Document and Entity Information
Document and Entity Information - USD ($) | 12 Months Ended | ||
Dec. 31, 2017 | Jan. 31, 2018 | Jun. 30, 2017 | |
Document And Entity Information [Abstract] | |||
Entity Registrant Name | QEP RESOURCES, INC. | ||
Entity Central Index Key | 1,108,827 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Common Stock, Shares Outstanding | 240,968,931 | ||
Document Fiscal Year Focus | 2,017 | ||
Document Fiscal Period Focus | FY | ||
Document Type | 10-K | ||
Amendment Flag | false | ||
Document Period End Date | Dec. 31, 2017 | ||
Entity Public Float | $ 2,429,606,369 |
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 | |||
Oil sales | $ 939.4 | $ 769.1 | $ 834.2 |
Gas sales | 494 | 417.1 | 468.5 |
NGL sales | 111.9 | 83.5 | 80 |
Other revenues | 15 | 6.2 | 15.1 |
Purchased oil and gas sales | 62.6 | 101.2 | 620.8 |
Total Revenues | 1,622.9 | 1,377.1 | 2,018.6 |
OPERATING EXPENSES | |||
Purchased oil and gas expense | 64.3 | 105.5 | 626.8 |
Lease operating expense | 294.8 | 224.7 | 238.8 |
Transportation and processing costs | 245.3 | 289.2 | 291.3 |
Gathering and other expense | 7.3 | 5 | 5.8 |
General and administrative | 153.5 | 196.5 | 168 |
Production and property taxes | 114.3 | 94.8 | 117.6 |
Depreciation, depletion and amortization | 754.5 | 871.1 | 881.1 |
Exploration expenses | 22 | 1.7 | 2.7 |
Impairment | 78.9 | 1,194.3 | 55.6 |
Total Operating Expenses | 1,734.9 | 2,982.8 | 2,387.7 |
Net gain (loss) from asset sales | 213.5 | 5 | 4.6 |
OPERATING INCOME (LOSS) | 101.5 | (1,600.7) | (364.5) |
Realized and unrealized gains (losses) on derivative contracts (Note 6) | 24.5 | (233) | 277.2 |
Interest and other income (expense) | 1.6 | 23.7 | (10.1) |
Loss from early extinguishment of debt | (32.7) | 0 | 0 |
Interest expense | (137.8) | (143.2) | (145.6) |
INCOME (LOSS) BEFORE INCOME TAXES | (42.9) | (1,953.2) | (243) |
Income tax (provision) benefit | 312.2 | 708.2 | 93.6 |
NET INCOME (LOSS) | $ 269.3 | $ (1,245) | $ (149.4) |
Earnings (loss) per common share | |||
Basic | $ 1.12 | $ (5.62) | $ (0.85) |
Diluted | $ 1.12 | $ (5.62) | $ (0.85) |
Weighted-average common shares outstanding | |||
Used in basic calculation | 240.6 | 221.7 | 176.6 |
Used in diluted calculation | 240.6 | 221.7 | 176.6 |
Dividends per common share | $ 0 | $ 0 | $ 0.08 |
CONSOLIDATED STATEMENTS OF COMP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | ||
Statement of Comprehensive Income [Abstract] | ||||
Net income (loss) | $ 269.3 | $ (1,245) | $ (149.4) | |
Other comprehensive income, net of tax: | ||||
Future tax effective rate change(1) | [1] | (3.8) | 0 | 0 |
Pension and other postretirement plans adjustments: | ||||
Current period prior service cost(2) | [2] | (2.4) | 0 | 0.6 |
Current period net actuarial (gain) loss(3) | [3] | 5.8 | (5.6) | (0.5) |
Amortization of prior service cost(4) | [4] | 0.5 | 0.8 | 8.2 |
Amortization of net actuarial (gain) loss(5) | [5] | 0.3 | 0.5 | 0.3 |
Net curtailment and settlement cost incurred(6) | [6] | 0.4 | 0 | 4.5 |
Other comprehensive income (loss) | 5.6 | (4.3) | 11.9 | |
Comprehensive income (loss) | $ 274.9 | $ (1,249.3) | $ (137.5) | |
[1] | The new tax legislation changed the federal corporate income tax rate from 35% to 21% starting in 2018. The rate change caused the Company to revalue its deferred tax liabilities and assets using the lower rate. | |||
[2] | Presented net of income tax expense of $0.8 million for the year ended December 31, 2017 and net of income tax benefit of $0.3 million for the year ended December 31, 2015. | |||
[3] | Presented net of income tax expense of $1.8 million for the year ended December 31, 2017 and net of income tax benefit of $3.3 million and $0.3 million for the years ended December 31, 2016 and 2015, respectively. | |||
[4] | Presented net of income tax expense of $0.2 million, $0.5 million, and $4.9 million for the years ended December 31, 2017, 2016, and 2015, respectively. | |||
[5] | Presented net of income tax expense of $0.1 million, $0.3 million, and $0.2 million for the years ended December 31, 2017, 2016, and 2015, respectively. | |||
[6] | Presented net of income tax expense of $0.1 million and $2.6 million for the years ended December 31, 2017 and 2015, respectively. |
CONSOLIDATED STATEMENTS OF COM4
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | ||
Pension and other postretirement plans adjustments: | ||||
Current period prior service cost, tax | [1] | $ 0.8 | $ 0 | $ (0.3) |
Current period net actuarial (gain) loss, tax | [2] | (1.8) | 3.3 | 0.3 |
Amortization of prior service cost, tax | [3] | (0.2) | (0.5) | (4.9) |
Amortization of net actuarial (gain) loss, tax | [4] | (0.1) | (0.3) | (0.2) |
Net curtailment and settlement cost incurred, tax | [5] | $ 0.1 | $ 0 | $ (2.6) |
[1] | Presented net of income tax expense of $0.8 million for the year ended December 31, 2017 and net of income tax benefit of $0.3 million for the year ended December 31, 2015. | |||
[2] | Presented net of income tax expense of $1.8 million for the year ended December 31, 2017 and net of income tax benefit of $3.3 million and $0.3 million for the years ended December 31, 2016 and 2015, respectively. | |||
[3] | Presented net of income tax expense of $0.2 million, $0.5 million, and $4.9 million for the years ended December 31, 2017, 2016, and 2015, respectively. | |||
[4] | Presented net of income tax expense of $0.1 million, $0.3 million, and $0.2 million for the years ended December 31, 2017, 2016, and 2015, respectively. | |||
[5] | Presented net of income tax expense of $0.1 million and $2.6 million for the years ended December 31, 2017 and 2015, respectively. |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Current Assets | ||
Cash and cash equivalents | $ 0 | $ 443.8 |
Accounts receivable, net | 142.1 | 155.7 |
Income tax receivable | 4.9 | 18.6 |
Fair value of derivative contracts | 3.4 | 0 |
Hydrocarbon inventories, at lower of average cost or net realizable value | 3.6 | 10.4 |
Prepaid expenses | 10.7 | 11.4 |
Other current assets | 0.7 | 0.2 |
Total Current Assets | 165.4 | 640.1 |
Property, Plant and Equipment (successful efforts method for oil and gas properties) | ||
Proved properties | 12,470.9 | 14,232.5 |
Unproved properties | 1,095.8 | 871.5 |
Gathering and other | 319.7 | 301.8 |
Materials and supplies | 37.8 | 32.7 |
Total Property, Plant and Equipment | 13,924.2 | 15,438.5 |
Less Accumulated Depreciation, Depletion and Amortization | ||
Exploration and production | 6,642.9 | 8,797.7 |
Gathering and other | 124.3 | 101.8 |
Total Accumulated Depreciation, Depletion and Amortization | 6,767.2 | 8,899.5 |
Net Property, Plant and Equipment | 7,157 | 6,539 |
Fair value of derivative contracts | 0.1 | 0 |
Other noncurrent assets | 72.3 | 66.3 |
TOTAL ASSETS | 7,394.8 | 7,245.4 |
Current Liabilities | ||
Checks outstanding in excess of cash balances | 44 | 12.3 |
Accounts payable and accrued expenses | 372.1 | 269.7 |
Production and property taxes | 31.6 | 30.1 |
Interest payable | 26 | 32.9 |
Fair value of derivative contracts | 103.6 | 169.8 |
Total Current Liabilities | 577.3 | 514.8 |
Long-term debt | 2,160.8 | 2,020.9 |
Deferred income taxes | 518 | 825.9 |
Asset retirement obligations | 206.6 | 225.8 |
Fair value of derivative contracts | 31.8 | 32 |
Other long-term liabilities | 102.4 | 123.3 |
Commitments and Contingencies (Note 9) | ||
EQUITY | ||
Common stock - par value $0.01 per share; 500.0 million shares authorized; 243.0 million and 240.7 million shares issued, respectively | 2.4 | 2.4 |
Treasury stock - 2.0 million and 1.1 million shares, respectively | (34.2) | (22.9) |
Additional paid-in capital | 1,398.2 | 1,366.6 |
Retained earnings | 2,442.6 | 2,173.3 |
Accumulated other comprehensive income (loss) | (11.1) | (16.7) |
Total Common Shareholders' Equity | 3,797.9 | 3,502.7 |
TOTAL LIABILITIES AND EQUITY | $ 7,394.8 | $ 7,245.4 |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares shares in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
EQUITY | ||
Common stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Common stock, shares authorized (in shares) | 500 | 500 |
Common stock, shares issued (in shares) | 243 | 240.7 |
Treasury stock (in shares) | 2 | 1.1 |
CONSOLIDATED STATEMENTS OF EQUI
CONSOLIDATED STATEMENTS OF EQUITY - USD ($) shares in Millions, $ in Millions | Total | Common Stock, Value [Member] | Treasury Stock [Member] | Additional Paid-in Capital [Member] | Retained Earnings [Member] | Other Comprehensive Income (Loss) [Member] | Stockholders' Equity, Total [Member] |
Balance at Dec. 31, 2014 | $ 1.8 | $ (25.4) | $ 535.3 | $ 3,587.9 | $ (24.3) | $ 4,075.3 | |
Shares at Dec. 31, 2014 | 176.2 | ||||||
Treasury shares at Dec. 31, 2014 | (0.8) | ||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||
Net income (loss) | $ 149.4 | $ 0 | $ 0 | 0 | (149.4) | 0 | (149.4) |
Net income (loss), shares | 0 | 0 | |||||
Dividends | 0 | 0 | |||||
Dividends | $ 0 | $ 0 | 0 | (14.1) | 0 | (14.1) | |
Share-based compensation | $ 0 | $ 10.8 | 19.5 | (6.1) | 0 | 24.2 | |
Share-based compensation, shares | 1.1 | 0.3 | |||||
Change in pension and postretirement liability, net of tax, shares | 0 | 0 | |||||
Change in pension and postretirement liability, net of tax | $ 0 | $ 0 | 0 | 0 | 11.9 | 11.9 | |
Shares at Dec. 31, 2015 | 177.3 | ||||||
Treasury shares at Dec. 31, 2015 | (0.5) | ||||||
Balance at Dec. 31, 2015 | $ 1.8 | $ (14.6) | 554.8 | 3,418.3 | (12.4) | 3,947.9 | |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||
Net income (loss) | $ 1,245 | $ 0 | $ 0 | 0 | (1,245) | 0 | (1,245) |
Net income (loss), shares | 0 | 0 | |||||
Equity issuance, net of offering costs, shares | 61 | 0 | |||||
Equity issuance, net of offering costs | $ 0.6 | $ 0 | 780.8 | 0 | 0 | (781.4) | |
Share-based compensation | $ 0 | $ (8.3) | 31 | 0 | 0 | 22.7 | |
Share-based compensation, shares | 2.4 | (0.6) | |||||
Change in pension and postretirement liability, net of tax, shares | 0 | 0 | |||||
Change in pension and postretirement liability, net of tax | $ 0 | $ 0 | 0 | 0 | (4.3) | (4.3) | |
Shares at Dec. 31, 2016 | 240.7 | ||||||
Treasury shares at Dec. 31, 2016 | (1.1) | (1.1) | |||||
Balance at Dec. 31, 2016 | $ 3,502.7 | $ 2.4 | $ (22.9) | 1,366.6 | 2,173.3 | (16.7) | 3,502.7 |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||
Net income (loss) | $ (269.3) | $ 0 | $ 0 | 0 | 269.3 | 0 | 269.3 |
Net income (loss), shares | 0 | 0 | |||||
Share-based compensation | $ 0 | $ (11.3) | 31.6 | 0 | 0 | 20.3 | |
Share-based compensation, shares | 2.3 | (0.9) | |||||
Change in pension and postretirement liability, net of tax, shares | 0 | 0 | |||||
Change in pension and postretirement liability, net of tax | $ 0 | $ 0 | 0 | 0 | 5.6 | 5.6 | |
Shares at Dec. 31, 2017 | 243 | ||||||
Treasury shares at Dec. 31, 2017 | (2) | (2) | |||||
Balance at Dec. 31, 2017 | $ 2.4 | $ (34.2) | $ 1,398.2 | $ 2,442.6 | $ (11.1) | $ 3,797.9 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
OPERATING ACTIVITIES | |||
Net income (loss) | $ 269.3 | $ (1,245) | $ (149.4) |
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: | |||
Depreciation, depletion and amortization | 754.5 | 871.1 | 881.1 |
Deferred income taxes | (314.8) | (651.3) | 25.3 |
Impairment | 78.9 | 1,194.3 | 55.6 |
Dry hole exploratory well expense | 21.3 | 0 | 0 |
Share-based compensation | 22.4 | 35.6 | 34.7 |
Pension curtailment loss | 0 | 0 | 11.2 |
Amortization of debt issuance costs and discounts | 6.2 | 6.4 | 6.2 |
Bargain purchase gain from acquisitions | 0.4 | (22.6) | 0 |
Net (gain) loss from asset sales | (213.5) | (5) | (4.6) |
Loss from early extinguishment of debt | 32.7 | 0 | 0 |
Unrealized (gains) losses on marketable securities | (2.9) | (1.4) | 0.2 |
Unrealized (gains) losses on derivative contracts | (40) | 367 | 183.7 |
Other non-cash activity | (9.4) | 0 | 0 |
Accounts receivable | (2) | 95.3 | 124.6 |
Hydrocarbon inventories | (1.1) | 8.7 | 15.5 |
Prepaid expenses | (0.2) | 18.5 | 16.7 |
Accounts payable and accrued expenses | 3.5 | (50.3) | (34.5) |
Federal income taxes receivable | 13.7 | 68.7 | (619.4) |
Other | (20.6) | (26.3) | (65.6) |
Net Cash Provided by (Used in) Operating Activities | 598.4 | 663.7 | 481.3 |
INVESTING ACTIVITIES | |||
Property acquisitions | (815.2) | (639) | (98.3) |
Property, plant and equipment, including exploratory well expense | (1,159.6) | (569.1) | (1,141.1) |
Proceeds from disposition of assets | 806.8 | 29 | 21.8 |
Net Cash Provided by (Used in) Investing Activities | (1,168) | (1,179.1) | (1,217.6) |
FINANCING ACTIVITIES | |||
Checks outstanding in excess of cash balances | 31.7 | (17.5) | (24.9) |
Long-term debt issued | 500 | 0 | 0 |
Long-term debt issuance costs paid | (14.4) | 0 | (2.6) |
Long-term debt extinguishment costs paid | (28.1) | 0 | 0 |
Long-term debt repaid | (445.6) | (176.8) | 0 |
Proceeds from credit facility | 492 | 0 | 0 |
Repayments of credit facility | (403) | 0 | 0 |
Treasury stock repurchases | (6.8) | (4.1) | (2.7) |
Other capital contributions | 0 | 0 | (0.2) |
Dividends paid | 0 | 0 | (14.1) |
Proceeds from issuance of common stock, net | 0 | 781.4 | 0 |
Excess tax (provision) benefit on share-based compensation | 0 | (0.1) | 3.2 |
Net Cash Provided by (Used in) Financing Activities | 125.8 | 583.1 | (47.7) |
Change in cash and cash equivalents | (443.8) | 67.7 | (784) |
Beginning cash and cash equivalents | 443.8 | 376.1 | 1,160.1 |
Ending cash and cash equivalents | $ 0 | $ 443.8 | $ 376.1 |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2017 | |
Summary of Significant Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | Nature of Business QEP Resources, Inc. is an independent crude oil and natural gas exploration and production company with operations in two regions of the United States: the Northern Region (primarily in North Dakota and Utah) and the Southern Region (primarily in Texas and Louisiana). Unless otherwise specified or the context otherwise requires, all references to "QEP" or the "Company" are to QEP Resources, Inc. and its subsidiaries on a consolidated basis. QEP's corporate headquarters are located in Denver, Colorado and shares of QEP's common stock trade on the New York Stock Exchange (NYSE) under the ticker symbol "QEP". Principles of Consolidation The Consolidated Financial Statements contain the accounts of QEP and its majority-owned or controlled subsidiaries. The Consolidated Financial Statements were prepared in accordance with GAAP and with the instructions for annual reports on Form 10-K and Regulations S-X. All significant intercompany accounts and transactions have been eliminated in consolidation. All dollar and share amounts in this Annual Report on Form 10-K are in millions, except per share information and where otherwise noted. Termination of Marketing Agreements Effective January 1, 2016, QEP terminated its contracts for resale and marketing transactions between its wholly owned subsidiaries, QEP Marketing Company (QEP Marketing) and QEP Energy Company (QEP Energy). In addition, substantially all of QEP Marketing's third-party purchase and sale agreements and gathering, processing and transportation contracts were assigned to QEP Energy, except those contracts related to natural gas storage activities and Haynesville Gathering. As a result, QEP Energy directly markets its own oil, gas and NGL production. While QEP continues to act as an agent for the sale of oil, gas and NGL production for other working interest owners, for whom QEP serves as the operator, QEP is no longer the first purchaser of this production. QEP has substantially reduced its marketing activities, and subsequently, is reporting lower resale revenue and expenses than it had prior to 2016. In conjunction with the changes described above, QEP conducted a segment analysis in accordance with Accounting Standards Codification (ASC) Topic 280, Segment Reporting, and determined that QEP had one reportable segment effective January 1, 2016. The Company has recast its financial statements for historical periods to reflect the impact of the termination of marketing agreements to show its financial results without segments. Reclassifications Certain prior period amounts on the Consolidated Statements of Operations, Consolidated Balance Sheets and Consolidated Statements of Cash Flows have been reclassified to conform to the current year presentation. Such reclassifications had no effect on the Company's net income (loss), earnings (loss) per share, cash flows, current assets or retained earnings previously reported. Use of Estimates The preparation of the Consolidated Financial Statements and Notes in conformity with GAAP requires that management formulate estimates and assumptions that affect revenues, expenses, assets, liabilities and the disclosure of contingent assets and liabilities. A significant item that requires management's estimates and assumptions is the estimate of proved oil, gas and NGL reserves, which are used in the calculation of depreciation, depletion and amortization rates of its oil and gas properties, impairment of proved properties and asset retirement obligations. Changes in estimated quantities of its reserves could impact the Company's reported financial results as well as disclosures regarding the quantities and value of proved oil and gas reserves. Other items subject to estimates and assumptions include the carrying amount of property, plant and equipment, assigning fair value and allocating purchase price in connection with business combinations, valuation allowances for receivables, income taxes, valuation of derivatives instruments, accrued liabilities, accrued revenue and related receivables and obligations related to employee benefits, among others. Although management believes these estimates are reasonable, actual results could differ from these estimates. Risks and Uncertainties The Company's revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for oil, gas and NGL, which are affected by many factors outside of QEP's control, including changes in market supply and demand. Changes in market supply and demand are impacted by weather conditions, pipeline capacity constraints, inventory storage levels, basis differentials, export capacity, strength of the U.S. dollar and other factors. Field-level prices received for QEP's oil and gas production have historically been volatile and may be subject to significant fluctuations in the future. The Company's derivative contracts serve to mitigate in part the effect of this price volatility on the Company's cash flows, and the Company has derivative contracts in place for a portion of its expected future oil and gas production. Refer to Note 6 – Derivative Contracts for the Company's open oil and gas commodity derivative contracts. Revenue Recognition QEP recognizes revenue from oil and gas producing activities in the period that services are provided or products are delivered. Revenues associated with the sale of oil, gas and NGL are accounted for using the sales method, whereby revenue is recognized when these commodities are sold to purchasers. Revenues include estimates for the two most recent months using published commodity price indexes and volumes supplied by field operators. An imbalance liability is recorded to the extent that QEP has sold volumes in excess of its share of remaining reserves in an underlying property. QEP also purchases and resells oil and gas primarily to mitigate losses on unutilized capacity related to firm transportation commitments and storage activities. QEP recognizes revenue from these resale activities when title transfers to the customer. Cash and Cash Equivalents and Restricted Cash Cash equivalents consist principally of highly liquid investments in securities with original maturities of three months or less made through commercial bank accounts that result in available funds the next business day. As of December 31, 2017 , QEP had no unrestricted cash and restricted cash of $23.4 million . As of December 31, 2016 , QEP had unrestricted cash of $443.8 million and restricted cash of $21.6 million . QEP's restricted cash is primarily cash deposited into an escrow account related to a title dispute between third parties in the Williston Basin and is included in "Other noncurrent assets" on the Consolidated Balance Sheets. Supplemental cash flow information is shown in the table below: Year Ended December 31, 2017 2016 2015 Supplemental Disclosures (in millions) Cash paid for interest, net of capitalized interest $ 134.9 $ 139.1 $ 139.4 Cash paid (refund received) for income taxes, net $ (0.3 ) $ (123.5 ) $ 487.8 Non-cash investing activities Change in capital expenditure accrual balance $ 60.2 $ (32.8 ) $ (129.2 ) Accounts Receivable Accounts receivable consists mainly of receivables from oil and gas purchasers and joint interest owners on properties the Company operates. For receivables from joint interest owners, the Company has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. Generally, the Company's oil and gas receivables are collected and bad debts are minimal. However, if commodity prices remain low for an extended period of time, the Company could incur increased levels of bad debt expense. Recovery of bad debt associated with accounts receivable for the year ended December 31, 2017 was $1.0 million . Bad debt expense associated with accounts receivable for the years ended December 31, 2016 and 2015 , was $1.8 million , and $0.5 million , respectively. Bad debt recovery or expense is included in "General and administrative" expense on the Consolidated Statements of Operations. The Company routinely assesses the recoverability of all material trade and other receivables to determine their collectability. The allowance for bad debt expenses was $1.6 million at December 31, 2017 , and $4.8 million at December 31, 2016 . Property, Plant and Equipment Property, plant and equipment balances are stated at historical cost. Material and supplies inventories are valued at the lower of cost or net realizable value. Maintenance and repair costs are expensed as incurred. Significant accounting policies for our property, plant and equipment are as follows: Successful Efforts Accounting for Oil and Gas Operations The Company follows the successful efforts method of accounting for oil and gas property acquisitions, exploration, development and production activities. Under this method, the acquisition costs of proved and unproved properties, successful exploratory wells and development wells are capitalized. Other exploration costs, including geological and geophysical costs, delay rentals and administrative costs associated with unproved property and unsuccessful exploratory well costs are expensed. Costs to operate and maintain wells and field equipment are expensed as incurred. A gain or loss is generally recognized only when an entire field is sold or abandoned, or if the unit-of-production depreciation, depletion and amortization rate would be significantly affected. Capitalized costs of unproved properties are reclassified to proved property when related proved reserves are determined or charged against the impairment allowance when abandoned. Capitalized Exploratory Well Costs The Company capitalizes exploratory well costs until it determines whether an exploratory well is commercial or noncommercial. If the Company deems the well commercial, capitalized costs are depreciated on a field basis using the unit-of-production method and the estimated proved developed oil and gas reserves. If the Company concludes that the well is noncommercial, well costs are immediately charged to exploration expense. Exploratory well costs that have been capitalized for a period greater than one year since the completion of drilling are expensed unless the Company remains engaged in substantial activities to assess whether the project is commercial. Depreciation, Depletion and Amortization (DD&A) Capitalized proved leasehold costs are depleted on a field-by-field basis using the unit-of-production method and the estimated proved oil and gas reserves. Capitalized costs of exploratory wells that have found proved oil and gas reserves and capitalized development costs are depreciated using the unit-of-production method based on estimated proved developed reserves for a successful effort field. The Company capitalizes an estimate of the fair value of future abandonment costs. DD&A for the Company's remaining properties is generally based upon rates that will systematically charge the costs of assets against income over the estimated useful lives of those assets using the straight-line method. The estimated useful lives of those assets depreciated under the straight-line basis generally range as follows: Buildings 10 to 30 years Leasehold improvements 3 to 10 years Service, transportation and field service equipment 3 to 7 years Furniture and office equipment 3 to 7 years Impairment of Long-Lived Assets Proved oil and gas properties are evaluated on a field-by-field basis for potential impairment. Other properties are evaluated on a specific asset basis or in groups of similar assets, as applicable. Impairment is indicated when a triggering event occurs and/or the sum of the estimated undiscounted future net cash flows of an evaluated asset is less than the asset's carrying value. Triggering events could include, but are not limited to, a reduction of oil, gas and NGL reserves caused by mechanical problems, faster-than-expected decline of production, lease ownership issues, and declines in oil, gas and NGL prices. If impairment is indicated, fair value is estimated using a discounted cash flow approach. Cash flow estimates require forecasts and assumptions for many years into the future for a variety of factors, including commodity prices, operating costs and estimates of proved, probable and possible reserves. Cash flow estimates relating to future cash flows from probable and possible reserves are reduced by additional risk-weighting factors. Unproved properties are evaluated on a specific asset basis or in groups of similar assets, as applicable. The Company performs periodic assessments of unproved oil and gas properties for impairment and recognizes a loss at the time of impairment. In determining whether an unproved property is impaired, the Company considers numerous factors including, but not limited to, current development and exploration drilling plans, favorable or unfavorable exploration activity on adjacent leaseholds, in-house geologists' evaluation of the lease, future reserve cash flows and the remaining lease term. During the year ended December 31, 2017 , QEP recorded impairment charges of $78.9 million , of which $38.1 million was related to proved properties due to lower future gas prices, $29.0 million was primarily related to unproved leasehold acreage in the Central Basin Platform (Refer to Note 3 – Capitalized Exploratory Well Costs for additional information), $6.5 million was related to impairment of an underground gas storage facility and $5.3 million was related to the impairment of goodwill. Of the $38.1 million impairment of proved properties, $37.1 million related to the Other Northern area and $1.0 million related to Louisiana properties. During the year ended December 31, 2016 , QEP recorded impairment charges of $1,194.3 million , of which $1,172.7 million was related to proved properties due to lower future oil and gas prices, $17.9 million was related to expiring leaseholds on unproved properties and $3.7 million was related to the impairment of goodwill. Of the $1,172.7 million impairment of proved properties, $1,164.0 million related to Pinedale properties, $4.7 million related to Uinta Basin properties, $3.4 million related to the Other Northern area and $0.6 million related to QEP's remaining Other Southern properties. During the year ended December 31, 2015 , QEP recorded impairment charges of $55.6 million , of which $39.3 million was related to proved properties due to lower future oil and gas prices, $2.0 million was related to expiring leaseholds on unproved properties and $14.3 million was related to the impairment of goodwill. Of the $39.3 million impairment on proved properties, $20.2 million related to QEP's remaining Other Southern properties, $18.4 million related Other Northern properties, and $0.7 million related to Permian Basin properties. Asset Retirement Obligations QEP is obligated to fund the costs of disposing of long-lived assets upon their abandonment. The Company's ARO liability applies primarily to abandonment costs associated with oil and gas wells and certain other properties. ARO associated with the retirement of tangible long-lived assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived assets in the period incurred. The cost of the tangible asset, including the asset retirement costs, is depreciated over the useful life of the asset. ARO are recorded at estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligations discounted at the Company's credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. If estimated future costs of ARO change, an adjustment is recorded to both the ARO liability and the long-lived asset. Revisions to estimated ARO can result from changes in retirement cost estimates, revisions to estimated inflation rates and changes in the estimated timing of abandonment. Refer to Note 4 – Asset Retirement Obligations for additional information. Goodwill Goodwill represents the excess of the amount paid over the fair value of assets acquired in a business combination and is not subject to amortization. During the year ended December 31, 2017 , QEP early adopted ASU 2017-04, Intangibles – Goodwill and Other (Topic 350): Simplifying the test for goodwill impairment . Under the new guidance QEP performs an annual goodwill impairment test by comparing the fair value of a reporting unit with its carry amount, with an impairment charge being recognized for the amount by which the carrying amount exceeds the reporting unit's fair value. QEP determines the fair value of its reporting units in which goodwill is allocated using the income approach in which the fair value is estimated based on the value of expected future cash flows. Key assumptions used in the cash flow model include estimated quantities of oil, gas and NGL reserves, including both proved reserves and risk-adjusted unproved reserves, and including probable and possible reserves; estimates of market prices considering forward commodity price curves as of the measurement date; estimates of revenue and operating costs over a multi-year period; and estimates of capital costs. During the year ended December 31, 2017 , QEP recorded $5.3 million of goodwill, which related to an acquisition in the first quarter of 2017. During the fourth quarter of 2017, QEP performed an annual impairment test over goodwill as described above, which resulted in a full write down of goodwill of $5.3 million . During the years ended December 31, 2016 and 2015 , QEP recorded $3.7 million and $14.3 million , respectively, of goodwill. Annual impairment tests over goodwill at year end December 31, 2016 and 2015 resulted in a full write down of $3.7 million and $14.3 million , respectively. Litigation and Other Contingencies The Company is involved in various commercial and regulatory claims, litigation and other legal proceedings that arise in the ordinary course of its business. In each reporting period, the Company assesses these claims in an effort to determine the degree of probability and range of possible loss for potential accrual in its Consolidated Financial Statements. The amount of ultimate loss may differ from these estimates. In accordance with ASC 450, Contingencies , an accrual is recorded for a material loss contingency when its occurrence is probable and damages are reasonably estimable based on the anticipated most likely outcome or the minimum amount within a range of possible outcomes. Refer to Note 9 – Commitments and Contingencies for additional information. QEP accrues material losses associated with environmental obligations when such losses are probable and can be reasonably estimated. Accruals for estimated environmental losses are recognized no later than at the time the remediation feasibility study, or the evaluation of response options, is complete. These accruals are adjusted as additional information becomes available or as circumstances change. Future environmental expenditures are not discounted to their present value. Recoveries of environmental costs from other parties are recorded separately as assets at their undiscounted value when receipt of such recoveries is probable. Derivative Contracts QEP has established policies and procedures for managing commodity price volatility through the use of derivative instruments. QEP uses commodity derivative instruments, typically fixed-price swaps and costless collars to realize a known price or price range for a specific volume of production delivered into a regional sales point. QEP's commodity derivative instruments do not require the physical delivery of oil or gas between the parties at settlement. All transactions are settled in cash with one party paying the other for the net difference in prices, multiplied by the contract volume, for the settlement period. QEP does not engage in speculative hedging transactions, nor does it buy and sell energy contracts with the objective of generating profits on short-term differences in price. Additionally, QEP does not currently have any commodity derivative transactions that have margin requirements or collateral provisions that would require payments prior to the scheduled settlement dates. These derivative contracts are recorded in "Realized and unrealized gains (losses) on derivative contracts" on the Consolidated Statements of Operations in the month of settlement and are also marked-to-market monthly. Refer to Note 6 – Derivative Contracts for additional information. Credit Risk Management believes that its credit review procedures, loss reserves, cash deposits and investments, and collection procedures have adequately provided for usual and customary credit-related losses. Exposure to credit risk may be affected by extended periods of low commodity prices, as well as the concentration of customers in certain regions due to changes in economic or other conditions. Customers include commercial and industrial enterprises and financial institutions that may react differently to changing conditions. The Company utilizes various processes to monitor and evaluate its credit risk exposure, which include closely monitoring current market conditions and counterparty credit fundamentals, including public credit ratings, where available. Credit exposure is controlled through credit approvals and limits based on counterparty credit fundamentals, and is aggregated across all lines of business, including derivatives, physical exposure and short-term cash investments. To further manage the level of credit risk, the Company requests credit support and, in some cases, requests parental guarantees, letters of credit or prepayment from companies with perceived higher credit risk. Loss reserves are periodically reviewed for adequacy and may be established on a specific case basis. The Company also has master-netting agreements with some counterparties that allow the offsetting of receivables and payables in a default situation. The Company enters into International Swap Dealers Association Master Agreements (ISDA Agreements) with each of its derivative counterparties prior to executing derivative contracts. 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 counterparty to a derivative contract. The Company routinely monitors and manages its exposure to counterparty risk related to derivative contracts by requiring specific minimum credit standards for all counterparties, actively monitoring counterparties public credit ratings, and avoiding concentration of credit exposure by transacting with multiple counterparties. The Company's commodity derivative contract counterparties are typically financial institutions and energy trading firms with investment-grade credit ratings. The Company's five largest customers accounted for 59% , 48% , and 30% of QEP's revenues for the years ended December 31, 2017 , 2016 and 2015 , respectively. During the year ended December 31, 2017 , Shell Trading Company , Occidental Energy Marketing , Andeavor Logistics LP , BP Energy Company and Plains Marketing LP accounted for 14% , 13% , 13% , 10% and 10% , respectively, of QEP's total revenues. During the year ended December 31, 2016 , Shell Trading Company , BP Energy Company and Valero Marketing & Supply Company accounted for 14% , 10% and 10% , respectively, of QEP's total revenues. During the year ended December 31, 2015 , no customer accounted for 10% or more of QEP's total revenues. Management believes that the loss of any of these customers, or any other customer, would not have a material effect on the financial position or results of operations of QEP, since there are numerous potential purchasers of its production. Income Taxes The amount of income taxes recorded by QEP requires interpretations of complex rules and regulations of various tax jurisdictions throughout the United States. QEP has recognized deferred tax assets and liabilities for temporary differences, operating losses and tax credit carryforwards. Deferred income taxes are provided for the temporary differences arising between the book and tax carrying amounts of assets and liabilities. These differences create taxable or tax-deductible amounts for future periods. ASC 740, Income Taxes, specifies the accounting for uncertainty in income taxes by prescribing a minimum recognition threshold for a tax position to be reflected in the financial statements. If recognized, the tax benefit is measured as the largest amount of tax benefit that is more-likely-than-not to be realized upon ultimate settlement. Management has considered the amounts and the probabilities of the outcomes that could be realized upon ultimate settlement and believes that it is more-likely-than-not that the Company's recorded income tax benefits will be fully realized, except as noted below. As of December 31, 2017 , the Company had a valuation allowance of $56.8 million against the state net operating loss deferred tax asset because management does not forecast future income in Oklahoma and Louisiana to offset net operating losses before they expire. All federal income tax returns prior to 2017 have been examined by the Internal Revenue Service and are closed. Income tax returns for 2017 have not yet been filed. Most state tax returns for 2014 and subsequent years remain subject to examination. The benefits of uncertain tax positions taken or expected to be taken on income tax returns is recognized in the consolidated financial statements at the largest amount that is more-likely-than-not to be sustained upon examination by the relevant taxing authorities. Our policy is to recognize any interest earned on income tax refunds in "Interest and other income (expense)" on the Consolidated Statements of Operations, any interest expense related to uncertain tax positions in "Interest expense" on the Consolidated Statements of Operations and to recognize any penalties related to uncertain tax positions in "General and administrative" expense on the Consolidated Statements of Operations. As of December 31, 2017 and 2016 , QEP had $19.0 million and $15.6 million of unrecognized tax benefits related to uncertain tax positions for asset sales that occurred in 2014, which was included within "Other long-term liabilities" on the Consolidated Balance Sheets. During the year ended December 31, 2017 , the Company incurred $0.7 million of estimated interest expense related to uncertain tax positions. During the year ended December 31, 2016 , the Company incurred $0.7 million of estimated interest expense and $0.6 million of estimated penalties related to uncertain tax positions. During the year ended December 31, 2015 , the Company incurred $0.5 million of estimated interest expense and $2.2 million of estimated penalties related to uncertain tax positions. On December 22, 2017 the Tax Cuts and Jobs Act (H.R.1) (Tax Legislation) was signed into law, which resulted in significant changes to U.S. federal income tax law. QEP expects that these changes will positively impact QEP's future after-tax earnings in the U.S., primarily due to the lower federal statutory tax rate of 21% compared to 35%. The Tax Legislation also repeals the corporate alternative minimum tax (AMT). Several provisions of the new tax law such as limitations on the deductibility of interest expense and certain executive compensation and the inability to use Section 1031 like-kind exchanges for assets such as machinery and equipment could apply to QEP; however, we do not believe that they will materially impact QEP's financial statements. The impact of the Tax Legislation may differ from the statements above due to, among other things, changes in interpretations and assumptions the Company has made and actions the Company may take as a result of the Tax Legislation. Additionally, guidance issued by the relevant regulatory authorities regarding the Tax Legislation may materially impact QEP's financial statements. The Company will continue to analyze the Tax Legislation to determine the full impact of the new law, on the Company's consolidated financial statements and operations. Treasury Stock We record treasury stock purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as a reduction in shareholders' equity in the Consolidated Balance Sheets. QEP acquires treasury stock from stock forfeitures and withholdings and uses the acquired treasury stock for stock option exercises and certain stock grants to employees; refer to Note 10 – Share-Based Compensation for additional information. Earnings (Loss) Per Share Basic earnings (loss) per share (EPS) are computed by dividing net income (loss) by the weighted-average number of common shares outstanding during the reporting period. Diluted EPS includes the potential increase in the number of outstanding shares that could result from the exercise of in-the-money stock options. QEP's unvested restricted share awards are included in weighted-average basic common shares outstanding because, once the shares are granted, the restricted share awards are considered issued and outstanding, the historical forfeiture rate is minimal and the restricted share awards are eligible to receive dividends. Unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents are considered participating securities and are included in the computation of earnings (loss) per share pursuant to the two-class method. The Company's unvested restricted share awards contain non-forfeitable dividend rights and participate equally with common stock with respect to dividends issued or declared. However, the Company's unvested restricted share awards do not have a contractual obligation to share in losses of the Company. The Company's unexercised stock options do not contain rights to dividends. Under the two-class method, the earnings used to determine basic earnings (loss) per common share are reduced by an amount allocated to participating securities. When the Company records a net loss, none of the loss is allocated to the participating securities since the securities are not obligated to share in Company losses. Use of the two-class method has an insignificant impact on the calculation of basic and diluted earnings (loss) per common share. For the years ended December 31, 2017 and 2015 , there were no anti-dilutive shares. For the year ended December 31, 2016 , there were 0.1 million shares not included in diluted common shares outstanding as they were anti-dilutive due to QEP's net loss from continuing operations. The following is a reconciliation of the components of basic and diluted shares used in the EPS calculation: December 31, 2017 2016 2015 (in millions) Weighted-average basic common shares outstanding 240.6 221.7 176.6 Potential number of shares issuable upon exercise of in-the-money stock options under the Long-Term Stock Incentive Plan — — — Average diluted common shares outstanding 240.6 221.7 176.6 Share-Based Compensation QEP issues stock options, restricted share awards and restricted share units to certain officers, employees and non-employee directors under its Long-Term Stock Incentive Plan (LTSIP). QEP uses the Black-Scholes-Merton mathematical model to estimate the fair value of stock options for accounting purposes. The grant date fair value for restricted share awards is determined based on the closing bid price of the Company's common stock on the grant date. Share-based compensation cost for restricted share units is equal to its fair value as of the end of the period and is classified as a liability. QEP uses an accelerated method in recognizing share-based compensation costs for stock options and restricted share awards with graded-vesting periods. Stock options held by employees generally vest in three equal, annual installments and primarily have a term of seven years. Restricted share awards and restricted share units vest in equal installments over a specified number of years after the grant date with the majority vesting in three years. Non-vested restricted share awards have voting and dividend rights; however, sale or transfer is restricted. Employees may elect to defer their grants of restricted share awards and these deferred awards are designated as restricted share units. Restricted share units vest over a three-year |
Acquisitions and Divestitures
Acquisitions and Divestitures | 12 Months Ended |
Dec. 31, 2017 | |
Business Combinations [Abstract] | |
Acquisitions and divestitures [Text Block] | 2017 Permian Basin Acquisition In the fourth quarter of 2017, QEP acquired additional oil and gas properties in the Permian Basin for an aggregate purchase price of $720.7 million , subject to post-closing purchase price adjustments (the 2017 Permian Basin Acquisition). The 2017 Permian Basin Acquisition consists of approximately 15,100 acres, mainly in Martin County, Texas, which are held by production from existing vertical wells. QEP structured the transaction as a like-kind exchange under Section 1031 of the Internal Revenue Service Code and funded the purchase price with the proceeds from the Pinedale Divestiture. In accordance with the early adoption of ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the definition of a business in the fourth quarter of 2017 , the 2017 Permian Basin Acquisition meets the definition of an asset acquisition because substantially all of the total fair value acquired relates to undeveloped leaseholds which do not have outputs. In addition, QEP has made offers to various persons who own additional oil and gas interests in certain properties included in the 2017 Permian Basin Acquisition on substantially the same terms and conditions as the original purchase. If all offers are accepted, the aggregate purchase price is not expected to exceed $50.0 million . 2016 Permian Basin Acquisition In October 2016, QEP acquired oil and gas properties in the Permian Basin for an aggregate purchase price of approximately $591.0 million (the 2016 Permian Basin Acquisition). The 2016 Permian Basin Acquisition consists of approximately 9,600 net acres in Martin County, Texas, which are primarily held by production from existing vertical wells. The 2016 Permian Basin Acquisition was funded with cash on hand, which included proceeds from an equity offering in June 2016. The 2016 Permian Basin Acquisition meets the definition of a business combination under ASC 805, Business Combinations , as it included significant proved properties. QEP allocated the cost of the 2016 Permian Basin Acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. Revenues of $80.2 million and a net income of $221.4 million were generated from the acquired properties for the year ended December 31, 2017 . Revenues of $3.8 million and a net loss of $0.7 million were generated from the acquired properties from October 19, 2016 to December 31, 2016. The revenue and net income (loss) are included in QEP's Consolidated Statements of Operations. During the year ended December 31, 2016 , QEP incurred acquisition-related costs of $2.3 million , which are included in "General and administrative" expense on the Consolidated Statements of Operations. In conjunction with the 2016 Permian Basin Acquisition, the Company recorded a $17.8 million bargain purchase gain. The acquisition resulted in a bargain purchase gain primarily as a result of an increase in future oil prices from the execution of the purchase and sale agreement to the closing date of the acquisition. The bargain purchase gain is reported on the Consolidated Statements of Operations within "Interest and other income (expense)". The following table presents a summary of the Company's purchase accounting entries (in millions) as of December 31, 2017 : Consideration: Total consideration $ 591.0 Amounts recognized for fair value of assets acquired and liabilities assumed: Proved properties $ 406.2 Unproved properties 214.2 Asset retirement obligations (11.6 ) Bargain purchase gain (17.8 ) Total fair value $ 591.0 The following unaudited, pro forma results of operations are provided for the year ended December 31, 2016 . Pro forma results are not provided for the year ended December 31, 2017 , because the 2016 Permian Basin Acquisition occurred during the fourth quarter of 2016; and therefore, the results are included in QEP's results of operations for the year ended December 31, 2017 . The supplemental pro forma results of operations are provided for illustrative purposes only and may not be indicative of the actual results that would have been achieved by the acquired properties for the periods presented, or that may be achieved by such properties in the future. Future results may vary significantly from the results reflected in this pro forma financial information because of future events and transactions, as well as other factors. The pro forma information is based on QEP's consolidated results of operations for the year ended December 31, 2016 , the acquired properties' historical results of operations and estimates of the effect of the transaction on the combined results. The pro forma results of operations have been prepared by adjusting, and quantifying, the historical results of QEP to include the historical results of the acquired properties based on information provided by the seller and the impact of the purchase price allocation. The pro forma results of operations do not include any cost savings or other synergies that may result from the 2016 Permian Basin Acquisition or any estimated costs that have been or will be incurred by the Company to integrate the acquired properties. Year ended December 31, 2016 Actual Pro forma (in millions, except per share amounts) Revenues $ 1,377.1 $ 1,392.5 Net income (loss) $ (1,245.0 ) $ (1,246.8 ) Earnings (loss) per common share Basic $ (5.62 ) $ (5.62 ) Diluted $ (5.62 ) $ (5.62 ) Other Acquisitions In addition to the 2017 Permian Basin Acquisition, QEP acquired various oil and gas properties in 2017, which primarily included undeveloped leasehold acreage, producing wells and additional surface acreage in the Permian Basin, for an aggregate purchase price of $94.5 million , subject to customary post-closing purchase price adjustments. In conjunction with the acquisitions, the Company recorded $5.3 million of goodwill, which was subsequently impaired. In addition to the 2016 Permian Basin Acquisition, QEP acquired various oil and gas properties in 2016, primarily in the Permian and Williston basins, for an aggregate purchase price of $54.6 million , which included acquisitions of additional interests in QEP operated wells and additional undeveloped leasehold acreage. In conjunction with the acquisitions, the Company recorded $3.7 million of goodwill, which was subsequently impaired, and a $4.4 million bargain purchase gain. The bargain purchase gain is reported on the Consolidated Statements of Operations within "Interest and other income (expense)". During the year ended December 31, 2015 , QEP acquired various oil and gas properties, primarily in the Williston and Permian basins, for a total purchase price of $98.3 million , which included acquisitions of additional interests in QEP operated wells and additional undeveloped leasehold acreage. In conjunction with the acquisitions, the Company recorded $14.3 million of goodwill, which was subsequently impaired. Pinedale Divestiture In September 2017, QEP sold its Pinedale assets (the Pinedale Divestiture), for net cash proceeds (after purchase price adjustments) of $718.2 million , subject to post-closing purchase price adjustments, and recorded a pre-tax gain on sale of $180.4 million which was recorded within "Net gain (loss) from asset sales" on the Consolidated Statements of Operations. As part of the purchase and sale agreement, at the request of the buyer, QEP agreed to enter into derivative contracts covering a portion of Pinedale's future production. Those derivative contracts were novated to the buyer at closing. In addition, QEP agreed to reimburse the buyer for certain deficiency charges it incurs related to gas processing and NGL transportation and fractionation contracts, if any, between the effective date of the sale and December 31, 2019, in an aggregate amount not to exceed $45.0 million . The fair value of the deficiency charges was measured utilizing an internally developed cash flow model discounted at QEP's weighted average cost of debt. Given the unobservable nature of the inputs, the fair value calculation associated with the deficiency charges is considered Level 3 within the fair value hierarchy . As of December 31, 2017 , the liability associated with estimated future payments for this commitment was $30.6 million , of which $27.4 million is reported on the Consolidated Balance Sheets within "Accounts payable and accrued expenses" and $3.2 million is reported on the Consolidated Balance Sheets within "Other long-term liabilities". QEP accounted for revenues and expenses related to Pinedale, including the pre-tax gain on sale of $180.4 million , during the years ended December 31, 2017 , 2016 and 2015 , as income on the Consolidated Statements of Operations because the sale of the Pinedale assets did not cause a strategic shift for the Company and as a result, did not qualify as discontinued operations under ASU 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity . The Pinedale Divestiture did, however, represent the sale of an individually significant component. For the year ended December 31, 2017 , QEP recorded net income before income taxes related to Pinedale, prior to the divestiture, of $251.0 million , which includes the pre-tax gain on sale of $180.4 million . For the year ended December 31, 2016 , QEP recorded a net loss before income taxes of $1,152.7 million . The net loss before income taxes was primarily due to an impairment on proved properties of $1,164.0 million recognized in 2016 as a result of a decrease in expected future gas prices. For the year ended December 31, 2015 , QEP recorded net loss before income taxes of $45.6 million related to Pinedale. Other Divestitures In addition to the Pinedale Divestiture, during the year ended December 31, 2017 , QEP also sold its Central Basin Platform assets (Central Basin Platform Divestiture) and received net cash proceeds of $3.5 million . Refer to Note 3 – Capitalized Exploratory Well Costs for more information. In addition, QEP received net cash proceeds of $85.1 million and recorded a pre-tax gain on sale of $33.1 million , primarily related to the sale of properties in the Other Northern area. During the year ended December 31, 2016 , QEP sold its interest in certain non-core properties, primarily in the Other Southern area for aggregate proceeds of $29.0 million and recorded a pre-tax gain on sale of $8.6 million . During the year ended December 31, 2015 , QEP sold its interest in certain non-core properties in the Other Southern area for aggregate proceeds of $31.7 million , of which $21.8 million was cash and $9.9 million of accounts receivable and recorded a pre-tax gain on sale of $21.0 million . During the year ended December 31, 2016 , QEP recorded a pre-tax loss of sale of $0.9 million , due to post-closing purchase price adjustments from the sale of such properties. These gains and losses are reported on the Consolidated Statements of Operations within "Net gain (loss) from asset sales". |
Capitalized Exploratory Well Co
Capitalized Exploratory Well Costs | 12 Months Ended |
Dec. 31, 2017 | |
Capitalized Exploratory Well Costs [Abstract] | |
Suspended Well Costs Disclosure [Text Block] | Net changes in capitalized exploratory well costs are presented in the table below. Capitalized Exploratory Well Costs 2017 2016 2015 (in millions) Balance at January 1, $ 14.2 $ 2.6 $ 12.6 Additions to capitalized exploratory well costs 10.7 11.7 6.0 Reclassifications to proved properties (3.6 ) — (16.0 ) Capitalized exploratory well costs charged to expense (21.3 ) (0.1 ) — Balance at December 31, $ — $ 14.2 $ 2.6 The balance at December 31, 2016 and 2015 represents the amount of capitalized exploratory well costs that are pending the determination of proved reserves. During the years ended December 31, 2017 and 2016 , QEP's exploratory well activity was related to the Central Basin Platform exploration project in the Permian Basin targeting the Woodford Formation. QEP completed a second exploratory well related to this project in the first half of 2017. During the year ended December 31, 2017, based on the performance of the two exploratory wells that were drilled and the analysis of the ultimate economic feasibility of this exploration project, QEP determined it would no longer pursue the development of the Central Basin Platform exploration project and would seek to monetize the assets. QEP charged $21.3 million of exploratory well costs to exploration expense. In conjunction with the expensing of the exploratory well costs, QEP charged $28.3 million of the associated unproved leasehold acreage in the Central Basin Platform to impairment expense during the year ended December 31, 2017 . QEP wrote down the Central Basin Platform assets to their fair market value of $3.6 million and reclassified the assets to proved properties. During the fourth quarter of 2017, QEP closed on the Central Basin Platform Divestiture for net cash proceeds of $3.5 million . |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2017 | |
Asset Retirement Obligation [Abstract] | |
Asset Retirement Obligations | QEP records ARO associated with the retirement of tangible, long-lived assets. The Company's ARO liability applies primarily to abandonment costs associated with oil and gas wells and certain other properties. The fair values of such costs are estimated by Company personnel based on abandonment costs of similar assets and depreciated over the life of the related assets. Revisions to the ARO estimates result from changes in expected cash flows or material changes in estimated asset retirement costs. The ARO liability is adjusted to present value each period through an accretion calculation using a credit-adjusted risk-free interest rate. Of the $214.1 million and $231.6 million ARO liability as of December 31, 2017 and 2016 , respectively, $7.5 million and $5.8 million , respectively, was included as a liability in "Accounts payable and accrued expenses" on the Consolidated Balance Sheets. The following is a reconciliation of the changes in the Company's ARO for the periods specified below: Asset Retirement Obligations 2017 2016 (in millions) ARO liability at January 1, $ 231.6 $ 206.8 Accretion 7.7 8.9 Additions (1) 23.5 17.0 Revisions 8.5 6.5 Liabilities related to assets sold (2) (34.9 ) — Liabilities settled (22.3 ) (7.6 ) ARO liability at December 31, $ 214.1 $ 231.6 ___________________________ (1) Additions for the year ended December 31, 2017 , include $14.2 million related to the 2017 Permian Basin Acquisition and additions for the year ended December 31, 2016 , include $11.6 million related to the 2016 Permian Basin Acquisition (refer to Note 2 – Acquisitions and Divestitures for more information). (2) Liabilities related to assets sold for the year ended December 31, 2017 , include $34.9 million related to the Pinedale Divestiture (refer to Note 2 – Acquisitions and Divestitures for more information). |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2017 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | QEP measures and discloses fair values in accordance with the provisions of ASC 820, Fair Value Measurements and Disclosures . This guidance defines fair value in applying GAAP, establishes a framework for measuring fair value and expands disclosures about fair value measurements. ASC 820 also establishes a fair value hierarchy. Level 1 inputs are quoted prices (unadjusted) for identical assets or liabilities in active markets that the Company has the ability to access at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability. QEP has determined that its commodity derivative instruments are Level 2. The Level 2 fair value of commodity derivative contracts (refer to Note 6 – Derivative Contracts for additional information) is based on market prices posted on the respective commodity exchange on the last trading day of the reporting period and industry standard discounted cash flow models. QEP primarily applies the market approach for recurring fair value measurements and maximizes its use of observable inputs and minimizes its use of unobservable inputs. QEP considers bid and ask prices for valuing the majority of its assets and liabilities measured and reported at fair value. In addition to using market data, QEP makes assumptions in valuing its assets and liabilities, including assumptions about risk and the risks inherent in the inputs to the valuation technique. The Company's policy is to recognize significant transfers between levels at the end of the reporting period. Certain of the Company's commodity derivative instruments are valued using industry standard models that consider various inputs, including quoted forward prices for commodities, time value, volatility, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable prices at which transactions are executed in the marketplace. The determination of fair value for derivative assets and liabilities also incorporates nonperformance risk for counterparties and for QEP. Derivative contract fair values are reported on a net basis to the extent a legal right of offset with the counterparty exists. The fair value of financial assets and liabilities at December 31, 2017 and 2016 , is shown in the table below: Fair Value Measurements Gross Amounts of Assets and Liabilities Netting Adjustments (1) Net Amounts Presented on the Consolidated Balance Sheets Level 1 Level 2 Level 3 (in millions) December 31, 2017 Financial Assets Fair value of derivative contracts – short-term $ — $ 20.6 $ — $ (17.2 ) $ 3.4 Fair value of derivative contracts – long-term — 2.3 — (2.2 ) 0.1 Total financial assets $ — $ 22.9 $ — $ (19.4 ) $ 3.5 Financial Liabilities Fair value of derivative contracts – short-term $ — $ 120.8 $ — $ (17.2 ) $ 103.6 Fair value of derivative contracts – long-term — 34.0 — (2.2 ) 31.8 Total financial liabilities $ — $ 154.8 $ — $ (19.4 ) $ 135.4 December 31, 2016 Financial Assets Fair value of derivative contracts – short-term $ — $ — $ — $ — $ — Fair value of derivative contracts – long-term — — — — — Total financial assets $ — $ — $ — $ — $ — Financial Liabilities Fair value of derivative contracts – short-term $ — $ 169.8 $ — $ — $ 169.8 Fair value of derivative contracts – long-term — 32.0 — — 32.0 Total financial liabilities $ — $ 201.8 $ — $ — $ 201.8 ____________________________ (1) The Company nets its derivative contract assets and liabilities outstanding with the same counterparty on the Consolidated Balance Sheets for the contracts that contain netting provisions. Refer to Note 6 – Derivative Contracts for additional information regarding the Company's derivative contracts. The following table discloses the fair value and related carrying amount of certain financial instruments not disclosed in other Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K: Carrying Amount Level 1 Fair Value Carrying Amount Level 1 Fair Value December 31, 2017 December 31, 2016 Financial Assets (in millions) Cash and cash equivalents $ — $ — $ 443.8 $ 443.8 Financial Liabilities Checks outstanding in excess of cash balances $ 44.0 $ 44.0 $ 12.3 $ 12.3 Long-term debt $ 2,160.8 $ 2,256.2 $ 2,020.9 $ 2,104.3 The carrying amounts of cash and cash equivalents and checks outstanding in excess of cash balances approximate fair value. The fair value of fixed-rate long-term debt is based on the trading levels and dollar prices for the Company's debt at the end of the year. The carrying amount of variable-rate long-term debt approximates fair value because the floating interest rate paid on such debt was set for periods of one month. The initial measurement of ARO at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with property, plant and equipment. Significant Level 3 inputs used in the calculation of ARO include plugging costs and reserve lives. A reconciliation of the Company's ARO is presented in Note 4 – Asset Retirement Obligations . Nonrecurring Fair Value Measurements The provisions of the fair value measurement standard are also applied to the Company's nonrecurring measurements. The Company utilizes fair value on a nonrecurring basis to review its proved oil and gas properties for potential impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such property. During the years ended December 31, 2017 and 2016 , the Company recorded impairments of certain proved oil and gas properties of $38.1 million and $1,172.7 million , respectively, resulting in a reduction of the associated carrying value to fair value. The fair value of the property was measured utilizing the income approach and utilizing inputs which are primarily based upon internally developed cash flow models discounted at an appropriate weighted average cost of capital. Given the unobservable nature of the inputs, fair value calculations associated with proved oil and gas property impairments are considered Level 3 within the fair value hierarchy. Refer to Note 1 – Summary of Significant Accounting Policies for additional information on impairment of oil and gas properties. Acquisitions of proved and unproved properties are also measured at fair value on a nonrecurring basis. The Company utilizes a discounted cash flow model to estimate the fair value of acquired property as of the acquisition date which utilizes the following inputs to estimate future net cash flows: (i) estimated quantities of oil, gas and NGL reserves; (ii) estimates of future commodity prices; and (iii) estimated production rates, future operating and development costs, which are based on the Company's historic experience with similar properties. In some instances, market comparable information of recent transactions is used to estimate fair value of unproved acreage. Due to the unobservable characteristics of the inputs, the fair value of the acquired properties is considered Level 3 within the fair value hierarchy. Refer to Note 2 – Acquisitions and Divestitures for additional information on the fair value of acquired properties. |
Derivative Contracts
Derivative Contracts | 12 Months Ended |
Dec. 31, 2017 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative Contracts | QEP has established policies and procedures for managing commodity price volatility through the use of derivative instruments. In the normal course of business, QEP uses commodity price derivative instruments to reduce the impact of potential downward movements in commodity prices on cash flow, returns on capital investment, and other financial results. However, these instruments typically limit gains from favorable price movements. The volume of production subject to commodity derivative instruments and the mix of the instruments are frequently evaluated and adjusted by management in response to changing market conditions. QEP may enter into commodity derivative contracts for up to 100% of forecasted production, but generally, QEP enters into commodity derivative contracts for approximately 50% to 75% of its forecasted annual production by the end of the first quarter of each fiscal year. In addition, QEP may enter into commodity derivative contracts on a portion of its storage transactions. QEP does not enter into commodity derivative contracts for speculative purposes. QEP uses commodity derivative instruments known as fixed-price swaps or costless collars to realize a known price or price range for a specific volume of production delivered into a regional sales point. QEP's commodity derivative instruments do not require the physical delivery of oil or gas between the parties at settlement. All transactions are settled in cash with one party paying the other for the net difference in prices, multiplied by the contract volume, for the settlement period. Oil price derivative instruments are typically structured as NYMEX fixed-price swaps based at Cushing, Oklahoma or oil price swaps that use ICE Brent oil prices as the reference price. Gas price derivative instruments are typically structured as fixed-price swaps or costless collars at NYMEX Henry Hub or regional price indices. QEP also enters into oil and gas basis swaps to achieve a fixed-price swap for a portion of its oil and gas sales at prices that reference specific regional index prices. QEP does not currently have any commodity derivative transactions that have margin requirements or collateral provisions that would require payments prior to the scheduled settlement dates. QEP's commodity derivative contract counterparties are typically financial institutions and energy trading firms with investment-grade credit ratings. QEP routinely monitors and manages its exposure to counterparty risk by requiring specific minimum credit standards for all counterparties, actively monitoring counterparties public credit ratings and avoiding the concentration of credit exposure by transacting with multiple counterparties. The Company has master-netting agreements with some counterparties that allow the offsetting of receivables and payables in a default situation. Derivative Contracts – Production The following table presents QEP's volumes and average prices for its commodity derivative swap contracts as of December 31, 2017 : Year Index Total Volumes Average Swap Price per Unit (in millions) Oil sales (bbls) ($/bbl) 2018 NYMEX WTI 16.8 $ 52.48 2019 NYMEX WTI 8.0 $ 51.78 Gas sales (MMBtu) ($/MMBtu) 2018 (Full Year) NYMEX HH 109.5 $ 2.99 2018 (July through December) NYMEX HH 1.8 $ 3.01 2019 NYMEX HH 36.5 $ 2.88 QEP uses oil and gas basis swaps, combined with NYMEX WTI and NYMEX HH fixed price swaps, to achieve fixed price swaps for the location at which it sells its physical production. The following table presents details of QEP's oil and gas basis swaps as of December 31, 2017 : Year Index Less Differential Index Total Volumes Weighted-Average Differential (in millions) Oil sales (bbls) ($/bbl) 2018 (Full Year) NYMEX WTI Argus WTI Midland 7.3 $ (1.06 ) 2018 (July through December) NYMEX WTI Argus WTI Midland 0.9 $ (0.71 ) 2019 NYMEX WTI Argus WTI Midland 4.0 $ (0.80 ) Gas sales (MMBtu) ($/MMBtu) 2018 NYMEX HH IFNPCR 7.3 $ (0.16 ) Derivative Contracts – Gas Storage QEP enters into commodity derivative transactions to lock in a margin on gas volumes placed into storage. The following table presents QEP's volumes and average prices for its gas storage commodity derivative swap contracts as of December 31, 2017 : Year Type of Contract Index Total Volumes Average Swap Price per Unit (in millions) Gas sales (MMBtu) ($/MMBtu) 2018 SWAP IFNPCR 0.6 $ 3.06 QEP Derivative Financial Statement Presentation The following table identifies the Consolidated Balance Sheets location of QEP's outstanding derivative contracts on a gross contract basis as opposed to the net contract basis presentation on the Consolidated Balance Sheets and the related fair values at the balance sheet dates: Gross asset derivative Gross liability derivative December 31, Balance Sheet line item 2017 2016 2017 2016 Current: (in millions) Commodity Fair value of derivative contracts $ 20.6 $ — $ 120.8 $ 169.8 Long-term: Commodity Fair value of derivative contracts 2.3 — 34.0 32.0 Total derivative instruments $ 22.9 $ — $ 154.8 $ 201.8 The effects of the change in fair value and settlement of QEP's derivative contracts recorded in "Realized and unrealized gains (losses) on derivative contracts" on the Consolidated Statements of Operations are summarized in the following table: Derivative contracts not designated as cash flow hedges Year Ended December 31, 2017 2016 2015 Realized gains (losses) on commodity derivative contracts (in millions) Production Oil derivative contracts $ 6.8 $ 86.3 $ 353.7 Gas derivative contracts (22.3 ) 44.8 103.4 Gas Storage Gas derivative contracts — 2.9 3.8 Realized gains (losses) on commodity derivative contracts (15.5 ) 134.0 460.9 Unrealized gains (losses) on commodity derivative contracts Production Oil derivative contracts (66.2 ) (217.2 ) (244.9 ) Gas derivative contracts 133.6 (145.4 ) 62.0 Gas Storage Gas derivative contracts 2.5 (4.4 ) (0.8 ) Unrealized gains (losses) on commodity derivative contracts 69.9 (367.0 ) (183.7 ) Total realized and unrealized gains (losses) on commodity derivative contracts related to production and storage contracts $ 54.4 $ (233.0 ) $ 277.2 Derivatives associated with the Pinedale Divestiture (1) Unrealized gains (losses) on commodity derivative contracts Production Oil derivative contracts $ (1.3 ) $ — $ — Gas derivative contracts (23.5 ) — — NGL derivative contracts (5.1 ) — — Unrealized gains (losses) on commodity derivative contracts related to the Pinedale Divestiture $ (29.9 ) $ — $ — Total realized and unrealized gains (losses) on commodity derivative contracts $ 24.5 $ (233.0 ) $ 277.2 _______________________ (1) The unrealized gains (losses) on commodity derivative contracts related to the Pinedale Divestiture are comprised of derivatives entered into in conjunction with the execution of the Pinedale purchase and sale agreement, which were subsequently novated to the buyer upon the closing of the sale in September 2017. Refer to Note 2 – Acquisitions and Divestitures for more information. The unrealized gains (losses) on commodity derivatives associated with the Pinedale Divestiture are offset by an equal amount recorded within "Net gain (loss) from asset sales" on the Consolidated Statements of Operations. |
Restructuring Costs
Restructuring Costs | 12 Months Ended |
Dec. 31, 2017 | |
Restructuring and Related Activities [Abstract] | |
Restructuring Costs | In April 2016, the Company streamlined its organizational structure, resulting in a reduction of approximately 6% of its total workforce. The total costs related to the 2016 restructuring were approximately $1.9 million and were related to one-time termination benefits. During the year ended December 31, 2016 , restructuring costs of $1.9 million were incurred and paid related to the 2016 restructuring. The Company did not incur additional costs related to the 2016 restructuring in 2017. During 2015, QEP had multiple restructuring events, including the closure of its Tulsa office, which occurred in the third quarter of 2015. The total costs related to the 2015 restructuring events were approximately $8.3 million , of which approximately $5.3 million was related to one-time termination benefits and approximately $3.0 million was related to relocation of certain employees. During the year ended December 31, 2016 , restructuring costs of $0.6 million were incurred and paid related to the Tulsa office closure, all of which were related to the relocation of certain employees. The Company did not incur additional costs related to the closure of its Tulsa office. All restructuring costs were recorded within "General and administrative" expense on the Consolidated Statements of Operations. |
Debt
Debt | 12 Months Ended |
Dec. 31, 2017 | |
Debt Disclosure [Abstract] | |
Debt | As of the indicated dates, the principal amount of QEP's debt consisted of the following: December 31, 2017 2016 (in millions) Revolving Credit Facility due 2022 $ 89.0 $ — 6.80% Senior Notes due 2018 (1) — 134.0 6.80% Senior Notes due 2020 (1) 51.7 136.0 6.875% Senior Notes due 2021 (1) 397.6 625.0 5.375% Senior Notes due 2022 500.0 500.0 5.25% Senior Notes due 2023 650.0 650.0 5.625% Senior Notes due 2026 (1) 500.0 — Less: unamortized discount and unamortized debt issuance costs (27.5 ) (24.1 ) Total long-term debt outstanding $ 2,160.8 $ 2,020.9 _______________________ (1) During the quarter ended December 31, 2017 , the Company issued $500.0 million of 5.625% Senior Notes due in 2026. The Company used the majority of the proceeds from the offering to redeem all of its outstanding 6.80% Senior Notes due in 2018 and fund tender offers for $84.3 million of 6.80% Senior Notes due in 2020 and $227.4 million of its outstanding 6.875% Senior Notes due in 2021. The Company recorded a $32.7 million loss from early extinguishment of debt related to the redemption and tender offers. Of the total debt outstanding on December 31, 2017 , the 6.80% Senior Notes due March 1, 2020 , the 6.875% Senior Notes due March 1, 2021 and the 5.375% Senior Notes due October 1, 2022 , will mature within the next five years. In addition, the revolving credit facility matures on September 1, 2022 . Credit Facility In November 2017, QEP entered into the Seventh Amendment to its Credit Agreement, which, among other things, reduced the aggregate principal amount of commitments to $1.25 billion and extended the maturity date, subject to satisfaction of certain conditions, to September 1, 2022. The credit facility provides for borrowings at short-term interest rates and contains customary covenants and restrictions. The amended credit agreement contains financial covenants (that are defined in the credit agreement) that limit the amount of debt the Company can incur and may limit the amount available to be drawn under the credit facility including: (i) a net funded debt to capitalization ratio that may not exceed 60%, (ii) a leverage ratio under which net funded debt may not exceed 4.25 times consolidated EBITDA (as defined in the credit agreement) for the fiscal quarter ending December 31, 2017, 4.00 times commencing with the fiscal quarter ending March 31, 2018, through the fiscal quarter ending December 31, 2018, and 3.75 times thereafter, and (iii) during a ratings trigger period (as defined), a present value coverage ratio under which the present value of the Company's proved reserves must exceed net funded debt by 1.25 times at any time prior to January 1, 2019, must exceed net funded debt by 1.40 times commencing on January 1, 2019, through December 31, 2019, and must exceed net funded debt by 1.50 times at any time on or after January 1, 2020. The company is currently not subject to the present value coverage ratio. As of December 31, 2017 and 2016 , QEP was in compliance with the covenants under the credit agreement. During the year ended December 31, 2017 , QEP's weighted-average interest rates on borrowings from its credit facility were 3.52% . As of December 31, 2017 , QEP had $89.0 million of borrowings outstanding and $1.0 million in letters of credit outstanding under the credit facility. As of December 31, 2016 , QEP had no borrowings outstanding and $2.8 million in letters of credit outstanding under the credit facility. Senior Notes At December 31, 2017 , the Company had $2,099.3 million principal amount of senior notes outstanding with maturities ranging from March 2020 to March 2026 and coupons ranging from 5.25% to 6.875% . The senior notes pay interest semi-annually, are unsecured senior obligations and rank equally with all of our other existing and future unsecured and senior obligations. QEP may redeem some or all of its senior notes at any time before their maturity at a redemption price based on a make-whole amount plus accrued and unpaid interest to the date of redemption. The indentures governing QEP's senior notes contain customary events of default and covenants that may limit QEP's ability to, among other things, place liens on its property or assets. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Contingencies | The Company is involved in various commercial and regulatory claims, litigation and other legal proceedings that arise in the ordinary course of its business. In each reporting period, the Company assesses these claims in an effort to determine the degree of probability and range of possible loss for potential accrual in its Consolidated Financial Statements. In accordance with ASC 450, Contingencies , an accrual is recorded for a material loss contingency when its occurrence is probable and damages are reasonably estimable based on the anticipated most likely outcome or the minimum amount within a range of possible outcomes. Legal proceedings are inherently unpredictable and unfavorable resolutions can occur. Assessing contingencies is highly subjective and requires judgment about uncertain future events. When evaluating contingencies related to legal proceedings, the Company may be unable to estimate losses due to a number of factors, including potential defenses, the procedural status of the matter in question, the presence of complex legal and/or factual issues, the ongoing discovery and/or development of information important to the matter. Litigation Landowner Litigation – In October, 2017, the owners of certain surface and mineral interests in Martin and Andrews County, Texas filed suit against QEP, alleging QEP improperly used the surface of the properties and failed to correctly pay royalties, and are seeking money damages and a declaratory judgment that portions of the oil and gas leases covering the properties are no longer in effect. The Company continues to evaluate the allegations and its defenses. The Company is unable to make an estimate of the reasonably possible loss at this early stage. Commitments QEP has contracted for gathering, processing, firm transportation and storage services with various third parties. Market conditions, drilling activity and competition may prevent full utilization of the contractual capacity. In addition, QEP has contracts with third parties who provide drilling services. Annual payments and the corresponding years for gathering, processing, transportation, storage, drilling, and fractionation contracts are as follows (in millions): Year Amount 2018 $ 95.6 2019 $ 68.4 2020 $ 54.9 2021 $ 29.9 2022 $ 28.3 After 2022 $ 122.5 QEP rents office space throughout its scope of operations from third-party lessors. Rental expense from operating leases amounted to $9.6 million , $9.1 million , and $8.0 million during the years ended December 31, 2017 , 2016 and 2015 , respectively. Minimum future payments under the terms of long-term operating leases for the Company's primary office locations are as follows (in millions): Year Amount 2018 $ 7.0 2019 $ 7.2 2020 $ 7.4 2021 $ 7.4 2022 $ 7.2 After 2022 $ 4.8 |
Share-Based Compensation
Share-Based Compensation | 12 Months Ended |
Dec. 31, 2017 | |
Share-based Compensation [Abstract] | |
Share-Based Compensation | QEP issues stock options, restricted share awards and restricted share units under its LTSIP and awards performance share units under its CIP to certain officers, employees, and non-employee directors. QEP recognizes expense over the vesting periods for the stock options, restricted share awards, restricted share units and performance share units. There were 5.0 million shares available for future grants under the LTSIP at December 31, 2017 . Share-based compensation expense related to continuing operations is recognized within "General and administrative" expense on the Consolidated Statements of Operations and is summarized in the table below. Year Ended December 31, 2017 2016 2015 (in millions) Stock options $ 2.3 $ 2.3 $ 2.9 Restricted share awards 24.6 23.7 25.6 Performance share units (4.5 ) 9.4 6.2 Restricted share units — 0.2 — Total share-based compensation expense $ 22.4 $ 35.6 $ 34.7 Stock Options QEP uses the Black-Scholes-Merton mathematical model to estimate the fair value of stock option awards at the date of grant. Fair value calculations rely upon subjective assumptions used in the mathematical model and may not be representative of future results. The Black-Scholes-Merton model is intended for calculating the value of options not traded on an exchange. The Company utilizes the "simplified" method to estimate the expected term of the stock options granted as there is limited historical exercise data available in estimating the expected term of the stock options. QEP uses a historical volatility method to estimate the fair value of stock options awards and the risk-free interest rate is based on the yield on U.S. Treasury strips with maturities similar to those of the expected term of the stock options. The stock options typically vest in equal installments over a three-year period from the grant date and are exercisable immediately upon vesting through the seventh anniversary of the grant date. To fulfill options exercised, QEP either reissues treasury stock or issues new shares. The Company expenses forfeitures of stock options as they occur. The calculated fair value of options granted and major assumptions used in the model at the date of grant are listed below: Stock Option Assumptions Year Ended December 31, 2017 2016 2015 Weighted-average grant date fair value of awards granted during the period $ 6.44 $ 3.77 $ 6.82 Risk-free interest rate range 1.66% - 1.81% 0.99% - 1.15% 1.38% - 1.38% Weighted-average risk-free interest rate 1.8 % 1.2 % 1.4 % Expected price volatility range 43.82% - 46.70% 43.42% - 43.66% 36.8% - 36.8% Weighted-average expected price volatility 43.9 % 43.4 % 36.8 % Expected dividend yield — % — % 0.37 % Expected term in years at the date of grant 4.5 4.5 4.5 Stock option transactions under the terms of the LTSIP are summarized below: Options Outstanding Weighted-Average Exercise Price Weighted-Average Remaining Contractual Term Aggregate Intrinsic Value (per share) (in years) (in millions) Outstanding at December 31, 2016 2,151,957 $ 25.26 Granted 418,752 16.77 Forfeited (14,172 ) 15.33 Cancelled (202,260 ) 27.55 Outstanding at December 31, 2017 2,354,277 $ 23.62 3.50 $ — Options Exercisable at December 31, 2017 1,551,861 $ 27.90 2.47 $ — Unvested Options at December 31, 2017 802,416 $ 15.33 5.48 $ — During the years ended December 31, 2017 and 2016 , there were no exercises of stock options. The total intrinsic value (the difference between the market price at the exercise date and the exercise price) of options exercised was $0.1 million during the year ended December 31, 2015 . There was no income tax impact for the year ended December 31, 2017 . The Company realized an income tax benefit of $0.2 million for the year ended December 31, 2016 and $6.4 million of income tax expense for the year ended December 31, 2015 . As of December 31, 2017 , $1.6 million of unrecognized compensation cost related to stock options granted under the LTSIP is expected to be recognized over a weighted-average period of 2.04 years. Restricted Share Awards Restricted share award grants typically vest in equal installments over a three -year period from the grant date. The grant date fair value is determined based on the closing bid price of the Company's common stock on the grant date. The Company expenses forfeitures of restricted share awards as they occur. The total fair value of restricted share awards that vested during the years ended December 31, 2017 , 2016 and 2015 , was $18.4 million , $24.3 million and $22.7 million , respectively. There was no income tax impact for the year ended December 31, 2017 and 2016 . The Company realized an income tax benefit of $3.2 million for the year ended December 31, 2015 . The weighted-average grant date fair value of restricted share awards granted was $13.90 per share, $10.50 per share and $20.92 per share for the years ended December 31, 2017 , 2016 and 2015 , respectively. As of December 31, 2017 , $19.2 million of unrecognized compensation cost related to restricted share awards granted under the LTSIP is expected to be recognized over a weighted-average vesting period of 1.99 years. Transactions involving restricted share awards under the terms of the LTSIP are summarized below: Restricted Share Awards Outstanding Weighted-Average Grant Date Fair Value (per share) Unvested balance at December 31, 2016 3,208,503 $ 14.32 Granted 2,219,763 13.90 Vested (1,392,043 ) 16.53 Forfeited (314,889 ) 14.49 Unvested balance at December 31, 2017 3,721,334 $ 13.23 Performance Share Units The payouts for performance share units are dependent upon the Company's total shareholder return compared to a group of its peers over a three-year period. The awards are denominated in share units and have historically been paid in cash. Beginning with awards granted in 2015, the Company has the option to settle earned awards in cash or shares of common stock under the Company's LTSIP; however, as of December 31, 2017 , the Company expects to settle all awards in cash. These awards are classified as liabilities and are included within "Other long-term liabilities" on the Consolidated Balance Sheets. As these awards are dependent upon the Company's total shareholder return and stock price, they are measured at fair value at the end of each reporting period. The Company paid $5.3 million , $2.8 million and $3.1 million for vested performance share units during the years ended December 31, 2017 , 2016 and 2015 , respectively. The weighted-average grant date fair value of the performance share units granted during the years ended December 31, 2017 , 2016 and 2015 , was $16.90 , $10.16 , and $21.69 per share, respectively. As of December 31, 2017 , $1.2 million of unrecognized compensation cost, which represents the unvested portion of the fair market value of performance shares granted, is expected to be recognized over a weighted-average vesting period of 1.89 years. Transactions involving performance share units under the terms of the CIP are summarized below: Performance Share Units Outstanding Weighted-Average Grant Date Fair Value (per share) Unvested balance at December 31, 2016 1,027,280 $ 17.24 Granted 405,014 16.90 Vested and paid (215,439 ) 31.63 Forfeited (17,519 ) 13.88 Unvested balance at December 31, 2017 1,199,336 $ 14.59 Restricted Share Units Employees may elect to defer their grants of restricted share awards and these deferred awards are designated as restricted share units. Restricted share units vest over a three-year period and are deferred into the Company's nonqualified, unfunded deferred compensation plan at the time of vesting. These awards are ultimately delivered in cash. They are classified as liabilities in "Other long-term liabilities" on the Consolidated Balance Sheets and are measured at fair value at the end of each reporting period. The weighted-average grant date fair value of the restricted share units was $16.98 and $10.12 per share for the years ended December 31, 2017 and 2016 , respectively. As of December 31, 2017 , $0.1 million of unrecognized compensation cost, which represents the unvested portion of the fair market value of restricted share units granted, is expected to be recognized over a weighted-average vesting period of 1.03 years. Transactions involving restricted share units under the terms of the LTSIP are summarized below: Restricted Share Units Outstanding Weighted-Average Grant Date Fair Value (per share) Unvested balance at December 31, 2016 18,034 $ 10.12 Granted 9,924 16.98 Vested (6,012 ) 10.12 Unvested balance at December 31, 2017 21,946 $ 13.22 |
Employee Benefits
Employee Benefits | 12 Months Ended |
Dec. 31, 2017 | |
Compensation and Retirement Disclosure [Abstract] | |
Employee Benefits | Pension and other postretirement benefits The Company provides pension and other postretirement benefits to certain employees through three retirement benefit plans: the QEP Resources, Inc. Retirement Plan (the Pension Plan), the Supplemental Executive Retirement Plan (the SERP), and a postretirement medical plan (the Medical Plan). The Pension Plan is a closed, qualified, defined-benefit pension plan that is funded and provides pension benefits to certain QEP employees, which, as of December 31, 2017 , covers 30 active and suspended participants, or 5% , of QEP's active employees, and 184 participants that are retired or were terminated and vested. Pension Plan benefits are based on the employee's age at retirement, years of service as of the earlier of the participant's termination of employment or December 31, 2015, and highest earnings in a consecutive 72 semi-monthly pay period during the 10 years preceding termination of employment or, if earlier, December 31, 2015. During the year ended December 31, 2017 , the Company made contributions of $4.0 million to the Pension Plan and expects to contribute approximately $4.0 million to the Pension Plan in 2018 . Contributions to the Pension Plan increase plan assets. Due to the Pension Plan freeze on January 1, 2016, the Company began making additional contributions for eligible employees who were active participants in the Pension Plan on December 31, 2015 based on the eligible employee's age as of December 31, 2015. During the year ended December 31, 2017 , QEP contributed $0.4 million for these employees. As a result of the Company's 2014 divestitures and retirements in 2015, the number of active participants in the Pension Plan fell to 50 participants during the year ended December 31, 2015, which is the minimum number of active participants for a plan to meet the qualification requirements of the minimum participation rules under the Internal Revenue Code. In order to prevent disqualification, the Pension Plan was amended in June 2015 and was frozen effective January 1, 2016, such that employees do not earn additional defined benefits for future services except for purposes of determining eligibility for an early retirement benefit. This change resulted in a non-cash curtailment loss of $11.2 million recognized on the Consolidated Statements of Operations within "Interest and other income (expense)" expense during the year ended December 31, 2015 . A curtailment is recognized immediately when there is a significant reduction in, or an elimination of, defined benefit accruals for present employees' future services. The SERP is a nonqualified retirement plan that is unfunded and provides pension benefits to certain QEP employees. SERP benefits are based on the employee's age at retirement, years of service and highest earnings in a consecutive 72 semi-monthly pay period during the 10 years preceding the participant's termination of employment. During the year ended December 31, 2017 , the Company made contributions of $2.0 million to its SERP and expects to contribute approximately $0.7 million in 2018 . Contributions to the SERP are used to fund current benefit payments. The SERP was amended and restated in June 2015 and is closed to new participants effective January 1, 2016. During the year ended December 31, 2017 , the Company recognized a $0.7 million loss on curtailment related to the SERP in connection with the Pinedale Divestiture, which was recorded on the Consolidated Statements of Operations within "Net gain (loss) from asset sales". The Medical Plan is a self-insured plan. It is unfunded and provides other postretirement benefits including certain health care and life insurance benefits for certain retired QEP employees. The Medical Plan was originally provided only to employees hired by Questar Corporation before January 1, 1997. Of the 30 active, pension eligible employees, 17 are also eligible for the Medical Plan when they retire. As of December 31, 2017 , 55 retirees are enrolled in the Medical Plan. The Company has capped its exposure to increasing medical costs by paying a fixed dollar monthly contribution toward these retiree benefits. The Company's contribution is prorated based on an employee's years of service at retirement; only those employees with 25 or more years of service receive the maximum company contribution. During the year ended December 31, 2017 , the Company made contributions of $0.1 million and expects to contribute approximately $0.3 million of benefits in 2018 . At December 31, 2017 and 2016 , QEP's accumulated benefit obligation exceeded the fair value of its qualified retirement plan assets. In February 2017, the Company changed the eligibility requirements for active employees eligible for the Medical Plan, as well as retirees currently enrolled. Effective July 1, 2017, the Company no longer offers the Medical Plan to a retiree and spouse that are both Medicare eligible. In addition, the Company no longer offers life insurance to individuals retiring on or after July 1, 2017. In accordance with the early adoption of ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the presentation of net periodic pension cost and net periodic postretirement benefit cost, the Company recast years ended December 31, 2016 and 2015 by recognizing service costs related to SERP and Medical Plan benefits within "General and administrative" expense on the Consolidated Statements of Operations. All other expenses related to the Pension Plan, SERP and Medical Plan are recognized within "Interest and other income (expense)" on the Consolidated Statements of Operations. The accumulated benefit obligation for all defined-benefit pension plans was $128.7 million and $124.5 million at December 31, 2017 and 2016 , respectively. The following table sets forth changes in the benefit obligations and fair value of plan assets for the Company's Pension Plan, SERP and Medical Plan for the years ended December 31, 2017 and 2016 , as well as the funded status of the plans and amounts recognized in the financial statements at December 31, 2017 and 2016 : Pension Plan and SERP benefits Medical Plan benefits 2017 2016 2017 2016 Change in benefit obligation (in millions) Benefit obligation at January 1, $ 129.2 $ 120.3 $ 5.4 $ 5.2 Service cost 0.8 1.2 — — Interest cost 4.7 5.2 0.1 0.2 Curtailments (0.3 ) — — — Benefit payments (6.9 ) (7.8 ) (0.1 ) (0.4 ) Plan amendments — — (2.4 ) — Actuarial loss (gain) 2.5 10.3 (0.1 ) 0.4 Benefit obligation at December 31, $ 130.0 $ 129.2 $ 2.9 $ 5.4 Change in plan assets Fair value of plan assets at January 1, $ 86.1 $ 79.3 $ — $ — Actual return on plan assets 15.3 7.4 — — Company contributions to the plan 6.0 7.2 0.1 0.4 Benefit payments (6.9 ) (7.8 ) (0.1 ) (0.4 ) Fair value of plan assets at December 31, 100.5 86.1 — — Underfunded status (current and long-term) $ (29.5 ) $ (43.1 ) $ (2.9 ) $ (5.4 ) Amounts recognized in balance sheets Accounts payable and accrued expenses $ (1.5 ) $ (2.5 ) $ (0.2 ) $ (0.3 ) Other long-term liabilities (27.9 ) (40.6 ) (2.6 ) (5.1 ) Total amount recognized in balance sheet $ (29.4 ) $ (43.1 ) $ (2.8 ) $ (5.4 ) Amounts recognized in AOCI Net actuarial loss (gain) $ 15.0 $ 23.5 $ (0.5 ) $ (0.4 ) Prior service cost 1.2 2.9 (1.2 ) 1.0 Total amount recognized in AOCI $ 16.2 $ 26.4 $ (1.7 ) $ 0.6 The following table sets forth the Company's Pension Plan, SERP and Medical Plan cost and amounts recognized in other comprehensive income (before tax) for the respective years ended December 31 : Pension Plan and SERP benefits Medical Plan benefits 2017 2016 2015 2017 2016 2015 Components of net periodic benefit cost (in millions) Service cost $ 0.8 $ 1.2 $ 2.1 $ — $ — $ — Interest cost 4.7 5.2 4.9 0.1 0.2 0.2 Expected return on plan assets (5.4 ) (5.6 ) (5.7 ) — — — Curtailment loss 0.7 — 11.2 — — — Settlements 0.2 — — — — — Amortization of prior service costs 1.0 1.1 1.7 (0.3 ) 0.2 0.2 Amortization of actuarial loss 0.5 0.8 0.5 (0.1 ) — — Periodic expense $ 2.5 $ 2.7 $ 14.7 $ (0.3 ) $ 0.4 $ 0.4 Components recognized in accumulated other comprehensive income Current period prior service cost $ (0.7 ) $ — $ 0.9 $ (2.5 ) $ — $ — Current period actuarial (gain) loss (7.5 ) 8.5 2.2 (0.1 ) 0.4 (1.4 ) Amortization of prior service cost (1.0 ) (1.1 ) (12.9 ) 0.3 (0.2 ) (0.2 ) Amortization of actuarial gain (loss) (0.5 ) (0.8 ) (0.5 ) 0.1 — — Loss on curtailment in current period (0.3 ) — (7.1 ) — — — Settlements (0.2 ) — — — — — Total amount recognized in accumulated other comprehensive income $ (10.2 ) $ 6.6 $ (17.4 ) $ (2.2 ) $ 0.2 $ (1.6 ) The Company recognizes service costs related to SERP and Medical Plan benefits on the Consolidated Statements of Operations within "General and administrative" expense. All other expenses related to the Pension Plan, SERP and Medical Plan are recognized on the Consolidated Statements of Operations within "Interest and other income (expense)". The estimated portion of net actuarial loss and net prior service cost for the Pension Plan and SERP that will be amortized from AOCI into net periodic benefit cost in 2018 is $1.9 million , which represents amortization of prior service cost recognized and actuarial losses . The estimated portion of net actuarial loss and net prior service cost for the Medical Plan that will be amortized from AOCI into net periodic benefit cost in 2018 is $0.3 million , which represents amortization of prior service cost recognized and actuarial gains . Amortization of prior service costs and actuarial gains or losses out of AOCI are recognized in the Consolidated Statements of Operations in "Interest and other income (expense)". Following are the weighted-average assumptions (weighted by the plan level benefit obligation for pension benefits) used by the Company to calculate the Pension Plan, SERP and Medical Plan obligations at December 31, 2017 and 2016 : Pension Plan and SERP benefits Medical Plan benefits 2017 2016 2017 2016 Discount rate 3.52 % 3.96 % 3.60 % 4.10 % Rate of increase in compensation (1) 3.50 % 3.50 % n/a 3.50 % _______________________ (1) The Pension Plan was frozen effective January 1, 2016, and as a result, the rate of increase in compensation for participants is no longer considered an assumption used by the Company to calculate the value of the Pension Plan. As such, for the years ended December 31, 2017 and 2016 , the rate of increase in compensation only includes the SERP and Medical Plan. The discount rate assumptions used by the Company represents an estimate of the interest rate at which the Pension Plan, SERP and Medical Plan obligations could effectively be settled on the measurement date. Following are the weighted-average assumptions (weighted by the net period benefit cost for pension benefits) used by the Company in determining the net periodic Pension Plan, SERP and Medical Plan cost for the years ended December 31: Pension Plan and SERP benefits Medical Plan benefits 2017 2016 2015 2017 2016 2015 Discount rate 4.00 % 4.23 % 3.94 % 4.10 % 4.40 % 4.00 % Expected long-term return on plan assets 6.00 % 6.50 % 6.75 % n/a n/a n/a Rate of increase in compensation (1) 3.50 % 4.00 % 4.00 % 3.50 % 4.00 % 4.00 % _______________________ (1) The Pension Plan was frozen effective January 1, 2016, and as a result, the rate of increase in compensation for participants is no longer considered an assumption used by the Company to calculate the value of the Pension Plan. As such, for the years ended December 31, 2017 and 2016 , the rate of increase in compensation only includes the SERP and Medical Plan. In selecting the assumption for expected long-term rate of return on assets, the Company considers the average rate of return expected on the funds to be invested to provide benefits. This includes considering the plan's asset allocation, historical returns on these types of assets, the current economic environment and the expected returns likely to be earned over the life of the plan. No plan assets are expected to be returned to the Company in 2018 . Historical health care cost trend rates are not applicable to the Company, because the Company's medical costs are capped at a fixed amount. As the Company's medical costs are capped at a fixed amount, the sensitivity to increases and decreases in the health-care inflation rate is not applicable. Plan Assets The Company's Employee Benefits Committee (EBC) oversees investment of qualified pension plan assets. The EBC uses a third-party asset manager to assist in setting targeted-policy ranges for the allocation of assets among various investment categories. The EBC allocates pension plan assets among broad asset categories and reviews the asset allocation at least annually. Asset allocation decisions consider risk and return, future-benefit requirements, participant growth and other expected cash flows. These characteristics affect the level, risk and expected growth of postretirement-benefit assets. The EBC uses asset-mix guidelines that include targets for each asset category, return objectives for each asset group and the desired level of diversification and liquidity. These guidelines may change from time to time based on the EBC's ongoing evaluation of each plan's risk tolerance. The EBC estimates an expected overall long-term rate of return on assets by weighting expected returns of each asset class by its targeted asset allocation percentage. Expected return estimates are developed from analysis of past performance and forecasts of long-term return expectations by third-parties. Responsibility for individual security selection rests with each investment manager, who is subject to guidelines specified by the EBC. The EBC sets performance objectives for each investment manager that are expected to be met over a three-year period or a complete market cycle, whichever is shorter. Performance and risk levels are regularly monitored to confirm policy compliance and that results are within expectations. Performance for each investment is measured relative to the appropriate index benchmark for its category. QEP securities may be considered for purchase at an investment manager's discretion, but within limitations prescribed by the Employee Retirement Income Security Act of 1974 (ERISA) and other laws. There was no direct investment in QEP shares for the periods disclosed. The majority of retirement-benefit assets were invested as follows: Equity securities: Domestic equity assets were invested in a combination of index funds and actively managed products, with a diversification goal representative of the whole U.S. stock market. International equity securities consisted of developed and emerging market foreign equity assets that were invested in funds that hold a diversified portfolio of common stocks of corporations in developed and emerging foreign countries. Debt securities: Investment grade intermediate-term debt assets are invested in funds holding a diversified portfolio of debt of governments, corporations and mortgage borrowers with average maturities of five to ten years and investment grade credit ratings. Investment grade long-term debt assets are invested in a diversified portfolio of debt of corporate and non-corporate issuers, with an average maturity of more than ten years and investment grade credit ratings. High yield and bank loan assets are held in funds holding a diversified portfolio of these instruments with an average maturity of five to seven years. Although the actual allocation to cash and short-term investments is minimal (less than 5%), larger cash allocations may be held from time to time if deemed necessary for operational aspects of the retirement plan. Cash is invested in a high-quality, short-term temporary investment fund that purchases investment-grade quality short-term debt issued by governments and corporations. The EBC made the decision to invest all of the retirement plan assets in commingled funds as these funds typically have lower expense ratios and are more tax efficient than mutual funds. These investments are public investment vehicles valued using the net asset value (NAV) as a practical expedient. The NAV is based on the underlying assets owned by the fund excluding transaction costs and minus liabilities, which can be traced back to observable asset values. No assets held by the Pension Plan that were valued using the NAV methodology were subject to redemption restrictions on their valuation date. These commingled funds are audited annually by an independent accounting firm. In conjunction with the issuance of ASU 2015-07, Fair Value Measurements (Topic 820): Disclosures for Investment in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent) , QEP no longer presents its Pension Plan assets in the fair value hierarchy, in accordance with the provisions of ASC 820, Fair Value Measurements and Disclosures, as all investments are measured at NAV as a practical expedient, which are now required to be excluded from the fair value hierarchy. The following table summarizes investments for which fair value is measured using the NAV per share practical expedient as of December 31, 2017 and 2016 , respectively: December 31, 2017 December 31, 2016 Total Percentage of total Total Percentage of total (in millions, except percentages) Cash and short-term investments $ 0.5 — % $ 3.5 4 % Equity securities: Domestic 35.0 35 % 39.3 46 % International 15.3 15 % 21.6 25 % Fixed income 49.7 50 % 21.7 25 % Total investments $ 100.5 100 % $ 86.1 100 % Expected Benefit Payments As of December 31, 2017 , the following future benefit payments are expected to be paid: Pension Plan and SERP benefits Medical Plan benefits (in millions) 2018 $ 6.6 $ 0.2 2019 $ 8.1 $ 0.2 2020 $ 7.6 $ 0.2 2021 $ 8.3 $ 0.2 2022 $ 6.8 $ 0.2 2023 through 2026 $ 39.1 $ 0.6 Employee Investment Plan QEP employees may participate in the QEP Employee Investment Plan, a defined-contribution plan (the 401(k) Plan). The 401(k) Plan allows eligible employees to make investments, including purchasing shares of QEP common stock, through payroll deduction at the current fair market value on the transaction date. Participants receive 100% employer matching contributions on participant 401(k) plan contributions up to a percentage of qualifying earnings as described below. Year Ended December 31, 2017 2016 2015 Employees not covered by the Pension Plan or SERP (1) Maximum employer matching of qualifying earnings 8 % 8 % 8 % Employees covered by the Pension Plan but not the SERP (1) Maximum employer matching of qualifying earnings 8 % 8 % 6 % Employees covered by both the Pension Plan and the SERP (1) Maximum employer matching of qualifying earnings 6 % 6 % 6 % _______________________ (1) The Pension Plan was frozen effective January 1, 2016. The Company may contribute a discretionary portion beyond the Company's matching contribution to employees not in the Pension Plan or SERP. The Company recognizes expense equal to its yearly contributions, which amounted to $6.0 million , $5.6 million and $6.3 million during the years ended December 31, 2017 , 2016 and 2015 , respectively. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | |
Income Tax Disclosure [Text Block] | On December 22, 2017 the Tax Cuts and Jobs Act (H.R.1) (Tax Legislation) was signed into law, which resulted in significant changes to U.S. federal income tax law. QEP expects that these changes will positively impact QEP's future after-tax earnings in the U.S., primarily due to the lower federal statutory tax rate of 21% compared to 35% . The Tax Legislation also repeals the corporate alternative minimum tax (AMT). Several provisions of the new tax law such as limitations on the deductibility of interest expense and certain executive compensation and the inability to use Section 1031 like-kind exchanges for assets such as machinery and equipment could apply to QEP; however, we do not believe that they will materially impact QEP's financial statements. The impact of the Tax Legislation may differ from the statements above due to, among other things, changes in interpretations and assumptions the Company has made and actions the Company may take as a result of the Tax Legislation. Additionally, guidance issued by the relevant regulatory authorities regarding the Tax Legislation may materially impact QEP's financial statements. The Company will continue to analyze the Tax Legislation to determine the full impact of the new law, on the Company's consolidated financial statements and operations. Details of income tax provisions and deferred income taxes from continuing operations are provided in the following tables. The components of income tax provisions and benefits were as follows: Year Ended December 31, 2017 2016 2015 Federal income tax provision (benefit) (in millions) Current $ 2.1 $ (55.5 ) $ (112.3 ) Deferred (339.8 ) (614.3 ) 34.5 State income tax provision (benefit) Current 0.5 (1.5 ) (6.6 ) Deferred 25.0 (36.9 ) (9.2 ) Total income tax provision (benefit) $ (312.2 ) $ (708.2 ) $ (93.6 ) The difference between the statutory federal income tax rate and the Company's effective income tax rate is explained as follows: Year Ended December 31, 2017 2016 2015 Federal income taxes statutory rate 35.0 % 35.0 % 35.0 % Increase (decrease) in rate as a result of: State income taxes, net of federal income tax benefit (1) (40.1 )% 2.4 % 4.2 % Federal rate change (2) 741.3 % — % — % State rate change 2.1 % (1.1 )% — % Penalties (0.4 )% — % (0.3 )% Return to provision adjustment (0.7 )% — % (0.3 )% Uncertain tax provision (federal rate change) (7.7 )% — % — % Other (1.8 )% — % (0.1 )% Effective income tax rate 727.7 % 36.3 % 38.5 % ____________________________ (1) State income taxes changed significantly from prior years mainly due to the change in valuation allowance during the year of $36.2 million . (2) The new tax legislation changed the federal corporate income tax rate from 35% to 21% starting in 2018. The rate change caused the Company to revalue its deferred tax liabilities and assets as of December 31, 2017 from a 35% to 21% federal corporate income tax rate which caused the majority of the change in rate. Significant components of the Company's deferred income taxes were as follows: December 31, 2017 (1) 2016 Deferred tax liabilities (in millions) Property, plant and equipment $ 898.7 $ 1,135.0 Deferred tax assets Net operating loss and tax credit carryforwards $ 308.8 $ 161.6 Employee benefits and compensation costs 26.4 49.0 Bonus and vacation accrual 6.2 11.4 Commodity price derivatives 29.9 74.3 Other 9.4 12.8 Total deferred tax assets 380.7 309.1 Net deferred income tax liability $ 518.0 $ 825.9 Balance sheet classification Deferred income tax liability – noncurrent 518.0 825.9 Net deferred income tax liability $ 518.0 $ 825.9 ____________________________ (1) The $307.9 million decrease in net deferred income tax liability as of December 31, 2017 is primarily related to a $318.0 million decrease from the federal rate change from 35% to 21% . The amounts and expiration dates of net operating loss and tax credit carryforwards at December 31, 2017 , are as follows: Expiration Dates Amounts (in millions) State net operating loss and tax credit carryforwards 2018-2037 $ 95.8 State net operating loss valuation allowance $ (56.8 ) U.S. net operating loss 2036-2037 $ 250.4 U.S. alternative minimum tax credit Indefinite $ 19.5 The valuation allowance of $56.8 million was established in 2014 and 2017 against the available state net operating loss and is related primarily to losses incurred in Oklahoma and Louisiana. Due to the 2014 property sales in the Other Southern area in which the Company sold its interests in most of its properties in Oklahoma, the Company does not forecast sufficient taxable income to utilize the net operating loss in Oklahoma. In 2017, a valuation allowance of $31.8 million was established against Louisiana's net operating loss as the Company does not forecast sufficient taxable income to utilize the entire net operating loss in Louisiana. The Tax Legislation eliminated AMT, and allowed the ability to offset our regular tax liability or claim refunds for taxable years 2018 through 2021 for AMT credits carried forward from prior years. The Company currently anticipates it will realize approximately $19.5 million in AMT value over the next four years with approximately half of this value estimated to be realized in 2019 for taxable year 2018. Unrecognized Tax Benefit As of December 31, 2017 and 2016 , QEP had $19.0 million and $15.6 million , respectively, of unrecognized tax benefits related to uncertain tax positions for asset sales that occurred in 2014, which were recorded within "Other long-term liabilities" on the Consolidated Balance Sheets. The $15.6 million uncertain tax position the Company reported during the year ended December 31, 2016 , was expensed during the year ended December 31, 2014, with an additional $3.4 million expensed during the year ended December 31, 2017 with the new Tax Legislation. The benefits of uncertain tax positions taken or expected to be taken on income tax returns is recognized in the consolidated financial statements at the largest amount that is more likely than not to be sustained upon examination by the relevant taxing authorities. Our policy is to recognize any interest expense related to uncertain tax positions in "Interest expense" on the Consolidated Statements of Operations and to recognize any penalties related to uncertain tax positions in "General and administrative" expense on the Consolidated Statements of Operations. During the year ended December 31, 2017 , the Company incurred $0.7 million of estimated interest expense related to uncertain tax positions. During the year ended December 31, 2016 , the Company incurred $0.7 million of estimated interest expense and $0.6 million of estimated penalties related to uncertain tax positions. The following is a reconciliation of our beginning and ending amounts of unrecognized tax benefits for the years ended December 31, 2017 and 2016 : Unrecognized Tax Benefits 2017 2016 (in millions) Balance as of January 1, $ 15.6 $ 15.6 Federal benefit of state (change from 35% to 21%) 3.4 — Balance as of December 31, $ 19.0 $ 15.6 As of December 31, 2017 and 2016 , QEP had approximately $19.0 million and $15.6 million , respectively, of unrecognized tax benefit that would impact its effective tax rate if recognized. The difference is due to the change in the Federal tax rate in 2017 from 35% to 21% , which affects the federal benefit of the state deduction to the unrecognized tax position. |
Quarterly Financial Information
Quarterly Financial Information (Unaudited) | 12 Months Ended |
Dec. 31, 2017 | |
Quarterly Financial Information Disclosure [Abstract] | |
Quarterly Financial Information [Text Block] | The following table provides a summary of unaudited quarterly financial information: First Quarter Second Quarter Third Quarter Fourth Quarter Year 2017 (in millions, except per share amounts or otherwise specified) Revenues $ 420.1 $ 383.7 $ 390.1 $ 429.0 $ 1,622.9 Operating income (loss) (5.2 ) (0.9 ) 132.1 (24.5 ) 101.5 Net income (loss) 76.9 45.4 (3.3 ) 150.3 269.3 Net gain (loss) from asset sales and impairment (0.1 ) 19.8 157.1 (42.2 ) 134.6 Nonrecurring items in operating income (loss) (1) — — 8.2 — 8.2 Per share information Basic EPS $ 0.32 $ 0.19 $ (0.01 ) $ 0.62 $ 1.12 Diluted EPS 0.32 0.19 (0.01 ) 0.62 1.12 Production information Total equivalent production (Mboe) 13,090.3 13,860.6 14,124.1 12,069.9 53,144.9 Total equivalent production (Bcfe) 78.6 83.2 84.7 72.1 318.6 2016 Revenues $ 261.3 $ 333.7 $ 382.4 $ 399.7 $ 1,377.1 Operating income (loss) (1,379.0 ) (92.1 ) (93.1 ) (36.5 ) (1,600.7 ) Net income (loss) (863.8 ) (197.0 ) (50.9 ) (133.3 ) (1,245.0 ) Net gain (loss) from asset sales and impairment (1,181.9 ) (1.6 ) 0.3 (6.1 ) (1,189.3 ) Nonrecurring items in operating income (loss) (1) 7.7 — 25.0 — 32.7 Per share information Basic EPS $ (4.55 ) $ (0.90 ) $ (0.21 ) $ (0.56 ) $ (5.62 ) Diluted EPS (4.55 ) (0.90 ) (0.21 ) (0.56 ) (5.62 ) Production information Total equivalent production (Mboe) 13,776.4 13,882.4 14,445.7 13,675.7 55,780.2 Total equivalent production (Bcfe) 82.7 83.3 86.6 82.1 334.7 ____________________________ (1) Reflects legal expenses and loss contingencies incurred during the years ended December 31, 2017 and 2016 . |
Supplemental Gas and Oil Inform
Supplemental Gas and Oil Information (Unaudited) | 12 Months Ended |
Dec. 31, 2017 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |
Oil and Gas Exploration and Production Industries Disclosures [Text Block] | The Company is making the following supplemental disclosures of oil and gas producing activities, in accordance with ASC 932, Extractive Activities – Oil and Gas, as amended by ASU 2010-03, Oil and Gas Reserve Estimation and Disclosures, and SEC Regulation S-X. The Company uses the successful efforts accounting method for its oil and gas exploration and development activities. All of QEP's properties are located in the United States. Capitalized Costs The aggregate amounts of costs capitalized for oil and gas exploration and development activities and the related amounts of accumulated depreciation, depletion and amortization are shown below: December 31, 2017 2016 (in millions) Proved properties $ 12,470.9 $ 14,232.5 Unproved properties, net 1,095.8 871.5 Total proved and unproved properties 13,566.7 15,104.0 Accumulated depreciation, depletion and amortization (6,642.9 ) (8,797.7 ) Net capitalized costs $ 6,923.8 $ 6,306.3 Costs Incurred The costs incurred in oil and gas acquisition, exploration and development activities are displayed in the table below. Development costs are net of the change in accrued capital costs of $60.6 million and ARO additions and revisions of $32.0 million during the year ended December 31, 2017 . The costs incurred for the development of reserves that were classified as proved undeveloped were approximately $389.3 million in 2017 , $258.1 million in 2016 , and $490.4 million in 2015 . Year Ended December 31, 2017 2016 2015 (in millions) Proved property acquisitions $ 269.6 $ 431.6 $ 49.6 Unproved property acquisitions 532.4 208.7 39.8 Other acquisitions 13.2 — — Exploration costs (capitalized and expensed) 32.7 13.4 8.7 Development costs 1,189.3 509.2 1,010.3 Total costs incurred $ 2,037.2 $ 1,162.9 $ 1,108.4 Results of Operations Following are the results of operations of QEP's oil and gas producing activities, before allocated corporate overhead and interest expenses. Year Ended December 31, 2017 2016 2015 (in millions) Revenues $ 1,548.1 $ 1,271.0 $ 1,390.4 Production costs 675.4 616.7 654.1 Exploration expenses 22.0 1.7 2.7 Depreciation, depletion and amortization 735.1 852.3 870.8 Impairment 72.3 1,194.3 55.6 Total expenses 1,504.8 2,665.0 1,583.2 Income (loss) before income taxes 43.3 (1,394.0 ) (192.8 ) Income tax benefit (expense) (16.0 ) 517.2 70.6 Results of operations from producing activities excluding allocated corporate overhead and interest expenses $ 27.3 $ (876.8 ) $ (122.2 ) Estimated Quantities of Proved Oil and Gas Reserves Estimates of proved oil and gas reserves have been completed in accordance with professional engineering standards and the Company's established internal controls, which includes the oversight of a multi-functional Reserves Review Committee reporting to the Company's Audit Committee of the Board of Directors. The Company retained Ryder Scott Company, L.P. (RSC), independent oil and gas reserve evaluation engineering consultants, to prepare the estimates of all of its proved reserves as of December 31, 2017 and 2016 , and retained RSC and DeGolyer and MacNaughton to prepare the estimates of all of its proved reserves as of December 31, 2015 . The estimated proved reserves have been prepared in accordance with the SEC's Regulation S-X and ASC 932 as amended. The individuals performing reserves estimates possess professional qualifications and demonstrate competency in reserves estimation and evaluation. The estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors. All of QEP's proved undeveloped reserves at December 31, 2017 , are scheduled to be developed within five years from the date such locations were initially disclosed as proved undeveloped reserves. The Company plans to continue development of its leaseholds and anticipates that it will have the financial capability to continue development in the manner estimated. While the majority of QEP's PUD reserves are located on leaseholds that are held by production, any PUD locations on expiring leaseholds are scheduled for development during the primary term of the lease. As of December 31, 2017 , all of the Company's oil and gas reserves are attributable to properties within the United Sates. A summary of the Company's change in quantities of proved oil, gas and NGL reserves for the years ended December 31, 2015 , 2016 and 2017 are as follows: Oil Gas NGL Total (13) (MMbbl) (Bcf) (MMbbl) (MMboe) Balance at December 31, 2014 172.5 2,317.2 96.6 655.3 Revisions of previous estimates (1) (47.0 ) (463.8 ) (55.3 ) (179.6 ) Extensions and discoveries (2) 85.6 467.7 21.8 185.4 Purchase of reserves in place (3) 2.0 3.2 0.6 3.1 Sale of reserves in place (4) (0.4 ) (34.3 ) (0.2 ) (6.3 ) Production (19.6 ) (181.1 ) (4.7 ) (54.5 ) Balance at December 31, 2015 193.1 2,108.9 58.8 603.4 Revisions of previous estimates (5) (9.7 ) 412.8 (0.3 ) 58.8 Extensions and discoveries (6) 13.0 158.1 3.3 42.6 Purchase of reserves in place (7) 62.7 54.6 11.5 83.3 Sale of reserves in place (8) (0.2 ) (3.6 ) (0.1 ) (0.9 ) Production (20.3 ) (177.0 ) (6.0 ) (55.8 ) Balance at December 31, 2016 238.6 2,553.8 67.2 731.4 Revisions of previous estimates (9) 3.7 12.5 (3.1 ) 2.7 Extensions and discoveries (10) 59.1 101.9 10.4 86.4 Purchase of reserves in place (11) 46.6 125.5 8.7 76.3 Sale of reserves in place (12) (7.9 ) (831.2 ) (12.6 ) (159.0 ) Production (19.6 ) (168.9 ) (5.4 ) (53.1 ) Balance at December 31, 2017 320.5 1,793.6 65.2 684.7 Proved developed reserves Balance at December 31, 2014 99.3 1,288.4 52.2 366.2 Balance at December 31, 2015 109.7 1,245.3 34.4 351.6 Balance at December 31, 2016 103.2 1,309.8 35.7 357.2 Balance at December 31, 2017 116.0 655.5 27.9 253.1 Proved undeveloped reserves Balance at December 31, 2014 73.2 1,028.8 44.4 289.1 Balance at December 31, 2015 83.4 863.6 24.4 251.8 Balance at December 31, 2016 135.4 1,244.0 31.5 374.2 Balance at December 31, 2017 204.5 1,138.1 37.3 431.6 ___________________________ (1) Revisions of previous estimates in 2015 include: 126.2 MMboe of negative revisions due to lower pricing and 67.2 MMboe of negative revisions unrelated to pricing, partially offset by 13.7 MMboe of positive performance revisions. Negative pricing revisions were driven by lower oil, gas and NGL prices. Negative other revisions included operating in ethane rejection in Pinedale and the Uinta Basin. (2) Extensions and discoveries in 2015 increased proved reserves by 185.4 MMboe, primarily related to extensions and discoveries in the Williston Basin of 68.2 MMboe, the Uinta Basin of 53.2 MMboe, and the Permian Basin of 49.6 MMboe. All of these extensions and discoveries related to new well completions and associated new PUD locations. (3) Purchase of reserves in place in 2015 related to the acquisition of additional interests in QEP operated wells in the Williston and Permian basins as discussed in Note 2 – Acquisitions and Divestitures . (4) Sale of reserves in place in 2015 relate to the divestiture of QEP's interest in certain non-core properties as discussed in Note 2 – Acquisitions and Divestitures . (5) Revisions of previous estimates in 2016 include 77.3 MMboe of positive revisions, primarily related to successful workovers in Haynesville/Cotton Valley; reserves associated with increased density wells in areas that have been previously developed on lower density spacing; and 5.5 MMboe of positive performance revisions. These positive revisions were partially offset by 18.5 MMboe of negative revisions related to pricing, driven by lower oil, gas and NGL prices. (6) Extensions and discoveries in 2016 were primarily in the Permian and Uinta basins and related to new well completions and associated new PUD locations. (7) Purchase of reserves in place in 2016 primarily relates to QEP's 2016 Permian Basin Acquisition as discussed in Note 2 – Acquisitions and Divestitures . (8) Sale of reserves in place in 2016 relates to the divestiture of QEP's interest in certain non-core properties as discussed in Note 2 – Acquisitions and Divestitures . (9) Revisions of previous estimates in 2017 include 2.7 MMboe of positive revisions, primarily related to 32.0 MMboe of positive revisions related to pricing, driven by higher oil, gas and NGL prices and 2.2 MMboe of positive performance revisions. These positive revisions were partially offset by 11.0 MMboe of negative revisions related to higher operating costs and 20.5 MMboe of other revisions primarily from changing to a horizontal development plan from a vertical well development plan in the Uinta Basin and increased longer laterals in Haynesville/Cotton Valley. These negative other revisions are partially offset by positive other revisions from successful infill drilling in Haynesville/Cotton Valley and the Williston Basin. (10) Extensions and discoveries in 2017 primarily related to new well completions and associated new PUD locations in the Permian Basin. (11) Purchase of reserves in place in 2017 was primarily related to QEP's 2017 Permian Basin Acquisition and various other acquired oil and gas properties as discussed in Note 2 – Acquisitions and Divestitures . (12) Sale of reserves in place in 2017 was primarily related to QEP's Pinedale Divestiture as discussed in Note 2 – Acquisitions and Divestitures . (13) Generally, gas consumed in operations was excluded from reserves, however, in some cases, produced gas consumed in operations was included in reserves when the volumes replaced fuel purchases. Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves Future net cash flows were calculated at December 31, 2017 , 2016 and 2015 , by applying prices, which were the simple average of the first-of-the-month commodity prices, adjusted for location and quality differentials, for each of the 12 months during 2017 , 2016 and 2015 , with consideration of known contractual price changes. The prices used do not include any impact of QEP's commodity derivatives portfolio. The following table provides the average benchmark prices per unit, before location and quality differential adjustments, used to calculate the related reserve category: For the year ended December 31, 2017 2016 2015 Average benchmark price per unit: Oil price (per bbl) $ 51.34 $ 42.75 $ 50.28 Gas price (per MMBtu) $ 2.98 $ 2.48 $ 2.59 Year ended operating expenses, development costs and appropriate statutory income tax rates, with consideration of future tax rates, were used to compute the future net cash flows. All cash flows were discounted at 10% to reflect the time value of cash flows, without regard to the risk of specific properties. The estimated future costs to develop proved undeveloped reserves are approximately $486.5 million in 2018 , $710.0 million in 2019 and $1,006.2 million in 2020 . Estimated future development costs include capital spending on major development projects, some of which will take several years to complete. QEP believes cash flow from its operating activities, cash on hand and borrowings under its revolving credit facility will be sufficient to cover these estimated future development costs. In addition, QEP estimates that its future development costs relating to wells waiting on completion and its refracturing program, which are not classified as PUD, are approximately $132.6 million in 2018. The assumptions used to derive the standardized measure of discounted future net cash flows are those required by accounting standards and do not necessarily reflect the Company's expectations. The information may be useful for certain comparative purposes but should not be solely relied upon in evaluating QEP or its performance. Furthermore, information contained in the following table may not represent realistic assessments of future cash flows, nor should the standardized measure of discounted future net cash flows be viewed as representative of the current value of the Company's reserves. Management believes that the following factors should be considered when reviewing the information below: • Future commodity prices received for selling the Company's net production will likely differ from those required to be used in these calculations. • Future operating and capital costs will likely differ from those required to be used in these calculations. • Future market conditions, government regulations, reservoir conditions and risks inherent in the production of oil and gas may cause production rates in future years to vary significantly from those rates used in the calculations. • Future revenues may be subject to different production, severance and property taxation rates. • The selection of a 10% discount rate is arbitrary and may not be a reasonable factor in adjusting for future economic conditions or in considering the risk that is part of realizing future net cash flows from the reserves. The standardized measure of discounted future net cash flows relating to proved reserves is presented in the table below: Year Ended December 31, 2017 2016 2015 (in millions) Future cash inflows $ 22,028.9 $ 16,239.8 $ 15,325.3 Future production costs (9,074.2 ) (7,789.0 ) (7,389.9 ) Future development costs (1) (4,726.0 ) (3,432.9 ) (2,202.5 ) Future income tax expenses (2) (1,439.1 ) (913.4 ) (1,169.3 ) Future net cash flows 6,789.6 4,104.5 4,563.6 10% annual discount for estimated timing of net cash flows (3,692.3 ) (2,176.5 ) (2,087.3 ) Standardized measure of discounted future net cash flows $ 3,097.3 $ 1,928.0 $ 2,476.3 ___________________________ (1) Future development costs include future abandonment and salvage costs. (2) The standardized measure of discounted future net cash flows for the year ended December 31, 2017, assumes the new 21% federal tax rate from the Tax Legislation enacted in December 2017. The principal sources of change in the standardized measure of discounted future net cash flows relating to proved reserves is presented in the table below: Year Ended December 31, 2017 2016 2015 (in millions) Balance at January 1, $ 1,928.0 $ 2,476.3 $ 5,340.0 Sales of oil, gas and NGL produced, net of production costs (872.7 ) (654.3 ) (736.3 ) Net change in sales prices and in production (lifting) costs related to future production 1,457.2 (739.4 ) (6,307.8 ) Net change due to extensions and discoveries 556.8 81.8 1,765.7 Net change due to revisions of quantity estimates 9.9 122.7 (1,350.2 ) Net change due to purchases of reserves in place 342.7 256.5 29.7 Net change due to sales of reserves in place (504.7 ) (4.3 ) (48.8 ) Previously estimated development costs incurred during the period 475.4 374.6 865.0 Changes in estimated future development costs (283.4 ) (476.5 ) 560.7 Accretion of discount 235.7 311.1 752.9 Net change in income taxes (227.4 ) 205.4 1,554.4 Other (20.2 ) (25.9 ) 51.0 Net change 1,169.3 (548.3 ) (2,863.7 ) Balance at December 31, $ 3,097.3 $ 1,928.0 $ 2,476.3 |
Subsequent Event (Notes)
Subsequent Event (Notes) | 12 Months Ended |
Dec. 31, 2017 | |
Subsequent Event [Abstract] | |
Subsequent Events [Text Block] | Note 15 – Subsequent Event In February 2018, in conjunction with the 2017 Permian Basin Acquisition, QEP entered into agreements to acquire oil and gas properties in the Permian Basin for an aggregate purchase price of $36.1 million , subject to customary purchase price adjustments. The transactions are expected to be funded with borrowings under the credit facility and are expected to close in the first half of 2018. In February 2018, the Board of Directors approved a retention and severance program in conjunction with the announcement of several strategic initiatives, which include selling assets and focusing the Company's activities on its Permian Basin operations. The estimated amount of general and administrative expenses to be incurred related to this program in 2018 is approximately $20.0 million . |
Summary of Significant Accoun24
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2017 | |
Summary of Significant Accounting Policies [Abstract] | |
Nature of Business [Text Block] | Nature of Business QEP Resources, Inc. is an independent crude oil and natural gas exploration and production company with operations in two regions of the United States: the Northern Region (primarily in North Dakota and Utah) and the Southern Region (primarily in Texas and Louisiana). Unless otherwise specified or the context otherwise requires, all references to "QEP" or the "Company" are to QEP Resources, Inc. and its subsidiaries on a consolidated basis. QEP's corporate headquarters are located in Denver, Colorado and shares of QEP's common stock trade on the New York Stock Exchange (NYSE) under the ticker symbol "QEP". |
Principles of Consolidation [Policy Text Block] | Principles of Consolidation The Consolidated Financial Statements contain the accounts of QEP and its majority-owned or controlled subsidiaries. The Consolidated Financial Statements were prepared in accordance with GAAP and with the instructions for annual reports on Form 10-K and Regulations S-X. All significant intercompany accounts and transactions have been eliminated in consolidation. All dollar and share amounts in this Annual Report on Form 10-K are in millions, except per share information and where otherwise noted. |
Termination of Marketing Agreements [Policy Text Block] | Termination of Marketing Agreements Effective January 1, 2016, QEP terminated its contracts for resale and marketing transactions between its wholly owned subsidiaries, QEP Marketing Company (QEP Marketing) and QEP Energy Company (QEP Energy). In addition, substantially all of QEP Marketing's third-party purchase and sale agreements and gathering, processing and transportation contracts were assigned to QEP Energy, except those contracts related to natural gas storage activities and Haynesville Gathering. As a result, QEP Energy directly markets its own oil, gas and NGL production. While QEP continues to act as an agent for the sale of oil, gas and NGL production for other working interest owners, for whom QEP serves as the operator, QEP is no longer the first purchaser of this production. QEP has substantially reduced its marketing activities, and subsequently, is reporting lower resale revenue and expenses than it had prior to 2016. In conjunction with the changes described above, QEP conducted a segment analysis in accordance with Accounting Standards Codification (ASC) Topic 280, Segment Reporting, and determined that QEP had one reportable segment effective January 1, 2016. The Company has recast its financial statements for historical periods to reflect the impact of the termination of marketing agreements to show its financial results without segments. |
Reclassifications [Policy Text Block] | Reclassifications Certain prior period amounts on the Consolidated Statements of Operations, Consolidated Balance Sheets and Consolidated Statements of Cash Flows have been reclassified to conform to the current year presentation. Such reclassifications had no effect on the Company's net income (loss), earnings (loss) per share, cash flows, current assets or retained earnings previously reported. |
Use of Estimates [Policy Text Block] | Use of Estimates The preparation of the Consolidated Financial Statements and Notes in conformity with GAAP requires that management formulate estimates and assumptions that affect revenues, expenses, assets, liabilities and the disclosure of contingent assets and liabilities. A significant item that requires management's estimates and assumptions is the estimate of proved oil, gas and NGL reserves, which are used in the calculation of depreciation, depletion and amortization rates of its oil and gas properties, impairment of proved properties and asset retirement obligations. Changes in estimated quantities of its reserves could impact the Company's reported financial results as well as disclosures regarding the quantities and value of proved oil and gas reserves. Other items subject to estimates and assumptions include the carrying amount of property, plant and equipment, assigning fair value and allocating purchase price in connection with business combinations, valuation allowances for receivables, income taxes, valuation of derivatives instruments, accrued liabilities, accrued revenue and related receivables and obligations related to employee benefits, among others. Although management believes these estimates are reasonable, actual results could differ from these estimates. |
Risks And Uncertainties [Policy Text Block] | Risks and Uncertainties The Company's revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for oil, gas and NGL, which are affected by many factors outside of QEP's control, including changes in market supply and demand. Changes in market supply and demand are impacted by weather conditions, pipeline capacity constraints, inventory storage levels, basis differentials, export capacity, strength of the U.S. dollar and other factors. Field-level prices received for QEP's oil and gas production have historically been volatile and may be subject to significant fluctuations in the future. The Company's derivative contracts serve to mitigate in part the effect of this price volatility on the Company's cash flows, and the Company has derivative contracts in place for a portion of its expected future oil and gas production. Refer to Note 6 – Derivative Contracts for the Company's open oil and gas commodity derivative contracts. |
Revenue Recognition [Policy Text Block] | Revenue Recognition QEP recognizes revenue from oil and gas producing activities in the period that services are provided or products are delivered. Revenues associated with the sale of oil, gas and NGL are accounted for using the sales method, whereby revenue is recognized when these commodities are sold to purchasers. Revenues include estimates for the two most recent months using published commodity price indexes and volumes supplied by field operators. An imbalance liability is recorded to the extent that QEP has sold volumes in excess of its share of remaining reserves in an underlying property. QEP also purchases and resells oil and gas primarily to mitigate losses on unutilized capacity related to firm transportation commitments and storage activities. QEP recognizes revenue from these resale activities when title transfers to the customer. |
Cash and Cash Equivalents and Restricted Cash [Policy Text Block] | Cash and Cash Equivalents and Restricted Cash Cash equivalents consist principally of highly liquid investments in securities with original maturities of three months or less made through commercial bank accounts that result in available funds the next business day. As of December 31, 2017 , QEP had no unrestricted cash and restricted cash of $23.4 million . As of December 31, 2016 , QEP had unrestricted cash of $443.8 million and restricted cash of $21.6 million . QEP's restricted cash is primarily cash deposited into an escrow account related to a title dispute between third parties in the Williston Basin and is included in "Other noncurrent assets" on the Consolidated Balance Sheets. Supplemental cash flow information is shown in the table below: Year Ended December 31, 2017 2016 2015 Supplemental Disclosures (in millions) Cash paid for interest, net of capitalized interest $ 134.9 $ 139.1 $ 139.4 Cash paid (refund received) for income taxes, net $ (0.3 ) $ (123.5 ) $ 487.8 Non-cash investing activities Change in capital expenditure accrual balance $ 60.2 $ (32.8 ) $ (129.2 ) |
Accounts Receivable [Policy Text Block] | Accounts Receivable Accounts receivable consists mainly of receivables from oil and gas purchasers and joint interest owners on properties the Company operates. For receivables from joint interest owners, the Company has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. Generally, the Company's oil and gas receivables are collected and bad debts are minimal. However, if commodity prices remain low for an extended period of time, the Company could incur increased levels of bad debt expense. Recovery of bad debt associated with accounts receivable for the year ended December 31, 2017 was $1.0 million . Bad debt expense associated with accounts receivable for the years ended December 31, 2016 and 2015 , was $1.8 million , and $0.5 million , respectively. Bad debt recovery or expense is included in "General and administrative" expense on the Consolidated Statements of Operations. The Company routinely assesses the recoverability of all material trade and other receivables to determine their collectability. The allowance for bad debt expenses was $1.6 million at December 31, 2017 , and $4.8 million at December 31, 2016 . |
Property, Plant and Equipment [Policy Text Block] | Property, Plant and Equipment Property, plant and equipment balances are stated at historical cost. Material and supplies inventories are valued at the lower of cost or net realizable value. Maintenance and repair costs are expensed as incurred. Significant accounting policies for our property, plant and equipment are as follows: Successful Efforts Accounting for Oil and Gas Operations The Company follows the successful efforts method of accounting for oil and gas property acquisitions, exploration, development and production activities. Under this method, the acquisition costs of proved and unproved properties, successful exploratory wells and development wells are capitalized. Other exploration costs, including geological and geophysical costs, delay rentals and administrative costs associated with unproved property and unsuccessful exploratory well costs are expensed. Costs to operate and maintain wells and field equipment are expensed as incurred. A gain or loss is generally recognized only when an entire field is sold or abandoned, or if the unit-of-production depreciation, depletion and amortization rate would be significantly affected. Capitalized costs of unproved properties are reclassified to proved property when related proved reserves are determined or charged against the impairment allowance when abandoned. Capitalized Exploratory Well Costs The Company capitalizes exploratory well costs until it determines whether an exploratory well is commercial or noncommercial. If the Company deems the well commercial, capitalized costs are depreciated on a field basis using the unit-of-production method and the estimated proved developed oil and gas reserves. If the Company concludes that the well is noncommercial, well costs are immediately charged to exploration expense. Exploratory well costs that have been capitalized for a period greater than one year since the completion of drilling are expensed unless the Company remains engaged in substantial activities to assess whether the project is commercial. Depreciation, Depletion and Amortization (DD&A) Capitalized proved leasehold costs are depleted on a field-by-field basis using the unit-of-production method and the estimated proved oil and gas reserves. Capitalized costs of exploratory wells that have found proved oil and gas reserves and capitalized development costs are depreciated using the unit-of-production method based on estimated proved developed reserves for a successful effort field. The Company capitalizes an estimate of the fair value of future abandonment costs. DD&A for the Company's remaining properties is generally based upon rates that will systematically charge the costs of assets against income over the estimated useful lives of those assets using the straight-line method. The estimated useful lives of those assets depreciated under the straight-line basis generally range as follows: Buildings 10 to 30 years Leasehold improvements 3 to 10 years Service, transportation and field service equipment 3 to 7 years Furniture and office equipment 3 to 7 years Impairment of Long-Lived Assets Proved oil and gas properties are evaluated on a field-by-field basis for potential impairment. Other properties are evaluated on a specific asset basis or in groups of similar assets, as applicable. Impairment is indicated when a triggering event occurs and/or the sum of the estimated undiscounted future net cash flows of an evaluated asset is less than the asset's carrying value. Triggering events could include, but are not limited to, a reduction of oil, gas and NGL reserves caused by mechanical problems, faster-than-expected decline of production, lease ownership issues, and declines in oil, gas and NGL prices. If impairment is indicated, fair value is estimated using a discounted cash flow approach. Cash flow estimates require forecasts and assumptions for many years into the future for a variety of factors, including commodity prices, operating costs and estimates of proved, probable and possible reserves. Cash flow estimates relating to future cash flows from probable and possible reserves are reduced by additional risk-weighting factors. Unproved properties are evaluated on a specific asset basis or in groups of similar assets, as applicable. The Company performs periodic assessments of unproved oil and gas properties for impairment and recognizes a loss at the time of impairment. In determining whether an unproved property is impaired, the Company considers numerous factors including, but not limited to, current development and exploration drilling plans, favorable or unfavorable exploration activity on adjacent leaseholds, in-house geologists' evaluation of the lease, future reserve cash flows and the remaining lease term. During the year ended December 31, 2017 , QEP recorded impairment charges of $78.9 million , of which $38.1 million was related to proved properties due to lower future gas prices, $29.0 million was primarily related to unproved leasehold acreage in the Central Basin Platform (Refer to Note 3 – Capitalized Exploratory Well Costs for additional information), $6.5 million was related to impairment of an underground gas storage facility and $5.3 million was related to the impairment of goodwill. Of the $38.1 million impairment of proved properties, $37.1 million related to the Other Northern area and $1.0 million related to Louisiana properties. During the year ended December 31, 2016 , QEP recorded impairment charges of $1,194.3 million , of which $1,172.7 million was related to proved properties due to lower future oil and gas prices, $17.9 million was related to expiring leaseholds on unproved properties and $3.7 million was related to the impairment of goodwill. Of the $1,172.7 million impairment of proved properties, $1,164.0 million related to Pinedale properties, $4.7 million related to Uinta Basin properties, $3.4 million related to the Other Northern area and $0.6 million related to QEP's remaining Other Southern properties. During the year ended December 31, 2015 , QEP recorded impairment charges of $55.6 million , of which $39.3 million was related to proved properties due to lower future oil and gas prices, $2.0 million was related to expiring leaseholds on unproved properties and $14.3 million was related to the impairment of goodwill. Of the $39.3 million impairment on proved properties, $20.2 million related to QEP's remaining Other Southern properties, $18.4 million related Other Northern properties, and $0.7 million related to Permian Basin properties. Asset Retirement Obligations QEP is obligated to fund the costs of disposing of long-lived assets upon their abandonment. The Company's ARO liability applies primarily to abandonment costs associated with oil and gas wells and certain other properties. ARO associated with the retirement of tangible long-lived assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived assets in the period incurred. The cost of the tangible asset, including the asset retirement costs, is depreciated over the useful life of the asset. ARO are recorded at estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligations discounted at the Company's credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. If estimated future costs of ARO change, an adjustment is recorded to both the ARO liability and the long-lived asset. Revisions to estimated ARO can result from changes in retirement cost estimates, revisions to estimated inflation rates and changes in the estimated timing of abandonment. Refer to Note 4 – Asset Retirement Obligations for additional information. |
Goodwill [Policy Text Block] | Goodwill Goodwill represents the excess of the amount paid over the fair value of assets acquired in a business combination and is not subject to amortization. During the year ended December 31, 2017 , QEP early adopted ASU 2017-04, Intangibles – Goodwill and Other (Topic 350): Simplifying the test for goodwill impairment . Under the new guidance QEP performs an annual goodwill impairment test by comparing the fair value of a reporting unit with its carry amount, with an impairment charge being recognized for the amount by which the carrying amount exceeds the reporting unit's fair value. QEP determines the fair value of its reporting units in which goodwill is allocated using the income approach in which the fair value is estimated based on the value of expected future cash flows. Key assumptions used in the cash flow model include estimated quantities of oil, gas and NGL reserves, including both proved reserves and risk-adjusted unproved reserves, and including probable and possible reserves; estimates of market prices considering forward commodity price curves as of the measurement date; estimates of revenue and operating costs over a multi-year period; and estimates of capital costs. During the year ended December 31, 2017 , QEP recorded $5.3 million of goodwill, which related to an acquisition in the first quarter of 2017. During the fourth quarter of 2017, QEP performed an annual impairment test over goodwill as described above, which resulted in a full write down of goodwill of $5.3 million . During the years ended December 31, 2016 and 2015 , QEP recorded $3.7 million and $14.3 million , respectively, of goodwill. Annual impairment tests over goodwill at year end December 31, 2016 and 2015 resulted in a full write down of $3.7 million and $14.3 million , respectively. |
Litigation and Other Contingencies [Policy Text Block] | Litigation and Other Contingencies The Company is involved in various commercial and regulatory claims, litigation and other legal proceedings that arise in the ordinary course of its business. In each reporting period, the Company assesses these claims in an effort to determine the degree of probability and range of possible loss for potential accrual in its Consolidated Financial Statements. The amount of ultimate loss may differ from these estimates. In accordance with ASC 450, Contingencies , an accrual is recorded for a material loss contingency when its occurrence is probable and damages are reasonably estimable based on the anticipated most likely outcome or the minimum amount within a range of possible outcomes. Refer to Note 9 – Commitments and Contingencies for additional information. QEP accrues material losses associated with environmental obligations when such losses are probable and can be reasonably estimated. Accruals for estimated environmental losses are recognized no later than at the time the remediation feasibility study, or the evaluation of response options, is complete. These accruals are adjusted as additional information becomes available or as circumstances change. Future environmental expenditures are not discounted to their present value. Recoveries of environmental costs from other parties are recorded separately as assets at their undiscounted value when receipt of such recoveries is probable. |
Derivative Contracts [Policy Text Block] | Derivative Contracts QEP has established policies and procedures for managing commodity price volatility through the use of derivative instruments. QEP uses commodity derivative instruments, typically fixed-price swaps and costless collars to realize a known price or price range for a specific volume of production delivered into a regional sales point. QEP's commodity derivative instruments do not require the physical delivery of oil or gas between the parties at settlement. All transactions are settled in cash with one party paying the other for the net difference in prices, multiplied by the contract volume, for the settlement period. QEP does not engage in speculative hedging transactions, nor does it buy and sell energy contracts with the objective of generating profits on short-term differences in price. Additionally, QEP does not currently have any commodity derivative transactions that have margin requirements or collateral provisions that would require payments prior to the scheduled settlement dates. These derivative contracts are recorded in "Realized and unrealized gains (losses) on derivative contracts" on the Consolidated Statements of Operations in the month of settlement and are also marked-to-market monthly. Refer to Note 6 – Derivative Contracts for additional information. |
Credit Risk [Policy Text Block] | Credit Risk Management believes that its credit review procedures, loss reserves, cash deposits and investments, and collection procedures have adequately provided for usual and customary credit-related losses. Exposure to credit risk may be affected by extended periods of low commodity prices, as well as the concentration of customers in certain regions due to changes in economic or other conditions. Customers include commercial and industrial enterprises and financial institutions that may react differently to changing conditions. The Company utilizes various processes to monitor and evaluate its credit risk exposure, which include closely monitoring current market conditions and counterparty credit fundamentals, including public credit ratings, where available. Credit exposure is controlled through credit approvals and limits based on counterparty credit fundamentals, and is aggregated across all lines of business, including derivatives, physical exposure and short-term cash investments. To further manage the level of credit risk, the Company requests credit support and, in some cases, requests parental guarantees, letters of credit or prepayment from companies with perceived higher credit risk. Loss reserves are periodically reviewed for adequacy and may be established on a specific case basis. The Company also has master-netting agreements with some counterparties that allow the offsetting of receivables and payables in a default situation. The Company enters into International Swap Dealers Association Master Agreements (ISDA Agreements) with each of its derivative counterparties prior to executing derivative contracts. 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 counterparty to a derivative contract. The Company routinely monitors and manages its exposure to counterparty risk related to derivative contracts by requiring specific minimum credit standards for all counterparties, actively monitoring counterparties public credit ratings, and avoiding concentration of credit exposure by transacting with multiple counterparties. The Company's commodity derivative contract counterparties are typically financial institutions and energy trading firms with investment-grade credit ratings. The Company's five largest customers accounted for 59% , 48% , and 30% of QEP's revenues for the years ended December 31, 2017 , 2016 and 2015 , respectively. During the year ended December 31, 2017 , Shell Trading Company , Occidental Energy Marketing , Andeavor Logistics LP , BP Energy Company and Plains Marketing LP accounted for 14% , 13% , 13% , 10% and 10% , respectively, of QEP's total revenues. During the year ended December 31, 2016 , Shell Trading Company , BP Energy Company and Valero Marketing & Supply Company accounted for 14% , 10% and 10% , respectively, of QEP's total revenues. During the year ended December 31, 2015 , no customer accounted for 10% or more of QEP's total revenues. Management believes that the loss of any of these customers, or any other customer, would not have a material effect on the financial position or results of operations of QEP, since there are numerous potential purchasers of its production. |
Income Taxes [Policy Text Block] | Income Taxes The amount of income taxes recorded by QEP requires interpretations of complex rules and regulations of various tax jurisdictions throughout the United States. QEP has recognized deferred tax assets and liabilities for temporary differences, operating losses and tax credit carryforwards. Deferred income taxes are provided for the temporary differences arising between the book and tax carrying amounts of assets and liabilities. These differences create taxable or tax-deductible amounts for future periods. ASC 740, Income Taxes, specifies the accounting for uncertainty in income taxes by prescribing a minimum recognition threshold for a tax position to be reflected in the financial statements. If recognized, the tax benefit is measured as the largest amount of tax benefit that is more-likely-than-not to be realized upon ultimate settlement. Management has considered the amounts and the probabilities of the outcomes that could be realized upon ultimate settlement and believes that it is more-likely-than-not that the Company's recorded income tax benefits will be fully realized, except as noted below. As of December 31, 2017 , the Company had a valuation allowance of $56.8 million against the state net operating loss deferred tax asset because management does not forecast future income in Oklahoma and Louisiana to offset net operating losses before they expire. All federal income tax returns prior to 2017 have been examined by the Internal Revenue Service and are closed. Income tax returns for 2017 have not yet been filed. Most state tax returns for 2014 and subsequent years remain subject to examination. The benefits of uncertain tax positions taken or expected to be taken on income tax returns is recognized in the consolidated financial statements at the largest amount that is more-likely-than-not to be sustained upon examination by the relevant taxing authorities. Our policy is to recognize any interest earned on income tax refunds in "Interest and other income (expense)" on the Consolidated Statements of Operations, any interest expense related to uncertain tax positions in "Interest expense" on the Consolidated Statements of Operations and to recognize any penalties related to uncertain tax positions in "General and administrative" expense on the Consolidated Statements of Operations. As of December 31, 2017 and 2016 , QEP had $19.0 million and $15.6 million of unrecognized tax benefits related to uncertain tax positions for asset sales that occurred in 2014, which was included within "Other long-term liabilities" on the Consolidated Balance Sheets. During the year ended December 31, 2017 , the Company incurred $0.7 million of estimated interest expense related to uncertain tax positions. During the year ended December 31, 2016 , the Company incurred $0.7 million of estimated interest expense and $0.6 million of estimated penalties related to uncertain tax positions. During the year ended December 31, 2015 , the Company incurred $0.5 million of estimated interest expense and $2.2 million of estimated penalties related to uncertain tax positions. |
Treasury Stock [Policy Text Block] | Treasury Stock We record treasury stock purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as a reduction in shareholders' equity in the Consolidated Balance Sheets. QEP acquires treasury stock from stock forfeitures and withholdings and uses the acquired treasury stock for stock option exercises and certain stock grants to employees; refer to Note 10 – Share-Based Compensation for additional information. |
Earnings Per Share [Policy Text Block] | Earnings (Loss) Per Share Basic earnings (loss) per share (EPS) are computed by dividing net income (loss) by the weighted-average number of common shares outstanding during the reporting period. Diluted EPS includes the potential increase in the number of outstanding shares that could result from the exercise of in-the-money stock options. QEP's unvested restricted share awards are included in weighted-average basic common shares outstanding because, once the shares are granted, the restricted share awards are considered issued and outstanding, the historical forfeiture rate is minimal and the restricted share awards are eligible to receive dividends. Unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents are considered participating securities and are included in the computation of earnings (loss) per share pursuant to the two-class method. The Company's unvested restricted share awards contain non-forfeitable dividend rights and participate equally with common stock with respect to dividends issued or declared. However, the Company's unvested restricted share awards do not have a contractual obligation to share in losses of the Company. The Company's unexercised stock options do not contain rights to dividends. Under the two-class method, the earnings used to determine basic earnings (loss) per common share are reduced by an amount allocated to participating securities. When the Company records a net loss, none of the loss is allocated to the participating securities since the securities are not obligated to share in Company losses. Use of the two-class method has an insignificant impact on the calculation of basic and diluted earnings (loss) per common share. For the years ended December 31, 2017 and 2015 , there were no anti-dilutive shares. For the year ended December 31, 2016 , there were 0.1 million shares not included in diluted common shares outstanding as they were anti-dilutive due to QEP's net loss from continuing operations. The following is a reconciliation of the components of basic and diluted shares used in the EPS calculation: December 31, 2017 2016 2015 (in millions) Weighted-average basic common shares outstanding 240.6 221.7 176.6 Potential number of shares issuable upon exercise of in-the-money stock options under the Long-Term Stock Incentive Plan — — — Average diluted common shares outstanding 240.6 221.7 176.6 |
Share-based Compensation [Policy Text Block] | Share-Based Compensation QEP issues stock options, restricted share awards and restricted share units to certain officers, employees and non-employee directors under its Long-Term Stock Incentive Plan (LTSIP). QEP uses the Black-Scholes-Merton mathematical model to estimate the fair value of stock options for accounting purposes. The grant date fair value for restricted share awards is determined based on the closing bid price of the Company's common stock on the grant date. Share-based compensation cost for restricted share units is equal to its fair value as of the end of the period and is classified as a liability. QEP uses an accelerated method in recognizing share-based compensation costs for stock options and restricted share awards with graded-vesting periods. Stock options held by employees generally vest in three equal, annual installments and primarily have a term of seven years. Restricted share awards and restricted share units vest in equal installments over a specified number of years after the grant date with the majority vesting in three years. Non-vested restricted share awards have voting and dividend rights; however, sale or transfer is restricted. Employees may elect to defer their grants of restricted share awards and these deferred awards are designated as restricted share units. Restricted share units vest over a three-year period and are deferred into the Company's nonqualified unfunded deferred compensation plan at the time of vesting. The Company also awards performance share units under its CIP that are generally paid out in cash depending upon the Company's total shareholder return compared to a group of its peers over a three-year period. Share-based compensation cost for the performance share units is equal to its fair value as of the end of the period and is classified as a liability. For additional information, refer to Note 10 – Share-Based Compensation for additional information. |
Pension and Other Postretirement Benefits [Policy Text Block] | Pension and Other Postretirement Benefits QEP maintains closed, defined-benefit pension and other postretirement benefit plans, including both a qualified and a supplemental plan. QEP also provides certain health care and life insurance benefits for certain retired QEP employees. Determination of the benefit obligations for QEP's defined-benefit pension and other postretirement benefit plans impacts the recorded amounts for such obligations on the Consolidated Balance Sheets and the amount of benefit expense recorded to the Consolidated Statements of Operations. QEP measures pension plan assets at fair value. Defined-benefit plan obligations and costs are actuarially determined, incorporating the use of various assumptions. Critical assumptions for pension and other postretirement benefit plans include the discount rate, the expected rate of return on plan assets (for funded pension plans) and the rate of future compensation increases. Other assumptions involve demographic factors such as retirement, mortality and turnover. QEP evaluates and updates its actuarial assumptions at least annually. QEP recognizes a pension curtailment immediately when there is a significant reduction in, or an elimination of, defined-benefit accruals for present employees' future services. Refer to Note 11 – Employee Benefits for additional information. |
Comprehensive Income [Policy Text Block] | Comprehensive Income (Loss) Comprehensive income (loss) is the sum of net income (loss) as reported in the Consolidated Statements of Operations and changes in the components of other comprehensive income. Other comprehensive income (loss) includes certain items that are recorded directly to equity and classified as accumulated other comprehensive income (AOCI), which includes changes in the underfunded portion of the Company's defined-benefit pension and other postretirement benefits plans and changes in deferred income taxes on such amounts. These transactions do not represent the culmination of the earnings process but result from periodically adjusting historical balances to fair value. |
Recent Accounting Developments [Policy Text Block] | Recent Accounting Developments In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2014-09, Revenue from Contracts with Customers (Topic 606) , which seeks to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability within industries, across industries and across capital markets. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing of when it is recognized. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. In addition, new and enhanced disclosures will be required. The amendment is effective prospectively for reporting periods beginning on or after December 15, 2017, and early adoption is permitted for periods beginning on or after December 15, 2016. The two permitted transition methods under the new standard are the full retrospective method, in which case the standard would be applied to each prior reporting period presented, or the modified retrospective method, in which case the cumulative effect of applying the standard would be recognized at the date of initial application. The Company does not expect net income (loss) or cash flows to be materially impacted by the new standard; however, the Company expects that a portion of its transportation and processing costs will be netted within revenue under the new standard. In addition, the Company will have expanded disclosure requirements, as a result of the adoption of the ASU. The Company has selected the modified retrospective method and will adopt this guidance on the effective date of January 1, 2018. In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) , which requires lessees to recognize the lease assets and lease liabilities classified as operating leases on the balance sheet and disclose key quantitative and qualitative information about leasing arrangements. The amendment will be effective for reporting periods beginning after December 15, 2018, and early adoption is permitted. The Company is currently assessing the impact of the ASU on the Company's Consolidated Financial Statements. In March 2016, the FASB issued ASU No. 2016-06, Derivatives and hedging (Topic 815): Contingent put and call options in debt instruments , which clarifies the requirements for assessing whether contingent call (put) options that can accelerate the payment of principal on debt instruments are clearly and closely related to their debt hosts. The amendment was effective prospectively for reporting periods beginning on or after December 15, 2016, and early adoption was permitted. The Company adopted this standard in the first quarter of 2017 and the adoption of this new standard did not have a material impact on the Company's Consolidated Financial Statements. In March 2016, the FASB issued ASU No. 2016-09, Compensation – Stock Compensation (Topic 718): Improvements to employee share-based payment accounting, which includes provisions intended to simplify various aspects related to how share-based compensation payments are accounted for and presented in the financial statements. This amendment was effective prospectively for reporting periods beginning after December 15, 2016, and early adoption was permitted. The Company adopted this standard in the first quarter of 2017 and the adoption of this new standard did not have a material impact on the Company's Consolidated Financial Statements. In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of certain cash receipts and cash payments , which intends to reduce the diversity in practice in how certain transactions are classified in the statement of cash flows. This amendment will be effective retrospectively for reporting periods beginning after December 15, 2017, and early adoption is permitted. The Company early adopted this standard in the fourth quarter of 2017 and the adoption of this standard did not have a material impact on the Company's Consolidated Financial Statements. In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the definition of a business , which clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of businesses. The amendment will be effective prospectively for reporting periods beginning after December 15, 2017, and early adoption is permitted. The Company early adopted this standard in the fourth quarter of 2017 and the adoption of this standard did not have a material impact on the Company's Consolidated Financial Statements; however, this standard may impact the determination of whether future acquisitions are accounted for as a business combination or an asset acquisition. In January 2017, the FASB issued ASU No. 2017-04, Intangibles – Goodwill and Other (Topic 350): Simplifying the test for goodwill impairment , which eliminates the requirement to calculate implied fair value of goodwill to measure the goodwill impairment charge. The amendment will be effective prospectively for reporting periods beginning after December 15, 2019, and early adoption is permitted. The Company early adopted this standard in the first quarter of 2017 and the adoption of this new standard did not have a material impact on the Company's Consolidated Financial Statements. In March 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the presentation of net periodic pension cost and net periodic postretirement benefit cost , which changes how employers of a defined benefit plan present net periodic benefit cost in the statements of operations. The amendment will be effective retrospectively for reporting periods beginning after December 15, 2017, and early adoption is permitted. The Company early adopted this standard in the first quarter of 2017 and recast the years ended December 31, 2016 and 2015 . The adoption of this new standard did not have a material impact on the Company's Consolidated Financial Statements. Refer to Note 11 – Employee Benefits for additional information regarding the Company's pension and other postretirement plans. |
Summary of Significant Accoun25
Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Summary of Significant Accounting Policies [Abstract] | |
Supplemental Cash Flow Information [Table Text Block] | Supplemental cash flow information is shown in the table below: Year Ended December 31, 2017 2016 2015 Supplemental Disclosures (in millions) Cash paid for interest, net of capitalized interest $ 134.9 $ 139.1 $ 139.4 Cash paid (refund received) for income taxes, net $ (0.3 ) $ (123.5 ) $ 487.8 Non-cash investing activities Change in capital expenditure accrual balance $ 60.2 $ (32.8 ) $ (129.2 ) |
Property, Plant and Equipment [Table Text Block] | Buildings 10 to 30 years Leasehold improvements 3 to 10 years Service, transportation and field service equipment 3 to 7 years Furniture and office equipment 3 to 7 years |
Schedule of Earnings Per Share, Basic and Diluted [Table Text Block] | The following is a reconciliation of the components of basic and diluted shares used in the EPS calculation: December 31, 2017 2016 2015 (in millions) Weighted-average basic common shares outstanding 240.6 221.7 176.6 Potential number of shares issuable upon exercise of in-the-money stock options under the Long-Term Stock Incentive Plan — — — Average diluted common shares outstanding 240.6 221.7 176.6 |
Acquisitions and Divestitures (
Acquisitions and Divestitures (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Business Combinations [Abstract] | |
Schedule of Purchase Price Allocation [Table Text Block] | Consideration: Total consideration $ 591.0 Amounts recognized for fair value of assets acquired and liabilities assumed: Proved properties $ 406.2 Unproved properties 214.2 Asset retirement obligations (11.6 ) Bargain purchase gain (17.8 ) Total fair value $ 591.0 |
Business Acquisition, Pro Forma Information [Table Text Block] | Year ended December 31, 2016 Actual Pro forma (in millions, except per share amounts) Revenues $ 1,377.1 $ 1,392.5 Net income (loss) $ (1,245.0 ) $ (1,246.8 ) Earnings (loss) per common share Basic $ (5.62 ) $ (5.62 ) Diluted $ (5.62 ) $ (5.62 ) |
Capitalized Exploratory Well 27
Capitalized Exploratory Well Costs (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Capitalized Exploratory Well Costs [Abstract] | |
Capitalized Exploratory Well Costs, Roll Forward [Table Text Block] | Capitalized Exploratory Well Costs 2017 2016 2015 (in millions) Balance at January 1, $ 14.2 $ 2.6 $ 12.6 Additions to capitalized exploratory well costs 10.7 11.7 6.0 Reclassifications to proved properties (3.6 ) — (16.0 ) Capitalized exploratory well costs charged to expense (21.3 ) (0.1 ) — Balance at December 31, $ — $ 14.2 $ 2.6 |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Asset Retirement Obligation [Abstract] | |
Schedule of Change in Asset Retirement Obligation [Table Text Block] | The following is a reconciliation of the changes in the Company's ARO for the periods specified below: Asset Retirement Obligations 2017 2016 (in millions) ARO liability at January 1, $ 231.6 $ 206.8 Accretion 7.7 8.9 Additions (1) 23.5 17.0 Revisions 8.5 6.5 Liabilities related to assets sold (2) (34.9 ) — Liabilities settled (22.3 ) (7.6 ) ARO liability at December 31, $ 214.1 $ 231.6 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Fair Value Disclosures [Abstract] | |
Fair value and related carrying amount of certain financial instruments | The fair value of financial assets and liabilities at December 31, 2017 and 2016 , is shown in the table below: Fair Value Measurements Gross Amounts of Assets and Liabilities Netting Adjustments (1) Net Amounts Presented on the Consolidated Balance Sheets Level 1 Level 2 Level 3 (in millions) December 31, 2017 Financial Assets Fair value of derivative contracts – short-term $ — $ 20.6 $ — $ (17.2 ) $ 3.4 Fair value of derivative contracts – long-term — 2.3 — (2.2 ) 0.1 Total financial assets $ — $ 22.9 $ — $ (19.4 ) $ 3.5 Financial Liabilities Fair value of derivative contracts – short-term $ — $ 120.8 $ — $ (17.2 ) $ 103.6 Fair value of derivative contracts – long-term — 34.0 — (2.2 ) 31.8 Total financial liabilities $ — $ 154.8 $ — $ (19.4 ) $ 135.4 December 31, 2016 Financial Assets Fair value of derivative contracts – short-term $ — $ — $ — $ — $ — Fair value of derivative contracts – long-term — — — — — Total financial assets $ — $ — $ — $ — $ — Financial Liabilities Fair value of derivative contracts – short-term $ — $ 169.8 $ — $ — $ 169.8 Fair value of derivative contracts – long-term — 32.0 — — 32.0 Total financial liabilities $ — $ 201.8 $ — $ — $ 201.8 The following table discloses the fair value and related carrying amount of certain financial instruments not disclosed in other Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K: Carrying Amount Level 1 Fair Value Carrying Amount Level 1 Fair Value December 31, 2017 December 31, 2016 Financial Assets (in millions) Cash and cash equivalents $ — $ — $ 443.8 $ 443.8 Financial Liabilities Checks outstanding in excess of cash balances $ 44.0 $ 44.0 $ 12.3 $ 12.3 Long-term debt $ 2,160.8 $ 2,256.2 $ 2,020.9 $ 2,104.3 |
Derivative Contracts (Tables)
Derivative Contracts (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative Volumes and Average Prices | Derivative Contracts – Production The following table presents QEP's volumes and average prices for its commodity derivative swap contracts as of December 31, 2017 : Year Index Total Volumes Average Swap Price per Unit (in millions) Oil sales (bbls) ($/bbl) 2018 NYMEX WTI 16.8 $ 52.48 2019 NYMEX WTI 8.0 $ 51.78 Gas sales (MMBtu) ($/MMBtu) 2018 (Full Year) NYMEX HH 109.5 $ 2.99 2018 (July through December) NYMEX HH 1.8 $ 3.01 2019 NYMEX HH 36.5 $ 2.88 QEP uses oil and gas basis swaps, combined with NYMEX WTI and NYMEX HH fixed price swaps, to achieve fixed price swaps for the location at which it sells its physical production. The following table presents details of QEP's oil and gas basis swaps as of December 31, 2017 : Year Index Less Differential Index Total Volumes Weighted-Average Differential (in millions) Oil sales (bbls) ($/bbl) 2018 (Full Year) NYMEX WTI Argus WTI Midland 7.3 $ (1.06 ) 2018 (July through December) NYMEX WTI Argus WTI Midland 0.9 $ (0.71 ) 2019 NYMEX WTI Argus WTI Midland 4.0 $ (0.80 ) Gas sales (MMBtu) ($/MMBtu) 2018 NYMEX HH IFNPCR 7.3 $ (0.16 ) Derivative Contracts – Gas Storage QEP enters into commodity derivative transactions to lock in a margin on gas volumes placed into storage. The following table presents QEP's volumes and average prices for its gas storage commodity derivative swap contracts as of December 31, 2017 : Year Type of Contract Index Total Volumes Average Swap Price per Unit (in millions) Gas sales (MMBtu) ($/MMBtu) 2018 SWAP IFNPCR 0.6 $ 3.06 |
Fair values of Derivatives by Balance Sheet Location | Gross asset derivative Gross liability derivative December 31, Balance Sheet line item 2017 2016 2017 2016 Current: (in millions) Commodity Fair value of derivative contracts $ 20.6 $ — $ 120.8 $ 169.8 Long-term: Commodity Fair value of derivative contracts 2.3 — 34.0 32.0 Total derivative instruments $ 22.9 $ — $ 154.8 $ 201.8 |
Effects of Derivative Transactions | Derivative contracts not designated as cash flow hedges Year Ended December 31, 2017 2016 2015 Realized gains (losses) on commodity derivative contracts (in millions) Production Oil derivative contracts $ 6.8 $ 86.3 $ 353.7 Gas derivative contracts (22.3 ) 44.8 103.4 Gas Storage Gas derivative contracts — 2.9 3.8 Realized gains (losses) on commodity derivative contracts (15.5 ) 134.0 460.9 Unrealized gains (losses) on commodity derivative contracts Production Oil derivative contracts (66.2 ) (217.2 ) (244.9 ) Gas derivative contracts 133.6 (145.4 ) 62.0 Gas Storage Gas derivative contracts 2.5 (4.4 ) (0.8 ) Unrealized gains (losses) on commodity derivative contracts 69.9 (367.0 ) (183.7 ) Total realized and unrealized gains (losses) on commodity derivative contracts related to production and storage contracts $ 54.4 $ (233.0 ) $ 277.2 Derivatives associated with the Pinedale Divestiture (1) Unrealized gains (losses) on commodity derivative contracts Production Oil derivative contracts $ (1.3 ) $ — $ — Gas derivative contracts (23.5 ) — — NGL derivative contracts (5.1 ) — — Unrealized gains (losses) on commodity derivative contracts related to the Pinedale Divestiture $ (29.9 ) $ — $ — Total realized and unrealized gains (losses) on commodity derivative contracts $ 24.5 $ (233.0 ) $ 277.2 _______________________ (1) The unrealized gains (losses) on commodity derivative contracts related to the Pinedale Divestiture are comprised of derivatives entered into in conjunction with the execution of the Pinedale purchase and sale agreement, which were subsequently novated to the buyer upon the closing of the sale in September 2017. Refer to Note 2 – Acquisitions and Divestitures for more information. The unrealized gains (losses) on commodity derivatives associated with the Pinedale Divestiture are offset by an equal amount recorded within "Net gain (loss) from asset sales" on the Consolidated Statements of Operations. |
Debt (Tables)
Debt (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Debt Disclosure [Abstract] | |
Debt Outstanding | December 31, 2017 2016 (in millions) Revolving Credit Facility due 2022 $ 89.0 $ — 6.80% Senior Notes due 2018 (1) — 134.0 6.80% Senior Notes due 2020 (1) 51.7 136.0 6.875% Senior Notes due 2021 (1) 397.6 625.0 5.375% Senior Notes due 2022 500.0 500.0 5.25% Senior Notes due 2023 650.0 650.0 5.625% Senior Notes due 2026 (1) 500.0 — Less: unamortized discount and unamortized debt issuance costs (27.5 ) (24.1 ) Total long-term debt outstanding $ 2,160.8 $ 2,020.9 |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Unrecorded Unconditional Purchase Obligations Disclosure [Table Text Block] | Annual payments and the corresponding years for gathering, processing, transportation, storage, drilling, and fractionation contracts are as follows (in millions): Year Amount 2018 $ 95.6 2019 $ 68.4 2020 $ 54.9 2021 $ 29.9 2022 $ 28.3 After 2022 $ 122.5 |
Operating Leases of Lessee Disclosure [Table Text Block] | Minimum future payments under the terms of long-term operating leases for the Company's primary office locations are as follows (in millions): Year Amount 2018 $ 7.0 2019 $ 7.2 2020 $ 7.4 2021 $ 7.4 2022 $ 7.2 After 2022 $ 4.8 |
Share-Based Compensation (Table
Share-Based Compensation (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Share-based Compensation [Abstract] | |
Share-based Compensation Expense [Table Text Block] | Year Ended December 31, 2017 2016 2015 (in millions) Stock options $ 2.3 $ 2.3 $ 2.9 Restricted share awards 24.6 23.7 25.6 Performance share units (4.5 ) 9.4 6.2 Restricted share units — 0.2 — Total share-based compensation expense $ 22.4 $ 35.6 $ 34.7 |
Schedule of calculated fair value of options granted and major assumptions used [Table Text Block] | The calculated fair value of options granted and major assumptions used in the model at the date of grant are listed below: Stock Option Assumptions Year Ended December 31, 2017 2016 2015 Weighted-average grant date fair value of awards granted during the period $ 6.44 $ 3.77 $ 6.82 Risk-free interest rate range 1.66% - 1.81% 0.99% - 1.15% 1.38% - 1.38% Weighted-average risk-free interest rate 1.8 % 1.2 % 1.4 % Expected price volatility range 43.82% - 46.70% 43.42% - 43.66% 36.8% - 36.8% Weighted-average expected price volatility 43.9 % 43.4 % 36.8 % Expected dividend yield — % — % 0.37 % Expected term in years at the date of grant 4.5 4.5 4.5 |
Stock Options Activity [Table Text Block] | Stock option transactions under the terms of the LTSIP are summarized below: Options Outstanding Weighted-Average Exercise Price Weighted-Average Remaining Contractual Term Aggregate Intrinsic Value (per share) (in years) (in millions) Outstanding at December 31, 2016 2,151,957 $ 25.26 Granted 418,752 16.77 Forfeited (14,172 ) 15.33 Cancelled (202,260 ) 27.55 Outstanding at December 31, 2017 2,354,277 $ 23.62 3.50 $ — Options Exercisable at December 31, 2017 1,551,861 $ 27.90 2.47 $ — Unvested Options at December 31, 2017 802,416 $ 15.33 5.48 $ — |
Restricted Share Awards Activity [Table Text Block] | Transactions involving restricted share awards under the terms of the LTSIP are summarized below: Restricted Share Awards Outstanding Weighted-Average Grant Date Fair Value (per share) Unvested balance at December 31, 2016 3,208,503 $ 14.32 Granted 2,219,763 13.90 Vested (1,392,043 ) 16.53 Forfeited (314,889 ) 14.49 Unvested balance at December 31, 2017 3,721,334 $ 13.23 |
Performance Share Units Activity [Table Text Block] | Performance Share Units Outstanding Weighted-Average Grant Date Fair Value (per share) Unvested balance at December 31, 2016 1,027,280 $ 17.24 Granted 405,014 16.90 Vested and paid (215,439 ) 31.63 Forfeited (17,519 ) 13.88 Unvested balance at December 31, 2017 1,199,336 $ 14.59 |
Restricted Share Units Activity [Table Text Block] | Transactions involving restricted share units under the terms of the LTSIP are summarized below: Restricted Share Units Outstanding Weighted-Average Grant Date Fair Value (per share) Unvested balance at December 31, 2016 18,034 $ 10.12 Granted 9,924 16.98 Vested (6,012 ) 10.12 Unvested balance at December 31, 2017 21,946 $ 13.22 |
Employee Benefits (Tables)
Employee Benefits (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |
Schedule of Defined Benefit Plans Disclosures [Table Text Block] | The following table sets forth changes in the benefit obligations and fair value of plan assets for the Company's Pension Plan, SERP and Medical Plan for the years ended December 31, 2017 and 2016 , as well as the funded status of the plans and amounts recognized in the financial statements at December 31, 2017 and 2016 : Pension Plan and SERP benefits Medical Plan benefits 2017 2016 2017 2016 Change in benefit obligation (in millions) Benefit obligation at January 1, $ 129.2 $ 120.3 $ 5.4 $ 5.2 Service cost 0.8 1.2 — — Interest cost 4.7 5.2 0.1 0.2 Curtailments (0.3 ) — — — Benefit payments (6.9 ) (7.8 ) (0.1 ) (0.4 ) Plan amendments — — (2.4 ) — Actuarial loss (gain) 2.5 10.3 (0.1 ) 0.4 Benefit obligation at December 31, $ 130.0 $ 129.2 $ 2.9 $ 5.4 Change in plan assets Fair value of plan assets at January 1, $ 86.1 $ 79.3 $ — $ — Actual return on plan assets 15.3 7.4 — — Company contributions to the plan 6.0 7.2 0.1 0.4 Benefit payments (6.9 ) (7.8 ) (0.1 ) (0.4 ) Fair value of plan assets at December 31, 100.5 86.1 — — Underfunded status (current and long-term) $ (29.5 ) $ (43.1 ) $ (2.9 ) $ (5.4 ) Amounts recognized in balance sheets Accounts payable and accrued expenses $ (1.5 ) $ (2.5 ) $ (0.2 ) $ (0.3 ) Other long-term liabilities (27.9 ) (40.6 ) (2.6 ) (5.1 ) Total amount recognized in balance sheet $ (29.4 ) $ (43.1 ) $ (2.8 ) $ (5.4 ) Amounts recognized in AOCI Net actuarial loss (gain) $ 15.0 $ 23.5 $ (0.5 ) $ (0.4 ) Prior service cost 1.2 2.9 (1.2 ) 1.0 Total amount recognized in AOCI $ 16.2 $ 26.4 $ (1.7 ) $ 0.6 |
Pension and Other Postretirement Benefit Costs | The following table sets forth the Company's Pension Plan, SERP and Medical Plan cost and amounts recognized in other comprehensive income (before tax) for the respective years ended December 31 : Pension Plan and SERP benefits Medical Plan benefits 2017 2016 2015 2017 2016 2015 Components of net periodic benefit cost (in millions) Service cost $ 0.8 $ 1.2 $ 2.1 $ — $ — $ — Interest cost 4.7 5.2 4.9 0.1 0.2 0.2 Expected return on plan assets (5.4 ) (5.6 ) (5.7 ) — — — Curtailment loss 0.7 — 11.2 — — — Settlements 0.2 — — — — — Amortization of prior service costs 1.0 1.1 1.7 (0.3 ) 0.2 0.2 Amortization of actuarial loss 0.5 0.8 0.5 (0.1 ) — — Periodic expense $ 2.5 $ 2.7 $ 14.7 $ (0.3 ) $ 0.4 $ 0.4 Components recognized in accumulated other comprehensive income Current period prior service cost $ (0.7 ) $ — $ 0.9 $ (2.5 ) $ — $ — Current period actuarial (gain) loss (7.5 ) 8.5 2.2 (0.1 ) 0.4 (1.4 ) Amortization of prior service cost (1.0 ) (1.1 ) (12.9 ) 0.3 (0.2 ) (0.2 ) Amortization of actuarial gain (loss) (0.5 ) (0.8 ) (0.5 ) 0.1 — — Loss on curtailment in current period (0.3 ) — (7.1 ) — — — Settlements (0.2 ) — — — — — Total amount recognized in accumulated other comprehensive income $ (10.2 ) $ 6.6 $ (17.4 ) $ (2.2 ) $ 0.2 $ (1.6 ) |
Schedule of Assumptions Used [Table Text Block] | Following are the weighted-average assumptions (weighted by the plan level benefit obligation for pension benefits) used by the Company to calculate the Pension Plan, SERP and Medical Plan obligations at December 31, 2017 and 2016 : Pension Plan and SERP benefits Medical Plan benefits 2017 2016 2017 2016 Discount rate 3.52 % 3.96 % 3.60 % 4.10 % Rate of increase in compensation (1) 3.50 % 3.50 % n/a 3.50 % _______________________ (1) The Pension Plan was frozen effective January 1, 2016, and as a result, the rate of increase in compensation for participants is no longer considered an assumption used by the Company to calculate the value of the Pension Plan. As such, for the years ended December 31, 2017 and 2016 , the rate of increase in compensation only includes the SERP and Medical Plan. The discount rate assumptions used by the Company represents an estimate of the interest rate at which the Pension Plan, SERP and Medical Plan obligations could effectively be settled on the measurement date. Following are the weighted-average assumptions (weighted by the net period benefit cost for pension benefits) used by the Company in determining the net periodic Pension Plan, SERP and Medical Plan cost for the years ended December 31: Pension Plan and SERP benefits Medical Plan benefits 2017 2016 2015 2017 2016 2015 Discount rate 4.00 % 4.23 % 3.94 % 4.10 % 4.40 % 4.00 % Expected long-term return on plan assets 6.00 % 6.50 % 6.75 % n/a n/a n/a Rate of increase in compensation (1) 3.50 % 4.00 % 4.00 % 3.50 % 4.00 % 4.00 % _______________________ (1) The Pension Plan was frozen effective January 1, 2016, and as a result, the rate of increase in compensation for participants is no longer considered an assumption used by the Company to calculate the value of the Pension Plan. As such, for the years ended December 31, 2017 and 2016 , the rate of increase in compensation only includes the SERP and Medical Plan. |
Defined Benefit Plan, Actual Plan Asset Allocations [Abstract] (Deprecated 2012-01-31) | The following table summarizes investments for which fair value is measured using the NAV per share practical expedient as of December 31, 2017 and 2016 , respectively: December 31, 2017 December 31, 2016 Total Percentage of total Total Percentage of total (in millions, except percentages) Cash and short-term investments $ 0.5 — % $ 3.5 4 % Equity securities: Domestic 35.0 35 % 39.3 46 % International 15.3 15 % 21.6 25 % Fixed income 49.7 50 % 21.7 25 % Total investments $ 100.5 100 % $ 86.1 100 % |
Schedule of Expected Benefit Payments [Table Text Block] | Expected Benefit Payments As of December 31, 2017 , the following future benefit payments are expected to be paid: Pension Plan and SERP benefits Medical Plan benefits (in millions) 2018 $ 6.6 $ 0.2 2019 $ 8.1 $ 0.2 2020 $ 7.6 $ 0.2 2021 $ 8.3 $ 0.2 2022 $ 6.8 $ 0.2 2023 through 2026 $ 39.1 $ 0.6 |
Compensation and Employee Benefit Plans [Text Block] | Year Ended December 31, 2017 2016 2015 Employees not covered by the Pension Plan or SERP (1) Maximum employer matching of qualifying earnings 8 % 8 % 8 % Employees covered by the Pension Plan but not the SERP (1) Maximum employer matching of qualifying earnings 8 % 8 % 6 % Employees covered by both the Pension Plan and the SERP (1) Maximum employer matching of qualifying earnings 6 % 6 % 6 % |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | |
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block] | Details of income tax provisions and deferred income taxes from continuing operations are provided in the following tables. The components of income tax provisions and benefits were as follows: Year Ended December 31, 2017 2016 2015 Federal income tax provision (benefit) (in millions) Current $ 2.1 $ (55.5 ) $ (112.3 ) Deferred (339.8 ) (614.3 ) 34.5 State income tax provision (benefit) Current 0.5 (1.5 ) (6.6 ) Deferred 25.0 (36.9 ) (9.2 ) Total income tax provision (benefit) $ (312.2 ) $ (708.2 ) $ (93.6 ) |
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block] | The difference between the statutory federal income tax rate and the Company's effective income tax rate is explained as follows: Year Ended December 31, 2017 2016 2015 Federal income taxes statutory rate 35.0 % 35.0 % 35.0 % Increase (decrease) in rate as a result of: State income taxes, net of federal income tax benefit (1) (40.1 )% 2.4 % 4.2 % Federal rate change (2) 741.3 % — % — % State rate change 2.1 % (1.1 )% — % Penalties (0.4 )% — % (0.3 )% Return to provision adjustment (0.7 )% — % (0.3 )% Uncertain tax provision (federal rate change) (7.7 )% — % — % Other (1.8 )% — % (0.1 )% Effective income tax rate 727.7 % 36.3 % 38.5 % |
Schedule of Deferred Tax Assets and Liabilities [Table Text Block] | December 31, 2017 (1) 2016 Deferred tax liabilities (in millions) Property, plant and equipment $ 898.7 $ 1,135.0 Deferred tax assets Net operating loss and tax credit carryforwards $ 308.8 $ 161.6 Employee benefits and compensation costs 26.4 49.0 Bonus and vacation accrual 6.2 11.4 Commodity price derivatives 29.9 74.3 Other 9.4 12.8 Total deferred tax assets 380.7 309.1 Net deferred income tax liability $ 518.0 $ 825.9 Balance sheet classification Deferred income tax liability – noncurrent 518.0 825.9 Net deferred income tax liability $ 518.0 $ 825.9 |
Summary of Operating Loss Carryforwards [Table Text Block] | The amounts and expiration dates of net operating loss and tax credit carryforwards at December 31, 2017 , are as follows: Expiration Dates Amounts (in millions) State net operating loss and tax credit carryforwards 2018-2037 $ 95.8 State net operating loss valuation allowance $ (56.8 ) U.S. net operating loss 2036-2037 $ 250.4 U.S. alternative minimum tax credit Indefinite $ 19.5 |
Summary of Positions for which Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Table Text Block] | The following is a reconciliation of our beginning and ending amounts of unrecognized tax benefits for the years ended December 31, 2017 and 2016 : Unrecognized Tax Benefits 2017 2016 (in millions) Balance as of January 1, $ 15.6 $ 15.6 Federal benefit of state (change from 35% to 21%) 3.4 — Balance as of December 31, $ 19.0 $ 15.6 As of December 31, 2017 and 2016 , QEP had approximately $19.0 million and $15.6 million , respectively, of unrecognized tax benefit that would impact its effective tax rate if recognized. The difference is due to the change in the Federal tax rate in 2017 from 35% to 21% , which affects the federal benefit of the state deduction to the unrecognized tax position. |
Quarterly Financial Informati36
Quarterly Financial Information (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Quarterly Financial Information Disclosure [Abstract] | |
Schedule of Quarterly Financial Information [Table Text Block] | The following table provides a summary of unaudited quarterly financial information: First Quarter Second Quarter Third Quarter Fourth Quarter Year 2017 (in millions, except per share amounts or otherwise specified) Revenues $ 420.1 $ 383.7 $ 390.1 $ 429.0 $ 1,622.9 Operating income (loss) (5.2 ) (0.9 ) 132.1 (24.5 ) 101.5 Net income (loss) 76.9 45.4 (3.3 ) 150.3 269.3 Net gain (loss) from asset sales and impairment (0.1 ) 19.8 157.1 (42.2 ) 134.6 Nonrecurring items in operating income (loss) (1) — — 8.2 — 8.2 Per share information Basic EPS $ 0.32 $ 0.19 $ (0.01 ) $ 0.62 $ 1.12 Diluted EPS 0.32 0.19 (0.01 ) 0.62 1.12 Production information Total equivalent production (Mboe) 13,090.3 13,860.6 14,124.1 12,069.9 53,144.9 Total equivalent production (Bcfe) 78.6 83.2 84.7 72.1 318.6 2016 Revenues $ 261.3 $ 333.7 $ 382.4 $ 399.7 $ 1,377.1 Operating income (loss) (1,379.0 ) (92.1 ) (93.1 ) (36.5 ) (1,600.7 ) Net income (loss) (863.8 ) (197.0 ) (50.9 ) (133.3 ) (1,245.0 ) Net gain (loss) from asset sales and impairment (1,181.9 ) (1.6 ) 0.3 (6.1 ) (1,189.3 ) Nonrecurring items in operating income (loss) (1) 7.7 — 25.0 — 32.7 Per share information Basic EPS $ (4.55 ) $ (0.90 ) $ (0.21 ) $ (0.56 ) $ (5.62 ) Diluted EPS (4.55 ) (0.90 ) (0.21 ) (0.56 ) (5.62 ) Production information Total equivalent production (Mboe) 13,776.4 13,882.4 14,445.7 13,675.7 55,780.2 Total equivalent production (Bcfe) 82.7 83.3 86.6 82.1 334.7 ____________________________ (1) Reflects legal expenses and loss contingencies incurred during the years ended December 31, 2017 and 2016 . |
Supplemental Gas and Oil Info37
Supplemental Gas and Oil Information (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |
Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure [Table Text Block] | December 31, 2017 2016 (in millions) Proved properties $ 12,470.9 $ 14,232.5 Unproved properties, net 1,095.8 871.5 Total proved and unproved properties 13,566.7 15,104.0 Accumulated depreciation, depletion and amortization (6,642.9 ) (8,797.7 ) Net capitalized costs $ 6,923.8 $ 6,306.3 |
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Table Text Block] | Year Ended December 31, 2017 2016 2015 (in millions) Proved property acquisitions $ 269.6 $ 431.6 $ 49.6 Unproved property acquisitions 532.4 208.7 39.8 Other acquisitions 13.2 — — Exploration costs (capitalized and expensed) 32.7 13.4 8.7 Development costs 1,189.3 509.2 1,010.3 Total costs incurred $ 2,037.2 $ 1,162.9 $ 1,108.4 |
Results of Operations for Oil and Gas Producing Activities Disclosure [Table Text Block] | Following are the results of operations of QEP's oil and gas producing activities, before allocated corporate overhead and interest expenses. Year Ended December 31, 2017 2016 2015 (in millions) Revenues $ 1,548.1 $ 1,271.0 $ 1,390.4 Production costs 675.4 616.7 654.1 Exploration expenses 22.0 1.7 2.7 Depreciation, depletion and amortization 735.1 852.3 870.8 Impairment 72.3 1,194.3 55.6 Total expenses 1,504.8 2,665.0 1,583.2 Income (loss) before income taxes 43.3 (1,394.0 ) (192.8 ) Income tax benefit (expense) (16.0 ) 517.2 70.6 Results of operations from producing activities excluding allocated corporate overhead and interest expenses $ 27.3 $ (876.8 ) $ (122.2 ) |
Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities [Table Text Block] | As of December 31, 2017 , all of the Company's oil and gas reserves are attributable to properties within the United Sates. A summary of the Company's change in quantities of proved oil, gas and NGL reserves for the years ended December 31, 2015 , 2016 and 2017 are as follows: Oil Gas NGL Total (13) (MMbbl) (Bcf) (MMbbl) (MMboe) Balance at December 31, 2014 172.5 2,317.2 96.6 655.3 Revisions of previous estimates (1) (47.0 ) (463.8 ) (55.3 ) (179.6 ) Extensions and discoveries (2) 85.6 467.7 21.8 185.4 Purchase of reserves in place (3) 2.0 3.2 0.6 3.1 Sale of reserves in place (4) (0.4 ) (34.3 ) (0.2 ) (6.3 ) Production (19.6 ) (181.1 ) (4.7 ) (54.5 ) Balance at December 31, 2015 193.1 2,108.9 58.8 603.4 Revisions of previous estimates (5) (9.7 ) 412.8 (0.3 ) 58.8 Extensions and discoveries (6) 13.0 158.1 3.3 42.6 Purchase of reserves in place (7) 62.7 54.6 11.5 83.3 Sale of reserves in place (8) (0.2 ) (3.6 ) (0.1 ) (0.9 ) Production (20.3 ) (177.0 ) (6.0 ) (55.8 ) Balance at December 31, 2016 238.6 2,553.8 67.2 731.4 Revisions of previous estimates (9) 3.7 12.5 (3.1 ) 2.7 Extensions and discoveries (10) 59.1 101.9 10.4 86.4 Purchase of reserves in place (11) 46.6 125.5 8.7 76.3 Sale of reserves in place (12) (7.9 ) (831.2 ) (12.6 ) (159.0 ) Production (19.6 ) (168.9 ) (5.4 ) (53.1 ) Balance at December 31, 2017 320.5 1,793.6 65.2 684.7 Proved developed reserves Balance at December 31, 2014 99.3 1,288.4 52.2 366.2 Balance at December 31, 2015 109.7 1,245.3 34.4 351.6 Balance at December 31, 2016 103.2 1,309.8 35.7 357.2 Balance at December 31, 2017 116.0 655.5 27.9 253.1 Proved undeveloped reserves Balance at December 31, 2014 73.2 1,028.8 44.4 289.1 Balance at December 31, 2015 83.4 863.6 24.4 251.8 Balance at December 31, 2016 135.4 1,244.0 31.5 374.2 Balance at December 31, 2017 204.5 1,138.1 37.3 431.6 ___________________________ (1) Revisions of previous estimates in 2015 include: 126.2 MMboe of negative revisions due to lower pricing and 67.2 MMboe of negative revisions unrelated to pricing, partially offset by 13.7 MMboe of positive performance revisions. Negative pricing revisions were driven by lower oil, gas and NGL prices. Negative other revisions included operating in ethane rejection in Pinedale and the Uinta Basin. (2) Extensions and discoveries in 2015 increased proved reserves by 185.4 MMboe, primarily related to extensions and discoveries in the Williston Basin of 68.2 MMboe, the Uinta Basin of 53.2 MMboe, and the Permian Basin of 49.6 MMboe. All of these extensions and discoveries related to new well completions and associated new PUD locations. (3) Purchase of reserves in place in 2015 related to the acquisition of additional interests in QEP operated wells in the Williston and Permian basins as discussed in Note 2 – Acquisitions and Divestitures . (4) Sale of reserves in place in 2015 relate to the divestiture of QEP's interest in certain non-core properties as discussed in Note 2 – Acquisitions and Divestitures . (5) Revisions of previous estimates in 2016 include 77.3 MMboe of positive revisions, primarily related to successful workovers in Haynesville/Cotton Valley; reserves associated with increased density wells in areas that have been previously developed on lower density spacing; and 5.5 MMboe of positive performance revisions. These positive revisions were partially offset by 18.5 MMboe of negative revisions related to pricing, driven by lower oil, gas and NGL prices. (6) Extensions and discoveries in 2016 were primarily in the Permian and Uinta basins and related to new well completions and associated new PUD locations. (7) Purchase of reserves in place in 2016 primarily relates to QEP's 2016 Permian Basin Acquisition as discussed in Note 2 – Acquisitions and Divestitures . (8) Sale of reserves in place in 2016 relates to the divestiture of QEP's interest in certain non-core properties as discussed in Note 2 – Acquisitions and Divestitures . |
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure Price per Unit [Table Text Block] | he following table provides the average benchmark prices per unit, before location and quality differential adjustments, used to calculate the related reserve category: For the year ended December 31, 2017 2016 2015 Average benchmark price per unit: Oil price (per bbl) $ 51.34 $ 42.75 $ 50.28 Gas price (per MMBtu) $ 2.98 $ 2.48 $ 2.59 |
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure [Table Text Block] | he standardized measure of discounted future net cash flows relating to proved reserves is presented in the table below: Year Ended December 31, 2017 2016 2015 (in millions) Future cash inflows $ 22,028.9 $ 16,239.8 $ 15,325.3 Future production costs (9,074.2 ) (7,789.0 ) (7,389.9 ) Future development costs (1) (4,726.0 ) (3,432.9 ) (2,202.5 ) Future income tax expenses (2) (1,439.1 ) (913.4 ) (1,169.3 ) Future net cash flows 6,789.6 4,104.5 4,563.6 10% annual discount for estimated timing of net cash flows (3,692.3 ) (2,176.5 ) (2,087.3 ) Standardized measure of discounted future net cash flows $ 3,097.3 $ 1,928.0 $ 2,476.3 |
Principal Sources of Change in Standardized measure of Discounted Future Net Cash Flows [Table Text Block] | he principal sources of change in the standardized measure of discounted future net cash flows relating to proved reserves is presented in the table below: Year Ended December 31, 2017 2016 2015 (in millions) Balance at January 1, $ 1,928.0 $ 2,476.3 $ 5,340.0 Sales of oil, gas and NGL produced, net of production costs (872.7 ) (654.3 ) (736.3 ) Net change in sales prices and in production (lifting) costs related to future production 1,457.2 (739.4 ) (6,307.8 ) Net change due to extensions and discoveries 556.8 81.8 1,765.7 Net change due to revisions of quantity estimates 9.9 122.7 (1,350.2 ) Net change due to purchases of reserves in place 342.7 256.5 29.7 Net change due to sales of reserves in place (504.7 ) (4.3 ) (48.8 ) Previously estimated development costs incurred during the period 475.4 374.6 865.0 Changes in estimated future development costs (283.4 ) (476.5 ) 560.7 Accretion of discount 235.7 311.1 752.9 Net change in income taxes (227.4 ) 205.4 1,554.4 Other (20.2 ) (25.9 ) 51.0 Net change 1,169.3 (548.3 ) (2,863.7 ) Balance at December 31, $ 3,097.3 $ 1,928.0 $ 2,476.3 |
Summary of Significant Accoun38
Summary of Significant Accounting Policies Cash and Cash Equivalents (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Accounting Policies [Abstract] | |||
Unrestricted Cash | $ 0 | $ 443.8 | |
Restricted cash | 23.4 | 21.6 | |
Supplemental Disclosures | |||
Cash paid for interest, net of capitalized interest | 134.9 | 139.1 | $ 139.4 |
Cash paid (refund received) for income taxes, net | (0.3) | (123.5) | 487.8 |
Non-cash investing activities | |||
Change in capital expenditure accrual balance | $ 60.2 | $ (32.8) | $ (129.2) |
Summary of Significant Accoun39
Summary of Significant Accounting Policies Accounts Receivable (Details) - Allowance for Doubtful Accounts [Member] - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Accounts, Notes, Loans and Financing Receivable [Line Items] | |||
Bad Debt Expense | $ (1) | $ 1.8 | $ 0.5 |
Allowance for Doubtful Accounts Receivable | $ 1.6 | $ 4.8 |
Summary of Significant Accoun40
Summary of Significant Accounting Policies Property, plant and equipment (Details) | 12 Months Ended |
Dec. 31, 2017 | |
Building [Member] | Minimum [Member] | |
Property, Plant and Equipment [Line Items] | |
Estimated Useful Life | 10 years |
Building [Member] | Maximum [Member] | |
Property, Plant and Equipment [Line Items] | |
Estimated Useful Life | 30 years |
Leasehold Improvements [Member] | Minimum [Member] | |
Property, Plant and Equipment [Line Items] | |
Estimated Useful Life | 3 years |
Leasehold Improvements [Member] | Maximum [Member] | |
Property, Plant and Equipment [Line Items] | |
Estimated Useful Life | 10 years |
Equipment [Member] | Minimum [Member] | |
Property, Plant and Equipment [Line Items] | |
Estimated Useful Life | 3 years |
Equipment [Member] | Maximum [Member] | |
Property, Plant and Equipment [Line Items] | |
Estimated Useful Life | 7 years |
Furniture and Fixtures [Member] | Minimum [Member] | |
Property, Plant and Equipment [Line Items] | |
Estimated Useful Life | 3 years |
Furniture and Fixtures [Member] | Maximum [Member] | |
Property, Plant and Equipment [Line Items] | |
Estimated Useful Life | 7 years |
Summary of Significant Accoun41
Summary of Significant Accounting Policies Impairment of long-lived assets (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Impaired Long-Lived Assets Held and Used [Line Items] | |||
Impairment | $ 78.9 | $ 1,194.3 | $ 55.6 |
Gas storage facility [Member] | |||
Impaired Long-Lived Assets Held and Used [Line Items] | |||
Impairment of Oil and Gas Properties | 6.5 | ||
Pinedale [Member] | |||
Impaired Long-Lived Assets Held and Used [Line Items] | |||
Impairment of Oil and Gas Properties | 1,164 | ||
Uinta Basin [Member] | |||
Impaired Long-Lived Assets Held and Used [Line Items] | |||
Impairment of Oil and Gas Properties | 4.7 | ||
Other Northern [Member] | |||
Impaired Long-Lived Assets Held and Used [Line Items] | |||
Impairment of Oil and Gas Properties | 37.1 | 3.4 | 18.4 |
Louisiana [Member] | |||
Impaired Long-Lived Assets Held and Used [Line Items] | |||
Impairment of Oil and Gas Properties | 1 | ||
Permian Basin [Member] | |||
Impaired Long-Lived Assets Held and Used [Line Items] | |||
Impairment of Oil and Gas Properties | 0.7 | ||
Other Southern [Member] | |||
Impaired Long-Lived Assets Held and Used [Line Items] | |||
Impairment of Oil and Gas Properties | 0.6 | 20.2 | |
Proved properties [Member] | |||
Impaired Long-Lived Assets Held and Used [Line Items] | |||
Impairment of Oil and Gas Properties | 38.1 | 1,172.7 | 39.3 |
Unproved properties [Member] | |||
Impaired Long-Lived Assets Held and Used [Line Items] | |||
Impairment of Oil and Gas Properties | 29 | 17.9 | 2 |
Goodwill [Member] | |||
Impaired Long-Lived Assets Held and Used [Line Items] | |||
Impairment of Oil and Gas Properties | $ 5.3 | $ 3.7 | $ 14.3 |
Summary of Significant Accoun42
Summary of Significant Accounting Policies Goodwill (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Goodwill [Line Items] | |||
Goodwill | $ 5.3 | $ 3.7 | $ 14.3 |
Goodwill [Member] | |||
Goodwill [Line Items] | |||
Impairment of Oil and Gas Properties | $ 5.3 | $ 3.7 | $ 14.3 |
Summary of Significant Accoun43
Summary of Significant Accounting Policies Credit Risk (Details) | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Concentration Risk [Line Items] | |||
Concentration Risk, Percentage | 59.00% | 48.00% | 30.00% |
Shell Trading Company [Member] | |||
Concentration Risk [Line Items] | |||
Concentration Risk, Percentage | 14.00% | 14.00% | |
Occidental Energy Marketing [Member] | |||
Concentration Risk [Line Items] | |||
Concentration Risk, Percentage | 13.00% | ||
Andeavor Logistics LP [Member] | |||
Concentration Risk [Line Items] | |||
Concentration Risk, Percentage | 13.00% | ||
BP Energy Company [Member] | |||
Concentration Risk [Line Items] | |||
Concentration Risk, Percentage | 10.00% | 10.00% | |
Plains Marketing LP [Member] | |||
Concentration Risk [Line Items] | |||
Concentration Risk, Percentage | 10.00% | ||
Valero Marketing And Supply Company [Member] | |||
Concentration Risk [Line Items] | |||
Concentration Risk, Percentage | 10.00% | ||
No Customer [Member] | |||
Concentration Risk [Line Items] | |||
Concentration Risk, Percentage | 10.00% |
Summary of Significant Accoun44
Summary of Significant Accounting Policies Income Taxes (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Accounting Changes and Error Corrections [Abstract] | |||
Unrecognized Tax Benefits | $ 19 | $ 15.6 | $ 15.6 |
Interest Related to Uncertain Tax Positions | $ 0.7 | 0.7 | 0.5 |
Penalties Related to Uncertain Tax Positions | $ 0.6 | $ 2.2 |
Summary of Significant Accoun45
Summary of Significant Accounting Policies Earnings Per Share (Details) - shares shares in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items] | |||
Antidilutive shares excluded from computation of EPS | 0 | 0.1 | 0 |
Used in basic calculation | 240.6 | 221.7 | 176.6 |
Potential number of shares issuable upon exercise of in-the-money stock options under the Long-Term Stock Incentive Plan | 0 | 0 | 0 |
Average diluted common shares outstanding | 240.6 | 221.7 | 176.6 |
Acquisitions and Divestitures 2
Acquisitions and Divestitures 2017 Permian Basin Acquisition (Details) $ in Millions | 12 Months Ended | |
Dec. 31, 2017USD ($)a | Dec. 31, 2016USD ($) | |
Business Acquisition [Line Items] | ||
Aggregate purchase price | $ 94.5 | $ 54.6 |
2017 Permian Basin Acquisition [Member] | ||
Business Acquisition [Line Items] | ||
Aggregate purchase price | $ 720.7 | |
Net acres of producing and undeveloped oil and gas properties | a | 15,100 | |
Additional acquisitions in the Permian Basin [Member] | ||
Business Acquisition [Line Items] | ||
Aggregate purchase price | $ 50 |
Acquisitions and Divestitures47
Acquisitions and Divestitures 2016 Permian Basin Acquisition Narrative (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017USD ($)a | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | |
Business Acquisition [Line Items] | |||
Aggregate purchase price | $ 94.5 | $ 54.6 | |
Bargain purchase gain from acquisitions | 0.4 | (22.6) | $ 0 |
2016 Permian Basin Acquisition [Member] | |||
Business Acquisition [Line Items] | |||
Aggregate purchase price | $ 591 | ||
Net acres of producing and undeveloped oil and gas properties | a | 9,600 | ||
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual | $ 80.2 | 3.8 | |
Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual | 221.4 | (0.7) | |
Business Combination, Acquisition Related Costs | $ 2.3 | ||
Bargain purchase gain from acquisitions | $ 17.8 |
Acquisitions and Divestitures48
Acquisitions and Divestitures 2016 Permian Basin Purchase Accounting Entries (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Business Acquisition [Line Items] | ||
Aggregate purchase price | $ 94.5 | $ 54.6 |
2016 Permian Basin Acquisition [Member] | ||
Business Acquisition [Line Items] | ||
Aggregate purchase price | 591 | |
Recognized identifiable assets acquired and liabilities assumed, net | 591 | |
2016 Permian Basin Acquisition [Member] | Proved Property [Member] | ||
Business Acquisition [Line Items] | ||
Recognized identifiable assets acquired and liabilities assumed, net | 406.2 | |
2016 Permian Basin Acquisition [Member] | Unproved Property [Member] | ||
Business Acquisition [Line Items] | ||
Recognized identifiable assets acquired and liabilities assumed, net | 214.2 | |
2016 Permian Basin Acquisition [Member] | Asset Retirement Obligation Costs [Member] | ||
Business Acquisition [Line Items] | ||
Recognized identifiable assets acquired and liabilities assumed, net | (11.6) | |
2016 Permian Basin Acquisition [Member] | Bargain Purchase Gain [Member] | ||
Business Acquisition [Line Items] | ||
Recognized identifiable assets acquired and liabilities assumed, net | $ (17.8) |
Acquisitions and Divestitures49
Acquisitions and Divestitures 2016 Permian Basin Acquisition Pro Forma Results (Details) - USD ($) $ / shares in Units, $ in Millions | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Business Acquisition [Line Items] | |||||||||||
Revenues | $ 429 | $ 390.1 | $ 383.7 | $ 420.1 | $ 399.7 | $ 382.4 | $ 333.7 | $ 261.3 | $ 1,622.9 | $ 1,377.1 | $ 2,018.6 |
Net income (loss) | $ 150.3 | $ (3.3) | $ 45.4 | $ 76.9 | $ (133.3) | $ (50.9) | $ (197) | $ (863.8) | $ 269.3 | $ (1,245) | $ (149.4) |
Earnings Per Share, Basic | $ 0.62 | $ (0.01) | $ 0.19 | $ 0.32 | $ (0.56) | $ (0.21) | $ (0.90) | $ (4.55) | $ 1.12 | $ (5.62) | $ (0.85) |
Earnings Per Share, Diluted | $ 0.62 | $ (0.01) | $ 0.19 | $ 0.32 | $ (0.56) | $ (0.21) | $ (0.90) | $ (4.55) | $ 1.12 | $ (5.62) | $ (0.85) |
2016 Permian Basin Acquisition [Member] | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Revenues | $ 1,377.1 | ||||||||||
Net income (loss) | $ (1,245) | ||||||||||
Earnings Per Share, Basic | $ (5.62) | ||||||||||
Earnings Per Share, Diluted | $ (5.62) | ||||||||||
Business Acquisition, Pro Forma Revenue | $ 1,392.5 | ||||||||||
Business Acquisition, Pro Forma Net Income (Loss) | $ (1,246.8) | ||||||||||
Business Acquisition, Pro Forma Earnings Per Share, Basic | $ (5.62) | ||||||||||
Business Acquisition, Pro Forma Earnings Per Share, Diluted | $ (5.62) |
Acquisitions and Divestitures P
Acquisitions and Divestitures Pinedale Divestiture (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Divestitures [Line Items] | |||
Proceeds from Sale of Oil and Gas Property and Equipment | $ 806.8 | $ 29 | $ 21.8 |
Gain (Loss) on Disposition of Property Plant Equipment | 213.5 | 5 | 4.6 |
Long-term Purchase Commitment, Amount | 45 | ||
Results of Operations, Income before Income Taxes | 43.3 | (1,394) | (192.8) |
Pinedale Divestiture [Member] | |||
Divestitures [Line Items] | |||
Proceeds from Sale of Oil and Gas Property and Equipment | 718.2 | ||
Gain (Loss) on Disposition of Property Plant Equipment | 180.4 | ||
Results of Operations, Income before Income Taxes | 251 | (1,152.7) | $ (45.6) |
Long term [Member] | |||
Divestitures [Line Items] | |||
Purchase Commitment, Remaining Minimum Amount Committed | 3.2 | ||
Total [Member] | |||
Divestitures [Line Items] | |||
Purchase Commitment, Remaining Minimum Amount Committed | 30.6 | ||
Short term [Member] | |||
Divestitures [Line Items] | |||
Purchase Commitment, Remaining Minimum Amount Committed | $ 27.4 | ||
Pinedale [Member] | |||
Divestitures [Line Items] | |||
Impairment of Oil and Gas Properties | 1,164 | ||
Proved Property [Member] | Pinedale [Member] | |||
Divestitures [Line Items] | |||
Impairment of Oil and Gas Properties | $ 1,164 |
Acquisitions and Divestitures51
Acquisitions and Divestitures (Narrative) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Significant Acquisitions and Disposals [Line Items] | |||
Aggregate purchase price | $ 94.5 | $ 54.6 | |
Bargain purchase gain from acquisitions | 0.4 | (22.6) | $ 0 |
Goodwill | 5.3 | 3.7 | 14.3 |
Proceeds from Sale of Oil and Gas Property and Equipment | 806.8 | 29 | 21.8 |
Gain (Loss) on Disposition of Property Plant Equipment | 213.5 | 5 | 4.6 |
Central Basin Platform [Member] | |||
Significant Acquisitions and Disposals [Line Items] | |||
Proceeds from Sale of Oil and Gas Property and Equipment | 3.5 | ||
2015 Divestitures [Member] | |||
Significant Acquisitions and Disposals [Line Items] | |||
Gain (Loss) on Disposition of Property Plant Equipment | (0.9) | ||
Other Northern [Member] | |||
Significant Acquisitions and Disposals [Line Items] | |||
Proceeds from Sale of Oil and Gas Property and Equipment | 85.1 | ||
Gain (Loss) on Disposition of Property Plant Equipment | $ 33.1 | ||
Other Southern [Member] | |||
Significant Acquisitions and Disposals [Line Items] | |||
Proceeds from Sale of Oil and Gas Property and Equipment | 29 | 31.7 | |
Gain (Loss) on Disposition of Property Plant Equipment | 8.6 | 21 | |
Other Southern [Member] | Cash [Member] | |||
Significant Acquisitions and Disposals [Line Items] | |||
Proceeds from Sale of Oil and Gas Property and Equipment | 21.8 | ||
Other Southern [Member] | Accounts Receivable [Member] | |||
Significant Acquisitions and Disposals [Line Items] | |||
Proceeds from Sale of Oil and Gas Property and Equipment | 9.9 | ||
Other Acquisitions [Member] | |||
Significant Acquisitions and Disposals [Line Items] | |||
Bargain purchase gain from acquisitions | 4.4 | ||
Williston & Permian Basins [Member] | |||
Significant Acquisitions and Disposals [Line Items] | |||
Goodwill | $ 14.3 | ||
Other Northern & Uinta Basin [Member] | |||
Significant Acquisitions and Disposals [Line Items] | |||
Aggregate purchase price | $ 98.3 |
Capitalized Exploratory Well 52
Capitalized Exploratory Well Costs (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Capitalized Exploratory Well Costs [Line Items] | |||
Proceeds from Sale of Oil and Gas Property and Equipment | $ 806.8 | $ 29 | $ 21.8 |
Balance at January 1, | 14.2 | 2.6 | 12.6 |
Additions to capitalized exploratory well costs | 10.7 | 11.7 | 6 |
Reclassifications to proved properties | (3.6) | 0 | (16) |
Capitalized exploratory well costs charged to expense | 21.3 | (0.1) | 0 |
Impairment | 78.9 | 1,194.3 | 55.6 |
Balance at December 31, | 0 | $ 14.2 | $ 2.6 |
Central Basin Platform [Member] | |||
Capitalized Exploratory Well Costs [Line Items] | |||
Reclassifications to proved properties | (3.6) | ||
Impairment | 28.3 | ||
Central Basin Platform [Member] | |||
Capitalized Exploratory Well Costs [Line Items] | |||
Proceeds from Sale of Oil and Gas Property and Equipment | $ 3.5 |
Asset Retirement Obligations (D
Asset Retirement Obligations (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Asset retirement obligation, current | $ 7.5 | $ 5.8 |
Asset retirement obligations, noncurrent | 206.6 | 225.8 |
ARO Liability [Roll Forward] | ||
ARO liability, Beginning Balance | 231.6 | 206.8 |
Accretion | 7.7 | 8.9 |
Liabilities incurred | 23.5 | 17 |
Revisions of Estimates | 8.5 | 6.5 |
Liabilities related to assets sold | 34.9 | 0 |
Liabilities settled | (22.3) | (7.6) |
ARO liability, Ending Balance | 214.1 | $ 231.6 |
2017 Permian Basin Acquisition [Member] | ||
ARO Liability [Roll Forward] | ||
Liabilities incurred | 14.2 | |
2016 Permian Basin Acquisition [Member] | ||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Recognized identifiable assets acquired and liabilities assumed, net | (591) | |
ARO Liability [Roll Forward] | ||
Liabilities incurred | 11.6 | |
Pinedale Divestiture [Member] | ||
ARO Liability [Roll Forward] | ||
Liabilities related to assets sold | $ (34.9) |
Fair Value Measurements (Narrat
Fair Value Measurements (Narrative) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Proved properties [Member] | |||
Fair Value, Option, Quantitative Disclosures [Line Items] | |||
Impairment of Oil and Gas Properties | $ 38.1 | $ 1,172.7 | $ 39.3 |
Fair Value of Financial Assets
Fair Value of Financial Assets and Liabilities (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 | |
Financial Assets | |||
Netting Adjustments | [1] | $ (19.4) | $ 0 |
Derivative Asset | 3.5 | 0 | |
Financial liabilities | |||
Netting Adjustments | [1] | (19.4) | 0 |
Derivative Liability | 135.4 | 201.8 | |
Level 1 [Member] | |||
Financial Assets | |||
Derivative instruments | 0 | 0 | |
Financial liabilities | |||
Derivative instruments | 0 | 0 | |
Level 2 [Member] | |||
Financial Assets | |||
Derivative instruments | 22.9 | 0 | |
Financial liabilities | |||
Derivative instruments | 154.8 | 201.8 | |
Level 3 [Member] | |||
Financial Assets | |||
Derivative instruments | 0 | 0 | |
Financial liabilities | |||
Derivative instruments | 0 | 0 | |
Long term [Member] | |||
Financial Assets | |||
Netting Adjustments | [1] | (2.2) | 0 |
Derivative Asset | 0.1 | 0 | |
Financial liabilities | |||
Netting Adjustments | [1] | (2.2) | 0 |
Derivative Liability | 31.8 | 32 | |
Long term [Member] | Level 1 [Member] | |||
Financial Assets | |||
Derivative instruments | 0 | 0 | |
Financial liabilities | |||
Derivative instruments | 0 | 0 | |
Long term [Member] | Level 2 [Member] | |||
Financial Assets | |||
Derivative instruments | 2.3 | 0 | |
Financial liabilities | |||
Derivative instruments | 34 | 32 | |
Long term [Member] | Level 3 [Member] | |||
Financial Assets | |||
Derivative instruments | 0 | 0 | |
Financial liabilities | |||
Derivative instruments | 0 | 0 | |
Short term [Member] | |||
Financial Assets | |||
Netting Adjustments | [1] | (17.2) | 0 |
Derivative Asset | 3.4 | 0 | |
Financial liabilities | |||
Netting Adjustments | [1] | (17.2) | 0 |
Derivative Liability | 103.6 | 169.8 | |
Short term [Member] | Level 1 [Member] | |||
Financial Assets | |||
Derivative instruments | 0 | 0 | |
Financial liabilities | |||
Derivative instruments | 0 | 0 | |
Short term [Member] | Level 2 [Member] | |||
Financial Assets | |||
Derivative instruments | 20.6 | 0 | |
Financial liabilities | |||
Derivative instruments | 120.8 | 169.8 | |
Short term [Member] | Level 3 [Member] | |||
Financial Assets | |||
Derivative instruments | 0 | 0 | |
Financial liabilities | |||
Derivative instruments | $ 0 | $ 0 | |
[1] | The Company nets its derivative contract assets and liabilities outstanding with the same counterparty on the Consolidated Balance Sheets for the contracts that contain netting provisions. Refer to Note 6 – Derivative Contracts for additional information regarding the Company's derivative contracts. |
Fair Value Measurements Fair Va
Fair Value Measurements Fair Value and Related Carrying Amount of Certain Financial Instruments (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Fair Value Disclosures [Abstract] | ||
Cash and cash equivalents | $ 0 | $ 443.8 |
Cash and cash equivalents, Level 1 Fair Value | 0 | 443.8 |
Checks outstanding in excess of cash balances | 44 | 12.3 |
Checks outstanding in excess of cash balances, Level 1 Fair Value | 44 | 12.3 |
Long-term debt | 2,160.8 | 2,020.9 |
Long-term debt, Level 1 Fair Value | $ 2,256.2 | $ 2,104.3 |
Derivative Contracts (Narrative
Derivative Contracts (Narrative) (Details) | 12 Months Ended |
Dec. 31, 2017 | |
Derivatives, Fair Value [Line Items] | |
Forecasted production from proved reserves (in hundredths) | 100.00% |
Expected Annual Production Covered By Derivatives | 50.00% |
Expected Annual Production Covered By Derivatives, High | 75.00% |
Derivative Contracts Schedule o
Derivative Contracts Schedule of Commodity Derivative Contracts (Details) bbl in Millions, MMBTU in Millions | 12 Months Ended |
Dec. 31, 2017USD ($)MMBTUbbl$ / MMBTU$ / bbl | |
Oil Swaps [Member] | Production [Member] | Year 2018 [Member] | NYMEX WTI [Member] | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount | bbl | 16.8 |
Underlying, Derivative Asset | $ / bbl | 52.48 |
Oil Swaps [Member] | Production [Member] | Year 2019 [Member] | NYMEX WTI [Member] | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount | bbl | 8 |
Underlying, Derivative Asset | $ / bbl | 51.78 |
Gas Swaps [Member] | Production [Member] | Year 2018 (July through December) [Member] | NYMEX HH [Member] | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount | 1.8 |
Underlying, Derivative Asset | $ / MMBTU | 3.01 |
Gas Swaps [Member] | Production [Member] | Year 2018 [Member] | NYMEX HH [Member] | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount | 109.5 |
Underlying, Derivative Asset | $ / MMBTU | 2.99 |
Gas Swaps [Member] | Production [Member] | Year 2019 [Member] | IFNPCR [Member] | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount | 36.5 |
Underlying, Derivative Asset | $ / MMBTU | 2.88 |
Gas Swaps [Member] | Storage [Member] | Year 2018 [Member] | IFNPCR [Member] | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount | 0.6 |
Underlying, Derivative Asset | $ / MMBTU | 3.06 |
Oil Basis Swaps [Member] | Production [Member] | Year 2018 (July through December) [Member] | NYMEX WTI less Argus WTI Midland [Member] | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount | 0.9 |
Derivatives, Weighted Average Differential | $ | $ (0.71) |
Oil Basis Swaps [Member] | Production [Member] | Year 2018 [Member] | NYMEX WTI less Argus WTI Midland [Member] | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount | 7.3 |
Derivatives, Weighted Average Differential | $ | $ (1.06) |
Oil Basis Swaps [Member] | Production [Member] | Year 2019 [Member] | NYMEX WTI less Argus WTI Midland [Member] | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount | 4 |
Derivatives, Weighted Average Differential | $ | $ (0.80) |
Gas Basis Swaps [Member] | Production [Member] | Year 2018 [Member] | NYMEX HH less IFNPCR [Member] | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount | 7.3 |
Derivatives, Weighted Average Differential | $ | $ (0.16) |
Derivative Contracts Schedule59
Derivative Contracts Schedule of Derivatives Financial Statement Presentation (Details) - Fair Value, Inputs, Level 2 [Member] - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Derivative [Line Items] | ||
Derivative instruments - assets | $ 22.9 | $ 0 |
Derivative instruments - liabilities | 154.8 | 201.8 |
Short term [Member] | ||
Derivative [Line Items] | ||
Derivative instruments - assets | 20.6 | 0 |
Derivative instruments - liabilities | 120.8 | 169.8 |
Long term [Member] | ||
Derivative [Line Items] | ||
Derivative instruments - assets | 2.3 | 0 |
Derivative instruments - liabilities | 34 | 32 |
Fair Value, Measurements, Recurring [Member] | ||
Derivative [Line Items] | ||
Derivative instruments - assets | 22.9 | 0 |
Derivative instruments - liabilities | 154.8 | 201.8 |
Fair Value, Measurements, Recurring [Member] | Commodity Contract [Member] | Short term [Member] | ||
Derivative [Line Items] | ||
Derivative instruments - assets | 20.6 | 0 |
Derivative instruments - liabilities | 120.8 | 169.8 |
Fair Value, Measurements, Recurring [Member] | Commodity Contract [Member] | Long term [Member] | ||
Derivative [Line Items] | ||
Derivative instruments - assets | 2.3 | 0 |
Derivative instruments - liabilities | $ 34 | $ 32 |
Derivative Contracts Gain (Loss
Derivative Contracts Gain (Loss) in Statement of Financial Performance (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Realized gain (loss) on commodity derivative contracts not designated as hedging instruments | $ (15.5) | $ 134 | $ 460.9 | |
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments | 69.9 | (367) | (183.7) | |
Realized and Unrealized Gain (Loss) on Commodity Derivative Contracts Not Designated as Hedging Instruments | [1] | 24.5 | (233) | 277.2 |
Oil derivative contracts [Member] | Production [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Realized gain (loss) on commodity derivative contracts not designated as hedging instruments | 6.8 | 86.3 | 353.7 | |
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments | (66.2) | (217.2) | (244.9) | |
Gas derivative contracts [Member] | Production [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Realized gain (loss) on commodity derivative contracts not designated as hedging instruments | (22.3) | 44.8 | 103.4 | |
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments | 133.6 | (145.4) | 62 | |
Gas derivative contracts [Member] | Storage [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Realized gain (loss) on commodity derivative contracts not designated as hedging instruments | 0 | 2.9 | 3.8 | |
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments | 2.5 | (4.4) | (0.8) | |
Total [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Realized and Unrealized Gain (Loss) on Commodity Derivative Contracts Not Designated as Hedging Instruments | 54.4 | (233) | 277.2 | |
Pinedale Divestiture [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments | [1] | (29.9) | 0 | 0 |
Pinedale Divestiture [Member] | Oil derivative contracts [Member] | Production [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments | [1] | (1.3) | 0 | 0 |
Pinedale Divestiture [Member] | Gas derivative contracts [Member] | Production [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments | [1] | (23.5) | 0 | 0 |
Pinedale Divestiture [Member] | NGL derivative contracts [Member] | Production [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments | [1] | $ (5.1) | $ 0 | $ 0 |
[1] | The unrealized gains (losses) on commodity derivative contracts related to the Pinedale Divestiture are comprised of derivatives entered into in conjunction with the execution of the Pinedale purchase and sale agreement, which were subsequently novated to the buyer upon the closing of the sale in September 2017. Refer to Note 2 – Acquisitions and Divestitures for more information. The unrealized gains (losses) on commodity derivatives associated with the Pinedale Divestiture are offset by an equal amount recorded within "Net gain (loss) from asset sales" on the Consolidated Statements of Operations. |
Restructuring Costs (Narrative)
Restructuring Costs (Narrative) (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Denver Restructuring [Member] | ||
Restructuring Cost and Reserve [Line Items] | ||
Restructuring costs, percentage of reduction | 6.00% | |
Restructuring costs, costs incurred | $ 1.9 | |
Denver Restructuring [Member] | Employee Relocation [Member] | ||
Restructuring Cost and Reserve [Line Items] | ||
Restructuring costs, costs incurred | 1.9 | |
Tulsa Office Closure [Member] | ||
Restructuring Cost and Reserve [Line Items] | ||
Restructuring costs, costs incurred | $ 8.3 | |
Tulsa Office Closure [Member] | Employee Relocation [Member] | ||
Restructuring Cost and Reserve [Line Items] | ||
Restructuring costs, costs incurred | $ 0.6 | 3 |
Tulsa Office Closure [Member] | Special Termination Benefits [Member] | ||
Restructuring Cost and Reserve [Line Items] | ||
Restructuring costs, costs incurred | $ 5.3 |
Debt (Narrative) (Details)
Debt (Narrative) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Debt Instrument [Line Items] | |||
Long-term debt | $ 2,160.8 | $ 2,020.9 | |
Loss from early extinguishment of debt | (32.7) | 0 | $ 0 |
Long-term Debt | $ 2,099.3 | ||
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Minimum | 5.25% | ||
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Maximum | 6.875% | ||
Revolving Credit Facility due 2019 [Member] | |||
Debt Instrument [Line Items] | |||
Long-term debt | $ 89 | 0 | |
Long-term Line of Credit | 1,250 | ||
Letters of Credit Outstanding, Amount | 1 | 2.8 | |
Senior Notes due 2018 [Member] | |||
Debt Instrument [Line Items] | |||
Long-term debt | $ 0 | 134 | |
Debt Instrument, Interest Rate, Stated Percentage | 6.80% | ||
Senior Notes Due 2020 [Member] | |||
Debt Instrument [Line Items] | |||
Long-term debt | $ 51.7 | 136 | |
Debt Instrument, Maturity Date | Mar. 1, 2020 | ||
Debt Instrument, Interest Rate, Stated Percentage | 6.80% | ||
Debt Instrument, Repurchased Face Amount | $ 84.3 | ||
Senior Notes Due 2021 [Member] | |||
Debt Instrument [Line Items] | |||
Long-term debt | $ 397.6 | 625 | |
Debt Instrument, Maturity Date | Mar. 1, 2021 | ||
Debt Instrument, Interest Rate, Stated Percentage | 6.875% | ||
Debt Instrument, Repurchased Face Amount | $ 227.4 | ||
Senior Notes Due 2022 [Member] | |||
Debt Instrument [Line Items] | |||
Long-term debt | $ 500 | 500 | |
Debt Instrument, Interest Rate, Stated Percentage | 5.40% | ||
Senior Notes Due 2026 [Member] | |||
Debt Instrument [Line Items] | |||
Long-term debt | $ 500 | $ 0 | |
Debt Instrument, Maturity Date | Mar. 1, 2026 | ||
Debt Instrument, Interest Rate, Stated Percentage | 5.60% |
Debt Schedule of Debt Instrumen
Debt Schedule of Debt Instruments (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Debt Instrument [Line Items] | ||
Total principal amount of debt | $ 2,160.8 | $ 2,020.9 |
Less unamortized discount | (27.5) | (24.1) |
Long-term Debt, Excluding Current Maturities | 2,160.8 | 2,020.9 |
Revolving Credit Facility due 2019 [Member] | ||
Debt Instrument [Line Items] | ||
Total principal amount of debt | 89 | 0 |
Senior Notes due 2018 [Member] | ||
Debt Instrument [Line Items] | ||
Total principal amount of debt | 0 | 134 |
Senior Notes Due 2020 [Member] | ||
Debt Instrument [Line Items] | ||
Total principal amount of debt | 51.7 | 136 |
Senior Notes Due 2021 [Member] | ||
Debt Instrument [Line Items] | ||
Total principal amount of debt | 397.6 | 625 |
Senior Notes Due 2022 [Member] | ||
Debt Instrument [Line Items] | ||
Total principal amount of debt | 500 | 500 |
Senior Notes Due 2023 [Member] | ||
Debt Instrument [Line Items] | ||
Total principal amount of debt | 650 | 650 |
Senior Notes Due 2026 [Member] | ||
Debt Instrument [Line Items] | ||
Total principal amount of debt | $ 500 | $ 0 |
Commitments and Contingencies O
Commitments and Contingencies Other Commitments (Details) $ in Millions | Dec. 31, 2017USD ($) |
Long-term Purchase Commitment [Line Items] | |
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months | $ 95.6 |
Unrecorded Unconditional Purchase Obligation, Due within Two Years | 68.4 |
Unrecorded Unconditional Purchase Obligation, Due within Three Years | 54.9 |
Unrecorded Unconditional Purchase Obligation, Due within Four Years | 29.9 |
Unrecorded Unconditional Purchase Obligation, Due within Five Years | 28.3 |
Unrecorded Unconditional Purchase Obligation, Due after Five Years | $ 122.5 |
Commitments and Contingencies L
Commitments and Contingencies Long-term Operating lease commitments (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Operating lease commitments [Abstract] | |||
Operating Leases, Rent Expense | $ 9.6 | $ 9.1 | $ 8 |
Operating Leases, Future Minimum Payments Due, Next Twelve Months | 7 | ||
Operating Leases, Future Minimum Payments, Due in Two Years | 7.2 | ||
Operating Leases, Future Minimum Payments, Due in Three Years | 7.4 | ||
Operating Leases, Future Minimum Payments, Due in Four Years | 7.4 | ||
Operating Leases, Future Minimum Payments, Due in Five Years | 7.2 | ||
Operating Leases, Future Minimum Payments, Due Thereafter | $ 4.8 |
Share-Based Compensation (Narra
Share-Based Compensation (Narrative) (Details) - USD ($) $ / shares in Units, shares in Millions, $ 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] | |||
Share-based compensation expense | $ 22.4 | $ 35.6 | $ 34.7 |
Shares available for future grants | 5 | ||
Share-based compensation | $ 22.4 | 35.6 | 34.7 |
Stock Options [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based compensation expense | 2.3 | 2.3 | 2.9 |
Intrinsic value of options exercised | $ 0.1 | ||
Tax benefit from equity-based compensation expense | 0.2 | $ (6.4) | |
Unrecognized compensation costs | $ 1.6 | ||
Weighted average period for recognition of equity-based compensation expense | 2 years 15 days | ||
Weighted average grant date fair value | $ 6.44 | $ 3.77 | $ 6.82 |
Restricted Share Awards [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Weighted average grant date fair value, grants | $ 13.90 | ||
Share-based compensation expense | $ 24.6 | $ 23.7 | $ 25.6 |
Unrecognized compensation costs | $ 19.2 | ||
Weighted average period for recognition of equity-based compensation expense | 1 year 11 months 26 days | ||
Award vesting period | 3 years | ||
Total fair value of stock that vested during the period | $ 18.4 | $ 24.3 | 22.7 |
Income tax expense (benefit) related to restricted stock compensation | $ (3.2) | ||
Weighted average grant date fair value | $ 13.90 | $ 10.50 | $ 20.92 |
Performance Share Units [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Weighted average grant date fair value, grants | $ 16.90 | ||
Share-based compensation expense | $ (4.5) | $ 9.4 | $ 6.2 |
Unrecognized compensation costs | $ 1.2 | ||
Weighted average period for recognition of equity-based compensation expense | 1 year 10 months 21 days | ||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Share-based Liabilities Paid | $ 5.3 | $ 2.8 | $ 3.1 |
Weighted average grant date fair value | $ 16.90 | $ 10.16 | $ 21.69 |
Restricted Share Units (RSUs) [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Weighted average grant date fair value, grants | $ 16.98 | $ 10.12 | |
Share-based compensation expense | $ 0 | $ 0.2 | $ 0 |
Unrecognized compensation costs | $ 0.1 | ||
Weighted average period for recognition of equity-based compensation expense | 1 year 11 days |
Share-Based Compensation Schedu
Share-Based Compensation Schedule of Share-based Compensation Expense (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Share-based Compensation Expense [Line Items] | |||
Share-based compensation expense | $ 22.4 | $ 35.6 | $ 34.7 |
Stock Options [Member] | |||
Share-based Compensation Expense [Line Items] | |||
Share-based compensation expense | 2.3 | 2.3 | 2.9 |
Restricted Share Awards [Member] | |||
Share-based Compensation Expense [Line Items] | |||
Share-based compensation expense | 24.6 | 23.7 | 25.6 |
Performance Share Units [Member] | |||
Share-based Compensation Expense [Line Items] | |||
Share-based compensation expense | (4.5) | 9.4 | 6.2 |
Restricted Share Units (RSUs) [Member] | |||
Share-based Compensation Expense [Line Items] | |||
Share-based compensation expense | $ 0 | $ 0.2 | $ 0 |
Share-Based Compensation Fair V
Share-Based Compensation Fair Value of Options Granted and Major Assumptions Used (Details) - Stock Options [Member] - $ / shares | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Weighted average grant date fair value | $ 6.44 | $ 3.77 | $ 6.82 |
Risk free interest rate, minimum | 1.66% | 0.99% | 1.38% |
Risk free interest rate, maximum | 1.81% | 1.15% | 1.38% |
Weighted average risk-free interest rate | 1.80% | 1.20% | 1.40% |
Expected price volatility range, minimum | 43.80% | 43.42% | 36.80% |
Expected price volatility range, maximum | 46.70% | 43.66% | 36.80% |
Weighted average expected price volatility | 43.90% | 43.40% | 36.80% |
Expected dividend yield | 0.00% | 0.00% | 0.37% |
Expected term in years at the date of grant | 4 years 6 months | 4 years 6 months | 4 years 6 months |
Share-Based Compensation Sche69
Share-Based Compensation Schedule of Stock Option Transactions (Details) $ / shares in Units, $ in Millions | 12 Months Ended |
Dec. 31, 2017USD ($)$ / sharesshares | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward] | |
Stock options outstanding, beginning of year | shares | 2,151,957 |
Options granted | shares | 418,752 |
Options forfeited | shares | (14,172) |
Options Cancelled | shares | (202,260) |
Stock options outstanding, end of year | shares | 2,354,277 |
Options exercisable, shares | shares | 1,551,861 |
Unvested options, shares | shares | 802,416 |
Share-based Compensation Arrangement by Share-based Payment Award, Additional General Disclosures [Abstract] | |
Weighted average exercise price, beginning of year | $ / shares | $ 25.26 |
Weighted average exercise price, granted in period | $ / shares | 16.77 |
Weighted average exercise price, forfeited in period | $ / shares | 15.33 |
Weighted average exercise price, cancelled in period | $ / shares | 27.55 |
Weighted average exercise price, end of year | $ / shares | 23.62 |
Options exercisable, weighted average exercise price | $ / shares | 27.90 |
Unvested options, weighted average exercise price | $ / shares | $ 15.33 |
Weighted average remaining contractual term, options outstanding | 3 years 6 months |
Weighted average remaining contractual term, options exercisable | 2 years 5 months 21 days |
Weighted average remaining contractual term, options unvested | 5 years 5 months 24 days |
Aggregate intrinsic value, options outstanding | $ | $ 0 |
Aggregate intrinsic value, options exercisable | $ | 0 |
Aggregate intrinsic value, options unvested | $ | $ 0 |
Share-Based Compensation Sche70
Share-Based Compensation Schedule of Restricted Stock Transactions (Details) - Restricted Share Awards [Member] | 12 Months Ended |
Dec. 31, 2017$ / sharesshares | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | |
Unvested balance at beginning of period | shares | 3,208,503 |
Shares granted | shares | 2,219,763 |
Shares vested | shares | (1,392,043) |
Shares forfeited | shares | (314,889) |
Unvested balance at end of period | shares | 3,721,334 |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Additional Disclosures [Abstract] | |
Weighted average grant date fair value, beginning of period | $ / shares | $ 14.32 |
Weighted average grant date fair value, grants | $ / shares | 13.90 |
Weighted average grant date fair value, vested | $ / shares | 16.53 |
Weighted average grant date fair value, forfeited | $ / shares | 14.49 |
Weighted average grant date fair value, end of period | $ / shares | $ 13.23 |
Share-Based Compensation Sche71
Share-Based Compensation Schedule of Performance Share Unit Transactions (Details) - Performance Share Units [Member] | 12 Months Ended |
Dec. 31, 2017$ / sharesshares | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | |
Unvested balance at beginning of period | shares | 1,027,280 |
Shares granted | shares | 405,014 |
Shares vested and paid out | shares | (215,439) |
Shares forfeited | shares | (17,519) |
Unvested balance at end of period | shares | 1,199,336 |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Additional Disclosures [Abstract] | |
Weighted average grant date fair value, beginning of period | $ / shares | $ 17.24 |
Weighted average grant date fair value, grants | $ / shares | 16.90 |
Weighted average grant date fair value, vested and paid out | $ / shares | 31.63 |
Weighted average grant date fair value, forfeited | $ / shares | 13.88 |
Weighted average grant date fair value, end of period | $ / shares | $ 14.59 |
Share-Based Compensation Sche72
Share-Based Compensation Schedule of Restricted Share Unit Transactions (Details) - Restricted Share Units (RSUs) [Member] - $ / shares | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Unvested balance at beginning of period | 18,034 | |
Shares granted | 9,924 | |
Shares vested | (6,012) | |
Unvested balance at end of period | 21,946 | 18,034 |
Weighted average grant date fair value, beginning of period | $ 10.12 | |
Weighted average grant date fair value, grants | 16.98 | $ 10.12 |
Weighted average grant date fair value, vested | 10.12 | |
Weighted average grant date fair value, end of period | $ 13.22 | $ 10.12 |
Employee Benefits (Narrative) (
Employee Benefits (Narrative) (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Defined Benefit Plan, Accumulated Benefit Obligation | $ 128.7 | $ 124.5 | |
Pension Plan [Member] | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Defined Benefit Plan, Contributions by Employer | 4 | ||
Defined Benefit Plan, Estimated Future Employer Contributions in Current Fiscal Year | 4 | ||
Defined Contribution Plan, Employer Discretionary Contribution Amount | $ 0.4 | ||
Defined Benefit Plan, Curtailment loss | $ 11.2 | ||
Pension Plan [Member] | Active Employees [Member] | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Defined Benefit Plan, Number of Employees Covered | 30 | ||
Defined Benefit Plan, Percentage Of Employees Covered | 5.00% | ||
Pension Plan [Member] | Non-active Employees [Member] | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Defined Benefit Plan, Number of Employees Covered | 184 | ||
Pension Plan and SERP [Member] | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Defined Benefit Plan, Contributions by Employer | $ 6 | 7.2 | |
Defined Benefit Plan, Curtailment loss | 0.7 | 0 | 11.2 |
Defined Benefit Plan, Amount to be Amortized from Accumulated Other Comprehensive Income (Loss) Next Fiscal Year | $ 1.9 | ||
Medical Plan [Member] | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Defined Benefit Plan, Number of Eligible | 17 | ||
Defined Benefit Plan, Contributions by Employer | $ 0.1 | 0.4 | |
Defined Benefit Plan, Estimated Future Employer Contributions in Current Fiscal Year | 0.3 | ||
Defined Benefit Plan, Curtailment loss | 0 | $ 0 | $ 0 |
Defined Benefit Plan, Amount to be Amortized from Accumulated Other Comprehensive Income (Loss) Next Fiscal Year | (0.3) | ||
SERP [Member] | |||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | |||
Defined Benefit Plan, Contributions by Employer | 2 | ||
Defined Benefit Plan, Estimated Future Employer Contributions in Current Fiscal Year | 0.7 | ||
Defined Benefit Plan, Curtailment loss | $ 0.7 |
Employee Benefits Schedule of C
Employee Benefits Schedule of Changes in Benefit Obligations and Fair Value of Plan Assets (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Change in plan assets | |||
Fair value of plan assets at January 1, | $ 86.1 | ||
Fair value of plan assets at December 31, | 100.5 | $ 86.1 | |
Pension Plan and SERP [Member] | |||
Change in benefit obligation | |||
Benefit obligation at January 1, | 129.2 | 120.3 | |
Service cost | 0.8 | 1.2 | $ 2.1 |
Interest cost | 4.7 | 5.2 | 4.9 |
Curtailments | (0.3) | 0 | |
Benefit payments | (6.9) | (7.8) | |
Plan amendments | 0 | 0 | |
Actuarial loss (gain) | 2.5 | 10.3 | |
Benefit obligation at December 31, | 130 | 129.2 | 120.3 |
Change in plan assets | |||
Fair value of plan assets at January 1, | 86.1 | 79.3 | |
Actual return on plan assets | 15.3 | 7.4 | |
Company contributions to the plan | 6 | 7.2 | |
Benefit payments | (6.9) | (7.8) | |
Fair value of plan assets at December 31, | 100.5 | 86.1 | 79.3 |
Underfunded status (current and long-term) | (29.5) | (43.1) | |
Amounts recognized in balance sheets | |||
Accounts payable and accrued expenses | (1.5) | (2.5) | |
Other long-term liabilities | (27.9) | (40.6) | |
Total amount recognized in balance sheet | (29.4) | (43.1) | |
Amounts recognized in AOCI | |||
Net actuarial loss (gain) | 15 | 23.5 | |
Prior service cost | 1.2 | 2.9 | |
Total amount recognized in AOCI | 16.2 | 26.4 | |
Medical Plan [Member] | |||
Change in benefit obligation | |||
Benefit obligation at January 1, | 5.4 | 5.2 | |
Service cost | 0 | 0 | 0 |
Interest cost | 0.1 | 0.2 | 0.2 |
Curtailments | 0 | 0 | |
Benefit payments | (0.1) | (0.4) | |
Plan amendments | (2.4) | 0 | |
Actuarial loss (gain) | (0.1) | 0.4 | |
Benefit obligation at December 31, | 2.9 | 5.4 | 5.2 |
Change in plan assets | |||
Fair value of plan assets at January 1, | 0 | 0 | |
Actual return on plan assets | 0 | 0 | |
Company contributions to the plan | 0.1 | 0.4 | |
Benefit payments | (0.1) | (0.4) | |
Fair value of plan assets at December 31, | 0 | 0 | $ 0 |
Underfunded status (current and long-term) | (2.9) | (5.4) | |
Amounts recognized in balance sheets | |||
Accounts payable and accrued expenses | (0.2) | (0.3) | |
Other long-term liabilities | (2.6) | (5.1) | |
Total amount recognized in balance sheet | (2.8) | (5.4) | |
Amounts recognized in AOCI | |||
Net actuarial loss (gain) | (0.5) | (0.4) | |
Prior service cost | (1.2) | 1 | |
Total amount recognized in AOCI | $ (1.7) | $ 0.6 |
Employee Benefits Schedule of N
Employee Benefits Schedule of Net Periodic Benefit Cost and Other Comprehensive Income for Pension and Other Postretirement Benefit Plans (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Pension Plan and SERP [Member] | |||
Components of net periodic benefit cost | |||
Service cost | $ 0.8 | $ 1.2 | $ 2.1 |
Interest cost | 4.7 | 5.2 | 4.9 |
Expected return on plan assets | (5.4) | (5.6) | (5.7) |
Curtailment loss | 0.7 | 0 | 11.2 |
Settlements | 0.2 | 0 | 0 |
Amortization of prior service costs | 1 | 1.1 | 1.7 |
Amortization of actuarial loss | 0.5 | 0.8 | 0.5 |
Periodic expense | 2.5 | 2.7 | 14.7 |
Components recognized in accumulated other comprehensive income | |||
Current period prior service cost | (0.7) | 0 | 0.9 |
Current period actuarial (gain) loss | (7.5) | 8.5 | 2.2 |
Amortization of prior service cost | (1) | (1.1) | (12.9) |
Amortization of actuarial gain (loss) | (0.5) | (0.8) | (0.5) |
Loss on curtailment in current period | (0.3) | 0 | (7.1) |
Settlements | (0.2) | 0 | 0 |
Total amount recognized in accumulated other comprehensive income | (10.2) | 6.6 | (17.4) |
Medical Plan [Member] | |||
Components of net periodic benefit cost | |||
Service cost | 0 | 0 | 0 |
Interest cost | 0.1 | 0.2 | 0.2 |
Expected return on plan assets | 0 | 0 | 0 |
Curtailment loss | 0 | 0 | 0 |
Settlements | 0 | 0 | 0 |
Amortization of prior service costs | (0.3) | 0.2 | 0.2 |
Amortization of actuarial loss | 0.1 | 0 | 0 |
Periodic expense | (0.3) | 0.4 | 0.4 |
Components recognized in accumulated other comprehensive income | |||
Current period prior service cost | (2.5) | 0 | 0 |
Current period actuarial (gain) loss | (0.1) | 0.4 | (1.4) |
Amortization of prior service cost | 0.3 | (0.2) | (0.2) |
Amortization of actuarial gain (loss) | 0.1 | 0 | 0 |
Loss on curtailment in current period | 0 | 0 | 0 |
Settlements | 0 | 0 | 0 |
Total amount recognized in accumulated other comprehensive income | $ (2.2) | $ 0.2 | $ (1.6) |
Employee Benefits Schedule of W
Employee Benefits Schedule of Weighted Average Actuarial Assumptions Used to Determine Benefit Obligations and Net Periodic Benefit Costs (Details) | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Pension Plan and SERP [Member] | |||
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract] | |||
Discount rate used in calculating benefit obligation | 3.52% | 3.96% | |
Rate of increase in compensation used for calculating benefit obligation | 3.50% | 3.50% | |
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract] | |||
Discount rate used in calculating net periodic benefit cost | 4.00% | 4.23% | 3.94% |
Expected long-term return on plan assets used in calculating net periodic benefit cost | 6.00% | 6.50% | 6.75% |
Rate of increase in compensation used in calculating net periodic benefit cost | 3.50% | 4.00% | 4.00% |
Medical Plan [Member] | |||
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract] | |||
Discount rate used in calculating benefit obligation | 3.60% | 4.10% | |
Rate of increase in compensation used for calculating benefit obligation | 3.50% | ||
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract] | |||
Discount rate used in calculating net periodic benefit cost | 4.10% | 4.40% | 4.00% |
Rate of increase in compensation used in calculating net periodic benefit cost | 3.50% | 4.00% | 4.00% |
Employee Benefits Schedule of F
Employee Benefits Schedule of Fair Values of Pension and Postretirement Benefit Assets by Asset Class (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Defined Benefit Plan, Fair Value of Plan Assets | $ 100.5 | $ 86.1 |
Defined Benefit Plan, Actual Plan Asset Allocations | 100.00% | 100.00% |
Cash and short-term investments [Member] | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Defined Benefit Plan, Fair Value of Plan Assets | $ 0.5 | $ 3.5 |
Defined Benefit Plan, Actual Plan Asset Allocations | 0.00% | 4.00% |
Domestic equity securities [Member] | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Defined Benefit Plan, Fair Value of Plan Assets | $ 35 | $ 39.3 |
Defined Benefit Plan, Actual Plan Asset Allocations | 35.00% | 46.00% |
International equity securities [Member] | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Defined Benefit Plan, Fair Value of Plan Assets | $ 15.3 | $ 21.6 |
Defined Benefit Plan, Actual Plan Asset Allocations | 15.00% | 25.00% |
Fixed income securities [Member] | ||
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items] | ||
Defined Benefit Plan, Fair Value of Plan Assets | $ 49.7 | $ 21.7 |
Defined Benefit Plan, Actual Plan Asset Allocations | 50.00% | 25.00% |
Employee Benefits Schedule of E
Employee Benefits Schedule of Expected Benefit Payments for Pension and Other Postretirement Benefits (Details) $ in Millions | Dec. 31, 2017USD ($) |
Pension Plan and SERP [Member] | |
Defined Benefit Plan, Expected Future Benefit Payments, Fiscal Year Maturity [Abstract] | |
2,018 | $ 6.6 |
2,019 | 8.1 |
2,020 | 7.6 |
2,021 | 8.3 |
2,022 | 6.8 |
2023 through 2026 | 39.1 |
Medical Plan [Member] | |
Defined Benefit Plan, Expected Future Benefit Payments, Fiscal Year Maturity [Abstract] | |
2,018 | 0.2 |
2,019 | 0.2 |
2,020 | 0.2 |
2,021 | 0.2 |
2,022 | 0.2 |
2023 through 2026 | $ 0.6 |
Employee Benefits EIP (Details)
Employee Benefits EIP (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Defined Contribution Plan Disclosure [Line Items] | |||
Defined Contribution Plan, Employer Matching Contribution, Percent of Match | 8.00% | 8.00% | 8.00% |
Employee Investment Plan [Member] | |||
Defined Contribution Plan Disclosure [Line Items] | |||
Defined Contribution Plan, Cost Recognized | $ 6 | $ 5.6 | $ 6.3 |
Pension Plan [Member] | |||
Defined Contribution Plan Disclosure [Line Items] | |||
Defined Contribution Plan, Employer Matching Contribution, Percent of Match | 8.00% | 8.00% | 6.00% |
SERP [Member] | |||
Defined Contribution Plan Disclosure [Line Items] | |||
Defined Contribution Plan, Employer Matching Contribution, Percent of Match | 6.00% | 6.00% | 6.00% |
Income Taxes Narrative (Details
Income Taxes Narrative (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Valuation Allowance [Line Items] | ||||
Federal income tax rate | 35.00% | |||
Operating Loss Carryforwards, Valuation Allowance | $ 56.8 | |||
Alternative minimum tax | 19.5 | |||
Balance as of December 31, | 19 | $ 15.6 | $ 15.6 | |
Interest Related to Uncertain Tax Positions | 0.7 | 0.7 | 0.5 | |
Penalties Related to Uncertain Tax Positions | $ 0.6 | $ 2.2 | ||
Louisiana [Member] | ||||
Valuation Allowance [Line Items] | ||||
Operating Loss Carryforwards, Valuation Allowance | $ 31.8 | |||
Subsequent Event [Member] | ||||
Valuation Allowance [Line Items] | ||||
Federal income tax rate | 21.00% |
Income Taxes Schedule of Income
Income Taxes Schedule of Income Tax Expense (Benefit) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Federal income tax provision (benefit) | |||
Current | $ 2.1 | $ (55.5) | $ (112.3) |
Deferred | (339.8) | (614.3) | 34.5 |
State income tax provision (benefit) | |||
Current | 0.5 | (1.5) | (6.6) |
Deferred | 25 | (36.9) | (9.2) |
Total income tax provision (benefit) | $ (312.2) | $ (708.2) | $ (93.6) |
Income Taxes Reconciliation of
Income Taxes Reconciliation of Statutory Federal Income Tax Rate and Effective Tax Rate (Details) - USD ($) $ in Millions | 12 Months Ended | |||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Investments, Owned, Federal Income Tax Note [Line Items] | ||||
Federal income tax rate | 35.00% | |||
Valuation allowance | $ 36.2 | |||
Federal income taxes statutory rate | 35.00% | 35.00% | 35.00% | |
Increase (decrease) in rate as a result of: | ||||
State income taxes, net of federal income tax benefit(1) | (40.10%) | 2.40% | 4.20% | |
Federal rate change(2) | 741.30% | 0.00% | 0.00% | |
State rate change | 2.10% | (1.10%) | 0.00% | |
Penalties | (0.40%) | 0.00% | (0.30%) | |
Return to provision adjustment | (0.70%) | 0.00% | (0.30%) | |
Uncertain tax provision (federal rate change) | (7.70%) | 0.00% | 0.00% | |
Other | (1.80%) | 0.00% | (0.10%) | |
Effective income tax rate | 727.70% | 36.30% | 38.50% | |
Subsequent Event [Member] | ||||
Investments, Owned, Federal Income Tax Note [Line Items] | ||||
Federal income tax rate | 21.00% |
Income Taxes Schedule of Deferr
Income Taxes Schedule of Deferred Income Tax Assets and Liabilities (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Deferred tax liabilities | ||
Property, plant and equipment | $ 898.7 | $ 1,135 |
Deferred tax assets | ||
Net operating loss and tax credit carryforwards | 308.8 | 161.6 |
Employee benefits and compensation costs | 26.4 | 49 |
Bonus and vacation accrual | 6.2 | 11.4 |
Commodity price derivatives | 29.9 | 74.3 |
Other | 9.4 | 12.8 |
Total deferred tax assets | 380.7 | 309.1 |
Net deferred income tax liability | 518 | 825.9 |
Balance sheet classification | ||
Deferred income tax liability – noncurrent | 518 | $ 825.9 |
Net deferred income tax liability | 307.9 | |
Change [Member] | ||
Balance sheet classification | ||
Net deferred income tax liability | $ 318 |
Income Taxes Amounts and Expira
Income Taxes Amounts and Expiration Dates of Net Operating Loss and Tax Credit Carryforwards (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2017USD ($) | |
Operating Loss Carryforwards [Line Items] | |
State net operating loss and tax credit carryforwards | $ 95.8 |
State net operating loss valuation allowance | (56.8) |
U.S. net operating loss | 250.4 |
U.S. alternative minimum tax credit | $ 19.5 |
State [Member] | |
Operating Loss Carryforwards [Line Items] | |
Operating Loss Carryforwards Minimum Expiration Date | 2,018 |
Operating Loss Carryforwards Maximum Expiration Date | 2,034 |
U.S. (Federal) [Member] | |
Operating Loss Carryforwards [Line Items] | |
Operating Loss Carryforwards Minimum Expiration Date | 2,036 |
Operating Loss Carryforwards Maximum Expiration Date | 2,037 |
Income Taxes Unrecognized Tax B
Income Taxes Unrecognized Tax Benefits (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Income Tax Disclosure [Abstract] | ||
Balance as of January 1, | $ 15.6 | $ 15.6 |
Federal benefit of state (change from 35% to 21%) | 3.4 | 0 |
Balance as of December 31, | $ 19 | $ 15.6 |
Quarterly Financial Informati86
Quarterly Financial Information (Unaudited) (Details) $ / shares in Units, $ in Millions, Bcfe in Billions | 3 Months Ended | 12 Months Ended | ||||||||||
Dec. 31, 2017USD ($)BcfeMBoe$ / shares | Sep. 30, 2017USD ($)BcfeMBoe$ / shares | Jun. 30, 2017USD ($)BcfeMBoe$ / shares | Mar. 31, 2017USD ($)BcfeMBoe$ / shares | Dec. 31, 2016USD ($)BcfeMBoe$ / shares | Sep. 30, 2016USD ($)BcfeMBoe$ / shares | Jun. 30, 2016USD ($)BcfeMBoe$ / shares | Mar. 31, 2016USD ($)BcfeMBoe$ / shares | Dec. 31, 2017USD ($)BcfeMBoe$ / shares | Dec. 31, 2016USD ($)BcfeMBoe$ / shares | Dec. 31, 2015USD ($)$ / shares | ||
Quarterly Financial Information Disclosure [Line Items] | ||||||||||||
Revenues | $ 429 | $ 390.1 | $ 383.7 | $ 420.1 | $ 399.7 | $ 382.4 | $ 333.7 | $ 261.3 | $ 1,622.9 | $ 1,377.1 | $ 2,018.6 | |
Operating income (loss) | (24.5) | 132.1 | (0.9) | (5.2) | (36.5) | (93.1) | (92.1) | (1,379) | 101.5 | (1,600.7) | (364.5) | |
Net income (loss) | 150.3 | (3.3) | 45.4 | 76.9 | (133.3) | (50.9) | (197) | (863.8) | 269.3 | (1,245) | $ (149.4) | |
Net gain (loss) from asset sales and impairment | (42.2) | 157.1 | 19.8 | (0.1) | (6.1) | 0.3 | (1.6) | (1,181.9) | 134.6 | (1,189.3) | ||
Nonrecurring items in operating income (loss)(1) | [1] | $ 0 | $ 8.2 | $ 0 | $ 0 | $ 0 | $ 25 | $ 0 | $ 7.7 | $ 8.2 | $ 32.7 | |
Basic | $ / shares | $ 0.62 | $ (0.01) | $ 0.19 | $ 0.32 | $ (0.56) | $ (0.21) | $ (0.90) | $ (4.55) | $ 1.12 | $ (5.62) | $ (0.85) | |
Diluted | $ / shares | $ 0.62 | $ (0.01) | $ 0.19 | $ 0.32 | $ (0.56) | $ (0.21) | $ (0.90) | $ (4.55) | $ 1.12 | $ (5.62) | $ (0.85) | |
Total equivalent production (Mboe) | MBoe | 12,069,900 | 14,124,100 | 13,860,600 | 13,090,300 | 13,675,700 | 14,445,700 | 13,882,400 | 13,776,400 | 53,144,900 | 55,780,200 | ||
Total equivalent production (Bcfe) | Bcfe | 72.1 | 84.7 | 83.2 | 78.6 | 82.1 | 86.6 | 83.3 | 82.7 | 318.6 | 334.7 | ||
[1] | Reflects legal expenses and loss contingencies incurred during the years ended December 31, 2017 and 2016. |
Supplemental Gas and Oil Info87
Supplemental Gas and Oil Information (Unaudited) Capitalized costs (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Capitalized Costs, Oil and Gas Producing Activities, Net [Abstract] | ||
Proved properties | $ 12,470.9 | $ 14,232.5 |
Unproved properties, net | 1,095.8 | 871.5 |
Total proved and unproved properties | 13,566.7 | 15,104 |
Accumulated depreciation, depletion and amortization | (6,642.9) | (8,797.7) |
Net capitalized costs | $ 6,923.8 | $ 6,306.3 |
Supplemental Gas and Oil Info88
Supplemental Gas and Oil Information (Unaudited) Costs incurred (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Abstract] | |||
Accrued capital costs included in development costs | $ 60.6 | ||
ARO additions and revisions | 32 | ||
Costs incurred related to the development of proved undeveloped reserves | 389.3 | $ 258.1 | $ 490.4 |
Proved property acquisitions | 269.6 | 431.6 | 49.6 |
Unproved property acquisitions | 532.4 | 208.7 | 39.8 |
Other acquisitions | 13.2 | 0 | 0 |
Exploration costs (capitalized and expensed) | 32.7 | 13.4 | 8.7 |
Development costs | 1,189.3 | 509.2 | 1,010.3 |
Total costs incurred | $ 2,037.2 | $ 1,162.9 | $ 1,108.4 |
Supplemental Gas and Oil Info89
Supplemental Gas and Oil Information (Unaudited) Results of Operations (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Results of Operations, Income before Income Taxes [Abstract] | |||
Revenues | $ 1,548.1 | $ 1,271 | $ 1,390.4 |
Production costs | 675.4 | 616.7 | 654.1 |
Exploration expenses | 22 | 1.7 | 2.7 |
Depreciation, depletion and amortization | 735.1 | 852.3 | 870.8 |
Impairment | 72.3 | 1,194.3 | 55.6 |
Total expenses | 1,504.8 | 2,665 | 1,583.2 |
Income (loss) before income taxes | 43.3 | (1,394) | (192.8) |
Income tax benefit (expense) | (16) | 517.2 | 70.6 |
Results of operations from producing activities excluding allocated corporate overhead and interest expenses | $ 27.3 | $ (876.8) | $ (122.2) |
Supplemental Gas and Oil Info90
Supplemental Gas and Oil Information (Unaudited) Estimated Quantities of Proved Gas and Oil Reserves (Details) MMBoe in Millions, MMBbls in Millions, Bcf in Billions | 12 Months Ended | ||||||
Dec. 31, 2017MMBoeBcfMMBbls | Dec. 31, 2016MMBoeBcfMMBbls | Dec. 31, 2015MMBoeBcfMMBbls | |||||
Reserve Quantities [Line Items] | |||||||
Extensions and discoveries | MMBoe | 185.4 | ||||||
Oil [Member] | |||||||
Reserve Quantities [Line Items] | |||||||
Proved reserves balance, beginning balance | 238.6 | 193.1 | 172.5 | ||||
Revisions of previous estimates | 3.7 | [1] | (9.7) | [2] | (47) | [3] | |
Extensions and discoveries | 59.1 | [4] | 13 | [5] | 85.6 | [6] | |
Purchase of reserves in place | 46.6 | [7] | 62.7 | [8] | 2 | [9] | |
Sale of reserves in place | (7.9) | [10] | (0.2) | [11] | (0.4) | [12] | |
Production | (19.6) | (20.3) | (19.6) | ||||
Proved reserves balance, ending balance | 320.5 | 238.6 | 193.1 | ||||
Proved undeveloped reserves, beginning balance | 135.4 | 83.4 | 73.2 | ||||
Proved undeveloped reserve, ending balance | 204.5 | 135.4 | 83.4 | ||||
Proved developed reserves, beginning balance | 103.2 | 109.7 | 99.3 | ||||
Proved developed reserves, ending balance | 116 | 103.2 | 109.7 | ||||
Gas [Member] | |||||||
Reserve Quantities [Line Items] | |||||||
Proved reserves balance, beginning balance | Bcf | 2,553.8 | 2,108.9 | 2,317.2 | ||||
Revisions of previous estimates | Bcf | 12.5 | [1] | 412.8 | [2] | (463.8) | [3] | |
Extensions and discoveries | Bcf | 101.9 | [4] | 158.1 | [5] | 467.7 | [6] | |
Purchase of reserves in place | Bcf | 125.5 | [7] | 54.6 | [8] | 3.2 | [9] | |
Sale of reserves in place | Bcf | (831.2) | [10] | (3.6) | [11] | (34.3) | [12] | |
Production | Bcf | (168.9) | (177) | (181.1) | ||||
Proved reserves balance, ending balance | Bcf | 1,793.6 | 2,553.8 | 2,108.9 | ||||
Proved undeveloped reserves, beginning balance | Bcf | 1,244 | 863.6 | 1,028.8 | ||||
Proved undeveloped reserve, ending balance | Bcf | 1,138.1 | 1,244 | 863.6 | ||||
Proved developed reserves, beginning balance | Bcf | 1,309.8 | 1,245.3 | 1,288.4 | ||||
Proved developed reserves, ending balance | Bcf | 655.5 | 1,309.8 | 1,245.3 | ||||
Natural Gas Liquids [Member] | |||||||
Reserve Quantities [Line Items] | |||||||
Proved reserves balance, beginning balance | 67.2 | 58.8 | 96.6 | ||||
Revisions of previous estimates | (3.1) | [1] | (0.3) | [2] | (55.3) | [3] | |
Extensions and discoveries | 10.4 | [4] | 3.3 | [5] | 21.8 | [6] | |
Purchase of reserves in place | 8.7 | [7] | 11.5 | [8] | 0.6 | [9] | |
Sale of reserves in place | (12.6) | [10] | (0.1) | [11] | (0.2) | [12] | |
Production | (5.4) | (6) | (4.7) | ||||
Proved reserves balance, ending balance | 65.2 | 67.2 | 58.8 | ||||
Proved undeveloped reserves, beginning balance | 31.5 | 24.4 | 44.4 | ||||
Proved undeveloped reserve, ending balance | 37.3 | 31.5 | 24.4 | ||||
Proved developed reserves, beginning balance | 35.7 | 34.4 | 52.2 | ||||
Proved developed reserves, ending balance | 27.9 | 35.7 | 34.4 | ||||
Barrels of oil equivalent production [Member] | |||||||
Reserve Quantities [Line Items] | |||||||
Proved developed and undeveloped reserves, beginning balance | MMBoe | [13] | 731.4 | 603.4 | 655.3 | |||
Revisions of previous estimates | MMBoe | [13] | 2.7 | [1] | 58.8 | [2] | (179.6) | [3] |
Extensions and discoveries | MMBoe | [13] | 86.4 | [4] | 42.6 | [5] | 185.4 | [6] |
Purchase of reserves in place | MMBoe | [13] | 76.3 | [7] | 83.3 | [8] | 3.1 | [9] |
Sale of reserves in place | MMBoe | [13] | (159) | [10] | (0.9) | [11] | (6.3) | [12] |
Production | MMBoe | [13] | (53.1) | (55.8) | (54.5) | |||
Proved developed and undeveloped reserves, ending balance | MMBoe | [13] | 684.7 | 731.4 | 603.4 | |||
Proved undeveloped reserves, beginning balance | MMBoe | 374.2 | 251.8 | 289.1 | ||||
Proved undeveloped reserves, ending balance | MMBoe | 431.6 | 374.2 | 251.8 | ||||
Proved developed reserves, beginning balance | MMBoe | 357.2 | 351.6 | 366.2 | ||||
Proved developed reserves, ending balance | MMBoe | 253.1 | 357.2 | 351.6 | ||||
Pricing Revisions [Member] | |||||||
Reserve Quantities [Line Items] | |||||||
Revisions of previous estimates | MMBoe | 32 | 18.5 | 126.2 | ||||
Performance Revisions [Member] | |||||||
Reserve Quantities [Line Items] | |||||||
Revisions of previous estimates | MMBoe | 2.2 | 5.5 | 13.7 | ||||
Positive revisions [Member] | |||||||
Reserve Quantities [Line Items] | |||||||
Revisions of previous estimates | MMBoe | 2.7 | 77.3 | |||||
Operating Cost Revisions [Member] | |||||||
Reserve Quantities [Line Items] | |||||||
Revisions of previous estimates | MMBoe | 11 | ||||||
Other Revisions [Member] | |||||||
Reserve Quantities [Line Items] | |||||||
Revisions of previous estimates | MMBoe | 67.2 | ||||||
Development plan change [Member] | |||||||
Reserve Quantities [Line Items] | |||||||
Revisions of previous estimates | MMBoe | 20.5 | ||||||
Williston Basin [Member] | |||||||
Reserve Quantities [Line Items] | |||||||
Extensions and discoveries | MMBoe | 68.2 | ||||||
Uinta Basin [Member] | |||||||
Reserve Quantities [Line Items] | |||||||
Extensions and discoveries | MMBoe | 53.2 | ||||||
Permian Basin [Member] | |||||||
Reserve Quantities [Line Items] | |||||||
Extensions and discoveries | MMBoe | 49.6 | ||||||
[1] | Revisions of previous estimates in 2017 include 2.7 MMboe of positive revisions, primarily related to 32.0 MMboe of positive revisions related to pricing, driven by higher oil, gas and NGL prices and 2.2 MMboe of positive performance revisions. These positive revisions were partially offset by 11.0 MMboe of negative revisions related to higher operating costs and 20.5 MMboe of other revisions primarily from changing to a horizontal development plan from a vertical well development plan in the Uinta Basin and increased longer laterals in Haynesville/Cotton Valley. These negative other revisions are partially offset by positive other revisions from successful infill drilling in Haynesville/Cotton Valley and the Williston Basin. | ||||||
[2] | Revisions of previous estimates in 2016 include 77.3 MMboe of positive revisions, primarily related to successful workovers in Haynesville/Cotton Valley; reserves associated with increased density wells in areas that have been previously developed on lower density spacing; and 5.5 MMboe of positive performance revisions. These positive revisions were partially offset by 18.5 MMboe of negative revisions related to pricing, driven by lower oil, gas and NGL prices. | ||||||
[3] | Revisions of previous estimates in 2015 include: 126.2 MMboe of negative revisions due to lower pricing and 67.2 MMboe of negative revisions unrelated to pricing, partially offset by 13.7 MMboe of positive performance revisions. Negative pricing revisions were driven by lower oil, gas and NGL prices. Negative other revisions included operating in ethane rejection in Pinedale and the Uinta Basin. | ||||||
[4] | Extensions and discoveries in 2017 primarily related to new well completions and associated new PUD locations in the Permian Basin. | ||||||
[5] | Extensions and discoveries in 2016 were primarily in the Permian and Uinta basins and related to new well completions and associated new PUD locations. | ||||||
[6] | Extensions and discoveries in 2015 increased proved reserves by 185.4 MMboe, primarily related to extensions and discoveries in the Williston Basin of 68.2 MMboe, the Uinta Basin of 53.2 MMboe, and the Permian Basin of 49.6 MMboe. All of these extensions and discoveries related to new well completions and associated new PUD locations. | ||||||
[7] | Purchase of reserves in place in 2017 was primarily related to QEP's 2017 Permian Basin Acquisition and various other acquired oil and gas properties as discussed in Note 2 – Acquisitions and Divestitures. | ||||||
[8] | Purchase of reserves in place in 2016 primarily relates to QEP's 2016 Permian Basin Acquisition as discussed in Note 2 – Acquisitions and Divestitures. | ||||||
[9] | Purchase of reserves in place in 2015 related to the acquisition of additional interests in QEP operated wells in the Williston and Permian basins as discussed in Note 2 – Acquisitions and Divestitures. | ||||||
[10] | Sale of reserves in place in 2017 was primarily related to QEP's Pinedale Divestiture as discussed in Note 2 – Acquisitions and Divestitures. | ||||||
[11] | Sale of reserves in place in 2016 relates to the divestiture of QEP's interest in certain non-core properties as discussed in Note 2 – Acquisitions and Divestitures. | ||||||
[12] | Sale of reserves in place in 2015 relate to the divestiture of QEP's interest in certain non-core properties as discussed in Note 2 – Acquisitions and Divestitures. | ||||||
[13] | Generally, gas consumed in operations was excluded from reserves, however, in some cases, produced gas consumed in operations was included in reserves when the volumes replaced fuel purchases. |
Supplemental Gas and Oil Info91
Supplemental Gas and Oil Information (Unaudited) Average price per unit (Details) | 12 Months Ended | ||
Dec. 31, 2017$ / bbl$ / Mcf | Dec. 31, 2016$ / bbl$ / Mcf | Dec. 31, 2015$ / bbl$ / Mcf | |
Oil [Member] | |||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | |||
12 month average first-of the month commodity price | $ / bbl | 51.34 | 42.75 | 50.28 |
Gas [Member] | |||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | |||
12 month average first-of the month commodity price | $ / Mcf | 2.98 | 2.48 | 2.59 |
Supplemental Gas and Oil Info92
Supplemental Gas and Oil Information (Unaudited) Future Development Costs (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | |||
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Future Development Costs, Next Twelve Months | $ 486.5 | ||
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Future Development Costs, Year Two | 710 | ||
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Future Development Costs, Year Three | 1,006.2 | ||
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Development Costs | 4,726 | $ 3,432.9 | $ 2,202.5 |
Waiting on completion and refracturing [Member] | |||
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | |||
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Development Costs | $ 132.6 |
Supplemental Gas and Oil Info93
Supplemental Gas and Oil Information (Unaudited) Standardized Measure Of Future Net Cash Flows (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | ||||
Future cash inflows | $ 22,028.9 | $ 16,239.8 | $ 15,325.3 | |
Future production costs | (9,074.2) | (7,789) | (7,389.9) | |
Future development costs | (4,726) | (3,432.9) | (2,202.5) | |
Future income tax expenses | (1,439.1) | (913.4) | (1,169.3) | |
Future net cash flows | 6,789.6 | 4,104.5 | 4,563.6 | |
10% annual discount for estimated timing of net cash flows | (3,692.3) | (2,176.5) | (2,087.3) | |
Standardized measure of discounted future net cash flows | $ 3,097.3 | $ 1,928 | $ 2,476.3 | $ 5,340 |
Supplemental Gas and Oil Info94
Supplemental Gas and Oil Information (Unaudited) Change in Standardized Measure of Future Cash Flows (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Change in Standardized Measure of Future Cash Flows [Abstract] | |||
Beginning Balance | $ 1,928 | $ 2,476.3 | $ 5,340 |
Sales of gas, oil and NGL produced during the period, net of production costs | (872.7) | (654.3) | (736.3) |
Net change in sales prices and in production (lifting) costs related to future production | 1,457.2 | (739.4) | (6,307.8) |
Net change due to extensions and discoveries | 556.8 | 81.8 | 1,765.7 |
Net change due to revisions of quantity estimates | 9.9 | 122.7 | (1,350.2) |
Changes due to purchases of reserves in place | 342.7 | 256.5 | 29.7 |
Changes due to sales of reserves in place | (504.7) | (4.3) | (48.8) |
Previously estimated development costs incurred during the period | 475.4 | 374.6 | 865 |
Changes in estimated future development costs | (283.4) | (476.5) | 560.7 |
Accretion of discount | 235.7 | 311.1 | 752.9 |
Net change in income taxes | (227.4) | 205.4 | 1,554.4 |
Other | (20.2) | (25.9) | 51 |
Net change | 1,169.3 | (548.3) | (2,863.7) |
Ending Balance | $ 3,097.3 | $ 1,928 | $ 2,476.3 |
Subsequent Event (Details)
Subsequent Event (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Subsequent Event [Line Items] | ||
Aggregate purchase price | $ 94.5 | $ 54.6 |
Potential Divestitures [Member] | ||
Subsequent Event [Line Items] | ||
Severance Costs | 20 | |
2017 Permian Basin Acquisition [Member] | ||
Subsequent Event [Line Items] | ||
Aggregate purchase price | 720.7 | |
2017 Permian Basin Acquisition [Member] | 2017 Permian Basin Acquisition (Additional) [Member] | ||
Subsequent Event [Line Items] | ||
Aggregate purchase price | $ 36.1 |