Document and Entity Information
Document and Entity Information - USD ($) | 12 Months Ended | ||
Dec. 31, 2017 | Feb. 21, 2018 | Jun. 30, 2017 | |
Document and Entity Information [Abstract] | |||
Entity Registrant Name | Matador Resources Co | ||
Entity Central Index Key | 1,520,006 | ||
Document Type | 10-K | ||
Document Period End Date | Dec. 31, 2017 | ||
Amendment Flag | false | ||
Document Fiscal Year Focus | 2,017 | ||
Document Fiscal Period Focus | FY | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Public Float | $ 1,910,451,565 | ||
Entity Common Stock, Shares Outstanding | 109,248,747 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Current assets | ||
Cash | $ 96,505 | $ 212,884 |
Restricted cash | 5,977 | 1,258 |
Accounts receivable | ||
Oil and natural gas revenues | 65,962 | 34,154 |
Joint interest billings | 67,225 | 19,347 |
Other | 8,031 | 5,167 |
Derivative instruments | 1,190 | 0 |
Lease and well equipment inventory | 5,993 | 3,045 |
Prepaid expenses and other assets | 6,287 | 3,327 |
Total current assets | 257,170 | 279,182 |
Oil and natural gas properties, full-cost method | ||
Evaluated | 3,004,770 | 2,408,305 |
Unproved and unevaluated | 637,396 | 479,736 |
Midstream and other property and equipment | 281,096 | 160,795 |
Less accumulated depletion, depreciation and amortization | (2,041,806) | (1,864,311) |
Net property and equipment | 1,881,456 | 1,184,525 |
Other assets | ||
Other assets | 7,064 | 958 |
Total assets | 2,145,690 | 1,464,665 |
Current liabilities | ||
Accounts payable | 11,757 | 4,674 |
Accrued liabilities | 174,348 | 101,460 |
Royalties payable | 61,358 | 23,988 |
Amounts due to affiliates | 10,302 | 8,651 |
Derivative instruments | 16,429 | 24,203 |
Advances from joint interest owners | 2,789 | 1,700 |
Amounts due to joint ventures | 4,873 | 4,251 |
Other current liabilities | 750 | 578 |
Total current liabilities | 282,606 | 169,505 |
Long-term liabilities | ||
Senior unsecured notes payable | 574,073 | 573,924 |
Asset retirement obligations | 25,080 | 19,725 |
Derivative instruments | 0 | 751 |
Amounts due to joint ventures | 0 | 1,771 |
Other long-term liabilities | 6,385 | 7,544 |
Total long-term liabilities | 605,538 | 603,715 |
Commitments and contingencies (Note 13) | ||
Shareholders' equity | ||
Common stock — $0.01 par value, 160,000,000 and 120,000,000 shares authorized; 108,513,597 and 99,518,764 shares issued; and 108,510,160 and 99,511,931 shares outstanding, respectively | 1,085 | 995 |
Additional paid-in capital | 1,666,024 | 1,325,481 |
Accumulated deficit | (510,484) | (636,351) |
Treasury stock, at cost, 3,437 and 6,833 shares, respectively | (69) | 0 |
Total shareholders' equity | 1,156,556 | 690,125 |
Non-controlling interest in subsidiaries | 100,990 | 1,320 |
Total shareholders’ equity | 1,257,546 | 691,445 |
Total liabilities and shareholders’ equity | $ 2,145,690 | $ 1,464,665 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - $ / shares | Dec. 31, 2017 | Dec. 31, 2016 |
Statement of Financial Position [Abstract] | ||
Treasury stock (in shares) | 3,437 | 6,833 |
Common stock, par value (usd per share) | $ 0.01 | $ 0.01 |
Common stock, shares authorized (in shares) | 160,000,000 | 120,000,000 |
Common stock, shares issued (in shares) | 108,513,597 | 99,518,764 |
Common stock, shares outstanding (in shares) | 108,510,160 | 99,511,931 |
Consolidated Statements of Oper
Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Revenues | |||
Oil and natural gas revenues | $ 528,684 | $ 291,156 | $ 278,340 |
Third-party midstream services revenues | 10,198 | 5,218 | 1,864 |
Realized (loss) gain on derivatives | (4,321) | 9,286 | 77,094 |
Unrealized gain (loss) on derivatives | 9,715 | (41,238) | (39,265) |
Total revenues | 544,276 | 264,422 | 318,033 |
Expenses | |||
Production taxes, transportation and processing | 58,275 | 43,046 | 35,650 |
Lease operating | 67,313 | 56,202 | 54,704 |
Plant and other midstream services operating | 13,039 | 5,389 | 3,489 |
Depletion, depreciation and amortization | 177,502 | 122,048 | 178,847 |
Accretion of asset retirement obligations | 1,290 | 1,182 | 734 |
Full-cost ceiling impairment | 0 | 158,633 | 801,166 |
General and administrative | 66,016 | 55,089 | 50,105 |
Total expenses | 383,435 | 441,589 | 1,124,695 |
Operating income (loss) | 160,841 | (177,167) | (806,662) |
Other income (expense) | |||
Net gain on asset sales and inventory impairment | 23 | 107,277 | 908 |
Interest expense | (34,565) | (28,199) | (21,754) |
Other income (expense) | 3,551 | (4) | 616 |
Total other (expense) income | (30,991) | 79,074 | (20,230) |
Income (loss) before income taxes | 129,850 | (98,093) | (826,892) |
Income tax (benefit) provision | |||
Current | (8,157) | (1,036) | 2,959 |
Deferred | 0 | 0 | (150,327) |
Total income tax benefit | (8,157) | (1,036) | (147,368) |
Net income (loss) | 138,007 | (97,057) | (679,524) |
Net income attributable to non-controlling interest in subsidiaries | (12,140) | (364) | (261) |
Net income (loss) attributable to Matador Resources Company shareholders | $ 125,867 | $ (97,421) | $ (679,785) |
Earnings (loss) per common share | |||
Basic (usd per share) | $ 1.23 | $ (1.07) | $ (8.34) |
Diluted (usd per share) | $ 1.23 | $ (1.07) | $ (8.34) |
Weighted average common shares outstanding | |||
Basic (in shares) | 102,029 | 91,273 | 81,537 |
Diluted (in shares) | 102,543 | 91,273 | 81,537 |
Consolidated Statements of Chan
Consolidated Statements of Changes in Shareholders' Equity - USD ($) | Total | Common stock | Preferred Stock | Additional paid-in capital | Retained earnings (deficit) | Treasury stock | Parent | Noncontrolling Interest | Convertible Preferred Stock [Member] | Convertible Preferred Stock [Member]Common stock | Convertible Preferred Stock [Member]Preferred Stock | Convertible Preferred Stock [Member]Additional paid-in capital | Convertible Preferred Stock [Member]Parent |
Beginning Balance at Dec. 31, 2014 | $ 866,541,000 | $ 734,000 | $ 0 | $ 724,819,000 | $ 140,855,000 | $ 0 | $ 866,408,000 | $ 133,000 | |||||
Beginning Balance, shares (in shares) at Dec. 31, 2014 | 73,374,000 | 0 | 31,000 | ||||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||||||||
Issuance of Class A common stock | 260,252,000 | $ 104,000 | 260,148,000 | 260,252,000 | $ 32,490,000 | $ 1,000 | $ 32,489,000 | $ 32,490,000 | |||||
Issuance of Class A common stock, shares | 10,329,000 | 150,000 | |||||||||||
Conversion of Class B common stock to Class A common stock, shares | (1,500,000) | 150,000 | |||||||||||
Stock Issued During Period, Value, Conversion of Convertible Securities | 0 | $ (15,000) | $ 1,000 | 14,000 | 0 | ||||||||
Stock options expense related to equity based awards | 9,333,000 | 9,333,000 | 9,333,000 | ||||||||||
Stock options exercised, shares | 25,000 | ||||||||||||
Stock options exercised | 10,000 | 10,000 | 10,000 | ||||||||||
Liability-based stock option awards settled, shares | 25,000 | ||||||||||||
Liability-based stock option awards settled | 446,000 | 446,000 | 446,000 | ||||||||||
Restricted stock issued | 0 | $ (4,000) | (4,000) | 0 | |||||||||
Restricted stock issued, shares | 429,000 | ||||||||||||
Cost to issue equity | (1,151,000) | $ 0 | (1,151,000) | (1,151,000) | |||||||||
Restricted stock forfeited, Shares | 138,000 | ||||||||||||
Restricted stock forfeited | 0 | 0 | 0 | ||||||||||
Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries | 562,000 | 562,000 | |||||||||||
Vesting of restricted stock units | 52,000 | ||||||||||||
Restricted stock and restricted stock units expense | 0 | $ 1,000 | (1,000) | 0 | |||||||||
Cancellation of treasury stock (shares) | (167,000) | (167,000) | |||||||||||
Cancellation of treasury stock | 0 | $ (2,000) | 2,000 | $ 0 | 0 | ||||||||
Current period net income | (679,785,000) | ||||||||||||
Capital contribution from non-controlling interest owners in less-than-wholly-owned subsidiaries | 0 | ||||||||||||
Class B dividends declared | 0 | ||||||||||||
Net (loss) income | (679,524,000) | (679,785,000) | (679,785,000) | 261,000 | |||||||||
Ending Balance, shares (in shares) at Dec. 31, 2015 | 85,567,000 | 0 | 2,000 | ||||||||||
Ending Balance at Dec. 31, 2015 | 488,959,000 | $ 856,000 | $ 0 | 1,026,077,000 | (538,930,000) | $ 0 | 488,003,000 | 956,000 | |||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||||||||
Issuance of Class A common stock | 288,510,000 | $ 135,000 | 288,375,000 | 288,510,000 | 0 | $ 4,000 | $ 0 | (4,000) | 0 | ||||
Issuance of Class A common stock, shares | 13,500,000 | 471,000 | 0 | ||||||||||
Issuance of Class A common stock to Board member and advisors, shares | 51,000 | ||||||||||||
Issuance of Class A common stock to Board member and advisors | $ 1,000 | 0 | (1,000) | 0 | |||||||||
Stock options expense related to equity based awards | 11,958,000 | 11,958,000 | 11,958,000 | ||||||||||
Stock options exercised, shares | 36,000 | ||||||||||||
Stock options exercised | 10,000 | 10,000 | 10,000 | ||||||||||
Liability-based stock option awards settled, shares | 10,000 | ||||||||||||
Liability-based stock option awards settled | 255,000 | 255,000 | 255,000 | ||||||||||
Cost to issue equity | (1,190,000) | (1,190,000) | (1,190,000) | ||||||||||
Restricted stock forfeited, Shares | 120,000 | ||||||||||||
Restricted stock forfeited | 0 | 0 | 0 | ||||||||||
Cancellation of treasury stock (shares) | (116,000) | (116,000) | |||||||||||
Cancellation of treasury stock | 0 | $ (1,000) | 1,000 | $ 0 | 0 | ||||||||
Current period net income | (97,421,000) | ||||||||||||
Capital contribution from non-controlling interest owners in less-than-wholly-owned subsidiaries | 0 | ||||||||||||
Net (loss) income | $ (97,057,000) | (97,421,000) | (97,421,000) | 364,000 | |||||||||
Ending Balance, shares (in shares) at Dec. 31, 2016 | 99,511,931 | 99,519,000 | 0 | 6,000 | |||||||||
Ending Balance at Dec. 31, 2016 | $ 691,445,000 | $ 995,000 | $ 0 | 1,325,481,000 | (636,351,000) | $ 0 | 690,125,000 | 1,320,000 | |||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||||||||
Issuance of Class A common stock | 208,720,000 | $ 80,000 | 208,640,000 | 208,720,000 | 0 | $ 5,000 | (5,000) | 0 | |||||
Issuance of Class A common stock, shares | 8,000,000 | 530,000 | |||||||||||
Issuance of Class A common stock to Board member and advisors, shares | 77,000 | ||||||||||||
Issuance of Class A common stock to Board member and advisors | $ 1,000 | $ 0 | $ (1,000) | $ 0 | |||||||||
Stock options expense related to equity based awards | $ 19,594,000 | 19,594,000 | 19,594,000 | ||||||||||
Stock options exercised, shares | 833,000 | 514,000 | |||||||||||
Stock options exercised | $ (1,184,000) | $ 5,000 | (1,189,000) | (1,184,000) | |||||||||
Cost to issue equity | (280,000) | (280,000) | (280,000) | ||||||||||
Restricted stock forfeited, Shares | 123,000 | ||||||||||||
Restricted stock forfeited | (1,658,000) | $ (1,658,000) | (1,658,000) | ||||||||||
Purchase of non-controlling interest of less-than-wholly-owned subsidiary | (2,653,000) | (1,250,000) | (1,250,000) | (1,403,000) | |||||||||
Contributions related to formation of Joint Venture (see Note 5) | 171,500,000 | 116,622,000 | 116,622,000 | 54,878,000 | |||||||||
Contributions from non-controlling interest owners of less-than-wholly-owned subsidiaries | 44,100,000 | 44,100,000 | |||||||||||
Distributions to non-controlling interest owners of less-than wholly-owned subsidiaries | (10,045,000) | (10,045,000) | |||||||||||
Cancellation of treasury stock (shares) | (126,000) | (126,000) | |||||||||||
Cancellation of treasury stock | 0 | $ (1,000) | (1,588,000) | $ (1,589,000) | 0 | ||||||||
Current period net income | 125,867,000 | ||||||||||||
Capital contribution from non-controlling interest owners in less-than-wholly-owned subsidiaries | 44,100,000 | ||||||||||||
Net (loss) income | $ 138,007,000 | 125,867,000 | 12,140,000 | ||||||||||
Ending Balance, shares (in shares) at Dec. 31, 2017 | 108,510,160 | 108,514,000 | 0 | 3,000 | |||||||||
Ending Balance at Dec. 31, 2017 | $ 1,257,546,000 | $ 1,085,000 | $ 0 | $ 1,666,024,000 | $ (510,484,000) | $ (69,000) | $ 1,156,556,000 | $ 100,990,000 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Operating activities | |||
Net (loss) income | $ 138,007 | $ (97,057) | $ (679,524) |
Adjustments to reconcile net income (loss) to net cash provided by operating activities | |||
Unrealized (gain) loss on derivatives | (9,715) | 41,238 | 39,265 |
Depletion, depreciation and amortization | 177,502 | 122,048 | 178,847 |
Accretion of asset retirement obligations | 1,290 | 1,182 | 734 |
Full-cost ceiling impairment | 0 | 158,633 | 801,166 |
Stock-based compensation expense | 16,654 | 12,362 | 9,450 |
Deferred income tax benefit | 0 | 0 | (150,327) |
Amortization of debt issuance cost | 468 | 1,148 | 852 |
Net gain on asset sales and inventory impairment | (23) | (107,277) | (908) |
Changes in operating assets and liabilities | |||
Accounts receivable | (82,549) | (14,259) | 3,633 |
Lease and well equipment inventory | (3,623) | (700) | (180) |
Prepaid expenses | (2,960) | (124) | (544) |
Other assets | (6,425) | 490 | (552) |
Accounts payable, accrued liabilities and other current liabilities | 33,559 | 6,611 | 1,375 |
Royalties payable | 37,370 | 7,495 | 1,654 |
Advances from joint interest owners | 1,089 | 1,000 | 700 |
Income taxes payable | 0 | (2,848) | 2,405 |
Other long-term liabilities | (1,519) | 4,144 | 489 |
Net cash provided by operating activities | 299,125 | 134,086 | 208,535 |
Investing activities | |||
Oil and natural gas properties capital expenditures | (699,445) | (379,067) | (432,715) |
Expenditures for other property and equipment | (120,816) | (74,845) | (64,499) |
Proceeds from sale of assets | 977 | 5,173 | 139,836 |
Business combination, net of cash acquired | 0 | 0 | (24,028) |
Restricted cash | 0 | 43,098 | (43,098) |
Restricted cash in less-than-wholly-owned subsidiaries | (4,719) | 1 | (650) |
Net cash used in investing activities | (824,003) | (405,640) | (425,154) |
Financing activities | |||
Repayments of borrowings | 0 | (120,000) | (476,982) |
Borrowings under Credit Agreement | 0 | 120,000 | 125,000 |
Proceeds from issuance of common stock | 208,720 | 288,510 | 188,720 |
Proceeds from issuance of senior unsecured notes | 0 | 184,625 | 400,000 |
Cost to issue equity | (280) | (847) | (1,158) |
Cost to issue senior unsecured notes | 0 | (2,734) | (9,598) |
Proceeds from stock options exercised | 2,920 | 100 | 10 |
Capital commitments from non-controlling interest owners of less-than-wholly-owned subsidiaries | 0 | 0 | 562 |
Contributions related to formation of Joint Venture | 171,500 | 0 | 0 |
Capital contribution from non-controlling interest owners in less-than-wholly-owned subsidiaries | 44,100 | 0 | 0 |
Distributions to non-controlling interest owners of less-than-wholly-owned subsidiaries | 10,045 | 0 | 0 |
Taxes paid related to net share settlement of stock-based compensation | 5,763 | 1,948 | 1,610 |
Purchase of non-controlling interest of less-than-wholly-owned subsidiary | (2,653) | 0 | 0 |
Net cash provided by financing activities | 408,499 | 467,706 | 224,944 |
(Decrease) increase in cash | (116,379) | 196,152 | 8,325 |
Cash at beginning of year | 212,884 | 16,732 | 8,407 |
Cash at end of year | $ 96,505 | $ 212,884 | $ 16,732 |
Nature of Operations
Nature of Operations | 12 Months Ended |
Dec. 31, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
NATURE OF OPERATIONS | Matador Resources Company, a Texas corporation (“Matador” and, collectively with its subsidiaries, the “Company”), is an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. The Company’s current operations are focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company also operates in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas. Additionally, the Company conducts midstream operations, primarily through its midstream joint venture, San Mateo Midstream, LLC (“San Mateo” or the “Joint Venture”), in support of the Company’s exploration, development and production operations and provides natural gas processing, oil transportation services, oil, natural gas and salt water gathering services and salt water disposal services to third parties. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Policies [Abstract] | |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | Basis of Presentation The consolidated financial statements include the accounts of Matador Resources Company and its wholly-owned and majority-owned subsidiaries. These consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”). Accordingly, the Company consolidates certain subsidiaries that are less-than-wholly-owned and the net income and equity attributable to the non-controlling interest in these subsidiaries have been reported separately. The Company proportionately consolidates certain joint ventures that are less-than-wholly-owned and are involved in oil and natural gas exploration. All intercompany balances and transactions have been eliminated in consolidation. Use of Estimates The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates and assumptions may also affect disclosure of contingent assets and liabilities at the date of the financial statements, purchase price allocations and the reported amounts of revenues and expenses during the reporting period. While the Company believes its estimates are reasonable, changes in facts and assumptions or the discovery of new information may result in revised estimates. Actual results could differ from these estimates. The Company’s consolidated financial statements are based on a number of significant estimates, including oil and natural gas revenues, accrued assets and liabilities, stock-based compensation, valuation of derivative instruments, deferred tax assets and liabilities, purchase price allocations and oil and natural gas reserves. The estimates of oil and natural gas reserves quantities and future net cash flows are the basis for the calculations of depletion and impairment of oil and natural gas properties, as well as estimates of asset retirement obligations and certain tax accruals. The Company’s oil and natural gas reserves estimates, which are inherently imprecise and based upon many factors that are beyond the Company’s control, including oil and natural gas prices, are prepared by the Company’s engineering staff in accordance with guidelines established by the Securities and Exchange Commission (“SEC”) and then audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers. Restricted Cash Restricted cash represents a portion of the cash associated with the Company’s less-than-wholly-owned subsidiaries, primarily San Mateo. By contractual agreement, the cash in the accounts held by the Company’s less-than-wholly-owned subsidiaries is not to be commingled with other Company cash and is to be used only to fund the capital expenditures and operations of these less-than-wholly-owned subsidiaries. Accounts Receivable The Company sells its operated oil, natural gas and natural gas liquids production to various purchasers (see “ —Revenue Recognition” below). Due to the nature of the markets for oil, natural gas and natural gas liquids, the Company does not believe that the loss of any one purchaser would significantly impact operations. In addition, the Company may participate with industry partners in the drilling, completion and operation of oil and natural gas wells. Substantially all of the Company’s accounts receivable are due from either purchasers of oil, natural gas and natural gas liquids or participants in oil and natural gas wells for which the Company serves as the operator. Accounts receivable are due within 30 to 60 days of the production date and 30 days of the billing date and are stated at amounts due from purchasers and industry partners. Amounts are considered past due if they have been outstanding for 60 days or more. No interest is typically charged on past due amounts. The Company reviews its need for an allowance for doubtful accounts on a periodic basis and determines the allowance, if any, by considering the length of time past due, previous loss history, future net revenues of the debtor’s ownership interest in oil and natural gas properties operated by the Company and the debtor’s ability to pay its obligations, among other things. The Company has no allowance for doubtful accounts related to its accounts receivable for any reporting period presented. Lease and Well Equipment Inventory Lease and well equipment inventory is stated at the lower of cost or market and consists entirely of materials or equipment scheduled for use in future well or midstream operations. Oil and Natural Gas Properties The Company uses the full-cost method of accounting for its investments in oil and natural gas properties. Under this method of accounting, all costs associated with the acquisition, exploration and development of oil and natural gas properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred and accumulated in a single cost center representing the Company’s activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive wells, capitalized interest on qualifying projects and general and administrative expenses directly related to acquisition, exploration and development activities, but do not include any costs related to production, selling or general corporate administrative activities. The Company capitalized $23.1 million , $15.7 million and $6.9 million of its general and administrative costs in 2017 , 2016 and 2015 , respectively. The Company capitalized $7.3 million , $3.7 million and $3.9 million of its interest expense for the years ended December 31, 2017, 2016 and 2015 , respectively. Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon production and estimates of proved reserves quantities. Unproved and unevaluated property costs are excluded from the amortization base used to determine depletion. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions. This assessment includes consideration of the following factors, among others: the assignment of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term and drilling activity and results. Upon impairment, the costs of the unproved and unevaluated properties are immediately included in the amortization base. Exploratory dry holes are included in the amortization base immediately upon determination that the well is not productive. Sales of oil and natural gas properties are accounted for as adjustments to net capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between net capitalized costs and proved reserves of oil and natural gas. All costs related to production activities and maintenance and repairs are expensed as incurred. Significant workovers that increase the properties’ reserves are capitalized. Ceiling Test The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less related deferred income taxes or the cost center “ceiling.” The cost center ceiling is defined as the sum of: (a) the present value, discounted at 10% , of future net revenues of proved oil and natural gas reserves, reduced by the estimated costs of developing these reserves, plus (b) unproved and unevaluated property costs not being amortized, plus (c) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less (d) income tax effects related to the properties involved. Any excess of the Company’s net capitalized costs above the cost center ceiling as described above is charged to operations as a full-cost ceiling impairment. The fair value of the Company’s derivative instruments is not included in the ceiling test computation as the Company does not designate these instruments as hedge instruments for accounting purposes. The estimated present value of after-tax future net cash flows from proved oil and natural gas reserves is highly dependent upon the quantities of proved reserves, the estimation of which requires substantial judgment. The associated commodity prices and the applicable discount rate used in these estimates are in accordance with guidelines established by the SEC. Under these guidelines, oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost changes in future periods except by contractual arrangements. Future net revenues are calculated using prices that represent the arithmetic averages of the first-day-of-the-month oil and natural gas prices for the previous 12 -month period and a 10% discount factor is used to determine the present value of future net revenues. For the period from January through December 2017 , these average oil and natural gas prices were $47.79 per Bbl and $2.98 per MMBtu, respectively. For the period from January through December 2016 , these average oil and natural gas prices were $39.25 per Bbl and $2.48 per MMBtu, respectively. For the period from January through December 2015 , these average oil and natural gas prices were $46.79 per Bbl and $2.59 per MMBtu, respectively. In estimating the present value of after-tax future net cash flows from proved oil and natural gas reserves, the average oil prices were further adjusted by property for quality, transportation and marketing fees and regional price differentials, and the average natural gas prices were further adjusted by property for energy content, transportation and marketing fees and regional price differentials. During the year ended December 31, 2017, the Company’s full-cost ceiling exceeded the net capitalized costs less related deferred income taxes. As a result, the Company recorded no impairment to its net capitalized costs during the year ended December 31, 2017. During the year ended December 31, 2016, the Company’s net capitalized costs less related deferred income taxes periodically exceeded the full-cost ceiling. As a result, in the first six months of 2016, the Company recorded an impairment charge of $158.6 million , exclusive of tax effect, to its consolidated statement of operations with the related deferred income tax credit recorded net of a valuation allowance (see Note 7). During the year ended December 31, 2015, the Company’s net capitalized costs less related deferred income taxes exceeded the full-cost ceiling. As a result, throughout 2015, the Company recorded an impairment charge of $801.2 million , exclusive of tax effect, to its consolidated statement of operations for December 31, 2015 with the related deferred income tax credit recorded net of a valuation allowance (see Note 7). As a non-cash item, the full-cost ceiling impairment impacts the accumulated depletion and the net carrying value of the Company’s assets on its consolidated balance sheets, as well as the corresponding shareholders’ equity, but it has no impact on the Company’s net cash flows as reported. Changes in oil and natural gas production rates, oil and natural gas prices, reserves estimates, future development costs and other factors will determine the Company’s actual ceiling test computation and impairment analyses in future periods. Midstream and Other Property and Equipment Midstream and other property and equipment are recorded at historical cost and include midstream equipment and facilities, including the Company’s pipelines, processing facilities and salt water disposal systems, and corporate assets, including furniture, fixtures, equipment, land and leasehold improvements. Midstream equipment and facilities are depreciated over a 30 -year useful life using the straight-line, mid-month convention method. Leasehold improvements are depreciated over the lesser of their useful lives or the term of the lease. Software, furniture, fixtures and other equipment are depreciated over their useful life ( five to 30 years) using the straight-line method. Maintenance and repair costs that do not extend the useful life of the property or equipment are expensed as incurred. See Note 3 for a detail of midstream and other property and equipment. Asset Retirement Obligations The Company recognizes the fair value of an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. The asset retirement obligation is recorded as a liability at its estimated present value, with an offsetting increase recognized in oil and natural gas properties or midstream and other property and equipment on the consolidated balance sheets. Periodic accretion of the discounted value of the estimated liability is recorded as an expense in the consolidated statements of operations. Derivative Financial Instruments From time to time, the Company uses derivative financial instruments to mitigate its exposure to commodity price risk associated with oil, natural gas and natural gas liquids prices. The Company’s derivative financial instruments are recorded on the consolidated balance sheets as either an asset or a liability measured at fair value. The Company has elected not to apply hedge accounting for its existing derivative financial instruments, and as a result, the Company recognizes the change in derivative fair value between reporting periods currently in its consolidated statements of operations. The fair value of the Company’s derivative financial instruments is determined using industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Realized gains and losses from the settlement of derivative financial instruments and unrealized gains and unrealized losses from valuation changes in the remaining unsettled derivative financial instruments are reported under “Revenues” in the consolidated statements of operations. See Note 11 for additional information about the Company’s derivative instruments. Revenue Recognition The Company follows the sales method of accounting for its oil, natural gas and natural gas liquids revenues, whereby it recognizes revenue, net of royalties, on all oil, natural gas and natural gas liquids sold to purchasers regardless of whether the sales are proportionate to the Company’s ownership in the property. Under this method, revenue is recognized at the time oil, natural gas and natural gas liquids are produced and sold, and the Company accrues for revenue earned but not yet received. The Company recognizes midstream services revenue at the time services have been rendered and the price is fixed and determinable. See below for a discussion of the impact of the adoption of Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers (Topic 606) on the Company’s 2018 consolidated financial statements. For the year ended December 31, 2017 , four significant purchasers accounted for 60% of the Company’s total oil, natural gas and natural gas liquids revenues: Occidental Energy Marketing, Inc. ( 23% ), Plains Marketing, L.P. ( 14% ), Shell Trading (US) Company ( 12% ) and Western Refining Crude Oil ( 11% ). For the year ended December 31, 2016 , three significant purchasers accounted for 48% of the Company’s total oil, natural gas and natural gas liquids revenues: Plains Marketing, L.P. ( 18% ), Shell Trading (US) Company ( 17% ) and Occidental Energy Marketing, Inc. ( 13% ). For the year ended December 31, 2015 , three significant purchasers accounted for approximately 59% of the Company’s total oil, natural gas and natural gas liquids revenues: Shell Trading (US) Company ( 33% ), Enterprise Crude Oil LLC ( 14% ) and Sequent Energy Management, L.P. ( 12% ). Due to the nature of the markets for oil, natural gas and natural gas liquids, the Company does not believe the loss of any one purchaser would have a material adverse impact on the Company’s financial condition, results of operations or cash flows for any significant period of time. At December 31, 2017, 2016 and 2015 , approximately 43% , 38% and 39% , respectively, of the Company’s accounts receivable, including joint interest billings, related to these purchasers. Stock-Based Compensation The Company grants common stock, stock options, restricted stock and restricted stock units to members of its Board of Directors and selected employees. All such awards are measured at fair value on the date of grant and are generally recognized as a component of general and administrative expenses in the accompanying statements of operations on a straight-line basis over the awards’ vesting periods. The Company accounts for all outstanding stock options granted under the 2003 Plan (as described and defined in Note 8) as liability instruments as a result of the Company purchasing shares from certain of its employees to assist them in the exercise of outstanding options of the Company’s common stock. The Company uses the Black Scholes Merton option pricing model to measure the fair value of stock options, the closing stock price on the date of grant to measure the fair value of restricted stock and restricted stock unit awards and the Monte Carlo simulation method to measure the fair value of performance units. The Company’s consolidated statements of operations for the years ended December 31, 2017, 2016 and 2015 include a stock-based compensation (non-cash) expense of $16.7 million , $12.4 million and $9.5 million , respectively. This stock-based compensation expense includes common stock issuances and restricted stock units expense totaling $3.0 million (including a one-time expense of $1.5 million resulting from a change in the vesting schedule applicable to equity awards granted to independent members of the Company’s Board of Directors), $1.0 million and $0.9 million in 2017 , 2016 and 2015 , respectively, paid to independent members of the Board of Directors and advisors as compensation for their services to the Company. Income Taxes The Company accounts for income taxes using the asset and liability approach for financial accounting and reporting. The Company evaluates the probability of realizing the future benefits of its deferred tax assets and records a valuation allowance for the portion of any deferred tax assets when it is more likely than not that the benefit from the deferred tax asset will not be realized. The Company recognizes the tax benefit of an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities based on the technical merits of the position. For tax positions meeting the more likely than not threshold, the amount recognized in the financial statements is the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. At December 31, 2017, 2016 and 2015 , the Company had not established any reserves for, nor recorded any unrecognized tax benefits related to, uncertain tax positions. When necessary, the Company would include interest assessed by taxing authorities in “Interest expense” and penalties related to income taxes in “Other expense” on its consolidated statements of operations. The Company did not record any interest or penalties related to income taxes for the years ended December 31, 2017, 2016 and 2015 . On December 22, 2017, the President of the United States signed into law the Tax Cuts and Jobs Act. The legislation significantly changes U.S. tax law by, among other things, lowering corporate income tax rates, implementing a territorial tax system and imposing a repatriation tax on deemed repatriated earnings of foreign subsidiaries. The Tax Cuts and Jobs Act permanently reduces the U.S. corporate income tax rate from a maximum of 35% to a flat rate of 21% effective January 1, 2018. For the year ended December 31, 2017 , the Company re-valued its deferred tax assets and liabilities at the enacted rate (see Note 7). Allocation of Purchase Price in Business Combinations As part of the Company’s business strategy, it periodically pursues the acquisition of oil and natural gas properties. The purchase price in a business combination is allocated to the assets acquired and liabilities assumed based on their fair values as of the acquisition date, which may occur many months after the announcement date. Therefore, while the consideration to be paid may be fixed, the fair value of the assets acquired and liabilities assumed is subject to change during the period between the announcement date and the acquisition date. The most significant estimates in the allocation typically relate to the value assigned to proved oil and natural gas reserves and unproved and unevaluated properties. As the allocation of the purchase price is subject to significant estimates and subjective judgments, the accuracy of this assessment is inherently uncertain. Earnings (Loss) Per Common Share The Company reports basic earnings (loss) attributable to Matador Resources Company shareholders per common share, which excludes the effect of potentially dilutive securities, and diluted earnings (loss) attributable to Matador Resources Company shareholders per common share, which includes the effect of all potentially dilutive securities, unless their impact is anti-dilutive. The following are reconciliations of the numerators and denominators used to compute the Company’s basic and diluted earnings per common share as reported for the years ended December 31, 2017, 2016 and 2015 (in thousands, except per share data). Year Ended December 31, 2017 2016 2015 Net income (loss) attributable to Matador Resources Company shareholders — numerator $ 125,867 $ (97,421 ) $ (679,785 ) Weighted average common shares outstanding — denominator Basic 102,029 91,273 81,537 Dilutive effect of options and restricted stock units 514 — — Diluted weighted average common shares outstanding 102,543 91,273 81,537 Earnings (loss) per common share attributable to Basic $ 1.23 $ (1.07 ) $ (8.34 ) Diluted $ 1.23 $ (1.07 ) $ (8.34 ) A total of 1.0 million options to purchase shares of the Company’s common stock were excluded from the calculations above for the year ended December 31, 2017 because their effects were anti-dilutive. A total of 2.9 million options to purchase shares of the Company’s common stock and 0.1 million restricted stock units were excluded from the calculations above for the year ended December 31, 2016 because their effects were anti-dilutive. Additionally, 1.0 million restricted shares, which are participating securities, were excluded from the calculations above for the year ended December 31, 2016 as the security holders do not have the obligation to share in the losses of the Company. A total of 2.4 million options to purchase shares of the Company’s common stock and 0.1 million restricted stock units were excluded from the calculations above for the year ended December 31, 2015 because their effects were anti-dilutive. Additionally, 0.9 million restricted shares, which are participating securities, were excluded from the calculations above for the year ended December 31, 2015 as the security holders do not have the obligation to share in the losses of the Company. Credit Risk The Company’s cash is held in financial institutions and at times these amounts exceed the insurance limits of the Federal Deposit Insurance Corporation. Management believes, however, that the Company’s counterparty risks are minimal based on the reputation and history of the institutions selected. The Company uses derivative financial instruments to mitigate its exposure to oil, natural gas and natural gas liquids price volatility. These transactions expose the Company to potential credit risk from its counterparties. The Company manages counterparty credit risk through established internal derivatives policies that are reviewed on an ongoing basis. Additionally, all of the Company’s commodity derivative contracts at December 31, 2017 were with Royal Bank of Canada (“RBC”), The Bank of Nova Scotia, BMO Harris Financing (Bank of Montreal) and SunTrust Bank (or affiliates thereof), parties that are lenders (or affiliates thereof) under the Company’s revolving credit agreement. Accounts receivable constitute the principal component of additional credit risk to which the Company may be exposed. The Company attempts to minimize credit risk exposure to counterparties by monitoring the financial condition and payment history of its purchasers and joint interest partners. Recent Accounting Pronouncements Revenue from Contracts with Customers . In May 2014, the Financial Accounting Standards Board (“FASB”) issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) , which specifies how and when to recognize revenue. This standard requires expanded disclosures surrounding revenue recognition and is intended to improve, and converge with international standards, the financial reporting requirements for revenue from contracts with customers. In August 2015, the FASB issued ASU 2015-14, which deferred the effective date of ASU 2014-09 for one year to fiscal years beginning after December 15, 2017. Entities have the option of using either a full retrospective or modified approach to adopt the new standards. In December 2016, the FASB issued ASU 2016-20, which clarifies disclosure requirements in ASU 2014-09. The Company adopted the new guidance effective January 1, 2018 using the modified approach. The Company identified all revenue streams and reviewed all contracts and procedures currently in place. The Company determined there is no material impact on its consolidated financial statements as a result of adoption, including no material impact to the timing or amount of revenue recognized, although the Company will be required to include certain additional disclosures regarding revenue from contracts with customers as a result of adoption of ASU 2014-09. Leases . In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) , which requires the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases under previous U.S. GAAP. This ASU will become effective for fiscal years beginning after December 15, 2018 with early adoption permitted. Entities are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The modified retrospective approach includes a number of optional practical expedients that entities may elect to apply. These practical expedients relate to the identification and classification of leases that commenced before the effective date, initial direct costs for leases that commenced before the effective date and the ability to use hindsight in evaluating lessee options to extend or terminate a lease or to purchase the underlying asset. In January 2018, the FASB issued ASU 2018-01, Leases (Topic 842) , which is a land easement practical expedient. If the Company elects to use this practical expedient, the Company should evaluate new or modified land easements under this ASU beginning at the date of adoption. Adoption of ASU 2016-02 will result in increased reported assets and liabilities. The quantitative impact of the new lease standard will depend on the leases in force at the time of adoption. The Company is currently evaluating the impact of the adoption of these ASUs on its consolidated financial statements, including identifying all leases, as defined under the new lease standard, determining which practical expedients the Company will use and quantifying the impact of the new lease standard on existing leases. The Company expects to adopt this lease standard on January 1, 2019. Statement of Cash Flows . In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230) , which specifies that a statement of cash flows explain the change during the period in the total of cash, cash equivalents and amounts generally described as restricted cash or restricted cash equivalents. This ASU will become effective for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years. The update should be applied using a retrospective transition method to each period presented. The Company adopted ASU 2016-18 effective January 1, 2018 and believes that the adoption of this ASU will change the presentation of its beginning and ending cash balances and eliminate the presentation of changes in restricted cash balances from investing activities in its consolidated statement of cash flows. Clarifying the Definition of a Business . In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805) , which specifies the minimum inputs and processes required for an integrated set of assets and activities to meet the definition of a business. This ASU will become effective for fiscal years beginning after December 15, 2017. Entities are required to apply guidance prospectively upon adoption. Effective January 1, 2018, the Company adopted ASU 2017-01, which did not have a material impact on its consolidated financial statements. |
Property and Equipment
Property and Equipment | 12 Months Ended |
Dec. 31, 2017 | |
Property, Plant and Equipment [Abstract] | |
PROPERTY AND EQUIPMENT | The following table presents a summary of the Company’s property and equipment balances as of December 31, 2017 and 2016 (in thousands). December 31, 2017 2016 Oil and natural gas properties Evaluated (subject to amortization) $ 3,004,770 $ 2,408,305 Unproved and unevaluated (not subject to amortization) 637,396 479,736 Total oil and natural gas properties 3,642,166 2,888,041 Accumulated depletion (2,021,169 ) (1,850,882 ) Net oil and natural gas properties 1,620,997 1,037,159 Midstream and other property and equipment Midstream equipment and facilities 258,725 145,662 Furniture, fixtures and other equipment 6,109 5,487 Software 7,942 3,206 Land 2,892 1,437 Leasehold improvements 5,428 5,003 Total midstream and other property and equipment 281,096 160,795 Accumulated depreciation (20,637 ) (13,429 ) Net midstream and other property and equipment 260,459 147,366 Net property and equipment $ 1,881,456 $ 1,184,525 The following table provides a breakdown of the Company’s unproved and unevaluated property costs not subject to amortization as of December 31, 2017 and the year in which these costs were incurred (in thousands). Description 2017 2016 2015 2014 and prior Total Costs incurred for Property acquisition $ 213,076 $ 125,689 $ 222,912 $ 45,809 $ 607,486 Exploration wells 16,688 988 547 — 18,223 Development wells 11,396 272 19 — 11,687 Total $ 241,160 $ 126,949 $ 223,478 $ 45,809 $ 637,396 Property acquisition costs primarily include leasehold costs paid to secure oil and natural gas mineral leases, but may also include broker and legal expenses, geological and geophysical expenses and capitalized internal costs associated with developing oil and natural gas prospects on these properties. Property acquisition costs are transferred into the amortization base on an ongoing basis as these properties are evaluated and proved reserves are established or impairment is determined. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions. Property acquisition costs incurred that remain in unproved and unevaluated property at December 31, 2017 are related almost entirely to the Company’s leasehold and mineral acquisitions in the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas during the past five years. These costs are associated with acreage for which proved reserves have yet to be assigned. A significant portion of these costs are associated with properties that are held by production or have automatic lease renewal options. As the Company drills wells and assigns proved reserves to these properties or determines that certain portions of this acreage, if any, cannot be assigned proved reserves, portions of these costs are transferred to the amortization base. Costs excluded from amortization also include those costs associated with exploration and development wells in progress or awaiting completion at year-end. These costs are transferred into the amortization base on an ongoing basis as these wells are completed and proved reserves are established or confirmed. These costs totaled $29.9 million at December 31, 2017 . Of this total, $18.2 million was associated with exploration wells and $11.7 million was associated with development wells. The Company anticipates that most of the $29.9 million associated with these wells in progress at December 31, 2017 will be transferred to the amortization base during 2018 . |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2017 | |
Asset Retirement Obligation Disclosure [Abstract] | |
ASSET RETIREMENT OBLIGATIONS | In general, the Company’s asset retirement obligations relate to future costs associated with plugging and abandonment of its oil, natural gas and salt water disposal wells, removal of pipelines, equipment and facilities from leased acreage and returning such land to its original condition. The amounts recognized are based on numerous estimates and assumptions, including future retirement costs, future recoverable quantities of oil and natural gas, future inflation rates and the Company’s credit-adjusted risk-free interest rate. Revisions to the liability can occur due to changes in these estimates and assumptions or if federal or state regulators enact new plugging and abandonment requirements. At the time of the actual plugging and abandonment of its oil and natural gas wells, the Company includes any gain or loss associated with the operation in the amortization base to the extent the actual costs are different from the estimated liability. The following table summarizes the changes in the Company’s asset retirement obligations for the years ended December 31, 2017 and 2016 (in thousands). Year Ended December 31, 2017 2016 Beginning asset retirement obligations $ 20,640 $ 15,420 Liabilities incurred during period 2,920 1,791 Liabilities settled during period (430 ) (375 ) Revisions in estimated cash flows 1,836 2,622 Accretion expense 1,290 1,182 Ending asset retirement obligations 26,256 20,640 Less: current asset retirement obligations (1) (1,176 ) (915 ) Long-term asset retirement obligations $ 25,080 $ 19,725 __________________ (1) Included in accrued liabilities in the Company’s consolidated balance sheets at December 31, 2017 and 2016 . |
Business Combinations and Dives
Business Combinations and Divestitures (Notes) | 12 Months Ended |
Dec. 31, 2017 | |
Business Combinations [Abstract] | |
BUSINESS COMBINATIONS AND DIVESTITURES | Joint Venture On February 17, 2017, the Company contributed substantially all of its midstream assets located in the Rustler Breaks (Eddy County, New Mexico) and Wolf (Loving County, Texas) asset areas in the Delaware Basin to San Mateo, a joint venture with a subsidiary of Five Point Capital Partners LLC (“Five Point”). The midstream assets contributed to San Mateo include (i) the Black River cryogenic natural gas processing plant in the Rustler Breaks asset area (the “Black River Processing Plant”); (ii) one salt water disposal well and a related commercial salt water disposal facility in the Rustler Breaks asset area; (iii) three salt water disposal wells and related commercial salt water disposal facilities in the Wolf asset area; and (iv) substantially all related oil, natural gas and water gathering systems and pipelines in both the Rustler Breaks and Wolf asset areas (collectively, the “Delaware Midstream Assets”). The Company continues to operate the Delaware Midstream Assets and San Mateo’s other assets. The Company retained its ownership in certain midstream assets owned in South Texas and Northwest Louisiana, which are not part of San Mateo. The Company and Five Point own 51% and 49% of San Mateo, respectively. Five Point provided initial cash consideration of $176.4 million to San Mateo in exchange for its 49% interest. Approximately $171.5 million of this cash contribution by Five Point was distributed by San Mateo to the Company as a special distribution. Through January 31, 2018, the Company had earned an additional $14.7 million in performance incentives to be paid by Five Point in the first quarter of 2018 and may earn an additional $58.8 million in performance incentives over the next four years . The Company contributed the Delaware Midstream Assets and $5.1 million in cash to San Mateo in exchange for its 51% interest. San Mateo is consolidated in the Company’s financial statements with Five Point’s interest in San Mateo being accounted for as a non-controlling interest. The Company dedicated its current and future leasehold interests in the Rustler Breaks and Wolf asset areas to San Mateo pursuant to 15 -year, fixed-fee natural gas, oil and salt water gathering agreements and salt water disposal agreements, effective as of February 1, 2017. In addition, the Company dedicated its current and future leasehold interests in the Rustler Breaks asset area to San Mateo pursuant to a 15 -year, fixed fee natural gas processing agreement (see Note 13). Business Combinations On February 27, 2015, the Company completed a business combination with Harvey E. Yates Company (“HEYCO”), a subsidiary of HEYCO Energy Group, Inc., through a merger of HEYCO with and into a wholly-owned subsidiary of Matador (the “HEYCO Merger”). In the HEYCO Merger, the Company obtained certain oil and natural gas producing properties and undeveloped acreage located in Lea and Eddy Counties, New Mexico, consisting of approximately 58,600 gross ( 18,200 net) acres strategically located between the Company’s existing acreage in its Ranger and Rustler Breaks asset areas. HEYCO, headquartered in Roswell, New Mexico, was privately-owned prior to the transaction. As consideration for the business combination, Matador paid approximately $33.6 million in cash and assumed debt obligations and issued 3,300,000 shares of Matador common stock and 150,000 shares of a new series of Matador Series A Convertible Preferred Stock (“Series A Preferred Stock”) to HEYCO Energy Group, Inc. (convertible into ten shares of common stock for each one share of Series A Preferred Stock upon the effectiveness of an amendment to the Company’s Amended and Restated Certificate of Formation to increase the number of authorized shares of common stock; the Series A Preferred Stock converted to common stock on April 6, 2015). Divestitures On October 1, 2015 , the Company completed the sale of its wholly-owned subsidiary that owned certain natural gas gathering and processing assets in the Delaware Basin in Loving County, Texas (the “Loving County Processing System”) to an affiliate of EnLink Midstream Partners, LP (“EnLink”). The Loving County Processing System included a cryogenic natural gas processing plant with approximately 35 MMcf per day of inlet capacity (the “Wolf Processing Plant”) and approximately six miles of high-pressure gathering pipeline which connects the Company’s gathering system to the Wolf Processing Plant. Pursuant to the terms of the transaction, EnLink paid approximately $143.4 million , and the Company received net proceeds of approximately $139.8 million after deducting customary purchase price adjustments of approximately $3.6 million . In conjunction with the sale of the Loving County Processing System, the Company dedicated a significant portion of its leasehold interests in Loving County as of the closing date pursuant to a 15 -year fixed-fee natural gas gathering and processing agreement and provided a volume commitment in exchange for priority one service. See Note 13 for more information related to this agreement. Due to the terms of the agreement, the transaction was accounted for as a sale and leaseback transaction; the carrying value of the net assets sold of approximately $31.0 million was removed from the consolidated balance sheet as of December 31, 2015 and the resulting difference of approximately $108.4 million between the net proceeds received less closing costs of $0.4 million and the basis of the assets sold was recorded as deferred gain on plant sale and was to be recognized as a gain on asset sales over the 15 -year term of the gathering and processing agreement. During the fourth quarter of 2016, EnLink completed construction of another processing plant in Loving County, Texas. Upon completion and successful testing of this new plant, as allowed under the gathering and processing agreement, EnLink began processing the Company’s natural gas produced in this area at the new plant. As such, the gathering and processing agreement the Company entered into with EnLink was no longer considered a lease, and accordingly, the Company recognized the unamortized gain on the sale of $107.3 million in the consolidated statement of operations for the year ended December 31, 2016. The Company can, at its option and upon mutual agreement with EnLink, dedicate any future leasehold acquisitions in Loving County to EnLink. In addition, the Company retained its natural gas gathering system up to a central delivery point and its other midstream assets in the area, including oil and water gathering systems and salt water disposal wells. On February 17, 2017, these assets were contributed to San Mateo. |
Debt
Debt | 12 Months Ended |
Dec. 31, 2017 | |
Debt Disclosure [Abstract] | |
DEBT | Credit Agreement On September 28, 2012 , the Company amended and restated its revolving credit agreement with the lenders party thereto (the “Credit Agreement”), which increased the maximum facility amount from $400.0 million to $500.0 million . MRC Energy Company, which is a subsidiary of Matador and directly or indirectly holds the ownership interests in the Company’s other operating subsidiaries, other than its less-than-wholly-owned subsidiaries, is the borrower under the Credit Agreement. Borrowings are secured by mortgages on at least 80% of the Company’s proved oil and natural gas properties and by the equity interests of MRC Energy Company’s wholly-owned subsidiaries, which are also guarantors. In addition, all obligations under the Credit Agreement are guaranteed by Matador, the parent corporation. Various commodity hedging agreements with certain of the lenders under the Credit Agreement (or affiliates thereof) are also secured by the collateral of and guaranteed by certain eligible subsidiaries of MRC Energy Company. The borrowing base under the Credit Agreement is determined semi-annually as of May 1 and November 1 by the lenders based primarily on the estimated value of the Company’s proved oil and natural gas reserves at December 31 and June 30 of each year, respectively. Both the Company and the lenders may request an unscheduled redetermination of the borrowing base once each between scheduled redetermination dates. Early in the fourth quarter of 2017, the lenders completed their review of the Company’s proved oil and natural gas reserves at June 30, 2017, and as a result, on October 25, 2017, the borrowing base was increased to $525.0 million and the maximum facility amount remained at $500.0 million . This October 2017 redetermination constituted the regularly scheduled November 1 redetermination. The Company elected to keep the borrowing commitment at $400.0 million . Borrowings under the Credit Agreement are limited to the lowest of the borrowing base, the maximum facility amount and the elected commitment. The Credit Agreement matures on October 16, 2020. In the event of an increase in the elected commitment, the Company is required to pay a fee to the lenders equal to a percentage of the amount of the increase, which is determined based on market conditions at the time of the increase. Total deferred loan costs were $1.0 million at December 31, 2017 , and these costs are being amortized over the term of the Credit Agreement, which approximates amortization of these costs using the effective interest method. If, upon a redetermination of the borrowing base, the borrowing base were to be less than the outstanding borrowings under the Credit Agreement at any time, the Company would be required to provide additional collateral satisfactory in nature and value to the lenders to increase the borrowing base to an amount sufficient to cover such excess or to repay the deficit in equal installments over a period of six months . At December 31, 2017 and February 21, 2018 , the Company had no borrowings outstanding under the Credit Agreement and approximately $2.1 million in outstanding letters of credit issued pursuant to the Credit Agreement. Borrowings under the Credit Agreement may be in the form of a base rate loan or a Eurodollar loan. If the Company borrows funds as a base rate loan, such borrowings will bear interest at a rate equal to the higher of (i) the prime rate for such day or (ii) the Federal Funds Effective Rate (as defined in the Credit Agreement) on such day, plus 0.50% or (iii) the daily adjusting LIBOR rate (as defined in the Credit Agreement) plus 1.0% plus, in each case, an amount from 0.50% to 1.50% of such outstanding loan depending on the level of borrowings under the Credit Agreement. If the Company borrows funds as a Eurodollar loan, such borrowings will bear interest at a rate equal to (i) the quotient obtained by dividing (A) the LIBOR rate by (B) a percentage equal to 100% minus the maximum rate during such interest calculation period at which RBC is required to maintain reserves on Eurocurrency Liabilities (as defined in Regulation D of the Board of Governors of the Federal Reserve System) plus (ii) an amount from 1.50% to 2.50% of such outstanding loan depending on the level of borrowings under the Credit Agreement. The interest period for Eurodollar borrowings may be one, two, three or six months as designated by the Company. A commitment fee of 0.375% to 0.50% , depending on the unused availability under the Credit Agreement, is also paid quarterly in arrears. The Company includes this commitment fee, any amortization of deferred financing costs (including origination, borrowing base increase and amendment fees) and annual agency fees, if any, as interest expense and in its interest rate calculations and related disclosures. The Credit Agreement requires the Company to maintain a debt to EBITDA ratio, which is defined as total debt outstanding divided by a rolling four quarter EBITDA calculation, of 4.25 or less. Subject to certain exceptions, the Credit Agreement contains various covenants that limit the Company’s ability to take certain actions, including, but not limited to, the following: • incur indebtedness or grant liens on any of the Company’s assets; • enter into commodity hedging agreements; • declare or pay dividends, distributions or redemptions; • merge or consolidate; • make any loans or investments; • engage in transactions with affiliates; • engage in certain asset dispositions, including a sale of all or substantially all of the Company’s assets; and • take certain actions with respect to the Company’s senior unsecured notes. If an event of default exists under the Credit Agreement, the lenders will be able to accelerate the maturity of the borrowings and exercise other rights and remedies. Events of default include, but are not limited to, the following events: • failure to pay any principal or interest on the outstanding borrowings or any reimbursement obligation under any letter of credit when due or any fees or other amounts within certain grace periods; • failure to perform or otherwise comply with the covenants and obligations in the Credit Agreement or other loan documents, subject, in certain instances, to certain grace periods; • bankruptcy or insolvency events involving the Company or its subsidiaries; and • a change of control, as defined in the Credit Agreement. The Company believes that it was in compliance with the terms of the Credit Agreement at December 31, 2017 . Senior Unsecured Notes On April 14, 2015, Matador issued $400.0 million of 6.875% senior notes due 2023 (the “Original Notes”) in a private placement. The Original Notes were issued at par value, and the net proceeds were used to pay down a portion of the outstanding borrowings under the Credit Agreement and the debt assumed in connection with the HEYCO Merger. On October 21, 2015, and pursuant to a registered exchange offer, Matador exchanged all of the privately placed Original Notes for a like principal amount of 6.875% senior notes due 2023 that have been registered under the Securities Act (the “Registered Notes”). The terms of such Registered Notes are substantially the same as the terms of the Original Notes except that the transfer restrictions, registration rights and provisions for additional interest relating to the Original Notes do not apply to the Registered Notes. On December 9, 2016, Matador issued $175.0 million of 6.875% senior notes due 2023 (the “Additional Notes”) in a private placement (the “Notes Offering”). The Additional Notes were issued pursuant to and are governed by the same indenture governing the Original Notes (the “Indenture”). The Additional Notes were issued at 105.5% of par, plus accrued interest from October 15, 2016, resulting in an effective interest rate of 5.5% . The Company received net proceeds from the Notes Offering of approximately $181.5 million , including the issue premium, but after deducting the initial purchasers’ discounts and estimated offering expenses and excluding accrued interest paid by buyers of the Additional Notes. On May 24, 2017, pursuant to a registered exchange offer, Matador exchanged all of the privately placed Additional Notes for a like principal amount of 6.875% senior notes due 2023 that have been registered under the Securities Act (the “Additional Registered Notes,” and, collectively with the Registered Notes, the “Notes”). The terms of the Additional Registered Notes are substantially the same as the terms of the Additional Notes except that the transfer restrictions, registration rights and provisions for additional interest relating to the Additional Notes do not apply to the Additional Registered Notes. The Notes are Matador’s senior unsecured obligations and are redeemable as described below. The Notes mature on April 15, 2023, and interest is payable semi-annually in arrears on April 15 and October 15 of each year. On or after April 15, 2018 , Matador may redeem all or a portion of the Notes at any time or from time to time at the following redemption prices (expressed as percentages of the principal amount) plus accrued and unpaid interest, if any, to the applicable redemption date, if redeemed during the 12-month period beginning on April 15 of the years indicated. Year Redemption Price 2018 105.156% 2019 103.438% 2020 101.719% 2021 and thereafter 100.000% At any time prior to April 15, 2018 , Matador may redeem up to 35% of the aggregate principal amount of the Notes with net proceeds from certain equity offerings at a redemption price of 106.875% of the principal amount of the Notes, plus accrued and unpaid interest, if any, to the redemption date; provided that (i) at least 65% in aggregate principal amount of the Notes (including any additional notes) originally issued remains outstanding immediately after the occurrence of such redemption (excluding Notes held by Matador and its subsidiaries) and (ii) each such redemption occurs within 180 days of the date of the closing of the related equity offering. In addition, at any time prior to April 15, 2018 , Matador may redeem all or part of the Notes at a redemption price equal to the sum of (i) the principal amount thereof, plus (ii) the excess, if any, of (a) the present value at such time of (1) the redemption price of such Notes at April 15, 2018 plus (2) any required interest payments due on such Notes through April 15, 2018 discounted to the redemption date on a semi-annual basis using a discount rate equal to the Treasury Rate (as defined in the Indenture) plus 50 basis points, over (b) the principal amount of such Notes, plus (iii) accrued and unpaid interest, if any, to the redemption date. Subject to certain exceptions, the Indenture contains various covenants that limit the Company’s ability to take certain actions, including, but not limited to, the following: • incur or guarantee additional debt or issue certain types of preferred stock; • pay dividends on capital stock or redeem, repurchase or retire its capital stock or subordinated indebtedness; • transfer or sell assets; • make certain investments; • create certain liens; • enter into agreements that restrict dividends or other payments from its Restricted Subsidiaries (as defined in the Indenture) to the Company; • consolidate, merge or transfer all or substantially all of its assets; • engage in transactions with affiliates; and • create unrestricted subsidiaries. In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to Matador, any Restricted Subsidiary that is a Significant Subsidiary (as defined in the Indenture) or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary, all outstanding Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding Notes may declare all the Notes to be due and payable immediately. Events of default include, but are not limited to, the following events: • default for 30 days in the payment when due of interest on the Notes; • default in the payment when due of the principal of, or premium, if any, on the Notes; • failure by Matador to comply with its obligations to offer to purchase or purchase Notes when required pursuant to the change of control or asset sale provisions of the Indenture or Matador’s failure to comply with the covenant relating to merger, consolidation or sale of assets; • failure by Matador for 180 days after notice to comply with its reporting obligations under the Indenture; • failure by Matador for 60 days after notice to comply with any of the other agreements in the Indenture; • payment defaults and accelerations with respect to other indebtedness of Matador and its Restricted Subsidiaries in the aggregate principal amount of $25.0 million or more; • failure by Matador or any Restricted Subsidiary to pay certain final judgments aggregating in excess of $25.0 million within 60 days; • any subsidiary guarantee by a guarantor ceasing to be in full force and effect, being declared null and void in a judicial proceeding or being denied or disaffirmed by its maker; and • certain events of bankruptcy or insolvency with respect to Matador or any Restricted Subsidiary that is a Significant Subsidiary or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary. On February 17, 2017, in connection with the formation of San Mateo (see Note 5), Matador entered into a Fourth Supplemental Indenture (the “Fourth Supplemental Indenture”), which supplements the indenture governing the Notes. Pursuant to the Fourth Supplemental Indenture, (i) Longwood Midstream Holdings, LLC, the holder of Matador’s 51% equity interest in San Mateo, was designated as a guarantor of the Notes and (ii) DLK Black River Midstream, LLC and Black River Water Management Company, LLC, each subsidiaries of San Mateo, were released as parties to, and as guarantors of, the Notes. The guarantors of the Notes, following the effectiveness of the Fourth Supplemental Indenture, are referred to herein as the “Guarantor Subsidiaries.” San Mateo and its subsidiaries (the “Non-Guarantor Subsidiaries”) are not guarantors of the Notes, although they remain restricted subsidiaries under the Indenture. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | |
INCOME TAXES | Deferred tax assets and liabilities are the result of temporary differences between the financial statement carrying values and the tax bases of assets and liabilities. The Company’s net deferred tax position as of December 31, 2017 and 2016 is as follows (in thousands). December 31, 2017 2016 Deferred tax assets Unrealized loss on derivatives $ 3,200 $ 8,734 Net operating loss carryforwards 118,134 137,757 Alternative minimum tax carryforward — 8,633 Percentage depletion carryover 1,582 2,595 Property and equipment — 44,391 Basis increase related to the San Mateo transaction 18,382 — Total deferred tax assets 141,298 202,110 Valuation allowance on deferred tax assets (89,482 ) (190,255 ) Total deferred tax assets, net of valuation allowance 51,816 11,855 Deferred tax liabilities Property and equipment (40,568 ) — Other (11,248 ) (11,855 ) Total deferred tax liabilities (51,816 ) (11,855 ) Net deferred tax liabilities $ — $ — At December 31, 2017 , the Company had net operating loss carryforwards of $498.4 million for federal income tax purposes and $17.0 million for state income tax purposes available to offset future taxable income, as limited by the applicable provisions, and which expire at various dates beginning in 2027 for the federal net operating loss carryforwards. The state net operating loss carryforwards begin expiring at various dates beginning in 2024 ; however, the significant portion of the Company’s state net operating loss carryforwards expire beginning in 2027 . As a result of the net capitalized costs of the Company’s oil and natural gas properties less related deferred income taxes exceeding the full-cost ceiling during the years ended December 31, 2016 and 2015, the Company recorded impairment charges of $158.6 million and $801.2 million , respectively, exclusive of tax effect, to the net capitalized costs of its oil and natural gas properties. At December 31, 2017 and 2016 , the Company’s deferred tax assets exceeded its deferred tax liabilities due to the deferred tax assets generated by the impairment charges recorded in 2016 and 2015. As a result, the Company established a valuation allowance against most of the deferred tax assets beginning in the third quarter of 2015 and retained a full valuation allowance at December 31, 2017 and 2016 due to uncertainties regarding the future utilization of its deferred tax assets. The valuation allowance will continue to be recognized until the realization of future deferred tax benefits are more likely than not to be utilized. The current income tax (benefit) provision for the years ended December 31, 2017, 2016 and 2015 was comprised of the following (in thousands). Year Ended December 31, 2017 2016 2015 Current income tax provision State income tax $ 21 $ 108 $ 371 Federal alternative minimum tax (8,178 ) (1,144 ) 2,588 Net current income tax (benefit) provision $ (8,157 ) $ (1,036 ) $ 2,959 Reconciliations of the tax expense (benefit) computed at the statutory federal rate to the Company’s total income tax benefit for the years ended December 31, 2017, 2016 and 2015 is as follows (in thousands). Year Ended December 31, 2017 2016 2015 Federal tax expense (benefit) at statutory rate (1) $ 45,447 $ (34,333 ) $ (289,412 ) State income tax 368 539 (13,215 ) Permanent differences (2) (4,740 ) (499 ) 698 Federal alternative minimum tax — 1,144 (2,588 ) AMT credit refundable (net of sequestration) 8,178 — — Tax Cuts and Jobs Act rate change 51,525 — — Change in federal valuation allowance (101,917 ) 33,688 145,777 Change in state valuation allowance 1,139 (539 ) 8,413 Net deferred income tax benefit — — (150,327 ) Net current income tax (benefit) provision (8,157 ) (1,036 ) 2,959 Total income tax benefit $ (8,157 ) $ (1,036 ) $ (147,368 ) __________________ (1) The statutory federal tax rate was 35% for the years ended December 31, 2017, 2016 and 2015 . (2) Amount is primarily attributable to stock-based compensation. The Company files a United States federal income tax return and several state tax returns, a number of which remain open for examination. The earliest tax year open for examination for the State of New Mexico and the State of Louisiana tax returns is 2015 . The earliest tax years open for examination for the federal and the State of Texas tax returns are 2013 and 2014, respectively. The Company has evaluated all tax positions for which the statute of limitations remains open and believes that the material positions taken would more likely than not be sustained by examination. Therefore, at December 31, 2017 , the Company had not established any reserves for, nor recorded any unrecognized benefits related to, uncertain tax positions. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to reverse. As a result of the reduction in the U.S. corporate income tax rate from 35% to 21% under the Tax Cuts and Jobs Act, the Company revalued its deferred tax assets and liabilities at December 31, 2017, which resulted in a $51.5 million tax provision. As the Company maintained a valuation allowance against its federal and state deferred tax assets at December 31, 2017, a corresponding reduction in the valuation allowance was recorded against this tax provision; therefore, there was no net impact to the Company’s consolidated statement of operations for the year ended December 31, 2017 as a result of this corporate income tax rate change. Corporate alternative minimum taxes were also repealed under the Tax Cuts and Jobs Act; therefore, corporate alternative minimum tax carryforwards will be refunded. As a result, the Company recorded $8.2 million as a current income tax benefit in its consolidated statement of operations for the year ended December 31, 2017. On December 22, 2017, the SEC staff issued Staff Accounting Bulletin No. 118 to address the application of U.S. GAAP in situations when a registrant does not have the necessary information available, prepared or analyzed (including computations) in reasonable detail to complete the accounting for certain income tax effects of the Tax Cuts and Jobs Act. The Company has recognized the tax impacts related to the revaluation of deferred tax assets and liabilities and the repeal of the corporate alternative minimum tax and included these amounts in its consolidated financial statements for the year ended December 31, 2017. The ultimate tax impacts may differ from these provisional amounts, possibly materially, due to, among other things, additional analysis, changes in interpretations and assumptions the Company has made, additional regulatory guidance that may be issued, and actions the Company may take as a result of the Tax Cuts and Jobs Act. |
Stock-Based Compensation
Stock-Based Compensation | 12 Months Ended |
Dec. 31, 2017 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
STOCK-BASED COMPENSATION | Stock Options, Restricted Stock, Restricted Stock Units, Stock and Performance Awards In 2003, the Company’s Board of Directors and shareholders approved the 2003 Stock and Incentive Plan (the “2003 Plan”). The 2003 Plan, as amended, provided that a maximum of 3,481,569 shares of common stock in the aggregate could be issued pursuant to options or restricted stock grants. The persons eligible to receive awards under the 2003 Plan included employees, directors, contractors or advisors of the Company. In 2012, the Board of Directors adopted and shareholders approved the 2012 Long-Term Incentive Plan (as subsequently amended and restated, the “2012 Incentive Plan”). As of December 31, 2017 , the 2012 Incentive Plan provided for a maximum of 8,700,000 shares of common stock in the aggregate that may be issued by the Company pursuant to grants of stock options, restricted stock, stock appreciation rights, restricted stock units or other performance awards. The persons eligible to receive awards under the 2012 Incentive Plan include employees, directors, contractors or advisors of the Company. The primary purpose of the 2012 Incentive Plan is to attract and retain key employees, key contractors and outside directors and advisors of the Company. With the adoption of the 2012 Incentive Plan, the Company does not plan to make any future awards under the 2003 Plan, but the 2003 Plan will remain in place until all awards outstanding under that plan have been settled. The 2003 Plan and the 2012 Incentive Plan are administered by the independent members of the Board of Directors, which, upon recommendation of the Compensation Committee of the Board of Directors, determine the number of options, restricted shares or other awards to be granted, the effective dates, the terms of the grants and the vesting periods. The Company typically uses newly issued shares of common stock to satisfy option exercises or restricted share grants. All stock-based compensation awards granted since 2012 have been granted under the 2012 Incentive Plan and are equity-based awards for which the fair value is fixed at the grant date, while all stock-based compensation awards granted prior to January 1, 2012 were granted under the 2003 Plan and are liability-based awards for which the fair value is remeasured at each reporting period. Stock Options Historically, stock option awards have been granted to purchase the Company’s common stock at an exercise price equal to the fair market value on the date of grant, a typical vesting period of three or four years and a typical maximum term of five , six or ten years. The fair value of the 75,000 , 77,500 and 87,500 stock option awards outstanding under the 2003 Plan at December 31, 2017, 2016 and 2015 , respectively, was estimated using the following weighted average assumptions. 2017 2016 2015 Stock option pricing model Black Scholes Merton Black Scholes Merton Black Scholes Merton Expected option life 2.14 years 3.14 years 0.39 years Risk-free interest rate 1.98% 1.70% 0.64% Volatility 43.60% 47.07% 91.98% Dividend yield —% —% —% Estimated forfeiture rate —% —% —% The weighted average grant date fair value for stock option awards granted under the 2012 Incentive Plan was estimated using the following weighted average assumptions during the years ended December 31, 2017, 2016 and 2015 . 2017 2016 2015 Stock option pricing model Black Scholes Merton Black Scholes Merton Black Scholes Merton Expected option life 4.00 years 3.96 years 4.00 years Risk-free interest rate 1.77% 1.08% 1.15% Volatility 47.00% 45.68% 56.89% Dividend yield —% —% —% Estimated forfeiture rate 3.66% 1.16% 3.21% Weighted average fair value of stock option awards granted during the year $10.49 $5.65 $9.90 The Company estimated the future volatility of its common stock using the historical value of its stock for a period of time commensurate with the expected term of the stock option. The expected term was estimated using the simplified method outlined in Staff Accounting Bulletin Topic 14. The risk-free interest rate is the rate for constant yield U.S. Treasury securities with a term to maturity that is consistent with the expected term of the award. Summarized information about stock options outstanding at December 31, 2017 under the 2003 Plan and the 2012 Incentive Plan is as follows. Number of options (in thousands) Weighted average exercise price Options outstanding at December 31, 2016 2,887 $ 15.59 Options granted 1,034 $ 27.09 Options exercised (833 ) $ 9.20 Options forfeited (24 ) $ 23.81 Options expired — $ — Options outstanding at December 31, 2017 3,064 $ 21.14 Options outstanding at December 31, 2017 Options exercisable at December 31, 2017 Range of exercise prices Shares outstanding (in thousands) Weighted average remaining contractual life Weighted average exercise price Shares exercisable (in thousands) Weighted average exercise price $8.18 - $9.55 294 0.69 $ 8.46 294 $ 8.46 $13.22 - $17.80 625 3.10 $ 15.01 11 $ 16.45 $19.71 - $22.70 839 2.05 $ 21.87 73 $ 21.50 $23.40 - $27.33 1,306 4.33 $ 26.47 141 $ 24.21 At December 31, 2017 , the aggregate intrinsic value was $30.6 million for outstanding options and $8.5 million for exercisable options, based on the Company’s quoted closing market price of $31.13 per share on that date. The remaining weighted average contractual term of exercisable options at December 31, 2017 was 1.07 years. The total intrinsic value of options exercised during the years ended December 31, 2017, 2016 and 2015 was $13.2 million , $1.6 million and $1.3 million , respectively. The tax related benefit realized from the exercise of stock options totaled $5.0 million , $0.5 million and $0.3 million for the years ended December 31, 2017, 2016 and 2015 , respectively. At December 31, 2017 , the total remaining unrecognized compensation expense related to unvested stock options was approximately $9.8 million and the weighted average remaining requisite service period (vesting period) of all unvested stock options was 0.78 years. The fair value of options vested during 2017 , 2016 and 2015 was $2.1 million , $3.0 million and $1.3 million , respectively. Restricted Stock, Restricted Stock Units and Common Stock The Company has granted stock, restricted stock and restricted stock unit awards to employees, outside directors and advisors of the Company under the 2003 Plan and the 2012 Incentive Plan. The stock and restricted stock are issued upon grant, with the restrictions, if any, being removed upon vesting. The restricted stock units are issued upon vesting, unless the recipient makes an election to defer issuance for a set term after vesting. Restricted stock and restricted stock units granted in 2017, 2016 and 2015 were service based awards and vest over the service period, which is one to four years. All restricted stock and restricted stock unit awards outstanding at December 31, 2017 were granted under the 2012 Incentive Plan. A summary of the non-vested restricted stock and restricted stock units as of December 31, 2017 is presented below (in thousands, except fair value). Restricted Stock Restricted Stock Units Non-vested restricted stock and restricted stock units Shares Weighted average fair value Shares Weighted average fair value Non-vested at December 31, 2016 1,039 $ 18.23 82 $ 21.32 Granted 531 $ 26.25 113 $ 23.77 Vested (429 ) $ 16.54 (124 ) $ 22.38 Forfeited (37 ) $ 22.94 (6 ) 23.45 Non-vested at December 31, 2017 1,104 $ 22.59 65 $ 23.36 At December 31, 2017 , the aggregate intrinsic value for the restricted stock and restricted stock units outstanding was $36.4 million as calculated based on the maximum number of shares of restricted stock and restricted stock units vesting, using the Company’s quoted closing market price of $31.13 per share on that date. At December 31, 2017 , the total remaining unrecognized compensation expense related to unvested restricted stock and restricted stock units was approximately $14.4 million and the weighted average remaining requisite service period (vesting period) of all non-vested restricted stock and restricted stock units was 0.95 years. The fair value of restricted stock and restricted stock units vested during 2017 , 2016 and 2015 was $9.9 million , $4.6 million and $0.8 million , respectively. The total tax benefit recognized for all stock-based compensation was $6.8 million , $4.3 million and $3.4 million for the years ended December 31, 2017, 2016 and 2015 , respectively. During the years ended December 31, 2017, 2016 and 2015 , the total expense attributable to stock options was $7.1 million , $5.9 million and $4.7 million , respectively. At December 31, 2017, 2016 and 2015 , the Company had recorded $0.4 million , $1.4 million and zero of long-term liabilities and zero , zero and $1.0 million of current liabilities, respectively, related to its outstanding liability-based stock options. The Company did not settle any liability-based awards in cash for the years ended December 31, 2017, 2016 and 2015 , respectively. During the years ended December 31, 2017, 2016 and 2015 , the total expense attributable to restricted stock and restricted stock units was $12.9 million , $6.6 million and $4.7 million , respectively. During the year ended December 31, 2017 , the Company capitalized $3.3 million related to stock-based compensation and expensed the remaining $16.7 million . In mid-February 2018, the Company granted awards of 667,488 shares of restricted stock and options to purchase 563,408 shares of the Company’s common stock at an exercise price of $29.68 per share to certain of its employees. The fair value of these awards was approximately $26.9 million . All of these awards vest ratably over three years. |
Employee Benefit Plans
Employee Benefit Plans | 12 Months Ended |
Dec. 31, 2017 | |
Retirement Benefits [Abstract] | |
EMPLOYEE BENEFIT PLANS | 401(k) Plan All full-time Company employees are eligible to join the Company’s defined contribution retirement plan the first day of the calendar month immediately following their date of employment. Each employee may contribute up to the maximum allowable under the Internal Revenue Code. Each year, the Company makes a contribution to the plan which equals 3% of the employee’s annual compensation, referred to as the Employer’s Safe Harbor Non-Elective Contribution, which totaled $0.9 million , $0.7 million and $0.6 million in 2017 , 2016 and 2015 , respectively. In addition, each year, the Company may make a discretionary matching contribution, as well as additional contributions. The Company’s discretionary matching contributions totaled $1.1 million , $0.9 million and $0.8 million in 2017 , 2016 and 2015 , respectively. The Company made no additional contributions in any reporting period presented. |
Equity
Equity | 12 Months Ended |
Dec. 31, 2017 | |
Stockholders' Equity Note [Abstract] | |
EQUITY | Stock Offerings, Retirement and Issuances On October 10, 2017 , the Company completed a public offering of 8,000,000 shares of its common stock. After deducting offering costs totaling approximately $0.3 million , the Company received net proceeds of approximately $208.4 million . A portion of the proceeds from this offering were used to acquire approximately 6,600 net acres of additional leasehold and minerals in the Delaware Basin at a total acquisition cost of approximately $38 million and to fund certain midstream initiatives and opportunities. The remaining proceeds have been and are expected to be used for other midstream development, acreage acquisitions and general corporate purposes, including to fund a portion of the Company’s current and future capital expenditures. On June 1, 2017, the shareholders of the Company approved an amendment to the Company’s Amended and Restated Certificate of Formation that authorized an increase in the number of authorized shares of common stock from 120,000,000 to 160,000,000 shares. On December 9, 2016 , the Company completed a public offering of 6,000,000 shares of its common stock. After deducting offering costs totaling approximately $0.4 million , the Company received net proceeds of approximately $145.8 million . On March 11, 2016, the Company completed a public offering of 7,500,000 shares of its common stock. After deducting offering costs totaling approximately $0.8 million , the Company received net proceeds of approximately $141.5 million . On April 21, 2015, the Company completed a public offering of 7,000,000 shares of its common stock. After deducting offering costs totaling approximately $1.2 million , the Company received net proceeds of approximately $187.6 million . As discussed in Note 5, the Company issued 3,300,000 shares of common stock and 150,000 shares of a new series of Series A Preferred Stock to HEYCO Energy Group, Inc. in connection with the HEYCO Merger. Pursuant to the statement of resolutions, each share of Series A Preferred Stock would automatically convert into ten shares of Matador common stock, subject to customary anti-dilution adjustments, upon the vote and approval by Matador’s shareholders of an amendment to Matador’s Amended and Restated Certificate of Formation to increase the number of shares of authorized Matador common stock. On April 2, 2015, the shareholders of the Company approved an amendment to the Company’s Amended and Restated Certificate of Formation that authorized an increase in the number of authorized shares of common stock from 80,000,000 shares to 120,000,000 shares. Following such approval, the 150,000 outstanding shares of Series A Preferred Stock converted to 1,500,000 shares of common stock on April 6, 2015. Pursuant to the terms of the HEYCO Merger, 166,667 of the 1,500,000 shares were being held in escrow at December 31, 2017 to satisfy certain conditions under the merger agreement. Treasury Stock On November 1, 2017, October 27, 2016 and October 30, 2015, Matador’s Board of Directors canceled all of the shares of treasury stock outstanding as of September 30, 2017, 2016 and 2015, respectively. These shares were restored to the status of authorized but unissued shares of common stock of the Company. The shares of treasury stock outstanding at December 31, 2017 , 2016 and 2015 represent forfeitures of non-vested restricted stock awards and forfeitures of fully vested restricted stock awards due to net share settlements with employees. |
Derivative Financial Instrument
Derivative Financial Instruments | 12 Months Ended |
Dec. 31, 2017 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
DERIVATIVE FINANCIAL INSTRUMENTS | From time to time, the Company uses derivative financial instruments to mitigate its exposure to commodity price risk associated with oil, natural gas and natural gas liquids (“NGL”) prices. The Company records derivative financial instruments on its consolidated balance sheets as either assets or liabilities measured at fair value. The Company has elected not to apply hedge accounting for its existing derivative financial instruments. As a result, the Company recognizes the change in derivative fair value between reporting periods currently in its consolidated statements of operations as an unrealized gain or loss. The fair value of the Company’s derivative financial instruments is determined using industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. The Company has evaluated and considered the credit standings of its counterparties in determining the fair value of its derivative financial instruments. At December 31, 2017 , the Company had various costless collar and swap contracts open and in place to mitigate its exposure to oil and natural gas price volatility, each with a specific term (calculation period), notional quantity (volume hedged) and price floor and ceiling and fixed price for the swaps. Each contract is set to expire at varying times during 2018. The following is a summary of the Company’s open costless collar contracts for oil and natural gas at December 31, 2017 . Notional Quantity (Bbl or MMBtu) Weighted Average Price Floor ($/Bbl or Weighted Average Price Ceiling ($/Bbl or Fair Value of Asset (Liability) Commodity Calculation Period Oil - WTI (1) 01/01/2018 - 12/31/2018 2,880,000 $ 44.27 $ 60.29 (8,414 ) Oil - LLS (2) 01/01/2018 - 12/31/2018 720,000 $ 45.00 $ 63.05 (2,451 ) Natural Gas 01/01/2018 - 12/31/2018 16,800,000 $ 2.58 $ 3.67 1,190 Total open costless collar contracts $ (9,675 ) _____________________ (1) NYMEX West Texas Intermediate crude oil. (2) Argus Louisiana Light Sweet crude oil. The following is a summary of the Company’s open basis swaps contracts for oil at December 31, 2017 . Commodity Calculation Period Notional Quantity (Bbl or Gal) Fixed Price ($/Bbl or $/Gal) Fair Value of Asset (Liability) Oil Basis Swaps 01/01/2018 - 12/31/2018 5,220,000 $ (1.02 ) $ (5,564 ) Total open swap contracts $ (5,564 ) Total open derivative financial instruments $ (15,239 ) From time-to-time, we enter into derivative financial instruments with certain counterparties. These derivative financial instruments are subject to master netting arrangements, and all but one counterparty allow for cross-commodity master netting provided the settlements dates for the commodities are the same. The Company does not present different types of commodities with the same counterparty on a net basis in its consolidated balance sheets. The following table presents the gross asset and liability fair values of the Company’s commodity price derivative financial instruments and the location of these balances in the consolidated balance sheets as of December 31, 2017 and December 31, 2016 (in thousands). Derivative Instruments Gross amounts recognized Gross amounts netted in the consolidated balance sheets Net amounts presented in the consolidated balance sheets December 31, 2017 Current assets $ 131,092 $ (129,902 ) $ 1,190 Current liabilities (146,331 ) 129,902 (16,429 ) Total $ (15,239 ) $ — $ (15,239 ) December 31, 2016 Current liabilities $ (24,203 ) $ — $ (24,203 ) Other liabilities (751 ) — (751 ) Total $ (24,954 ) $ — $ (24,954 ) The following table summarizes the location and aggregate fair value of all derivative financial instruments recorded in the consolidated statements of operations for the periods presented (in thousands). These derivative financial instruments are not designated as hedging instruments. Year Ended December 31, Type of Instrument Location in Statement of Operations 2017 2016 2015 Derivative Instrument Oil Revenues: Realized (loss) gain on derivatives $ (3,657 ) $ 5,851 $ 62,259 Natural Gas Revenues: Realized (loss) gain on derivatives (608 ) 3,435 12,653 Natural Gas Liquids (NGL) Revenues: Realized (loss) gain on derivatives (56 ) — 2,182 Realized (loss) gain on derivatives (4,321 ) 9,286 77,094 Oil Revenues: Unrealized gain (loss) on derivatives 2,638 (18,969 ) (31,897 ) Natural Gas Revenues: Unrealized gain (loss) on derivatives 7,077 (22,269 ) (5,440 ) Natural Gas Liquids (NGL) Revenues: Unrealized loss on derivatives — — (1,928 ) Unrealized gain (loss) on derivatives 9,715 (41,238 ) (39,265 ) Total $ 5,394 $ (31,952 ) $ 37,829 |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2017 | |
Fair Value Disclosures [Abstract] | |
FAIR VALUE MEASUREMENTS | The Company measures and reports certain financial and non-financial assets and liabilities on a fair value basis. 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 (exit price). Fair value measurements are classified and disclosed in one of the following categories. Level 1 Unadjusted quoted prices for identical, unrestricted assets or liabilities in active markets. Level 2 Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that are valued with industry standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument and can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace. Level 3 Unobservable inputs that are not corroborated by market data which reflect a company’s own market assumptions. Financial and non-financial assets and liabilities are classified based on the lowest 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, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. At December 31, 2017 and 2016 , the carrying values reported on the consolidated balance sheets for accounts receivable, prepaid expenses, accounts payable, accrued liabilities, royalties payable, amounts due to affiliates, advances from joint interest owners, amounts due to joint ventures and other current liabilities approximate their fair values due to their short-term maturities. At December 31, 2017 and 2016 , the fair value of the Company’s Notes was $614.1 million and $605.2 million , respectively, based on quoted market prices, which represents Level 1 inputs in the fair value hierarchy. The following tables summarize the valuation of the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis in accordance with the classifications provided above as of December 31, 2017 and 2016 (in thousands). Fair Value Measurements at Description Level 1 Level 2 Level 3 Total Assets (Liabilities) Natural gas derivatives $ — $ 1,190 $ — $ 1,190 Oil derivatives and basis swaps — (16,429 ) — (16,429 ) Total $ — $ (15,239 ) $ — $ (15,239 ) Fair Value Measurements at Description Level 1 Level 2 Level 3 Total Assets (Liabilities) Oil and natural gas derivatives $ — $ (24,954 ) $ — $ (24,954 ) Total $ — $ (24,954 ) $ — $ (24,954 ) Additional disclosures related to derivative financial instruments are provided in Note 11. For purposes of fair value measurement, the Company determined that derivative financial instruments (e.g., oil, natural gas and NGL derivatives) should be classified as Level 2 in the fair value hierarchy. Certain assets and liabilities are measured at fair value on a nonrecurring basis, including assets and liabilities acquired in a business combination, lease and well equipment inventory when the market value is determined to be lower than the cost of the inventory and other property and equipment that are reduced to fair value when they are impaired or held for sale. The Company recorded no impairment to its lease and well equipment inventory or other property and equipment in 2017 and 2016 . The Company determined the value of the lease and well equipment inventory using Level 3 inputs and assumptions. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
COMMITMENTS AND CONTINGENCIES | Office Lease The Company’s corporate headquarters are located at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. The lease for the Company’s corporate headquarters expires during 2026 . The base rate escalates during the course of the lease; however, the Company recognizes rent expense ratably over the term of the lease. From time to time, the Company also enters into leases for field offices in locations where it has active field operations. These leases are typically for terms of less than five years and are not considered principal properties. The following is a schedule of future minimum lease payments required under all office lease agreements as of December 31, 2017 (in thousands). Year Ending December 31, Amount 2018 $ 2,495 2019 2,528 2020 2,602 2021 2,660 2022 2,774 Thereafter 9,561 Total $ 22,620 Rent expense, including fees for operating expenses and consumption of electricity, was $2.6 million , $2.9 million and $1.7 million for 2017 , 2016 and 2015 , respectively. Processing, Transportation and Salt Water Disposal Commitments Delaware Basin — Loving County, Texas Natural Gas Processing In late 2015, the Company entered into a 15 -year, fixed-fee natural gas gathering and processing agreement whereby the Company committed to deliver the anticipated natural gas production from a significant portion of its Loving County, Texas acreage in West Texas through the counterparty’s gathering system for processing at the counterparty’s facilities. Under this agreement, if the Company does not meet the volume commitment for transportation and processing at the facilities in a contract year, it may be required to pay a deficiency fee per MMBtu of natural gas deficiency. At the end of each year of the agreement, the Company can elect to have the previous year’s actual transportation and processing volumes be the new minimum commitment for each of the remaining years of the contract. As such, the Company has the ability to unilaterally reduce the gathering and processing commitment if the Company’s production in the Loving County area is less than the Company’s currently projected production. If the Company ceased operations in this area at December 31, 2017 , the total deficiency fee required to be paid would be approximately $8.4 million . In addition, if the Company elects to reduce the gathering and processing commitment in any year, the Company has the ability to elect to increase the committed volumes in any future year to the originally agreed gathering and processing commitment. Any quantity in excess of the volume commitment delivered in a contract year can be carried over to the next contract year for purposes of calculating the natural gas deficiency. The Company paid approximately $14.4 million and $9.8 million in processing and gathering fees under this agreement during the years ended December 31, 2017 and 2016 , respectively. The Company can elect to either sell the residue gas to the counterparty at the tailgate of its processing plants or have the counterparty deliver to the Company the residue gas in-kind to be sold to third parties downstream of the plants. Delaware Basin — Eddy County, New Mexico Natural Gas Transportation In late 2017, the Company entered into an 18 -year, fixed-fee natural gas transportation agreement whereby the Company committed to deliver a portion of the residue natural gas production at the tailgate of the Black River Processing Plant to transport through the counterparty’s pipeline. Under this agreement, if the Company does not meet the volume commitment for transportation in a contract year, it may be required to pay a deficiency fee per MMBtu of natural gas deficiency. The minimum contractual obligation at December 31, 2017 was approximately $59.4 million . The Company paid approximately $0.2 million in transportation fees, which included no deficiency fees, under this agreement during the year ended December 31, 2017 . In late 2017, the Company also entered into a fixed-fee NGL transportation and fractionation agreement whereby the Company committed to deliver its NGL production at the tailgate of the Black River Processing Plant. The Company is committed to deliver a minimum amount of NGLs to the counterparty upon construction and completion of a pipeline expansion and a fractionation facility by the counterparty, which is currently expected to be completed late in 2019. The Company has no rights to compel the counterparty to construct this pipeline extension or fractionation facility. If the counterparty does not construct the pipeline extension and fractionation facility, then the Company does not have any minimum volume commitments under the agreement. If the counterparty constructs the pipeline extension and fractionation facility on or prior to February 28, 2021, then the Company will have a commitment to deliver a minimum amount of NGLs for seven years following the completion of the pipeline extension and fractionation facility. If the Company does not meet its NGL volume commitment in any quarter during the seven -year commitment period, it will be required to pay a deficiency fee per gallon of NGL deficiency. The Company’s minimum contractual obligation over the seven -year period containing minimum NGL commitments would be approximately $132.5 million . Delaware Basin — San Mateo The Company dedicated its current and future leasehold interests in the Rustler Breaks and Wolf asset areas pursuant to 15 -year, fixed-fee natural gas, oil and salt water gathering agreements and salt water disposal agreements. In addition, the Company dedicated its current and future leasehold interests in the Rustler Breaks asset area pursuant to a 15 -year, fixed-fee natural gas processing agreement (collectively with the gathering and salt water disposal agreements, the “Operational Agreements”). San Mateo provides the Company with firm service under each of the Operational Agreements in exchange for certain minimum volume commitments. The minimum contractual obligation under the Operational Agreements at December 31, 2017 was approximately $232.6 million . The Company paid approximately $39.4 million in fees under the Operational Agreements during the year ended December 31, 2017 . Beginning in May 2017, a subsidiary of San Mateo entered into certain agreements with third parties for the engineering, procurement, construction and installation of an expansion of the Black River Processing Plant, including required compression. The expansion is expected to be placed into service in 2018. San Mateo’s total commitments under these agreements are $55.3 million . The subsidiary of San Mateo paid approximately $49.7 million under these agreements during the year ended December 31, 2017 . As of December 31, 2017 , the remaining obligations under these agreements were $5.6 million , which are expected to be incurred within the next year. On January 22, 2018, a subsidiary of San Mateo entered into a strategic relationship with a subsidiary of Plains All American Pipeline, L.P. (“Plains”) (see Note 18). Other Commitments The Company does not own or operate its own drilling rigs, but instead enters into contracts with third parties for such drilling rigs. These contracts establish daily rates for the drilling rigs and the term of the Company’s commitment for the drilling services to be provided. The Company would incur a termination obligation if the Company elected to terminate a contract and if the drilling contractor were unable to secure replacement work for the contracted drilling rigs at the same daily rates being charged to the Company prior to the end of their respective contract terms. The Company’s undiscounted minimum outstanding aggregate termination obligations under its drilling rig contracts were approximately $36.5 million at December 31, 2017 . At December 31, 2017 , the Company had outstanding commitments to participate in the drilling and completion of various non-operated wells. If all of these wells are drilled and completed as proposed, the Company’s minimum outstanding aggregate commitments for its participation in these non-operated wells were approximately $24.8 million at December 31, 2017 . The Company expects these costs to be incurred within the next year. Legal Proceedings The Company is a party to several lawsuits encountered in the ordinary course of its business. While the ultimate outcome and impact to the Company cannot be predicted with certainty, in the opinion of management, it is remote that these lawsuits will have a material adverse impact on the Company’s financial condition, results of operations or cash flows. |
Supplemental Disclosures
Supplemental Disclosures | 12 Months Ended |
Dec. 31, 2017 | |
Supplemental Disclosures [Abstract] | |
SUPPLEMENTAL DISCLOSURES | Accrued Liabilities The following table summarizes the Company’s current accrued liabilities at December 31, 2017 and 2016 (in thousands). December 31, 2017 2016 Accrued evaluated and unproved and unevaluated property costs $ 105,347 $ 54,273 Accrued support equipment and facilities costs 14,823 15,139 Accrued lease operating expenses 12,611 16,009 Accrued interest on debt 8,345 6,541 Accrued asset retirement obligations 1,176 915 Accrued partners’ share of joint interest charges 27,628 5,572 Other 4,418 3,011 Total accrued liabilities $ 174,348 $ 101,460 Supplemental Cash Flow Information The following table provides supplemental disclosures of cash flow information for the years ended December 31, 2017, 2016 and 2015 (in thousands). Year Ended December 31, 2017 2016 2015 Cash paid for income taxes $ — $ 2,895 $ 506 Cash paid for interest expense, net of amounts capitalized $ 32,760 $ 27,464 $ 16,154 Increase in asset retirement obligations related to mineral properties $ 4,385 $ 3,817 $ 2,510 (Decrease) increase in asset retirement obligations related to support equipment and facilities $ (60 ) $ 222 $ 383 Increase (decrease) in liabilities for oil and natural gas properties capital expenditures $ 48,929 $ 1,775 $ (30,683 ) (Decrease) increase in liabilities for support equipment and facilities $ (955 ) $ (588 ) $ 12,076 Issuance of restricted stock units for director and advisor services $ — $ 992 $ 584 Stock-based compensation expense recognized as liability $ 362 $ 569 $ 79 (Decrease) increase in liabilities for accrued cost to issue equity $ (343 ) $ 343 $ — Transfer of inventory (to) from oil and natural gas properties $ (374 ) $ 395 $ 615 Transfer of inventory to midstream and other property and equipment $ (317 ) $ — $ — |
Subsidiary Guarantors (Notes)
Subsidiary Guarantors (Notes) | 12 Months Ended |
Dec. 31, 2017 | |
Equity [Abstract] | |
SUBSIDIARY GUARANTORS | On April 14, 2015, Matador issued the Original Notes and on December 9, 2016, Matador issued the Additional Notes (see Note 6), which are jointly and severally guaranteed by certain subsidiaries of Matador (the “Guarantor Subsidiaries”) on a full and unconditional basis (except for customary release provisions). Matador filed a registration statement on Form S-3 with the SEC on August 11, 2017, which became effective upon filing, registering, among other securities, senior and subordinated debt securities and guarantees of debt securities by the Guarantor Subsidiaries. At December 31, 2017 , the Guarantor Subsidiaries were 100% owned by Matador. Matador is a parent holding company and has no independent assets or operations, and there are no significant restrictions on the ability of Matador to obtain funds from the Guarantor Subsidiaries by dividend or loan. San Mateo and its subsidiaries are not guarantors of the Notes. The following presents condensed consolidating financial information of the issuer (Matador), the Non-Guarantor Subsidiaries, the Guarantor Subsidiaries and all entities on a consolidated basis (in thousands). Elimination entries are necessary to combine the entities. This financial information is presented in accordance with the requirements of Rule 3-10 of Regulation S-X. The following financial information may not necessarily be indicative of results of operations, cash flows or financial position had the Guarantor Subsidiaries operated as independent entities. Condensed Consolidating Balance Sheet Matador Non-Guarantor Subsidiaries Guarantor Subsidiaries Eliminating Entries Consolidated ASSETS Intercompany receivable $ 585,109 $ 2,912 $ — $ (588,021 ) $ — Third-party current assets 2,240 9,334 245,596 — 257,170 Net property and equipment — 223,178 1,658,278 — 1,881,456 Investment in subsidiaries 1,147,295 — 111,077 (1,258,372 ) — Third-party long-term assets 6,425 — 3,642 (3,003 ) 7,064 Total assets $ 1,741,069 $ 235,424 $ 2,018,593 $ (1,849,396 ) $ 2,145,690 LIABILITIES AND EQUITY Intercompany payable $ — $ — $ 588,021 $ (588,021 ) $ — Third-party current liabilities 8,847 19,891 254,142 (274 ) 282,606 Senior unsecured notes payable 574,073 — — — 574,073 Other third-party long-term liabilities 1,593 3,466 29,135 (2,729 ) 31,465 Total equity attributable to Matador Resources Company 1,156,556 111,077 1,147,295 (1,258,372 ) 1,156,556 Non-controlling interest in subsidiaries — 100,990 — — 100,990 Total liabilities and equity $ 1,741,069 $ 235,424 $ 2,018,593 $ (1,849,396 ) $ 2,145,690 Condensed Consolidating Balance Sheet Matador Non-Guarantor Subsidiaries Guarantor Subsidiaries Eliminating Entries Consolidated ASSETS Intercompany receivable $ 316,791 $ 3,571 $ 12,091 $ (332,453 ) $ — Third-party current assets 101,102 4,242 173,838 — 279,182 Net property and equipment 33 113,107 1,071,385 — 1,184,525 Investment in subsidiaries 856,762 — 90,275 (947,037 ) — Third-party long-term assets — — 958 — 958 Total assets $ 1,274,688 $ 120,920 $ 1,348,547 $ (1,279,490 ) $ 1,464,665 LIABILITIES AND EQUITY Intercompany payable $ — $ 12,091 $ 320,362 $ (332,453 ) $ — Third-party current liabilities 9,265 16,632 143,608 — 169,505 Senior unsecured notes payable 573,924 — — — 573,924 Other third-party long-term liabilities 1,374 602 27,815 — 29,791 Total equity attributable to Matador Resources Company 690,125 90,275 856,762 (947,037 ) 690,125 Non-controlling interest in subsidiaries — 1,320 — — 1,320 Total liabilities and equity $ 1,274,688 $ 120,920 $ 1,348,547 $ (1,279,490 ) $ 1,464,665 Condensed Consolidating Statement of Operations Matador Non-Guarantor Subsidiaries Guarantor Subsidiaries Eliminating Entries Consolidated Total revenues $ — $ 47,883 $ 531,508 $ (35,115 ) $ 544,276 Total expenses 5,610 21,260 391,680 (35,115 ) 383,435 Operating (loss) income (5,610 ) 26,623 139,828 — 160,841 Net gain on asset sales and inventory impairment — — 23 — 23 Interest expense (34,565 ) — — — (34,565 ) Other income 27 37 3,487 — 3,551 Earnings in subsidiaries 157,589 — 14,251 (171,840 ) — Income before income taxes 117,441 26,660 157,589 (171,840 ) 129,850 Total income tax (benefit) provision (8,426 ) 269 — — (8,157 ) Net income attributable to non-controlling interest in subsidiaries — (12,140 ) — — (12,140 ) Net income attributable to Matador Resources Company shareholders $ 125,867 $ 14,251 $ 157,589 $ (171,840 ) $ 125,867 Condensed Consolidating Statement of Operations Matador Non-Guarantor Subsidiaries Guarantor Subsidiaries Eliminating Entries Consolidated Total revenues $ — $ 17,302 $ 257,828 $ (10,708 ) $ 264,422 Total expenses 5,319 7,031 439,947 (10,708 ) 441,589 Operating (loss) income (5,319 ) 10,271 (182,119 ) — (177,167 ) Net gain on asset sales and inventory impairment — — 107,277 — 107,277 Interest expense (28,199 ) — — — (28,199 ) Other expense — — (4 ) — (4 ) (Loss) earnings in subsidiaries (64,349 ) — 9,810 54,539 — (Loss) income before income taxes (97,867 ) 10,271 (65,036 ) 54,539 (98,093 ) Total income tax (benefit) provision (446 ) 97 (687 ) — (1,036 ) Net income attributable to non-controlling interest in subsidiaries — (364 ) — — (364 ) Net (loss) income attributable to Matador Resources Company shareholders $ (97,421 ) $ 9,810 $ (64,349 ) $ 54,539 $ (97,421 ) Condensed Consolidating Statement of Operations Matador Non-Guarantor Subsidiaries Guarantor Subsidiaries Eliminating Entries Consolidated Total revenues $ — $ 6,310 $ 316,067 $ (4,344 ) $ 318,033 Total expenses 5,739 2,944 1,120,356 (4,344 ) 1,124,695 Operating (loss) income (5,739 ) 3,366 (804,289 ) — (806,662 ) Net gain on asset sales and inventory impairment — — 908 — 908 Interest expense (20,511 ) — (1,243 ) — (21,754 ) Other income — — 616 — 616 (Loss) earnings in subsidiaries (658,698 ) — 2,458 656,240 — (Loss) income before income taxes (684,948 ) 3,366 (801,550 ) 656,240 (826,892 ) Total income tax (benefit) provision (5,163 ) 647 (142,852 ) — (147,368 ) Net income attributable to non-controlling interest in subsidiaries — (261 ) — — (261 ) Net (loss) income attributable to Matador Resources Company shareholders $ (679,785 ) $ 2,458 $ (658,698 ) $ 656,240 $ (679,785 ) Condensed Consolidating Statement of Cash Flows Matador Non-Guarantor Subsidiaries Guarantor Subsidiaries Eliminating Entries Consolidated Net cash (used in) provided by operating activities $ (307,982 ) $ 21,308 $ 585,799 $ — $ 299,125 Net cash provided by (used in) investing activities 33 (119,922 ) (597,519 ) (106,595 ) (824,003 ) Net cash provided by (used in) financing activities 208,440 96,307 (2,843 ) 106,595 408,499 Decrease in cash (99,509 ) (2,307 ) (14,563 ) — (116,379 ) Cash at beginning of year 99,795 2,307 110,782 — 212,884 Cash at end of year $ 286 $ — $ 96,219 $ — $ 96,505 Condensed Consolidating Statement of Cash Flows Matador Non-Guarantor Subsidiaries Guarantor Subsidiaries Eliminating Entries Consolidated Net cash (used in) provided by operating activities $ (45,215 ) $ 6,694 $ 172,607 $ — $ 134,086 Net cash used in investing activities (324,724 ) (64,683 ) (401,034 ) 384,801 (405,640 ) Net cash provided by financing activities 469,654 60,110 322,743 (384,801 ) 467,706 Increase in cash 99,715 2,121 94,316 — 196,152 Cash at beginning of year 80 186 16,466 — 16,732 Cash at end of year $ 99,795 $ 2,307 $ 110,782 $ — $ 212,884 Condensed Consolidating Statement of Cash Flows Matador Non-Guarantor Subsidiaries Guarantor Subsidiaries Eliminating Entries Consolidated Net cash (used in) provided by operating activities $ (31,271 ) $ 13,916 $ 225,890 $ — $ 208,535 Net cash used in investing activities (546,715 ) (31,101 ) (410,843 ) 563,505 (425,154 ) Net cash provided by financing activities 577,973 17,353 193,123 (563,505 ) 224,944 (Decrease) increase in cash (13 ) 168 8,170 — 8,325 Cash at beginning of year 93 18 8,296 — 8,407 Cash at end of year $ 80 $ 186 $ 16,466 $ — $ 16,732 |
Related Party Transactions (Not
Related Party Transactions (Notes) | 12 Months Ended |
Dec. 31, 2017 | |
Related Party Transactions [Abstract] | |
RELATED PARTY TRANSACTIONS | In June 2015, the Company entered into two joint ventures to develop certain leasehold interests held by certain affiliates (the “HEYCO Affiliates”) of HEYCO Energy Group, Inc., the former parent company of HEYCO. The HEYCO Affiliates are owned by George M. Yates, who is a member of the Company’s Board of Directors, and certain of his affiliates. Pursuant to the terms of the transaction, the HEYCO Affiliates contributed an aggregate of approximately 1,900 net acres, primarily in the same properties previously held by HEYCO, to the two newly-formed entities in exchange for a 50% interest in each entity. The Company has agreed to contribute an aggregate of approximately $14 million in exchange for the other 50% interest in both entities. As of December 31, 2017 , the Company had contributed an aggregate of approximately $4.4 million to the two entities. The Company’s contributions will be used to fund future capital expenditures associated with the interests being acquired as well as to fund acquisitions of other non-operated acreage opportunities. |
Segment Reporting (Notes)
Segment Reporting (Notes) | 12 Months Ended |
Dec. 31, 2017 | |
Segment Reporting [Abstract] | |
Segment Reporting | The Company operates in two business segments: (i) exploration and production and (ii) midstream. The exploration and production segment is engaged in the acquisition, exploration and development of oil and natural gas properties and is currently focused primarily on the oil and liquids-rich portion of the Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. The Company also operates in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas. The midstream segment conducts midstream operations in support of the Company’s exploration, development and production operations and provides natural gas processing, oil transportation services, natural gas, oil and salt water gathering services and salt water disposal services to third parties. Substantially all of the Company’s midstream operations in the Rustler Breaks and Wolf asset areas in the Delaware Basin are conducted through San Mateo (see Note 5). The following tables present selected financial information for the periods presented regarding the Company’s operating segments on a stand-alone basis, corporate expenses that are not allocated to a segment and the consolidation and elimination entries necessary to arrive at the financial information for the Company on a consolidated basis (in thousands). On a consolidated basis, midstream services revenues consist primarily of those revenues from midstream operations related to third parties, including working interest owners in the Company’s operated wells. All midstream services revenues associated with Company-owned production are eliminated in consolidation. In evaluating the operating results of the exploration and production and midstream segments, the Company does not allocate certain expenses to the individual segments, including general and administrative expenses. Such expenses are reflected in the column labeled “Corporate.” Exploration and Production Consolidations and Eliminations Consolidated Company Midstream Corporate Year Ended December 31, 2017 Oil and natural gas revenues $ 525,862 $ 2,822 $ — $ — $ 528,684 Midstream services revenues — 47,037 — (36,839 ) 10,198 Realized loss on derivatives (4,321 ) — — — (4,321 ) Unrealized gain on derivatives 9,715 — — — 9,715 Expenses (1) 333,923 23,420 62,931 (36,839 ) 383,435 Operating income (loss) (2) $ 197,333 $ 26,439 $ (62,931 ) $ — $ 160,841 Total assets $ 1,768,393 $ 257,871 $ 119,426 $ — $ 2,145,690 Capital expenditures (3) $ 753,157 $ 114,113 $ 5,688 $ — $ 872,958 _____________________ (1) Includes depletion, depreciation and amortization expenses of $170.5 million and $5.2 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $1.7 million . (2) Includes $12.1 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment. (3) Includes $54.9 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment. Exploration and Production Consolidations and Eliminations Consolidated Company Midstream Corporate Year Ended December 31, 2016 Oil and natural gas revenues $ 289,512 $ 1,644 $ — $ — $ 291,156 Midstream services revenues — 18,982 — (13,764 ) 5,218 Realized gain on derivatives 9,286 — — — 9,286 Unrealized loss on derivatives (41,238 ) — — — (41,238 ) Expenses (1) 391,098 8,254 56,001 (13,764 ) 441,589 Operating (loss) income (2) $ (133,538 ) $ 12,372 $ (56,001 ) $ — $ (177,167 ) Total assets $ 1,098,525 $ 140,459 $ 225,681 $ — $ 1,464,665 Capital expenditures $ 379,881 $ 67,566 $ 6,913 $ — $ 454,360 _____________________ (1) Includes depletion, depreciation and amortization expenses of $118.4 million and $2.7 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $0.9 million and full-cost ceiling impairment expense of $158.6 million for the exploration and production segment. (2) Includes $0.4 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment. Exploration and Production Consolidations and Eliminations Consolidated Company Midstream Corporate Year Ended December 31, 2015 Oil and natural gas revenues $ 277,844 $ 496 $ — $ — $ 278,340 Midstream services revenues — 11,485 — (9,621 ) 1,864 Realized gain on derivatives 77,094 — — — 77,094 Unrealized loss on derivatives (39,265 ) — — — (39,265 ) Expenses (1) 1,078,534 5,178 50,604 (9,621 ) 1,124,695 Operating (loss) income (2) $ (762,861 ) $ 6,803 $ (50,604 ) $ — $ (806,662 ) Total assets $ 1,000,075 $ 75,980 $ 64,806 $ — $ 1,140,861 Capital expenditures (3) $ 622,642 $ 75,009 $ 786 $ — $ 698,437 _____________________ (1) Includes depletion, depreciation and amortization expenses of $176.7 million and $1.6 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $0.5 million and full-cost ceiling impairment expense of $801.2 million for the exploration and production segment. (2) Includes $0.3 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment. (3) In October 2015, the Company sold the Loving County Processing System to EnLink and the cost basis of $31.0 million for those assets was removed from the total midstream assets. |
Subsequent Events
Subsequent Events | 12 Months Ended |
Dec. 31, 2017 | |
Subsequent Events [Abstract] | |
Subsequent Events | On January 22, 2018, a subsidiary of San Mateo entered into a strategic relationship with a subsidiary of Plains to gather and transport crude oil for the Company and third-party customers in and around the Rustler Breaks asset area in Eddy County, New Mexico. Subsidiaries of San Mateo and Plains have agreed to work together through a joint tariff arrangement and related transactions to offer third-party producers located within a joint development area of approximately 400,000 acres in Eddy County, New Mexico (the “Joint Development Area”) crude oil transportation services from the wellhead to Midland, Texas with access to other end markets, such as Cushing and the Gulf Coast. In addition, another subsidiary of Plains has agreed to purchase Matador’s oil production in the Rustler Breaks asset area and in the Wolf asset area in Loving County, Texas. |
Summary of Significant Accoun25
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Policies [Abstract] | |
Basis of Presentation | Basis of Presentation The consolidated financial statements include the accounts of Matador Resources Company and its wholly-owned and majority-owned subsidiaries. These consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”). Accordingly, the Company consolidates certain subsidiaries that are less-than-wholly-owned and the net income and equity attributable to the non-controlling interest in these subsidiaries have been reported separately. The Company proportionately consolidates certain joint ventures that are less-than-wholly-owned and are involved in oil and natural gas exploration. All intercompany balances and transactions have been eliminated in consolidation. |
Use of Estimates | Use of Estimates The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates and assumptions may also affect disclosure of contingent assets and liabilities at the date of the financial statements, purchase price allocations and the reported amounts of revenues and expenses during the reporting period. While the Company believes its estimates are reasonable, changes in facts and assumptions or the discovery of new information may result in revised estimates. Actual results could differ from these estimates. The Company’s consolidated financial statements are based on a number of significant estimates, including oil and natural gas revenues, accrued assets and liabilities, stock-based compensation, valuation of derivative instruments, deferred tax assets and liabilities, purchase price allocations and oil and natural gas reserves. The estimates of oil and natural gas reserves quantities and future net cash flows are the basis for the calculations of depletion and impairment of oil and natural gas properties, as well as estimates of asset retirement obligations and certain tax accruals. The Company’s oil and natural gas reserves estimates, which are inherently imprecise and based upon many factors that are beyond the Company’s control, including oil and natural gas prices, are prepared by the Company’s engineering staff in accordance with guidelines established by the Securities and Exchange Commission (“SEC”) and then audited for their reasonableness and conformance with SEC guidelines by Netherland, Sewell & Associates, Inc., independent reservoir engineers. |
Restricted Cash | Restricted Cash Restricted cash represents a portion of the cash associated with the Company’s less-than-wholly-owned subsidiaries, primarily San Mateo. By contractual agreement, the cash in the accounts held by the Company’s less-than-wholly-owned subsidiaries is not to be commingled with other Company cash and is to be used only to fund the capital expenditures and operations of these less-than-wholly-owned subsidiaries. |
Accounts Receivable | Accounts Receivable The Company sells its operated oil, natural gas and natural gas liquids production to various purchasers (see “ —Revenue Recognition” below). Due to the nature of the markets for oil, natural gas and natural gas liquids, the Company does not believe that the loss of any one purchaser would significantly impact operations. In addition, the Company may participate with industry partners in the drilling, completion and operation of oil and natural gas wells. Substantially all of the Company’s accounts receivable are due from either purchasers of oil, natural gas and natural gas liquids or participants in oil and natural gas wells for which the Company serves as the operator. Accounts receivable are due within 30 to 60 days of the production date and 30 days of the billing date and are stated at amounts due from purchasers and industry partners. Amounts are considered past due if they have been outstanding for 60 days or more. No interest is typically charged on past due amounts. The Company reviews its need for an allowance for doubtful accounts on a periodic basis and determines the allowance, if any, by considering the length of time past due, previous loss history, future net revenues of the debtor’s ownership interest in oil and natural gas properties operated by the Company and the debtor’s ability to pay its obligations, among other things. The Company has no allowance for doubtful accounts related to its accounts receivable for any reporting period presented. |
Lease and Well Equipment Inventory | Lease and Well Equipment Inventory Lease and well equipment inventory is stated at the lower of cost or market and consists entirely of materials or equipment scheduled for use in future well or midstream operations. |
Property and Equipment | The Company uses the full-cost method of accounting for its investments in oil and natural gas properties. Under this method of accounting, all costs associated with the acquisition, exploration and development of oil and natural gas properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred and accumulated in a single cost center representing the Company’s activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive wells, capitalized interest on qualifying projects and general and administrative expenses directly related to acquisition, exploration and development activities, but do not include any costs related to production, selling or general corporate administrative activities. The Company capitalized $23.1 million , $15.7 million and $6.9 million of its general and administrative costs in 2017 , 2016 and 2015 , respectively. The Company capitalized $7.3 million , $3.7 million and $3.9 million of its interest expense for the years ended December 31, 2017, 2016 and 2015 , respectively. Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method based upon production and estimates of proved reserves quantities. Unproved and unevaluated property costs are excluded from the amortization base used to determine depletion. Unproved and unevaluated properties are assessed for possible impairment on a periodic basis based upon changes in operating or economic conditions. This assessment includes consideration of the following factors, among others: the assignment of proved reserves, geological and geophysical evaluations, intent to drill, remaining lease term and drilling activity and results. Upon impairment, the costs of the unproved and unevaluated properties are immediately included in the amortization base. Exploratory dry holes are included in the amortization base immediately upon determination that the well is not productive. Sales of oil and natural gas properties are accounted for as adjustments to net capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between net capitalized costs and proved reserves of oil and natural gas. All costs related to production activities and maintenance and repairs are expensed as incurred. Significant workovers that increase the properties’ reserves are capitalized. Ceiling Test The net capitalized costs of oil and natural gas properties are limited to the lower of unamortized costs less related deferred income taxes or the cost center “ceiling.” The cost center ceiling is defined as the sum of: (a) the present value, discounted at 10% , of future net revenues of proved oil and natural gas reserves, reduced by the estimated costs of developing these reserves, plus (b) unproved and unevaluated property costs not being amortized, plus (c) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less (d) income tax effects related to the properties involved. Any excess of the Company’s net capitalized costs above the cost center ceiling as described above is charged to operations as a full-cost ceiling impairment. The fair value of the Company’s derivative instruments is not included in the ceiling test computation as the Company does not designate these instruments as hedge instruments for accounting purposes. The estimated present value of after-tax future net cash flows from proved oil and natural gas reserves is highly dependent upon the quantities of proved reserves, the estimation of which requires substantial judgment. The associated commodity prices and the applicable discount rate used in these estimates are in accordance with guidelines established by the SEC. Under these guidelines, oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost changes in future periods except by contractual arrangements. Future net revenues are calculated using prices that represent the arithmetic averages of the first-day-of-the-month oil and natural gas prices for the previous 12 -month period and a 10% discount factor is used to determine the present value of future net revenues. For the period from January through December 2017 , these average oil and natural gas prices were $47.79 per Bbl and $2.98 per MMBtu, respectively. For the period from January through December 2016 , these average oil and natural gas prices were $39.25 per Bbl and $2.48 per MMBtu, respectively. For the period from January through December 2015 , these average oil and natural gas prices were $46.79 per Bbl and $2.59 per MMBtu, respectively. In estimating the present value of after-tax future net cash flows from proved oil and natural gas reserves, the average oil prices were further adjusted by property for quality, transportation and marketing fees and regional price differentials, and the average natural gas prices were further adjusted by property for energy content, transportation and marketing fees and regional price differentials. During the year ended December 31, 2017, the Company’s full-cost ceiling exceeded the net capitalized costs less related deferred income taxes. As a result, the Company recorded no impairment to its net capitalized costs during the year ended December 31, 2017. During the year ended December 31, 2016, the Company’s net capitalized costs less related deferred income taxes periodically exceeded the full-cost ceiling. As a result, in the first six months of 2016, the Company recorded an impairment charge of $158.6 million , exclusive of tax effect, to its consolidated statement of operations with the related deferred income tax credit recorded net of a valuation allowance (see Note 7). During the year ended December 31, 2015, the Company’s net capitalized costs less related deferred income taxes exceeded the full-cost ceiling. As a result, throughout 2015, the Company recorded an impairment charge of $801.2 million , exclusive of tax effect, to its consolidated statement of operations for December 31, 2015 with the related deferred income tax credit recorded net of a valuation allowance (see Note 7). As a non-cash item, the full-cost ceiling impairment impacts the accumulated depletion and the net carrying value of the Company’s assets on its consolidated balance sheets, as well as the corresponding shareholders’ equity, but it has no impact on the Company’s net cash flows as reported. Changes in oil and natural gas production rates, oil and natural gas prices, reserves estimates, future development costs and other factors will determine the Company’s actual ceiling test computation and impairment analyses in future periods. Midstream and Other Property and Equipment Midstream and other property and equipment are recorded at historical cost and include midstream equipment and facilities, including the Company’s pipelines, processing facilities and salt water disposal systems, and corporate assets, including furniture, fixtures, equipment, land and leasehold improvements. Midstream equipment and facilities are depreciated over a 30 -year useful life using the straight-line, mid-month convention method. Leasehold improvements are depreciated over the lesser of their useful lives or the term of the lease. Software, furniture, fixtures and other equipment are depreciated over their useful life ( five to 30 years) using the straight-line method. Maintenance and repair costs that do not extend the useful life of the property or equipment are expensed as incurred. See Note 3 for a detail of midstream and other property and equipment |
Asset Retirement Obligations | Asset Retirement Obligations The Company recognizes the fair value of an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. The asset retirement obligation is recorded as a liability at its estimated present value, with an offsetting increase recognized in oil and natural gas properties or midstream and other property and equipment on the consolidated balance sheets. Periodic accretion of the discounted value of the estimated liability is recorded as an expense in the consolidated statements of operations. |
Derivative Financial Instruments | Derivative Financial Instruments From time to time, the Company uses derivative financial instruments to mitigate its exposure to commodity price risk associated with oil, natural gas and natural gas liquids prices. The Company’s derivative financial instruments are recorded on the consolidated balance sheets as either an asset or a liability measured at fair value. The Company has elected not to apply hedge accounting for its existing derivative financial instruments, and as a result, the Company recognizes the change in derivative fair value between reporting periods currently in its consolidated statements of operations. The fair value of the Company’s derivative financial instruments is determined using industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Realized gains and losses from the settlement of derivative financial instruments and unrealized gains and unrealized losses from valuation changes in the remaining unsettled derivative financial instruments are reported under “Revenues” in the consolidated statements of operations. |
Revenue Recognition | Revenue Recognition The Company follows the sales method of accounting for its oil, natural gas and natural gas liquids revenues, whereby it recognizes revenue, net of royalties, on all oil, natural gas and natural gas liquids sold to purchasers regardless of whether the sales are proportionate to the Company’s ownership in the property. Under this method, revenue is recognized at the time oil, natural gas and natural gas liquids are produced and sold, and the Company accrues for revenue earned but not yet received. |
Stock-Based Compensation | Stock-Based Compensation The Company grants common stock, stock options, restricted stock and restricted stock units to members of its Board of Directors and selected employees. All such awards are measured at fair value on the date of grant and are generally recognized as a component of general and administrative expenses in the accompanying statements of operations on a straight-line basis over the awards’ vesting periods. The Company accounts for all outstanding stock options granted under the 2003 Plan (as described and defined in Note 8) as liability instruments as a result of the Company purchasing shares from certain of its employees to assist them in the exercise of outstanding options of the Company’s common stock. The Company uses the Black Scholes Merton option pricing model to measure the fair value of stock options, the closing stock price on the date of grant to measure the fair value of restricted stock and restricted stock unit awards and the Monte Carlo simulation method to measure the fair value of performance units. |
Income Taxes | Income Taxes The Company accounts for income taxes using the asset and liability approach for financial accounting and reporting. The Company evaluates the probability of realizing the future benefits of its deferred tax assets and records a valuation allowance for the portion of any deferred tax assets when it is more likely than not that the benefit from the deferred tax asset will not be realized. The Company recognizes the tax benefit of an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities based on the technical merits of the position. For tax positions meeting the more likely than not threshold, the amount recognized in the financial statements is the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. At December 31, 2017, 2016 and 2015 , the Company had not established any reserves for, nor recorded any unrecognized tax benefits related to, uncertain tax positions. When necessary, the Company would include interest assessed by taxing authorities in “Interest expense” and penalties related to income taxes in “Other expense” on its consolidated statements of operations. |
Earnings Per Common Share | Earnings (Loss) Per Common Share The Company reports basic earnings (loss) attributable to Matador Resources Company shareholders per common share, which excludes the effect of potentially dilutive securities, and diluted earnings (loss) attributable to Matador Resources Company shareholders per common share, which includes the effect of all potentially dilutive securities, unless their impact is anti-dilutive. |
Credit Risk | Credit Risk The Company’s cash is held in financial institutions and at times these amounts exceed the insurance limits of the Federal Deposit Insurance Corporation. Management believes, however, that the Company’s counterparty risks are minimal based on the reputation and history of the institutions selected. The Company uses derivative financial instruments to mitigate its exposure to oil, natural gas and natural gas liquids price volatility. These transactions expose the Company to potential credit risk from its counterparties. The Company manages counterparty credit risk through established internal derivatives policies that are reviewed on an ongoing basis. Additionally, all of the Company’s commodity derivative contracts at December 31, 2017 were with Royal Bank of Canada (“RBC”), The Bank of Nova Scotia, BMO Harris Financing (Bank of Montreal) and SunTrust Bank (or affiliates thereof), parties that are lenders (or affiliates thereof) under the Company’s revolving credit agreement. Accounts receivable constitute the principal component of additional credit risk to which the Company may be exposed. The Company attempts to minimize credit risk exposure to counterparties by monitoring the financial condition and payment history of its purchasers and joint interest partners. |
Recent Accounting Pronouncements | Recent Accounting Pronouncements Revenue from Contracts with Customers . In May 2014, the Financial Accounting Standards Board (“FASB”) issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) , which specifies how and when to recognize revenue. This standard requires expanded disclosures surrounding revenue recognition and is intended to improve, and converge with international standards, the financial reporting requirements for revenue from contracts with customers. In August 2015, the FASB issued ASU 2015-14, which deferred the effective date of ASU 2014-09 for one year to fiscal years beginning after December 15, 2017. Entities have the option of using either a full retrospective or modified approach to adopt the new standards. In December 2016, the FASB issued ASU 2016-20, which clarifies disclosure requirements in ASU 2014-09. The Company adopted the new guidance effective January 1, 2018 using the modified approach. The Company identified all revenue streams and reviewed all contracts and procedures currently in place. The Company determined there is no material impact on its consolidated financial statements as a result of adoption, including no material impact to the timing or amount of revenue recognized, although the Company will be required to include certain additional disclosures regarding revenue from contracts with customers as a result of adoption of ASU 2014-09. Leases . In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) , which requires the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases under previous U.S. GAAP. This ASU will become effective for fiscal years beginning after December 15, 2018 with early adoption permitted. Entities are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The modified retrospective approach includes a number of optional practical expedients that entities may elect to apply. These practical expedients relate to the identification and classification of leases that commenced before the effective date, initial direct costs for leases that commenced before the effective date and the ability to use hindsight in evaluating lessee options to extend or terminate a lease or to purchase the underlying asset. In January 2018, the FASB issued ASU 2018-01, Leases (Topic 842) , which is a land easement practical expedient. If the Company elects to use this practical expedient, the Company should evaluate new or modified land easements under this ASU beginning at the date of adoption. Adoption of ASU 2016-02 will result in increased reported assets and liabilities. The quantitative impact of the new lease standard will depend on the leases in force at the time of adoption. The Company is currently evaluating the impact of the adoption of these ASUs on its consolidated financial statements, including identifying all leases, as defined under the new lease standard, determining which practical expedients the Company will use and quantifying the impact of the new lease standard on existing leases. The Company expects to adopt this lease standard on January 1, 2019. Statement of Cash Flows . In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230) , which specifies that a statement of cash flows explain the change during the period in the total of cash, cash equivalents and amounts generally described as restricted cash or restricted cash equivalents. This ASU will become effective for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years. The update should be applied using a retrospective transition method to each period presented. The Company adopted ASU 2016-18 effective January 1, 2018 and believes that the adoption of this ASU will change the presentation of its beginning and ending cash balances and eliminate the presentation of changes in restricted cash balances from investing activities in its consolidated statement of cash flows. Clarifying the Definition of a Business . In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805) , which specifies the minimum inputs and processes required for an integrated set of assets and activities to meet the definition of a business. This ASU will become effective for fiscal years beginning after December 15, 2017. Entities are required to apply guidance prospectively upon adoption. Effective January 1, 2018, the Company adopted ASU 2017-01, which did not have a material impact on its consolidated financial statements. |
Summary of Significant Accoun26
Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Policies [Abstract] | |
Reconciliations of basic and diluted distributed and undistributed earnings (loss) per common share | The following are reconciliations of the numerators and denominators used to compute the Company’s basic and diluted earnings per common share as reported for the years ended December 31, 2017, 2016 and 2015 (in thousands, except per share data). Year Ended December 31, 2017 2016 2015 Net income (loss) attributable to Matador Resources Company shareholders — numerator $ 125,867 $ (97,421 ) $ (679,785 ) Weighted average common shares outstanding — denominator Basic 102,029 91,273 81,537 Dilutive effect of options and restricted stock units 514 — — Diluted weighted average common shares outstanding 102,543 91,273 81,537 Earnings (loss) per common share attributable to Basic $ 1.23 $ (1.07 ) $ (8.34 ) Diluted $ 1.23 $ (1.07 ) $ (8.34 ) |
Property and Equipment (Tables)
Property and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Property, Plant and Equipment [Abstract] | |
Summary of the Company's property and equipment | The following table presents a summary of the Company’s property and equipment balances as of December 31, 2017 and 2016 (in thousands). December 31, 2017 2016 Oil and natural gas properties Evaluated (subject to amortization) $ 3,004,770 $ 2,408,305 Unproved and unevaluated (not subject to amortization) 637,396 479,736 Total oil and natural gas properties 3,642,166 2,888,041 Accumulated depletion (2,021,169 ) (1,850,882 ) Net oil and natural gas properties 1,620,997 1,037,159 Midstream and other property and equipment Midstream equipment and facilities 258,725 145,662 Furniture, fixtures and other equipment 6,109 5,487 Software 7,942 3,206 Land 2,892 1,437 Leasehold improvements 5,428 5,003 Total midstream and other property and equipment 281,096 160,795 Accumulated depreciation (20,637 ) (13,429 ) Net midstream and other property and equipment 260,459 147,366 Net property and equipment $ 1,881,456 $ 1,184,525 |
Breakdown of the Company's unproved and unevaluated property costs not subject to amortization | The following table provides a breakdown of the Company’s unproved and unevaluated property costs not subject to amortization as of December 31, 2017 and the year in which these costs were incurred (in thousands). Description 2017 2016 2015 2014 and prior Total Costs incurred for Property acquisition $ 213,076 $ 125,689 $ 222,912 $ 45,809 $ 607,486 Exploration wells 16,688 988 547 — 18,223 Development wells 11,396 272 19 — 11,687 Total $ 241,160 $ 126,949 $ 223,478 $ 45,809 $ 637,396 |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Schedule of changes in Company's asset retirement obligations | The following table summarizes the changes in the Company’s asset retirement obligations for the years ended December 31, 2017 and 2016 (in thousands). Year Ended December 31, 2017 2016 Beginning asset retirement obligations $ 20,640 $ 15,420 Liabilities incurred during period 2,920 1,791 Liabilities settled during period (430 ) (375 ) Revisions in estimated cash flows 1,836 2,622 Accretion expense 1,290 1,182 Ending asset retirement obligations 26,256 20,640 Less: current asset retirement obligations (1) (1,176 ) (915 ) Long-term asset retirement obligations $ 25,080 $ 19,725 __________________ (1) Included in accrued liabilities in the Company’s consolidated balance sheets at December 31, 2017 and 2016 . |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | |
Summary of net deferred tax position | The Company’s net deferred tax position as of December 31, 2017 and 2016 is as follows (in thousands). December 31, 2017 2016 Deferred tax assets Unrealized loss on derivatives $ 3,200 $ 8,734 Net operating loss carryforwards 118,134 137,757 Alternative minimum tax carryforward — 8,633 Percentage depletion carryover 1,582 2,595 Property and equipment — 44,391 Basis increase related to the San Mateo transaction 18,382 — Total deferred tax assets 141,298 202,110 Valuation allowance on deferred tax assets (89,482 ) (190,255 ) Total deferred tax assets, net of valuation allowance 51,816 11,855 Deferred tax liabilities Property and equipment (40,568 ) — Other (11,248 ) (11,855 ) Total deferred tax liabilities (51,816 ) (11,855 ) Net deferred tax liabilities $ — $ — |
Income tax expense reconciled to the tax computed at the statutory federal rate | The current income tax (benefit) provision for the years ended December 31, 2017, 2016 and 2015 was comprised of the following (in thousands). Year Ended December 31, 2017 2016 2015 Current income tax provision State income tax $ 21 $ 108 $ 371 Federal alternative minimum tax (8,178 ) (1,144 ) 2,588 Net current income tax (benefit) provision $ (8,157 ) $ (1,036 ) $ 2,959 Reconciliations of the tax expense (benefit) computed at the statutory federal rate to the Company’s total income tax benefit for the years ended December 31, 2017, 2016 and 2015 is as follows (in thousands). Year Ended December 31, 2017 2016 2015 Federal tax expense (benefit) at statutory rate (1) $ 45,447 $ (34,333 ) $ (289,412 ) State income tax 368 539 (13,215 ) Permanent differences (2) (4,740 ) (499 ) 698 Federal alternative minimum tax — 1,144 (2,588 ) AMT credit refundable (net of sequestration) 8,178 — — Tax Cuts and Jobs Act rate change 51,525 — — Change in federal valuation allowance (101,917 ) 33,688 145,777 Change in state valuation allowance 1,139 (539 ) 8,413 Net deferred income tax benefit — — (150,327 ) Net current income tax (benefit) provision (8,157 ) (1,036 ) 2,959 Total income tax benefit $ (8,157 ) $ (1,036 ) $ (147,368 ) __________________ (1) The statutory federal tax rate was 35% for the years ended December 31, 2017, 2016 and 2015 . (2) Amount is primarily attributable to stock-based compensation. |
Stock-Based Compensation (Table
Stock-Based Compensation (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Summarized information about stock options outstanding | Summarized information about stock options outstanding at December 31, 2017 under the 2003 Plan and the 2012 Incentive Plan is as follows. Number of options (in thousands) Weighted average exercise price Options outstanding at December 31, 2016 2,887 $ 15.59 Options granted 1,034 $ 27.09 Options exercised (833 ) $ 9.20 Options forfeited (24 ) $ 23.81 Options expired — $ — Options outstanding at December 31, 2017 3,064 $ 21.14 |
Summarized information about outstanding and exercisable stock option | Options outstanding at December 31, 2017 Options exercisable at December 31, 2017 Range of exercise prices Shares outstanding (in thousands) Weighted average remaining contractual life Weighted average exercise price Shares exercisable (in thousands) Weighted average exercise price $8.18 - $9.55 294 0.69 $ 8.46 294 $ 8.46 $13.22 - $17.80 625 3.10 $ 15.01 11 $ 16.45 $19.71 - $22.70 839 2.05 $ 21.87 73 $ 21.50 $23.40 - $27.33 1,306 4.33 $ 26.47 141 $ 24.21 |
Summary of the non-vested restricted stock and restricted stock units | A summary of the non-vested restricted stock and restricted stock units as of December 31, 2017 is presented below (in thousands, except fair value). Restricted Stock Restricted Stock Units Non-vested restricted stock and restricted stock units Shares Weighted average fair value Shares Weighted average fair value Non-vested at December 31, 2016 1,039 $ 18.23 82 $ 21.32 Granted 531 $ 26.25 113 $ 23.77 Vested (429 ) $ 16.54 (124 ) $ 22.38 Forfeited (37 ) $ 22.94 (6 ) 23.45 Non-vested at December 31, 2017 1,104 $ 22.59 65 $ 23.36 |
2003 Stock and Incentive Plan [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Weighted average assumptions used to estimate fair value of stock options granted under the Stock and Incentive Plan | The fair value of the 75,000 , 77,500 and 87,500 stock option awards outstanding under the 2003 Plan at December 31, 2017, 2016 and 2015 , respectively, was estimated using the following weighted average assumptions. 2017 2016 2015 Stock option pricing model Black Scholes Merton Black Scholes Merton Black Scholes Merton Expected option life 2.14 years 3.14 years 0.39 years Risk-free interest rate 1.98% 1.70% 0.64% Volatility 43.60% 47.07% 91.98% Dividend yield —% —% —% Estimated forfeiture rate —% —% —% |
2012 Incentive Plan [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Weighted average assumptions used to estimate fair value of stock options granted under the Stock and Incentive Plan | The weighted average grant date fair value for stock option awards granted under the 2012 Incentive Plan was estimated using the following weighted average assumptions during the years ended December 31, 2017, 2016 and 2015 . 2017 2016 2015 Stock option pricing model Black Scholes Merton Black Scholes Merton Black Scholes Merton Expected option life 4.00 years 3.96 years 4.00 years Risk-free interest rate 1.77% 1.08% 1.15% Volatility 47.00% 45.68% 56.89% Dividend yield —% —% —% Estimated forfeiture rate 3.66% 1.16% 3.21% Weighted average fair value of stock option awards granted during the year $10.49 $5.65 $9.90 |
Derivative Financial Instrume31
Derivative Financial Instruments (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Summary of contracts for oil and natural gas | The following is a summary of the Company’s open costless collar contracts for oil and natural gas at December 31, 2017 . Notional Quantity (Bbl or MMBtu) Weighted Average Price Floor ($/Bbl or Weighted Average Price Ceiling ($/Bbl or Fair Value of Asset (Liability) Commodity Calculation Period Oil - WTI (1) 01/01/2018 - 12/31/2018 2,880,000 $ 44.27 $ 60.29 (8,414 ) Oil - LLS (2) 01/01/2018 - 12/31/2018 720,000 $ 45.00 $ 63.05 (2,451 ) Natural Gas 01/01/2018 - 12/31/2018 16,800,000 $ 2.58 $ 3.67 1,190 Total open costless collar contracts $ (9,675 ) _____________________ (1) NYMEX West Texas Intermediate crude oil. (2) Argus Louisiana Light Sweet crude oil. The following is a summary of the Company’s open basis swaps contracts for oil at December 31, 2017 . Commodity Calculation Period Notional Quantity (Bbl or Gal) Fixed Price ($/Bbl or $/Gal) Fair Value of Asset (Liability) Oil Basis Swaps 01/01/2018 - 12/31/2018 5,220,000 $ (1.02 ) $ (5,564 ) Total open swap contracts $ (5,564 ) Total open derivative financial instruments $ (15,239 ) |
Summary of offsetting assets | The following table presents the gross asset and liability fair values of the Company’s commodity price derivative financial instruments and the location of these balances in the consolidated balance sheets as of December 31, 2017 and December 31, 2016 (in thousands). Derivative Instruments Gross amounts recognized Gross amounts netted in the consolidated balance sheets Net amounts presented in the consolidated balance sheets December 31, 2017 Current assets $ 131,092 $ (129,902 ) $ 1,190 Current liabilities (146,331 ) 129,902 (16,429 ) Total $ (15,239 ) $ — $ (15,239 ) December 31, 2016 Current liabilities $ (24,203 ) $ — $ (24,203 ) Other liabilities (751 ) — (751 ) Total $ (24,954 ) $ — $ (24,954 ) |
Summary of offsetting liabilities | The following table presents the gross asset and liability fair values of the Company’s commodity price derivative financial instruments and the location of these balances in the consolidated balance sheets as of December 31, 2017 and December 31, 2016 (in thousands). Derivative Instruments Gross amounts recognized Gross amounts netted in the consolidated balance sheets Net amounts presented in the consolidated balance sheets December 31, 2017 Current assets $ 131,092 $ (129,902 ) $ 1,190 Current liabilities (146,331 ) 129,902 (16,429 ) Total $ (15,239 ) $ — $ (15,239 ) December 31, 2016 Current liabilities $ (24,203 ) $ — $ (24,203 ) Other liabilities (751 ) — (751 ) Total $ (24,954 ) $ — $ (24,954 ) |
Summary of location and aggregate fair value of all derivative financial instruments recorded in the consolidated statements of operations | The following table summarizes the location and aggregate fair value of all derivative financial instruments recorded in the consolidated statements of operations for the periods presented (in thousands). These derivative financial instruments are not designated as hedging instruments. Year Ended December 31, Type of Instrument Location in Statement of Operations 2017 2016 2015 Derivative Instrument Oil Revenues: Realized (loss) gain on derivatives $ (3,657 ) $ 5,851 $ 62,259 Natural Gas Revenues: Realized (loss) gain on derivatives (608 ) 3,435 12,653 Natural Gas Liquids (NGL) Revenues: Realized (loss) gain on derivatives (56 ) — 2,182 Realized (loss) gain on derivatives (4,321 ) 9,286 77,094 Oil Revenues: Unrealized gain (loss) on derivatives 2,638 (18,969 ) (31,897 ) Natural Gas Revenues: Unrealized gain (loss) on derivatives 7,077 (22,269 ) (5,440 ) Natural Gas Liquids (NGL) Revenues: Unrealized loss on derivatives — — (1,928 ) Unrealized gain (loss) on derivatives 9,715 (41,238 ) (39,265 ) Total $ 5,394 $ (31,952 ) $ 37,829 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Fair Value Disclosures [Abstract] | |
Summary of the valuation of the Company's financial assets and liabilities that were accounted for at fair value on a recurring basis | The following tables summarize the valuation of the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis in accordance with the classifications provided above as of December 31, 2017 and 2016 (in thousands). Fair Value Measurements at Description Level 1 Level 2 Level 3 Total Assets (Liabilities) Natural gas derivatives $ — $ 1,190 $ — $ 1,190 Oil derivatives and basis swaps — (16,429 ) — (16,429 ) Total $ — $ (15,239 ) $ — $ (15,239 ) Fair Value Measurements at Description Level 1 Level 2 Level 3 Total Assets (Liabilities) Oil and natural gas derivatives $ — $ (24,954 ) $ — $ (24,954 ) Total $ — $ (24,954 ) $ — $ (24,954 ) |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Commitments and Contingencies Disclosure [Abstract] | |
Schedule of future minimum lease payments required under the office lease agreement | The following is a schedule of future minimum lease payments required under all office lease agreements as of December 31, 2017 (in thousands). Year Ending December 31, Amount 2018 $ 2,495 2019 2,528 2020 2,602 2021 2,660 2022 2,774 Thereafter 9,561 Total $ 22,620 |
Supplemental Disclosures (Table
Supplemental Disclosures (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Supplemental Disclosures [Abstract] | |
Summary of current accrued liabilities | The following table summarizes the Company’s current accrued liabilities at December 31, 2017 and 2016 (in thousands). December 31, 2017 2016 Accrued evaluated and unproved and unevaluated property costs $ 105,347 $ 54,273 Accrued support equipment and facilities costs 14,823 15,139 Accrued lease operating expenses 12,611 16,009 Accrued interest on debt 8,345 6,541 Accrued asset retirement obligations 1,176 915 Accrued partners’ share of joint interest charges 27,628 5,572 Other 4,418 3,011 Total accrued liabilities $ 174,348 $ 101,460 |
Supplemental disclosures of cash flow information | The following table provides supplemental disclosures of cash flow information for the years ended December 31, 2017, 2016 and 2015 (in thousands). Year Ended December 31, 2017 2016 2015 Cash paid for income taxes $ — $ 2,895 $ 506 Cash paid for interest expense, net of amounts capitalized $ 32,760 $ 27,464 $ 16,154 Increase in asset retirement obligations related to mineral properties $ 4,385 $ 3,817 $ 2,510 (Decrease) increase in asset retirement obligations related to support equipment and facilities $ (60 ) $ 222 $ 383 Increase (decrease) in liabilities for oil and natural gas properties capital expenditures $ 48,929 $ 1,775 $ (30,683 ) (Decrease) increase in liabilities for support equipment and facilities $ (955 ) $ (588 ) $ 12,076 Issuance of restricted stock units for director and advisor services $ — $ 992 $ 584 Stock-based compensation expense recognized as liability $ 362 $ 569 $ 79 (Decrease) increase in liabilities for accrued cost to issue equity $ (343 ) $ 343 $ — Transfer of inventory (to) from oil and natural gas properties $ (374 ) $ 395 $ 615 Transfer of inventory to midstream and other property and equipment $ (317 ) $ — $ — |
Segment Reporting (Tables)
Segment Reporting (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Segment Reporting [Abstract] | |
Schedule of Segment Reporting Information, by Segment | The following tables present selected financial information for the periods presented regarding the Company’s operating segments on a stand-alone basis, corporate expenses that are not allocated to a segment and the consolidation and elimination entries necessary to arrive at the financial information for the Company on a consolidated basis (in thousands). On a consolidated basis, midstream services revenues consist primarily of those revenues from midstream operations related to third parties, including working interest owners in the Company’s operated wells. All midstream services revenues associated with Company-owned production are eliminated in consolidation. In evaluating the operating results of the exploration and production and midstream segments, the Company does not allocate certain expenses to the individual segments, including general and administrative expenses. Such expenses are reflected in the column labeled “Corporate.” Exploration and Production Consolidations and Eliminations Consolidated Company Midstream Corporate Year Ended December 31, 2017 Oil and natural gas revenues $ 525,862 $ 2,822 $ — $ — $ 528,684 Midstream services revenues — 47,037 — (36,839 ) 10,198 Realized loss on derivatives (4,321 ) — — — (4,321 ) Unrealized gain on derivatives 9,715 — — — 9,715 Expenses (1) 333,923 23,420 62,931 (36,839 ) 383,435 Operating income (loss) (2) $ 197,333 $ 26,439 $ (62,931 ) $ — $ 160,841 Total assets $ 1,768,393 $ 257,871 $ 119,426 $ — $ 2,145,690 Capital expenditures (3) $ 753,157 $ 114,113 $ 5,688 $ — $ 872,958 _____________________ (1) Includes depletion, depreciation and amortization expenses of $170.5 million and $5.2 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $1.7 million . (2) Includes $12.1 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment. (3) Includes $54.9 million in capital expenditures attributable to non-controlling interest in subsidiaries related to the midstream segment. Exploration and Production Consolidations and Eliminations Consolidated Company Midstream Corporate Year Ended December 31, 2016 Oil and natural gas revenues $ 289,512 $ 1,644 $ — $ — $ 291,156 Midstream services revenues — 18,982 — (13,764 ) 5,218 Realized gain on derivatives 9,286 — — — 9,286 Unrealized loss on derivatives (41,238 ) — — — (41,238 ) Expenses (1) 391,098 8,254 56,001 (13,764 ) 441,589 Operating (loss) income (2) $ (133,538 ) $ 12,372 $ (56,001 ) $ — $ (177,167 ) Total assets $ 1,098,525 $ 140,459 $ 225,681 $ — $ 1,464,665 Capital expenditures $ 379,881 $ 67,566 $ 6,913 $ — $ 454,360 _____________________ (1) Includes depletion, depreciation and amortization expenses of $118.4 million and $2.7 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $0.9 million and full-cost ceiling impairment expense of $158.6 million for the exploration and production segment. (2) Includes $0.4 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment. Exploration and Production Consolidations and Eliminations Consolidated Company Midstream Corporate Year Ended December 31, 2015 Oil and natural gas revenues $ 277,844 $ 496 $ — $ — $ 278,340 Midstream services revenues — 11,485 — (9,621 ) 1,864 Realized gain on derivatives 77,094 — — — 77,094 Unrealized loss on derivatives (39,265 ) — — — (39,265 ) Expenses (1) 1,078,534 5,178 50,604 (9,621 ) 1,124,695 Operating (loss) income (2) $ (762,861 ) $ 6,803 $ (50,604 ) $ — $ (806,662 ) Total assets $ 1,000,075 $ 75,980 $ 64,806 $ — $ 1,140,861 Capital expenditures (3) $ 622,642 $ 75,009 $ 786 $ — $ 698,437 _____________________ (1) Includes depletion, depreciation and amortization expenses of $176.7 million and $1.6 million for the exploration and production and midstream segments, respectively. Also includes corporate depletion, depreciation and amortization expenses of $0.5 million and full-cost ceiling impairment expense of $801.2 million for the exploration and production segment. (2) Includes $0.3 million in net income attributable to non-controlling interest in subsidiaries related to the midstream segment. (3) In October 2015, the Company sold the Loving County Processing System to EnLink and the cost basis of $31.0 million for those assets was removed from the total midstream assets. |
Summary of Significant Accoun36
Summary of Significant Accounting Policies (Details Textual) | 12 Months Ended | ||||||||||||||||||
Dec. 31, 2017USD ($) | Dec. 31, 2017USD ($)shares | Dec. 31, 2017USD ($)Purchasers | Dec. 31, 2017USD ($)$ / bbl | Dec. 31, 2017USD ($)$ / MMBTU | Dec. 31, 2017USD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2016shares | Dec. 31, 2016Purchasers | Dec. 31, 2016$ / bbl | Dec. 31, 2016$ / MMBTU | Dec. 31, 2016 | Dec. 31, 2016USD ($) | Dec. 31, 2015shares | Dec. 31, 2015Purchasers | Dec. 31, 2015$ / bbl | Dec. 31, 2015$ / MMBTU | Dec. 31, 2015 | Dec. 31, 2015USD ($) | |
Summary of Significant Accounting Policies [Line Items] | |||||||||||||||||||
Billing date | 30 days | ||||||||||||||||||
Outstanding days of account receivable | 60 days | ||||||||||||||||||
Allowance for doubtful accounts | $ 0 | $ 0 | $ 0 | $ 0 | $ 0 | $ 0 | $ 0 | ||||||||||||
Capitalized general and administrative costs | 23,100,000 | $ 15,700,000 | $ 6,900,000 | ||||||||||||||||
Capitalized interest expense | 7,300,000 | 3,700,000 | 3,900,000 | ||||||||||||||||
Present value discounted percent of future net revenues of proved oil and natural gas reserves | 10.00% | ||||||||||||||||||
Average oil and natural gas prices | 47.79 | 2.98 | 39.25 | 2.48 | 46.79 | 2.59 | |||||||||||||
Impairment charge of net capitalized costs | 0 | 158,633,000 | 801,166,000 | ||||||||||||||||
Number of purchasers | Purchasers | 4 | 3 | 3 | ||||||||||||||||
Stock-based compensation (non-cash) expense | 16,654,000 | 12,362,000 | 9,450,000 | ||||||||||||||||
Common stock and restricted stock unit expense | 3,000,000 | 1,000,000 | 900,000 | ||||||||||||||||
Accelerated compensation cost | 1,500,000 | ||||||||||||||||||
Percentage being realized up on ultimate settlement | 50.00% | ||||||||||||||||||
Machinery and Equipment [Member] | |||||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | |||||||||||||||||||
Useful life using the straight-line | 30 years | ||||||||||||||||||
Maximum [Member] | |||||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | |||||||||||||||||||
Accounts receivable due period | 60 days | ||||||||||||||||||
Useful life | 30 years | ||||||||||||||||||
Minimum [Member] | |||||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | |||||||||||||||||||
Accounts receivable due period | 30 days | ||||||||||||||||||
Useful life | 5 years | ||||||||||||||||||
Accounts Receivable [Member] | |||||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | |||||||||||||||||||
Concentration risk, percentage | 43.00% | 38.00% | 39.00% | ||||||||||||||||
Sales Revenue, Goods, Net [Member] | |||||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | |||||||||||||||||||
Concentration risk, percentage | 60.00% | 48.00% | 59.00% | ||||||||||||||||
Stock options [Member] | |||||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | |||||||||||||||||||
Stock-based compensation (non-cash) expense | $ 7,100,000 | $ 5,900,000 | $ 4,700,000 | ||||||||||||||||
Restricted Stock Units (RSUs) [Member] | |||||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | |||||||||||||||||||
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount | shares | 90,552 | 73,923 | |||||||||||||||||
Restricted stock [Member] | |||||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | |||||||||||||||||||
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount | shares | 1,039,292 | 854,238 | |||||||||||||||||
Stock options [Member] | |||||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | |||||||||||||||||||
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount | shares | 1,000,000 | 2,886,821 | 2,362,861 | ||||||||||||||||
Plains Marketing [Member] | Customer Concentration Risk [Member] | Sales Revenue, Goods, Net [Member] | |||||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | |||||||||||||||||||
Concentration risk, percentage | 14.00% | 18.00% | |||||||||||||||||
Shell Trading (US) Company [Member] | Customer Concentration Risk [Member] | Sales Revenue, Goods, Net [Member] | |||||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | |||||||||||||||||||
Concentration risk, percentage | 12.00% | 17.00% | 33.00% | ||||||||||||||||
Western Refining Oil [Member] | Customer Concentration Risk [Member] | Sales Revenue, Goods, Net [Member] | |||||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | |||||||||||||||||||
Concentration risk, percentage | 11.00% | ||||||||||||||||||
Occidental Energy Marketing [Member] | Customer Concentration Risk [Member] | Sales Revenue, Goods, Net [Member] | |||||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | |||||||||||||||||||
Concentration risk, percentage | 23.00% | 13.00% | |||||||||||||||||
Enterprise Crude Oil LLC [Member] | Customer Concentration Risk [Member] | Sales Revenue, Goods, Net [Member] | |||||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | |||||||||||||||||||
Concentration risk, percentage | 14.00% | ||||||||||||||||||
Sequent Energy Management [Member] | Customer Concentration Risk [Member] | Sales Revenue, Goods, Net [Member] | |||||||||||||||||||
Summary of Significant Accounting Policies [Line Items] | |||||||||||||||||||
Concentration risk, percentage | 12.00% |
Summary of Significant Accoun37
Summary of Significant Accounting Policies (Details) - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | |||
Current period net income | $ 125,867 | $ (97,421) | $ (679,785) |
Weighted average common shares outstanding — denominator | |||
Weighted average common shares outstanding for basic earnings (loss) per share (in shares) | 102,029,000 | 91,273,000 | 81,537,000 |
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements | 514,000 | 0 | 0 |
Diluted weighted average common shares outstanding (in shares) | 102,543,000 | 91,273,000 | 81,537,000 |
Earnings (loss) per common share | |||
Basic (usd per share) | $ 1.23 | $ (1.07) | $ (8.34) |
Diluted (usd per share) | $ 1.23 | $ (1.07) | $ (8.34) |
Stock options [Member] | |||
Earnings (loss) per common share | |||
Total (usd per share) | 1,000,000 | 2,886,821 | 2,362,861 |
Restricted Stock Units (RSUs) [Member] | |||
Earnings (loss) per common share | |||
Total (usd per share) | 90,552 | 73,923 | |
Restricted stock [Member] | |||
Earnings (loss) per common share | |||
Total (usd per share) | 1,039,292 | 854,238 |
Property and Equipment (Details
Property and Equipment (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Oil and natural gas properties | ||
Evaluated (subject to amortization) | $ 3,004,770 | $ 2,408,305 |
Total unproved and unevaluated | 637,396 | 479,736 |
Total oil and natural gas properties | 3,642,166 | 2,888,041 |
Accumulated depletion | (2,021,169) | (1,850,882) |
Net oil and natural gas properties | 1,620,997 | 1,037,159 |
Other property and equipment | ||
Midstream and other property and equipment | 281,096 | 160,795 |
Accumulated depreciation | (20,637) | (13,429) |
Net other property and equipment | 260,459 | 147,366 |
Net property and equipment | 1,881,456 | 1,184,525 |
Midstream equipment and facilities | ||
Other property and equipment | ||
Midstream and other property and equipment | 258,725 | 145,662 |
Furniture, fixtures and other equipment | ||
Other property and equipment | ||
Midstream and other property and equipment | 6,109 | 5,487 |
Software | ||
Other property and equipment | ||
Midstream and other property and equipment | 7,942 | 3,206 |
Land | ||
Other property and equipment | ||
Midstream and other property and equipment | 2,892 | 1,437 |
Leasehold improvements | ||
Other property and equipment | ||
Midstream and other property and equipment | $ 5,428 | $ 5,003 |
Property and Equipment (Detai39
Property and Equipment (Details 1) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2011 |
Costs incurred for | ||||
Total unproved and unevaluated | $ 637,396 | $ 479,736 | ||
2,017 | ||||
Costs incurred for | ||||
Property acquisition | 213,076 | |||
Exploration wells | 16,688 | |||
Development wells | 11,396 | |||
Total unproved and unevaluated | 241,160 | |||
2,016 | ||||
Costs incurred for | ||||
Property acquisition | 125,689 | |||
Exploration wells | 988 | |||
Development wells | 272 | |||
Total unproved and unevaluated | $ 126,949 | |||
2,015 | ||||
Costs incurred for | ||||
Property acquisition | $ 222,912 | |||
Exploration wells | 547 | |||
Development wells | 19 | |||
Total unproved and unevaluated | $ 223,478 | |||
2014 and prior | ||||
Costs incurred for | ||||
Property acquisition | $ 45,809 | |||
Exploration wells | 0 | |||
Development wells | 0 | |||
Total unproved and unevaluated | $ 45,809 | |||
Total | ||||
Costs incurred for | ||||
Property acquisition | 607,486 | |||
Exploration wells | 18,223 | |||
Development wells | 11,687 | |||
Total unproved and unevaluated | $ 637,396 |
Property and Equipment (Detai40
Property and Equipment (Details Textual) $ in Millions | 12 Months Ended |
Dec. 31, 2017USD ($) | |
Property, Plant and Equipment [Abstract] | |
Amortization costs | $ 29.9 |
Anticipated amount for wells | $ 29.9 |
Asset Retirement Obligations (D
Asset Retirement Obligations (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | |
Changes in the Company's asset retirement obligations | ||||
Beginning asset retirement obligations | $ 20,640 | $ 15,420 | ||
Liabilities incurred during period | 2,920 | 1,791 | ||
Liabilities settled during period | (430) | (375) | ||
Revisions in estimated cash flows | 1,836 | 2,622 | ||
Accretion expense | 1,290 | 1,182 | ||
Ending asset retirement obligations | $ 20,640 | $ 15,420 | $ 26,256 | $ 20,640 |
Less: current asset retirement obligations | (1,176) | (915) | ||
Long-term asset retirement obligations | $ 25,080 | $ 19,725 |
Business Combinations and Div42
Business Combinations and Divestitures (Details) $ in Millions | Feb. 17, 2017USD ($)well | Oct. 01, 2015USD ($) | Feb. 27, 2015USD ($)ashares | Jan. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Sep. 30, 2017 | Oct. 31, 2015USD ($) |
Business Acquisition [Line Items] | |||||||
Subsidiary ownership percentage | 100.00% | ||||||
Carrying value of net assets sold | $ 31 | ||||||
Sale leaseback transaction, transaction costs | $ 0.4 | ||||||
Sale leaseback transaction, current period gain recognized | 107.3 | ||||||
Harvey E Yates Company [Member] | |||||||
Business Acquisition [Line Items] | |||||||
Number of gross acres in acreage acquired | a | 58,600 | ||||||
Number of net acres in acreage acquired | a | 18,200 | ||||||
Business combination, consideration transferred, liabilities incurred | $ 33.6 | ||||||
Shares issued upon conversion | shares | 10 | ||||||
Harvey E Yates Company [Member] | Common Stock [Member] | |||||||
Business Acquisition [Line Items] | |||||||
Shares issued for acquisition | shares | 3,300,000 | ||||||
Harvey E Yates Company [Member] | Convertible Preferred Stock [Member] | |||||||
Business Acquisition [Line Items] | |||||||
Shares issued for acquisition | shares | 150,000 | ||||||
EnLink [Member] | |||||||
Business Acquisition [Line Items] | |||||||
Proceeds from sale of oil and gas property and equipment | $ 143.4 | ||||||
Proceeds from sale of oil and gas property and equipment net of purchase price adjustments | 139.8 | ||||||
Purchase price adjustments for production, revenues and operating and capital expenditures | $ 3.6 | ||||||
Gas gathering and processing agreement, term | 15 years | ||||||
Sale leaseback transaction, deferred gain | $ 108.4 | ||||||
Corporate Joint Venture [Member] | San Mateo Midstream [Member] | |||||||
Business Acquisition [Line Items] | |||||||
Subsidiary ownership percentage | 51.00% | 51.00% | |||||
Deferred performance incentives | $ 58.8 | ||||||
Deferred performance incentives, term | 4 years | ||||||
Contributions to joint venture, operating capital | $ 5.1 | ||||||
Corporate Joint Venture [Member] | San Mateo Midstream [Member] | Subsequent Event [Member] | |||||||
Business Acquisition [Line Items] | |||||||
Deferred performance incentives | $ 14.7 | ||||||
Five Point [Member] | Corporate Joint Venture [Member] | San Mateo Midstream [Member] | |||||||
Business Acquisition [Line Items] | |||||||
Subsidiary ownership percentage | 49.00% | ||||||
Payments to acquire interest in joint venture | $ 176.4 | ||||||
Proceeds from divestiture of interest in joint venture | $ 171.5 | ||||||
Rustler Breaks and Wolf Asset Area [Member] | Corporate Joint Venture [Member] | San Mateo Midstream [Member] | |||||||
Business Acquisition [Line Items] | |||||||
Contractual obligation, term | 15 years | ||||||
Rustler Breaks Asset Area [Member] | Corporate Joint Venture [Member] | San Mateo Midstream [Member] | |||||||
Business Acquisition [Line Items] | |||||||
Number of wells contributed to joint venture | well | 1 | ||||||
Contractual obligation, term | 15 years | ||||||
Wolf Asset Area [Member] | Corporate Joint Venture [Member] | San Mateo Midstream [Member] | |||||||
Business Acquisition [Line Items] | |||||||
Number of wells contributed to joint venture | well | 3 |
Revolving Credit Agreement (Det
Revolving Credit Agreement (Details Textual) - USD ($) | Dec. 09, 2016 | Apr. 14, 2015 | Sep. 30, 2012 | Dec. 31, 2017 | Feb. 21, 2018 | Sep. 30, 2017 | Feb. 17, 2017 | Dec. 31, 2016 | Oct. 31, 2016 | Oct. 21, 2015 | Sep. 28, 2012 |
Revolving Credit Agreement (Textual) [Abstract] | |||||||||||
Deferred loan costs | $ 1,000,000 | ||||||||||
Repay deficit in agreement Period | 6 months | ||||||||||
Borrowings under Credit Agreement | $ 0 | ||||||||||
Outstanding letters of credit | 2,100,000 | ||||||||||
Borrowings interest rate | 50.00% | ||||||||||
Senior unsecured notes payable | $ 574,073,000 | $ 573,924,000 | |||||||||
Proceeds from Issuance or Sale of Equity | $ 181,500,000 | ||||||||||
Subsidiary ownership percentage | 100.00% | ||||||||||
Third amended credit agreement [Member] | |||||||||||
Revolving Credit Agreement (Textual) [Abstract] | |||||||||||
Company amended and restated its senior secured revolving credit agreement | September 28, 2012 | ||||||||||
Senior secured revolving credit maximum facility | $ 525,000,000 | $ 400,000,000 | |||||||||
Maximum borrowing capacity, amended | $ 500,000,000 | ||||||||||
Percentage of reserves required to maintain | 100.00% | ||||||||||
Debt to EBITDA ratio covenant | 4.25 | ||||||||||
Subsequent Event [Member] | |||||||||||
Revolving Credit Agreement (Textual) [Abstract] | |||||||||||
Borrowings under Credit Agreement | $ 0 | ||||||||||
Outstanding letters of credit | $ 2,100,000 | ||||||||||
LIBOR rate [Member] | Third amended credit agreement [Member] | |||||||||||
Revolving Credit Agreement (Textual) [Abstract] | |||||||||||
Borrowings interest rate | 1.00% | ||||||||||
Maximum [Member] | Third amended credit agreement [Member] | |||||||||||
Revolving Credit Agreement (Textual) [Abstract] | |||||||||||
Commitment fee percentage | 0.50% | ||||||||||
Minimum [Member] | Third amended credit agreement [Member] | |||||||||||
Revolving Credit Agreement (Textual) [Abstract] | |||||||||||
Commitment fee percentage | 0.375% | ||||||||||
Minimum [Member] | Base rate loan [Member] | |||||||||||
Revolving Credit Agreement (Textual) [Abstract] | |||||||||||
Additional interest rate | 0.50% | ||||||||||
Eurodollar [Member] | Maximum [Member] | Third amended credit agreement [Member] | |||||||||||
Revolving Credit Agreement (Textual) [Abstract] | |||||||||||
Additional interest rate | 2.50% | ||||||||||
Eurodollar [Member] | Minimum [Member] | Third amended credit agreement [Member] | |||||||||||
Revolving Credit Agreement (Textual) [Abstract] | |||||||||||
Additional interest rate | 1.50% | ||||||||||
Unsecured Debt [Member] | Senior Notes Due 2023 [Member] | |||||||||||
Revolving Credit Agreement (Textual) [Abstract] | |||||||||||
Senior unsecured notes payable | $ 175,000,000 | $ 400,000,000 | |||||||||
Stated interest rate | 6.875% | 6.875% | |||||||||
Effective interest rate | 5.50% | ||||||||||
Percentage of principal amount redeemed | 35.00% | ||||||||||
Percentage of aggregate principal amount of notes outstanding after redemption | 65.00% | ||||||||||
Percentage of principal amount outstanding | 25.00% | ||||||||||
Period of default when due of interest | 30 days | ||||||||||
Period after notice to comply with reporting obligations | 180 days | ||||||||||
Period after notice to comply with agreements in indenture | 60 days | ||||||||||
Aggregate principal amount related to payment defaults or accelerations | $ 25,000,000 | ||||||||||
Amount of failure to pay final judgments | $ 25,000,000 | ||||||||||
Period for failure to pay final judgments | 60 days | ||||||||||
Federal Funds Effective Rate [Member] | Third amended credit agreement [Member] | |||||||||||
Revolving Credit Agreement (Textual) [Abstract] | |||||||||||
Borrowings interest rate | 0.50% | ||||||||||
Base rate loan [Member] | Maximum [Member] | Third amended credit agreement [Member] | |||||||||||
Revolving Credit Agreement (Textual) [Abstract] | |||||||||||
Additional interest rate | 1.50% | ||||||||||
Debt Redemption, 2018 [Member] | Unsecured Debt [Member] | Senior Notes Due 2023 [Member] | |||||||||||
Revolving Credit Agreement (Textual) [Abstract] | |||||||||||
Redemption Price | 105.156% | ||||||||||
Percentage of principal amount redeemed | 105.50% | 106.875% | |||||||||
Debt Redemption, 2019 [Member] | Unsecured Debt [Member] | Senior Notes Due 2023 [Member] | |||||||||||
Revolving Credit Agreement (Textual) [Abstract] | |||||||||||
Redemption Price | 103.438% | ||||||||||
Debt Redemption, 2020 [Member] | Unsecured Debt [Member] | Senior Notes Due 2023 [Member] | |||||||||||
Revolving Credit Agreement (Textual) [Abstract] | |||||||||||
Redemption Price | 101.719% | ||||||||||
Debt Redemption, 2021 and thereafter [Member] | Unsecured Debt [Member] | Senior Notes Due 2023 [Member] | |||||||||||
Revolving Credit Agreement (Textual) [Abstract] | |||||||||||
Redemption Price | 100.00% | ||||||||||
Revolving Credit Facility [Member] | |||||||||||
Revolving Credit Agreement (Textual) [Abstract] | |||||||||||
Senior secured revolving credit maximum facility | $ 400,000,000 | ||||||||||
Corporate Joint Venture [Member] | San Mateo Midstream [Member] | |||||||||||
Revolving Credit Agreement (Textual) [Abstract] | |||||||||||
Subsidiary ownership percentage | 51.00% | 51.00% |
Income Taxes (Details)
Income Taxes (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Deferred tax assets | ||
Unrealized loss on derivatives | $ 3,200 | $ 8,734 |
Net operating loss carryforwards | 118,134 | 137,757 |
Alternative minimum tax carryforward | 0 | 8,633 |
Percentage depletion carryover | 1,582 | 2,595 |
Property and equipment | 0 | 44,391 |
Basis increase related to the San Mateo transaction | 18,382 | 0 |
Total deferred tax assets | 141,298 | 202,110 |
Valuation allowance on deferred tax assets | (89,482) | (190,255) |
Total deferred tax assets, net of valuation allowance | 51,816 | 11,855 |
Deferred tax liabilities | ||
Property and equipment | 40,568 | 0 |
Other | (11,248) | (11,855) |
Total deferred tax liabilities | (51,816) | (11,855) |
Net deferred tax liabilities | $ 0 | $ 0 |
Income Taxes (Details Textual)
Income Taxes (Details Textual) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Operating Loss Carryforwards [Line Items] | |||
Full-cost ceiling impairment | $ 0 | $ 158,633 | $ 801,166 |
Increase in valuation allowance | 101,917 | (33,688) | (145,777) |
Provisional income tax | 51,500 | ||
Net current income tax (benefit) provision | 8,157 | $ 1,036 | $ (2,959) |
Internal Revenue Service (IRS) [Member] | |||
Operating Loss Carryforwards [Line Items] | |||
Operating loss carryforwards | 498,400 | ||
State and Local Jurisdiction [Member] | |||
Operating Loss Carryforwards [Line Items] | |||
Operating loss carryforwards | $ 17,000 |
Income Taxes (Details 1)
Income Taxes (Details 1) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Current income tax provision | |||
State income tax | $ 21 | $ 108 | $ 371 |
Federal alternative minimum tax | (8,178) | (1,144) | 2,588 |
Net current income tax (benefit) provision | (8,157) | (1,036) | 2,959 |
Deferred income tax provision (benefit) | |||
Federal tax (benefit) expense at statutory rate | 45,447 | (34,333) | (289,412) |
State income tax | 368 | 539 | (13,215) |
Permanent differences | (4,740) | (499) | 698 |
AMT credit refundable (net of sequestration) | 0 | 1,144 | (2,588) |
AMT credit refundable (net of sequestration) | 8,178 | 0 | 0 |
Tax Cuts and Jobs Act rate change | 51,525 | 0 | 0 |
Change in federal valuation allowance | (101,917) | 33,688 | 145,777 |
Change in state valuation allowance | 1,139 | (539) | 8,413 |
Net deferred income tax benefit | 0 | 0 | (150,327) |
Total income tax benefit | $ (8,157) | $ (1,036) | $ (147,368) |
Federal statutory rate | 35.00% | 35.00% | 35.00% |
Stock-Based Compensation (Detai
Stock-Based Compensation (Details) - $ / shares | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Weighted average assumptions used to estimate fair value of stock options granted under the Stock and Incentive Plan | |||
Weighted average fair value of stock option awards granted during the year | $ 10.49 | $ 5.65 | $ 9.90 |
Stock Based Compensation Two Thousand Twelve Incentive Plan [Member] | |||
Weighted average assumptions used to estimate fair value of stock options granted under the Stock and Incentive Plan | |||
Stock option pricing model | Black Scholes Merton | Black Scholes Merton | |
Expected option life | 4 years | 3 years 11 months 16 days | 4 years |
Risk-free interest rate | 1.77% | 1.08% | 1.15% |
Volatility | 47.00% | 45.68% | 56.89% |
Dividend yield | 0.00% | 0.00% | 0.00% |
Estimated forfeiture rate | 3.66% | 1.16% | 3.21% |
2003 Stock and Incentive Plan [Member] | |||
Weighted average assumptions used to estimate fair value of stock options granted under the Stock and Incentive Plan | |||
Stock option pricing model | Black Scholes Merton | Black Scholes Merton | Black Scholes Merton |
Expected option life | 2 years 1 month 20 days | 3 years 1 month 21 days | 4 months 21 days |
Risk-free interest rate | 1.98% | 1.70% | 0.64% |
Volatility | 43.60% | 47.07% | 91.98% |
Dividend yield | 0.00% | 0.00% | 0.00% |
Estimated forfeiture rate | 0.00% | 0.00% | 0.00% |
Stock-Based Compensation (Det48
Stock-Based Compensation (Details 1) shares in Thousands | 12 Months Ended |
Dec. 31, 2017$ / sharesshares | |
Number of options (in thousands) | |
Options outstanding at beginning of period (in shares) | shares | 2,887 |
Options granted (in shares) | shares | 1,034 |
Options exercised (in shares) | shares | (833) |
Options forfeited (in shares) | shares | (24) |
Options expired (in shares) | shares | 0 |
Options outstanding at end of period (in shares) | shares | 3,064 |
Weighted average exercise price | |
Weighted average exercise price, Options outstanding Beginning Balance (usd per share) | $ / shares | $ 15.59 |
Weighted average exercise price, Options granted (usd per share) | $ / shares | 27.09 |
Weighted average exercise price, Options exercised (usd per share) | $ / shares | 9.20 |
Weighted average exercise price, Options forfeited (usd per share) | $ / shares | 23.81 |
Weighted average exercise price, Options expired (usd per share) | $ / shares | 0 |
Weighted average exercise price, Options outstanding Ending Balance (usd per share) | $ / shares | $ 21.14 |
Stock-Based Compensation (Det49
Stock-Based Compensation (Details 2) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items] | |||
Deferred Compensation Liability, Current | $ 0 | $ 0 | $ 1 |
$8.18 - $9.55 Range [Member] | |||
Summarized information about outstanding and exercisable stock option | |||
Range of exercise prices, Lower limit | $ 8.18 | ||
Range of exercise prices, Upper limit | $ 9.55 | ||
Shares outstanding (in shares) | 294 | ||
Weighted average remaining contractual price | 8 months 10 days | ||
Weighted average exercise price (usd per share) | $ 8.46 | ||
Shares exercisable | 294 | ||
Weighted average exercise price (usd per share) | $ 8.46 | ||
$13.22 - $17.80 Range [Member] | |||
Summarized information about outstanding and exercisable stock option | |||
Range of exercise prices, Lower limit | 13.22 | ||
Range of exercise prices, Upper limit | $ 17.80 | ||
Shares outstanding (in shares) | 625 | ||
Weighted average remaining contractual price | 3 years 1 month 6 days | ||
Weighted average exercise price (usd per share) | $ 15.01 | ||
Shares exercisable | 11 | ||
Weighted average exercise price (usd per share) | $ 16.45 | ||
$19.71 - $22.70 Range [Member] | |||
Summarized information about outstanding and exercisable stock option | |||
Range of exercise prices, Lower limit | 19.71 | ||
Range of exercise prices, Upper limit | $ 22.70 | ||
Shares outstanding (in shares) | 839 | ||
Weighted average remaining contractual price | 2 years 17 days | ||
Weighted average exercise price (usd per share) | $ 21.87 | ||
Shares exercisable | 73 | ||
Weighted average exercise price (usd per share) | $ 21.50 | ||
$23.40-27.33 Range [Member] | |||
Summarized information about outstanding and exercisable stock option | |||
Range of exercise prices, Lower limit | 23.4 | ||
Range of exercise prices, Upper limit | $ 27.33 | ||
Shares outstanding (in shares) | 1,306 | ||
Weighted average remaining contractual price | 4 years 3 months 29 days | ||
Weighted average exercise price (usd per share) | $ 26.47 | ||
Shares exercisable | 141 | ||
Weighted average exercise price (usd per share) | $ 24.21 |
Stock-Based Compensation (Det50
Stock-Based Compensation (Details 3) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation expense | $ 16,654 | $ 12,362 | $ 9,450 |
Employee Stock Option [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Stock-based compensation expense | $ 7,100 | $ 5,900 | $ 4,700 |
Restricted Stock Service Based [Member] | |||
Summary of non-vested stock options | |||
Non-vested Shares, Beginning Balance (in shares) | 1,039 | ||
Shares Granted (in shares) | 531 | ||
Shares Vested (in shares) | (429) | ||
Shares Forfeited (in shares) | (37) | ||
Non-vested Shares, Ending Balance (in shares) | 1,104 | 1,039 | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract] | |||
Weighted average fair value, Beginning Balance (usd per share) | $ 18.23 | ||
Weighted average fair value, Granted (usd per share) | 26.25 | ||
Weighted average fair value, Vested (usd per share) | 16.54 | ||
Weighted average fair value, Forfeited (usd per share) | 22.94 | ||
Weighted average fair value, Ending Balance (usd per share) | $ 22.59 | $ 18.23 | |
Restricted Stock Units Service Based [Member] | |||
Summary of non-vested stock options | |||
Non-vested Shares, Beginning Balance (in shares) | 82 | ||
Shares Granted (in shares) | 113 | ||
Shares Vested (in shares) | (124) | ||
Shares Forfeited (in shares) | (6) | ||
Non-vested Shares, Ending Balance (in shares) | 65 | 82 | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract] | |||
Weighted average fair value, Beginning Balance (usd per share) | $ 21.32 | ||
Weighted average fair value, Granted (usd per share) | 23.77 | ||
Weighted average fair value, Vested (usd per share) | 22.38 | ||
Weighted average fair value, Forfeited (usd per share) | 23.45 | ||
Weighted average fair value, Ending Balance (usd per share) | $ 23.36 | $ 21.32 |
Stock Based Compensation (Detai
Stock Based Compensation (Details Textual) - USD ($) $ / shares in Units, $ in Thousands | Feb. 16, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Jun. 10, 2015 |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Maximum shares of common stock provided (in shares) | 8,700,000 | ||||
Fair value of stock option awards outstanding (in shares) | 3,064,000 | 2,887,000 | |||
Aggregate intrinsic value | $ 30,600 | ||||
Aggregate intrinsic value exercisable | $ 8,500 | ||||
Quoted closing market price | $ 31.13 | ||||
Weighted average contractual term | 1 year 25 days | ||||
Total intrinsic value of options exercised | $ 13,200 | $ 1,600 | $ 1,300 | ||
Tax related benefits realized from the exercise of stock options | 5,000 | 500 | 300 | ||
Unrecognized compensation expense related to unvested stock options | $ 9,800 | ||||
Weighted average remaining requisite service period of unvested stock awards | 9 months 12 days | ||||
Fair value of option shares vested | $ 2,100 | 3,000 | 1,300 | ||
Stock-based compensation expense | 16,654 | 12,362 | 9,450 | ||
Stock based long term liability | 400 | 1,400 | 0 | ||
Stock based current liability | $ 0 | 0 | 1,000 | ||
Restricted stock or unit expenses | 0 | ||||
Options granted (in shares) | 1,034,000 | ||||
Aggregate intrinsic value for the restricted stock and restricted stock units outstanding | $ 36,400 | ||||
Tax benefits recognized for stock based compensation | 6,800 | 4,300 | 3,400 | ||
Capitalized stock-based compensation | 3,300 | ||||
Expensed stock-based compensation | $ 16,700 | ||||
Minimum [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Vesting period of shares | 3 years | ||||
Maximum [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Vesting period of shares | 4 years | ||||
Class A [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Maximum shares that may be issued pursuant to options or restricted stock grants (in shares) | 3,481,569 | ||||
Restricted stock [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Weighted average remaining requisite service period of unvested stock awards | 11 months 12 days | ||||
Unrecognized compensation expense related to unvested restricted stock and restricted stock units | $ 14,400 | ||||
Fair value of restricted stock and restricted stock units vested | 9,900 | 4,600 | 800 | ||
Restricted stock or unit expenses | $ 12,900 | 6,600 | 4,700 | ||
Stock options [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Maximum vesting period | 5 years | ||||
Maximum vesting period 2 | 6 years | ||||
Maximum vesting period 3 | 10 years | ||||
Stock-based compensation expense | $ 7,100 | $ 5,900 | $ 4,700 | ||
Subsequent Event [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Options granted (in shares) | 563,408 | ||||
Fair value of grants | $ 26,900 | ||||
Subsequent Event [Member] | Restricted stock [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Restricted stock grants (in shares) | 667,488 | ||||
Subsequent Event [Member] | Stock options [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Vesting period of shares | 3 years | ||||
Weighted average fair value, Granted | $ 29.68 | ||||
2003 Stock and Incentive Plan [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Fair value of stock option awards outstanding (in shares) | 75,000 | 77,500 | 87,500 |
Employee Benefit Plans (Details
Employee Benefit Plans (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Employee Benefit Plan (Textual) [Abstract] | |||
Employees annual compensation | 3.00% | ||
Safe Harbor match | $ 900,000 | $ 700,000 | $ 600,000 |
Discretionary matching contributions | 1,100,000 | 900,000 | 800,000 |
No additional discretionary contributions | $ 0 | $ 0 | $ 0 |
Equity (Details)
Equity (Details) $ in Thousands | Oct. 10, 2017USD ($)ashares | Dec. 09, 2016USD ($)shares | Mar. 11, 2016USD ($)shares | Apr. 21, 2015USD ($)shares | Apr. 06, 2015shares | Feb. 27, 2015shares | Dec. 31, 2017USD ($)shares | Dec. 31, 2016USD ($)shares | Dec. 31, 2015USD ($) | Jun. 01, 2017shares | May 31, 2017shares | Apr. 02, 2015shares | Apr. 01, 2015shares |
Subsidiary, Sale of Stock [Line Items] | |||||||||||||
Payments of Stock Issuance Costs | $ | $ 300 | $ 280 | $ 847 | $ 1,158 | |||||||||
Sale of Stock, Consideration Received on Transaction | $ | $ 145,800 | $ 141,500 | |||||||||||
Adjustments to Additional Paid in Capital, Stock Issued, Issuance Costs | $ | $ 400 | $ 800 | $ 280 | $ 1,190 | 1,151 | ||||||||
Common stock, shares authorized (in shares) | 160,000,000 | 120,000,000 | |||||||||||
Issuance of Class A common stock, shares | 7,000,000 | ||||||||||||
Offering costs | $ | $ 1,200 | ||||||||||||
Proceeds from issuance of common stock | $ | $ 187,600 | $ 208,720 | $ 288,510 | 188,720 | |||||||||
Repayments of long-term debt | $ | $ 0 | $ 120,000 | $ 476,982 | ||||||||||
Net Acres | a | 6,600 | ||||||||||||
Acquisition Costs, Period Cost | $ | $ 38,000 | ||||||||||||
Common Stock [Member] | |||||||||||||
Subsidiary, Sale of Stock [Line Items] | |||||||||||||
Sale of Stock, Number of Shares Issued in Transaction | 6,000,000 | 7,500,000 | |||||||||||
Common stock, shares authorized (in shares) | 160,000,000 | 120,000,000 | 120,000,000 | 80,000,000 | |||||||||
Shares converted | 1,500,000 | ||||||||||||
Shares held in escrow | 166,667 | ||||||||||||
Harvey E Yates Company [Member] | |||||||||||||
Subsidiary, Sale of Stock [Line Items] | |||||||||||||
Shares issued upon conversion | 10 | ||||||||||||
Harvey E Yates Company [Member] | Convertible Preferred Stock [Member] | |||||||||||||
Subsidiary, Sale of Stock [Line Items] | |||||||||||||
Shares issued for acquisition | 150,000 | ||||||||||||
Shares issued as consideration in business combination | 150,000 | ||||||||||||
Harvey E Yates Company [Member] | Common Stock [Member] | |||||||||||||
Subsidiary, Sale of Stock [Line Items] | |||||||||||||
Shares issued for acquisition | 3,300,000 | ||||||||||||
Public Stock Offering [Member] | |||||||||||||
Subsidiary, Sale of Stock [Line Items] | |||||||||||||
Sale of Stock, Consideration Received on Transaction | $ | $ 208,400 | ||||||||||||
Public Stock Offering [Member] | Common Stock [Member] | |||||||||||||
Subsidiary, Sale of Stock [Line Items] | |||||||||||||
Sale of Stock, Number of Shares Issued in Transaction | 8,000,000 |
Derivative Financial Instrume54
Derivative Financial Instruments (Details) $ in Thousands | Dec. 31, 2017USD ($)MMBTUbbl$ / bbl$ / MMBTU | Sep. 30, 2017USD ($) |
Summary of contracts for oil and natural gas | ||
Fair Value of Asset (Liability) | $ (15,239) | |
Open costless collar contracts [Member] | ||
Summary of contracts for oil and natural gas | ||
Fair Value of Asset (Liability) | $ (9,675) | |
Open costless collar contracts [Member] | Oil - WTI [Member] | ||
Summary of contracts for oil and natural gas | ||
Derivative, Nonmonetary Notional Amount | bbl | 2,880,000 | |
Price Floor | $ / bbl | 44.27 | |
Price Ceiling | $ / bbl | 60.29 | |
Fair Value of Asset (Liability) | $ (8,414) | |
Open costless collar contracts [Member] | Oil - LLS [Member] | ||
Summary of contracts for oil and natural gas | ||
Derivative, Nonmonetary Notional Amount | bbl | 720,000 | |
Price Floor | $ / bbl | 45 | |
Price Ceiling | $ / bbl | 63.05 | |
Fair Value of Asset (Liability) | $ (2,451) | |
Open costless collar contracts [Member] | Natural Gas, Calculation Period One [Member] | ||
Summary of contracts for oil and natural gas | ||
Derivative, Nonmonetary Notional Amount | MMBTU | 16,800,000 | |
Price Floor | $ / MMBTU | 2.58 | |
Price Ceiling | $ / MMBTU | 3.67 | |
Fair Value of Asset (Liability) | $ 1,190 | |
Open Swap Contracts [Member] | ||
Summary of contracts for oil and natural gas | ||
Fair Value of Asset (Liability) | $ (5,564) | |
Open Swap Contracts [Member] | Oil, Calculation Period Two [Member] | ||
Summary of contracts for oil and natural gas | ||
Derivative, Nonmonetary Notional Amount | bbl | 5,220,000 | |
Fair Value of Asset (Liability) | $ (5,564) | |
Fixed price | $ / bbl | (1.02) |
Derivative Financial Instrume55
Derivative Financial Instruments (Details 2) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Offsetting Derivative Assets [Abstract] | ||
Derivative Liability | $ (15,239) | $ (24,954) |
Offsetting Derivative Liabilities [Abstract] | ||
Derivative Asset | 0 | 0 |
Other Current Assets [Member] | ||
Offsetting Derivative Liabilities [Abstract] | ||
Gross amounts of recognized assets | 131,092 | |
Gross amounts netted in the consolidated balance sheets | (129,902) | |
Derivative Asset | 1,190 | |
Current liabilities [Member] | ||
Offsetting Derivative Assets [Abstract] | ||
Gross amounts of recognized liabilities | (146,331) | (24,203) |
Gross amounts netted in the consolidated balance sheet | (129,902) | 0 |
Derivative Liability | $ (16,429) | (24,203) |
Other liabilities [Member] | ||
Offsetting Derivative Assets [Abstract] | ||
Gross amounts of recognized liabilities | 751 | |
Gross amounts netted in the consolidated balance sheet | 0 | |
Derivative Liability | $ 751 |
Derivative Financial Instrume56
Derivative Financial Instruments (Details 3) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Summary of location and aggregate fair value of all derivative financial instruments recorded in the consolidated statements of operations | |||
Realized (loss) gain on derivatives | $ (4,321) | $ 9,286 | $ 77,094 |
Unrealized gain (loss) on derivatives | 9,715 | (41,238) | (39,265) |
Revenues [Member] | |||
Summary of location and aggregate fair value of all derivative financial instruments recorded in the consolidated statements of operations | |||
Realized (loss) gain on derivatives | (4,321) | 9,286 | 77,094 |
Unrealized gain (loss) on derivatives | 9,715 | (41,238) | (39,265) |
Total | 5,394 | (31,952) | 37,829 |
Oil [Member] | Revenues [Member] | |||
Summary of location and aggregate fair value of all derivative financial instruments recorded in the consolidated statements of operations | |||
Realized (loss) gain on derivatives | (3,657) | 5,851 | 62,259 |
Unrealized gain (loss) on derivatives | 2,638 | (18,969) | (31,897) |
Natural Gas [Member] | Revenues [Member] | |||
Summary of location and aggregate fair value of all derivative financial instruments recorded in the consolidated statements of operations | |||
Realized (loss) gain on derivatives | (608) | 3,435 | 12,653 |
Unrealized gain (loss) on derivatives | 7,077 | (22,269) | (5,440) |
NGL's [Member] | Revenues [Member] | |||
Summary of location and aggregate fair value of all derivative financial instruments recorded in the consolidated statements of operations | |||
Realized (loss) gain on derivatives | (56) | 0 | 2,182 |
Unrealized gain (loss) on derivatives | $ 0 | $ 0 | $ (1,928) |
Fair Value Measurements (Detail
Fair Value Measurements (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Assets (Liabilities) | ||
Derivative Liability | $ 15,239 | $ 24,954 |
Derivative, Fair Value, Net | (15,239) | |
Fair value on a recurring basis [Member] | ||
Assets (Liabilities) | ||
Derivative Liability | 1,190 | (24,954) |
Derivative Assets (Liabilities), at Fair Value, Net | (15,239) | |
Fair value on a recurring basis [Member] | Oil [Member] | ||
Assets (Liabilities) | ||
Derivative Assets (Liabilities), at Fair Value, Net | (16,429) | (24,954) |
Fair value on a recurring basis [Member] | Level 1 [Member] | ||
Assets (Liabilities) | ||
Derivative Liability | 0 | 0 |
Fair value on a recurring basis [Member] | Level 1 [Member] | Oil [Member] | ||
Assets (Liabilities) | ||
Derivative Assets (Liabilities), at Fair Value, Net | 0 | |
Fair value on a recurring basis [Member] | Level 2 [Member] | ||
Assets (Liabilities) | ||
Derivative Liability | 1,190 | (24,954) |
Derivative, Fair Value, Net | (15,239) | (24,954) |
Fair value on a recurring basis [Member] | Level 2 [Member] | Oil [Member] | ||
Assets (Liabilities) | ||
Derivative Assets (Liabilities), at Fair Value, Net | (16,429) | |
Fair value on a recurring basis [Member] | Level 3 [Member] | ||
Assets (Liabilities) | ||
Derivative Liability | 0 | $ 0 |
Fair value on a recurring basis [Member] | Level 3 [Member] | Oil [Member] | ||
Assets (Liabilities) | ||
Derivative Assets (Liabilities), at Fair Value, Net | $ 0 |
Fair Value Measurements (Deta58
Fair Value Measurements (Details Textual) - USD ($) | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Fair value of notes payable | $ 614,100,000 | $ 605,200,000 |
Pipe and other equipment [Member] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Impairment charge for equipments held in inventory | $ 0 | $ 0 |
Commitments and Contingencies59
Commitments and Contingencies (Details) $ in Thousands | Dec. 31, 2017USD ($) |
Schedule of future minimum lease payments required under the office lease agreement | |
2,018 | $ 2,495 |
2,019 | 2,528 |
2,020 | 2,602 |
2,021 | 2,660 |
2,022 | 2,774 |
Thereafter | 9,561 |
Total | $ 22,620 |
Commitments and Contingencies60
Commitments and Contingencies (Details Textual) - USD ($) | Feb. 17, 2017 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Long-term Purchase Commitment [Line Items] | ||||
Term of leases | 5 years | |||
Rent expense, including fees for operating expenses and consumption of electricity | $ 2,600,000 | $ 2,900,000 | $ 1,700,000 | |
Deficiency fees | 0 | |||
Minimum outstanding commitments | 24,800,000 | |||
Capital Addition Purchase Commitments [Member] | ||||
Long-term Purchase Commitment [Line Items] | ||||
Long-term purchase commitment | 55,300,000 | |||
Payment for long-term purchase commitment | 49,700,000 | |||
Remaining minimum amount committed | 5,600,000 | |||
Drilling Rig Commitments [Member] | ||||
Long-term Purchase Commitment [Line Items] | ||||
Maximum termination outstanding obligations of contracts | 36,500,000 | |||
Loving County System Agreement [Member] | ||||
Long-term Purchase Commitment [Line Items] | ||||
Supply agreement, term | 15 years | |||
Total deficiency fee estimate | 8,400,000 | |||
Transportation and processing fees under the agreement | 14,400,000 | $ 9,800,000 | ||
Eddy County [Member] | ||||
Long-term Purchase Commitment [Line Items] | ||||
Transportation and processing fees under the agreement | 200,000 | |||
Corporate Joint Venture [Member] | San Mateo Midstream [Member] | ||||
Long-term Purchase Commitment [Line Items] | ||||
Contractual obligation | 232,600,000 | |||
Payment for long-term purchase commitment | $ 39,400,000 | |||
Corporate Joint Venture [Member] | San Mateo Midstream [Member] | Rustler Breaks and Wolf Asset Area [Member] | ||||
Long-term Purchase Commitment [Line Items] | ||||
Contractual obligation, term | 15 years | |||
Corporate Joint Venture [Member] | San Mateo Midstream [Member] | Rustler Breaks Asset Area [Member] | ||||
Long-term Purchase Commitment [Line Items] | ||||
Contractual obligation, term | 15 years | |||
Natural Gas Transportation Agreement [Member] | Eddy County [Member] | ||||
Long-term Purchase Commitment [Line Items] | ||||
Supply agreement, term | 18 years | |||
Contractual obligation | $ 59,400,000 | |||
Natural Gas Transportation and Fractionation Agreement [Member] | Eddy County [Member] | ||||
Long-term Purchase Commitment [Line Items] | ||||
Supply agreement, term | 7 years | |||
Contractual obligation | $ 132,500,000 |
Supplemental Disclosures (Detai
Supplemental Disclosures (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Summary of current accrued liabilities | ||
Total accrued liabilities | $ 174,348 | $ 101,460 |
Other | 4,418 | 3,011 |
Accrued evaluated and unproved and unevaluated property costs [Member] | ||
Summary of current accrued liabilities | ||
Total accrued liabilities | 105,347 | 54,273 |
Accrued support equipment and facilities costs [Member] | ||
Summary of current accrued liabilities | ||
Total accrued liabilities | 14,823 | 15,139 |
Accrued lease operating expenses [Member] | ||
Summary of current accrued liabilities | ||
Total accrued liabilities | 12,611 | 16,009 |
Accrued interest on debt [Member] | ||
Summary of current accrued liabilities | ||
Total accrued liabilities | 8,345 | 6,541 |
Accrued asset retirement obligations [Member] | ||
Summary of current accrued liabilities | ||
Total accrued liabilities | 1,176 | 915 |
Accrued partners' share of joint interest charges [Member] | ||
Summary of current accrued liabilities | ||
Total accrued liabilities | $ 27,628 | $ 5,572 |
Supplemental Disclosures (Det62
Supplemental Disclosures (Details 1) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Supplemental disclosures of cash flow information | |||
Cash paid for income taxes | $ 0 | $ 2,895 | $ 506 |
Cash paid for interest expense, net of amounts capitalized | 32,760 | 27,464 | 16,154 |
Increase in asset retirement obligations related to mineral properties | 4,385 | 3,817 | 2,510 |
(Decrease) increase in asset retirement obligations related to support equipment and facilities | (60) | 222 | 383 |
Increase (decrease) in liabilities for oil and natural gas properties capital expenditures | 48,929 | 1,775 | (30,683) |
(Decrease) increase in liabilities for support equipment and facilities | (955) | (588) | 12,076 |
Issuance of restricted stock units for director and advisor services | 0 | 992 | 584 |
Stock-based compensation expense recognized as liability | 362 | 569 | 79 |
(Decrease) increase in liabilities for accrued cost to issue equity | (343) | 343 | 0 |
Transfer of inventory (to) from oil and natural gas properties | (374) | 395 | 615 |
Transfer of inventory to other property and equipment | $ (317) | $ 0 | $ 0 |
Subsidiary Guarantors Consolida
Subsidiary Guarantors Consolidated Balance Sheet (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Condensed Balance Sheet Statements, Captions [Line Items] | |||
Receivables, Intercompany | $ 0 | $ 0 | |
Other Assets, Current | 257,170 | 279,182 | |
Property, Plant and Equipment, Net | 1,881,456 | 1,184,525 | |
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures | 0 | 0 | |
Other Assets | 7,064 | 958 | |
Assets | 2,145,690 | 1,464,665 | $ 1,140,861 |
Payables, Intercompany | 0 | 0 | |
Other Sundry Liabilities, Current | 282,606 | 169,505 | |
Unsecured Long-term Debt, Noncurrent | 574,073 | 573,924 | |
Other Sundry Liabilities, Noncurrent | 31,465 | 29,791 | |
Stockholders' Equity Attributable to Parent | 1,156,556 | 690,125 | |
Non-controlling interest in subsidiaries | 100,990 | 1,320 | |
Liabilities and Equity | $ 2,145,690 | 1,464,665 | |
Subsidiary ownership percentage | 100.00% | ||
Consolidation, Eliminations [Member] | |||
Condensed Balance Sheet Statements, Captions [Line Items] | |||
Receivables, Intercompany | $ (588,021) | (332,453) | |
Other Assets, Current | 0 | 0 | |
Property, Plant and Equipment, Net | 0 | 0 | |
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures | (1,258,372) | (947,037) | |
Other Assets | (3,003) | 0 | |
Assets | (1,849,396) | (1,279,490) | |
Payables, Intercompany | (588,021) | (332,453) | |
Other Sundry Liabilities, Current | (274) | 0 | |
Unsecured Long-term Debt, Noncurrent | 0 | 0 | |
Other Sundry Liabilities, Noncurrent | (2,729) | 0 | |
Stockholders' Equity Attributable to Parent | (1,258,372) | (947,037) | |
Non-controlling interest in subsidiaries | 0 | 0 | |
Liabilities and Equity | (1,849,396) | (1,279,490) | |
Parent Company [Member] | Reportable Legal Entities [Member] | |||
Condensed Balance Sheet Statements, Captions [Line Items] | |||
Receivables, Intercompany | 585,109 | 316,791 | |
Other Assets, Current | 2,240 | 101,102 | |
Property, Plant and Equipment, Net | 0 | 33 | |
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures | 1,147,295 | 856,762 | |
Other Assets | 6,425 | 0 | |
Assets | 1,741,069 | 1,274,688 | |
Payables, Intercompany | 0 | 0 | |
Other Sundry Liabilities, Current | 8,847 | 9,265 | |
Unsecured Long-term Debt, Noncurrent | 574,073 | 573,924 | |
Other Sundry Liabilities, Noncurrent | 1,593 | 1,374 | |
Stockholders' Equity Attributable to Parent | 1,156,556 | 690,125 | |
Non-controlling interest in subsidiaries | 0 | 0 | |
Liabilities and Equity | 1,741,069 | 1,274,688 | |
Non-Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member] | |||
Condensed Balance Sheet Statements, Captions [Line Items] | |||
Receivables, Intercompany | 2,912 | 3,571 | |
Other Assets, Current | 9,334 | 4,242 | |
Property, Plant and Equipment, Net | 223,178 | 113,107 | |
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures | 0 | 0 | |
Other Assets | 0 | 0 | |
Assets | 235,424 | 120,920 | |
Payables, Intercompany | 0 | 12,091 | |
Other Sundry Liabilities, Current | 19,891 | 16,632 | |
Unsecured Long-term Debt, Noncurrent | 0 | 0 | |
Other Sundry Liabilities, Noncurrent | 3,466 | 602 | |
Stockholders' Equity Attributable to Parent | 111,077 | 90,275 | |
Non-controlling interest in subsidiaries | 100,990 | 1,320 | |
Liabilities and Equity | 235,424 | 120,920 | |
Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member] | |||
Condensed Balance Sheet Statements, Captions [Line Items] | |||
Receivables, Intercompany | 0 | 12,091 | |
Other Assets, Current | 245,596 | 173,838 | |
Property, Plant and Equipment, Net | 1,658,278 | 1,071,385 | |
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures | 111,077 | 90,275 | |
Other Assets | 3,642 | 958 | |
Assets | 2,018,593 | 1,348,547 | |
Payables, Intercompany | 588,021 | 320,362 | |
Other Sundry Liabilities, Current | 254,142 | 143,608 | |
Unsecured Long-term Debt, Noncurrent | 0 | 0 | |
Other Sundry Liabilities, Noncurrent | 29,135 | 27,815 | |
Stockholders' Equity Attributable to Parent | 1,147,295 | 856,762 | |
Non-controlling interest in subsidiaries | 0 | 0 | |
Liabilities and Equity | $ 2,018,593 | $ 1,348,547 |
Subsidiary Guarantors Consoli64
Subsidiary Guarantors Consolidated Income Statement (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Condensed Income Statements, Captions [Line Items] | |||
Total revenues | $ 544,276 | $ 264,422 | $ 318,033 |
Total expenses | 383,435 | 441,589 | 1,124,695 |
Operating (loss) income | 160,841 | (177,167) | (806,662) |
Net gain on asset sales and inventory impairment | 23 | 107,277 | 908 |
Interest expense | (34,565) | (28,199) | (21,754) |
Other income | 3,551 | (4) | 616 |
Earnings in subsidiaries | 0 | 0 | 0 |
Income (loss) before income taxes | 129,850 | (98,093) | (826,892) |
Total income tax (benefit) provision | (8,157) | (1,036) | (147,368) |
Net income attributable to non-controlling interest in subsidiaries | (12,140) | (364) | (261) |
Net income (loss) attributable to Matador Resources Company shareholders | 125,867 | (97,421) | (679,785) |
Consolidation, Eliminations [Member] | |||
Condensed Income Statements, Captions [Line Items] | |||
Total revenues | (35,115) | (10,708) | (4,344) |
Total expenses | (35,115) | (10,708) | (4,344) |
Operating (loss) income | 0 | 0 | |
Net gain on asset sales and inventory impairment | 0 | 0 | 0 |
Interest expense | 0 | 0 | 0 |
Other income | 0 | ||
Earnings in subsidiaries | (171,840) | 54,539 | 656,240 |
Income (loss) before income taxes | (171,840) | 54,539 | 656,240 |
Total income tax (benefit) provision | 0 | 0 | 0 |
Net income attributable to non-controlling interest in subsidiaries | 0 | 0 | 0 |
Net income (loss) attributable to Matador Resources Company shareholders | (171,840) | 54,539 | 656,240 |
Parent Company [Member] | Reportable Legal Entities [Member] | |||
Condensed Income Statements, Captions [Line Items] | |||
Total revenues | 0 | ||
Total expenses | 5,610 | 5,319 | 5,739 |
Operating (loss) income | (5,610) | (5,319) | (5,739) |
Net gain on asset sales and inventory impairment | 0 | 0 | 0 |
Interest expense | (34,565) | (28,199) | (20,511) |
Other income | 27 | 0 | |
Earnings in subsidiaries | 157,589 | (64,349) | (658,698) |
Income (loss) before income taxes | 117,441 | (97,867) | (684,948) |
Total income tax (benefit) provision | (8,426) | (446) | (5,163) |
Net income attributable to non-controlling interest in subsidiaries | 0 | 0 | 0 |
Net income (loss) attributable to Matador Resources Company shareholders | 125,867 | (97,421) | (679,785) |
Non-Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member] | |||
Condensed Income Statements, Captions [Line Items] | |||
Total revenues | 47,883 | 17,302 | 6,310 |
Total expenses | 21,260 | 7,031 | 2,944 |
Operating (loss) income | 26,623 | 10,271 | 3,366 |
Net gain on asset sales and inventory impairment | 0 | 0 | 0 |
Interest expense | 0 | 0 | |
Other income | 37 | 0 | 0 |
Earnings in subsidiaries | 0 | 0 | 0 |
Income (loss) before income taxes | 26,660 | 10,271 | 3,366 |
Total income tax (benefit) provision | 269 | 97 | 647 |
Net income attributable to non-controlling interest in subsidiaries | (12,140) | (364) | (261) |
Net income (loss) attributable to Matador Resources Company shareholders | 14,251 | 9,810 | 2,458 |
Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member] | |||
Condensed Income Statements, Captions [Line Items] | |||
Total revenues | 531,508 | 257,828 | 316,067 |
Total expenses | 391,680 | 439,947 | 1,120,356 |
Operating (loss) income | 139,828 | (182,119) | (804,289) |
Net gain on asset sales and inventory impairment | 23 | 107,277 | 908 |
Interest expense | 0 | (1,243) | |
Other income | 3,487 | (4) | 616 |
Earnings in subsidiaries | 14,251 | 9,810 | 2,458 |
Income (loss) before income taxes | 157,589 | (65,036) | (801,550) |
Total income tax (benefit) provision | 0 | (687) | (142,852) |
Net income attributable to non-controlling interest in subsidiaries | 0 | 0 | 0 |
Net income (loss) attributable to Matador Resources Company shareholders | $ 157,589 | $ (64,349) | $ (658,698) |
Subsidiary Guarantors Consoli65
Subsidiary Guarantors Consolidated Cash Flow (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Condensed Cash Flow Statements, Captions [Line Items] | |||
Net cash (used in) provided by operating activities | $ 299,125 | $ 134,086 | $ 208,535 |
Net cash provided by (used in) investing activities | (824,003) | (405,640) | (425,154) |
Net cash provided by (used in) financing activities | 408,499 | 467,706 | 224,944 |
Decrease in cash | (116,379) | 196,152 | 8,325 |
Cash at beginning of year | 212,884 | 16,732 | 8,407 |
Cash at end of year | 96,505 | 212,884 | 16,732 |
Consolidation, Eliminations [Member] | |||
Condensed Cash Flow Statements, Captions [Line Items] | |||
Net cash (used in) provided by operating activities | 0 | 0 | 0 |
Net cash provided by (used in) investing activities | (106,595) | 384,801 | 563,505 |
Net cash provided by (used in) financing activities | 106,595 | (384,801) | (563,505) |
Decrease in cash | 0 | 0 | 0 |
Cash at beginning of year | 0 | 0 | 0 |
Cash at end of year | 0 | 0 | 0 |
Parent Company [Member] | Reportable Legal Entities [Member] | |||
Condensed Cash Flow Statements, Captions [Line Items] | |||
Net cash (used in) provided by operating activities | (307,982) | (45,215) | (31,271) |
Net cash provided by (used in) investing activities | 33 | (324,724) | (546,715) |
Net cash provided by (used in) financing activities | 208,440 | 469,654 | 577,973 |
Decrease in cash | (99,509) | 99,715 | (13) |
Cash at beginning of year | 99,795 | 80 | 93 |
Cash at end of year | 286 | 99,795 | 80 |
Non-Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member] | |||
Condensed Cash Flow Statements, Captions [Line Items] | |||
Net cash (used in) provided by operating activities | 21,308 | 6,694 | 13,916 |
Net cash provided by (used in) investing activities | (119,922) | (64,683) | (31,101) |
Net cash provided by (used in) financing activities | 96,307 | 60,110 | 17,353 |
Decrease in cash | (2,307) | 2,121 | 168 |
Cash at beginning of year | 2,307 | 186 | 18 |
Cash at end of year | 0 | 2,307 | 186 |
Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member] | |||
Condensed Cash Flow Statements, Captions [Line Items] | |||
Net cash (used in) provided by operating activities | 585,799 | 172,607 | 225,890 |
Net cash provided by (used in) investing activities | (597,519) | (401,034) | (410,843) |
Net cash provided by (used in) financing activities | (2,843) | 322,743 | 193,123 |
Decrease in cash | (14,563) | 94,316 | 8,170 |
Cash at beginning of year | 110,782 | 16,466 | 8,296 |
Cash at end of year | $ 96,219 | $ 110,782 | $ 16,466 |
Related Party Transactions (Det
Related Party Transactions (Details) $ in Thousands | 1 Months Ended | 12 Months Ended | ||
Jun. 30, 2015USD ($)ajoint_venture | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | |
Related Party Transaction [Line Items] | ||||
Capital contributed to joint ventures | $ 171,500 | $ 0 | $ 0 | |
Corporate Joint Venture [Member] | ||||
Related Party Transaction [Line Items] | ||||
Number of joint ventures | joint_venture | 2 | |||
Acreage contributed by joint venture partner | a | 1,900 | |||
Percentage of joint ventures owned by partners | 50.00% | |||
Capital commitment to joint ventures | $ 14,000 | |||
Capital contributed to joint ventures | $ 4,400 |
Segment Reporting (Details)
Segment Reporting (Details) | 12 Months Ended | |||
Dec. 31, 2017USD ($)segment | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Oct. 31, 2015USD ($) | |
Segment Reporting Information [Line Items] | ||||
Number of business segments | segment | 2 | |||
Oil and natural gas revenues | $ 528,684,000 | $ 291,156,000 | $ 278,340,000 | |
Third-party midstream services revenues | 10,198,000 | 5,218,000 | 1,864,000 | |
Realized gain on derivatives | (4,321,000) | 9,286,000 | 77,094,000 | |
Unrealized gain on derivatives | 9,715,000 | (41,238,000) | (39,265,000) | |
Total expenses | 383,435,000 | 441,589,000 | 1,124,695,000 | |
Operating income (loss) | 160,841,000 | (177,167,000) | (806,662,000) | |
Assets | 2,145,690,000 | 1,464,665,000 | 1,140,861,000 | |
Capital expenditures | 872,958,000 | 454,360,000 | 698,437,000 | |
Income (loss) attributable to noncontrolling interest | 12,140,000 | 364,000 | 261,000 | |
Depletion, depreciation and amortization | 177,502,000 | 122,048,000 | 178,847,000 | |
Impairment charge of net capitalized costs | 0 | 158,633,000 | 801,166,000 | |
Carrying value of net assets sold | $ 31,000,000 | |||
Operating Segments [Member] | Exploration and Production Segment [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Oil and natural gas revenues | 525,862,000 | 289,512,000 | 277,844,000 | |
Third-party midstream services revenues | 0 | 0 | 0 | |
Realized gain on derivatives | (4,321,000) | 9,286,000 | 77,094,000 | |
Unrealized gain on derivatives | 9,715,000 | (41,238,000) | (39,265,000) | |
Total expenses | 333,923,000 | 391,098,000 | 1,078,534,000 | |
Operating income (loss) | 197,333,000 | (133,538,000) | (762,861,000) | |
Assets | 1,768,393,000 | 1,098,525,000 | 1,000,075,000 | |
Capital expenditures | 753,157,000 | 379,881,000 | 622,642,000 | |
Depletion, depreciation and amortization | 170,500,000 | 118,400,000 | 176,700,000 | |
Impairment charge of net capitalized costs | 158,600,000 | 801,200,000 | ||
Operating Segments [Member] | Midstream Segment [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Oil and natural gas revenues | 2,822,000 | 1,644,000 | 496,000 | |
Third-party midstream services revenues | 47,037,000 | 18,982,000 | 11,485,000 | |
Realized gain on derivatives | 0 | 0 | ||
Unrealized gain on derivatives | 0 | 0 | ||
Total expenses | 23,420,000 | 8,254,000 | 5,178,000 | |
Operating income (loss) | 26,439,000 | 12,372,000 | 6,803,000 | |
Assets | 257,871,000 | 140,459,000 | 75,980,000 | |
Capital expenditures | 114,113,000 | 67,566,000 | 75,009,000 | |
Income (loss) attributable to noncontrolling interest | 12,100,000 | 300,000 | ||
Depletion, depreciation and amortization | 5,200,000 | 2,700,000 | 1,600,000 | |
Payments to acquire productive assets | 54,900,000 | 400,000 | ||
Corporate, Non-Segment [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Oil and natural gas revenues | 0 | 0 | ||
Third-party midstream services revenues | 0 | 0 | 0 | |
Realized gain on derivatives | 0 | 0 | ||
Unrealized gain on derivatives | 0 | 0 | ||
Total expenses | 62,931,000 | 56,001,000 | 50,604,000 | |
Operating income (loss) | (62,931,000) | (56,001,000) | (50,604,000) | |
Assets | 119,426,000 | 225,681,000 | 64,806,000 | |
Capital expenditures | 5,688,000 | 6,913,000 | 786,000 | |
Depletion, depreciation and amortization | 1,700,000 | 900,000 | 500,000 | |
Intersegment Eliminations [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Oil and natural gas revenues | 0 | 0 | ||
Third-party midstream services revenues | (36,839,000) | (13,764,000) | (9,621,000) | |
Realized gain on derivatives | 0 | 0 | ||
Unrealized gain on derivatives | 0 | 0 | ||
Total expenses | (36,839,000) | (13,764,000) | (9,621,000) | |
Assets | 0 | 0 | 0 | |
Capital expenditures | $ 0 | $ 0 | $ 0 |
Subsequent Events (Narrative) (
Subsequent Events (Narrative) (Details) | Jan. 22, 2018a |
Subsequent Event [Member] | |
Subsequent Event [Line Items] | |
Joint development area (acres) | 400,000 |