Document_and_Entity_Informatio
Document and Entity Information (USD $) | 12 Months Ended | ||
In Billions, except Share data, unless otherwise specified | Dec. 31, 2014 | Mar. 01, 2015 | Jun. 30, 2014 |
Document And Entity Information [Abstract] | |||
Document Type | 10-K | ||
Amendment Flag | FALSE | ||
Document Period End Date | 31-Dec-14 | ||
Document Fiscal Year Focus | 2014 | ||
Document Fiscal Period Focus | FY | ||
Trading Symbol | MRD | ||
Entity Registrant Name | MEMORIAL RESOURCE DEVELOPMENT CORP. | ||
Entity Central Index Key | 1599222 | ||
Current Fiscal Year End Date | -19 | ||
Entity Well Known Seasoned Issuer | No | ||
Entity Current Reporting Status | Yes | ||
Entity Voluntary Filers | No | ||
Entity Filer Category | Non-accelerated Filer | ||
Entity Common Stock, Shares Outstanding | 191,757,539 | ||
Entity Public Float | $1.20 |
CONSOLIDATED_AND_COMBINED_BALA
CONSOLIDATED AND COMBINED BALANCE SHEETS (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Current assets: | ||
Cash and cash equivalents | $5,958 | $77,721 |
Restricted cash | 35,000 | |
Accounts receivable: | ||
Oil and natural gas sales | 82,263 | 68,764 |
Joint interest owners and other | 49,313 | 19,958 |
Affiliates | 4,652 | |
Short-term derivative instruments | 340,056 | 9,289 |
Prepaid expenses and other current assets | 28,027 | 19,513 |
Total current assets | 505,617 | 234,897 |
Property and equipment, at cost: | ||
Oil and natural gas properties, successful efforts method | 4,844,529 | 3,037,298 |
Other | 33,815 | 10,331 |
Accumulated depreciation, depletion and impairment | -1,340,688 | -627,925 |
Property and equipment, net | 3,537,656 | 2,419,704 |
Long-term derivative instruments | 435,369 | 48,616 |
Restricted investments | 77,361 | 73,385 |
Restricted cash | 260 | 15,506 |
Other long-term assets | 37,284 | 37,053 |
Total assets | 4,593,547 | 2,829,161 |
Current liabilities: | ||
Accounts payable | 25,772 | 20,734 |
Accounts payable - affiliates | 624 | 1,975 |
Revenues payable | 57,352 | 56,091 |
Accrued liabilities | 199,000 | 98,130 |
Short-term derivative instruments | 3,289 | 9,711 |
Total current liabilities | 286,037 | 186,641 |
Noncurrent liabilities: | ||
Asset retirement obligations | 122,531 | 111,679 |
Long-term derivative instruments | 6,080 | |
Deferred tax liabilities | 95,017 | 3,106 |
Other long-term liabilities | 8,585 | 306 |
Total liabilities | 2,890,583 | 1,971,029 |
Commitments and contingencies (Note 16) | ||
Stockholders' equity (deficit): | ||
Preferred stock, $.01 par value: 50,000,000 shares authorized; no shares issued and outstanding | ||
Common stock, $.01 par value: 600,000,000 shares authorized; 193,435,414 shares issued and outstanding at December 31, 2014; no shares authorized, issued or outstanding at December 31, 2013 | 1,935 | |
Additional paid-in capital | 1,367,346 | |
Accumulated earnings (deficit) | -786,871 | |
Total stockholders' equity | 582,410 | |
Members' equity: | ||
Members | 237,186 | |
Previous owners (Note 1) | 40,331 | |
Total members' equity | 277,517 | |
Noncontrolling interests | 1,120,554 | 580,615 |
Total equity | 1,702,964 | 858,132 |
Total liabilities and equity | 4,593,547 | 2,829,161 |
MRD [Member] | ||
Noncurrent liabilities: | ||
Long-term debt | 783,000 | 871,150 |
MEMP [Member] | ||
Noncurrent liabilities: | ||
Long-term debt | $1,595,413 | $792,067 |
CONSOLIDATED_AND_COMBINED_BALA1
CONSOLIDATED AND COMBINED BALANCE SHEETS (Parenthetical) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
Statement Of Financial Position [Abstract] | ||
Preferred stock, par value | $0.01 | |
Preferred stock, shares authorized | 50,000,000 | |
Preferred stock, shares issued | 0 | |
Preferred stock, shares outstanding | 0 | |
Common stock, par value | $0.01 | $0.01 |
Common stock, shares authorized | 600,000,000 | 0 |
Common stock, shares issued | 193,435,414 | 0 |
Common stock, shares outstanding | 193,435,414 | 0 |
STATEMENTS_OF_CONSOLIDATED_AND
STATEMENTS OF CONSOLIDATED AND COMBINED OPERATIONS (USD $) | 12 Months Ended | ||
In Thousands, except Per Share data, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Revenues: | |||
Oil & natural gas sales | $894,967 | $571,948 | $393,631 |
Other revenues | 4,378 | 3,075 | 3,237 |
Total revenues | 899,345 | 575,023 | 396,868 |
Costs and expenses: | |||
Lease operating | 161,303 | 113,640 | 103,754 |
Pipeline operating | 2,068 | 1,835 | 2,114 |
Exploration | 16,603 | 2,356 | 9,800 |
Production and ad valorem taxes | 45,751 | 27,146 | 23,624 |
Depreciation, depletion, and amortization | 314,193 | 184,717 | 138,672 |
Impairment of proved oil and natural gas properties | 432,116 | 6,600 | 28,871 |
Incentive unit compensation expense | 943,949 | 43,279 | 9,510 |
General and administrative | 87,673 | 82,079 | 59,677 |
Accretion of asset retirement obligations | 6,306 | 5,581 | 5,009 |
(Gain) loss on commodity derivative instruments | -749,988 | -29,294 | -34,905 |
(Gain) loss on sale of properties | 3,057 | -85,621 | -9,761 |
Other, net | -12 | 649 | 502 |
Total costs and expenses | 1,263,019 | 352,967 | 336,867 |
Operating income (loss) | -363,674 | 222,056 | 60,001 |
Other income (expense): | |||
Interest expense, net | -133,833 | -69,250 | -33,238 |
Loss on extinguishment of debt | -37,248 | 0 | 0 |
Amortization of investment premium | 0 | 0 | -194 |
Other, net | -337 | 145 | 535 |
Total other income (expense) | -171,418 | -69,105 | -32,897 |
Income (loss) before income taxes | -535,092 | 152,951 | 27,104 |
Income tax benefit (expense) | -100,971 | -1,619 | -107 |
Net income (loss) | -636,063 | 151,332 | 26,997 |
Net income (loss) attributable to noncontrolling interest | 126,788 | 49,830 | -2,701 |
Net income (loss) attributable to Memorial Resource Development Corp. | -762,851 | 101,502 | 29,698 |
Net (income) loss allocated to members | -20,305 | -90,712 | 7,620 |
Net (income) loss allocated to previous owners | -1,425 | -10,790 | -37,318 |
Net income (loss) available to common stockholders | ($784,581) | $0 | $0 |
Earnings per common share: (Note 10) | |||
Basic | ($4.08) | $0 | $0 |
Diluted | ($4.08) | $0 | $0 |
Weighted average common and common equivalent shares outstanding: | |||
Basic | 192,498 | 0 | 0 |
Diluted | 192,498 | 0 | 0 |
STATEMENTS_OF_CONSOLIDATED_AND1
STATEMENTS OF CONSOLIDATED AND COMBINED CASH FLOWS (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Cash flows from operating activities: | |||
Net income (loss) | ($636,063) | $151,332 | $26,997 |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||
Depreciation, depletion, and amortization | 314,193 | 184,717 | 138,672 |
Impairment of proved oil and natural gas properties | 432,116 | 6,600 | 28,871 |
(Gain) loss on derivatives | -749,843 | -29,533 | -29,323 |
Cash settlements (paid) received on derivative instruments | 20,559 | 30,403 | 72,045 |
Cash settlements on terminated derivatives | 5,326 | 0 | 0 |
Premiums paid for derivatives | -6,065 | 0 | -411 |
Loss on extinguishment of debt | 30,248 | 0 | 0 |
Amortization of deferred financing costs | 7,436 | 8,343 | 3,584 |
Accretion of senior notes net discount | 2,501 | 554 | 0 |
Amortization of investment premium | 0 | 0 | 194 |
Accretion of asset retirement obligations | 6,306 | 5,581 | 5,009 |
Amortization of equity awards | 10,678 | 3,557 | 1,423 |
(Gain) loss on sale of properties | 3,057 | -85,621 | -9,761 |
Non-cash compensation expense | 916,218 | 1,057 | 0 |
Exploration costs | 14,953 | 181 | 6,980 |
Deferred income tax expense (benefit) | 100,230 | 76 | -312 |
Changes in operating assets and liabilities: | |||
Accounts receivable | -17,635 | -15,758 | -7,382 |
Prepaid expenses and other assets | -7,424 | -2,986 | -1,574 |
Payables and accrued liabilities | 21,208 | 19,320 | 5,392 |
Other | 8,272 | 0 | 0 |
Net cash provided by operating activities | 476,271 | 277,823 | 240,404 |
Cash flows from investing activities: | |||
Acquisitions of oil and natural gas properties | -1,177,670 | -105,762 | -360,678 |
Additions to oil and gas properties | -674,396 | -360,015 | -273,334 |
Additions to other property and equipment | -17,067 | -2,670 | -2,674 |
Additions to restricted investments | -3,976 | -5,361 | -4,599 |
Deposits for property acquisitions | -215 | 0 | 0 |
Decrease (increase) in restricted cash | 49,946 | -49,347 | -3 |
Proceeds from the sale of oil and natural gas properties | 6,700 | 155,712 | 34,521 |
Other | -301 | 0 | 29 |
Net cash used in investing activities | -1,816,979 | -367,443 | -606,738 |
Cash flows from financing activities: | |||
Advances on revolving credit facilities | 2,746,800 | 1,132,755 | 619,450 |
Payments on revolving credit facilities | -2,457,900 | -1,766,037 | -251,569 |
Proceeds from the issuances of senior notes | 1,092,425 | 1,031,563 | 0 |
Redemption of senior notes | -351,808 | 0 | 0 |
Borrowings under second lien credit facility | 0 | 325,000 | 0 |
Redemption of second lien credit facility | -328,282 | 0 | 0 |
Deferred financing costs | -30,334 | -41,175 | -3,501 |
Proceeds from changes in ownership interests in MEMP | 0 | 135,012 | 0 |
Repurchased shares under repurchase program | -161 | 0 | 0 |
Restricted MEMP units returned to plan | -1,012 | 0 | 0 |
Purchase of additional interests in consolidated subsidiaries | -3,292 | -15,135 | 0 |
Contributions from previous owners | 0 | 1,214 | 44,072 |
Distributions to the Funds | 0 | -732,362 | 0 |
Distributions to noncontrolling interests | -149,084 | -78,083 | -15,208 |
Distributions made by previous owners | 0 | -4,005 | -28,772 |
Cash retained by previous owners | 0 | -7,909 | 0 |
Other | 320 | 455 | 0 |
Net cash provided by financing activities | 1,268,945 | 117,950 | 361,761 |
Net change in cash and cash equivalents | -71,763 | 28,330 | -4,573 |
Cash and cash equivalents, beginning of period | 77,721 | 49,391 | 53,964 |
Cash and cash equivalents, end of period | 5,958 | 77,721 | 49,391 |
Natural Gas Partners [Member] | |||
Cash flows from financing activities: | |||
Contributions from NGP affiliates related to sale of properties | 1,165 | 2,013 | 45,158 |
Distribution to NGP affiliates related to purchase of assets | -66,693 | -355,494 | -242,174 |
Distribution to NGP affiliates related to sale of assets, net of cash received | -32,770 | 0 | 0 |
MRD Holdco LLC [Member] | |||
Cash flows from financing activities: | |||
Distributions to MRD Holdco | -59,803 | 0 | 0 |
MRD [Member] | |||
Cash flows from financing activities: | |||
Proceeds from public offering | 408,500 | 0 | 0 |
Costs incurred in conjunction with initial public offering | -28,373 | 0 | 0 |
MEMP [Member] | |||
Cash flows from financing activities: | |||
Proceeds from public offering | 553,288 | 511,204 | 202,573 |
Costs incurred in conjunction with initial public offering | -12,510 | -21,066 | -8,268 |
Repurchased shares under repurchase program | ($11,531) | $0 | $0 |
STATEMENTS_OF_CONSOLIDATED_AND2
STATEMENTS OF CONSOLIDATED AND COMBINED EQUITY (USD $) | Total | MRD [Member] | MEMP [Member] | Member Equity [Member] | Member Equity [Member] | Member Equity [Member] | Previous Owners [Member] | Previous Owners [Member] | Previous Owners [Member] | Noncontrolling Interest [Member] | Noncontrolling Interest [Member] | Noncontrolling Interest [Member] | Common Stock [Member] | Common Stock [Member] | Common Stock [Member] | Additional Paid-in Capital [Member] | Additional Paid-in Capital [Member] | Additional Paid-in Capital [Member] | Accumulated earnings (deficit) [Member] | Accumulated earnings (deficit) [Member] | Accumulated earnings (deficit) [Member] |
In Thousands | MRD [Member] | MEMP [Member] | Member Equity [Member] | Member Equity [Member] | Member Equity [Member] | MRD [Member] | MEMP [Member] | MRD [Member] | MEMP [Member] | MRD [Member] | MEMP [Member] | MRD [Member] | MEMP [Member] | ||||||||
MRD [Member] | MEMP [Member] | ||||||||||||||||||||
Members' equity, beginning balance at Dec. 31, 2011 | $853,436 | $261,340 | |||||||||||||||||||
Noncontrolling interests, beginning balance at Dec. 31, 2011 | 161,588 | ||||||||||||||||||||
Total equity, beginning balance at Dec. 31, 2011 | 1,276,364 | ||||||||||||||||||||
Net income (loss) | 26,997 | -7,620 | 37,318 | -2,701 | |||||||||||||||||
Contributions | 44,072 | 0 | 44,072 | 0 | |||||||||||||||||
Contribution of oil and gas properties from NGP affiliate | 6,893 | 0 | 6,893 | 0 | |||||||||||||||||
Net proceeds from MEMP public equity Offering | 194,134 | 0 | 0 | 194,134 | |||||||||||||||||
Distributions | -44,027 | 0 | -28,772 | -15,255 | |||||||||||||||||
Net book value of net assets acquired from affiliates | 0 | 52,217 | -93,696 | 41,479 | |||||||||||||||||
Amortization of MEMP equity awards | 1,423 | 0 | 0 | 1,423 | |||||||||||||||||
Noncontrolling interest's share of net book value in excess of consideration received from sale of assets to MEMP | 0 | 727 | 0 | -727 | |||||||||||||||||
Contribution related to sale of assets to NGP affiliate | 47,171 | 6,291 | 40,138 | 742 | |||||||||||||||||
Net book value of assets acquired by NGP affiliate | -34,506 | -579 | -33,859 | -68 | |||||||||||||||||
Distribution to affiliate in connection with acquisition of assets | -242,174 | -134,964 | 0 | -107,210 | |||||||||||||||||
Impact of equity transactions of MEMP | 0 | 41,930 | 0 | -41,930 | |||||||||||||||||
Other | 362 | 176 | -1 | 187 | |||||||||||||||||
Members' equity, ending balance at Dec. 31, 2012 | 811,614 | 233,433 | |||||||||||||||||||
Noncontrolling interests, ending balance at Dec. 31, 2012 | 231,662 | ||||||||||||||||||||
Total equity, ending balance at Dec. 31, 2012 | 1,276,709 | ||||||||||||||||||||
Net income (loss) | 151,332 | 90,712 | 10,790 | 49,830 | |||||||||||||||||
Contributions | 1,214 | 0 | 1,214 | 0 | |||||||||||||||||
Net proceeds from MEMP public equity Offering | 490,138 | 0 | 0 | 490,138 | |||||||||||||||||
Sale of MEMP common units | 135,012 | 60,701 | 0 | 74,311 | |||||||||||||||||
Distributions | -814,450 | -732,362 | -4,005 | -78,083 | |||||||||||||||||
Net book value of net assets acquired from affiliates | 0 | 50,751 | -181,556 | 130,805 | |||||||||||||||||
Amortization of MEMP equity awards | 3,558 | 0 | 0 | 3,558 | |||||||||||||||||
Noncontrolling interest's share of cash consideration received in excess of the net book value sold to MEMP | 0 | -24 | 0 | 24 | |||||||||||||||||
Distribution to affiliate in connection with acquisition of assets | -351,235 | -98,180 | 0 | -253,055 | |||||||||||||||||
Purchase of noncontrolling interests | -15,135 | -303 | 0 | -14,832 | |||||||||||||||||
Impact of equity transactions of MEMP | 0 | 54,183 | 0 | -54,183 | |||||||||||||||||
Other | -1,765 | 94 | -2,299 | 440 | |||||||||||||||||
Net assets retained by previous owners | -17,246 | 0 | -17,246 | 0 | |||||||||||||||||
Members' equity, ending balance at Dec. 31, 2013 | 277,517 | 237,186 | 40,331 | ||||||||||||||||||
Noncontrolling interests, ending balance at Dec. 31, 2013 | 580,615 | 580,615 | |||||||||||||||||||
Total equity, ending balance at Dec. 31, 2013 | 858,132 | ||||||||||||||||||||
Total stockholders equity, beginning balance at Dec. 31, 2013 | 0 | 0 | 0 | ||||||||||||||||||
Net income (loss) | -636,063 | 20,305 | 1,425 | 126,788 | 0 | 0 | -784,581 | ||||||||||||||
Issuance of shares in connection with restructuring transactions (see Note 1) | 914,862 | 0 | 0 | 0 | 1,710 | 913,152 | 0 | ||||||||||||||
Issuance of shares in connection with initial public offering (see Note 1) | 380,177 | 0 | 0 | 0 | 215 | 379,962 | 0 | ||||||||||||||
Tax related effects in connection with restructuring transactions and initial public offering | -43,251 | 0 | 0 | 0 | 0 | -43,251 | 0 | ||||||||||||||
Share repurchase | -2,215 | -12,903 | 0 | 0 | 0 | 0 | 0 | -12,903 | -1 | 0 | 0 | 0 | -2,214 | 0 | |||||||
Restricted stock awards | 0 | 0 | 0 | 0 | 11 | -11 | 0 | ||||||||||||||
Amortization of restricted stock awards | 2,804 | 0 | 0 | 0 | 0 | 2,804 | 0 | ||||||||||||||
Contribution related to MRD Holdco incentive unit compensation expense (see Note 12) | 111,866 | 0 | 0 | 0 | 0 | 111,866 | 0 | ||||||||||||||
Net proceeds from MEMP public equity Offering | 540,698 | 0 | 0 | 540,698 | 0 | 0 | 0 | ||||||||||||||
Distributions | -149,084 | 0 | 0 | -149,084 | 0 | 0 | 0 | ||||||||||||||
Net book value of net assets acquired from affiliates | 3,303 | 45,059 | -41,756 | 0 | 0 | 0 | 0 | ||||||||||||||
Amortization of MEMP equity awards | 7,874 | 0 | 0 | 7,874 | 0 | 0 | 0 | ||||||||||||||
Contribution related to sale of assets to NGP affiliate | 1,165 | 1,165 | 0 | 0 | 0 | 0 | 0 | ||||||||||||||
Net book value of assets sold to NGP affiliate | -621 | -621 | 0 | 0 | 0 | 0 | 0 | ||||||||||||||
Distribution to affiliate in connection with acquisition of assets | -66,693 | -66,693 | 0 | 0 | 0 | 0 | 0 | ||||||||||||||
Purchase of noncontrolling interests | -3,292 | 0 | 0 | -411 | 0 | -2,881 | 0 | ||||||||||||||
Distribution of net assets to MRD Holdco | -93,084 | -123,078 | 0 | 29,994 | 0 | 0 | 0 | ||||||||||||||
Distribution of shares received in connection with restructuring transactions to MRD Holdco | -110,510 | -110,510 | 0 | 0 | 0 | 0 | 0 | ||||||||||||||
Net equity deemed contribution (distribution) related to net assets transferred to MEMP | 0 | -2,659 | 0 | -2,668 | 0 | 5,327 | 0 | ||||||||||||||
Other | 811 | -154 | 0 | 663 | 0 | 378 | -76 | ||||||||||||||
MEMP restricted units repurchased | -1,012 | 0 | 0 | -1,012 | 0 | 0 | 0 | ||||||||||||||
Members' equity, ending balance at Dec. 31, 2014 | 0 | 0 | |||||||||||||||||||
Total stockholders equity, ending balance at Dec. 31, 2014 | 582,410 | 1,935 | 1,367,346 | -786,871 | |||||||||||||||||
Total equity, ending balance at Dec. 31, 2014 | 1,702,964 | ||||||||||||||||||||
Noncontrolling interests, ending balance at Dec. 31, 2014 | $1,120,554 | $1,120,554 |
Organization_and_Basis_of_Pres
Organization and Basis of Presentation | 12 Months Ended | |
Dec. 31, 2014 | ||
Organization Consolidation And Presentation Of Financial Statements [Abstract] | ||
Organization and Basis of Presentation | Note 1. Organization and Basis of Presentation | |
Overview | ||
Memorial Resource Development Corp. (the “Company”) is a publicly traded Delaware corporation, the common shares of which are listed on the NASDAQ Global Market (“NASDAQ”) under the symbol “MRD.” Unless the context requires otherwise, references to “we,” “us,” “our,” “MRD,” or “the Company” are intended to mean the business and operations of Memorial Resource Development Corp. and its consolidated subsidiaries. | ||
The Company was formed by Memorial Resource Development LLC (“MRD LLC”) in January 2014 to acquire, explore and develop natural gas and oil properties in North America. MRD LLC was a Delaware limited liability company formed on April 27, 2011 by Natural Gas Partners VIII, L.P. (“NGP VIII”), Natural Gas Partners IX, L.P. (“NGP IX”) and NGP IX Offshore Holdings, L.P. (“NGP IX Offshore”) (collectively, the “Funds”) to explore, develop and acquire natural gas and oil properties. The Funds are private equity funds managed by Natural Gas Partners (“NGP”). MRD LLC’s consolidated and combined financial statements represent our predecessor for accounting and financial reporting purposes prior to our initial public offering. | ||
Initial Public Offering and Restructuring Transactions | ||
On June 18, 2014, the Company completed its initial public offering of 21,500,000 common units at a price of $19.00 per share, which generated net proceeds to the Company of approximately $380.2 million after deducting underwriting discounts and commissions and other offering related fees and expenses. The following restructuring events and transactions occurred in connection with our initial public offering: | ||
— | The Funds contributed all of their interests in MRD LLC to MRD Holdco LLC (“MRD Holdco”) and the members of our management who owned incentive units in MRD LLC exchanged those incentive units for substantially identical incentive units in MRD Holdco, after which MRD Holdco owned 100% of MRD LLC; | |
— | WildHorse Resources, LLC (“WildHorse Resources”) sold its subsidiary, WildHorse Resources Management Company, LLC (“WHR Management Company”), to an affiliate of the Funds for approximately $0.2 million in cash, and WHR Management Company entered into a services agreement with the Company and WildHorse Resources pursuant to which WHR Management Company agreed to provide certain management services to WildHorse Resources, which was terminated as of March 1, 2015; | |
— | Classic Hydrocarbons Holdings, L.P. (“Classic”) and Classic Hydrocarbons GP Co., L.L.C. (“Classic GP”) distributed to MRD LLC the ownership interests in Classic Pipeline & Gathering, LLC (“Classic Pipeline”), which owns certain midstream assets in Texas, and Black Diamond Minerals, LLC (“Black Diamond”) distributed to MRD LLC its ownership interests in Golden Energy Partners LLC (“Golden Energy”), which sold all of its assets in May 2014; | |
— | MRD LLC contributed to us substantially all of its assets, comprised of: (i) 100% of the ownership interests in Classic, Classic GP, Black Diamond, Beta Operating Company, LLC (“Beta Operating”), Memorial Resource Finance Corp., MRD Operating LLC (“MRD Operating”), Memorial Production Partners GP LLC (“MEMP GP”) (including MEMP GP’s ownership of 50% of Memorial Production Partners LP’s (“MEMP”) incentive distribution rights) and (ii) 99.9% of the membership interests in WildHorse Resources; | |
— | We issued 128,665,677 shares of our common stock to MRD LLC, which MRD LLC immediately distributed to MRD Holdco; | |
— | We assumed the obligations of MRD LLC under the indenture governing the $350 million in aggregate principal amount of 10.00% / 10.75% Senior PIK Toggle Notes due 2018 (the “PIK notes”) and reimbursed MRD LLC for the June 15, 2014 interest payment made on the PIK notes; | |
— | Certain former management members of WildHorse Resources contributed to us their outstanding incentive units in WildHorse Resources, as well as the remaining 0.1% of the membership interests in WildHorse Resources, and we issued 42,334,323 shares of our common stock and paid cash consideration of $30.0 million to such former management members of WildHorse Resources; | |
— | We entered into a registration rights agreement and a voting agreement with MRD Holdco and certain former management members of WildHorse Resources; | |
— | We entered into a new $2.0 billion revolving credit facility (see Note 8) and used approximately $614.5 million in borrowings under that facility to repay all amounts outstanding under WildHorse Resources’ credit agreements, to partially fund the cash consideration payable to the former management members of WildHorse Resources and to reimburse MRD LLC for the June 15, 2014 interest payment made on the PIK notes; | |
— | Notice of redemption was given to the PIK notes trustee (see Note 8) specifying a redemption date of July 16, 2014 and indicating that a portion of the net proceeds from our initial public offering, which temporarily reduced amounts outstanding under our new revolving credit facility, would be used to redeem the PIK notes at a redemption price of 102% of the principal amount of the PIK notes plus accrued and unpaid interest thereon to the date of redemption; | |
— | MRD Operating entered into a merger agreement with MRD LLC pursuant to which after the termination or earlier discharge of the PIK notes MRD LLC would merge into MRD Operating; | |
— | MRD LLC distributed to MRD Holdco the following: (i) BlueStone Natural Resources Holdings, LLC (“BlueStone”), which sold substantially all of its assets in July 2013 for $117.9 million, MRD Royalty LLC, which owns certain leasehold interests and overriding royalty interests in Texas and Montana, MRD Midstream LLC, which owns an indirect interest in certain midstream assets in North Louisiana, Golden Energy and Classic Pipeline; (ii) 5,360,912 subordinated units of MEMP; (iii) the right to the remaining cash to be released from the debt service reserve account in connection with the redemption or earlier discharge of the PIK notes plus the cash received from us in reimbursement of the interest paid on June 15, 2014 in respect of the PIK notes; and (iv) approximately $6.7 million of cash received by MRD LLC in connection with the sale of Golden Energy’s assets in May 2014; | |
— | We irrevocably deposited with the PIK notes trustee approximately $360.0 million on June 27, 2014, which was an amount sufficient to fund the redemption of the PIK notes on the redemption date and to satisfy and discharge our obligations under the PIK notes and the related indenture. The discharge became effective upon the irrevocable deposit of the funds with the PIK notes trustee; and | |
— | MRD LLC merged into MRD Operating. | |
Previous Owners | ||
References to “the previous owners” for accounting and financial reporting purposes refer collectively to: | ||
— | Certain oil and natural gas properties and related assets primarily in the Permian Basin, East Texas and the Rockies that MEMP acquired through equity transactions in October 2013 from certain affiliates of NGP. In October 2013, MEMP acquired Boaz Energy, LLC (“Boaz”), Crown Energy Partners, LLC (“Crown”), the Crown net profits interest and overriding royalty interest (“Crown NPI/ORRI”), Propel Energy SPV LLC (“Propel SPV”), together with its wholly-owned subsidiary Propel Energy Services, LLC (“Propel Energy Services”), and Stanolind Oil and Gas SPV LLC (“Stanolind SPV”) from Boaz Energy Partners, LLC (“Boaz Energy Partners”), Crown Energy Partners Holdings, LLC (“Crown Holdings”), Propel Energy, LLC (“Propel Energy”) and Stanolind Oil and Gas LP (“Stanolind”), all of which are primarily owned by two of the Funds. | |
— | A net profits interest that WildHorse Resources purchased from NGP Income Co-Investment Fund II, L.P. (“NGPCIF”) in February 2014 (“NGPCIF NPI”). NGPCIF is controlled by NGP. Upon the completion of the 2010 Petrohawk and Clayton Williams acquisitions, WildHorse Resources sold a net profits interest in these properties to NGPCIF. Since WildHorse Resources sold the net profits interest, the historical results are accounted for as a working interest for all periods. | |
Our audited financial statements reported herein include the financial position and results attributable to: (i) those certain oil and natural gas properties and related assets that MEMP acquired through equity transactions in October 2013 from Boaz Energy Partners, Crown Holdings, Propel Energy and Stanolind and (ii) NGPCIF NPI. | ||
Basis of Presentation | ||
The financial statements reported herein include the financial position and results attributable to both our predecessor and the previous owners on a combined basis for periods prior to our initial public offering. For periods after the completion of our public offering, our consolidated financial statements include our accounts and those of our subsidiaries in which we have a controlling interest. Due to our control of MEMP through our ownership of MEMP GP, we are required to consolidate MEMP for accounting and financial reporting purposes. MEMP is owned 99.9% by its limited partners and 0.1% by MEMP GP. | ||
All material intercompany transactions and balances have been eliminated in preparation of our consolidated and combined financial statements. The accompanying consolidated and combined financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). | ||
We have two reportable business segments, both of which are engaged in the acquisition, exploration, development and production of oil and natural gas properties (See Note 14). Our reportable business segments are as follows: | ||
— | MRD—reflects the combined operations of the Company, MRD Operating, MRD LLC, WildHorse Resources and its previous owners, Classic and Classic GP, Black Diamond, BlueStone, Beta Operating and MEMP GP. | |
— | MEMP—reflects the combined operations of MEMP, its previous owners, and historical dropdown transactions that occurred between MEMP and other MRD LLC consolidating subsidiaries. | |
Segment financial information has been retrospectively revised for the following common control transactions for comparability purposes: | ||
— | acquisition by MEMP of all the outstanding membership interests in Tanos Energy, LLC (“Tanos”) from MRD LLC for a purchase price of approximately $77.4 million on October 1, 2013; | |
— | acquisition by MEMP of all the outstanding membership interests in Prospect Energy, LLC (“Prospect Energy”) from Black Diamond for a purchase price of approximately $16.3 million on October 1, 2013; | |
— | acquisition by MEMP of certain of the oil and natural gas properties in Jackson County, Texas from MRD LLC for a purchase price of approximately $2.6 million on October 1, 2013; | |
— | acquisition by MEMP of all the outstanding membership interests in WHT Energy Partners LLC (“WHT”) from WildHorse Resources and Tanos for a purchase price of approximately $200.0 million on March 28, 2013; | |
— | acquisition by MEMP of certain assets from Classic in East Texas in May 2012 for a purchase price of approximately $27.0 million; and | |
— | acquisition by MEMP of certain assets from Tanos in East Texas in April 2012 for a purchase price of approximately $18.5 million. |
Summary_of_Significant_Account
Summary of Significant Accounting Policies | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Accounting Policies [Abstract] | ||||||||||||
Summary of Significant Accounting Policies | MEMORIAL RESOURCE DEVELOPMENT CORP. | |||||||||||
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS | ||||||||||||
Note 2. Summary of Significant Accounting Policies | ||||||||||||
Use of Estimates | ||||||||||||
The preparation of consolidated and combined financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated and combined financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. | ||||||||||||
Significant estimates include, but are not limited to, oil and natural gas reserves; depreciation, depletion, and amortization of proved oil and natural gas properties; future cash flows from oil and natural gas properties; impairment of long-lived assets; fair value of derivatives; fair value of equity and incentive unit compensation; fair values of assets acquired and liabilities assumed in business combinations and asset retirement obligations. | ||||||||||||
Principles of Consolidation and Combination | ||||||||||||
Our consolidated financial statements include our accounts and those of our subsidiaries in which we have a controlling interest, after the elimination of all intercompany accounts and transactions. Likewise, the combined financial statements include the accounts of our predecessor and the previous owners as discussed above. All material intercompany balances and transactions have been eliminated. Certain prior period balances have been reclassified to better align with financial statement presentation in the current fiscal year. | ||||||||||||
Cash and Cash Equivalents | ||||||||||||
Cash and cash equivalents represent unrestricted cash on hand and all highly liquid investments with original contractual maturities of three months or less. | ||||||||||||
Book Overdrafts | ||||||||||||
Book overdrafts, representing outstanding checks in excess of funds on deposit, are classified as accounts payable and the change in the related balance is reflected in operating activities in the statement of cash flows. | ||||||||||||
Concentrations of Credit Risk | ||||||||||||
Cash balances, accounts receivable, restricted investments and derivative financial instruments are financial instruments potentially subject to credit risk. Cash and cash equivalents are maintained in bank deposit accounts which, at times, may exceed the federally insured limits. Management periodically reviews and assesses the financial condition of the banks to mitigate the risk of loss. Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with MEMP’s offshore Southern California oil and gas properties. These restricted investments may consist of money market deposit accounts, money market mutual funds, commercial paper, and U.S. Government securities, all held with credit-worthy financial institutions. Derivative financial instruments are generally executed with major financial institutions that expose us to market and credit risks and which may, at times, be concentrated with certain counterparties. The credit worthiness of the counterparties is subject to continual review. We rely upon netting arrangements with counterparties to reduce credit exposure. Neither we nor our predecessor and the previous owners have experienced any losses from such instruments. | ||||||||||||
Oil and natural gas are sold to a variety of purchasers, including intrastate and interstate pipelines or their marketing affiliates and independent marketing companies. Accounts receivable from joint operations are from a number of oil and natural gas companies, partnerships, individuals, and others who own interests in the properties operated by us, our predecessor, and the previous owners. Generally, operators of crude oil and natural gas properties have the right to offset future revenues against unpaid charges related to operated wells, minimizing the credit risk associated with these receivables. Additionally, management believes that any credit risk imposed by a concentration in the oil and natural gas industry is mitigated by the creditworthiness of its customer base. An allowance for doubtful accounts is recorded after all reasonable efforts have been exhausted to collect or settle the amount owed. Any amounts outstanding longer than the contractual terms are considered past due. Management determined that an allowance for uncollectible accounts was unnecessary at both December 31, 2014 and 2013, respectively. | ||||||||||||
If we were to lose any one of our customers, the loss could temporarily delay the production and the sale of oil and natural gas in the related producing region. If we were to lose any single customer, we believe that a substitute customer to purchase the impacted production volumes could be identified. | ||||||||||||
Oil and Natural Gas Properties | ||||||||||||
Oil and natural gas exploration, development and production activities are accounted for in accordance with the successful efforts method of accounting. Under this method, costs of acquiring properties, costs of drilling successful exploration wells, and development costs are capitalized. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if determination is made that proved reserves have been found. If no proved reserves have been found, the costs of each of the related exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. The costs of such exploratory wells are expensed if a determination of proved reserves has not been made within a twelve-month period after drilling is complete. Exploration costs such as geological, geophysical, and seismic costs are expensed as incurred. | ||||||||||||
As exploration and development work progresses and the reserves on these properties are proven, capitalized costs attributed to the properties are subject to depreciation and depletion. Depletion of capitalized costs is provided using the units-of-production method based on proved oil and gas reserves related to the associated field. Capitalized drilling and development costs of producing oil and natural gas properties are depleted over proved developed reserves and leasehold costs are depleted over total proved reserves. | ||||||||||||
On the sale or retirement of a complete or partial unit of a proved property or pipeline and related facilities, the cost and related accumulated depreciation, depletion, and amortization are removed from the property accounts, and any gain or loss is recognized. | ||||||||||||
There were no material capitalized exploratory drilling costs pending evaluation at December 31, 2014, 2013 and 2012. | ||||||||||||
Oil and Gas Reserves | ||||||||||||
The estimates of proved oil and natural gas reserves utilized in the preparation of the consolidated and combined financial statements are estimated in accordance with the rules established by the SEC and the Financial Accounting Standards Board (“FASB”). These rules require that reserve estimates be prepared under existing economic and operating conditions using a trailing 12-month average price with no provision for price and cost escalations in future years except by contractual arrangements. Netherland, Sewell & Associates, Inc. (“NSAI”), our independent reserve engineers, was engaged to audit our internally prepared reserves estimates at December 31, 2014. MEMP engaged NSAI and Ryder Scott Company, L.P. to audit MEMP’s internally prepared reserves estimates for all of MEMP’s proved reserves (by volume) at December 31, 2014. | ||||||||||||
Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties, or any combination of the above may be increased or decreased. Increases in recoverable economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates. | ||||||||||||
Other Property & Equipment | ||||||||||||
Other property and equipment is stated at historical cost and is comprised primarily of vehicles, furniture, fixtures, office build-out cost and computer hardware and software. Depreciation of other property and equipment is calculated using the straight-line method generally based on estimated useful lives of three to seven years. | ||||||||||||
Asset Retirement Obligations | ||||||||||||
An asset retirement obligation associated with retiring long-lived assets is recognized as a liability on a discounted basis in the period in which the legal obligation is incurred and becomes determinable, with an equal amount capitalized as an addition to oil and natural gas properties, which is allocated to expense over the useful life of the asset. Generally, oil and gas producing companies incur such a liability upon acquiring or drilling a well. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. Upon settlement of the liability, a gain or loss is recognized in net income (loss) to the extent the actual costs differ from the recorded liability. See Note 6 for further discussion of asset retirement obligations. | ||||||||||||
Impairments | ||||||||||||
Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate the carrying value of such properties may not be recoverable. This may be due to a downward revision of the reserve estimates, less than expected production, drilling results, higher operating and development costs, or lower commodity prices. The estimated undiscounted future cash flows expected in connection with the property are compared to the carrying value of the property to determine if the carrying amount is recoverable. If the carrying value of the property exceeds its estimated undiscounted future cash flows, the carrying amount of the property is reduced to its estimated fair value using Level 3 inputs. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. Impairment expense for the years ended December 31, 2014, 2013, and 2012 was approximately $432.1 million, $6.6 million, $28.9 million, respectively. See Note 4 for further discussion on impairments. | ||||||||||||
Restricted Investments | ||||||||||||
Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with MEMP’s offshore Southern California oil and gas properties. These investments are classified as held-to-maturity, and such investments are stated at amortized cost. Interest earned on these investments is included in interest expense – net in the statement of operations. The amortized cost of such investments is adjusted for amortization of premiums and accretion of discounts to maturity. Such amortization and accretion is displayed as a separate line item in the statement of operations. These restricted investments consist of money market deposit accounts, money market mutual funds, commercial paper, and U.S. Government securities. See Note 7 for additional information. | ||||||||||||
Debt Issuance Costs | ||||||||||||
These costs are recorded on the balance sheet and amortized over the term of the associated debt using the straight-line method which generally approximates the effective yield method. Amortization expense, including write-off of debt issuance costs, for the years ended December 31, 2014, 2013, and 2012 was approximately $7.4 million, $8.3 million and $3.6 million, respectively. | ||||||||||||
Revenue Recognition | ||||||||||||
Revenue from the sale of oil and natural gas is recognized when title passes, net of royalties due to third parties. Oil and natural gas revenues are recorded using the sales method. Under this method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers, regardless of whether the sales are proportionate to our ownership in the property. An asset or a liability is recognized to the extent there is an imbalance in excess of the proportionate share of the remaining recoverable reserves on the underlying properties. No significant imbalances existed at December 31, 2014 or 2013. | ||||||||||||
The following individual customers each accounted for 10% or more of total reported revenues for the period indicated: | ||||||||||||
Years Ending December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Consolidated & Combined: | ||||||||||||
Energy Transfer Equity, L.P. and subsidiaries | 33 | % | 35 | % | 13 | % | ||||||
MRD Segment: | ||||||||||||
Energy Transfer Equity, L.P. and subsidiaries | 73 | % | 77 | % | 39 | % | ||||||
Sunoco, Inc. (1) | n/a | n/a | 15 | % | ||||||||
Dominion Gas Ventures LP | n/a | n/a | 15 | % | ||||||||
MEMP Segment: | ||||||||||||
Sinclair Oil & Gas Company | 12 | % | n/a | n/a | ||||||||
Phillips 66 (2) | 13 | % | 15 | % | 13 | % | ||||||
ConocoPhillips | n/a | n/a | 14 | % | ||||||||
-1 | Sunoco, Inc. became a subsidiary of Energy Transfer Equity, L.P. in October 2012. | |||||||||||
-2 | Phillips 66 was a subsidiary of ConocoPhillips through April 30, 2012. Accordingly, any revenues generated from Phillips 66 prior to May 1, 2012 were reported under ConocoPhillips. | |||||||||||
Derivative Instruments | ||||||||||||
Commodity derivative financial instruments (e.g., swaps, collars, and put options) are used to reduce the impact of natural gas, NGL and oil price fluctuations. Interest rate swaps are used to manage exposure to interest rate volatility, primarily as a result of variable rate borrowings under the credit facilities. Every derivative instrument is recorded on the balance sheet as either an asset or liability measured at its fair value. Changes in the derivative’s fair value are recognized in earnings as we have not elected hedge accounting for any of our derivative positions. | ||||||||||||
Capitalized Interest | ||||||||||||
We capitalize interest costs to oil and gas properties on expenditures made in connection with certain projects such as drilling and completion of new oil and natural gas wells and major facility installations. Interest is capitalized only for the period that such activities are in progress. Interest is capitalized using a weighted average interest rate based on our outstanding borrowings. These capitalized costs are included within intangible drilling costs and amortized using the units of production method. For the year ended December 31, 2014, we capitalized $7.3 million of interest. We did not capitalize any interest in 2013 or 2012. | ||||||||||||
Income Tax | ||||||||||||
Prior to our initial public offering, MRD LLC was organized as a pass-through entity for federal income tax purposes and was not subject to federal income taxes; however, certain of its consolidating subsidiaries were taxed as corporations and subject to federal income taxes. We are organized as a taxable C corporation and subject to federal and certain state income taxes. We are also subject to the Texas margin tax and certain aspects of the tax make it similar to an income tax. | ||||||||||||
The Company accounts for income taxes using the asset and liability method wherein deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which temporary differences are expected to be recovered or settled. Deferred tax assets are reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of the deferred tax assets will not be realized. | ||||||||||||
We must recognize the tax effects of any uncertain tax positions we may adopt, if the position taken by us is more likely than not sustainable based on its technical merits. If a tax position meets such criteria, the tax effect that would be recognized by us would be the largest amount of benefit with more than 50% chance of being realized. | ||||||||||||
The evaluation of uncertain tax positions is a two-step process. The first step is a recognition process to determine whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. In evaluating whether a tax position has met the more likely than not recognition threshold, it is presumed that the position will be examined by the appropriate taxing authority with full knowledge of all relevant information. The second step is a measurement process whereby a tax position that meets the more likely than not recognition threshold is calculated to determine the amount of benefit/expense to recognize in the consolidated financial statements. The tax position is measured at the largest amount of benefit/expense that is more likely than not of being realized upon ultimate settlement. | ||||||||||||
The Company has no liability for unrecognized tax benefits as of December 31, 2014 and 2013. Accordingly, there is no amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate and there is no amount of interest or penalties currently recognized in the consolidated statements of operations or consolidated balance sheets as of December 31, 2014. In addition, the Company does not believe that there are any positions for which it is reasonably possible that the total amount of unrecognized tax benefits will significantly increase or decrease within the next twelve months. | ||||||||||||
In June 2014, we recorded a deferred tax liability of approximately $43.3 million in stockholders’ equity in connection with our initial public offering and the related restructuring transactions. The tax bases of our assets and liabilities changed as a result our initial public offering and the related restructuring transactions, which represented a transaction among stockholders. | ||||||||||||
Tax audits may be ongoing at any point in time. Tax liabilities are recorded based on estimates of additional taxes which may be due upon the conclusion of these audits. Estimates of these tax liabilities are made based upon prior experience and are updated for changes in facts and circumstances. However, due to the uncertain and complex application of tax regulations, it is possible that the ultimate resolution of audits may result in liabilities which could be materially different from these estimates. See Note 15 for additional information. | ||||||||||||
Earnings Per Share | ||||||||||||
Basic earnings per share (“EPS”) is computed using the two-class method based on net income (loss) available to common stockholders and the average number of shares of common stock outstanding for the period. Diluted EPS includes the impact of the Company’s restricted shares of common stock as they are participating securities. The Company determines the more dilutive of either the two-class method or the treasury stock method for diluted EPS. See Note 10 for additional information. | ||||||||||||
Incentive Based Compensation Arrangements | ||||||||||||
The fair value of equity-classified awards (e.g., restricted stock awards) is amortized to earnings over the requisite service or vesting period. Compensation expense for liability-classified awards are recognized over the requisite service or vesting period of an award based on the fair value of the award re-measured at each reporting period. Generally, no compensation expense is recognized for equity instruments that do not vest. | ||||||||||||
Prior to the restructuring transactions, the governing documents of MRD LLC and certain of its subsidiaries provided for the issuance of incentive units. The incentive units were subject to performance conditions that affected their vesting. Compensation cost was recognized only if the performance condition was probable of being satisfied at each reporting date. | ||||||||||||
In connection with the restructuring transactions, the MRD LLC incentive units were exchanged for substantially identical units in MRD Holdco, and such incentive units entitle holders thereof to portions of future distributions by MRD Holdco. While any such distributions made by MRD Holdco will not involve any cash payment by us, we will be required to recognize non-cash compensation expense, which may be material, in future periods. The compensation expense recognized by us related to the incentive units will be offset by a deemed capital contribution from MRD Holdco as they are remeasured at the end of each reporting period. | ||||||||||||
See Notes 11 and 12 for further information. | ||||||||||||
Accrued Liabilities | ||||||||||||
Current accrued liabilities consisted of the following at the dates indicated (in thousands): | ||||||||||||
December 31, | ||||||||||||
2014 | 2013 | |||||||||||
Accrued capital expenditures | $ | 80,350 | $ | 48,579 | ||||||||
Accrued lease operating expense | 16,403 | 13,240 | ||||||||||
Accrued general and administrative expenses | 8,516 | 14,485 | ||||||||||
Accrued ad valorem and production taxes | 8,870 | 3,541 | ||||||||||
Accrued interest payable | 24,797 | 11,934 | ||||||||||
Accrued environmental | 2,092 | 577 | ||||||||||
Accrued current deferred income taxes | 51,929 | 382 | ||||||||||
Other miscellaneous, including operator advances | 6,043 | 5,392 | ||||||||||
$ | 199,000 | $ | 98,130 | |||||||||
Supplemental Cash Flow Information | ||||||||||||
Supplemental cash flow for the periods presented (in thousands): | ||||||||||||
For Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Supplemental cash flows: | ||||||||||||
Cash paid for interest, net of amounts capitalized | $ | 130,732 | $ | 61,140 | $ | 23,525 | ||||||
Income tax paid | 838 | 168 | 22 | |||||||||
Noncash investing and financing activities: | ||||||||||||
Change in capital expenditures in payables and accrued liabilities | 31,771 | 41,017 | 17,158 | |||||||||
Assumptions of asset retirement obligations related to properties acquired or drilled | 5,420 | 4,227 | 7,962 | |||||||||
Contribution of oil and gas properties from NGP affiliate | — | — | 6,893 | |||||||||
Accrued distribution to NGP affiliates related to Cinco Group acquisitions | — | 4,352 | — | |||||||||
Contribution related to sale of assets to NGP affiliate - restricted cash | — | — | 2,013 | |||||||||
Accrued equity offering costs | — | — | 171 | |||||||||
Distributions to noncontrolling interests | — | — | 47 | |||||||||
Repurchase of equity under repurchase program | 3,425 | — | — | |||||||||
Accounts receivable related to acquisitions | 9,569 | — | — | |||||||||
New Accounting Pronouncements | ||||||||||||
Revenue from Contracts with Customers. In May 2014, the FASB issued a comprehensive new revenue recognition standard for contracts with customers that will supersede most current revenue recognition guidance, including industry-specific guidance. The core principle of this standard is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, the standard provides a five-step analysis of transactions to determine when and how revenue is recognized. Other major provisions include the capitalization and amortization of certain contract costs, ensuring the time value of money is considered in the transaction price, and allowing estimates of variable consideration to be recognized before contingencies are resolved in certain circumstances. This guidance also requires enhanced disclosures regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from an entity’s contracts with customers. The new standard is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016. Early application is prohibited. The standard permits the use of either the retrospective or cumulative effect transition method. This guidance will be applicable to the Company beginning on January 1, 2017. The Company is currently assessing the impact that adopting this new accounting guidance will have on its consolidated financial statements and footnote disclosures. | ||||||||||||
Reporting Discontinued Operations. In April 2014, the FASB issued an accounting standards update that changes the criteria for determining when disposals can be presented as discontinued operations and modifies discontinued operations disclosures. The new guidance now defines a “discontinued operation” as (i) a disposal of a component or group of components that is disposed of or is classified as held for sale and “represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results” or (ii) an acquired business or nonprofit activity that is classified as held for sale on the date of acquisition. We will adopt this guidance and apply the disclosure requirements prospectively beginning on January 1, 2015. | ||||||||||||
Amendments to Consolidation Analysis. In February 2015, the FASB issued an accounting standards update to improve consolidation guidance for certain types of legal entities. The guidance modifies the evaluation of whether limited partnerships and similar legal entities are variable interest entities (“VIEs”) or voting interest entities, eliminates the presumption that a general partner should consolidate a limited partnership, affects the consolidation analysis of reporting entities that are involved with VIEs, particularly those that have fee arrangements and related party relationships, and provides a scope exception from consolidation guidance for certain money market funds. These provisions are effective for annual reporting periods beginning after December 15, 2015, and interim periods within those annual periods, with early adoption permitted. These provisions may also be adopted using either a full retrospective or a modified retrospective approach. Although the Company is currently assessing the impact of adopting this new accounting guidance will have on its consolidated financial statements and footnote disclosures, we expect that MEMP will become a VIE. We will either: (i) continue to consolidate MEMP and become subject to the VIE primary beneficiary disclosure requirements or (ii) no longer consolidate MEMP under the revised VIE consolidation requirements and provide disclosures that apply to variable interest holders that do not consolidate a VIE. The deconsolidation of MEMP would have a material impact on our consolidated financial statements and related disclosures. | ||||||||||||
Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Company’s financial position, results of operations and cash flows. |
Acquisitions_and_Divestitures
Acquisitions and Divestitures | 12 Months Ended | |||||||||||||||
Dec. 31, 2014 | ||||||||||||||||
Business Combinations [Abstract] | ||||||||||||||||
Acquisitions and Divestitures | Note 3. Acquisitions and Divestitures | |||||||||||||||
The third party acquisitions discussed below were accounted for under the acquisition method of accounting. Accordingly, we, our predecessor, and the previous owners conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while acquisition costs associated with the acquisitions were expensed as incurred. The operating revenues and expenses of acquired properties are included in the accompanying financial statements from their respective closing dates forward. The transactions were financed through equity offerings, capital contributions and borrowings under credit facilities. | ||||||||||||||||
The fair values of oil and natural gas properties are measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural properties include estimates of: (i) economic reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital. | ||||||||||||||||
MEMP has consummated several common control acquisitions since completing its initial public offering in December 2011, as further discussed in Note 13, from certain affiliates of NGP. These acquisitions were each accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the net assets acquired were recorded at historical cost. | ||||||||||||||||
Acquisition-related costs | ||||||||||||||||
Acquisition-related costs for both related party and third party transactions are included in general and administrative expenses in the accompanying statements of operations for the periods indicated below (in thousands): | ||||||||||||||||
For the Year Ended December 31, | ||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
$ | 6,668 | $ | 8,313 | $ | 4,538 | |||||||||||
2014 Acquisitions | ||||||||||||||||
On December 30, 2014, MRD acquired certain oil and natural gas producing properties from third parties in the Terryville Complex for approximately $71.9 million, including estimated customary post-closing adjustments (the “Louisiana Acquisition”). | ||||||||||||||||
During the fourth quarter 2014, MRD acquired incremental interests in certain oil and gas properties and leases in the Terryville Complex from third parties in four separate transactions for an aggregate purchase price of approximately $24.0 million. | ||||||||||||||||
On July 1, 2014, MEMP consummated a transaction to acquire certain oil and natural gas liquids properties from a third party in Wyoming for an aggregate purchase price of approximately $906.1 million, including estimated post-closing adjustments (the “Wyoming Acquisition”). Revenues of $72.0 million were recorded in the statement of operations generated earnings of approximately $22.9 million related to the Wyoming Acquisition subsequent to the closing date. | ||||||||||||||||
On March 25, 2014, MEMP closed a transaction to acquire certain oil and natural gas producing properties from a third party in the Eagle Ford for approximately $168.1 million (the “Eagle Ford Acquisition”). In addition, MEMP acquired a 30% interest in the seller’s Eagle Ford leasehold. During the year ended December 31, 2014, revenues of approximately $36.5 million were recorded in the statement of operations related to the Eagle Ford Acquisition subsequent to the closing date and MEMP generated earnings of approximately $16.3 million. | ||||||||||||||||
The following table summarizes the fair value assessment of the assets acquired and liabilities assumed as of the acquisition dates (in thousands): | ||||||||||||||||
MRD | MEMP | MEMP | ||||||||||||||
Louisiana | Eagle Ford | Wyoming | ||||||||||||||
Acquisition | Acquisition | Acquisition | ||||||||||||||
Oil and gas properties | $ | 72,141 | $ | 168,606 | $ | 930,168 | ||||||||||
Asset retirement obligations | (271 | ) | (285 | ) | (3,980 | ) | ||||||||||
Revenue Payable | — | — | (375 | ) | ||||||||||||
Accrued liabilities | — | (250 | ) | (19,693 | ) | |||||||||||
Total identifiable net assets | $ | 71,870 | $ | 168,071 | $ | 906,120 | ||||||||||
The following unaudited pro forma combined results of operations are provided for the year ended December 31, 2014 and 2013 as though the Wyoming Acquisition had been completed on January 1, 2013. The unaudited pro forma financial information was derived from the historical combined statements of operations of the Company and the previous owners and adjusted to include: (i) the revenues and direct operating expenses associated with oil and gas properties acquired, (ii) depletion expense applied to the adjusted basis of the properties acquired and (iii) interest expense on additional borrowings necessary to finance the acquisition. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of expected future results of operations. | ||||||||||||||||
For the Year Ended December 31, | ||||||||||||||||
2014 | 2013 | |||||||||||||||
(In thousands, except per share amounts) | ||||||||||||||||
Revenues | $ | 990,544 | $ | 761,443 | ||||||||||||
Net income (loss) | (602,044 | ) | 257,839 | |||||||||||||
Basic earnings per share | $ | (4.08 | ) | $ | — | |||||||||||
Diluted earnings per share | $ | (4.08 | ) | $ | — | |||||||||||
2014 Divestitures | ||||||||||||||||
On May 9, 2014, MRD LLC sold certain producing and non-producing properties in the Mississippian oil play of Northern Oklahoma to a third party for approximately $7.6 million and recorded a loss of $3.2 million. | ||||||||||||||||
2013 Acquisitions | ||||||||||||||||
On April 30, 2013, WildHorse Resources purchased certain oil and gas properties and leases in Louisiana from a third party for approximately $67.1 million. | ||||||||||||||||
MEMP closed two separate transactions during 2013 to acquire certain oil and natural gas properties from third parties in East Texas (the “East Texas Acquisition”) and the Rockies (the “Rockies Acquisition”) for approximately $29.4 million in aggregate. The East Texas Acquisition closed on September 6, 2013 and the Rockies Acquisition closed on August 30, 2013. | ||||||||||||||||
Louisiana | East Texas | Rockies | ||||||||||||||
Acquisition | Acquisition | Acquisition | ||||||||||||||
Oil and gas properties | $ | 68,887 | $ | 9,974 | $ | 20,744 | ||||||||||
Asset retirement obligation | (1,789 | ) | (78 | ) | (1,163 | ) | ||||||||||
Accrued liabilities | - | - | (118 | ) | ||||||||||||
Total identifiable net assets | $ | 67,098 | $ | 9,896 | $ | 19,463 | ||||||||||
During 2013, Propel Energy acquired incremental interests in certain oil and gas properties and leases in the Hendrick Field located in Winkler County, Texas from third parties in three separate transactions for an aggregate purchase price of approximately $9.3 million. | ||||||||||||||||
2013 Divestitures | ||||||||||||||||
On January 1, 2013, Tanos sold a natural gas gathering pipeline located in East Texas, which it had originally acquired in April 2010, to a privately held gas transportation company for a minimum purchase price of $1.5 million. The maximum allowable additional proceeds are $2.0 million. The contingent consideration is based on the natural gas pipeline servicing any new wells that Tanos drills in the area over the following three years. The contingent consideration portion of an arrangement is recorded when the consideration is determined to be realizable. Tanos recorded an aggregate gain of approximately $1.4 million related to this transaction, of which $0.4 million was contingent consideration. During 2013, Tanos also sold certain non-operated oil and gas properties for $2.9 million and recorded a gain of $1.4 million. | ||||||||||||||||
On May 10, 2013, Black Diamond entered into a purchase and sale agreement with a third party to sell certain of its Wyoming oil and gas properties with an estimated net book value of $39.8 million for $33.0 million, before customary adjustments. As a result, Black Diamond recorded a loss on the sale of $6.8 million. This transaction closed on June 4, 2013. | ||||||||||||||||
During 2013, BlueStone entered into an agreement with a third party to sell its remaining interest in certain properties in the Mossy Grove Prospect in Walker and Madison Counties located in East Texas. Total cash consideration received by BlueStone was approximately $117.9 million, which exceeded the net book value of the properties sold by $89.5 million. The transaction closed on July 31, 2013. | ||||||||||||||||
2012 Acquisitions | ||||||||||||||||
On May 1, 2012, MEMP and WildHorse jointly acquired operating and non-operating interests in certain oil and natural gas properties located in East Texas and North Louisiana from an undisclosed third party seller (“Undisclosed Seller Acquisition”) for a final net purchase price of approximately $112.1 million. These properties are located primarily in Polk County, Texas and Lincoln and Claiborne Parishes, Louisiana. During the year ended December 31, 2012, approximately $22.1 million of revenue and $9.2 million of earnings were recorded in the statement of operations related to the Undisclosed Seller Acquisition subsequent to the closing date. | ||||||||||||||||
On September 28, 2012, MEMP acquired certain oil and natural gas properties in East Texas from Goodrich Petroleum Corporation (“Goodrich Acquisition”) for a final net purchase price of $90.4 million after customary post-closing adjustments. The effective date of this transaction was July 1, 2012. This transaction was financed with borrowings under MEMP’s revolving credit facility. These properties are located in the East Henderson field of Rusk County, Texas. During the year ended December 31, 2012, approximately $4.6 million of revenue and $2.0 million of earnings were recorded in the statement of operations related to the Goodrich Acquisition subsequent to the closing date. | ||||||||||||||||
Collectively, the previous owners consummated multiple acquisitions during 2012 by acquiring operating and non-operating interests in certain oil and natural gas properties primarily located in various Texas and New Mexico counties for an aggregate adjusted purchase price of $147.9 million, the largest of which was completed in July by Stanolind. In July 2012, Stanolind completed an acquisition of working interests, royalty interests and net revenue interests (the “Menemsha Acquisition”) located in various counties in Texas for a final net purchase price of $74.7 million. During the year ended December 31, 2012, approximately $4.9 million of revenue and $0.9 million of earnings were recorded in the statement of operations related to the Menemsha Acquisition subsequent to the closing date. | ||||||||||||||||
The following table summarizes the fair value of the assets acquired and liabilities assumed as of each acquisition date (in thousands). | ||||||||||||||||
Undisclosed Seller | Goodrich | Menemsha | Other | |||||||||||||
Acquisition | Acquisition | Acquisition | Acquisitions | |||||||||||||
Oil and gas properties | $ | 115,633 | $ | 91,187 | $ | 75,114 | $ | 77,764 | ||||||||
Prepaid expenses and other current assets | — | 425 | — | — | ||||||||||||
Revenues payable | (1,602 | ) | (875 | ) | — | — | ||||||||||
Asset retirement obligation | (1,592 | ) | (161 | ) | (408 | ) | (4,558 | ) | ||||||||
Accrued liabilities | (297 | ) | (153 | ) | — | — | ||||||||||
Total identifiable net assets | $ | 112,142 | $ | 90,423 | $ | 74,706 | $ | 73,206 | ||||||||
The following unaudited pro forma combined results of operations are provided for the year ended December 31, 2012 (in thousands) as though the Undisclosed Seller Acquisition, Goodrich Acquisition, and Menemsha Acquisition had been completed on January 1, 2011. The unaudited pro forma financial information was derived from our historical combined statements of operations and adjusted to include: (i) the revenues and direct operating expenses associated with oil and gas properties acquired, (ii) depletion expense applied to the adjusted basis of the properties acquired and (iii) interest expense on additional borrowings necessary to finance the acquisitions. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transactions occurred on the basis assumed above, nor is such information indicative of expected future results of operations. | ||||||||||||||||
Revenue | $ | 431,060 | ||||||||||||||
Net income | 40,940 | |||||||||||||||
During 2012, we also acquired certain interests in oil and gas properties through several individually immaterial acquisitions for an aggregate purchase price of $10.2 million. | ||||||||||||||||
2012 Divestitures | ||||||||||||||||
During 2012, certain of our subsidiaries sold certain interests in oil and gas properties for an aggregate $3.3 million. Losses of approximately $0.1 million were recognized related to these divestures. | ||||||||||||||||
On July 11, 2012, the previous owners completed the sale of a portion of its oil and gas assets located in Garza County, Texas to a third party for $26.1 million and recognized a gain of approximately $7.6 million. On September 18, 2012, the previous owners completed the sale of a portion of its oil and gas assets located in Ector County, Texas to a third party for $4.7 million and recognized a gain of approximately $2.2 million. | ||||||||||||||||
The majority of the proceeds generated from these sales were used to acquire operating and non-operating interests in certain oil and natural gas properties located primarily in various Texas and New Mexico counties. |
Fair_Value_Measurements_of_Fin
Fair Value Measurements of Financial Instruments | 12 Months Ended | |||||||||||||||
Dec. 31, 2014 | ||||||||||||||||
Fair Value Disclosures [Abstract] | ||||||||||||||||
Fair Value Measurements of Financial Instruments | ||||||||||||||||
Note 4. Fair Value Measurements of Financial Instruments | ||||||||||||||||
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 a specified measurement date. Fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk. A three-tier hierarchy has been established that classifies fair value amounts recognized or disclosed in the financial statements. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3). The characteristics of fair value amounts classified within each level of the hierarchy are described as follows: | ||||||||||||||||
Level 1 — Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. An active market is one in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. | ||||||||||||||||
Level 2 — Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. At December 31, 2014 and 2013, all of the derivative instruments reflected on the accompanying balance sheets were considered Level 2. | ||||||||||||||||
Level 3 — Measure based on prices or valuation models that require inputs that are both significant to the fair value measurement and are less observable from objective sources (i.e., supported by little or no market activity). | ||||||||||||||||
Assets and Liabilities Measured at Fair Value on a Recurring Basis | ||||||||||||||||
The carrying values of cash and cash equivalents, accounts receivables, accounts payables (including accrued liabilities) and amounts outstanding under long-term debt agreements with variable rates included in the accompanying balance sheets approximated fair value at December 31, 2014 and December 31, 2013. The fair value estimates are based upon observable market data and are classified within Level 2 of the fair value hierarchy. These assets and liabilities are not presented in the following tables. See Note 8 for the estimated fair value of our outstanding fixed-rate debt. | ||||||||||||||||
The fair market values of the derivative financial instruments reflected on the balance sheets as of December 31, 2014 and December 31, 2013 were based on estimated forward commodity prices (including nonperformance risk) and forward interest rate yield curves. Nonperformance risk is the risk that the obligation related to the derivative instrument will not be fulfilled. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement in its entirety. The significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. | ||||||||||||||||
The following table presents the derivative assets and liabilities that are measured at fair value on a recurring basis at December 31, 2014 and December 31, 2013 for each of the fair value hierarchy levels: | ||||||||||||||||
Fair Value Measurements at December 31, 2014 Using | ||||||||||||||||
Quoted Prices in | Significant Other | Significant | ||||||||||||||
Active | Observable | Unobservable | ||||||||||||||
Market | Inputs | Inputs | ||||||||||||||
(Level 1) | (Level 2) | (Level 3) | Fair Value | |||||||||||||
(In thousands) | ||||||||||||||||
Assets: | ||||||||||||||||
Commodity derivatives | $ | — | $ | 845,759 | $ | — | $ | 845,759 | ||||||||
Interest rate derivatives | — | 1,305 | — | 1,305 | ||||||||||||
Total assets | $ | — | $ | 847,064 | $ | — | $ | 847,064 | ||||||||
Liabilities: | ||||||||||||||||
Commodity derivatives | $ | — | $ | 71,639 | $ | — | $ | 71,639 | ||||||||
Interest rate derivatives | — | 3,289 | — | 3,289 | ||||||||||||
Total liabilities | $ | — | $ | 74,928 | $ | — | $ | 74,928 | ||||||||
Fair Value Measurements at December 31, 2013 Using | ||||||||||||||||
Quoted Prices in | Significant Other | Significant | ||||||||||||||
Active | Observable | Unobservable | ||||||||||||||
Market | Inputs | Inputs | ||||||||||||||
(Level 1) | (Level 2) | (Level 3) | Fair Value | |||||||||||||
(In thousands) | ||||||||||||||||
Assets: | ||||||||||||||||
Commodity derivatives | $ | — | $ | 105,054 | $ | — | $ | 105,054 | ||||||||
Interest rate derivatives | — | 884 | — | 884 | ||||||||||||
Total assets | $ | — | $ | 105,938 | $ | — | $ | 105,938 | ||||||||
Liabilities: | ||||||||||||||||
Commodity derivatives | $ | — | $ | 58,234 | $ | — | $ | 58,234 | ||||||||
Interest rate derivatives | — | 5,590 | — | 5,590 | ||||||||||||
Total liabilities | $ | — | $ | 63,824 | $ | — | $ | 63,824 | ||||||||
See Note 5 for additional information regarding our derivative instruments. | ||||||||||||||||
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis | ||||||||||||||||
Certain assets and liabilities are reported at fair value on a nonrecurring basis as reflected on the balance sheets. The following methods and assumptions are used to estimate the fair values: | ||||||||||||||||
— | The fair value of asset retirement obligations (“AROs”) is based on discounted cash flow projections using numerous estimates, assumptions, and judgments regarding such factors as the existence of a legal obligation for an ARO; amounts and timing of settlements; the credit-adjusted risk-free rate; and inflation rates. See Note 6 for a summary of changes in AROs. | |||||||||||||||
— | If sufficient market data is not available, the determination of the fair values of proved and unproved properties acquired in transactions accounted for as business combinations are prepared by utilizing estimates of discounted cash flow projections. The factors to determine fair value include, but are not limited to, estimates of: (i) economic reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital. The fair value of supporting equipment, such as plant assets, acquired in transactions accounted for as business combinations are commonly estimated using the depreciated replacement cost approach. | |||||||||||||||
— | Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate the carrying value of such properties may not be recoverable. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. | |||||||||||||||
· | During the year ended December 31, 2014, the MRD Segment recognized $24.6 million of impairments. The impairments primarily related to certain properties located in the Rockies as well as certain fields in North Louisiana. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable primarily due to declining commodity prices. | |||||||||||||||
During the year ended December 31, 2014, MEMP recognized $407.5 million of impairments. The impairments primarily related to certain properties located in the Permian Basin, East Texas, and South Texas. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable. In the Permian Basin the impairments were in due to a downward revision of estimated proved reserves based on declining commodity prices and updated well performance data. In South Texas, the impairments were in due to a downward revision of estimated proved reserves based on declining commodity prices and increased operating costs. In East Texas, the impairments were due to downward revisions based on declining commodity prices. The carrying value of the: (i) Permian Basin properties after the $234.2 million impairment was approximately $88.7 million; (ii) East Texas properties after the $107.6 million impairment was approximately $88.8 million; and (iii) South Texas properties after the $65.6 million impairment was $71.2 million. | ||||||||||||||||
· | During the year ended December 31, 2013, we recognized $6.6 million of impairments. The impairments related to certain properties located in South Texas. The estimated future cash flows expected were compared to their carrying values and determined to be unrecoverable as a result of a downward revision of estimated proved reserves based on pricing terms specific to these properties. | |||||||||||||||
· | During the year ended December 31, 2012, we recognized $28.9 million of impairments to proved oil and natural gas properties. Approximately $8.0 million related to a particular lease in the Elkhorn (Ellenburger) and Canyon Fields located in the Permian Basin as a result of a downward revision of estimated proved reserves due to unfavorable drilling results in the area. The remaining $20.9 million of impairments primarily related to certain fields in East Texas. The carrying values of these fields were determined to be unrecoverable due to a decline in gas prices. |
Risk_Management_and_Derivative
Risk Management and Derivative Instruments | 12 Months Ended | |||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||
Derivative Instruments And Hedging Activities Disclosure [Abstract] | ||||||||||||||||||||
Risk Management and Derivative Instruments | Note 5. Risk Management and Derivative Instruments | |||||||||||||||||||
Derivative instruments are utilized to manage exposure to commodity price and interest rate fluctuations and achieve a more predictable cash flow in connection with natural gas and oil sales from production and borrowing related activities. These transactions limit exposure to declines in prices or increases in interest rates, but also limit the benefits that would be realized if prices increase or interest rates decrease. | ||||||||||||||||||||
Certain inherent business risks are associated with commodity and interest derivative contracts, including market risk and credit risk. Market risk is the risk that the price of natural gas or oil will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the counterparty to a contract. It is our policy to enter into derivative contracts, including interest rate swaps, only with creditworthy counterparties, which generally are financial institutions, deemed by management as competent and competitive market makers. Some of the lenders, or certain of their affiliates, under our credit agreements are counterparties to our derivative contracts. While collateral is generally not required to be posted by counterparties, credit risk associated with derivative instruments is minimized by limiting exposure to any single counterparty and entering into derivative instruments only with counterparties that are large financial institutions, which management believes present minimal credit risk. Additionally, master netting agreements are used to mitigate risk of loss due to default with counterparties on derivative instruments. We have also entered into the International Swaps and Derivatives Association Master Agreements (“ISDA Agreements”) with each of our counterparties. The terms of the ISDA Agreements provide us and each of our counterparties with rights of set-off upon the occurrence of defined acts of default by either us or our counterparty to a derivative, whereby the party not in default may set-off all liabilities owed to the defaulting party against all net derivative asset receivables from the defaulting party. At December 31, 2014, MEMP had net derivative assets of $517.1 million. After taking into effect netting arrangements, MEMP had counterparty exposure of $309.8 million related to its derivative instruments of which $109.7 million was with a single counterparty. Had certain counterparties failed completely to perform according to the terms of their existing contracts, MEMP would have the right to offset $207.3 million against amounts outstanding under its revolving credit facility at December 31, 2014. At December 31, 2014, MRD had derivative assets of $255.0 million. After taking into effect netting arrangements, MRD had counterparty exposure of $155.8 million related to derivative instruments. Had certain counterparties failed completely to perform according to the terms of their existing contracts, MRD would have the right to offset $99.2 million against amounts outstanding under its revolving credit facility at December 31, 2014. See Note 8 for additional information regarding our revolving credit facilities. | ||||||||||||||||||||
Commodity Derivatives | ||||||||||||||||||||
We may use a combination of commodity derivatives (e.g., floating-for-fixed swaps, put options, costless collars, call spreads and basis swaps) to manage exposure to commodity price volatility. We recognize all derivative instruments at fair value; however, certain of our put option derivative instruments have a deferred premium, which reduces the asset. For the deferred premium puts, the Company agrees to pay a premium to the counterparty at the time of settlement. At settlement, if the applicable index price is below the strike price of the put, the Company receives the difference between the strike price and the applicable index price multiplied by the contract volumes less the premium. If the applicable index price settles at or above the strike price of the put, the Company pays only the premium at settlement. During the year ended December 31, 2014, MRD restructured a portion of its commodity derivative portfolio by terminating “in the money” natural gas collars settling in 2015 and entering into natural gas swaps. The cash settlement receipts of $6.1 million from the termination of the collars were utilized to enhance the fixed price portion of the natural gas swaps. | ||||||||||||||||||||
We enter into natural gas derivative contracts that are indexed to NYMEX-Henry Hub and regional indices such as NGPL TXOK, TETCO STX, TGT Z1, and Houston Ship Channel in proximity to our areas of production. We also enter into oil derivative contracts indexed to a variety of locations such as NYMEX-WTI, Inter-Continental Exchange (“ICE”) Brent, California Midway-Sunset and other regional locations. Our NGL derivative contracts are primarily indexed to OPIS Mont Belvieu. | ||||||||||||||||||||
At December 31, 2014, the MRD Segment had the following open commodity positions: | ||||||||||||||||||||
2015 | 2016 | 2017 | 2018 | |||||||||||||||||
Natural Gas Derivative Contracts: | ||||||||||||||||||||
Fixed price swap contracts: | ||||||||||||||||||||
Average Monthly Volume (MMBtu) | 3,700,000 | 2,570,000 | 1,770,000 | 2,900,000 | ||||||||||||||||
Weighted-average fixed price | $ | 4.15 | $ | 4.09 | $ | 4.24 | $ | 4.27 | ||||||||||||
Collar contracts: | ||||||||||||||||||||
Average Monthly Volume (MMBtu) | 130,000 | 1,100,000 | 1,050,000 | — | ||||||||||||||||
Weighted-average floor price | $ | 4 | $ | 4 | $ | 4 | $ | — | ||||||||||||
Weighted-average ceiling price | $ | 4.64 | $ | 4.71 | $ | 5.06 | $ | — | ||||||||||||
Natural gas put option contracts: | ||||||||||||||||||||
Average Monthly Volume (MMBtu) | 3,000,000 | 4,100,000 | 3,450,000 | 2,850,000 | ||||||||||||||||
Weighted-average fixed price | $ | 3.75 | $ | 3.75 | $ | 3.75 | $ | 3.75 | ||||||||||||
Weighted-average deferred premium | $ | (0.33 | ) | $ | (0.36 | ) | $ | (0.35 | ) | $ | (0.35 | ) | ||||||||
TGT Z1 basis swaps: | ||||||||||||||||||||
Average Monthly Volume (MMBtu) | 1,730,000 | 220,000 | 200,000 | — | ||||||||||||||||
Spread - Henry Hub | $ | (0.09 | ) | $ | (0.08 | ) | $ | (0.08 | ) | $ | — | |||||||||
Crude Oil Derivative Contracts: | ||||||||||||||||||||
Fixed price swap contracts: | ||||||||||||||||||||
Average Monthly Volume (Bbls) | 46,500 | 8,500 | 28,000 | 31,625 | ||||||||||||||||
Weighted-average fixed price | $ | 91.67 | $ | 84.8 | $ | 84.7 | $ | 84.5 | ||||||||||||
Collar contracts: | ||||||||||||||||||||
Average Monthly Volume (Bbls) | 2,000 | 27,000 | — | — | ||||||||||||||||
Weighted-average floor price | $ | 85 | $ | 80 | $ | — | $ | — | ||||||||||||
Weighted-average ceiling price | $ | 101.35 | $ | 99.7 | $ | — | $ | — | ||||||||||||
Put option contracts: | ||||||||||||||||||||
Average Monthly Volume (Bbls) | 26,000 | — | — | — | ||||||||||||||||
Weighted-average fixed price | $ | 85 | $ | — | $ | — | $ | — | ||||||||||||
Weighted-average deferred premium | $ | (3.80 | ) | $ | — | $ | — | $ | — | |||||||||||
NGL Derivative Contracts: | ||||||||||||||||||||
Fixed price swap contracts: | ||||||||||||||||||||
Average Monthly Volume (Bbls) | 151,000 | 185,658 | — | — | ||||||||||||||||
Weighted-average fixed price | $ | 41.61 | $ | 34.06 | $ | — | $ | — | ||||||||||||
At December 31, 2014, the MEMP Segment had the following open commodity positions: | ||||||||||||||||||||
2015 | 2016 | 2017 | 2018 | 2019 | ||||||||||||||||
Natural Gas Derivative Contracts: | ||||||||||||||||||||
Fixed price swap contracts: | ||||||||||||||||||||
Average Monthly Volume (MMBtu) | 2,605,278 | 2,692,442 | 2,450,067 | 2,160,000 | 1,914,583 | |||||||||||||||
Weighted-average fixed price | $ | 4.28 | $ | 4.4 | $ | 4.31 | $ | 4.51 | $ | 4.75 | ||||||||||
Collar contracts: | ||||||||||||||||||||
Average Monthly Volume (MMBtu) | 350,000 | — | — | — | — | |||||||||||||||
Weighted-average floor price | $ | 4.62 | $ | — | $ | — | $ | — | $ | — | ||||||||||
Weighted-average ceiling price | $ | 5.8 | $ | — | $ | — | $ | — | $ | — | ||||||||||
Call spreads (1): | ||||||||||||||||||||
Average Monthly Volume (MMBtu) | 80,000 | — | — | — | — | |||||||||||||||
Weighted-average sold strike price | $ | 5.25 | $ | — | $ | — | $ | — | $ | — | ||||||||||
Weighted-average bought strike price | $ | 6.75 | $ | — | $ | — | $ | — | $ | — | ||||||||||
Basis swaps: | ||||||||||||||||||||
Average Monthly Volume (MMBtu) | 2,940,000 | 2,508,333 | 415,000 | 115,000 | — | |||||||||||||||
Spread | $ | (0.12 | ) | $ | (0.04 | ) | $ | 0 | $ | 0.15 | $ | — | ||||||||
Crude Oil Derivative Contracts: | ||||||||||||||||||||
Fixed price swap contracts: | ||||||||||||||||||||
Average Monthly Volume (Bbls) | 314,281 | 332,813 | 326,600 | 312,000 | 160,000 | |||||||||||||||
Weighted-average fixed price | $ | 90.96 | $ | 85.83 | $ | 84.38 | $ | 83.74 | $ | 85.52 | ||||||||||
Collar contracts: | ||||||||||||||||||||
Average Monthly Volume (Bbls) | 5,000 | — | — | — | — | |||||||||||||||
Weighted-average floor price | $ | 80 | $ | — | $ | — | $ | — | $ | — | ||||||||||
Weighted-average ceiling price | $ | 94 | $ | — | $ | — | $ | — | $ | — | ||||||||||
Basis swaps: | ||||||||||||||||||||
Average Monthly Volume (Bbls) | 97,500 | 95,000 | — | — | — | |||||||||||||||
Spread | $ | (7.07 | ) | $ | (9.56 | ) | $ | — | $ | — | $ | — | ||||||||
NGL Derivative Contracts: | ||||||||||||||||||||
Fixed price swap contracts: | ||||||||||||||||||||
Average Monthly Volume (Bbls) | 149,200 | 84,600 | — | — | — | |||||||||||||||
Weighted-average fixed price | $ | 43.02 | $ | 41.49 | $ | — | $ | — | $ | — | ||||||||||
(1) These transactions were entered into for the purpose of eliminating the ceiling portion of certain collar arrangements, which effectively converted the applicable collars into swaps. | ||||||||||||||||||||
The MEMP Segment basis swaps included in the table above is presented on a disaggregated basis below: | ||||||||||||||||||||
2015 | 2016 | 2017 | 2018 | |||||||||||||||||
Natural Gas Derivative Contracts: | ||||||||||||||||||||
NGPL TexOk basis swaps: | ||||||||||||||||||||
Average Monthly Volume (MMBtu) | 2,280,000 | 2,103,333 | 300,000 | — | ||||||||||||||||
Spread - Henry Hub | $ | (0.11 | ) | $ | (0.06 | ) | $ | (0.05 | ) | $ | — | |||||||||
HSC basis swaps: | ||||||||||||||||||||
Average Monthly Volume (MMBtu) | 150,000 | 135,000 | 115,000 | 115,000 | ||||||||||||||||
Spread - Henry Hub | $ | (0.08 | ) | $ | 0.07 | $ | 0.14 | $ | 0.15 | |||||||||||
CIG basis swaps: | ||||||||||||||||||||
Average Monthly Volume (MMBtu) | 210,000 | — | — | — | ||||||||||||||||
Spread - Henry Hub | $ | (0.25 | ) | $ | — | $ | — | $ | — | |||||||||||
TETCO STX basis swaps: | ||||||||||||||||||||
Average Monthly Volume (MMBtu) | 300,000 | 270,000 | — | — | ||||||||||||||||
Spread - Henry Hub | $ | (0.09 | ) | $ | 0.06 | $ | — | $ | — | |||||||||||
Crude Oil Derivative Contracts: | ||||||||||||||||||||
Midway-Sunset basis swaps: | ||||||||||||||||||||
Average Monthly Volume (Bbls) | 57,500 | 55,000 | — | — | ||||||||||||||||
Spread - Brent | $ | (9.73 | ) | $ | (13.35 | ) | $ | — | $ | — | ||||||||||
Midland basis swaps: | ||||||||||||||||||||
Average Monthly Volume (Bbls) | 40,000 | 40,000 | — | — | ||||||||||||||||
Spread - WTI | $ | (3.25 | ) | $ | (4.34 | ) | $ | — | $ | — | ||||||||||
Interest Rate Swaps | ||||||||||||||||||||
Periodically, interest rate swaps are entered into to mitigate exposure to market rate fluctuations by converting variable interest rates such as those in our credit agreements to fixed interest rates. From time to time we enter into offsetting positions to avoid being economically over-hedged. At December 31, 2014, we had the following interest rate swap open positions: | ||||||||||||||||||||
Credit Facility | 2015 | 2016 | 2017 | |||||||||||||||||
MEMP: | ||||||||||||||||||||
Average Monthly Notional (in thousands) | $ | 314,167 | $ | 250,000 | $ | 250,000 | ||||||||||||||
Weighted-average fixed rate | 1.349 | % | 1.029 | % | 1.62 | % | ||||||||||||||
Floating rate | 1 Month LIBOR | 1 Month LIBOR | 1 Month LIBOR | |||||||||||||||||
On July 1, 2014, we elected to terminate the interest rate swaps associated with the MRD credit facility and in the aggregate paid our counterparties approximately $0.7 million. WildHorse Resources novated the interest rate swaps to MRD in connection with the closing of our initial public offering. | ||||||||||||||||||||
Balance Sheet Presentation | ||||||||||||||||||||
The following table summarizes both: (i) the gross fair value of derivative instruments by the appropriate balance sheet classification even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the balance sheet and (ii) the net recorded fair value as reflected on the balance sheet at December 31, 2014 and 2013. There was no cash collateral received or pledged associated with our derivative instruments since most of the counterparties, or certain affiliates, to our derivative contracts are lenders under our collective credit agreements. | ||||||||||||||||||||
Asset Derivatives | Liability Derivatives | |||||||||||||||||||
Type | Balance Sheet Location | 2014 | 2013 | 2014 | 2013 | |||||||||||||||
(In thousands) | ||||||||||||||||||||
Commodity contracts | Short-term derivative instruments | $ | 378,908 | $ | 21,759 | $ | 38,852 | $ | 19,739 | |||||||||||
Interest rate swaps | Short-term derivative instruments | — | 845 | 3,289 | 3,287 | |||||||||||||||
Gross fair value | 378,908 | 22,604 | 42,141 | 23,026 | ||||||||||||||||
Netting arrangements | Short-term derivative instruments | (38,852 | ) | (13,315 | ) | (38,852 | ) | (13,315 | ) | |||||||||||
Net recorded fair value | Short-term derivative instruments | $ | 340,056 | $ | 9,289 | $ | 3,289 | $ | 9,711 | |||||||||||
Commodity contracts | Long-term derivative instruments | $ | 466,851 | $ | 83,295 | $ | 32,787 | $ | 38,495 | |||||||||||
Interest rate swaps | Long-term derivative instruments | 1,305 | 39 | — | 2,303 | |||||||||||||||
Gross fair value | 468,156 | 83,334 | 32,787 | 40,798 | ||||||||||||||||
Netting arrangements | Long-term derivative instruments | (32,787 | ) | (34,718 | ) | (32,787 | ) | (34,718 | ) | |||||||||||
Net recorded fair value | Long-term derivative instruments | $ | 435,369 | $ | 48,616 | $ | — | $ | 6,080 | |||||||||||
(Gains) & Losses on Derivatives | ||||||||||||||||||||
All gains and losses, including changes in the derivative instruments’ fair values, have been recorded in the accompanying statements of operations since derivative instruments are not designated as hedging instruments for accounting and financial reporting purposes. The following table details the gains and losses related to derivative instruments for the years ending December 31, 2014, 2013, and 2012: | ||||||||||||||||||||
Statements of | For the Years Ended December 31, | |||||||||||||||||||
Operations Location | 2014 | 2013 | 2012 | |||||||||||||||||
(In thousands) | ||||||||||||||||||||
Commodity derivative contracts | (Gain) loss on commodity derivatives | $ | (749,988 | ) | $ | (29,294 | ) | $ | (34,905 | ) | ||||||||||
Interest rate derivatives | Interest expense, net | 145 | (239 | ) | 5,582 | |||||||||||||||
Asset_Retirement_Obligations
Asset Retirement Obligations | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Asset Retirement Obligation Disclosure [Abstract] | ||||||||||||
Asset Retirement Obligations | Note 6. Asset Retirement Obligations | |||||||||||
Asset retirement obligations primarily relate to our portion of future plugging and abandonment of wells and related facilities. | ||||||||||||
The following table presents the changes in the asset retirement obligations for the years ended December 31, 2014, 2013 and 2012: | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
(In thousands) | ||||||||||||
Asset retirement obligations at beginning of period | $ | 111,769 | $ | 102,380 | $ | 90,699 | ||||||
Liabilities added from acquisitions or drilling | 5,420 | 4,227 | 7,962 | |||||||||
Liabilities removed upon sale of wells | (669 | ) | (1,765 | ) | (1,931 | ) | ||||||
Liabilities removed upon plugging and abandoning | (588 | ) | (170 | ) | (119 | ) | ||||||
Revisions | 293 | 1,516 | 760 | |||||||||
Accretion expense | 6,306 | 5,581 | 5,009 | |||||||||
Asset retirement obligations at end of period | 122,531 | 111,769 | 102,380 | |||||||||
Less: Current portion | — | 90 | 390 | |||||||||
Asset retirement obligations— long-term portion | $ | 122,531 | $ | 111,679 | $ | 101,990 | ||||||
Restricted_Investments
Restricted Investments | 12 Months Ended | |||||||
Dec. 31, 2014 | ||||||||
Schedule Of Investments [Abstract] | ||||||||
Restricted Investments | ||||||||
Note 7. Restricted Investments | ||||||||
Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with the offshore Southern California oil and gas properties owned by MEMP. | ||||||||
The components of the restricted investment balance are as follows at December 31, 2014 and 2013: | ||||||||
2014 | 2013 | |||||||
(In thousands) | ||||||||
BOEM platform abandonment (See Note 16) | $ | 69,954 | $ | 66,373 | ||||
BOEM lease bonds | 794 | 794 | ||||||
SPBPC Collateral: | ||||||||
Contractual pipeline and surface facilities abandonment | 2,701 | 2,306 | ||||||
California State Lands Commission pipeline right-of-way bond | 3,005 | 3,005 | ||||||
City of Long Beach pipeline facility permit | 500 | 500 | ||||||
Federal pipeline right-of-way bond | 307 | 307 | ||||||
Port of Long Beach pipeline license | 100 | 100 | ||||||
Restricted investments | $ | 77,361 | $ | 73,385 | ||||
Long_Term_Debt
Long Term Debt | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Debt Disclosure [Abstract] | ||||||||||||
Long Term Debt | Note 8. Long Term Debt | |||||||||||
The following table presents our consolidated debt obligations at the dates indicated. The MEMP Segment debt included in the table below is nonrecourse to the Company. | ||||||||||||
December 31, | December 31, | |||||||||||
2014 | 2013 | |||||||||||
(In thousands) | ||||||||||||
MRD Segment: | ||||||||||||
MRD $2.0 billion revolving credit facility, variable-rate, due June 2019 | $ | 183,000 | $ | — | ||||||||
WildHorse Resources $1.0 billion revolving credit facility, variable-rate, terminated June 2014 | — | 203,100 | ||||||||||
WildHorse Resources $325.0 million second lien term facility, variable-rate, terminated June 2014 | — | 325,000 | ||||||||||
10.00%/10.75% senior PIK toggle notes redeemed June 2014 | — | 350,000 | ||||||||||
5.875% senior unsecured notes, due July 2022 (1) | 600,000 | — | ||||||||||
10.00%/10.75% senior PIK toggle notes unamortized discounts | — | (6,950 | ) | |||||||||
Subtotal | 783,000 | 871,150 | ||||||||||
MEMP Segment: | ||||||||||||
MEMP $2.0 billion revolving credit facility, variable-rate, due March 2018 | 412,000 | 103,000 | ||||||||||
7.625% senior notes, fixed-rate, due May 2021 (2) | 700,000 | 700,000 | ||||||||||
6.875% senior unsecured notes, due August 2022 (3) | 500,000 | — | ||||||||||
Unamortized discounts | (16,587 | ) | (10,933 | ) | ||||||||
Subtotal | 1,595,413 | 792,067 | ||||||||||
Total long-term debt | $ | 2,378,413 | $ | 1,663,217 | ||||||||
(1)The estimated fair value of this fixed-rate debt was $534.0 million at December 31, 2014. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. | ||||||||||||
(2)The estimated fair value of this fixed-rate debt was $563.5 million and $721.0 million at December 31, 2014 and 2013, respectively. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. | ||||||||||||
(3)The estimated fair value of this fixed-rate debt was $380.0 million at December 31, 2014. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. | ||||||||||||
Borrowing Base | ||||||||||||
Credit facilities tied to borrowing bases are common throughout the oil and gas industry. Each of the revolving credit facilities borrowing base is subject to redetermination on at least a semi-annual basis primarily based on estimated proved reserves. The borrowing base for MRD’s and MEMP’s revolving credit facility was the following at the date indicated: | ||||||||||||
December 31, | ||||||||||||
2014 | ||||||||||||
MRD Segment: | ||||||||||||
MRD $2.0 billion revolving credit facility, variable-rate, due June 2019 | $ | 725,000 | ||||||||||
MEMP Segment: | ||||||||||||
MEMP $2.0 billion revolving credit facility, variable-rate, due March 2018 | 1,440,000 | |||||||||||
MRD Revolving Credit Facility | ||||||||||||
On June 18, 2014, we, as borrower, and certain of our subsidiaries, as guarantors, entered into a revolving credit facility, which is a five-year, $2.0 billion revolving credit facility with an initial borrowing base of $725.0 million and aggregate elected commitments of $725.0 million. | ||||||||||||
We are permitted to borrow under the revolving credit facility in an amount up to the lesser of (i) the face amount of our revolving credit facility, (ii) the borrowing base or (iii) the aggregate elected commitments. The revolving credit facility is reserve-based, and thus our borrowing base is primarily based on the estimated value of our oil and natural gas properties and our commodity derivative contracts as determined semi-annually by our lenders in their sole discretion. Our borrowing base is subject to redetermination on a semi-annual basis based on an engineering report with respect to our estimated oil, NGL and natural gas reserves, which will take into account the prevailing oil, NGL and natural gas prices at such time, as adjusted for the impact of our commodity derivative contracts. Unanimous approval by the lenders is required for any increase to the borrowing base. In addition, we may, subject to certain conditions, increase our aggregate elected commitments in an amount not to exceed the then effective borrowing base on or following a scheduled redetermination of our borrowing base once before the next scheduled redetermination date. | ||||||||||||
Borrowings under the revolving credit facility are secured by liens on substantially all of our properties, but in any event, not less than 80% of the total value of our oil and natural gas properties, and all of our equity interests in any future guarantor subsidiaries and all of our other assets including personal property. Additionally, borrowings bear interest, at our option, at either (i) the greatest of (x) the prime rate as determined by the administrative agent, (y) the federal funds effective rate plus 0.50%, and (z) the one-month adjusted LIBOR plus 1.0% (adjusted upwards, if necessary, to the next 1/100th of 1%), in each case, plus a margin that varies from 0.50% to 1.50% per annum according to the total commitment usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect), or (ii) the applicable LIBOR plus a margin that varies from 1.50% to 2.50% per annum according to the total commitment usage. The unused portion of the total commitments is subject to a commitment fee that varies from 0.375% to 0.50% per annum according to our total commitments usage. | ||||||||||||
The revolving credit facility requires maintenance of a ratio of Consolidated EBITDAX to Consolidated Net Interest Expense (as each term is determined under the MRD revolving credit facility), which we refer to as the interest coverage ratio, of not less than 2.5 to 1.0, and a ratio of consolidated current assets to consolidated current liabilities, each as determined under the revolving credit facility, which we refer to as the current ratio, of not less than 1.0 to 1.0. | ||||||||||||
Additionally, the revolving credit facility contains various covenants and restrictive provisions that, among other things, limit our ability to incur additional debt, guarantees or liens; consolidate, merge or transfer all or substantially all of our assets; make certain investments, acquisitions or other restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; incur commodity hedges exceeding a certain percentage of our production and prepay certain indebtedness. | ||||||||||||
Events of default under the revolving credit facility include, but are not limited to, failure to make payments when due, breach of any covenant continuing beyond the applicable cure period, default under any other material debt, change in management or change of control, bankruptcy or other insolvency event and certain material adverse effects on our business. | ||||||||||||
MRD 5.875% Senior Unsecured Notes Offering | ||||||||||||
On July 10, 2014, MRD completed a private placement of $600.0 million aggregate principal amount of 5.875% senior unsecured notes (the “MRD Senior Notes”) at par. The MRD Senior Notes will mature on July 1, 2022. Interest on the MRD Senior Notes will accrue from July 10, 2014 and will be payable semiannually on January 1 and July 1 of each year, commencing on January 1, 2015. The MRD Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by certain of our existing subsidiaries (subject to customary release provisions). The MRD Senior Notes and the guarantees of the MRD Senior Notes will rank equally with our and the guarantors’ existing and future senior indebtedness, will be effectively junior to all of our and the guarantors’ existing and future secured indebtedness (to the extent of the value of the assets securing such indebtedness), and senior in right of payment to all of our and the guarantors’ subordinated indebtedness. The MRD Senior Notes will be structurally subordinated to the indebtedness and other liabilities of our non-guarantor subsidiaries, including MEMP and its subsidiaries and MEMP GP. | ||||||||||||
The MRD Senior Notes are governed by an indenture dated as of July 10, 2014. The MRD Senior Notes are subject to optional redemption at prices specified in the indenture plus accrued and unpaid interest, if any, to the date of redemption. The Company may also be required to repurchase the MRD Senior Notes upon a change of control. The indenture contains customary covenants and restrictive provisions, many of which will terminate if at any time no default exists under the indenture and the MRD Senior Notes receive an investment grade rating from both of two specified ratings agencies. MEMP and its subsidiaries are not subject to these covenants. The indenture also provides for customary and other events of default. In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to either the Company or the guarantors, all outstanding MRD Senior Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding MRD Senior Notes may declare all the MRD Senior Notes to be due and payable immediately. | ||||||||||||
PIK notes | ||||||||||||
On December 18, 2013, MRD LLC and its wholly-owned subsidiary Memorial Resource Finance Corp. (“MRD Finance Corp.” and, together with MRD LLC, the “MRD Issuers”) completed a private placement of $350.0 million in aggregate principal amount of the PIK notes. The PIK notes were issued at 98% of par with a maturity date of December 15, 2018. Net proceeds from the private offering were used: (i) to repay all indebtedness then outstanding under MRD LLC’s then-existing revolving credit facility, (ii) to establish a cash reserve of $50.0 million for the payment of interest on the PIK notes, (iii) to pay a $210.0 million distribution to the Funds, and (iv) for general company purposes. Interest on the PIK notes was payable semi-annually in arrears on June 15 and December 15 of each year, commencing on June 15, 2014. | ||||||||||||
A redemption notice was delivered to the PIK notes trustee on June 16, 2014, which specified a redemption date of July 16, 2014 at a redemption price of 102% of the principal amount of the PIK notes plus accrued and unpaid interest thereon to the date of redemption. In connection with the closing of our initial public offering, we assumed the obligations of MRD LLC under the PIK notes indenture and the related debt security agreement. We irrevocably deposited with the PIK notes trustee approximately $360.0 million on June 27, 2014, which was an amount sufficient to fund the redemption of the PIK notes on the redemption date and to satisfy and discharge our obligations under the PIK notes and the related indenture. The discharge became effective upon the irrevocable deposit of the funds with the PIK notes trustee. An extinguishment loss of $23.6 million was recognized related to the redemption of the PIK notes. | ||||||||||||
WildHorse Resources Revolving Credit Facility and Second Lien Facility | ||||||||||||
On April 3, 2013, WildHorse Resources entered into an amended and restated credit agreement. This revolving credit facility provided for aggregate maximum credit amounts at any time of $1.0 billion, consisting of borrowings and letters of credit and had an initial borrowing base of $300.0 million. This revolving credit facility was due to mature on April 13, 2018. The borrowing base was subject to redetermination on at least a semi-annual basis. Borrowings under the revolving credit facility were to be secured by liens on substantially all of WildHorse Resources’ properties, but in any event, not less than 80% of the total value of the WildHorse Resources’ oil and natural gas properties. | ||||||||||||
On June 13, 2013, WildHorse Resources entered into a $325.0 million second lien term loan agreement that was due to mature on December 13, 2018. Borrowings bore interest, at the borrower’s option, at either: (i) the Alternative Base Rate (as defined within each credit facility) plus 5.25% per annum or (ii) the applicable LIBOR plus 6.25% per annum. Borrowings under the second lien term loan agreement were to be secured by second-priority liens on substantially all of WildHorse Resources’ properties, but in any event, not less than 80% of the total value of the WildHorse Resources’ oil and natural gas properties. The priority of the security interests in the collateral and related creditors’ rights was set forth in an intercreditor agreement. The second lien term loan agreement contained customary affirmative and negative covenants, restrictive provisions and events of default. | ||||||||||||
On June 13, 2013, WildHorse Resources borrowed $325.0 million under its second lien term loan agreement and used such borrowings to reduce outstanding indebtedness under its revolving credit facility and to pay a onetime special $225.0 million distribution to MRD LLC. This $225.0 million distribution was subsequently distributed to the Funds. | ||||||||||||
In connection with the closing of our initial public offering, the WildHorse Resources’ revolving credit facility and second lien term loan were repaid in full and terminated. An extinguishment loss of $13.7 million was recognized related to the termination of the revolving credit facility and second lien term loan. | ||||||||||||
MEMP Revolving Credit Facility & Senior Notes | ||||||||||||
Memorial Production Operating LLC (“OLLC”), a wholly-owned subsidiary of MEMP, is a party to a $2.0 billion revolving credit facility, which is guaranteed by MEMP and all of its current and future subsidiaries (other than certain immaterial subsidiaries). | ||||||||||||
Borrowings under the revolving credit facility are secured by liens on substantially all of MEMP’s properties, but in any event, not less than 80% of the total value of MEMP’s oil and natural gas properties, and all of MEMP’s equity interests in OLLC and any future guarantor subsidiaries (other than San Pedro Bay Pipeline Company) and all of MEMP’s other assets including personal property. Additionally, borrowings under the revolving credit facility bear interest, at MEMP’s option, at: (i) the Alternative Base Rate defined as the greatest of (x) the prime rate as determined by the administrative agent, (y) the federal funds effective rate plus 0.50%, and (z) the one-month adjusted LIBOR plus 1.0% (adjusted upwards, if necessary, to the next 1/100th of 1%), in each case, plus a margin that varies from 0.50% to 1.50% per annum according to the borrowing base usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect), (ii) the applicable LIBOR plus a margin that varies from 1.50% to 2.50% per annum according to the borrowing base usage, or (iii) the applicable LIBOR Market Index plus a margin that varies from 1.50% to 2.50% per annum according to the borrowing base usage. The unused portion of the borrowing base (or, if lower, the reduced commitment amount that has been elected) will be subject to a commitment fee that varies from 0.375% to 0.50% per annum according to the borrowing base usage. | ||||||||||||
On April 17, 2013, May 23, 2013 and October 10, 2013, MEMP and its wholly-owned subsidiary Memorial Production Finance Corporation (“Finance Corp.” and, together with MEMP, the “MEMP Issuers”) completed a private placement of $300.0 million, $100.0 million and $300.0 million, respectively, of their 7.625% senior unsecured notes due 2021 (the “2021 Senior Notes”). The 2021 Senior Notes are fully and unconditionally guaranteed (subject to customary release provisions) on a joint and several basis by all of the MEMP’s subsidiaries (other than Finance Corp., which is co-issuer of the 2021 Senior Notes, and certain immaterial subsidiaries). The 2021 Senior Notes will mature on May 1, 2021 with interest accruing at a rate of 7.625% per annum and payable semi-annually in arrears on May 1 and November 1 of each year. The 2021 Senior Notes are governed by an indenture. The 2021 Senior Notes are subject to optional redemption at prices specified in the indenture plus accrued and unpaid interest, if any. The MEMP Issuers may also be required to repurchase the 2021 Senior Notes upon a change of control. The indenture contains customary covenants and restrictive provisions, many of which will terminate if at any time no default exists under the indenture and the 2021 Senior Notes receive an investment grade rating from both of two specified ratings agencies. The indenture also provides for customary and other events of default. In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to either of the MEMP Issuers, all outstanding 2021 Senior Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding 2021 Senior Notes may declare all the 2021 Senior Notes to be due and payable immediately. | ||||||||||||
On July 17, 2014, the MEMP Issuers completed a private placement of $500.0 million aggregate principal amount of 6.875% senior unsecured notes (the “2022 Senior Notes”). The 2022 Senior Notes were issued at 98.485% of par and are fully and unconditionally guaranteed (subject to customary release provisions) on a joint and several basis by all of MEMP’s subsidiaries (other than Finance Corp., which is co-issuer of the 2022 Senior Notes, and certain immaterial subsidiaries). The 2022 Senior Notes will mature on August 1, 2022 with interest accruing at 6.875% per annum and payable semi-annually in arrears on February 1 and August 1 of each year, commencing on February 1, 2015. The indenture governing the 2022 Notes, dated as July 17, 2014, contains customary covenants and restrictive provisions, many of which will terminate if at any time no default exists under the indenture and the 2022 Senior Notes receive an investment grade rating from both of two specified ratings agencies. The indenture also provides for customary and other events of default. In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to either of the MEMP Issuers, all outstanding 2022 Senior Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding 2022 Senior Notes may declare all the 2022 Senior Notes to be due and payable immediately. | ||||||||||||
Weighted-Average Interest Rates | ||||||||||||
The following table presents the weighted-average interest rates paid on our consolidated and combined variable-rate debt obligations for the periods presented: | ||||||||||||
For the Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
MRD Segment: | ||||||||||||
MRD revolving credit facility | 1.99 | % | n/a | n/a | ||||||||
MRD LLC revolver terminated December 2013 | n/a | 3.17 | % | 4.11 | % | |||||||
Classic revolving credit facility terminated November 2012 | n/a | n/a | 4.5 | % | ||||||||
WildHorse Resources revolver terminated June 2014 | 4.04 | % | 2.3 | % | 3 | % | ||||||
WildHorse Resources second lien terminated June 2014 | 6.44 | % | 7.6 | % | n/a | |||||||
Black Diamond terminated November 2013 | n/a | 3.97 | % | 3.62 | % | |||||||
MEMP Segment: | ||||||||||||
MEMP revolving credit facility | 2.67 | % | 3.25 | % | 2.74 | % | ||||||
WHT revolver terminated March 2013 | n/a | 2.29 | % | 2.6 | % | |||||||
Tanos revolver terminated April 2013 | n/a | 3.1 | % | 2.31 | % | |||||||
REO revolving credit facility terminated December 2012 | n/a | n/a | 3.4 | % | ||||||||
Stanolind revolver paid off by MEMP October 2013 | n/a | 3.52 | % | 3.76 | % | |||||||
Boaz revolver terminated October 2013 | n/a | 2.97 | % | 3.12 | % | |||||||
Crown revolver terminated October 2013 | n/a | 3.38 | % | 4.2 | % | |||||||
Propel Energy revolver paid off by MEMP October 2013 | n/a | 3.08 | % | 3.28 | % | |||||||
Unamortized Deferred Financing Costs | ||||||||||||
Unamortized deferred financing costs associated with our consolidated debt obligations were as follows at the dates indicated: | ||||||||||||
December 31, | December 31, | |||||||||||
2014 | 2013 | |||||||||||
(In thousands) | ||||||||||||
MRD Segment: | ||||||||||||
MRD revolving credit facility | $ | 4,285 | $ | — | ||||||||
MRD senior notes | 12,455 | — | ||||||||||
WildHorse Resources revolving credit facility | — | 2,436 | ||||||||||
WildHorse Resources second lien term loan | — | 9,030 | ||||||||||
PIK notes | — | 8,261 | ||||||||||
MEMP Segment: | ||||||||||||
MEMP revolving credit facility | 6,468 | 5,413 | ||||||||||
2021 Senior Notes | 13,308 | 15,053 | ||||||||||
2022 Senior Notes | 7,958 | — | ||||||||||
$ | 44,474 | $ | 40,193 | |||||||||
Stockholders_Equity_and_Noncon
Stockholders' Equity and Noncontrolling Interests | 12 Months Ended | |||
Dec. 31, 2014 | ||||
Equity [Abstract] | ||||
Stockholders' Equity and Noncontrolling Interests | Note 9. Stockholders’ Equity and Noncontrolling Interests | |||
Common Stock | ||||
The Company’s authorized capital stock includes 600,000,000 shares of common stock, $0.01 par value per share. The following is a summary of the changes in our common shares issued for the year ended December 31, 2014: | ||||
Balance January 1, 2014 | — | |||
Shares of common stock issued in connection with restructuring transactions (Note 1) | 171,000,000 | |||
Shares of common stock issued in initial public offering (Note 1) | 21,500,000 | |||
Shares of common stock repurchased and retired | (123,797 | ) | ||
Restricted common shares issued (Note 11) | 1,068,422 | |||
Restricted common shares forfeited | (9,211 | ) | ||
Balance December 31, 2014 | 193,435,414 | |||
See Note 11 for additional information regarding restricted common shares that were granted in connection with our initial public offering. Restricted shares of common stock are participating securities and considered issued and outstanding on the grant date of restricted stock award. | ||||
Share Repurchase Program | ||||
In December 2014, the board of directors (“Board”) of the Company authorized the repurchase of up to $50.0 million of the Company’s outstanding common stock from time to time on the open market, through block trades or otherwise and are subject to market conditions, as well as corporate, regulatory, and other considerations. During the year ended December 31, 2014, 123,797 shares of common stock were repurchased and retired for a total cost of approximately $2.2 million. | ||||
Subsequent event. MRD repurchased 2,764,887 shares of common stock under our repurchase program for an aggregate price of $47.8 million through March 16, 2015. MRD has retired all common stock repurchased and the shares of common stock are no longer issued or outstanding. | ||||
Preferred Stock | ||||
Our amended and restated certificate of incorporation authorizes our Board, subject to any limitations prescribed by law, without further stockholder approval, to establish and to issue from time to time one or more classes or series of preferred stock, par value $0.01 per share, covering up to an aggregate of 50,000,000 shares of preferred stock. There are no shares of preferred stock issued and outstanding as of December 31, 2014. | ||||
Dividend Policy | ||||
We do not anticipate declaring or providing any cash dividends to holders of our common stock in the foreseeable future. We currently intend to retain all future earnings, if any, for use in the operation of our business and to fund future growth. The decision whether to pay dividends in the future will be made by our Board in light of conditions then existing, including factors such as our financial condition, earnings, available cash, business opportunities, legal requirements, restrictions in our debt agreements, and other contracts and other factors our Board deems relevant. | ||||
Noncontrolling Interests | ||||
Noncontrolling interests is the portion of equity ownership in the Company’s consolidated subsidiaries not attributable to the Company and primarily consists of the equity interests held by: (i) the limited partners of MEMP, including the subordinated units held by MRD Holdco, that converted to common units in February 2015, and (ii) a third party investor in the San Pedro Bay Pipeline Company. Prior to our initial public offering, certain current or former key employees of certain of MRD LLC’s subsidiaries also held equity interests in those subsidiaries. | ||||
Distributions paid to the limited partners of MEMP primarily represent the quarterly cash distributions paid to MEMP’s unitholders, excluding those paid to MRD LLC. Contributions received from limited partners of MEMP primarily represent net cash proceeds received from common unit offerings. | ||||
In December 2012, MEMP sold 11,975,000 if its common units in an underwritten equity offering, which generated net cash proceeds of $194.1 million. The net proceeds from this equity offering partially funded MEMP’s December 2012 acquisition. | ||||
On March 25, 2013, MEMP sold 9,775,000 of its common units in an underwritten equity offering, which generated net cash proceeds of $171.8 million after deducting underwriting discounts and offering expenses. The net proceeds from this equity offering partially funded MEMP’s acquisition of all of the outstanding equity interests in WHT. | ||||
On October 8, 2013, MEMP sold 16,675,000 of its common units in an underwritten equity offering, which generated net cash proceeds of approximately $318.3 million after deducting underwriting discounts and offering expenses. The net proceeds from this equity offering were used to repay a portion of outstanding borrowings under MEMP’s revolving credit facility. | ||||
On July 15, 2014, MEMP sold 9,890,000 common units in an underwritten equity offering, which generated net proceeds of approximately $220.0 million after deducting offering expenses. The net proceeds from the equity offering were used to repay a portion of the outstanding borrowings under MEMP’s revolving credit facility. | ||||
On September 9, 2014, MEMP sold 14,950,000 common units in an underwritten equity offering, which generated net proceeds of approximately $321.3 million after deducting underwriting discounts and offering expenses. The net proceeds from the equity offering were used to repay a portion of the outstanding borrowings under MEMP’s revolving credit facility. | ||||
In December 2014, the board of directors of MEMP GP authorized the repurchase of up to $150.0 million of MEMP’s outstanding common units from time to time on the open market, through block trades or otherwise and are subject to market conditions, as well as corporate, regulatory, and other considerations. During the year ended December 31, 2014, 899,912 common units were repurchased and retired for a total cost of approximately $12.9 million. | ||||
Subsequent event. MEMP repurchased 1,909,583 common units under its repurchase program for an aggregate price of $28.5 million through February 1, 2015. MEMP has retired all common units repurchased and the common units are no longer issued or outstanding. | ||||
On April 1, 2013, Tanos’ management team sold its 1.066% interest in Tanos to MRD LLC and all incentive units held were forfeited. See Note 12 for further information. | ||||
In connection with this sale, all of Tanos’ employees resigned and became employees of Tanos Exploration II, LLC (“Tanos II”), a Texas limited liability company controlled by the former management team of Tanos. Effective April 1, 2013, Tanos II entered into a transition services agreement with Tanos, whereby Tanos II would manage the operations of Tanos for up to a 6-month period of time. Tanos II is an unrelated entity. | ||||
On November 1, 2013, MRD LLC purchased the noncontrolling interests in Black Diamond, Classic GP and Classic and all incentive units were forfeited. See Note 12 for further information. | ||||
In connection with our initial public offering, certain former management members of WildHorse Resources contributed their 0.1% membership interest in WildHorse Resources as well as their incentive units in exchange for shares of our common stock and cash consideration of $30.0 million. The difference between the carrying amount of the noncontrolling interest of $0.4 million and the fair value of the consideration paid of $3.3 million was recognized directly in stockholders’ equity as additional paid in capital. See Note 12 for further information. |
Earnings_per_Share
Earnings per Share | 12 Months Ended | |||
Dec. 31, 2014 | ||||
Earnings Per Share [Abstract] | ||||
Earnings per Share | Note 10. Earnings per share | |||
The following sets forth the calculation of earnings (loss) per share, or EPS, for the period indicated (in thousands, except per share amounts): | ||||
For the Year Ended December 31, | ||||
2014 | ||||
Numerator: | ||||
Net income (loss) available to common stockholders | $ | (784,581 | ) | |
Denominator: | ||||
Weighted average common shares outstanding | 192,498 | |||
Basic EPS | $ | (4.08 | ) | |
Diluted EPS (1) | $ | (4.08 | ) | |
-1 | The Company determines the more dilutive of either the two-class method or the treasury stock method for diluted EPS. The restricted common shares were antidilutive due to net losses and excluded from the diluted EPS calculation for the year ending December 31, 2014. There were 202,623 incremental shares excluded from the computation of diluted EPS for the year ending December 31, 2014. | |||
Our supplemental basic and diluted EPS includes earnings allocated to both previous owners and MRD LLC members for the period presented due to common control considerations. The following sets forth the calculation of our supplemental EPS, for the period indicated (in thousands, except per share amounts): | ||||
For the Year Ended December 31, | ||||
2014 | ||||
Numerator: | ||||
Net income (loss) attributable to Memorial Resource Development Corp. | $ | (762,851 | ) | |
Denominator: | ||||
Weighted average common shares outstanding | 192,498 | |||
Basic EPS | $ | (3.96 | ) | |
Diluted EPS (1) | $ | (3.96 | ) | |
-1 | The Company determines the more dilutive of either the two-class method or the treasury stock method for diluted EPS. The restricted common shares were antidilutive due to net losses and excluded from the diluted EPS calculation for the year ending December 31, 2014. There were 202,623 incremental shares excluded from the computation of diluted EPS for the year ending December 31, 2014. |
LongTerm_Incentive_Plans
Long-Term Incentive Plans | 12 Months Ended | ||||||||||
Dec. 31, 2014 | |||||||||||
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract] | |||||||||||
Long-Term Incentive Plans | Note 11. Long-Term Incentive Plans | ||||||||||
MRD | |||||||||||
In June 2014, our Board adopted the Memorial Resource Development Corp. 2014 Long Term Incentive Plan (“MRD LTIP”) for the employees of the Company and the Board. The MRD LTIP became effective upon filing of a registration statement on Form S-8 with the SEC on June 18, 2014. The MRD LTIP provides for potential grants of stock options, stock appreciation rights, restricted stock awards, restricted stock units, bonus stock, dividend equivalents, performance awards, annual incentive awards, and other stock-based awards. The MRD LTIP initially limits the number of common shares that may be delivered pursuant to awards under the plan up to 19,250,000 common shares. Common shares that are cancelled, forfeited or withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards. The MRD LTIP will be administered by our Board or a committee thereof. | |||||||||||
In connection with our initial public offering, our Board approved an aggregate award of 1,052,633 shares of restricted stock under the MRD LTIP to certain of our key employees, including each of our executive officers. These restricted stock awards will vest ratably on a four-year annual vesting schedule from the date of the grant and are subject to restrictions on transferability and customary forfeiture provisions. An award of 5,263 shares of restricted stock was also granted to each of our independent directors. These restricted stock awards will vest one year from the date of the grant and are also subject to restrictions on transferability and customary forfeiture provisions. | |||||||||||
Award recipients are entitled to all the rights of absolute ownership of the restricted common shares, including the right to vote those shares and to receive dividends thereon if, as, and when declared by our Board. The term “restricted common share” represents a time-vested share. Such awards are non-vested until the required service period expires. | |||||||||||
The following table summarizes information regarding restricted common share awards granted under the MRD LTIP for the periods presented: | |||||||||||
Number of Shares | Weighted-Average Grant Date Fair Value per Share (1) | ||||||||||
Restricted common shares outstanding at January 1, 2014 | — | $ | — | ||||||||
Granted (2) | 1,068,422 | $ | 19 | ||||||||
Forfeited | (9,211 | ) | $ | 19 | |||||||
Restricted common units outstanding at December 31, 2014 | 1,059,211 | $ | 19 | ||||||||
-1 | Determined by dividing the aggregate grant date fair value of awards by the number of awards issued. | ||||||||||
-2 | The aggregate grant date fair value of restricted common share awards issued in 2014 was $20.3 million based on grant date market price of $19.00 per share. | ||||||||||
The following table summarizes the amount of recognized compensation expense associated with these awards that are reflected in the accompanying statements of operations for the periods presented (in thousands): | |||||||||||
For the Year Ended December 31, | |||||||||||
2014 | |||||||||||
$ | 2,804 | ||||||||||
The unrecognized compensation cost associated with restricted common share awards was an aggregate $17.3 million at December 31, 2014. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 3.43 years. | |||||||||||
MEMP | |||||||||||
In December 2011, the Memorial Production Partners GP LLC Long-Term Incentive Plan (“MEMP LTIP”) was adopted for employees, officers, consultants and directors of MEMP GP and any of its affiliates who perform services for MEMP. The MEMP LTIP consists of restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, other unit-based awards and unit awards. The MEMP LTIP initially limits the number of common units that may be delivered pursuant to awards under the plan to 2,142,221 common units. 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 restricted common units awarded are subject to restrictions on transferability, customary forfeiture provisions and graded vesting provisions. One-third of each award generally vests on the first, second, and third anniversaries of the date of grant. Award recipients have all the rights of a unitholder in MEMP with respect to the restricted common units, including the right to receive distributions thereon if and when distributions are made by MEMP to its unitholders (except with respect to the fourth quarter 2011 distribution that was paid in February 2012). The term “restricted common unit” represents a time-vested unit. Such awards are non-vested until the required service period expires. | |||||||||||
The following table summarizes information regarding restricted common unit awards granted under the MEMP LTIP for the periods presented: | |||||||||||
Number of Units | Weighted-Average Grant Date Fair Value per Unit (1) | ||||||||||
Restricted common units outstanding at December 31, 2011 | — | $ | — | ||||||||
Granted (2) | 287,943 | $ | 18.07 | ||||||||
Forfeited | (2,334 | ) | $ | 17.14 | |||||||
Restricted common units outstanding at December 31, 2012 | 285,609 | $ | 18.08 | ||||||||
Granted (3) | 524,718 | $ | 18.83 | ||||||||
Forfeited | (11,734 | ) | $ | 17.24 | |||||||
Vested | (91,666 | ) | $ | 18.31 | |||||||
Restricted common units outstanding at December 31, 2013 | 706,927 | $ | 18.62 | ||||||||
Granted (4) | 684,954 | $ | 22.39 | ||||||||
Forfeited | (38,294 | ) | $ | 20.54 | |||||||
Vested | (260,067 | ) | $ | 18.56 | |||||||
Restricted common units outstanding at December 31, 2014 | 1,093,520 | $ | 20.93 | ||||||||
-1 | Determined by dividing the aggregate grant date fair value of awards by the number of awards issued. | ||||||||||
-2 | The aggregate grant date fair value of restricted common unit awards issued in 2012 was $5.2 million based on grant date market prices ranging from of $17.14 to $18.58 per unit. | ||||||||||
-3 | The aggregate grant date fair value of restricted common unit awards issued in 2013 was $9.9 million based on grant date market prices ranging from of $18.33 to $20.35 per unit. | ||||||||||
-4 | The aggregate grant date fair value of restricted common unit awards issued in 2014 was $15.3 million based on grant date market prices ranging from of $21.99 to $23.40 per unit. | ||||||||||
The following table summarizes the amount of recognized compensation expense associated with these awards that are reflected in the accompanying statements of operations for the periods presented (in thousands): | |||||||||||
For the Year Ended December 31, | |||||||||||
2014 | 2013 | 2012 | |||||||||
$ | 7,874 | $ | 3,558 | $ | 1,423 | ||||||
The unrecognized compensation cost associated with restricted common unit awards was $16.5 million at December 31, 2014. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.1 years. Since the restricted common units are participating securities, any distributions received by the restricted common unitholders are included in distributions to noncontrolling interests as presented on our statements of consolidated and combined cash flows. |
Incentive_Units
Incentive Units | 12 Months Ended | |||||||
Dec. 31, 2014 | ||||||||
Compensation Related Costs [Abstract] | ||||||||
Incentive Units | Note 12. Incentive Units | |||||||
General | ||||||||
Each of the governing documents of BlueStone, Tanos, WildHorse Resources, Classic, Black Diamond and MRD LLC previously provided for the issuance of incentive units. The incentive units were subject to performance conditions that affected their vesting. Compensation cost was recognized only if the performance condition was probable of being satisfied at each reporting date. | ||||||||
BlueStone, Tanos, WildHorse Resources, Classic, Black Diamond and MRD LLC each granted incentive units to certain of its members who were key employees at the time of grant. Holders of incentive units were entitled to distributions ranging from 10% to 31.5% when declared, but only after cumulative distribution thresholds (“payouts”) had been achieved. Payouts were generally triggered after the recovery of specified members’ capital contributions plus a rate of return. In connection with MEMP’s initial public offering in December 2011, BlueStone’s Special Tier and Tier I unit holders vested in their respective awards. Tier I unit holders became eligible to participate in 16.5% of any future distributions made by BlueStone. | ||||||||
Vesting of the incentive units was generally dependent upon an explicit service period, a fundamental change as defined in the respective governing document, and achievement of payout. All incentive units not vested were forfeited if an employee was no longer employed. All incentive units were forfeited if a holder resigned whether the incentive units were vested or not. If the payouts had not yet occurred, then all incentive units, whether or not vested, were forfeited automatically (unless extended). | ||||||||
On April 1, 2013, Tanos’ management team sold its 1.066% interest in Tanos to MRD LLC and all incentive units held were forfeited. Compensation expense of approximately $5.8 million was recorded by Tanos and recognized as a component of general and administrative expense during the year ended December 31, 2013. | ||||||||
On November 1, 2013, MRD LLC purchased the noncontrolling interests in Black Diamond, Classic GP and Classic and all incentive units were forfeited. Compensation expense of approximately $12.6 million was recorded by Black Diamond, Classic GP and Classic in the aggregate during November 2013. | ||||||||
Compensation expense of approximately $1.0 million and $20.7 million was recorded by BlueStone and recognized as a component of incentive unit compensation expense during the year ended December 31, 2014 and 2013, respectively. No compensation expense was recorded at December 31, 2012. | ||||||||
In connection with the PIK notes issued in December 2013, a special distribution of $10.0 million to holders of WildHorse’s Tier 1 incentive units was deemed probable of occurring. This amount was recognized as compensation expense in December 2013 with a corresponding amount in accrued liabilities on our balance sheet at December 31, 2013 as payment was not made until January 2, 2014. | ||||||||
In connection with the our initial public offering, certain former management members of WildHorse Resources contributed their 0.1% membership interest in WildHorse Resources as well as their incentive units in exchange for 42,334,323 shares of our common stock and cash consideration of $30.0 million. The portion of the total consideration related to acquiring the 0.1% membership interest was accounted for as the acquisition of noncontrolling interests. The difference between the carrying amount of the noncontrolling interest of $0.4 million and the fair value of the consideration paid of $3.3 million was recognized directly in stockholders’ equity as additional paid in capital. Compensation expense of approximately $831.1 million was recognized as a component of incentive unit compensation expense during the year ended December 31, 2014 related to the incentive units, of which approximately $26.7 million was paid in cash and the remaining $804.4 million related to the issuance of our common stock. | ||||||||
MRD Holdco | ||||||||
MRD LLC incentive units were originally granted in June 2012 and February 2013. In connection with our initial public offering and the related restructuring transactions, these incentive units were exchanged for substantially identical units in MRD Holdco, and such incentive units entitle holders thereof to portions of future distributions by MRD Holdco. MRD Holdco’s governing documents authorize the issuance of 1,000 incentive units, of which 930 incentive units were granted in an exchange for the cancelled MRD LLC awards (the “Exchanged Incentive Units”). | ||||||||
The holders of the Exchanged Incentive Units are eligible to participate in 9.3% of any future distributions made by MRD Holdco. The payment likelihood was deemed probable as a result of our initial public offering and the reasonable expectation that MRD Holdco will monetize the shares of our common stock it owns over an estimated three year period as market conditions permit. During 2014, we recognized $111.5 million of compensation expense offset by a deemed capital contribution from MRD Holdco and the unrecognized compensation expense of approximately $105.5 million as of December 31, 2014 will be recognized over the remaining expected service period of 2.41 years. | ||||||||
Subsequent to our initial public offering, MRD Holdco granted the remaining 70 incentive units to certain key employees (the “Subsequent Incentive Units”). The holders of the Subsequent Incentive Units are eligible to participate in 0.7% of any future distributions made by MRD Holdco once payout associated with these incentive units has been achieved. The payment likelihood was deemed probable at December 31, 2014 as a result of our initial public offering and the reasonable expectation that MRD Holdco will monetize the shares of our common stock it owns over an estimated three year period as market conditions permit. During 2014, we recognized $0.4 million of compensation expense and the unrecognized compensation expense of approximately $1.7 million as of December 31, 2014 will be recognized over the remaining expected service period of 2.41 years. | ||||||||
The fair value of the Exchanged and Subsequent Incentive Units will be remeasured on a quarterly basis until all payments have been made. The settlement obligation rests with MRD Holdco. Accordingly, no payments will ever be made by us related to these incentive units; however, non-cash compensation expense (income) will be allocated to us in future periods offset by capital contributions (distributions). As such, these awards are not dilutive to our stockholders. | ||||||||
The fair value of the incentive units was estimated using a Monte Carlo simulation valuation model with the following assumptions: | ||||||||
Exchanged Incentive Units | Subsequent Incentive Units | |||||||
Valuation date | 12/31/14 | 12/31/14 | ||||||
Dividend yield | 0 | % | 0 | % | ||||
Expected volatility | 39.54 | % | 39.54 | % | ||||
Risk-free rate | 0.85 | % | 0.85 | % | ||||
Expected life (years) | 2.41 | 2.41 | ||||||
Related_Party_Transactions
Related Party Transactions | 12 Months Ended | |||
Dec. 31, 2014 | ||||
Related Party Transactions [Abstract] | ||||
Related Party Transactions | Note 13. Related Party Transactions | |||
Amounts due to (due from) MRD Holdco and certain affiliates of NGP at December 31, 2014 and 2013 are presented as “Accounts receivable – affiliates” and “Accounts payable – affiliates” in the accompanying balance sheets. | ||||
Net Profits Interest Sold to NGP | ||||
Upon the completion of the 2010 Petrohawk and Clayton Williams acquisitions, WildHorse Resources sold a net profits interest in these properties to NGPCIF. Upon the acquisition of the Petrohawk properties WildHorse Resources immediately sold a net profits interest of 6.25% for all producing well bores and the right to participate in a 3.125% net profits interest in non-producing wellbores for the subject area for $19.5 million, or $19.1 million after adjustments. Upon the acquisition of the Clayton Williams properties, WildHorse Resources immediately sold a net profits interest of 23.5% for all producing wellbores and the right to participate in a 10.0% net profits interest in non-producing wellbores for the subject area for $19.8 million, or $19.9 million after adjustments. No gain or loss was recorded from these two transactions. | ||||
The net profits agreements for these transactions provided for a fixed fee of $20,000 per month for overhead and management in lieu of COPAS (Council of Petroleum Accountants Societies) billings. The net profits agreements did not provide for an overhead adjustment factor for this monthly charge, as suggested by COPAS. Quarterly net payments were made to NGPCIF for its net profits interest in the Petrohawk and Clayton Williams acquisitions. The net payments included credits for revenue receipts which were offset with production costs, capital expenditures and the management fee and were adjusted for any acquisition settlements received or paid and any other miscellaneous adjustments. As required by such agreements, WildHorse Resources could not collect funds owed by NGPCIF to WildHorse Resources, but WildHorse Resources could net amounts due from future quarterly payments. | ||||
As a result of these transactions, WildHorse Resources paid NGPCIF a total of $2.6 million and $2.3 million during 2013 and 2012, respectively. NGPCIF owed WildHorse Resources $0.2 million at December 31, 2013. | ||||
NGPCIF NPI Acquisition | ||||
WildHorse Resources repurchased the net profits interests discussed above from NGPCIF on February 28, 2014 for a purchase price of $63.4 million (see Note 1). This acquisition was accounted for as a combination of entities under common control at historical cost in a manner similar to the pooling of interest method. WildHorse Resources recorded the following net assets (in thousands): | ||||
Accounts receivable | $ | 2,274 | ||
Oil and natural gas properties, net | 40,056 | |||
Accrued liabilities | (297 | ) | ||
Asset retirement obligations | (277 | ) | ||
Net assets | $ | 41,756 | ||
Due to common control considerations, the difference between the purchase price and the net assets acquired are reflected within equity as a deemed distribution to NGP affiliates. | ||||
Transactions Between the Previous Owners and NGP Affiliates | ||||
The previous owners sold certain interests in oil and gas properties offshore Louisiana on October 11, 2012 for an aggregate $40.1 million to an NGP controlled entity, of which $38.1 million was received upon closing and the remaining proceeds were released from escrow in April 2013. Due to common control considerations, the proceeds from the sale exceeded the net book value of the properties sold by $6.3 million and recognized in the equity statement as a net contribution. | ||||
Beta Acquisition | ||||
On December 12, 2012, MEMP acquired Rise Energy Operating, Inc. (‘REO”), which owns certain operating interests in producing and non-producing oil and gas properties offshore Southern California (the “Beta Properties”), from Rise for a purchase price of $270.6 million, which included $3.0 million of working capital and other customary adjustments. The Beta acquisition was funded with borrowings under MEMP’s revolving credit facility and the net proceeds generated from its December 12, 2012 public offering of common units. This acquisition was accounted for as a combination of entities under common control at historical cost in a manner similar to the pooling of interest method. MEMP recorded the following net assets (in thousands): | ||||
Cash and cash equivalents | $ | 6,021 | ||
Accounts receivable | 16,284 | |||
Short-term derivative instruments, net | 2,926 | |||
Prepaid expenses and other current assets | 4,521 | |||
Oil and natural gas properties, net | 108,342 | |||
Restricted investments | 68,009 | |||
Accounts payable | (9,092 | ) | ||
Accrued liabilities | (9,140 | ) | ||
Asset retirement obligations | (58,746 | ) | ||
Credit facilities | (28,500 | ) | ||
Deferred tax liability | (1,674 | ) | ||
Noncontrolling interest | (5,255 | ) | ||
Net assets | $ | 93,696 | ||
An affiliate of REO collected a management fee for providing administrative services to REO. These administrative services included accounting, business development, finance, legal, information technology, insurance, government regulations, communications, regulatory, environmental and human resources services. REO incurred and paid management fees of $1.6 million during the year ended December 31, 2012. These management fees are presented as a component of general and administrative costs and expenses in the accompanying statements of operations. | ||||
October 2013 Cinco Group Acquisition | ||||
On October 1, 2013, MEMP acquired, through equity and asset transactions, oil and natural gas properties primarily in the Permian Basin, East Texas and the Rockies from MRD LLC and certain affiliates of NGP for an aggregate purchase price of approximately $603 million (subject to customary post-closing adjustments), of which approximately $507.1 million was received by certain affiliates of NGP. We refer to this transaction as the “Cinco Group acquisition.” The Cinco Group acquisition was funded with borrowings under MEMP’s revolving credit facility. The Cinco Group acquisition was accounted for as a combination of entities under common control at historical cost in a manner similar to the pooling of interest method. | ||||
Cash and cash equivalents | $ | 2,820 | ||
Accounts receivable | 5,184 | |||
Prepaid expenses and other current assets | 1,454 | |||
Oil and natural gas properties, net | 342,759 | |||
Long-term derivative instruments, net | (826 | ) | ||
Other long-term assets | 344 | |||
Accounts payable | (2,346 | ) | ||
Revenue payable | (2,910 | ) | ||
Accrued liabilities | (1,799 | ) | ||
Short-term derivative instruments, net | (1,828 | ) | ||
Asset retirement obligations | (9,606 | ) | ||
Credit facilities | (151,690 | ) | ||
Net assets | $ | 181,556 | ||
Other Acquisitions or Dispositions | ||||
On March 10, 2014, BlueStone sold certain interests in oil and gas properties in McMullen, Webb, Zapata, and Hidalgo Counties located in South Texas to BlueStone Natural Resources II, LLC, an NGP controlled entity. Total cash consideration received by BlueStone was approximately $1.2 million, which exceeded the net book value of the properties sold by $0.5 million. Due to common control considerations, the $0.5 million was recognized in the equity statement as a contribution. | ||||
On March 28, 2014, MRD Royalty acquired certain interests in oil and gas properties in Gonzales and Karnes Counties located in South Texas from Propel Energy for $3.3 million. | ||||
On June 18, 2014, in connection with our initial public offering and the related restructuring transactions (see Note 1), WHR Management Company was sold by WildHorse Resources to an affiliate of the Funds for net book value. The net book value of the assets sold was as follows (in thousands): | ||||
Cash and cash equivalents | $ | 33,001 | ||
Restricted cash | 300 | |||
Accounts receivable | 5,256 | |||
Prepaid expenses and other current assets | 379 | |||
Property, plant and equipment, net | 3,410 | |||
Other long-term assets | 4 | |||
Accounts payable | (19,959 | ) | ||
Accounts payable - affiliates | (17,099 | ) | ||
Accrued liabilities | (5,061 | ) | ||
Net assets | $ | 231 | ||
Related Party Agreements | ||||
We and certain of our affiliates have entered into various documents and agreements. These agreements have been negotiated among affiliated parties and, consequently, are not the result of arm’s-length negotiations. | ||||
Registration Rights Agreement | ||||
In connection with the closing of our initial public offering, we entered into a registration rights agreement with MRD Holdco and former management members of WildHorse Resources, Jay Graham (“Graham”) and Anthony Bahr (“Bahr”). Pursuant to the registration rights agreement, we have agreed to register the sale of shares of our common stock under certain circumstances. | ||||
Voting Agreement | ||||
In connection with the closing of our initial public offering, we entered into a voting agreement with MRD Holdco, WHR Incentive LLC, a limited liability company beneficially owned by Messrs. Bahr and Graham, and certain former management members of WildHorse Resources, who contributed their ownership of WildHorse Resources to us in the restructuring transactions. Among other things, the voting agreement provides that those former management members of WildHorse Resources will vote all of their shares of our common stock as directed by MRD Holdco. The voting agreement also prohibits the transfer of any shares of our common stock by the former management members of WildHorse Resources until after the termination of the services agreement described below; provided, however, that the former management members of WildHorse Resources (other than Messrs. Bahr and Graham) may transfer their shares of our common stock after the 180 day lock-up period has expired and these transfer restrictions will not prohibit Messrs. Bahr and Graham from exercising piggyback registration rights under the registration rights agreement described above. | ||||
Services Agreement | ||||
In connection with the closing of our initial public offering, we entered into a services agreement with WildHorse Resources and WHR Management Company, pursuant to which WHR Management Company would provide operating and administrative services to us for twelve months relating to the Terryville Complex. In exchange for such services, we paid a monthly management fee to WHR Management Company of approximately $1.0 million excluding third party COPAS income credits. | ||||
Upon the closing of our initial public offering, WHR Management Company became a subsidiary of WildHorse Resources II, LLC, an affiliate of the Company. NGP and certain former management members of WildHorse Resources own WHR II. | ||||
Subsequent event. We terminated the services agreement as of March 1, 2015. | ||||
WildHorse Management Services Agreement | ||||
WHR II is an independent energy company engaged in the acquisition, exploration, and development of natural gas and crude oil properties. WHR II is a related party and was organized in the State of Delaware on June 3, 2013. A management services agreement was executed on August 8, 2013, where WildHorse Resources provided general, administrative and employee services to WHR II. On August 8, 2013, a management agreement between WildHorse Resources and WHR II was executed where WildHorse was appointed the manager for WHR II with responsibilities included administrative and land services, operator services and financial and accounting services. As operator, WildHorse Resources received operated and non-operated revenues on behalf of WHR II and billed and received joint interest billings. In addition, WildHorse Resources paid for lease operating expenses and drilling costs on behalf of WHR II. On August 8, 2013, an asset and cost sharing agreement between WildHorse Resources and WHR II was executed. As part of the agreement, shared WildHorse Resources costs were allocated between WildHorse Resources and WHR II in accordance with a sharing ratio. The sharing ratio is based on the previous quarter’s capital expenditures and number of operated wells. Company specific costs were billed directly to the appropriate entity. As a result of these agreements, WildHorse Resources received net payments of $4.4 million from WHR II in 2013. WildHorse Resources owed WHR II $2.4 million as of December 31, 2013. These agreements were terminated in connection with our initial public offering. | ||||
Cinco Group Transition Service Agreements | ||||
MEMP entered into transition service agreements with Propel Energy, Stanolind, and Boaz Energy Partners to provide operating and administrative services to MEMP with respect to the acquired properties. The term of these agreements were from October 1, 2013 through February 28, 2014. MEMP paid transition service fees of approximately $0.8 million in the aggregate under these agreements. | ||||
Other Agreements | ||||
Effective March 1, 2012, BlueStone entered into an agreement with CH4 Energy III, LLC, an NGP controlled entity, to sell an undivided 25% interest in certain properties in the Mossy Grove Prospect in Walker and Madison Counties located in East Texas. Total cash consideration received by BlueStone was approximately $7.0 million, which exceeded the net book value of the properties sold by $6.4 million. Due to common control considerations, the $6.4 million was recognized in the equity statement as a contribution. The transaction closed on July 13, 2012. | ||||
A company affiliated with one of the Classic’s employees provided certain land-related services to Classic. Classic paid approximately $1.0 million to this affiliated company for these services in 2012. | ||||
Certain of the Cinco Group entities entered into advisory service, reimbursement, and indemnification agreements with NGP. These agreements generally required that an annual advisory fee be paid to NGP. Fees paid under these agreements for the years ended December 31, 2013 and 2012 were approximately $0.3 million and $0.4 million, respectively. Certain of the Cinco Group entities also paid a financing fee equal to a percentage of the capital contributions raised by NGP. These fees were considered a syndication cost and reduced equity contributions for financing fees paid. Fees for the year ended December 31, 2012 was approximately $0.4 million. There were no fees for the year ended December 31, 2013. | ||||
During 2012, the previous owners received an equity contribution of $6.9 million of oil and gas properties in the Hendricks Field located in the Permian Basin of Texas by an NGP controlled entity. Due to common control considerations, this equity contribution was recorded at historical cost of the properties. | ||||
During 2012, Boaz reimbursed a member of its management team approximately $0.3 million in general, administrative, and lease operating expenses related to an oral lease agreement between the member of management and a third party for a field office and yard located in Bronte, Texas. | ||||
Gas Processing Agreement | ||||
On March 17, 2014, WildHorse Resources entered into a gas processing agreement with PennTex North Louisiana, LLC (“PennTex”). PennTex is a joint venture among certain affiliates of NGP in which MRD Holdco owns, through its subsidiary MRD Midstream LLC, a minority interest. Once PennTex’s processing plant becomes operational, it will process natural gas produced from wells located on certain leases owned by us in the state of Louisiana. The agreement has a 15-year primary term, subject to one-year extensions at either party’s election. We will pay PennTex a monthly fee, subject to an annual inflationary escalation, based on volumes of natural gas delivered and processed. Once the plant is declared operational, we will be obligated to pay a minimum processing fee equal to approximately $18.3 million on an annual basis, subject to certain adjustments and conditions. The gas processing agreement requires that the processing plant be operational no later than November 1, 2015. | ||||
Classic Pipeline Gas Gathering Agreement & Water Disposal Agreement | ||||
On November 1, 2011, Classic Hydrocarbons Operating, LLC (“Classic Operating”), which became our wholly-owned subsidiary in connection with the restructuring transactions, and Classic Pipeline entered into a gas gathering agreement. Pursuant to the gas gathering agreement, Classic Operating dedicated to Classic Pipeline all of the natural gas produced (up to 50,000 MMBtus per day) on the properties operated by Classic Operating within certain counties in Texas through 2020, subject to one-year extensions at either party’s election. On May 1, 2014, Classic Operating and Classic Pipeline amended the gas gathering agreement with respect to Classic Operating’s remaining assets located in Panola and Shelby Counties, Texas. Under the amended gas gathering agreement, Classic Operating agreed to pay a fee of (i) $0.30 per MMBtu, subject to an annual 3.5% inflationary escalation, based on volumes of natural gas delivered and processed, and (ii) $0.07 per MMBtu per stage of compression plus its allocated share of compressor fuel. The amended gas gathering agreement has a term until December 31, 2023, subject to one-year extensions at either party’s election. | ||||
On May 1, 2014, Classic Operating and Classic Pipeline entered into a water disposal agreement. The water disposal agreement has a three-year term, subject to one-year extensions at either party’s election. Under the water disposal agreement, Classic Operating agreed to pay a fee of $1.10 per barrel for each barrel of water delivered to Classic Pipeline. |
Business_Segment_Data
Business Segment Data | 12 Months Ended | |||||||||||||||
Dec. 31, 2014 | ||||||||||||||||
Segment Reporting [Abstract] | ||||||||||||||||
Business Segment Data | Note 14. Business Segment Data | |||||||||||||||
Our reportable business segments are organized in a manner that reflects how management manages those business activities. | ||||||||||||||||
We have two reportable business segments, both of which are engaged in the acquisition, exploration, development and production of oil and natural gas properties. Our reportable business segments are as follows: | ||||||||||||||||
— | MRD—reflects the combined operations of the Company, MRD Operating, MRD LLC, WildHorse Resources and its previous owners, Classic and Classic GP, Black Diamond, BlueStone, Beta Operating and MEMP GP. | |||||||||||||||
— | MEMP—reflects the combined operations of MEMP, its previous owners, and historical dropdown transactions that occurred between MEMP and other MRD LLC consolidating subsidiaries. | |||||||||||||||
We evaluate segment performance based on Adjusted EBITDA. Adjusted EBITDA is defined as net income (loss), plus interest expense; loss on extinguishment of debt; income tax expense; depreciation, depletion and amortization (“DD&A”); impairment of goodwill and long-lived properties; accretion of asset retirement obligations (“AROs”); losses on commodity derivative contracts and cash settlements received; losses on sale of properties; incentive-based compensation expenses; exploration costs; provision for environmental remediation; equity loss from MEMP (MRD Segment only); cash distributions from MEMP (MRD Segment only); acquisition related costs; amortization of investment premium; and other non-routine items, less interest income; income tax benefit; gains on commodity derivative contracts and cash settlements paid; equity income from MEMP (MRD Segment only); gains on sale of assets and other non-routine items. | ||||||||||||||||
Financial information presented for the MEMP business segment is derived from the underlying consolidated and combined financial statements of MEMP that are publicly available. | ||||||||||||||||
Segment revenues and expenses include intersegment transactions. Our combined totals reflect the elimination of intersegment transactions. | ||||||||||||||||
In the MRD Segment’s individual financial statements, investments in the MEMP Segment that are included in the consolidated and combined financial statements are accounted for by the equity method. | ||||||||||||||||
The following table presents selected business segment information for the periods indicated (in thousands): | ||||||||||||||||
Other, | Consolidated | |||||||||||||||
Adjustments & | & Combined | |||||||||||||||
MRD | MEMP | Eliminations | Totals | |||||||||||||
Total revenues: | ||||||||||||||||
For the Year ended December 31, 2014 | $ | 405,286 | $ | 494,105 | $ | (46 | ) | $ | 899,345 | |||||||
For the Year ended December 31, 2013 | 231,558 | 343,616 | (151 | ) | 575,023 | |||||||||||
For the Year ended December 31, 2012 | 138,814 | 258,423 | (369 | ) | 396,868 | |||||||||||
Adjusted EBITDA: (1) | ||||||||||||||||
For the Year ended December 31, 2014 | 343,976 | 309,901 | (6,144 | ) | 647,733 | |||||||||||
For the Year ended December 31, 2013 | 197,903 | 222,185 | (25,232 | ) | 394,856 | |||||||||||
For the Year ended December 31, 2012 | 132,105 | 179,334 | (23,447 | ) | 287,992 | |||||||||||
Segment assets: (2) | ||||||||||||||||
As of December 31, 2014 | 1,632,313 | 2,930,559 | 30,675 | 4,593,547 | ||||||||||||
As of December 31, 2013 | 1,281,134 | 1,552,307 | (4,280 | ) | 2,829,161 | |||||||||||
Total cash expenditures for additions to long-lived assets: | ||||||||||||||||
For the Year ended December 31, 2014 | 521,038 | 1,348,095 | — | 1,869,133 | ||||||||||||
For the Year ended December 31, 2013 | 267,870 | 200,577 | — | 468,447 | ||||||||||||
For the Year ended December 31, 2012 | 249,526 | 387,160 | — | 636,686 | ||||||||||||
-1 | Adjustments and eliminations for the years ended December 31, 2014, 2013 and 2012 include amounts related to the MRD Segment’s equity investments in the MEMP Segment as well the elimination of $6.1 million, $26.0 million and $19.3 million of cash distributions that MEMP paid MRD Segment for the years ended December 31, 2014, 2013 and 2012, respectively, related to MRD Segment’s partnership interests in MEMP. | |||||||||||||||
-2 | Adjustments and eliminations primarily represent the elimination of the MRD Segment’s equity investments in the MEMP Segment. The adjustment at December 31, 2014 and 2013 also includes $46.0 million and $49.9 million, respectively related to an impairment recognized by the MEMP Segment during 2013. This impairment did not exist on a consolidated basis. | |||||||||||||||
Calculation of Reportable Segments’ Adjusted EBITDA | ||||||||||||||||
For the Year Ended December 31, 2014 | ||||||||||||||||
Combined | ||||||||||||||||
MRD | MEMP | Totals | ||||||||||||||
(In thousands) | ||||||||||||||||
Net income (loss) | $ | (762,926 | ) | $ | 118,079 | $ | (644,847 | ) | ||||||||
Interest expense, net | 50,283 | 83,550 | 133,833 | |||||||||||||
Loss on extinguishment of debt | 37,248 | — | 37,248 | |||||||||||||
Income tax expense (benefit) | 99,850 | 1,121 | 100,971 | |||||||||||||
DD&A | 154,917 | 155,404 | 310,321 | |||||||||||||
Impairment of proved oil and natural gas properties | 24,576 | 407,540 | 432,116 | |||||||||||||
Accretion of AROs | 688 | 5,618 | 6,306 | |||||||||||||
(Gain) loss on commodity derivative instruments | (257,734 | ) | (492,254 | ) | (749,988 | ) | ||||||||||
Cash settlements received (paid) on commodity derivative instruments | 9,166 | 13,522 | 22,688 | |||||||||||||
(Gain) loss on sale of properties | 3,057 | — | 3,057 | |||||||||||||
Acquisition related costs | 2,305 | 4,363 | 6,668 | |||||||||||||
Incentive-based compensation expense | 946,753 | 7,874 | 954,627 | |||||||||||||
Exploration costs | 15,813 | 790 | 16,603 | |||||||||||||
Provision for environmental remediation | — | 2,852 | 2,852 | |||||||||||||
Loss on office lease | 1,180 | 1,442 | 2,622 | |||||||||||||
Non-cash equity (income) loss from MEMP | 12,656 | — | 12,656 | |||||||||||||
Cash distributions from MEMP | 6,144 | — | 6,144 | |||||||||||||
Adjusted EBITDA | $ | 343,976 | $ | 309,901 | $ | 653,877 | ||||||||||
For the Year Ended December 31, 2013 | ||||||||||||||||
Combined | ||||||||||||||||
MRD | MEMP | Totals | ||||||||||||||
(In thousands) | ||||||||||||||||
Net income (loss) | $ | 82,243 | $ | 20,268 | $ | 102,511 | ||||||||||
Interest expense, net | 27,349 | 41,901 | 69,250 | |||||||||||||
Income tax expense (benefit) | 1,311 | 308 | 1,619 | |||||||||||||
DD&A | 87,043 | 97,269 | 184,312 | |||||||||||||
Impairment of proved oil and natural gas properties | 2,527 | 54,362 | 56,889 | |||||||||||||
Accretion of AROs | 728 | 4,853 | 5,581 | |||||||||||||
(Gain) loss on commodity derivative instruments | (3,013 | ) | (26,281 | ) | (29,294 | ) | ||||||||||
Cash settlements received (paid) on commodity derivative instruments | 12,240 | 19,879 | 32,119 | |||||||||||||
(Gain) loss on sale of properties | (82,773 | ) | (2,848 | ) | (85,621 | ) | ||||||||||
Acquisition related costs | 1,584 | 6,729 | 8,313 | |||||||||||||
Incentive-based compensation expense | 43,279 | 3,558 | 46,837 | |||||||||||||
Non-cash compensation expense | — | 1,057 | 1,057 | |||||||||||||
Exploration costs | 1,226 | 1,130 | 2,356 | |||||||||||||
Non-cash equity (income) loss from MEMP | (1,847 | ) | — | (1,847 | ) | |||||||||||
Cash distributions from MEMP | 26,006 | — | 26,006 | |||||||||||||
Adjusted EBITDA | $ | 197,903 | $ | 222,185 | $ | 420,088 | ||||||||||
For the Year Ended December 31, 2012 | ||||||||||||||||
Combined | ||||||||||||||||
MRD | MEMP | Totals | ||||||||||||||
(In thousands) | ||||||||||||||||
Net income (loss) | $ | (14,641 | ) | $ | 46,518 | $ | 31,877 | |||||||||
Interest expense, net | 12,802 | 20,436 | 33,238 | |||||||||||||
Income tax expense (benefit) | (178 | ) | 285 | 107 | ||||||||||||
DD&A | 62,636 | 76,036 | 138,672 | |||||||||||||
Impairment of proved oil and natural gas properties | 18,339 | 10,532 | 28,871 | |||||||||||||
Accretion of AROs | 632 | 4,377 | 5,009 | |||||||||||||
(Gain) loss on commodity derivative instruments | (13,488 | ) | (21,417 | ) | (34,905 | ) | ||||||||||
Cash settlements received (paid) on commodity derivative instruments | 30,188 | 44,111 | 74,299 | |||||||||||||
(Gain) loss on sale of properties | (2 | ) | (9,759 | ) | (9,761 | ) | ||||||||||
Acquisition related costs | 403 | 4,135 | 4,538 | |||||||||||||
Incentive-based compensation expense | 9,510 | 1,423 | 10,933 | |||||||||||||
Amortization of investment premium | — | 194 | 194 | |||||||||||||
Exploration costs | 7,337 | 2,463 | 9,800 | |||||||||||||
Non-cash equity (income) loss from MEMP | (696 | ) | — | (696 | ) | |||||||||||
Cash distributions from MEMP | 19,263 | — | 19,263 | |||||||||||||
Adjusted EBITDA | $ | 132,105 | $ | 179,334 | $ | 311,439 | ||||||||||
The following table presents a reconciliation of total reportable segments’ Adjusted EBITDA to net income (loss) for each of the periods indicated (in thousands): | ||||||||||||||||
For the Year Ended December 31, | ||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
Total Reportable Segments' Adjusted EBITDA | $ | 653,877 | $ | 420,088 | $ | 311,439 | ||||||||||
Adjustments to reconcile Adjusted EBITDA to net income (loss): | ||||||||||||||||
Interest expense, net | (133,833 | ) | (69,250 | ) | (33,238 | ) | ||||||||||
Loss on extinguishment of debt | (37,248 | ) | — | — | ||||||||||||
Income tax benefit (expense) | (100,971 | ) | (1,619 | ) | (107 | ) | ||||||||||
DD&A | (314,193 | ) | (184,717 | ) | (138,672 | ) | ||||||||||
Impairment of proved oil and natural gas properties | (432,116 | ) | (6,600 | ) | (28,871 | ) | ||||||||||
Accretion of AROs | (6,306 | ) | (5,581 | ) | (5,009 | ) | ||||||||||
Gains (losses) on commodity derivative instruments | 749,988 | 29,294 | 34,905 | |||||||||||||
Cash settlements paid (received) on commodity derivative instruments | (22,688 | ) | (32,119 | ) | (74,299 | ) | ||||||||||
Gain (loss) on sale of properties | (3,057 | ) | 85,621 | 9,761 | ||||||||||||
Acquisition related costs | (6,668 | ) | (8,313 | ) | (4,538 | ) | ||||||||||
Incentive-based compensation expense | (954,627 | ) | (46,837 | ) | (10,933 | ) | ||||||||||
Non-cash compensation expense | — | (1,057 | ) | — | ||||||||||||
Exploration costs | (16,603 | ) | (2,356 | ) | (9,800 | ) | ||||||||||
Amortization of investment premium | — | — | (194 | ) | ||||||||||||
Cash distributions from MEMP | (6,144 | ) | (26,006 | ) | (19,263 | ) | ||||||||||
Provision for environmental remediation | (2,852 | ) | — | — | ||||||||||||
Loss on office lease | (2,622 | ) | — | — | ||||||||||||
Other non-cash equity (income) loss | — | 784 | (4,184 | ) | ||||||||||||
Net income (loss) | $ | (636,063 | ) | $ | 151,332 | $ | 26,997 | |||||||||
Included below is our consolidated and combined statement of operations disaggregated by reportable segment for the period indicated (in thousands): | ||||||||||||||||
For the Year Ended December 31, 2014 | ||||||||||||||||
MRD | MEMP | Other, Adjustments & Eliminations | Consolidated & Combined Totals | |||||||||||||
Revenues: | ||||||||||||||||
Oil & natural gas sales | $ | 404,718 | $ | 490,249 | $ | — | $ | 894,967 | ||||||||
Other revenues | 568 | 3,856 | (46 | ) | 4,378 | |||||||||||
Total revenues | 405,286 | 494,105 | (46 | ) | 899,345 | |||||||||||
Costs and expenses: | ||||||||||||||||
Lease operating | 26,695 | 134,654 | (46 | ) | 161,303 | |||||||||||
Pipeline operating | — | 2,068 | — | 2,068 | ||||||||||||
Exploration | 15,813 | 790 | — | 16,603 | ||||||||||||
Production and ad valorem taxes | 14,150 | 31,601 | — | 45,751 | ||||||||||||
Depreciation, depletion, and amortization | 154,917 | 155,404 | 3,872 | 314,193 | ||||||||||||
Impairment of proved oil and natural gas properties | 24,576 | 407,540 | — | 432,116 | ||||||||||||
Incentive unit compensation expense | 943,949 | — | — | 943,949 | ||||||||||||
General and administrative | 42,054 | 45,619 | — | 87,673 | ||||||||||||
Accretion of asset retirement obligations | 688 | 5,618 | — | 6,306 | ||||||||||||
(Gain) loss on commodity derivative instruments | (257,734 | ) | (492,254 | ) | — | (749,988 | ) | |||||||||
(Gain) loss on sale of properties | 3,057 | — | — | 3,057 | ||||||||||||
Other, net | — | (12 | ) | — | (12 | ) | ||||||||||
Total costs and expenses | 968,165 | 291,028 | 3,826 | 1,263,019 | ||||||||||||
Operating income (loss) | (562,879 | ) | 203,077 | (3,872 | ) | (363,674 | ) | |||||||||
Other income (expense): | ||||||||||||||||
Interest expense, net | (50,283 | ) | (83,550 | ) | — | (133,833 | ) | |||||||||
Loss on extinguishment of debt | (37,248 | ) | — | — | (37,248 | ) | ||||||||||
Earnings from equity investments | (12,656 | ) | — | 12,656 | — | |||||||||||
Other, net | (10 | ) | (327 | ) | — | (337 | ) | |||||||||
Total other income (expense) | (100,197 | ) | (83,877 | ) | 12,656 | (171,418 | ) | |||||||||
Income (loss) before income taxes | (663,076 | ) | 119,200 | 8,784 | (535,092 | ) | ||||||||||
Income tax benefit (expense) | (99,850 | ) | (1,121 | ) | — | (100,971 | ) | |||||||||
Net income (loss) | $ | (762,926 | ) | $ | 118,079 | $ | 8,784 | $ | (636,063 | ) | ||||||
For the Year Ended December 31, 2013 | ||||||||||||||||
MRD | MEMP | Other, Adjustments & Eliminations | Consolidated & Combined Totals | |||||||||||||
Revenues: | ||||||||||||||||
Oil & natural gas sales | $ | 230,751 | $ | 341,197 | $ | — | $ | 571,948 | ||||||||
Other revenues | 807 | 2,419 | (151 | ) | 3,075 | |||||||||||
Total revenues | 231,558 | 343,616 | (151 | ) | 575,023 | |||||||||||
Costs and expenses: | ||||||||||||||||
Lease operating | 25,006 | 88,893 | (259 | ) | 113,640 | |||||||||||
Pipeline operating | — | 1,835 | — | 1,835 | ||||||||||||
Exploration | 1,226 | 1,130 | — | 2,356 | ||||||||||||
Production and ad valorem taxes | 9,362 | 17,784 | — | 27,146 | ||||||||||||
Depreciation, depletion, and amortization | 87,043 | 97,269 | 405 | 184,717 | ||||||||||||
Impairment of proved oil and natural gas properties | 2,527 | 54,362 | (50,289 | ) | 6,600 | |||||||||||
Incentive unit compensation expense | 43,279 | — | — | 43,279 | ||||||||||||
General and administrative | 38,479 | 43,495 | 105 | 82,079 | ||||||||||||
Accretion of asset retirement obligations | 728 | 4,853 | — | 5,581 | ||||||||||||
(Gain) loss on commodity derivative instruments | (3,013 | ) | (26,281 | ) | — | (29,294 | ) | |||||||||
(Gain) loss on sale of properties | (82,773 | ) | (2,848 | ) | — | (85,621 | ) | |||||||||
Other, net | 2 | 647 | — | 649 | ||||||||||||
Total costs and expenses | 121,866 | 281,139 | (50,038 | ) | 352,967 | |||||||||||
Operating income (loss) | 109,692 | 62,477 | 49,887 | 222,056 | ||||||||||||
Other income (expense): | ||||||||||||||||
Interest expense, net | (27,349 | ) | (41,901 | ) | — | (69,250 | ) | |||||||||
Earnings from equity investments | 1,066 | — | (1,066 | ) | — | |||||||||||
Other, net | 145 | — | — | 145 | ||||||||||||
Total other income (expense) | (26,138 | ) | (41,901 | ) | (1,066 | ) | (69,105 | ) | ||||||||
Income before income taxes | 83,554 | 20,576 | 48,821 | 152,951 | ||||||||||||
Income tax benefit (expense) | (1,311 | ) | (308 | ) | — | (1,619 | ) | |||||||||
Net income (loss) | $ | 82,243 | $ | 20,268 | $ | 48,821 | $ | 151,332 | ||||||||
For the Year Ended December 31, 2012 | ||||||||||||||||
MRD | MEMP | Other, Adjustments & Eliminations | Consolidated & Combined Totals | |||||||||||||
Revenues: | ||||||||||||||||
Oil & natural gas sales | $ | 138,032 | $ | 255,608 | $ | (9 | ) | $ | 393,631 | |||||||
Other revenues | 782 | 2,815 | (360 | ) | 3,237 | |||||||||||
Total revenues | 138,814 | 258,423 | (369 | ) | 396,868 | |||||||||||
Costs and expenses: | ||||||||||||||||
Lease operating | 24,438 | 80,116 | (800 | ) | 103,754 | |||||||||||
Pipeline operating | — | 2,114 | — | 2,114 | ||||||||||||
Exploration | 7,337 | 2,463 | — | 9,800 | ||||||||||||
Production and ad valorem taxes | 7,576 | 16,048 | — | 23,624 | ||||||||||||
Depreciation, depletion, and amortization | 62,636 | 76,036 | — | 138,672 | ||||||||||||
Impairment of proved oil and natural gas properties | 18,339 | 10,532 | — | 28,871 | ||||||||||||
Incentive unit compensation expense | 9,510 | — | — | 9,510 | ||||||||||||
General and administrative | 28,904 | 30,342 | 431 | 59,677 | ||||||||||||
Accretion of asset retirement obligations | 632 | 4,377 | — | 5,009 | ||||||||||||
(Gain) loss on commodity derivative instruments | (13,488 | ) | (21,417 | ) | — | (34,905 | ) | |||||||||
(Gain) loss on sale of properties | (2 | ) | (9,759 | ) | — | (9,761 | ) | |||||||||
Other, net | 364 | 138 | — | 502 | ||||||||||||
Total costs and expenses | 146,246 | 190,990 | (369 | ) | 336,867 | |||||||||||
Operating income (loss) | (7,432 | ) | 67,433 | — | 60,001 | |||||||||||
Other income (expense): | ||||||||||||||||
Interest expense, net | (12,802 | ) | (20,436 | ) | — | (33,238 | ) | |||||||||
Amortization of investment premium | — | (194 | ) | — | (194 | ) | ||||||||||
Earnings from equity investments | 4,880 | — | (4,880 | ) | — | |||||||||||
Other, net | 535 | — | — | 535 | ||||||||||||
Total other income (expense) | (7,387 | ) | (20,630 | ) | (4,880 | ) | (32,897 | ) | ||||||||
Income before income taxes | (14,819 | ) | 46,803 | (4,880 | ) | 27,104 | ||||||||||
Income tax benefit (expense) | 178 | (285 | ) | — | (107 | ) | ||||||||||
Net income (loss) | $ | (14,641 | ) | $ | 46,518 | $ | (4,880 | ) | $ | 26,997 | ||||||
Income_Taxes
Income Taxes | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Income Tax Disclosure [Abstract] | ||||||||||||
Income Tax | Note 15. Income Taxes | |||||||||||
Income tax benefit (expense) for the indicated periods is comprised of the following: | ||||||||||||
For the Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
(In thousands) | ||||||||||||
Current taxes: | ||||||||||||
Federal | $ | — | $ | — | $ | — | ||||||
State | 22 | (1,619 | ) | 178 | ||||||||
Deferred taxes: | ||||||||||||
Federal | (88,994 | ) | — | — | ||||||||
State | (11,999 | ) | — | (285 | ) | |||||||
Total income tax benefit (expense) | $ | (100,971 | ) | $ | (1,619 | ) | $ | (107 | ) | |||
The actual income tax benefit (expense) differs from the expected income tax benefit (provision) as computed by applying the federal statutory corporate tax rate of 35% for each period indicated as follows: | ||||||||||||
For the Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Expected tax benefit (expense) | $ | 187,282 | $ | (53,533 | ) | $ | (9,486 | ) | ||||
State income tax expense, net of federal benefit | (9,660 | ) | (1,619 | ) | (107 | ) | ||||||
Pass-through entities (1) | 49,989 | 53,533 | 9,486 | |||||||||
Stock compensation (2) | (330,024 | ) | — | — | ||||||||
Other | 1,442 | — | — | |||||||||
Total income tax benefit (expense) | $ | (100,971 | ) | $ | (1,619 | ) | $ | (107 | ) | |||
-1 | MEMP, a publicly traded partnership with qualifying income, is a pass-through entity for federal income tax purposes. In addition, our predecessor was also a pass-through entity for federal income tax purposes. | |||||||||||
-2 | As discussed in Note 12, the compensation expense associated with the incentive units of WildHorse Resources and MRD Holdco created a nondeductible permanent difference for income tax purposes. | |||||||||||
The components of net deferred income tax assets and (liabilities) recognized were as follows: | ||||||||||||
December 31, | ||||||||||||
2014 | 2013 | |||||||||||
(In thousands) | ||||||||||||
Deferred current income tax assets: | ||||||||||||
Unrealized hedging transactions | $ | 109 | $ | 37 | ||||||||
Accrued liabilities | — | 5 | ||||||||||
Other | 342 | (42 | ) | |||||||||
Deferred current income tax assets: | $ | 451 | $ | — | ||||||||
Deferred current income tax liabilities: | ||||||||||||
Unrealized hedging transactions | $ | (52,328 | ) | — | ||||||||
Other | (52 | ) | (382 | ) | ||||||||
Deferred current income tax liabilities: | $ | (52,380 | ) | $ | (382 | ) | ||||||
Deferred noncurrent income tax assets: | ||||||||||||
Net operating loss carryforward | $ | 28,043 | $ | 2,350 | ||||||||
Asset retirement obligation | 5,757 | 971 | ||||||||||
Other | 3,224 | 1 | ||||||||||
Net deferred tax valuation allowance | (2,634 | ) | (2,896 | ) | ||||||||
Deferred noncurrent income tax assets: | $ | 34,390 | $ | 426 | ||||||||
Deferred noncurrent income tax liabilities: | ||||||||||||
Property, plant and equipment | $ | (80,198 | ) | $ | (3,318 | ) | ||||||
Unrealized hedging transactions | (48,929 | ) | (275 | ) | ||||||||
Other | (280 | ) | 61 | |||||||||
Deferred noncurrent income tax liabilities: | $ | (129,407 | ) | $ | (3,532 | ) | ||||||
Net current deferred income tax assets (liabilities) | $ | (51,929 | ) | $ | (382 | ) | ||||||
Net noncurrent deferred income tax assets (liabilities) | $ | (95,017 | ) | $ | (3,106 | ) | ||||||
We must recognize the tax effects of any uncertain tax positions we may adopt, if the position taken by us is more likely than not sustainable based on its technical merits. For those benefits to be recognized, an income tax position must be more-likely-than-not to be sustained upon examination by taxing authorities. The Company has no unrecognized tax benefits for the years ended December 31, 2014, 2013 or 2012. | ||||||||||||
Generally, the Company's income tax years 2011 through 2014 remain open and subject to examination by Federal tax authorities or state tax authorities where the Company conducts operations. In certain jurisdictions the Company operates through more than one legal entity, each of which may have different open years subject to examination. | ||||||||||||
The Company recognizes interest and penalties accrued to unrecognized benefits in Other income (expense) in its consolidated statements of operations. For the years ended December 31, 2014, 2013 and 2012 the Company recognized no interest and penalties. | ||||||||||||
As of December 31, 2014, the Company has available, to reduce future taxable income, a United States net operating loss carryforwards (NOLs) of approximately $74.3 million before consideration of any valuation allowance which expires in the years 2027 thru 2035. A portion of these net operating loss carryforwards are subject to the ownership change limitation provisions of Section 382 of the Internal Revenue Code (IRC). The Company also has various net state NOL carryforwards of approximately $65.0 million, before consideration of any valuation allowance with varying lengths of allowable carryforward periods ranging from 10 to 20 years that can be used to offset future state taxable income. |
Commitments_and_Contingencies
Commitments and Contingencies | 12 Months Ended | |||||||||||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||||||||||
Commitments And Contingencies Disclosure [Abstract] | ||||||||||||||||||||||||||||
Commitments and Contingencies | Note 16. Commitments and Contingencies | |||||||||||||||||||||||||||
Litigation & Environmental | ||||||||||||||||||||||||||||
As part of our normal business activities, we may be named as defendants in litigation and legal proceedings, including those arising from regulatory and environmental matters. Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to indemnify us against liabilities arising from future legal proceedings. We are not aware of any litigation, pending or threatened, that we believe is reasonably likely to have a significant adverse effect on our financial position, results of operations or cash flows. | ||||||||||||||||||||||||||||
Environmental costs for remediation are accrued when environmental remediation efforts are probable and the costs can be reasonably estimated. Such accruals are based on management’s best estimate of the ultimate cost to remediate a site and are adjusted as further information and circumstances develop. Those estimates may change substantially depending on information about the nature and extent of contamination, appropriate remediation technologies and regulatory approvals. | ||||||||||||||||||||||||||||
The following table presents the activity of our environmental reserves for the periods presented: | ||||||||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||||||
Balance at beginning of period | $ | 577 | $ | 1,469 | $ | 1,747 | ||||||||||||||||||||||
Charged to costs and expenses | 2,852 | — | 193 | |||||||||||||||||||||||||
Payments | (1,337 | ) | (892 | ) | (471 | ) | ||||||||||||||||||||||
Balance at end of period | $ | 2,092 | $ | 577 | $ | 1,469 | ||||||||||||||||||||||
At December 31, 2014 and 2013, $2.1 million and $0.6 million, respectively, of our environmental reserves were classified as current liabilities in accrued liabilities. | ||||||||||||||||||||||||||||
Sinking Fund Trust Agreement | ||||||||||||||||||||||||||||
REO assumed an obligation with a third party to make payments into a sinking fund in connection with its 2009 acquisition of the Beta properties, the purpose of which is to provide funds adequate to decommission the portion of the San Pedro Bay pipeline that lies within State waters and the surface facilities. Under the terms of the agreement, REO, as the operator of the properties, is obligated to make monthly deposits into the sinking fund account in an amount equal to $0.25 per barrel of oil and other liquid hydrocarbon produced from the acquired working interest. Interest earned in the account stays in the account. The obligation to fund ceases when the aggregate value of the account reaches $4.3 million. As of December 31, 2014, the gross account balance included in restricted investments was approximately $2.7 million. REO’s maximum remaining obligation net to its 51.75% interest under the terms of the current agreement was $0.8 million at December 31, 2014. | ||||||||||||||||||||||||||||
Supplemental Bond for Decommissioning Liabilities Trust Agreement | ||||||||||||||||||||||||||||
REO assumed an obligation with the BOEM in connection with its 2009 acquisition of the Beta properties. Under the terms of the agreement dated March 1, 2007, the seller of the Beta properties was obligated to deliver a $90.0 million U.S. Treasury Note into a trust account for the decommissioning of the offshore production facilities. At the time of acquisition, all obligations under this existing agreement had been met. | ||||||||||||||||||||||||||||
In January 2010, the BOEM issued a report that revised upward, the estimated cost of decommissioning. In June 2010, REO agreed to make additional quarterly payments to the trust account attributable to its net working interest of approximately $0.6 million beginning on June 30, 2010 until the payments and accrued interest attributable to REO equal $78.7 million by December 31, 2016. The trust account must maintain minimum balances attributable to REO’s net working interest as follows (in thousands): | ||||||||||||||||||||||||||||
30-Jun-15 | $ | 72,450 | ||||||||||||||||||||||||||
30-Jun-16 | $ | 76,590 | ||||||||||||||||||||||||||
31-Dec-16 | $ | 78,660 | ||||||||||||||||||||||||||
In the event the account balance is less than the contractual amount, the working interest owners must make additional payments. Interest income earned and deposited in the trust account mitigates the likelihood that additional payments will have to be made by the working interest owners. As of December 31, 2014, the maximum remaining obligation net to REO’s interest was approximately $8.7 million. | ||||||||||||||||||||||||||||
The trust account is held by REO for the benefit of all working interest owners. The following is a summary of the gross held-to-maturity investments held in the trust account less the outside working interest owners share as of December 31, 2014 (in thousands): | ||||||||||||||||||||||||||||
Amortized | ||||||||||||||||||||||||||||
Investment | Cost | |||||||||||||||||||||||||||
U.S. Bank Money Market Cash Equivalent | $ | 135,176 | ||||||||||||||||||||||||||
Less: Outside working interest owners share | (65,222 | ) | ||||||||||||||||||||||||||
$ | 69,954 | |||||||||||||||||||||||||||
Purchase Commitment Assumed | ||||||||||||||||||||||||||||
At December 31, 2014, MEMP had a CO2 purchase commitment with a third party that was assumed in its Wyoming Acquisition. The table below outlines MEMP’s purchase commitment under the contract for the remainder of 2014 and annually thereafter (in thousands): | ||||||||||||||||||||||||||||
Payment or Settlement due by Period | ||||||||||||||||||||||||||||
Purchase commitment | Total | 2015 | 2016 | 2017 | 2018 | 2019 | Thereafter | |||||||||||||||||||||
CO2 minimum purchase commitment: | ||||||||||||||||||||||||||||
Estimated payment obligation | $ | 50,495 | $ | 9,608 | $ | 10,179 | $ | 10,151 | $ | 6,995 | $ | 7,060 | $ | 6,502 | ||||||||||||||
Processing Plant Expansions by Third Party Gatherer | ||||||||||||||||||||||||||||
In 2012, WildHorse Resources contracted with Regency Field Services LLC (the “Gatherer”) to expand their Dubach processing plant by up to 70 MMcf per day among other facility and infrastructure improvements. In 2013, WildHorse Resources contracted with the Gatherer to build a new high pressure pipeline from the dedicated area to the Gatherer’s Dubberly processing plant in Webster Parish, LA amongst other pipeline and infrastructure improvements. The Gatherer is entitled to receive a payback demand fee from us and other third parties equal to 110% of the infrastructure improvement costs. Effective February 1, 2014, the payback demand fee is equal to the monthly demand quantity (192,950 MMBtu per day) times $0.275 per MMBtu. In addition, for each MMBtu gathered in excess of the demand quantity, we are obligated to pay a payback demand fee of $0.275 per MMBtu. The monthly demand quantity escalated to 249,700 MMBtu per day until payout effective January 1, 2015. | ||||||||||||||||||||||||||||
WildHorse Resources’ minimum commitments to the Gatherer, before other owner contributions, as of December 31, 2014 were as follows (in thousands): | ||||||||||||||||||||||||||||
Dubach | Dubberly | |||||||||||||||||||||||||||
2015 | $ | 13,671 | $ | 11,393 | ||||||||||||||||||||||||
2016 | 13,709 | 11,424 | ||||||||||||||||||||||||||
2017 | 13,671 | 11,393 | ||||||||||||||||||||||||||
2018 | 12,772 | 10,643 | ||||||||||||||||||||||||||
Total | $ | 53,823 | $ | 44,853 | ||||||||||||||||||||||||
Related Party Agreements | ||||||||||||||||||||||||||||
Classic Operating entered into a gas gathering agreement and water disposal agreement with Classic Pipeline. | ||||||||||||||||||||||||||||
On March 17, 2014, WildHorse Resources entered into a gas processing agreement with PennTex. See Note 13 for additional information. | ||||||||||||||||||||||||||||
Operating Leases | ||||||||||||||||||||||||||||
We have leases for offshore Southern California pipeline right-of-way use as well as office space for our corporate headquarters and operating regions. We also lease equipment and incur surface rentals related to our business operations. For the years ended December 31, 2014, 2013, and 2012 we recognized $10.8 million, $8.3 million, and $5.0 million of rent expense, respectively. | ||||||||||||||||||||||||||||
Amounts shown in the following table represent minimum lease payment obligations and sublease rental income under non-cancelable operating leases with a remaining term in excess of one year: | ||||||||||||||||||||||||||||
Payment or Settlement due by Period | ||||||||||||||||||||||||||||
Total | 2015 | 2016 | 2017 | 2018 | 2019 | Thereafter | ||||||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||||||
MRD Segment: | ||||||||||||||||||||||||||||
Operating leases | $ | 43,625 | $ | 6,534 | $ | 6,607 | $ | 6,694 | $ | 6,259 | $ | 5,960 | $ | 11,571 | ||||||||||||||
Sublease rental income | 5,786 | 1,691 | 1,579 | 1,197 | 814 | 431 | 74 | |||||||||||||||||||||
MEMP Segment: | ||||||||||||||||||||||||||||
Operating leases | 3,665 | 788 | 416 | 205 | 205 | 205 | 1,846 | |||||||||||||||||||||
Defined_Contribution_Plans
Defined Contribution Plans | 12 Months Ended |
Dec. 31, 2014 | |
Postemployment Benefits [Abstract] | |
Defined Contribution Plans | Note 17. Defined Contribution Plans |
MRD sponsors a defined contribution plan for the benefit of substantially all employees who have attained 18 years of age. The plan allows eligible employees to make tax-deferred contributions up to 100% of their annual compensation, not to exceed annual limits established by the Internal Revenue Service. MRD makes matching contributions of 100% of employee contributions that does not exceed 6% of compensation. Employees are immediately vested in these matching contributions. This plan became effective on January 1, 2012. The plan received employer contributions of approximately $1.4 million, $0.9 million, and $0.4 million in 2014, 2013, and 2012 respectively. | |
Effective January 1, 2012, REO assumed sponsorship of a separate defined contribution plan. This plan specifically benefits substantially all those employed by the MRD subsidiary (Beta Operating) that operates and supports the Beta properties that have attained 21 years of age. Eligible employees are permitted to make tax-deferred contributions up to 100% of their annual compensation, not to exceed annual limits established by the Internal Revenue Service. Employer matching contributions of 100% of employee contributions that does not exceed 6% of compensation are made to the plan as well. The employer matching contributions associated with this plan were subject to a three-year graded vesting schedule through February 28, 2012. Effective March 1, 2012, the plan was amended to offer immediate vesting of employer matching contributions. This plan was terminated December 31, 2013. The plan received employer contributions of approximately $0.6 million and $0.5 million in 2013, and 2012 respectively. Approximately $0.3 million associated with this plan are reflected as costs and expenses in the accompanying statements of operations for the each of the years ended December 31, 2013 and 2012, respectively. | |
WildHorse, Tanos, BlueStone, Classic and Black Diamond also sponsored defined contribution plans for the benefit their eligible employees. Matching employer contributions of approximately $0.2 million, $0.5 million and $0.6 million were made to these other plans in 2014, 2013 and 2012, respectively. | |
Crown and Stanolind also made matching contributions to defined contribution plans for the benefit of their eligible employees. Matching employer contributions of approximately $0.1 million were made to these plans in both 2013 and 2012. Such contributions to these plans are included in general and administrative expenses in the accompanying combined statements of operations. | |
Quarterly_Financial_Informatio
Quarterly Financial Information (Unaudited) | 12 Months Ended | |||||||||||||||
Dec. 31, 2014 | ||||||||||||||||
Quarterly Financial Information Disclosure [Abstract] | ||||||||||||||||
Quarterly Financial Information (Unaudited) | Note 18. Quarterly Financial Information (Unaudited) | |||||||||||||||
The following tables present selected quarterly financial data for the periods indicated. Earnings per share are computed independently for each of the quarters presented and the sum of the quarterly earnings per share may not necessarily equal the total for the year. As discussed in Note 4 and Note 12, we recorded oil and natural gas property impairments and incentive unit compensation expense, respectively, during 2014, which impacted the comparability between the periods presented below. | ||||||||||||||||
First | Second | Third | Fourth | |||||||||||||
Quarter | Quarter | Quarter | Quarter | |||||||||||||
For the Year Ended December 31, 2014 | (In thousands, except per share amounts) | |||||||||||||||
Revenues | $ | 190,828 | $ | 236,564 | $ | 245,493 | $ | 226,460 | ||||||||
Operating income (loss) | 10,605 | (993,256 | ) | 174,201 | 444,776 | |||||||||||
Net income (loss) | (23,516 | ) | (1,053,443 | ) | 112,037 | 328,859 | ||||||||||
Net income (loss) attributable to noncontrolling interest | (31,888 | ) | (105,094 | ) | 102,109 | 161,661 | ||||||||||
Net income (loss) attributable to Memorial Resource | 8,372 | (948,349 | ) | 9,928 | 167,198 | |||||||||||
Development Corp. | ||||||||||||||||
Net income (loss) allocated to members | 6,947 | 13,358 | — | — | ||||||||||||
Net income (loss) allocated to previous owners | 1,425 | — | — | — | ||||||||||||
Net income (loss) available to common stockholders | n/a | (961,707 | ) | 9,928 | 167,198 | |||||||||||
Basic earnings per share | n/a | (5.00 | ) | 0.05 | 0.87 | |||||||||||
Diluted earnings per share | n/a | (5.00 | ) | 0.05 | 0.87 | |||||||||||
First | Second | Third | Fourth | |||||||||||||
Quarter | Quarter | Quarter | Quarter | |||||||||||||
For the Year Ended December 31, 2013 | (In thousands, except per share amounts) | |||||||||||||||
Revenues | $ | 122,181 | $ | 147,045 | $ | 153,515 | $ | 152,282 | ||||||||
Operating income (loss) | 9,521 | 90,327 | 117,797 | 4,411 | ||||||||||||
Net income (loss) | 180 | 78,158 | 95,962 | (22,968 | ) | |||||||||||
Net income (loss) attributable to noncontrolling interest | (4,069 | ) | 34,975 | 11,235 | 7,689 | |||||||||||
Net income (loss) attributable to Memorial Resource | 4,249 | 43,183 | 84,727 | (30,657 | ) | |||||||||||
Development Corp. | ||||||||||||||||
Net income (loss) allocated to members | 2,597 | 35,278 | 84,754 | (31,917 | ) | |||||||||||
Net income (loss) allocated to previous owners | 1,652 | 7,905 | (27 | ) | 1,260 | |||||||||||
Supplemental_Oil_and_Gas_Infor
Supplemental Oil and Gas Information (Unaudited) | 12 Months Ended | |||||||||||||||
Dec. 31, 2014 | ||||||||||||||||
Extractive Industries [Abstract] | ||||||||||||||||
Supplemental Oil and Gas Information (Unaudited) | ||||||||||||||||
Note 19. Supplemental Oil and Gas Information (Unaudited) | ||||||||||||||||
Capitalized Costs Relating to Oil and Natural Gas Producing Activities | ||||||||||||||||
The total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depreciation, depletion and amortization is as follows at the dates indicated. | ||||||||||||||||
For the Year Ended December 31, | ||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
(In thousands) | ||||||||||||||||
MRD Segment: | ||||||||||||||||
Evaluated oil and natural gas properties | $ | 1,590,997 | $ | 1,226,417 | $ | 1,052,219 | ||||||||||
Unevaluated oil and natural gas properties | 48,229 | 46,413 | 26,589 | |||||||||||||
Accumulated depletion, depreciation, and amortization | (391,145 | ) | (256,629 | ) | (202,581 | ) | ||||||||||
Subtotal | $ | 1,248,081 | $ | 1,016,201 | $ | 876,227 | ||||||||||
MEMP Segment: | ||||||||||||||||
Evaluated oil and natural gas properties (1) | $ | 3,007,214 | $ | 1,748,438 | $ | 1,539,642 | ||||||||||
Support equipment and facilities | 185,997 | 5,910 | 5,760 | |||||||||||||
Unevaluated oil and natural gas properties | — | — | 5,004 | |||||||||||||
Accumulated depletion, depreciation, and amortization (1) | (989,103 | ) | (416,617 | ) | (265,710 | ) | ||||||||||
Subtotal | $ | 2,204,108 | $ | 1,337,731 | $ | 1,284,696 | ||||||||||
Eliminations: | ||||||||||||||||
Accumulated depletion, depreciation, and amortization | $ | 46,013 | $ | 49,884 | $ | — | ||||||||||
Consolidated: | ||||||||||||||||
Evaluated oil and natural gas properties (1) | $ | 4,598,211 | $ | 2,974,855 | $ | 2,591,861 | ||||||||||
Support equipment and facilities | 185,997 | 5,910 | 5,760 | |||||||||||||
Unevaluated oil and natural gas properties | 48,229 | 46,413 | 31,593 | |||||||||||||
Accumulated depletion, depreciation, and amortization (1) | (1,334,235 | ) | (623,362 | ) | (468,291 | ) | ||||||||||
Total | $ | 3,498,202 | $ | 2,403,816 | $ | 2,160,923 | ||||||||||
-1 | Amounts do not include costs for SPBPC and related support equipment. | |||||||||||||||
Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities | ||||||||||||||||
Costs incurred in property acquisition, exploration and development activities were as follows for the periods indicated: | ||||||||||||||||
For the Year Ended December 31, | ||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
(In thousands) | ||||||||||||||||
MRD Segment: | ||||||||||||||||
Property acquisition costs, proved | $ | 74,490 | $ | 56,108 | $ | 87,857 | ||||||||||
Property acquisition costs, unproved | 25,030 | 19,975 | 5,293 | |||||||||||||
Exploration and extension well costs | 209,532 | 13,313 | 212 | |||||||||||||
Development | 208,459 | 210,440 | 135,951 | |||||||||||||
Subtotal | $ | 517,511 | $ | 299,836 | $ | 229,313 | ||||||||||
MEMP Segment: | ||||||||||||||||
Property acquisition costs, proved | $ | 983,076 | $ | 37,786 | $ | 278,246 | ||||||||||
Exploration and extension well costs | — | — | 42,430 | |||||||||||||
Development (1) | 279,318 | 145,830 | 62,472 | |||||||||||||
Subtotal | $ | 1,262,394 | $ | 183,616 | $ | 383,148 | ||||||||||
Consolidated: | ||||||||||||||||
Property acquisition costs, proved | $ | 1,057,566 | $ | 93,894 | $ | 366,103 | ||||||||||
Property acquisition costs, unproved | 25,030 | 19,975 | 5,293 | |||||||||||||
Exploration and extension well costs | 209,532 | 13,313 | 42,642 | |||||||||||||
Development (1) | 487,777 | 356,270 | 198,423 | |||||||||||||
Total | $ | 1,779,905 | $ | 483,452 | $ | 612,461 | ||||||||||
-1 | Amounts do not include costs for SPBPC and related support equipment. | |||||||||||||||
Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves | ||||||||||||||||
As required by the FASB and SEC, the standardized measure of discounted future net cash flows presented below is computed by applying first-day-of-the-month average prices, year-end costs and legislated tax rates and a discount factor of 10 percent to proved reserves. We do not believe the standardized measure provides a reliable estimate of the Company’s expected future cash flows to be obtained from the development and production of its oil and gas properties or of the value of its proved oil and gas reserves. The standardized measure is prepared on the basis of certain prescribed assumptions including first-day-of-the-month average prices, which represent discrete points in time and therefore may cause significant variability in cash flows from year to year as prices change. | ||||||||||||||||
Oil and Natural Gas Reserves | ||||||||||||||||
Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures. | ||||||||||||||||
Proved reserves are those quantities of oil and natural gas that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. | ||||||||||||||||
We engaged NSAI and MEMP engaged NSAI and Ryder Scott to audit our internally prepared reserves estimates for all of our estimated proved reserves (by volume) at December 31, 2014. All proved reserves are located in the United States and all prices are held constant in accordance with SEC rules. | ||||||||||||||||
The weighted-average benchmark product prices used for valuing the reserves are based upon the average of the first-day-of-the-month price for each month within the period January through December of each year presented: | ||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
Oil ($/Bbl) | ||||||||||||||||
West Texas Intermediate (1) | $ | 91.48 | $ | 93.42 | $ | 91.33 | ||||||||||
NGL ($/Bbl) | ||||||||||||||||
West Texas Intermediate (1) | $ | 91.48 | $ | 93.42 | $ | 91.75 | ||||||||||
Natural Gas ($/Mmbtu) | ||||||||||||||||
Henry Hub (2) | $ | 4.35 | $ | 3.67 | $ | 2.75 | ||||||||||
-1 | The unweighted average West Texas Intermediate price was adjusted by lease for quality, transportation fees, and a regional price differential. | |||||||||||||||
-2 | The unweighted average Henry Hub price was adjusted by lease for energy content, compression charges, transportation fees, and regional price differentials. | |||||||||||||||
MRD Segment | ||||||||||||||||
The following tables set forth estimates of the net reserves as of December 31, 2014, 2013, and 2012 respectively: | ||||||||||||||||
For the Year Ended December 31, 2014 | ||||||||||||||||
Oil | Gas | NGLs | Equivalent | |||||||||||||
(MBbls) | (MMcf) | (MBbls) | (MMcfe) | |||||||||||||
Proved developed and undeveloped reserves: | ||||||||||||||||
Beginning of the year | 11,311 | 802,254 | 42,576 | 1,125,577 | ||||||||||||
Extensions and discoveries | 1,825 | 183,527 | 9,876 | 253,730 | ||||||||||||
Purchase of minerals in place | 269 | 22,186 | 1,247 | 31,283 | ||||||||||||
Production | (951 | ) | (63,801 | ) | (2,220 | ) | (82,816 | ) | ||||||||
Sales of minerals in place | (623 | ) | (10,815 | ) | (950 | ) | (20,253 | ) | ||||||||
Revision of previous estimates | 772 | 247,578 | 12,060 | 324,558 | ||||||||||||
End of year | 12,603 | 1,180,929 | 62,589 | 1,632,079 | ||||||||||||
Proved developed reserves: | ||||||||||||||||
Beginning of year | 3,402 | 263,797 | 13,904 | 367,641 | ||||||||||||
End of year | 3,905 | 392,181 | 19,924 | 535,151 | ||||||||||||
Proved undeveloped reserves: | ||||||||||||||||
Beginning of year | 7,909 | 538,457 | 28,672 | 757,936 | ||||||||||||
End of year | 8,698 | 788,748 | 42,665 | 1,096,928 | ||||||||||||
For the Year Ended December 31, 2013 | ||||||||||||||||
Oil | Gas | NGLs | Equivalent | |||||||||||||
(MBbls) | (MMcf) | (MBbls) | (MMcfe) | |||||||||||||
Proved developed and undeveloped reserves: | ||||||||||||||||
Beginning of the year | 11,953 | 739,378 | 41,466 | 1,059,895 | ||||||||||||
Extensions and discoveries | 1,794 | 149,974 | 8,319 | 210,652 | ||||||||||||
Purchase of minerals in place | 211 | 31,815 | 1,017 | 39,183 | ||||||||||||
Production | (665 | ) | (34,092 | ) | (1,457 | ) | (46,819 | ) | ||||||||
Sales of minerals in place | (599 | ) | (14,137 | ) | (1,573 | ) | (27,169 | ) | ||||||||
Revision of previous estimates | (1,383 | ) | (70,684 | ) | (5,196 | ) | (110,165 | ) | ||||||||
End of year (1) | 11,311 | 802,254 | 42,576 | 1,125,577 | ||||||||||||
Proved developed reserves: | ||||||||||||||||
Beginning of year | 3,082 | 245,449 | 12,321 | 337,869 | ||||||||||||
End of year | 3,402 | 263,797 | 13,904 | 367,641 | ||||||||||||
Proved undeveloped reserves: | ||||||||||||||||
Beginning of year | 8,871 | 493,929 | 29,145 | 722,026 | ||||||||||||
End of year | 7,909 | 538,457 | 28,672 | 757,936 | ||||||||||||
-1 | Includes reserves of 41,077 MMcfe attributable to noncontrolling interests and the MRD Segment previous owners. | |||||||||||||||
For the Year Ended December 31, 2012 | ||||||||||||||||
Oil | Gas | NGLs | Equivalent | |||||||||||||
(MBbls) | (MMcf) | (MBbls) | (MMcfe) | |||||||||||||
Proved developed and undeveloped reserves: | ||||||||||||||||
Beginning of the year | 10,834 | 929,335 | 53,031 | 1,312,533 | ||||||||||||
Extensions and discoveries | 689 | 42,019 | 2,778 | 62,819 | ||||||||||||
Purchase of minerals in place | 1,100 | 28,115 | 1,879 | 45,987 | ||||||||||||
Production | (369 | ) | (24,131 | ) | (898 | ) | (31,731 | ) | ||||||||
Sales of minerals in place | (4 | ) | (728 | ) | — | (752 | ) | |||||||||
Revision of previous estimates | (297 | ) | (235,232 | ) | (15,324 | ) | (328,961 | ) | ||||||||
End of year (1) | 11,953 | 739,378 | 41,466 | 1,059,895 | ||||||||||||
Proved developed reserves: | ||||||||||||||||
Beginning of year | 2,107 | 191,557 | 7,644 | 250,073 | ||||||||||||
End of year | 3,082 | 245,449 | 12,321 | 337,869 | ||||||||||||
Proved undeveloped reserves: | ||||||||||||||||
Beginning of year | 8,727 | 737,778 | 45,387 | 1,062,460 | ||||||||||||
End of year | 8,871 | 493,929 | 29,145 | 722,026 | ||||||||||||
-1 | Includes reserves of 67,135 MMcfe attributable to noncontrolling interests and the MRD Segment previous owners. | |||||||||||||||
Noteworthy amounts included in the categories of proved reserve changes in the above tables include: | ||||||||||||||||
· | MRD had upward revisions of 324.6 Bcfe primarily due to well performance in East Texas and North Louisiana. Additionally, there was an increase of 253.7 Bcfe from extensions, primarily due to the redevelopment program in the Terryville Complex. MRD also acquired 31.3 Bcfe from multiple acquisitions already inside the Terryville Complex. Proved undeveloped reserves increased during the year primarily due to the development of unproved locations in 2014 and revisions to our forecasts for East Texas properties, which give effect for well performance using longer lateral lengths. | |||||||||||||||
· | 148.6 Bcfe of the increase in reserves for the year end December 31, 2013, through the category extensions and discoveries, was due to the horizontal redevelopment drilling program in the Terryville Complex. | |||||||||||||||
· | WildHorse acquired 43.5 Bcfe in multiple acquisitions during the year ended December 31, 2012, the largest being the Undisclosed Seller Acquisition. Downward revisions of previous estimates for estimated natural gas proved reserves was primarily the result of a decrease in natural gas prices. | |||||||||||||||
See Note 3 for additional information on acquisitions and divestitures. | ||||||||||||||||
A variety of methodologies are used to determine our proved reserve estimates. The principal methodologies employed are reservoir simulation, decline curve analysis, volumetric, material balance, advance production type curve matching, petro-physics/log analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all of our fields. | ||||||||||||||||
The standardized measure of discounted future net cash flows is as follows: | ||||||||||||||||
For the Year Ended December 31, | ||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
(In thousands) | ||||||||||||||||
Future cash inflows | $ | 8,313,329 | $ | 5,722,848 | $ | 4,921,192 | ||||||||||
Future production costs | (1,325,573 | ) | (1,587,374 | ) | (1,255,289 | ) | ||||||||||
Future development costs | (1,443,612 | ) | (1,352,945 | ) | (1,060,777 | ) | ||||||||||
Future income tax expense (1) | (1,789,031 | ) | — | — | ||||||||||||
Future net cash flows for estimated timing of cash flows | 3,755,113 | 2,782,529 | 2,605,126 | |||||||||||||
10% annual discount for estimated timing of cash flows | (1,792,579 | ) | (1,313,577 | ) | (1,284,531 | ) | ||||||||||
Standardized measure of discounted future net cash flows (2) | $ | 1,962,534 | $ | 1,468,952 | $ | 1,320,595 | ||||||||||
-1 | Our predecessor was a pass through entity and was subject to the Texas margin tax which has a maximum effective rate of 0.7% of gross income apportioned to Texas. Due to immateriality, we have excluded the impact of this tax for the years ended December 31, 2013 and 2012. | |||||||||||||||
-2 | Includes $63,422 and $78,518 attributable to both noncontrolling interests and the MRD Segment previous owners for the years ended December 31, 2013 and 2012, respectively. | |||||||||||||||
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves | ||||||||||||||||
The following is a summary of the changes in the standardized measure of discounted future net cash flows for the proved oil and natural gas reserves during each of the years in the three year period ended December 31, 2014: | ||||||||||||||||
For the Year Ended December 31, | ||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
(In thousands) | ||||||||||||||||
Beginning of year | $ | 1,468,952 | $ | 1,320,595 | $ | 1,386,071 | ||||||||||
Sale of oil and natural gas produced, net of production costs | (363,723 | ) | (196,444 | ) | (107,316 | ) | ||||||||||
Purchase of minerals in place | 69,282 | 51,177 | 98,384 | |||||||||||||
Sale of minerals in place | (47,791 | ) | (54,091 | ) | — | |||||||||||
Extensions and discoveries | 653,186 | 301,004 | 127,994 | |||||||||||||
Changes in income taxes, net | (1,058,814 | ) | — | — | ||||||||||||
Changes in prices and costs | 365,030 | (11,336 | ) | (402,202 | ) | |||||||||||
Previously estimated development costs incurred | 256,605 | 87,297 | 64,390 | |||||||||||||
Net changes in future development costs | (126,598 | ) | 57,353 | (67,331 | ) | |||||||||||
Revisions of previous quantities | 828,296 | (186,804 | ) | (176,788 | ) | |||||||||||
Accretion of discount | 146,896 | 128,544 | 138,607 | |||||||||||||
Change in production rates and other | (228,787 | ) | (28,343 | ) | 258,786 | |||||||||||
End of year | $ | 1,962,534 | $ | 1,468,952 | $ | 1,320,595 | ||||||||||
MEMP Segment | ||||||||||||||||
The following tables set forth estimates of the net reserves as of December 31, 2014, 2013, and 2012 respectively: | ||||||||||||||||
For the Year Ended December 31, 2014 | ||||||||||||||||
Oil | Gas | NGLs | Equivalent | |||||||||||||
(MBbls) | (MMcf) | (MBbls) | (MMcfe) | |||||||||||||
Proved developed and undeveloped reserves: | ||||||||||||||||
Beginning of the year | 39,149 | 607,139 | 28,846 | 1,015,105 | ||||||||||||
Extensions and discoveries | 849 | 12,723 | 711 | 22,085 | ||||||||||||
Purchase of minerals in place | 69,095 | 13,036 | 22,351 | 561,713 | ||||||||||||
Production | (3,092 | ) | (41,494 | ) | (2,143 | ) | (72,902 | ) | ||||||||
Revision of previous estimates | (6,431 | ) | (31,777 | ) | (287 | ) | (72,090 | ) | ||||||||
End of year (1) | 99,570 | 559,627 | 49,478 | 1,453,911 | ||||||||||||
Proved developed reserves: | ||||||||||||||||
Beginning of year | 22,265 | 387,548 | 15,959 | 616,893 | ||||||||||||
End of year | 54,526 | 380,397 | 35,539 | 920,783 | ||||||||||||
Proved undeveloped reserves: | ||||||||||||||||
Beginning of year | 16,884 | 219,591 | 12,887 | 398,212 | ||||||||||||
End of year | 45,044 | 179,230 | 13,939 | 533,128 | ||||||||||||
(1) MRD Segment’s share of these reserves is 1,454 MMcfe. | ||||||||||||||||
For the Year Ended December 31, 2013 | ||||||||||||||||
Oil | Gas | NGLs | Equivalent | |||||||||||||
(MBbls) | (MMcf) | (MBbls) | (MMcfe) | |||||||||||||
Proved developed and undeveloped reserves: | ||||||||||||||||
Beginning of the year | 39,089 | 604,440 | 29,352 | 1,015,095 | ||||||||||||
Extensions and discoveries | 5,655 | 40,770 | 1,747 | 85,180 | ||||||||||||
Purchase of minerals in place | 119 | 16,294 | 258 | 18,554 | ||||||||||||
Production | (1,764 | ) | (35,924 | ) | (1,632 | ) | (56,303 | ) | ||||||||
Revision of previous estimates | (3,950 | ) | (18,441 | ) | (879 | ) | (47,421 | ) | ||||||||
End of year (1) | 39,149 | 607,139 | 28,846 | 1,015,105 | ||||||||||||
Proved developed reserves: | ||||||||||||||||
Beginning of year | 24,515 | 376,932 | 15,947 | 619,704 | ||||||||||||
End of year | 22,265 | 387,548 | 15,959 | 616,893 | ||||||||||||
Proved undeveloped reserves: | ||||||||||||||||
Beginning of year | 14,574 | 227,508 | 13,405 | 395,391 | ||||||||||||
End of year | 16,884 | 219,591 | 12,887 | 398,212 | ||||||||||||
(1) MRD Segment’s share of these reserves is 89,837 MMcfe. | ||||||||||||||||
For the Year Ended December 31, 2012 | ||||||||||||||||
Oil | Gas | NGLs | Equivalent | |||||||||||||
(MBbls) | (MMcf) | (MBbls) | (MMcfe) | |||||||||||||
Proved developed and undeveloped reserves: | ||||||||||||||||
Beginning of the year | 27,150 | 579,751 | 15,045 | 832,913 | ||||||||||||
Extensions and discoveries | 7,501 | 19,869 | 1,053 | 71,192 | ||||||||||||
Purchase of minerals in place | 11,336 | 113,617 | 7,095 | 224,202 | ||||||||||||
Production | (1,519 | ) | (29,744 | ) | (745 | ) | (43,329 | ) | ||||||||
Sales of minerals in place | (4,214 | ) | (4,214 | ) | — | (29,499 | ) | |||||||||
Revision of previous estimates | (1,165 | ) | (74,839 | ) | 6,904 | (40,384 | ) | |||||||||
End of year (1) | 39,089 | 604,440 | 29,352 | 1,015,095 | ||||||||||||
Proved developed reserves: | ||||||||||||||||
Beginning of year | 19,332 | 413,431 | 10,015 | 589,504 | ||||||||||||
End of year | 24,515 | 376,932 | 15,947 | 619,704 | ||||||||||||
Proved undeveloped reserves: | ||||||||||||||||
Beginning of year | 7,818 | 166,320 | 5,030 | 243,409 | ||||||||||||
End of year | 14,574 | 227,508 | 13,405 | 395,391 | ||||||||||||
(1) MRD Segment’s share of these reserves is 476,550 MMcfe. | ||||||||||||||||
Noteworthy amounts included in the categories of proved reserve changes in the above tables include: | ||||||||||||||||
· | MEMP acquired 561.7 Bcfe in multiple acquisitions during the year ended December 31, 2014, the largest being the Wyoming Acquisition of 497.2 Bcfe. MEMP also acquired 45.0 Bcfe from the Eagle Ford Acquisition. Downward revision of natural gas for the year ended December 31, 2014 was primarily due to updated well performance data in certain East Texas fields. Proved undeveloped reserves increased during the year ended December 31, 2014 primarily due to the Wyoming Acquisition. | |||||||||||||||
· | MEMP acquired 224.2 Bcfe in multiple acquisitions during the year ended December 31, 2012, the largest being the Goodrich Acquisition of 148.9 Bcfe. Stanolind acquired 43.6 Bcfe through multiple acquisitions, the largest being the Menemsha Acquisition of 23.9 Bcfe. During the year ended December 31, 2012, Propel divested 19.0 Bcfe of offshore Louisiana oil and gas properties to an NGP controlled entity. | |||||||||||||||
See Note 3 for additional information on acquisitions and divestitures. | ||||||||||||||||
A variety of methodologies are used to determine our proved reserve estimates. The principal methodologies employed are reservoir simulation, decline curve analysis, volumetric, material balance, advance production type curve matching, petro-physics/log analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all of our fields. | ||||||||||||||||
The standardized measure of discounted future net cash flows is as follows: | ||||||||||||||||
For the Year Ended December 31, | ||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
(In thousands) | ||||||||||||||||
Future cash inflows | $ | 13,191,866 | $ | 6,892,150 | $ | 6,511,776 | ||||||||||
Future production costs | (4,516,077 | ) | (2,719,024 | ) | (2,258,554 | ) | ||||||||||
Future development costs | (1,222,221 | ) | (685,858 | ) | (620,944 | ) | ||||||||||
Future net cash flows for estimated timing of cash flows (1) | 7,453,568 | 3,487,268 | 3,632,278 | |||||||||||||
10% annual discount for estimated timing of cash flows | (4,693,960 | ) | (1,879,156 | ) | (2,042,362 | ) | ||||||||||
Standardized measure of discounted future net cash flows (2) | $ | 2,759,608 | $ | 1,608,112 | $ | 1,589,916 | ||||||||||
-1 | MEMP is subject to the Texas margin tax which has a maximum effective rate of 0.7% of gross income apportioned to Texas. Due to immateriality we have excluded the impact of this tax for the years ended December 31, 2014, 2013 and 2012. | |||||||||||||||
-2 | MRD Segment’s share of the standardized measure of discounted future net cash flows was $2,760, $142,318 and $554,981 for the years ended December 31, 2014, 2013 and 2012, respectively. | |||||||||||||||
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves | ||||||||||||||||
The following is a summary of the changes in the standardized measure of discounted future net cash flows for the proved oil and natural gas reserves during each of the years in the three year period ended December 31, 2014: | ||||||||||||||||
For the Year Ended December 31, | ||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
(In thousands) | ||||||||||||||||
Beginning of year | $ | 1,608,112 | $ | 1,589,916 | $ | 1,499,414 | ||||||||||
Sale of oil and natural gas produced, net of production costs | (323,994 | ) | (234,520 | ) | (160,023 | ) | ||||||||||
Purchase of minerals in place | 1,489,477 | 23,160 | 375,953 | |||||||||||||
Sale of minerals in place | — | — | (154,963 | ) | ||||||||||||
Extensions and discoveries | 44,745 | 136,423 | 265,108 | |||||||||||||
Changes in income taxes, net | — | — | 1,947 | |||||||||||||
Changes in prices and costs | (168,500 | ) | (74,395 | ) | (331,760 | ) | ||||||||||
Previously estimated development costs incurred | 223,861 | 174,490 | 66,360 | |||||||||||||
Net changes in future development costs | (74,579 | ) | (74,867 | ) | (1,140 | ) | ||||||||||
Revisions of previous quantities | (163,207 | ) | (141,122 | ) | (90,587 | ) | ||||||||||
Accretion of discount | 160,811 | 158,991 | 150,136 | |||||||||||||
Change in production rates and other | (37,118 | ) | 50,036 | (30,529 | ) | |||||||||||
End of year | $ | 2,759,608 | $ | 1,608,112 | $ | 1,589,916 | ||||||||||
Subsequent_Events
Subsequent Events | 12 Months Ended |
Dec. 31, 2014 | |
Subsequent Events [Abstract] | |
Subsequent Events | Note 20. Subsequent Events |
Termination of WHR Management Company Service Agreement | |
For additional information, see Note 13. | |
2015 Repurchases of MRD Common Stock and MEMP Common Units | |
For additional information, see Note 9. |
Summary_of_Significant_Account1
Summary of Significant Accounting Policies (Policies) | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Accounting Policies [Abstract] | ||||||||||||
Overview | Overview | |||||||||||
Memorial Resource Development Corp. (the “Company”) is a publicly traded Delaware corporation, the common shares of which are listed on the NASDAQ Global Market (“NASDAQ”) under the symbol “MRD.” Unless the context requires otherwise, references to “we,” “us,” “our,” “MRD,” or “the Company” are intended to mean the business and operations of Memorial Resource Development Corp. and its consolidated subsidiaries. | ||||||||||||
The Company was formed by Memorial Resource Development LLC (“MRD LLC”) in January 2014 to acquire, explore and develop natural gas and oil properties in North America. MRD LLC was a Delaware limited liability company formed on April 27, 2011 by Natural Gas Partners VIII, L.P. (“NGP VIII”), Natural Gas Partners IX, L.P. (“NGP IX”) and NGP IX Offshore Holdings, L.P. (“NGP IX Offshore”) (collectively, the “Funds”) to explore, develop and acquire natural gas and oil properties. The Funds are private equity funds managed by Natural Gas Partners (“NGP”). MRD LLC’s consolidated and combined financial statements represent our predecessor for accounting and financial reporting purposes prior to our initial public offering. | ||||||||||||
Initial Public Offering and Restructuring Transactions | Initial Public Offering and Restructuring Transactions | |||||||||||
On June 18, 2014, the Company completed its initial public offering of 21,500,000 common units at a price of $19.00 per share, which generated net proceeds to the Company of approximately $380.2 million after deducting underwriting discounts and commissions and other offering related fees and expenses. The following restructuring events and transactions occurred in connection with our initial public offering: | ||||||||||||
· | The Funds contributed all of their interests in MRD LLC to MRD Holdco LLC (“MRD Holdco”) and the members of our management who owned incentive units in MRD LLC exchanged those incentive units for substantially identical incentive units in MRD Holdco, after which MRD Holdco owned 100% of MRD LLC; | |||||||||||
· | WildHorse Resources, LLC (“WildHorse Resources”) sold its subsidiary, WildHorse Resources Management Company, LLC (“WHR Management Company”), to an affiliate of the Funds for approximately $0.2 million in cash, and WHR Management Company entered into a services agreement with the Company and WildHorse Resources pursuant to which WHR Management Company agreed to provide certain management services to WildHorse Resources, which was terminated as of March 1, 2015; | |||||||||||
· | Classic Hydrocarbons Holdings, L.P. (“Classic”) and Classic Hydrocarbons GP Co., L.L.C. (“Classic GP”) distributed to MRD LLC the ownership interests in Classic Pipeline & Gathering, LLC (“Classic Pipeline”), which owns certain midstream assets in Texas, and Black Diamond Minerals, LLC (“Black Diamond”) distributed to MRD LLC its ownership interests in Golden Energy Partners LLC (“Golden Energy”), which sold all of its assets in May 2014; | |||||||||||
· | MRD LLC contributed to us substantially all of its assets, comprised of: (i) 100% of the ownership interests in Classic, Classic GP, Black Diamond, Beta Operating Company, LLC (“Beta Operating”), Memorial Resource Finance Corp., MRD Operating LLC (“MRD Operating”), Memorial Production Partners GP LLC (“MEMP GP”) (including MEMP GP’s ownership of 50% of Memorial Production Partners LP’s (“MEMP”) incentive distribution rights) and (ii) 99.9% of the membership interests in WildHorse Resources; | |||||||||||
· | We issued 128,665,677 shares of our common stock to MRD LLC, which MRD LLC immediately distributed to MRD Holdco; | |||||||||||
· | We assumed the obligations of MRD LLC under the indenture governing the $350 million in aggregate principal amount of 10.00% / 10.75% Senior PIK Toggle Notes due 2018 (the “PIK notes”) and reimbursed MRD LLC for the June 15, 2014 interest payment made on the PIK notes; | |||||||||||
· | Certain former management members of WildHorse Resources contributed to us their outstanding incentive units in WildHorse Resources, as well as the remaining 0.1% of the membership interests in WildHorse Resources, and we issued 42,334,323 shares of our common stock and paid cash consideration of $30.0 million to such former management members of WildHorse Resources; | |||||||||||
· | We entered into a registration rights agreement and a voting agreement with MRD Holdco and certain former management members of WildHorse Resources; | |||||||||||
· | We entered into a new $2.0 billion revolving credit facility (see Note 8) and used approximately $614.5 million in borrowings under that facility to repay all amounts outstanding under WildHorse Resources’ credit agreements, to partially fund the cash consideration payable to the former management members of WildHorse Resources and to reimburse MRD LLC for the June 15, 2014 interest payment made on the PIK notes; | |||||||||||
· | Notice of redemption was given to the PIK notes trustee (see Note 8) specifying a redemption date of July 16, 2014 and indicating that a portion of the net proceeds from our initial public offering, which temporarily reduced amounts outstanding under our new revolving credit facility, would be used to redeem the PIK notes at a redemption price of 102% of the principal amount of the PIK notes plus accrued and unpaid interest thereon to the date of redemption; | |||||||||||
· | MRD Operating entered into a merger agreement with MRD LLC pursuant to which after the termination or earlier discharge of the PIK notes MRD LLC would merge into MRD Operating; | |||||||||||
· | MRD LLC distributed to MRD Holdco the following: (i) BlueStone Natural Resources Holdings, LLC (“BlueStone”), which sold substantially all of its assets in July 2013 for $117.9 million, MRD Royalty LLC, which owns certain leasehold interests and overriding royalty interests in Texas and Montana, MRD Midstream LLC, which owns an indirect interest in certain midstream assets in North Louisiana, Golden Energy and Classic Pipeline; (ii) 5,360,912 subordinated units of MEMP; (iii) the right to the remaining cash to be released from the debt service reserve account in connection with the redemption or earlier discharge of the PIK notes plus the cash received from us in reimbursement of the interest paid on June 15, 2014 in respect of the PIK notes; and (iv) approximately $6.7 million of cash received by MRD LLC in connection with the sale of Golden Energy’s assets in May 2014; | |||||||||||
· | We irrevocably deposited with the PIK notes trustee approximately $360.0 million on June 27, 2014, which was an amount sufficient to fund the redemption of the PIK notes on the redemption date and to satisfy and discharge our obligations under the PIK notes and the related indenture. The discharge became effective upon the irrevocable deposit of the funds with the PIK notes trustee; and | |||||||||||
· | MRD LLC merged into MRD Operating. | |||||||||||
Previous Owners | Previous Owners | |||||||||||
References to “the previous owners” for accounting and financial reporting purposes refer collectively to: | ||||||||||||
· | Certain oil and natural gas properties and related assets primarily in the Permian Basin, East Texas and the Rockies that MEMP acquired through equity transactions in October 2013 from certain affiliates of NGP. In October 2013, MEMP acquired Boaz Energy, LLC (“Boaz”), Crown Energy Partners, LLC (“Crown”), the Crown net profits interest and overriding royalty interest (“Crown NPI/ORRI”), Propel Energy SPV LLC (“Propel SPV”), together with its wholly-owned subsidiary Propel Energy Services, LLC (“Propel Energy Services”), and Stanolind Oil and Gas SPV LLC (“Stanolind SPV”) from Boaz Energy Partners, LLC (“Boaz Energy Partners”), Crown Energy Partners Holdings, LLC (“Crown Holdings”), Propel Energy, LLC (“Propel Energy”) and Stanolind Oil and Gas LP (“Stanolind”), all of which are primarily owned by two of the Funds. | |||||||||||
· | A net profits interest that WildHorse Resources purchased from NGP Income Co-Investment Fund II, L.P. (“NGPCIF”) in February 2014 (“NGPCIF NPI”). NGPCIF is controlled by NGP. Upon the completion of the 2010 Petrohawk and Clayton Williams acquisitions, WildHorse Resources sold a net profits interest in these properties to NGPCIF. Since WildHorse Resources sold the net profits interest, the historical results are accounted for as a working interest for all periods. | |||||||||||
Our audited financial statements reported herein include the financial position and results attributable to: (i) those certain oil and natural gas properties and related assets that MEMP acquired through equity transactions in October 2013 from Boaz Energy Partners, Crown Holdings, Propel Energy and Stanolind and (ii) NGPCIF NPI. | ||||||||||||
Basis of Presentation | Basis of Presentation | |||||||||||
The financial statements reported herein include the financial position and results attributable to both our predecessor and the previous owners on a combined basis for periods prior to our initial public offering. For periods after the completion of our public offering, our consolidated financial statements include our accounts and those of our subsidiaries in which we have a controlling interest. Due to our control of MEMP through our ownership of MEMP GP, we are required to consolidate MEMP for accounting and financial reporting purposes. MEMP is owned 99.9% by its limited partners and 0.1% by MEMP GP. | ||||||||||||
All material intercompany transactions and balances have been eliminated in preparation of our consolidated and combined financial statements. The accompanying consolidated and combined financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). | ||||||||||||
We have two reportable business segments, both of which are engaged in the acquisition, exploration, development and production of oil and natural gas properties (See Note 14). Our reportable business segments are as follows: | ||||||||||||
· | MRD—reflects the combined operations of the Company, MRD Operating, MRD LLC, WildHorse Resources and its previous owners, Classic and Classic GP, Black Diamond, BlueStone, Beta Operating and MEMP GP. | |||||||||||
· | MEMP—reflects the combined operations of MEMP, its previous owners, and historical dropdown transactions that occurred between MEMP and other MRD LLC consolidating subsidiaries. | |||||||||||
Segment financial information has been retrospectively revised for the following common control transactions for comparability purposes: | ||||||||||||
· | acquisition by MEMP of all the outstanding membership interests in Tanos Energy, LLC (“Tanos”) from MRD LLC for a purchase price of approximately $77.4 million on October 1, 2013; | |||||||||||
· | acquisition by MEMP of all the outstanding membership interests in Prospect Energy, LLC (“Prospect Energy”) from Black Diamond for a purchase price of approximately $16.3 million on October 1, 2013; | |||||||||||
· | acquisition by MEMP of certain of the oil and natural gas properties in Jackson County, Texas from MRD LLC for a purchase price of approximately $2.6 million on October 1, 2013; | |||||||||||
· | acquisition by MEMP of all the outstanding membership interests in WHT Energy Partners LLC (“WHT”) from WildHorse Resources and Tanos for a purchase price of approximately $200.0 million on March 28, 2013; | |||||||||||
· | acquisition by MEMP of certain assets from Classic in East Texas in May 2012 for a purchase price of approximately $27.0 million; and | |||||||||||
· | acquisition by MEMP of certain assets from Tanos in East Texas in April 2012 for a purchase price of approximately $18.5 million. | |||||||||||
Use of Estimates | Use of Estimates | |||||||||||
The preparation of consolidated and combined financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated and combined financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. | ||||||||||||
Significant estimates include, but are not limited to, oil and natural gas reserves; depreciation, depletion, and amortization of proved oil and natural gas properties; future cash flows from oil and natural gas properties; impairment of long-lived assets; fair value of derivatives; fair value of equity and incentive unit compensation; fair values of assets acquired and liabilities assumed in business combinations and asset retirement obligations. | ||||||||||||
Principles of Consolidation and Combination | Principles of Consolidation and Combination | |||||||||||
Our consolidated financial statements include our accounts and those of our subsidiaries in which we have a controlling interest, after the elimination of all intercompany accounts and transactions. Likewise, the combined financial statements include the accounts of our predecessor and the previous owners as discussed above. All material intercompany balances and transactions have been eliminated. Certain prior period balances have been reclassified to better align with financial statement presentation in the current fiscal year. | ||||||||||||
Cash and Cash Equivalents | Cash and Cash Equivalents | |||||||||||
Cash and cash equivalents represent unrestricted cash on hand and all highly liquid investments with original contractual maturities of three months or less. | ||||||||||||
Book Overdrafts | Book Overdrafts | |||||||||||
Book overdrafts, representing outstanding checks in excess of funds on deposit, are classified as accounts payable and the change in the related balance is reflected in operating activities in the statement of cash flows. | ||||||||||||
Concentrations of Credit Risk | Concentrations of Credit Risk | |||||||||||
Cash balances, accounts receivable, restricted investments and derivative financial instruments are financial instruments potentially subject to credit risk. Cash and cash equivalents are maintained in bank deposit accounts which, at times, may exceed the federally insured limits. Management periodically reviews and assesses the financial condition of the banks to mitigate the risk of loss. Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with MEMP’s offshore Southern California oil and gas properties. These restricted investments may consist of money market deposit accounts, money market mutual funds, commercial paper, and U.S. Government securities, all held with credit-worthy financial institutions. Derivative financial instruments are generally executed with major financial institutions that expose us to market and credit risks and which may, at times, be concentrated with certain counterparties. The credit worthiness of the counterparties is subject to continual review. We rely upon netting arrangements with counterparties to reduce credit exposure. Neither we nor our predecessor and the previous owners have experienced any losses from such instruments. | ||||||||||||
Oil and natural gas are sold to a variety of purchasers, including intrastate and interstate pipelines or their marketing affiliates and independent marketing companies. Accounts receivable from joint operations are from a number of oil and natural gas companies, partnerships, individuals, and others who own interests in the properties operated by us, our predecessor, and the previous owners. Generally, operators of crude oil and natural gas properties have the right to offset future revenues against unpaid charges related to operated wells, minimizing the credit risk associated with these receivables. Additionally, management believes that any credit risk imposed by a concentration in the oil and natural gas industry is mitigated by the creditworthiness of its customer base. An allowance for doubtful accounts is recorded after all reasonable efforts have been exhausted to collect or settle the amount owed. Any amounts outstanding longer than the contractual terms are considered past due. Management determined that an allowance for uncollectible accounts was unnecessary at both December 31, 2014 and 2013, respectively. | ||||||||||||
If we were to lose any one of our customers, the loss could temporarily delay the production and the sale of oil and natural gas in the related producing region. If we were to lose any single customer, we believe that a substitute customer to purchase the impacted production volumes could be identified. | ||||||||||||
Oil and Natural Gas Properties | Oil and Natural Gas Properties | |||||||||||
Oil and natural gas exploration, development and production activities are accounted for in accordance with the successful efforts method of accounting. Under this method, costs of acquiring properties, costs of drilling successful exploration wells, and development costs are capitalized. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if determination is made that proved reserves have been found. If no proved reserves have been found, the costs of each of the related exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. The costs of such exploratory wells are expensed if a determination of proved reserves has not been made within a twelve-month period after drilling is complete. Exploration costs such as geological, geophysical, and seismic costs are expensed as incurred. | ||||||||||||
As exploration and development work progresses and the reserves on these properties are proven, capitalized costs attributed to the properties are subject to depreciation and depletion. Depletion of capitalized costs is provided using the units-of-production method based on proved oil and gas reserves related to the associated field. Capitalized drilling and development costs of producing oil and natural gas properties are depleted over proved developed reserves and leasehold costs are depleted over total proved reserves. | ||||||||||||
On the sale or retirement of a complete or partial unit of a proved property or pipeline and related facilities, the cost and related accumulated depreciation, depletion, and amortization are removed from the property accounts, and any gain or loss is recognized. | ||||||||||||
There were no material capitalized exploratory drilling costs pending evaluation at December 31, 2014, 2013 and 2012. | ||||||||||||
Oil and Gas Reserves | Oil and Gas Reserves | |||||||||||
The estimates of proved oil and natural gas reserves utilized in the preparation of the consolidated and combined financial statements are estimated in accordance with the rules established by the SEC and the Financial Accounting Standards Board (“FASB”). These rules require that reserve estimates be prepared under existing economic and operating conditions using a trailing 12-month average price with no provision for price and cost escalations in future years except by contractual arrangements. Netherland, Sewell & Associates, Inc. (“NSAI”), our independent reserve engineers, was engaged to audit our internally prepared reserves estimates at December 31, 2014. MEMP engaged NSAI and Ryder Scott Company, L.P. to audit MEMP’s internally prepared reserves estimates for all of MEMP’s proved reserves (by volume) at December 31, 2014. | ||||||||||||
Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties, or any combination of the above may be increased or decreased. Increases in recoverable economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates. | ||||||||||||
Other Property & Equipment | Other Property & Equipment | |||||||||||
Other property and equipment is stated at historical cost and is comprised primarily of vehicles, furniture, fixtures, office build-out cost and computer hardware and software. Depreciation of other property and equipment is calculated using the straight-line method generally based on estimated useful lives of three to seven years. | ||||||||||||
Asset Retirement Obligations | Asset Retirement Obligations | |||||||||||
An asset retirement obligation associated with retiring long-lived assets is recognized as a liability on a discounted basis in the period in which the legal obligation is incurred and becomes determinable, with an equal amount capitalized as an addition to oil and natural gas properties, which is allocated to expense over the useful life of the asset. Generally, oil and gas producing companies incur such a liability upon acquiring or drilling a well. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. Upon settlement of the liability, a gain or loss is recognized in net income (loss) to the extent the actual costs differ from the recorded liability. See Note 6 for further discussion of asset retirement obligations. | ||||||||||||
Impairments | Impairments | |||||||||||
Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate the carrying value of such properties may not be recoverable. This may be due to a downward revision of the reserve estimates, less than expected production, drilling results, higher operating and development costs, or lower commodity prices. The estimated undiscounted future cash flows expected in connection with the property are compared to the carrying value of the property to determine if the carrying amount is recoverable. If the carrying value of the property exceeds its estimated undiscounted future cash flows, the carrying amount of the property is reduced to its estimated fair value using Level 3 inputs. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. Impairment expense for the years ended December 31, 2014, 2013, and 2012 was approximately $432.1 million, $6.6 million, $28.9 million, respectively. See Note 4 for further discussion on impairments. | ||||||||||||
Restricted Investments | Restricted Investments | |||||||||||
Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with MEMP’s offshore Southern California oil and gas properties. These investments are classified as held-to-maturity, and such investments are stated at amortized cost. Interest earned on these investments is included in interest expense – net in the statement of operations. The amortized cost of such investments is adjusted for amortization of premiums and accretion of discounts to maturity. Such amortization and accretion is displayed as a separate line item in the statement of operations. These restricted investments consist of money market deposit accounts, money market mutual funds, commercial paper, and U.S. Government securities. See Note 7 for additional information. | ||||||||||||
Debt Issuance Costs | Debt Issuance Costs | |||||||||||
These costs are recorded on the balance sheet and amortized over the term of the associated debt using the straight-line method which generally approximates the effective yield method. Amortization expense, including write-off of debt issuance costs, for the years ended December 31, 2014, 2013, and 2012 was approximately $7.4 million, $8.3 million and $3.6 million, respectively. | ||||||||||||
Revenue Recognition | Revenue Recognition | |||||||||||
Revenue from the sale of oil and natural gas is recognized when title passes, net of royalties due to third parties. Oil and natural gas revenues are recorded using the sales method. Under this method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers, regardless of whether the sales are proportionate to our ownership in the property. An asset or a liability is recognized to the extent there is an imbalance in excess of the proportionate share of the remaining recoverable reserves on the underlying properties. No significant imbalances existed at December 31, 2014 or 2013. | ||||||||||||
The following individual customers each accounted for 10% or more of total reported revenues for the period indicated: | ||||||||||||
Years Ending December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Consolidated & Combined: | ||||||||||||
Energy Transfer Equity, L.P. and subsidiaries | 33 | % | 35 | % | 13 | % | ||||||
MRD Segment: | ||||||||||||
Energy Transfer Equity, L.P. and subsidiaries | 73 | % | 77 | % | 39 | % | ||||||
Sunoco, Inc. (1) | n/a | n/a | 15 | % | ||||||||
Dominion Gas Ventures LP | n/a | n/a | 15 | % | ||||||||
MEMP Segment: | ||||||||||||
Sinclair Oil & Gas Company | 12 | % | n/a | n/a | ||||||||
Phillips 66 (2) | 13 | % | 15 | % | 13 | % | ||||||
ConocoPhillips | n/a | n/a | 14 | % | ||||||||
-1 | Sunoco, Inc. became a subsidiary of Energy Transfer Equity, L.P. in October 2012. | |||||||||||
-2 | Phillips 66 was a subsidiary of ConocoPhillips through April 30, 2012. Accordingly, any revenues generated from Phillips 66 prior to May 1, 2012 were reported under ConocoPhillips. | |||||||||||
Derivative Instruments | Derivative Instruments | |||||||||||
Commodity derivative financial instruments (e.g., swaps, collars, and put options) are used to reduce the impact of natural gas, NGL and oil price fluctuations. Interest rate swaps are used to manage exposure to interest rate volatility, primarily as a result of variable rate borrowings under the credit facilities. Every derivative instrument is recorded on the balance sheet as either an asset or liability measured at its fair value. Changes in the derivative’s fair value are recognized in earnings as we have not elected hedge accounting for any of our derivative positions. | ||||||||||||
Capitalized Interest | Capitalized Interest | |||||||||||
We capitalize interest costs to oil and gas properties on expenditures made in connection with certain projects such as drilling and completion of new oil and natural gas wells and major facility installations. Interest is capitalized only for the period that such activities are in progress. Interest is capitalized using a weighted average interest rate based on our outstanding borrowings. These capitalized costs are included within intangible drilling costs and amortized using the units of production method. For the year ended December 31, 2014, we capitalized $7.3 million of interest. We did not capitalize any interest in 2013 or 2012. | ||||||||||||
Income Tax | Income Tax | |||||||||||
Prior to our initial public offering, MRD LLC was organized as a pass-through entity for federal income tax purposes and was not subject to federal income taxes; however, certain of its consolidating subsidiaries were taxed as corporations and subject to federal income taxes. We are organized as a taxable C corporation and subject to federal and certain state income taxes. We are also subject to the Texas margin tax and certain aspects of the tax make it similar to an income tax. | ||||||||||||
The Company accounts for income taxes using the asset and liability method wherein deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which temporary differences are expected to be recovered or settled. Deferred tax assets are reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of the deferred tax assets will not be realized. | ||||||||||||
We must recognize the tax effects of any uncertain tax positions we may adopt, if the position taken by us is more likely than not sustainable based on its technical merits. If a tax position meets such criteria, the tax effect that would be recognized by us would be the largest amount of benefit with more than 50% chance of being realized. | ||||||||||||
The evaluation of uncertain tax positions is a two-step process. The first step is a recognition process to determine whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. In evaluating whether a tax position has met the more likely than not recognition threshold, it is presumed that the position will be examined by the appropriate taxing authority with full knowledge of all relevant information. The second step is a measurement process whereby a tax position that meets the more likely than not recognition threshold is calculated to determine the amount of benefit/expense to recognize in the consolidated financial statements. The tax position is measured at the largest amount of benefit/expense that is more likely than not of being realized upon ultimate settlement. | ||||||||||||
The Company has no liability for unrecognized tax benefits as of December 31, 2014 and 2013. Accordingly, there is no amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate and there is no amount of interest or penalties currently recognized in the consolidated statements of operations or consolidated balance sheets as of December 31, 2014. In addition, the Company does not believe that there are any positions for which it is reasonably possible that the total amount of unrecognized tax benefits will significantly increase or decrease within the next twelve months. | ||||||||||||
In June 2014, we recorded a deferred tax liability of approximately $43.3 million in stockholders’ equity in connection with our initial public offering and the related restructuring transactions. The tax bases of our assets and liabilities changed as a result our initial public offering and the related restructuring transactions, which represented a transaction among stockholders. | ||||||||||||
Tax audits may be ongoing at any point in time. Tax liabilities are recorded based on estimates of additional taxes which may be due upon the conclusion of these audits. Estimates of these tax liabilities are made based upon prior experience and are updated for changes in facts and circumstances. However, due to the uncertain and complex application of tax regulations, it is possible that the ultimate resolution of audits may result in liabilities which could be materially different from these estimates. See Note 15 for additional information. | ||||||||||||
Earnings Per Share | Earnings Per Share | |||||||||||
Basic earnings per share (“EPS”) is computed using the two-class method based on net income (loss) available to common stockholders and the average number of shares of common stock outstanding for the period. Diluted EPS includes the impact of the Company’s restricted shares of common stock as they are participating securities. The Company determines the more dilutive of either the two-class method or the treasury stock method for diluted EPS. See Note 10 for additional information. | ||||||||||||
Incentive Based Compensation Arrangements | Incentive Based Compensation Arrangements | |||||||||||
The fair value of equity-classified awards (e.g., restricted stock awards) is amortized to earnings over the requisite service or vesting period. Compensation expense for liability-classified awards are recognized over the requisite service or vesting period of an award based on the fair value of the award re-measured at each reporting period. Generally, no compensation expense is recognized for equity instruments that do not vest. | ||||||||||||
Prior to the restructuring transactions, the governing documents of MRD LLC and certain of its subsidiaries provided for the issuance of incentive units. The incentive units were subject to performance conditions that affected their vesting. Compensation cost was recognized only if the performance condition was probable of being satisfied at each reporting date. | ||||||||||||
In connection with the restructuring transactions, the MRD LLC incentive units were exchanged for substantially identical units in MRD Holdco, and such incentive units entitle holders thereof to portions of future distributions by MRD Holdco. While any such distributions made by MRD Holdco will not involve any cash payment by us, we will be required to recognize non-cash compensation expense, which may be material, in future periods. The compensation expense recognized by us related to the incentive units will be offset by a deemed capital contribution from MRD Holdco as they are remeasured at the end of each reporting period. | ||||||||||||
See Notes 11 and 12 for further information. | ||||||||||||
Accrued Liabilities | Accrued Liabilities | |||||||||||
Current accrued liabilities consisted of the following at the dates indicated (in thousands): | ||||||||||||
December 31, | ||||||||||||
2014 | 2013 | |||||||||||
Accrued capital expenditures | $ | 80,350 | $ | 48,579 | ||||||||
Accrued lease operating expense | 16,403 | 13,240 | ||||||||||
Accrued general and administrative expenses | 8,516 | 14,485 | ||||||||||
Accrued ad valorem and production taxes | 8,870 | 3,541 | ||||||||||
Accrued interest payable | 24,797 | 11,934 | ||||||||||
Accrued environmental | 2,092 | 577 | ||||||||||
Accrued current deferred income taxes | 51,929 | 382 | ||||||||||
Other miscellaneous, including operator advances | 6,043 | 5,392 | ||||||||||
$ | 199,000 | $ | 98,130 | |||||||||
Supplemental Cash Flow Information | Supplemental Cash Flow Information | |||||||||||
Supplemental cash flow for the periods presented (in thousands): | ||||||||||||
For Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Supplemental cash flows: | ||||||||||||
Cash paid for interest, net of amounts capitalized | $ | 130,732 | $ | 61,140 | $ | 23,525 | ||||||
Income tax paid | 838 | 168 | 22 | |||||||||
Noncash investing and financing activities: | ||||||||||||
Change in capital expenditures in payables and accrued liabilities | 31,771 | 41,017 | 17,158 | |||||||||
Assumptions of asset retirement obligations related to properties acquired or drilled | 5,420 | 4,227 | 7,962 | |||||||||
Contribution of oil and gas properties from NGP affiliate | — | — | 6,893 | |||||||||
Accrued distribution to NGP affiliates related to Cinco Group acquisitions | — | 4,352 | — | |||||||||
Contribution related to sale of assets to NGP affiliate - restricted cash | — | — | 2,013 | |||||||||
Accrued equity offering costs | — | — | 171 | |||||||||
Distributions to noncontrolling interests | — | — | 47 | |||||||||
Repurchase of equity under repurchase program | 3,425 | — | — | |||||||||
Accounts receivable related to acquisitions | 9,569 | — | — | |||||||||
New Accounting Pronouncements | ERROR: Could not retrieve Word content for note block |
Summary_of_Significant_Account2
Summary of Significant Accounting Policies (Tables) | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Accounting Policies [Abstract] | ||||||||||||
Individual Customers Each Accounted for 10% or More of Total Reported Revenues | The following individual customers each accounted for 10% or more of total reported revenues for the period indicated: | |||||||||||
Years Ending December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Consolidated & Combined: | ||||||||||||
Energy Transfer Equity, L.P. and subsidiaries | 33 | % | 35 | % | 13 | % | ||||||
MRD Segment: | ||||||||||||
Energy Transfer Equity, L.P. and subsidiaries | 73 | % | 77 | % | 39 | % | ||||||
Sunoco, Inc. (1) | n/a | n/a | 15 | % | ||||||||
Dominion Gas Ventures LP | n/a | n/a | 15 | % | ||||||||
MEMP Segment: | ||||||||||||
Sinclair Oil & Gas Company | 12 | % | n/a | n/a | ||||||||
Phillips 66 (2) | 13 | % | 15 | % | 13 | % | ||||||
ConocoPhillips | n/a | n/a | 14 | % | ||||||||
-1 | Sunoco, Inc. became a subsidiary of Energy Transfer Equity, L.P. in October 2012. | |||||||||||
-2 | Phillips 66 was a subsidiary of ConocoPhillips through April 30, 2012. Accordingly, any revenues generated from Phillips 66 prior to May 1, 2012 were reported under ConocoPhillips. | |||||||||||
Schedule of Accrued Liabilities | Current accrued liabilities consisted of the following at the dates indicated (in thousands): | |||||||||||
December 31, | ||||||||||||
2014 | 2013 | |||||||||||
Accrued capital expenditures | $ | 80,350 | $ | 48,579 | ||||||||
Accrued lease operating expense | 16,403 | 13,240 | ||||||||||
Accrued general and administrative expenses | 8,516 | 14,485 | ||||||||||
Accrued ad valorem and production taxes | 8,870 | 3,541 | ||||||||||
Accrued interest payable | 24,797 | 11,934 | ||||||||||
Accrued environmental | 2,092 | 577 | ||||||||||
Accrued current deferred income taxes | 51,929 | 382 | ||||||||||
Other miscellaneous, including operator advances | 6,043 | 5,392 | ||||||||||
$ | 199,000 | $ | 98,130 | |||||||||
Schedule of Supplemental Cash flow | Supplemental cash flow for the periods presented (in thousands): | |||||||||||
For Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Supplemental cash flows: | ||||||||||||
Cash paid for interest, net of amounts capitalized | $ | 130,732 | $ | 61,140 | $ | 23,525 | ||||||
Income tax paid | 838 | 168 | 22 | |||||||||
Noncash investing and financing activities: | ||||||||||||
Change in capital expenditures in payables and accrued liabilities | 31,771 | 41,017 | 17,158 | |||||||||
Assumptions of asset retirement obligations related to properties acquired or drilled | 5,420 | 4,227 | 7,962 | |||||||||
Contribution of oil and gas properties from NGP affiliate | — | — | 6,893 | |||||||||
Accrued distribution to NGP affiliates related to Cinco Group acquisitions | — | 4,352 | — | |||||||||
Contribution related to sale of assets to NGP affiliate - restricted cash | — | — | 2,013 | |||||||||
Accrued equity offering costs | — | — | 171 | |||||||||
Distributions to noncontrolling interests | — | — | 47 | |||||||||
Repurchase of equity under repurchase program | 3,425 | — | — | |||||||||
Accounts receivable related to acquisitions | 9,569 | — | — | |||||||||
Acquisitions_and_Divestitures_
Acquisitions and Divestitures (Tables) | 12 Months Ended | |||||||||||||||
Dec. 31, 2014 | ||||||||||||||||
Acquisition-Related Costs | Acquisition-related costs for both related party and third party transactions are included in general and administrative expenses in the accompanying statements of operations for the periods indicated below (in thousands): | |||||||||||||||
For the Year Ended December 31, | ||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
$ | 6,668 | $ | 8,313 | $ | 4,538 | |||||||||||
Unaudited Pro Forma Results of Operations | The following unaudited pro forma combined results of operations are provided for the year ended December 31, 2014 and 2013 as though the Wyoming Acquisition had been completed on January 1, 2013. The unaudited pro forma financial information was derived from the historical combined statements of operations of the Company and the previous owners and adjusted to include: (i) the revenues and direct operating expenses associated with oil and gas properties acquired, (ii) depletion expense applied to the adjusted basis of the properties acquired and (iii) interest expense on additional borrowings necessary to finance the acquisition. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of expected future results of operations. | |||||||||||||||
For the Year Ended December 31, | ||||||||||||||||
2014 | 2013 | |||||||||||||||
(In thousands, except per share amounts) | ||||||||||||||||
Revenues | $ | 990,544 | $ | 761,443 | ||||||||||||
Net income (loss) | (602,044 | ) | 257,839 | |||||||||||||
Basic earnings per share | $ | (4.08 | ) | $ | — | |||||||||||
Diluted earnings per share | $ | (4.08 | ) | $ | — | |||||||||||
Eagle Ford and Wyoming Acquisition [Member] | ||||||||||||||||
Summary of Fair Value Assessment of Assets Acquired and Liabilities Assumed | The following table summarizes the fair value assessment of the assets acquired and liabilities assumed as of the acquisition dates (in thousands): | |||||||||||||||
MRD | MEMP | MEMP | ||||||||||||||
Louisiana | Eagle Ford | Wyoming | ||||||||||||||
Acquisition | Acquisition | Acquisition | ||||||||||||||
Oil and gas properties | $ | 72,141 | $ | 168,606 | $ | 930,168 | ||||||||||
Asset retirement obligations | (271 | ) | (285 | ) | (3,980 | ) | ||||||||||
Revenue Payable | — | — | (375 | ) | ||||||||||||
Accrued liabilities | — | (250 | ) | (19,693 | ) | |||||||||||
Total identifiable net assets | $ | 71,870 | $ | 168,071 | $ | 906,120 | ||||||||||
2013 Acquisitions [Member] | ||||||||||||||||
Summary of Fair Value Assessment of Assets Acquired and Liabilities Assumed | Louisiana | East Texas | Rockies | |||||||||||||
Acquisition | Acquisition | Acquisition | ||||||||||||||
Oil and gas properties | $ | 68,887 | $ | 9,974 | $ | 20,744 | ||||||||||
Asset retirement obligation | (1,789 | ) | (78 | ) | (1,163 | ) | ||||||||||
Accrued liabilities | - | - | (118 | ) | ||||||||||||
Total identifiable net assets | $ | 67,098 | $ | 9,896 | $ | 19,463 | ||||||||||
2012 Acquisitions [Member] | ||||||||||||||||
Summary of Fair Value Assessment of Assets Acquired and Liabilities Assumed | The following table summarizes the fair value of the assets acquired and liabilities assumed as of each acquisition date (in thousands). | |||||||||||||||
Undisclosed Seller | Goodrich | Menemsha | Other | |||||||||||||
Acquisition | Acquisition | Acquisition | Acquisitions | |||||||||||||
Oil and gas properties | $ | 115,633 | $ | 91,187 | $ | 75,114 | $ | 77,764 | ||||||||
Prepaid expenses and other current assets | — | 425 | — | — | ||||||||||||
Revenues payable | (1,602 | ) | (875 | ) | — | — | ||||||||||
Asset retirement obligation | (1,592 | ) | (161 | ) | (408 | ) | (4,558 | ) | ||||||||
Accrued liabilities | (297 | ) | (153 | ) | — | — | ||||||||||
Total identifiable net assets | $ | 112,142 | $ | 90,423 | $ | 74,706 | $ | 73,206 | ||||||||
Unaudited Pro Forma Results of Operations | The following unaudited pro forma combined results of operations are provided for the year ended December 31, 2012 (in thousands) as though the Undisclosed Seller Acquisition, Goodrich Acquisition, and Menemsha Acquisition had been completed on January 1, 2011. The unaudited pro forma financial information was derived from our historical combined statements of operations and adjusted to include: (i) the revenues and direct operating expenses associated with oil and gas properties acquired, (ii) depletion expense applied to the adjusted basis of the properties acquired and (iii) interest expense on additional borrowings necessary to finance the acquisitions. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transactions occurred on the basis assumed above, nor is such information indicative of expected future results of operations. | |||||||||||||||
Revenue | $ | 431,060 | ||||||||||||||
Net income | 40,940 | |||||||||||||||
Fair_Value_Measurements_of_Fin1
Fair Value Measurements of Financial Instruments (Tables) | 12 Months Ended | |||||||||||||||
Dec. 31, 2014 | ||||||||||||||||
Fair Value Disclosures [Abstract] | ||||||||||||||||
Assets and Liabilities Measured at Fair Value on Recurring Basis | The following table presents the derivative assets and liabilities that are measured at fair value on a recurring basis at December 31, 2014 and December 31, 2013 for each of the fair value hierarchy levels: | |||||||||||||||
Fair Value Measurements at December 31, 2014 Using | ||||||||||||||||
Quoted Prices in | Significant Other | Significant | ||||||||||||||
Active | Observable | Unobservable | ||||||||||||||
Market | Inputs | Inputs | ||||||||||||||
(Level 1) | (Level 2) | (Level 3) | Fair Value | |||||||||||||
(In thousands) | ||||||||||||||||
Assets: | ||||||||||||||||
Commodity derivatives | $ | — | $ | 845,759 | $ | — | $ | 845,759 | ||||||||
Interest rate derivatives | — | 1,305 | — | 1,305 | ||||||||||||
Total assets | $ | — | $ | 847,064 | $ | — | $ | 847,064 | ||||||||
Liabilities: | ||||||||||||||||
Commodity derivatives | $ | — | $ | 71,639 | $ | — | $ | 71,639 | ||||||||
Interest rate derivatives | — | 3,289 | — | 3,289 | ||||||||||||
Total liabilities | $ | — | $ | 74,928 | $ | — | $ | 74,928 | ||||||||
Fair Value Measurements at December 31, 2013 Using | ||||||||||||||||
Quoted Prices in | Significant Other | Significant | ||||||||||||||
Active | Observable | Unobservable | ||||||||||||||
Market | Inputs | Inputs | ||||||||||||||
(Level 1) | (Level 2) | (Level 3) | Fair Value | |||||||||||||
(In thousands) | ||||||||||||||||
Assets: | ||||||||||||||||
Commodity derivatives | $ | — | $ | 105,054 | $ | — | $ | 105,054 | ||||||||
Interest rate derivatives | — | 884 | — | 884 | ||||||||||||
Total assets | $ | — | $ | 105,938 | $ | — | $ | 105,938 | ||||||||
Liabilities: | ||||||||||||||||
Commodity derivatives | $ | — | $ | 58,234 | $ | — | $ | 58,234 | ||||||||
Interest rate derivatives | — | 5,590 | — | 5,590 | ||||||||||||
Total liabilities | $ | — | $ | 63,824 | $ | — | $ | 63,824 | ||||||||
Risk_Management_and_Derivative1
Risk Management and Derivative Instruments (Tables) | 12 Months Ended | |||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||
Derivative Instruments And Hedging Activities Disclosure [Abstract] | ||||||||||||||||||||
Schedule of Open Commodity Positions | At December 31, 2014, the MRD Segment had the following open commodity positions: | |||||||||||||||||||
2015 | 2016 | 2017 | 2018 | |||||||||||||||||
Natural Gas Derivative Contracts: | ||||||||||||||||||||
Fixed price swap contracts: | ||||||||||||||||||||
Average Monthly Volume (MMBtu) | 3,700,000 | 2,570,000 | 1,770,000 | 2,900,000 | ||||||||||||||||
Weighted-average fixed price | $ | 4.15 | $ | 4.09 | $ | 4.24 | $ | 4.27 | ||||||||||||
Collar contracts: | ||||||||||||||||||||
Average Monthly Volume (MMBtu) | 130,000 | 1,100,000 | 1,050,000 | — | ||||||||||||||||
Weighted-average floor price | $ | 4 | $ | 4 | $ | 4 | $ | — | ||||||||||||
Weighted-average ceiling price | $ | 4.64 | $ | 4.71 | $ | 5.06 | $ | — | ||||||||||||
Natural gas put option contracts: | ||||||||||||||||||||
Average Monthly Volume (MMBtu) | 3,000,000 | 4,100,000 | 3,450,000 | 2,850,000 | ||||||||||||||||
Weighted-average fixed price | $ | 3.75 | $ | 3.75 | $ | 3.75 | $ | 3.75 | ||||||||||||
Weighted-average deferred premium | $ | (0.33 | ) | $ | (0.36 | ) | $ | (0.35 | ) | $ | (0.35 | ) | ||||||||
TGT Z1 basis swaps: | ||||||||||||||||||||
Average Monthly Volume (MMBtu) | 1,730,000 | 220,000 | 200,000 | — | ||||||||||||||||
Spread - Henry Hub | $ | (0.09 | ) | $ | (0.08 | ) | $ | (0.08 | ) | $ | — | |||||||||
Crude Oil Derivative Contracts: | ||||||||||||||||||||
Fixed price swap contracts: | ||||||||||||||||||||
Average Monthly Volume (Bbls) | 46,500 | 8,500 | 28,000 | 31,625 | ||||||||||||||||
Weighted-average fixed price | $ | 91.67 | $ | 84.8 | $ | 84.7 | $ | 84.5 | ||||||||||||
Collar contracts: | ||||||||||||||||||||
Average Monthly Volume (Bbls) | 2,000 | 27,000 | — | — | ||||||||||||||||
Weighted-average floor price | $ | 85 | $ | 80 | $ | — | $ | — | ||||||||||||
Weighted-average ceiling price | $ | 101.35 | $ | 99.7 | $ | — | $ | — | ||||||||||||
Put option contracts: | ||||||||||||||||||||
Average Monthly Volume (Bbls) | 26,000 | — | — | — | ||||||||||||||||
Weighted-average fixed price | $ | 85 | $ | — | $ | — | $ | — | ||||||||||||
Weighted-average deferred premium | $ | (3.80 | ) | $ | — | $ | — | $ | — | |||||||||||
NGL Derivative Contracts: | ||||||||||||||||||||
Fixed price swap contracts: | ||||||||||||||||||||
Average Monthly Volume (Bbls) | 151,000 | 185,658 | — | — | ||||||||||||||||
Weighted-average fixed price | $ | 41.61 | $ | 34.06 | $ | — | $ | — | ||||||||||||
At December 31, 2014, the MEMP Segment had the following open commodity positions: | ||||||||||||||||||||
2015 | 2016 | 2017 | 2018 | 2019 | ||||||||||||||||
Natural Gas Derivative Contracts: | ||||||||||||||||||||
Fixed price swap contracts: | ||||||||||||||||||||
Average Monthly Volume (MMBtu) | 2,605,278 | 2,692,442 | 2,450,067 | 2,160,000 | 1,914,583 | |||||||||||||||
Weighted-average fixed price | $ | 4.28 | $ | 4.4 | $ | 4.31 | $ | 4.51 | $ | 4.75 | ||||||||||
Collar contracts: | ||||||||||||||||||||
Average Monthly Volume (MMBtu) | 350,000 | — | — | — | — | |||||||||||||||
Weighted-average floor price | $ | 4.62 | $ | — | $ | — | $ | — | $ | — | ||||||||||
Weighted-average ceiling price | $ | 5.8 | $ | — | $ | — | $ | — | $ | — | ||||||||||
Call spreads (1): | ||||||||||||||||||||
Average Monthly Volume (MMBtu) | 80,000 | — | — | — | — | |||||||||||||||
Weighted-average sold strike price | $ | 5.25 | $ | — | $ | — | $ | — | $ | — | ||||||||||
Weighted-average bought strike price | $ | 6.75 | $ | — | $ | — | $ | — | $ | — | ||||||||||
Basis swaps: | ||||||||||||||||||||
Average Monthly Volume (MMBtu) | 2,940,000 | 2,508,333 | 415,000 | 115,000 | — | |||||||||||||||
Spread | $ | (0.12 | ) | $ | (0.04 | ) | $ | 0 | $ | 0.15 | $ | — | ||||||||
Crude Oil Derivative Contracts: | ||||||||||||||||||||
Fixed price swap contracts: | ||||||||||||||||||||
Average Monthly Volume (Bbls) | 314,281 | 332,813 | 326,600 | 312,000 | 160,000 | |||||||||||||||
Weighted-average fixed price | $ | 90.96 | $ | 85.83 | $ | 84.38 | $ | 83.74 | $ | 85.52 | ||||||||||
Collar contracts: | ||||||||||||||||||||
Average Monthly Volume (Bbls) | 5,000 | — | — | — | — | |||||||||||||||
Weighted-average floor price | $ | 80 | $ | — | $ | — | $ | — | $ | — | ||||||||||
Weighted-average ceiling price | $ | 94 | $ | — | $ | — | $ | — | $ | — | ||||||||||
Basis swaps: | ||||||||||||||||||||
Average Monthly Volume (Bbls) | 97,500 | 95,000 | — | — | — | |||||||||||||||
Spread | $ | (7.07 | ) | $ | (9.56 | ) | $ | — | $ | — | $ | — | ||||||||
NGL Derivative Contracts: | ||||||||||||||||||||
Fixed price swap contracts: | ||||||||||||||||||||
Average Monthly Volume (Bbls) | 149,200 | 84,600 | — | — | — | |||||||||||||||
Weighted-average fixed price | $ | 43.02 | $ | 41.49 | $ | — | $ | — | $ | — | ||||||||||
(1) These transactions were entered into for the purpose of eliminating the ceiling portion of certain collar arrangements, which effectively converted the applicable collars into swaps. | ||||||||||||||||||||
The MEMP Segment basis swaps included in the table above is presented on a disaggregated basis below: | ||||||||||||||||||||
2015 | 2016 | 2017 | 2018 | |||||||||||||||||
Natural Gas Derivative Contracts: | ||||||||||||||||||||
NGPL TexOk basis swaps: | ||||||||||||||||||||
Average Monthly Volume (MMBtu) | 2,280,000 | 2,103,333 | 300,000 | — | ||||||||||||||||
Spread - Henry Hub | $ | (0.11 | ) | $ | (0.06 | ) | $ | (0.05 | ) | $ | — | |||||||||
HSC basis swaps: | ||||||||||||||||||||
Average Monthly Volume (MMBtu) | 150,000 | 135,000 | 115,000 | 115,000 | ||||||||||||||||
Spread - Henry Hub | $ | (0.08 | ) | $ | 0.07 | $ | 0.14 | $ | 0.15 | |||||||||||
CIG basis swaps: | ||||||||||||||||||||
Average Monthly Volume (MMBtu) | 210,000 | — | — | — | ||||||||||||||||
Spread - Henry Hub | $ | (0.25 | ) | $ | — | $ | — | $ | — | |||||||||||
TETCO STX basis swaps: | ||||||||||||||||||||
Average Monthly Volume (MMBtu) | 300,000 | 270,000 | — | — | ||||||||||||||||
Spread - Henry Hub | $ | (0.09 | ) | $ | 0.06 | $ | — | $ | — | |||||||||||
Crude Oil Derivative Contracts: | ||||||||||||||||||||
Midway-Sunset basis swaps: | ||||||||||||||||||||
Average Monthly Volume (Bbls) | 57,500 | 55,000 | — | — | ||||||||||||||||
Spread - Brent | $ | (9.73 | ) | $ | (13.35 | ) | $ | — | $ | — | ||||||||||
Midland basis swaps: | ||||||||||||||||||||
Average Monthly Volume (Bbls) | 40,000 | 40,000 | — | — | ||||||||||||||||
Spread - WTI | $ | (3.25 | ) | $ | (4.34 | ) | $ | — | $ | — | ||||||||||
Schedule of Entity's Interest Rate Swap Open Positions | At December 31, 2014, we had the following interest rate swap open positions: | |||||||||||||||||||
Credit Facility | 2015 | 2016 | 2017 | |||||||||||||||||
MEMP: | ||||||||||||||||||||
Average Monthly Notional (in thousands) | $ | 314,167 | $ | 250,000 | $ | 250,000 | ||||||||||||||
Weighted-average fixed rate | 1.349 | % | 1.029 | % | 1.62 | % | ||||||||||||||
Floating rate | 1 Month LIBOR | 1 Month LIBOR | 1 Month LIBOR | |||||||||||||||||
Summary of Gross Fair Value and Net Recorded Fair Value of Derivative Instruments by Appropriate Balance Sheet Classification | The following table summarizes both: (i) the gross fair value of derivative instruments by the appropriate balance sheet classification even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the balance sheet and (ii) the net recorded fair value as reflected on the balance sheet at December 31, 2014 and 2013. There was no cash collateral received or pledged associated with our derivative instruments since most of the counterparties, or certain affiliates, to our derivative contracts are lenders under our collective credit agreements. | |||||||||||||||||||
Asset Derivatives | Liability Derivatives | |||||||||||||||||||
Type | Balance Sheet Location | 2014 | 2013 | 2014 | 2013 | |||||||||||||||
(In thousands) | ||||||||||||||||||||
Commodity contracts | Short-term derivative instruments | $ | 378,908 | $ | 21,759 | $ | 38,852 | $ | 19,739 | |||||||||||
Interest rate swaps | Short-term derivative instruments | — | 845 | 3,289 | 3,287 | |||||||||||||||
Gross fair value | 378,908 | 22,604 | 42,141 | 23,026 | ||||||||||||||||
Netting arrangements | Short-term derivative instruments | (38,852 | ) | (13,315 | ) | (38,852 | ) | (13,315 | ) | |||||||||||
Net recorded fair value | Short-term derivative instruments | $ | 340,056 | $ | 9,289 | $ | 3,289 | $ | 9,711 | |||||||||||
Commodity contracts | Long-term derivative instruments | $ | 466,851 | $ | 83,295 | $ | 32,787 | $ | 38,495 | |||||||||||
Interest rate swaps | Long-term derivative instruments | 1,305 | 39 | — | 2,303 | |||||||||||||||
Gross fair value | 468,156 | 83,334 | 32,787 | 40,798 | ||||||||||||||||
Netting arrangements | Long-term derivative instruments | (32,787 | ) | (34,718 | ) | (32,787 | ) | (34,718 | ) | |||||||||||
Net recorded fair value | Long-term derivative instruments | $ | 435,369 | $ | 48,616 | $ | — | $ | 6,080 | |||||||||||
Schedule of Gains and Losses Related to Derivative Instruments | The following table details the gains and losses related to derivative instruments for the years ending December 31, 2014, 2013, and 2012: | |||||||||||||||||||
Statements of | For the Years Ended December 31, | |||||||||||||||||||
Operations Location | 2014 | 2013 | 2012 | |||||||||||||||||
(In thousands) | ||||||||||||||||||||
Commodity derivative contracts | (Gain) loss on commodity derivatives | $ | (749,988 | ) | $ | (29,294 | ) | $ | (34,905 | ) | ||||||||||
Interest rate derivatives | Interest expense, net | 145 | (239 | ) | 5,582 | |||||||||||||||
Asset_Retirement_Obligations_T
Asset Retirement Obligations (Tables) | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Asset Retirement Obligation Disclosure [Abstract] | ||||||||||||
Summary of Changes in Asset Retirement Obligations | The following table presents the changes in the asset retirement obligations for the years ended December 31, 2014, 2013 and 2012: | |||||||||||
2014 | 2013 | 2012 | ||||||||||
(In thousands) | ||||||||||||
Asset retirement obligations at beginning of period | $ | 111,769 | $ | 102,380 | $ | 90,699 | ||||||
Liabilities added from acquisitions or drilling | 5,420 | 4,227 | 7,962 | |||||||||
Liabilities removed upon sale of wells | (669 | ) | (1,765 | ) | (1,931 | ) | ||||||
Liabilities removed upon plugging and abandoning | (588 | ) | (170 | ) | (119 | ) | ||||||
Revisions | 293 | 1,516 | 760 | |||||||||
Accretion expense | 6,306 | 5,581 | 5,009 | |||||||||
Asset retirement obligations at end of period | 122,531 | 111,769 | 102,380 | |||||||||
Less: Current portion | — | 90 | 390 | |||||||||
Asset retirement obligations— long-term portion | $ | 122,531 | $ | 111,679 | $ | 101,990 | ||||||
Restricted_Investments_Tables
Restricted Investments (Tables) | 12 Months Ended | |||||||
Dec. 31, 2014 | ||||||||
Schedule Of Investments [Abstract] | ||||||||
Restricted Investment Balance | The components of the restricted investment balance are as follows at December 31, 2014 and 2013: | |||||||
2014 | 2013 | |||||||
(In thousands) | ||||||||
BOEM platform abandonment (See Note 16) | $ | 69,954 | $ | 66,373 | ||||
BOEM lease bonds | 794 | 794 | ||||||
SPBPC Collateral: | ||||||||
Contractual pipeline and surface facilities abandonment | 2,701 | 2,306 | ||||||
California State Lands Commission pipeline right-of-way bond | 3,005 | 3,005 | ||||||
City of Long Beach pipeline facility permit | 500 | 500 | ||||||
Federal pipeline right-of-way bond | 307 | 307 | ||||||
Port of Long Beach pipeline license | 100 | 100 | ||||||
Restricted investments | $ | 77,361 | $ | 73,385 | ||||
Long_Term_Debt_Tables
Long Term Debt (Tables) | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Debt Disclosure [Abstract] | ||||||||||||
Consolidated Debt Obligations | The following table presents our consolidated debt obligations at the dates indicated. The MEMP Segment debt included in the table below is nonrecourse to the Company. | |||||||||||
December 31, | December 31, | |||||||||||
2014 | 2013 | |||||||||||
(In thousands) | ||||||||||||
MRD Segment: | ||||||||||||
MRD $2.0 billion revolving credit facility, variable-rate, due June 2019 | $ | 183,000 | $ | — | ||||||||
WildHorse Resources $1.0 billion revolving credit facility, variable-rate, terminated June 2014 | — | 203,100 | ||||||||||
WildHorse Resources $325.0 million second lien term facility, variable-rate, terminated June 2014 | — | 325,000 | ||||||||||
10.00%/10.75% senior PIK toggle notes redeemed June 2014 | — | 350,000 | ||||||||||
5.875% senior unsecured notes, due July 2022 (1) | 600,000 | — | ||||||||||
10.00%/10.75% senior PIK toggle notes unamortized discounts | — | (6,950 | ) | |||||||||
Subtotal | 783,000 | 871,150 | ||||||||||
MEMP Segment: | ||||||||||||
MEMP $2.0 billion revolving credit facility, variable-rate, due March 2018 | 412,000 | 103,000 | ||||||||||
7.625% senior notes, fixed-rate, due May 2021 (2) | 700,000 | 700,000 | ||||||||||
6.875% senior unsecured notes, due August 2022 (3) | 500,000 | — | ||||||||||
Unamortized discounts | (16,587 | ) | (10,933 | ) | ||||||||
Subtotal | 1,595,413 | 792,067 | ||||||||||
Total long-term debt | $ | 2,378,413 | $ | 1,663,217 | ||||||||
(1)The estimated fair value of this fixed-rate debt was $534.0 million at December 31, 2014. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. | ||||||||||||
(2)The estimated fair value of this fixed-rate debt was $563.5 million and $721.0 million at December 31, 2014 and 2013, respectively. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. | ||||||||||||
(3)The estimated fair value of this fixed-rate debt was $380.0 million at December 31, 2014. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. | ||||||||||||
Borrowing Base Credit Facility | The borrowing base for MRD’s and MEMP’s revolving credit facility was the following at the date indicated: | |||||||||||
December 31, | ||||||||||||
2014 | ||||||||||||
MRD Segment: | ||||||||||||
MRD $2.0 billion revolving credit facility, variable-rate, due June 2019 | $ | 725,000 | ||||||||||
MEMP Segment: | ||||||||||||
MEMP $2.0 billion revolving credit facility, variable-rate, due March 2018 | 1,440,000 | |||||||||||
Summary of Weighted-Average Interest Rates Paid On Variable-Rate Debt Obligations | The following table presents the weighted-average interest rates paid on our consolidated and combined variable-rate debt obligations for the periods presented: | |||||||||||
For the Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
MRD Segment: | ||||||||||||
MRD revolving credit facility | 1.99 | % | n/a | n/a | ||||||||
MRD LLC revolver terminated December 2013 | n/a | 3.17 | % | 4.11 | % | |||||||
Classic revolving credit facility terminated November 2012 | n/a | n/a | 4.5 | % | ||||||||
WildHorse Resources revolver terminated June 2014 | 4.04 | % | 2.3 | % | 3 | % | ||||||
WildHorse Resources second lien terminated June 2014 | 6.44 | % | 7.6 | % | n/a | |||||||
Black Diamond terminated November 2013 | n/a | 3.97 | % | 3.62 | % | |||||||
MEMP Segment: | ||||||||||||
MEMP revolving credit facility | 2.67 | % | 3.25 | % | 2.74 | % | ||||||
WHT revolver terminated March 2013 | n/a | 2.29 | % | 2.6 | % | |||||||
Tanos revolver terminated April 2013 | n/a | 3.1 | % | 2.31 | % | |||||||
REO revolving credit facility terminated December 2012 | n/a | n/a | 3.4 | % | ||||||||
Stanolind revolver paid off by MEMP October 2013 | n/a | 3.52 | % | 3.76 | % | |||||||
Boaz revolver terminated October 2013 | n/a | 2.97 | % | 3.12 | % | |||||||
Crown revolver terminated October 2013 | n/a | 3.38 | % | 4.2 | % | |||||||
Propel Energy revolver paid off by MEMP October 2013 | n/a | 3.08 | % | 3.28 | % | |||||||
Summary of Unamortized Deferred Financing Costs Associated with Consolidated Debt Obligations | Unamortized deferred financing costs associated with our consolidated debt obligations were as follows at the dates indicated: | |||||||||||
December 31, | December 31, | |||||||||||
2014 | 2013 | |||||||||||
(In thousands) | ||||||||||||
MRD Segment: | ||||||||||||
MRD revolving credit facility | $ | 4,285 | $ | — | ||||||||
MRD senior notes | 12,455 | — | ||||||||||
WildHorse Resources revolving credit facility | — | 2,436 | ||||||||||
WildHorse Resources second lien term loan | — | 9,030 | ||||||||||
PIK notes | — | 8,261 | ||||||||||
MEMP Segment: | ||||||||||||
MEMP revolving credit facility | 6,468 | 5,413 | ||||||||||
2021 Senior Notes | 13,308 | 15,053 | ||||||||||
2022 Senior Notes | 7,958 | — | ||||||||||
$ | 44,474 | $ | 40,193 | |||||||||
Stockholders_Equity_and_Noncon1
Stockholders' Equity and Noncontrolling Interests (Tables) | 12 Months Ended | |||
Dec. 31, 2014 | ||||
Equity [Abstract] | ||||
Summary of Changes In Common Shares Issued | The Company’s authorized capital stock includes 600,000,000 shares of common stock, $0.01 par value per share. The following is a summary of the changes in our common shares issued for the year ended December 31, 2014: | |||
Balance January 1, 2014 | — | |||
Shares of common stock issued in connection with restructuring transactions (Note 1) | 171,000,000 | |||
Shares of common stock issued in initial public offering (Note 1) | 21,500,000 | |||
Shares of common stock repurchased and retired | (123,797 | ) | ||
Restricted common shares issued (Note 11) | 1,068,422 | |||
Restricted common shares forfeited | (9,211 | ) | ||
Balance December 31, 2014 | 193,435,414 | |||
Earnings_per_Share_Tables
Earnings per Share (Tables) | 12 Months Ended | |||
Dec. 31, 2014 | ||||
Summary of Calculation of Earnings (Loss) Per Share, or EPS | The following sets forth the calculation of earnings (loss) per share, or EPS, for the period indicated (in thousands, except per share amounts): | |||
For the Year Ended December 31, | ||||
2014 | ||||
Numerator: | ||||
Net income (loss) available to common stockholders | $ | (784,581 | ) | |
Denominator: | ||||
Weighted average common shares outstanding | 192,498 | |||
Basic EPS | $ | (4.08 | ) | |
Diluted EPS (1) | $ | (4.08 | ) | |
-1 | The Company determines the more dilutive of either the two-class method or the treasury stock method for diluted EPS. The restricted common shares were antidilutive due to net losses and excluded from the diluted EPS calculation for the year ending December 31, 2014. There were 202,623 incremental shares excluded from the computation of diluted EPS for the year ending December 31, 2014. | |||
Supplemental EPS [Member] | ||||
Summary of Calculation of Earnings (Loss) Per Share, or EPS | The following sets forth the calculation of our supplemental EPS, for the period indicated (in thousands, except per share amounts): | |||
For the Year Ended December 31, | ||||
2014 | ||||
Numerator: | ||||
Net income (loss) attributable to Memorial Resource Development Corp. | $ | (762,851 | ) | |
Denominator: | ||||
Weighted average common shares outstanding | 192,498 | |||
Basic EPS | $ | (3.96 | ) | |
Diluted EPS (1) | $ | (3.96 | ) | |
-1 | The Company determines the more dilutive of either the two-class method or the treasury stock method for diluted EPS. The restricted common shares were antidilutive due to net losses and excluded from the diluted EPS calculation for the year ending December 31, 2014. There were 202,623 incremental shares excluded from the computation of diluted EPS for the year ending December 31, 2014. |
LongTerm_Incentive_Plans_Table
Long-Term Incentive Plans (Tables) | 12 Months Ended | ||||||||||
Dec. 31, 2014 | |||||||||||
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract] | |||||||||||
Summary of Information Regarding Restricted Common Unit Awards | The following table summarizes information regarding restricted common share awards granted under the MRD LTIP for the periods presented: | ||||||||||
Number of Shares | Weighted-Average Grant Date Fair Value per Share (1) | ||||||||||
Restricted common shares outstanding at January 1, 2014 | — | $ | — | ||||||||
Granted (2) | 1,068,422 | $ | 19 | ||||||||
Forfeited | (9,211 | ) | $ | 19 | |||||||
Restricted common units outstanding at December 31, 2014 | 1,059,211 | $ | 19 | ||||||||
-1 | Determined by dividing the aggregate grant date fair value of awards by the number of awards issued. | ||||||||||
-2 | The aggregate grant date fair value of restricted common share awards issued in 2014 was $20.3 million based on grant date market price of $19.00 per share. | ||||||||||
The following table summarizes information regarding restricted common unit awards granted under the MEMP LTIP for the periods presented: | |||||||||||
Number of Units | Weighted-Average Grant Date Fair Value per Unit (1) | ||||||||||
Restricted common units outstanding at December 31, 2011 | — | $ | — | ||||||||
Granted (2) | 287,943 | $ | 18.07 | ||||||||
Forfeited | (2,334 | ) | $ | 17.14 | |||||||
Restricted common units outstanding at December 31, 2012 | 285,609 | $ | 18.08 | ||||||||
Granted (3) | 524,718 | $ | 18.83 | ||||||||
Forfeited | (11,734 | ) | $ | 17.24 | |||||||
Vested | (91,666 | ) | $ | 18.31 | |||||||
Restricted common units outstanding at December 31, 2013 | 706,927 | $ | 18.62 | ||||||||
Granted (4) | 684,954 | $ | 22.39 | ||||||||
Forfeited | (38,294 | ) | $ | 20.54 | |||||||
Vested | (260,067 | ) | $ | 18.56 | |||||||
Restricted common units outstanding at December 31, 2014 | 1,093,520 | $ | 20.93 | ||||||||
· | Determined by dividing the aggregate grant date fair value of awards by the number of awards issued. | ||||||||||
· | The aggregate grant date fair value of restricted common unit awards issued in 2012 was $5.2 million based on grant date market prices ranging from of $17.14 to $18.58 per unit. | ||||||||||
-3 | The aggregate grant date fair value of restricted common unit awards issued in 2013 was $9.9 million based on grant date market prices ranging from of $18.33 to $20.35 per unit. | ||||||||||
-4 | The aggregate grant date fair value of restricted common unit awards issued in 2014 was $15.3 million based on grant date market prices ranging from of $21.99 to $23.40 per unit. | ||||||||||
Summary of Amount of Compensation Expense Recognized | The following table summarizes the amount of recognized compensation expense associated with these awards that are reflected in the accompanying statements of operations for the periods presented (in thousands): | ||||||||||
For the Year Ended December 31, | |||||||||||
2014 | |||||||||||
$ | 2,804 | ||||||||||
The following table summarizes the amount of recognized compensation expense associated with these awards that are reflected in the accompanying statements of operations for the periods presented (in thousands): | |||||||||||
For the Year Ended December 31, | |||||||||||
2014 | 2013 | 2012 | |||||||||
$ | 7,874 | $ | 3,558 | $ | 1,423 | ||||||
Incentive_Units_Tables
Incentive Units (Tables) | 12 Months Ended | |||||||
Dec. 31, 2014 | ||||||||
Compensation Related Costs [Abstract] | ||||||||
Fair Value of Incentive Units Estimated | The fair value of the incentive units was estimated using a Monte Carlo simulation valuation model with the following assumptions: | |||||||
Exchanged Incentive Units | Subsequent Incentive Units | |||||||
Valuation date | 12/31/14 | 12/31/14 | ||||||
Dividend yield | 0 | % | 0 | % | ||||
Expected volatility | 39.54 | % | 39.54 | % | ||||
Risk-free rate | 0.85 | % | 0.85 | % | ||||
Expected life (years) | 2.41 | 2.41 | ||||||
Related_Party_Transactions_Tab
Related Party Transactions (Tables) | 12 Months Ended | |||
Dec. 31, 2014 | ||||
Related Party Transactions [Abstract] | ||||
Schedule of Net Assets Recorded | WildHorse Resources recorded the following net assets (in thousands): | |||
Accounts receivable | $ | 2,274 | ||
Oil and natural gas properties, net | 40,056 | |||
Accrued liabilities | (297 | ) | ||
Asset retirement obligations | (277 | ) | ||
Net assets | $ | 41,756 | ||
MEMP recorded the following net assets (in thousands): | ||||
Cash and cash equivalents | $ | 6,021 | ||
Accounts receivable | 16,284 | |||
Short-term derivative instruments, net | 2,926 | |||
Prepaid expenses and other current assets | 4,521 | |||
Oil and natural gas properties, net | 108,342 | |||
Restricted investments | 68,009 | |||
Accounts payable | (9,092 | ) | ||
Accrued liabilities | (9,140 | ) | ||
Asset retirement obligations | (58,746 | ) | ||
Credit facilities | (28,500 | ) | ||
Deferred tax liability | (1,674 | ) | ||
Noncontrolling interest | (5,255 | ) | ||
Net assets | $ | 93,696 | ||
Book Value of Assets Sold | The Cinco Group acquisition was accounted for as a combination of entities under common control at historical cost in a manner similar to the pooling of interest method. | |||
Cash and cash equivalents | $ | 2,820 | ||
Accounts receivable | 5,184 | |||
Prepaid expenses and other current assets | 1,454 | |||
Oil and natural gas properties, net | 342,759 | |||
Long-term derivative instruments, net | (826 | ) | ||
Other long-term assets | 344 | |||
Accounts payable | (2,346 | ) | ||
Revenue payable | (2,910 | ) | ||
Accrued liabilities | (1,799 | ) | ||
Short-term derivative instruments, net | (1,828 | ) | ||
Asset retirement obligations | (9,606 | ) | ||
Credit facilities | (151,690 | ) | ||
Net assets | $ | 181,556 | ||
The net book value of the assets sold was as follows (in thousands): | ||||
Cash and cash equivalents | $ | 33,001 | ||
Restricted cash | 300 | |||
Accounts receivable | 5,256 | |||
Prepaid expenses and other current assets | 379 | |||
Property, plant and equipment, net | 3,410 | |||
Other long-term assets | 4 | |||
Accounts payable | (19,959 | ) | ||
Accounts payable - affiliates | (17,099 | ) | ||
Accrued liabilities | (5,061 | ) | ||
Net assets | $ | 231 | ||
Business_Segment_Data_Tables
Business Segment Data (Tables) | 12 Months Ended | |||||||||||||||
Dec. 31, 2014 | ||||||||||||||||
Segment Reporting [Abstract] | ||||||||||||||||
Summary of Selected Business Segment Information | The following table presents selected business segment information for the periods indicated (in thousands): | |||||||||||||||
Other, | Consolidated | |||||||||||||||
Adjustments & | & Combined | |||||||||||||||
MRD | MEMP | Eliminations | Totals | |||||||||||||
Total revenues: | ||||||||||||||||
For the Year ended December 31, 2014 | $ | 405,286 | $ | 494,105 | $ | (46 | ) | $ | 899,345 | |||||||
For the Year ended December 31, 2013 | 231,558 | 343,616 | (151 | ) | 575,023 | |||||||||||
For the Year ended December 31, 2012 | 138,814 | 258,423 | (369 | ) | 396,868 | |||||||||||
Adjusted EBITDA: (1) | ||||||||||||||||
For the Year ended December 31, 2014 | 343,976 | 309,901 | (6,144 | ) | 647,733 | |||||||||||
For the Year ended December 31, 2013 | 197,903 | 222,185 | (25,232 | ) | 394,856 | |||||||||||
For the Year ended December 31, 2012 | 132,105 | 179,334 | (23,447 | ) | 287,992 | |||||||||||
Segment assets: (2) | ||||||||||||||||
As of December 31, 2014 | 1,632,313 | 2,930,559 | 30,675 | 4,593,547 | ||||||||||||
As of December 31, 2013 | 1,281,134 | 1,552,307 | (4,280 | ) | 2,829,161 | |||||||||||
Total cash expenditures for additions to long-lived assets: | ||||||||||||||||
For the Year ended December 31, 2014 | 521,038 | 1,348,095 | — | 1,869,133 | ||||||||||||
For the Year ended December 31, 2013 | 267,870 | 200,577 | — | 468,447 | ||||||||||||
For the Year ended December 31, 2012 | 249,526 | 387,160 | — | 636,686 | ||||||||||||
-1 | Adjustments and eliminations for the years ended December 31, 2014, 2013 and 2012 include amounts related to the MRD Segment’s equity investments in the MEMP Segment as well the elimination of $6.1 million, $26.0 million and $19.3 million of cash distributions that MEMP paid MRD Segment for the years ended December 31, 2014, 2013 and 2012, respectively, related to MRD Segment’s partnership interests in MEMP. | |||||||||||||||
-2 | Adjustments and eliminations primarily represent the elimination of the MRD Segment’s equity investments in the MEMP Segment. The adjustment at December 31, 2014 and 2013 also includes $46.0 million and $49.9 million, respectively related to an impairment recognized by the MEMP Segment during 2013. This impairment did not exist on a consolidated basis. | |||||||||||||||
Schedule of Calculation of Reportable Segment's Adjusted EBITDA | Calculation of Reportable Segments’ Adjusted EBITDA | |||||||||||||||
For the Year Ended December 31, 2014 | ||||||||||||||||
Combined | ||||||||||||||||
MRD | MEMP | Totals | ||||||||||||||
(In thousands) | ||||||||||||||||
Net income (loss) | $ | (762,926 | ) | $ | 118,079 | $ | (644,847 | ) | ||||||||
Interest expense, net | 50,283 | 83,550 | 133,833 | |||||||||||||
Loss on extinguishment of debt | 37,248 | — | 37,248 | |||||||||||||
Income tax expense (benefit) | 99,850 | 1,121 | 100,971 | |||||||||||||
DD&A | 154,917 | 155,404 | 310,321 | |||||||||||||
Impairment of proved oil and natural gas properties | 24,576 | 407,540 | 432,116 | |||||||||||||
Accretion of AROs | 688 | 5,618 | 6,306 | |||||||||||||
(Gain) loss on commodity derivative instruments | (257,734 | ) | (492,254 | ) | (749,988 | ) | ||||||||||
Cash settlements received (paid) on commodity derivative instruments | 9,166 | 13,522 | 22,688 | |||||||||||||
(Gain) loss on sale of properties | 3,057 | — | 3,057 | |||||||||||||
Acquisition related costs | 2,305 | 4,363 | 6,668 | |||||||||||||
Incentive-based compensation expense | 946,753 | 7,874 | 954,627 | |||||||||||||
Exploration costs | 15,813 | 790 | 16,603 | |||||||||||||
Provision for environmental remediation | — | 2,852 | 2,852 | |||||||||||||
Loss on office lease | 1,180 | 1,442 | 2,622 | |||||||||||||
Non-cash equity (income) loss from MEMP | 12,656 | — | 12,656 | |||||||||||||
Cash distributions from MEMP | 6,144 | — | 6,144 | |||||||||||||
Adjusted EBITDA | $ | 343,976 | $ | 309,901 | $ | 653,877 | ||||||||||
For the Year Ended December 31, 2013 | ||||||||||||||||
Combined | ||||||||||||||||
MRD | MEMP | Totals | ||||||||||||||
(In thousands) | ||||||||||||||||
Net income (loss) | $ | 82,243 | $ | 20,268 | $ | 102,511 | ||||||||||
Interest expense, net | 27,349 | 41,901 | 69,250 | |||||||||||||
Income tax expense (benefit) | 1,311 | 308 | 1,619 | |||||||||||||
DD&A | 87,043 | 97,269 | 184,312 | |||||||||||||
Impairment of proved oil and natural gas properties | 2,527 | 54,362 | 56,889 | |||||||||||||
Accretion of AROs | 728 | 4,853 | 5,581 | |||||||||||||
(Gain) loss on commodity derivative instruments | (3,013 | ) | (26,281 | ) | (29,294 | ) | ||||||||||
Cash settlements received (paid) on commodity derivative instruments | 12,240 | 19,879 | 32,119 | |||||||||||||
(Gain) loss on sale of properties | (82,773 | ) | (2,848 | ) | (85,621 | ) | ||||||||||
Acquisition related costs | 1,584 | 6,729 | 8,313 | |||||||||||||
Incentive-based compensation expense | 43,279 | 3,558 | 46,837 | |||||||||||||
Non-cash compensation expense | — | 1,057 | 1,057 | |||||||||||||
Exploration costs | 1,226 | 1,130 | 2,356 | |||||||||||||
Non-cash equity (income) loss from MEMP | (1,847 | ) | — | (1,847 | ) | |||||||||||
Cash distributions from MEMP | 26,006 | — | 26,006 | |||||||||||||
Adjusted EBITDA | $ | 197,903 | $ | 222,185 | $ | 420,088 | ||||||||||
For the Year Ended December 31, 2012 | ||||||||||||||||
Combined | ||||||||||||||||
MRD | MEMP | Totals | ||||||||||||||
(In thousands) | ||||||||||||||||
Net income (loss) | $ | (14,641 | ) | $ | 46,518 | $ | 31,877 | |||||||||
Interest expense, net | 12,802 | 20,436 | 33,238 | |||||||||||||
Income tax expense (benefit) | (178 | ) | 285 | 107 | ||||||||||||
DD&A | 62,636 | 76,036 | 138,672 | |||||||||||||
Impairment of proved oil and natural gas properties | 18,339 | 10,532 | 28,871 | |||||||||||||
Accretion of AROs | 632 | 4,377 | 5,009 | |||||||||||||
(Gain) loss on commodity derivative instruments | (13,488 | ) | (21,417 | ) | (34,905 | ) | ||||||||||
Cash settlements received (paid) on commodity derivative instruments | 30,188 | 44,111 | 74,299 | |||||||||||||
(Gain) loss on sale of properties | (2 | ) | (9,759 | ) | (9,761 | ) | ||||||||||
Acquisition related costs | 403 | 4,135 | 4,538 | |||||||||||||
Incentive-based compensation expense | 9,510 | 1,423 | 10,933 | |||||||||||||
Amortization of investment premium | — | 194 | 194 | |||||||||||||
Exploration costs | 7,337 | 2,463 | 9,800 | |||||||||||||
Non-cash equity (income) loss from MEMP | (696 | ) | — | (696 | ) | |||||||||||
Cash distributions from MEMP | 19,263 | — | 19,263 | |||||||||||||
Adjusted EBITDA | $ | 132,105 | $ | 179,334 | $ | 311,439 | ||||||||||
Reconciliation of Total Reportable Segment's Adjusted EBITDA to Net Income (Loss) | The following table presents a reconciliation of total reportable segments’ Adjusted EBITDA to net income (loss) for each of the periods indicated (in thousands): | |||||||||||||||
For the Year Ended December 31, | ||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
Total Reportable Segments' Adjusted EBITDA | $ | 653,877 | $ | 420,088 | $ | 311,439 | ||||||||||
Adjustments to reconcile Adjusted EBITDA to net income (loss): | ||||||||||||||||
Interest expense, net | (133,833 | ) | (69,250 | ) | (33,238 | ) | ||||||||||
Loss on extinguishment of debt | (37,248 | ) | — | — | ||||||||||||
Income tax benefit (expense) | (100,971 | ) | (1,619 | ) | (107 | ) | ||||||||||
DD&A | (314,193 | ) | (184,717 | ) | (138,672 | ) | ||||||||||
Impairment of proved oil and natural gas properties | (432,116 | ) | (6,600 | ) | (28,871 | ) | ||||||||||
Accretion of AROs | (6,306 | ) | (5,581 | ) | (5,009 | ) | ||||||||||
Gains (losses) on commodity derivative instruments | 749,988 | 29,294 | 34,905 | |||||||||||||
Cash settlements paid (received) on commodity derivative instruments | (22,688 | ) | (32,119 | ) | (74,299 | ) | ||||||||||
Gain (loss) on sale of properties | (3,057 | ) | 85,621 | 9,761 | ||||||||||||
Acquisition related costs | (6,668 | ) | (8,313 | ) | (4,538 | ) | ||||||||||
Incentive-based compensation expense | (954,627 | ) | (46,837 | ) | (10,933 | ) | ||||||||||
Non-cash compensation expense | — | (1,057 | ) | — | ||||||||||||
Exploration costs | (16,603 | ) | (2,356 | ) | (9,800 | ) | ||||||||||
Amortization of investment premium | — | — | (194 | ) | ||||||||||||
Cash distributions from MEMP | (6,144 | ) | (26,006 | ) | (19,263 | ) | ||||||||||
Provision for environmental remediation | (2,852 | ) | — | — | ||||||||||||
Loss on office lease | (2,622 | ) | — | — | ||||||||||||
Other non-cash equity (income) loss | — | 784 | (4,184 | ) | ||||||||||||
Net income (loss) | $ | (636,063 | ) | $ | 151,332 | $ | 26,997 | |||||||||
Schedule of Consolidated and Combined Statement of Operations Disaggregated by Reportable Segment | Included below is our consolidated and combined statement of operations disaggregated by reportable segment for the period indicated (in thousands): | |||||||||||||||
For the Year Ended December 31, 2014 | ||||||||||||||||
MRD | MEMP | Other, Adjustments & Eliminations | Consolidated & Combined Totals | |||||||||||||
Revenues: | ||||||||||||||||
Oil & natural gas sales | $ | 404,718 | $ | 490,249 | $ | — | $ | 894,967 | ||||||||
Other revenues | 568 | 3,856 | (46 | ) | 4,378 | |||||||||||
Total revenues | 405,286 | 494,105 | (46 | ) | 899,345 | |||||||||||
Costs and expenses: | ||||||||||||||||
Lease operating | 26,695 | 134,654 | (46 | ) | 161,303 | |||||||||||
Pipeline operating | — | 2,068 | — | 2,068 | ||||||||||||
Exploration | 15,813 | 790 | — | 16,603 | ||||||||||||
Production and ad valorem taxes | 14,150 | 31,601 | — | 45,751 | ||||||||||||
Depreciation, depletion, and amortization | 154,917 | 155,404 | 3,872 | 314,193 | ||||||||||||
Impairment of proved oil and natural gas properties | 24,576 | 407,540 | — | 432,116 | ||||||||||||
Incentive unit compensation expense | 943,949 | — | — | 943,949 | ||||||||||||
General and administrative | 42,054 | 45,619 | — | 87,673 | ||||||||||||
Accretion of asset retirement obligations | 688 | 5,618 | — | 6,306 | ||||||||||||
(Gain) loss on commodity derivative instruments | (257,734 | ) | (492,254 | ) | — | (749,988 | ) | |||||||||
(Gain) loss on sale of properties | 3,057 | — | — | 3,057 | ||||||||||||
Other, net | — | (12 | ) | — | (12 | ) | ||||||||||
Total costs and expenses | 968,165 | 291,028 | 3,826 | 1,263,019 | ||||||||||||
Operating income (loss) | (562,879 | ) | 203,077 | (3,872 | ) | (363,674 | ) | |||||||||
Other income (expense): | ||||||||||||||||
Interest expense, net | (50,283 | ) | (83,550 | ) | — | (133,833 | ) | |||||||||
Loss on extinguishment of debt | (37,248 | ) | — | — | (37,248 | ) | ||||||||||
Earnings from equity investments | (12,656 | ) | — | 12,656 | — | |||||||||||
Other, net | (10 | ) | (327 | ) | — | (337 | ) | |||||||||
Total other income (expense) | (100,197 | ) | (83,877 | ) | 12,656 | (171,418 | ) | |||||||||
Income (loss) before income taxes | (663,076 | ) | 119,200 | 8,784 | (535,092 | ) | ||||||||||
Income tax benefit (expense) | (99,850 | ) | (1,121 | ) | — | (100,971 | ) | |||||||||
Net income (loss) | $ | (762,926 | ) | $ | 118,079 | $ | 8,784 | $ | (636,063 | ) | ||||||
For the Year Ended December 31, 2013 | ||||||||||||||||
MRD | MEMP | Other, Adjustments & Eliminations | Consolidated & Combined Totals | |||||||||||||
Revenues: | ||||||||||||||||
Oil & natural gas sales | $ | 230,751 | $ | 341,197 | $ | — | $ | 571,948 | ||||||||
Other revenues | 807 | 2,419 | (151 | ) | 3,075 | |||||||||||
Total revenues | 231,558 | 343,616 | (151 | ) | 575,023 | |||||||||||
Costs and expenses: | ||||||||||||||||
Lease operating | 25,006 | 88,893 | (259 | ) | 113,640 | |||||||||||
Pipeline operating | — | 1,835 | — | 1,835 | ||||||||||||
Exploration | 1,226 | 1,130 | — | 2,356 | ||||||||||||
Production and ad valorem taxes | 9,362 | 17,784 | — | 27,146 | ||||||||||||
Depreciation, depletion, and amortization | 87,043 | 97,269 | 405 | 184,717 | ||||||||||||
Impairment of proved oil and natural gas properties | 2,527 | 54,362 | (50,289 | ) | 6,600 | |||||||||||
Incentive unit compensation expense | 43,279 | — | — | 43,279 | ||||||||||||
General and administrative | 38,479 | 43,495 | 105 | 82,079 | ||||||||||||
Accretion of asset retirement obligations | 728 | 4,853 | — | 5,581 | ||||||||||||
(Gain) loss on commodity derivative instruments | (3,013 | ) | (26,281 | ) | — | (29,294 | ) | |||||||||
(Gain) loss on sale of properties | (82,773 | ) | (2,848 | ) | — | (85,621 | ) | |||||||||
Other, net | 2 | 647 | — | 649 | ||||||||||||
Total costs and expenses | 121,866 | 281,139 | (50,038 | ) | 352,967 | |||||||||||
Operating income (loss) | 109,692 | 62,477 | 49,887 | 222,056 | ||||||||||||
Other income (expense): | ||||||||||||||||
Interest expense, net | (27,349 | ) | (41,901 | ) | — | (69,250 | ) | |||||||||
Earnings from equity investments | 1,066 | — | (1,066 | ) | — | |||||||||||
Other, net | 145 | — | — | 145 | ||||||||||||
Total other income (expense) | (26,138 | ) | (41,901 | ) | (1,066 | ) | (69,105 | ) | ||||||||
Income before income taxes | 83,554 | 20,576 | 48,821 | 152,951 | ||||||||||||
Income tax benefit (expense) | (1,311 | ) | (308 | ) | — | (1,619 | ) | |||||||||
Net income (loss) | $ | 82,243 | $ | 20,268 | $ | 48,821 | $ | 151,332 | ||||||||
For the Year Ended December 31, 2012 | ||||||||||||||||
MRD | MEMP | Other, Adjustments & Eliminations | Consolidated & Combined Totals | |||||||||||||
Revenues: | ||||||||||||||||
Oil & natural gas sales | $ | 138,032 | $ | 255,608 | $ | (9 | ) | $ | 393,631 | |||||||
Other revenues | 782 | 2,815 | (360 | ) | 3,237 | |||||||||||
Total revenues | 138,814 | 258,423 | (369 | ) | 396,868 | |||||||||||
Costs and expenses: | ||||||||||||||||
Lease operating | 24,438 | 80,116 | (800 | ) | 103,754 | |||||||||||
Pipeline operating | — | 2,114 | — | 2,114 | ||||||||||||
Exploration | 7,337 | 2,463 | — | 9,800 | ||||||||||||
Production and ad valorem taxes | 7,576 | 16,048 | — | 23,624 | ||||||||||||
Depreciation, depletion, and amortization | 62,636 | 76,036 | — | 138,672 | ||||||||||||
Impairment of proved oil and natural gas properties | 18,339 | 10,532 | — | 28,871 | ||||||||||||
Incentive unit compensation expense | 9,510 | — | — | 9,510 | ||||||||||||
General and administrative | 28,904 | 30,342 | 431 | 59,677 | ||||||||||||
Accretion of asset retirement obligations | 632 | 4,377 | — | 5,009 | ||||||||||||
(Gain) loss on commodity derivative instruments | (13,488 | ) | (21,417 | ) | — | (34,905 | ) | |||||||||
(Gain) loss on sale of properties | (2 | ) | (9,759 | ) | — | (9,761 | ) | |||||||||
Other, net | 364 | 138 | — | 502 | ||||||||||||
Total costs and expenses | 146,246 | 190,990 | (369 | ) | 336,867 | |||||||||||
Operating income (loss) | (7,432 | ) | 67,433 | — | 60,001 | |||||||||||
Other income (expense): | ||||||||||||||||
Interest expense, net | (12,802 | ) | (20,436 | ) | — | (33,238 | ) | |||||||||
Amortization of investment premium | — | (194 | ) | — | (194 | ) | ||||||||||
Earnings from equity investments | 4,880 | — | (4,880 | ) | — | |||||||||||
Other, net | 535 | — | — | 535 | ||||||||||||
Total other income (expense) | (7,387 | ) | (20,630 | ) | (4,880 | ) | (32,897 | ) | ||||||||
Income before income taxes | (14,819 | ) | 46,803 | (4,880 | ) | 27,104 | ||||||||||
Income tax benefit (expense) | 178 | (285 | ) | — | (107 | ) | ||||||||||
Net income (loss) | $ | (14,641 | ) | $ | 46,518 | $ | (4,880 | ) | $ | 26,997 | ||||||
Income_Taxes_Tables
Income Taxes (Tables) | 12 Months Ended | |||||||||||
Dec. 31, 2014 | ||||||||||||
Income Tax Disclosure [Abstract] | ||||||||||||
Components of Income Tax Expense (Benefit) | Income tax benefit (expense) for the indicated periods is comprised of the following: | |||||||||||
For the Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
(In thousands) | ||||||||||||
Current taxes: | ||||||||||||
Federal | $ | — | $ | — | $ | — | ||||||
State | 22 | (1,619 | ) | 178 | ||||||||
Deferred taxes: | ||||||||||||
Federal | (88,994 | ) | — | — | ||||||||
State | (11,999 | ) | — | (285 | ) | |||||||
Total income tax benefit (expense) | $ | (100,971 | ) | $ | (1,619 | ) | $ | (107 | ) | |||
Reconciliation of Income Tax Benefit (Provision) | ||||||||||||
The actual income tax benefit (expense) differs from the expected income tax benefit (provision) as computed by applying the federal statutory corporate tax rate of 35% for each period indicated as follows: | ||||||||||||
For the Year Ended December 31, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
Expected tax benefit (expense) | $ | 187,282 | $ | (53,533 | ) | $ | (9,486 | ) | ||||
State income tax expense, net of federal benefit | (9,660 | ) | (1,619 | ) | (107 | ) | ||||||
Pass-through entities (1) | 49,989 | 53,533 | 9,486 | |||||||||
Stock compensation (2) | (330,024 | ) | — | — | ||||||||
Other | 1,442 | — | — | |||||||||
Total income tax benefit (expense) | $ | (100,971 | ) | $ | (1,619 | ) | $ | (107 | ) | |||
Components of Net Deferred Income Tax Assets and (Liabilities) | ||||||||||||
-1 | MEMP, a publicly traded partnership with qualifying income, is a pass-through entity for federal income tax purposes. In addition, our predecessor was also a pass-through entity for federal income tax purposes. | |||||||||||
-2 | As discussed in Note 12, the compensation expense associated with the incentive units of WildHorse Resources and MRD Holdco created a nondeductible permanent difference for income tax purposes. | |||||||||||
The components of net deferred income tax assets and (liabilities) recognized were as follows: | ||||||||||||
December 31, | ||||||||||||
2014 | 2013 | |||||||||||
(In thousands) | ||||||||||||
Deferred current income tax assets: | ||||||||||||
Unrealized hedging transactions | $ | 109 | $ | 37 | ||||||||
Accrued liabilities | — | 5 | ||||||||||
Other | 342 | (42 | ) | |||||||||
Deferred current income tax assets: | $ | 451 | $ | — | ||||||||
Deferred current income tax liabilities: | ||||||||||||
Unrealized hedging transactions | $ | (52,328 | ) | — | ||||||||
Other | (52 | ) | (382 | ) | ||||||||
Deferred current income tax liabilities: | $ | (52,380 | ) | $ | (382 | ) | ||||||
Deferred noncurrent income tax assets: | ||||||||||||
Net operating loss carryforward | $ | 28,043 | $ | 2,350 | ||||||||
Asset retirement obligation | 5,757 | 971 | ||||||||||
Other | 3,224 | 1 | ||||||||||
Net deferred tax valuation allowance | (2,634 | ) | (2,896 | ) | ||||||||
Deferred noncurrent income tax assets: | $ | 34,390 | $ | 426 | ||||||||
Deferred noncurrent income tax liabilities: | ||||||||||||
Property, plant and equipment | $ | (80,198 | ) | $ | (3,318 | ) | ||||||
Unrealized hedging transactions | (48,929 | ) | (275 | ) | ||||||||
Other | (280 | ) | 61 | |||||||||
Deferred noncurrent income tax liabilities: | $ | (129,407 | ) | $ | (3,532 | ) | ||||||
Net current deferred income tax assets (liabilities) | $ | (51,929 | ) | $ | (382 | ) | ||||||
Net noncurrent deferred income tax assets (liabilities) | $ | (95,017 | ) | $ | (3,106 | ) | ||||||
Commitments_and_Contingencies_
Commitments and Contingencies (Tables) | 12 Months Ended | |||||||||||||||||||||||||||
Dec. 31, 2014 | ||||||||||||||||||||||||||||
Environmental Reserves Activity | The following table presents the activity of our environmental reserves for the periods presented: | |||||||||||||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||||||
Balance at beginning of period | $ | 577 | $ | 1,469 | $ | 1,747 | ||||||||||||||||||||||
Charged to costs and expenses | 2,852 | — | 193 | |||||||||||||||||||||||||
Payments | (1,337 | ) | (892 | ) | (471 | ) | ||||||||||||||||||||||
Balance at end of period | $ | 2,092 | $ | 577 | $ | 1,469 | ||||||||||||||||||||||
Minimum Balances Attributable to Net Working Interest | The trust account must maintain minimum balances attributable to REO’s net working interest as follows (in thousands): | |||||||||||||||||||||||||||
30-Jun-15 | $ | 72,450 | ||||||||||||||||||||||||||
30-Jun-16 | $ | 76,590 | ||||||||||||||||||||||||||
31-Dec-16 | $ | 78,660 | ||||||||||||||||||||||||||
Gross Held-to-Maturity Investments | The following is a summary of the gross held-to-maturity investments held in the trust account less the outside working interest owners share as of December 31, 2014 (in thousands): | |||||||||||||||||||||||||||
Amortized | ||||||||||||||||||||||||||||
Investment | Cost | |||||||||||||||||||||||||||
U.S. Bank Money Market Cash Equivalent | $ | 135,176 | ||||||||||||||||||||||||||
Less: Outside working interest owners share | (65,222 | ) | ||||||||||||||||||||||||||
$ | 69,954 | |||||||||||||||||||||||||||
Minimum Commitments to Gatherer before Other Owner Contributions | WildHorse Resources’ minimum commitments to the Gatherer, before other owner contributions, as of December 31, 2014 were as follows (in thousands): | |||||||||||||||||||||||||||
Dubach | Dubberly | |||||||||||||||||||||||||||
2015 | $ | 13,671 | $ | 11,393 | ||||||||||||||||||||||||
2016 | 13,709 | 11,424 | ||||||||||||||||||||||||||
2017 | 13,671 | 11,393 | ||||||||||||||||||||||||||
2018 | 12,772 | 10,643 | ||||||||||||||||||||||||||
Total | $ | 53,823 | $ | 44,853 | ||||||||||||||||||||||||
Minimum Lease Payment Obligations and Sublease Rental Income Under Non-Cancelable Operating Leases | Amounts shown in the following table represent minimum lease payment obligations and sublease rental income under non-cancelable operating leases with a remaining term in excess of one year: | |||||||||||||||||||||||||||
Payment or Settlement due by Period | ||||||||||||||||||||||||||||
Total | 2015 | 2016 | 2017 | 2018 | 2019 | Thereafter | ||||||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||||||
MRD Segment: | ||||||||||||||||||||||||||||
Operating leases | $ | 43,625 | $ | 6,534 | $ | 6,607 | $ | 6,694 | $ | 6,259 | $ | 5,960 | $ | 11,571 | ||||||||||||||
Sublease rental income | 5,786 | 1,691 | 1,579 | 1,197 | 814 | 431 | 74 | |||||||||||||||||||||
MEMP Segment: | ||||||||||||||||||||||||||||
Operating leases | 3,665 | 788 | 416 | 205 | 205 | 205 | 1,846 | |||||||||||||||||||||
Wyoming Acquisition [Member] | ||||||||||||||||||||||||||||
CO2 Minimum Purchase Commitment | At December 31, 2014, MEMP had a CO2 purchase commitment with a third party that was assumed in its Wyoming Acquisition. The table below outlines MEMP’s purchase commitment under the contract for the remainder of 2014 and annually thereafter (in thousands): | |||||||||||||||||||||||||||
Payment or Settlement due by Period | ||||||||||||||||||||||||||||
Purchase commitment | Total | 2015 | 2016 | 2017 | 2018 | 2019 | Thereafter | |||||||||||||||||||||
CO2 minimum purchase commitment: | ||||||||||||||||||||||||||||
Estimated payment obligation | $ | 50,495 | $ | 9,608 | $ | 10,179 | $ | 10,151 | $ | 6,995 | $ | 7,060 | $ | 6,502 | ||||||||||||||
Quarterly_Financial_Informatio1
Quarterly Financial Information (Unaudited) (Tables) | 12 Months Ended | |||||||||||||||
Dec. 31, 2014 | ||||||||||||||||
Quarterly Financial Information Disclosure [Abstract] | ||||||||||||||||
Schedule of Quarterly Financial Information | The following tables present selected quarterly financial data for the periods indicated. Earnings per share are computed independently for each of the quarters presented and the sum of the quarterly earnings per share may not necessarily equal the total for the year. As discussed in Note 4 and Note 12, we recorded oil and natural gas property impairments and incentive unit compensation expense, respectively, during 2014, which impacted the comparability between the periods presented below. | |||||||||||||||
First | Second | Third | Fourth | |||||||||||||
Quarter | Quarter | Quarter | Quarter | |||||||||||||
For the Year Ended December 31, 2014 | (In thousands, except per share amounts) | |||||||||||||||
Revenues | $ | 190,828 | $ | 236,564 | $ | 245,493 | $ | 226,460 | ||||||||
Operating income (loss) | 10,605 | (993,256 | ) | 174,201 | 444,776 | |||||||||||
Net income (loss) | (23,516 | ) | (1,053,443 | ) | 112,037 | 328,859 | ||||||||||
Net income (loss) attributable to noncontrolling interest | (31,888 | ) | (105,094 | ) | 102,109 | 161,661 | ||||||||||
Net income (loss) attributable to Memorial Resource | 8,372 | (948,349 | ) | 9,928 | 167,198 | |||||||||||
Development Corp. | ||||||||||||||||
Net income (loss) allocated to members | 6,947 | 13,358 | — | — | ||||||||||||
Net income (loss) allocated to previous owners | 1,425 | — | — | — | ||||||||||||
Net income (loss) available to common stockholders | n/a | (961,707 | ) | 9,928 | 167,198 | |||||||||||
Basic earnings per share | n/a | (5.00 | ) | 0.05 | 0.87 | |||||||||||
Diluted earnings per share | n/a | (5.00 | ) | 0.05 | 0.87 | |||||||||||
First | Second | Third | Fourth | |||||||||||||
Quarter | Quarter | Quarter | Quarter | |||||||||||||
For the Year Ended December 31, 2013 | (In thousands, except per share amounts) | |||||||||||||||
Revenues | $ | 122,181 | $ | 147,045 | $ | 153,515 | $ | 152,282 | ||||||||
Operating income (loss) | 9,521 | 90,327 | 117,797 | 4,411 | ||||||||||||
Net income (loss) | 180 | 78,158 | 95,962 | (22,968 | ) | |||||||||||
Net income (loss) attributable to noncontrolling interest | (4,069 | ) | 34,975 | 11,235 | 7,689 | |||||||||||
Net income (loss) attributable to Memorial Resource | 4,249 | 43,183 | 84,727 | (30,657 | ) | |||||||||||
Development Corp. | ||||||||||||||||
Net income (loss) allocated to members | 2,597 | 35,278 | 84,754 | (31,917 | ) | |||||||||||
Net income (loss) allocated to previous owners | 1,652 | 7,905 | (27 | ) | 1,260 | |||||||||||
Supplemental_Oil_and_Gas_Infor1
Supplemental Oil and Gas Information (Unaudited) (Tables) | 12 Months Ended | |||||||||||||||
Dec. 31, 2014 | ||||||||||||||||
Capitalized Costs Relating to Oil and Natural Gas Producing Activities | The total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depreciation, depletion and amortization is as follows at the dates indicated. | |||||||||||||||
For the Year Ended December 31, | ||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
(In thousands) | ||||||||||||||||
MRD Segment: | ||||||||||||||||
Evaluated oil and natural gas properties | $ | 1,590,997 | $ | 1,226,417 | $ | 1,052,219 | ||||||||||
Unevaluated oil and natural gas properties | 48,229 | 46,413 | 26,589 | |||||||||||||
Accumulated depletion, depreciation, and amortization | (391,145 | ) | (256,629 | ) | (202,581 | ) | ||||||||||
Subtotal | $ | 1,248,081 | $ | 1,016,201 | $ | 876,227 | ||||||||||
MEMP Segment: | ||||||||||||||||
Evaluated oil and natural gas properties (1) | $ | 3,007,214 | $ | 1,748,438 | $ | 1,539,642 | ||||||||||
Support equipment and facilities | 185,997 | 5,910 | 5,760 | |||||||||||||
Unevaluated oil and natural gas properties | — | — | 5,004 | |||||||||||||
Accumulated depletion, depreciation, and amortization (1) | (989,103 | ) | (416,617 | ) | (265,710 | ) | ||||||||||
Subtotal | $ | 2,204,108 | $ | 1,337,731 | $ | 1,284,696 | ||||||||||
Eliminations: | ||||||||||||||||
Accumulated depletion, depreciation, and amortization | $ | 46,013 | $ | 49,884 | $ | — | ||||||||||
Consolidated: | ||||||||||||||||
Evaluated oil and natural gas properties (1) | $ | 4,598,211 | $ | 2,974,855 | $ | 2,591,861 | ||||||||||
Support equipment and facilities | 185,997 | 5,910 | 5,760 | |||||||||||||
Unevaluated oil and natural gas properties | 48,229 | 46,413 | 31,593 | |||||||||||||
Accumulated depletion, depreciation, and amortization (1) | (1,334,235 | ) | (623,362 | ) | (468,291 | ) | ||||||||||
Total | $ | 3,498,202 | $ | 2,403,816 | $ | 2,160,923 | ||||||||||
-1 | Amounts do not include costs for SPBPC and related support equipment. | |||||||||||||||
Costs Incurred for Property Acquisitions, Exploration and Development | Costs incurred in property acquisition, exploration and development activities were as follows for the periods indicated: | |||||||||||||||
For the Year Ended December 31, | ||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
(In thousands) | ||||||||||||||||
MRD Segment: | ||||||||||||||||
Property acquisition costs, proved | $ | 74,490 | $ | 56,108 | $ | 87,857 | ||||||||||
Property acquisition costs, unproved | 25,030 | 19,975 | 5,293 | |||||||||||||
Exploration and extension well costs | 209,532 | 13,313 | 212 | |||||||||||||
Development | 208,459 | 210,440 | 135,951 | |||||||||||||
Subtotal | $ | 517,511 | $ | 299,836 | $ | 229,313 | ||||||||||
MEMP Segment: | ||||||||||||||||
Property acquisition costs, proved | $ | 983,076 | $ | 37,786 | $ | 278,246 | ||||||||||
Exploration and extension well costs | — | — | 42,430 | |||||||||||||
Development (1) | 279,318 | 145,830 | 62,472 | |||||||||||||
Subtotal | $ | 1,262,394 | $ | 183,616 | $ | 383,148 | ||||||||||
Consolidated: | ||||||||||||||||
Property acquisition costs, proved | $ | 1,057,566 | $ | 93,894 | $ | 366,103 | ||||||||||
Property acquisition costs, unproved | 25,030 | 19,975 | 5,293 | |||||||||||||
Exploration and extension well costs | 209,532 | 13,313 | 42,642 | |||||||||||||
Development (1) | 487,777 | 356,270 | 198,423 | |||||||||||||
Total | $ | 1,779,905 | $ | 483,452 | $ | 612,461 | ||||||||||
-1 | Amounts do not include costs for SPBPC and related support equipment. | |||||||||||||||
Weighted Average Benchmark Product Prices | The weighted-average benchmark product prices used for valuing the reserves are based upon the average of the first-day-of-the-month price for each month within the period January through December of each year presented: | |||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
Oil ($/Bbl) | ||||||||||||||||
West Texas Intermediate (1) | $ | 91.48 | $ | 93.42 | $ | 91.33 | ||||||||||
NGL ($/Bbl) | ||||||||||||||||
West Texas Intermediate (1) | $ | 91.48 | $ | 93.42 | $ | 91.75 | ||||||||||
Natural Gas ($/Mmbtu) | ||||||||||||||||
Henry Hub (2) | $ | 4.35 | $ | 3.67 | $ | 2.75 | ||||||||||
-1 | The unweighted average West Texas Intermediate price was adjusted by lease for quality, transportation fees, and a regional price differential. | |||||||||||||||
-2 | The unweighted average Henry Hub price was adjusted by lease for energy content, compression charges, transportation fees, and regional price differentials. | |||||||||||||||
MRD [Member] | ||||||||||||||||
Reserve Quantity Information | The following tables set forth estimates of the net reserves as of December 31, 2014, 2013, and 2012 respectively: | |||||||||||||||
For the Year Ended December 31, 2014 | ||||||||||||||||
Oil | Gas | NGLs | Equivalent | |||||||||||||
(MBbls) | (MMcf) | (MBbls) | (MMcfe) | |||||||||||||
Proved developed and undeveloped reserves: | ||||||||||||||||
Beginning of the year | 11,311 | 802,254 | 42,576 | 1,125,577 | ||||||||||||
Extensions and discoveries | 1,825 | 183,527 | 9,876 | 253,730 | ||||||||||||
Purchase of minerals in place | 269 | 22,186 | 1,247 | 31,283 | ||||||||||||
Production | (951 | ) | (63,801 | ) | (2,220 | ) | (82,816 | ) | ||||||||
Sales of minerals in place | (623 | ) | (10,815 | ) | (950 | ) | (20,253 | ) | ||||||||
Revision of previous estimates | 772 | 247,578 | 12,060 | 324,558 | ||||||||||||
End of year | 12,603 | 1,180,929 | 62,589 | 1,632,079 | ||||||||||||
Proved developed reserves: | ||||||||||||||||
Beginning of year | 3,402 | 263,797 | 13,904 | 367,641 | ||||||||||||
End of year | 3,905 | 392,181 | 19,924 | 535,151 | ||||||||||||
Proved undeveloped reserves: | ||||||||||||||||
Beginning of year | 7,909 | 538,457 | 28,672 | 757,936 | ||||||||||||
End of year | 8,698 | 788,748 | 42,665 | 1,096,928 | ||||||||||||
For the Year Ended December 31, 2013 | ||||||||||||||||
Oil | Gas | NGLs | Equivalent | |||||||||||||
(MBbls) | (MMcf) | (MBbls) | (MMcfe) | |||||||||||||
Proved developed and undeveloped reserves: | ||||||||||||||||
Beginning of the year | 11,953 | 739,378 | 41,466 | 1,059,895 | ||||||||||||
Extensions and discoveries | 1,794 | 149,974 | 8,319 | 210,652 | ||||||||||||
Purchase of minerals in place | 211 | 31,815 | 1,017 | 39,183 | ||||||||||||
Production | (665 | ) | (34,092 | ) | (1,457 | ) | (46,819 | ) | ||||||||
Sales of minerals in place | (599 | ) | (14,137 | ) | (1,573 | ) | (27,169 | ) | ||||||||
Revision of previous estimates | (1,383 | ) | (70,684 | ) | (5,196 | ) | (110,165 | ) | ||||||||
End of year (1) | 11,311 | 802,254 | 42,576 | 1,125,577 | ||||||||||||
Proved developed reserves: | ||||||||||||||||
Beginning of year | 3,082 | 245,449 | 12,321 | 337,869 | ||||||||||||
End of year | 3,402 | 263,797 | 13,904 | 367,641 | ||||||||||||
Proved undeveloped reserves: | ||||||||||||||||
Beginning of year | 8,871 | 493,929 | 29,145 | 722,026 | ||||||||||||
End of year | 7,909 | 538,457 | 28,672 | 757,936 | ||||||||||||
-1 | Includes reserves of 41,077 MMcfe attributable to noncontrolling interests and the MRD Segment previous owners. | |||||||||||||||
For the Year Ended December 31, 2012 | ||||||||||||||||
Oil | Gas | NGLs | Equivalent | |||||||||||||
(MBbls) | (MMcf) | (MBbls) | (MMcfe) | |||||||||||||
Proved developed and undeveloped reserves: | ||||||||||||||||
Beginning of the year | 10,834 | 929,335 | 53,031 | 1,312,533 | ||||||||||||
Extensions and discoveries | 689 | 42,019 | 2,778 | 62,819 | ||||||||||||
Purchase of minerals in place | 1,100 | 28,115 | 1,879 | 45,987 | ||||||||||||
Production | (369 | ) | (24,131 | ) | (898 | ) | (31,731 | ) | ||||||||
Sales of minerals in place | (4 | ) | (728 | ) | — | (752 | ) | |||||||||
Revision of previous estimates | (297 | ) | (235,232 | ) | (15,324 | ) | (328,961 | ) | ||||||||
End of year (1) | 11,953 | 739,378 | 41,466 | 1,059,895 | ||||||||||||
Proved developed reserves: | ||||||||||||||||
Beginning of year | 2,107 | 191,557 | 7,644 | 250,073 | ||||||||||||
End of year | 3,082 | 245,449 | 12,321 | 337,869 | ||||||||||||
Proved undeveloped reserves: | ||||||||||||||||
Beginning of year | 8,727 | 737,778 | 45,387 | 1,062,460 | ||||||||||||
End of year | 8,871 | 493,929 | 29,145 | 722,026 | ||||||||||||
-1 | Includes reserves of 67,135 MMcfe attributable to noncontrolling interests and the MRD Segment previous owners. | |||||||||||||||
Discounted Future Net Cash Flows | The standardized measure of discounted future net cash flows is as follows: | |||||||||||||||
For the Year Ended December 31, | ||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
(In thousands) | ||||||||||||||||
Future cash inflows | $ | 8,313,329 | $ | 5,722,848 | $ | 4,921,192 | ||||||||||
Future production costs | (1,325,573 | ) | (1,587,374 | ) | (1,255,289 | ) | ||||||||||
Future development costs | (1,443,612 | ) | (1,352,945 | ) | (1,060,777 | ) | ||||||||||
Future income tax expense (1) | (1,789,031 | ) | — | — | ||||||||||||
Future net cash flows for estimated timing of cash flows | 3,755,113 | 2,782,529 | 2,605,126 | |||||||||||||
10% annual discount for estimated timing of cash flows | (1,792,579 | ) | (1,313,577 | ) | (1,284,531 | ) | ||||||||||
Standardized measure of discounted future net cash flows (2) | $ | 1,962,534 | $ | 1,468,952 | $ | 1,320,595 | ||||||||||
-1 | Our predecessor was a pass through entity and was subject to the Texas margin tax which has a maximum effective rate of 0.7% of gross income apportioned to Texas. Due to immateriality, we have excluded the impact of this tax for the years ended December 31, 2013 and 2012. | |||||||||||||||
-2 | Includes $63,422 and $78,518 attributable to both noncontrolling interests and the MRD Segment previous owners for the years ended December 31, 2013 and 2012, respectively. | |||||||||||||||
Summary of the Changes in the Standardized Measure of Future Net Cash Flows | The following is a summary of the changes in the standardized measure of discounted future net cash flows for the proved oil and natural gas reserves during each of the years in the three year period ended December 31, 2014: | |||||||||||||||
For the Year Ended December 31, | ||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
(In thousands) | ||||||||||||||||
Beginning of year | $ | 1,468,952 | $ | 1,320,595 | $ | 1,386,071 | ||||||||||
Sale of oil and natural gas produced, net of production costs | (363,723 | ) | (196,444 | ) | (107,316 | ) | ||||||||||
Purchase of minerals in place | 69,282 | 51,177 | 98,384 | |||||||||||||
Sale of minerals in place | (47,791 | ) | (54,091 | ) | — | |||||||||||
Extensions and discoveries | 653,186 | 301,004 | 127,994 | |||||||||||||
Changes in income taxes, net | (1,058,814 | ) | — | — | ||||||||||||
Changes in prices and costs | 365,030 | (11,336 | ) | (402,202 | ) | |||||||||||
Previously estimated development costs incurred | 256,605 | 87,297 | 64,390 | |||||||||||||
Net changes in future development costs | (126,598 | ) | 57,353 | (67,331 | ) | |||||||||||
Revisions of previous quantities | 828,296 | (186,804 | ) | (176,788 | ) | |||||||||||
Accretion of discount | 146,896 | 128,544 | 138,607 | |||||||||||||
Change in production rates and other | (228,787 | ) | (28,343 | ) | 258,786 | |||||||||||
End of year | $ | 1,962,534 | $ | 1,468,952 | $ | 1,320,595 | ||||||||||
MEMP [Member] | ||||||||||||||||
Reserve Quantity Information | The following tables set forth estimates of the net reserves as of December 31, 2014, 2013, and 2012 respectively: | |||||||||||||||
For the Year Ended December 31, 2014 | ||||||||||||||||
Oil | Gas | NGLs | Equivalent | |||||||||||||
(MBbls) | (MMcf) | (MBbls) | (MMcfe) | |||||||||||||
Proved developed and undeveloped reserves: | ||||||||||||||||
Beginning of the year | 39,149 | 607,139 | 28,846 | 1,015,105 | ||||||||||||
Extensions and discoveries | 849 | 12,723 | 711 | 22,085 | ||||||||||||
Purchase of minerals in place | 69,095 | 13,036 | 22,351 | 561,713 | ||||||||||||
Production | (3,092 | ) | (41,494 | ) | (2,143 | ) | (72,902 | ) | ||||||||
Revision of previous estimates | (6,431 | ) | (31,777 | ) | (287 | ) | (72,090 | ) | ||||||||
End of year (1) | 99,570 | 559,627 | 49,478 | 1,453,911 | ||||||||||||
Proved developed reserves: | ||||||||||||||||
Beginning of year | 22,265 | 387,548 | 15,959 | 616,893 | ||||||||||||
End of year | 54,526 | 380,397 | 35,539 | 920,783 | ||||||||||||
Proved undeveloped reserves: | ||||||||||||||||
Beginning of year | 16,884 | 219,591 | 12,887 | 398,212 | ||||||||||||
End of year | 45,044 | 179,230 | 13,939 | 533,128 | ||||||||||||
(1) MRD Segment’s share of these reserves is 1,454 MMcfe. | ||||||||||||||||
For the Year Ended December 31, 2013 | ||||||||||||||||
Oil | Gas | NGLs | Equivalent | |||||||||||||
(MBbls) | (MMcf) | (MBbls) | (MMcfe) | |||||||||||||
Proved developed and undeveloped reserves: | ||||||||||||||||
Beginning of the year | 39,089 | 604,440 | 29,352 | 1,015,095 | ||||||||||||
Extensions and discoveries | 5,655 | 40,770 | 1,747 | 85,180 | ||||||||||||
Purchase of minerals in place | 119 | 16,294 | 258 | 18,554 | ||||||||||||
Production | (1,764 | ) | (35,924 | ) | (1,632 | ) | (56,303 | ) | ||||||||
Revision of previous estimates | (3,950 | ) | (18,441 | ) | (879 | ) | (47,421 | ) | ||||||||
End of year (1) | 39,149 | 607,139 | 28,846 | 1,015,105 | ||||||||||||
Proved developed reserves: | ||||||||||||||||
Beginning of year | 24,515 | 376,932 | 15,947 | 619,704 | ||||||||||||
End of year | 22,265 | 387,548 | 15,959 | 616,893 | ||||||||||||
Proved undeveloped reserves: | ||||||||||||||||
Beginning of year | 14,574 | 227,508 | 13,405 | 395,391 | ||||||||||||
End of year | 16,884 | 219,591 | 12,887 | 398,212 | ||||||||||||
(1) MRD Segment’s share of these reserves is 89,837 MMcfe. | ||||||||||||||||
For the Year Ended December 31, 2012 | ||||||||||||||||
Oil | Gas | NGLs | Equivalent | |||||||||||||
(MBbls) | (MMcf) | (MBbls) | (MMcfe) | |||||||||||||
Proved developed and undeveloped reserves: | ||||||||||||||||
Beginning of the year | 27,150 | 579,751 | 15,045 | 832,913 | ||||||||||||
Extensions and discoveries | 7,501 | 19,869 | 1,053 | 71,192 | ||||||||||||
Purchase of minerals in place | 11,336 | 113,617 | 7,095 | 224,202 | ||||||||||||
Production | (1,519 | ) | (29,744 | ) | (745 | ) | (43,329 | ) | ||||||||
Sales of minerals in place | (4,214 | ) | (4,214 | ) | — | (29,499 | ) | |||||||||
Revision of previous estimates | (1,165 | ) | (74,839 | ) | 6,904 | (40,384 | ) | |||||||||
End of year (1) | 39,089 | 604,440 | 29,352 | 1,015,095 | ||||||||||||
Proved developed reserves: | ||||||||||||||||
Beginning of year | 19,332 | 413,431 | 10,015 | 589,504 | ||||||||||||
End of year | 24,515 | 376,932 | 15,947 | 619,704 | ||||||||||||
Proved undeveloped reserves: | ||||||||||||||||
Beginning of year | 7,818 | 166,320 | 5,030 | 243,409 | ||||||||||||
End of year | 14,574 | 227,508 | 13,405 | 395,391 | ||||||||||||
(1) MRD Segment’s share of these reserves is 476,550 MMcfe. | ||||||||||||||||
Discounted Future Net Cash Flows | The standardized measure of discounted future net cash flows is as follows: | |||||||||||||||
For the Year Ended December 31, | ||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
(In thousands) | ||||||||||||||||
Future cash inflows | $ | 13,191,866 | $ | 6,892,150 | $ | 6,511,776 | ||||||||||
Future production costs | (4,516,077 | ) | (2,719,024 | ) | (2,258,554 | ) | ||||||||||
Future development costs | (1,222,221 | ) | (685,858 | ) | (620,944 | ) | ||||||||||
Future net cash flows for estimated timing of cash flows (1) | 7,453,568 | 3,487,268 | 3,632,278 | |||||||||||||
10% annual discount for estimated timing of cash flows | (4,693,960 | ) | (1,879,156 | ) | (2,042,362 | ) | ||||||||||
Standardized measure of discounted future net cash flows (2) | $ | 2,759,608 | $ | 1,608,112 | $ | 1,589,916 | ||||||||||
-1 | MEMP is subject to the Texas margin tax which has a maximum effective rate of 0.7% of gross income apportioned to Texas. Due to immateriality we have excluded the impact of this tax for the years ended December 31, 2014, 2013 and 2012. | |||||||||||||||
-2 | MRD Segment’s share of the standardized measure of discounted future net cash flows was $2,760, $142,318 and $554,981 for the years ended December 31, 2014, 2013 and 2012, respectively. | |||||||||||||||
Summary of the Changes in the Standardized Measure of Future Net Cash Flows | The following is a summary of the changes in the standardized measure of discounted future net cash flows for the proved oil and natural gas reserves during each of the years in the three year period ended December 31, 2014: | |||||||||||||||
For the Year Ended December 31, | ||||||||||||||||
2014 | 2013 | 2012 | ||||||||||||||
(In thousands) | ||||||||||||||||
Beginning of year | $ | 1,608,112 | $ | 1,589,916 | $ | 1,499,414 | ||||||||||
Sale of oil and natural gas produced, net of production costs | (323,994 | ) | (234,520 | ) | (160,023 | ) | ||||||||||
Purchase of minerals in place | 1,489,477 | 23,160 | 375,953 | |||||||||||||
Sale of minerals in place | — | — | (154,963 | ) | ||||||||||||
Extensions and discoveries | 44,745 | 136,423 | 265,108 | |||||||||||||
Changes in income taxes, net | — | — | 1,947 | |||||||||||||
Changes in prices and costs | (168,500 | ) | (74,395 | ) | (331,760 | ) | ||||||||||
Previously estimated development costs incurred | 223,861 | 174,490 | 66,360 | |||||||||||||
Net changes in future development costs | (74,579 | ) | (74,867 | ) | (1,140 | ) | ||||||||||
Revisions of previous quantities | (163,207 | ) | (141,122 | ) | (90,587 | ) | ||||||||||
Accretion of discount | 160,811 | 158,991 | 150,136 | |||||||||||||
Change in production rates and other | (37,118 | ) | 50,036 | (30,529 | ) | |||||||||||
End of year | $ | 2,759,608 | $ | 1,608,112 | $ | 1,589,916 | ||||||||||
Organization_and_Basis_of_Pres1
Organization and Basis of Presentation - Additional Information (Detail) (USD $) | 0 Months Ended | 12 Months Ended | 0 Months Ended | 1 Months Ended | 0 Months Ended | 1 Months Ended | 0 Months Ended | 1 Months Ended | ||||||
Jun. 18, 2014 | Dec. 31, 2014 | Dec. 31, 2010 | Oct. 02, 2013 | Apr. 30, 2012 | Mar. 28, 2013 | Jul. 31, 2013 | 31-May-14 | Jul. 16, 2014 | 31-May-12 | Dec. 31, 2013 | Jun. 27, 2014 | Jun. 15, 2014 | Dec. 18, 2013 | |
Segment | ||||||||||||||
Consolidation And Basis Of Presentation [Line Items] | ||||||||||||||
Initial public offering | 21,500,000 | |||||||||||||
Common unit price per share | $19 | |||||||||||||
Proceeds from public offering | $380,200,000 | |||||||||||||
Initial public offering completion date | 18-Jun-14 | |||||||||||||
Common stock, shares issued | 193,435,414 | 0 | ||||||||||||
Senior PIK Toggle Notes, Redemption date | 16-Jul-14 | |||||||||||||
Number of reportable business segments | 2 | |||||||||||||
Business acquisition purchase price | 19,800,000 | |||||||||||||
Tanos Energy LLC [Member] | ||||||||||||||
Consolidation And Basis Of Presentation [Line Items] | ||||||||||||||
Business acquisition purchase price | 77,400,000 | 18,500,000 | ||||||||||||
Prospect Energy LLC [Member] | ||||||||||||||
Consolidation And Basis Of Presentation [Line Items] | ||||||||||||||
Business acquisition purchase price | 16,300,000 | |||||||||||||
Jackson County [Member] | ||||||||||||||
Consolidation And Basis Of Presentation [Line Items] | ||||||||||||||
Business acquisition purchase price | 2,600,000 | |||||||||||||
WHT Energy Partners LLC [Member] | ||||||||||||||
Consolidation And Basis Of Presentation [Line Items] | ||||||||||||||
Business acquisition purchase price | 200,000,000 | |||||||||||||
Limited Partner [Member] | ||||||||||||||
Consolidation And Basis Of Presentation [Line Items] | ||||||||||||||
Partnership ownership percentage | 99.90% | |||||||||||||
General Partner [Member] | ||||||||||||||
Consolidation And Basis Of Presentation [Line Items] | ||||||||||||||
Partnership ownership percentage | 0.10% | |||||||||||||
PIK notes trustee [Member] | ||||||||||||||
Consolidation And Basis Of Presentation [Line Items] | ||||||||||||||
Irrevocable deposits | 360,000,000 | |||||||||||||
MRD [Member] | ||||||||||||||
Consolidation And Basis Of Presentation [Line Items] | ||||||||||||||
Revolving credit facility | 2,000,000,000 | |||||||||||||
Credit facility used | 614,500,000 | |||||||||||||
BlueStone Natural Resources Holdings, LLC [Member] | ||||||||||||||
Consolidation And Basis Of Presentation [Line Items] | ||||||||||||||
Sale of assets | 117,900,000 | |||||||||||||
Golden Energy [Member] | ||||||||||||||
Consolidation And Basis Of Presentation [Line Items] | ||||||||||||||
Sale of assets | 6,700,000 | |||||||||||||
Limited Partners Subordinated Units [Member] | ||||||||||||||
Consolidation And Basis Of Presentation [Line Items] | ||||||||||||||
Subordinated units | 5,360,912 | |||||||||||||
PIK notes [Member] | ||||||||||||||
Consolidation And Basis Of Presentation [Line Items] | ||||||||||||||
Aggregate principal amount | 350,000,000 | 350,000,000 | ||||||||||||
Debt Instrument, maturity date | 15-Dec-18 | |||||||||||||
Debt interest rate, minimum | 10.00% | |||||||||||||
Debt interest rate, maximum | 10.75% | |||||||||||||
Senior PIK Toggle Notes, Redemption price percentage | 102.00% | |||||||||||||
Irrevocable deposits | 360,000,000 | |||||||||||||
MRD Holdco LLC [Member] | ||||||||||||||
Consolidation And Basis Of Presentation [Line Items] | ||||||||||||||
Ownership percentage in MRD LLC after contribution from Funds and prior to redemption of PIK notes | 100.00% | |||||||||||||
Common stock, shares issued | 128,665,677 | |||||||||||||
WildHorse Resources, LLC [Member] | ||||||||||||||
Consolidation And Basis Of Presentation [Line Items] | ||||||||||||||
Proceeds for sale of subsidiary | 200,000 | |||||||||||||
Ownership interest percentage | 99.90% | |||||||||||||
Common stock, shares issued | 42,334,323 | |||||||||||||
Membership interest percentage | 0.10% | |||||||||||||
Cash consideration paid | 30,000,000 | |||||||||||||
Classic [Member] | ||||||||||||||
Consolidation And Basis Of Presentation [Line Items] | ||||||||||||||
Ownership interest percentage | 100.00% | |||||||||||||
Business acquisition purchase price | $27,000,000 | |||||||||||||
Classic GP[Member] | ||||||||||||||
Consolidation And Basis Of Presentation [Line Items] | ||||||||||||||
Ownership interest percentage | 100.00% | |||||||||||||
Black Diamond [Member] | ||||||||||||||
Consolidation And Basis Of Presentation [Line Items] | ||||||||||||||
Ownership interest percentage | 100.00% | |||||||||||||
Beta Operating [Member] | ||||||||||||||
Consolidation And Basis Of Presentation [Line Items] | ||||||||||||||
Ownership interest percentage | 100.00% | |||||||||||||
Memorial Resource Finance Corp [Member] | ||||||||||||||
Consolidation And Basis Of Presentation [Line Items] | ||||||||||||||
Ownership interest percentage | 100.00% | |||||||||||||
MRD Operating [Member] | ||||||||||||||
Consolidation And Basis Of Presentation [Line Items] | ||||||||||||||
Ownership interest percentage | 100.00% | |||||||||||||
Memorial Production Partners GP LLC [Member] | ||||||||||||||
Consolidation And Basis Of Presentation [Line Items] | ||||||||||||||
Ownership interest percentage | 100.00% | |||||||||||||
MEMP GP & MEMP IDRs [Member] | ||||||||||||||
Consolidation And Basis Of Presentation [Line Items] | ||||||||||||||
Ownership interest percentage | 50.00% |
Summary_of_Significant_Account3
Summary of Significant Accounting Policies - Additional Information (Detail) (USD $) | 12 Months Ended | |||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Jun. 30, 2014 | |
Summary Of Significant Accounting Policies [Line Items] | ||||
Capitalized exploratory drilling costs | $0 | $0 | $0 | |
Impairment of proved oil and natural gas properties | 432,116,000 | 6,600,000 | 28,871,000 | |
Amortization expense, including write-offs of debt issuance costs | 7,436,000 | 8,343,000 | 3,584,000 | |
Capitalized interest | 7,300,000 | 0 | 0 | |
Minimum percentage likelihood of tax benefit to be realized | 50.00% | |||
Unrecognized tax benefits | 0 | 0 | 0 | |
Unrecognized tax benefits that would affect effective tax rate | 0 | |||
Interest or penalties recognized in consolidated statements of operations | 0 | |||
Interest or penalties recognized in consolidated balance sheets | 0 | |||
Deferred tax liabilities | $43,300,000 | |||
Minimum [Member] | ||||
Summary Of Significant Accounting Policies [Line Items] | ||||
Estimated useful lives | 3 years | |||
Maximum [Member] | ||||
Summary Of Significant Accounting Policies [Line Items] | ||||
Estimated useful lives | 7 years |
Summary_of_Significant_Account4
Summary of Significant Accounting Policies - Individual Customers Each Accounted for 10% or More of Total Reported Revenues (Detail) (Sales Revenue, Net [Member], Customer Concentration Risk [Member]) | 12 Months Ended | |||||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | ||||
Sinclair Oil and Gas Company [Member] | ||||||
Entity Wide Revenue Major Customer [Line Items] | ||||||
Individual customers each accounted for 10% or more of total reported revenues | 12.00% | |||||
Consolidated & Combined [Member] | Energy Transfer Equity, LP. and subsidiaries [Member] | ||||||
Entity Wide Revenue Major Customer [Line Items] | ||||||
Individual customers each accounted for 10% or more of total reported revenues | 33.00% | 35.00% | 13.00% | |||
MRD [Member] | Energy Transfer Equity, LP. and subsidiaries [Member] | ||||||
Entity Wide Revenue Major Customer [Line Items] | ||||||
Individual customers each accounted for 10% or more of total reported revenues | 73.00% | 77.00% | 39.00% | |||
MRD [Member] | Sunoco Inc [Member] | ||||||
Entity Wide Revenue Major Customer [Line Items] | ||||||
Individual customers each accounted for 10% or more of total reported revenues | 15.00% | [1] | ||||
MRD [Member] | Dominion Gas Ventures LP [Member] | ||||||
Entity Wide Revenue Major Customer [Line Items] | ||||||
Individual customers each accounted for 10% or more of total reported revenues | 15.00% | |||||
MEMP [Member] | Phillips 66 [Member] | ||||||
Entity Wide Revenue Major Customer [Line Items] | ||||||
Individual customers each accounted for 10% or more of total reported revenues | 13.00% | [2] | 15.00% | [2] | 13.00% | [2] |
MEMP [Member] | ConocoPhillips [Member] | ||||||
Entity Wide Revenue Major Customer [Line Items] | ||||||
Individual customers each accounted for 10% or more of total reported revenues | 14.00% | |||||
[1] | Sunoco, Inc. became a subsidiary of Energy Transfer Equity, L.P. in October 2012. | |||||
[2] | Phillips 66 was a subsidiary of ConocoPhillips through AprilB 30, 2012. Accordingly, any revenues generated from Phillips 66 prior to MayB 1, 2012 were reported under ConocoPhillips. |
Summary_of_Significant_Account5
Summary of Significant Accounting Policies - Schedule of Accrued Liabilities (Detail) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Accounting Policies [Abstract] | ||
Accrued capital expenditures | $80,350 | $48,579 |
Accrued lease operating expense | 16,403 | 13,240 |
Accrued general and administrative expenses | 8,516 | 14,485 |
Accrued ad valorem and production taxes | 8,870 | 3,541 |
Accrued interest payable | 24,797 | 11,934 |
Accrued environmental | 2,092 | 577 |
Accrued current deferred income taxes | 51,929 | 382 |
Other miscellaneous, including operator advances | 6,043 | 5,392 |
Accrued liabilities | $199,000 | $98,130 |
Summary_of_Significant_Account6
Summary of Significant Accounting Policies - Schedule of Supplemental Cash flow (Detail) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Supplemental cash flows: | |||
Cash paid for interest, net of amounts capitalized | $130,732 | $61,140 | $23,525 |
Income tax paid | 838 | 168 | 22 |
Noncash investing and financing activities: | |||
Change in capital expenditures in payables and accrued liabilities | 31,771 | 41,017 | 17,158 |
Assumptions of asset retirement obligations related to properties acquired or drilled | 5,420 | 4,227 | 7,962 |
Distributions to noncontrolling interests | 0 | 0 | 47 |
Repurchase of equity under repurchase program | 3,425 | 0 | 0 |
Accounts receivable related to acquisitions | 9,569 | 0 | 0 |
Natural Gas Partners [Member] | |||
Noncash investing and financing activities: | |||
Contribution of oil and gas properties from NGP affiliate | 0 | 0 | 6,893 |
Accrued distribution to NGP affiliates related to Cinco Group acquisitions | 0 | 4,352 | 0 |
Contribution related to sale of assets to NGP affiliate - restricted cash | 0 | 0 | 2,013 |
MEMP [Member] | |||
Noncash investing and financing activities: | |||
Accrued equity offering costs | $0 | $0 | $171 |
Acquisitions_and_Divestitures_1
Acquisitions and Divestitures - Acquisition Related Costs (Detail) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Business Acquisition [Line Items] | |||
Acquisition related costs | $6,668 | $8,313 | $4,538 |
General and administrative expense [Member] | |||
Business Acquisition [Line Items] | |||
Acquisition related costs | $6,668 | $8,313 | $4,538 |
Acquisitions_and_Divestitures_2
Acquisitions and Divestitures - Additional Information (Detail) (USD $) | 12 Months Ended | 0 Months Ended | 3 Months Ended | 0 Months Ended | 1 Months Ended | |||||||||||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Apr. 30, 2013 | 9-May-14 | Jul. 11, 2012 | Sep. 18, 2012 | Dec. 30, 2014 | Dec. 31, 2014 | Jul. 01, 2014 | Mar. 25, 2014 | Jan. 01, 2013 | 10-May-13 | 1-May-12 | Sep. 28, 2012 | Jul. 31, 2012 | |
Business Acquisition [Line Items] | ||||||||||||||||
Proceeds from the sale of oil and natural gas properties | $6,700,000 | $155,712,000 | $34,521,000 | |||||||||||||
Subsidiaries [Member] | ||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||
Proceeds from divestitures | 3,300,000 | |||||||||||||||
Gain (loss) on sale of oil and gas properties | -100,000 | |||||||||||||||
Series of Individually Immaterial Business Acquisitions [Member] | ||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||
Payments to acquire oil and gas properties and leases | 10,200,000 | |||||||||||||||
WildHorse Resources, LLC [Member] | ||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||
Payments to acquire oil and gas properties and leases | 67,100,000 | |||||||||||||||
Northern Oklahoma [Member] | ||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||
Proceeds from divestitures | 7,600,000 | |||||||||||||||
Gain (loss) on sale of oil and gas properties | -3,200,000 | |||||||||||||||
Garza County, Texas [Member] | ||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||
Proceeds from divestitures | 26,100,000 | |||||||||||||||
Gain (loss) on sale of oil and gas properties | 7,600,000 | |||||||||||||||
Ector County, Texas [Member] | ||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||
Proceeds from divestitures | 4,700,000 | |||||||||||||||
Gain (loss) on sale of oil and gas properties | 2,200,000 | |||||||||||||||
Terryville Acquisition [Member] | ||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||
Payments to acquire oil and gas properties and leases | 71,900,000 | 24,000,000 | ||||||||||||||
Wyoming Acquisition [Member] | ||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||
Payments to acquire oil and gas properties and leases | 906,100,000 | |||||||||||||||
Business acquisition, revenues | 72,000,000 | |||||||||||||||
Business acquisition, earnings | 22,900,000 | |||||||||||||||
Eagle Ford Acquisition [Member] | ||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||
Payments to acquire oil and gas properties and leases | 168,100,000 | |||||||||||||||
Business acquisition, revenues | 36,500,000 | |||||||||||||||
Business acquisition, earnings | 16,300,000 | |||||||||||||||
Percentage of leasehold interest acquired | 30.00% | |||||||||||||||
East Texas Acquisition and Rockies Acquisition [Member] | ||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||
Payments to acquire oil and gas properties and leases | 29,400,000 | |||||||||||||||
Propel Energy [Member] | ||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||
Payments to acquire oil and gas properties and leases | 9,300,000 | |||||||||||||||
Tanos [Member] | Natural Gas Pipe Lines [Member] | ||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||
Gain (loss) on sale of oil and gas properties | 1,400,000 | |||||||||||||||
Period for drilling any new wells | 3 years | |||||||||||||||
Contingent consideration related to sale of natural gas pipeline | 400,000 | |||||||||||||||
Tanos [Member] | Natural Gas Pipe Lines [Member] | Minimum [Member] | ||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||
Proceeds from divestitures | 1,500,000 | |||||||||||||||
Tanos [Member] | Natural Gas Pipe Lines [Member] | Maximum [Member] | ||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||
Proceeds from divestitures | 2,000,000 | |||||||||||||||
Tanos [Member] | Oil And Natural Gas Properties [Member] | ||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||
Proceeds from divestitures | 2,900,000 | |||||||||||||||
Tanos [Member] | Non Operated Oil And Natural Gas Properties [Member] | ||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||
Gain (loss) on sale of oil and gas properties | 1,400,000 | |||||||||||||||
Black Diamond [Member] | ||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||
Proceeds from divestitures | 33,000,000 | |||||||||||||||
Gain (loss) on sale of oil and gas properties | -6,800,000 | |||||||||||||||
Net book value of oil and gas properties | 39,800,000 | |||||||||||||||
BlueStone Natural Resources Holdings, LLC [Member] | ||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||
Gain (loss) on sale of oil and gas properties | 89,500,000 | |||||||||||||||
Proceeds from the sale of oil and natural gas properties | 117,900,000 | |||||||||||||||
Undisclosed Seller Acquisition [Member] | ||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||
Payments to acquire oil and gas properties and leases | 112,100,000 | |||||||||||||||
Business acquisition, revenues | 22,100,000 | |||||||||||||||
Business acquisition, earnings | 9,200,000 | |||||||||||||||
Goodrich Acquisition [Member] | ||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||
Payments to acquire oil and gas properties and leases | 90,400,000 | |||||||||||||||
Business acquisition, revenues | 4,600,000 | |||||||||||||||
Business acquisition, earnings | 2,000,000 | |||||||||||||||
Texas And New Mexico [Member] | ||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||
Payments to acquire oil and gas properties and leases | 147,900,000 | |||||||||||||||
Menemsha Acquisition [Member] | ||||||||||||||||
Business Acquisition [Line Items] | ||||||||||||||||
Payments to acquire oil and gas properties and leases | 74,700,000 | |||||||||||||||
Business acquisition, revenues | 4,900,000 | |||||||||||||||
Business acquisition, earnings | $900,000 |
Acquisitions_and_Divestitures_3
Acquisitions and Divestitures - Summary of Fair Value Assessment of Assets Acquired and Liabilities Assumed (Detail) (USD $) | Dec. 30, 2014 | Apr. 30, 2013 | Sep. 06, 2013 | Aug. 30, 2013 | 1-May-12 | Sep. 28, 2012 | Jul. 31, 2012 | Dec. 31, 2012 | Mar. 25, 2014 | Jul. 01, 2014 |
In Thousands, unless otherwise specified | ||||||||||
Louisiana [Member] | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Oil and gas properties | $72,141 | $68,887 | ||||||||
Asset retirement obligations | -271 | -1,789 | ||||||||
Total identifiable net assets | 71,870 | 67,098 | ||||||||
East Texas Acquisition [Member] | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Oil and gas properties | 9,974 | |||||||||
Asset retirement obligations | -78 | |||||||||
Total identifiable net assets | 9,896 | |||||||||
Rockies Acquisition [Member] | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Oil and gas properties | 20,744 | |||||||||
Asset retirement obligations | -1,163 | |||||||||
Accrued liabilities | -118 | |||||||||
Total identifiable net assets | 19,463 | |||||||||
Undisclosed Seller Acquisition [Member] | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Oil and gas properties | 115,633 | |||||||||
Asset retirement obligations | -1,592 | |||||||||
Revenue Payable | -1,602 | |||||||||
Accrued liabilities | -297 | |||||||||
Total identifiable net assets | 112,142 | |||||||||
Goodrich Acquisition [Member] | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Oil and gas properties | 91,187 | |||||||||
Prepaid expenses and other current assets | 425 | |||||||||
Asset retirement obligations | -161 | |||||||||
Revenue Payable | -875 | |||||||||
Accrued liabilities | -153 | |||||||||
Total identifiable net assets | 90,423 | |||||||||
Menemsha Acquisition [Member] | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Oil and gas properties | 75,114 | |||||||||
Asset retirement obligations | -408 | |||||||||
Total identifiable net assets | 74,706 | |||||||||
Other Acquisitions [Member] | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Oil and gas properties | 77,764 | |||||||||
Asset retirement obligations | -4,558 | |||||||||
Total identifiable net assets | 73,206 | |||||||||
MEMP [Member] | Eagle Ford Acquisition [Member] | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Oil and gas properties | 168,606 | |||||||||
Asset retirement obligations | -285 | |||||||||
Accrued liabilities | -250 | |||||||||
Total identifiable net assets | 168,071 | |||||||||
MEMP [Member] | Wyoming Acquisition [Member] | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Oil and gas properties | 930,168 | |||||||||
Asset retirement obligations | -3,980 | |||||||||
Revenue Payable | -375 | |||||||||
Accrued liabilities | -19,693 | |||||||||
Total identifiable net assets | $906,120 |
Acquisitions_and_Divestitures_4
Acquisitions and Divestitures - Unaudited Pro Forma Results of Operations (Detail) (USD $) | 12 Months Ended | ||
In Thousands, except Per Share data, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Business Combinations [Abstract] | |||
Revenues | $990,544 | $761,443 | $431,060 |
Net income (loss) | ($602,044) | $257,839 | $40,940 |
Basic earnings per share | ($4.08) | ||
Diluted earnings per share | ($4.08) |
Fair_Value_Measurements_of_Fin2
Fair Value Measurements of Financial Instruments - Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) (Fair Value, Measurements [Member], USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Assets: | ||
Fair value of derivative asset | $847,064 | $105,938 |
Liabilities: | ||
Fair value of derivative liability | 74,928 | 63,824 |
Significant Other Observable Inputs (Level 2) [Member] | ||
Assets: | ||
Fair value of derivative asset | 847,064 | 105,938 |
Liabilities: | ||
Fair value of derivative liability | 74,928 | 63,824 |
Commodity derivatives [Member] | ||
Assets: | ||
Fair value of derivative asset | 845,759 | 105,054 |
Liabilities: | ||
Fair value of derivative liability | 71,639 | 58,234 |
Commodity derivatives [Member] | Significant Other Observable Inputs (Level 2) [Member] | ||
Assets: | ||
Fair value of derivative asset | 845,759 | 105,054 |
Liabilities: | ||
Fair value of derivative liability | 71,639 | 58,234 |
Interest rate derivatives [Member] | ||
Assets: | ||
Fair value of derivative asset | 1,305 | 884 |
Liabilities: | ||
Fair value of derivative liability | 3,289 | 5,590 |
Interest rate derivatives [Member] | Significant Other Observable Inputs (Level 2) [Member] | ||
Assets: | ||
Fair value of derivative asset | 1,305 | 884 |
Liabilities: | ||
Fair value of derivative liability | $3,289 | $5,590 |
Fair_Value_Measurements_of_Fin3
Fair Value Measurements of Financial Instruments - Additional Information (Detail) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||
Impairment of proved oil and natural gas properties | $432,116,000 | $6,600,000 | $28,871,000 |
MEMP [Member] | |||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||
Impairment of proved oil and natural gas properties | 407,500,000 | 28,871,000 | |
MEMP [Member] | Permian Basin Properties [Member] | |||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||
Impairment of proved oil and natural gas properties | 234,200,000 | ||
Carrying value of oil and gas properties after impairment | 88,700,000 | ||
MEMP [Member] | East Texas Properties [Member] | |||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||
Impairment of proved oil and natural gas properties | 107,600,000 | 20,900,000 | |
Carrying value of oil and gas properties after impairment | 88,800,000 | ||
MEMP [Member] | South Texas Properties [Member] | |||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||
Impairment of proved oil and natural gas properties | 65,600,000 | ||
Carrying value of oil and gas properties after impairment | 71,200,000 | ||
MEMP [Member] | Elkhorn and Canyon Fields (Member) | |||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||
Impairment of proved oil and natural gas properties | 8,000,000 | ||
MRD [Member] | |||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||
Impairment of proved oil and natural gas properties | $24,600,000 |
Risk_Management_and_Derivative2
Risk Management and Derivative Instruments - Additional Information (Detail) (USD $) | 12 Months Ended | |
Dec. 31, 2014 | Jul. 01, 2014 | |
Derivative Instruments, Gain (Loss) [Line Items] | ||
Conditional rights of set-off under ISDA Master Agreement reduce the maximum amount of loss due to credit risk | $99,200,000 | |
Effect netting arrangements, counterparty exposure | 155,800,000 | |
Derivative asset | 255,000,000 | |
Cash settlement receipt | 6,100,000 | |
Cash collateral received or pledged | 0 | |
Interest rate swaps [Member] | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Aggregate termination amount paid to counterparties | 700,000 | |
Single Counterparty [Member] | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Effect netting arrangements, counterparty exposure | 109,700,000 | |
MEMP [Member] | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Conditional rights of set-off under ISDA Master Agreement reduce the maximum amount of loss due to credit risk | 207,300,000 | |
Effect netting arrangements, counterparty exposure | 309,800,000 | |
Derivative asset | $517,100,000 |
Risk_Management_and_Derivative3
Risk Management and Derivative Instruments - Schedule of Open Commodity Positions (Detail) | 12 Months Ended | |
Dec. 31, 2014 | ||
MMBTU | ||
2015 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | Fixed price swap contracts [Member] | ||
Derivative [Line Items] | ||
Average Monthly Volume (MMBtu) | 3,700,000 | |
Weighted-average fixed price | 4.15 | |
2015 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | Collar contracts [Member] | ||
Derivative [Line Items] | ||
Average Monthly Volume (MMBtu) | 130,000 | |
Weighted-average floor price | 4 | |
Weighted-average ceiling price | 4.64 | |
2015 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | Put Option [Member] | ||
Derivative [Line Items] | ||
Average Monthly Volume (MMBtu) | 3,000,000 | |
Weighted-average fixed price | 3.75 | |
Weighted-average deferred premium | -0.33 | |
2015 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | TGT Z1 basis swaps [Member] | ||
Derivative [Line Items] | ||
Average Monthly Volume (MMBtu) | 1,730,000 | |
2015 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | TGT Z1 basis swaps [Member] | Henry Hub [Member] | ||
Derivative [Line Items] | ||
Spread | -0.09 | |
2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member] | ||
Derivative [Line Items] | ||
Average Monthly Volume (MMBtu) | 2,605,278 | |
Weighted-average fixed price | 4.28 | |
2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Collar contracts [Member] | ||
Derivative [Line Items] | ||
Average Monthly Volume (MMBtu) | 350,000 | |
Weighted-average floor price | 4.62 | |
Weighted-average ceiling price | 5.8 | |
2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Call Spreads [Member] | ||
Derivative [Line Items] | ||
Average Monthly Volume (MMBtu) | 80,000 | [1] |
Weighted-average sold strike price | 5.25 | [1] |
Weighted-average bought strike price | 6.75 | [1] |
2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Basis Swaps [Member] | ||
Derivative [Line Items] | ||
Average Monthly Volume (MMBtu) | 2,940,000 | |
Spread | -0.12 | |
2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | NGPL TexOk basis swaps [Member] | ||
Derivative [Line Items] | ||
Average Monthly Volume (MMBtu) | 2,280,000 | |
2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | NGPL TexOk basis swaps [Member] | Henry Hub [Member] | ||
Derivative [Line Items] | ||
Spread | -0.11 | |
2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | HSC basis swaps [Member] | ||
Derivative [Line Items] | ||
Average Monthly Volume (MMBtu) | 150,000 | |
2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | HSC basis swaps [Member] | Henry Hub [Member] | ||
Derivative [Line Items] | ||
Spread | -0.08 | |
2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | CIG basis swaps [Member] | ||
Derivative [Line Items] | ||
Average Monthly Volume (MMBtu) | 210,000 | |
2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | CIG basis swaps [Member] | Henry Hub [Member] | ||
Derivative [Line Items] | ||
Spread | -0.25 | |
2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | TETCO STX basis swaps [Member] | ||
Derivative [Line Items] | ||
Average Monthly Volume (MMBtu) | 300,000 | |
2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | TETCO STX basis swaps [Member] | Henry Hub [Member] | ||
Derivative [Line Items] | ||
Spread | -0.09 | |
2015 [Member] | Crude Oil Derivative Contracts [Member] | MRD [Member] | Fixed price swap contracts [Member] | ||
Derivative [Line Items] | ||
Weighted-average fixed price | 91.67 | |
Average Monthly Volume (Bbls) | 46,500 | |
2015 [Member] | Crude Oil Derivative Contracts [Member] | MRD [Member] | Collar contracts [Member] | ||
Derivative [Line Items] | ||
Weighted-average floor price | 85 | |
Weighted-average ceiling price | 101.35 | |
Average Monthly Volume (Bbls) | 2,000 | |
2015 [Member] | Crude Oil Derivative Contracts [Member] | MRD [Member] | Put Option [Member] | ||
Derivative [Line Items] | ||
Weighted-average deferred premium | -3.8 | |
Average Monthly Volume (Bbls) | 26,000 | |
Weighted-average fixed price | 85 | |
2015 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member] | ||
Derivative [Line Items] | ||
Weighted-average fixed price | 90.96 | |
Average Monthly Volume (Bbls) | 314,281 | |
2015 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Collar contracts [Member] | ||
Derivative [Line Items] | ||
Weighted-average floor price | 80 | |
Weighted-average ceiling price | 94 | |
Average Monthly Volume (Bbls) | 5,000 | |
2015 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Basis Swaps [Member] | ||
Derivative [Line Items] | ||
Spread | -7.07 | |
Average Monthly Volume (Bbls) | 97,500 | |
2015 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Midway-Sunset basis swaps [Member] | ||
Derivative [Line Items] | ||
Average Monthly Volume (Bbls) | 57,500 | |
2015 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Midway-Sunset basis swaps [Member] | Brent [Member] | ||
Derivative [Line Items] | ||
Spread | -9.73 | |
2015 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Midland Basis Swap [Member] | ||
Derivative [Line Items] | ||
Average Monthly Volume (Bbls) | 40,000 | |
2015 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Midland Basis Swap [Member] | WTI [Member] | ||
Derivative [Line Items] | ||
Spread | -3.25 | |
2015 [Member] | NGL Derivative Contracts [Member] | MRD [Member] | Fixed price swap contracts [Member] | ||
Derivative [Line Items] | ||
Weighted-average fixed price | 41.61 | |
Average Monthly Volume (Bbls) | 151,000 | |
2015 [Member] | NGL Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member] | ||
Derivative [Line Items] | ||
Weighted-average fixed price | 43.02 | |
Average Monthly Volume (Bbls) | 149,200 | |
2016 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | Fixed price swap contracts [Member] | ||
Derivative [Line Items] | ||
Average Monthly Volume (MMBtu) | 2,570,000 | |
Weighted-average fixed price | 4.09 | |
2016 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | Collar contracts [Member] | ||
Derivative [Line Items] | ||
Average Monthly Volume (MMBtu) | 1,100,000 | |
Weighted-average floor price | 4 | |
Weighted-average ceiling price | 4.71 | |
2016 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | Put Option [Member] | ||
Derivative [Line Items] | ||
Average Monthly Volume (MMBtu) | 4,100,000 | |
Weighted-average fixed price | 3.75 | |
Weighted-average deferred premium | -0.36 | |
2016 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | TGT Z1 basis swaps [Member] | ||
Derivative [Line Items] | ||
Average Monthly Volume (MMBtu) | 220,000 | |
2016 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | TGT Z1 basis swaps [Member] | Henry Hub [Member] | ||
Derivative [Line Items] | ||
Spread | -0.08 | |
2016 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member] | ||
Derivative [Line Items] | ||
Average Monthly Volume (MMBtu) | 2,692,442 | |
Weighted-average fixed price | 4.4 | |
2016 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Basis Swaps [Member] | ||
Derivative [Line Items] | ||
Average Monthly Volume (MMBtu) | 2,508,333 | |
Spread | -0.04 | |
2016 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | NGPL TexOk basis swaps [Member] | ||
Derivative [Line Items] | ||
Average Monthly Volume (MMBtu) | 2,103,333 | |
2016 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | NGPL TexOk basis swaps [Member] | Henry Hub [Member] | ||
Derivative [Line Items] | ||
Spread | -0.06 | |
2016 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | HSC basis swaps [Member] | ||
Derivative [Line Items] | ||
Average Monthly Volume (MMBtu) | 135,000 | |
2016 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | HSC basis swaps [Member] | Henry Hub [Member] | ||
Derivative [Line Items] | ||
Spread | 0.07 | |
2016 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | TETCO STX basis swaps [Member] | ||
Derivative [Line Items] | ||
Average Monthly Volume (MMBtu) | 270,000 | |
2016 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | TETCO STX basis swaps [Member] | Henry Hub [Member] | ||
Derivative [Line Items] | ||
Spread | 0.06 | |
2016 [Member] | Crude Oil Derivative Contracts [Member] | MRD [Member] | Fixed price swap contracts [Member] | ||
Derivative [Line Items] | ||
Weighted-average fixed price | 84.8 | |
Average Monthly Volume (Bbls) | 8,500 | |
2016 [Member] | Crude Oil Derivative Contracts [Member] | MRD [Member] | Collar contracts [Member] | ||
Derivative [Line Items] | ||
Weighted-average floor price | 80 | |
Weighted-average ceiling price | 99.7 | |
Average Monthly Volume (Bbls) | 27,000 | |
2016 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member] | ||
Derivative [Line Items] | ||
Weighted-average fixed price | 85.83 | |
Average Monthly Volume (Bbls) | 332,813 | |
2016 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Basis Swaps [Member] | ||
Derivative [Line Items] | ||
Spread | -9.56 | |
Average Monthly Volume (Bbls) | 95,000 | |
2016 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Midway-Sunset basis swaps [Member] | ||
Derivative [Line Items] | ||
Average Monthly Volume (Bbls) | 55,000 | |
2016 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Midway-Sunset basis swaps [Member] | Brent [Member] | ||
Derivative [Line Items] | ||
Spread | -13.35 | |
2016 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Midland Basis Swap [Member] | ||
Derivative [Line Items] | ||
Average Monthly Volume (Bbls) | 40,000 | |
2016 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Midland Basis Swap [Member] | WTI [Member] | ||
Derivative [Line Items] | ||
Spread | -4.34 | |
2016 [Member] | NGL Derivative Contracts [Member] | MRD [Member] | Fixed price swap contracts [Member] | ||
Derivative [Line Items] | ||
Weighted-average fixed price | 34.06 | |
Average Monthly Volume (Bbls) | 185,658 | |
2016 [Member] | NGL Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member] | ||
Derivative [Line Items] | ||
Weighted-average fixed price | 41.49 | |
Average Monthly Volume (Bbls) | 84,600 | |
2017 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | Fixed price swap contracts [Member] | ||
Derivative [Line Items] | ||
Average Monthly Volume (MMBtu) | 1,770,000 | |
Weighted-average fixed price | 4.24 | |
2017 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | Collar contracts [Member] | ||
Derivative [Line Items] | ||
Average Monthly Volume (MMBtu) | 1,050,000 | |
Weighted-average floor price | 4 | |
Weighted-average ceiling price | 5.06 | |
2017 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | Put Option [Member] | ||
Derivative [Line Items] | ||
Average Monthly Volume (MMBtu) | 3,450,000 | |
Weighted-average fixed price | 3.75 | |
Weighted-average deferred premium | -0.35 | |
2017 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | TGT Z1 basis swaps [Member] | ||
Derivative [Line Items] | ||
Average Monthly Volume (MMBtu) | 200,000 | |
2017 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | TGT Z1 basis swaps [Member] | Henry Hub [Member] | ||
Derivative [Line Items] | ||
Spread | -0.08 | |
2017 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member] | ||
Derivative [Line Items] | ||
Average Monthly Volume (MMBtu) | 2,450,067 | |
Weighted-average fixed price | 4.31 | |
2017 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Basis Swaps [Member] | ||
Derivative [Line Items] | ||
Average Monthly Volume (MMBtu) | 415,000 | |
Spread | 0 | |
2017 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | NGPL TexOk basis swaps [Member] | ||
Derivative [Line Items] | ||
Average Monthly Volume (MMBtu) | 300,000 | |
2017 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | NGPL TexOk basis swaps [Member] | Henry Hub [Member] | ||
Derivative [Line Items] | ||
Spread | -0.05 | |
2017 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | HSC basis swaps [Member] | ||
Derivative [Line Items] | ||
Average Monthly Volume (MMBtu) | 115,000 | |
2017 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | HSC basis swaps [Member] | Henry Hub [Member] | ||
Derivative [Line Items] | ||
Spread | 0.14 | |
2017 [Member] | Crude Oil Derivative Contracts [Member] | MRD [Member] | Fixed price swap contracts [Member] | ||
Derivative [Line Items] | ||
Weighted-average fixed price | 84.7 | |
Average Monthly Volume (Bbls) | 28,000 | |
2017 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member] | ||
Derivative [Line Items] | ||
Weighted-average fixed price | 84.38 | |
Average Monthly Volume (Bbls) | 326,600 | |
2018 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | Fixed price swap contracts [Member] | ||
Derivative [Line Items] | ||
Average Monthly Volume (MMBtu) | 2,900,000 | |
Weighted-average fixed price | 4.27 | |
2018 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | Put Option [Member] | ||
Derivative [Line Items] | ||
Average Monthly Volume (MMBtu) | 2,850,000 | |
Weighted-average fixed price | 3.75 | |
Weighted-average deferred premium | -0.35 | |
2018 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member] | ||
Derivative [Line Items] | ||
Average Monthly Volume (MMBtu) | 2,160,000 | |
Weighted-average fixed price | 4.51 | |
2018 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Basis Swaps [Member] | ||
Derivative [Line Items] | ||
Average Monthly Volume (MMBtu) | 115,000 | |
Spread | 0.15 | |
2018 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | HSC basis swaps [Member] | ||
Derivative [Line Items] | ||
Average Monthly Volume (MMBtu) | 115,000 | |
2018 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | HSC basis swaps [Member] | Henry Hub [Member] | ||
Derivative [Line Items] | ||
Spread | 0.15 | |
2018 [Member] | Crude Oil Derivative Contracts [Member] | MRD [Member] | Fixed price swap contracts [Member] | ||
Derivative [Line Items] | ||
Weighted-average fixed price | 84.5 | |
Average Monthly Volume (Bbls) | 31,625 | |
2018 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member] | ||
Derivative [Line Items] | ||
Weighted-average fixed price | 83.74 | |
Average Monthly Volume (Bbls) | 312,000 | |
2019 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member] | ||
Derivative [Line Items] | ||
Average Monthly Volume (MMBtu) | 1,914,583 | |
Weighted-average fixed price | 4.75 | |
2019 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member] | ||
Derivative [Line Items] | ||
Weighted-average fixed price | 85.52 | |
Average Monthly Volume (Bbls) | 160,000 | |
[1] | These transactions were entered into for the purpose of eliminating the ceiling portion of certain collar arrangements, which effectively converted the applicable collars into swaps. |
Risk_Management_and_Derivative4
Risk Management and Derivative Instruments - Schedule of Entity's Interest Rate Swap Open Positions (Detail) (MEMP [Member], Interest rate swaps [Member], USD $) | 12 Months Ended |
In Thousands, unless otherwise specified | Dec. 31, 2014 |
2015 [Member] | |
Derivative [Line Items] | |
Average Monthly Notional | $314,167 |
Weighted-average fixed rate | 1.35% |
Floating rate | 1 Month LIBOR |
2016 [Member] | |
Derivative [Line Items] | |
Average Monthly Notional | 250,000 |
Weighted-average fixed rate | 1.03% |
Floating rate | 1 Month LIBOR |
2017 [Member] | |
Derivative [Line Items] | |
Average Monthly Notional | $250,000 |
Weighted-average fixed rate | 1.62% |
Floating rate | 1 Month LIBOR |
Risk_Management_and_Derivative5
Risk Management and Derivative Instruments - Summary of Gross Fair Value and Net Recorded Fair Value of Derivative Instruments by Appropriate Balance Sheet Classification (Detail) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Derivative Instruments and Hedges, Assets [Abstract] | ||
Asset Derivatives, Net recorded fair value | $340,056 | $9,289 |
Asset Derivatives, Net recorded fair value | 435,369 | 48,616 |
Liability Derivatives, Net recorded fair value | 3,289 | 9,711 |
Liability Derivatives, Net recorded fair value | 6,080 | |
Short-term derivative instruments [Member] | ||
Derivative Instruments and Hedges, Assets [Abstract] | ||
Asset Derivatives, Gross fair value | 378,908 | 22,604 |
Asset Derivatives, Netting arrangements | -38,852 | -13,315 |
Asset Derivatives, Net recorded fair value | 340,056 | 9,289 |
Liability Derivatives, Gross fair value | 42,141 | 23,026 |
Liability Derivatives, Netting arrangements | -38,852 | -13,315 |
Liability Derivatives, Net recorded fair value | 3,289 | 9,711 |
Short-term derivative instruments [Member] | Commodity contracts [Member] | ||
Derivative Instruments and Hedges, Assets [Abstract] | ||
Asset Derivatives, Gross fair value | 378,908 | 21,759 |
Liability Derivatives, Gross fair value | 38,852 | 19,739 |
Short-term derivative instruments [Member] | Interest rate swaps [Member] | ||
Derivative Instruments and Hedges, Assets [Abstract] | ||
Asset Derivatives, Gross fair value | 845 | |
Liability Derivatives, Gross fair value | 3,289 | 3,287 |
Long-term derivative instruments [Member] | ||
Derivative Instruments and Hedges, Assets [Abstract] | ||
Asset Derivatives, Gross fair value | 468,156 | 83,334 |
Asset Derivatives, Netting arrangements | -32,787 | -34,718 |
Asset Derivatives, Net recorded fair value | 435,369 | 48,616 |
Liability Derivatives, Gross fair value | 32,787 | 40,798 |
Liability Derivatives, Netting arrangements | -32,787 | -34,718 |
Liability Derivatives, Net recorded fair value | 6,080 | |
Long-term derivative instruments [Member] | Commodity contracts [Member] | ||
Derivative Instruments and Hedges, Assets [Abstract] | ||
Asset Derivatives, Gross fair value | 466,851 | 83,295 |
Liability Derivatives, Gross fair value | 32,787 | 38,495 |
Long-term derivative instruments [Member] | Interest rate swaps [Member] | ||
Derivative Instruments and Hedges, Assets [Abstract] | ||
Asset Derivatives, Gross fair value | 1,305 | 39 |
Liability Derivatives, Gross fair value | $2,303 |
Risk_Management_and_Derivative6
Risk Management and Derivative Instruments - Schedule of Gains and Losses Related to Derivative Instruments (Detail) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Gain (Loss) on Derivative Instruments, Net, Pretax [Abstract] | |||
(Gain) loss on commodity derivative instruments | ($749,988) | ($29,294) | ($34,905) |
Interest expense, net | 133,833 | 69,250 | 33,238 |
Commodity contracts [Member] | |||
Gain (Loss) on Derivative Instruments, Net, Pretax [Abstract] | |||
(Gain) loss on commodity derivative instruments | -749,988 | -29,294 | -34,905 |
Interest rate derivatives [Member] | |||
Gain (Loss) on Derivative Instruments, Net, Pretax [Abstract] | |||
Interest expense, net | $145 | ($239) | $5,582 |
Asset_Retirement_Obligations_S
Asset Retirement Obligations - Summary of Changes in Asset Retirement Obligations (Detail) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Asset Retirement Obligation Disclosure [Abstract] | |||
Asset retirement obligations at beginning of period | $111,769 | $102,380 | $90,699 |
Liabilities added from acquisitions or drilling | 5,420 | 4,227 | 7,962 |
Liabilities removed upon sale of wells | -669 | -1,765 | -1,931 |
Liabilities removed upon plugging and abandoning | -588 | -170 | -119 |
Revisions | 293 | 1,516 | 760 |
Accretion expense | 6,306 | 5,581 | 5,009 |
Asset retirement obligations at end of period | 122,531 | 111,769 | 102,380 |
Less: Current portion | 90 | 390 | |
Asset retirement obligationsb long-term portion | $122,531 | $111,679 | $101,990 |
Restricted_Investments_Restric
Restricted Investments - Restricted Investment Balance (Detail) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Schedule Of Investments [Line Items] | ||
Restricted investments | $77,361 | $73,385 |
BOEM platform abandonment [Member] | ||
Schedule Of Investments [Line Items] | ||
Restricted investments | 69,954 | 66,373 |
BOEM lease bonds [Member] | ||
Schedule Of Investments [Line Items] | ||
Restricted investments | 794 | 794 |
SPBPC Collateral Contractual pipeline and surface facilities abandonment [Member] | ||
Schedule Of Investments [Line Items] | ||
Restricted investments | 2,701 | 2,306 |
SPBPC Collateral California State Lands Commission pipeline right-of-way bond [Member] | ||
Schedule Of Investments [Line Items] | ||
Restricted investments | 3,005 | 3,005 |
SPBPC Collateral City of Long Beach pipeline facility permit [Member] | ||
Schedule Of Investments [Line Items] | ||
Restricted investments | 500 | 500 |
SPBPC Collateral Federal pipeline right-of-way bond [Member] | ||
Schedule Of Investments [Line Items] | ||
Restricted investments | 307 | 307 |
SPBPC Collateral Port of Long Beach pipeline license [Member] | ||
Schedule Of Investments [Line Items] | ||
Restricted investments | $100 | $100 |
Long_Term_Debt_Consolidated_De
Long Term Debt - Consolidated Debt Obligations (Detail) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | ||
In Thousands, unless otherwise specified | ||||
Debt Instrument [Line Items] | ||||
Total long-term debt | $2,378,413 | $1,663,217 | ||
MRD [Member] | ||||
Debt Instrument [Line Items] | ||||
Long-term debt | 783,000 | 871,150 | ||
MRD [Member] | 2.0 billion revolving credit facility [Member] | ||||
Debt Instrument [Line Items] | ||||
Credit facility | 183,000 | |||
MRD [Member] | PIK notes [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | 350,000 | |||
MRD [Member] | 5.875% Senior Unsecured Notes Due July 2022 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | 600,000 | [1] | ||
MRD [Member] | Senior Pik Toggle Notes Unamortized Discounts [Member] | ||||
Debt Instrument [Line Items] | ||||
Unamortized discounts | -6,950 | |||
MRD [Member] | WildHorse Resources, LLC [Member] | 1.0 billion revolving credit facility [Member] | ||||
Debt Instrument [Line Items] | ||||
Credit facility | 203,100 | |||
MRD [Member] | WildHorse Resources, LLC [Member] | 325.0 Million Lien Term Facility [Member] | ||||
Debt Instrument [Line Items] | ||||
Credit facility | 325,000 | |||
MEMP [Member] | ||||
Debt Instrument [Line Items] | ||||
Unamortized discounts | -16,587 | -10,933 | ||
Long-term debt | 1,595,413 | 792,067 | ||
MEMP [Member] | 2.0 billion revolving credit facility [Member] | ||||
Debt Instrument [Line Items] | ||||
Credit facility | 412,000 | 103,000 | ||
MEMP [Member] | 7.625 % Senior Notes Due May 2021 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | 700,000 | [2] | 700,000 | [2] |
MEMP [Member] | 6.875% Senior Unsecured Notes Due August 2022 [Member] | ||||
Debt Instrument [Line Items] | ||||
Senior Notes | $500,000 | [3] | ||
[1] | The estimated fair value of this fixed-rate debt was $534.0 million at DecemberB 31, 2014. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. | |||
[2] | The estimated fair value of this fixed-rate debt was $563.5 million and $721.0 million at DecemberB 31, 2014 and 2013, respectively. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. | |||
[3] | The estimated fair value of this fixed-rate debt was $380.0 million at DecemberB 31, 2014. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. |
Long_Term_Debt_Consolidated_De1
Long Term Debt - Consolidated Debt Obligations (Parenthetical) (Detail) (USD $) | 12 Months Ended | |
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 |
PIK notes [Member] | ||
Debt Instrument [Line Items] | ||
Senior notes maturity date | 15-Dec-18 | |
Debt interest rate, minimum | 10.00% | |
Debt interest rate, maximum | 10.75% | |
7.625 % Senior Notes Due May 2021 [Member] | ||
Debt Instrument [Line Items] | ||
Senior notes maturity date | 1-May-21 | |
MRD [Member] | 2.0 billion revolving credit facility [Member] | ||
Debt Instrument [Line Items] | ||
Credit facilities | 2,000 | |
Senior notes maturity date | 30-Jun-19 | |
MRD [Member] | 1.0 billion revolving credit facility [Member] | ||
Debt Instrument [Line Items] | ||
Credit facilities | 1,000 | |
Termination date of revolving credit facility | 30-Jun-14 | |
MRD [Member] | PIK notes [Member] | ||
Debt Instrument [Line Items] | ||
Debt interest rate, minimum | 10.00% | |
Senior notes redemption date | 30-Jun-14 | |
Debt interest rate, maximum | 10.75% | |
MRD [Member] | 5.875% Senior Unsecured Notes Due July 2022 [Member] | ||
Debt Instrument [Line Items] | ||
Senior notes maturity date | 31-Jul-22 | |
Debt interest rate | 5.88% | |
Estimated fair value of fixed rate debt | 534 | |
MRD [Member] | WildHorse Resources, LLC [Member] | 325.0 Million Lien Term Facility [Member] | ||
Debt Instrument [Line Items] | ||
Credit facilities | 325 | |
MEMP [Member] | ||
Debt Instrument [Line Items] | ||
Credit facilities | 2,000 | |
MEMP [Member] | 2.0 billion revolving credit facility [Member] | ||
Debt Instrument [Line Items] | ||
Credit facilities | 2,000 | |
Senior notes maturity date | 31-Mar-18 | |
MEMP [Member] | 7.625 % Senior Notes Due May 2021 [Member] | ||
Debt Instrument [Line Items] | ||
Senior notes maturity date | 31-May-21 | |
Debt interest rate | 7.63% | |
Estimated fair value of fixed rate debt | 563.5 | 721 |
MEMP [Member] | 6.875% Senior Unsecured Notes Due August 2022 [Member] | ||
Debt Instrument [Line Items] | ||
Senior notes maturity date | 31-Aug-22 | |
Debt interest rate | 6.88% | |
Estimated fair value of fixed rate debt | 380 |
Long_Term_Debt_Borrowing_Base_
Long Term Debt - Borrowing Base Credit Facility (Detail) (USD $) | Dec. 31, 2014 |
In Thousands, unless otherwise specified | |
MRD [Member] | 2.0 Billion Revolving Credit Facility Due June 2019 [Member] | |
Line Of Credit Facility [Line Items] | |
Borrowing base | $725,000 |
MEMP [Member] | 2.0 Billion Revolving Credit Facility Due March 2018 [Member] | |
Line Of Credit Facility [Line Items] | |
Borrowing base | $1,440,000 |
Long_Term_Debt_Borrowing_Base_1
Long Term Debt - Borrowing Base Credit Facility (Parenthetical) (Detail) (USD $) | Dec. 31, 2014 |
In Millions, unless otherwise specified | |
MRD [Member] | 2.0 Billion Revolving Credit Facility Due June 2019 [Member] | |
Line Of Credit Facility [Line Items] | |
Revolving credit facility | $2,000 |
MEMP [Member] | |
Line Of Credit Facility [Line Items] | |
Revolving credit facility | 2,000 |
MEMP [Member] | 2.0 Billion Revolving Credit Facility Due March 2018 [Member] | |
Line Of Credit Facility [Line Items] | |
Revolving credit facility | $2,000 |
Long_Term_Debt_MRD_Revolving_C
Long Term Debt - MRD Revolving Credit Facility - Additional Information (Detail) (MRD [Member], Revolving Credit Facility [Member], USD $) | 0 Months Ended | 12 Months Ended |
Jul. 18, 2014 | Dec. 31, 2014 | |
Debt Obligations [Line Items] | ||
Revolving credit facility expiration term | 5 years | |
Line of credit facility, aggregate maximum borrowing amount | $2,000,000,000 | |
Line of credit facility, initial borrowing base | 725,000,000 | |
Aggregate elected capacity of revolving credit | $725,000,000 | |
Optional Base Rate | Federal Funds Effective Rate [Member] | ||
Debt Obligations [Line Items] | ||
Lien percentage of assets for credit facility | 80.00% | |
Line of credit, additional margin rate | 0.50% | |
Line of credit, adjusted description | The one-month adjusted LIBOR plus 1.0% (adjusted upwards, if necessary, to the next 1/100th of 1%) | |
Range 1 [Member] | Alternative Base Rate | ||
Debt Obligations [Line Items] | ||
Line of credit, additional margin rate | 0.50% | |
Range 1 [Member] | London Interbank Offered Rate (LIBOR) | ||
Debt Obligations [Line Items] | ||
Line of credit, additional margin rate | 1.50% | |
Range 2 [Member] | Alternative Base Rate | ||
Debt Obligations [Line Items] | ||
Line of credit, additional margin rate | 1.50% | |
Range 2 [Member] | London Interbank Offered Rate (LIBOR) | ||
Debt Obligations [Line Items] | ||
Line of credit, additional margin rate | 2.50% | |
Minimum [Member] | ||
Debt Obligations [Line Items] | ||
Percentage of revolving unused commitment fee | 0.38% | |
Debt instrument interest coverage ratio | 2.50% | |
Debt instrument, current asset to current liabilities ratio | 1.00% | |
Maximum [Member] | ||
Debt Obligations [Line Items] | ||
Percentage of revolving unused commitment fee | 0.50% |
Long_Term_Debt_MRD_5875_Senior
Long Term Debt - MRD 5.875% Senior Unsecured Notes Offering - Additional Information (Detail) (5.875% Senior Unsecured Notes ("MRD Senior Notes") [Member], USD $) | 0 Months Ended |
In Millions, unless otherwise specified | Jul. 10, 2014 |
Debt Obligations [Line Items] | |
Debt Instrument, maturity date | 1-Jul-22 |
Other event of default minimum note holder percentage to accelerate | 25.00% |
Private Placement of Debt [Member] | |
Debt Obligations [Line Items] | |
Aggregate principal amount | 600 |
Senior unsecured notes interest rate | 5.88% |
Long_Term_Debt_PIK_notes_Addit
Long Term Debt - PIK notes - Additional Information (Detail) (USD $) | 12 Months Ended | 0 Months Ended | |||||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Jul. 16, 2014 | Dec. 18, 2013 | Jun. 27, 2014 | Jun. 15, 2014 | |
Debt Obligations [Line Items] | |||||||
Payment of distribution to funds | $0 | $732,362,000 | $0 | ||||
Extinguishment loss | 37,248,000 | 0 | 0 | ||||
PIK notes [Member] | |||||||
Debt Obligations [Line Items] | |||||||
Aggregate principal amount | 350,000,000 | 350,000,000 | |||||
Percentage of PIK toggle notes issued at par | 98.00% | ||||||
Cash reserve for payment of interest on notes | 50,000,000 | ||||||
Payment of distribution to funds | 210,000,000 | ||||||
Debt redemption price percentage | 102.00% | ||||||
Irrevocable deposits | 360,000,000 | ||||||
Extinguishment loss | $23,600,000 |
Long_Term_Debt_WildHorse_Resou
Long Term Debt - WildHorse Resources Revolving Credit Facility and Second Lien Facility - Additional Information (Detail) (USD $) | 12 Months Ended | 0 Months Ended | |||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Apr. 03, 2013 | Jun. 13, 2013 | |
Debt Obligations [Line Items] | |||||
Cash distribution paid | $0 | $732,362,000 | $0 | ||
Loss on extinguishment of debt | 37,248,000 | 0 | 0 | ||
Revolving Credit Facility [Member] | WildHorse Resources, LLC [Member] | |||||
Debt Obligations [Line Items] | |||||
Initial borrowing base of second lien term facility | 1,000,000,000 | ||||
Line of credit facility, initial borrowing base | 300,000,000 | ||||
Line of credit, minimum collateral percentage | 80.00% | ||||
Revolving Credit Facility [Member] | WildHorse Resources, LLC [Member] | Second Lien Term Loan [Member] | |||||
Debt Obligations [Line Items] | |||||
Initial borrowing base of second lien term facility | 325,000,000 | ||||
Line of credit, minimum collateral percentage | 80.00% | ||||
Cash distribution paid | 225,000,000 | ||||
Loss on extinguishment of debt | $13,700,000 | ||||
Revolving Credit Facility [Member] | WildHorse Resources, LLC [Member] | Second Lien Term Loan [Member] | Alternative Base Rate | |||||
Debt Obligations [Line Items] | |||||
Debt instrument interest rate | 5.25% | ||||
Revolving Credit Facility [Member] | WildHorse Resources, LLC [Member] | Second Lien Term Loan [Member] | London Interbank Offered Rate (LIBOR) | |||||
Debt Obligations [Line Items] | |||||
Debt instrument interest rate | 6.25% |
Long_Term_Debt_MEMP_Revolving_
Long Term Debt - MEMP Revolving Credit Facility and Senior Notes - Additional Information (Detail) (USD $) | 12 Months Ended | 0 Months Ended | |||
In Millions, unless otherwise specified | Dec. 31, 2014 | Jul. 17, 2014 | Oct. 10, 2013 | 23-May-13 | Apr. 17, 2013 |
7.625 % Senior Notes Due May 2021 [Member] | |||||
Debt Obligations [Line Items] | |||||
Debt Instrument, maturity date | 1-May-21 | ||||
MEMP [Member] | |||||
Debt Obligations [Line Items] | |||||
Initial borrowing base of second lien term facility | 2,000 | ||||
MEMP [Member] | 6.875% Senior Unsecured Notes ("2022 Senior Notes") [Member] | |||||
Debt Obligations [Line Items] | |||||
Other event of default minimum note holder percentage to accelerate | 25.00% | ||||
Debt Instrument, maturity date | 1-Aug-22 | ||||
Note issued at percentage of par | 98.49% | ||||
MEMP [Member] | Private Placement of Debt [Member] | 6.875% Senior Unsecured Notes ("2022 Senior Notes") [Member] | |||||
Debt Obligations [Line Items] | |||||
Aggregate principal amount | 500 | ||||
Senior unsecured notes interest rate | 6.88% | ||||
MEMP [Member] | 7.625 % Senior Notes Due May 2021 [Member] | |||||
Debt Obligations [Line Items] | |||||
Senior unsecured notes interest rate | 7.63% | ||||
Other event of default minimum note holder percentage to accelerate | 25.00% | ||||
Debt Instrument, maturity date | 31-May-21 | ||||
MEMP [Member] | 7.625 % Senior Notes Due May 2021 [Member] | Private Placement of Debt [Member] | |||||
Debt Obligations [Line Items] | |||||
Aggregate principal amount | $300 | $100 | $300 | ||
MEMP [Member] | Optional Base Rate | Federal Funds Effective Rate [Member] | |||||
Debt Obligations [Line Items] | |||||
Lien percentage of assets for credit facility | 80.00% | ||||
Line of credit, additional margin rate | 0.50% | ||||
Line of credit, adjusted description | The one-month adjusted LIBOR plus 1.0% (adjusted upwards, if necessary, to the next 1/100th of 1%) | ||||
MEMP [Member] | Optional Base Rate | Adjusted London Interbank Offered Rate | |||||
Debt Obligations [Line Items] | |||||
Line of credit, additional margin rate | 1.00% | ||||
MEMP [Member] | Minimum [Member] | |||||
Debt Obligations [Line Items] | |||||
Percentage of revolving unused commitment fee | 0.38% | ||||
MEMP [Member] | Minimum [Member] | Alternative Base Rate | Range 1 [Member] | |||||
Debt Obligations [Line Items] | |||||
Line of credit, additional margin rate | 0.50% | ||||
MEMP [Member] | Minimum [Member] | London Interbank Offered Rate (LIBOR) | Range 2 [Member] | |||||
Debt Obligations [Line Items] | |||||
Line of credit, additional margin rate | 1.50% | ||||
MEMP [Member] | Minimum [Member] | LIBOR Market Index Plus [Member] | Range 3 [Member] | |||||
Debt Obligations [Line Items] | |||||
Line of credit, additional margin rate | 1.50% | ||||
MEMP [Member] | Maximum [Member] | |||||
Debt Obligations [Line Items] | |||||
Percentage of revolving unused commitment fee | 0.50% | ||||
MEMP [Member] | Maximum [Member] | Alternative Base Rate | Range 1 [Member] | |||||
Debt Obligations [Line Items] | |||||
Line of credit, additional margin rate | 1.50% | ||||
MEMP [Member] | Maximum [Member] | London Interbank Offered Rate (LIBOR) | Range 2 [Member] | |||||
Debt Obligations [Line Items] | |||||
Line of credit, additional margin rate | 2.50% | ||||
MEMP [Member] | Maximum [Member] | LIBOR Market Index Plus [Member] | Range 3 [Member] | |||||
Debt Obligations [Line Items] | |||||
Line of credit, additional margin rate | 2.50% |
Long_Term_Debt_Summary_of_Weig
Long Term Debt - Summary of Weighted-Average Interest Rates Paid On Variable-Rate Debt Obligations (Detail) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
MRD [Member] | |||
Line Of Credit Facility [Line Items] | |||
Revolving credit facility, weighted-average interest rates | 1.99% | ||
MRD [Member] | MRD LLC [Member] | |||
Line Of Credit Facility [Line Items] | |||
Revolving credit facility, weighted-average interest rates | 3.17% | 4.11% | |
MRD [Member] | Classic Revolving Credit Facility [Member] | |||
Line Of Credit Facility [Line Items] | |||
Revolving credit facility, weighted-average interest rates | 4.50% | ||
MRD [Member] | WildHorse Resources, LLC [Member] | |||
Line Of Credit Facility [Line Items] | |||
Revolving credit facility, weighted-average interest rates | 4.04% | 2.30% | 3.00% |
MRD [Member] | WildHorse Resources second lien [Member] | |||
Line Of Credit Facility [Line Items] | |||
Revolving credit facility, weighted-average interest rates | 6.44% | 7.60% | |
MRD [Member] | Black Diamond [Member] | |||
Line Of Credit Facility [Line Items] | |||
Revolving credit facility, weighted-average interest rates | 3.97% | 3.62% | |
MEMP [Member] | |||
Line Of Credit Facility [Line Items] | |||
Revolving credit facility, weighted-average interest rates | 2.67% | 3.25% | 2.74% |
MEMP [Member] | Wht [Member] | |||
Line Of Credit Facility [Line Items] | |||
Revolving credit facility, weighted-average interest rates | 2.29% | 2.60% | |
MEMP [Member] | Tanos Energy LLC [Member] | |||
Line Of Credit Facility [Line Items] | |||
Revolving credit facility, weighted-average interest rates | 3.10% | 2.31% | |
MEMP [Member] | REO Revolving Credit Facility [Member] | |||
Line Of Credit Facility [Line Items] | |||
Revolving credit facility, weighted-average interest rates | 3.40% | ||
MEMP [Member] | Stanolind [Member] | |||
Line Of Credit Facility [Line Items] | |||
Revolving credit facility, weighted-average interest rates | 3.52% | 3.76% | |
MEMP [Member] | Boaz [Member] | |||
Line Of Credit Facility [Line Items] | |||
Revolving credit facility, weighted-average interest rates | 2.97% | 3.12% | |
MEMP [Member] | Crown [Member] | |||
Line Of Credit Facility [Line Items] | |||
Revolving credit facility, weighted-average interest rates | 3.38% | 4.20% | |
MEMP [Member] | Propel Energy [Member] | |||
Line Of Credit Facility [Line Items] | |||
Revolving credit facility, weighted-average interest rates | 3.08% | 3.28% |
Long_Term_Debt_Summary_of_Unam
Long Term Debt - Summary of Unamortized Deferred Financing Costs Associated with Consolidated Debt Obligations (Detail) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Debt Obligations [Line Items] | ||
Unamortized deferred financing costs | $44,474 | $40,193 |
MRD [Member] | Revolving Credit Facility [Member] | ||
Debt Obligations [Line Items] | ||
Unamortized deferred financing costs | 4,285 | |
MRD [Member] | Revolving Credit Facility [Member] | WildHorse Resources, LLC [Member] | ||
Debt Obligations [Line Items] | ||
Unamortized deferred financing costs | 2,436 | |
MRD [Member] | Senior Notes | ||
Debt Obligations [Line Items] | ||
Unamortized deferred financing costs | 12,455 | |
MRD [Member] | Second Lien Credit Facility [Member] | ||
Debt Obligations [Line Items] | ||
Unamortized deferred financing costs | 9,030 | |
MRD [Member] | PIK notes [Member] | ||
Debt Obligations [Line Items] | ||
Unamortized deferred financing costs | 8,261 | |
MEMP [Member] | Revolving Credit Facility [Member] | ||
Debt Obligations [Line Items] | ||
Unamortized deferred financing costs | 6,468 | 5,413 |
MEMP [Member] | 2021 Senior Notes [Member] | ||
Debt Obligations [Line Items] | ||
Unamortized deferred financing costs | 13,308 | 15,053 |
MEMP [Member] | 2022 Senior Notes [Member] | ||
Debt Obligations [Line Items] | ||
Unamortized deferred financing costs | $7,958 |
Stockholders_Equity_and_Noncon2
Stockholders' Equity and Noncontrolling Interests - Additional Information (Detail) (USD $) | 12 Months Ended | 0 Months Ended | |||||||||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Sep. 09, 2014 | Jul. 15, 2014 | Oct. 08, 2013 | Mar. 25, 2013 | Apr. 01, 2013 | Mar. 16, 2015 | Feb. 01, 2015 | Jun. 18, 2014 | |
Stockholders Equity Note Disclosure [Line Items] | |||||||||||
Common stock, shares authorized | 600,000,000 | 0 | |||||||||
Common stock, par value | $0.01 | $0.01 | |||||||||
Stock repurchase program, authorized amount | $50,000,000 | ||||||||||
Stock repurchased and retired during period, shares | 123,797 | ||||||||||
Payments for repurchase of common stock | 2,215,000 | ||||||||||
Preferred stock, par value | $0.01 | ||||||||||
Preferred stock, shares authorized | 50,000,000 | ||||||||||
Preferred stock, shares issued | 0 | ||||||||||
Preferred stock, shares outstanding | 0 | ||||||||||
Public offering price per common unit | $19 | ||||||||||
Noncontrolling interests | 1,120,554,000 | 580,615,000 | |||||||||
Fair value consideration paid | 3,292,000 | 15,135,000 | 0 | ||||||||
Common Stock [Member] | |||||||||||
Stockholders Equity Note Disclosure [Line Items] | |||||||||||
Stock repurchased and retired during period, shares | 123,797 | ||||||||||
MEMP [Member] | |||||||||||
Stockholders Equity Note Disclosure [Line Items] | |||||||||||
Stock repurchase program, authorized amount | 150,000,000 | ||||||||||
Stock repurchased and retired during period, shares | 899,912 | ||||||||||
Payments for repurchase of common stock | 12,900,000 | ||||||||||
MEMP [Member] | Common Stock [Member] | |||||||||||
Stockholders Equity Note Disclosure [Line Items] | |||||||||||
Number of common units sold by subsidiary | 11,975,000 | 14,950,000 | 9,890,000 | 16,675,000 | 9,775,000 | ||||||
Net proceeds from sale of common units by subsidiary | 194,100,000 | 321,300,000 | 220,000,000 | 318,300,000 | 171,800,000 | ||||||
Tanos Energy LLC [Member] | |||||||||||
Stockholders Equity Note Disclosure [Line Items] | |||||||||||
Percentage of ownership interest sold to company | 1.07% | ||||||||||
WildHorse Resources, LLC [Member] | |||||||||||
Stockholders Equity Note Disclosure [Line Items] | |||||||||||
Percentage of interest contributed former management members | 0.10% | ||||||||||
Cash consideration paid to certain former management members | 30,000,000 | ||||||||||
Noncontrolling interests | 400,000 | ||||||||||
Fair value consideration paid | 3,300,000 | ||||||||||
Subsequent Event [Member] | MRD [Member] | |||||||||||
Stockholders Equity Note Disclosure [Line Items] | |||||||||||
Stock repurchased and retired during period, shares | 2,764,887 | ||||||||||
Payments for repurchase of common stock | 47,800,000 | ||||||||||
Subsequent Event [Member] | MEMP [Member] | |||||||||||
Stockholders Equity Note Disclosure [Line Items] | |||||||||||
Stock repurchased and retired during period, shares | 1,909,583 | ||||||||||
Payments for repurchase of common stock | $28,500,000 |
Stockholders_Equity_and_Noncon3
Stockholders' Equity and Noncontrolling Interests - Summary of Changes In Common Shares Issued (Detail) | 0 Months Ended | 12 Months Ended |
Jun. 18, 2014 | Dec. 31, 2014 | |
Class of Stock [Line Items] | ||
Beginning Balance | 0 | |
Shares of common stock issued in initial public offering (Note 1) | 21,500,000 | |
Shares of common stock repurchased and retired | -123,797 | |
Ending Balance | 193,435,414 | |
Common Stock [Member] | ||
Class of Stock [Line Items] | ||
Shares of common stock issued in connection with restructuring transactions (Note 1) | 171,000,000 | |
Shares of common stock issued in initial public offering (Note 1) | 21,500,000 | |
Shares of common stock repurchased and retired | -123,797 | |
Restricted common shares issued (Note 11) | 1,068,422 | |
Restricted common shares forfeited | -9,211 |
Earnings_per_Share_Summary_of_
Earnings per Share - Summary of Calculation of Earnings (Loss) Per Share (Detail) (USD $) | 3 Months Ended | 12 Months Ended | ||||
In Thousands, except Per Share data, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Numerator: | ||||||
Net income (loss) available to common stockholders | $167,198 | $9,928 | ($961,707) | ($784,581) | $0 | $0 |
Denominator: | ||||||
Weighted average common shares outstanding | 192,498 | |||||
Basic EPS | $0.87 | $0.05 | ($5) | ($4.08) | $0 | $0 |
Diluted EPS | $0.87 | $0.05 | ($5) | ($4.08) | $0 | $0 |
Earnings_per_Share_Summary_of_1
Earnings per Share - Summary of Calculation of Earnings (Loss) Per Share (Parenthetical) (Detail) | 12 Months Ended |
In Thousands, unless otherwise specified | Dec. 31, 2014 |
Earnings Per Share [Abstract] | |
Shares excluded from computation of EPS | 202,623 |
Earnings_per_Share_Summary_of_2
Earnings per Share - Summary of Calculation of Supplemental EPS (Detail) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||
In Thousands, except Per Share data, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Numerator: | |||||||||||
Net income (loss) attributable to Memorial Resource Development Corp. | $167,198 | $9,928 | ($948,349) | $8,372 | ($30,657) | $84,727 | $43,183 | $4,249 | ($762,851) | $101,502 | $29,698 |
Denominator: | |||||||||||
Weighted average common shares outstanding | 192,498 | ||||||||||
Basic EPS | $0.87 | $0.05 | ($5) | ($4.08) | $0 | $0 | |||||
Diluted EPS | $0.87 | $0.05 | ($5) | ($4.08) | $0 | $0 | |||||
Supplemental EPS [Member] | |||||||||||
Numerator: | |||||||||||
Net income (loss) attributable to Memorial Resource Development Corp. | ($762,851) | ||||||||||
Denominator: | |||||||||||
Weighted average common shares outstanding | 192,498 | ||||||||||
Basic EPS | ($3.96) | ||||||||||
Diluted EPS | ($3.96) |
Earnings_per_Share_Summary_of_3
Earnings per Share - Summary of Calculation of Supplemental EPS (Parenthetical) (Detail) | 12 Months Ended |
In Thousands, unless otherwise specified | Dec. 31, 2014 |
Earnings Per Share [Line Items] | |
Shares excluded from computation of EPS | 202,623 |
Supplemental EPS [Member] | |
Earnings Per Share [Line Items] | |
Shares excluded from computation of EPS | 202,623 |
LongTerm_Incentive_Plans_Addit
Long-Term Incentive Plans - Additional Information (Detail) (USD $) | 12 Months Ended | |
In Millions, except Share data, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2011 |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||
Number of common shares that may be delivered | 19,250,000 | |
MEMP [Member] | ||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||
Number of common units that may be delivered | 2,142,221 | |
Restricted Stock [Member] | ||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||
Aggregate award of restricted stock issued to employees and each independent director | 1,052,633 | |
Vesting period of award | 4 years | |
Unrecognized compensation cost | $17.30 | |
Unrecognized compensation cost weighted-average period | 3 years 5 months 5 days | |
Restricted Stock [Member] | MEMP [Member] | ||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||
Unrecognized compensation cost | $16.50 | |
Unrecognized compensation cost weighted-average period | 2 years 1 month 6 days | |
Restricted Stock [Member] | Director [Member] | ||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||
Aggregate award of restricted stock issued to employees and each independent director | 5,263 | |
Vesting period of award | 1 year |
LongTerm_Incentive_Plans_Summa
Long-Term Incentive Plans - Summary of Information Regarding Restricted Common Unit Awards (Detail) (Restricted Stock [Member], USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Granted, Number of Units | 1,068,422 | ||
Forfeited, Number of Units | -9,211 | ||
Restricted common shares outstanding, Number of Units, Ending Balance | 1,059,211 | ||
Granted, Weighted-Average Grant Date Fair Value Per Unit | $19 | ||
Forfeited, Weighted-Average Grant Date Fair Value Per Unit | $19 | ||
Restricted common shares outstanding, Weighted-Average Grant Date Fair Value Per Unit, Ending Balance | $19 | ||
MEMP [Member] | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Granted, Number of Units | 684,954 | 524,718 | 287,943 |
Forfeited, Number of Units | -38,294 | -11,734 | -2,334 |
Restricted common shares outstanding, Weighted-Average Grant Date Fair Value Per Unit, Beginning Balance | $18.62 | $18.08 | |
Granted, Weighted-Average Grant Date Fair Value Per Unit | $22.39 | $18.83 | $18.07 |
Forfeited, Weighted-Average Grant Date Fair Value Per Unit | $20.54 | $17.24 | $17.14 |
Restricted common shares outstanding, Weighted-Average Grant Date Fair Value Per Unit, Ending Balance | $20.93 | $18.62 | $18.08 |
Restricted common shares outstanding, Number of Units, Beginning Balance | 706,927 | 285,609 | |
Vested, Number of Units | -260,067 | -91,666 | |
Restricted common shares outstanding, Number of Units, Ending Balance | 1,093,520 | 706,927 | 285,609 |
Vested, Weighted-Average Grant Date Fair Value Per Unit | $18.56 | $18.31 |
LongTerm_Incentive_Plans_Summa1
Long-Term Incentive Plans - Summary of Information Regarding Restricted Common Unit Awards (Parenthetical) (Detail) (Restricted Stock [Member], USD $) | 12 Months Ended | ||
In Millions, except Per Share data, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Aggregate grant date fair value | $20.30 | ||
Granted, Weighted-Average Grant Date Fair Value Per Unit | $19 | ||
MEMP [Member] | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Aggregate grant date fair value | $15.30 | $9.90 | $5.20 |
Granted, Weighted-Average Grant Date Fair Value Per Unit | $20.93 | $18.62 | $18.08 |
MEMP [Member] | Minimum [Member] | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Aggregate grant date fair value, market price range | $21.99 | $18.33 | $17.14 |
MEMP [Member] | Maximum [Member] | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Aggregate grant date fair value, market price range | $23.40 | $20.35 | $18.58 |
LongTerm_Incentive_Plans_Summa2
Long-Term Incentive Plans - Summary of Amount of Compensation Expense Recognized (Detail) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Compensation Related Costs Disclosure [Line Items] | |||
Amortization of equity awards | $954,627 | $46,837 | $10,933 |
MEMP [Member] | |||
Compensation Related Costs Disclosure [Line Items] | |||
Amortization of equity awards | 7,874 | 3,558 | 1,423 |
Restricted Stock [Member] | MRD [Member] | |||
Compensation Related Costs Disclosure [Line Items] | |||
Amortization of equity awards | $2,804 |
Incentive_Units_Additional_Inf
Incentive Units - Additional Information (Detail) (USD $) | 12 Months Ended | 0 Months Ended | 1 Months Ended | ||||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Apr. 01, 2013 | Nov. 30, 2013 | Dec. 31, 2013 | Jun. 18, 2014 | |
Equity Incentive Plan [Line Items] | |||||||
Compensation expense | $954,627,000 | $46,837,000 | $10,933,000 | ||||
Accrued liabilities | 199,000,000 | 98,130,000 | 98,130,000 | ||||
Exchange of incentive units | 193,435,414 | 0 | 0 | ||||
Carrying amount of the noncontrolling interest | 1,120,554,000 | 580,615,000 | 580,615,000 | ||||
Fair value of consideration paid for noncontrolling interests | 3,292,000 | 15,135,000 | 0 | ||||
BlueStone Natural Resources Holdings, LLC [Member] | |||||||
Equity Incentive Plan [Line Items] | |||||||
Compensation expense | 1,000,000 | 20,700,000 | 0 | ||||
BlueStone Natural Resources Holdings, LLC [Member] | Special Tier and Tier I Unit Holders [Member] | |||||||
Equity Incentive Plan [Line Items] | |||||||
Percentage of future distributions incentive unit holders are entitled to after payout has been achieved | 16.50% | ||||||
Tanos Energy LLC [Member] | |||||||
Equity Incentive Plan [Line Items] | |||||||
Percentage of ownership interest sold to company | 1.07% | ||||||
Compensation expense as component of general and administrative expense | 5,800,000 | ||||||
Black Diamond, Classic GP and Classic | |||||||
Equity Incentive Plan [Line Items] | |||||||
Compensation expense | 12,600,000 | ||||||
WildHorse Resources, LLC [Member] | |||||||
Equity Incentive Plan [Line Items] | |||||||
Compensation expense | 831,100,000 | 10,000,000 | |||||
Accrued liabilities | 10,000,000 | 10,000,000 | |||||
Percentage of interest contributed former management members | 0.10% | ||||||
Exchange of incentive units | 42,334,323 | ||||||
Cash consideration paid to certain former management members | 30,000,000 | ||||||
Carrying amount of the noncontrolling interest | 400,000 | ||||||
Fair value of consideration paid for noncontrolling interests | 3,300,000 | ||||||
Cash component of incentive unit compensation expense | 26,700,000 | ||||||
Incentive units exchanges for shares of our common stock | 804,400,000 | ||||||
MRD Holdco LLC [Member] | |||||||
Equity Incentive Plan [Line Items] | |||||||
The number of incentive units authorized by governing documents | 1,000 | ||||||
Remaining expected life | 3 years | ||||||
MRD Holdco LLC [Member] | Exchanged Incentive Units [Member] | |||||||
Equity Incentive Plan [Line Items] | |||||||
Percentage of future distributions incentive unit holders are entitled to after payout has been achieved | 9.30% | ||||||
Compensation expense | 111,500,000 | ||||||
Incentive units granted in an exchange for cancelled predecessor awards | 930 | ||||||
Unrecognized compensation expense | 105,500,000 | ||||||
Remaining expected life | 2 years 4 months 28 days | ||||||
MRD Holdco LLC [Member] | Subsequent Incentive Units [Member] | |||||||
Equity Incentive Plan [Line Items] | |||||||
Percentage of future distributions incentive unit holders are entitled to after payout has been achieved | 0.70% | ||||||
Compensation expense | 400,000 | ||||||
Unrecognized compensation expense | $1,700,000 | ||||||
Remaining expected life | 2 years 4 months 28 days | ||||||
Subsequent incentive units | 70 | ||||||
Minimum [Member] | |||||||
Equity Incentive Plan [Line Items] | |||||||
Ranging of distributions for incentive units | 10.00% | ||||||
Maximum [Member] | |||||||
Equity Incentive Plan [Line Items] | |||||||
Ranging of distributions for incentive units | 31.50% |
Incentive_Units_Fair_Value_of_
Incentive Units - Fair Value of Incentive Units Estimated (Detail) | 12 Months Ended |
Dec. 31, 2014 | |
Exchanged Incentive Units [Member] | |
Schedule Of Share Based Compensation Valuation Assumptions [Line Items] | |
Valuation date | 31-Dec-14 |
Dividend yield | 0.00% |
Expected volatility | 39.54% |
Risk-free rate | 0.85% |
Expected life (years) | 2 years 4 months 28 days |
Subsequent Incentive Units [Member] | |
Schedule Of Share Based Compensation Valuation Assumptions [Line Items] | |
Valuation date | 31-Dec-14 |
Dividend yield | 0.00% |
Expected volatility | 39.54% |
Risk-free rate | 0.85% |
Expected life (years) | 2 years 4 months 28 days |
Related_Party_Transactions_Add
Related Party Transactions - Additional Information (Detail) (USD $) | 0 Months Ended | 12 Months Ended | 0 Months Ended | |||||||||||
1-May-14 | Nov. 01, 2011 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2010 | Oct. 11, 2012 | Mar. 28, 2014 | Dec. 12, 2012 | Mar. 17, 2014 | Mar. 10, 2014 | Mar. 01, 2012 | Feb. 28, 2014 | Oct. 01, 2013 | |
Related Party Transaction [Line Items] | ||||||||||||||
Net Profits Interest Sold to NGP | 10.00% | |||||||||||||
Cash received | $19,800,000 | |||||||||||||
General and administrative | 87,673,000 | 82,079,000 | 59,677,000 | |||||||||||
Received an equity contribution of oil and gas properties | 6,900,000 | |||||||||||||
Fee per MMBTU | 0.3 | |||||||||||||
Natural gas produced per day | 50,000 | |||||||||||||
Annual inflationary escalation | 3.50% | |||||||||||||
Price per unit | 0.07 | |||||||||||||
NGP Controlled Entity [Member] | ||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||
Proceeds from divestitures | 40,100,000 | |||||||||||||
Proceeds from sale exceeded net book value of properties sold | 6,300,000 | |||||||||||||
Propel Energy [Member] | ||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||
Cash received | 3,300,000 | |||||||||||||
NGPCIF [Member] | ||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||
Net Profits Interest Sold to NGP | 3.13% | |||||||||||||
Cash received | 19,500,000 | |||||||||||||
Fixed overhead cost per month | 20,000 | |||||||||||||
Business acquisition common control purchase price | 63,400,000 | |||||||||||||
Date of acquisition common control | 28-Feb-14 | |||||||||||||
REO Sponsorship [Member] | ||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||
Business acquisition common control purchase price | 270,600,000 | |||||||||||||
Working capital and other customary adjustments to Beta acquisition | 3,000,000 | |||||||||||||
General and administrative | 1,600,000 | |||||||||||||
Cinco Group [Member] | ||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||
Business acquisition common control purchase price | 603,000,000 | |||||||||||||
Financing fees equal to a percentage of capital contributions | 0 | 400,000 | ||||||||||||
Cinco Group [Member] | Advisory Fees [Member] | ||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||
Expenses incurred with related parties | 300,000 | 400,000 | ||||||||||||
MEMP [Member] | ||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||
Payable to related party | 800,000 | |||||||||||||
Oil And Gas Production [Member] | ||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||
Net Profits Interest Sold to NGP | 23.50% | |||||||||||||
Oil And Gas Production [Member] | NGPCIF [Member] | ||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||
Net Profits Interest Sold to NGP | 6.25% | |||||||||||||
WildHorse Resources, LLC [Member] | ||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||
Common stock lock-up agreement period | 180 days | |||||||||||||
Cash received from related party | 4,400,000 | |||||||||||||
Primary term of gas processing agreement | 15 years | |||||||||||||
Minimum annual processing fee | 18,300,000 | |||||||||||||
WildHorse Resources, LLC [Member] | NGPCIF [Member] | ||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||
Payment to related party | 2,600,000 | 2,300,000 | ||||||||||||
Payable to related party | 200,000 | |||||||||||||
Natural Gas Partners [Member] | Cinco Group [Member] | ||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||
Business acquisition common control purchase price | 507,100,000 | |||||||||||||
BlueStone Natural Resources Holdings, LLC [Member] | ||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||
Total cash consideration | 1,200,000 | 7,000,000 | ||||||||||||
Amount of gain over the book value | 500,000 | |||||||||||||
Gain recognized as contribution | 500,000 | 6,400,000 | ||||||||||||
Undivided interest sold to affiliate | 25.00% | |||||||||||||
WHR Management Company [Member] | ||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||
Payable to related party | 2,400,000 | |||||||||||||
Management fee per month | 1,000,000 | |||||||||||||
Employee [Member] | ||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||
Expenses incurred with related parties | 1,000,000 | |||||||||||||
Boaz [Member] | ||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||
Expenses incurred with related parties | 300,000 | |||||||||||||
Classic [Member] | ||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||
Water disposal fee per barrel | 1.1 | |||||||||||||
Water disposal agreement period | 3 years | |||||||||||||
Adjustments [Member] | ||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||
Cash received | 19,900,000 | |||||||||||||
Adjustments [Member] | NGPCIF [Member] | ||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||
Cash received | 19,100,000 | |||||||||||||
Received Upon Closing [Member] | NGP Controlled Entity [Member] | ||||||||||||||
Related Party Transaction [Line Items] | ||||||||||||||
Proceeds from divestitures | $38,100,000 |
Related_Party_Transactions_Sch
Related Party Transactions - Schedule of Net Assets Recorded (Detail) (USD $) | Feb. 28, 2014 | Sep. 01, 2012 | Oct. 01, 2013 |
In Thousands, unless otherwise specified | |||
NGPCIF [Member] | |||
Related Party Transaction [Line Items] | |||
Accounts receivable | $2,274 | ||
Oil and natural gas properties, net | 40,056 | ||
Accrued liabilities | -297 | ||
Asset retirement obligations | -277 | ||
Net assets | 41,756 | ||
REO Sponsorship [Member] | |||
Related Party Transaction [Line Items] | |||
Cash and cash equivalents | 6,021 | ||
Accounts receivable | 16,284 | ||
Short-term derivative instruments, net | 2,926 | ||
Prepaid expenses and other current assets | 4,521 | ||
Oil and natural gas properties, net | 108,342 | ||
Restricted investments | 68,009 | ||
Accounts payable | -9,092 | ||
Accrued liabilities | -9,140 | ||
Asset retirement obligations | -58,746 | ||
Credit facilities | -28,500 | ||
Deferred tax liability | -1,674 | ||
Noncontrolling interest | -5,255 | ||
Net assets | 93,696 | ||
Cinco Group Acquisition [Member] | |||
Related Party Transaction [Line Items] | |||
Cash and cash equivalents | 2,820 | ||
Accounts receivable | 5,184 | ||
Prepaid expenses and other current assets | 1,454 | ||
Oil and natural gas properties, net | 342,759 | ||
Long-term derivative instruments, net | -826 | ||
Other long-term assets | 344 | ||
Accounts payable | -2,346 | ||
Revenue payable | -2,910 | ||
Accrued liabilities | -1,799 | ||
short-term derivative instruments, net | -1,828 | ||
Asset retirement obligations | -9,606 | ||
Credit facilities | -151,690 | ||
Net assets | $181,556 |
Related_Party_Transactions_Boo
Related Party Transactions - Book Value of Assets Sold (Detail) (WHR Management Company [Member], USD $) | Jun. 18, 2014 |
In Thousands, unless otherwise specified | |
WHR Management Company [Member] | |
Related Party Transaction [Line Items] | |
Cash and cash equivalents | $33,001 |
Restricted cash | 300 |
Accounts receivable | 5,256 |
Prepaid expenses and other current assets | 379 |
Property, plant and equipment, net | 3,410 |
Other long-term assets | 4 |
Accounts payable | -19,959 |
Accounts payable - affiliates | -17,099 |
Accrued liabilities | -5,061 |
Net assets | $231 |
Business_Segment_Data_Addition
Business Segment Data - Additional Information (Detail) | 12 Months Ended |
Dec. 31, 2014 | |
Segment | |
Segment Reporting [Abstract] | |
Number of reportable business segments | 2 |
Business_Segment_Data_Summary_
Business Segment Data - Summary of Selected Business Segment Information (Detail) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Segment Reporting Information [Line Items] | |||||||||||
Total revenues | $226,460 | $245,493 | $236,564 | $190,828 | $152,282 | $153,515 | $147,045 | $122,181 | $899,345 | $575,023 | $396,868 |
Adjusted EBITDA | 647,733 | 394,856 | 287,992 | ||||||||
Segment assets | 4,593,547 | 2,829,161 | 4,593,547 | 2,829,161 | |||||||
Total cash expenditures for additions to long-lived assets | 1,869,133 | 468,447 | 636,686 | ||||||||
Operating Segments [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Adjusted EBITDA | 653,877 | 420,088 | 311,439 | ||||||||
Operating Segments [Member] | MRD [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Total revenues | 405,286 | 231,558 | 138,814 | ||||||||
Adjusted EBITDA | 343,976 | 197,903 | 132,105 | ||||||||
Segment assets | 1,632,313 | 1,281,134 | 1,632,313 | 1,281,134 | |||||||
Total cash expenditures for additions to long-lived assets | 521,038 | 267,870 | 249,526 | ||||||||
Operating Segments [Member] | MEMP [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Total revenues | 494,105 | 343,616 | 258,423 | ||||||||
Adjusted EBITDA | 309,901 | 222,185 | 179,334 | ||||||||
Segment assets | 2,930,559 | 1,552,307 | 2,930,559 | 1,552,307 | |||||||
Total cash expenditures for additions to long-lived assets | 1,348,095 | 200,577 | 387,160 | ||||||||
Other, Adjustments & Eliminations [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Total revenues | -46 | -151 | -369 | ||||||||
Adjusted EBITDA | -6,144 | -25,232 | -23,447 | ||||||||
Segment assets | $30,675 | ($4,280) | $30,675 | ($4,280) |
Business_Segment_Data_Summary_1
Business Segment Data - Summary of Selected Business Segment Information (Parenthetical) (Detail) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Segment Reporting Information [Line Items] | |||
Cash distributions from MEMP | $6,144,000 | $26,006,000 | $19,263,000 |
Other, Adjustments & Eliminations [Member] | |||
Segment Reporting Information [Line Items] | |||
Impairment charges | 46,000,000 | 49,900,000 | |
Other, Adjustments & Eliminations [Member] | MEMP [Member] | |||
Segment Reporting Information [Line Items] | |||
Cash distributions from MEMP | $6,100,000 | $26,000,000 | $19,300,000 |
Business_Segment_Data_Schedule
Business Segment Data - Schedule of Calculation of Reportable Segment's Adjusted EBITDA (Detail) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Segment Reporting Information [Line Items] | |||||||||||
Net income (loss) | $328,859 | $112,037 | ($1,053,443) | ($23,516) | ($22,968) | $95,962 | $78,158 | $180 | ($636,063) | $151,332 | $26,997 |
Interest expense, net | 133,833 | 69,250 | 33,238 | ||||||||
Loss on extinguishment of debt | 37,248 | 0 | 0 | ||||||||
Income tax expense (benefit) | 100,971 | 1,619 | 107 | ||||||||
DD&A | 314,193 | 184,717 | 138,672 | ||||||||
Impairment of proved oil and natural gas properties | 432,116 | 6,600 | 28,871 | ||||||||
Accretion of AROs | 6,306 | 5,581 | 5,009 | ||||||||
(Gain) loss on commodity derivative instruments | -749,988 | -29,294 | -34,905 | ||||||||
Cash settlements received (paid) on commodity derivative instruments | 22,688 | 32,119 | 74,299 | ||||||||
(Gain) loss on sale of properties | 3,057 | -85,621 | -9,761 | ||||||||
Acquisition related costs | 6,668 | 8,313 | 4,538 | ||||||||
Compensation expense | 954,627 | 46,837 | 10,933 | ||||||||
Amortization of investment premium | 0 | 0 | 194 | ||||||||
Non-cash compensation expense | 1,057 | ||||||||||
Exploration costs | 16,603 | 2,356 | 9,800 | ||||||||
Provision for environmental remediation | 2,852 | ||||||||||
Loss on office lease | 2,622 | ||||||||||
Cash distributions from MEMP | 6,144 | 26,006 | 19,263 | ||||||||
Adjusted EBITDA | 647,733 | 394,856 | 287,992 | ||||||||
MEMP [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Impairment of proved oil and natural gas properties | 407,500 | 28,871 | |||||||||
Operating Segments [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Net income (loss) | -644,847 | 102,511 | 31,877 | ||||||||
Interest expense, net | 133,833 | 69,250 | 33,238 | ||||||||
Loss on extinguishment of debt | 37,248 | ||||||||||
Income tax expense (benefit) | 100,971 | 1,619 | 107 | ||||||||
DD&A | 310,321 | 184,312 | 138,672 | ||||||||
Impairment of proved oil and natural gas properties | 432,116 | 56,889 | 28,871 | ||||||||
Accretion of AROs | 6,306 | 5,581 | 5,009 | ||||||||
(Gain) loss on commodity derivative instruments | -749,988 | -29,294 | -34,905 | ||||||||
Cash settlements received (paid) on commodity derivative instruments | 22,688 | 32,119 | 74,299 | ||||||||
(Gain) loss on sale of properties | 3,057 | -85,621 | -9,761 | ||||||||
Acquisition related costs | 6,668 | 8,313 | 4,538 | ||||||||
Compensation expense | 954,627 | 46,837 | 10,933 | ||||||||
Amortization of investment premium | 194 | ||||||||||
Non-cash compensation expense | 1,057 | ||||||||||
Exploration costs | 16,603 | 2,356 | 9,800 | ||||||||
Provision for environmental remediation | 2,852 | ||||||||||
Loss on office lease | 2,622 | ||||||||||
Non-cash equity (income) loss from MEMP | 12,656 | -1,847 | -696 | ||||||||
Cash distributions from MEMP | 6,144 | 26,006 | 19,263 | ||||||||
Adjusted EBITDA | 653,877 | 420,088 | 311,439 | ||||||||
Operating Segments [Member] | MRD [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Net income (loss) | -762,926 | 82,243 | -14,641 | ||||||||
Interest expense, net | 50,283 | 27,349 | 12,802 | ||||||||
Loss on extinguishment of debt | 37,248 | ||||||||||
Income tax expense (benefit) | 99,850 | 1,311 | -178 | ||||||||
DD&A | 154,917 | 87,043 | 62,636 | ||||||||
Impairment of proved oil and natural gas properties | 24,576 | 2,527 | 18,339 | ||||||||
Accretion of AROs | 688 | 728 | 632 | ||||||||
(Gain) loss on commodity derivative instruments | -257,734 | -3,013 | -13,488 | ||||||||
Cash settlements received (paid) on commodity derivative instruments | 9,166 | 12,240 | 30,188 | ||||||||
(Gain) loss on sale of properties | 3,057 | -82,773 | -2 | ||||||||
Acquisition related costs | 2,305 | 1,584 | 403 | ||||||||
Compensation expense | 946,753 | 43,279 | 9,510 | ||||||||
Exploration costs | 15,813 | 1,226 | 7,337 | ||||||||
Loss on office lease | 1,180 | ||||||||||
Non-cash equity (income) loss from MEMP | 12,656 | -1,847 | -696 | ||||||||
Cash distributions from MEMP | 6,144 | 26,006 | 19,263 | ||||||||
Adjusted EBITDA | 343,976 | 197,903 | 132,105 | ||||||||
Operating Segments [Member] | MEMP [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Net income (loss) | 118,079 | 20,268 | 46,518 | ||||||||
Interest expense, net | 83,550 | 41,901 | 20,436 | ||||||||
Income tax expense (benefit) | 1,121 | 308 | 285 | ||||||||
DD&A | 155,404 | 97,269 | 76,036 | ||||||||
Impairment of proved oil and natural gas properties | 407,540 | 54,362 | 10,532 | ||||||||
Accretion of AROs | 5,618 | 4,853 | 4,377 | ||||||||
(Gain) loss on commodity derivative instruments | -492,254 | -26,281 | -21,417 | ||||||||
Cash settlements received (paid) on commodity derivative instruments | 13,522 | 19,879 | 44,111 | ||||||||
(Gain) loss on sale of properties | -2,848 | -9,759 | |||||||||
Acquisition related costs | 4,363 | 6,729 | 4,135 | ||||||||
Compensation expense | 7,874 | 3,558 | 1,423 | ||||||||
Amortization of investment premium | 194 | ||||||||||
Non-cash compensation expense | 1,057 | ||||||||||
Exploration costs | 790 | 1,130 | 2,463 | ||||||||
Provision for environmental remediation | 2,852 | ||||||||||
Loss on office lease | 1,442 | ||||||||||
Adjusted EBITDA | $309,901 | $222,185 | $179,334 |
Business_Segment_Data_Reconcil
Business Segment Data - Reconciliation of Total Reportable Segment's Adjusted EBITDA to Net Income (Loss) (Detail) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Segment Reporting, Revenue Reconciling Item [Line Items] | |||||||||||
Total Reportable Segments' Adjusted EBITDA | $647,733 | $394,856 | $287,992 | ||||||||
Adjustments to reconcile Adjusted EBITDA to net income (loss): | |||||||||||
Interest expense, net | -133,833 | -69,250 | -33,238 | ||||||||
Loss on extinguishment of debt | -37,248 | 0 | 0 | ||||||||
Income tax benefit (expense) | -100,971 | -1,619 | -107 | ||||||||
DD&A | -314,193 | -184,717 | -138,672 | ||||||||
Impairment of proved oil and natural gas properties | -432,116 | -6,600 | -28,871 | ||||||||
Accretion of AROs | -6,306 | -5,581 | -5,009 | ||||||||
Gains (losses) on commodity derivative instruments | 749,988 | 29,294 | 34,905 | ||||||||
Cash settlements paid (received) on commodity derivative instruments | -22,688 | -32,119 | -74,299 | ||||||||
Gain (loss) on sale of properties | -3,057 | 85,621 | 9,761 | ||||||||
Acquisition related costs | -6,668 | -8,313 | -4,538 | ||||||||
Incentive-based compensation expense | -954,627 | -46,837 | -10,933 | ||||||||
Non-cash compensation expense | -1,057 | ||||||||||
Exploration costs | -16,603 | -2,356 | -9,800 | ||||||||
Amortization of investment premium | 0 | 0 | -194 | ||||||||
Cash distributions from MEMP | -6,144 | -26,006 | -19,263 | ||||||||
Provision for environmental remediation | -2,852 | ||||||||||
Loss on office lease | -2,622 | ||||||||||
Other non-cash equity (income) loss | 784 | -4,184 | |||||||||
Net income (loss) | 328,859 | 112,037 | -1,053,443 | -23,516 | -22,968 | 95,962 | 78,158 | 180 | -636,063 | 151,332 | 26,997 |
Reportable Segments [Member] | |||||||||||
Segment Reporting, Revenue Reconciling Item [Line Items] | |||||||||||
Total Reportable Segments' Adjusted EBITDA | $653,877 | $420,088 | $311,439 |
Business_Segment_Data_Schedule1
Business Segment Data - Schedule of Consolidated and Combined Statement of Operations Disaggregated by Reportable Segment (Detail) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Revenues: | |||||||||||
Oil & natural gas sales | $894,967 | $571,948 | $393,631 | ||||||||
Other revenues | 4,378 | 3,075 | 3,237 | ||||||||
Total revenues | 226,460 | 245,493 | 236,564 | 190,828 | 152,282 | 153,515 | 147,045 | 122,181 | 899,345 | 575,023 | 396,868 |
Costs and expenses: | |||||||||||
Lease operating | 161,303 | 113,640 | 103,754 | ||||||||
Pipeline operating | 2,068 | 1,835 | 2,114 | ||||||||
Exploration | 16,603 | 2,356 | 9,800 | ||||||||
Production and ad valorem taxes | 45,751 | 27,146 | 23,624 | ||||||||
Depreciation, depletion, and amortization | 314,193 | 184,717 | 138,672 | ||||||||
Impairment of proved oil and natural gas properties | 432,116 | 6,600 | 28,871 | ||||||||
Incentive unit compensation expense | 943,949 | 43,279 | 9,510 | ||||||||
General and administrative | 87,673 | 82,079 | 59,677 | ||||||||
Accretion of asset retirement obligations | 6,306 | 5,581 | 5,009 | ||||||||
(Gain) loss on commodity derivative instruments | -749,988 | -29,294 | -34,905 | ||||||||
(Gain) loss on sale of properties | 3,057 | -85,621 | -9,761 | ||||||||
Other, net | -12 | 649 | 502 | ||||||||
Total costs and expenses | 1,263,019 | 352,967 | 336,867 | ||||||||
Operating income (loss) | 444,776 | 174,201 | -993,256 | 10,605 | 4,411 | 117,797 | 90,327 | 9,521 | -363,674 | 222,056 | 60,001 |
Other income (expense): | |||||||||||
Interest expense, net | -133,833 | -69,250 | -33,238 | ||||||||
Amortization of investment premium | 0 | 0 | -194 | ||||||||
Loss on extinguishment of debt | -37,248 | 0 | 0 | ||||||||
Earnings from equity investments | -784 | 4,184 | |||||||||
Other, net | -337 | 145 | 535 | ||||||||
Total other income (expense) | -171,418 | -69,105 | -32,897 | ||||||||
Income (loss) before income taxes | -535,092 | 152,951 | 27,104 | ||||||||
Income tax benefit (expense) | -100,971 | -1,619 | -107 | ||||||||
Net income (loss) | -636,063 | 151,332 | 26,997 | ||||||||
Operating Segments [Member] | |||||||||||
Costs and expenses: | |||||||||||
Exploration | 16,603 | 2,356 | 9,800 | ||||||||
Depreciation, depletion, and amortization | 310,321 | 184,312 | 138,672 | ||||||||
Impairment of proved oil and natural gas properties | 432,116 | 56,889 | 28,871 | ||||||||
Accretion of asset retirement obligations | 6,306 | 5,581 | 5,009 | ||||||||
(Gain) loss on commodity derivative instruments | -749,988 | -29,294 | -34,905 | ||||||||
(Gain) loss on sale of properties | 3,057 | -85,621 | -9,761 | ||||||||
Other income (expense): | |||||||||||
Interest expense, net | -133,833 | -69,250 | -33,238 | ||||||||
Amortization of investment premium | -194 | ||||||||||
Loss on extinguishment of debt | -37,248 | ||||||||||
Income tax benefit (expense) | -100,971 | -1,619 | -107 | ||||||||
Other, Adjustments & Eliminations [Member] | |||||||||||
Revenues: | |||||||||||
Oil & natural gas sales | -9 | ||||||||||
Other revenues | -46 | -151 | -360 | ||||||||
Total revenues | -46 | -151 | -369 | ||||||||
Costs and expenses: | |||||||||||
Lease operating | -46 | -259 | -800 | ||||||||
Depreciation, depletion, and amortization | 3,872 | 405 | |||||||||
Impairment of proved oil and natural gas properties | -50,289 | ||||||||||
General and administrative | 105 | 431 | |||||||||
Total costs and expenses | 3,826 | -50,038 | -369 | ||||||||
Operating income (loss) | -3,872 | 49,887 | |||||||||
Other income (expense): | |||||||||||
Earnings from equity investments | 12,656 | -1,066 | -4,880 | ||||||||
Total other income (expense) | 12,656 | -1,066 | -4,880 | ||||||||
Income (loss) before income taxes | 8,784 | 48,821 | -4,880 | ||||||||
Net income (loss) | 8,784 | 48,821 | -4,880 | ||||||||
MRD [Member] | Operating Segments [Member] | |||||||||||
Revenues: | |||||||||||
Oil & natural gas sales | 404,718 | 230,751 | 138,032 | ||||||||
Other revenues | 568 | 807 | 782 | ||||||||
Total revenues | 405,286 | 231,558 | 138,814 | ||||||||
Costs and expenses: | |||||||||||
Lease operating | 26,695 | 25,006 | 24,438 | ||||||||
Exploration | 15,813 | 1,226 | 7,337 | ||||||||
Production and ad valorem taxes | 14,150 | 9,362 | 7,576 | ||||||||
Depreciation, depletion, and amortization | 154,917 | 87,043 | 62,636 | ||||||||
Impairment of proved oil and natural gas properties | 24,576 | 2,527 | 18,339 | ||||||||
Incentive unit compensation expense | 943,949 | 43,279 | 9,510 | ||||||||
General and administrative | 42,054 | 38,479 | 28,904 | ||||||||
Accretion of asset retirement obligations | 688 | 728 | 632 | ||||||||
(Gain) loss on commodity derivative instruments | -257,734 | -3,013 | -13,488 | ||||||||
(Gain) loss on sale of properties | 3,057 | -82,773 | -2 | ||||||||
Other, net | 2 | 364 | |||||||||
Total costs and expenses | 968,165 | 121,866 | 146,246 | ||||||||
Operating income (loss) | -562,879 | 109,692 | -7,432 | ||||||||
Other income (expense): | |||||||||||
Interest expense, net | -50,283 | -27,349 | -12,802 | ||||||||
Loss on extinguishment of debt | -37,248 | ||||||||||
Earnings from equity investments | -12,656 | 1,066 | 4,880 | ||||||||
Other, net | -10 | 145 | 535 | ||||||||
Total other income (expense) | -100,197 | -26,138 | -7,387 | ||||||||
Income (loss) before income taxes | -663,076 | 83,554 | -14,819 | ||||||||
Income tax benefit (expense) | -99,850 | -1,311 | 178 | ||||||||
Net income (loss) | -762,926 | 82,243 | -14,641 | ||||||||
MEMP [Member] | |||||||||||
Costs and expenses: | |||||||||||
Impairment of proved oil and natural gas properties | 407,500 | 28,871 | |||||||||
MEMP [Member] | Operating Segments [Member] | |||||||||||
Revenues: | |||||||||||
Oil & natural gas sales | 490,249 | 341,197 | 255,608 | ||||||||
Other revenues | 3,856 | 2,419 | 2,815 | ||||||||
Total revenues | 494,105 | 343,616 | 258,423 | ||||||||
Costs and expenses: | |||||||||||
Lease operating | 134,654 | 88,893 | 80,116 | ||||||||
Pipeline operating | 2,068 | 1,835 | 2,114 | ||||||||
Exploration | 790 | 1,130 | 2,463 | ||||||||
Production and ad valorem taxes | 31,601 | 17,784 | 16,048 | ||||||||
Depreciation, depletion, and amortization | 155,404 | 97,269 | 76,036 | ||||||||
Impairment of proved oil and natural gas properties | 407,540 | 54,362 | 10,532 | ||||||||
General and administrative | 45,619 | 43,495 | 30,342 | ||||||||
Accretion of asset retirement obligations | 5,618 | 4,853 | 4,377 | ||||||||
(Gain) loss on commodity derivative instruments | -492,254 | -26,281 | -21,417 | ||||||||
(Gain) loss on sale of properties | -2,848 | -9,759 | |||||||||
Other, net | -12 | 647 | 138 | ||||||||
Total costs and expenses | 291,028 | 281,139 | 190,990 | ||||||||
Operating income (loss) | 203,077 | 62,477 | 67,433 | ||||||||
Other income (expense): | |||||||||||
Interest expense, net | -83,550 | -41,901 | -20,436 | ||||||||
Amortization of investment premium | -194 | ||||||||||
Other, net | -327 | ||||||||||
Total other income (expense) | -83,877 | -41,901 | -20,630 | ||||||||
Income (loss) before income taxes | 119,200 | 20,576 | 46,803 | ||||||||
Income tax benefit (expense) | -1,121 | -308 | -285 | ||||||||
Net income (loss) | $118,079 | $20,268 | $46,518 |
Income_Taxes_Components_of_Inc
Income Taxes - Components of Income Tax Expense (Benefit) (Detail) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Current taxes: | |||
State | $22 | ($1,619) | $178 |
Deferred taxes: | |||
Federal | -88,994 | ||
State | -11,999 | -285 | |
Total income tax benefit (expense) | ($100,971) | ($1,619) | ($107) |
Income_Taxes_Additional_Inform
Income Taxes - Additional Information (Details) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Operating Loss Carryforwards [Line Items] | |||
Federal statutory corporate tax rate | 35.00% | ||
Unrecognized tax benefits | $0 | $0 | $0 |
Interest and penalties on unrecognized benefits | 0 | 0 | 0 |
United States [Member] | |||
Operating Loss Carryforwards [Line Items] | |||
Net operating loss carryforwards | 74,300,000 | ||
Operating loss carryforwards expiration start year | 2027 | ||
Operating loss carryforwards expiration end year | 2035 | ||
State [Member] | |||
Operating Loss Carryforwards [Line Items] | |||
Net operating loss carryforwards | $65,000,000 | ||
Minimum [Member] | State [Member] | |||
Operating Loss Carryforwards [Line Items] | |||
Operating loss carryforwards periods | 10 years | ||
Maximum [Member] | State [Member] | |||
Operating Loss Carryforwards [Line Items] | |||
Operating loss carryforwards periods | 20 years |
Income_Taxes_Reconciliation_of
Income Taxes - Reconciliation of Income Tax Benefit (Provision) (Detail) (USD $) | 12 Months Ended | |||||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |||
Income Tax Disclosure [Abstract] | ||||||
Expected tax benefit (expense) | $187,282 | ($53,533) | ($9,486) | |||
State income tax expense, net of federal benefit | -9,660 | -1,619 | -107 | |||
Pass-through entities (1) | 49,989 | [1] | 53,533 | [1] | 9,486 | [1] |
Stock compensation (2) | -330,024 | [2] | ||||
Other | 1,442 | |||||
Total income tax benefit (expense) | ($100,971) | ($1,619) | ($107) | |||
[1] | MEMP, a publicly traded partnership with qualifying income, is a pass-through entity for federal income tax purposes. In addition, our predecessor was also a pass-through entity for federal income tax purposes. | |||||
[2] | As discussed in Note 12, the compensation expense associated with the incentive units of WildHorse Resources and MRD Holdco created a nondeductible permanent difference for income tax purposes. |
Income_Taxes_Components_of_Net
Income Taxes - Components of Net Deferred Income Tax Assets and (Liabilities) (Detail) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Deferred current income tax assets: | ||
Unrealized hedging transactions | $109 | $37 |
Accrued liabilities | 5 | |
Other | 342 | -42 |
Deferred current income tax assets: | 451 | |
Deferred current income tax liabilities: | ||
Unrealized hedging transactions | -52,328 | |
Other | -52 | -382 |
Deferred current income tax liabilities: | -52,380 | -382 |
Deferred noncurrent income tax assets: | ||
Net operating loss carryforward | 28,043 | 2,350 |
Asset retirement obligation | 5,757 | 971 |
Other | 3,224 | 1 |
Net deferred tax valuation allowance | -2,634 | -2,896 |
Deferred noncurrent income tax assets: | 34,390 | 426 |
Deferred noncurrent income tax liabilities: | ||
Property, plant and equipment | -80,198 | -3,318 |
Unrealized hedging transactions | -48,929 | -275 |
Other | -280 | 61 |
Deferred noncurrent income tax liabilities: | -129,407 | -3,532 |
Net current deferred income tax assets (liabilities) | -51,929 | -382 |
Net noncurrent deferred income tax assets (liabilities) | ($95,017) | ($3,106) |
Commitments_and_Contingencies_1
Commitments and Contingencies - Environmental Reserves Activity (Detail) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Commitments And Contingencies Disclosure [Abstract] | |||
Balance at beginning of period | $577 | $1,469 | $1,747 |
Charged to costs and expenses | 2,852 | 193 | |
Payments | -1,337 | -892 | -471 |
Balance at end of period | $2,092 | $577 | $1,469 |
Commitments_and_Contingencies_2
Commitments and Contingencies - Additional Information (Detail) (USD $) | 12 Months Ended | 0 Months Ended | ||||||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Feb. 01, 2014 | Jan. 01, 2015 | Dec. 31, 2011 | Jun. 30, 2010 | Mar. 01, 2007 | |
MMBTU_day | ||||||||
Commitments And Contingencies (Additional Textual) [Abstract] | ||||||||
Accrued liabilities | $2,092,000 | $577,000 | $1,469,000 | $1,747,000 | ||||
Amount per barrel of oil | 0.25 | |||||||
Aggregate value of account required to cease fund | 4,300,000 | |||||||
Restricted investment | 2,700,000 | |||||||
Percentage of working interest under sinking fund trust agreement | 51.75% | |||||||
Additional quarterly payments | 600,000 | |||||||
Maximum remaining obligation | 8,700,000 | |||||||
Rent expense | 10,800,000 | 8,300,000 | 5,000,000 | |||||
Dubach [Member] | ||||||||
Commitments And Contingencies (Additional Textual) [Abstract] | ||||||||
Expansion of processing plant | 70 | |||||||
Dubberly [Member] | ||||||||
Commitments And Contingencies (Additional Textual) [Abstract] | ||||||||
Payback demand fee received by the third party | 110.00% | |||||||
Payback demand quality per day | 192,950 | |||||||
Payback of fee in excess of demand quantity | 0.275 | |||||||
Subsequent Event [Member] | Dubberly [Member] | ||||||||
Commitments And Contingencies (Additional Textual) [Abstract] | ||||||||
Monthly demand quantity | 249,700 | |||||||
December 31, 2016 [Member] | ||||||||
Commitments And Contingencies (Additional Textual) [Abstract] | ||||||||
Minimum balances attributable to net working interest | 78,660,000 | |||||||
REO Sponsorship [Member] | ||||||||
Commitments And Contingencies (Additional Textual) [Abstract] | ||||||||
Supplemental bond for decommissioning liabilities trust agreement | 90,000,000 | |||||||
Maximum [Member] | ||||||||
Commitments And Contingencies (Additional Textual) [Abstract] | ||||||||
Remaining obligation | $800,000 |
Commitments_and_Contingencies_3
Commitments and Contingencies - Minimum Balances Attributable to Net Working Interest (Detail) (USD $) | Dec. 31, 2014 |
In Thousands, unless otherwise specified | |
June 30, 2015 [Member] | |
Asset retirement obligations | |
Minimum balances attributable to net working interest | $72,450 |
June 30, 2016 [Member] | |
Asset retirement obligations | |
Minimum balances attributable to net working interest | 76,590 |
December 31, 2016 [Member] | |
Asset retirement obligations | |
Minimum balances attributable to net working interest | $78,660 |
Commitments_and_Contingencies_4
Commitments and Contingencies - Gross Held-to-Maturity Investments (Detail) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Held-to-maturity Securities [Abstract] | ||
Less: Outside working interest owners share, Amortized Cost | ($65,222) | |
Restricted investments | 77,361 | 73,385 |
BOEM platform abandonment [Member] | ||
Held-to-maturity Securities [Abstract] | ||
Restricted investments | 69,954 | 66,373 |
Money Market Funds [Member] | ||
Held-to-maturity Securities [Abstract] | ||
Amortized Cost | $135,176 |
Commitments_and_Contingencies_5
Commitments and Contingencies - CO2 Minimum Purchase Commitment (Detail) (Wyoming Acquisition [Member], USD $) | Dec. 31, 2014 |
In Thousands, unless otherwise specified | |
Wyoming Acquisition [Member] | |
Minimum Purchase Commitment [Line Items] | |
Estimated payment obligation, Total | $50,495 |
Estimated payment obligation, 2015 | 9,608 |
Estimated payment obligation, 2016 | 10,179 |
Estimated payment obligation, 2017 | 10,151 |
Estimated payment obligation, 2018 | 6,995 |
Estimated payment obligation, 2019 | 7,060 |
Estimated payment obligation, Thereafter | $6,502 |
Commitments_and_Contingencies_6
Commitments and Contingencies - Minimum Commitments to Gather before Other Owner Contributions (Detail) (USD $) | Dec. 31, 2014 |
In Thousands, unless otherwise specified | |
Dubach [Member] | |
Other Commitments [Line Items] | |
2015 | $13,671 |
2016 | 13,709 |
2017 | 13,671 |
2018 | 12,772 |
Total | 53,823 |
Dubberly [Member] | |
Other Commitments [Line Items] | |
2015 | 11,393 |
2016 | 11,424 |
2017 | 11,393 |
2018 | 10,643 |
Total | $44,853 |
Commitments_and_Contingencies_7
Commitments and Contingencies - Minimum Lease Payment Obligations and Sublease Rental Income Under Non-Cancelable Operating Leases (Detail) (USD $) | Dec. 31, 2014 |
In Thousands, unless otherwise specified | |
MRD [Member] | |
Operating leases | |
Total | $43,625 |
2015 | 6,534 |
2016 | 6,607 |
2017 | 6,694 |
2018 | 6,259 |
2019 | 5,960 |
Thereafter | 11,571 |
Sublease rental income | |
Sublease rental income, Total | 5,786 |
Sublease rental income, 2015 | 1,691 |
Sublease rental income, 2016 | 1,579 |
Sublease rental income, 2017 | 1,197 |
Sublease rental income, 2018 | 814 |
Sublease rental income, 2019 | 431 |
Sublease rental income, Thereafter | 74 |
MEMP [Member] | |
Operating leases | |
Total | 3,665 |
2015 | 788 |
2016 | 416 |
2017 | 205 |
2018 | 205 |
2019 | 205 |
Thereafter | $1,846 |
Defined_Contribution_Plans_Add
Defined Contribution Plans - Additional Information (Detail) (USD $) | 12 Months Ended | ||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Defined Contribution Plan Disclosure [Line Items] | |||
Employee eligibility age | 18 years | ||
Tax-deferred contributions | 100.00% | ||
Matching contribution | 100.00% | ||
Contribution By Participants, Percentage | 6.00% | ||
Employer contributions | $1.40 | $0.90 | $0.40 |
REO Sponsorship [Member] | |||
Defined Contribution Plan Disclosure [Line Items] | |||
Employee eligibility age | 21 years | ||
Tax-deferred contributions | 100.00% | ||
Matching contribution | 100.00% | ||
Contribution By Participants, Percentage | 6.00% | ||
Employer contributions | 0.6 | 0.5 | |
Defined contribution plan, company contribution, vesting period, years | 3 years | ||
Defined benefit plan cost and expense | 0.3 | 0.3 | |
WildHorse, Tanos, BlueStone, Classic and Black Diamond [Member] | |||
Defined Contribution Plan Disclosure [Line Items] | |||
Employer contributions | 0.2 | 0.5 | 0.6 |
Crown and Stanolind [Member] | |||
Defined Contribution Plan Disclosure [Line Items] | |||
Employer contributions | $0.10 | $0.10 |
Quarterly_Financial_Informatio2
Quarterly Financial Information (Unaudited) - Schedule of Quarterly Financial Information (Detail) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||
In Thousands, except Per Share data, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Quarterly Financial Data [Abstract] | |||||||||||
Revenues | $226,460 | $245,493 | $236,564 | $190,828 | $152,282 | $153,515 | $147,045 | $122,181 | $899,345 | $575,023 | $396,868 |
Operating income (loss) | 444,776 | 174,201 | -993,256 | 10,605 | 4,411 | 117,797 | 90,327 | 9,521 | -363,674 | 222,056 | 60,001 |
Net income (loss) | 328,859 | 112,037 | -1,053,443 | -23,516 | -22,968 | 95,962 | 78,158 | 180 | -636,063 | 151,332 | 26,997 |
Net income (loss) attributable to noncontrolling interest | 161,661 | 102,109 | -105,094 | -31,888 | 7,689 | 11,235 | 34,975 | -4,069 | 126,788 | 49,830 | -2,701 |
Net income (loss) attributable to Memorial Resource Development Corp. | 167,198 | 9,928 | -948,349 | 8,372 | -30,657 | 84,727 | 43,183 | 4,249 | -762,851 | 101,502 | 29,698 |
Net income (loss) allocated to members | 13,358 | 6,947 | -31,917 | 84,754 | 35,278 | 2,597 | 20,305 | 90,712 | -7,620 | ||
Net income (loss) allocated to previous owners | 1,425 | 1,260 | -27 | 7,905 | 1,652 | 1,425 | 10,790 | 37,318 | |||
Net income (loss) available to common stockholders | $167,198 | $9,928 | ($961,707) | ($784,581) | $0 | $0 | |||||
Basic EPS | $0.87 | $0.05 | ($5) | ($4.08) | $0 | $0 | |||||
Diluted EPS | $0.87 | $0.05 | ($5) | ($4.08) | $0 | $0 |
Capitalized_Costs_Relating_to_
Capitalized Costs Relating to Oil and Natural Gas Producing Activities (Detail) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |||
In Thousands, unless otherwise specified | ||||||
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items] | ||||||
Evaluated oil and natural gas properties | $4,598,211 | [1] | $2,974,855 | [1] | $2,591,861 | [1] |
Support equipment and facilities | 185,997 | 5,910 | 5,760 | |||
Unevaluated oil and natural gas properties | 48,229 | 46,413 | 31,593 | |||
Accumulated depletion, depreciation, and amortization | -1,334,235 | [1] | -623,362 | [1] | -468,291 | [1] |
Subtotal | 3,498,202 | 2,403,816 | 2,160,923 | |||
Eliminations [Member] | ||||||
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items] | ||||||
Accumulated depletion, depreciation, and amortization | 46,013 | 49,884 | ||||
MRD [Member] | ||||||
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items] | ||||||
Evaluated oil and natural gas properties | 1,590,997 | 1,226,417 | 1,052,219 | |||
Unevaluated oil and natural gas properties | 48,229 | 46,413 | 26,589 | |||
Accumulated depletion, depreciation, and amortization | -391,145 | -256,629 | -202,581 | |||
Subtotal | 1,248,081 | 1,016,201 | 876,227 | |||
MEMP [Member] | ||||||
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items] | ||||||
Evaluated oil and natural gas properties | 3,007,214 | [1] | 1,748,438 | [1] | 1,539,642 | [1] |
Support equipment and facilities | 185,997 | 5,910 | 5,760 | |||
Unevaluated oil and natural gas properties | 5,004 | |||||
Accumulated depletion, depreciation, and amortization | -989,103 | [1] | -416,617 | [1] | -265,710 | [1] |
Subtotal | $2,204,108 | $1,337,731 | $1,284,696 | |||
[1] | Amounts do not include costs for SPBPC and related support equipment. |
Costs_Incurred_for_Property_Ac
Costs Incurred for Property Acquisition, Exploration and Development (Detail) (USD $) | 12 Months Ended | |||||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |||
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | ||||||
Property acquisition costs, proved | $1,057,566 | $93,894 | $366,103 | |||
Property acquisition costs, unproved | 25,030 | 19,975 | 5,293 | |||
Exploration and extension well costs | 209,532 | 13,313 | 42,642 | |||
Development | 487,777 | [1] | 356,270 | [1] | 198,423 | [1] |
Subtotal | 1,779,905 | 483,452 | 612,461 | |||
MRD [Member] | ||||||
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | ||||||
Property acquisition costs, proved | 74,490 | 56,108 | 87,857 | |||
Property acquisition costs, unproved | 25,030 | 19,975 | 5,293 | |||
Exploration and extension well costs | 209,532 | 13,313 | 212 | |||
Development | 208,459 | 210,440 | 135,951 | |||
Subtotal | 517,511 | 299,836 | 229,313 | |||
MEMP [Member] | ||||||
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | ||||||
Property acquisition costs, proved | 983,076 | 37,786 | 278,246 | |||
Exploration and extension well costs | 42,430 | |||||
Development | 279,318 | [1] | 145,830 | [1] | 62,472 | [1] |
Subtotal | $1,262,394 | $183,616 | $383,148 | |||
[1] | Amounts do not include costs for SPBPC and related support equipment. |
Weighted_Average_Product_Price
Weighted Average Product Price (Detail) | 12 Months Ended | |||||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | ||||
Oil [Member] | West Texas Intermediate [Member] | ||||||
Supplemental Oil And Gas Reserve Information [Line Items] | ||||||
Price | 91.48 | [1] | 93.42 | [1] | 91.33 | [1] |
Natural Gas Liquids [Member] | West Texas Intermediate [Member] | ||||||
Supplemental Oil And Gas Reserve Information [Line Items] | ||||||
Price | 91.48 | [1] | 93.42 | [1] | 91.75 | [1] |
Natural Gas [Member] | Henry Hub [Member] | ||||||
Supplemental Oil And Gas Reserve Information [Line Items] | ||||||
Price | 4.35 | [2] | 3.67 | [2] | 2.75 | [2] |
[1] | The unweighted average West Texas Intermediate price was adjusted by lease for quality, transportation fees, and a regional price differential. | |||||
[2] | The unweighted average Henry Hub price was adjusted by lease for energy content, compression charges, transportation fees, and regional price differentials. |
Reserve_Quantity_Information_D
Reserve Quantity Information (Detail) | 12 Months Ended | |||||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | ||||
MBbls | MBbls | MBbls | ||||
MRD [Member] | Oil [Member] | ||||||
Proved developed and undeveloped reserves: | ||||||
Beginning of the year | 11,311 | [1] | 11,953 | [2] | 10,834 | |
Extensions and discoveries | 1,825 | 1,794 | 689 | |||
Purchase of minerals in place | 269 | 211 | 1,100 | |||
Production | -951 | -665 | -369 | |||
Sales of minerals in place | -623 | -599 | -4 | |||
Revision of previous estimates | 772 | -1,383 | -297 | |||
End of year | 12,603 | 11,311 | [1] | 11,953 | [2] | |
Proved developed reserves: | ||||||
Beginning of year | 3,402 | 3,082 | 2,107 | |||
End of year | 3,905 | 3,402 | 3,082 | |||
Proved undeveloped reserves: | ||||||
Beginning of year | 7,909 | 8,871 | 8,727 | |||
End of year | 8,698 | 7,909 | 8,871 | |||
MRD [Member] | Natural Gas [Member] | ||||||
Proved developed and undeveloped reserves: | ||||||
Beginning of the year | 802,254 | [1] | 739,378 | [2] | 929,335 | |
Extensions and discoveries | 183,527 | 149,974 | 42,019 | |||
Purchase of minerals in place | 22,186 | 31,815 | 28,115 | |||
Production | -63,801 | -34,092 | -24,131 | |||
Sales of minerals in place | -10,815 | -14,137 | -728 | |||
Revision of previous estimates | 247,578 | -70,684 | -235,232 | |||
End of year | 1,180,929 | 802,254 | [1] | 739,378 | [2] | |
Proved developed reserves: | ||||||
Beginning of year | 263,797 | 245,449 | 191,557 | |||
End of year | 392,181 | 263,797 | 245,449 | |||
Proved undeveloped reserves: | ||||||
Beginning of year | 538,457 | 493,929 | 737,778 | |||
End of year | 788,748 | 538,457 | 493,929 | |||
MRD [Member] | Natural Gas Liquids [Member] | ||||||
Proved developed and undeveloped reserves: | ||||||
Beginning of the year | 42,576 | [1] | 41,466 | [2] | 53,031 | |
Extensions and discoveries | 9,876 | 8,319 | 2,778 | |||
Purchase of minerals in place | 1,247 | 1,017 | 1,879 | |||
Production | -2,220 | -1,457 | -898 | |||
Sales of minerals in place | -950 | -1,573 | ||||
Revision of previous estimates | 12,060 | -5,196 | -15,324 | |||
End of year | 62,589 | 42,576 | [1] | 41,466 | [2] | |
Proved developed reserves: | ||||||
Beginning of year | 13,904 | 12,321 | 7,644 | |||
End of year | 19,924 | 13,904 | 12,321 | |||
Proved undeveloped reserves: | ||||||
Beginning of year | 28,672 | 29,145 | 45,387 | |||
End of year | 42,665 | 28,672 | 29,145 | |||
MRD [Member] | Natural Gas Equivalent [Member] | ||||||
Proved developed and undeveloped reserves: | ||||||
Beginning of the year | 1,125,577 | [1] | 1,059,895 | [2] | 1,312,533 | |
Extensions and discoveries | 253,730 | 210,652 | 62,819 | |||
Purchase of minerals in place | 31,283 | 39,183 | 45,987 | |||
Production | -82,816 | -46,819 | -31,731 | |||
Sales of minerals in place | -20,253 | -27,169 | -752 | |||
Revision of previous estimates | 324,558 | -110,165 | -328,961 | |||
End of year | 1,632,079 | 1,125,577 | [1] | 1,059,895 | [2] | |
Proved developed reserves: | ||||||
Beginning of year | 367,641 | 337,869 | 250,073 | |||
End of year | 535,151 | 367,641 | 337,869 | |||
Proved undeveloped reserves: | ||||||
Beginning of year | 757,936 | 722,026 | 1,062,460 | |||
End of year | 1,096,928 | 757,936 | 722,026 | |||
MEMP [Member] | Oil [Member] | ||||||
Proved developed and undeveloped reserves: | ||||||
Beginning of the year | 39,149 | [3] | 39,089 | [4] | 27,150 | |
Extensions and discoveries | 849 | 5,655 | 7,501 | |||
Purchase of minerals in place | 69,095 | 119 | 11,336 | |||
Production | -3,092 | -1,764 | -1,519 | |||
Sales of minerals in place | -4,214 | |||||
Revision of previous estimates | -6,431 | -3,950 | -1,165 | |||
End of year | 99,570 | [5] | 39,149 | [3] | 39,089 | [4] |
Proved developed reserves: | ||||||
Beginning of year | 22,265 | 24,515 | 19,332 | |||
End of year | 54,526 | 22,265 | 24,515 | |||
Proved undeveloped reserves: | ||||||
Beginning of year | 16,884 | 14,574 | 7,818 | |||
End of year | 45,044 | 16,884 | 14,574 | |||
MEMP [Member] | Natural Gas [Member] | ||||||
Proved developed and undeveloped reserves: | ||||||
Beginning of the year | 607,139 | [3] | 604,440 | [4] | 579,751 | |
Extensions and discoveries | 12,723 | 40,770 | 19,869 | |||
Purchase of minerals in place | 13,036 | 16,294 | 113,617 | |||
Production | -41,494 | -35,924 | -29,744 | |||
Sales of minerals in place | -4,214 | |||||
Revision of previous estimates | -31,777 | -18,441 | -74,839 | |||
End of year | 559,627 | [5] | 607,139 | [3] | 604,440 | [4] |
Proved developed reserves: | ||||||
Beginning of year | 387,548 | 376,932 | 413,431 | |||
End of year | 380,397 | 387,548 | 376,932 | |||
Proved undeveloped reserves: | ||||||
Beginning of year | 219,591 | 227,508 | 166,320 | |||
End of year | 179,230 | 219,591 | 227,508 | |||
MEMP [Member] | Natural Gas Liquids [Member] | ||||||
Proved developed and undeveloped reserves: | ||||||
Beginning of the year | 28,846 | [3] | 29,352 | [4] | 15,045 | |
Extensions and discoveries | 711 | 1,747 | 1,053 | |||
Purchase of minerals in place | 22,351 | 258 | 7,095 | |||
Production | -2,143 | -1,632 | -745 | |||
Revision of previous estimates | -287 | -879 | 6,904 | |||
End of year | 49,478 | [5] | 28,846 | [3] | 29,352 | [4] |
Proved developed reserves: | ||||||
Beginning of year | 15,959 | 15,947 | 10,015 | |||
End of year | 35,539 | 15,959 | 15,947 | |||
Proved undeveloped reserves: | ||||||
Beginning of year | 12,887 | 13,405 | 5,030 | |||
End of year | 13,939 | 12,887 | 13,405 | |||
MEMP [Member] | Natural Gas Equivalent [Member] | ||||||
Proved developed and undeveloped reserves: | ||||||
Beginning of the year | 1,015,105 | [3] | 1,015,095 | [4] | 832,913 | |
Extensions and discoveries | 22,085 | 85,180 | 71,192 | |||
Purchase of minerals in place | 561,713 | 18,554 | 224,202 | |||
Production | -72,902 | -56,303 | -43,329 | |||
Sales of minerals in place | -29,499 | |||||
Revision of previous estimates | -72,090 | -47,421 | -40,384 | |||
End of year | 1,453,911 | [5] | 1,015,105 | [3] | 1,015,095 | [4] |
Proved developed reserves: | ||||||
Beginning of year | 616,893 | 619,704 | 589,504 | |||
End of year | 920,783 | 616,893 | 619,704 | |||
Proved undeveloped reserves: | ||||||
Beginning of year | 398,212 | 395,391 | 243,409 | |||
End of year | 533,128 | 398,212 | 395,391 | |||
[1] | Includes reserves of 41,077 MMcfe attributable to noncontrolling interests and the MRD Segment previous owners. | |||||
[2] | Includes reserves of 67,135 MMcfe attributable to noncontrolling interests and the MRD Segment previous owners. | |||||
[3] | MRD Segmentbs share of these reserves is 89,837 MMcfe. | |||||
[4] | MRD Segmentbs share of these reserves is 476,550 MMcfe. | |||||
[5] | MRD Segmentbs share of these reserves is 1,454 MMcfe. |
Reserve_Quantity_Information_P
Reserve Quantity Information (Parenthetical) (Detail) (Natural Gas Equivalent [Member]) | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | ||
MMcfe | MMcfe | MMcfe | MMcfe | |||
MRD [Member] | ||||||
Reserve Quantities [Line Items] | ||||||
End of year | 1,632,079 | 1,125,577 | [1] | 1,059,895 | [2] | 1,312,533 |
Parent Company | MRD [Member] | ||||||
Reserve Quantities [Line Items] | ||||||
End of year | 1,454 | 89,837 | 476,550 | |||
Noncontrolling Interest [Member] | ||||||
Reserve Quantities [Line Items] | ||||||
End of year | 41,077 | 67,135 | ||||
[1] | Includes reserves of 41,077 MMcfe attributable to noncontrolling interests and the MRD Segment previous owners. | |||||
[2] | Includes reserves of 67,135 MMcfe attributable to noncontrolling interests and the MRD Segment previous owners. |
Recovered_Sheet1
Supplemental Oil And Gas Information - Additional Information (Detail) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2012 | Dec. 31, 2013 | |
Bcfe | Bcfe | Bcfe | |
Reserve Quantities [Line Items] | |||
Multiple acquisitions | 561.7 | 224.2 | |
MRD [Member] | |||
Reserve Quantities [Line Items] | |||
Upward revisions in proved reserve | 324.6 | ||
MRD [Member] | WildHorse Resources, LLC [Member] | |||
Reserve Quantities [Line Items] | |||
Extensions and discoveries | 148.6 | ||
Multiple acquisitions | 43.5 | ||
Terryville Acquisition [Member] | MRD [Member] | |||
Reserve Quantities [Line Items] | |||
Extensions and discoveries | 253.7 | ||
Multiple acquisitions | 31.3 | ||
Wyoming Acquisition [Member] | |||
Reserve Quantities [Line Items] | |||
Multiple acquisitions, Largest acquisition | 497.2 | ||
Eagle Ford Acquisition [Member] | |||
Reserve Quantities [Line Items] | |||
Multiple acquisitions | 45 | ||
Goodrich [Member] | |||
Reserve Quantities [Line Items] | |||
Multiple acquisitions, Largest acquisition | 148.9 | ||
Stanolind [Member] | |||
Reserve Quantities [Line Items] | |||
Multiple acquisitions | 43.6 | ||
Menemsha [Member] | |||
Reserve Quantities [Line Items] | |||
Multiple acquisitions, Largest acquisition | 23.9 | ||
Propel [Member] | |||
Reserve Quantities [Line Items] | |||
Divestiture of Oil and Gas Properties | 19 |
Discounted_Future_Net_Cash_Flo
Discounted Future Net Cash Flows (Detail) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |||
In Thousands, unless otherwise specified | |||||||
MRD [Member] | |||||||
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items] | |||||||
Future cash inflows | $8,313,329 | $5,722,848 | $4,921,192 | ||||
Future production costs | -1,325,573 | -1,587,374 | -1,255,289 | ||||
Future development costs | -1,443,612 | -1,352,945 | -1,060,777 | ||||
Future income tax expense | -1,789,031 | [1] | |||||
Future net cash flows for estimated timing of cash flows | 3,755,113 | 2,782,529 | 2,605,126 | ||||
10% annual discount for estimated timing of cash flows | -1,792,579 | -1,313,577 | -1,284,531 | ||||
Standardized measure of discounted future net cash flows | 1,962,534 | [2] | 1,468,952 | [2] | 1,320,595 | [2] | 1,386,071 |
MEMP [Member] | |||||||
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items] | |||||||
Future cash inflows | 13,191,866 | 6,892,150 | 6,511,776 | ||||
Future production costs | -4,516,077 | -2,719,024 | -2,258,554 | ||||
Future development costs | -1,222,221 | -685,858 | -620,944 | ||||
Future net cash flows for estimated timing of cash flows | 7,453,568 | [3] | 3,487,268 | [3] | 3,632,278 | [3] | |
10% annual discount for estimated timing of cash flows | -4,693,960 | -1,879,156 | -2,042,362 | ||||
Standardized measure of discounted future net cash flows | $2,759,608 | [4] | $1,608,112 | [4] | $1,589,916 | [4] | $1,499,414 |
[1] | Our predecessor was a pass through entity and was subject to the Texas margin tax which has a maximum effective rate of 0.7% of gross income apportioned to Texas. Due to immateriality, we have excluded the impact of this tax for the years ended DecemberB 31, 2013 and 2012. | ||||||
[2] | Includes $63,422 and $78,518 attributable to both noncontrolling interests and the MRD Segment previous owners for the years ended DecemberB 31, 2013 and 2012, respectively. | ||||||
[3] | MEMP is subject to the Texas margin tax which has a maximum effective rate of 0.7% of gross income apportioned to Texas. Due to immateriality we have excluded the impact of this tax for the years ended DecemberB 31, 2014, 2013 and 2012. | ||||||
[4] | MRD Segmentbs share of the standardized measure of discounted future net cash flows was $2,760, $142,318 and $554,981 for the years ended December 31, 2014, 2013 and 2012, respectively. |
Discounted_Future_Net_Cash_Flo1
Discounted Future Net Cash Flows (Parenthetical) (Detail) (USD $) | 12 Months Ended | ||||||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | |||
MRD [Member] | |||||||
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items] | |||||||
Standardized measure of discounted future net cash flows | 1,962,534 | [1] | 1,468,952 | [1] | 1,320,595 | [1] | $1,386,071 |
MRD [Member] | Parent Company | |||||||
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items] | |||||||
Standardized measure of discounted future net cash flows | 2,760 | 142,318 | 554,981 | ||||
MRD [Member] | Maximum [Member] | Texas Margin Tax [Member] | |||||||
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items] | |||||||
Franchise effective tax rate | 0.70% | 0.70% | 0.70% | ||||
MEMP [Member] | |||||||
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items] | |||||||
Standardized measure of discounted future net cash flows | 2,759,608 | [2] | 1,608,112 | [2] | 1,589,916 | [2] | 1,499,414 |
MEMP [Member] | Maximum [Member] | Texas Margin Tax [Member] | |||||||
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items] | |||||||
Franchise effective tax rate | 0.70% | 0.70% | 0.70% | ||||
Noncontrolling Interest [Member] | Previous Owners [Member] | |||||||
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items] | |||||||
Standardized measure of discounted future net cash flows | 63,422 | 78,518 | |||||
[1] | Includes $63,422 and $78,518 attributable to both noncontrolling interests and the MRD Segment previous owners for the years ended DecemberB 31, 2013 and 2012, respectively. | ||||||
[2] | MRD Segmentbs share of the standardized measure of discounted future net cash flows was $2,760, $142,318 and $554,981 for the years ended December 31, 2014, 2013 and 2012, respectively. |
Summary_of_the_Changes_in_the_
Summary of the Changes in the Standardized Measure of Future Net Cash Flows (Detail) (USD $) | 12 Months Ended | ||||||||||||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | ||||||||||
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items] | |||||||||||||
Restricted Investments | |||||||||||||
Note 7. Restricted Investments | |||||||||||||
Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with the offshore Southern California oil and gas properties owned by MEMP. | |||||||||||||
The components of the restricted investment balance are as follows at December 31, 2014 and 2013: | |||||||||||||
2014 | 2013 | ||||||||||||
(In thousands) | |||||||||||||
BOEM platform abandonment (See Note 16) | $ | 69,954 | $ | 66,373 | |||||||||
BOEM lease bonds | 794 | 794 | |||||||||||
SPBPC Collateral: | |||||||||||||
Contractual pipeline and surface facilities abandonment | 2,701 | 2,306 | |||||||||||
California State Lands Commission pipeline right-of-way bond | 3,005 | 3,005 | |||||||||||
City of Long Beach pipeline facility permit | 500 | 500 | |||||||||||
Federal pipeline right-of-way bond | 307 | 307 | |||||||||||
Port of Long Beach pipeline license | 100 | 100 | |||||||||||
Restricted investments | $ | 77,361 | $ | 73,385 | |||||||||
MRD [Member] | |||||||||||||
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items] | |||||||||||||
Beginning of year | $1,468,952 | [1] | $1,320,595 | [1] | $1,386,071 | ||||||||
Sale of oil and natural gas produced, net of production costs | -363,723 | -196,444 | -107,316 | ||||||||||
Purchase of minerals in place | 69,282 | 51,177 | 98,384 | ||||||||||
Sale of minerals in place | -47,791 | -54,091 | |||||||||||
Extensions and discoveries | 653,186 | 301,004 | 127,994 | ||||||||||
Changes in income taxes, net | -1,058,814 | ||||||||||||
Changes in prices and costs | 365,030 | -11,336 | -402,202 | ||||||||||
Previously estimated development costs incurred | 256,605 | 87,297 | 64,390 | ||||||||||
Net changes in future development costs | -126,598 | 57,353 | -67,331 | ||||||||||
Revisions of previous quantities | 828,296 | -186,804 | -176,788 | ||||||||||
Accretion of discount | 146,896 | 128,544 | 138,607 | ||||||||||
Change in production rates and other | -228,787 | -28,343 | 258,786 | ||||||||||
End of year | 1,962,534 | [1] | 1,468,952 | [1] | 1,320,595 | [1] | |||||||
MEMP [Member] | |||||||||||||
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items] | |||||||||||||
Beginning of year | 1,608,112 | [2] | 1,589,916 | [2] | 1,499,414 | ||||||||
Sale of oil and natural gas produced, net of production costs | -323,994 | -234,520 | -160,023 | ||||||||||
Purchase of minerals in place | 1,489,477 | 23,160 | 375,953 | ||||||||||
Sale of minerals in place | -154,963 | ||||||||||||
Extensions and discoveries | 44,745 | 136,423 | 265,108 | ||||||||||
Changes in income taxes, net | 1,947 | ||||||||||||
Changes in prices and costs | -168,500 | -74,395 | -331,760 | ||||||||||
Previously estimated development costs incurred | 223,861 | 174,490 | 66,360 | ||||||||||
Net changes in future development costs | -74,579 | -74,867 | -1,140 | ||||||||||
Revisions of previous quantities | -163,207 | -141,122 | -90,587 | ||||||||||
Accretion of discount | 160,811 | 158,991 | 150,136 | ||||||||||
Change in production rates and other | -37,118 | 50,036 | -30,529 | ||||||||||
End of year | $2,759,608 | [2] | $1,608,112 | [2] | $1,589,916 | [2] | |||||||
[1] | Includes $63,422 and $78,518 attributable to both noncontrolling interests and the MRD Segment previous owners for the years ended DecemberB 31, 2013 and 2012, respectively. | ||||||||||||
[2] | MRD Segmentbs share of the standardized measure of discounted future net cash flows was $2,760, $142,318 and $554,981 for the years ended December 31, 2014, 2013 and 2012, respectively. |