Document and Entity Information
Document and Entity Information - USD ($) | 12 Months Ended | ||
Dec. 31, 2015 | Feb. 16, 2016 | Jun. 30, 2015 | |
Document and Entity Information [Abstract] | |||
Document Type | 10-K | ||
Amendment Flag | false | ||
Document Period End Date | Dec. 31, 2015 | ||
Document Fiscal Year Focus | 2,015 | ||
Document Fiscal Period Focus | FY | ||
Entity Registrant Name | Diamondback Energy, Inc. | ||
Entity Central Index Key | 1,539,838 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Common Stock, Shares Outstanding | 71,397,041 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Public Float | $ 4,709,835,344 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Current assets: | ||
Cash and cash equivalents | $ 20,115 | $ 30,183 |
Restricted cash | 500 | 500 |
Accounts receivable: | ||
Joint interest and other | 41,309 | 50,943 |
Oil and natural gas sales | 36,004 | 43,050 |
Related party | 1,591 | 4,001 |
Inventories | 1,728 | 2,827 |
Derivative instruments | 4,623 | 115,607 |
Prepaid expenses and other | 2,875 | 4,600 |
Total current assets | 108,745 | 251,711 |
Property and equipment | ||
Oil and natural gas properties, based on the full cost method of accounting ($1,106,816 and $773,520 excluded from amortization at December 31, 2015 and December 31, 2014, respectively) | 3,955,373 | 3,118,597 |
Pipeline and gas gathering assets | 7,174 | 7,174 |
Other property and equipment | 48,621 | 48,180 |
Accumulated depletion, depreciation, amortization and impairment | (1,413,543) | (382,144) |
Net property and equipment | 2,597,625 | 2,791,807 |
Derivative instruments | 0 | 1,934 |
Other assets | 52,042 | 50,029 |
Total assets | 2,758,412 | 3,095,481 |
Current liabilities: | ||
Accounts payable-trade | 20,008 | 26,230 |
Accounts payable-related party | 217 | 0 |
Accrued capital expenditures | 59,937 | 129,397 |
Other accrued liabilities | 44,293 | 41,149 |
Revenues and royalties payable | 16,966 | 30,000 |
Deferred income taxes | 0 | 39,953 |
Total current liabilities | 141,421 | 266,729 |
Long-term debt | 495,500 | 673,500 |
Asset retirement obligations | 12,518 | 8,447 |
Deferred income taxes | 0 | 161,592 |
Total liabilities | $ 649,439 | $ 1,110,268 |
Commitments and contingencies | ||
Stockholders’ equity: | ||
Common stock, $0.01 par value, 100,000,000 shares authorized, 66,797,041 issued and outstanding at December 31, 2015; 56,887,583 issued and outstanding at December 31, 2014 | $ 668 | $ 569 |
Additional paid-in capital | 2,229,664 | 1,554,174 |
Retained earnings | (354,360) | 196,268 |
Total Diamondback Energy, Inc. stockholders’ equity | 1,875,972 | 1,751,011 |
Noncontrolling interest | 233,001 | 234,202 |
Total equity | 2,108,973 | 1,985,213 |
Total liabilities and equity | $ 2,758,412 | $ 3,095,481 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Statement of Financial Position [Abstract] | ||
Oil and natural gas properties, amortization excluded | $ 1,106,816 | $ 773,520 |
Common Stock, Par Value (in dollars per share) | $ 0.01 | $ 0.01 |
Common Stock, Shares, Authorized | 100,000,000 | 100,000,000 |
Common Stock, Shares, Issued | 66,797,041 | 56,887,583 |
Common Stock, Shares, Outstanding | 66,797,041 | 56,887,583 |
Consolidated Statements of Oper
Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Revenues: | |||
Oil sales | $ 405,715 | $ 449,244 | $ 188,753 |
Natural gas sales | 16,952 | 8,662 | 3,715 |
Natural gas sales - related party | 2,640 | 9,366 | 2,534 |
Natural gas liquid sales | 18,882 | 13,408 | 8,304 |
Natural gas liquid sales - related party | 2,544 | 15,038 | 4,696 |
Total revenues | 446,733 | 495,718 | 208,002 |
Costs and expenses: | |||
Lease operating expenses | 82,404 | 55,166 | 19,991 |
Lease operating expenses - related party | 221 | 218 | 1,166 |
Production and ad valorem taxes | 32,837 | 31,160 | 12,399 |
Production and ad valorem taxes - related party | 153 | 1,478 | 500 |
Gathering and transportation | 5,122 | 618 | 237 |
Gathering and transportation - related party | 969 | 2,670 | 681 |
Depreciation, depletion and amortization | 217,697 | 170,005 | 66,597 |
Impairment of oil and natural gas properties | 814,798 | 0 | 0 |
General and administrative expenses (including non-cash equity-based compensation, net of capitalized amounts, of $18,529, $9,816 and $1,752 for the year ended December 31, 2015, 2014 and 2013, respectively) | 29,640 | 19,921 | 9,870 |
General and administrative expenses - related party | 2,328 | 1,345 | 1,166 |
Asset retirement obligation accretion expense | 833 | 467 | 201 |
Total costs and expenses | 1,187,002 | 283,048 | 112,808 |
Income (loss) from operations | (740,269) | 212,670 | 95,194 |
Other income (expense) | |||
Interest income (expense) | (41,510) | (34,514) | (8,058) |
Other income | 567 | 556 | 0 |
Other income - related party | 161 | 121 | 1,077 |
Other expense | 0 | (1,416) | 0 |
Gain (loss) on derivative instruments, net | 31,951 | 127,539 | (1,872) |
Total other income (expense), net | (8,831) | 92,286 | (8,853) |
Income (loss) before income taxes | (749,100) | 304,956 | 86,341 |
Provision for (benefit from) income taxes | (201,310) | 108,985 | 31,754 |
Net income (loss) | (547,790) | 195,971 | 54,587 |
Less: Net income attributable to noncontrolling interest | 2,838 | 2,216 | 0 |
Net income (loss) attributable to Diamondback Energy, Inc. | $ (550,628) | $ 193,755 | $ 54,587 |
Earnings per common share | |||
Basic (in dollars per share) | $ (8.74) | $ 3.67 | $ 1.30 |
Diluted (in dollars per share) | $ (8.74) | $ 3.64 | $ 1.29 |
Weighted average common shares outstanding | |||
Basic (in shares) | 63,019 | 52,826 | 42,015 |
Diluted (in shares) | 63,019 | 53,297 | 42,255 |
Consolidated Statements of Ope5
Consolidated Statements of Operations (Parentheticals) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Income Statement [Abstract] | |||
Non-cash stock based compensation, net of capitalized amount | $ 18,529 | $ 9,816 | $ 1,752 |
Consolidated Statement of Stock
Consolidated Statement of Stockholders' Equity - USD ($) $ in Thousands | Total | Common Stock [Member] | Additional Paid-in Capital [Member] | Retained Earnings (Accumulated Deficit) [Member] | Noncontrolling Interest [Member] |
Balance at beginning of period at Dec. 31, 2012 | $ 462,068 | $ 370 | $ 513,772 | $ (52,074) | $ 0 |
Balance at beginning of period, shares at Dec. 31, 2012 | 36,986,000 | ||||
Increase (Decrease) in Stockholders' Equity | |||||
Stock-based compensation | 2,724 | $ 0 | 2,724 | 0 | 0 |
Tax benefits related to stock-based compensation | 749 | 0 | 749 | 0 | 0 |
Common shares issued in public offering, net of offering costs | 321,912 | $ 98 | 321,814 | 0 | 0 |
Common shares issued in public offering, net of offering costs, shares | 9,775,000 | ||||
Exercise of stock options and awards of restricted stock | 3,501 | $ 3 | 3,498 | 0 | 0 |
Exercise of stock options and awards of restricted stock, shares | 345,000 | ||||
Net income (loss) | 54,587 | $ 0 | 0 | 54,587 | 0 |
Balance at end of period at Dec. 31, 2013 | 845,541 | $ 471 | 842,557 | 2,513 | 0 |
Balance at end of period, shares at Dec. 31, 2013 | 47,106,000 | ||||
Increase (Decrease) in Stockholders' Equity | |||||
Net proceeds from issuance of common units - Viper Energy Partners LP | 232,198 | $ 0 | 0 | 0 | 232,198 |
Unit-based compensation | 2,102 | 0 | 0 | 0 | 2,102 |
Distribution to noncontrolling interest | (2,314) | 0 | 0 | 0 | (2,314) |
Stock-based compensation | 12,152 | 0 | 12,152 | 0 | 0 |
Tax benefits related to stock-based compensation | (749) | 0 | (749) | 0 | 0 |
Common shares issued in public offering, net of offering costs | 689,482 | $ 92 | 689,390 | 0 | 0 |
Common shares issued in public offering, net of offering costs, shares | 9,200,000 | ||||
Exercise of stock options and awards of restricted stock | 7,080 | $ 5 | 7,075 | 0 | 0 |
Exercise of stock options and awards of restricted stock, shares | 518,000 | ||||
Equity payment - Wexford Advisory Services | $ 3,750 | $ 1 | 3,749 | 0 | 0 |
Equity payment - Wexford Advisory Services, shares | 64,000 | ||||
Net income (loss) | $ 195,971 | 0 | 0 | 193,755 | 2,216 |
Balance at end of period at Dec. 31, 2014 | $ 1,985,213 | $ 569 | 1,554,174 | 196,268 | 234,202 |
Balance at end of period, shares at Dec. 31, 2014 | 56,887,583 | 56,888,000 | |||
Increase (Decrease) in Stockholders' Equity | |||||
Unit-based compensation | $ 3,929 | $ 0 | 0 | 0 | 3,929 |
Distribution to noncontrolling interest | (7,968) | 0 | 0 | 0 | (7,968) |
Stock-based compensation | 20,645 | 0 | 20,645 | 0 | 0 |
Common shares issued in public offering, net of offering costs | 650,073 | $ 94 | 649,979 | 0 | 0 |
Common shares issued in public offering, net of offering costs, shares | 9,488,000 | ||||
Exercise of stock options and awards of restricted stock | 4,871 | $ 5 | 4,866 | 0 | 0 |
Exercise of stock options and awards of restricted stock, shares | 421,000 | ||||
Net income (loss) | (547,790) | $ 0 | 0 | (550,628) | 2,838 |
Balance at end of period at Dec. 31, 2015 | $ 2,108,973 | $ 668 | $ 2,229,664 | $ (354,360) | $ 233,001 |
Balance at end of period, shares at Dec. 31, 2015 | 66,797,041 | 66,797,000 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Cash flows from operating activities: | |||
Net income (loss) | $ (547,790) | $ 195,971 | $ 54,587 |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||
Provision for (benefit from) deferred income taxes | (201,545) | 108,985 | 31,563 |
Excess tax benefit from stock-based compensation | 0 | 0 | (749) |
Impairment of oil and natural gas properties | 814,798 | 0 | 0 |
Asset retirement obligation accretion expense | 833 | 467 | 201 |
Depreciation, depletion, and amortization | 217,697 | 170,005 | 66,597 |
Amortization of debt issuance costs | 2,601 | 2,125 | 1,018 |
Change in fair value of derivative instruments | 112,918 | (117,109) | (5,346) |
Equity-based compensation expense | 18,529 | 9,816 | 1,752 |
(Gain) loss on sale of assets, net | 668 | 1,396 | (39) |
Changes in operating assets and liabilities: | |||
Accounts receivable | 8,998 | (39,442) | (19,973) |
Accounts receivable-related party | 2,149 | (2,699) | (532) |
Restricted cash | 0 | (500) | 0 |
Inventories | 224 | 915 | 554 |
Prepaid expenses and other | (1,310) | (4,601) | (271) |
Accounts payable and accrued liabilities | 802 | 6,829 | 20,588 |
Accounts payable and accrued liabilities-related party | 218 | (17) | (128) |
Accrued interest | (255) | 3,473 | 0 |
Revenues and royalties payable | (13,034) | 20,775 | 5,955 |
Net cash provided by operating activities | 416,501 | 356,389 | 155,777 |
Cash flows from investing activities: | |||
Additions to oil and natural gas properties-related party | (419,241) | (494,708) | (278,809) |
Additions to oil and natural gas properties-related party | (271) | (3,631) | (13,777) |
Acquisition of Gulfport properties | 0 | 0 | (18,550) |
Acquisition of royalty interests | (43,907) | (57,689) | (444,083) |
Acquisition of leasehold interests | (437,455) | (845,826) | (177,343) |
Pipeline and gas gathering assets | 0 | (1,509) | (5,127) |
Purchase of other property and equipment | (1,213) | (44,213) | (2,234) |
Proceeds from sale of assets | 9,739 | 56 | 72 |
Equity investments | (2,702) | (34,477) | 0 |
Settlement of non-hedge derivative instruments | 0 | 0 | (289) |
Net cash used in investing activities | (895,050) | (1,481,997) | (940,140) |
Cash flows from financing activities: | |||
Proceeds from borrowings on credit facility | 425,001 | 509,400 | 59,000 |
Repayment on credit facility | (603,001) | (295,900) | (49,000) |
Proceeds from senior notes | 0 | 0 | 450,000 |
Debt issuance costs | (526) | (3,469) | (12,361) |
Public offering costs | (586) | (2,994) | (1,009) |
Proceeds from public offerings | 650,688 | 928,432 | 322,680 |
Exercise of stock options | 4,873 | 7,081 | 3,501 |
Excess tax benefits of stock-based compensation | 0 | 0 | 749 |
Distribution to non-controlling interest | (7,968) | (2,314) | 0 |
Net cash provided by financing activities | 468,481 | 1,140,236 | 773,560 |
Net increase (decrease) in cash and cash equivalents | (10,068) | 14,628 | (10,803) |
Cash and cash equivalents at beginning of period | 30,183 | 15,555 | 26,358 |
Cash and cash equivalents at end of period | 20,115 | 30,183 | 15,555 |
Supplemental disclosure of cash flow information: | |||
Interest paid, net of capitalized interest | 38,758 | 31,621 | 404 |
Cash paid for income taxes | 267 | 0 | 0 |
Supplemental disclosure of non-cash transactions: | |||
Asset retirement obligation incurred | 594 | 703 | 226 |
Asset retirement obligation revisions in estimated liability | (69) | 588 | 0 |
Asset retirement obligation acquired | 3,159 | 3,726 | 471 |
Change in accrued capital expenditures | (69,460) | 54,748 | 45,252 |
Capitalized stock-based compensation | $ 6,043 | $ 4,437 | $ 972 |
Description of the Business and
Description of the Business and Basis of Presentation | 12 Months Ended |
Dec. 31, 2015 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Description of the Business and Basis of Presentation | DESCRIPTION OF THE BUSINESS AND BASIS OF PRESENTATION Organization and Description of the Business Diamondback Energy, Inc. (“Diamondback” or the “Company”) is an independent oil and gas company focused on the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves in the Permian Basin in West Texas. Diamondback was incorporated in Delaware on December 30, 2011. On June 17, 2014, Diamondback entered into a contribution agreement with Viper Energy Partners LP (the “Partnership”), Viper Energy Partners GP LLC (the “General Partner”) and Viper Energy Partners LLC to transfer Diamondback’s ownership interest in Viper Energy Partners LLC to the Partnership in exchange for 70,450,000 common units. Diamondback also owns and controls the General Partner, which holds a non-economic general partner interest in the Partnership. On June 23, 2014, the Partnership completed its initial public offering (the “Viper Offering”) of 5,750,000 common units, and the Company’s common units represented an approximate 92% limited partner interest in the Partnership. On September 19, 2014, the Partnership completed an underwritten public offering of 3,500,000 common units. At the completion of this offering, the Company owned approximately 88% of the common units of the Partnership. See Note 4 –Viper Energy Partners LP for additional information regarding the Partnership. The wholly-owned subsidiaries of Diamondback, as of December 31, 2015 , include Diamondback E&P LLC, a Delaware limited liability company, Diamondback O&G LLC, a Delaware limited liability company, Viper Energy Partners GP LLC, a Delaware limited liability company, and White Fang Energy LLC, a Delaware limited liability company. The consolidated subsidiaries include the wholly-owned subsidiaries as well as Viper Energy Partners LP, a Delaware limited partnership, and Viper Energy Partners LLC, a Delaware limited liability company. Basis of Presentation The consolidated financial statements include the accounts of the Company and its subsidiaries after all significant intercompany balances and transactions have been eliminated upon consolidation. The Partnership is consolidated in the financial statements of the Company. As of December 31, 2015 , the Company owned approximately 88% of the common units of the Partnership and the Company’s wholly owned subsidiary, Viper Energy Partners GP LLC, is the General Partner of the Partnership. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2015 | |
Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Use of Estimates Certain amounts included in or affecting the Company’s consolidated financial statements and related disclosures must be estimated by management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the consolidated financial statements are prepared. These estimates and assumptions affect the amounts the Company reports for assets and liabilities and the Company’s disclosure of contingent assets and liabilities at the date of the consolidated financial statements. Actual results could differ from those estimates. The Company evaluates these estimates on an ongoing basis, using historical experience, consultation with experts and other methods the Company considers reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from the Company’s estimates. Any effects on the Company’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include estimates of proved oil and natural gas reserves and related present value estimates of future net cash flows therefrom, the carrying value of oil and natural gas properties, asset retirement obligations, the fair value determination of acquired assets and liabilities, equity-based compensation, fair value estimates of commodity derivatives and estimates of income taxes. Cash and Cash Equivalents The Company considers all highly liquid investments purchased with a maturity of three months or less and money market funds to be cash equivalents. The Company maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Company has not experienced any significant losses from such investments. Restricted Cash A subsidiary of the Company entered into an agreement to purchase certain overriding royalty interests and deposited $0.5 million in escrow. The agreement provided that the subsidiary would have the right to terminate the agreement and receive a return of the deposit if the subsidiary in good faith asserted title defects in excess of a certain amount. The subsidiary asserted title defects in excess of the amount and requested that the escrow agent return the deposit. The seller provided the escrow agent with notice alleging the subsidiary did not timely assert the defects in good faith. The escrow agent tendered the deposit to the court subject to a judicial determination of the proper payment of the funds. Accounts Receivable Accounts receivable consist of receivables from joint interest owners on properties the Company operates and from sales of oil and natural gas production delivered to purchasers. The purchasers remit payment for production directly to the Company. Most payments are received within three months after the production date. Accounts receivable are stated at amounts due from joint interest owners or purchasers, net of an allowance for doubtful accounts when the Company believes collection is doubtful. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. Accounts receivable outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance by considering a number of factors, including the length of time accounts receivable are past due, the Company’s previous loss history, the debtor’s current ability to pay its obligation to the Company, the condition of the general economy and the industry as a whole. The Company writes off specific accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful accounts. No allowance was deemed necessary at December 31, 2015 or December 31, 2014 . Derivative Instruments The Company is required to recognize its derivative instruments on the consolidated balance sheets as assets or liabilities at fair value with such amounts classified as current or long-term based on their anticipated settlement dates. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the cash and non-cash change in fair value on derivative instruments in the consolidated statements of operations. Fair Value of Financial Instruments The Company’s financial instruments consist of cash and cash equivalents, restricted cash, receivables, payables, derivatives, notes payable and senior notes. The carrying amount of cash and cash equivalents, receivables and payables approximates fair value because of the short-term nature of the instruments. The fair value of the revolving credit facility approximates its carrying value based on the borrowing rates currently available to the Company for bank loans with similar terms and maturities. The note payable is carried at cost, which approximates fair value due to the nature of the instrument and relatively short maturity. The fair value of the senior notes are determined using quoted market prices. Derivatives are recorded at fair value (see Note 14 –Fair Value Measurements). Oil and Natural Gas Properties The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain internal costs, are capitalized and amortized on a composite unit of production method based on proved oil, natural gas liquids and natural gas reserves. Internal costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. All internal costs not directly associated with exploration and development activities were charged to expense as they were incurred. Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, natural gas liquids and natural gas. Any income from services provided by subsidiaries to working interest owners of properties in which the Company also owns an interest, to the extent they exceed related costs incurred, are accounted for as reductions of capitalized costs of oil and natural gas properties proportionate to the Company’s investment in the subsidiary (see Note 7 –Equity Method Investments). Depletion of evaluated oil and natural gas properties is computed on the units of production method, whereby capitalized costs plus estimated future development costs are amortized over total proved reserves. The average depletion rate per barrel equivalent unit of production was $17.84 , $23.79 and $24.63 for the years ended December 31, 2015 , 2014 and 2013 , respectively. Depreciation, depletion and amortization expense for oil and natural gas properties was $216.1 million , $168.7 million and $65.8 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. Under this method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the proved oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes, or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the trailing 12-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions, and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or non-cash writedown is required. During the year ended December 31, 2015 , the Company recorded an impairment on proved oil and natural gas properties of $814.8 million . No impairment on proved oil and natural gas properties was recorded for the years ended December 31, 2014 and 2013 , respectively. Costs associated with unevaluated properties are excluded from the full cost pool until the Company has made a determination as to the existence of proved reserves. The Company assesses all items classified as unevaluated property on an annual basis for possible impairment. The Company assesses properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization. Other Property and Equipment Other property and equipment is recorded at cost. The Company expenses maintenance and repairs in the period incurred. Upon retirements or disposition of assets, the cost and related accumulated depreciation are removed from the consolidated balance sheet with the resulting gains or losses, if any, reflected in operations. Depreciation of other property and equipment is computed using the straight line method over their estimated useful lives, which range from three to fifteen years. Depreciation expense for other property and equipment was $1.6 million , $1.3 million and $0.8 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. Asset Retirement Obligations The Company measures the future cost to retire its tangible long-lived assets and recognizes such cost as a liability for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction or normal operation of a long-lived asset. The Company records a liability relating to the retirement and removal of all assets used in their businesses. Asset retirement obligations represent the future abandonment costs of tangible assets, namely wells. The fair value of a liability for an asset’s retirement obligation is recorded in the period in which it is incurred if a reasonable estimate of fair value can be made and the corresponding cost is capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, the difference is recorded in oil and natural gas properties. Impairment of Long-Lived Assets Other property and equipment used in operations are reviewed whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. An impairment loss is recognized only if the carrying amount of a long-lived asset is not recoverable from its estimated future undiscounted cash flows. An impairment loss is the difference between the carrying amount and fair value of the asset. The Company had no such impairment losses for the years ended December 31, 2015 , 2014 and 2013 , respectively. Capitalized Interest The Company capitalizes interest on expenditures made in connection with exploration and development projects that are not subject to current amortization. Interest is capitalized only for the period that activities are in progress to bring these projects to their intended use. Capitalized interest cannot exceed gross interest expense. The Company capitalized interest of $5.3 million and $4.0 million amounts for the years ended December 31, 2014 and 2013 , respectively. The Company did no t have any capitalized interest for the year ended December 31, 2015 . Inventories Inventories are stated at the lower of cost or market and consist of tubular goods and equipment at December 31, 2015 and 2014 . The Company’s tubular goods and equipment are primarily comprised of oil and natural gas drilling or repair items such as tubing, casing and pumping units. The inventory is primarily acquired for use in future drilling or repair operations and is carried at lower of cost or market. “Market”, in the context of inventory valuation, represents net realizable value, which is the amount that the Company is allowed to bill to the joint accounts under joint operating agreements to which the Company is a party. As of December 31, 2015 , the Company estimated that all of its tubular goods and equipment will be utilized within one year. Debt Issuance Costs Other assets included capitalized costs of $18.2 million and $13.8 million , net of accumulated amortization of $6.5 million and $3.9 million , as of December 31, 2015 and 2014 , respectively. The costs associated with the Senior Notes are being amortized over the term of the Senior Notes using the effective interest method. The costs associated with the Company’s credit facility are being amortized over the term of the facility. Other Accrued Liabilities Other accrued liabilities consist of the following: December 31, 2015 2014 (In thousands) Prepaid drilling liability $ 12,683 $ 3,758 Interest payable 8,606 8,861 Lease operating expense payable 14,100 11,851 Taxes payable 518 9,952 Current portion of asset retirement obligations 193 39 Other 8,193 6,688 Total other accrued liabilities $ 44,293 $ 41,149 Revenue and Royalties Payable For certain oil and natural gas properties, where the Company serves as operator, the Company receives production proceeds from the purchaser and further distributes such amounts to other revenue and royalty owners. Production proceeds applicable to other revenue and royalty owners are reflected as revenue and royalties payable in the accompanying consolidated balance sheets. The Company recognizes revenue for only its net revenue interest in oil and natural gas properties. Revenue Recognition Oil and natural gas revenues are recorded when title passes to the purchaser, net of royalty interests, discounts and allowances, as applicable. The Company accounts for oil and natural gas production imbalances using the sales method, whereby a liability is recorded when the Company’s overtake volumes exceed its estimated remaining recoverable reserves. No receivables are recorded for those wells where the Company has taken less than its ownership share of production. The Company did not have any gas imbalances as of December 31, 2015 or December 31, 2014 . Revenues from oil and natural gas services are recognized as services are provided. Investments Equity investments in which the Company exercises significant influence but does not control are accounted for using the equity method. Under the equity method, generally the Company’s share of investees’ earnings or loss is recognized in the statement of operations. The Company reviews its investments to determine if a loss in value which is other than a temporary decline has occurred. If such loss has occurred, the Company would recognize an impairment provision. There was no impairment for the Company’s equity investments for the years ended December 31, 2015 , 2014 and 2013 . For additional information on the Company’s investments, see Note 7 –Equity Method Investments. Accounting for Equity-Based Compensation The Company grants various types of stock-based awards including stock options and restricted stock units. These plans and related accounting policies are defined and described more fully in Note 10 –Equity-Based Compensation. Stock compensation awards are measured at fair value on the date of grant and are expensed, net of estimated forfeitures, over the required service period. Concentrations The Company is subject to risk resulting from the concentration of its crude oil and natural gas sales and receivables with several significant purchasers. For the year ended December 31, 2015 , two purchasers accounted for more than 10% of our revenue: Shell Trading (US) Company ( 59% ); and Enterprise Crude Oil LLC ( 15% ). For the year ended December 31, 2014 , two purchasers accounted for more than 10% of our revenue: Shell Trading (US) Company ( 64% ); and Enterprise Crude Oil LLC ( 16% ). For the year ended December 31, 2013 , two purchasers each accounted for more than 10% of our revenue: Plains Marketing, L.P. ( 37% ); and Shell Trading (US) Company ( 37% ). The Company does not require collateral and does not believe the loss of any single purchaser would materially impact its operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers. Environmental Compliance and Remediation Environmental compliance and remediation costs, including ongoing maintenance and monitoring, are expensed as incurred. Liabilities are accrued when environmental assessments and remediation are probable, and the costs can be reasonably estimated. Income Taxes Diamondback uses the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized. The Company is subject to margin tax in the state of Texas. During the years ended December 31, 2015 , 2014 and 2013 , there was no margin tax expense. The Company’s 2011 , 2012 , 2013 , 2014 and 2015 federal income tax and state margin tax returns remain open to examination by tax authorities. As of December 31, 2015 and December 31, 2014 , the Company had no unrecognized tax benefits that would have a material impact on the effective rate. The Company is continuing its practice of recognizing interest and penalties related to income tax matters as interest expense and general and administrative expenses, respectively. During the years ended December 31, 2015 , 2014 and 2013 , there was no interest or penalties associated with uncertain tax positions recognized in the Company’s consolidated financial statements. Recent Accounting Pronouncements In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update 2014-09, “Revenue from Contracts with Customers”. This update supersedes most of the existing revenue recognition requirements in GAAP and requires (i) an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goods or services and (ii) requires expanded disclosures regarding the nature, amount, timing, and certainty of revenue and cash flows from contracts with customers. The standard will be effective for annual and interim reporting periods beginning after December 15, 2017, with early application not permitted. The standard allows for either full retrospective adoption, meaning the standard is applied to all periods presented in the financial statements, or modified retrospective adoption, meaning the standard is applied only to the most current period presented. The Company is currently evaluating the impact, if any, that the adoption of this update will have on the Company’s financial position, results of operations and liquidity. In April 2015, the Financial Accounting Standards Board issued Accounting Standards Update 2015-03, “Interest–Imputation of Interest”. This update requires that debt issuance costs related to a recognized debt liability (except costs associated with revolving debt arrangements) be presented in the balance sheet as a direct deduction from that debt liability, consistent with the presentation of a debt discount to simplify the presentation of debt issuance costs. The standard will be effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within fiscal years beginning after December 15, 2016. Early application will be permitted for financial statements that have not previously been issued. Adoption of the new guidance will only affect the presentation of the Company’s consolidated balance sheets and will not have a material impact on its consolidated financial statements. In July 2015, the Financial Accounting Standards Board issued Accounting Standards Update 2015-11, “Inventory”. This update applies to all inventory that is not measured using last-in, first-out or the retail inventory method. Under this update, an entity should measure inventory at the lower of cost and net realizable value. This standard will be effective for financial statements issued for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. This standard should be applied prospectively with early adoption permitted as of the beginning of an interim or annual reporting period. The Company is currently evaluating the impact that the adoption of this update will have on the Company’s financial position, results of operations and liquidity. In November 2015, the Financial Accounting Standards Board issued Accounting Standards Update 2015-17, “Income Taxes”. This update requires that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. The standard will be effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early application will be permitted as of the beginning of an interim or annual reporting period. This standard may be applied either prospectively to all deferred tax liabilities and assets or retrospectively to all periods presented. Adoption of the new guidance will only affect the presentation of the Company’s consolidated balance sheets and will not have a material impact on its consolidated financial statements. |
Acquisitions
Acquisitions | 12 Months Ended |
Dec. 31, 2015 | |
Business Combinations [Abstract] | |
Acquisitions | ACQUISITIONS 2015 Activity Since January 1, 2015, the Company has completed acquisitions from unrelated third party sellers of an aggregate of approximately 16,940 gross ( 12,672 net) acres in the Midland Basin, primarily in northwest Howard County, for an aggregate purchase price of approximately $437.5 million , subject to certain adjustments. The acquisitions were accounted for according to the acquisition method, which requires the recording of net assets acquired and consideration transferred at fair value. These acquisitions were funded with the net proceeds of the May 2015 equity offering discussed in Note 9 –Capital Stock and Earnings Per Share and borrowings under the Company’s revolving credit facility discussed in Note 8 –Debt. On July 9, 2015, the Company completed the sale of an approximate average 1.5% overriding royalty interest in certain of its acreage primarily located in Howard County, Texas to the Partnership for $31.1 million . The Partnership primarily funded this acquisition with borrowings under its revolving credit facility discussed in Note 8 – Debt. 2014 Activity On September 9, 2014, the Company completed the acquisition of oil and natural gas interests in the Permian Basin from unrelated third party sellers. The Company acquired approximately 17,617 gross ( 12,967 net) acres with an approximate 74% working interest (approximately 75% net revenue interest). The acquisition was accounted for according to the acquisition method, which requires the recording of net assets acquired and consideration transferred at fair value. This acquisition was funded with the net proceeds of the July 2014 equity offering and borrowings under the Company’s revolving credit facility discussed in Note 8 –Debt. The following represents the estimated fair values of the assets and liabilities assumed on the acquisition date. The aggregate consideration transferred was $523.3 million in cash, subject to post-closing adjustments, resulting in no goodwill or bargain purchase gain. (in thousands) Joint interest receivables $ 42 Proved oil and natural gas properties 128,589 Unevaluated oil and natural gas properties 400,527 Total assets acquired 529,158 Accrued production and ad valorem taxes 358 Revenues payable 3,174 Asset retirement obligations 2,366 Total liabilities assumed 5,898 Total fair value of net assets $ 523,260 The Company has included in its consolidated statements of operations revenues of $12.3 million and direct operating expenses of $4.6 million for the period from September 9, 2014 to December 31, 2014 due to the acquisition. The disclosure of net earnings is impracticable to calculate due to the full cost method of depletion. On August 25, 2014, the Company completed an acquisition of surface rights in the Permian Basin from an unrelated third party seller. The Company acquired surface rights to approximately 4,200 acres for approximately $41.9 million . On February 27 and 28, 2014, the Company completed acquisitions of oil and natural gas interests in the Permian Basin from unrelated third party sellers. The Company acquired approximately 6,450 gross ( 4,785 net) acres with a 74% working interest ( 56% net revenue interest). The acquisitions were accounted for according to the acquisition method, which requires the recording of net assets acquired and consideration transferred at fair value. These acquisitions were funded with the net proceeds of the February 2014 equity offering and borrowings under the Company’s revolving credit facility discussed in Note 8 –Debt. The following represents the estimated fair values of the assets and liabilities assumed on the acquisition dates. The aggregate consideration transferred was $292.2 million in cash, subject to post-closing adjustments, resulting in no goodwill or bargain purchase gain. (in thousands) Proved oil and natural gas properties $ 170,174 Unevaluated oil and natural gas properties 123,243 Total assets acquired 293,417 Asset retirement obligations 1,258 Total liabilities assumed 1,258 Total fair value of net assets $ 292,159 The Company has included in its consolidated statements of operations revenues of $40.5 million and direct operating expenses of $7.8 million for the period from February 28, 2014 to December 31, 2014 due to the acquisitions. The disclosure of net earnings is impracticable to calculate due to the full cost method of depletion. During the year ended December 31, 2014, the Partnership acquired (i) mineral interests underlying an aggregate of approximately 10,364 gross ( 3,261 net) acres in the Midland and Delaware basins for approximately $57.7 million and (ii) a minor equity interest in an entity that owns mineral, overriding royalty, net profits, leasehold and other similar interests for approximately $33.9 million . The equity interest is so minor that we have no influence over partnership operating and financial policies and is accounted for under the cost method. Pro Forma Financial Information The following unaudited summary pro forma consolidated statement of operations data of Diamondback for the years ended December 31, 2014 and 2013 have been prepared to give effect to the February 27 and 28, 2014 acquisitions and the September 9, 2014 acquisition as if they had occurred on January 1, 2013. The pro forma data are not necessarily indicative of financial results that would have been attained had the acquisitions occurred on January 1, 2013. The pro forma data also necessarily exclude various operation expenses related to the properties and the financial statements should not be viewed as indicative of operations in future periods. Pro Forma (Unaudited) Year Ended December 31, 2014 2013 (in thousands) Revenues $ 541,103 $ 315,736 Income from operations 224,382 146,429 Net income 201,257 86,277 2013 Activity In September 2013, the Company completed two separate acquisitions of additional leasehold interests in the Permian Basin from unrelated third party sellers for an aggregate purchase price of $165.0 million , subject to certain adjustments. The first of these acquisitions closed on September 4, 2013 when the Company acquired certain assets located in northwestern Martin County, Texas, consisting of a 100% working interest ( 80% net revenue interest) in 4,506 gross and net acres. The second of these acquisitions closed on September 26, 2013, when the Company acquired certain assets located primarily in southwestern Dawson County, Texas, consisting of a 71% working interest ( 55% net revenue interest) in 9,390 gross ( 6,638 net) acres. These acquisitions were funded with a portion of the net proceeds from the August 2013 equity offering discussed in Note 9 –Capital Stock and Earnings Per Share. On September 19, 2013, the Company completed the acquisition of the mineral interests underlying approximately 14,804 gross ( 12,687 net) acres in Midland County, Texas in the Permian Basin. As part of the closing of the acquisition, the mineral interests were conveyed from the previous owners to Viper Energy Partners LLC and, subsequently, were contributed to the Partnership on June 17, 2014. See Note 4 – Viper Energy Partners LP for additional information regarding the Partnership. The mineral interests entitle the holder of such interests to receive a 21.4% royalty interest on all production on an acreage weighted basis from this acreage with no additional future capital or operating expense required. The $440.0 million purchase price was funded with the net proceeds of the Company’s offering of Senior Notes discussed in Note 8 –Debt. |
Property and Equipment
Property and Equipment | 12 Months Ended |
Dec. 31, 2015 | |
Property, Plant and Equipment [Abstract] | |
Property and Equipment | PROPERTY AND EQUIPMENT Property and equipment includes the following: December 31, 2015 2014 (in thousands) Oil and natural gas properties: Subject to depletion $ 2,848,557 $ 2,345,077 Not subject to depletion-acquisition costs Incurred in 2015 433,769 — Incurred in 2014 543,399 576,802 Incurred in 2013 68,351 130,474 Incurred in 2012 61,297 65,480 Incurred in 2011 — 764 Total not subject to depletion 1,106,816 773,520 Gross oil and natural gas properties 3,955,373 3,118,597 Accumulated depletion (512,144 ) (296,317 ) Accumulated impairment (897,962 ) (83,164 ) Oil and natural gas properties, net 2,545,267 2,739,116 Pipeline and gas gathering assets, net 7,174 7,174 Other property and equipment, net 48,621 48,180 Accumulated depreciation (3,437 ) (2,663 ) Property and equipment, net of accumulated depreciation, depletion, amortization and impairment $ 2,597,625 $ 2,791,807 The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain internal costs, are capitalized and amortized on a composite unit of production method based on proved oil, natural gas liquids and natural gas reserves. Internal costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. All internal costs not directly associated with exploration and development activities were charged to expense as they were incurred. Capitalized internal costs were approximately $15.2 million $11.4 million and $5.3 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. Costs associated with unevaluated properties are excluded from the full cost pool until the Company has made a determination as to the existence of proved reserves. The inclusion of the Company’s unevaluated costs into the amortization base is expected to be completed within three to five years. Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, natural gas liquids and natural gas. Under this method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the proved oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes, or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the trailing 12-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions, and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or non-cash writedown is required. As a result of the significant decline in prices during 2015 , the Company recorded non-cash ceiling test impairments for the year ended December 31, 2015 of $814.8 million , which is included in accumulated depletion. The Company did not have any impairment of its proved oil and natural gas properties during 2014 . The impairment charge affected the Company’s reported net income but did not reduce its cash flow. In addition to commodity prices, the Company’s production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine its actual ceiling test calculation and impairment analysis in future periods. |
Viper Energy Partners LP
Viper Energy Partners LP | 12 Months Ended |
Dec. 31, 2015 | |
Noncontrolling Interest [Abstract] | |
Viper Energy Partners LP | VIPER ENERGY PARTNERS LP The Partnership is a publicly traded Delaware limited partnership, the common units of which are listed on the NASDAQ Global Market under the symbol “VNOM”. The Partnership was formed by Diamondback on February 27, 2014, to, among other things, own, acquire and exploit oil and natural gas properties in North America. The Partnership is currently focused on oil and natural gas properties in the Permian Basin. Viper Energy Partners GP LLC, a fully-consolidated subsidiary of Diamondback, serves as the general partner of, and holds a non-economic general partner interest in, the Partnership. As of December 31, 2015 , the Company owned approximately 88% of the common units of the Partnership. Prior to the completion on June 23, 2014 of the Viper Offering, Diamondback owned all of the general and limited partner interests in the Partnership. The Viper Offering consisted of 5,750,000 common units representing approximately 8% of the limited partner interests in the Partnership at a price to the public of $26.00 per common unit, which included 750,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters on the same terms. The Partnership received proceeds of approximately $137.2 million from the sale of these common units, net of offering expenses and underwriting discounts and commissions. In connection with the Viper Offering, Diamondback contributed all of the membership interests in Viper Energy Partners LLC to the Partnership in exchange for 70,450,000 common units. In addition, in connection with the closing of the Viper Offering, the Partnership agreed to distribute to Diamondback all cash and cash equivalents and the royalty income receivable on hand in the aggregate amount of approximately $11.3 million and the net proceeds from the Viper Offering. As of December 31, 2014 , the Partnership had distributed $148.8 million to Diamondback and the Partnership recorded a payable balance of approximately $11.3 million . The contribution of Viper Energy Partners LLC to the Partnership was accounted for as a combination of entities under common control with assets and liabilities transferred at their carrying amounts in a manner similar to a pooling of interests. During the year ended December 31, 2015 , the Partnership distributed $60.6 million to Diamondback in respect of its common units. On September 19, 2014, the Partnership completed an underwritten public offering of 3,500,000 common units. The common units were sold to the public at $28.50 per unit and the Partnership received proceeds of approximately $94.8 million from the sale of these common units, net of offering expenses and underwriting discounts and commissions. Partnership Agreement In connection with the closing of the Viper Offering, the General Partner and Diamondback entered into the first amended and restated agreement of limited partnership, dated as of June 23, 2014 (the “Partnership Agreement”). The Partnership Agreement requires the Partnership to reimburse the General Partner for all direct and indirect expenses incurred or paid on the Partnership’s behalf and all other expenses allocable to the Partnership or otherwise incurred by the General Partner in connection with operating the Partnership’s business. The Partnership Agreement does not set a limit on the amount of expenses for which the General Partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for the Partnership or on its behalf and expenses allocated to the General Partner by its affiliates. The General Partner is entitled to determine the expenses that are allocable to the Partnership. Tax Sharing In connection with the closing of the Viper Offering, the Partnership entered into a tax sharing agreement with Diamondback, dated June 23, 2014, pursuant to which the Partnership agreed to reimburse Diamondback for its share of state and local income and other taxes for which the Partnership’s results are included in a consolidated tax return filed by Diamondback with respect to taxable periods including or beginning on June 23, 2014. The amount of any such reimbursement is limited to the tax the Partnership would have paid had it not been included in a combined group with Diamondback. Diamondback may use its tax attributes to cause its consolidated group, of which the Partnership may be a member for this purpose, to owe less or no tax. In such a situation, the Partnership agreed to reimburse Diamondback for the tax the Partnership would have owed had the tax attributes not been available or used for the Partnership’s benefit, even though Diamondback had no cash tax expense for that period. Other Agreements See Note 11 –Related Party Transactions for information regarding the advisory services agreement the Partnership and the General Partner entered into with Wexford Capital LP (“Wexford”). The Partnership has entered into a secured revolving credit facility with Wells Fargo Bank, National Association, (“Wells Fargo”) as administrative agent sole book runner and lead arranger. See Note 8 –Debt for a description of this credit facility. |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2015 | |
Asset Retirement Obligation [Abstract] | |
Asset Retirement Obligations | ASSET RETIREMENT OBLIGATIONS The following table describes the changes to the Company’s asset retirement obligation liability for the following periods: Year Ended December 31, 2015 2014 2013 (in thousands) Asset retirement obligation, beginning of period $ 8,486 $ 3,029 $ 2,145 Additional liability incurred 594 703 226 Liabilities acquired 3,159 3,726 471 Liabilities settled (292 ) (27 ) (14 ) Accretion expense 833 467 201 Revisions in estimated liabilities (69 ) 588 — Asset retirement obligation, end of period 12,711 8,486 3,029 Less current portion 193 39 40 Asset retirement obligations - long-term $ 12,518 $ 8,447 $ 2,989 The Company’s asset retirement obligations primarily relate to the future plugging and abandonment of wells and related facilities. The Company estimates the future plugging and abandonment costs of wells, the ultimate productive life of the properties, a risk-adjusted discount rate and an inflation factor in order to determine the current present value of this obligation. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to the oil and natural gas property balance. |
Equity Method Investments
Equity Method Investments | 12 Months Ended |
Dec. 31, 2015 | |
Equity Method Investments and Joint Ventures [Abstract] | |
Equity Method Investments | EQUITY METHOD INVESTMENTS In October 2014, the Company paid $0.6 million for a 25% in HMW Fluid Management LLC, which was formed to develop, own and operate an integrated water management system to gather, store, process, treat, distribute and dispose of water to exploration and production companies operating in Midland, Martin and Andrews Counties, Texas. The board of this entity may also authorize the entity to offer these services to other counties in the Permian Basin and to pursue other business opportunities. The Company has committed to invest an aggregate amount of $5.0 million in this entity, and several other third parties have committed to invest an aggregate of $15.0 million . For the year ended December 31, 2015 , the Company invested an additional $2.7 million in this entity. The Company will retain a minority interest after all commitments are received. The entity was formed as a limited liability company and maintains a specific ownership account for each investor, similar to a partnership capital account structure. Therefore, the Company accounts for this investment under the equity method of accounting. |
Debt
Debt | 12 Months Ended |
Dec. 31, 2015 | |
Debt Disclosure [Abstract] | |
Debt | DEBT Long-term debt consisted of the following as of the dates indicated: December 31, 2015 2014 (in thousands) 7.625 % Senior Notes due 2021 $ 450,000 $ 450,000 Revolving credit facility $ 11,000 $ 223,500 Partnership revolving credit facility 34,500 — Total long-term debt $ 495,500 $ 673,500 Senior Notes On September 18, 2013, the Company completed an offering of $450.0 million in aggregate principal amount of 7.625% senior unsecured notes due 2021 (the “Senior Notes”). The Senior Notes bear interest at the rate of 7.625% per annum, payable semi-annually, in arrears on April 1 and October 1 of each year, commencing on April 1, 2014 and will mature on October 1, 2021. On June 23, 2014, in connection with the Viper Offering, the Company designated the Partnership, the General Partner and Viper Energy Partners LLC as unrestricted subsidiaries and, upon such designation, Viper Energy Partners LLC, which was a guarantor under the indenture governing of the Senior Notes, was released as a guarantor under the indenture. As of December 31, 2015 , the Senior Notes were fully and unconditionally guaranteed by Diamondback O&G LLC, Diamondback E&P LLC and White Fang Energy LLC and will also be guaranteed by any future restricted subsidiaries of Diamondback. The net proceeds from the Senior Notes were used to fund the acquisition of mineral interests underlying approximately 14,804 gross ( 12,687 net) acres in Midland County, Texas in the Permian Basin. The Senior Notes were issued under, and are governed by, an indenture among the Company, the subsidiary guarantors party thereto and Wells Fargo, as the trustee, as supplemented (the “Indenture”). The Indenture contains certain covenants that, subject to certain exceptions and qualifications, among other things, limit the Company’s ability and the ability of the restricted subsidiaries to incur or guarantee additional indebtedness, make certain investments, declare or pay dividends or make other distributions on, or redeem or repurchase, capital stock, prepay subordinated indebtedness, sell assets including capital stock of subsidiaries, agree to payment restrictions affecting the Company’s restricted subsidiaries, consolidate, merge, sell or otherwise dispose of all or substantially all of its assets, enter into transactions with affiliates, incur liens, engage in business other than the oil and gas business and designate certain of the Company’s subsidiaries as unrestricted subsidiaries. If the Company experiences certain kinds of changes of control or if it sells certain of its assets, holders of the Senior Notes may have the right to require the Company to repurchase their Senior Notes. The Company will have the option to redeem the Senior Notes, in whole or in part, at any time on or after October 1, 2016 at the redemption prices (expressed as percentages of principal amount) of 105.719% for the 12-month period beginning on October 1, 2016, 103.813% for the 12-month period beginning on October 1, 2017, 101.906% for the 12-month period beginning on October 1, 2018 and 100.000% beginning on October 1, 2019 and at any time thereafter with any accrued and unpaid interest to, but not including, the date of redemption. In addition, prior to October 1, 2016, the Company may redeem all or a part of the Senior Notes at a price equal to 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date, plus a “make-whole” premium at the redemption date. Furthermore, before October 1, 2016, the Company may, at any time or from time to time, redeem up to 35% of the aggregate principal amount of the Senior Notes with the net cash proceeds of certain equity offerings at a redemption price of 107.625% of the principal amount of the Senior Notes being redeemed plus any accrued and unpaid interest to the date of redemption, if at least 65% of the aggregate principal amount of the Senior Notes originally issued under the Indenture remains outstanding immediately after such redemption and the redemption occurs within 120 days of the closing date of such equity offering. In connection with the issuance of the Senior Notes, the Company and the subsidiary guarantors entered into a Registration Rights Agreement (the “Registration Rights Agreement”) with the initial purchasers on September 18, 2013, pursuant to which the Company and the subsidiary guarantors agreed to file a registration statement with respect to an offer to exchange the Senior Notes for a new issue of substantially identical debt securities registered under the Securities Act, which exchange offer completed on October 23, 2014. The Company’s Credit Facility On June 9, 2014, Diamondback O&G LLC, as borrower, entered into a first amendment and on November 13, 2014, Diamondback O&G LLC entered into a second amendment to the second amended and restated credit agreement, dated November 1, 2013 (the “credit agreement”). The first amendment modified certain provisions of the credit agreement to, among other things, allow one or more of the Company’s subsidiaries to be designated as “Unrestricted Subsidiaries” that are not subject to certain restrictions contained in the credit agreement. In connection with the Viper Offering, the Partnership, the General Partner and Viper Energy Partners LLC were designated as unrestricted subsidiaries under the credit agreement. As of December 31, 2015 , the credit agreement was guaranteed by Diamondback, Diamondback E&P LLC and White Fang Energy LLC and will also be guaranteed by any future restricted subsidiaries of Diamondback. The credit agreement is also secured by substantially all of the assets of Diamondback O&G LLC, the Company and the other guarantors. The second amendment increased the maximum amount of the credit facility to $2.0 billion , modified the dates and deadlines of the credit agreement relating to the scheduled borrowing base redeterminations based on the Company’s oil and natural gas reserves and other factors and added new provisions that allow the Company to elect a commitment amount that is less than its borrowing base as determined by the lenders. The borrowing base is scheduled to be re-determined semi-annually with effective dates of May 1st and November 1st. In addition, the Company may request up to three additional redeterminations of the borrowing base during any 12 -month period. As of December 31, 2015 , the borrowing base was set at $750.0 million , of which the Company had elected a commitment amount of $500.0 million , and the Company had outstanding borrowings of $11.0 million . The outstanding borrowings under the credit agreement bear interest at a rate elected by the Company that is equal to an alternative base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.5% and 3-month LIBOR plus 1.0% ) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.50% to 1.50% in the case of the alternative base rate and from 1.50% to 2.50% in the case of LIBOR, in each case depending on the amount of the loan outstanding in relation to the borrowing base. The Company is obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the borrowing base, which fee is also dependent on the amount of the loan outstanding in relation to the borrowing base. Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be repaid (a) to the extent that the loan amount exceeds the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period), (b) in an amount equal to the net cash proceeds from the sale of property when a borrowing base deficiency or event of default exists under the credit agreement and (c) at the maturity date of November 1, 2018. The credit agreement contains various affirmative, negative and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates and entering into certain swap agreements and require the maintenance of the financial ratios described below. Financial Covenant Required Ratio Ratio of total debt to EBITDAX Not greater than 4.0 to 1.0 Ratio of current assets to liabilities, as defined in the credit agreement Not less than 1.0 to 1.0 The covenant prohibiting additional indebtedness allows for the issuance of unsecured debt of up to $750.0 million in the form of senior or senior subordinated notes and, in connection with any such issuance, the reduction of the borrowing base by 25% of the stated principal amount of each such issuance. A borrowing base reduction in connection with such issuance may require a portion of the outstanding principal of the loan to be repaid. As of December 31, 2015 , the Company had $450.0 million of senior unsecured notes outstanding. As of December 31, 2015 and December 31, 2014 , the Company was in compliance with all financial covenants under its revolving credit facility, as then in effect. The lenders may accelerate all of the indebtedness under the Company’s revolving credit facility upon the occurrence and during the continuance of any event of default. The credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control. There are no cure periods for events of default due to non-payment of principal and breaches of negative and financial covenants, but non-payment of interest and breaches of certain affirmative covenants are subject to customary cure periods. The Partnership’s Credit Agreement On July 8, 2014, the Partnership entered into a secured revolving credit agreement with Wells Fargo, as the administrative agent, sole book runner and lead arranger. The credit agreement, which was amended August 15, 2014 to add additional lenders to the lending group, provides for a revolving credit facility in the maximum amount of $500.0 million , subject to scheduled semi-annual and other elective collateral borrowing base redeterminations based on the Partnership’s oil and natural gas reserves and other factors. The borrowing base is scheduled to be re-determined semi-annually with effective dates of April 1st and October 1st. In addition, the Partnership may request up to three additional redeterminations of the borrowing base during any 12 -month period. The credit agreement was further amended on May 22, 2015 to, among other things, increase the borrowing base from $110.0 million to $175.0 million and to provide for certain restrictions on purchasing margin stock. On November 13, 2015, the borrowing base was increased from $175.0 million to $200.0 million . As of December 31, 2015 , the borrowing base was set at $200.0 million . The Partnership had $34.5 million outstanding under its credit agreement. The outstanding borrowings under the credit agreement bear interest at a rate elected by the Partnership that is equal to an alternative base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.5% and 3-month LIBOR plus 1.0% ) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.5% to 1.50% in the case of the alternative base rate and from 1.50% to 2.50% in the case of LIBOR, in each case depending on the amount of the loan outstanding in relation to the borrowing base. The Partnership is obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the borrowing base, which fee is also dependent on the amount of the loan outstanding in relation to the borrowing base. Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be repaid (a) to the extent that the loan amount exceeds the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period) and (b) at the maturity date of July 8, 2019. The loan is secured by substantially all of the assets of the Partnership and its subsidiaries . The credit agreement contains various affirmative, negative and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, purchases of margin stock, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates and entering into certain swap agreements and require the maintenance of the financial ratios described below. Financial Covenant Required Ratio Ratio of total debt to EBITDAX Not greater than 4.0 to 1.0 Ratio of current assets to liabilities, as defined in the credit agreement Not less than 1.0 to 1.0 The covenant prohibiting additional indebtedness allows for the issuance of unsecured debt of up to $250.0 million in the form of senior unsecured notes and, in connection with any such issuance, the reduction of the borrowing base by 25% of the stated principal amount of each such issuance. A borrowing base reduction in connection with such issuance may require a portion of the outstanding principal of the loan to be repaid. The lenders may accelerate all of the indebtedness under the Partnership’s credit agreement upon the occurrence and during the continuance of any event of default. The Partnership’s credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control. There are no cure periods for events of default due to non-payment of principal and breaches of negative and financial covenants, but non-payment of interest and breaches of certain affirmative covenants are subject to customary cure periods. Interest expense The following amounts have been incurred and charged to interest expense for the years ended December 31, 2015 , 2014 and 2013 : Year Ended December 31, 2015 2014 2013 (in thousands) Interest expense $ 40,221 $ 36,669 $ 10,322 Less capitalized interest — (5,275 ) (3,951 ) Other fees and expenses 1,292 3,121 1,688 Total interest expense 41,513 34,515 8,059 |
Capital Stock and Earnings Per
Capital Stock and Earnings Per Share | 12 Months Ended |
Dec. 31, 2015 | |
Equity [Abstract] | |
Capital Stock and Earnings Per Share | CAPITAL STOCK AND EARNINGS PER SHARE As of December 31, 2015 , Diamondback had completed the following equity offerings since the closing of its initial public offering on October 17, 2012: In May 2013, the Company completed an underwritten primary public offering of 5,175,000 shares of common stock, which included 675,000 shares of common stock issued pursuant to an option to purchase additional shares granted to the underwriters. The stock was sold to the public at $29.25 per share and the Company received proceeds of approximately $144.4 million from the sale of these shares of common stock, net of offering expenses and underwriting discounts and commissions. In August 2013, the Company completed an underwritten public offering of 4,600,000 shares of common stock, which included 600,000 shares of common stock issued pursuant to an option to purchase additional shares granted to the underwriters. The stock was sold to the public at $40.25 per share and the Company received proceeds of approximately $177.5 million from the sale of these shares of common stock, net of offering expenses and underwriting discounts and commissions. In February 2014, the Company completed an underwritten public offering of 3,450,000 shares of common stock, which included 450,000 shares of common stock issued pursuant to an option to purchase additional shares granted to the underwriters. The stock was sold to the public at $62.67 per share and the Company received proceeds of approximately $208.4 million from the sale of these shares of common stock, net of offering expenses and underwriting discounts and commissions. In July 2014, the Company completed an underwritten public offering of 5,750,000 shares of common stock, which included 750,000 shares of common stock issued pursuant to an option to purchase additional shares granted to the underwriters. The stock was sold to the public at $87.00 per share and the Company received proceeds of approximately $485.0 million from the sale of these shares of common stock, net of offering expenses and underwriting discounts and commissions. In January 2015, the Company completed an underwritten public offering of 2,012,500 shares of common stock, which included 262,500 shares of common stock issued pursuant to an option to purchase additional shares granted to the underwriter. The stock was sold to the underwriter at $59.34 per share and the Company received proceeds of approximately $119.4 million from the sale of these shares of common stock, net of offering expenses and underwriting discounts and commissions. In May 2015, the Company completed an underwritten public offering of 4,600,000 shares of common stock, which included 600,000 shares of common stock issued pursuant to an option to purchase additional shares granted to the underwriter. The stock was sold to the underwriter at $72.53 per share and the Company received proceeds of approximately $333.6 million from the sale of these shares of common stock, net of offering expenses and underwriting discounts and commissions. In August 2015, the Company completed an underwritten public offering of 2,875,000 shares of common stock, which included 375,000 shares of common stock issued pursuant to an option to purchase additional shares granted to the underwriter. The stock was sold to the underwriter at $68.74 per share and the Company received proceeds of approximately $197.6 million from the sale of these shares of common stock, net of offering expenses and underwriting discounts and commissions. Earnings Per Share The Company’s basic earnings per share amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period. Diluted earnings per share include the effect of potentially dilutive shares outstanding for the period. Additionally, for the diluted earnings per share computation, the per share earnings of the Partnership are included in the consolidated earnings per share computation based on the consolidated group’s holdings of the subsidiary. A reconciliation of the components of basic and diluted earnings per common share is presented in the table below: 2015 Income Shares Per Share (in thousands, except per share amounts) Basic: Net income attributable to common stock $ (550,628 ) 63,019 $ (8.74 ) Effect of Dilutive Securities: Dilutive effect of potential common shares issuable $ — — Diluted: Net income attributable to common stock $ (550,628 ) 63,019 $ (8.74 ) 2014 Income Shares Per Share (in thousands, except per share amounts) Basic: Net income attributable to common stock $ 193,755 52,826 $ 3.67 Effect of Dilutive Securities: Dilutive effect of potential common shares issuable $ — 471 Diluted: Net income attributable to common stock $ 193,755 53,297 $ 3.64 2013 Income Shares Per Share (in thousands, except per share amounts) Basic: Net income attributable to common stock $ 54,587 42,015 $ 1.30 Effect of Dilutive Securities: Dilutive effect of potential common shares issuable $ — 240 Diluted: Net income attributable to common stock $ 54,587 42,255 $ 1.29 For the year ended December 31, 2015 , there were 100,924 shares that were not included in the computation of diluted earnings per share because their inclusion would have been anti-dilutive for the periods presented but could potentially dilute basic earnings per share in future periods. |
Equity-Based Compensation
Equity-Based Compensation | 12 Months Ended |
Dec. 31, 2015 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Stock and Unit Based Compensation | EQUITY-BASED COMPENSATION On October 10, 2012, the Board of Directors approved the Diamondback Energy, Inc. 2012 Equity Incentive Plan (the “2012 Plan”), which is intended to provide eligible employees with equity-based incentives. The 2012 Plan provides for the granting of incentive stock options, nonstatutory stock options, restricted awards (restricted stock and restricted stock units), performance awards, and stock appreciation rights, or any combination of the foregoing. A total of 2,500,000 shares of the Company’s common stock has been reserved for issuance pursuant to this plan. The following table presents the effects of the equity and stock based compensation plans and related costs: 2015 2014 2013 (In thousands) General and administrative expenses $ 18,529 $ 9,816 $ 1,752 Equity-based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties 6,043 4,437 972 Related income tax benefit — — 704 On June 17, 2014, in connection with the Viper Offering, the Board of Directors of the General Partner adopted the Viper Energy Partners LP Long Term Incentive Plan (“Viper LTIP”), effective June 17, 2014, for employees, officers, consultants and directors of the General Partner and any of its affiliates, including Diamondback, who perform services for the Partnership. The Viper LTIP provides for the grant of unit options, unit appreciation rights, restricted units, unit awards, phantom units, distribution equivalent rights, cash awards, performance awards, other unit-based awards and substitute awards. A total of 9,144,000 common units has been reserved for issuance pursuant to the Viper LTIP. Common units that are cancelled, forfeited or withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards. The Viper LTIP is administered by the Board of Directors of the General Partner or a committee thereof. Stock Options In accordance with the 2012 Plan, the exercise price of stock options granted may not be less than the market value of the stock at the date of grant. The shares issued under the 2012 Plan will consist of new shares of Company stock. Unless otherwise specified in an agreement, options become exercisable ratably over a five -year period. However, as described above, options associated with the modification vest in four substantially equal annual installments and are exercisable for five years from the date of grant. The fair value of the stock options on the date of grant is expensed over the applicable vesting period. The Company estimates the fair values of stock options granted using a Black-Scholes option valuation model, which requires the Company to make several assumptions. The Company does not have a long history of market prices, thus the expected volatility was determined using the historical volatility for a peer group of companies. The expected term of options granted was determined based on the contractual term of the awards and remaining vesting term at the modification date. The risk-free interest rate is based on the U.S. treasury yield curve rate for the expected term of the option at the date of grant. The Company does not anticipate paying cash dividends; therefore, the expected dividend yield was assumed to be zero. All such amounts represent the weighted-average amounts for each year. The following table presents a summary of the weighted average grant-date fair values and related assumptions for 2013 . No stock options were granted during the years ended December 31, 2015 and 2014 . 2013 Grant-date fair value $ 6.51 Expected volatility 36.9 % Expected dividend yield 0.0 % Expected term (in years) 3.8 Risk-free rate 0.57 % The following table presents the Company’s stock option activity under the Company’s 2012 Equity Incentive Plan (“2012 Plan”) for the year ended December 31, 2015 . Weighted Average Exercise Remaining Intrinsic Options Price Term Value (in years) (in thousands) Outstanding at December 31, 2014 313,105 $ 18.29 Exercised (273,605 ) $ 17.80 Outstanding at December 31, 2015 39,500 $ 21.66 1.83 $ 1,787 Vested and Expected to vest at December 31, 2015 39,500 $ 21.66 1.83 $ 1,787 Exercisable at December 31, 2015 8,000 $ 17.50 0.78 $ 395 The aggregate intrinsic value of stock options that were exercised during the year ended December 31, 2015 , 2014 and 2013 was $15.7 million , $22.0 million and $5.7 million , respectively. As of December 31, 2015 , the unrecognized compensation cost related to unvested stock options was $0.1 million . Such cost is expected to be recognized over a weighted-average period of 1.1 years. Restricted Stock Units Under the 2012 Plan, approved by the Board of Directors, the Company is authorized to issue restricted stock and restricted stock units to eligible employees. The Company estimates the fair values of restricted stock awards and units as the closing price of the Company’s common stock on the grant date of the award, which is expensed over the applicable vesting period. The following table presents the Company’s restricted stock units activity under the 2012 Plan during the year ended December 31, 2015 . Restricted Stock Weighted Average Grant-Date Unvested at December 31, 2014 167,291 $ 49.99 Granted 138,534 $ 68.54 Vested (143,956 ) $ 42.58 Forfeited (2,110 ) $ 74.14 Unvested at December 31, 2015 159,759 $ 64.66 The aggregate fair value of restricted stock units that vested during the year ended December 31, 2015 , 2014 and 2013 was $10.1 million , $8.2 million and $3.3 million , respectively. As of December 31, 2015 , the Company’s unrecognized compensation cost related to unvested restricted stock awards and units was $6.0 million . Such cost is expected to be recognized over a weighted-average period of 1.6 years. Performance-Based Restricted Stock Units To provide long-term incentives for the executive officers to deliver competitive returns to the Company’s stockholders, the Company has granted performance-based restricted stock units to eligible employees. The ultimate number of shares awarded from these conditional restricted stock units is based upon measurement of total stockholder return of the Company’s common stock (“TSR”) as compared to a designated peer group during a three -year performance period. In February 2014, eligible employees received initial performance restricted stock unit awards totaling 79,150 units from which a minimum of 0% and a maximum of 200% units could be awarded. The awards have a performance period of January 1, 2013 to December 31, 2015 and vested at December 31, 2015, subject to certification by the compensation committee that the performance standards were satisfied. In February 2015, eligible employees received additional performance restricted stock unit awards totaling 90,249 units from which a minimum of 0% and a maximum of 200% units could be awarded. The awards have a performance period of January 1, 2014 to December 31, 2016 and cliff vest at December 31, 2016. The fair value of each performance restricted stock unit is estimated at the date of grant using a Monte Carlo simulation, which results in an expected percentage of units to be earned during the performance period. The following table presents a summary of the grant-date fair values of performance restricted stock units granted and the related assumptions. 2015 2014 Grant-date fair value $ 137.14 $ 125.63 Risk-free rate 0.49 % 0.30 % Company volatility 43.36 % 39.60 % The following table presents the Company’s performance restricted stock units activity under the 2012 Plan for the year ended December 31, 2015 . Performance Restricted Stock Units Weighted Average Grant-Date Fair Value Unvested at December 31, 2014 79,150 $ 125.63 Granted 90,249 $ 137.14 Vested (79,150 ) $ 125.63 Unvested at December 31, 2015 (1) 90,249 $ 137.14 (1) A maximum of 180,498 units could be awarded based upon the Company’s final TSR ranking. As of December 31, 2015 , the Company’s unrecognized compensation cost related to unvested performance based restricted stock awards and units was $6.5 million . Such cost is expected to be recognized over a weighted-average period of 1.0 year. Partnership Unit Options In accordance with the Viper LTIP, the exercise price of unit options granted may not be less than the market value of the common units at the date of grant. The units issued under the Viper LTIP will consist of new common units of the Partnership. On June 17, 2014, the Board of Directors of the General Partner granted 2,500,000 unit options to the executive officers of the General Partner. The unit options vest approximately 33% ratably on each of the first three anniversaries of the date of grant or earlier upon a change of control (as defined in the Viper LTIP). Vested unit options will be automatically exercised upon the earlier of a change of control or the third anniversary of the grant date unless extended in accordance with the terms of the Viper LTIP (the “Exercise Date”). In the event the fair market value per unit as of the exercise date is less than the exercise price per option unit then the vested options will automatically terminate and become null and void as of the exercise date. The fair value of the unit options on the date of grant is expensed over the applicable vesting period. The Partnership estimates the fair values of unit options granted using a Black-Scholes option valuation model, which requires the Partnership to make several assumptions. At the time of grant the Partnership did not have a history of market prices, thus the expected volatility was determined using the historical volatility for a peer group of companies. The expected term of options granted was determined based on the contractual term of the awards. The risk-free interest rate is based on the U.S. treasury yield curve rate for the expected term of the unit option at the date of grant. The expected dividend yield was based upon projected performance of the Partnership. 2014 Grant-date fair value $ 4.24 Expected volatility 36.0 % Expected dividend yield 5.9 % Expected term (in years) 3.0 Risk-free rate 0.99 % The following table presents the unit option activity under the Viper LTIP for the year ended December 31, 2015 . Weighted Average Unit Options Exercise Price Remaining Term Intrinsic Value (in years) (in thousands) Outstanding at December 31, 2014 2,500,000 $ 26.00 Granted — $ — Outstanding at December 31, 2015 2,500,000 $ — 1.50 $ — Vested and Expected to vest at December 31, 2015 2,500,000 $ — 1.50 $ — Exercisable at December 31, 2015 — $ — 0.00 $ — As of December 31, 2015 , the unrecognized compensation cost related to unvested unit options was $5.2 million . Such cost is expected to be recognized over a weighted-average period of 1.5 years. Phantom Units Under the Viper LTIP, the Board of Directors of the General Partner is authorized to issue phantom units to eligible employees. The Partnership estimates the fair value of phantom units as the closing price of the Partnership’s common units on the grant date of the award, which is expensed over the applicable vesting period. Upon vesting the phantom units entitle the recipient one common unit of the Partnership for each phantom unit. The following table presents the phantom unit activity under the Viper LTIP for the year ended December 31, 2015 . Phantom Units Weighted Average Grant-Date Unvested at December 31, 2014 17,776 $ 19.51 Granted 24,690 $ 15.48 Vested (17,118 ) $ 17.57 Unvested at December 31, 2015 25,348 $ 16.89 The aggregate fair value of phantom units that vested during the year ended December 31, 2015 was $0.3 million . As of December 31, 2015 , the unrecognized compensation cost related to unvested phantom units was $0.3 million . Such cost is expected to be recognized over a weighted-average period of 1.2 years. |
Related Party Transactions
Related Party Transactions | 12 Months Ended |
Dec. 31, 2015 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | RELATED PARTY TRANSACTIONS Immediately upon the completion of the Company’s initial public offering on October 17, 2012, Wexford beneficially owned approximately 44% of the Company’s outstanding common stock. As of December 31, 2015 , Wexford beneficially owned less than 1% of the Company’s outstanding common stock. A partner at Wexford serves as Chairman of the Board of Directors of each of the Company and the General Partner. Another partner at Wexford serves a member of the Board of Directors of the General Partner. Administrative Services An entity then under common management with the Company provided technical, administrative and payroll services to the Company under a shared services agreement which began March 1, 2008. The initial term of this shared service agreement was two years . Since the expiration of such two-year period on March 1, 2010, the agreement, by its terms continued on a month-to-month basis. Effective August 31, 2014, this agreement was mutually terminated. For the years ended December 31, 2014 and 2013 , the Company incurred total costs of less than $0.1 million and $0.2 million , respectively. Costs incurred unrelated to drilling activities are expensed and costs incurred in the acquisition, exploration and development of proved oil and natural gas properties have been capitalized. The Company had no outstanding amount payable at December 31, 2014 and owed the administrative services affiliate less than $0.1 million at December 31, 2013 . Effective January 1, 2012, the Company entered into an additional shared services agreement with this entity. Under this agreement, the Company provided this entity and, at its request, certain affiliates, with consulting, technical and administrative services. The initial term of the additional shared services agreement was two years . Thereafter, the agreement continued on a month-to-month basis subject to the right of either party to terminate the agreement upon 30 days , prior written notice. Effective August 31, 2014, this agreement was mutually terminated. Costs that are attributable to and billed to other affiliates are reported as other income-related party. For the years ended December 31, 2014 and 2013 , the affiliate reimbursed the Company $0.1 million and $1.1 million , respectively, for services under the shared services agreement. As of December 31, 2014 , the affiliate owed the company less than $0.1 million . As of December 31, 2013 , the affiliate had no outstanding amounts payable to the Company. Drilling Services Bison Drilling and Field Services LLC (“Bison”), an entity controlled by Wexford, has performed drilling and field services for the Company under master drilling and field service agreements. Under the Company’s most recent master drilling agreement with Bison, effective as of January 1, 2013, Bison committed to accept orders from the Company for the use of at least two of its rigs. As of December 31, 2015 and December 31, 2014 , the Company was not utilizing any Bison rigs. This master drilling agreement is terminable by either party on 30 days ’ prior written notice, although neither party will be relieved of its respective obligations arising from a drilling contract being performed prior to the termination of the master drilling agreement. For the year ended December 31, 2015 , the Company did no t incur any costs for services performed by Bison. For the years ended December 31, 2014 and 2013 , the Company incurred total costs for services performed by Bison of $3.5 million and $13.9 million , respectively. Bison is an affiliate of Wexford. Effective September 9, 2013, the Company entered into a master service agreement with Panther Drilling Systems LLC, under which Panther Drilling Systems LLC provides directional drilling and other services. This master service agreement is terminable by either party on 30 days ’ prior written notice, although neither party will be relieved of its respective obligations arising from work performed prior to the termination of the master service agreement. In the third quarter 2013, the Company began using Panther Drilling Systems LLC’s directional drilling services. For the year ended December 31, 2015 , Panther Drilling Systems LLC did no t perform any services for the Company. The Company incurred $0.3 million and $0.2 million for services performed for the years ended December 31, 2014 and 2013 , respectively. Panther Drilling Systems LLC is an affiliate of Wexford. Coronado Midstream The Company is party to a gas purchase agreement, dated May 1, 2009, as amended, with Coronado Midstream LLC, formerly known as MidMar Gas LLC, an entity affiliated with Wexford, that owns a gas gathering system and processing plant in the Permian Basin. Under this agreement, Coronado Midstream LLC is obligated to purchase from the Company, and the Company is obligated to sell to Coronado Midstream LLC, all of the gas conforming to certain quality specifications produced from certain of the Company’s Permian Basin acreage. Following the expiration of the initial ten year term, the agreement will continue on a year-to-year basis until terminated by either party on 30 days ’ written notice. Under the gas purchase agreement, Coronado Midstream LLC is obligated to pay the Company 87% of the net revenue received by Coronado Midstream LLC for all components of the Company’s dedicated gas, including the liquid hydrocarbons, and the sale of residue gas, in each case extracted, recovered or otherwise processed at Coronado Midstream LLC’s gas processing plant, and 94.56% of the net revenue received by Coronado Midstream LLC from the sale of such gas components and residue gas, extracted, recovered or otherwise processed at Chevron’s Headlee plant. An entity controlled by Wexford had owned approximately 28% equity interest in Coronado Midstream LLC until Coronado Midstream LLC was sold in March 2015. Coronado Midstream LLC is no longer a related party and any revenues, production and ad valorem taxes and gathering and transportation expense after March 2015 are not classified as those attributable to a related party. The Company recognized revenues from Coronado Midstream LLC of $5.2 million for the three months ended March 31, 2015. The Company recognized revenues from Coronado Midstream LLC of $24.4 million and $7.2 million for the years ended December 31, 2014 and 2013 , respectively. The Company recognized production and ad valorem taxes and gathering and transportation expenses from Coronado Midstream LLC of $1.1 million for the three months ended March 31, 2015. The Company recognized production and ad valorem taxes and gathering and transportation expenses from Coronado Midstream LLC of $4.1 million and $1.2 million for the years ended December 31, 2014 and 2013 , respectively. As of December 31, 2014 , Coronado Midstream owed the Company $4.0 million for the Company’s portion of the net proceeds from the sale of gas, gas products and residue gas. Sand Supply Muskie Proppant LLC (“Muskie”), an entity affiliated with Wexford, processes and sells fracing grade sand for oil and natural gas operations. The Company began purchasing sand from Muskie in March 2013. On May 16, 2013, the Company entered into a master services agreement with Muskie, pursuant to which Muskie agreed to sell custom natural sand proppant to the Company based on the Company’s requirements. The Company is not obligated to place any orders with, or accept any offers from, Muskie for sand proppant. The agreement may be terminated at the option of either party on 30 days ’ notice. The Company did not incur any costs for sand purchased from Muskie for the years ended December 31, 2015 and 2014 , respectively. The Company incurred costs of $0.7 million for sand purchased from Muskie for the year ended December 31, 2013 . The Company had no outstanding amounts payable to Muskie as of December 31, 2015 or December 31, 2014 . Midland Leases Effective May 15, 2011, the Company occupied corporate office space in Midland, Texas under a lease with a five -year term. The office space is owned by an entity controlled by an affiliate of Wexford. The Company paid $1.0 million , $0.4 million and $0.2 million for the years ended December 31, 2015 , 2014 and 2013 , respectively, under this lease. The following table contains information regarding recent amendments to the Midland corporate lease: Date of Amendment Reason for Amendment Current Monthly Base Rent New Monthly Base Rent or Rent for Additional Space Approx. Annual Increase of Monthly Base Rent 2 nd and 3 rd quarters 2013 (1) Lease additional space $13,000 $15,000 N/A 2 nd quarter 2014 Lease additional space $25,000 $27,000 N/A 4 th quarter 2014 (2) Lease additional space $27,000 $53,000 4% November 2014 (3)(4) Extend the term N/A N/A N/A April 2015 Lease additional space N/A $23,000 N/A June 2015 Lease additional space N/A $22,000 2% (1) The monthly rent will increase further to $25,000 beginning on October 1, 2013. (2) The monthly rent will continue to increase approximately 4% annually on June 1 of each year during the remainder of the lease term. (3) The lease was amended to extend the term of the lease for an additional 10 -year period. (4) Upon commencement of the extension in June 2016, the monthly base rent will increase to $94,000 , with an increase of approximately 2% annually. Field Office Lease The Company leased field office space in Midland, Texas from an unrelated third party from March 1, 2011 to March 1, 2014. Effective March 1, 2014, the building was purchased by an entity controlled by an affiliate of Wexford. The remaining term of the lease as of March 1, 2014 is four years. The Company paid rent of $0.2 million and $0.1 million to the related party for the years ended December 31, 2015 and 2014 , respectively. The monthly base rent is $11,000 which will increase 3% annually on March 1 of each year during the remainder of the lease term. During the third quarter of 2014, the Company negotiated a sublease with Bison, in which Bison will lease the field office space for the same term as the initial lease and will pay the monthly rent of $11,000 which will increase 3% annually on March 1 of each year during the remainder of the lease term. Oklahoma City Lease Effective January 1, 2012, the Company occupied corporate office space in Oklahoma City, Oklahoma under a lease with a 67 month term. The office space is owned by an entity controlled by an affiliate of Wexford. The Company paid $0.2 million and $0.2 million for the years ended December 31, 2014 and 2013 , respectively, under this lease. Effective April 1, 2013, the Company amended this lease to increase the size of the leased premises, at which time the monthly base rent increased to $19,000 for the remainder of the lease term. The Company was also responsible for paying a portion of specified costs, fees and expenses associated with the operation of the premises. Effective September 23, 2014, this lease agreement was mutually terminated. Advisory Services Agreement - The Company The Company entered into an advisory services agreement (the “Advisory Services Agreement”) with Wexford, dated as of October 11, 2012, under which Wexford provides the Company with general financial and strategic advisory services related to the business in return for an annual fee of $0.5 million , plus reasonable out-of-pocket expenses. The Advisory Services Agreement had an initial term of two years commencing on October 18, 2012, and continues for additional one -year periods unless terminated in writing by either party at least ten days prior to the expiration of the then current term. It may be terminated at any time by either party upon 30 days prior written notice. In the event the Company terminates such agreement, it is obligated to pay all amounts due through the remaining term. In addition, the Company agreed to pay Wexford to-be-negotiated market-based fees approved by the Company’s independent directors for such services as may be provided by Wexford at the Company’s request in connection with acquisitions and divestitures, financings or other transactions in which the Company may be involved. The services provided by Wexford under the Advisory Services Agreement do not extend to the Company’s day-to-day business or operations. The Company has agreed to indemnify Wexford and its affiliates from any and all losses arising out of or in connection with the Advisory Services Agreement except for losses resulting from Wexford’s or its affiliates’ gross negligence or willful misconduct. The Company incurred total costs of $1.2 million , $8.3 million and $0.5 million for the years ended December 31, 2015 , 2014 and 2013 , respectively, under the Advisory Services Agreement. For the year ended December 31, 2014, the total amount of $8.3 million was paid by cash payments of $4.3 million and the issuance to Wexford of 63,786 shares of the Company’s common stock. Advisory Services Agreement - The Partnership In connection with the closing of the Viper Offering, the Partnership and the General Partner entered into an advisory services agreement (the “Viper Advisory Services Agreement”) with Wexford, dated as of June 23, 2014, under which Wexford provides the Partnership and the General Partner with general financial and strategic advisory services related to the business in return for an annual fee of $0.5 million , plus reasonable out-of-pocket expenses. The Viper Advisory Services Agreement had an initial term of two years commencing on June 23, 2014, and will continue for additional one -year periods unless terminated in writing by either party at least ten days prior to the expiration of the then current term. It may be terminated at any time by either party upon 30 days prior written notice. In the event the Partnership or the General Partner terminates such agreement, the Partnership is obligated to pay all amounts due through the remaining term. In addition, the Partnership and the General Partner have agreed to pay Wexford to-be-negotiated market-based fees approved by the conflict committee of the board of directors of the General Partner for such services as may be provided by Wexford at the Partnership’s or the General Partner’s request in connection with acquisitions and divestitures, financings or other transactions in which we may be involved. The services provided by Wexford under the Viper Advisory Services Agreement do not extend to the Partnership or the General Partners day-to-day business or operations. The Partnership and General Partner have agreed to indemnify Wexford and its affiliates from any and all losses arising out of or in connection with the Viper Advisory Services Agreement except for losses resulting from Wexford’s or its affiliates’ gross negligence or willful misconduct. For the years ended December 31, 2015 and 2014 , the Partnership incurred costs of $0.6 million and $0.3 million , respectively, under the Viper Advisory Services Agreement. Secondary Offering Costs On November 17, 2014, Gulfport Energy Corporation (“Gulfport”) and certain entities controlled by Wexford completed an underwritten secondary public offering of 2,000,000 shares of the Company’s common stock and, on November 13, 2014, the underwriters purchased an additional 300,000 shares of the Company’s common stock from these selling stockholders pursuant to an option to purchase such additional shares granted to the underwriters. The shares were sold to the underwriters at $64.54 per share and the selling stockholders received all proceeds from this offering after deducting the underwriting discount. The Company incurred costs of less than $0.1 million related to this secondary public offering. On September 23, 2014, Gulfport and certain entities controlled by Wexford completed an underwritten secondary public offering of 2,500,000 shares of the Company’s common stock. The shares were sold to the underwriters at $75.44 per share and the selling stockholders received all proceeds from this offering after deducting the underwriting discount. The Company incurred costs of $0.1 million related to this secondary public offering. On June 27, 2014, Gulfport and certain entities controlled by Wexford completed an underwritten secondary public offering of 2,000,000 shares of the Company’s common stock. The shares were sold to the public at $90.04 per share and the selling stockholders received all proceeds from this offering after deducting the underwriting discount. The Company incurred costs of approximately $0.1 million related to this secondary public offering. On June 24, 2013, Gulfport and certain entities controlled by Wexford completed an underwritten secondary public offering of 6,000,000 shares of the Company’s common stock and, on July 5, 2013, the underwriters purchased an additional 869,222 shares of the Company’s common stock from these selling stockholders pursuant to an option to purchase such additional shares granted to the underwriters. The shares were sold to the public at $34.75 per share and the selling stockholders received all proceeds from this offering after deducting the underwriting discount. The Company incurred costs of approximately $0.2 million related to this secondary public offering. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2015 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | INCOME TAXES Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The Company is subject to corporate income taxes and the Texas margin tax. The components of the provision for income taxes for the years ended December 31, 2015 , 2014 and 2013 are as follows: Year Ended December 31, 2015 2014 2013 (In thousands) Current income tax provision (benefit): Federal $ (33 ) $ — $ 191 State 268 — — Total current income tax provision 235 — 191 Deferred income tax provision (benefit): Federal (198,729 ) 106,107 30,768 State (2,816 ) 2,878 795 Total deferred income tax provision (benefit) (201,545 ) 108,985 31,563 Total provision for (benefit from) income taxes $ (201,310 ) $ 108,985 $ 31,754 A reconciliation of the statutory federal income tax amount to the recorded expense is as follows: Year Ended December 31, 2015 2014 2013 (In thousands) Income tax expense (benefit) at the federal statutory rate (35%) $ (263,179 ) $ 105,959 $ 30,231 Income tax expense (benefit) relating to change in tax rate (1,145 ) — — State income tax expense (benefit), net of federal tax effect (2,548 ) 2,878 517 Non-deductible expenses and other 4,506 148 1,006 Change in valuation allowance 61,056 — — Provision for (benefit from) income taxes $ (201,310 ) $ 108,985 $ 31,754 The components of the Company’s deferred tax assets and liabilities as of December 31, 2015 and 2014 are as follows: December 31, 2015 2014 (In thousands) Current: Deferred tax assets Derivative instruments $ — $ — Other 2,658 1,950 Current deferred tax assets 2,658 1,950 Valuation allowance (1,018 ) — Current deferred tax assets, net of valuation allowance 1,640 1,950 Deferred tax liabilities Derivative instruments 1,640 41,903 Total current deferred tax liabilities 1,640 41,903 Net current deferred tax assets — (39,953 ) Noncurrent: Deferred tax assets Net operating loss carryforwards (subject to 20 year expiration) 82,635 49,627 Stock based compensation 3,873 2,520 Alternative minimum tax credit carryforward — 33 Other 4,533 — Noncurrent deferred tax assets 91,041 52,180 Valuation allowance (60,038 ) — Noncurrent deferred tax assets, net of valuation allowance 31,003 52,180 Deferred tax liabilities Oil and natural gas properties and equipment 31,003 213,772 Other — — Total noncurrent deferred tax liabilities 31,003 213,772 Net noncurrent deferred tax liabilities — 161,592 Net deferred tax liabilities $ — $ 201,545 The Company incurred a tax net operating loss ("NOL") in the current year due principally to the ability to expense certain intangible drilling and development costs under current law. There is no tax refund available to the Company, nor is there any current income tax payable. In light of the impairment of oil and gas properties, Management has recorded a $61.1 million valuation against the Company's federal NOLs. The valuation reduces the Company’s deferred assets to a zero value, as management does not believe that it is more-likely-than-not that this portion of the Company's NOLs are realizable. Management believes that the balance of the Company's NOLs are realizable only to the extent of future taxable income primarily related to the excess of book carrying value of properties over their respective tax bases. No other sources of future taxable income are considered in this judgment. The Company's U.S. federal NOLs and were incurred in the tax years 2015 and 2014 , and will generally be available for use through the tax years 2035 and 2034 , respectively. The State of Texas currently has no NOL carryover provision. The Company believes that Section 382 of the Internal Revenue Code of 1986, as amended, which relates to tax attribute limitations upon the 50% or greater change of ownership of an entity during any three-year look back period, will not have an adverse effect on future NOL usage. |
Derivatives
Derivatives | 12 Months Ended |
Dec. 31, 2015 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivatives | DERIVATIVES All derivative financial instruments are recorded at fair value. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the cash and non-cash changes in fair value in the consolidated statements of operations under the caption “Gain (loss) on derivative instruments, net.” The Company has used price swap contracts to reduce price volatility associated with certain of its oil sales. With respect to the Company’s fixed price swap contracts, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is less than the swap price, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap price. The Company’s derivative contracts are based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on Inter–Continental Exchange pricing for Brent crude oil. By using derivative instruments to hedge exposure to changes in commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. The Company’s counterparties are participants in the secured second amended and restated credit agreement, which is secured by substantially all of the assets of the guarantor subsidiaries; therefore, the Company is not required to post any collateral. The Company does not require collateral from its counterparties. The Company has entered into derivative instruments only with counterparties that are also lenders in our credit facility and have been deemed an acceptable credit risk. As of December 31, 2015 , the Company had open crude oil derivative positions with respect to future production as set forth in the table below. When aggregating multiple contracts, the weighted average contract price is disclosed. Crude Oil—Inter–Continental Exchange Brent Fixed Price Swap Production Period Volume (Bbls) Fixed Swap Price January - February 2016 91,000 88.72 Balance sheet offsetting of derivative assets and liabilities The fair value of swaps is generally determined using established index prices and other sources which are based upon, among other things, futures prices and time to maturity. These fair values are recorded by netting asset and liability positions that are with the same counterparty and are subject to contractual terms which provide for net settlement. The following tables present the gross amounts of recognized derivative assets and liabilities, the amounts offset under master netting arrangements with counterparties and the resulting net amounts presented in the Company’s consolidated balance sheets as of December 31, 2015 and December 31, 2014 . December 31, 2015 2014 (in thousands) Gross amounts of recognized assets $ 4,623 $ 117,541 Gross amounts offset in the Consolidated Balance Sheet — — Net amounts of assets presented in the Consolidated Balance Sheet $ 4,623 $ 117,541 The net amounts are classified as current or noncurrent based on their anticipated settlement dates. The net fair value of the Company’s derivative assets and liabilities and their locations on the consolidated balance sheet are as follows: December 31, 2015 2014 (in thousands) Current Assets: Derivative instruments $ 4,623 $ 115,607 Noncurrent Assets: Derivative instruments — 1,934 Total Assets $ 4,623 $ 117,541 None of the Company’s derivatives have been designated as hedges. As such, all changes in fair value are immediately recognized in earnings. The following table summarizes the gains and losses on derivative instruments included in the consolidated statements of operations: Year Ended December 31, 2015 2014 2013 (in thousands) Change in fair value of open non-hedge derivative instruments $ (112,918 ) $ 117,109 $ 5,346 Gain (loss) on settlement of non-hedge derivative instruments 144,869 10,430 (7,218 ) Gain (loss) on derivative instruments $ 31,951 $ 127,539 $ (1,872 ) |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2015 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | FAIR VALUE MEASUREMENTS Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Valuation techniques used to measure fair value must maximize the use of observable inputs and minimize the use of unobservable inputs. The fair value hierarchy is based on three levels of inputs, of which the first two are considered observable and the last unobservable, that may be used to measure fair value. The Company’s assessment of the significance of a particular input to the fair value measurements requires judgment and may affect the valuation of the assets and liabilities being measured and their placement within the fair value hierarchy. The Company uses appropriate valuation techniques based on available inputs to measure the fair values of its assets and liabilities. Level 1 - Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date. Level 2 - Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 3 - Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Assets and Liabilities Measured at Fair Value on a Recurring Basis Certain assets and liabilities are reported at fair value on a recurring basis, including the Company’s derivative instruments. The fair values of the Company’s fixed price crude oil swaps are measured internally using established commodity futures price strips for the underlying commodity provided by a reputable third party, the contracted notional volumes, and time to maturity. These valuations are Level 2 inputs. The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis as of December 31, 2015 and 2014 . December 31, 2015 2014 (in thousands) Fixed price swaps: Quoted prices in active markets level 1 $ — $ — Significant other observable inputs level 2 4,623 117,541 Significant unobservable inputs level 3 — — Total $ 4,623 $ 117,541 Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis The following table provides the fair value of financial instruments that are not recorded at fair value in the consolidated balance sheets. December 31, 2015 December 31, 2014 Carrying Carrying Amount Fair Value Amount Fair Value (in thousands) Debt: Revolving credit facility $ 11,000 $ 11,000 $ 223,500 $ 223,500 7.625% Senior Notes due 2021 450,000 450,000 450,000 440,438 Partnership revolving credit facility 34,500 34,500 — — The fair value of the revolving credit facility approximates its carrying value based on borrowing rates available to the Company for bank loans with similar terms and maturities and is classified as Level 2 in the fair value hierarchy. The fair value of the Senior Notes was determined using the December 31, 2015 quoted market price, a Level 1 classification in the fair value hierarchy. The fair value of the Partnership’s revolving credit facility approximates its carrying value based on borrowing rates available to us for bank loans with similar terms and maturities and is classified as Level 2 in the fair value hierarchy. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2015 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | COMMITMENTS AND CONTINGENCIES The Company could be subject to various possible loss contingencies which arise primarily from interpretation of federal and state laws and regulations affecting the natural gas and crude oil industry. Such contingencies include differing interpretations as to the prices at which natural gas and crude oil sales may be made, the prices at which royalty owners may be paid for production from their leases, environmental issues and other matters. Management believes it has complied with the various laws and regulations, administrative rulings and interpretations. Lease Commitments The following is a schedule of minimum future lease payments with commitments that have initial or remaining noncancelable lease terms in excess of one year as of December 31, 2015 : Year Ending December 31, Drilling Rig Commitments Office and Equipment Leases (in thousands) 2016 $ 29,536 $ 1,935 2017 19,893 2,053 2018 16,866 1,973 2019 589 1,839 2020 — 1,659 Thereafter — 9,583 Total $ 66,884 $ 19,042 The Company leases office space in Midland, Texas from related parties and office space in Oklahoma City, OK from an unrelated third party. Refer to Note 11 —Related Party Transactions for further information on the related party lease agreements. The following table presents rent expense for the years ended December 31, 2015 , 2014 and 2013 . Year ended December 31, 2015 2014 2013 (in thousands) Rent Expense $ 1,449 $ 852 $ 571 Drilling contracts As of December 31, 2015 , the Company had entered into drilling rig contracts with one related party and various third parties in the ordinary course of business to ensure rig availability to complete the Company’s drilling projects. Refer to Note 11 –Related Party Transactions for further information on the related party drilling agreement. These commitments are not recorded in the accompanying consolidated balance sheets. Future commitments as of December 31, 2015 total approximately $66.9 million . Oil production purchase agreement On May 24, 2012, the Company entered into an oil purchase agreement with Shell Trading (US) Company, in which the Company is obligated to commence delivery of specified quantities of oil to Shell Trading (US) Company upon completion of the reversal of the Magellan Longhorn pipeline and its conversion for oil shipment, which occurred on October 1, 2013. The Company’s agreement with Shell Trading has an initial term of 5 years from the completion date. The Company’s maximum delivery obligation under this agreement is 8,000 gross barrels per day. The Company has a one-time right to elect to decrease the contract quantity by not more than 20% of the then-current quantity, which decreased contract quantity will be effective for the remainder of the term of the agreement. The Company will receive the price per barrel of oil based on the arithmetic average of the daily settlement price for “Light Sweet Crude Oil” Prompt Month future contracts reported by the NYMEX over the one-month period, as adjusted based on adjustment formulas specified in the agreement. If the Company fails to deliver the required quantities of oil under the agreement during any three-month period following the service commencement date, the Company has agreed to pay Shell Trading (US) Company a deficiency payment, which is calculated by multiplying (i) the volume of oil that the Company failed to deliver as required under the agreement during such period by (ii) Magellan’s Longhorn Spot tariff rate in effect for transportation from Crane, Texas to the Houston Ship Channel for the period of time for which such deficiency volume is calculated. The agreement may be terminated by Shell Trading (US) Company in the event that Shell Trading (US) Company’s contract for transportation on the pipeline is terminated. Defined contribution plan The Company sponsors a 401(k) defined contribution plan for the benefit of substantially all employees at their date of hire. The plan allows eligible employees to contribute up to 100% of their annual compensation, not to exceed annual limits established by the federal government. The Company makes matching contributions of up to 6% of an employee’s compensation and may make additional discretionary contributions for eligible employees. Employer contributions vest in equal annual installments over a four year period. For the years ended December 31, 2015 , 2014 and 2013 the Company paid $1.4 million , $0.4 million and $0.3 million , respectively, in contributions to the plan. |
Subsequent Events
Subsequent Events | 12 Months Ended |
Dec. 31, 2015 | |
Subsequent Events [Abstract] | |
Subsequent Events | SUBSEQUENT EVENTS In January 2016, the Company completed an underwritten public offering of 4,600,000 shares of common stock, which included 600,000 shares of common stock issued pursuant to an option to purchase additional shares granted to the underwriter. The stock was sold to the underwriter at $55.33 per share and the Company received net proceeds of approximately $254.5 million from the sale of these shares of common stock, net of offering expenses and underwriting discounts and commissions. |
Guarantor Financial Statements
Guarantor Financial Statements | 12 Months Ended |
Dec. 31, 2015 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Guarantor Financial Statements | GUARANTOR FINANCIAL STATEMENTS Diamondback E&P LLC, Diamondback O&G LLC and White Fang Energy LLC (the “Guarantor Subsidiaries”) are guarantors under the Indenture relating to the Senior Notes. On June 23, 2014, in connection with the Viper Offering, the Company designated the Partnership, the General Partner and Viper Energy Partners LLC (the “Non-Guarantor Subsidiaries”) as unrestricted subsidiaries under the Indenture and, upon such designation, Viper Energy Partners LLC, which was a guarantor under the Indenture prior to such designation, was released as a guarantor under the Indenture. Viper Energy Partners LLC is a limited liability company formed on September 18, 2013 to own and acquire mineral and other oil and natural gas interests in properties in the Permian Basin in West Texas. The following presents condensed consolidated financial information for the Company (which for purposes of this Note 17 is referred to as the “Parent”), the Guarantor Subsidiaries and the Non–Guarantor Subsidiaries on a consolidated basis. Elimination entries presented are necessary to combine the entities. The information is presented in accordance with the requirements of Rule 3-10 under the SEC’s Regulation S-X. The financial information may not necessarily be indicative of results of operations, cash flows or financial position had the Guarantor Subsidiaries operated as independent entities. The Company has not presented separate financial and narrative information for each of the Guarantor Subsidiaries because it believes such financial and narrative information would not provide any additional information that would be material in evaluating the sufficiency of the Guarantor Subsidiaries. Condensed Consolidated Balance Sheet December 31, 2015 (In thousands) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations Consolidated Assets Current assets: Cash and cash equivalents $ 148 $ 19,428 $ 539 $ — $ 20,115 Restricted cash — — 500 — 500 Accounts receivable — 67,942 9,369 2 77,313 Accounts receivable - related party — 1,591 — — 1,591 Intercompany receivable 2,246,846 205,915 — (2,452,761 ) — Inventories — 1,728 — — 1,728 Other current assets 450 6,572 476 — 7,498 Total current assets 2,247,444 303,176 10,884 (2,452,759 ) 108,745 Property and equipment Oil and natural gas properties, at cost, based on the full cost method of accounting — 3,400,381 554,992 — 3,955,373 Pipeline and gas gathering assets — 7,174 — — 7,174 Other property and equipment — 48,621 — — 48,621 Accumulated depletion, depreciation, amortization and impairment — (1,347,296 ) (71,659 ) 5,412 (1,413,543 ) Net property and equipment — 2,108,880 483,333 5,412 2,597,625 Investment in subsidiaries 79,417 — — (79,417 ) — Other assets 7,795 8,733 35,514 — 52,042 Total assets $ 2,334,656 $ 2,420,789 $ 529,731 $ (2,526,764 ) $ 2,758,412 Liabilities and Stockholders’ Equity Current liabilities: Accounts payable-trade $ — $ 20,007 $ 1 $ — $ 20,008 Accounts payable-related party 1 212 4 — 217 Intercompany payable — 2,452,759 — (2,452,759 ) — Other current liabilities 8,683 112,431 82 — 121,196 Total current liabilities 8,684 2,585,409 87 (2,452,759 ) 141,421 Long-term debt 450,000 11,000 34,500 — 495,500 Asset retirement obligations — 12,518 — — 12,518 Total liabilities 458,684 2,608,927 34,587 (2,452,759 ) 649,439 Commitments and contingencies Stockholders’ equity: 1,875,972 (188,138 ) 495,144 (307,006 ) 1,875,972 Noncontrolling interest — — — 233,001 233,001 Total equity 1,875,972 (188,138 ) 495,144 (74,005 ) 2,108,973 Total liabilities and equity $ 2,334,656 $ 2,420,789 $ 529,731 $ (2,526,764 ) $ 2,758,412 Condensed Consolidated Balance Sheet December 31, 2014 (In thousands) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations Consolidated Assets Current assets: Cash and cash equivalents $ 6 $ 15,067 $ 15,110 $ — $ 30,183 Restricted cash — — 500 — 500 Accounts receivable — 85,752 8,239 2 93,993 Accounts receivable - related party — 4,001 — — 4,001 Intercompany receivable 1,658,215 2,167,434 — (3,825,649 ) — Inventories — 2,827 — — 2,827 Other current assets 562 119,392 253 — 120,207 Total current assets 1,658,783 2,394,473 24,102 (3,825,647 ) 251,711 Property and equipment Oil and natural gas properties, at cost, based on the full cost method of accounting — 2,607,513 511,084 — 3,118,597 Pipeline and gas gathering assets — 7,174 — — 7,174 Other property and equipment — 48,180 — — 48,180 Accumulated depletion, depreciation, amortization and impairment — (351,200 ) (32,799 ) 1,855 (382,144 ) Net property and equipment — 2,311,667 478,285 1,855 2,791,807 Investment in subsidiaries 839,217 — — (839,217 ) — Other assets 9,155 7,793 35,015 — 51,963 Total assets $ 2,507,155 $ 4,713,933 $ 537,402 $ (4,663,009 ) $ 3,095,481 Liabilities and Stockholders’ Equity Current liabilities: Accounts payable-trade $ — $ 26,224 $ 6 $ — $ 26,230 Intercompany payable 95,362 3,730,287 — (3,825,649 ) — Other current liabilities 49,190 189,264 2,045 — 240,499 Total current liabilities 144,552 3,945,775 2,051 (3,825,649 ) 266,729 Long-term debt 450,000 223,500 — — 673,500 Asset retirement obligations — 8,447 — — 8,447 Deferred income taxes 161,592 — — — 161,592 Total liabilities 756,144 4,177,722 2,051 (3,825,649 ) 1,110,268 Commitments and contingencies Stockholders’ equity: 1,751,011 536,211 535,351 (1,071,562 ) 1,751,011 Noncontrolling interest — — — 234,202 234,202 Total equity 1,751,011 536,211 535,351 (837,360 ) 1,985,213 Total liabilities and equity $ 2,507,155 $ 4,713,933 $ 537,402 $ (4,663,009 ) $ 3,095,481 Condensed Consolidated Statement of Operations Year Ended December 31, 2015 (In thousands) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations Consolidated Revenues: Oil sales $ — $ 336,106 $ — $ 69,609 $ 405,715 Natural gas sales — 16,932 — 2,660 19,592 Natural gas liquid sales — 18,836 — 2,590 21,426 Royalty income — — 74,859 (74,859 ) — Total revenues — 371,874 74,859 — 446,733 Costs and expenses: Lease operating expenses — 82,625 — — 82,625 Production and ad valorem taxes — 27,459 5,531 — 32,990 Gathering and transportation — 5,832 259 — 6,091 Depreciation, depletion and amortization — 182,395 35,436 (134 ) 217,697 Impairment of oil and natural gas properties — 814,798 3,423 (3,423 ) 814,798 General and administrative expenses 17,077 9,056 5,835 — 31,968 Asset retirement obligation accretion expense — 833 — — 833 Total costs and expenses 17,077 1,122,998 50,484 (3,557 ) 1,187,002 Income (loss) from operations (17,077 ) (751,124 ) 24,375 3,557 (740,269 ) Other income (expense) Interest expense (35,651 ) (4,749 ) (1,110 ) — (41,510 ) Other income 1 (588 ) 1,154 — 567 Other income - intercompany — 161 — — 161 Gain (loss) on derivative instruments, net — 31,951 — — 31,951 Total other income (expense), net (35,650 ) 26,775 44 — (8,831 ) Income (loss) before income taxes (52,727 ) (724,349 ) 24,419 3,557 (749,100 ) Benefit from income taxes (201,310 ) — — — (201,310 ) Net income (loss) 148,583 (724,349 ) 24,419 3,557 (547,790 ) Less: Net income attributable to noncontrolling interest — — — 2,838 2,838 Net income (loss) attributable to Diamondback Energy, Inc. $ 148,583 $ (724,349 ) $ 24,419 $ 719 $ (550,628 ) Condensed Consolidated Statement of Operations Year Ended December 31, 2014 (In thousands) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations Consolidated Revenues: Oil sales $ — $ 377,712 $ — $ 71,532 $ 449,244 Natural gas sales — 15,240 — 2,788 18,028 Natural gas liquid sales — 24,545 — 3,901 28,446 Royalty income — — 77,767 (77,767 ) — Total revenues — 417,497 77,767 454 495,718 Costs and expenses: Lease operating expenses — 55,384 — — 55,384 Production and ad valorem taxes — 27,242 5,377 19 32,638 Gathering and transportation — 3,294 — (6 ) 3,288 Depreciation, depletion and amortization — 143,477 27,601 (1,073 ) 170,005 General and administrative expenses 10,879 7,189 4,372 (1,174 ) 21,266 Asset retirement obligation accretion expense — 467 — — 467 Total costs and expenses 10,879 237,053 37,350 (2,234 ) 283,048 Income (loss) from operations (10,879 ) 180,444 40,417 2,688 212,670 Other income (expense) Interest income - intercompany 10,755 — — (10,755 ) — Interest expense (30,281 ) (3,746 ) (487 ) — (34,514 ) Interest expense - intercompany — — (10,755 ) 10,755 — Other income 6 91 459 — 556 Other income - intercompany — 1,027 — (906 ) 121 Other expense — (1,416 ) — — (1,416 ) Loss on derivative instruments, net — 127,539 — — 127,539 Total other income (expense), net (19,520 ) 123,495 (10,783 ) (906 ) 92,286 Income before income taxes (30,399 ) 303,939 29,634 1,782 304,956 Provision for income taxes 108,985 — — — 108,985 Net income (loss) $ (139,384 ) $ 303,939 $ 29,634 $ 1,782 $ 195,971 Less: Net income attributable to noncontrolling interest — — — 2,216 2,216 Net income (loss) attributable to Diamondback Energy, Inc. $ (139,384 ) $ 303,939 $ 29,634 $ (434 ) $ 193,755 Condensed Consolidated Statement of Operations Year Ended December 31, 2013 (In thousands) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations Consolidated Revenues: Oil sales $ — $ 174,868 $ — $ 13,885 $ 188,753 Natural gas sales — 5,852 — 397 6,249 Natural gas liquid sales — 12,295 — 705 13,000 Royalty income — — 14,987 (14,987 ) — Total revenues — 193,015 14,987 — 208,002 Costs and expenses: Lease operating expenses — 21,157 — — 21,157 Production and ad valorem taxes — 11,927 972 — 12,899 Gathering and transportation — 918 — — 918 Depreciation, depletion and amortization — 61,398 5,199 — 66,597 General and administrative expenses 3,909 7,127 — — 11,036 Asset retirement obligation accretion expense — 201 — — 201 Intercompany charges — — 87 (87 ) — Total costs and expenses 3,909 102,728 6,258 (87 ) 112,808 Income (loss) from operations (3,909 ) 90,287 8,729 87 95,194 Other income (expense) Interest income - intercompany 5,741 — — (5,741 ) — Interest expense (591 ) (7,467 ) (5,741 ) 5,741 (8,058 ) Other income — 87 — (87 ) — Other income - intercompany — 1,077 — — 1,077 Loss on derivative instruments, net — (1,872 ) — — (1,872 ) Total other income (expense), net 5,150 (8,175 ) (5,741 ) (87 ) (8,853 ) Income (loss) before income taxes 1,241 82,112 2,988 — 86,341 Provision for income taxes 31,754 — — — 31,754 Net income (loss) $ (30,513 ) $ 82,112 $ 2,988 $ — $ 54,587 Condensed Consolidated Statement of Cash Flows Year Ended December 31, 2015 (In thousands) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations Consolidated Net cash provided by (used in) operating activities $ (37,597 ) $ 390,266 $ 63,832 $ — $ 416,501 Cash flows from investing activities: Additions to oil and natural gas properties — (419,512 ) — — (419,512 ) Acquisition of leasehold interests — (437,455 ) — — (437,455 ) Acquisition of royalty interests — — (43,907 ) — (43,907 ) Purchase of other property and equipment — (1,213 ) — — (1,213 ) Proceeds from sale of assets — 9,739 — — 9,739 Equity investments — (2,702 ) — — (2,702 ) Intercompany transfers (145,023 ) 145,023 — — — Other investing activities — — — — — Net cash used in investing activities (145,023 ) (706,120 ) (43,907 ) — (895,050 ) Cash flows from financing activities: Proceeds from borrowing on credit facility — 390,501 34,500 — 425,001 Repayment on credit facility — (603,001 ) — — (603,001 ) Debit issuance costs — (85 ) (441 ) — (526 ) Public offering costs (586 ) — — — (586 ) Proceeds from public offerings 650,688 — — — 650,688 Distribution to parent — — — — — Distribution from subsidiary 60,587 — — (60,587 ) — Exercise of stock options 4,873 — — — 4,873 Distribution to non-controlling interest — — (68,555 ) 60,587 (7,968 ) Intercompany transfers (532,800 ) 532,800 — — — Net cash provided by financing activities 182,762 320,215 (34,496 ) — 468,481 Net increase (decrease) in cash and cash equivalents 142 4,361 (14,571 ) — (10,068 ) Cash and cash equivalents at beginning of period 6 15,067 15,110 — 30,183 Cash and cash equivalents at end of period $ 148 $ 19,428 $ 539 $ — $ 20,115 Condensed Consolidated Statement of Cash Flows Year Ended December 31, 2014 (In thousands) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations Consolidated Net cash provided by (used in) operating activities $ (8,862 ) $ 313,438 $ 51,813 $ — $ 356,389 Cash flows from investing activities: Additions to oil and natural gas properties — (493,063 ) (5,276 ) — (498,339 ) Acquisition of leasehold interests — (845,826 ) — — (845,826 ) Acquisition of royalty interests — — (57,689 ) — (57,689 ) Purchase of other property and equipment — (44,213 ) — — (44,213 ) Equity investments — (627 ) (33,850 ) — (34,477 ) Intercompany transfers (642,978 ) 642,978 — — — Other investing activities — (1,453 ) — — (1,453 ) Net cash used in investing activities (642,978 ) (742,204 ) (96,815 ) — (1,481,997 ) Cash flows from financing activities: Proceeds from borrowing on credit facility — 431,400 78,000 — 509,400 Repayment on credit facility — (217,900 ) (78,000 ) — (295,900 ) Proceeds from public offerings 693,886 — 234,546 — 928,432 Distribution to parent — — (148,760 ) 148,760 — Distribution from subsidiary 166,372 — — (166,372 ) — Distribution to non-controlling interest — — (19,926 ) 17,612 (2,314 ) Intercompany transfers (217,900 ) 217,900 — — — Other financing activities 8,962 (1,834 ) (6,510 ) — 618 Net cash provided by financing activities 651,320 429,566 59,350 — 1,140,236 Net increase (decrease) in cash and cash equivalents (520 ) 800 14,348 — 14,628 Cash and cash equivalents at beginning of period 526 14,267 762 — 15,555 Cash and cash equivalents at end of period $ 6 $ 15,067 $ 15,110 $ — $ 30,183 Condensed Consolidated Statement of Cash Flows Year Ended December 31, 2013 (In thousands) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations Consolidated Net cash provided by operating activities $ 12,302 $ 138,630 $ 4,845 $ — $ 155,777 Cash flows from investing activities: Additions to oil and natural gas properties — (292,586 ) — — (292,586 ) Acquisition of leasehold interests — (195,893 ) — — (195,893 ) Acquisition of royalty interests — — (444,083 ) — (444,083 ) Intercompany transfers (289,344 ) 289,344 — — — Other investing activities — (7,578 ) — — (7,578 ) Net cash used in investing activities (289,344 ) (206,713 ) (444,083 ) — (940,140 ) Cash flows from financing activities: Proceeds from borrowing on credit facility — 59,000 — — 59,000 Repayment on credit facility — (49,000 ) — — (49,000 ) Proceeds from senior notes 10,000 — 440,000 — 450,000 Proceeds from public offerings 322,680 — — — 322,680 Intercompany transfers (49,000 ) 49,000 — — — Other financing activities (6,126 ) (2,994 ) — — (9,120 ) Net cash provided by financing activities 277,554 56,006 440,000 — 773,560 Net increase in cash and cash equivalents 512 (12,077 ) 762 — (10,803 ) Cash and cash equivalents at beginning of period 14 26,344 — — 26,358 Cash and cash equivalents at end of period $ 526 $ 14,267 $ 762 $ — $ 15,555 |
Supplemental Information on Oil
Supplemental Information on Oil and Natural Gas Operations (Unaudited) | 12 Months Ended |
Dec. 31, 2015 | |
Extractive Industries [Abstract] | |
Supplemental information on oil and natural gas operations | SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) The Company’s oil and natural gas reserves are attributable solely to properties within the United States. Capitalized oil and natural gas costs Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, amortization and impairment are as follows: December 31, 2015 2014 (In thousands) Oil and Natural Gas Properties: Proved properties $ 2,848,557 $ 2,345,077 Unproved properties 1,106,816 773,520 Total Oil and Natural Gas Properties 3,955,373 3,118,597 Accumulated depreciation, depletion, amortization (512,144 ) (296,317 ) Accumulated impairment (897,962 ) (83,164 ) Net oil and natural gas properties capitalized $ 2,545,267 $ 2,739,116 Costs incurred in oil and natural gas activities Costs incurred in oil and natural gas property acquisition, exploration and development activities are as follows: Year Ended December 31, 2015 2014 2013 (In thousands) Acquisition costs Proved properties $ 64,340 $ 302,234 $ 339,130 Unproved properties 448,638 601,188 279,402 Development costs 42,749 86,097 88,460 Exploration costs 319,102 475,756 242,929 Capitalized asset retirement costs 3,458 4,962 697 Total $ 878,287 $ 1,470,237 $ 950,618 Results of Operations from Oil and Natural Gas Producing Activities The following schedule sets forth the revenues and expenses related to the production and sale of oil and natural gas. It does not include any interest costs or general and administrative costs and, therefore, is not necessarily indicative of the contribution to consolidated net operating results of our oil, natural gas and natural gas liquids operations. Year Ended December 31, 2015 2014 2013 (In thousands) Oil, natural gas and natural gas liquid sales $ 446,733 $ 495,718 $ 208,002 Lease operating expenses (82,625 ) (55,384 ) (21,157 ) Production and ad valorem taxes (32,990 ) (32,638 ) (12,899 ) Gathering and transportation (6,091 ) (3,288 ) (918 ) Depreciation, depletion, and amortization (216,056 ) (168,674 ) (65,821 ) Impairment (814,798 ) — — Asset retirement obligation accretion expense (833 ) (467 ) (201 ) Income tax expense 201,310 (108,985 ) (31,754 ) Results of operations $ (505,350 ) $ 126,282 $ 75,252 Oil and Natural Gas Reserves Proved oil and natural gas reserve estimates as of December 31, 2015 , 2014 and 2013 were prepared by Ryder Scott Company, L.P., independent petroleum engineers. Proved reserves were estimated in accordance with guidelines established by the SEC, which require that reserve estimates be prepared under existing economic and operating conditions based upon the 12-month unweighted average of the first-day-of-the-month prices. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. The changes in estimated proved reserves are as follows: Oil Natural Gas Natural Gas Proved Developed and Undeveloped Reserves: As of January 1, 2013 26,196,859 8,251,429 34,570,148 Extensions and discoveries 17,041,744 4,597,856 24,184,540 Revisions of previous estimates (5,943,164 ) (3,455,306 ) (5,786,180 ) Purchase of reserves in place 7,328,162 1,672,824 10,441,485 Production (2,022,749 ) (361,079 ) (1,730,497 ) As of December 31, 2013 42,600,852 10,705,724 61,679,496 Extensions and discoveries 37,068,820 7,828,094 52,099,252 Revisions of previous estimates (6,784,560 ) 649,476 (17,726,552 ) Purchase of reserves in place 8,186,053 360,536 19,898,649 Production (5,381,576 ) (1,001,898 ) (4,345,585 ) As of December 31, 2014 75,689,589 18,541,932 111,605,260 Extensions and discoveries 48,725,132 12,055,631 53,452,948 Revisions of previous estimates (12,130,474 ) (4,080,886 ) (14,726,160 ) Purchase of reserves in place 2,775,599 1,165,090 7,101,933 Production (9,081,135 ) (1,677,623 ) (7,931,237 ) As of December 31, 2015 105,978,711 26,004,144 149,502,744 Proved Developed Reserves: January 1, 2013 7,189,367 2,999,440 12,864,941 December 31, 2013 19,789,965 4,973,493 31,428,756 December 31, 2014 43,885,835 11,221,428 68,264,113 December 31, 2015 60,569,398 15,418,353 96,871,109 Proved Undeveloped Reserves: January 1, 2013 19,007,492 5,251,989 21,705,207 December 31, 2013 22,810,887 5,732,231 30,250,740 December 31, 2014 31,803,754 7,320,504 43,341,147 December 31, 2015 45,409,313 10,585,791 52,631,635 Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs or development costs. The Company made one large acquisition of oil and natural gas interests in 2015 located in western Howard and eastern Martin counties. Several small acquisitions were also made in various counties including Andrews, Midland, Martin, and Glasscock counties. The reserves from these acquisitions were primarily proved producing reserves from 136 vertical wells and four horizontal wells and three vertical wells where additional interest was acquired. All of the properties were acquired for horizontal exploitation. Although there were four producing horizontal wells on the properties no PUD’s were included in the acquired properties because of very limited production from the wells at the time of acquisition. Significant extensions occurred in 2015 as a result of continued horizontal development of the Lower Spraberry and Wolfcamp B horizons. There was also initial development of the Wolfcamp A and Middle Spraberry horizons in some locations. The extensions resulted from two vertical wells and 119 horizontal wells in which the Company has a working interest and from 16 horizontal wells in which the Company has a mineral interest through its ownership in Viper. Of the two vertical wells and 135 horizontal wells, one of the vertical wells and 89 of the horizontal wells are in the proved undeveloped category. The revisions are primarily the result of lower product pricing. As a result of lower pricing 80 vertical wells and 22 horizontal wells in which the Company has a working interest and 22 vertical wells in which the Company has a mineral interest were downgraded from the proved undeveloped category to probable or possible reserves. Additional downward revisions resulted from shorter producing lives on existing wells as a result of the wells reaching their economic limit sooner due to lower revenues. The Company made two major acquisitions of oil and natural gas interests in 2014. One involved properties located in southwest Martin County and the other involved properties located predominantly in Glasscock and Midland Counties. The reserves from these acquisitions were primarily proved producing reserves from 280 existing vertical wells and six existing horizontal wells. The properties were acquired for horizontal exploitation, however the only horizontal wells that existed on the properties were in one isolated block in Reagan County. As a result, no horizontal PUDs were included in the acquired reserves. Significant extensions occurred primarily as a result of continued horizontal development of the Wolfcamp B horizon and the initial horizontal development of the Lower Spraberry shale. The extensions resulted from development of 18 vertical wells and 103 horizontal wells in which the Company has a working interest and one vertical well and 14 horizontal wells in which the Company has a mineral interest through its ownership in Viper. Of the total 19 vertical wells and 117 horizontal wells, five of the vertical wells and 66 of the horizontal wells are in the proved undeveloped category. The revisions are primarily the result of 73 vertical wells that were downgraded from PUDs to probable reserves due to a shift in the Company’s focus to horizontal development rather than vertical development. As a result these wells are no longer expected to be developed within five years of when they were originally booked. The Company experienced downward reserve revisions in estimated proved oil, natural gas and natural gas liquid reserves in 2013. The downward revisions were primarily a result of downgrading 92 vertical locations that were booked as PUDs to probable in accordance with the SEC five year PUD rule. At December 31, 2015 , the Company’s estimated PUD reserves were approximately 64,767 MBOE, an 18,419 MBOE increase over the reserve estimate at December 31, 2014 of 46,348 MBOE. The following table includes the changes in PUD reserves for 2015 : (MBOE) Beginning proved undeveloped reserves at December 31, 2014 46,348 Undeveloped reserves transferred to developed (13,680 ) Revisions (12,656 ) Extensions and discoveries 44,755 Ending proved undeveloped reserves at December 31, 2015 64,767 The increase in proved undeveloped reserves was primarily attributable to extensions and discoveries of 44,755 MBOE. Approximately 20% of the proved undeveloped reserve extensions are associated with well locations that are more than one offset away from existing producing wells. All of these locations are within 1,700 feet of producing wells. Partially offsetting the increase in proved undeveloped reserves were decreases due to technical revisions. Downward revisions of approximately 12,656 MBOE were a result of reclassifying 14,619 MBOE of reserves attributable to 80 vertical wells and 22 horizontal wells in which the Company has a working interest and 22 vertical wells in which the Company has only a mineral interest held through the Partnership due to lower product prices. Vertical well reclassifications accounted for 8,607 MBOE of the total of 14,619 MBOE. These vertical locations were also unlikely to be developed within the five -year period required by the applicable SEC rules due to the Company’s focus on horizontal well development. As of December 31, 2015 , all of the Company’s proved undeveloped reserves are planned to be developed within five years from the date they were initially recorded. During 2015 , approximately $42.7 million in capital expenditures went toward the development of proved undeveloped reserves, which includes drilling, completion and other facility costs associated with developing proved undeveloped wells. Standardized Measure of Discounted Future Net Cash Flows The following information has been prepared in accordance with the provisions of the Financial Accounting Standards Board Codification, Topic 932–“Extractive Activities–Oil and Gas.” The standardized measure of discounted future net cash flows are based on the unweighted average, first-day-of-the-month price. The projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be interpreted as representing current value to the Company. Material revisions to estimates of proved reserves may occur in the future; development and production of the reserves may not occur in the periods assumed; actual prices realized are expected to vary significantly from those used; and actual costs may vary. The following table sets forth the standardized measure of discounted future net cash flows attributable to the Company’s proved oil and natural gas reserves as of December 31, 2015 , 2014 and 2013 . December 31, 2015 2014 2013 (In thousands) Future cash inflows $ 5,377,783 $ 7,695,368 $ 4,604,241 Future development costs (548,239 ) (602,438 ) (517,075 ) Future production costs (1,279,101 ) (1,278,487 ) (806,895 ) Future production taxes (363,129 ) (534,851 ) (318,396 ) Future income tax expenses (28,233 ) (672,380 ) (674,260 ) Future net cash flows 3,159,081 4,607,212 2,287,615 10% discount to reflect timing of cash flows (1,740,948 ) (2,561,988 ) (1,311,976 ) Standardized measure of discounted future net cash flows $ 1,418,133 $ 2,045,224 $ 975,639 In the table below the average first-day-of–the-month price for oil, natural gas and natural gas liquids is presented, all utilized in the computation of future cash inflows. December 31, 2015 2014 2013 Unweighted Arithmetic Average First-Day-of-the-Month Prices Oil (per Bbl) $ 45.07 $ 87.15 $ 92.59 Natural gas (per Mcf) $ 1.83 $ 4.85 $ 4.13 Natural gas liquids (per Bbl) $ 12.56 $ 30.09 $ 37.82 Principal changes in the standardized measure of discounted future net cash flows attributable to the Company’s proved reserves are as follows: Year Ended December 31, 2015 2014 2013 (In thousands) Standardized measure of discounted future net cash flows at the beginning of the period $ 2,045,224 $ 975,639 $ 367,220 Sales of oil and natural gas, net of production costs (331,119 ) (404,409 ) (173,946 ) Purchase of minerals in place 57,359 291,807 305,109 Extensions and discoveries, net of future development costs 629,149 1,135,293 552,450 Previously estimated development costs incurred during the period 129,901 111,527 76,631 Net changes in prices and production costs (1,383,698 ) (105,210 ) 51,828 Changes in estimated future development costs 38,638 (4,877 ) (5,822 ) Revisions of previous quantity estimates (377,160 ) (173,004 ) (126,993 ) Accretion of discount 236,716 151,481 57,988 Net change in income taxes 268,963 (12,326 ) (168,570 ) Net changes in timing of production and other 104,160 79,303 39,744 Standardized measure of discounted future net cash flows at the end of the period $ 1,418,133 $ 2,045,224 $ 975,639 |
Quarterly Financial Data (Unaud
Quarterly Financial Data (Unaudited) | 12 Months Ended |
Dec. 31, 2015 | |
Quarterly Financial Information Disclosure [Abstract] | |
Quarterly Financial Data (Unaudited) | QUARTERLY FINANCIAL DATA (Unaudited) The Company’s unaudited quarterly financial data for 2015 and 2014 is summarized below. 2015 First Second Third Fourth Revenues $ 101,401 $ 119,063 $ 111,946 $ 114,323 Income (loss) from operations 1,437 (299,120 ) (254,773 ) (187,813 ) Income tax expense (benefit) 3,370 (116,732 ) (81,461 ) (6,487 ) Net income (loss) 6,439 (211,352 ) (156,042 ) (186,835 ) Less: Net income attributable to noncontrolling interest 590 935 739 574 Net income (loss) attributable to Diamondback Energy, Inc. $ 5,849 $ (212,287 ) $ (156,781 ) $ (187,409 ) Earnings per common share Basic $ 0.10 $ (3.45 ) $ (2.40 ) $ (2.80 ) Diluted $ 0.10 $ (3.45 ) $ (2.40 ) $ (2.80 ) 2014 First Second Third Fourth Revenues $ 98,004 $ 127,004 $ 139,127 $ 131,583 Income from operations 48,063 63,192 63,516 37,899 Income tax expense (benefit) 13,601 15,163 23,978 56,243 Net income 23,589 27,824 44,641 99,917 Less: Net income attributable to noncontrolling interest — 71 902 1,243 Net income attributable to Diamondback Energy, Inc. $ 23,589 $ 27,753 $ 43,739 $ 98,674 Earnings per common share Basic $ 0.49 $ 0.55 $ 0.79 $ 1.74 Diluted $ 0.48 $ 0.54 $ 0.79 $ 1.73 |
Summary of Significant Accoun27
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2015 | |
Accounting Policies [Abstract] | |
Basis of Presentation | Basis of Presentation The consolidated financial statements include the accounts of the Company and its subsidiaries after all significant intercompany balances and transactions have been eliminated upon consolidation. |
Use of Estimates | Use of Estimates Certain amounts included in or affecting the Company’s consolidated financial statements and related disclosures must be estimated by management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the consolidated financial statements are prepared. These estimates and assumptions affect the amounts the Company reports for assets and liabilities and the Company’s disclosure of contingent assets and liabilities at the date of the consolidated financial statements. Actual results could differ from those estimates. The Company evaluates these estimates on an ongoing basis, using historical experience, consultation with experts and other methods the Company considers reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from the Company’s estimates. Any effects on the Company’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include estimates of proved oil and natural gas reserves and related present value estimates of future net cash flows therefrom, the carrying value of oil and natural gas properties, asset retirement obligations, the fair value determination of acquired assets and liabilities, equity-based compensation, fair value estimates of commodity derivatives and estimates of income taxes. |
Cash and Cash Equivalents and Restricted Cash | Cash and Cash Equivalents The Company considers all highly liquid investments purchased with a maturity of three months or less and money market funds to be cash equivalents. The Company maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Company has not experienced any significant losses from such investments. Restricted Cash A subsidiary of the Company entered into an agreement to purchase certain overriding royalty interests and deposited $0.5 million in escrow. The agreement provided that the subsidiary would have the right to terminate the agreement and receive a return of the deposit if the subsidiary in good faith asserted title defects in excess of a certain amount. The subsidiary asserted title defects in excess of the amount and requested that the escrow agent return the deposit. The seller provided the escrow agent with notice alleging the subsidiary did not timely assert the defects in good faith. The escrow agent tendered the deposit to the court subject to a judicial determination of the proper payment of the funds. |
Accounts Receivable | Accounts Receivable Accounts receivable consist of receivables from joint interest owners on properties the Company operates and from sales of oil and natural gas production delivered to purchasers. The purchasers remit payment for production directly to the Company. Most payments are received within three months after the production date. Accounts receivable are stated at amounts due from joint interest owners or purchasers, net of an allowance for doubtful accounts when the Company believes collection is doubtful. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. Accounts receivable outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance by considering a number of factors, including the length of time accounts receivable are past due, the Company’s previous loss history, the debtor’s current ability to pay its obligation to the Company, the condition of the general economy and the industry as a whole. The Company writes off specific accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful accounts. |
Derivative Instruments | Derivative Instruments The Company is required to recognize its derivative instruments on the consolidated balance sheets as assets or liabilities at fair value with such amounts classified as current or long-term based on their anticipated settlement dates. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the cash and non-cash change in fair value on derivative instruments in the consolidated statements of operations. |
Fair Value of Financial Instruments | Fair Value of Financial Instruments The Company’s financial instruments consist of cash and cash equivalents, restricted cash, receivables, payables, derivatives, notes payable and senior notes. The carrying amount of cash and cash equivalents, receivables and payables approximates fair value because of the short-term nature of the instruments. The fair value of the revolving credit facility approximates its carrying value based on the borrowing rates currently available to the Company for bank loans with similar terms and maturities. The note payable is carried at cost, which approximates fair value due to the nature of the instrument and relatively short maturity. The fair value of the senior notes are determined using quoted market prices. Derivatives are recorded at fair value (see Note 14 –Fair Value Measurements). |
Oil and Natural Gas Properties | Oil and Natural Gas Properties The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain internal costs, are capitalized and amortized on a composite unit of production method based on proved oil, natural gas liquids and natural gas reserves. Internal costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. All internal costs not directly associated with exploration and development activities were charged to expense as they were incurred. Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, natural gas liquids and natural gas. Any income from services provided by subsidiaries to working interest owners of properties in which the Company also owns an interest, to the extent they exceed related costs incurred, are accounted for as reductions of capitalized costs of oil and natural gas properties proportionate to the Company’s investment in the subsidiary (see Note 7 –Equity Method Investments). Depletion of evaluated oil and natural gas properties is computed on the units of production method, whereby capitalized costs plus estimated future development costs are amortized over total proved reserves. The average depletion rate per barrel equivalent unit of production was $17.84 , $23.79 and $24.63 for the years ended December 31, 2015 , 2014 and 2013 , respectively. Depreciation, depletion and amortization expense for oil and natural gas properties was $216.1 million , $168.7 million and $65.8 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. Under this method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the proved oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes, or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the trailing 12-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions, and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or non-cash writedown is required. During the year ended December 31, 2015 , the Company recorded an impairment on proved oil and natural gas properties of $814.8 million . No impairment on proved oil and natural gas properties was recorded for the years ended December 31, 2014 and 2013 , respectively. Costs associated with unevaluated properties are excluded from the full cost pool until the Company has made a determination as to the existence of proved reserves. The Company assesses all items classified as unevaluated property on an annual basis for possible impairment. The Company assesses properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization. |
Other Property and Equipment | Other Property and Equipment Other property and equipment is recorded at cost. The Company expenses maintenance and repairs in the period incurred. Upon retirements or disposition of assets, the cost and related accumulated depreciation are removed from the consolidated balance sheet with the resulting gains or losses, if any, reflected in operations. Depreciation of other property and equipment is computed using the straight line method over their estimated useful lives, which range from three to fifteen years. |
Asset Retirement Obligations | Asset Retirement Obligations The Company measures the future cost to retire its tangible long-lived assets and recognizes such cost as a liability for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction or normal operation of a long-lived asset. The Company records a liability relating to the retirement and removal of all assets used in their businesses. Asset retirement obligations represent the future abandonment costs of tangible assets, namely wells. The fair value of a liability for an asset’s retirement obligation is recorded in the period in which it is incurred if a reasonable estimate of fair value can be made and the corresponding cost is capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, the difference is recorded in oil and natural gas properties. |
Impairment or Long-Lived Assets | Impairment of Long-Lived Assets Other property and equipment used in operations are reviewed whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. An impairment loss is recognized only if the carrying amount of a long-lived asset is not recoverable from its estimated future undiscounted cash flows. An impairment loss is the difference between the carrying amount and fair value of the asset. |
Capitalized Interest | Capitalized Interest The Company capitalizes interest on expenditures made in connection with exploration and development projects that are not subject to current amortization. Interest is capitalized only for the period that activities are in progress to bring these projects to their intended use. Capitalized interest cannot exceed gross interest expense. |
Inventories | Inventories Inventories are stated at the lower of cost or market and consist of tubular goods and equipment at December 31, 2015 and 2014 . The Company’s tubular goods and equipment are primarily comprised of oil and natural gas drilling or repair items such as tubing, casing and pumping units. The inventory is primarily acquired for use in future drilling or repair operations and is carried at lower of cost or market. “Market”, in the context of inventory valuation, represents net realizable value, which is the amount that the Company is allowed to bill to the joint accounts under joint operating agreements to which the Company is a party. As of December 31, 2015 , the Company estimated that all of its tubular goods and equipment will be utilized within one year. |
Debt Issuance Costs | Debt Issuance Costs Other assets included capitalized costs of $18.2 million and $13.8 million , net of accumulated amortization of $6.5 million and $3.9 million , as of December 31, 2015 and 2014 , respectively. The costs associated with the Senior Notes are being amortized over the term of the Senior Notes using the effective interest method. The costs associated with the Company’s credit facility are being amortized over the term of the facility. |
Revenue and Royalties Payable | Revenue and Royalties Payable For certain oil and natural gas properties, where the Company serves as operator, the Company receives production proceeds from the purchaser and further distributes such amounts to other revenue and royalty owners. Production proceeds applicable to other revenue and royalty owners are reflected as revenue and royalties payable in the accompanying consolidated balance sheets. The Company recognizes revenue for only its net revenue interest in oil and natural gas properties. |
Revenue Recognition | Revenue Recognition Oil and natural gas revenues are recorded when title passes to the purchaser, net of royalty interests, discounts and allowances, as applicable. The Company accounts for oil and natural gas production imbalances using the sales method, whereby a liability is recorded when the Company’s overtake volumes exceed its estimated remaining recoverable reserves. No receivables are recorded for those wells where the Company has taken less than its ownership share of production. The Company did not have any gas imbalances as of December 31, 2015 or December 31, 2014 . Revenues from oil and natural gas services are recognized as services are provided. |
Investments | Investments Equity investments in which the Company exercises significant influence but does not control are accounted for using the equity method. Under the equity method, generally the Company’s share of investees’ earnings or loss is recognized in the statement of operations. The Company reviews its investments to determine if a loss in value which is other than a temporary decline has occurred. If such loss has occurred, the Company would recognize an impairment provision. |
Accounting for Stock-based Compensation | Accounting for Equity-Based Compensation The Company grants various types of stock-based awards including stock options and restricted stock units. These plans and related accounting policies are defined and described more fully in Note 10 –Equity-Based Compensation. Stock compensation awards are measured at fair value on the date of grant and are expensed, net of estimated forfeitures, over the required service period. |
Concentrations | Concentrations The Company is subject to risk resulting from the concentration of its crude oil and natural gas sales and receivables with several significant purchasers. For the year ended December 31, 2015 , two purchasers accounted for more than 10% of our revenue: Shell Trading (US) Company ( 59% ); and Enterprise Crude Oil LLC ( 15% ). For the year ended December 31, 2014 , two purchasers accounted for more than 10% of our revenue: Shell Trading (US) Company ( 64% ); and Enterprise Crude Oil LLC ( 16% ). For the year ended December 31, 2013 , two purchasers each accounted for more than 10% of our revenue: Plains Marketing, L.P. ( 37% ); and Shell Trading (US) Company ( 37% ). The Company does not require collateral and does not believe the loss of any single purchaser would materially impact its operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers. |
Environmental Compliance and Remediation | Environmental Compliance and Remediation Environmental compliance and remediation costs, including ongoing maintenance and monitoring, are expensed as incurred. Liabilities are accrued when environmental assessments and remediation are probable, and the costs can be reasonably estimated. |
Income Taxes | Income Taxes Diamondback uses the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized. |
Recent Accounting Pronouncements | Recent Accounting Pronouncements In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update 2014-09, “Revenue from Contracts with Customers”. This update supersedes most of the existing revenue recognition requirements in GAAP and requires (i) an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goods or services and (ii) requires expanded disclosures regarding the nature, amount, timing, and certainty of revenue and cash flows from contracts with customers. The standard will be effective for annual and interim reporting periods beginning after December 15, 2017, with early application not permitted. The standard allows for either full retrospective adoption, meaning the standard is applied to all periods presented in the financial statements, or modified retrospective adoption, meaning the standard is applied only to the most current period presented. The Company is currently evaluating the impact, if any, that the adoption of this update will have on the Company’s financial position, results of operations and liquidity. In April 2015, the Financial Accounting Standards Board issued Accounting Standards Update 2015-03, “Interest–Imputation of Interest”. This update requires that debt issuance costs related to a recognized debt liability (except costs associated with revolving debt arrangements) be presented in the balance sheet as a direct deduction from that debt liability, consistent with the presentation of a debt discount to simplify the presentation of debt issuance costs. The standard will be effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within fiscal years beginning after December 15, 2016. Early application will be permitted for financial statements that have not previously been issued. Adoption of the new guidance will only affect the presentation of the Company’s consolidated balance sheets and will not have a material impact on its consolidated financial statements. In July 2015, the Financial Accounting Standards Board issued Accounting Standards Update 2015-11, “Inventory”. This update applies to all inventory that is not measured using last-in, first-out or the retail inventory method. Under this update, an entity should measure inventory at the lower of cost and net realizable value. This standard will be effective for financial statements issued for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. This standard should be applied prospectively with early adoption permitted as of the beginning of an interim or annual reporting period. The Company is currently evaluating the impact that the adoption of this update will have on the Company’s financial position, results of operations and liquidity. In November 2015, the Financial Accounting Standards Board issued Accounting Standards Update 2015-17, “Income Taxes”. This update requires that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. The standard will be effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early application will be permitted as of the beginning of an interim or annual reporting period. This standard may be applied either prospectively to all deferred tax liabilities and assets or retrospectively to all periods presented. Adoption of the new guidance will only affect the presentation of the Company’s consolidated balance sheets and will not have a material impact on its consolidated financial statements. |
Fair Value Measurement | Fair value is defined as 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. Valuation techniques used to measure fair value must maximize the use of observable inputs and minimize the use of unobservable inputs. The fair value hierarchy is based on three levels of inputs, of which the first two are considered observable and the last unobservable, that may be used to measure fair value. The Company’s assessment of the significance of a particular input to the fair value measurements requires judgment and may affect the valuation of the assets and liabilities being measured and their placement within the fair value hierarchy. The Company uses appropriate valuation techniques based on available inputs to measure the fair values of its assets and liabilities. Level 1 - Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date. Level 2 - Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 3 - Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. |
Summary of Significant Accoun28
Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Accounting Policies [Abstract] | |
Schedule of other accrued liabilities | Other accrued liabilities consist of the following: December 31, 2015 2014 (In thousands) Prepaid drilling liability $ 12,683 $ 3,758 Interest payable 8,606 8,861 Lease operating expense payable 14,100 11,851 Taxes payable 518 9,952 Current portion of asset retirement obligations 193 39 Other 8,193 6,688 Total other accrued liabilities $ 44,293 $ 41,149 |
Acquisitions (Tables)
Acquisitions (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Oil and Gas Interest in Permian Basin Acquired in 2014 [Member] | |
Business Acquisition [Line Items] | |
Schedule of business acquisition pro forma | The following unaudited summary pro forma consolidated statement of operations data of Diamondback for the years ended December 31, 2014 and 2013 have been prepared to give effect to the February 27 and 28, 2014 acquisitions and the September 9, 2014 acquisition as if they had occurred on January 1, 2013. The pro forma data are not necessarily indicative of financial results that would have been attained had the acquisitions occurred on January 1, 2013. The pro forma data also necessarily exclude various operation expenses related to the properties and the financial statements should not be viewed as indicative of operations in future periods. Pro Forma (Unaudited) Year Ended December 31, 2014 2013 (in thousands) Revenues $ 541,103 $ 315,736 Income from operations 224,382 146,429 Net income 201,257 86,277 |
Oil and Gas Interest in Permian Basin Acquired in September 2014 [Member] | |
Business Acquisition [Line Items] | |
Schedule of estimated fair values of assets acquired and liabilities assumed | The following represents the estimated fair values of the assets and liabilities assumed on the acquisition date. The aggregate consideration transferred was $523.3 million in cash, subject to post-closing adjustments, resulting in no goodwill or bargain purchase gain. (in thousands) Joint interest receivables $ 42 Proved oil and natural gas properties 128,589 Unevaluated oil and natural gas properties 400,527 Total assets acquired 529,158 Accrued production and ad valorem taxes 358 Revenues payable 3,174 Asset retirement obligations 2,366 Total liabilities assumed 5,898 Total fair value of net assets $ 523,260 |
Oil and Gas Interest in Permian Basin Acquired in February 2014 [Member] | |
Business Acquisition [Line Items] | |
Schedule of estimated fair values of assets acquired and liabilities assumed | The following represents the estimated fair values of the assets and liabilities assumed on the acquisition dates. The aggregate consideration transferred was $292.2 million in cash, subject to post-closing adjustments, resulting in no goodwill or bargain purchase gain. (in thousands) Proved oil and natural gas properties $ 170,174 Unevaluated oil and natural gas properties 123,243 Total assets acquired 293,417 Asset retirement obligations 1,258 Total liabilities assumed 1,258 Total fair value of net assets $ 292,159 |
Property and Equipment (Tables)
Property and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Property, Plant and Equipment [Abstract] | |
Property and Equipment | Property and equipment includes the following: December 31, 2015 2014 (in thousands) Oil and natural gas properties: Subject to depletion $ 2,848,557 $ 2,345,077 Not subject to depletion-acquisition costs Incurred in 2015 433,769 — Incurred in 2014 543,399 576,802 Incurred in 2013 68,351 130,474 Incurred in 2012 61,297 65,480 Incurred in 2011 — 764 Total not subject to depletion 1,106,816 773,520 Gross oil and natural gas properties 3,955,373 3,118,597 Accumulated depletion (512,144 ) (296,317 ) Accumulated impairment (897,962 ) (83,164 ) Oil and natural gas properties, net 2,545,267 2,739,116 Pipeline and gas gathering assets, net 7,174 7,174 Other property and equipment, net 48,621 48,180 Accumulated depreciation (3,437 ) (2,663 ) Property and equipment, net of accumulated depreciation, depletion, amortization and impairment $ 2,597,625 $ 2,791,807 |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Asset Retirement Obligation [Abstract] | |
Asset Retirement Obligations | The following table describes the changes to the Company’s asset retirement obligation liability for the following periods: Year Ended December 31, 2015 2014 2013 (in thousands) Asset retirement obligation, beginning of period $ 8,486 $ 3,029 $ 2,145 Additional liability incurred 594 703 226 Liabilities acquired 3,159 3,726 471 Liabilities settled (292 ) (27 ) (14 ) Accretion expense 833 467 201 Revisions in estimated liabilities (69 ) 588 — Asset retirement obligation, end of period 12,711 8,486 3,029 Less current portion 193 39 40 Asset retirement obligations - long-term $ 12,518 $ 8,447 $ 2,989 |
Debt (Tables)
Debt (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Line of Credit Facility [Line Items] | |
Schedule of long-term debt | Long-term debt consisted of the following as of the dates indicated: December 31, 2015 2014 (in thousands) 7.625 % Senior Notes due 2021 $ 450,000 $ 450,000 Revolving credit facility $ 11,000 $ 223,500 Partnership revolving credit facility 34,500 — Total long-term debt $ 495,500 $ 673,500 |
Financial Covenants | Financial Covenant Required Ratio Ratio of total debt to EBITDAX Not greater than 4.0 to 1.0 Ratio of current assets to liabilities, as defined in the credit agreement Not less than 1.0 to 1.0 |
Schedule of interest expense | The following amounts have been incurred and charged to interest expense for the years ended December 31, 2015 , 2014 and 2013 : Year Ended December 31, 2015 2014 2013 (in thousands) Interest expense $ 40,221 $ 36,669 $ 10,322 Less capitalized interest — (5,275 ) (3,951 ) Other fees and expenses 1,292 3,121 1,688 Total interest expense 41,513 34,515 8,059 |
Viper Energy Partners LP [Member] | |
Line of Credit Facility [Line Items] | |
Financial Covenants | Financial Covenant Required Ratio Ratio of total debt to EBITDAX Not greater than 4.0 to 1.0 Ratio of current assets to liabilities, as defined in the credit agreement Not less than 1.0 to 1.0 |
Capital Stock and Earnings Pe33
Capital Stock and Earnings Per Share (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Equity [Abstract] | |
Schedule of reconciliation of basic and diluted net income per share | A reconciliation of the components of basic and diluted earnings per common share is presented in the table below: 2015 Income Shares Per Share (in thousands, except per share amounts) Basic: Net income attributable to common stock $ (550,628 ) 63,019 $ (8.74 ) Effect of Dilutive Securities: Dilutive effect of potential common shares issuable $ — — Diluted: Net income attributable to common stock $ (550,628 ) 63,019 $ (8.74 ) 2014 Income Shares Per Share (in thousands, except per share amounts) Basic: Net income attributable to common stock $ 193,755 52,826 $ 3.67 Effect of Dilutive Securities: Dilutive effect of potential common shares issuable $ — 471 Diluted: Net income attributable to common stock $ 193,755 53,297 $ 3.64 2013 Income Shares Per Share (in thousands, except per share amounts) Basic: Net income attributable to common stock $ 54,587 42,015 $ 1.30 Effect of Dilutive Securities: Dilutive effect of potential common shares issuable $ — 240 Diluted: Net income attributable to common stock $ 54,587 42,255 $ 1.29 |
Equity-Based Compensation (Tabl
Equity-Based Compensation (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
The effects of stock-based compensation plans and related costs | The following table presents the effects of the equity and stock based compensation plans and related costs: 2015 2014 2013 (In thousands) General and administrative expenses $ 18,529 $ 9,816 $ 1,752 Equity-based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties 6,043 4,437 972 Related income tax benefit — — 704 |
Summary of grant-date fair value and related assumptions | 2013 Grant-date fair value $ 6.51 Expected volatility 36.9 % Expected dividend yield 0.0 % Expected term (in years) 3.8 Risk-free rate 0.57 % |
Schedule of stock/unit option activity | The following table presents the Company’s stock option activity under the Company’s 2012 Equity Incentive Plan (“2012 Plan”) for the year ended December 31, 2015 . Weighted Average Exercise Remaining Intrinsic Options Price Term Value (in years) (in thousands) Outstanding at December 31, 2014 313,105 $ 18.29 Exercised (273,605 ) $ 17.80 Outstanding at December 31, 2015 39,500 $ 21.66 1.83 $ 1,787 Vested and Expected to vest at December 31, 2015 39,500 $ 21.66 1.83 $ 1,787 Exercisable at December 31, 2015 8,000 $ 17.50 0.78 $ 395 |
Summary of restricted stock awards and units | The following table presents the Company’s restricted stock units activity under the 2012 Plan during the year ended December 31, 2015 . Restricted Stock Weighted Average Grant-Date Unvested at December 31, 2014 167,291 $ 49.99 Granted 138,534 $ 68.54 Vested (143,956 ) $ 42.58 Forfeited (2,110 ) $ 74.14 Unvested at December 31, 2015 159,759 $ 64.66 |
Summary of grant-date fair values of performance restricted stock units granted and related assumptions | The following table presents a summary of the grant-date fair values of performance restricted stock units granted and the related assumptions. 2015 2014 Grant-date fair value $ 137.14 $ 125.63 Risk-free rate 0.49 % 0.30 % Company volatility 43.36 % 39.60 % |
Schedule of performance restricted stock units activity | The following table presents the Company’s performance restricted stock units activity under the 2012 Plan for the year ended December 31, 2015 . Performance Restricted Stock Units Weighted Average Grant-Date Fair Value Unvested at December 31, 2014 79,150 $ 125.63 Granted 90,249 $ 137.14 Vested (79,150 ) $ 125.63 Unvested at December 31, 2015 (1) 90,249 $ 137.14 (1) A maximum of 180,498 units could be awarded based upon the Company’s final TSR ranking. |
Viper Energy Partners LP [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Summary of grant-date fair value and related assumptions | 2014 Grant-date fair value $ 4.24 Expected volatility 36.0 % Expected dividend yield 5.9 % Expected term (in years) 3.0 Risk-free rate 0.99 % |
Schedule of stock/unit option activity | The following table presents the unit option activity under the Viper LTIP for the year ended December 31, 2015 . Weighted Average Unit Options Exercise Price Remaining Term Intrinsic Value (in years) (in thousands) Outstanding at December 31, 2014 2,500,000 $ 26.00 Granted — $ — Outstanding at December 31, 2015 2,500,000 $ — 1.50 $ — Vested and Expected to vest at December 31, 2015 2,500,000 $ — 1.50 $ — Exercisable at December 31, 2015 — $ — 0.00 $ — |
Phantom Units [Member] | Viper Energy Partners LP [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Schedule of phantom units activity | The following table presents the phantom unit activity under the Viper LTIP for the year ended December 31, 2015 . Phantom Units Weighted Average Grant-Date Unvested at December 31, 2014 17,776 $ 19.51 Granted 24,690 $ 15.48 Vested (17,118 ) $ 17.57 Unvested at December 31, 2015 25,348 $ 16.89 |
Related Party Transactions (Tab
Related Party Transactions (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Related Party Transaction | |
Schedule of Amendments to Corporate Office Leases [Table Text Block] | The following table contains information regarding recent amendments to the Midland corporate lease: Date of Amendment Reason for Amendment Current Monthly Base Rent New Monthly Base Rent or Rent for Additional Space Approx. Annual Increase of Monthly Base Rent 2 nd and 3 rd quarters 2013 (1) Lease additional space $13,000 $15,000 N/A 2 nd quarter 2014 Lease additional space $25,000 $27,000 N/A 4 th quarter 2014 (2) Lease additional space $27,000 $53,000 4% November 2014 (3)(4) Extend the term N/A N/A N/A April 2015 Lease additional space N/A $23,000 N/A June 2015 Lease additional space N/A $22,000 2% (1) The monthly rent will increase further to $25,000 beginning on October 1, 2013. (2) The monthly rent will continue to increase approximately 4% annually on June 1 of each year during the remainder of the lease term. (3) The lease was amended to extend the term of the lease for an additional 10 -year period. (4) Upon commencement of the extension in June 2016, the monthly base rent will increase to $94,000 , with an increase of approximately 2% annually. |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Income Tax Disclosure [Abstract] | |
Schedule of Components of Income Tax Expense (Benefit) | The components of the provision for income taxes for the years ended December 31, 2015 , 2014 and 2013 are as follows: Year Ended December 31, 2015 2014 2013 (In thousands) Current income tax provision (benefit): Federal $ (33 ) $ — $ 191 State 268 — — Total current income tax provision 235 — 191 Deferred income tax provision (benefit): Federal (198,729 ) 106,107 30,768 State (2,816 ) 2,878 795 Total deferred income tax provision (benefit) (201,545 ) 108,985 31,563 Total provision for (benefit from) income taxes $ (201,310 ) $ 108,985 $ 31,754 |
Reconciliation of Statutory Federal Income Tax Amount to Recorded Expense | A reconciliation of the statutory federal income tax amount to the recorded expense is as follows: Year Ended December 31, 2015 2014 2013 (In thousands) Income tax expense (benefit) at the federal statutory rate (35%) $ (263,179 ) $ 105,959 $ 30,231 Income tax expense (benefit) relating to change in tax rate (1,145 ) — — State income tax expense (benefit), net of federal tax effect (2,548 ) 2,878 517 Non-deductible expenses and other 4,506 148 1,006 Change in valuation allowance 61,056 — — Provision for (benefit from) income taxes $ (201,310 ) $ 108,985 $ 31,754 |
Schedule of Deferred Tax Assets and Liabilities | The components of the Company’s deferred tax assets and liabilities as of December 31, 2015 and 2014 are as follows: December 31, 2015 2014 (In thousands) Current: Deferred tax assets Derivative instruments $ — $ — Other 2,658 1,950 Current deferred tax assets 2,658 1,950 Valuation allowance (1,018 ) — Current deferred tax assets, net of valuation allowance 1,640 1,950 Deferred tax liabilities Derivative instruments 1,640 41,903 Total current deferred tax liabilities 1,640 41,903 Net current deferred tax assets — (39,953 ) Noncurrent: Deferred tax assets Net operating loss carryforwards (subject to 20 year expiration) 82,635 49,627 Stock based compensation 3,873 2,520 Alternative minimum tax credit carryforward — 33 Other 4,533 — Noncurrent deferred tax assets 91,041 52,180 Valuation allowance (60,038 ) — Noncurrent deferred tax assets, net of valuation allowance 31,003 52,180 Deferred tax liabilities Oil and natural gas properties and equipment 31,003 213,772 Other — — Total noncurrent deferred tax liabilities 31,003 213,772 Net noncurrent deferred tax liabilities — 161,592 Net deferred tax liabilities $ — $ 201,545 |
Derivatives (Tables)
Derivatives (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule of derivative instruments | As of December 31, 2015 , the Company had open crude oil derivative positions with respect to future production as set forth in the table below. When aggregating multiple contracts, the weighted average contract price is disclosed. Crude Oil—Inter–Continental Exchange Brent Fixed Price Swap Production Period Volume (Bbls) Fixed Swap Price January - February 2016 91,000 88.72 |
Schedule of netting offsets of derivative assets and liabilities | The following tables present the gross amounts of recognized derivative assets and liabilities, the amounts offset under master netting arrangements with counterparties and the resulting net amounts presented in the Company’s consolidated balance sheets as of December 31, 2015 and December 31, 2014 . December 31, 2015 2014 (in thousands) Gross amounts of recognized assets $ 4,623 $ 117,541 Gross amounts offset in the Consolidated Balance Sheet — — Net amounts of assets presented in the Consolidated Balance Sheet $ 4,623 $ 117,541 |
Schedule of derivative instruments included in the consolidated balance sheet | The net fair value of the Company’s derivative assets and liabilities and their locations on the consolidated balance sheet are as follows: December 31, 2015 2014 (in thousands) Current Assets: Derivative instruments $ 4,623 $ 115,607 Noncurrent Assets: Derivative instruments — 1,934 Total Assets $ 4,623 $ 117,541 |
Summary of derivative contract gains and losses included in the consolidated statements of operations | The following table summarizes the gains and losses on derivative instruments included in the consolidated statements of operations: Year Ended December 31, 2015 2014 2013 (in thousands) Change in fair value of open non-hedge derivative instruments $ (112,918 ) $ 117,109 $ 5,346 Gain (loss) on settlement of non-hedge derivative instruments 144,869 10,430 (7,218 ) Gain (loss) on derivative instruments $ 31,951 $ 127,539 $ (1,872 ) |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Fair Value Disclosures [Abstract] | |
Fair value measurement information for financial instruments measured on a recurring basis | The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis as of December 31, 2015 and 2014 . December 31, 2015 2014 (in thousands) Fixed price swaps: Quoted prices in active markets level 1 $ — $ — Significant other observable inputs level 2 4,623 117,541 Significant unobservable inputs level 3 — — Total $ 4,623 $ 117,541 |
Fair value measurement information for financial instruments measured on a nonrecurring basis | The following table provides the fair value of financial instruments that are not recorded at fair value in the consolidated balance sheets. December 31, 2015 December 31, 2014 Carrying Carrying Amount Fair Value Amount Fair Value (in thousands) Debt: Revolving credit facility $ 11,000 $ 11,000 $ 223,500 $ 223,500 7.625% Senior Notes due 2021 450,000 450,000 450,000 440,438 Partnership revolving credit facility 34,500 34,500 — — |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Commitments and Contingencies Disclosure [Abstract] | |
Schedule of minimum future lease payments | The following is a schedule of minimum future lease payments with commitments that have initial or remaining noncancelable lease terms in excess of one year as of December 31, 2015 : Year Ending December 31, Drilling Rig Commitments Office and Equipment Leases (in thousands) 2016 $ 29,536 $ 1,935 2017 19,893 2,053 2018 16,866 1,973 2019 589 1,839 2020 — 1,659 Thereafter — 9,583 Total $ 66,884 $ 19,042 |
Schedule of rent expense | The following table presents rent expense for the years ended December 31, 2015 , 2014 and 2013 . Year ended December 31, 2015 2014 2013 (in thousands) Rent Expense $ 1,449 $ 852 $ 571 |
Guarantor Financial Statements
Guarantor Financial Statements (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Condensed Consolidated Balance Sheet | Condensed Consolidated Balance Sheet December 31, 2015 (In thousands) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations Consolidated Assets Current assets: Cash and cash equivalents $ 148 $ 19,428 $ 539 $ — $ 20,115 Restricted cash — — 500 — 500 Accounts receivable — 67,942 9,369 2 77,313 Accounts receivable - related party — 1,591 — — 1,591 Intercompany receivable 2,246,846 205,915 — (2,452,761 ) — Inventories — 1,728 — — 1,728 Other current assets 450 6,572 476 — 7,498 Total current assets 2,247,444 303,176 10,884 (2,452,759 ) 108,745 Property and equipment Oil and natural gas properties, at cost, based on the full cost method of accounting — 3,400,381 554,992 — 3,955,373 Pipeline and gas gathering assets — 7,174 — — 7,174 Other property and equipment — 48,621 — — 48,621 Accumulated depletion, depreciation, amortization and impairment — (1,347,296 ) (71,659 ) 5,412 (1,413,543 ) Net property and equipment — 2,108,880 483,333 5,412 2,597,625 Investment in subsidiaries 79,417 — — (79,417 ) — Other assets 7,795 8,733 35,514 — 52,042 Total assets $ 2,334,656 $ 2,420,789 $ 529,731 $ (2,526,764 ) $ 2,758,412 Liabilities and Stockholders’ Equity Current liabilities: Accounts payable-trade $ — $ 20,007 $ 1 $ — $ 20,008 Accounts payable-related party 1 212 4 — 217 Intercompany payable — 2,452,759 — (2,452,759 ) — Other current liabilities 8,683 112,431 82 — 121,196 Total current liabilities 8,684 2,585,409 87 (2,452,759 ) 141,421 Long-term debt 450,000 11,000 34,500 — 495,500 Asset retirement obligations — 12,518 — — 12,518 Total liabilities 458,684 2,608,927 34,587 (2,452,759 ) 649,439 Commitments and contingencies Stockholders’ equity: 1,875,972 (188,138 ) 495,144 (307,006 ) 1,875,972 Noncontrolling interest — — — 233,001 233,001 Total equity 1,875,972 (188,138 ) 495,144 (74,005 ) 2,108,973 Total liabilities and equity $ 2,334,656 $ 2,420,789 $ 529,731 $ (2,526,764 ) $ 2,758,412 Condensed Consolidated Balance Sheet December 31, 2014 (In thousands) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations Consolidated Assets Current assets: Cash and cash equivalents $ 6 $ 15,067 $ 15,110 $ — $ 30,183 Restricted cash — — 500 — 500 Accounts receivable — 85,752 8,239 2 93,993 Accounts receivable - related party — 4,001 — — 4,001 Intercompany receivable 1,658,215 2,167,434 — (3,825,649 ) — Inventories — 2,827 — — 2,827 Other current assets 562 119,392 253 — 120,207 Total current assets 1,658,783 2,394,473 24,102 (3,825,647 ) 251,711 Property and equipment Oil and natural gas properties, at cost, based on the full cost method of accounting — 2,607,513 511,084 — 3,118,597 Pipeline and gas gathering assets — 7,174 — — 7,174 Other property and equipment — 48,180 — — 48,180 Accumulated depletion, depreciation, amortization and impairment — (351,200 ) (32,799 ) 1,855 (382,144 ) Net property and equipment — 2,311,667 478,285 1,855 2,791,807 Investment in subsidiaries 839,217 — — (839,217 ) — Other assets 9,155 7,793 35,015 — 51,963 Total assets $ 2,507,155 $ 4,713,933 $ 537,402 $ (4,663,009 ) $ 3,095,481 Liabilities and Stockholders’ Equity Current liabilities: Accounts payable-trade $ — $ 26,224 $ 6 $ — $ 26,230 Intercompany payable 95,362 3,730,287 — (3,825,649 ) — Other current liabilities 49,190 189,264 2,045 — 240,499 Total current liabilities 144,552 3,945,775 2,051 (3,825,649 ) 266,729 Long-term debt 450,000 223,500 — — 673,500 Asset retirement obligations — 8,447 — — 8,447 Deferred income taxes 161,592 — — — 161,592 Total liabilities 756,144 4,177,722 2,051 (3,825,649 ) 1,110,268 Commitments and contingencies Stockholders’ equity: 1,751,011 536,211 535,351 (1,071,562 ) 1,751,011 Noncontrolling interest — — — 234,202 234,202 Total equity 1,751,011 536,211 535,351 (837,360 ) 1,985,213 Total liabilities and equity $ 2,507,155 $ 4,713,933 $ 537,402 $ (4,663,009 ) $ 3,095,481 |
Condensed Consolidated Statement of Operations | Condensed Consolidated Statement of Operations Year Ended December 31, 2015 (In thousands) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations Consolidated Revenues: Oil sales $ — $ 336,106 $ — $ 69,609 $ 405,715 Natural gas sales — 16,932 — 2,660 19,592 Natural gas liquid sales — 18,836 — 2,590 21,426 Royalty income — — 74,859 (74,859 ) — Total revenues — 371,874 74,859 — 446,733 Costs and expenses: Lease operating expenses — 82,625 — — 82,625 Production and ad valorem taxes — 27,459 5,531 — 32,990 Gathering and transportation — 5,832 259 — 6,091 Depreciation, depletion and amortization — 182,395 35,436 (134 ) 217,697 Impairment of oil and natural gas properties — 814,798 3,423 (3,423 ) 814,798 General and administrative expenses 17,077 9,056 5,835 — 31,968 Asset retirement obligation accretion expense — 833 — — 833 Total costs and expenses 17,077 1,122,998 50,484 (3,557 ) 1,187,002 Income (loss) from operations (17,077 ) (751,124 ) 24,375 3,557 (740,269 ) Other income (expense) Interest expense (35,651 ) (4,749 ) (1,110 ) — (41,510 ) Other income 1 (588 ) 1,154 — 567 Other income - intercompany — 161 — — 161 Gain (loss) on derivative instruments, net — 31,951 — — 31,951 Total other income (expense), net (35,650 ) 26,775 44 — (8,831 ) Income (loss) before income taxes (52,727 ) (724,349 ) 24,419 3,557 (749,100 ) Benefit from income taxes (201,310 ) — — — (201,310 ) Net income (loss) 148,583 (724,349 ) 24,419 3,557 (547,790 ) Less: Net income attributable to noncontrolling interest — — — 2,838 2,838 Net income (loss) attributable to Diamondback Energy, Inc. $ 148,583 $ (724,349 ) $ 24,419 $ 719 $ (550,628 ) Condensed Consolidated Statement of Operations Year Ended December 31, 2014 (In thousands) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations Consolidated Revenues: Oil sales $ — $ 377,712 $ — $ 71,532 $ 449,244 Natural gas sales — 15,240 — 2,788 18,028 Natural gas liquid sales — 24,545 — 3,901 28,446 Royalty income — — 77,767 (77,767 ) — Total revenues — 417,497 77,767 454 495,718 Costs and expenses: Lease operating expenses — 55,384 — — 55,384 Production and ad valorem taxes — 27,242 5,377 19 32,638 Gathering and transportation — 3,294 — (6 ) 3,288 Depreciation, depletion and amortization — 143,477 27,601 (1,073 ) 170,005 General and administrative expenses 10,879 7,189 4,372 (1,174 ) 21,266 Asset retirement obligation accretion expense — 467 — — 467 Total costs and expenses 10,879 237,053 37,350 (2,234 ) 283,048 Income (loss) from operations (10,879 ) 180,444 40,417 2,688 212,670 Other income (expense) Interest income - intercompany 10,755 — — (10,755 ) — Interest expense (30,281 ) (3,746 ) (487 ) — (34,514 ) Interest expense - intercompany — — (10,755 ) 10,755 — Other income 6 91 459 — 556 Other income - intercompany — 1,027 — (906 ) 121 Other expense — (1,416 ) — — (1,416 ) Loss on derivative instruments, net — 127,539 — — 127,539 Total other income (expense), net (19,520 ) 123,495 (10,783 ) (906 ) 92,286 Income before income taxes (30,399 ) 303,939 29,634 1,782 304,956 Provision for income taxes 108,985 — — — 108,985 Net income (loss) $ (139,384 ) $ 303,939 $ 29,634 $ 1,782 $ 195,971 Less: Net income attributable to noncontrolling interest — — — 2,216 2,216 Net income (loss) attributable to Diamondback Energy, Inc. $ (139,384 ) $ 303,939 $ 29,634 $ (434 ) $ 193,755 Condensed Consolidated Statement of Operations Year Ended December 31, 2013 (In thousands) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations Consolidated Revenues: Oil sales $ — $ 174,868 $ — $ 13,885 $ 188,753 Natural gas sales — 5,852 — 397 6,249 Natural gas liquid sales — 12,295 — 705 13,000 Royalty income — — 14,987 (14,987 ) — Total revenues — 193,015 14,987 — 208,002 Costs and expenses: Lease operating expenses — 21,157 — — 21,157 Production and ad valorem taxes — 11,927 972 — 12,899 Gathering and transportation — 918 — — 918 Depreciation, depletion and amortization — 61,398 5,199 — 66,597 General and administrative expenses 3,909 7,127 — — 11,036 Asset retirement obligation accretion expense — 201 — — 201 Intercompany charges — — 87 (87 ) — Total costs and expenses 3,909 102,728 6,258 (87 ) 112,808 Income (loss) from operations (3,909 ) 90,287 8,729 87 95,194 Other income (expense) Interest income - intercompany 5,741 — — (5,741 ) — Interest expense (591 ) (7,467 ) (5,741 ) 5,741 (8,058 ) Other income — 87 — (87 ) — Other income - intercompany — 1,077 — — 1,077 Loss on derivative instruments, net — (1,872 ) — — (1,872 ) Total other income (expense), net 5,150 (8,175 ) (5,741 ) (87 ) (8,853 ) Income (loss) before income taxes 1,241 82,112 2,988 — 86,341 Provision for income taxes 31,754 — — — 31,754 Net income (loss) $ (30,513 ) $ 82,112 $ 2,988 $ — $ 54,587 |
Condensed Consolidated Statement of Cash Flows | Condensed Consolidated Statement of Cash Flows Year Ended December 31, 2015 (In thousands) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations Consolidated Net cash provided by (used in) operating activities $ (37,597 ) $ 390,266 $ 63,832 $ — $ 416,501 Cash flows from investing activities: Additions to oil and natural gas properties — (419,512 ) — — (419,512 ) Acquisition of leasehold interests — (437,455 ) — — (437,455 ) Acquisition of royalty interests — — (43,907 ) — (43,907 ) Purchase of other property and equipment — (1,213 ) — — (1,213 ) Proceeds from sale of assets — 9,739 — — 9,739 Equity investments — (2,702 ) — — (2,702 ) Intercompany transfers (145,023 ) 145,023 — — — Other investing activities — — — — — Net cash used in investing activities (145,023 ) (706,120 ) (43,907 ) — (895,050 ) Cash flows from financing activities: Proceeds from borrowing on credit facility — 390,501 34,500 — 425,001 Repayment on credit facility — (603,001 ) — — (603,001 ) Debit issuance costs — (85 ) (441 ) — (526 ) Public offering costs (586 ) — — — (586 ) Proceeds from public offerings 650,688 — — — 650,688 Distribution to parent — — — — — Distribution from subsidiary 60,587 — — (60,587 ) — Exercise of stock options 4,873 — — — 4,873 Distribution to non-controlling interest — — (68,555 ) 60,587 (7,968 ) Intercompany transfers (532,800 ) 532,800 — — — Net cash provided by financing activities 182,762 320,215 (34,496 ) — 468,481 Net increase (decrease) in cash and cash equivalents 142 4,361 (14,571 ) — (10,068 ) Cash and cash equivalents at beginning of period 6 15,067 15,110 — 30,183 Cash and cash equivalents at end of period $ 148 $ 19,428 $ 539 $ — $ 20,115 Condensed Consolidated Statement of Cash Flows Year Ended December 31, 2014 (In thousands) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations Consolidated Net cash provided by (used in) operating activities $ (8,862 ) $ 313,438 $ 51,813 $ — $ 356,389 Cash flows from investing activities: Additions to oil and natural gas properties — (493,063 ) (5,276 ) — (498,339 ) Acquisition of leasehold interests — (845,826 ) — — (845,826 ) Acquisition of royalty interests — — (57,689 ) — (57,689 ) Purchase of other property and equipment — (44,213 ) — — (44,213 ) Equity investments — (627 ) (33,850 ) — (34,477 ) Intercompany transfers (642,978 ) 642,978 — — — Other investing activities — (1,453 ) — — (1,453 ) Net cash used in investing activities (642,978 ) (742,204 ) (96,815 ) — (1,481,997 ) Cash flows from financing activities: Proceeds from borrowing on credit facility — 431,400 78,000 — 509,400 Repayment on credit facility — (217,900 ) (78,000 ) — (295,900 ) Proceeds from public offerings 693,886 — 234,546 — 928,432 Distribution to parent — — (148,760 ) 148,760 — Distribution from subsidiary 166,372 — — (166,372 ) — Distribution to non-controlling interest — — (19,926 ) 17,612 (2,314 ) Intercompany transfers (217,900 ) 217,900 — — — Other financing activities 8,962 (1,834 ) (6,510 ) — 618 Net cash provided by financing activities 651,320 429,566 59,350 — 1,140,236 Net increase (decrease) in cash and cash equivalents (520 ) 800 14,348 — 14,628 Cash and cash equivalents at beginning of period 526 14,267 762 — 15,555 Cash and cash equivalents at end of period $ 6 $ 15,067 $ 15,110 $ — $ 30,183 Condensed Consolidated Statement of Cash Flows Year Ended December 31, 2013 (In thousands) Non– Guarantor Guarantor Parent Subsidiaries Subsidiaries Eliminations Consolidated Net cash provided by operating activities $ 12,302 $ 138,630 $ 4,845 $ — $ 155,777 Cash flows from investing activities: Additions to oil and natural gas properties — (292,586 ) — — (292,586 ) Acquisition of leasehold interests — (195,893 ) — — (195,893 ) Acquisition of royalty interests — — (444,083 ) — (444,083 ) Intercompany transfers (289,344 ) 289,344 — — — Other investing activities — (7,578 ) — — (7,578 ) Net cash used in investing activities (289,344 ) (206,713 ) (444,083 ) — (940,140 ) Cash flows from financing activities: Proceeds from borrowing on credit facility — 59,000 — — 59,000 Repayment on credit facility — (49,000 ) — — (49,000 ) Proceeds from senior notes 10,000 — 440,000 — 450,000 Proceeds from public offerings 322,680 — — — 322,680 Intercompany transfers (49,000 ) 49,000 — — — Other financing activities (6,126 ) (2,994 ) — — (9,120 ) Net cash provided by financing activities 277,554 56,006 440,000 — 773,560 Net increase in cash and cash equivalents 512 (12,077 ) 762 — (10,803 ) Cash and cash equivalents at beginning of period 14 26,344 — — 26,358 Cash and cash equivalents at end of period $ 526 $ 14,267 $ 762 $ — $ 15,555 |
Supplemental Information on O41
Supplemental Information on Oil and Natural Gas Operations (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Extractive Industries [Abstract] | |
Aggregate capitalized costs related to oil and natural gas production activities | Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, amortization and impairment are as follows: December 31, 2015 2014 (In thousands) Oil and Natural Gas Properties: Proved properties $ 2,848,557 $ 2,345,077 Unproved properties 1,106,816 773,520 Total Oil and Natural Gas Properties 3,955,373 3,118,597 Accumulated depreciation, depletion, amortization (512,144 ) (296,317 ) Accumulated impairment (897,962 ) (83,164 ) Net oil and natural gas properties capitalized $ 2,545,267 $ 2,739,116 |
Costs incurred in oil and natural gas property acquisition, exploration, and development activities | Costs incurred in oil and natural gas property acquisition, exploration and development activities are as follows: Year Ended December 31, 2015 2014 2013 (In thousands) Acquisition costs Proved properties $ 64,340 $ 302,234 $ 339,130 Unproved properties 448,638 601,188 279,402 Development costs 42,749 86,097 88,460 Exploration costs 319,102 475,756 242,929 Capitalized asset retirement costs 3,458 4,962 697 Total $ 878,287 $ 1,470,237 $ 950,618 |
Results of operations from oil and natural gas producing activities | The following schedule sets forth the revenues and expenses related to the production and sale of oil and natural gas. It does not include any interest costs or general and administrative costs and, therefore, is not necessarily indicative of the contribution to consolidated net operating results of our oil, natural gas and natural gas liquids operations. Year Ended December 31, 2015 2014 2013 (In thousands) Oil, natural gas and natural gas liquid sales $ 446,733 $ 495,718 $ 208,002 Lease operating expenses (82,625 ) (55,384 ) (21,157 ) Production and ad valorem taxes (32,990 ) (32,638 ) (12,899 ) Gathering and transportation (6,091 ) (3,288 ) (918 ) Depreciation, depletion, and amortization (216,056 ) (168,674 ) (65,821 ) Impairment (814,798 ) — — Asset retirement obligation accretion expense (833 ) (467 ) (201 ) Income tax expense 201,310 (108,985 ) (31,754 ) Results of operations $ (505,350 ) $ 126,282 $ 75,252 |
Schedule of changes in estimated proved reserves | The following table includes the changes in PUD reserves for 2015 : (MBOE) Beginning proved undeveloped reserves at December 31, 2014 46,348 Undeveloped reserves transferred to developed (13,680 ) Revisions (12,656 ) Extensions and discoveries 44,755 Ending proved undeveloped reserves at December 31, 2015 64,767 The changes in estimated proved reserves are as follows: Oil Natural Gas Natural Gas Proved Developed and Undeveloped Reserves: As of January 1, 2013 26,196,859 8,251,429 34,570,148 Extensions and discoveries 17,041,744 4,597,856 24,184,540 Revisions of previous estimates (5,943,164 ) (3,455,306 ) (5,786,180 ) Purchase of reserves in place 7,328,162 1,672,824 10,441,485 Production (2,022,749 ) (361,079 ) (1,730,497 ) As of December 31, 2013 42,600,852 10,705,724 61,679,496 Extensions and discoveries 37,068,820 7,828,094 52,099,252 Revisions of previous estimates (6,784,560 ) 649,476 (17,726,552 ) Purchase of reserves in place 8,186,053 360,536 19,898,649 Production (5,381,576 ) (1,001,898 ) (4,345,585 ) As of December 31, 2014 75,689,589 18,541,932 111,605,260 Extensions and discoveries 48,725,132 12,055,631 53,452,948 Revisions of previous estimates (12,130,474 ) (4,080,886 ) (14,726,160 ) Purchase of reserves in place 2,775,599 1,165,090 7,101,933 Production (9,081,135 ) (1,677,623 ) (7,931,237 ) As of December 31, 2015 105,978,711 26,004,144 149,502,744 Proved Developed Reserves: January 1, 2013 7,189,367 2,999,440 12,864,941 December 31, 2013 19,789,965 4,973,493 31,428,756 December 31, 2014 43,885,835 11,221,428 68,264,113 December 31, 2015 60,569,398 15,418,353 96,871,109 Proved Undeveloped Reserves: January 1, 2013 19,007,492 5,251,989 21,705,207 December 31, 2013 22,810,887 5,732,231 30,250,740 December 31, 2014 31,803,754 7,320,504 43,341,147 December 31, 2015 45,409,313 10,585,791 52,631,635 |
Standardized measure of discounted future net cash flows attributable to proved crude oil and natural gas reserves | The following table sets forth the standardized measure of discounted future net cash flows attributable to the Company’s proved oil and natural gas reserves as of December 31, 2015 , 2014 and 2013 . December 31, 2015 2014 2013 (In thousands) Future cash inflows $ 5,377,783 $ 7,695,368 $ 4,604,241 Future development costs (548,239 ) (602,438 ) (517,075 ) Future production costs (1,279,101 ) (1,278,487 ) (806,895 ) Future production taxes (363,129 ) (534,851 ) (318,396 ) Future income tax expenses (28,233 ) (672,380 ) (674,260 ) Future net cash flows 3,159,081 4,607,212 2,287,615 10% discount to reflect timing of cash flows (1,740,948 ) (2,561,988 ) (1,311,976 ) Standardized measure of discounted future net cash flows $ 1,418,133 $ 2,045,224 $ 975,639 |
Average first-day-of-the-month price for oil, natural gas and natural gas liquids | In the table below the average first-day-of–the-month price for oil, natural gas and natural gas liquids is presented, all utilized in the computation of future cash inflows. December 31, 2015 2014 2013 Unweighted Arithmetic Average First-Day-of-the-Month Prices Oil (per Bbl) $ 45.07 $ 87.15 $ 92.59 Natural gas (per Mcf) $ 1.83 $ 4.85 $ 4.13 Natural gas liquids (per Bbl) $ 12.56 $ 30.09 $ 37.82 |
Schedule of principal changes in the standardized measure of discounted future net cash flows attributable to proved reserves | Principal changes in the standardized measure of discounted future net cash flows attributable to the Company’s proved reserves are as follows: Year Ended December 31, 2015 2014 2013 (In thousands) Standardized measure of discounted future net cash flows at the beginning of the period $ 2,045,224 $ 975,639 $ 367,220 Sales of oil and natural gas, net of production costs (331,119 ) (404,409 ) (173,946 ) Purchase of minerals in place 57,359 291,807 305,109 Extensions and discoveries, net of future development costs 629,149 1,135,293 552,450 Previously estimated development costs incurred during the period 129,901 111,527 76,631 Net changes in prices and production costs (1,383,698 ) (105,210 ) 51,828 Changes in estimated future development costs 38,638 (4,877 ) (5,822 ) Revisions of previous quantity estimates (377,160 ) (173,004 ) (126,993 ) Accretion of discount 236,716 151,481 57,988 Net change in income taxes 268,963 (12,326 ) (168,570 ) Net changes in timing of production and other 104,160 79,303 39,744 Standardized measure of discounted future net cash flows at the end of the period $ 1,418,133 $ 2,045,224 $ 975,639 |
Quarterly Financial Data (Una42
Quarterly Financial Data (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Quarterly Financial Information Disclosure [Abstract] | |
Schedule of Quarterly Financial Data | The Company’s unaudited quarterly financial data for 2015 and 2014 is summarized below. 2015 First Second Third Fourth Revenues $ 101,401 $ 119,063 $ 111,946 $ 114,323 Income (loss) from operations 1,437 (299,120 ) (254,773 ) (187,813 ) Income tax expense (benefit) 3,370 (116,732 ) (81,461 ) (6,487 ) Net income (loss) 6,439 (211,352 ) (156,042 ) (186,835 ) Less: Net income attributable to noncontrolling interest 590 935 739 574 Net income (loss) attributable to Diamondback Energy, Inc. $ 5,849 $ (212,287 ) $ (156,781 ) $ (187,409 ) Earnings per common share Basic $ 0.10 $ (3.45 ) $ (2.40 ) $ (2.80 ) Diluted $ 0.10 $ (3.45 ) $ (2.40 ) $ (2.80 ) 2014 First Second Third Fourth Revenues $ 98,004 $ 127,004 $ 139,127 $ 131,583 Income from operations 48,063 63,192 63,516 37,899 Income tax expense (benefit) 13,601 15,163 23,978 56,243 Net income 23,589 27,824 44,641 99,917 Less: Net income attributable to noncontrolling interest — 71 902 1,243 Net income attributable to Diamondback Energy, Inc. $ 23,589 $ 27,753 $ 43,739 $ 98,674 Earnings per common share Basic $ 0.49 $ 0.55 $ 0.79 $ 1.74 Diluted $ 0.48 $ 0.54 $ 0.79 $ 1.73 |
Description of the Business a43
Description of the Business and Basis of Presentation (Details) - Viper Energy Partners LP [Member] - shares | Sep. 19, 2014 | Jun. 23, 2014 | Dec. 31, 2015 |
Noncontrolling Interest [Line Items] | |||
Interest in Viper Energy Partners LP | 88.00% | 92.00% | 88.00% |
IPO [Member] | |||
Noncontrolling Interest [Line Items] | |||
Units issued by Viper Energy Partners LP | 5,750,000 | ||
Public Offering [Member] | |||
Noncontrolling Interest [Line Items] | |||
Units issued by Viper Energy Partners LP | 3,500,000 | ||
Limited Partner [Member] | Diamondback Energy, Inc. [Member] | |||
Noncontrolling Interest [Line Items] | |||
Exchange of membership interests for common units | 70,450,000 |
Summary of Significant Accoun44
Summary of Significant Accounting Policies (Details) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015USD ($)$ / Boe | Dec. 31, 2014USD ($)$ / Boe | Dec. 31, 2013USD ($)$ / Boe | |
Accounting Policies [Abstract] | |||
Deposit escrow | $ 500 | ||
Allowance for Doubtful Accounts Receivable, Current | $ 0 | $ 0 | |
Average depletion rate per barrel equivalent unit of production | $ / Boe | 17.84 | 23.79 | 24.63 |
Depreciation, depletion and amortization | $ 216,056 | $ 168,674 | $ 65,821 |
Capitalized costs, proved oil and natural gas properties, net, discount percentage | 10.00% | ||
Impairment of oil and natural gas properties | $ 814,798 | 0 | 0 |
Impairment losses of long-lived assets | 0 | 0 | 0 |
Interest costs capitalized | 5,300 | 4,000 | |
Deferred Finance Costs, Net | 18,249 | 13,802 | |
Debt issuance costs, accumulated amortization | 6,523 | 3,921 | |
Equity method investment impairment | 0 | 0 | 0 |
Unrecognized tax benefits that would have a material impact on the effective rate | 0 | 0 | |
Interest or penalties associated with uncertain tax positions | $ 0 | $ 0 | $ 0 |
Summary of Significant Accoun45
Summary of Significant Accounting Policies - Other Property and Equipment (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Property, Plant and Equipment [Line Items] | |||
Depreciation expense | $ 1,641 | $ 1,331 | $ 776 |
Minimum [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Estimated useful life of property and equipment | 3 years | ||
Maximum [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Estimated useful life of property and equipment | 15 years |
Summary of Significant Accoun46
Summary of Significant Accounting Policies - Inventory (Details) | 12 Months Ended |
Dec. 31, 2015 | |
Tubular Goods and Equipment [Member] | |
Inventory [Line Items] | |
Utilization period | 1 year |
Summary of Significant Accoun47
Summary of Significant Accounting Policies - Other Accrued Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Accounting Policies [Abstract] | |||
Prepaid drilling liability | $ 12,683 | $ 3,758 | |
Interest payable | 8,606 | 8,861 | |
Lease operating expense payable | 14,100 | 11,851 | |
Taxes payable | 518 | 9,952 | |
Current portion of asset retirement obligations | 193 | 39 | $ 40 |
Other | 8,193 | 6,688 | |
Total other accrued liabilities | $ 44,293 | $ 41,149 |
Summary of Significant Accoun48
Summary of Significant Accounting Policies - Concentrations (Details) - Customer Concentration Risk [Member] - Sales Revenue, Net [Member] | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Shell Trading US Company [Member] | |||
Concentration Risk [Line Items] | |||
Concentration Risk, Percentage | 59.00% | 64.00% | 37.00% |
Enterprise Crude Oil LLC [Member] | |||
Concentration Risk [Line Items] | |||
Concentration Risk, Percentage | 15.00% | 16.00% | |
Plains Marketing, L.P. [Member] | |||
Concentration Risk [Line Items] | |||
Concentration Risk, Percentage | 37.00% |
Acquisitions - 2015 Activity (D
Acquisitions - 2015 Activity (Details) $ in Thousands | Jul. 09, 2015USD ($) | Dec. 31, 2015USD ($)a |
Permian Basin [Member] | Oil and Gas Interest in Permian Basin Acquired in 2015 [Member] | ||
Business Acquisition [Line Items] | ||
Gas and Oil Area, Developed, Gross | a | 16,940 | |
Gas and Oil Area, Developed, Net | a | 12,672 | |
Business Combination, Consideration Transferred | $ | $ 437,455 | |
Viper Energy Partners LP [Member] | Howard County, Texas [Member] | ||
Business Acquisition [Line Items] | ||
Oil and Gas Property, Percent of Royalty Interest Sold | 1.50% | |
Proceeds from Sale of Oil and Gas Property and Equipment | $ | $ 31,100 |
Acquisitions - 2014 Activity (D
Acquisitions - 2014 Activity (Details) | Sep. 09, 2014USD ($)a | Aug. 25, 2014USD ($)a | Feb. 28, 2014USD ($)a | Sep. 30, 2013USD ($) | Dec. 31, 2014USD ($)a | Dec. 31, 2014USD ($)a | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($)a | Dec. 31, 2013USD ($) |
Business Acquisition [Line Items] | |||||||||
Payments to acquire leasehold interests | $ 437,455,000 | $ 845,826,000 | $ 177,343,000 | ||||||
Payments to acquire surface rights | 1,213,000 | 44,213,000 | 2,234,000 | ||||||
Payments to acquire mineral interests | $ 43,907,000 | 57,689,000 | $ 444,083,000 | ||||||
Permian Basin [Member] | |||||||||
Business Acquisition [Line Items] | |||||||||
Payments to acquire leasehold interests | $ 165,000,000 | ||||||||
Surface rights area (in acres) | a | 4,200 | ||||||||
Payments to acquire surface rights | $ 41,900,000 | ||||||||
Viper Energy Partners LP [Member] | |||||||||
Business Acquisition [Line Items] | |||||||||
Cost method investment | $ 33,900,000 | $ 33,900,000 | $ 33,900,000 | ||||||
Viper Energy Partners LP [Member] | Midland and Delaware Basin [Member] | |||||||||
Business Acquisition [Line Items] | |||||||||
Mineral Interest Area, Developed, Gross | a | 10,364 | 10,364 | 10,364 | ||||||
Mineral Interest, Area, Developed, Net | a | 3,261 | 3,261 | 3,261 | ||||||
Payments to acquire mineral interests | $ 57,700,000 | ||||||||
Oil and Gas Interest in Permian Basin Acquired in September 2014 [Member] | Permian Basin [Member] | |||||||||
Business Acquisition [Line Items] | |||||||||
Acres of oil and gas property, working interest, gross | a | 17,617 | ||||||||
Acres of oil and gas property, working interest, net | a | 12,967 | ||||||||
Percent of working interest | 74.00% | ||||||||
Percent of net revenue interest | 75.00% | ||||||||
Payments to acquire leasehold interests | $ 523,260,000 | ||||||||
Goodwill acquired | 0 | ||||||||
Bargain purchase gain | $ 0 | ||||||||
Revenues included in consolidated statements of operations since acquisition date | $ 12,327,000 | ||||||||
Direct operating expenses included in consolidated statements of operations since acquisition date | $ 4,565,000 | ||||||||
Oil and Gas Interest in Permian Basin Acquired in February 2014 [Member] | Permian Basin [Member] | |||||||||
Business Acquisition [Line Items] | |||||||||
Acres of oil and gas property, working interest, gross | a | 6,450 | ||||||||
Percent of working interest | 74.00% | ||||||||
Percent of net revenue interest | 56.00% | ||||||||
Payments to acquire leasehold interests | $ 292,159,000 | ||||||||
Goodwill acquired | 0 | ||||||||
Bargain purchase gain | $ 0 | ||||||||
Revenues included in consolidated statements of operations since acquisition date | $ 40,500,000 | ||||||||
Direct operating expenses included in consolidated statements of operations since acquisition date | $ 7,800,000 | ||||||||
Mineral Interest, Area, Developed, Net | a | 4,785 |
Acquisitions - Estimated Fair V
Acquisitions - Estimated Fair Values of Assets Acquired and Liabilities Assumed (Details) - Permian Basin [Member] - USD ($) $ in Thousands | Sep. 09, 2014 | Feb. 28, 2014 |
Oil and Gas Interest in Permian Basin Acquired in September 2014 [Member] | ||
Business Acquisition [Line Items] | ||
Joint interest receivables | $ 42 | |
Proved oil and gas properties | 128,589 | |
Unevaluated oil and natural gas properties | 400,527 | |
Total assets acquired | 529,158 | |
Accrued production and ad valorem taxes | 358 | |
Revenues payable | 3,174 | |
Asset retirement obligations | 2,366 | |
Total liabilities assumed | 5,898 | |
Total fair value of net assets | $ 523,260 | |
Oil and Gas Interest in Permian Basin Acquired in February 2014 [Member] | ||
Business Acquisition [Line Items] | ||
Proved oil and gas properties | $ 170,174 | |
Unevaluated oil and natural gas properties | 123,243 | |
Total assets acquired | 293,417 | |
Asset retirement obligations | 1,258 | |
Total liabilities assumed | 1,258 | |
Total fair value of net assets | $ 292,159 |
Acquisitions - Pro Forma Financ
Acquisitions - Pro Forma Financial Information (Details) - Oil and Gas Interest in Permian Basin Acquired in 2014 [Member] - Permian Basin [Member] - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2014 | Dec. 31, 2013 | |
Business Acquisition [Line Items] | ||
Revenues | $ 541,103 | $ 315,736 |
Income from operations | 224,382 | 146,429 |
Net income | $ 201,257 | $ 86,277 |
Acquisitions - 2013 Activity (D
Acquisitions - 2013 Activity (Details) $ in Thousands | Sep. 26, 2013a | Sep. 19, 2013USD ($)a | Sep. 04, 2013a | Sep. 30, 2013USD ($)leasehold_interest | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) |
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | |||||||
Payments to acquire leasehold interests | $ | $ 437,455 | $ 845,826 | $ 177,343 | ||||
Payments to acquire mineral interests | $ | $ 43,907 | $ 57,689 | $ 444,083 | ||||
Permian Basin [Member] | |||||||
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | |||||||
Number of leasehold interest acquisitions | leasehold_interest | 2 | ||||||
Payments to acquire leasehold interests | $ | $ 165,000 | ||||||
Martin County, Texas [Member] | |||||||
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | |||||||
Percent of working interest | 100.00% | ||||||
Percent of net revenue interest | 80.00% | ||||||
Acres of oil and gas property, working interest, gross | 4,506 | ||||||
Acres of oil and gas property, working interest, net | 4,506 | ||||||
Dawson County, Texas [Member] | |||||||
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | |||||||
Percent of working interest | 71.00% | ||||||
Percent of net revenue interest | 55.00% | ||||||
Acres of oil and gas property, working interest, gross | 9,390 | ||||||
Acres of oil and gas property, working interest, net | 6,638 | ||||||
Midland County, Texas [Member] | |||||||
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | |||||||
Acres of oil and gas property, mineral interest, gross | 14,804 | ||||||
Acres of oil and gas property, mineral interest, net | 12,687 | ||||||
Percent of royalty interest | 21.40% | ||||||
Payments to acquire mineral interests | $ | $ 440,000 |
Viper Energy Partners LP (Detai
Viper Energy Partners LP (Details) - Viper Energy Partners LP [Member] - USD ($) $ / shares in Units, $ in Thousands | Sep. 19, 2014 | Jun. 23, 2014 | Dec. 31, 2015 | Dec. 31, 2014 |
Noncontrolling Interest [Line Items] | ||||
Interest in Viper Energy Partners LP | 88.00% | 92.00% | 88.00% | |
IPO [Member] | ||||
Noncontrolling Interest [Line Items] | ||||
Units issued by Viper Energy Partners LP | 5,750,000 | |||
Noncontrolling owners' interest in Viper Energy Partners LP | 8.00% | |||
Price per common unit (in dollars per unit) | $ 26 | |||
Proceeds from sale of common units, net of offering expenses and underwriting discounts and commissions | $ 137,238 | |||
Over-Allotment Option [Member] | ||||
Noncontrolling Interest [Line Items] | ||||
Units issued by Viper Energy Partners LP | 750,000 | |||
Public Offering [Member] | ||||
Noncontrolling Interest [Line Items] | ||||
Units issued by Viper Energy Partners LP | 3,500,000 | |||
Price per common unit (in dollars per unit) | $ 28.50 | |||
Proceeds from sale of common units, net of offering expenses and underwriting discounts and commissions | $ 94,800 | |||
Diamondback Energy, Inc. [Member] | ||||
Noncontrolling Interest [Line Items] | ||||
Distribution payable | $ 11,300 | |||
Diamondback Energy, Inc. [Member] | Limited Partner [Member] | ||||
Noncontrolling Interest [Line Items] | ||||
Exchange of membership interests for common units | 70,450,000 | |||
Cash distributions | $ 60,600 | $ 148,800 |
Property and Equipment (Details
Property and Equipment (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Oil and Natural Gas Properties: | |||
Subject to depletion | $ 2,848,557 | $ 2,345,077 | |
Not subject to depletion-acquisition costs | 1,106,816 | 773,520 | |
Gross oil and natural gas properties | 3,955,373 | 3,118,597 | |
Accumulated depletion | 512,144 | 296,317 | |
Accumulated impairment | 897,962 | 83,164 | |
Oil and natural gas properties, net | 2,545,267 | 2,739,116 | |
Pipeline and gas gathering assets, net | 7,174 | 7,174 | |
Other property and equipment, net | 48,621 | 48,180 | |
Accumulated depreciation | (1,413,543) | (382,144) | |
Property and equipment, net of accumulated depreciation, depletion, amortization and impairment | 2,597,625 | 2,791,807 | |
Capitalized general and administrative costs | $ 15,210 | 11,411 | $ 5,348 |
Capitalized costs, proved oil and natural gas properties, net, discount percentage | 10.00% | ||
Impairment of oil and natural gas properties | $ 814,798 | 0 | $ 0 |
Incurred in 2015 | |||
Oil and Natural Gas Properties: | |||
Not subject to depletion-acquisition costs | 433,769 | 0 | |
Incurred in 2014 | |||
Oil and Natural Gas Properties: | |||
Not subject to depletion-acquisition costs | 543,399 | 576,802 | |
Incurred in 2013 | |||
Oil and Natural Gas Properties: | |||
Not subject to depletion-acquisition costs | 68,351 | 130,474 | |
Incurred in 2012 | |||
Oil and Natural Gas Properties: | |||
Not subject to depletion-acquisition costs | 61,297 | 65,480 | |
Incurred in 2011 | |||
Oil and Natural Gas Properties: | |||
Not subject to depletion-acquisition costs | $ 0 | 764 | |
Minimum [Member] | |||
Oil and Natural Gas Properties: | |||
Number of years until unevaluated properties are included in full cost pool | 3 years | ||
Maximum [Member] | |||
Oil and Natural Gas Properties: | |||
Number of years until unevaluated properties are included in full cost pool | 5 years | ||
Other Property and Equipment, Net [Member] | |||
Oil and Natural Gas Properties: | |||
Accumulated depreciation | $ (3,437) | $ (2,663) |
Asset Retirement Obligations (D
Asset Retirement Obligations (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Changes in ARO liability | |||
Asset retirement obligation, beginning of period | $ 8,486 | $ 3,029 | $ 2,145 |
Additional liability incurred | 594 | 703 | 226 |
Liabilities acquired | 3,159 | 3,726 | 471 |
Liabilities settled | (292) | (27) | (14) |
Accretion expense | 833 | 467 | 201 |
Revisions in estimated liabilities | (69) | 588 | 0 |
Asset retirement obligation, end of period | 12,711 | 8,486 | 3,029 |
Less current portion | 193 | 39 | 40 |
Asset retirement obligations - long-term | $ 12,518 | $ 8,447 | $ 2,989 |
Equity Method Investments (Deta
Equity Method Investments (Details) - USD ($) $ in Thousands | 1 Months Ended | 12 Months Ended | ||
Oct. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Schedule of Equity Method Investments | ||||
Payment to acquire equity method investment | $ 600 | $ 2,702 | $ 34,477 | $ 0 |
Ownership interest | 25.00% | |||
Aggregate cost of equity method investment | 5,000 | |||
Third Party Investors [Member] | ||||
Schedule of Equity Method Investments | ||||
Aggregate cost of equity method investment | $ 15,000 |
Debt - Long-term Debt (Details)
Debt - Long-term Debt (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Debt Instrument [Line Items] | ||
Long-term Debt | $ 495,500 | $ 673,500 |
Revolving Credit Facility [Member] | ||
Debt Instrument [Line Items] | ||
Long-term Debt | 11,000 | 223,500 |
Senior Notes [Member] | Senior Unsecured Notes due 2021 [Member] | ||
Debt Instrument [Line Items] | ||
Long-term Debt | 450,000 | 450,000 |
Viper Energy Partners LP [Member] | Revolving Credit Facility [Member] | ||
Debt Instrument [Line Items] | ||
Long-term Debt | $ 34,500 | $ 0 |
Debt - Senior Notes (Details)
Debt - Senior Notes (Details) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Sep. 19, 2013a | Sep. 18, 2013USD ($) | |
Senior Notes [Member] | Senior Unsecured Notes due 2021 [Member] | ||||
Debt Instrument [Line Items] | ||||
Aggregate principal amount | $ | $ 450,000 | |||
Stated interest rate | 7.625% | 7.625% | 7.625% | |
Senior Notes [Member] | Senior Unsecured Notes due 2021 [Member] | 12-month period beginning October 1, 2016 [Member] | ||||
Debt Instrument [Line Items] | ||||
Redemption price, expressed as percentage of principal amount | 105.719% | |||
Senior Notes [Member] | Senior Unsecured Notes due 2021 [Member] | 12-month period beginning October 1, 2017 [Member] | ||||
Debt Instrument [Line Items] | ||||
Redemption price, expressed as percentage of principal amount | 103.813% | |||
Senior Notes [Member] | Senior Unsecured Notes due 2021 [Member] | 12-month period beginning October 1, 2018 [Member] | ||||
Debt Instrument [Line Items] | ||||
Redemption price, expressed as percentage of principal amount | 101.906% | |||
Senior Notes [Member] | Senior Unsecured Notes due 2021 [Member] | 12-month period beginning October 1, 2019 and thereafter [Member] | ||||
Debt Instrument [Line Items] | ||||
Redemption price, expressed as percentage of principal amount | 100.00% | |||
Make-whole premium option [Member] | Senior Notes [Member] | Senior Unsecured Notes due 2021 [Member] | Period prior to October 1, 2016 [Member] | ||||
Debt Instrument [Line Items] | ||||
Redemption price, expressed as percentage of principal amount | 100.00% | |||
Net cash proceeds of certain equity offerings [Member] | Senior Notes [Member] | Senior Unsecured Notes due 2021 [Member] | Period prior to October 1, 2016 [Member] | ||||
Debt Instrument [Line Items] | ||||
Redemption price, expressed as percentage of principal amount | 107.625% | |||
Maximum percent of aggregate principal amount redeemable | 35.00% | |||
Minimum required principal amount to remain outstanding subsequent to redemption | 65.00% | |||
Number of days within closing date redemption can occur | 120 days | |||
Midland County, Texas [Member] | ||||
Debt Instrument [Line Items] | ||||
Acres of oil and gas property, mineral interest, gross | 14,804 | |||
Acres of oil and gas property, mineral interest, net | 12,687 |
Debt - The Company's Credit Fac
Debt - The Company's Credit Facility (Details) | 12 Months Ended | ||
Dec. 31, 2015USD ($)redetermindation | Dec. 31, 2014USD ($) | Nov. 02, 2013USD ($) | |
Line of Credit Facility [Line Items] | |||
Debt outstanding | $ 495,500,000 | $ 673,500,000 | |
Revolving Credit Facility [Member] | |||
Line of Credit Facility [Line Items] | |||
Debt outstanding | 11,000,000 | 223,500,000 | |
Senior Unsecured Notes due 2021 [Member] | Senior Notes [Member] | |||
Line of Credit Facility [Line Items] | |||
Debt outstanding | $ 450,000,000 | $ 450,000,000 | |
Revolving Credit Facility [Member] | |||
Line of Credit Facility [Line Items] | |||
Maximum borrowing capacity | $ 2,000,000,000 | ||
Number of additional redeterminations that may be requested | redetermindation | 3 | ||
Period of Redeterminations | 12 months | ||
Current borrowing base | $ 750,000,000 | ||
Elected borrowing base | 500,000,000 | ||
Financial covenant, maximum issuance of unsecured debt | $ 750,000,000 | ||
Financial covenant, reduction of borrowing base | 25.00% | ||
Revolving Credit Facility [Member] | Minimum [Member] | |||
Line of Credit Facility [Line Items] | |||
Quarterly commitment fee percentage based on unused portion of borrowing base | 0.375% | ||
Revolving Credit Facility [Member] | Maximum [Member] | |||
Line of Credit Facility [Line Items] | |||
Quarterly commitment fee percentage based on unused portion of borrowing base | 0.50% | ||
Revolving Credit Facility [Member] | Base Rate [Member] | Minimum [Member] | |||
Line of Credit Facility [Line Items] | |||
Basis spread on variable rate | 0.50% | ||
Revolving Credit Facility [Member] | Base Rate [Member] | Maximum [Member] | |||
Line of Credit Facility [Line Items] | |||
Basis spread on variable rate | 1.50% | ||
Revolving Credit Facility [Member] | Federal Funds Rate [Member] | |||
Line of Credit Facility [Line Items] | |||
Basis spread on variable rate | 0.50% | ||
Revolving Credit Facility [Member] | LIBOR, 3-month [Member] | |||
Line of Credit Facility [Line Items] | |||
Basis spread on variable rate | 1.00% | ||
Revolving Credit Facility [Member] | LIBOR [Member] | Minimum [Member] | |||
Line of Credit Facility [Line Items] | |||
Basis spread on variable rate | 1.50% | ||
Revolving Credit Facility [Member] | LIBOR [Member] | Maximum [Member] | |||
Line of Credit Facility [Line Items] | |||
Basis spread on variable rate | 2.50% |
Debt - The Partnership's Credit
Debt - The Partnership's Credit Facility (Details) | 12 Months Ended | |||||
Dec. 31, 2015USD ($)redetermindation | Sep. 30, 2015USD ($) | May. 21, 2015USD ($) | Dec. 31, 2014USD ($) | Jul. 08, 2014USD ($) | Nov. 02, 2013USD ($) | |
Line of Credit Facility [Line Items] | ||||||
Long-term Debt | $ 495,500,000 | $ 673,500,000 | ||||
Revolving Credit Facility [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Maximum borrowing capacity | $ 2,000,000,000 | |||||
Number of additional redeterminations that may be requested | redetermindation | 3 | |||||
Period of Redeterminations | 12 months | |||||
Current borrowing base | $ 750,000,000 | |||||
Financial covenant, maximum issuance of unsecured debt | $ 750,000,000 | |||||
Financial covenant, reduction of borrowing base | 25.00% | |||||
Viper Energy Partners LP [Member] | Wells Fargo [Member] | Revolving Credit Facility [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Maximum borrowing capacity | $ 500,000,000 | |||||
Number of additional redeterminations that may be requested | redetermindation | 3 | |||||
Period of Redeterminations | 12 months | |||||
Current borrowing base | $ 200,000,000 | $ 175,000,000 | $ 110,000,000 | |||
Financial covenant, maximum issuance of unsecured debt | $ 250,000,000 | |||||
Financial covenant, reduction of borrowing base | 25.00% | |||||
Federal Funds Rate [Member] | Revolving Credit Facility [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Basis spread on variable rate | 0.50% | |||||
Federal Funds Rate [Member] | Viper Energy Partners LP [Member] | Wells Fargo [Member] | Revolving Credit Facility [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Basis spread on variable rate | 0.50% | |||||
LIBOR, 3-month [Member] | Revolving Credit Facility [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Basis spread on variable rate | 1.00% | |||||
LIBOR, 3-month [Member] | Viper Energy Partners LP [Member] | Wells Fargo [Member] | Revolving Credit Facility [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Basis spread on variable rate | 1.00% | |||||
Minimum [Member] | Revolving Credit Facility [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Quarterly commitment fee percentage based on unused portion of borrowing base | 0.375% | |||||
Minimum [Member] | Viper Energy Partners LP [Member] | Wells Fargo [Member] | Revolving Credit Facility [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Quarterly commitment fee percentage based on unused portion of borrowing base | 0.375% | |||||
Minimum [Member] | Base Rate [Member] | Revolving Credit Facility [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Basis spread on variable rate | 0.50% | |||||
Minimum [Member] | Base Rate [Member] | Viper Energy Partners LP [Member] | Wells Fargo [Member] | Revolving Credit Facility [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Basis spread on variable rate | 0.50% | |||||
Minimum [Member] | LIBOR [Member] | Revolving Credit Facility [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Basis spread on variable rate | 1.50% | |||||
Minimum [Member] | LIBOR [Member] | Viper Energy Partners LP [Member] | Wells Fargo [Member] | Revolving Credit Facility [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Basis spread on variable rate | 1.50% | |||||
Maximum [Member] | Revolving Credit Facility [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Quarterly commitment fee percentage based on unused portion of borrowing base | 0.50% | |||||
Maximum [Member] | Viper Energy Partners LP [Member] | Wells Fargo [Member] | Revolving Credit Facility [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Quarterly commitment fee percentage based on unused portion of borrowing base | 0.50% | |||||
Maximum [Member] | Base Rate [Member] | Revolving Credit Facility [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Basis spread on variable rate | 1.50% | |||||
Maximum [Member] | Base Rate [Member] | Viper Energy Partners LP [Member] | Wells Fargo [Member] | Revolving Credit Facility [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Basis spread on variable rate | 1.50% | |||||
Maximum [Member] | LIBOR [Member] | Revolving Credit Facility [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Basis spread on variable rate | 2.50% | |||||
Maximum [Member] | LIBOR [Member] | Viper Energy Partners LP [Member] | Wells Fargo [Member] | Revolving Credit Facility [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Basis spread on variable rate | 2.50% | |||||
Revolving Credit Facility [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Long-term Debt | $ 11,000,000 | 223,500,000 | ||||
Revolving Credit Facility [Member] | Viper Energy Partners LP [Member] | ||||||
Line of Credit Facility [Line Items] | ||||||
Long-term Debt | $ 34,500,000 | $ 0 |
Debt - Financial Covenant Table
Debt - Financial Covenant Table (Details) - Revolving Credit Facility [Member] | Dec. 31, 2015 |
Maximum [Member] | |
Line of Credit Facility [Line Items] | |
Ratio of total debt to EBITDAX | 4 |
Maximum [Member] | Viper Energy Partners LP [Member] | Wells Fargo [Member] | |
Line of Credit Facility [Line Items] | |
Ratio of total debt to EBITDAX | 4 |
Minimum [Member] | |
Line of Credit Facility [Line Items] | |
Ratio of current assets to liabilities, as defined in the credit agreement | 1 |
Minimum [Member] | Viper Energy Partners LP [Member] | Wells Fargo [Member] | |
Line of Credit Facility [Line Items] | |
Ratio of current assets to liabilities, as defined in the credit agreement | 1 |
Debt - Interest Expense (Detail
Debt - Interest Expense (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Debt Disclosure [Abstract] | |||
Interest expense | $ 40,221 | $ 36,669 | $ 10,322 |
Less capitalized interest | 0 | (5,275) | (3,951) |
Other fees and expenses | 1,292 | 3,121 | 1,688 |
Total interest expense | $ 41,513 | $ 34,515 | $ 8,059 |
Capital Stock and Earnings Pe64
Capital Stock and Earnings Per Share - Capital Stock (Details) - Common Stock [Member] - USD ($) $ / shares in Units, $ in Thousands | 1 Months Ended | ||||||
Aug. 31, 2015 | May. 31, 2015 | Jan. 31, 2015 | Jul. 31, 2014 | Feb. 28, 2014 | Aug. 31, 2013 | May. 31, 2013 | |
Class of Stock [Line Items] | |||||||
Shares issued upon public offering | 2,875,000 | 4,600,000 | 2,012,500 | 5,750,000 | 3,450,000 | 4,600,000 | 5,175,000 |
Common stock issued pursuant to underwriters over allotment option | 375,000 | 600,000 | 262,500 | 750,000 | 450,000 | 600,000 | 675,000 |
Stock price per share at public offering (in dollars per share) | $ 68.74 | $ 72.53 | $ 59.34 | $ 87 | $ 62.67 | $ 40.25 | $ 29.25 |
Net proceeds received from public offering | $ 197,628 | $ 333,638 | $ 119,422 | $ 485,000 | $ 208,445 | $ 177,500 | $ 144,439 |
Capital Stock and Earnings Pe65
Capital Stock and Earnings Per Share - Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Basic: | |||||||||||
Net Income (Loss) Attributable to Parent | $ (187,409) | $ (156,781) | $ (212,287) | $ 5,849 | $ 98,674 | $ 43,739 | $ 27,753 | $ 23,589 | $ (550,628) | $ 193,755 | $ 54,587 |
Weighted Average Number of Shares Outstanding, Basic | 63,019 | 52,826 | 42,015 | ||||||||
Net income attributable to common stock, basic, (in dollars per share) | $ (2.80) | $ (2.40) | $ (3.45) | $ 0.10 | $ 1.74 | $ 0.79 | $ 0.55 | $ 0.49 | $ (8.74) | $ 3.67 | $ 1.30 |
Effect of Dilutive Securities: | |||||||||||
Dilutive effect of potential common shares issuable | $ 0 | $ 0 | $ 0 | ||||||||
Dilutive effect of potential common shares issuable (in shares) | 0 | 471 | 240 | ||||||||
Diluted: | |||||||||||
Net income attributable to common stock, diluted | $ (550,628) | $ 193,755 | $ 54,587 | ||||||||
Net income attributable to common stock, diluted (in shares) | 63,019 | 53,297 | 42,255 | ||||||||
Net income attributable to common stock, diluted (in dollars per share) | $ (2.80) | $ (2.40) | $ (3.45) | $ 0.10 | $ 1.73 | $ 0.79 | $ 0.54 | $ 0.48 | $ (8.74) | $ 3.64 | $ 1.29 |
Antidilutive securities excluded from earnings per share (in shares) | 101 |
Equity-Based Compensation - Add
Equity-Based Compensation - Additional Disclosures (Details) - shares | Jun. 17, 2014 | Dec. 31, 2015 | Oct. 10, 2012 |
2012 Plan [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Shares of common stock reserved for issuance | 2,500,000 | ||
2012 Plan [Member] | Stock/Unit Options [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Vesting, number of annual installments | 4 years | ||
Exercisable period from original date of grant | 5 years | ||
Viper Energy Partners LP [Member] | Viper LTIP [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Shares of common stock reserved for issuance | 9,144,000 | ||
Options granted (shares) | 0 | ||
Executive Officers of General Partner [Member] | Viper Energy Partners LP [Member] | Viper LTIP [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Options granted (shares) | 2,500,000 | ||
Executive Officers of General Partner [Member] | Viper Energy Partners LP [Member] | Viper LTIP [Member] | Stock/Unit Options [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Award vesting percentage | 33.00% |
Equity-Based Compensation - Sch
Equity-Based Compensation - Schedule of Stock-Based Compensation Plans and Related Costs (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Equity-based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties | $ 6,043 | $ 4,437 | $ 972 |
Related income tax benefit | 0 | 0 | 704 |
General and Administrative Expense [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Stock and equity based compensation | $ 18,529 | $ 9,816 | $ 1,752 |
Equity-Based Compensation - Val
Equity-Based Compensation - Valuation Assumptions (Details) - $ / shares | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Stock/Unit Options [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Grant-date fair value, stock/unit options (in dollars per share) | $ 6.51 | ||
Expected volatility | 36.90% | ||
Expected dividend yield | 0.00% | ||
Expected term (in years) | 3 years 9 months 18 days | ||
Risk-free rate | 0.57% | ||
Performance Restricted Stock Units [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Grant-date fair value, performance restricted stock units (in dollars per share) | $ 137.14 | $ 125.63 | |
Expected volatility | 43.36% | 39.60% | |
Risk-free rate | 0.49% | 0.30% | |
Viper LTIP [Member] | Viper Energy Partners LP [Member] | Stock/Unit Options [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Grant-date fair value, stock/unit options (in dollars per share) | $ 4.24 | ||
Expected volatility | 36.00% | ||
Expected dividend yield | 5.90% | ||
Expected term (in years) | 3 years | ||
Risk-free rate | 0.99% |
Equity-Based Compensation - Sto
Equity-Based Compensation - Stock/Unit Option Activity (Details) - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Number of Options (in shares) | |||
Outstanding, beginning of period | 313,105 | ||
Exercised | 273,605 | ||
Outstanding, end of period | 39,500 | 313,105 | |
Vested and expected to vest, at period end | 39,500 | ||
Exercisable, at period end | 8,000 | ||
Weighted Average Exercise Price (in dollars per share) | |||
Outstanding, beginning of period | $ 18.29 | ||
Exercised | 17.80 | ||
Outstanding, end of period | 21.66 | $ 18.29 | |
Vested and expected to vest, period end | 21.66 | ||
Exercisable, period end | $ 17.50 | ||
Outstanding, period end, remaining term | 1 year 9 months 29 days | ||
Vested and expected to vest, period end, remaining term | 1 year 9 months 29 days | ||
Exercisable, period end, remaining term | 9 months 11 days | ||
Outstanding, period end, intrinsic value | $ 1,787 | ||
Vested and expected to vest, period end, intrinsic value | 1,787 | ||
Exercisable, period end, intrinsic value | 395 | ||
Options exercised, intrinsic value | 15,700 | $ 22,000 | $ 5,700 |
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized [Abstract] | |||
Unrecognized compensation cost related to unvested stock options | $ 100 | ||
Stock/Unit Options [Member] | |||
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized [Abstract] | |||
Unrecognized compensation cost, period of recognition | 1 year 1 month 6 days | ||
Viper LTIP [Member] | Viper Energy Partners LP [Member] | |||
Number of Options (in shares) | |||
Outstanding, beginning of period | 2,500,000 | ||
Granted | 0 | ||
Outstanding, end of period | 2,500,000 | 2,500,000 | |
Vested and expected to vest, at period end | 2,500,000 | ||
Exercisable, at period end | 0 | ||
Weighted Average Exercise Price (in dollars per share) | |||
Outstanding, beginning of period | $ 26 | ||
Granted | 0 | ||
Outstanding, end of period | 0 | $ 26 | |
Vested and expected to vest, period end | 0 | ||
Exercisable, period end | $ 0 | ||
Outstanding, period end, remaining term | 1 year 6 months | ||
Vested and expected to vest, period end, remaining term | 1 year 6 months | ||
Exercisable, period end, remaining term | 0 years | ||
Outstanding, period end, intrinsic value | $ 0 | ||
Vested and expected to vest, period end, intrinsic value | 0 | ||
Exercisable, period end, intrinsic value | 0 | ||
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized [Abstract] | |||
Unrecognized compensation cost related to unvested stock options | $ 5,172 | ||
Viper LTIP [Member] | Viper Energy Partners LP [Member] | Stock/Unit Options [Member] | |||
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized [Abstract] | |||
Unrecognized compensation cost, period of recognition | 1 year 6 months |
Equity-Based Compensation - Res
Equity-Based Compensation - Restricted Stock (Details) - USD ($) $ / shares in Units, $ in Thousands | 1 Months Ended | 12 Months Ended | |||||
Feb. 28, 2015 | Feb. 28, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Oct. 10, 2012 | ||
Restricted Stock Units (RSUs) [Member] | |||||||
Weighted Average Grant-Date Fair Value (in dollars per share) | |||||||
Aggregate fair value of share-based awards that vested | $ 10,100 | $ 8,200 | $ 3,300 | ||||
Unrecognized compensation cost related to unvested awards | $ 6,000 | ||||||
Unrecognized compensation cost, period of recognition | 1 year 6 months 26 days | ||||||
Performance Shares [Member] | |||||||
Awards & Units (in shares) | |||||||
Granted | 90,249 | 79,150 | |||||
Weighted Average Grant-Date Fair Value (in dollars per share) | |||||||
Granted | $ 137.14 | $ 125.63 | |||||
Unrecognized compensation cost related to unvested awards | $ 6,500 | ||||||
Unrecognized compensation cost, period of recognition | 1 year | ||||||
Performance shares, performance period | 3 years | ||||||
Maximum number of units that could be awarded | 180,498 | ||||||
Minimum [Member] | Performance Shares [Member] | |||||||
Weighted Average Grant-Date Fair Value (in dollars per share) | |||||||
Number of shares authorized to be awarded, percent of initial awards received | 0.00% | 0.00% | |||||
Maximum [Member] | Performance Shares [Member] | |||||||
Weighted Average Grant-Date Fair Value (in dollars per share) | |||||||
Number of shares authorized to be awarded, percent of initial awards received | 200.00% | 200.00% | |||||
2012 Plan [Member] | |||||||
Weighted Average Grant-Date Fair Value (in dollars per share) | |||||||
Maximum number of units that could be awarded | 2,500,000 | ||||||
2012 Plan [Member] | Restricted Stock Units (RSUs) [Member] | |||||||
Awards & Units (in shares) | |||||||
Unvested at beginning of period | 167,291 | ||||||
Granted | 138,534 | ||||||
Vested | (143,956) | ||||||
Forfeited | (2,110) | ||||||
Unvested at end of period | 159,759 | 167,291 | |||||
Weighted Average Grant-Date Fair Value (in dollars per share) | |||||||
Unvested at beginning of period | $ 49.99 | ||||||
Granted | 68.54 | ||||||
Vested | 42.58 | ||||||
Forfeited | 74.14 | ||||||
Unvested at end of period | $ 64.66 | $ 49.99 | |||||
2012 Plan [Member] | Performance Shares [Member] | |||||||
Awards & Units (in shares) | |||||||
Unvested at beginning of period | 79,150 | ||||||
Granted | 90,249 | ||||||
Vested | (79,150) | ||||||
Unvested at end of period | 90,249 | [1] | 79,150 | ||||
Weighted Average Grant-Date Fair Value (in dollars per share) | |||||||
Unvested at beginning of period | $ 125.63 | ||||||
Granted | 137.14 | ||||||
Vested | 125.63 | ||||||
Unvested at end of period | $ 137.14 | $ 125.63 | |||||
[1] | A maximum of 180,498 units could be awarded based upon the Company’s final TSR ranking. |
Equity-Based Compensation - Pha
Equity-Based Compensation - Phantom Units (Details) - Viper Energy Partners LP [Member] - Viper LTIP [Member] - Phantom Units [Member] $ / shares in Units, $ in Thousands | 12 Months Ended |
Dec. 31, 2015USD ($)$ / sharesshares | |
Awards & Units (in shares) | |
Unvested at beginning of period | shares | 17,776 |
Granted | shares | 24,690 |
Vested | shares | (17,118) |
Unvested at end of period | shares | 25,348 |
Weighted Average Grant-Date Fair Value (in dollars per share) | |
Unvested at beginning of period | $ / shares | $ 19.51 |
Granted | $ / shares | 15.48 |
Vested | $ / shares | 17.57 |
Unvested at end of period | $ / shares | $ 16.89 |
Aggregate fair value of share-based awards that vested | $ | $ 301 |
Unrecognized compensation cost related to unvested awards | $ | $ 302 |
Unrecognized compensation cost, period of recognition | 1 year 2 months 9 days |
Related Party Transactions (Det
Related Party Transactions (Details) - Affiliated Entity, Wexford [Member] | Dec. 31, 2015 | Oct. 17, 2012 |
Related Party Transaction | ||
Affiliate Beneficial Ownership Percentage | 44.00% | |
Maximum [Member] | ||
Related Party Transaction | ||
Affiliate Beneficial Ownership Percentage | 1.00% |
Related Party Transactions - Ad
Related Party Transactions - Administrative Services (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Related Party Transaction | |||
Accounts payable-related party | $ 217 | $ 0 | |
Subsidiary of Common Parent [Member] | |||
Related Party Transaction | |||
Initial term of the additional shared services agreement | 2 years | ||
Related party incurred costs | $ 207 | ||
Accounts payable-related party | 0 | ||
Affiliated Entity [Member] | |||
Related Party Transaction | |||
Initial term of the additional shared services agreement | 2 years | ||
Agreement termination, written notice period | 30 days | ||
Reimbursement from affiliate | 121 | 1,077 | |
Amount owed by affiliate | 0 | ||
Maximum [Member] | Subsidiary of Common Parent [Member] | |||
Related Party Transaction | |||
Related party incurred costs | 100 | ||
Accounts payable-related party | $ 100 | ||
Maximum [Member] | Affiliated Entity [Member] | |||
Related Party Transaction | |||
Amount owed by affiliate | $ 100 |
Related Party Transactions - Dr
Related Party Transactions - Drilling Services (Details) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015USD ($)drilling_rig | Dec. 31, 2014USD ($)drilling_rig | Dec. 31, 2013USD ($) | |
Bison [Member] | |||
Related Party Transaction | |||
Number of drilling rigs committed to use during the period | drilling_rig | 2 | ||
Number of drilling rigs utilized | drilling_rig | 0 | 0 | |
Agreement termination, written notice period | 30 days | ||
Related party incurred costs | $ | $ 0 | $ 3,544 | $ 13,921 |
Panther Drilling [Member] | |||
Related Party Transaction | |||
Agreement termination, written notice period | 30 days | ||
Related party incurred costs | $ | $ 0 | $ 305 | $ 176 |
Related Party Transactions - Co
Related Party Transactions - Coronado Midstream (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||
Mar. 31, 2015 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Feb. 28, 2015 | |
Related Party Transaction | |||||
Ownership interest | 25.00% | ||||
Natural gas revenue from related party | $ 2,544 | $ 15,038 | $ 4,696 | ||
Coronado Midstream [Member] | |||||
Related Party Transaction | |||||
Initial term of the additional shared services agreement | 10 years | ||||
Agreement termination, written notice period | 30 days | ||||
Ownership interest | 28.00% | ||||
Natural gas revenue from related party | $ 5,184 | 24,404 | 7,230 | ||
Related party incurred costs | $ 1,122 | 4,148 | $ 1,181 | ||
Amount owed from related party from the sale of gas, gas products and residue gas | $ 4,000 | ||||
Coronado Midstream [Member] | Coronado Midstream Plant [Member] | |||||
Related Party Transaction | |||||
Percent of natural gas revenue from related party | 87.00% | ||||
Coronado Midstream [Member] | Chevron Headlee Plant [Member] | |||||
Related Party Transaction | |||||
Percent of natural gas revenue from related party | 94.56% |
Related Party Transactions - Sa
Related Party Transactions - Sand Supply (Details) - Muskie [Member] - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Related Party Transaction | |||
Agreement termination, written notice period | 30 days | ||
Related party incurred costs | $ 0 | $ 0 | $ 700 |
Amount owed to related party | $ 0 | $ 0 |
Related Party Transactions - Mi
Related Party Transactions - Midland Leases (Details) - Midland, Texas [Member] - Wexford Affiliate [Member] - USD ($) | 1 Months Ended | 12 Months Ended | |||||||||
Nov. 30, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Jun. 30, 2016 | Jun. 30, 2015 | Apr. 30, 2015 | Jun. 30, 2014 | Mar. 31, 2014 | Aug. 02, 2013 | Jul. 31, 2013 | |
Corporate Office Space [Member] | |||||||||||
Related Party Transaction | |||||||||||
Term of lease from related party | 10 years | 5 years | |||||||||
Office rent to affiliate | $ 1,018,000 | $ 435,000 | $ 214,000 | ||||||||
Monthly rent | 53,000 | $ 22,000 | $ 23,000 | $ 27,000 | $ 25,000 | $ 15,000 | $ 13,000 | ||||
Annual monthly rent increase | 4.00% | 2.00% | |||||||||
Corporate Office Space [Member] | Scenario, Forecast [Member] | |||||||||||
Related Party Transaction | |||||||||||
Monthly rent | $ 94,000 | ||||||||||
Annual monthly rent increase | 2.00% | ||||||||||
Field Office Space [Member] | |||||||||||
Related Party Transaction | |||||||||||
Term of lease from related party | 4 years | ||||||||||
Office rent to affiliate | $ 163,000 | $ 129,000 | |||||||||
Field Office Space [Member] | Affiliated Entity, Bison [Member] | |||||||||||
Related Party Transaction | |||||||||||
Monthly rent | $ 11,000 | ||||||||||
Annual monthly rent increase | 3.00% |
Related Party Transactions - Ok
Related Party Transactions - Oklahoma City Lease (Details) - Oklahoma City, Oklahoma [Member] - Wexford Affiliate [Member] - USD ($) | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Related Party Transaction | |||
Term of lease from related party | 67 months | ||
Office rent to affiliate | $ 188,000 | $ 244,000 | |
Monthly rent | $ 19,000 |
Related Party Transactions - 79
Related Party Transactions - Advisory Services Agreement & Professional Services from Wexford (Details) - Advisory Services Agreement [Member] - Wexford [Member] - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Related Party Transaction | |||
Advisory services agreement, annual fee | $ 500 | ||
Term of advisory services agreement | 2 years | ||
Renewal term of advisory services agreement | 1 year | ||
Minimum period for cancellation of additional one-year periods | 10 days | ||
Agreement termination, written notice period | 30 days | ||
Related party incurred costs | $ 1,165 | $ 8,276 | $ 500 |
Cash reimbursement | $ 4,300 | ||
Stock reimbursement, number of shares | 63,786 |
Related Party Transactions - 80
Related Party Transactions - Advisory Services Agreement - Viper Energy Partners LP (Details) - Wexford [Member] - Advisory Services Agreement [Member] - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Related Party Transaction | |||
Advisory services agreement, annual fee | $ 500 | ||
Term of advisory services agreement | 2 years | ||
Renewal term of advisory services agreement | 1 year | ||
Minimum period for cancellation of additional one-year periods | 10 days | ||
Agreement termination, written notice period | 30 days | ||
Related party incurred costs | $ 1,165 | $ 8,276 | $ 500 |
Viper Energy Partners LP [Member] | |||
Related Party Transaction | |||
Advisory services agreement, annual fee | $ 500 | ||
Term of advisory services agreement | 2 years | ||
Renewal term of advisory services agreement | 1 year | ||
Minimum period for cancellation of additional one-year periods | 10 days | ||
Agreement termination, written notice period | 30 days | ||
Related party incurred costs | $ 609 | $ 276 |
Related Party Transactions - Se
Related Party Transactions - Secondary Offering Costs (Details) - Common Stock [Member] - Wexford and Gulfport Affiliates [Member] - USD ($) $ / shares in Units, $ in Thousands | Nov. 17, 2014 | Nov. 13, 2014 | Sep. 23, 2014 | Jun. 27, 2014 | Jul. 05, 2013 | Jul. 05, 2013 | Jun. 24, 2013 |
Related Party Transaction | |||||||
Shares sold in secondary public offering | 2,000,000 | 2,500,000 | 2,000,000 | 6,000,000 | |||
Shares sold by existing stockholders | 300,000 | 869,222 | |||||
Stock price per share, selling stockholders (in dollars per share) | $ 64.54 | $ 75.44 | $ 90.04 | $ 34.75 | |||
Related party incurred costs | $ 86 | $ 103 | $ 129 | $ 185 |
Income Taxes - Components of Fe
Income Taxes - Components of Federal Income Tax (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Income Tax Disclosure [Abstract] | |||||||||||
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent | 35.00% | 35.00% | 35.00% | ||||||||
Current income tax provision (benefit): | |||||||||||
Federal | $ (33) | $ 0 | $ 191 | ||||||||
State | 268 | 0 | 0 | ||||||||
Total current income tax provision | 235 | 0 | 191 | ||||||||
Deferred income tax provision (benefit): | |||||||||||
Federal | (198,729) | 106,107 | 30,768 | ||||||||
State | (2,816) | 2,878 | 795 | ||||||||
Total deferred income tax provision (benefit) | (201,545) | 108,985 | 31,563 | ||||||||
Total provision for (benefit from) income taxes | $ (6,487) | $ (81,461) | $ (116,732) | $ 3,370 | $ 56,243 | $ 23,978 | $ 15,163 | $ 13,601 | $ (201,310) | $ 108,985 | $ 31,754 |
Income Taxes - Reconciliation o
Income Taxes - Reconciliation of Statutory Federal Income Tax (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Income Tax Disclosure [Abstract] | |||||||||||
Income tax expense (benefit) at the federal statutory rate (35%) | $ (263,179) | $ 105,959 | $ 30,231 | ||||||||
Income tax expense (benefit) relating to change in tax rate | (1,145) | 0 | 0 | ||||||||
State income tax expense (benefit), net of federal tax effect | (2,548) | 2,878 | 517 | ||||||||
Non-deductible expenses and other | 4,506 | 148 | 1,006 | ||||||||
Change in valuation allowance | 61,056 | 0 | 0 | ||||||||
Total provision for (benefit from) income taxes | $ (6,487) | $ (81,461) | $ (116,732) | $ 3,370 | $ 56,243 | $ 23,978 | $ 15,163 | $ 13,601 | $ (201,310) | $ 108,985 | $ 31,754 |
Income Taxes - Components of De
Income Taxes - Components of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Current deferred tax assets | ||
Derivative instruments | $ 0 | $ 0 |
Other | 2,658 | 1,950 |
Current deferred tax assets | 2,658 | 1,950 |
Valuation allowance | (1,018) | 0 |
Current deferred tax assets, net of valuation allowance | 1,640 | 1,950 |
Current deferred tax liabilities | ||
Derivative instruments | 1,640 | 41,903 |
Total current deferred tax liabilities | 1,640 | 41,903 |
Net current deferred tax assets | 0 | (39,953) |
Noncurrent deferred tax assets | ||
Net operating loss carryforwards (subject to 20 year expiration) | 82,635 | 49,627 |
Stock based compensation | 3,873 | 2,520 |
Alternative minimum tax credit carryforward | 0 | 33 |
Other | 4,533 | 0 |
Noncurrent deferred tax assets | 91,041 | 52,180 |
Valuation allowance | (60,038) | 0 |
Noncurrent deferred tax assets, net of valuation allowance | 31,003 | 52,180 |
Deferred Tax Assets, Valuation Allowance, Noncurrent | (61,056) | |
Noncurrent deferred tax liabilities | ||
Oil and natural gas properties and equipment | 31,003 | 213,772 |
Other | 0 | 0 |
Total noncurrent deferred tax liabilities | 31,003 | 213,772 |
Net noncurrent deferred tax liabilities | 0 | 161,592 |
Net deferred tax liabilities | $ 0 | $ 201,545 |
Operating Loss Carryforwards, Expiration Date | Dec. 31, 2035 | Dec. 31, 2034 |
Operating Loss Carryforwards, Limitations on Use | 50.00% |
Derivatives - Open Derivative P
Derivatives - Open Derivative Positions (Details) - ICE Brent [Member] - January - February 2016 [Member] - Crude Oil [Member] - Swap [Member] bbl in Thousands | Dec. 31, 2015bbl$ / bbl |
Derivative [Line Items] | |
Volume (Bbls) | bbl | 91 |
Fixed Swap Price | $ / bbl | 88.72 |
Derivatives - Offsetting Deriva
Derivatives - Offsetting Derivative Instruments (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||
Gross Amounts of Recognized Assets | $ 4,623 | $ 117,541 |
Gross Amounts Offset in the Consolidated Balance Sheet | 0 | 0 |
Net Amounts of Assets Presented in the Consolidated Balance Sheet | $ 4,623 | $ 117,541 |
Derivatives - Balance Sheet Loc
Derivatives - Balance Sheet Location (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||
Current Assets: Derivative instruments | $ 4,623 | $ 115,607 |
Noncurrent Assets: Derivative instruments | 0 | 1,934 |
Total Assets | $ 4,623 | $ 117,541 |
Derivatives - Gains and Losses
Derivatives - Gains and Losses on Derivative Instruments Included in Statement of Operations (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||
Change in fair value of open non-hedge derivative instruments | $ (112,918) | $ 117,109 | $ 5,346 |
Gain (loss) on settlement of non-hedge derivative instruments | 144,869 | 10,430 | (7,218) |
Gain (loss) on derivative instruments | $ 31,951 | $ 127,539 | $ (1,872) |
Fair Value Measurements - Recur
Fair Value Measurements - Recurring Measurements (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Assets: | ||
Fixed price swaps | $ 4,623 | $ 117,541 |
Recurring [Member] | ||
Assets: | ||
Fixed price swaps | 4,623 | 117,541 |
Recurring [Member] | Quoted Prices in Active Markets Level 1 [Member] | ||
Assets: | ||
Fixed price swaps | 0 | 0 |
Recurring [Member] | Significant Other Observable Inputs Level 2 [Member] | ||
Assets: | ||
Fixed price swaps | 4,623 | 117,541 |
Recurring [Member] | Significant Unobservable Inputs Level 3 [Member] | ||
Assets: | ||
Fixed price swaps | $ 0 | $ 0 |
Fair Value Measurements - Nonre
Fair Value Measurements - Nonrecurring Measurements (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 | Sep. 18, 2013 |
Carrying Amount [Member] | Nonrecurring [Member] | |||
Fair value of assets and liabilities measured on a recurring and nonrecurring basis | |||
Revolving credit facility | $ 11,000 | $ 223,500 | |
Fair Value [Member] | Nonrecurring [Member] | |||
Fair value of assets and liabilities measured on a recurring and nonrecurring basis | |||
Revolving credit facility | 11,000 | 223,500 | |
Viper Energy Partners LP [Member] | Carrying Amount [Member] | Nonrecurring [Member] | |||
Fair value of assets and liabilities measured on a recurring and nonrecurring basis | |||
Revolving credit facility | 34,500 | 0 | |
Viper Energy Partners LP [Member] | Fair Value [Member] | Nonrecurring [Member] | |||
Fair value of assets and liabilities measured on a recurring and nonrecurring basis | |||
Revolving credit facility | $ 34,500 | $ 0 | |
Senior Unsecured Notes due 2021 [Member] | Senior Notes [Member] | |||
Fair value of assets and liabilities measured on a recurring and nonrecurring basis | |||
Stated interest rate | 7.625% | 7.625% | 7.625% |
Senior Unsecured Notes due 2021 [Member] | Senior Notes [Member] | Carrying Amount [Member] | Nonrecurring [Member] | |||
Fair value of assets and liabilities measured on a recurring and nonrecurring basis | |||
7.625% Senior Notes due 2021 | $ 450,000 | $ 450,000 | |
Senior Unsecured Notes due 2021 [Member] | Senior Notes [Member] | Fair Value [Member] | Nonrecurring [Member] | |||
Fair value of assets and liabilities measured on a recurring and nonrecurring basis | |||
7.625% Senior Notes due 2021 | $ 450,000 | $ 440,438 |
Commitments and Contingencies -
Commitments and Contingencies - Lease Commitments (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Future minimum lease payments | |||
Rent Expense | $ 1,449 | $ 852 | $ 571 |
Drilling Rig [Member] | |||
Future minimum lease payments | |||
2,016 | 29,536 | ||
2,017 | 19,893 | ||
2,018 | 16,866 | ||
2,019 | 589 | ||
2,020 | 0 | ||
Thereafter | 0 | ||
Total | 66,884 | ||
Office and Equipment [Member] | |||
Future minimum lease payments | |||
2,016 | 1,935 | ||
2,017 | 2,053 | ||
2,018 | 1,973 | ||
2,019 | 1,839 | ||
2,020 | 1,659 | ||
Thereafter | 9,583 | ||
Total | $ 19,042 |
Commitments and Contingencies92
Commitments and Contingencies - Commitments and Obligations (Details) $ in Thousands | May. 24, 2012bbl | Dec. 31, 2015USD ($) |
Supply Commitment [Line Items] | ||
Future commitments for drilling contracts | $ | $ 66,884 | |
Shell Trading US Company [Member] | ||
Supply Commitment [Line Items] | ||
Delivery contract, term | 5 years | |
Maximum delivery obligation, barrels per day | bbl | 8,000 | |
One-time right to decrease contract quantity, percent, not more than 20% | 20.00% |
Commitments and Contingencies93
Commitments and Contingencies - Defined Contribution Plan (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Defined contribution plan | |||
Employee maximum annual contribution as percentage of annual compensation | 100.00% | ||
Employer matching contribution percentage, up to 6% | 6.00% | ||
Employer contribution vesting period | 4 years | ||
Contributions by employer | $ 1,395 | $ 428 | $ 262 |
Subsequent Events (Details)
Subsequent Events (Details) - Common Stock [Member] - USD ($) $ / shares in Units, $ in Thousands | 1 Months Ended | |||||||
Jan. 31, 2016 | Aug. 31, 2015 | May. 31, 2015 | Jan. 31, 2015 | Jul. 31, 2014 | Feb. 28, 2014 | Aug. 31, 2013 | May. 31, 2013 | |
Subsequent Event [Line Items] | ||||||||
Shares issued upon public offering | 2,875,000 | 4,600,000 | 2,012,500 | 5,750,000 | 3,450,000 | 4,600,000 | 5,175,000 | |
Common stock issued pursuant to underwriters over allotment option | 375,000 | 600,000 | 262,500 | 750,000 | 450,000 | 600,000 | 675,000 | |
Stock price per share at public offering (in dollars per share) | $ 68.74 | $ 72.53 | $ 59.34 | $ 87 | $ 62.67 | $ 40.25 | $ 29.25 | |
Net proceeds received from public offering | $ 197,628 | $ 333,638 | $ 119,422 | $ 485,000 | $ 208,445 | $ 177,500 | $ 144,439 | |
Subsequent Event [Member] | ||||||||
Subsequent Event [Line Items] | ||||||||
Shares issued upon public offering | 4,600,000 | |||||||
Stock price per share at public offering (in dollars per share) | $ 55.33 | |||||||
Net proceeds received from public offering | $ 254,518 | |||||||
Over-Allotment Option [Member] | Subsequent Event [Member] | ||||||||
Subsequent Event [Line Items] | ||||||||
Common stock issued pursuant to underwriters over allotment option | 600,000 |
Guarantor Financial Statement95
Guarantor Financial Statements - Balance Sheet (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Current assets: | ||||
Cash and cash equivalents | $ 20,115 | $ 30,183 | $ 15,555 | $ 26,358 |
Restricted cash | 500 | 500 | ||
Accounts receivable | 77,313 | 93,993 | ||
Accounts receivable - related party | 1,591 | 4,001 | ||
Intercompany receivable | 0 | 0 | ||
Inventories | 1,728 | 2,827 | ||
Other current assets | 7,498 | 120,207 | ||
Total current assets | 108,745 | 251,711 | ||
Property and equipment | ||||
Oil and natural gas properties, at cost, based on the full cost method of accounting | 3,955,373 | 3,118,597 | ||
Pipeline and gas gathering assets | 7,174 | 7,174 | ||
Other property and equipment | 48,621 | 48,180 | ||
Accumulated depletion, depreciation, amortization and impairment | (1,413,543) | (382,144) | ||
Net property and equipment | 2,597,625 | 2,791,807 | ||
Investment in subsidiaries | 0 | 0 | ||
Other assets | 52,042 | 51,963 | ||
Total assets | 2,758,412 | 3,095,481 | ||
Current liabilities: | ||||
Accounts payable-trade | 20,008 | 26,230 | ||
Accounts payable-related party | 217 | 0 | ||
Intercompany payable | 0 | 0 | ||
Other current liabilities | 121,196 | 240,499 | ||
Total current liabilities | 141,421 | 266,729 | ||
Long-term debt | 495,500 | 673,500 | ||
Asset retirement obligations | 12,518 | 8,447 | 2,989 | |
Deferred income taxes | 0 | 161,592 | ||
Total liabilities | $ 649,439 | $ 1,110,268 | ||
Commitments and contingencies | ||||
Stockholders’ equity: | ||||
Stockholders’ equity | $ 1,875,972 | $ 1,751,011 | ||
Noncontrolling interest | 233,001 | 234,202 | ||
Total equity | 2,108,973 | 1,985,213 | 845,541 | 462,068 |
Total liabilities and equity | 2,758,412 | 3,095,481 | ||
Eliminations [Member] | ||||
Current assets: | ||||
Cash and cash equivalents | 0 | 0 | 0 | 0 |
Restricted cash | 0 | 0 | ||
Accounts receivable | 2 | 2 | ||
Accounts receivable - related party | 0 | 0 | ||
Intercompany receivable | (2,452,761) | (3,825,649) | ||
Inventories | 0 | 0 | ||
Other current assets | 0 | 0 | ||
Total current assets | (2,452,759) | (3,825,647) | ||
Property and equipment | ||||
Oil and natural gas properties, at cost, based on the full cost method of accounting | 0 | 0 | ||
Pipeline and gas gathering assets | 0 | 0 | ||
Other property and equipment | 0 | 0 | ||
Accumulated depletion, depreciation, amortization and impairment | 5,412 | 1,855 | ||
Net property and equipment | 5,412 | 1,855 | ||
Investment in subsidiaries | (79,417) | (839,217) | ||
Other assets | 0 | 0 | ||
Total assets | (2,526,764) | (4,663,009) | ||
Current liabilities: | ||||
Accounts payable-trade | 0 | 0 | ||
Accounts payable-related party | 0 | |||
Intercompany payable | (2,452,759) | (3,825,649) | ||
Other current liabilities | 0 | 0 | ||
Total current liabilities | (2,452,759) | (3,825,649) | ||
Long-term debt | 0 | 0 | ||
Asset retirement obligations | 0 | 0 | ||
Deferred income taxes | 0 | |||
Total liabilities | $ (2,452,759) | (3,825,649) | ||
Commitments and contingencies | ||||
Stockholders’ equity: | ||||
Stockholders’ equity | $ (307,006) | (1,071,562) | ||
Noncontrolling interest | 233,001 | 234,202 | ||
Total equity | (74,005) | (837,360) | ||
Total liabilities and equity | (2,526,764) | (4,663,009) | ||
Parent Company [Member] | Reportable Legal Entities [Member] | ||||
Current assets: | ||||
Cash and cash equivalents | 148 | 6 | 526 | 14 |
Restricted cash | 0 | 0 | ||
Accounts receivable | 0 | 0 | ||
Accounts receivable - related party | 0 | 0 | ||
Intercompany receivable | 2,246,846 | 1,658,215 | ||
Inventories | 0 | 0 | ||
Other current assets | 450 | 562 | ||
Total current assets | 2,247,444 | 1,658,783 | ||
Property and equipment | ||||
Oil and natural gas properties, at cost, based on the full cost method of accounting | 0 | 0 | ||
Pipeline and gas gathering assets | 0 | 0 | ||
Other property and equipment | 0 | 0 | ||
Accumulated depletion, depreciation, amortization and impairment | 0 | 0 | ||
Net property and equipment | 0 | 0 | ||
Investment in subsidiaries | 79,417 | 839,217 | ||
Other assets | 7,795 | 9,155 | ||
Total assets | 2,334,656 | 2,507,155 | ||
Current liabilities: | ||||
Accounts payable-trade | 0 | 0 | ||
Accounts payable-related party | 1 | |||
Intercompany payable | 0 | 95,362 | ||
Other current liabilities | 8,683 | 49,190 | ||
Total current liabilities | 8,684 | 144,552 | ||
Long-term debt | 450,000 | 450,000 | ||
Asset retirement obligations | 0 | 0 | ||
Deferred income taxes | 161,592 | |||
Total liabilities | $ 458,684 | 756,144 | ||
Commitments and contingencies | ||||
Stockholders’ equity: | ||||
Stockholders’ equity | $ 1,875,972 | 1,751,011 | ||
Noncontrolling interest | 0 | 0 | ||
Total equity | 1,875,972 | 1,751,011 | ||
Total liabilities and equity | 2,334,656 | 2,507,155 | ||
Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member] | ||||
Current assets: | ||||
Cash and cash equivalents | 19,428 | 15,067 | 14,267 | 26,344 |
Restricted cash | 0 | 0 | ||
Accounts receivable | 67,942 | 85,752 | ||
Accounts receivable - related party | 1,591 | 4,001 | ||
Intercompany receivable | 205,915 | 2,167,434 | ||
Inventories | 1,728 | 2,827 | ||
Other current assets | 6,572 | 119,392 | ||
Total current assets | 303,176 | 2,394,473 | ||
Property and equipment | ||||
Oil and natural gas properties, at cost, based on the full cost method of accounting | 3,400,381 | 2,607,513 | ||
Pipeline and gas gathering assets | 7,174 | 7,174 | ||
Other property and equipment | 48,621 | 48,180 | ||
Accumulated depletion, depreciation, amortization and impairment | (1,347,296) | (351,200) | ||
Net property and equipment | 2,108,880 | 2,311,667 | ||
Investment in subsidiaries | 0 | 0 | ||
Other assets | 8,733 | 7,793 | ||
Total assets | 2,420,789 | 4,713,933 | ||
Current liabilities: | ||||
Accounts payable-trade | 20,007 | 26,224 | ||
Accounts payable-related party | 212 | |||
Intercompany payable | 2,452,759 | 3,730,287 | ||
Other current liabilities | 112,431 | 189,264 | ||
Total current liabilities | 2,585,409 | 3,945,775 | ||
Long-term debt | 11,000 | 223,500 | ||
Asset retirement obligations | 12,518 | 8,447 | ||
Deferred income taxes | 0 | |||
Total liabilities | $ 2,608,927 | 4,177,722 | ||
Commitments and contingencies | ||||
Stockholders’ equity: | ||||
Stockholders’ equity | $ (188,138) | 536,211 | ||
Noncontrolling interest | 0 | 0 | ||
Total equity | (188,138) | 536,211 | ||
Total liabilities and equity | 2,420,789 | 4,713,933 | ||
Non-Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member] | ||||
Current assets: | ||||
Cash and cash equivalents | 539 | 15,110 | $ 762 | $ 0 |
Restricted cash | 500 | 500 | ||
Accounts receivable | 9,369 | 8,239 | ||
Accounts receivable - related party | 0 | 0 | ||
Intercompany receivable | 0 | 0 | ||
Inventories | 0 | 0 | ||
Other current assets | 476 | 253 | ||
Total current assets | 10,884 | 24,102 | ||
Property and equipment | ||||
Oil and natural gas properties, at cost, based on the full cost method of accounting | 554,992 | 511,084 | ||
Pipeline and gas gathering assets | 0 | 0 | ||
Other property and equipment | 0 | 0 | ||
Accumulated depletion, depreciation, amortization and impairment | (71,659) | (32,799) | ||
Net property and equipment | 483,333 | 478,285 | ||
Investment in subsidiaries | 0 | 0 | ||
Other assets | 35,514 | 35,015 | ||
Total assets | 529,731 | 537,402 | ||
Current liabilities: | ||||
Accounts payable-trade | 1 | 6 | ||
Accounts payable-related party | 4 | |||
Intercompany payable | 0 | 0 | ||
Other current liabilities | 82 | 2,045 | ||
Total current liabilities | 87 | 2,051 | ||
Long-term debt | 34,500 | 0 | ||
Asset retirement obligations | 0 | 0 | ||
Deferred income taxes | 0 | |||
Total liabilities | $ 34,587 | 2,051 | ||
Commitments and contingencies | ||||
Stockholders’ equity: | ||||
Stockholders’ equity | $ 495,144 | 535,351 | ||
Noncontrolling interest | 0 | 0 | ||
Total equity | 495,144 | 535,351 | ||
Total liabilities and equity | $ 529,731 | $ 537,402 |
Guarantor Financial Statement96
Guarantor Financial Statements - Income Statement (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Revenues: | |||||||||||
Oil sales | $ 405,715 | $ 449,244 | $ 188,753 | ||||||||
Natural gas sales | 19,592 | 18,028 | 6,249 | ||||||||
Natural gas liquid sales | 21,426 | 28,446 | 13,000 | ||||||||
Royalty income | 0 | 0 | 0 | ||||||||
Revenues | $ 114,323 | $ 111,946 | $ 119,063 | $ 101,401 | $ 131,583 | $ 139,127 | $ 127,004 | $ 98,004 | 446,733 | 495,718 | 208,002 |
Costs and expenses: | |||||||||||
Lease operating expenses | 82,625 | 55,384 | 21,157 | ||||||||
Production and ad valorem taxes | 32,990 | 32,638 | 12,899 | ||||||||
Gathering and transportation | 6,091 | 3,288 | 918 | ||||||||
Depreciation, depletion and amortization | 217,697 | 170,005 | 66,597 | ||||||||
Impairment of oil and natural gas properties | 814,798 | 0 | 0 | ||||||||
General and administrative expenses | 31,968 | 21,266 | 11,036 | ||||||||
Asset retirement obligation accretion expense | 833 | 467 | 201 | ||||||||
Intercompany charges | 0 | ||||||||||
Total costs and expenses | 1,187,002 | 283,048 | 112,808 | ||||||||
Income (loss) from operations | (187,813) | (254,773) | (299,120) | 1,437 | 37,899 | 63,516 | 63,192 | 48,063 | (740,269) | 212,670 | 95,194 |
Other income (expense) | |||||||||||
Interest income - intercompany | 0 | 0 | |||||||||
Interest expense | (41,510) | (34,514) | (8,058) | ||||||||
Interest expense - intercompany | 0 | ||||||||||
Other income | 567 | 556 | 0 | ||||||||
Other income - intercompany | 161 | 121 | 1,077 | ||||||||
Other expense | 0 | (1,416) | 0 | ||||||||
Gain (loss) on derivative instruments, net | 31,951 | 127,539 | (1,872) | ||||||||
Total other income (expense), net | (8,831) | 92,286 | (8,853) | ||||||||
Income before income taxes | (749,100) | 304,956 | 86,341 | ||||||||
Provision for (benefit from) income taxes | (6,487) | (81,461) | (116,732) | 3,370 | 56,243 | 23,978 | 15,163 | 13,601 | (201,310) | 108,985 | 31,754 |
Net income (loss) | (186,835) | (156,042) | (211,352) | 6,439 | 99,917 | 44,641 | 27,824 | 23,589 | (547,790) | 195,971 | 54,587 |
Less: Net income attributable to noncontrolling interest | 574 | 739 | 935 | 590 | 1,243 | 902 | 71 | 0 | 2,838 | 2,216 | 0 |
Net income (loss) attributable to Diamondback Energy, Inc. | $ (187,409) | $ (156,781) | $ (212,287) | $ 5,849 | $ 98,674 | $ 43,739 | $ 27,753 | $ 23,589 | (550,628) | 193,755 | 54,587 |
Eliminations [Member] | |||||||||||
Revenues: | |||||||||||
Oil sales | 69,609 | 71,532 | 13,885 | ||||||||
Natural gas sales | 2,660 | 2,788 | 397 | ||||||||
Natural gas liquid sales | 2,590 | 3,901 | 705 | ||||||||
Royalty income | (74,859) | (77,767) | (14,987) | ||||||||
Revenues | 0 | 454 | 0 | ||||||||
Costs and expenses: | |||||||||||
Lease operating expenses | 0 | 0 | 0 | ||||||||
Production and ad valorem taxes | 0 | 19 | 0 | ||||||||
Gathering and transportation | 0 | (6) | 0 | ||||||||
Depreciation, depletion and amortization | (134) | (1,073) | 0 | ||||||||
Impairment of oil and natural gas properties | (3,423) | ||||||||||
General and administrative expenses | 0 | (1,174) | 0 | ||||||||
Asset retirement obligation accretion expense | 0 | 0 | 0 | ||||||||
Intercompany charges | (87) | ||||||||||
Total costs and expenses | (3,557) | (2,234) | (87) | ||||||||
Income (loss) from operations | 3,557 | 2,688 | 87 | ||||||||
Other income (expense) | |||||||||||
Interest income - intercompany | (10,755) | (5,741) | |||||||||
Interest expense | 0 | 0 | 5,741 | ||||||||
Interest expense - intercompany | 10,755 | ||||||||||
Other income | 0 | 0 | (87) | ||||||||
Other income - intercompany | 0 | (906) | 0 | ||||||||
Other expense | 0 | ||||||||||
Gain (loss) on derivative instruments, net | 0 | 0 | 0 | ||||||||
Total other income (expense), net | 0 | (906) | (87) | ||||||||
Income before income taxes | 3,557 | 1,782 | 0 | ||||||||
Provision for (benefit from) income taxes | 0 | 0 | 0 | ||||||||
Net income (loss) | 3,557 | 1,782 | |||||||||
Less: Net income attributable to noncontrolling interest | 2,838 | 2,216 | |||||||||
Net income (loss) attributable to Diamondback Energy, Inc. | 719 | (434) | 0 | ||||||||
Parent Company [Member] | Reportable Legal Entities [Member] | |||||||||||
Revenues: | |||||||||||
Oil sales | 0 | 0 | 0 | ||||||||
Natural gas sales | 0 | 0 | 0 | ||||||||
Natural gas liquid sales | 0 | 0 | 0 | ||||||||
Royalty income | 0 | 0 | 0 | ||||||||
Revenues | 0 | 0 | 0 | ||||||||
Costs and expenses: | |||||||||||
Lease operating expenses | 0 | 0 | 0 | ||||||||
Production and ad valorem taxes | 0 | 0 | 0 | ||||||||
Gathering and transportation | 0 | 0 | 0 | ||||||||
Depreciation, depletion and amortization | 0 | 0 | 0 | ||||||||
Impairment of oil and natural gas properties | 0 | ||||||||||
General and administrative expenses | 17,077 | 10,879 | 3,909 | ||||||||
Asset retirement obligation accretion expense | 0 | 0 | 0 | ||||||||
Intercompany charges | 0 | ||||||||||
Total costs and expenses | 17,077 | 10,879 | 3,909 | ||||||||
Income (loss) from operations | (17,077) | (10,879) | (3,909) | ||||||||
Other income (expense) | |||||||||||
Interest income - intercompany | 10,755 | 5,741 | |||||||||
Interest expense | (35,651) | (30,281) | (591) | ||||||||
Interest expense - intercompany | 0 | ||||||||||
Other income | 1 | 6 | 0 | ||||||||
Other income - intercompany | 0 | 0 | 0 | ||||||||
Other expense | 0 | ||||||||||
Gain (loss) on derivative instruments, net | 0 | 0 | 0 | ||||||||
Total other income (expense), net | (35,650) | (19,520) | 5,150 | ||||||||
Income before income taxes | (52,727) | (30,399) | 1,241 | ||||||||
Provision for (benefit from) income taxes | (201,310) | 108,985 | 31,754 | ||||||||
Net income (loss) | 148,583 | (139,384) | |||||||||
Less: Net income attributable to noncontrolling interest | 0 | 0 | |||||||||
Net income (loss) attributable to Diamondback Energy, Inc. | 148,583 | (139,384) | (30,513) | ||||||||
Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member] | |||||||||||
Revenues: | |||||||||||
Oil sales | 336,106 | 377,712 | 174,868 | ||||||||
Natural gas sales | 16,932 | 15,240 | 5,852 | ||||||||
Natural gas liquid sales | 18,836 | 24,545 | 12,295 | ||||||||
Royalty income | 0 | 0 | 0 | ||||||||
Revenues | 371,874 | 417,497 | 193,015 | ||||||||
Costs and expenses: | |||||||||||
Lease operating expenses | 82,625 | 55,384 | 21,157 | ||||||||
Production and ad valorem taxes | 27,459 | 27,242 | 11,927 | ||||||||
Gathering and transportation | 5,832 | 3,294 | 918 | ||||||||
Depreciation, depletion and amortization | 182,395 | 143,477 | 61,398 | ||||||||
Impairment of oil and natural gas properties | 814,798 | ||||||||||
General and administrative expenses | 9,056 | 7,189 | 7,127 | ||||||||
Asset retirement obligation accretion expense | 833 | 467 | 201 | ||||||||
Intercompany charges | 0 | ||||||||||
Total costs and expenses | 1,122,998 | 237,053 | 102,728 | ||||||||
Income (loss) from operations | (751,124) | 180,444 | 90,287 | ||||||||
Other income (expense) | |||||||||||
Interest income - intercompany | 0 | 0 | |||||||||
Interest expense | (4,749) | (3,746) | (7,467) | ||||||||
Interest expense - intercompany | 0 | ||||||||||
Other income | (588) | 91 | 87 | ||||||||
Other income - intercompany | 161 | 1,027 | 1,077 | ||||||||
Other expense | (1,416) | ||||||||||
Gain (loss) on derivative instruments, net | 31,951 | 127,539 | (1,872) | ||||||||
Total other income (expense), net | 26,775 | 123,495 | (8,175) | ||||||||
Income before income taxes | (724,349) | 303,939 | 82,112 | ||||||||
Provision for (benefit from) income taxes | 0 | 0 | 0 | ||||||||
Net income (loss) | (724,349) | 303,939 | |||||||||
Less: Net income attributable to noncontrolling interest | 0 | 0 | |||||||||
Net income (loss) attributable to Diamondback Energy, Inc. | (724,349) | 303,939 | 82,112 | ||||||||
Non-Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member] | |||||||||||
Revenues: | |||||||||||
Oil sales | 0 | 0 | 0 | ||||||||
Natural gas sales | 0 | 0 | 0 | ||||||||
Natural gas liquid sales | 0 | 0 | 0 | ||||||||
Royalty income | 74,859 | 77,767 | 14,987 | ||||||||
Revenues | 74,859 | 77,767 | 14,987 | ||||||||
Costs and expenses: | |||||||||||
Lease operating expenses | 0 | 0 | 0 | ||||||||
Production and ad valorem taxes | 5,531 | 5,377 | 972 | ||||||||
Gathering and transportation | 259 | 0 | 0 | ||||||||
Depreciation, depletion and amortization | 35,436 | 27,601 | 5,199 | ||||||||
Impairment of oil and natural gas properties | 3,423 | ||||||||||
General and administrative expenses | 5,835 | 4,372 | 0 | ||||||||
Asset retirement obligation accretion expense | 0 | 0 | 0 | ||||||||
Intercompany charges | 87 | ||||||||||
Total costs and expenses | 50,484 | 37,350 | 6,258 | ||||||||
Income (loss) from operations | 24,375 | 40,417 | 8,729 | ||||||||
Other income (expense) | |||||||||||
Interest income - intercompany | 0 | 0 | |||||||||
Interest expense | (1,110) | (487) | (5,741) | ||||||||
Interest expense - intercompany | (10,755) | ||||||||||
Other income | 1,154 | 459 | 0 | ||||||||
Other income - intercompany | 0 | 0 | 0 | ||||||||
Other expense | 0 | ||||||||||
Gain (loss) on derivative instruments, net | 0 | 0 | 0 | ||||||||
Total other income (expense), net | 44 | (10,783) | (5,741) | ||||||||
Income before income taxes | 24,419 | 29,634 | 2,988 | ||||||||
Provision for (benefit from) income taxes | 0 | 0 | 0 | ||||||||
Net income (loss) | 24,419 | 29,634 | |||||||||
Less: Net income attributable to noncontrolling interest | 0 | 0 | |||||||||
Net income (loss) attributable to Diamondback Energy, Inc. | $ 24,419 | $ 29,634 | $ 2,988 |
Guarantor Financial Statement97
Guarantor Financial Statements - Cash Flow Statement (Details) - USD ($) $ in Thousands | 1 Months Ended | 12 Months Ended | ||
Oct. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Condensed Financial Statements, Captions [Line Items] | ||||
Net cash provided by (used in) operating activities | $ 416,501 | $ 356,389 | $ 155,777 | |
Cash flows from investing activities: | ||||
Additions to oil and natural gas properties | (419,512) | (498,339) | (292,586) | |
Acquisition of leasehold interests | (437,455) | (845,826) | (195,893) | |
Acquisition of royalty interests | (43,907) | (57,689) | (444,083) | |
Purchase of other property and equipment | (1,213) | (44,213) | (2,234) | |
Proceeds from sale of assets | 9,739 | 56 | 72 | |
Equity investments | $ (600) | (2,702) | (34,477) | 0 |
Intercompany transfers | 0 | 0 | 0 | |
Other investing activities | 0 | (1,453) | (7,578) | |
Net cash used in investing activities | (895,050) | (1,481,997) | (940,140) | |
Cash flows from financing activities: | ||||
Proceeds from borrowings on credit facility | 425,001 | 509,400 | 59,000 | |
Repayment on credit facility | (603,001) | (295,900) | (49,000) | |
Debit issuance costs | (526) | (3,469) | (12,361) | |
Public offering costs | (586) | (2,994) | (1,009) | |
Proceeds from senior notes | 0 | 0 | 450,000 | |
Proceeds from public offerings | 650,688 | 928,432 | 322,680 | |
Distribution to parent | 0 | 0 | ||
Distribution from subsidiary | 0 | 0 | ||
Exercise of stock options | 4,873 | 7,081 | 3,501 | |
Distribution to non-controlling interest | (7,968) | (2,314) | 0 | |
Intercompany transfers | 0 | 0 | 0 | |
Other financing activities | 618 | (9,120) | ||
Net cash provided by financing activities | 468,481 | 1,140,236 | 773,560 | |
Net increase (decrease) in cash and cash equivalents | (10,068) | 14,628 | (10,803) | |
Cash and cash equivalents at beginning of period | 30,183 | 15,555 | 26,358 | |
Cash and cash equivalents at end of period | 20,115 | 30,183 | 15,555 | |
Eliminations [Member] | ||||
Condensed Financial Statements, Captions [Line Items] | ||||
Net cash provided by (used in) operating activities | 0 | 0 | 0 | |
Cash flows from investing activities: | ||||
Additions to oil and natural gas properties | 0 | 0 | 0 | |
Acquisition of leasehold interests | 0 | 0 | 0 | |
Acquisition of royalty interests | 0 | 0 | 0 | |
Purchase of other property and equipment | 0 | 0 | ||
Proceeds from sale of assets | 0 | |||
Equity investments | 0 | 0 | ||
Intercompany transfers | 0 | 0 | 0 | |
Other investing activities | 0 | 0 | 0 | |
Net cash used in investing activities | 0 | 0 | 0 | |
Cash flows from financing activities: | ||||
Proceeds from borrowings on credit facility | 0 | 0 | 0 | |
Repayment on credit facility | 0 | 0 | 0 | |
Debit issuance costs | 0 | |||
Public offering costs | 0 | |||
Proceeds from senior notes | 0 | |||
Proceeds from public offerings | 0 | 0 | 0 | |
Distribution to parent | 0 | 148,760 | ||
Distribution from subsidiary | (60,587) | (166,372) | ||
Exercise of stock options | 0 | |||
Distribution to non-controlling interest | 60,587 | 17,612 | ||
Intercompany transfers | 0 | 0 | 0 | |
Other financing activities | 0 | 0 | ||
Net cash provided by financing activities | 0 | 0 | 0 | |
Net increase (decrease) in cash and cash equivalents | 0 | 0 | 0 | |
Cash and cash equivalents at beginning of period | 0 | 0 | 0 | |
Cash and cash equivalents at end of period | 0 | 0 | 0 | |
Parent Company [Member] | Reportable Legal Entities [Member] | ||||
Condensed Financial Statements, Captions [Line Items] | ||||
Net cash provided by (used in) operating activities | (37,597) | (8,862) | 12,302 | |
Cash flows from investing activities: | ||||
Additions to oil and natural gas properties | 0 | 0 | 0 | |
Acquisition of leasehold interests | 0 | 0 | 0 | |
Acquisition of royalty interests | 0 | 0 | 0 | |
Purchase of other property and equipment | 0 | 0 | ||
Proceeds from sale of assets | 0 | |||
Equity investments | 0 | 0 | ||
Intercompany transfers | (145,023) | (642,978) | (289,344) | |
Other investing activities | 0 | 0 | 0 | |
Net cash used in investing activities | (145,023) | (642,978) | (289,344) | |
Cash flows from financing activities: | ||||
Proceeds from borrowings on credit facility | 0 | 0 | 0 | |
Repayment on credit facility | 0 | 0 | 0 | |
Debit issuance costs | 0 | |||
Public offering costs | (586) | |||
Proceeds from senior notes | 10,000 | |||
Proceeds from public offerings | 650,688 | 693,886 | 322,680 | |
Distribution to parent | 0 | 0 | ||
Distribution from subsidiary | 60,587 | 166,372 | ||
Exercise of stock options | 4,873 | |||
Distribution to non-controlling interest | 0 | 0 | ||
Intercompany transfers | (532,800) | (217,900) | (49,000) | |
Other financing activities | 8,962 | (6,126) | ||
Net cash provided by financing activities | 182,762 | 651,320 | 277,554 | |
Net increase (decrease) in cash and cash equivalents | 142 | (520) | 512 | |
Cash and cash equivalents at beginning of period | 6 | 526 | 14 | |
Cash and cash equivalents at end of period | 148 | 6 | 526 | |
Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member] | ||||
Condensed Financial Statements, Captions [Line Items] | ||||
Net cash provided by (used in) operating activities | 390,266 | 313,438 | 138,630 | |
Cash flows from investing activities: | ||||
Additions to oil and natural gas properties | (419,512) | (493,063) | (292,586) | |
Acquisition of leasehold interests | (437,455) | (845,826) | (195,893) | |
Acquisition of royalty interests | 0 | 0 | 0 | |
Purchase of other property and equipment | (1,213) | (44,213) | ||
Proceeds from sale of assets | 9,739 | |||
Equity investments | (2,702) | (627) | ||
Intercompany transfers | 145,023 | 642,978 | 289,344 | |
Other investing activities | 0 | (1,453) | (7,578) | |
Net cash used in investing activities | (706,120) | (742,204) | (206,713) | |
Cash flows from financing activities: | ||||
Proceeds from borrowings on credit facility | 390,501 | 431,400 | 59,000 | |
Repayment on credit facility | (603,001) | (217,900) | (49,000) | |
Debit issuance costs | (85) | |||
Public offering costs | 0 | |||
Proceeds from senior notes | 0 | |||
Proceeds from public offerings | 0 | 0 | 0 | |
Distribution to parent | 0 | 0 | ||
Distribution from subsidiary | 0 | 0 | ||
Exercise of stock options | 0 | |||
Distribution to non-controlling interest | 0 | 0 | ||
Intercompany transfers | 532,800 | 217,900 | 49,000 | |
Other financing activities | (1,834) | (2,994) | ||
Net cash provided by financing activities | 320,215 | 429,566 | 56,006 | |
Net increase (decrease) in cash and cash equivalents | 4,361 | 800 | (12,077) | |
Cash and cash equivalents at beginning of period | 15,067 | 14,267 | 26,344 | |
Cash and cash equivalents at end of period | 19,428 | 15,067 | 14,267 | |
Non-Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member] | ||||
Condensed Financial Statements, Captions [Line Items] | ||||
Net cash provided by (used in) operating activities | 63,832 | 51,813 | 4,845 | |
Cash flows from investing activities: | ||||
Additions to oil and natural gas properties | 0 | (5,276) | 0 | |
Acquisition of leasehold interests | 0 | 0 | 0 | |
Acquisition of royalty interests | (43,907) | (57,689) | (444,083) | |
Purchase of other property and equipment | 0 | 0 | ||
Proceeds from sale of assets | 0 | |||
Equity investments | 0 | (33,850) | ||
Intercompany transfers | 0 | 0 | 0 | |
Other investing activities | 0 | 0 | 0 | |
Net cash used in investing activities | (43,907) | (96,815) | (444,083) | |
Cash flows from financing activities: | ||||
Proceeds from borrowings on credit facility | 34,500 | 78,000 | 0 | |
Repayment on credit facility | 0 | (78,000) | 0 | |
Debit issuance costs | (441) | |||
Public offering costs | 0 | |||
Proceeds from senior notes | 440,000 | |||
Proceeds from public offerings | 0 | 234,546 | 0 | |
Distribution to parent | 0 | (148,760) | ||
Distribution from subsidiary | 0 | 0 | ||
Exercise of stock options | 0 | |||
Distribution to non-controlling interest | (68,555) | (19,926) | ||
Intercompany transfers | 0 | 0 | 0 | |
Other financing activities | (6,510) | 0 | ||
Net cash provided by financing activities | (34,496) | 59,350 | 440,000 | |
Net increase (decrease) in cash and cash equivalents | (14,571) | 14,348 | 762 | |
Cash and cash equivalents at beginning of period | 15,110 | 762 | 0 | |
Cash and cash equivalents at end of period | $ 539 | $ 15,110 | $ 762 |
Supplemental Information on O98
Supplemental Information on Oil and Natural Gas Operations (Unaudited) - Capitalized Oil and Natural Gas Costs (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Oil and Natural Gas Properties: | ||
Proved properties | $ 2,848,557 | $ 2,345,077 |
Unproved properties | 1,106,816 | 773,520 |
Total Oil and Natural Gas Properties | 3,955,373 | 3,118,597 |
Accumulated depreciation, depletion, amortization | (512,144) | (296,317) |
Accumulated impairment | (897,962) | (83,164) |
Oil and natural gas properties, net | $ 2,545,267 | $ 2,739,116 |
Supplemental Information on O99
Supplemental Information on Oil and Natural Gas Operations (Unaudited) - Costs Incurred in Crude Oil and Natural Gas Activities (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Acquisition costs | |||
Proved properties | $ 64,340 | $ 302,234 | $ 339,130 |
Unproved properties | 448,638 | 601,188 | 279,402 |
Development costs | 42,749 | 86,097 | 88,460 |
Exploration costs | 319,102 | 475,756 | 242,929 |
Capitalized asset retirement costs | 3,458 | 4,962 | 697 |
Total | $ 878,287 | $ 1,470,237 | $ 950,618 |
Supplemental Information on 100
Supplemental Information on Oil and Natural Gas Operations (Unaudited) - Results of Operations for Oil and Natural Gas Producing Activities (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Extractive Industries [Abstract] | |||
Oil, natural gas and natural gas liquid sales | $ 446,733 | $ 495,718 | $ 208,002 |
Lease operating expenses | (82,625) | (55,384) | (21,157) |
Production and ad valorem taxes | (32,990) | (32,638) | (12,899) |
Gathering and transportation | (6,091) | (3,288) | (918) |
Depreciation, depletion, and amortization | (216,056) | (168,674) | (65,821) |
Impairment | (814,798) | 0 | 0 |
Asset retirement obligation accretion expense | (833) | (467) | (201) |
Income tax expense | 201,310 | (108,985) | (31,754) |
Results of operations | $ (505,350) | $ 126,282 | $ 75,252 |
Supplemental Information on 101
Supplemental Information on Oil and Natural Gas Operations (Unaudited) - Oil and Natural Gas Reserves (Details) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2015USD ($)BoewellacquisitionftbblMcf | Dec. 31, 2014USD ($)BoewellacquisitionbblMcf | Dec. 31, 2013USD ($)wellbblMcf | Dec. 31, 2012bblMcf | |
Proved Developed and Undeveloped Reserves (Volume) | ||||
Number of major acquisitions | acquisition | 1 | 2 | ||
Number of existing vertical wells | well | 136 | 280 | ||
Number of existing horizontal wells | well | 4 | 6 | ||
Number of vertical wells acquired | well | 3 | |||
Number of horizontal PUDs included in the acquired reserves | well | 0 | 0 | ||
Number of vertical wells developed, working interest | well | 2 | 18 | ||
Number of horizontal wells developed, working interest | well | 119 | 103 | ||
Number of vertical wells developed, mineral interest | well | 1 | |||
Number of horizontal wells developed, mineral interest | well | 16 | 14 | ||
Number of vertical wells developed | well | 2 | 19 | ||
Number of horizontal wells developed | well | 135 | 117 | ||
Number of vertical wells developed, proved undeveloped category | well | 1 | 5 | ||
Number of horizontal wells developed, proved undeveloped category | well | 66 | |||
Number of vertical locations downgraded | well | 89 | 73 | 92 | |
Proved Undeveloped Reserves, Vertical Wells Downgraded, Working Interest | well | 80 | |||
Proved Undeveloped Reserves, Horizontal Wells Downgraded, Working Interest | well | 22 | |||
Proved Undeveloped Reserves, Vertical Wells Downgraded, Mineral Interest | well | 22 | |||
Proved Undeveloped Reserves, Vertical Reclassifications | Boe | 8,607,000 | |||
Proved undeveloped reserves, increase (Energy) | Boe | 18,419,000 | |||
Proved Undeveloped Reserves (Energy) | ||||
Beginning proved undeveloped reserves at December 31, 2014 | Boe | 46,347,783 | |||
Undeveloped reserves transferred to developed | Boe | (13,680,000) | |||
Revisions | Boe | (12,656,000) | |||
Extensions and discoveries | Boe | 44,755,000 | |||
Ending proved undeveloped reserves at December 31, 2015 | Boe | 64,767,000 | 46,347,783 | ||
Percent of proved undeveloped reserve extensions that are more than one offset away from existing producing wells | 20.00% | |||
Distance from producing wells | ft | 1,700 | |||
Downward revisions | Boe | 12,656,000 | |||
Proved Undeveloped Reserves, Reclassifications | Boe | 14,619,000 | |||
Proved undeveloped reserves, planned development period | 5 years | |||
Capital expenditures towards development of proved undeveloped reserves | $ | $ 42,749 | $ 86,097 | $ 88,460 | |
Martin County, Texas [Member] | ||||
Proved Developed and Undeveloped Reserves (Volume) | ||||
Number of major acquisitions | acquisition | 1 | |||
Oil [Member] | ||||
Proved Developed and Undeveloped Reserves (Volume) | ||||
Beginning of the period | bbl | 75,689,589 | 42,600,852 | 26,196,859 | |
Extensions and discoveries | bbl | 48,725,132 | 37,068,820 | 17,041,744 | |
Revisions of previous estimates | bbl | (12,130,474) | (6,784,560) | (5,943,164) | |
Purchase of reserves in place | bbl | 2,775,599 | 8,186,053 | 7,328,162 | |
Production | bbl | (9,081,135) | (5,381,576) | (2,022,749) | |
End of the period | bbl | 105,978,711 | 75,689,589 | 42,600,852 | |
Proved Developed Reserves (Volume) | bbl | 60,569,398 | 43,885,835 | 19,789,965 | 7,189,367 |
Proved Undeveloped Reserves (Volume) | bbl | 45,409,313 | 31,803,754 | 22,810,887 | 19,007,492 |
Natural Gas Liquids [Member] | ||||
Proved Developed and Undeveloped Reserves (Volume) | ||||
Beginning of the period | bbl | 18,541,932 | 10,705,724 | 8,251,429 | |
Extensions and discoveries | bbl | 12,055,631 | 7,828,094 | 4,597,856 | |
Revisions of previous estimates | bbl | (4,080,886) | 649,476 | (3,455,306) | |
Purchase of reserves in place | bbl | 1,165,090 | 360,536 | 1,672,824 | |
Production | bbl | (1,677,623) | (1,001,898) | (361,079) | |
End of the period | bbl | 26,004,144 | 18,541,932 | 10,705,724 | |
Proved Developed Reserves (Volume) | bbl | 15,418,353 | 11,221,428 | 4,973,493 | 2,999,440 |
Proved Undeveloped Reserves (Volume) | bbl | 10,585,791 | 7,320,504 | 5,732,231 | 5,251,989 |
Natural Gas [Member] | ||||
Proved Developed and Undeveloped Reserves (Volume) | ||||
Beginning of the period | Mcf | 111,605,260 | 61,679,496 | 34,570,148 | |
Extensions and discoveries | Mcf | 53,452,948 | 52,099,252 | 24,184,540 | |
Revisions of previous estimates | Mcf | (14,726,160) | (17,726,552) | (5,786,180) | |
Purchase of reserves in place | Mcf | 7,101,933 | 19,898,649 | 10,441,485 | |
Production | Mcf | (7,931,237) | (4,345,585) | (1,730,497) | |
End of the period | Mcf | 149,502,744 | 111,605,260 | 61,679,496 | |
Proved Developed Reserves (Volume) | Mcf | 96,871,109 | 68,264,113 | 31,428,756 | 12,864,941 |
Proved Undeveloped Reserves (Volume) | Mcf | 52,631,635 | 43,341,147 | 30,250,740 | 21,705,207 |
Supplemental Information on 102
Supplemental Information on Oil and Natural Gas Operations (Unaudited) - Standardized Measure of Discounted Future Net Cash Flows - Proved Crude Oil and Natural Gas Reserves (Details) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Standardized Measure [Abstract] | ||||
Future cash inflows | $ 5,377,783 | $ 7,695,368 | $ 4,604,241 | |
Future development costs | (548,239) | (602,438) | (517,075) | |
Future production costs | (1,279,101) | (1,278,487) | (806,895) | |
Future production taxes | (363,129) | (534,851) | (318,396) | |
Future income tax expenses | (28,233) | (672,380) | (674,260) | |
Future net cash flows | 3,159,081 | 4,607,212 | 2,287,615 | |
10% discount to reflect timing of cash flows | (1,740,948) | (2,561,988) | (1,311,976) | |
Standardized measure of discounted future net cash flows | $ 1,418,133 | $ 2,045,224 | $ 975,639 | $ 367,220 |
Supplemental Information on 103
Supplemental Information on Oil and Natural Gas Operations (Unaudited) - Average First Day of the Month Price for Oil, Natural Gas & Natural Gas Liquids (Details) | 12 Months Ended | ||
Dec. 31, 2015$ / bbl$ / Mcf | Dec. 31, 2014$ / bbl$ / Mcf | Dec. 31, 2013$ / bbl$ / Mcf | |
Oil [Member] | |||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | |||
Average sales prices (dollars per unit) | 45.07 | 87.15 | 92.59 |
Natural Gas [Member] | |||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | |||
Average sales prices (dollars per unit) | $ / Mcf | 1.83 | 4.85 | 4.13 |
Natural Gas Liquids [Member] | |||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | |||
Average sales prices (dollars per unit) | 12.56 | 30.09 | 37.82 |
Supplemental Information on 104
Supplemental Information on Oil and Natural Gas Operations (Unaudited) - Principal Changes in Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward] | |||
Standardized measure of discounted future net cash flows at the beginning of the period | $ 2,045,224 | $ 975,639 | $ 367,220 |
Sales of oil and natural gas, net of production costs | (331,119) | (404,409) | (173,946) |
Purchase of minerals in place | 57,359 | 291,807 | 305,109 |
Extensions and discoveries, net of future development costs | 629,149 | 1,135,293 | 552,450 |
Previously estimated development costs incurred during the period | 129,901 | 111,527 | 76,631 |
Net changes in prices and production costs | (1,383,698) | (105,210) | 51,828 |
Changes in estimated future development costs | 38,638 | (4,877) | (5,822) |
Revisions of previous quantity estimates | (377,160) | (173,004) | (126,993) |
Accretion of discount | 236,716 | 151,481 | 57,988 |
Net change in income taxes | 268,963 | (12,326) | (168,570) |
Net changes in timing of production and other | 104,160 | 79,303 | 39,744 |
Standardized measure of discounted future net cash flows at the end of the period | $ 1,418,133 | $ 2,045,224 | $ 975,639 |
Quarterly Financial Data (Un105
Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Quarterly Financial Information Disclosure [Abstract] | |||||||||||
Revenues | $ 114,323 | $ 111,946 | $ 119,063 | $ 101,401 | $ 131,583 | $ 139,127 | $ 127,004 | $ 98,004 | $ 446,733 | $ 495,718 | $ 208,002 |
Income (loss) from operations | (187,813) | (254,773) | (299,120) | 1,437 | 37,899 | 63,516 | 63,192 | 48,063 | (740,269) | 212,670 | 95,194 |
Income tax expense (benefit) | (6,487) | (81,461) | (116,732) | 3,370 | 56,243 | 23,978 | 15,163 | 13,601 | (201,310) | 108,985 | 31,754 |
Net income (loss) | (186,835) | (156,042) | (211,352) | 6,439 | 99,917 | 44,641 | 27,824 | 23,589 | (547,790) | 195,971 | 54,587 |
Less: Net income attributable to noncontrolling interest | 574 | 739 | 935 | 590 | 1,243 | 902 | 71 | 0 | 2,838 | 2,216 | 0 |
Net income (loss) attributable to Diamondback Energy, Inc. | $ (187,409) | $ (156,781) | $ (212,287) | $ 5,849 | $ 98,674 | $ 43,739 | $ 27,753 | $ 23,589 | $ (550,628) | $ 193,755 | $ 54,587 |
Earnings per common share | |||||||||||
Basic (in dollars per share) | $ (2.80) | $ (2.40) | $ (3.45) | $ 0.10 | $ 1.74 | $ 0.79 | $ 0.55 | $ 0.49 | $ (8.74) | $ 3.67 | $ 1.30 |
Diluted (in dollars per share) | $ (2.80) | $ (2.40) | $ (3.45) | $ 0.10 | $ 1.73 | $ 0.79 | $ 0.54 | $ 0.48 | $ (8.74) | $ 3.64 | $ 1.29 |