Document and Entity Information
Document and Entity Information - USD ($) | 12 Months Ended | ||
Dec. 31, 2017 | Feb. 23, 2018 | Jun. 30, 2017 | |
Document And Entity Information [Abstract] | |||
Document Type | 10-K | ||
Amendment Flag | false | ||
Document Period End Date | Dec. 31, 2017 | ||
Document Fiscal Year Focus | 2,017 | ||
Document Fiscal Period Focus | FY | ||
Trading Symbol | RRC | ||
Entity Registrant Name | RANGE RESOURCES CORP | ||
Entity Central Index Key | 315,852 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Current Reporting Status | Yes | ||
Entity Voluntary Filers | No | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Common Stock, Shares Outstanding | 248,539,169 | ||
Entity Public Float | $ 5,683,957,000 |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 | |
Current assets: | |||
Cash and cash equivalents | $ 448 | $ 314 | |
Accounts receivable, less allowance for doubtful accounts of $7,111 and $5,559 | 348,833 | 241,718 | |
Derivative assets | 58,607 | 13,278 | |
Inventory and other | 21,346 | 26,573 | |
Total current assets | 429,234 | 281,883 | |
Derivative assets | 273 | 205 | |
Goodwill | 1,641,197 | 1,654,292 | |
Natural gas and oil properties, successful efforts method | [1] | 13,216,453 | 12,386,153 |
Accumulated depletion and depreciation | [1] | (3,649,716) | (3,129,816) |
Natural gas and oil properties, successful efforts method, net | [1] | 9,566,737 | 9,256,337 |
Other property and equipment | 114,361 | 112,796 | |
Accumulated depreciation and amortization | (99,695) | (95,923) | |
Other Property and equipment, net | 14,666 | 16,873 | |
Other assets | 76,734 | 72,655 | |
Total assets | 11,728,841 | 11,282,245 | |
Current liabilities: | |||
Accounts payable | 343,871 | 229,190 | |
Asset retirement obligations | 6,327 | 7,271 | |
Accrued liabilities | 317,531 | 265,843 | |
Accrued interest | 43,511 | 35,340 | |
Derivative liabilities | 44,233 | 165,009 | |
Total current liabilities | 755,473 | 702,653 | |
Bank debt | 1,208,467 | 876,428 | |
Senior notes | 2,851,754 | 2,848,591 | |
Senior subordinated notes | 48,585 | 48,498 | |
Deferred tax liabilities | 693,356 | 943,343 | |
Derivative liabilities | 9,789 | 24,491 | |
Deferred compensation liabilities | 101,102 | 119,231 | |
Asset retirement obligations and other liabilities | 286,043 | 310,642 | |
Total liabilities | 5,954,569 | 5,873,877 | |
Commitments and contingencies | |||
Stockholders' Equity | |||
Preferred stock, $1 par 10,000,000 shares authorized, none issued and outstanding | 0 | 0 | |
Common stock, $0.01 par 475,000,000 shares authorized, 248,144,397 issued at December 31, 2017 and 247,174,903 issued at December 31, 2016 | 2,481 | 2,471 | |
Common stock held in treasury, 14,967 shares at December 31, 2017 and 30,547 shares at December 31, 2016 | (599) | (1,209) | |
Additional paid-in capital | 5,577,732 | 5,524,423 | |
Accumulated other comprehensive loss | (1,332) | 0 | |
Retained earnings (deficit) | 195,990 | (117,317) | |
Total stockholders' equity | 5,774,272 | 5,408,368 | |
Total liabilities and stockholders' equity | $ 11,728,841 | $ 11,282,245 | |
[1] | Includes capitalized asset retirement costs and the associated accumulated amortization. |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Statement Of Financial Position [Abstract] | ||
Allowance for doubtful accounts on accounts receivable | $ 7,111 | $ 5,559 |
Preferred stock, par value | $ 1 | $ 1 |
Preferred stock, shares authorized | 10,000,000 | 10,000,000 |
Preferred stock, shares issued | 0 | 0 |
Preferred stock, shares outstanding | 0 | 0 |
Common stock, par value | $ 0.01 | $ 0.01 |
Common stock, shares authorized | 475,000,000 | 475,000,000 |
Common stock, shares issued | 248,144,397 | 247,174,903 |
Common stock held in treasury, shares | 14,967 | 30,547 |
CONSOLIDATED STATEMENTS OF OPER
CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands | 3 Months Ended | 9 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, 2014 | Dec. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | ||
Revenues and other income: | ||||||||||||||
Natural gas, NGLs and oil sales | $ 603,159 | $ 507,541 | $ 506,137 | $ 559,450 | $ 458,645 | $ 304,477 | $ 224,606 | $ 209,487 | $ 2,176,287 | $ 1,197,215 | $ 1,089,644 | |||
Derivative fair value income (loss) | 25,024 | (88,426) | 111,195 | 165,557 | (250,057) | 64,556 | (162,798) | 86,908 | 213,350 | (261,391) | 416,364 | |||
Brokered natural gas, marketing and other | 50,849 | 63,117 | 55,779 | 51,648 | 44,934 | 44,174 | 39,989 | 35,018 | 221,393 | 164,115 | 92,060 | |||
Total revenues and other income | 679,032 | 482,232 | 673,111 | 776,655 | 253,522 | 413,207 | 101,797 | 331,413 | 2,611,030 | 1,099,939 | 1,598,068 | |||
Costs and expenses: | ||||||||||||||
Direct operating | 37,921 | 36,888 | 31,420 | 28,023 | 30,276 | 22,387 | 20,671 | 24,054 | 134,252 | 97,388 | 136,363 | |||
Transportation, gathering, processing and compression | 200,300 | 191,645 | 191,590 | 177,648 | 164,338 | 138,764 | 136,844 | 125,263 | 761,183 | 565,209 | 396,739 | |||
Production and ad valorem taxes | 11,757 | 11,993 | 9,969 | 9,163 | 6,790 | 6,717 | 6,049 | 5,887 | 42,882 | 25,443 | 33,860 | |||
Brokered natural gas and marketing | 51,131 | 59,773 | 55,857 | 53,550 | 46,471 | 44,622 | 40,925 | 36,558 | 220,311 | 168,576 | 115,866 | |||
Exploration | 7,893 | 22,767 | 14,498 | 8,504 | 13,684 | 6,943 | 6,785 | 4,913 | 53,662 | 32,325 | 21,406 | |||
Abandonment and impairment of unproved properties | 217,544 | 42,568 | 5,193 | 4,420 | 6,307 | 6,082 | 7,059 | 10,628 | 269,725 | 30,076 | 47,619 | |||
General and administrative | 80,553 | 53,035 | 52,322 | 47,496 | 57,027 | 41,024 | 46,064 | 40,657 | 233,406 | 184,772 | 194,015 | |||
MRD Merger expenses | 813 | 33,791 | 2,621 | 0 | $ 37,200 | 0 | 37,225 | 0 | ||||||
Termination costs | (279) | (47) | (96) | 4,192 | (822) | 136 | 5 | 162 | $ 8,400 | 3,770 | (519) | 15,070 | ||
Deferred compensation plan | (14,077) | (9,203) | (14,466) | (13,169) | (11,013) | (11,636) | 25,746 | 16,056 | (50,915) | 19,153 | (77,627) | |||
Interest | 51,473 | 49,179 | 47,926 | 47,101 | 46,749 | 45,967 | 37,758 | 37,739 | 195,679 | 168,213 | 166,439 | |||
Loss on early extinguishment of debt | 0 | 0 | 22,495 | |||||||||||
Depletion, depreciation and amortization | 162,918 | 159,749 | 152,504 | 149,821 | 149,662 | 131,489 | 122,390 | 120,561 | 624,992 | 524,102 | 581,155 | |||
Impairment of proved properties | 0 | 63,679 | 0 | 0 | 0 | 0 | 0 | 43,040 | 63,679 | 43,040 | 590,174 | |||
(Gain) loss on the sale of assets | (207) | (102) | (807) | (22,600) | (470) | 2,597 | 3,304 | 1,643 | (23,716) | 7,074 | 406,856 | |||
Total costs and expenses | 806,927 | 681,924 | 545,910 | 494,149 | 509,812 | 468,883 | 456,221 | 467,161 | 2,528,910 | 1,902,077 | 2,650,430 | |||
Income (loss) before income taxes | (127,895) | (199,692) | 127,201 | 282,506 | (256,290) | (55,676) | (354,424) | (135,748) | 82,120 | (802,138) | (1,052,362) | |||
Income tax (benefit) expense: | ||||||||||||||
Current | 17 | 0 | 0 | 0 | 98 | 0 | 0 | 0 | 17 | 98 | 29 | |||
Deferred | (349,097) | (71,992) | 57,651 | 112,395 | (95,679) | (13,705) | (129,488) | (41,976) | (251,043) | (280,848) | (338,706) | |||
Total (benefit) expense for income taxes | (349,080) | (71,992) | 57,651 | 112,395 | (95,581) | (13,705) | (129,488) | (41,976) | (251,026) | (280,750) | (338,677) | |||
Net income (loss) | $ 221,185 | $ (127,700) | $ 69,550 | $ 170,111 | $ (160,709) | $ (41,971) | $ (224,936) | $ (93,772) | $ 333,146 | $ (521,388) | $ (713,685) | |||
Net income (loss) per common share: | ||||||||||||||
Basic | $ 0.89 | $ (0.52) | $ 0.28 | $ 0.69 | $ (0.66) | $ (0.23) | $ (1.35) | $ (0.56) | $ 1.34 | $ (2.75) | $ (4.29) | |||
Diluted | $ 0.89 | $ (0.52) | $ 0.28 | $ 0.69 | $ (0.66) | $ (0.23) | $ (1.35) | $ (0.56) | $ 1.34 | $ (2.75) | $ (4.29) | |||
Weighted average common shares outstanding: | ||||||||||||||
Basic | [1] | 245,091 | 189,868 | 166,389 | ||||||||||
Diluted | 245,458 | 189,868 | 166,389 | |||||||||||
[1] | Includes common stock issued in connection with the exchange of 77.0 million shares for all outstanding Memorial common stock on September 16, 2016. |
CONSOLIDATED STATEMENTS OF COMP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Statement Of Income And Comprehensive Income [Abstract] | |||
Net income (loss) | $ 333,146 | $ (521,388) | $ (713,685) |
Postretirement benefits: | |||
Prior service cost | (1,769) | 0 | 0 |
Income tax benefit | 437 | 0 | 0 |
Total comprehensive income (loss) | $ 331,814 | $ (521,388) | $ (713,685) |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Operating activities: | |||
Net income (loss) | $ 333,146,000 | $ (521,388,000) | $ (713,685,000) |
Adjustments to reconcile net income (loss) to net cash provided from operating activities: | |||
Deferred income tax benefit | (251,043,000) | (280,848,000) | (338,706,000) |
Depletion, depreciation and amortization and impairment | 688,671,000 | 567,142,000 | 1,171,329,000 |
Exploration dry hole and impairment costs | 9,172,000 | 18,000 | 88,000 |
Abandonment and impairment of unproved properties | 269,725,000 | 30,076,000 | 47,619,000 |
Derivative fair value (income) loss | (213,350,000) | 261,391,000 | (416,364,000) |
Cash settlements on derivative financial instruments | 13,117,000 | 347,336,000 | 532,122,000 |
Allowance for bad debt | 1,550,000 | 800,000 | 2,300,000 |
Amortization of deferred financing costs, loss on extinguishment of debt and other | 5,445,000 | 7,170,000 | 29,383,000 |
Deferred and stock-based compensation | 30,706,000 | 74,685,000 | (20,411,000) |
(Gain) loss on the sale of assets | (23,716,000) | 7,074,000 | 406,856,000 |
Changes in working capital: | |||
Accounts receivable | (102,866,000) | (20,586,000) | 64,704,000 |
Inventory and other | (2,979,000) | 6,220,000 | (14,868,000) |
Accounts payable | 45,912,000 | (27,259,000) | (26,197,000) |
Accrued liabilities and other | 12,764,000 | (64,763,000) | (32,768,000) |
Net cash provided from operating activities | 816,254,000 | 387,068,000 | 691,402,000 |
Investing activities: | |||
Additions to natural gas and oil properties | (1,148,613,000) | (466,252,000) | (1,030,644,000) |
Additions to field service assets | (5,710,000) | (3,052,000) | (4,441,000) |
Acreage purchases | (58,213,000) | (43,482,000) | (74,880,000) |
MRD Merger, net of cash acquired | 0 | 7,180,000 | 0 |
Other | 0 | 0 | (75,000) |
Proceeds from disposal of assets | 72,468,000 | 193,755,000 | 890,901,000 |
Purchases of marketable securities held by the deferred compensation plan | (88,167,000) | (37,019,000) | (28,876,000) |
Proceeds from the sales of marketable securities held by the deferred compensation plan | 89,178,000 | 40,035,000 | 29,243,000 |
Net cash used in investing activities | (1,139,057,000) | (308,835,000) | (218,772,000) |
Financing activities: | |||
Borrowings on credit facilities | 2,041,000,000 | 2,274,000,000 | 2,271,000,000 |
Repayments on credit facilities | (1,712,000,000) | (1,487,000,000) | (2,899,000,000) |
Issuance of senior notes | 0 | 0 | 750,000,000 |
Repayment of senior or senior subordinated notes | (500,000) | (273,012,000) | (516,875,000) |
Dividends paid | (19,839,000) | (16,682,000) | (27,083,000) |
Debt issuance costs | (403,000) | (6,342,000) | (14,156,000) |
Taxes paid for shares withheld | (6,983,000) | (3,849,000) | (7,702,000) |
Change in cash overdrafts | 17,180,000 | 18,393,000 | (37,089,000) |
Proceeds from the sales of common stock held by the deferred compensation plan | 4,482,000 | 13,102,000 | 8,298,000 |
Net cash provided from (used in) financing activities | 322,937,000 | (78,390,000) | (472,607,000) |
Increase (decrease) in cash and cash equivalents | 134,000 | (157,000) | 23,000 |
Cash and cash equivalents at beginning of year | 314,000 | 471,000 | 448,000 |
Cash and cash equivalents at end of year | 448,000 | 314,000 | 471,000 |
MRD | |||
Financing activities: | |||
Repayments on credit facilities | $ 0 | $ (597,000,000) | $ 0 |
CONSOLIDATED STATEMENTS OF SHAR
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY - USD ($) $ in Thousands | Total | Common Stock | Common stock held in treasury | Additional paid-in capital | Retained earnings/(deficit) | Accumulated other comprehensive (loss) |
Beginning balance at Dec. 31, 2014 | $ 3,457,429 | $ 1,687 | $ (3,088) | $ 2,400,475 | $ 1,058,355 | $ 0 |
Beginning balance Shares at Dec. 31, 2014 | 168,711,000 | |||||
Issuance of common stock | 10,073 | $ 6 | 0 | 10,067 | 0 | 0 |
Issuance of common stock, shares | 665,000 | |||||
Stock-based compensation expense | 36,496 | $ 0 | 0 | 36,496 | 0 | 0 |
Tax benefit related to stock-based compensation | (3,572) | 0 | 0 | (3,572) | 0 | 0 |
Common dividends declared ($0.16 per share for 2015 and $0.08 per share for 2016, 2017) | (27,083) | 0 | 0 | 0 | (27,083) | 0 |
Treasury stock issuance | 0 | 843 | (843) | 0 | 0 | |
Net income (loss) | (713,685) | 0 | 0 | 0 | (713,685) | 0 |
Ending balance at Dec. 31, 2015 | 2,759,658 | $ 1,693 | (2,245) | 2,442,623 | 317,587 | 0 |
Ending balance Shares at Dec. 31, 2015 | 169,376,000 | |||||
Issuance of common stock | 3,048,653 | $ 778 | 0 | 3,047,875 | 0 | 0 |
Issuance of common stock, shares | 77,799,000 | |||||
Stock-based compensation expense | 37,023 | $ 0 | 0 | 37,023 | 0 | 0 |
Tax benefit related to stock-based compensation | (2,062) | 0 | 0 | (2,062) | 0 | 0 |
Common dividends declared ($0.16 per share for 2015 and $0.08 per share for 2016, 2017) | (16,682) | 0 | 0 | 0 | (16,682) | 0 |
Cumulative-effect adjustment from adoption of ASU 2016-09 | 103,166 | 0 | 0 | 0 | 103,166 | 0 |
Treasury stock issuance | 0 | 1,036 | (1,036) | 0 | 0 | |
Net income (loss) | (521,388) | 0 | 0 | 0 | (521,388) | 0 |
Ending balance at Dec. 31, 2016 | $ 5,408,368 | $ 2,471 | (1,209) | 5,524,423 | (117,317) | 0 |
Ending balance Shares at Dec. 31, 2016 | 247,174,903 | 247,175,000 | ||||
Issuance of common stock | $ 2,987 | $ 10 | 0 | 2,977 | 0 | 0 |
Issuance of common stock, shares | 969,000 | |||||
Stock-based compensation expense | 50,942 | $ 0 | 0 | 50,942 | 0 | 0 |
Common dividends declared ($0.16 per share for 2015 and $0.08 per share for 2016, 2017) | (19,839) | 0 | 0 | 0 | (19,839) | 0 |
Treasury stock issuance | 0 | 0 | 610 | (610) | 0 | 0 |
Other comprehensive loss | (1,332) | 0 | 0 | 0 | 0 | (1,332) |
Net income (loss) | 333,146 | 0 | 0 | 0 | 333,146 | 0 |
Ending balance at Dec. 31, 2017 | $ 5,774,272 | $ 2,481 | $ (599) | $ 5,577,732 | $ 195,990 | $ (1,332) |
Ending balance Shares at Dec. 31, 2017 | 248,144,397 | 248,144,000 |
CONSOLIDATED STATEMENTS OF SHA8
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (Parenthetical) - $ / shares | 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, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Statement Of Stockholders Equity [Abstract] | |||||||||||||||
Common dividends declared per share | $ 0.02 | $ 0.02 | $ 0.02 | $ 0.02 | $ 0.02 | $ 0.02 | $ 0.02 | $ 0.02 | $ 0.04 | $ 0.04 | $ 0.04 | $ 0.04 | $ 0.08 | $ 0.08 | $ 0.16 |
Summary of Organization and Nat
Summary of Organization and Nature of Business | 12 Months Ended |
Dec. 31, 2017 | |
Industry Specific Policies [Abstract] | |
Summary of Organization and Nature of Business | (1) Summary of Organization and Nature of Business Range Resources Corporation (“Range,” “we,” “us,” or “our”) is a Fort Worth, Texas-based independent natural gas, NGLs and oil company primarily engaged in the exploration, development and acquisition of natural gas and oil properties in the Appalachian and North Louisiana regions of the United States. Our objective is to build stockholder value through consistent returns − focused on growth, on a per share debt-adjusted basis, of both reserves and production on a cost-efficient basis. Range is a Delaware corporation with our common stock listed and traded on the New York Stock Exchange under the symbol “RRC”. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | (2) Summary of Significant Accounting Policies Basis of Presentation and Principles of Consolidation The accompanying consolidated financial statements include the accounts of all of our subsidiaries. All material intercompany balances and transactions have been eliminated. Use of Estimates The preparation of financial statements in accordance with U.S. GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from these estimates and changes in these estimates are recorded when known. Business Segment Information We have evaluated how we are organized and managed and have identified only one operating segment, which is the exploration and production of natural gas, NGLs and oil in the United States. We consider our gathering, processing and marketing functions as integral to our natural gas and oil producing activities. Operating segments are defined as components of an enterprise that engage in activities from which it may earn revenues and incur expenses for which separate operational financial information is available and this information is regularly evaluated by the chief operating decision maker for the purpose of allocating resources and assessing performance. We have a single company-wide management team that administers all properties as a whole rather than by discrete operating segments. We track only basic operational data by area. We do not maintain complete separate financial statement information by area. We measure financial performance as a single enterprise and not on a geographical or area-by-area basis. Throughout the year, we allocate capital resources on a project-by-project basis, across our entire asset base to optimize returns without regard to individual areas. Revenue Recognition, Accounts Receivable and Gas Imbalances Natural gas, NGLs and oil sales are recognized when we deliver our production to the customer and collectability is reasonably assured. We generally sell natural gas, NGLs and oil under two types of agreements, which are common in our industry. Both types of agreements include transportation charges. We are reporting our gathering and transportation costs in accordance with Accounting Standards Code Section 605-45-05 of Subtopic 605-45 for Revenue Recognition. One type of agreement is a netback arrangement, under which we sell natural gas and oil at the wellhead and collect a price, net of transportation incurred by the purchaser. In this case, we record revenue at the price we receive from the purchaser. For the sale of our NGLs, in some cases, we receive a price from the purchaser (which is net of processing costs) that is recorded in revenue at the net price we receive. Under the other type of agreement, we sell natural gas, NGLs or oil at a specific delivery point, pay transportation, gathering, processing and compression expenses to a third party and receive proceeds from the purchaser with no deduction. In that case, we record revenue at the price received from the purchaser and record the expenses we incur as transportation, gathering, processing and compression expense. We realize brokered margins as a result of buying and selling natural gas utilizing separate purchase and sale transactions, typically with separate counterparties, whereby Range or the counterparty takes title to the natural gas purchased or sold. Revenues and expenses related to brokered natural gas are reported gross as part of revenues and expenses in accordance with applicable accounting standards. Our net brokered margin was a loss of $5.7 million in 2017 compared to losses of $2.8 million in 2016 and losses of $2.7 million in 2015. Although receivables are concentrated in the oil and gas industry, we do not view this as an unusual credit risk. We provide for an allowance for doubtful accounts for specific receivables judged unlikely to be collected based on the age of the receivable, our experience with the debtor, potential offsets to the amount owed and economic conditions. In certain instances, we require purchasers to post stand-by letters of credit. Many of our receivables are from joint interest owners of properties we operate. Thus, we may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. We have allowances for doubtful accounts relating to exploration and production receivables of $7.1 million at December 31, 2017 compared to $5.6 million at December 31, 2016. We recorded bad debt expense of $1.6 million in the year ended December 31, 2017 compared to $800,000 in the year ended December 31, 2016 and $2.3 million in the year ended 2015. Revenues from the production of natural gas, NGLs and oil on properties in which we have joint ownership are recorded under the sales method. Under the sales method, we and other joint owners may sell more or less than our entitled share of production. Should our sales exceed our share of remaining reasonable reserves, a liability is recorded. Imbalances are not significant in the periods presented. Cash and Cash Equivalents Cash and cash equivalents include cash on hand and on deposit and investments in highly liquid debt instruments with maturities of three months or less. Outstanding checks in excess of funds on deposit are included in accounts payable on the consolidated balance sheets and the change in such overdrafts is classified as a financing activity on the consolidated statements of cash flows. Marketable Securities Investments in unaffiliated equity securities held in our deferred compensation plans qualify as trading securities and are recorded at fair value. Investments held in the deferred compensation plans consist of various publicly-traded mutual funds. These funds include equity securities and money market instruments and are reported in other assets in the accompanying consolidated balance sheets. Inventory Inventories were comprised of $12.1 million of materials and supplies at December 31, 2017 compared to $9.4 million at December 31, 2016. Inventories consist primarily of tubular goods and equipment used in our operations and are stated at the lower of specific cost of each inventory item or net realizable value, on a first-in, first-out basis. Our material and supplies inventory is primarily acquired for use in future drilling operations or repair operations and is reviewed periodically for obsolescence or impairment when market conditions indicate. At December 31, 2017, we also had commodity inventory of $508,000, compared to $8.3 million at December 31, 2016, which is carried at lower of weighted average cost or net realizable value, on a first-in, first-out basis. Commodity inventory at December 31, 2017 consists of NGLs held as line fill in pipelines or tanks. Goodwill As a result of our merger with Memorial Resource Development Corp. (the “MRD Merger” or “Memorial”) in September 2016, we have goodwill in the amount of $1.6 billion at December 31, 2017, the excess of consideration transferred over the fair value of Memorial. Goodwill is not amortized but tested for impairment annually, as of November 1 st Performing a qualitative impairment assessment of our business requires an examination of relevant events and circumstances that could have a negative impact on our business, such as macroeconomic conditions, industry and market conditions (including current commodity price), earnings and cash flows, overall financial performance and other relevant entity specific events. When performing a quantitative impairment assessment of goodwill, fair value is estimated based on a combination of (i) recent market transactions, where available; and (ii) projected discounted cash flows (an income approach). Under the income approach, the fair value is based on the present value of expected future cash flows. The income approach is dependent on a number of factors including estimates of forecasted revenue and operating costs, proved reserves, as well as the success of future exploration for and development of unproved reserves, discount rates and other variables. Negative revisions of estimated reserves quantities, increases in future cost estimates, divestitures or sustained decreases in crude oil or natural gas prices could lead to a reduction in expected future cash flows and possibly an impairment of all or a portion of goodwill in future periods. Key assumptions used in the discounted cash flow model include estimated quantities of crude oil, natural gas and NGLs reserves, including both proved reserves and risk-adjusted unproved reserves; estimates of market prices considering forward commodity price curves as of the measurement date; and estimates of operating, administrative and capital costs adjusted for inflation. We discount the resulting future cash flows using a peer company based weighted average cost of capital. Under the market approach, we would estimate fair value by a comparison to similar businesses whose securities are actively traded in the public market. This requires management to make certain judgments including the selection of comparable companies and/or comparable recent company asset transactions, transaction premiums and selected financial metrics. If natural gas, NGLs and oil prices decrease, drilling efforts are unsuccessful or our market capitalization declines further, it is reasonably possible that we would be required to record additional impairments. Natural Gas and Oil Properties Property Acquisition Costs . We use the successful efforts method of accounting for natural gas and oil producing activities. Costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs, delay rentals and costs of carrying and retaining unproved properties are expensed. Costs incurred for exploratory wells that find reserves that cannot yet be classified as proved are capitalized if (a) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (b) we are making sufficient progress assessing the reserves and the economic and operating viability of the project. The status of suspended well costs is monitored continuously and reviewed not less than quarterly. We capitalize successful exploratory wells and all developmental wells, whether successful or not. Due to the capital-intensive nature and the geographical location of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and the economics associated with making a determination on its commercial viability. In these instances, the project’s feasibility is not contingent upon price improvements or advances in technology, but rather our ongoing efforts and expenditures related to accurately predicting the hydrocarbon recoverability based on well information, gaining access to other companies’ production data in the area, transportation or processing facilities and/or obtaining partner approval to drill additional appraisal wells. These activities are ongoing and are being pursued constantly. Consequently, our assessment of suspended exploratory well costs is continuous until a decision can be made that the project has found proved reserves to sanction the project or is noncommercial and is charged to exploration expense. For more information regarding suspended exploratory well costs, see Note 7. Depreciation, Depletion and Amortization . Depreciation, depletion and amortization of proved producing properties, including other property and equipment such as gathering lines related to natural gas and oil producing activities, is provided on the units of production method. Historically, we have adjusted our depletion rates in the fourth quarter of each year based on the year-end reserve report and at other times during the year when circumstances indicate there has been a significant change in reserves or costs. In the year ended December 31, 2015, the fair value of our natural gas and oil properties in Northwest Pennsylvania was determined to be zero. As a result, any future adjustments to the asset retirement liability for these properties represents an impairment expense and we have elected to record such expense in depreciation, depletion and amortization. In the year ended December 31, 2017, additional expense of $158,000 was recorded related to these costs compared to $1.9 million in the year ended December 31, 2016. Impairments . Our proved natural gas and oil properties are reviewed for impairment annually and periodically as events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. These assets are reviewed for potential impairment at the lowest level for which there are identifiable cash flows that are largely independent of other groups of assets which is the level at which depletion is calculated. The review is done by determining if the historical cost of proved properties less the applicable accumulated depreciation, depletion and amortization is less than the estimated expected undiscounted future net cash flows. The expected future net cash flows are estimated based on our plans to produce and develop reserves. Expected future net cash inflow from the sale of produced reserves is calculated based on estimated future prices and estimated operating and development costs. We estimate prices based upon market-related information including published futures prices. The estimated future level of production, which is based on proved and risk adjusted probable and possible reserves, has assumptions surrounding the future levels of prices and costs, field decline rates, market demand and supply, and the economic and regulatory climate. In certain circumstances, we also consider potential sales of properties to third parties in our estimates of cash flows. When the carrying value exceeds the sum of undiscounted future net cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future net cash flows using a discount rate similar to that used by market participants) and the carrying value of the asset. A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events. Such events include a projection of future natural gas and oil prices, an estimate of the ultimate amount of recoverable natural gas and oil reserves that will be produced from an asset group, the timing of future production, future production costs, future abandonment costs and future inflation. We cannot predict whether impairment charges may be required in the future. If natural gas, NGLs and oil prices decrease or drilling efforts are unsuccessful, we may be required to record additional impairments. For additional information regarding proved property impairments, see Note 12. We evaluate our unproved property investment periodically for impairment. The majority of these costs generally relate to the acquisition of leasehold costs. The costs are capitalized and evaluated (at least quarterly) as to recoverability, based on changes brought about by economic factors and potential shifts in business strategy employed by management. Impairment of a significant portion of our unproved properties is assessed and amortized on an aggregate basis based on our average holding period, expected forfeiture rate and anticipated drilling success. Impairment of individually significant unproved property is assessed on a property-by-property basis considering a combination of time, geologic and engineering factors. In certain circumstances, our future plans to develop acreage may accelerate our impairment. Unproved properties had a net book value of $2.6 billion as of December 31, 2017 compared to $2.9 billion in 2016. We have recorded abandonment and impairment expense related to unproved properties of $269.7 million in the year ended December 31, 2017 compared to $30.1 million in 2016 and $47.6 million in 2015. Dispositions . Proceeds from the disposal of natural gas and oil producing properties that are part of an amortization base are credited to the net book value of the amortization group with no immediate effect on income. However, gain or loss is recognized if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the amortization base. Dispositions are accounted for as a sale of assets. For additional information regarding our dispositions, see Note 3. Acquisitions . Acquisitions of proved properties are accounted for as either a business combination or an asset acquisition and, accordingly, the results of operations are included in the accompanying consolidated statements of operations from the closing date of the acquisition. In a business combination, purchase prices are allocated to acquired assets and assumed liabilities based on their estimated fair value at the time of the acquisition. In an asset acquisition, fair value is assigned to the assets acquired. In the past, acquisitions have been funded with internal cash flow, bank borrowings and the issuance of debt and equity securities. For additional information regarding our acquisitions, see Note 3. Other Property and Equipment Other property and equipment includes assets such as buildings, furniture and fixtures, field equipment, leasehold improvements and data processing and communication equipment. These items are generally depreciated by individual components on a straight-line basis over their economic useful life, which is generally from three to ten years. Leasehold improvements are amortized over the lesser of their economic useful lives or the underlying terms of the associated leases. Depreciation expense was $7.7 million in the year ended December 31, 2017 compared to $8.4 million in the year ended December 31, 2016 and $11.9 million in the year ended December 31, 2015. Other Assets Other assets at December 31, 2017 include $67.1 million of marketable securities held in our deferred compensation plans and $9.6 million of other investments including surface acreage. Other assets at December 31, 2016 include $61.7 million of marketable securities held in our deferred compensation plans and $10.6 million of other investments including surface acreage. Stock-based Compensation Arrangements We account for stock-based compensation under the fair value method of accounting. We grant various types of stock-based awards including restricted stock and performance-based awards. The fair value of our restricted stock awards and our performance-based awards (where the performance condition is based on internal performance metrics) is based on the market value of our common stock on the date of grant. The fair value of our performance-based awards where the performance condition is based on market conditions is estimated using a Monte Carlo simulation method. We recognize stock-based compensation expense on a straight-line basis over the requisite service period for the entire award. The expense we recognize is net of estimated forfeitures. We estimate our forfeiture rate based on prior experience and adjust it as circumstances warrant. If actual forfeitures are different than expected, adjustments to recognize expense may be required in future periods. To the extent possible, we limit the amount of shares to be issued for these awards by satisfying tax withholding requirements with cash. All awards have been issued at prevailing market prices at the time of grant and the vesting of these awards is based on an employee’s continued employment with us, with the exception of employment termination due to death, disability or retirement. For additional information regarding stock-based compensation, see Note 13. Derivative Financial Instruments and Hedging All of our derivative instruments are issued to manage the price risk attributable to our expected natural gas, NGLs and oil production. While there is risk that the financial benefit of rising natural gas, NGLs and oil prices may not be captured, we believe the benefits of stable and predictable cash flow are more important. Among these benefits are more efficient utilization of existing personnel and planning for future staff additions, the flexibility to enter into long-term projects requiring substantial committed capital, smoother and more efficient execution of our ongoing development drilling and production enhancement programs, more consistent returns on invested capital and better access to bank and other capital markets. All unsettled derivative instruments are recorded in the accompanying consolidated balance sheets as either an asset or a liability measured at their fair value. In most cases, our derivatives are reflected on our consolidated balance sheets on a net basis by brokerage firm when they are governed by master netting agreements. Changes in a derivative’s fair value are recognized in earnings. Cash flows from derivative contract settlements are reflected in operating activities in the accompanying consolidated statements of cash flows. All realized and unrealized gains and losses on derivatives are accounted for using the mark-to-market accounting method. We recognize all unrealized and realized gains and losses related to these contracts in each period in derivative fair value in the accompanying consolidated statements of operations. Certain of our derivatives are swaps where we receive a fixed price for our production and pay market prices to the counterparty. We also have collars which establish a minimum floor price and a predetermined ceiling price. At times, we have also entered into basis swap agreements. The price we receive for our natural gas production can be more or less than the NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors; therefore, we have entered into natural gas basis swap agreements that effectively fix our basis adjustments. We have also entered into propane basis swaps which lock in the differential between Mont Belvieu and international propane indexes. In third quarter 2017, we entered into combined natural gas derivative instruments containing a fixed price swap and a sold option to extend or double the volume (which we refer to as a swaption). The swap price is a fixed price determined at the time of the swaption contract. If the option is exercised, the contract will become a swap treated consistently with our fixed-price swaps. For additional information regarding our derivatives, see Note 11. From time to time, we may enter into derivative contracts and pay or receive premium payments at the inception of the derivative contract which represent the fair value of the contract at its inception. These amounts would be included within the net derivative asset or liability on our consolidated balance sheets. The amounts paid or received for derivative premiums reduce or increase the amount of gains and losses that are recorded in the earnings each period as the derivative contracts settle. During 2017, we did not modify any existing derivative contracts. Concentrations of Credit Risk As of December 31, 2017, our primary concentrations of credit risk are the risks of collecting accounts receivable and the risk of counterparties’ failure to perform under derivative contracts. Most of our receivables are from a diverse group of companies, including major energy companies, pipeline companies, local distribution companies, financial institutions, commodity traders and end-users in various industries and such receivables are generally unsecured. To manage risks of collecting accounts receivable, we monitor our counterparties’ financial strength and/or credit ratings and where we deem necessary, we obtain parent company guarantees, prepayments, letters of credit or other credit enhancements to reduce risk of loss. Our allowance for doubtful accounts was $7.1 million at December 31, 2017 compared to $5.6 million at December 31, 2016. For the years ended December 31, 2017, 2016 and 2015, we had one customer that accounted for 10% or more of total natural gas, NGLs and oil sales. We believe that the loss of any one customer would not have an adverse effect on our ability to sell our natural gas, NGLs and oil production. We have executed International Swap Dealers Association Master Agreements (“ISDA Agreements”) with counterparties for the purpose of entering into derivative contracts. To manage counterparty risk associated with our derivatives, we select and monitor counterparties based on assessment of their financial strength and/or credit ratings. We may also limit the level of exposure with any single counterparty. Additionally, the terms of our ISDA Agreements provide us and our counterparties with netting rights such that we may offset payables against receivables with a counterparty under separate derivative contracts. Our ISDA Agreements also generally contain set-off rights such that, upon the occurrence of defined acts of default by either us or a counterparty to a derivative contract, the non-defaulting party may set-off receivables owed under all derivative contracts against payables from other agreements with that counterparty. The majority of our derivative contracts have no margin requirements or collateral provisions that would require us to fund or post additional collateral prior to the scheduled cash settlement date. At December 31, 2017, our derivative counterparties included nineteen financial institutions and commodity traders, of which all but five are secured lenders in our bank credit facility. At December 31, 2017, our net derivative asset includes a payable to the counterparties not included in our bank credit facility totaling $28.2 million. In determining fair value of derivative assets, we evaluate the risk of non-performance and incorporate factors such as amounts owed under other agreements permitting set-off, as well as pricing of credit default swaps for the counterparty. Net derivative liabilities are determined in part by using our market based credit spread to incorporate our theoretical risk of non-performance. Asset Retirement Obligations The fair value of asset retirement obligations is recognized in the period they are incurred, if a reasonable estimate of fair value can be made. Asset retirement obligations primarily relate to the abandonment of natural gas and oil producing facilities and include costs to dismantle and relocate or dispose of production platforms, gathering systems, wells and related structures. Estimates are based on historical experience of plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates of the cost to plug and abandon the wells in the future and federal and state regulatory requirements. We are required to operate and maintain our natural gas pipeline systems and intend to do so as long as supply and demand for natural gas exists, which we expect for the foreseeable future. Therefore, these assets have indeterminate lives. Depreciation of capitalized asset retirement costs will generally be determined on a units-of-production basis while accretion to be recognized will escalate over the life of the producing assets. See Note 9 for additional information. Environmental Costs Environmental expenditures are capitalized if the costs mitigate or prevent future contamination or if the costs improve environmental safety or efficiency of the existing assets. Expenditures that relate to an existing condition caused by past operations that have no future economic benefits are expensed. Deferred Taxes Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to the differences between the financial statement carrying amounts of assets and liabilities and their tax bases as reported in our filings with the respective taxing authorities. Deferred tax assets are recorded when it is more likely than not that they will be realized. The realization of deferred tax assets is assessed periodically based on several interrelated factors. These factors may include our expectation to generate sufficient taxable income in the periods before tax credits and operating loss carryforwards expire. All deferred taxes are classified as long-term on the balance sheet. New Accounting Pronouncements Recently Adopted In January 2017, an accounting standards update was issued that eliminates the requirements to calculate the implied fair value of goodwill to measure any goodwill impairment charge. Instead, entities will record an impairment charge based on the excess of a reporting unit’s carrying amount over its fair value. This standard is effective for annual periods beginning after December 15, 2019 and should be applied on a prospective basis. Early adoption is permitted for any goodwill impairment tests performed in first quarter 2017 or later. We elected to adopt this accounting standards update in first quarter 2017. The adoption did not have a significant impact on our consolidated results of operations, financial position, cash flows or financial disclosures; however, this standard did change our policy for our goodwill impairment assessment by eliminating the requirement to calculate the implied fair value of goodwill. In March 2016, an accounting standards update was issued that simplifies several aspects of the accounting for share-based payment award transactions. Among other things, this new guidance will require all income tax effects of share-based awards to be recognized in the statement of operations when the awards vest or are settled, will allow an employer to repurchase more of an employee’s shares for tax withholding purposes than it can today without triggering liability accounting and will allow a policy election to account for forfeitures as they occur. This new standard will be effective for annual periods beginning after December 15, 2016. Early adoption was permitted. We elected to early adopt this accounting standards update in fourth quarter 2016 which required us to reflect any adjustments as of January 1, 2016, the beginning of the annual period that included the interim period of adoption. The following summarizes the impact of this new standard on our consolidated financial statements: Income taxes - Upon adoption of this standard, all excess tax benefits and tax deficiencies (including tax benefits of dividends on share-based payment awards) are recognized as income tax expense or benefit in our consolidated statements of operations. The tax effects of exercised or vested awards are treated as discrete items in the reporting period in which they occur. Adoption of this new standard resulted in the recognition of an excess tax deficiency in our provision for income taxes rather than paid-in capital of $2.1 million for the year ended December 31, 2016 and affected our previously reported first quarter 2016 results as follows (in thousands, except per share data): For The Three Months Ended March 31, 2016 As Reported As Adjusted Statements of Operations: Income tax benefit $ (44,038 ) $ (41,976 ) Net loss (91,710 ) (93,772 ) Basic earnings per share (0.55 ) (0.56 ) Diluted earnings per share (0.55 ) (0.56 ) In addition, we have recorded a cumulative-effect adjustment to retained earnings (deficit) and reduced our deferred tax liability for $101.1 million for previously unrecognized tax benefits due to our NOL position. Forfeitures - Prior to adoption, share-based compensation expense was recognized on a straight line basis, net of estimated forfeitures, such that expense was recognized only for share-based awards that are expected to vest. We have elected to continue to estimate forfeitures. Statements of cash flows - The presentation requirements for cash flows related to employee taxes paid for withheld shares will be adjusted retrospectively. These cash flows have historically been presented as an operating activity. Upon adoption of this new standard, these cash outflows will be classified as a financing activity. Prior periods have been adjusted as follows (in thousands): As Reported As Adjusted Net cash provided from operating activities Net cash provided from operating activities Year ended 2015 $ 683,700 $ 691,402 Year ended 2014 954,135 974,353 Year ended 2013 743,538 757,373 Three months ended March 31, 2016 87,424 90,785 Six months ended J |
Dispositions and Acquisitions
Dispositions and Acquisitions | 12 Months Ended |
Dec. 31, 2017 | |
Business Combinations [Abstract] | |
Dispositions and Acquisitions | (3) Dispositions and Acquisitions We recognized a pretax net gain on the sale of assets of $23.7 million in the year ended December 31, 2017 compared to a loss of $7.1 million in 2016 and a loss of $406.9 million in 2015. The following describes the significant divestitures that are included in our consolidated results of operations for each of three years ended December 31, 2017, 2016 and 2015. 2017 Dispositions Texas Panhandle. In fourth quarter 2017, we sold various properties in the Texas Panhandle for proceeds of $40.4 million and we recorded a loss of $989,000 related to this sale, after closing adjustments. Western Oklahoma. In the year ended December 31, 2017, we sold certain properties in Oklahoma for proceeds of $30.8 million and we recorded a gain of $23.8 million related to this sale, after closing adjustments and transaction fees. Other. In 2017, we sold miscellaneous unproved property, inventory and surface property for proceeds of $1.3 million resulting in a gain of $870,000. 2016 Dispositions Western Oklahoma. In first nine months 2016, we sold various properties in Western Oklahoma for proceeds of $78.6 million and we recorded a loss of $5.3 million related to these sales, after closing adjustments and transaction fees. Pennsylvania. In first quarter 2016, we sold our non-operated interest in certain wells and gathering facilities in northeast Pennsylvania for proceeds of $111.5 million. After closing adjustments, we recorded a loss of $2.1 million related to this sale. Other. In 2016, we sold miscellaneous proved and unproved property, inventory and surface property for proceeds of $3.7 million resulting in a gain of $302,000. Included in the $3.7 million of proceeds is $1.2 million received from the sale of proved properties in Mississippi and South Texas. 2015 Dispositions Virginia and West Virginia . In December 2015, we sold the majority of our producing properties and gathering assets in Virginia and West Virginia for cash proceeds of $876.0 million, before closing adjustments. We recorded a pretax loss of $407.7 million related to this sale. We recognized $52.3 million of field net operating income (defined as natural gas, oil and NGLs sales plus net brokered margin less direct operating expenses, production and ad valorem taxes, transportation expense, exploration expense and divisional office general and administrative expense) for these assets for the period from January 1, 2015 to December 30, 2015. West Texas. In February 2015, we sold certain of our West Texas properties for cash proceeds of $10.5 million and we recognized a pretax loss of $101,000 related to this sale. Other. During 2015, we also sold miscellaneous inventory, surface acreage and unproved property for proceeds of $4.4 million which resulted in a pretax gain of $943,000. Memorial Merger On September 16, 2016, we completed the MRD Merger which was accomplished through the merger of Medina Merger Sub, Inc., a Delaware corporation and a direct, wholly-owned subsidiary of Range, with and into Memorial, with Memorial surviving as a wholly-owned subsidiary of Range. The results of Memorial’s operations since the effective time of the merger are included in our consolidated statement of operations. The merger was effected through the issuance of approximately 77.0 million shares of Range common stock in exchange for all outstanding shares of Memorial using an exchange ratio of 0.375 of a share of Range common stock for each share of Memorial common stock. At the effective time of the merger, Memorial’s liabilities, which are reflected in Range’s consolidated financial statements, included approximately $1.2 billion fair value of outstanding debt. In connection with the MRD Merger, we incurred merger-related expenses of approximately $37.2 million including consulting, investment banking, advisory, legal and other merger-related fees. Allocation of Purchase Price. The MRD Merger has been accounted for as a business combination, using the acquisition method. The following table represents the final allocation of the total purchase price of the MRD Merger to the assets acquired and the liabilities assumed based on the fair value at the effective time of the merger, with any excess of the purchase price over the estimated fair value of the identifiable net assets acquired recorded as goodwill (in thousands, except shares and stock price): Purchase price: Shares of Range common stock issued to Memorial stockholders 77,042,749 Range common stock price per share at September 15, 2016 (close) $ 39.37 Total purchase price $ 3,033,173 Plus fair value of liabilities assumed by Range: Accounts payable $ 55,624 Other current liabilities 108,367 Long-term debt 1,204,449 Deferred taxes 547,706 Other long-term liabilities 77,223 Total purchase price plus liabilities assumed $ 5,026,542 Fair value of Memorial assets: Cash and equivalents $ 7,180 Other current assets 99,969 Derivative instruments 152,994 Natural gas and oil properties: Proved property 1,122,311 Unproved property 1,999,187 Other property and equipment 3,579 Goodwill (a) 1,641,197 Other 125 Total asset value $ 5,026,542 (a) The fair value measurements of derivative instruments assumed were determined based on published forward commodity price curves as of the date of the MRD Merger and represent Level 2 inputs. Derivative instruments in an asset position include a measure of counterparty nonperformance risk and the fair values of commodity derivative instruments in a liability position include a measure of our own nonperformance risk, each based on the current published credit default swap rates. The fair value measurements of long-term debt were estimated based on published market prices and represent Level 1 inputs. The fair value measurements of natural gas and oil properties and asset retirement obligations are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair value of natural gas and oil properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of natural gas and oil properties include estimates of: (i) recoverable reserves, (ii) production rates, (iii) future operating and development costs, (iv) future commodity prices and (v) a market-based weighted average costs of capital rate. These inputs require significant judgments and estimates by management at the time of the valuation and may be subject to change. Management utilized the assistance of a third party valuation expert to estimate the value of natural gas and oil properties acquired. In some cases, certain amounts allocated to unproved properties are based on a market approach using third party published data which provides lease pricing information based on certain geographic areas and represent Level 2 inputs. Goodwill is attributed to net deferred tax liabilities arising from the differences between the purchase price allocated to Memorial’s assets and liabilities based on fair value and the tax basis of these assets and liabilities. In addition, the total consideration for the merger included a control premium, which resulted in a higher value compared to the fair value of net assets acquired. There are also other qualitative assumptions of long-term factors that the merger creates including additional potential for exploration and development opportunities, additional scale and efficiencies in other basins in which we operate and substantial operating and administrative synergies. The results of operations attributable to Memorial are included in our consolidated statements of operations beginning on September 16, 2016. We recognized $477.4 million of natural gas, oil and NGLs revenue and $278.8 million of field net operating income from these assets from January 1, 2017 to December 31, 2017. We recognized $146.6 million of natural gas, oil and NGLs revenues and $94.9 million of field net operating income from these assets from September 16, 2016 to December 31, 2016. Pro forma Financial Information. The following pro forma condensed combined financial information was derived from the historical financial statements of Range and Memorial and gives effect to the merger as if it had occurred on January 1, 2015. The below information reflects pro forma adjustments for the issuance of Range common stock in exchange for Memorial’s outstanding shares of common stock, as well as pro forma adjustments based on available information and certain assumptions that we believe are reasonable, including (i) the depletion of Memorial’s fair-valued proved natural gas and oil properties and (ii) the estimated tax impacts of the pro forma adjustments. Additionally, pro forma earnings for the year ended December 31, 2016 were adjusted to exclude $37.2 million of merger-related costs incurred by Range and $7.1 million incurred by Memorial. The pro forma results of operations do not include any cost savings or other synergies that may result from the MRD Merger or any estimated costs that have been or will be incurred by us to integrate the Memorial assets. The pro forma condensed combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the MRD Merger taken place on January 1, 2015. In addition, the pro forma financial information below is not intended to be a projection of future results (in thousands, except per share amounts). Year Ended December 31, 2016 2015 Revenues $ 1,334,290 $ 2,253,368 Net loss $ (591,121 ) $ (556,164 ) Loss per share: Basic $ (2.42 ) $ (2.28 ) Diluted $ (2.42 ) $ (2.28 ) |
Goodwill
Goodwill | 12 Months Ended |
Dec. 31, 2017 | |
Goodwill And Intangible Assets Disclosure [Abstract] | |
Goodwill | (4) Goodwill Our goodwill relates to the excess of purchase price over amounts assigned to assets and liabilities from the MRD Merger which is equal to $1.6 billion at December 31, 2017. We performed a quantitative impairment test during third quarter 2017 due to a sustained decline in our market capitalization. Management utilized the assistance of a third-party valuation expert to determine the fair value of our business (our reporting unit). The fair value was determined based on a combination of a market and an income approach. As a result of this measurement, the fair value of our business exceeded the carrying value of net assets and no impairment was recorded. As of this date, our fair value exceeded book value by $1.4 billion or 24%. After considering the impact of the new tax law, our fair value exceeded our book value by $2.4 billion or 42%. For additional information regarding the new tax law, see Note 5. During fourth quarter 2017, we conducted a qualitative impairment assessment, by examining relevant events and circumstances which could have a negative impact on our business such as: macroeconomic conditions, industry and market conditions, including the downturn in the oil and gas industry, cost factors that could have a negative effect on earnings and cash flows, overall financial performance, dispositions and acquisitions, and other relevant entity-specific events. We identified various factors to consider including commodity prices, our year-end proved reserves evaluation and the market value of our common stock. Our analysis indicated that the fair value of our business was not below book value. Although we based the fair value estimate on assumptions we believe to be reasonable, those assumptions are inherently unpredictable and uncertain. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | (5) Income Taxes Our income tax benefit was $251.0 million for the year ended December 31, 2017 compared to $280.8 million in 2016 and $338.7 million in 2015. Reconciliation between the statutory federal income tax rate and our effective income tax rate is as follows: Year Ended December 31, 2017 2016 2015 Federal statutory tax rate 35.0 % 35.0 % 35.0 % Federal rate change (406.7 ) — — State (0.7 ) 3.0 4.3 State rate and law change (1.3 ) 1.0 (0.2 ) Non-deductible executive compensation 0.7 (0.2 ) (0.1 ) Non-deductible MRD transaction costs — (0.6 ) — Valuation allowances 36.8 (2.5 ) (6.8 ) Equity compensation 30.2 (0.7 ) — Other 0.3 — — Consolidated effective tax rate (305.7 %) 35.0 % 32.2 % Income tax (benefit) expense attributable to income before income taxes consists of the following (in thousands): 2017 2016 2015 Current Deferred Total Current Deferred Total Current Deferred Total U.S. federal $ — $ (302,507 ) $ (302,507 ) $ — $ (266,105 ) $ (266,105 ) $ — $ (328,257 ) $ (328,257 ) U.S. state and local 17 51,464 51,481 98 (14,743 ) (14,645 ) 29 (10,449 ) (10,420 ) Total $ 17 $ (251,043 ) $ (251,026 ) $ 98 $ (280,848 ) $ (280,750 ) $ 29 $ (338,706 ) $ (338,677 ) Significant components of deferred tax assets and liabilities are as follows: December 31, 2017 2016 (in thousands) Deferred tax assets: Net operating loss carryforward $ 413,672 $ 478,203 Deferred compensation 24,704 50,808 Equity compensation 5,269 29,528 AMT credits and other credits 7,264 13,644 Asset retirement obligation 69,398 99,000 Cumulative mark-to-market loss — 73,404 Other 18,806 39,922 Valuation allowances: Federal (31,308 ) (48,750 ) State, net of federal benefit (93,826 ) (58,424 ) Total deferred tax assets 413,979 677,335 Deferred tax liabilities: Depreciation, depletion and investments (1,105,494 ) (1,619,922 ) Cumulative mark-to-market gain (1,841 ) — Other — (756 ) Total deferred tax liabilities (1,107,335 ) (1,620,678 ) Net deferred tax liability $ (693,356 ) $ (943,343 ) On December 22, 2017, the Tax Cuts and Jobs Act of 2017 was signed into law. The law significantly reforms the Internal Revenue Code of 1986, as amended. The reduction in the corporate tax rate required a one-time revaluation of certain tax related assets and liabilities to reflect their value at the lower corporate tax rate of 21%. We reviewed all of the valuation allowances previously established at the corporate rate of 35% to reflect the appropriate new balances after the enactment of the new law. A one-time tax benefit was recorded related to the tax law changes in the amount of $334.0 At December 31, 2017, deferred tax liabilities exceeded deferred tax assets by $693.4 million. As of December 31, 2017, we have a valuation allowance of $1.9 million on the deferred tax asset related to our deferred compensation plan for planned future distributions to certain executives to the extent that their estimated future compensation plus distribution amounts would exceed the $1.0 million deductible limit provided under I.R.C. Section 162(m). As of December 31, 2017, we have a state valuation allowance of $36.3 million related to state tax attributes in Oklahoma, Texas and West Virginia. During 2017, we adjusted our valuation allowance related to our Pennsylvania state tax attributes to be $57.5 million due to the low commodity price environment and the limitation Pennsylvania places on future utilization of net operating loss carryforwards. On October 18, 2017, the Supreme Court of Pennsylvania issued a decision on a case related to limiting net operating loss deductions to the greater of $3.0 million or 30 percent of taxable income. The Supreme Court ruled that the net operating loss deduction limitation violated the Uniformity Clause of the Pennsylvania Constitution and struck the $3.0 million flat cap limitation but not the percentage of taxable income limitation. The changes in our deferred tax asset valuation allowances are as follows (in thousands): 2017 2016 2015 Balance at the beginning of the year $ (107,174 ) $ (87,623 ) $ (16,599 ) Charged to provision for income taxes: State net operating loss carryforwards (11,612 ) (17,374 ) (30,457 ) Federal net operating carryforwards 15,385 (1,100 ) (42,500 ) Other state valuation allowances (23,790 ) 500 (1,050 ) Other federal valuation allowances (247 ) (477 ) (511 ) Rabbi trust valuation allowance 2,304 (1,066 ) 3,494 Other — (34 ) — Balance at the end of the year $ (125,134 ) $ (107,174 ) $ (87,623 ) At December 31, 2017, we had federal net operating loss (“NOL”) carryforwards of $1.5 billion that expire between 2018 and 2035 and an NOL in Pennsylvania of $872.6 million that expire between 2025 and 2036. We file consolidated tax returns in the United States federal jurisdiction. We file separate company state income tax returns in Louisiana, Pennsylvania and Virginia and file consolidated or unitary state income tax returns in Oklahoma, Texas and West Virginia. We are subject to U.S. Federal income tax examinations for the years 2013 and after and we are subject to various state tax examinations for years 2012 and after. We have not extended the statute of limitation period in any income tax jurisdiction. Our policy is to recognize interest related to income tax expense on interest expense and penalties in general and administrative expense. We do not have any accrued interest or penalties related to tax amounts as of December 31, 2017. Throughout 2017, our unrecognized tax benefits were not material. |
Net Income (Loss) Per Common Sh
Net Income (Loss) Per Common Share | 12 Months Ended |
Dec. 31, 2017 | |
Earnings Per Share [Abstract] | |
Net Income (Loss) Per Common Share | (6) Net Income (Loss) per Common Share Basic income or loss per share attributable to common stockholders is computed as (i) income or loss attributable to common stockholders (ii) less income allocable to participating securities (iii) divided by weighted average basic shares outstanding. Diluted income or loss per share attributable to common stockholders is computed as (i) basic income or loss attributable to common stockholders (ii) plus diluted adjustments to income allocable to participating securities (iii) divided by weighted average diluted shares outstanding. Diluted net income (loss) per share is calculated under both the two class method and the treasury stock method and the more dilutive of the two calculations is presented. The following table sets forth a reconciliation of net income or loss to basic income or loss attributable to common stockholders and to diluted income or loss attributable to common stockholders (in thousands except per share amounts): Year Ended December 31, 2017 2016 2015 Net income (loss), as reported $ 333,146 $ (521,388 ) $ (713,685 ) Participating basic earnings (a) (3,751 ) (223 ) (450 ) Basic net income (loss) attributed to common stockholders 329,395 (521,611 ) (714,135 ) Reallocation of participating earnings (a) 5 — — Diluted net income (loss) attributed to common stockholders $ 329,400 $ (521,611 ) $ (714,135 ) Net income (loss) per common share: Basic $ 1.34 $ (2.75 ) $ (4.29 ) Diluted $ 1.34 $ (2.75 ) $ (4.29 ) (a) Restricted stock Liability Awards represent participating securities because they participate in nonforfeitable dividends or distributions with common equity owners. Income allocable to participating securities represents the distributed and undistributed earnings attributable to the participating securities. Participating securities, however, do not participate in undistributed net losses. The following table provides a reconciliation of basic weighted average common shares outstanding to diluted weighted average common shares outstanding (in thousands): Year Ended December 31, 2017 2016 2015 Denominator: Weighted average common shares outstanding – basic (1) 245,091 189,868 166,389 Effect of dilutive securities: Director and employee restricted stock and performance-based equity awards 367 — — Weighted average common shares outstanding – diluted 245,458 189,868 166,389 (1) Includes common stock issued in connection with the exchange of 77.0 million shares for all outstanding Memorial common stock on September 16, 2016. Weighted average common shares – basic excludes 2.8 million shares of restricted stock Liability Awards held in our deferred compensation plans (although all awards are issued and outstanding upon grant) for each of the periods ending December 31, 2017, 2016 and 2015. Due to our net loss for the years ended December 31, 2016 and 2015, we excluded all outstanding equity grants from the computation of diluted net loss per share because the effect would have been anti-dilutive to the computations. Equity grants of 702,000 for the year ended December 31, 2017 were outstanding but not included in the computations of diluted net income per share because the grant prices were greater than the average market price of the common shares and would be anti-dilutive to the computations. For purposes of calculating diluted weighted average common shares for the year ended December 31, 2017, nonvested restricted stock and performance – based equity awards are included in the computation using the treasury stock method with the deemed proceeds equal to the average unrecognized compensation during the period. |
Suspended Exploratory Well Cost
Suspended Exploratory Well Costs | 12 Months Ended |
Dec. 31, 2017 | |
Extractive Industries [Abstract] | |
Suspended Exploratory Well Costs | (7) Suspended Exploratory Well Costs We capitalize exploratory well costs until a determination is made that the well has either found proved reserves or that it is impaired. Capitalized exploratory well costs are presented in natural gas and oil properties in the accompanying consolidated balance sheets. If an exploratory well is determined to be impaired, the well costs are charged to exploration expense in the accompanying consolidated statements of operations. The following table reflects the changes in capitalized exploratory well costs for the years ended December 31, 2017, 2016 and 2015 (in thousands, except for number of projects): 2017 2016 2015 Balance at beginning of period $ 7,412 $ 4,161 $ 2,996 Additions to capitalized exploratory well costs pending the determination of proved reserves 1,388 9,128 1,165 Reclassifications to wells, facilities and equipment based on determination of proved reserves — (5,877 ) — Capitalized exploratory well costs charged to expense (8,800 ) — — Balance at end of period — 7,412 4,161 Less exploratory well costs that have been capitalized for a period of one year or less — (7,412 ) (1,165 ) Capitalized exploratory well costs that have been capitalized for a period greater than one year $ — $ — $ 2,996 Number of projects that have exploratory well costs that have been capitalized for a period greater than one year — — 1 |
Indebtedness
Indebtedness | 12 Months Ended |
Dec. 31, 2017 | |
Debt Disclosure [Abstract] | |
Indebtedness | (8) Indebtedness We had the following debt outstanding as of the dates shown below (in thousands) (bank debt interest rate at December 31, 2017 is shown parenthetically). The expenses of issuing debt are capitalized and included as a reduction to debt in the accompanying consolidated balance sheets. These costs are amortized over the expected life of the related instruments. When debt is retired before maturity, or modifications significantly change the cash flows, the related unamortized costs are expensed. No interest was capitalized during 2017, 2016, and 2015. December 31, 2017 December 31, 2016 Bank debt (3.0%) $ 1,211,000 $ 882,000 Senior notes 4.875% senior notes due 2025 750,000 750,000 5.00% senior notes due 2023 741,531 741,531 5.00% senior notes due 2022 580,032 580,032 5.75% senior notes due 2021 475,952 475,952 5.875% senior notes due 2022 (a) 329,244 329,244 Other senior notes due 2022 (b) 590 1,090 Total senior notes 2,877,349 2,877,849 Senior subordinated notes 5.00% senior subordinated notes due 2023 7,712 7,712 5.00% senior subordinated notes due 2022 19,054 19,054 5.75% senior subordinated notes due 2021 22,214 22,214 Total senior subordinated notes 48,980 48,980 Total debt 4,137,329 3,808,829 Unamortized premium 6,027 7,241 Unamortized debt issuance costs (34,550 ) (42,553 ) Total debt net of debt issuance costs $ 4,108,806 $ 3,773,517 (a) (b) Bank Debt In October 2014, we entered into an amended and restated revolving bank facility, which we refer to as our bank debt or our bank credit facility, which is secured by substantially all of our assets. The bank credit facility has a maximum facility amount of $4.0 billion. As of December 31, 2017, the facility had a borrowing base of $3.0 billion and bank commitments of $2.0 billion. The bank credit facility provides for a borrowing base subject to redeterminations annually by each May and for event-driven unscheduled redeterminations. As part of our annual redetermination completed on March 21, 2017, our borrowing base was reaffirmed at $3.0 billion and our bank commitment was also reaffirmed at $2.0 billion. Our current bank group is comprised of twenty-nine financial institutions, with no one bank holding more than 5.8% of the total facility. The borrowing base may be increased or decreased based on our request and sufficient proved reserves, as determined by the bank group. The commitment amount may be increased to the borrowing base, subject to payment of a mutually acceptable commitment fee to those banks agreeing to participate in the facility increase. The commitment matures on October 16, 2019. As of December 31, 2017, the outstanding balance under the bank credit facility was $1.2 billion with $281.4 million of undrawn letters of credit leaving $507.6 million of borrowing capacity available under the commitment amount. During a non-investment grade period, borrowings under the bank facility can either be at the alternate base rate (“ABR,” as defined in the bank credit agreement) plus a spread ranging from 0.25% to 1.25% or LIBOR borrowings at the LIBOR Rate (as defined in the bank credit agreement) plus a spread ranging from 1.25% to 2.25%. The applicable spread is dependent upon borrowings relative to the borrowing base. We may elect, from time to time, to convert all or any part of our LIBOR loans to ABR loans or to convert all or any part of our ABR loans to LIBOR loans. The weighted average interest rate was 2.7% for the year ended December 31, 2017 compared to 2.2% for the year ended December 31, 2016 and 1.7% for the year ended December 31, 2015. A commitment fee is paid on the undrawn balance based on an annual rate of 0.30% to 0.375%. At December 31, 2017, the commitment fee was 0.3%, the interest rate margin was 1.5% on our LIBOR loans and 0.5% on our ABR. At any time during which we have an investment grade debt rating from Moody’s Investors Service, Inc. or Standard & Poor’s Ratings Services and we have elected, at our discretion, to effect the investment grade rating period, certain collateral security requirements, including the borrowing base requirement and restrictive covenants will cease to apply, certain other restrictive covenants will become less restrictive and an additional financial covenant (as defined in the bank credit facility) will be temporarily imposed. During the investment grade period, borrowings under the bank credit facility can either be at the ABR plus a spread ranging from 0.125% to 0.75% or LIBOR Rate plus a spread ranging from 1.125% to 1.75% depending on our debt rating. The commitment fee paid on the undrawn balance ranges from 0.15% to 0.30%. We currently do not have an investment grade rating. Senior Notes In September 2016, in conjunction with MRD Merger, we issued $329.2 million senior unsecured 5.875% notes due 2022 (the “5.875% Notes”) (See also Senior Notes Exchange and Cash Tender Offer Senior Subordinated Notes Exchange Principal Amount 5.00% senior notes due 2023 $ 741,531 5.00% senior notes due 2022 $ 580,032 5.75% senior notes due 2021 $ 475,952 All of the notes were offered to qualified institutional buyers and to non-U.S. persons outside the United States in compliance with Rule 144A and Regulation S under the Securities Act of 1933, as amended (the “Securities Act”). On October 5, 2017, the 5.875% Notes, the 5.00% senior notes due 2023, the 5.00% senior notes due 2022 and the 5.75% senior notes due 2021 (collectively, the “Old Notes”) were exchanged for an equal principal amount of registered notes pursuant to an effective registration statement on Form S-4 filed with the SEC on August 9, 2017 under the Securities Act (the “New Notes”). The New Notes are identical to the Old Notes except the New Notes are registered under the Securities Act and do not have restrictions on transfer, registration rights or provisions for additional interest. Under certain circumstances, if we experience a change of control, noteholders may require us to repurchase all of our senior notes at 101% of the aggregate principal amount plus accrued and unpaid interest, if any. In May 2015, we issued $750.0 million aggregate principal amount of 4.875% senior notes due 2025 (the “Outstanding Notes”) for net proceeds of $737.4 million after underwriting discounts and commissions of $12.6 million. The notes were issued at par and were offered to qualified institutional buyers and non-U.S. persons outside the United States in compliance with Rule 144A and Regulation S under the Securities Act. On April 8, 2016, all of the Outstanding Notes were exchanged for an equal principal amount of registered 4.875% senior notes due 2025 pursuant to an effective registration statement on Form S-4 filed with the SEC on February 29, 2016 under the Securities Act (the “Exchange Notes”). The Exchange Notes are identical to the Outstanding Notes except the Exchange Notes are registered under the Securities Act and do not have restrictions on transfer, registration rights or provisions for additional interest. Under certain circumstances, if we experience a change of control, noteholders may require us to repurchase all of our senior notes at 101% of the aggregate principal amount plus accrued and unpaid interest, if any. Senior Notes Exchange and Cash Tender Offer On September 16, 2016, we completed a debt exchange offer to exchange all validly tendered and accepted Memorial senior notes assumed in the MRD Merger. We exchanged 54.9% of the outstanding Memorial senior notes, whereby we issued the 5.875% Notes. The 5.875% Notes were offered to qualified institutional buyers and to non-U.S. persons outside the United States in compliance with Rule 144A and Regulation S under the Securities Act. Interest on the 5.875% Notes is payable in January and July. The 5.875% Notes will mature on July 1, 2022 and are unconditionally guaranteed on a senior unsecured basis by all of our subsidiary guarantors. On or after April 1, 2022, we may redeem the 5.875% Notes in whole or in part and from time to time, at 100% of the principal amount, plus accrued and unpaid interest. The 5.875% Notes are unsecured and are subordinated to all of our existing and future secured debt, rank equally with all of our existing and future senior unsecured debt and rank senior to all of our existing and future subordinated debt. The deferred financing cost for this exchange was $6.3 million. The early cash tender premium paid was $4.1 million, which was paid to note holders who tendered their notes within the ten business day early offer period. Also on September 16, 2016, we completed our concurrent offer to purchase for cash the Memorial senior notes assumed in the MRD Merger. We acquired 44.9% of the outstanding Memorial senior notes, or $269.7 million principal amount of the senior notes assumed in the MRD Merger, which we purchased for cash. The early cash tender premium paid was $3.3 million which was paid to note holders who tendered their notes within the ten business day early offer period. The cash tender offer and early cash tender premium were financed with borrowings under our bank credit facility. Concurrently with the Memorial senior note exchange offer and cash tender offer, we also solicited consents from the eligible holders to amend the indenture that governed the existing Memorial senior notes. The amendments included eliminating certain of the covenants, restrictive provisions, reporting requirements and events of default. Once a majority of consents were received, the amendments were accepted for all existing Memorial senior note holders, even if the senior notes were not tendered in either the exchange offer or cash tender offer. Senior Subordinated Notes Exchange On September 16, 2016, we also completed our debt exchange offer to exchange all validly tendered and accepted Range senior subordinated notes as detailed below (in thousands): Existing Note New Note Principal Amount of Notes Validly Tendered (1) Approximate Percentage Validly Tendered 5.00% senior subordinated notes due 2023 5.00% senior notes due 2023 $742,291 99.0% 5.00% senior subordinated notes due 2022 5.00% senior notes due 2022 $580,946 96.8% 5.75% senior subordinated notes due 2021 5.75% senior notes due 2021 $477,786 95.6% (1) We recorded $6.6 million of third party costs in interest expense in third quarter 2016 related to this exchange. The new senior notes were issued at par and were offered to qualified institutional buyers and non-U.S. persons outside the United States in compliance with Rule 144A and Regulation S under the Securities Act. A $3.5 million premium was recorded in connection with the exchange for certain holders that participated in the exchange after the early tender period and received 95% of face amount tendered in exchange consideration. Interest on the new 5.00% senior notes due 2023 is payable in March and September with a maturity date of March 15, 2023. Interest on the new 5.00% senior notes due 2022 is payable in February and August with a maturity date of August 15, 2022. Interest on the new 5.75% senior notes due 2021 is payable in June and December with a maturity date of June 1, 2021. All of the new senior notes are unconditionally guaranteed on a senior unsecured basis by all of our subsidiary guarantors. The new senior notes are unsecured and are subordinated to all of our existing and future senior secured debt and rank senior to all of our existing and future subordinated debt. Under certain circumstances, if we experience a change of control, noteholders may require us to repurchase all of our senior notes at 101% of the aggregate principal amount plus accrued and unpaid interest, if any. Concurrently with the senior subordinated notes exchange offer, we also solicited consents from the eligible holders to amend the indentures that governed each of the existing senior subordinated notes. The amendments included eliminating certain of the covenants, restrictive provisions, reporting requirements and events of default. Once a majority of consents were received, the amendments were accepted for all senior subordinated note holders, even if the remaining senior subordinated notes were not exchanged. Senior Subordinated Notes If we experience a change of control, noteholders may require us to repurchase all or a portion of our senior subordinated notes at 101% of the principal amount plus accrued and unpaid interest, if any. All of the senior subordinated notes and the guarantees by our subsidiary guarantors are general, unsecured obligations and are subordinated to our bank debt and to existing and future senior debt that we or our subsidiary guarantors are permitted to incur. Early Extinguishment of Debt In July 2015, we announced a call for the redemption of $500.0 million of our outstanding 6.75% senior subordinated notes due 2020 at a price of 103.375% of par plus accrued and unpaid interest, which were redeemed on August 3, 2015. In the year ended 2015, we recognized a loss on early extinguishment of debt of $22.5 million, including transaction call premium costs and the expensing of the remaining deferred financing costs on the repurchased debt. Guarantees Range Resources Corporation is a holding company which owns no operating assets and has no significant operations independent of its subsidiaries. The guarantees by our wholly-owned subsidiaries, which are directly or indirectly owned by Range, of our senior notes, our senior subordinated notes and our bank credit facility are full and unconditional and joint and several, subject to certain customary release provisions. A subsidiary guarantor may be released from its obligations under the guarantee: • in the event of a sale or other disposition of all or substantially all of the assets of the subsidiary guarantor or a sale or other disposition of all the capital stock of the subsidiary guarantor, to any corporation or other person (including an unrestricted subsidiary of Range) by way of merger, consolidation, or otherwise; or • if Range designates any restricted subsidiary that is a guarantor to be an unrestricted subsidiary in accordance with the terms of the indenture. Debt Covenants and Maturity Our bank credit facility contains negative covenants that limit our ability, among other things, to pay cash dividends, incur additional indebtedness, sell assets, enter into certain hedging contracts, change the nature of our business or operations, merge, consolidate, or make certain investments. In addition, we are required to maintain a ratio of EBITDAX (as defined in the credit agreement) to cash interest expense of equal to or greater than 2.5 and a current ratio (as defined in the credit agreement) of no less than 1.0. In addition, the ratio of the present value of proved reserves (as defined in the credit agreement) to total debt must be equal to or greater than 1.5 until Range has two investment grade ratings. We were in compliance with applicable covenants under the bank credit facility at December 31, 2017. The following is the principal maturity schedule for our long-term debt outstanding as of December 31, 2017 (in thousands): Year Ended 2018 $ — 2019 1,211,000 2020 — 2021 498,166 2022 928,920 Thereafter 1,499,243 $ 4,137,329 |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2017 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligations | (9) Asset Retirement Obligations Our asset retirement obligations primarily represent the present value of the estimated amounts we will incur to plug, abandon and remediate our producing properties at the end of their productive lives. Significant inputs used in determining such obligations include estimates of plugging and abandonment costs, estimated future inflation rates and well life. The inputs are calculated based on historical data as well as current estimated costs. The following is a reconciliation of our liability for plugging and abandonment costs as of December 31, 2017 and 2016 (in thousands): 2017 2016 Beginning of period $ 257,943 $ 264,137 Liabilities incurred 7,724 2,694 Acquisitions — 21,900 Liabilities settled (7,965 ) (11,511 ) Disposition of wells (8,078 ) (10,540 ) Accretion expense 14,711 18,021 Change in estimate 12,520 (26,758 ) End of period 276,855 257,943 Less current portion (6,327 ) (7,271 ) Long-term asset retirement obligations $ 270,528 $ 250,672 Accretion expense is recognized as an increase to depreciation, depletion and amortization expense in the accompanying consolidated statements of operations. |
Capital Stock
Capital Stock | 12 Months Ended |
Dec. 31, 2017 | |
Equity [Abstract] | |
Capital Stock | (10) Capital Stock We have authorized capital stock of 485.0 million shares, which includes 475.0 million shares of common stock and 10.0 million shares of preferred stock. The following is a schedule of changes in the number of common shares outstanding since the beginning of 2015: Year Ended December 31, 2017 2016 2015 Beginning balance 247,144,356 169,316,460 168,628,177 MRD Merger — 77,042,749 — Stock options/SARs exercised — — 77,002 Restricted stock grants 539,096 490,609 335,103 Restricted stock units vested 344,937 266,541 252,507 Performance stock units issued 85,461 — — Shares retired — (739 ) — Treasury shares 15,580 28,736 23,671 Ending balance 248,129,430 247,144,356 169,316,460 Common Stock Dividends The board of directors declared quarterly dividends of $0.02 per common share for each of the four quarters of 2017 and 2016. The board of directors declared quarterly dividends of $0.04 per common share for each of the four quarters of 2015. The determination of the amount of future dividends, if any, to be declared and paid is at the sole discretion of the board of directors and will depend on our financial condition, earnings, capital requirements, levels of indebtedness, our future business prospects and other matters our board of directors deem relevant. Our bank credit facility and our senior subordinated notes allow for the payment of common dividends, with certain limitations. |
Derivative Activities
Derivative Activities | 12 Months Ended |
Dec. 31, 2017 | |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |
Derivative Activities | (11) Derivative Activities We use commodity-based derivative contracts to manage exposure to commodity price fluctuations. We do not enter into these arrangements for speculative or trading purposes. We do not utilize complex derivatives as we typically utilize commodity swap, swaptions or collar contracts to (1) reduce the effect of price volatility of the commodities we produce and sell and (2) support our annual capital budget and expenditure plans. Every derivative instrument is required to be recorded on the balance sheet as either an asset or a liability measured at its fair value. Their fair value, which is represented by the estimated amount that would be realized upon termination, based on a comparison of the contract price and a reference price (generally NYMEX for natural gas and crude oil or Mont Belvieu for NGLs), approximated a net derivative asset of $13.6 million at December 31, 2017. These contracts expire monthly through December 2019. The following table sets forth the derivative volumes by year as of December 31, 2017, excluding our basis and freight swaps which are discussed separately below: Period Contract Type Volume Hedged Weighted Natural Gas 2018 Swaps 794,822 Mmbtu/day $ 3.13 2019 Swaps 12,329 Mmbtu/day $ 3.01 January − March 2018 Collars 60,000 Mmbtu/day $ 3.40-$ 3.76 April – December 2018 Swaptions 307,500 Mmbtu/day $ 2.98 (1) 2019 Swaptions 85,000 Mmbtu/day $ 2.97 (1 ) Crude Oil 2018 Swaps 8,995 bbls/day $ 53.30 2019 Swaps 4,746 bbls/day $ 52.81 NGLs (C2-Ethane) 2018 Swaps 250 bbls/day $ 0.29/gallon NGLs (C3-Propane) 2018 Swaps 10,362 bbls/day $ 0.68/gallon 2018 Collars 2,000 bbls/day $ 0.90-$ 1.05/gallon NGLs (NC4-Normal Butane) 2018 Swaps 4,621 bbls/day $ 0.81/gallon NGLs (C5-Natural Gasoline) 2018 Swaps 4,713 bbls/day $ 1.19/gallon 2019 Swaps 1,000 bbls/day $ 1.24/gallon (1) Basis Swap Contracts In addition to the swaps, collars and swaptions above, at December 31, 2017, we had natural gas basis swap contracts which lock in the differential between NYMEX and certain of our physical pricing points in Appalachia. These contracts settle monthly through October 2019 and include a total volume of 120,892,500 Mmbtu. The fair value of these contracts was a net derivative liability of $7.8 million on December 31, 2017. At December 31, 2017, we also had propane spread swap contracts which lock in the differential between Mont Belvieu and international propane indexes. The contracts settle monthly through December 2018 and include a total volume of 1,362,000 barrels. The fair value of these contracts was a net derivative liability of $1.2 million on December 31, 2017. Freight Swap Contracts In connection with our international propane sales, we utilize propane swaps. To further hedge our propane price, at December 31, 2017, we had freight swap contracts which lock in the freight rate for a specific trade route on the Baltic Exchange. These contracts settle monthly through December 2018 and cover 5,000 metric tons per month with a fair value net derivative asset of $276,000 on December 31, 2017. These contracts use observable third-party pricing inputs that we consider to be Level 2 fair value classification. Derivative assets and liabilities The combined fair value of derivatives included in the accompanying consolidated balance sheets as of December 31, 2017 and 2016 is summarized below (in thousands). As of December 31, 2017, we are conducting derivative activities with nineteen counterparties, of which all but five are secured lenders in our bank credit facility. We believe all of these counterparties are acceptable credit risks. At times, such risks may be concentrated with certain counterparties. The credit worthiness of our counterparties is subject to periodic review. The assets and liabilities are netted where derivatives with both gain and loss positions are held by a single counterparty and we have master netting arrangements. December 31, 2017 Gross Amounts of Recognized Assets Gross Amounts Offset in the Balance Sheet Net Amounts of Assets Presented in the Balance Sheet Derivative assets: Natural gas –swaps $ 87,794 $ (4,106 ) $ 83,688 –swaptions 18,817 (8,103 ) 10,714 –basis swaps 1,815 (6,673 ) (4,858 ) –collars 3,039 (500 ) 2,539 Crude oil –swaps 2 (7,928 ) (7,926 ) NGLs –C2 ethane swaps 57 — 57 –C3 propane swaps — (12,556 ) (12,556 ) –C3 propane collars 85 (85 ) — –C3 propane spread swaps 12,762 (12,762 ) — –NC4 butane swaps — (6,051 ) (6,051 ) –C5 natural gasoline swaps — (6,727 ) (6,727 ) Freight –swaps 276 (276 ) — $ 124,647 $ (65,767 ) $ 58,880 December 31, 2017 Gross Amounts of Recognized (Liabilities) Gross Amounts Net Amounts of (Liabilities) Presented in the Balance Sheet Derivative (liabilities): Natural gas –swaps $ (216 ) $ 4,106 $ 3,890 –swaptions (12,283 ) 8,103 (4,180 ) –basis swaps (9,580 ) 6,673 (2,907 ) –collars — 500 500 Crude oil –swaps (24,726 ) 7,928 (16,798 ) NGLs –C3 propane swaps (34,325 ) 12,556 (21,769 ) –C3 propane collars — 85 85 –C3 propane spread swaps (13,983 ) 12,762 (1,221 ) –NC4 butane swaps (11,188 ) 6,051 (5,137 ) –C5 natural gasoline swaps (13,488 ) 6,727 (6,761 ) Freight –swaps — 276 276 $ (119,789 ) $ 65,767 $ (54,022 ) December 31, 2016 Gross Amounts of Recognized Assets Gross Amounts Offset in the Balance Sheet Net Amounts of Assets Presented in the Balance Sheet Derivative assets: Natural gas –swaps $ 13,213 $ (11,425 ) $ 1,788 –basis swaps 12,535 (9,437 ) 3,098 –collars 6,298 (6,298 ) — –puts 18,159 (15,429 ) 2,730 Crude oil –swaps 9,356 (3,489 ) 5,867 NGLs –C2 ethane swaps 53 (53 ) — –C3 propane spread swaps 17,396 (17,396 ) — –NC4 butane swaps 4 (4 ) — Freight –swaps 65 (65 ) — $ 77,079 $ (63,596 ) $ 13,483 December 31, 2016 Gross Amounts of Recognized (Liabilities) Gross Amounts Net Amounts of (Liabilities) Presented in the Balance Sheet Derivative (liabilities): Natural gas –swaps $ (158,359 ) $ 11,425 $ (146,934 ) –basis swaps (687 ) 9,437 8,750 –collars (2,625 ) 6,298 3,673 –puts — 15,429 15,429 –calls (1,041 ) — (1,041 ) Crude oil –swaps (13,206 ) 3,489 (9,717 ) NGLs –C2 ethane swaps (1,008 ) 53 (955 ) –C3 propane swaps (32,437 ) — (32,437 ) –C3 propane spread swaps (18,138 ) 17,396 (742 ) –NC4 butane swaps (13,419 ) 4 (13,415 ) –C5 natural gasoline swaps (12,176 ) — (12,176 ) Freight –swaps — 65 65 $ (253,096 ) $ 63,596 $ (189,500 ) The effects of our derivatives on our consolidated statements of operations for the last three years are summarized below (in thousands). Year Ended December 31, Derivative Fair Value Income (Loss) 2017 2016 2015 Commodity Swaps $ 181,095 $ (265,466 ) $ 398,020 Swaptions 6,534 — — Re-purchased swaps — — 851 Collars 18,132 (6,926 ) 16,539 Basis swaps (4,647 ) 29,154 954 Puts 10,929 (18,201 ) — Calls 987 (18 ) — Freight swaps 320 66 — Total $ 213,350 $ (261,391 ) $ 416,364 |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2017 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | (12) Fair Value Measurements Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. There are three approaches for measuring the fair value of assets and liabilities: the market approach, the income approach and the cost approach, each of which includes multiple valuation techniques. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. The income approach uses valuation techniques to measure fair value by converting future amounts, such as cash flows or earnings, into a single present value amount using current market expectations about those future amounts. The cost approach is based on the amount that would currently be required to replace the service capacity of an asset. This is often referred to as current replacement cost. The cost approach assumes that the fair value would not exceed what it would cost a market participant to acquire or construct a substitute asset of comparable utility, adjusted for obsolescence. The fair value accounting standards do not prescribe which valuation technique should be used when measuring fair value and do not prioritize among the techniques. These standards establish a fair value hierarchy that prioritizes the inputs used in applying the various valuation techniques. Inputs broadly refer to the assumptions that market participants use to make pricing decisions, including assumptions about risk. Level 1 inputs are given the highest priority in the fair value hierarchy, while Level 3 inputs are given the lowest priority. The three levels of the fair value hierarchy are as follows: • Level 1 – Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. • Level 2 – Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. • Level 3 – Unobservable inputs for which there is little, if any, market activity for the asset or liability being measured. These inputs reflect management’s best estimates of the assumptions market participants would use in determining fair value. Our Level 3 measurements consist of instruments using standard pricing models and other valuation methods that utilize unobservable pricing inputs that are significant to the overall value. Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy. Fair Values-Recurring We use a market approach for our recurring fair value measurements and endeavor to use the best information available. Accordingly, valuation techniques that maximize the use of observable impacts are favored. The following tables present the fair value hierarchy table for assets and liabilities measured at fair value, on a recurring basis (in thousands): Fair Value Measurements at December 31, 2017 Using: Quoted Prices Significant Significant Total Trading securities held in the deferred compensation plans $ 67,117 $ — $ — $ 67,117 Derivatives –swaps — 3,910 — 3,910 –collars — 3,039 85 3,124 –basis swaps — (9,025 ) 39 (8,986 ) –freight swaps — 276 — 276 –swaptions — — 6,534 6,534 Fair Value Measurements at December 31, 2016 Using: Quoted Prices Significant Significant Total Trading securities held in the deferred compensation plans $ 61,717 $ — $ — $ 61,717 Derivatives –swaps — (207,979 ) — (207,979 ) –collars — 3,673 — 3,673 –puts — 18,159 — 18,159 –calls — (1,041 ) — (1,041 ) –basis swaps — 11,106 — 11,106 –freight swaps — 65 — 65 Our trading securities in Level 1 are exchange-traded and measured at fair value with a market approach using December 31, 2017 market values. Derivatives in Level 2 are measured at fair value with a market approach using third-party pricing services, which have been corroborated with data from active markets or broker quotes. As of December 31, 2017, a portion of our natural gas derivative instruments contain swaptions where the counterparty has the right, but not the obligation, to enter into a fixed price swap on a predetermined date. Derivatives in Level 3 are measured at fair value with a market approach using third-party pricing services, which have been corroborated with data from active markets or broker quotes. Subjectivity in the volatility factors utilized can cause a significant change in the fair value measurement of our swaptions. The following is a reconciliation of the beginning and ending balances for derivative instruments classified as Level 3 in the fair value hierarchy (in thousands): Year Ended December 31, 2017 Balance at the beginning of period $ — Total gains (losses): Included in earnings 6,658 Settlements received — Transfers in and/or out of Level 3 — Balance at end of period $ 6,658 Our trading securities held in the deferred compensation plan are accounted for using the mark-to-market accounting method and are included in other assets in the accompanying consolidated balance sheets. We elected to adopt the fair value option to simplify our accounting for the investments in our deferred compensation plan. Interest, dividends, and mark-to-market gains/losses are included in deferred compensation plan expense in the accompanying consolidated statements of operations. For the year ended December 31, 2017, interest and dividends were $4.1 million and mark-to-market was a gain of $4.2 million. For the year ended December 31, 2016, interest and dividends were $972,000 and mark-to-market was a gain of $3.1 million. For the year ended December 31, 2015, interest and dividends were $908,000 and mark-to-market was a loss of $5.9 million. Fair Values-Non recurring Due to declines in commodity prices and estimated reserves over the last three years, there were indications that the carrying values of certain natural gas and oil properties may be impaired and undiscounted future cash flows attributed to these assets indicated their carrying amounts were not expected to be recovered. Their fair value was measured using an income approach based upon internal estimates of future production levels, prices, drilling and operating costs and discount rates, which are Level 3 inputs. In some cases, we also considered the potential sale of certain of these properties. We recorded non-cash charges during the year ended 2017 of $63.7 million related to certain of our oil and gas properties in Oklahoma and the Texas Panhandle. We recorded non-cash charges during the year ended 2016 of $43.0 million related to certain of our natural gas and oil properties in Western Oklahoma. We recorded non-cash charges of $306.6 million during the year ended 2015 related to natural gas and oil properties in Northern Oklahoma, $195.6 million related to our shallow legacy oil and natural gas assets in Northwest Pennsylvania, $86.9 million related to our assets in the Texas Panhandle and $1.1 million related to our onshore Gulf Coast properties. The following table presents the value of these assets measured at fair value on a nonrecurring basis at the time impairment was recorded (in thousands): Year Ended December 31, 2017 2016 2015 Fair Value Impairment Fair Value Impairment Fair Value Impairment Natural gas and oil properties $ 85,597 $ 63,679 $ 90,150 $ 43,040 $ 152,230 $ 590,174 Fair Values - Reported The following table presents the carrying amounts and the fair values of our financial instruments as of December 31, 2017 and 2016 (in thousands): December 31, 2017 December 31, 2016 Carrying Fair Carrying Fair Assets: Commodity swaps, options and basis swaps $ 58,880 $ 58,880 $ 13,483 $ 13,483 Marketable securities (a) 67,117 67,117 61,717 61,717 (Liabilities): Commodity swaps, options and basis swaps (54,022 ) (54,022 ) (189,500 ) (189,500 ) Bank credit facility (b) (1,211,000 ) (1,211,000 ) (882,000 ) (882,000 ) 5.75% senior notes due 2021 (b) (475,952 ) (493,872 ) (475,952 ) (496,180 ) 5.00% senior notes due 2022 (b) (580,032 ) (578,727 ) (580,032 ) (577,132 ) 5.875% senior notes due 2022 (b) (329,244 ) (339,200 ) (329,244 ) (343,648 ) Other senior notes due 2022 (b) (590 ) (591 ) (1,090 ) (1,104 ) 5.00% senior notes due 2023 (b) (741,531 ) (735,614 ) (741,531 ) (735,043 ) 4.875% senior notes due 2025 (b) (750,000 ) (733,755 ) (750,000 ) (724,688 ) 5.75% senior subordinated notes due 2021 (b) (22,214 ) (22,192 ) (22,214 ) (22,325 ) 5.00% senior subordinated notes due 2022 (b) (19,054 ) (18,741 ) (19,054 ) (18,387 ) 5.00% senior subordinated notes due 2023 (b) (7,712 ) (7,614 ) (7,712 ) (7,645 ) Deferred compensation plan (c) (114,414 ) (114,414 ) (139,580 ) (139,580 ) (a) Marketable securities, which are held in our deferred compensation plans, are actively traded on major exchanges. (b) The book value of our bank debt approximates fair value because of its floating rate structure. The fair value of our senior notes and our senior subordinated notes is based on end of period market quotes which are Level 2 inputs. (c) The fair value of our deferred compensation plan is updated at the closing price on the balance sheet date which is a Level 1 input. Our current assets and liabilities contain financial instruments, the most significant of which are trade accounts receivables and payables. We believe the carrying values of our current assets and liabilities approximate fair value. Our fair value assessment incorporates a variety of considerations, including (1) the short-term duration of the instruments and (2) our historical incurrence of and expected future insignificance of bad debt expense. |
Stock-based Compensation Plans
Stock-based Compensation Plans | 12 Months Ended |
Dec. 31, 2017 | |
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract] | |
Stock-based Compensation Plans | (13) Stock-Based Compensation Plans Description of the Plans The 2005 Equity Based Compensation Plan (the “2005 Plan”) authorizes the compensation committee of the board of directors to grant, among other things, stock options, SARs, PSUs and restricted stock awards to employees. The 2005 Plan also allows us to provide equity compensation to our non-employee directors. The 2005 Plan was approved by stockholders in May 2005 and replaced our 1999 Stock Option Plan. The number of shares that may be issued under the 2005 Plan is equal to (i) 5.6 million shares plus (ii) the number of shares subject to the 1999 Stock Option Plan awards outstanding at May 18, 2005 that subsequently lapse or terminate without the underlying shares being issued plus (iii) subsequent shares approved by the stockholders. Shares issued as a result of awards granted are generally new common shares. After the approval of the 2005 Plan, no new grants have been made from the 1999 Stock Option Plan. In addition, our 2004 Non-Employee Director Stock Option Plan expired at the end of 2014. Any awards previously granted under the 1999 Stock Option Plan or the 2004 Non-Employee Director Stock Option Plan continue to be exercisable in accordance with their original terms and conditions. Total Stock-Based Compensation Expense Stock-based compensation expense represents amortization of restricted stock and performance units. The following table details the amount of stock-based compensation that is allocated to functional expense categories for each of the years in the three-year period ended December 31, 2017 (in thousands): 2017 (1) 2016 2015 Direct operating expense $ 2,060 $ 2,302 $ 2,780 Brokered natural gas and marketing expense 1,437 1,725 2,132 Exploration expense 2,742 2,298 2,985 General and administrative expense 74,873 49,293 49,687 Termination costs 1,664 — 217 Total $ 82,776 $ 55,618 $ 57,801 (1) Includes $30.8 million accelerated vesting of equity grants. In fourth quarter 2017, the compensation committee approved a new post-retirement benefit plan (See Other Post Retirement Benefits Unlike the other forms of stock-based compensation expense mentioned above, the mark-to-market of the liability related to the vested restricted stock held in our deferred compensation plans is directly tied to the change in our stock price and not directly related to the functional expenses. Therefore, the liability related to the vested restricted stock held in our deferred compensation plans is not allocated to the functional categories and is reported as deferred compensation plan expense in the accompanying consolidated statements of operations. In 2017, we recorded $5.3 million additional tax expense for the tax effect of excess financial accounting expense over the corporate income tax deduction for equity compensation vested during 2017. In 2016, we recorded $5.7 million additional tax expense for the tax effect of excess financial accounting expense over the corporate income tax deduction for equity compensation vested during 2016. In 2015, the tax deduction for stock-based compensation was less than the book stock-based compensation expense for equity compensation grants vested or exercised during the year. The tax effect of the 2015 deduction was recorded as a reduction to additional paid-in capital. Stock-Based Awards Restricted Stock Awards . We grant restricted stock units under our equity-based stock compensation plan. These restricted stock units, which we refer to as restricted stock Equity Awards, generally vest over a three year period, contingent on the recipient’s continued employment. The grant date fair value of the Equity Awards is based on the fair market value of our common stock on the date of grant. The compensation committee also grants restricted stock to certain employees and non-employee directors of the board of directors as part of their compensation. We also grant restricted stock to certain employees for retention purposes. Compensation expense is recognized over the balance of the vesting period, which is typically three years for employee grants and immediate vesting for non-employee directors. All restricted stock awards are issued at prevailing market prices at the time of the grant and the vesting is based upon an employee’s continued employment with us. Prior to vesting, all restricted stock awards have the right to vote such stock (by the trustee) and receive dividends thereon. Upon grant of these restricted shares, which we refer to as restricted stock Liability Awards, the majority of these shares are generally placed in our deferred compensation plan and, upon vesting, withdrawals are allowed in either cash or in stock. These Liability Awards are classified as a liability and are remeasured at fair value each reporting period. This mark-to-market amount is reported in deferred compensation plan expense in the accompanying consolidated statements of operations. Historically, we have used authorized but unissued shares of stock when restricted stock is granted. However, we also utilize treasury shares when available. Stock-Based Performance Units . We grant three types of performance share awards: two based on performance conditions measured against internal performance metrics (Production Growth Awards or “PG-PSUs” and Reserve Growth Awards or “RG-PSUs” and one based on market conditions measured based on Range’s performance relative to a predetermined peer group (TSR Award or “TSR-PSUs”). At grant date, each unit represents the value of one share of our common stock. These units are settled in stock and the amount of the payout is based on (1) the vesting percentage, which can be from zero to 150% based on performance achieved and (2) the value of our common stock on the date vesting is determined by the Compensation Committee. Dividend equivalent may accrue during the performance period and would be paid in stock at the end of the performance period. The performance period is a three year period. SARs . At December 31, 2017, there were 383,000 SARs outstanding. Restricted Stock – Equity Awards In 2017, we granted 888,000 restricted stock Equity Awards to employees which generally vest over a three-year period compared to 973,000 in 2016 and 588,000 in 2015. We recorded compensation expense for these awards of $23.4 million in the year ended December 31, 2017 compared to $22.8 million in 2016 and $23.8 million in 2015. As of December 31, 2017, there was $24.4 million of unrecognized compensation related to Equity Awards expected to be recognized over a weighted average period of 1.7 years. Restricted stock Equity Awards are not issued to employees until such time as they are vested and the employees do not have the option to receive cash. Restricted Stock – Liability Awards In 2017, we granted 543,000 shares of restricted stock Liability Awards as compensation to directors and employees at an average price of $25.91. This grant included 90,000 issued to non-employee directors which vest immediately and 453,000 to employees with vesting generally over a three year period. In 2016, we granted 540,000 shares of restricted stock Liability Awards as compensation to directors and employees at an average price of $35.92. This grant included 59,000 issued to non-employee directors which vest immediately and 481,000 to employees with vesting generally over a three-year period. In 2015, we granted 343,000 shares of restricted stock Liability Awards as compensation to directors and employees at an average price of $55.92. This grant included 48,000 issued to non-employee directors, which vest immediately and 295,000 to employees with vesting generally over a three-year period. We recorded compensation expense for these Liability Awards of $30.4 million in the year ended December 31, 2017 compared to $18.6 million in 2016 and $20.8 million in 2015. Accelerated vesting compensation expense of $15.4 million is included in the year ended December 31, 2017. As of December 31, 2017, there was $1.7 million of unrecognized compensation related to restricted stock Liability Awards expected to be recognized over a weighted average period of 1.6 years. The majority of all of these awards are held in our deferred compensation plan, are classified as a liability and are remeasured at fair value each reporting period. This mark-to-market amount is reported as deferred compensation expense in our consolidated statements of operations (see additional discussion below). The proceeds received from the sale of stock held in our deferred compensation plan were $4.5 Restricted Stock Restricted Stock Shares Weighted Shares Weighted Outstanding at December 31, 2014 360,415 $ 79.60 304,504 $ 80.33 Granted 587,711 52.29 343,397 55.92 Vested (480,253 ) 65.21 (330,870 ) 68.71 Forfeited (31,109 ) 64.73 (8,294 ) 74.22 Outstanding at December 31, 2015 436,764 59.74 308,737 65.80 Granted 973,491 28.51 540,128 35.92 Vested (525,617 ) 43.83 (374,328 ) 51.40 Forfeited (118,667 ) 42.60 (49,519 ) 40.33 Outstanding at December 31, 2016 765,971 33.62 425,018 43.48 Granted 888,326 32.61 543,438 25.91 Vested (698,563 ) 34.82 (908,912 ) 33.71 Forfeited (122,676 ) 32.91 (4,342 ) 31.10 Outstanding at December 31, 2017 833,058 $ 31.64 55,202 $ 32.26 Stock-Based Performance Units Production Growth and Reserve Growth Awards. The PG-PSUs and RG-PSUs vest at the end of the three-year performance period. The performance metrics for each year are set by the Compensation Committee no later than March 31 of such year. Based on our probability assessment at December 31, 2017, it is considered not probable that the criteria for the 2017 PG-PSUs will be met but it is considered probable that the criteria for the 2017 RG-PSUs will be met. If the performance metric for the applicable period is not met, then the portion is considered forfeited. The following is a summary of our non-vested PG/RG-PSUs awards outstanding at December 31, 2017: Number of Weighted Outstanding at December 31, 2016 — — Units granted (a) 122,921 $ 25.53 Outstanding at December 30, 2017 122,921 $ 25.53 (a) We recorded PG/RG-PSUs compensation expense of $1.8 million in the year ended December 31, 2017, which includes $1.5 million accelerated vesting compensation expense. TSR Awards. TSR-PSUs granted are earned, or not earned, based on the comparative performance of Range’s common stock measured against a predetermined group of companies in the peer group over a three-year performance period. The fair value of the TSR-PSUs is estimated on the date of grant using a Monte Carlo simulation model which utilizes multiple input variables that determine the probability of satisfying the market condition stipulated in the award grant and calculates the fair value of the award. The fair value is recognized as stock-based compensation expense over the three year performance period. Expected volatilities utilized in the model were estimated using a combination of a historical period consistent with the remaining performance period of three years and option implied volatilities. The risk-free interest rate was based on the United States Treasury rate for a term commensurate with the life of the grant. The following assumptions were used to estimate the fair value of PSUs granted during the years ended December 31, 2017, 2016 and 2015: Year Ended December 31, 2017 2017 2016 2015 Risk-free interest rate 1.49 % 0.94 % 1.02 % Expected annual volatility 44 % 49 % 33 % Grant date fair value per unit $ 26.26 $ 36.64 $ 56.78 The following is a summary of our non-vested TSR – Weighted Outstanding at December 31, 2014 226,418 $ 86.16 Granted (a) 276,204 56.78 Forfeited (2,679 ) 82.60 Outstanding at December 31, 2015 499,943 69.95 Granted (a) 413,959 36.64 Forfeited (42,603 ) 46.09 Outstanding at December 31, 2016 871,299 55.29 Granted (a) 358,519 26.26 Vested and issued (b) (85,461 ) 86.23 Forfeited (134,515 ) 85.24 Outstanding at December 31, 2017 1,009,842 $ 38.38 (a) These (b ) th th We recorded TSR-PSU compensation expense of $24.8 million in the year ended December 31, 2017 compared to $12.4 million in the year ended December 31, 2016 and $8.7 million in the year ended December 31, 2015. Accelerated vesting compensation expense of $13.0 million is included in the year ended December 31, 2017. As of December 31, 2017, there was $1.2 million of unrecognized compensation related to PSU awards to be recognized over a weighted average period of 2.0 years. SARs Information with respect to our SARs activities is summarized below. Shares Weighted Outstanding at December 31, 2014 1,966,549 $ 59.80 Exercised (427,598 ) 45.67 Expired/forfeited (27,974 ) 63.10 Outstanding at December 31, 2015 1,510,977 63.73 Expired/forfeited (507,377 ) 53.16 Outstanding at December 31, 2016 1,003,600 69.08 Expired/forfeited (620,821 ) 62.29 Outstanding at December 31, 2017 382,779 $ 76.54 The following table shows information with respect to SARs outstanding and exercisable at December 31, 2017: Outstanding Exercisable Range of Exercise Prices Shares Weighted Weighted Average Exercise Price Shares Weighted Average Exercise Price $ 70.00–$ 79.99 380,879 0.36 $ 76.51 380,879 $ 76.51 80.00–81.15 1,900 0.69 81.15 1,900 81.15 Total 382,779 0.36 $ 76.54 382,779 $ 76.54 The expected dividend yield is based on the current annual dividend at the time of grant. The expected life is based on the historical exercise activity. The expected volatility factors are based on a combination of both the historical volatilities of the stock and implied volatility of traded options on our common stock. The risk-free interest rate is based on the U.S. Treasury yield curve in effect at the time of grant for periods commensurate with the expected terms of the options. The total intrinsic value (the difference in value between exercise and market price at the time of grant) of SARs exercised during the year ended December 31, 2015 was $5.4 million. There were no SARs exercised in 2017 or 2016. As of December 31, 2017, there was no aggregate intrinsic value for any of the awards exercisable or awards outstanding. The weighted average remaining contractual life of awards exercisable was less than one year. As of December 31, 2017, the number of fully vested awards and the awards expected to vest was 383,000 shares. The weighted average exercise price and weighted average remaining contractual life of these awards were $76.54 and 0.4 years. As of December 31, 2017, there was no unrecognized compensation cost related to the awards. 401(k) Plan We maintain a 401(k) benefit plan that allows employees to contribute up to 75% of their salary (subject to Internal Revenue Service limitations) on a pretax basis. We match up to 6% of salary in cash and vesting of those contributions is immediate. In 2017, we contributed $5.1 million to the 401(k) Plan compared to $4.7 million in 2016 and $6.1 million in 2015. Employees have a variety of investment options in the 401(k) benefit plan. Deferred Compensation Plan Our deferred compensation plan gives directors, officers and key employees the ability to defer all or a portion of their salaries and bonuses and invest in Range common stock or make other investments at the individual’s discretion. Range provides a partial matching contribution which vests over three years. The assets of the plans are held in a grantor trust, which we refer to as the Rabbi Trust, and are therefore available to satisfy the claims of our creditors in the event of bankruptcy or insolvency. Our stock held in the Rabbi Trust is treated as a liability award as employees are allowed to take withdrawals from the Rabbi Trust either in cash or in Range stock. The liability for the vested portion of the stock held in the Rabbi Trust is reflected in the deferred compensation liability in the accompanying consolidated balance sheets and is adjusted to fair value each reporting period by a charge or credit to deferred compensation plan expense on our consolidated statements of operations. The assets of the Rabbi Trust, other than our common stock, are invested in marketable securities and reported at their market value in other assets in the accompanying consolidated balance sheets. The deferred compensation liability reflects the vested market value of the marketable securities and Range stock held in the Rabbi Trust. Changes in the market value of the marketable securities and changes in the fair value of the deferred compensation plan liability are charged or credited to deferred compensation plan expense each quarter. We recorded mark-to-market gain of $50.9 million in 2017 compared to a loss of $19.2 million in 2016 and a gain of $77.6 million in 2015. The Rabbi Trust held 2.9 million shares (2.8 million of vested shares) of Range stock at December 31, 2017 compared to 2.7 million (2.3 million of vested shares) at December 31, 2016. Other Post Retirement Benefits Effective fourth quarter 2017, we implemented a post-retirement benefit plan to assist in providing health care to officers who are active employees (including their spouses) and have met certain age and service requirements. These benefits are not funded in advance and are provided up to age 65 or at the date they become eligible for Medicare, subject to various cost-sharing features (in thousands). December 31, 2017 Accumulated benefit obligation $ 1,769 Change in benefit obligations (recognized in comprehensive income – pretax) Beginning balance at December 31, 2016 $ — Prior service cost 1,769 Total other comprehensive income (loss) at December 31, 2017 $ 1,769 Amounts recognized in the consolidated balance sheets: Noncurrent liability-accrued benefit cost $ 1,769 The following summarizes the assumptions used to determine the benefit obligation at December 31, 2017. December 31, 2017 Weighted average assumptions used to determine benefit obligation: Discount rate 3.3 % Assumed weighted average healthcare cost trend rates: Initial healthcare trend rate 7.00 % Ultimate trend rate 5.00 % Year ultimate trend rate reached 2028 The expected future benefit payments under our post-retirement medical plan for the next ten years is $675,000 for the five year period 2018 through 2022 and $638,000 for the five year period 2023 through 2027. The estimated prior service cost that will be amortized from accumulated other comprehensive income into our statement of operations in 2018 is $369,000. |
Supplemental Cash Flow Informat
Supplemental Cash Flow Information | 12 Months Ended |
Dec. 31, 2017 | |
Supplemental Cash Flow Elements [Abstract] | |
Supplemental Cash Flow Information | (14) Supplemental Cash Flow Information Year Ended December 31, 2017 2016 2015 (in thousands) Net cash provided from operating activities included: Income taxes (refunded from) paid to taxing authorities $ (1,024 ) $ (102 ) $ 100 Interest paid 179,431 159,875 168,826 Non-cash investing and financing activities included (a) Asset retirement costs capitalized, net $ 20,245 $ (24,064 ) $ 22,184 Increase (decrease) in accrued capital expenditures 71,739 61,419 (225,455 ) (a) For additional information on non-cash investing activities associated with the MRD Merger, see Note 3. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2017 | |
Commitments And Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | (15) Commitments and Contingencies Litigation We are the subject of, or party to, a number of pending or threatened legal actions and claims arising in the ordinary course of our business. While many of these matters involve inherent uncertainty, we believe that the amount of the liability, if any, ultimately incurred with respect to proceedings or claims will not have a material adverse effect on our consolidated financial position as a whole or on our liquidity, capital resources or future annual results of operations. We will continue to evaluate our litigation on a quarterly basis and will establish and adjust any litigation reserves as appropriate to reflect our assessment of the then current status of litigation. Lease Commitments We lease certain office space, office equipment, production facilities, compressors and transportation equipment under cancelable and non-cancelable leases. Rent expense under operating leases (including renewable monthly leases) totaled $19.1 million in 2017 compared to $14.0 million in 2016 and $15.9 million in 2015. Commitments related to these lease payments are not recorded in the accompanying consolidated balance sheets. Future minimum rental commitments under non-cancelable leases having remaining lease terms in excess of one year are as follows (in thousands): Operating Sublease 2018 $ 18,498 $ 3,472 2019 17,803 3,472 2020 16,945 3,174 2021 14,249 2,578 2022 8,058 215 Thereafter 32,909 — $ 108,462 $ 12,911 Transportation, Gathering and Processing Contracts We have entered into firm transportation and gathering contracts with various pipeline carriers for the future transportation and gathering of natural gas, NGLs and oil production from our properties in Pennsylvania and North Louisiana. Under these contracts, we are obligated to transport, process or gather minimum daily natural gas volumes, or pay for any deficiencies at a specified reservation fee rate. In most cases, our production committed to these pipelines is expected to exceed the minimum daily volumes provided in the contracts. As part of our purchase price allocation of liabilities that existed at the time of the MRD Merger, we have a remaining liability of $25.1 million for certain expected volume deficiency payments related to our properties in North Louisiana. As of December 31, 2017, future minimum transportation, processing and gathering fees under our commitments are as follows (in thousands): Transportation, (a) 2018 $ 805,161 2019 825,231 2020 767,090 2021 733,133 2022 691,968 Thereafter 4,689,133 $ 8,511,716 (a) In addition to the amounts included in the above table, we have entered into an additional agreement which is contingent on certain pipeline modifications and/or construction. This agreement has a twenty year term and may begin in 2018. Based on this contract, we will have additional transportation obligations for natural gas volumes of 400,000 mcf per day until 2038. Delivery Commitments We have various volume delivery commitments that are primarily related to our Marcellus Shale and North Louisiana areas. We expect to be able to fulfill our contractual obligations from our own production; however, we may purchase third party volumes to satisfy our commitments or pay demand fees for commitment shortfalls, should they occur. As of December 31, 2017, our delivery commitments through 2031 were as follows: Year Ending December 31, Natural Gas Ethane and Propane (bbls per day) 2018 382,534 71,000 2019 364,356 55,932 2020 252,878 48,625 2021 116,189 48,000 2022 68,712 43,000 2023 — 35,000 2024 — — 35,000 2029—2031 — 20,000 In addition to the amounts included in the above table, we have contracted with a pipeline company through 2020 to deliver ethane production volumes from our Marcellus Shale wells. These agreements and related fees, which are contingent upon pipeline construction and/or modification, are for 13,000 bbls per day starting in 2018. In addition, we have agreements in place to deliver natural gas volumes from our Marcellus Shale wells, which are also contingent upon pipeline construction and/or modification, for 15,000 mcf per day starting in late 2018, increasing to 65,000 mcf per day in early 2019 and 180,000 mcf per day in late 2019. Other We also have lease acreage that is generally subject to lease expiration if initial wells are not drilled within a specified period, generally between three and five years. We do not expect to lose significant lease acreage because of failure to drill due to inadequate capital, equipment or personnel. However, based on our evaluation of prospective economics, we have allowed acreage to expire and will allow additional acreage to expire in the future. To date, our expenditures to comply with environmental or safety regulations have not been a significant component of our cost structure and are not expected to be significant in the future. However, new regulations, enforcement policies, claims for damages or other events could result in significant future costs. |
Office Closing and Exit Costs
Office Closing and Exit Costs | 12 Months Ended |
Dec. 31, 2017 | |
Restructuring And Related Activities [Abstract] | |
Office Closing and Exit Costs | ( 16) Office Closing and Exit Costs In first quarter 2015, we announced the closing of our Oklahoma City administrative and operational office in order to lower our general and administrative expenses, due in part to the impact of lower commodity prices on our operations. In fourth quarter 2014, we initially accrued an estimated $8.4 million of termination costs relating to the closure of this office as it had become probable of occurring. In early 2015, the plans to close the Oklahoma City office were finalized which resulted in additional accruals in 2015 for severance and other personnel costs of $275,000, additional accelerated vesting of stock-based compensation of $948,000 and $3.1 million of building lease costs. In the year ended December 31, 2015 additional accruals for severance of $11.4 million and a gain of $731,000 of accelerated vesting of stock-based compensation related to the sale of our Virginia and West Virginia properties which closed on December 30, 2015 and additional reductions in our work force due to the lower commodity price environment. There are no office closing or termination costs associated with the MRD Merger in 2016. As part of a continuing effort to reduce our general and administrative expenses due to the lower commodity price environment, additional accruals for severance of $2.2 million and accelerated vesting of stock-based compensation of $1.7 million were recorded in the year ended December 31, 2017. The following table details the accrued liability as of December 31, 2017 and December 31, 2016 (in thousands): 2017 2016 Beginning balance $ 2,460 $ 11,630 Accrued severance costs 2,176 (822 ) Accrued building rent (70 ) 303 Payments (2,711 ) (8,651 ) Ending balance $ 1,855 $ 2,460 The following summarizes our termination costs for three years ended December 31, 2017, 2016 and 2015 (in thousands): 2017 2016 2015 Severance costs $ 2,176 $ (822 ) $ 11,706 Building lease (70 ) 303 3,147 Stock-based compensation 1,664 — 217 Total termination costs $ 3,770 $ (519 ) $ 15,070 |
Selected Quarterly Financial Da
Selected Quarterly Financial Data (Unaudited) | 12 Months Ended |
Dec. 31, 2017 | |
Quarterly Financial Data [Abstract] | |
Selected Quarterly Financial Data (Unaudited) | (17) Selected Quarterly Financial Data (Unaudited) The following tables set forth unaudited financial information on a quarterly basis for each of the last two years. Third quarter 2017 includes impairment expense of $63.7 million related to oil and gas properties in Oklahoma and Texas. Fourth quarter 2017 deferred income tax benefit includes the impact of the Tax Cuts and Jobs Act of 2017 which was signed into law on December 22, 2017. First quarter 2016 includes impairment expense of $43.0 million related to oil and gas properties in Western Oklahoma. Second quarter, third quarter and fourth quarter 2016 include a total of $37.2 million of expenses related to the MRD Merger (in thousands, except per share data): 2017 March June September December Total Revenues and other income: Natural gas, NGLs and oil sales $ 559,450 $ 506,137 $ 507,541 $ 603,159 $ 2,176,287 Derivative fair value income (loss) 165,557 111,195 (88,426 ) 25,024 213,350 Brokered natural gas, marketing and other 51,648 55,779 63,117 50,849 221,393 Total revenue and other income 776,655 673,111 482,232 679,032 2,611,030 Costs and expenses: Direct operating 28,023 31,420 36,888 37,921 134,252 Transportation, gathering, processing and compression 177,648 191,590 191,645 200,300 761,183 Production and ad valorem taxes 9,163 9,969 11,993 11,757 42,882 Brokered natural gas and marketing 53,550 55,857 59,773 51,131 220,311 Exploration 8,504 14,498 22,767 7,893 53,662 Abandonment and impairment of unproved properties 4,420 5,193 42,568 217,544 269,725 General and administrative 47,496 52,322 53,035 80,553 233,406 Termination costs 4,192 (96 ) (47 ) (279 ) 3,770 Deferred compensation plan (13,169 ) (14,466 ) (9,203 ) (14,077 ) (50,915 ) Interest 47,101 47,926 49,179 51,473 195,679 Depletion, depreciation and amortization 149,821 152,504 159,749 162,918 624,992 Impairment of proved properties and other — — 63,679 — 63,679 (Gain) loss on sale of assets (22,600 ) (807 ) (102 ) (207 ) (23,716 ) Total costs and expenses 494,149 545,910 681,924 806,927 2,528,910 Income (loss) before income taxes 282,506 127,201 (199,692 ) (127,895 ) 82,120 Income tax expense (benefit): Current — — — 17 17 Deferred 112,395 57,651 (71,992 ) (349,097 ) (251,043 ) 112,395 57,651 (71,992 ) (349,080 ) (251,026 ) Net income (loss) $ 170,111 $ 69,550 $ (127,700 ) $ 221,185 $ 333,146 Net income (loss) per common share: Basic $ 0.69 $ 0.28 $ (0.52 ) $ 0.89 $ 1.34 Diluted $ 0.69 $ 0.28 $ (0.52 ) $ 0.89 $ 1.34 2016 March June September December Total Revenues and other income: Natural gas, NGLs and oil sales $ 209,487 $ 224,606 $ 304,477 $ 458,645 $ 1,197,215 Derivative fair value income (loss) 86,908 (162,798 ) 64,556 (250,057 ) (261,391 ) Brokered natural gas, marketing and other 35,018 39,989 44,174 44,934 164,115 Total revenue and other income 331,413 101,797 413,207 253,522 1,099,939 Costs and expenses: Direct operating 24,054 20,671 22,387 30,276 97,388 Transportation, gathering, processing and compression 125,263 136,844 138,764 164,338 565,209 Production and ad valorem taxes 5,887 6,049 6,717 6,790 25,443 Brokered natural gas and marketing 36,558 40,925 44,622 46,471 168,576 Exploration 4,913 6,785 6,943 13,684 32,325 Abandonment and impairment of unproved properties 10,628 7,059 6,082 6,307 30,076 General and administrative 40,657 46,064 41,024 57,027 184,772 MRD Merger expenses — 2,621 33,791 813 37,225 Termination costs 162 5 136 (822 ) (519 ) Deferred compensation plan 16,056 25,746 (11,636 ) (11,013 ) 19,153 Interest 37,739 37,758 45,967 46,749 168,213 Depletion, depreciation and amortization 120,561 122,390 131,489 149,662 524,102 Impairment of proved properties and other 43,040 — — — 43,040 Loss (gain) on sale of assets 1,643 3,304 2,597 (470 ) 7,074 Total costs and expenses 467,161 456,221 468,883 509,812 1,902,077 Loss before income taxes (135,748 ) (354,424 ) (55,676 ) (256,290 ) (802,138 ) Income tax expense (benefit): Current — — — 98 98 Deferred (41,976 ) (129,488 ) (13,705 ) (95,679 ) (280,848 ) (41,976 ) (129,488 ) (13,705 ) (95,581 ) (280,750 ) Net loss $ (93,772 ) $ (224,936 ) $ (41,971 ) $ (160,709 ) $ (521,388 ) Net loss per common share: Basic $ (0.56 ) $ (1.35 ) $ (0.23 ) $ (0.66 ) $ (2.75 ) Diluted $ (0.56 ) $ (1.35 ) $ (0.23 ) $ (0.66 ) $ (2.75 ) |
Supplemental Information on Nat
Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) | 12 Months Ended |
Dec. 31, 2017 | |
Extractive Industries [Abstract] | |
Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) | (18) Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) Our natural gas and oil producing activities are conducted onshore within the continental United States and all of our proved reserves are located within the United States. Capitalized Costs and Accumulated Depreciation, Depletion and Amortization (a) December 31, 2017 2016 2015 (in thousands) Natural gas and oil properties: Properties subject to depletion $ 10,572,453 $ 9,462,350 $ 8,047,181 Unproved properties 2,644,000 2,923,803 949,155 Total 13,216,453 12,386,153 8,996,336 Accumulated depreciation, depletion and amortization (3,649,716 ) (3,129,816 ) (2,635,031 ) Net capitalized costs $ 9,566,737 $ 9,256,337 $ 6,361,305 (a) Costs Incurred for Property Acquisition, Exploration (a) December 31, 2017 2016 2015 (in thousands) Acquisitions Acreage purchases $ 62,075 $ 33,142 $ 73,025 Oil and gas properties 18,269 3,098,772 — Asset retirement obligations and other — 21,908 — Development 1,177,526 497,795 708,268 Exploration: Drilling 2,030 37,680 87,505 Expense 50,920 30,027 18,421 Stock-based compensation expense 2,742 2,298 2,985 Gas gathering facilities: Development 15,097 3,595 13,337 Subtotal 1,328,659 3,725,217 903,541 Asset retirement obligations 20,245 (24,064 ) 22,184 Total costs incurred $ 1,348,904 $ 3,701,153 $ 925,725 (a) Reserve Audit All reserve information in this report is based on estimates prepared by our petroleum engineering staff. At year-end 2017, the following independent petroleum consultants conducted an audit of our reserves: Wright & Company, Inc. (Appalachia) and Netherland, Sewell & Associates, Inc. (North Louisiana). These engineers were selected for their geographic expertise and their historical experience in engineering certain properties. At December 31, 2017, our consultants collectively audited approximately 98% of our proved reserves. Copies of the summary reserve reports prepared by our independent petroleum consultants are included as exhibits to this Annual Report on Form 10-K. The technical professional at our independent petroleum consulting firms responsible for reviewing the reserve estimates presented herein meets the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent petroleum consultants to ensure the integrity, accuracy and timeliness of data furnished during the reserves audit process. Throughout the year, our technical team meets periodically with representatives of our independent petroleum consultants to review properties and discuss methods and assumptions. While we have no formal committee specifically designated to review reserves reporting and the reserves estimation process, our senior management reviews and approves any significant changes to our proved reserves. We provide historical information to our consultants for our largest producing properties such as ownership interest, natural gas, NGLs and oil production, well test data, commodity prices and operating and development costs. The consultants perform an independent analysis and differences are reviewed with our Senior Vice President of Reservoir Engineering and Economics. In some cases, additional meetings are held to review identified reserve differences. The reserve auditor estimates of proved reserves and the pretax present value of such reserves discounted at 10% did not differ from our estimates by more than 10% in the aggregate. However, when compared lease-by-lease, field-by-field or area-by-area basis, some of our estimates may be greater and some may be less than the estimates of our reserve auditor. When such differences do not exceed 10% in the aggregate, our reserve auditor is satisfied that the proved reserves and pretax present value of such reserves discounted at 10% are reasonable and will issue an unqualified opinion. Remaining differences are not resolved due to the limited cost benefit of continuing such analysis. Historical variances between our reserve estimates and the aggregate estimates of our independent petroleum consultants have been less than 5%. All of our reserve estimates are reviewed and approved by our Senior Vice President of Reservoir Engineering and Economics, who reports directly to our Chairman, President and Chief Executive Officer. Mr. Alan Farquharson, our Senior Vice President of Reservoir Engineering and Economics, holds a Bachelor of Science degree in Electrical Engineering from the Pennsylvania State University. Before joining Range, he held various technical and managerial positions with Amoco, Hunt Oil and Union Pacific Resources and has more than thirty-five years of engineering experience in the oil and gas industry. During the year, our reserves group may also perform separate, detailed technical reviews of reserve estimates for significant acquisitions or for properties with problematic indicators such as excessively long lives, sudden changes in performance or changes in economic or operating conditions. Estimated Quantities of Proved Oil and Gas Reserves (Unaudited) Reserves of natural gas, NGLs, crude oil and condensate are estimated by our petroleum engineering staff and are adjusted to reflect contractual arrangements and royalty rates in effect at the end of each year. Many assumptions and judgmental decisions are required to estimate reserves. Reported quantities are subject to future revisions, some of which may be substantial, as additional information becomes available from reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes, production taxes and other economic factors. The SEC defines proved reserves as those volumes of natural gas, NGLs, crude oil and condensate that geological and engineering data demonstrate with reasonable certainty are recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those proved reserves which can be expected to be recovered from existing wells with existing equipment and operating methods. Proved undeveloped reserves are volumes expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Proved undeveloped reserves can only be assigned to acreage for which improved recovery technology is contemplated when such techniques have been proven effective by actual tests in the area and in the same reservoir. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating each location is scheduled to be drilled within five years from the date it was booked as proved reserves, unless specific circumstances justify a longer time. The reported value of proved reserves is not necessarily indicative of either fair market value or present value of future net cash flows because prices, costs and governmental policies do not remain static, appropriate discount rates may vary, and extensive judgment is required to estimate the timing of production. Other logical assumptions would likely have resulted in significantly different amounts. The average realized prices used at December 31, 2017 to estimate reserve information were $45.73 per barrel of oil, $17.84 per barrel of NGLs and $2.60 per mcf for gas using a benchmark (NYMEX) of $51.19 per barrel and $2.98 per Mmbtu. The average realized prices used at December 31, 2016 to estimate reserve information were $37.41 per barrel of oil, $13.44 per barrel of NGLs and $2.07 per mcf for gas using a benchmark (NYMEX) of $42.68 per barrel and $2.48 per Mmbtu. The average realized prices used at December 31, 2015 to estimate reserve information were $35.07 per barrel of oil, $11.74 per barrel of NGLs and $2.07 per mcf for gas, using a benchmark (NYMEX) of $50.13 per barrel and $2.59 per Mmbtu. Natural Gas NGLs Crude Oil and Condensate Natural Gas (Mmcf) (Mbbls) (Mbbls) (Mmcfe) (a) Proved developed and undeveloped reserves: Balance, December 31, 2014 6,922,836 515,907 48,658 10,310,229 Revisions (340,286 ) 17,717 3,804 (211,163 ) Extensions, discoveries and additions 1,017,956 36,308 4,924 1,265,348 Property sales (960,122 ) (441 ) (109 ) (963,423 ) Production (362,687 ) (20,356 ) (4,084 ) (509,328 ) Balance, December 31, 2015 6,277,697 549,135 53,193 9,891,663 Revisions (7,441 ) 41,402 2,471 255,794 Extensions, discoveries and additions 1,193,154 26,991 6,506 1,394,134 Purchases 943,544 40,724 11,986 1,259,806 Property sales (160,727 ) (360 ) (295 ) (164,655 ) Production (375,811 ) (27,826 ) (3,609 ) (564,420 ) Balance, December 31, 2016 7,870,416 630,066 70,252 12,072,322 Revisions 70,222 83,338 (10,555 ) 506,919 Extensions, discoveries and additions 2,866,103 87,572 15,997 3,487,519 Purchases 7,738 330 66 10,116 Property sales (60,278 ) (2,356 ) (1,121 ) (81,133 ) Production (490,552 ) (35,686 ) (4,785 ) (733,382 ) Balance, December 31, 2017 10,263,649 763,264 69,854 15,262,361 Proved developed reserves: December 31, 2015 3,376,165 309,306 31,679 5,422,075 December 31, 2016 4,352,141 363,852 39,110 6,769,908 December 31, 2017 5,437,674 448,258 36,808 8,348,074 Proved undeveloped reserves: December 31, 2015 2,901,533 239,828 21,514 4,469,588 December 31, 2016 3,518,275 266,214 31,143 5,302,414 December 31, 2017 4,825,975 315,006 33,046 6,914,287 (a) Oil and NGLs are converted to mcfe at the rate of one barrel equals six mcf based upon the approximate relative energy content of oil to natural gas, which is not indicative of the relationship of oil and natural gas prices. During 2017, we added approximately 3.5 Tcfe of proved reserves from drilling activities and evaluation of proved areas primarily in the Marcellus Shale. Approximately 82% of the 2017 reserve additions are attributable to natural gas. Included in 2017 proved reserves is a total of 360.6 Mmbbls of ethane reserves (1,596 Bcfe) in the Marcellus Shale. Revisions of previous estimates of 507 Bcfe includes positive performance revisions of 532 Bcfe, improved recoveries of 597 Bcfe, positive pricing revisions of 46 Bcfe partially offset by 668 Bcfe reclassified to unproved for previously planned wells not to be drilled within the original five-year development horizon. Purchases of reserves in 2017 reflects reserves added in North Louisiana. During 2016, we added approximately 1.4 Tcfe of proved reserves from drilling activities and evaluation of proved areas primarily in the Marcellus Shale. Approximately 86% of the 2016 reserve additions are attributable to natural gas. Included in 2016 proved reserves is a total of 308.9 Mmbbls of ethane reserves (1,367 Bcfe) in the Marcellus Shale. Revisions of previous estimates of 256 Bcfe includes positive performance revisions of 154 Bcfe and improved recoveries of 393 Bcfe primarily from our Marcellus Shale natural gas properties partially offset by negative price revisions and 269 Bcfe reclassified to unproved for previously planned wells not to be drilled within the original five-year development horizon. Purchases of reserves in 2016 reflect reserves added in North Louisiana, primarily from the MRD Merger. During 2015, we added approximately 1.3 Tcfe of proved reserves from drilling activities and evaluation of proved areas primarily in the Marcellus Shale. Approximately 80% of the 2015 reserve additions are attributable to natural gas. Included in 2015 proved reserves is a total of 292.8 Mmbbls of ethane reserves (1,296 Bcfe) in the Marcellus Shale. Revisions of previous estimates of a negative 211 Bcfe includes positive performance revisions and improved recoveries of 781.0 Bcf primarily from our Marcellus Shale natural gas properties more than offset by negative price revisions and 1.2 Tcfe reclassified to unproved because of lower future capital spending in response to lower commodity prices. The following details the changes in proved undeveloped reserves for 2017 (Mmcfe): Beginning proved undeveloped reserves at December 31, 2016 5,302,414 Undeveloped reserves transferred to developed (1,861,994 ) Revisions (a) 308,929 Purchases/(sales) (8,907 ) Extension and discoveries 3,173,845 Ending proved undeveloped reserves at December 31, 2017 6,914,287 (a) Approximately $920 million was spent during 2017 related to undeveloped reserves that were transferred to developed reserves. Estimated future development costs of proved undeveloped reserves are projected to be approximately $717 million in 2018, $707 million in 2019 and $567 million in 2020. As of December 31, 2017, we have 64 Bcfe of reserves (less than 1% of total proved undeveloped reserves) that have been reported for more than five years from their original date of booking, all of which are in the process of being drilled. All of our recorded proved undeveloped drilling locations are scheduled to be drilled within five years of initial disclosure. All proved undeveloped drilling locations are scheduled to be drilled prior to the end of 2022. Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited) The following summarizes the policies we used in the preparation of the accompanying natural gas, NGLs, crude oil and condensate reserve disclosures, standardized measures of discounted future net cash flows from proved natural gas, NGLs and oil reserves and the reconciliations of standardized measures from year to year. The information disclosed is an attempt to present the information in a manner comparable with industry peers. The information is based on estimates of proved reserves attributable to our interest in natural gas and oil properties as of December 31 of the years presented. These estimates were prepared by our petroleum engineering staff. Proved reserves are estimated quantities of natural gas, NGLs, crude oil and condensate, which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. The standardized measure of discounted future net cash flows from production of proved reserves was developed as follows: 1. Estimates are made of quantities of proved reserves and future amounts expected to be produced based on current year-end economic conditions. 2. For the years ended 2017, 2016 and 2015, estimated future cash inflows are calculated by applying a twelve-month average price of natural gas, NGLs and oil relating to our proved reserves to the quantities of those reserves produced in each future year. 3. Future cash flows are reduced by estimated production costs, administrative costs, costs to develop and produce the proved reserves and abandonment costs, all based on current year-end economic conditions. Future income tax expenses are based on current year-end statutory tax rates giving effect to the remaining tax basis in the natural gas, NGLs and oil properties, other deductions, credits and allowances relating to our proved natural gas and oil reserves. 4. The resulting future net cash flows are discounted to present value by applying a discount rate of 10%. The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair value of our natural gas, NGLs and oil reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs and a discount factor more representative of the time value of money and the risks inherent in reserve estimates. The standardized measure of discounted future net cash flows relating to proved natural gas, NGLs, crude oil and condensate reserves is as follows and excludes cash flows associated with derivatives outstanding at each of the respective reporting dates. Future cash inflows are net of third party transportation, gathering and compression expense. As of December 31, 2017 2016 (in thousands) Future cash inflows $ 43,500,054 $ 27,413,864 Future costs: Production (18,958,695 ) (14,465,059 ) Development (a) (3,072,688 ) (2,647,801 ) Future net cash flows before income taxes 21,468,671 10,301,004 Future income tax expense (3,989,459 ) (1,946,259 ) Total future net cash flows before 10% discount 17,479,212 8,354,745 10% annual discount (10,313,998 ) (4,902,816 ) Standardized measure of discounted future net cash flows $ 7,165,214 $ 3,451,929 (a) The following table summarizes changes in the standardized measure of discounted future net cash flows. December 31, 2017 2016 2015 (in thousands) Revisions of previous estimates: Changes in prices and production costs $ 2,615,825 $ (212,867 ) $ (7,231,629 ) Revisions in quantities 445,667 96,615 (868,886 ) Changes in future development and abandonment costs (497,400 ) (314,864 ) 359,540 Net change in income taxes (706,531 ) 27,842 2,173,904 Accretion of discount 372,743 302,920 1,007,027 Purchases of reserves in place 6,173 488,959 — Additions to proved reserves from extensions, discoveries and improved recovery 2,128,135 541,095 486,478 Natural gas, NGLs and oil sales, net of production costs (1,237,970 ) (509,174 ) (522,682 ) Development costs incurred during the period 885,803 435,928 1,033,539 Sales of reserves in place (32,946 ) (65,538 ) (1,050,237 ) Timing and other (266,214 ) (64,850 ) (254,218 ) Net change for the year 3,713,285 726,066 (4,867,164 ) Beginning of year 3,451,929 2,725,863 7,593,027 End of year $ 7,165,214 $ 3,451,929 $ 2,725,863 |
Summary of Significant Accoun27
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Policies [Abstract] | |
Basis of Presentation and Principles of Consolidation | Basis of Presentation and Principles of Consolidation The accompanying consolidated financial statements include the accounts of all of our subsidiaries. All material intercompany balances and transactions have been eliminated. |
Use of Estimates | Use of Estimates The preparation of financial statements in accordance with U.S. GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from these estimates and changes in these estimates are recorded when known. |
Business Segment Information | Business Segment Information We have evaluated how we are organized and managed and have identified only one operating segment, which is the exploration and production of natural gas, NGLs and oil in the United States. We consider our gathering, processing and marketing functions as integral to our natural gas and oil producing activities. Operating segments are defined as components of an enterprise that engage in activities from which it may earn revenues and incur expenses for which separate operational financial information is available and this information is regularly evaluated by the chief operating decision maker for the purpose of allocating resources and assessing performance. We have a single company-wide management team that administers all properties as a whole rather than by discrete operating segments. We track only basic operational data by area. We do not maintain complete separate financial statement information by area. We measure financial performance as a single enterprise and not on a geographical or area-by-area basis. Throughout the year, we allocate capital resources on a project-by-project basis, across our entire asset base to optimize returns without regard to individual areas. |
Revenue Recognition, Accounts Receivable and Gas Imbalances | Revenue Recognition, Accounts Receivable and Gas Imbalances Natural gas, NGLs and oil sales are recognized when we deliver our production to the customer and collectability is reasonably assured. We generally sell natural gas, NGLs and oil under two types of agreements, which are common in our industry. Both types of agreements include transportation charges. We are reporting our gathering and transportation costs in accordance with Accounting Standards Code Section 605-45-05 of Subtopic 605-45 for Revenue Recognition. One type of agreement is a netback arrangement, under which we sell natural gas and oil at the wellhead and collect a price, net of transportation incurred by the purchaser. In this case, we record revenue at the price we receive from the purchaser. For the sale of our NGLs, in some cases, we receive a price from the purchaser (which is net of processing costs) that is recorded in revenue at the net price we receive. Under the other type of agreement, we sell natural gas, NGLs or oil at a specific delivery point, pay transportation, gathering, processing and compression expenses to a third party and receive proceeds from the purchaser with no deduction. In that case, we record revenue at the price received from the purchaser and record the expenses we incur as transportation, gathering, processing and compression expense. We realize brokered margins as a result of buying and selling natural gas utilizing separate purchase and sale transactions, typically with separate counterparties, whereby Range or the counterparty takes title to the natural gas purchased or sold. Revenues and expenses related to brokered natural gas are reported gross as part of revenues and expenses in accordance with applicable accounting standards. Our net brokered margin was a loss of $5.7 million in 2017 compared to losses of $2.8 million in 2016 and losses of $2.7 million in 2015. Although receivables are concentrated in the oil and gas industry, we do not view this as an unusual credit risk. We provide for an allowance for doubtful accounts for specific receivables judged unlikely to be collected based on the age of the receivable, our experience with the debtor, potential offsets to the amount owed and economic conditions. In certain instances, we require purchasers to post stand-by letters of credit. Many of our receivables are from joint interest owners of properties we operate. Thus, we may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. We have allowances for doubtful accounts relating to exploration and production receivables of $7.1 million at December 31, 2017 compared to $5.6 million at December 31, 2016. We recorded bad debt expense of $1.6 million in the year ended December 31, 2017 compared to $800,000 in the year ended December 31, 2016 and $2.3 million in the year ended 2015. Revenues from the production of natural gas, NGLs and oil on properties in which we have joint ownership are recorded under the sales method. Under the sales method, we and other joint owners may sell more or less than our entitled share of production. Should our sales exceed our share of remaining reasonable reserves, a liability is recorded. Imbalances are not significant in the periods presented. |
Cash and Cash Equivalents | Cash and Cash Equivalents Cash and cash equivalents include cash on hand and on deposit and investments in highly liquid debt instruments with maturities of three months or less. Outstanding checks in excess of funds on deposit are included in accounts payable on the consolidated balance sheets and the change in such overdrafts is classified as a financing activity on the consolidated statements of cash flows. |
Marketable Securities | Marketable Securities Investments in unaffiliated equity securities held in our deferred compensation plans qualify as trading securities and are recorded at fair value. Investments held in the deferred compensation plans consist of various publicly-traded mutual funds. These funds include equity securities and money market instruments and are reported in other assets in the accompanying consolidated balance sheets. |
Inventory | Inventory Inventories were comprised of $12.1 million of materials and supplies at December 31, 2017 compared to $9.4 million at December 31, 2016. Inventories consist primarily of tubular goods and equipment used in our operations and are stated at the lower of specific cost of each inventory item or net realizable value, on a first-in, first-out basis. Our material and supplies inventory is primarily acquired for use in future drilling operations or repair operations and is reviewed periodically for obsolescence or impairment when market conditions indicate. At December 31, 2017, we also had commodity inventory of $508,000, compared to $8.3 million at December 31, 2016, which is carried at lower of weighted average cost or net realizable value, on a first-in, first-out basis. Commodity inventory at December 31, 2017 consists of NGLs held as line fill in pipelines or tanks. |
Goodwill | Goodwill As a result of our merger with Memorial Resource Development Corp. (the “MRD Merger” or “Memorial”) in September 2016, we have goodwill in the amount of $1.6 billion at December 31, 2017, the excess of consideration transferred over the fair value of Memorial. Goodwill is not amortized but tested for impairment annually, as of November 1 st Performing a qualitative impairment assessment of our business requires an examination of relevant events and circumstances that could have a negative impact on our business, such as macroeconomic conditions, industry and market conditions (including current commodity price), earnings and cash flows, overall financial performance and other relevant entity specific events. When performing a quantitative impairment assessment of goodwill, fair value is estimated based on a combination of (i) recent market transactions, where available; and (ii) projected discounted cash flows (an income approach). Under the income approach, the fair value is based on the present value of expected future cash flows. The income approach is dependent on a number of factors including estimates of forecasted revenue and operating costs, proved reserves, as well as the success of future exploration for and development of unproved reserves, discount rates and other variables. Negative revisions of estimated reserves quantities, increases in future cost estimates, divestitures or sustained decreases in crude oil or natural gas prices could lead to a reduction in expected future cash flows and possibly an impairment of all or a portion of goodwill in future periods. Key assumptions used in the discounted cash flow model include estimated quantities of crude oil, natural gas and NGLs reserves, including both proved reserves and risk-adjusted unproved reserves; estimates of market prices considering forward commodity price curves as of the measurement date; and estimates of operating, administrative and capital costs adjusted for inflation. We discount the resulting future cash flows using a peer company based weighted average cost of capital. Under the market approach, we would estimate fair value by a comparison to similar businesses whose securities are actively traded in the public market. This requires management to make certain judgments including the selection of comparable companies and/or comparable recent company asset transactions, transaction premiums and selected financial metrics. If natural gas, NGLs and oil prices decrease, drilling efforts are unsuccessful or our market capitalization declines further, it is reasonably possible that we would be required to record additional impairments. |
Natural Gas and Oil Properties | Natural Gas and Oil Properties Property Acquisition Costs . We use the successful efforts method of accounting for natural gas and oil producing activities. Costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs, delay rentals and costs of carrying and retaining unproved properties are expensed. Costs incurred for exploratory wells that find reserves that cannot yet be classified as proved are capitalized if (a) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (b) we are making sufficient progress assessing the reserves and the economic and operating viability of the project. The status of suspended well costs is monitored continuously and reviewed not less than quarterly. We capitalize successful exploratory wells and all developmental wells, whether successful or not. Due to the capital-intensive nature and the geographical location of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and the economics associated with making a determination on its commercial viability. In these instances, the project’s feasibility is not contingent upon price improvements or advances in technology, but rather our ongoing efforts and expenditures related to accurately predicting the hydrocarbon recoverability based on well information, gaining access to other companies’ production data in the area, transportation or processing facilities and/or obtaining partner approval to drill additional appraisal wells. These activities are ongoing and are being pursued constantly. Consequently, our assessment of suspended exploratory well costs is continuous until a decision can be made that the project has found proved reserves to sanction the project or is noncommercial and is charged to exploration expense. For more information regarding suspended exploratory well costs, see Note 7. Depreciation, Depletion and Amortization . Depreciation, depletion and amortization of proved producing properties, including other property and equipment such as gathering lines related to natural gas and oil producing activities, is provided on the units of production method. Historically, we have adjusted our depletion rates in the fourth quarter of each year based on the year-end reserve report and at other times during the year when circumstances indicate there has been a significant change in reserves or costs. In the year ended December 31, 2015, the fair value of our natural gas and oil properties in Northwest Pennsylvania was determined to be zero. As a result, any future adjustments to the asset retirement liability for these properties represents an impairment expense and we have elected to record such expense in depreciation, depletion and amortization. In the year ended December 31, 2017, additional expense of $158,000 was recorded related to these costs compared to $1.9 million in the year ended December 31, 2016. Impairments . Our proved natural gas and oil properties are reviewed for impairment annually and periodically as events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. These assets are reviewed for potential impairment at the lowest level for which there are identifiable cash flows that are largely independent of other groups of assets which is the level at which depletion is calculated. The review is done by determining if the historical cost of proved properties less the applicable accumulated depreciation, depletion and amortization is less than the estimated expected undiscounted future net cash flows. The expected future net cash flows are estimated based on our plans to produce and develop reserves. Expected future net cash inflow from the sale of produced reserves is calculated based on estimated future prices and estimated operating and development costs. We estimate prices based upon market-related information including published futures prices. The estimated future level of production, which is based on proved and risk adjusted probable and possible reserves, has assumptions surrounding the future levels of prices and costs, field decline rates, market demand and supply, and the economic and regulatory climate. In certain circumstances, we also consider potential sales of properties to third parties in our estimates of cash flows. When the carrying value exceeds the sum of undiscounted future net cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future net cash flows using a discount rate similar to that used by market participants) and the carrying value of the asset. A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events. Such events include a projection of future natural gas and oil prices, an estimate of the ultimate amount of recoverable natural gas and oil reserves that will be produced from an asset group, the timing of future production, future production costs, future abandonment costs and future inflation. We cannot predict whether impairment charges may be required in the future. If natural gas, NGLs and oil prices decrease or drilling efforts are unsuccessful, we may be required to record additional impairments. For additional information regarding proved property impairments, see Note 12. We evaluate our unproved property investment periodically for impairment. The majority of these costs generally relate to the acquisition of leasehold costs. The costs are capitalized and evaluated (at least quarterly) as to recoverability, based on changes brought about by economic factors and potential shifts in business strategy employed by management. Impairment of a significant portion of our unproved properties is assessed and amortized on an aggregate basis based on our average holding period, expected forfeiture rate and anticipated drilling success. Impairment of individually significant unproved property is assessed on a property-by-property basis considering a combination of time, geologic and engineering factors. In certain circumstances, our future plans to develop acreage may accelerate our impairment. Unproved properties had a net book value of $2.6 billion as of December 31, 2017 compared to $2.9 billion in 2016. We have recorded abandonment and impairment expense related to unproved properties of $269.7 million in the year ended December 31, 2017 compared to $30.1 million in 2016 and $47.6 million in 2015. Dispositions . Proceeds from the disposal of natural gas and oil producing properties that are part of an amortization base are credited to the net book value of the amortization group with no immediate effect on income. However, gain or loss is recognized if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the amortization base. Dispositions are accounted for as a sale of assets. For additional information regarding our dispositions, see Note 3. Acquisitions . Acquisitions of proved properties are accounted for as either a business combination or an asset acquisition and, accordingly, the results of operations are included in the accompanying consolidated statements of operations from the closing date of the acquisition. In a business combination, purchase prices are allocated to acquired assets and assumed liabilities based on their estimated fair value at the time of the acquisition. In an asset acquisition, fair value is assigned to the assets acquired. In the past, acquisitions have been funded with internal cash flow, bank borrowings and the issuance of debt and equity securities. For additional information regarding our acquisitions, see Note 3. |
Other Property and Equipment | Other Property and Equipment Other property and equipment includes assets such as buildings, furniture and fixtures, field equipment, leasehold improvements and data processing and communication equipment. These items are generally depreciated by individual components on a straight-line basis over their economic useful life, which is generally from three to ten years. Leasehold improvements are amortized over the lesser of their economic useful lives or the underlying terms of the associated leases. Depreciation expense was $7.7 million in the year ended December 31, 2017 compared to $8.4 million in the year ended December 31, 2016 and $11.9 million in the year ended December 31, 2015. |
Other Assets | Other Assets Other assets at December 31, 2017 include $67.1 million of marketable securities held in our deferred compensation plans and $9.6 million of other investments including surface acreage. Other assets at December 31, 2016 include $61.7 million of marketable securities held in our deferred compensation plans and $10.6 million of other investments including surface acreage. |
Stock-based Compensation Arrangements | Stock-based Compensation Arrangements We account for stock-based compensation under the fair value method of accounting. We grant various types of stock-based awards including restricted stock and performance-based awards. The fair value of our restricted stock awards and our performance-based awards (where the performance condition is based on internal performance metrics) is based on the market value of our common stock on the date of grant. The fair value of our performance-based awards where the performance condition is based on market conditions is estimated using a Monte Carlo simulation method. We recognize stock-based compensation expense on a straight-line basis over the requisite service period for the entire award. The expense we recognize is net of estimated forfeitures. We estimate our forfeiture rate based on prior experience and adjust it as circumstances warrant. If actual forfeitures are different than expected, adjustments to recognize expense may be required in future periods. To the extent possible, we limit the amount of shares to be issued for these awards by satisfying tax withholding requirements with cash. All awards have been issued at prevailing market prices at the time of grant and the vesting of these awards is based on an employee’s continued employment with us, with the exception of employment termination due to death, disability or retirement. For additional information regarding stock-based compensation, see Note 13. |
Derivative Financial Instruments and Hedging | Derivative Financial Instruments and Hedging All of our derivative instruments are issued to manage the price risk attributable to our expected natural gas, NGLs and oil production. While there is risk that the financial benefit of rising natural gas, NGLs and oil prices may not be captured, we believe the benefits of stable and predictable cash flow are more important. Among these benefits are more efficient utilization of existing personnel and planning for future staff additions, the flexibility to enter into long-term projects requiring substantial committed capital, smoother and more efficient execution of our ongoing development drilling and production enhancement programs, more consistent returns on invested capital and better access to bank and other capital markets. All unsettled derivative instruments are recorded in the accompanying consolidated balance sheets as either an asset or a liability measured at their fair value. In most cases, our derivatives are reflected on our consolidated balance sheets on a net basis by brokerage firm when they are governed by master netting agreements. Changes in a derivative’s fair value are recognized in earnings. Cash flows from derivative contract settlements are reflected in operating activities in the accompanying consolidated statements of cash flows. All realized and unrealized gains and losses on derivatives are accounted for using the mark-to-market accounting method. We recognize all unrealized and realized gains and losses related to these contracts in each period in derivative fair value in the accompanying consolidated statements of operations. Certain of our derivatives are swaps where we receive a fixed price for our production and pay market prices to the counterparty. We also have collars which establish a minimum floor price and a predetermined ceiling price. At times, we have also entered into basis swap agreements. The price we receive for our natural gas production can be more or less than the NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors; therefore, we have entered into natural gas basis swap agreements that effectively fix our basis adjustments. We have also entered into propane basis swaps which lock in the differential between Mont Belvieu and international propane indexes. In third quarter 2017, we entered into combined natural gas derivative instruments containing a fixed price swap and a sold option to extend or double the volume (which we refer to as a swaption). The swap price is a fixed price determined at the time of the swaption contract. If the option is exercised, the contract will become a swap treated consistently with our fixed-price swaps. For additional information regarding our derivatives, see Note 11. From time to time, we may enter into derivative contracts and pay or receive premium payments at the inception of the derivative contract which represent the fair value of the contract at its inception. These amounts would be included within the net derivative asset or liability on our consolidated balance sheets. The amounts paid or received for derivative premiums reduce or increase the amount of gains and losses that are recorded in the earnings each period as the derivative contracts settle. During 2017, we did not modify any existing derivative contracts. |
Concentrations of Credit Risk | Concentrations of Credit Risk As of December 31, 2017, our primary concentrations of credit risk are the risks of collecting accounts receivable and the risk of counterparties’ failure to perform under derivative contracts. Most of our receivables are from a diverse group of companies, including major energy companies, pipeline companies, local distribution companies, financial institutions, commodity traders and end-users in various industries and such receivables are generally unsecured. To manage risks of collecting accounts receivable, we monitor our counterparties’ financial strength and/or credit ratings and where we deem necessary, we obtain parent company guarantees, prepayments, letters of credit or other credit enhancements to reduce risk of loss. Our allowance for doubtful accounts was $7.1 million at December 31, 2017 compared to $5.6 million at December 31, 2016. For the years ended December 31, 2017, 2016 and 2015, we had one customer that accounted for 10% or more of total natural gas, NGLs and oil sales. We believe that the loss of any one customer would not have an adverse effect on our ability to sell our natural gas, NGLs and oil production. We have executed International Swap Dealers Association Master Agreements (“ISDA Agreements”) with counterparties for the purpose of entering into derivative contracts. To manage counterparty risk associated with our derivatives, we select and monitor counterparties based on assessment of their financial strength and/or credit ratings. We may also limit the level of exposure with any single counterparty. Additionally, the terms of our ISDA Agreements provide us and our counterparties with netting rights such that we may offset payables against receivables with a counterparty under separate derivative contracts. Our ISDA Agreements also generally contain set-off rights such that, upon the occurrence of defined acts of default by either us or a counterparty to a derivative contract, the non-defaulting party may set-off receivables owed under all derivative contracts against payables from other agreements with that counterparty. The majority of our derivative contracts have no margin requirements or collateral provisions that would require us to fund or post additional collateral prior to the scheduled cash settlement date. At December 31, 2017, our derivative counterparties included nineteen financial institutions and commodity traders, of which all but five are secured lenders in our bank credit facility. At December 31, 2017, our net derivative asset includes a payable to the counterparties not included in our bank credit facility totaling $28.2 million. In determining fair value of derivative assets, we evaluate the risk of non-performance and incorporate factors such as amounts owed under other agreements permitting set-off, as well as pricing of credit default swaps for the counterparty. Net derivative liabilities are determined in part by using our market based credit spread to incorporate our theoretical risk of non-performance. |
Asset Retirement Obligations | Asset Retirement Obligations The fair value of asset retirement obligations is recognized in the period they are incurred, if a reasonable estimate of fair value can be made. Asset retirement obligations primarily relate to the abandonment of natural gas and oil producing facilities and include costs to dismantle and relocate or dispose of production platforms, gathering systems, wells and related structures. Estimates are based on historical experience of plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates of the cost to plug and abandon the wells in the future and federal and state regulatory requirements. We are required to operate and maintain our natural gas pipeline systems and intend to do so as long as supply and demand for natural gas exists, which we expect for the foreseeable future. Therefore, these assets have indeterminate lives. Depreciation of capitalized asset retirement costs will generally be determined on a units-of-production basis while accretion to be recognized will escalate over the life of the producing assets. See Note 9 for additional information. |
Environmental Costs | Environmental Costs Environmental expenditures are capitalized if the costs mitigate or prevent future contamination or if the costs improve environmental safety or efficiency of the existing assets. Expenditures that relate to an existing condition caused by past operations that have no future economic benefits are expensed. |
Deferred Taxes | Deferred Taxes Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to the differences between the financial statement carrying amounts of assets and liabilities and their tax bases as reported in our filings with the respective taxing authorities. Deferred tax assets are recorded when it is more likely than not that they will be realized. The realization of deferred tax assets is assessed periodically based on several interrelated factors. These factors may include our expectation to generate sufficient taxable income in the periods before tax credits and operating loss carryforwards expire. All deferred taxes are classified as long-term on the balance sheet. |
New Accounting Pronouncements | New Accounting Pronouncements Recently Adopted In January 2017, an accounting standards update was issued that eliminates the requirements to calculate the implied fair value of goodwill to measure any goodwill impairment charge. Instead, entities will record an impairment charge based on the excess of a reporting unit’s carrying amount over its fair value. This standard is effective for annual periods beginning after December 15, 2019 and should be applied on a prospective basis. Early adoption is permitted for any goodwill impairment tests performed in first quarter 2017 or later. We elected to adopt this accounting standards update in first quarter 2017. The adoption did not have a significant impact on our consolidated results of operations, financial position, cash flows or financial disclosures; however, this standard did change our policy for our goodwill impairment assessment by eliminating the requirement to calculate the implied fair value of goodwill. In March 2016, an accounting standards update was issued that simplifies several aspects of the accounting for share-based payment award transactions. Among other things, this new guidance will require all income tax effects of share-based awards to be recognized in the statement of operations when the awards vest or are settled, will allow an employer to repurchase more of an employee’s shares for tax withholding purposes than it can today without triggering liability accounting and will allow a policy election to account for forfeitures as they occur. This new standard will be effective for annual periods beginning after December 15, 2016. Early adoption was permitted. We elected to early adopt this accounting standards update in fourth quarter 2016 which required us to reflect any adjustments as of January 1, 2016, the beginning of the annual period that included the interim period of adoption. The following summarizes the impact of this new standard on our consolidated financial statements: Income taxes - Upon adoption of this standard, all excess tax benefits and tax deficiencies (including tax benefits of dividends on share-based payment awards) are recognized as income tax expense or benefit in our consolidated statements of operations. The tax effects of exercised or vested awards are treated as discrete items in the reporting period in which they occur. Adoption of this new standard resulted in the recognition of an excess tax deficiency in our provision for income taxes rather than paid-in capital of $2.1 million for the year ended December 31, 2016 and affected our previously reported first quarter 2016 results as follows (in thousands, except per share data): For The Three Months Ended March 31, 2016 As Reported As Adjusted Statements of Operations: Income tax benefit $ (44,038 ) $ (41,976 ) Net loss (91,710 ) (93,772 ) Basic earnings per share (0.55 ) (0.56 ) Diluted earnings per share (0.55 ) (0.56 ) In addition, we have recorded a cumulative-effect adjustment to retained earnings (deficit) and reduced our deferred tax liability for $101.1 million for previously unrecognized tax benefits due to our NOL position. Forfeitures - Prior to adoption, share-based compensation expense was recognized on a straight line basis, net of estimated forfeitures, such that expense was recognized only for share-based awards that are expected to vest. We have elected to continue to estimate forfeitures. Statements of cash flows - The presentation requirements for cash flows related to employee taxes paid for withheld shares will be adjusted retrospectively. These cash flows have historically been presented as an operating activity. Upon adoption of this new standard, these cash outflows will be classified as a financing activity. Prior periods have been adjusted as follows (in thousands): As Reported As Adjusted Net cash provided from operating activities Net cash provided from operating activities Year ended 2015 $ 683,700 $ 691,402 Year ended 2014 954,135 974,353 Year ended 2013 743,538 757,373 Three months ended March 31, 2016 87,424 90,785 Six months ended June 30, 2016 169,604 173,201 Nine months ended September 30, 2016 202,037 205,837 As Reported As Adjusted Net cash (used in) provided from financing activities Net cash (used in) provided from financing activities Year ended 2015 $ (464,905 ) $ (472,607 ) Year ended 2014 291,421 271,203 Year ended 2013 239,994 226,159 Three months ended March 31, 2016 (72,473 ) (75,834 ) Six months ended June 30, 2016 (95,411 ) (99,008 ) Nine months ended September 30, 2016 (35,229 ) (39,029 ) In July 2015, an accounting standards update was issued that requires an entity to measure inventory at the lower of cost or net realizable value. This excludes inventory measured using LIFO or the retail inventory method. This standard was effective for us in first quarter 2017 and was applied prospectively. Adoption of this standard did not have an impact on our consolidated results of operations, financial position or cash flows. In August 2016, an accounting standards update was issued that clarifies how entities classify certain cash receipts and cash payments on the statement of cash flows. The guidance is effective for us in first quarter 2018 and should be applied retrospectively with early adoption permitted. We adopted this new standard in the fourth quarter 2017 on a retrospective basis. Adoption of this standard did not have an impact on our consolidated cash flow statement presentation. In January 2017, an accounting standards update was issued which clarifies the definition of a business. This new standard is effective for us in first quarter 2018 with early adoption permitted. We adopted this new standard in the fourth quarter 2017. Adoption of this standard did not have a significant impact on our consolidated results of operations, financial position or cash flows. Accounting Pronouncements Not Yet Adopted In May 2014, an accounting standards update was issued that supersedes the existing revenue recognition requirements. This standard includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. Among other things, the standard also eliminates industry-specific revenue guidance, requires enhanced disclosures about revenue, provides guidance for transactions that were not previously addressed comprehensively and improves guidance for multiple-element arrangements. This standard is effective for us in first quarter 2018 and we expect to adopt the new standard using the modified retrospective method of adoption. We have utilized a bottom-up approach to analyze the impact of the new standard on our contracts by reviewing our current accounting policies and practices to identify potential differences that would result from applying the requirements of the new standard to our revenue contracts and the impact of adopting this standards update on our total revenues, operating income (loss) and our consolidated balance sheet. As of December 31, 2017, we have substantially completed our evaluation of our sources of revenue and the impact of this accounting standards update on our consolidated results of operations, financial position, cash flows and financial disclosures, in addition to developing and implementing any process or control changes necessary. We do not expect to record a cumulative effect adjustment on date of adoption; however, our financial statement presentation related to revenue received from certain gas processing contracts will change. Based on current accounting guidance, certain of our gas processing contracts are reported in revenue at the net price (net of processing costs) we receive. Upon adoption of this accounting standards update, these contracts will be reported as a gross price received at a delivery point and additional transportation, marketing and processing expense. In February 2016, an accounting standards update was issued that requires an entity to recognize a right-of-use asset and lease liability for all leases with terms of more than twelve months. Classification of leases as either a finance or operating lease will determine the recognition, measurement and presentation of expenses. This accounting standards update also requires certain quantitative and qualitative disclosures about leasing arrangements. This standards update is effective for us in first quarter 2019 and should be applied using a modified retrospective approach for leases that exist or are entered into after the beginning of the earliest comparative period in the financial statements, with early adoption is permitted. We are evaluating the provisions of this accounting standards update and assessing the impact it will have on our consolidated results of operations, financial position or cash flows but based on our preliminary review of the update, we expect that we will have operating leases with durations greater than twelve months on the balance sheet. As we continue to evaluate and implement the standards update, we will provide additional information about the expected financial impact at a future date. In June 2016, an accounting standards update was issued that changes the impairment model for trade receivables, net investments in leases, debt securities, loans and certain other instruments. The standards update requires the use of a forward-looking “expected loss” model as opposed to the current “incurred loss” model. This standards update is effective for us in first quarter 2020 and will be adopted on a modified retrospective basis though a cumulative-effect adjustment to retained earnings as of the beginning of the adoption period. Early adoption is permitted starting January 2019. We are evaluating the provisions of this accounting standards update and assessing the impact, if any, it may have on our consolidated results of operations, financial position or cash flows. In March 2017, an accounting standards update was issued which provides additional guidance on the presentation of net benefit cost in the statement of operations. Employers will present the service cost component of net periodic benefit cost in the same consolidated results of operations line item as other employee compensation costs rising from services rendered during the period. This new standards update will be effective for us for annual reporting periods in first quarter 2018, with early adoption permitted. We anticipate this standard will not have a material impact on our financial statements and related disclosures. In May 2017, an accounting standards update was issued which clarifies what constitutes a modification of a share-based award. This standards update is intended to provide clarity and reduce both diversity in practice and cost and complexity to a change to the terms or conditions of a share-based payment award. This standards update will be effective for us in first quarter 2018 and we do not anticipate it will have a material impact on our financial position or consolidated results of operations. |
Summary of Significant Accoun28
Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Policies [Abstract] | |
Summary of Adjustments to Quarterly Data Resulting from Adoption of New Standard | Income taxes - Upon adoption of this standard, all excess tax benefits and tax deficiencies (including tax benefits of dividends on share-based payment awards) are recognized as income tax expense or benefit in our consolidated statements of operations. The tax effects of exercised or vested awards are treated as discrete items in the reporting period in which they occur. Adoption of this new standard resulted in the recognition of an excess tax deficiency in our provision for income taxes rather than paid-in capital of $2.1 million for the year ended December 31, 2016 and affected our previously reported first quarter 2016 results as follows (in thousands, except per share data): For The Three Months Ended March 31, 2016 As Reported As Adjusted Statements of Operations: Income tax benefit $ (44,038 ) $ (41,976 ) Net loss (91,710 ) (93,772 ) Basic earnings per share (0.55 ) (0.56 ) Diluted earnings per share (0.55 ) (0.56 ) Statements of cash flows - The presentation requirements for cash flows related to employee taxes paid for withheld shares will be adjusted retrospectively. These cash flows have historically been presented as an operating activity. Upon adoption of this new standard, these cash outflows will be classified as a financing activity. Prior periods have been adjusted as follows (in thousands): As Reported As Adjusted Net cash provided from operating activities Net cash provided from operating activities Year ended 2015 $ 683,700 $ 691,402 Year ended 2014 954,135 974,353 Year ended 2013 743,538 757,373 Three months ended March 31, 2016 87,424 90,785 Six months ended June 30, 2016 169,604 173,201 Nine months ended September 30, 2016 202,037 205,837 As Reported As Adjusted Net cash (used in) provided from financing activities Net cash (used in) provided from financing activities Year ended 2015 $ (464,905 ) $ (472,607 ) Year ended 2014 291,421 271,203 Year ended 2013 239,994 226,159 Three months ended March 31, 2016 (72,473 ) (75,834 ) Six months ended June 30, 2016 (95,411 ) (99,008 ) Nine months ended September 30, 2016 (35,229 ) (39,029 ) |
Dispositions and Acquisitions (
Dispositions and Acquisitions (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Business Combinations [Abstract] | |
Summary of Final Allocation of Total Purchase Price | Purchase price: Shares of Range common stock issued to Memorial stockholders 77,042,749 Range common stock price per share at September 15, 2016 (close) $ 39.37 Total purchase price $ 3,033,173 Plus fair value of liabilities assumed by Range: Accounts payable $ 55,624 Other current liabilities 108,367 Long-term debt 1,204,449 Deferred taxes 547,706 Other long-term liabilities 77,223 Total purchase price plus liabilities assumed $ 5,026,542 Fair value of Memorial assets: Cash and equivalents $ 7,180 Other current assets 99,969 Derivative instruments 152,994 Natural gas and oil properties: Proved property 1,122,311 Unproved property 1,999,187 Other property and equipment 3,579 Goodwill (a) 1,641,197 Other 125 Total asset value $ 5,026,542 (a) |
Summary of Pro Forma Financial Information | The pro forma condensed combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the MRD Merger taken place on January 1, 2015. In addition, the pro forma financial information below is not intended to be a projection of future results (in thousands, except per share amounts). Year Ended December 31, 2016 2015 Revenues $ 1,334,290 $ 2,253,368 Net loss $ (591,121 ) $ (556,164 ) Loss per share: Basic $ (2.42 ) $ (2.28 ) Diluted $ (2.42 ) $ (2.28 ) |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | |
Reconciliation Between Statutory Federal Income Tax Rate and Effective Income Tax | Our income tax benefit was $251.0 million for the year ended December 31, 2017 compared to $280.8 million in 2016 and $338.7 million in 2015. Reconciliation between the statutory federal income tax rate and our effective income tax rate is as follows: Year Ended December 31, 2017 2016 2015 Federal statutory tax rate 35.0 % 35.0 % 35.0 % Federal rate change (406.7 ) — — State (0.7 ) 3.0 4.3 State rate and law change (1.3 ) 1.0 (0.2 ) Non-deductible executive compensation 0.7 (0.2 ) (0.1 ) Non-deductible MRD transaction costs — (0.6 ) — Valuation allowances 36.8 (2.5 ) (6.8 ) Equity compensation 30.2 (0.7 ) — Other 0.3 — — Consolidated effective tax rate (305.7 %) 35.0 % 32.2 % |
Income Tax (Benefit) Expense Attributable to Income Before Income Taxes | Income tax (benefit) expense attributable to income before income taxes consists of the following (in thousands): 2017 2016 2015 Current Deferred Total Current Deferred Total Current Deferred Total U.S. federal $ — $ (302,507 ) $ (302,507 ) $ — $ (266,105 ) $ (266,105 ) $ — $ (328,257 ) $ (328,257 ) U.S. state and local 17 51,464 51,481 98 (14,743 ) (14,645 ) 29 (10,449 ) (10,420 ) Total $ 17 $ (251,043 ) $ (251,026 ) $ 98 $ (280,848 ) $ (280,750 ) $ 29 $ (338,706 ) $ (338,677 ) |
Significant Components of Deferred Tax Assets and Liabilities | Significant components of deferred tax assets and liabilities are as follows: December 31, 2017 2016 (in thousands) Deferred tax assets: Net operating loss carryforward $ 413,672 $ 478,203 Deferred compensation 24,704 50,808 Equity compensation 5,269 29,528 AMT credits and other credits 7,264 13,644 Asset retirement obligation 69,398 99,000 Cumulative mark-to-market loss — 73,404 Other 18,806 39,922 Valuation allowances: Federal (31,308 ) (48,750 ) State, net of federal benefit (93,826 ) (58,424 ) Total deferred tax assets 413,979 677,335 Deferred tax liabilities: Depreciation, depletion and investments (1,105,494 ) (1,619,922 ) Cumulative mark-to-market gain (1,841 ) — Other — (756 ) Total deferred tax liabilities (1,107,335 ) (1,620,678 ) Net deferred tax liability $ (693,356 ) $ (943,343 ) |
Changes in Deferred Tax Asset Valuation Allowances | The changes in our deferred tax asset valuation allowances are as follows (in thousands): 2017 2016 2015 Balance at the beginning of the year $ (107,174 ) $ (87,623 ) $ (16,599 ) Charged to provision for income taxes: State net operating loss carryforwards (11,612 ) (17,374 ) (30,457 ) Federal net operating carryforwards 15,385 (1,100 ) (42,500 ) Other state valuation allowances (23,790 ) 500 (1,050 ) Other federal valuation allowances (247 ) (477 ) (511 ) Rabbi trust valuation allowance 2,304 (1,066 ) 3,494 Other — (34 ) — Balance at the end of the year $ (125,134 ) $ (107,174 ) $ (87,623 ) |
Net Income (Loss) Per Common 31
Net Income (Loss) Per Common Share (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Earnings Per Share [Abstract] | |
Computations of Basic and Diluted Income (Loss ) Per Common Share | Basic income or loss per share attributable to common stockholders is computed as (i) income or loss attributable to common stockholders (ii) less income allocable to participating securities (iii) divided by weighted average basic shares outstanding. Diluted income or loss per share attributable to common stockholders is computed as (i) basic income or loss attributable to common stockholders (ii) plus diluted adjustments to income allocable to participating securities (iii) divided by weighted average diluted shares outstanding. Diluted net income (loss) per share is calculated under both the two class method and the treasury stock method and the more dilutive of the two calculations is presented. The following table sets forth a reconciliation of net income or loss to basic income or loss attributable to common stockholders and to diluted income or loss attributable to common stockholders (in thousands except per share amounts): Year Ended December 31, 2017 2016 2015 Net income (loss), as reported $ 333,146 $ (521,388 ) $ (713,685 ) Participating basic earnings (a) (3,751 ) (223 ) (450 ) Basic net income (loss) attributed to common stockholders 329,395 (521,611 ) (714,135 ) Reallocation of participating earnings (a) 5 — — Diluted net income (loss) attributed to common stockholders $ 329,400 $ (521,611 ) $ (714,135 ) Net income (loss) per common share: Basic $ 1.34 $ (2.75 ) $ (4.29 ) Diluted $ 1.34 $ (2.75 ) $ (4.29 ) (a) Restricted stock Liability Awards represent participating securities because they participate in nonforfeitable dividends or distributions with common equity owners. Income allocable to participating securities represents the distributed and undistributed earnings attributable to the participating securities. Participating securities, however, do not participate in undistributed net losses. |
Basic Weighted Average Common Shares Outstanding to Diluted Weighted Average Common Shares Outstanding | The following table provides a reconciliation of basic weighted average common shares outstanding to diluted weighted average common shares outstanding (in thousands): Year Ended December 31, 2017 2016 2015 Denominator: Weighted average common shares outstanding – basic (1) 245,091 189,868 166,389 Effect of dilutive securities: Director and employee restricted stock and performance-based equity awards 367 — — Weighted average common shares outstanding – diluted 245,458 189,868 166,389 (1) Includes common stock issued in connection with the exchange of 77.0 million shares for all outstanding Memorial common stock on September 16, 2016. |
Suspended Exploratory Well Co32
Suspended Exploratory Well Costs (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Extractive Industries [Abstract] | |
Suspended Exploratory Well Costs | The following table reflects the changes in capitalized exploratory well costs for the years ended December 31, 2017, 2016 and 2015 (in thousands, except for number of projects): 2017 2016 2015 Balance at beginning of period $ 7,412 $ 4,161 $ 2,996 Additions to capitalized exploratory well costs pending the determination of proved reserves 1,388 9,128 1,165 Reclassifications to wells, facilities and equipment based on determination of proved reserves — (5,877 ) — Capitalized exploratory well costs charged to expense (8,800 ) — — Balance at end of period — 7,412 4,161 Less exploratory well costs that have been capitalized for a period of one year or less — (7,412 ) (1,165 ) Capitalized exploratory well costs that have been capitalized for a period greater than one year $ — $ — $ 2,996 Number of projects that have exploratory well costs that have been capitalized for a period greater than one year — — 1 |
Indebtedness (Tables)
Indebtedness (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Debt Disclosure [Abstract] | |
Debt Outstanding | We had the following debt outstanding as of the dates shown below (in thousands) (bank debt interest rate at December 31, 2017 is shown parenthetically). The expenses of issuing debt are capitalized and included as a reduction to debt in the accompanying consolidated balance sheets. These costs are amortized over the expected life of the related instruments. When debt is retired before maturity, or modifications significantly change the cash flows, the related unamortized costs are expensed. No interest was capitalized during 2017, 2016, and 2015. December 31, 2017 December 31, 2016 Bank debt (3.0%) $ 1,211,000 $ 882,000 Senior notes 4.875% senior notes due 2025 750,000 750,000 5.00% senior notes due 2023 741,531 741,531 5.00% senior notes due 2022 580,032 580,032 5.75% senior notes due 2021 475,952 475,952 5.875% senior notes due 2022 (a) 329,244 329,244 Other senior notes due 2022 (b) 590 1,090 Total senior notes 2,877,349 2,877,849 Senior subordinated notes 5.00% senior subordinated notes due 2023 7,712 7,712 5.00% senior subordinated notes due 2022 19,054 19,054 5.75% senior subordinated notes due 2021 22,214 22,214 Total senior subordinated notes 48,980 48,980 Total debt 4,137,329 3,808,829 Unamortized premium 6,027 7,241 Unamortized debt issuance costs (34,550 ) (42,553 ) Total debt net of debt issuance costs $ 4,108,806 $ 3,773,517 (a) (b) |
Summary of Senior Notes Principal Subsequent to Debt Exchange | In September 2016, in conjunction with MRD Merger, we issued $329.2 million senior unsecured 5.875% notes due 2022 (the “5.875% Notes”) (See also Senior Notes Exchange and Cash Tender Offer Senior Subordinated Notes Exchange Principal Amount 5.00% senior notes due 2023 $ 741,531 5.00% senior notes due 2022 $ 580,032 5.75% senior notes due 2021 $ 475,952 |
Summary of Debt Exchange Offer to Exchange Validly Tendered and Accepted Range Senior Subordinated Notes | On September 16, 2016, we also completed our debt exchange offer to exchange all validly tendered and accepted Range senior subordinated notes as detailed below (in thousands): Existing Note New Note Principal Amount of Notes Validly Tendered (1) Approximate Percentage Validly Tendered 5.00% senior subordinated notes due 2023 5.00% senior notes due 2023 $742,291 99.0% 5.00% senior subordinated notes due 2022 5.00% senior notes due 2022 $580,946 96.8% 5.75% senior subordinated notes due 2021 5.75% senior notes due 2021 $477,786 95.6% (1) |
Schedule for Long-Term Debt Outstanding | The following is the principal maturity schedule for our long-term debt outstanding as of December 31, 2017 (in thousands): Year Ended 2018 $ — 2019 1,211,000 2020 — 2021 498,166 2022 928,920 Thereafter 1,499,243 $ 4,137,329 |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligation | The following is a reconciliation of our liability for plugging and abandonment costs as of December 31, 2017 and 2016 (in thousands): 2017 2016 Beginning of period $ 257,943 $ 264,137 Liabilities incurred 7,724 2,694 Acquisitions — 21,900 Liabilities settled (7,965 ) (11,511 ) Disposition of wells (8,078 ) (10,540 ) Accretion expense 14,711 18,021 Change in estimate 12,520 (26,758 ) End of period 276,855 257,943 Less current portion (6,327 ) (7,271 ) Long-term asset retirement obligations $ 270,528 $ 250,672 |
Capital Stock (Tables)
Capital Stock (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Equity [Abstract] | |
Capital Stock | The following is a schedule of changes in the number of common shares outstanding since the beginning of 2015: Year Ended December 31, 2017 2016 2015 Beginning balance 247,144,356 169,316,460 168,628,177 MRD Merger — 77,042,749 — Stock options/SARs exercised — — 77,002 Restricted stock grants 539,096 490,609 335,103 Restricted stock units vested 344,937 266,541 252,507 Performance stock units issued 85,461 — — Shares retired — (739 ) — Treasury shares 15,580 28,736 23,671 Ending balance 248,129,430 247,144,356 169,316,460 |
Derivative Activities (Tables)
Derivative Activities (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |
Derivative Volumes Hedged and Average Hedge Prices | The following table sets forth the derivative volumes by year as of December 31, 2017, excluding our basis and freight swaps which are discussed separately below: Period Contract Type Volume Hedged Weighted Natural Gas 2018 Swaps 794,822 Mmbtu/day $ 3.13 2019 Swaps 12,329 Mmbtu/day $ 3.01 January − March 2018 Collars 60,000 Mmbtu/day $ 3.40-$ 3.76 April – December 2018 Swaptions 307,500 Mmbtu/day $ 2.98 (1) 2019 Swaptions 85,000 Mmbtu/day $ 2.97 (1 ) Crude Oil 2018 Swaps 8,995 bbls/day $ 53.30 2019 Swaps 4,746 bbls/day $ 52.81 NGLs (C2-Ethane) 2018 Swaps 250 bbls/day $ 0.29/gallon NGLs (C3-Propane) 2018 Swaps 10,362 bbls/day $ 0.68/gallon 2018 Collars 2,000 bbls/day $ 0.90-$ 1.05/gallon NGLs (NC4-Normal Butane) 2018 Swaps 4,621 bbls/day $ 0.81/gallon NGLs (C5-Natural Gasoline) 2018 Swaps 4,713 bbls/day $ 1.19/gallon 2019 Swaps 1,000 bbls/day $ 1.24/gallon (1) |
Combined Fair Value of Derivatives, by Consolidated Balance Sheets | The combined fair value of derivatives included in the accompanying consolidated balance sheets as of December 31, 2017 and 2016 is summarized below (in thousands). As of December 31, 2017, we are conducting derivative activities with nineteen counterparties, of which all but five are secured lenders in our bank credit facility. We believe all of these counterparties are acceptable credit risks. At times, such risks may be concentrated with certain counterparties. The credit worthiness of our counterparties is subject to periodic review. The assets and liabilities are netted where derivatives with both gain and loss positions are held by a single counterparty and we have master netting arrangements. December 31, 2017 Gross Amounts of Recognized Assets Gross Amounts Offset in the Balance Sheet Net Amounts of Assets Presented in the Balance Sheet Derivative assets: Natural gas –swaps $ 87,794 $ (4,106 ) $ 83,688 –swaptions 18,817 (8,103 ) 10,714 –basis swaps 1,815 (6,673 ) (4,858 ) –collars 3,039 (500 ) 2,539 Crude oil –swaps 2 (7,928 ) (7,926 ) NGLs –C2 ethane swaps 57 — 57 –C3 propane swaps — (12,556 ) (12,556 ) –C3 propane collars 85 (85 ) — –C3 propane spread swaps 12,762 (12,762 ) — –NC4 butane swaps — (6,051 ) (6,051 ) –C5 natural gasoline swaps — (6,727 ) (6,727 ) Freight –swaps 276 (276 ) — $ 124,647 $ (65,767 ) $ 58,880 December 31, 2017 Gross Amounts of Recognized (Liabilities) Gross Amounts Net Amounts of (Liabilities) Presented in the Balance Sheet Derivative (liabilities): Natural gas –swaps $ (216 ) $ 4,106 $ 3,890 –swaptions (12,283 ) 8,103 (4,180 ) –basis swaps (9,580 ) 6,673 (2,907 ) –collars — 500 500 Crude oil –swaps (24,726 ) 7,928 (16,798 ) NGLs –C3 propane swaps (34,325 ) 12,556 (21,769 ) –C3 propane collars — 85 85 –C3 propane spread swaps (13,983 ) 12,762 (1,221 ) –NC4 butane swaps (11,188 ) 6,051 (5,137 ) –C5 natural gasoline swaps (13,488 ) 6,727 (6,761 ) Freight –swaps — 276 276 $ (119,789 ) $ 65,767 $ (54,022 ) December 31, 2016 Gross Amounts of Recognized Assets Gross Amounts Offset in the Balance Sheet Net Amounts of Assets Presented in the Balance Sheet Derivative assets: Natural gas –swaps $ 13,213 $ (11,425 ) $ 1,788 –basis swaps 12,535 (9,437 ) 3,098 –collars 6,298 (6,298 ) — –puts 18,159 (15,429 ) 2,730 Crude oil –swaps 9,356 (3,489 ) 5,867 NGLs –C2 ethane swaps 53 (53 ) — –C3 propane spread swaps 17,396 (17,396 ) — –NC4 butane swaps 4 (4 ) — Freight –swaps 65 (65 ) — $ 77,079 $ (63,596 ) $ 13,483 December 31, 2016 Gross Amounts of Recognized (Liabilities) Gross Amounts Net Amounts of (Liabilities) Presented in the Balance Sheet Derivative (liabilities): Natural gas –swaps $ (158,359 ) $ 11,425 $ (146,934 ) –basis swaps (687 ) 9,437 8,750 –collars (2,625 ) 6,298 3,673 –puts — 15,429 15,429 –calls (1,041 ) — (1,041 ) Crude oil –swaps (13,206 ) 3,489 (9,717 ) NGLs –C2 ethane swaps (1,008 ) 53 (955 ) –C3 propane swaps (32,437 ) — (32,437 ) –C3 propane spread swaps (18,138 ) 17,396 (742 ) –NC4 butane swaps (13,419 ) 4 (13,415 ) –C5 natural gasoline swaps (12,176 ) — (12,176 ) Freight –swaps — 65 65 $ (253,096 ) $ 63,596 $ (189,500 ) |
Effects of Derivatives on Consolidated Statements of Operations | The effects of our derivatives on our consolidated statements of operations for the last three years are summarized below (in thousands). Year Ended December 31, Derivative Fair Value Income (Loss) 2017 2016 2015 Commodity Swaps $ 181,095 $ (265,466 ) $ 398,020 Swaptions 6,534 — — Re-purchased swaps — — 851 Collars 18,132 (6,926 ) 16,539 Basis swaps (4,647 ) 29,154 954 Puts 10,929 (18,201 ) — Calls 987 (18 ) — Freight swaps 320 66 — Total $ 213,350 $ (261,391 ) $ 416,364 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Fair Value Disclosures [Abstract] | |
Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value | We use a market approach for our recurring fair value measurements and endeavor to use the best information available. Accordingly, valuation techniques that maximize the use of observable impacts are favored. The following tables present the fair value hierarchy table for assets and liabilities measured at fair value, on a recurring basis (in thousands): Fair Value Measurements at December 31, 2017 Using: Quoted Prices Significant Significant Total Trading securities held in the deferred compensation plans $ 67,117 $ — $ — $ 67,117 Derivatives –swaps — 3,910 — 3,910 –collars — 3,039 85 3,124 –basis swaps — (9,025 ) 39 (8,986 ) –freight swaps — 276 — 276 –swaptions — — 6,534 6,534 Fair Value Measurements at December 31, 2016 Using: Quoted Prices Significant Significant Total Trading securities held in the deferred compensation plans $ 61,717 $ — $ — $ 61,717 Derivatives –swaps — (207,979 ) — (207,979 ) –collars — 3,673 — 3,673 –puts — 18,159 — 18,159 –calls — (1,041 ) — (1,041 ) –basis swaps — 11,106 — 11,106 –freight swaps — 65 — 65 |
Reconciliation of the Beginning and Ending Balances for Derivative Instruments Classified as Level 3 in the Fair Value Hierarchy | The following is a reconciliation of the beginning and ending balances for derivative instruments classified as Level 3 in the fair value hierarchy (in thousands): Year Ended December 31, 2017 Balance at the beginning of period $ — Total gains (losses): Included in earnings 6,658 Settlements received — Transfers in and/or out of Level 3 — Balance at end of period $ 6,658 |
Value of Assets Measured at Fair Value on Nonrecurring Basis | The following table presents the value of these assets measured at fair value on a nonrecurring basis at the time impairment was recorded (in thousands): Year Ended December 31, 2017 2016 2015 Fair Value Impairment Fair Value Impairment Fair Value Impairment Natural gas and oil properties $ 85,597 $ 63,679 $ 90,150 $ 43,040 $ 152,230 $ 590,174 |
Carrying Amounts and Fair Values of Financial Instruments | The following table presents the carrying amounts and the fair values of our financial instruments as of December 31, 2017 and 2016 (in thousands): December 31, 2017 December 31, 2016 Carrying Fair Carrying Fair Assets: Commodity swaps, options and basis swaps $ 58,880 $ 58,880 $ 13,483 $ 13,483 Marketable securities (a) 67,117 67,117 61,717 61,717 (Liabilities): Commodity swaps, options and basis swaps (54,022 ) (54,022 ) (189,500 ) (189,500 ) Bank credit facility (b) (1,211,000 ) (1,211,000 ) (882,000 ) (882,000 ) 5.75% senior notes due 2021 (b) (475,952 ) (493,872 ) (475,952 ) (496,180 ) 5.00% senior notes due 2022 (b) (580,032 ) (578,727 ) (580,032 ) (577,132 ) 5.875% senior notes due 2022 (b) (329,244 ) (339,200 ) (329,244 ) (343,648 ) Other senior notes due 2022 (b) (590 ) (591 ) (1,090 ) (1,104 ) 5.00% senior notes due 2023 (b) (741,531 ) (735,614 ) (741,531 ) (735,043 ) 4.875% senior notes due 2025 (b) (750,000 ) (733,755 ) (750,000 ) (724,688 ) 5.75% senior subordinated notes due 2021 (b) (22,214 ) (22,192 ) (22,214 ) (22,325 ) 5.00% senior subordinated notes due 2022 (b) (19,054 ) (18,741 ) (19,054 ) (18,387 ) 5.00% senior subordinated notes due 2023 (b) (7,712 ) (7,614 ) (7,712 ) (7,645 ) Deferred compensation plan (c) (114,414 ) (114,414 ) (139,580 ) (139,580 ) (a) Marketable securities, which are held in our deferred compensation plans, are actively traded on major exchanges. (b) The book value of our bank debt approximates fair value because of its floating rate structure. The fair value of our senior notes and our senior subordinated notes is based on end of period market quotes which are Level 2 inputs. (c) The fair value of our deferred compensation plan is updated at the closing price on the balance sheet date which is a Level 1 input. |
Stock-based Compensation Plans
Stock-based Compensation Plans (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Allocation of Stock-Based Compensation by Functional Category | The following table details the amount of stock-based compensation that is allocated to functional expense categories for each of the years in the three-year period ended December 31, 2017 (in thousands): 2017 (1) 2016 2015 Direct operating expense $ 2,060 $ 2,302 $ 2,780 Brokered natural gas and marketing expense 1,437 1,725 2,132 Exploration expense 2,742 2,298 2,985 General and administrative expense 74,873 49,293 49,687 Termination costs 1,664 — 217 Total $ 82,776 $ 55,618 $ 57,801 (1) Includes $30.8 million accelerated vesting of equity grants. |
Restricted Stock and Restricted Stock Units Outstanding | The following is a summary of the status of our non-vested restricted stock outstanding at December 31, 2017: Restricted Stock Restricted Stock Shares Weighted Shares Weighted Outstanding at December 31, 2014 360,415 $ 79.60 304,504 $ 80.33 Granted 587,711 52.29 343,397 55.92 Vested (480,253 ) 65.21 (330,870 ) 68.71 Forfeited (31,109 ) 64.73 (8,294 ) 74.22 Outstanding at December 31, 2015 436,764 59.74 308,737 65.80 Granted 973,491 28.51 540,128 35.92 Vested (525,617 ) 43.83 (374,328 ) 51.40 Forfeited (118,667 ) 42.60 (49,519 ) 40.33 Outstanding at December 31, 2016 765,971 33.62 425,018 43.48 Granted 888,326 32.61 543,438 25.91 Vested (698,563 ) 34.82 (908,912 ) 33.71 Forfeited (122,676 ) 32.91 (4,342 ) 31.10 Outstanding at December 31, 2017 833,058 $ 31.64 55,202 $ 32.26 |
Schedule of Share Based Payment Award Performance Stock Awards Valuation Assumptions | The following assumptions were used to estimate the fair value of PSUs granted during the years ended December 31, 2017, 2016 and 2015: Year Ended December 31, 2017 2017 2016 2015 Risk-free interest rate 1.49 % 0.94 % 1.02 % Expected annual volatility 44 % 49 % 33 % Grant date fair value per unit $ 26.26 $ 36.64 $ 56.78 |
Summary of SARs Outstanding and Exercisable | The following table shows information with respect to SARs outstanding and exercisable at December 31, 2017: Outstanding Exercisable Range of Exercise Prices Shares Weighted Weighted Average Exercise Price Shares Weighted Average Exercise Price $ 70.00–$ 79.99 380,879 0.36 $ 76.51 380,879 $ 76.51 80.00–81.15 1,900 0.69 81.15 1,900 81.15 Total 382,779 0.36 $ 76.54 382,779 $ 76.54 |
Summary of Change in Benefit Obligations Recognized in Comprehensive Income on Pre-tax Basis and Amounts Recognized in Consolidated Balance Sheets | Effective fourth quarter 2017, we implemented a post-retirement benefit plan to assist in providing health care to officers who are active employees (including their spouses) and have met certain age and service requirements. These benefits are not funded in advance and are provided up to age 65 or at the date they become eligible for Medicare, subject to various cost-sharing features (in thousands). December 31, 2017 Accumulated benefit obligation $ 1,769 Change in benefit obligations (recognized in comprehensive income – pretax) Beginning balance at December 31, 2016 $ — Prior service cost 1,769 Total other comprehensive income (loss) at December 31, 2017 $ 1,769 Amounts recognized in the consolidated balance sheets: Noncurrent liability-accrued benefit cost $ 1,769 |
Summary of Assumptions Used to Determine Benefit Obligation | The following summarizes the assumptions used to determine the benefit obligation at December 31, 2017. December 31, 2017 Weighted average assumptions used to determine benefit obligation: Discount rate 3.3 % Assumed weighted average healthcare cost trend rates: Initial healthcare trend rate 7.00 % Ultimate trend rate 5.00 % Year ultimate trend rate reached 2028 |
Stock Option and SARs Activities | Information with respect to our SARs activities is summarized below. Shares Weighted Outstanding at December 31, 2014 1,966,549 $ 59.80 Exercised (427,598 ) 45.67 Expired/forfeited (27,974 ) 63.10 Outstanding at December 31, 2015 1,510,977 63.73 Expired/forfeited (507,377 ) 53.16 Outstanding at December 31, 2016 1,003,600 69.08 Expired/forfeited (620,821 ) 62.29 Outstanding at December 31, 2017 382,779 $ 76.54 |
Performance-based PG-PSUs and RG-PSUs | |
Summary of Non-Vested Awards Activities | The following is a summary of our non-vested PG/RG-PSUs awards outstanding at December Number of Weighted Outstanding at December 31, 2016 — — Units granted (a) 122,921 $ 25.53 Outstanding at December 30, 2017 122,921 $ 25.53 (a) |
Performance Based TSR - PSUs | |
Summary of Non-Vested Awards Activities | The following is a summary of our non-vested TSR – Weighted Outstanding at December 31, 2014 226,418 $ 86.16 Granted (a) 276,204 56.78 Forfeited (2,679 ) 82.60 Outstanding at December 31, 2015 499,943 69.95 Granted (a) 413,959 36.64 Forfeited (42,603 ) 46.09 Outstanding at December 31, 2016 871,299 55.29 Granted (a) 358,519 26.26 Vested and issued (b) (85,461 ) 86.23 Forfeited (134,515 ) 85.24 Outstanding at December 31, 2017 1,009,842 $ 38.38 (a) These (b ) th th |
Supplemental Cash Flow Inform39
Supplemental Cash Flow Information (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Supplemental Cash Flow Elements [Abstract] | |
Supplemental Cash Flow Information | Year Ended December 31, 2017 2016 2015 (in thousands) Net cash provided from operating activities included: Income taxes (refunded from) paid to taxing authorities $ (1,024 ) $ (102 ) $ 100 Interest paid 179,431 159,875 168,826 Non-cash investing and financing activities included (a) Asset retirement costs capitalized, net $ 20,245 $ (24,064 ) $ 22,184 Increase (decrease) in accrued capital expenditures 71,739 61,419 (225,455 ) (a) For additional information on non-cash investing activities associated with the MRD Merger, see Note 3. |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Commitments And Contingencies Disclosure [Abstract] | |
Future Minimum Rental Commitments | We lease certain office space, office equipment, production facilities, compressors and transportation equipment under cancelable and non-cancelable leases. Rent expense under operating leases (including renewable monthly leases) totaled $19.1 million in 2017 compared to $14.0 million in 2016 and $15.9 million in 2015. Commitments related to these lease payments are not recorded in the accompanying consolidated balance sheets. Future minimum rental commitments under non-cancelable leases having remaining lease terms in excess of one year are as follows (in thousands): Operating Sublease 2018 $ 18,498 $ 3,472 2019 17,803 3,472 2020 16,945 3,174 2021 14,249 2,578 2022 8,058 215 Thereafter 32,909 — $ 108,462 $ 12,911 |
Schedule of Future Minimum Transportation Fees Due | We have entered into firm transportation and gathering contracts with various pipeline carriers for the future transportation and gathering of natural gas, NGLs and oil production from our properties in Pennsylvania and North Louisiana. Under these contracts, we are obligated to transport, process or gather minimum daily natural gas volumes, or pay for any deficiencies at a specified reservation fee rate. In most cases, our production committed to these pipelines is expected to exceed the minimum daily volumes provided in the contracts. As part of our purchase price allocation of liabilities that existed at the time of the MRD Merger, we have a remaining liability of $25.1 million for certain expected volume deficiency payments related to our properties in North Louisiana. As of December 31, 2017, future minimum transportation, processing and gathering fees under our commitments are as follows (in thousands): Transportation, (a) 2018 $ 805,161 2019 825,231 2020 767,090 2021 733,133 2022 691,968 Thereafter 4,689,133 $ 8,511,716 (a) |
Future Delivery Commitments | We have various volume delivery commitments that are primarily related to our Marcellus Shale and North Louisiana areas. We expect to be able to fulfill our contractual obligations from our own production; however, we may purchase third party volumes to satisfy our commitments or pay demand fees for commitment shortfalls, should they occur. As of December 31, 2017, our delivery commitments through 2031 were as follows: Year Ending December 31, Natural Gas Ethane and Propane (bbls per day) 2018 382,534 71,000 2019 364,356 55,932 2020 252,878 48,625 2021 116,189 48,000 2022 68,712 43,000 2023 — 35,000 2024 — — 35,000 2029—2031 — 20,000 |
Office Closing and Exit Costs (
Office Closing and Exit Costs (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Restructuring And Related Activities [Abstract] | |
Exit Costs Included in Accrued Liabilities in Consolidated Balance Sheet | The following table details the accrued liability as of December 31, 2017 and December 31, 2016 (in thousands): 2017 2016 Beginning balance $ 2,460 $ 11,630 Accrued severance costs 2,176 (822 ) Accrued building rent (70 ) 303 Payments (2,711 ) (8,651 ) Ending balance $ 1,855 $ 2,460 |
Summary of Termination Costs | The following summarizes our termination costs for three years ended December 31, 2017, 2016 and 2015 (in thousands): 2017 2016 2015 Severance costs $ 2,176 $ (822 ) $ 11,706 Building lease (70 ) 303 3,147 Stock-based compensation 1,664 — 217 Total termination costs $ 3,770 $ (519 ) $ 15,070 |
Selected Quarterly Financial 42
Selected Quarterly Financial Data (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Quarterly Financial Data [Abstract] | |
Selected Quarterly Financial Data | The following tables set forth unaudited financial information on a quarterly basis for each of the last two years. Third quarter 2017 includes impairment expense of $63.7 million related to oil and gas properties in Oklahoma and Texas. Fourth quarter 2017 deferred income tax benefit includes the impact of the Tax Cuts and Jobs Act of 2017 which was signed into law on December 22, 2017. First quarter 2016 includes impairment expense of $43.0 million related to oil and gas properties in Western Oklahoma. Second quarter, third quarter and fourth quarter 2016 include a total of $37.2 million of expenses related to the MRD Merger (in thousands, except per share data): 2017 March June September December Total Revenues and other income: Natural gas, NGLs and oil sales $ 559,450 $ 506,137 $ 507,541 $ 603,159 $ 2,176,287 Derivative fair value income (loss) 165,557 111,195 (88,426 ) 25,024 213,350 Brokered natural gas, marketing and other 51,648 55,779 63,117 50,849 221,393 Total revenue and other income 776,655 673,111 482,232 679,032 2,611,030 Costs and expenses: Direct operating 28,023 31,420 36,888 37,921 134,252 Transportation, gathering, processing and compression 177,648 191,590 191,645 200,300 761,183 Production and ad valorem taxes 9,163 9,969 11,993 11,757 42,882 Brokered natural gas and marketing 53,550 55,857 59,773 51,131 220,311 Exploration 8,504 14,498 22,767 7,893 53,662 Abandonment and impairment of unproved properties 4,420 5,193 42,568 217,544 269,725 General and administrative 47,496 52,322 53,035 80,553 233,406 Termination costs 4,192 (96 ) (47 ) (279 ) 3,770 Deferred compensation plan (13,169 ) (14,466 ) (9,203 ) (14,077 ) (50,915 ) Interest 47,101 47,926 49,179 51,473 195,679 Depletion, depreciation and amortization 149,821 152,504 159,749 162,918 624,992 Impairment of proved properties and other — — 63,679 — 63,679 (Gain) loss on sale of assets (22,600 ) (807 ) (102 ) (207 ) (23,716 ) Total costs and expenses 494,149 545,910 681,924 806,927 2,528,910 Income (loss) before income taxes 282,506 127,201 (199,692 ) (127,895 ) 82,120 Income tax expense (benefit): Current — — — 17 17 Deferred 112,395 57,651 (71,992 ) (349,097 ) (251,043 ) 112,395 57,651 (71,992 ) (349,080 ) (251,026 ) Net income (loss) $ 170,111 $ 69,550 $ (127,700 ) $ 221,185 $ 333,146 Net income (loss) per common share: Basic $ 0.69 $ 0.28 $ (0.52 ) $ 0.89 $ 1.34 Diluted $ 0.69 $ 0.28 $ (0.52 ) $ 0.89 $ 1.34 2016 March June September December Total Revenues and other income: Natural gas, NGLs and oil sales $ 209,487 $ 224,606 $ 304,477 $ 458,645 $ 1,197,215 Derivative fair value income (loss) 86,908 (162,798 ) 64,556 (250,057 ) (261,391 ) Brokered natural gas, marketing and other 35,018 39,989 44,174 44,934 164,115 Total revenue and other income 331,413 101,797 413,207 253,522 1,099,939 Costs and expenses: Direct operating 24,054 20,671 22,387 30,276 97,388 Transportation, gathering, processing and compression 125,263 136,844 138,764 164,338 565,209 Production and ad valorem taxes 5,887 6,049 6,717 6,790 25,443 Brokered natural gas and marketing 36,558 40,925 44,622 46,471 168,576 Exploration 4,913 6,785 6,943 13,684 32,325 Abandonment and impairment of unproved properties 10,628 7,059 6,082 6,307 30,076 General and administrative 40,657 46,064 41,024 57,027 184,772 MRD Merger expenses — 2,621 33,791 813 37,225 Termination costs 162 5 136 (822 ) (519 ) Deferred compensation plan 16,056 25,746 (11,636 ) (11,013 ) 19,153 Interest 37,739 37,758 45,967 46,749 168,213 Depletion, depreciation and amortization 120,561 122,390 131,489 149,662 524,102 Impairment of proved properties and other 43,040 — — — 43,040 Loss (gain) on sale of assets 1,643 3,304 2,597 (470 ) 7,074 Total costs and expenses 467,161 456,221 468,883 509,812 1,902,077 Loss before income taxes (135,748 ) (354,424 ) (55,676 ) (256,290 ) (802,138 ) Income tax expense (benefit): Current — — — 98 98 Deferred (41,976 ) (129,488 ) (13,705 ) (95,679 ) (280,848 ) (41,976 ) (129,488 ) (13,705 ) (95,581 ) (280,750 ) Net loss $ (93,772 ) $ (224,936 ) $ (41,971 ) $ (160,709 ) $ (521,388 ) Net loss per common share: Basic $ (0.56 ) $ (1.35 ) $ (0.23 ) $ (0.66 ) $ (2.75 ) Diluted $ (0.56 ) $ (1.35 ) $ (0.23 ) $ (0.66 ) $ (2.75 ) |
Supplemental Information on N43
Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Extractive Industries [Abstract] | |
Capitalized Costs and Accumulated Depreciation, Depletion and Amortization | Capitalized Costs and Accumulated Depreciation, Depletion and Amortization (a) December 31, 2017 2016 2015 (in thousands) Natural gas and oil properties: Properties subject to depletion $ 10,572,453 $ 9,462,350 $ 8,047,181 Unproved properties 2,644,000 2,923,803 949,155 Total 13,216,453 12,386,153 8,996,336 Accumulated depreciation, depletion and amortization (3,649,716 ) (3,129,816 ) (2,635,031 ) Net capitalized costs $ 9,566,737 $ 9,256,337 $ 6,361,305 (a) |
Costs Incurred for Property Acquisition, Exploration and Development | Costs Incurred for Property Acquisition, Exploration (a) December 31, 2017 2016 2015 (in thousands) Acquisitions Acreage purchases $ 62,075 $ 33,142 $ 73,025 Oil and gas properties 18,269 3,098,772 — Asset retirement obligations and other — 21,908 — Development 1,177,526 497,795 708,268 Exploration: Drilling 2,030 37,680 87,505 Expense 50,920 30,027 18,421 Stock-based compensation expense 2,742 2,298 2,985 Gas gathering facilities: Development 15,097 3,595 13,337 Subtotal 1,328,659 3,725,217 903,541 Asset retirement obligations 20,245 (24,064 ) 22,184 Total costs incurred $ 1,348,904 $ 3,701,153 $ 925,725 (a) |
Proved Developed and Undeveloped Reserves | Natural Gas NGLs Crude Oil and Condensate Natural Gas (Mmcf) (Mbbls) (Mbbls) (Mmcfe) (a) Proved developed and undeveloped reserves: Balance, December 31, 2014 6,922,836 515,907 48,658 10,310,229 Revisions (340,286 ) 17,717 3,804 (211,163 ) Extensions, discoveries and additions 1,017,956 36,308 4,924 1,265,348 Property sales (960,122 ) (441 ) (109 ) (963,423 ) Production (362,687 ) (20,356 ) (4,084 ) (509,328 ) Balance, December 31, 2015 6,277,697 549,135 53,193 9,891,663 Revisions (7,441 ) 41,402 2,471 255,794 Extensions, discoveries and additions 1,193,154 26,991 6,506 1,394,134 Purchases 943,544 40,724 11,986 1,259,806 Property sales (160,727 ) (360 ) (295 ) (164,655 ) Production (375,811 ) (27,826 ) (3,609 ) (564,420 ) Balance, December 31, 2016 7,870,416 630,066 70,252 12,072,322 Revisions 70,222 83,338 (10,555 ) 506,919 Extensions, discoveries and additions 2,866,103 87,572 15,997 3,487,519 Purchases 7,738 330 66 10,116 Property sales (60,278 ) (2,356 ) (1,121 ) (81,133 ) Production (490,552 ) (35,686 ) (4,785 ) (733,382 ) Balance, December 31, 2017 10,263,649 763,264 69,854 15,262,361 Proved developed reserves: December 31, 2015 3,376,165 309,306 31,679 5,422,075 December 31, 2016 4,352,141 363,852 39,110 6,769,908 December 31, 2017 5,437,674 448,258 36,808 8,348,074 Proved undeveloped reserves: December 31, 2015 2,901,533 239,828 21,514 4,469,588 December 31, 2016 3,518,275 266,214 31,143 5,302,414 December 31, 2017 4,825,975 315,006 33,046 6,914,287 (a) Oil and NGLs are converted to mcfe at the rate of one barrel equals six mcf based upon the approximate relative energy content of oil to natural gas, which is not indicative of the relationship of oil and natural gas prices. |
Changes in Proved Undeveloped Reserves | The following details the changes in proved undeveloped reserves for 2017 (Mmcfe): Beginning proved undeveloped reserves at December 31, 2016 5,302,414 Undeveloped reserves transferred to developed (1,861,994 ) Revisions (a) 308,929 Purchases/(sales) (8,907 ) Extension and discoveries 3,173,845 Ending proved undeveloped reserves at December 31, 2017 6,914,287 (a) |
Standardized Measure of Discounted Future Net Cash Flows | The standardized measure of discounted future net cash flows relating to proved natural gas, NGLs, crude oil and condensate reserves is as follows and excludes cash flows associated with derivatives outstanding at each of the respective reporting dates. Future cash inflows are net of third party transportation, gathering and compression expense. As of December 31, 2017 2016 (in thousands) Future cash inflows $ 43,500,054 $ 27,413,864 Future costs: Production (18,958,695 ) (14,465,059 ) Development (a) (3,072,688 ) (2,647,801 ) Future net cash flows before income taxes 21,468,671 10,301,004 Future income tax expense (3,989,459 ) (1,946,259 ) Total future net cash flows before 10% discount 17,479,212 8,354,745 10% annual discount (10,313,998 ) (4,902,816 ) Standardized measure of discounted future net cash flows $ 7,165,214 $ 3,451,929 (a) |
Changes in Discounted Future Net Cash Flows | The following table summarizes changes in the standardized measure of discounted future net cash flows. December 31, 2017 2016 2015 (in thousands) Revisions of previous estimates: Changes in prices and production costs $ 2,615,825 $ (212,867 ) $ (7,231,629 ) Revisions in quantities 445,667 96,615 (868,886 ) Changes in future development and abandonment costs (497,400 ) (314,864 ) 359,540 Net change in income taxes (706,531 ) 27,842 2,173,904 Accretion of discount 372,743 302,920 1,007,027 Purchases of reserves in place 6,173 488,959 — Additions to proved reserves from extensions, discoveries and improved recovery 2,128,135 541,095 486,478 Natural gas, NGLs and oil sales, net of production costs (1,237,970 ) (509,174 ) (522,682 ) Development costs incurred during the period 885,803 435,928 1,033,539 Sales of reserves in place (32,946 ) (65,538 ) (1,050,237 ) Timing and other (266,214 ) (64,850 ) (254,218 ) Net change for the year 3,713,285 726,066 (4,867,164 ) Beginning of year 3,451,929 2,725,863 7,593,027 End of year $ 7,165,214 $ 3,451,929 $ 2,725,863 |
Summary of Significant Accoun44
Summary of Significant Accounting Policies - Additional Information (Detail) - USD ($) | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Summary Of Significant Accounting Policies [Line Items] | |||
Net brokered margin gain (losses) | $ (5,700,000) | $ (2,800,000) | $ (2,700,000) |
Allowance for doubtful accounts on accounts receivable | 7,111,000 | 5,559,000 | |
Bad debt expense | 1,550,000 | 800,000 | $ 2,300,000 |
Inventory and other | 21,346,000 | 26,573,000 | |
Goodwill | 1,641,197,000 | 1,654,292,000 | |
Materials and supplies inventory | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Inventory and other | 12,100,000 | 9,400,000 | |
Commodity inventory | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Inventory and other | $ 508,000 | $ 8,300,000 |
Summary of Significant Accoun45
Summary of Significant Accounting Policies - Additional Information 1 (Detail) - USD ($) | 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 | ||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||
Net book value of unproved properties | [1] | $ 2,644,000,000 | $ 2,923,803,000 | $ 2,644,000,000 | $ 2,923,803,000 | $ 949,155,000 | ||||||
Abandonment and impairment of unproved properties | 217,544,000 | $ 42,568,000 | $ 5,193,000 | $ 4,420,000 | 6,307,000 | $ 6,082,000 | $ 7,059,000 | $ 10,628,000 | 269,725,000 | 30,076,000 | 47,619,000 | |
Depreciation expense | 7,700,000 | 8,400,000 | 11,900,000 | |||||||||
Marketable securities held in deferred compensation plans | 67,100,000 | 61,700,000 | 67,100,000 | 61,700,000 | ||||||||
Surface acreage | $ 9,600,000 | $ 10,600,000 | 9,600,000 | 10,600,000 | ||||||||
Natural Gas and Oil Properties | Northwest Pennsylvania | ||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||
Fair Value | $ 0 | |||||||||||
Adjustments of the asset retirement liability additional expense | $ 158,000 | $ 1,900,000 | ||||||||||
Other property and equipment | Minimum | ||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||
Useful life of assets | 3 years | |||||||||||
Other property and equipment | Maximum | ||||||||||||
Summary Of Significant Accounting Policies [Line Items] | ||||||||||||
Useful life of assets | 10 years | |||||||||||
[1] | Includes capitalized asset retirement costs and the associated accumulated amortization. |
Summary of Significant Accoun46
Summary of Significant Accounting Policies - Additional Information 2 (Detail) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017USD ($)CustomerCounterparty | Dec. 31, 2016USD ($)Customer | Dec. 31, 2015Customer | |
Summary Of Significant Accounting Policies [Line Items] | |||
Allowance for doubtful accounts on accounts receivable | $ 7,111 | $ 5,559 | |
Number of customers accounted more than 10% of total oil and gas revenues | Customer | 1 | 1 | 1 |
Net derivative asset | $ 28,200 | ||
Number of counterparties | Counterparty | 5 | ||
Number of financial institutions included in counter parties | Counterparty | 19 | ||
Accounting Standards Update 2016-09 | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Recognition of an excess tax deficiency in provision for income taxes rather than paid-in capital | $ 2,100 | ||
Cumulative-effect adjustments to retained earnings (deficit) and reduced deferred tax liability | $ 101,100 |
Summary of Significant Accoun47
Summary of Significant Accounting Policies - Summary of Adjustments to Quarterly Data Resulting from Adoption of New Standard in Statements of Operations (Detail) - USD ($) $ / shares in Units, $ in Thousands | 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 | |
New Accounting Pronouncement Early Adoption [Line Items] | |||||||||||
Income tax benefit | $ (349,080) | $ (71,992) | $ 57,651 | $ 112,395 | $ (95,581) | $ (13,705) | $ (129,488) | $ (41,976) | $ (251,026) | $ (280,750) | $ (338,677) |
Net loss | $ 221,185 | $ (127,700) | $ 69,550 | $ 170,111 | $ (160,709) | $ (41,971) | $ (224,936) | $ (93,772) | $ 333,146 | $ (521,388) | $ (713,685) |
Basic earnings per share | $ 0.89 | $ (0.52) | $ 0.28 | $ 0.69 | $ (0.66) | $ (0.23) | $ (1.35) | $ (0.56) | $ 1.34 | $ (2.75) | $ (4.29) |
Diluted earnings per share | $ 0.89 | $ (0.52) | $ 0.28 | $ 0.69 | $ (0.66) | $ (0.23) | $ (1.35) | $ (0.56) | $ 1.34 | $ (2.75) | $ (4.29) |
Accounting Standards Update 2016-09 | |||||||||||
New Accounting Pronouncement Early Adoption [Line Items] | |||||||||||
Income tax benefit | $ (41,976) | ||||||||||
Net loss | $ (93,772) | ||||||||||
Basic earnings per share | $ (0.56) | ||||||||||
Diluted earnings per share | $ (0.56) | ||||||||||
Accounting Standards Update 2016-09 | As Reported | |||||||||||
New Accounting Pronouncement Early Adoption [Line Items] | |||||||||||
Income tax benefit | $ (44,038) | ||||||||||
Net loss | $ (91,710) | ||||||||||
Basic earnings per share | $ (0.55) | ||||||||||
Diluted earnings per share | $ (0.55) |
Summary of Significant Accoun48
Summary of Significant Accounting Policies - Summary of Adjustments to Quarterly Data Resulting from Adoption of New Standard in Statements of Cash Flows (Detail) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | 9 Months Ended | 12 Months Ended | ||||
Mar. 31, 2016 | Jun. 30, 2016 | Sep. 30, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
New Accounting Pronouncement Early Adoption [Line Items] | ||||||||
Net cash provided from operating activities | $ 816,254 | $ 387,068 | $ 691,402 | |||||
Net cash (used in) provided from financing activities | $ 322,937 | $ (78,390) | (472,607) | |||||
Accounting Standards Update 2016-09 | ||||||||
New Accounting Pronouncement Early Adoption [Line Items] | ||||||||
Net cash provided from operating activities | $ 90,785 | $ 173,201 | $ 205,837 | 691,402 | $ 974,353 | $ 757,373 | ||
Net cash (used in) provided from financing activities | (75,834) | (99,008) | (39,029) | (472,607) | 271,203 | 226,159 | ||
As Reported | Accounting Standards Update 2016-09 | ||||||||
New Accounting Pronouncement Early Adoption [Line Items] | ||||||||
Net cash provided from operating activities | 87,424 | 169,604 | 202,037 | 683,700 | 954,135 | 743,538 | ||
Net cash (used in) provided from financing activities | $ (72,473) | $ (95,411) | $ (35,229) | $ (464,905) | $ 291,421 | $ 239,994 |
Dispositions and Acquisitions -
Dispositions and Acquisitions - Dispositions - Additional Information (Detail) - USD ($) | 1 Months Ended | 3 Months Ended | 9 Months Ended | 12 Months Ended | ||||||||||
Feb. 28, 2015 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Sep. 30, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 30, 2015 | |
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items] | ||||||||||||||
(Loss) gain on the sale of assets | $ 207,000 | $ 102,000 | $ 807,000 | $ 22,600,000 | $ 470,000 | $ (2,597,000) | $ (3,304,000) | $ (1,643,000) | $ 23,716,000 | $ (7,074,000) | $ (406,856,000) | |||
Texas Panhandle Properties | ||||||||||||||
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items] | ||||||||||||||
(Loss) gain on the sale of assets | (989,000) | |||||||||||||
Proceeds from sale of oil and gas properties | $ 40,400,000 | |||||||||||||
Western Oklahoma Properties | ||||||||||||||
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items] | ||||||||||||||
(Loss) gain on the sale of assets | $ (5,300,000) | 23,800,000 | ||||||||||||
Proceeds from sale of oil and gas properties | $ 78,600,000 | 30,800,000 | ||||||||||||
Miscellaneous Proved, Unproved Properties and Surface Acreage | ||||||||||||||
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items] | ||||||||||||||
(Loss) gain on the sale of assets | 870,000 | 302,000 | 943,000 | |||||||||||
Proceeds from sale of oil and gas properties | $ 1,300,000 | 3,700,000 | 4,400,000 | |||||||||||
Northeast Pennsylvania Non-operated Interest | ||||||||||||||
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items] | ||||||||||||||
(Loss) gain on the sale of assets | (2,100,000) | |||||||||||||
Proceeds from sale of oil and gas properties | $ 111,500,000 | |||||||||||||
Mississippi and South Texas properties | ||||||||||||||
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items] | ||||||||||||||
Proceeds from sale of oil and gas properties | $ 1,200,000 | |||||||||||||
Virginia And West Virginia Property | ||||||||||||||
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items] | ||||||||||||||
(Loss) gain on the sale of assets | (407,700,000) | |||||||||||||
Cash proceeds from sale of assets | $ 876,000,000 | |||||||||||||
Net operating income prior to disposition | $ 52,300,000 | |||||||||||||
West Texas Properties | ||||||||||||||
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items] | ||||||||||||||
(Loss) gain on the sale of assets | $ (101,000) | |||||||||||||
Proceeds from sale of oil and gas properties | $ 10,500,000 |
Dispositions and Acquisitions50
Dispositions and Acquisitions - Acquisitions - Additional Information (Detail) $ in Thousands | Sep. 16, 2016USD ($)shares | Dec. 31, 2016USD ($) | Sep. 30, 2016USD ($) | Jun. 30, 2016USD ($) | Mar. 31, 2016USD ($) | Dec. 31, 2016USD ($) | Dec. 31, 2016USD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) |
Business Acquisition [Line Items] | ||||||||||
Merger-related expenses | $ 813 | $ 33,791 | $ 2,621 | $ 0 | $ 37,200 | $ 0 | $ 37,225 | $ 0 | ||
Pro Forma Adjusted for Merger Expenses Incurred | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Merger-related expenses | 37,200 | |||||||||
MRD | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Business merger date | Sep. 16, 2016 | |||||||||
Common stock issued in connection with exchange of outstanding shares | shares | 77,042,749 | |||||||||
Exchange ratio of common shares for acquired company | 0.375 | |||||||||
Fair value of outstanding debt | $ 1,204,449 | |||||||||
Revenues | $ 146,600 | $ 477,400 | ||||||||
Net operating income | $ 94,900 | $ 278,800 | ||||||||
MRD | Pro Forma Adjustment | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Merger-related expenses | $ 7,100 |
Dispositions and Acquisitions51
Dispositions and Acquisitions - Summary of Final Allocation of Total Purchase Price (Details) - USD ($) $ / shares in Units, $ in Thousands | Sep. 16, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | |
Natural gas and oil properties: | ||||
Goodwill | $ 1,641,197 | $ 1,654,292 | ||
MRD | ||||
Purchase price: | ||||
Shares of Range common stock issued to Memorial stockholders | 77,042,749 | |||
Range common stock price per share at September 15, 2016 (close) | $ 39.37 | |||
Total purchase price | $ 3,033,173 | |||
Plus fair value of liabilities assumed by Range: | ||||
Accounts payable | 55,624 | |||
Other current liabilities | 108,367 | |||
Long-term debt | 1,204,449 | |||
Deferred taxes | 547,706 | |||
Other long-term liabilities | 77,223 | |||
Total purchase price plus liabilities assumed | 5,026,542 | |||
Fair value of Memorial assets: | ||||
Cash and equivalents | 7,180 | |||
Other current assets | 99,969 | |||
Derivative instruments | 152,994 | |||
Natural gas and oil properties: | ||||
Proved property | 1,122,311 | |||
Unproved property | 1,999,187 | |||
Other property and equipment | 3,579 | |||
Goodwill | [1] | 1,641,197 | ||
Other | 125 | |||
Total asset value | $ 5,026,542 | |||
[1] | Goodwill will not be deductible for income tax purposes. |
Dispositions and Acquisitions52
Dispositions and Acquisitions - Summary of Pro Forma Financial Information (Details) - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Business Acquisition Pro Forma Information [Abstract] | ||
Revenues | $ 1,334,290 | $ 2,253,368 |
Net loss | $ (591,121) | $ (556,164) |
Loss per share: | ||
Basic | $ (2.42) | $ (2.28) |
Diluted | $ (2.42) | $ (2.28) |
Goodwill - Additional Informati
Goodwill - Additional Information (Detail) - USD ($) | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Goodwill And Intangible Assets Disclosure [Abstract] | ||
Goodwill | $ 1,641,197,000 | $ 1,654,292,000 |
Impairment charge | 0 | |
Fair value exceeded book value, amount | 1,400,000,000 | |
Fair value exceeded book value impact after effect of new tax law, amount | $ 2,400,000,000 | |
Fair value exceeded book value, percentage | 24.00% | |
Fair value exceeded book value impact after effect of new tax law, percentage | 42.00% |
Income Taxes - Additional Infor
Income Taxes - Additional Information (Detail) - USD ($) | Dec. 22, 2017 | Oct. 18, 2017 | 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, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Income Taxes [Line Items] | ||||||||||||||
Income tax benefit | $ (349,080,000) | $ (71,992,000) | $ 57,651,000 | $ 112,395,000 | $ (95,581,000) | $ (13,705,000) | $ (129,488,000) | $ (41,976,000) | $ (251,026,000) | $ (280,750,000) | $ (338,677,000) | |||
Corporate tax rate | 35.00% | 35.00% | 35.00% | |||||||||||
Deferred tax liabilities | 693,356,000 | $ 943,343,000 | $ 693,356,000 | $ 943,343,000 | ||||||||||
Deductible limit | 1,000,000 | 1,000,000 | ||||||||||||
Accrued interest or penalties related to tax amounts | 0 | $ 0 | ||||||||||||
Minimum | ||||||||||||||
Income Taxes [Line Items] | ||||||||||||||
Period during which net operating loss carryforwards and alternative minimum tax expire | Dec. 31, 2018 | |||||||||||||
Maximum | ||||||||||||||
Income Taxes [Line Items] | ||||||||||||||
Period during which net operating loss carryforwards and alternative minimum tax expire | Dec. 31, 2035 | |||||||||||||
Deferred compensation plan | ||||||||||||||
Income Taxes [Line Items] | ||||||||||||||
Valuation allowances | 1,900,000 | $ 1,900,000 | ||||||||||||
Amendment on Internal Revenue Code of 1986 | ||||||||||||||
Income Taxes [Line Items] | ||||||||||||||
Corporate tax rate | 35.00% | |||||||||||||
One-time tax benefit related to tax law changes | $ 334,000,000 | |||||||||||||
Amendment on Internal Revenue Code of 1986 | Scenario, Forecast | ||||||||||||||
Income Taxes [Line Items] | ||||||||||||||
Corporate tax rate | 21.00% | |||||||||||||
Oklahoma, Texas and West Virginia | ||||||||||||||
Income Taxes [Line Items] | ||||||||||||||
State valuation allowance | 36,300,000 | $ 36,300,000 | ||||||||||||
Pennsylvania | ||||||||||||||
Income Taxes [Line Items] | ||||||||||||||
State valuation allowance | 57,500,000 | $ 57,500,000 | ||||||||||||
Minimum net operating loss deduction amount | $ 3,000,000 | |||||||||||||
Percentage of taxable income | 30.00% | |||||||||||||
Net operating loss deduction, description | The Supreme Court ruled that the net operating loss deduction limitation violated the Uniformity Clause of the Pennsylvania Constitution and struck the $3.0 million flat cap limitation but not the percentage of taxable income limitation. | |||||||||||||
Net operating loss carryforwards | 872,600,000 | $ 872,600,000 | ||||||||||||
Pennsylvania | Minimum | ||||||||||||||
Income Taxes [Line Items] | ||||||||||||||
Period during which net operating loss carryforwards and alternative minimum tax expire | Dec. 31, 2025 | |||||||||||||
Pennsylvania | Maximum | ||||||||||||||
Income Taxes [Line Items] | ||||||||||||||
Period during which net operating loss carryforwards and alternative minimum tax expire | Dec. 31, 2036 | |||||||||||||
Federal and State | ||||||||||||||
Income Taxes [Line Items] | ||||||||||||||
Net operating loss carryforwards | $ 1,500,000,000 | $ 1,500,000,000 |
Income Taxes - Reconciliation B
Income Taxes - Reconciliation Between Statutory Federal Income Tax Rate and Effective Income Tax (Detail) | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Income Taxes [Line Items] | |||
Federal statutory tax rate | 35.00% | 35.00% | 35.00% |
Federal rate change | (406.70%) | 0.00% | 0.00% |
State | (0.70%) | 3.00% | 4.30% |
State rate and law change | (1.30%) | 1.00% | (0.20%) |
Non-deductible executive compensation | 0.70% | (0.20%) | (0.10%) |
Valuation allowances | 36.80% | (2.50%) | (6.80%) |
Equity compensation | 30.20% | (0.70%) | 0.00% |
Other | 0.30% | 0.00% | 0.00% |
Consolidated effective tax rate | (305.70%) | 35.00% | 32.20% |
MRD | |||
Income Taxes [Line Items] | |||
Non-deductible MRD transaction costs | 0.00% | (0.60%) | 0.00% |
Income Taxes - Income Tax (Bene
Income Taxes - Income Tax (Benefit) Expense Attributable to Income Before Income Taxes (Details) - USD ($) $ in Thousands | 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 | |
Components Of Income Tax Expense Benefit Continuing Operations [Abstract] | |||||||||||
U.S. federal, Current | $ 0 | $ 0 | $ 0 | ||||||||
U.S. state and local, Current | 17 | 98 | 29 | ||||||||
Total, Current | $ 17 | $ 0 | $ 0 | $ 0 | $ 98 | $ 0 | $ 0 | $ 0 | 17 | 98 | 29 |
U.S. federal, Deferred | (302,507) | (266,105) | (328,257) | ||||||||
U.S. state and local, Deferred | 51,464 | (14,743) | (10,449) | ||||||||
Total, Deferred | (349,097) | (71,992) | 57,651 | 112,395 | (95,679) | (13,705) | (129,488) | (41,976) | (251,043) | (280,848) | (338,706) |
U.S. federal, Total | (302,507) | (266,105) | (328,257) | ||||||||
U.S. state and local, Total | 51,481 | (14,645) | (10,420) | ||||||||
Total (benefit) expense for income taxes | $ (349,080) | $ (71,992) | $ 57,651 | $ 112,395 | $ (95,581) | $ (13,705) | $ (129,488) | $ (41,976) | $ (251,026) | $ (280,750) | $ (338,677) |
Income Taxes - Significant Comp
Income Taxes - Significant Components of Deferred Tax Assets and Liabilities (Detail) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Deferred tax assets: | ||
Net operating loss carryforward | $ 413,672 | $ 478,203 |
Deferred compensation | 24,704 | 50,808 |
Equity compensation | 5,269 | 29,528 |
AMT credits and other credits | 7,264 | 13,644 |
Asset retirement obligation | 69,398 | 99,000 |
Cumulative mark-to-market loss | 0 | 73,404 |
Other | 18,806 | 39,922 |
Valuation allowances: | ||
Total deferred tax assets | 413,979 | 677,335 |
Deferred tax liabilities: | ||
Depreciation, depletion and investments | (1,105,494) | (1,619,922) |
Cumulative mark-to-market gain | (1,841) | 0 |
Other | 0 | (756) |
Total deferred tax liabilities | (1,107,335) | (1,620,678) |
Net deferred tax liability | (693,356) | (943,343) |
Federal | ||
Valuation allowances: | ||
Valuation allowances | (31,308) | (48,750) |
State, net of federal benefit | ||
Valuation allowances: | ||
Valuation allowances | $ (93,826) | $ (58,424) |
Income Taxes - Changes in Defer
Income Taxes - Changes in Deferred Tax Asset Valuation Allowances (Detail) - Valuation Allowance of Deferred Tax Assets - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Income Taxes [Line Items] | |||
Balance at the beginning of the year | $ (107,174) | $ (87,623) | $ (16,599) |
Charged to provision for income taxes: | |||
Other state valuation allowances | (23,790) | 500 | (1,050) |
Other federal valuation allowances | (247) | (477) | (511) |
Rabbi trust valuation allowance | 2,304 | (1,066) | 3,494 |
Other | 0 | (34) | 0 |
Balance at the end of the year | (125,134) | (107,174) | (87,623) |
State | |||
Charged to provision for income taxes: | |||
Net operating loss carryforwards | (11,612) | (17,374) | (30,457) |
Federal | |||
Charged to provision for income taxes: | |||
Net operating loss carryforwards | $ 15,385 | $ (1,100) | $ (42,500) |
Net Income (Loss) Per Common 59
Net Income (Loss) Per Common Share - Computations of Basic and Diluted Income (Loss) Per Common Share (Detail) - USD ($) $ / shares in Units, $ in Thousands | 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 | ||
Earnings Per Share Reconciliation [Abstract] | ||||||||||||
Net income (loss) | $ 221,185 | $ (127,700) | $ 69,550 | $ 170,111 | $ (160,709) | $ (41,971) | $ (224,936) | $ (93,772) | $ 333,146 | $ (521,388) | $ (713,685) | |
Participating basic earnings | [1] | (3,751) | (223) | (450) | ||||||||
Basic net income (loss) attributed to common stockholders | 329,395 | (521,611) | (714,135) | |||||||||
Reallocation of participating earnings | [1] | 5 | 0 | 0 | ||||||||
Diluted net income (loss) attributed to common stockholders | $ 329,400 | $ (521,611) | $ (714,135) | |||||||||
Net income (loss) per common share: | ||||||||||||
Basic | $ 0.89 | $ (0.52) | $ 0.28 | $ 0.69 | $ (0.66) | $ (0.23) | $ (1.35) | $ (0.56) | $ 1.34 | $ (2.75) | $ (4.29) | |
Diluted | $ 0.89 | $ (0.52) | $ 0.28 | $ 0.69 | $ (0.66) | $ (0.23) | $ (1.35) | $ (0.56) | $ 1.34 | $ (2.75) | $ (4.29) | |
[1] | Restricted stock Liability Awards represent participating securities because they participate in nonforfeitable dividends or distributions with common equity owners. Income allocable to participating securities represents the distributed and undistributed earnings attributable to the participating securities. Participating securities, however, do not participate in undistributed net losses. |
Net Income (Loss) Per Common 60
Net Income (Loss) Per Common Share - Basic Weighted Average Common Shares Outstanding to Diluted Weighted Average Common Shares Outstanding (Detail) - shares shares in Thousands | 12 Months Ended | |||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | ||
Denominator: | ||||
Weighted average common shares outstanding – basic | [1] | 245,091 | 189,868 | 166,389 |
Effect of dilutive securities: | ||||
Director and employee restricted stock and performance-based equity awards | 367 | 0 | 0 | |
Weighted average common shares outstanding – diluted | 245,458 | 189,868 | 166,389 | |
[1] | Includes common stock issued in connection with the exchange of 77.0 million shares for all outstanding Memorial common stock on September 16, 2016. |
Net Income (Loss) Per Common 61
Net Income (Loss) Per Common Share - Basic Weighted Average Common Shares Outstanding to Diluted Weighted Average Common Shares Outstanding (Parenthetical) (Detail) | Sep. 16, 2016shares |
MRD | |
Earnings Per Share Basic [Line Items] | |
Common stock issued in connection with exchange of outstanding shares | 77,042,749 |
Net Income (Loss) Per Common 62
Net Income (Loss) Per Common Share - Additional Information (Detail) - shares | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Restricted Stock Liability Awards | |||
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items] | |||
Stock excluded from earning per share calculation | 2,800,000 | 2,800,000 | 2,800,000 |
Equity Grants | |||
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Line Items] | |||
Stock excluded from earning per share calculation | 702,000 |
Suspended Exploratory Well Co63
Suspended Exploratory Well Costs - Suspended Exploratory Well Costs (Detail) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017USD ($)Project | Dec. 31, 2016USD ($)Project | Dec. 31, 2015USD ($)Project | |
Extractive Industries [Abstract] | |||
Balance at beginning of period | $ 7,412 | $ 4,161 | $ 2,996 |
Additions to capitalized exploratory well costs pending the determination of proved reserves | 1,388 | 9,128 | 1,165 |
Reclassifications to wells, facilities and equipment based on determination of proved reserves | 0 | (5,877) | 0 |
Capitalized exploratory well costs charged to expense | (8,800) | 0 | 0 |
Balance at end of period | 0 | 7,412 | 4,161 |
Less exploratory well costs that have been capitalized for a period of one year or less | 0 | (7,412) | (1,165) |
Capitalized exploratory well costs that have been capitalized for a period greater than one year | $ 0 | $ 0 | $ 2,996 |
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year | Project | 0 | 0 | 1 |
Indebtedness - Additional Infor
Indebtedness - Additional Information (Detail) - USD ($) | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Debt Disclosure [Abstract] | |||
Interest capitalized during the period | $ 0 | $ 0 | $ 0 |
Indebtedness - Debt Outstanding
Indebtedness - Debt Outstanding (Detail) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 | May 31, 2015 | |
Debt Instrument [Line Items] | ||||
Senior notes | $ 2,877,349 | $ 2,877,849 | ||
Senior subordinated notes | 48,980 | 48,980 | ||
Total debt | 4,137,329 | 3,808,829 | ||
Unamortized premium | 6,027 | 7,241 | ||
Unamortized debt issuance costs | (34,550) | (42,553) | ||
Total debt net of debt issuance costs | 4,108,806 | 3,773,517 | ||
3.0% Bank Debt | Notes Payable to Banks | ||||
Debt Instrument [Line Items] | ||||
Bank debt (3.0%) | 1,211,000 | 882,000 | ||
4.875% Senior Notes Due 2025 | ||||
Debt Instrument [Line Items] | ||||
Senior notes | 750,000 | 750,000 | $ 750,000 | |
5.00% Senior Notes Due 2023 | ||||
Debt Instrument [Line Items] | ||||
Senior notes | 741,531 | 741,531 | ||
5.00% Senior Notes Due 2022 | ||||
Debt Instrument [Line Items] | ||||
Senior notes | 580,032 | 580,032 | ||
5.75% Senior Notes Due 2021 | ||||
Debt Instrument [Line Items] | ||||
Senior notes | 475,952 | 475,952 | ||
5.875% Senior Notes Due 2022 | ||||
Debt Instrument [Line Items] | ||||
Senior notes | [1] | 329,244 | 329,244 | |
Other Senior Notes Due 2022 | ||||
Debt Instrument [Line Items] | ||||
Senior notes | [2] | 590 | 1,090 | |
5.00% Senior Subordinated Notes Due 2023 | ||||
Debt Instrument [Line Items] | ||||
Senior subordinated notes | 7,712 | 7,712 | ||
5.00% Senior Subordinated Notes Due 2022 | ||||
Debt Instrument [Line Items] | ||||
Senior subordinated notes | 19,054 | 19,054 | ||
5.75% Senior Subordinated Notes Due 2021 | ||||
Debt Instrument [Line Items] | ||||
Senior subordinated notes | $ 22,214 | $ 22,214 | ||
[1] | Represents senior notes assumed in the MRD Merger that were not purchased for cash but were exchanged for Range 5.875% senior notes due 2022. See Senior Notes Exchange and Cash Tender Offer below. | |||
[2] | Represents the remaining Memorial 5.875% senior notes assumed in the MRD Merger that were not purchased for cash or were not exchanged for Range 5.875% senior notes due 2022. See Senior Notes Exchange and Cash Tender Offer below. |
Indebtedness - Debt Outstandi66
Indebtedness - Debt Outstanding (Parenthetical) (Detail) | Dec. 31, 2017 | Oct. 05, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Sep. 16, 2016 | May 31, 2015 |
4.875% Senior Notes Due 2025 | ||||||
Debt Instrument [Line Items] | ||||||
Interest rate on notes | 4.875% | 4.875% | 4.875% | |||
5.00% Senior Notes Due 2023 | ||||||
Debt Instrument [Line Items] | ||||||
Interest rate on notes | 5.00% | 5.00% | 5.00% | 5.00% | 5.00% | |
5.00% Senior Notes Due 2022 | ||||||
Debt Instrument [Line Items] | ||||||
Interest rate on notes | 5.00% | 5.00% | 5.00% | 5.00% | 5.00% | |
5.75% Senior Notes Due 2021 | ||||||
Debt Instrument [Line Items] | ||||||
Interest rate on notes | 5.75% | 5.75% | 5.75% | 5.75% | 5.75% | |
5.875% Senior Notes Due 2022 | ||||||
Debt Instrument [Line Items] | ||||||
Interest rate on notes | 5.875% | 5.875% | 5.875% | |||
5.00% Senior Subordinated Notes Due 2023 | ||||||
Debt Instrument [Line Items] | ||||||
Interest rate on notes | 5.00% | 5.00% | 5.00% | |||
5.00% Senior Subordinated Notes Due 2022 | ||||||
Debt Instrument [Line Items] | ||||||
Interest rate on notes | 5.00% | 5.00% | 5.00% | |||
5.75% Senior Subordinated Notes Due 2021 | ||||||
Debt Instrument [Line Items] | ||||||
Interest rate on notes | 5.75% | 5.75% | 5.75% | |||
Other Senior Notes Due 2022 | ||||||
Debt Instrument [Line Items] | ||||||
Interest rate on notes | 5.875% | |||||
Notes Payable to Banks | 3.0% Bank Debt | ||||||
Debt Instrument [Line Items] | ||||||
Bank debt percentage | 3.00% |
Indebtedness - Bank Debt - Addi
Indebtedness - Bank Debt - Additional Information (Detail) | 12 Months Ended | |||
Dec. 31, 2017USD ($)CommercialBank | Dec. 31, 2016USD ($) | Dec. 31, 2015 | Mar. 21, 2017USD ($) | |
Debt Instrument [Line Items] | ||||
Bank debt | $ 1,208,467,000 | $ 876,428,000 | ||
Bank Credit Facility | ||||
Debt Instrument [Line Items] | ||||
Bank Credit facility, maximum amount | 4,000,000,000 | |||
Bank Credit facility, borrowing base | 3,000,000,000 | $ 3,000,000,000 | ||
Bank commitments | $ 2,000,000,000 | $ 2,000,000,000 | ||
Percentage holding of commercial banks, Maximum | 5.80% | |||
Number of commercial banks included in current bank group | CommercialBank | 29 | |||
Maturity date of loan | Oct. 16, 2019 | |||
Bank debt | $ 1,200,000,000 | |||
Undrawn letters of credit | 281,400,000 | |||
Borrowing capacity available under the commitment amount | $ 507,600,000 | |||
Weighted average interest rate on the bank credit facility | 2.70% | 2.20% | 1.70% | |
Annual rate of commitment fee paid on the undrawn balance | 0.30% | |||
Bank Credit Facility | Alternate Base Rate | ||||
Debt Instrument [Line Items] | ||||
Interest rate margin | 0.50% | |||
Bank Credit Facility | LIBOR Rate | ||||
Debt Instrument [Line Items] | ||||
Interest rate margin | 1.50% | |||
Bank Credit Facility | Minimum | ||||
Debt Instrument [Line Items] | ||||
Annual rate of commitment fee paid on the undrawn balance | 0.30% | |||
Bank Credit Facility | Minimum | Credit Facility | ||||
Debt Instrument [Line Items] | ||||
Annual rate of commitment fee paid on the undrawn balance | 0.15% | |||
Bank Credit Facility | Minimum | Alternate Base Rate | ||||
Debt Instrument [Line Items] | ||||
Base rate on debt | 0.25% | |||
Bank Credit Facility | Minimum | Alternate Base Rate | Credit Facility | ||||
Debt Instrument [Line Items] | ||||
Base rate on debt | 0.125% | |||
Bank Credit Facility | Minimum | LIBOR Rate | ||||
Debt Instrument [Line Items] | ||||
Base rate on debt | 1.25% | |||
Bank Credit Facility | Minimum | LIBOR Rate | Credit Facility | ||||
Debt Instrument [Line Items] | ||||
Base rate on debt | 1.125% | |||
Bank Credit Facility | Maximum | ||||
Debt Instrument [Line Items] | ||||
Annual rate of commitment fee paid on the undrawn balance | 0.375% | |||
Bank Credit Facility | Maximum | Credit Facility | ||||
Debt Instrument [Line Items] | ||||
Annual rate of commitment fee paid on the undrawn balance | 0.30% | |||
Bank Credit Facility | Maximum | Alternate Base Rate | ||||
Debt Instrument [Line Items] | ||||
Base rate on debt | 1.25% | |||
Bank Credit Facility | Maximum | Alternate Base Rate | Credit Facility | ||||
Debt Instrument [Line Items] | ||||
Base rate on debt | 0.75% | |||
Bank Credit Facility | Maximum | LIBOR Rate | ||||
Debt Instrument [Line Items] | ||||
Base rate on debt | 2.25% | |||
Bank Credit Facility | Maximum | LIBOR Rate | Credit Facility | ||||
Debt Instrument [Line Items] | ||||
Base rate on debt | 1.75% |
Indebtedness - Senior Notes - A
Indebtedness - Senior Notes - Additional Information (Detail) - USD ($) $ in Thousands | 1 Months Ended | 12 Months Ended | |||||
Sep. 30, 2016 | May 31, 2015 | Dec. 31, 2017 | Oct. 05, 2017 | Dec. 31, 2016 | Sep. 16, 2016 | ||
Debt Instrument [Line Items] | |||||||
Aggregate principal amount | $ 2,877,349 | $ 2,877,849 | |||||
Senior Notes | |||||||
Debt Instrument [Line Items] | |||||||
Maximum redemption price of notes as percentage of principal amount | 101.00% | ||||||
5.875% Senior Notes Due 2022 | |||||||
Debt Instrument [Line Items] | |||||||
Interest rate on notes | 5.875% | 5.875% | 5.875% | ||||
Aggregate principal amount | [1] | $ 329,244 | $ 329,244 | ||||
5.875% Senior Notes Due 2022 | Senior Notes Exchange Offer | Unsecured Debt | |||||||
Debt Instrument [Line Items] | |||||||
Senior notes exchange amount | $ 329,200 | ||||||
Interest rate on notes | 5.875% | 5.875% | |||||
Maximum redemption price of notes as percentage of principal amount | 100.00% | ||||||
5.00% Senior Notes Due 2023 | |||||||
Debt Instrument [Line Items] | |||||||
Senior notes exchange amount | $ 741,531 | ||||||
Interest rate on notes | 5.00% | 5.00% | 5.00% | 5.00% | 5.00% | ||
Aggregate principal amount | $ 741,531 | $ 741,531 | |||||
5.00% Senior Notes Due 2022 | |||||||
Debt Instrument [Line Items] | |||||||
Senior notes exchange amount | $ 580,032 | ||||||
Interest rate on notes | 5.00% | 5.00% | 5.00% | 5.00% | 5.00% | ||
Aggregate principal amount | $ 580,032 | $ 580,032 | |||||
5.75% Senior Notes Due 2021 | |||||||
Debt Instrument [Line Items] | |||||||
Senior notes exchange amount | $ 475,952 | ||||||
Interest rate on notes | 5.75% | 5.75% | 5.75% | 5.75% | 5.75% | ||
Aggregate principal amount | $ 475,952 | $ 475,952 | |||||
4.875% Senior Notes Due 2025 | |||||||
Debt Instrument [Line Items] | |||||||
Interest rate on notes | 4.875% | 4.875% | 4.875% | ||||
Maximum redemption price of notes as percentage of principal amount | 101.00% | ||||||
Aggregate principal amount | $ 750,000 | $ 750,000 | $ 750,000 | ||||
Net proceeds after underwriting discounts and commissions | 737,400 | ||||||
Underwriting discounts and commissions | $ 12,600 | ||||||
[1] | Represents senior notes assumed in the MRD Merger that were not purchased for cash but were exchanged for Range 5.875% senior notes due 2022. See Senior Notes Exchange and Cash Tender Offer below. |
Indebtedness - Summary of Debt
Indebtedness - Summary of Debt Exchange Offer to Exchange Senior Subordinated Notes (Detail) $ in Thousands | 1 Months Ended |
Sep. 30, 2016USD ($) | |
5.00% Senior Notes Due 2023 | |
Debt Instrument [Line Items] | |
Senior notes | $ 741,531 |
5.00% Senior Notes Due 2022 | |
Debt Instrument [Line Items] | |
Senior notes | 580,032 |
5.75% Senior Notes Due 2021 | |
Debt Instrument [Line Items] | |
Senior notes | $ 475,952 |
Indebtedness - Summary of Deb70
Indebtedness - Summary of Debt Exchange Offer to Exchange Senior Subordinated Notes (Parenthetical) (Detail) | Dec. 31, 2017 | Oct. 05, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Sep. 16, 2016 |
5.00% Senior Notes Due 2023 | |||||
Debt Instrument [Line Items] | |||||
Interest rate on notes | 5.00% | 5.00% | 5.00% | 5.00% | 5.00% |
5.00% Senior Notes Due 2022 | |||||
Debt Instrument [Line Items] | |||||
Interest rate on notes | 5.00% | 5.00% | 5.00% | 5.00% | 5.00% |
5.75% Senior Notes Due 2021 | |||||
Debt Instrument [Line Items] | |||||
Interest rate on notes | 5.75% | 5.75% | 5.75% | 5.75% | 5.75% |
Indebtedness - Senior Notes Exc
Indebtedness - Senior Notes Exchange and Cash Tender Offer - Additional Information (Detail) - USD ($) $ in Millions | Sep. 16, 2016 | Dec. 31, 2017 | Oct. 05, 2017 | Dec. 31, 2016 | Sep. 30, 2016 |
5.875% Senior Notes Due 2022 | |||||
Debt Instrument [Line Items] | |||||
Interest rate on notes | 5.875% | 5.875% | 5.875% | ||
Senior Notes Cash Tender Offer | 5.875% Senior Notes Due 2022 | |||||
Debt Instrument [Line Items] | |||||
Early cash tender premium paid | $ 3.3 | ||||
Senior Notes Cash Tender Offer | 5.875% Senior Notes Due 2022 | MRD | |||||
Debt Instrument [Line Items] | |||||
Percentage of outstanding notes acquired | 44.90% | ||||
Principal amount purchased | $ 269.7 | ||||
Senior Notes | |||||
Debt Instrument [Line Items] | |||||
Maximum redemption price of notes as percentage of principal amount | 101.00% | ||||
Senior Notes | Senior Notes Exchange Offer | MRD | |||||
Debt Instrument [Line Items] | |||||
Percentage of outstanding notes exchanged | 54.90% | ||||
Unsecured Debt | Senior Notes Exchange Offer | 5.875% Senior Notes Due 2022 | |||||
Debt Instrument [Line Items] | |||||
Interest rate on notes | 5.875% | 5.875% | |||
Maturity date of loan | Jul. 1, 2022 | ||||
Maximum redemption price of notes as percentage of principal amount | 100.00% | ||||
Deferred financing costs | $ 6.3 | ||||
Early cash tender premium paid | $ 4.1 |
Indebtedness - Summary of Deb72
Indebtedness - Summary of Debt Exchange Offer to Exchange All Validly Tendered and Accepted Range Senior Subordinated Notes (Detail) $ in Thousands | Sep. 16, 2016USD ($) | |
5.00% Senior Subordinated Notes Due 2023 | ||
Debt Instrument [Line Items] | ||
Principal Amount of Notes Validly Tendered | $ 742,291 | [1] |
Approximate Percentage Validly Tendered | 99.00% | |
5.00% Senior Subordinated Notes Due 2022 | ||
Debt Instrument [Line Items] | ||
Principal Amount of Notes Validly Tendered | $ 580,946 | [1] |
Approximate Percentage Validly Tendered | 96.80% | |
5.75% Senior Subordinated Notes Due 2021 | ||
Debt Instrument [Line Items] | ||
Principal Amount of Notes Validly Tendered | $ 477,786 | [1] |
Approximate Percentage Validly Tendered | 95.60% | |
[1] | (1) Prior to exchange premium |
Indebtedness - Summary of Deb73
Indebtedness - Summary of Debt Exchange Offer to Exchange All Validly Tendered and Accepted Range Senior Subordinated Notes (Parenthetical) (Detail) | Dec. 31, 2017 | Oct. 05, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Sep. 16, 2016 |
5.00% Senior Subordinated Notes Due 2023 | |||||
Debt Instrument [Line Items] | |||||
Interest rate on notes | 5.00% | 5.00% | 5.00% | ||
5.00% Senior Subordinated Notes Due 2022 | |||||
Debt Instrument [Line Items] | |||||
Interest rate on notes | 5.00% | 5.00% | 5.00% | ||
5.75% Senior Subordinated Notes Due 2021 | |||||
Debt Instrument [Line Items] | |||||
Interest rate on notes | 5.75% | 5.75% | 5.75% | ||
5.00% Senior Notes Due 2023 | |||||
Debt Instrument [Line Items] | |||||
Interest rate on notes | 5.00% | 5.00% | 5.00% | 5.00% | 5.00% |
5.00% Senior Notes Due 2022 | |||||
Debt Instrument [Line Items] | |||||
Interest rate on notes | 5.00% | 5.00% | 5.00% | 5.00% | 5.00% |
5.75% Senior Notes Due 2021 | |||||
Debt Instrument [Line Items] | |||||
Interest rate on notes | 5.75% | 5.75% | 5.75% | 5.75% | 5.75% |
Indebtedness - Senior Subordina
Indebtedness - Senior Subordinated Notes Exchange- Additional Information (Detail) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |||
Sep. 30, 2016 | Dec. 31, 2017 | Oct. 05, 2017 | Dec. 31, 2016 | Sep. 16, 2016 | |
5.00% Senior Notes Due 2023 | |||||
Debt Instrument [Line Items] | |||||
Interest rate on notes | 5.00% | 5.00% | 5.00% | 5.00% | 5.00% |
Maturity date of loan | Mar. 15, 2023 | ||||
5.00% Senior Notes Due 2022 | |||||
Debt Instrument [Line Items] | |||||
Interest rate on notes | 5.00% | 5.00% | 5.00% | 5.00% | 5.00% |
Maturity date of loan | Aug. 15, 2022 | ||||
5.75% Senior Notes Due 2021 | |||||
Debt Instrument [Line Items] | |||||
Interest rate on notes | 5.75% | 5.75% | 5.75% | 5.75% | 5.75% |
Maturity date of loan | Jun. 1, 2021 | ||||
Senior Notes | |||||
Debt Instrument [Line Items] | |||||
Additional interest expense on senior subordinated notes exchange | $ 6.6 | ||||
Premium recorded in connection with debt exchange | $ 3.5 | ||||
Percentage of premium received on face amount tendered in exchange of debt | 95.00% | ||||
Maximum redemption price of notes as percentage of principal amount | 101.00% |
Indebtedness - Senior Subordi75
Indebtedness - Senior Subordinated Notes and Early Extinguishment of Debt - Additional Information (Detail) - USD ($) $ in Thousands | 1 Months Ended | 12 Months Ended | ||
Jul. 31, 2015 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Debt Instrument [Line Items] | ||||
Loss on early extinguishment of debt | $ 0 | $ 0 | $ 22,495 | |
Subordinated Debt | ||||
Debt Instrument [Line Items] | ||||
Maximum redemption price of notes as percentage of principal amount | 101.00% | |||
Senior Subordinated Notes | 6.75% Senior Subordinated Notes Due 2020 | ||||
Debt Instrument [Line Items] | ||||
Maximum redemption price of notes as percentage of principal amount | 103.375% | |||
Announced call for redemption amount of debt | $ 500,000 | |||
Interest rate on notes | 6.75% | |||
Debt instrument, redemption description | In July 2015, we announced a call for the redemption of $500.0 million of our outstanding 6.75% senior subordinated notes due 2020 at a price of 103.375% of par plus accrued and unpaid interest, which were redeemed on August 3, 2015. In the year ended 2015, we recognized a loss on early extinguishment of debt of $22.5 million, including transaction call premium costs and the expensing of the remaining deferred financing costs on the repurchased debt |
Indebtedness - Guarantees and D
Indebtedness - Guarantees and Debt Covenants and Maturity - Additional Information (Detail) - Bank Credit Facility | 12 Months Ended |
Dec. 31, 2017 | |
Debt Instrument [Line Items] | |
Debt instrument, Covenant compliance | Our bank credit facility contains negative covenants that limit our ability, among other things, to pay cash dividends, incur additional indebtedness, sell assets, enter into certain hedging contracts, change the nature of our business or operations, merge, consolidate, or make certain investments. In addition, we are required to maintain a ratio of EBITDAX (as defined in the credit agreement) to cash interest expense of equal to or greater than 2.5 and a current ratio (as defined in the credit agreement) of no less than 1.0. In addition, the ratio of the present value of proved reserves (as defined in the credit agreement) to total debt must be equal to or greater than 1.5 until Range has two investment grade ratings. We were in compliance with applicable covenants under the bank credit facility at December 31, 2017. |
Maximum | |
Debt Instrument [Line Items] | |
Ratio of debt to EBITDAX | 250.00% |
Present value of proved reserves to total debt | 150.00% |
Minimum | |
Debt Instrument [Line Items] | |
Current ratio | 100.00% |
Indebtedness - Schedule for Lon
Indebtedness - Schedule for Long-Term Debt Outstanding (Detail) $ in Thousands | Dec. 31, 2016USD ($) |
Debt Disclosure [Abstract] | |
2,018 | $ 0 |
2,019 | 1,211,000 |
2,020 | 0 |
2,021 | 498,166 |
2,022 | 928,920 |
Thereafter | 1,499,243 |
Total debt | $ 4,137,329 |
Asset Retirement Obligations -
Asset Retirement Obligations - Asset Retirement Obligations (Detail) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Asset Retirement Obligation [Abstract] | ||
Beginning of period | $ 257,943 | $ 264,137 |
Liabilities incurred | 7,724 | 2,694 |
Acquisitions | 0 | 21,900 |
Liabilities settled | (7,965) | (11,511) |
Disposition of wells | (8,078) | (10,540) |
Accretion expense | 14,711 | 18,021 |
Change in estimate | 12,520 | (26,758) |
End of period | 276,855 | 257,943 |
Less current portion | (6,327) | (7,271) |
Long-term asset retirement obligations | $ 270,528 | $ 250,672 |
Capital Stock - Additional Info
Capital Stock - Additional Information (Detail) - $ / shares | 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, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Class Of Stock Disclosures [Abstract] | |||||||||||||||
Authorized capital stock | 485,000,000 | 485,000,000 | 485,000,000 | 485,000,000 | |||||||||||
Common stock, shares authorized | 475,000,000 | 475,000,000 | 475,000,000 | 475,000,000 | |||||||||||
Preferred stock, shares authorized | 10,000,000 | 10,000,000 | 10,000,000 | 10,000,000 | |||||||||||
Common dividends declared per share | $ 0.02 | $ 0.02 | $ 0.02 | $ 0.02 | $ 0.02 | $ 0.02 | $ 0.02 | $ 0.02 | $ 0.04 | $ 0.04 | $ 0.04 | $ 0.04 | $ 0.08 | $ 0.08 | $ 0.16 |
Capital Stock (Detail)
Capital Stock (Detail) - shares | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Class Of Stock [Line Items] | |||
Beginning balance | 247,144,356 | 169,316,460 | 168,628,177 |
Stock options/SARs exercised | 0 | 0 | 77,002 |
Restricted stock grants | 539,096 | 490,609 | 335,103 |
Shares retired | 0 | (739) | 0 |
Treasury shares | 15,580 | 28,736 | 23,671 |
Ending balance | 248,129,430 | 247,144,356 | 169,316,460 |
MRD | |||
Class Of Stock [Line Items] | |||
MRD Merger | 0 | 77,042,749 | 0 |
Restricted Stock | |||
Class Of Stock [Line Items] | |||
Restricted stock units vested | 344,937 | 266,541 | 252,507 |
Performance Share | |||
Class Of Stock [Line Items] | |||
Performance stock units issued | 85,461 | 0 | 0 |
Derivative Activities - Additio
Derivative Activities - Additional Information (Detail) | 12 Months Ended |
Dec. 31, 2017USD ($)t_per_MMMBTUCounterpartyInstitutionbbl | |
Derivative [Line Items] | |
Number of financial institutions with whom we conduct derivative activities | Institution | 19 |
Number of secured lenders not in banking credit facility | Counterparty | 5 |
Derivatives Excluding Basis Swaps and Freight Swaps | |
Derivative [Line Items] | |
Derivative assets liabilities at fair value net | $ 13,600,000 |
Commodity | Basis Swaps | Natural Gas | |
Derivative [Line Items] | |
Derivative assets liabilities at fair value net | $ (7,800,000) |
Volume Hedged | MMBTU | 120,892,500 |
Commodity | Basis Swaps | Propane | |
Derivative [Line Items] | |
Derivative assets liabilities at fair value net | $ (1,200,000) |
Commodity | Swaps | Freight | Level 2 | |
Derivative [Line Items] | |
Derivative assets liabilities at fair value net | $ 276,000 |
Volume Hedged | t_per_M | 5,000 |
2018 Commodity Contract | Basis Swaps | Propane | |
Derivative [Line Items] | |
Volume Hedged | bbl | 1,362,000 |
Derivative Activities - Derivat
Derivative Activities - Derivative Volumes Hedged and Average Hedge Prices (Detail) | Dec. 31, 2017MMBTU / dbbl / d$ / MMBTU$ / bbl$ / gal | |
2018 Commodity Contract | Swaps | Natural Gas | ||
Derivative [Line Items] | ||
Volume Hedged | MMBTU / d | 794,822 | |
Weighted Average Hedge Price | $ / MMBTU | 3.13 | |
2018 Commodity Contract | Swaps | Crude Oil | ||
Derivative [Line Items] | ||
Volume Hedged | 8,995 | |
Weighted Average Hedge Price | $ / bbl | 53.30 | |
2018 Commodity Contract | Swaps | NGLs (C2-Ethane) | ||
Derivative [Line Items] | ||
Volume Hedged | 250 | |
Weighted Average Hedge Price | $ / gal | 0.29 | |
2018 Commodity Contract | Swaps | NGLs (C3-Propane) | ||
Derivative [Line Items] | ||
Volume Hedged | 10,362 | |
Weighted Average Hedge Price | $ / gal | 0.68 | |
2018 Commodity Contract | Swaps | NGLs (NC4-Normal Butane) | ||
Derivative [Line Items] | ||
Volume Hedged | 4,621 | |
Weighted Average Hedge Price | $ / gal | 0.81 | |
2018 Commodity Contract | Swaps | NGLs (C5-Natural Gasoline) | ||
Derivative [Line Items] | ||
Volume Hedged | 4,713 | |
Weighted Average Hedge Price | $ / gal | 1.19 | |
2018 Commodity Contract | Collars | NGLs (C3-Propane) | ||
Derivative [Line Items] | ||
Volume Hedged | 2,000 | |
Weighted Average Floor Price | $ / gal | 0.90 | |
Weighted Average Cap Price | $ / gal | 1.05 | |
2019 Commodity Contract | Swaps | Natural Gas | ||
Derivative [Line Items] | ||
Volume Hedged | MMBTU / d | 12,329 | |
Weighted Average Hedge Price | $ / MMBTU | 3.01 | |
2019 Commodity Contract | Swaps | Crude Oil | ||
Derivative [Line Items] | ||
Volume Hedged | 4,746 | |
Weighted Average Hedge Price | $ / bbl | 52.81 | |
2019 Commodity Contract | Swaps | NGLs (C5-Natural Gasoline) | ||
Derivative [Line Items] | ||
Volume Hedged | 1,000 | |
Weighted Average Hedge Price | $ / gal | 1.24 | |
2019 Commodity Contract | Swaptions | Natural Gas | ||
Derivative [Line Items] | ||
Volume Hedged | MMBTU / d | 85,000 | |
Weighted Average Hedge Price | $ / MMBTU | 2.97 | [1] |
January−March 2018 Commodity Contract | Collars | Natural Gas | ||
Derivative [Line Items] | ||
Volume Hedged | MMBTU / d | 60,000 | |
Weighted Average Floor Price | $ / MMBTU | 3.40 | |
Weighted Average Cap Price | $ / MMBTU | 3.76 | |
April-December 2018 Commodity Contract | Swaptions | Natural Gas | ||
Derivative [Line Items] | ||
Volume Hedged | MMBTU / d | 307,500 | |
Weighted Average Hedge Price | $ / MMBTU | 2.98 | [1] |
[1] | Contains a combined derivative instrument consisting of a fixed price swap and a sold option to extend or double the volume. For April through December 2018, we have swaps in place for 147,500 Mmbtu per day on which the counterparty can elect to double the volume at a weighted average price of $2.89. We also have swaps in place for 160,000 Mmbtu per day on which the counterparty can elect to extend the contract through December 2019 at a weighted average price of $3.07. In 2019, if the counterparty elects to double the volume, we would have additional swaps covering 85,000 Mmbtu per day at a weighted average price of $2.97. |
Derivative Activities - Deriv83
Derivative Activities - Derivative Volumes Hedged and Average Hedge Prices (Parenthetical) (Detail) - Swaps - Natural Gas | Dec. 31, 2017MMBTU / d$ / shares$ / MMBTU |
April-December 2018 Commodity Contract | Counterparty Can Elect to Double The Volume | |
Derivative [Line Items] | |
Volume Hedged | 147,500 |
Weighted average price of hedge | $ / shares | 2.89 |
April-December 2018 Commodity Contract | Counterparty Can Elect to Extend Contract | |
Derivative [Line Items] | |
Volume Hedged | 160,000 |
Weighted average price of hedge | $ / shares | 3.07 |
2019 Commodity Contract | |
Derivative [Line Items] | |
Volume Hedged | 12,329 |
Weighted average price of hedge | $ / MMBTU | 3.01 |
2019 Commodity Contract | Counterparty Can Elect to Double The Volume | |
Derivative [Line Items] | |
Volume Hedged | 85,000 |
Weighted average price of hedge | $ / shares | 2.97 |
Derivative Activities - Schedul
Derivative Activities - Schedule of Additional Information Related to Master Netting Arrangements with Derivative Counterparties (Detail) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Derivative [Line Items] | ||
Gross Amounts of Recognized Assets | $ 124,647 | $ 77,079 |
Gross Amounts Offset in the Balance Sheet | (65,767) | (63,596) |
Net Amounts of Assets Presented in the Balance Sheet | 58,880 | 13,483 |
Gross Amounts of Recognized (Liabilities) | (119,789) | (253,096) |
Gross Amounts Offset in the Balance Sheet | 65,767 | 63,596 |
Net Amounts of (Liabilities) Presented in the Balance Sheet | (54,022) | (189,500) |
Commodity | Swaps | Natural Gas | ||
Derivative [Line Items] | ||
Gross Amounts of Recognized Assets | 87,794 | 13,213 |
Gross Amounts Offset in the Balance Sheet | (4,106) | (11,425) |
Net Amounts of Assets Presented in the Balance Sheet | 83,688 | 1,788 |
Gross Amounts of Recognized (Liabilities) | (216) | (158,359) |
Gross Amounts Offset in the Balance Sheet | 4,106 | 11,425 |
Net Amounts of (Liabilities) Presented in the Balance Sheet | 3,890 | (146,934) |
Commodity | Swaps | Crude Oil | ||
Derivative [Line Items] | ||
Gross Amounts of Recognized Assets | 2 | 9,356 |
Gross Amounts Offset in the Balance Sheet | (7,928) | (3,489) |
Net Amounts of Assets Presented in the Balance Sheet | (7,926) | 5,867 |
Gross Amounts of Recognized (Liabilities) | (24,726) | (13,206) |
Gross Amounts Offset in the Balance Sheet | 7,928 | 3,489 |
Net Amounts of (Liabilities) Presented in the Balance Sheet | (16,798) | (9,717) |
Commodity | Swaps | NGLs (C2-Ethane) | ||
Derivative [Line Items] | ||
Gross Amounts of Recognized Assets | 57 | 53 |
Gross Amounts Offset in the Balance Sheet | 0 | (53) |
Net Amounts of Assets Presented in the Balance Sheet | 57 | 0 |
Gross Amounts of Recognized (Liabilities) | (1,008) | |
Gross Amounts Offset in the Balance Sheet | 53 | |
Net Amounts of (Liabilities) Presented in the Balance Sheet | (955) | |
Commodity | Swaps | NGLs (C3-Propane) | ||
Derivative [Line Items] | ||
Gross Amounts of Recognized Assets | 0 | |
Gross Amounts Offset in the Balance Sheet | (12,556) | |
Net Amounts of Assets Presented in the Balance Sheet | (12,556) | |
Gross Amounts of Recognized (Liabilities) | (34,325) | (32,437) |
Gross Amounts Offset in the Balance Sheet | 12,556 | 0 |
Net Amounts of (Liabilities) Presented in the Balance Sheet | (21,769) | (32,437) |
Commodity | Swaps | NGLs (NC4-Normal Butane) | ||
Derivative [Line Items] | ||
Gross Amounts of Recognized Assets | 0 | 4 |
Gross Amounts Offset in the Balance Sheet | (6,051) | (4) |
Net Amounts of Assets Presented in the Balance Sheet | (6,051) | 0 |
Gross Amounts of Recognized (Liabilities) | (11,188) | (13,419) |
Gross Amounts Offset in the Balance Sheet | 6,051 | 4 |
Net Amounts of (Liabilities) Presented in the Balance Sheet | (5,137) | (13,415) |
Commodity | Swaps | NGLs (C5-Natural Gasoline) | ||
Derivative [Line Items] | ||
Gross Amounts of Recognized Assets | 0 | |
Gross Amounts Offset in the Balance Sheet | (6,727) | |
Net Amounts of Assets Presented in the Balance Sheet | (6,727) | |
Gross Amounts of Recognized (Liabilities) | (13,488) | (12,176) |
Gross Amounts Offset in the Balance Sheet | 6,727 | 0 |
Net Amounts of (Liabilities) Presented in the Balance Sheet | (6,761) | (12,176) |
Commodity | Swaps | Freight | ||
Derivative [Line Items] | ||
Gross Amounts of Recognized Assets | 276 | 65 |
Gross Amounts Offset in the Balance Sheet | (276) | (65) |
Net Amounts of Assets Presented in the Balance Sheet | 0 | 0 |
Gross Amounts of Recognized (Liabilities) | 0 | 0 |
Gross Amounts Offset in the Balance Sheet | 276 | 65 |
Net Amounts of (Liabilities) Presented in the Balance Sheet | 276 | 65 |
Commodity | Swaptions | Natural Gas | ||
Derivative [Line Items] | ||
Gross Amounts of Recognized Assets | 18,817 | |
Gross Amounts Offset in the Balance Sheet | (8,103) | |
Net Amounts of Assets Presented in the Balance Sheet | 10,714 | |
Gross Amounts of Recognized (Liabilities) | (12,283) | |
Gross Amounts Offset in the Balance Sheet | 8,103 | |
Net Amounts of (Liabilities) Presented in the Balance Sheet | (4,180) | |
Commodity | Basis Swaps | Natural Gas | ||
Derivative [Line Items] | ||
Gross Amounts of Recognized Assets | 1,815 | 12,535 |
Gross Amounts Offset in the Balance Sheet | (6,673) | (9,437) |
Net Amounts of Assets Presented in the Balance Sheet | (4,858) | 3,098 |
Gross Amounts of Recognized (Liabilities) | (9,580) | (687) |
Gross Amounts Offset in the Balance Sheet | 6,673 | 9,437 |
Net Amounts of (Liabilities) Presented in the Balance Sheet | (2,907) | 8,750 |
Commodity | Collars | Natural Gas | ||
Derivative [Line Items] | ||
Gross Amounts of Recognized Assets | 3,039 | 6,298 |
Gross Amounts Offset in the Balance Sheet | (500) | (6,298) |
Net Amounts of Assets Presented in the Balance Sheet | 2,539 | 0 |
Gross Amounts of Recognized (Liabilities) | 0 | (2,625) |
Gross Amounts Offset in the Balance Sheet | 500 | 6,298 |
Net Amounts of (Liabilities) Presented in the Balance Sheet | 500 | 3,673 |
Commodity | Collars | NGLs (C3-Propane) | ||
Derivative [Line Items] | ||
Gross Amounts of Recognized Assets | 85 | |
Gross Amounts Offset in the Balance Sheet | (85) | |
Net Amounts of Assets Presented in the Balance Sheet | 0 | |
Gross Amounts of Recognized (Liabilities) | 0 | |
Gross Amounts Offset in the Balance Sheet | 85 | |
Net Amounts of (Liabilities) Presented in the Balance Sheet | 85 | |
Commodity | Spread Swaps | NGLs (C3-Propane) | ||
Derivative [Line Items] | ||
Gross Amounts of Recognized Assets | 12,762 | 17,396 |
Gross Amounts Offset in the Balance Sheet | (12,762) | (17,396) |
Net Amounts of Assets Presented in the Balance Sheet | 0 | 0 |
Gross Amounts of Recognized (Liabilities) | (13,983) | (18,138) |
Gross Amounts Offset in the Balance Sheet | 12,762 | 17,396 |
Net Amounts of (Liabilities) Presented in the Balance Sheet | $ (1,221) | (742) |
Commodity | Puts | Natural Gas | ||
Derivative [Line Items] | ||
Gross Amounts of Recognized Assets | 18,159 | |
Gross Amounts Offset in the Balance Sheet | (15,429) | |
Net Amounts of Assets Presented in the Balance Sheet | 2,730 | |
Gross Amounts of Recognized (Liabilities) | 0 | |
Gross Amounts Offset in the Balance Sheet | 15,429 | |
Net Amounts of (Liabilities) Presented in the Balance Sheet | 15,429 | |
Commodity | Calls | Natural Gas | ||
Derivative [Line Items] | ||
Gross Amounts of Recognized (Liabilities) | (1,041) | |
Gross Amounts Offset in the Balance Sheet | 0 | |
Net Amounts of (Liabilities) Presented in the Balance Sheet | $ (1,041) |
Derivative Activities - Effects
Derivative Activities - Effects of Derivatives on Consolidated Statements of Operations (Detail) - USD ($) $ in Thousands | 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 | |
Derivative [Line Items] | |||||||||||
Derivative Fair Value Income (Loss) | $ 25,024 | $ (88,426) | $ 111,195 | $ 165,557 | $ (250,057) | $ 64,556 | $ (162,798) | $ 86,908 | $ 213,350 | $ (261,391) | $ 416,364 |
Swaptions | |||||||||||
Derivative [Line Items] | |||||||||||
Derivative Fair Value Income (Loss) | 6,534 | 0 | 0 | ||||||||
Re-purchased Swaps | |||||||||||
Derivative [Line Items] | |||||||||||
Derivative Fair Value Income (Loss) | 0 | 0 | 851 | ||||||||
Collars | |||||||||||
Derivative [Line Items] | |||||||||||
Derivative Fair Value Income (Loss) | 18,132 | (6,926) | 16,539 | ||||||||
Basis Swaps | |||||||||||
Derivative [Line Items] | |||||||||||
Derivative Fair Value Income (Loss) | (4,647) | 29,154 | 954 | ||||||||
Puts | |||||||||||
Derivative [Line Items] | |||||||||||
Derivative Fair Value Income (Loss) | 10,929 | (18,201) | 0 | ||||||||
Calls | |||||||||||
Derivative [Line Items] | |||||||||||
Derivative Fair Value Income (Loss) | 987 | (18) | 0 | ||||||||
Commodity | Swaps | |||||||||||
Derivative [Line Items] | |||||||||||
Derivative Fair Value Income (Loss) | 181,095 | (265,466) | 398,020 | ||||||||
Freight | Commodity | Swaps | |||||||||||
Derivative [Line Items] | |||||||||||
Derivative Fair Value Income (Loss) | $ 320 | $ 66 | $ 0 |
Fair Value Measurements - Fair
Fair Value Measurements - Fair Value Hierarchy Table for Assets and Liabilities Measured at Fair Value (Detail) - Fair Value, Measurements, Recurring - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Trading securities held in the deferred compensation plans | $ 67,117 | $ 61,717 |
Swaps | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Derivative assets liabilities at fair value net | 3,910 | (207,979) |
Swaps | Freight | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Derivative assets liabilities at fair value net | 65 | |
Collars | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Derivative assets liabilities at fair value net | 3,124 | 3,673 |
Puts | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Derivative assets liabilities at fair value net | (8,986) | 18,159 |
Calls | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Derivative assets liabilities at fair value net | 276 | (1,041) |
Basis Swaps | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Derivative assets liabilities at fair value net | 6,534 | 11,106 |
Fair Value, Inputs, Level 1 | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Trading securities held in the deferred compensation plans | 67,117 | 61,717 |
Fair Value, Inputs, Level 3 | Collars | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Derivative assets liabilities at fair value net | 85 | |
Fair Value, Inputs, Level 3 | Puts | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Derivative assets liabilities at fair value net | 39 | |
Fair Value, Inputs, Level 3 | Basis Swaps | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Derivative assets liabilities at fair value net | 6,534 | |
Level 2 | Swaps | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Derivative assets liabilities at fair value net | 3,910 | (207,979) |
Level 2 | Swaps | Freight | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Derivative assets liabilities at fair value net | 65 | |
Level 2 | Collars | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Derivative assets liabilities at fair value net | 3,039 | 3,673 |
Level 2 | Puts | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Derivative assets liabilities at fair value net | (9,025) | 18,159 |
Level 2 | Calls | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Derivative assets liabilities at fair value net | $ 276 | (1,041) |
Level 2 | Basis Swaps | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Derivative assets liabilities at fair value net | $ 11,106 |
Fair Value Measurements - Recon
Fair Value Measurements - Reconciliation of the Beginning and Ending Balances for Derivative Instruments Classified as Level 3 in the Fair Value Hierarchy (Detail) - Fair Value, Inputs, Level 3 $ in Thousands | 12 Months Ended |
Dec. 31, 2017USD ($) | |
Fair Value Assets Measured On Recurring Basis Unobservable Input Reconciliation [Line Items] | |
Balance at the beginning of period | $ 0 |
Total gains (losses) included in earnings | 6,658 |
Balance at end of period | $ 6,658 |
Fair Value Measurements - Addit
Fair Value Measurements - Additional Information (Detail) - USD ($) | 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 | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||||||||||
Interest and dividends | $ 4,100,000 | $ 972,000 | $ 908,000 | ||||||||
Mark-to-market gain (loss) | 4,200,000 | 3,100,000 | (5,900,000) | ||||||||
Impairment on natural gas and oil properties | $ 0 | $ 63,679,000 | $ 0 | $ 0 | $ 0 | $ 0 | $ 0 | $ 43,040,000 | 63,679,000 | 43,040,000 | 590,174,000 |
Oklahoma and Texas Panhandle | |||||||||||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||||||||||
Impairment on natural gas and oil properties | $ 63,700,000 | ||||||||||
Western Oklahoma | |||||||||||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||||||||||
Impairment on natural gas and oil properties | $ 43,000,000 | ||||||||||
Northwest Pennsylvania | |||||||||||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||||||||||
Impairment on natural gas and oil properties | 195,600,000 | ||||||||||
Northern Oklahoma | |||||||||||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||||||||||
Impairment on natural gas and oil properties | 306,600,000 | ||||||||||
Texas Panhandle | |||||||||||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||||||||||
Impairment on natural gas and oil properties | 86,900,000 | ||||||||||
Gulf Coast | |||||||||||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||||||||||
Impairment on natural gas and oil properties | $ 1,100,000 |
Fair Value Measurements - Value
Fair Value Measurements - Value of Assets Measured at Fair Value on Nonrecurring Basis (Detail) - USD ($) $ in Thousands | 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 | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||||||||||
Impairment of proved properties | $ 0 | $ 63,679 | $ 0 | $ 0 | $ 0 | $ 0 | $ 0 | $ 43,040 | $ 63,679 | $ 43,040 | $ 590,174 |
Fair Value, Measurements, Nonrecurring | Natural Gas and Oil Properties | |||||||||||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||||||||||
Fair Value | $ 85,597 | $ 90,150 | 85,597 | 90,150 | 152,230 | ||||||
Impairment of proved properties | $ 63,679 | $ 43,040 | $ 590,174 |
Fair Value Measurements - Carry
Fair Value Measurements - Carrying Amounts and Fair Values of Financial Instruments (Detail) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 | |
Carrying Value | |||
Assets: | |||
Commodity swaps, options and basis swaps | $ 58,880 | $ 13,483 | |
Marketable securities | [1] | 67,117 | 61,717 |
(Liabilities): | |||
Commodity swaps, options and basis swaps | (54,022) | (189,500) | |
Bank credit facility | [2] | (1,211,000) | (882,000) |
Deferred compensation plan | [3] | (114,414) | (139,580) |
Carrying Value | 5.75% Senior Notes Due 2021 | |||
(Liabilities): | |||
Senior notes | [2] | (475,952) | (475,952) |
Carrying Value | 5.00% Senior Notes Due 2022 | |||
(Liabilities): | |||
Senior notes | [2] | (580,032) | (580,032) |
Carrying Value | 5.875% Senior Notes Due 2022 | |||
(Liabilities): | |||
Senior notes | [2] | (329,244) | (329,244) |
Carrying Value | 5.00% Senior Notes Due 2023 | |||
(Liabilities): | |||
Senior notes | [2] | (741,531) | (741,531) |
Carrying Value | Other Senior Notes Due 2022 | |||
(Liabilities): | |||
Senior notes | [2] | (590) | (1,090) |
Carrying Value | 5.75% Senior Subordinated Notes Due 2021 | |||
(Liabilities): | |||
Subordinated debt | [2] | (22,214) | (22,214) |
Carrying Value | 5.00% Senior Subordinated Notes Due 2023 | |||
(Liabilities): | |||
Subordinated debt | [2] | (7,712) | (7,712) |
Carrying Value | 4.875% Senior Notes Due 2025 | |||
(Liabilities): | |||
Senior notes | [2] | (750,000) | (750,000) |
Carrying Value | 5.00% Senior Subordinated Notes Due 2022 | |||
(Liabilities): | |||
Subordinated debt | [2] | (19,054) | (19,054) |
Fair Value | |||
Assets: | |||
Commodity swaps, options and basis swaps | 58,880 | 13,483 | |
Marketable securities | [1] | 67,117 | 61,717 |
(Liabilities): | |||
Commodity swaps, options and basis swaps | (54,022) | (189,500) | |
Bank credit facility | [2] | (1,211,000) | (882,000) |
Deferred compensation plan | [3] | (114,414) | (139,580) |
Fair Value | 5.75% Senior Notes Due 2021 | |||
(Liabilities): | |||
Senior notes | [2] | (493,872) | (496,180) |
Fair Value | 5.00% Senior Notes Due 2022 | |||
(Liabilities): | |||
Senior notes | [2] | (578,727) | (577,132) |
Fair Value | 5.875% Senior Notes Due 2022 | |||
(Liabilities): | |||
Senior notes | [2] | (339,200) | (343,648) |
Fair Value | 5.00% Senior Notes Due 2023 | |||
(Liabilities): | |||
Senior notes | [2] | (735,614) | (735,043) |
Fair Value | Other Senior Notes Due 2022 | |||
(Liabilities): | |||
Senior notes | [2] | (591) | (1,104) |
Fair Value | 5.75% Senior Subordinated Notes Due 2021 | |||
(Liabilities): | |||
Subordinated debt | [2] | (22,192) | (22,325) |
Fair Value | 5.00% Senior Subordinated Notes Due 2023 | |||
(Liabilities): | |||
Subordinated debt | [2] | (7,614) | (7,645) |
Fair Value | 4.875% Senior Notes Due 2025 | |||
(Liabilities): | |||
Senior notes | [2] | (733,755) | (724,688) |
Fair Value | 5.00% Senior Subordinated Notes Due 2022 | |||
(Liabilities): | |||
Subordinated debt | [2] | $ (18,741) | $ (18,387) |
[1] | Marketable securities, which are held in our deferred compensation plans, are actively traded on major exchanges. | ||
[2] | The book value of our bank debt approximates fair value because of its floating rate structure. The fair value of our senior notes and our senior subordinated notes is based on end of period market quotes which are Level 2 inputs. | ||
[3] | The fair value of our deferred compensation plan is updated at the closing price on the balance sheet date which is a Level 1 input. |
Fair Value Measurements - Car91
Fair Value Measurements - Carrying Amounts and Fair Values of Financial Instruments (Parenthetical) (Detail) | Dec. 31, 2017 | Oct. 05, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Sep. 16, 2016 | May 31, 2015 |
5.75% Senior Notes Due 2021 | ||||||
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items] | ||||||
Interest rate on notes | 5.75% | 5.75% | 5.75% | 5.75% | 5.75% | |
5.00% Senior Notes Due 2022 | ||||||
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items] | ||||||
Interest rate on notes | 5.00% | 5.00% | 5.00% | 5.00% | 5.00% | |
5.875% Senior Notes Due 2022 | ||||||
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items] | ||||||
Interest rate on notes | 5.875% | 5.875% | 5.875% | |||
5.00% Senior Notes Due 2023 | ||||||
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items] | ||||||
Interest rate on notes | 5.00% | 5.00% | 5.00% | 5.00% | 5.00% | |
4.875% Senior Notes Due 2025 | ||||||
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items] | ||||||
Interest rate on notes | 4.875% | 4.875% | 4.875% | |||
5.75% Senior Subordinated Notes Due 2021 | ||||||
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items] | ||||||
Interest rate on notes | 5.75% | 5.75% | 5.75% | |||
5.00% Senior Subordinated Notes Due 2022 | ||||||
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items] | ||||||
Interest rate on notes | 5.00% | 5.00% | 5.00% | |||
5.00% Senior Subordinated Notes Due 2023 | ||||||
Fair Value Balance Sheet Grouping Financial Statement Captions [Line Items] | ||||||
Interest rate on notes | 5.00% | 5.00% | 5.00% |
Stock-based Compensation Plan92
Stock-based Compensation Plans - Additional Information (Detail) - USD ($) $ in Thousands | 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 | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||||||||||
Accelerated vesting of equity grants | $ 30,800 | $ 30,800 | |||||||||
Income tax benefit | $ (349,080) | $ (71,992) | $ 57,651 | $ 112,395 | $ (95,581) | $ (13,705) | $ (129,488) | $ (41,976) | (251,026) | $ (280,750) | $ (338,677) |
Equity Compensation | |||||||||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||||||||||
Income tax benefit | $ 5,300 | $ 5,700 | |||||||||
2005 Equity Based Compensation Plan | |||||||||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||||||||||
Number of shares issued under the plans | 5,600,000 | ||||||||||
1999 Stock Option Plan | |||||||||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||||||||||
Awards granted | 0 |
Stock-based Compensation Plan93
Stock-based Compensation Plans - Allocation of Stock-Based Compensation by Functional Category (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||||
Dec. 31, 2017 | [1] | Dec. 31, 2016 | Dec. 31, 2015 | ||
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items] | |||||
Stock-based compensation expense | $ 82,776 | $ 55,618 | $ 57,801 | ||
Direct Operating Expense | |||||
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items] | |||||
Stock-based compensation expense | 2,060 | 2,302 | 2,780 | ||
Brokered Natural Gas and Marketing Expense | |||||
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items] | |||||
Stock-based compensation expense | 1,437 | 1,725 | 2,132 | ||
Exploration Expense | |||||
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items] | |||||
Stock-based compensation expense | [2] | 2,742 | 2,298 | 2,985 | |
General and Administrative Expense | |||||
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items] | |||||
Stock-based compensation expense | 74,873 | 49,293 | 49,687 | ||
Termination Costs | |||||
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items] | |||||
Stock-based compensation expense | $ 1,664 | $ 0 | $ 217 | ||
[1] | Includes $30.8 million accelerated vesting of equity grants. | ||||
[2] | Includes cost incurred whether capitalized or expensed. |
Stock-based Compensation Plan94
Stock-based Compensation Plans - Allocation of Stock-Based Compensation by Functional Category (Parenthetical) (Detail) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended |
Dec. 31, 2017 | Dec. 31, 2017 | |
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract] | ||
Accelerated vesting of equity grants | $ 30.8 | $ 30.8 |
Stock-based Compensation Plan95
Stock-based Compensation Plans - Additional Information 1 (Detail) | 12 Months Ended | |||
Dec. 31, 2017Awardshares | Dec. 31, 2016shares | Dec. 31, 2015shares | Dec. 31, 2014shares | |
Restricted Stock Equity Awards | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Vesting period | 3 years | 3 years | 3 years | |
Performance Share | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Vesting period | 3 years | |||
Number of awards available for grant | 3 | |||
Performance Share | Common Stock | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Number of share value each unit represents at grant date | shares | 1 | |||
Performance-based PG-PSUs and RG-PSUs | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Vesting period | 3 years | |||
Number of awards available for grant | 2 | |||
Performance-based PG-PSUs and RG-PSUs | Minimum | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Potential payout of shares granted | 0.00% | |||
Performance-based PG-PSUs and RG-PSUs | Maximum | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Potential payout of shares granted | 150.00% | |||
Performance Based TSR - PSUs | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Vesting period | 3 years | |||
Number of awards available for grant | 1 | |||
Performance Based TSR - PSUs | Minimum | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Potential payout of shares granted | 0.00% | 0.00% | 0.00% | |
Performance Based TSR - PSUs | Maximum | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Potential payout of shares granted | 150.00% | 150.00% | 150.00% | |
Stock Appreciation Rights (SARs) | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Number of stock option outstanding | shares | 382,779 | 1,003,600 | 1,510,977 | 1,966,549 |
Stock-based Compensation Plan96
Stock-based Compensation Plans - Additional Information 2 (Detail) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 12 Months Ended | |||
Dec. 31, 2017 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | ||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||||
Stock-based compensation expense | $ 82,776 | [1] | $ 55,618 | $ 57,801 | |
Accelerated vesting of equity grants | $ 30,800 | 30,800 | |||
Proceeds from the sales of common stock held by the deferred compensation plan | $ 4,482 | $ 13,102 | $ 8,298 | ||
Restricted Stock Equity Awards | |||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||||
Granted | 888,326 | 973,491 | 587,711 | ||
Vesting period | 3 years | 3 years | 3 years | ||
Stock-based compensation expense | $ 23,400 | $ 22,800 | $ 23,800 | ||
Unrecognized compensation related to Awards | 24,400 | $ 24,400 | |||
Weighted average period | 1 year 8 months 12 days | ||||
Granted, weighted average grant date fair value | $ 32.61 | $ 28.51 | $ 52.29 | ||
Restricted Stock Liability Awards | |||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||||
Granted | 543,438 | 540,128 | 343,397 | ||
Stock-based compensation expense | $ 30,400 | $ 18,600 | $ 20,800 | ||
Unrecognized compensation related to Awards | $ 1,700 | $ 1,700 | |||
Weighted average period | 1 year 7 months 6 days | ||||
Granted, weighted average grant date fair value | $ 25.91 | $ 35.92 | $ 55.92 | ||
Accelerated vesting of equity grants | $ 15,400 | ||||
Restricted Stock Liability Awards | Non Employee Director | |||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||||
Granted | 90,000 | 59,000 | 48,000 | ||
Restricted Stock Liability Awards | Employees | |||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||||
Granted | 453,000 | 481,000 | 295,000 | ||
Vesting period | 3 years | 3 years | 3 years | ||
[1] | Includes $30.8 million accelerated vesting of equity grants. |
Stock-based Compensation Plan97
Stock-based Compensation Plans - Restricted Stock and Restricted Stock Units Outstanding (Detail) - $ / shares | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Restricted Stock Equity Awards | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Outstanding, Beginning Balance | 765,971 | 436,764 | 360,415 |
Granted | 888,326 | 973,491 | 587,711 |
Vested | (698,563) | (525,617) | (480,253) |
Forfeited | (122,676) | (118,667) | (31,109) |
Outstanding, Ending Balance | 833,058 | 765,971 | 436,764 |
Outstanding, Beginning Balance, weighted average grant date fair value | $ 33.62 | $ 59.74 | $ 79.60 |
Granted, weighted average grant date fair value | 32.61 | 28.51 | 52.29 |
Vested, weighted average grant date fair value | 34.82 | 43.83 | 65.21 |
Forfeited, weighted average grant date fair value | 32.91 | 42.60 | 64.73 |
Outstanding, Ending Balance, weighted average grant date fair value | $ 31.64 | $ 33.62 | $ 59.74 |
Restricted Stock Liability Awards | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Outstanding, Beginning Balance | 425,018 | 308,737 | 304,504 |
Granted | 543,438 | 540,128 | 343,397 |
Vested | (908,912) | (374,328) | (330,870) |
Forfeited | (4,342) | (49,519) | (8,294) |
Outstanding, Ending Balance | 55,202 | 425,018 | 308,737 |
Outstanding, Beginning Balance, weighted average grant date fair value | $ 43.48 | $ 65.80 | $ 80.33 |
Granted, weighted average grant date fair value | 25.91 | 35.92 | 55.92 |
Vested, weighted average grant date fair value | 33.71 | 51.40 | 68.71 |
Forfeited, weighted average grant date fair value | 31.10 | 40.33 | 74.22 |
Outstanding, Ending Balance, weighted average grant date fair value | $ 32.26 | $ 43.48 | $ 65.80 |
Stock-based Compensation Plan98
Stock-based Compensation Plans - Additional Information 3 (Detail) - USD ($) | 3 Months Ended | 12 Months Ended | |||
Dec. 31, 2017 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | ||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||||
Stock-based compensation expense | $ 82,776,000 | [1] | $ 55,618,000 | $ 57,801,000 | |
Accelerated vesting of equity grants | $ 30,800,000 | 30,800,000 | |||
Total intrinsic value of stock options and SARs exercised | 0 | 0 | 5,400,000 | ||
Aggregate intrinsic value of the awards outstanding | 0 | 0 | |||
Aggregate intrinsic value of the awards exercisable | 0 | $ 0 | |||
Maximum | |||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||||
Weighted average remaining contractual life of awards exercisable | 1 year | ||||
Performance-based PG-PSUs and RG-PSUs | |||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||||
Vesting period | 3 years | ||||
Stock-based compensation expense | $ 1,800,000 | ||||
Accelerated vesting of equity grants | $ 1,500,000 | ||||
Performance Based TSR - PSUs | |||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||||
Vesting period | 3 years | ||||
Stock-based compensation expense | $ 24,800,000 | $ 12,400,000 | $ 8,700,000 | ||
Accelerated vesting of equity grants | $ 13,000,000 | ||||
Performance Share | |||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||||
Vesting period | 3 years | ||||
Unrecognized compensation related to Awards | 1,200,000 | $ 1,200,000 | |||
Weighted average period | 2 years | ||||
Stock Appreciation Rights (SARs) | |||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||||
Unrecognized compensation related to Awards | $ 0 | $ 0 | |||
Number of fully vested awards and awards expected to vest | 383,000 | 383,000 | |||
Weighted average exercise price of fully vested awards and awards expected to vest | $ 76.54 | $ 76.54 | |||
Weighted average exercise price of fully vested awards and awards expected to vest in years | 4 months 24 days | ||||
[1] | Includes $30.8 million accelerated vesting of equity grants. |
Stock-based Compensation Plan99
Stock-based Compensation Plans - PG/RG-PSUs Activities (Detail) - Performance-based PG-PSUs and RG-PSUs | 12 Months Ended | |
Dec. 31, 2017$ / sharesshares | ||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||
Outstanding, Beginning Balance | shares | 0 | |
Granted | shares | 122,921 | [1] |
Outstanding, Ending Balance | shares | 122,921 | |
Outstanding, Beginning Balance, weighted average grant date fair value | $ / shares | $ 0 | |
Granted, weighted average grant date fair value | $ / shares | 25.53 | [1] |
Outstanding, Ending Balance, weighted average grant date fair value | $ / shares | $ 25.53 | |
[1] | Amounts granted reflect the number of performance units granted; however, the actual payout of shares will be between zero and 150% depending on achievement of specifically identified performance targets. |
Stock-based Compensation Pla100
Stock-based Compensation Plans - PG/RG-PSUs Activities (Parenthetical) (Detail) - Performance-based PG-PSUs and RG-PSUs | 12 Months Ended |
Dec. 31, 2017 | |
Minimum | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |
Potential payout of shares granted | 0.00% |
Maximum | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |
Potential payout of shares granted | 150.00% |
Stock-based Compensation Pla101
Stock-based Compensation Plans - Valuation Assumptions for Grant Date Fair Value of Performance Awards (Detail) - Performance Shares - $ / shares | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Risk-free interest rate | 1.49% | 0.94% | 1.02% |
Expected annual volatility | 44.00% | 49.00% | 33.00% |
Grant date fair value per unit | $ 26.26 | $ 36.64 | $ 56.78 |
Stock-based Compensation Pla102
Stock-based Compensation Plans - TSR - PSUs Activities (Detail) - Performance Based TSR - PSUs - $ / shares | 12 Months Ended | |||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | ||
Summary of Performance Share Unit Awards outstanding, Number of Units | ||||
Outstanding, Beginning Balance | 871,299 | 499,943 | 226,418 | |
Granted | [1] | 358,519 | 413,959 | 276,204 |
Vested and issued | [2] | (85,461) | ||
Forfeited | (134,515) | (42,603) | (2,679) | |
Outstanding, Ending Balance | 1,009,842 | 871,299 | 499,943 | |
Summary of Performance Share Unit Awards outstanding, Weighted Average Grant Date Fair Value | ||||
Outstanding, Beginning Balance, weighted average grant date fair value | $ 55.29 | $ 69.95 | $ 86.16 | |
Granted, weighted average grant date fair value | [1] | 26.26 | 36.64 | 56.78 |
Vested, weighted average grant date fair value | [2] | 86.23 | ||
Forfeited, weighted average grant date fair value | 85.24 | 46.09 | 82.60 | |
Outstanding, Ending Balance, weighted average grant date fair value | $ 38.38 | $ 55.29 | $ 69.95 | |
[1] | These amounts reflect the number of performance units granted. The actual payout of shares may be between zero and 150% of the performance units granted depending on the total shareholder return ranking compared to our peer companies at the vesting date. | |||
[2] | Includes 85,461 TSR-PSU awards issued related to the 2014 performance period where the return on our common stock was the 67th percentile for the February 2014 grant and 56th percentile for the May 2014 grant. The remaining 2014 awards are considered to be forfeited. |
Stock-based Compensation Pla103
Stock-based Compensation Plans - TSR - PSUs Activities (Parenthetical) (Detail) - Performance Based TSR - PSUs - shares | 12 Months Ended | |||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | ||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Shares vested and issued related to performance period number of common stock | [1] | 85,461 | ||
February 2014 Grant | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Return on common stock percentile | 67.00% | |||
May 2014 Grant | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Return on common stock percentile | 56.00% | |||
Minimum | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Potential payout of shares on performance units granted | 0.00% | 0.00% | 0.00% | |
Maximum | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Potential payout of shares on performance units granted | 150.00% | 150.00% | 150.00% | |
[1] | Includes 85,461 TSR-PSU awards issued related to the 2014 performance period where the return on our common stock was the 67th percentile for the February 2014 grant and 56th percentile for the May 2014 grant. The remaining 2014 awards are considered to be forfeited. |
Stock-based Compensation Pla104
Stock-based Compensation Plans - Stock Option and SARs Activities (Detail) - $ / shares | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Exercised, Shares | 0 | 0 | (77,002) |
Stock Appreciation Rights (SARs) | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Beginning Balance, Shares | 1,003,600 | 1,510,977 | 1,966,549 |
Exercised, Shares | (427,598) | ||
Expired/forfeited, Shares | (620,821) | (507,377) | (27,974) |
Ending Balance, Shares | 382,779 | 1,003,600 | 1,510,977 |
Beginning Balance, Weighted Average Exercise Price | $ 69.08 | $ 63.73 | $ 59.80 |
Exercised, Weighted Average Exercise Price | 45.67 | ||
Expired/forfeited, Weighted Average Exercise Price | 62.29 | 53.16 | 63.10 |
Ending Balance, Weighted Average Exercise Price | $ 76.54 | $ 69.08 | $ 63.73 |
Stock-based Compensation Pla105
Stock-based Compensation Plans - Summary of SARs Outstanding and Exercisable (Detail) - Stock Appreciation Rights (SARs) - $ / shares | 12 Months Ended | |||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items] | ||||
Number of outstanding Number of exercisable, Shares | 382,779 | |||
Weighted Average Remaining Contractual Life (in years) | 4 months 9 days | |||
Weighted Average Exercise Price, Outstanding | $ 76.54 | $ 69.08 | $ 63.73 | $ 59.80 |
Number of exercisable, Shares | 382,779 | |||
Weighted Average Exercise Price, Exercisable | $ 76.54 | |||
Range of Exercise Prices One | ||||
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items] | ||||
Exercise Price, Minimum | 70 | |||
Exercise Price, Maximum | $ 79.99 | |||
Number of outstanding Number of exercisable, Shares | 380,879 | |||
Weighted Average Remaining Contractual Life (in years) | 4 months 9 days | |||
Weighted Average Exercise Price, Outstanding | $ 76.51 | |||
Number of exercisable, Shares | 380,879 | |||
Weighted Average Exercise Price, Exercisable | $ 76.51 | |||
Range of Exercise Prices Two | ||||
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range [Line Items] | ||||
Exercise Price, Minimum | 80 | |||
Exercise Price, Maximum | $ 81.15 | |||
Number of outstanding Number of exercisable, Shares | 1,900 | |||
Weighted Average Remaining Contractual Life (in years) | 8 months 8 days | |||
Weighted Average Exercise Price, Outstanding | $ 81.15 | |||
Number of exercisable, Shares | 1,900 | |||
Weighted Average Exercise Price, Exercisable | $ 81.15 |
Stock-based Compensation Pla106
Stock-based Compensation Plans - Additional Information 4 (Detail) - USD ($) shares 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 | |
Defined Benefit Plan Disclosure [Line Items] | |||||||||||
Maximum percentage of employees contribution | 75.00% | ||||||||||
Maximum percentage of employers contribution in cash | 6.00% | ||||||||||
Employer contribution | $ 5,100,000 | $ 4,700,000 | $ 6,100,000 | ||||||||
Deferred compensation plan vesting period | 3 years | ||||||||||
Deferred compensation plan | $ 14,077,000 | $ 9,203,000 | $ 14,466,000 | $ 13,169,000 | $ 11,013,000 | $ 11,636,000 | $ (25,746,000) | $ (16,056,000) | $ 50,915,000 | $ (19,153,000) | $ 77,627,000 |
Shares held in rabbi trust total | 2.9 | 2.7 | 2.9 | 2.7 | |||||||
Vested shares held in rabbi trust | 2.8 | 2.3 | 2.8 | 2.3 | |||||||
Post-Retirement Medical Plan | |||||||||||
Defined Benefit Plan Disclosure [Line Items] | |||||||||||
Expected future benefit payments for the five year period 2018 through 2022 | $ 675,000 | $ 675,000 | |||||||||
Expected future benefit payments for the five year period 2023 through 2027 | 638,000 | 638,000 | |||||||||
Estimated prior service cost amortized from accumulated other comprehensive income into statement of operation in 2018 | $ 369,000 | $ 369,000 |
Stock-based Compensation Pla107
Stock-based Compensation Plans - Summary of Change in Benefit Obligations Recognized in Comprehensive Income on Pre-tax Basis and Amounts Recognized in Consolidated Balance Sheets (Detail) - Other Post Retirement Benefits $ in Thousands | Dec. 31, 2017USD ($) |
Defined Benefit Plan Disclosure [Line Items] | |
Accumulated benefit obligation | $ 1,769 |
Change in benefit obligations (recognized in comprehensive income – pretax) | |
Prior service cost | 1,769 |
Total other comprehensive income (loss) at December 31, 2017 | 1,769 |
Amounts recognized in the consolidated balance sheets: | |
Noncurrent liability-accrued benefit cost | $ 1,769 |
Stock-based Compensation Pla108
Stock-based Compensation Plans - Summary of Assumptions Used to Determine Benefit Obligation (Detail) - Other Post Retirement Benefits | 12 Months Ended |
Dec. 31, 2017 | |
Weighted average assumptions used to determine benefit obligation: | |
Discount rate | 3.30% |
Assumed weighted average healthcare cost trend rates: | |
Initial healthcare trend rate | 7.00% |
Ultimate trend rate | 5.00% |
Year ultimate trend rate reached | 2,028 |
Supplemental Cash Flow Infor109
Supplemental Cash Flow Information - Supplemental Cash Flow Information (Detail) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | ||
Net cash provided from operating activities included: | ||||
Income taxes (refunded from) paid to taxing authorities | $ (1,024) | $ (102) | $ 100 | |
Interest paid | 179,431 | 159,875 | 168,826 | |
Non-cash investing and financing activities included: | ||||
Asset retirement costs capitalized, net | [1],[2] | 20,245 | (24,064) | 22,184 |
Increase (decrease) in accrued capital expenditures | [1] | $ 71,739 | $ 61,419 | $ (225,455) |
[1] | For additional information on non-cash investing activities associated with the MRD Merger, see Note 3 | |||
[2] | Includes cost incurred whether capitalized or expensed. |
Commitments and Contingencies -
Commitments and Contingencies - Additional Information (Detail) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017USD ($)bbl / dMcf / d | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | |
Commitments And Contingencies Disclosure [Line Items] | |||
Rent expense under operating leases | $ | $ 19.1 | $ 14 | $ 15.9 |
Transportation and gathering commitments contingent upon pipeline construction or modification, term of contract | 20 years | ||
Minimum remaining terms of leases on undeveloped acreage, in years | 3 years | ||
Maximum remaining terms of leases on undeveloped acreage, in years | 5 years | ||
2,018 | |||
Commitments And Contingencies Disclosure [Line Items] | |||
Delivery commitments contingent upon pipeline construction or modification per day | bbl / d | 13,000 | ||
Natural Gas | 2038 | |||
Commitments And Contingencies Disclosure [Line Items] | |||
Transportation commitments contingent upon pipeline construction or modification | 400,000 | ||
Natural Gas | Late 2018 | |||
Commitments And Contingencies Disclosure [Line Items] | |||
Delivery commitments contingent upon pipeline construction or modification per day | 15,000 | ||
Natural Gas | Early 2019 | |||
Commitments And Contingencies Disclosure [Line Items] | |||
Delivery commitments contingent upon pipeline construction or modification per day | 65,000 | ||
Natural Gas | Late 2019 | |||
Commitments And Contingencies Disclosure [Line Items] | |||
Delivery commitments contingent upon pipeline construction or modification per day | 180,000 | ||
North Louisiana | |||
Commitments And Contingencies Disclosure [Line Items] | |||
Remaining liability for expected volume deficiency payments | $ | $ 25.1 |
Commitments and Contingencie111
Commitments and Contingencies - Future Minimum Lease Commitments (Detail) $ in Thousands | Dec. 31, 2017USD ($) |
Commitments And Contingencies Disclosure [Abstract] | |
2,018 | $ 18,498 |
2,019 | 17,803 |
2,020 | 16,945 |
2,021 | 14,249 |
2,022 | 8,058 |
Thereafter | 32,909 |
Operating Lease Obligations | 108,462 |
2,018 | 3,472 |
2,019 | 3,472 |
2,020 | 3,174 |
2,021 | 2,578 |
2,022 | 215 |
Sublease Rental Receipts | $ 12,911 |
Commitments and Contingencie112
Commitments and Contingencies - Schedule of Future Minimum Transportation Fees Due (Detail) $ in Thousands | Dec. 31, 2017USD ($) | [1] |
Disclosure Commitments And Contingencies Schedule Of Future Minimum Transportation And Gathering Fees [Abstract] | ||
2,018 | $ 805,161 | |
2,019 | 825,231 | |
2,020 | 767,090 | |
2,021 | 733,133 | |
2,022 | 691,968 | |
Thereafter | 4,689,133 | |
Transportation, Gathering and Processing Contracts | $ 8,511,716 | |
[1] | The amounts in this table represent the gross amounts that we are committed to pay; however, we will record in our financial statements our proportionate share of costs based on our working interest which can vary based on volumes produced. |
Commitments and Contingencie113
Commitments and Contingencies - Future Delivery Commitments (Detail) | 12 Months Ended |
Dec. 31, 2017MMBTU / dbbl / d | |
2018 | Natural Gas | |
Commitments And Contingencies Disclosure [Line Items] | |
Oil and Gas Delivery Commitments and Contracts, Daily Production | MMBTU / d | 382,534 |
2018 | Ethane and Propane | |
Commitments And Contingencies Disclosure [Line Items] | |
Oil and Gas Delivery Commitments and Contracts, Daily Production | bbl / d | 71,000 |
2019 | Natural Gas | |
Commitments And Contingencies Disclosure [Line Items] | |
Oil and Gas Delivery Commitments and Contracts, Daily Production | MMBTU / d | 364,356 |
2019 | Ethane and Propane | |
Commitments And Contingencies Disclosure [Line Items] | |
Oil and Gas Delivery Commitments and Contracts, Daily Production | bbl / d | 55,932 |
2020 | Natural Gas | |
Commitments And Contingencies Disclosure [Line Items] | |
Oil and Gas Delivery Commitments and Contracts, Daily Production | MMBTU / d | 252,878 |
2020 | Ethane and Propane | |
Commitments And Contingencies Disclosure [Line Items] | |
Oil and Gas Delivery Commitments and Contracts, Daily Production | bbl / d | 48,625 |
2021 | Natural Gas | |
Commitments And Contingencies Disclosure [Line Items] | |
Oil and Gas Delivery Commitments and Contracts, Daily Production | MMBTU / d | 116,189 |
2021 | Ethane and Propane | |
Commitments And Contingencies Disclosure [Line Items] | |
Oil and Gas Delivery Commitments and Contracts, Daily Production | bbl / d | 48,000 |
2022 | Natural Gas | |
Commitments And Contingencies Disclosure [Line Items] | |
Oil and Gas Delivery Commitments and Contracts, Daily Production | MMBTU / d | 68,712 |
2022 | Ethane and Propane | |
Commitments And Contingencies Disclosure [Line Items] | |
Oil and Gas Delivery Commitments and Contracts, Daily Production | bbl / d | 43,000 |
2023 | Natural Gas | |
Commitments And Contingencies Disclosure [Line Items] | |
Oil and Gas Delivery Commitments and Contracts, Daily Production | MMBTU / d | 0 |
2023 | Ethane and Propane | |
Commitments And Contingencies Disclosure [Line Items] | |
Oil and Gas Delivery Commitments and Contracts, Daily Production | bbl / d | 35,000 |
2024 - 2028 | Natural Gas | |
Commitments And Contingencies Disclosure [Line Items] | |
Oil and Gas Delivery Commitments and Contracts, Daily Production | MMBTU / d | 0 |
2024 - 2028 | Ethane and Propane | |
Commitments And Contingencies Disclosure [Line Items] | |
Oil and Gas Delivery Commitments and Contracts, Daily Production | bbl / d | 35,000 |
2029 - 2031 | Natural Gas | |
Commitments And Contingencies Disclosure [Line Items] | |
Oil and Gas Delivery Commitments and Contracts, Daily Production | MMBTU / d | 0 |
2029 - 2031 | Ethane and Propane | |
Commitments And Contingencies Disclosure [Line Items] | |
Oil and Gas Delivery Commitments and Contracts, Daily Production | bbl / d | 20,000 |
Office Closing and Exit Costs -
Office Closing and Exit Costs - Additional Information (Detail) - USD ($) | 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, 2014 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Restructuring Cost And Reserve [Line Items] | ||||||||||||
Termination costs | $ (279,000) | $ (47,000) | $ (96,000) | $ 4,192,000 | $ (822,000) | $ 136,000 | $ 5,000 | $ 162,000 | $ 8,400,000 | $ 3,770,000 | $ (519,000) | $ 15,070,000 |
Stock-based compensation expense (gain) | 1,664,000 | 0 | 217,000 | |||||||||
Building lease | (70,000) | 303,000 | 3,147,000 | |||||||||
Accrued severance costs | $ 2,176,000 | (822,000) | 11,706,000 | |||||||||
MRD | ||||||||||||
Restructuring Cost And Reserve [Line Items] | ||||||||||||
Termination costs | 0 | |||||||||||
Office closing costs | $ 0 | |||||||||||
Oklahoma City Restructuring | ||||||||||||
Restructuring Cost And Reserve [Line Items] | ||||||||||||
Additional accruals for severance costs | 275,000 | |||||||||||
Stock-based compensation expense (gain) | 948,000 | |||||||||||
Virginia and West Virginia Properties and Other | ||||||||||||
Restructuring Cost And Reserve [Line Items] | ||||||||||||
Additional accruals for severance costs | 11,400,000 | |||||||||||
Stock-based compensation expense (gain) | $ (731,000) |
Office Closing and Exit Cost115
Office Closing and Exit Costs - Exit Costs Included in Accrued Liabilities in Consolidated Balance Sheet (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Exit costs included in accrued liabilities in consolidated balance sheet | |||
Beginning balance | $ 2,460 | $ 11,630 | |
Accrued severance costs | 2,176 | (822) | $ 11,706 |
Accrued building rent | (70) | 303 | |
Payments | (2,711) | (8,651) | |
Ending balance | $ 1,855 | $ 2,460 | $ 11,630 |
Office Closing and Exit Cost116
Office Closing and Exit Costs - Summary of Termination Costs (Detail) - USD ($) $ in Thousands | 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, 2014 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Statement Of Financial Position [Abstract] | ||||||||||||
Severance costs | $ 2,176 | $ (822) | $ 11,706 | |||||||||
Building lease | (70) | 303 | 3,147 | |||||||||
Stock-based compensation | 1,664 | 0 | 217 | |||||||||
Total termination costs | $ (279) | $ (47) | $ (96) | $ 4,192 | $ (822) | $ 136 | $ 5 | $ 162 | $ 8,400 | $ 3,770 | $ (519) | $ 15,070 |
Selected Quarterly Financial117
Selected Quarterly Financial Data (Unaudited) - Additional Information (Detail) - USD ($) $ in Thousands | 3 Months Ended | 9 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, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Selected Quarterly Financial Information [Line Items] | ||||||||||||
Impairment of proved properties and other | $ 0 | $ 63,679 | $ 0 | $ 0 | $ 0 | $ 0 | $ 0 | $ 43,040 | $ 63,679 | $ 43,040 | $ 590,174 | |
MRD Merger expenses | $ 813 | $ 33,791 | $ 2,621 | 0 | $ 37,200 | $ 0 | $ 37,225 | $ 0 | ||||
Oklahoma and Texas Properties | ||||||||||||
Selected Quarterly Financial Information [Line Items] | ||||||||||||
Impairment of proved properties and other | $ 63,700 | |||||||||||
Western Oklahoma Properties | ||||||||||||
Selected Quarterly Financial Information [Line Items] | ||||||||||||
Impairment of proved properties and other | $ 43,000 |
Selected Quarterly Financial118
Selected Quarterly Financial Data (Unaudited) - Selected Quarterly Financial Data (Detail) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 9 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, 2014 | Dec. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Revenues and other income: | |||||||||||||
Natural gas, NGLs and oil sales | $ 603,159 | $ 507,541 | $ 506,137 | $ 559,450 | $ 458,645 | $ 304,477 | $ 224,606 | $ 209,487 | $ 2,176,287 | $ 1,197,215 | $ 1,089,644 | ||
Derivative fair value income (loss) | 25,024 | (88,426) | 111,195 | 165,557 | (250,057) | 64,556 | (162,798) | 86,908 | 213,350 | (261,391) | 416,364 | ||
Brokered natural gas, marketing and other | 50,849 | 63,117 | 55,779 | 51,648 | 44,934 | 44,174 | 39,989 | 35,018 | 221,393 | 164,115 | 92,060 | ||
Total revenues and other income | 679,032 | 482,232 | 673,111 | 776,655 | 253,522 | 413,207 | 101,797 | 331,413 | 2,611,030 | 1,099,939 | 1,598,068 | ||
Costs and expenses: | |||||||||||||
Direct operating | 37,921 | 36,888 | 31,420 | 28,023 | 30,276 | 22,387 | 20,671 | 24,054 | 134,252 | 97,388 | 136,363 | ||
Transportation, gathering, processing and compression | 200,300 | 191,645 | 191,590 | 177,648 | 164,338 | 138,764 | 136,844 | 125,263 | 761,183 | 565,209 | 396,739 | ||
Production and ad valorem taxes | 11,757 | 11,993 | 9,969 | 9,163 | 6,790 | 6,717 | 6,049 | 5,887 | 42,882 | 25,443 | 33,860 | ||
Brokered natural gas and marketing | 51,131 | 59,773 | 55,857 | 53,550 | 46,471 | 44,622 | 40,925 | 36,558 | 220,311 | 168,576 | 115,866 | ||
Exploration | 7,893 | 22,767 | 14,498 | 8,504 | 13,684 | 6,943 | 6,785 | 4,913 | 53,662 | 32,325 | 21,406 | ||
Abandonment and impairment of unproved properties | 217,544 | 42,568 | 5,193 | 4,420 | 6,307 | 6,082 | 7,059 | 10,628 | 269,725 | 30,076 | 47,619 | ||
General and administrative | 80,553 | 53,035 | 52,322 | 47,496 | 57,027 | 41,024 | 46,064 | 40,657 | 233,406 | 184,772 | 194,015 | ||
MRD Merger expenses | 813 | 33,791 | 2,621 | 0 | $ 37,200 | 0 | 37,225 | 0 | |||||
Termination costs | (279) | (47) | (96) | 4,192 | (822) | 136 | 5 | 162 | $ 8,400 | 3,770 | (519) | 15,070 | |
Deferred compensation plan | (14,077) | (9,203) | (14,466) | (13,169) | (11,013) | (11,636) | 25,746 | 16,056 | (50,915) | 19,153 | (77,627) | ||
Interest | 51,473 | 49,179 | 47,926 | 47,101 | 46,749 | 45,967 | 37,758 | 37,739 | 195,679 | 168,213 | 166,439 | ||
Loss on early extinguishment of debt | 0 | 0 | 22,495 | ||||||||||
Depletion, depreciation and amortization | 162,918 | 159,749 | 152,504 | 149,821 | 149,662 | 131,489 | 122,390 | 120,561 | 624,992 | 524,102 | 581,155 | ||
Impairment of proved properties and other | 0 | 63,679 | 0 | 0 | 0 | 0 | 0 | 43,040 | 63,679 | 43,040 | 590,174 | ||
(Gain) loss on the sale of assets | (207) | (102) | (807) | (22,600) | (470) | 2,597 | 3,304 | 1,643 | (23,716) | 7,074 | 406,856 | ||
Total costs and expenses | 806,927 | 681,924 | 545,910 | 494,149 | 509,812 | 468,883 | 456,221 | 467,161 | 2,528,910 | 1,902,077 | 2,650,430 | ||
Income (loss) before income taxes | (127,895) | (199,692) | 127,201 | 282,506 | (256,290) | (55,676) | (354,424) | (135,748) | 82,120 | (802,138) | (1,052,362) | ||
Income tax (benefit) expense: | |||||||||||||
Current | 17 | 0 | 0 | 0 | 98 | 0 | 0 | 0 | 17 | 98 | 29 | ||
Deferred | (349,097) | (71,992) | 57,651 | 112,395 | (95,679) | (13,705) | (129,488) | (41,976) | (251,043) | (280,848) | (338,706) | ||
Total (benefit) expense for income taxes | (349,080) | (71,992) | 57,651 | 112,395 | (95,581) | (13,705) | (129,488) | (41,976) | (251,026) | (280,750) | (338,677) | ||
Net income (loss) | $ 221,185 | $ (127,700) | $ 69,550 | $ 170,111 | $ (160,709) | $ (41,971) | $ (224,936) | $ (93,772) | $ 333,146 | $ (521,388) | $ (713,685) | ||
Net income (loss) per common share: | |||||||||||||
Basic | $ 0.89 | $ (0.52) | $ 0.28 | $ 0.69 | $ (0.66) | $ (0.23) | $ (1.35) | $ (0.56) | $ 1.34 | $ (2.75) | $ (4.29) | ||
Diluted | $ 0.89 | $ (0.52) | $ 0.28 | $ 0.69 | $ (0.66) | $ (0.23) | $ (1.35) | $ (0.56) | $ 1.34 | $ (2.75) | $ (4.29) |
Supplemental Information on 119
Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) - Capitalized Costs and Accumulated Depreciation, Depletion and Amortization (Detail) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Natural gas and oil properties: | ||||
Properties subject to depletion | [1] | $ 10,572,453 | $ 9,462,350 | $ 8,047,181 |
Unproved properties | [1] | 2,644,000 | 2,923,803 | 949,155 |
Total | [1] | 13,216,453 | 12,386,153 | 8,996,336 |
Accumulated depletion and depreciation | [1] | (3,649,716) | (3,129,816) | (2,635,031) |
Natural gas and oil properties, successful efforts method, net | [1] | $ 9,566,737 | $ 9,256,337 | $ 6,361,305 |
[1] | Includes capitalized asset retirement costs and the associated accumulated amortization. |
Supplemental Information on 120
Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) - Costs Incurred for Property Acquisition, Exploration and Development (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |||
Acquisitions | |||||
Acreage purchases | [1] | $ 62,075 | $ 33,142 | $ 73,025 | |
Oil and gas properties | [1] | 18,269 | 3,098,772 | 0 | |
Asset retirement obligations and other | [1] | 0 | 21,908 | 0 | |
Development | [1] | 1,177,526 | 497,795 | 708,268 | |
Exploration: | |||||
Exploration drilling costs incurred | [1] | 2,030 | 37,680 | 87,505 | |
Stock-based compensation expense | 82,776 | [2] | 55,618 | 57,801 | |
Gas gathering facilities: | |||||
Development | [1] | 15,097 | 3,595 | 13,337 | |
Subtotal | [1] | 1,328,659 | 3,725,217 | 903,541 | |
Asset retirement obligations | [1],[3] | 20,245 | (24,064) | 22,184 | |
Total costs incurred | [1] | 1,348,904 | 3,701,153 | 925,725 | |
Expense | |||||
Exploration: | |||||
Exploration costs incurred | [1] | 50,920 | 30,027 | 18,421 | |
Stock-based compensation expense | [1] | $ 2,742 | [2] | $ 2,298 | $ 2,985 |
[1] | Includes cost incurred whether capitalized or expensed. | ||||
[2] | Includes $30.8 million accelerated vesting of equity grants. | ||||
[3] | For additional information on non-cash investing activities associated with the MRD Merger, see Note 3 |
Supplemental Information on 121
Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) - Additional Information (Detail) $ in Millions | 12 Months Ended | ||||
Dec. 31, 2017USD ($)MMcfe$ / MMBTU$ / bbl$ / McfMMcfMBbls | Dec. 31, 2016MMcfe$ / MMBTU$ / bbl$ / McfMMcfMBbls | Dec. 31, 2015MMcfe$ / MMBTU$ / bbl$ / McfMMcfMBbls | Dec. 31, 2014MMcfeMMcfMBbls | ||
Reserve Quantities [Line Items] | |||||
Percentage of proved resources reviewed by consultants | 98.00% | ||||
Statement That Reserve Estimates Differ From Auditors | more than 10% | ||||
Proved Reserve And Pretax Present Value of Reserve Discounted | 10.00% | ||||
Variance in reserve estimates | less than 5%. | ||||
Scheduled to be drilling period maximum for undeveloped reserves | Scheduled to be drilled within five years | ||||
Reserve attributable to natural gas | 82.00% | 86.00% | 80.00% | ||
Revisions of positive pricing | 46,000 | ||||
Improved recoveries | 597,000 | 393,000 | 781,000 | ||
Proved undeveloped reserves dropped | 668,000 | 269,000 | 1,200,000 | ||
Cost spent on undeveloped reserves transferred to developed reserves | $ | $ 920 | ||||
Estimated future development costs in 2018 | $ | 717 | ||||
Estimated future development costs in 2019 | $ | 707 | ||||
Estimated future development costs in 2020 | $ | $ 567 | ||||
Proved undeveloped reserves reported for more than five years | 64,000 | ||||
Maximum | |||||
Reserve Quantities [Line Items] | |||||
Percentage of proved undeveloped reserves reported for more than five years | 1.00% | ||||
Crude Oil and NGL | |||||
Reserve Quantities [Line Items] | |||||
Benchmark price used for calculating average realized prices | $ / bbl | 51.19 | 42.68 | 50.13 | ||
Crude Oil | |||||
Reserve Quantities [Line Items] | |||||
Estimate reserve information average realized prices | $ / bbl | 45.73 | 37.41 | 35.07 | ||
Proved developed and undeveloped reserves | MBbls | 69,854 | 70,252 | 53,193 | 48,658 | |
NGLs | |||||
Reserve Quantities [Line Items] | |||||
Estimate reserve information average realized prices | $ / bbl | 17.84 | 13.44 | 11.74 | ||
Proved developed and undeveloped reserves | MBbls | 763,264 | 630,066 | 549,135 | 515,907 | |
Natural Gas | |||||
Reserve Quantities [Line Items] | |||||
Estimate reserve information average realized prices | $ / Mcf | 2.60 | 2.07 | 2.07 | ||
Proved developed and undeveloped reserves | MMcf | 10,263,649 | 7,870,416 | 6,277,697 | 6,922,836 | |
Natural Gas, Per Thousand Cubic Feet | |||||
Reserve Quantities [Line Items] | |||||
Benchmark price used for calculating average realized prices | $ / MMBTU | 2.98 | 2.48 | 2.59 | ||
Natural Gas Equivalents | |||||
Reserve Quantities [Line Items] | |||||
Proved reserves from drilling activities and evaluations of proved areas | [1] | 3,487,519 | 1,394,134 | 1,265,348 | |
Proved developed and undeveloped reserve balances | [1] | 15,262,361 | 12,072,322 | 9,891,663 | 10,310,229 |
Revisions of previous estimates | [1] | 506,919 | 255,794 | (211,163) | |
Revisions of positive performance | 532,000 | 154,000 | |||
Ethane and Natural Gas Equivalents | |||||
Reserve Quantities [Line Items] | |||||
Proved developed and undeveloped reserve balances | 1,596,000 | 1,367,000 | 1,296,000 | ||
Ethane Reserves and NGLs | |||||
Reserve Quantities [Line Items] | |||||
Proved developed and undeveloped reserves | MBbls | 360,600 | 308,900 | 292,800 | ||
[1] | Oil and NGLs are converted to mcfe at the rate of one barrel equals six mcf based upon the approximate relative energy content of oil to natural gas, which is not indicative of the relationship of oil and natural gas prices. |
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Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) - Proved Developed and Undeveloped Reserves (Detail) | 12 Months Ended | |||
Dec. 31, 2017MMcfeMMcfMBbls | Dec. 31, 2016MMcfeMMcfMBbls | Dec. 31, 2015MMcfeMMcfMBbls | ||
Proved undeveloped reserves: | ||||
Proved undeveloped reserves | MMcfe | 6,914,287 | 5,302,414 | ||
Natural Gas | ||||
Reserve Quantities [Line Items] | ||||
Beginning Balance | MMcf | 7,870,416 | 6,277,697 | 6,922,836 | |
Revisions | MMcf | 70,222 | (7,441) | (340,286) | |
Extensions, discoveries and additions | MMcf | 2,866,103 | 1,193,154 | 1,017,956 | |
Purchases | MMcf | 7,738 | 943,544 | ||
Property sales | MMcf | (60,278) | (160,727) | (960,122) | |
Production | MMcf | (490,552) | (375,811) | (362,687) | |
Ending Balance | MMcf | 10,263,649 | 7,870,416 | 6,277,697 | |
Proved developed reserves: | ||||
Proved developed reserves | MMcf | 5,437,674 | 4,352,141 | 3,376,165 | |
Proved undeveloped reserves: | ||||
Proved undeveloped reserves | MMcf | 4,825,975 | 3,518,275 | 2,901,533 | |
NGLs | ||||
Reserve Quantities [Line Items] | ||||
Beginning Balance | 630,066 | 549,135 | 515,907 | |
Revisions | 83,338 | 41,402 | 17,717 | |
Extensions, discoveries and additions | 87,572 | 26,991 | 36,308 | |
Purchases | 330 | 40,724 | ||
Property sales | (2,356) | (360) | (441) | |
Production | (35,686) | (27,826) | (20,356) | |
Ending Balance | 763,264 | 630,066 | 549,135 | |
Proved developed reserves: | ||||
Proved developed reserves | 448,258 | 363,852 | 309,306 | |
Proved undeveloped reserves: | ||||
Proved undeveloped reserves | 315,006 | 266,214 | 239,828 | |
Crude Oil and Condensate | ||||
Reserve Quantities [Line Items] | ||||
Beginning Balance | 70,252 | 53,193 | 48,658 | |
Revisions | (10,555) | 2,471 | 3,804 | |
Extensions, discoveries and additions | 15,997 | 6,506 | 4,924 | |
Purchases | 66 | 11,986 | ||
Property sales | (1,121) | (295) | (109) | |
Production | (4,785) | (3,609) | (4,084) | |
Ending Balance | 69,854 | 70,252 | 53,193 | |
Proved developed reserves: | ||||
Proved developed reserves | 36,808 | 39,110 | 31,679 | |
Proved undeveloped reserves: | ||||
Proved undeveloped reserves | 33,046 | 31,143 | 21,514 | |
Natural Gas Equivalents | ||||
Proved developed reserves: | ||||
Proved developed reserves | MMcfe | [1] | 8,348,074 | 6,769,908 | 5,422,075 |
Proved undeveloped reserves: | ||||
Proved undeveloped reserves | MMcfe | [1] | 6,914,287 | 5,302,414 | 4,469,588 |
Beginning Balance | MMcfe | [1] | 12,072,322 | 9,891,663 | 10,310,229 |
Revisions | MMcfe | [1] | 506,919 | 255,794 | (211,163) |
Extensions, discoveries and additions | MMcfe | [1] | 3,487,519 | 1,394,134 | 1,265,348 |
Purchases | MMcfe | [1] | 10,116 | 1,259,806 | |
Property sales | MMcfe | [1] | (81,133) | (164,655) | (963,423) |
Production | MMcfe | [1] | (733,382) | (564,420) | (509,328) |
Ending Balance | MMcfe | [1] | 15,262,361 | 12,072,322 | 9,891,663 |
[1] | Oil and NGLs are converted to mcfe at the rate of one barrel equals six mcf based upon the approximate relative energy content of oil to natural gas, which is not indicative of the relationship of oil and natural gas prices. |
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Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) - Changes in Proved Undeveloped Reserves (Detail) | 12 Months Ended | |
Dec. 31, 2017MMcfe | ||
Extractive Industries [Abstract] | ||
Beginning proved undeveloped reserves at December 31, 2016 | 5,302,414 | |
Undeveloped reserves transferred to developed | (1,861,994) | |
Revisions | 308,929 | [1] |
Purchases/(sales) | (8,907) | |
Extension and discoveries | 3,173,845 | |
Ending proved undeveloped reserves at December 31, 2017 | 6,914,287 | |
[1] | Includes 668 Bcfe of proved undeveloped reserves dropped due to the five year rule which can be included in our future proved reserves as these locations are added back to our five-year development plan. |
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Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) - Changes in Proved Undeveloped Reserves (Parenthetical) (Detail) - MMcfe MMcfe in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Extractive Industries [Abstract] | |||
Proved undeveloped reserves dropped | 668 | 269 | 1,200 |
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Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) - Standardized Measure of Discounted Future Net Cash Flows (Detail) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Extractive Industries [Abstract] | |||||
Future cash inflows | $ 43,500,054 | $ 27,413,864 | |||
Future costs: | |||||
Production | (18,958,695) | (14,465,059) | |||
Development | [1] | (3,072,688) | (2,647,801) | ||
Future net cash flows before income taxes | 21,468,671 | 10,301,004 | |||
Future income tax expense | (3,989,459) | (1,946,259) | |||
Total future net cash flows before 10% discount | 17,479,212 | 8,354,745 | |||
10% annual discount | (10,313,998) | (4,902,816) | |||
Standardized measure of discounted future net cash flows | $ 7,165,214 | $ 3,451,929 | $ 2,725,863 | $ 7,593,027 | |
[1] | 2017 includes $430.6 million of undiscounted future asset retirement costs estimated as of December 31, 2017, using current estimates of future abandonment costs. |
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Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) - Standardized Measure of Discounted Future Net Cash Flows (Parenthetical) (Detail) $ in Millions | Dec. 31, 2017USD ($) |
Extractive Industries [Abstract] | |
Undiscounted future asset retirement costs estimation | $ 430.6 |
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Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited) - Changes in Discounted Future Net Cash Flows (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Revisions of previous estimates | |||
Changes in prices and production costs | $ 2,615,825 | $ (212,867) | $ (7,231,629) |
Revisions in quantities | 445,667 | 96,615 | (868,886) |
Changes in future development and abandonment costs | (497,400) | (314,864) | 359,540 |
Net change in income taxes | (706,531) | 27,842 | 2,173,904 |
Accretion of discount | 372,743 | 302,920 | 1,007,027 |
Purchases of reserves in place | 6,173 | 488,959 | 0 |
Additions to proved reserves from extensions, discoveries and improved recovery | 2,128,135 | 541,095 | 486,478 |
Natural gas, NGLs and oil sales, net of production costs | (1,237,970) | (509,174) | (522,682) |
Development costs incurred during the period | 885,803 | 435,928 | 1,033,539 |
Sales of reserves in place | (32,946) | (65,538) | (1,050,237) |
Timing and other | (266,214) | (64,850) | (254,218) |
Net change for the year | 3,713,285 | 726,066 | (4,867,164) |
Beginning of year | 3,451,929 | 2,725,863 | 7,593,027 |
End of year | $ 7,165,214 | $ 3,451,929 | $ 2,725,863 |