt | $ 1,175 | $ 500 | |||||||||||||||||
Capital spending | 593 | 1,798 | $ 2,043 | ||||||||||||||||
Repayment of short-term debt | 4,500 | ||||||||||||||||||
General and administrative expenses | 247 | 246 | 221 | ||||||||||||||||
Interest expense | 88 | 56 | 59 | ||||||||||||||||
Other current assets | $ 35 | $ 48 | 35 | 48 | |||||||||||||||
Revenues | 684 | $ 651 | $ 522 | $ 579 | 687 | $ 749 | $ 764 | $ 933 | 2,436 | 3,133 | 4,038 | ||||||||
Operating income (loss) | 122 | $ (725) | $ (492) | $ (1,100) | (2,561) | $ (2,842) | $ (1,284) | $ 165 | $ (2,195) | (6,522) | 1,373 | ||||||||
Bridge Loan [Member] | |||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||
Bridge loan | $ 4,500 | $ 4,500 | 4,500 | $ 4,500 | $ 4,500 | ||||||||||||||
Debt instrument, term | 364 days | 364 days | 364 days | ||||||||||||||||
Repayment of short-term debt | $ 4,500 | ||||||||||||||||||
Debt issuance costs | $ 47 | ||||||||||||||||||
Unsecured Debt [Member] | Term Loan due December 2016 [Member] | |||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||
Loans payable | $ 500 | $ 500 | $ 500 | $ 500 | |||||||||||||||
Maturity date, year and month | 2016-12 | ||||||||||||||||||
Debt instrument, term | 2 years | ||||||||||||||||||
Long-term Debt [Member] | Term Loan 1 due December 2020 [Member] | |||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||
Payments on long-term debt | $ 48 | $ 375 | |||||||||||||||||
Loans payable | $ 750 | ||||||||||||||||||
Maturity date, year and month | 2020-12 | 2018-11 | |||||||||||||||||
Debt instrument, term | 3 years | ||||||||||||||||||
Debt issuance costs | $ 3 | $ 3 | |||||||||||||||||
WPX Property Acquisition [Member] | |||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||
Area of land purchased | a | 46,700 | ||||||||||||||||||
Cash consideration | $ 270 | ||||||||||||||||||
Net production per day of acreage sold in MMcf | ft³ | 50 | 50 | |||||||||||||||||
Number of horizontal wells operated | item | 63 | ||||||||||||||||||
Firm transportation capacity assumed, per day | ft³ | 260 | ||||||||||||||||||
Firm transportation, useful life | 19 years | ||||||||||||||||||
Amortization | $ 17 | $ 8 | |||||||||||||||||
Percentage of interest acquired | 86.00% | 86.00% | |||||||||||||||||
Assets acquired and liabilities net book value | $ 270 | ||||||||||||||||||
Statoil Property Acquisition [Member] | |||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||
Area of land purchased | a | 30,000 | ||||||||||||||||||
Percentage of interest acquired | 20.00% | ||||||||||||||||||
Allocated to natural gas and oil properties | $ 357 | ||||||||||||||||||
Chesapeake Property Acquisition [Member] | |||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||
Area of land purchased | a | 413,000 | 413,000 | |||||||||||||||||
Cash consideration | $ 4,949 | ||||||||||||||||||
Assets acquired and liabilities net book value | 4,949 | $ 4,949 | |||||||||||||||||
General and administrative expenses | 1 | ||||||||||||||||||
Interest expense | 5 | ||||||||||||||||||
Revenues | 10 | ||||||||||||||||||
Operating income (loss) | 2 | ||||||||||||||||||
Chesapeake Property Acquisition [Member] | Bridge Loan [Member] | |||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||
Other current assets | 47 | 47 | |||||||||||||||||
Chesapeake Property Acquisition [Member] | Unsecured Debt [Member] | Term Loan due December 2016 [Member] | |||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||
Unamortized fees | $ 1 | $ 1 | |||||||||||||||||
West Virginia [Member] | |||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||
Area of land sold | a | 55,000 | 55,000 | |||||||||||||||||
Proceeds from sale of oil and gas property and equipment | $ 422 | ||||||||||||||||||
East Texas and Arkoma Basin [Member] | |||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||
Proceeds from sale of oil and gas property and equipment | $ 211 | ||||||||||||||||||
Reduction in capitalized costs relating to proceeds | $ 205 | ||||||||||||||||||
Bradford And Lycoming Counties, Pennsylvania [Member] | |||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||
Proceeds from sale of oil and gas property and equipment | $ 489 | ||||||||||||||||||
Net book value | 206 | ||||||||||||||||||
Gain on sale of property | $ 283 | ||||||||||||||||||
Number of miles of natural gas gathering pipeline | mi | 100 | ||||||||||||||||||
Pipeline capacity per day | ft³ | 600 |
Acquisitions And Divestitures51
Acquisitions And Divestitures (Summary Of Consideration Paid And Fair Value Of Assets Acquired And Liabilities Assumed) (Details) - USD ($) $ in Millions | 1 Months Ended | |
Jan. 31, 2015 | Dec. 31, 2014 | |
WPX Property Acquisition [Member] | ||
Business Acquisition [Line Items] | ||
Cash | $ 270 | |
Proved natural gas and oil properties | 31 | |
Unproved natural gas and oil properties | 114 | |
Intangible asset | 109 | |
Gathering system | 22 | |
Other | 1 | |
Total assets acquired | 277 | |
Asset retirement obligations | (7) | |
Total liabilities assumed | (7) | |
Total assets acquired and liabilities assumed | $ 270 | |
Chesapeake Property Acquisition [Member] | ||
Business Acquisition [Line Items] | ||
Cash | $ 4,949 | |
Proved natural gas and oil properties | 1,418 | |
Unproved natural gas and oil properties | 3,573 | |
Other property and equipment | 33 | |
Inventory | 3 | |
Total assets acquired | 5,027 | |
Asset retirement obligations | (42) | |
Other liabilities | (36) | |
Total liabilities assumed | (78) | |
Total assets acquired and liabilities assumed | $ 4,949 |
Acquisitions And Divestitures52
Acquisitions And Divestitures (Summary Of Consolidated Results Of Operations On Pro Forma Basis) (Details) - Chesapeake Property Acquisition [Member] - USD ($) $ / shares in Units, $ in Millions | 12 Months Ended | |
Dec. 31, 2014 | Dec. 31, 2013 | |
Business Acquisition [Line Items] | ||
Revenues | $ 4,439 | $ 3,713 |
Net income attributable to common stock | $ 803 | $ 594 |
Basic | $ 2.11 | $ 1.56 |
Diluted | $ 2.10 | $ 1.56 |
Derivatives And Risk Manageme53
Derivatives And Risk Management (Narrative) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Derivative [Line Items] | |||
Gas sales | $ 1,273 | $ 1,946 | $ 2,827 |
Interest Rate Swaps [Member] | |||
Derivative [Line Items] | |||
Derivative liabilities | 3 | 5 | |
Notional amount | $ 170 | ||
Derivative, expiration | Jun. 30, 2020 | ||
Fixed Price Swaps [Member] | |||
Derivative [Line Items] | |||
Derivative liabilities | $ 178 | ||
Not Designated as Hedging Instrument [Member] | Interest Rate Swaps [Member] | |||
Derivative [Line Items] | |||
Derivative liabilities | 3 | ||
Designated as Hedging Instrument [Member] | Fixed Price Swaps [Member] | |||
Derivative [Line Items] | |||
Gas sales | 209 | ||
Natural Gas [Member] | Not Designated as Hedging Instrument [Member] | |||
Derivative [Line Items] | |||
Derivative liabilities | $ 372 | ||
Mark To Market Gain (Loss) On Derivatives [Member] | Designated as Hedging Instrument [Member] | Fixed Price Swaps [Member] | |||
Derivative [Line Items] | |||
Derivative gain (loss) in other comprehensive income | $ 45 |
Derivatives And Risk Manageme54
Derivatives And Risk Management (Schedule Of Derivative Instruments, Notional Amount In BCF, Weighted Average Contract Prices And Fair Value) (Details) $ in Millions, ft³ in Billions | 12 Months Ended |
Dec. 31, 2016USD ($)$ / MMBTUft³ | |
Fixed Price Swaps - 2017 [Member] | |
Derivative [Line Items] | |
Volume (Bcf) | ft³ | 322 |
Fixed Price Swaps - 2017 [Member] | Not Designated as Hedging Instrument [Member] | |
Derivative [Line Items] | |
Average price per MMBtu | 3.07 |
Fair value | $ | $ (175) |
Two-way Costless-collars - 2017 [Member] | |
Derivative [Line Items] | |
Volume (Bcf) | ft³ | 103 |
Two-way Costless-collars - 2017 [Member] | Not Designated as Hedging Instrument [Member] | |
Derivative [Line Items] | |
Fair value | $ | $ (42) |
Two-way Costless-collars - 2017 Purchased Puts [Member] | Not Designated as Hedging Instrument [Member] | |
Derivative [Line Items] | |
Floor price per MMBtu | 2.94 |
Two-way Costless-collars - 2017 Sold Calls [Member] | Not Designated as Hedging Instrument [Member] | |
Derivative [Line Items] | |
Cap price per MMBtu | 3.38 |
Three-way Costless-collars - 2017 [Member] | |
Derivative [Line Items] | |
Volume (Bcf) | ft³ | 135 |
Three-way Costless-collars - 2017 [Member] | Not Designated as Hedging Instrument [Member] | |
Derivative [Line Items] | |
Fair value | $ | $ (59) |
Three-way Costless-collars - 2017 Sold Puts [Member] | Not Designated as Hedging Instrument [Member] | |
Derivative [Line Items] | |
Floor price per MMBtu | 2.29 |
Three-way Costless-collars - 2017 Purchased Puts [Member] | Not Designated as Hedging Instrument [Member] | |
Derivative [Line Items] | |
Floor price per MMBtu | 2.97 |
Three-way Costless-collars - 2017 Sold Calls [Member] | Not Designated as Hedging Instrument [Member] | |
Derivative [Line Items] | |
Cap price per MMBtu | 3.30 |
Basis Swaps - 2017 [Member] | |
Derivative [Line Items] | |
Volume (Bcf) | ft³ | 132 |
Basis Swaps - 2017 [Member] | Not Designated as Hedging Instrument [Member] | |
Derivative [Line Items] | |
Basis differential per MMBtu | (0.87) |
Fair value | $ | $ 19 |
Financial protection on production - 2017 [Member] | |
Derivative [Line Items] | |
Volume (Bcf) | ft³ | 692 |
Financial protection on production - 2017 [Member] | Not Designated as Hedging Instrument [Member] | |
Derivative [Line Items] | |
Fair value | $ | $ (257) |
Fixed Price Swaps - 2018 [Member] | |
Derivative [Line Items] | |
Volume (Bcf) | ft³ | 18 |
Fixed Price Swaps - 2018 [Member] | Not Designated as Hedging Instrument [Member] | |
Derivative [Line Items] | |
Average price per MMBtu | 3 |
Fair value | $ | $ (2) |
Two-way Costless-collars - 2018 [Member] | |
Derivative [Line Items] | |
Volume (Bcf) | ft³ | 14 |
Two-way Costless-collars - 2018 [Member] | Not Designated as Hedging Instrument [Member] | |
Derivative [Line Items] | |
Fair value | $ | $ (6) |
Two-way Costless-collars - 2018 Purchased Puts [Member] | Not Designated as Hedging Instrument [Member] | |
Derivative [Line Items] | |
Floor price per MMBtu | 3 |
Two-way Costless-collars - 2018 Sold Calls [Member] | Not Designated as Hedging Instrument [Member] | |
Derivative [Line Items] | |
Cap price per MMBtu | 3.46 |
Three-way Costless-collars - 2018 [Member] | |
Derivative [Line Items] | |
Volume (Bcf) | ft³ | 208 |
Three-way Costless-collars - 2018 [Member] | Not Designated as Hedging Instrument [Member] | |
Derivative [Line Items] | |
Fair value | $ | $ (20) |
Three-way Costless-collars - 2018 Sold Puts [Member] | Not Designated as Hedging Instrument [Member] | |
Derivative [Line Items] | |
Floor price per MMBtu | 2.37 |
Three-way Costless-collars - 2018 Purchased Puts [Member] | Not Designated as Hedging Instrument [Member] | |
Derivative [Line Items] | |
Floor price per MMBtu | 2.96 |
Three-way Costless-collars - 2018 Sold Calls [Member] | Not Designated as Hedging Instrument [Member] | |
Derivative [Line Items] | |
Cap price per MMBtu | 3.37 |
Basis Swaps - 2018 [Member] | |
Derivative [Line Items] | |
Volume (Bcf) | ft³ | 16 |
Basis Swaps - 2018 [Member] | Not Designated as Hedging Instrument [Member] | |
Derivative [Line Items] | |
Basis differential per MMBtu | (0.94) |
Fair value | $ | $ (4) |
Financial protection on production - 2018 [Member] | |
Derivative [Line Items] | |
Volume (Bcf) | ft³ | 256 |
Financial protection on production - 2018 [Member] | Not Designated as Hedging Instrument [Member] | |
Derivative [Line Items] | |
Fair value | $ | $ (32) |
Three-way Costless-collars - 2019 [Member] | |
Derivative [Line Items] | |
Volume (Bcf) | ft³ | 62 |
Three-way Costless-collars - 2019 [Member] | Not Designated as Hedging Instrument [Member] | |
Derivative [Line Items] | |
Fair value | $ | $ (2) |
Three-way Costless-collars - 2019 Sold Puts [Member] | Not Designated as Hedging Instrument [Member] | |
Derivative [Line Items] | |
Floor price per MMBtu | 2.50 |
Three-way Costless-collars - 2019 Purchased Puts [Member] | Not Designated as Hedging Instrument [Member] | |
Derivative [Line Items] | |
Floor price per MMBtu | 2.92 |
Three-way Costless-collars - 2019 Sold Calls [Member] | Not Designated as Hedging Instrument [Member] | |
Derivative [Line Items] | |
Cap price per MMBtu | 3.35 |
Financial protection on production - 2019 [Member] | |
Derivative [Line Items] | |
Volume (Bcf) | ft³ | 62 |
Financial protection on production - 2019 [Member] | Not Designated as Hedging Instrument [Member] | |
Derivative [Line Items] | |
Fair value | $ | $ (2) |
Sold Call Options - 2017 [Member] | |
Derivative [Line Items] | |
Volume (Bcf) | ft³ | 86 |
Sold Call Options - 2017 [Member] | Not Designated as Hedging Instrument [Member] | |
Derivative [Line Items] | |
Cap price per MMBtu | 3.25 |
Fair value | $ | $ (46) |
Sold Call Options - 2018 [Member] | |
Derivative [Line Items] | |
Volume (Bcf) | ft³ | 63 |
Sold Call Options - 2018 [Member] | Not Designated as Hedging Instrument [Member] | |
Derivative [Line Items] | |
Cap price per MMBtu | 3.50 |
Fair value | $ | $ (18) |
Sold Call Options - 2019 [Member] | |
Derivative [Line Items] | |
Volume (Bcf) | ft³ | 52 |
Sold Call Options - 2019 [Member] | Not Designated as Hedging Instrument [Member] | |
Derivative [Line Items] | |
Cap price per MMBtu | 3.50 |
Fair value | $ | $ (11) |
Sold Call Options - 2020 [Member] | |
Derivative [Line Items] | |
Volume (Bcf) | ft³ | 32 |
Sold Call Options - 2020 [Member] | Not Designated as Hedging Instrument [Member] | |
Derivative [Line Items] | |
Cap price per MMBtu | 3.75 |
Fair value | $ | $ (6) |
Sold Call Options [Member] | |
Derivative [Line Items] | |
Volume (Bcf) | ft³ | 233 |
Sold Call Options [Member] | Not Designated as Hedging Instrument [Member] | |
Derivative [Line Items] | |
Fair value | $ | $ (81) |
Derivatives And Risk Manageme55
Derivatives And Risk Management (Balance Sheet Classification Of Derivative Financial Instruments) (Details) - Not Designated as Hedging Instrument [Member] - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Derivatives, Fair Value [Line Items] | ||
Derivative assets | $ 155 | $ 3 |
Derivative liabilities | 530 | 5 |
Fixed Price Swaps [Member] | Other Long-Term Assets [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets | 1 | |
Fixed Price Swaps [Member] | Derivative Liabilities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liabilities | 175 | |
Fixed Price Swaps [Member] | Other Long-Term Liabilities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liabilities | 3 | |
Two-way Costless-collars [Member] | Derivative Assets [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets | 8 | |
Two-way Costless-collars [Member] | Other Long-Term Assets [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets | 2 | |
Two-way Costless-collars [Member] | Derivative Liabilities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liabilities | 49 | |
Two-way Costless-collars [Member] | Other Long-Term Liabilities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liabilities | 9 | |
Three-way Costless-collars [Member] | Derivative Assets [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets | 11 | |
Three-way Costless-collars [Member] | Other Long-Term Assets [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets | 100 | |
Three-way Costless-collars [Member] | Derivative Liabilities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liabilities | 70 | |
Three-way Costless-collars [Member] | Other Long-Term Liabilities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liabilities | 122 | |
Basis Swaps [Member] | Derivative Assets [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets | 32 | 3 |
Basis Swaps [Member] | Other Long-Term Assets [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative assets | 1 | |
Basis Swaps [Member] | Derivative Liabilities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liabilities | 13 | |
Basis Swaps [Member] | Other Long-Term Liabilities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liabilities | 5 | |
Sold Call Options [Member] | Derivative Liabilities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liabilities | 46 | |
Sold Call Options [Member] | Other Long-Term Liabilities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liabilities | 35 | |
Interest Rate Swaps [Member] | Derivative Liabilities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liabilities | 2 | 3 |
Interest Rate Swaps [Member] | Other Long-Term Liabilities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liabilities | $ 1 | $ 2 |
Derivatives And Risk Manageme56
Derivatives And Risk Management (Summary Of Before Tax Effect Of Fair Value Hedges Not Designated For Hedge Accounting) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Derivative Instruments, Gain (Loss) [Line Items] | ||
Derivative Instrument, Gain (Loss) on Derivatives, Unsettled | $ (373) | $ (155) |
Derivative Instrument, Gain (Loss) on Derivatives, Settled | 34 | 202 |
Total gain (loss) on derivatives | (339) | 47 |
Fixed Price Swaps [Member] | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Derivative Instrument, Gain (Loss) on Derivatives, Unsettled | (177) | (164) |
Derivative Instrument, Gain (Loss) on Derivatives, Settled | 208 | |
Purchased Put Options [Member] | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Derivative Instrument, Gain (Loss) on Derivatives, Settled | 11 | |
Two-way Costless-collars [Member] | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Derivative Instrument, Gain (Loss) on Derivatives, Unsettled | (48) | |
Derivative Instrument, Gain (Loss) on Derivatives, Settled | 3 | |
Three-way Costless-collars [Member] | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Derivative Instrument, Gain (Loss) on Derivatives, Unsettled | (81) | |
Derivative Instrument, Gain (Loss) on Derivatives, Settled | 1 | |
Basis Swaps [Member] | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Derivative Instrument, Gain (Loss) on Derivatives, Unsettled | 12 | (2) |
Derivative Instrument, Gain (Loss) on Derivatives, Settled | 21 | (2) |
Sold Call Options [Member] | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Derivative Instrument, Gain (Loss) on Derivatives, Unsettled | (81) | 13 |
Interest Rate Swaps [Member] | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Derivative Instrument, Gain (Loss) on Derivatives, Unsettled | 2 | (2) |
Derivative Instrument, Gain (Loss) on Derivatives, Settled | $ (2) | $ (4) |
Reclassifications From Accumu57
Reclassifications From Accumulated Other Comprehensive Income (Loss) (Components Of Accumulated Other Comprehensive Income (Loss)) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Beginning balance, December 31, 2015 | $ (48) | ||
Other comprehensive income (loss) before reclassifications | (4) | ||
Amounts reclassified from other comprehensive income (loss) | 13 | ||
Net current-period other comprehensive income (loss) | 9 | $ (110) | $ 66 |
Ending balance, December 31, 2016 | (39) | (48) | |
Pension And Other Postretirement [Member] | |||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Beginning balance, December 31, 2015 | (25) | ||
Other comprehensive income (loss) before reclassifications | (7) | ||
Amounts reclassified from other comprehensive income (loss) | 13 | ||
Net current-period other comprehensive income (loss) | 6 | ||
Ending balance, December 31, 2016 | (19) | (25) | |
Foreign Currency [Member] | |||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Beginning balance, December 31, 2015 | (23) | ||
Other comprehensive income (loss) before reclassifications | 3 | ||
Net current-period other comprehensive income (loss) | 3 | ||
Ending balance, December 31, 2016 | $ (20) | $ (23) |
Reclassifications From Accumu58
Reclassifications From Accumulated Other Comprehensive Income (Loss) (Amounts Reclassified From Accumulated Other Comprehensive Income (Loss)) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
General and administrative expenses | $ 247 | $ 246 | $ 221 |
Provision (benefit) for income taxes | (29) | (2,005) | 525 |
Net Income (Loss) | (2,643) | $ (4,556) | $ 924 |
Reclassification from Accumulated Other Comprehensive Income [Member] | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
Net Income (Loss) | 13 | ||
Pension And Other Postretirement [Member] | Reclassification from Accumulated Other Comprehensive Income [Member] | |||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | |||
General and administrative expenses | 21 | ||
Provision (benefit) for income taxes | 8 | ||
Net Income (Loss) | $ 13 |
Fair Value Measurements (Carryi
Fair Value Measurements (Carrying Amount And Estimated Fair Values Of Financial Instruments) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative instruments, net | $ (375) | $ (2) |
Carrying Amount [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Cash and cash equivalents | 1,423 | 15 |
Credit facility | 116 | |
Derivative instruments, net | (375) | (2) |
Fair Value [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Cash and cash equivalents | 1,423 | 15 |
Credit facility | 116 | |
Derivative instruments, net | (375) | (2) |
Unsecured Debt [Member] | Carrying Amount [Member] | Term Loan 1 due December 2020 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Loans | 327 | 750 |
Unsecured Debt [Member] | Carrying Amount [Member] | Term Loan 2 due December 2020 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Loans | 1,191 | |
Unsecured Debt [Member] | Fair Value [Member] | Term Loan 1 due December 2020 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Loans | 327 | $ 750 |
Unsecured Debt [Member] | Fair Value [Member] | Term Loan 2 due December 2020 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Loans | $ 1,191 | |
Long-term Debt [Member] | Term Loan 1 due December 2020 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Maturity date, year and month | 2020-12 | 2018-11 |
Accelerated maturity date, year and month if not amended, redeemed or refinanced | 2019-10 | |
Long-term Debt [Member] | Term Loan 2 due December 2020 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Maturity date, year and month | 2020-12 | |
Accelerated maturity date, year and month if not amended, redeemed or refinanced | 2019-10 | |
Long-term Debt [Member] | 2020 Senior Notes [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Maturity date, year and month | 2020-01 | |
Amount to be amended, redeemed or refinanced to avoid acceleration | $ 765 | |
Senior Notes [Member] | Carrying Amount [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Senior notes | 3,166 | $ 3,867 |
Senior Notes [Member] | Fair Value [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Senior notes | $ 3,182 | $ 2,672 |
Fair Value Measurements (Summar
Fair Value Measurements (Summary Of Assets And Liabilities Measured At Fair Value On Recurring Basis) (Details) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total | $ (375) | $ (2) |
Significant Other Observable Inputs (Level 2) [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total | (180) | (5) |
Significant Unobservable Inputs (Level 3) [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total | (195) | 3 |
Fixed Price Swaps [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative assets | 1 | |
Derivative liabilities | (178) | |
Fixed Price Swaps [Member] | Significant Other Observable Inputs (Level 2) [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative assets | 1 | |
Derivative liabilities | (178) | |
Two-way Costless-collars [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative assets | 10 | |
Derivative liabilities | (58) | |
Two-way Costless-collars [Member] | Significant Unobservable Inputs (Level 3) [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative assets | 10 | |
Derivative liabilities | (58) | |
Three-way Costless-collars [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative assets | 111 | |
Derivative liabilities | (192) | |
Three-way Costless-collars [Member] | Significant Unobservable Inputs (Level 3) [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative assets | 111 | |
Derivative liabilities | (192) | |
Basis Swaps [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative assets | 33 | 3 |
Derivative liabilities | (18) | |
Basis Swaps [Member] | Significant Unobservable Inputs (Level 3) [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative assets | 33 | 3 |
Derivative liabilities | (18) | |
Sold Call Options [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative liabilities | (81) | |
Sold Call Options [Member] | Significant Unobservable Inputs (Level 3) [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative liabilities | (81) | |
Interest Rate Swaps [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative liabilities | (3) | (5) |
Interest Rate Swaps [Member] | Significant Other Observable Inputs (Level 2) [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative liabilities | $ (3) | $ (5) |
Fair Value Measurements (Reconc
Fair Value Measurements (Reconciliations For Change In Net Fair Value Of Derivative Assets And Liabilities Measured At Fair Value On A Recurring Basis Using Significant Unobservable Inputs (Level 3)) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Fair Value Measurements [Abstract] | ||
Balance at beginning of period | $ 3 | $ (8) |
Included in earnings | (162) | 9 |
Settlements | (36) | 2 |
Transfers into/out of Level 3 | ||
Balance at end of period | (195) | 3 |
Change in gains (losses) included in earnings relating to derivatives still held as of December 31 | $ (198) | $ 11 |
Debt (2016 Credit Facility - Na
Debt (2016 Credit Facility - Narrative) (Details) | 1 Months Ended | 12 Months Ended | ||||
Jun. 30, 2016USD ($) | Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Dec. 31, 2013USD ($) | |
Debt Instrument [Line Items] | ||||||
Debt instrument | $ 4,684,000,000 | $ 4,733,000,000 | ||||
Amount outstanding | 0 | |||||
Long-term Debt [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Maximum borrowing capacity | $ 1,934,000,000 | |||||
Debt instrument | 4,643,000,000 | $ 4,732,000,000 | ||||
Long-term Debt [Member] | 2013 Credit Facility [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Maximum borrowing capacity | 66,000,000 | $ 2,000,000,000 | ||||
Repayment of line of credit | 285,000,000 | |||||
Amount outstanding | 0 | |||||
Long-term Debt [Member] | 2016 Credit Facility [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Maximum borrowing capacity | $ 743,000,000 | |||||
Long-term Debt [Member] | Letter of Credit [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Amount outstanding | $ 174,000,000 | |||||
Revolving Credit Facility And Term Loan Facility [Member] | Long-term Debt [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Maturity date, year and month | 2020-12 | |||||
Incremental increase EBITDAX to interest expense ratio | 0.25 | |||||
Revolving Credit Facility And Term Loan Facility [Member] | Long-term Debt [Member] | Minimum [Member] | ||||||
Debt Instrument [Line Items] | ||||||
EBITDAX to interest expense ratio | 0.75 | |||||
Liquidity requirement | $ 300,000,000 | |||||
Anti-hoarding provision, required unrestricted cash | $ 100,000,000 | |||||
Collateral coverage ratio | 1.50 | |||||
Revolving Credit Facility And Term Loan Facility [Member] | Long-term Debt [Member] | Minimum [Member] | Scenario, Forecast [Member] | ||||||
Debt Instrument [Line Items] | ||||||
EBITDAX to interest expense ratio | 1.50 | 1.50 | ||||
Revolving Credit Facility And Term Loan Facility [Member] | Long-term Debt [Member] | Maximum [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Liquidity requirement | $ 500,000,000 | |||||
Revolving Credit Facility And Term Loan Facility [Member] | Long-term Debt [Member] | Eurodollar [Member] | Minimum [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Basis points | 1.75% | |||||
Revolving Credit Facility And Term Loan Facility [Member] | Long-term Debt [Member] | Eurodollar [Member] | Maximum [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Basis points | 2.50% | |||||
Revolving Credit Facility And Term Loan Facility [Member] | Long-term Debt [Member] | Base Rate [Member] | Minimum [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Basis points | 0.75% | |||||
Revolving Credit Facility And Term Loan Facility [Member] | Long-term Debt [Member] | Base Rate [Member] | Maximum [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Basis points | 1.50% | |||||
Term Loan 2 due December 2020 [Member] | Long-term Debt [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Maximum borrowing capacity | $ 1,191,000,000 | |||||
Debt instrument | $ 1,191,000,000 | |||||
Maturity date, year and month | 2020-12 | |||||
Accelerated maturity date, year and month if not amended, redeemed or refinanced | 2019-10 | |||||
Term Loan 2 due December 2020 [Member] | Long-term Debt [Member] | Over LIBOR [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Basis points | 2.50% | |||||
2020 Senior Notes [Member] | Long-term Debt [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Maturity date, year and month | 2020-01 | |||||
Amount to be amended, redeemed or refinanced to avoid acceleration | $ 765,000,000 |
Debt (2013 Credit Facility - Na
Debt (2013 Credit Facility - Narrative) (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2016 | Jun. 30, 2016 | Dec. 31, 2013 | |
Debt Instrument [Line Items] | |||
Amount outstanding | $ 0 | ||
Adjusted debt capital structure, percentage | 34.00% | ||
Adjusted equity capital structure, percentage | 66.00% | ||
Long-term Debt [Member] | |||
Debt Instrument [Line Items] | |||
Maximum borrowing capacity | $ 1,934,000,000 | ||
Long-term Debt [Member] | 2013 Credit Facility [Member] | |||
Debt Instrument [Line Items] | |||
Maximum borrowing capacity | 66,000,000 | $ 2,000,000,000 | |
Credit facility, maturity date | Dec. 1, 2018 | ||
Amount outstanding | $ 0 | ||
Debt percentage of adjusted book capital structure covenant | 60.00% | ||
Long-term Debt [Member] | 2016 Credit Facility [Member] | |||
Debt Instrument [Line Items] | |||
Maximum borrowing capacity | 743,000,000 | ||
Term Loan 2 due December 2020 [Member] | Long-term Debt [Member] | |||
Debt Instrument [Line Items] | |||
Maximum borrowing capacity | $ 1,191,000,000 |
Debt (2015 Term Facility - Narr
Debt (2015 Term Facility - Narrative) (Details) $ in Millions | 1 Months Ended | 12 Months Ended | |||
Sep. 30, 2016USD ($)a | Jul. 31, 2016USD ($) | Nov. 30, 2015USD ($) | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | |
Debt Instrument [Line Items] | |||||
Payments on long-term debt | $ 1,175 | $ 500 | |||
Term Loan 1 due December 2020 [Member] | Long-term Debt [Member] | |||||
Debt Instrument [Line Items] | |||||
Loans payable | $ 750 | ||||
Debt instrument, term | 3 years | ||||
Payments on long-term debt | $ 48 | $ 375 | |||
Maturity date, year and month | 2020-12 | 2018-11 | |||
Accelerated maturity date, year and month if not amended, redeemed or refinanced | 2019-10 | ||||
Debt issuance costs | $ 3 | ||||
2020 Senior Notes [Member] | Long-term Debt [Member] | |||||
Debt Instrument [Line Items] | |||||
Payments on long-term debt | $ 48 | ||||
Maturity date, year and month | 2020-01 | ||||
Amount to be amended, redeemed or refinanced to avoid acceleration | $ 765 | ||||
Over LIBOR [Member] | Term Loan 1 due December 2020 [Member] | Long-term Debt [Member] | |||||
Debt Instrument [Line Items] | |||||
Basis points | 2.50% | ||||
West Virginia [Member] | |||||
Debt Instrument [Line Items] | |||||
Area of land sold | a | 55,000 |
Debt (Commercial Paper - Narrat
Debt (Commercial Paper - Narrative) (Details) - Unsecured Debt [Member] - USD ($) | 1 Months Ended | ||
Apr. 30, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | |
Commercial Paper [Member] | |||
Debt Instrument [Line Items] | |||
Maximum borrowing capacity | $ 2,000,000,000 | ||
Commercial paper | $ 0 | $ 0 | |
Commercial Paper [Member] | Maximum [Member] | |||
Debt Instrument [Line Items] | |||
Debt instrument, term | 397 days | ||
Commercial Paper And Revolving Credit Facility [Member] | |||
Debt Instrument [Line Items] | |||
Maximum borrowing capacity | $ 2,000,000,000 |
Debt (Senior Notes - Narrative)
Debt (Senior Notes - Narrative) (Details) - USD ($) $ in Millions | Dec. 19, 2014 | Jul. 31, 2016 | Jan. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Debt Instrument [Line Items] | ||||||
Net loss on extinguishment of debt | $ (51) | |||||
Unamortized debt expense | 28 | $ 24 | ||||
Long-term Debt [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Unamortized debt expense | 28 | 24 | ||||
Senior Notes [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Proceeds from issuance of debt | $ 2,200 | $ 2,200 | ||||
Purchase of note principal | $ 700 | |||||
Net loss on extinguishment of debt | (51) | |||||
Premium | 50 | |||||
Unamortized debt expense | $ 2 | |||||
Senior Notes [Member] | Over LIBOR [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Incremental increase in basis points resulting from downgrades | 0.25% | |||||
Incremental decrease in basis points resulting from upgrades | 0.25% | |||||
Increase in basis spread | 1.75% | |||||
Bridge Loan [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Bridge loan | $ 4,500 | $ 4,500 | $ 4,500 | |||
Debt instrument, term | 364 days | 364 days | 364 days | |||
Debt issuance costs | 47 | |||||
3.30% Senior Notes due January 2018 [Member] | Long-term Debt [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Stated interest rate | 5.05% | 3.30% | 3.30% | |||
Unamortized debt expense | $ 2 | |||||
3.30% Senior Notes due January 2018 [Member] | Senior Notes [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Senior notes | $ 350 | |||||
Stated interest rate | 3.30% | |||||
Percentage of face amount, sold to public | 99.949% | |||||
4.05% Senior Notes due January 2020 [Member] | Long-term Debt [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Stated interest rate | 5.80% | 4.05% | 4.05% | |||
Unamortized debt expense | $ 5 | $ 5 | ||||
4.05% Senior Notes due January 2020 [Member] | Senior Notes [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Senior notes | $ 850 | |||||
Stated interest rate | 4.05% | |||||
Percentage of face amount, sold to public | 99.897% | |||||
4.95% Senior Notes due January 2025 [Member] | Long-term Debt [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Stated interest rate | 6.70% | 4.95% | 4.95% | |||
Unamortized debt expense | $ 7 | $ 7 | ||||
4.95% Senior Notes due January 2025 [Member] | Senior Notes [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Senior notes | $ 1,000 | |||||
Stated interest rate | 4.95% | |||||
Percentage of face amount, sold to public | 99.782% | |||||
Maximum [Member] | 3.30% Senior Notes due January 2018 [Member] | Long-term Debt [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Stated interest rate | 5.30% | |||||
Maximum [Member] | 4.05% Senior Notes due January 2020 [Member] | Long-term Debt [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Stated interest rate | 6.05% | |||||
Maximum [Member] | 4.95% Senior Notes due January 2025 [Member] | Long-term Debt [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Stated interest rate | 6.95% |
Debt (Chesapeake Property Acqui
Debt (Chesapeake Property Acquisition Financing - Narrative) (Details) - USD ($) $ in Millions | Dec. 19, 2014 | Jul. 31, 2016 | Jan. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Senior Notes [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Proceeds from issuance of debt | $ 2,200 | $ 2,200 | ||||
Depositary Shares [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Proceeds from issuance of shares | 1,700 | |||||
Common Stock [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Proceeds from issuance of shares | $ 1,247 | 669 | ||||
Bridge Loan [Member] | ||||||
Debt Instrument [Line Items] | ||||||
Bridge loan | $ 4,500 | $ 4,500 | $ 4,500 | |||
Debt instrument, term | 364 days | 364 days | 364 days | |||
Repayment of debt | $ 4,500 |
Debt (Components Of Debt) (Deta
Debt (Components Of Debt) (Details) - USD ($) $ in Millions | 1 Months Ended | 12 Months Ended | |||
Sep. 30, 2016 | Jul. 31, 2016 | Jan. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | |
Debt Instrument [Line Items] | |||||
Debt Instrument | $ 4,684 | $ 4,733 | |||
Unamortized Issuance Cost | (28) | (24) | |||
Unamortized Debt Discount | (3) | (4) | |||
Total | 4,653 | 4,705 | |||
Payments on long-term debt | 1,175 | 500 | |||
Short-term Debt [Member] | |||||
Debt Instrument [Line Items] | |||||
Debt Instrument | 41 | 1 | |||
Unamortized Issuance Cost | |||||
Unamortized Debt Discount | |||||
Total | 41 | 1 | |||
Short-term Debt [Member] | 7.35% Senior Notes due October 2017 [Member] | |||||
Debt Instrument [Line Items] | |||||
Debt Instrument | 15 | ||||
Unamortized Issuance Cost | |||||
Unamortized Debt Discount | |||||
Total | $ 15 | ||||
Stated interest rate | 7.35% | ||||
Maturity date, year and month | 2017-10 | ||||
Short-term Debt [Member] | 7.125% Senior Notes due October 2017 [Member] | |||||
Debt Instrument [Line Items] | |||||
Debt Instrument | $ 25 | ||||
Unamortized Issuance Cost | |||||
Unamortized Debt Discount | |||||
Total | $ 25 | ||||
Stated interest rate | 7.125% | ||||
Maturity date, year and month | 2017-10 | ||||
Short-term Debt [Member] | 7.15% Senior Notes due June 2018 [Member] | |||||
Debt Instrument [Line Items] | |||||
Debt Instrument | $ 1 | 1 | |||
Unamortized Issuance Cost | |||||
Unamortized Debt Discount | |||||
Total | $ 1 | $ 1 | |||
Stated interest rate | 7.15% | 7.15% | |||
Maturity date, year and month | 2018-06 | 2018-06 | |||
Long-term Debt [Member] | |||||
Debt Instrument [Line Items] | |||||
Debt Instrument | $ 4,643 | $ 4,732 | |||
Unamortized Issuance Cost | (28) | (24) | |||
Unamortized Debt Discount | (3) | (4) | |||
Total | 4,612 | 4,704 | |||
Long-term Debt [Member] | Credit Facility [Member] | |||||
Debt Instrument [Line Items] | |||||
Debt Instrument | 116 | ||||
Unamortized Issuance Cost | |||||
Unamortized Debt Discount | |||||
Total | $ 116 | ||||
Credit facility, variable interest rate | 1.886% | ||||
Credit facility, maturity date | Dec. 1, 2018 | ||||
Long-term Debt [Member] | 7.35% Senior Notes due October 2017 [Member] | |||||
Debt Instrument [Line Items] | |||||
Debt Instrument | $ 15 | ||||
Unamortized Issuance Cost | |||||
Unamortized Debt Discount | |||||
Total | $ 15 | ||||
Stated interest rate | 7.35% | ||||
Maturity date, year and month | 2017-10 | ||||
Long-term Debt [Member] | 7.125% Senior Notes due October 2017 [Member] | |||||
Debt Instrument [Line Items] | |||||
Debt Instrument | $ 25 | ||||
Unamortized Issuance Cost | |||||
Unamortized Debt Discount | |||||
Total | $ 25 | ||||
Stated interest rate | 7.125% | ||||
Maturity date, year and month | 2017-10 | ||||
Long-term Debt [Member] | 3.30% Senior Notes due January 2018 [Member] | |||||
Debt Instrument [Line Items] | |||||
Debt Instrument | 38 | $ 350 | |||
Unamortized Issuance Cost | (2) | ||||
Unamortized Debt Discount | |||||
Total | $ 38 | $ 348 | |||
Stated interest rate | 5.05% | 3.30% | 3.30% | ||
Maturity date, year and month | 2018-01 | 2018-01 | |||
Payments on long-term debt | $ 312 | ||||
Long-term Debt [Member] | 7.50% Senior Notes due February 2018 [Member] | |||||
Debt Instrument [Line Items] | |||||
Debt Instrument | $ 212 | $ 600 | |||
Unamortized Issuance Cost | (2) | ||||
Unamortized Debt Discount | |||||
Total | $ 212 | $ 598 | |||
Stated interest rate | 7.50% | 7.50% | |||
Maturity date, year and month | 2018-02 | 2018-02 | |||
Payments on long-term debt | $ 388 | ||||
Long-term Debt [Member] | 7.15% Senior Notes due June 2018 [Member] | |||||
Debt Instrument [Line Items] | |||||
Debt Instrument | $ 25 | $ 26 | |||
Unamortized Issuance Cost | |||||
Unamortized Debt Discount | |||||
Total | $ 25 | $ 26 | |||
Stated interest rate | 7.15% | 7.15% | |||
Maturity date, year and month | 2018-06 | 2018-06 | |||
Long-term Debt [Member] | 4.05% Senior Notes due January 2020 [Member] | |||||
Debt Instrument [Line Items] | |||||
Debt Instrument | $ 850 | $ 850 | |||
Unamortized Issuance Cost | (5) | (5) | |||
Unamortized Debt Discount | (1) | ||||
Total | $ 845 | $ 844 | |||
Stated interest rate | 5.80% | 4.05% | 4.05% | ||
Maturity date, year and month | 2020-01 | 2020-01 | |||
Long-term Debt [Member] | 4.10% Senior Notes due March 2022 [Member] | |||||
Debt Instrument [Line Items] | |||||
Debt Instrument | $ 1,000 | $ 1,000 | |||
Unamortized Issuance Cost | (4) | (5) | |||
Unamortized Debt Discount | (1) | (1) | |||
Total | $ 995 | $ 994 | |||
Stated interest rate | 4.10% | 4.10% | |||
Maturity date, year and month | 2022-03 | 2022-03 | |||
Long-term Debt [Member] | 4.95% Senior Notes due January 2025 [Member] | |||||
Debt Instrument [Line Items] | |||||
Debt Instrument | $ 1,000 | $ 1,000 | |||
Unamortized Issuance Cost | (7) | (7) | |||
Unamortized Debt Discount | (2) | (2) | |||
Total | $ 991 | $ 991 | |||
Stated interest rate | 6.70% | 4.95% | 4.95% | ||
Maturity date, year and month | 2025-01 | 2025-01 | |||
Long-term Debt [Member] | Term Loan 1 due December 2020 [Member] | |||||
Debt Instrument [Line Items] | |||||
Debt Instrument | $ 327 | $ 750 | |||
Unamortized Issuance Cost | $ (0.4) | (2) | (3) | ||
Unamortized Debt Discount | |||||
Total | $ 325 | $ 747 | |||
Variable interest rate | 3.22% | 1.775% | |||
Maturity date, year and month | 2020-12 | 2018-11 | |||
Payments on long-term debt | 48 | $ 375 | |||
Accelerated maturity date, year and month if not amended, redeemed or refinanced | 2019-10 | ||||
Long-term Debt [Member] | Term Loan 2 due December 2020 [Member] | |||||
Debt Instrument [Line Items] | |||||
Debt Instrument | $ 1,191 | ||||
Unamortized Issuance Cost | (10) | ||||
Unamortized Debt Discount | |||||
Total | $ 1,181 | ||||
Variable interest rate | 3.22% | ||||
Maturity date, year and month | 2020-12 | ||||
Accelerated maturity date, year and month if not amended, redeemed or refinanced | 2019-10 | ||||
Long-term Debt [Member] | 2020 Senior Notes [Member] | |||||
Debt Instrument [Line Items] | |||||
Maturity date, year and month | 2020-01 | ||||
Payments on long-term debt | $ 48 | ||||
Amount to be amended, redeemed or refinanced to avoid acceleration | $ 765 | ||||
Senior Notes [Member] | |||||
Debt Instrument [Line Items] | |||||
Unamortized Issuance Cost | $ (2) | ||||
Senior Notes [Member] | 3.30% Senior Notes due January 2018 [Member] | |||||
Debt Instrument [Line Items] | |||||
Stated interest rate | 3.30% | ||||
Maturity date, year and month | 2018-01 | ||||
Senior Notes [Member] | 4.05% Senior Notes due January 2020 [Member] | |||||
Debt Instrument [Line Items] | |||||
Stated interest rate | 4.05% | ||||
Maturity date, year and month | 2020-01 | ||||
Senior Notes [Member] | 4.95% Senior Notes due January 2025 [Member] | |||||
Debt Instrument [Line Items] | |||||
Stated interest rate | 4.95% | ||||
Maturity date, year and month | 2025-01 | ||||
Over LIBOR [Member] | Senior Notes [Member] | |||||
Debt Instrument [Line Items] | |||||
Increase in basis spread | 1.75% |
Debt (Schedule Of Debt Maturiti
Debt (Schedule Of Debt Maturities) (Details) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Debt [Abstract] | ||
2,017 | $ 41 | |
2,018 | 275 | |
2,020 | 2,368 | |
Thereafter | 2,000 | |
Total | $ 4,684 | $ 4,733 |
Commitments And Contingencies70
Commitments And Contingencies (Narrative) (Details) | Nov. 17, 2015item | Sep. 30, 2015plaintiffitem | Dec. 31, 2016USD ($)item | Dec. 31, 2010USD ($) |
Commitments And Contingencies [Line Items] | ||||
Total future demand transportation charges due | $ 8,400,000,000 | |||
Obligation under transportation agreements | 8,429,000,000 | |||
Guarantee obligations relative to the firms transportation agreements and gathering project and services | $ 862,000,000 | |||
Lease expiration date | Dec. 31, 2027 | |||
Residual value guarantee liability | $ 4,000,000 | |||
Operating leases, future minimum payments, 2017 | 66,000,000 | |||
Operating leases, future minimum payments, 2018 | 52,000,000 | |||
Operating leases, future minimum payments, 2019 | 45,000,000 | |||
Operating leases, future minimum payments, 2020 | 35,000,000 | |||
Operating leases, future minimum payments, 2021 | 17,000,000 | |||
Operating leases, future minimum payments, thereafter | 14,000,000 | |||
Actual damages recoverable by plaintiff | $ 11,000,000 | |||
Disgorgement recoverable by plaintiff | $ 24,000,000 | |||
Indemnification liability | 0 | |||
Purchase Commitment [Member] | Access Capacity on Future Projects Concentration Risk [Member] | ||||
Commitments And Contingencies [Line Items] | ||||
Obligation under transportation agreements | $ 3,400,000,000 | |||
Arkansas Royalty Litigation [Member] | ||||
Commitments And Contingencies [Line Items] | ||||
Number of cases | item | 3 | |||
Arkansas Royalty Litigation [Member] | Arkansas State Court 2010 and 2013 [Member] | ||||
Commitments And Contingencies [Line Items] | ||||
Number of cases | item | 2 | |||
Arkansas Royalty Litigation [Member] | Federal Court 2014 [Member] | ||||
Commitments And Contingencies [Line Items] | ||||
Number of cases | item | 1 | |||
Number of alternative damages theories presented | item | 2 | |||
Loss contingency, range of possible loss, minimum | $ 100,000,000 | |||
Arkansas Royalty Litigation [Member] | Arkansas State Court 2015 [Member] | ||||
Commitments And Contingencies [Line Items] | ||||
Number of cases | item | 3 | |||
Number of plaintiffs | plaintiff | 248 | |||
Pending Regulatory Approval and/or Construction [Member] | ||||
Commitments And Contingencies [Line Items] | ||||
Obligation under transportation agreements | $ 3,362,000,000 | |||
Exploration and Production [Member] | Pressure Pumping Equipment [Member] | ||||
Commitments And Contingencies [Line Items] | ||||
Number of leases | item | 13 | |||
Aggregate annual lease payment | $ 8,000,000 | |||
Exploration and Production [Member] | Drilling Rigs [Member] | ||||
Commitments And Contingencies [Line Items] | ||||
Number of leases | item | 7 | |||
Lease expiration date | Dec. 31, 2021 | |||
Aggregate annual lease payment | $ 13,000,000 | |||
Exploration and Production [Member] | Maximum [Member] | Pressure Pumping Equipment [Member] | ||||
Commitments And Contingencies [Line Items] | ||||
Lease expiration date | Jan. 1, 2018 | |||
Exploration and Production [Member] | Minimum [Member] | Pressure Pumping Equipment [Member] | ||||
Commitments And Contingencies [Line Items] | ||||
Lease expiration date | Dec. 1, 2017 | |||
Midstream Services and E&P [Member] | ||||
Commitments And Contingencies [Line Items] | ||||
Operating leases, future minimum payments, 2017 | $ 16,000,000 | |||
Operating leases, future minimum payments, 2018 | 7,000,000 | |||
Operating leases, future minimum payments, 2019 | $ 3,000,000 |
Commitments And Contingencies71
Commitments And Contingencies (Schedule Of Future Obligation Under Transportation Agreements) (Details) $ in Millions | Dec. 31, 2016USD ($) |
Other Commitments [Line Items] | |
Less than 1 year | $ 627 |
1 to 3 years | 1,484 |
3 to 5 years | 1,275 |
5 to 8 years | 1,507 |
More than 8 years | 3,536 |
Total transportation charges | 8,429 |
Infrastructure Currently in Service [Member] | |
Other Commitments [Line Items] | |
Less than 1 year | 612 |
1 to 3 years | 1,158 |
3 to 5 years | 825 |
5 to 8 years | 829 |
More than 8 years | 1,643 |
Total transportation charges | 5,067 |
Pending Regulatory Approval and/or Construction [Member] | |
Other Commitments [Line Items] | |
Less than 1 year | 15 |
1 to 3 years | 326 |
3 to 5 years | 450 |
5 to 8 years | 678 |
More than 8 years | 1,893 |
Total transportation charges | $ 3,362 |
Income Taxes (Narrative) (Detai
Income Taxes (Narrative) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Income Taxes [Line Items] | |||
Effective tax rate | 1.00% | 31.00% | 36.00% |
Income tax benefit | $ 29 | $ 2,005 | $ (525) |
Cash paid for income taxes | (15) | (6) | 28 |
Net operating loss carryforward | 1,177 | 445 | |
Alternative minimum tax credit carryforward | 100 | 125 | |
Statutory depletion carryforward | 13 | ||
Increase in valuation allowance | 983 | ||
Windfalls included in net operating loss carryforwards but not reflected in deferred tax assets | 149 | ||
Unrecognized tax benefits related to alternative minimum tax | 17 | 37 | $ 44 |
Exploration Program in Canada [Member] | |||
Income Taxes [Line Items] | |||
Net operating loss carryforward | 35 | ||
State [Member] | |||
Income Taxes [Line Items] | |||
Net operating loss carryforward | 2,200 | ||
Federal [Member] | |||
Income Taxes [Line Items] | |||
Income tax refund received | 15 | ||
Net operating loss carryforward | $ 3,200 | ||
Minimum [Member] | |||
Income Taxes [Line Items] | |||
Net operating loss carryforwards expiration date | Jan. 1, 2029 | ||
Minimum [Member] | Exploration Program in Canada [Member] | |||
Income Taxes [Line Items] | |||
Net operating loss carryforwards expiration date | Jan. 1, 2030 | ||
Maximum [Member] | |||
Income Taxes [Line Items] | |||
Net operating loss carryforwards expiration date | Dec. 31, 2036 | ||
Accrued liability of interest related to uncertain tax position | $ 1 | ||
Maximum [Member] | Exploration Program in Canada [Member] | |||
Income Taxes [Line Items] | |||
Net operating loss carryforwards expiration date | Dec. 31, 2036 | ||
Maximum [Member] | State [Member] | |||
Income Taxes [Line Items] | |||
Cash paid for income taxes | $ 1 | $ 1 |
Income Taxes (Provision (Benefi
Income Taxes (Provision (Benefit) For Income Taxes) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Current: | |||
Federal | $ (6) | $ 1 | $ 11 |
State | (1) | (3) | 10 |
Total | (7) | (2) | 21 |
Deferred: | |||
Federal | (22) | (1,697) | 501 |
State | (304) | 2 | |
Foreign | (2) | 1 | |
Total | (22) | (2,003) | 504 |
Provision (Benefit) for Income Taxes | $ (29) | $ (2,005) | $ 525 |
Income Taxes (Reconciliation Of
Income Taxes (Reconciliation Of Provision For Income Taxes) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Income Taxes [Abstract] | |||
Expected provision (benefit) at federal statutory rate | $ (935) | $ (2,296) | $ 507 |
Increase (decrease) resulting from: | |||
State income taxes, net of federal income tax effect | (79) | (194) | 58 |
Nondeductible expenses | 3 | ||
State rate redetermination | (48) | ||
Change in uncertain tax positions | (19) | (7) | |
Change in valuation allowance | 1,002 | 495 | 5 |
Other | 2 | (3) | |
Provision (Benefit) for Income Taxes | $ (29) | $ (2,005) | $ 525 |
Income Taxes (Components Of Def
Income Taxes (Components Of Deferred Tax Balances) (Details) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Deferred tax liabilities: | ||
Differences between book and tax basis of property | $ 81 | $ 216 |
Other | 1 | 2 |
Total deferred tax liabilities | 82 | 218 |
Deferred tax assets | ||
Accrued compensation | 38 | 19 |
Alternative minimum tax credit carryforward | 100 | 125 |
Accrued pension costs | 19 | 19 |
Asset retirement obligations | 53 | 77 |
Net operating loss carryforward | 1,177 | 445 |
Derivative activity | 142 | |
Other | 29 | 26 |
Total deferred tax assets | 1,558 | 711 |
Valuation allowance | (1,476) | (493) |
Net deferred tax liability |
Income Taxes (Reconciliation 76
Income Taxes (Reconciliation Of Beginning And Ending Balances Of Unrecognized Tax Benefits) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Income Taxes [Abstract] | ||
Unrecognized tax benefits at beginning of period | $ 37 | $ 44 |
Additions based on tax positions related to the current year | 7 | |
Additions to tax positions of prior years | ||
Reductions to tax positions of prior years | (20) | (14) |
Unrecognized tax benefits at end of period | $ 17 | $ 37 |
Asset Retirement Obligations (S
Asset Retirement Obligations (Schedule Of Asset Retirement Obligations) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Asset Retirement Obligations [Line Items] | ||
Asset retirement obligation at January 1 | $ 201 | $ 207 |
Accretion of discount | 10 | 11 |
Obligations incurred | 1 | 17 |
Obligations settled/removed | (45) | (30) |
Revisions of estimates | (26) | (4) |
Asset retirement obligation at December 31 | 141 | 201 |
Current liability | 6 | 10 |
Long-term liability | 135 | 191 |
Asset retirement obligation | 141 | 201 |
Asset Divestitures [Member] | ||
Asset Retirement Obligations [Line Items] | ||
Obligations settled/removed | $ (35) | $ (25) |
Retirement And Employee Benef78
Retirement And Employee Benefit Plans (Narrative) (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||
Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Defined Benefit Plan Disclosure [Line Items] | |||||
Defined benefit plan included in accumulated other comprehensive income (loss), before tax | $ (31) | $ (42) | |||
Defined benefit plan included in accumulated other comprehensive income (loss), after tax | (19) | (25) | |||
Classified to accumulated other comprehensive income (loss) | 6 | $ (1) | $ (15) | ||
Expected future net loss | (1) | ||||
Company's expected additional annual contribution | $ 15 | ||||
Common Stock in Treasury, Shares | 31,269 | 47,149 | |||
401 (k) Defined Contribution Plan [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Contribution expense | $ 4 | $ 3 | 3 | ||
Contributions capitalized | 2 | 4 | 3 | ||
Pension Benefits [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Non-cash curtailment gain (loss) | $ (1) | (1) | |||
Settlement loss | (11) | ||||
Lump-sum payment | 37 | ||||
Net periodic benefit cost (gain) | 24 | 15 | 12 | ||
Change in accumulated other comprehensive income (loss) | 7 | (2) | |||
Change in accumulated other comprehensive income (loss) after tax | 4 | (2) | |||
Employer contributions | 10 | 12 | |||
Benefit obligation | $ 117 | $ 138 | 134 | ||
Discount rate | 4.20% | 4.60% | |||
Other Postretirement Benefits [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Non-cash curtailment gain (loss) | $ 6 | $ 6 | |||
Settlement loss | |||||
Net periodic benefit cost (gain) | (3) | 4 | 3 | ||
Change in accumulated other comprehensive income (loss) | 3 | 1 | |||
Change in accumulated other comprehensive income (loss) after tax | 2 | 1 | |||
Employer contributions | 1 | ||||
Benefit obligation | $ 13 | $ 20 | $ 18 | ||
Discount rate | 4.20% | 4.60% |
Retirement And Employee Benef79
Retirement And Employee Benefit Plans (Changes In The Plans Benefit Obligations, Fair Value Of Assets, And Funded Status) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Pension Benefits [Member] | |||
Change in benefit obligations: | |||
Benefit obligation at January 1 | $ 138 | $ 134 | |
Service cost | 11 | 16 | $ 13 |
Interest cost | 5 | 6 | 5 |
Participant contributions | |||
Actuarial loss (gain) | 14 | (7) | |
Benefits paid | (3) | (11) | |
Plan amendments | |||
Curtailments | (8) | ||
Settlements | (40) | ||
Benefit obligation at December 31 | 117 | 138 | 134 |
Change in plan assets: | |||
Fair value of plan assets at January 1 | 108 | 108 | |
Actual return on plan assets | 3 | (1) | |
Employer contributions | 10 | 12 | |
Participant contributions | |||
Benefits paid | (3) | (11) | |
Settlements | (37) | ||
Fair value of plan assets at December 31 | 81 | 108 | 108 |
Funded status of plans at December 31 | (36) | (30) | |
Other Postretirement Benefits [Member] | |||
Change in benefit obligations: | |||
Benefit obligation at January 1 | 20 | 18 | |
Service cost | 2 | 3 | 2 |
Interest cost | 1 | 1 | 1 |
Participant contributions | |||
Actuarial loss (gain) | (2) | (2) | |
Benefits paid | (1) | ||
Plan amendments | |||
Curtailments | (7) | ||
Settlements | |||
Benefit obligation at December 31 | 13 | 20 | 18 |
Change in plan assets: | |||
Fair value of plan assets at January 1 | |||
Actual return on plan assets | |||
Employer contributions | 1 | ||
Participant contributions | |||
Benefits paid | (1) | ||
Settlements | |||
Fair value of plan assets at December 31 | |||
Funded status of plans at December 31 | $ (13) | $ (20) |
Retirement And Employee Benef80
Retirement And Employee Benefit Plans (Projected Benefit Obligation, Accumulated Benefit Obligation And Fair Value Of Plan Assets) (Details) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Retirement And Employee Benefit Plans [Abstract] | ||
Projected benefit obligation | $ 117 | $ 138 |
Accumulated benefit obligation | 116 | 135 |
Fair value of plan assets | $ 81 | $ 108 |
Retirement And Employee Benef81
Retirement And Employee Benefit Plans (Pension And Other Postretirement Benefit Costs) (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||
Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Pension Benefits [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Service cost | $ 11 | $ 16 | $ 13 | ||
Interest cost | 5 | 6 | 5 | ||
Expected return on plan assets | (6) | (9) | (7) | ||
Amortization of transition obligation | |||||
Amortization of prior service cost | |||||
Amortization of net loss | 2 | 2 | 1 | ||
Net periodic benefit cost | 12 | 15 | 12 | ||
Curtailment loss | $ 1 | 1 | |||
Settlement loss | 11 | ||||
Total benefit cost (benefit) | 24 | 15 | 12 | ||
Other Postretirement Benefits [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Service cost | 2 | 3 | 2 | ||
Interest cost | 1 | 1 | 1 | ||
Expected return on plan assets | |||||
Amortization of transition obligation | |||||
Amortization of prior service cost | |||||
Amortization of net loss | |||||
Net periodic benefit cost | 3 | 4 | 3 | ||
Curtailment loss | $ (6) | (6) | |||
Settlement loss | |||||
Total benefit cost (benefit) | $ (3) | $ 4 | $ 3 |
Retirement And Employee Benef82
Retirement And Employee Benefit Plans (Amounts Recognized In Other Comprehensive Income) (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2016USD ($) | |
Pension Benefits [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Net actuarial (loss) gain arising during the year | $ (13) |
Amortization of prior service cost | |
Amortization of net loss | 20 |
Settlements | |
Tax effect | (3) |
Total | 4 |
Other Postretirement Benefits [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Net actuarial (loss) gain arising during the year | 2 |
Amortization of prior service cost | |
Amortization of net loss | |
Settlements | 1 |
Tax effect | (1) |
Total | $ 2 |
Retirement And Employee Benef83
Retirement And Employee Benefit Plans (Schedule Of Assumptions Used - Benefit Obligations) (Details) | Dec. 31, 2016 | Dec. 31, 2015 |
Pension Benefits [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Discount rate | 4.20% | 4.60% |
Rate of compensation increase | 3.50% | 3.50% |
Other Postretirement Benefits [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Discount rate | 4.20% | 4.60% |
Retirement And Employee Benef84
Retirement And Employee Benefit Plans (Schedule Of Assumptions Used - Benefit Obligations - Net Periodic Benefit Cost) (Details) | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Pension Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Discount rate | 4.20% | 4.25% | 5.00% |
Expected return on plan assets | 7.00% | 7.00% | 7.00% |
Rate of compensation increase | 3.50% | 4.50% | 4.50% |
Other Postretirement Benefits [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Discount rate | 4.20% | 4.25% | 5.00% |
Retirement And Employee Benef85
Retirement And Employee Benefit Plans (Schedule Of Health Care Cost Trend Rates) (Details) | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Retirement And Employee Benefit Plans [Abstract] | ||
Health care cost trend assumed for next year | 7.00% | 8.00% |
Rate to which the cost trend is assumed to decline | 5.00% | 5.00% |
Year that the rate reaches the ultimate trend rate | 2,034 | 2,034 |
Retirement And Employee Benef86
Retirement And Employee Benefit Plans (One Percentage Point Change In Assumed Health Care Cost Trend Rates) (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2016USD ($) | |
Retirement And Employee Benefit Plans [Abstract] | |
Effect on total service and interest cost components, 1% Increase | |
Effect on total service and interest cost components, 1% Decrease | |
Effect on postretirement benefit obligations, 1% Increase | 2 |
Effect on postretirement benefit obligation, 1% Decrease | $ (2) |
Retirement And Employee Benef87
Retirement And Employee Benefit Plans (Schedule Of Expected Benefit Payments) (Details) $ in Millions | Dec. 31, 2016USD ($) |
Pension Benefits [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
2,017 | $ 8 |
2,018 | 6 |
2,019 | 6 |
2,020 | 7 |
2,021 | 8 |
Years 2022-2026 | 46 |
Other Postretirement Benefits [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
2,017 | 1 |
2,018 | 1 |
2,019 | 1 |
2,020 | 1 |
2,021 | 1 |
Years 2022-2026 | $ 6 |
Retirement And Employee Benef88
Retirement And Employee Benefit Plans (Schedule Of Allocation Of Plan Assets) (Details) - Pension Benefits [Member] | 12 Months Ended |
Dec. 31, 2016 | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations | 100.00% |
Actual asset allocations | 100.00% |
Fixed Income [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations | 28.00% |
Actual asset allocations | 25.00% |
Cash and Cash Equivalents [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations | 2.00% |
Actual asset allocations | 5.00% |
U.S. Equity [Member] | Equity Securities [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations | 35.00% |
Actual asset allocations | 36.00% |
Non-U.S. Equity [Member] | Equity Securities [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations | 30.00% |
Actual asset allocations | 28.00% |
Emerging Markets Equity [Member] | Equity Securities [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations | 5.00% |
Actual asset allocations | 6.00% |
Opportunistic Securities [Member] | Equity Securities [Member] | |
Defined Benefit Plan Disclosure [Line Items] | |
Target asset allocations | |
Actual asset allocations |
Retirement And Employee Benef89
Retirement And Employee Benefit Plans (Fair Value Measurement Of Pension Plan Assets) (Details) - Pension Benefits [Member] - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | $ 81 | $ 108 | $ 108 |
Quoted Prices in Active Markets (Level 1) [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 67 | 59 | |
Excluding Net Assets Value [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 67 | 59 | |
Net Asset Value [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 14 | 49 | |
Equity Securities [Member] | U.S. Large Cap Growth Equity [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 6 | 9 | |
Equity Securities [Member] | U.S. Large Cap Growth Equity [Member] | Quoted Prices in Active Markets (Level 1) [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 6 | 9 | |
Equity Securities [Member] | U.S. Large Cap Value Equity [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 6 | 9 | |
Equity Securities [Member] | U.S. Large Cap Value Equity [Member] | Quoted Prices in Active Markets (Level 1) [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 6 | 9 | |
Equity Securities [Member] | U.S. Large Cap Core Equity [Member] | Net Asset Value [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 14 | 18 | |
Equity Securities [Member] | U.S. Small Cap Equity [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 3 | 3 | |
Equity Securities [Member] | U.S. Small Cap Equity [Member] | Quoted Prices in Active Markets (Level 1) [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 3 | 3 | |
Equity Securities [Member] | Non-U.S. Equity [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 23 | 31 | |
Equity Securities [Member] | Non-U.S. Equity [Member] | Quoted Prices in Active Markets (Level 1) [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 23 | 31 | |
Equity Securities [Member] | Emerging Markets Equity [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 4 | 5 | |
Equity Securities [Member] | Emerging Markets Equity [Member] | Quoted Prices in Active Markets (Level 1) [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 4 | 5 | |
Fixed Income [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 21 | ||
Fixed Income [Member] | Quoted Prices in Active Markets (Level 1) [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 21 | ||
Fixed Income [Member] | Net Asset Value [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 31 | ||
Cash and Cash Equivalents [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | 4 | 2 | |
Cash and Cash Equivalents [Member] | Quoted Prices in Active Markets (Level 1) [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Fair value of plan assets | $ 4 | $ 2 |
Stock-Based Compensation (Narra
Stock-Based Compensation (Narrative) (Details) - USD ($) $ / shares in Units, $ in Millions | 1 Months Ended | 3 Months Ended | 12 Months Ended | ||
Jan. 31, 2016 | Mar. 31, 2016 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Period of service for immediate vesting upon death, disability or retirement | 3 years | ||||
2004 Plan [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Maximum shares | 16,800,000 | ||||
Expiration period from date of grant | 7 years | ||||
2013 Plan [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Expiration period from date of grant | 7 years | ||||
2002 Plan [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Maximum shares | 300,000 | ||||
Expiration period from date of grant | 10 years | ||||
2000 Plan [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Maximum shares | 1,250,000 | ||||
Unvested Stock Options [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Vesting period for stock awards from grant date | 3 years | ||||
Deferred tax asset (liability) recorded | $ 2 | $ 2 | $ 3 | ||
Unrecognized compensation cost related to the Company's unvested stock option grants, restricted stock grants, and performance units | $ 4 | ||||
Weighted average period over which cost is recognized, years | 2 years | ||||
Weighted-average grant-date fair value of options granted | $ 3.22 | $ 3.16 | $ 10.16 | ||
Stock options, exercised, number of options | 45,000 | 0 | 402,000 | ||
Intrinsic value | $ 4 | ||||
Stock-based compensation costs - expensed | $ 6 | $ 5 | 5 | ||
Restricted Stock [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Vesting period for stock awards from grant date | 4 years | ||||
Deferred tax asset (liability) recorded | $ 12 | 11 | (10) | ||
Unrecognized compensation cost related to the Company's unvested stock option grants, restricted stock grants, and performance units | $ 37 | ||||
Weighted average period over which cost is recognized, restricted stock (years) | 2 years | ||||
Total fair value of restricted stock grants | $ 1 | 47 | 40 | ||
Total fair value of shares vested | 43 | 29 | 20 | ||
Stock-based compensation costs - expensed | 33 | 14 | 10 | ||
Equity-Classified Performance Units [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Deferred tax asset (liability) recorded | 4 | 4 | 2 | ||
Unrecognized compensation cost related to the Company's unvested stock option grants, restricted stock grants, and performance units | $ 9 | ||||
Weighted average period over which cost is recognized, years | 2 years | ||||
Stock-based compensation costs - expensed | $ 9 | $ 6 | $ 3 | ||
Liability-Classified Performance Units [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Vesting period for stock awards from grant date | 3 years | ||||
Maximum [Member] | 2013 Plan [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Maximum shares | 33,850,000 | ||||
Maximum [Member] | Unvested Stock Options [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Intrinsic value | $ 1 | ||||
Workforce Reduction [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Positions eliminated, percent | 40.00% | 40.00% | |||
Workforce Reduction [Member] | Restricted Stock [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Stock-based compensation costs - expensed | 16 | ||||
Workforce Reduction [Member] | Maximum [Member] | Unvested Stock Options [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Stock-based compensation costs - expensed | 1 | ||||
Workforce Reduction [Member] | Maximum [Member] | Equity-Classified Performance Units [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Stock-based compensation costs - expensed | $ 1 |
Stock-Based Compensation (Sched
Stock-Based Compensation (Schedule Of Stock-Based Compensation Costs) (Details) - Unvested Stock Options [Member] - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Stock-based compensation costs - expensed | $ 6 | $ 5 | $ 5 |
Stock-based compensation costs - capitalized | 1 | $ 3 | $ 4 |
Workforce Reduction [Member] | Maximum [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Stock-based compensation costs - expensed | 1 | ||
Executive Management [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Stock-based compensation costs - expensed | $ 1 |
Stock-Based Compensation (Sch92
Stock-Based Compensation (Schedule Of Valuation Assumptions) (Details) | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Stock-Based Compensation [Abstract] | |||
Risk-free interest rate | 1.40% | 1.70% | 1.60% |
Expected dividend yield | |||
Expected volatility | 41.00% | 36.00% | 32.50% |
Expected term | 5 years | 5 years | 5 years |
Stock-Based Compensation (Summa
Stock-Based Compensation (Summary Of Stock Option Activity) (Details) - $ / shares | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock options, Outstanding at December 31, Number of Options | 5,416,000 | ||
Stock options, Exercisable at December 31, Number of Options | 3,428,000 | ||
Stock options, Outstanding at December 31, Weighted Average Exercise Price | $ 23.46 | ||
Unvested Stock Options [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock options, Outstanding at January 1, Number of Options | 5,623,000 | 3,622,000 | 3,313,000 |
Stock options, Granted, Number of Options | 155,000 | 2,401,000 | 835,000 |
Stock options, Exercised, Number of Options | (45,000) | 0 | (402,000) |
Stock options, Forfeited or expired, Number of Options | (317,000) | (400,000) | (124,000) |
Stock options, Outstanding at December 31, Number of Options | 5,416,000 | 5,623,000 | 3,622,000 |
Stock options, Outstanding at January 1, Weighted Average Exercise Price | $ 24.57 | $ 35.41 | $ 35.70 |
Stock options, Granted, Weighted Average Exercise Price | 8.60 | 9.47 | 32.31 |
Stock options, Exercised, Weighted Average Exercise Price | 7.74 | 30.60 | |
Stock options, Forfeited or expired, Weighted Average Exercise Price | 38.01 | 32.20 | 37.80 |
Stock options, Outstanding at December 31, Weighted Average Exercise Price | $ 23.46 | $ 24.57 | $ 35.41 |
Stock-Based Compensation (Sum94
Stock-Based Compensation (Summary Of Restricted Stock Activity) (Details) - Restricted Stock [Member] - $ / shares | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Unvested shares/units at January 1, Number of Shares | 7,222,000 | 2,376,000 | 1,771,000 |
Granted, Number of Shares/Units | 81,000 | 5,822,000 | 1,295,000 |
Vested, Number of Shares/Units | (3,817,000) | (873,000) | (548,000) |
Forfeited, Number of Shares/Units | (165,000) | (103,000) | (142,000) |
Unvested shares/units at December 31, Number of Shares | 3,321,000 | 7,222,000 | 2,376,000 |
Unvested shares/units at January 1, Weighted Average Fair Value | $ 13.24 | $ 34 | $ 37.55 |
Granted, Weighted Average Fair Value | 8.56 | 8.07 | 30.89 |
Vested, Weighted Average Fair Value | 11.34 | 33.33 | 37.12 |
Forfeited, Weighted Average Fair Value | 12.05 | 29.14 | 37.91 |
Unvested shares at December 31, Weighted Average Fair Value | $ 11.85 | $ 13.24 | $ 34 |
Workforce Reduction [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Vested, Number of Shares/Units | (2,059,626) | ||
Executive Management [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Vested, Number of Shares/Units | (151,575) |
Stock-Based Compensation (Sum95
Stock-Based Compensation (Summary Of Stock Options Outstanding And Options Exercisable) (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Options Outstanding - Options Outstanding at December 31, 2016 | 5,416 | |||
Options Outstanding - Weighted Average Exercise Price | $ 23.46 | |||
Options Outstanding - Weighted Average Remaining Contractual Life (Years) | 4 years 4 months 24 days | |||
Options Outstanding - Aggregate Intrinsic Value | $ 7 | |||
Options Exercisable - Options Exercisable at December 31, 2016 | 3,428 | |||
Options Exercisable - Weighted Average Exercise Price | $ 29.80 | |||
Options Exercisable - Weighted Average Remaining Contractual Life (Years) | 3 years 7 months 6 days | |||
Options Exercisable - Aggregate Intrinsic Value | $ 2 | |||
Unvested Stock Options [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Options Outstanding - Options Outstanding at December 31, 2016 | 5,416 | 5,623 | 3,622 | 3,313 |
Options Outstanding - Weighted Average Exercise Price | $ 23.46 | $ 24.57 | $ 35.41 | $ 35.70 |
Range of Exercise Prices $7.74-$29.69 [Member] | Unvested Stock Options [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Range of Exercise Prices, Lower Range Limit | 7.74 | |||
Range of Exercise Prices, Upper Range Limit | $ 29.69 | |||
Options Outstanding - Options Outstanding at December 31, 2016 | 2,501 | |||
Options Outstanding - Weighted Average Exercise Price | $ 9.54 | |||
Options Outstanding - Weighted Average Remaining Contractual Life (Years) | 5 years 10 months 24 days | |||
Options Exercisable - Options Exercisable at December 31, 2016 | 781 | |||
Options Exercisable - Weighted Average Exercise Price | $ 9.77 | |||
Options Exercisable - Weighted Average Remaining Contractual Life (Years) | 5 years 9 months 18 days | |||
Range of Exercise Prices $30.59-$35.91 [Member] | Unvested Stock Options [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Range of Exercise Prices, Lower Range Limit | $ 30.59 | |||
Range of Exercise Prices, Upper Range Limit | $ 35.91 | |||
Options Outstanding - Options Outstanding at December 31, 2016 | 1,384 | |||
Options Outstanding - Weighted Average Exercise Price | $ 32.32 | |||
Options Outstanding - Weighted Average Remaining Contractual Life (Years) | 3 years 10 months 24 days | |||
Options Exercisable - Options Exercisable at December 31, 2016 | 1,146 | |||
Options Exercisable - Weighted Average Exercise Price | $ 32.68 | |||
Options Exercisable - Weighted Average Remaining Contractual Life (Years) | 3 years 8 months 12 days | |||
Range of Exercise Prices $36.22-$39.68 [Member] | Unvested Stock Options [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Range of Exercise Prices, Lower Range Limit | $ 36.22 | |||
Range of Exercise Prices, Upper Range Limit | $ 39.68 | |||
Options Outstanding - Options Outstanding at December 31, 2016 | 1,402 | |||
Options Outstanding - Weighted Average Exercise Price | $ 37.49 | |||
Options Outstanding - Weighted Average Remaining Contractual Life (Years) | 2 years 4 months 24 days | |||
Options Exercisable - Options Exercisable at December 31, 2016 | 1,402 | |||
Options Exercisable - Weighted Average Exercise Price | $ 37.49 | |||
Options Exercisable - Weighted Average Remaining Contractual Life (Years) | 2 years 4 months 24 days | |||
Range of Exercise Prices $40.15-$51.47 [Member] | Unvested Stock Options [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Range of Exercise Prices, Lower Range Limit | $ 40.15 | |||
Range of Exercise Prices, Upper Range Limit | $ 51.47 | |||
Options Outstanding - Options Outstanding at December 31, 2016 | 129 | |||
Options Outstanding - Weighted Average Exercise Price | $ 45.79 | |||
Options Outstanding - Weighted Average Remaining Contractual Life (Years) | 3 years 3 months 18 days | |||
Options Exercisable - Options Exercisable at December 31, 2016 | 99 | |||
Options Exercisable - Weighted Average Exercise Price | $ 45.57 | |||
Options Exercisable - Weighted Average Remaining Contractual Life (Years) | 3 years |
Stock-Based Compensation (Sch96
Stock-Based Compensation (Schedule Of Stock-Based Compensation Costs - Restricted Stock) (Details) - Restricted Stock [Member] - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation costs - expensed | $ 33 | $ 14 | $ 10 |
Stock-based compensation costs - capitalized | 8 | $ 16 | $ 12 |
Workforce Reduction [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation costs - expensed | 16 | ||
Executive Management [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation costs - expensed | $ 1 |
Stock-Based Compensation (Sch97
Stock-Based Compensation (Schedule Of Stock-Based Compensation Costs - Equity-Classified Performance Units) (Details) - Equity-Classified Performance Units [Member] - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation costs - expensed | $ 9 | $ 6 | $ 3 |
Stock-based compensation costs - capitalized | 1 | $ 4 | $ 2 |
Workforce Reduction [Member] | Maximum [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation costs - expensed | 1 | ||
Executive Management [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation costs - expensed | $ 1 |
Stock-Based Compensation (Sum98
Stock-Based Compensation (Summary Of Equity-Classified Performance Units) (Details) - Equity-Classified Performance Units [Member] - $ / shares | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Unvested shares/units at January 1, Number of Shares | 407,000 | 223,000 | |
Granted, Number of Shares/Units | 1,503,000 | 443,000 | 359,000 |
Vested, Number of Shares/Units | (889,000) | (259,000) | (111,000) |
Forfeited, Number of Shares/Units | (302,000) | (25,000) | |
Unvested shares/units at December 31, Number of Shares | 719,000 | 407,000 | 223,000 |
Unvested shares/units at January 1, Weighted Average Fair Value | $ 36.65 | $ 40.44 | |
Granted, Weighted Average Fair Value | 8.60 | 35.22 | 40.44 |
Vested, Weighted Average Fair Value | 12.78 | 37.46 | 40.44 |
Forfeited, Weighted Average Fair Value | 11.26 | 40.44 | |
Unvested shares at December 31, Weighted Average Fair Value | $ 11.46 | $ 36.65 | $ 40.44 |
Minimum [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Granted, Number of Shares/Units | 0 | ||
Maximum [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Granted, Number of Shares/Units | 2 | ||
Share-based Compensation Award, Tranche One [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period | 3 years | ||
Vesting period for stock awards from grant date | 3 years | ||
Workforce Reduction [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Vested, Number of Shares/Units | (22,918) | ||
Forfeited, Number of Shares/Units | (87,595) | ||
Executive Management [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Vested, Number of Shares/Units | (37,590) | ||
Forfeited, Number of Shares/Units | (195,834) |
Segment Information (Details)
Segment Information (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | ||||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Segment Reporting Information [Line Items] | ||||||||||||
Revenues | $ 684 | $ 651 | $ 522 | $ 579 | $ 687 | $ 749 | $ 764 | $ 933 | $ 2,436 | $ 3,133 | $ 4,038 | |
Depreciation, depletion and amortization expense | 436 | 1,091 | 942 | |||||||||
Impairment of natural gas and oil properties | 0 | 817 | 470 | 1,034 | 2,576 | 2,839 | 1,535 | 2,321 | 6,950 | |||
Operating income (loss) | 122 | $ (725) | $ (492) | $ (1,100) | (2,561) | $ (2,842) | $ (1,284) | $ 165 | (2,195) | (6,522) | 1,373 | |
Interest expense | 88 | 56 | 59 | |||||||||
Gain (loss) on derivatives | (339) | 47 | 139 | |||||||||
Loss on Early Extinguishment of Debt | (51) | |||||||||||
Other income (loss), net | 1 | (30) | (4) | |||||||||
Provision (benefit) for income taxes | (29) | (2,005) | 525 | |||||||||
Assets | 7,076 | 8,086 | 7,076 | 8,086 | 14,915 | |||||||
Capital investments | 648 | 2,437 | 7,447 | |||||||||
Restructuring charges | 78 | |||||||||||
Cash and cash equivalents | 1,423 | 15 | 1,423 | 15 | 53 | $ 23 | ||||||
Change in accrued expenditures | (43) | 33 | (155) | |||||||||
Gain on sale of assets, net | 283 | |||||||||||
Intersegment Eliminations [Member] | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||
Revenues | (1,546) | (2,060) | (3,182) | |||||||||
Exploration and Production [Member] | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||
Revenues | 1,435 | 2,095 | 2,850 | |||||||||
Depreciation, depletion and amortization expense | 371 | 1,028 | 884 | |||||||||
Impairment of natural gas and oil properties | 2,321 | 6,950 | ||||||||||
Operating income (loss) | (2,404) | (7,104) | 1,013 | |||||||||
Interest expense | 87 | 47 | 47 | |||||||||
Gain (loss) on derivatives | (338) | 51 | 142 | |||||||||
Other income (loss), net | 5 | (21) | (3) | |||||||||
Provision (benefit) for income taxes | (29) | (2,273) | 402 | |||||||||
Assets | 4,178 | 6,588 | 4,178 | 6,588 | 13,018 | |||||||
Capital investments | 623 | 2,258 | 7,254 | |||||||||
Restructuring and other one-time charges | 86 | |||||||||||
Exploration and Production [Member] | Intersegment Eliminations [Member] | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||
Revenues | 22 | 21 | (12) | |||||||||
Midstream Services [Member] | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||
Revenues | 1,001 | 1,038 | 1,188 | |||||||||
Depreciation, depletion and amortization expense | 65 | 62 | 58 | |||||||||
Operating income (loss) | 209 | 583 | 361 | |||||||||
Interest expense | 1 | 9 | 12 | |||||||||
Gain (loss) on derivatives | (1) | (1) | ||||||||||
Other income (loss), net | (2) | (9) | (1) | |||||||||
Provision (benefit) for income taxes | 268 | 123 | ||||||||||
Assets | 1,331 | 1,290 | 1,331 | 1,290 | 1,554 | |||||||
Capital investments | 21 | 167 | 144 | |||||||||
Restructuring charges | 3 | |||||||||||
Gain on sale of assets, net | 277 | |||||||||||
Midstream Services [Member] | Intersegment Eliminations [Member] | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||
Revenues | (1,568) | (2,081) | (3,170) | |||||||||
Other [Member] | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||
Depreciation, depletion and amortization expense | 1 | |||||||||||
Operating income (loss) | (1) | (1) | ||||||||||
Gain (loss) on derivatives | (4) | (2) | ||||||||||
Loss on Early Extinguishment of Debt | (51) | |||||||||||
Other income (loss), net | (2) | |||||||||||
Assets | $ 1,567 | $ 208 | 1,567 | 208 | 343 | |||||||
Capital investments | 4 | 12 | 49 | |||||||||
Marketing [Member] | Midstream Services [Member] | Intersegment Eliminations [Member] | ||||||||||||
Segment Reporting Information [Line Items] | ||||||||||||
Revenues | $ (1,300) | $ (1,800) | $ (2,800) |
Supplemental Quarterly Resul100
Supplemental Quarterly Results (Details) - USD ($) $ / shares in Units, $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Quarterly Financial Data [Line Items] | |||||||||||
Operating revenues | $ 684 | $ 651 | $ 522 | $ 579 | $ 687 | $ 749 | $ 764 | $ 933 | $ 2,436 | $ 3,133 | $ 4,038 |
Operating income (loss) | 122 | (725) | (492) | (1,100) | (2,561) | (2,842) | (1,284) | 165 | (2,195) | (6,522) | 1,373 |
Net income (loss) attributable to common stock | $ (237) | $ (735) | $ (620) | $ (1,159) | $ (2,134) | $ (1,766) | $ (815) | $ 46 | $ (2,751) | $ (4,662) | $ 924 |
Earnings (Loss) per share - Basic | $ (0.48) | $ (1.52) | $ (1.61) | $ (3.03) | $ (5.58) | $ (4.62) | $ (2.13) | $ 0.12 | $ (6.32) | $ (12.25) | $ 2.63 |
Earnings (Loss) per share - Diluted | $ (0.48) | $ (1.52) | $ (1.61) | $ (3.03) | $ (5.58) | $ (4.62) | $ (2.13) | $ 0.12 | $ (6.32) | $ (12.25) | $ 2.62 |
Impairment of natural gas and oil properties | $ 0 | $ 817 | $ 470 | $ 1,034 | $ 2,576 | $ 2,839 | $ 1,535 | $ 2,321 | $ 6,950 | ||
Series B Preferred Stock [Member] | |||||||||||
Quarterly Financial Data [Line Items] | |||||||||||
Participating securities - mandatory convertible preferred stock | $ 7 |
Supplemental Oil And Gas Dis101
Supplemental Oil And Gas Disclosures (Narrative) (Details) ft³ in Thousands, $ in Millions | 12 Months Ended | 120 Months Ended | 156 Months Ended | |||||||
Dec. 31, 2016USD ($)$ / bbl$ / MMBTUsiteft³ | Dec. 31, 2015USD ($)$ / bbl$ / MMBTUsiteft³ | Dec. 31, 2014USD ($)a$ / bbl$ / MMBTUsiteft³ | Dec. 31, 2013USD ($)ft³ | Dec. 31, 2016USD ($)siteft³ | Sep. 30, 2016USD ($) | Jun. 30, 2016USD ($) | Mar. 31, 2016USD ($) | Sep. 30, 2015USD ($) | Jun. 30, 2015USD ($) | |
Natural Gas and Oil Properties [Line Items] | ||||||||||
Natural gas, oil and NGL reserves discount | 10.00% | 10.00% | 10.00% | |||||||
Period of time needed to calculate ceiling value of reserves | 12 months | 12 months | 12 months | |||||||
Cash flow hedges impact on ceiling value, net of tax | $ | $ 40 | $ 60 | ||||||||
Net unevaluated costs excluded from amortization | $ | $ 147 | $ 332 | $ 1,535 | $ 91 | $ 2,105 | |||||
Impairment of natural gas and oil properties, net of tax | $ | $ 506 | $ 297 | $ 641 | $ 1,746 | $ 944 | |||||
Percentage of present worth of proved reserves evaluated in audit | 99.00% | 100.00% | 97.00% | |||||||
Capitalized interest based on weighted average cost of borrowings | $ | $ 152 | $ 204 | $ 55 | |||||||
Capitalized internal costs related to acquisition, exploration and development | $ | 112 | 307 | 320 | |||||||
Capitalized internal costs related to acquisition, exploration and development activities - subsidiaries | $ | $ 19 | $ 118 | $ 123 | |||||||
Proved developed and undeveloped reserves | 5,253,000,000 | 6,215,000,000 | 10,747,000,000 | 6,976,000,000 | 5,253,000,000 | |||||
Production | 875,000,000 | 976,000,000 | 768,000,000 | |||||||
Production volumes replaced with proved reserve additions, net upward revisions and acquisitions, percentage | 550.00% | |||||||||
Extensions, discoveries and other additions | 282,000,000 | 592,000,000 | 1,693,000,000 | |||||||
Net revisions | (354,000,000) | (4,083,000,000) | 543,000,000 | |||||||
Undeveloped Properties Marcellus Shale [Member] | ||||||||||
Natural Gas and Oil Properties [Line Items] | ||||||||||
Net unevaluated costs excluded from amortization | $ | $ 94 | |||||||||
Undeveloped Properties New Ventures - Excluding Canada [Member] | ||||||||||
Natural Gas and Oil Properties [Line Items] | ||||||||||
Net unevaluated costs excluded from amortization | $ | 100 | |||||||||
Wells In Progress [Member] | ||||||||||
Natural Gas and Oil Properties [Line Items] | ||||||||||
Net unevaluated costs excluded from amortization | $ | $ 113 | |||||||||
Southwest Appalachia [Member] | ||||||||||
Natural Gas and Oil Properties [Line Items] | ||||||||||
Proved developed and undeveloped reserves | 677,000,000 | 611,000,000 | 2,297,000,000 | 677,000,000 | ||||||
Production | 148,000,000 | 143,000,000 | 3,000,000 | |||||||
Extensions, discoveries and other additions | 157,000,000 | 88,000,000 | ||||||||
Net revisions | 72,000,000 | (1,666,000,000) | ||||||||
Other Properties [Member] | ||||||||||
Natural Gas and Oil Properties [Line Items] | ||||||||||
Proved developed and undeveloped reserves | 5,000,000 | 4,000,000 | 190,000,000 | 218,000,000 | 5,000,000 | |||||
Production | 2,000,000 | 8,000,000 | 17,000,000 | |||||||
Extensions, discoveries and other additions | 1,000,000 | 2,000,000 | ||||||||
Net revisions | 3,000,000 | 1,000,000 | (15,000,000) | |||||||
Undeveloped Properties, Various Locations [Member] | ||||||||||
Natural Gas and Oil Properties [Line Items] | ||||||||||
Natural gas, oil and NGL reserves discount | 10.00% | 10.00% | 10.00% | |||||||
Proved undeveloped reserves | 77,000,000 | 217,000,000 | 181,000,000 | 77,000,000 | ||||||
Number of locations | site | 15 | 75 | 60 | 15 | ||||||
Present value of proved reserves, discounted basis | $ | $ (11) | $ (34) | $ (28) | $ (11) | ||||||
Proved reserves, committed development period | 5 years | |||||||||
Chesapeake and Statoil Property Acquisitions [Member] | ||||||||||
Natural Gas and Oil Properties [Line Items] | ||||||||||
Net unevaluated costs excluded from amortization | $ | $ 1,600 | |||||||||
Chesapeake Property Acquisition [Member] | ||||||||||
Natural Gas and Oil Properties [Line Items] | ||||||||||
Area of land purchased | a | 413,000 | |||||||||
Chesapeake Property Acquisition [Member] | Southwest Appalachia [Member] | ||||||||||
Natural Gas and Oil Properties [Line Items] | ||||||||||
Area of land purchased | a | 413,000 | |||||||||
Natural Gas [Member] | ||||||||||
Natural Gas and Oil Properties [Line Items] | ||||||||||
Average market prices used in reserves | $ / MMBTU | 2.48 | 2.59 | 4.35 | |||||||
Oil [Member] | ||||||||||
Natural Gas and Oil Properties [Line Items] | ||||||||||
Average market prices used in reserves | $ / bbl | 39.25 | 46.79 | 91.48 | |||||||
NGL [Member] | ||||||||||
Natural Gas and Oil Properties [Line Items] | ||||||||||
Full cost ceiling test, price | $ / bbl | 6.74 | 6.82 | 23.79 | |||||||
Impairment of natural gas and oil properties, net of tax | $ | $ 1,586 | |||||||||
Average market prices used in reserves | $ / MMBTU | 6.74 | 6.82 | 23.79 | |||||||
Natural Gas and Oil [Member] | ||||||||||
Natural Gas and Oil Properties [Line Items] | ||||||||||
Proved developed and undeveloped reserves | 5,253,000,000 | 6,215,000,000 | 5,253,000,000 | |||||||
Synthetic Gas, Synthetic Oil or Nonrenewable Natural Resources [Member] | ||||||||||
Natural Gas and Oil Properties [Line Items] | ||||||||||
Proved developed and undeveloped reserves | 0 | 0 |
Supplemental Oil And Gas Dis102
Supplemental Oil And Gas Disclosures (Capitalized Costs Relating To Oil And Gas Producing Activities Disclosure) (Details) - USD ($) $ in Millions | Dec. 31, 2016 | Dec. 31, 2015 |
Supplemental Oil And Gas Disclosures [Abstract] | ||
Proved properties | $ 20,548 | $ 18,751 |
Unproved properties | 2,105 | 3,727 |
Total capitalized costs | 22,653 | 22,478 |
Less: Accumulated depreciation, depletion and amortization | (18,897) | (16,248) |
Net capitalized costs | $ 3,756 | $ 6,230 |
Supplemental Oil And Gas Dis103
Supplemental Oil And Gas Disclosures (Composition Of Net Unevaluated Costs Excluded From Amortization) (Details) - USD ($) $ in Millions | 12 Months Ended | 120 Months Ended | 156 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2016 | |
Supplemental Oil And Gas Disclosures [Abstract] | |||||
Property acquisition costs | $ 22 | $ 213 | $ 1,501 | $ 54 | $ 1,790 |
Exploration and development costs | 55 | 64 | 24 | 16 | 159 |
Capitalized interest | 70 | 55 | 10 | 21 | 156 |
Net unevaluated costs excluded from amortization | $ 147 | $ 332 | $ 1,535 | $ 91 | $ 2,105 |
Supplemental Oil And Gas Dis104
Supplemental Oil And Gas Disclosures (Cost Incurred In Oil And Gas Property Acquisition, Exploration, And Development Activities Disclosure) (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016USD ($)$ / ft³ | Dec. 31, 2015USD ($)$ / ft³ | Dec. 31, 2014USD ($)$ / ft³ | |
Supplemental Oil And Gas Disclosures [Abstract] | |||
Proved property acquisition costs | $ 81 | $ 1,455 | |
Unproved property acquisition costs | $ 171 | 692 | 3,934 |
Exploration costs | 17 | 50 | 232 |
Development costs | 433 | 1,417 | 1,600 |
Capitalized costs incurred | $ 621 | $ 2,240 | $ 7,221 |
Full cost pool amortization per Mcfe | $ / ft³ | 0.38 | 1 | 1.10 |
Supplemental Oil And Gas Dis105
Supplemental Oil And Gas Disclosures (Results Of Operations For Oil And Gas Producing Activities Disclosure) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items] | |||
Sales | $ 1,413 | $ 2,074 | $ 2,862 |
Production (lifting) costs | (839) | (989) | (776) |
Depreciation, depletion and amortization | (371) | (1,028) | (884) |
Impairment of natural gas and oil properties | (2,321) | (6,950) | |
Results of operations - income before income taxes | (2,118) | (6,893) | 1,202 |
Provision (benefit) for income taxes | (2,619) | 457 | |
Results of operations | (2,118) | $ (4,274) | $ 745 |
Prior to Recognition of Valuation Allowance [Member] | |||
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items] | |||
Provision (benefit) for income taxes | $ 805 |
Supplemental Oil And Gas Dis106
Supplemental Oil And Gas Disclosures (Summary Of Changes In Reserves - United States) (Details) ft³ in Billions | 12 Months Ended | ||
Dec. 31, 2016MBblsft³ | Dec. 31, 2015MBblsft³ | Dec. 31, 2014MBblsft³ | |
Reserve Quantities [Line Items] | |||
Proved reserves, beginning of year | ft³ | 6,215 | 10,747 | 6,976 |
Revisions of previous estimates | ft³ | (354) | (4,083) | 543 |
Extensions, discoveries and other additions | ft³ | 282 | 592 | 1,693 |
Production | ft³ | (875) | (976) | (768) |
Acquisition of reserves in place | ft³ | 115 | 2,303 | |
Disposition of reserves in place | ft³ | (15) | (180) | |
Proved reserves, end of year | ft³ | 5,253 | 6,215 | 10,747 |
United States [Member] | Natural Gas [Member] | |||
Reserve Quantities [Line Items] | |||
Proved reserves, beginning of year | ft³ | 5,917 | 9,809 | 6,974 |
Revisions of previous estimates | ft³ | (446) | (3,458) | 542 |
Extensions, discoveries and other additions | ft³ | 198 | 546 | 1,692 |
Production | ft³ | (788) | (899) | (766) |
Acquisition of reserves in place | ft³ | 97 | 1,367 | |
Disposition of reserves in place | ft³ | (15) | (178) | |
Proved reserves, end of year | ft³ | 4,866 | 5,917 | 9,809 |
Proved developed reserves: | |||
Beginning of year | ft³ | 5,474 | 5,675 | 4,237 |
End of year | ft³ | 4,789 | 5,474 | 5,675 |
Proved undeveloped reserves: | |||
Beginning of year | ft³ | 443 | 4,134 | 2,737 |
End of year | ft³ | 77 | 443 | 4,134 |
United States [Member] | Oil [Member] | |||
Reserve Quantities [Line Items] | |||
Proved reserves, beginning of year | 8,753 | 37,615 | 373 |
Revisions of previous estimates | 1,564 | (28,394) | (14) |
Extensions, discoveries and other additions | 2,417 | 1,367 | 250 |
Production | (2,192) | (2,265) | (235) |
Acquisition of reserves in place | 525 | 37,246 | |
Disposition of reserves in place | (19) | (95) | (5) |
Proved reserves, end of year | 10,523 | 8,753 | 37,615 |
Proved developed reserves: | |||
Beginning of year | 8,753 | 7,445 | 372 |
End of year | 10,523 | 8,753 | 7,445 |
Proved undeveloped reserves: | |||
Beginning of year | 30,170 | 1 | |
End of year | 30,170 | ||
United States [Member] | NGL [Member] | |||
Reserve Quantities [Line Items] | |||
Proved reserves, beginning of year | 40,947 | 118,699 | |
Revisions of previous estimates | 13,794 | (75,664) | 66 |
Extensions, discoveries and other additions | 11,576 | 6,274 | 48 |
Production | (12,372) | (10,702) | (231) |
Acquisition of reserves in place | 2,340 | 118,816 | |
Disposition of reserves in place | (14) | ||
Proved reserves, end of year | 53,931 | 40,947 | 118,699 |
Proved developed reserves: | |||
Beginning of year | 40,947 | 38,632 | |
End of year | 53,931 | 40,947 | 38,632 |
Proved undeveloped reserves: | |||
Beginning of year | 80,067 | ||
End of year | 80,067 |
Supplemental Oil And Gas Dis107
Supplemental Oil And Gas Disclosures (Summary Of Changes In Reserves) (Details) - ft³ ft³ in Billions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Reserve Quantities [Line Items] | |||
Proved reserves, beginning of year | 6,215 | 10,747 | 6,976 |
Production | (875) | (976) | (768) |
Disposition of reserves in place | (15) | (180) | |
Acquisition of reserves in place | 115 | 2,303 | |
Price revisions | (1,037) | (5,718) | 54 |
Performance and production revisions | 683 | 1,635 | 489 |
Total net revisions | (354) | (4,083) | 543 |
Proved developed | 257 | 416 | 531 |
Proved undeveloped | 25 | 176 | 1,162 |
Total reserve additions | 282 | 592 | 1,693 |
Proved reserves, end of year | 5,253 | 6,215 | 10,747 |
Northeast Appalachia [Member] | |||
Reserve Quantities [Line Items] | |||
Proved reserves, beginning of year | 2,319 | 3,191 | 1,963 |
Production | (350) | (360) | (254) |
Disposition of reserves in place | |||
Acquisition of reserves in place | 80 | 1 | |
Price revisions | (794) | (2,315) | 10 |
Performance and production revisions | 318 | 1,383 | 636 |
Total net revisions | (476) | (932) | 646 |
Proved developed | 81 | 202 | 246 |
Proved undeveloped | 138 | 589 | |
Total reserve additions | 81 | 340 | 835 |
Proved reserves, end of year | 1,574 | 2,319 | 3,191 |
Southwest Appalachia [Member] | |||
Reserve Quantities [Line Items] | |||
Proved reserves, beginning of year | 611 | 2,297 | |
Production | (148) | (143) | (3) |
Disposition of reserves in place | (15) | ||
Acquisition of reserves in place | 35 | 2,300 | |
Price revisions | (127) | (1,875) | |
Performance and production revisions | 199 | 209 | |
Total net revisions | 72 | (1,666) | |
Proved developed | 157 | 84 | |
Proved undeveloped | 4 | ||
Total reserve additions | 157 | 88 | |
Proved reserves, end of year | 677 | 611 | 2,297 |
Fayetteville Shale [Member] | |||
Reserve Quantities [Line Items] | |||
Proved reserves, beginning of year | 3,281 | 5,069 | 4,795 |
Production | (375) | (465) | (494) |
Disposition of reserves in place | |||
Acquisition of reserves in place | |||
Price revisions | (116) | (1,496) | 38 |
Performance and production revisions | 163 | 10 | (126) |
Total net revisions | 47 | (1,486) | (88) |
Proved developed | 19 | 129 | 283 |
Proved undeveloped | 25 | 34 | 573 |
Total reserve additions | 44 | 163 | 856 |
Proved reserves, end of year | 2,997 | 3,281 | 5,069 |
Other Properties [Member] | |||
Reserve Quantities [Line Items] | |||
Proved reserves, beginning of year | 4 | 190 | 218 |
Production | (2) | (8) | (17) |
Disposition of reserves in place | (180) | ||
Acquisition of reserves in place | 2 | ||
Price revisions | (32) | 6 | |
Performance and production revisions | 3 | 33 | (21) |
Total net revisions | 3 | 1 | (15) |
Proved developed | 1 | 2 | |
Proved undeveloped | |||
Total reserve additions | 1 | 2 | |
Proved reserves, end of year | 5 | 4 | 190 |
Supplemental Oil And Gas Dis108
Supplemental Oil And Gas Disclosures (Standardized Measure Of Discounted Future Cash Flows Relating To Proved Reserves Disclosure) (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Supplemental Oil And Gas Disclosures [Abstract] | ||||
Future cash inflows | $ 9,064 | $ 11,887 | $ 41,812 | |
Future production costs | (5,880) | (7,376) | (16,477) | |
Future development costs | (485) | (792) | (5,750) | |
Future income tax expense | (4,743) | |||
Future net cash flows | 2,699 | 3,719 | 14,842 | |
10% annual discount for estimated timing of cash flows | (1,034) | (1,302) | (7,299) | |
Standardized measure of discounted future net cash flows | $ 1,665 | $ 2,417 | $ 7,543 | $ 3,736 |
Annual discount for estimated timing of cash flows percent | 10.00% | 10.00% | 10.00% |
Supplemental Oil And Gas Dis109
Supplemental Oil And Gas Disclosures (Schedule Of Analysis Of Changes In Standardized Measure) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Supplemental Oil And Gas Disclosures [Abstract] | |||
Standardized measure, beginning of year | $ 2,417 | $ 7,543 | $ 3,736 |
Sales and transfers of natural gas and oil produced, net of production costs | (574) | (1,082) | (2,084) |
Net changes in prices and production costs | (415) | (8,075) | 1,192 |
Extensions, discoveries, and other additions, net of future production and development costs | 45 | 162 | 1,049 |
Acquisition of reserves in place | 28 | 1,897 | |
Sales of reserves in place | (10) | (244) | |
Revisions of previous quantity estimates | (140) | (1,385) | 622 |
Accretion of discount | 242 | 946 | 513 |
Net change in income taxes | 1,915 | (522) | |
Changes in estimated future development costs | 71 | 2,007 | 110 |
Previously estimated development costs incurred during the year | 114 | 875 | 815 |
Changes in production rates (timing) and other | (85) | (273) | 215 |
Standardized measure, end of year | $ 1,665 | $ 2,417 | $ 7,543 |