Document and Entity Information
Document and Entity Information - USD ($) $ in Billions | 12 Months Ended | ||
Dec. 31, 2015 | Jan. 31, 2016 | Jun. 30, 2015 | |
Document And Entity Information [Abstract] | |||
Document Type | 10-K | ||
Amendment Flag | false | ||
Document Period End Date | Dec. 31, 2015 | ||
Document Fiscal Year Focus | 2,015 | ||
Document Fiscal Period Focus | FY | ||
Trading Symbol | MRD | ||
Entity Registrant Name | MEMORIAL RESOURCE DEVELOPMENT CORP. | ||
Entity Central Index Key | 1,599,222 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Well Known Seasoned Issuer | Yes | ||
Entity Current Reporting Status | Yes | ||
Entity Voluntary Filers | No | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Common Stock, Shares Outstanding | 205,308,614 | ||
Entity Public Float | $ 1.6 |
CONSOLIDATED AND COMBINED BALAN
CONSOLIDATED AND COMBINED BALANCE SHEETS - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Current assets: | ||
Cash and cash equivalents | $ 2,175 | $ 5,958 |
Accounts receivable: | ||
Oil and natural gas sales | 45,872 | 82,263 |
Joint interest owners and other | 68,223 | 49,313 |
Short-term derivative instruments | 500,311 | 340,056 |
Other financial instruments (Note 5) | 46,106 | |
Prepaid expenses and other current assets | 13,017 | 23,203 |
Total current assets | 675,704 | 500,793 |
Property and equipment, at cost: | ||
Oil and natural gas properties, successful efforts method (Note 2) | 5,982,209 | 4,844,529 |
Other | 26,826 | 33,815 |
Accumulated depreciation, depletion and impairment | (2,317,651) | (1,340,688) |
Property and equipment, net | 3,691,384 | 3,537,656 |
Long-term derivative instruments | 553,101 | 435,369 |
Restricted investments | 152,631 | 77,361 |
Other long-term assets | 10,029 | 8,647 |
Total assets | 5,082,849 | 4,559,826 |
Current liabilities: | ||
Accounts payable | 33,849 | 25,772 |
Accounts payable - affiliates | 5,209 | 624 |
Revenues payable | 61,047 | 57,352 |
Accrued liabilities (Note 2) | 121,799 | 147,071 |
Short-term derivative instruments | 2,850 | 3,289 |
Total current liabilities | 224,754 | 234,108 |
Noncurrent liabilities: | ||
Long-term debt | 3,012,643 | 2,344,692 |
Asset retirement obligations | 173,068 | 122,531 |
Long-term derivative instruments | 1,441 | |
Deferred tax liabilities | 195,827 | 146,946 |
Other long-term liabilities | 7,195 | 8,585 |
Total liabilities | $ 3,614,928 | $ 2,856,862 |
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; 205,293,743 shares issued and outstanding at December 31, 2015; 193,435,414 shares issued and outstanding at December 31, 2014 | $ 2,053 | $ 1,935 |
Additional paid-in capital | 1,560,949 | 1,367,346 |
Accumulated earnings (deficit) | (740,175) | (786,871) |
Total stockholders' equity | 822,827 | 582,410 |
Noncontrolling interests | 645,094 | 1,120,554 |
Total equity | 1,467,921 | 1,702,964 |
Total liabilities and equity | 5,082,849 | 4,559,826 |
MRD Segment [Member] | ||
Noncurrent liabilities: | ||
Long-term debt | 1,012,064 | 770,545 |
MEMP [Member] | ||
Property and equipment, at cost: | ||
Property and equipment, net | 408,600 | |
Noncurrent liabilities: | ||
Long-term debt | $ 2,000,579 | $ 1,574,147 |
CONSOLIDATED AND COMBINED BALA3
CONSOLIDATED AND COMBINED BALANCE SHEETS (Parenthetical) - $ / shares | Dec. 31, 2015 | Dec. 31, 2014 |
Statement Of Financial Position [Abstract] | ||
Preferred stock, par value | $ 0.01 | $ 0.01 |
Preferred stock, shares authorized | 50,000,000 | 50,000,000 |
Preferred stock, shares issued | 0 | 0 |
Preferred stock, shares outstanding | 0 | 0 |
Common stock, par value | $ 0.01 | $ 0.01 |
Common stock, shares authorized | 600,000,000 | 600,000,000 |
Common stock, shares issued | 205,293,743 | 193,435,414 |
Common stock, shares outstanding | 205,293,743 | 193,435,414 |
STATEMENTS OF CONSOLIDATED AND
STATEMENTS OF CONSOLIDATED AND COMBINED OPERATIONS - USD ($) shares in Thousands, $ in Thousands | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Revenues: | ||||
Oil & natural gas sales | $ 729,464 | $ 970,747 | $ 610,992 | |
Other revenues | 2,725 | 4,378 | 3,075 | |
Total revenues | 732,189 | 975,125 | 614,067 | |
Costs and expenses: | ||||
Lease operating | 193,102 | 161,303 | 111,798 | |
Gathering, processing, and transportation | 107,493 | 77,848 | 42,721 | |
Gathering, processing, and transportation - affiliate | 25,403 | |||
Exploration | 11,286 | 16,603 | 2,356 | |
Taxes other than income | 40,724 | 45,751 | 27,146 | |
Depreciation, depletion, and amortization | 384,556 | 314,193 | 184,717 | |
Impairment of proved oil and natural gas properties | 616,784 | 432,116 | 6,600 | |
Incentive unit compensation expense | 35,142 | 943,949 | 43,279 | |
General and administrative | 102,959 | 87,673 | 82,079 | |
Accretion of asset retirement obligations | 7,542 | 6,306 | 5,581 | |
(Gain) loss on commodity derivative instruments | (744,139) | (749,988) | (29,294) | |
(Gain) loss on sale of properties | (3,045) | 3,057 | (85,621) | |
Other, net | (665) | (12) | 649 | |
Total costs and expenses | 777,142 | 1,338,799 | 392,011 | |
Operating income (loss) | (44,953) | (363,674) | 222,056 | |
Other income (expense): | ||||
Interest expense, net | (154,128) | (133,833) | (69,250) | |
Loss on extinguishment of debt | 0 | (37,248) | ||
Other, net | (979) | (337) | 145 | |
Total other income (expense) | (155,107) | (171,418) | (69,105) | |
Income (loss) before income taxes | (200,060) | (535,092) | 152,951 | |
Income tax benefit (expense) | (97,830) | (100,971) | (1,619) | |
Net income (loss) | (297,890) | (636,063) | 151,332 | |
Net income (loss) attributable to noncontrolling interest | (393,538) | 126,788 | 49,830 | |
Net income (loss) attributable to Memorial Resource Development Corp. | 95,648 | (762,851) | 101,502 | |
Net (income) loss allocated to members | 0 | (20,305) | (90,712) | |
Net (income) loss allocated to previous owners | 0 | (1,425) | $ (10,790) | |
Net (income) allocated to participating restricted stockholders | (734) | |||
Net income (loss) available to common stockholders | $ 94,914 | $ (784,581) | ||
Earnings per common share: (Note 10) | ||||
Basic | $ 0.49 | $ (4.08) | ||
Diluted | [1] | $ 0.49 | $ (4.08) | |
Weighted average common and common equivalent shares outstanding: | ||||
Basic | 193,698 | 192,498 | ||
Diluted | 193,698 | 192,498 | ||
[1] | The Company determines the more dilutive of either the two-class method or the treasury stock method for diluted EPS. The two-class method was more dilutive for each period presented. |
STATEMENTS OF CONSOLIDATED AND5
STATEMENTS OF CONSOLIDATED AND COMBINED CASH FLOWS - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Cash flows from operating activities: | |||
Net income (loss) | $ (297,890) | $ (636,063) | $ 151,332 |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||
Depreciation, depletion, and amortization | 384,556 | 314,193 | 184,717 |
Impairment of proved oil and natural gas properties | 616,784 | 432,116 | 6,600 |
(Gain) loss on derivatives | (739,465) | (749,843) | (29,533) |
Cash settlements (paid) received on expired derivative instruments | 420,942 | 20,559 | 30,403 |
Cash settlements on terminated derivatives | 140,188 | 5,326 | |
Premiums paid for derivatives | (94,082) | (6,065) | |
Loss on extinguishment of debt | 0 | 30,248 | |
Amortization of deferred financing costs | 8,881 | 7,436 | 8,343 |
Accretion of senior notes net discount | 2,430 | 2,501 | 554 |
Accretion of asset retirement obligations | 7,542 | 6,306 | 5,581 |
Amortization of equity awards | 19,597 | 10,678 | 3,557 |
Settlement of asset retirement obligations | (1,430) | ||
(Gain) loss on sale of properties | (3,045) | 3,057 | (85,621) |
Non-cash compensation expense | 35,142 | 916,218 | 1,057 |
Deferred income tax expense (benefit) | 87,701 | 100,230 | 76 |
Exploration costs | 2,163 | 14,953 | 181 |
Changes in operating assets and liabilities: | |||
Accounts receivable | 32,784 | (17,635) | (15,758) |
Prepaid expenses and other assets | 10,004 | (7,424) | (2,986) |
Payables and accrued liabilities | 1,410 | 21,208 | 19,320 |
Other | (301) | 8,272 | |
Net cash provided by operating activities | 633,911 | 476,271 | 277,823 |
Cash flows from investing activities: | |||
Acquisitions of oil and natural gas properties | (382,696) | (1,177,670) | (105,762) |
Additions to oil and gas properties | (836,200) | (674,396) | (360,015) |
Additions to other property and equipment | (3,789) | (17,067) | (2,670) |
Additions to restricted investments | (5,690) | (3,976) | (5,361) |
Other financial instruments | (46,106) | ||
Deposits for property acquisitions | 0 | (215) | |
Decrease (increase) in restricted cash | 0 | 49,946 | (49,347) |
Proceeds from the sale of oil and natural gas properties | 14,192 | 6,700 | 155,712 |
Other | 0 | (301) | |
Net cash used in investing activities | (1,260,289) | (1,816,979) | (367,443) |
Cash flows from financing activities: | |||
Advances on revolving credit facilities | 1,360,000 | 2,746,800 | 1,132,755 |
Payments on revolving credit facilities | (696,000) | (2,457,900) | (1,766,037) |
Termination of second lien credit facility | 0 | (328,282) | |
Proceeds from the issuance of senior notes | 0 | 1,092,425 | 1,031,563 |
Redemption of senior notes | (2,914) | (351,808) | |
Borrowings under second lien credit facility | 0 | 325,000 | |
Deferred financing costs | (1,839) | (30,334) | (41,175) |
Purchase of additional interests in consolidated subsidiaries | (5,946) | (3,292) | (15,135) |
Proceeds from changes in ownership interests in MEMP | 0 | 135,012 | |
Contributions from previous owners | 0 | 1,214 | |
Distributions to the Funds | 0 | (732,362) | |
Distributions to noncontrolling interests | (163,007) | (149,084) | (78,083) |
Distributions made by previous owners | 0 | (4,005) | |
Cash retained by previous owners | 0 | (7,909) | |
Repurchased shares under repurchase program | (106,666) | ||
Other | 0 | 320 | 455 |
Net cash provided by financing activities | 622,595 | 1,268,945 | 117,950 |
Net change in cash and cash equivalents | (3,783) | (71,763) | 28,330 |
Cash and cash equivalents, beginning of period | 5,958 | 77,721 | 49,391 |
Cash and cash equivalents, end of period | 2,175 | 5,958 | 77,721 |
Natural Gas Partners [Member] | |||
Cash flows from financing activities: | |||
Contributions from NGP affiliates related to sale of assets | 860 | 1,165 | 2,013 |
Distribution to NGP affiliates related to purchase of assets | 0 | (66,693) | (355,494) |
Distribution to NGP affiliates related to sale of assets, net of cash received | 0 | (32,770) | |
MRD Holdco LLC [Member] | |||
Cash flows from financing activities: | |||
Distribution to MRD Holdco | 0 | (59,803) | |
MRD Segment [Member] | |||
Cash flows from financing activities: | |||
Proceeds from MRD equity offering | 242,880 | 408,500 | |
Costs incurred in conjunction with equity offering | (4,773) | (28,373) | |
Repurchased shares under repurchase program | (51,197) | (161) | |
MEMP [Member] | |||
Cash flows from financing activities: | |||
Costs incurred in conjunction with equity offering | 0 | (12,510) | (21,066) |
Proceeds from MEMP equity offering | 0 | 553,288 | 511,204 |
Proceeds from changes in ownership interests in MEMP | $ 135,012 | ||
Contributions from NGP affiliates related to sale of assets | 860 | ||
Repurchased shares under repurchase program | (54,184) | (11,531) | |
Restricted units returned to plan | $ (1,285) | $ (1,012) |
STATEMENTS OF CONSOLIDATED AND6
STATEMENTS OF CONSOLIDATED AND COMBINED EQUITY - USD ($) $ in Thousands | Total | Member Equity [Member] | MRD Segment [Member] | MRD Segment [Member]Member Equity [Member] | MEMP [Member] | MEMP [Member]Member Equity [Member] | Common Stock [Member] | Common Stock [Member]MRD Segment [Member] | Common Stock [Member]MEMP [Member] | Additional Paid-in Capital [Member] | Additional Paid-in Capital [Member]MRD Segment [Member] | Additional Paid-in Capital [Member]MEMP [Member] | Accumulated earnings (deficit) [Member] | Accumulated earnings (deficit) [Member]MRD Segment [Member] | Accumulated earnings (deficit) [Member]MEMP [Member] | Previous Owners [Member]Member Equity [Member] | Previous Owners [Member]MRD Segment [Member]Member Equity [Member] | Previous Owners [Member]MEMP [Member]Member Equity [Member] | Noncontrolling Interest [Member] | Noncontrolling Interest [Member]MRD Segment [Member] | Noncontrolling Interest [Member]MEMP [Member] |
Total equity, beginning balance at Dec. 31, 2012 | $ 1,276,709 | ||||||||||||||||||||
Noncontrolling interests, beginning balance at Dec. 31, 2012 | $ 231,662 | ||||||||||||||||||||
Members' equity, beginning balance at Dec. 31, 2012 | $ 811,614 | $ 233,433 | |||||||||||||||||||
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 | 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 | $ 0 | $ 0 | $ 0 | (181,556) | 130,805 | ||||||||||||||
Amortization of MEMP equity awards | 3,558 | 0 | 0 | 0 | 0 | 0 | 3,558 | ||||||||||||||
Distribution to NGP affiliates in connection with acquisition of assets | (351,235) | (98,180) | 0 | 0 | 0 | 0 | (253,055) | ||||||||||||||
Noncontrolling interest's share of cash consideration received in excess of the net book value sold to MEMP | 0 | (24) | 0 | 0 | 0 | 0 | 24 | ||||||||||||||
Purchase of noncontrolling interests | (15,135) | (303) | 0 | 0 | 0 | 0 | (14,832) | ||||||||||||||
Impact of equity transactions of MEMP | 0 | 54,183 | 0 | 0 | 0 | 0 | (54,183) | ||||||||||||||
Other | (1,765) | 94 | 0 | 0 | 0 | (2,299) | 440 | ||||||||||||||
Net assets retained by previous owners | (17,246) | 0 | 0 | 0 | 0 | (17,246) | 0 | ||||||||||||||
Members' equity, ending balance at Dec. 31, 2013 | 237,186 | 40,331 | |||||||||||||||||||
Total stockholders equity, ending balance at Dec. 31, 2013 | 0 | 0 | 0 | ||||||||||||||||||
Total equity, ending balance at Dec. 31, 2013 | 858,132 | ||||||||||||||||||||
Noncontrolling interests, ending balance at Dec. 31, 2013 | 580,615 | ||||||||||||||||||||
Net income (loss) | (636,063) | 20,305 | 0 | 0 | (784,581) | 1,425 | 126,788 | ||||||||||||||
Issuance of shares in connection with restructuring transactions (see Note 1) | 914,862 | 0 | 1,710 | 913,152 | 0 | 0 | 0 | ||||||||||||||
Issuance of shares in connection with initial public offering (see Note 1) | 380,177 | 0 | 215 | 379,962 | 0 | 0 | 0 | ||||||||||||||
Tax related effects in connection with restructuring transactions and initial public offering | (43,251) | 0 | 0 | (43,251) | 0 | 0 | 0 | ||||||||||||||
Share repurchase | (2,200) | $ (2,215) | $ 0 | $ (12,903) | $ 0 | $ (1) | $ 0 | $ 0 | $ 0 | $ (2,214) | $ 0 | $ 0 | $ 0 | $ 0 | $ (12,903) | ||||||
Restricted stock awards | 0 | 0 | 11 | (11) | 0 | 0 | 0 | ||||||||||||||
Amortization of restricted stock awards | 2,804 | 0 | 0 | 2,804 | 0 | 0 | 0 | ||||||||||||||
Contribution related to MRD Holdco incentive unit compensation expense (see Note 12) | 111,866 | 0 | 0 | 111,866 | 0 | 0 | 0 | ||||||||||||||
Net Proceeds from MEMP public equity offering | 540,698 | 0 | 0 | 0 | 0 | 0 | 540,698 | ||||||||||||||
Distributions | (149,084) | 0 | 0 | 0 | 0 | 0 | (149,084) | ||||||||||||||
Net book value of net assets acquired from affiliates | 3,303 | 45,059 | 0 | 0 | 0 | (41,756) | 0 | ||||||||||||||
Amortization of MEMP equity awards | 7,874 | 0 | 0 | 0 | 0 | 0 | 7,874 | ||||||||||||||
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 NGP affiliates in connection with acquisition of assets | (66,693) | (66,693) | 0 | 0 | 0 | 0 | 0 | ||||||||||||||
Purchase of noncontrolling interests | (3,292) | 0 | 0 | (2,881) | 0 | 0 | (411) | ||||||||||||||
Distribution of net assets to MRD Holdco | (93,084) | (123,078) | 0 | 0 | 0 | 0 | 29,994 | ||||||||||||||
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 | 5,327 | 0 | 0 | (2,668) | ||||||||||||||
Other | 811 | (154) | 0 | 378 | (76) | 0 | 663 | ||||||||||||||
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 | |||||||||||||||||||
MEMP restricted units repurchased | (1,012) | $ 0 | 0 | 0 | 0 | $ 0 | (1,012) | ||||||||||||||
Net income (loss) | (297,890) | 0 | 0 | 95,648 | (393,538) | ||||||||||||||||
Contributions | 2,962 | 0 | 0 | 0 | 2,962 | ||||||||||||||||
Issuance of shares in connection with initial public offering (see Note 1) | 242,880 | 138 | 242,742 | 0 | 0 | ||||||||||||||||
Share repurchase | $ (47,785) | $ (53,999) | $ (28) | $ 0 | $ 0 | $ 0 | $ (47,757) | $ 0 | $ 0 | $ (53,999) | |||||||||||
Restricted stock awards | 0 | 9 | (9) | 0 | 0 | ||||||||||||||||
Amortization of restricted stock awards | 8,788 | 0 | 8,788 | 0 | 0 | ||||||||||||||||
Contribution related to MRD Holdco incentive unit compensation expense (see Note 12) | 35,142 | 0 | 35,142 | 0 | 0 | ||||||||||||||||
Distributions | (163,007) | 0 | 0 | 0 | (163,007) | ||||||||||||||||
Amortization of MEMP equity awards | 10,809 | 0 | 0 | 0 | 10,809 | ||||||||||||||||
Purchase of noncontrolling interests | (5,946) | 0 | 0 | 0 | (5,946) | ||||||||||||||||
Net equity deemed contribution (distribution) related to net assets transferred to MEMP | 0 | 0 | (127,149) | 0 | 127,149 | ||||||||||||||||
Other | (177) | 0 | (287) | 0 | 110 | ||||||||||||||||
Total stockholders equity, ending balance at Dec. 31, 2015 | 822,827 | 2,053 | 1,560,949 | (740,175) | |||||||||||||||||
Total equity, ending balance at Dec. 31, 2015 | 1,467,921 | ||||||||||||||||||||
Noncontrolling interests, ending balance at Dec. 31, 2015 | 645,094 | 645,094 | |||||||||||||||||||
Cost incurred in conjunction with equity offering | (4,402) | 0 | (4,402) | 0 | 0 | ||||||||||||||||
Deferred tax adjustments (Note 15) | 38,778 | 0 | 38,778 | 0 | 0 | ||||||||||||||||
Restricted stock awards returned to plan | $ (1,196) | $ (1) | $ 0 | $ (1,195) | $ 0 |
Organization and Basis of Prese
Organization and Basis of Presentation | 12 Months Ended |
Dec. 31, 2015 | |
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. 2014 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, including Jay Graham, our Chief Executive Officer, 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 Jay Graham and such other former management members of WildHorse Resources; We entered into a registration rights agreement and a voting agreement with MRD Holdco, Jay Graham, our Chief Executive Officer, and certain other 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 owned certain leasehold interests and overriding royalty interests in Texas and Montana, MRD Midstream LLC, which owned 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. Certain amounts in the prior year financial statements have been reclassified to conform to current presentation. Gathering, processing, and transportation costs were previously accounted for as revenue deductions and are now being presented as costs and expenses on our statements of operations on a separate line item. We have elected to early adopt new accounting pronouncements related to the presentation of deferred taxes and debt issuance costs. The retrospective adjustments to the December 31, 2014 balance sheet are shown below. Previously Reported December 31, 2014 Adjustment Effect December 31, 2014 As Adjusted (In thousands) Prepaid expenses and other current assets 28,027 (4,824 ) 23,203 Other long-term assets 37,284 (28,637 ) 8,647 Accrued liabilities 199,000 (51,929 ) 147,071 Long-term debt — 783,000 (12,455 ) 770,545 Long-term debt—MEMP Segment 1,595,413 (21,266 ) 1,574,147 Deferred tax liabilities 95,017 51,929 146,946 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 and its consolidating subsidiaries except for MEMP and its subsidiaries. MEMP—reflects the combined operations of MEMP and its subsidiaries. Segment financial information has been retrospectively revised for the following common control transactions for comparability purposes: acquisition by MEMP of certain assets in East Texas from MRD in February 2015 in exchange for approximately $78.4 million in cash and certain properties in North Louisiana (the “Property Swap”); 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; and 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. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2015 | |
Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | 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 and other 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. We did not have any material write-offs related to uncollectible accounts during the years ended December 31, 2015, 2014 and 2013. Management determined that an allowance for uncollectible accounts was unnecessary at both December 31, 2015 and 2014, 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, 2015, 2014, and 2013. Oil and natural gas properties consisted of the following at the dates indicated: Years Ended December 31, 2015 2014 (In thousands) Proved oil and natural gas properties $ 5,353,594 $ 4,598,211 Support equipment and facilities 210,595 198,089 Unproved oil and natural gas properties 418,020 48,229 Total oil and natural gas properties $ 5,982,209 $ 4,844,529 At December 31, 2015 and 2014, we had $201.0 million and $119.0 million, respectively, capitalized in proved oil and natural gas properties related to wells in various stages of drilling and completion, which have been excluded from the depletion base. 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, 2015. MEMP engaged Ryder Scott Company, L.P. (“Ryder Scott”) to audit MEMP’s internally prepared reserves estimates for all of MEMP’s proved reserves (by volume) at December 31, 2015. 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, 2015, 2014, and 2013 was approximately $616.8 million, $432.1 million and $6.6 million, respectively. See Note 4 for further discussion on impairments. Unproved oil and natural gas properties are reviewed for impairment based on time or geologic factors. Information such as drilling results, reservoir performance, seismic interpretation or future plans to develop acreage is also considered. When unproved property investments are deemed to be impaired, the expense is reported in exploration expenses. We did not record any impairments related to unproved properties for the years ended December 31, 2015, 2014 and 2013. 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. These restricted investments consist of money market deposit accounts, money market mutual funds, and commercial paper. 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, 2015, 2014, and 2013 was approximately $8.9 million, $7.4 million and $8.3 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, 2015 or 2014. The following individual customers each accounted for 10% or more of total reported revenues for the period indicated: Years Ending December 31, 2015 2014 2013 Consolidated & Combined: Energy Transfer Equity, L.P. and subsidiaries 26 % 33 % 35 % Royal Dutch Shell plc and subsidiaries 11 % n/a n/a Sinclair Oil & Gas Company 11 % n/a n/a MRD Segment: Energy Transfer Equity, L.P. and subsidiaries 56 % 85 % 86 % Plains Marketing, L.P. 11 % n/a n/a MEMP Segment: Sinclair Oil & Gas Company 18 % 11 % n/a Phillips 66 12 % 12 % 14 % Royal Dutch Shell plc and subsidiaries 14 % n/a n/a Derivative and Other Financial 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. Embedded derivatives that are required to be bifurcated and accounted for separately are treated in the same manner as freestanding derivatives. Embedded derivatives are recorded at fair value, with the difference between the basis of the hybrid financial instrument and the fair value of the embedded derivative recorded as the carrying value of the host contract. See Note 5 for further information on certain commodity contracts that required bifurcation. 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, 2015 and 2014, we capitalized $7.4 million and $7.3 million of interest, respectively. Income Tax The Company uses the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the tax basis in assets and liabilities and their reported amounts in the financial statements and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. 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 deferred tax assets will not be realized. The Company recognizes interest and penalties accrued to unrecognized tax benefits in other income (expense) in its consolidated statement of operations. A tax benefit from an uncertain tax position is recognized when it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position. The tax benefit recorded is equal to the largest amount that is greater than 50% likely to be realized through effective settlement with a taxing authority. 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 (e.g., phantom unit awards) is 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, December 31, 2015 2014 Accrued capital expenditures $ 48,307 $ 80,350 Accrued interest payable 40,849 24,797 Accrued lease operating expense 18,874 16,403 Accrued general and administrative expenses 5,991 8,516 Accrued ad valorem taxes 1,583 8,870 Asset retirement obligation - current 1,175 — Other miscellaneous, including operator advances 5,020 8,135 $ 121,799 $ 147,071 Supplemental Cash Flow Information Supplemental cash flow for the periods presented (in thousands): For the Year Ended December 31, 2015 2014 2013 Supplemental cash flows: Cash paid for interest, net of capitalized interest $ 126,087 $ 130,732 $ 61,140 Cash paid for taxes 8,632 838 168 Noncash investing and financing activities: Increase (decrease) in capital expenditures in payables and accrued liabilities (32,043 ) 31,771 41,017 (Increase) decrease in accounts receivable related to acquisitions and divestitures 10,550 (6,706 ) (4,301 ) Assumptions of asset retirement obligations related to properties acquired or drilled 25,896 5,420 4,227 Accrued distribution to NGP affiliates related to Cinco Group acquisitions — — 4,352 Repurchase of equity under repurchase program — 3,425 — New Accounting Pronouncements Balance Sheet Classification of Deferred Taxes. In November 2015, the Financial Accounting Standards Board (“FASB”) issued an accounting standards update that requires entities with a classified balance sheet to present all deferred tax assets and liabilities as noncurrent. The current requirement that deferred tax assets and liabilities of a tax-paying component of an entity be offset and presented as a single amount is not affected by the amendment. The amendments are effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early adoption is permitted for all entities as of the beginning of an interim or annual reporting period. The amendments may be applied either prospectively to all deferred tax assets and liabilities or retrospectively to all periods presented. We have adopted this guidance as of December 31, 2015 and applied the disclosure requirements retrospectively to the consolidated financial statements and footnote disclosure. Simplifying the Accounting for Measurement-Period Adjustments. In September 2015, the FASB issued an accounting standards update that eliminates the requirement that an acquirer in a business combination account for measurement-period adjustments retrospectively. Instead, an acquirer will recognize a measurement-period adjustment during the period in which it determines the amount of the adjustment. Disclosure of the effect on earnings of any amounts an acquirer would have recorded in previous periods if the accounting had been completed at the acquisition date is required. The disclosure is required for each affected income statement line item, and may be presented separately on the face of the income statement or in the notes to the financial statements. The new guidance should be applied prospectively to adjustments to provisional amounts that occur after the effective date and is effective for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Early adoption is permitted for any interim and annual financial statements that have not yet been issued. The Company does not expect the impact of adopting this guidance to be material to the Company’s financial statements and related disclosures. 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. In August 2015, the FASB issued an accounting standards update that formally delayed the effective date of its new revenue recognition standard. The new standard is now effective for fiscal years, and interim periods within those years, beginning after December 15, 2017. Early adoption is now permitted for fiscal years, and interim periods within those years, beginning after December 15, 2016. 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, 2018. The Company has not yet selected a transition method and is currently evaluating the standard and the impact on its consolidated financial statements and footnote disclosures. Presentation of Debt Issuance Cost. In April 2015, the FASB issued an accounting standards update that requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying value of that debt liability, consistent with debt discounts. The guidance is effective retrospectively for fiscal years, and interim periods within those years, beginning after December 15, 2015. Early adoption is permitted for financial statements that have not been previously issued. The Company has chosen to adopt this standard and have applied this guidance in its consolidated financial statements and footnote disclosures. In August 2015, the FASB issued an accounting standards update that incorporates SEC guidance clarifying that debt issuance costs related to line-of-credit arrangements can be deferred and presented as an asset that is subsequently amortized over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The Company has elected this presentation in its consolidated financial statements and footnote disclosures as of December 31, 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 continues to assess the impact that adopting this new accounting guidance will have on its consolidated financial statements and footnote disclosures, we expect that MEMP will become a VIE. We believe we will continue to consolidate MEMP and become subject to the VIE primary beneficiary disclosure requirements. The deconsolidation of MEMP would have a material impact on our consolidated financial statements and related disclosures in the event there is a reconsideration event that triggers deconsolidation. 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, 2015 | |
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 proved 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 proved 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. Transaction-related costs Transaction-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, 2015 2014 2013 $ 3,902 $ 6,668 $ 8,313 2015 Acquisitions On June 1, 2015, we entered into an oil and gas lease option agreement with a third party pursuant to which we have the right to obtain one or more oil and gas leases in North Louisiana and is exercisable through February 2017. The purchase price of this option was approximately $4.0 million. The purchase price has been capitalized as part of unproved properties and will be expensed if the option is not exercised. On October 22, 2015, MRD closed a transaction to acquire certain proved and unproved oil and natural gas properties in North Louisiana from a third party for approximately $284.3 million (the “North Louisiana Acquisition”), of which $281.9 million of the purchase price was allocated to unproved oil and natural gas properties with the remainder allocated to proved oil and natural gas properties. On November 3, 2015, MEMP acquired the remaining interest in its oil and gas properties offshore California from a third party for $94.6 million (the “Beta Properties”). Beta Properties Oil and gas properties $ 40,029 Prepaid expenses and other current assets 840 Restricted investments 69,579 Derivative instruments 4,568 Accounts receivable - affiliates and other 4,499 Asset retirement obligations (22,871 ) Accrued liabilities (2,010 ) Total identifiable net assets $ 94,634 2015 Divestitures On April 17, 2015, MRD sold certain oil and natural gas properties in Colorado and Wyoming to a third party for approximately $13.6 million (the “Rockies Divestiture”) and recorded a gain of less than $0.1 million related to the sale. During the year ended December 31, 2015, MEMP conducted an auction process administered by a third-party and sold interests in certain oil and gas properties located in the Permian Basin in various Texas and New Mexico counties to two third parties for an aggregate $0.6 million. In addition as part of that auction process, MEMP also sold interests in certain oil and gas properties located in the Permian Basin to a related party for approximately $0.9 million. See Note 13 for additional information regarding this related party divestiture. 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, after 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 final purchase price of approximately $906.1 million (the “Wyoming Acquisition”). Revenues of $72.8 million were recorded in the statement of operations and 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 $36.6 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): MEMP MEMP MRD Eagle Ford Wyoming Louisiana Acquisition Acquisition Acquisition Oil and gas properties $ 168,606 $ 930,168 $ 72,141 Asset retirement obligations (285 ) (3,980 ) (271 ) Revenue Payable — (375 ) — Accrued liabilities (250 ) (19,693 ) — Total identifiable net assets $ 168,071 $ 906,120 $ 71,870 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 MRD Consolidated and Combined (In thousands) Revenues $ 1,066,324 $ 800,487 Net income (loss) (602,044 ) 257,839 Basic and 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 obligations (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. |
Fair Value Measurements of Fina
Fair Value Measurements of Financial Instruments | 12 Months Ended |
Dec. 31, 2015 | |
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, 2015 and 2014, 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, other financial assets, 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, 2015 and December 31, 2014. 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, 2015 and December 31, 2014 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, 2015 and December 31, 2014 for each of the fair value hierarchy levels: Fair Value Measurements at December 31, 2015 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 $ — $ 1,136,757 $ — $ 1,136,757 Interest rate derivatives — — — — Total assets $ — $ 1,136,757 $ — $ 1,136,757 Liabilities: Commodity derivatives $ — $ 84,981 $ — $ 84,981 Interest rate derivatives — 2,655 — 2,655 Total liabilities $ — $ 87,636 $ — $ 87,636 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 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. To compensate for the inherent risk of estimating and valuing unproved properties, the discounted future net revenues of probable and possible reserves are reduced by additional risk-weighting factors. 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, 2015, the MRD Segment did not recognize any impairments. · During the year ended December 31, 2015, MEMP recognized $616.8 million of impairments. These impairments primarily related to certain properties located in East Texas, South Texas, the Permian Basin, Wyoming, and Colorado. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable primarily as a result of declining commodity prices. As a result of the impairments, the carrying value of these properties was reduced to approximately $408.6 million. · 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. |
Risk Management and Derivative
Risk Management and Derivative and Other Financial Instruments | 12 Months Ended |
Dec. 31, 2015 | |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |
Risk Management and Derivative and Other Financial Instruments | Note 5. Risk Management and Derivative and Other Financial Instruments Derivative and other financial 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 and other financial instruments, 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, and other financial instruments 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 and other financial 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 or other financial instrument, whereby the party not in default may set-off all liabilities owed to the defaulting party against all net derivative and other financial asset receivables from the defaulting party. At December 31, 2015, MEMP had net derivative assets of $729.8 million. After taking into effect netting arrangements, MEMP had counterparty exposure of $380.9 million related to its derivative instruments of which $123.4 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 $350.0 million against amounts outstanding under its revolving credit facility at December 31, 2015. At December 31, 2015, MRD had derivative and other financial assets of $365.4 million. After taking into effect netting arrangements, MRD had counterparty exposure of $169.1 million related to derivative and other financial instruments of which $86.8 million was with a single counterparty. Had certain counterparties failed completely to perform according to the terms of their existing contracts, MRD would have the right to offset $196.3 million against amounts outstanding under its revolving credit facility at December 31, 2015. See Note 8 for additional information regarding our revolving credit facilities. Commodity Derivatives and Other Financial Instruments We may use a combination of commodity derivatives and other financial instruments (e.g., floating-for-fixed swaps, put options, costless collars 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. Cash settlements received on settled derivative positions during 2015 is net of deferred premiums of $8.0 million. During the year ended December 31, 2015, MRD restructured its existing 2018 crude oil and natural gas hedges for crude oil and NGL swaps that will settle in 2016. Cash settlements of approximately $92.3 million from the terminated 2018 positions were received and applied as premiums for the new crude oil and NGL swaps. Certain contracts are classified as other financial instruments, which require bifurcation, based on the relationship between the fixed swap price and the market price at the restructure dates. Due to bifurcation, $46.1 million of the restructured contracts represents other financial assets at December 31, 2015. In February 2015, MEMP restructured a portion of its commodity derivative portfolio by effectively terminating “in-the-money” crude oil derivatives settling in 2015 through 2017 and entering into NGL derivatives with the same tenor. Cash settlement receipts of approximately $27.1 million from the termination of the crude oil derivatives were applied as premiums for the new NGL derivatives. In November 2015, MEMP had cash settlement receipts of $16.4 million from the termination of certain WTI crude oil derivatives that were applied as premiums for new Brent crude oil derivatives. As a part of MEMP’s 2015 Beta Acquisition, MEMP acquired $4.6 million in derivatives. These derivatives were subsequently restructured by terminating “in-the-money” crude oil derivatives settling in 2015 through 2016 and entering into new crude oil derivatives. Cash settlement receipts of approximately $4.4 million from the termination of the crude oil derivatives were applied as premiums for the new crude oil swaps. 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, 2015, the MRD Segment had the following open commodity positions (excluding embedded derivatives): 2016 2017 Natural Gas Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (MMBtu) 2,570,000 1,770,000 Weighted-average fixed price $ 4.09 $ 4.24 Collar contracts: Average Monthly Volume (MMBtu) 1,100,000 1,050,000 Weighted-average floor price $ 4.00 $ 4.00 Weighted-average ceiling price $ 4.71 $ 5.06 Purchased put option contracts: Average Monthly Volume (MMBtu) 6,000,000 5,350,000 Weighted-average strike price $ 3.51 $ 3.48 Weighted-average deferred premium paid $ (0.34 ) $ (0.32 ) TGT Z1 basis swaps: Average Monthly Volume (MMBtu) 1,120,000 200,000 Spread - Henry Hub $ (0.10 ) $ (0.08 ) Crude Oil Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 35,583 28,000 Weighted-average fixed price $ 83.58 $ 84.70 Collar contracts: Average Monthly Volume (Bbls) 27,000 — Weighted-average floor price $ 80.00 $ — Weighted-average ceiling price $ 99.70 $ — NGL Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 353,399 — Weighted-average fixed price $ 39.68 $ — At December 31, 2015, the MRD Segment had the following open embedded derivative positions: 2016 Oil Hybrid Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 27,080 Weighted-average fixed price $ 46.51 Initial net investment price 62.16 Total contract swap price $ 108.67 NGL Hybrid Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 83,101 Weighted-average fixed price $ 15.84 Initial net investment price 25.98 Total contract swap price $ 41.82 At December 31, 2015, the MEMP Segment had the following open commodity positions: 2016 2017 2018 2019 Natural Gas Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (MMBtu) 3,592,442 3,350,067 3,060,000 2,814,583 Weighted-average fixed price $ 4.14 $ 4.06 $ 4.18 $ 4.31 Basis swaps: Average Monthly Volume (MMBtu) 3,578,333 2,210,000 1,315,000 900,000 Spread $ (0.07 ) $ (0.04 ) $ (0.02 ) $ 0.01 Crude Oil Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 304,813 301,600 312,000 160,000 Weighted-average fixed price $ 85.48 $ 85.00 $ 83.74 $ 85.52 Basis swaps: Average Monthly Volume (Bbls) 140,000 67,500 — — Spread $ (10.02 ) $ (7.82 ) $ — $ — NGL Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 213,100 43,300 — — Weighted-average fixed price $ 35.64 $ 37.55 $ — $ — The MEMP Segment basis swaps included in the table above is presented on a disaggregated basis below: 2016 2017 2018 2019 Natural Gas Derivative Contracts: NGPL TexOk basis swaps: Average Monthly Volume (MMBtu) 3,003,333 1,800,000 1,200,000 900,000 Spread - Henry Hub $ (0.07 ) $ (0.07 ) $ (0.03 ) $ 0.01 HSC basis swaps: Average Monthly Volume (MMBtu) 135,000 115,000 115,000 — Spread - Henry Hub $ 0.07 $ 0.14 $ 0.15 $ — CIG basis swaps: Average Monthly Volume (MMBtu) 170,000 — — — Spread - Henry Hub $ (0.30 ) $ — $ — $ — TETCO STX basis swaps: Average Monthly Volume (MMBtu) 270,000 295,000 — — Spread - Henry Hub $ 0.06 $ 0.03 $ — $ — Crude Oil Derivative Contracts: Midway-Sunset basis swaps: Average Monthly Volume (Bbls) 100,000 37,500 — — Spread - Brent $ (12.29 ) $ (12.20 ) $ — $ — Midland basis swaps: Average Monthly Volume (Bbls) 40,000 30,000 — — Spread - WTI $ (4.34 ) $ (2.35 ) $ — $ — 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, 2015, MEMP had the following interest rate swap open positions: Credit Facility 2016 2017 2018 MEMP: Average Monthly Notional (in thousands) $ 400,000 $ 400,000 $ 100,000 Weighted-average fixed rate 0.943 % 1.612 % 1.946 % 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. The MRD segment did not have any interest rate swaps at December 31, 2015. 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, 2015 and 2014. 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 2015 2014 2015 2014 (In thousands) Commodity contracts Short-term derivative instruments $ 552,614 $ 378,908 $ 53,939 $ 38,852 Interest rate swaps Short-term derivative instruments — — 1,214 3,289 Gross fair value 552,614 378,908 55,153 42,141 Netting arrangements Short-term derivative instruments (52,303 ) (38,852 ) (52,303 ) (38,852 ) Net recorded fair value Short-term derivative instruments $ 500,311 $ 340,056 $ 2,850 $ 3,289 Commodity contracts Long-term derivative instruments $ 584,143 $ 466,851 $ 31,042 $ 32,787 Interest rate swaps Long-term derivative instruments — 1,305 1,441 — Gross fair value 584,143 468,156 32,483 32,787 Netting arrangements Long-term derivative instruments (31,042 ) (32,787 ) (31,042 ) (32,787 ) Net recorded fair value Long-term derivative instruments $ 553,101 $ 435,369 $ 1,441 $ — (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, 2015, 2014, and 2013: Statements of For the Year Ended December 31, Operations Location 2015 2014 2013 Commodity derivative contracts (Gain) loss on commodity derivatives $ (744,139 ) $ (749,988 ) $ (29,294 ) Interest rate derivatives Interest expense, net 4,674 145 (239 ) |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2015 | |
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, 2015, 2014 and 2013: 2015 2014 2013 (In thousands) Asset retirement obligations at beginning of period $ 122,531 $ 111,769 $ 102,380 Liabilities added from acquisitions or drilling 25,896 5,420 4,227 Liabilities settled (1,430 ) (588 ) (170 ) Revision of estimates 23,230 293 1,516 Liabilities removed upon sale of wells (3,526 ) (669 ) (1,765 ) Accretion expense 7,542 6,306 5,581 Asset retirement obligations at end of period 174,243 122,531 111,769 Less: Current portion 1,175 — 90 Asset retirement obligations - long-term portion $ 173,068 $ 122,531 $ 111,679 The increase in revisions of estimates during 2015 is related to increases in estimated future plugging and abandonment costs compared to estimates made in prior periods as well as decreases to the estimated remaining economic well life for certain wells. |
Restricted Investments
Restricted Investments | 12 Months Ended |
Dec. 31, 2015 | |
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, 2015 and 2014: 2015 2014 (In thousands) BOEM platform abandonment (See Note 16) $ 144,008 $ 69,954 BOEM lease bonds 1,533 794 SPBPC Collateral: Contractual pipeline and surface facilities abandonment 3,178 2,701 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 $ 152,631 $ 77,361 On November 3, 2015, MEMP acquired the remaining interests in the Beta properties. The restricted investments balance at December 31, 2015 represents 100% ownership of these properties compared to a 51.75% ownership at December 31, 2014. See Note 3 for additional information . |
Long Term Debt
Long Term Debt | 12 Months Ended |
Dec. 31, 2015 | |
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 (other than MEMP GP). December 31, December 31, 2015 2014 (In thousands) MRD Segment: MRD $2.0 billion revolving credit facility, variable-rate, due June 2019 $ 423,000 $ 183,000 5.875% senior unsecured notes, due July 2022 ("MRD Senior Notes") (1) (4) 600,000 600,000 Unamortized debt issuance costs (10,936 ) (12,455 ) Subtotal 1,012,064 770,545 MEMP Segment: MEMP $2.0 billion revolving credit facility, variable-rate, due March 2018 836,000 412,000 7.625% senior unsecured notes, due May 2021 ("2021 Senior Notes") (2) (4) 700,000 700,000 6.875% senior unsecured notes, due August 2022 ("2022 Senior Notes") (3) (4) 496,990 500,000 Unamortized discounts (14,114 ) (16,587 ) Unamortized debt issuance costs (18,297 ) (21,266 ) Subtotal 2,000,579 1,574,147 Total long-term debt $ 3,012,643 $ 2,344,692 ( 1) The estimated fair value of this fixed-rate debt was $525.0 million and $534.0 million at December 31, 2015 and 2014, respectively. (2) The estimated fair value of this fixed-rate debt was $210.0 million and $563.5 million at December 31, 2015 and 2014, respectively. (3) The estimated fair value of this fixed-rate debt was $149.1 million and $380.0 million at December 31, 2015 and 2014, respectively. (4) 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, 2015 MRD Segment: MRD $2.0 billion revolving credit facility, variable-rate, due June 2019 $ 1,000,000 MEMP Segment: MEMP $2.0 billion revolving credit facility, variable-rate, due March 2018 1,175,000 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. 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 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. 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 certain of its current and future 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 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 2022 Senior Notes are subject to optional redemption at prices specified in the indenture plus accrued and unpaid interest, if any. The indenture governing the 2022 Senior Notes 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 Credit Facility December 31, 2015 2014 2013 MRD Segment: MRD revolving credit facility 1.92 % 1.99 % n/a WildHorse Resources revolver terminated June 2014 n/a 4.04 % 2.30 % WildHorse Resources second lien terminated June 2014 n/a 6.44 % 7.60 % Black Diamond terminated November 2013 n/a n/a 3.97 % MEMP Segment: MEMP revolving credit facility 2.12 % 2.67 % 3.25 % WHT revolver terminated March 2013 n/a n/a 2.29 % Tanos revolver terminated April 2013 n/a n/a 3.10 % Stanolind revolver paid off by MEMP October 2013 n/a n/a 3.52 % Boaz revolver terminated October 2013 n/a n/a 2.97 % Crown revolver terminated October 2013 n/a n/a 3.38 % MRD LLC revolver terminated December 2013 n/a n/a 3.17 % Propel Energy revolver paid off by MEMP October 2013 n/a n/a 3.08 % 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, 2015 2014 (In thousands) MRD Segment: MRD revolving credit facility $ 4,976 $ 4,285 MRD Senior Notes 10,936 12,455 MEMP Segment: MEMP revolving credit facility 3,672 6,468 2021 Senior Notes 11,194 13,308 2022 Senior Notes 7,103 7,958 $ 37,881 $ 44,474 |
Stockholders' Equity and Noncon
Stockholders' Equity and Noncontrolling Interests | 12 Months Ended |
Dec. 31, 2015 | |
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 since January 1, 2014: Balance January 1, 2014 — Shares of common stock issued 192,500,000 Shares of common stock repurchased (123,797 ) Restricted common shares issued (Note 11) 1,068,422 Restricted common shares forfeited (9,211 ) Balance December 31, 2014 193,435,414 Shares of common stock issued 13,800,000 Shares of common stock repurchased (2,764,887 ) Restricted common shares issued (Note 11) 938,558 Restricted common shares repurchased (1) (60,773 ) Restricted common shares forfeited (54,569 ) Balance December 31, 2015 205,293,743 (1) Restricted common shares are generally net-settled by shareholders to cover the required withholding tax upon vesting. Participants surrendered shares with value equivalent to the employee’s minimum statutory obligation for the applicable income and other employment taxes. Total payments remitted for the employees’ tax obligations to the appropriate taxing authorities were approximately $1.2 million. These net-settlements had the effect of shares repurchased by the Company as they reduced the number of shares that would have otherwise been outstanding as a result of the vesting and did not represent an expense to the Company. See Note 11 for additional information regarding restricted common shares that were granted in connection with our long-term incentive plan. Restricted shares of common stock are participating securities and considered issued and outstanding on the grant date of restricted stock award. On September 25, 2015, the Company issued 13,800,000 shares of common stock (including 1,800,000 shares of common stock sold pursuant to the full exercise of the underwriters’ option to purchase additional shares of common stock) to the public generating total net proceeds of approximately $238.1 million after deducting underwriting discounts and offering expenses. The net proceeds from the equity offering were used to temporarily pay down our revolving credit facility and subsequently re-borrowed to fund a portion of the purchase price of the North Louisiana Acquisition that closed on October 22, 2015. Share Repurchase Program In December 2014, the board of directors (“Board”) of the Company authorized the repurchase of up to $50.0 million through block trades or otherwise and subject to market conditions, as well as corporate, regulatory, and other considerations. 123,797 shares of common stock $2.2 million 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, which exhausted the December 2014 repurchase program. MRD has retired all of the shares of common stock repurchased and the shares of common stock are no longer issued or outstanding. In April 2015, the Board 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. The Company is not obligated to repurchase any dollar amount or specific number of shares of its common stock under the program, which may be suspended or discontinued at any time. The amount, timing and price of purchases will depend on market conditions and other factors. The Company did not repurchase any shares of common stock under this program through December 31, 2015. 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, 2015. 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 the limited partners of MEMP. 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 prior to our initial public offering. Contributions received from limited partners of MEMP primarily represent net cash proceeds received from common unit offerings. 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. MEMP repurchased 3,547,921 common units under its repurchase program for an aggregate price of $52.8 million through December 31, 2015. MEMP has retired all common units repurchased and the common units are no longer issued or outstanding. At December 31, 2015, MEMP had no authorized repurchases remaining under the MEMP repurchase program. 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. On November 3, 2015, MEMP purchased the noncontrolling interests in SPBPC for approximately $6.0 million as previously discussed in Note 3. In connection with our initial public offering, certain former management members of WildHorse Resources, including Mr. Graham, 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, 2015 | |
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, 2015 2014 Numerator: Net income (loss) available to common stockholders $ 94,914 $ (784,581 ) Denominator: Weighted average common shares outstanding 193,698 192,498 Incremental treasury stock method shares (1) 469 203 Basic EPS $ 0.49 $ (4.08 ) Diluted EPS (1) $ 0.49 $ (4.08 ) (1) The Company determines the more dilutive of either the two-class method or the treasury stock method for diluted EPS. The two-class method was more dilutive for each period presented. |
Long-Term Incentive Plans
Long-Term Incentive Plans | 12 Months Ended |
Dec. 31, 2015 | |
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. Restricted stock awards granted to our employees subsequent to our initial public offering generally vest ratably on a three-year annual vesting schedule from the date of the grant. 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 $ 19.00 Forfeited (9,211 ) $ 19.00 Restricted common shares outstanding at December 31, 2014 1,059,211 $ 19.00 Granted (3) 938,558 $ 18.80 Forfeited (54,569 ) $ 18.83 Vested (274,355 ) $ 19.00 Restricted common shares outstanding at December 31, 2015 1,668,845 $ 18.89 (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 (3) The aggregate grant date fair value of restricted common share awards issued in 2015 was $17.6 million based on grant date market prices ranging from $17.58 to $18.91 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, 2015 2014 $ 8,788 $ 2,804 The unrecognized compensation cost associated with restricted common share awards was an aggregate $25.1 million at December 31, 2015. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.42 years. Subsequent event. An award of 8,023 shares of restricted stock was granted to each of our independent directors on January 8, 2016 and will vest one year from the date of grant. 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 (“DERs”), 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, 2012 285,609 $ 18.08 Granted (2) 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 (3) 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 Granted (4) 827,704 $ 14.90 Forfeited (69,059 ) $ 18.35 Vested (483,627 ) $ 20.37 Restricted common units outstanding at December 31, 2015 1,368,538 $ 17.61 (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 2013 was $9.9 million based on grant date market prices ranging from $18.33 to $20.35 per unit. (3) 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 $21.99 to $23.40 per unit. (4) The aggregate grant date fair value of restricted common unit awards issued in 2015 was $12.3 million based on grant date market prices ranging from $6.20 to $15.45 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, 2015 2014 2013 $ 10,809 $ 7,874 $ 3,558 The unrecognized compensation cost associated with restricted common unit awards was $16.5 million at December 31, 2015. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 1.8 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. Subsequent event. On January 8, 2015, MEMP issued a total of 155,601 phantom units to the independent directors of MEMP GP, which vest 100% after a one year period. Upon vesting, the phantom units will settle (i) in cash, (ii) in a number of common units equal to the number of vested units or (iii) a combination of cash and units. The phantom unit awards also include DERs which stipulate that if there is a distribution paid on the common units, the independent directors are entitled to receive a cash payment with respect to each phantom unit equal to the cash distribution paid per unit to common unit holders. |
Incentive Units
Incentive Units | 12 Months Ended |
Dec. 31, 2015 | |
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. 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. 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”). Subsequent to our initial public offering, MRD Holdco granted the remaining 70 incentive units to certain key employees (the “Subsequent Incentive Units”). We recognized $35.2 million and $111.9 million of compensation expense in 2015 and 2014, respectively, offset by a deemed capital contribution from MRD Holdco and the unrecognized compensation expense of approximately $58.8 million as of December 31, 2015 will be recognized over the remaining expected service period of 1.42 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 12/31/2015 12/31/2015 Dividend yield 0 % 0 % Expected volatility 51.30 % 51.30 % Risk-free rate 0.82 % 0.82 % Expected life (years) 1.42 1.42 |
Related Party Transactions
Related Party Transactions | 12 Months Ended |
Dec. 31, 2015 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | Note 13. Related Party Transactions Amounts due to MRD Holdco and certain affiliates of NGP at December 31, 2015 and 2014 are presented as “Accounts payable – affiliates” in the accompanying balance sheets. NGP Affiliated Companies During the year ended December 31, 2015, MRD paid approximately $8.5 million to Cretic Energy Services, LLC, an NGP affiliated company, for services related to our drilling and completion activities. During the year ended December 31, 2015, MRD paid approximately $2.3 million to Multi-Shot, LLC, an NGP affiliated company, for services related to our drilling and completion activities. 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 during 2013. 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. The remaining proceeds of approximately $2.0 million were released from escrow in April 2013. 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. The net assets acquired were as follows (in thousands): 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 November 2, 2015, in connection with an auction process administered by a third-party, MEMP divested certain oil and gas properties in the Permian Basin to an affiliate of NGP for a purchase price of approximately $0.9 million. Due to common control considerations, the proceeds from the sale exceeded the net book value of the properties by $0.7 million and is recognized as a contribution in the equity statement. 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, including Graham, who contributed their ownership of WildHorse Resources to us in the restructuring transactions. Among other things, the voting agreement provides that Graham and 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 provides MRD Holdco with the right to designate up to three nominees to the Board, provided that such number of nominees shall be reduced to two, one and zero if the Funds and their affiliates collectively own less than 35%, 15%, and 5% respectively, of the outstanding shares of our common stock. The voting agreement also requires us and the stockholders party thereto to take all necessary actions, to the fullest extent permitted by applicable law (including with respect to any fiduciary duties under Delaware law), including voting their shares of our common stock, to cause the election of the nominees designated by MRD Holdco. In addition, the voting agreement provides that for so long as MRD Holdco has the right to designate two directors to the Board, we will cause any committee of the Board to include in its membership at least one director designated by MRD Holdco, except to the extent that such membership would violate applicable securities laws or stock exchange rules. 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 agreed to 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, Graham and certain former management members of WildHorse Resources own WHR II. The services agreement was terminated effective 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 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 year ended December 31, 2013 were approximately $0.3 million. Midstream Agreements Prior to our initial public offering, we entered into various midstream service agreements with affiliates of PennTex Midstream Partners, LP (“PennTex”), an affiliate of NGP, for the gathering, processing and transportation of natural gas and NGLs. Additionally, we entered into an area of mutual interest and exclusivity agreement (“AMI”) with PennTex pursuant to which PennTex has the exclusive right to provide midstream services to support our current and future production in North Louisiana on our operated acreage within such area (other than production subject to existing third-party commitments). PennTex is a publicly traded master limited partnership. MRD Midstream LLC (“MRD Midstream”), a wholly-owned subsidiary of MRD Holdco, has ownership interests in both PennTex and its general partner. In addition to a 5.25% membership interest in PennTex’s general partner, MRD Midstream also owns approximately 18.4% of PennTex’s limited partner interests and 5.25% of its incentive distribution rights. The amended and restated gas processing agreement, (“GPA”) has a 15-year primary term, subject to one-year extensions at either party’s election. Processing fees under the GPA are subject to annual inflation escalators. Under the GPA, the Company has agreed to deliver a minimum volume of gas for processing through the term of the agreement measured on a cumulative basis based on specified daily minimum volume thresholds. Any volumes of gas delivered up to the then-applicable daily minimum volume threshold are considered firm reserved gas and are charged the firm fixed-commitment fee, and any volumes delivered in excess of such threshold are considered interruptible volumes and are charged the interruptible-service fixed fee. Pursuant to the GPA, any deficiency payments made by the Company under the GPA will be treated as prepaid processing fees by PennTex (except for the June 2015 deficiency payment). These charges do not expire until the end of the primary term of the GPA. Quarterly deficiency payments are based on the firm-commitment fixed fee. The following table summarizes the minimum volume commitment (“MVC”) and fees associated with the GPA. Period MVC (MMBtu/d) Firm Fee ($/MMBtu) Interruptible Fee ($/MMBtu) June 1, 2015 to September 30, 2015 115,000 0.435 0.470 October 1, 2015 to June 30, 2016 345,000 0.435 0.470 July 1, 2016 to June 30, 2026 (1) 460,000 0.435 0.350 July 1, 2026 to June 1, 2030 345,000 0.435 0.350 June 2, 2030 to October 1, 2030 115,000 0.435 0.350 (1) The firm fee is reduced to $0.35 $/MMBtu for volumes in excess of 345,000 MMBtu/d. The gas gathering agreement, as amended, (“GGA”) has a 15-year primary term, subject to one-year extensions at either party’s election. The Company pays fees for gathering services provided by PennTex, including a firm capacity reservation payment through November 30, 2019 and a usage fee component that is subject to a minimum volume commitment. The GGA also has an annual “use it or lose it” deficiency provision that is based on the usage fee. The minimum volume commitment under the GGA is linked to the minimum volume commitment under the GPA. Period MVC (MMBtu/d) Firm Fee ($/MMBtu) Usage Fee ($/MMBtu) June 1, 2015 to June 1, 2030 460,000 0.03 n/a June 1, 2016 to December 31, 2025 115,000 n/a 0.02 October 1, 2015 to June 30, 2016 345,000 n/a 0.02 July 1, 2016 to November 30, 2019 460,000 n/a 0.02 December 1, 2019 to June 30, 2026 460,000 n/a 0.05 July 1, 2026 to June 1, 2030 345,000 n/a 0.05 The gas transportation agreement, as amended, (“GTA”) has a 15-year primary term, subject to one-year extensions at either party’s election. The GTA provides for the transportation of residue gas through PennTex’s residue gas pipeline from the outlet of their processing plants to delivery points at interconnections with third-party natural gas transportation pipelines. The Company pays a usage fee for all volumes transported under the GTA. The GTA includes a plant tailgate dedication pursuant to which all of the Company’s residue gas produced from the PennTex’s processing plants are delivered for transportation on their residue gas pipeline. The GTA also includes a fixed monthly demand charge to provide priority firm service. The following table summarizes the fees associated with the GTA: Period Demand Fee ($/month) Usage Fee ($/MMBtu) June 1, 2015 to June 1, 2030 n/a 0.04 January 1, 2016 to December 31, 2025 360,000 n/a The transportation services agreement (“TSA”) provides for the transportation of NGLs through PennTex’s NGL pipeline from the outlet of their processing plants to a third party delivery point. The Company pays a usage fee for all volumes transported under the TSA. The TSA includes a plant tailgate dedication pursuant to which all of the Company’s NGLs produced from PennTex’s processing plants are delivered for transportation on the its NGL pipeline. The following table summarizes the fees associated with the TSA: Period Usage Fee ($/gallon) October 1, 2015 to October 1, 2030 0.04 All net costs associated with these agreements are reflected in the statement of operations in the “Gathering processing, and transportation – affiliate” line. 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 had a term until December 31, 2023, subject to one-year extensions at either party’s election. The amended gas gather agreement was terminated in November 2015 in connection with a third party’s acquisition of Classic Pipeline’s Joaquin gathering system. On May 1, 2014, Classic Operating and Classic Pipeline entered into a water disposal agreement. The water disposal agreement had 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. Effective July, 1 2015, the fee was reduced to $0.40 per barrel for each barrel of water delivered to Classic Pipeline. In February 2015, in connection with and as part of the Property Swap, Classic sold all of the equity interests owned by it in Classic Operating to OLLC, a wholly-owned subsidiary of MEMP, and Classic and Classic GP were merged into MRD Operating in March 2015. Classic Pipeline assigned its saltwater disposal system to OLLC in November 2015. Due to common control considerations, we recorded the receipt of this asset at historical cost and recognized approximately $2.1 million as a contribution in the equity statement. For the years ended December 31, 2015, 2014 and 2013, MEMP incurred gathering and salt water disposal fees of approximately $3.6 million, $1.8 million and $0.6 million, respectively, from Classic Pipeline, an affiliate. |
Business Segment Data
Business Segment Data | 12 Months Ended |
Dec. 31, 2015 | |
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 and its consolidating subsidiaries except for MEMP and its subsidiaries. MEMP—reflects the combined operations of MEMP and its 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, 2015 374,042 358,147 — 732,189 For the Year Ended December 31, 2014 409,082 566,043 — 975,125 For the Year Ended December 31, 2013 219,552 394,515 — 614,067 Adjusted EBITDA: (1) For the Year Ended December 31, 2015 370,889 340,392 (252 ) 711,029 For the Year Ended December 31, 2014 316,317 337,560 (6,144 ) 647,733 For the Year Ended December 31, 2013 175,994 244,094 (25,232 ) 394,856 Segment assets: (2) As of December 31, 2015 2,177,492 2,906,003 (646 ) 5,082,849 As of December 31, 2014 1,401,313 3,168,494 (9,981 ) 4,559,826 Total cash expenditures for additions to long-lived assets: For the Year Ended December 31, 2015 890,226 332,459 — 1,222,685 For the Year Ended December 31, 2014 487,001 1,382,133 — 1,869,134 For the Year Ended December 31, 2013 254,724 213,723 — 468,447 (1) Adjustments and eliminations for the years ended December 31, 2015, 2014 and 2013 include amounts related to the MRD Segment’s equity investments in the MEMP Segment as well the elimination of $0.3 million, $6.1 million and $26.0 million of cash distributions that MEMP paid MRD Segment for the years ended December 31, 2015, 2014 and 2013, 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. Calculation of Reportable Segments’ Adjusted EBITDA For the Year Ended December 31, 2015 Combined MRD MEMP Totals (In thousands) Net income (loss) $ 97,274 $ (395,491 ) $ (298,217 ) Interest expense, net 39,396 114,732 154,128 Income tax expense (benefit) 100,005 (2,175 ) 97,830 DD&A 188,742 195,814 384,556 Impairment of proved oil and natural gas properties — 616,784 616,784 Accretion of AROs 417 7,125 7,542 (Gain) loss on commodity derivative instruments (281,249 ) (462,890 ) (744,139 ) Cash settlements received (paid) on expired commodity derivative instruments 170,899 254,047 424,946 (Gain) loss on sale of properties (47 ) (2,998 ) (3,045 ) Transaction related costs 1,974 1,928 3,902 Incentive-based compensation expense 43,930 10,809 54,739 Exploration costs 8,969 2,317 11,286 Insurance recoveries related to environmental remediation — (1,216 ) (1,216 ) Loss on settlement of AROs — 1,606 1,606 Non-cash equity (income) loss from MEMP 327 — 327 Cash distributions from MEMP 252 — 252 Adjusted EBITDA $ 370,889 $ 340,392 $ 711,281 For the Year Ended December 31, 2014 Combined MRD MEMP Totals (In thousands) Net income (loss) $ (764,333 ) $ 115,614 $ (648,719 ) Interest expense, net 50,283 83,550 133,833 Income tax expense (benefit) 102,392 (1,421 ) 100,971 Loss on extinguishment of debt 37,248 — 37,248 DD&A 128,238 185,955 314,193 Impairment of proved oil and natural gas properties 24,576 407,540 432,116 Accretion of AROs 533 5,773 6,306 (Gain) loss on commodity derivative instruments (257,734 ) (492,254 ) (749,988 ) Cash settlements received (paid) on expired commodity derivative instruments 9,166 13,522 22,688 (Gain) loss on sale of properties 3,057 — 3,057 Transaction related costs 2,305 4,363 6,668 Incentive-based compensation expense 946,753 7,874 954,627 Exploration costs 13,853 2,750 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 $ 316,317 $ 337,560 $ 653,877 For the Year Ended December 31, 2013 Combined MRD MEMP Totals (In thousands) Net income (loss) $ 91,390 $ 61,005 $ 152,395 Interest expense, net 24,948 44,302 69,250 Income tax expense (benefit) 1,311 308 1,619 DD&A 70,903 113,814 184,717 Impairment of proved oil and natural gas properties 2,528 4,072 6,600 Accretion of AROs 593 4,988 5,581 (Gain) loss on commodity derivative instruments (3,161 ) (26,133 ) (29,294 ) Cash settlements received (paid) on expired commodity derivative instruments 8,481 23,638 32,119 (Gain) loss on sale of properties (82,773 ) (2,848 ) (85,621 ) Transaction related costs 1,584 6,729 8,313 Incentive-based compensation expense 34,997 11,840 46,837 Non-cash based compensation expense — 1,057 1,057 Exploration costs 1,034 1,322 2,356 Non-cash equity (income) loss from MEMP (1,847 ) — (1,847 ) Cash distributions from MEMP 26,006 — 26,006 Adjusted EBITDA $ 175,994 $ 244,094 $ 420,088 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, 2015 2014 2013 Total Reportable Segments' Adjusted EBITDA $ 711,281 $ 653,877 $ 420,088 Adjustments to reconcile Adjusted EBITDA to net income (loss): Interest expense, net (154,128 ) (133,833 ) (69,250 ) Loss on extinguishment of debt — (37,248 ) — Income tax benefit (expense) (97,830 ) (100,971 ) (1,619 ) DD&A (384,556 ) (314,193 ) (184,717 ) Impairment of proved oil and natural gas properties (616,784 ) (432,116 ) (6,600 ) Accretion of AROs (7,542 ) (6,306 ) (5,581 ) Gains (losses) on commodity derivative instruments 744,139 749,988 29,294 Cash settlements received (paid) on expired commodity derivative instruments (424,946 ) (22,688 ) (32,119 ) Gain (loss) on sale of properties 3,045 (3,057 ) 85,621 Transaction related costs (3,902 ) (6,668 ) (8,313 ) Incentive-based compensation expense (54,739 ) (954,627 ) (46,837 ) Non-cash based compensation expense — — (1,057 ) Exploration costs (11,286 ) (16,603 ) (2,356 ) Cash distributions from MEMP (252 ) (6,144 ) (26,006 ) Insurance recoveries related to environmental remediation 1,216 — — Provision for environmental remediation — (2,852 ) — Loss on office lease — (2,622 ) — Loss on settlement of AROs (1,606 ) — — Other non-cash equity (income) loss — — 784 Net income (loss) $ (297,890 ) $ (636,063 ) $ 151,332 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, 2015 MRD MEMP Other, Adjustments & Eliminations Consolidated Revenues: Oil & natural gas sales $ 374,042 $ 355,422 $ — $ 729,464 Other revenues — 2,725 — 2,725 Total revenues 374,042 358,147 — 732,189 Costs and expenses: Lease operating 24,903 168,199 — 193,102 Gathering, processing, and transportation 72,554 34,939 — 107,493 Gathering, processing, and transportation - affiliate 25,403 — — 25,403 Exploration 8,969 2,317 — 11,286 Taxes other than income 14,896 25,828 — 40,724 Depreciation, depletion, and amortization 188,742 195,814 — 384,556 Impairment of proved oil and natural gas properties — 616,784 — 616,784 Incentive unit compensation expense 35,142 — — 35,142 General and administrative 46,288 56,671 — 102,959 Accretion of asset retirement obligations 417 7,125 — 7,542 (Gain) loss on commodity derivative instruments (281,249 ) (462,890 ) — (744,139 ) (Gain) loss on sale of properties (47 ) (2,998 ) — (3,045 ) Other, net — (665 ) — (665 ) Total costs and expenses 136,018 641,124 — 777,142 Operating income (loss) 238,024 (282,977 ) — (44,953 ) Other income (expense): Interest expense, net (39,396 ) (114,732 ) — (154,128 ) Earnings from equity investments (327 ) — 327 — Other, net (1,022 ) 43 — (979 ) Total other income (expense) (40,745 ) (114,689 ) 327 (155,107 ) Income (loss) before income taxes 197,279 (397,666 ) 327 (200,060 ) Income tax benefit (expense) (100,005 ) 2,175 — (97,830 ) Net income (loss) $ 97,274 $ (395,491 ) $ 327 $ (297,890 ) For the Year Ended December 31, 2014 MRD MEMP Other, Adjustments & Eliminations Consolidated & Combined Revenues: Oil & natural gas sales $ 409,070 $ 561,677 $ — $ 970,747 Other revenues 12 4,366 — 4,378 Total revenues 409,082 566,043 — 975,125 Costs and expenses: Lease operating 17,570 143,733 — 161,303 Gathering, processing, and transportation 45,956 31,892 — 77,848 Exploration 13,853 2,750 — 16,603 Taxes other than income 12,610 33,141 — 45,751 Depreciation, depletion, and amortization 128,238 185,955 — 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 38,549 49,124 — 87,673 Accretion of asset retirement obligations 533 5,773 — 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 (1 ) (11 ) — (12 ) Total costs and expenses 971,156 367,643 — 1,338,799 Operating income (loss) (562,074 ) 198,400 — (363,674 ) Other income (expense): Interest expense, net (50,283 ) (83,550 ) — (133,833 ) Loss on extinguishment on debt (37,248 ) — — (37,248 ) Earnings from equity investments (12,656 ) — 12,656 — Other, net 320 (657 ) — (337 ) Total other income (expense) (99,867 ) (84,207 ) 12,656 (171,418 ) Income before income taxes (661,941 ) 114,193 12,656 (535,092 ) Income tax benefit (expense) (102,392 ) 1,421 — (100,971 ) Net income (loss) $ (764,333 ) $ 115,614 $ 12,656 $ (636,063 ) For the Year Ended December 31, 2013 MRD MEMP Other, Adjustments & Eliminations Consolidated & Combined Totals Revenues: Oil & natural gas sales $ 219,552 $ 391,440 $ — $ 610,992 Other revenues — 3,075 — 3,075 Total revenues 219,552 394,515 — 614,067 Costs and expenses: Lease operating 17,315 94,591 (108 ) 111,798 Gathering, processing, and transportation 17,666 25,055 — 42,721 Exploration 1,034 1,322 — 2,356 Taxes other than income 8,699 18,447 — 27,146 Depreciation, depletion, and amortization 70,903 113,814 — 184,717 Impairment of proved oil and natural gas properties 2,528 4,072 — 6,600 Incentive unit compensation expense 34,997 8,282 — 43,279 General and administrative 35,309 46,665 105 82,079 Accretion of asset retirement obligations 593 4,988 — 5,581 (Gain) loss on commodity derivative instruments (3,161 ) (26,133 ) — (29,294 ) (Gain) loss on sale of properties (82,773 ) (2,848 ) — (85,621 ) Other, net 2 647 — 649 Total costs and expenses 103,112 288,902 (3 ) 392,011 Operating income (loss) 116,440 105,613 3 222,056 Other income (expense): Interest expense, net (24,948 ) (44,302 ) — (69,250 ) Earnings from equity investments 1,066 — (1,066 ) — Other, net 143 2 — 145 Total other income (expense) (23,739 ) (44,300 ) (1,066 ) (69,105 ) Income before income taxes 92,701 61,313 (1,063 ) 152,951 Income tax benefit (expense) (1,311 ) (308 ) — (1,619 ) Net income (loss) $ 91,390 $ 61,005 $ (1,063 ) $ 151,332 |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2015 | |
Income Tax Disclosure [Abstract] | |
Income Tax | Note 15. Income Taxes The components of income tax benefit (expense) are as follows: For the Year Ended December 31, 2015 2014 2013 (In thousands) Current income taxes: Federal $ (9,982 ) $ — $ — State (147 ) 22 (1,619 ) Total current income tax benefit (expense) (10,129 ) 22 (1,619 ) Deferred income taxes: Federal (54,224 ) (88,994 ) — State (33,477 ) (11,999 ) — Total deferred income tax benefit (expense) (87,701 ) (100,993 ) — Total income tax benefit (expense) $ (97,830 ) $ (100,971 ) $ (1,619 ) The actual income tax benefit (expense) differs from the expected amount computed by applying the federal statutory corporate tax rate of 35% as follows: For the Year Ended December 31, 2015 2014 2013 (In thousands) Expected tax benefit (expense) at federal statutory rate $ 70,021 $ 187,282 $ (53,533 ) State income tax benefit (expense), net of federal benefit (21,856 ) (9,660 ) (1,619 ) Pass-through entities (1) (137,704 ) 49,989 53,533 Stock compensation (2) (12,300 ) (330,024 ) — Other 4,009 1,442 — Total income tax benefit (expense) $ (97,830 ) $ (100,971 ) $ (1,619 ) (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 liabilities are as follows: December 31, 2015 2014 (In thousands) Deferred income tax assets: Net operating loss carryforward $ 68,431 $ 28,043 Asset retirement obligation 4,483 5,757 Alternative minimum tax credit carryforward 9,984 — Other 5,584 3,566 Total deferred income tax assets $ 88,482 $ 37,366 Valuation allowance — (2,634 ) Net deferred income tax assets 88,482 34,732 Deferred income tax liabilities: Property, plant and equipment $ 172,951 $ 80,198 Derivatives 111,313 101,148 Other 45 332 Total deferred income tax liabilities $ 284,309 $ 181,678 Net deferred income tax liabilities $ 195,827 $ 146,946 In June 2014, the Company recorded a deferred tax liability of approximately $43.3 million through stockholders’ equity in connection with its initial public offering and the related restructuring transactions. The tax basis of its assets and liabilities was stepped up as a result of its initial public offering and the related restructuring transactions, which is reported as a transaction among stockholders for financial reporting purposes. Consistent with establishing the deferred tax liability through stockholders’ equity in its initial public offering, MRD reversed a deferred tax liability of approximately $38.8 million through stockholders’ equity in 2015, of which $4.4 million was associated with the estimated deferred tax effects included in equity in connection with its initial public offering in 2014 and $34.4 million was attributable to the deferred tax effects of the Property Swap in 2015. Uncertain Income Tax Position. The Company must recognize the tax effects of any uncertain tax positions it 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 had no unrecognized tax benefits as of December 31, 2015 and expects no significant change to the unrecognized tax benefits over the next twelve months ending December 31, 2016. Tax Audits and Settlements. Generally, the Company's income tax years 2011 through 2015 remain open and subject to examination by Federal tax authorities or the tax authorities in Louisiana and Texas and certain other small state taxing jurisdictions 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. Tax Attribute Carryforwards and Valuation Allowance. As of December 31, 2015, the Company had federal net operating loss carryforwards of approximately $169.7 million, which would expire in 2034 and 2035. The Company also had state tax carryforwards of approximately $173.6 million, which would expire 2034 and 2035. No valuation allowance was established based upon management’s evaluation that loss carryforwards will be fully realized. The Company had alternative minimum tax credit carryfowards of approximately $10.0 million, which would be carried forward indefinitely. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2015 | |
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: 2015 2014 2013 (In thousands) Balance at beginning of period $ 2,092 $ 577 $ 1,469 Charged to costs and expenses — 2,852 — Payments (1,876 ) (1,337 ) (892 ) Balance at end of period $ 216 $ 2,092 $ 577 Our environmental reserves were classified as current liabilities in accrued liabilities for the periods presented. 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, 2015, the gross account balance included in restricted investments was approximately $3.2 million. 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 of approximately $1.3 million. The trust account must maintain minimum balances as follows (in thousands): June 30, 2016 $ 148,000 December 31, 2016 $ 152,000 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, 2015, the remaining obligation was approximately $8.0 million. In 2015, the BOEM issued a preliminary report that indicated the estimated cost of decommissioning may further increase, and MEMP expects the amount to be finalized during 2016 after negotiations are completed. The following is a summary of the gross held-to-maturity investments held in the trust account as of December 31, 2015 (in thousands): Amortized Investment Cost U.S. Bank Money Market Cash Equivalent $ 144,008 Purchase Commitments At December 31, 2015, MEMP had a CO 2 Payment or Settlement due by Period Purchase commitment Total 2016 2017 2018 2019 2020 Thereafter CO 2 $ 30,307 $ 7,393 $ 7,505 $ 5,075 $ 5,366 $ 4,968 $ — Offshore ship services and other 4,662 4,662 — — — — — Third Party Midstream Service Agreement The Company has an existing amended and restated midstream service agreement with Regency Field Services LLC (“Regency”) for the gathering and processing of natural gas in in North Louisiana. The agreement’s primary term expires on December 31, 2025, subject to one-year extensions at either party’s election. Pursuant to the agreement, Regency expanded its Dubach processing facility among other facility and infrastructure improvements, built a new high pressure gathering pipeline to tie-in to their Dubberly processing plant amongst other pipeline and infrastructure improvements, and constructed facilities that permit deliveries into PennTex’s system (see Note 13). Regency is entitled to receive a payback demand fee from us and other third parties equal to 110% of the infrastructure improvement costs. The payback demand fee is based upon actual volumes gathered, but not less than a specified monthly demand quantity. Until payout is achieved, there is also a monthly demand quantity associated with gathering and processing fees. MDQ (MMBtu/d) Pay Demand Fee ($/MMBtu) Gathering Demand Fee ($/MMBtu) Dubberly Cryogenic Processing Fee ($/MMBtu) January 1, 2016 to January 22, 2020 249,700 0.275 0.295 n/a January 1, 2016 to January 22, 2020 113,000 n/a n/a 0.380 Regency has no obligation to process gas gathered and dedicated under the agreement after December 31, 2020. Effective on January 1, 2021 and continuing through the termination or expiration of the agreement, we will deliver all gas from the dedicated area and Regency will gather such gas, but will only process gas upon request. We have the right to request that gas gathered by Regency be delivered to alternative delivery points for processing (e.g., PennTex). Under these circumstances, Regency assesses us a $0.25 per MMBtu gathering only fee to take gas off its system. Minimum Volume Commitment At December 31, 2015, MEMP had a seven year minimum volume commitment with a third party associated with a certain portion of its properties located in East Texas. The table below outlines the payment commitments associated with this minimum volume commitment (in thousands): Payment or Settlement due by Period Purchase commitment Total 2016 2017 2018 2019 2020 Thereafter Midstream Services $ 35,788 $ 5,121 $ 5,121 $ 5,106 $ 5,107 $ 5,106 $ 10,227 Related Party Agreements See Note 13 for additional information related to the Classic and PennTex agreements. Operating Leases We also have leases for our corporate headquarters, lease equipment and incur surface rentals related to our business operations. For the years ended December 31, 2015, 2014, and 2013, we recognized $25.4 million, $10.8 million, and $8.3 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 2016 2017 2018 2019 2020 Thereafter (In thousands) MRD Segment: Operating leases $ 45,323 $ 10,509 $ 9,344 $ 7,368 $ 6,776 $ 6,203 $ 5,123 Sublease rental income 4,021 1,579 1,197 814 431 — — MEMP Segment: Operating leases 6,107 1,007 317 294 294 295 3,900 |
Condensed Consolidating Financi
Condensed Consolidating Financial Information | 12 Months Ended |
Dec. 31, 2015 | |
Organization Consolidation And Presentation Of Financial Statements [Abstract] | |
Condensed Consolidating Financial Information | Note 17. Condensed Consolidating Financial Information The Company owns no operating assets and has no significant operations independent of its subsidiaries. Our obligations under the MRD Senior Notes outstanding are fully and unconditionally guaranteed, jointly and severally, by certain of our 100% owned subsidiaries on a senior unsecured basis. Subsidiaries with noncontrolling interests and certain de minimis subsidiaries are non-guarantors. The following condensed consolidating financial information presents the financial information of the Company on a unconsolidated stand-alone basis and its combined guarantor and combined non-guarantor subsidiaries as of and for the periods indicated. Such financial information may not necessarily be indicative of our results of operations, cash flows or financial position had these subsidiaries operated as independent entities. As of December 31, 2015 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated (In thousands) ASSETS Current assets: Cash and cash equivalents $ 2,986 $ — $ 599 $ (1,410 ) $ 2,175 Accounts receivable - trade 7,850 49,537 60,238 (3,530 ) 114,095 Accounts receivable - affiliates 9,525 — — (9,525 ) — Short-term derivative instruments 227,991 — 272,320 — 500,311 Other financial assets 46,106 — — — 46,106 Prepaid expenses and other current assets 2,318 3,670 7,029 — 13,017 Total current assets 296,776 53,207 340,186 (14,465 ) 675,704 Property and equipment, net 15,825 1,729,236 1,946,323 — 3,691,384 Long-term derivative instruments 91,292 — 461,809 — 553,101 Investments in subsidiaries 1,482,847 — — (1,482,847 ) — Other long-term assets 4,976 — 157,684 — 162,660 Total assets $ 1,891,716 $ 1,782,443 $ 2,906,002 $ (1,497,312 ) $ 5,082,849 LIABILITIES AND EQUITY Current Liabilities: Accounts payable and accrued liabilities $ 26,796 $ 69,279 $ 61,715 $ (2,142 ) $ 155,648 Accounts payable - affiliates — 14,193 3,339 (12,323 ) 5,209 Revenues payable 80 35,463 25,504 — 61,047 Short-term derivative instruments — — 2,850 — 2,850 Total current liabilities 26,876 118,935 93,408 (14,465 ) 224,754 Long-term debt 1,012,064 — 2,000,579 — 3,012,643 Asset retirement obligations — 10,079 162,989 — 173,068 Long-term derivative instruments — — 1,441 — 1,441 Deferred tax liabilities 22,754 170,979 2,094 — 195,827 Other long-term liabilities 7,195 — — — 7,195 Total liabilities 1,068,889 299,993 2,260,511 (14,465 ) 3,614,928 Equity: Equity 822,827 1,482,450 645,491 (2,127,941 ) 822,827 Noncontrolling interest — — — 645,094 645,094 Total equity 822,827 1,482,450 645,491 (1,482,847 ) 1,467,921 Total liabilities & equity $ 1,891,716 $ 1,782,443 $ 2,906,002 $ (1,497,312 ) $ 5,082,849 As of December 30, 2014 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated (In thousands) ASSETS Current assets: Cash and cash equivalents $ 2,241 $ 3,762 $ 970 $ (1,015 ) $ 5,958 Accounts receivable- trade 5,995 44,952 83,346 (2,717 ) 131,576 Accounts receivable - affiliates 10,047 — 28 (10,075 ) — Short-term derivative instruments 131,471 — 208,585 — 340,056 Prepaid expenses and other current assets 4,178 7,993 11,032 — 23,203 Total current assets 153,932 56,707 303,961 (13,807 ) 500,793 Property and equipment, net 16,601 1,050,722 2,470,333 — 3,537,656 Long-term derivative instruments 123,567 — 311,802 — 435,369 Investments in subsidiaries 1,139,792 — — (1,139,792 ) — Other long-term assets 3,324 260 82,424 — 86,008 Total assets $ 1,437,216 $ 1,107,689 $ 3,168,520 $ (1,153,599 ) $ 4,559,826 LIABILITIES AND EQUITY Current Liabilities: Accounts payable and accrued expenses $ 6,245 $ 56,546 $ 113,177 $ (3,125 ) $ 172,843 Accounts payable - affiliates — 3,638 6,409 (9,423 ) 624 Revenues payable — 27,242 30,110 — 57,352 Short-term derivative instruments — — 3,289 — 3,289 Total current liabilities 6,245 87,426 152,985 (12,548 ) 234,108 Long-term debt 770,545 — 1,574,147 — 2,344,692 Asset retirement obligations — 9,830 112,701 — 122,531 Deferred tax liabilities 69,431 45,122 32,393 — 146,946 Other long-term liabilities 8,585 — — — 8,585 Total liabilities 854,806 142,378 1,872,226 (12,548 ) 2,856,862 Equity: Equity 582,410 965,311 1,290,734 (2,256,045 ) 582,410 Noncontrolling interest — — 5,560 1,114,994 1,120,554 Total equity 582,410 965,311 1,296,294 (1,141,051 ) 1,702,964 Total liabilities & equity $ 1,437,216 $ 1,107,689 $ 3,168,520 $ (1,153,599 ) $ 4,559,826 December 31, 2015 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated (In thousands) Revenues: Oil & natural gas sales $ — $ 374,042 $ 355,422 $ — $ 729,464 Other income — — 2,725 — 2,725 Total revenues — 374,042 358,147 — 732,189 Costs and expenses: Lease operating — 24,904 168,198 — 193,102 Gathering, processing and transportation — 72,555 34,938 — 107,493 Gathering, processing, and transportation - affiliate — 25,403 — — 25,403 Exploration — 8,969 2,317 — 11,286 Taxes other than income 3,833 11,063 25,828 — 40,724 Depreciation, depletion and amortization 4,191 184,551 195,814 — 384,556 Impairment of proved oil and natural gas properties — — 616,784 — 616,784 Incentive unit compensation expense 35,142 — — — 35,142 General and administrative 43,624 2,664 56,671 — 102,959 Accretion of asset retirement obligations — 418 7,124 — 7,542 (Gain) loss on commodity derivatives (281,250 ) — (462,889 ) — (744,139 ) (Gain) loss on sale of properties — (47 ) (2,998 ) — (3,045 ) Other, net — — (665 ) — (665 ) Total costs and expenses (194,460 ) 330,480 641,122 — 777,142 Operating income (loss) 194,460 43,562 (282,975 ) — (44,953 ) Other income (expense): Interest expense, net (39,308 ) (88 ) (114,732 ) — (154,128 ) Equity earnings from subsidiaries 16,434 — — (16,434 ) — Other, net (100 ) (922 ) 43 — (979 ) Total other income (expense) (22,974 ) (1,010 ) (114,689 ) (16,434 ) (155,107 ) Income before income taxes 171,486 42,552 (397,664 ) (16,434 ) (200,060 ) Income tax benefit (expense) (75,838 ) (24,167 ) 2,175 — (97,830 ) Net income (loss) 95,648 18,385 (395,489 ) (16,434 ) (297,890 ) Net income (loss) attributable to noncontrolling interest — — 386 (393,924 ) (393,538 ) Net income (loss) attributable to Memorial Resource Development Corp. $ 95,648 $ 18,385 $ (395,875 ) $ 377,490 $ 95,648 December 31, 2014 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated (In thousands) Revenues: Oil & natural gas sales $ — $ 409,070 $ 561,677 $ — $ 970,747 Other income 5 7 4,366 — 4,378 Total revenues 5 409,077 566,043 — 975,125 Costs and expenses: Lease operating — 17,570 143,733 — 161,303 Gathering, processing and transportation — 45,956 31,892 — 77,848 Exploration — 13,853 2,750 — 16,603 Taxes other than income — 12,610 33,141 — 45,751 Depreciation, depletion and amortization 1,133 127,105 185,955 — 314,193 Impairment of proved oil and natural gas properties — 24,576 407,540 — 432,116 Incentive unit compensation expense 111,866 831,060 1,023 — 943,949 General and administrative 13,232 25,277 49,164 — 87,673 Accretion of asset retirement obligations — 533 5,773 — 6,306 (Gain) loss on commodity derivatives (277,129 ) 19,395 (492,254 ) — (749,988 ) (Gain) loss on sale of properties — 3,167 (110 ) — 3,057 Other, net — — (12 ) — (12 ) Total costs and expenses (150,898 ) 1,121,102 368,595 — 1,338,799 Operating income (loss) 150,903 (712,025 ) 197,448 — (363,674 ) Other income (expense): Interest expense, net (19,532 ) (30,751 ) (83,550 ) — (133,833 ) Loss on extinguishment of debt (23,562 ) (13,686 ) — — (37,248 ) Equity earnings from subsidiaries (809,017 ) — — 809,017 — Other, net — 319 (656 ) — (337 ) Total other income (expense) (852,111 ) (44,118 ) (84,206 ) 809,017 (171,418 ) Income before income taxes (701,208 ) (756,143 ) 113,242 809,017 (535,092 ) Income tax benefit (expense) (83,373 ) (19,028 ) 1,430 — (100,971 ) Net income (loss) (784,581 ) (775,171 ) 114,672 809,017 (636,063 ) Net income (loss) attributable to noncontrolling interest — — 32 126,756 126,788 Net income (loss) attributable to Memorial Resource Development Corp. $ (784,581 ) $ (775,171 ) $ 114,640 $ 682,261 $ (762,851 ) December 31, 2013 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Combined & Consolidated (In thousands) Revenues: Oil & natural gas sales $ — $ 202,423 $ 408,569 $ — $ 610,992 Other income — — 3,075 — 3,075 Total revenues — 202,423 411,644 — 614,067 Costs and expenses: Lease operating — 14,710 97,088 — 111,798 Gathering, processing and transportation — 17,666 25,055 — 42,721 Exploration — 1,034 1,322 — 2,356 Taxes other than income — 7,869 19,277 — 27,146 Depreciation, depletion and amortization — 61,990 122,727 — 184,717 Impairment of proved oil and natural gas properties — 128 6,472 — 6,600 Incentive unit compensation expense — 14,353 28,926 — 43,279 General and administrative — 31,674 50,405 — 82,079 Accretion of asset retirement obligations — 516 5,065 — 5,581 (Gain) loss on commodity derivatives — (3,179 ) (26,115 ) — (29,294 ) (Gain) loss on sale of properties — 6,776 (92,397 ) — (85,621 ) Other, net — — 649 — 649 Total costs and expenses — 153,537 238,474 — 392,011 Operating income (loss) — 48,886 173,170 — 222,056 Other income (expense): Interest expense, net — (24,895 ) (44,355 ) — (69,250 ) Equity earnings from subsidiaries — 71,222 — (71,222 ) — Other, net — 141 4 — 145 Total other income (expense) — 46,468 (44,351 ) (71,222 ) (69,105 ) Income before income taxes — 95,354 128,819 (71,222 ) 152,951 Income tax benefit (expense) — (164 ) (1,455 ) — (1,619 ) Net income (loss) — 95,190 127,364 (71,222 ) 151,332 Net income (loss) attributable to noncontrolling interest — — 267 49,563 49,830 Net income (loss) attributable to Memorial Resource Development Corp. — 95,190 127,097 (120,785 ) 101,502 December 31, 2015 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated (In thousands) Net cash provided by (used in) operating activities $ 45,528 $ 372,028 $ 216,750 $ (395 ) $ 633,911 Cash flows from investing activities: Acquisitions of oil and natural gas properties — (291,536 ) (91,160 ) — (382,696 ) Additions to oil and gas properties — (594,902 ) (241,298 ) — (836,200 ) Additions to other property and equipment (3,401 ) (388 ) — — (3,789 ) Additions to restricted investments — — (5,690 ) — (5,690 ) Other financial hybrid instruments (46,106 ) — — — (46,106 ) Deposit for property acquisition — — — — — Investments in subsidiaries (499,336 ) — — 499,336 — Distributions from subsidiaries 78,648 — — (78,648 ) — Proceeds from the sale of oil and gas properties — 13,612 580 — 14,192 Net cash used in investing activities (470,195 ) (873,214 ) (337,568 ) 420,688 (1,260,289 ) Cash flows from financing activities: Advances on revolving credit facility 798,000 — 562,000 — 1,360,000 Payments on revolving credit facility (558,000 ) — (138,000 ) — (696,000 ) Repayment of senior notes — — (2,914 ) — (2,914 ) Deferred finance costs (1,498 ) — (341 ) — (1,839 ) Proceeds from MRD equity offering 242,880 — — — 242,880 Costs incurred in conjunction with MRD equity offering (4,773 ) — — — (4,773 ) Purchase of additional interests in consolidated subsidiaries — — (5,946 ) — (5,946 ) Contribution to MEMP — — 860 — 860 Capital contributions — 497,424 1,912 (499,336 ) — Distributions to MRD — — (78,396 ) 78,396 — Distribution to partners — — (163,259 ) 163,259 — Distribution to noncontrolling interests — — — (163,007 ) (163,007 ) Repurchases of equity (51,197 ) — (55,469 ) — (106,666 ) Net cash provided by financing activities 425,412 497,424 120,447 (420,688 ) 622,595 Net change in cash and cash equivalents 745 (3,762 ) (371 ) (395 ) (3,783 ) Cash and cash equivalents, beginning of period 2,241 3,762 970 (1,015 ) 5,958 Cash and cash equivalents, end of period $ 2,986 $ — $ 599 $ (1,410 ) $ 2,175 December 31, 2014 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Combined & Consolidated (In thousands) Net cash provided by (used in) operating activities $ (72,612 ) $ 297,490 $ 251,393 $ — $ 476,271 Cash flows from investing activities: Acquisitions of oil and natural gas properties — (93,909 ) (1,083,761 ) — (1,177,670 ) Additions to oil and gas properties — (376,123 ) (298,273 ) — (674,396 ) Additions to other property and equipment (15,980 ) (989 ) (98 ) — (17,067 ) Additions to restricted investments — — (3,976 ) — (3,976 ) Investments in subsidiaries (696,489 ) — — 696,489 — Distributions from subsidiaries 15,140 74,424 — (89,564 ) — Change in restricted cash — 49,946 — — 49,946 Deposits for property acquisitions — (215 ) (215 ) Proceeds from the sale of oil and gas properties — — 6,700 — 6,700 Other — — (301 ) — (301 ) Net cash used in investing activities (697,329 ) (346,866 ) (1,379,709 ) 606,925 (1,816,979 ) Cash flows from financing activities: Advances on revolving credit facility 1,174,000 126,800 1,446,000 — 2,746,800 Payments on revolving credit facility (991,000 ) (329,900 ) (1,137,000 ) — (2,457,900 ) Termination of second lien credit facility — (328,282 ) — — (328,282 ) Proceeds from the issuances of senior notes 600,000 — 492,425 — 1,092,425 Redemption of senior notes (351,808 ) — — — (351,808 ) Deferred finance costs (18,779 ) (61 ) (11,494 ) — (30,334 ) Proceeds from MRD initial public offering 408,500 — — — 408,500 Costs incurred in conjunction with initial public offering (28,373 ) — — — (28,373 ) Proceeds from MEMP equity offering — — 553,288 — 553,288 Costs incurred in conjunction with MEMP equity offering — — (12,510 ) — (12,510 ) MRD equity repurchases (161 ) — — — (161 ) MEMP equity repurchases — — (11,531 ) (11,531 ) Restricted MEMP units returned to plan — — (1,012 ) (1,012 ) Capital contributions — 686,623 9,866 (696,489 ) — Contributions from NGP affiliates related to sale of properties — — 1,165 — 1,165 Purchase of additional interests in subsidiaries (3,292 ) — — — (3,292 ) Distribution to equity owners — (15,000 ) (222,633 ) 237,633 — Distribution to NGP affiliates related to purchase of assets — (63,389 ) (3,304 ) — (66,693 ) Distribution to noncontrolling interests — — — (149,084 ) (149,084 ) Distributions to MRD Holdco (17,207 ) (39,520 ) (3,076 ) — (59,803 ) Distribution to NGP affiliates related to sale of assets, net of cash received — (32,770 ) — — (32,770 ) Other 302 18 — — 320 Net cash provided by financing activities 772,182 4,519 1,100,184 (607,940 ) 1,268,945 Net change in cash and cash equivalents 2,241 (44,857 ) (28,132 ) (1,015 ) (71,763 ) Cash and cash equivalents, beginning of period — 48,619 29,102 — 77,721 Cash and cash equivalents, end of period $ 2,241 $ 3,762 $ 970 $ (1,015 ) $ 5,958 December 31, 2013 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Combined & Consolidated (In thousands) Net cash provided by (used in) operating activities $ — $ 93,864 $ 183,959 $ — $ 277,823 Cash flows from investing activities: Acquisitions of oil and natural gas properties — (67,098 ) (38,664 ) — (105,762 ) Additions to oil and gas properties — (164,850 ) (195,165 ) — (360,015 ) Additions to restricted investments — — (5,361 ) — (5,361 ) Additions to other property and equipment — (2,432 ) (238 ) — (2,670 ) Investment in subsidiaries — (93,433 ) — 93,433 — Distribution from subsidiaries — 273,694 — (273,694 ) — Change in restricted cash — (49,347 ) — — (49,347 ) Proceeds from the sale of oil and gas properties — 33,152 122,560 155,712 Net cash used in investing activities — (70,314 ) (116,868 ) (180,261 ) (367,443 ) Cash flows from financing activities: Advances on revolving credit facilities — 174,400 958,355 — 1,132,755 Payments on revolving credit facilities — (200,500 ) (1,565,537 ) — (1,766,037 ) Proceeds from the issuances of senior notes — 343,000 688,563 — 1,031,563 Borrowings under second lien credit facility — 325,000 — — 325,000 Deferred financing costs — (20,250 ) (20,925 ) — (41,175 ) Proceeds from MEMP public offering — — 511,204 — 511,204 Costs incurred in conjunction with MEMP public offering — — (21,066 ) — (21,066 ) Proceeds from changes in ownership interests in MEMP — 135,012 — — 135,012 Purchase of additional interests in subsidiaries — (15,135 ) — — (15,135 ) Capital contributions — — 93,433 (93,433 ) — Contributions from previous owners — — 1,214 — 1,214 Contributions from NGP affiliates related to sale of properties — — 2,013 — 2,013 Distributions to the Funds — (732,362 ) — — (732,362 ) Distribution to equity owners — — (351,777 ) 351,777 — Distributions to noncontrolling interests — — — (78,083 ) (78,083 ) Distribution to NGP affiliates related to purchase of assets — — (355,494 ) — (355,494 ) Distributions made by previous owners — (2,590 ) (1,415 ) — (4,005 ) Cash retained by previous owners — — (7,909 ) — (7,909 ) Other — (129 ) 584 — 455 Net cash provided by financing activities — 6,446 (68,757 ) 180,261 117,950 Net change in cash and cash equivalents — 29,996 (1,666 ) — 28,330 Cash and cash equivalents, beginning of period — 18,623 30,768 — 49,391 Cash and cash equivalents, end of period $ — $ 48,619 $ 29,102 $ — $ 77,721 |
Quarterly Financial Information
Quarterly Financial Information (Unaudited) | 12 Months Ended |
Dec. 31, 2015 | |
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 and 2015, which impacted the comparability between the periods presented below. First Quarter Second Quarter Third Quarter Fourth Quarter For the Year Ended December 31, 2015 (In thousands, except per share amounts) Revenues $ 179,841 $ 176,743 $ 199,737 $ 175,868 Operating income (loss) (28,498 ) (126,790 ) (40,429 ) 150,764 Net income (loss) (112,149 ) (140,473 ) (135,255 ) 89,987 Net income (loss) attributable to noncontrolling interest (158,041 ) (113,771 ) (191,807 ) 70,081 Net income (loss) attributable to Memorial Resource Development Corp. 45,892 (26,702 ) 56,552 19,906 Net income (loss) available to common stockholders 45,615 (26,702 ) 56,051 19,950 Basic earnings per share 0.24 (0.14 ) 0.29 0.10 Diluted earnings per share 0.24 (0.14 ) 0.29 0.10 First Quarter Second Quarter Third Quarter Fourth Quarter For the Year Ended December 31, 2014 (In thousands, except per share amounts) Revenues $ 204,621 $ 254,777 $ 265,296 $ 250,431 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 Development Corp. 8,372 (948,349 ) 9,928 167,198 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 |
Supplemental Oil and Gas Inform
Supplemental Oil and Gas Information (Unaudited) | 12 Months Ended |
Dec. 31, 2015 | |
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, 2015 2014 2013 (In thousands) MRD Segment: Evaluated oil and natural gas properties $ 1,740,530 $ 1,268,873 $ 897,511 Support equipment and facilities 4,719 — — Unevaluated oil and natural gas properties 414,759 48,229 44,453 Accumulated depletion, depreciation, and amortization (434,735 ) (276,837 ) (160,620 ) Subtotal $ 1,725,273 $ 1,040,265 $ 781,344 MEMP Segment: Evaluated oil and natural gas properties $ 3,616,325 $ 3,329,338 $ 2,077,344 Support equipment and facilities 205,876 198,088 16,030 Unevaluated oil and natural gas properties — — 1,960 Accumulated depletion, depreciation, and amortization (1,878,549 ) (1,060,114 ) (464,812 ) Subtotal $ 1,943,652 $ 2,467,312 $ 1,630,522 Consolidated: Evaluated oil and natural gas properties $ 5,356,855 $ 4,598,211 $ 2,974,855 Support equipment and facilities 210,595 198,088 16,030 Unevaluated oil and natural gas properties 414,759 48,229 46,413 Accumulated depletion, depreciation, and amortization (2,313,284 ) (1,336,951 ) (625,432 ) Total $ 3,668,925 $ 3,507,577 $ 2,411,866 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, 2015 2014 2013 (In thousands) MRD Segment: Property acquisition costs, proved $ 8,347 $ 74,490 $ 56,108 Property acquisition costs, unproved 360,353 24,310 19,975 Exploration and extension well costs 28,068 209,532 13,313 Development 492,191 181,026 191,350 Subtotal $ 888,959 $ 489,358 $ 280,746 MEMP Segment: Property acquisition costs, proved $ 77,834 $ 983,076 $ 37,786 Property acquisition costs, unproved 1,887 720 — Exploration and extension well costs 2,078 — — Development 233,241 308,724 166,090 Subtotal $ 315,040 $ 1,292,520 $ 203,876 Consolidated: Property acquisition costs, proved $ 86,181 $ 1,057,566 $ 93,894 Property acquisition costs, unproved 362,240 25,030 19,975 Exploration and extension well costs 30,146 209,532 13,313 Development 725,432 489,750 357,440 Total $ 1,203,999 $ 1,781,878 $ 484,622 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 Ryder Scott to audit our internally prepared reserves estimates for all of our estimated proved reserves (by volume) at December 31, 2015. 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: 2015 2014 2013 Oil ($/Bbl) West Texas Intermediate (1) $ 46.79 $ 91.48 $ 93.42 NGL ($/Bbl) West Texas Intermediate (1) $ 46.79 $ 91.48 $ 93.42 Natural Gas ($/Mmbtu) Henry Hub (2) $ 2.59 $ 4.35 $ 3.67 (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, 2015, 2014, and 2013 respectively: For the Year Ended December 31, 2015 Oil (MBbls) Gas (MMcf) NGLs (MBbls) Equivalent (MMcfe) Proved developed and undeveloped reserves: Beginning of the year 11,915 1,013,340 53,033 1,403,030 Extensions and discoveries 1,111 50,343 2,741 73,456 Purchase of minerals in place 535 17,508 969 26,532 Production (1,331 ) (98,269 ) (3,249 ) (125,749 ) Sales of minerals in place (407 ) (39,272 ) (358 ) (43,861 ) Revision of previous estimates 1,331 30,164 1,024 44,286 End of year 13,154 973,814 54,160 1,377,694 Proved developed reserves: Beginning of year 3,708 355,331 18,203 486,793 End of year 6,101 443,983 24,583 628,081 Proved undeveloped reserves: Beginning of year 8,207 658,009 34,830 916,237 End of year 7,053 529,831 29,577 749,613 For the Year Ended December 31, 2014 Oil (MBbls) Gas (MMcf) NGLs (MBbls) Equivalent (MMcfe) Proved developed and undeveloped reserves: Beginning of the year 10,824 671,485 35,628 950,199 Extensions and discoveries 1,825 183,467 9,876 253,670 Purchase of minerals in place 269 22,186 1,247 31,283 Production (908 ) (56,574 ) (1,863 ) (73,200 ) Sales of minerals in place (623 ) (10,815 ) (950 ) (20,253 ) Revision of previous estimates 528 203,591 9,095 261,331 End of year 11,915 1,013,340 53,033 1,403,030 Proved developed reserves: Beginning of year 3,238 223,362 12,226 316,154 End of year 3,708 355,331 18,203 486,793 Proved undeveloped reserves: Beginning of year 7,586 448,123 23,402 634,045 End of year 8,207 658,009 34,830 916,237 For the Year Ended December 31, 2013 Oil (MBbls) Gas (MMcf) NGLs (MBbls) Equivalent (MMcfe) Proved developed and undeveloped reserves: Beginning of the year 10,220 549,449 31,264 798,357 Extensions and discoveries 1,635 105,289 5,712 149,369 Purchase of minerals in place 211 31,815 1,017 39,183 Production (631 ) (28,729 ) (1,282 ) (40,212 ) Sales of minerals in place (599 ) (14,137 ) (1,573 ) (27,169 ) Revision of previous estimates (12 ) 27,798 490 30,671 End of year (1) 10,824 671,485 35,628 950,199 Proved developed reserves: Beginning of year 2,813 180,523 10,208 258,651 End of year 3,238 223,362 12,226 316,154 Proved undeveloped reserves: Beginning of year 7,407 368,926 21,056 539,706 End of year 7,586 448,123 23,402 634,045 (1) Noteworthy amounts included in the categories of proved reserve changes in the above tables include: · During 2015, MRD had upward performance revisions to total proved reserves of 233 Bcfe offset by downward price revisions of 189 Bcfe primarily due to declining commodity prices. Additionally, there was an increase of 74 Bcfe from extensions and discoveries, primarily due to the continued redevelopment program in the Terryville Complex. MRD also acquired 27 Bcfe in the Terryville Complex and divested 44 Bcfe in other noncore areas. PUDs decreased by 166 Bcfe during 2015 due to reclassifications of 231 Bcfe into proved developed reserves, upward revisions of 286 Bcfe due to well performance and downward revisions of 221 Bcfe due to uneconomic vertical PUDs. · During 2014, MRD had an increase in reserves of 254 Bcfe, primarily through the category extensions and discoveries. The extensions and discoveries were due to the horizontal development of unproved locations. Additionally, upward revisions of 261 Bcfe were due to positive well performance in the Terryville Complex. MRD also acquired 31 Bcfe from multiple acquisitions within the Terryville Complex. · During 2013, extensions and discoveries of 149 Bcfe primarily related to the horizontal redevelopment drilling program in the Terryville Complex. 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, 2015 2014 2013 (In thousands) Future cash inflows $ 4,008,764 $ 7,314,745 $ 4,942,687 Future production costs (1,438,531 ) (1,020,599 ) (1,343,252 ) Future development costs (784,003 ) (1,209,907 ) (1,137,429 ) Future income tax expense (1) (88,723 ) (1,669,356 ) — Future net cash flows for estimated timing of cash flows 1,697,507 3,414,883 2,462,006 10% annual discount for estimated timing of cash flows (877,647 ) (1,604,728 ) (1,103,145 ) Standardized measure of discounted future net cash flows (2) $ 819,860 $ 1,810,155 $ 1,358,861 ( 1) Our predecessor was a pass through entity and was subject to the Texas margin tax based on the taxable margin apportioned to Texas. However, due to immateriality, we have excluded the impact of this tax for the year ended December 31, 2013. (2) Includes $63,422 attributable to both noncontrolling interests and the MRD Segment previous owners for the year ended December 31, 2013. 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, 2015: For the Year Ended December 31, 2015 2014 2013 (In thousands) Beginning of year $ 1,810,155 $ 1,358,861 $ 1,138,271 Sale of oil and natural gas produced, net of production costs (240,244 ) (332,785 ) (175,933 ) Purchase of minerals in place 53,597 69,282 51,177 Sale of minerals in place (41,543 ) (47,791 ) (54,091 ) Extensions and discoveries 30,006 653,088 286,796 Changes in income taxes, net 882,942 (995,635 ) — Changes in prices and costs (2,284,279 ) 367,212 (59,083 ) Previously estimated development costs incurred 294,617 205,388 62,012 Net changes in future development costs 190,403 (68,079 ) (1,295 ) Revisions of previous quantities 51,455 713,176 45,183 Accretion of discount 244,123 135,887 110,312 Change in production rates and other (171,372 ) (248,449 ) (44,488 ) End of year $ 819,860 $ 1,810,155 $ 1,358,861 MEMP Segment The following tables set forth estimates of the net reserves as of December 31, 2015, 2014, and 2013 respectively: For the Year Ended December 31, 2015 Oil (MBbls) Gas (MMcf) NGLs (MBbls) Equivalent (MMcfe) Proved developed and undeveloped reserves: Beginning of the year 100,258 727,216 59,034 1,682,960 Extensions and discoveries 2,319 8,686 558 25,950 Purchase of minerals in place 10,132 34,128 367 97,122 Production (4,087 ) (50,875 ) (2,820 ) (92,315 ) Sale of minerals in place (380 ) (13,731 ) (758 ) (20,559 ) Revision of previous estimates (17,297 ) (243,898 ) (12,986 ) (425,587 ) End of year (1) 90,945 461,526 43,395 1,267,571 Proved developed reserves: Beginning of year 54,723 417,247 37,260 969,141 End of year 50,817 311,147 30,315 797,936 Proved undeveloped reserves: Beginning of year 45,535 309,969 21,774 713,819 End of year 40,128 150,379 13,080 469,635 (1) MRD Segment’s share of these reserves is 1,268 MMcfe . For the Year Ended December 31, 2014 Oil (MBbls) Gas (MMcf) NGLs (MBbls) Equivalent (MMcfe) Proved developed and undeveloped reserves: Beginning of the year 39,635 737,908 35,794 1,190,484 Extensions and discoveries 849 12,783 711 22,145 Purchase of minerals in place 69,095 13,036 22,351 561,713 Production (3,135 ) (48,721 ) (2,498 ) (82,520 ) Revision of previous estimates (6,186 ) 12,210 2,676 (8,862 ) End of year (1) 100,258 727,216 59,034 1,682,960 Proved developed reserves: Beginning of year 22,429 427,983 17,637 668,381 End of year 54,723 417,247 37,260 969,141 Proved undeveloped reserves: Beginning of year 17,206 309,925 18,157 522,103 End of year 45,535 309,969 21,774 713,819 (1) MRD Segment’s share of these reserves is 230,503 MMcfe. For the Year Ended December 31, 2013 Oil (MBbls) Gas (MMcf) NGLs (MBbls) Equivalent (MMcfe) Proved developed and undeveloped reserves: Beginning of the year 40,822 794,369 39,554 1,276,625 Extensions and discoveries 5,814 85,455 4,353 146,463 Purchase of minerals in place 119 16,294 258 18,554 Production (1,797 ) (41,287 ) (1,806 ) (62,907 ) Revision of previous estimates (5,323 ) (116,923 ) (6,565 ) (188,251 ) End of year (1) 39,635 737,908 35,794 1,190,484 Proved developed reserves: Beginning of year 24,784 441,858 18,060 698,922 End of year 22,429 427,983 17,637 668,381 Proved undeveloped reserves: 16,038 352,511 21,494 577,703 Beginning of year 17,206 309,925 18,157 522,103 End of year (1) MRD Segment’s share of these reserves is 265,216 MMcfe. Noteworthy amounts included in the categories of proved reserve changes in the above tables include: · MEMP acquired 562 Bcfe in multiple acquisitions during the year ended December 31, 2014, the largest being the Wyoming Acquisition of 497 Bcfe. MEMP also acquired 45 Bcfe from the Eagle Ford Acquisition. An upward revision of natural gas for the year ended December 31, 2014 was due to increased natural gas prices on certain East Texas properties. The upward revision was partially offset by a downward revision of natural gas for the year ended December 31, 2014, which was primarily due to updated well performance data in certain other East Texas fields. Proved undeveloped reserves increased during the year ended December 31, 2014 primarily due to the Wyoming Acquisition. · The 415 Bcfe reduction in reserves for the year ended December 31, 2015 was primarily due to a 413 Bcfe downward pricing revision and a 13 Bcfe downward revision due to updated well performance data. MEMP acquired 97 Bcfe during the year ended December 31, 2015, the largest being the 2015 Beta Acquisition of 59 Bcfe. PUD reserves decreased primarily due to downward pricing during the year ended December 31, 2015. 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, 2015 2014 2013 (In thousands) Future cash inflows $ 5,952,935 $ 14,190,450 $ 7,672,312 Future production costs (3,194,577 ) (4,821,051 ) (2,963,146 ) Future development costs (808,512 ) (1,455,926 ) (901,374 ) Future income tax expense (1) — (119,675 ) — Future net cash flows for estimated timing of cash flows 1,949,846 7,793,798 3,807,792 10% annual discount for estimated timing of cash flows (1,360,292 ) (4,881,811 ) (2,089,588 ) Standardized measure of discounted future net cash flows (2) $ 589,554 $ 2,911,987 $ 1,718,204 (1) MEMP is subject to the Texas margin tax based on the taxable margin apportioned to Texas. However, due to immateriality we have excluded the impact of this tax for the years ended December 31, 2015, 2014 and 2013. The taxes in 2014 relate to Classic since its reserves were attributable to a taxable entity for federal income tax purposes for the year ended December 31, 2014. (2) MRD Segment’s share of the standardized measure of discounted future net cash flows was $589, $155,139 and $252,410 for the years ended December 31, 2015, 2014 and 2013, 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, 2015: For the Year Ended December 31, 2015 2014 2013 (In thousands) Beginning of year $ 2,911,987 $ 1,718,204 $ 1,772,240 Sale of oil and natural gas produced, net of production costs (128,382 ) (354,932 ) (255,031 ) Purchase of minerals in place 75,998 1,489,477 23,160 Sale of minerals in place (45,100 ) — — Extensions and discoveries 18,582 44,843 150,631 Changes in income taxes, net 63,180 (63,180 ) — Changes in prices and costs (2,764,481 ) (170,682 ) (26,648 ) Previously estimated development costs incurred 322,446 275,078 199,775 Net changes in future development costs 448,089 (133,098 ) (16,219 ) Revisions of previous quantities (344,775 ) (48,087 ) (373,109 ) Accretion of discount 297,517 171,820 177,223 Change in production rates and other (265,507 ) (17,456 ) 66,182 End of year $ 589,554 $ 2,911,987 $ 1,718,204 |
Summary of Significant Accoun26
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2015 | |
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 | 2014 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, including Jay Graham, our Chief Executive Officer, 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 Jay Graham and such other former management members of WildHorse Resources; We entered into a registration rights agreement and a voting agreement with MRD Holdco, Jay Graham, our Chief Executive Officer, and certain other 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 owned certain leasehold interests and overriding royalty interests in Texas and Montana, MRD Midstream LLC, which owned 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. Certain amounts in the prior year financial statements have been reclassified to conform to current presentation. Gathering, processing, and transportation costs were previously accounted for as revenue deductions and are now being presented as costs and expenses on our statements of operations on a separate line item. We have elected to early adopt new accounting pronouncements related to the presentation of deferred taxes and debt issuance costs. The retrospective adjustments to the December 31, 2014 balance sheet are shown below. Previously Reported December 31, 2014 Adjustment Effect December 31, 2014 As Adjusted (In thousands) Prepaid expenses and other current assets 28,027 (4,824 ) 23,203 Other long-term assets 37,284 (28,637 ) 8,647 Accrued liabilities 199,000 (51,929 ) 147,071 Long-term debt — 783,000 (12,455 ) 770,545 Long-term debt—MEMP Segment 1,595,413 (21,266 ) 1,574,147 Deferred tax liabilities 95,017 51,929 146,946 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 and its consolidating subsidiaries except for MEMP and its subsidiaries. MEMP—reflects the combined operations of MEMP and its subsidiaries. Segment financial information has been retrospectively revised for the following common control transactions for comparability purposes: acquisition by MEMP of certain assets in East Texas from MRD in February 2015 in exchange for approximately $78.4 million in cash and certain properties in North Louisiana (the “Property Swap”); 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; and 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. |
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 and other 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. We did not have any material write-offs related to uncollectible accounts during the years ended December 31, 2015, 2014 and 2013. Management determined that an allowance for uncollectible accounts was unnecessary at both December 31, 2015 and 2014, 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, 2015, 2014, and 2013. Oil and natural gas properties consisted of the following at the dates indicated: Years Ended December 31, 2015 2014 (In thousands) Proved oil and natural gas properties $ 5,353,594 $ 4,598,211 Support equipment and facilities 210,595 198,089 Unproved oil and natural gas properties 418,020 48,229 Total oil and natural gas properties $ 5,982,209 $ 4,844,529 At December 31, 2015 and 2014, we had $201.0 million and $119.0 million, respectively, capitalized in proved oil and natural gas properties related to wells in various stages of drilling and completion, which have been excluded from the depletion base. |
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, 2015. MEMP engaged Ryder Scott Company, L.P. (“Ryder Scott”) to audit MEMP’s internally prepared reserves estimates for all of MEMP’s proved reserves (by volume) at December 31, 2015. 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, 2015, 2014, and 2013 was approximately $616.8 million, $432.1 million and $6.6 million, respectively. See Note 4 for further discussion on impairments. Unproved oil and natural gas properties are reviewed for impairment based on time or geologic factors. Information such as drilling results, reservoir performance, seismic interpretation or future plans to develop acreage is also considered. When unproved property investments are deemed to be impaired, the expense is reported in exploration expenses. We did not record any impairments related to unproved properties for the years ended December 31, 2015, 2014 and 2013. |
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. These restricted investments consist of money market deposit accounts, money market mutual funds, and commercial paper. 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, 2015, 2014, and 2013 was approximately $8.9 million, $7.4 million and $8.3 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, 2015 or 2014. The following individual customers each accounted for 10% or more of total reported revenues for the period indicated: Years Ending December 31, 2015 2014 2013 Consolidated & Combined: Energy Transfer Equity, L.P. and subsidiaries 26 % 33 % 35 % Royal Dutch Shell plc and subsidiaries 11 % n/a n/a Sinclair Oil & Gas Company 11 % n/a n/a MRD Segment: Energy Transfer Equity, L.P. and subsidiaries 56 % 85 % 86 % Plains Marketing, L.P. 11 % n/a n/a MEMP Segment: Sinclair Oil & Gas Company 18 % 11 % n/a Phillips 66 12 % 12 % 14 % Royal Dutch Shell plc and subsidiaries 14 % n/a n/a |
Derivative and Other Financial Instruments | Derivative and Other Financial 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. Embedded derivatives that are required to be bifurcated and accounted for separately are treated in the same manner as freestanding derivatives. Embedded derivatives are recorded at fair value, with the difference between the basis of the hybrid financial instrument and the fair value of the embedded derivative recorded as the carrying value of the host contract. See Note 5 for further information on certain commodity contracts that required bifurcation. |
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, 2015 and 2014, we capitalized $7.4 million and $7.3 million of interest, respectively. |
Income Tax | Income Tax The Company uses the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the tax basis in assets and liabilities and their reported amounts in the financial statements and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. 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 deferred tax assets will not be realized. The Company recognizes interest and penalties accrued to unrecognized tax benefits in other income (expense) in its consolidated statement of operations. A tax benefit from an uncertain tax position is recognized when it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position. The tax benefit recorded is equal to the largest amount that is greater than 50% likely to be realized through effective settlement with a taxing authority. |
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 (e.g., phantom unit awards) is 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, December 31, 2015 2014 Accrued capital expenditures $ 48,307 $ 80,350 Accrued interest payable 40,849 24,797 Accrued lease operating expense 18,874 16,403 Accrued general and administrative expenses 5,991 8,516 Accrued ad valorem taxes 1,583 8,870 Asset retirement obligation - current 1,175 — Other miscellaneous, including operator advances 5,020 8,135 $ 121,799 $ 147,071 |
Supplemental Cash Flow Information | Supplemental Cash Flow Information Supplemental cash flow for the periods presented (in thousands): For the Year Ended December 31, 2015 2014 2013 Supplemental cash flows: Cash paid for interest, net of capitalized interest $ 126,087 $ 130,732 $ 61,140 Cash paid for taxes 8,632 838 168 Noncash investing and financing activities: Increase (decrease) in capital expenditures in payables and accrued liabilities (32,043 ) 31,771 41,017 (Increase) decrease in accounts receivable related to acquisitions and divestitures 10,550 (6,706 ) (4,301 ) Assumptions of asset retirement obligations related to properties acquired or drilled 25,896 5,420 4,227 Accrued distribution to NGP affiliates related to Cinco Group acquisitions — — 4,352 Repurchase of equity under repurchase program — 3,425 — |
New Accounting Pronouncements | New Accounting Pronouncements Balance Sheet Classification of Deferred Taxes. In November 2015, the Financial Accounting Standards Board (“FASB”) issued an accounting standards update that requires entities with a classified balance sheet to present all deferred tax assets and liabilities as noncurrent. The current requirement that deferred tax assets and liabilities of a tax-paying component of an entity be offset and presented as a single amount is not affected by the amendment. The amendments are effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early adoption is permitted for all entities as of the beginning of an interim or annual reporting period. The amendments may be applied either prospectively to all deferred tax assets and liabilities or retrospectively to all periods presented. We have adopted this guidance as of December 31, 2015 and applied the disclosure requirements retrospectively to the consolidated financial statements and footnote disclosure. Simplifying the Accounting for Measurement-Period Adjustments. In September 2015, the FASB issued an accounting standards update that eliminates the requirement that an acquirer in a business combination account for measurement-period adjustments retrospectively. Instead, an acquirer will recognize a measurement-period adjustment during the period in which it determines the amount of the adjustment. Disclosure of the effect on earnings of any amounts an acquirer would have recorded in previous periods if the accounting had been completed at the acquisition date is required. The disclosure is required for each affected income statement line item, and may be presented separately on the face of the income statement or in the notes to the financial statements. The new guidance should be applied prospectively to adjustments to provisional amounts that occur after the effective date and is effective for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Early adoption is permitted for any interim and annual financial statements that have not yet been issued. The Company does not expect the impact of adopting this guidance to be material to the Company’s financial statements and related disclosures. 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. In August 2015, the FASB issued an accounting standards update that formally delayed the effective date of its new revenue recognition standard. The new standard is now effective for fiscal years, and interim periods within those years, beginning after December 15, 2017. Early adoption is now permitted for fiscal years, and interim periods within those years, beginning after December 15, 2016. 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, 2018. The Company has not yet selected a transition method and is currently evaluating the standard and the impact on its consolidated financial statements and footnote disclosures. Presentation of Debt Issuance Cost. In April 2015, the FASB issued an accounting standards update that requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying value of that debt liability, consistent with debt discounts. The guidance is effective retrospectively for fiscal years, and interim periods within those years, beginning after December 15, 2015. Early adoption is permitted for financial statements that have not been previously issued. The Company has chosen to adopt this standard and have applied this guidance in its consolidated financial statements and footnote disclosures. In August 2015, the FASB issued an accounting standards update that incorporates SEC guidance clarifying that debt issuance costs related to line-of-credit arrangements can be deferred and presented as an asset that is subsequently amortized over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The Company has elected this presentation in its consolidated financial statements and footnote disclosures as of December 31, 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 continues to assess the impact that adopting this new accounting guidance will have on its consolidated financial statements and footnote disclosures, we expect that MEMP will become a VIE. We believe we will continue to consolidate MEMP and become subject to the VIE primary beneficiary disclosure requirements. The deconsolidation of MEMP would have a material impact on our consolidated financial statements and related disclosures in the event there is a reconsideration event that triggers deconsolidation. 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. |
Organization and Basis of Pre27
Organization and Basis of Presentation (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Organization Consolidation And Presentation Of Financial Statements [Abstract] | |
Schedule of Retrospective Adjustments to Balance Sheet | The retrospective adjustments to the December 31, 2014 balance sheet are shown below. Previously Reported December 31, 2014 Adjustment Effect December 31, 2014 As Adjusted (In thousands) Prepaid expenses and other current assets 28,027 (4,824 ) 23,203 Other long-term assets 37,284 (28,637 ) 8,647 Accrued liabilities 199,000 (51,929 ) 147,071 Long-term debt — 783,000 (12,455 ) 770,545 Long-term debt—MEMP Segment 1,595,413 (21,266 ) 1,574,147 Deferred tax liabilities 95,017 51,929 146,946 |
Summary of Significant Accoun28
Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Accounting Policies [Abstract] | |
Schedule of Oil and Natural Gas Properties | Oil and natural gas properties consisted of the following at the dates indicated: Years Ended December 31, 2015 2014 (In thousands) Proved oil and natural gas properties $ 5,353,594 $ 4,598,211 Support equipment and facilities 210,595 198,089 Unproved oil and natural gas properties 418,020 48,229 Total oil and natural gas properties $ 5,982,209 $ 4,844,529 |
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, 2015 2014 2013 Consolidated & Combined: Energy Transfer Equity, L.P. and subsidiaries 26 % 33 % 35 % Royal Dutch Shell plc and subsidiaries 11 % n/a n/a Sinclair Oil & Gas Company 11 % n/a n/a MRD Segment: Energy Transfer Equity, L.P. and subsidiaries 56 % 85 % 86 % Plains Marketing, L.P. 11 % n/a n/a MEMP Segment: Sinclair Oil & Gas Company 18 % 11 % n/a Phillips 66 12 % 12 % 14 % Royal Dutch Shell plc and subsidiaries 14 % n/a n/a |
Schedule of Accrued Liabilities | Current accrued liabilities consisted of the following at the dates indicated (in thousands): December 31, December 31, 2015 2014 Accrued capital expenditures $ 48,307 $ 80,350 Accrued interest payable 40,849 24,797 Accrued lease operating expense 18,874 16,403 Accrued general and administrative expenses 5,991 8,516 Accrued ad valorem taxes 1,583 8,870 Asset retirement obligation - current 1,175 — Other miscellaneous, including operator advances 5,020 8,135 $ 121,799 $ 147,071 |
Schedule of Supplemental Cash flow | Supplemental cash flow for the periods presented (in thousands): For the Year Ended December 31, 2015 2014 2013 Supplemental cash flows: Cash paid for interest, net of capitalized interest $ 126,087 $ 130,732 $ 61,140 Cash paid for taxes 8,632 838 168 Noncash investing and financing activities: Increase (decrease) in capital expenditures in payables and accrued liabilities (32,043 ) 31,771 41,017 (Increase) decrease in accounts receivable related to acquisitions and divestitures 10,550 (6,706 ) (4,301 ) Assumptions of asset retirement obligations related to properties acquired or drilled 25,896 5,420 4,227 Accrued distribution to NGP affiliates related to Cinco Group acquisitions — — 4,352 Repurchase of equity under repurchase program — 3,425 — |
Acquisitions and Divestitures (
Acquisitions and Divestitures (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Transaction-Related Costs | Transaction-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, 2015 2014 2013 $ 3,902 $ 6,668 $ 8,313 |
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 MRD Consolidated and Combined (In thousands) Revenues $ 1,066,324 $ 800,487 Net income (loss) (602,044 ) 257,839 Basic and diluted earnings per share $ (4.08 ) $ — |
Beta Properties [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 for the Beta Properties (in thousands): Beta Properties Oil and gas properties $ 40,029 Prepaid expenses and other current assets 840 Restricted investments 69,579 Derivative instruments 4,568 Accounts receivable - affiliates and other 4,499 Asset retirement obligations (22,871 ) Accrued liabilities (2,010 ) Total identifiable net assets $ 94,634 |
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): MEMP MEMP MRD Eagle Ford Wyoming Louisiana Acquisition Acquisition Acquisition Oil and gas properties $ 168,606 $ 930,168 $ 72,141 Asset retirement obligations (285 ) (3,980 ) (271 ) Revenue Payable — (375 ) — Accrued liabilities (250 ) (19,693 ) — Total identifiable net assets $ 168,071 $ 906,120 $ 71,870 |
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 obligations (1,789 ) (78 ) (1,163 ) Accrued liabilities — — (118 ) Total identifiable net assets $ 67,098 $ 9,896 $ 19,463 |
Fair Value Measurements of Fi30
Fair Value Measurements of Financial Instruments (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
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, 2015 and December 31, 2014 for each of the fair value hierarchy levels: Fair Value Measurements at December 31, 2015 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 $ — $ 1,136,757 $ — $ 1,136,757 Interest rate derivatives — — — — Total assets $ — $ 1,136,757 $ — $ 1,136,757 Liabilities: Commodity derivatives $ — $ 84,981 $ — $ 84,981 Interest rate derivatives — 2,655 — 2,655 Total liabilities $ — $ 87,636 $ — $ 87,636 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 |
Risk Management and Derivativ31
Risk Management and Derivative and Other Financial Instruments (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |
Schedule of Open Commodity Positions | At December 31, 2015, the MRD Segment had the following open commodity positions (excluding embedded derivatives): 2016 2017 Natural Gas Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (MMBtu) 2,570,000 1,770,000 Weighted-average fixed price $ 4.09 $ 4.24 Collar contracts: Average Monthly Volume (MMBtu) 1,100,000 1,050,000 Weighted-average floor price $ 4.00 $ 4.00 Weighted-average ceiling price $ 4.71 $ 5.06 Purchased put option contracts: Average Monthly Volume (MMBtu) 6,000,000 5,350,000 Weighted-average strike price $ 3.51 $ 3.48 Weighted-average deferred premium paid $ (0.34 ) $ (0.32 ) TGT Z1 basis swaps: Average Monthly Volume (MMBtu) 1,120,000 200,000 Spread - Henry Hub $ (0.10 ) $ (0.08 ) Crude Oil Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 35,583 28,000 Weighted-average fixed price $ 83.58 $ 84.70 Collar contracts: Average Monthly Volume (Bbls) 27,000 — Weighted-average floor price $ 80.00 $ — Weighted-average ceiling price $ 99.70 $ — NGL Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 353,399 — Weighted-average fixed price $ 39.68 $ — At December 31, 2015, the MRD Segment had the following open embedded derivative positions: 2016 Oil Hybrid Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 27,080 Weighted-average fixed price $ 46.51 Initial net investment price 62.16 Total contract swap price $ 108.67 NGL Hybrid Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 83,101 Weighted-average fixed price $ 15.84 Initial net investment price 25.98 Total contract swap price $ 41.82 At December 31, 2015, the MEMP Segment had the following open commodity positions: 2016 2017 2018 2019 Natural Gas Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (MMBtu) 3,592,442 3,350,067 3,060,000 2,814,583 Weighted-average fixed price $ 4.14 $ 4.06 $ 4.18 $ 4.31 Basis swaps: Average Monthly Volume (MMBtu) 3,578,333 2,210,000 1,315,000 900,000 Spread $ (0.07 ) $ (0.04 ) $ (0.02 ) $ 0.01 Crude Oil Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 304,813 301,600 312,000 160,000 Weighted-average fixed price $ 85.48 $ 85.00 $ 83.74 $ 85.52 Basis swaps: Average Monthly Volume (Bbls) 140,000 67,500 — — Spread $ (10.02 ) $ (7.82 ) $ — $ — NGL Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 213,100 43,300 — — Weighted-average fixed price $ 35.64 $ 37.55 $ — $ — The MEMP Segment basis swaps included in the table above is presented on a disaggregated basis below: 2016 2017 2018 2019 Natural Gas Derivative Contracts: NGPL TexOk basis swaps: Average Monthly Volume (MMBtu) 3,003,333 1,800,000 1,200,000 900,000 Spread - Henry Hub $ (0.07 ) $ (0.07 ) $ (0.03 ) $ 0.01 HSC basis swaps: Average Monthly Volume (MMBtu) 135,000 115,000 115,000 — Spread - Henry Hub $ 0.07 $ 0.14 $ 0.15 $ — CIG basis swaps: Average Monthly Volume (MMBtu) 170,000 — — — Spread - Henry Hub $ (0.30 ) $ — $ — $ — TETCO STX basis swaps: Average Monthly Volume (MMBtu) 270,000 295,000 — — Spread - Henry Hub $ 0.06 $ 0.03 $ — $ — Crude Oil Derivative Contracts: Midway-Sunset basis swaps: Average Monthly Volume (Bbls) 100,000 37,500 — — Spread - Brent $ (12.29 ) $ (12.20 ) $ — $ — Midland basis swaps: Average Monthly Volume (Bbls) 40,000 30,000 — — Spread - WTI $ (4.34 ) $ (2.35 ) $ — $ — |
Schedule of Entity's Interest Rate Swap Open Positions | At December 31, 2015, MEMP had the following interest rate swap open positions: Credit Facility 2016 2017 2018 MEMP: Average Monthly Notional (in thousands) $ 400,000 $ 400,000 $ 100,000 Weighted-average fixed rate 0.943 % 1.612 % 1.946 % 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, 2015 and 2014. 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 2015 2014 2015 2014 (In thousands) Commodity contracts Short-term derivative instruments $ 552,614 $ 378,908 $ 53,939 $ 38,852 Interest rate swaps Short-term derivative instruments — — 1,214 3,289 Gross fair value 552,614 378,908 55,153 42,141 Netting arrangements Short-term derivative instruments (52,303 ) (38,852 ) (52,303 ) (38,852 ) Net recorded fair value Short-term derivative instruments $ 500,311 $ 340,056 $ 2,850 $ 3,289 Commodity contracts Long-term derivative instruments $ 584,143 $ 466,851 $ 31,042 $ 32,787 Interest rate swaps Long-term derivative instruments — 1,305 1,441 — Gross fair value 584,143 468,156 32,483 32,787 Netting arrangements Long-term derivative instruments (31,042 ) (32,787 ) (31,042 ) (32,787 ) Net recorded fair value Long-term derivative instruments $ 553,101 $ 435,369 $ 1,441 $ — |
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, 2015, 2014, and 2013: Statements of For the Year Ended December 31, Operations Location 2015 2014 2013 Commodity derivative contracts (Gain) loss on commodity derivatives $ (744,139 ) $ (749,988 ) $ (29,294 ) Interest rate derivatives Interest expense, net 4,674 145 (239 ) |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
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, 2015, 2014 and 2013: 2015 2014 2013 (In thousands) Asset retirement obligations at beginning of period $ 122,531 $ 111,769 $ 102,380 Liabilities added from acquisitions or drilling 25,896 5,420 4,227 Liabilities settled (1,430 ) (588 ) (170 ) Revision of estimates 23,230 293 1,516 Liabilities removed upon sale of wells (3,526 ) (669 ) (1,765 ) Accretion expense 7,542 6,306 5,581 Asset retirement obligations at end of period 174,243 122,531 111,769 Less: Current portion 1,175 — 90 Asset retirement obligations - long-term portion $ 173,068 $ 122,531 $ 111,679 |
Restricted Investments (Tables)
Restricted Investments (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Schedule Of Investments [Abstract] | |
Restricted Investment Balance | 2015 2014 (In thousands) BOEM platform abandonment (See Note 16) $ 144,008 $ 69,954 BOEM lease bonds 1,533 794 SPBPC Collateral: Contractual pipeline and surface facilities abandonment 3,178 2,701 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 $ 152,631 $ 77,361 |
Long Term Debt (Tables)
Long Term Debt (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
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 (other than MEMP GP). December 31, December 31, 2015 2014 (In thousands) MRD Segment: MRD $2.0 billion revolving credit facility, variable-rate, due June 2019 $ 423,000 $ 183,000 5.875% senior unsecured notes, due July 2022 ("MRD Senior Notes") (1) (4) 600,000 600,000 Unamortized debt issuance costs (10,936 ) (12,455 ) Subtotal 1,012,064 770,545 MEMP Segment: MEMP $2.0 billion revolving credit facility, variable-rate, due March 2018 836,000 412,000 7.625% senior unsecured notes, due May 2021 ("2021 Senior Notes") (2) (4) 700,000 700,000 6.875% senior unsecured notes, due August 2022 ("2022 Senior Notes") (3) (4) 496,990 500,000 Unamortized discounts (14,114 ) (16,587 ) Unamortized debt issuance costs (18,297 ) (21,266 ) Subtotal 2,000,579 1,574,147 Total long-term debt $ 3,012,643 $ 2,344,692 ( 1) The estimated fair value of this fixed-rate debt was $525.0 million and $534.0 million at December 31, 2015 and 2014, respectively. (2) The estimated fair value of this fixed-rate debt was $210.0 million and $563.5 million at December 31, 2015 and 2014, respectively. (3) The estimated fair value of this fixed-rate debt was $149.1 million and $380.0 million at December 31, 2015 and 2014, respectively. (4) 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, 2015 MRD Segment: MRD $2.0 billion revolving credit facility, variable-rate, due June 2019 $ 1,000,000 MEMP Segment: MEMP $2.0 billion revolving credit facility, variable-rate, due March 2018 1,175,000 |
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 Credit Facility December 31, 2015 2014 2013 MRD Segment: MRD revolving credit facility 1.92 % 1.99 % n/a WildHorse Resources revolver terminated June 2014 n/a 4.04 % 2.30 % WildHorse Resources second lien terminated June 2014 n/a 6.44 % 7.60 % Black Diamond terminated November 2013 n/a n/a 3.97 % MEMP Segment: MEMP revolving credit facility 2.12 % 2.67 % 3.25 % WHT revolver terminated March 2013 n/a n/a 2.29 % Tanos revolver terminated April 2013 n/a n/a 3.10 % Stanolind revolver paid off by MEMP October 2013 n/a n/a 3.52 % Boaz revolver terminated October 2013 n/a n/a 2.97 % Crown revolver terminated October 2013 n/a n/a 3.38 % MRD LLC revolver terminated December 2013 n/a n/a 3.17 % Propel Energy revolver paid off by MEMP October 2013 n/a n/a 3.08 % |
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, 2015 2014 (In thousands) MRD Segment: MRD revolving credit facility $ 4,976 $ 4,285 MRD Senior Notes 10,936 12,455 MEMP Segment: MEMP revolving credit facility 3,672 6,468 2021 Senior Notes 11,194 13,308 2022 Senior Notes 7,103 7,958 $ 37,881 $ 44,474 |
Stockholders' Equity and Nonc35
Stockholders' Equity and Noncontrolling Interests (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
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 since January 1, 2014: Balance January 1, 2014 — Shares of common stock issued 192,500,000 Shares of common stock repurchased (123,797 ) Restricted common shares issued (Note 11) 1,068,422 Restricted common shares forfeited (9,211 ) Balance December 31, 2014 193,435,414 Shares of common stock issued 13,800,000 Shares of common stock repurchased (2,764,887 ) Restricted common shares issued (Note 11) 938,558 Restricted common shares repurchased (1) (60,773 ) Restricted common shares forfeited (54,569 ) Balance December 31, 2015 205,293,743 (1) Restricted common shares are generally net-settled by shareholders to cover the required withholding tax upon vesting. Participants surrendered shares with value equivalent to the employee’s minimum statutory obligation for the applicable income and other employment taxes. Total payments remitted for the employees’ tax obligations to the appropriate taxing authorities were approximately $1.2 million. These net-settlements had the effect of shares repurchased by the Company as they reduced the number of shares that would have otherwise been outstanding as a result of the vesting and did not represent an expense to the Company. |
Earnings per Share (Tables)
Earnings per Share (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Earnings Per Share [Abstract] | |
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, 2015 2014 Numerator: Net income (loss) available to common stockholders $ 94,914 $ (784,581 ) Denominator: Weighted average common shares outstanding 193,698 192,498 Incremental treasury stock method shares (1) 469 203 Basic EPS $ 0.49 $ (4.08 ) Diluted EPS (1) $ 0.49 $ (4.08 ) (1) The Company determines the more dilutive of either the two-class method or the treasury stock method for diluted EPS. The two-class method was more dilutive for each period presented. |
Long-Term Incentive Plans (Tabl
Long-Term Incentive Plans (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
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 $ 19.00 Forfeited (9,211 ) $ 19.00 Restricted common shares outstanding at December 31, 2014 1,059,211 $ 19.00 Granted (3) 938,558 $ 18.80 Forfeited (54,569 ) $ 18.83 Vested (274,355 ) $ 19.00 Restricted common shares outstanding at December 31, 2015 1,668,845 $ 18.89 (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 (3) The aggregate grant date fair value of restricted common share awards issued in 2015 was $17.6 million based on grant date market prices ranging from $17.58 to $18.91 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, 2012 285,609 $ 18.08 Granted (2) 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 (3) 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 Granted (4) 827,704 $ 14.90 Forfeited (69,059 ) $ 18.35 Vested (483,627 ) $ 20.37 Restricted common units outstanding at December 31, 2015 1,368,538 $ 17.61 (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 2013 was $9.9 million based on grant date market prices ranging from $18.33 to $20.35 per unit. (3) 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 $21.99 to $23.40 per unit. (4) The aggregate grant date fair value of restricted common unit awards issued in 2015 was $12.3 million based on grant date market prices ranging from $6.20 to $15.45 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, 2015 2014 $ 8,788 $ 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, 2015 2014 2013 $ 10,809 $ 7,874 $ 3,558 |
Incentive Units (Tables)
Incentive Units (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
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 12/31/2015 12/31/2015 Dividend yield 0 % 0 % Expected volatility 51.30 % 51.30 % Risk-free rate 0.82 % 0.82 % Expected life (years) 1.42 1.42 |
Related Party Transactions (Tab
Related Party Transactions (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
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 |
Book Value of Net Assets Acquired | The net assets acquired were as follows (in thousands): 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 |
Book Value of Assets Sold | 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 |
Schedule of Minimum Volume Commitment and Fees Associated with the GPA | The amended and restated gas processing agreement, (“GPA”) has a 15-year primary term, subject to one-year extensions at either party’s election. Processing fees under the GPA are subject to annual inflation escalators. Under the GPA, the Company has agreed to deliver a minimum volume of gas for processing through the term of the agreement measured on a cumulative basis based on specified daily minimum volume thresholds. Any volumes of gas delivered up to the then-applicable daily minimum volume threshold are considered firm reserved gas and are charged the firm fixed-commitment fee, and any volumes delivered in excess of such threshold are considered interruptible volumes and are charged the interruptible-service fixed fee. Pursuant to the GPA, any deficiency payments made by the Company under the GPA will be treated as prepaid processing fees by PennTex (except for the June 2015 deficiency payment). These charges do not expire until the end of the primary term of the GPA. Quarterly deficiency payments are based on the firm-commitment fixed fee. The following table summarizes the minimum volume commitment (“MVC”) and fees associated with the GPA. Period MVC (MMBtu/d) Firm Fee ($/MMBtu) Interruptible Fee ($/MMBtu) June 1, 2015 to September 30, 2015 115,000 0.435 0.470 October 1, 2015 to June 30, 2016 345,000 0.435 0.470 July 1, 2016 to June 30, 2026 (1) 460,000 0.435 0.350 July 1, 2026 to June 1, 2030 345,000 0.435 0.350 June 2, 2030 to October 1, 2030 115,000 0.435 0.350 (1) The firm fee is reduced to $0.35 $/MMBtu for volumes in excess of 345,000 MMBtu/d. |
Transportation Services Agreement [Member] | |
Schedule of Fees Associated with Agreement | The transportation services agreement (“TSA”) provides for the transportation of NGLs through PennTex’s NGL pipeline from the outlet of their processing plants to a third party delivery point. The Company pays a usage fee for all volumes transported under the TSA. The TSA includes a plant tailgate dedication pursuant to which all of the Company’s NGLs produced from PennTex’s processing plants are delivered for transportation on the its NGL pipeline. The following table summarizes the fees associated with the TSA: Period Usage Fee ($/gallon) October 1, 2015 to October 1, 2030 0.04 |
Gas Gathering Agreement [Member] | |
Schedule of Minimum Volume Commitment and Fees Associated with the GPA | The gas gathering agreement, as amended, (“GGA”) has a 15-year primary term, subject to one-year extensions at either party’s election. The Company pays fees for gathering services provided by PennTex, including a firm capacity reservation payment through November 30, 2019 and a usage fee component that is subject to a minimum volume commitment. The GGA also has an annual “use it or lose it” deficiency provision that is based on the usage fee. The minimum volume commitment under the GGA is linked to the minimum volume commitment under the GPA. Period MVC (MMBtu/d) Firm Fee ($/MMBtu) Usage Fee ($/MMBtu) June 1, 2015 to June 1, 2030 460,000 0.03 n/a June 1, 2016 to December 31, 2025 115,000 n/a 0.02 October 1, 2015 to June 30, 2016 345,000 n/a 0.02 July 1, 2016 to November 30, 2019 460,000 n/a 0.02 December 1, 2019 to June 30, 2026 460,000 n/a 0.05 July 1, 2026 to June 1, 2030 345,000 n/a 0.05 |
Gas Transportation Agreement [Member] | |
Schedule of Fees Associated with Agreement | The gas transportation agreement, as amended, (“GTA”) has a 15-year primary term, subject to one-year extensions at either party’s election. The GTA provides for the transportation of residue gas through PennTex’s residue gas pipeline from the outlet of their processing plants to delivery points at interconnections with third-party natural gas transportation pipelines. The Company pays a usage fee for all volumes transported under the GTA. The GTA includes a plant tailgate dedication pursuant to which all of the Company’s residue gas produced from the PennTex’s processing plants are delivered for transportation on their residue gas pipeline. The GTA also includes a fixed monthly demand charge to provide priority firm service. The following table summarizes the fees associated with the GTA: Period Demand Fee ($/month) Usage Fee ($/MMBtu) June 1, 2015 to June 1, 2030 n/a 0.04 January 1, 2016 to December 31, 2025 360,000 n/a |
Business Segment Data (Tables)
Business Segment Data (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
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, 2015 374,042 358,147 — 732,189 For the Year Ended December 31, 2014 409,082 566,043 — 975,125 For the Year Ended December 31, 2013 219,552 394,515 — 614,067 Adjusted EBITDA: (1) For the Year Ended December 31, 2015 370,889 340,392 (252 ) 711,029 For the Year Ended December 31, 2014 316,317 337,560 (6,144 ) 647,733 For the Year Ended December 31, 2013 175,994 244,094 (25,232 ) 394,856 Segment assets: (2) As of December 31, 2015 2,177,492 2,906,003 (646 ) 5,082,849 As of December 31, 2014 1,401,313 3,168,494 (9,981 ) 4,559,826 Total cash expenditures for additions to long-lived assets: For the Year Ended December 31, 2015 890,226 332,459 — 1,222,685 For the Year Ended December 31, 2014 487,001 1,382,133 — 1,869,134 For the Year Ended December 31, 2013 254,724 213,723 — 468,447 (1) Adjustments and eliminations for the years ended December 31, 2015, 2014 and 2013 include amounts related to the MRD Segment’s equity investments in the MEMP Segment as well the elimination of $0.3 million, $6.1 million and $26.0 million of cash distributions that MEMP paid MRD Segment for the years ended December 31, 2015, 2014 and 2013, 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. |
Schedule of Calculation of Reportable Segment's Adjusted EBITDA | Calculation of Reportable Segments’ Adjusted EBITDA For the Year Ended December 31, 2015 Combined MRD MEMP Totals (In thousands) Net income (loss) $ 97,274 $ (395,491 ) $ (298,217 ) Interest expense, net 39,396 114,732 154,128 Income tax expense (benefit) 100,005 (2,175 ) 97,830 DD&A 188,742 195,814 384,556 Impairment of proved oil and natural gas properties — 616,784 616,784 Accretion of AROs 417 7,125 7,542 (Gain) loss on commodity derivative instruments (281,249 ) (462,890 ) (744,139 ) Cash settlements received (paid) on expired commodity derivative instruments 170,899 254,047 424,946 (Gain) loss on sale of properties (47 ) (2,998 ) (3,045 ) Transaction related costs 1,974 1,928 3,902 Incentive-based compensation expense 43,930 10,809 54,739 Exploration costs 8,969 2,317 11,286 Insurance recoveries related to environmental remediation — (1,216 ) (1,216 ) Loss on settlement of AROs — 1,606 1,606 Non-cash equity (income) loss from MEMP 327 — 327 Cash distributions from MEMP 252 — 252 Adjusted EBITDA $ 370,889 $ 340,392 $ 711,281 For the Year Ended December 31, 2014 Combined MRD MEMP Totals (In thousands) Net income (loss) $ (764,333 ) $ 115,614 $ (648,719 ) Interest expense, net 50,283 83,550 133,833 Income tax expense (benefit) 102,392 (1,421 ) 100,971 Loss on extinguishment of debt 37,248 — 37,248 DD&A 128,238 185,955 314,193 Impairment of proved oil and natural gas properties 24,576 407,540 432,116 Accretion of AROs 533 5,773 6,306 (Gain) loss on commodity derivative instruments (257,734 ) (492,254 ) (749,988 ) Cash settlements received (paid) on expired commodity derivative instruments 9,166 13,522 22,688 (Gain) loss on sale of properties 3,057 — 3,057 Transaction related costs 2,305 4,363 6,668 Incentive-based compensation expense 946,753 7,874 954,627 Exploration costs 13,853 2,750 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 $ 316,317 $ 337,560 $ 653,877 For the Year Ended December 31, 2013 Combined MRD MEMP Totals (In thousands) Net income (loss) $ 91,390 $ 61,005 $ 152,395 Interest expense, net 24,948 44,302 69,250 Income tax expense (benefit) 1,311 308 1,619 DD&A 70,903 113,814 184,717 Impairment of proved oil and natural gas properties 2,528 4,072 6,600 Accretion of AROs 593 4,988 5,581 (Gain) loss on commodity derivative instruments (3,161 ) (26,133 ) (29,294 ) Cash settlements received (paid) on expired commodity derivative instruments 8,481 23,638 32,119 (Gain) loss on sale of properties (82,773 ) (2,848 ) (85,621 ) Transaction related costs 1,584 6,729 8,313 Incentive-based compensation expense 34,997 11,840 46,837 Non-cash based compensation expense — 1,057 1,057 Exploration costs 1,034 1,322 2,356 Non-cash equity (income) loss from MEMP (1,847 ) — (1,847 ) Cash distributions from MEMP 26,006 — 26,006 Adjusted EBITDA $ 175,994 $ 244,094 $ 420,088 |
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, 2015 2014 2013 Total Reportable Segments' Adjusted EBITDA $ 711,281 $ 653,877 $ 420,088 Adjustments to reconcile Adjusted EBITDA to net income (loss): Interest expense, net (154,128 ) (133,833 ) (69,250 ) Loss on extinguishment of debt — (37,248 ) — Income tax benefit (expense) (97,830 ) (100,971 ) (1,619 ) DD&A (384,556 ) (314,193 ) (184,717 ) Impairment of proved oil and natural gas properties (616,784 ) (432,116 ) (6,600 ) Accretion of AROs (7,542 ) (6,306 ) (5,581 ) Gains (losses) on commodity derivative instruments 744,139 749,988 29,294 Cash settlements received (paid) on expired commodity derivative instruments (424,946 ) (22,688 ) (32,119 ) Gain (loss) on sale of properties 3,045 (3,057 ) 85,621 Transaction related costs (3,902 ) (6,668 ) (8,313 ) Incentive-based compensation expense (54,739 ) (954,627 ) (46,837 ) Non-cash based compensation expense — — (1,057 ) Exploration costs (11,286 ) (16,603 ) (2,356 ) Cash distributions from MEMP (252 ) (6,144 ) (26,006 ) Insurance recoveries related to environmental remediation 1,216 — — Provision for environmental remediation — (2,852 ) — Loss on office lease — (2,622 ) — Loss on settlement of AROs (1,606 ) — — Other non-cash equity (income) loss — — 784 Net income (loss) $ (297,890 ) $ (636,063 ) $ 151,332 |
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, 2015 MRD MEMP Other, Adjustments & Eliminations Consolidated Revenues: Oil & natural gas sales $ 374,042 $ 355,422 $ — $ 729,464 Other revenues — 2,725 — 2,725 Total revenues 374,042 358,147 — 732,189 Costs and expenses: Lease operating 24,903 168,199 — 193,102 Gathering, processing, and transportation 72,554 34,939 — 107,493 Gathering, processing, and transportation - affiliate 25,403 — — 25,403 Exploration 8,969 2,317 — 11,286 Taxes other than income 14,896 25,828 — 40,724 Depreciation, depletion, and amortization 188,742 195,814 — 384,556 Impairment of proved oil and natural gas properties — 616,784 — 616,784 Incentive unit compensation expense 35,142 — — 35,142 General and administrative 46,288 56,671 — 102,959 Accretion of asset retirement obligations 417 7,125 — 7,542 (Gain) loss on commodity derivative instruments (281,249 ) (462,890 ) — (744,139 ) (Gain) loss on sale of properties (47 ) (2,998 ) — (3,045 ) Other, net — (665 ) — (665 ) Total costs and expenses 136,018 641,124 — 777,142 Operating income (loss) 238,024 (282,977 ) — (44,953 ) Other income (expense): Interest expense, net (39,396 ) (114,732 ) — (154,128 ) Earnings from equity investments (327 ) — 327 — Other, net (1,022 ) 43 — (979 ) Total other income (expense) (40,745 ) (114,689 ) 327 (155,107 ) Income (loss) before income taxes 197,279 (397,666 ) 327 (200,060 ) Income tax benefit (expense) (100,005 ) 2,175 — (97,830 ) Net income (loss) $ 97,274 $ (395,491 ) $ 327 $ (297,890 ) For the Year Ended December 31, 2014 MRD MEMP Other, Adjustments & Eliminations Consolidated & Combined Revenues: Oil & natural gas sales $ 409,070 $ 561,677 $ — $ 970,747 Other revenues 12 4,366 — 4,378 Total revenues 409,082 566,043 — 975,125 Costs and expenses: Lease operating 17,570 143,733 — 161,303 Gathering, processing, and transportation 45,956 31,892 — 77,848 Exploration 13,853 2,750 — 16,603 Taxes other than income 12,610 33,141 — 45,751 Depreciation, depletion, and amortization 128,238 185,955 — 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 38,549 49,124 — 87,673 Accretion of asset retirement obligations 533 5,773 — 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 (1 ) (11 ) — (12 ) Total costs and expenses 971,156 367,643 — 1,338,799 Operating income (loss) (562,074 ) 198,400 — (363,674 ) Other income (expense): Interest expense, net (50,283 ) (83,550 ) — (133,833 ) Loss on extinguishment on debt (37,248 ) — — (37,248 ) Earnings from equity investments (12,656 ) — 12,656 — Other, net 320 (657 ) — (337 ) Total other income (expense) (99,867 ) (84,207 ) 12,656 (171,418 ) Income before income taxes (661,941 ) 114,193 12,656 (535,092 ) Income tax benefit (expense) (102,392 ) 1,421 — (100,971 ) Net income (loss) $ (764,333 ) $ 115,614 $ 12,656 $ (636,063 ) For the Year Ended December 31, 2013 MRD MEMP Other, Adjustments & Eliminations Consolidated & Combined Totals Revenues: Oil & natural gas sales $ 219,552 $ 391,440 $ — $ 610,992 Other revenues — 3,075 — 3,075 Total revenues 219,552 394,515 — 614,067 Costs and expenses: Lease operating 17,315 94,591 (108 ) 111,798 Gathering, processing, and transportation 17,666 25,055 — 42,721 Exploration 1,034 1,322 — 2,356 Taxes other than income 8,699 18,447 — 27,146 Depreciation, depletion, and amortization 70,903 113,814 — 184,717 Impairment of proved oil and natural gas properties 2,528 4,072 — 6,600 Incentive unit compensation expense 34,997 8,282 — 43,279 General and administrative 35,309 46,665 105 82,079 Accretion of asset retirement obligations 593 4,988 — 5,581 (Gain) loss on commodity derivative instruments (3,161 ) (26,133 ) — (29,294 ) (Gain) loss on sale of properties (82,773 ) (2,848 ) — (85,621 ) Other, net 2 647 — 649 Total costs and expenses 103,112 288,902 (3 ) 392,011 Operating income (loss) 116,440 105,613 3 222,056 Other income (expense): Interest expense, net (24,948 ) (44,302 ) — (69,250 ) Earnings from equity investments 1,066 — (1,066 ) — Other, net 143 2 — 145 Total other income (expense) (23,739 ) (44,300 ) (1,066 ) (69,105 ) Income before income taxes 92,701 61,313 (1,063 ) 152,951 Income tax benefit (expense) (1,311 ) (308 ) — (1,619 ) Net income (loss) $ 91,390 $ 61,005 $ (1,063 ) $ 151,332 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Income Tax Disclosure [Abstract] | |
Components of Income Tax Expense (Benefit) | The components of income tax benefit (expense) are as follows: For the Year Ended December 31, 2015 2014 2013 (In thousands) Current income taxes: Federal $ (9,982 ) $ — $ — State (147 ) 22 (1,619 ) Total current income tax benefit (expense) (10,129 ) 22 (1,619 ) Deferred income taxes: Federal (54,224 ) (88,994 ) — State (33,477 ) (11,999 ) — Total deferred income tax benefit (expense) (87,701 ) (100,993 ) — Total income tax benefit (expense) $ (97,830 ) $ (100,971 ) $ (1,619 ) |
Reconciliation of Income Tax Benefit (Expense) | The actual income tax benefit (expense) differs from the expected amount computed by applying the federal statutory corporate tax rate of 35% as follows: For the Year Ended December 31, 2015 2014 2013 (In thousands) Expected tax benefit (expense) at federal statutory rate $ 70,021 $ 187,282 $ (53,533 ) State income tax benefit (expense), net of federal benefit (21,856 ) (9,660 ) (1,619 ) Pass-through entities (1) (137,704 ) 49,989 53,533 Stock compensation (2) (12,300 ) (330,024 ) — Other 4,009 1,442 — Total income tax benefit (expense) $ (97,830 ) $ (100,971 ) $ (1,619 ) |
Components of Net Deferred Income Tax Liabilities | The components of net deferred income tax liabilities are as follows: December 31, 2015 2014 (In thousands) Deferred income tax assets: Net operating loss carryforward $ 68,431 $ 28,043 Asset retirement obligation 4,483 5,757 Alternative minimum tax credit carryforward 9,984 — Other 5,584 3,566 Total deferred income tax assets $ 88,482 $ 37,366 Valuation allowance — (2,634 ) Net deferred income tax assets 88,482 34,732 Deferred income tax liabilities: Property, plant and equipment $ 172,951 $ 80,198 Derivatives 111,313 101,148 Other 45 332 Total deferred income tax liabilities $ 284,309 $ 181,678 Net deferred income tax liabilities $ 195,827 $ 146,946 |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Commitments And Contingencies Disclosure [Abstract] | |
Environmental Reserves Activity | The following table presents the activity of our environmental reserves for the periods presented: 2015 2014 2013 (In thousands) Balance at beginning of period $ 2,092 $ 577 $ 1,469 Charged to costs and expenses — 2,852 — Payments (1,876 ) (1,337 ) (892 ) Balance at end of period $ 216 $ 2,092 $ 577 |
Minimum Balances Attributable to Net Working Interest | The trust account must maintain minimum balances as follows (in thousands): June 30, 2016 $ 148,000 December 31, 2016 $ 152,000 |
Gross Held-to-Maturity Investments | The following is a summary of the gross held-to-maturity investments held in the trust account as of December 31, 2015 (in thousands): Amortized Investment Cost U.S. Bank Money Market Cash Equivalent $ 144,008 |
CO2 and Midstream Minimum Purchase Commitments | At December 31, 2015, MEMP had a CO 2 Payment or Settlement due by Period Purchase commitment Total 2016 2017 2018 2019 2020 Thereafter CO 2 $ 30,307 $ 7,393 $ 7,505 $ 5,075 $ 5,366 $ 4,968 $ — Offshore ship services and other 4,662 4,662 — — — — — At December 31, 2015, MEMP had a seven year minimum volume commitment with a third party associated with a certain portion of its properties located in East Texas. The table below outlines the payment commitments associated with this minimum volume commitment (in thousands): Payment or Settlement due by Period Purchase commitment Total 2016 2017 2018 2019 2020 Thereafter Midstream Services $ 35,788 $ 5,121 $ 5,121 $ 5,106 $ 5,107 $ 5,106 $ 10,227 |
Monthly Demand Quantity and Fees | The table below summarizes the monthly demand quantity (“MDQ”) and fees associated with the agreement. Based on the MDQ, we project that that payout would be achieved during January 2020 MDQ (MMBtu/d) Pay Demand Fee ($/MMBtu) Gathering Demand Fee ($/MMBtu) Dubberly Cryogenic Processing Fee ($/MMBtu) January 1, 2016 to January 22, 2020 249,700 0.275 0.295 n/a January 1, 2016 to January 22, 2020 113,000 n/a n/a 0.380 |
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 2016 2017 2018 2019 2020 Thereafter (In thousands) MRD Segment: Operating leases $ 45,323 $ 10,509 $ 9,344 $ 7,368 $ 6,776 $ 6,203 $ 5,123 Sublease rental income 4,021 1,579 1,197 814 431 — — MEMP Segment: Operating leases 6,107 1,007 317 294 294 295 3,900 |
Condensed Consolidating Finan43
Condensed Consolidating Financial Information (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Organization Consolidation And Presentation Of Financial Statements [Abstract] | |
Condensed Consolidating Balance Sheets | The following condensed consolidating financial information presents the financial information of the Company on a unconsolidated stand-alone basis and its combined guarantor and combined non-guarantor subsidiaries as of and for the periods indicated. Such financial information may not necessarily be indicative of our results of operations, cash flows or financial positio n had these subsidiaries operated as independent entities. As of December 31, 2015 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated (In thousands) ASSETS Current assets: Cash and cash equivalents $ 2,986 $ — $ 599 $ (1,410 ) $ 2,175 Accounts receivable - trade 7,850 49,537 60,238 (3,530 ) 114,095 Accounts receivable - affiliates 9,525 — — (9,525 ) — Short-term derivative instruments 227,991 — 272,320 — 500,311 Other financial assets 46,106 — — — 46,106 Prepaid expenses and other current assets 2,318 3,670 7,029 — 13,017 Total current assets 296,776 53,207 340,186 (14,465 ) 675,704 Property and equipment, net 15,825 1,729,236 1,946,323 — 3,691,384 Long-term derivative instruments 91,292 — 461,809 — 553,101 Investments in subsidiaries 1,482,847 — — (1,482,847 ) — Other long-term assets 4,976 — 157,684 — 162,660 Total assets $ 1,891,716 $ 1,782,443 $ 2,906,002 $ (1,497,312 ) $ 5,082,849 LIABILITIES AND EQUITY Current Liabilities: Accounts payable and accrued liabilities $ 26,796 $ 69,279 $ 61,715 $ (2,142 ) $ 155,648 Accounts payable - affiliates — 14,193 3,339 (12,323 ) 5,209 Revenues payable 80 35,463 25,504 — 61,047 Short-term derivative instruments — — 2,850 — 2,850 Total current liabilities 26,876 118,935 93,408 (14,465 ) 224,754 Long-term debt 1,012,064 — 2,000,579 — 3,012,643 Asset retirement obligations — 10,079 162,989 — 173,068 Long-term derivative instruments — — 1,441 — 1,441 Deferred tax liabilities 22,754 170,979 2,094 — 195,827 Other long-term liabilities 7,195 — — — 7,195 Total liabilities 1,068,889 299,993 2,260,511 (14,465 ) 3,614,928 Equity: Equity 822,827 1,482,450 645,491 (2,127,941 ) 822,827 Noncontrolling interest — — — 645,094 645,094 Total equity 822,827 1,482,450 645,491 (1,482,847 ) 1,467,921 Total liabilities & equity $ 1,891,716 $ 1,782,443 $ 2,906,002 $ (1,497,312 ) $ 5,082,849 As of December 30, 2014 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated (In thousands) ASSETS Current assets: Cash and cash equivalents $ 2,241 $ 3,762 $ 970 $ (1,015 ) $ 5,958 Accounts receivable- trade 5,995 44,952 83,346 (2,717 ) 131,576 Accounts receivable - affiliates 10,047 — 28 (10,075 ) — Short-term derivative instruments 131,471 — 208,585 — 340,056 Prepaid expenses and other current assets 4,178 7,993 11,032 — 23,203 Total current assets 153,932 56,707 303,961 (13,807 ) 500,793 Property and equipment, net 16,601 1,050,722 2,470,333 — 3,537,656 Long-term derivative instruments 123,567 — 311,802 — 435,369 Investments in subsidiaries 1,139,792 — — (1,139,792 ) — Other long-term assets 3,324 260 82,424 — 86,008 Total assets $ 1,437,216 $ 1,107,689 $ 3,168,520 $ (1,153,599 ) $ 4,559,826 LIABILITIES AND EQUITY Current Liabilities: Accounts payable and accrued expenses $ 6,245 $ 56,546 $ 113,177 $ (3,125 ) $ 172,843 Accounts payable - affiliates — 3,638 6,409 (9,423 ) 624 Revenues payable — 27,242 30,110 — 57,352 Short-term derivative instruments — — 3,289 — 3,289 Total current liabilities 6,245 87,426 152,985 (12,548 ) 234,108 Long-term debt 770,545 — 1,574,147 — 2,344,692 Asset retirement obligations — 9,830 112,701 — 122,531 Deferred tax liabilities 69,431 45,122 32,393 — 146,946 Other long-term liabilities 8,585 — — — 8,585 Total liabilities 854,806 142,378 1,872,226 (12,548 ) 2,856,862 Equity: Equity 582,410 965,311 1,290,734 (2,256,045 ) 582,410 Noncontrolling interest — — 5,560 1,114,994 1,120,554 Total equity 582,410 965,311 1,296,294 (1,141,051 ) 1,702,964 Total liabilities & equity $ 1,437,216 $ 1,107,689 $ 3,168,520 $ (1,153,599 ) $ 4,559,826 |
Condensed Consolidating Statements of Operations | December 31, 2015 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated (In thousands) Revenues: Oil & natural gas sales $ — $ 374,042 $ 355,422 $ — $ 729,464 Other income — — 2,725 — 2,725 Total revenues — 374,042 358,147 — 732,189 Costs and expenses: Lease operating — 24,904 168,198 — 193,102 Gathering, processing and transportation — 72,555 34,938 — 107,493 Gathering, processing, and transportation - affiliate — 25,403 — — 25,403 Exploration — 8,969 2,317 — 11,286 Taxes other than income 3,833 11,063 25,828 — 40,724 Depreciation, depletion and amortization 4,191 184,551 195,814 — 384,556 Impairment of proved oil and natural gas properties — — 616,784 — 616,784 Incentive unit compensation expense 35,142 — — — 35,142 General and administrative 43,624 2,664 56,671 — 102,959 Accretion of asset retirement obligations — 418 7,124 — 7,542 (Gain) loss on commodity derivatives (281,250 ) — (462,889 ) — (744,139 ) (Gain) loss on sale of properties — (47 ) (2,998 ) — (3,045 ) Other, net — — (665 ) — (665 ) Total costs and expenses (194,460 ) 330,480 641,122 — 777,142 Operating income (loss) 194,460 43,562 (282,975 ) — (44,953 ) Other income (expense): Interest expense, net (39,308 ) (88 ) (114,732 ) — (154,128 ) Equity earnings from subsidiaries 16,434 — — (16,434 ) — Other, net (100 ) (922 ) 43 — (979 ) Total other income (expense) (22,974 ) (1,010 ) (114,689 ) (16,434 ) (155,107 ) Income before income taxes 171,486 42,552 (397,664 ) (16,434 ) (200,060 ) Income tax benefit (expense) (75,838 ) (24,167 ) 2,175 — (97,830 ) Net income (loss) 95,648 18,385 (395,489 ) (16,434 ) (297,890 ) Net income (loss) attributable to noncontrolling interest — — 386 (393,924 ) (393,538 ) Net income (loss) attributable to Memorial Resource Development Corp. $ 95,648 $ 18,385 $ (395,875 ) $ 377,490 $ 95,648 December 31, 2014 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated (In thousands) Revenues: Oil & natural gas sales $ — $ 409,070 $ 561,677 $ — $ 970,747 Other income 5 7 4,366 — 4,378 Total revenues 5 409,077 566,043 — 975,125 Costs and expenses: Lease operating — 17,570 143,733 — 161,303 Gathering, processing and transportation — 45,956 31,892 — 77,848 Exploration — 13,853 2,750 — 16,603 Taxes other than income — 12,610 33,141 — 45,751 Depreciation, depletion and amortization 1,133 127,105 185,955 — 314,193 Impairment of proved oil and natural gas properties — 24,576 407,540 — 432,116 Incentive unit compensation expense 111,866 831,060 1,023 — 943,949 General and administrative 13,232 25,277 49,164 — 87,673 Accretion of asset retirement obligations — 533 5,773 — 6,306 (Gain) loss on commodity derivatives (277,129 ) 19,395 (492,254 ) — (749,988 ) (Gain) loss on sale of properties — 3,167 (110 ) — 3,057 Other, net — — (12 ) — (12 ) Total costs and expenses (150,898 ) 1,121,102 368,595 — 1,338,799 Operating income (loss) 150,903 (712,025 ) 197,448 — (363,674 ) Other income (expense): Interest expense, net (19,532 ) (30,751 ) (83,550 ) — (133,833 ) Loss on extinguishment of debt (23,562 ) (13,686 ) — — (37,248 ) Equity earnings from subsidiaries (809,017 ) — — 809,017 — Other, net — 319 (656 ) — (337 ) Total other income (expense) (852,111 ) (44,118 ) (84,206 ) 809,017 (171,418 ) Income before income taxes (701,208 ) (756,143 ) 113,242 809,017 (535,092 ) Income tax benefit (expense) (83,373 ) (19,028 ) 1,430 — (100,971 ) Net income (loss) (784,581 ) (775,171 ) 114,672 809,017 (636,063 ) Net income (loss) attributable to noncontrolling interest — — 32 126,756 126,788 Net income (loss) attributable to Memorial Resource Development Corp. $ (784,581 ) $ (775,171 ) $ 114,640 $ 682,261 $ (762,851 ) December 31, 2013 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Combined & Consolidated (In thousands) Revenues: Oil & natural gas sales $ — $ 202,423 $ 408,569 $ — $ 610,992 Other income — — 3,075 — 3,075 Total revenues — 202,423 411,644 — 614,067 Costs and expenses: Lease operating — 14,710 97,088 — 111,798 Gathering, processing and transportation — 17,666 25,055 — 42,721 Exploration — 1,034 1,322 — 2,356 Taxes other than income — 7,869 19,277 — 27,146 Depreciation, depletion and amortization — 61,990 122,727 — 184,717 Impairment of proved oil and natural gas properties — 128 6,472 — 6,600 Incentive unit compensation expense — 14,353 28,926 — 43,279 General and administrative — 31,674 50,405 — 82,079 Accretion of asset retirement obligations — 516 5,065 — 5,581 (Gain) loss on commodity derivatives — (3,179 ) (26,115 ) — (29,294 ) (Gain) loss on sale of properties — 6,776 (92,397 ) — (85,621 ) Other, net — — 649 — 649 Total costs and expenses — 153,537 238,474 — 392,011 Operating income (loss) — 48,886 173,170 — 222,056 Other income (expense): Interest expense, net — (24,895 ) (44,355 ) — (69,250 ) Equity earnings from subsidiaries — 71,222 — (71,222 ) — Other, net — 141 4 — 145 Total other income (expense) — 46,468 (44,351 ) (71,222 ) (69,105 ) Income before income taxes — 95,354 128,819 (71,222 ) 152,951 Income tax benefit (expense) — (164 ) (1,455 ) — (1,619 ) Net income (loss) — 95,190 127,364 (71,222 ) 151,332 Net income (loss) attributable to noncontrolling interest — — 267 49,563 49,830 Net income (loss) attributable to Memorial Resource Development Corp. — 95,190 127,097 (120,785 ) 101,502 |
Condensed Consolidating Statements of Cash Flows | December 31, 2015 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated (In thousands) Net cash provided by (used in) operating activities $ 45,528 $ 372,028 $ 216,750 $ (395 ) $ 633,911 Cash flows from investing activities: Acquisitions of oil and natural gas properties — (291,536 ) (91,160 ) — (382,696 ) Additions to oil and gas properties — (594,902 ) (241,298 ) — (836,200 ) Additions to other property and equipment (3,401 ) (388 ) — — (3,789 ) Additions to restricted investments — — (5,690 ) — (5,690 ) Other financial hybrid instruments (46,106 ) — — — (46,106 ) Deposit for property acquisition — — — — — Investments in subsidiaries (499,336 ) — — 499,336 — Distributions from subsidiaries 78,648 — — (78,648 ) — Proceeds from the sale of oil and gas properties — 13,612 580 — 14,192 Net cash used in investing activities (470,195 ) (873,214 ) (337,568 ) 420,688 (1,260,289 ) Cash flows from financing activities: Advances on revolving credit facility 798,000 — 562,000 — 1,360,000 Payments on revolving credit facility (558,000 ) — (138,000 ) — (696,000 ) Repayment of senior notes — — (2,914 ) — (2,914 ) Deferred finance costs (1,498 ) — (341 ) — (1,839 ) Proceeds from MRD equity offering 242,880 — — — 242,880 Costs incurred in conjunction with MRD equity offering (4,773 ) — — — (4,773 ) Purchase of additional interests in consolidated subsidiaries — — (5,946 ) — (5,946 ) Contribution to MEMP — — 860 — 860 Capital contributions — 497,424 1,912 (499,336 ) — Distributions to MRD — — (78,396 ) 78,396 — Distribution to partners — — (163,259 ) 163,259 — Distribution to noncontrolling interests — — — (163,007 ) (163,007 ) Repurchases of equity (51,197 ) — (55,469 ) — (106,666 ) Net cash provided by financing activities 425,412 497,424 120,447 (420,688 ) 622,595 Net change in cash and cash equivalents 745 (3,762 ) (371 ) (395 ) (3,783 ) Cash and cash equivalents, beginning of period 2,241 3,762 970 (1,015 ) 5,958 Cash and cash equivalents, end of period $ 2,986 $ — $ 599 $ (1,410 ) $ 2,175 December 31, 2014 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Combined & Consolidated (In thousands) Net cash provided by (used in) operating activities $ (72,612 ) $ 297,490 $ 251,393 $ — $ 476,271 Cash flows from investing activities: Acquisitions of oil and natural gas properties — (93,909 ) (1,083,761 ) — (1,177,670 ) Additions to oil and gas properties — (376,123 ) (298,273 ) — (674,396 ) Additions to other property and equipment (15,980 ) (989 ) (98 ) — (17,067 ) Additions to restricted investments — — (3,976 ) — (3,976 ) Investments in subsidiaries (696,489 ) — — 696,489 — Distributions from subsidiaries 15,140 74,424 — (89,564 ) — Change in restricted cash — 49,946 — — 49,946 Deposits for property acquisitions — (215 ) (215 ) Proceeds from the sale of oil and gas properties — — 6,700 — 6,700 Other — — (301 ) — (301 ) Net cash used in investing activities (697,329 ) (346,866 ) (1,379,709 ) 606,925 (1,816,979 ) Cash flows from financing activities: Advances on revolving credit facility 1,174,000 126,800 1,446,000 — 2,746,800 Payments on revolving credit facility (991,000 ) (329,900 ) (1,137,000 ) — (2,457,900 ) Termination of second lien credit facility — (328,282 ) — — (328,282 ) Proceeds from the issuances of senior notes 600,000 — 492,425 — 1,092,425 Redemption of senior notes (351,808 ) — — — (351,808 ) Deferred finance costs (18,779 ) (61 ) (11,494 ) — (30,334 ) Proceeds from MRD initial public offering 408,500 — — — 408,500 Costs incurred in conjunction with initial public offering (28,373 ) — — — (28,373 ) Proceeds from MEMP equity offering — — 553,288 — 553,288 Costs incurred in conjunction with MEMP equity offering — — (12,510 ) — (12,510 ) MRD equity repurchases (161 ) — — — (161 ) MEMP equity repurchases — — (11,531 ) (11,531 ) Restricted MEMP units returned to plan — — (1,012 ) (1,012 ) Capital contributions — 686,623 9,866 (696,489 ) — Contributions from NGP affiliates related to sale of properties — — 1,165 — 1,165 Purchase of additional interests in subsidiaries (3,292 ) — — — (3,292 ) Distribution to equity owners — (15,000 ) (222,633 ) 237,633 — Distribution to NGP affiliates related to purchase of assets — (63,389 ) (3,304 ) — (66,693 ) Distribution to noncontrolling interests — — — (149,084 ) (149,084 ) Distributions to MRD Holdco (17,207 ) (39,520 ) (3,076 ) — (59,803 ) Distribution to NGP affiliates related to sale of assets, net of cash received — (32,770 ) — — (32,770 ) Other 302 18 — — 320 Net cash provided by financing activities 772,182 4,519 1,100,184 (607,940 ) 1,268,945 Net change in cash and cash equivalents 2,241 (44,857 ) (28,132 ) (1,015 ) (71,763 ) Cash and cash equivalents, beginning of period — 48,619 29,102 — 77,721 Cash and cash equivalents, end of period $ 2,241 $ 3,762 $ 970 $ (1,015 ) $ 5,958 December 31, 2013 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Combined & Consolidated (In thousands) Net cash provided by (used in) operating activities $ — $ 93,864 $ 183,959 $ — $ 277,823 Cash flows from investing activities: Acquisitions of oil and natural gas properties — (67,098 ) (38,664 ) — (105,762 ) Additions to oil and gas properties — (164,850 ) (195,165 ) — (360,015 ) Additions to restricted investments — — (5,361 ) — (5,361 ) Additions to other property and equipment — (2,432 ) (238 ) — (2,670 ) Investment in subsidiaries — (93,433 ) — 93,433 — Distribution from subsidiaries — 273,694 — (273,694 ) — Change in restricted cash — (49,347 ) — — (49,347 ) Proceeds from the sale of oil and gas properties — 33,152 122,560 155,712 Net cash used in investing activities — (70,314 ) (116,868 ) (180,261 ) (367,443 ) Cash flows from financing activities: Advances on revolving credit facilities — 174,400 958,355 — 1,132,755 Payments on revolving credit facilities — (200,500 ) (1,565,537 ) — (1,766,037 ) Proceeds from the issuances of senior notes — 343,000 688,563 — 1,031,563 Borrowings under second lien credit facility — 325,000 — — 325,000 Deferred financing costs — (20,250 ) (20,925 ) — (41,175 ) Proceeds from MEMP public offering — — 511,204 — 511,204 Costs incurred in conjunction with MEMP public offering — — (21,066 ) — (21,066 ) Proceeds from changes in ownership interests in MEMP — 135,012 — — 135,012 Purchase of additional interests in subsidiaries — (15,135 ) — — (15,135 ) Capital contributions — — 93,433 (93,433 ) — Contributions from previous owners — — 1,214 — 1,214 Contributions from NGP affiliates related to sale of properties — — 2,013 — 2,013 Distributions to the Funds — (732,362 ) — — (732,362 ) Distribution to equity owners — — (351,777 ) 351,777 — Distributions to noncontrolling interests — — — (78,083 ) (78,083 ) Distribution to NGP affiliates related to purchase of assets — — (355,494 ) — (355,494 ) Distributions made by previous owners — (2,590 ) (1,415 ) — (4,005 ) Cash retained by previous owners — — (7,909 ) — (7,909 ) Other — (129 ) 584 — 455 Net cash provided by financing activities — 6,446 (68,757 ) 180,261 117,950 Net change in cash and cash equivalents — 29,996 (1,666 ) — 28,330 Cash and cash equivalents, beginning of period — 18,623 30,768 — 49,391 Cash and cash equivalents, end of period $ — $ 48,619 $ 29,102 $ — $ 77,721 |
Quarterly Financial Informati44
Quarterly Financial Information (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
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 and 2015, which impacted the comparability between the periods presented below. First Quarter Second Quarter Third Quarter Fourth Quarter For the Year Ended December 31, 2015 (In thousands, except per share amounts) Revenues $ 179,841 $ 176,743 $ 199,737 $ 175,868 Operating income (loss) (28,498 ) (126,790 ) (40,429 ) 150,764 Net income (loss) (112,149 ) (140,473 ) (135,255 ) 89,987 Net income (loss) attributable to noncontrolling interest (158,041 ) (113,771 ) (191,807 ) 70,081 Net income (loss) attributable to Memorial Resource Development Corp. 45,892 (26,702 ) 56,552 19,906 Net income (loss) available to common stockholders 45,615 (26,702 ) 56,051 19,950 Basic earnings per share 0.24 (0.14 ) 0.29 0.10 Diluted earnings per share 0.24 (0.14 ) 0.29 0.10 First Quarter Second Quarter Third Quarter Fourth Quarter For the Year Ended December 31, 2014 (In thousands, except per share amounts) Revenues $ 204,621 $ 254,777 $ 265,296 $ 250,431 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 Development Corp. 8,372 (948,349 ) 9,928 167,198 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 |
Supplemental Oil and Gas Info45
Supplemental Oil and Gas Information (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
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, 2015 2014 2013 (In thousands) MRD Segment: Evaluated oil and natural gas properties $ 1,740,530 $ 1,268,873 $ 897,511 Support equipment and facilities 4,719 — — Unevaluated oil and natural gas properties 414,759 48,229 44,453 Accumulated depletion, depreciation, and amortization (434,735 ) (276,837 ) (160,620 ) Subtotal $ 1,725,273 $ 1,040,265 $ 781,344 MEMP Segment: Evaluated oil and natural gas properties $ 3,616,325 $ 3,329,338 $ 2,077,344 Support equipment and facilities 205,876 198,088 16,030 Unevaluated oil and natural gas properties — — 1,960 Accumulated depletion, depreciation, and amortization (1,878,549 ) (1,060,114 ) (464,812 ) Subtotal $ 1,943,652 $ 2,467,312 $ 1,630,522 Consolidated: Evaluated oil and natural gas properties $ 5,356,855 $ 4,598,211 $ 2,974,855 Support equipment and facilities 210,595 198,088 16,030 Unevaluated oil and natural gas properties 414,759 48,229 46,413 Accumulated depletion, depreciation, and amortization (2,313,284 ) (1,336,951 ) (625,432 ) Total $ 3,668,925 $ 3,507,577 $ 2,411,866 |
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, 2015 2014 2013 (In thousands) MRD Segment: Property acquisition costs, proved $ 8,347 $ 74,490 $ 56,108 Property acquisition costs, unproved 360,353 24,310 19,975 Exploration and extension well costs 28,068 209,532 13,313 Development 492,191 181,026 191,350 Subtotal $ 888,959 $ 489,358 $ 280,746 MEMP Segment: Property acquisition costs, proved $ 77,834 $ 983,076 $ 37,786 Property acquisition costs, unproved 1,887 720 — Exploration and extension well costs 2,078 — — Development 233,241 308,724 166,090 Subtotal $ 315,040 $ 1,292,520 $ 203,876 Consolidated: Property acquisition costs, proved $ 86,181 $ 1,057,566 $ 93,894 Property acquisition costs, unproved 362,240 25,030 19,975 Exploration and extension well costs 30,146 209,532 13,313 Development 725,432 489,750 357,440 Total $ 1,203,999 $ 1,781,878 $ 484,622 |
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: 2015 2014 2013 Oil ($/Bbl) West Texas Intermediate (1) $ 46.79 $ 91.48 $ 93.42 NGL ($/Bbl) West Texas Intermediate (1) $ 46.79 $ 91.48 $ 93.42 Natural Gas ($/Mmbtu) Henry Hub (2) $ 2.59 $ 4.35 $ 3.67 (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 [Member] | |
Reserve Quantity Information | The following tables set forth estimates of the net reserves as of December 31, 2015, 2014, and 2013 respectively: For the Year Ended December 31, 2015 Oil (MBbls) Gas (MMcf) NGLs (MBbls) Equivalent (MMcfe) Proved developed and undeveloped reserves: Beginning of the year 11,915 1,013,340 53,033 1,403,030 Extensions and discoveries 1,111 50,343 2,741 73,456 Purchase of minerals in place 535 17,508 969 26,532 Production (1,331 ) (98,269 ) (3,249 ) (125,749 ) Sales of minerals in place (407 ) (39,272 ) (358 ) (43,861 ) Revision of previous estimates 1,331 30,164 1,024 44,286 End of year 13,154 973,814 54,160 1,377,694 Proved developed reserves: Beginning of year 3,708 355,331 18,203 486,793 End of year 6,101 443,983 24,583 628,081 Proved undeveloped reserves: Beginning of year 8,207 658,009 34,830 916,237 End of year 7,053 529,831 29,577 749,613 For the Year Ended December 31, 2014 Oil (MBbls) Gas (MMcf) NGLs (MBbls) Equivalent (MMcfe) Proved developed and undeveloped reserves: Beginning of the year 10,824 671,485 35,628 950,199 Extensions and discoveries 1,825 183,467 9,876 253,670 Purchase of minerals in place 269 22,186 1,247 31,283 Production (908 ) (56,574 ) (1,863 ) (73,200 ) Sales of minerals in place (623 ) (10,815 ) (950 ) (20,253 ) Revision of previous estimates 528 203,591 9,095 261,331 End of year 11,915 1,013,340 53,033 1,403,030 Proved developed reserves: Beginning of year 3,238 223,362 12,226 316,154 End of year 3,708 355,331 18,203 486,793 Proved undeveloped reserves: Beginning of year 7,586 448,123 23,402 634,045 End of year 8,207 658,009 34,830 916,237 For the Year Ended December 31, 2013 Oil (MBbls) Gas (MMcf) NGLs (MBbls) Equivalent (MMcfe) Proved developed and undeveloped reserves: Beginning of the year 10,220 549,449 31,264 798,357 Extensions and discoveries 1,635 105,289 5,712 149,369 Purchase of minerals in place 211 31,815 1,017 39,183 Production (631 ) (28,729 ) (1,282 ) (40,212 ) Sales of minerals in place (599 ) (14,137 ) (1,573 ) (27,169 ) Revision of previous estimates (12 ) 27,798 490 30,671 End of year (1) 10,824 671,485 35,628 950,199 Proved developed reserves: Beginning of year 2,813 180,523 10,208 258,651 End of year 3,238 223,362 12,226 316,154 Proved undeveloped reserves: Beginning of year 7,407 368,926 21,056 539,706 End of year 7,586 448,123 23,402 634,045 (1) |
Discounted Future Net Cash Flows | The standardized measure of discounted future net cash flows is as follows: For the Year Ended December 31, 2015 2014 2013 (In thousands) Future cash inflows $ 4,008,764 $ 7,314,745 $ 4,942,687 Future production costs (1,438,531 ) (1,020,599 ) (1,343,252 ) Future development costs (784,003 ) (1,209,907 ) (1,137,429 ) Future income tax expense (1) (88,723 ) (1,669,356 ) — Future net cash flows for estimated timing of cash flows 1,697,507 3,414,883 2,462,006 10% annual discount for estimated timing of cash flows (877,647 ) (1,604,728 ) (1,103,145 ) Standardized measure of discounted future net cash flows (2) $ 819,860 $ 1,810,155 $ 1,358,861 ( 1) Our predecessor was a pass through entity and was subject to the Texas margin tax based on the taxable margin apportioned to Texas. However, due to immateriality, we have excluded the impact of this tax for the year ended December 31, 2013. (2) Includes $63,422 attributable to both noncontrolling interests and the MRD Segment previous owners for the year ended December 31, 2013. |
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, 2015: For the Year Ended December 31, 2015 2014 2013 (In thousands) Beginning of year $ 1,810,155 $ 1,358,861 $ 1,138,271 Sale of oil and natural gas produced, net of production costs (240,244 ) (332,785 ) (175,933 ) Purchase of minerals in place 53,597 69,282 51,177 Sale of minerals in place (41,543 ) (47,791 ) (54,091 ) Extensions and discoveries 30,006 653,088 286,796 Changes in income taxes, net 882,942 (995,635 ) — Changes in prices and costs (2,284,279 ) 367,212 (59,083 ) Previously estimated development costs incurred 294,617 205,388 62,012 Net changes in future development costs 190,403 (68,079 ) (1,295 ) Revisions of previous quantities 51,455 713,176 45,183 Accretion of discount 244,123 135,887 110,312 Change in production rates and other (171,372 ) (248,449 ) (44,488 ) End of year $ 819,860 $ 1,810,155 $ 1,358,861 |
MEMP [Member] | |
Reserve Quantity Information | The following tables set forth estimates of the net reserves as of December 31, 2015, 2014, and 2013 respectively: For the Year Ended December 31, 2015 Oil (MBbls) Gas (MMcf) NGLs (MBbls) Equivalent (MMcfe) Proved developed and undeveloped reserves: Beginning of the year 100,258 727,216 59,034 1,682,960 Extensions and discoveries 2,319 8,686 558 25,950 Purchase of minerals in place 10,132 34,128 367 97,122 Production (4,087 ) (50,875 ) (2,820 ) (92,315 ) Sale of minerals in place (380 ) (13,731 ) (758 ) (20,559 ) Revision of previous estimates (17,297 ) (243,898 ) (12,986 ) (425,587 ) End of year (1) 90,945 461,526 43,395 1,267,571 Proved developed reserves: Beginning of year 54,723 417,247 37,260 969,141 End of year 50,817 311,147 30,315 797,936 Proved undeveloped reserves: Beginning of year 45,535 309,969 21,774 713,819 End of year 40,128 150,379 13,080 469,635 (1) MRD Segment’s share of these reserves is 1,268 MMcfe . For the Year Ended December 31, 2014 Oil (MBbls) Gas (MMcf) NGLs (MBbls) Equivalent (MMcfe) Proved developed and undeveloped reserves: Beginning of the year 39,635 737,908 35,794 1,190,484 Extensions and discoveries 849 12,783 711 22,145 Purchase of minerals in place 69,095 13,036 22,351 561,713 Production (3,135 ) (48,721 ) (2,498 ) (82,520 ) Revision of previous estimates (6,186 ) 12,210 2,676 (8,862 ) End of year (1) 100,258 727,216 59,034 1,682,960 Proved developed reserves: Beginning of year 22,429 427,983 17,637 668,381 End of year 54,723 417,247 37,260 969,141 Proved undeveloped reserves: Beginning of year 17,206 309,925 18,157 522,103 End of year 45,535 309,969 21,774 713,819 (1) MRD Segment’s share of these reserves is 230,503 MMcfe. For the Year Ended December 31, 2013 Oil (MBbls) Gas (MMcf) NGLs (MBbls) Equivalent (MMcfe) Proved developed and undeveloped reserves: Beginning of the year 40,822 794,369 39,554 1,276,625 Extensions and discoveries 5,814 85,455 4,353 146,463 Purchase of minerals in place 119 16,294 258 18,554 Production (1,797 ) (41,287 ) (1,806 ) (62,907 ) Revision of previous estimates (5,323 ) (116,923 ) (6,565 ) (188,251 ) End of year (1) 39,635 737,908 35,794 1,190,484 Proved developed reserves: Beginning of year 24,784 441,858 18,060 698,922 End of year 22,429 427,983 17,637 668,381 Proved undeveloped reserves: 16,038 352,511 21,494 577,703 Beginning of year 17,206 309,925 18,157 522,103 End of year (1) MRD Segment’s share of these reserves is 265,216 MMcfe. |
Discounted Future Net Cash Flows | The standardized measure of discounted future net cash flows is as follows: For the Year Ended December 31, 2015 2014 2013 (In thousands) Future cash inflows $ 5,952,935 $ 14,190,450 $ 7,672,312 Future production costs (3,194,577 ) (4,821,051 ) (2,963,146 ) Future development costs (808,512 ) (1,455,926 ) (901,374 ) Future income tax expense (1) — (119,675 ) — Future net cash flows for estimated timing of cash flows 1,949,846 7,793,798 3,807,792 10% annual discount for estimated timing of cash flows (1,360,292 ) (4,881,811 ) (2,089,588 ) Standardized measure of discounted future net cash flows (2) $ 589,554 $ 2,911,987 $ 1,718,204 (1) MEMP is subject to the Texas margin tax based on the taxable margin apportioned to Texas. However, due to immateriality we have excluded the impact of this tax for the years ended December 31, 2015, 2014 and 2013. The taxes in 2014 relate to Classic since its reserves were attributable to a taxable entity for federal income tax purposes for the year ended December 31, 2014. (2) MRD Segment’s share of the standardized measure of discounted future net cash flows was $589, $155,139 and $252,410 for the years ended December 31, 2015, 2014 and 2013, 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, 2015: For the Year Ended December 31, 2015 2014 2013 (In thousands) Beginning of year $ 2,911,987 $ 1,718,204 $ 1,772,240 Sale of oil and natural gas produced, net of production costs (128,382 ) (354,932 ) (255,031 ) Purchase of minerals in place 75,998 1,489,477 23,160 Sale of minerals in place (45,100 ) — — Extensions and discoveries 18,582 44,843 150,631 Changes in income taxes, net 63,180 (63,180 ) — Changes in prices and costs (2,764,481 ) (170,682 ) (26,648 ) Previously estimated development costs incurred 322,446 275,078 199,775 Net changes in future development costs 448,089 (133,098 ) (16,219 ) Revisions of previous quantities (344,775 ) (48,087 ) (373,109 ) Accretion of discount 297,517 171,820 177,223 Change in production rates and other (265,507 ) (17,456 ) 66,182 End of year $ 589,554 $ 2,911,987 $ 1,718,204 |
Organization and Basis of Pre46
Organization and Basis of Presentation - Additional Information (Detail) | Jul. 16, 2014 | Jun. 18, 2014USD ($)$ / sharesshares | Oct. 01, 2013USD ($) | Mar. 28, 2013USD ($) | Feb. 28, 2015USD ($) | May. 31, 2014USD ($) | Jul. 31, 2013USD ($) | Dec. 31, 2015USD ($)Segmentshares | Dec. 31, 2014shares | Dec. 31, 2010USD ($) | Jun. 27, 2014USD ($) | Jun. 15, 2014USD ($) | Dec. 31, 2013shares | Dec. 18, 2013USD ($) |
Consolidation And Basis Of Presentation [Line Items] | ||||||||||||||
Initial public offering | shares | 21,500,000 | |||||||||||||
Common unit price per share | $ / shares | $ 19 | |||||||||||||
Proceeds from initial public offering | $ 380,200,000 | |||||||||||||
Initial public offering completion date | Jun. 18, 2014 | |||||||||||||
Common stock, shares issued | shares | 205,293,743 | 193,435,414 | 0 | |||||||||||
Senior PIK Toggle Notes, Redemption date | Jul. 16, 2014 | |||||||||||||
Number of reportable business segments | Segment | 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 | |||||||||||||
East Texas [Member] | ||||||||||||||
Consolidation And Basis Of Presentation [Line Items] | ||||||||||||||
Business acquisition purchase price | $ 78,400,000 | |||||||||||||
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 | shares | 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 | Jun. 15, 2014 | |||||||||||||
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 | shares | 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 | shares | 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% | |||||||||||||
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% |
Organization and Basis of Pre47
Organization and Basis of Presentation - Schedule of Retrospective Adjustments to Balance Sheet (Detail) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Consolidation And Basis Of Presentation [Line Items] | ||
Prepaid expenses and other current assets | $ 13,017 | $ 23,203 |
Other long-term assets | 10,029 | 8,647 |
Accrued liabilities (Note 2) | 121,799 | 147,071 |
Long-term debt | 3,012,643 | 2,344,692 |
Deferred tax liabilities | 195,827 | 146,946 |
Previously Reported [Member] | ||
Consolidation And Basis Of Presentation [Line Items] | ||
Prepaid expenses and other current assets | 28,027 | |
Other long-term assets | 37,284 | |
Accrued liabilities (Note 2) | 199,000 | |
Deferred tax liabilities | 95,017 | |
Adjustment Effect [Member] | ||
Consolidation And Basis Of Presentation [Line Items] | ||
Prepaid expenses and other current assets | (4,824) | |
Other long-term assets | (28,637) | |
Accrued liabilities (Note 2) | (51,929) | |
Deferred tax liabilities | 51,929 | |
MRD Segment [Member] | ||
Consolidation And Basis Of Presentation [Line Items] | ||
Long-term debt | 1,012,064 | 770,545 |
MRD Segment [Member] | Previously Reported [Member] | ||
Consolidation And Basis Of Presentation [Line Items] | ||
Long-term debt | 783,000 | |
MRD Segment [Member] | Adjustment Effect [Member] | ||
Consolidation And Basis Of Presentation [Line Items] | ||
Long-term debt | (12,455) | |
MEMP [Member] | ||
Consolidation And Basis Of Presentation [Line Items] | ||
Long-term debt | $ 2,000,579 | 1,574,147 |
MEMP [Member] | Previously Reported [Member] | ||
Consolidation And Basis Of Presentation [Line Items] | ||
Long-term debt | 1,595,413 | |
MEMP [Member] | Adjustment Effect [Member] | ||
Consolidation And Basis Of Presentation [Line Items] | ||
Long-term debt | $ (21,266) |
Summary of Significant Accoun48
Summary of Significant Accounting Policies - Additional Information (Detail) - USD ($) | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Summary Of Significant Accounting Policies [Line Items] | |||
Capitalized exploratory drilling costs | $ 0 | $ 0 | $ 0 |
Capitalized in proved oil and natural gas properties | 201,000,000 | 119,000,000 | |
Impairment of proved oil and natural gas properties | 616,784,000 | 432,116,000 | 6,600,000 |
Impairment of unproved properties | 0 | 0 | 0 |
Amortization expense, including write-offs of debt issuance costs | 8,881,000 | 7,436,000 | $ 8,343,000 |
Capitalized interest | $ 7,400,000 | $ 7,300,000 | |
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 Accoun49
Summary of Significant Accounting Policies - Schedule of Oil and Natural Gas Properties (Detail) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Accounting Policies [Abstract] | ||
Proved oil and natural gas properties | $ 5,353,594 | $ 4,598,211 |
Support equipment and facilities | 210,595 | 198,089 |
Unproved oil and natural gas properties | 418,020 | 48,229 |
Total oil and natural gas properties | $ 5,982,209 | $ 4,844,529 |
Summary of Significant Accoun50
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, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
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 | 26.00% | 33.00% | 35.00% |
Consolidated & Combined [Member] | Royal Dutch Shell plc and subsidiaries [Member] | |||
Entity Wide Revenue Major Customer [Line Items] | |||
Individual customers each accounted for 10% or more of total reported revenues | 11.00% | ||
Consolidated & Combined [Member] | 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 | 11.00% | ||
MRD Segment [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 | 56.00% | 85.00% | 86.00% |
MRD Segment [Member] | Plains Marketing, L.P.[Member] | |||
Entity Wide Revenue Major Customer [Line Items] | |||
Individual customers each accounted for 10% or more of total reported revenues | 11.00% | ||
MEMP [Member] | Royal Dutch Shell plc and subsidiaries [Member] | |||
Entity Wide Revenue Major Customer [Line Items] | |||
Individual customers each accounted for 10% or more of total reported revenues | 14.00% | ||
MEMP [Member] | 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 | 18.00% | 11.00% | |
MEMP [Member] | Phillips 66 [Member] | |||
Entity Wide Revenue Major Customer [Line Items] | |||
Individual customers each accounted for 10% or more of total reported revenues | 12.00% | 12.00% | 14.00% |
Summary of Significant Accoun51
Summary of Significant Accounting Policies - Schedule of Accrued Liabilities (Detail) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Accounting Policies [Abstract] | |||
Accrued capital expenditures | $ 48,307 | $ 80,350 | |
Accrued interest payable | 40,849 | 24,797 | |
Accrued lease operating expense | 18,874 | 16,403 | |
Accrued general and administrative expenses | 5,991 | 8,516 | |
Accrued ad valorem taxes | 1,583 | 8,870 | |
Asset retirement obligation - current | 1,175 | 0 | $ 90 |
Other miscellaneous, including operator advances | 5,020 | 8,135 | |
Accrued liabilities | $ 121,799 | $ 147,071 |
Summary of Significant Accoun52
Summary of Significant Accounting Policies - Schedule of Supplemental Cash flow (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Supplemental cash flows: | |||
Cash paid for interest, net of capitalized interest | $ 126,087 | $ 130,732 | $ 61,140 |
Cash paid for taxes | 8,632 | 838 | 168 |
Noncash investing and financing activities: | |||
Increase (decrease) in capital expenditures in payables and accrued liabilities | (32,043) | 31,771 | 41,017 |
(Increase) decrease in accounts receivable related to acquisitions and divestitures | 10,550 | (6,706) | (4,301) |
Assumptions of asset retirement obligations related to properties acquired or drilled | 25,896 | 5,420 | 4,227 |
Repurchase of equity under repurchase program | 0 | 3,425 | 0 |
Natural Gas Partners [Member] | |||
Noncash investing and financing activities: | |||
Accrued distribution to NGP affiliates related to Cinco Group acquisitions | $ 0 | $ 0 | $ 4,352 |
Acquisitions and Divestitures -
Acquisitions and Divestitures - Transaction Related Costs (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Business Acquisition [Line Items] | |||
Acquisition related costs | $ 3,902 | $ 6,668 | $ 8,313 |
General and administrative expense [Member] | |||
Business Acquisition [Line Items] | |||
Acquisition related costs | $ 3,902 | $ 6,668 | $ 8,313 |
Acquisitions and Divestitures54
Acquisitions and Divestitures - Additional Information (Detail) - USD ($) $ in Thousands | Nov. 03, 2015 | Oct. 22, 2015 | Jun. 01, 2015 | Apr. 17, 2015 | Dec. 30, 2014 | Jul. 01, 2014 | May. 09, 2014 | Mar. 25, 2014 | May. 10, 2013 | Apr. 30, 2013 | Jan. 01, 2013 | Dec. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Business Acquisition And Divestiture [Line Items] | |||||||||||||||
Purchase price to unproved oil and natural gas properties | $ 362,240 | $ 25,030 | $ 19,975 | ||||||||||||
Purchase of noncontrolling interest | 5,946 | 3,292 | 15,135 | ||||||||||||
Proceeds from the sale of oil and natural gas properties | 14,192 | 6,700 | 155,712 | ||||||||||||
Terryville Acquisition [Member] | |||||||||||||||
Business Acquisition And Divestiture [Line Items] | |||||||||||||||
Payments to acquire oil and gas properties and leases | $ 71,900 | $ 24,000 | |||||||||||||
Wyoming Acquisition [Member] | |||||||||||||||
Business Acquisition And Divestiture [Line Items] | |||||||||||||||
Payments to acquire oil and gas properties and leases | $ 906,100 | ||||||||||||||
Business acquisition, revenues | 72,800 | ||||||||||||||
Business acquisition, earnings | $ 22,900 | ||||||||||||||
Eagle Ford Acquisition [Member] | |||||||||||||||
Business Acquisition And Divestiture [Line Items] | |||||||||||||||
Payments to acquire oil and gas properties and leases | $ 168,100 | ||||||||||||||
Business acquisition, revenues | 36,600 | ||||||||||||||
Business acquisition, earnings | $ 16,300 | ||||||||||||||
Percentage of working interests owned | 30.00% | ||||||||||||||
East Texas Acquisition and Rockies Acquisition [Member] | |||||||||||||||
Business Acquisition And Divestiture [Line Items] | |||||||||||||||
Payments to acquire oil and gas properties and leases | 29,400 | ||||||||||||||
Propel Energy [Member] | |||||||||||||||
Business Acquisition And Divestiture [Line Items] | |||||||||||||||
Payments to acquire oil and gas properties and leases | 9,300 | ||||||||||||||
Black Diamond [Member] | |||||||||||||||
Business Acquisition And Divestiture [Line Items] | |||||||||||||||
Proceeds from divestitures | $ 33,000 | ||||||||||||||
Gain (loss) on sale of oil and gas properties | (6,800) | ||||||||||||||
Net book value of oil and gas properties | $ 39,800 | ||||||||||||||
BlueStone Natural Resources Holdings, LLC [Member] | |||||||||||||||
Business Acquisition And Divestiture [Line Items] | |||||||||||||||
Gain (loss) on sale of oil and gas properties | 89,500 | ||||||||||||||
Proceeds from the sale of oil and natural gas properties | 117,900 | ||||||||||||||
Natural Gas Pipe Lines [Member] | Tanos [Member] | |||||||||||||||
Business Acquisition And Divestiture [Line Items] | |||||||||||||||
Gain (loss) on sale of oil and gas properties | $ 1,400 | ||||||||||||||
Period for drilling any new wells | 3 years | ||||||||||||||
Contingent consideration related to sale of natural gas pipeline | $ 400 | ||||||||||||||
Natural Gas Pipe Lines [Member] | Tanos [Member] | Minimum [Member] | |||||||||||||||
Business Acquisition And Divestiture [Line Items] | |||||||||||||||
Proceeds from divestitures | 1,500 | ||||||||||||||
Natural Gas Pipe Lines [Member] | Tanos [Member] | Maximum [Member] | |||||||||||||||
Business Acquisition And Divestiture [Line Items] | |||||||||||||||
Proceeds from divestitures | $ 2,000 | ||||||||||||||
Oil And Natural Gas Properties [Member] | Tanos [Member] | |||||||||||||||
Business Acquisition And Divestiture [Line Items] | |||||||||||||||
Proceeds from divestitures | 2,900 | ||||||||||||||
Non Operated Oil And Natural Gas Properties [Member] | Tanos [Member] | |||||||||||||||
Business Acquisition And Divestiture [Line Items] | |||||||||||||||
Gain (loss) on sale of oil and gas properties | $ 1,400 | ||||||||||||||
Related Party Transaction One [Member] | Permian Basin Properties [Member] | |||||||||||||||
Business Acquisition And Divestiture [Line Items] | |||||||||||||||
Proceeds from divestitures | 600 | ||||||||||||||
Related Party Transaction Two [Member] | Permian Basin Properties [Member] | |||||||||||||||
Business Acquisition And Divestiture [Line Items] | |||||||||||||||
Proceeds from divestitures | $ 900 | ||||||||||||||
WildHorse Resources, LLC [Member] | |||||||||||||||
Business Acquisition And Divestiture [Line Items] | |||||||||||||||
Payments to acquire oil and gas properties and leases | $ 67,100 | ||||||||||||||
Rockies Divestiture [Member] | |||||||||||||||
Business Acquisition And Divestiture [Line Items] | |||||||||||||||
Proceeds from divestitures | $ 13,600 | ||||||||||||||
Gain (loss) on sale of oil and gas properties | $ (100) | ||||||||||||||
SPBPC [Member] | |||||||||||||||
Business Acquisition And Divestiture [Line Items] | |||||||||||||||
Purchase of noncontrolling interest | $ 6,000 | ||||||||||||||
North Louisiana [Member] | |||||||||||||||
Business Acquisition And Divestiture [Line Items] | |||||||||||||||
Payments to acquire oil and gas properties and leases | $ 284,300 | $ 4,000 | |||||||||||||
Purchase price to unproved oil and natural gas properties | $ 281,900 | ||||||||||||||
C A | Beta Properties [Member] | |||||||||||||||
Business Acquisition And Divestiture [Line Items] | |||||||||||||||
Payments to acquire oil and gas properties and leases | $ 94,600 | ||||||||||||||
Northern Oklahoma [Member] | |||||||||||||||
Business Acquisition And Divestiture [Line Items] | |||||||||||||||
Proceeds from divestitures | $ 7,600 | ||||||||||||||
Gain (loss) on sale of oil and gas properties | $ (3,200) |
Acquisitions and Divestitures55
Acquisitions and Divestitures - Summary of Fair Value Assessment of Assets Acquired and Liabilities Assumed (Detail) - USD ($) $ in Thousands | Dec. 31, 2015 | Nov. 03, 2015 | Dec. 30, 2014 | Jul. 01, 2014 | Mar. 25, 2014 | Sep. 06, 2013 | Aug. 30, 2013 | Apr. 30, 2013 |
Business Acquisition [Line Items] | ||||||||
Restricted investments | $ 3,200 | |||||||
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 | |||||||
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 | |||||||
Beta Properties [Member] | ||||||||
Business Acquisition [Line Items] | ||||||||
Oil and gas properties | $ 40,029 | |||||||
Prepaid expenses and other current assets | 840 | |||||||
Restricted investments | 69,579 | |||||||
Derivative instruments | 4,568 | |||||||
Accounts receivable - affiliates and other | 4,499 | |||||||
Asset retirement obligations | (22,871) | |||||||
Accrued liabilities | (2,010) | |||||||
Total identifiable net assets | $ 94,634 |
Acquisitions and Divestitures56
Acquisitions and Divestitures - Unaudited Pro Forma Results of Operations (Detail) - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | |
Dec. 31, 2014 | Dec. 31, 2013 | |
Business Combinations [Abstract] | ||
Revenues | $ 1,066,324 | $ 800,487 |
Net income (loss) | $ (602,044) | $ 257,839 |
Basic and diluted earnings per share | $ (4.08) |
Fair Value Measurements of Fi57
Fair Value Measurements of Financial Instruments - Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) - Fair Value, Measurements [Member] - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Assets: | ||
Fair value of derivative asset | $ 1,136,757 | $ 847,064 |
Liabilities: | ||
Fair value of derivative liability | 87,636 | 74,928 |
Significant Other Observable Inputs (Level 2) [Member] | ||
Assets: | ||
Fair value of derivative asset | 1,136,757 | 847,064 |
Liabilities: | ||
Fair value of derivative liability | 87,636 | 74,928 |
Commodity derivatives [Member] | ||
Assets: | ||
Fair value of derivative asset | 1,136,757 | 845,759 |
Liabilities: | ||
Fair value of derivative liability | 84,981 | 71,639 |
Commodity derivatives [Member] | Significant Other Observable Inputs (Level 2) [Member] | ||
Assets: | ||
Fair value of derivative asset | 1,136,757 | 845,759 |
Liabilities: | ||
Fair value of derivative liability | 84,981 | 71,639 |
Interest rate derivatives [Member] | ||
Assets: | ||
Fair value of derivative asset | 1,305 | |
Liabilities: | ||
Fair value of derivative liability | 2,655 | 3,289 |
Interest rate derivatives [Member] | Significant Other Observable Inputs (Level 2) [Member] | ||
Assets: | ||
Fair value of derivative asset | 1,305 | |
Liabilities: | ||
Fair value of derivative liability | $ 2,655 | $ 3,289 |
Fair Value Measurements of Fi58
Fair Value Measurements of Financial Instruments - Additional Information (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||
Impairment of proved oil and natural gas properties | $ 616,784 | $ 432,116 | $ 6,600 |
Carrying value of properties after impairment charges | 3,691,384 | 3,537,656 | |
MRD [Member] | |||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||
Impairment of proved oil and natural gas properties | 0 | 24,600 | |
MEMP [Member] | |||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||
Impairment of proved oil and natural gas properties | 616,800 | 407,500 | |
Carrying value of properties after impairment charges | $ 408,600 | ||
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 | ||
Carrying value of properties after impairment charges | 88,700 | ||
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 | ||
Carrying value of properties after impairment charges | 88,800 | ||
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 | ||
Carrying value of properties after impairment charges | $ 71,200 |
Risk Management and Derivativ59
Risk Management and Derivative and Other Financial Instruments - Additional Information (Detail) - USD ($) | 1 Months Ended | 12 Months Ended | |
Nov. 30, 2015 | Dec. 31, 2015 | 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 | $ 196,300,000 | ||
Effect netting arrangements, counterparty exposure | 169,100,000 | ||
Derivative asset | 365,400,000 | ||
Deferred premiums | 8,000,000 | ||
Cash settlement receipt | $ 16,400,000 | 6,100,000 | |
Other financial assets | 46,106,000 | ||
Derivative, Cost of Hedge | 4,600,000 | ||
Cash collateral received or pledged | 0 | ||
Crude Oil Derivative Contracts [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Cash settlement receipt | 4,400,000 | ||
Interest rate swaps [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Aggregate termination amount paid to counterparties | $ 700,000 | ||
MRD Segment [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Cash settlement receipt | 92,300,000 | ||
Single Counterparty [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Effect netting arrangements, counterparty exposure | 123,400,000 | ||
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 | 350,000,000 | ||
Effect netting arrangements, counterparty exposure | 380,900,000 | ||
Derivative asset | 729,800,000 | ||
Cash settlement receipt | 27,100,000 | ||
MRD [Member] | Single Counterparty [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Effect netting arrangements, counterparty exposure | $ 86,800,000 |
Risk Management and Derivativ60
Risk Management and Derivative and Other Financial Instruments - Schedule of Open Commodity Positions Excluding Embedded Derivatives (Detail) - MRD Segment [Member] MMBTU in Thousands | 12 Months Ended |
Dec. 31, 2015MMBTU$ / MMBTUbbl | |
Natural Gas Derivative Contracts [Member] | 2016 [Member] | Fixed price swap contracts [Member] | |
Derivative [Line Items] | |
Average Monthly Volume (MMBtu) | MMBTU | 2,570 |
Weighted-average fixed price | 4.09 |
Natural Gas Derivative Contracts [Member] | 2016 [Member] | Collar contracts [Member] | |
Derivative [Line Items] | |
Average Monthly Volume (MMBtu) | MMBTU | 1,100 |
Weighted-average floor price | 4 |
Weighted-average ceiling price | 4.71 |
Natural Gas Derivative Contracts [Member] | 2016 [Member] | Put Option [Member] | Purchased [Member] | |
Derivative [Line Items] | |
Average Monthly Volume (MMBtu) | MMBTU | 6,000 |
Weighted-average strike price | 3.51 |
Weighted-average deferred premium paid | (0.34) |
Natural Gas Derivative Contracts [Member] | 2016 [Member] | TGT Z1 basis swaps [Member] | |
Derivative [Line Items] | |
Average Monthly Volume (MMBtu) | MMBTU | 1,120 |
Natural Gas Derivative Contracts [Member] | 2016 [Member] | TGT Z1 basis swaps [Member] | Henry Hub [Member] | |
Derivative [Line Items] | |
Spread | (0.10) |
Natural Gas Derivative Contracts [Member] | 2017 [Member] | Fixed price swap contracts [Member] | |
Derivative [Line Items] | |
Average Monthly Volume (MMBtu) | MMBTU | 1,770 |
Weighted-average fixed price | 4.24 |
Natural Gas Derivative Contracts [Member] | 2017 [Member] | Collar contracts [Member] | |
Derivative [Line Items] | |
Average Monthly Volume (MMBtu) | MMBTU | 1,050 |
Weighted-average floor price | 4 |
Weighted-average ceiling price | 5.06 |
Natural Gas Derivative Contracts [Member] | 2017 [Member] | Put Option [Member] | Purchased [Member] | |
Derivative [Line Items] | |
Average Monthly Volume (MMBtu) | MMBTU | 5,350 |
Weighted-average strike price | 3.48 |
Weighted-average deferred premium paid | (0.32) |
Natural Gas Derivative Contracts [Member] | 2017 [Member] | TGT Z1 basis swaps [Member] | |
Derivative [Line Items] | |
Average Monthly Volume (MMBtu) | MMBTU | 200 |
Natural Gas Derivative Contracts [Member] | 2017 [Member] | TGT Z1 basis swaps [Member] | Henry Hub [Member] | |
Derivative [Line Items] | |
Spread | (0.08) |
Crude Oil Derivative Contracts [Member] | 2016 [Member] | Fixed price swap contracts [Member] | |
Derivative [Line Items] | |
Weighted-average fixed price | 83.58 |
Average Monthly Volume (Bbls) | bbl | 35,583 |
Crude Oil Derivative Contracts [Member] | 2016 [Member] | Collar contracts [Member] | |
Derivative [Line Items] | |
Weighted-average floor price | 80 |
Weighted-average ceiling price | 99.70 |
Average Monthly Volume (Bbls) | bbl | 27,000 |
Crude Oil Derivative Contracts [Member] | 2017 [Member] | Fixed price swap contracts [Member] | |
Derivative [Line Items] | |
Weighted-average fixed price | 84.70 |
Average Monthly Volume (Bbls) | bbl | 28,000 |
Crude Oil Derivative Contracts [Member] | 2017 [Member] | Collar contracts [Member] | |
Derivative [Line Items] | |
Weighted-average floor price | 0 |
Weighted-average ceiling price | 0 |
Average Monthly Volume (Bbls) | bbl | 0 |
NGL Derivative Contracts [Member] | 2016 [Member] | Fixed price swap contracts [Member] | |
Derivative [Line Items] | |
Weighted-average fixed price | 39.68 |
Average Monthly Volume (Bbls) | bbl | 353,399 |
NGL Derivative Contracts [Member] | 2017 [Member] | Fixed price swap contracts [Member] | |
Derivative [Line Items] | |
Weighted-average fixed price | 0 |
Average Monthly Volume (Bbls) | bbl | 0 |
Risk Management and Derivativ61
Risk Management and Derivative and Other Financial Instruments - Schedule of Open Embedded Derivative Positions (Detail) - 2016 [Member] - MRD Segment [Member] - Fixed price swap contracts [Member] | 12 Months Ended |
Dec. 31, 2015$ / bblbbl | |
Oil Hybrid Contracts [Member] | |
Derivative [Line Items] | |
Average Monthly Volume (Bbls) | bbl | 27,080 |
Weighted-average fixed price | 46.51 |
Initial net investment price | 62.16 |
Total contract swap price | 108.67 |
NGL Hybrid Contracts [Member] | |
Derivative [Line Items] | |
Average Monthly Volume (Bbls) | bbl | 83,101 |
Weighted-average fixed price | 15.84 |
Initial net investment price | 25.98 |
Total contract swap price | 41.82 |
Risk Management and Derivativ62
Risk Management and Derivative and Other Financial Instruments - Schedule of Open Commodity Positions (Detail) - MEMP [Member] | 12 Months Ended |
Dec. 31, 2015MMBTU$ / MMBTU$ / bblbbl | |
2016 [Member] | Natural Gas Derivative Contracts [Member] | Fixed price swap contracts [Member] | |
Derivative [Line Items] | |
Average Monthly Volume (MMBtu) | MMBTU | 3,592,442 |
Weighted-average fixed price | $ / MMBTU | 4.14 |
2016 [Member] | Natural Gas Derivative Contracts [Member] | Basis Swaps [Member] | |
Derivative [Line Items] | |
Average Monthly Volume (MMBtu) | MMBTU | 3,578,333 |
Spread | $ / MMBTU | (0.07) |
2016 [Member] | Crude Oil Derivative Contracts [Member] | Fixed price swap contracts [Member] | |
Derivative [Line Items] | |
Weighted-average fixed price | $ / bbl | 85.48 |
Average Monthly Volume (Bbls) | bbl | 304,813 |
2016 [Member] | Crude Oil Derivative Contracts [Member] | Basis Swaps [Member] | |
Derivative [Line Items] | |
Spread | $ / bbl | (10.02) |
Average Monthly Volume (Bbls) | bbl | 140,000 |
2016 [Member] | NGL Derivative Contracts [Member] | Fixed price swap contracts [Member] | |
Derivative [Line Items] | |
Weighted-average fixed price | $ / bbl | 35.64 |
Average Monthly Volume (Bbls) | bbl | 213,100 |
2017 [Member] | Natural Gas Derivative Contracts [Member] | Fixed price swap contracts [Member] | |
Derivative [Line Items] | |
Average Monthly Volume (MMBtu) | MMBTU | 3,350,067 |
Weighted-average fixed price | $ / MMBTU | 4.06 |
2017 [Member] | Natural Gas Derivative Contracts [Member] | Basis Swaps [Member] | |
Derivative [Line Items] | |
Average Monthly Volume (MMBtu) | MMBTU | 2,210,000 |
Spread | $ / MMBTU | (0.04) |
2017 [Member] | Crude Oil Derivative Contracts [Member] | Fixed price swap contracts [Member] | |
Derivative [Line Items] | |
Weighted-average fixed price | $ / bbl | 85 |
Average Monthly Volume (Bbls) | bbl | 301,600 |
2017 [Member] | Crude Oil Derivative Contracts [Member] | Basis Swaps [Member] | |
Derivative [Line Items] | |
Spread | $ / bbl | (7.82) |
Average Monthly Volume (Bbls) | bbl | 67,500 |
2017 [Member] | NGL Derivative Contracts [Member] | Fixed price swap contracts [Member] | |
Derivative [Line Items] | |
Weighted-average fixed price | $ / bbl | 37.55 |
Average Monthly Volume (Bbls) | bbl | 43,300 |
2018 [Member] | Natural Gas Derivative Contracts [Member] | Fixed price swap contracts [Member] | |
Derivative [Line Items] | |
Average Monthly Volume (MMBtu) | MMBTU | 3,060,000 |
Weighted-average fixed price | $ / MMBTU | 4.18 |
2018 [Member] | Natural Gas Derivative Contracts [Member] | Basis Swaps [Member] | |
Derivative [Line Items] | |
Average Monthly Volume (MMBtu) | MMBTU | 1,315,000 |
Spread | $ / MMBTU | (0.02) |
2018 [Member] | Crude Oil Derivative Contracts [Member] | Fixed price swap contracts [Member] | |
Derivative [Line Items] | |
Weighted-average fixed price | $ / bbl | 83.74 |
Average Monthly Volume (Bbls) | bbl | 312,000 |
2018 [Member] | Crude Oil Derivative Contracts [Member] | Basis Swaps [Member] | |
Derivative [Line Items] | |
Spread | $ / bbl | 0 |
Average Monthly Volume (Bbls) | bbl | 0 |
2018 [Member] | NGL Derivative Contracts [Member] | Fixed price swap contracts [Member] | |
Derivative [Line Items] | |
Weighted-average fixed price | $ / bbl | 0 |
Average Monthly Volume (Bbls) | bbl | 0 |
2019 [Member] | Natural Gas Derivative Contracts [Member] | Fixed price swap contracts [Member] | |
Derivative [Line Items] | |
Average Monthly Volume (MMBtu) | MMBTU | 2,814,583 |
Weighted-average fixed price | $ / MMBTU | 4.31 |
2019 [Member] | Natural Gas Derivative Contracts [Member] | Basis Swaps [Member] | |
Derivative [Line Items] | |
Average Monthly Volume (MMBtu) | MMBTU | 900,000 |
Spread | $ / MMBTU | 0.01 |
2019 [Member] | Crude Oil Derivative Contracts [Member] | Fixed price swap contracts [Member] | |
Derivative [Line Items] | |
Weighted-average fixed price | $ / bbl | 85.52 |
Average Monthly Volume (Bbls) | bbl | 160,000 |
2019 [Member] | Crude Oil Derivative Contracts [Member] | Basis Swaps [Member] | |
Derivative [Line Items] | |
Spread | $ / bbl | 0 |
Average Monthly Volume (Bbls) | bbl | 0 |
2019 [Member] | NGL Derivative Contracts [Member] | Fixed price swap contracts [Member] | |
Derivative [Line Items] | |
Weighted-average fixed price | $ / bbl | 0 |
Average Monthly Volume (Bbls) | bbl | 0 |
Risk Management and Derivativ63
Risk Management and Derivative and Other Financial Instruments - Schedule of Swaps on Disaggregated Basis (Detail) - MEMP [Member] | 12 Months Ended |
Dec. 31, 2015MMBTU$ / MMBTU$ / bblbbl | |
2016 [Member] | Natural Gas Derivative Contracts [Member] | NGPL TexOk basis swaps [Member] | |
Derivative [Line Items] | |
Average Monthly Volume (MMBtu) | MMBTU | 3,003,333 |
2016 [Member] | Natural Gas Derivative Contracts [Member] | NGPL TexOk basis swaps [Member] | Henry Hub [Member] | |
Derivative [Line Items] | |
Spread | $ / MMBTU | (0.07) |
2016 [Member] | Natural Gas Derivative Contracts [Member] | HSC basis swaps [Member] | |
Derivative [Line Items] | |
Average Monthly Volume (MMBtu) | MMBTU | 135,000 |
2016 [Member] | Natural Gas Derivative Contracts [Member] | HSC basis swaps [Member] | Henry Hub [Member] | |
Derivative [Line Items] | |
Spread | $ / MMBTU | 0.07 |
2016 [Member] | Natural Gas Derivative Contracts [Member] | CIG basis swaps [Member] | |
Derivative [Line Items] | |
Average Monthly Volume (MMBtu) | MMBTU | 170,000 |
2016 [Member] | Natural Gas Derivative Contracts [Member] | CIG basis swaps [Member] | Henry Hub [Member] | |
Derivative [Line Items] | |
Spread | $ / MMBTU | (0.30) |
2016 [Member] | Natural Gas Derivative Contracts [Member] | TETCO STX basis swaps [Member] | |
Derivative [Line Items] | |
Average Monthly Volume (MMBtu) | MMBTU | 270,000 |
2016 [Member] | Natural Gas Derivative Contracts [Member] | TETCO STX basis swaps [Member] | Henry Hub [Member] | |
Derivative [Line Items] | |
Spread | $ / MMBTU | 0.06 |
2016 [Member] | Crude Oil Derivative Contracts [Member] | Midway-Sunset basis swaps [Member] | |
Derivative [Line Items] | |
Average Monthly Volume (Bbls) | bbl | 100,000 |
2016 [Member] | Crude Oil Derivative Contracts [Member] | Midway-Sunset basis swaps [Member] | Brent [Member] | |
Derivative [Line Items] | |
Spread | $ / bbl | (12.29) |
2016 [Member] | Crude Oil Derivative Contracts [Member] | Midland Basis Swap [Member] | |
Derivative [Line Items] | |
Average Monthly Volume (Bbls) | bbl | 40,000 |
2016 [Member] | Crude Oil Derivative Contracts [Member] | Midland Basis Swap [Member] | WTI [Member] | |
Derivative [Line Items] | |
Spread | $ / bbl | (4.34) |
2017 [Member] | Natural Gas Derivative Contracts [Member] | NGPL TexOk basis swaps [Member] | |
Derivative [Line Items] | |
Average Monthly Volume (MMBtu) | MMBTU | 1,800,000 |
2017 [Member] | Natural Gas Derivative Contracts [Member] | NGPL TexOk basis swaps [Member] | Henry Hub [Member] | |
Derivative [Line Items] | |
Spread | $ / MMBTU | (0.07) |
2017 [Member] | Natural Gas Derivative Contracts [Member] | HSC basis swaps [Member] | |
Derivative [Line Items] | |
Average Monthly Volume (MMBtu) | MMBTU | 115,000 |
2017 [Member] | Natural Gas Derivative Contracts [Member] | HSC basis swaps [Member] | Henry Hub [Member] | |
Derivative [Line Items] | |
Spread | $ / MMBTU | 0.14 |
2017 [Member] | Natural Gas Derivative Contracts [Member] | CIG basis swaps [Member] | |
Derivative [Line Items] | |
Average Monthly Volume (MMBtu) | MMBTU | 0 |
2017 [Member] | Natural Gas Derivative Contracts [Member] | CIG basis swaps [Member] | Henry Hub [Member] | |
Derivative [Line Items] | |
Spread | $ / MMBTU | 0 |
2017 [Member] | Natural Gas Derivative Contracts [Member] | TETCO STX basis swaps [Member] | |
Derivative [Line Items] | |
Average Monthly Volume (MMBtu) | MMBTU | 295,000 |
2017 [Member] | Natural Gas Derivative Contracts [Member] | TETCO STX basis swaps [Member] | Henry Hub [Member] | |
Derivative [Line Items] | |
Spread | $ / MMBTU | 0.03 |
2017 [Member] | Crude Oil Derivative Contracts [Member] | Midway-Sunset basis swaps [Member] | |
Derivative [Line Items] | |
Average Monthly Volume (Bbls) | bbl | 37,500 |
2017 [Member] | Crude Oil Derivative Contracts [Member] | Midway-Sunset basis swaps [Member] | Brent [Member] | |
Derivative [Line Items] | |
Spread | $ / bbl | (12.20) |
2017 [Member] | Crude Oil Derivative Contracts [Member] | Midland Basis Swap [Member] | |
Derivative [Line Items] | |
Average Monthly Volume (Bbls) | bbl | 30,000 |
2017 [Member] | Crude Oil Derivative Contracts [Member] | Midland Basis Swap [Member] | WTI [Member] | |
Derivative [Line Items] | |
Spread | $ / bbl | (2.35) |
2018 [Member] | Natural Gas Derivative Contracts [Member] | NGPL TexOk basis swaps [Member] | |
Derivative [Line Items] | |
Average Monthly Volume (MMBtu) | MMBTU | 1,200,000 |
2018 [Member] | Natural Gas Derivative Contracts [Member] | NGPL TexOk basis swaps [Member] | Henry Hub [Member] | |
Derivative [Line Items] | |
Spread | $ / MMBTU | (0.03) |
2018 [Member] | Natural Gas Derivative Contracts [Member] | HSC basis swaps [Member] | |
Derivative [Line Items] | |
Average Monthly Volume (MMBtu) | MMBTU | 115,000 |
2018 [Member] | Natural Gas Derivative Contracts [Member] | HSC basis swaps [Member] | Henry Hub [Member] | |
Derivative [Line Items] | |
Spread | $ / MMBTU | 0.15 |
2018 [Member] | Natural Gas Derivative Contracts [Member] | CIG basis swaps [Member] | |
Derivative [Line Items] | |
Average Monthly Volume (MMBtu) | MMBTU | 0 |
2018 [Member] | Natural Gas Derivative Contracts [Member] | CIG basis swaps [Member] | Henry Hub [Member] | |
Derivative [Line Items] | |
Spread | $ / MMBTU | 0 |
2018 [Member] | Natural Gas Derivative Contracts [Member] | TETCO STX basis swaps [Member] | |
Derivative [Line Items] | |
Average Monthly Volume (MMBtu) | MMBTU | 0 |
2018 [Member] | Natural Gas Derivative Contracts [Member] | TETCO STX basis swaps [Member] | Henry Hub [Member] | |
Derivative [Line Items] | |
Spread | $ / MMBTU | 0 |
2018 [Member] | Crude Oil Derivative Contracts [Member] | Midway-Sunset basis swaps [Member] | |
Derivative [Line Items] | |
Average Monthly Volume (Bbls) | bbl | 0 |
2018 [Member] | Crude Oil Derivative Contracts [Member] | Midway-Sunset basis swaps [Member] | Brent [Member] | |
Derivative [Line Items] | |
Spread | $ / bbl | 0 |
2018 [Member] | Crude Oil Derivative Contracts [Member] | Midland Basis Swap [Member] | |
Derivative [Line Items] | |
Average Monthly Volume (Bbls) | bbl | 0 |
2018 [Member] | Crude Oil Derivative Contracts [Member] | Midland Basis Swap [Member] | WTI [Member] | |
Derivative [Line Items] | |
Spread | $ / bbl | 0 |
2019 [Member] | Natural Gas Derivative Contracts [Member] | NGPL TexOk basis swaps [Member] | |
Derivative [Line Items] | |
Average Monthly Volume (MMBtu) | MMBTU | 900,000 |
2019 [Member] | Natural Gas Derivative Contracts [Member] | NGPL TexOk basis swaps [Member] | Henry Hub [Member] | |
Derivative [Line Items] | |
Spread | $ / MMBTU | 0.01 |
2019 [Member] | Natural Gas Derivative Contracts [Member] | HSC basis swaps [Member] | |
Derivative [Line Items] | |
Average Monthly Volume (MMBtu) | MMBTU | 0 |
2019 [Member] | Natural Gas Derivative Contracts [Member] | HSC basis swaps [Member] | Henry Hub [Member] | |
Derivative [Line Items] | |
Spread | $ / MMBTU | 0 |
2019 [Member] | Natural Gas Derivative Contracts [Member] | CIG basis swaps [Member] | |
Derivative [Line Items] | |
Average Monthly Volume (MMBtu) | MMBTU | 0 |
2019 [Member] | Natural Gas Derivative Contracts [Member] | CIG basis swaps [Member] | Henry Hub [Member] | |
Derivative [Line Items] | |
Spread | $ / MMBTU | 0 |
2019 [Member] | Natural Gas Derivative Contracts [Member] | TETCO STX basis swaps [Member] | |
Derivative [Line Items] | |
Average Monthly Volume (MMBtu) | MMBTU | 0 |
2019 [Member] | Natural Gas Derivative Contracts [Member] | TETCO STX basis swaps [Member] | Henry Hub [Member] | |
Derivative [Line Items] | |
Spread | $ / MMBTU | 0 |
2019 [Member] | Crude Oil Derivative Contracts [Member] | Midway-Sunset basis swaps [Member] | |
Derivative [Line Items] | |
Average Monthly Volume (Bbls) | bbl | 0 |
2019 [Member] | Crude Oil Derivative Contracts [Member] | Midway-Sunset basis swaps [Member] | Brent [Member] | |
Derivative [Line Items] | |
Spread | $ / bbl | 0 |
2019 [Member] | Crude Oil Derivative Contracts [Member] | Midland Basis Swap [Member] | |
Derivative [Line Items] | |
Average Monthly Volume (Bbls) | bbl | 0 |
2019 [Member] | Crude Oil Derivative Contracts [Member] | Midland Basis Swap [Member] | WTI [Member] | |
Derivative [Line Items] | |
Spread | $ / bbl | 0 |
Risk Management and Derivativ64
Risk Management and Derivative and Other Financial Instruments - Schedule of Entity's Interest Rate Swap Open Positions (Detail) - MEMP [Member] - Interest rate swaps [Member] $ in Thousands | 12 Months Ended |
Dec. 31, 2015USD ($) | |
2016 [Member] | |
Derivative [Line Items] | |
Average Monthly Notional | $ 400,000 |
Weighted-average fixed rate | 0.943% |
Floating rate | 1 Month LIBOR |
2017 [Member] | |
Derivative [Line Items] | |
Average Monthly Notional | $ 400,000 |
Weighted-average fixed rate | 1.612% |
Floating rate | 1 Month LIBOR |
2018 [Member] | |
Derivative [Line Items] | |
Average Monthly Notional | $ 100,000 |
Weighted-average fixed rate | 1.946% |
Floating rate | 1 Month LIBOR |
Risk Management and Derivativ65
Risk Management and Derivative and Other Financial Instruments - Summary of Gross Fair Value and Net Recorded Fair Value of Derivative Instruments by Appropriate Balance Sheet Classification (Detail) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Derivative Instruments and Hedges, Assets [Abstract] | ||
Asset Derivatives, Net recorded fair value | $ 500,311 | $ 340,056 |
Asset Derivatives, Net recorded fair value | 553,101 | 435,369 |
Liability Derivatives, Net recorded fair value | 2,850 | 3,289 |
Liability Derivatives, Net recorded fair value | 1,441 | |
Short-term derivative instruments [Member] | ||
Derivative Instruments and Hedges, Assets [Abstract] | ||
Asset Derivatives, Gross fair value | 552,614 | 378,908 |
Asset Derivatives, Netting arrangements | (52,303) | (38,852) |
Asset Derivatives, Net recorded fair value | 500,311 | 340,056 |
Liability Derivatives, Gross fair value | 55,153 | 42,141 |
Liability Derivatives, Netting arrangements | (52,303) | (38,852) |
Liability Derivatives, Net recorded fair value | 2,850 | 3,289 |
Short-term derivative instruments [Member] | Commodity derivatives [Member] | ||
Derivative Instruments and Hedges, Assets [Abstract] | ||
Asset Derivatives, Gross fair value | 552,614 | 378,908 |
Liability Derivatives, Gross fair value | 53,939 | 38,852 |
Short-term derivative instruments [Member] | Interest rate swaps [Member] | ||
Derivative Instruments and Hedges, Assets [Abstract] | ||
Asset Derivatives, Gross fair value | 0 | |
Liability Derivatives, Gross fair value | 1,214 | 3,289 |
Long-term derivative instruments [Member] | ||
Derivative Instruments and Hedges, Assets [Abstract] | ||
Asset Derivatives, Gross fair value | 584,143 | 468,156 |
Asset Derivatives, Netting arrangements | (31,042) | (32,787) |
Asset Derivatives, Net recorded fair value | 553,101 | 435,369 |
Liability Derivatives, Gross fair value | 32,483 | 32,787 |
Liability Derivatives, Netting arrangements | (31,042) | (32,787) |
Liability Derivatives, Net recorded fair value | 1,441 | |
Long-term derivative instruments [Member] | Commodity derivatives [Member] | ||
Derivative Instruments and Hedges, Assets [Abstract] | ||
Asset Derivatives, Gross fair value | 584,143 | 466,851 |
Liability Derivatives, Gross fair value | 31,042 | 32,787 |
Long-term derivative instruments [Member] | Interest rate swaps [Member] | ||
Derivative Instruments and Hedges, Assets [Abstract] | ||
Asset Derivatives, Gross fair value | 0 | $ 1,305 |
Liability Derivatives, Gross fair value | $ 1,441 |
Risk Management and Derivativ66
Risk Management and Derivative and Other Financial Instruments - Schedule of Gains and Losses Related to Derivative Instruments (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Gain (Loss) on Derivative Instruments, Net, Pretax [Abstract] | |||
(Gain) loss on commodity derivative instruments | $ (744,139) | $ (749,988) | $ (29,294) |
Interest expense, net | 154,128 | 133,833 | 69,250 |
Commodity derivative contracts [Member] | |||
Gain (Loss) on Derivative Instruments, Net, Pretax [Abstract] | |||
(Gain) loss on commodity derivative instruments | (744,139) | (749,988) | (29,294) |
Interest rate derivatives [Member] | |||
Gain (Loss) on Derivative Instruments, Net, Pretax [Abstract] | |||
Interest expense, net | $ 4,674 | $ 145 | $ (239) |
Asset Retirement Obligations -
Asset Retirement Obligations - Summary of Changes in Asset Retirement Obligations (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Asset Retirement Obligation Disclosure [Abstract] | |||
Asset retirement obligations at beginning of period | $ 122,531 | $ 111,769 | $ 102,380 |
Liabilities added from acquisitions or drilling | 25,896 | 5,420 | 4,227 |
Liabilities settled | (1,430) | (588) | (170) |
Revision of estimates | 23,230 | 293 | 1,516 |
Liabilities removed upon sale of wells | (3,526) | (669) | (1,765) |
Accretion expense | 7,542 | 6,306 | 5,581 |
Asset retirement obligations at end of period | 174,243 | 122,531 | 111,769 |
Less: Current portion | 1,175 | 0 | 90 |
Asset retirement obligations - long-term portion | $ 173,068 | $ 122,531 | $ 111,679 |
Restricted Investments - Restri
Restricted Investments - Restricted Investment Balance (Detail) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Schedule Of Investments [Line Items] | ||
Restricted investments | $ 152,631 | $ 77,361 |
BOEM platform abandonment [Member] | ||
Schedule Of Investments [Line Items] | ||
Restricted investments | 144,008 | 69,954 |
BOEM lease bonds [Member] | ||
Schedule Of Investments [Line Items] | ||
Restricted investments | 1,533 | 794 |
SPBPC Collateral Contractual pipeline and surface facilities abandonment [Member] | ||
Schedule Of Investments [Line Items] | ||
Restricted investments | 3,178 | 2,701 |
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 |
California State | SPBPC Collateral Lands Commission pipeline right-of-way bond [Member] | ||
Schedule Of Investments [Line Items] | ||
Restricted investments | $ 3,005 | $ 3,005 |
Restricted Investments - Additi
Restricted Investments - Additional Information (Detail) | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Beta Properties [Member] | ||
Schedule Of Investments [Line Items] | ||
Percentage of working interests owned | 100.00% | 51.75% |
Long Term Debt - Consolidated D
Long Term Debt - Consolidated Debt Obligations (Detail) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 | |
Debt Instrument [Line Items] | |||
Unamortized debt issuance costs | $ (37,881) | $ (44,474) | |
Long-term debt | 3,012,643 | 2,344,692 | |
MRD Segment [Member] | |||
Debt Instrument [Line Items] | |||
Unamortized debt issuance costs | (10,936) | (12,455) | |
Long-term debt | 1,012,064 | 770,545 | |
MRD Segment [Member] | 2.0 Billion Revolving Credit Facility Due June 2019 [Member] | |||
Debt Instrument [Line Items] | |||
Credit facility | 423,000 | 183,000 | |
Unamortized debt issuance costs | (4,976) | (4,285) | |
MRD Segment [Member] | 5.875% Senior Unsecured Notes Due July 2022 [Member] | |||
Debt Instrument [Line Items] | |||
Senior Notes | [1],[2] | 600,000 | 600,000 |
MEMP [Member] | |||
Debt Instrument [Line Items] | |||
Unamortized debt issuance costs | (18,297) | (21,266) | |
Long-term debt | 2,000,579 | 1,574,147 | |
Unamortized discounts | (14,114) | (16,587) | |
MEMP [Member] | 2.0 Billion Revolving Credit Facility Due March 2018 [Member] | |||
Debt Instrument [Line Items] | |||
Credit facility | 836,000 | 412,000 | |
Unamortized debt issuance costs | (3,672) | (6,468) | |
MEMP [Member] | 7.625% senior unsecured notes, due May 2021 ("2021 Senior Notes") [Member] | |||
Debt Instrument [Line Items] | |||
Senior Notes | [1],[3] | 700,000 | 700,000 |
Unamortized debt issuance costs | (11,194) | (13,308) | |
MEMP [Member] | 6.875% Senior Unsecured Notes Due August 2022 ("2022 Senior Notes") [Member] | |||
Debt Instrument [Line Items] | |||
Senior Notes | [1],[4] | 496,990 | 500,000 |
Unamortized debt issuance costs | $ (7,103) | $ (7,958) | |
[1] | 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 $525.0 million and $534.0 million at December 31, 2015 and 2014, respectively. | ||
[3] | The estimated fair value of this fixed-rate debt was $210.0 million and $563.5 million at December 31, 2015 and 2014, respectively. | ||
[4] | The estimated fair value of this fixed-rate debt was $149.1 million and $380.0 million at December 31, 2015 and 2014, respectively. |
Long Term Debt - Consolidated71
Long Term Debt - Consolidated Debt Obligations (Parenthetical) (Detail) - USD ($) | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
MRD Segment [Member] | 2.0 Billion Revolving Credit Facility Due June 2019 [Member] | ||
Debt Instrument [Line Items] | ||
Revolving credit facility | $ 2,000,000,000 | |
Maturity date | Jun. 18, 2019 | |
MRD Segment [Member] | 5.875% Senior Unsecured Notes Due July 2022 [Member] | ||
Debt Instrument [Line Items] | ||
Maturity date | Jul. 1, 2022 | |
Debt interest rate | 5.875% | |
Estimated fair value of fixed rate debt | $ 525,000,000 | $ 534,000,000 |
MEMP [Member] | 2.0 Billion Revolving Credit Facility Due March 2018 [Member] | ||
Debt Instrument [Line Items] | ||
Revolving credit facility | $ 2,000,000,000 | |
Maturity date | Mar. 19, 2018 | |
MEMP [Member] | 7.625% senior unsecured notes, due May 2021 ("2021 Senior Notes") [Member] | ||
Debt Instrument [Line Items] | ||
Maturity date | May 1, 2021 | |
Debt interest rate | 7.625% | |
Estimated fair value of fixed rate debt | $ 210,000,000 | 563,500,000 |
MEMP [Member] | 6.875% Senior Unsecured Notes Due August 2022 ("2022 Senior Notes") [Member] | ||
Debt Instrument [Line Items] | ||
Maturity date | Aug. 1, 2022 | |
Debt interest rate | 6.875% | |
Estimated fair value of fixed rate debt | $ 149,100,000 | $ 380,000,000 |
Long Term Debt - Borrowing Base
Long Term Debt - Borrowing Base Credit Facility (Detail) | Dec. 31, 2015USD ($) |
MRD Segment [Member] | 2.0 Billion Revolving Credit Facility Due June 2019 [Member] | |
Line Of Credit Facility [Line Items] | |
Borrowing base | $ 1,000,000,000 |
MEMP [Member] | 2.0 Billion Revolving Credit Facility Due March 2018 [Member] | |
Line Of Credit Facility [Line Items] | |
Borrowing base | $ 1,175,000,000 |
Long Term Debt - Borrowing Ba73
Long Term Debt - Borrowing Base Credit Facility (Parenthetical) (Detail) | Dec. 31, 2015USD ($) |
MRD Segment [Member] | 2.0 Billion Revolving Credit Facility Due June 2019 [Member] | |
Line Of Credit Facility [Line Items] | |
Revolving credit facility | $ 2,000,000,000 |
MEMP [Member] | 2.0 Billion Revolving Credit Facility Due March 2018 [Member] | |
Line Of Credit Facility [Line Items] | |
Revolving credit facility | $ 2,000,000,000 |
Long Term Debt - MRD Revolving
Long Term Debt - MRD Revolving Credit Facility - Additional Information (Detail) - MRD Segment [Member] - Revolving Credit Facility [Member] - USD ($) | Jul. 18, 2014 | Dec. 31, 2015 |
Debt Obligations [Line Items] | ||
Revolving credit facility expiration term | 5 years | |
Line of credit facility, aggregate maximum borrowing amount | $ 2,000,000,000 | |
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 | 0.375% | |
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 5.875% Sen
Long Term Debt - MRD 5.875% Senior Unsecured Notes Offering - Additional Information (Detail) - 5.875% Senior Unsecured Notes ("MRD Senior Notes") [Member] $ in Millions | Jul. 10, 2014USD ($) |
Debt Obligations [Line Items] | |
Debt Instrument, maturity date | Jul. 1, 2022 |
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 | 5.875% |
Long Term Debt - PIK notes - Ad
Long Term Debt - PIK notes - Additional Information (Detail) - USD ($) $ in Thousands | Jul. 16, 2014 | Dec. 18, 2013 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Jun. 27, 2014 | Jun. 15, 2014 |
Debt Obligations [Line Items] | |||||||
Payment of distribution to funds | $ 0 | $ 732,362 | |||||
Extinguishment loss | $ 0 | $ 37,248 | |||||
PIK notes [Member] | |||||||
Debt Obligations [Line Items] | |||||||
Aggregate principal amount | $ 350,000 | $ 350,000 | |||||
Percentage of PIK toggle notes issued at par | 98.00% | ||||||
Cash reserve for payment of interest on notes | $ 50,000 | ||||||
Payment of distribution to funds | $ 210,000 | ||||||
Debt redemption price percentage | 102.00% | ||||||
Irrevocable deposits | $ 360,000 | ||||||
Extinguishment loss | $ 23,600 |
Long Term Debt - WildHorse Reso
Long Term Debt - WildHorse Resources Revolving Credit Facility and Second Lien Facility - Additional Information (Detail) - USD ($) | Jun. 13, 2013 | Apr. 03, 2013 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Debt Obligations [Line Items] | |||||
Cash distribution paid | $ 0 | $ 732,362,000 | |||
Loss on extinguishment of debt | $ 0 | $ 37,248,000 | |||
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, 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 ($) | Jul. 17, 2014 | Dec. 31, 2015 | Oct. 10, 2013 | May. 23, 2013 | Apr. 17, 2013 |
7.625 % Senior Notes Due May 2021 [Member] | |||||
Debt Obligations [Line Items] | |||||
Debt Instrument, maturity date | May 1, 2021 | ||||
MEMP [Member] | 7.625 % Senior Notes Due May 2021 [Member] | |||||
Debt Obligations [Line Items] | |||||
Senior unsecured notes interest rate | 7.625% | ||||
Other event of default minimum note holder percentage to accelerate | 25.00% | ||||
MEMP [Member] | 7.625 % Senior Notes Due May 2021 [Member] | Private Placement of Debt [Member] | |||||
Debt Obligations [Line Items] | |||||
Aggregate principal amount | $ 300,000,000 | $ 100,000,000 | $ 300,000,000 | ||
MEMP [Member] | Minimum [Member] | |||||
Debt Obligations [Line Items] | |||||
Percentage of revolving unused commitment fee | 0.375% | ||||
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% | ||||
MEMP [Member] | 2.0 Billion Revolving Credit Facility Due March 2018 [Member] | |||||
Debt Obligations [Line Items] | |||||
Initial borrowing base of second lien term facility | $ 2,000,000,000 | ||||
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] | 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 | Aug. 1, 2022 | ||||
Note issued at percentage of par | 98.485% | ||||
MEMP [Member] | 6.875% Senior Unsecured Notes ("2022 Senior Notes") [Member] | Private Placement of Debt [Member] | |||||
Debt Obligations [Line Items] | |||||
Aggregate principal amount | $ 500,000,000 | ||||
Senior unsecured notes interest rate | 6.875% |
Long Term Debt - Summary of Wei
Long Term Debt - Summary of Weighted-Average Interest Rates Paid On Variable-Rate Debt Obligations (Detail) | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
MRD Segment [Member] | 2.0 Billion Revolving Credit Facility Due June 2019 [Member] | |||
Line Of Credit Facility [Line Items] | |||
Revolving credit facility, weighted-average interest rates | 1.92% | 1.99% | |
MRD Segment [Member] | WildHorse Resources, LLC [Member] | |||
Line Of Credit Facility [Line Items] | |||
Revolving credit facility, weighted-average interest rates | 4.04% | 2.30% | |
MRD Segment [Member] | WildHorse Resources second lien [Member] | |||
Line Of Credit Facility [Line Items] | |||
Revolving credit facility, weighted-average interest rates | 6.44% | 7.60% | |
MRD Segment [Member] | Black Diamond [Member] | |||
Line Of Credit Facility [Line Items] | |||
Revolving credit facility, weighted-average interest rates | 3.97% | ||
MEMP [Member] | 2.0 Billion Revolving Credit Facility Due March 2018 [Member] | |||
Line Of Credit Facility [Line Items] | |||
Revolving credit facility, weighted-average interest rates | 2.12% | 2.67% | 3.25% |
MEMP [Member] | WHT [Member] | |||
Line Of Credit Facility [Line Items] | |||
Revolving credit facility, weighted-average interest rates | 2.29% | ||
MEMP [Member] | Tanos Energy LLC [Member] | |||
Line Of Credit Facility [Line Items] | |||
Revolving credit facility, weighted-average interest rates | 3.10% | ||
MEMP [Member] | Stanolind [Member] | |||
Line Of Credit Facility [Line Items] | |||
Revolving credit facility, weighted-average interest rates | 3.52% | ||
MEMP [Member] | Boaz [Member] | |||
Line Of Credit Facility [Line Items] | |||
Revolving credit facility, weighted-average interest rates | 2.97% | ||
MEMP [Member] | Crown [Member] | |||
Line Of Credit Facility [Line Items] | |||
Revolving credit facility, weighted-average interest rates | 3.38% | ||
MEMP [Member] | MRD LLC [Member] | |||
Line Of Credit Facility [Line Items] | |||
Revolving credit facility, weighted-average interest rates | 3.17% | ||
MEMP [Member] | Propel Energy [Member] | |||
Line Of Credit Facility [Line Items] | |||
Revolving credit facility, weighted-average interest rates | 3.08% |
Long Term Debt - Summary of Una
Long Term Debt - Summary of Unamortized Deferred Financing Costs Associated with Consolidated Debt Obligations (Detail) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 |
Debt Instrument [Line Items] | ||
Unamortized deferred financing costs | $ 37,881 | $ 44,474 |
MRD Segment [Member] | ||
Debt Instrument [Line Items] | ||
Unamortized deferred financing costs | 10,936 | 12,455 |
MRD Segment [Member] | 2.0 Billion Revolving Credit Facility Due June 2019 [Member] | ||
Debt Instrument [Line Items] | ||
Unamortized deferred financing costs | 4,976 | 4,285 |
MRD Segment [Member] | Senior Notes [Member] | ||
Debt Instrument [Line Items] | ||
Unamortized deferred financing costs | 10,936 | 12,455 |
MEMP [Member] | ||
Debt Instrument [Line Items] | ||
Unamortized deferred financing costs | 18,297 | 21,266 |
MEMP [Member] | 2.0 Billion Revolving Credit Facility Due March 2018 [Member] | ||
Debt Instrument [Line Items] | ||
Unamortized deferred financing costs | 3,672 | 6,468 |
MEMP [Member] | 7.625% senior unsecured notes, due May 2021 ("2021 Senior Notes") [Member] | ||
Debt Instrument [Line Items] | ||
Unamortized deferred financing costs | 11,194 | 13,308 |
MEMP [Member] | 6.875% Senior Unsecured Notes Due August 2022 ("2022 Senior Notes") [Member] | ||
Debt Instrument [Line Items] | ||
Unamortized deferred financing costs | $ 7,103 | $ 7,958 |
Stockholders' Equity and Nonc81
Stockholders' Equity and Noncontrolling Interests - Additional Information (Detail) - USD ($) | Nov. 03, 2015 | Sep. 25, 2015 | Mar. 16, 2015 | Sep. 09, 2014 | Jul. 15, 2014 | Jun. 18, 2014 | Oct. 08, 2013 | Apr. 01, 2013 | Mar. 25, 2013 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Apr. 30, 2015 |
Stockholders Equity Note Disclosure [Line Items] | |||||||||||||
Common stock, shares authorized | 600,000,000 | 600,000,000 | |||||||||||
Common stock, par value | $ 0.01 | $ 0.01 | |||||||||||
Shares of common stock issued | 21,500,000 | ||||||||||||
Net proceeds from issuance of common stock | $ 238,100,000 | ||||||||||||
Stock repurchase program, authorized amount | $ 50,000,000 | $ 50,000,000 | |||||||||||
Stock repurchased and retired during period, shares | 0 | 123,797 | |||||||||||
Payments for repurchase of common stock | $ 2,200,000 | ||||||||||||
Preferred stock, par value | $ 0.01 | $ 0.01 | |||||||||||
Preferred stock, shares authorized | 50,000,000 | 50,000,000 | |||||||||||
Preferred stock, shares issued | 0 | 0 | |||||||||||
Preferred stock, shares outstanding | 0 | 0 | |||||||||||
Purchase of noncontrolling interest | $ 5,946,000 | $ 3,292,000 | $ 15,135,000 | ||||||||||
Noncontrolling interests | 645,094,000 | 1,120,554,000 | |||||||||||
Fair value consideration paid | $ 5,946,000 | 3,292,000 | 15,135,000 | ||||||||||
SPBPC [Member] | |||||||||||||
Stockholders Equity Note Disclosure [Line Items] | |||||||||||||
Purchase of noncontrolling interest | $ 6,000,000 | ||||||||||||
MEMP [Member] | |||||||||||||
Stockholders Equity Note Disclosure [Line Items] | |||||||||||||
Stock repurchase program, authorized amount | $ 150,000,000 | ||||||||||||
Stock repurchased and retired during period, shares | 3,547,921 | 899,912 | |||||||||||
Payments for repurchase of common stock | $ 52,800,000 | $ 12,900,000 | |||||||||||
Stock repurchase program, remaining authorized amount | 0 | ||||||||||||
Tanos Energy LLC [Member] | |||||||||||||
Stockholders Equity Note Disclosure [Line Items] | |||||||||||||
Percentage of ownership interest sold to company | 1.066% | ||||||||||||
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 | ||||||||||||
MRD Segment [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 | $ 47,785,000 | $ 2,215,000 | ||||||||||
Common Stock [Member] | |||||||||||||
Stockholders Equity Note Disclosure [Line Items] | |||||||||||||
Shares of common stock issued | 13,800,000 | 13,800,000 | 192,500,000 | ||||||||||
Stock repurchased and retired during period, shares | 2,764,887 | 123,797 | |||||||||||
Purchase of noncontrolling interest | $ 0 | $ 0 | $ 0 | ||||||||||
Common Stock [Member] | MEMP [Member] | |||||||||||||
Stockholders Equity Note Disclosure [Line Items] | |||||||||||||
Number of common units sold by subsidiary | 14,950,000 | 9,890,000 | 16,675,000 | 9,775,000 | |||||||||
Net proceeds from sale of common units by subsidiary | $ 321,300,000 | $ 220,000,000 | $ 318,300,000 | $ 171,800,000 | |||||||||
Common Stock [Member] | MRD Segment [Member] | |||||||||||||
Stockholders Equity Note Disclosure [Line Items] | |||||||||||||
Payments for repurchase of common stock | $ 28,000 | $ 1,000 | |||||||||||
Common Stock [Member] | Over-Allotment [Member] | |||||||||||||
Stockholders Equity Note Disclosure [Line Items] | |||||||||||||
Shares of common stock issued | 1,800,000 |
Stockholders' Equity and Nonc82
Stockholders' Equity and Noncontrolling Interests - Summary of Changes In Common Shares Issued (Detail) - shares | Sep. 25, 2015 | Jun. 18, 2014 | Dec. 31, 2015 | Dec. 31, 2014 |
Class of Stock [Line Items] | ||||
Beginning Balance | 193,435,414 | 0 | ||
Shares of common stock issued | 21,500,000 | |||
Shares of common stock repurchased | 0 | (123,797) | ||
Ending Balance | 205,293,743 | 193,435,414 | ||
Common Stock [Member] | ||||
Class of Stock [Line Items] | ||||
Shares of common stock issued | 13,800,000 | 13,800,000 | 192,500,000 | |
Shares of common stock repurchased | (2,764,887) | (123,797) | ||
Restricted common shares issued (Note 11) | 938,558 | 1,068,422 | ||
Restricted common shares repurchased | (60,773) | |||
Restricted common shares forfeited | (54,569) | (9,211) |
Stockholders' Equity and Nonc83
Stockholders' Equity and Noncontrolling Interests - Summary of Changes In Common Shares Issued (Parenthetical) (Detail) $ in Millions | 12 Months Ended |
Dec. 31, 2015USD ($) | |
Statement Of Stockholders Equity [Abstract] | |
Payments remitted for employees tax obligations | $ 1.2 |
Earnings per Share - Summary of
Earnings per Share - Summary of Calculation of Earnings (Loss) Per Share (Detail) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 3 Months Ended | 12 Months Ended | ||||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | ||||
Numerator: | ||||||||||||
Net income (loss) available to common stockholders | $ 19,950 | $ 56,051 | $ (26,702) | $ 45,615 | $ 167,198 | $ 9,928 | $ (961,707) | $ 94,914 | $ (784,581) | |||
Denominator: | ||||||||||||
Weighted average common shares outstanding | 193,698 | 192,498 | ||||||||||
Incremental treasury stock method shares | [1] | 469 | 203 | |||||||||
Basic EPS | $ 0.10 | $ 0.29 | $ (0.14) | $ 0.24 | $ 0.87 | $ 0.05 | $ (5) | $ 0.49 | $ (4.08) | |||
Diluted EPS | $ 0.10 | $ 0.29 | $ (0.14) | $ 0.24 | $ 0.87 | $ 0.05 | $ (5) | $ 0.49 | [1] | $ (4.08) | [1] | |
[1] | The Company determines the more dilutive of either the two-class method or the treasury stock method for diluted EPS. The two-class method was more dilutive for each period presented. |
Long-Term Incentive Plans - Add
Long-Term Incentive Plans - Additional Information (Detail) - USD ($) $ in Millions | Jan. 08, 2016 | Jan. 08, 2015 | Dec. 31, 2015 | 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 | |||
Unrecognized compensation cost | $ 25.1 | |||
Unrecognized compensation cost weighted-average period | 2 years 5 months 1 day | |||
Tranche One [Member] | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Vesting percentage | 100.00% | |||
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 | |||
Restricted Stock [Member] | MEMP [Member] | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Unrecognized compensation cost | $ 16.5 | |||
Unrecognized compensation cost weighted-average period | 1 year 9 months 18 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 | |||
Restricted Stock [Member] | Director [Member] | Subsequent Event [Member] | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Aggregate award of restricted stock issued to employees and each independent director | 8,023 | |||
Vesting period of award | 1 year | |||
Phantom Share Units P S Us | Director [Member] | MEMP [Member] | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Vesting period of award | 1 year | |||
Aggregate award of phantom units issued to each independent director of our subsidiary | 155,601 |
Long-Term Incentive Plans - Sum
Long-Term Incentive Plans - Summary of Information Regarding Restricted Common Unit Awards (Detail) - Restricted Stock [Member] - $ / shares | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Restricted common shares outstanding, Number of Shares, Beginning Balance | 1,059,211 | ||
Granted, Number of Shares | 938,558 | 1,068,422 | |
Forfeited, Number of Shares | (54,569) | (9,211) | |
Vested, Number of Shares | (274,355) | ||
Restricted common shares outstanding, Number of Shares, Ending Balance | 1,668,845 | 1,059,211 | |
Restricted common shares outstanding, Weighted-Average Grant Date Fair Value Per Shares, Beginning Balance | $ 19 | ||
Granted, Weighted-Average Grant Date Fair Value Per Shares | 18.80 | $ 19 | |
Forfeited, Weighted-Average Grant Date Fair Value Per Shares | 18.83 | 19 | |
Vested, Weighted-Average Grant Date Fair Value Per Shares | 19 | ||
Restricted common shares outstanding, Weighted-Average Grant Date Fair Value Per Shares, Ending Balance | $ 18.89 | $ 19 | |
MEMP [Member] | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Restricted common shares outstanding, Number of Shares, Beginning Balance | 1,093,520 | 706,927 | 285,609 |
Granted, Number of Shares | 827,704 | 684,954 | 524,718 |
Forfeited, Number of Shares | (69,059) | (38,294) | (11,734) |
Vested, Number of Shares | (483,627) | (260,067) | (91,666) |
Restricted common shares outstanding, Number of Shares, Ending Balance | 1,368,538 | 1,093,520 | 706,927 |
Restricted common shares outstanding, Weighted-Average Grant Date Fair Value Per Shares, Beginning Balance | $ 20.93 | $ 18.62 | $ 18.08 |
Granted, Weighted-Average Grant Date Fair Value Per Shares | 14.90 | 22.39 | 18.83 |
Forfeited, Weighted-Average Grant Date Fair Value Per Shares | 18.35 | 20.54 | 17.24 |
Vested, Weighted-Average Grant Date Fair Value Per Shares | 20.37 | 18.56 | 18.31 |
Restricted common shares outstanding, Weighted-Average Grant Date Fair Value Per Shares, Ending Balance | $ 17.61 | $ 20.93 | $ 18.62 |
Long-Term Incentive Plans - S87
Long-Term Incentive Plans - Summary of Information Regarding Restricted Common Unit Awards (Parenthetical) (Detail) - Restricted Stock [Member] - USD ($) $ / shares in Units, $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Granted, Weighted-Average Grant Date Fair Value Per Shares | $ 18.80 | $ 19 | |
MRD Segment [Member] | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Aggregate grant date fair value | $ 17.6 | $ 20.3 | |
Granted, Weighted-Average Grant Date Fair Value Per Shares | $ 19 | ||
MRD Segment [Member] | Maximum [Member] | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Granted, Weighted-Average Grant Date Fair Value Per Shares | $ 18.91 | ||
MRD Segment [Member] | Minimum [Member] | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Granted, Weighted-Average Grant Date Fair Value Per Shares | $ 17.58 | ||
MEMP [Member] | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Aggregate grant date fair value | $ 12.3 | $ 15.3 | $ 9.9 |
Granted, Weighted-Average Grant Date Fair Value Per Shares | $ 14.90 | $ 22.39 | $ 18.83 |
MEMP [Member] | Maximum [Member] | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Granted, Weighted-Average Grant Date Fair Value Per Shares | 15.45 | 23.40 | 20.35 |
MEMP [Member] | Minimum [Member] | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Granted, Weighted-Average Grant Date Fair Value Per Shares | $ 6.20 | $ 21.99 | $ 18.33 |
Long-Term Incentive Plans - S88
Long-Term Incentive Plans - Summary of Amount of Compensation Expense Recognized (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Amortization of equity awards | $ 54,739 | $ 954,627 | $ 46,837 |
MEMP [Member] | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Amortization of equity awards | 10,809 | 7,874 | $ 3,558 |
Restricted Stock [Member] | MRD Segment [Member] | |||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||
Amortization of equity awards | $ 8,788 | $ 2,804 |
Incentive Units - Additional In
Incentive Units - Additional Information (Detail) - USD ($) $ in Thousands | Apr. 01, 2013 | Dec. 31, 2013 | Nov. 30, 2013 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Jun. 18, 2014 |
Equity Incentive Plan [Line Items] | |||||||
Compensation expense | $ 54,739 | $ 954,627 | $ 46,837 | ||||
Exchange of incentive units | 0 | 205,293,743 | 193,435,414 | 0 | |||
Carrying amount of the noncontrolling interest | $ 645,094 | $ 1,120,554 | |||||
Fair value of consideration paid for noncontrolling interests | $ 5,946 | 3,292 | $ 15,135 | ||||
Tanos Energy LLC [Member] | |||||||
Equity Incentive Plan [Line Items] | |||||||
Percentage of ownership interest sold to company | 1.066% | ||||||
Compensation expense as component of general and administrative expense | 5,800 | ||||||
BlueStone Natural Resources Holdings, LLC [Member] | |||||||
Equity Incentive Plan [Line Items] | |||||||
Compensation expense | 1,000 | $ 20,700 | |||||
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% | ||||||
Black Diamond, Classic GP and Classic [Member] | |||||||
Equity Incentive Plan [Line Items] | |||||||
Compensation expense | $ 12,600 | ||||||
WildHorse Resources, LLC [Member] | |||||||
Equity Incentive Plan [Line Items] | |||||||
Compensation expense | $ 10,000 | 831,100 | |||||
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 | ||||||
Carrying amount of the noncontrolling interest | $ 400 | ||||||
Fair value of consideration paid for noncontrolling interests | 3,300 | ||||||
Cash component of incentive unit compensation expense | 26,700 | ||||||
Incentive units exchanges for shares of our common stock | 804,400 | ||||||
MRD Holdco LLC [Member] | |||||||
Equity Incentive Plan [Line Items] | |||||||
The number of incentive units authorized by governing documents | 1,000 | ||||||
MRD Holdco LLC [Member] | Exchanged Incentive Units [Member] | |||||||
Equity Incentive Plan [Line Items] | |||||||
Compensation expense | $ 35,200 | $ 111,900 | |||||
Incentive units granted in an exchange for cancelled predecessor awards | 930 | ||||||
Unrecognized compensation expense | $ 58,800 | ||||||
Remaining expected life | 1 year 5 months 1 day | ||||||
MRD Holdco LLC [Member] | Subsequent Incentive Units [Member] | |||||||
Equity Incentive Plan [Line Items] | |||||||
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, 2015 | |
Exchanged Incentive Units [Member] | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |
Dividend yield | 0.00% |
Expected volatility | 51.30% |
Risk-free rate | 0.82% |
Expected life (years) | 1 year 5 months 1 day |
Subsequent Incentive Units [Member] | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |
Dividend yield | 0.00% |
Expected volatility | 51.30% |
Risk-free rate | 0.82% |
Expected life (years) | 1 year 5 months 1 day |
Related Party Transactions - Ad
Related Party Transactions - Additional Information (Detail) | Nov. 02, 2015USD ($) | Jul. 01, 2015$ / bbl | May. 01, 2014$ / MMBTU$ / bbl | Mar. 28, 2014USD ($) | Mar. 10, 2014USD ($) | Apr. 30, 2013USD ($) | Nov. 01, 2011MMBTU / d | Nov. 30, 2015USD ($) | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | Dec. 31, 2012USD ($) | Dec. 31, 2010USD ($) | Feb. 28, 2014USD ($) | Oct. 01, 2013USD ($) |
Related Party Transaction [Line Items] | |||||||||||||||
Cash received | $ 19,800,000 | ||||||||||||||
Related party transaction voting agreement description | The voting agreement also provides MRD Holdco with the right to designate up to three nominees to the Board, provided that such number of nominees shall be reduced to two, one and zero if the Funds and their affiliates collectively own less than 35%, 15%, and 5% respectively, of the outstanding shares of our common stock. | ||||||||||||||
Gas Gathering Agreement [Member] | |||||||||||||||
Related Party Transaction [Line Items] | |||||||||||||||
Primary term of gas agreement | 15 years | ||||||||||||||
Extension term of gas agreement | 1 year | ||||||||||||||
Gas Transportation Agreement [Member] | |||||||||||||||
Related Party Transaction [Line Items] | |||||||||||||||
Primary term of gas agreement | 15 years | ||||||||||||||
Extension term of gas agreement | 1 year | ||||||||||||||
NGP Controlled Entity [Member] | |||||||||||||||
Related Party Transaction [Line Items] | |||||||||||||||
Proceeds from divestitures | $ 2,000,000 | ||||||||||||||
MRD Midstream LLC [Member] | |||||||||||||||
Related Party Transaction [Line Items] | |||||||||||||||
General partner interest percentage | 5.25% | ||||||||||||||
Limited partner interest percentage | 18.40% | ||||||||||||||
Incentive distribution rights percentage | 5.25% | ||||||||||||||
NGPCIF [Member] | |||||||||||||||
Related Party Transaction [Line Items] | |||||||||||||||
Net Profits Interest Sold to NGP | 3.125% | ||||||||||||||
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 | Feb. 28, 2014 | ||||||||||||||
Cinco Group [Member] | |||||||||||||||
Related Party Transaction [Line Items] | |||||||||||||||
Business acquisition common control purchase price | $ 603,000,000 | ||||||||||||||
Cinco Group [Member] | Advisory Fees [Member] | |||||||||||||||
Related Party Transaction [Line Items] | |||||||||||||||
Expenses incurred with related parties | 300,000 | ||||||||||||||
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 | ||||||||||||||
Cretic Energy Services, LLC [Member] | |||||||||||||||
Related Party Transaction [Line Items] | |||||||||||||||
Drilling and completion expenses | $ 8,500,000 | ||||||||||||||
Multi-Shot, LLC [Member] | |||||||||||||||
Related Party Transaction [Line Items] | |||||||||||||||
Drilling and completion expenses | 2,300,000 | ||||||||||||||
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% | ||||||||||||||
Non Producing Wellbore [Member] | Net Profits Interest Sold To Affiliate NGPCIF [Member] | |||||||||||||||
Related Party Transaction [Line Items] | |||||||||||||||
Net Profits Interest Sold to NGP | 10.00% | ||||||||||||||
WildHorse Resources, LLC [Member] | |||||||||||||||
Related Party Transaction [Line Items] | |||||||||||||||
Cash received from related party | 4,400,000 | ||||||||||||||
WildHorse Resources, LLC [Member] | NGPCIF [Member] | |||||||||||||||
Related Party Transaction [Line Items] | |||||||||||||||
Payment to related party | 2,600,000 | $ 2,600,000 | |||||||||||||
Payable to related party | 200,000 | ||||||||||||||
Natural Gas Partners [Member] | |||||||||||||||
Related Party Transaction [Line Items] | |||||||||||||||
Proceeds from divestitures | $ 900,000 | ||||||||||||||
Gain (loss) on sale of oil and gas properties | $ 700,000 | ||||||||||||||
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] | |||||||||||||||
Gain (loss) on sale of oil and gas properties | $ 500,000 | ||||||||||||||
Gain recognized as contribution | 500,000 | ||||||||||||||
Total cash consideration | $ 1,200,000 | ||||||||||||||
Propel Energy [Member] | |||||||||||||||
Related Party Transaction [Line Items] | |||||||||||||||
Cash received | $ 3,300,000 | ||||||||||||||
WHR Management Company [Member] | |||||||||||||||
Related Party Transaction [Line Items] | |||||||||||||||
Payable to related party | 2,400,000 | ||||||||||||||
Management fee per month | $ 1,000,000 | ||||||||||||||
MEMP [Member] | |||||||||||||||
Related Party Transaction [Line Items] | |||||||||||||||
Payable to related party | 800,000 | ||||||||||||||
PennTex Operating [Member] | Gas Processing Agreement | |||||||||||||||
Related Party Transaction [Line Items] | |||||||||||||||
Primary term of gas agreement | 15 years | ||||||||||||||
Extension term of gas agreement | 1 year | ||||||||||||||
Classic Operating And Classic Pipeline [Member] | Gas Gathering Agreement [Member] | |||||||||||||||
Related Party Transaction [Line Items] | |||||||||||||||
Pipeline transportation agreement expiration year | 2,020 | ||||||||||||||
Pipeline transportation agreement extension | 1 year | ||||||||||||||
Amended gas gathering agreement terms disclosure | 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 | ||||||||||||||
Fee per MMBTU | $ / MMBTU | 0.30 | ||||||||||||||
MVC (MMBtu/d) | MMBTU / d | 50,000 | ||||||||||||||
Annual inflationary escalation | 3.50% | ||||||||||||||
Price per unit | $ / MMBTU | 0.07 | ||||||||||||||
Agreement expired, date | Dec. 31, 2023 | ||||||||||||||
Classic Operating And Classic Pipeline [Member] | Water Disposal Agreement [Member] | |||||||||||||||
Related Party Transaction [Line Items] | |||||||||||||||
Gain recognized as contribution | $ 2,100,000 | ||||||||||||||
Water disposal fee per barrel | $ / bbl | 0.40 | 1.10 | |||||||||||||
Water disposal agreement period | 3 years | ||||||||||||||
Pipeline water disposal agreement extension | 1 year | ||||||||||||||
Salt water disposal fees | $ 3,600,000 | $ 1,800,000 | $ 600,000 |
Related Party Transactions - Sc
Related Party Transactions - Schedule of Net Assets Recorded (Detail) - USD ($) $ in Thousands | Feb. 28, 2014 | Oct. 01, 2013 |
Cinco Group [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 | |
WildHorse Resources, LLC [Member] | NGPCIF [Member] | Acquisitions [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 |
Related Party Transactions - Bo
Related Party Transactions - Book Value of Assets Sold (Detail) - WHR Management Company [Member] - WildHorse Resources, LLC [Member] - Disposition [Member] $ in Thousands | Jun. 18, 2014USD ($) |
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 |
Related Party Transactions - Su
Related Party Transactions - Summary of Minimum Volume Commitment and Fees Associated with GPA (Detail) - Gas Processing Agreement | 12 Months Ended | |
Dec. 31, 2015MMBTU / d$ / MMBTU | ||
June 1, 2015 to September 30, 2015 [Member] | ||
Related Party Transaction [Line Items] | ||
MVC (MMBtu/d) | MMBTU / d | 115,000 | |
Firm Fee ($/MMBtu) | 0.435 | |
Interruptible Fee ($/MMBtu) | 0.470 | |
October 1, 2015 to June 30, 2016 [Member] | ||
Related Party Transaction [Line Items] | ||
MVC (MMBtu/d) | MMBTU / d | 345,000 | |
Firm Fee ($/MMBtu) | 0.435 | |
Interruptible Fee ($/MMBtu) | 0.470 | |
July 1, 2016 to June 30, 2026 [Member] | ||
Related Party Transaction [Line Items] | ||
MVC (MMBtu/d) | MMBTU / d | 460,000 | [1] |
Firm Fee ($/MMBtu) | 0.435 | [1] |
Interruptible Fee ($/MMBtu) | 0.350 | [1] |
July 1, 2026 to June 1, 2030 [Member] | ||
Related Party Transaction [Line Items] | ||
MVC (MMBtu/d) | MMBTU / d | 345,000 | |
Firm Fee ($/MMBtu) | 0.435 | |
Interruptible Fee ($/MMBtu) | 0.350 | |
June 2, 2030 to October 1, 2030 [Member] | ||
Related Party Transaction [Line Items] | ||
MVC (MMBtu/d) | MMBTU / d | 115,000 | |
Firm Fee ($/MMBtu) | 0.435 | |
Interruptible Fee ($/MMBtu) | 0.350 | |
[1] | (1) The firm fee is reduced to $0.35 $/MMBtu for volumes in excess of 345,000 MMBtu/d. |
Related Party Transactions - 95
Related Party Transactions - Summary of Minimum Volume Commitment and Fees Associated with GPA (Parenthetical) (Detail) - Gas Processing Agreement | 12 Months Ended |
Dec. 31, 2015MMBTU / d$ / MMBTU | |
Related Party Transaction [Line Items] | |
Decrease in firm fee | $ / MMBTU | 0.35 |
Minimum [Member] | |
Related Party Transaction [Line Items] | |
MVC (MMBtu/d) | MMBTU / d | 345,000 |
Related Party Transactions - 96
Related Party Transactions - Summary of Minimum Volume Commitment under GGA (Detail) - Gas Gathering Agreement [Member] | 12 Months Ended |
Dec. 31, 2015MMBTU / d$ / MMBTU | |
June 1, 2015 to June 1, 2030 [Member] | |
Related Party Transaction [Line Items] | |
MVC (MMBtu/d) | MMBTU / d | 460,000 |
Firm Fee ($/MMBtu) | $ / MMBTU | 0.03 |
June 1, 2016 to December 31, 2025 [Member] | |
Related Party Transaction [Line Items] | |
MVC (MMBtu/d) | MMBTU / d | 115,000 |
Usage Fee ($/MMBtu) | $ / MMBTU | 0.02 |
October 1, 2015 to June 30, 2016 [Member] | |
Related Party Transaction [Line Items] | |
MVC (MMBtu/d) | MMBTU / d | 345,000 |
Usage Fee ($/MMBtu) | $ / MMBTU | 0.02 |
July 1, 2016 to November 30, 2019 [Member] | |
Related Party Transaction [Line Items] | |
MVC (MMBtu/d) | MMBTU / d | 460,000 |
Usage Fee ($/MMBtu) | $ / MMBTU | 0.02 |
December 1, 2019 to June 30, 2026 [Member] | |
Related Party Transaction [Line Items] | |
MVC (MMBtu/d) | MMBTU / d | 460,000 |
Usage Fee ($/MMBtu) | $ / MMBTU | 0.05 |
July 1, 2026 to June 1, 2030 [Member] | |
Related Party Transaction [Line Items] | |
MVC (MMBtu/d) | MMBTU / d | 345,000 |
Usage Fee ($/MMBtu) | $ / MMBTU | 0.05 |
Related Party Transactions - 97
Related Party Transactions - Summary of Fees Associated with Agreement (Detail) | 12 Months Ended |
Dec. 31, 2015MMBTU / d$ / MMBTU$ / gal | |
October One Two Thousand Fifteen To October One Two Thousand Thirty | Transportation Services Agreement [Member] | |
Related Party Transaction [Line Items] | |
Usage Fee | $ / gal | 0.04 |
Gas Transportation Agreement [Member] | June 1, 2015 to June 1, 2030 [Member] | |
Related Party Transaction [Line Items] | |
Usage Fee | $ / MMBTU | 0.04 |
Gas Transportation Agreement [Member] | January 1, 2016 to December 31, 2025 [Member] | |
Related Party Transaction [Line Items] | |
MVC (MMBtu/d) | MMBTU / d | 360,000 |
Business Segment Data - Additio
Business Segment Data - Additional Information (Detail) | 12 Months Ended |
Dec. 31, 2015Segment | |
Segment Reporting [Abstract] | |
Number of reportable business segments | 2 |
Business Segment Data - Summary
Business Segment Data - Summary of Selected Business Segment Information (Detail) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Segment Reporting Information [Line Items] | |||||||||||
Total revenues | $ 175,868 | $ 199,737 | $ 176,743 | $ 179,841 | $ 250,431 | $ 265,296 | $ 254,777 | $ 204,621 | $ 732,189 | $ 975,125 | $ 614,067 |
Adjusted EBITDA | 711,029 | 647,733 | 394,856 | ||||||||
Segment assets | 5,082,849 | 4,559,826 | 5,082,849 | 4,559,826 | |||||||
Total cash expenditures for additions to long-lived assets | 1,222,685 | 1,869,134 | 468,447 | ||||||||
Operating Segments [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Adjusted EBITDA | 711,281 | 653,877 | 420,088 | ||||||||
Operating Segments [Member] | MRD Segment [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Total revenues | 374,042 | 409,082 | 219,552 | ||||||||
Adjusted EBITDA | 370,889 | 316,317 | 175,994 | ||||||||
Segment assets | 2,177,492 | 1,401,313 | 2,177,492 | 1,401,313 | |||||||
Total cash expenditures for additions to long-lived assets | 890,226 | 487,001 | 254,724 | ||||||||
Operating Segments [Member] | MEMP [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Total revenues | 358,147 | 566,043 | 394,515 | ||||||||
Adjusted EBITDA | 340,392 | 337,560 | 244,094 | ||||||||
Segment assets | 2,906,003 | 3,168,494 | 2,906,003 | 3,168,494 | |||||||
Total cash expenditures for additions to long-lived assets | 332,459 | 1,382,133 | 213,723 | ||||||||
Other, Adjustments & Eliminations [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Total revenues | 0 | ||||||||||
Adjusted EBITDA | (252) | (6,144) | $ (25,232) | ||||||||
Segment assets | $ (646) | $ (9,981) | (646) | $ (9,981) | |||||||
Total cash expenditures for additions to long-lived assets | $ 0 |
Business Segment Data - Summ100
Business Segment Data - Summary of Selected Business Segment Information (Parenthetical) (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Segment Reporting Information [Line Items] | |||
Cash distributions from MEMP | $ 252 | $ 6,144 | $ 26,006 |
Other, Adjustments & Eliminations [Member] | MEMP [Member] | |||
Segment Reporting Information [Line Items] | |||
Cash distributions from MEMP | $ 300 | $ 6,100 | $ 26,000 |
Business Segment Data - Schedul
Business Segment Data - Schedule of Calculation of Reportable Segment's Adjusted EBITDA (Detail) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Segment Reporting Information [Line Items] | |||||||||||
Net income (loss) | $ 89,987 | $ (135,255) | $ (140,473) | $ (112,149) | $ 328,859 | $ 112,037 | $ (1,053,443) | $ (23,516) | $ 95,648 | $ (762,851) | $ 101,502 |
Interest expense, net | 154,128 | 133,833 | 69,250 | ||||||||
Income tax expense (benefit) | 97,830 | 100,971 | 1,619 | ||||||||
Loss on extinguishment of debt | 0 | 37,248 | |||||||||
DD&A | 384,556 | 314,193 | 184,717 | ||||||||
Impairment of proved oil and natural gas properties | 616,784 | 432,116 | 6,600 | ||||||||
Accretion of AROs | 7,542 | 6,306 | 5,581 | ||||||||
(Gain) loss on commodity derivative instruments | (744,139) | (749,988) | (29,294) | ||||||||
Cash settlements received (paid) on expired commodity derivative instruments | (424,946) | (22,688) | (32,119) | ||||||||
(Gain) loss on sale of properties | (3,045) | 3,057 | (85,621) | ||||||||
Transaction related costs | 3,902 | 6,668 | 8,313 | ||||||||
Compensation expense | 54,739 | 954,627 | 46,837 | ||||||||
Non-cash based compensation expense | 0 | 1,057 | |||||||||
Exploration costs | 11,286 | 16,603 | 2,356 | ||||||||
Insurance recoveries related to environmental remediation | (1,216) | ||||||||||
Provision for environmental remediation | 2,852 | ||||||||||
Loss on settlement of AROs | (1,606) | ||||||||||
Loss on office lease | 0 | 2,622 | |||||||||
Cash distributions from MEMP | 252 | 6,144 | 26,006 | ||||||||
Adjusted EBITDA | 711,029 | 647,733 | 394,856 | ||||||||
MEMP [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Impairment of proved oil and natural gas properties | 616,800 | 407,500 | |||||||||
Operating Segments [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Net income (loss) | (298,217) | (648,719) | 152,395 | ||||||||
Interest expense, net | 154,128 | 133,833 | 69,250 | ||||||||
Income tax expense (benefit) | 97,830 | 100,971 | 1,619 | ||||||||
Loss on extinguishment of debt | 37,248 | ||||||||||
DD&A | 384,556 | 314,193 | 184,717 | ||||||||
Impairment of proved oil and natural gas properties | 616,784 | 432,116 | 6,600 | ||||||||
Accretion of AROs | 7,542 | 6,306 | 5,581 | ||||||||
(Gain) loss on commodity derivative instruments | (744,139) | (749,988) | (29,294) | ||||||||
Cash settlements received (paid) on expired commodity derivative instruments | 424,946 | 22,688 | 32,119 | ||||||||
(Gain) loss on sale of properties | (3,045) | 3,057 | (85,621) | ||||||||
Transaction related costs | 3,902 | 6,668 | 8,313 | ||||||||
Compensation expense | 54,739 | 954,627 | 46,837 | ||||||||
Non-cash based compensation expense | 1,057 | ||||||||||
Exploration costs | 11,286 | 16,603 | 2,356 | ||||||||
Insurance recoveries related to environmental remediation | (1,216) | ||||||||||
Provision for environmental remediation | 2,852 | ||||||||||
Loss on settlement of AROs | 1,606 | ||||||||||
Loss on office lease | 2,622 | ||||||||||
Non-cash equity (income) loss from MEMP | 327 | 12,656 | (1,847) | ||||||||
Cash distributions from MEMP | 252 | 6,144 | 26,006 | ||||||||
Adjusted EBITDA | 711,281 | 653,877 | 420,088 | ||||||||
Operating Segments [Member] | MRD Segment [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Net income (loss) | 97,274 | (764,333) | 91,390 | ||||||||
Interest expense, net | 39,396 | 50,283 | 24,948 | ||||||||
Income tax expense (benefit) | 100,005 | 102,392 | 1,311 | ||||||||
Loss on extinguishment of debt | 37,248 | ||||||||||
DD&A | 188,742 | 128,238 | 70,903 | ||||||||
Impairment of proved oil and natural gas properties | 0 | 24,576 | 2,528 | ||||||||
Accretion of AROs | 417 | 533 | 593 | ||||||||
(Gain) loss on commodity derivative instruments | (281,249) | (257,734) | (3,161) | ||||||||
Cash settlements received (paid) on expired commodity derivative instruments | 170,899 | 9,166 | 8,481 | ||||||||
(Gain) loss on sale of properties | (47) | 3,057 | (82,773) | ||||||||
Transaction related costs | 1,974 | 2,305 | 1,584 | ||||||||
Compensation expense | 43,930 | 946,753 | 34,997 | ||||||||
Exploration costs | 8,969 | 13,853 | 1,034 | ||||||||
Insurance recoveries related to environmental remediation | 0 | ||||||||||
Loss on settlement of AROs | 0 | ||||||||||
Loss on office lease | 1,180 | ||||||||||
Non-cash equity (income) loss from MEMP | 327 | 12,656 | (1,847) | ||||||||
Cash distributions from MEMP | 252 | 6,144 | 26,006 | ||||||||
Adjusted EBITDA | 370,889 | 316,317 | 175,994 | ||||||||
Operating Segments [Member] | MEMP [Member] | |||||||||||
Segment Reporting Information [Line Items] | |||||||||||
Net income (loss) | (395,491) | 115,614 | 61,005 | ||||||||
Interest expense, net | 114,732 | 83,550 | 44,302 | ||||||||
Income tax expense (benefit) | (2,175) | (1,421) | 308 | ||||||||
DD&A | 195,814 | 185,955 | 113,814 | ||||||||
Impairment of proved oil and natural gas properties | 616,784 | 407,540 | 4,072 | ||||||||
Accretion of AROs | 7,125 | 5,773 | 4,988 | ||||||||
(Gain) loss on commodity derivative instruments | (462,890) | (492,254) | (26,133) | ||||||||
Cash settlements received (paid) on expired commodity derivative instruments | 254,047 | 13,522 | 23,638 | ||||||||
(Gain) loss on sale of properties | (2,998) | (2,848) | |||||||||
Transaction related costs | 1,928 | 4,363 | 6,729 | ||||||||
Compensation expense | 10,809 | 7,874 | 11,840 | ||||||||
Non-cash based compensation expense | 1,057 | ||||||||||
Exploration costs | 2,317 | 2,750 | 1,322 | ||||||||
Insurance recoveries related to environmental remediation | (1,216) | ||||||||||
Provision for environmental remediation | 2,852 | ||||||||||
Loss on settlement of AROs | 1,606 | ||||||||||
Loss on office lease | 1,442 | ||||||||||
Non-cash equity (income) loss from MEMP | 0 | ||||||||||
Cash distributions from MEMP | 0 | ||||||||||
Adjusted EBITDA | $ 340,392 | $ 337,560 | $ 244,094 |
Business Segment Data - Reconci
Business Segment Data - Reconciliation of Total Reportable Segment's Adjusted EBITDA to Net Income (Loss) (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Segment Reporting, Revenue Reconciling Item [Line Items] | |||
Total Reportable Segments' Adjusted EBITDA | $ 711,029 | $ 647,733 | $ 394,856 |
Adjustments to reconcile Adjusted EBITDA to net income (loss): | |||
Interest expense, net | (154,128) | (133,833) | (69,250) |
Loss on extinguishment of debt | 0 | (37,248) | |
Income tax benefit (expense) | (97,830) | (100,971) | (1,619) |
DD&A | (384,556) | (314,193) | (184,717) |
Impairment of proved oil and natural gas properties | (616,784) | (432,116) | (6,600) |
Accretion of AROs | (7,542) | (6,306) | (5,581) |
Gains (losses) on commodity derivative instruments | 744,139 | 749,988 | 29,294 |
Cash settlements received (paid) on expired commodity derivative instruments | (424,946) | (22,688) | (32,119) |
Gain (loss) on sale of properties | 3,045 | (3,057) | 85,621 |
Transaction related costs | (3,902) | (6,668) | (8,313) |
Incentive-based compensation expense | (54,739) | (954,627) | (46,837) |
Non-cash based compensation expense | 0 | (1,057) | |
Exploration costs | (11,286) | (16,603) | (2,356) |
Cash distributions from MEMP | (252) | (6,144) | (26,006) |
Insurance recoveries related to environmental remediation | 1,216 | ||
Provision for environmental remediation | (2,852) | ||
Loss on office lease | 0 | (2,622) | |
Loss on settlement of AROs | (1,606) | ||
Other non-cash equity (income) loss | 0 | 784 | |
Net income (loss) | (297,890) | (636,063) | 151,332 |
Reportable Segments [Member] | |||
Segment Reporting, Revenue Reconciling Item [Line Items] | |||
Total Reportable Segments' Adjusted EBITDA | $ 711,281 | $ 653,877 | $ 420,088 |
Business Segment Data - Sche103
Business Segment Data - Schedule of Consolidated and Combined Statement of Operations Disaggregated by Reportable Segment (Detail) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Revenues: | |||||||||||
Oil & natural gas sales | $ 729,464 | $ 970,747 | $ 610,992 | ||||||||
Other revenues | 2,725 | 4,378 | 3,075 | ||||||||
Total revenues | $ 175,868 | $ 199,737 | $ 176,743 | $ 179,841 | $ 250,431 | $ 265,296 | $ 254,777 | $ 204,621 | 732,189 | 975,125 | 614,067 |
Costs and expenses: | |||||||||||
Lease operating | 193,102 | 161,303 | 111,798 | ||||||||
Gathering, processing, and transportation | 107,493 | 77,848 | 42,721 | ||||||||
Gathering, processing, and transportation - affiliate | 25,403 | ||||||||||
Exploration | 11,286 | 16,603 | 2,356 | ||||||||
Taxes other than income | 40,724 | 45,751 | 27,146 | ||||||||
Depreciation, depletion, and amortization | 384,556 | 314,193 | 184,717 | ||||||||
Impairment of proved oil and natural gas properties | 616,784 | 432,116 | 6,600 | ||||||||
Incentive unit compensation expense | 35,142 | 943,949 | 43,279 | ||||||||
General and administrative | 102,959 | 87,673 | 82,079 | ||||||||
Accretion of asset retirement obligations | 7,542 | 6,306 | 5,581 | ||||||||
(Gain) loss on commodity derivative instruments | (744,139) | (749,988) | (29,294) | ||||||||
(Gain) loss on sale of properties | (3,045) | 3,057 | (85,621) | ||||||||
Other, net | (665) | (12) | 649 | ||||||||
Total costs and expenses | 777,142 | 1,338,799 | 392,011 | ||||||||
Operating income (loss) | $ 150,764 | $ (40,429) | $ (126,790) | $ (28,498) | $ 444,776 | $ 174,201 | $ (993,256) | $ 10,605 | (44,953) | (363,674) | 222,056 |
Other income (expense): | |||||||||||
Interest expense, net | (154,128) | (133,833) | (69,250) | ||||||||
Loss on extinguishment of debt | 0 | (37,248) | |||||||||
Earnings from equity investments | 0 | (784) | |||||||||
Other, net | (979) | (337) | 145 | ||||||||
Total other income (expense) | (155,107) | (171,418) | (69,105) | ||||||||
Income (loss) before income taxes | (200,060) | (535,092) | 152,951 | ||||||||
Income tax benefit (expense) | (97,830) | (100,971) | (1,619) | ||||||||
Net income (loss) | (297,890) | (636,063) | 151,332 | ||||||||
Operating Segments [Member] | |||||||||||
Costs and expenses: | |||||||||||
Exploration | 11,286 | 16,603 | 2,356 | ||||||||
Depreciation, depletion, and amortization | 384,556 | 314,193 | 184,717 | ||||||||
Impairment of proved oil and natural gas properties | 616,784 | 432,116 | 6,600 | ||||||||
Accretion of asset retirement obligations | 7,542 | 6,306 | 5,581 | ||||||||
(Gain) loss on commodity derivative instruments | (744,139) | (749,988) | (29,294) | ||||||||
(Gain) loss on sale of properties | (3,045) | 3,057 | (85,621) | ||||||||
Other income (expense): | |||||||||||
Interest expense, net | (154,128) | (133,833) | (69,250) | ||||||||
Loss on extinguishment of debt | (37,248) | ||||||||||
Income tax benefit (expense) | (97,830) | (100,971) | (1,619) | ||||||||
Other, Adjustments & Eliminations [Member] | |||||||||||
Revenues: | |||||||||||
Oil & natural gas sales | 0 | ||||||||||
Other revenues | 0 | ||||||||||
Total revenues | 0 | ||||||||||
Costs and expenses: | |||||||||||
Lease operating | 0 | (108) | |||||||||
Gathering, processing, and transportation | 0 | ||||||||||
Gathering, processing, and transportation - affiliate | 0 | ||||||||||
Exploration | 0 | ||||||||||
Taxes other than income | 0 | ||||||||||
Depreciation, depletion, and amortization | 0 | ||||||||||
Impairment of proved oil and natural gas properties | 0 | ||||||||||
Incentive unit compensation expense | 0 | ||||||||||
General and administrative | 0 | 105 | |||||||||
Accretion of asset retirement obligations | 0 | ||||||||||
(Gain) loss on commodity derivative instruments | 0 | ||||||||||
(Gain) loss on sale of properties | 0 | ||||||||||
Other, net | 0 | ||||||||||
Total costs and expenses | 0 | (3) | |||||||||
Operating income (loss) | 0 | 3 | |||||||||
Other income (expense): | |||||||||||
Interest expense, net | 0 | ||||||||||
Earnings from equity investments | 327 | 12,656 | (1,066) | ||||||||
Other, net | 0 | ||||||||||
Total other income (expense) | 327 | 12,656 | (1,066) | ||||||||
Income (loss) before income taxes | 327 | 12,656 | (1,063) | ||||||||
Income tax benefit (expense) | 0 | ||||||||||
Net income (loss) | 327 | 12,656 | (1,063) | ||||||||
MRD Segment [Member] | Operating Segments [Member] | |||||||||||
Revenues: | |||||||||||
Oil & natural gas sales | 374,042 | 409,070 | 219,552 | ||||||||
Other revenues | 0 | 12 | |||||||||
Total revenues | 374,042 | 409,082 | 219,552 | ||||||||
Costs and expenses: | |||||||||||
Lease operating | 24,903 | 17,570 | 17,315 | ||||||||
Gathering, processing, and transportation | 72,554 | 45,956 | 17,666 | ||||||||
Gathering, processing, and transportation - affiliate | 25,403 | ||||||||||
Exploration | 8,969 | 13,853 | 1,034 | ||||||||
Taxes other than income | 14,896 | 12,610 | 8,699 | ||||||||
Depreciation, depletion, and amortization | 188,742 | 128,238 | 70,903 | ||||||||
Impairment of proved oil and natural gas properties | 0 | 24,576 | 2,528 | ||||||||
Incentive unit compensation expense | 35,142 | 943,949 | 34,997 | ||||||||
General and administrative | 46,288 | 38,549 | 35,309 | ||||||||
Accretion of asset retirement obligations | 417 | 533 | 593 | ||||||||
(Gain) loss on commodity derivative instruments | (281,249) | (257,734) | (3,161) | ||||||||
(Gain) loss on sale of properties | (47) | 3,057 | (82,773) | ||||||||
Other, net | 0 | (1) | 2 | ||||||||
Total costs and expenses | 136,018 | 971,156 | 103,112 | ||||||||
Operating income (loss) | 238,024 | (562,074) | 116,440 | ||||||||
Other income (expense): | |||||||||||
Interest expense, net | (39,396) | (50,283) | (24,948) | ||||||||
Loss on extinguishment of debt | (37,248) | ||||||||||
Earnings from equity investments | (327) | (12,656) | 1,066 | ||||||||
Other, net | (1,022) | 320 | 143 | ||||||||
Total other income (expense) | (40,745) | (99,867) | (23,739) | ||||||||
Income (loss) before income taxes | 197,279 | (661,941) | 92,701 | ||||||||
Income tax benefit (expense) | (100,005) | (102,392) | (1,311) | ||||||||
Net income (loss) | 97,274 | (764,333) | 91,390 | ||||||||
MEMP [Member] | |||||||||||
Costs and expenses: | |||||||||||
Impairment of proved oil and natural gas properties | 616,800 | 407,500 | |||||||||
MEMP [Member] | Operating Segments [Member] | |||||||||||
Revenues: | |||||||||||
Oil & natural gas sales | 355,422 | 561,677 | 391,440 | ||||||||
Other revenues | 2,725 | 4,366 | 3,075 | ||||||||
Total revenues | 358,147 | 566,043 | 394,515 | ||||||||
Costs and expenses: | |||||||||||
Lease operating | 168,199 | 143,733 | 94,591 | ||||||||
Gathering, processing, and transportation | 34,939 | 31,892 | 25,055 | ||||||||
Gathering, processing, and transportation - affiliate | 0 | ||||||||||
Exploration | 2,317 | 2,750 | 1,322 | ||||||||
Taxes other than income | 25,828 | 33,141 | 18,447 | ||||||||
Depreciation, depletion, and amortization | 195,814 | 185,955 | 113,814 | ||||||||
Impairment of proved oil and natural gas properties | 616,784 | 407,540 | 4,072 | ||||||||
Incentive unit compensation expense | 0 | 8,282 | |||||||||
General and administrative | 56,671 | 49,124 | 46,665 | ||||||||
Accretion of asset retirement obligations | 7,125 | 5,773 | 4,988 | ||||||||
(Gain) loss on commodity derivative instruments | (462,890) | (492,254) | (26,133) | ||||||||
(Gain) loss on sale of properties | (2,998) | (2,848) | |||||||||
Other, net | (665) | (11) | 647 | ||||||||
Total costs and expenses | 641,124 | 367,643 | 288,902 | ||||||||
Operating income (loss) | (282,977) | 198,400 | 105,613 | ||||||||
Other income (expense): | |||||||||||
Interest expense, net | (114,732) | (83,550) | (44,302) | ||||||||
Earnings from equity investments | 0 | ||||||||||
Other, net | 43 | (657) | 2 | ||||||||
Total other income (expense) | (114,689) | (84,207) | (44,300) | ||||||||
Income (loss) before income taxes | (397,666) | 114,193 | 61,313 | ||||||||
Income tax benefit (expense) | 2,175 | 1,421 | (308) | ||||||||
Net income (loss) | $ (395,491) | $ 115,614 | $ 61,005 |
Income Taxes - Components of In
Income Taxes - Components of Income Tax Expense (Benefit) (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Current income taxes: | |||
Federal | $ (9,982) | $ 0 | $ 0 |
State | (147) | 22 | (1,619) |
Total current income tax benefit (expense) | (10,129) | 22 | (1,619) |
Deferred income taxes: | |||
Federal | (54,224) | (88,994) | 0 |
State | (33,477) | (11,999) | 0 |
Total deferred income tax benefit (expense) | (87,701) | (100,993) | 0 |
Total income tax benefit (expense) | $ (97,830) | $ (100,971) | $ (1,619) |
Income Taxes - Additional Infor
Income Taxes - Additional Information (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Jun. 30, 2014 | |
Operating Loss Carryforwards [Line Items] | |||
Federal statutory corporate tax rate | 35.00% | ||
Deferred tax liabilities | $ 284,309,000 | $ 181,678,000 | $ 43,300,000 |
Reversed deferred tax liability | 38,778,000 | ||
Deferred Tax Adjustment Equity Initial Public Offering | 4,400,000 | ||
Deferred Tax Adjustment Property Exchanges | 34,400,000 | ||
Unrecognized tax benefits | 0 | ||
Tax credit carryforward | 9,984,000 | ||
Valuation allowance | 0 | $ 2,634,000 | |
United States [Member] | |||
Operating Loss Carryforwards [Line Items] | |||
Net operating loss carryforwards | $ 169,700,000 | ||
Operating loss carryforwards expiration start year | 2,034 | ||
Operating loss carryforwards expiration end year | 2,035 | ||
State [Member] | |||
Operating Loss Carryforwards [Line Items] | |||
Net operating loss carryforwards | $ 173,600,000 | ||
Operating loss carryforwards expiration start year | 2,034 | ||
Operating loss carryforwards expiration end year | 2,035 |
Income Taxes - Reconciliation o
Income Taxes - Reconciliation of Income Tax Benefit (Expense) (Detail) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Income Tax Disclosure [Abstract] | ||||
Expected tax benefit (expense) at federal statutory rate | $ 70,021 | $ 187,282 | $ (53,533) | |
State income tax benefit (expense), net of federal benefit | (21,856) | (9,660) | (1,619) | |
Pass-through entities | [1] | (137,704) | 49,989 | 53,533 |
Stock compensation | [2] | (12,300) | (330,024) | 0 |
Other | 4,009 | 1,442 | 0 | |
Total income tax benefit (expense) | $ (97,830) | $ (100,971) | $ (1,619) | |
[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 Ne
Income Taxes - Components of Net Deferred Income Tax Liabilities (Detail) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 | Jun. 30, 2014 |
Deferred income tax assets: | |||
Net operating loss carryforward | $ 68,431 | $ 28,043 | |
Asset retirement obligation | 4,483 | 5,757 | |
Alternative minimum tax credit carryforward | 9,984 | ||
Other | 5,584 | 3,566 | |
Total deferred income tax assets | 88,482 | 37,366 | |
Valuation allowance | 0 | (2,634) | |
Net deferred income tax assets | 88,482 | 34,732 | |
Deferred income tax liabilities: | |||
Property, plant and equipment | 172,951 | 80,198 | |
Derivatives | 111,313 | 101,148 | |
Other | 45 | 332 | |
Total deferred income tax liabilities | 284,309 | 181,678 | $ 43,300 |
Net deferred income tax liabilities | $ 195,827 | $ 146,946 |
Commitments and Contingencies -
Commitments and Contingencies - Environmental Reserves Activity (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Commitments And Contingencies Disclosure [Abstract] | |||
Balance at beginning of period | $ 2,092 | $ 577 | $ 1,469 |
Charged to costs and expenses | 2,852 | ||
Payments | (1,876) | (1,337) | (892) |
Balance at end of period | $ 216 | $ 2,092 | $ 577 |
Commitments and Contingencie109
Commitments and Contingencies - Additional Information (Detail) | 12 Months Ended | ||||
Dec. 31, 2015USD ($)$ / MMBTU$ / bbl | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) | Jun. 30, 2010USD ($) | Mar. 01, 2007USD ($) | |
Loss Contingencies [Line Items] | |||||
Amount per barrel of oil | $ / bbl | 0.25 | ||||
Aggregate value of account required to cease fund | $ 4,300,000 | ||||
Restricted investment | 3,200,000 | ||||
Additional quarterly payments | $ 1,300,000 | ||||
Maximum remaining obligation | 8,000,000 | ||||
Rent expense | $ 25,400,000 | $ 10,800,000 | $ 8,300,000 | ||
East Texas Properties [Member] | |||||
Loss Contingencies [Line Items] | |||||
Term of minimum volume commitment | 7 years | ||||
Regency Field Services LLC [Member] | |||||
Loss Contingencies [Line Items] | |||||
Agreement expired, date | Dec. 31, 2025 | ||||
Extension term of gas agreement | 1 year | ||||
Natural gas assesses per MMBtu | $ / MMBTU | 0.25 | ||||
Regency Field Services LLC [Member] | Dubberly [Member] | |||||
Loss Contingencies [Line Items] | |||||
Payback demand fee received by the third party | 110.00% | ||||
REO Sponsorship [Member] | |||||
Loss Contingencies [Line Items] | |||||
Supplemental bond for decommissioning liabilities trust agreement | $ 90,000,000 |
Commitments and Contingencie110
Commitments and Contingencies - Minimum Balances Attributable to Net Working Interest (Detail) $ in Thousands | Dec. 31, 2015USD ($) |
June 30, 2016 [Member] | |
Asset retirement obligations | |
Minimum balances attributable to net working interest | $ 148,000 |
December 31, 2016 [Member] | |
Asset retirement obligations | |
Minimum balances attributable to net working interest | $ 152,000 |
Commitments and Contingencie111
Commitments and Contingencies - Gross Held-to-Maturity Investments (Detail) $ in Thousands | Dec. 31, 2015USD ($) |
Money Market Funds [Member] | |
Held-to-maturity Securities [Abstract] | |
Amortized Cost | $ 144,008 |
Commitments and Contingencie112
Commitments and Contingencies - CO2 and Midstream Minimum Purchase Commitments (Detail) $ in Thousands | Dec. 31, 2015USD ($) |
East Texas Properties [Member] | |
Minimum Purchase Commitment [Line Items] | |
Purchase Commitment, Total | $ 35,788 |
Purchase Commitment, 2016 | 5,121 |
Purchase Commitment, 2017 | 5,121 |
Purchase Commitment, 2018 | 5,106 |
Purchase Commitment, 2019 | 5,107 |
Purchase Commitment, 2020 | 5,106 |
Purchase Commitment, Thereafter | 10,227 |
Wyoming Bairoil Properties and Beta Properties [Member] | |
Minimum Purchase Commitment [Line Items] | |
Purchase Commitment, Total | 30,307 |
Purchase Commitment, 2016 | 7,393 |
Purchase Commitment, 2017 | 7,505 |
Purchase Commitment, 2018 | 5,075 |
Purchase Commitment, 2019 | 5,366 |
Purchase Commitment, 2020 | 4,968 |
Purchase Commitment, Thereafter | 0 |
Wyoming Bairoil Properties and Beta Properties [Member] | Offshore Ship Services and Other [Member] | |
Minimum Purchase Commitment [Line Items] | |
Purchase Commitment, Total | 4,662 |
Purchase Commitment, 2016 | 4,662 |
Purchase Commitment, 2017 | 0 |
Purchase Commitment, 2018 | 0 |
Purchase Commitment, 2019 | 0 |
Purchase Commitment, 2020 | 0 |
Purchase Commitment, Thereafter | $ 0 |
Commitments and Contingencie113
Commitments and Contingencies - Monthly Demand Quantity and Fees (Detail) - January 1, 2016 to January 22, 2020 [Member] | 12 Months Ended |
Dec. 31, 2015MMBTU / d$ / MMBTU | |
Other Commitments [Line Items] | |
MDQ | MMBTU / d | 249,700 |
Pay demand fee | 0.275 |
Gathering demand fee | 0.295 |
Dubberly [Member] | |
Other Commitments [Line Items] | |
Cryogenic processing fee | 0 |
MDQ | MMBTU / d | 113,000 |
Pay demand fee | 0 |
Gathering demand fee | 0 |
Dubberly [Member] | |
Other Commitments [Line Items] | |
Cryogenic processing fee | 0.380 |
Commitments and Contingencie114
Commitments and Contingencies - Minimum Lease Payment Obligations and Sublease Rental Income Under Non-Cancelable Operating Leases (Detail) $ in Thousands | Dec. 31, 2015USD ($) |
MRD Segment [Member] | |
Operating leases | |
Total | $ 45,323 |
2,016 | 10,509 |
2,017 | 9,344 |
2,018 | 7,368 |
2,019 | 6,776 |
2,020 | 6,203 |
Thereafter | 5,123 |
Sublease rental income | |
Sublease rental income, Total | 4,021 |
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, 2020 | 0 |
Sublease rental income, Thereafter | 0 |
MEMP [Member] | |
Operating leases | |
Total | 6,107 |
2,016 | 1,007 |
2,017 | 317 |
2,018 | 294 |
2,019 | 294 |
2,020 | 295 |
Thereafter | $ 3,900 |
Condensed Consolidating Fina115
Condensed Consolidating Financial Information - Condensed Consolidating Balance Sheets (Detail) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Current assets: | ||||
Cash and cash equivalents | $ 2,175 | $ 5,958 | $ 77,721 | $ 49,391 |
Accounts receivable - trade | 114,095 | 131,576 | ||
Accounts receivable - affiliates | 0 | |||
Short-term derivative instruments | 500,311 | 340,056 | ||
Other financial instruments (Note 5) | 46,106 | |||
Prepaid expenses and other current assets | 13,017 | 23,203 | ||
Total current assets | 675,704 | 500,793 | ||
Carrying value of properties after impairment charges | 3,691,384 | 3,537,656 | ||
Long-term derivative instruments | 553,101 | 435,369 | ||
Investments in subsidiaries | 0 | |||
Other long-term assets | 162,660 | 86,008 | ||
Total assets | 5,082,849 | 4,559,826 | ||
Current liabilities: | ||||
Accounts payable and accrued liabilities | 155,648 | 172,843 | ||
Accounts payable - affiliates | 5,209 | 624 | ||
Revenues payable | 61,047 | 57,352 | ||
Short-term derivative instruments | 2,850 | 3,289 | ||
Total current liabilities | 224,754 | 234,108 | ||
Long-term debt | 3,012,643 | 2,344,692 | ||
Asset retirement obligations | 173,068 | 122,531 | 111,679 | |
Long-term derivative instruments | 1,441 | |||
Deferred tax liabilities | 195,827 | 146,946 | ||
Other long-term liabilities | 7,195 | 8,585 | ||
Total liabilities | 3,614,928 | 2,856,862 | ||
Equity: | ||||
Equity | 822,827 | 582,410 | ||
Noncontrolling interests | 645,094 | 1,120,554 | ||
Total equity | 1,467,921 | 1,702,964 | 858,132 | 1,276,709 |
Total liabilities and equity | 5,082,849 | 4,559,826 | ||
Parent [Member] | ||||
Current assets: | ||||
Cash and cash equivalents | 2,986 | 2,241 | ||
Accounts receivable - trade | 7,850 | 5,995 | ||
Accounts receivable - affiliates | 9,525 | 10,047 | ||
Short-term derivative instruments | 227,991 | 131,471 | ||
Other financial instruments (Note 5) | 46,106 | |||
Prepaid expenses and other current assets | 2,318 | 4,178 | ||
Total current assets | 296,776 | 153,932 | ||
Carrying value of properties after impairment charges | 15,825 | 16,601 | ||
Long-term derivative instruments | 91,292 | 123,567 | ||
Investments in subsidiaries | 1,482,847 | 1,139,792 | ||
Other long-term assets | 4,976 | 3,324 | ||
Total assets | 1,891,716 | 1,437,216 | ||
Current liabilities: | ||||
Accounts payable and accrued liabilities | 26,796 | 6,245 | ||
Accounts payable - affiliates | 0 | |||
Revenues payable | 80 | |||
Short-term derivative instruments | 0 | |||
Total current liabilities | 26,876 | 6,245 | ||
Long-term debt | 1,012,064 | 770,545 | ||
Asset retirement obligations | 0 | |||
Long-term derivative instruments | 0 | |||
Deferred tax liabilities | 22,754 | 69,431 | ||
Other long-term liabilities | 7,195 | 8,585 | ||
Total liabilities | 1,068,889 | 854,806 | ||
Equity: | ||||
Equity | 822,827 | 582,410 | ||
Noncontrolling interests | 0 | |||
Total equity | 822,827 | 582,410 | ||
Total liabilities and equity | 1,891,716 | 1,437,216 | ||
Guarantor Subsidiaries [Member] | ||||
Current assets: | ||||
Cash and cash equivalents | 0 | 3,762 | 48,619 | 18,623 |
Accounts receivable - trade | 49,537 | 44,952 | ||
Accounts receivable - affiliates | 0 | |||
Short-term derivative instruments | 0 | |||
Prepaid expenses and other current assets | 3,670 | 7,993 | ||
Total current assets | 53,207 | 56,707 | ||
Carrying value of properties after impairment charges | 1,729,236 | 1,050,722 | ||
Long-term derivative instruments | 0 | |||
Investments in subsidiaries | 0 | |||
Other long-term assets | 0 | 260 | ||
Total assets | 1,782,443 | 1,107,689 | ||
Current liabilities: | ||||
Accounts payable and accrued liabilities | 69,279 | 56,546 | ||
Accounts payable - affiliates | 14,193 | 3,638 | ||
Revenues payable | 35,463 | 27,242 | ||
Short-term derivative instruments | 0 | |||
Total current liabilities | 118,935 | 87,426 | ||
Long-term debt | 0 | |||
Asset retirement obligations | 10,079 | 9,830 | ||
Long-term derivative instruments | 0 | |||
Deferred tax liabilities | 170,979 | 45,122 | ||
Other long-term liabilities | 0 | |||
Total liabilities | 299,993 | 142,378 | ||
Equity: | ||||
Equity | 1,482,450 | 965,311 | ||
Noncontrolling interests | 0 | |||
Total equity | 1,482,450 | 965,311 | ||
Total liabilities and equity | 1,782,443 | 1,107,689 | ||
Non-Guarantor Subsidiaries [Member] | ||||
Current assets: | ||||
Cash and cash equivalents | 599 | 970 | $ 29,102 | $ 30,768 |
Accounts receivable - trade | 60,238 | 83,346 | ||
Accounts receivable - affiliates | 0 | 28 | ||
Short-term derivative instruments | 272,320 | 208,585 | ||
Prepaid expenses and other current assets | 7,029 | 11,032 | ||
Total current assets | 340,186 | 303,961 | ||
Carrying value of properties after impairment charges | 1,946,323 | 2,470,333 | ||
Long-term derivative instruments | 461,809 | 311,802 | ||
Investments in subsidiaries | 0 | |||
Other long-term assets | 157,684 | 82,424 | ||
Total assets | 2,906,002 | 3,168,520 | ||
Current liabilities: | ||||
Accounts payable and accrued liabilities | 61,715 | 113,177 | ||
Accounts payable - affiliates | 3,339 | 6,409 | ||
Revenues payable | 25,504 | 30,110 | ||
Short-term derivative instruments | 2,850 | 3,289 | ||
Total current liabilities | 93,408 | 152,985 | ||
Long-term debt | 2,000,579 | 1,574,147 | ||
Asset retirement obligations | 162,989 | 112,701 | ||
Long-term derivative instruments | 1,441 | |||
Deferred tax liabilities | 2,094 | 32,393 | ||
Other long-term liabilities | 0 | |||
Total liabilities | 2,260,511 | 1,872,226 | ||
Equity: | ||||
Equity | 645,491 | 1,290,734 | ||
Noncontrolling interests | 0 | 5,560 | ||
Total equity | 645,491 | 1,296,294 | ||
Total liabilities and equity | 2,906,002 | 3,168,520 | ||
Eliminations [Member] | ||||
Current assets: | ||||
Cash and cash equivalents | (1,410) | (1,015) | ||
Accounts receivable - trade | (3,530) | (2,717) | ||
Accounts receivable - affiliates | (9,525) | (10,075) | ||
Short-term derivative instruments | 0 | |||
Prepaid expenses and other current assets | 0 | |||
Total current assets | (14,465) | (13,807) | ||
Carrying value of properties after impairment charges | 0 | |||
Long-term derivative instruments | 0 | |||
Investments in subsidiaries | (1,482,847) | (1,139,792) | ||
Other long-term assets | 0 | |||
Total assets | (1,497,312) | (1,153,599) | ||
Current liabilities: | ||||
Accounts payable and accrued liabilities | (2,142) | (3,125) | ||
Accounts payable - affiliates | (12,323) | (9,423) | ||
Revenues payable | 0 | |||
Short-term derivative instruments | 0 | |||
Total current liabilities | (14,465) | (12,548) | ||
Long-term debt | 0 | |||
Asset retirement obligations | 0 | |||
Long-term derivative instruments | 0 | |||
Deferred tax liabilities | 0 | |||
Other long-term liabilities | 0 | |||
Total liabilities | (14,465) | (12,548) | ||
Equity: | ||||
Equity | (2,127,941) | (2,256,045) | ||
Noncontrolling interests | 645,094 | 1,114,994 | ||
Total equity | (1,482,847) | (1,141,051) | ||
Total liabilities and equity | $ (1,497,312) | $ (1,153,599) |
Condensed Consolidating Fina116
Condensed Consolidating Financial Information - Condensed Consolidating Statements of Operations (Detail) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Revenues: | |||||||||||
Oil & natural gas sales | $ 729,464 | $ 970,747 | $ 610,992 | ||||||||
Other revenues | 2,725 | 4,378 | 3,075 | ||||||||
Total revenues | $ 175,868 | $ 199,737 | $ 176,743 | $ 179,841 | $ 250,431 | $ 265,296 | $ 254,777 | $ 204,621 | 732,189 | 975,125 | 614,067 |
Costs and expenses: | |||||||||||
Lease operating | 193,102 | 161,303 | 111,798 | ||||||||
Gathering, processing, and transportation | 107,493 | 77,848 | 42,721 | ||||||||
Gathering, processing, and transportation - affiliate | 25,403 | ||||||||||
Exploration | 11,286 | 16,603 | 2,356 | ||||||||
Taxes other than income | 40,724 | 45,751 | 27,146 | ||||||||
DD&A | 384,556 | 314,193 | 184,717 | ||||||||
Impairment of proved oil and natural gas properties | 616,784 | 432,116 | 6,600 | ||||||||
Incentive unit compensation expense | 35,142 | 943,949 | 43,279 | ||||||||
General and administrative | 102,959 | 87,673 | 82,079 | ||||||||
Accretion expense | 7,542 | 6,306 | 5,581 | ||||||||
(Gain) loss on commodity derivative instruments | (744,139) | (749,988) | (29,294) | ||||||||
(Gain) loss on sale of properties | (3,045) | 3,057 | (85,621) | ||||||||
Other, net | (665) | (12) | 649 | ||||||||
Total costs and expenses | 777,142 | 1,338,799 | 392,011 | ||||||||
Operating income (loss) | 150,764 | (40,429) | (126,790) | (28,498) | 444,776 | 174,201 | (993,256) | 10,605 | (44,953) | (363,674) | 222,056 |
Other income (expense): | |||||||||||
Interest expense, net | (154,128) | (133,833) | (69,250) | ||||||||
Loss on extinguishment of debt | 0 | (37,248) | |||||||||
Equity earnings from subsidiaries | 0 | (784) | |||||||||
Other, net | (979) | (337) | 145 | ||||||||
Total other income (expense) | (155,107) | (171,418) | (69,105) | ||||||||
Income (loss) before income taxes | (200,060) | (535,092) | 152,951 | ||||||||
Income tax benefit (expense) | (97,830) | (100,971) | (1,619) | ||||||||
Net income (loss) | (297,890) | (636,063) | 151,332 | ||||||||
Net income (loss) attributable to noncontrolling interest | 70,081 | (191,807) | (113,771) | (158,041) | 161,661 | 102,109 | (105,094) | (31,888) | (393,538) | 126,788 | 49,830 |
Net income (loss) attributable to Memorial Resource Development Corp. | $ 89,987 | $ (135,255) | $ (140,473) | $ (112,149) | $ 328,859 | $ 112,037 | $ (1,053,443) | $ (23,516) | 95,648 | (762,851) | 101,502 |
Parent [Member] | |||||||||||
Revenues: | |||||||||||
Oil & natural gas sales | 0 | ||||||||||
Other revenues | 0 | 5 | |||||||||
Total revenues | 0 | 5 | |||||||||
Costs and expenses: | |||||||||||
Lease operating | 0 | ||||||||||
Gathering, processing, and transportation | 0 | ||||||||||
Gathering, processing, and transportation - affiliate | 0 | ||||||||||
Exploration | 0 | ||||||||||
Taxes other than income | 3,833 | ||||||||||
DD&A | 4,191 | 1,133 | |||||||||
Impairment of proved oil and natural gas properties | 0 | ||||||||||
Incentive unit compensation expense | 35,142 | 111,866 | |||||||||
General and administrative | 43,624 | 13,232 | |||||||||
Accretion expense | 0 | ||||||||||
(Gain) loss on commodity derivative instruments | (281,250) | (277,129) | |||||||||
(Gain) loss on sale of properties | 0 | ||||||||||
Other, net | 0 | ||||||||||
Total costs and expenses | (194,460) | (150,898) | |||||||||
Operating income (loss) | 194,460 | 150,903 | |||||||||
Other income (expense): | |||||||||||
Interest expense, net | (39,308) | (19,532) | |||||||||
Loss on extinguishment of debt | (23,562) | ||||||||||
Equity earnings from subsidiaries | 16,434 | (809,017) | |||||||||
Other, net | (100) | ||||||||||
Total other income (expense) | (22,974) | (852,111) | |||||||||
Income (loss) before income taxes | 171,486 | (701,208) | |||||||||
Income tax benefit (expense) | (75,838) | (83,373) | |||||||||
Net income (loss) | 95,648 | (784,581) | |||||||||
Net income (loss) attributable to noncontrolling interest | 0 | ||||||||||
Net income (loss) attributable to Memorial Resource Development Corp. | 95,648 | (784,581) | |||||||||
Guarantor Subsidiaries [Member] | |||||||||||
Revenues: | |||||||||||
Oil & natural gas sales | 374,042 | 409,070 | 202,423 | ||||||||
Other revenues | 0 | 7 | |||||||||
Total revenues | 374,042 | 409,077 | 202,423 | ||||||||
Costs and expenses: | |||||||||||
Lease operating | 24,904 | 17,570 | 14,710 | ||||||||
Gathering, processing, and transportation | 72,555 | 45,956 | 17,666 | ||||||||
Gathering, processing, and transportation - affiliate | 25,403 | ||||||||||
Exploration | 8,969 | 13,853 | 1,034 | ||||||||
Taxes other than income | 11,063 | 12,610 | 7,869 | ||||||||
DD&A | 184,551 | 127,105 | 61,990 | ||||||||
Impairment of proved oil and natural gas properties | 0 | 24,576 | 128 | ||||||||
Incentive unit compensation expense | 0 | 831,060 | 14,353 | ||||||||
General and administrative | 2,664 | 25,277 | 31,674 | ||||||||
Accretion expense | 418 | 533 | 516 | ||||||||
(Gain) loss on commodity derivative instruments | 0 | 19,395 | (3,179) | ||||||||
(Gain) loss on sale of properties | (47) | 3,167 | 6,776 | ||||||||
Other, net | 0 | ||||||||||
Total costs and expenses | 330,480 | 1,121,102 | 153,537 | ||||||||
Operating income (loss) | 43,562 | (712,025) | 48,886 | ||||||||
Other income (expense): | |||||||||||
Interest expense, net | (88) | (30,751) | (24,895) | ||||||||
Loss on extinguishment of debt | (13,686) | ||||||||||
Equity earnings from subsidiaries | 0 | 71,222 | |||||||||
Other, net | (922) | 319 | 141 | ||||||||
Total other income (expense) | (1,010) | (44,118) | 46,468 | ||||||||
Income (loss) before income taxes | 42,552 | (756,143) | 95,354 | ||||||||
Income tax benefit (expense) | (24,167) | (19,028) | (164) | ||||||||
Net income (loss) | 18,385 | (775,171) | 95,190 | ||||||||
Net income (loss) attributable to noncontrolling interest | 0 | ||||||||||
Net income (loss) attributable to Memorial Resource Development Corp. | 18,385 | (775,171) | 95,190 | ||||||||
Non-Guarantor Subsidiaries [Member] | |||||||||||
Revenues: | |||||||||||
Oil & natural gas sales | 355,422 | 561,677 | 408,569 | ||||||||
Other revenues | 2,725 | 4,366 | 3,075 | ||||||||
Total revenues | 358,147 | 566,043 | 411,644 | ||||||||
Costs and expenses: | |||||||||||
Lease operating | 168,198 | 143,733 | 97,088 | ||||||||
Gathering, processing, and transportation | 34,938 | 31,892 | 25,055 | ||||||||
Gathering, processing, and transportation - affiliate | 0 | ||||||||||
Exploration | 2,317 | 2,750 | 1,322 | ||||||||
Taxes other than income | 25,828 | 33,141 | 19,277 | ||||||||
DD&A | 195,814 | 185,955 | 122,727 | ||||||||
Impairment of proved oil and natural gas properties | 616,784 | 407,540 | 6,472 | ||||||||
Incentive unit compensation expense | 0 | 1,023 | 28,926 | ||||||||
General and administrative | 56,671 | 49,164 | 50,405 | ||||||||
Accretion expense | 7,124 | 5,773 | 5,065 | ||||||||
(Gain) loss on commodity derivative instruments | (462,889) | (492,254) | (26,115) | ||||||||
(Gain) loss on sale of properties | (2,998) | (110) | (92,397) | ||||||||
Other, net | (665) | (12) | 649 | ||||||||
Total costs and expenses | 641,122 | 368,595 | 238,474 | ||||||||
Operating income (loss) | (282,975) | 197,448 | 173,170 | ||||||||
Other income (expense): | |||||||||||
Interest expense, net | (114,732) | (83,550) | (44,355) | ||||||||
Equity earnings from subsidiaries | 0 | ||||||||||
Other, net | 43 | (656) | 4 | ||||||||
Total other income (expense) | (114,689) | (84,206) | (44,351) | ||||||||
Income (loss) before income taxes | (397,664) | 113,242 | 128,819 | ||||||||
Income tax benefit (expense) | 2,175 | 1,430 | (1,455) | ||||||||
Net income (loss) | (395,489) | 114,672 | 127,364 | ||||||||
Net income (loss) attributable to noncontrolling interest | 386 | 32 | 267 | ||||||||
Net income (loss) attributable to Memorial Resource Development Corp. | (395,875) | 114,640 | 127,097 | ||||||||
Eliminations [Member] | |||||||||||
Revenues: | |||||||||||
Oil & natural gas sales | 0 | ||||||||||
Other revenues | 0 | ||||||||||
Total revenues | 0 | ||||||||||
Costs and expenses: | |||||||||||
Lease operating | 0 | ||||||||||
Gathering, processing, and transportation | 0 | ||||||||||
Gathering, processing, and transportation - affiliate | 0 | ||||||||||
Exploration | 0 | ||||||||||
Taxes other than income | 0 | ||||||||||
DD&A | 0 | ||||||||||
Impairment of proved oil and natural gas properties | 0 | ||||||||||
Incentive unit compensation expense | 0 | ||||||||||
General and administrative | 0 | ||||||||||
Accretion expense | 0 | ||||||||||
(Gain) loss on commodity derivative instruments | 0 | ||||||||||
(Gain) loss on sale of properties | 0 | ||||||||||
Other, net | 0 | ||||||||||
Total costs and expenses | 0 | ||||||||||
Operating income (loss) | 0 | ||||||||||
Other income (expense): | |||||||||||
Interest expense, net | 0 | ||||||||||
Equity earnings from subsidiaries | (16,434) | 809,017 | (71,222) | ||||||||
Other, net | 0 | ||||||||||
Total other income (expense) | (16,434) | 809,017 | (71,222) | ||||||||
Income (loss) before income taxes | (16,434) | 809,017 | (71,222) | ||||||||
Income tax benefit (expense) | 0 | ||||||||||
Net income (loss) | (16,434) | 809,017 | (71,222) | ||||||||
Net income (loss) attributable to noncontrolling interest | (393,924) | 126,756 | 49,563 | ||||||||
Net income (loss) attributable to Memorial Resource Development Corp. | $ 377,490 | $ 682,261 | $ (120,785) |
Condensed Consolidating Fina117
Condensed Consolidating Financial Information - Condensed Consolidating Statements of Cash Flows (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Cash flows from operating activities: | |||
Net cash provided by (used in) operating activities | $ 633,911 | $ 476,271 | $ 277,823 |
Cash flows from investing activities: | |||
Acquisitions of oil and natural gas properties | (382,696) | (1,177,670) | (105,762) |
Additions to oil and gas properties | (836,200) | (674,396) | (360,015) |
Additions to other property and equipment | (3,789) | (17,067) | (2,670) |
Additions to restricted investments | (5,690) | (3,976) | (5,361) |
Other financial instruments | (46,106) | ||
Deposits for property acquisitions | 0 | (215) | |
Investments in subsidiaries | 0 | ||
Distributions from subsidiaries | 0 | ||
Decrease (increase) in restricted cash | 0 | 49,946 | (49,347) |
Proceeds from the sale of oil and gas properties | 14,192 | 6,700 | 155,712 |
Other | 0 | (301) | |
Net cash used in investing activities | (1,260,289) | (1,816,979) | (367,443) |
Cash flows from financing activities: | |||
Advances on revolving credit facilities | 1,360,000 | 2,746,800 | 1,132,755 |
Payments on revolving credit facilities | (696,000) | (2,457,900) | (1,766,037) |
Termination of second lien credit facility | 0 | (328,282) | |
Borrowings under second lien credit facility | 0 | 325,000 | |
Proceeds from the issuance of senior notes | 0 | 1,092,425 | 1,031,563 |
Redemption of senior notes | (2,914) | (351,808) | |
Deferred financing costs | (1,839) | (30,334) | (41,175) |
Repurchases of equity | (106,666) | ||
Purchase of additional interests in consolidated subsidiaries | (5,946) | (3,292) | (15,135) |
Capital contributions | 0 | ||
Proceeds from changes in ownership interests in MEMP | 0 | 135,012 | |
Distributions to the Funds | 0 | (732,362) | |
Contributions from previous owners | 0 | 1,214 | |
Distributions to noncontrolling interests | (163,007) | (149,084) | (78,083) |
Distributions made by previous owners | 0 | (4,005) | |
Cash retained by previous owners | 0 | (7,909) | |
Other | 0 | 320 | 455 |
Net cash provided by financing activities | 622,595 | 1,268,945 | 117,950 |
Net change in cash and cash equivalents | (3,783) | (71,763) | 28,330 |
Cash and cash equivalents, beginning of period | 5,958 | 77,721 | 49,391 |
Cash and cash equivalents, end of period | 2,175 | 5,958 | 77,721 |
Parent [Member] | |||
Cash flows from operating activities: | |||
Net cash provided by (used in) operating activities | 45,528 | (72,612) | |
Cash flows from investing activities: | |||
Acquisitions of oil and natural gas properties | 0 | ||
Additions to oil and gas properties | 0 | ||
Additions to other property and equipment | (3,401) | (15,980) | |
Additions to restricted investments | 0 | ||
Other financial instruments | (46,106) | ||
Deposits for property acquisitions | 0 | ||
Investments in subsidiaries | (499,336) | (696,489) | |
Distributions from subsidiaries | 78,648 | 15,140 | |
Proceeds from the sale of oil and gas properties | 0 | ||
Net cash used in investing activities | (470,195) | (697,329) | |
Cash flows from financing activities: | |||
Advances on revolving credit facilities | 798,000 | 1,174,000 | |
Payments on revolving credit facilities | (558,000) | (991,000) | |
Proceeds from the issuance of senior notes | 600,000 | ||
Redemption of senior notes | 0 | (351,808) | |
Deferred financing costs | (1,498) | (18,779) | |
Repurchases of equity | (51,197) | ||
Purchase of additional interests in consolidated subsidiaries | 0 | (3,292) | |
Capital contributions | 0 | ||
Distributions to the Funds | 0 | ||
Distributions to noncontrolling interests | 0 | ||
Other | 302 | ||
Net cash provided by financing activities | 425,412 | 772,182 | |
Net change in cash and cash equivalents | 745 | 2,241 | |
Cash and cash equivalents, beginning of period | 2,241 | ||
Cash and cash equivalents, end of period | 2,986 | 2,241 | |
Guarantor Subsidiaries [Member] | |||
Cash flows from operating activities: | |||
Net cash provided by (used in) operating activities | 372,028 | 297,490 | 93,864 |
Cash flows from investing activities: | |||
Acquisitions of oil and natural gas properties | (291,536) | (93,909) | (67,098) |
Additions to oil and gas properties | (594,902) | (376,123) | (164,850) |
Additions to other property and equipment | (388) | (989) | (2,432) |
Additions to restricted investments | 0 | ||
Other financial instruments | 0 | ||
Deposits for property acquisitions | 0 | (215) | |
Investments in subsidiaries | 0 | (93,433) | |
Distributions from subsidiaries | 0 | 74,424 | 273,694 |
Decrease (increase) in restricted cash | 49,946 | (49,347) | |
Proceeds from the sale of oil and gas properties | 13,612 | 33,152 | |
Net cash used in investing activities | (873,214) | (346,866) | (70,314) |
Cash flows from financing activities: | |||
Advances on revolving credit facilities | 0 | 126,800 | 174,400 |
Payments on revolving credit facilities | 0 | (329,900) | (200,500) |
Termination of second lien credit facility | (328,282) | ||
Borrowings under second lien credit facility | 325,000 | ||
Proceeds from the issuance of senior notes | 343,000 | ||
Redemption of senior notes | 0 | ||
Deferred financing costs | 0 | (61) | (20,250) |
Repurchases of equity | 0 | ||
Purchase of additional interests in consolidated subsidiaries | 0 | (15,135) | |
Capital contributions | 497,424 | 686,623 | |
Distributions to the Funds | 0 | (732,362) | |
Distribution to equity owners | (15,000) | ||
Distributions to noncontrolling interests | 0 | ||
Distributions made by previous owners | (2,590) | ||
Other | 18 | (129) | |
Net cash provided by financing activities | 497,424 | 4,519 | 6,446 |
Net change in cash and cash equivalents | (3,762) | (44,857) | 29,996 |
Cash and cash equivalents, beginning of period | 3,762 | 48,619 | 18,623 |
Cash and cash equivalents, end of period | 0 | 3,762 | 48,619 |
Non-Guarantor Subsidiaries [Member] | |||
Cash flows from operating activities: | |||
Net cash provided by (used in) operating activities | 216,750 | 251,393 | 183,959 |
Cash flows from investing activities: | |||
Acquisitions of oil and natural gas properties | (91,160) | (1,083,761) | (38,664) |
Additions to oil and gas properties | (241,298) | (298,273) | (195,165) |
Additions to other property and equipment | 0 | (98) | (238) |
Additions to restricted investments | (5,690) | (3,976) | (5,361) |
Other financial instruments | 0 | ||
Deposits for property acquisitions | 0 | ||
Investments in subsidiaries | 0 | ||
Distributions from subsidiaries | 0 | ||
Proceeds from the sale of oil and gas properties | 580 | 6,700 | 122,560 |
Other | (301) | ||
Net cash used in investing activities | (337,568) | (1,379,709) | (116,868) |
Cash flows from financing activities: | |||
Advances on revolving credit facilities | 562,000 | 1,446,000 | 958,355 |
Payments on revolving credit facilities | (138,000) | (1,137,000) | (1,565,537) |
Proceeds from the issuance of senior notes | 492,425 | 688,563 | |
Redemption of senior notes | (2,914) | ||
Deferred financing costs | (341) | (11,494) | (20,925) |
Repurchases of equity | (55,469) | ||
Purchase of additional interests in consolidated subsidiaries | (5,946) | ||
Capital contributions | 1,912 | 9,866 | 93,433 |
Distributions to the Funds | (163,259) | ||
Contributions from previous owners | 1,214 | ||
Distribution to equity owners | (222,633) | (351,777) | |
Distributions to noncontrolling interests | 0 | ||
Distributions made by previous owners | (1,415) | ||
Cash retained by previous owners | (7,909) | ||
Other | 584 | ||
Net cash provided by financing activities | 120,447 | 1,100,184 | (68,757) |
Net change in cash and cash equivalents | (371) | (28,132) | (1,666) |
Cash and cash equivalents, beginning of period | 970 | 29,102 | 30,768 |
Cash and cash equivalents, end of period | 599 | 970 | 29,102 |
Natural Gas Partners [Member] | |||
Cash flows from financing activities: | |||
Contribution to MEMP/Contributions from NGP affiliates related to sale of properties | 860 | 1,165 | 2,013 |
Distribution to NGP affiliates related to purchase of assets | 0 | (66,693) | (355,494) |
Distribution to NGP affiliates related to sale of assets, net of cash received | 0 | (32,770) | |
Natural Gas Partners [Member] | Guarantor Subsidiaries [Member] | |||
Cash flows from financing activities: | |||
Distribution to NGP affiliates related to purchase of assets | (63,389) | ||
Distribution to NGP affiliates related to sale of assets, net of cash received | (32,770) | ||
Natural Gas Partners [Member] | Non-Guarantor Subsidiaries [Member] | |||
Cash flows from financing activities: | |||
Contribution to MEMP/Contributions from NGP affiliates related to sale of properties | 1,165 | 2,013 | |
Distribution to NGP affiliates related to purchase of assets | (3,304) | (355,494) | |
MRD [Member] | |||
Cash flows from financing activities: | |||
Distribution to MRD Holdco | 0 | ||
MRD [Member] | Parent [Member] | |||
Cash flows from financing activities: | |||
Distribution to MRD Holdco | 0 | ||
MRD [Member] | Guarantor Subsidiaries [Member] | |||
Cash flows from financing activities: | |||
Distribution to MRD Holdco | 0 | ||
MRD [Member] | Non-Guarantor Subsidiaries [Member] | |||
Cash flows from financing activities: | |||
Distribution to MRD Holdco | (78,396) | ||
MRD Holdco LLC [Member] | |||
Cash flows from financing activities: | |||
Distribution to MRD Holdco | 0 | (59,803) | |
MRD Holdco LLC [Member] | Parent [Member] | |||
Cash flows from financing activities: | |||
Distribution to MRD Holdco | (17,207) | ||
MRD Holdco LLC [Member] | Guarantor Subsidiaries [Member] | |||
Cash flows from financing activities: | |||
Distribution to MRD Holdco | (39,520) | ||
MRD Holdco LLC [Member] | Non-Guarantor Subsidiaries [Member] | |||
Cash flows from financing activities: | |||
Distribution to MRD Holdco | (3,076) | ||
Eliminations [Member] | |||
Cash flows from operating activities: | |||
Net cash provided by (used in) operating activities | (395) | ||
Cash flows from investing activities: | |||
Acquisitions of oil and natural gas properties | 0 | ||
Additions to oil and gas properties | 0 | ||
Additions to other property and equipment | 0 | ||
Additions to restricted investments | 0 | ||
Other financial instruments | 0 | ||
Deposits for property acquisitions | 0 | ||
Investments in subsidiaries | 499,336 | 696,489 | 93,433 |
Distributions from subsidiaries | (78,648) | (89,564) | (273,694) |
Proceeds from the sale of oil and gas properties | 0 | ||
Net cash used in investing activities | 420,688 | 606,925 | (180,261) |
Cash flows from financing activities: | |||
Advances on revolving credit facilities | 0 | ||
Payments on revolving credit facilities | 0 | ||
Redemption of senior notes | 0 | ||
Deferred financing costs | 0 | ||
Repurchases of equity | 0 | ||
Purchase of additional interests in consolidated subsidiaries | 0 | ||
Capital contributions | (499,336) | (696,489) | (93,433) |
Distributions to the Funds | 163,259 | ||
Distribution to equity owners | 237,633 | 351,777 | |
Distributions to noncontrolling interests | (163,007) | (149,084) | (78,083) |
Net cash provided by financing activities | (420,688) | (607,940) | 180,261 |
Net change in cash and cash equivalents | (395) | (1,015) | |
Cash and cash equivalents, beginning of period | (1,015) | ||
Cash and cash equivalents, end of period | (1,410) | (1,015) | |
Eliminations [Member] | MRD [Member] | |||
Cash flows from financing activities: | |||
Distribution to MRD Holdco | 78,396 | ||
MRD Segment [Member] | |||
Cash flows from financing activities: | |||
Proceeds from MRD equity offering | 242,880 | 408,500 | |
Costs incurred in conjunction with equity offering | (4,773) | (28,373) | |
Repurchases of equity | (51,197) | (161) | |
MRD Segment [Member] | Parent [Member] | |||
Cash flows from financing activities: | |||
Proceeds from MRD equity offering | 242,880 | 408,500 | |
Costs incurred in conjunction with equity offering | (4,773) | (28,373) | |
Repurchases of equity | (161) | ||
MRD Segment [Member] | Guarantor Subsidiaries [Member] | |||
Cash flows from financing activities: | |||
Proceeds from MRD equity offering | 0 | ||
Costs incurred in conjunction with equity offering | 0 | ||
MRD Segment [Member] | Non-Guarantor Subsidiaries [Member] | |||
Cash flows from financing activities: | |||
Proceeds from MRD equity offering | 0 | ||
Costs incurred in conjunction with equity offering | 0 | ||
MRD Segment [Member] | Eliminations [Member] | |||
Cash flows from financing activities: | |||
Proceeds from MRD equity offering | 0 | ||
Costs incurred in conjunction with equity offering | 0 | ||
MEMP [Member] | |||
Cash flows from financing activities: | |||
Costs incurred in conjunction with equity offering | 0 | (12,510) | (21,066) |
Proceeds from MEMP equity offering | 0 | 553,288 | 511,204 |
Repurchases of equity | (54,184) | (11,531) | |
Restricted units returned to plan | (1,285) | (1,012) | |
Contribution to MEMP/Contributions from NGP affiliates related to sale of properties | 860 | ||
Proceeds from changes in ownership interests in MEMP | 135,012 | ||
MEMP [Member] | Parent [Member] | |||
Cash flows from financing activities: | |||
Contribution to MEMP/Contributions from NGP affiliates related to sale of properties | 0 | ||
MEMP [Member] | Guarantor Subsidiaries [Member] | |||
Cash flows from financing activities: | |||
Contribution to MEMP/Contributions from NGP affiliates related to sale of properties | 0 | ||
Proceeds from changes in ownership interests in MEMP | 135,012 | ||
MEMP [Member] | Non-Guarantor Subsidiaries [Member] | |||
Cash flows from financing activities: | |||
Costs incurred in conjunction with equity offering | (12,510) | (21,066) | |
Proceeds from MEMP equity offering | 553,288 | $ 511,204 | |
Repurchases of equity | (11,531) | ||
Restricted units returned to plan | $ (1,012) | ||
Contribution to MEMP/Contributions from NGP affiliates related to sale of properties | 860 | ||
MEMP [Member] | Eliminations [Member] | |||
Cash flows from financing activities: | |||
Contribution to MEMP/Contributions from NGP affiliates related to sale of properties | $ 0 |
Quarterly Financial Informat118
Quarterly Financial Information (Unaudited) - Schedule of Quarterly Financial Information (Detail) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |||
Quarterly Financial Data [Abstract] | |||||||||||||
Revenues | $ 175,868 | $ 199,737 | $ 176,743 | $ 179,841 | $ 250,431 | $ 265,296 | $ 254,777 | $ 204,621 | $ 732,189 | $ 975,125 | $ 614,067 | ||
Operating income (loss) | 150,764 | (40,429) | (126,790) | (28,498) | 444,776 | 174,201 | (993,256) | 10,605 | (44,953) | (363,674) | 222,056 | ||
Net income (loss) | 89,987 | (135,255) | (140,473) | (112,149) | 328,859 | 112,037 | (1,053,443) | (23,516) | 95,648 | (762,851) | 101,502 | ||
Net income (loss) attributable to noncontrolling interest | 70,081 | (191,807) | (113,771) | (158,041) | 161,661 | 102,109 | (105,094) | (31,888) | (393,538) | 126,788 | 49,830 | ||
Net income (loss) attributable to Memorial Resource Development Corp. | 19,906 | 56,552 | (26,702) | 45,892 | 167,198 | 9,928 | (948,349) | 8,372 | |||||
Net income (loss) allocated to members | 13,358 | 6,947 | 0 | (20,305) | (90,712) | ||||||||
Net income (loss) allocated to previous owners | $ 1,425 | 0 | (1,425) | $ (10,790) | |||||||||
Net income (loss) available to common stockholders | $ 19,950 | $ 56,051 | $ (26,702) | $ 45,615 | $ 167,198 | $ 9,928 | $ (961,707) | $ 94,914 | $ (784,581) | ||||
Basic EPS | $ 0.10 | $ 0.29 | $ (0.14) | $ 0.24 | $ 0.87 | $ 0.05 | $ (5) | $ 0.49 | $ (4.08) | ||||
Diluted EPS | $ 0.10 | $ 0.29 | $ (0.14) | $ 0.24 | $ 0.87 | $ 0.05 | $ (5) | $ 0.49 | [1] | $ (4.08) | [1] | ||
[1] | The Company determines the more dilutive of either the two-class method or the treasury stock method for diluted EPS. The two-class method was more dilutive for each period presented. |
Capitalized Costs Relating to O
Capitalized Costs Relating to Oil and Natural Gas Producing Activities (Detail) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items] | |||
Evaluated oil and natural gas properties | $ 5,356,855 | $ 4,598,211 | $ 2,974,855 |
Support equipment and facilities | 210,595 | 198,088 | 16,030 |
Unevaluated oil and natural gas properties | 414,759 | 48,229 | 46,413 |
Accumulated depletion, depreciation, and amortization | (2,313,284) | (1,336,951) | (625,432) |
Subtotal | 3,668,925 | 3,507,577 | 2,411,866 |
MRD Segment [Member] | |||
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items] | |||
Evaluated oil and natural gas properties | 1,740,530 | 1,268,873 | 897,511 |
Support equipment and facilities | 4,719 | ||
Unevaluated oil and natural gas properties | 414,759 | 48,229 | 44,453 |
Accumulated depletion, depreciation, and amortization | (434,735) | (276,837) | (160,620) |
Subtotal | 1,725,273 | 1,040,265 | 781,344 |
MEMP [Member] | |||
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items] | |||
Evaluated oil and natural gas properties | 3,616,325 | 3,329,338 | 2,077,344 |
Support equipment and facilities | 205,876 | 198,088 | 16,030 |
Unevaluated oil and natural gas properties | 0 | 1,960 | |
Accumulated depletion, depreciation, and amortization | (1,878,549) | (1,060,114) | (464,812) |
Subtotal | $ 1,943,652 | $ 2,467,312 | $ 1,630,522 |
Costs Incurred for Property Acq
Costs Incurred for Property Acquisition, Exploration and Development (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | |||
Property acquisition costs, proved | $ 86,181 | $ 1,057,566 | $ 93,894 |
Property acquisition costs, unproved | 362,240 | 25,030 | 19,975 |
Exploration and extension well costs | 30,146 | 209,532 | 13,313 |
Development | 725,432 | 489,750 | 357,440 |
Subtotal | 1,203,999 | 1,781,878 | 484,622 |
MRD Segment [Member] | |||
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | |||
Property acquisition costs, proved | 8,347 | 74,490 | 56,108 |
Property acquisition costs, unproved | 360,353 | 24,310 | 19,975 |
Exploration and extension well costs | 28,068 | 209,532 | 13,313 |
Development | 492,191 | 181,026 | 191,350 |
Subtotal | 888,959 | 489,358 | 280,746 |
MEMP [Member] | |||
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | |||
Property acquisition costs, proved | 77,834 | 983,076 | 37,786 |
Property acquisition costs, unproved | 1,887 | 720 | |
Exploration and extension well costs | 2,078 | ||
Development | 233,241 | 308,724 | 166,090 |
Subtotal | $ 315,040 | $ 1,292,520 | $ 203,876 |
Weighted Average Product Price
Weighted Average Product Price (Detail) | 12 Months Ended | |||
Dec. 31, 2015$ / MMBTU$ / bbl | Dec. 31, 2014$ / MMBTU$ / bbl | Dec. 31, 2013$ / MMBTU$ / bbl | ||
Oil [Member] | West Texas Intermediate [Member] | ||||
Supplemental Oil And Gas Reserve Information [Line Items] | ||||
Price | [1] | 46.79 | 91.48 | 93.42 |
Natural Gas Liquids [Member] | West Texas Intermediate [Member] | ||||
Supplemental Oil And Gas Reserve Information [Line Items] | ||||
Price | [1] | 46.79 | 91.48 | 93.42 |
Natural Gas [Member] | Henry Hub [Member] | ||||
Supplemental Oil And Gas Reserve Information [Line Items] | ||||
Price | $ / MMBTU | [2] | 2.59 | 4.35 | 3.67 |
[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, 2015MMcfeMBblsMMcf | Dec. 31, 2014MMcfeMBblsMMcf | Dec. 31, 2013MMcfeMBblsMMcf | ||||
MRD Segment [Member] | Oil [Member] | ||||||
Proved developed and undeveloped reserves: | ||||||
Beginning of the year | 11,915 | 10,824 | [1] | 10,220 | ||
Extensions and discoveries | 1,111 | 1,825 | 1,635 | |||
Purchase of minerals in place | 535 | 269 | 211 | |||
Production | (1,331) | (908) | (631) | |||
Sales of minerals in place | (407) | (623) | (599) | |||
Revision of previous estimates | 1,331 | 528 | (12) | |||
End of year | 13,154 | 11,915 | 10,824 | [1] | ||
Proved developed reserves: | ||||||
Beginning of year | 3,708 | 3,238 | 2,813 | |||
End of year | 6,101 | 3,708 | 3,238 | |||
Proved undeveloped reserves: | ||||||
Beginning of year | 8,207 | 7,586 | 7,407 | |||
End of year | 7,053 | 8,207 | 7,586 | |||
MRD Segment [Member] | Natural Gas [Member] | ||||||
Proved developed and undeveloped reserves: | ||||||
Beginning of the year | MMcf | 1,013,340 | 671,485 | [1] | 549,449 | ||
Extensions and discoveries | MMcf | 50,343 | 183,467 | 105,289 | |||
Purchase of minerals in place | MMcf | 17,508 | 22,186 | 31,815 | |||
Production | MMcf | (98,269) | (56,574) | (28,729) | |||
Sales of minerals in place | MMcf | (39,272) | (10,815) | (14,137) | |||
Revision of previous estimates | MMcf | 30,164 | 203,591 | 27,798 | |||
End of year | MMcf | 973,814 | 1,013,340 | 671,485 | [1] | ||
Proved developed reserves: | ||||||
Beginning of year | MMcf | 355,331 | 223,362 | 180,523 | |||
End of year | MMcf | 443,983 | 355,331 | 223,362 | |||
Proved undeveloped reserves: | ||||||
Beginning of year | MMcf | 658,009 | 448,123 | 368,926 | |||
End of year | MMcf | 529,831 | 658,009 | 448,123 | |||
MRD Segment [Member] | Natural Gas Liquids [Member] | ||||||
Proved developed and undeveloped reserves: | ||||||
Beginning of the year | 53,033 | 35,628 | [1] | 31,264 | ||
Extensions and discoveries | 2,741 | 9,876 | 5,712 | |||
Purchase of minerals in place | 969 | 1,247 | 1,017 | |||
Production | (3,249) | (1,863) | (1,282) | |||
Sales of minerals in place | (358) | (950) | (1,573) | |||
Revision of previous estimates | 1,024 | 9,095 | 490 | |||
End of year | 54,160 | 53,033 | 35,628 | [1] | ||
Proved developed reserves: | ||||||
Beginning of year | 18,203 | 12,226 | 10,208 | |||
End of year | 24,583 | 18,203 | 12,226 | |||
Proved undeveloped reserves: | ||||||
Beginning of year | 34,830 | 23,402 | 21,056 | |||
End of year | 29,577 | 34,830 | 23,402 | |||
MRD Segment [Member] | Natural Gas Equivalent [Member] | ||||||
Proved developed and undeveloped reserves: | ||||||
Beginning of the year | MMcfe | 1,403,030 | 950,199 | [1] | 798,357 | ||
Extensions and discoveries | MMcfe | 73,456 | 253,670 | 149,369 | |||
Purchase of minerals in place | MMcfe | 26,532 | 31,283 | 39,183 | |||
Production | MMcfe | (125,749) | (73,200) | (40,212) | |||
Sales of minerals in place | MMcfe | (43,861) | (20,253) | (27,169) | |||
Revision of previous estimates | MMcfe | 44,286 | 261,331 | 30,671 | |||
End of year | MMcfe | 1,377,694 | 1,403,030 | 950,199 | [1] | ||
Proved developed reserves: | ||||||
Beginning of year | MMcfe | 486,793 | 316,154 | 258,651 | |||
End of year | MMcfe | 628,081 | 486,793 | 316,154 | |||
Proved undeveloped reserves: | ||||||
Beginning of year | MMcfe | 916,237 | 634,045 | 539,706 | |||
End of year | MMcfe | 749,613 | 916,237 | 634,045 | |||
MEMP [Member] | Oil [Member] | ||||||
Proved developed and undeveloped reserves: | ||||||
Beginning of the year | 100,258 | [2] | 39,635 | [3] | 40,822 | |
Extensions and discoveries | 2,319 | 849 | 5,814 | |||
Purchase of minerals in place | 10,132 | 69,095 | 119 | |||
Production | (4,087) | (3,135) | (1,797) | |||
Sales of minerals in place | (380) | |||||
Revision of previous estimates | (17,297) | (6,186) | (5,323) | |||
End of year | 90,945 | [4] | 100,258 | [2] | 39,635 | [3] |
Proved developed reserves: | ||||||
Beginning of year | 54,723 | 22,429 | 24,784 | |||
End of year | 50,817 | 54,723 | 22,429 | |||
Proved undeveloped reserves: | ||||||
Beginning of year | 45,535 | 17,206 | 17,206 | |||
End of year | 40,128 | 45,535 | 17,206 | |||
MEMP [Member] | Natural Gas [Member] | ||||||
Proved developed and undeveloped reserves: | ||||||
Beginning of the year | MMcf | 727,216 | [2] | 737,908 | [3] | 794,369 | |
Extensions and discoveries | MMcf | 8,686 | 12,783 | 85,455 | |||
Purchase of minerals in place | MMcf | 34,128 | 13,036 | 16,294 | |||
Production | MMcf | (50,875) | (48,721) | (41,287) | |||
Sales of minerals in place | MMcf | (13,731) | |||||
Revision of previous estimates | MMcf | (243,898) | 12,210 | (116,923) | |||
End of year | MMcf | 461,526 | [4] | 727,216 | [2] | 737,908 | [3] |
Proved developed reserves: | ||||||
Beginning of year | MMcf | 417,247 | 427,983 | 441,858 | |||
End of year | MMcf | 311,147 | 417,247 | 427,983 | |||
Proved undeveloped reserves: | ||||||
Beginning of year | MMcf | 309,969 | 309,925 | 309,925 | |||
End of year | MMcf | 150,379 | 309,969 | 309,925 | |||
MEMP [Member] | Natural Gas Liquids [Member] | ||||||
Proved developed and undeveloped reserves: | ||||||
Beginning of the year | 59,034 | [2] | 35,794 | [3] | 39,554 | |
Extensions and discoveries | 558 | 711 | 4,353 | |||
Purchase of minerals in place | 367 | 22,351 | 258 | |||
Production | (2,820) | (2,498) | (1,806) | |||
Sales of minerals in place | (758) | |||||
Revision of previous estimates | (12,986) | 2,676 | (6,565) | |||
End of year | 43,395 | [4] | 59,034 | [2] | 35,794 | [3] |
Proved developed reserves: | ||||||
Beginning of year | 37,260 | 17,637 | 18,060 | |||
End of year | 30,315 | 37,260 | 17,637 | |||
Proved undeveloped reserves: | ||||||
Beginning of year | 21,774 | 18,157 | 18,157 | |||
End of year | 13,080 | 21,774 | 18,157 | |||
MEMP [Member] | Natural Gas Equivalent [Member] | ||||||
Proved developed and undeveloped reserves: | ||||||
Beginning of the year | MMcfe | 1,682,960 | [2] | 1,190,484 | [3] | 1,276,625 | |
Extensions and discoveries | MMcfe | 25,950 | 22,145 | 146,463 | |||
Purchase of minerals in place | MMcfe | 97,122 | 561,713 | 18,554 | |||
Production | MMcfe | (92,315) | (82,520) | (62,907) | |||
Sales of minerals in place | MMcfe | (20,559) | |||||
Revision of previous estimates | MMcfe | (425,587) | (8,862) | (188,251) | |||
End of year | MMcfe | 1,267,571 | [4] | 1,682,960 | [2] | 1,190,484 | [3] |
Proved developed reserves: | ||||||
Beginning of year | MMcfe | 969,141 | 668,381 | 698,922 | |||
End of year | MMcfe | 797,936 | 969,141 | 668,381 | |||
Proved undeveloped reserves: | ||||||
Beginning of year | MMcfe | 713,819 | 522,103 | 522,103 | |||
End of year | MMcfe | 469,635 | 713,819 | 522,103 | |||
[1] | Includes reserves of 41,077 MMcfe attributable to noncontrolling interests and the MRD Segment previous owners. | |||||
[2] | (1) MRD Segment’s share of these reserves is 230,503 MMcfe. | |||||
[3] | MRD Segment’s share of these reserves is 265,216 MMcfe. | |||||
[4] | (1) MRD Segment’s share of these reserves is 1,268 MMcfe. |
Reserve Quantity Information (P
Reserve Quantity Information (Parenthetical) (Detail) - Natural Gas Equivalent [Member] - MMcfe | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
MRD Segment [Member] | |||||
Reserve Quantities [Line Items] | |||||
End of year | 1,377,694 | 1,403,030 | 950,199 | [1] | 798,357 |
Parent [Member] | MRD Segment [Member] | |||||
Reserve Quantities [Line Items] | |||||
End of year | 1,268 | 230,503 | 265,216 | ||
Noncontrolling Interest [Member] | |||||
Reserve Quantities [Line Items] | |||||
End of year | 41,077 | ||||
[1] | Includes reserves of 41,077 MMcfe attributable to noncontrolling interests and the MRD Segment previous owners. |
Supplemental Oil And Gas Inf124
Supplemental Oil And Gas Information - Additional Information (Detail) - Bcfe | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
MRD Segment [Member] | |||
Reserve Quantities [Line Items] | |||
Upward revisions in proved reserve | 233 | ||
Downward price revisions in proved reserve | 189 | ||
Decrease in reserve | 166 | ||
Reclassification of proved undeveloped resources to proved developed | 231 | ||
Upward revisions due to updated well performance data | 286 | ||
Downward revisions due to uneconomic vertical proved undeveloped reserve | 221 | ||
MRD Segment [Member] | Terryville Acquisition [Member] | |||
Reserve Quantities [Line Items] | |||
Extensions and discoveries | 149 | ||
MEMP [Member] | |||
Reserve Quantities [Line Items] | |||
Downward price revisions in proved reserve | 413 | ||
Multiple acquisitions | 97 | 562 | |
Reduction in reserves | 415 | ||
Downward revisions due to updated well performance data | 13 | ||
Terryville Acquisition [Member] | MRD Segment [Member] | |||
Reserve Quantities [Line Items] | |||
Upward revisions in proved reserve | 261 | ||
Extensions and discoveries | 74 | 254 | |
Multiple acquisitions | 27 | 31 | |
Divestiture of oil and gas properties in other noncore areas | 44 | ||
Wyoming Acquisition [Member] | MEMP [Member] | |||
Reserve Quantities [Line Items] | |||
Multiple acquisitions, Largest acquisition | 497 | ||
Eagle Ford Acquisition [Member] | MEMP [Member] | |||
Reserve Quantities [Line Items] | |||
Multiple acquisitions | 45 | ||
2015 Beta Acquisition [Member] | MEMP [Member] | |||
Reserve Quantities [Line Items] | |||
Multiple acquisitions, Largest acquisition | 59 |
Discounted Future Net Cash Flow
Discounted Future Net Cash Flows (Detail) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | ||||
MRD Segment [Member] | ||||||||
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items] | ||||||||
Future cash inflows | $ 4,008,764 | $ 7,314,745 | $ 4,942,687 | |||||
Future production costs | (1,438,531) | (1,020,599) | (1,343,252) | |||||
Future development costs | (784,003) | (1,209,907) | (1,137,429) | |||||
Future income tax expense | [1] | (88,723) | (1,669,356) | |||||
Future net cash flows for estimated timing of cash flows | 1,697,507 | 3,414,883 | 2,462,006 | |||||
10% annual discount for estimated timing of cash flows | (877,647) | (1,604,728) | (1,103,145) | |||||
Standardized measure of discounted future net cash flows | 819,860 | [2] | 1,810,155 | [2] | 1,358,861 | [2] | $ 1,138,271 | |
MEMP [Member] | ||||||||
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items] | ||||||||
Future cash inflows | 5,952,935 | 14,190,450 | 7,672,312 | |||||
Future production costs | (3,194,577) | (4,821,051) | (2,963,146) | |||||
Future development costs | (808,512) | (1,455,926) | (901,374) | |||||
Future income tax expense | 0 | (119,675) | ||||||
Future net cash flows for estimated timing of cash flows | [3] | 1,949,846 | 7,793,798 | 3,807,792 | ||||
10% annual discount for estimated timing of cash flows | (1,360,292) | (4,881,811) | (2,089,588) | |||||
Standardized measure of discounted future net cash flows | $ 589,554 | [4] | $ 2,911,987 | [4] | $ 1,718,204 | [4] | $ 1,772,240 | |
[1] | Our predecessor was a pass through entity and was subject to the Texas margin tax based on the taxable margin apportioned to Texas. However, due to immateriality, we have excluded the impact of this tax for the year ended December 31, 2013. | |||||||
[2] | Includes $63,422 attributable to both noncontrolling interests and the MRD Segment previous owners for the year ended December 31, 2013. | |||||||
[3] | MEMP is subject to the Texas margin tax based on the taxable margin apportioned to Texas. However, due to immateriality we have excluded the impact of this tax for the years ended December 31, 2015, 2014 and 2013. The taxes in 2014 relate to Classic since its reserves were attributable to a taxable entity for federal income tax purposes for the year ended December 31, 2014. | |||||||
[4] | MRD Segment’s share of the standardized measure of discounted future net cash flows was $589, $155,139 and $252,410 for the years ended December 31, 2015, 2014 and 2013, respectively. |
Discounted Future Net Cash F126
Discounted Future Net Cash Flows (Parenthetical) (Detail) - USD ($) $ in Thousands | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |||
MRD Segment [Member] | |||||||
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items] | |||||||
Standardized measure of discounted future net cash flows | $ 819,860 | [1] | $ 1,810,155 | [1] | $ 1,358,861 | [1] | $ 1,138,271 |
MRD Segment [Member] | Parent [Member] | |||||||
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items] | |||||||
Standardized measure of discounted future net cash flows | $ 589 | $ 155,139 | 252,410 | ||||
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 | ||||||
[1] | Includes $63,422 attributable to both noncontrolling interests and the MRD Segment previous owners for the year ended December 31, 2013. |
Summary of the Changes in the S
Summary of the Changes in the Standardized Measure of Future Net Cash Flows (Detail) - USD ($) $ in Thousands | 12 Months Ended | |||||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||||
MRD Segment [Member] | ||||||
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items] | ||||||
Beginning of year | $ 1,810,155 | [1] | $ 1,358,861 | [1] | $ 1,138,271 | |
Sale of oil and natural gas produced, net of production costs | (240,244) | (332,785) | (175,933) | |||
Purchase of minerals in place | 53,597 | 69,282 | 51,177 | |||
Sale of minerals in place | (41,543) | (47,791) | (54,091) | |||
Extensions and discoveries | 30,006 | 653,088 | 286,796 | |||
Changes in income taxes, net | 882,942 | (995,635) | ||||
Changes in prices and costs | (2,284,279) | 367,212 | (59,083) | |||
Previously estimated development costs incurred | 294,617 | 205,388 | 62,012 | |||
Net changes in future development costs | 190,403 | (68,079) | (1,295) | |||
Revisions of previous quantities | 51,455 | 713,176 | 45,183 | |||
Accretion of discount | 244,123 | 135,887 | 110,312 | |||
Change in production rates and other | (171,372) | (248,449) | (44,488) | |||
End of year | [1] | 819,860 | 1,810,155 | 1,358,861 | ||
MEMP [Member] | ||||||
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items] | ||||||
Beginning of year | 2,911,987 | [2] | 1,718,204 | [2] | 1,772,240 | |
Sale of oil and natural gas produced, net of production costs | (128,382) | (354,932) | (255,031) | |||
Purchase of minerals in place | 75,998 | 1,489,477 | 23,160 | |||
Sale of minerals in place | (45,100) | |||||
Extensions and discoveries | 18,582 | 44,843 | 150,631 | |||
Changes in income taxes, net | 63,180 | (63,180) | ||||
Changes in prices and costs | (2,764,481) | (170,682) | (26,648) | |||
Previously estimated development costs incurred | 322,446 | 275,078 | 199,775 | |||
Net changes in future development costs | 448,089 | (133,098) | (16,219) | |||
Revisions of previous quantities | (344,775) | (48,087) | (373,109) | |||
Accretion of discount | 297,517 | 171,820 | 177,223 | |||
Change in production rates and other | (265,507) | (17,456) | 66,182 | |||
End of year | [2] | $ 589,554 | $ 2,911,987 | $ 1,718,204 | ||
[1] | Includes $63,422 attributable to both noncontrolling interests and the MRD Segment previous owners for the year ended December 31, 2013. | |||||
[2] | MRD Segment’s share of the standardized measure of discounted future net cash flows was $589, $155,139 and $252,410 for the years ended December 31, 2015, 2014 and 2013, respectively. |