Document And Entity Information
Document And Entity Information - USD ($) | 12 Months Ended | ||
Dec. 31, 2017 | Feb. 14, 2018 | Jun. 30, 2017 | |
Document And Entity Information [Abstract] | |||
Entity Registrant Name | Pioneer Natural Resources Company | ||
Trading Symbol | PXD | ||
Entity Central Index Key | 1,038,357 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Filer Category | Large Accelerated Filer | ||
Document Type | 10-K | ||
Document Period End Date | Dec. 31, 2017 | ||
Document Fiscal Year Focus | 2,017 | ||
Document Fiscal Period Focus | FY | ||
Amendment Flag | false | ||
Entity Common Stock, Shares Outstanding | 170,300,825 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Public Float | $ 26,939,176,465 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Current assets: | ||
Cash and cash equivalents | $ 896 | $ 1,118 |
Short-term investments | 1,218 | 1,441 |
Accounts receivable: | ||
Trade, net | 639 | 517 |
Due from affiliates | 1 | 1 |
Income taxes receivable | 7 | 3 |
Inventories | 212 | 181 |
Derivatives | 11 | 14 |
Other | 26 | 23 |
Total current assets | 3,010 | 3,298 |
Oil and gas properties, using the successful efforts method of accounting: | ||
Proved properties | 20,404 | 18,566 |
Unproved properties | 558 | 486 |
Accumulated depletion, depreciation and amortization | (9,196) | (8,211) |
Total property, plant and equipment | 11,766 | 10,841 |
Long-term investments | 66 | 420 |
Goodwill | 270 | 272 |
Other property and equipment, net | 1,759 | 1,529 |
Other assets, net | 132 | 99 |
Total Assets | 17,003 | 16,459 |
Accounts payable: | ||
Trade | 1,174 | 741 |
Due to affiliates | 108 | 134 |
Interest payable | 59 | 68 |
Current portion of long-term debt | 449 | 485 |
Derivatives | 232 | 77 |
Other | 106 | 61 |
Total current liabilities | 2,128 | 1,566 |
Long-term debt | 2,283 | 2,728 |
Derivatives | 23 | 7 |
Deferred income taxes | 899 | 1,397 |
Other liabilities | 391 | 350 |
Equity: | ||
Common stock, $.01 par value | 2 | 2 |
Additional paid-in capital | 8,974 | 8,892 |
Treasury stock, at cost | (249) | (218) |
Retained earnings | 2,547 | 1,728 |
Total equity attributable to common stockholders | 11,274 | 10,404 |
Noncontrolling interest in consolidated subsidiaries | 5 | 7 |
Total equity | 11,279 | 10,411 |
Commitments and contingencies | ||
Total Liabilities and Stockholders' Equity | $ 17,003 | $ 16,459 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - $ / shares | Dec. 31, 2017 | Dec. 31, 2016 |
Statement of Financial Position [Abstract] | ||
Common stock, par value | $ 0.01 | $ 0.01 |
Common stock, shares authorized | 500,000,000 | 500,000,000 |
Common stock, shares issued | 173,796,743 | 173,221,845 |
Treasury stock, shares | 3,608,132 | 3,497,742 |
Consolidated Statements Of Oper
Consolidated Statements Of Operations - USD ($) shares in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Revenues and other income: | |||
Oil and gas | $ 3,518 | $ 2,418 | $ 2,178 |
Sales of purchased oil and gas | 1,776 | 1,091 | 700 |
Interest and other | 53 | 32 | 22 |
Derivative gains (losses), net | (100) | (161) | 879 |
Gain on disposition of assets, net | 208 | 2 | 782 |
Revenues | 5,455 | 3,382 | 4,561 |
Costs and expenses: | |||
Oil and gas production | 591 | 581 | 717 |
Production and ad valorem taxes | 215 | 136 | 145 |
Depletion, depreciation and amortization | 1,400 | 1,480 | 1,385 |
Purchased oil and gas | 1,807 | 1,155 | 739 |
Impairment of oil and gas properties | 285 | 32 | 1,056 |
Exploration and abandonments | 106 | 119 | 99 |
General and administrative | 326 | 325 | 327 |
Accretion of discount on asset retirement obligations | 19 | 18 | 12 |
Interest | 153 | 207 | 187 |
Other | 244 | 288 | 315 |
Costs and Expenses | 5,146 | 4,341 | 4,982 |
Income (loss) from continuing operations before income taxes | 309 | (959) | (421) |
Income tax benefit | 524 | 403 | 155 |
Income (loss) from continuing operations | 833 | (556) | (266) |
Loss from discontinued operations, net of tax | 0 | 0 | (7) |
Net income (loss) attributable to common stockholders | $ 833 | $ (556) | $ (273) |
Basic net income (loss) per share attributable to common stockholders: | |||
Income (loss) from continuing operations (usd per share) | $ 4.86 | $ (3.34) | $ (1.79) |
Loss from discontinued operations (usd per share) | 0 | 0 | (0.04) |
Net income (loss) (usd per share) | 4.86 | (3.34) | (1.83) |
Diluted net income (loss) per share attributable to common stockholders: | |||
Income (loss) from continuing operations (usd per share) | 4.85 | (3.34) | (1.79) |
Loss from discontinued operations (usd per share) | 0 | 0 | (0.04) |
Net income (loss) (usd per share) | $ 4.85 | $ (3.34) | $ (1.83) |
Basic and diluted weighted average shares outstanding | 170 | 166 | 149 |
Consolidated Statements Of Stoc
Consolidated Statements Of Stockholders' Equity - USD ($) shares in Thousands, $ in Millions | Total | Common Stock | Additional Paid-in Capital | Treasury Stock | Retained Earnings | Noncontrolling Interests |
Beginning Balance at Dec. 31, 2014 | $ 8,589 | $ 2 | $ 6,167 | $ (171) | $ 2,583 | $ 8 |
Beginning Balance, shares at Dec. 31, 2014 | 148,905 | |||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||
Dividends declared ($0.08 per share) | (12) | (12) | ||||
Exercise of long-term incentive plan stock options and employee stock purchases | 6 | 3 | 3 | |||
Exercise of long-term incentive plan stock options and employee stock purchases, shares | 58 | |||||
Purchase of treasury stock | (31) | (31) | ||||
Purchase of treasury stock, shares | (201) | |||||
Tax benefits related to stock-based compensation | 7 | 7 | ||||
Compensation costs: | ||||||
Vested compensation awards, net | 0 | |||||
Vested compensation awards, net, shares | 618 | |||||
Compensation costs included in net loss | 90 | 90 | ||||
Distributions to noncontrolling interests | (1) | (1) | ||||
Net income (loss) | (273) | (273) | ||||
Ending Balance at Dec. 31, 2015 | 8,375 | $ 2 | 6,267 | (199) | 2,298 | 7 |
Ending Balance, shares at Dec. 31, 2015 | 149,380 | |||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||
Issuance of common stock | 2,534 | 2,534 | ||||
Issuance of common stock, shares | 19,838 | |||||
Dividends declared ($0.08 per share) | (14) | (14) | ||||
Exercise of long-term incentive plan stock options and employee stock purchases | 7 | 1 | 6 | |||
Exercise of long-term incentive plan stock options and employee stock purchases, shares | 98 | |||||
Purchase of treasury stock | (25) | (25) | ||||
Purchase of treasury stock, shares | (200) | |||||
Tax benefits related to stock-based compensation | 1 | 1 | ||||
Compensation costs: | ||||||
Vested compensation awards, net | 0 | |||||
Vested compensation awards, net, shares | 608 | |||||
Compensation costs included in net loss | 89 | 89 | ||||
Net income (loss) | (556) | (556) | ||||
Ending Balance at Dec. 31, 2016 | 10,411 | $ 2 | 8,892 | (218) | 1,728 | 7 |
Ending Balance, shares at Dec. 31, 2016 | 169,724 | |||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||
Dividends declared ($0.08 per share) | (14) | (14) | ||||
Exercise of long-term incentive plan stock options and employee stock purchases | 6 | 1 | 5 | |||
Exercise of long-term incentive plan stock options and employee stock purchases, shares | 81 | |||||
Purchase of treasury stock | (36) | (36) | ||||
Purchase of treasury stock, shares | (191) | |||||
Compensation costs: | ||||||
Vested compensation awards, net | 0 | |||||
Vested compensation awards, net, shares | 575 | |||||
Compensation costs included in net loss | 79 | 79 | ||||
Purchase of noncontrolling interest | 2 | 2 | ||||
Net income (loss) | 833 | 833 | ||||
Ending Balance at Dec. 31, 2017 | $ 11,279 | $ 2 | $ 8,974 | $ (249) | $ 2,547 | $ 5 |
Ending Balance, shares at Dec. 31, 2017 | 170,189 |
Consolidated Statements Of Sto6
Consolidated Statements Of Stockholders' Equity (Parenthetical) - $ / shares | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Statement of Stockholders' Equity [Abstract] | |||
Dividends declared (usd per share) | $ 0.08 | $ 0.08 | $ 0.08 |
Consolidated Statements Of Cash
Consolidated Statements Of Cash Flows - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Cash flows from operating activities: | |||
Net income (loss) | $ 833 | $ (556) | $ (273) |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||
Depletion, depreciation and amortization | 1,400 | 1,480 | 1,385 |
Impairment of oil and gas properties | 285 | 32 | 1,056 |
Impairment of inventory and other property and equipment | 2 | 8 | 86 |
Exploration expenses, including dry holes | 22 | 42 | 28 |
Deferred income taxes | (519) | (379) | (178) |
Gain on disposition of assets, net | (208) | (2) | (782) |
Accretion of discount on asset retirement obligations | 19 | 18 | 12 |
Adjustment Income Loss From Discontinued Operations Net Of Tax | 0 | 0 | (4) |
Interest expense | 5 | 13 | 18 |
Derivative related activity | 174 | 851 | (3) |
Amortization of stock-based compensation | 79 | 89 | 90 |
Other | 74 | 67 | 45 |
Change in operating assets and liabilities | |||
Accounts receivable | (122) | (134) | 54 |
Income taxes receivable | (4) | 40 | (20) |
Inventories | (35) | (32) | 8 |
Derivatives | 0 | (24) | 0 |
Investments | 8 | (22) | 0 |
Other current assets | (3) | (7) | 0 |
Accounts payable | 134 | 58 | (258) |
Interest payable | (9) | 3 | 25 |
Other current liabilities | (45) | (46) | (34) |
Net cash provided by operating activities | 2,090 | 1,499 | 1,255 |
Cash flows from investing activities: | |||
Proceeds from disposition of assets, net of cash sold | 352 | 507 | 553 |
Payments for acquisitions | 0 | (428) | 0 |
Proceeds from investments | 1,465 | 902 | 0 |
Purchase of investments | (899) | (2,741) | 0 |
Additions to oil and gas properties | (2,365) | (1,857) | (2,110) |
Additions to other assets and other property and equipment, net | (336) | (203) | (283) |
Net cash used in investing activities | (1,783) | (3,820) | (1,840) |
Cash flows from financing activities: | |||
Borrowings of long-term debt | 0 | 0 | 998 |
Principal payments on long-term debt | (485) | (455) | 0 |
Proceeds from issuance of common stock, net of issuance costs | 0 | 2,534 | 0 |
Distributions to noncontrolling interests | 0 | 0 | (1) |
Exercise of long-term incentive plan stock options and employee stock purchases | 6 | 7 | 6 |
Purchases of treasury stock | (36) | (25) | (31) |
Payments of financing fees | 0 | 0 | (9) |
Dividends paid | (14) | (13) | (12) |
Net cash provided by (used in) financing activities | (529) | 2,048 | 951 |
Net increase (decrease) in cash and cash equivalents | (222) | (273) | 366 |
Cash and cash equivalents, beginning of period | 1,118 | 1,391 | 1,025 |
Cash and cash equivalents, end of period | $ 896 | $ 1,118 | $ 1,391 |
Organization And Nature Of Oper
Organization And Nature Of Operations | 12 Months Ended |
Dec. 31, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Organization and Nature of Operations | Organization and Nature of Operations Pioneer Natural Resources Company ("Pioneer" or the "Company") is a Delaware corporation whose common stock is listed and traded on the New York Stock Exchange. The Company is a large independent oil and gas exploration and production company that explores for, develops and produces oil, natural gas liquids ("NGLs") and gas within the United States, with operations primarily in the Permian Basin in West Texas, the Eagle Ford Shale play in South Texas, the Raton field in southeast Colorado and the West Panhandle field in the Texas Panhandle. |
Summary Of Significant Accounti
Summary Of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Policies [Abstract] | |
Summary Of Significant Accounting Policies | NOTE B. Summary of Significant Accounting Policies Principles of consolidation. The consolidated financial statements include the accounts of the Company and its wholly-owned and majority-owned subsidiaries since their acquisition or formation. All material intercompany balances and transactions have been eliminated. Certain reclassifications have been made to the 2016 and 2015 consolidated financial statement and footnote amounts in order to conform them to the 2017 presentations. In addition, the presentation of certain purchases and sales of third-party oil and gas with the same counterparty has been revised in 2016 and 2015 to present such transactions on a net basis in purchased oil and gas expense. Previously, these transportation arrangements, which were carried out as purchases from and sales to the same third party, were separately stated on a gross basis in sales of purchased oil and gas and purchased oil and gas expense. This revision did not impact the Company's balance sheet, net income (loss) from continuing operations, equity or cash flows. While not material to the 2016 and 2015 consolidated financial statements as a whole, the presentation has been revised to enhance consistency. The following individual line items were affected, in addition to total revenues and total costs and expenses: Year Ended December 31, 2016 2015 (in millions) Sales of purchased oil and gas, as previously reported $ 1,533 $ 964 Revision to sales of purchased oil and gas (442 ) (264 ) Sales of purchased oil and gas, reported herein $ 1,091 $ 700 Purchased oil and gas, as previously reported $ 1,597 $ 1,003 Revision to purchased oil and gas (442 ) (264 ) Purchased oil and gas, reported herein $ 1,155 $ 739 Use of estimates in the preparation of financial statements. Preparation of the accompanying consolidated financial statements in conformity with generally accepted accounting principles in the United States ("GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Depletion of oil and gas properties and impairment of goodwill and proved and unproved oil and gas properties, in part, is determined using estimates of proved, probable and possible oil and gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved, probable and possible reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves and commodity price outlooks. Actual results could differ from the estimates and assumptions utilized. Cash and cash equivalents. The Company's cash and cash equivalents include depository accounts held by banks and marketable securities with original issuance maturities of 90 days or less. Investments. Periodically, the Company invests in commercial paper and corporate bonds with investment grade rated entities. The Company also periodically enters into time deposits with financial institutions. Commercial paper and time deposits are included in cash and cash equivalents if they have maturity dates that are less than 90 days at the date of purchase; otherwise, investments are reflected in short-term investments or long-term investments in the accompanying consolidated balance sheets based on their maturity dates. Accounts receivable. As of December 31, 2017 and 2016 , the Company had accounts receivable – trade, net of allowances for bad debts, of $639 million and $517 million , respectively. The Company's accounts receivable – trade are primarily comprised of oil and gas sales receivables, joint interest receivables and other receivables for which the Company does not require collateral security. As of December 31, 2017 and 2016 , the Company's allowances for doubtful accounts totaled $1 million for both respective periods. The Company establishes allowances for bad debts equal to the estimable portions of accounts receivable for which failure to collect is considered probable. The Company estimates the portions of joint interest receivables for which failure to collect is probable based on percentages of joint interest receivables that are past due. The Company estimates the portions of other receivables for which failure to collect is probable based on the relevant facts and circumstances surrounding the receivable. Allowances for doubtful accounts are recorded as reductions to the carrying values of the receivables included in the Company's accompanying consolidated balance sheets and as charges to other expense in the accompanying consolidated statements of operations in the accounting periods during which failure to collect an estimable portion is determined to be probable. Inventories. The Company's inventories consist of materials, supplies and commodities. The Company's materials and supplies inventory is primarily comprised of oil and gas drilling or repair items such as tubing, casing, proppant used to fracture-stimulate oil and gas wells, water, chemicals, operating supplies and ordinary maintenance materials and parts. The materials and supplies inventory is primarily acquired for use in future drilling operations or repair operations and is carried at the lower of cost or market, on a first-in, first-out cost basis. Valuation allowances for materials and supplies inventories are recorded as reductions to the carrying values of the materials and supplies inventories in the Company's accompanying consolidated balance sheets and as charges to other expense in the accompanying consolidated statements of operations. Commodity inventories are carried at the lower of cost or market, on a first-in, first-out basis. The Company's commodity inventories consist of oil, NGLs and gas volumes held in storage or as linefill in pipelines. Any valuation allowances of commodity inventories are recorded as reductions to the carrying values of the commodity inventories included in the Company's accompanying consolidated balance sheets and as charges to other expense in the accompanying consolidated statements of operations. The following table presents the Company's materials and supplies and commodity inventories as of December 31, 2017 and 2016 : As of December 31, 2017 2016 (in millions) Materials and supplies (a) $ 134 $ 144 Commodities 78 37 $ 212 $ 181 ____________________ (a) As of December 31, 2017 and 2016 , the Company's materials and supplies inventories were net of valuation allowances of $5 million and $28 million , respectively. See Note D for additional information regarding inventory impairments. Oil and gas properties. The Company utilizes the successful efforts method of accounting for its oil and gas properties. Under this method, all costs associated with productive wells and nonproductive development wells are capitalized while nonproductive exploration costs and geological and geophysical expenditures are expensed. The Company capitalizes interest on expenditures for significant development projects, generally when the underlying project is sanctioned, until such projects are ready for their intended use. The Company does not carry the costs of drilling an exploratory well as an asset in its consolidated balance sheets following the completion of drilling unless both of the following conditions are met: (i) The well has found a sufficient quantity of reserves to justify its completion as a producing well; and (ii) The Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. Due to the capital-intensive nature and the geographical location of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and the economics associated with making a determination on its commercial viability. In these instances, the project's feasibility is not contingent upon price improvements or advances in technology, but rather the Company's ongoing efforts and expenditures related to accurately predicting the hydrocarbon recoverability based on well information, gaining access to other companies' production data in the area, transportation or processing facilities and/or getting partner approval to drill additional appraisal wells. These activities are ongoing and are being pursued constantly. Consequently, the Company's assessment of suspended exploratory well costs is continuous until a decision can be made that the project has found sufficient proved reserves to sanction the project or is noncommercial and is charged to exploration and abandonments expense. See Note F for additional information regarding the Company's suspended exploratory well costs. The Company owns interests in 10 gas processing plants and four treating facilities. The Company is the operator of one of the gas processing plants and all four of the treating facilities. Nine of the gas processing plants are operated by third parties and one of the treating facilities is not currently being used. The Company's ownership interests in the gas processing plants and treating facilities are primarily to accommodate handling the Company's gas production and thus are considered a component of the capital and operating costs of the respective fields that they service. To the extent that there is excess capacity at a plant or treating facility, the Company attempts to process third-party gas volumes for a fee to keep the plant or treating facility at capacity. All revenues and expenses derived from third-party gas volumes processed through the plants and treating facilities are reported as components of oil and gas production costs. Third-party revenues generated from the processing plants and treating facilities in continuing operations for the years ended December 31, 2017 , 2016 and 2015 were $60 million , $41 million and $39 million , respectively. Third-party expenses attributable to the processing plants and treating facilities in continuing operations for the same respective periods were $26 million , $24 million and $27 million . The capitalized costs of the plants and treating facilities are included in proved oil and gas properties and are depleted using the unit-of-production method along with the other capitalized costs of the field that they service. The capitalized costs of proved properties are depleted using the unit-of-production method based on proved reserves. Costs of significant nonproducing properties, wells in the process of being drilled and development projects are excluded from depletion until the related project is completed and proved reserves are established or, if unsuccessful, impairment is determined. Proceeds from the sales of individual properties and the capitalized costs of individual properties sold or abandoned are credited and charged, respectively, to accumulated depletion, depreciation and amortization, if doing so does not materially impact the depletion rate of an amortization base. Generally, no gain or loss is recognized until an entire amortization base is sold. However, gain or loss is recognized from the sale of less than an entire amortization base if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the amortization base. The Company performs assessments of its long-lived assets to be held and used, including proved oil and gas properties accounted for under the successful efforts method of accounting, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. An impairment loss is indicated if the sum of the expected future cash flows, including vertical integrated services that are used in the development of the assets, is less than the carrying amount of the assets, including the carrying value of vertical integrated services assets. In these circumstances, the Company recognizes an impairment loss for the amount by which the carrying amount of the assets exceeds the estimated fair value of the assets. See Note D for additional information regarding the Company's impairment of proved oil and gas properties. Unproved oil and gas properties are periodically assessed for impairment on a project-by-project basis. These impairment assessments are affected by the results of exploration activities, commodity price outlooks, planned future sales or expirations of all or a portion of such projects. If the estimated future net cash flows attributable to such projects are not expected to be sufficient to fully recover the costs invested in each project, the Company will recognize an impairment loss at that time. Goodwill. During 2004, the Company recorded goodwill associated with a business combination, which represents the cost of the acquired entity over the net amounts assigned to assets acquired and liabilities assumed. In accordance with GAAP, goodwill is not amortized to earnings, but is assessed for impairment whenever events or circumstances indicate that impairment of the carrying value of goodwill is likely, but no less often than annually. If the carrying value of goodwill is determined to be impaired, it is reduced to the impaired value with a corresponding charge to earnings in the period in which it is determined to be impaired. During the third quarter of 2017 , the Company performed its annual qualitative assessment of goodwill to determine whether it was more likely than not that the fair value of the Company's reporting unit was less than its carrying amount as a basis for determining whether it was necessary to perform the two-step impairment test. Based on the results of the assessment, the Company determined it was not likely that the Company's goodwill was impaired. Other property and equipment, net. Other property and equipment is recorded at cost. As of December 31, 2017 and 2016 , the net carrying value of other property and equipment consisted of the following: As of December 31, 2017 (a) 2016 (a) (in millions) Land and buildings $ 529 $ 475 Proved and unproved sand properties (b) 488 484 Water infrastructure (c) 347 221 Equipment (d) 194 206 Information technology (e) 143 84 Leasehold improvements 20 22 Vehicles 19 15 Furniture and fixtures 19 22 $ 1,759 $ 1,529 ____________________ (a) At December 31, 2017 and 2016 , other property and equipment was net of accumulated depreciation of $936 million and $866 million , respectively. (b) Includes sand mines, facilities and unproved leaseholds that primarily provide the Company with proppant for use in the fracture stimulation of oil and gas wells. (c) Includes pipeline infrastructure costs and water supply wells. (d) Includes fracture stimulation and well servicing equipment that is owned by wholly-owned subsidiaries that provide pressure pumping and well services on Company-operated properties. As of December 31, 2017 , the Company owned eight fracture stimulation fleets and other oilfield services equipment, including pulling units, fracture stimulation tanks, water transport trucks, hot oilers, blowout preventers, construction equipment and fishing tools. (e) Information technology costs include hardware and software costs associated with the Company's existing systems and in-progress system upgrades. As of December 31, 2017 and 2016 , $93 million and $37 million , respectively, had not yet been placed into service. The primary purpose of the Company's sand mine, pressure pumping, well services and water infrastructure operations is to assist in the execution of the Company's drilling, completion and production operations by increasing the availability of supplies, equipment and services, rather than being dependent on third-party availability, and to contain associated costs. All intercompany profits or losses of the Company's sand mine, pressure pumping, well services and water infrastructure operations are eliminated. The capitalized costs of proved sand properties are depleted using the unit-of-production method based on proved sand reserves. Other property and equipment is depreciated over its estimated useful life on a straight-line basis. Buildings are generally depreciated over 20 to 39 years . Equipment, vehicles, furniture and fixtures and information technology assets are generally depreciated over two to 15 years . Water infrastructure is generally depreciated over 10 to 50 years . Leasehold improvements are amortized over the lesser of their estimated useful lives or the underlying terms of the associated leases. The Company reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the asset exceeds its estimated fair value. The estimated fair value is determined using either a discounted future cash flow model or another appropriate fair value method. Asset retirement obligations. The Company records a liability for the fair value of an asset retirement obligation in the period in which it is incurred, if a reasonable estimate of fair value can be made. Asset retirement obligations are generally capitalized as part of the carrying value of the long-lived asset to which it relates. Conditional asset retirement obligations meet the definition of liabilities and are recognized when incurred if their fair values can be reasonably estimated. The Company records the current and noncurrent portions of asset retirement obligations in other current liabilities and other liabilities, respectively, in the accompanying consolidated balance sheets and expenditures are classified as cash used in operating activities in the accompanying consolidated statements of cash flows. See Note I for additional information about the Company's asset retirement obligations. Treasury stock. Treasury stock purchases are recorded at cost. Upon reissuance, the cost of treasury shares held is reduced by the average purchase price per share of the aggregate treasury shares held. Issuance of common stock. In January and June of 2016, the Company issued 13.8 million and 6.0 million shares of its common stock, respectively, and realized cash proceeds of $1.6 billion and $937 million , respectively, net of associated underwriting and offering expenses. Revenue recognition. The Company recognizes revenue when it is realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller's price to the buyer is fixed or determinable and (iv) collectability is reasonably assured. The Company enters into purchase transactions with third parties and separate sale transactions with third parties to diversify a portion of the Company's West Texas Intermediate oil ("WTI") sales to a Gulf Coast or export market price and to satisfy unused pipeline capacity commitments. Revenues and expenses from these transactions are presented on a gross basis as the Company acts as a principal in the transaction by assuming the risk and rewards of ownership, including credit risk, of the commodities purchased and assuming the responsibility to deliver the commodities sold. Transportation costs associated with purchases and sales of third-party oil and gas are presented on a net basis in purchased oil and gas expense. Firm transportation payments on excess pipeline capacity are included in other expense in the accompanying consolidated statements of operations. See Note N for further information on transportation commitment charges. Derivatives. All derivatives are recorded in the accompanying consolidated balance sheets at estimated fair value. The Company recognizes all changes in the fair values of its derivative contracts as gains or losses in the earnings of the periods in which they occur. The Company classifies the fair value amounts of derivative assets and liabilities executed under master netting arrangements as net current or noncurrent derivative assets or net current or noncurrent derivative liabilities, whichever the case may be, by commodity and counterparty. Net derivative asset values are determined, in part, by utilization of the derivative counterparties' credit-adjusted risk-free rate curves and net derivative liabilities are determined, in part, by utilization of the Company's credit-adjusted risk-free rate curve. The credit-adjusted risk-free rate curves for the Company and the counterparties are based on their independent market-quoted credit default swap rate curves plus the United States Treasury Bill yield curve as of the valuation date. See Note E for additional information about the Company's derivative instruments. Income taxes. The provision for income taxes is determined using the asset and liability approach of accounting for income taxes. Under this approach, deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes and net operating loss and tax credit carryforwards. The amount of deferred taxes on these temporary differences is determined using the tax rates that are expected to apply to the period when the asset is realized or the liability is settled, as applicable, based on tax rates and laws in the respective tax jurisdiction enacted as of the balance sheet date. The Company reviews its deferred tax assets for recoverability and establishes a valuation allowance based on projected future taxable income, applicable tax strategies and the expected timing of the reversals of existing temporary differences. A valuation allowance is provided when it is more likely than not (likelihood of greater than 50%) that some portion or all of the deferred tax assets will not be realized. The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based upon the technical merits of the position. If all or a portion of the unrecognized tax benefit is sustained upon examination by the taxing authorities, the tax benefit will be recognized as a reduction to the Company's deferred tax liability and will affect the Company's effective tax rate in the period it is recognized. See Note O for additional information regarding uncertain tax positions. Stock-based compensation. Stock-based compensation expense is being recognized on restricted stock, restricted stock units, performance units and stock option awards that are expected to be settled in the Company's common stock ("Equity Awards") in the Company's consolidated financial statements on a straight line basis over the awards' vesting periods based on their fair values on the dates of grant or modification, as applicable. Stock-based compensation awards generally vest over a period of three years . The amount of stock-based compensation expense recognized at any date is approximately equal to the ratable portion of the grant date value of the award that is vested at that date. Stock-based compensation liability awards ("Liability Awards") are restricted stock awards that are expected to be settled in cash on their vesting dates, rather than in common stock. Liability Awards are recorded as accounts payable—affiliates based on the fair value of the vested portion of the awards on the balance sheet date. The fair values of Liability Awards are updated at each balance sheet date and changes in the fair values of the vested portions of the awards are recorded as increases or decreases to stock-based compensation expense. The Company utilizes (i) the Black-Scholes option pricing model to measure the fair value of stock options, (ii) the prior day's closing stock price on the date of grant to measure the fair value of Equity Awards and Liability Awards, (iii) the closing stock price on the balance sheet date to measure the fair value of the vested portions of Liability Awards and (iv) the Monte Carlo simulation method to measure the fair value of performance unit awards. Segments. Operating segments are defined as components of an enterprise that (i) engage in activities from which it may earn revenues and incur expenses (ii) for which separate operational financial information is available and is regularly evaluated by the chief operating decision maker for the purpose of allocating resources and assessing performance. Based upon how the Company is organized and managed, the Company has only one reportable operating segment, which is oil and gas development, exploration and production. The Company considers its vertical integration services as ancillary to its oil and gas development, exploration and producing activities and manages these services to support such activities. In addition, the Company has a single, company-wide management team that allocates capital resources to maximize profitability and measures financial performance as a single enterprise. Restructuring. In February 2016, the Company announced plans to restructure its pressure pumping operations in South Texas, including relocating its two Eagle Ford Shale pressure pumping fleets to the Spraberry/Wolfcamp area. In connection therewith, the Company offered severance to certain employees and relocated a number of other employees from its South Texas locations to its operations in the Permian Basin. The initiative was substantially complete as of December 31, 2016. In connection therewith, the Company recognized $4 million of restructuring charges in other expense in the accompanying consolidated statements of operations during the year ended December 31, 2016 . The restructuring costs included $3 million in cash employee severance costs and $1 million in employee relocation and other costs. In May 2015, the Company announced plans to restructure its operations in Colorado, including closing its office in Denver, Colorado and eliminating its Trinidad-based pressure pumping services operations. The restructuring plan was substantially complete as of December 31, 2015. In connection therewith, the Company recognized $23 million of restructuring charges in other expense in the accompanying consolidated statements of operations during the year ended December 31, 2015 . The restructuring costs included $17 million in employee severance costs and $6 million in office lease-related costs. The $17 million of employee severance costs for the year ended December 31, 2015 included $16 million related to cash severance payments and $1 million related to accelerated vesting of share-based grants, which were noncash charges. Lease obligations and other . The $6 million of office lease-related costs for the year ended December 31, 2015 related to certain Denver office space that will no longer be used, of which $2 million represented the impairment of leasehold improvements and $4 million represented the Company's future obligations under the operating leases, net of anticipated sublease income. As of December 31, 2017 and 2016 , the Company had $1 million and $2 million of restructuring liabilities, respectively, primarily related to future lease obligations recorded in other current and noncurrent liabilities in the accompanying consolidated balance sheets. New accounting pronouncements. In March 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2016-09, "Improvements to Employee Share-Based Payment Accounting." ASU 2016-09 simplifies several aspects of the accounting for share-based payment transactions, including accounting for income taxes, forfeitures and statutory tax withholding requirements, as well as certain classification changes in the statement of cash flows. The Company adopted this standard on January 1, 2017. See Note O for discussion on the impact of the adoption to the Company's income tax benefit. In February 2016, FASB issued ASU 2016-02, "Leases (Topic 842)." ASU 2016-02 requires the recognition of lease assets and lease liabilities by lessees for those leases currently classified as operating leases and makes certain changes to the accounting for lease expenses. This update is effective for fiscal years beginning after December 15, 2018 and for interim periods beginning the following year. This update should be applied using a modified retrospective approach, and early adoption is permitted. The Company anticipates that the adoption of ASU 2016-02 for its leasing arrangements will likely (i) increase the Company's recorded assets and liabilities, (ii) increase depreciation, depletion and amortization expense, (iii) increase interest expense and (iv) decrease lease/rental expense. The Company is currently evaluating each of its lease arrangements and has not determined the aggregate amount of change expected for each category. In January 2018, the FASB issued ASU 2018-01, which permits an entity to elect an optional transition practical expedient to not evaluate land easements that exist or expire before the Company's adoption of Topic 842 and that were not previously accounted for as leases under Topic 840. The Company intends to elect this transition provision. In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers (Topic 606)," which supersedes the revenue recognition requirements in Accounting Standards Codification ("ASC") Topic 605, "Revenue Recognition," and most industry-specific guidance. ASU 2014-09 is based on the principle that revenue is recognized to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. In August 2015, the FASB issued ASU 2015-14, which defers the effective date of ASU 2014-09 for one year to annual reports beginning after December 15, 2017. Early adoption is permitted for fiscal years beginning after December 15, 2016. In addition, in May 2016, the FASB issued ASU 2016-11, which rescinds guidance from the SEC on accounting for gas balancing arrangements and will eliminate the use of the entitlements method. During the Company's implementation of Topic 606, it identified the following revenue streams: oil, NGL and gas sales and sales of purchased oil and gas. The Company's analysis of contracts with customers in accordance with the requirements of Topic 606 is complete. The Company has not identified any changes to the timing of revenue recognition based upon the requirements of Topic 606 that would have a material impact on the Company's consolidated financial statements. The Company will utilize the modified approach to adopt the new standards on their January 1, 2018 effective date. The Company continues to review its implementation documentation and its evaluation of the new disclosure requirements is ongoing. |
Acquisitions and Divestitures
Acquisitions and Divestitures | 12 Months Ended |
Dec. 31, 2017 | |
Business Combinations [Abstract] | |
Acquisitions and Divestitures | Acquisitions and Divestitures Acquisitions Permian Basin. In August 2016, the Company acquired approximately 28,000 net acres in the Permian Basin, with net production of approximately 1,400 barrels of oil equivalent per day ("BOEPD"), from an unaffiliated third party for $428 million . The acquisition was accounted for using the acquisition method under ASC 805, "Business Combinations," which requires acquired assets and liabilities to be recorded at fair value as of the acquisition date. The following table represents the allocation of the acquisition price to the assets acquired and the liabilities assumed based on their fair value at the acquisition date (in millions): Assets acquired: Proved properties $ 79 Unproved properties 347 Other property and equipment 5 Liabilities assumed: Asset retirement obligations (2 ) Other liabilities (1 ) Net assets acquired $ 428 The fair value measurements of the net assets acquired are based on inputs that are not observable in the market and, therefore, represent Level 3 inputs in the fair value hierarchy (see Note D for a description of the input levels in the fair value hierarchy). The Company calculated the fair values of the acquired proved properties and asset retirement obligations using a discounted future cash flow model that utilizes management's estimates of (i) proved reserves, (ii) forecasted production rates, (iii) future operating, development and plugging and abandonment costs, (iv) future commodity prices and (v) a discount rate of 10 percent for proved properties and seven percent for asset retirement obligations. The Company calculated the fair values of the acquired unproved properties based on the average price per acre in comparable market transactions. The operating results attributable to the acquired assets and liabilities assumed are included in the Company's accompanying consolidated statements of operations since the date of acquisition. In connection with the acquisition, the Company incurred acquisition related costs (primarily consulting, advisory and legal fees) of $1 million . The operating results included in the Company's accompanying consolidated statements of operations from the date of acquisition to December 31, 2016, and the operating results that would have been recognized had the acquisition occurred on January 1, 2016, are not material to the Company's accompanying consolidated statements of operations. Divestitures Recorded in Continuing Operations The Company recorded net gains on the disposition of assets in continuing operations of $208 million , $2 million and $782 million during the years ended December 31, 2017 , 2016 and 2015 , respectively. The following describes the significant divestitures included in continuing operations: • In April 2017, the Company completed the sale of approximately 20,500 acres in the Martin County region of the Permian Basin, with net production of approximately 1,500 BOEPD, to an unaffiliated third party for cash proceeds of $264 million . The sale resulted in a gain of $194 million . In conjunction with the divestiture, the Company reduced the carrying value of goodwill by $2 million , reflecting the portion of the Company's goodwill related to the assets sold. • EFS Midstream. In July 2015, the Company completed the sale of its 50.1 percent interest in EFS Midstream LLC ("EFS Midstream"), which was accounted for under the equity method of accounting, to an unaffiliated third party, with the Company receiving total consideration of $1.0 billion , of which $530 million was received at closing, and the remaining $501 million was received in July 2016. Associated with the sale, the Company recorded a gain of $777 million during 2015. • Other. During 2017 , 2016 and 2015 , the Company sold other proved and unproved properties, inventory and other property and equipment and recorded net gains of $14 million , $2 million and $5 million , respectively. The net gain of $14 million for 2017 is primarily related to the sale of nonstrategic proved and unproved properties in the Permian Basin for cash proceeds of $77 million . Divestitures Recorded in Discontinued Operations In 2015, the Company recognized losses from discontinued operations, net of tax, of $7 million related to plugging and abandonment obligations associated with two Gulf of Mexico wells that Pioneer divested in 2009. The results of operations for these assets were recorded in discontinued operations upon their divestiture and therefore the costs incurred subsequent to their divestiture are reflected as discontinued operations in the accompanying consolidated statements of operations. |
Disclosures About Fair Value Me
Disclosures About Fair Value Measurements | 12 Months Ended |
Dec. 31, 2017 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | Fair Value Measurements Fair value is defined as the price that would be received to sell an asset or the price paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are characterized according to a hierarchy that prioritizes those inputs based on the degree to which they are observable. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company's own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. The three input levels of the fair value hierarchy are as follows: • Level 1 – quoted prices for identical assets or liabilities in active markets. • Level 2 – quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; inputs other than quoted prices that are observable for the asset or liability (e.g. interest rates) and inputs derived principally from or corroborated by observable market data by correlation or other means. • Level 3 – unobservable inputs for the asset or liability. Assets and liabilities measured at fair value on a recurring basis. The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level input that is significant to the measurement in its entirety. The following tables present the Company's assets and liabilities that are measured at fair value on a recurring basis as of December 31, 2017 and 2016 for each of the fair value hierarchy levels: Fair Value Measurements at December 31, 2017 Using Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Fair Value at December 31, 2017 (in millions) Assets: Commodity derivatives $ — $ 11 $ — $ 11 Deferred compensation plan assets 95 — — 95 Total assets 95 11 — 106 Liabilities: Commodity derivatives — 255 — 255 Total liabilities — 255 — 255 Total recurring fair value measurements $ 95 $ (244 ) $ — $ (149 ) Fair Value Measurements at December 31, 2016 Using Quoted Prices in Significant Other Significant Fair Value at December 31, 2016 (in millions) Assets: Commodity derivatives $ — $ 8 $ — $ 8 Interest rate derivatives — 6 — 6 Deferred compensation plan assets 83 — — 83 Total assets 83 14 — 97 Liabilities: Commodity derivatives — 84 — 84 Total liabilities — 84 — 84 Total recurring fair value measurements $ 83 $ (70 ) $ — $ 13 Commodity derivatives. The Company's commodity derivatives represent oil, NGL and gas swap contracts, collar contracts and collar contracts with short puts. The asset and liability measurements for the Company's commodity derivative contracts represented Level 2 inputs in the hierarchy. The Company utilizes discounted cash flow and option-pricing models for valuing its commodity derivatives. The asset and liability values attributable to the Company's commodity derivatives were determined based on inputs that include (i) the contracted notional volumes, (ii) independent active market price quotes, (iii) the applicable estimated credit-adjusted risk-free rate yield curve and (iv) the implied rate of volatility inherent in the collar contracts and collar contracts with short puts, which is based on active and independent market-quoted volatility factors. Deferred compensation plan assets. The Company's deferred compensation plan assets represent investments in equity and mutual fund securities that are actively traded on major exchanges. These investments are measured based on observable prices on major exchanges. As of December 31, 2017 and 2016 , the significant inputs to these asset exchange values represented Level 1 independent active exchange market price inputs. Assets and liabilities measured at fair value on a nonrecurring basis. Certain assets and liabilities are measured at fair value on a nonrecurring basis. These assets and liabilities are not measured at fair value on an ongoing basis, but are subject to fair value adjustments in certain circumstances. These assets and liabilities can include inventory, proved and unproved oil and gas properties and other long-lived assets that are written down to fair value when they are impaired or held for sale. See Note C for information on the fair value of assets and liabilities acquired in the Permian Basin acquisition. Inventories. During the years ended December 31, 2017 , 2016 and 2015 , the Company recognized noncash impairment charges of $2 million , $8 million and $71 million , respectively, primarily to reduce the carrying value of its excess pipe inventory. The Company calculated the estimated fair value of the inventory using significant Level 2 assumptions based on third-party price quotes for the asset in an active market. The impairment charges are included in other expense in the Company's accompanying consolidated statements of operations. Proved oil and gas properties. As a result of the Company's proved property impairment assessments, the Company recognized noncash impairment charges to reduce the carrying values of (i) the Raton field during the year ended December 31, 2017, (ii) the West Panhandle field during the year ended December 31, 2016 and (iii) the Eagle Ford Shale field, the South Texas - Other field and the West Panhandle field during the year ended December 31, 2015. The Company calculated the fair values of the Raton field, the West Panhandle field, the Eagle Ford Shale field and the South Texas - Other field proved properties using a discounted cash flow model. Significant Level 3 assumptions associated with the calculation of discounted future cash flows included management's longer-term commodity price outlooks ("Management's Price Outlooks") and management's outlooks for (i) production, (ii) capital expenditures, (iii) production costs and (iv) estimated proved reserves and risk-adjusted probable reserves. Management's Price Outlooks are developed based on third-party longer-term commodity futures price outlooks as of each measurement date. The expected future net cash flows were discounted using an annual rate of 10 percent to determine fair value. The following table presents the fair value and fair value adjustments (in millions) for the 2017, 2016 and 2015 proved property impairments, as well as the average oil price per barrel ("Bbl") and gas price per British thermal unit ("MMBtu") utilized in the respective Management's Price Outlooks: Fair Value Fair Value Adjustment Management's Price Outlooks Oil Gas Raton March 2017 $ 186 $ (285 ) $ 53.65 $ 3.00 West Panhandle March 2016 $ 33 $ (32 ) $ 49.77 $ 3.24 South Texas - Eagle Ford Shale December 2015 $ 483 $ (846 ) $ 52.82 $ 3.34 South Texas - Other September 2015 $ 88 $ (72 ) $ 57.41 $ 3.46 West Panhandle March 2015 $ 61 $ (138 ) $ 65.02 $ 3.83 It is reasonably possible that the Company's estimate of undiscounted future net cash flows attributable to these or other properties may change in the future resulting in the need to impair their carrying values. The primary factors that may affect estimates of future cash flows are (i) future adjustments, both positive and negative, to proved and risk-adjusted probable and possible oil and gas reserves, (ii) results of future drilling activities, (iii) Management's Price Outlooks and (iv) increases or decreases in production and capital costs associated with these reserves. Unproved oil and gas properties. During March 2016, the Company recorded an impairment charge of $32 million to write-off the carrying value of its unproved royalty acreage in Alaska as a result of the operator curtailing operations in the area and Management's Price Outlooks. During 2015, the Company recorded impairment charges of $7 million to impair the remaining carrying value of its unproved properties in southeast Colorado as a result of the Company no longer planning to develop this acreage and the acreage's limited market value, if any, given the short time period until the leases expire. The Company's impairment charges for unproved oil and gas properties are reported in exploration and abandonments in the accompanying consolidated statements of operations. Financial instruments not carried at fair value. Carrying values and fair values of financial instruments that are not carried at fair value in the accompanying consolidated balance sheets as of December 31, 2017 and 2016 are as follows: December 31, 2017 December 31, 2016 Carrying Value Fair Value Carrying Value Fair Value (in millions) Commercial paper, corporate bonds and time deposits $ 1,284 $ 1,282 $ 1,906 $ 1,901 Current portion of long-term debt $ 449 $ 457 $ 485 $ 490 Long-term debt $ 2,283 $ 2,479 $ 2,728 $ 2,956 Commercial paper, corporate bonds and time deposits. Periodically, the Company invests in commercial paper and corporate bonds with investment grade rated entities. The Company also periodically enters into time deposits with financial institutions. The investments are carried at amortized cost and classified as held-to-maturity as the Company has the intent and ability to hold them until they mature. The carrying values of held-to-maturity investments are adjusted for amortization of premiums and accretion of discounts over the remaining life of the investment. Income related to these investments is recorded in interest and other income in the Company's consolidated statement of operations. The Company's investments in corporate bonds represent Level 1 inputs in the hierarchy, while other investments represent Level 2 inputs in the hierarchy. Commercial paper and time deposits are included in cash and cash equivalents if they have maturity dates that are less than 90 days at the date of purchase; otherwise, investments are reflected in short-term investments or long-term investments in the accompanying consolidated balance sheets based on their maturity dates. The following tables provide the components of the Company's cash and cash equivalents and investments as of December 31, 2017 and 2016 : December 31, 2017 Consolidated Balance Sheet Location Cash Commercial Paper Corporate Bonds Time Total (in millions) Cash and cash equivalents $ 846 $ — $ — $ 50 $ 896 Short-term investments — 124 647 447 1,218 Long-term investments — — 66 — 66 $ 846 $ 124 $ 713 $ 497 $ 2,180 December 31, 2016 Consolidated Balance Sheet Location Cash Commercial Paper Corporate Bonds Time Total (in millions) Cash and cash equivalents $ 873 $ 45 $ — $ 200 $ 1,118 Short-term investments — 368 691 382 1,441 Long-term investments — — 420 — 420 $ 873 $ 413 $ 1,111 $ 582 $ 2,979 Debt obligations. The Company's debt obligations are composed of its senior notes whose fair value is determined utilizing inputs that are Level 2 measurements in the fair value hierarchy. The Company's senior notes represent debt securities that are quoted but not actively traded on major exchanges; therefore, fair values of the Company's senior notes are based on their periodic values as quoted on the major exchanges. The Company has other financial instruments consisting primarily of receivables, payables and other current assets and liabilities that approximate fair value due to the nature of the instrument and their relatively short maturities. Non-financial assets and liabilities initially measured at fair value include assets acquired and liabilities assumed in a business combination, goodwill and asset retirement obligations. Concentrations of credit risk. As of December 31, 2017 , the Company's primary concentration of credit risks are the risks associated with collecting receivables (principally accounts receivables) and the risk of a counterparty's failure to perform under derivative contracts owed to the Company. See Note L for information regarding the Company's major customers. With respect to accounts receivables, the Company uses credit and other financial criteria to evaluate the credit standing of the entity obligated to make the payment, and where appropriate, the Company obtains assurances of payment, such as a guarantee by the parent company of the entity or such other credit support as the Company believes is appropriate. The Company has entered into International Swap Dealers Association Master Agreements ("ISDA Agreements") with each of its derivative counterparties. The terms of the ISDA Agreements provide the Company and the counterparties with rights of set off upon the occurrence of defined acts of default by either the Company or a counterparty to a derivative, whereby the party not in default may set off all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party. See Note E for additional information regarding the Company's derivative activities and information regarding derivative net assets and liabilities by counterparty. |
Derivative Financial Instrument
Derivative Financial Instruments | 12 Months Ended |
Dec. 31, 2017 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative Financial Instruments | Derivative Financial Instruments The Company utilizes commodity swap contracts, collar contracts and collar contracts with short puts to (i) reduce the effect of price volatility on the commodities the Company produces and sells or consumes, (ii) support the Company's annual capital budgeting and expenditure plans and (iii) reduce commodity price risk associated with certain capital projects. The Company also, from time to time, utilizes interest rate contracts to reduce the effect of interest rate volatility on the Company's indebtedness. Periodically, the Company may pay a premium to enter into commodity contracts. Premiums paid, if any, have been nominal in relation to the value of the underlying asset in the contract. The Company recognizes the nominal premium payments as an increase to the value of the derivative assets when paid. All derivatives are adjusted to fair value as of each balance sheet date. Oil production derivative activities. All material physical sales contracts governing the Company's oil production are tied directly to, or are highly correlated with, New York Mercantile Exchange ("NYMEX") WTI oil prices. The Company uses derivative contracts to manage oil price volatility and basis swap contracts to reduce basis risk between NYMEX prices and actual index prices at which the oil is sold. The following table sets forth the volumes per day associated with the Company's outstanding oil derivative contracts as of December 31, 2017 and the weighted average oil prices for those contracts: 2018 Year Ending December 31, 2019 First Quarter Second Quarter Third Quarter Fourth Quarter Collar contracts: Volume (Bbl) 3,000 3,000 3,000 3,000 — Average price per Bbl: Ceiling $ 58.05 $ 58.05 $ 58.05 $ 58.05 $ — Floor $ 45.00 $ 45.00 $ 45.00 $ 45.00 $ — Collar contracts with short puts (a): Volume (Bbl) 149,000 149,000 154,000 159,000 40,000 Price per Bbl: Ceiling $ 57.79 $ 57.79 $ 57.70 $ 57.62 $ 59.62 Floor $ 47.42 $ 47.42 $ 47.34 $ 47.26 $ 52.00 Short put $ 37.38 $ 37.38 $ 37.31 $ 37.23 $ 42.00 ____________________ (a) Subsequent to December 31, 2017 , the Company entered into additional oil collar contracts with short puts for 25,000 Bbl per day of 2019 production with a ceiling price of $62.55 per Bbl, a floor price of $53.80 per Bbl and a short put price of $43.80 per Bbl. NGL production derivative activities. All material physical sales contracts governing the Company's NGL production are tied directly or indirectly to either Mont Belvieu, Texas or Conway, Kansas NGL component product prices. The Company uses derivative contracts to manage the NGL component product price volatility. The following table sets forth the volumes per day associated with the Company's outstanding NGL derivative contracts as of December 31, 2017 and the weighted average NGL prices for those contracts: 2018 Year Ending December 31, 2019 First Second Quarter Third Quarter Fourth Quarter Ethane basis swap contracts (a): Volume (MMBtu) 6,920 6,920 6,920 6,920 6,920 Price differential ($/MMBtu) $ 1.60 $ 1.60 $ 1.60 $ 1.60 $ 1.60 ____________________ (a) The ethane basis swap contracts reduce the price volatility of ethane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices. The ethane basis swap contracts fix the basis differential on a NYMEX Henry Hub ("HH") MMBtu equivalent basis. The Company will receive the HH price plus the price differential on 6,920 MMBtu per day, which is equivalent to 2,500 Bbls per day of ethane. Gas production derivative activities. All material physical sales contracts governing the Company's gas production are tied directly or indirectly to HH gas prices or regional index prices where the gas is sold. The Company uses derivative contracts to manage gas price volatility and basis swap contracts to reduce basis risk between HH prices and actual index prices at which the gas is sold. The following table sets forth the volumes per day associated with the Company's outstanding gas derivative contracts as of December 31, 2017 and the weighted average gas prices for those contracts: 2018 Year Ending December 31, 2019 First Second Quarter Third Quarter Fourth Quarter Swap contracts (a): Volume (MMBtu) 30,000 100,000 100,000 100,000 — Price per MMBtu $ 3.37 $ 3.00 $ 3.00 $ 3.00 $ — Collar contracts with short puts: Volume (MMBtu) 100,000 50,000 50,000 50,000 — Price per MMBtu: Ceiling $ 3.82 $ 3.40 $ 3.40 $ 3.40 $ — Floor $ 3.15 $ 2.75 $ 2.75 $ 2.75 $ — Short put $ 2.57 $ 2.25 $ 2.25 $ 2.25 $ — Basis swap contracts: Southern California index swap volume (MMBtu) (b)(c) 80,000 40,000 80,000 53,261 80,000 Price differential ($/MMBtu) $ 0.34 $ 0.30 $ 0.30 $ 0.43 $ 0.31 Houston Ship Channel index swap volume (MMBtu) (b)(d) 3,444 — — — — Price differential ($/MMBtu) $ 0.63 $ — $ — $ — $ — ____________________ (a) Subsequent to December 31, 2017 , the Company entered into additional swap contracts for 100,000 MMBtu per day of February 2018 production with a price of $3.46 per MMBtu. (b) The referenced basis swap contracts fix the basis differentials between Permian Basin index prices and southern California or Houston Ship Channel index prices for Permian Basin gas forecasted for sale in southern California or the Gulf Coast region. (c) Subsequent to December 31, 2017 , the Company entered into additional basis swap contracts for 20,000 MMBtu per day of November 2018 through March 2019 production with a price differential of $0.77 per MMBtu. (d) Subsequent to December 31, 2017 , the Company entered into additional basis swap contracts for 10,000 MMBtu per day of February 2018 production with a price differential of $0.82 per MMBtu. Marketing derivatives. Periodically, the Company enters into buy and sell marketing arrangements to fulfill firm pipeline transportation commitments. Associated with these marketing arrangements, the Company may enter into index swap contracts to mitigate price risk. The following table sets forth the volumes per day associated with the Company's outstanding marketing derivative contracts as of December 31, 2017 and the weighted average prices for those contracts: 2018 First Quarter Second Quarter Third Quarter Fourth Quarter Average Daily Oil Transportation Commitments Associated with Derivatives (Bbl): Basis swap contracts: Louisiana Light Sweet index swap volume (a) 10,000 10,000 6,739 — Price differential ($/Bbl) $ 3.18 $ 3.18 $ 3.18 $ — Magellan East Houston index swap volume (a) 11,556 11,703 3,370 — Price differential ($/Bbl) $ 3.29 $ 3.30 $ 3.30 $ — ____________________ (a) The referenced basis swap contracts fix the basis differentials between NYMEX WTI and Louisiana Light Sweet or Magellan East Houston oil prices for Permian Basin oil forecasted for sale in the Gulf Coast region. Interest rate derivatives. During 2017, the Company was party to interest rate derivative contracts whereby the Company would have received the three-month LIBOR rate for the 10 -year period from December 2017 through December 2027 in exchange for paying a fixed interest rate of 1.81 percent on a notional amount of $100 million on December 15, 2017. During the fourth quarter of 2017, the Company liquidated its interest rate derivative contracts for cash proceeds of $5 million . As of December 31, 2017 , the Company did not have any interest rate derivatives outstanding. Diesel derivatives. Periodically, the Company enters into diesel derivative swap contracts that mitigate fuel price risk. The diesel derivative swap contracts are priced at an index that is highly correlated to the prices that the Company incurs to fuel its drilling rigs and fracture stimulation fleet equipment. During 2017, the Company liquidated its diesel derivative swap contracts for cash proceeds of $2 million . As of December 31, 2017 , the Company did not have any diesel derivative contracts outstanding. Tabular disclosure of derivative financial instruments . All of the Company's derivatives are accounted for as non-hedge derivatives as of December 31, 2017 and December 31, 2016 and therefore all changes in the fair values of its derivative contracts are recognized as gains or losses in the earnings of the periods in which they occur. The Company classifies the fair value amounts of derivative assets and liabilities as net current or noncurrent derivative assets or net current or noncurrent derivative liabilities, whichever the case may be, by commodity and counterparty. The Company enters into derivatives under master netting arrangements, which, in an event of default, allows the Company to offset payables to and receivables from the defaulting counterparty. The aggregate fair value of the Company's derivative instruments reported in the accompanying consolidated balance sheets by type and counterparty, including the classification between current and noncurrent assets and liabilities, consists of the following: Fair Value of Derivative Instruments as of December 31, 2017 Type Consolidated Balance Sheet Location Fair Value Gross Amounts Offset in the Consolidated Balance Sheet Net Fair Value Presented in the Consolidated Balance Sheet (in millions) Derivatives not designated as hedging instruments Asset Derivatives: Commodity price derivatives Derivatives - current $ 13 $ (2 ) $ 11 Commodity price derivatives Derivatives - noncurrent 3 (3 ) — $ 11 Liability Derivatives: Commodity price derivatives Derivatives - current $ 234 $ (2 ) $ 232 Commodity price derivatives Derivatives - noncurrent 26 (3 ) 23 $ 255 Fair Value of Derivative Instruments as of December 31, 2016 Type Consolidated Balance Sheet Location Fair Value Gross Amounts Offset in the Consolidated Balance Sheet Net Fair Value Presented in the Consolidated Balance Sheet (in millions) Derivatives not designated as hedging instruments Asset Derivatives: Commodity price derivatives Derivatives - current $ 33 $ (25 ) $ 8 Interest rate derivatives Derivatives - current 6 — 6 $ 14 Liability Derivatives: Commodity price derivatives Derivatives - current $ 102 $ (25 ) $ 77 Commodity price derivatives Derivatives - noncurrent 7 — 7 $ 84 The following table details the location of gains and losses recognized on the Company's derivative contracts in the accompanying consolidated statements of operations: Derivatives Not Designated as Hedging Instruments Location of Gain/(Loss) Recognized in Earnings on Derivatives Amount of Gain/(Loss) Recognized in Earnings on Derivatives Year Ended December 31, 2017 2016 2015 (in millions) Commodity price derivatives Derivative gains (losses), net $ (99 ) $ (174 ) $ 873 Interest rate derivatives Derivative gains (losses), net (1 ) 13 6 Total $ (100 ) $ (161 ) $ 879 Derivative counterparties. The Company uses credit and other financial criteria to evaluate the credit standing of, and to select, counterparties to its derivative instruments. Although the Company does not obtain collateral or otherwise secure the fair value of its derivative instruments, associated credit risk is mitigated by the Company's credit risk policies and procedures. The following table provides the Company's net derivative assets or liabilities by counterparty as of December 31, 2017 : Net Assets (Liabilities) (in millions) Macquarie Bank $ (31 ) BMO Financial Group (30 ) JP Morgan Chase (28 ) Citibank, N.A. (28 ) Morgan Stanley (21 ) J. Aron & Company (21 ) BNP Paribas (20 ) Wells Fargo Bank, N.A. (20 ) Merrill Lynch (20 ) Nextera Energy (17 ) Scotia Bank (5 ) Societe Generale (4 ) JP Morgan Ventures Energy Corp (2 ) Toronto Dominion 3 Total $ (244 ) |
Exploratory Well Costs
Exploratory Well Costs | 12 Months Ended |
Dec. 31, 2017 | |
Extractive Industries [Abstract] | |
Exploratory Well Costs | Exploratory Well Costs The Company capitalizes exploratory well and project costs until a determination is made that the well or project has either found proved reserves, is impaired or is sold. The Company's capitalized exploratory well and project costs are presented in proved properties in the accompanying consolidated balance sheets. If the exploratory well or project is determined to be impaired, the impaired costs are charged to exploration and abandonments expense. The following table reflects the Company's capitalized exploratory well and project activity during each of the years ended December 31, 2017 , 2016 and 2015 : Year Ended December 31, 2017 2016 2015 (in millions) Beginning capitalized exploratory well costs $ 323 $ 306 $ 305 Additions to exploratory well costs pending the determination of proved reserves 1,956 1,387 1,178 Reclassification due to determination of proved reserves (1,764 ) (1,369 ) (1,160 ) Exploratory well costs charged to exploration and abandonment expense (10 ) (1 ) (17 ) Ending capitalized exploratory well costs $ 505 $ 323 $ 306 The following table provides an aging, as of December 31, 2017 , 2016 and 2015 of capitalized exploratory costs and the number of projects for which exploratory well costs have been capitalized for a period greater than one year, based on the date drilling was completed: As of December 31, 2017 2016 2015 (in millions, except well counts) Capitalized exploratory well costs that have been suspended: One year or less $ 493 $ 318 $ 303 More than one year 12 5 3 $ 505 $ 323 $ 306 Number of projects with exploratory well costs that have been suspended for a period greater than one year 7 3 1 The projects with exploratory well costs that have been suspended for a period greater than one year at December 31, 2017 are in the Eagle Ford Shale area. The Company is evaluating both the well performance of similar wells completed in 2017 and whether to drill additional wells near these wells in order for all of the wells in the area to be fracture stimulated as a package, thereby improving the resource recovery for the area. The Company expects to complete its evaluation of these seven wells during 2018. |
Long-term Debt and Interest Exp
Long-term Debt and Interest Expense | 12 Months Ended |
Dec. 31, 2017 | |
Debt Disclosure [Abstract] | |
Long-term Debt and Interest Expense | Long-term Debt and Interest Expense Long-term debt, including the effects of issuance costs and issuance discounts, consisted of the following components at December 31, 2017 and 2016 : December 31, 2017 2016 (in millions) Outstanding debt principal balances: 6.65% senior notes due 2017 (a) $ — $ 485 6.875% senior notes due 2018 (b) 450 450 7.500% senior notes due 2020 450 450 3.45% senior notes due 2021 500 500 3.95% senior notes due 2022 600 600 4.45% senior notes due 2026 500 500 7.20% senior notes due 2028 250 250 2,750 3,235 Issuance costs and discounts (18 ) (22 ) Long-term debt 2,732 3,213 Less current portion of long-term debt (a) (b) 449 485 Long-term debt $ 2,283 $ 2,728 ______________________________ (a) The 6.65% senior notes, net of $173 thousand of unamortized issuance costs and issuance discounts, are classified as current in the accompanying consolidated balance sheets as of December 31, 2016. (b) The 6.875% senior notes, net of $106 thousand of unamortized issuance costs and issuance discounts, are classified as current in the accompanying consolidated balance sheets as of December 31, 2017. Credit facility. During August 2015, the Company entered into a Second Amendment to its Second Amended and Restated 5 -year Revolving Credit Agreement ("Credit Facility") with a syndicate of financial institutions (the "Syndicate"), primarily to extend the maturity of the credit facility from December 2017 to August 2020, while maintaining aggregate loan commitments of $1.5 billion . The Company accounted for the entry into the Credit Facility as a modification of the prior agreement and capitalized the debt issuance costs along with those unamortized issuance costs that remained from the issuance of the prior agreement. As of December 31, 2017 , the Company had no outstanding borrowings under the Credit Facility. Borrowings under the Credit Facility may be in the form of revolving loans or swing line loans. Revolving loans represent loans made ratably by the Syndicate in accordance with their respective commitments under the Credit Facility and bear interest, at the option of the Company, based on (a) a rate per annum equal to the higher of the prime rate announced from time to time by Wells Fargo Bank, National Association or the weighted average of the rates on overnight Federal funds transactions with members of the Federal Reserve System during the last preceding business day plus 0.5 percent plus a defined alternate base rate spread margin, which is currently 0.25 percent based upon the Company's debt rating or (b) a base Eurodollar rate, substantially equal to LIBOR, plus a margin (the "Applicable Margin"), which is currently 1.25 percent and is also determined by the Company's debt rating. Swing line loans represent loans made by a subset of the lenders in the Syndicate and may not exceed $150 million . Swing line loans under the Credit Facility bear interest at a rate per annum equal to the "ASK" rate for Federal funds periodically published by the Dow Jones Market Service plus the Applicable Margin. Letters of credit outstanding under the Credit Facility are subject to a per annum fee, representing the Applicable Margin plus 0.125 percent . The Company also pays commitment fees on undrawn amounts under the Credit Facility that are determined by the Company's debt rating (currently 0.15 percent ). Borrowings under the Credit Facility are general unsecured obligations. The Credit Facility requires the maintenance of a ratio of total debt to book capitalization, subject to certain adjustments, not to exceed .60 to 1.0. As of December 31, 2017 , the Company was in compliance with all of its debt covenants. Senior notes. The Company's 6.65% senior notes (the " 6.65% Senior Notes") and 5.875% senior notes (the " 5.875% Senior Notes") matured and were repaid in March 2017 and July 2016, respectively. The Company funded both the $485 million repayment of the 6.65% Senior Notes and the $455 million repayment of the 5.875% Senior Notes with cash on hand. The Company's 6.875% senior notes (the " 6.875% Senior Notes"), with an outstanding debt principal balance of $450 million , will mature in May 2018. The 6.875% Senior Notes are classified as current in the accompanying consolidated balance sheets as of December 31, 2017 . The Company's senior notes are general unsecured obligations ranking equally in right of payment with all other senior unsecured indebtedness of the Company and are senior in right of payment to all existing and future subordinated indebtedness of the Company. The Company is a holding company that conducts all of its operations through subsidiaries; consequently, the senior notes are structurally subordinated to all obligations of its subsidiaries. Interest on the Company's senior notes is payable semiannually. Principal maturities. Principal maturities of long-term debt at December 31, 2017 , are as follows (in millions): 2018 $ 450 2019 $ — 2020 $ 450 2021 $ 500 2022 $ 600 Thereafter $ 750 Interest expense. The following amounts have been incurred and charged to interest expense for the years ended December 31, 2017 , 2016 and 2015 : Year Ended December 31, 2017 2016 2015 (in millions) Cash payments for interest $ 164 $ 196 $ 148 Amortization of issuance discounts 1 9 13 Amortization of capitalized loan fees 4 4 5 Net changes in accruals (9 ) 2 25 Interest incurred 160 211 191 Less capitalized interest (7 ) (4 ) (4 ) Total interest expense $ 153 $ 207 $ 187 |
Incentive Plans
Incentive Plans | 12 Months Ended |
Dec. 31, 2017 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Incentive Plans | Incentive Plans Deferred compensation retirement plan. In August 1997, the Compensation Committee of the Company's board of directors (the "Board") approved a deferred compensation retirement plan for the officers and certain key employees of the Company. Each officer and key employee is allowed to contribute up to 25 percent of their base salary and 100 percent of their annual bonus. The Company will provide a matching contribution of 100 percent of the officer's and key employee's contribution limited to the first ten percent of the officer's base salary and eight percent of the key employee's base salary. The Company's matching contribution vests immediately. A trust fund has been established by the Company to accumulate the contributions made under this retirement plan. The Company's matching contributions were $3 million for each of the years ended December 31, 2017 , 2016 and 2015 , respectively. 401(k) plan. The Pioneer Natural Resources USA, Inc. ("Pioneer USA," a wholly-owned subsidiary of the Company) 401(k) and Matching Plan (the "401(k) Plan") is a defined contribution plan established under the Internal Revenue Code Section 401. All regular full-time and part-time employees of Pioneer USA are eligible to participate in the 401(k) Plan on the first day of the month following their date of hire. Participants may contribute an amount up to 80 percent of their annual salary into the 401(k) Plan. Matching contributions are made to the 401(k) Plan in cash by Pioneer USA in amounts equal to 200 percent of a participant's contributions to the 401(k) Plan that are not in excess of five percent of the participant's base compensation (the "Matching Contribution"). Each participant's account is credited with the participant's contributions, Matching Contributions and allocations of the 401(k) Plan's earnings. Participants are fully vested in their account balances except for Matching Contributions and their proportionate share of 401(k) Plan earnings attributable to Matching Contributions, which proportionately vest over a four -year period that begins with the participant's date of hire. During the years ended December 31, 2017 , 2016 and 2015 , the Company recognized compensation expense of $25 million , $23 million and $31 million , respectively, as a result of Matching Contributions. Stock-based compensation costs. In accordance with GAAP, the Company records stock-based compensation expense ratably over the vesting periods of the Company's stock-based compensation awards using the awards' fair value. The Company maintains two plans providing for stock-based compensation: the Amended and Restated 2006 Long-Term Incentive Plan ("LTIP") and the Employee Stock Purchase Plan ("ESPP"). Long-Term Incentive Plan. The LTIP provides for the granting of various forms of awards, including stock options, stock appreciation rights, performance units, restricted stock and restricted stock units to directors, officers and employees of the Company. The shares to be delivered under the LTIP shall be made available from (i) authorized but unissued shares, (ii) shares held as treasury stock or (iii) previously issued shares reacquired by the Company, including shares purchased on the open market. In May 2016, the stockholders of the Company approved a 3.5 million increase in the number of shares available under the plan. The following table shows the number of shares available for issuance pursuant to awards under the LTIP at December 31, 2017 : Approved and authorized awards 12,600,000 Awards issued under plan (7,657,755 ) Awards available for future grant 4,942,245 Employee Stock Purchase Plan. The ESPP allows eligible employees to annually purchase the Company's common stock at a discounted price. Officers of the Company are not eligible to participate in the ESPP. Contributions to the ESPP are limited to 15 percent of an employee's pay (subject to certain ESPP limits) during the eight -month offering period (January 1 to August 31). Participants in the ESPP purchase the Company's common stock at a price that is 15 percent below the closing sales price of the Company's common stock on either the first day or the last day of each offering period, whichever closing sales price is lower. The following table shows the number of shares available for issuance under the ESPP at December 31, 2017 : Approved and authorized shares 1,250,000 Shares issued (951,285 ) Shares available for future issuance 298,715 The following table reflects stock-based compensation expense recorded for each type of stock-based compensation award and the associated income tax benefit for the years ended December 31, 2017 , 2016 and 2015 : Year Ended December 31, 2017 2016 2015 (in millions) Restricted stock-Equity Awards $ 60 $ 66 $ 70 Restricted stock-Liability Awards 24 24 22 Stock options (a) — — — Performance unit awards 17 21 18 ESPP 2 2 2 Total $ 103 $ 113 $ 112 Income tax benefit $ 19 $ 34 $ 34 _____________________ (a) Cash proceeds received from stock option exercises during 2017 and 2016 amounted to $300 thousand and $1 million , respectively. There were no stock option exercises during 2015 . As of December 31, 2017 , there was $94 million of unrecognized stock-based compensation expense related to unvested share-based compensation plans, including $22 million attributable to Liability Awards that are expected to be settled in cash on their vesting dates. The stock-based compensation expense will be recognized on a straight-line basis over the remaining vesting periods of the awards, which is a period of less than three years on a weighted average basis. Restricted stock awards. During 2017 , the Company awarded 450,619 restricted shares or units of the Company's common stock as compensation to directors, officers and employees of the Company (including 117,984 shares or units representing Liability Awards). The Company's issued shares, as reflected in the accompanying consolidated balance sheet as of December 31, 2017 , do not include 77,727 of issued, but unvested shares awarded under stock-based compensation plans that have voting rights. The following table reflects the restricted stock award activity for the year ended December 31, 2017 : Equity Awards Liability Awards Number of Shares Weighted Average Grant- Date Fair Value Number of Shares Outstanding at beginning of year 1,077,227 $ 143.39 290,552 Shares granted 332,635 $ 180.50 117,984 Shares forfeited (33,283 ) $ 153.17 (20,687 ) Shares vested (460,356 ) $ 153.06 (135,114 ) Outstanding at end of year 916,223 $ 151.71 252,735 The weighted average grant-date fair value of restricted stock equity awards awarded during 2017 , 2016 and 2015 was $180.50 , $122.72 and $153.55 , respectively. The grant-date fair value of restricted stock equity awards that vested during 2017 , 2016 and 2015 was $70 million , $66 million and $76 million , respectively. As of December 31, 2017 and 2016 , accounts payable – due to affiliates in the accompanying consolidated balance sheets includes $20 million and $22 million , respectively, of liabilities attributable to the Liability Awards, representing the fair value of the earned, but unvested, portion of the outstanding awards as of that date. The cash paid for Liability Awards that vested during 2017 , 2016 and 2015 was $20 million , $18 million and $29 million , respectively. Stock option awards. Certain employees may be granted options to purchase shares of the Company's common stock with an exercise price equal to the fair market value of Pioneer common stock on the date of grant. The fair value of stock option awards is determined using the Black-Scholes option-pricing model. Option awards have a ten -year contract life. The expected life of an option is estimated based on historical and expected exercise behavior. The volatility assumption was estimated based upon expectations of volatility over the life of the option as measured by historical volatility. The risk-free interest rate was based on the United States Treasury rate for a term commensurate with the expected life of the option. The dividend yield was based upon a seven -year average dividend yield. A summary of the Company's nonstatutory stock option awards activity for the year ended December 31, 2017 is presented below: Number of Shares Weighted Average Exercise Price Weighted Average Remaining Contractual Life Aggregate Intrinsic Value (in years) (in millions) Outstanding at beginning of year 159,378 $ 89.03 Options exercised (20,885 ) $ 15.62 Outstanding at end of year 138,493 $ 100.10 3.61 $ 10 Exercisable at end of year 138,493 $ 100.10 3.61 $ 10 The Company has not granted stock options since February 2012. The intrinsic value of options exercised during 2017 and 2016 was $3 million and $6 million , respectively, based on the difference between the market price at the exercise date and the option exercise price. There were no options exercised during 2015 . Performance unit awards. During 2017 , 2016 and 2015 , the Company awarded performance units to certain of the Company's officers under the LTIP. The number of shares of common stock to be issued is determined by comparing the Company's total shareholder return to the total shareholder return of a predetermined group of peer companies over the performance period. The performance unit awards vest over a 34 -month service period. The grant-date fair values per unit of the 2017 , 2016 and 2015 performance unit awards were $258.27 , $203.69 and $222.33 , respectively, which amounts were determined using the Monte Carlo simulation method and are being recognized as stock-based compensation expense ratably over the performance period. The Monte Carlo simulation model utilizes multiple input variables that determine the probability of satisfying the market condition stipulated in the award grant and calculates the fair value of the award. Expected volatilities utilized in the model were estimated using a historical period consistent with the performance period of approximately three years . The risk-free interest rate was based on the United States Treasury rate for a term commensurate with the expected life of the grant. The Company used the following assumptions to estimate the fair value of performance unit awards granted during 2017 , 2016 and 2015 : 2017 2016 2015 Risk-free interest rate 1.42% 0.96% 1.03% Range of volatilities 33.6 % - 58.2% 28.3 % - 53.6% 26.1 % - 41.3% The following table summarizes the performance unit activity for the year ended December 31, 2017 : Number of Units (a) Weighted Average Grant-Date Fair Value Beginning performance unit awards 178,556 $ 211.46 Units granted 59,044 $ 258.27 Units forfeited — $ — Units vested (b) (74,442 ) $ 222.33 Ending performance unit awards 163,158 $ 223.45 _____________________ (a) These amounts reflect the number of performance units granted. The actual payout of shares may be between zero percent and 250 percent of the performance units granted depending upon the total shareholder return ranking of the Company compared to peer companies at the vesting date. (b) On December 31, 2017 , the service period lapsed on 78,796 performance unit awards that earned 1.50 shares for each vested award, representing 118,198 aggregate shares of common stock issued on January 2, 2018. The vested performance units that earned 1.50 shares for each vested award included 74,442 units vested in the current year, 4,029 units that vested in 2016 and 325 units that vested in 2015 upon the retirement of the officers to whom the performance unit awards were granted. The grant-date fair value of performance units that vested during 2017 , 2016 and 2015 was $18 million , $15 million and $17 million , respectively. |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2017 | |
Asset Retirement Obligation [Abstract] | |
Asset Retirement Obligations | Asset Retirement Obligations The Company's asset retirement obligations primarily relate to the future plugging and abandonment of wells and related facilities. Market risk premiums associated with asset retirement obligations are estimated to represent a component of the Company's credit-adjusted risk-free rate that is utilized in the calculations of asset retirement obligations. The following table summarizes the Company's asset retirement obligation activity during the years ended December 31, 2017 , 2016 and 2015 : Year Ended December 31, 2017 2016 2015 (in millions) Beginning asset retirement obligations $ 297 $ 285 $ 189 Obligations assumed in acquisitions — 2 — New wells placed on production 3 2 4 Changes in estimates (a) (9 ) 17 103 Dispositions (7 ) — — Liabilities settled (32 ) (27 ) (23 ) Accretion of discount 19 18 12 Ending asset retirement obligations $ 271 $ 297 $ 285 _____________________ (a) Changes in estimates are determined based on several factors, including abandonment cost estimates based on recent actual costs incurred to abandon wells, credit-adjusted risk-free discount rates and well life estimates. The decrease in 2017 was primarily due to a increase in commodity prices, which has the effect of lengthening the economic life of the Company's producing wells. The increase in 2016 was primarily due to the forecasted timing of abandoning the Company's oil and gas wells being accelerated as a result of lower commodity prices, which has the effect of shortening the economic lives of the Company's producing wells. As of December 31, 2017 and 2016 , the current portions of the Company's asset retirement obligations were $41 million and $39 million , respectively. |
Commitments And Contingencies
Commitments And Contingencies | 12 Months Ended |
Dec. 31, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Commitments and Contingencies Severance agreements. The Company has entered into severance and change in control agreements with its officers and certain key employees. The current annual salaries for the officers and key employees covered under such agreements total $32 million . Indemnifications. The Company has agreed to indemnify its directors and certain of its officers, employees and agents with respect to claims and damages arising from acts or omissions taken in such capacity, as well as with respect to certain litigation. Legal actions. The Company is party to various proceedings and claims incidental to its business. While many of these matters involve inherent uncertainty, the Company believes that the amount of the liability, if any, ultimately incurred with respect to these proceedings and claims will not have a material adverse effect on the Company's consolidated financial position as a whole or on its liquidity, capital resources or future annual results of operations. The Company records reserves for contingencies when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated. Environmental. Environmental expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Environmental expenditures that extend the life of the related property or mitigate or prevent future environmental contamination are capitalized. Liabilities for expenditures that will not qualify for capitalization are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated. Such liabilities are undiscounted unless the timing of cash payments for the liability is fixed or reliably determinable. Environmental liabilities normally involve estimates that are subject to revision until settlement occurs. Obligations following divestitures. In connection with its divestiture transactions, the Company may retain certain liabilities and provides the purchaser certain indemnifications, subject to defined limitations, which may apply to identified pre-closing matters, including matters of litigation, environmental contingencies, royalty obligations and income taxes. The Company does not believe that these obligations are probable of having a material impact on its liquidity, financial position or future results of operations. Drilling commitments. The Company's principal drilling commitments are related to drilling rig contracts that require the Company to pay day rates for contracted drilling rigs over their contractual term. Certain of the drilling rig day rates are based upon oil prices and are subject to change over the lives of the commitments. In addition, the Company periodically enters into contractual arrangements under which the Company is committed to expend funds to drill wells in the future. The Company recognizes its drilling commitments in the periods in which the rig services are performed. Lease agreements. The Company leases equipment and office facilities under operating leases. Rent expense for the years ended December 31, 2017 , 2016 and 2015 was $ 69 million , $59 million and $58 million , respectively. In June 2017, the Company entered into a 20 -year operating lease for the Company's new corporate headquarters that is currently being constructed in Irving, Texas. Annual base rent is expected to be $33 million and lease payments are expected to commence once the building is complete, which is anticipated to occur during the second half of 2019. The Company has a variable equity interest in the entity that is constructing the building. The Company is not the primary beneficiary of the variable interest entity and only has a profit sharing interest after certain economic returns are achieved. The Company has no exposure to the variable interest entity's losses or future liabilities, if any. The Company is the deemed owner of the building (for accounting purposes) during the construction period and is following the build-to-suit accounting guidance. Accordingly, as of December 31, 2017 , the Company has capitalized $57 million of construction costs, including capitalized interest, within other property and equipment and has recognized a corresponding build-to-suit lease liability of $56 million . The recording of these assets and liabilities are considered noncash investing (other than capitalized interest) and financing items, respectively, for purposes of the consolidated statements of cash flows. Firm purchase, gathering, processing, transportation and fractionation commitments. The Company from time to time enters into, and as of December 31, 2017 was a party to, take-or-pay agreements, which include contractual commitments to purchase sand and water for use in the Company's drilling operations and contractual commitments with midstream service companies and pipeline carriers for future gathering, processing, transportation, storage and fractionation. These commitments are normal and customary for the Company's business activities. Certain future minimum gathering, processing, transportation, storage and fractionation fees are based upon rates and tariffs that are subject to change over the lives of the commitments. The Company's minimum commitments as of December 31, 2017 are as follows: Drilling Commitments Lease Commitments Purchase, Gathering, Processing, Transportation, Storage and Fractionation Commitments Total (in millions) 2018 $ 93 $ 27 $ 568 $ 688 2019 $ 41 $ 42 $ 619 $ 702 2020 $ 37 $ 53 $ 672 $ 762 2021 $ — $ 40 $ 627 $ 667 2022 $ — $ 37 $ 476 $ 513 Thereafter $ — $ 680 $ 1,554 $ 2,234 Total minimum commitments $ 171 $ 879 $ 4,516 $ 5,566 Delivery commitments. The above commitments include demand fees associated with volume delivery commitments that are primarily related to the Permian Basin. If the Company does not expect to be able to fulfill its short-term and long-term delivery obligations from projected production of available reserves, the Company expects to purchase third party volumes, where applicable, to satisfy its commitment assuming it is economic to do so; otherwise, it will pay the demand fees associated with any commitment shortfalls. The Company's delivery commitments as of December 31, 2017 are as follows: Oil Gas (MBbls per day) (MMBtu per day) 2018 66,685 — 2019 63,356 75,342 2020 68,347 100,000 2021 70,000 100,000 2022 30,575 100,000 2023 — 100,000 2024 — 24,863 |
Related Party Transactions
Related Party Transactions | 12 Months Ended |
Dec. 31, 2017 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | Related Party Transactions Transactions with EFS Midstream. Prior to July 2015, the Company, through a wholly-owned subsidiary, owned a noncontrolling interest in its unconsolidated affiliate, EFS Midstream. In July 2015, the Company completed the sale of its interest in EFS Midstream to an unaffiliated third party. Prior to July 2015, the Company also (i) provided certain services as the manager of EFS Midstream in accordance with a Master Services Agreement and (ii) contracted for services from EFS Midstream under a Hydrocarbon Gathering and Handling Agreement (the "HGH Agreement"). Master Services Agreement. The terms of the Master Services Agreement provided that the Company would perform certain manager services for EFS Midstream and be compensated by monthly fixed payments and variable payments attributable to expenses incurred by employees whose time was substantially dedicated to EFS Midstream's business. During 2015 , the Company received $2 million of fixed payments and $9 million of variable payments, from EFS Midstream. Hydrocarbon Gathering and Handling Agreement. Under the terms of the HGH Agreement, EFS Midstream was obligated to construct certain equipment and facilities capable of gathering, treating and transporting oil and gas production from the Eagle Ford Shale properties operated by the Company. The HGH Agreement obligated the Company to use the EFS Midstream gathering, treating and transportation equipment and facilities. In accordance with the terms of the HGH Agreement, the Company paid EFS Midstream $54 million of gathering and treating fees during 2015 prior to its sale. Such amounts were expensed as oil and gas production costs in the accompanying consolidated statements of operations. |
Major Customer
Major Customer | 12 Months Ended |
Dec. 31, 2017 | |
Risks and Uncertainties [Abstract] | |
Major Customers | Major Customers The Company's share of oil and gas production is sold to various purchasers who must be prequalified under the Company's credit risk policies and procedures. The Company records allowances for doubtful accounts based on the age of accounts receivables and the financial condition of its purchasers and, depending on facts and circumstances, may require purchasers to provide collateral or otherwise secure their accounts. The following purchasers individually accounted for ten percent or more of the Company's consolidated oil, NGL and gas production revenues in at least one of the three years ended December 31, 2017 : Year Ended December 31, 2017 2016 2015 Sunoco Logistics Partners L.P. (a) 21 % 19 % 18 % Occidental Energy Marketing Inc. 16 % 16 % 18 % Plains Marketing LP 14 % 16 % 22 % Enterprise Products Partners L.P. 11 % 12 % 12 % ______________________ (a) Sunoco Logistics Partners L.P. ("Sunoco") acquired Vitol Inc.'s Permian Basin oil systems during the fourth quarter of 2016, and the Company's contracts with Vitol Inc. were transferred to Sunoco. The loss of any of these significant purchasers could have a material adverse effect on the ability of the Company to sell its oil and gas production. The Company enters into purchase transactions with third parties and separate sale transactions with third parties to diversify a portion of the Company's WTI oil sales to a Gulf Coast and export market price and to satisfy unused pipeline capacity commitments. The following purchasers individually accounted for ten percent or more of the Company's consolidated oil, NGL and gas revenues from sales of commodities purchased from third parties in at least one of the three years ended December 31, 2017 : Year Ended December 31, 2017 2016 2015 Occidental Energy Marketing Inc. 39 % 27 % 25 % Valero Marketing and Supply Company 14 % 17 % 50 % BP Energy 11 % 18 % — % Exxon Mobil 11 % 23 % 12 % The presentation of certain purchases and sales of third-party oil and gas with the same counterparty has been revised in 2016 and 2015 to present such transactions on a net basis in purchased oil and gas expense. Previously, these purchase and sales, which were carried out as purchases from and sales to the same third party, were separately stated on a gross basis in sales of purchased oil and gas and purchased oil and gas expense. See Note B for additional information about the revision of the Company's revenues and expenses associated with these transactions. The Company believes that the loss of any of these purchasers would not have an adverse effect on the ability of the Company to sell commodities it purchases from third parties. |
Interest And Other Income
Interest And Other Income | 12 Months Ended |
Dec. 31, 2017 | |
Other Income and Expenses [Abstract] | |
Interest and Other Income | Interest and Other Income The following table provides the components of the Company's interest and other income during the years ended December 31, 2017 , 2016 and 2015 : Year Ended December 31, 2017 2016 2015 (in millions) Interest income $ 32 $ 22 $ 3 Severance, sales and property tax refunds 13 2 — Deferred compensation plan income 4 3 4 Other income 4 5 10 Equity interest in income of EFS Midstream (a) — — 5 Total interest and other income $ 53 $ 32 $ 22 ______________________ (a) The Company accounted for its investment in EFS Midstream prior to its sale in July 2015 using the equity method. EFS Midstream provided gathering, treating and transportation services for the Company. See Note C for additional information on the Company's sale of EFS Midstream. |
Other Expense
Other Expense | 12 Months Ended |
Dec. 31, 2017 | |
Other Income and Expenses [Abstract] | |
Other Expense | Other Expense The following table provides the components of the Company's other expense during the years ended December 31, 2017 , 2016 and 2015 : Year Ended December 31, 2017 2016 2015 (in millions) Transportation commitment charges (a) $ 167 $ 109 $ 53 Other 58 49 27 Loss from vertical integration services (b) 17 54 34 Impairment of inventory and other property and equipment (c) 2 8 86 Idle drilling and well service equipment charges (d) — 64 92 Restructuring charges (e) — 4 23 Total other expense $ 244 $ 288 $ 315 ____________________ (a) Primarily represents firm transportation payments on excess pipeline capacity commitments. (b) Loss from vertical integration services primarily represents net margins (attributable to third party working interest owners) that result from Company-provided fracture stimulation and well service operations, which are ancillary to and supportive of the Company's oil and gas joint operating activities, and do not represent intercompany transactions. For the three years ended December 31, 2017 , 2016 and 2015 , these net losses include $140 million , $147 million and $298 million of gross vertical integration revenues, respectively, and $157 million , $201 million and $332 million of total vertical integration costs and expenses, respectively. (c) Primarily represents charges to reduce excess materials and supplies inventories to their market values for the years ended December 31, 2017 , 2016 and 2015 , respectively. See Note D for additional information on the fair value of material and supplies inventory. (d) Primarily represents expenses attributable to idle drilling rig fees that are not chargeable to joint operations and charges to terminate rig contracts that were not required to meet planned drilling activities. (e) Represents restructuring costs associated with the Company's restructuring of its operations in South Texas in 2016 and Colorado in 2015. See Note B for additional information on the restructuring charges. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Income Taxes The Company and its eligible subsidiaries file a consolidated United States federal income tax return. Certain subsidiaries are not eligible to be included in the consolidated United States federal income tax return and separate provisions for income taxes have been determined for these entities or groups of entities. The tax returns and the amount of taxable income or loss are subject to examination by United States federal, state, local and foreign taxing authorities. The Company received tax refunds of $66 million (net of tax payments) during 2016 and made current and estimated tax payments of nil and $43 million (net of tax refunds) during 2017 and 2015 , respectively. The Company continually assesses both positive and negative evidence to determine whether it is more likely than not that deferred tax assets can be realized prior to their expiration. Pioneer monitors Company-specific, oil and gas industry and worldwide economic factors and assesses the likelihood that the Company's net operating loss carryforwards ("NOLs") and other deferred tax attributes in the United States federal, state, local and foreign tax jurisdictions will be utilized prior to their expiration. Enactment of the Tax Cuts and Jobs Act On December 22, 2017, the United States enacted the Tax Cuts and Jobs Act (the "Tax Reform Legislation"), which introduces significant changes to the United States federal income tax law. The changes that most impact the Company include: • A permanent reduction in the federal corporate income tax rate from 35 percent to 21 percent . The rate reduction is effective for the Company as of January 1, 2018. The application of the rate change on the Company's existing deferred tax liabilities resulted in a $625 million income tax benefit to the Company during 2017 . • The corporate alternative minimum tax ("AMT") for tax years beginning in January 1, 2018 has been repealed. The Tax Reform Legislation provides that existing AMT credit carryovers are refundable beginning in 2018 . As of December 31, 2017 , the Company had AMT credit carryovers of $20 million that are expected to be fully refunded by 2022 . • The Tax Reform Legislation preserves the deductibility of intangible drilling costs and provides for 100 percent bonus depreciation on personal tangible property expenditures through 2022. The bonus depreciation percentage is phased down from 100 percent beginning in 2023 through 2026. The Tax Reform Legislation is a comprehensive bill containing other provisions, such as limitations on the deductibility of interest expense and certain executive compensation, that are not expected to materially affect Pioneer. The ultimate impact of the Tax Reform Legislation may differ from the Company's estimates as of December 31, 2017 due to changes in the interpretations and assumptions made by the Company as well as additional regulatory guidance that may be issued. Uncertain tax positions The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based upon the technical merits of the position. As of December 31, 2017 and 2016 , the Company had unrecognized tax benefits of $124 million and $112 million , respectively, resulting from research and experimental expenditures related to horizontal drilling and completion innovations. If all or a portion of the unrecognized tax benefit is sustained upon examination by the taxing authorities, the tax benefit will be recognized as a reduction to the Company's deferred tax liability and will affect the Company's effective tax rate in the period it is recognized. The Company is unable to estimate the range of a reasonably likely outcome at this time. The Company expects to substantially resolve the uncertainties associated with the unrecognized tax benefits by December 2018 . The following table sets forth changes in the Company's unrecognized tax benefits: Year Ended December 31, 2017 2016 Balance at beginning of year $ 112 $ — Additions based on tax positions related to the current year 12 112 Reductions for tax positions of prior years — — Balance at end of year $ 124 $ 112 Other Tax Matters With respect to income taxes, the Company's policy is to account for interest charges as interest expense and any penalties as other expense in the accompanying consolidated statements of operations. The Company files income tax returns in the United States federal jurisdiction, and various state and foreign jurisdictions. As of December 31, 2017 , there are no proposed adjustments in any jurisdiction that would have a significant effect on the Company's future results of operations or financial position. The Company's earliest open years in its key jurisdictions are as follows: U.S. federal 2012 Various U.S. states 2013 The Company's income tax benefit and amounts separately allocated were attributable to the following items for the years ended December 31, 2017 , 2016 and 2015 : Year Ended December 31, 2017 2016 2015 (in millions) Income tax benefit from continuing operations $ 524 $ 403 $ 155 Income tax benefit from discontinued operations $ — $ — $ 2 The Company's income tax (provision) benefit attributable to income from continuing operations consisted of the following for the years ended December 31, 2017 , 2016 and 2015 : Year Ended December 31, 2017 2016 2015 (in millions) Current: U.S. federal $ 5 $ 22 $ (22 ) U.S. state — 2 (1 ) 5 24 (23 ) Deferred: U.S. federal 526 375 165 U.S. state (7 ) 4 13 519 379 178 Income tax benefit from continuing operations $ 524 $ 403 $ 155 Reconciliations of the United States federal statutory tax rate to the Company's effective tax rate for income (loss) from continuing operations are as follows for the years ended December 31, 2017 , 2016 and 2015 : Year Ended December 31, 2017 2016 2015 (in millions, except percentages) Income (loss) from continuing operations attributable to common stockholders before income taxes $ 309 $ (959 ) $ (421 ) Federal statutory income tax rate 35 % 35 % 35 % (Provision) benefit for federal income taxes at the statutory rate (108 ) 336 147 State income tax (provision) benefit (net of federal tax) (4 ) 3 8 State valuation allowance (net of federal tax) (1 ) (3 ) — Change in federal income tax rate (a) 625 — — Equity compensation excess tax benefit (b) 9 — — Federal credit for increasing research activities (net of unrecognized tax benefits) 6 68 — State credit for increasing research activities (net of unrecognized tax benefits and federal tax) — 4 — Other (3 ) (5 ) — Income tax benefit from continuing operations $ 524 $ 403 $ 155 Effective income tax rate, excluding net income attributable to the noncontrolling interests (170 )% 42 % 37 % ____________________ (a) During 2017, the Company recognized a benefit of $625 million as a result of the December 22, 2017 Tax Reform Legislation that reduces the federal income tax rate beginning in 2018. (b) During 2017, the Company recognized excess tax benefits of $9 million associated with the adoption of ASU 2016-09, "Improvements to Employee Share-Based Payment Accounting," which requires excess tax benefits or deficiencies associated with the vesting of long-term incentive awards to be recorded as income tax expense or benefit in the statement of operations rather than as an adjustment to additional paid-in capital in the balance sheet. The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities related to continuing operations are as follows as of December 31, 2017 and 2016 : December 31, 2017 2016 (in millions) Deferred tax assets: Net operating loss carryforward (a) $ 594 $ 635 Credit carryforwards (b) 87 107 Asset retirement obligations 59 106 Incentive plans 48 81 Net deferred hedge losses 52 32 Other 22 30 Total deferred tax assets 862 991 Deferred tax liabilities: Oil and gas properties, principally due to differences in basis, depletion and the deduction of intangible drilling costs for tax purposes (1,640 ) (2,184 ) Other property and equipment, principally due to the deduction of bonus depreciation for tax purposes (121 ) (204 ) Total deferred tax liabilities (1,761 ) (2,388 ) Net deferred tax liability $ (899 ) $ (1,397 ) ____________________ (a) Net operating loss carryforwards as of December 31, 2017 consist of $2.8 billion of U.S. federal NOLs, which expire between 2032 and 2037 , and $164 million of Colorado NOLs, which expire between 2027 and 2037 , and are net of a $6 million valuation allowance relating to $125 million of Colorado NOLs that the Company believes will more likely than not expire unutilized. (b) Credit carryforwards as of December 31, 2017 consist of U.S. federal credits for increasing research activities of $82 million and Texas credits for increasing research activities of $5 million . The U.S. federal and state research credits as of December 31, 2017 exclude $124 million of unrecognized tax benefits. |
Net Income Per Share Attributab
Net Income Per Share Attributable To Common Stockholders | 12 Months Ended |
Dec. 31, 2017 | |
Earnings Per Share [Abstract] | |
Net Income Per Share Attributable To Common Stockholders | Net Income Per Share Attributable To Common Stockholders In the calculation of basic net income (loss) per share attributable to common stockholders, participating securities are allocated earnings based on actual dividend distributions received plus a proportionate share of undistributed net income attributable to common stockholders, 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. The computation of diluted net income (loss) per share attributable to common stockholders reflects the potential dilution that could occur if securities or other contracts to issue common stock that are dilutive were exercised or converted into common stock or resulted in the issuance of common stock that would then share in the earnings of the Company. During periods in which the Company realizes a loss from continuing operations attributable to common stockholders, securities or other contracts to issue common stock would not be dilutive to net loss per share and conversion into common stock is assumed not to occur. Diluted net income (loss) per share is calculated under both the two-class method and the treasury stock method and the more dilutive of the two calculations is presented. The Company's basic net income (loss) per share attributable to common stockholders is computed as (i) net income (loss) attributable to common stockholders, (ii) less participating share- and unit-based basic earnings (iii) divided by weighted average basic shares outstanding. The Company's diluted net income (loss) per share attributable to common stockholders is computed as (i) basic net income (loss) attributable to common stockholders, (ii) plus diluted adjustments to participating undistributed earnings (iii) divided by weighted average diluted shares outstanding. The following table is a reconciliation of the Company's net income (loss) attributable to common stockholders to basic and diluted net income (loss) attributable to common stockholders for the years ended December 31, 2017 , 2016 and 2015 : Year Ended December 31, 2017 2016 2015 (in millions) Income (loss) from continuing operations $ 833 $ (556 ) $ (266 ) Participating basic earnings (a) (6 ) — — Basic and diluted net income (loss) from continuing operations 827 (556 ) (266 ) Basic and diluted net loss from discontinued operations — — (7 ) Basic and diluted net income (loss) attributable to common stockholders $ 827 $ (556 ) $ (273 ) ______________________ (a) Unvested restricted stock awards represent participating securities because they participate in nonforfeitable dividends with the common equity owners of the Company. Participating share- or unit-based earnings represent the distributed and undistributed earnings of the Company attributable to the participating securities. Unvested restricted stock awards do not participate in undistributed net losses as they are not contractually obligated to do so. Basic and diluted weighted average common shares outstanding were 170 million , 166 million and 149 million for the years ended December 31, 2017 , 2016 and 2015 , respectively. |
Subsequent Events
Subsequent Events | 12 Months Ended |
Dec. 31, 2017 | |
Subsequent Events [Abstract] | |
Subsequent Events | Subsequent Events In February 2018, the Company announced its intention to divest its properties in South Texas, Raton and the West Panhandle field and focus its efforts and capital resources to its Permian Basin assets. No assurance can be given that the sales will be completed in accordance with the Company's plans or on terms and at prices acceptable to the Company. In February 2018, the Board (i) declared a cash dividend of $0.16 per share on Pioneer’s outstanding common stock, payable April 12, 2018 to stockholders of record at the close of business on March 29, 2018 and (ii) approved a common stock repurchase program to offset the impact of dilution associated with annual employee stock awards. The stock repurchase program allows for up to $100 million of common stock to be repurchased during 2018. |
Summary Of Significant Accoun25
Summary Of Significant Accounting Policies (Policy) | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Policies [Abstract] | |
Principles of consolidation | Principles of consolidation. The consolidated financial statements include the accounts of the Company and its wholly-owned and majority-owned subsidiaries since their acquisition or formation. All material intercompany balances and transactions have been eliminated. |
Reclassifications | Certain reclassifications have been made to the 2016 and 2015 consolidated financial statement and footnote amounts in order to conform them to the 2017 presentations. |
Use of estimates in the preparation of financial statements | Use of estimates in the preparation of financial statements. Preparation of the accompanying consolidated financial statements in conformity with generally accepted accounting principles in the United States ("GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Depletion of oil and gas properties and impairment of goodwill and proved and unproved oil and gas properties, in part, is determined using estimates of proved, probable and possible oil and gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved, probable and possible reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves and commodity price outlooks. Actual results could differ from the estimates and assumptions utilized. |
Cash and cash equivalents | Cash and cash equivalents. The Company's cash and cash equivalents include depository accounts held by banks and marketable securities with original issuance maturities of 90 days or less. |
Investments | Investments. Periodically, the Company invests in commercial paper and corporate bonds with investment grade rated entities. The Company also periodically enters into time deposits with financial institutions. Commercial paper and time deposits are included in cash and cash equivalents if they have maturity dates that are less than 90 days at the date of purchase; otherwise, investments are reflected in short-term investments or long-term investments in the accompanying consolidated balance sheets based on their maturity dates |
Accounts receivable | Accounts receivable. As of December 31, 2017 and 2016 , the Company had accounts receivable – trade, net of allowances for bad debts, of $639 million and $517 million , respectively. The Company's accounts receivable – trade are primarily comprised of oil and gas sales receivables, joint interest receivables and other receivables for which the Company does not require collateral security. As of December 31, 2017 and 2016 , the Company's allowances for doubtful accounts totaled $1 million for both respective periods. The Company establishes allowances for bad debts equal to the estimable portions of accounts receivable for which failure to collect is considered probable. The Company estimates the portions of joint interest receivables for which failure to collect is probable based on percentages of joint interest receivables that are past due. The Company estimates the portions of other receivables for which failure to collect is probable based on the relevant facts and circumstances surrounding the receivable. Allowances for doubtful accounts are recorded as reductions to the carrying values of the receivables included in the Company's accompanying consolidated balance sheets and as charges to other expense in the accompanying consolidated statements of operations in the accounting periods during which failure to collect an estimable portion is determined to be probable. |
Inventories | Inventories. The Company's inventories consist of materials, supplies and commodities. The Company's materials and supplies inventory is primarily comprised of oil and gas drilling or repair items such as tubing, casing, proppant used to fracture-stimulate oil and gas wells, water, chemicals, operating supplies and ordinary maintenance materials and parts. The materials and supplies inventory is primarily acquired for use in future drilling operations or repair operations and is carried at the lower of cost or market, on a first-in, first-out cost basis. Valuation allowances for materials and supplies inventories are recorded as reductions to the carrying values of the materials and supplies inventories in the Company's accompanying consolidated balance sheets and as charges to other expense in the accompanying consolidated statements of operations. Commodity inventories are carried at the lower of cost or market, on a first-in, first-out basis. The Company's commodity inventories consist of oil, NGLs and gas volumes held in storage or as linefill in pipelines. Any valuation allowances of commodity inventories are recorded as reductions to the carrying values of the commodity inventories included in the Company's accompanying consolidated balance sheets and as charges to other expense in the accompanying consolidated statements of operations. |
Oil and gas properties | Oil and gas properties. The Company utilizes the successful efforts method of accounting for its oil and gas properties. Under this method, all costs associated with productive wells and nonproductive development wells are capitalized while nonproductive exploration costs and geological and geophysical expenditures are expensed. The Company capitalizes interest on expenditures for significant development projects, generally when the underlying project is sanctioned, until such projects are ready for their intended use. The Company does not carry the costs of drilling an exploratory well as an asset in its consolidated balance sheets following the completion of drilling unless both of the following conditions are met: (i) The well has found a sufficient quantity of reserves to justify its completion as a producing well; and (ii) The Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. Due to the capital-intensive nature and the geographical location of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and the economics associated with making a determination on its commercial viability. In these instances, the project's feasibility is not contingent upon price improvements or advances in technology, but rather the Company's ongoing efforts and expenditures related to accurately predicting the hydrocarbon recoverability based on well information, gaining access to other companies' production data in the area, transportation or processing facilities and/or getting partner approval to drill additional appraisal wells. These activities are ongoing and are being pursued constantly. Consequently, the Company's assessment of suspended exploratory well costs is continuous until a decision can be made that the project has found sufficient proved reserves to sanction the project or is noncommercial and is charged to exploration and abandonments expense. See Note F for additional information regarding the Company's suspended exploratory well costs. The Company owns interests in 10 gas processing plants and four treating facilities. The Company is the operator of one of the gas processing plants and all four of the treating facilities. Nine of the gas processing plants are operated by third parties and one of the treating facilities is not currently being used. The Company's ownership interests in the gas processing plants and treating facilities are primarily to accommodate handling the Company's gas production and thus are considered a component of the capital and operating costs of the respective fields that they service. To the extent that there is excess capacity at a plant or treating facility, the Company attempts to process third-party gas volumes for a fee to keep the plant or treating facility at capacity. All revenues and expenses derived from third-party gas volumes processed through the plants and treating facilities are reported as components of oil and gas production costs. Third-party revenues generated from the processing plants and treating facilities in continuing operations for the years ended December 31, 2017 , 2016 and 2015 were $60 million , $41 million and $39 million , respectively. Third-party expenses attributable to the processing plants and treating facilities in continuing operations for the same respective periods were $26 million , $24 million and $27 million . The capitalized costs of the plants and treating facilities are included in proved oil and gas properties and are depleted using the unit-of-production method along with the other capitalized costs of the field that they service. The capitalized costs of proved properties are depleted using the unit-of-production method based on proved reserves. Costs of significant nonproducing properties, wells in the process of being drilled and development projects are excluded from depletion until the related project is completed and proved reserves are established or, if unsuccessful, impairment is determined. Proceeds from the sales of individual properties and the capitalized costs of individual properties sold or abandoned are credited and charged, respectively, to accumulated depletion, depreciation and amortization, if doing so does not materially impact the depletion rate of an amortization base. Generally, no gain or loss is recognized until an entire amortization base is sold. However, gain or loss is recognized from the sale of less than an entire amortization base if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the amortization base. The Company performs assessments of its long-lived assets to be held and used, including proved oil and gas properties accounted for under the successful efforts method of accounting, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. An impairment loss is indicated if the sum of the expected future cash flows, including vertical integrated services that are used in the development of the assets, is less than the carrying amount of the assets, including the carrying value of vertical integrated services assets. In these circumstances, the Company recognizes an impairment loss for the amount by which the carrying amount of the assets exceeds the estimated fair value of the assets. See Note D for additional information regarding the Company's impairment of proved oil and gas properties. Unproved oil and gas properties are periodically assessed for impairment on a project-by-project basis. These impairment assessments are affected by the results of exploration activities, commodity price outlooks, planned future sales or expirations of all or a portion of such projects. If the estimated future net cash flows attributable to such projects are not expected to be sufficient to fully recover the costs invested in each project, the Company will recognize an impairment loss at that time. |
Goodwill | Goodwill. During 2004, the Company recorded goodwill associated with a business combination, which represents the cost of the acquired entity over the net amounts assigned to assets acquired and liabilities assumed. In accordance with GAAP, goodwill is not amortized to earnings, but is assessed for impairment whenever events or circumstances indicate that impairment of the carrying value of goodwill is likely, but no less often than annually. If the carrying value of goodwill is determined to be impaired, it is reduced to the impaired value with a corresponding charge to earnings in the period in which it is determined to be impaired. During the third quarter of 2017 , the Company performed its annual qualitative assessment of goodwill to determine whether it was more likely than not that the fair value of the Company's reporting unit was less than its carrying amount as a basis for determining whether it was necessary to perform the two-step impairment test. Based on the results of the assessment, the Company determined it was not likely that the Company's goodwill was impaired. |
Other property and equipment, net | Other property and equipment, net. Other property and equipment is recorded at cost. As of December 31, 2017 and 2016 , the net carrying value of other property and equipment consisted of the following: As of December 31, 2017 (a) 2016 (a) (in millions) Land and buildings $ 529 $ 475 Proved and unproved sand properties (b) 488 484 Water infrastructure (c) 347 221 Equipment (d) 194 206 Information technology (e) 143 84 Leasehold improvements 20 22 Vehicles 19 15 Furniture and fixtures 19 22 $ 1,759 $ 1,529 ____________________ (a) At December 31, 2017 and 2016 , other property and equipment was net of accumulated depreciation of $936 million and $866 million , respectively. (b) Includes sand mines, facilities and unproved leaseholds that primarily provide the Company with proppant for use in the fracture stimulation of oil and gas wells. (c) Includes pipeline infrastructure costs and water supply wells. (d) Includes fracture stimulation and well servicing equipment that is owned by wholly-owned subsidiaries that provide pressure pumping and well services on Company-operated properties. As of December 31, 2017 , the Company owned eight fracture stimulation fleets and other oilfield services equipment, including pulling units, fracture stimulation tanks, water transport trucks, hot oilers, blowout preventers, construction equipment and fishing tools. (e) Information technology costs include hardware and software costs associated with the Company's existing systems and in-progress system upgrades. As of December 31, 2017 and 2016 , $93 million and $37 million , respectively, had not yet been placed into service. The primary purpose of the Company's sand mine, pressure pumping, well services and water infrastructure operations is to assist in the execution of the Company's drilling, completion and production operations by increasing the availability of supplies, equipment and services, rather than being dependent on third-party availability, and to contain associated costs. All intercompany profits or losses of the Company's sand mine, pressure pumping, well services and water infrastructure operations are eliminated. The capitalized costs of proved sand properties are depleted using the unit-of-production method based on proved sand reserves. Other property and equipment is depreciated over its estimated useful life on a straight-line basis. Buildings are generally depreciated over 20 to 39 years . Equipment, vehicles, furniture and fixtures and information technology assets are generally depreciated over two to 15 years . Water infrastructure is generally depreciated over 10 to 50 years . Leasehold improvements are amortized over the lesser of their estimated useful lives or the underlying terms of the associated leases. The Company reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the asset exceeds its estimated fair value. The estimated fair value is determined using either a discounted future cash flow model or another appropriate fair value method. |
Asset retirement obligations | Asset retirement obligations. The Company records a liability for the fair value of an asset retirement obligation in the period in which it is incurred, if a reasonable estimate of fair value can be made. Asset retirement obligations are generally capitalized as part of the carrying value of the long-lived asset to which it relates. Conditional asset retirement obligations meet the definition of liabilities and are recognized when incurred if their fair values can be reasonably estimated. The Company records the current and noncurrent portions of asset retirement obligations in other current liabilities and other liabilities, respectively, in the accompanying consolidated balance sheets and expenditures are classified as cash used in operating activities in the accompanying consolidated statements of cash flows. See Note I for additional information about the Company's asset retirement obligations. |
Treasury stock | Treasury stock. Treasury stock purchases are recorded at cost. Upon reissuance, the cost of treasury shares held is reduced by the average purchase price per share of the aggregate treasury shares held. |
Revenue recognition | Revenue recognition. The Company recognizes revenue when it is realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller's price to the buyer is fixed or determinable and (iv) collectability is reasonably assured. The Company enters into purchase transactions with third parties and separate sale transactions with third parties to diversify a portion of the Company's West Texas Intermediate oil ("WTI") sales to a Gulf Coast or export market price and to satisfy unused pipeline capacity commitments. Revenues and expenses from these transactions are presented on a gross basis as the Company acts as a principal in the transaction by assuming the risk and rewards of ownership, including credit risk, of the commodities purchased and assuming the responsibility to deliver the commodities sold. Transportation costs associated with purchases and sales of third-party oil and gas are presented on a net basis in purchased oil and gas expense. Firm transportation payments on excess pipeline capacity are included in other expense in the accompanying consolidated statements of operations. See Note N for further information on transportation commitment charges. |
Derivatives | Derivatives. All derivatives are recorded in the accompanying consolidated balance sheets at estimated fair value. The Company recognizes all changes in the fair values of its derivative contracts as gains or losses in the earnings of the periods in which they occur. The Company classifies the fair value amounts of derivative assets and liabilities executed under master netting arrangements as net current or noncurrent derivative assets or net current or noncurrent derivative liabilities, whichever the case may be, by commodity and counterparty. Net derivative asset values are determined, in part, by utilization of the derivative counterparties' credit-adjusted risk-free rate curves and net derivative liabilities are determined, in part, by utilization of the Company's credit-adjusted risk-free rate curve. The credit-adjusted risk-free rate curves for the Company and the counterparties are based on their independent market-quoted credit default swap rate curves plus the United States Treasury Bill yield curve as of the valuation date. See Note E for additional information about the Company's derivative instruments. |
Stock-based compensation | Stock-based compensation. Stock-based compensation expense is being recognized on restricted stock, restricted stock units, performance units and stock option awards that are expected to be settled in the Company's common stock ("Equity Awards") in the Company's consolidated financial statements on a straight line basis over the awards' vesting periods based on their fair values on the dates of grant or modification, as applicable. Stock-based compensation awards generally vest over a period of three years . The amount of stock-based compensation expense recognized at any date is approximately equal to the ratable portion of the grant date value of the award that is vested at that date. Stock-based compensation liability awards ("Liability Awards") are restricted stock awards that are expected to be settled in cash on their vesting dates, rather than in common stock. Liability Awards are recorded as accounts payable—affiliates based on the fair value of the vested portion of the awards on the balance sheet date. The fair values of Liability Awards are updated at each balance sheet date and changes in the fair values of the vested portions of the awards are recorded as increases or decreases to stock-based compensation expense. The Company utilizes (i) the Black-Scholes option pricing model to measure the fair value of stock options, (ii) the prior day's closing stock price on the date of grant to measure the fair value of Equity Awards and Liability Awards, (iii) the closing stock price on the balance sheet date to measure the fair value of the vested portions of Liability Awards and (iv) the Monte Carlo simulation method to measure the fair value of performance unit awards. |
Segments | Segments. Operating segments are defined as components of an enterprise that (i) engage in activities from which it may earn revenues and incur expenses (ii) for which separate operational financial information is available and is regularly evaluated by the chief operating decision maker for the purpose of allocating resources and assessing performance. Based upon how the Company is organized and managed, the Company has only one reportable operating segment, which is oil and gas development, exploration and production. The Company considers its vertical integration services as ancillary to its oil and gas development, exploration and producing activities and manages these services to support such activities. In addition, the Company has a single, company-wide management team that allocates capital resources to maximize profitability and measures financial performance as a single enterprise. |
New accounting pronouncements | New accounting pronouncements. In March 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2016-09, "Improvements to Employee Share-Based Payment Accounting." ASU 2016-09 simplifies several aspects of the accounting for share-based payment transactions, including accounting for income taxes, forfeitures and statutory tax withholding requirements, as well as certain classification changes in the statement of cash flows. The Company adopted this standard on January 1, 2017. See Note O for discussion on the impact of the adoption to the Company's income tax benefit. In February 2016, FASB issued ASU 2016-02, "Leases (Topic 842)." ASU 2016-02 requires the recognition of lease assets and lease liabilities by lessees for those leases currently classified as operating leases and makes certain changes to the accounting for lease expenses. This update is effective for fiscal years beginning after December 15, 2018 and for interim periods beginning the following year. This update should be applied using a modified retrospective approach, and early adoption is permitted. The Company anticipates that the adoption of ASU 2016-02 for its leasing arrangements will likely (i) increase the Company's recorded assets and liabilities, (ii) increase depreciation, depletion and amortization expense, (iii) increase interest expense and (iv) decrease lease/rental expense. The Company is currently evaluating each of its lease arrangements and has not determined the aggregate amount of change expected for each category. In January 2018, the FASB issued ASU 2018-01, which permits an entity to elect an optional transition practical expedient to not evaluate land easements that exist or expire before the Company's adoption of Topic 842 and that were not previously accounted for as leases under Topic 840. The Company intends to elect this transition provision. In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers (Topic 606)," which supersedes the revenue recognition requirements in Accounting Standards Codification ("ASC") Topic 605, "Revenue Recognition," and most industry-specific guidance. ASU 2014-09 is based on the principle that revenue is recognized to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. In August 2015, the FASB issued ASU 2015-14, which defers the effective date of ASU 2014-09 for one year to annual reports beginning after December 15, 2017. Early adoption is permitted for fiscal years beginning after December 15, 2016. In addition, in May 2016, the FASB issued ASU 2016-11, which rescinds guidance from the SEC on accounting for gas balancing arrangements and will eliminate the use of the entitlements method. During the Company's implementation of Topic 606, it identified the following revenue streams: oil, NGL and gas sales and sales of purchased oil and gas. The Company's analysis of contracts with customers in accordance with the requirements of Topic 606 is complete. The Company has not identified any changes to the timing of revenue recognition based upon the requirements of Topic 606 that would have a material impact on the Company's consolidated financial statements. The Company will utilize the modified approach to adopt the new standards on their January 1, 2018 effective date. The Company continues to review its implementation documentation and its evaluation of the new disclosure requirements is ongoing. |
Net Income Per Share Attribut26
Net Income Per Share Attributable To Common Stockholders Net Income Per Share Attributable to Common Stockholders (Policies) | 12 Months Ended |
Dec. 31, 2017 | |
Earnings Per Share [Abstract] | |
Earnings Per Share, Policy [Policy Text Block] | In the calculation of basic net income (loss) per share attributable to common stockholders, participating securities are allocated earnings based on actual dividend distributions received plus a proportionate share of undistributed net income attributable to common stockholders, 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. The computation of diluted net income (loss) per share attributable to common stockholders reflects the potential dilution that could occur if securities or other contracts to issue common stock that are dilutive were exercised or converted into common stock or resulted in the issuance of common stock that would then share in the earnings of the Company. During periods in which the Company realizes a loss from continuing operations attributable to common stockholders, securities or other contracts to issue common stock would not be dilutive to net loss per share and conversion into common stock is assumed not to occur. Diluted net income (loss) per share is calculated under both the two-class method and the treasury stock method and the more dilutive of the two calculations is presented. The Company's basic net income (loss) per share attributable to common stockholders is computed as (i) net income (loss) attributable to common stockholders, (ii) less participating share- and unit-based basic earnings (iii) divided by weighted average basic shares outstanding. The Company's diluted net income (loss) per share attributable to common stockholders is computed as (i) basic net income (loss) attributable to common stockholders, (ii) plus diluted adjustments to participating undistributed earnings (iii) divided by weighted average diluted shares outstanding. |
Summary Of Significant Accoun27
Summary Of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Policies [Abstract] | |
Schedule of individual line items affected by restatement | The following individual line items were affected, in addition to total revenues and total costs and expenses: Year Ended December 31, 2016 2015 (in millions) Sales of purchased oil and gas, as previously reported $ 1,533 $ 964 Revision to sales of purchased oil and gas (442 ) (264 ) Sales of purchased oil and gas, reported herein $ 1,091 $ 700 Purchased oil and gas, as previously reported $ 1,597 $ 1,003 Revision to purchased oil and gas (442 ) (264 ) Purchased oil and gas, reported herein $ 1,155 $ 739 |
Schedule of materials and supplies and commodity inventories | The following table presents the Company's materials and supplies and commodity inventories as of December 31, 2017 and 2016 : As of December 31, 2017 2016 (in millions) Materials and supplies (a) $ 134 $ 144 Commodities 78 37 $ 212 $ 181 ____________________ (a) As of December 31, 2017 and 2016 , the Company's materials and supplies inventories were net of valuation allowances of $5 million and $28 million , respectively. See Note D for additional information regarding inventory impairments. |
Schedule of other property and equipment, net | As of December 31, 2017 and 2016 , the net carrying value of other property and equipment consisted of the following: As of December 31, 2017 (a) 2016 (a) (in millions) Land and buildings $ 529 $ 475 Proved and unproved sand properties (b) 488 484 Water infrastructure (c) 347 221 Equipment (d) 194 206 Information technology (e) 143 84 Leasehold improvements 20 22 Vehicles 19 15 Furniture and fixtures 19 22 $ 1,759 $ 1,529 ____________________ (a) At December 31, 2017 and 2016 , other property and equipment was net of accumulated depreciation of $936 million and $866 million , respectively. (b) Includes sand mines, facilities and unproved leaseholds that primarily provide the Company with proppant for use in the fracture stimulation of oil and gas wells. (c) Includes pipeline infrastructure costs and water supply wells. (d) Includes fracture stimulation and well servicing equipment that is owned by wholly-owned subsidiaries that provide pressure pumping and well services on Company-operated properties. As of December 31, 2017 , the Company owned eight fracture stimulation fleets and other oilfield services equipment, including pulling units, fracture stimulation tanks, water transport trucks, hot oilers, blowout preventers, construction equipment and fishing tools. (e) Information technology costs include hardware and software costs associated with the Company's existing systems and in-progress system upgrades. As of December 31, 2017 and 2016 , $93 million and $37 million , respectively, had not yet been placed into service. |
Acquisitions and Divestitures A
Acquisitions and Divestitures Acquisitions and Divestitures (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Business Combinations [Abstract] | |
Schedule allocation of the acquisition price | The following table represents the allocation of the acquisition price to the assets acquired and the liabilities assumed based on their fair value at the acquisition date (in millions): Assets acquired: Proved properties $ 79 Unproved properties 347 Other property and equipment 5 Liabilities assumed: Asset retirement obligations (2 ) Other liabilities (1 ) Net assets acquired $ 428 |
Disclosures About Fair Value 29
Disclosures About Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Fair Value Disclosures [Abstract] | |
Assets and liabilities that are measured at fair value | The following tables present the Company's assets and liabilities that are measured at fair value on a recurring basis as of December 31, 2017 and 2016 for each of the fair value hierarchy levels: Fair Value Measurements at December 31, 2017 Using Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Fair Value at December 31, 2017 (in millions) Assets: Commodity derivatives $ — $ 11 $ — $ 11 Deferred compensation plan assets 95 — — 95 Total assets 95 11 — 106 Liabilities: Commodity derivatives — 255 — 255 Total liabilities — 255 — 255 Total recurring fair value measurements $ 95 $ (244 ) $ — $ (149 ) Fair Value Measurements at December 31, 2016 Using Quoted Prices in Significant Other Significant Fair Value at December 31, 2016 (in millions) Assets: Commodity derivatives $ — $ 8 $ — $ 8 Interest rate derivatives — 6 — 6 Deferred compensation plan assets 83 — — 83 Total assets 83 14 — 97 Liabilities: Commodity derivatives — 84 — 84 Total liabilities — 84 — 84 Total recurring fair value measurements $ 83 $ (70 ) $ — $ 13 |
Fair value and fair value adjustments, nonrecurring | The following table presents the fair value and fair value adjustments (in millions) for the 2017, 2016 and 2015 proved property impairments, as well as the average oil price per barrel ("Bbl") and gas price per British thermal unit ("MMBtu") utilized in the respective Management's Price Outlooks: Fair Value Fair Value Adjustment Management's Price Outlooks Oil Gas Raton March 2017 $ 186 $ (285 ) $ 53.65 $ 3.00 West Panhandle March 2016 $ 33 $ (32 ) $ 49.77 $ 3.24 South Texas - Eagle Ford Shale December 2015 $ 483 $ (846 ) $ 52.82 $ 3.34 South Texas - Other September 2015 $ 88 $ (72 ) $ 57.41 $ 3.46 West Panhandle March 2015 $ 61 $ (138 ) $ 65.02 $ 3.83 |
Carrying values and fair values of financial instruments not carried at fair value | Carrying values and fair values of financial instruments that are not carried at fair value in the accompanying consolidated balance sheets as of December 31, 2017 and 2016 are as follows: December 31, 2017 December 31, 2016 Carrying Value Fair Value Carrying Value Fair Value (in millions) Commercial paper, corporate bonds and time deposits $ 1,284 $ 1,282 $ 1,906 $ 1,901 Current portion of long-term debt $ 449 $ 457 $ 485 $ 490 Long-term debt $ 2,283 $ 2,479 $ 2,728 $ 2,956 |
Cash, Cash Equivalents and Investments [Table Text Block] | The following tables provide the components of the Company's cash and cash equivalents and investments as of December 31, 2017 and 2016 : December 31, 2017 Consolidated Balance Sheet Location Cash Commercial Paper Corporate Bonds Time Total (in millions) Cash and cash equivalents $ 846 $ — $ — $ 50 $ 896 Short-term investments — 124 647 447 1,218 Long-term investments — — 66 — 66 $ 846 $ 124 $ 713 $ 497 $ 2,180 December 31, 2016 Consolidated Balance Sheet Location Cash Commercial Paper Corporate Bonds Time Total (in millions) Cash and cash equivalents $ 873 $ 45 $ — $ 200 $ 1,118 Short-term investments — 368 691 382 1,441 Long-term investments — — 420 — 420 $ 873 $ 413 $ 1,111 $ 582 $ 2,979 |
Derivative Financial Instrume30
Derivative Financial Instruments (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Schedule of oil derivative contracts volume and weighted average price | The following table sets forth the volumes per day associated with the Company's outstanding oil derivative contracts as of December 31, 2017 and the weighted average oil prices for those contracts: 2018 Year Ending December 31, 2019 First Quarter Second Quarter Third Quarter Fourth Quarter Collar contracts: Volume (Bbl) 3,000 3,000 3,000 3,000 — Average price per Bbl: Ceiling $ 58.05 $ 58.05 $ 58.05 $ 58.05 $ — Floor $ 45.00 $ 45.00 $ 45.00 $ 45.00 $ — Collar contracts with short puts (a): Volume (Bbl) 149,000 149,000 154,000 159,000 40,000 Price per Bbl: Ceiling $ 57.79 $ 57.79 $ 57.70 $ 57.62 $ 59.62 Floor $ 47.42 $ 47.42 $ 47.34 $ 47.26 $ 52.00 Short put $ 37.38 $ 37.38 $ 37.31 $ 37.23 $ 42.00 ____________________ (a) Subsequent to December 31, 2017 , the Company entered into additional oil collar contracts with short puts for 25,000 Bbl per day of 2019 production with a ceiling price of $62.55 per Bbl, a floor price of $53.80 per Bbl and a short put price of $43.80 per Bbl. |
Schedule of NGL derivative volumes and weighted average prices | The following table sets forth the volumes per day associated with the Company's outstanding NGL derivative contracts as of December 31, 2017 and the weighted average NGL prices for those contracts: 2018 Year Ending December 31, 2019 First Second Quarter Third Quarter Fourth Quarter Ethane basis swap contracts (a): Volume (MMBtu) 6,920 6,920 6,920 6,920 6,920 Price differential ($/MMBtu) $ 1.60 $ 1.60 $ 1.60 $ 1.60 $ 1.60 ____________________ (a) The ethane basis swap contracts reduce the price volatility of ethane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices. The ethane basis swap contracts fix the basis differential on a NYMEX Henry Hub ("HH") MMBtu equivalent basis. The Company will receive the HH price plus the price differential on 6,920 MMBtu per day, which is equivalent to 2,500 Bbls per day of ethane. |
Gas Volume And Weighted Average Price | The following table sets forth the volumes per day associated with the Company's outstanding gas derivative contracts as of December 31, 2017 and the weighted average gas prices for those contracts: 2018 Year Ending December 31, 2019 First Second Quarter Third Quarter Fourth Quarter Swap contracts (a): Volume (MMBtu) 30,000 100,000 100,000 100,000 — Price per MMBtu $ 3.37 $ 3.00 $ 3.00 $ 3.00 $ — Collar contracts with short puts: Volume (MMBtu) 100,000 50,000 50,000 50,000 — Price per MMBtu: Ceiling $ 3.82 $ 3.40 $ 3.40 $ 3.40 $ — Floor $ 3.15 $ 2.75 $ 2.75 $ 2.75 $ — Short put $ 2.57 $ 2.25 $ 2.25 $ 2.25 $ — Basis swap contracts: Southern California index swap volume (MMBtu) (b)(c) 80,000 40,000 80,000 53,261 80,000 Price differential ($/MMBtu) $ 0.34 $ 0.30 $ 0.30 $ 0.43 $ 0.31 Houston Ship Channel index swap volume (MMBtu) (b)(d) 3,444 — — — — Price differential ($/MMBtu) $ 0.63 $ — $ — $ — $ — ____________________ (a) Subsequent to December 31, 2017 , the Company entered into additional swap contracts for 100,000 MMBtu per day of February 2018 production with a price of $3.46 per MMBtu. (b) The referenced basis swap contracts fix the basis differentials between Permian Basin index prices and southern California or Houston Ship Channel index prices for Permian Basin gas forecasted for sale in southern California or the Gulf Coast region. (c) Subsequent to December 31, 2017 , the Company entered into additional basis swap contracts for 20,000 MMBtu per day of November 2018 through March 2019 production with a price differential of $0.77 per MMBtu. (d) Subsequent to December 31, 2017 , the Company entered into additional basis swap contracts for 10,000 MMBtu per day of February 2018 production with a price differential of $0.82 per MMBtu. |
Schedule of Marketing Derivative Contracts Volume and Price | The following table sets forth the volumes per day associated with the Company's outstanding marketing derivative contracts as of December 31, 2017 and the weighted average prices for those contracts: 2018 First Quarter Second Quarter Third Quarter Fourth Quarter Average Daily Oil Transportation Commitments Associated with Derivatives (Bbl): Basis swap contracts: Louisiana Light Sweet index swap volume (a) 10,000 10,000 6,739 — Price differential ($/Bbl) $ 3.18 $ 3.18 $ 3.18 $ — Magellan East Houston index swap volume (a) 11,556 11,703 3,370 — Price differential ($/Bbl) $ 3.29 $ 3.30 $ 3.30 $ — ____________________ (a) The referenced basis swap contracts fix the basis differentials between NYMEX WTI and Louisiana Light Sweet or Magellan East Houston oil prices for Permian Basin oil forecasted for sale in the Gulf Coast region. |
Offsetting asset and liability | The aggregate fair value of the Company's derivative instruments reported in the accompanying consolidated balance sheets by type and counterparty, including the classification between current and noncurrent assets and liabilities, consists of the following: Fair Value of Derivative Instruments as of December 31, 2017 Type Consolidated Balance Sheet Location Fair Value Gross Amounts Offset in the Consolidated Balance Sheet Net Fair Value Presented in the Consolidated Balance Sheet (in millions) Derivatives not designated as hedging instruments Asset Derivatives: Commodity price derivatives Derivatives - current $ 13 $ (2 ) $ 11 Commodity price derivatives Derivatives - noncurrent 3 (3 ) — $ 11 Liability Derivatives: Commodity price derivatives Derivatives - current $ 234 $ (2 ) $ 232 Commodity price derivatives Derivatives - noncurrent 26 (3 ) 23 $ 255 Fair Value of Derivative Instruments as of December 31, 2016 Type Consolidated Balance Sheet Location Fair Value Gross Amounts Offset in the Consolidated Balance Sheet Net Fair Value Presented in the Consolidated Balance Sheet (in millions) Derivatives not designated as hedging instruments Asset Derivatives: Commodity price derivatives Derivatives - current $ 33 $ (25 ) $ 8 Interest rate derivatives Derivatives - current 6 — 6 $ 14 Liability Derivatives: Commodity price derivatives Derivatives - current $ 102 $ (25 ) $ 77 Commodity price derivatives Derivatives - noncurrent 7 — 7 $ 84 |
Schedule of derivative gains and losses recognized on statement of operations | The following table details the location of gains and losses recognized on the Company's derivative contracts in the accompanying consolidated statements of operations: Derivatives Not Designated as Hedging Instruments Location of Gain/(Loss) Recognized in Earnings on Derivatives Amount of Gain/(Loss) Recognized in Earnings on Derivatives Year Ended December 31, 2017 2016 2015 (in millions) Commodity price derivatives Derivative gains (losses), net $ (99 ) $ (174 ) $ 873 Interest rate derivatives Derivative gains (losses), net (1 ) 13 6 Total $ (100 ) $ (161 ) $ 879 |
Schedule of derivative assets or liabilities by counterparty | The following table provides the Company's net derivative assets or liabilities by counterparty as of December 31, 2017 : Net Assets (Liabilities) (in millions) Macquarie Bank $ (31 ) BMO Financial Group (30 ) JP Morgan Chase (28 ) Citibank, N.A. (28 ) Morgan Stanley (21 ) J. Aron & Company (21 ) BNP Paribas (20 ) Wells Fargo Bank, N.A. (20 ) Merrill Lynch (20 ) Nextera Energy (17 ) Scotia Bank (5 ) Societe Generale (4 ) JP Morgan Ventures Energy Corp (2 ) Toronto Dominion 3 Total $ (244 ) |
Exploratory Well Costs (Tables)
Exploratory Well Costs (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Extractive Industries [Abstract] | |
Capitalized exploratory well and project activity | The following table reflects the Company's capitalized exploratory well and project activity during each of the years ended December 31, 2017 , 2016 and 2015 : Year Ended December 31, 2017 2016 2015 (in millions) Beginning capitalized exploratory well costs $ 323 $ 306 $ 305 Additions to exploratory well costs pending the determination of proved reserves 1,956 1,387 1,178 Reclassification due to determination of proved reserves (1,764 ) (1,369 ) (1,160 ) Exploratory well costs charged to exploration and abandonment expense (10 ) (1 ) (17 ) Ending capitalized exploratory well costs $ 505 $ 323 $ 306 |
Capitalized exploratory costs and the number of projects for which exploratory costs have been capitalized | The following table provides an aging, as of December 31, 2017 , 2016 and 2015 of capitalized exploratory costs and the number of projects for which exploratory well costs have been capitalized for a period greater than one year, based on the date drilling was completed: As of December 31, 2017 2016 2015 (in millions, except well counts) Capitalized exploratory well costs that have been suspended: One year or less $ 493 $ 318 $ 303 More than one year 12 5 3 $ 505 $ 323 $ 306 Number of projects with exploratory well costs that have been suspended for a period greater than one year 7 3 1 |
Long-term Debt and Interest E32
Long-term Debt and Interest Expense (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Debt Disclosure [Abstract] | |
Components of long-term debt | Long-term debt, including the effects of issuance costs and issuance discounts, consisted of the following components at December 31, 2017 and 2016 : December 31, 2017 2016 (in millions) Outstanding debt principal balances: 6.65% senior notes due 2017 (a) $ — $ 485 6.875% senior notes due 2018 (b) 450 450 7.500% senior notes due 2020 450 450 3.45% senior notes due 2021 500 500 3.95% senior notes due 2022 600 600 4.45% senior notes due 2026 500 500 7.20% senior notes due 2028 250 250 2,750 3,235 Issuance costs and discounts (18 ) (22 ) Long-term debt 2,732 3,213 Less current portion of long-term debt (a) (b) 449 485 Long-term debt $ 2,283 $ 2,728 ______________________________ (a) The 6.65% senior notes, net of $173 thousand of unamortized issuance costs and issuance discounts, are classified as current in the accompanying consolidated balance sheets as of December 31, 2016. (b) The 6.875% senior notes, net of $106 thousand of unamortized issuance costs and issuance discounts, are classified as current in the accompanying consolidated balance sheets as of December 31, 2017. |
Principal maturities of long-term debt | Principal maturities of long-term debt at December 31, 2017 , are as follows (in millions): 2018 $ 450 2019 $ — 2020 $ 450 2021 $ 500 2022 $ 600 Thereafter $ 750 |
Interest expense | The following amounts have been incurred and charged to interest expense for the years ended December 31, 2017 , 2016 and 2015 : Year Ended December 31, 2017 2016 2015 (in millions) Cash payments for interest $ 164 $ 196 $ 148 Amortization of issuance discounts 1 9 13 Amortization of capitalized loan fees 4 4 5 Net changes in accruals (9 ) 2 25 Interest incurred 160 211 191 Less capitalized interest (7 ) (4 ) (4 ) Total interest expense $ 153 $ 207 $ 187 |
Incentive Plans (Tables)
Incentive Plans (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Number of LTIP shares available for issuance | The following table shows the number of shares available for issuance pursuant to awards under the LTIP at December 31, 2017 : Approved and authorized awards 12,600,000 Awards issued under plan (7,657,755 ) Awards available for future grant 4,942,245 |
Number of ESPP shares available for issuance | The following table shows the number of shares available for issuance under the ESPP at December 31, 2017 : Approved and authorized shares 1,250,000 Shares issued (951,285 ) Shares available for future issuance 298,715 |
Schedule of stock-based compensation expense | The following table reflects stock-based compensation expense recorded for each type of stock-based compensation award and the associated income tax benefit for the years ended December 31, 2017 , 2016 and 2015 : Year Ended December 31, 2017 2016 2015 (in millions) Restricted stock-Equity Awards $ 60 $ 66 $ 70 Restricted stock-Liability Awards 24 24 22 Stock options (a) — — — Performance unit awards 17 21 18 ESPP 2 2 2 Total $ 103 $ 113 $ 112 Income tax benefit $ 19 $ 34 $ 34 _____________________ (a) Cash proceeds received from stock option exercises during 2017 and 2016 amounted to $300 thousand and $1 million , respectively. There were no stock option exercises during 2015 . |
Schedule of restricted stock award activity | The following table reflects the restricted stock award activity for the year ended December 31, 2017 : Equity Awards Liability Awards Number of Shares Weighted Average Grant- Date Fair Value Number of Shares Outstanding at beginning of year 1,077,227 $ 143.39 290,552 Shares granted 332,635 $ 180.50 117,984 Shares forfeited (33,283 ) $ 153.17 (20,687 ) Shares vested (460,356 ) $ 153.06 (135,114 ) Outstanding at end of year 916,223 $ 151.71 252,735 |
Schedule of nonstatutory stock option awards activity | A summary of the Company's nonstatutory stock option awards activity for the year ended December 31, 2017 is presented below: Number of Shares Weighted Average Exercise Price Weighted Average Remaining Contractual Life Aggregate Intrinsic Value (in years) (in millions) Outstanding at beginning of year 159,378 $ 89.03 Options exercised (20,885 ) $ 15.62 Outstanding at end of year 138,493 $ 100.10 3.61 $ 10 Exercisable at end of year 138,493 $ 100.10 3.61 $ 10 |
Schedule of assumptions to estimate the fair value | The Company used the following assumptions to estimate the fair value of performance unit awards granted during 2017 , 2016 and 2015 : 2017 2016 2015 Risk-free interest rate 1.42% 0.96% 1.03% Range of volatilities 33.6 % - 58.2% 28.3 % - 53.6% 26.1 % - 41.3% |
Schedule of performance unit activity | The following table summarizes the performance unit activity for the year ended December 31, 2017 : Number of Units (a) Weighted Average Grant-Date Fair Value Beginning performance unit awards 178,556 $ 211.46 Units granted 59,044 $ 258.27 Units forfeited — $ — Units vested (b) (74,442 ) $ 222.33 Ending performance unit awards 163,158 $ 223.45 _____________________ (a) These amounts reflect the number of performance units granted. The actual payout of shares may be between zero percent and 250 percent of the performance units granted depending upon the total shareholder return ranking of the Company compared to peer companies at the vesting date. (b) On December 31, 2017 , the service period lapsed on 78,796 performance unit awards that earned 1.50 shares for each vested award, representing 118,198 aggregate shares of common stock issued on January 2, 2018. The vested performance units that earned 1.50 shares for each vested award included 74,442 units vested in the current year, 4,029 units that vested in 2016 and 325 units that vested in 2015 upon the retirement of the officers to whom the performance unit awards were granted. |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Asset Retirement Obligation [Abstract] | |
Schedule of asset retirement obligation activity | The following table summarizes the Company's asset retirement obligation activity during the years ended December 31, 2017 , 2016 and 2015 : Year Ended December 31, 2017 2016 2015 (in millions) Beginning asset retirement obligations $ 297 $ 285 $ 189 Obligations assumed in acquisitions — 2 — New wells placed on production 3 2 4 Changes in estimates (a) (9 ) 17 103 Dispositions (7 ) — — Liabilities settled (32 ) (27 ) (23 ) Accretion of discount 19 18 12 Ending asset retirement obligations $ 271 $ 297 $ 285 _____________________ (a) Changes in estimates are determined based on several factors, including abandonment cost estimates based on recent actual costs incurred to abandon wells, credit-adjusted risk-free discount rates and well life estimates. The decrease in 2017 was primarily due to a increase in commodity prices, which has the effect of lengthening the economic life of the Company's producing wells. The increase in 2016 was primarily due to the forecasted timing of abandoning the Company's oil and gas wells being accelerated as a result of lower commodity prices, which has the effect of shortening the economic lives of the Company's producing wells. |
Commitments And Contingencies (
Commitments And Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Schedule of future minimum drilling commitments | The Company's minimum commitments as of December 31, 2017 are as follows: Drilling Commitments Lease Commitments Purchase, Gathering, Processing, Transportation, Storage and Fractionation Commitments Total (in millions) 2018 $ 93 $ 27 $ 568 $ 688 2019 $ 41 $ 42 $ 619 $ 702 2020 $ 37 $ 53 $ 672 $ 762 2021 $ — $ 40 $ 627 $ 667 2022 $ — $ 37 $ 476 $ 513 Thereafter $ — $ 680 $ 1,554 $ 2,234 Total minimum commitments $ 171 $ 879 $ 4,516 $ 5,566 |
Delivery Commitments | The Company's delivery commitments as of December 31, 2017 are as follows: Oil Gas (MBbls per day) (MMBtu per day) 2018 66,685 — 2019 63,356 75,342 2020 68,347 100,000 2021 70,000 100,000 2022 30,575 100,000 2023 — 100,000 2024 — 24,863 |
Major Customers (Tables)
Major Customers (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Risks and Uncertainties [Abstract] | |
Schedule of revenue by major customer | The following purchasers individually accounted for ten percent or more of the Company's consolidated oil, NGL and gas production revenues in at least one of the three years ended December 31, 2017 : Year Ended December 31, 2017 2016 2015 Sunoco Logistics Partners L.P. (a) 21 % 19 % 18 % Occidental Energy Marketing Inc. 16 % 16 % 18 % Plains Marketing LP 14 % 16 % 22 % Enterprise Products Partners L.P. 11 % 12 % 12 % ______________________ (a) Sunoco Logistics Partners L.P. ("Sunoco") acquired Vitol Inc.'s Permian Basin oil systems during the fourth quarter of 2016, and the Company's contracts with Vitol Inc. were transferred to Sunoco. |
Schedule of sales of purchased oil, NGL and gas revenues | The following purchasers individually accounted for ten percent or more of the Company's consolidated oil, NGL and gas revenues from sales of commodities purchased from third parties in at least one of the three years ended December 31, 2017 : Year Ended December 31, 2017 2016 2015 Occidental Energy Marketing Inc. 39 % 27 % 25 % Valero Marketing and Supply Company 14 % 17 % 50 % BP Energy 11 % 18 % — % Exxon Mobil 11 % 23 % 12 % |
Interest And Other Income (Tabl
Interest And Other Income (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Other Income and Expenses [Abstract] | |
Interest And Other Income | The following table provides the components of the Company's interest and other income during the years ended December 31, 2017 , 2016 and 2015 : Year Ended December 31, 2017 2016 2015 (in millions) Interest income $ 32 $ 22 $ 3 Severance, sales and property tax refunds 13 2 — Deferred compensation plan income 4 3 4 Other income 4 5 10 Equity interest in income of EFS Midstream (a) — — 5 Total interest and other income $ 53 $ 32 $ 22 ______________________ (a) The Company accounted for its investment in EFS Midstream prior to its sale in July 2015 using the equity method. EFS Midstream provided gathering, treating and transportation services for the Company. See Note C for additional information on the Company's sale of EFS Midstream. |
Other Expense (Tables)
Other Expense (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Other Income and Expenses [Abstract] | |
Schedule of components of other expense | The following table provides the components of the Company's other expense during the years ended December 31, 2017 , 2016 and 2015 : Year Ended December 31, 2017 2016 2015 (in millions) Transportation commitment charges (a) $ 167 $ 109 $ 53 Other 58 49 27 Loss from vertical integration services (b) 17 54 34 Impairment of inventory and other property and equipment (c) 2 8 86 Idle drilling and well service equipment charges (d) — 64 92 Restructuring charges (e) — 4 23 Total other expense $ 244 $ 288 $ 315 ____________________ (a) Primarily represents firm transportation payments on excess pipeline capacity commitments. (b) Loss from vertical integration services primarily represents net margins (attributable to third party working interest owners) that result from Company-provided fracture stimulation and well service operations, which are ancillary to and supportive of the Company's oil and gas joint operating activities, and do not represent intercompany transactions. For the three years ended December 31, 2017 , 2016 and 2015 , these net losses include $140 million , $147 million and $298 million of gross vertical integration revenues, respectively, and $157 million , $201 million and $332 million of total vertical integration costs and expenses, respectively. (c) Primarily represents charges to reduce excess materials and supplies inventories to their market values for the years ended December 31, 2017 , 2016 and 2015 , respectively. See Note D for additional information on the fair value of material and supplies inventory. (d) Primarily represents expenses attributable to idle drilling rig fees that are not chargeable to joint operations and charges to terminate rig contracts that were not required to meet planned drilling activities. (e) Represents restructuring costs associated with the Company's restructuring of its operations in South Texas in 2016 and Colorado in 2015. See Note B for additional information on the restructuring charges. |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | |
Schedule of unrecognized tax benefits | The following table sets forth changes in the Company's unrecognized tax benefits: Year Ended December 31, 2017 2016 Balance at beginning of year $ 112 $ — Additions based on tax positions related to the current year 12 112 Reductions for tax positions of prior years — — Balance at end of year $ 124 $ 112 |
Summary of open tax years | The Company's earliest open years in its key jurisdictions are as follows: U.S. federal 2012 Various U.S. states 2013 |
Schedule of income tax benefit allocation | The Company's income tax benefit and amounts separately allocated were attributable to the following items for the years ended December 31, 2017 , 2016 and 2015 : Year Ended December 31, 2017 2016 2015 (in millions) Income tax benefit from continuing operations $ 524 $ 403 $ 155 Income tax benefit from discontinued operations $ — $ — $ 2 |
Income tax (provision) benefit attributable to continuing operations | The Company's income tax (provision) benefit attributable to income from continuing operations consisted of the following for the years ended December 31, 2017 , 2016 and 2015 : Year Ended December 31, 2017 2016 2015 (in millions) Current: U.S. federal $ 5 $ 22 $ (22 ) U.S. state — 2 (1 ) 5 24 (23 ) Deferred: U.S. federal 526 375 165 U.S. state (7 ) 4 13 519 379 178 Income tax benefit from continuing operations $ 524 $ 403 $ 155 |
Reconciliation of federal statutory tax rate | Reconciliations of the United States federal statutory tax rate to the Company's effective tax rate for income (loss) from continuing operations are as follows for the years ended December 31, 2017 , 2016 and 2015 : Year Ended December 31, 2017 2016 2015 (in millions, except percentages) Income (loss) from continuing operations attributable to common stockholders before income taxes $ 309 $ (959 ) $ (421 ) Federal statutory income tax rate 35 % 35 % 35 % (Provision) benefit for federal income taxes at the statutory rate (108 ) 336 147 State income tax (provision) benefit (net of federal tax) (4 ) 3 8 State valuation allowance (net of federal tax) (1 ) (3 ) — Change in federal income tax rate (a) 625 — — Equity compensation excess tax benefit (b) 9 — — Federal credit for increasing research activities (net of unrecognized tax benefits) 6 68 — State credit for increasing research activities (net of unrecognized tax benefits and federal tax) — 4 — Other (3 ) (5 ) — Income tax benefit from continuing operations $ 524 $ 403 $ 155 Effective income tax rate, excluding net income attributable to the noncontrolling interests (170 )% 42 % 37 % ____________________ (a) During 2017, the Company recognized a benefit of $625 million as a result of the December 22, 2017 Tax Reform Legislation that reduces the federal income tax rate beginning in 2018. (b) During 2017, the Company recognized excess tax benefits of $9 million associated with the adoption of ASU 2016-09, "Improvements to Employee Share-Based Payment Accounting," which requires excess tax benefits or deficiencies associated with the vesting of long-term incentive awards to be recorded as income tax expense or benefit in the statement of operations rather than as an adjustment to additional paid-in capital in the balance sheet. |
Schedule of deferred tax assets and liabilities | The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities related to continuing operations are as follows as of December 31, 2017 and 2016 : December 31, 2017 2016 (in millions) Deferred tax assets: Net operating loss carryforward (a) $ 594 $ 635 Credit carryforwards (b) 87 107 Asset retirement obligations 59 106 Incentive plans 48 81 Net deferred hedge losses 52 32 Other 22 30 Total deferred tax assets 862 991 Deferred tax liabilities: Oil and gas properties, principally due to differences in basis, depletion and the deduction of intangible drilling costs for tax purposes (1,640 ) (2,184 ) Other property and equipment, principally due to the deduction of bonus depreciation for tax purposes (121 ) (204 ) Total deferred tax liabilities (1,761 ) (2,388 ) Net deferred tax liability $ (899 ) $ (1,397 ) ____________________ (a) Net operating loss carryforwards as of December 31, 2017 consist of $2.8 billion of U.S. federal NOLs, which expire between 2032 and 2037 , and $164 million of Colorado NOLs, which expire between 2027 and 2037 , and are net of a $6 million valuation allowance relating to $125 million of Colorado NOLs that the Company believes will more likely than not expire unutilized. (b) Credit carryforwards as of December 31, 2017 consist of U.S. federal credits for increasing research activities of $82 million and Texas credits for increasing research activities of $5 million . The U.S. federal and state research credits as of December 31, 2017 exclude $124 million of unrecognized tax benefits. |
Net Income Per Share Attribut40
Net Income Per Share Attributable To Common Stockholders (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Earnings Per Share [Abstract] | |
Reconciliation of net income (loss) attributable to common stockholders, basic and diluted | The following table is a reconciliation of the Company's net income (loss) attributable to common stockholders to basic and diluted net income (loss) attributable to common stockholders for the years ended December 31, 2017 , 2016 and 2015 : Year Ended December 31, 2017 2016 2015 (in millions) Income (loss) from continuing operations $ 833 $ (556 ) $ (266 ) Participating basic earnings (a) (6 ) — — Basic and diluted net income (loss) from continuing operations 827 (556 ) (266 ) Basic and diluted net loss from discontinued operations — — (7 ) Basic and diluted net income (loss) attributable to common stockholders $ 827 $ (556 ) $ (273 ) ______________________ (a) Unvested restricted stock awards represent participating securities because they participate in nonforfeitable dividends with the common equity owners of the Company. Participating share- or unit-based earnings represent the distributed and undistributed earnings of the Company attributable to the participating securities. Unvested restricted stock awards do not participate in undistributed net losses as they are not contractually obligated to do so. |
Summary Of Significant Accoun41
Summary Of Significant Accounting Policies (Schedule of individual line items affected by restatement) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Error Corrections and Prior Period Adjustments Restatement [Line Items] | |||
Sales of purchased oil and gas | $ 1,776 | $ 1,091 | $ 700 |
Purchased oil and gas | $ 1,807 | 1,155 | 739 |
Previously reported | |||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | |||
Sales of purchased oil and gas | 1,533 | 964 | |
Purchased oil and gas | 1,597 | 1,003 | |
Revision | |||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | |||
Sales of purchased oil and gas | (442) | (264) | |
Purchased oil and gas | $ (442) | $ (264) |
Summary Of Significant Accoun42
Summary Of Significant Accounting Policies (Narrative) (Details) shares in Millions, $ in Millions | 3 Months Ended | 12 Months Ended | |||
Jun. 30, 2016USD ($)shares | Mar. 31, 2016USD ($)shares | Dec. 31, 2017USD ($)segment | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | |
Summary Of Significant Accounting Policies [Line Items] | |||||
Accounts receivable - trade | $ 639 | $ 517 | |||
Allowances for doubtful accounts | $ 1 | 1 | |||
Natural gas processing plants number | 10 | ||||
Treating facilities number | 4 | ||||
Company operated natural gas processing plants | 1 | ||||
Company Operated Treating Facilities | 4 | ||||
Third party operated natural gas processing plants | 9 | ||||
Nonoperated treating facilities | 1 | ||||
Third party revenues, processing plants and treating facilities | $ 60 | 41 | $ 39 | ||
Third party expenses, processing plants and treating facilities | 26 | 24 | 27 | ||
Issuance of common stock, shares | shares | 6 | 13.8 | |||
Proceeds from issuance of common stock, net of issuance costs | $ 937 | $ 1,600 | $ 0 | 2,534 | 0 |
Stock-based compensation awards general vesting period | 3 years | ||||
Reportable operating segments | segment | 1 | ||||
Restructuring and Related Cost, Incurred Cost | $ 0 | 4 | 23 | ||
Restructuring Reserve | $ 1 | 2 | |||
Minimum | Buildings | |||||
Summary Of Significant Accounting Policies [Line Items] | |||||
Estimated useful life | 20 years | ||||
Minimum | Equipment, vehicles, furniture and fixtures and information technology | |||||
Summary Of Significant Accounting Policies [Line Items] | |||||
Estimated useful life | 2 years | ||||
Minimum | Water infrastructure | |||||
Summary Of Significant Accounting Policies [Line Items] | |||||
Estimated useful life | 10 years | ||||
Maximum | Buildings | |||||
Summary Of Significant Accounting Policies [Line Items] | |||||
Estimated useful life | 39 years | ||||
Maximum | Equipment, vehicles, furniture and fixtures and information technology | |||||
Summary Of Significant Accounting Policies [Line Items] | |||||
Estimated useful life | 15 years | ||||
Maximum | Water infrastructure | |||||
Summary Of Significant Accounting Policies [Line Items] | |||||
Estimated useful life | 50 years | ||||
South Texas - Eagle Ford Shale | |||||
Summary Of Significant Accounting Policies [Line Items] | |||||
Restructuring and Related Cost, Incurred Cost | 4 | ||||
South Texas - Eagle Ford Shale | Employee relocation and other costs | |||||
Summary Of Significant Accounting Policies [Line Items] | |||||
Restructuring and Related Cost, Incurred Cost | 1 | ||||
South Texas - Eagle Ford Shale | Cash Severance Payments | |||||
Summary Of Significant Accounting Policies [Line Items] | |||||
Restructuring and Related Cost, Incurred Cost | 3 | ||||
Colorado | |||||
Summary Of Significant Accounting Policies [Line Items] | |||||
Restructuring and Related Cost, Incurred Cost | 23 | ||||
Colorado | Cash Severance Payments | |||||
Summary Of Significant Accounting Policies [Line Items] | |||||
Restructuring and Related Cost, Incurred Cost | 16 | ||||
Colorado | Employee severance costs | |||||
Summary Of Significant Accounting Policies [Line Items] | |||||
Restructuring and Related Cost, Incurred Cost | 17 | ||||
Colorado | Office lease-related costs | |||||
Summary Of Significant Accounting Policies [Line Items] | |||||
Restructuring and Related Cost, Incurred Cost | 6 | ||||
Colorado | Accelerated vesting of share-based grants | |||||
Summary Of Significant Accounting Policies [Line Items] | |||||
Severance Costs | $ 1 | ||||
Colorado | Operating lease and leasehold improvements | |||||
Summary Of Significant Accounting Policies [Line Items] | |||||
Restructuring and Related Cost, Incurred Cost | 4 | ||||
Restructuring and Related Cost, Accelerated Depreciation | $ 2 |
Summary Of Significant Accoun43
Summary Of Significant Accounting Policies (Schedule of Inventory) (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Accounting Policies [Abstract] | ||
Materials and supplies inventories | $ 134 | $ 144 |
Commodities | 78 | 37 |
Inventories | 212 | 181 |
Net materials and supplies inventories reserves | $ 5 | $ 28 |
Summary of Significant Accoun44
Summary of Significant Accounting Policies (Schedule of Other Property Plant and Equipment) (Details) $ in Millions | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) |
Property, Plant and Equipment [Line Items] | ||
Other property and equipment, net | $ 1,759 | $ 1,529 |
Accumulated depreciation property, plant and equipment, other assets | $ 936 | 866 |
Fracture Stimulation Fleets | 8 | |
Land and Building [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Other property and equipment, net | $ 529 | 475 |
Proved and Unproved Sand Leaseholds [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Other property and equipment, net | 488 | 484 |
Water infrastructure | ||
Property, Plant and Equipment [Line Items] | ||
Other property and equipment, net | 347 | 221 |
Wells and Related Equipment and Facilities [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Other property and equipment, net | 194 | 206 |
Transportation Equipment [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Other property and equipment, net | 19 | 15 |
Furniture and Fixtures [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Other property and equipment, net | 19 | 22 |
Computer Equipment [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Other property and equipment, net | 143 | 84 |
Leasehold Improvements [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Other property and equipment, net | 20 | 22 |
Computer Equipment Not Placed in Service [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Other property and equipment, net | $ 93 | $ 37 |
Acquisitions and Divestitures45
Acquisitions and Divestitures Acquisitions and Divestitures (Permian Basin Acquisition) (Details) - Permian Basin a in Thousands, $ in Millions | 1 Months Ended | |
Aug. 31, 2016USD ($)aBoe | Dec. 31, 2016USD ($) | |
Business Acquisition [Line Items] | ||
Net acres acquired | a | 28 | |
Net production in barrels | Boe | 1,400 | |
Payments for acquisition | $ 428 | |
Acquisition related costs | $ 1 | |
Proved properties | ||
Business Acquisition [Line Items] | ||
Discount rate | 10.00% | |
Asset retirement obligations | ||
Business Acquisition [Line Items] | ||
Discount rate | 7.00% |
Acquisitions and Divestitures (
Acquisitions and Divestitures (Schedule of Allocation of the Acquisition Price) (Details) - Permian Basin $ in Millions | Aug. 31, 2016USD ($) |
Assets acquired: | |
Proved properties | $ 79 |
Unproved properties | 347 |
Other property and equipment | 5 |
Liabilities assumed: | |
Asset retirement obligations | (2) |
Other liabilities | (1) |
Net assets acquired | $ 428 |
Acquisitions and Divestitures47
Acquisitions and Divestitures (Divestitures Recorded in Continuing Operations) (Details) $ in Millions | 1 Months Ended | 12 Months Ended | ||||
Apr. 30, 2017USD ($)aBoe | Jul. 31, 2016USD ($) | Jul. 31, 2015USD ($)Rate | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||
Gain on disposition of assets, net | $ 208 | $ 2 | $ 782 | |||
Proceeds from disposition of assets, net of cash sold | 352 | 507 | 553 | |||
Ownership interest, percent | Rate | 50.10% | |||||
Total consideration | $ 1,000 | |||||
Pretax gain | 777 | |||||
Loss from discontinued operations, net of tax | 0 | 0 | (7) | |||
Proceeds received at closing | ||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||
Total consideration | $ 530 | |||||
Proceeds received July 2016 | ||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||
Total consideration | $ 501 | |||||
Martin County | ||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||
Gain on disposition of assets, net | $ 194 | |||||
Acres sold | a | 20,500 | |||||
Net production in barrels | Boe | 1,500 | |||||
Proceeds from disposition of assets, net of cash sold | $ 264 | |||||
Reduction of carrying value of goodwill | $ 2 | |||||
Other proved and unproved properties, inventory and other property and equipment | ||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||
Gain on disposition of assets, net | 14 | $ 2 | $ 5 | |||
Permian Basin | ||||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||||
Proceeds from disposition of assets, net of cash sold | $ 77 |
Acquisitions and Divestitures48
Acquisitions and Divestitures (Divestitures Recorded in Discontinued Operations) (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($)Well | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||
Loss from discontinued operations, net of tax | $ 0 | $ 0 | $ (7) |
Discontinued operations | |||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||
Loss from discontinued operations, net of tax | $ 7 | ||
Abandoned Wells | Well | 2 |
Disclosures About Fair Value 49
Disclosures About Fair Value Measurements (Assets And Liabilities That Are Measured At Fair Value On A Recurring Basis) (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Deferred compensation plan assets | $ 95 | $ 83 |
Total assets | 106 | 97 |
Total liabilities | 255 | 84 |
Total recurring fair value measurements | (149) | 13 |
Commodity derivatives | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Commodity derivatives | 11 | 8 |
Commodity derivatives | 255 | 84 |
Interest rate derivatives | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Commodity derivatives | 6 | |
Quoted Prices in Active Markets for Identical Assets (Level 1) | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Deferred compensation plan assets | 95 | 83 |
Total assets | 95 | 83 |
Total liabilities | 0 | 0 |
Total recurring fair value measurements | 95 | 83 |
Quoted Prices in Active Markets for Identical Assets (Level 1) | Commodity derivatives | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Commodity derivatives | 0 | 0 |
Commodity derivatives | 0 | 0 |
Quoted Prices in Active Markets for Identical Assets (Level 1) | Interest rate derivatives | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Commodity derivatives | 0 | |
Significant Other Observable Inputs (Level 2) | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Deferred compensation plan assets | 0 | 0 |
Total assets | 11 | 14 |
Total liabilities | 255 | 84 |
Total recurring fair value measurements | (244) | (70) |
Significant Other Observable Inputs (Level 2) | Commodity derivatives | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Commodity derivatives | 11 | 8 |
Commodity derivatives | 255 | 84 |
Significant Other Observable Inputs (Level 2) | Interest rate derivatives | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Commodity derivatives | 6 | |
Significant Unobservable Inputs (Level 3) | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Deferred compensation plan assets | 0 | 0 |
Total assets | 0 | 0 |
Total liabilities | 0 | 0 |
Total recurring fair value measurements | 0 | 0 |
Significant Unobservable Inputs (Level 3) | Commodity derivatives | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Commodity derivatives | 0 | 0 |
Commodity derivatives | $ 0 | 0 |
Significant Unobservable Inputs (Level 3) | Interest rate derivatives | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Commodity derivatives | $ 0 |
Disclosures About Fair Value 50
Disclosures About Fair Value Measurements (Narrative) (Details) - USD ($) $ in Millions | 1 Months Ended | 12 Months Ended | ||
Mar. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Noncash impairment charges | $ 2 | $ 8 | $ 71 | |
Discount rate used in impairment calculation | 10.00% | |||
Alaska | ||||
Impairment charge | $ 32 | |||
Colorado | ||||
Impairment charge | $ 7 |
Disclosures About Fair Value 51
Disclosures About Fair Value Measurements (Measured On A Nonrecurring Basis) (Details) $ in Millions | 1 Months Ended | 12 Months Ended | ||||||
Mar. 31, 2017USD ($)$ / MMBTU$ / bbl | Mar. 31, 2016USD ($)$ / MMBTU$ / bbl | Dec. 31, 2015USD ($)$ / MMBTU$ / bbl | Sep. 30, 2015USD ($)$ / MMBTU$ / bbl | Mar. 31, 2015USD ($)$ / MMBTU$ / bbl | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||
Fair Value Adjustment | $ (285) | $ (32) | $ (1,056) | |||||
Raton | ||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||
Fair Value | $ 186 | |||||||
Fair Value Adjustment | $ 285 | |||||||
Management oil price outlook | $ / bbl | 53.65 | |||||||
Management gas price outlook | $ / MMBTU | 3 | |||||||
West Panhandle | ||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||
Fair Value | $ 33 | $ 61 | ||||||
Fair Value Adjustment | $ 32 | $ 138 | ||||||
Management oil price outlook | $ / bbl | 49.77 | 65.02 | ||||||
Management gas price outlook | $ / MMBTU | 3.24 | 3.83 | ||||||
South Texas - Eagle Ford Shale | ||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||
Fair Value | $ 483 | $ 483 | ||||||
Fair Value Adjustment | $ 846 | |||||||
Management oil price outlook | $ / bbl | 52.82 | |||||||
Management gas price outlook | $ / MMBTU | 3.34 | |||||||
South Texas - Other | ||||||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||||||
Fair Value | $ 88 | |||||||
Fair Value Adjustment | $ 72 | |||||||
Management oil price outlook | $ / bbl | 57.41 | |||||||
Management gas price outlook | $ / MMBTU | 3.46 |
Disclosures About Fair Value 52
Disclosures About Fair Value Measurements (Financial Assets and Liabilities Not Carried At Fair Value) (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Fair Value Assets and Liabilities Not Carried At Fair Value [Line Items] | ||
Current portion of long-term debt | $ 449 | $ 485 |
Long-term debt | 2,283 | 2,728 |
Carrying Value | ||
Fair Value Assets and Liabilities Not Carried At Fair Value [Line Items] | ||
Commercial paper, corporate bonds and time deposits | 1,284 | 1,906 |
Current portion of long-term debt | 449 | 485 |
Long-term debt | 2,283 | 2,728 |
Fair Value | ||
Fair Value Assets and Liabilities Not Carried At Fair Value [Line Items] | ||
Commercial paper, corporate bonds and time deposits | 1,282 | 1,901 |
Current portion of long-term debt | 457 | 490 |
Long-term debt | $ 2,479 | $ 2,956 |
Disclosures About Fair Value 53
Disclosures About Fair Value Measurements Schedule of Fair Value Measurements (Cash and Cash Equivalents and Investments) (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Schedule of Held-to-maturity Securities [Line Items] | ||||
Cash and cash equivalents | $ 896 | $ 1,118 | $ 1,391 | $ 1,025 |
Short-term investments | 1,218 | 1,441 | ||
Long-term investments | 66 | 420 | ||
Total cash and cash equivalents and investments | 2,180 | 2,979 | ||
Cash | ||||
Schedule of Held-to-maturity Securities [Line Items] | ||||
Cash and cash equivalents | 846 | 873 | ||
Short-term investments | 0 | 0 | ||
Long-term investments | 0 | 0 | ||
Total cash and cash equivalents and investments | 846 | 873 | ||
Commercial Paper | ||||
Schedule of Held-to-maturity Securities [Line Items] | ||||
Cash and cash equivalents | 0 | 45 | ||
Short-term investments | 124 | 368 | ||
Long-term investments | 0 | 0 | ||
Total cash and cash equivalents and investments | 124 | 413 | ||
Corporate Bonds | ||||
Schedule of Held-to-maturity Securities [Line Items] | ||||
Cash and cash equivalents | 0 | 0 | ||
Short-term investments | 647 | 691 | ||
Long-term investments | 66 | 420 | ||
Total cash and cash equivalents and investments | 713 | 1,111 | ||
Time Deposits | ||||
Schedule of Held-to-maturity Securities [Line Items] | ||||
Cash and cash equivalents | 50 | 200 | ||
Short-term investments | 447 | 382 | ||
Long-term investments | 0 | 0 | ||
Total cash and cash equivalents and investments | $ 497 | $ 582 |
Derivative Financial Instrume54
Derivative Financial Instruments (Narrative) (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2017USD ($)Rate | |
Schedule of Trading Securities and Other Trading Assets [Line Items] | |
Interest rate derivative contract, term | 10 years |
Proceeds from Termination of Diesel Derivatives | $ 2 |
Notional amount of debt | 100 |
Proceeds from Termination of Interest Rate Derivatives | $ 5 |
Derivative fixed interest rate | Rate | 1.81% |
Derivative Financial Instrume55
Derivative Financial Instruments (Oil Derivative Contracts Volume And Weighted Average Price) (Details) | Feb. 14, 2018bbl / d$ / bbl | Dec. 31, 2017bbl / d$ / bbl |
Collar contracts for next year Q1 | Oil contracts | ||
Trading Activity, Gains and Losses, Net [Line Items] | ||
Volume, barrels per day | bbl / d | 3,000 | |
Collar contracts for next year Q1 | Oil contracts, price per bbl | ||
Trading Activity, Gains and Losses, Net [Line Items] | ||
Ceiling, price per barrel | 58.05 | |
Floor, price per barrel | 45 | |
Collar contracts for next year Q2 | Oil contracts | ||
Trading Activity, Gains and Losses, Net [Line Items] | ||
Volume, barrels per day | bbl / d | 3,000 | |
Collar contracts for next year Q2 | Oil contracts, price per bbl | ||
Trading Activity, Gains and Losses, Net [Line Items] | ||
Ceiling, price per barrel | 58.05 | |
Floor, price per barrel | 45 | |
Collar contracts for next year Q3 | Oil contracts | ||
Trading Activity, Gains and Losses, Net [Line Items] | ||
Volume, barrels per day | bbl / d | 3,000 | |
Collar contracts for next year Q3 | Oil contracts, price per bbl | ||
Trading Activity, Gains and Losses, Net [Line Items] | ||
Ceiling, price per barrel | 58.05 | |
Floor, price per barrel | 45 | |
Collar contracts for next year Q4 | Oil contracts | ||
Trading Activity, Gains and Losses, Net [Line Items] | ||
Volume, barrels per day | bbl / d | 3,000 | |
Collar contracts for next year Q4 | Oil contracts, price per bbl | ||
Trading Activity, Gains and Losses, Net [Line Items] | ||
Ceiling, price per barrel | 58.05 | |
Floor, price per barrel | 45 | |
Collar contracts for year 2 | Oil contracts | ||
Trading Activity, Gains and Losses, Net [Line Items] | ||
Volume, barrels per day | bbl / d | 0 | |
Collar contracts for year 2 | Oil contracts | Subsequent event | ||
Trading Activity, Gains and Losses, Net [Line Items] | ||
Volume, barrels per day | bbl / d | 25,000 | |
Collar contracts for year 2 | Oil contracts, price per bbl | ||
Trading Activity, Gains and Losses, Net [Line Items] | ||
Ceiling, price per barrel | 0 | |
Floor, price per barrel | 0 | |
Collar contracts for year 2 | Oil contracts, price per bbl | Subsequent event | ||
Trading Activity, Gains and Losses, Net [Line Items] | ||
Ceiling, price per barrel | 62.55 | |
Floor, price per barrel | 53.80 | |
Short put, price per barrel | 43.80 | |
Collar contracts with short puts for next year Q1 | Oil contracts | ||
Trading Activity, Gains and Losses, Net [Line Items] | ||
Volume, barrels per day | bbl / d | 149,000 | |
Collar contracts with short puts for next year Q1 | Oil contracts, price per bbl | ||
Trading Activity, Gains and Losses, Net [Line Items] | ||
Ceiling, price per barrel | 57.79 | |
Floor, price per barrel | 47.42 | |
Short put, price per barrel | 37.38 | |
Collar contracts with short puts for next year Q2 | Oil contracts | ||
Trading Activity, Gains and Losses, Net [Line Items] | ||
Volume, barrels per day | bbl / d | 149,000 | |
Collar contracts with short puts for next year Q2 | Oil contracts, price per bbl | ||
Trading Activity, Gains and Losses, Net [Line Items] | ||
Ceiling, price per barrel | 57.79 | |
Floor, price per barrel | 47.42 | |
Short put, price per barrel | 37.38 | |
Collar contracts with short puts for next year Q3 | Oil contracts | ||
Trading Activity, Gains and Losses, Net [Line Items] | ||
Volume, barrels per day | bbl / d | 154,000 | |
Collar contracts with short puts for next year Q3 | Oil contracts, price per bbl | ||
Trading Activity, Gains and Losses, Net [Line Items] | ||
Ceiling, price per barrel | 57.70 | |
Floor, price per barrel | 47.34 | |
Short put, price per barrel | 37.31 | |
Collar contracts with short puts for next year Q4 | Oil contracts | ||
Trading Activity, Gains and Losses, Net [Line Items] | ||
Volume, barrels per day | bbl / d | 159,000 | |
Collar contracts with short puts for next year Q4 | Oil contracts, price per bbl | ||
Trading Activity, Gains and Losses, Net [Line Items] | ||
Ceiling, price per barrel | 57.62 | |
Floor, price per barrel | 47.26 | |
Short put, price per barrel | 37.23 | |
Collar contracts with short puts for year 2 | Oil contracts | ||
Trading Activity, Gains and Losses, Net [Line Items] | ||
Volume, barrels per day | bbl / d | 40,000 | |
Collar contracts with short puts for year 2 | Oil contracts, price per bbl | ||
Trading Activity, Gains and Losses, Net [Line Items] | ||
Ceiling, price per barrel | 59.62 | |
Floor, price per barrel | 52 | |
Short put, price per barrel | 42 |
Derivative Financial Instrume56
Derivative Financial Instruments Derivative Financial Instruments (NGL Derivative Contracts Volume and Weighted Average Price) (Details) - Ethane | Dec. 31, 2017bbl / dMMBTU / d$ / MMBTU |
NGL contract, MMBtu Equivalent | Basis swap contracts for next year Q1 | |
Derivative [Line Items] | |
Volume, barrels per day | MMBTU / d | 6,920 |
NGL contract, MMBtu Equivalent | Basis swap contracts for next year Q2 | |
Derivative [Line Items] | |
Volume, barrels per day | MMBTU / d | 6,920 |
NGL contract, MMBtu Equivalent | Basis swap contracts for next year Q3 | |
Derivative [Line Items] | |
Volume, barrels per day | MMBTU / d | 6,920 |
NGL contract, MMBtu Equivalent | Basis swap contracts for next year Q4 | |
Derivative [Line Items] | |
Volume, barrels per day | MMBTU / d | 6,920 |
NGL contract, MMBtu Equivalent | Basis swap contracts for year 2 | |
Derivative [Line Items] | |
Volume, barrels per day | MMBTU / d | 6,920 |
NGL contract, price per MMBtu Equivalent | Basis swap contracts for next year Q1 | |
Derivative [Line Items] | |
Price differential, dollars per barrel | $ / MMBTU | 1.60 |
NGL contract, price per MMBtu Equivalent | Basis swap contracts for next year Q2 | |
Derivative [Line Items] | |
Price differential, dollars per barrel | $ / MMBTU | 1.60 |
NGL contract, price per MMBtu Equivalent | Basis swap contracts for next year Q3 | |
Derivative [Line Items] | |
Price differential, dollars per barrel | $ / MMBTU | 1.60 |
NGL contract, price per MMBtu Equivalent | Basis swap contracts for next year Q4 | |
Derivative [Line Items] | |
Price differential, dollars per barrel | $ / MMBTU | 1.60 |
NGL contract, price per MMBtu Equivalent | Basis swap contracts for year 2 | |
Derivative [Line Items] | |
Price differential, dollars per barrel | $ / MMBTU | 1.60 |
NGL contract, in BBLS | |
Derivative [Line Items] | |
Volume, barrels per day | bbl / d | 2,500 |
Derivative Financial Instrume57
Derivative Financial Instruments (Gas Derivative Contracts Volume And Weighted Average Price) (Details) | Feb. 14, 2018MMBTU / d$ / MMBTU | Dec. 31, 2017MMBTU / d$ / MMBTU |
Swap contracts for next year Q1 | Gas contracts, in MMBTU | ||
Derivative [Line Items] | ||
Volume, barrels per day | MMBTU / d | 30,000 | |
Swap contracts for next year Q1 | Gas contracts, in MMBTU | Subsequent event | ||
Derivative [Line Items] | ||
Volume, barrels per day | MMBTU / d | 100,000 | |
Price per MMBtu in usd | 3.46 | |
Swap contracts for next year Q1 | Gas contracts, price per MMBTU | ||
Derivative [Line Items] | ||
Price per MMBtu in usd | 3.37 | |
Swap contracts for next year Q2 | Gas contracts, in MMBTU | ||
Derivative [Line Items] | ||
Volume, barrels per day | MMBTU / d | 100,000 | |
Swap contracts for next year Q2 | Gas contracts, price per MMBTU | ||
Derivative [Line Items] | ||
Price per MMBtu in usd | 3 | |
Swap contracts for next year Q3 | Gas contracts, in MMBTU | ||
Derivative [Line Items] | ||
Volume, barrels per day | MMBTU / d | 100,000 | |
Swap contracts for next year Q3 | Gas contracts, price per MMBTU | ||
Derivative [Line Items] | ||
Price per MMBtu in usd | 3 | |
Swap contracts for next year Q4 | Gas contracts, in MMBTU | ||
Derivative [Line Items] | ||
Volume, barrels per day | MMBTU / d | 100,000 | |
Swap contracts for next year Q4 | Gas contracts, price per MMBTU | ||
Derivative [Line Items] | ||
Price per MMBtu in usd | 3 | |
Swap contracts for year 2 | Gas contracts, in MMBTU | ||
Derivative [Line Items] | ||
Volume, barrels per day | MMBTU / d | 0 | |
Swap contracts for year 2 | Gas contracts, price per MMBTU | ||
Derivative [Line Items] | ||
Price per MMBtu in usd | 0 | |
Collar contracts with short puts for next year Q1 | Gas contracts, in MMBTU | ||
Derivative [Line Items] | ||
Volume, barrels per day | MMBTU / d | 100,000 | |
Collar contracts with short puts for next year Q1 | Gas contracts, price per MMBTU | ||
Derivative [Line Items] | ||
Ceiling, price per barrel | 3.82 | |
Floor, price per barrel | 3.15 | |
Short put, price per barrel | 2.57 | |
Collar contracts with short puts for next year Q2 | Gas contracts, in MMBTU | ||
Derivative [Line Items] | ||
Volume, barrels per day | MMBTU / d | 50,000 | |
Collar contracts with short puts for next year Q2 | Gas contracts, price per MMBTU | ||
Derivative [Line Items] | ||
Ceiling, price per barrel | 3.40 | |
Floor, price per barrel | 2.75 | |
Short put, price per barrel | 2.25 | |
Collar contracts with short puts for next year Q3 | Gas contracts, in MMBTU | ||
Derivative [Line Items] | ||
Volume, barrels per day | MMBTU / d | 50,000 | |
Collar contracts with short puts for next year Q3 | Gas contracts, price per MMBTU | ||
Derivative [Line Items] | ||
Ceiling, price per barrel | 3.40 | |
Floor, price per barrel | 2.75 | |
Short put, price per barrel | 2.25 | |
Collar contracts with short puts for next year Q4 | Gas contracts, in MMBTU | ||
Derivative [Line Items] | ||
Volume, barrels per day | MMBTU / d | 50,000 | |
Collar contracts with short puts for next year Q4 | Gas contracts, price per MMBTU | ||
Derivative [Line Items] | ||
Ceiling, price per barrel | 3.40 | |
Floor, price per barrel | 2.75 | |
Short put, price per barrel | 2.25 | |
Collar contracts with short puts for year 2 | Gas contracts, in MMBTU | ||
Derivative [Line Items] | ||
Volume, barrels per day | MMBTU / d | 0 | |
Collar contracts with short puts for year 2 | Gas contracts, price per MMBTU | ||
Derivative [Line Items] | ||
Ceiling, price per barrel | 0 | |
Floor, price per barrel | 0 | |
Short put, price per barrel | 0 | |
Basis swap contracts for next year Q1 | Gas contracts, in MMBTU | Southern California | ||
Derivative [Line Items] | ||
Volume, barrels per day | MMBTU / d | 80,000 | |
Basis swap contracts for next year Q1 | Gas contracts, in MMBTU | Houston Ship Channel | ||
Derivative [Line Items] | ||
Volume, barrels per day | MMBTU / d | 3,444 | |
Basis swap contracts for next year Q1 | Gas contracts, in MMBTU | Houston Ship Channel | Subsequent event | ||
Derivative [Line Items] | ||
Volume, barrels per day | MMBTU / d | 10,000 | |
Basis swap contracts for next year Q1 | Gas contracts, price per MMBTU | Southern California | ||
Derivative [Line Items] | ||
Price differential, dollars per barrel | 0.34 | |
Basis swap contracts for next year Q1 | Gas contracts, price per MMBTU | Houston Ship Channel | ||
Derivative [Line Items] | ||
Price differential, dollars per barrel | 0.63 | |
Basis swap contracts for next year Q1 | Gas contracts, price per MMBTU | Houston Ship Channel | Subsequent event | ||
Derivative [Line Items] | ||
Price differential, dollars per barrel | 0.82 | |
Basis swap contracts for next year Q2 | Gas contracts, in MMBTU | Southern California | ||
Derivative [Line Items] | ||
Volume, barrels per day | MMBTU / d | 40,000 | |
Basis swap contracts for next year Q2 | Gas contracts, in MMBTU | Houston Ship Channel | ||
Derivative [Line Items] | ||
Volume, barrels per day | MMBTU / d | 0 | |
Basis swap contracts for next year Q2 | Gas contracts, price per MMBTU | Southern California | ||
Derivative [Line Items] | ||
Price differential, dollars per barrel | 0.30 | |
Basis swap contracts for next year Q2 | Gas contracts, price per MMBTU | Houston Ship Channel | ||
Derivative [Line Items] | ||
Price differential, dollars per barrel | 0 | |
Basis swap contracts for next year Q3 | Gas contracts, in MMBTU | Southern California | ||
Derivative [Line Items] | ||
Volume, barrels per day | MMBTU / d | 80,000 | |
Basis swap contracts for next year Q3 | Gas contracts, in MMBTU | Houston Ship Channel | ||
Derivative [Line Items] | ||
Volume, barrels per day | MMBTU / d | 0 | |
Basis swap contracts for next year Q3 | Gas contracts, price per MMBTU | Southern California | ||
Derivative [Line Items] | ||
Price differential, dollars per barrel | 0.30 | |
Basis swap contracts for next year Q3 | Gas contracts, price per MMBTU | Houston Ship Channel | ||
Derivative [Line Items] | ||
Price differential, dollars per barrel | 0 | |
Basis swap contracts for next year Q4 | Gas contracts, in MMBTU | Southern California | ||
Derivative [Line Items] | ||
Volume, barrels per day | MMBTU / d | 53,261 | |
Basis swap contracts for next year Q4 | Gas contracts, in MMBTU | Houston Ship Channel | ||
Derivative [Line Items] | ||
Volume, barrels per day | MMBTU / d | 0 | |
Basis swap contracts for next year Q4 | Gas contracts, price per MMBTU | Southern California | ||
Derivative [Line Items] | ||
Price differential, dollars per barrel | 0.43 | |
Basis swap contracts for next year Q4 | Gas contracts, price per MMBTU | Houston Ship Channel | ||
Derivative [Line Items] | ||
Price differential, dollars per barrel | 0 | |
Basis swap contracts for year 2 | Gas contracts, in MMBTU | Southern California | ||
Derivative [Line Items] | ||
Volume, barrels per day | MMBTU / d | 80,000 | |
Basis swap contracts for year 2 | Gas contracts, in MMBTU | Houston Ship Channel | ||
Derivative [Line Items] | ||
Volume, barrels per day | MMBTU / d | 0 | |
Basis swap contracts for year 2 | Gas contracts, price per MMBTU | Southern California | ||
Derivative [Line Items] | ||
Price differential, dollars per barrel | 0.31 | |
Basis swap contracts for year 2 | Gas contracts, price per MMBTU | Houston Ship Channel | ||
Derivative [Line Items] | ||
Price differential, dollars per barrel | 0 | |
Basis swap contracts for November 2018 through March 2019 | Gas contracts, in MMBTU | Southern California | Subsequent event | ||
Derivative [Line Items] | ||
Volume, barrels per day | MMBTU / d | 20,000 | |
Basis swap contracts for November 2018 through March 2019 | Gas contracts, price per MMBTU | Southern California | Subsequent event | ||
Derivative [Line Items] | ||
Price differential, dollars per barrel | 0.77 |
Derivative Financial Instrume58
Derivative Financial Instruments (Offsetting Assets and Liabilities) (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Asset Derivatives: | ||
Net Fair Value Presented in the Consolidated Balance Sheet, current | $ 11 | $ 14 |
Derivative Liability [Abstract] | ||
Net Fair Value Presented in the Consolidated Balance Sheet, current | 232 | 77 |
Net Fair Value Presented in the Consolidated Balance Sheet, noncurrent | 23 | 7 |
Derivatives not designated as hedging instruments | ||
Asset Derivatives: | ||
Net Fair Value Presented in the Consolidated Balance Sheet, total | 11 | 14 |
Derivative Liability [Abstract] | ||
Net Fair Value Presented in the Consolidated Balance Sheet, total | 255 | 84 |
Derivatives - current | Derivatives not designated as hedging instruments | Commodity price derivatives | ||
Asset Derivatives: | ||
Fair Value | 13 | 33 |
Gross Amounts Offset in the Consolidated Balance Sheet | (2) | (25) |
Net Fair Value Presented in the Consolidated Balance Sheet, current | 11 | 8 |
Derivative Liability [Abstract] | ||
Fair Value | 234 | 102 |
Gross Amounts Offset in the Consolidated Balance Sheet | (2) | (25) |
Net Fair Value Presented in the Consolidated Balance Sheet, current | 232 | 77 |
Derivatives - current | Derivatives not designated as hedging instruments | Interest rate derivatives | ||
Asset Derivatives: | ||
Fair Value | 6 | |
Gross Amounts Offset in the Consolidated Balance Sheet | 0 | |
Net Fair Value Presented in the Consolidated Balance Sheet, current | 6 | |
Derivatives - noncurrent | Derivatives not designated as hedging instruments | Commodity price derivatives | ||
Asset Derivatives: | ||
Fair Value | 3 | |
Gross Amounts Offset in the Consolidated Balance Sheet | (3) | |
Net Fair Value Presented in the Consolidated Balance Sheet, noncurrent | 0 | |
Derivative Liability [Abstract] | ||
Fair Value | 26 | 7 |
Gross Amounts Offset in the Consolidated Balance Sheet | (3) | 0 |
Net Fair Value Presented in the Consolidated Balance Sheet, noncurrent | $ 23 | $ 7 |
Derivative Financial Instrume59
Derivative Financial Instruments Derivative Financial Instruments (Schedule of Marketing Derivative Contracts Volume and Price (Details) - Oil Index Swap Contracts [Member] | Dec. 31, 2017bbl / d$ / bbl |
Louisiana Light Sweet [Member] | Basis swap contracts for next year Q1 | |
Schedule of Marketing Derivative Contracts Volume and Price [Line Items] | |
Volume, barrels per day | bbl / d | 10,000 |
Price differential, dollars per barrel | $ / bbl | 3.18 |
Louisiana Light Sweet [Member] | Basis swap contracts for next year Q2 | |
Schedule of Marketing Derivative Contracts Volume and Price [Line Items] | |
Volume, barrels per day | bbl / d | 10,000 |
Price differential, dollars per barrel | $ / bbl | 3.18 |
Louisiana Light Sweet [Member] | Basis swap contracts for next year Q3 | |
Schedule of Marketing Derivative Contracts Volume and Price [Line Items] | |
Volume, barrels per day | bbl / d | 6,739 |
Price differential, dollars per barrel | $ / bbl | 3.18 |
Magellan East Houston [Member] | Basis swap contracts for next year Q1 | |
Schedule of Marketing Derivative Contracts Volume and Price [Line Items] | |
Volume, barrels per day | bbl / d | 11,556 |
Price differential, dollars per barrel | $ / bbl | 3.29 |
Magellan East Houston [Member] | Basis swap contracts for next year Q2 | |
Schedule of Marketing Derivative Contracts Volume and Price [Line Items] | |
Volume, barrels per day | bbl / d | 11,703 |
Price differential, dollars per barrel | $ / bbl | 3.30 |
Magellan East Houston [Member] | Basis swap contracts for next year Q3 | |
Schedule of Marketing Derivative Contracts Volume and Price [Line Items] | |
Volume, barrels per day | bbl / d | 3,370 |
Price differential, dollars per barrel | $ / bbl | 3.30 |
Derivative Financial Instrume60
Derivative Financial Instruments (Derivative Obligations Under Terminated Hedge Arrangements) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Derivative [Line Items] | |||
Amount of Gain/(Loss) Recognized in Earnings on Derivatives | $ (100) | $ (161) | $ 879 |
Commodity price derivatives | Derivative gains (losses), net | |||
Derivative [Line Items] | |||
Amount of Gain/(Loss) Recognized in Earnings on Derivatives | (99) | (174) | 873 |
Interest rate derivatives | Derivative gains (losses), net | |||
Derivative [Line Items] | |||
Amount of Gain/(Loss) Recognized in Earnings on Derivatives | $ (1) | $ 13 | $ 6 |
Schedule of Derivative Assets a
Schedule of Derivative Assets and Liabilities by Counterparty (Details) $ in Millions | Dec. 31, 2017USD ($) |
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items] | |
Net Assets (Liabilities) | $ (244) |
Macquarie Bank | |
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items] | |
Net Assets (Liabilities) | (31) |
BMO Financial Group | |
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items] | |
Net Assets (Liabilities) | (30) |
JP Morgan Chase | |
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items] | |
Net Assets (Liabilities) | (28) |
Citibank, N.A. | |
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items] | |
Net Assets (Liabilities) | (28) |
Morgan Stanley | |
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items] | |
Net Assets (Liabilities) | (21) |
J. Aron & Company | |
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items] | |
Net Assets (Liabilities) | (21) |
BNP Paribas | |
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items] | |
Net Assets (Liabilities) | (20) |
Wells Fargo Bank, N.A. | |
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items] | |
Net Assets (Liabilities) | (20) |
Merrill Lynch | |
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items] | |
Net Assets (Liabilities) | (20) |
Nextera Energy | |
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items] | |
Net Assets (Liabilities) | (17) |
Scotia Bank | |
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items] | |
Net Assets (Liabilities) | (5) |
Societe Generale | |
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items] | |
Net Assets (Liabilities) | (4) |
JP Morgan Ventures Energy Corp | |
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items] | |
Net Assets (Liabilities) | (2) |
Toronto Dominion | |
Schedule of Derivative Assets and Liabilities by Counterparty [Line Items] | |
Net Assets (Liabilities) | $ 3 |
Exploratory Well Costs (Capital
Exploratory Well Costs (Capitalized Exploratory Well And Project Activity) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward] | |||
Beginning capitalized exploratory well costs | $ 323 | $ 306 | $ 305 |
Additions to exploratory well costs pending the determination of proved reserves | 1,956 | 1,387 | 1,178 |
Reclassification due to determination of proved reserves | (1,764) | (1,369) | (1,160) |
Exploratory well costs charged to exploration and abandonment expense | (10) | (1) | (17) |
Ending capitalized exploratory well costs | $ 505 | $ 323 | $ 306 |
Exploratory Well Costs (Capit63
Exploratory Well Costs (Capitalized Exploratory Costs And the Number Of Projects For Which Exploratory Costs Have Been Capitalized) (Details) $ in Millions | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) |
Capitalized exploratory well costs that have been suspended: | ||||
One year or less | $ 493 | $ 318 | $ 303 | |
More than one year | 12 | 5 | 3 | |
Total | $ 505 | $ 323 | $ 306 | $ 305 |
Number of projects with exploratory well costs that have been suspended for a period greater than one year | 7 | 3 | 1 |
Long-term Debt and Interest E64
Long-term Debt and Interest Expense (Components Of Long-Term Debt) (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Mar. 31, 2017 | Dec. 31, 2016 |
Debt Instrument [Line Items] | |||
Outstanding debt principal balances, gross | $ 2,750,000 | $ 3,235,000 | |
Issuance costs and discounts | (18,000) | (22,000) | |
Long-term debt | 2,732,000 | 3,213,000 | |
Less current portion of long-term debt | 449,000 | 485,000 | |
Long-term debt | $ 2,283,000 | $ 2,728,000 | |
6.65% senior notes due 2017 | |||
Debt Instrument [Line Items] | |||
Senior notes, interest rate | 6.65% | 6.65% | 6.65% |
Outstanding debt principal balances, gross | $ 0 | $ 485,000 | |
Issuance costs and discounts | (173) | ||
6.875% senior notes due 2018 | |||
Debt Instrument [Line Items] | |||
Senior notes, interest rate | 6.875% | ||
Outstanding debt principal balances, gross | $ 450,000 | 450,000 | |
Issuance costs and discounts | $ (106) | ||
7.500% senior notes due 2020 | |||
Debt Instrument [Line Items] | |||
Senior notes, interest rate | 7.50% | ||
Outstanding debt principal balances, gross | $ 450,000 | 450,000 | |
3.45% senior notes due 2021 | |||
Debt Instrument [Line Items] | |||
Senior notes, interest rate | 3.45% | ||
Outstanding debt principal balances, gross | $ 500,000 | 500,000 | |
3.95% senior notes due 2022 | |||
Debt Instrument [Line Items] | |||
Senior notes, interest rate | 3.95% | ||
Outstanding debt principal balances, gross | $ 600,000 | 600,000 | |
4.45% senior notes due 2026 | |||
Debt Instrument [Line Items] | |||
Senior notes, interest rate | 4.45% | ||
Outstanding debt principal balances, gross | $ 500,000 | 500,000 | |
7.20% senior notes due 2028 | |||
Debt Instrument [Line Items] | |||
Senior notes, interest rate | 7.20% | ||
Outstanding debt principal balances, gross | $ 250,000 | $ 250,000 |
Long-term Debt and Interest E65
Long-term Debt and Interest Expense (Narrative) (Details) | 1 Months Ended | 3 Months Ended | 12 Months Ended | |||
Aug. 31, 2015 | Mar. 31, 2017USD ($)Rate | Sep. 30, 2016USD ($)Rate | Dec. 31, 2017USD ($)Rate | Dec. 31, 2016USD ($)Rate | Dec. 31, 2015USD ($) | |
Debt Instrument [Line Items] | ||||||
Credit Facility term | 5 years | |||||
Line of credit facility, maximum borrowing capacity | $ | $ 1,500,000,000 | |||||
Outstanding borrowings under the Credit Facility | $ | 0 | |||||
Repayments of debt | $ | $ 485,000,000 | $ 455,000,000 | $ 0 | |||
Credit Facility | ||||||
Debt Instrument [Line Items] | ||||||
Federal fund rate | 0.50% | |||||
Alternate base rate spread | 0.25% | |||||
Applicable margin | 1.25% | |||||
Letters of credit outstanding under the Credit Facility, interest percentage | 0.125% | |||||
Unused portion, fee percentage | 0.15% | |||||
Debt instrument covenant description | 0.60 | |||||
Swing Line Loans | Credit Facility | ||||||
Debt Instrument [Line Items] | ||||||
Maximum outstanding borrowings under the Credit Facility | $ | $ 150,000,000 | |||||
6.65% senior notes due 2017 | ||||||
Debt Instrument [Line Items] | ||||||
Senior Notes, interest rate, percentage | 6.65% | 6.65% | 6.65% | |||
Repayments of debt | $ | $ 485,000,000 | |||||
5.875% senior notes due 2016 | ||||||
Debt Instrument [Line Items] | ||||||
Senior Notes, interest rate, percentage | 5.875% | |||||
Repayments of debt | $ | $ 455,000,000 | |||||
6.875% senior notes due 2018 | ||||||
Debt Instrument [Line Items] | ||||||
Senior Notes, interest rate, percentage | 6.875% | |||||
Issuance of senior notes | $ | $ 450,000,000 |
Long-term Debt and Interest E66
Long-term Debt and Interest Expense (Principal Maturities Of Long-Term Debt) (Details) $ in Millions | Dec. 31, 2017USD ($) |
Debt Disclosure [Abstract] | |
2,018 | $ 450 |
2,019 | 0 |
2,020 | 450 |
2,021 | 500 |
2,022 | 600 |
Thereafter | $ 750 |
Long-term Debt and Interest E67
Long-term Debt and Interest Expense (Interest Expenses) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Debt Disclosure [Abstract] | |||
Cash payments for interest | $ 164 | $ 196 | $ 148 |
Amortization of issuance discounts | 1 | 9 | 13 |
Amortization of capitalized loan fees | 4 | 4 | 5 |
Net changes in accruals | (9) | 2 | 25 |
Interest incurred | 160 | 211 | 191 |
Less capitalized interest | (7) | (4) | (4) |
Total interest expense | $ 153 | $ 207 | $ 187 |
Incentive Plans (Narrative) (De
Incentive Plans (Narrative) (Details) $ / shares in Units, $ in Millions | 12 Months Ended | |||
Dec. 31, 2017USD ($)$ / sharesRateshares | Dec. 31, 2016USD ($)$ / shares | Dec. 31, 2015USD ($)$ / shares | Jun. 30, 2016shares | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
ESPP offering period | 8 months | |||
Unrecognized share-based compensation expense | $ | $ 94 | |||
Remaining vesting period | 3 years | |||
Pioneer Long Term Incentive Plan [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Approved and authorized awards | shares | 12,600,000 | 3,500,000 | ||
ESPP | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Employee stock purchase plan contribution limit | 15.00% | |||
Employee stock purchase plan participants purchase price percent | 15.00% | |||
Approved and authorized awards | shares | 1,250,000 | |||
Restricted stock-Liability Awards | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Unrecognized share-based compensation expense | $ | $ 22 | |||
Shares granted | shares | 117,984 | |||
Grant date fair value | $ | $ 20 | $ 18 | $ 29 | |
Amount of liabilities attributable to liability awards included in accounts payable | $ | $ 20 | $ 22 | ||
Restricted stock units, including liability awards [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Shares granted | shares | 450,619 | |||
Restricted stock awards | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Shares granted | shares | 332,635 | |||
Number of unvested shares | shares | 77,727 | |||
Shares granted (usd per share) | $ / shares | $ 180.50 | $ 122.72 | $ 153.55 | |
Grant date fair value | $ | $ 70 | $ 66 | $ 76 | |
Stock options award | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Option awards contract life | 10 | |||
Average dividend yield | 7 | |||
Intrinsic value of options exercised | $ | $ 3 | $ 6 | ||
Performance unit awards | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Remaining vesting period | 34 months | |||
Shares granted | shares | 59,044 | |||
Shares granted (usd per share) | $ / shares | $ 258.27 | $ 203.69 | $ 222.33 | |
Grant date fair value | $ | $ 18 | $ 15 | $ 17 | |
Expected volatility period | 3 years | |||
401(k) plan | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Participants annual salary contributions, percentage | 80.00% | |||
Matching contributions percent | 200.00% | |||
Limit of employee's contribution of base salary, percent | 5.00% | |||
Matching contributions vesting period in years | 4 | |||
Recognized compensation matching contribution expense | $ | $ 25 | 23 | 31 | |
Deferred compensation retirement plan | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Matching contributions percent | 100.00% | |||
Matching contributions | $ | $ 3 | $ 3 | $ 3 | |
Deferred compensation retirement plan | Base salary | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Participants annual salary contributions, percentage | 25.00% | |||
Deferred compensation retirement plan | Annual bonus | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Participants annual salary contributions, percentage | 100.00% | |||
Deferred compensation retirement plan | Officer | Base salary | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Limit of employee's contribution of base salary, percent | 10.00% | |||
Deferred compensation retirement plan | Key employee | Annual bonus | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Limit of employee's contribution of base salary, percent | 8.00% |
Incentive Plans (Number Of Shar
Incentive Plans (Number Of Shares Available Under The Company's Long Term Incentive Plan) (Details) - Pioneer Long Term Incentive Plan [Member] - shares | 140 Months Ended | |
Dec. 31, 2017 | Jun. 30, 2016 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Approved and authorized awards | 12,600,000 | 3,500,000 |
Awards issued under plan | (7,657,755) | |
Awards available for future grant | 4,942,245 |
Incentive Plans (Schedule Of Em
Incentive Plans (Schedule Of Employee Stock Purchase Plan) (Details) - ESPP | 252 Months Ended |
Dec. 31, 2017shares | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Approved and authorized shares | 1,250,000 |
Awards issued under plan | (951,285) |
Shares available for future issuance | 298,715 |
Incentive Plans (Schedule of Co
Incentive Plans (Schedule of Compensation Expense for Each Type of Incentive Award) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation expense | $ 103 | $ 113 | $ 112 |
Income tax benefit | 524 | 403 | 155 |
Cash proceeds received from stock option exercises | 0 | 1 | |
Restricted stock-Equity Awards | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation expense | 60 | 66 | 70 |
Restricted stock-Liability Awards | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation expense | 24 | 24 | 22 |
Stock options | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation expense | 0 | 0 | 0 |
Performance unit awards | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation expense | 17 | 21 | 18 |
ESPP | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation expense | 2 | 2 | 2 |
Compensation Expense For Incentive Awards [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Income tax benefit | $ 19 | $ 34 | $ 34 |
Incentive Plans (Schedule Of Re
Incentive Plans (Schedule Of Restricted Stock Award Activity) (Details) - $ / shares | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Restricted stock awards | |||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | |||
Outstanding at beginning of year, shares | 1,077,227 | ||
Shares granted | 332,635 | ||
Shares forfeited | (33,283) | ||
Awards vested | (460,356) | ||
Outstanding at end of year, shares | 916,223 | 1,077,227 | |
Weighted Average Grant- Date Fair Value | |||
Outstanding (usd per share) | $ 151.71 | $ 143.39 | |
Shares granted (usd per share) | 180.50 | $ 122.72 | $ 153.55 |
Shares forfeited (usd per share) | 153.17 | ||
Shares vested (usd per share) | $ 153.06 | ||
Restricted stock-Liability Awards | |||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | |||
Outstanding at beginning of year, shares | 290,552 | ||
Shares granted | 117,984 | ||
Shares forfeited | (20,687) | ||
Awards vested | (135,114) | ||
Outstanding at end of year, shares | 252,735 | 290,552 |
Incentive Plans (Schedule Of St
Incentive Plans (Schedule Of Stock Options Awards Activity) (Details) - Stock options award $ / shares in Units, $ in Millions | 12 Months Ended |
Dec. 31, 2017USD ($)$ / sharesshares | |
Number of Shares | |
Number of Shares, Outstanding at beginning of year | shares | 159,378 |
Options exercised | shares | (20,885) |
Number of Shares, Outstanding and expected to vest at end of year | shares | 138,493 |
Number of Shares, Exercisable at end of year | shares | 138,493 |
Weighted Average Exercise Price | |
Outstanding at beginning of year (usd per share) | $ / shares | $ 89.03 |
Options exercised (usd per share) | $ / shares | 15.62 |
Outstanding at end of year (usd per share) | $ / shares | 100.10 |
Exercisable at end of year (usd per share) | $ / shares | $ 100.10 |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract] | |
Weighted Average Remaining Contractual Life, Outstanding and expected to vest at end of year (usd per share) | 3 years 7 months 11 days |
Weighted Average Remaining Contractual Life, Exercisable at end of (usd per share) | 3 years 7 months 11 days |
Aggregate Intrinsic Value, Outstanding and expected to vest at end of year | $ | $ 10 |
Aggregate Intrinsic Value, Exercisable at end of year | $ | $ 10 |
Incentive Plans (Schedule Of As
Incentive Plans (Schedule Of Assumptions To Estimate The Fair Value) (Details) - Performance unit awards | 12 Months Ended | ||
Dec. 31, 2017Rate | Dec. 31, 2016Rate | Dec. 31, 2015Rate | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Risk-free interest rate | 1.42% | 0.96% | 1.03% |
Minimum | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Range of volatilities | 33.60% | 28.30% | 26.10% |
Maximum | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Range of volatilities | 58.20% | 53.60% | 41.30% |
Incentive Plans (Schedule Of Pe
Incentive Plans (Schedule Of Performance Unit Activity) (Details) - $ / shares | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Weighted Average Grant- Date Fair Value | |||
Common stock, shares issued | 173,796,743 | 173,221,845 | |
Performance unit awards | |||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | |||
Outstanding at beginning of year, shares | 178,556 | ||
Units granted | 59,044 | ||
Units forfeited | 0 | ||
Units vested | (74,442) | ||
Outstanding at end of year, shares | 163,158 | 178,556 | |
Weighted Average Grant- Date Fair Value | |||
Outstanding (usd per share) | $ 223.45 | $ 211.46 | |
Units granted (usd per share) | 258.27 | $ 203.69 | $ 222.33 |
Units forfeited (usd per share) | 0 | ||
Units vested (usd per share) | $ 222.33 | ||
Performance Units [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | |||
Units vested | (74,442) | (4,029) | |
Weighted Average Grant- Date Fair Value | |||
Performance percentage of actual payout minimum | 0.00% | ||
Performance percentage to reach maximum | 250.00% | ||
Number of shares earned for each vested award | 1.50 | ||
Common stock, shares issued | 118,198 | ||
Performance Units Service Period Lapsed [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | |||
Units vested | (78,796) | ||
Retirement Deferred Performance Units Service Period Lapse [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | |||
Units vested | (325) |
Asset Retirement Obligations (D
Asset Retirement Obligations (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||
Beginning asset retirement obligations | $ 297 | $ 285 | $ 189 |
Obligations assumed in acquisitions | 0 | 2 | 0 |
New wells placed on production | 3 | 2 | 4 |
Changes in estimates (a) | (9) | 17 | 103 |
Dispositions | (7) | 0 | 0 |
Liabilities settled | (32) | (27) | (23) |
Accretion of discount | 19 | 18 | 12 |
Ending asset retirement obligations | 271 | 297 | $ 285 |
Asset retirement obligations, current portion | $ 41 | $ 39 |
Commitments And Contingencies77
Commitments And Contingencies (Narrative) (Details) - USD ($) $ in Millions | 1 Months Ended | 12 Months Ended | ||
Jun. 30, 2017 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Commitments and Contingencies Disclosure [Abstract] | ||||
Current annual salaries of officers and key employees | $ 32 | |||
Rent expense | 69 | $ 59 | $ 58 | |
Operating lease term | 20 years | |||
Annual base rent | 33 | |||
Capitalized construction costs | 57 | |||
Build-to-suit lease liability | $ 56 |
Commitments And Contingencies C
Commitments And Contingencies Commitments and Contingencies (Schedule of Minimum Commitments) (Details) $ in Millions | Dec. 31, 2017USD ($) |
Other Commitments [Line Items] | |
2,018 | $ 688 |
2,019 | 702 |
2,020 | 762 |
2,021 | 667 |
2,022 | 513 |
Thereafter | 2,234 |
Total minimum commitments | 5,566 |
Lease Commitments | |
2,018 | 27 |
2,019 | 42 |
2,020 | 53 |
2,021 | 40 |
2,022 | 37 |
Thereafter | 680 |
Total minimum commitments | 879 |
Drilling Commitments | |
Other Commitments [Line Items] | |
2,018 | 93 |
2,019 | 41 |
2,020 | 37 |
2,021 | 0 |
2,022 | 0 |
Thereafter | 0 |
Total minimum commitments | 171 |
Purchase, Gathering, Processing, Transportation, Storage and Fractionation Commitments | |
Other Commitments [Line Items] | |
2,018 | 568 |
2,019 | 619 |
2,020 | 672 |
2,021 | 627 |
2,022 | 476 |
Thereafter | 1,554 |
Total minimum commitments | $ 4,516 |
Commitments And Contingencies79
Commitments And Contingencies (Schedule of Delivery Commitments) (Details) | Dec. 31, 2017MMBTU / dMBbl_per_day |
Oil | |
2018 | MBbl_per_day | 66,685 |
2019 | MBbl_per_day | 63,356 |
2020 | MBbl_per_day | 68,347 |
2021 | MBbl_per_day | 70,000 |
2022 | MBbl_per_day | 30,575 |
2023 | MBbl_per_day | 0 |
2024 | MBbl_per_day | 0 |
Gas | |
2018 | MMBTU / d | 0 |
2019 | MMBTU / d | 75,342 |
2020 | MMBTU / d | 100,000 |
2021 | MMBTU / d | 100,000 |
2022 | MMBTU / d | 100,000 |
2022 | MMBTU / d | 100,000 |
2024 | MMBTU / d | 24,863 |
Related Party Transactions (Nar
Related Party Transactions (Narrative) (Details) - EFS Midstream - Noncontrolling interest owned by wholly-owned subsidiary $ in Millions | 12 Months Ended |
Dec. 31, 2015USD ($) | |
Master Services Agreement | |
Cost reimbursement fixed | $ 2 |
Cost reimbursement variable | 9 |
HGH Agreement | |
Related party transaction expenses paid | $ 54 |
Major Customers (Consolidated O
Major Customers (Consolidated Oil, NGL And Gas Revenues) (Details) - Oil, NGL and gas production revenues - Customer concentration | 12 Months Ended | ||
Dec. 31, 2017Rate | Dec. 31, 2016Rate | Dec. 31, 2015Rate | |
Sunoco Logistics Partners L.P. | |||
Concentration Risk [Line Items] | |||
Concentration risk percent | 21.00% | 19.00% | 18.00% |
Occidental Energy Marketing Inc. | |||
Concentration Risk [Line Items] | |||
Concentration risk percent | 16.00% | 16.00% | 18.00% |
Plains Marketing LP | |||
Concentration Risk [Line Items] | |||
Concentration risk percent | 14.00% | 16.00% | 22.00% |
Enterprise Products Partners L.P. | |||
Concentration Risk [Line Items] | |||
Concentration risk percent | 11.00% | 12.00% | 12.00% |
Major Customers Major Customers
Major Customers Major Customers (Sales of Purchased Oil and Gas (Details) - Sales of Purchased Oil and Gas [Member] | 12 Months Ended | ||
Dec. 31, 2017Rate | Dec. 31, 2016Rate | Dec. 31, 2015Rate | |
Occidental Energy Marketing Inc. | |||
Concentration Risk [Line Items] | |||
Concentration risk percent | 39.00% | 27.00% | 25.00% |
Valero Marketing and Supply Company | |||
Concentration Risk [Line Items] | |||
Concentration risk percent | 14.00% | 17.00% | 50.00% |
BP Energy | |||
Concentration Risk [Line Items] | |||
Concentration risk percent | 11.00% | 18.00% | 0.00% |
Exxon Mobil | |||
Concentration Risk [Line Items] | |||
Concentration risk percent | 11.00% | 23.00% | 12.00% |
Interest And Other Income (Inte
Interest And Other Income (Interest And Other Income) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Other Income and Expenses [Abstract] | |||
Interest income | $ 32 | $ 22 | $ 3 |
Tax refunds | 13 | 2 | 0 |
Deferred compensation plan income | 4 | 3 | 4 |
Other income | 4 | 5 | 10 |
Equity interest in income of EFS Midstream | 0 | 0 | 5 |
Total interest and other income | $ 53 | $ 32 | $ 22 |
Other Expense (Details)
Other Expense (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Other Income and Expenses [Abstract] | |||
Transportation commitment charges | $ 167 | $ 109 | $ 53 |
Other | 58 | 49 | 27 |
Loss from vertical integration services | 17 | 54 | 34 |
Impairment of inventory and other property and equipment | 2 | 8 | 86 |
Idle drilling and well service equipment charges | 0 | 64 | 92 |
Restructuring charges | 0 | 4 | 23 |
Total other expense | 244 | 288 | 315 |
Gross vertical integration revenues | 140 | 147 | 298 |
Total vertical integration costs and expenses | $ 157 | $ 201 | $ 332 |
Income Taxes (Narrative) (Detai
Income Taxes (Narrative) (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Income Tax Disclosure [Abstract] | |||
Tax refunds received | $ (66,000,000) | ||
Payments for income taxes, net of tax refunds received | $ 0 | $ 43,000,000 | |
Income tax benefit from from rate change | 625,000,000 | ||
AMT credit carryovers | 20,000,000 | ||
Unrecognized tax benefits | $ 124,000,000 | $ 112,000,000 | $ 0 |
Income Taxes (Schedule of Unrec
Income Taxes (Schedule of Unrecognized Tax Benefits) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | ||
Balance at beginning of year | $ 112 | $ 0 |
Additions based on tax positions related to the current year | 12 | 112 |
Reductions for tax positions of prior years | 0 | 0 |
Balance at end of year | $ 124 | $ 112 |
Income Taxes (Summary Of Open T
Income Taxes (Summary Of Open Tax Years, By Jurisdiction) (Details) | 12 Months Ended |
Dec. 31, 2017 | |
U.S. federal | |
Income Tax Contingency [Line Items] | |
Open tax years, by jurisdiction | 2,012 |
Various U.S. states | |
Income Tax Contingency [Line Items] | |
Open tax years, by jurisdiction | 2,013 |
Income Taxes (Schedule Of Incom
Income Taxes (Schedule Of Income Tax (Provision) Benefit Allocation) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Income Tax Disclosure [Abstract] | |||
Income tax benefit from continuing operations | $ 524 | $ 403 | $ 155 |
Income tax benefit from discontinued operations | $ 0 | $ 0 | $ 2 |
Income Taxes (Income Tax (Provi
Income Taxes (Income Tax (Provision) Benefit Attributable To Income From Continuing Operations) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Current: | |||
U.S. federal | $ 5 | $ 22 | $ (22) |
U.S. state | 0 | 2 | (1) |
Current income tax (provision) benefit | 5 | 24 | (23) |
Deferred: | |||
U.S. federal | 526 | 375 | 165 |
U.S. state | (7) | 4 | 13 |
Deferred income tax benefit | 519 | 379 | 178 |
Income tax benefit from continuing operations | $ 524 | $ 403 | $ 155 |
Income Taxes (Schedule Of Effec
Income Taxes (Schedule Of Effective Income Tax Rate Reconciliation) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Income Tax Disclosure [Abstract] | |||
Income (loss) from continuing operations attributable to common stockholders before income taxes | $ 309 | $ (959) | $ (421) |
Federal statutory income tax rate | 35.00% | 35.00% | 35.00% |
(Provision) benefit for federal income taxes at the statutory rate | $ (108) | $ 336 | $ 147 |
State income tax (provision) benefit (net of federal tax) | (4) | 3 | 8 |
State valuation allowance (net of federal tax) | (1) | (3) | 0 |
Change in federal income tax rate | 625 | 0 | 0 |
Equity compensation excess tax benefit | 9 | 0 | 0 |
Federal credit for increasing research activities (net of unrecognized tax benefits) | 6 | 68 | 0 |
State credit for increasing research activities (net of unrecognized tax benefits and federal tax) | 0 | 4 | 0 |
Other | (3) | (5) | 0 |
Income tax benefit from continuing operations | $ 524 | $ 403 | $ 155 |
Effective income tax rate, excluding net income attributable to the noncontrolling interests | (170.00%) | 42.00% | 37.00% |
Income Taxes (Schedule Of Defer
Income Taxes (Schedule Of Deferred Tax Assets And Deferred Tax Liabilities) (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Valuation Allowance [Line Items] | |||
Net operating loss carryforward | $ 594 | $ 635 | |
Deferred Tax Assets, Tax Credit Carryforwards, Research | 87 | 107 | |
Asset retirement obligations | 59 | 106 | |
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits, Share-based Compensation Cost | 48 | 81 | |
Deferred Tax Assets, Hedging Transactions | 52 | 32 | |
Other | 22 | 30 | |
Total deferred tax assets | 862 | 991 | |
Oil and gas properties, principally due to differences in basis, depletion and the deduction of intangible drilling costs for tax purposes | (1,640) | (2,184) | |
Other property and equipment, principally due to the deduction of bonus depreciation for tax purposes | (121) | (204) | |
Total deferred tax liabilities | (1,761) | (2,388) | |
Deferred Tax Liabilities, Net | (899) | (1,397) | |
Valuation allowances | (6) | ||
Unrecognized tax benefits | 124 | $ 112 | $ 0 |
Research Tax Credit Carryforward [Member] | U.S. | |||
Valuation Allowance [Line Items] | |||
Deferred Tax Assets, Tax Credit Carryforwards, Research | 82 | ||
Research Tax Credit Carryforward [Member] | Texas | |||
Valuation Allowance [Line Items] | |||
Deferred Tax Assets, Tax Credit Carryforwards, Research | 5 | ||
Domestic Tax Authority [Member] | |||
Valuation Allowance [Line Items] | |||
Net operating loss carryforward | 2,800 | ||
COLORADO | |||
Valuation Allowance [Line Items] | |||
Net operating loss carryforward | 164 | ||
Valuation allowances | $ (125) |
Net Income Per Share Attribut92
Net Income Per Share Attributable To Common Stockholders (Details) - USD ($) shares in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Statement Operating Activities Segment [Line Items] | |||
Net income (loss) attributable to common stockholders | $ 827 | $ (556) | $ (273) |
Basic and diluted weighted average common shares outstanding | 170 | 166 | 149 |
Continuing operations | |||
Statement Operating Activities Segment [Line Items] | |||
Income (loss) from continuing operations | $ 833 | $ (556) | $ (266) |
Participating basic earnings | (6) | 0 | 0 |
Net income (loss) attributable to common stockholders | 827 | (556) | (266) |
Discontinued operations | |||
Statement Operating Activities Segment [Line Items] | |||
Net income (loss) attributable to common stockholders | $ 0 | $ 0 | $ (7) |
Subsequent Events (Details)
Subsequent Events (Details) - USD ($) $ / shares in Units, $ in Millions | 2 Months Ended | 12 Months Ended | ||
Feb. 14, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Subsequent Event [Line Items] | ||||
Dividends declared (usd per share) | $ 0.08 | $ 0.08 | $ 0.08 | |
Subsequent event | ||||
Subsequent Event [Line Items] | ||||
Stock Repurchase Program, Authorized Amount | $ 100 | |||
Future Year Semiannual Amount [Member] | Subsequent event | ||||
Subsequent Event [Line Items] | ||||
Dividends declared (usd per share) | $ 0.16 |