Memorial Resource Development 8-K 8 Jul 15 Management’s Discussion and Analysis of Financial Condition and Results of Operations Financial data

Document and Entity Information

Document and Entity Information	3 Months Ended
	Mar. 31, 2015
Document And Entity Information [Abstract]
Document Type	8-K
Amendment Flag	false
Document Period End Date	Mar. 31, 2015
Trading Symbol	MRD
Entity Registrant Name	MEMORIAL RESOURCE DEVELOPMENT CORP.
Entity Central Index Key	1,599,222
Entity Filer Category	Non-accelerated Filer

CONSOLIDATED AND COMBINED BALAN

CONSOLIDATED AND COMBINED BALANCE SHEETS - USD ($) $ in Thousands	Mar. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Current assets:
Cash and cash equivalents	$ 4,512	$ 5,958	$ 77,721
Restricted cash			35,000
Accounts receivable:
Oil and natural gas sales	61,649	82,263	68,764
Joint interest owners and other	56,750	49,313	19,958
Affiliates	1,976		4,652
Short-term derivative instruments	357,060	340,056	9,289
Prepaid expenses and other current assets	32,133	28,027	19,513
Total current assets	514,080	505,617	234,897
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method	5,014,671	4,844,529	3,037,298
Other	35,882	33,815	10,331
Accumulated depreciation, depletion and impairment	(1,683,953)	(1,340,688)	(627,925)
Property and equipment, net	3,366,600	3,537,656	2,419,704
Long-term derivative instruments	578,153	435,369	48,616
Restricted investments	78,787	77,361	73,385
Restricted cash		260	15,506
Other long-term assets		37,284	37,053
Total assets	4,574,222	4,593,547	2,829,161
Other long-term assets	36,602	37,544
Current liabilities:
Accounts payable	42,069	25,772	20,734
Accounts payable - affiliates		624	1,975
Revenues payable	58,331	57,352	56,091
Accrued liabilities	217,669	199,000	98,130
Short-term derivative instruments	3,300	3,289	9,711
Total current liabilities	321,369	286,037	186,641
Noncurrent liabilities:
Long-term debt	2,498,045	2,378,413	1,663,217
Asset retirement obligations	124,476	122,531	111,679
Long-term derivative instruments	555		6,080
Deferred tax liabilities	111,790	95,017	3,106
Other long-term liabilities	7,566	8,585	306
Total liabilities	$ 3,063,801	$ 2,890,583	$ 1,971,029
Commitments and contingencies (Note 16)
Stockholders' equity (deficit):
Preferred stock, value
Common stock, value	$ 1,908	$ 1,935
Additional paid-in capital	1,234,194	1,367,346
Accumulated earnings (deficit)	(788,736)	(786,871)
Total stockholders' equity	447,366	582,410	$ 277,517
Members' equity:
Members			237,186
Previous owners (Note 1)			40,331
Total members' equity			277,517
Noncontrolling interests	1,063,055	1,120,554	580,615
Total equity	1,510,421	1,702,964	858,132
Total liabilities and equity	4,574,222	4,593,547	2,829,161
MRD [Member]
Noncurrent liabilities:
Long-term debt	744,000	783,000	871,150
MEMP [Member]
Noncurrent liabilities:
Long-term debt	$ 1,754,045	1,595,413	$ 792,067
Deferred tax liabilities		$ 29,200

CONSOLIDATED AND COMBINED BALA3

CONSOLIDATED AND COMBINED BALANCE SHEETS (Parenthetical) - $ / shares	Mar. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
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	$ 0.01
Common stock, shares authorized	600,000,000	600,000,000	0
Common stock, shares issued	190,776,618	193,435,414	0
Common stock, shares outstanding	190,776,618	193,435,414	0

STATEMENTS OF CONSOLIDATED AND

STATEMENTS OF CONSOLIDATED AND COMBINED OPERATIONS - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenues:
Oil & natural gas sales	$ 178,972	$ 203,710	$ 894,967	$ 571,948	$ 393,631
Other revenues	869	911	4,378	3,075	3,237
Total revenues	179,841	204,621	899,345	575,023	396,868
Costs and expenses:
Lease operating	45,700	33,355	161,303	113,640	103,754
Gathering, processing, and transportation	22,983	14,120
Pipeline operating	446	489	2,068	1,835	2,114
Exploration	816	146	16,603	2,356	9,800
Production and ad valorem taxes	9,430	8,584	45,751	27,146	23,624
Depreciation, depletion, and amortization	91,798	57,679	314,193	184,717	138,672
Impairment of proved oil and natural gas properties	251,347		432,116	6,600	28,871
Incentive unit compensation expense	10,224	1,023	943,949	43,279	9,510
General and administrative	27,487	17,739	87,673	82,079	59,677
Accretion of asset retirement obligations	1,757	1,521	6,306	5,581	5,009
(Gain) loss on commodity derivative instruments	(253,649)	59,482	(749,988)	(29,294)	(34,905)
(Gain) loss on sale of properties		(110)	3,057	(85,621)	(9,761)
Other, net		(12)	(12)	649	502
Total costs and expenses	208,339	194,016	1,263,019	352,967	336,867
Operating income (loss)	(28,498)	10,605	(363,674)	222,056	60,001
Other income (expense):
Interest expense, net	(38,574)	(34,052)	(133,833)	(69,250)	(33,238)
Loss on extinguishment of debt			(37,248)	0	0
Amortization of investment premium			0	0	(194)
Other, net	111	31	(337)	145	535
Total other income (expense)	(38,463)	(34,021)	(171,418)	(69,105)	(32,897)
Income (loss) before income taxes	(66,961)	(23,416)	(535,092)	152,951	27,104
Income tax benefit (expense)	(45,188)	(100)	(100,971)	(1,619)	(107)
Net income (loss)	(112,149)	(23,516)	(636,063)	151,332	26,997
Net income (loss) attributable to noncontrolling interest	(158,041)	(31,888)	126,788	49,830	(2,701)
Net income (loss) attributable to Memorial Resource Development Corp.	45,892	8,372	(762,851)	101,502	29,698
Net (income) loss allocated to members		(6,947)	(20,305)	(90,712)	7,620
Net (income) loss allocated to previous owners		$ (1,425)	(1,425)	(10,790)	(37,318)
Net (income) allocated to participating restricted stockholders	(277)		0	0	0
Net income (loss) available to common stockholders	$ 45,615		$ (784,581)	$ 0	$ 0
Earnings per common share: (Note 10)
Basic	$ 0.24		$ (4.08)	$ 0	$ 0
Diluted	$ 0.24		$ (4.08)	$ 0	$ 0
Weighted average common and common equivalent shares outstanding:
Basic	190,705		192,498	0	0
Diluted	190,705		192,498	0	0

STATEMENTS OF CONSOLIDATED AND5

STATEMENTS OF CONSOLIDATED AND COMBINED CASH FLOWS - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Cash flows from operating activities:
Net income (loss)	$ (112,149)	$ (23,516)	$ (636,063)	$ 151,332	$ 26,997
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization	91,798	57,679	314,193	184,717	138,672
Impairment of proved oil and natural gas properties	251,347		432,116	6,600	28,871
(Gain) loss on derivatives	(251,208)	59,993	(749,843)	(29,533)	(29,323)
Cash settlements (paid) received on expired derivative instruments	91,985	(13,309)
Cash settlements (paid) received on derivative instruments			20,559	30,403	72,045
Cash settlements on terminated derivatives	27,063		5,326
Premiums paid for derivatives	(27,063)		(6,065)		(411)
Loss on extinguishment of debt			30,248
Amortization of deferred financing costs	2,515	1,899	7,436	8,343	3,584
Accretion of senior notes net discount	599	713	2,501	554
Amortization of investment premium			0	0	194
Accretion of asset retirement obligations	1,757	1,521	6,306	5,581	5,009
Amortization of equity awards	3,827	1,295	10,678	3,557	1,423
(Gain) loss on sale of properties		(110)	3,057	(85,621)	(9,761)
Non-cash compensation expense	10,224		916,218	1,057
Exploration costs			14,953	181	6,980
Deferred income tax expense (benefit)	43,188		100,230	76	(312)
Changes in operating assets and liabilities:
Accounts receivable	13,719	(3,951)	(17,635)	(15,758)	(7,382)
Prepaid expenses and other assets	(561)	2,832	(7,424)	(2,986)	(1,574)
Payables and accrued liabilities	25,875	18,895	21,208	19,320	5,392
Other	(1,100)		8,272
Net cash provided by operating activities	171,816	103,941	476,271	277,823	240,404
Cash flows from investing activities:
Acquisitions of oil and natural gas properties	(3,305)	(173,000)	(1,177,670)	(105,762)	(360,678)
Additions to oil and gas properties	(160,994)	(134,200)	(674,396)	(360,015)	(273,334)
Additions to other property and equipment	(1,947)	(31)	(17,067)	(2,670)	(2,674)
Additions to restricted investments	(1,426)	(826)	(3,976)	(5,361)	(4,599)
Deposits for property acquisitions			(215)
Decrease (increase) in restricted cash			49,946	(49,347)	(3)
Proceeds from the sale of oil and natural gas properties			6,700	155,712	34,521
Other		(304)	(301)		29
Net cash used in investing activities	(167,672)	(308,361)	(1,816,979)	(367,443)	(606,738)
Cash flows from financing activities:
Advances on revolving credit facilities	270,000	343,000	2,746,800	1,132,755	619,450
Payments on revolving credit facilities	(148,000)	(79,000)	(2,457,900)	(1,766,037)	(251,569)
Proceeds from the issuances of senior notes			1,092,425	1,031,563
Redemption of senior notes			(351,808)
Borrowings under second lien credit facility				325,000
Redemption of second lien credit facility			(328,282)
Deferred financing costs	(10)	(1,162)	(30,334)	(41,175)	(3,501)
Proceeds from changes in ownership interests in MEMP				135,012
Repurchased shares under repurchase program			(161)
Restricted MEMP units returned to plan			(1,012)
Purchase of additional interests in consolidated subsidiaries			(3,292)	(15,135)
Contributions from previous owners				1,214	44,072
Distributions to the Funds				(732,362)
Distributions to noncontrolling interests	(46,239)	(31,085)	(149,084)	(78,083)	(15,208)
Distributions made by previous owners				(4,005)	(28,772)
Cash retained by previous owners				(7,909)
Other	(7)	(7)	320	455
Net cash provided by financing activities	(5,590)	166,218	1,268,945	117,950	361,761
Net change in cash and cash equivalents	(1,446)	(38,202)	(71,763)	28,330	(4,573)
Cash and cash equivalents, beginning of period	5,958	77,721	77,721	49,391	53,964
Cash and cash equivalents, end of period	4,512	39,519	5,958	77,721	49,391
Supplemental cash flows:
Cash paid for interest, net of capitalized interest	39,203	8,838
Cash paid for taxes	2,055		838	168	22
Noncash investing and financing activities:
Change in capital expenditures in payables and accrued liabilities	4,589	10,668	31,771	41,017	17,158
Assumptions of asset retirement obligations related to properties acquired or drilled	39	433	5,420	4,227	7,962
Accounts receivable related to acquisitions and divestitures		3,879
Natural Gas Partners [Member]
Cash flows from financing activities:
Contributions from NGP affiliates related to sale of properties		1,165	1,165	2,013	45,158
Distribution to NGP affiliates related to purchase of assets		(66,693)	(66,693)	(355,494)	(242,174)
Distribution to NGP affiliates related to sale of assets, net of cash received		$ (66,693)	(32,770)
MRD Holdco LLC [Member]
Cash flows from financing activities:
Distributions to MRD Holdco			(59,803)
MEMP [Member]
Cash flows from financing activities:
Repayment of senior notes	(2,914)
Costs incurred in conjunction with initial public offering			(12,510)	(21,066)	(8,268)
Proceeds from MEMP public offering			553,288	$ 511,204	$ 202,573
Repurchased shares under repurchase program	(28,420)		(11,531)
MRD [Member]
Cash flows from financing activities:
Proceeds from initial public offering			408,500
Costs incurred in conjunction with initial public offering			(28,373)
Repurchased shares under repurchase program	$ (50,000)		$ (161)

STATEMENTS OF CONSOLIDATED AND6

STATEMENTS OF CONSOLIDATED AND COMBINED EQUITY - USD ($) $ in Thousands	Total	MEMP [Member]	MRD [Member]	Member Equity [Member]	Previous Owners [Member]Member Equity [Member]	Noncontrolling Interest [Member]	Noncontrolling Interest [Member]MEMP [Member]	Common Stock [Member]	Common Stock [Member]MRD [Member]	Additional Paid-in Capital [Member]	Accumulated earnings (deficit) [Member]	Accumulated earnings (deficit) [Member]MRD [Member]
Total equity, beginning balance at Dec. 31, 2011	$ 1,276,364
Noncontrolling interests, beginning balance at Dec. 31, 2011						$ 161,588
Members' equity, beginning balance at Dec. 31, 2011				$ 853,436	$ 261,340
Net income (loss)	26,997			(7,620)	37,318	(2,701)
Contributions	44,072				44,072
Contribution of oil and gas properties from NGP affiliate	6,893				6,893
Net proceeds from MEMP public equity Offering	194,134					194,134
Distributions	(44,027)				(28,772)	(15,255)
Net book value of net assets acquired from affiliates				52,217	(93,696)	41,479
Amortization of MEMP equity awards	1,423					1,423
Noncontrolling interest's share of net book value in excess of consideration received from sale of assets to MEMP				727		(727)
Contribution related to sale of assets to NGP affiliate	47,171			6,291	40,138	742
Net book value of assets acquired by NGP affiliate	(34,506)			(579)	(33,859)	(68)
Distribution to affiliate in connection with acquisition of assets	(242,174)			(134,964)		(107,210)
Impact of equity transactions of MEMP				41,930		(41,930)
Other	362			176	(1)	187
Total equity, ending balance at Dec. 31, 2012	1,276,709
Noncontrolling interests, ending balance at Dec. 31, 2012						231,662
Members' equity, ending balance at Dec. 31, 2012				811,614	233,433
Net income (loss)	151,332			90,712	10,790	49,830
Contributions	1,214				1,214
Net proceeds from MEMP public equity Offering	490,138					490,138
Sale of MEMP common units	135,012			60,701		74,311
Distributions	(814,450)			(732,362)	(4,005)	(78,083)
Net book value of net assets acquired from affiliates				50,751	(181,556)	130,805
Amortization of MEMP equity awards	3,558					3,558
Noncontrolling interest's share of cash consideration received in excess of the net book value sold to MEMP				(24)		24
Distribution to affiliate in connection with acquisition of assets	(351,235)			(98,180)		(253,055)
Purchase of noncontrolling interests	(15,135)			(303)		(14,832)
Impact of equity transactions of MEMP				54,183		(54,183)
Other	(1,765)			94	(2,299)	440
Net assets retained by previous owners	(17,246)				(17,246)
Total equity, ending balance at Dec. 31, 2013	858,132
Noncontrolling interests, ending balance at Dec. 31, 2013	580,615					580,615
Members' equity, ending balance at Dec. 31, 2013	277,517			237,186	40,331
Total stockholders equity, ending balance at Dec. 31, 2013	277,517
Net income (loss)	(23,516)			6,947	1,425	(31,888)
Amortization of MEMP equity awards	1,295					1,295
Contribution related to sale of assets to NGP affiliate	1,165			1,165
Net book value of assets sold to NGP affiliate	(621)			(621)
Net book value of assets acquired by NGP affiliate	3,303			45,059	(41,756)
Distribution to affiliate in connection with acquisition of assets	(66,693)			(66,693)
Other	333			(154)		487
Total equity, ending balance at Mar. 31, 2014	742,313
Noncontrolling interests, ending balance at Mar. 31, 2014						519,424
Members' equity, ending balance at Mar. 31, 2014				222,889
Distributions	(31,085)					(31,085)
Total equity, beginning balance at Dec. 31, 2013	858,132
Noncontrolling interests, beginning balance at Dec. 31, 2013	580,615					580,615
Members' equity, beginning balance at Dec. 31, 2013	277,517			237,186	40,331
Net income (loss)	(636,063)			20,305	1,425	126,788					$ (784,581)
Issuance of shares in connection with restructuring transactions (see Note 1)	914,862							$ 1,710		$ 913,152
Issuance of shares in connection with initial public offering (see Note 1)	380,177							215		379,962
Tax related effects in connection with restructuring transactions and initial public offering	(43,251)									(43,251)
Share repurchase	(2,215)	$ (12,903)	$ (2,215)				$ (12,903)		$ (1)			$ (2,214)
Restricted stock awards								11		(11)
Amortization of restricted stock awards	2,804									2,804
Contribution related to MRD Holdco incentive unit compensation expense (see Note 12)	111,866									111,866
Net proceeds from MEMP public equity Offering	540,698					540,698
Distributions	(149,084)					(149,084)
Net book value of net assets acquired from affiliates	3,303			45,059	$ (41,756)
Amortization of MEMP equity awards	7,874					7,874
Contribution related to sale of assets to NGP affiliate	1,165			1,165
Net book value of assets sold to NGP affiliate	(621)			(621)
Distribution to affiliate in connection with acquisition of assets	(66,693)			(66,693)
Purchase of noncontrolling interests	(3,292)					(411)				(2,881)
Distribution of net assets to MRD Holdco	(93,084)			(123,078)		29,994
Distribution of shares received in connection with restructuring transactions to MRD Holdco	(110,510)			(110,510)
Net equity deemed contribution (distribution) related to net assets transferred to MEMP				(2,659)		(2,668)				5,327
Other	811			$ (154)		663				378	(76)
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
Total stockholders equity, beginning balance at Dec. 31, 2013	277,517
MEMP restricted units repurchased	(1,012)					(1,012)
Total stockholders equity, ending balance at Dec. 31, 2014	582,410							1,935		1,367,346	(786,871)
Net income (loss)	(112,149)					(158,041)					45,892
Share repurchase	(47,785)	$ (28,420)					$ (28,420)	(28)			(47,757)
Restricted stock awards								1		(1)
Amortization of restricted stock awards	1,486									1,486
Contribution related to MRD Holdco incentive unit compensation expense (see Note 12)	10,224									10,224
Amortization of MEMP equity awards	2,341					2,341
Other	(14)					(2)				(12)
Total equity, ending balance at Mar. 31, 2015	1,510,421
Noncontrolling interests, ending balance at Mar. 31, 2015	1,063,055					1,063,055
MEMP restricted units repurchased	(7)					(7)
Total stockholders equity, ending balance at Mar. 31, 2015	447,366							$ 1,908		1,234,194	$ (788,736)
Net equity deemed contribution (distribution) related to MEMP property exchange (Note 1)						172,869				(172,869)
Deferred tax effect of MEMP property exchange (Note 2)	28,020									$ 28,020
Distributions	$ (46,239)					$ (46,239)

Organization and Basis of Prese

Organization and Basis of Presentation	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Organization and Basis of Presentation	Note 1. Background, 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. References to: (i) “Memorial Production Partners,” “MEMP” and “the Partnership” refer to Memorial Production Partners LP individually and collectively with its subsidiaries, as the context requires; (ii) “MEMP GP” refer to Memorial Production Partners GP LLC, the general partner of the Partnership, which we own; (iii) “MRD Holdco” refer to MRD Holdco LLC, a holding company controlled by the Funds (defined below) that, together as part of a group, owns a majority of our common stock; (iv) “MRD LLC” refer to Memorial Resource Development LLC, which historically owned our predecessor’s business and was merged into MRD Operating LLC (“MRD Operating”), our 100% owned subsidiary, subsequent to our initial public offering; (v) “WildHorse Resources” refer to WildHorse Resources, LLC, which owned our interest in the Terryville Complex and merged into MRD Operating in February 2015; (vi) “our predecessor” refer collectively to MRD LLC and its former consolidated subsidiaries, consisting of Classic Hydrocarbons Holdings, L.P., Classic Hydrocarbons GP Co., L.L.C., Black Diamond Minerals, LLC, Beta Operating Company, LLC, MEMP GP, BlueStone Natural Resources Holdings, LLC (“BlueStone”), MRD Operating, WildHorse Resources, Tanos Energy LLC and each of their respective subsidiaries, including MEMP and its subsidiaries; (vii) “the Funds” refer collectively to Natural Gas Partners VIII, L.P., Natural Gas Partners IX, L.P. and NGP IX Offshore Holdings, L.P., which collectively control MRD Holdco; and (viii) “NGP” refer to Natural Gas Partners, a family of private equity investment funds organized to make direct equity investments in the energy industry, including the Funds. Previous Owners References to “the previous owners” for accounting and financial reporting purposes refer to the 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 certain acquisitions in 2010, 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 unaudited financial statements reported herein include the financial position and results attributable to 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. All material intercompany transactions and balances have been eliminated in preparation of our consolidated and combined financial statements. Our results of operations for the three months ended March 31, 2015 are not necessarily indicative of results expected for the full year. In our opinion, the accompanying unaudited condensed consolidated and combined financial statements include all adjustments of a normal recurring nature necessary for fair presentation. Although we believe the disclosures in these financial statements are adequate and make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted pursuant to the rules and regulations of the United States Securities and Exchange Commission (“SEC”). We have two reportable business segments, both of which are engaged in the acquisition, exploration and development 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 acquisition by the MEMP Segment of certain assets from the MRD Segment in East Texas in February 2015 in exchange for approximately $78.0 million in cash and certain properties in North Louisiana (the “Property Swap”) for comparability purposes. Our equity statement reflects a $172.9 million equity transfer from stockholders’ equity to noncontrolling interest related to this transaction. This amount represents $250.8 million of net book value related to the assets transferred to MEMP allocated to its limited partners less $77.9 million of cash allocated to its limited partners. Amounts allocated to MEMP GP eliminate in consolidation. Use of Estimates The preparation of the accompanying unaudited condensed 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 compensation; fair values of assets acquired and liabilities assumed in business combinations and asset retirement obligations.	Note 1. Organization and Basis of Presentation Overview Memorial Resource Development Corp. (the “Company”) is a publicly traded Delaware corporation, the common shares of which are listed on the NASDAQ Global Market (“NASDAQ”) under the symbol “MRD.” Unless the context requires otherwise, references to “we,” “us,” “our,” “MRD,” or “the Company” are intended to mean the business and operations of Memorial Resource Development Corp. and its consolidated subsidiaries. The Company was formed by Memorial Resource Development LLC (“MRD LLC”) in January 2014 to acquire, explore and develop natural gas and oil properties in North America. MRD LLC was a Delaware limited liability company formed on April 27, 2011 by Natural Gas Partners VIII, L.P. (“NGP VIII”), Natural Gas Partners IX, L.P. (“NGP IX”) and NGP IX Offshore Holdings, L.P. (“NGP IX Offshore”) (collectively, the “Funds”) to explore, develop and acquire natural gas and oil properties. The Funds are private equity funds managed by Natural Gas Partners (“NGP”). MRD LLC’s consolidated and combined financial statements represent our predecessor for accounting and financial reporting purposes prior to our initial public offering. Initial Public Offering and Restructuring Transactions On June 18, 2014, the Company completed its initial public offering of 21,500,000 common units at a price of $19.00 per share, which generated net proceeds to the Company of approximately $380.2 million after deducting underwriting discounts and commissions and other offering related fees and expenses. The following restructuring events and transactions occurred in connection with our initial public offering: — The Funds contributed all of their interests in MRD LLC to MRD Holdco LLC (“MRD Holdco”) and the members of our management who owned incentive units in MRD LLC exchanged those incentive units for substantially identical incentive units in MRD Holdco, after which MRD Holdco owned 100% of MRD LLC; — WildHorse Resources, LLC (“WildHorse Resources”) sold its subsidiary, WildHorse Resources Management Company, LLC (“WHR Management Company”), to an affiliate of the Funds for approximately $0.2 million in cash, and WHR Management Company entered into a services agreement with the Company and WildHorse Resources pursuant to which WHR Management Company agreed to provide certain management services to WildHorse Resources, which was terminated as of March 1, 2015; — Classic Hydrocarbons Holdings, L.P. (“Classic”) and Classic Hydrocarbons GP Co., L.L.C. (“Classic GP”) distributed to MRD LLC the ownership interests in Classic Pipeline & Gathering, LLC (“Classic Pipeline”), which owns certain midstream assets in Texas, and Black Diamond Minerals, LLC (“Black Diamond”) distributed to MRD LLC its ownership interests in Golden Energy Partners LLC (“Golden Energy”), which sold all of its assets in May 2014; — MRD LLC contributed to us substantially all of its assets, comprised of: (i) 100% of the ownership interests in Classic, Classic GP, Black Diamond, Beta Operating Company, LLC (“Beta Operating”), Memorial Resource Finance Corp., MRD Operating LLC (“MRD Operating”), Memorial Production Partners GP LLC (“MEMP GP”) (including MEMP GP’s ownership of 50% of Memorial Production Partners LP’s (“MEMP”) incentive distribution rights) and (ii) 99.9% of the membership interests in WildHorse Resources; — We issued 128,665,677 shares of our common stock to MRD LLC, which MRD LLC immediately distributed to MRD Holdco; — We assumed the obligations of MRD LLC under the indenture governing the $350 million in aggregate principal amount of 10.00% / 10.75% Senior PIK Toggle Notes due 2018 (the “PIK notes”) and reimbursed MRD LLC for the June 15, 2014 interest payment made on the PIK notes; — Certain former management members of WildHorse Resources contributed to us their outstanding incentive units in WildHorse Resources, as well as the remaining 0.1% of the membership interests in WildHorse Resources, and we issued 42,334,323 shares of our common stock and paid cash consideration of $30.0 million to such former management members of WildHorse Resources; — We entered into a registration rights agreement and a voting agreement with MRD Holdco and certain former management members of WildHorse Resources; — We entered into a new $2.0 billion revolving credit facility (see Note 8) and used approximately $614.5 million in borrowings under that facility to repay all amounts outstanding under WildHorse Resources’ credit agreements, to partially fund the cash consideration payable to the former management members of WildHorse Resources and to reimburse MRD LLC for the June 15, 2014 interest payment made on the PIK notes; — Notice of redemption was given to the PIK notes trustee (see Note 8) specifying a redemption date of July 16, 2014 and indicating that a portion of the net proceeds from our initial public offering, which temporarily reduced amounts outstanding under our new revolving credit facility, would be used to redeem the PIK notes at a redemption price of 102% of the principal amount of the PIK notes plus accrued and unpaid interest thereon to the date of redemption; — MRD Operating entered into a merger agreement with MRD LLC pursuant to which after the termination or earlier discharge of the PIK notes MRD LLC would merge into MRD Operating; — MRD LLC distributed to MRD Holdco the following: (i) BlueStone Natural Resources Holdings, LLC (“BlueStone”), which sold substantially all of its assets in July 2013 for $117.9 million, MRD Royalty LLC, which owns certain leasehold interests and overriding royalty interests in Texas and Montana, MRD Midstream LLC, which owns an indirect interest in certain midstream assets in North Louisiana, Golden Energy and Classic Pipeline; (ii) 5,360,912 subordinated units of MEMP; (iii) the right to the remaining cash to be released from the debt service reserve account in connection with the redemption or earlier discharge of the PIK notes plus the cash received from us in reimbursement of the interest paid on June 15, 2014 in respect of the PIK notes; and (iv) approximately $6.7 million of cash received by MRD LLC in connection with the sale of Golden Energy’s assets in May 2014; — We irrevocably deposited with the PIK notes trustee approximately $360.0 million on June 27, 2014, which was an amount sufficient to fund the redemption of the PIK notes on the redemption date and to satisfy and discharge our obligations under the PIK notes and the related indenture. The discharge became effective upon the irrevocable deposit of the funds with the PIK notes trustee; and — MRD LLC merged into MRD Operating. Previous Owners References to “the previous owners” for accounting and financial reporting purposes refer collectively to: — Certain oil and natural gas properties and related assets primarily in the Permian Basin, East Texas and the Rockies that MEMP acquired through equity transactions in October 2013 from certain affiliates of NGP. In October 2013, MEMP acquired Boaz Energy, LLC (“Boaz”), Crown Energy Partners, LLC (“Crown”), the Crown net profits interest and overriding royalty interest (“Crown NPI/ORRI”), Propel Energy SPV LLC (“Propel SPV”), together with its wholly-owned subsidiary Propel Energy Services, LLC (“Propel Energy Services”), and Stanolind Oil and Gas SPV LLC (“Stanolind SPV”) from Boaz Energy Partners, LLC (“Boaz Energy Partners”), Crown Energy Partners Holdings, LLC (“Crown Holdings”), Propel Energy, LLC (“Propel Energy”) and Stanolind Oil and Gas LP (“Stanolind”), all of which are primarily owned by two of the Funds. — A net profits interest that WildHorse Resources purchased from NGP Income Co-Investment Fund II, L.P. (“NGPCIF”) in February 2014 (“NGPCIF NPI”). NGPCIF is controlled by NGP. Upon the completion of the 2010 Petrohawk and Clayton Williams acquisitions, WildHorse Resources sold a net profits interest in these properties to NGPCIF. Since WildHorse Resources sold the net profits interest, the historical results are accounted for as a working interest for all periods. Our audited financial statements reported herein include the financial position and results attributable to: (i) those certain oil and natural gas properties and related assets that MEMP acquired through equity transactions in October 2013 from Boaz Energy Partners, Crown Holdings, Propel Energy and Stanolind and (ii) NGPCIF NPI. Basis of Presentation The financial statements reported herein include the financial position and results attributable to both our predecessor and the previous owners on a combined basis for periods prior to our initial public offering. For periods after the completion of our public offering, our consolidated financial statements include our accounts and those of our subsidiaries in which we have a controlling interest. Due to our control of MEMP through our ownership of MEMP GP, we are required to consolidate MEMP for accounting and financial reporting purposes. MEMP is owned 99.9% by its limited partners and 0.1% by MEMP GP. All material intercompany transactions and balances have been eliminated in preparation of our consolidated and combined financial statements. The accompanying consolidated and combined financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). We have two reportable business segments, both of which are engaged in the acquisition, exploration, development and production of oil and natural gas properties (See Note 14). Our reportable business segments are as follows: — MRD—reflects the combined operations of the Company, MRD Operating, MRD LLC, WildHorse Resources and its previous owners, Black Diamond, BlueStone, Beta Operating and MEMP GP. — MEMP—reflects the combined operations of MEMP, its previous owners, and historical dropdown transactions that occurred between MEMP and other MRD (or its predecessor) consolidating subsidiaries. Segment financial information has been retrospectively revised for the following common control transactions for comparability purposes: — acquisition by MEMP of certain oil and gas properties in East Texas and non-core Louisiana from MRD in exchange for MEMP’s North Louisiana oil and gas properties and approximately $78.0 million in cash in February 2015; — acquisition by MEMP of all the outstanding membership interests in Tanos Energy, LLC (“Tanos”) from MRD LLC for a purchase price of approximately $77.4 million on October 1, 2013; — acquisition by MEMP of all the outstanding membership interests in Prospect Energy, LLC (“Prospect Energy”) from Black Diamond for a purchase price of approximately $16.3 million on October 1, 2013; — acquisition by MEMP of certain of the oil and natural gas properties in Jackson County, Texas from MRD LLC for a purchase price of approximately $2.6 million on October 1, 2013; — acquisition by MEMP of all the outstanding membership interests in WHT Energy Partners LLC (“WHT”) from WildHorse Resources and Tanos for a purchase price of approximately $200.0 million on March 28, 2013; — acquisition by MEMP of certain assets from Classic in East Texas in May 2012 for a purchase price of approximately $27.0 million; and — acquisition by MEMP of certain assets from Tanos in East Texas in April 2012 for a purchase price of approximately $18.5 million.

Summary of Significant Accounti

Summary of Significant Accounting Policies	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Note 2. Summary of Significant Accounting Policies A discussion of our critical accounting policies and estimates is included in our 2014 Form 10-K. Accrued liabilities Current accrued liabilities consisted of the following at the dates indicated (in thousands): March 31, December 31, 2015 2014 Accrued capital expenditures $ 84,939 $ 80,350 Accrued lease operating expense 17,996 16,403 Accrued general and administrative expenses 10,098 8,516 Accrued ad valorem and production taxes 10,390 8,870 Accrued interest payable 36,815 24,797 Accrued environmental 1,309 2,092 Accrued current deferred income taxes 51,937 51,929 Other miscellaneous, including operator advances 4,185 6,043 $ 217,669 $ 199,000 Income Tax Our predecessor was organized as a pass-through entity for federal income tax purposes and was not subject to federal income taxes prior to our initial public offering in June 2014; however, certain of its consolidating subsidiaries were subject to federal and certain state income taxes. We are organized as a taxable C corporation and subject to federal and certain state income taxes. We are also subject to the Texas margin tax and certain aspects of the tax make it similar to an income tax. The net income (loss) attributable to noncontrolling interest is related to MEMP, which is a pass-through entity for federal income tax purposes. As discussed in Note 12, the compensation expense associated with the incentive units of MRD Holdco creates a nondeductible permanent difference for income tax purposes. We reported no liability for unrecognized tax benefits as of March 31, 2015 and expect no significant change to the unrecognized tax benefits in the next twelve months. Our effective tax rate is negative 67.5% for the three months ended March 31, 2015, which differs from the statutory federal income tax rate of 35% primarily due to the following recurring items: · 84.0% reduction to the effective tax rate related to pass-through entities; · 10.6% reduction to the effective tax rate related to non-deductible incentive compensation; and · 8.1% reduction to the effective tax rate related to state income tax provision, net of federal benefit. We had a net noncurrent deferred income tax liability of $95.0 million at December 31, 2014, of which $29.2 million was attributable to certain oil and gas properties in East Texas that MEMP acquired from us in February 2015 as noted above. A deferred income tax benefit of $1.2 million associated with these oil and gas properties was recorded during February 2015. As such, a net deferred income tax liability of $28.0 million has been reduced through additional paid capital in our equity statement. New Accounting Pronouncements Presentation of Debt Issuance Cost. In April 2015, the Financial Accounting Standards Board ("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 does not expect the impact of adopting this guidance to be material to the Company's financial statements and related disclosures. Amendments to Consolidation Analysis . In February 2015, the FASB issued an accounting standards update to improve consolidation guidance for certain types of legal entities. The guidance modifies the evaluation of whether limited partnerships and similar legal entities are variable interest entities (“VIEs”) or voting interest entities, eliminates the presumption that a general partner should consolidate a limited partnership, affects the consolidation analysis of reporting entities that are involved with VIEs, particularly those that have fee arrangements and related party relationships, and provides a scope exception from consolidation guidance for certain money market funds. These provisions are effective for annual reporting periods beginning after December 15, 2015, and interim periods within those annual periods, with early adoption permitted. These provisions may also be adopted using either a full retrospective or a modified retrospective approach. Although the Company is currently assessing the impact 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 will either: (i) continue to consolidate MEMP and become subject to the VIE primary beneficiary disclosure requirements or (ii) no longer consolidate MEMP under the revised VIE consolidation requirements and provide disclosures that apply to variable interest holders that do not consolidate a VIE. The deconsolidation of MEMP would have a material impact on our consolidated financial statements and related disclosures. Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Company’s financial position, results of operations and cash flows.	Note 2. Summary of Significant Accounting Policies Use of Estimates The preparation of consolidated and combined financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated and combined financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates include, but are not limited to, oil and natural gas reserves; depreciation, depletion, and amortization of proved oil and natural gas properties; future cash flows from oil and natural gas properties; impairment of long-lived assets; fair value of derivatives; fair value of equity and incentive unit compensation; fair values of assets acquired and liabilities assumed in business combinations and asset retirement obligations. Principles of Consolidation and Combination Our consolidated financial statements include our accounts and those of our subsidiaries in which we have a controlling interest, after the elimination of all intercompany accounts and transactions. Likewise, the combined financial statements include the accounts of our predecessor and the previous owners as discussed above. All material intercompany balances and transactions have been eliminated. Certain prior period balances have been reclassified to better align with financial statement presentation in the current fiscal year. Cash and Cash Equivalents Cash and cash equivalents represent unrestricted cash on hand and all highly liquid investments with original contractual maturities of three months or less. Book Overdrafts Book overdrafts, representing outstanding checks in excess of funds on deposit, are classified as accounts payable and the change in the related balance is reflected in operating activities in the statement of cash flows. Concentrations of Credit Risk Cash balances, accounts receivable, restricted investments and derivative financial instruments are financial instruments potentially subject to credit risk. Cash and cash equivalents are maintained in bank deposit accounts which, at times, may exceed the federally insured limits. Management periodically reviews and assesses the financial condition of the banks to mitigate the risk of loss. Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with MEMP’s offshore Southern California oil and gas properties. These restricted investments may consist of money market deposit accounts, money market mutual funds, commercial paper, and U.S. Government securities, all held with credit-worthy financial institutions. Derivative financial instruments are generally executed with major financial institutions that expose us to market and credit risks and which may, at times, be concentrated with certain counterparties. The credit worthiness of the counterparties is subject to continual review. We rely upon netting arrangements with counterparties to reduce credit exposure. Neither we nor our predecessor and the previous owners have experienced any losses from such instruments. Oil and natural gas are sold to a variety of purchasers, including intrastate and interstate pipelines or their marketing affiliates and independent marketing companies. Accounts receivable from joint operations are from a number of oil and natural gas companies, partnerships, individuals, and others who own interests in the properties operated by us, our predecessor, and the previous owners. Generally, operators of crude oil and natural gas properties have the right to offset future revenues against unpaid charges related to operated wells, minimizing the credit risk associated with these receivables. Additionally, management believes that any credit risk imposed by a concentration in the oil and natural gas industry is mitigated by the creditworthiness of its customer base. An allowance for doubtful accounts is recorded after all reasonable efforts have been exhausted to collect or settle the amount owed. Any amounts outstanding longer than the contractual terms are considered past due. Management determined that an allowance for uncollectible accounts was unnecessary at both December 31, 2014 and 2013, respectively. If we were to lose any one of our customers, the loss could temporarily delay the production and the sale of oil and natural gas in the related producing region. If we were to lose any single customer, we believe that a substitute customer to purchase the impacted production volumes could be identified. Oil and Natural Gas Properties Oil and natural gas exploration, development and production activities are accounted for in accordance with the successful efforts method of accounting. Under this method, costs of acquiring properties, costs of drilling successful exploration wells, and development costs are capitalized. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if determination is made that proved reserves have been found. If no proved reserves have been found, the costs of each of the related exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. The costs of such exploratory wells are expensed if a determination of proved reserves has not been made within a twelve-month period after drilling is complete. Exploration costs such as geological, geophysical, and seismic costs are expensed as incurred. As exploration and development work progresses and the reserves on these properties are proven, capitalized costs attributed to the properties are subject to depreciation and depletion. Depletion of capitalized costs is provided using the units-of-production method based on proved oil and gas reserves related to the associated field. Capitalized drilling and development costs of producing oil and natural gas properties are depleted over proved developed reserves and leasehold costs are depleted over total proved reserves. On the sale or retirement of a complete or partial unit of a proved property or pipeline and related facilities, the cost and related accumulated depreciation, depletion, and amortization are removed from the property accounts, and any gain or loss is recognized. There were no material capitalized exploratory drilling costs pending evaluation at December 31, 2014, 2013 and 2012. Oil and Gas Reserves The estimates of proved oil and natural gas reserves utilized in the preparation of the consolidated and combined financial statements are estimated in accordance with the rules established by the SEC and the Financial Accounting Standards Board (“FASB”). These rules require that reserve estimates be prepared under existing economic and operating conditions using a trailing 12-month average price with no provision for price and cost escalations in future years except by contractual arrangements. Netherland, Sewell & Associates, Inc. (“NSAI”), our independent reserve engineers, was engaged to audit our internally prepared reserves estimates at December 31, 2014. MEMP engaged NSAI and Ryder Scott Company, L.P. to audit MEMP’s internally prepared reserves estimates for all of MEMP’s proved reserves (by volume) at December 31, 2014. Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties, or any combination of the above may be increased or decreased. Increases in recoverable economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates. Other Property & Equipment Other property and equipment is stated at historical cost and is comprised primarily of vehicles, furniture, fixtures, office build-out cost and computer hardware and software. Depreciation of other property and equipment is calculated using the straight-line method generally based on estimated useful lives of three to seven years. Asset Retirement Obligations An asset retirement obligation associated with retiring long-lived assets is recognized as a liability on a discounted basis in the period in which the legal obligation is incurred and becomes determinable, with an equal amount capitalized as an addition to oil and natural gas properties, which is allocated to expense over the useful life of the asset. Generally, oil and gas producing companies incur such a liability upon acquiring or drilling a well. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. Upon settlement of the liability, a gain or loss is recognized in net income (loss) to the extent the actual costs differ from the recorded liability. See Note 6 for further discussion of asset retirement obligations. Impairments Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate the carrying value of such properties may not be recoverable. This may be due to a downward revision of the reserve estimates, less than expected production, drilling results, higher operating and development costs, or lower commodity prices. The estimated undiscounted future cash flows expected in connection with the property are compared to the carrying value of the property to determine if the carrying amount is recoverable. If the carrying value of the property exceeds its estimated undiscounted future cash flows, the carrying amount of the property is reduced to its estimated fair value using Level 3 inputs. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. Impairment expense for the years ended December 31, 2014, 2013, and 2012 was approximately $432.1 million, $6.6 million, $28.9 million, respectively. See Note 4 for further discussion on impairments. Restricted Investments Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with MEMP’s offshore Southern California oil and gas properties. These investments are classified as held-to-maturity, and such investments are stated at amortized cost. Interest earned on these investments is included in interest expense – net in the statement of operations. The amortized cost of such investments is adjusted for amortization of premiums and accretion of discounts to maturity. Such amortization and accretion is displayed as a separate line item in the statement of operations. These restricted investments consist of money market deposit accounts, money market mutual funds, commercial paper, and U.S. Government securities. See Note 7 for additional information. Debt Issuance Costs These costs are recorded on the balance sheet and amortized over the term of the associated debt using the straight-line method which generally approximates the effective yield method. Amortization expense, including write-off of debt issuance costs, for the years ended December 31, 2014, 2013, and 2012 was approximately $7.4 million, $8.3 million and $3.6 million, respectively. Revenue Recognition Revenue from the sale of oil and natural gas is recognized when title passes, net of royalties due to third parties. Oil and natural gas revenues are recorded using the sales method. Under this method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers, regardless of whether the sales are proportionate to our ownership in the property. An asset or a liability is recognized to the extent there is an imbalance in excess of the proportionate share of the remaining recoverable reserves on the underlying properties. No significant imbalances existed at December 31, 2014 or 2013. The following individual customers each accounted for 10% or more of total reported revenues for the period indicated: Years Ending December 31, 2014 2013 2012 Consolidated & Combined: Energy Transfer Equity, L.P. and subsidiaries 33 % 35 % 13 % MRD Segment: Energy Transfer Equity, L.P. and subsidiaries 85 % 86 % 52 % Sunoco, Inc. (1) n/a n/a 20 % MEMP Segment: Sinclair Oil & Gas Company 11 % n/a n/a Phillips 66 (2) 12 % 14 % 12 % ConocoPhillips n/a n/a 13 % (1) Sunoco, Inc. became a subsidiary of Energy Transfer Equity, L.P. in October 2012. (2) Phillips 66 was a subsidiary of ConocoPhillips through April 30, 2012. Accordingly, any revenues generated from Phillips 66 prior to May 1, 2012 were reported under ConocoPhillips. Derivative Instruments Commodity derivative financial instruments (e.g., swaps, collars, and put options) are used to reduce the impact of natural gas, NGL and oil price fluctuations. Interest rate swaps are used to manage exposure to interest rate volatility, primarily as a result of variable rate borrowings under the credit facilities. Every derivative instrument is recorded on the balance sheet as either an asset or liability measured at its fair value. Changes in the derivative’s fair value are recognized in earnings as we have not elected hedge accounting for any of our derivative positions. Capitalized Interest We capitalize interest costs to oil and gas properties on expenditures made in connection with certain projects such as drilling and completion of new oil and natural gas wells and major facility installations. Interest is capitalized only for the period that such activities are in progress. Interest is capitalized using a weighted average interest rate based on our outstanding borrowings. These capitalized costs are included within intangible drilling costs and amortized using the units of production method. For the year ended December 31, 2014, we capitalized $7.3 million of interest. We did not capitalize any interest in 2013 or 2012. Income Tax Prior to our initial public offering, MRD LLC was organized as a pass-through entity for federal income tax purposes and was not subject to federal income taxes; however, certain of its consolidating subsidiaries were taxed as corporations and subject to federal income taxes. We are organized as a taxable C corporation and subject to federal and certain state income taxes. We are also subject to the Texas margin tax and certain aspects of the tax make it similar to an income tax. The Company accounts for income taxes using the asset and liability method wherein deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which temporary differences are expected to be recovered or settled. Deferred tax assets are reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of the deferred tax assets will not be realized. We must recognize the tax effects of any uncertain tax positions we may adopt, if the position taken by us is more likely than not sustainable based on its technical merits. If a tax position meets such criteria, the tax effect that would be recognized by us would be the largest amount of benefit with more than 50% chance of being realized. The evaluation of uncertain tax positions is a two-step process. The first step is a recognition process to determine whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. In evaluating whether a tax position has met the more likely than not recognition threshold, it is presumed that the position will be examined by the appropriate taxing authority with full knowledge of all relevant information. The second step is a measurement process whereby a tax position that meets the more likely than not recognition threshold is calculated to determine the amount of benefit/expense to recognize in the consolidated financial statements. The tax position is measured at the largest amount of benefit/expense that is more likely than not of being realized upon ultimate settlement. The Company has no liability for unrecognized tax benefits as of December 31, 2014 and 2013. Accordingly, there is no amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate and there is no amount of interest or penalties currently recognized in the consolidated statements of operations or consolidated balance sheets as of December 31, 2014. In addition, the Company does not believe that there are any positions for which it is reasonably possible that the total amount of unrecognized tax benefits will significantly increase or decrease within the next twelve months. In June 2014, we recorded a deferred tax liability of approximately $43.3 million in stockholders’ equity in connection with our initial public offering and the related restructuring transactions. The tax bases of our assets and liabilities changed as a result our initial public offering and the related restructuring transactions, which represented a transaction among stockholders. Tax audits may be ongoing at any point in time. Tax liabilities are recorded based on estimates of additional taxes which may be due upon the conclusion of these audits. Estimates of these tax liabilities are made based upon prior experience and are updated for changes in facts and circumstances. However, due to the uncertain and complex application of tax regulations, it is possible that the ultimate resolution of audits may result in liabilities which could be materially different from these estimates. Earnings Per Share Basic earnings per share (“EPS”) is computed using the two-class method based on net income (loss) available to common stockholders and the average number of shares of common stock outstanding for the period. Diluted EPS includes the impact of the Company’s restricted shares of common stock as they are participating securities. The Company determines the more dilutive of either the two-class method or the treasury stock method for diluted EPS. See Note 10 for additional information. Incentive Based Compensation Arrangements The fair value of equity-classified awards (e.g., restricted stock awards) is amortized to earnings over the requisite service or vesting period. Compensation expense for liability-classified awards are recognized over the requisite service or vesting period of an award based on the fair value of the award re-measured at each reporting period. Generally, no compensation expense is recognized for equity instruments that do not vest. Prior to the restructuring transactions, the governing documents of MRD LLC and certain of its subsidiaries provided for the issuance of incentive units. The incentive units were subject to performance conditions that affected their vesting. Compensation cost was recognized only if the performance condition was probable of being satisfied at each reporting date. In connection with the restructuring transactions, the MRD LLC incentive units were exchanged for substantially identical units in MRD Holdco, and such incentive units entitle holders thereof to portions of future distributions by MRD Holdco. While any such distributions made by MRD Holdco will not involve any cash payment by us, we will be required to recognize non-cash compensation expense, which may be material, in future periods. The compensation expense recognized by us related to the incentive units will be offset by a deemed capital contribution from MRD Holdco as they are remeasured at the end of each reporting period. See Notes 11 and 12 for further information. Accrued Liabilities Current accrued liabilities consisted of the following at the dates indicated (in thousands): December 31, 2014 2013 Accrued capital expenditures $ 80,350 $ 48,579 Accrued lease operating expense 16,403 13,240 Accrued general and administrative expenses 8,516 14,485 Accrued ad valorem and production taxes 8,870 3,541 Accrued interest payable 24,797 11,934 Accrued environmental 2,092 577 Accrued current deferred income taxes 51,929 382 Other miscellaneous, including operator advances 6,043 5,392 $ 199,000 $ 98,130 Supplemental Cash Flow Information Supplemental cash flow for the periods presented (in thousands): For Year Ended December 31, 2014 2013 2012 Supplemental cash flows: Cash paid for interest, net of amounts capitalized $ 130,732 $ 61,140 $ 23,525 Income tax paid 838 168 22 Noncash investing and financing activities: Change in capital expenditures in payables and accrued liabilities 31,771 41,017 17,158 Assumptions of asset retirement obligations related to properties acquired or drilled 5,420 4,227 7,962 Contribution of oil and gas properties from NGP affiliate — — 6,893 Accrued distribution to NGP affiliates related to Cinco Group acquisitions — 4,352 — Contribution related to sale of assets to NGP affiliate - restricted cash — — 2,013 Accrued equity offering costs — — 171 Distributions to noncontrolling interests — — 47 Repurchase of equity under repurchase program 3,425 — — Accounts receivable related to acquisitions 9,569 — — New Accounting Pronouncements Revenue from Contracts with Customers. In May 2014, the FASB issued a comprehensive new revenue recognition standard for contracts with customers that will supersede most current revenue recognition guidance, including industry-specific guidance. The core principle of this standard is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, the standard provides a five-step analysis of transactions to determine when and how revenue is recognized. Other major provisions include the capitalization and amortization of certain contract costs, ensuring the time value of money is considered in the transaction price, and allowing estimates of variable consideration to be recognized before contingencies are resolved in certain circumstances. This guidance also requires enhanced disclosures regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from an entity’s contracts with customers. The new standard is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016. Early application is prohibited. The standard permits the use of either the retrospective or cumulative effect transition method. This guidance will be applicable to the Company beginning on January 1, 2017. The Company is currently assessing the impact that adopting this new accounting guidance will have on its consolidated financial statements and footnote disclosures. Reporting Discontinued Operations. In April 2014, the FASB issued an accounting standards update that changes the criteria for determining when disposals can be presented as discontinued operations and modifies discontinued operations disclosures. The new guidance now defines a “discontinued operation” as (i) a disposal of a component or group of components that is disposed of or is classified as held for sale and “represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results” or (ii) an acquired business or nonprofit activity that is classified as held for sale on the date of acquisition. We will adopt this guidance and apply the disclosure requirements prospectively beginning on January 1, 2015. Amendments to Consolidation Analysis . In February 2015, the FASB issued an accounting standards update to improve consolidation guidance for certain types of legal entities. The guidance modifies the evaluation of whether limited partnerships and similar legal entities are variable interest entities (“VIEs”) or voting interest entities, eliminates the presumption that a general partner should consolidate a limited partnership, affects the consolidation analysis of reporting entities that are involved with VIEs, particularly those that have fee arrangements and related party relationships, and provides a scope exception from consolidation guidance for certain money market funds. These provisions are effective for annual reporting periods beginning after December 15, 2015, and interim periods within those annual periods, with early adoption permitted. These provisions may also be adopted using either a full retrospective or a modified retrospective approach. Although the Company is currently assessing the impact of adopting this new accounting guidance will have on its consolidated financial statements and footnote disclosures, we expect that MEMP will become a VIE. We will either: (i) continue to consolidate MEMP and become subject to the VIE primary beneficiary disclosure requirements or (ii) no longer consolidate MEMP under the revised VIE consolidation requirements and provide disclosures that apply to variable interest holders that do not consolidate a VIE. The deconsolidation of MEMP would have a material impact on our consolidated financial statements and related disclosures. Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Company’s financial position, results of operations and cash flows.

Acquisitions and Divestitures

Acquisitions and Divestitures	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Business Combinations [Abstract]
Acquisitions and Divestitures	Note 3. Acquisitions and Divestitures Acquisition-related costs are included in general and administrative expenses in the accompanying statements of operations for the periods indicated below (in thousands): For the Three Months Ended March 31, 2015 2014 $ 2,580 $ 2,462 2015 Divestitures Subsequent event. On April 17, 2015, MRD sold certain oil and natural gas properties to a third party in Colorado and Wyoming for approximately $13.5 million (the “Rockies Divestiture”). 2014 Acquisitions 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 (the “Eagle Ford Acquisition”). In addition, MEMP acquired a 30% interest in the seller’s Eagle Ford leasehold. In July 2014, MEMP closed a third-party acquisition that was deemed significant to our consolidated financial statements. The following unaudited pro forma combined results of operations are provided for the three months ended March 31, 2014 as though this third-party acquisition had been completed on January 1, 2013. The unaudited pro forma financial information was derived from the historical combined statements of operations of our predecessor and 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 Three Months Ended March 31, 2014 (In thousands) Revenues $ 252,019 Net income (loss) (14,817 )	Note 3. Acquisitions and Divestitures The third party acquisitions discussed below were accounted for under the acquisition method of accounting. Accordingly, we, our predecessor, and the previous owners conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while acquisition costs associated with the acquisitions were expensed as incurred. The operating revenues and expenses of acquired properties are included in the accompanying financial statements from their respective closing dates forward. The transactions were financed through equity offerings, capital contributions and borrowings under credit facilities. The fair values of oil and natural gas properties are measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural properties include estimates of: (i) economic reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital. MEMP has consummated several common control acquisitions since completing its initial public offering in December 2011, as further discussed in Note 13, from certain affiliates of NGP. These acquisitions were each accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the net assets acquired were recorded at historical cost. Acquisition-related costs Acquisition-related costs for both related party and third party transactions are included in general and administrative expenses in the accompanying statements of operations for the periods indicated below (in thousands): For the Year Ended December 31, 2014 2013 2012 $ 6,668 $ 8,313 $ 4,538 2014 Acquisitions On December 30, 2014, MRD acquired certain oil and natural gas producing properties from third parties in the Terryville Complex for approximately $71.9 million, including estimated customary post-closing adjustments (the “Louisiana Acquisition”). During the fourth quarter 2014, MRD acquired incremental interests in certain oil and gas properties and leases in the Terryville Complex from third parties in four separate transactions for an aggregate purchase price of approximately $24.0 million. On July 1, 2014, MEMP consummated a transaction to acquire certain oil and natural gas liquids properties from a third party in Wyoming for an aggregate purchase price of approximately $906.1 million, including estimated post-closing adjustments (the “Wyoming Acquisition”). Revenues of $72.0 million were recorded in the statement of operations generated earnings of approximately $22.9 million related to the Wyoming Acquisition subsequent to the closing date. On March 25, 2014, MEMP closed a transaction to acquire certain oil and natural gas producing properties from a third party in the Eagle Ford for approximately $168.1 million (the “Eagle Ford Acquisition”). In addition, MEMP acquired a 30% interest in the seller’s Eagle Ford leasehold. During the year ended December 31, 2014, revenues of approximately $36.5 million were recorded in the statement of operations related to the Eagle Ford Acquisition subsequent to the closing date and MEMP generated earnings of approximately $16.3 million. The following table summarizes the fair value assessment of the assets acquired and liabilities assumed as of the acquisition dates (in thousands): MRD MEMP MEMP Louisiana Eagle Ford Wyoming Acquisition Acquisition Acquisition Oil and gas properties $ 72,141 $ 168,606 $ 930,168 Asset retirement obligations (271 ) (285 ) (3,980 ) Revenue Payable — — (375 ) Accrued liabilities — (250 ) (19,693 ) Total identifiable net assets $ 71,870 $ 168,071 $ 906,120 The following unaudited pro forma combined results of operations are provided for the year ended December 31, 2014 and 2013 as though the Wyoming Acquisition had been completed on January 1, 2013. The unaudited pro forma financial information was derived from the historical combined statements of operations of the Company and the previous owners and adjusted to include: (i) the revenues and direct operating expenses associated with oil and gas properties acquired, (ii) depletion expense applied to the adjusted basis of the properties acquired and (iii) interest expense on additional borrowings necessary to finance the acquisition. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of expected future results of operations. For the Year Ended December 31, 2014 2013 (In thousands, except per share amounts) Revenues $ 990,544 $ 761,443 Net income (loss) (602,044 ) 257,839 Basic earnings per share $ (4.08 ) $ — Diluted earnings per share $ (4.08 ) $ — 2014 Divestitures On May 9, 2014, MRD LLC sold certain producing and non-producing properties in the Mississippian oil play of Northern Oklahoma to a third party for approximately $7.6 million and recorded a loss of $3.2 million. 2013 Acquisitions On April 30, 2013, WildHorse Resources purchased certain oil and gas properties and leases in Louisiana from a third party for approximately $67.1 million. MEMP closed two separate transactions during 2013 to acquire certain oil and natural gas properties from third parties in East Texas (the “East Texas Acquisition”) and the Rockies (the “Rockies Acquisition”) for approximately $29.4 million in aggregate. The East Texas Acquisition closed on September 6, 2013 and the Rockies Acquisition closed on August 30, 2013. Louisiana East Texas Rockies Acquisition Acquisition Acquisition Oil and gas properties $ 68,887 $ 9,974 $ 20,744 Asset retirement obligation (1,789 ) (78 ) (1,163 ) Accrued liabilities - - (118 ) Total identifiable net assets $ 67,098 $ 9,896 $ 19,463 During 2013, Propel Energy acquired incremental interests in certain oil and gas properties and leases in the Hendrick Field located in Winkler County, Texas from third parties in three separate transactions for an aggregate purchase price of approximately $9.3 million. 2013 Divestitures On January 1, 2013, Tanos sold a natural gas gathering pipeline located in East Texas, which it had originally acquired in April 2010, to a privately held gas transportation company for a minimum purchase price of $1.5 million. The maximum allowable additional proceeds are $2.0 million. The contingent consideration is based on the natural gas pipeline servicing any new wells that Tanos drills in the area over the following three years. The contingent consideration portion of an arrangement is recorded when the consideration is determined to be realizable. Tanos recorded an aggregate gain of approximately $1.4 million related to this transaction, of which $0.4 million was contingent consideration. During 2013, Tanos also sold certain non-operated oil and gas properties for $2.9 million and recorded a gain of $1.4 million. On May 10, 2013, Black Diamond entered into a purchase and sale agreement with a third party to sell certain of its Wyoming oil and gas properties with an estimated net book value of $39.8 million for $33.0 million, before customary adjustments. As a result, Black Diamond recorded a loss on the sale of $6.8 million. This transaction closed on June 4, 2013. During 2013, BlueStone entered into an agreement with a third party to sell its remaining interest in certain properties in the Mossy Grove Prospect in Walker and Madison Counties located in East Texas. Total cash consideration received by BlueStone was approximately $117.9 million, which exceeded the net book value of the properties sold by $89.5 million. The transaction closed on July 31, 2013. 2012 Acquisitions On May 1, 2012, MEMP and WildHorse jointly acquired operating and non-operating interests in certain oil and natural gas properties located in East Texas and North Louisiana from an undisclosed third party seller (“Undisclosed Seller Acquisition”) for a final net purchase price of approximately $112.1 million. These properties are located primarily in Polk County, Texas and Lincoln and Claiborne Parishes, Louisiana. During the year ended December 31, 2012, approximately $22.1 million of revenue and $9.2 million of earnings were recorded in the statement of operations related to the Undisclosed Seller Acquisition subsequent to the closing date. On September 28, 2012, MEMP acquired certain oil and natural gas properties in East Texas from Goodrich Petroleum Corporation (“Goodrich Acquisition”) for a final net purchase price of $90.4 million after customary post-closing adjustments. The effective date of this transaction was July 1, 2012. This transaction was financed with borrowings under MEMP’s revolving credit facility. These properties are located in the East Henderson field of Rusk County, Texas. During the year ended December 31, 2012, approximately $4.6 million of revenue and $2.0 million of earnings were recorded in the statement of operations related to the Goodrich Acquisition subsequent to the closing date. Collectively, the previous owners consummated multiple acquisitions during 2012 by acquiring operating and non-operating interests in certain oil and natural gas properties primarily located in various Texas and New Mexico counties for an aggregate adjusted purchase price of $147.9 million, the largest of which was completed in July by Stanolind. In July 2012, Stanolind completed an acquisition of working interests, royalty interests and net revenue interests (the “Menemsha Acquisition”) located in various counties in Texas for a final net purchase price of $74.7 million. During the year ended December 31, 2012, approximately $4.9 million of revenue and $0.9 million of earnings were recorded in the statement of operations related to the Menemsha Acquisition subsequent to the closing date. The following table summarizes the fair value of the assets acquired and liabilities assumed as of each acquisition date (in thousands). Undisclosed Seller Goodrich Menemsha Other Acquisition Acquisition Acquisition Acquisitions Oil and gas properties $ 115,633 $ 91,187 $ 75,114 $ 77,764 Prepaid expenses and other current assets — 425 — — Revenues payable (1,602 ) (875 ) — — Asset retirement obligation (1,592 ) (161 ) (408 ) (4,558 ) Accrued liabilities (297 ) (153 ) — — Total identifiable net assets $ 112,142 $ 90,423 $ 74,706 $ 73,206 The following unaudited pro forma combined results of operations are provided for the year ended December 31, 2012 (in thousands) as though the Undisclosed Seller Acquisition, Goodrich Acquisition, and Menemsha Acquisition had been completed on January 1, 2011. The unaudited pro forma financial information was derived from our historical combined statements of operations and adjusted to include: (i) the revenues and direct operating expenses associated with oil and gas properties acquired, (ii) depletion expense applied to the adjusted basis of the properties acquired and (iii) interest expense on additional borrowings necessary to finance the acquisitions. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transactions occurred on the basis assumed above, nor is such information indicative of expected future results of operations. Revenue $ 431,060 Net income 40,940 During 2012, we also acquired certain interests in oil and gas properties through several individually immaterial acquisitions for an aggregate purchase price of $10.2 million. 2012 Divestitures During 2012, certain of our subsidiaries sold certain interests in oil and gas properties for an aggregate $3.3 million. Losses of approximately $0.1 million were recognized related to these divestures. On July 11, 2012, the previous owners completed the sale of a portion of its oil and gas assets located in Garza County, Texas to a third party for $26.1 million and recognized a gain of approximately $7.6 million. On September 18, 2012, the previous owners completed the sale of a portion of its oil and gas assets located in Ector County, Texas to a third party for $4.7 million and recognized a gain of approximately $2.2 million. The majority of the proceeds generated from these sales were used to acquire operating and non-operating interests in certain oil and natural gas properties located primarily in various Texas and New Mexico counties.

Fair Value Measurements of Fina

Fair Value Measurements of Financial Instruments	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Fair Value Measurements of Financial Instruments	Note 4. Fair Value Measurements of Financial Instruments Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. Fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk. A three-tier hierarchy has been established that classifies fair value amounts recognized or disclosed in the financial statements. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3). All of the derivative instruments reflected on the accompanying balance sheets were considered Level 2. The carrying values of accounts receivables, accounts payables (including accrued liabilities) and amounts outstanding under long-term debt agreements with variable rates included in the accompanying balance sheets approximated fair value at March 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. Assets and Liabilities Measured at Fair Value on a Recurring Basis The fair market values of the derivative financial instruments reflected on the balance sheets as of March 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 gross derivative assets and liabilities that are measured at fair value on a recurring basis at March 31, 2015 and December 31, 2014 for each of the fair value hierarchy levels: Fair Value Measurements at March 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 $ — $ 1,022,706 $ — $ 1,022,706 Interest rate derivatives — 10 — 10 Total assets $ — $ 1,022,716 $ — $ 1,022,716 Liabilities: Commodity derivatives $ — $ 87,809 $ — $ 87,809 Interest rate derivatives — 3,549 — 3,549 Total liabilities $ — $ 91,358 $ — $ 91,358 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 factors such 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. — Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such properties. 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 period ended March 31, 2015, MEMP recognized $251.3 million of impairments primarily related to certain properties located in East Texas, Wyoming and Colorado. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable due to declining commodity prices. The carrying value of these properties after the $251.3 million impairment was approximately $157.6 million. MEMP did not record any impairments for the three months ended March 31, 2014.	Note 4. Fair Value Measurements of Financial Instruments Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. Fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk. A three-tier hierarchy has been established that classifies fair value amounts recognized or disclosed in the financial statements. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3). The characteristics of fair value amounts classified within each level of the hierarchy are described as follows: Level 1 — Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. An active market is one in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2 — Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. At December 31, 2014 and 2013, all of the derivative instruments reflected on the accompanying balance sheets were considered Level 2. Level 3 — Measure based on prices or valuation models that require inputs that are both significant to the fair value measurement and are less observable from objective sources (i.e., supported by little or no market activity). Assets and Liabilities Measured at Fair Value on a Recurring Basis The carrying values of cash and cash equivalents, accounts receivables, accounts payables (including accrued liabilities) and amounts outstanding under long-term debt agreements with variable rates included in the accompanying balance sheets approximated fair value at December 31, 2014 and December 31, 2013. The fair value estimates are based upon observable market data and are classified within Level 2 of the fair value hierarchy. These assets and liabilities are not presented in the following tables. See Note 8 for the estimated fair value of our outstanding fixed-rate debt. The fair market values of the derivative financial instruments reflected on the balance sheets as of December 31, 2014 and December 31, 2013 were based on estimated forward commodity prices (including nonperformance risk) and forward interest rate yield curves. Nonperformance risk is the risk that the obligation related to the derivative instrument will not be fulfilled. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement in its entirety. The significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The following table presents the derivative assets and liabilities that are measured at fair value on a recurring basis at December 31, 2014 and December 31, 2013 for each of the fair value hierarchy levels: Fair Value Measurements at December 31, 2014 Using Quoted Prices in Significant Other Significant Active Observable Unobservable Market Inputs Inputs (Level 1) (Level 2) (Level 3) Fair Value (In thousands) Assets: Commodity derivatives $ — $ 845,759 $ — $ 845,759 Interest rate derivatives — 1,305 — 1,305 Total assets $ — $ 847,064 $ — $ 847,064 Liabilities: Commodity derivatives $ — $ 71,639 $ — $ 71,639 Interest rate derivatives — 3,289 — 3,289 Total liabilities $ — $ 74,928 $ — $ 74,928 Fair Value Measurements at December 31, 2013 Using Quoted Prices in Significant Other Significant Active Observable Unobservable Market Inputs Inputs (Level 1) (Level 2) (Level 3) Fair Value (In thousands) Assets: Commodity derivatives $ — $ 105,054 $ — $ 105,054 Interest rate derivatives — 884 — 884 Total assets $ — $ 105,938 $ — $ 105,938 Liabilities: Commodity derivatives $ — $ 58,234 $ — $ 58,234 Interest rate derivatives — 5,590 — 5,590 Total liabilities $ — $ 63,824 $ — $ 63,824 See Note 5 for additional information regarding our derivative instruments. Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis Certain assets and liabilities are reported at fair value on a nonrecurring basis as reflected on the balance sheets. The following methods and assumptions are used to estimate the fair values: — The fair value of asset retirement obligations (“AROs”) is based on discounted cash flow projections using numerous estimates, assumptions, and judgments regarding such factors as the existence of a legal obligation for an ARO; amounts and timing of settlements; the credit-adjusted risk-free rate; and inflation rates. See Note 6 for a summary of changes in AROs. — If sufficient market data is not available, the determination of the fair values of proved and unproved properties acquired in transactions accounted for as business combinations are prepared by utilizing estimates of discounted cash flow projections. The factors to determine fair value include, but are not limited to, estimates of: (i) economic reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital. The fair value of supporting equipment, such as plant assets, acquired in transactions accounted for as business combinations are commonly estimated using the depreciated replacement cost approach. — Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate the carrying value of such properties may not be recoverable. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. · During the year ended December 31, 2014, the MRD Segment recognized $24.6 million of impairments. The impairments primarily related to certain properties located in the Rockies as well as certain fields in North Louisiana. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable primarily due to declining commodity prices. · During the year ended December 31, 2014, MEMP recognized $407.5 million of impairments. The impairments primarily related to certain properties located in the Permian Basin, East Texas, and South Texas. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable. In the Permian Basin the impairments were in due to a downward revision of estimated proved reserves based on declining commodity prices and updated well performance data. In South Texas, the impairments were in due to a downward revision of estimated proved reserves based on declining commodity prices and increased operating costs. In East Texas, the impairments were due to downward revisions based on declining commodity prices. The carrying value of the: (i) Permian Basin properties after the $234.2 million impairment was approximately $88.7 million; (ii) East Texas properties after the $107.6 million impairment was approximately $88.8 million; and (iii) South Texas properties after the $65.6 million impairment was $71.2 million. · During the year ended December 31, 2013, we recognized $6.6 million of impairments. The impairments related to certain properties located in South Texas. The estimated future cash flows expected were compared to their carrying values and determined to be unrecoverable as a result of a downward revision of estimated proved reserves based on pricing terms specific to these properties. · During the year ended December 31, 2012, we recognized $28.9 million of impairments to proved oil and natural gas properties. Approximately $8.0 million related to a particular lease in the Elkhorn (Ellenburger) and Canyon Fields located in the Permian Basin as a result of a downward revision of estimated proved reserves due to unfavorable drilling results in the area. The remaining $20.9 million of impairments primarily related to certain fields in East Texas. The carrying values of these fields were determined to be unrecoverable due to a decline in gas prices.

Risk Management and Derivative

Risk Management and Derivative Instruments	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Risk Management and Derivative Instruments	Note 5. Risk Management and Derivative Instruments Derivative instruments are utilized to manage exposure to commodity price and interest rate fluctuations and achieve a more predictable cash flow in connection with natural gas and oil sales from production and borrowing related activities. These instruments limit exposure to declines in prices or increases in interest rates, but also limit the benefits that would be realized if prices increase or interest rates decrease. Certain inherent business risks are associated with commodity and interest derivative contracts, including market risk and credit risk. Market risk is the risk that the price of natural gas or oil will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the counterparty to a contract. It is our policy to enter into derivative contracts, including interest rate swaps, only with creditworthy counterparties, which generally are financial institutions, deemed by management as competent and competitive market makers. Some of the lenders, or certain of their affiliates, under our credit agreements are counterparties to our derivative contracts. While collateral is generally not required to be posted by counterparties, credit risk associated with derivative instruments is minimized by limiting exposure to any single counterparty and entering into derivative instruments only with counterparties that are large financial institutions, which management believes present minimal credit risk. Additionally, master netting agreements are used to mitigate risk of loss due to default with counterparties on derivative instruments. We have also entered into the International Swaps and Derivatives Association Master Agreements (“ISDA Agreements”) with each of our counterparties. The terms of the ISDA Agreements provide us and each of our counterparties with rights of set-off upon the occurrence of defined acts of default by either us or our counterparty to a derivative, whereby the party not in default may set-off all liabilities owed to the defaulting party against all net derivative asset receivables from the defaulting party. At March 31, 2015, MEMP had net derivative assets of $601.0 million. After taking into effect netting arrangements, MEMP had counterparty exposure of $328.4 million related to its derivative instruments of which $113.4 million was with a single counterparty. Had all counterparties failed completely to perform according to the terms of their existing contracts, MEMP would have the right to offset $272.6 million against amounts outstanding under its revolving credit facility at March 31, 2015. At March 31, 2015, MRD had net derivative assets of $330.5 million. After taking into effect netting arrangements, MRD had counterparty exposure of $248.7 million related to derivative instruments of which $66.6 million was with a single counterparty. Had all counterparties failed completely to perform according to the terms of their existing contracts, MRD would have the right to offset $81.8 million against amounts outstanding under its revolving credit facility at March 31, 2015. See Note 8 for additional information regarding our revolving credit facilities. Commodity Derivatives We may use a combination of commodity derivatives (e.g., floating-for-fixed swaps, put options, costless collars and basis swaps) to manage exposure to commodity price volatility. We recognize all derivative instruments at fair value; however, certain of our derivative instruments have a deferred premium. The deferred premium is factored into the fair value measurement and the Company agrees to defer the premium paid or received until the time of settlement. Cash settlements received on settled derivative positions during the three months ended March 31, 2015 is net of deferred premiums of $1.8 million. 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. 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 March 31, 2015, the MRD Segment had the following open commodity positions: Remaining 2015 2016 2017 2018 Natural Gas Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (MMBtu) 3,600,000 2,570,000 1,770,000 4,600,000 Weighted-average fixed price $ 4.15 $ 4.09 $ 4.24 $ 4.06 Collar contracts: Average Monthly Volume (MMBtu) 130,000 1,100,000 1,050,000 — Weighted-average floor price $ 4.00 $ 4.00 $ 4.00 $ — Weighted-average ceiling price $ 4.64 $ 4.71 $ 5.06 $ — Purchased put option contracts: Average Monthly Volume (MMBtu) 3,366,667 4,100,000 3,450,000 2,850,000 Weighted-average fixed price $ 3.75 $ 3.75 $ 3.75 $ 3.75 Weighted-average deferred premium paid $ (0.33 ) $ (0.36 ) $ (0.35 ) $ (0.35 ) Written call option contracts (1): Average Monthly Volume (MMBtu) 2,625,000 — — — Weighted-average sold strike price $ 3.75 $ — $ — $ — Weighted-average deferred premium received $ 0.08 $ — $ — $ — TGT Z1 basis swaps: Average Monthly Volume (MMBtu) 3,480,000 1,120,000 200,000 — Spread - Henry Hub $ (0.10 ) $ (0.10 ) $ (0.08 ) $ — Crude Oil Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 45,000 8,500 28,000 31,625 Weighted-average fixed price $ 91.67 $ 84.80 $ 84.70 $ 84.50 Collar contracts: Average Monthly Volume (Bbls) 2,000 27,000 — — Weighted-average floor price $ 85.00 $ 80.00 $ — $ — Weighted-average ceiling price $ 101.35 $ 99.70 $ — $ — Purchased put option contracts: Average Monthly Volume (Bbls) 30,333 — — — Weighted-average fixed price $ 85.00 $ — $ — $ — Weighted-average deferred premium paid $ (3.80 ) $ — $ — $ — Written call option contracts (1): Average Monthly Volume (Bbls) 22,750 — — — Weighted-average sold strike price $ 85.00 $ — $ — $ — Weighted-average deferred premium received $ 0.48 $ — $ — $ — NGL Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 155,000 185,658 — — Weighted-average fixed price $ 41.58 $ 34.06 $ — $ — (1) These transactions were entered into for the purpose of creating a ceiling on our put options, which effectively converted the applicable puts into swaps. At March 31, 2015, the MEMP Segment had the following open commodity positions: Remaining 2015 2016 2017 2018 2019 Natural Gas Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (MMBtu) 3,061,181 3,292,442 3,050,067 2,760,000 2,514,583 Weighted-average fixed price $ 4.16 $ 4.22 $ 4.14 $ 4.28 $ 4.43 Collar contracts: Average Monthly Volume (MMBtu) 350,000 — — — — Weighted-average floor price $ 4.62 $ — $ — $ — $ — Weighted-average ceiling price $ 5.80 $ — $ — $ — $ — Call spreads (1): Average Monthly Volume (MMBtu) 80,000 — — — — Weighted-average sold strike price $ 5.25 $ — $ — $ — $ — Weighted-average bought strike price $ 6.75 $ — $ — $ — $ — Basis swaps: Average Monthly Volume (MMBtu) 3,390,000 3,108,333 415,000 115,000 — Spread $ (0.12 ) $ (0.05 ) $ — $ 0.15 $ — Crude Oil Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 273,864 279,813 301,600 312,000 160,000 Weighted-average fixed price $ 91.34 $ 86.87 $ 84.70 $ 83.74 $ 85.52 Collar contracts: Average Monthly Volume (Bbls) 5,000 — — — — Weighted-average floor price $ 80.00 $ — $ — $ — $ — Weighted-average ceiling price $ 94.00 $ — $ — $ — $ — Basis swaps: Average Monthly Volume (Bbls) 97,333 95,000 — — — Spread $ (7.07 ) $ (9.56 ) $ — $ — $ — NGL Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 211,867 158,600 43,300 — — Weighted-average fixed price $ 42.30 $ 40.36 $ 37.55 $ — $ — (1) These transactions were entered into for the purpose of eliminating the ceiling portion of certain collar arrangements, which effectively converted the applicable collars into swaps. The MEMP Segment basis swaps included in the table above is presented on a disaggregated basis below: Remaining 2015 2016 2017 2018 Natural Gas Derivative Contracts: NGPL TexOk basis swaps: Average Monthly Volume (MMBtu) 2,730,000 2,703,333 300,000 — Spread - Henry Hub $ (0.12 ) $ (0.07 ) $ (0.05 ) $ — HSC basis swaps: Average Monthly Volume (MMBtu) 150,000 135,000 115,000 115,000 Spread - Henry Hub $ (0.08 ) $ 0.07 $ 0.14 $ 0.15 CIG basis swaps: Average Monthly Volume (MMBtu) 210,000 — — — Spread - Henry Hub $ (0.25 ) $ — $ — $ — TETCO STX basis swaps: Average Monthly Volume (MMBtu) 300,000 270,000 — — Spread - Henry Hub $ (0.09 ) $ 0.06 $ — $ — Crude Oil Derivative Contracts: Midway-Sunset basis swaps: Average Monthly Volume (Bbls) 57,333 55,000 — — Spread - Brent $ (9.73 ) $ (13.35 ) $ — $ — Midland basis swaps: Average Monthly Volume (Bbls) 40,000 40,000 — — Spread - WTI $ (3.25 ) $ (4.34 ) $ — $ — Interest Rate Swaps Periodically, we enter into interest rate swaps 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 March 31, 2015, we had the following interest rate swap open positions: Remaining Credit Facility 2015 2016 2017 2018 MEMP: Average Monthly Notional (in thousands) $ 386,111 $ 400,000 $ 400,000 $ 100,000 Weighted-average fixed rate 1.247 % 0.943 % 1.612 % 1.946 % Floating rate 1 Month LIBOR 1 Month LIBOR 1 Month LIBOR 1 Month LIBOR 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 March 31, 2015 and December 31, 2014. There was no cash collateral received or pledged associated with our derivative instruments since most of the counterparties, or certain of their affiliates, to our derivative contracts are lenders under our collective credit agreements. Asset Derivatives Liability Derivatives March 31, December 31, March 31, December 31, Type Balance Sheet Location 2015 2014 2015 2014 (In thousands) Commodity contracts Short-term derivative instruments $ 398,708 $ 378,908 $ 41,954 $ 38,852 Interest rate swaps Short-term derivative instruments — — 2,994 3,289 Gross fair value 398,708 378,908 44,948 42,141 Netting arrangements Short-term derivative instruments (41,648 ) (38,852 ) (41,648 ) (38,852 ) Net recorded fair value Short-term derivative instruments $ 357,060 $ 340,056 $ 3,300 $ 3,289 Commodity contracts Long-term derivative instruments $ 623,998 $ 466,851 $ 45,855 $ 32,787 Interest rate swaps Long-term derivative instruments 10 1,305 555 — Gross fair value 624,008 468,156 46,410 32,787 Netting arrangements Long-term derivative instruments (45,855 ) (32,787 ) (45,855 ) (32,787 ) Net recorded fair value Long-term derivative instruments $ 578,153 $ 435,369 $ 555 $ — (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 three months ended March 31, 2015 and 2014 (in thousands): For the Three Months Ended Statements of March 31, Operations Location 2015 2014 Commodity derivative contracts (Gain) loss on commodity derivatives $ (253,649 ) $ 59,482 Interest rate derivatives Interest expense, net 2,441 511	Note 5. Risk Management and Derivative Instruments Derivative instruments are utilized to manage exposure to commodity price and interest rate fluctuations and achieve a more predictable cash flow in connection with natural gas and oil sales from production and borrowing related activities. These transactions limit exposure to declines in prices or increases in interest rates, but also limit the benefits that would be realized if prices increase or interest rates decrease. Certain inherent business risks are associated with commodity and interest derivative contracts, including market risk and credit risk. Market risk is the risk that the price of natural gas or oil will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the counterparty to a contract. It is our policy to enter into derivative contracts, including interest rate swaps, only with creditworthy counterparties, which generally are financial institutions, deemed by management as competent and competitive market makers. Some of the lenders, or certain of their affiliates, under our credit agreements are counterparties to our derivative contracts. While collateral is generally not required to be posted by counterparties, credit risk associated with derivative instruments is minimized by limiting exposure to any single counterparty and entering into derivative instruments only with counterparties that are large financial institutions, which management believes present minimal credit risk. Additionally, master netting agreements are used to mitigate risk of loss due to default with counterparties on derivative instruments. We have also entered into the International Swaps and Derivatives Association Master Agreements (“ISDA Agreements”) with each of our counterparties. The terms of the ISDA Agreements provide us and each of our counterparties with rights of set-off upon the occurrence of defined acts of default by either us or our counterparty to a derivative, whereby the party not in default may set-off all liabilities owed to the defaulting party against all net derivative asset receivables from the defaulting party. At December 31, 2014, MEMP had net derivative assets of $517.1 million. After taking into effect netting arrangements, MEMP had counterparty exposure of $309.8 million related to its derivative instruments of which $109.7 million was with a single counterparty. Had certain counterparties failed completely to perform according to the terms of their existing contracts, MEMP would have the right to offset $207.3 million against amounts outstanding under its revolving credit facility at December 31, 2014. At December 31, 2014, MRD had derivative assets of $255.0 million. After taking into effect netting arrangements, MRD had counterparty exposure of $155.8 million related to derivative instruments. Had certain counterparties failed completely to perform according to the terms of their existing contracts, MRD would have the right to offset $99.2 million against amounts outstanding under its revolving credit facility at December 31, 2014. See Note 8 for additional information regarding our revolving credit facilities. Commodity Derivatives We may use a combination of commodity derivatives (e.g., floating-for-fixed swaps, put options, costless collars, call spreads and basis swaps) to manage exposure to commodity price volatility. We recognize all derivative instruments at fair value; however, certain of our put option derivative instruments have a deferred premium, which reduces the asset. For the deferred premium puts, the Company agrees to pay a premium to the counterparty at the time of settlement. At settlement, if the applicable index price is below the strike price of the put, the Company receives the difference between the strike price and the applicable index price multiplied by the contract volumes less the premium. If the applicable index price settles at or above the strike price of the put, the Company pays only the premium at settlement. During the year ended December 31, 2014, MRD restructured a portion of its commodity derivative portfolio by terminating “in the money” natural gas collars settling in 2015 and entering into natural gas swaps. The cash settlement receipts of $6.1 million from the termination of the collars were utilized to enhance the fixed price portion of the natural gas swaps. We enter into natural gas derivative contracts that are indexed to NYMEX-Henry Hub and regional indices such as NGPL TXOK, TETCO STX, TGT Z1, and Houston Ship Channel in proximity to our areas of production. We also enter into oil derivative contracts indexed to a variety of locations such as NYMEX-WTI, Inter-Continental Exchange (“ICE”) Brent, California Midway-Sunset and other regional locations. Our NGL derivative contracts are primarily indexed to OPIS Mont Belvieu. At December 31, 2014, the MRD Segment had the following open commodity positions: 2015 2016 2017 2018 Natural Gas Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (MMBtu) 3,700,000 2,570,000 1,770,000 2,900,000 Weighted-average fixed price $ 4.15 $ 4.09 $ 4.24 $ 4.27 Collar contracts: Average Monthly Volume (MMBtu) 130,000 1,100,000 1,050,000 — Weighted-average floor price $ 4.00 $ 4.00 $ 4.00 $ — Weighted-average ceiling price $ 4.64 $ 4.71 $ 5.06 $ — Natural gas put option contracts: Average Monthly Volume (MMBtu) 3,000,000 4,100,000 3,450,000 2,850,000 Weighted-average fixed price $ 3.75 $ 3.75 $ 3.75 $ 3.75 Weighted-average deferred premium $ (0.33 ) $ (0.36 ) $ (0.35 ) $ (0.35 ) TGT Z1 basis swaps: Average Monthly Volume (MMBtu) 1,730,000 220,000 200,000 — Spread - Henry Hub $ (0.09 ) $ (0.08 ) $ (0.08 ) $ — Crude Oil Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 46,500 8,500 28,000 31,625 Weighted-average fixed price $ 91.67 $ 84.80 $ 84.70 $ 84.50 Collar contracts: Average Monthly Volume (Bbls) 2,000 27,000 — — Weighted-average floor price $ 85.00 $ 80.00 $ — $ — Weighted-average ceiling price $ 101.35 $ 99.70 $ — $ — Put option contracts: Average Monthly Volume (Bbls) 26,000 — — — Weighted-average fixed price $ 85.00 $ — $ — $ — Weighted-average deferred premium $ (3.80 ) $ — $ — $ — NGL Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 151,000 185,658 — — Weighted-average fixed price $ 41.61 $ 34.06 $ — $ — At December 31, 2014, the MEMP Segment had the following open commodity positions: 2015 2016 2017 2018 2019 Natural Gas Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (MMBtu) 2,605,278 2,692,442 2,450,067 2,160,000 1,914,583 Weighted-average fixed price $ 4.28 $ 4.40 $ 4.31 $ 4.51 $ 4.75 Collar contracts: Average Monthly Volume (MMBtu) 350,000 — — — — Weighted-average floor price $ 4.62 $ — $ — $ — $ — Weighted-average ceiling price $ 5.80 $ — $ — $ — $ — Call spreads (1): Average Monthly Volume (MMBtu) 80,000 — — — — Weighted-average sold strike price $ 5.25 $ — $ — $ — $ — Weighted-average bought strike price $ 6.75 $ — $ — $ — $ — Basis swaps: Average Monthly Volume (MMBtu) 2,940,000 2,508,333 415,000 115,000 — Spread $ (0.12 ) $ (0.04 ) $ 0.00 $ 0.15 $ — Crude Oil Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 314,281 332,813 326,600 312,000 160,000 Weighted-average fixed price $ 90.96 $ 85.83 $ 84.38 $ 83.74 $ 85.52 Collar contracts: Average Monthly Volume (Bbls) 5,000 — — — — Weighted-average floor price $ 80.00 $ — $ — $ — $ — Weighted-average ceiling price $ 94.00 $ — $ — $ — $ — Basis swaps: Average Monthly Volume (Bbls) 97,500 95,000 — — — Spread $ (7.07 ) $ (9.56 ) $ — $ — $ — NGL Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 149,200 84,600 — — — Weighted-average fixed price $ 43.02 $ 41.49 $ — $ — $ — (1 ) These transactions were entered into for the purpose of eliminating the ceiling portion of certain collar arrangements, which effectively converted the applicable collars into swaps. The MEMP Segment basis swaps included in the table above is presented on a disaggregated basis below: 2015 2016 2017 2018 Natural Gas Derivative Contracts: NGPL TexOk basis swaps: Average Monthly Volume (MMBtu) 2,280,000 2,103,333 300,000 — Spread - Henry Hub $ (0.11 ) $ (0.06 ) $ (0.05 ) $ — HSC basis swaps: Average Monthly Volume (MMBtu) 150,000 135,000 115,000 115,000 Spread - Henry Hub $ (0.08 ) $ 0.07 $ 0.14 $ 0.15 CIG basis swaps: Average Monthly Volume (MMBtu) 210,000 — — — Spread - Henry Hub $ (0.25 ) $ — $ — $ — TETCO STX basis swaps: Average Monthly Volume (MMBtu) 300,000 270,000 — — Spread - Henry Hub $ (0.09 ) $ 0.06 $ — $ — Crude Oil Derivative Contracts: Midway-Sunset basis swaps: Average Monthly Volume (Bbls) 57,500 55,000 — — Spread - Brent $ (9.73 ) $ (13.35 ) $ — $ — Midland basis swaps: Average Monthly Volume (Bbls) 40,000 40,000 — — Spread - WTI $ (3.25 ) $ (4.34 ) $ — $ — Interest Rate Swaps Periodically, interest rate swaps are entered into to mitigate exposure to market rate fluctuations by converting variable interest rates such as those in our credit agreements to fixed interest rates. From time to time we enter into offsetting positions to avoid being economically over-hedged. At December 31, 2014, we had the following interest rate swap open positions: Credit Facility 2015 2016 2017 MEMP: Average Monthly Notional (in thousands) $ 314,167 $ 250,000 $ 250,000 Weighted-average fixed rate 1.349 % 1.029 % 1.620 % Floating rate 1 Month LIBOR 1 Month LIBOR 1 Month LIBOR On July 1, 2014, we elected to terminate the interest rate swaps associated with the MRD credit facility and in the aggregate paid our counterparties approximately $0.7 million. WildHorse Resources novated the interest rate swaps to MRD in connection with the closing of our initial public offering. Balance Sheet Presentation The following table summarizes both: (i) the gross fair value of derivative instruments by the appropriate balance sheet classification even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the balance sheet and (ii) the net recorded fair value as reflected on the balance sheet at December 31, 2014 and 2013. There was no cash collateral received or pledged associated with our derivative instruments since most of the counterparties, or certain affiliates, to our derivative contracts are lenders under our collective credit agreements. Asset Derivatives Liability Derivatives Type Balance Sheet Location 2014 2013 2014 2013 (In thousands) Commodity contracts Short-term derivative instruments $ 378,908 $ 21,759 $ 38,852 $ 19,739 Interest rate swaps Short-term derivative instruments — 845 3,289 3,287 Gross fair value 378,908 22,604 42,141 23,026 Netting arrangements Short-term derivative instruments (38,852 ) (13,315 ) (38,852 ) (13,315 ) Net recorded fair value Short-term derivative instruments $ 340,056 $ 9,289 $ 3,289 $ 9,711 Commodity contracts Long-term derivative instruments $ 466,851 $ 83,295 $ 32,787 $ 38,495 Interest rate swaps Long-term derivative instruments 1,305 39 — 2,303 Gross fair value 468,156 83,334 32,787 40,798 Netting arrangements Long-term derivative instruments (32,787 ) (34,718 ) (32,787 ) (34,718 ) Net recorded fair value Long-term derivative instruments $ 435,369 $ 48,616 $ — $ 6,080 (Gains) & Losses on Derivatives All gains and losses, including changes in the derivative instruments’ fair values, have been recorded in the accompanying statements of operations since derivative instruments are not designated as hedging instruments for accounting and financial reporting purposes. The following table details the gains and losses related to derivative instruments for the years ending December 31, 2014, 2013, and 2012: Statements of For the Years Ended December 31, Operations Location 2014 2013 2012 (In thousands) Commodity derivative contracts (Gain) loss on commodity derivatives $ (749,988 ) $ (29,294 ) $ (34,905 ) Interest rate derivatives Interest expense, net 145 (239 ) 5,582

Asset Retirement Obligations

Asset Retirement Obligations	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Note 6. Asset Retirement Obligations Asset retirement obligations primarily relate to our portion of future plugging and abandonment costs for wells and related facilities. The following table presents the changes in the asset retirement obligations for the three months ended March 31, 2015 (in thousands): Asset retirement obligations at beginning of period $ 122,531 Liabilities added from acquisitions or drilling 39 Revisions 149 Accretion expense 1,757 Asset retirement obligations at end of period $ 124,476	Note 6. Asset Retirement Obligations Asset retirement obligations primarily relate to our portion of future plugging and abandonment of wells and related facilities. The following table presents the changes in the asset retirement obligations for the years ended December 31, 2014, 2013 and 2012: 2014 2013 2012 (In thousands) Asset retirement obligations at beginning of period $ 111,769 $ 102,380 $ 90,699 Liabilities added from acquisitions or drilling 5,420 4,227 7,962 Liabilities removed upon sale of wells (669 ) (1,765 ) (1,931 ) Liabilities removed upon plugging and abandoning (588 ) (170 ) (119 ) Revisions 293 1,516 760 Accretion expense 6,306 5,581 5,009 Asset retirement obligations at end of period 122,531 111,769 102,380 Less: Current portion — 90 390 Asset retirement obligations— long-term portion $ 122,531 $ 111,679 $ 101,990

Restricted Investments

Restricted Investments	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Schedule Of Investments [Abstract]
Restricted Investments	Note 7. Restricted Investments Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with offshore Southern California oil and gas properties owned by MEMP. The components of the restricted investment balance consisted of the following at the dates indicated: March 31, December 31, 2015 2014 (In thousands) BOEM platform abandonment (See Note 15) $ 71,263 $ 69,954 BOEM lease bonds 794 794 SPBPC Collateral: Contractual pipeline and surface facilities abandonment 2,818 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 $ 78,787 $ 77,361	Note 7. Restricted Investments Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with the offshore Southern California oil and gas properties owned by MEMP. The components of the restricted investment balance are as follows at December 31, 2014 and 2013: 2014 2013 (In thousands) BOEM platform abandonment (See Note 16) $ 69,954 $ 66,373 BOEM lease bonds 794 794 SPBPC Collateral: Contractual pipeline and surface facilities abandonment 2,701 2,306 California State Lands Commission pipeline right-of-way bond 3,005 3,005 City of Long Beach pipeline facility permit 500 500 Federal pipeline right-of-way bond 307 307 Port of Long Beach pipeline license 100 100 Restricted investments $ 77,361 $ 73,385

Long Term Debt

Long Term Debt	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Debt Disclosure [Abstract]
Long Term Debt	Note 8. Long Term Debt The following table presents our consolidated debt obligations at the dates indicated: March 31, December 31, 2015 2014 (In thousands) MRD Segment: MRD $2.0 billion revolving credit facility, variable-rate, due June 2019 $ 144,000 $ 183,000 5.875% senior unsecured notes, due July 2022 (1) 600,000 600,000 Subtotal 744,000 783,000 MEMP Segment: MEMP $2.0 billion revolving credit facility, variable-rate, due March 2018 573,000 412,000 7.625% senior unsecured notes, due May 2021 ("2021 Senior Notes") (2) 700,000 700,000 6.875% senior unsecured notes, due August 2022 ("2022 Senior Notes") (3) 496,990 500,000 Unamortized discounts (15,945 ) (16,587 ) Subtotal 1,754,045 1,595,413 Total long-term debt $ 2,498,045 $ 2,378,413 (1) The estimated fair value of this fixed-rate debt was $564.0 million and $534.0 million at March 31, 2015 and December 31, 2014, respectively. 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 $640.5 million and $563.5 million at March 31, 2015 and December 31, 2014, respectively. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. (3) The estimated fair value of this fixed-rate debt was $437.4 million and $380.0 million at March 31, 2015 and December 31, 2014, respectively. 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 each credit facility was the following at the date indicated (in thousands): March 31, 2015 MRD Segment: MRD $2.0 billion revolving credit facility, variable-rate, due June 2019 $ 725,000 MEMP Segment: MEMP $2.0 billion revolving credit facility, variable-rate, due March 2018 1,300,000 Subsequent event. On April 13, 2015, MRD’s revolving credit facility borrowing base was re-affirmed at $725.0 million. Weighted-Average Interest Rates The following table presents the weighted-average interest rates paid on our consolidated variable-rate debt obligations for the periods presented: For the Three Months Ended Credit Facility March 31, 2015 2014 MRD Segment: MRD revolving credit facility 1.87 % n/a WildHorse Resources revolver terminated June 2014 n/a 3.97 % WildHorse Resources second lien terminated June 2014 n/a 6.44 % MEMP Segment: MEMP revolving credit facility 1.90 % 1.66 % Unamortized Deferred Financing Costs Unamortized deferred financing costs associated with our consolidated debt obligations were as follows at the dates indicated: March 31, December 31, 2015 2014 (In thousands) MRD Segment: MRD revolving credit facility $ 4,060 $ 4,285 MRD senior notes 12,041 12,455 MEMP Segment: MEMP revolving credit facility 5,395 6,468 2021 Senior Notes 12,779 13,308 2022 Senior Notes 7,656 7,958 $ 41,931 $ 44,474	Note 8. Long Term Debt The following table presents our consolidated debt obligations at the dates indicated. The MEMP Segment debt included in the table below is nonrecourse to the Company. December 31, December 31, 2014 2013 (In thousands) MRD Segment: MRD $2.0 billion revolving credit facility, variable-rate, due June 2019 $ 183,000 $ — WildHorse Resources $1.0 billion revolving credit facility, variable-rate, terminated June 2014 — 203,100 WildHorse Resources $325.0 million second lien term facility, variable-rate, terminated June 2014 — 325,000 10.00%/10.75% senior PIK toggle notes redeemed June 2014 — 350,000 5.875% senior unsecured notes, due July 2022 (1) 600,000 — 10.00%/10.75% senior PIK toggle notes unamortized discounts — (6,950 ) Subtotal 783,000 871,150 MEMP Segment: MEMP $2.0 billion revolving credit facility, variable-rate, due March 2018 412,000 103,000 7.625% senior notes, fixed-rate, due May 2021 (2) 700,000 700,000 6.875% senior unsecured notes, due August 2022 (3) 500,000 — Unamortized discounts (16,587 ) (10,933 ) Subtotal 1,595,413 792,067 Total long-term debt $ 2,378,413 $ 1,663,217 ( 1) The estimated fair value of this fixed-rate debt was $534.0 million at December 31, 2014. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. (2) The estimated fair value of this fixed-rate debt was $563.5 million and $721.0 million at December 31, 2014 and 2013, respectively. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. (3) The estimated fair value of this fixed-rate debt was $380.0 million at December 31, 2014. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. Borrowing Base Credit facilities tied to borrowing bases are common throughout the oil and gas industry. Each of the revolving credit facilities borrowing base is subject to redetermination on at least a semi-annual basis primarily based on estimated proved reserves. The borrowing base for MRD’s and MEMP’s revolving credit facility was the following at the date indicated: December 31, 2014 MRD Segment: MRD $2.0 billion revolving credit facility, variable-rate, due June 2019 $ 725,000 MEMP Segment: MEMP $2.0 billion revolving credit facility, variable-rate, due March 2018 1,440,000 MRD Revolving Credit Facility On June 18, 2014, we, as borrower, and certain of our subsidiaries, as guarantors, entered into a revolving credit facility, which is a five-year, $2.0 billion revolving credit facility with an initial borrowing base of $725.0 million and aggregate elected commitments of $725.0 million. We are permitted to borrow under the revolving credit facility in an amount up to the lesser of (i) the face amount of our revolving credit facility, (ii) the borrowing base or (iii) the aggregate elected commitments. The revolving credit facility is reserve-based, and thus our borrowing base is primarily based on the estimated value of our oil and natural gas properties and our commodity derivative contracts as determined semi-annually by our lenders in their sole discretion. Our borrowing base is subject to redetermination on a semi-annual basis based on an engineering report with respect to our estimated oil, NGL and natural gas reserves, which will take into account the prevailing oil, NGL and natural gas prices at such time, as adjusted for the impact of our commodity derivative contracts. Unanimous approval by the lenders is required for any increase to the borrowing base. In addition, we may, subject to certain conditions, increase our aggregate elected commitments in an amount not to exceed the then effective borrowing base on or following a scheduled redetermination of our borrowing base once before the next scheduled redetermination date. Borrowings under the revolving credit facility are secured by liens on substantially all of our properties, but in any event, not less than 80% of the total value of our oil and natural gas properties, and all of our equity interests in any future guarantor subsidiaries and all of our other assets including personal property. Additionally, borrowings bear interest, at our option, at either (i) the greatest of (x) the prime rate as determined by the administrative agent, (y) the federal funds effective rate plus 0.50%, and (z) the one-month adjusted LIBOR plus 1.0% (adjusted upwards, if necessary, to the next 1/100th of 1%), in each case, plus a margin that varies from 0.50% to 1.50% per annum according to the total commitment usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect), or (ii) the applicable LIBOR plus a margin that varies from 1.50% to 2.50% per annum according to the total commitment usage. The unused portion of the total commitments is subject to a commitment fee that varies from 0.375% to 0.50% per annum according to our total commitments usage. The revolving credit facility requires maintenance of a ratio of Consolidated EBITDAX to Consolidated Net Interest Expense (as each term is determined under the MRD revolving credit facility), which we refer to as the interest coverage ratio, of not less than 2.5 to 1.0, and a ratio of consolidated current assets to consolidated current liabilities, each as determined under the revolving credit facility, which we refer to as the current ratio, of not less than 1.0 to 1.0. Additionally, the revolving credit facility contains various covenants and restrictive provisions that, among other things, limit our ability to incur additional debt, guarantees or liens; consolidate, merge or transfer all or substantially all of our assets; make certain investments, acquisitions or other restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; incur commodity hedges exceeding a certain percentage of our production and prepay certain indebtedness. Events of default under the revolving credit facility include, but are not limited to, failure to make payments when due, breach of any covenant continuing beyond the applicable cure period, default under any other material debt, change in management or change of control, bankruptcy or other insolvency event and certain material adverse effects on our business. MRD 5.875% Senior Unsecured Notes Offering On July 10, 2014, MRD completed a private placement of $600.0 million aggregate principal amount of 5.875% senior unsecured notes (the “MRD Senior Notes”) at par. The MRD Senior Notes will mature on July 1, 2022. Interest on the MRD Senior Notes will accrue from July 10, 2014 and will be payable semiannually on January 1 and July 1 of each year, commencing on January 1, 2015. The MRD Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by certain of our existing subsidiaries (subject to customary release provisions). The MRD Senior Notes and the guarantees of the MRD Senior Notes will rank equally with our and the guarantors’ existing and future senior indebtedness, will be effectively junior to all of our and the guarantors’ existing and future secured indebtedness (to the extent of the value of the assets securing such indebtedness), and senior in right of payment to all of our and the guarantors’ subordinated indebtedness. The MRD Senior Notes will be structurally subordinated to the indebtedness and other liabilities of our non-guarantor subsidiaries, including MEMP and its subsidiaries and MEMP GP. The MRD Senior Notes are governed by an indenture dated as of July 10, 2014. The MRD Senior Notes are subject to optional redemption at prices specified in the indenture plus accrued and unpaid interest, if any, to the date of redemption. The Company may also be required to repurchase the MRD Senior Notes upon a change of control. The indenture contains customary covenants and restrictive provisions, many of which will terminate if at any time no default exists under the indenture and the MRD Senior Notes receive an investment grade rating from both of two specified ratings agencies. MEMP and its subsidiaries are not subject to these covenants. The indenture also provides for customary and other events of default. In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to either the Company or the guarantors, all outstanding MRD Senior Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding MRD Senior Notes may declare all the MRD Senior Notes to be due and payable immediately. PIK notes On December 18, 2013, MRD LLC and its wholly-owned subsidiary Memorial Resource Finance Corp. (“MRD Finance Corp.” and, together with MRD LLC, the “MRD Issuers”) completed a private placement of $350.0 million in aggregate principal amount of the PIK notes. The PIK notes were issued at 98% of par with a maturity date of December 15, 2018. Net proceeds from the private offering were used: (i) to repay all indebtedness then outstanding under MRD LLC’s then-existing revolving credit facility, (ii) to establish a cash reserve of $50.0 million for the payment of interest on the PIK notes, (iii) to pay a $210.0 million distribution to the Funds, and (iv) for general company purposes. Interest on the PIK notes was payable semi-annually in arrears on June 15 and December 15 of each year, commencing on June 15, 2014. A redemption notice was delivered to the PIK notes trustee on June 16, 2014, which specified a redemption date of July 16, 2014 at a redemption price of 102% of the principal amount of the PIK notes plus accrued and unpaid interest thereon to the date of redemption. In connection with the closing of our initial public offering, we assumed the obligations of MRD LLC under the PIK notes indenture and the related debt security agreement. We irrevocably deposited with the PIK notes trustee approximately $360.0 million on June 27, 2014, which was an amount sufficient to fund the redemption of the PIK notes on the redemption date and to satisfy and discharge our obligations under the PIK notes and the related indenture. The discharge became effective upon the irrevocable deposit of the funds with the PIK notes trustee. An extinguishment loss of $23.6 million was recognized related to the redemption of the PIK notes. WildHorse Resources Revolving Credit Facility and Second Lien Facility On April 3, 2013, WildHorse Resources entered into an amended and restated credit agreement. This revolving credit facility provided for aggregate maximum credit amounts at any time of $1.0 billion, consisting of borrowings and letters of credit and had an initial borrowing base of $300.0 million. This revolving credit facility was due to mature on April 13, 2018. The borrowing base was subject to redetermination on at least a semi-annual basis. Borrowings under the revolving credit facility were to be secured by liens on substantially all of WildHorse Resources’ properties, but in any event, not less than 80% of the total value of the WildHorse Resources’ oil and natural gas properties. On June 13, 2013, WildHorse Resources entered into a $325.0 million second lien term loan agreement that was due to mature on December 13, 2018. Borrowings bore interest, at the borrower’s option, at either: (i) the Alternative Base Rate (as defined within each credit facility) plus 5.25% per annum or (ii) the applicable LIBOR plus 6.25% per annum. Borrowings under the second lien term loan agreement were to be secured by second-priority liens on substantially all of WildHorse Resources’ properties, but in any event, not less than 80% of the total value of the WildHorse Resources’ oil and natural gas properties. The priority of the security interests in the collateral and related creditors’ rights was set forth in an intercreditor agreement. The second lien term loan agreement contained customary affirmative and negative covenants, restrictive provisions and events of default. On June 13, 2013, WildHorse Resources borrowed $325.0 million under its second lien term loan agreement and used such borrowings to reduce outstanding indebtedness under its revolving credit facility and to pay a onetime special $225.0 million distribution to MRD LLC. This $225.0 million distribution was subsequently distributed to the Funds. In connection with the closing of our initial public offering, the WildHorse Resources’ revolving credit facility and second lien term loan were repaid in full and terminated. An extinguishment loss of $13.7 million was recognized related to the termination of the revolving credit facility and second lien term loan. MEMP Revolving Credit Facility & Senior Notes Memorial Production Operating LLC (“OLLC”), a wholly-owned subsidiary of MEMP, is a party to a $2.0 billion revolving credit facility, which is guaranteed by MEMP and all of its current and future subsidiaries (other than certain immaterial subsidiaries). Borrowings under the revolving credit facility are secured by liens on substantially all of MEMP’s properties, but in any event, not less than 80% of the total value of MEMP’s oil and natural gas properties, and all of MEMP’s equity interests in OLLC and any future guarantor subsidiaries (other than San Pedro Bay Pipeline Company) and all of MEMP’s other assets including personal property. Additionally, borrowings under the revolving credit facility bear interest, at MEMP’s option, at: (i) the Alternative Base Rate defined as the greatest of (x) the prime rate as determined by the administrative agent, (y) the federal funds effective rate plus 0.50%, and (z) the one-month adjusted LIBOR plus 1.0% (adjusted upwards, if necessary, to the next 1/100th of 1%), in each case, plus a margin that varies from 0.50% to 1.50% per annum according to the borrowing base usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect), (ii) the applicable LIBOR plus a margin that varies from 1.50% to 2.50% per annum according to the borrowing base usage, or (iii) the applicable LIBOR Market Index plus a margin that varies from 1.50% to 2.50% per annum according to the borrowing base usage. The unused portion of the borrowing base (or, if lower, the reduced commitment amount that has been elected) will be subject to a commitment fee that varies from 0.375% to 0.50% per annum according to the borrowing base usage. On April 17, 2013, May 23, 2013 and October 10, 2013, MEMP and its wholly-owned subsidiary Memorial Production Finance Corporation (“Finance Corp.” and, together with MEMP, the “MEMP Issuers”) completed a private placement of $300.0 million, $100.0 million and $300.0 million, respectively, of their 7.625% senior unsecured notes due 2021 (the “2021 Senior Notes”). The 2021 Senior Notes are fully and unconditionally guaranteed (subject to customary release provisions) on a joint and several basis by all of the MEMP’s subsidiaries (other than Finance Corp., which is co-issuer of the 2021 Senior Notes, and certain immaterial subsidiaries). The 2021 Senior Notes will mature on May 1, 2021 with interest accruing at a rate of 7.625% per annum and payable semi-annually in arrears on May 1 and November 1 of each year. The 2021 Senior Notes are governed by an indenture. The 2021 Senior Notes are subject to optional redemption at prices specified in the indenture plus accrued and unpaid interest, if any. The MEMP Issuers may also be required to repurchase the 2021 Senior Notes upon a change of control. The indenture contains customary covenants and restrictive provisions, many of which will terminate if at any time no default exists under the indenture and the 2021 Senior Notes receive an investment grade rating from both of two specified ratings agencies. The indenture also provides for customary and other events of default. In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to either of the MEMP Issuers, all outstanding 2021 Senior Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding 2021 Senior Notes may declare all the 2021 Senior Notes to be due and payable immediately. On July 17, 2014, the MEMP Issuers completed a private placement of $500.0 million aggregate principal amount of 6.875% senior unsecured notes (the “2022 Senior Notes”). The 2022 Senior Notes were issued at 98.485% of par and are fully and unconditionally guaranteed (subject to customary release provisions) on a joint and several basis by all of MEMP’s subsidiaries (other than Finance Corp., which is co-issuer of the 2022 Senior Notes, and certain immaterial subsidiaries). The 2022 Senior Notes will mature on August 1, 2022 with interest accruing at 6.875% per annum and payable semi-annually in arrears on February 1 and August 1 of each year, commencing on February 1, 2015. The indenture governing the 2022 Notes, dated as July 17, 2014, contains customary covenants and restrictive provisions, many of which will terminate if at any time no default exists under the indenture and the 2022 Senior Notes receive an investment grade rating from both of two specified ratings agencies. The indenture also provides for customary and other events of default. In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to either of the MEMP Issuers, all outstanding 2022 Senior Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding 2022 Senior Notes may declare all the 2022 Senior Notes to be due and payable immediately. Weighted-Average Interest Rates The following table presents the weighted-average interest rates paid on our consolidated and combined variable-rate debt obligations for the periods presented: For the Year Ended December 31, 2014 2013 2012 MRD Segment: MRD revolving credit facility 1.99 % n/a n/a WildHorse Resources revolver terminated June 2014 4.04 % 2.30 % 3.00 % WildHorse Resources second lien terminated June 2014 6.44 % 7.60 % n/a Black Diamond terminated November 2013 n/a 3.97 % 3.62 % MEMP Segment: MEMP revolving credit facility 2.67 % 3.25 % 2.74 % WHT revolver terminated March 2013 n/a 2.29 % 2.60 % Tanos revolver terminated April 2013 n/a 3.10 % 2.31 % REO revolving credit facility terminated December 2012 n/a n/a 3.40 % Stanolind revolver paid off by MEMP October 2013 n/a 3.52 % 3.76 % Boaz revolver terminated October 2013 n/a 2.97 % 3.12 % Crown revolver terminated October 2013 n/a 3.38 % 4.20 % MRD LLC revolver terminated December 2013 n/a 3.17 % 4.11 % Classic revolving credit facility terminated November 2012 n/a n/a 4.50 % Propel Energy revolver paid off by MEMP October 2013 n/a 3.08 % 3.28 % Unamortized Deferred Financing Costs Unamortized deferred financing costs associated with our consolidated debt obligations were as follows at the dates indicated: December 31, December 31, 2014 2013 (In thousands) MRD Segment: MRD revolving credit facility $ 4,285 $ — MRD senior notes 12,455 — WildHorse Resources revolving credit facility — 2,436 WildHorse Resources second lien term loan — 9,030 PIK notes — 8,261 MEMP Segment: MEMP revolving credit facility 6,468 5,413 2021 Senior Notes 13,308 15,053 2022 Senior Notes 7,958 — $ 44,474 $ 40,193

Stockholders' Equity and Noncon

Stockholders' Equity and Noncontrolling Interests	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Equity [Abstract]
Stockholders' Equity and Noncontrolling Interests	Note 9. Stockholders’ Equity and Noncontrolling Interests Common Stock The Company's authorized capital stock includes 600,000,000 shares of common stock, $0.01 par value per share. The following is a summary of the changes in our common shares issued for the three months ended March 31, 2015: Balance December 31, 2014 193,435,414 Shares of common stock repurchased (2,764,887 ) Restricted common shares issued (Note 11) 115,302 Restricted common shares forfeited (9,211 ) Balance March 31, 2015 190,776,618 See Note 11 for additional information regarding restricted common shares. Restricted shares of common stock are considered issued and outstanding on the grant date of the restricted stock award. Share Repurchase Program MRD repurchased 2,764,887 shares of common stock under the December 2014 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. Subsequent event. In April 2015, the board of directors (“Board”) of the Company authorized the repurchase of up to $50.0 million of the Company’s outstanding common stock from time to time on the open market, through block trades or otherwise. 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. Noncontrolling Interests Noncontrolling interests is the portion of equity ownership in the Company’s consolidated subsidiaries not attributable to the Company and primarily consists of the equity interests held by: (i) the limited partners of MEMP and (ii) a third party investor in the San Pedro Bay Pipeline Company. Prior to our initial public offering, certain current or former key employees of certain of MRD LLC’s subsidiaries also held equity interests in those subsidiaries. Distributions paid to the limited partners of MEMP primarily represent the quarterly cash distributions paid to MEMP’s unitholders, excluding those paid to MRD LLC prior to our initial public offering. Contributions received from limited partners of MEMP primarily represent net cash proceeds received from common unit offerings. During the three months ended March 31, 2015, MEMP repurchased 1,909,583 common units under its repurchase program for an aggregate price of $28.4 million. MEMP has retired all common units repurchased and those common units are no longer issued or outstanding.	Note 9. Stockholders’ Equity and Noncontrolling Interests Common Stock The Company’s authorized capital stock includes 600,000,000 shares of common stock, $0.01 par value per share. The following is a summary of the changes in our common shares issued for the year ended December 31, 2014: Balance January 1, 2014 — Shares of common stock issued in connection with restructuring transactions (Note 1) 171,000,000 Shares of common stock issued in initial public offering (Note 1) 21,500,000 Shares of common stock repurchased and retired (123,797 ) Restricted common shares issued (Note 11) 1,068,422 Restricted common shares forfeited (9,211 ) Balance December 31, 2014 193,435,414 See Note 11 for additional information regarding restricted common shares that were granted in connection with our initial public offering. Restricted shares of common stock are participating securities and considered issued and outstanding on the grant date of restricted stock award. Share Repurchase Program In December 2014, the board of directors (“Board”) of the Company authorized the repurchase of up to $50.0 million through block trades or otherwise and are subject to market conditions, as well as corporate, regulatory, and other considerations. 123,797 shares of common stock $2.2 million Subsequent event . MRD repurchased 2,764,887 shares of common stock under our repurchase program for an aggregate price of $47.8 million through March 16, 2015. MRD has retired all of the shares of common stock repurchased and the shares of common stock are no longer issued or outstanding. Preferred Stock Our amended and restated certificate of incorporation authorizes our Board, subject to any limitations prescribed by law, without further stockholder approval, to establish and to issue from time to time one or more classes or series of preferred stock, par value $0.01 per share, covering up to an aggregate of 50,000,000 shares of preferred stock. There are no shares of preferred stock issued and outstanding as of December 31, 2014. Dividend Policy We do not anticipate declaring or providing any cash dividends to holders of our common stock in the foreseeable future. We currently intend to retain all future earnings, if any, for use in the operation of our business and to fund future growth. The decision whether to pay dividends in the future will be made by our Board in light of conditions then existing, including factors such as our financial condition, earnings, available cash, business opportunities, legal requirements, restrictions in our debt agreements, and other contracts and other factors our Board deems relevant. Noncontrolling Interests Noncontrolling interests is the portion of equity ownership in the Company’s consolidated subsidiaries not attributable to the Company and primarily consists of the equity interests held by: (i) the limited partners of MEMP, including the subordinated units held by MRD Holdco, that converted to common units in February 2015, and (ii) a third party investor in the San Pedro Bay Pipeline Company. Prior to our initial public offering, certain current or former key employees of certain of MRD LLC’s subsidiaries also held equity interests in those subsidiaries. Distributions paid to the limited partners of MEMP primarily represent the quarterly cash distributions paid to MEMP’s unitholders, excluding those paid to MRD LLC. Contributions received from limited partners of MEMP primarily represent net cash proceeds received from common unit offerings. In December 2012, MEMP sold 11,975,000 if its common units in an underwritten equity offering, which generated net cash proceeds of $194.1 million. The net proceeds from this equity offering partially funded MEMP’s December 2012 acquisition. On March 25, 2013, MEMP sold 9,775,000 of its common units in an underwritten equity offering, which generated net cash proceeds of $171.8 million after deducting underwriting discounts and offering expenses. The net proceeds from this equity offering partially funded MEMP’s acquisition of all of the outstanding equity interests in WHT. On October 8, 2013, MEMP sold 16,675,000 of its common units in an underwritten equity offering, which generated net cash proceeds of approximately $318.3 million after deducting underwriting discounts and offering expenses. The net proceeds from this equity offering were used to repay a portion of outstanding borrowings under MEMP’s revolving credit facility. On July 15, 2014, MEMP sold 9,890,000 common units in an underwritten equity offering, which generated net proceeds of approximately $220.0 million after deducting offering expenses. The net proceeds from the equity offering were used to repay a portion of the outstanding borrowings under MEMP’s revolving credit facility. On September 9, 2014, MEMP sold 14,950,000 common units in an underwritten equity offering, which generated net proceeds of approximately $321.3 million after deducting underwriting discounts and offering expenses. The net proceeds from the equity offering were used to repay a portion of the outstanding borrowings under MEMP’s revolving credit facility. In December 2014, the board of directors of MEMP GP authorized the repurchase of up to $150.0 million through block trades or otherwise and are subject to market conditions, as well as corporate, regulatory, and other considerations 899,912 common units $12.9 million Subsequent event . MEMP repurchased 1,909,583 common units under its repurchase program for an aggregate price of $28.5 million through February 1, 2015. MEMP has retired all common units repurchased and the common units are no longer issued or outstanding. On April 1, 2013, Tanos’ management team sold its 1.066% interest in Tanos to MRD LLC and all incentive units held were forfeited. See Note 12 for further information. In connection with this sale, all of Tanos’ employees resigned and became employees of Tanos Exploration II, LLC (“Tanos II”), a Texas limited liability company controlled by the former management team of Tanos. Effective April 1, 2013, Tanos II entered into a transition services agreement with Tanos, whereby Tanos II would manage the operations of Tanos for up to a 6-month period of time. Tanos II is an unrelated entity. On November 1, 2013, MRD LLC purchased the noncontrolling interests in Black Diamond, Classic GP and Classic and all incentive units were forfeited. See Note 12 for further information. In connection with our initial public offering, certain former management members of WildHorse Resources contributed their 0.1% membership interest in WildHorse Resources as well as their incentive units in exchange for shares of our common stock and cash consideration of $30.0 million. The difference between the carrying amount of the noncontrolling interest of $0.4 million and the fair value of the consideration paid of $3.3 million was recognized directly in stockholders’ equity as additional paid in capital. See Note 12 for further information.

Earnings per Share

Earnings per Share	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Earnings Per Share [Abstract]
Earnings per Share	Note 10. Earnings per Share The following sets forth the calculation of earnings (loss) per share, or EPS, for the periods indicated (in thousands, except per share amounts): For the Three Months Ended March 31, 2015 Numerator: Net income (loss) available to common stockholders $ 45,615 Denominator: Weighted average common shares outstanding 190,705 Basic EPS $ 0.24 Diluted EPS (1) $ 0.24 (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 the period presented. Under the treasury stock method, 151,123 incremental shares were included in the diluted EPS computation.	Note 10. Earnings per Share The following sets forth the calculation of earnings (loss) per share, or EPS, for the period indicated (in thousands, except per share amounts): For the Year Ended December 31, 2014 Numerator: Net income (loss) available to common stockholders $ (784,581 ) Denominator: Weighted average common shares outstanding 192,498 Basic EPS $ (4.08 ) Diluted EPS (1) $ (4.08 ) (1) The Company determines the more dilutive of either the two-class method or the treasury stock method for diluted EPS. The restricted common shares were antidilutive due to net losses and excluded from the diluted EPS calculation for the year ending December 31, 2014. There were 202,623 incremental shares excluded from the computation of diluted EPS for the year ending December 31, 2014. Our supplemental basic and diluted EPS includes earnings allocated to both previous owners and MRD LLC members for the period presented due to common control considerations. The following sets forth the calculation of our supplemental EPS, for the period indicated (in thousands, except per share amounts): For the Year Ended December 31, 2014 Numerator: Net income (loss) attributable to Memorial Resource Development Corp. $ (762,851 ) Denominator: Weighted average common shares outstanding 192,498 Basic EPS $ (3.96 ) Diluted EPS (1) $ (3.96 ) (1) The Company determines the more dilutive of either the two-class method or the treasury stock method for diluted EPS. The restricted common shares were antidilutive due to net losses and excluded from the diluted EPS calculation for the year ending December 31, 2014. There were 202,623 incremental shares excluded from the computation of diluted EPS for the year ending December 31, 2014.

Long-Term Incentive Plans

Long-Term Incentive Plans	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Long-Term Incentive Plans	Note 11. Long-Term Incentive Plans MRD The following table summarizes information regarding restricted common share awards granted under the Memorial Resource Development Corp. 2014 Long-Term Incentive Plan for the periods presented: Number of Shares Weighted-Average Grant Date Fair Value per Share (1) Restricted common shares outstanding at December 31, 2014 1,059,211 $ 19.00 Granted (2) 115,302 $ 18.05 Forfeited (9,211 ) $ 19.00 Restricted common shares outstanding at March 31, 2015 1,165,302 $ 18.91 (1) Determined by dividing the aggregate grant date fair value of awards issued. (2) The aggregate grant date fair value of restricted common share awards issued in 2015 was $2.1 million based on a grant date market price of $18.05 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 Three Months Ended March 31, 2015 2014 $ 1,486 n/a The unrecognized compensation cost associated with restricted common share awards was $17.7 million at March 31, 2015. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 3.13 years. MEMP The following table summarizes information regarding restricted common unit awards granted under the Memorial Production Partners GP LLC Long-Term Incentive Plan for the periods presented: Number of Units Weighted-Average Grant Date Fair Value per Unit (1) Restricted common units outstanding at December 31, 2014 1,093,520 $ 20.93 Granted (2) 157,360 $ 15.45 Forfeited (12,467 ) $ 20.73 Vested (78,307 ) $ 19.16 Restricted common units outstanding at March 31, 2015 1,160,106 $ 20.31 (1) Determined by dividing the aggregate grant date fair value of awards issued. (2) The aggregate grant date fair value of restricted common unit awards issued in 2015 was $2.4 million based on a grant date market price of $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 Three Months Ended March 31, 2015 2014 $ 2,341 $ 1,295 The unrecognized compensation cost associated with restricted common unit awards was $16.3 million at March 31, 2015. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 1.99 years. Since the restricted common units are participating securities, distributions received by the restricted common unitholders are generally included in distributions to noncontrolling interests as presented on our unaudited condensed statements of consolidated and combined cash flows.	Note 11. Long-Term Incentive Plans MRD In June 2014, our Board adopted the Memorial Resource Development Corp. 2014 Long Term Incentive Plan (“MRD LTIP”) for the employees of the Company and the Board. The MRD LTIP became effective upon filing of a registration statement on Form S-8 with the SEC on June 18, 2014. The MRD LTIP provides for potential grants of stock options, stock appreciation rights, restricted stock awards, restricted stock units, bonus stock, dividend equivalents, performance awards, annual incentive awards, and other stock-based awards. The MRD LTIP initially limits the number of common shares that may be delivered pursuant to awards under the plan up to 19,250,000 common shares. Common shares that are cancelled, forfeited or withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards. The MRD LTIP will be administered by our Board or a committee thereof. In connection with our initial public offering, our Board approved an aggregate award of 1,052,633 shares of restricted stock under the MRD LTIP to certain of our key employees, including each of our executive officers. These restricted stock awards will vest ratably on a four-year annual vesting schedule from the date of the grant and are subject to restrictions on transferability and customary forfeiture provisions. An award of 5,263 shares of restricted stock was also granted to each of our independent directors. These restricted stock awards will vest one year from the date of the grant and are also subject to restrictions on transferability and customary forfeiture provisions. Award recipients are entitled to all the rights of absolute ownership of the restricted common shares, including the right to vote those shares and to receive dividends thereon if, as, and when declared by our Board. The term “restricted common share” represents a time-vested share. Such awards are non-vested until the required service period expires. The following table summarizes information regarding restricted common share awards granted under the MRD LTIP for the periods presented: Number of Shares Weighted-Average Grant Date Fair Value per Share (1) Restricted common shares outstanding at January 1, 2014 — $ — Granted (2) 1,068,422 $ 19.00 Forfeited (9,211 ) $ 19.00 Restricted common units outstanding at December 31, 2014 1,059,211 $ 19.00 (1) Determined by dividing the aggregate grant date fair value of awards by the number of awards issued. ( 2 ) The aggregate grant date fair value of restricted common share awards issued in 2014 was $20.3 million based on grant date market price of $19.00 per share. The following table summarizes the amount of recognized compensation expense associated with these awards that are reflected in the accompanying statements of operations for the periods presented (in thousands): For the Year Ended December 31, 2014 $ 2,804 The unrecognized compensation cost associated with restricted common share awards was an aggregate $17.3 million at December 31, 2014. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 3.43 years. MEMP In December 2011, the Memorial Production Partners GP LLC Long-Term Incentive Plan (“MEMP LTIP”) was adopted for employees, officers, consultants and directors of MEMP GP and any of its affiliates who perform services for MEMP. The MEMP LTIP consists of restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, other unit-based awards and unit awards. The MEMP LTIP initially limits the number of common units that may be delivered pursuant to awards under the plan to 2,142,221 common units. Common units that are cancelled, forfeited or withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards. The restricted common units awarded are subject to restrictions on transferability, customary forfeiture provisions and graded vesting provisions. One-third of each award generally vests on the first, second, and third anniversaries of the date of grant. Award recipients have all the rights of a unitholder in MEMP with respect to the restricted common units, including the right to receive distributions thereon if and when distributions are made by MEMP to its unitholders (except with respect to the fourth quarter 2011 distribution that was paid in February 2012). The term “restricted common unit” represents a time-vested unit. Such awards are non-vested until the required service period expires. The following table summarizes information regarding restricted common unit awards granted under the MEMP LTIP for the periods presented: Number of Units Weighted-Average Grant Date Fair Value per Unit (1) Restricted common units outstanding at December 31, 2011 — $ — Granted (2) 287,943 $ 18.07 Forfeited (2,334 ) $ 17.14 Restricted common units outstanding at December 31, 2012 285,609 $ 18.08 Granted (3) 524,718 $ 18.83 Forfeited (11,734 ) $ 17.24 Vested (91,666 ) $ 18.31 Restricted common units outstanding at December 31, 2013 706,927 $ 18.62 Granted (4) 684,954 $ 22.39 Forfeited (38,294 ) $ 20.54 Vested (260,067 ) $ 18.56 Restricted common units outstanding at December 31, 2014 1,093,520 $ 20.93 (1) Determined by dividing the aggregate grant date fair value of awards by the number of awards issued. (2) The aggregate grant date fair value of restricted common unit awards issued in 2012 was $5.2 million based on grant date market prices ranging from of $17.14 to $18.58 per unit. ( 3 ) The aggregate grant date fair value of restricted common unit awards issued in 2013 was $9.9 million based on grant date market prices ranging from of $18.33 to $20.35 per unit. ( 4 ) The aggregate grant date fair value of restricted common unit awards issued in 2014 was $15.3 million based on grant date market prices ranging from of $21.99 to $23.40 per unit. The following table summarizes the amount of recognized compensation expense associated with these awards that are reflected in the accompanying statements of operations for the periods presented (in thousands): For the Year Ended December 31, 2014 2013 2012 $ 7,874 $ 3,558 $ 1,423 The unrecognized compensation cost associated with restricted common unit awards was $16.5 million at December 31, 2014. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.1 years. Since the restricted common units are participating securities, any distributions received by the restricted common unitholders are included in distributions to noncontrolling interests as presented on our statements of consolidated and combined cash flows.

Incentive Units

Incentive Units	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Compensation Related Costs [Abstract]
Incentive Units	Note 12. Incentive Units 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 $10.2 million of compensation expense during the three months ended March 31, 2015, offset by a deemed capital contribution from MRD Holdco and the unrecognized compensation expense of approximately $95.5 million as of March 31, 2015 will be recognized over the remaining expected service period of 2.17 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 will be allocated to us in future periods offset by deemed capital contributions. 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 3/31/2015 3/31/2015 Dividend yield 0 % 0 % Expected volatility 27.90 % 27.90 % Risk-free rate 0.61 % 0.61 % Expected life (years) 2.17 2.17	Note 12. Incentive Units General Each of the governing documents of BlueStone, Tanos, WildHorse Resources, Classic, Black Diamond and MRD LLC previously provided for the issuance of incentive units. The incentive units were subject to performance conditions that affected their vesting. Compensation cost was recognized only if the performance condition was probable of being satisfied at each reporting date. BlueStone, Tanos, WildHorse Resources, Classic, Black Diamond and MRD LLC each granted incentive units to certain of its members who were key employees at the time of grant. Holders of incentive units were entitled to distributions ranging from 10% to 31.5% when declared, but only after cumulative distribution thresholds (“payouts”) had been achieved. Payouts were generally triggered after the recovery of specified members’ capital contributions plus a rate of return. In connection with MEMP’s initial public offering in December 2011, BlueStone’s Special Tier and Tier I unit holders vested in their respective awards. Tier I unit holders became eligible to participate in 16.5% of any future distributions made by BlueStone. Vesting of the incentive units was generally dependent upon an explicit service period, a fundamental change as defined in the respective governing document, and achievement of payout. All incentive units not vested were forfeited if an employee was no longer employed. All incentive units were forfeited if a holder resigned whether the incentive units were vested or not. If the payouts had not yet occurred, then all incentive units, whether or not vested, were forfeited automatically (unless extended). On April 1, 2013, Tanos’ management team sold its 1.066% interest in Tanos to MRD LLC and all incentive units held were forfeited. Compensation expense of approximately $5.8 million was recorded by Tanos and recognized as a component of general and administrative expense during the year ended December 31, 2013. On November 1, 2013, MRD LLC purchased the noncontrolling interests in Black Diamond, Classic GP and Classic and all incentive units were forfeited. Compensation expense of approximately $12.6 million was recorded by Black Diamond, Classic GP and Classic in the aggregate during November 2013. Compensation expense of approximately $1.0 million and $20.7 million was recorded by BlueStone and recognized as a component of incentive unit compensation expense during the year ended December 31, 2014 and 2013, respectively. No compensation expense was recorded at December 31, 2012. In connection with the PIK notes issued in December 2013, a special distribution of $10.0 million to holders of WildHorse’s Tier 1 incentive units was deemed probable of occurring. This amount was recognized as compensation expense in December 2013 with a corresponding amount in accrued liabilities on our balance sheet at December 31, 2013 as payment was not made until January 2, 2014. In connection with the our initial public offering, certain former management members of WildHorse Resources contributed their 0.1% membership interest in WildHorse Resources as well as their incentive units in exchange for 42,334,323 shares of our common stock and cash consideration of $30.0 million. The portion of the total consideration related to acquiring the 0.1% membership interest was accounted for as the acquisition of noncontrolling interests. The difference between the carrying amount of the noncontrolling interest of $0.4 million and the fair value of the consideration paid of $3.3 million was recognized directly in stockholders’ equity as additional paid in capital. Compensation expense of approximately $831.1 million was recognized as a component of incentive unit compensation expense during the year ended December 31, 2014 related to the incentive units, of which approximately $26.7 million was paid in cash and the remaining $804.4 million related to the issuance of our common stock. MRD Holdco MRD LLC incentive units were originally granted in June 2012 and February 2013. In connection with our initial public offering and the related restructuring transactions, these incentive units were exchanged for substantially identical units in MRD Holdco, and such incentive units entitle holders thereof to portions of future distributions by MRD Holdco. MRD Holdco’s governing documents authorize the issuance of 1,000 incentive units, of which 930 incentive units were granted in an exchange for the cancelled MRD LLC awards (the “Exchanged Incentive Units”). The holders of the Exchanged Incentive Units are eligible to participate in 9.3% of any future distributions made by MRD Holdco. The payment likelihood was deemed probable as a result of our initial public offering and the reasonable expectation that MRD Holdco will monetize the shares of our common stock it owns over an estimated three year period as market conditions permit. During 2014, we recognized $111.5 million of compensation expense offset by a deemed capital contribution from MRD Holdco and the unrecognized compensation expense of approximately $105.5 million as of December 31, 2014 will be recognized over the remaining expected service period of 2.41 years. Subsequent to our initial public offering, MRD Holdco granted the remaining 70 incentive units to certain key employees (the “Subsequent Incentive Units”). The holders of the Subsequent Incentive Units are eligible to participate in 0.7% of any future distributions made by MRD Holdco once payout associated with these incentive units has been achieved. The payment likelihood was deemed probable at December 31, 2014 as a result of our initial public offering and the reasonable expectation that MRD Holdco will monetize the shares of our common stock it owns over an estimated three year period as market conditions permit. During 2014, we recognized $0.4 million of compensation expense and the unrecognized compensation expense of approximately $1.7 million as of December 31, 2014 will be recognized over the remaining expected service period of 2.41 years. The fair value of the Exchanged and Subsequent Incentive Units will be remeasured on a quarterly basis until all payments have been made. The settlement obligation rests with MRD Holdco. Accordingly, no payments will ever be made by us related to these incentive units; however, non-cash compensation expense will be allocated to us in future periods offset by capital contributions. 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 12/31/2014 12/31/2014 Dividend yield 0 % 0 % Expected volatility 39.54 % 39.54 % Risk-free rate 0.85 % 0.85 % Expected life (years) 2.41 2.41

Related Party Transactions

Related Party Transactions	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Related Party Transactions [Abstract]
Related Party Transactions	Note 13. Related Party Transactions Amounts due to (due from) MRD Holdco and certain affiliates of NGP at March 31, 2015 and December 31, 2014 are presented as “Accounts receivable – – NGP Affiliated Companies During the three months ended March 31, 2015, MRD paid approximately $0.6 million to Cretic Energy Services, LLC, a NGP affiliated company, for services related to our drilling and completion activities. NGPCIF NPI Acquisition WildHorse Resources purchased a net profits interest 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. Other Acquisitions or Dispositions On March 10, 2014, BlueStone sold certain interests in oil and gas properties in McMullen, Webb, Zapata, and Hidalgo Counties located in South Texas to BlueStone Natural Resources II, LLC, an NGP controlled entity. Total cash consideration received by BlueStone was approximately $1.2 million, which exceeded the net book value of the properties sold by $0.5 million. Due to common control considerations, the $0.5 million was recognized in the equity statement as a contribution. On March 28, 2014, our predecessor acquired certain interests in oil and gas properties in Gonzales and Karnes Counties located in South Texas from a NGP affiliated company for $3.3 million. Due to common control considerations, this transaction was recognized in the equity statement. Related Party Agreements We and certain of our affiliates have entered into various documents and agreements. These agreements have been negotiated among affiliated parties and, consequently, are not the result of arm’s-length negotiations. Registration Rights Agreement In connection with the closing of our initial public offering, we entered into a registration rights agreement with MRD Holdco and former management members of WildHorse Resources, Jay Graham (“Graham”) and Anthony Bahr (“Bahr”). Pursuant to the registration rights agreement, we have agreed to register the sale of shares of our common stock under certain circumstances. Voting Agreement In connection with the closing of our initial public offering, we entered into a voting agreement with MRD Holdco, WHR Incentive LLC, a limited liability company beneficially owned by Messrs. Bahr and Graham, and certain former management members of WildHorse Resources, who contributed their ownership of WildHorse Resources to us in the restructuring transactions. Among other things, the voting agreement provides that those former management members of WildHorse Resources will vote all of their shares of our common stock as directed by MRD Holdco. Services Agreement In connection with the closing of our initial public offering, we entered into a services agreement with WildHorse Resources and WildHorse Resource Management Company, LLC (“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 (“WHR II”). NGP and certain former management members of WildHorse Resources own WHR II. The services agreement was terminated effective March 1, 2015. WildHorse Management Services Agreement A discussion of the WildHorse and WHR II management services and related agreements is included in our 2014 Form 10-K. These agreements were terminated in connection with our initial public offering. Gas Processing Agreement Subsequent event . On April 14, 2015, we, through our wholly-owned subsidiary, MRD Operating, entered into an amended and restated gas processing agreement (“GPA”) with PennTex North Louisiana Operating, LLC (“PennTex Operating”), a wholly-owned subsidiary of PennTex North Louisiana, LLC (“PennTex”). WildHorse Resources, which owned our interest in the Terryville Complex and merged into MRD Operating in February 2015, initially entered into a gas processing agreement with PennTex in March 2014, prior to our initial public offering. PennTex is a joint venture among certain affiliates of NGP in which MRD Midstream LLC, a wholly-owned subsidiary of MRD Holdco, owns a minority interest. Once PennTex Operating’s first processing plant becomes operational, it will process natural gas produced from wells located on certain leases owned by us in the state of Louisiana. The GPA has a 15-year primary term, subject to one-year extensions at either party’s election. We will pay PennTex Operating a monthly volume processing fee, subject to annual inflation escalators, based on volumes of natural gas processed by PennTex Operating. Once the first plant is declared operational, we will be obligated to pay a minimum processing fee equal to approximately $18.3 million on an annual basis, subject to certain adjustments and conditions until the second processing plant is declared operational. Once the second plant is declared operational, we will be obligated to pay a minimum volume processing fee equal to approximately $55.0 million on an annual basis, subject to certain adjustments and conditions. In addition, on April 14, 2015, we entered into (i) an amended and restated area of mutual interest and midstream exclusivity agreement (“AMI”) with PennTex NLA Holdings, LLC, which owns a majority interest in PennTex, MRD WHR LA Midstream LLC, an affiliate of MRD Holdco, and PennTex, (ii) a gas transportation agreement (“GTA”) with PennTex Operating, (iii) a gas gathering agreement (“GGA”) with PennTex Operating, and (iv) a transportation services agreement (“TSA” and, together with the GPA, AMI, GTA, and GGA, the “Midstream Agreements”) with PennTex Operating to provide gathering, residue gas and natural gas liquids transportation services to us in the state of Louisiana. The Midstream Agreements have a 15-year primary term, subject to one-year extensions at either party’s elections. Under the GGA, once the first processing plant is declared operational, we will pay PennTex Operating a commodity usage charge equal to at least the minimum volume commitment (115,000 MMBtu per day) times $0.02 per MMBtu until PennTex Operating’s second processing plant is declared operational. Once the second processing plant is declared operational, we will pay PennTex Operating a commodity usage charge equal to at least an increased minimum volume commitment (345,000 MMBtu per day) times $0.02 MMBtu through November 30, 2019. The minimum volume commitment will increase to 460,000 MMBtu on July 1, 2016 and may further increase subject to the terms of the GGA. Prior to December 1, 2019, PennTex Operating is also entitled to a payback demand fee from us equal to the monthly demand quantity (460,000 MMBtu per day) times a $0.03 MMBtu through November 30, 2019. Beginning on December 1, 2019, PennTex Operating is not entitled to a monthly demand charge, the commodity usage charge escalates to $0.05 per MMBtu, and PennTex Operating is entitled to receive a commodity usage charge from us equal to the minimum volume commitment (460,000 MMBtu per day through June 30, 2026, and 345,000 MMBtu per day thereafter) times $0.05 MMBtu. Similarly, under each of the GTA and TSA, which commence concurrently with the operational dates of the two processing plants, PennTex Operating will be entitled to a commodity usage charge of $0.04 per MMBtu for all volumes of residue gas and natural gas liquids produced on our behalf. Under the AMI, we granted PennTex Operating the exclusive right to build all of our midstream infrastructure in northern Louisiana and to provide midstream services to support our current and future production on our operated acreage within such area (other than production subject to existing third-party commitments). Classic Pipeline Gas Gathering Agreement & Water Disposal Agreement In November 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. In May 2014, Classic Operating and Classic Pipeline amended the gas gathering agreement with respect to Classic Operating’s remaining assets located in Panola and Shelby Counties, Texas. Under the amended gas gathering agreement, Classic Operating agreed to pay a fee of (i) $0.30 per MMBtu, subject to an annual 3.5% inflationary escalation, based on volumes of natural gas delivered and processed, and (ii) $0.07 per MMBtu per stage of compression plus its allocated share of compressor fuel. The amended gas gathering agreement has a term until December 31, 2023, subject to one-year extensions at either party’s election. In May 2014, Classic Operating and Classic Pipeline entered into a water disposal agreement. The water disposal agreement has a three-year term, subject to one-year extensions at either party’s election. Under the water disposal agreement, Classic Operating agreed to pay a fee of $1.10 per barrel for each barrel of water delivered to Classic Pipeline. 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 Memorial Production Operating LLC, a wholly-owned subsidiary of MEMP, and Classic and Classic GP were merged into MRD Operating in March 2015.	Note 13. Related Party Transactions Amounts due to (due from) MRD Holdco and certain affiliates of NGP at December 31, 2014 and 2013 are presented as “Accounts receivable – affiliates” and “Accounts payable – affiliates” in the accompanying balance sheets. Net Profits Interest Sold to NGP Upon the completion of the 2010 Petrohawk and Clayton Williams acquisitions, WildHorse Resources sold a net profits interest in these properties to NGPCIF. Upon the acquisition of the Petrohawk properties WildHorse Resources immediately sold a net profits interest of 6.25% for all producing well bores and the right to participate in a 3.125% net profits interest in non-producing wellbores for the subject area for $19.5 million, or $19.1 million after adjustments. Upon the acquisition of the Clayton Williams properties, WildHorse Resources immediately sold a net profits interest of 23.5% for all producing wellbores and the right to participate in a 10.0% net profits interest in non-producing wellbores for the subject area for $19.8 million, or $19.9 million after adjustments. No gain or loss was recorded from these two transactions. The net profits agreements for these transactions provided for a fixed fee of $20,000 per month for overhead and management in lieu of COPAS (Council of Petroleum Accountants Societies) billings. The net profits agreements did not provide for an overhead adjustment factor for this monthly charge, as suggested by COPAS. Quarterly net payments were made to NGPCIF for its net profits interest in the Petrohawk and Clayton Williams acquisitions. The net payments included credits for revenue receipts which were offset with production costs, capital expenditures and the management fee and were adjusted for any acquisition settlements received or paid and any other miscellaneous adjustments. As required by such agreements, WildHorse Resources could not collect funds owed by NGPCIF to WildHorse Resources, but WildHorse Resources could net amounts due from future quarterly payments. As a result of these transactions, WildHorse Resources paid NGPCIF a total of $2.6 million and $2.3 million during 2013 and 2012, respectively. NGPCIF owed WildHorse Resources $0.2 million at December 31, 2013. NGPCIF NPI Acquisition WildHorse Resources repurchased the net profits interests discussed above from NGPCIF on February 28, 2014 for a purchase price of $63.4 million (see Note 1). This acquisition was accounted for as a combination of entities under common control at historical cost in a manner similar to the pooling of interest method. WildHorse Resources recorded the following net assets (in thousands): Accounts receivable $ 2,274 Oil and natural gas properties, net 40,056 Accrued liabilities (297 ) Asset retirement obligations (277 ) Net assets $ 41,756 Due to common control considerations, the difference between the purchase price and the net assets acquired are reflected within equity as a deemed distribution to NGP affiliates. Transactions Between the Previous Owners and NGP Affiliates The previous owners sold certain interests in oil and gas properties offshore Louisiana on October 11, 2012 for an aggregate $40.1 million to an NGP controlled entity, of which $38.1 million was received upon closing and the remaining proceeds were released from escrow in April 2013. Due to common control considerations, the proceeds from the sale exceeded the net book value of the properties sold by $6.3 million and recognized in the equity statement as a net contribution. Beta Acquisition On December 12, 2012, MEMP acquired Rise Energy Operating, Inc. (‘REO”), which owns certain operating interests in producing and non-producing oil and gas properties offshore Southern California (the “Beta Properties”), from Rise for a purchase price of $270.6 million, which included $3.0 million of working capital and other customary adjustments. The Beta acquisition was funded with borrowings under MEMP’s revolving credit facility and the net proceeds generated from its December 12, 2012 public offering of common units. This acquisition was accounted for as a combination of entities under common control at historical cost in a manner similar to the pooling of interest method. MEMP recorded the following net assets (in thousands): Cash and cash equivalents $ 6,021 Accounts receivable 16,284 Short-term derivative instruments, net 2,926 Prepaid expenses and other current assets 4,521 Oil and natural gas properties, net 108,342 Restricted investments 68,009 Accounts payable (9,092 ) Accrued liabilities (9,140 ) Asset retirement obligations (58,746 ) Credit facilities (28,500 ) Deferred tax liability (1,674 ) Noncontrolling interest (5,255 ) Net assets $ 93,696 An affiliate of REO collected a management fee for providing administrative services to REO. These administrative services included accounting, business development, finance, legal, information technology, insurance, government regulations, communications, regulatory, environmental and human resources services. REO incurred and paid management fees of $1.6 million during the year ended December 31, 2012. These management fees are presented as a component of general and administrative costs and expenses in the accompanying statements of operations. October 2013 Cinco Group Acquisition On October 1, 2013, MEMP acquired, through equity and asset transactions, oil and natural gas properties primarily in the Permian Basin, East Texas and the Rockies from MRD LLC and certain affiliates of NGP for an aggregate purchase price of approximately $603 million (subject to customary post-closing adjustments), of which approximately $507.1 million was received by certain affiliates of NGP. We refer to this transaction as the “Cinco Group acquisition.” The Cinco Group acquisition was funded with borrowings under MEMP’s revolving credit facility. The Cinco Group acquisition was accounted for as a combination of entities under common control at historical cost in a manner similar to the pooling of interest method. Cash and cash equivalents $ 2,820 Accounts receivable 5,184 Prepaid expenses and other current assets 1,454 Oil and natural gas properties, net 342,759 Long-term derivative instruments, net (826 ) Other long-term assets 344 Accounts payable (2,346 ) Revenue payable (2,910 ) Accrued liabilities (1,799 ) Short-term derivative instruments, net (1,828 ) Asset retirement obligations (9,606 ) Credit facilities (151,690 ) Net assets $ 181,556 Other Acquisitions or Dispositions On March 10, 2014, BlueStone sold certain interests in oil and gas properties in McMullen, Webb, Zapata, and Hidalgo Counties located in South Texas to BlueStone Natural Resources II, LLC, an NGP controlled entity. Total cash consideration received by BlueStone was approximately $1.2 million, which exceeded the net book value of the properties sold by $0.5 million. Due to common control considerations, the $0.5 million was recognized in the equity statement as a contribution. On March 28, 2014, MRD Royalty acquired certain interests in oil and gas properties in Gonzales and Karnes Counties located in South Texas from Propel Energy for $3.3 million. On June 18, 2014, in connection with our initial public offering and the related restructuring transactions (see Note 1), WHR Management Company was sold by WildHorse Resources to an affiliate of the Funds for net book value. The net book value of the assets sold was as follows (in thousands): Cash and cash equivalents $ 33,001 Restricted cash 300 Accounts receivable 5,256 Prepaid expenses and other current assets 379 Property, plant and equipment, net 3,410 Other long-term assets 4 Accounts payable (19,959 ) Accounts payable - affiliates (17,099 ) Accrued liabilities (5,061 ) Net assets $ 231 Related Party Agreements We and certain of our affiliates have entered into various documents and agreements. These agreements have been negotiated among affiliated parties and, consequently, are not the result of arm’s-length negotiations. Registration Rights Agreement In connection with the closing of our initial public offering, we entered into a registration rights agreement with MRD Holdco and former management members of WildHorse Resources, Jay Graham (“Graham”) and Anthony Bahr (“Bahr”). Pursuant to the registration rights agreement, we have agreed to register the sale of shares of our common stock under certain circumstances. Voting Agreement In connection with the closing of our initial public offering, we entered into a voting agreement with MRD Holdco, WHR Incentive LLC, a limited liability company beneficially owned by Messrs. Bahr and Graham, and certain former management members of WildHorse Resources, who contributed their ownership of WildHorse Resources to us in the restructuring transactions. Among other things, the voting agreement provides that those former management members of WildHorse Resources will vote all of their shares of our common stock as directed by MRD Holdco. The voting agreement also prohibits the transfer of any shares of our common stock by the former management members of WildHorse Resources until after the termination of the services agreement described below; provided, however, that the former management members of WildHorse Resources (other than Messrs. Bahr and Graham) may transfer their shares of our common stock after the 180 day lock-up period has expired and these transfer restrictions will not prohibit Messrs. Bahr and Graham from exercising piggyback registration rights under the registration rights agreement described above. Services Agreement In connection with the closing of our initial public offering, we entered into a services agreement with WildHorse Resources and WHR Management Company, pursuant to which WHR Management Company would provide operating and administrative services to us for twelve months relating to the Terryville Complex. In exchange for such services, we paid a monthly management fee to WHR Management Company of approximately $1.0 million excluding third party COPAS income credits. Upon the closing of our initial public offering, WHR Management Company became a subsidiary of WildHorse Resources II, LLC, an affiliate of the Company. NGP and certain former management members of WildHorse Resources own WHR II. Subsequent event. We terminated the services agreement as of March 1, 2015. WildHorse Management Services Agreement WHR II is an independent energy company engaged in the acquisition, exploration, and development of natural gas and crude oil properties. WHR II is a related party and was organized in the State of Delaware on June 3, 2013. A management services agreement was executed on August 8, 2013, where WildHorse Resources provided general, administrative and employee services to WHR II. On August 8, 2013, a management agreement between WildHorse Resources and WHR II was executed where WildHorse was appointed the manager for WHR II with responsibilities included administrative and land services, operator services and financial and accounting services. As operator, WildHorse Resources received operated and non-operated revenues on behalf of WHR II and billed and received joint interest billings. In addition, WildHorse Resources paid for lease operating expenses and drilling costs on behalf of WHR II. On August 8, 2013, an asset and cost sharing agreement between WildHorse Resources and WHR II was executed. As part of the agreement, shared WildHorse Resources costs were allocated between WildHorse Resources and WHR II in accordance with a sharing ratio. The sharing ratio is based on the previous quarter’s capital expenditures and number of operated wells. Company specific costs were billed directly to the appropriate entity. As a result of these agreements, WildHorse Resources received net payments of $4.4 million from WHR II in 2013. WildHorse Resources owed WHR II $2.4 million as of December 31, 2013. These agreements were terminated in connection with our initial public offering. Cinco Group Transition Service Agreements MEMP entered into transition service agreements with Propel Energy, Stanolind, and Boaz Energy Partners to provide operating and administrative services to MEMP with respect to the acquired properties. The term of these agreements were from October 1, 2013 through February 28, 2014. MEMP paid transition service fees of approximately $0.8 million in the aggregate under these agreements. Other Agreements Effective March 1, 2012, BlueStone entered into an agreement with CH4 Energy III, LLC, an NGP controlled entity, to sell an undivided 25% interest in certain properties in the Mossy Grove Prospect in Walker and Madison Counties located in East Texas. Total cash consideration received by BlueStone was approximately $7.0 million, which exceeded the net book value of the properties sold by $6.4 million. Due to common control considerations, the $6.4 million was recognized in the equity statement as a contribution. The transaction closed on July 13, 2012. A company affiliated with one of Classic’s employees provided certain land-related services to Classic. Classic paid approximately $1.0 million to this affiliated company for these services in 2012. Certain of the Cinco Group entities entered into advisory service, reimbursement, and indemnification agreements with NGP. These agreements generally required that an annual advisory fee be paid to NGP. Fees paid under these agreements for the years ended December 31, 2013 and 2012 were approximately $0.3 million and $0.4 million, respectively. Certain of the Cinco Group entities also paid a financing fee equal to a percentage of the capital contributions raised by NGP. These fees were considered a syndication cost and reduced equity contributions for financing fees paid. Fees for the year ended December 31, 2012 was approximately $0.4 million. There were no fees for the year ended December 31, 2013. During 2012, the previous owners received an equity contribution of $6.9 million of oil and gas properties in the Hendricks Field located in the Permian Basin of Texas by an NGP controlled entity. Due to common control considerations, this equity contribution was recorded at historical cost of the properties. During 2012, Boaz reimbursed a member of its management team approximately $0.3 million in general, administrative, and lease operating expenses related to an oral lease agreement between the member of management and a third party for a field office and yard located in Bronte, Texas. Gas Processing Agreement On March 17, 2014, WildHorse Resources entered into a gas processing agreement with PennTex North Louisiana, LLC (“PennTex”). PennTex is a joint venture among certain affiliates of NGP in which MRD Holdco owns, through its subsidiary MRD Midstream LLC, a minority interest. Once PennTex’s processing plant becomes operational, it will process natural gas produced from wells located on certain leases owned by us in the state of Louisiana. The agreement has a 15-year primary term, subject to one-year extensions at either party’s election. We will pay PennTex a monthly fee, subject to an annual inflationary escalation, based on volumes of natural gas delivered and processed. Once the plant is declared operational, we will be obligated to pay a minimum processing fee equal to approximately $18.3 million on an annual basis, subject to certain adjustments and conditions. The gas processing agreement requires that the processing plant be operational no later than November 1, 2015. Classic Pipeline Gas Gathering Agreement & Water Disposal Agreement On November 1, 2011, Classic Hydrocarbons Operating, LLC (“Classic Operating”), which became our wholly-owned subsidiary in connection with the restructuring transactions, and Classic Pipeline entered into a gas gathering agreement. Pursuant to the gas gathering agreement, Classic Operating dedicated to Classic Pipeline all of the natural gas produced (up to 50,000 MMBtus per day) on the properties operated by Classic Operating within certain counties in Texas through 2020, subject to one-year extensions at either party’s election. On May 1, 2014, Classic Operating and Classic Pipeline amended the gas gathering agreement with respect to Classic Operating’s remaining assets located in Panola and Shelby Counties, Texas. Under the amended gas gathering agreement, Classic Operating agreed to pay a fee of (i) $0.30 per MMBtu, subject to an annual 3.5% inflationary escalation, based on volumes of natural gas delivered and processed, and (ii) $0.07 per MMBtu per stage of compression plus its allocated share of compressor fuel. The amended gas gathering agreement has a term until December 31, 2023, subject to one-year extensions at either party’s election. On May 1, 2014, Classic Operating and Classic Pipeline entered into a water disposal agreement. The water disposal agreement has a three-year term, subject to one-year extensions at either party’s election. Under the water disposal agreement, Classic Operating agreed to pay a fee of $1.10 per barrel for each barrel of water delivered to Classic Pipeline.

Business Segment Data

Business Segment Data	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Segment Reporting [Abstract]
Business Segment Data	MEMORIAL RESOURCE DEVELOPMENT CORP. NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS 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 and development 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); transaction 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 on expired positions; 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 Three Months Ended March 31, 2015 $ 87,023 $ 92,818 $ — $ 179,841 For the Three Months Ended March 31, 2014 87,736 116,885 — 204,621 Adjusted EBITDA: (1) For the Three Months Ended March 31, 2015 86,830 86,432 (76 ) 173,186 For the Three Months Ended March 31, 2014 64,752 62,046 (3,002 ) 123,796 Segment assets: (2) As of March 31, 2015 1,535,233 3,051,190 (12,201 ) 4,574,222 As of December 31, 2014 1,413,768 3,189,760 (9,981 ) 4,593,547 Total cash expenditures for additions to long-lived assets: For the Three Months Ended March 31, 2015 88,566 77,680 — 166,246 For the Three Months Ended March 31, 2014 75,258 231,973 — 307,231 (1) Adjustments and eliminations for the three months ended March 31, 2015 and 2014 include less than $0.1 million and $3.0 million of cash distributions that MEMP paid MRD for the three months ended March 31, 2015 and 2014, respectively, related to MRD’s partnership interests in MEMP. In 2014, MRD LLC owned MEMP subordinated units, which were distributed to MRD Holdco in connection with the Company’s initial public offering in June 2014. (2) As of March 31, 2015, adjustments and eliminations primarily represent the elimination of accounts receivable and accounts payable balances between the MRD Segment and the MEMP Segment. Calculation of Reportable Segments’ Adjusted EBITDA For the Three Months Ended March 31, 2015 Combined MRD MEMP Totals (In thousands) Net income (loss) $ 50,371 $ (162,658 ) $ (112,287 ) Interest expense, net 9,756 28,818 38,574 Income tax expense (benefit) 47,558 (2,370 ) 45,188 DD&A 40,532 51,266 91,798 Impairment of proved oil and natural gas properties — 251,347 251,347 Accretion of AROs 123 1,634 1,757 (Gain) loss on commodity derivative instruments (108,190 ) (145,459 ) (253,649 ) Cash settlements received (paid) on expired commodity derivative instruments 32,749 60,124 92,873 Transaction related costs 1,281 1,299 2,580 Incentive-based compensation expense 11,710 2,341 14,051 Exploration costs 726 90 816 Non-cash equity (income) loss from MEMP 138 — 138 Cash distributions from MEMP 76 — 76 Adjusted EBITDA $ 86,830 $ 86,432 $ 173,262 For the Three Months Ended March 31, 2014 Combined MRD MEMP Totals (In thousands) Net income (loss) $ 6,390 $ (32,892 ) $ (26,502 ) Interest expense, net 17,974 16,078 34,052 Income tax expense (benefit) 25 75 100 DD&A 25,129 32,550 57,679 Accretion of AROs 130 1,391 1,521 (Gain) loss on commodity derivative instruments 12,716 46,766 59,482 Cash settlements received (paid) on expired commodity derivative instruments (5,221 ) (7,969 ) (13,190 ) (Gain) loss on sale of properties (110 ) — (110 ) Transaction related costs 568 1,894 2,462 Incentive-based compensation expense 1,023 1,295 2,318 Exploration costs 140 6 146 Provision for environmental remediation — 2,852 2,852 Non-cash equity (income) loss from MEMP 2,986 — 2,986 Cash distributions from MEMP 3,002 — 3,002 Adjusted EBITDA $ 64,752 $ 62,046 $ 126,798 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 Three Months Ended March 31, 2015 2014 Total Reportable Segments' Adjusted EBITDA $ 173,262 $ 126,798 Adjustments to reconcile Adjusted EBITDA to net income (loss): Interest expense, net (38,574 ) (34,052 ) Income tax benefit (expense) (45,188 ) (100 ) DD&A (91,798 ) (57,679 ) Impairment of proved oil and natural gas properties (251,347 ) — Accretion of AROs (1,757 ) (1,521 ) Gains (losses) on commodity derivative instruments 253,649 (59,482 ) Cash settlements paid (received) on expired commodity derivative instruments (92,873 ) 13,190 Gain (loss) on sale of properties — 110 Transaction related costs (2,580 ) (2,462 ) Incentive-based compensation expense (14,051 ) (2,318 ) Exploration costs (816 ) (146 ) Provision for environmental remediation — (2,852 ) Cash distributions from MEMP (76 ) (3,002 ) Net income (loss) $ (112,149 ) $ (23,516 ) Included below is our consolidated and combined statement of operations disaggregated by reportable segment for the period indicated (in thousands): For the Three Months Ended March 31, 2015 MRD MEMP Other, Adjustments & Eliminations Consolidated & Combined Totals Revenues: Oil & natural gas sales $ 87,023 $ 91,949 $ — $ 178,972 Other revenues — 869 — 869 Total revenues 87,023 92,818 — 179,841 Costs and expenses: Lease operating 5,222 40,478 — 45,700 Gathering, processing, and transportation 14,763 8,220 — 22,983 Pipeline operating — 446 — 446 Exploration 726 90 — 816 Production and ad valorem taxes 2,775 6,655 — 9,430 Depreciation, depletion, and amortization 40,532 51,266 — 91,798 Impairment of proved oil and natural gas properties — 251,347 — 251,347 Incentive unit compensation expense 10,224 — — 10,224 General and administrative 12,976 14,511 — 27,487 Accretion of asset retirement obligations 123 1,634 — 1,757 (Gain) loss on commodity derivative instruments (108,190 ) (145,459 ) — (253,649 ) Total costs and expenses (20,849 ) 229,188 — 208,339 Operating income (loss) 107,872 (136,370 ) — (28,498 ) Other income (expense): Interest expense, net (9,756 ) (28,818 ) — (38,574 ) Earnings from equity investments (138 ) — 138 — Other, net (49 ) 160 — 111 Total other income (expense) (9,943 ) (28,658 ) 138 (38,463 ) Income (loss) before income taxes 97,929 (165,028 ) 138 (66,961 ) Income tax benefit (expense) (47,558 ) 2,370 — (45,188 ) Net income (loss) $ 50,371 $ (162,658 ) $ 138 $ (112,149 ) For the Three Months Ended March 31, 2014 MRD MEMP Other, Adjustments & Eliminations Consolidated & Combined Totals Revenues: Oil & natural gas sales $ 87,733 $ 115,977 $ — $ 203,710 Other revenues 3 908 — 911 Total revenues 87,736 116,885 — 204,621 Costs and expenses: Lease operating 3,235 30,120 — 33,355 Gathering, processing, and transportation 8,557 5,563 14,120 Pipeline operating — 489 — 489 Exploration 140 6 — 146 Production and ad valorem taxes 2,573 6,011 — 8,584 Depreciation, depletion, and amortization 25,129 32,550 — 57,679 Incentive unit compensation expense 1,023 — — 1,023 General and administrative 6,999 10,740 — 17,739 Accretion of asset retirement obligations 130 1,391 — 1,521 (Gain) loss on commodity derivative instruments 12,716 46,766 — 59,482 (Gain) loss on sale of properties (110 ) — — (110 ) Other, net — (12 ) — (12 ) Total costs and expenses 60,392 133,624 — 194,016 Operating income (loss) 27,344 (16,739 ) — 10,605 Other income (expense): Interest expense, net (17,974 ) (16,078 ) — (34,052 ) Earnings from equity investments (2,986 ) — 2,986 — Other, net 31 — — 31 Total other income (expense) (20,929 ) (16,078 ) 2,986 (34,021 ) Income (loss) before income taxes 6,415 (32,817 ) 2,986 (23,416 ) Income tax benefit (expense) (25 ) (75 ) — (100 ) Net income (loss) $ 6,390 $ (32,892 ) $ 2,986 $ (23,516 )	Note 14. Business Segment Data Our reportable business segments are organized in a manner that reflects how management manages those business activities. We have two reportable business segments, both of which are engaged in the acquisition, exploration, development and production of oil and natural gas properties. Our reportable business segments are as follows: — MRD—reflects the combined operations of the Company, MRD Operating, MRD LLC, WildHorse Resources and its previous owners, Black Diamond, BlueStone, Beta Operating and MEMP GP. — MEMP—reflects the combined operations of MEMP, its previous owners, and historical dropdown transactions that occurred between MEMP and other MRD (or its predecessor) consolidating subsidiaries. We evaluate segment performance based on Adjusted EBITDA. Adjusted EBITDA is defined as net income (loss), plus interest expense; loss on extinguishment of debt; income tax expense; depreciation, depletion and amortization (“DD&A”); impairment of goodwill and long-lived properties; accretion of asset retirement obligations (“AROs”); losses on commodity derivative contracts and cash settlements received; losses on sale of properties; incentive-based compensation expenses; exploration costs; provision for environmental remediation; equity loss from MEMP (MRD Segment only); cash distributions from MEMP (MRD Segment only); acquisition related costs; amortization of investment premium; and other non-routine items, less interest income; income tax benefit; gains on commodity derivative contracts and cash settlements paid; equity income from MEMP (MRD Segment only); gains on sale of assets and other non-routine items. Financial information presented for the MEMP business segment is derived from the underlying consolidated and combined financial statements of MEMP that are publicly available. Segment revenues and expenses include intersegment transactions. Our combined totals reflect the elimination of intersegment transactions. In the MRD Segment’s individual financial statements, investments in the MEMP Segment that are included in the consolidated and combined financial statements are accounted for by the equity method. The following table presents selected business segment information for the periods indicated (in thousands): Other, Consolidated Adjustments & & Combined MRD MEMP Eliminations Totals Total revenues: For the Year ended December 31, 2014 $ 363,126 $ 536,219 $ — $ 899,345 For the Year ended December 31, 2013 201,886 373,137 — 575,023 For the Year ended December 31, 2012 104,072 293,165 (369 ) 396,868 Adjusted EBITDA: (1) 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 For the Year ended December 31, 2012 99,746 211,693 (23,447 ) 287,992 Segment assets: (2) As of December 31, 2014 1,413,768 3,189,760 (9,981 ) 4,593,547 As of December 31, 2013 1,033,958 1,849,368 (54,165 ) 2,829,161 Total cash expenditures for additions to long-lived assets: 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 For the Year ended December 31, 2012 188,903 447,782 — 636,685 (1) Adjustments and eliminations for the years ended December 31, 2014, 2013 and 2012 include amounts related to the MRD Segment’s equity investments in the MEMP Segment as well the elimination of $6.1 million, $26.0 million and $19.3 million of cash distributions that MEMP paid MRD Segment for the years ended December 31, 2014, 2013 and 2012, respectively, related to MRD Segment’s partnership interests in MEMP. (2) Adjustments and eliminations primarily represent the elimination of the MRD Segment’s equity investments in the MEMP Segment. Calculation of Reportable Segments’ Adjusted EBITDA 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 Loss on extinguishment of debt 37,248 — 37,248 Income tax expense (benefit) 102,392 (1,421 ) 100,971 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 commodity derivative instruments 9,166 13,522 22,688 (Gain) loss on sale of properties 3,057 — 3,057 Acquisition related costs 2,305 4,363 6,668 Incentive-based compensation expense 946,753 7,874 954,627 Exploration costs 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 commodity derivative instruments 8,481 23,638 32,119 (Gain) loss on sale of properties (82,773 ) (2,848 ) (85,621 ) Acquisition related costs 1,584 6,729 8,313 Incentive-based compensation expense 34,997 11,840 46,837 Non-cash 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 For the Year Ended December 31, 2012 Combined MRD MEMP Totals (In thousands) Net income (loss) $ 8,810 $ 23,067 $ 31,877 Interest expense, net 8,283 24,955 33,238 Income tax expense (benefit) (1 ) 108 107 DD&A 37,048 101,624 138,672 Impairment of proved oil and natural gas properties 5,877 22,994 28,871 Accretion of AROs 551 4,458 5,009 (Gain) loss on commodity derivative instruments (10,500 ) (24,405 ) (34,905 ) Cash settlements received (paid) on commodity derivative instruments 20,740 53,559 74,299 (Gain) loss on sale of properties (2 ) (9,759 ) (9,761 ) Acquisition related costs 403 4,135 4,538 Incentive-based compensation expense 9,510 1,423 10,933 Amortization of investment premium — 194 194 Exploration costs 460 9,340 9,800 Non-cash equity (income) loss from MEMP (696 ) — (696 ) Cash distributions from MEMP 19,263 — 19,263 Adjusted EBITDA $ 99,746 $ 211,693 $ 311,439 The following table presents a reconciliation of total reportable segments’ Adjusted EBITDA to net income (loss) for each of the periods indicated (in thousands): For the Year Ended December 31, 2014 2013 2012 Total Reportable Segments' Adjusted EBITDA $ 653,877 $ 420,088 $ 311,439 Adjustments to reconcile Adjusted EBITDA to net income (loss): Interest expense, net (133,833 ) (69,250 ) (33,238 ) Loss on extinguishment of debt (37,248 ) — — Income tax benefit (expense) (100,971 ) (1,619 ) (107 ) DD&A (314,193 ) (184,717 ) (138,672 ) Impairment of proved oil and natural gas properties (432,116 ) (6,600 ) (28,871 ) Accretion of AROs (6,306 ) (5,581 ) (5,009 ) Gains (losses) on commodity derivative instruments 749,988 29,294 34,905 Cash settlements paid (received) on commodity derivative instruments (22,688 ) (32,119 ) (74,299 ) Gain (loss) on sale of properties (3,057 ) 85,621 9,761 Acquisition related costs (6,668 ) (8,313 ) (4,538 ) Incentive-based compensation expense (954,627 ) (46,837 ) (10,933 ) Non-cash compensation expense — (1,057 ) — Exploration costs (16,603 ) (2,356 ) (9,800 ) Amortization of investment premium — — (194 ) Cash distributions from MEMP (6,144 ) (26,006 ) (19,263 ) Provision for environmental remediation (2,852 ) — — Loss on office lease (2,622 ) — — Other non-cash equity (income) loss — 784 (4,184 ) Net income (loss) $ (636,063 ) $ 151,332 $ 26,997 Included below is our consolidated and combined statement of operations disaggregated by reportable segment for the period indicated (in thousands): For the Year Ended December 31, 2014 MRD MEMP Other, Adjustments & Eliminations Consolidated & Combined Totals Revenues: Oil & natural gas sales $ 363,114 $ 531,853 $ — $ 894,967 Other revenues 12 4,366 — 4,378 Total revenues 363,126 536,219 — 899,345 Costs and expenses: Lease operating 17,570 143,733 — 161,303 Pipeline operating — 2,068 — 2,068 Exploration 13,853 2,750 — 16,603 Production and ad valorem taxes 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 925,200 337,819 — 1,263,019 Operating income (loss) (562,074 ) 198,400 — (363,674 ) Other income (expense): Interest expense, net (50,283 ) (83,550 ) — (133,833 ) Loss on extinguishment of debt (37,248 ) — — (37,248 ) Earnings from equity investments (12,656 ) — 12,656 — Other, net 320 (657 ) — (337 ) Total other income (expense) (99,867 ) (84,207 ) 12,656 (171,418 ) Income (loss) 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 $ 201,886 $ 370,062 $ — $ 571,948 Other revenues — 3,075 — 3,075 Total revenues 201,886 373,137 — 575,023 Costs and expenses: Lease operating 17,315 96,433 (108 ) 113,640 Pipeline operating — 1,835 — 1,835 Exploration 1,034 1,322 — 2,356 Production and ad valorem taxes 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 85,446 267,524 (3 ) 352,967 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 For the Year Ended December 31, 2012 MRD MEMP Other, Adjustments & Eliminations Consolidated & Combined Totals Revenues: Oil & natural gas sales $ 103,728 $ 289,912 $ (9 ) $ 393,631 Other revenues 344 3,253 (360 ) 3,237 Total revenues 104,072 293,165 (369 ) 396,868 Costs and expenses: Lease operating 16,582 87,972 (800 ) 103,754 Pipeline operating — 2,114 — 2,114 Exploration 460 9,340 — 9,800 Production and ad valorem taxes 8,270 15,354 — 23,624 Depreciation, depletion, and amortization 37,048 101,624 — 138,672 Impairment of proved oil and natural gas properties 5,877 22,994 — 28,871 Incentive unit compensation expense 9,510 — — 9,510 General and administrative 24,134 35,112 431 59,677 Accretion of asset retirement obligations 551 4,458 — 5,009 (Gain) loss on commodity derivative instruments (10,500 ) (24,405 ) — (34,905 ) (Gain) loss on sale of properties (2 ) (9,759 ) — (9,761 ) Other, net 464 38 — 502 Total costs and expenses 92,394 244,842 (369 ) 336,867 Operating income (loss) 11,678 48,323 — 60,001 Other income (expense): Interest expense, net (8,283 ) (24,955 ) — (33,238 ) Amortization of investment premium — (194 ) — (194 ) Earnings from equity investments 4,880 — (4,880 ) — Other, net 534 1 — 535 Total other income (expense) (2,869 ) (25,148 ) (4,880 ) (32,897 ) Income before income taxes 8,809 23,175 (4,880 ) 27,104 Income tax benefit (expense) 1 (108 ) — (107 ) Net income (loss) $ 8,810 $ 23,067 $ (4,880 ) $ 26,997

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Income Tax	Note 15. Income Taxes Income tax benefit (expense) for the indicated periods is comprised of the following: For the Year Ended December 31, 2014 2013 2012 (In thousands) Current taxes: Federal $ — $ — $ — State 22 (1,619 ) 178 Deferred taxes: Federal (88,994 ) — — State (11,999 ) — (285 ) Total income tax benefit (expense) $ (100,971 ) $ (1,619 ) $ (107 ) The actual income tax benefit (expense) differs from the expected income tax benefit (provision) as computed by applying the federal statutory corporate tax rate of 35% for each period indicated as follows: For the Year Ended December 31, 2014 2013 2012 Expected tax benefit (expense) $ 187,282 $ (53,533 ) $ (9,486 ) State income tax expense, net of federal benefit (9,660 ) (1,619 ) (107 ) Pass-through entities (1) 49,989 53,533 9,486 Stock compensation (2) (330,024 ) — — Other 1,442 — — Total income tax benefit (expense) $ (100,971 ) $ (1,619 ) $ (107 ) (1) MEMP, a publicly traded partnership with qualifying income, is a pass-through entity for federal income tax purposes. In addition, our predecessor was also a pass-through entity for federal income tax purposes. (2 ) As discussed in Note 12, the compensation expense associated with the incentive units of WildHorse Resources and MRD Holdco created a nondeductible permanent difference for income tax purposes. The components of net deferred income tax assets and (liabilities) recognized were as follows: December 31, 2014 2013 (In thousands) Deferred current income tax assets: Unrealized hedging transactions $ 109 $ 37 Accrued liabilities — 5 Other 342 (42 ) Deferred current income tax assets: $ 451 $ — Deferred current income tax liabilities: Unrealized hedging transactions $ (52,328 ) — Other (52 ) (382 ) Deferred current income tax liabilities: $ (52,380 ) $ (382 ) Deferred noncurrent income tax assets: Net operating loss carryforward $ 28,043 $ 2,350 Asset retirement obligation 5,757 971 Other 3,224 1 Net deferred tax valuation allowance (2,634 ) (2,896 ) Deferred noncurrent income tax assets: $ 34,390 $ 426 Deferred noncurrent income tax liabilities: Property, plant and equipment $ (80,198 ) $ (3,318 ) Unrealized hedging transactions (48,929 ) (275 ) Other (280 ) 61 Deferred noncurrent income tax liabilities: $ (129,407 ) $ (3,532 ) Net current deferred income tax assets (liabilities) $ (51,929 ) $ (382 ) Net noncurrent deferred income tax assets (liabilities) $ (95,017 ) $ (3,106 ) We must recognize the tax effects of any uncertain tax positions we may adopt, if the position taken by us is more likely than not sustainable based on its technical merits. For those benefits to be recognized, an income tax position must be more-likely-than-not to be sustained upon examination by taxing authorities. The Company has no unrecognized tax benefits for the years ended December 31, 2014, 2013 or 2012. Generally, the Company's income tax years 2011 through 2014 remain open and subject to examination by Federal tax authorities or state tax authorities where the Company conducts operations. In certain jurisdictions the Company operates through more than one legal entity, each of which may have different open years subject to examination. The Company recognizes interest and penalties accrued to unrecognized benefits in Other income (expense) in its consolidated statements of operations. For the years ended December 31, 2014, 2013 and 2012 the Company recognized no interest and penalties. As of December 31, 2014, the Company has available, to reduce future taxable income, a United States net operating loss carryforwards (NOLs) of approximately $74.3 million before consideration of any valuation allowance which expires in the years 2027 thru 2035. A portion of these net operating loss carryforwards are subject to the ownership change limitation provisions of Section 382 of the Internal Revenue Code (IRC). The Company also has various net state NOL carryforwards of approximately $65.0 million, before consideration of any valuation allowance with varying lengths of allowable carryforward periods ranging from 10 to 20 years that can be used to offset future state taxable income.

Commitments and Contingencies

Commitments and Contingencies	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Commitments And Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 15. 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. At March 31, 2015 and December 31, 2014, we had $1.3 million and $2.1 million of environmental reserves recorded on our balance sheets, respectively. Gas Processing Agreement See Note 13 for additional information. Supplemental Bond for Decommissioning Liabilities Trust Agreement In connection with its 2009 acquisition of the Beta properties, Rise Energy Operating, LLC (“REO”), a wholly-owned subsidiary of MEMP, assumed an obligation with the BOEM for the decommissioning of the offshore production facilities. The trust account is held by REO for the benefit of all working interest owners. The following is a summary of the gross held-to-maturity investments held in the trust account less the outside working interest owners share as of March 31, 2015 (in thousands): Amortized Investment Cost U.S. Bank Money Market Cash Equivalent $ 137,705 Less: Outside working interest owners share (66,442 ) $ 71,263 The trust account must maintain minimum balances attributable to REO’s net working interest as follows (in thousands): June 30, 2015 $ 72,450 June 30, 2016 $ 76,590 December 31, 2016 $ 78,660 As of March 31, 2015, the maximum remaining obligation net to REO’s interest was approximately $7.4 million. Processing Plant Expansions by Third Party Gatherer A discussion of processing plant expansions by a third party gatherer is included in our 2014 Form 10-K. Related Party Agreements See Note 13 for additional information.	Note 16. Commitments and Contingencies Litigation & Environmental As part of our normal business activities, we may be named as defendants in litigation and legal proceedings, including those arising from regulatory and environmental matters. Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to indemnify us against liabilities arising from future legal proceedings. We are not aware of any litigation, pending or threatened, that we believe is reasonably likely to have a significant adverse effect on our financial position, results of operations or cash flows. Environmental costs for remediation are accrued when environmental remediation efforts are probable and the costs can be reasonably estimated. Such accruals are based on management’s best estimate of the ultimate cost to remediate a site and are adjusted as further information and circumstances develop. Those estimates may change substantially depending on information about the nature and extent of contamination, appropriate remediation technologies and regulatory approvals. The following table presents the activity of our environmental reserves for the periods presented: 2014 2013 2012 (In thousands) Balance at beginning of period $ 577 $ 1,469 $ 1,747 Charged to costs and expenses 2,852 — 193 Payments (1,337 ) (892 ) (471 ) Balance at end of period $ 2,092 $ 577 $ 1,469 At December 31, 2014 and 2013, $2.1 million and $0.6 million, respectively, of our environmental reserves were classified as current liabilities in accrued liabilities. Sinking Fund Trust Agreement REO assumed an obligation with a third party to make payments into a sinking fund in connection with its 2009 acquisition of the Beta properties, the purpose of which is to provide funds adequate to decommission the portion of the San Pedro Bay pipeline that lies within State waters and the surface facilities. Under the terms of the agreement, REO, as the operator of the properties, is obligated to make monthly deposits into the sinking fund account in an amount equal to $0.25 per barrel of oil and other liquid hydrocarbon produced from the acquired working interest. Interest earned in the account stays in the account. The obligation to fund ceases when the aggregate value of the account reaches $4.3 million. As of December 31, 2014, the gross account balance included in restricted investments was approximately $2.7 million. REO’s maximum remaining obligation net to its 51.75% interest under the terms of the current agreement was $0.8 million at December 31, 2014. Supplemental Bond for Decommissioning Liabilities Trust Agreement REO assumed an obligation with the BOEM in connection with its 2009 acquisition of the Beta properties. Under the terms of the agreement dated March 1, 2007, the seller of the Beta properties was obligated to deliver a $90.0 million U.S. Treasury Note into a trust account for the decommissioning of the offshore production facilities. At the time of acquisition, all obligations under this existing agreement had been met. In January 2010, the BOEM issued a report that revised upward, the estimated cost of decommissioning. In June 2010, REO agreed to make additional quarterly payments to the trust account attributable to its net working interest of approximately $0.6 million beginning on June 30, 2010 until the payments and accrued interest attributable to REO equal $78.7 million by December 31, 2016. The trust account must maintain minimum balances attributable to REO’s net working interest as follows (in thousands): June 30, 2015 $ 72,450 June 30, 2016 $ 76,590 December 31, 2016 $ 78,660 In the event the account balance is less than the contractual amount, the working interest owners must make additional payments. Interest income earned and deposited in the trust account mitigates the likelihood that additional payments will have to be made by the working interest owners. As of December 31, 2014, the maximum remaining obligation net to REO’s interest was approximately $8.7 million. The trust account is held by REO for the benefit of all working interest owners. The following is a summary of the gross held-to-maturity investments held in the trust account less the outside working interest owners share as of December 31, 2014 (in thousands): Amortized Investment Cost U.S. Bank Money Market Cash Equivalent $ 135,176 Less: Outside working interest owners share (65,222 ) $ 69,954 Purchase Commitment Assumed At December 31, 2014, MEMP had a CO 2 Payment or Settlement due by Period Purchase commitment Total 2015 2016 2017 2018 2019 Thereafter CO 2 Estimated payment obligation $ 50,495 $ 9,608 $ 10,179 $ 10,151 $ 6,995 $ 7,060 $ 6,502 Processing Plant Expansions by Third Party Gatherer In 2012, WildHorse Resources contracted with Regency Field Services LLC (the “Gatherer”) to expand their Dubach processing plant by up to 70 MMcf per day among other facility and infrastructure improvements. In 2013, WildHorse Resources contracted with the Gatherer to build a new high pressure pipeline from the dedicated area to the Gatherer’s Dubberly processing plant in Webster Parish, LA amongst other pipeline and infrastructure improvements. The Gatherer is entitled to receive a payback demand fee from us and other third parties equal to 110% of the infrastructure improvement costs. Effective February 1, 2014, the payback demand fee is equal to the monthly demand quantity (192,950 MMBtu per day) times $0.275 per MMBtu. In addition, for each MMBtu gathered in excess of the demand quantity, we are obligated to pay a payback demand fee of $0.275 per MMBtu. The monthly demand quantity escalated to 249,700 MMBtu per day until payout effective January 1, 2015. WildHorse Resources’ minimum commitments to the Gatherer, before other owner contributions, as of December 31, 2014 were as follows (in thousands): Dubach Dubberly 2015 $ 13,671 $ 11,393 2016 13,709 11,424 2017 13,671 11,393 2018 12,772 10,643 Total $ 53,823 $ 44,853 Related Party Agreements Classic Operating entered into a gas gathering agreement and water disposal agreement with Classic Pipeline. On March 17, 2014, WildHorse Resources entered into a gas processing agreement with PennTex. See Note 13 for additional information. Operating Leases We have leases for offshore Southern California pipeline right-of-way use as well as office space for our corporate headquarters and operating regions. We also lease equipment and incur surface rentals related to our business operations. For the years ended December 31, 2014, 2013, and 2012 we recognized $10.8 million, $8.3 million, and $5.0 million of rent expense, respectively. Amounts shown in the following table represent minimum lease payment obligations and sublease rental income under non-cancelable operating leases with a remaining term in excess of one year: Payment or Settlement due by Period Total 2015 2016 2017 2018 2019 Thereafter (In thousands) MRD Segment: Operating leases $ 43,625 $ 6,534 $ 6,607 $ 6,694 $ 6,259 $ 5,960 $ 11,571 Sublease rental income 5,786 1,691 1,579 1,197 814 431 74 MEMP Segment: Operating leases 3,665 788 416 205 205 205 1,846

Defined Contribution Plans

Defined Contribution Plans	12 Months Ended
	Dec. 31, 2014
Postemployment Benefits [Abstract]
Defined Contribution Plans	Note 17. Defined Contribution Plans MRD sponsors a defined contribution plan for the benefit of substantially all employees who have attained 18 years of age. The plan allows eligible employees to make tax-deferred contributions up to 100% of their annual compensation, not to exceed annual limits established by the Internal Revenue Service. MRD makes matching contributions of 100% of employee contributions that does not exceed 6% of compensation. Employees are immediately vested in these matching contributions. This plan became effective on January 1, 2012. The plan received employer contributions of approximately $1.4 million, $0.9 million, and $0.4 million in 2014, 2013, and 2012 respectively. Effective January 1, 2012, REO assumed sponsorship of a separate defined contribution plan. This plan specifically benefits substantially all those employed by the MRD subsidiary (Beta Operating) that operates and supports the Beta properties that have attained 21 years of age. Eligible employees are permitted to make tax-deferred contributions up to 100% of their annual compensation, not to exceed annual limits established by the Internal Revenue Service. Employer matching contributions of 100% of employee contributions that does not exceed 6% of compensation are made to the plan as well. The employer matching contributions associated with this plan were subject to a three-year graded vesting schedule through February 28, 2012. Effective March 1, 2012, the plan was amended to offer immediate vesting of employer matching contributions. This plan was terminated December 31, 2013. The plan received employer contributions of approximately $0.6 million and $0.5 million in 2013, and 2012 respectively. Approximately $0.3 million associated with this plan are reflected as costs and expenses in the accompanying statements of operations for the each of the years ended December 31, 2013 and 2012, respectively. WildHorse, Tanos, BlueStone, Classic and Black Diamond also sponsored defined contribution plans for the benefit their eligible employees. Matching employer contributions of approximately $0.2 million, $0.5 million and $0.6 million were made to these other plans in 2014, 2013 and 2012, respectively. Crown and Stanolind also made matching contributions to defined contribution plans for the benefit of their eligible employees. Matching employer contributions of approximately $0.1 million were made to these plans in both 2013 and 2012. Such contributions to these plans are included in general and administrative expenses in the accompanying combined statements of operations.

Condensed Consolidating Financi

Condensed Consolidating Financial Information	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Condensed Consolidating Financial Information	Note 16. 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 period 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. March 31, 2015 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated (In thousands) ASSETS Current assets: Cash and cash equivalents $ 454 $ 2,985 $ 1,073 $ — $ 4,512 Accounts receivable - trade 5,259 43,307 73,503 (3,670 ) 118,399 Accounts receivable - affiliates 13,303 — 28 (11,355 ) 1,976 Short-term derivative instruments 142,074 — 214,986 — 357,060 Prepaid expenses and other current assets 5,036 7,410 19,687 — 32,133 Total current assets 166,126 53,702 309,277 (15,025 ) 514,080 Property and equipment, net 17,320 1,098,997 2,250,283 — 3,366,600 Long-term derivative instruments 188,405 — 389,748 — 578,153 Investments in subsidiaries 928,289 — — (928,289 ) — Other long-term assets 13,481 — 101,908 — 115,389 Total assets $ 1,313,621 $ 1,152,699 $ 3,051,216 $ (943,314 ) $ 4,574,222 LIABILITIES AND EQUITY Current liabilities: Accounts payable and accrued liabilities $ 11,711 $ 127,921 $ 122,152 $ (2,046 ) $ 259,738 Accounts payable - affiliates — 4,185 9,145 (13,330 ) — Revenues payable — 31,136 27,195 — 58,331 Short-term derivative instruments — — 3,300 — 3,300 Total current liabilities 11,711 163,242 161,792 (15,376 ) 321,369 Long-term debt 744,000 — 1,754,045 — 2,498,045 Asset retirement obligations — 7,749 116,727 — 124,476 Long-term derivative instruments — — 555 — 555 Deferred tax liabilities 102,978 6,648 2,164 — 111,790 Other long-term liabilities 7,566 — — — 7,566 Total liabilities 866,255 177,639 2,035,283 (15,376 ) 3,063,801 Equity: Equity 447,366 975,060 1,010,214 (1,985,274 ) 447,366 Noncontrolling interests — — 5,719 1,057,336 1,063,055 Total equity 447,366 975,060 1,015,933 (927,938 ) 1,510,421 Total liabilities and equity $ 1,313,621 $ 1,152,699 $ 3,051,216 $ (943,314 ) $ 4,574,222 December 31, 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 5,833 7,993 14,201 — 28,027 Total current assets 155,587 56,707 307,130 (13,807 ) 505,617 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 14,124 5,660 100,521 (5,400 ) 114,905 Total assets $ 1,449,671 $ 1,113,089 $ 3,189,786 $ (1,158,999 ) $ 4,593,547 LIABILITIES AND EQUITY Current liabilities: Accounts payable and accrued liabilities $ 6,245 $ 107,068 $ 114,584 $ (3,125 ) $ 224,772 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 6,245 137,948 154,392 (12,548 ) 286,037 Long-term debt 783,000 — 1,595,413 — 2,378,413 Asset retirement obligations — 9,830 112,701 — 122,531 Deferred tax liabilities 69,431 — 30,986 (5,400 ) 95,017 Other long-term liabilities 8,585 — — — 8,585 Total liabilities 867,261 147,778 1,893,492 (17,948 ) 2,890,583 Equity: Equity 582,410 965,311 1,290,734 (2,256,045 ) 582,410 Noncontrolling interests — — 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 and equity $ 1,449,671 $ 1,113,089 $ 3,189,786 $ (1,158,999 ) $ 4,593,547 Three Months Ended March 31, 2015 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated (In thousands) Revenues: Oil & natural gas sales $ — $ 87,023 $ 91,949 $ — $ 178,972 Other revenues — — 869 — 869 Total revenues — 87,023 92,818 — 179,841 Costs and expenses: Lease operating — 5,222 40,478 — 45,700 Gathering, processing and transportation — 14,763 8,220 — 22,983 Pipeline operating — — 446 — 446 Exploration — 726 90 — 816 Production and ad valorem taxes — 2,775 6,655 — 9,430 Depreciation, depletion and amortization 968 39,564 51,266 — 91,798 Impairment of proved oil and natural gas properties — — 251,347 — 251,347 Incentive unit compensation expense 10,224 — — — 10,224 General and administrative 10,925 2,051 14,511 — 27,487 Accretion of asset retirement obligations — 123 1,634 — 1,757 (Gain) loss on commodity derivatives (108,190 ) — (145,459 ) — (253,649 ) Total costs and expenses (86,073 ) 65,224 229,188 — 208,339 Operating income (loss) 86,073 21,799 (136,370 ) — (28,498 ) Other income (expense): Interest expense, net (9,757 ) — (28,817 ) — (38,574 ) Equity earnings from subsidiaries 7,021 — — (7,021 ) — Other, net — (49 ) 160 — 111 Total other income (expense) (2,736 ) (49 ) (28,657 ) (7,021 ) (38,463 ) Income before income taxes 83,337 21,750 (165,027 ) (7,021 ) (66,961 ) Income tax benefit (expense) (37,445 ) (10,113 ) 2,370 — (45,188 ) Net income (loss) 45,892 11,637 (162,657 ) (7,021 ) (112,149 ) Net income (loss) attributable to noncontrolling interest — — 159 (158,200 ) (158,041 ) Net income (loss) attributable to Memorial Resource Development Corp. $ 45,892 $ 11,637 $ (162,816 ) $ 151,179 $ 45,892 Three Months Ended March 31, 2014 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Combined & Consolidated (In thousands) Revenues: Oil & natural gas sales $ — $ 87,733 $ 115,977 $ — $ 203,710 Other revenues — 3 908 — 911 Total revenues — 87,736 116,885 — 204,621 Costs and expenses: Lease operating — 3,235 30,120 — 33,355 Gathering, processing and transportation — 8,557 5,563 — 14,120 Pipeline operating — — 489 — 489 Exploration — 140 6 — 146 Production and ad valorem taxes — 2,573 6,011 — 8,584 Depreciation, depletion and amortization — 25,129 32,550 — 57,679 Incentive unit compensation expense — — 1,023 — 1,023 General and administrative — 6,982 10,757 — 17,739 Accretion of asset retirement obligations — 130 1,391 — 1,521 (Gain) loss on commodity derivatives — 12,716 46,766 — 59,482 (Gain) loss on sale of properties — — (110 ) — (110 ) Other, net — — (12 ) — (12 ) Total costs and expenses — 59,462 134,554 — 194,016 Operating income (loss) — 28,274 (17,669 ) — 10,605 Other income (expense): Interest expense, net — (17,974 ) (16,078 ) — (34,052 ) Equity earnings from subsidiaries — (3,260 ) — 3,260 — Other, net — 31 — — 31 Total other income (expense) — (21,203 ) (16,078 ) 3,260 (34,021 ) Income before income taxes — 7,071 (33,747 ) 3,260 (23,416 ) Income tax benefit (expense) — (25 ) (75 ) — (100 ) Net income (loss) — 7,046 (33,822 ) 3,260 (23,516 ) Net income (loss) attributable to noncontrolling interest — — 55 (31,943 ) (31,888 ) Net income (loss) attributable to Memorial Resource Development Corp. $ — $ 7,046 $ (33,877 ) $ 35,203 $ 8,372 Three Months Ended March 31, 2015 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated (In thousands) Net cash provided by (used in) operating activities $ 16,404 $ 82,434 $ 71,963 $ 1,015 $ 171,816 Cash flows from investing activities: Acquisitions of oil and natural gas properties — — (3,305 ) — (3,305 ) Additions to oil and gas properties — (86,619 ) (74,375 ) — (160,994 ) Additons to restricted investments — — (1,426 ) — (1,426 ) Additions to other property and equipment (1,687 ) (260 ) — — (1,947 ) Investment in subsidiaries (5,580 ) — — 5,580 — Distribution from subsidiaries 78,076 — — (78,076 ) — Net cash used in investing activities 70,809 (86,879 ) (79,106 ) (72,496 ) (167,672 ) Cash flows from financing activities: Advances on revolving credit facility 104,000 — 166,000 — 270,000 Payments on revolving credit facility (143,000 ) — (5,000 ) — (148,000 ) Repayment of senior notes — — (2,914 ) — (2,914 ) Deferred finance costs — — (10 ) — (10 ) Capital contributions — 3,668 1,912 (5,580 ) — Distribution to equity owners — — (46,315 ) 46,315 — Distribution to noncontrolling interests — — — (46,239 ) (46,239 ) Distributions to MRD — — (78,000 ) 78,000 — MRD equity repurchases (50,000 ) — — — (50,000 ) MEMP equity repurchases — — (28,420 ) — (28,420 ) Other — — (7 ) — (7 ) Net cash provided by financing activities (89,000 ) 3,668 7,246 72,496 (5,590 ) Net change in cash and cash equivalents (1,787 ) (777 ) 103 1,015 (1,446 ) Cash and cash equivalents, beginning of period 2,241 3,762 970 (1,015 ) 5,958 Cash and cash equivalents, end of period $ 454 $ 2,985 $ 1,073 $ — $ 4,512 Three Months Ended March 31, 2014 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Combined & Consolidated (In thousands) Net cash provided by (used in) operating activities $ — $ 51,864 $ 52,077 $ — $ 103,941 Cash flows from investing activities: Acquisitions of oil and natural gas properties — — (173,000 ) — (173,000 ) Additions to oil and gas properties — (75,227 ) (58,973 ) — (134,200 ) Additons to restricted investments — — (826 ) — (826 ) Additions to other property and equipment — (31 ) — — (31 ) Investment in subsidiaries — (4,146 ) — 4,146 — Distribution from subsidiaries — 4,993 — (4,993 ) — Other — (3 ) (301 ) — (304 ) Net cash used in investing activities — (74,414 ) (233,100 ) (847 ) (308,361 ) Cash flows from financing activities: — Advances on revolving credit facility — 108,000 235,000 — 343,000 Payments on revolving credit facility — (40,000 ) (39,000 ) — (79,000 ) Deferred finance costs — (895 ) (267 ) — (1,162 ) Capital contributions — — 4,146 (4,146 ) — Contributions related to sale of assets to NGP affiliate — — 1,165 — 1,165 Distribution to equity owners — — (36,078 ) 36,078 — Distribution to noncontrolling interests — — — (31,085 ) (31,085 ) Distribution related to assets aquired from NGP affiliates — (63,389 ) (3,304 ) — (66,693 ) Other — — (7 ) — (7 ) Net cash provided by financing activities — 3,716 161,655 847 166,218 Net change in cash and cash equivalents — (18,834 ) (19,368 ) — (38,202 ) Cash and cash equivalents, beginning of period 48,619 29,102 77,721 Cash and cash equivalents, end of period $ — $ 29,785 $ 9,734 $ — $ 39,519	Note 18. 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 period 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. December 31, 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 5,833 7,993 14,201 — 28,027 Total current assets 155,587 56,707 307,130 (13,807 ) 505,617 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 14,124 5,660 100,521 (5,400 ) 114,905 Total assets $ 1,449,671 $ 1,113,089 $ 3,189,786 $ (1,158,999 ) $ 4,593,547 LIABILITIES AND EQUITY Current liabilities: Accounts payable and accrued liabilities $ 6,245 $ 107,068 $ 114,584 $ (3,125 ) $ 224,772 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 6,245 137,948 154,392 (12,548 ) 286,037 Long-term debt 783,000 — 1,595,413 — 2,378,413 Asset retirement obligations — 9,830 112,701 — 122,531 Deferred tax liabilities 69,431 — 30,986 (5,400 ) 95,017 Other long-term liabilities 8,585 — — — 8,585 Total liabilities 867,261 147,778 1,893,492 (17,948 ) 2,890,583 Equity: Equity 582,410 965,311 1,290,734 (2,256,045 ) 582,410 Noncontrolling interests — — 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 and equity $ 1,449,671 $ 1,113,089 $ 3,189,786 $ (1,158,999 ) $ 4,593,547 December 31, 2013 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Combined & Consolidated (In thousands) ASSETS Current assets: Cash and cash equivalents $ — $ 48,619 $ 29,102 $ — $ 77,721 Restricted cash — 35,000 — — 35,000 Accounts receivable - trade — 49,655 39,459 (392 ) 88,722 Accounts receivable - affiliates — 8,905 1,532 (5,785 ) 4,652 Short-term derivative instruments — 1,688 7,601 — 9,289 Prepaid expenses and other current assets — 7,783 11,730 — 19,513 Total current assets — 151,650 89,424 (6,177 ) 234,897 Property and equipment, net — 785,914 1,633,790 — 2,419,704 Long-term derivative instruments — 5,960 42,656 — 48,616 Investments in subsidiaries — 288,760 — (288,760 ) — Other long-term assets — 35,137 90,807 — 125,944 Total assets $ — 1,267,421 1,856,677 (294,937 ) 2,829,161 LIABILITIES AND EQUITY Current Liabilities: Accounts payable and accrued liabilities $ — $ 61,865 $ 57,392 $ (393 ) $ 118,864 Accounts payable - affiliates — 7,481 1,017 (6,523 ) 1,975 Revenues payable — 36,307 19,784 — 56,091 Short-term derivative instruments — 1,715 7,996 — 9,711 Total current liabilities — 107,368 86,189 (6,916 ) 186,641 Long-term debt — 871,150 792,067 — 1,663,217 Asset retirement obligations — 9,612 102,067 — 111,679 Long-term derivative instruments — 205 5,875 — 6,080 Deferred tax liabilities — — 1,151 1,955 3,106 Other long-term liabilities — 306 1,955 (1,955 ) 306 Total liabilities — 988,641 989,304 (6,916 ) 1,971,029 Equity: Equity — 277,517 855,768 (855,768 ) 277,517 Noncontrolling interests — 1,263 11,605 567,747 580,615 Total equity — 278,780 867,373 (288,021 ) 858,132 Total liabilities and equity $ — $ 1,267,421 $ 1,856,677 $ (294,937 ) $ 2,829,161 December 31, 2014 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Combined & Consolidated (In thousands) Revenues: Oil & natural gas sales $ — $ 363,114 $ 531,853 $ — $ 894,967 Other revenues 5 7 4,366 — 4,378 Total revenues 5 363,121 536,219 — 899,345 Costs and expenses: Lease operating — 17,570 143,733 — 161,303 Pipeline operating — — 2,068 — 2,068 Exploration — 13,853 2,750 — 16,603 Production and ad valorem taxes — 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 ) 1,075,146 338,771 — 1,263,019 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 ) Debt extinguishment costs (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 $ — $ 184,757 $ 387,191 $ — $ 571,948 Other revenues — — 3,075 — 3,075 Total revenues — 184,757 390,266 — 575,023 Costs and expenses: Lease operating — 14,710 98,930 — 113,640 Pipeline operating — — 1,835 — 1,835 Exploration — 1,034 1,322 — 2,356 Production and ad valorem taxes — 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 — 135,871 217,096 — 352,967 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 $ (120,785.00 ) $ 101,502 December 31, 2012 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Combined & Consolidated (In thousands) Revenues: Oil & natural gas sales $ — $ 100,242 $ 293,389 $ — $ 393,631 Other revenues — — 3,237 — 3,237 Total revenues — 100,242 296,626 — 396,868 Costs and expenses: Lease operating — 14,656 89,529 (431 ) 103,754 Pipeline operating — — 2,114 — 2,114 Exploration — 466 9,334 — 9,800 Production and ad valorem taxes — 8,021 15,603 — 23,624 Depreciation, depletion and amortization — 34,843 103,829 — 138,672 Impairment of proved oil and natural gas properties — 4,250 24,621 — 28,871 Incentive unit compensation expense — 9,510 — — 9,510 General and administrative — 19,525 39,721 431 59,677 Accretion of asset retirement obligations — 487 4,522 — 5,009 (Gain) loss on commodity derivatives — (10,500 ) (24,405 ) — (34,905 ) (Gain) loss on sale of properties — (2 ) (9,759 ) — (9,761 ) Other, net — 459 43 — 502 Total costs and expenses — 81,715 255,152 — 336,867 Operating income (loss) — 18,527 41,474 — 60,001 Other income (expense): Interest expense, net — (8,164 ) (25,074 ) — (33,238 ) Equity earnings from subsidiaries — (16,331 ) — 16,331 — Other, net — 456 (115 ) — 341 Total other income (expense) — (24,039 ) (25,189 ) 16,331 (32,897 ) Income before income taxes — (5,512 ) 16,285 16,331 27,104 Income tax benefit (expense) — — (107 ) — (107 ) Net income (loss) — (5,512 ) 16,178 16,331 26,997 Net income (loss) attributable to noncontrolling interest — — 104 (2,805 ) (2,701 ) Net income (loss) attributable to Memorial Resource Development Corp. $ — $ (5,512.00 ) $ 16,074 $ 19,136 $ 29,698 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 restricted investments — — (3,976 ) — (3,976 ) Additions to other property and equipment (15,980 ) (989 ) (98 ) — (17,067 ) Investment in subsidiaries (696,489 ) — — 696,489 — Distribution 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 facilities 1,174,000 126,800 1,446,000 — 2,746,800 Payments on revolving credit facilities (991,000 ) (329,900 ) (1,137,000 ) — (2,457,900 ) Proceeds from the issuances of senior notes 600,000 — 492,425 — 1,092,425 Redemption of senior notes (351,808 ) — — — (351,808 ) Redemption of second lien credit facility — (328,282 ) — — (328,282 ) Deferred financing costs (18,779 ) (61 ) (11,494 ) — (30,334 ) Proceeds from initial public offering 408,500 — — — 408,500 Costs incurred in conjunction with initial public offering (28,373 ) — — — (28,373 ) Proceeds from MEMP public offering — — 553,288 — 553,288 Costs incurred in conjunction with MEMP public 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 ) Purchase of additional interests in subsidiaries (3,292 ) — — — (3,292 ) Capital contributions — 686,623 9,866 (696,489 ) — Contributions from NGP affiliates related to sale of properties — — 1,165 — 1,165 Distribution to equity owners — (15,000 ) (222,633 ) 237,633 — Distributions to MRD Holdco (17,207 ) (39,520 ) (3,076 ) (59,803 ) Distributions to noncontrolling interests — — — (149,084 ) (149,084 ) Distribution to NGP affiliates related to purchase of assets — (63,389 ) (3,304 ) — (66,693 ) 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 ) Equity repurchases — — — — — 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 December 31, 2012 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidation (In thousands) Net cash provided by (used in) operating activities $ — $ 56,443 $ 183,961 $ — $ 240,404 Cash flows from investing activities: Acquisitions of oil and natural gas properties — (83,055 ) (277,623 ) — (360,678 ) Additions to oil and gas properties — (85,431 ) (187,903 ) — (273,334 ) Additions to restricted investments — — (4,599 ) — (4,599 ) Additions to other property and equipment — (926 ) (1,748 ) — (2,674 ) Investment in subsidiaries — (718 ) — 718 — Distribution from subsidiaries — 22,979 — (22,979 ) — Change in restricted cash — (3 ) — — (3 ) Proceeds from the sale of oil and gas properties — — 34,521 — 34,521 Other — — 29 — 29 Net cash used in investing activities — (147,154 ) (437,323 ) (22,261 ) (606,738 ) Cash flows from financing activities: Advances on revolving credit facilities — 122,950 496,500 — 619,450 Payments on revolving credit facilities — (24,750 ) (226,819 ) — (251,569 ) Deferred financing costs — (1,109 ) (2,392 ) — (3,501 ) Capital contributions — — 718 (718 ) — Contributions from previous owners — — 44,072 — 44,072 Contributions from NGP affiliates related to sale of properties — — 45,158 — 45,158 Proceeds from MEMP public offering — — 202,573 — 202,573 Costs incurred in conjunction with MEMP public offering — — (8,268 ) — (8,268 ) Distributions to equity owners — — (38,187 ) 38,187 — Distribution to NGP affiliates related to purchase of assets — — (242,174 ) — (242,174 ) Distributions to noncontrolling interests — — — (15,208 ) (15,208 ) Distributions made by previous owners — (2,282 ) (26,490 ) — (28,772 ) Net cash provided by financing activities — 94,809 244,691 22,261 361,761 Net change in cash and cash equivalents — 4,098 (8,671 ) — (4,573 ) Cash and cash equivalents, beginning of period — 14,525 39,439 — 53,964 Cash and cash equivalents, end of period $ — $ 18,623 $ 30,768 $ — $ 49,391

Quarterly Financial Information

Quarterly Financial Information (Unaudited)	12 Months Ended
	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Information (Unaudited)	Note 19. Quarterly Financial Information (Unaudited) The following tables present selected quarterly financial data for the periods indicated. Earnings per share are computed independently for each of the quarters presented and the sum of the quarterly earnings per share may not necessarily equal the total for the year. As discussed in Note 4 and Note 12, we recorded oil and natural gas property impairments and incentive unit compensation expense, respectively, during 2014, which impacted the comparability between the periods presented below. First Quarter Second Quarter Third Quarter Fourth Quarter For the Year Ended December 31, 2014 (In thousands, except per share amounts) Revenues $ 190,828 $ 236,564 $ 245,493 $ 226,460 Operating income (loss) 10,605 (993,256 ) 174,201 444,776 Net income (loss) (23,516 ) (1,053,443 ) 112,037 328,859 Net income (loss) attributable to noncontrolling interest (31,888 ) (105,094 ) 102,109 161,661 Net income (loss) attributable to Memorial Resource 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 First Quarter Second Quarter Third Quarter Fourth Quarter For the Year Ended December 31, 2013 (In thousands, except per share amounts) Revenues $ 122,181 $ 147,045 $ 153,515 $ 152,282 Operating income (loss) 9,521 90,327 117,797 4,411 Net income (loss) 180 78,158 95,962 (22,968 ) Net income (loss) attributable to noncontrolling interest (4,069 ) 34,975 11,235 7,689 Net income (loss) attributable to Memorial Resource Development Corp. 4,249 43,183 84,727 (30,657 ) Net income (loss) allocated to members 2,597 35,278 84,754 (31,917 ) Net income (loss) allocated to previous owners 1,652 7,905 (27 ) 1,260

Supplemental Oil and Gas Inform

Supplemental Oil and Gas Information (Unaudited)	12 Months Ended
	Dec. 31, 2014
Extractive Industries [Abstract]
Supplemental Oil and Gas Information (Unaudited)	Note 20. Supplemental Oil and Gas Information (Unaudited) Capitalized Costs Relating to Oil and Natural Gas Producing Activities The total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depreciation, depletion and amortization is as follows at the dates indicated. For the Year Ended December 31, 2014 2013 2012 (In thousands) MRD Segment: Evaluated oil and natural gas properties $ 1,268,873 $ 897,511 $ 742,404 Unevaluated oil and natural gas properties 48,229 44,453 24,629 Accumulated depletion, depreciation, and amortization (276,837 ) (160,620 ) (122,712 ) Subtotal $ 1,040,265 $ 781,344 $ 644,321 MEMP Segment: Evaluated oil and natural gas properties (1) $ 3,329,338 $ 2,077,344 $ 1,849,457 Support equipment and facilities 185,997 5,910 5,760 Unevaluated oil and natural gas properties — 1,960 6,964 Accumulated depletion, depreciation, and amortization (1) (1,057,398 ) (462,742 ) (345,579 ) Subtotal $ 2,457,937 $ 1,622,472 $ 1,516,602 Consolidated: Evaluated oil and natural gas properties (1) $ 4,598,211 $ 2,974,855 $ 2,591,861 Support equipment and facilities 185,997 5,910 5,760 Unevaluated oil and natural gas properties 48,229 46,413 31,593 Accumulated depletion, depreciation, and amortization (1) (1,334,235 ) (623,362 ) (468,291 ) Total $ 3,498,202 $ 2,403,816 $ 2,160,923 (1) Amounts do not include costs for SPBPC and related support equipment. Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities Costs incurred in property acquisition, exploration and development activities were as follows for the periods indicated: For the Year Ended December 31, 2014 2013 2012 (In thousands) MRD Segment: Property acquisition costs, proved $ 74,490 $ 56,108 $ 87,857 Property acquisition costs, unproved 24,310 19,975 5,293 Exploration and extension well costs 209,532 13,313 212 Development 181,026 191,350 99,028 Subtotal $ 489,358 $ 280,746 $ 192,390 MEMP Segment: Property acquisition costs, proved $ 983,796 $ 37,786 $ 278,246 Exploration and extension well costs — — 42,430 Development (1) 306,751 164,920 99,395 Subtotal $ 1,290,547 $ 202,706 $ 420,071 Consolidated: Property acquisition costs, proved $ 1,058,286 $ 93,894 $ 366,103 Property acquisition costs, unproved 24,310 19,975 5,293 Exploration and extension well costs 209,532 13,313 42,642 Development (1) 487,777 356,270 198,423 Total $ 1,779,905 $ 483,452 $ 612,461 (1) Amounts do not include costs for SPBPC and related support equipment. Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves As required by the FASB and SEC, the standardized measure of discounted future net cash flows presented below is computed by applying first-day-of-the-month average prices, year-end costs and legislated tax rates and a discount factor of 10 percent to proved reserves. We do not believe the standardized measure provides a reliable estimate of the Company’s expected future cash flows to be obtained from the development and production of its oil and gas properties or of the value of its proved oil and gas reserves. The standardized measure is prepared on the basis of certain prescribed assumptions including first-day-of-the-month average prices, which represent discrete points in time and therefore may cause significant variability in cash flows from year to year as prices change. Oil and Natural Gas Reserves Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures. Proved reserves are those quantities of oil and natural gas that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. We engaged NSAI and MEMP engaged NSAI and Ryder Scott to audit our internally prepared reserves estimates for all of our estimated proved reserves (by volume) at December 31, 2014. All proved reserves are located in the United States and all prices are held constant in accordance with SEC rules. The weighted-average benchmark product prices used for valuing the reserves are based upon the average of the first-day-of-the-month price for each month within the period January through December of each year presented: 2014 2013 2012 Oil ($/Bbl) West Texas Intermediate (1) $ 91.48 $ 93.42 $ 91.33 NGL ($/Bbl) West Texas Intermediate (1) $ 91.48 $ 93.42 $ 91.75 Natural Gas ($/Mmbtu) Henry Hub (2) $ 4.35 $ 3.67 $ 2.75 (1) The unweighted average West Texas Intermediate price was adjusted by lease for quality, transportation fees, and a regional price differential. (2) The unweighted average Henry Hub price was adjusted by lease for energy content, compression charges, transportation fees, and regional price differentials. Net Reserves The following tables set forth estimates of the net reserves as of December 31, 2014, 2013, and 2012 respectively: For the Year Ended December 31, 2014 Oil (MBbls) Gas (MMcf) NGLs (MBbls) Equivalent (MMcfe) Proved developed and undeveloped reserves: Beginning of the year 50,459 1,409,393 71,422 2,140,683 Extensions and discoveries 2,674 196,250 10,587 275,815 Purchase of minerals in place 69,364 35,222 23,598 592,996 Production (4,042 ) (105,295 ) (4,363 ) (155,718 ) Sales of minerals in place (623 ) (10,815 ) (950 ) (20,253 ) Revision of previous estimates (5,659 ) 215,801 11,773 252,467 End of year (1) 112,173 1,740,556 112,067 3,085,990 Proved developed reserves: Beginning of year 25,667 651,345 29,863 984,535 End of year 58,431 772,578 55,463 1,455,934 Proved undeveloped reserves: Beginning of year 24,792 758,048 41,559 1,156,148 End of year 53,742 967,978 56,604 1,630,056 (1) Includes reserves of 1,452,457 MMcfe attributable to noncontrolling interests. For the Year Ended December 31, 2013 Oil (MBbls) Gas (MMcf) NGLs (MBbls) Equivalent (MMcfe) Proved developed and undeveloped reserves: Beginning of the year 51,042 1,343,818 70,818 2,074,982 Extensions and discoveries 7,449 190,744 10,065 295,832 Purchase of minerals in place 330 48,109 1,275 57,737 Production (2,429 ) (70,016 ) (3,089 ) (103,122 ) Sales of minerals in place (599 ) (14,137 ) (1,573 ) (27,169 ) Revision of previous estimates (5,334 ) (89,125 ) (6,074 ) (157,577 ) End of year (1) 50,459 1,409,393 71,422 2,140,683 Proved developed reserves: Beginning of year 27,597 622,381 28,268 957,573 End of year 25,667 651,345 29,863 984,535 Proved undeveloped reserves: Beginning of year 23,445 721,437 42,550 1,117,409 End of year 24,792 758,048 41,559 1,156,148 (1) Includes reserves of 966,335 MMcfe attributable to noncontrolling interests and previous owners. For the Year Ended December 31, 2012 Oil (MBbls) Gas (MMcf) NGLs (MBbls) Equivalent (MMcfe) Proved developed and undeveloped reserves: Beginning of the year 37,984 1,509,086 68,076 2,145,454 Extensions and discoveries 8,190 61,888 3,831 134,010 Purchase of minerals in place 12,436 141,732 8,974 270,190 Production (1,888 ) (53,875 ) (1,643 ) (75,056 ) Sales of minerals in place (4,218 ) (4,942 ) — (30,250 ) Revision of previous estimates (1,462 ) (310,071 ) (8,420 ) (369,366 ) End of year (1) 51,042 1,343,818 70,818 2,074,982 Proved developed reserves: Beginning of year 21,439 604,988 17,659 839,577 End of year 27,597 622,381 28,268 957,573 Proved undeveloped reserves: Beginning of year 16,545 904,098 50,417 1,305,877 End of year 23,445 721,437 # 42,550 1,117,409 (1) Includes reserves of 605,680 MMcfe attributable to noncontrolling interests and previous owners. Noteworthy amounts included in the categories of proved reserve changes in the above tables include: · MRD had upward revisions of 261.3 Bcfe primarily due to well performance in East Texas and North Louisiana. Additionally, there was an increase of 253.7 Bcfe from extensions, primarily due to the redevelopment program in the Terryville Complex. MRD also acquired 31.3 Bcfe from multiple acquisitions already inside the Terryville Complex. Proved undeveloped reserves increased during the year primarily due to the development of unproved locations in 2014 and revisions to our forecasts for East Texas properties, which give effect for well performance using longer lateral lengths. · 148.6 Bcfe of the increase in reserves for the year ended December 31, 2013, through the category extensions and discoveries, was due to the horizontal redevelopment drilling program in the Terryville Complex. · WildHorse acquired 43.5 Bcfe in multiple acquisitions during the year ended December 31, 2012, the largest being the Undisclosed Seller Acquisition. Downward revisions of previous estimates for estimated natural gas proved reserves was primarily the result of a decrease in natural gas prices. · MEMP acquired 561.7 Bcfe in multiple acquisitions during the year ended December 31, 2014, the largest being the Wyoming Acquisition of 497.2 Bcfe. MEMP also acquired 45.0 Bcfe from the Eagle Ford Acquisition. Downward revision of natural gas for the year ended December 31, 2014 was primarily due to updated well performance data in certain East Texas fields. Proved undeveloped reserves increased during the year ended December 31, 2014 primarily due to the Wyoming Acquisition. · MEMP acquired 224.2 Bcfe in multiple acquisitions during the year ended December 31, 2012, the largest being the Goodrich Acquisition of 148.9 Bcfe. Stanolind acquired 43.6 Bcfe through multiple acquisitions, the largest being the Menemsha Acquisition of 23.9 Bcfe. During the year ended December 31, 2012, Propel divested 19.0 Bcfe of offshore Louisiana oil and gas properties to an NGP controlled entity. See Note 3 for additional information on acquisitions and divestitures. A variety of methodologies are used to determine our proved reserve estimates. The principal methodologies employed are reservoir simulation, decline curve analysis, volumetric, material balance, advance production type curve matching, petro-physics/log analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all of our fields. Standardized Measure The standardized measure of discounted future net cash flows is as follows: For the Year Ended December 31, 2014 2013 2012 (In thousands) Future cash inflows $ 21,505,195 $ 12,614,999 $ 11,432,968 Future production costs (5,841,650 ) (4,306,398 ) (3,513,843 ) Future development costs (2,665,833 ) (2,038,803 ) (1,681,721 ) Future income tax expense (1) (1,789,031 ) — — Future net cash flows for estimated timing of cash flows 11,208,681 6,269,798 6,237,404 10% annual discount for estimated timing of cash flows (6,486,539 ) (3,192,733 ) (3,326,893 ) Standardized measure of discounted future net cash flows (2) $ 4,722,142 $ 3,077,065 $ 2,910,511 (1) Our predecessor was a pass through entity and was subject to the Texas margin tax which has a maximum effective rate of 0.7% of gross income apportioned to Texas. Due to immateriality, we have excluded the impact of this tax for the years ended December 31, 2013 and 2012. (2) Includes $2,756,848, $1,529,216 and $1,113,453 attributable to both noncontrolling interests and previous owners for the years ended December 31, 2014, 2013 and 2012, respectively. Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves The following is a summary of the changes in the standardized measure of discounted future net cash flows for the proved oil and natural gas reserves during each of the years in the three year period ended December 31, 2014: For the Year Ended December 31, 2014 2013 2012 (In thousands) Beginning of year $ 3,077,065 $ 2,910,511 $ 2,885,485 Sale of oil and natural gas produced, net of production costs (687,717 ) (430,964 ) (267,339 ) Purchase of minerals in place 1,558,759 74,337 474,337 Sale of minerals in place (47,791 ) (54,091 ) (154,963 ) Extensions and discoveries 697,931 437,427 393,102 Changes in income taxes, net (1,058,815 ) — 1,947 Changes in prices and costs 196,530 (85,731 ) (733,962 ) Previously estimated development costs incurred 480,466 261,787 130,750 Net changes in future development costs (201,177 ) (17,514 ) (68,471 ) Revisions of previous quantities 665,089 (327,926 ) (267,375 ) Accretion of discount 307,707 287,535 288,743 Change in production rates and other (265,905 ) 21,694 228,257 End of year $ 4,722,142 $ 3,077,065 $ 2,910,511

Subsequent Events

Subsequent Events	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Subsequent Events [Abstract]
Subsequent Events	Note 17. Subsequent Events MRD Common Stock Repurchase Approval For additional information, see Note 9. MRD Borrowing Base Reaffirmed For additional information, see Note 8. MRD Sale of Oil and Natural Gas Properties in Colorado and Wyoming For additional information, see Note 3. MRD and PennTex Midstream Agreements For additional information, see Note 13.	Note 21. Subsequent Events Termination of WHR Management Company Service Agreement For additional information, see Note 13. 2015 Repurchases of MRD Common Stock and MEMP Common Units For additional information, see Note 9.

Background, Organization and Ba

Background, Organization and Basis of Presentation	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Organization and Basis of Presentation	Note 1. Background, 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. References to: (i) “Memorial Production Partners,” “MEMP” and “the Partnership” refer to Memorial Production Partners LP individually and collectively with its subsidiaries, as the context requires; (ii) “MEMP GP” refer to Memorial Production Partners GP LLC, the general partner of the Partnership, which we own; (iii) “MRD Holdco” refer to MRD Holdco LLC, a holding company controlled by the Funds (defined below) that, together as part of a group, owns a majority of our common stock; (iv) “MRD LLC” refer to Memorial Resource Development LLC, which historically owned our predecessor’s business and was merged into MRD Operating LLC (“MRD Operating”), our 100% owned subsidiary, subsequent to our initial public offering; (v) “WildHorse Resources” refer to WildHorse Resources, LLC, which owned our interest in the Terryville Complex and merged into MRD Operating in February 2015; (vi) “our predecessor” refer collectively to MRD LLC and its former consolidated subsidiaries, consisting of Classic Hydrocarbons Holdings, L.P., Classic Hydrocarbons GP Co., L.L.C., Black Diamond Minerals, LLC, Beta Operating Company, LLC, MEMP GP, BlueStone Natural Resources Holdings, LLC (“BlueStone”), MRD Operating, WildHorse Resources, Tanos Energy LLC and each of their respective subsidiaries, including MEMP and its subsidiaries; (vii) “the Funds” refer collectively to Natural Gas Partners VIII, L.P., Natural Gas Partners IX, L.P. and NGP IX Offshore Holdings, L.P., which collectively control MRD Holdco; and (viii) “NGP” refer to Natural Gas Partners, a family of private equity investment funds organized to make direct equity investments in the energy industry, including the Funds. Previous Owners References to “the previous owners” for accounting and financial reporting purposes refer to the 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 certain acquisitions in 2010, 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 unaudited financial statements reported herein include the financial position and results attributable to 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. All material intercompany transactions and balances have been eliminated in preparation of our consolidated and combined financial statements. Our results of operations for the three months ended March 31, 2015 are not necessarily indicative of results expected for the full year. In our opinion, the accompanying unaudited condensed consolidated and combined financial statements include all adjustments of a normal recurring nature necessary for fair presentation. Although we believe the disclosures in these financial statements are adequate and make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted pursuant to the rules and regulations of the United States Securities and Exchange Commission (“SEC”). We have two reportable business segments, both of which are engaged in the acquisition, exploration and development 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 acquisition by the MEMP Segment of certain assets from the MRD Segment in East Texas in February 2015 in exchange for approximately $78.0 million in cash and certain properties in North Louisiana (the “Property Swap”) for comparability purposes. Our equity statement reflects a $172.9 million equity transfer from stockholders’ equity to noncontrolling interest related to this transaction. This amount represents $250.8 million of net book value related to the assets transferred to MEMP allocated to its limited partners less $77.9 million of cash allocated to its limited partners. Amounts allocated to MEMP GP eliminate in consolidation. Use of Estimates The preparation of the accompanying unaudited condensed 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 compensation; fair values of assets acquired and liabilities assumed in business combinations and asset retirement obligations.	Note 1. Organization and Basis of Presentation Overview Memorial Resource Development Corp. (the “Company”) is a publicly traded Delaware corporation, the common shares of which are listed on the NASDAQ Global Market (“NASDAQ”) under the symbol “MRD.” Unless the context requires otherwise, references to “we,” “us,” “our,” “MRD,” or “the Company” are intended to mean the business and operations of Memorial Resource Development Corp. and its consolidated subsidiaries. The Company was formed by Memorial Resource Development LLC (“MRD LLC”) in January 2014 to acquire, explore and develop natural gas and oil properties in North America. MRD LLC was a Delaware limited liability company formed on April 27, 2011 by Natural Gas Partners VIII, L.P. (“NGP VIII”), Natural Gas Partners IX, L.P. (“NGP IX”) and NGP IX Offshore Holdings, L.P. (“NGP IX Offshore”) (collectively, the “Funds”) to explore, develop and acquire natural gas and oil properties. The Funds are private equity funds managed by Natural Gas Partners (“NGP”). MRD LLC’s consolidated and combined financial statements represent our predecessor for accounting and financial reporting purposes prior to our initial public offering. Initial Public Offering and Restructuring Transactions On June 18, 2014, the Company completed its initial public offering of 21,500,000 common units at a price of $19.00 per share, which generated net proceeds to the Company of approximately $380.2 million after deducting underwriting discounts and commissions and other offering related fees and expenses. The following restructuring events and transactions occurred in connection with our initial public offering: — The Funds contributed all of their interests in MRD LLC to MRD Holdco LLC (“MRD Holdco”) and the members of our management who owned incentive units in MRD LLC exchanged those incentive units for substantially identical incentive units in MRD Holdco, after which MRD Holdco owned 100% of MRD LLC; — WildHorse Resources, LLC (“WildHorse Resources”) sold its subsidiary, WildHorse Resources Management Company, LLC (“WHR Management Company”), to an affiliate of the Funds for approximately $0.2 million in cash, and WHR Management Company entered into a services agreement with the Company and WildHorse Resources pursuant to which WHR Management Company agreed to provide certain management services to WildHorse Resources, which was terminated as of March 1, 2015; — Classic Hydrocarbons Holdings, L.P. (“Classic”) and Classic Hydrocarbons GP Co., L.L.C. (“Classic GP”) distributed to MRD LLC the ownership interests in Classic Pipeline & Gathering, LLC (“Classic Pipeline”), which owns certain midstream assets in Texas, and Black Diamond Minerals, LLC (“Black Diamond”) distributed to MRD LLC its ownership interests in Golden Energy Partners LLC (“Golden Energy”), which sold all of its assets in May 2014; — MRD LLC contributed to us substantially all of its assets, comprised of: (i) 100% of the ownership interests in Classic, Classic GP, Black Diamond, Beta Operating Company, LLC (“Beta Operating”), Memorial Resource Finance Corp., MRD Operating LLC (“MRD Operating”), Memorial Production Partners GP LLC (“MEMP GP”) (including MEMP GP’s ownership of 50% of Memorial Production Partners LP’s (“MEMP”) incentive distribution rights) and (ii) 99.9% of the membership interests in WildHorse Resources; — We issued 128,665,677 shares of our common stock to MRD LLC, which MRD LLC immediately distributed to MRD Holdco; — We assumed the obligations of MRD LLC under the indenture governing the $350 million in aggregate principal amount of 10.00% / 10.75% Senior PIK Toggle Notes due 2018 (the “PIK notes”) and reimbursed MRD LLC for the June 15, 2014 interest payment made on the PIK notes; — Certain former management members of WildHorse Resources contributed to us their outstanding incentive units in WildHorse Resources, as well as the remaining 0.1% of the membership interests in WildHorse Resources, and we issued 42,334,323 shares of our common stock and paid cash consideration of $30.0 million to such former management members of WildHorse Resources; — We entered into a registration rights agreement and a voting agreement with MRD Holdco and certain former management members of WildHorse Resources; — We entered into a new $2.0 billion revolving credit facility (see Note 8) and used approximately $614.5 million in borrowings under that facility to repay all amounts outstanding under WildHorse Resources’ credit agreements, to partially fund the cash consideration payable to the former management members of WildHorse Resources and to reimburse MRD LLC for the June 15, 2014 interest payment made on the PIK notes; — Notice of redemption was given to the PIK notes trustee (see Note 8) specifying a redemption date of July 16, 2014 and indicating that a portion of the net proceeds from our initial public offering, which temporarily reduced amounts outstanding under our new revolving credit facility, would be used to redeem the PIK notes at a redemption price of 102% of the principal amount of the PIK notes plus accrued and unpaid interest thereon to the date of redemption; — MRD Operating entered into a merger agreement with MRD LLC pursuant to which after the termination or earlier discharge of the PIK notes MRD LLC would merge into MRD Operating; — MRD LLC distributed to MRD Holdco the following: (i) BlueStone Natural Resources Holdings, LLC (“BlueStone”), which sold substantially all of its assets in July 2013 for $117.9 million, MRD Royalty LLC, which owns certain leasehold interests and overriding royalty interests in Texas and Montana, MRD Midstream LLC, which owns an indirect interest in certain midstream assets in North Louisiana, Golden Energy and Classic Pipeline; (ii) 5,360,912 subordinated units of MEMP; (iii) the right to the remaining cash to be released from the debt service reserve account in connection with the redemption or earlier discharge of the PIK notes plus the cash received from us in reimbursement of the interest paid on June 15, 2014 in respect of the PIK notes; and (iv) approximately $6.7 million of cash received by MRD LLC in connection with the sale of Golden Energy’s assets in May 2014; — We irrevocably deposited with the PIK notes trustee approximately $360.0 million on June 27, 2014, which was an amount sufficient to fund the redemption of the PIK notes on the redemption date and to satisfy and discharge our obligations under the PIK notes and the related indenture. The discharge became effective upon the irrevocable deposit of the funds with the PIK notes trustee; and — MRD LLC merged into MRD Operating. Previous Owners References to “the previous owners” for accounting and financial reporting purposes refer collectively to: — Certain oil and natural gas properties and related assets primarily in the Permian Basin, East Texas and the Rockies that MEMP acquired through equity transactions in October 2013 from certain affiliates of NGP. In October 2013, MEMP acquired Boaz Energy, LLC (“Boaz”), Crown Energy Partners, LLC (“Crown”), the Crown net profits interest and overriding royalty interest (“Crown NPI/ORRI”), Propel Energy SPV LLC (“Propel SPV”), together with its wholly-owned subsidiary Propel Energy Services, LLC (“Propel Energy Services”), and Stanolind Oil and Gas SPV LLC (“Stanolind SPV”) from Boaz Energy Partners, LLC (“Boaz Energy Partners”), Crown Energy Partners Holdings, LLC (“Crown Holdings”), Propel Energy, LLC (“Propel Energy”) and Stanolind Oil and Gas LP (“Stanolind”), all of which are primarily owned by two of the Funds. — A net profits interest that WildHorse Resources purchased from NGP Income Co-Investment Fund II, L.P. (“NGPCIF”) in February 2014 (“NGPCIF NPI”). NGPCIF is controlled by NGP. Upon the completion of the 2010 Petrohawk and Clayton Williams acquisitions, WildHorse Resources sold a net profits interest in these properties to NGPCIF. Since WildHorse Resources sold the net profits interest, the historical results are accounted for as a working interest for all periods. Our audited financial statements reported herein include the financial position and results attributable to: (i) those certain oil and natural gas properties and related assets that MEMP acquired through equity transactions in October 2013 from Boaz Energy Partners, Crown Holdings, Propel Energy and Stanolind and (ii) NGPCIF NPI. Basis of Presentation The financial statements reported herein include the financial position and results attributable to both our predecessor and the previous owners on a combined basis for periods prior to our initial public offering. For periods after the completion of our public offering, our consolidated financial statements include our accounts and those of our subsidiaries in which we have a controlling interest. Due to our control of MEMP through our ownership of MEMP GP, we are required to consolidate MEMP for accounting and financial reporting purposes. MEMP is owned 99.9% by its limited partners and 0.1% by MEMP GP. All material intercompany transactions and balances have been eliminated in preparation of our consolidated and combined financial statements. The accompanying consolidated and combined financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). We have two reportable business segments, both of which are engaged in the acquisition, exploration, development and production of oil and natural gas properties (See Note 14). Our reportable business segments are as follows: — MRD—reflects the combined operations of the Company, MRD Operating, MRD LLC, WildHorse Resources and its previous owners, Black Diamond, BlueStone, Beta Operating and MEMP GP. — MEMP—reflects the combined operations of MEMP, its previous owners, and historical dropdown transactions that occurred between MEMP and other MRD (or its predecessor) consolidating subsidiaries. Segment financial information has been retrospectively revised for the following common control transactions for comparability purposes: — acquisition by MEMP of certain oil and gas properties in East Texas and non-core Louisiana from MRD in exchange for MEMP’s North Louisiana oil and gas properties and approximately $78.0 million in cash in February 2015; — acquisition by MEMP of all the outstanding membership interests in Tanos Energy, LLC (“Tanos”) from MRD LLC for a purchase price of approximately $77.4 million on October 1, 2013; — acquisition by MEMP of all the outstanding membership interests in Prospect Energy, LLC (“Prospect Energy”) from Black Diamond for a purchase price of approximately $16.3 million on October 1, 2013; — acquisition by MEMP of certain of the oil and natural gas properties in Jackson County, Texas from MRD LLC for a purchase price of approximately $2.6 million on October 1, 2013; — acquisition by MEMP of all the outstanding membership interests in WHT Energy Partners LLC (“WHT”) from WildHorse Resources and Tanos for a purchase price of approximately $200.0 million on March 28, 2013; — acquisition by MEMP of certain assets from Classic in East Texas in May 2012 for a purchase price of approximately $27.0 million; and — acquisition by MEMP of certain assets from Tanos in East Texas in April 2012 for a purchase price of approximately $18.5 million.

Summary of Significant Accoun29

Summary of Significant Accounting Policies (Policies)	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Accounting Policies [Abstract]
Overview	Overview Memorial Resource Development Corp. (the “Company”) is a publicly traded Delaware corporation, the common shares of which are listed on the NASDAQ Global Market (“NASDAQ”) under the symbol “MRD.” Unless the context requires otherwise, references to “we,” “us,” “our,” “MRD,” or “the Company” are intended to mean the business and operations of Memorial Resource Development Corp. and its consolidated subsidiaries. References to: (i) “Memorial Production Partners,” “MEMP” and “the Partnership” refer to Memorial Production Partners LP individually and collectively with its subsidiaries, as the context requires; (ii) “MEMP GP” refer to Memorial Production Partners GP LLC, the general partner of the Partnership, which we own; (iii) “MRD Holdco” refer to MRD Holdco LLC, a holding company controlled by the Funds (defined below) that, together as part of a group, owns a majority of our common stock; (iv) “MRD LLC” refer to Memorial Resource Development LLC, which historically owned our predecessor’s business and was merged into MRD Operating LLC (“MRD Operating”), our 100% owned subsidiary, subsequent to our initial public offering; (v) “WildHorse Resources” refer to WildHorse Resources, LLC, which owned our interest in the Terryville Complex and merged into MRD Operating in February 2015; (vi) “our predecessor” refer collectively to MRD LLC and its former consolidated subsidiaries, consisting of Classic Hydrocarbons Holdings, L.P., Classic Hydrocarbons GP Co., L.L.C., Black Diamond Minerals, LLC, Beta Operating Company, LLC, MEMP GP, BlueStone Natural Resources Holdings, LLC (“BlueStone”), MRD Operating, WildHorse Resources, Tanos Energy LLC and each of their respective subsidiaries, including MEMP and its subsidiaries; (vii) “the Funds” refer collectively to Natural Gas Partners VIII, L.P., Natural Gas Partners IX, L.P. and NGP IX Offshore Holdings, L.P., which collectively control MRD Holdco; and (viii) “NGP” refer to Natural Gas Partners, a family of private equity investment funds organized to make direct equity investments in the energy industry, including the Funds.	Overview Memorial Resource Development Corp. (the “Company”) is a publicly traded Delaware corporation, the common shares of which are listed on the NASDAQ Global Market (“NASDAQ”) under the symbol “MRD.” Unless the context requires otherwise, references to “we,” “us,” “our,” “MRD,” or “the Company” are intended to mean the business and operations of Memorial Resource Development Corp. and its consolidated subsidiaries. The Company was formed by Memorial Resource Development LLC (“MRD LLC”) in January 2014 to acquire, explore and develop natural gas and oil properties in North America. MRD LLC was a Delaware limited liability company formed on April 27, 2011 by Natural Gas Partners VIII, L.P. (“NGP VIII”), Natural Gas Partners IX, L.P. (“NGP IX”) and NGP IX Offshore Holdings, L.P. (“NGP IX Offshore”) (collectively, the “Funds”) to explore, develop and acquire natural gas and oil properties. The Funds are private equity funds managed by Natural Gas Partners (“NGP”). MRD LLC’s consolidated and combined financial statements represent our predecessor for accounting and financial reporting purposes prior to our initial public offering.
Initial Public Offering and Restructuring Transactions		Initial Public Offering and Restructuring Transactions On June 18, 2014, the Company completed its initial public offering of 21,500,000 common units at a price of $19.00 per share, which generated net proceeds to the Company of approximately $380.2 million after deducting underwriting discounts and commissions and other offering related fees and expenses. The following restructuring events and transactions occurred in connection with our initial public offering: — The Funds contributed all of their interests in MRD LLC to MRD Holdco LLC (“MRD Holdco”) and the members of our management who owned incentive units in MRD LLC exchanged those incentive units for substantially identical incentive units in MRD Holdco, after which MRD Holdco owned 100% of MRD LLC; — WildHorse Resources, LLC (“WildHorse Resources”) sold its subsidiary, WildHorse Resources Management Company, LLC (“WHR Management Company”), to an affiliate of the Funds for approximately $0.2 million in cash, and WHR Management Company entered into a services agreement with the Company and WildHorse Resources pursuant to which WHR Management Company agreed to provide certain management services to WildHorse Resources, which was terminated as of March 1, 2015; — Classic Hydrocarbons Holdings, L.P. (“Classic”) and Classic Hydrocarbons GP Co., L.L.C. (“Classic GP”) distributed to MRD LLC the ownership interests in Classic Pipeline & Gathering, LLC (“Classic Pipeline”), which owns certain midstream assets in Texas, and Black Diamond Minerals, LLC (“Black Diamond”) distributed to MRD LLC its ownership interests in Golden Energy Partners LLC (“Golden Energy”), which sold all of its assets in May 2014; — MRD LLC contributed to us substantially all of its assets, comprised of: (i) 100% of the ownership interests in Classic, Classic GP, Black Diamond, Beta Operating Company, LLC (“Beta Operating”), Memorial Resource Finance Corp., MRD Operating LLC (“MRD Operating”), Memorial Production Partners GP LLC (“MEMP GP”) (including MEMP GP’s ownership of 50% of Memorial Production Partners LP’s (“MEMP”) incentive distribution rights) and (ii) 99.9% of the membership interests in WildHorse Resources; — We issued 128,665,677 shares of our common stock to MRD LLC, which MRD LLC immediately distributed to MRD Holdco; — We assumed the obligations of MRD LLC under the indenture governing the $350 million in aggregate principal amount of 10.00% / 10.75% Senior PIK Toggle Notes due 2018 (the “PIK notes”) and reimbursed MRD LLC for the June 15, 2014 interest payment made on the PIK notes; — Certain former management members of WildHorse Resources contributed to us their outstanding incentive units in WildHorse Resources, as well as the remaining 0.1% of the membership interests in WildHorse Resources, and we issued 42,334,323 shares of our common stock and paid cash consideration of $30.0 million to such former management members of WildHorse Resources; — We entered into a registration rights agreement and a voting agreement with MRD Holdco and certain former management members of WildHorse Resources; — We entered into a new $2.0 billion revolving credit facility (see Note 8) and used approximately $614.5 million in borrowings under that facility to repay all amounts outstanding under WildHorse Resources’ credit agreements, to partially fund the cash consideration payable to the former management members of WildHorse Resources and to reimburse MRD LLC for the June 15, 2014 interest payment made on the PIK notes; — Notice of redemption was given to the PIK notes trustee (see Note 8) specifying a redemption date of July 16, 2014 and indicating that a portion of the net proceeds from our initial public offering, which temporarily reduced amounts outstanding under our new revolving credit facility, would be used to redeem the PIK notes at a redemption price of 102% of the principal amount of the PIK notes plus accrued and unpaid interest thereon to the date of redemption; — MRD Operating entered into a merger agreement with MRD LLC pursuant to which after the termination or earlier discharge of the PIK notes MRD LLC would merge into MRD Operating; — MRD LLC distributed to MRD Holdco the following: (i) BlueStone Natural Resources Holdings, LLC (“BlueStone”), which sold substantially all of its assets in July 2013 for $117.9 million, MRD Royalty LLC, which owns certain leasehold interests and overriding royalty interests in Texas and Montana, MRD Midstream LLC, which owns an indirect interest in certain midstream assets in North Louisiana, Golden Energy and Classic Pipeline; (ii) 5,360,912 subordinated units of MEMP; (iii) the right to the remaining cash to be released from the debt service reserve account in connection with the redemption or earlier discharge of the PIK notes plus the cash received from us in reimbursement of the interest paid on June 15, 2014 in respect of the PIK notes; and (iv) approximately $6.7 million of cash received by MRD LLC in connection with the sale of Golden Energy’s assets in May 2014; — We irrevocably deposited with the PIK notes trustee approximately $360.0 million on June 27, 2014, which was an amount sufficient to fund the redemption of the PIK notes on the redemption date and to satisfy and discharge our obligations under the PIK notes and the related indenture. The discharge became effective upon the irrevocable deposit of the funds with the PIK notes trustee; and — MRD LLC merged into MRD Operating.
Previous Owners	Previous Owners References to “the previous owners” for accounting and financial reporting purposes refer to the 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 certain acquisitions in 2010, 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 unaudited financial statements reported herein include the financial position and results attributable to NGPCIF NPI.	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. All material intercompany transactions and balances have been eliminated in preparation of our consolidated and combined financial statements. Our results of operations for the three months ended March 31, 2015 are not necessarily indicative of results expected for the full year. In our opinion, the accompanying unaudited condensed consolidated and combined financial statements include all adjustments of a normal recurring nature necessary for fair presentation. Although we believe the disclosures in these financial statements are adequate and make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted pursuant to the rules and regulations of the United States Securities and Exchange Commission (“SEC”). We have two reportable business segments, both of which are engaged in the acquisition, exploration and development 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 acquisition by the MEMP Segment of certain assets from the MRD Segment in East Texas in February 2015 in exchange for approximately $78.0 million in cash and certain properties in North Louisiana (the “Property Swap”) for comparability purposes. Our equity statement reflects a $172.9 million equity transfer from stockholders’ equity to noncontrolling interest related to this transaction. This amount represents $250.8 million of net book value related to the assets transferred to MEMP allocated to its limited partners less $77.9 million of cash allocated to its limited partners. Amounts allocated to MEMP GP eliminate in consolidation.	Basis of Presentation The financial statements reported herein include the financial position and results attributable to both our predecessor and the previous owners on a combined basis for periods prior to our initial public offering. For periods after the completion of our public offering, our consolidated financial statements include our accounts and those of our subsidiaries in which we have a controlling interest. Due to our control of MEMP through our ownership of MEMP GP, we are required to consolidate MEMP for accounting and financial reporting purposes. MEMP is owned 99.9% by its limited partners and 0.1% by MEMP GP. All material intercompany transactions and balances have been eliminated in preparation of our consolidated and combined financial statements. The accompanying consolidated and combined financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). We have two reportable business segments, both of which are engaged in the acquisition, exploration, development and production of oil and natural gas properties (See Note 14). Our reportable business segments are as follows: — MRD—reflects the combined operations of the Company, MRD Operating, MRD LLC, WildHorse Resources and its previous owners, Black Diamond, BlueStone, Beta Operating and MEMP GP. — MEMP—reflects the combined operations of MEMP, its previous owners, and historical dropdown transactions that occurred between MEMP and other MRD (or its predecessor) consolidating subsidiaries. Segment financial information has been retrospectively revised for the following common control transactions for comparability purposes: — acquisition by MEMP of certain oil and gas properties in East Texas and non-core Louisiana from MRD in exchange for MEMP’s North Louisiana oil and gas properties and approximately $78.0 million in cash in February 2015; — acquisition by MEMP of all the outstanding membership interests in Tanos Energy, LLC (“Tanos”) from MRD LLC for a purchase price of approximately $77.4 million on October 1, 2013; — acquisition by MEMP of all the outstanding membership interests in Prospect Energy, LLC (“Prospect Energy”) from Black Diamond for a purchase price of approximately $16.3 million on October 1, 2013; — acquisition by MEMP of certain of the oil and natural gas properties in Jackson County, Texas from MRD LLC for a purchase price of approximately $2.6 million on October 1, 2013; — acquisition by MEMP of all the outstanding membership interests in WHT Energy Partners LLC (“WHT”) from WildHorse Resources and Tanos for a purchase price of approximately $200.0 million on March 28, 2013; — acquisition by MEMP of certain assets from Classic in East Texas in May 2012 for a purchase price of approximately $27.0 million; and — acquisition by MEMP of certain assets from Tanos in East Texas in April 2012 for a purchase price of approximately $18.5 million.
Use of Estimates	Use of Estimates The preparation of the accompanying unaudited condensed 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 compensation; fair values of assets acquired and liabilities assumed in business combinations and asset retirement obligations.	Use of Estimates The preparation of consolidated and combined financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated and combined financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates include, but are not limited to, oil and natural gas reserves; depreciation, depletion, and amortization of proved oil and natural gas properties; future cash flows from oil and natural gas properties; impairment of long-lived assets; fair value of derivatives; fair value of equity and incentive unit compensation; fair values of assets acquired and liabilities assumed in business combinations and asset retirement obligations.
Principles of Consolidation and Combination		Principles of Consolidation and Combination Our consolidated financial statements include our accounts and those of our subsidiaries in which we have a controlling interest, after the elimination of all intercompany accounts and transactions. Likewise, the combined financial statements include the accounts of our predecessor and the previous owners as discussed above. All material intercompany balances and transactions have been eliminated. Certain prior period balances have been reclassified to better align with financial statement presentation in the current fiscal year.
Cash and Cash Equivalents		Cash and Cash Equivalents Cash and cash equivalents represent unrestricted cash on hand and all highly liquid investments with original contractual maturities of three months or less.
Book Overdrafts		Book Overdrafts Book overdrafts, representing outstanding checks in excess of funds on deposit, are classified as accounts payable and the change in the related balance is reflected in operating activities in the statement of cash flows.
Concentrations of Credit Risk		Concentrations of Credit Risk Cash balances, accounts receivable, restricted investments and derivative financial instruments are financial instruments potentially subject to credit risk. Cash and cash equivalents are maintained in bank deposit accounts which, at times, may exceed the federally insured limits. Management periodically reviews and assesses the financial condition of the banks to mitigate the risk of loss. Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with MEMP’s offshore Southern California oil and gas properties. These restricted investments may consist of money market deposit accounts, money market mutual funds, commercial paper, and U.S. Government securities, all held with credit-worthy financial institutions. Derivative financial instruments are generally executed with major financial institutions that expose us to market and credit risks and which may, at times, be concentrated with certain counterparties. The credit worthiness of the counterparties is subject to continual review. We rely upon netting arrangements with counterparties to reduce credit exposure. Neither we nor our predecessor and the previous owners have experienced any losses from such instruments. Oil and natural gas are sold to a variety of purchasers, including intrastate and interstate pipelines or their marketing affiliates and independent marketing companies. Accounts receivable from joint operations are from a number of oil and natural gas companies, partnerships, individuals, and others who own interests in the properties operated by us, our predecessor, and the previous owners. Generally, operators of crude oil and natural gas properties have the right to offset future revenues against unpaid charges related to operated wells, minimizing the credit risk associated with these receivables. Additionally, management believes that any credit risk imposed by a concentration in the oil and natural gas industry is mitigated by the creditworthiness of its customer base. An allowance for doubtful accounts is recorded after all reasonable efforts have been exhausted to collect or settle the amount owed. Any amounts outstanding longer than the contractual terms are considered past due. Management determined that an allowance for uncollectible accounts was unnecessary at both December 31, 2014 and 2013, respectively. If we were to lose any one of our customers, the loss could temporarily delay the production and the sale of oil and natural gas in the related producing region. If we were to lose any single customer, we believe that a substitute customer to purchase the impacted production volumes could be identified.
Oil and Natural Gas Properties		Oil and Natural Gas Properties Oil and natural gas exploration, development and production activities are accounted for in accordance with the successful efforts method of accounting. Under this method, costs of acquiring properties, costs of drilling successful exploration wells, and development costs are capitalized. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if determination is made that proved reserves have been found. If no proved reserves have been found, the costs of each of the related exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. The costs of such exploratory wells are expensed if a determination of proved reserves has not been made within a twelve-month period after drilling is complete. Exploration costs such as geological, geophysical, and seismic costs are expensed as incurred. As exploration and development work progresses and the reserves on these properties are proven, capitalized costs attributed to the properties are subject to depreciation and depletion. Depletion of capitalized costs is provided using the units-of-production method based on proved oil and gas reserves related to the associated field. Capitalized drilling and development costs of producing oil and natural gas properties are depleted over proved developed reserves and leasehold costs are depleted over total proved reserves. On the sale or retirement of a complete or partial unit of a proved property or pipeline and related facilities, the cost and related accumulated depreciation, depletion, and amortization are removed from the property accounts, and any gain or loss is recognized. There were no material capitalized exploratory drilling costs pending evaluation at December 31, 2014, 2013 and 2012.
Oil and Gas Reserves		Oil and Gas Reserves The estimates of proved oil and natural gas reserves utilized in the preparation of the consolidated and combined financial statements are estimated in accordance with the rules established by the SEC and the Financial Accounting Standards Board (“FASB”). These rules require that reserve estimates be prepared under existing economic and operating conditions using a trailing 12-month average price with no provision for price and cost escalations in future years except by contractual arrangements. Netherland, Sewell & Associates, Inc. (“NSAI”), our independent reserve engineers, was engaged to audit our internally prepared reserves estimates at December 31, 2014. MEMP engaged NSAI and Ryder Scott Company, L.P. to audit MEMP’s internally prepared reserves estimates for all of MEMP’s proved reserves (by volume) at December 31, 2014. Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties, or any combination of the above may be increased or decreased. Increases in recoverable economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates.
Other Property & Equipment		Other Property & Equipment Other property and equipment is stated at historical cost and is comprised primarily of vehicles, furniture, fixtures, office build-out cost and computer hardware and software. Depreciation of other property and equipment is calculated using the straight-line method generally based on estimated useful lives of three to seven years.
Asset Retirement Obligations		Asset Retirement Obligations An asset retirement obligation associated with retiring long-lived assets is recognized as a liability on a discounted basis in the period in which the legal obligation is incurred and becomes determinable, with an equal amount capitalized as an addition to oil and natural gas properties, which is allocated to expense over the useful life of the asset. Generally, oil and gas producing companies incur such a liability upon acquiring or drilling a well. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. Upon settlement of the liability, a gain or loss is recognized in net income (loss) to the extent the actual costs differ from the recorded liability. See Note 6 for further discussion of asset retirement obligations.
Impairments		Impairments Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate the carrying value of such properties may not be recoverable. This may be due to a downward revision of the reserve estimates, less than expected production, drilling results, higher operating and development costs, or lower commodity prices. The estimated undiscounted future cash flows expected in connection with the property are compared to the carrying value of the property to determine if the carrying amount is recoverable. If the carrying value of the property exceeds its estimated undiscounted future cash flows, the carrying amount of the property is reduced to its estimated fair value using Level 3 inputs. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. Impairment expense for the years ended December 31, 2014, 2013, and 2012 was approximately $432.1 million, $6.6 million, $28.9 million, respectively. See Note 4 for further discussion on impairments.
Restricted Investments		Restricted Investments Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with MEMP’s offshore Southern California oil and gas properties. These investments are classified as held-to-maturity, and such investments are stated at amortized cost. Interest earned on these investments is included in interest expense – net in the statement of operations. The amortized cost of such investments is adjusted for amortization of premiums and accretion of discounts to maturity. Such amortization and accretion is displayed as a separate line item in the statement of operations. These restricted investments consist of money market deposit accounts, money market mutual funds, commercial paper, and U.S. Government securities. See Note 7 for additional information.
Debt Issuance Costs		Debt Issuance Costs These costs are recorded on the balance sheet and amortized over the term of the associated debt using the straight-line method which generally approximates the effective yield method. Amortization expense, including write-off of debt issuance costs, for the years ended December 31, 2014, 2013, and 2012 was approximately $7.4 million, $8.3 million and $3.6 million, respectively.
Revenue Recognition		Revenue Recognition Revenue from the sale of oil and natural gas is recognized when title passes, net of royalties due to third parties. Oil and natural gas revenues are recorded using the sales method. Under this method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers, regardless of whether the sales are proportionate to our ownership in the property. An asset or a liability is recognized to the extent there is an imbalance in excess of the proportionate share of the remaining recoverable reserves on the underlying properties. No significant imbalances existed at December 31, 2014 or 2013. The following individual customers each accounted for 10% or more of total reported revenues for the period indicated: Years Ending December 31, 2014 2013 2012 Consolidated & Combined: Energy Transfer Equity, L.P. and subsidiaries 33 % 35 % 13 % MRD Segment: Energy Transfer Equity, L.P. and subsidiaries 85 % 86 % 52 % Sunoco, Inc. (1) n/a n/a 20 % MEMP Segment: Sinclair Oil & Gas Company 11 % n/a n/a Phillips 66 (2) 12 % 14 % 12 % ConocoPhillips n/a n/a 13 % (1) Sunoco, Inc. became a subsidiary of Energy Transfer Equity, L.P. in October 2012. (2) Phillips 66 was a subsidiary of ConocoPhillips through April 30, 2012. Accordingly, any revenues generated from Phillips 66 prior to May 1, 2012 were reported under ConocoPhillips.
Derivative Instruments		Derivative Instruments Commodity derivative financial instruments (e.g., swaps, collars, and put options) are used to reduce the impact of natural gas, NGL and oil price fluctuations. Interest rate swaps are used to manage exposure to interest rate volatility, primarily as a result of variable rate borrowings under the credit facilities. Every derivative instrument is recorded on the balance sheet as either an asset or liability measured at its fair value. Changes in the derivative’s fair value are recognized in earnings as we have not elected hedge accounting for any of our derivative positions.
Capitalized Interest		Capitalized Interest We capitalize interest costs to oil and gas properties on expenditures made in connection with certain projects such as drilling and completion of new oil and natural gas wells and major facility installations. Interest is capitalized only for the period that such activities are in progress. Interest is capitalized using a weighted average interest rate based on our outstanding borrowings. These capitalized costs are included within intangible drilling costs and amortized using the units of production method. For the year ended December 31, 2014, we capitalized $7.3 million of interest. We did not capitalize any interest in 2013 or 2012.
Income Tax	Income Tax Our predecessor was organized as a pass-through entity for federal income tax purposes and was not subject to federal income taxes prior to our initial public offering in June 2014; however, certain of its consolidating subsidiaries were subject to federal and certain state income taxes. We are organized as a taxable C corporation and subject to federal and certain state income taxes. We are also subject to the Texas margin tax and certain aspects of the tax make it similar to an income tax. The net income (loss) attributable to noncontrolling interest is related to MEMP, which is a pass-through entity for federal income tax purposes. As discussed in Note 12, the compensation expense associated with the incentive units of MRD Holdco creates a nondeductible permanent difference for income tax purposes. We reported no liability for unrecognized tax benefits as of March 31, 2015 and expect no significant change to the unrecognized tax benefits in the next twelve months. Our effective tax rate is negative 67.5% for the three months ended March 31, 2015, which differs from the statutory federal income tax rate of 35% primarily due to the following recurring items: — 84.0% reduction to the effective tax rate related to pass-through entities; — 10.6% reduction to the effective tax rate related to non-deductible incentive compensation; and — 8.1% reduction to the effective tax rate related to state income tax provision, net of federal benefit. We had a net noncurrent deferred income tax liability of $95.0 million at December 31, 2014, of which $29.2 million was attributable to certain oil and gas properties in East Texas that MEMP acquired from us in February 2015 as noted above. A deferred income tax benefit of $1.2 million associated with these oil and gas properties was recorded during February 2015. As such, a net deferred income tax liability of $28.0 million has been reduced through additional paid capital in our equity statement.	Income Tax Prior to our initial public offering, MRD LLC was organized as a pass-through entity for federal income tax purposes and was not subject to federal income taxes; however, certain of its consolidating subsidiaries were taxed as corporations and subject to federal income taxes. We are organized as a taxable C corporation and subject to federal and certain state income taxes. We are also subject to the Texas margin tax and certain aspects of the tax make it similar to an income tax. The Company accounts for income taxes using the asset and liability method wherein deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which temporary differences are expected to be recovered or settled. Deferred tax assets are reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of the deferred tax assets will not be realized. We must recognize the tax effects of any uncertain tax positions we may adopt, if the position taken by us is more likely than not sustainable based on its technical merits. If a tax position meets such criteria, the tax effect that would be recognized by us would be the largest amount of benefit with more than 50% chance of being realized. The evaluation of uncertain tax positions is a two-step process. The first step is a recognition process to determine whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. In evaluating whether a tax position has met the more likely than not recognition threshold, it is presumed that the position will be examined by the appropriate taxing authority with full knowledge of all relevant information. The second step is a measurement process whereby a tax position that meets the more likely than not recognition threshold is calculated to determine the amount of benefit/expense to recognize in the consolidated financial statements. The tax position is measured at the largest amount of benefit/expense that is more likely than not of being realized upon ultimate settlement. The Company has no liability for unrecognized tax benefits as of December 31, 2014 and 2013. Accordingly, there is no amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate and there is no amount of interest or penalties currently recognized in the consolidated statements of operations or consolidated balance sheets as of December 31, 2014. In addition, the Company does not believe that there are any positions for which it is reasonably possible that the total amount of unrecognized tax benefits will significantly increase or decrease within the next twelve months. In June 2014, we recorded a deferred tax liability of approximately $43.3 million in stockholders’ equity in connection with our initial public offering and the related restructuring transactions. The tax bases of our assets and liabilities changed as a result our initial public offering and the related restructuring transactions, which represented a transaction among stockholders. Tax audits may be ongoing at any point in time. Tax liabilities are recorded based on estimates of additional taxes which may be due upon the conclusion of these audits. Estimates of these tax liabilities are made based upon prior experience and are updated for changes in facts and circumstances. However, due to the uncertain and complex application of tax regulations, it is possible that the ultimate resolution of audits may result in liabilities which could be materially different from these estimates.
Earnings Per Share		Earnings Per Share Basic earnings per share (“EPS”) is computed using the two-class method based on net income (loss) available to common stockholders and the average number of shares of common stock outstanding for the period. Diluted EPS includes the impact of the Company’s restricted shares of common stock as they are participating securities. The Company determines the more dilutive of either the two-class method or the treasury stock method for diluted EPS. See Note 10 for additional information.
Incentive Based Compensation Arrangements		Incentive Based Compensation Arrangements The fair value of equity-classified awards (e.g., restricted stock awards) is amortized to earnings over the requisite service or vesting period. Compensation expense for liability-classified awards are recognized over the requisite service or vesting period of an award based on the fair value of the award re-measured at each reporting period. Generally, no compensation expense is recognized for equity instruments that do not vest. Prior to the restructuring transactions, the governing documents of MRD LLC and certain of its subsidiaries provided for the issuance of incentive units. The incentive units were subject to performance conditions that affected their vesting. Compensation cost was recognized only if the performance condition was probable of being satisfied at each reporting date. In connection with the restructuring transactions, the MRD LLC incentive units were exchanged for substantially identical units in MRD Holdco, and such incentive units entitle holders thereof to portions of future distributions by MRD Holdco. While any such distributions made by MRD Holdco will not involve any cash payment by us, we will be required to recognize non-cash compensation expense, which may be material, in future periods. The compensation expense recognized by us related to the incentive units will be offset by a deemed capital contribution from MRD Holdco as they are remeasured at the end of each reporting period. See Notes 11 and 12 for further information.
Accrued Liabilities	Accrued liabilities Current accrued liabilities consisted of the following at the dates indicated (in thousands): March 31, December 31, 2015 2014 Accrued capital expenditures $ 84,939 $ 80,350 Accrued lease operating expense 17,996 16,403 Accrued general and administrative expenses 10,098 8,516 Accrued ad valorem and production taxes 10,390 8,870 Accrued interest payable 36,815 24,797 Accrued environmental 1,309 2,092 Accrued current deferred income taxes 51,937 51,929 Other miscellaneous, including operator advances 4,185 6,043 $ 217,669 $ 199,000	Accrued Liabilities Current accrued liabilities consisted of the following at the dates indicated (in thousands): December 31, 2014 2013 Accrued capital expenditures $ 80,350 $ 48,579 Accrued lease operating expense 16,403 13,240 Accrued general and administrative expenses 8,516 14,485 Accrued ad valorem and production taxes 8,870 3,541 Accrued interest payable 24,797 11,934 Accrued environmental 2,092 577 Accrued current deferred income taxes 51,929 382 Other miscellaneous, including operator advances 6,043 5,392 $ 199,000 $ 98,130
Supplemental Cash Flow Information		Supplemental Cash Flow Information Supplemental cash flow for the periods presented (in thousands): For Year Ended December 31, 2014 2013 2012 Supplemental cash flows: Cash paid for interest, net of amounts capitalized $ 130,732 $ 61,140 $ 23,525 Income tax paid 838 168 22 Noncash investing and financing activities: Change in capital expenditures in payables and accrued liabilities 31,771 41,017 17,158 Assumptions of asset retirement obligations related to properties acquired or drilled 5,420 4,227 7,962 Contribution of oil and gas properties from NGP affiliate — — 6,893 Accrued distribution to NGP affiliates related to Cinco Group acquisitions — 4,352 — Contribution related to sale of assets to NGP affiliate - restricted cash — — 2,013 Accrued equity offering costs — — 171 Distributions to noncontrolling interests — — 47 Repurchase of equity under repurchase program 3,425 — — Accounts receivable related to acquisitions 9,569 — —
New Accounting Pronouncements	New Accounting Pronouncements Presentation of Debt Issuance Cost. In April 2015, the Financial Accounting Standards Board ("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 does not expect the impact of adopting this guidance to be material to the Company's financial statements and related disclosures. Amendments to Consolidation Analysis . In February 2015, the FASB issued an accounting standards update to improve consolidation guidance for certain types of legal entities. The guidance modifies the evaluation of whether limited partnerships and similar legal entities are variable interest entities (“VIEs”) or voting interest entities, eliminates the presumption that a general partner should consolidate a limited partnership, affects the consolidation analysis of reporting entities that are involved with VIEs, particularly those that have fee arrangements and related party relationships, and provides a scope exception from consolidation guidance for certain money market funds. These provisions are effective for annual reporting periods beginning after December 15, 2015, and interim periods within those annual periods, with early adoption permitted. These provisions may also be adopted using either a full retrospective or a modified retrospective approach. Although the Company is currently assessing the impact 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 will either: (i) continue to consolidate MEMP and become subject to the VIE primary beneficiary disclosure requirements or (ii) no longer consolidate MEMP under the revised VIE consolidation requirements and provide disclosures that apply to variable interest holders that do not consolidate a VIE. The deconsolidation of MEMP would have a material impact on our consolidated financial statements and related disclosures. Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Company’s financial position, results of operations and cash flows.	New Accounting Pronouncements Revenue from Contracts with Customers. In May 2014, the FASB issued a comprehensive new revenue recognition standard for contracts with customers that will supersede most current revenue recognition guidance, including industry-specific guidance. The core principle of this standard is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, the standard provides a five-step analysis of transactions to determine when and how revenue is recognized. Other major provisions include the capitalization and amortization of certain contract costs, ensuring the time value of money is considered in the transaction price, and allowing estimates of variable consideration to be recognized before contingencies are resolved in certain circumstances. This guidance also requires enhanced disclosures regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from an entity’s contracts with customers. The new standard is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016. Early application is prohibited. The standard permits the use of either the retrospective or cumulative effect transition method. This guidance will be applicable to the Company beginning on January 1, 2017. The Company is currently assessing the impact that adopting this new accounting guidance will have on its consolidated financial statements and footnote disclosures. Reporting Discontinued Operations. In April 2014, the FASB issued an accounting standards update that changes the criteria for determining when disposals can be presented as discontinued operations and modifies discontinued operations disclosures. The new guidance now defines a “discontinued operation” as (i) a disposal of a component or group of components that is disposed of or is classified as held for sale and “represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results” or (ii) an acquired business or nonprofit activity that is classified as held for sale on the date of acquisition. We will adopt this guidance and apply the disclosure requirements prospectively beginning on January 1, 2015. Amendments to Consolidation Analysis . In February 2015, the FASB issued an accounting standards update to improve consolidation guidance for certain types of legal entities. The guidance modifies the evaluation of whether limited partnerships and similar legal entities are variable interest entities (“VIEs”) or voting interest entities, eliminates the presumption that a general partner should consolidate a limited partnership, affects the consolidation analysis of reporting entities that are involved with VIEs, particularly those that have fee arrangements and related party relationships, and provides a scope exception from consolidation guidance for certain money market funds. These provisions are effective for annual reporting periods beginning after December 15, 2015, and interim periods within those annual periods, with early adoption permitted. These provisions may also be adopted using either a full retrospective or a modified retrospective approach. Although the Company is currently assessing the impact of adopting this new accounting guidance will have on its consolidated financial statements and footnote disclosures, we expect that MEMP will become a VIE. We will either: (i) continue to consolidate MEMP and become subject to the VIE primary beneficiary disclosure requirements or (ii) no longer consolidate MEMP under the revised VIE consolidation requirements and provide disclosures that apply to variable interest holders that do not consolidate a VIE. The deconsolidation of MEMP would have a material impact on our consolidated financial statements and related disclosures. Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Company’s financial position, results of operations and cash flows.

Summary of Significant Accoun30

Summary of Significant Accounting Policies (Tables)	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Accounting Policies [Abstract]
Individual Customers Each Accounted for 10% or More of Total Reported Revenues		The following individual customers each accounted for 10% or more of total reported revenues for the period indicated: Years Ending December 31, 2014 2013 2012 Consolidated & Combined: Energy Transfer Equity, L.P. and subsidiaries 33 % 35 % 13 % MRD Segment: Energy Transfer Equity, L.P. and subsidiaries 85 % 86 % 52 % Sunoco, Inc. (1) n/a n/a 20 % MEMP Segment: Sinclair Oil & Gas Company 11 % n/a n/a Phillips 66 (2) 12 % 14 % 12 % ConocoPhillips n/a n/a 13 % (1) Sunoco, Inc. became a subsidiary of Energy Transfer Equity, L.P. in October 2012. (2) Phillips 66 was a subsidiary of ConocoPhillips through April 30, 2012. Accordingly, any revenues generated from Phillips 66 prior to May 1, 2012 were reported under ConocoPhillips.
Schedule of Accrued Liabilities	Current accrued liabilities consisted of the following at the dates indicated (in thousands): March 31, December 31, 2015 2014 Accrued capital expenditures $ 84,939 $ 80,350 Accrued lease operating expense 17,996 16,403 Accrued general and administrative expenses 10,098 8,516 Accrued ad valorem and production taxes 10,390 8,870 Accrued interest payable 36,815 24,797 Accrued environmental 1,309 2,092 Accrued current deferred income taxes 51,937 51,929 Other miscellaneous, including operator advances 4,185 6,043 $ 217,669 $ 199,000	Current accrued liabilities consisted of the following at the dates indicated (in thousands): December 31, 2014 2013 Accrued capital expenditures $ 80,350 $ 48,579 Accrued lease operating expense 16,403 13,240 Accrued general and administrative expenses 8,516 14,485 Accrued ad valorem and production taxes 8,870 3,541 Accrued interest payable 24,797 11,934 Accrued environmental 2,092 577 Accrued current deferred income taxes 51,929 382 Other miscellaneous, including operator advances 6,043 5,392 $ 199,000 $ 98,130
Schedule of Supplemental Cash flow		Supplemental cash flow for the periods presented (in thousands): For Year Ended December 31, 2014 2013 2012 Supplemental cash flows: Cash paid for interest, net of amounts capitalized $ 130,732 $ 61,140 $ 23,525 Income tax paid 838 168 22 Noncash investing and financing activities: Change in capital expenditures in payables and accrued liabilities 31,771 41,017 17,158 Assumptions of asset retirement obligations related to properties acquired or drilled 5,420 4,227 7,962 Contribution of oil and gas properties from NGP affiliate — — 6,893 Accrued distribution to NGP affiliates related to Cinco Group acquisitions — 4,352 — Contribution related to sale of assets to NGP affiliate - restricted cash — — 2,013 Accrued equity offering costs — — 171 Distributions to noncontrolling interests — — 47 Repurchase of equity under repurchase program 3,425 — — Accounts receivable related to acquisitions 9,569 — —

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Acquisition-Related Costs	Acquisition-related costs are included in general and administrative expenses in the accompanying statements of operations for the periods indicated below (in thousands): For the Three Months Ended March 31, 2015 2014 $ 2,580 $ 2,462	Acquisition-related costs for both related party and third party transactions are included in general and administrative expenses in the accompanying statements of operations for the periods indicated below (in thousands): For the Year Ended December 31, 2014 2013 2012 $ 6,668 $ 8,313 $ 4,538
Unaudited Pro Forma Results of Operations	In July 2014, MEMP closed a third-party acquisition that was deemed significant to our consolidated financial statements. The following unaudited pro forma combined results of operations are provided for the three months ended March 31, 2014 as though this third-party acquisition had been completed on January 1, 2013. The unaudited pro forma financial information was derived from the historical combined statements of operations of our predecessor and 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 Three Months Ended March 31, 2014 (In thousands) Revenues $ 252,019 Net income (loss) (14,817 )	The following unaudited pro forma combined results of operations are provided for the year ended December 31, 2014 and 2013 as though the Wyoming Acquisition had been completed on January 1, 2013. The unaudited pro forma financial information was derived from the historical combined statements of operations of the Company and the previous owners and adjusted to include: (i) the revenues and direct operating expenses associated with oil and gas properties acquired, (ii) depletion expense applied to the adjusted basis of the properties acquired and (iii) interest expense on additional borrowings necessary to finance the acquisition. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of expected future results of operations. For the Year Ended December 31, 2014 2013 (In thousands, except per share amounts) Revenues $ 990,544 $ 761,443 Net income (loss) (602,044 ) 257,839 Basic earnings per share $ (4.08 ) $ — Diluted earnings per share $ (4.08 ) $ —
Eagle Ford and Wyoming Acquisition [Member]
Summary of Fair Value Assessment of Assets Acquired and Liabilities Assumed		The following table summarizes the fair value assessment of the assets acquired and liabilities assumed as of the acquisition dates (in thousands): MRD MEMP MEMP Louisiana Eagle Ford Wyoming Acquisition Acquisition Acquisition Oil and gas properties $ 72,141 $ 168,606 $ 930,168 Asset retirement obligations (271 ) (285 ) (3,980 ) Revenue Payable — — (375 ) Accrued liabilities — (250 ) (19,693 ) Total identifiable net assets $ 71,870 $ 168,071 $ 906,120
2013 Acquisitions [Member]
Summary of Fair Value Assessment of Assets Acquired and Liabilities Assumed		Louisiana East Texas Rockies Acquisition Acquisition Acquisition Oil and gas properties $ 68,887 $ 9,974 $ 20,744 Asset retirement obligation (1,789 ) (78 ) (1,163 ) Accrued liabilities - - (118 ) Total identifiable net assets $ 67,098 $ 9,896 $ 19,463
2012 Acquisitions [Member]
Summary of Fair Value Assessment of Assets Acquired and Liabilities Assumed		The following table summarizes the fair value of the assets acquired and liabilities assumed as of each acquisition date (in thousands). Undisclosed Seller Goodrich Menemsha Other Acquisition Acquisition Acquisition Acquisitions Oil and gas properties $ 115,633 $ 91,187 $ 75,114 $ 77,764 Prepaid expenses and other current assets — 425 — — Revenues payable (1,602 ) (875 ) — — Asset retirement obligation (1,592 ) (161 ) (408 ) (4,558 ) Accrued liabilities (297 ) (153 ) — — Total identifiable net assets $ 112,142 $ 90,423 $ 74,706 $ 73,206
Unaudited Pro Forma Results of Operations		The following unaudited pro forma combined results of operations are provided for the year ended December 31, 2012 (in thousands) as though the Undisclosed Seller Acquisition, Goodrich Acquisition, and Menemsha Acquisition had been completed on January 1, 2011. The unaudited pro forma financial information was derived from our historical combined statements of operations and adjusted to include: (i) the revenues and direct operating expenses associated with oil and gas properties acquired, (ii) depletion expense applied to the adjusted basis of the properties acquired and (iii) interest expense on additional borrowings necessary to finance the acquisitions. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transactions occurred on the basis assumed above, nor is such information indicative of expected future results of operations. Revenue $ 431,060 Net income 40,940

Fair Value Measurements of Fi32

Fair Value Measurements of Financial Instruments (Tables)	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Assets and Liabilities Measured at Fair Value on Recurring Basis	The following table presents the gross derivative assets and liabilities that are measured at fair value on a recurring basis at March 31, 2015 and December 31, 2014 for each of the fair value hierarchy levels: Fair Value Measurements at March 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 $ — $ 1,022,706 $ — $ 1,022,706 Interest rate derivatives — 10 — 10 Total assets $ — $ 1,022,716 $ — $ 1,022,716 Liabilities: Commodity derivatives $ — $ 87,809 $ — $ 87,809 Interest rate derivatives — 3,549 — 3,549 Total liabilities $ — $ 91,358 $ — $ 91,358 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	The following table presents the derivative assets and liabilities that are measured at fair value on a recurring basis at December 31, 2014 and December 31, 2013 for each of the fair value hierarchy levels: Fair Value Measurements at December 31, 2014 Using Quoted Prices in Significant Other Significant Active Observable Unobservable Market Inputs Inputs (Level 1) (Level 2) (Level 3) Fair Value (In thousands) Assets: Commodity derivatives $ — $ 845,759 $ — $ 845,759 Interest rate derivatives — 1,305 — 1,305 Total assets $ — $ 847,064 $ — $ 847,064 Liabilities: Commodity derivatives $ — $ 71,639 $ — $ 71,639 Interest rate derivatives — 3,289 — 3,289 Total liabilities $ — $ 74,928 $ — $ 74,928 Fair Value Measurements at December 31, 2013 Using Quoted Prices in Significant Other Significant Active Observable Unobservable Market Inputs Inputs (Level 1) (Level 2) (Level 3) Fair Value (In thousands) Assets: Commodity derivatives $ — $ 105,054 $ — $ 105,054 Interest rate derivatives — 884 — 884 Total assets $ — $ 105,938 $ — $ 105,938 Liabilities: Commodity derivatives $ — $ 58,234 $ — $ 58,234 Interest rate derivatives — 5,590 — 5,590 Total liabilities $ — $ 63,824 $ — $ 63,824

Risk Management and Derivativ33

Risk Management and Derivative Instruments (Tables)	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Schedule of Open Commodity Positions	At March 31, 2015, the MRD Segment had the following open commodity positions: Remaining 2015 2016 2017 2018 Natural Gas Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (MMBtu) 3,600,000 2,570,000 1,770,000 4,600,000 Weighted-average fixed price $ 4.15 $ 4.09 $ 4.24 $ 4.06 Collar contracts: Average Monthly Volume (MMBtu) 130,000 1,100,000 1,050,000 — Weighted-average floor price $ 4.00 $ 4.00 $ 4.00 $ — Weighted-average ceiling price $ 4.64 $ 4.71 $ 5.06 $ — Purchased put option contracts: Average Monthly Volume (MMBtu) 3,366,667 4,100,000 3,450,000 2,850,000 Weighted-average fixed price $ 3.75 $ 3.75 $ 3.75 $ 3.75 Weighted-average deferred premium paid $ (0.33 ) $ (0.36 ) $ (0.35 ) $ (0.35 ) Written call option contracts (1): Average Monthly Volume (MMBtu) 2,625,000 — — — Weighted-average sold strike price $ 3.75 $ — $ — $ — Weighted-average deferred premium received $ 0.08 $ — $ — $ — TGT Z1 basis swaps: Average Monthly Volume (MMBtu) 3,480,000 1,120,000 200,000 — Spread - Henry Hub $ (0.10 ) $ (0.10 ) $ (0.08 ) $ — Crude Oil Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 45,000 8,500 28,000 31,625 Weighted-average fixed price $ 91.67 $ 84.80 $ 84.70 $ 84.50 Collar contracts: Average Monthly Volume (Bbls) 2,000 27,000 — — Weighted-average floor price $ 85.00 $ 80.00 $ — $ — Weighted-average ceiling price $ 101.35 $ 99.70 $ — $ — Purchased put option contracts: Average Monthly Volume (Bbls) 30,333 — — — Weighted-average fixed price $ 85.00 $ — $ — $ — Weighted-average deferred premium paid $ (3.80 ) $ — $ — $ — Written call option contracts (1): Average Monthly Volume (Bbls) 22,750 — — — Weighted-average sold strike price $ 85.00 $ — $ — $ — Weighted-average deferred premium received $ 0.48 $ — $ — $ — NGL Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 155,000 185,658 — — Weighted-average fixed price $ 41.58 $ 34.06 $ — $ — (1) These transactions were entered into for the purpose of creating a ceiling on our put options, which effectively converted the applicable puts into swaps. At March 31, 2015, the MEMP Segment had the following open commodity positions: Remaining 2015 2016 2017 2018 2019 Natural Gas Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (MMBtu) 3,061,181 3,292,442 3,050,067 2,760,000 2,514,583 Weighted-average fixed price $ 4.16 $ 4.22 $ 4.14 $ 4.28 $ 4.43 Collar contracts: Average Monthly Volume (MMBtu) 350,000 — — — — Weighted-average floor price $ 4.62 $ — $ — $ — $ — Weighted-average ceiling price $ 5.80 $ — $ — $ — $ — Call spreads (1): Average Monthly Volume (MMBtu) 80,000 — — — — Weighted-average sold strike price $ 5.25 $ — $ — $ — $ — Weighted-average bought strike price $ 6.75 $ — $ — $ — $ — Basis swaps: Average Monthly Volume (MMBtu) 3,390,000 3,108,333 415,000 115,000 — Spread $ (0.12 ) $ (0.05 ) $ — $ 0.15 $ — Crude Oil Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 273,864 279,813 301,600 312,000 160,000 Weighted-average fixed price $ 91.34 $ 86.87 $ 84.70 $ 83.74 $ 85.52 Collar contracts: Average Monthly Volume (Bbls) 5,000 — — — — Weighted-average floor price $ 80.00 $ — $ — $ — $ — Weighted-average ceiling price $ 94.00 $ — $ — $ — $ — Basis swaps: Average Monthly Volume (Bbls) 97,333 95,000 — — — Spread $ (7.07 ) $ (9.56 ) $ — $ — $ — NGL Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 211,867 158,600 43,300 — — Weighted-average fixed price $ 42.30 $ 40.36 $ 37.55 $ — $ — (1) These transactions were entered into for the purpose of eliminating the ceiling portion of certain collar arrangements, which effectively converted the applicable collars into swaps. The MEMP Segment basis swaps included in the table above is presented on a disaggregated basis below: Remaining 2015 2016 2017 2018 Natural Gas Derivative Contracts: NGPL TexOk basis swaps: Average Monthly Volume (MMBtu) 2,730,000 2,703,333 300,000 — Spread - Henry Hub $ (0.12 ) $ (0.07 ) $ (0.05 ) $ — HSC basis swaps: Average Monthly Volume (MMBtu) 150,000 135,000 115,000 115,000 Spread - Henry Hub $ (0.08 ) $ 0.07 $ 0.14 $ 0.15 CIG basis swaps: Average Monthly Volume (MMBtu) 210,000 — — — Spread - Henry Hub $ (0.25 ) $ — $ — $ — TETCO STX basis swaps: Average Monthly Volume (MMBtu) 300,000 270,000 — — Spread - Henry Hub $ (0.09 ) $ 0.06 $ — $ — Crude Oil Derivative Contracts: Midway-Sunset basis swaps: Average Monthly Volume (Bbls) 57,333 55,000 — — Spread - Brent $ (9.73 ) $ (13.35 ) $ — $ — Midland basis swaps: Average Monthly Volume (Bbls) 40,000 40,000 — — Spread - WTI $ (3.25 ) $ (4.34 ) $ — $ —	At December 31, 2014, the MRD Segment had the following open commodity positions: 2015 2016 2017 2018 Natural Gas Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (MMBtu) 3,700,000 2,570,000 1,770,000 2,900,000 Weighted-average fixed price $ 4.15 $ 4.09 $ 4.24 $ 4.27 Collar contracts: Average Monthly Volume (MMBtu) 130,000 1,100,000 1,050,000 — Weighted-average floor price $ 4.00 $ 4.00 $ 4.00 $ — Weighted-average ceiling price $ 4.64 $ 4.71 $ 5.06 $ — Natural gas put option contracts: Average Monthly Volume (MMBtu) 3,000,000 4,100,000 3,450,000 2,850,000 Weighted-average fixed price $ 3.75 $ 3.75 $ 3.75 $ 3.75 Weighted-average deferred premium $ (0.33 ) $ (0.36 ) $ (0.35 ) $ (0.35 ) TGT Z1 basis swaps: Average Monthly Volume (MMBtu) 1,730,000 220,000 200,000 — Spread - Henry Hub $ (0.09 ) $ (0.08 ) $ (0.08 ) $ — Crude Oil Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 46,500 8,500 28,000 31,625 Weighted-average fixed price $ 91.67 $ 84.80 $ 84.70 $ 84.50 Collar contracts: Average Monthly Volume (Bbls) 2,000 27,000 — — Weighted-average floor price $ 85.00 $ 80.00 $ — $ — Weighted-average ceiling price $ 101.35 $ 99.70 $ — $ — Put option contracts: Average Monthly Volume (Bbls) 26,000 — — — Weighted-average fixed price $ 85.00 $ — $ — $ — Weighted-average deferred premium $ (3.80 ) $ — $ — $ — NGL Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 151,000 185,658 — — Weighted-average fixed price $ 41.61 $ 34.06 $ — $ — At December 31, 2014, the MEMP Segment had the following open commodity positions: 2015 2016 2017 2018 2019 Natural Gas Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (MMBtu) 2,605,278 2,692,442 2,450,067 2,160,000 1,914,583 Weighted-average fixed price $ 4.28 $ 4.40 $ 4.31 $ 4.51 $ 4.75 Collar contracts: Average Monthly Volume (MMBtu) 350,000 — — — — Weighted-average floor price $ 4.62 $ — $ — $ — $ — Weighted-average ceiling price $ 5.80 $ — $ — $ — $ — Call spreads (1): Average Monthly Volume (MMBtu) 80,000 — — — — Weighted-average sold strike price $ 5.25 $ — $ — $ — $ — Weighted-average bought strike price $ 6.75 $ — $ — $ — $ — Basis swaps: Average Monthly Volume (MMBtu) 2,940,000 2,508,333 415,000 115,000 — Spread $ (0.12 ) $ (0.04 ) $ 0.00 $ 0.15 $ — Crude Oil Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 314,281 332,813 326,600 312,000 160,000 Weighted-average fixed price $ 90.96 $ 85.83 $ 84.38 $ 83.74 $ 85.52 Collar contracts: Average Monthly Volume (Bbls) 5,000 — — — — Weighted-average floor price $ 80.00 $ — $ — $ — $ — Weighted-average ceiling price $ 94.00 $ — $ — $ — $ — Basis swaps: Average Monthly Volume (Bbls) 97,500 95,000 — — — Spread $ (7.07 ) $ (9.56 ) $ — $ — $ — NGL Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 149,200 84,600 — — — Weighted-average fixed price $ 43.02 $ 41.49 $ — $ — $ — (1 ) These transactions were entered into for the purpose of eliminating the ceiling portion of certain collar arrangements, which effectively converted the applicable collars into swaps. The MEMP Segment basis swaps included in the table above is presented on a disaggregated basis below: 2015 2016 2017 2018 Natural Gas Derivative Contracts: NGPL TexOk basis swaps: Average Monthly Volume (MMBtu) 2,280,000 2,103,333 300,000 — Spread - Henry Hub $ (0.11 ) $ (0.06 ) $ (0.05 ) $ — HSC basis swaps: Average Monthly Volume (MMBtu) 150,000 135,000 115,000 115,000 Spread - Henry Hub $ (0.08 ) $ 0.07 $ 0.14 $ 0.15 CIG basis swaps: Average Monthly Volume (MMBtu) 210,000 — — — Spread - Henry Hub $ (0.25 ) $ — $ — $ — TETCO STX basis swaps: Average Monthly Volume (MMBtu) 300,000 270,000 — — Spread - Henry Hub $ (0.09 ) $ 0.06 $ — $ — Crude Oil Derivative Contracts: Midway-Sunset basis swaps: Average Monthly Volume (Bbls) 57,500 55,000 — — Spread - Brent $ (9.73 ) $ (13.35 ) $ — $ — Midland basis swaps: Average Monthly Volume (Bbls) 40,000 40,000 — — Spread - WTI $ (3.25 ) $ (4.34 ) $ — $ —
Schedule of Entity's Interest Rate Swap Open Positions	At March 31, 2015, we had the following interest rate swap open positions: Remaining Credit Facility 2015 2016 2017 2018 MEMP: Average Monthly Notional (in thousands) $ 386,111 $ 400,000 $ 400,000 $ 100,000 Weighted-average fixed rate 1.247 % 0.943 % 1.612 % 1.946 % Floating rate 1 Month LIBOR 1 Month LIBOR 1 Month LIBOR 1 Month LIBOR	At December 31, 2014, we had the following interest rate swap open positions: Credit Facility 2015 2016 2017 MEMP: Average Monthly Notional (in thousands) $ 314,167 $ 250,000 $ 250,000 Weighted-average fixed rate 1.349 % 1.029 % 1.620 % 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 March 31, 2015 and December 31, 2014. There was no cash collateral received or pledged associated with our derivative instruments since most of the counterparties, or certain of their affiliates, to our derivative contracts are lenders under our collective credit agreements. Asset Derivatives Liability Derivatives March 31, December 31, March 31, December 31, Type Balance Sheet Location 2015 2014 2015 2014 (In thousands) Commodity contracts Short-term derivative instruments $ 398,708 $ 378,908 $ 41,954 $ 38,852 Interest rate swaps Short-term derivative instruments — — 2,994 3,289 Gross fair value 398,708 378,908 44,948 42,141 Netting arrangements Short-term derivative instruments (41,648 ) (38,852 ) (41,648 ) (38,852 ) Net recorded fair value Short-term derivative instruments $ 357,060 $ 340,056 $ 3,300 $ 3,289 Commodity contracts Long-term derivative instruments $ 623,998 $ 466,851 $ 45,855 $ 32,787 Interest rate swaps Long-term derivative instruments 10 1,305 555 — Gross fair value 624,008 468,156 46,410 32,787 Netting arrangements Long-term derivative instruments (45,855 ) (32,787 ) (45,855 ) (32,787 ) Net recorded fair value Long-term derivative instruments $ 578,153 $ 435,369 $ 555 $ —	The following table summarizes both: (i) the gross fair value of derivative instruments by the appropriate balance sheet classification even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the balance sheet and (ii) the net recorded fair value as reflected on the balance sheet at December 31, 2014 and 2013. There was no cash collateral received or pledged associated with our derivative instruments since most of the counterparties, or certain affiliates, to our derivative contracts are lenders under our collective credit agreements. Asset Derivatives Liability Derivatives Type Balance Sheet Location 2014 2013 2014 2013 (In thousands) Commodity contracts Short-term derivative instruments $ 378,908 $ 21,759 $ 38,852 $ 19,739 Interest rate swaps Short-term derivative instruments — 845 3,289 3,287 Gross fair value 378,908 22,604 42,141 23,026 Netting arrangements Short-term derivative instruments (38,852 ) (13,315 ) (38,852 ) (13,315 ) Net recorded fair value Short-term derivative instruments $ 340,056 $ 9,289 $ 3,289 $ 9,711 Commodity contracts Long-term derivative instruments $ 466,851 $ 83,295 $ 32,787 $ 38,495 Interest rate swaps Long-term derivative instruments 1,305 39 — 2,303 Gross fair value 468,156 83,334 32,787 40,798 Netting arrangements Long-term derivative instruments (32,787 ) (34,718 ) (32,787 ) (34,718 ) Net recorded fair value Long-term derivative instruments $ 435,369 $ 48,616 $ — $ 6,080
Schedule of Gains and Losses Related to Derivative Instruments	The following table details the gains and losses related to derivative instruments for the three months ended March 31, 2015 and 2014 (in thousands): For the Three Months Ended Statements of March 31, Operations Location 2015 2014 Commodity derivative contracts (Gain) loss on commodity derivatives $ (253,649 ) $ 59,482 Interest rate derivatives Interest expense, net 2,441 511	The following table details the gains and losses related to derivative instruments for the years ending December 31, 2014, 2013, and 2012: Statements of For the Years Ended December 31, Operations Location 2014 2013 2012 (In thousands) Commodity derivative contracts (Gain) loss on commodity derivatives $ (749,988 ) $ (29,294 ) $ (34,905 ) Interest rate derivatives Interest expense, net 145 (239 ) 5,582

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Summary of Changes in Asset Retirement Obligations	The following table presents the changes in the asset retirement obligations for the three months ended March 31, 2015 (in thousands): Asset retirement obligations at beginning of period $ 122,531 Liabilities added from acquisitions or drilling 39 Revisions 149 Accretion expense 1,757 Asset retirement obligations at end of period $ 124,476	The following table presents the changes in the asset retirement obligations for the years ended December 31, 2014, 2013 and 2012: 2014 2013 2012 (In thousands) Asset retirement obligations at beginning of period $ 111,769 $ 102,380 $ 90,699 Liabilities added from acquisitions or drilling 5,420 4,227 7,962 Liabilities removed upon sale of wells (669 ) (1,765 ) (1,931 ) Liabilities removed upon plugging and abandoning (588 ) (170 ) (119 ) Revisions 293 1,516 760 Accretion expense 6,306 5,581 5,009 Asset retirement obligations at end of period 122,531 111,769 102,380 Less: Current portion — 90 390 Asset retirement obligations— long-term portion $ 122,531 $ 111,679 $ 101,990

Restricted Investments (Tables)

Restricted Investments (Tables)	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Schedule Of Investments [Abstract]
Restricted Investment Balance	The components of the restricted investment balance consisted of the following at the dates indicated: March 31, December 31, 2015 2014 (In thousands) BOEM platform abandonment (See Note 15) $ 71,263 $ 69,954 BOEM lease bonds 794 794 SPBPC Collateral: Contractual pipeline and surface facilities abandonment 2,818 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 $ 78,787 $ 77,361	The components of the restricted investment balance are as follows at December 31, 2014 and 2013: 2014 2013 (In thousands) BOEM platform abandonment (See Note 16) $ 69,954 $ 66,373 BOEM lease bonds 794 794 SPBPC Collateral: Contractual pipeline and surface facilities abandonment 2,701 2,306 California State Lands Commission pipeline right-of-way bond 3,005 3,005 City of Long Beach pipeline facility permit 500 500 Federal pipeline right-of-way bond 307 307 Port of Long Beach pipeline license 100 100 Restricted investments $ 77,361 $ 73,385

Long Term Debt (Tables)

Long Term Debt (Tables)	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Debt Disclosure [Abstract]
Consolidated Debt Obligations	The following table presents our consolidated debt obligations at the dates indicated: March 31, December 31, 2015 2014 (In thousands) MRD Segment: MRD $2.0 billion revolving credit facility, variable-rate, due June 2019 $ 144,000 $ 183,000 5.875% senior unsecured notes, due July 2022 (1) 600,000 600,000 Subtotal 744,000 783,000 MEMP Segment: MEMP $2.0 billion revolving credit facility, variable-rate, due March 2018 573,000 412,000 7.625% senior unsecured notes, due May 2021 ("2021 Senior Notes") (2) 700,000 700,000 6.875% senior unsecured notes, due August 2022 ("2022 Senior Notes") (3) 496,990 500,000 Unamortized discounts (15,945 ) (16,587 ) Subtotal 1,754,045 1,595,413 Total long-term debt $ 2,498,045 $ 2,378,413 (1) The estimated fair value of this fixed-rate debt was $564.0 million and $534.0 million at March 31, 2015 and December 31, 2014, respectively. 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 $640.5 million and $563.5 million at March 31, 2015 and December 31, 2014, respectively. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. (3) The estimated fair value of this fixed-rate debt was $437.4 million and $380.0 million at March 31, 2015 and December 31, 2014, respectively. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.	The following table presents our consolidated debt obligations at the dates indicated. The MEMP Segment debt included in the table below is nonrecourse to the Company. December 31, December 31, 2014 2013 (In thousands) MRD Segment: MRD $2.0 billion revolving credit facility, variable-rate, due June 2019 $ 183,000 $ — WildHorse Resources $1.0 billion revolving credit facility, variable-rate, terminated June 2014 — 203,100 WildHorse Resources $325.0 million second lien term facility, variable-rate, terminated June 2014 — 325,000 10.00%/10.75% senior PIK toggle notes redeemed June 2014 — 350,000 5.875% senior unsecured notes, due July 2022 (1) 600,000 — 10.00%/10.75% senior PIK toggle notes unamortized discounts — (6,950 ) Subtotal 783,000 871,150 MEMP Segment: MEMP $2.0 billion revolving credit facility, variable-rate, due March 2018 412,000 103,000 7.625% senior notes, fixed-rate, due May 2021 (2) 700,000 700,000 6.875% senior unsecured notes, due August 2022 (3) 500,000 — Unamortized discounts (16,587 ) (10,933 ) Subtotal 1,595,413 792,067 Total long-term debt $ 2,378,413 $ 1,663,217 ( 1) The estimated fair value of this fixed-rate debt was $534.0 million at December 31, 2014. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. (2) The estimated fair value of this fixed-rate debt was $563.5 million and $721.0 million at December 31, 2014 and 2013, respectively. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. (3) The estimated fair value of this fixed-rate debt was $380.0 million at December 31, 2014. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.
Borrowing Base Credit Facility	The borrowing base for each credit facility was the following at the date indicated (in thousands): March 31, 2015 MRD Segment: MRD $2.0 billion revolving credit facility, variable-rate, due June 2019 $ 725,000 MEMP Segment: MEMP $2.0 billion revolving credit facility, variable-rate, due March 2018 1,300,000	The borrowing base for MRD’s and MEMP’s revolving credit facility was the following at the date indicated: December 31, 2014 MRD Segment: MRD $2.0 billion revolving credit facility, variable-rate, due June 2019 $ 725,000 MEMP Segment: MEMP $2.0 billion revolving credit facility, variable-rate, due March 2018 1,440,000
Summary of Weighted-Average Interest Rates Paid On Variable-Rate Debt Obligations	The following table presents the weighted-average interest rates paid on our consolidated variable-rate debt obligations for the periods presented: For the Three Months Ended Credit Facility March 31, 2015 2014 MRD Segment: MRD revolving credit facility 1.87 % n/a WildHorse Resources revolver terminated June 2014 n/a 3.97 % WildHorse Resources second lien terminated June 2014 n/a 6.44 % MEMP Segment: MEMP revolving credit facility 1.90 % 1.66 %	The following table presents the weighted-average interest rates paid on our consolidated and combined variable-rate debt obligations for the periods presented: For the Year Ended December 31, 2014 2013 2012 MRD Segment: MRD revolving credit facility 1.99 % n/a n/a WildHorse Resources revolver terminated June 2014 4.04 % 2.30 % 3.00 % WildHorse Resources second lien terminated June 2014 6.44 % 7.60 % n/a Black Diamond terminated November 2013 n/a 3.97 % 3.62 % MEMP Segment: MEMP revolving credit facility 2.67 % 3.25 % 2.74 % WHT revolver terminated March 2013 n/a 2.29 % 2.60 % Tanos revolver terminated April 2013 n/a 3.10 % 2.31 % REO revolving credit facility terminated December 2012 n/a n/a 3.40 % Stanolind revolver paid off by MEMP October 2013 n/a 3.52 % 3.76 % Boaz revolver terminated October 2013 n/a 2.97 % 3.12 % Crown revolver terminated October 2013 n/a 3.38 % 4.20 % MRD LLC revolver terminated December 2013 n/a 3.17 % 4.11 % Classic revolving credit facility terminated November 2012 n/a n/a 4.50 % Propel Energy revolver paid off by MEMP October 2013 n/a 3.08 % 3.28 %
Summary of Unamortized Deferred Financing Costs Associated with Consolidated Debt Obligations	Unamortized deferred financing costs associated with our consolidated debt obligations were as follows at the dates indicated: March 31, December 31, 2015 2014 (In thousands) MRD Segment: MRD revolving credit facility $ 4,060 $ 4,285 MRD senior notes 12,041 12,455 MEMP Segment: MEMP revolving credit facility 5,395 6,468 2021 Senior Notes 12,779 13,308 2022 Senior Notes 7,656 7,958 $ 41,931 $ 44,474	Unamortized deferred financing costs associated with our consolidated debt obligations were as follows at the dates indicated: December 31, December 31, 2014 2013 (In thousands) MRD Segment: MRD revolving credit facility $ 4,285 $ — MRD senior notes 12,455 — WildHorse Resources revolving credit facility — 2,436 WildHorse Resources second lien term loan — 9,030 PIK notes — 8,261 MEMP Segment: MEMP revolving credit facility 6,468 5,413 2021 Senior Notes 13,308 15,053 2022 Senior Notes 7,958 — $ 44,474 $ 40,193

Stockholders' Equity and Nonc37

Stockholders' Equity and Noncontrolling Interests (Tables)	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Equity [Abstract]
Summary of Changes In Common Shares Issued		The Company’s authorized capital stock includes 600,000,000 shares of common stock, $0.01 par value per share. The following is a summary of the changes in our common shares issued for the year ended December 31, 2014: Balance January 1, 2014 — Shares of common stock issued in connection with restructuring transactions (Note 1) 171,000,000 Shares of common stock issued in initial public offering (Note 1) 21,500,000 Shares of common stock repurchased and retired (123,797 ) Restricted common shares issued (Note 11) 1,068,422 Restricted common shares forfeited (9,211 ) Balance December 31, 2014 193,435,414
Summary of Changes In Common Shares Issued	The Company's authorized capital stock includes 600,000,000 shares of common stock, $0.01 par value per share. The following is a summary of the changes in our common shares issued for the three months ended March 31, 2015: Balance December 31, 2014 193,435,414 Shares of common stock repurchased (2,764,887 ) Restricted common shares issued (Note 11) 115,302 Restricted common shares forfeited (9,211 ) Balance March 31, 2015 190,776,618

Earnings per Share (Tables)

Earnings per Share (Tables)	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Summary of Calculation of Earnings (Loss) Per Share, or EPS	The following sets forth the calculation of earnings (loss) per share, or EPS, for the periods indicated (in thousands, except per share amounts): For the Three Months Ended March 31, 2015 Numerator: Net income (loss) available to common stockholders $ 45,615 Denominator: Weighted average common shares outstanding 190,705 Basic EPS $ 0.24 Diluted EPS (1) $ 0.24 (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 the period presented. Under the treasury stock method, 151,123 incremental shares were included in the diluted EPS computation.	The following sets forth the calculation of earnings (loss) per share, or EPS, for the period indicated (in thousands, except per share amounts): For the Year Ended December 31, 2014 Numerator: Net income (loss) available to common stockholders $ (784,581 ) Denominator: Weighted average common shares outstanding 192,498 Basic EPS $ (4.08 ) Diluted EPS (1) $ (4.08 ) (1) The Company determines the more dilutive of either the two-class method or the treasury stock method for diluted EPS. The restricted common shares were antidilutive due to net losses and excluded from the diluted EPS calculation for the year ending December 31, 2014. There were 202,623 incremental shares excluded from the computation of diluted EPS for the year ending December 31, 2014.
Supplemental EPS [Member]
Summary of Calculation of Earnings (Loss) Per Share, or EPS		The following sets forth the calculation of our supplemental EPS, for the period indicated (in thousands, except per share amounts): For the Year Ended December 31, 2014 Numerator: Net income (loss) attributable to Memorial Resource Development Corp. $ (762,851 ) Denominator: Weighted average common shares outstanding 192,498 Basic EPS $ (3.96 ) Diluted EPS (1) $ (3.96 ) (1) The Company determines the more dilutive of either the two-class method or the treasury stock method for diluted EPS. The restricted common shares were antidilutive due to net losses and excluded from the diluted EPS calculation for the year ending December 31, 2014. There were 202,623 incremental shares excluded from the computation of diluted EPS for the year ending December 31, 2014.

Long-Term Incentive Plans (Tabl

Long-Term Incentive Plans (Tables)	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Summary of Information Regarding Restricted Common Unit Awards	The following table summarizes information regarding restricted common share awards granted under the Memorial Resource Development Corp. 2014 Long-Term Incentive Plan for the periods presented: Number of Shares Weighted-Average Grant Date Fair Value per Share (1) Restricted common shares outstanding at December 31, 2014 1,059,211 $ 19.00 Granted (2) 115,302 $ 18.05 Forfeited (9,211 ) $ 19.00 Restricted common shares outstanding at March 31, 2015 1,165,302 $ 18.91 (1) Determined by dividing the aggregate grant date fair value of awards issued. (2) The aggregate grant date fair value of restricted common share awards issued in 2015 was $2.1 million based on a grant date market price of $18.05 per share. The following table summarizes information regarding restricted common unit awards granted under the Memorial Production Partners GP LLC Long-Term Incentive Plan for the periods presented: Number of Units Weighted-Average Grant Date Fair Value per Unit (1) Restricted common units outstanding at December 31, 2014 1,093,520 $ 20.93 Granted (2) 157,360 $ 15.45 Forfeited (12,467 ) $ 20.73 Vested (78,307 ) $ 19.16 Restricted common units outstanding at March 31, 2015 1,160,106 $ 20.31 (1) Determined by dividing the aggregate grant date fair value of awards issued. (2) The aggregate grant date fair value of restricted common unit awards issued in 2015 was $2.4 million based on a grant date market price of $15.45 per unit.	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 units outstanding at December 31, 2014 1,059,211 $ 19.00 (1) Determined by dividing the aggregate grant date fair value of awards by the number of awards issued. ( 2 ) The aggregate grant date fair value of restricted common share awards issued in 2014 was $20.3 million based on grant date market price of $19.00 per share. The following table summarizes information regarding restricted common unit awards granted under the MEMP LTIP for the periods presented: Number of Units Weighted-Average Grant Date Fair Value per Unit (1) Restricted common units outstanding at December 31, 2011 — $ — Granted (2) 287,943 $ 18.07 Forfeited (2,334 ) $ 17.14 Restricted common units outstanding at December 31, 2012 285,609 $ 18.08 Granted (3) 524,718 $ 18.83 Forfeited (11,734 ) $ 17.24 Vested (91,666 ) $ 18.31 Restricted common units outstanding at December 31, 2013 706,927 $ 18.62 Granted (4) 684,954 $ 22.39 Forfeited (38,294 ) $ 20.54 Vested (260,067 ) $ 18.56 Restricted common units outstanding at December 31, 2014 1,093,520 $ 20.93 — Determined by dividing the aggregate grant date fair value of awards by the number of awards issued. — The aggregate grant date fair value of restricted common unit awards issued in 2012 was $5.2 million based on grant date market prices ranging from of $17.14 to $18.58 per unit. ( 3 ) The aggregate grant date fair value of restricted common unit awards issued in 2013 was $9.9 million based on grant date market prices ranging from of $18.33 to $20.35 per unit. ( 4 ) The aggregate grant date fair value of restricted common unit awards issued in 2014 was $15.3 million based on grant date market prices ranging from of $21.99 to $23.40 per unit.
Summary of Amount of Compensation Expense Recognized	The following table summarizes the amount of recognized compensation expense associated with these awards that are reflected in the accompanying statements of operations for the periods presented (in thousands): For the Three Months Ended March 31, 2015 2014 $ 1,486 n/a	The following table summarizes the amount of recognized compensation expense associated with these awards that are reflected in the accompanying statements of operations for the periods presented (in thousands): For the Year Ended December 31, 2014 $ 2,804 The following table summarizes the amount of recognized compensation expense associated with these awards that are reflected in the accompanying statements of operations for the periods presented (in thousands): For the Year Ended December 31, 2014 2013 2012 $ 7,874 $ 3,558 $ 1,423

Incentive Units (Tables)

Incentive Units (Tables)	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Compensation Related Costs [Abstract]
Fair Value of Incentive Units Estimated		The fair value of the incentive units was estimated using a Monte Carlo simulation valuation model with the following assumptions: Exchanged Incentive Units Subsequent Incentive Units Valuation date 12/31/2014 12/31/2014 Dividend yield 0 % 0 % Expected volatility 39.54 % 39.54 % Risk-free rate 0.85 % 0.85 % Expected life (years) 2.41 2.41
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 3/31/2015 3/31/2015 Dividend yield 0 % 0 % Expected volatility 27.90 % 27.90 % Risk-free rate 0.61 % 0.61 % Expected life (years) 2.17 2.17

Related Party Transactions (Tab

Related Party Transactions (Tables)	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Related Party Transactions [Abstract]
Schedule of Net Assets Recorded	WildHorse Resources recorded the following net assets (in thousands): Accounts receivable $ 2,274 Oil and natural gas properties, net 40,056 Accrued liabilities (297 ) Asset retirement obligations (277 ) Net assets $ 41,756	WildHorse Resources recorded the following net assets (in thousands): Accounts receivable $ 2,274 Oil and natural gas properties, net 40,056 Accrued liabilities (297 ) Asset retirement obligations (277 ) Net assets $ 41,756 MEMP recorded the following net assets (in thousands): Cash and cash equivalents $ 6,021 Accounts receivable 16,284 Short-term derivative instruments, net 2,926 Prepaid expenses and other current assets 4,521 Oil and natural gas properties, net 108,342 Restricted investments 68,009 Accounts payable (9,092 ) Accrued liabilities (9,140 ) Asset retirement obligations (58,746 ) Credit facilities (28,500 ) Deferred tax liability (1,674 ) Noncontrolling interest (5,255 ) Net assets $ 93,696
Book Value of Assets Sold		The Cinco Group acquisition was accounted for as a combination of entities under common control at historical cost in a manner similar to the pooling of interest method. Cash and cash equivalents $ 2,820 Accounts receivable 5,184 Prepaid expenses and other current assets 1,454 Oil and natural gas properties, net 342,759 Long-term derivative instruments, net (826 ) Other long-term assets 344 Accounts payable (2,346 ) Revenue payable (2,910 ) Accrued liabilities (1,799 ) Short-term derivative instruments, net (1,828 ) Asset retirement obligations (9,606 ) Credit facilities (151,690 ) Net assets $ 181,556 The net book value of the assets sold was as follows (in thousands): Cash and cash equivalents $ 33,001 Restricted cash 300 Accounts receivable 5,256 Prepaid expenses and other current assets 379 Property, plant and equipment, net 3,410 Other long-term assets 4 Accounts payable (19,959 ) Accounts payable - affiliates (17,099 ) Accrued liabilities (5,061 ) Net assets $ 231

Business Segment Data (Tables)

Business Segment Data (Tables)	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Segment Reporting [Abstract]
Summary of Selected Business Segment Information	The following table presents selected business segment information for the periods indicated (in thousands): Other, Consolidated Adjustments & & Combined MRD MEMP Eliminations Totals Total revenues: For the Three Months Ended March 31, 2015 $ 87,023 $ 92,818 $ — $ 179,841 For the Three Months Ended March 31, 2014 87,736 116,885 — 204,621 Adjusted EBITDA: (1) For the Three Months Ended March 31, 2015 86,830 86,432 (76 ) 173,186 For the Three Months Ended March 31, 2014 64,752 62,046 (3,002 ) 123,796 Segment assets: (2) As of March 31, 2015 1,535,233 3,051,190 (12,201 ) 4,574,222 As of December 31, 2014 1,413,768 3,189,760 (9,981 ) 4,593,547 Total cash expenditures for additions to long-lived assets: For the Three Months Ended March 31, 2015 88,566 77,680 — 166,246 For the Three Months Ended March 31, 2014 75,258 231,973 — 307,231 (1) Adjustments and eliminations for the three months ended March 31, 2015 and 2014 include less than $0.1 million and $3.0 million of cash distributions that MEMP paid MRD for the three months ended March 31, 2015 and 2014, respectively, related to MRD’s partnership interests in MEMP. In 2014, MRD LLC owned MEMP subordinated units, which were distributed to MRD Holdco in connection with the Company’s initial public offering in June 2014. (2) As of March 31, 2015, adjustments and eliminations primarily represent the elimination of accounts receivable and accounts payable balances between the MRD Segment and the MEMP Segment.	The following table presents selected business segment information for the periods indicated (in thousands): Other, Consolidated Adjustments & & Combined MRD MEMP Eliminations Totals Total revenues: For the Year ended December 31, 2014 $ 363,126 $ 536,219 $ — $ 899,345 For the Year ended December 31, 2013 201,886 373,137 — 575,023 For the Year ended December 31, 2012 104,072 293,165 (369 ) 396,868 Adjusted EBITDA: (1) 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 For the Year ended December 31, 2012 99,746 211,693 (23,447 ) 287,992 Segment assets: (2) As of December 31, 2014 1,413,768 3,189,760 (9,981 ) 4,593,547 As of December 31, 2013 1,033,958 1,849,368 (54,165 ) 2,829,161 Total cash expenditures for additions to long-lived assets: 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 For the Year ended December 31, 2012 188,903 447,782 — 636,685 (1) Adjustments and eliminations for the years ended December 31, 2014, 2013 and 2012 include amounts related to the MRD Segment’s equity investments in the MEMP Segment as well the elimination of $6.1 million, $26.0 million and $19.3 million of cash distributions that MEMP paid MRD Segment for the years ended December 31, 2014, 2013 and 2012, respectively, related to MRD Segment’s partnership interests in MEMP. (2) Adjustments and eliminations primarily represent the elimination of the MRD Segment’s equity investments in the MEMP Segment.
Schedule of Calculation of Reportable Segment's Adjusted EBITDA	Calculation of Reportable Segments’ Adjusted EBITDA For the Three Months Ended March 31, 2015 Combined MRD MEMP Totals (In thousands) Net income (loss) $ 50,371 $ (162,658 ) $ (112,287 ) Interest expense, net 9,756 28,818 38,574 Income tax expense (benefit) 47,558 (2,370 ) 45,188 DD&A 40,532 51,266 91,798 Impairment of proved oil and natural gas properties — 251,347 251,347 Accretion of AROs 123 1,634 1,757 (Gain) loss on commodity derivative instruments (108,190 ) (145,459 ) (253,649 ) Cash settlements received (paid) on expired commodity derivative instruments 32,749 60,124 92,873 Transaction related costs 1,281 1,299 2,580 Incentive-based compensation expense 11,710 2,341 14,051 Exploration costs 726 90 816 Non-cash equity (income) loss from MEMP 138 — 138 Cash distributions from MEMP 76 — 76 Adjusted EBITDA $ 86,830 $ 86,432 $ 173,262 For the Three Months Ended March 31, 2014 Combined MRD MEMP Totals (In thousands) Net income (loss) $ 6,390 $ (32,892 ) $ (26,502 ) Interest expense, net 17,974 16,078 34,052 Income tax expense (benefit) 25 75 100 DD&A 25,129 32,550 57,679 Accretion of AROs 130 1,391 1,521 (Gain) loss on commodity derivative instruments 12,716 46,766 59,482 Cash settlements received (paid) on expired commodity derivative instruments (5,221 ) (7,969 ) (13,190 ) (Gain) loss on sale of properties (110 ) — (110 ) Transaction related costs 568 1,894 2,462 Incentive-based compensation expense 1,023 1,295 2,318 Exploration costs 140 6 146 Provision for environmental remediation — 2,852 2,852 Non-cash equity (income) loss from MEMP 2,986 — 2,986 Cash distributions from MEMP 3,002 — 3,002 Adjusted EBITDA $ 64,752 $ 62,046 $ 126,798	Calculation of Reportable Segments’ Adjusted EBITDA 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 Loss on extinguishment of debt 37,248 — 37,248 Income tax expense (benefit) 102,392 (1,421 ) 100,971 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 commodity derivative instruments 9,166 13,522 22,688 (Gain) loss on sale of properties 3,057 — 3,057 Acquisition related costs 2,305 4,363 6,668 Incentive-based compensation expense 946,753 7,874 954,627 Exploration costs 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 commodity derivative instruments 8,481 23,638 32,119 (Gain) loss on sale of properties (82,773 ) (2,848 ) (85,621 ) Acquisition related costs 1,584 6,729 8,313 Incentive-based compensation expense 34,997 11,840 46,837 Non-cash 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 For the Year Ended December 31, 2012 Combined MRD MEMP Totals (In thousands) Net income (loss) $ 8,810 $ 23,067 $ 31,877 Interest expense, net 8,283 24,955 33,238 Income tax expense (benefit) (1 ) 108 107 DD&A 37,048 101,624 138,672 Impairment of proved oil and natural gas properties 5,877 22,994 28,871 Accretion of AROs 551 4,458 5,009 (Gain) loss on commodity derivative instruments (10,500 ) (24,405 ) (34,905 ) Cash settlements received (paid) on commodity derivative instruments 20,740 53,559 74,299 (Gain) loss on sale of properties (2 ) (9,759 ) (9,761 ) Acquisition related costs 403 4,135 4,538 Incentive-based compensation expense 9,510 1,423 10,933 Amortization of investment premium — 194 194 Exploration costs 460 9,340 9,800 Non-cash equity (income) loss from MEMP (696 ) — (696 ) Cash distributions from MEMP 19,263 — 19,263 Adjusted EBITDA $ 99,746 $ 211,693 $ 311,439
Reconciliation of Total Reportable Segment's Adjusted EBITDA to Net Income (Loss)	The following table presents a reconciliation of total reportable segments’ Adjusted EBITDA to net income (loss) for each of the periods indicated (in thousands). For the Three Months Ended March 31, 2015 2014 Total Reportable Segments' Adjusted EBITDA $ 173,262 $ 126,798 Adjustments to reconcile Adjusted EBITDA to net income (loss): Interest expense, net (38,574 ) (34,052 ) Income tax benefit (expense) (45,188 ) (100 ) DD&A (91,798 ) (57,679 ) Impairment of proved oil and natural gas properties (251,347 ) — Accretion of AROs (1,757 ) (1,521 ) Gains (losses) on commodity derivative instruments 253,649 (59,482 ) Cash settlements paid (received) on expired commodity derivative instruments (92,873 ) 13,190 Gain (loss) on sale of properties — 110 Transaction related costs (2,580 ) (2,462 ) Incentive-based compensation expense (14,051 ) (2,318 ) Exploration costs (816 ) (146 ) Provision for environmental remediation — (2,852 ) Cash distributions from MEMP (76 ) (3,002 ) Net income (loss) $ (112,149 ) $ (23,516 )	The following table presents a reconciliation of total reportable segments’ Adjusted EBITDA to net income (loss) for each of the periods indicated (in thousands): For the Year Ended December 31, 2014 2013 2012 Total Reportable Segments' Adjusted EBITDA $ 653,877 $ 420,088 $ 311,439 Adjustments to reconcile Adjusted EBITDA to net income (loss): Interest expense, net (133,833 ) (69,250 ) (33,238 ) Loss on extinguishment of debt (37,248 ) — — Income tax benefit (expense) (100,971 ) (1,619 ) (107 ) DD&A (314,193 ) (184,717 ) (138,672 ) Impairment of proved oil and natural gas properties (432,116 ) (6,600 ) (28,871 ) Accretion of AROs (6,306 ) (5,581 ) (5,009 ) Gains (losses) on commodity derivative instruments 749,988 29,294 34,905 Cash settlements paid (received) on commodity derivative instruments (22,688 ) (32,119 ) (74,299 ) Gain (loss) on sale of properties (3,057 ) 85,621 9,761 Acquisition related costs (6,668 ) (8,313 ) (4,538 ) Incentive-based compensation expense (954,627 ) (46,837 ) (10,933 ) Non-cash compensation expense — (1,057 ) — Exploration costs (16,603 ) (2,356 ) (9,800 ) Amortization of investment premium — — (194 ) Cash distributions from MEMP (6,144 ) (26,006 ) (19,263 ) Provision for environmental remediation (2,852 ) — — Loss on office lease (2,622 ) — — Other non-cash equity (income) loss — 784 (4,184 ) Net income (loss) $ (636,063 ) $ 151,332 $ 26,997
Schedule of Consolidated and Combined Statement of Operations Disaggregated by Reportable Segment	Included below is our consolidated and combined statement of operations disaggregated by reportable segment for the period indicated (in thousands): For the Three Months Ended March 31, 2015 MRD MEMP Other, Adjustments & Eliminations Consolidated & Combined Totals Revenues: Oil & natural gas sales $ 87,023 $ 91,949 $ — $ 178,972 Other revenues — 869 — 869 Total revenues 87,023 92,818 — 179,841 Costs and expenses: Lease operating 5,222 40,478 — 45,700 Gathering, processing, and transportation 14,763 8,220 — 22,983 Pipeline operating — 446 — 446 Exploration 726 90 — 816 Production and ad valorem taxes 2,775 6,655 — 9,430 Depreciation, depletion, and amortization 40,532 51,266 — 91,798 Impairment of proved oil and natural gas properties — 251,347 — 251,347 Incentive unit compensation expense 10,224 — — 10,224 General and administrative 12,976 14,511 — 27,487 Accretion of asset retirement obligations 123 1,634 — 1,757 (Gain) loss on commodity derivative instruments (108,190 ) (145,459 ) — (253,649 ) Total costs and expenses (20,849 ) 229,188 — 208,339 Operating income (loss) 107,872 (136,370 ) — (28,498 ) Other income (expense): Interest expense, net (9,756 ) (28,818 ) — (38,574 ) Earnings from equity investments (138 ) — 138 — Other, net (49 ) 160 — 111 Total other income (expense) (9,943 ) (28,658 ) 138 (38,463 ) Income (loss) before income taxes 97,929 (165,028 ) 138 (66,961 ) Income tax benefit (expense) (47,558 ) 2,370 — (45,188 ) Net income (loss) $ 50,371 $ (162,658 ) $ 138 $ (112,149 ) For the Three Months Ended March 31, 2014 MRD MEMP Other, Adjustments & Eliminations Consolidated & Combined Totals Revenues: Oil & natural gas sales $ 87,733 $ 115,977 $ — $ 203,710 Other revenues 3 908 — 911 Total revenues 87,736 116,885 — 204,621 Costs and expenses: Lease operating 3,235 30,120 — 33,355 Gathering, processing, and transportation 8,557 5,563 14,120 Pipeline operating — 489 — 489 Exploration 140 6 — 146 Production and ad valorem taxes 2,573 6,011 — 8,584 Depreciation, depletion, and amortization 25,129 32,550 — 57,679 Incentive unit compensation expense 1,023 — — 1,023 General and administrative 6,999 10,740 — 17,739 Accretion of asset retirement obligations 130 1,391 — 1,521 (Gain) loss on commodity derivative instruments 12,716 46,766 — 59,482 (Gain) loss on sale of properties (110 ) — — (110 ) Other, net — (12 ) — (12 ) Total costs and expenses 60,392 133,624 — 194,016 Operating income (loss) 27,344 (16,739 ) — 10,605 Other income (expense): Interest expense, net (17,974 ) (16,078 ) — (34,052 ) Earnings from equity investments (2,986 ) — 2,986 — Other, net 31 — — 31 Total other income (expense) (20,929 ) (16,078 ) 2,986 (34,021 ) Income (loss) before income taxes 6,415 (32,817 ) 2,986 (23,416 ) Income tax benefit (expense) (25 ) (75 ) — (100 ) Net income (loss) $ 6,390 $ (32,892 ) $ 2,986 $ (23,516 )	Included below is our consolidated and combined statement of operations disaggregated by reportable segment for the period indicated (in thousands): For the Year Ended December 31, 2014 MRD MEMP Other, Adjustments & Eliminations Consolidated & Combined Totals Revenues: Oil & natural gas sales $ 363,114 $ 531,853 $ — $ 894,967 Other revenues 12 4,366 — 4,378 Total revenues 363,126 536,219 — 899,345 Costs and expenses: Lease operating 17,570 143,733 — 161,303 Pipeline operating — 2,068 — 2,068 Exploration 13,853 2,750 — 16,603 Production and ad valorem taxes 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 925,200 337,819 — 1,263,019 Operating income (loss) (562,074 ) 198,400 — (363,674 ) Other income (expense): Interest expense, net (50,283 ) (83,550 ) — (133,833 ) Loss on extinguishment of debt (37,248 ) — — (37,248 ) Earnings from equity investments (12,656 ) — 12,656 — Other, net 320 (657 ) — (337 ) Total other income (expense) (99,867 ) (84,207 ) 12,656 (171,418 ) Income (loss) 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 $ 201,886 $ 370,062 $ — $ 571,948 Other revenues — 3,075 — 3,075 Total revenues 201,886 373,137 — 575,023 Costs and expenses: Lease operating 17,315 96,433 (108 ) 113,640 Pipeline operating — 1,835 — 1,835 Exploration 1,034 1,322 — 2,356 Production and ad valorem taxes 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 85,446 267,524 (3 ) 352,967 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 For the Year Ended December 31, 2012 MRD MEMP Other, Adjustments & Eliminations Consolidated & Combined Totals Revenues: Oil & natural gas sales $ 103,728 $ 289,912 $ (9 ) $ 393,631 Other revenues 344 3,253 (360 ) 3,237 Total revenues 104,072 293,165 (369 ) 396,868 Costs and expenses: Lease operating 16,582 87,972 (800 ) 103,754 Pipeline operating — 2,114 — 2,114 Exploration 460 9,340 — 9,800 Production and ad valorem taxes 8,270 15,354 — 23,624 Depreciation, depletion, and amortization 37,048 101,624 — 138,672 Impairment of proved oil and natural gas properties 5,877 22,994 — 28,871 Incentive unit compensation expense 9,510 — — 9,510 General and administrative 24,134 35,112 431 59,677 Accretion of asset retirement obligations 551 4,458 — 5,009 (Gain) loss on commodity derivative instruments (10,500 ) (24,405 ) — (34,905 ) (Gain) loss on sale of properties (2 ) (9,759 ) — (9,761 ) Other, net 464 38 — 502 Total costs and expenses 92,394 244,842 (369 ) 336,867 Operating income (loss) 11,678 48,323 — 60,001 Other income (expense): Interest expense, net (8,283 ) (24,955 ) — (33,238 ) Amortization of investment premium — (194 ) — (194 ) Earnings from equity investments 4,880 — (4,880 ) — Other, net 534 1 — 535 Total other income (expense) (2,869 ) (25,148 ) (4,880 ) (32,897 ) Income before income taxes 8,809 23,175 (4,880 ) 27,104 Income tax benefit (expense) 1 (108 ) — (107 ) Net income (loss) $ 8,810 $ 23,067 $ (4,880 ) $ 26,997

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Components of Income Tax Expense (Benefit)	Income tax benefit (expense) for the indicated periods is comprised of the following: For the Year Ended December 31, 2014 2013 2012 (In thousands) Current taxes: Federal $ — $ — $ — State 22 (1,619 ) 178 Deferred taxes: Federal (88,994 ) — — State (11,999 ) — (285 ) Total income tax benefit (expense) $ (100,971 ) $ (1,619 ) $ (107 )
Reconciliation of Income Tax Benefit (Provision)	The actual income tax benefit (expense) differs from the expected income tax benefit (provision) as computed by applying the federal statutory corporate tax rate of 35% for each period indicated as follows: For the Year Ended December 31, 2014 2013 2012 Expected tax benefit (expense) $ 187,282 $ (53,533 ) $ (9,486 ) State income tax expense, net of federal benefit (9,660 ) (1,619 ) (107 ) Pass-through entities (1) 49,989 53,533 9,486 Stock compensation (2) (330,024 ) — — Other 1,442 — — Total income tax benefit (expense) $ (100,971 ) $ (1,619 ) $ (107 )
Components of Net Deferred Income Tax Assets and (Liabilities)	(1) MEMP, a publicly traded partnership with qualifying income, is a pass-through entity for federal income tax purposes. In addition, our predecessor was also a pass-through entity for federal income tax purposes. (2 ) As discussed in Note 12, the compensation expense associated with the incentive units of WildHorse Resources and MRD Holdco created a nondeductible permanent difference for income tax purposes. The components of net deferred income tax assets and (liabilities) recognized were as follows: December 31, 2014 2013 (In thousands) Deferred current income tax assets: Unrealized hedging transactions $ 109 $ 37 Accrued liabilities — 5 Other 342 (42 ) Deferred current income tax assets: $ 451 $ — Deferred current income tax liabilities: Unrealized hedging transactions $ (52,328 ) — Other (52 ) (382 ) Deferred current income tax liabilities: $ (52,380 ) $ (382 ) Deferred noncurrent income tax assets: Net operating loss carryforward $ 28,043 $ 2,350 Asset retirement obligation 5,757 971 Other 3,224 1 Net deferred tax valuation allowance (2,634 ) (2,896 ) Deferred noncurrent income tax assets: $ 34,390 $ 426 Deferred noncurrent income tax liabilities: Property, plant and equipment $ (80,198 ) $ (3,318 ) Unrealized hedging transactions (48,929 ) (275 ) Other (280 ) 61 Deferred noncurrent income tax liabilities: $ (129,407 ) $ (3,532 ) Net current deferred income tax assets (liabilities) $ (51,929 ) $ (382 ) Net noncurrent deferred income tax assets (liabilities) $ (95,017 ) $ (3,106 )

Commitments and Contingencies (

Commitments and Contingencies (Tables)	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Environmental Reserves Activity		The following table presents the activity of our environmental reserves for the periods presented: 2014 2013 2012 (In thousands) Balance at beginning of period $ 577 $ 1,469 $ 1,747 Charged to costs and expenses 2,852 — 193 Payments (1,337 ) (892 ) (471 ) Balance at end of period $ 2,092 $ 577 $ 1,469
Minimum Balances Attributable to Net Working Interest	The trust account must maintain minimum balances attributable to REO’s net working interest as follows (in thousands): June 30, 2015 $ 72,450 June 30, 2016 $ 76,590 December 31, 2016 $ 78,660	The trust account must maintain minimum balances attributable to REO’s net working interest as follows (in thousands): June 30, 2015 $ 72,450 June 30, 2016 $ 76,590 December 31, 2016 $ 78,660
Gross Held-to-Maturity Investments	The following is a summary of the gross held-to-maturity investments held in the trust account less the outside working interest owners share as of March 31, 2015 (in thousands): Amortized Investment Cost U.S. Bank Money Market Cash Equivalent $ 137,705 Less: Outside working interest owners share (66,442 ) $ 71,263	The following is a summary of the gross held-to-maturity investments held in the trust account less the outside working interest owners share as of December 31, 2014 (in thousands): Amortized Investment Cost U.S. Bank Money Market Cash Equivalent $ 135,176 Less: Outside working interest owners share (65,222 ) $ 69,954
Minimum Commitments to Gatherer before Other Owner Contributions		WildHorse Resources’ minimum commitments to the Gatherer, before other owner contributions, as of December 31, 2014 were as follows (in thousands): Dubach Dubberly 2015 $ 13,671 $ 11,393 2016 13,709 11,424 2017 13,671 11,393 2018 12,772 10,643 Total $ 53,823 $ 44,853
Minimum Lease Payment Obligations and Sublease Rental Income Under Non-Cancelable Operating Leases		Amounts shown in the following table represent minimum lease payment obligations and sublease rental income under non-cancelable operating leases with a remaining term in excess of one year: Payment or Settlement due by Period Total 2015 2016 2017 2018 2019 Thereafter (In thousands) MRD Segment: Operating leases $ 43,625 $ 6,534 $ 6,607 $ 6,694 $ 6,259 $ 5,960 $ 11,571 Sublease rental income 5,786 1,691 1,579 1,197 814 431 74 MEMP Segment: Operating leases 3,665 788 416 205 205 205 1,846
Wyoming Acquisition [Member]
CO2 Minimum Purchase Commitment		At December 31, 2014, MEMP had a CO 2 Payment or Settlement due by Period Purchase commitment Total 2015 2016 2017 2018 2019 Thereafter CO 2 Estimated payment obligation $ 50,495 $ 9,608 $ 10,179 $ 10,151 $ 6,995 $ 7,060 $ 6,502

Condensed Consolidating Finan45

Condensed Consolidating Financial Information (Tables)	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Condensed Consolidating Balance Sheets	March 31, 2015 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated (In thousands) ASSETS Current assets: Cash and cash equivalents $ 454 $ 2,985 $ 1,073 $ — $ 4,512 Accounts receivable - trade 5,259 43,307 73,503 (3,670 ) 118,399 Accounts receivable - affiliates 13,303 — 28 (11,355 ) 1,976 Short-term derivative instruments 142,074 — 214,986 — 357,060 Prepaid expenses and other current assets 5,036 7,410 19,687 — 32,133 Total current assets 166,126 53,702 309,277 (15,025 ) 514,080 Property and equipment, net 17,320 1,098,997 2,250,283 — 3,366,600 Long-term derivative instruments 188,405 — 389,748 — 578,153 Investments in subsidiaries 928,289 — — (928,289 ) — Other long-term assets 13,481 — 101,908 — 115,389 Total assets $ 1,313,621 $ 1,152,699 $ 3,051,216 $ (943,314 ) $ 4,574,222 LIABILITIES AND EQUITY Current liabilities: Accounts payable and accrued liabilities $ 11,711 $ 127,921 $ 122,152 $ (2,046 ) $ 259,738 Accounts payable - affiliates — 4,185 9,145 (13,330 ) — Revenues payable — 31,136 27,195 — 58,331 Short-term derivative instruments — — 3,300 — 3,300 Total current liabilities 11,711 163,242 161,792 (15,376 ) 321,369 Long-term debt 744,000 — 1,754,045 — 2,498,045 Asset retirement obligations — 7,749 116,727 — 124,476 Long-term derivative instruments — — 555 — 555 Deferred tax liabilities 102,978 6,648 2,164 — 111,790 Other long-term liabilities 7,566 — — — 7,566 Total liabilities 866,255 177,639 2,035,283 (15,376 ) 3,063,801 Equity: Equity 447,366 975,060 1,010,214 (1,985,274 ) 447,366 Noncontrolling interests — — 5,719 1,057,336 1,063,055 Total equity 447,366 975,060 1,015,933 (927,938 ) 1,510,421 Total liabilities and equity $ 1,313,621 $ 1,152,699 $ 3,051,216 $ (943,314 ) $ 4,574,222 December 31, 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 5,833 7,993 14,201 — 28,027 Total current assets 155,587 56,707 307,130 (13,807 ) 505,617 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 14,124 5,660 100,521 (5,400 ) 114,905 Total assets $ 1,449,671 $ 1,113,089 $ 3,189,786 $ (1,158,999 ) $ 4,593,547 LIABILITIES AND EQUITY Current liabilities: Accounts payable and accrued liabilities $ 6,245 $ 107,068 $ 114,584 $ (3,125 ) $ 224,772 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 6,245 137,948 154,392 (12,548 ) 286,037 Long-term debt 783,000 — 1,595,413 — 2,378,413 Asset retirement obligations — 9,830 112,701 — 122,531 Deferred tax liabilities 69,431 — 30,986 (5,400 ) 95,017 Other long-term liabilities 8,585 — — — 8,585 Total liabilities 867,261 147,778 1,893,492 (17,948 ) 2,890,583 Equity: Equity 582,410 965,311 1,290,734 (2,256,045 ) 582,410 Noncontrolling interests — — 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 and equity $ 1,449,671 $ 1,113,089 $ 3,189,786 $ (1,158,999 ) $ 4,593,547	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 period 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. December 31, 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 5,833 7,993 14,201 — 28,027 Total current assets 155,587 56,707 307,130 (13,807 ) 505,617 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 14,124 5,660 100,521 (5,400 ) 114,905 Total assets $ 1,449,671 $ 1,113,089 $ 3,189,786 $ (1,158,999 ) $ 4,593,547 LIABILITIES AND EQUITY Current liabilities: Accounts payable and accrued liabilities $ 6,245 $ 107,068 $ 114,584 $ (3,125 ) $ 224,772 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 6,245 137,948 154,392 (12,548 ) 286,037 Long-term debt 783,000 — 1,595,413 — 2,378,413 Asset retirement obligations — 9,830 112,701 — 122,531 Deferred tax liabilities 69,431 — 30,986 (5,400 ) 95,017 Other long-term liabilities 8,585 — — — 8,585 Total liabilities 867,261 147,778 1,893,492 (17,948 ) 2,890,583 Equity: Equity 582,410 965,311 1,290,734 (2,256,045 ) 582,410 Noncontrolling interests — — 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 and equity $ 1,449,671 $ 1,113,089 $ 3,189,786 $ (1,158,999 ) $ 4,593,547 December 31, 2013 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Combined & Consolidated (In thousands) ASSETS Current assets: Cash and cash equivalents $ — $ 48,619 $ 29,102 $ — $ 77,721 Restricted cash — 35,000 — — 35,000 Accounts receivable - trade — 49,655 39,459 (392 ) 88,722 Accounts receivable - affiliates — 8,905 1,532 (5,785 ) 4,652 Short-term derivative instruments — 1,688 7,601 — 9,289 Prepaid expenses and other current assets — 7,783 11,730 — 19,513 Total current assets — 151,650 89,424 (6,177 ) 234,897 Property and equipment, net — 785,914 1,633,790 — 2,419,704 Long-term derivative instruments — 5,960 42,656 — 48,616 Investments in subsidiaries — 288,760 — (288,760 ) — Other long-term assets — 35,137 90,807 — 125,944 Total assets $ — 1,267,421 1,856,677 (294,937 ) 2,829,161 LIABILITIES AND EQUITY Current Liabilities: Accounts payable and accrued liabilities $ — $ 61,865 $ 57,392 $ (393 ) $ 118,864 Accounts payable - affiliates — 7,481 1,017 (6,523 ) 1,975 Revenues payable — 36,307 19,784 — 56,091 Short-term derivative instruments — 1,715 7,996 — 9,711 Total current liabilities — 107,368 86,189 (6,916 ) 186,641 Long-term debt — 871,150 792,067 — 1,663,217 Asset retirement obligations — 9,612 102,067 — 111,679 Long-term derivative instruments — 205 5,875 — 6,080 Deferred tax liabilities — — 1,151 1,955 3,106 Other long-term liabilities — 306 1,955 (1,955 ) 306 Total liabilities — 988,641 989,304 (6,916 ) 1,971,029 Equity: Equity — 277,517 855,768 (855,768 ) 277,517 Noncontrolling interests — 1,263 11,605 567,747 580,615 Total equity — 278,780 867,373 (288,021 ) 858,132 Total liabilities and equity $ — $ 1,267,421 $ 1,856,677 $ (294,937 ) $ 2,829,161
Condensed Consolidating Statements of Operations	Three Months Ended March 31, 2015 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated (In thousands) Revenues: Oil & natural gas sales $ — $ 87,023 $ 91,949 $ — $ 178,972 Other revenues — — 869 — 869 Total revenues — 87,023 92,818 — 179,841 Costs and expenses: Lease operating — 5,222 40,478 — 45,700 Gathering, processing and transportation — 14,763 8,220 — 22,983 Pipeline operating — — 446 — 446 Exploration — 726 90 — 816 Production and ad valorem taxes — 2,775 6,655 — 9,430 Depreciation, depletion and amortization 968 39,564 51,266 — 91,798 Impairment of proved oil and natural gas properties — — 251,347 — 251,347 Incentive unit compensation expense 10,224 — — — 10,224 General and administrative 10,925 2,051 14,511 — 27,487 Accretion of asset retirement obligations — 123 1,634 — 1,757 (Gain) loss on commodity derivatives (108,190 ) — (145,459 ) — (253,649 ) Total costs and expenses (86,073 ) 65,224 229,188 — 208,339 Operating income (loss) 86,073 21,799 (136,370 ) — (28,498 ) Other income (expense): Interest expense, net (9,757 ) — (28,817 ) — (38,574 ) Equity earnings from subsidiaries 7,021 — — (7,021 ) — Other, net — (49 ) 160 — 111 Total other income (expense) (2,736 ) (49 ) (28,657 ) (7,021 ) (38,463 ) Income before income taxes 83,337 21,750 (165,027 ) (7,021 ) (66,961 ) Income tax benefit (expense) (37,445 ) (10,113 ) 2,370 — (45,188 ) Net income (loss) 45,892 11,637 (162,657 ) (7,021 ) (112,149 ) Net income (loss) attributable to noncontrolling interest — — 159 (158,200 ) (158,041 ) Net income (loss) attributable to Memorial Resource Development Corp. $ 45,892 $ 11,637 $ (162,816 ) $ 151,179 $ 45,892 Three Months Ended March 31, 2014 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Combined & Consolidated (In thousands) Revenues: Oil & natural gas sales $ — $ 87,733 $ 115,977 $ — $ 203,710 Other revenues — 3 908 — 911 Total revenues — 87,736 116,885 — 204,621 Costs and expenses: Lease operating — 3,235 30,120 — 33,355 Gathering, processing and transportation — 8,557 5,563 — 14,120 Pipeline operating — — 489 — 489 Exploration — 140 6 — 146 Production and ad valorem taxes — 2,573 6,011 — 8,584 Depreciation, depletion and amortization — 25,129 32,550 — 57,679 Incentive unit compensation expense — — 1,023 — 1,023 General and administrative — 6,982 10,757 — 17,739 Accretion of asset retirement obligations — 130 1,391 — 1,521 (Gain) loss on commodity derivatives — 12,716 46,766 — 59,482 (Gain) loss on sale of properties — — (110 ) — (110 ) Other, net — — (12 ) — (12 ) Total costs and expenses — 59,462 134,554 — 194,016 Operating income (loss) — 28,274 (17,669 ) — 10,605 Other income (expense): Interest expense, net — (17,974 ) (16,078 ) — (34,052 ) Equity earnings from subsidiaries — (3,260 ) — 3,260 — Other, net — 31 — — 31 Total other income (expense) — (21,203 ) (16,078 ) 3,260 (34,021 ) Income before income taxes — 7,071 (33,747 ) 3,260 (23,416 ) Income tax benefit (expense) — (25 ) (75 ) — (100 ) Net income (loss) — 7,046 (33,822 ) 3,260 (23,516 ) Net income (loss) attributable to noncontrolling interest — — 55 (31,943 ) (31,888 ) Net income (loss) attributable to Memorial Resource Development Corp. $ — $ 7,046 $ (33,877 ) $ 35,203 $ 8,372	December 31, 2014 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Combined & Consolidated (In thousands) Revenues: Oil & natural gas sales $ — $ 363,114 $ 531,853 $ — $ 894,967 Other revenues 5 7 4,366 — 4,378 Total revenues 5 363,121 536,219 — 899,345 Costs and expenses: Lease operating — 17,570 143,733 — 161,303 Pipeline operating — — 2,068 — 2,068 Exploration — 13,853 2,750 — 16,603 Production and ad valorem taxes — 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 ) 1,075,146 338,771 — 1,263,019 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 ) Debt extinguishment costs (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 $ — $ 184,757 $ 387,191 $ — $ 571,948 Other revenues — — 3,075 — 3,075 Total revenues — 184,757 390,266 — 575,023 Costs and expenses: Lease operating — 14,710 98,930 — 113,640 Pipeline operating — — 1,835 — 1,835 Exploration — 1,034 1,322 — 2,356 Production and ad valorem taxes — 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 — 135,871 217,096 — 352,967 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 $ (120,785.00 ) $ 101,502 December 31, 2012 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Combined & Consolidated (In thousands) Revenues: Oil & natural gas sales $ — $ 100,242 $ 293,389 $ — $ 393,631 Other revenues — — 3,237 — 3,237 Total revenues — 100,242 296,626 — 396,868 Costs and expenses: Lease operating — 14,656 89,529 (431 ) 103,754 Pipeline operating — — 2,114 — 2,114 Exploration — 466 9,334 — 9,800 Production and ad valorem taxes — 8,021 15,603 — 23,624 Depreciation, depletion and amortization — 34,843 103,829 — 138,672 Impairment of proved oil and natural gas properties — 4,250 24,621 — 28,871 Incentive unit compensation expense — 9,510 — — 9,510 General and administrative — 19,525 39,721 431 59,677 Accretion of asset retirement obligations — 487 4,522 — 5,009 (Gain) loss on commodity derivatives — (10,500 ) (24,405 ) — (34,905 ) (Gain) loss on sale of properties — (2 ) (9,759 ) — (9,761 ) Other, net — 459 43 — 502 Total costs and expenses — 81,715 255,152 — 336,867 Operating income (loss) — 18,527 41,474 — 60,001 Other income (expense): Interest expense, net — (8,164 ) (25,074 ) — (33,238 ) Equity earnings from subsidiaries — (16,331 ) — 16,331 — Other, net — 456 (115 ) — 341 Total other income (expense) — (24,039 ) (25,189 ) 16,331 (32,897 ) Income before income taxes — (5,512 ) 16,285 16,331 27,104 Income tax benefit (expense) — — (107 ) — (107 ) Net income (loss) — (5,512 ) 16,178 16,331 26,997 Net income (loss) attributable to noncontrolling interest — — 104 (2,805 ) (2,701 ) Net income (loss) attributable to Memorial Resource Development Corp. $ — $ (5,512.00 ) $ 16,074 $ 19,136 $ 29,698
Condensed Consolidating Statements of Cash Flows	Three Months Ended March 31, 2015 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated (In thousands) Net cash provided by (used in) operating activities $ 16,404 $ 82,434 $ 71,963 $ 1,015 $ 171,816 Cash flows from investing activities: Acquisitions of oil and natural gas properties — — (3,305 ) — (3,305 ) Additions to oil and gas properties — (86,619 ) (74,375 ) — (160,994 ) Additons to restricted investments — — (1,426 ) — (1,426 ) Additions to other property and equipment (1,687 ) (260 ) — — (1,947 ) Investment in subsidiaries (5,580 ) — — 5,580 — Distribution from subsidiaries 78,076 — — (78,076 ) — Net cash used in investing activities 70,809 (86,879 ) (79,106 ) (72,496 ) (167,672 ) Cash flows from financing activities: Advances on revolving credit facility 104,000 — 166,000 — 270,000 Payments on revolving credit facility (143,000 ) — (5,000 ) — (148,000 ) Repayment of senior notes — — (2,914 ) — (2,914 ) Deferred finance costs — — (10 ) — (10 ) Capital contributions — 3,668 1,912 (5,580 ) — Distribution to equity owners — — (46,315 ) 46,315 — Distribution to noncontrolling interests — — — (46,239 ) (46,239 ) Distributions to MRD — — (78,000 ) 78,000 — MRD equity repurchases (50,000 ) — — — (50,000 ) MEMP equity repurchases — — (28,420 ) — (28,420 ) Other — — (7 ) — (7 ) Net cash provided by financing activities (89,000 ) 3,668 7,246 72,496 (5,590 ) Net change in cash and cash equivalents (1,787 ) (777 ) 103 1,015 (1,446 ) Cash and cash equivalents, beginning of period 2,241 3,762 970 (1,015 ) 5,958 Cash and cash equivalents, end of period $ 454 $ 2,985 $ 1,073 $ — $ 4,512 Three Months Ended March 31, 2014 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Combined & Consolidated (In thousands) Net cash provided by (used in) operating activities $ — $ 51,864 $ 52,077 $ — $ 103,941 Cash flows from investing activities: Acquisitions of oil and natural gas properties — — (173,000 ) — (173,000 ) Additions to oil and gas properties — (75,227 ) (58,973 ) — (134,200 ) Additons to restricted investments — — (826 ) — (826 ) Additions to other property and equipment — (31 ) — — (31 ) Investment in subsidiaries — (4,146 ) — 4,146 — Distribution from subsidiaries — 4,993 — (4,993 ) — Other — (3 ) (301 ) — (304 ) Net cash used in investing activities — (74,414 ) (233,100 ) (847 ) (308,361 ) Cash flows from financing activities: — Advances on revolving credit facility — 108,000 235,000 — 343,000 Payments on revolving credit facility — (40,000 ) (39,000 ) — (79,000 ) Deferred finance costs — (895 ) (267 ) — (1,162 ) Capital contributions — — 4,146 (4,146 ) — Contributions related to sale of assets to NGP affiliate — — 1,165 — 1,165 Distribution to equity owners — — (36,078 ) 36,078 — Distribution to noncontrolling interests — — — (31,085 ) (31,085 ) Distribution related to assets aquired from NGP affiliates — (63,389 ) (3,304 ) — (66,693 ) Other — — (7 ) — (7 ) Net cash provided by financing activities — 3,716 161,655 847 166,218 Net change in cash and cash equivalents — (18,834 ) (19,368 ) — (38,202 ) Cash and cash equivalents, beginning of period 48,619 29,102 77,721 Cash and cash equivalents, end of period $ — $ 29,785 $ 9,734 $ — $ 39,519	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 restricted investments — — (3,976 ) — (3,976 ) Additions to other property and equipment (15,980 ) (989 ) (98 ) — (17,067 ) Investment in subsidiaries (696,489 ) — — 696,489 — Distribution 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 facilities 1,174,000 126,800 1,446,000 — 2,746,800 Payments on revolving credit facilities (991,000 ) (329,900 ) (1,137,000 ) — (2,457,900 ) Proceeds from the issuances of senior notes 600,000 — 492,425 — 1,092,425 Redemption of senior notes (351,808 ) — — — (351,808 ) Redemption of second lien credit facility — (328,282 ) — — (328,282 ) Deferred financing costs (18,779 ) (61 ) (11,494 ) — (30,334 ) Proceeds from initial public offering 408,500 — — — 408,500 Costs incurred in conjunction with initial public offering (28,373 ) — — — (28,373 ) Proceeds from MEMP public offering — — 553,288 — 553,288 Costs incurred in conjunction with MEMP public 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 ) Purchase of additional interests in subsidiaries (3,292 ) — — — (3,292 ) Capital contributions — 686,623 9,866 (696,489 ) — Contributions from NGP affiliates related to sale of properties — — 1,165 — 1,165 Distribution to equity owners — (15,000 ) (222,633 ) 237,633 — Distributions to MRD Holdco (17,207 ) (39,520 ) (3,076 ) (59,803 ) Distributions to noncontrolling interests — — — (149,084 ) (149,084 ) Distribution to NGP affiliates related to purchase of assets — (63,389 ) (3,304 ) — (66,693 ) 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 ) Equity repurchases — — — — — 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 December 31, 2012 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidation (In thousands) Net cash provided by (used in) operating activities $ — $ 56,443 $ 183,961 $ — $ 240,404 Cash flows from investing activities: Acquisitions of oil and natural gas properties — (83,055 ) (277,623 ) — (360,678 ) Additions to oil and gas properties — (85,431 ) (187,903 ) — (273,334 ) Additions to restricted investments — — (4,599 ) — (4,599 ) Additions to other property and equipment — (926 ) (1,748 ) — (2,674 ) Investment in subsidiaries — (718 ) — 718 — Distribution from subsidiaries — 22,979 — (22,979 ) — Change in restricted cash — (3 ) — — (3 ) Proceeds from the sale of oil and gas properties — — 34,521 — 34,521 Other — — 29 — 29 Net cash used in investing activities — (147,154 ) (437,323 ) (22,261 ) (606,738 ) Cash flows from financing activities: Advances on revolving credit facilities — 122,950 496,500 — 619,450 Payments on revolving credit facilities — (24,750 ) (226,819 ) — (251,569 ) Deferred financing costs — (1,109 ) (2,392 ) — (3,501 ) Capital contributions — — 718 (718 ) — Contributions from previous owners — — 44,072 — 44,072 Contributions from NGP affiliates related to sale of properties — — 45,158 — 45,158 Proceeds from MEMP public offering — — 202,573 — 202,573 Costs incurred in conjunction with MEMP public offering — — (8,268 ) — (8,268 ) Distributions to equity owners — — (38,187 ) 38,187 — Distribution to NGP affiliates related to purchase of assets — — (242,174 ) — (242,174 ) Distributions to noncontrolling interests — — — (15,208 ) (15,208 ) Distributions made by previous owners — (2,282 ) (26,490 ) — (28,772 ) Net cash provided by financing activities — 94,809 244,691 22,261 361,761 Net change in cash and cash equivalents — 4,098 (8,671 ) — (4,573 ) Cash and cash equivalents, beginning of period — 14,525 39,439 — 53,964 Cash and cash equivalents, end of period $ — $ 18,623 $ 30,768 $ — $ 49,391

Quarterly Financial Informati46

Quarterly Financial Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Schedule of Quarterly Financial Information	The following tables present selected quarterly financial data for the periods indicated. Earnings per share are computed independently for each of the quarters presented and the sum of the quarterly earnings per share may not necessarily equal the total for the year. As discussed in Note 4 and Note 12, we recorded oil and natural gas property impairments and incentive unit compensation expense, respectively, during 2014, which impacted the comparability between the periods presented below. First Quarter Second Quarter Third Quarter Fourth Quarter For the Year Ended December 31, 2014 (In thousands, except per share amounts) Revenues $ 190,828 $ 236,564 $ 245,493 $ 226,460 Operating income (loss) 10,605 (993,256 ) 174,201 444,776 Net income (loss) (23,516 ) (1,053,443 ) 112,037 328,859 Net income (loss) attributable to noncontrolling interest (31,888 ) (105,094 ) 102,109 161,661 Net income (loss) attributable to Memorial Resource 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 First Quarter Second Quarter Third Quarter Fourth Quarter For the Year Ended December 31, 2013 (In thousands, except per share amounts) Revenues $ 122,181 $ 147,045 $ 153,515 $ 152,282 Operating income (loss) 9,521 90,327 117,797 4,411 Net income (loss) 180 78,158 95,962 (22,968 ) Net income (loss) attributable to noncontrolling interest (4,069 ) 34,975 11,235 7,689 Net income (loss) attributable to Memorial Resource Development Corp. 4,249 43,183 84,727 (30,657 ) Net income (loss) allocated to members 2,597 35,278 84,754 (31,917 ) Net income (loss) allocated to previous owners 1,652 7,905 (27 ) 1,260

Supplemental Oil and Gas Info47

Supplemental Oil and Gas Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2014
Extractive Industries [Abstract]
Capitalized Costs Relating to Oil and Natural Gas Producing Activities	The total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depreciation, depletion and amortization is as follows at the dates indicated. For the Year Ended December 31, 2014 2013 2012 (In thousands) MRD Segment: Evaluated oil and natural gas properties $ 1,268,873 $ 897,511 $ 742,404 Unevaluated oil and natural gas properties 48,229 44,453 24,629 Accumulated depletion, depreciation, and amortization (276,837 ) (160,620 ) (122,712 ) Subtotal $ 1,040,265 $ 781,344 $ 644,321 MEMP Segment: Evaluated oil and natural gas properties (1) $ 3,329,338 $ 2,077,344 $ 1,849,457 Support equipment and facilities 185,997 5,910 5,760 Unevaluated oil and natural gas properties — 1,960 6,964 Accumulated depletion, depreciation, and amortization (1) (1,057,398 ) (462,742 ) (345,579 ) Subtotal $ 2,457,937 $ 1,622,472 $ 1,516,602 Consolidated: Evaluated oil and natural gas properties (1) $ 4,598,211 $ 2,974,855 $ 2,591,861 Support equipment and facilities 185,997 5,910 5,760 Unevaluated oil and natural gas properties 48,229 46,413 31,593 Accumulated depletion, depreciation, and amortization (1) (1,334,235 ) (623,362 ) (468,291 ) Total $ 3,498,202 $ 2,403,816 $ 2,160,923 (1) Amounts do not include costs for SPBPC and related support equipment.
Costs Incurred for Property Acquisitions, Exploration and Development	Costs incurred in property acquisition, exploration and development activities were as follows for the periods indicated: For the Year Ended December 31, 2014 2013 2012 (In thousands) MRD Segment: Property acquisition costs, proved $ 74,490 $ 56,108 $ 87,857 Property acquisition costs, unproved 24,310 19,975 5,293 Exploration and extension well costs 209,532 13,313 212 Development 181,026 191,350 99,028 Subtotal $ 489,358 $ 280,746 $ 192,390 MEMP Segment: Property acquisition costs, proved $ 983,796 $ 37,786 $ 278,246 Exploration and extension well costs — — 42,430 Development (1) 306,751 164,920 99,395 Subtotal $ 1,290,547 $ 202,706 $ 420,071 Consolidated: Property acquisition costs, proved $ 1,058,286 $ 93,894 $ 366,103 Property acquisition costs, unproved 24,310 19,975 5,293 Exploration and extension well costs 209,532 13,313 42,642 Development (1) 487,777 356,270 198,423 Total $ 1,779,905 $ 483,452 $ 612,461 (1) Amounts do not include costs for SPBPC and related support equipment.
Weighted Average Benchmark Product Prices	The weighted-average benchmark product prices used for valuing the reserves are based upon the average of the first-day-of-the-month price for each month within the period January through December of each year presented: 2014 2013 2012 Oil ($/Bbl) West Texas Intermediate (1) $ 91.48 $ 93.42 $ 91.33 NGL ($/Bbl) West Texas Intermediate (1) $ 91.48 $ 93.42 $ 91.75 Natural Gas ($/Mmbtu) Henry Hub (2) $ 4.35 $ 3.67 $ 2.75 (1) The unweighted average West Texas Intermediate price was adjusted by lease for quality, transportation fees, and a regional price differential. (2) The unweighted average Henry Hub price was adjusted by lease for energy content, compression charges, transportation fees, and regional price differentials.
Reserve Quantity Information	The following tables set forth estimates of the net reserves as of December 31, 2014, 2013, and 2012 respectively: For the Year Ended December 31, 2014 Oil (MBbls) Gas (MMcf) NGLs (MBbls) Equivalent (MMcfe) Proved developed and undeveloped reserves: Beginning of the year 50,459 1,409,393 71,422 2,140,683 Extensions and discoveries 2,674 196,250 10,587 275,815 Purchase of minerals in place 69,364 35,222 23,598 592,996 Production (4,042 ) (105,295 ) (4,363 ) (155,718 ) Sales of minerals in place (623 ) (10,815 ) (950 ) (20,253 ) Revision of previous estimates (5,659 ) 215,801 11,773 252,467 End of year (1) 112,173 1,740,556 112,067 3,085,990 Proved developed reserves: Beginning of year 25,667 651,345 29,863 984,535 End of year 58,431 772,578 55,463 1,455,934 Proved undeveloped reserves: Beginning of year 24,792 758,048 41,559 1,156,148 End of year 53,742 967,978 56,604 1,630,056 (1) Includes reserves of 1,452,457 MMcfe attributable to noncontrolling interests. For the Year Ended December 31, 2013 Oil (MBbls) Gas (MMcf) NGLs (MBbls) Equivalent (MMcfe) Proved developed and undeveloped reserves: Beginning of the year 51,042 1,343,818 70,818 2,074,982 Extensions and discoveries 7,449 190,744 10,065 295,832 Purchase of minerals in place 330 48,109 1,275 57,737 Production (2,429 ) (70,016 ) (3,089 ) (103,122 ) Sales of minerals in place (599 ) (14,137 ) (1,573 ) (27,169 ) Revision of previous estimates (5,334 ) (89,125 ) (6,074 ) (157,577 ) End of year (1) 50,459 1,409,393 71,422 2,140,683 Proved developed reserves: Beginning of year 27,597 622,381 28,268 957,573 End of year 25,667 651,345 29,863 984,535 Proved undeveloped reserves: Beginning of year 23,445 721,437 42,550 1,117,409 End of year 24,792 758,048 41,559 1,156,148 (1) Includes reserves of 966,335 MMcfe attributable to noncontrolling interests and previous owners. For the Year Ended December 31, 2012 Oil (MBbls) Gas (MMcf) NGLs (MBbls) Equivalent (MMcfe) Proved developed and undeveloped reserves: Beginning of the year 37,984 1,509,086 68,076 2,145,454 Extensions and discoveries 8,190 61,888 3,831 134,010 Purchase of minerals in place 12,436 141,732 8,974 270,190 Production (1,888 ) (53,875 ) (1,643 ) (75,056 ) Sales of minerals in place (4,218 ) (4,942 ) — (30,250 ) Revision of previous estimates (1,462 ) (310,071 ) (8,420 ) (369,366 ) End of year (1) 51,042 1,343,818 70,818 2,074,982 Proved developed reserves: Beginning of year 21,439 604,988 17,659 839,577 End of year 27,597 622,381 28,268 957,573 Proved undeveloped reserves: Beginning of year 16,545 904,098 50,417 1,305,877 End of year 23,445 721,437 # 42,550 1,117,409 (1) Includes reserves of 605,680 MMcfe attributable to noncontrolling interests and previous owners.
Discounted Future Net Cash Flows	Standardized Measure The standardized measure of discounted future net cash flows is as follows: For the Year Ended December 31, 2014 2013 2012 (In thousands) Future cash inflows $ 21,505,195 $ 12,614,999 $ 11,432,968 Future production costs (5,841,650 ) (4,306,398 ) (3,513,843 ) Future development costs (2,665,833 ) (2,038,803 ) (1,681,721 ) Future income tax expense (1) (1,789,031 ) — — Future net cash flows for estimated timing of cash flows 11,208,681 6,269,798 6,237,404 10% annual discount for estimated timing of cash flows (6,486,539 ) (3,192,733 ) (3,326,893 ) Standardized measure of discounted future net cash flows (2) $ 4,722,142 $ 3,077,065 $ 2,910,511 (1) Our predecessor was a pass through entity and was subject to the Texas margin tax which has a maximum effective rate of 0.7% of gross income apportioned to Texas. Due to immateriality, we have excluded the impact of this tax for the years ended December 31, 2013 and 2012. (2) Includes $2,756,848, $1,529,216 and $1,113,453 attributable to both noncontrolling interests and previous owners for the years ended December 31, 2014, 2013 and 2012, respectively.
Summary of the Changes in the Standardized Measure of Future Net Cash Flows	The following is a summary of the changes in the standardized measure of discounted future net cash flows for the proved oil and natural gas reserves during each of the years in the three year period ended December 31, 2014: For the Year Ended December 31, 2014 2013 2012 (In thousands) Beginning of year $ 3,077,065 $ 2,910,511 $ 2,885,485 Sale of oil and natural gas produced, net of production costs (687,717 ) (430,964 ) (267,339 ) Purchase of minerals in place 1,558,759 74,337 474,337 Sale of minerals in place (47,791 ) (54,091 ) (154,963 ) Extensions and discoveries 697,931 437,427 393,102 Changes in income taxes, net (1,058,815 ) — 1,947 Changes in prices and costs 196,530 (85,731 ) (733,962 ) Previously estimated development costs incurred 480,466 261,787 130,750 Net changes in future development costs (201,177 ) (17,514 ) (68,471 ) Revisions of previous quantities 665,089 (327,926 ) (267,375 ) Accretion of discount 307,707 287,535 288,743 Change in production rates and other (265,905 ) 21,694 228,257 End of year $ 4,722,142 $ 3,077,065 $ 2,910,511

Organization and Basis of Pre48

Organization and Basis of Presentation - Additional Information (Detail)

Jul. 16, 2014

Jun. 18, 2014USD ($)$ / sharesshares

Oct. 02, 2013USD ($)

Mar. 28, 2013USD ($)

Feb. 28, 2015USD ($)

May. 31, 2014USD ($)

Jul. 31, 2013USD ($)

May. 31, 2012USD ($)

Apr. 30, 2012USD ($)

Mar. 31, 2015Segmentshares

Dec. 31, 2014USD ($)Segmentshares

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

190,776,618

193,435,414

0

Senior PIK Toggle Notes, Redemption date

Jul. 16, 2014

Number of reportable business segments | Segment

2

2

Business acquisition purchase price

$ 19,800,000

MEMP [Member]

Consolidation And Basis Of Presentation [Line Items]

Revolving credit facility

$ 2,000,000,000

Business acquisition purchase price

$ 78,000,000

Net equity deemed contribution (distribution) related to net assets transferred

172,900,000

Net book value of assets transferred to MEMP segment

250,800,000

Cash allocated to limited partners

77,900,000

Tanos Energy LLC [Member]

Consolidation And Basis Of Presentation [Line Items]

Business acquisition purchase price

$ 77,400,000

$ 18,500,000

East Texas and Non Core Louisiana [Member]

Consolidation And Basis Of Presentation [Line Items]

Business acquisition purchase price

$ 78,000,000

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%

99.90%

General Partner [Member]

Consolidation And Basis Of Presentation [Line Items]

Partnership ownership percentage

0.10%

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

Dec. 15, 2018

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%

Business acquisition purchase price

$ 27,000,000

Classic GP[Member]

Consolidation And Basis Of Presentation [Line Items]

Ownership interest percentage

100.00%

Black Diamond [Member]

Consolidation And Basis Of Presentation [Line Items]

Ownership interest percentage

100.00%

Beta Operating [Member]

Consolidation And Basis Of Presentation [Line Items]

Ownership interest percentage

100.00%

Memorial Resource Finance Corp [Member]

Consolidation And Basis Of Presentation [Line Items]

Ownership interest percentage

100.00%

MRD Operating [Member]

Consolidation And Basis Of Presentation [Line Items]

Ownership interest percentage

100.00%

100.00%

Memorial Production Partners GP LLC [Member]

Consolidation And Basis Of Presentation [Line Items]

Ownership interest percentage

100.00%

MEMP GP & MEMP IDRs [Member]

Consolidation And Basis Of Presentation [Line Items]

Ownership interest percentage

50.00%

Summary of Significant Accoun49

Summary of Significant Accounting Policies - Additional Information (Detail) - USD ($)	1 Months Ended	3 Months Ended		12 Months Ended
	Feb. 28, 2015	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jun. 30, 2014
Summary Of Significant Accounting Policies [Line Items]
Capitalized exploratory drilling costs				$ 0	$ 0	$ 0
Impairment of proved oil and natural gas properties		$ 251,347,000		432,116,000	6,600,000	28,871,000
Amortization expense, including write-offs of debt issuance costs		2,515,000	$ 1,899,000	7,436,000	8,343,000	3,584,000
Capitalized interest				$ 7,300,000	0	0
Minimum percentage likelihood of tax benefit to be realized				50.00%
Unrecognized tax benefits		0		$ 0	0	$ 0
Unrecognized tax benefits that would affect effective tax rate				0
Interest or penalties recognized in consolidated statements of operations				0
Interest or penalties recognized in consolidated balance sheets				$ 0
Deferred income tax liabilities, net		$ 28,000,000					$ 43,300,000
Effective tax rate		(67.50%)
Federal statutory income tax rate		35.00%		35.00%
Percentage of reduction to effective tax rate related to pass-through entities		84.00%
Percentage of reduction to effective tax rate related to non-deductible incentive compensation		10.60%
Percentage of effective tax rate related to state income tax provision, net of federal benefit		8.10%
Deferred tax liabilities		$ 111,790,000		$ 95,017,000	$ 3,106,000
MEMP [Member]
Summary Of Significant Accounting Policies [Line Items]
Impairment of proved oil and natural gas properties				407,540,000
Deferred tax liabilities				$ 29,200,000
Deferred income tax benefit	$ 1,200,000
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 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, 2014	Dec. 31, 2013	Dec. 31, 2012
Consolidated & Combined [Member] | Energy Transfer Equity, LP. and subsidiaries [Member]
Entity Wide Revenue Major Customer [Line Items]
Individual customers each accounted for 10% or more of total reported revenues		33.00%	35.00%	13.00%
MRD [Member] | Energy Transfer Equity, LP. and subsidiaries [Member]
Entity Wide Revenue Major Customer [Line Items]
Individual customers each accounted for 10% or more of total reported revenues		85.00%	86.00%	52.00%
MRD [Member] | Sunoco Inc [Member]
Entity Wide Revenue Major Customer [Line Items]
Individual customers each accounted for 10% or more of total reported revenues	[1]			20.00%
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		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	[2]	12.00%	14.00%	12.00%
MEMP [Member] | ConocoPhillips [Member]
Entity Wide Revenue Major Customer [Line Items]
Individual customers each accounted for 10% or more of total reported revenues				13.00%
[1]	Sunoco, Inc. became a subsidiary of Energy Transfer Equity, L.P. in October 2012.
[2]	Phillips 66 was a subsidiary of ConocoPhillips through April 30, 2012. Accordingly, any revenues generated from Phillips 66 prior to May 1, 2012 were reported under ConocoPhillips.

Summary of Significant Accoun51

Summary of Significant Accounting Policies - Schedule of Accrued Liabilities (Detail) - USD ($) $ in Thousands	Mar. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Accounting Policies [Abstract]
Accrued capital expenditures	$ 84,939	$ 80,350	$ 48,579
Accrued lease operating expense	17,996	16,403	13,240
Accrued general and administrative expenses	10,098	8,516	14,485
Accrued ad valorem and production taxes	10,390	8,870	3,541
Accrued interest payable	36,815	24,797	11,934
Accrued environmental	1,309	2,092	577
Accrued current deferred income taxes	51,937	51,929	382
Other miscellaneous, including operator advances	4,185	6,043	5,392
Accrued liabilities	$ 217,669	$ 199,000	$ 98,130

Summary of Significant Accoun52

Summary of Significant Accounting Policies - Schedule of Supplemental Cash flow (Detail) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Supplemental cash flows:
Cash paid for interest, net of amounts capitalized			$ 130,732	$ 61,140	$ 23,525
Income tax paid	$ 2,055		838	168	22
Noncash investing and financing activities:
Change in capital expenditures in payables and accrued liabilities	4,589	$ 10,668	31,771	41,017	17,158
Assumptions of asset retirement obligations related to properties acquired or drilled	$ 39	$ 433	5,420	4,227	7,962
Distributions to noncontrolling interests			0	0	47
Repurchase of equity under repurchase program			3,425	0	0
Accounts receivable related to acquisitions			9,569	0	0
Natural Gas Partners [Member]
Noncash investing and financing activities:
Contribution of oil and gas properties from NGP affiliate			0	0	6,893
Accrued distribution to NGP affiliates related to Cinco Group acquisitions			0	4,352	0
Contribution related to sale of assets to NGP affiliate - restricted cash			0	0	2,013
MEMP [Member]
Noncash investing and financing activities:
Accrued equity offering costs			$ 0	$ 0	$ 171

Acquisitions and Divestitures -

Acquisitions and Divestitures - Acquisition Related Costs (Detail) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Business Acquisition [Line Items]
Acquisition related costs	$ 2,580	$ 2,462	$ 6,668	$ 8,313	$ 4,538
General and administrative expense [Member]
Business Acquisition [Line Items]
Acquisition related costs	$ 2,580	$ 2,462	$ 6,668	$ 8,313	$ 4,538

Acquisitions and Divestitures54

Acquisitions and Divestitures - Additional Information (Detail) - USD ($)

Apr. 17, 2015

Dec. 30, 2014

Jul. 01, 2014

May. 09, 2014

Mar. 25, 2014

May. 10, 2013

Apr. 30, 2013

Jan. 01, 2013

Sep. 28, 2012

Sep. 18, 2012

Jul. 11, 2012

May. 01, 2012

Jul. 31, 2012

Dec. 31, 2014

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Business Acquisition And Divestiture [Line Items]

Proceeds from the sale of oil and natural gas properties

$ 6,700,000

$ 155,712,000

$ 34,521,000

Subsequent Event [Member] | Rockies Divestiture [Member]

Business Acquisition And Divestiture [Line Items]

Proceeds from divestitures

$ 13,500,000

Subsidiaries [Member]

Business Acquisition And Divestiture [Line Items]

Proceeds from divestitures

3,300,000

Gain (loss) on sale of oil and gas properties

(100,000)

Series of Individually Immaterial Business Acquisitions [Member]

Business Acquisition And Divestiture [Line Items]

Payments to acquire oil and gas properties and leases

10,200,000

WildHorse Resources, LLC [Member]

Business Acquisition And Divestiture [Line Items]

Payments to acquire oil and gas properties and leases

$ 67,100,000

Northern Oklahoma [Member]

Business Acquisition And Divestiture [Line Items]

Proceeds from divestitures

$ 7,600,000

Gain (loss) on sale of oil and gas properties

$ (3,200,000)

Garza County, Texas [Member]

Business Acquisition And Divestiture [Line Items]

Proceeds from divestitures

$ 26,100,000

Gain (loss) on sale of oil and gas properties

$ 7,600,000

Ector County, Texas [Member]

Business Acquisition And Divestiture [Line Items]

Proceeds from divestitures

$ 4,700,000

Gain (loss) on sale of oil and gas properties

$ 2,200,000

Terryville Acquisition [Member]

Business Acquisition And Divestiture [Line Items]

Payments to acquire oil and gas properties and leases

$ 71,900,000

$ 24,000,000

Wyoming Acquisition [Member]

Business Acquisition And Divestiture [Line Items]

Payments to acquire oil and gas properties and leases

$ 906,100,000

Business acquisition, revenues

72,000,000

Business acquisition, earnings

$ 22,900,000

Eagle Ford Acquisition [Member]

Business Acquisition And Divestiture [Line Items]

Payments to acquire oil and gas properties and leases

$ 168,100,000

Business acquisition, revenues

36,500,000

Business acquisition, earnings

$ 16,300,000

Percentage of leasehold interest acquired

30.00%

East Texas Acquisition and Rockies Acquisition [Member]

Business Acquisition And Divestiture [Line Items]

Payments to acquire oil and gas properties and leases

29,400,000

Propel Energy [Member]

Business Acquisition And Divestiture [Line Items]

Payments to acquire oil and gas properties and leases

9,300,000

Tanos [Member] | Natural Gas Pipe Lines [Member]

Business Acquisition And Divestiture [Line Items]

Gain (loss) on sale of oil and gas properties

$ 1,400,000

Period for drilling any new wells

3 years

Contingent consideration related to sale of natural gas pipeline

$ 400,000

Tanos [Member] | Natural Gas Pipe Lines [Member] | Minimum [Member]

Business Acquisition And Divestiture [Line Items]

Proceeds from divestitures

1,500,000

Tanos [Member] | Natural Gas Pipe Lines [Member] | Maximum [Member]

Business Acquisition And Divestiture [Line Items]

Proceeds from divestitures

$ 2,000,000

Tanos [Member] | Oil And Natural Gas Properties [Member]

Business Acquisition And Divestiture [Line Items]

Proceeds from divestitures

2,900,000

Tanos [Member] | Non Operated Oil And Natural Gas Properties [Member]

Business Acquisition And Divestiture [Line Items]

Gain (loss) on sale of oil and gas properties

1,400,000

Black Diamond [Member]

Business Acquisition And Divestiture [Line Items]

Proceeds from divestitures

$ 33,000,000

Gain (loss) on sale of oil and gas properties

(6,800,000)

Net book value of oil and gas properties

$ 39,800,000

BlueStone Natural Resources Holdings, LLC [Member]

Business Acquisition And Divestiture [Line Items]

Gain (loss) on sale of oil and gas properties

89,500,000

Proceeds from the sale of oil and natural gas properties

$ 117,900,000

Undisclosed Seller Acquisition [Member]

Business Acquisition And Divestiture [Line Items]

Payments to acquire oil and gas properties and leases

$ 112,100,000

Business acquisition, revenues

22,100,000

Business acquisition, earnings

9,200,000

Goodrich Acquisition [Member]

Business Acquisition And Divestiture [Line Items]

Payments to acquire oil and gas properties and leases

$ 90,400,000

Business acquisition, revenues

4,600,000

Business acquisition, earnings

2,000,000

Texas And New Mexico [Member]

Business Acquisition And Divestiture [Line Items]

Payments to acquire oil and gas properties and leases

147,900,000

Menemsha Acquisition [Member]

Business Acquisition And Divestiture [Line Items]

Payments to acquire oil and gas properties and leases

$ 74,700,000

Business acquisition, revenues

4,900,000

Business acquisition, earnings

$ 900,000

Acquisitions and Divestitures55

Acquisitions and Divestitures - Summary of Fair Value Assessment of Assets Acquired and Liabilities Assumed (Detail) - USD ($) $ in Thousands	Dec. 30, 2014	Jul. 01, 2014	Mar. 25, 2014	Sep. 06, 2013	Aug. 30, 2013	Apr. 30, 2013	Dec. 31, 2012	Sep. 28, 2012	Jul. 31, 2012	May. 01, 2012
Louisiana [Member]
Business Acquisition [Line Items]
Oil and gas properties	$ 72,141					$ 68,887
Asset retirement obligations	(271)					(1,789)
Total identifiable net assets	$ 71,870					$ 67,098
East Texas Acquisition [Member]
Business Acquisition [Line Items]
Oil and gas properties				$ 9,974
Asset retirement obligations				(78)
Total identifiable net assets				$ 9,896
Rockies Acquisition [Member]
Business Acquisition [Line Items]
Oil and gas properties					$ 20,744
Asset retirement obligations					(1,163)
Accrued liabilities					(118)
Total identifiable net assets					$ 19,463
Undisclosed Seller Acquisition [Member]
Business Acquisition [Line Items]
Oil and gas properties										$ 115,633
Asset retirement obligations										(1,592)
Revenue Payable										(1,602)
Accrued liabilities										(297)
Total identifiable net assets										$ 112,142
Goodrich Acquisition [Member]
Business Acquisition [Line Items]
Oil and gas properties								$ 91,187
Prepaid expenses and other current assets								425
Asset retirement obligations								(161)
Revenue Payable								(875)
Accrued liabilities								(153)
Total identifiable net assets								$ 90,423
Menemsha Acquisition [Member]
Business Acquisition [Line Items]
Oil and gas properties									$ 75,114
Asset retirement obligations									(408)
Total identifiable net assets									$ 74,706
Other Acquisitions [Member]
Business Acquisition [Line Items]
Oil and gas properties							$ 77,764
Asset retirement obligations							(4,558)
Total identifiable net assets							$ 73,206
MEMP [Member] | Eagle Ford Acquisition [Member]
Business Acquisition [Line Items]
Oil and gas properties			$ 168,606
Asset retirement obligations			(285)
Accrued liabilities			(250)
Total identifiable net assets			$ 168,071
MEMP [Member] | Wyoming Acquisition [Member]
Business Acquisition [Line Items]
Oil and gas properties		$ 930,168
Asset retirement obligations		(3,980)
Revenue Payable		(375)
Accrued liabilities		(19,693)
Total identifiable net assets		$ 906,120

Acquisitions and Divestitures56

Acquisitions and Divestitures - Unaudited Pro Forma Results of Operations (Detail) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Business Combinations [Abstract]
Revenues	$ 252,019	$ 990,544	$ 761,443	$ 431,060
Net income (loss)	$ (14,817)	$ (602,044)	$ 257,839	$ 40,940
Basic earnings per share		$ (4.08)
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	Mar. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Assets:
Fair value of derivative asset	$ 1,022,716	$ 847,064	$ 105,938
Liabilities:
Fair value of derivative liability	91,358	74,928	63,824
Significant Other Observable Inputs (Level 2) [Member]
Assets:
Fair value of derivative asset	1,022,716	847,064	105,938
Liabilities:
Fair value of derivative liability	91,358	74,928	63,824
Commodity derivatives [Member]
Assets:
Fair value of derivative asset	1,022,706	845,759	105,054
Liabilities:
Fair value of derivative liability	87,809	71,639	58,234
Commodity derivatives [Member] | Significant Other Observable Inputs (Level 2) [Member]
Assets:
Fair value of derivative asset	1,022,706	845,759	105,054
Liabilities:
Fair value of derivative liability	87,809	71,639	58,234
Interest rate derivatives [Member]
Assets:
Fair value of derivative asset	10	1,305	884
Liabilities:
Fair value of derivative liability	3,549	3,289	5,590
Interest rate derivatives [Member] | Significant Other Observable Inputs (Level 2) [Member]
Assets:
Fair value of derivative asset	10	1,305	884
Liabilities:
Fair value of derivative liability	$ 3,549	$ 3,289	$ 5,590

Fair Value Measurements of Fi58

Fair Value Measurements of Financial Instruments - Additional Information (Detail) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment of proved oil and natural gas properties	$ 251,347		$ 432,116	$ 6,600	$ 28,871
Carrying value of properties after impairment charges	3,366,600		3,537,656	$ 2,419,704
MEMP [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment of proved oil and natural gas properties			407,540
MEMP [Member] | East Texas, Wyoming and Colorado [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment of proved oil and natural gas properties	251,300	$ 0
Carrying value of properties after impairment charges	$ 157,600
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 oil and gas properties after impairment			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		20,900
Carrying value of oil and gas properties after impairment			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 oil and gas properties after impairment			71,200
MEMP [Member] | Elkhorn and Canyon Fields (Member)
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment of proved oil and natural gas properties					$ 8,000
MRD [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment of proved oil and natural gas properties			$ 24,600

Risk Management and Derivativ59

Risk Management and Derivative Instruments - Additional Information (Detail) - USD ($)	1 Months Ended	3 Months Ended	12 Months Ended
	Feb. 28, 2015	Mar. 31, 2015	Dec. 31, 2014	Jul. 01, 2014
Derivative Instruments, Gain (Loss) [Line Items]
Conditional rights of set-off under ISDA Master Agreement reduce the maximum amount of loss due to credit risk		$ 81,800,000	$ 99,200,000
Effect netting arrangements, counterparty exposure		248,700,000	155,800,000
Derivative asset		330,500,000	255,000,000
Cash settlement receipt			6,100,000
Cash collateral received or pledged		0	0
Deferred premiums		1,800,000
Interest rate swaps [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Aggregate termination amount paid to counterparties				$ 700,000
Single Counterparty [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Effect netting arrangements, counterparty exposure		113,400,000	109,700,000
MEMP [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Conditional rights of set-off under ISDA Master Agreement reduce the maximum amount of loss due to credit risk		272,600,000	207,300,000
Effect netting arrangements, counterparty exposure		328,400,000	309,800,000
Derivative asset		601,000,000	$ 517,100,000
Cash settlement receipt	$ 27,100,000
MRD [Member] | Single Counterparty [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Effect netting arrangements, counterparty exposure		$ 66,600,000

Risk Management and Derivativ60

Risk Management and Derivative Instruments - Schedule of Open Commodity Positions (Detail)	3 Months Ended	12 Months Ended
	Mar. 31, 2015MMBTU$ / MMBTU$ / bblbbl	Dec. 31, 2014MMBTU$ / MMBTU$ / bblbbl
2015 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	3,600,000	3,700,000
Weighted-average fixed price	4.15	4.15
2015 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | Collar contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	130,000	130,000
Weighted-average floor price	4	4
Weighted-average ceiling price	4.64	4.64
2015 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | Put Option [Member] | Purchased [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	3,366,667	3,000,000
Weighted-average fixed price	3.75	3.75
Weighted-average deferred premium	(0.33)	(0.33)
2015 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | TGT Z1 basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	3,480,000	1,730,000
2015 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | TGT Z1 basis swaps [Member] | Henry Hub [Member]
Derivative [Line Items]
Spread	(0.10)	(0.09)
2015 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | Call Option [Member | Written
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	2,625,000
Weighted-average sold strike price	3.75
Weighted-average deferred premium received	0.08
2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	3,061,181	2,605,278
Weighted-average fixed price	4.16	4.28
2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Collar contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	350,000	350,000
Weighted-average floor price	4.62	4.62
Weighted-average ceiling price	5.80	5.80
2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Call Spreads [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	80,000	80,000	[1]
Weighted-average sold strike price	5.25	5.25	[1]
Weighted-average bought strike price	6.75	6.75	[1]
2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Basis Swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	3,390,000	2,940,000
Spread	(0.12)	(0.12)
2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | NGPL TexOk basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	2,730,000	2,280,000
2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | NGPL TexOk basis swaps [Member] | Henry Hub [Member]
Derivative [Line Items]
Spread	(0.12)	(0.11)
2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | HSC basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	150,000	150,000
2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | HSC basis swaps [Member] | Henry Hub [Member]
Derivative [Line Items]
Spread	(0.08)	(0.08)
2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | CIG basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	210,000	210,000
2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | CIG basis swaps [Member] | Henry Hub [Member]
Derivative [Line Items]
Spread	(0.25)	(0.25)
2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | TETCO STX basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	300,000	300,000
2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | TETCO STX basis swaps [Member] | Henry Hub [Member]
Derivative [Line Items]
Spread	(0.09)	(0.09)
2015 [Member] | Crude Oil Derivative Contracts [Member] | MRD [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price | $ / bbl	91.67	91.67
Average Monthly Volume (Bbls) | bbl	45,000	46,500
2015 [Member] | Crude Oil Derivative Contracts [Member] | MRD [Member] | Collar contracts [Member]
Derivative [Line Items]
Weighted-average floor price | $ / bbl	85	85
Weighted-average ceiling price | $ / bbl	101.35	101.35
Average Monthly Volume (Bbls) | bbl	2,000	2,000
2015 [Member] | Crude Oil Derivative Contracts [Member] | MRD [Member] | Put Option [Member] | Purchased [Member]
Derivative [Line Items]
Weighted-average fixed price | $ / bbl	85
Weighted-average deferred premium | $ / bbl	(3.80)	(3.80)
Average Monthly Volume (Bbls) | bbl	30,333	26,000
Weighted-average fixed price | $ / bbl		85
2015 [Member] | Crude Oil Derivative Contracts [Member] | MRD [Member] | Call Option [Member | Written
Derivative [Line Items]
Average Monthly Volume (Bbls) | bbl	22,750
Weighted-average sold strike price | $ / bbl	85
Weighted-average deferred premium received | $ / bbl	0.48
2015 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price | $ / bbl	91.34	90.96
Average Monthly Volume (Bbls) | bbl	273,864	314,281
2015 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Collar contracts [Member]
Derivative [Line Items]
Weighted-average floor price | $ / bbl	80	80
Weighted-average ceiling price | $ / bbl	94	94
Average Monthly Volume (Bbls) | bbl	5,000	5,000
2015 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Basis Swaps [Member]
Derivative [Line Items]
Spread | $ / bbl	(7.07)	(7.07)
Average Monthly Volume (Bbls) | bbl	97,333	97,500
2015 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Midway-Sunset basis swaps [Member]
Derivative [Line Items]
Spread | $ / bbl	(9.73)
Average Monthly Volume (Bbls) | bbl	57,333	57,500
2015 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Midway-Sunset basis swaps [Member] | Brent [Member]
Derivative [Line Items]
Spread | $ / bbl		(9.73)
2015 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Midland Basis Swap [Member]
Derivative [Line Items]
Spread | $ / bbl	(3.25)
Average Monthly Volume (Bbls) | bbl	40,000	40,000
2015 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Midland Basis Swap [Member] | WTI [Member]
Derivative [Line Items]
Spread | $ / bbl		(3.25)
2015 [Member] | NGL Derivative Contracts [Member] | MRD [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price | $ / bbl	41.58	41.61
Average Monthly Volume (Bbls) | bbl	155,000	151,000
2015 [Member] | NGL Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price | $ / bbl	42.30	43.02
Average Monthly Volume (Bbls) | bbl	211,867	149,200
2016 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	2,570,000	2,570,000
Weighted-average fixed price	4.09	4.09
2016 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | Collar contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	1,100,000	1,100,000
Weighted-average floor price	4	4
Weighted-average ceiling price	4.71	4.71
2016 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | Put Option [Member] | Purchased [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	4,100,000	4,100,000
Weighted-average fixed price	3.75	3.75
Weighted-average deferred premium	(0.36)	(0.36)
2016 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | TGT Z1 basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	1,120,000	220,000
2016 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | TGT Z1 basis swaps [Member] | Henry Hub [Member]
Derivative [Line Items]
Spread	(0.10)	(0.08)
2016 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	3,292,442	2,692,442
Weighted-average fixed price	4.22	4.40
2016 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Basis Swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	3,108,333	2,508,333
Spread	(0.05)	(0.04)
2016 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | NGPL TexOk basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	2,703,333	2,103,333
2016 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | NGPL TexOk basis swaps [Member] | Henry Hub [Member]
Derivative [Line Items]
Spread	(0.07)	(0.06)
2016 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | HSC basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	135,000	135,000
2016 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | HSC basis swaps [Member] | Henry Hub [Member]
Derivative [Line Items]
Spread	0.07	0.07
2016 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | TETCO STX basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	270,000	270,000
2016 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | TETCO STX basis swaps [Member] | Henry Hub [Member]
Derivative [Line Items]
Spread	0.06	0.06
2016 [Member] | Crude Oil Derivative Contracts [Member] | MRD [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price | $ / bbl	84.80	84.80
Average Monthly Volume (Bbls) | bbl	8,500	8,500
2016 [Member] | Crude Oil Derivative Contracts [Member] | MRD [Member] | Collar contracts [Member]
Derivative [Line Items]
Weighted-average floor price | $ / bbl	80	80
Weighted-average ceiling price | $ / bbl	99.70	99.70
Average Monthly Volume (Bbls) | bbl	27,000	27,000
2016 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price | $ / bbl	86.87	85.83
Average Monthly Volume (Bbls) | bbl	279,813	332,813
2016 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Basis Swaps [Member]
Derivative [Line Items]
Spread | $ / bbl	(9.56)	(9.56)
Average Monthly Volume (Bbls) | bbl	95,000	95,000
2016 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Midway-Sunset basis swaps [Member]
Derivative [Line Items]
Spread | $ / bbl	(13.35)
Average Monthly Volume (Bbls) | bbl	55,000	55,000
2016 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Midway-Sunset basis swaps [Member] | Brent [Member]
Derivative [Line Items]
Spread | $ / bbl		(13.35)
2016 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Midland Basis Swap [Member]
Derivative [Line Items]
Spread | $ / bbl	(4.34)
Average Monthly Volume (Bbls) | bbl	40,000	40,000
2016 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Midland Basis Swap [Member] | WTI [Member]
Derivative [Line Items]
Spread | $ / bbl		(4.34)
2016 [Member] | NGL Derivative Contracts [Member] | MRD [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price | $ / bbl	34.06	34.06
Average Monthly Volume (Bbls) | bbl	185,658	185,658
2016 [Member] | NGL Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price | $ / bbl	40.36	41.49
Average Monthly Volume (Bbls) | bbl	158,600	84,600
2017 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	1,770,000	1,770,000
Weighted-average fixed price	4.24	4.24
2017 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | Collar contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	1,050,000	1,050,000
Weighted-average floor price	4	4
Weighted-average ceiling price	5.06	5.06
2017 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | Put Option [Member] | Purchased [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	3,450,000	3,450,000
Weighted-average fixed price	3.75	3.75
Weighted-average deferred premium	(0.35)	(0.35)
2017 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | TGT Z1 basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	200,000	200,000
2017 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | TGT Z1 basis swaps [Member] | Henry Hub [Member]
Derivative [Line Items]
Spread	(0.08)	(0.08)
2017 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	3,050,067	2,450,067
Weighted-average fixed price	4.14	4.31
2017 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Basis Swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	415,000	415,000
Spread		0
2017 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | NGPL TexOk basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	300,000	300,000
2017 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | NGPL TexOk basis swaps [Member] | Henry Hub [Member]
Derivative [Line Items]
Spread	(0.05)	(0.05)
2017 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | HSC basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	115,000	115,000
2017 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | HSC basis swaps [Member] | Henry Hub [Member]
Derivative [Line Items]
Spread	0.14	0.14
2017 [Member] | Crude Oil Derivative Contracts [Member] | MRD [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price | $ / bbl	84.70	84.70
Average Monthly Volume (Bbls) | bbl	28,000	28,000
2017 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price | $ / bbl	84.70	84.38
Average Monthly Volume (Bbls) | bbl	301,600	326,600
2017 [Member] | NGL Derivative Contracts [Member] | MEMP [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] | MRD [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	4,600,000	2,900,000
Weighted-average fixed price	4.06	4.27
2018 [Member] | Natural Gas Derivative Contracts [Member] | MRD [Member] | Put Option [Member] | Purchased [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	2,850,000	2,850,000
Weighted-average fixed price	3.75	3.75
Weighted-average deferred premium	(0.35)	(0.35)
2018 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	2,760,000	2,160,000
Weighted-average fixed price	4.28	4.51
2018 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Basis Swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	115,000	115,000
Spread	0.15	0.15
2018 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | HSC basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	115,000	115,000
2018 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | HSC basis swaps [Member] | Henry Hub [Member]
Derivative [Line Items]
Spread	0.15	0.15
2018 [Member] | Crude Oil Derivative Contracts [Member] | MRD [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price | $ / bbl	84.50	84.50
Average Monthly Volume (Bbls) | bbl	31,625	31,625
2018 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price | $ / bbl	83.74	83.74
Average Monthly Volume (Bbls) | bbl	312,000	312,000
2019 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	2,514,583	1,914,583
Weighted-average fixed price	4.43	4.75
2019 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price | $ / bbl	85.52	85.52
Average Monthly Volume (Bbls) | bbl	160,000	160,000
[1]	These transactions were entered into for the purpose of eliminating the ceiling portion of certain collar arrangements, which effectively converted the applicable collars into swaps.

Risk Management and Derivativ61

Risk Management and Derivative Instruments - Schedule of Entity's Interest Rate Swap Open Positions (Detail) - MEMP [Member] - Interest rate swaps [Member] - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
2015 [Member]
Derivative [Line Items]
Average Monthly Notional	$ 386,111	$ 314,167
Weighted-average fixed rate	1.247%	1.349%
Floating rate	1 Month LIBOR	1 Month LIBOR
2016 [Member]
Derivative [Line Items]
Average Monthly Notional	$ 400,000	$ 250,000
Weighted-average fixed rate	0.943%	1.029%
Floating rate	1 Month LIBOR	1 Month LIBOR
2017 [Member]
Derivative [Line Items]
Average Monthly Notional	$ 400,000	$ 250,000
Weighted-average fixed rate	1.612%	1.62%
Floating rate	1 Month LIBOR	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 Derivativ62

Risk Management and Derivative Instruments - Summary of Gross Fair Value and Net Recorded Fair Value of Derivative Instruments by Appropriate Balance Sheet Classification (Detail) - USD ($) $ in Thousands	Mar. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Net recorded fair value	$ 357,060	$ 340,056	$ 9,289
Asset Derivatives, Net recorded fair value	578,153	435,369	48,616
Liability Derivatives, Net recorded fair value	3,300	3,289	9,711
Liability Derivatives, Net recorded fair value	555		6,080
Short-term derivative instruments [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	398,708	378,908	22,604
Asset Derivatives, Netting arrangements	(41,648)	(38,852)	(13,315)
Asset Derivatives, Net recorded fair value	357,060	340,056	9,289
Liability Derivatives, Gross fair value	44,948	42,141	23,026
Liability Derivatives, Netting arrangements	(41,648)	(38,852)	(13,315)
Liability Derivatives, Net recorded fair value	3,300	3,289	9,711
Short-term derivative instruments [Member] | Commodity contracts [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	398,708	378,908	21,759
Liability Derivatives, Gross fair value	41,954	38,852	19,739
Short-term derivative instruments [Member] | Interest rate swaps [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value			845
Liability Derivatives, Gross fair value	2,994	3,289	3,287
Long-term derivative instruments [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	624,008	468,156	83,334
Asset Derivatives, Netting arrangements	(45,855)	(32,787)	(34,718)
Asset Derivatives, Net recorded fair value	578,153	435,369	48,616
Liability Derivatives, Gross fair value	46,410	32,787	40,798
Liability Derivatives, Netting arrangements	(45,855)	(32,787)	(34,718)
Liability Derivatives, Net recorded fair value	555		6,080
Long-term derivative instruments [Member] | Commodity contracts [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	623,998	466,851	83,295
Liability Derivatives, Gross fair value	45,855	32,787	38,495
Long-term derivative instruments [Member] | Interest rate swaps [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	10	$ 1,305	39
Liability Derivatives, Gross fair value	$ 555		$ 2,303

Risk Management and Derivativ63

Risk Management and Derivative Instruments - Schedule of Gains and Losses Related to Derivative Instruments (Detail) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Gain (Loss) on Derivative Instruments, Net, Pretax [Abstract]
(Gain) loss on commodity derivative instruments	$ (253,649)	$ 59,482	$ (749,988)	$ (29,294)	$ (34,905)
Interest expense, net	38,574	34,052	133,833	69,250	33,238
Commodity contracts [Member]
Gain (Loss) on Derivative Instruments, Net, Pretax [Abstract]
(Gain) loss on commodity derivative instruments	(253,649)	59,482	(749,988)	(29,294)	(34,905)
Interest rate derivatives [Member]
Gain (Loss) on Derivative Instruments, Net, Pretax [Abstract]
Interest expense, net	$ 2,441	$ 511	$ 145	$ (239)	$ 5,582

Asset Retirement Obligations -

Asset Retirement Obligations - Summary of Changes in Asset Retirement Obligations (Detail) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations at beginning of period	$ 122,531	$ 111,769	$ 111,769	$ 102,380	$ 90,699
Liabilities added from acquisitions or drilling	39		5,420	4,227	7,962
Liabilities removed upon sale of wells			(669)	(1,765)	(1,931)
Liabilities removed upon plugging and abandoning			(588)	(170)	(119)
Revisions	149		293	1,516	760
Accretion of asset retirement obligations	1,757	$ 1,521	6,306	5,581	5,009
Asset retirement obligations at end of period	124,476		122,531	111,769	102,380
Less: Current portion				90	390
Asset retirement obligations— long-term portion	$ 124,476		$ 122,531	$ 111,679	$ 101,990

Restricted Investments - Restri

Restricted Investments - Restricted Investment Balance (Detail) - USD ($) $ in Thousands	Mar. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Schedule Of Investments [Line Items]
Restricted investments	$ 78,787	$ 77,361	$ 73,385
BOEM platform abandonment [Member]
Schedule Of Investments [Line Items]
Restricted investments	71,263	69,954	66,373
BOEM lease bonds [Member]
Schedule Of Investments [Line Items]
Restricted investments	794	794	794
SPBPC Collateral Contractual pipeline and surface facilities abandonment [Member]
Schedule Of Investments [Line Items]
Restricted investments	2,818	2,701	2,306
SPBPC Collateral California State Lands Commission pipeline right-of-way bond [Member]
Schedule Of Investments [Line Items]
Restricted investments	3,005	3,005	3,005
SPBPC Collateral City of Long Beach pipeline facility permit [Member]
Schedule Of Investments [Line Items]
Restricted investments	500	500	500
SPBPC Collateral Federal pipeline right-of-way bond [Member]
Schedule Of Investments [Line Items]
Restricted investments	307	307	307
SPBPC Collateral Port of Long Beach pipeline license [Member]
Schedule Of Investments [Line Items]
Restricted investments	$ 100	$ 100	$ 100

Long Term Debt - Consolidated D

Long Term Debt - Consolidated Debt Obligations (Detail) - USD ($) $ in Thousands		Mar. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
Debt Instrument [Line Items]
Long-term debt		$ 2,498,045		$ 2,378,413		$ 1,663,217
MRD [Member]
Debt Instrument [Line Items]
Long-term debt		744,000		783,000		871,150
MRD [Member] | 2.0 billion revolving credit facility [Member]
Debt Instrument [Line Items]
Credit facility		144,000		183,000
MRD [Member] | PIK notes [Member]
Debt Instrument [Line Items]
Senior Notes						350,000
MRD [Member] | Senior Pik Toggle Notes Unamortized Discounts [Member]
Debt Instrument [Line Items]
Unamortized discounts						(6,950)
MRD [Member] | 5.875% Senior Unsecured Notes Due July 2022 [Member]
Debt Instrument [Line Items]
Senior Notes	[1]	600,000		600,000	[2]
MRD [Member] | WildHorse Resources, LLC [Member] | 1.0 billion revolving credit facility [Member]
Debt Instrument [Line Items]
Credit facility						203,100
MRD [Member] | WildHorse Resources, LLC [Member] | 325.0 Million Lien Term Facility [Member]
Debt Instrument [Line Items]
Credit facility						325,000
MEMP [Member]
Debt Instrument [Line Items]
Unamortized discounts		(15,945)		(16,587)		(10,933)
Long-term debt		1,754,045		1,595,413		792,067
MEMP [Member] | 2.0 billion revolving credit facility [Member]
Debt Instrument [Line Items]
Credit facility		573,000		412,000		103,000
MEMP [Member] | 7.625% senior unsecured notes, due May 2021 ("2021 Senior Notes") [Member]
Debt Instrument [Line Items]
Senior Notes		700,000	[3]	700,000	[3],[4]	$ 700,000	[4]
MEMP [Member] | 6.875% Senior Unsecured Notes Due August 2022 ("2022 Senior Notes") [Member]
Debt Instrument [Line Items]
Senior Notes	[5]	$ 496,990		$ 500,000	[6]
[1]	The estimated fair value of this fixed-rate debt was $564.0 million and $534.0 million at March 31, 2015 and December 31, 2014, respectively. 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 $534.0 million at December 31, 2014. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.
[3]	The estimated fair value of this fixed-rate debt was $640.5 million and $563.5 million at March 31, 2015 and December 31, 2014, respectively. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.
[4]	The estimated fair value of this fixed-rate debt was $563.5 million and $721.0 million at December 31, 2014 and 2013, respectively. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.
[5]	The estimated fair value of this fixed-rate debt was $437.4 million and $380.0 million at March 31, 2015 and December 31, 2014, respectively. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.
[6]	The estimated fair value of this fixed-rate debt was $380.0 million at December 31, 2014. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.

Long Term Debt - Consolidated67

Long Term Debt - Consolidated Debt Obligations (Parenthetical) (Detail) - USD ($)	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
PIK notes [Member]
Debt Instrument [Line Items]
Debt interest rate, minimum		10.00%
Debt interest rate, maximum		10.75%
MRD [Member] | 2.0 billion revolving credit facility [Member]
Debt Instrument [Line Items]
Credit facilities	$ 2,000,000,000	$ 2,000,000,000
Maturity date	Jun. 18, 2019	Jun. 18, 2019
MRD [Member] | 1.0 billion revolving credit facility [Member]
Debt Instrument [Line Items]
Credit facilities			$ 1,000,000,000
Maturity date			Jun. 30, 2014
MRD [Member] | PIK notes [Member]
Debt Instrument [Line Items]
Debt interest rate, minimum			10.00%
Senior notes redemption date			Jun. 30, 2014
Debt interest rate, maximum			10.75%
MRD [Member] | 5.875% Senior Unsecured Notes Due July 2022 [Member]
Debt Instrument [Line Items]
Maturity date	Jul. 1, 2022	Jul. 1, 2022
Debt interest rate	5.875%	5.875%
Estimated fair value of fixed rate debt	$ 564,000,000	$ 534,000,000
MRD [Member] | WildHorse Resources, LLC [Member] | 325.0 Million Lien Term Facility [Member]
Debt Instrument [Line Items]
Credit facilities			$ 325,000,000
MEMP [Member]
Debt Instrument [Line Items]
Credit facilities		2,000,000,000
MEMP [Member] | 2.0 billion revolving credit facility [Member]
Debt Instrument [Line Items]
Credit facilities	$ 2,000,000,000	$ 2,000,000,000
Maturity date	Mar. 19, 2018	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	May 1, 2021
Debt interest rate	7.625%	7.625%
Estimated fair value of fixed rate debt	$ 640,500,000	$ 563,500,000	$ 721,000,000
MEMP [Member] | 6.875% Senior Unsecured Notes Due August 2022 ("2022 Senior Notes") [Member]
Debt Instrument [Line Items]
Maturity date	Aug. 1, 2022	Aug. 1, 2022
Debt interest rate	6.875%	6.875%
Estimated fair value of fixed rate debt	$ 437,400,000	$ 380,000,000

Long Term Debt - Borrowing Base

Long Term Debt - Borrowing Base Credit Facility (Detail) - USD ($) $ in Thousands	Mar. 31, 2015	Dec. 31, 2014
MRD [Member] | 2.0 Billion Revolving Credit Facility Due June 2019 [Member]
Line Of Credit Facility [Line Items]
Borrowing base	$ 725,000	$ 725,000
MEMP [Member] | 2.0 Billion Revolving Credit Facility Due March 2018 [Member]
Line Of Credit Facility [Line Items]
Borrowing base	$ 1,300,000	$ 1,440,000

Long Term Debt - Borrowing Ba69

Long Term Debt - Borrowing Base Credit Facility (Parenthetical) (Detail) - USD ($)	Mar. 31, 2015	Dec. 31, 2014
MRD [Member] | 2.0 Billion Revolving Credit Facility Due June 2019 [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility	$ 2,000,000,000	$ 2,000,000,000
MEMP [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	$ 2,000,000,000

Long Term Debt - MRD Revolving

Long Term Debt - MRD Revolving Credit Facility - Additional Information (Detail) - USD ($)	Jul. 18, 2014	Dec. 31, 2014	Apr. 13, 2015
Subsequent Event [Member]
Debt Instrument [Line Items]
Revolving credit facility borrowing base			$ 725,000,000
MRD [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Revolving credit facility expiration term	5 years
Line of credit facility, aggregate maximum borrowing amount	$ 2,000,000,000
Revolving credit facility borrowing base	725,000,000
Aggregate elected capacity of revolving credit	$ 725,000,000
MRD [Member] | Revolving Credit Facility [Member] | Optional Base Rate | Federal Funds Effective Rate [Member]
Debt Instrument [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%)
MRD [Member] | Revolving Credit Facility [Member] | Range 1 [Member] | Alternative Base Rate
Debt Instrument [Line Items]
Line of credit, additional margin rate		0.50%
MRD [Member] | Revolving Credit Facility [Member] | Range 1 [Member] | London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Line of credit, additional margin rate		1.50%
MRD [Member] | Revolving Credit Facility [Member] | Range 2 [Member] | Alternative Base Rate
Debt Instrument [Line Items]
Line of credit, additional margin rate		1.50%
MRD [Member] | Revolving Credit Facility [Member] | Range 2 [Member] | London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Line of credit, additional margin rate		2.50%
MRD [Member] | Revolving Credit Facility [Member] | Minimum [Member]
Debt Instrument [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%
MRD [Member] | Revolving Credit Facility [Member] | Maximum [Member]
Debt Instrument [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) - Jul. 10, 2014 - 5.875% Senior Unsecured Notes ("MRD Senior Notes") [Member] - USD ($) $ in Millions	Total
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, 2014	Dec. 31, 2013	Dec. 31, 2012	Jun. 27, 2014	Jun. 15, 2014
Debt Obligations [Line Items]
Payment of distribution to funds				$ 732,362
Extinguishment loss			$ 37,248	$ 0	$ 0
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, 2014	Dec. 31, 2013	Dec. 31, 2012
Debt Obligations [Line Items]
Cash distribution paid				$ 732,362,000
Loss on extinguishment of debt			$ 37,248,000	$ 0	$ 0
WildHorse Resources, LLC [Member] | Second Lien Term Loan [Member] | Alternative Base Rate
Debt Obligations [Line Items]
Debt instrument interest rate	5.25%
WildHorse Resources, LLC [Member] | Second Lien Term Loan [Member] | London Interbank Offered Rate (LIBOR)
Debt Obligations [Line Items]
Debt instrument interest rate	6.25%
Revolving Credit Facility [Member] | WildHorse Resources, LLC [Member]
Debt Obligations [Line Items]
Initial borrowing base of second lien term facility		$ 1,000,000,000
Revolving credit facility borrowing base		$ 300,000,000
Line of credit, minimum collateral percentage		80.00%
Revolving Credit Facility [Member] | WildHorse Resources, LLC [Member] | Second Lien Term Loan [Member]
Debt Obligations [Line Items]
Initial borrowing base of second lien term facility	$ 325,000,000
Line of credit, minimum collateral percentage	80.00%
Cash distribution paid	$ 225,000,000
Loss on extinguishment of debt			$ 13,700,000

Long Term Debt - MEMP Revolving

Long Term Debt - MEMP Revolving Credit Facility and Senior Notes - Additional Information (Detail) - USD ($)	Jul. 17, 2014	Dec. 31, 2014	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]
Debt Obligations [Line Items]
Initial borrowing base of second lien term facility		$ 2,000,000,000
MEMP [Member] | 6.875% Senior Unsecured Notes ("2022 Senior Notes") [Member]
Debt Obligations [Line Items]
Other event of default minimum note holder percentage to accelerate	25.00%
Debt Instrument, maturity date	Aug. 1, 2022
Note issued at percentage of par	98.485%
MEMP [Member] | Private Placement of Debt [Member] | 6.875% Senior Unsecured Notes ("2022 Senior Notes") [Member]
Debt Obligations [Line Items]
Aggregate principal amount	$ 500,000,000
Senior unsecured notes interest rate	6.875%
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] | Optional Base Rate | Federal Funds Effective Rate [Member]
Debt Obligations [Line Items]
Lien percentage of assets for credit facility		80.00%
Line of credit, additional margin rate		0.50%
Line of credit, adjusted description		The one-month adjusted LIBOR plus 1.0% (adjusted upwards, if necessary, to the next 1/100th of 1%)
MEMP [Member] | Optional Base Rate | Adjusted London Interbank Offered Rate
Debt Obligations [Line Items]
Line of credit, additional margin rate		1.00%
MEMP [Member] | Minimum [Member]
Debt Obligations [Line Items]
Percentage of revolving unused commitment fee		0.375%
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%

Long Term Debt - Summary of Wei

Long Term Debt - Summary of Weighted-Average Interest Rates Paid On Variable-Rate Debt Obligations (Detail)	3 Months Ended		12 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
MRD [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates	1.87%		1.99%
MRD [Member] | WildHorse Resources, LLC [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates		3.97%	4.04%	2.30%	3.00%
MRD [Member] | WildHorse Resources second lien [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates		6.44%	6.44%	7.60%
MRD [Member] | Black Diamond [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates				3.97%	3.62%
MRD [Member] | MRD LLC [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates				3.17%	4.11%
MEMP [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates	1.90%	1.66%	2.67%	3.25%	2.74%
MEMP [Member] | Wht [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates				2.29%	2.60%
MEMP [Member] | Tanos Energy LLC [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates				3.10%	2.31%
MEMP [Member] | REO Revolving Credit Facility [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates					3.40%
MEMP [Member] | Stanolind [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates				3.52%	3.76%
MEMP [Member] | Boaz [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates				2.97%	3.12%
MEMP [Member] | Crown [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates				3.38%	4.20%
MEMP [Member] | Classic Revolving Credit Facility [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates					4.50%
MEMP [Member] | Propel Energy [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates				3.08%	3.28%

Long Term Debt - Summary of Una

Long Term Debt - Summary of Unamortized Deferred Financing Costs Associated with Consolidated Debt Obligations (Detail) - USD ($) $ in Thousands	Mar. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Unamortized deferred financing costs	$ 41,931	$ 44,474	$ 40,193
MRD [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Unamortized deferred financing costs	4,060	4,285
MRD [Member] | Revolving Credit Facility [Member] | WildHorse Resources, LLC [Member]
Debt Instrument [Line Items]
Unamortized deferred financing costs			2,436
MRD [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Unamortized deferred financing costs	12,041	12,455
MRD [Member] | Second Lien Credit Facility [Member]
Debt Instrument [Line Items]
Unamortized deferred financing costs			9,030
MRD [Member] | PIK notes [Member]
Debt Instrument [Line Items]
Unamortized deferred financing costs			8,261
MEMP [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Unamortized deferred financing costs	5,395	6,468	5,413
MEMP [Member] | 2021 Senior Notes [Member]
Debt Instrument [Line Items]
Unamortized deferred financing costs	12,779	13,308	$ 15,053
MEMP [Member] | 2022 Senior Notes [Member]
Debt Instrument [Line Items]
Unamortized deferred financing costs	$ 7,656	$ 7,958

Stockholders' Equity and Nonc77

Stockholders' Equity and Noncontrolling Interests - Additional Information (Detail) - USD ($)	Mar. 16, 2015	Feb. 01, 2015	Sep. 09, 2014	Jul. 15, 2014	Oct. 08, 2013	Apr. 01, 2013	Mar. 25, 2013	Mar. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Apr. 30, 2015	Jun. 18, 2014	Mar. 31, 2014	Dec. 31, 2011
Stockholders Equity Note Disclosure [Line Items]
Common stock, shares authorized								600,000,000	600,000,000	0
Common stock, par value								$ 0.01	$ 0.01	$ 0.01
Stock repurchase program, authorized amount									$ 50,000,000
Stock repurchased and retired during period, shares									123,797
Payments for repurchase of common stock								$ 47,785,000	$ 2,215,000
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
Public offering price per common unit													$ 19
Noncontrolling interests								$ 1,063,055,000	$ 1,120,554,000	$ 580,615,000
Fair value consideration paid									$ 3,292,000	15,135,000
Common Stock [Member]
Stockholders Equity Note Disclosure [Line Items]
Stock repurchased and retired during period, shares								2,764,887	123,797
Payments for repurchase of common stock								$ 28,000
Noncontrolling Interest [Member]
Stockholders Equity Note Disclosure [Line Items]
Noncontrolling interests								1,063,055,000	$ 1,120,554,000	$ 580,615,000	$ 231,662,000			$ 519,424,000	$ 161,588,000
MRD [Member]
Stockholders Equity Note Disclosure [Line Items]
Stock repurchased and retired during period, shares	2,764,887
Payments for repurchase of common stock	$ 47,800,000
MEMP [Member]
Stockholders Equity Note Disclosure [Line Items]
Stock repurchase program, authorized amount									$ 150,000,000
Stock repurchased and retired during period, shares									899,912
Payments for repurchase of common stock								$ 28,420,000	$ 12,903,000
MEMP [Member] | Common Stock [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				11,975,000
Net proceeds from sale of common units by subsidiary			$ 321,300,000	$ 220,000,000	$ 318,300,000		$ 171,800,000				$ 194,100,000
MEMP [Member] | Noncontrolling Interest [Member]
Stockholders Equity Note Disclosure [Line Items]
Stock repurchased and retired during period, shares								1,909,583
Payments for repurchase of common stock								$ 28,420,000	12,903,000
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
Subsequent Event [Member]
Stockholders Equity Note Disclosure [Line Items]
Stock repurchase program, authorized amount												$ 50,000,000
Subsequent Event [Member] | MRD [Member]
Stockholders Equity Note Disclosure [Line Items]
Stock repurchased and retired during period, shares	2,764,887
Payments for repurchase of common stock	$ 47,800,000
Subsequent Event [Member] | MEMP [Member]
Stockholders Equity Note Disclosure [Line Items]
Stock repurchased and retired during period, shares		1,909,583
Payments for repurchase of common stock		$ 28,500,000

Stockholders' Equity and Nonc78

Stockholders' Equity and Noncontrolling Interests - Summary of Changes In Common Shares Issued (Detail) - shares	Jun. 18, 2014	Mar. 31, 2015	Dec. 31, 2014
Class of Stock [Line Items]
Beginning Balance		193,435,414	0
Shares of common stock issued in initial public offering (Note 1)	21,500,000
Shares of common stock repurchased and retired			(123,797)
Ending Balance		190,776,618	193,435,414
Common Stock [Member]
Class of Stock [Line Items]
Shares of common stock issued in connection with restructuring transactions (Note 1)			171,000,000
Shares of common stock issued in initial public offering (Note 1)			21,500,000
Shares of common stock repurchased and retired		(2,764,887)	(123,797)
Restricted common shares issued (Note 11)		115,302	1,068,422
Restricted common shares forfeited		(9,211)	(9,211)

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
	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Numerator:
Net income (loss) available to common stockholders	$ 45,615	$ 167,198	$ 9,928	$ (961,707)	$ (784,581)	$ 0	$ 0
Weighted average common and common equivalent shares outstanding:
Weighted average common shares outstanding	190,705				192,498
Basic EPS	$ 0.24	$ 0.87	$ 0.05	$ (5)	$ (4.08)	$ 0	$ 0
Diluted EPS	$ 0.24	$ 0.87	$ 0.05	$ (5)	$ (4.08)	$ 0	$ 0

Earnings per Share - Summary 80

Earnings per Share - Summary of Calculation of Earnings (Loss) Per Share (Parenthetical) (Detail) - shares shares in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Earnings Per Share [Abstract]
Shares excluded from computation of EPS		202,623
Incremental shares included in diluted EPS computation	151,123

Earnings per Share - Summary 81

Earnings per Share - Summary of Calculation of Supplemental EPS (Detail) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended									12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Numerator:
Net income (loss) attributable to Memorial Resource Development Corp.	$ 45,892	$ 167,198	$ 9,928	$ (948,349)	$ 8,372	$ (30,657)	$ 84,727	$ 43,183	$ 4,249	$ (762,851)	$ 101,502	$ 29,698
Weighted average common and common equivalent shares outstanding:
Weighted average common shares outstanding	190,705									192,498
Basic EPS	$ 0.24	$ 0.87	$ 0.05	$ (5)						$ (4.08)	$ 0	$ 0
Diluted EPS	$ 0.24	$ 0.87	$ 0.05	$ (5)						$ (4.08)	$ 0	$ 0
Supplemental EPS [Member]
Numerator:
Net income (loss) attributable to Memorial Resource Development Corp.										$ (762,851)
Weighted average common and common equivalent shares outstanding:
Weighted average common shares outstanding										192,498
Basic EPS										$ (3.96)
Diluted EPS										$ (3.96)

Earnings per Share - Summary 82

Earnings per Share - Summary of Calculation of Supplemental EPS (Parenthetical) (Detail) shares in Thousands	12 Months Ended
	Dec. 31, 2014shares
Earnings Per Share [Line Items]
Shares excluded from computation of EPS	202,623
Supplemental EPS [Member]
Earnings Per Share [Line Items]
Shares excluded from computation of EPS	202,623

Long-Term Incentive Plans - Add

Long-Term Incentive Plans - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014	Dec. 31, 2011
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of common shares that may be delivered		19,250,000
MEMP [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of common units that may be delivered			2,142,221
Restricted Stock [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Aggregate award of restricted stock issued to employees and each independent director		1,052,633
Vesting period of award		4 years
Unrecognized compensation cost	$ 17.7	$ 17.3
Unrecognized compensation cost weighted-average period	3 years 1 month 17 days	3 years 5 months 5 days
Restricted Stock [Member] | MEMP [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Unrecognized compensation cost	$ 16.3	$ 16.5
Unrecognized compensation cost weighted-average period	1 year 11 months 27 days	2 years 1 month 6 days
Restricted Stock [Member] | Director [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Aggregate award of restricted stock issued to employees and each independent director		5,263
Vesting period of award		1 year

Long-Term Incentive Plans - Sum

Long-Term Incentive Plans - Summary of Information Regarding Restricted Common Unit Awards (Detail) - Restricted Stock [Member] - $ / shares	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
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	115,302	1,068,422
Forfeited, Number of Shares	(9,211)	(9,211)
Restricted common shares outstanding, Number of Shares, Ending Balance	1,165,302	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	18.05	$ 19
Forfeited, Weighted-Average Grant Date Fair Value Per Shares	19	19
Restricted common shares outstanding, Weighted-Average Grant Date Fair Value Per Shares, Ending Balance	$ 18.91	$ 19
MEMP [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted, Number of Shares	157,360	684,954	524,718	287,943
Forfeited, Number of Shares	(12,467)	(38,294)	(11,734)	(2,334)
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	15.45	22.39	18.83	$ 18.07
Forfeited, Weighted-Average Grant Date Fair Value Per Shares	20.73	20.54	17.24	17.14
Restricted common shares outstanding, Weighted-Average Grant Date Fair Value Per Shares, Ending Balance	$ 20.31	$ 20.93	$ 18.62	$ 18.08
Restricted common shares outstanding, Number of Units, Beginning Balance	1,093,520	706,927	285,609
Vested, Number of Units	(78,307)	(260,067)	(91,666)
Restricted common shares outstanding, Number of Units, Ending Balance	1,160,106	1,093,520	706,927	285,609
Vested, Weighted-Average Grant Date Fair Value Per Unit	$ 19.16	$ 18.56	$ 18.31

Long-Term Incentive Plans - S85

Long-Term Incentive Plans - Summary of Information Regarding Restricted Common Unit Awards (Parenthetical) (Detail) - Restricted Stock [Member] - USD ($) $ / shares in Units, $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Aggregate grant date fair value	$ 2.1	$ 20.3
Granted, Weighted-Average Grant Date Fair Value Per Shares	$ 18.91	$ 19
Granted, Weighted-Average Grant Date Fair Value Per Shares	$ 18.05	$ 19
MEMP [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Aggregate grant date fair value	$ 2.4	$ 15.3	$ 9.9	$ 5.2
Granted, Weighted-Average Grant Date Fair Value Per Shares	$ 20.31	$ 20.93	$ 18.62	$ 18.08
Granted, Weighted-Average Grant Date Fair Value Per Shares	$ 15.45	22.39	18.83	18.07
MEMP [Member] | Minimum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Aggregate grant date fair value, market price range		21.99	18.33	17.14
MEMP [Member] | Maximum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Aggregate grant date fair value, market price range		$ 23.40	$ 20.35	$ 18.58

Long-Term Incentive Plans - S86

Long-Term Incentive Plans - Summary of Amount of Compensation Expense Recognized (Detail) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Amortization of equity awards	$ 14,051	$ 2,318	$ 954,627	$ 46,837	$ 10,933
MEMP [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Amortization of equity awards	2,341	$ 1,295	7,874	$ 3,558	$ 1,423
Restricted Stock [Member] | MRD [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Amortization of equity awards	$ 1,486		$ 2,804

Incentive Units - Additional In

Incentive Units - Additional Information (Detail) - USD ($) $ in Thousands	Apr. 01, 2013	Dec. 31, 2013	Nov. 30, 2013	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jun. 18, 2014
Equity Incentive Plan [Line Items]
Compensation expense				$ 14,051	$ 2,318	$ 954,627	$ 46,837	$ 10,933
Accrued liabilities		$ 98,130		$ 217,669		$ 199,000	$ 98,130
Exchange of incentive units		0		190,776,618		193,435,414	0
Carrying amount of the noncontrolling interest		$ 580,615		$ 1,063,055		$ 1,120,554	$ 580,615
Fair value of consideration paid for noncontrolling interests						3,292	15,135
BlueStone Natural Resources Holdings, LLC [Member]
Equity Incentive Plan [Line Items]
Compensation expense						$ 1,000	20,700	$ 0
BlueStone Natural Resources Holdings, LLC [Member] | Special Tier and Tier I Unit Holders [Member]
Equity Incentive Plan [Line Items]
Percentage of future distributions incentive unit holders are entitled to after payout has been achieved						16.50%
Tanos Energy LLC [Member]
Equity Incentive Plan [Line Items]
Percentage of ownership interest sold to company	1.066%
Compensation expense as component of general and administrative expense							5,800
Black Diamond, Classic GP and Classic
Equity Incentive Plan [Line Items]
Compensation expense			$ 12,600
WildHorse Resources, LLC [Member]
Equity Incentive Plan [Line Items]
Compensation expense		10,000				$ 831,100
Accrued liabilities		$ 10,000					$ 10,000
Percentage of interest contributed former management members									0.10%
Exchange of incentive units									42,334,323
Cash consideration paid to certain former management members									$ 30,000
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		1,000
Remaining expected life						3 years
MRD Holdco LLC [Member] | Exchanged Incentive Units [Member]
Equity Incentive Plan [Line Items]
Percentage of future distributions incentive unit holders are entitled to after payout has been achieved						9.30%
Compensation expense				$ 10,200		$ 111,500
Incentive units granted in an exchange for cancelled predecessor awards				930		930
Unrecognized compensation expense				$ 95,500		$ 105,500
Remaining expected life				2 years 2 months 1 day		2 years 4 months 28 days
MRD Holdco LLC [Member] | Subsequent Incentive Units [Member]
Equity Incentive Plan [Line Items]
Percentage of future distributions incentive unit holders are entitled to after payout has been achieved						0.70%
Compensation expense						$ 400
Unrecognized compensation expense						$ 1,700
Remaining expected life						2 years 4 months 28 days
Subsequent incentive units				70		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)	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Exchanged Incentive Units [Member]
Schedule Of Share Based Compensation Valuation Assumptions [Line Items]
Valuation date	Mar. 30, 2015	Dec. 31, 2014
Dividend yield	0.00%	0.00%
Expected volatility	27.90%	39.54%
Risk-free rate	0.61%	0.85%
Expected life (years)	2 years 2 months 1 day	2 years 4 months 28 days
Subsequent Incentive Units [Member]
Schedule Of Share Based Compensation Valuation Assumptions [Line Items]
Valuation date	Mar. 31, 2015	Dec. 31, 2014
Dividend yield	0.00%	0.00%
Expected volatility	27.90%	39.54%
Risk-free rate	0.61%	0.85%
Expected life (years)	2 years 2 months 1 day	2 years 4 months 28 days

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Detail)

Apr. 14, 2015USD ($)

May. 01, 2014$ / bbl

Mar. 28, 2014USD ($)

Mar. 17, 2014USD ($)

Mar. 10, 2014USD ($)

Dec. 12, 2012USD ($)

Oct. 11, 2012USD ($)

Mar. 01, 2012USD ($)

May. 31, 2014$ / MMBTU

Nov. 30, 2011MMBTU / d

Mar. 31, 2015USD ($)MMBTU / d$ / MMBTU

Mar. 31, 2014USD ($)

Dec. 31, 2014USD ($)

Dec. 31, 2013USD ($)

Dec. 31, 2012USD ($)

Dec. 31, 2010USD ($)

Feb. 28, 2014USD ($)

Oct. 01, 2013USD ($)

Related Party Transaction [Line Items]

Net Profits Interest Sold to NGP

10.00%

Cash received

$ 19,800,000

General and administrative

$ 27,487,000

$ 17,739,000

$ 87,673,000

$ 82,079,000

$ 59,677,000

Received an equity contribution of oil and gas properties

6,900,000

Fee per MMBTU | $ / MMBTU

0.30

Natural gas produced per day | MMBTU / d

50,000

Annual inflationary escalation

3.50%

Price per unit | $ / MMBTU

0.07

Commodity usage charge | $ / MMBTU

0.04

Through November 30, 2019

Related Party Transaction [Line Items]

Payback demand quality per day | MMBTU / d

460,000

Payback demand fee | $ / MMBTU

0.03

July 1, 2016 | Minimum [Member]

Related Party Transaction [Line Items]

Minimum gas volume commitment | MMBTU / d

460,000

Through June 30, 2026 [Member]

Related Party Transaction [Line Items]

Commodity usage charge | $ / MMBTU

0.05

Through June 30, 2026 [Member] | Minimum [Member]

Related Party Transaction [Line Items]

Minimum gas volume commitment | MMBTU / d

460,000

June 30, 2026, and thereafter

Related Party Transaction [Line Items]

Commodity usage charge | $ / MMBTU

0.05

June 30, 2026, and thereafter | Minimum [Member]

Related Party Transaction [Line Items]

Minimum gas volume commitment | MMBTU / d

345,000

Second Plant [Member] | Through November 30, 2019

Related Party Transaction [Line Items]

Commodity usage charge | $ / MMBTU

0.02

Second Plant [Member] | Through November 30, 2019 | Minimum [Member]

Related Party Transaction [Line Items]

Minimum gas volume commitment | MMBTU / d

345,000

NGP Controlled Entity [Member]

Related Party Transaction [Line Items]

Proceeds from divestitures

$ 40,100,000

Proceeds from sale exceeded net book value of properties sold

6,300,000

Natural Gas Partners [Member]

Related Party Transaction [Line Items]

Cash received

$ 3,300,000

Propel Energy [Member]

Related Party Transaction [Line Items]

Cash received

$ 3,300,000

NGPCIF [Member]

Related Party Transaction [Line Items]

Net Profits Interest Sold to NGP

3.125%

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

Feb. 28, 2014

REO Sponsorship [Member]

Related Party Transaction [Line Items]

Business acquisition common control purchase price

$ 270,600,000

Working capital and other customary adjustments to Beta acquisition

$ 3,000,000

General and administrative

1,600,000

Cinco Group [Member]

Related Party Transaction [Line Items]

Business acquisition common control purchase price

$ 603,000,000

Financing fees equal to a percentage of capital contributions

0

400,000

Cinco Group [Member] | Advisory Fees [Member]

Related Party Transaction [Line Items]

Expenses incurred with related parties

300,000

400,000

Cinco Group [Member] | Natural Gas Partners [Member]

Related Party Transaction [Line Items]

Business acquisition common control purchase price

$ 507,100,000

MEMP [Member]

Related Party Transaction [Line Items]

Payable to related party

800,000

Oil And Gas Production [Member]

Related Party Transaction [Line Items]

Net Profits Interest Sold to NGP

23.50%

Oil And Gas Production [Member] | NGPCIF [Member]

Related Party Transaction [Line Items]

Net Profits Interest Sold to NGP

6.25%

WildHorse Resources, LLC [Member]

Related Party Transaction [Line Items]

Common stock lock-up agreement period

180 days

Cash received from related party

4,400,000

Primary term of gas processing agreement

15 years

Minimum annual processing fee

$ 18,300,000

WildHorse Resources, LLC [Member] | Subsequent Event [Member]

Related Party Transaction [Line Items]

Primary term of gas processing agreement

15 years

WildHorse Resources, LLC [Member] | First Plant [Member] | Subsequent Event [Member]

Related Party Transaction [Line Items]

Minimum annual processing fee

$ 18,300,000

WildHorse Resources, LLC [Member] | Second Plant [Member] | Subsequent Event [Member]

Related Party Transaction [Line Items]

Minimum annual processing fee

$ 55,000,000

WildHorse Resources, LLC [Member] | NGPCIF [Member]

Related Party Transaction [Line Items]

Payment to related party

2,600,000

2,300,000

Payable to related party

200,000

BlueStone Natural Resources Holdings, LLC [Member]

Related Party Transaction [Line Items]

Total cash consideration

$ 1,200,000

$ 7,000,000

Amount of gain over the book value

500,000

Gain recognized as contribution

$ 500,000

$ 6,400,000

Undivided interest sold to affiliate

25.00%

WHR Management Company [Member]

Related Party Transaction [Line Items]

Payable to related party

$ 2,400,000

Management fee per month

$ 1,000,000

$ 1,000,000

Employee [Member]

Related Party Transaction [Line Items]

Expenses incurred with related parties

1,000,000

Boaz [Member]

Related Party Transaction [Line Items]

Expenses incurred with related parties

$ 300,000

Classic [Member]

Related Party Transaction [Line Items]

Water disposal fee per barrel | $ / bbl

1.10

Water disposal agreement period

3 years

Cretic Energy Services, LLC [Member]

Related Party Transaction [Line Items]

Drilling and completion expenses

$ 600,000

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

Received Upon Closing [Member] | NGP Controlled Entity [Member]

Related Party Transaction [Line Items]

Proceeds from divestitures

$ 38,100,000

Until Second Processing Plant Operational | First Plant [Member]

Related Party Transaction [Line Items]

Commodity usage charge | $ / MMBTU

0.02

Until Second Processing Plant Operational | First Plant [Member] | Minimum [Member]

Related Party Transaction [Line Items]

Minimum gas volume commitment | MMBTU / d

115,000

Related Party Transactions - Sc

Related Party Transactions - Schedule of Net Assets Recorded (Detail) - USD ($) $ in Thousands	Feb. 28, 2014	Oct. 01, 2013	Dec. 12, 2012
NGPCIF [Member]
Related Party Transaction [Line Items]
Accounts receivable	$ 2,274
Oil and natural gas properties, net	40,056
Accrued liabilities	(297)
Asset retirement obligations	(277)
Net assets	$ 41,756
REO Sponsorship [Member]
Related Party Transaction [Line Items]
Cash and cash equivalents			$ 6,021
Accounts receivable			16,284
Short-term derivative instruments, net			2,926
Prepaid expenses and other current assets			4,521
Oil and natural gas properties, net			108,342
Restricted investments			68,009
Accounts payable			(9,092)
Accrued liabilities			(9,140)
Asset retirement obligations			(58,746)
Credit facilities			(28,500)
Deferred tax liability			(1,674)
Noncontrolling interest			(5,255)
Net assets			$ 93,696
Cinco Group Acquisition [Member]
Related Party Transaction [Line Items]
Cash and cash equivalents		$ 2,820
Accounts receivable		5,184
Prepaid expenses and other current assets		1,454
Oil and natural gas properties, net		342,759
Long-term derivative instruments, net		(826)
Other long-term assets		344
Accounts payable		(2,346)
Revenue payable		(2,910)
Accrued liabilities		(1,799)
short-term derivative instruments, net		(1,828)
Asset retirement obligations		(9,606)
Credit facilities		(151,690)
Net assets		$ 181,556

Related Party Transactions - Bo

Related Party Transactions - Book Value of Assets Sold (Detail) - WHR Management Company [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

Business Segment Data - Additio

Business Segment Data - Additional Information (Detail) - Segment	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Segment Reporting [Abstract]
Number of reportable business segments	2	2

Business Segment Data - Summary

Business Segment Data - Summary of Selected Business Segment Information (Detail) - USD ($) $ in Thousands	3 Months Ended									12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Segment Reporting Information [Line Items]
Total revenues	$ 179,841	$ 226,460	$ 245,493	$ 236,564	$ 204,621	$ 152,282	$ 153,515	$ 147,045	$ 122,181	$ 899,345	$ 575,023	$ 396,868
Adjusted EBITDA	173,186				123,796					647,733	394,856	287,992
Segment assets	4,574,222	4,593,547				2,829,161				4,593,547	2,829,161
Total cash expenditures for additions to long-lived assets	166,246				307,231					1,869,134	468,447	636,685
Operating Segments [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA	173,262				126,798					653,877	420,088	311,439
Operating Segments [Member] | MRD [Member]
Segment Reporting Information [Line Items]
Total revenues	87,023				87,736					363,126	201,886	104,072
Adjusted EBITDA	86,830				64,752					316,317	175,994	99,746
Segment assets	1,535,233	1,413,768				1,033,958				1,413,768	1,033,958
Total cash expenditures for additions to long-lived assets	88,566				75,258					487,001	254,724	188,903
Operating Segments [Member] | MEMP [Member]
Segment Reporting Information [Line Items]
Total revenues	92,818				116,885					536,219	373,137	293,165
Adjusted EBITDA	86,432				62,046					337,560	244,094	211,693
Segment assets	3,051,190	3,189,760				1,849,368				3,189,760	1,849,368
Total cash expenditures for additions to long-lived assets	77,680				231,973					1,382,133	213,723	447,782
Other, Adjustments & Eliminations [Member]
Segment Reporting Information [Line Items]
Total revenues												(369)
Adjusted EBITDA	(76)				$ (3,002)					(6,144)	(25,232)	$ (23,447)
Segment assets	$ (12,201)	$ (9,981)				$ (54,165)				$ (9,981)	$ (54,165)

Business Segment Data - Summa94

Business Segment Data - Summary of Selected Business Segment Information (Parenthetical) (Detail) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Segment Reporting Information [Line Items]
Cash distributions from MEMP	$ 76	$ 3,002	$ 6,144	$ 26,006	$ 19,263
Other, Adjustments & Eliminations [Member] | MEMP [Member]
Segment Reporting Information [Line Items]
Cash distributions from MEMP	$ 100	$ 3,000	$ 6,100	$ 26,000	$ 19,300

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
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Segment Reporting Information [Line Items]
Interest expense, net	$ 38,574	$ 34,052	$ 133,833	$ 69,250	$ 33,238
Loss on extinguishment of debt			37,248	0	0
Income tax expense (benefit)	45,188	100	100,971	1,619	107
DD&A	91,798	57,679	314,193	184,717	138,672
Impairment of proved oil and natural gas properties	251,347		432,116	6,600	28,871
Accretion of AROs	1,757	1,521	6,306	5,581	5,009
(Gain) loss on commodity derivative instruments	(253,649)	59,482	(749,988)	(29,294)	(34,905)
Cash settlements received (paid) on commodity derivative instruments			22,688	32,119	74,299
Cash settlements received (paid) on expired commodity derivative instruments	92,873	(13,190)
(Gain) loss on sale of properties		(110)	3,057	(85,621)	(9,761)
Acquisition related costs	2,580	2,462	6,668	8,313	4,538
Compensation expense	14,051	2,318	954,627	46,837	10,933
Amortization of investment premium			0	0	194
Non-cash compensation expense				1,057
Exploration costs	816	146	16,603	2,356	9,800
Provision for environmental remediation		2,852	2,852
Loss on office lease			2,622
Cash distributions from MEMP	76	3,002	6,144	26,006	19,263
Adjusted EBITDA	173,186	123,796	647,733	394,856	287,992
MEMP [Member]
Segment Reporting Information [Line Items]
Impairment of proved oil and natural gas properties			407,540
Operating Segments [Member]
Segment Reporting Information [Line Items]
Net income (loss)	(112,287)	(26,502)	(648,719)	152,395	31,877
Interest expense, net	38,574	34,052	133,833	69,250	33,238
Loss on extinguishment of debt			37,248
Income tax expense (benefit)	45,188	100	100,971	1,619	107
DD&A	91,798	57,679	314,193	184,717	138,672
Impairment of proved oil and natural gas properties	251,347		432,116	6,600	28,871
Accretion of AROs	1,757	1,521	6,306	5,581	5,009
(Gain) loss on commodity derivative instruments	(253,649)	59,482	(749,988)	(29,294)	(34,905)
Cash settlements received (paid) on commodity derivative instruments			22,688	32,119	74,299
Cash settlements received (paid) on expired commodity derivative instruments	92,873	(13,190)
(Gain) loss on sale of properties		(110)	3,057	(85,621)	(9,761)
Acquisition related costs	2,580	2,462	6,668	8,313	4,538
Compensation expense	14,051	2,318	954,627	46,837	10,933
Amortization of investment premium					194
Non-cash compensation expense				1,057
Exploration costs	816	146	16,603	2,356	9,800
Provision for environmental remediation		2,852	2,852
Loss on office lease			2,622
Non-cash equity (income) loss from MEMP	138	2,986	12,656	(1,847)	(696)
Cash distributions from MEMP	76	3,002	6,144	26,006	19,263
Adjusted EBITDA	173,262	126,798	653,877	420,088	311,439
Operating Segments [Member] | MRD [Member]
Segment Reporting Information [Line Items]
Net income (loss)	50,371	6,390	(764,333)	91,390	8,810
Interest expense, net	9,756	17,974	50,283	24,948	8,283
Loss on extinguishment of debt			37,248
Income tax expense (benefit)	47,558	25	102,392	1,311	(1)
DD&A	40,532	25,129	128,238	70,903	37,048
Impairment of proved oil and natural gas properties			24,576	2,528	5,877
Accretion of AROs	123	130	533	593	551
(Gain) loss on commodity derivative instruments	(108,190)	12,716	(257,734)	(3,161)	(10,500)
Cash settlements received (paid) on commodity derivative instruments			9,166	8,481	20,740
Cash settlements received (paid) on expired commodity derivative instruments	32,749	(5,221)
(Gain) loss on sale of properties		(110)	3,057	(82,773)	(2)
Acquisition related costs	1,281	568	2,305	1,584	403
Compensation expense	11,710	1,023	946,753	34,997	9,510
Exploration costs	726	140	13,853	1,034	460
Loss on office lease			1,180
Non-cash equity (income) loss from MEMP	138	2,986	12,656	(1,847)	(696)
Cash distributions from MEMP	76	3,002	6,144	26,006	19,263
Adjusted EBITDA	86,830	64,752	316,317	175,994	99,746
Operating Segments [Member] | MEMP [Member]
Segment Reporting Information [Line Items]
Net income (loss)	(162,658)	(32,892)	115,614	61,005	23,067
Interest expense, net	28,818	16,078	83,550	44,302	24,955
Income tax expense (benefit)	(2,370)	75	(1,421)	308	108
DD&A	51,266	32,550	185,955	113,814	101,624
Impairment of proved oil and natural gas properties	251,347		407,540	4,072	22,994
Accretion of AROs	1,634	1,391	5,773	4,988	4,458
(Gain) loss on commodity derivative instruments	(145,459)	46,766	(492,254)	(26,133)	(24,405)
Cash settlements received (paid) on commodity derivative instruments			13,522	23,638	53,559
Cash settlements received (paid) on expired commodity derivative instruments	60,124	(7,969)
(Gain) loss on sale of properties				(2,848)	(9,759)
Acquisition related costs	1,299	1,894	4,363	6,729	4,135
Compensation expense	2,341	1,295	7,874	11,840	1,423
Amortization of investment premium					194
Non-cash compensation expense				1,057
Exploration costs	90	6	2,750	1,322	9,340
Provision for environmental remediation		2,852	2,852
Loss on office lease			1,442
Adjusted EBITDA	$ 86,432	$ 62,046	$ 337,560	$ 244,094	$ 211,693

Business Segment Data - Reconci

Business Segment Data - Reconciliation of Total Reportable Segment's Adjusted EBITDA to Net Income (Loss) (Detail) - USD ($) $ in Thousands	3 Months Ended									12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Segment Reporting, Revenue Reconciling Item [Line Items]
Total Reportable Segments' Adjusted EBITDA	$ 173,186				$ 123,796					$ 647,733	$ 394,856	$ 287,992
Adjustments to reconcile Adjusted EBITDA to net income (loss):
Interest expense, net	(38,574)				(34,052)					(133,833)	(69,250)	(33,238)
Loss on extinguishment of debt										(37,248)	0	0
Income tax benefit (expense)	(45,188)				(100)					(100,971)	(1,619)	(107)
DD&A	(91,798)				(57,679)					(314,193)	(184,717)	(138,672)
Impairment of proved oil and natural gas properties	(251,347)									(432,116)	(6,600)	(28,871)
Accretion of AROs	(1,757)				(1,521)					(6,306)	(5,581)	(5,009)
Gains (losses) on commodity derivative instruments	253,649				(59,482)					749,988	29,294	34,905
Cash settlements paid (received) on commodity derivative instruments										(22,688)	(32,119)	(74,299)
Cash settlements paid (received) on expired commodity derivative instruments	(92,873)				13,190
Gain (loss) on sale of properties					110					(3,057)	85,621	9,761
Acquisition related costs	(2,580)				(2,462)					(6,668)	(8,313)	(4,538)
Incentive-based compensation expense	(14,051)				(2,318)					(954,627)	(46,837)	(10,933)
Non-cash compensation expense											(1,057)
Exploration costs	(816)				(146)					(16,603)	(2,356)	(9,800)
Amortization of investment premium										0	0	(194)
Cash distributions from MEMP	(76)				(3,002)					(6,144)	(26,006)	(19,263)
Provision for environmental remediation					(2,852)					(2,852)
Loss on office lease										(2,622)
Other non-cash equity (income) loss											784	(4,184)
Net income (loss)	(112,149)	$ 328,859	$ 112,037	$ (1,053,443)	(23,516)	$ (22,968)	$ 95,962	$ 78,158	$ 180	(636,063)	151,332	26,997
Reportable Segments [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Total Reportable Segments' Adjusted EBITDA	$ 173,262				$ 126,798					$ 653,877	$ 420,088	$ 311,439

Business Segment Data - Sched97

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
	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenues:
Oil & natural gas sales	$ 178,972				$ 203,710					$ 894,967	$ 571,948	$ 393,631
Other revenues	869				911					4,378	3,075	3,237
Total revenues	179,841	$ 226,460	$ 245,493	$ 236,564	204,621	$ 152,282	$ 153,515	$ 147,045	$ 122,181	899,345	575,023	396,868
Costs and expenses:
Lease operating	45,700				33,355					161,303	113,640	103,754
Gathering, processing, and transportation	22,983				14,120
Pipeline operating	446				489					2,068	1,835	2,114
Exploration	816				146					16,603	2,356	9,800
Production and ad valorem taxes	9,430				8,584					45,751	27,146	23,624
Depreciation, depletion, and amortization	91,798				57,679					314,193	184,717	138,672
Impairment of proved oil and natural gas properties	251,347									432,116	6,600	28,871
Incentive unit compensation expense	10,224				1,023					943,949	43,279	9,510
General and administrative	27,487				17,739					87,673	82,079	59,677
Accretion of asset retirement obligations	1,757				1,521					6,306	5,581	5,009
(Gain) loss on commodity derivative instruments	(253,649)				59,482					(749,988)	(29,294)	(34,905)
(Gain) loss on sale of properties					(110)					3,057	(85,621)	(9,761)
Other, net					(12)					(12)	649	502
Total costs and expenses	208,339				194,016					1,263,019	352,967	336,867
Operating income (loss)	(28,498)	444,776	174,201	(993,256)	10,605	4,411	117,797	90,327	9,521	(363,674)	222,056	60,001
Other income (expense):
Interest expense, net	(38,574)				(34,052)					(133,833)	(69,250)	(33,238)
Amortization of investment premium										0	0	(194)
Loss on extinguishment of debt										(37,248)	0	0
Earnings from equity investments											(784)	4,184
Other, net	111				31					(337)	145	535
Total other income (expense)	(38,463)				(34,021)					(171,418)	(69,105)	(32,897)
Income (loss) before income taxes	(66,961)				(23,416)					(535,092)	152,951	27,104
Income tax benefit (expense)	(45,188)				(100)					(100,971)	(1,619)	(107)
Net income (loss)	(112,149)	$ 328,859	$ 112,037	$ (1,053,443)	(23,516)	$ (22,968)	$ 95,962	$ 78,158	$ 180	(636,063)	151,332	26,997
Operating Segments [Member]
Costs and expenses:
Exploration	816				146					16,603	2,356	9,800
Depreciation, depletion, and amortization	91,798				57,679					314,193	184,717	138,672
Impairment of proved oil and natural gas properties	251,347									432,116	6,600	28,871
Accretion of asset retirement obligations	1,757				1,521					6,306	5,581	5,009
(Gain) loss on commodity derivative instruments	(253,649)				59,482					(749,988)	(29,294)	(34,905)
(Gain) loss on sale of properties					(110)					3,057	(85,621)	(9,761)
Other income (expense):
Interest expense, net	(38,574)				(34,052)					(133,833)	(69,250)	(33,238)
Amortization of investment premium												(194)
Loss on extinguishment of debt										(37,248)
Income tax benefit (expense)	(45,188)				(100)					(100,971)	(1,619)	(107)
Other, Adjustments & Eliminations [Member]
Revenues:
Oil & natural gas sales												(9)
Other revenues												(360)
Total revenues												(369)
Costs and expenses:
Lease operating											(108)	(800)
General and administrative											105	431
Total costs and expenses											(3)	(369)
Operating income (loss)											3
Other income (expense):
Earnings from equity investments	138				2,986					12,656	(1,066)	(4,880)
Total other income (expense)	138				2,986					12,656	(1,066)	(4,880)
Income (loss) before income taxes	138				2,986					12,656	(1,063)	(4,880)
Net income (loss)	138				2,986					12,656	(1,063)	(4,880)
MRD [Member] | Operating Segments [Member]
Revenues:
Oil & natural gas sales	87,023				87,733					363,114	201,886	103,728
Other revenues					3					12		344
Total revenues	87,023				87,736					363,126	201,886	104,072
Costs and expenses:
Lease operating	5,222				3,235					17,570	17,315	16,582
Gathering, processing, and transportation	14,763				8,557
Exploration	726				140					13,853	1,034	460
Production and ad valorem taxes	2,775				2,573					12,610	8,699	8,270
Depreciation, depletion, and amortization	40,532				25,129					128,238	70,903	37,048
Impairment of proved oil and natural gas properties										24,576	2,528	5,877
Incentive unit compensation expense	10,224				1,023					943,949	34,997	9,510
General and administrative	12,976				6,999					38,549	35,309	24,134
Accretion of asset retirement obligations	123				130					533	593	551
(Gain) loss on commodity derivative instruments	(108,190)				12,716					(257,734)	(3,161)	(10,500)
(Gain) loss on sale of properties					(110)					3,057	(82,773)	(2)
Other, net										(1)	2	464
Total costs and expenses	(20,849)				60,392					925,200	85,446	92,394
Operating income (loss)	107,872				27,344					(562,074)	116,440	11,678
Other income (expense):
Interest expense, net	(9,756)				(17,974)					(50,283)	(24,948)	(8,283)
Loss on extinguishment of debt										(37,248)
Earnings from equity investments	(138)				(2,986)					(12,656)	1,066	4,880
Other, net	(49)				31					320	143	534
Total other income (expense)	(9,943)				(20,929)					(99,867)	(23,739)	(2,869)
Income (loss) before income taxes	97,929				6,415					(661,941)	92,701	8,809
Income tax benefit (expense)	(47,558)				(25)					(102,392)	(1,311)	1
Net income (loss)	50,371				6,390					(764,333)	91,390	8,810
MEMP [Member]
Costs and expenses:
Impairment of proved oil and natural gas properties										407,540
MEMP [Member] | Operating Segments [Member]
Revenues:
Oil & natural gas sales	91,949				115,977					531,853	370,062	289,912
Other revenues	869				908					4,366	3,075	3,253
Total revenues	92,818				116,885					536,219	373,137	293,165
Costs and expenses:
Lease operating	40,478				30,120					143,733	96,433	87,972
Gathering, processing, and transportation	8,220				5,563
Pipeline operating	446				489					2,068	1,835	2,114
Exploration	90				6					2,750	1,322	9,340
Production and ad valorem taxes	6,655				6,011					33,141	18,447	15,354
Depreciation, depletion, and amortization	51,266				32,550					185,955	113,814	101,624
Impairment of proved oil and natural gas properties	251,347									407,540	4,072	22,994
Incentive unit compensation expense											8,282
General and administrative	14,511				10,740					49,124	46,665	35,112
Accretion of asset retirement obligations	1,634				1,391					5,773	4,988	4,458
(Gain) loss on commodity derivative instruments	(145,459)				46,766					(492,254)	(26,133)	(24,405)
(Gain) loss on sale of properties											(2,848)	(9,759)
Other, net					(12)					(11)	647	38
Total costs and expenses	229,188				133,624					337,819	267,524	244,842
Operating income (loss)	(136,370)				(16,739)					198,400	105,613	48,323
Other income (expense):
Interest expense, net	(28,818)				(16,078)					(83,550)	(44,302)	(24,955)
Amortization of investment premium												(194)
Other, net	160									(657)	2	1
Total other income (expense)	(28,658)				(16,078)					(84,207)	(44,300)	(25,148)
Income (loss) before income taxes	(165,028)				(32,817)					114,193	61,313	23,175
Income tax benefit (expense)	2,370				(75)					1,421	(308)	(108)
Net income (loss)	$ (162,658)				$ (32,892)					$ 115,614	$ 61,005	$ 23,067

Income Taxes - Components of In

Income Taxes - Components of Income Tax Expense (Benefit) (Detail) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Current taxes:
State			$ 22	$ (1,619)	$ 178
Deferred taxes:
Federal			(88,994)
State			(11,999)		(285)
Total income tax benefit (expense)	$ (45,188)	$ (100)	$ (100,971)	$ (1,619)	$ (107)

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details) - USD ($)	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating Loss Carryforwards [Line Items]
Federal statutory corporate tax rate	35.00%	35.00%
Unrecognized tax benefits	$ 0	$ 0	$ 0	$ 0
Interest and penalties on unrecognized benefits		0	$ 0	$ 0
United States [Member]
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards		$ 74,300,000
Operating loss carryforwards expiration start year		2,027
Operating loss carryforwards expiration end year		2,035
State [Member]
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards		$ 65,000,000
Minimum [Member] | State [Member]
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards periods		10 years
Maximum [Member] | State [Member]
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards periods		20 years

Income Taxes - Reconciliation o

Income Taxes - Reconciliation of Income Tax Benefit (Provision) (Detail) - USD ($) $ in Thousands		3 Months Ended		12 Months Ended
		Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]
Expected tax benefit (expense)				$ 187,282	$ (53,533)	$ (9,486)
State income tax expense, net of federal benefit				(9,660)	(1,619)	(107)
Pass-through entities	[1]			49,989	53,533	9,486
Stock compensation	[2]			(330,024)
Other				1,442
Total income tax benefit (expense)		$ (45,188)	$ (100)	$ (100,971)	$ (1,619)	$ (107)
[1]	MEMP, a publicly traded partnership with qualifying income, is a pass-through entity for federal income tax purposes. In addition, our predecessor was also a pass-through entity for federal income tax purposes.
[2]	As discussed in Note 12, the compensation expense associated with the incentive units of WildHorse Resources and MRD Holdco created a nondeductible permanent difference for income tax purposes.

Income Taxes - Components of Ne

Income Taxes - Components of Net Deferred Income Tax Assets and (Liabilities) (Detail) - USD ($) $ in Thousands	Dec. 31, 2014	Dec. 31, 2013
Deferred current income tax assets:
Unrealized hedging transactions	$ 109	$ 37
Accrued liabilities		5
Other	342	(42)
Deferred current income tax assets:	451
Deferred current income tax liabilities:
Unrealized hedging transactions	(52,328)
Other	(52)	(382)
Deferred current income tax liabilities:	(52,380)	(382)
Deferred noncurrent income tax assets:
Net operating loss carryforward	28,043	2,350
Asset retirement obligation	5,757	971
Other	3,224	1
Net deferred tax valuation allowance	(2,634)	(2,896)
Deferred noncurrent income tax assets:	34,390	426
Deferred noncurrent income tax liabilities:
Property, plant and equipment	(80,198)	(3,318)
Unrealized hedging transactions	(48,929)	(275)
Other	(280)	61
Deferred noncurrent income tax liabilities:	(129,407)	(3,532)
Net current deferred income tax assets (liabilities)	(51,929)	(382)
Net noncurrent deferred income tax assets (liabilities)	$ (95,017)	$ (3,106)

Commitments and Contingencies -

Commitments and Contingencies - Environmental Reserves Activity (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Commitments And Contingencies Disclosure [Abstract]
Balance at beginning of period	$ 577	$ 1,469	$ 1,747
Charged to costs and expenses	2,852		193
Payments	(1,337)	(892)	(471)
Balance at end of period	$ 2,092	$ 577	$ 1,469

Commitments and Contingencie103

Commitments and Contingencies - Additional Information (Detail)	Jan. 01, 2015MMBTU_day	Feb. 01, 2014MMBTU / d$ / MMBTU	Dec. 31, 2014USD ($)$ / bbl	Dec. 31, 2013USD ($)	Dec. 31, 2012USD ($)MMcf / d	Mar. 31, 2015USD ($)	Dec. 31, 2011USD ($)	Jun. 30, 2010USD ($)	Mar. 01, 2007USD ($)
Commitments And Contingencies (Additional Textual) [Abstract]
Environmental reserves liability			$ 2,092,000	$ 577,000	$ 1,469,000	$ 1,300,000	$ 1,747,000
Amount per barrel of oil | $ / bbl			0.25
Aggregate value of account required to cease fund			$ 4,300,000
Restricted investment			$ 2,700,000
Percentage of working interest under sinking fund trust agreement			51.75%
Additional quarterly payments								$ 600,000
Maximum remaining obligation			$ 8,700,000			7,400,000
Rent expense			10,800,000	$ 8,300,000	$ 5,000,000
Dubach [Member]
Commitments And Contingencies (Additional Textual) [Abstract]
Expansion of processing plant | MMcf / d					70
Dubberly [Member]
Commitments And Contingencies (Additional Textual) [Abstract]
Payback demand fee received by the third party				110.00%
Payback demand quality per day | MMBTU / d		192,950
Payback of fee in excess of demand quantity | $ / MMBTU		0.275
Subsequent Event [Member] | Dubberly [Member]
Commitments And Contingencies (Additional Textual) [Abstract]
Monthly demand quantity | MMBTU_day	249,700
December 31, 2016 [Member]
Commitments And Contingencies (Additional Textual) [Abstract]
Minimum balances attributable to net working interest			78,660,000			$ 78,660,000
REO Sponsorship [Member]
Commitments And Contingencies (Additional Textual) [Abstract]
Supplemental bond for decommissioning liabilities trust agreement									$ 90,000,000
Maximum [Member]
Commitments And Contingencies (Additional Textual) [Abstract]
Remaining obligation			$ 800,000

Commitments and Contingencie104

Commitments and Contingencies - Minimum Balances Attributable to Net Working Interest (Detail) - USD ($) $ in Thousands	Mar. 31, 2015	Dec. 31, 2014
June 30, 2015 [Member]
Asset retirement obligations
Minimum balances attributable to net working interest	$ 72,450	$ 72,450
June 30, 2016 [Member]
Asset retirement obligations
Minimum balances attributable to net working interest	76,590	76,590
December 31, 2016 [Member]
Asset retirement obligations
Minimum balances attributable to net working interest	$ 78,660	$ 78,660

Commitments and Contingencie105

Commitments and Contingencies - Gross Held-to-Maturity Investments (Detail) - USD ($) $ in Thousands	Mar. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Held-to-maturity Securities [Abstract]
Less: Outside working interest owners share, Amortized Cost	$ (66,442)	$ (65,222)
Restricted investments	78,787	77,361	$ 73,385
BOEM platform abandonment [Member]
Held-to-maturity Securities [Abstract]
Restricted investments	71,263	69,954	$ 66,373
Money Market Funds [Member]
Held-to-maturity Securities [Abstract]
Amortized Cost	$ 137,705	$ 135,176

Commitments and Contingencie106

Commitments and Contingencies - CO2 Minimum Purchase Commitment (Detail) - Wyoming Acquisition [Member] $ in Thousands	Dec. 31, 2014USD ($)
Minimum Purchase Commitment [Line Items]
Estimated payment obligation, Total	$ 50,495
Estimated payment obligation, 2015	9,608
Estimated payment obligation, 2016	10,179
Estimated payment obligation, 2017	10,151
Estimated payment obligation, 2018	6,995
Estimated payment obligation, 2019	7,060
Estimated payment obligation, Thereafter	$ 6,502

Commitments and Contingencie107

Commitments and Contingencies - Minimum Commitments to Gather before Other Owner Contributions (Detail) $ in Thousands	Dec. 31, 2014USD ($)
Dubach [Member]
Other Commitments [Line Items]
2,015	$ 13,671
2,016	13,709
2,017	13,671
2,018	12,772
Total	53,823
Dubberly [Member]
Other Commitments [Line Items]
2,015	11,393
2,016	11,424
2,017	11,393
2,018	10,643
Total	$ 44,853

Commitments and Contingencie108

Commitments and Contingencies - Minimum Lease Payment Obligations and Sublease Rental Income Under Non-Cancelable Operating Leases (Detail) $ in Thousands	Dec. 31, 2014USD ($)
MRD [Member]
Operating leases
Total	$ 43,625
2,015	6,534
2,016	6,607
2,017	6,694
2,018	6,259
2,019	5,960
Thereafter	11,571
Sublease rental income
Sublease rental income, Total	5,786
Sublease rental income, 2015	1,691
Sublease rental income, 2016	1,579
Sublease rental income, 2017	1,197
Sublease rental income, 2018	814
Sublease rental income, 2019	431
Sublease rental income, Thereafter	74
MEMP [Member]
Operating leases
Total	3,665
2,015	788
2,016	416
2,017	205
2,018	205
2,019	205
Thereafter	$ 1,846

Defined Contribution Plans - Ad

Defined Contribution Plans - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Defined Contribution Plan Disclosure [Line Items]
Employee eligibility age	18 years
Tax-deferred contributions	100.00%
Matching contribution	100.00%
Contribution by participants, percentage	6.00%
Employer contributions	$ 1.4	$ 0.9	$ 0.4
REO Sponsorship [Member]
Defined Contribution Plan Disclosure [Line Items]
Employee eligibility age	21 years
Tax-deferred contributions	100.00%
Matching contribution	100.00%
Contribution by participants, percentage	6.00%
Employer contributions		0.6	0.5
Defined contribution plan, company contribution, vesting period, years	3 years
Defined benefit plan cost and expense		0.3	0.3
WildHorse, Tanos, BlueStone, Classic and Black Diamond [Member]
Defined Contribution Plan Disclosure [Line Items]
Employer contributions	$ 0.2	0.5	0.6
Crown and Stanolind [Member]
Defined Contribution Plan Disclosure [Line Items]
Employer contributions		$ 0.1	$ 0.1

Condensed Consolidating Fina110

Condensed Consolidating Financial Information - Condensed Consolidating Balance Sheets (Detail) - USD ($) $ in Thousands	Mar. 31, 2015	Dec. 31, 2014	Mar. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Current assets:
Cash and cash equivalents	$ 4,512	$ 5,958	$ 39,519	$ 77,721	$ 49,391	$ 53,964
Restricted cash				35,000
Accounts receivable - trade	118,399	131,576		88,722
Accounts receivable - affiliates	1,976			4,652
Short-term derivative instruments	357,060	340,056		9,289
Prepaid expenses and other current assets	32,133	28,027		19,513
Total current assets	514,080	505,617		234,897
Property and equipment, net	3,366,600	3,537,656		2,419,704
Long-term derivative instruments	578,153	435,369		48,616
Other long-term assets	115,389	114,905		125,944
Total assets	4,574,222	4,593,547		2,829,161
Current liabilities:
Accounts payable and accrued liabilities	259,738	224,772		118,864
Accounts payable - affiliates		624		1,975
Revenues payable	58,331	57,352		56,091
Short-term derivative instruments	3,300	3,289		9,711
Total current liabilities	321,369	286,037		186,641
Long-term debt	2,498,045	2,378,413		1,663,217
Asset retirement obligations	124,476	122,531		111,679	101,990
Long-term derivative instruments	555			6,080
Deferred tax liabilities	111,790	95,017		3,106
Other long-term liabilities	7,566	8,585		306
Total liabilities	3,063,801	2,890,583		1,971,029
Equity:
Equity	447,366	582,410		277,517
Noncontrolling interests	1,063,055	1,120,554		580,615
Total equity	1,510,421	1,702,964	742,313	858,132	1,276,709	1,276,364
Total liabilities and equity	4,574,222	4,593,547		2,829,161
Parent [Member]
Current assets:
Cash and cash equivalents	454	2,241
Accounts receivable - trade	5,259	5,995
Accounts receivable - affiliates	13,303	10,047
Short-term derivative instruments	142,074	131,471
Prepaid expenses and other current assets	5,036	5,833
Total current assets	166,126	155,587
Property and equipment, net	17,320	16,601
Long-term derivative instruments	188,405	123,567
Investments in subsidiaries	928,289	1,139,792
Other long-term assets	13,481	14,124
Total assets	1,313,621	1,449,671
Current liabilities:
Accounts payable and accrued liabilities	11,711	6,245
Total current liabilities	11,711	6,245
Long-term debt	744,000	783,000
Deferred tax liabilities	102,978	69,431
Other long-term liabilities	7,566	8,585
Total liabilities	866,255	867,261
Equity:
Equity	447,366	582,410
Total equity	447,366	582,410
Total liabilities and equity	1,313,621	1,449,671
Guarantor Subsidiaries [Member]
Current assets:
Cash and cash equivalents	2,985	3,762	29,785	48,619	18,623	14,525
Restricted cash				35,000
Accounts receivable - trade	43,307	44,952		49,655
Accounts receivable - affiliates				8,905
Short-term derivative instruments				1,688
Prepaid expenses and other current assets	7,410	7,993		7,783
Total current assets	53,702	56,707		151,650
Property and equipment, net	1,098,997	1,050,722		785,914
Long-term derivative instruments				5,960
Investments in subsidiaries				288,760
Other long-term assets		5,660		35,137
Total assets	1,152,699	1,113,089		1,267,421
Current liabilities:
Accounts payable and accrued liabilities	127,921	107,068		61,865
Accounts payable - affiliates	4,185	3,638		7,481
Revenues payable	31,136	27,242		36,307
Short-term derivative instruments				1,715
Total current liabilities	163,242	137,948		107,368
Long-term debt				871,150
Asset retirement obligations	7,749	9,830		9,612
Long-term derivative instruments				205
Deferred tax liabilities	6,648
Other long-term liabilities				306
Total liabilities	177,639	147,778		988,641
Equity:
Equity	975,060	965,311		277,517
Noncontrolling interests				1,263
Total equity	975,060	965,311		278,780
Total liabilities and equity	1,152,699	1,113,089		1,267,421
Non-Guarantor Subsidiaries [Member]
Current assets:
Cash and cash equivalents	1,073	970	$ 9,734	29,102	$ 30,768	$ 39,439
Accounts receivable - trade	73,503	83,346		39,459
Accounts receivable - affiliates	28	28		1,532
Short-term derivative instruments	214,986	208,585		7,601
Prepaid expenses and other current assets	19,687	14,201		11,730
Total current assets	309,277	307,130		89,424
Property and equipment, net	2,250,283	2,470,333		1,633,790
Long-term derivative instruments	389,748	311,802		42,656
Other long-term assets	101,908	100,521		90,807
Total assets	3,051,216	3,189,786		1,856,677
Current liabilities:
Accounts payable and accrued liabilities	122,152	114,584		57,392
Accounts payable - affiliates	9,145	6,409		1,017
Revenues payable	27,195	30,110		19,784
Short-term derivative instruments	3,300	3,289		7,996
Total current liabilities	161,792	154,392		86,189
Long-term debt	1,754,045	1,595,413		792,067
Asset retirement obligations	116,727	112,701		102,067
Long-term derivative instruments	555			5,875
Deferred tax liabilities	2,164	30,986		1,151
Other long-term liabilities				1,955
Total liabilities	2,035,283	1,893,492		989,304
Equity:
Equity	1,010,214	1,290,734		855,768
Noncontrolling interests	5,719	5,560		11,605
Total equity	1,015,933	1,296,294		867,373
Total liabilities and equity	3,051,216	3,189,786		1,856,677
Eliminations [Member]
Current assets:
Cash and cash equivalents		(1,015)
Accounts receivable - trade	(3,670)	(2,717)		(392)
Accounts receivable - affiliates	(11,355)	(10,075)		(5,785)
Total current assets	(15,025)	(13,807)		(6,177)
Investments in subsidiaries	(928,289)	(1,139,792)		(288,760)
Other long-term assets		(5,400)
Total assets	(943,314)	(1,158,999)		(294,937)
Current liabilities:
Accounts payable and accrued liabilities	(2,046)	(3,125)		(393)
Accounts payable - affiliates	(13,330)	(9,423)		(6,523)
Total current liabilities	(15,376)	(12,548)		(6,916)
Deferred tax liabilities		(5,400)		1,955
Other long-term liabilities				(1,955)
Total liabilities	(15,376)	(17,948)		(6,916)
Equity:
Equity	(1,985,274)	(2,256,045)		(855,768)
Noncontrolling interests	1,057,336	1,114,994		567,747
Total equity	(927,938)	(1,141,051)		(288,021)
Total liabilities and equity	$ (943,314)	$ (1,158,999)		$ (294,937)

Condensed Consolidating Fina111

Condensed Consolidating Financial Information - Condensed Consolidating Statements of Operations (Detail) - USD ($) $ in Thousands	3 Months Ended									12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenues:
Oil & natural gas sales	$ 178,972				$ 203,710					$ 894,967	$ 571,948	$ 393,631
Other revenues	869				911					4,378	3,075	3,237
Total revenues	179,841	$ 226,460	$ 245,493	$ 236,564	204,621	$ 152,282	$ 153,515	$ 147,045	$ 122,181	899,345	575,023	396,868
Costs and expenses:
Lease operating	45,700				33,355					161,303	113,640	103,754
Gathering, processing, and transportation	22,983				14,120
Pipeline operating	446				489					2,068	1,835	2,114
Exploration	816				146					16,603	2,356	9,800
Production and ad valorem taxes	9,430				8,584					45,751	27,146	23,624
Depreciation, depletion, and amortization	91,798				57,679					314,193	184,717	138,672
Impairment of proved oil and natural gas properties	251,347									432,116	6,600	28,871
Incentive unit compensation expense	10,224				1,023					943,949	43,279	9,510
General and administrative	27,487				17,739					87,673	82,079	59,677
Accretion of asset retirement obligations	1,757				1,521					6,306	5,581	5,009
(Gain) loss on commodity derivatives	(253,649)				59,482					(749,988)	(29,294)	(34,905)
(Gain) loss on sale of properties					(110)					3,057	(85,621)	(9,761)
Other, net					(12)					(12)	649	502
Total costs and expenses	208,339				194,016					1,263,019	352,967	336,867
Operating income (loss)	(28,498)	444,776	174,201	(993,256)	10,605	4,411	117,797	90,327	9,521	(363,674)	222,056	60,001
Other income (expense):
Interest expense, net	(38,574)				(34,052)					(133,833)	(69,250)	(33,238)
Debt extinguishment costs										(37,248)	0	0
Equity earnings from subsidiaries											(784)	4,184
Other, net	111				31					(337)	145	341
Total other income (expense)	(38,463)				(34,021)					(171,418)	(69,105)	(32,897)
Income (loss) before income taxes	(66,961)				(23,416)					(535,092)	152,951	27,104
Income tax benefit (expense)	(45,188)				(100)					(100,971)	(1,619)	(107)
Net income (loss)	(112,149)	328,859	112,037	(1,053,443)	(23,516)	(22,968)	95,962	78,158	180	(636,063)	151,332	26,997
Net income (loss) attributable to noncontrolling interest	(158,041)	161,661	102,109	(105,094)	(31,888)	7,689	11,235	34,975	(4,069)	126,788	49,830	(2,701)
Net income (loss) attributable to Memorial Resource Development Corp.	45,892	$ 167,198	$ 9,928	$ (948,349)	8,372	$ (30,657)	$ 84,727	$ 43,183	$ 4,249	(762,851)	101,502	29,698
Parent [Member]
Revenues:
Other revenues										5
Total revenues										5
Costs and expenses:
Depreciation, depletion, and amortization	968									1,133
Incentive unit compensation expense	10,224									111,866
General and administrative	10,925									13,232
(Gain) loss on commodity derivatives										(277,129)
Total costs and expenses	(86,073)									(150,898)
Operating income (loss)	86,073									150,903
Other income (expense):
Interest expense, net	(9,757)									(19,532)
Debt extinguishment costs										(23,562)
Equity earnings from subsidiaries	7,021									(809,017)
Total other income (expense)	(2,736)									(852,111)
Income (loss) before income taxes	83,337									(701,208)
Income tax benefit (expense)	(37,445)									(83,373)
Net income (loss)	45,892									(784,581)
Net income (loss) attributable to Memorial Resource Development Corp.										(784,581)
Guarantor Subsidiaries [Member]
Revenues:
Oil & natural gas sales	87,023				87,733					363,114	184,757	100,242
Other revenues					3					7
Total revenues	87,023				87,736					363,121	184,757	100,242
Costs and expenses:
Lease operating	5,222				3,235					17,570	14,710	14,656
Gathering, processing, and transportation	14,763				8,557
Exploration	726				140					13,853	1,034	466
Production and ad valorem taxes	2,775				2,573					12,610	7,869	8,021
Depreciation, depletion, and amortization	39,564				25,129					127,105	61,990	34,843
Impairment of proved oil and natural gas properties										24,576	128	4,250
Incentive unit compensation expense										831,060	14,353	9,510
General and administrative	2,051				6,982					25,277	31,674	19,525
Accretion of asset retirement obligations	123				130					533	516	487
(Gain) loss on commodity derivatives										19,395	(3,179)	(10,500)
(Gain) loss on sale of properties										3,167	6,776	(2)
Other, net												459
Total costs and expenses	65,224				59,462					1,075,146	135,871	81,715
Operating income (loss)	21,799				28,274					(712,025)	48,886	18,527
Other income (expense):
Interest expense, net					(17,974)					(30,751)	(24,895)	(8,164)
Debt extinguishment costs										(13,686)
Equity earnings from subsidiaries					(3,260)						71,222	(16,331)
Other, net	(49)				31					319	141	456
Total other income (expense)	(49)				(21,203)					(44,118)	46,468	(24,039)
Income (loss) before income taxes	21,750				7,071					(756,143)	95,354	(5,512)
Income tax benefit (expense)	(10,113)				(25)					(19,028)	(164)
Net income (loss)	11,637				7,046					(775,171)	95,190	(5,512)
Net income (loss) attributable to Memorial Resource Development Corp.										(775,171)	95,190	(5,512)
Non-Guarantor Subsidiaries [Member]
Revenues:
Oil & natural gas sales	91,949				115,977					531,853	387,191	293,389
Other revenues	869				908					4,366	3,075	3,237
Total revenues	92,818				116,885					536,219	390,266	296,626
Costs and expenses:
Lease operating	40,478				30,120					143,733	98,930	89,529
Gathering, processing, and transportation	8,220				5,563
Pipeline operating	446				489					2,068	1,835	2,114
Exploration	90				6					2,750	1,322	9,334
Production and ad valorem taxes	6,655				6,011					33,141	19,277	15,603
Depreciation, depletion, and amortization	51,266				32,550					185,955	122,727	103,829
Impairment of proved oil and natural gas properties	251,347									407,540	6,472	24,621
Incentive unit compensation expense					1,023					1,023	28,926
General and administrative	14,511				10,757					49,164	50,405	39,721
Accretion of asset retirement obligations	1,634				1,391					5,773	5,065	4,522
(Gain) loss on commodity derivatives										(492,254)	(26,115)	(24,405)
(Gain) loss on sale of properties					(110)					(110)	(92,397)	(9,759)
Other, net					(12)					(12)	649	43
Total costs and expenses	229,188				134,554					338,771	217,096	255,152
Operating income (loss)	(136,370)				(17,669)					197,448	173,170	41,474
Other income (expense):
Interest expense, net	(28,817)				(16,078)					(83,550)	(44,355)	(25,074)
Other, net	160									(656)	4	(115)
Total other income (expense)	(28,657)				(16,078)					(84,206)	(44,351)	(25,189)
Income (loss) before income taxes	(165,027)				(33,747)					113,242	128,819	16,285
Income tax benefit (expense)	2,370				(75)					1,430	(1,455)	(107)
Net income (loss)	(162,657)				(33,822)					114,672	127,364	16,178
Net income (loss) attributable to noncontrolling interest										32	267	104
Net income (loss) attributable to Memorial Resource Development Corp.										114,640	127,097	16,074
Eliminations [Member]
Costs and expenses:
Lease operating												(431)
General and administrative												431
Other income (expense):
Equity earnings from subsidiaries	(7,021)				3,260					809,017	(71,222)	16,331
Total other income (expense)	(7,021)				3,260					809,017	(71,222)	16,331
Income (loss) before income taxes	(7,021)				3,260					809,017	(71,222)	16,331
Net income (loss)	$ (7,021)				$ 3,260					809,017	(71,222)	16,331
Net income (loss) attributable to noncontrolling interest										126,756	49,563	(2,805)
Net income (loss) attributable to Memorial Resource Development Corp.										$ 682,261	$ (120,785)	$ 19,136

Condensed Consolidating Fina112

Condensed Consolidating Financial Information - Condensed Consolidating Statements of Cash Flows (Detail) - USD ($) $ in Thousands	Jun. 18, 2014	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Cash flows from operating activities:
Net cash provided by (used in) operating activities		$ 171,816	$ 103,941	$ 476,271	$ 277,823	$ 240,404
Cash flows from investing activities:
Acquisitions of oil and natural gas properties		(3,305)	(173,000)	(1,177,670)	(105,762)	(360,678)
Additions to oil and gas properties		(160,994)	(134,200)	(674,396)	(360,015)	(273,334)
Additions to restricted investments		(1,426)	(826)	(3,976)	(5,361)	(4,599)
Additions to other property and equipment		(1,947)	(31)	(17,067)	(2,670)	(2,674)
Change in restricted cash				49,946	(49,347)	(3)
Deposits for property acquisitions				(215)
Proceeds from the sale of oil and natural gas properties				6,700	155,712	34,521
Other			(304)	(301)		29
Net cash used in investing activities		(167,672)	(308,361)	(1,816,979)	(367,443)	(606,738)
Cash flows from financing activities:
Advances on revolving credit facilities		270,000	343,000	2,746,800	1,132,755	619,450
Payments on revolving credit facilities		(148,000)	(79,000)	(2,457,900)	(1,766,037)	(251,569)
Proceeds from the issuances of senior notes				1,092,425	1,031,563
Borrowings under second lien credit facility					325,000
Redemption of senior notes				(351,808)
Redemption of second lien credit facility				(328,282)
Deferred financing costs		(10)	(1,162)	(30,334)	(41,175)	(3,501)
Proceeds from initial public offering	$ 380,200
Proceeds from changes in ownership interests in MEMP					135,012
Repurchased shares under repurchase program				(161)
Restricted MEMP units returned to plan				(1,012)
Purchase of additional interests in consolidated subsidiaries				(3,292)	(15,135)
Capital contributions						6,900
Contributions from previous owners					1,214	44,072
Distributions to the Funds					(732,362)
Distributions to noncontrolling interests		(46,239)	(31,085)	(149,084)	(78,083)	(15,208)
Distributions made by previous owners					(4,005)	(28,772)
Cash retained by previous owners					(7,909)
Other		(7)	(7)	320	455
Net cash provided by financing activities		(5,590)	166,218	1,268,945	117,950	361,761
Net change in cash and cash equivalents		(1,446)	(38,202)	(71,763)	28,330	(4,573)
Cash and cash equivalents, beginning of period		5,958	77,721	77,721	49,391	53,964
Cash and cash equivalents, end of period		4,512	39,519	5,958	77,721	49,391
Natural Gas Partners [Member]
Cash flows from financing activities:
Contributions from NGP affiliates related to sale of properties			1,165	1,165	2,013	45,158
Distribution to NGP affiliates related to purchase of assets			(66,693)	(66,693)	(355,494)	(242,174)
Distribution to NGP affiliates related to sale of assets, net of cash received			(66,693)	(32,770)
MRD Holdco LLC [Member]
Cash flows from financing activities:
Distributions to MRD Holdco				(59,803)
Parent [Member]
Cash flows from operating activities:
Net cash provided by (used in) operating activities		16,404		(72,612)
Cash flows from investing activities:
Additions to other property and equipment		(1,687)		(15,980)
Investment in subsidiaries		(5,580)		(696,489)
Distribution from subsidiaries		78,076		15,140
Net cash used in investing activities		70,809		(697,329)
Cash flows from financing activities:
Advances on revolving credit facilities		104,000		1,174,000
Payments on revolving credit facilities		(143,000)		(991,000)
Proceeds from the issuances of senior notes				600,000
Redemption of senior notes				(351,808)
Deferred financing costs				(18,779)
Purchase of additional interests in consolidated subsidiaries				(3,292)
Other				302
Net cash provided by financing activities		(89,000)		772,182
Net change in cash and cash equivalents		(1,787)		2,241
Cash and cash equivalents, beginning of period		2,241
Cash and cash equivalents, end of period		454		2,241
Parent [Member] | MRD Holdco LLC [Member]
Cash flows from financing activities:
Distributions to MRD Holdco				(17,207)
Guarantor Subsidiaries [Member]
Cash flows from operating activities:
Net cash provided by (used in) operating activities		82,434	51,864	297,490	93,864	56,443
Cash flows from investing activities:
Acquisitions of oil and natural gas properties				(93,909)	(67,098)	(83,055)
Additions to oil and gas properties		(86,619)	(75,227)	(376,123)	(164,850)	(85,431)
Additions to other property and equipment		(260)	(31)	(989)	(2,432)	(926)
Investment in subsidiaries			(4,146)		(93,433)	(718)
Distribution from subsidiaries			4,993	74,424	273,694	22,979
Change in restricted cash				49,946	(49,347)	(3)
Deposits for property acquisitions				(215)
Proceeds from the sale of oil and natural gas properties					33,152
Other			(3)
Net cash used in investing activities		(86,879)	(74,414)	(346,866)	(70,314)	(147,154)
Cash flows from financing activities:
Advances on revolving credit facilities			108,000	126,800	174,400	122,950
Payments on revolving credit facilities			(40,000)	(329,900)	(200,500)	(24,750)
Proceeds from the issuances of senior notes					343,000
Borrowings under second lien credit facility					325,000
Redemption of second lien credit facility				(328,282)
Deferred financing costs			(895)	(61)	(20,250)	(1,109)
Proceeds from changes in ownership interests in MEMP					135,012
Purchase of additional interests in consolidated subsidiaries					(15,135)
Capital contributions		3,668		686,623
Distributions to the Funds					(732,362)
Distribution to equity owners				(15,000)
Distributions made by previous owners					(2,590)	(2,282)
Other				18	(129)
Net cash provided by financing activities		3,668	3,716	4,519	6,446	94,809
Net change in cash and cash equivalents		(777)	(18,834)	(44,857)	29,996	4,098
Cash and cash equivalents, beginning of period		3,762	48,619	48,619	18,623	14,525
Cash and cash equivalents, end of period		2,985	29,785	3,762	48,619	18,623
Guarantor Subsidiaries [Member] | Natural Gas Partners [Member]
Cash flows from financing activities:
Distribution to NGP affiliates related to purchase of assets			(63,389)	(63,389)
Distribution to NGP affiliates related to sale of assets, net of cash received				(32,770)
Guarantor Subsidiaries [Member] | MRD Holdco LLC [Member]
Cash flows from financing activities:
Distributions to MRD Holdco				(39,520)
Non-Guarantor Subsidiaries [Member]
Cash flows from operating activities:
Net cash provided by (used in) operating activities		71,963	52,077	251,393	183,959	183,961
Cash flows from investing activities:
Acquisitions of oil and natural gas properties		(3,305)	(173,000)	(1,083,761)	(38,664)	(277,623)
Additions to oil and gas properties		(74,375)	(58,973)	(298,273)	(195,165)	(187,903)
Additions to restricted investments		(1,426)	(826)	(3,976)	(5,361)	(4,599)
Additions to other property and equipment				(98)	(238)	(1,748)
Proceeds from the sale of oil and natural gas properties				6,700	122,560	34,521
Other			(301)	(301)		29
Net cash used in investing activities		(79,106)	(233,100)	(1,379,709)	(116,868)	(437,323)
Cash flows from financing activities:
Advances on revolving credit facilities		166,000	235,000	1,446,000	958,355	496,500
Payments on revolving credit facilities		(5,000)	(39,000)	(1,137,000)	(1,565,537)	(226,819)
Proceeds from the issuances of senior notes				492,425	688,563
Deferred financing costs		(10)	(267)	(11,494)	(20,925)	(2,392)
Restricted MEMP units returned to plan				(1,012)
Capital contributions		1,912		9,866	93,433	718
Contributions from previous owners					1,214	44,072
Distribution to equity owners		(46,315)	(36,078)	(222,633)	(351,777)	(38,187)
Distributions made by previous owners					(1,415)	(26,490)
Cash retained by previous owners					(7,909)
Other		(7)	(7)		584
Net cash provided by financing activities		7,246	161,655	1,100,184	(68,757)	244,691
Net change in cash and cash equivalents		103	(19,368)	(28,132)	(1,666)	(8,671)
Cash and cash equivalents, beginning of period		970	29,102	29,102	30,768	39,439
Cash and cash equivalents, end of period		1,073	9,734	970	29,102	30,768
Non-Guarantor Subsidiaries [Member] | Natural Gas Partners [Member]
Cash flows from financing activities:
Contributions from NGP affiliates related to sale of properties			1,165	1,165	2,013	45,158
Distribution to NGP affiliates related to purchase of assets			(3,304)	(3,304)	(355,494)	(242,174)
Non-Guarantor Subsidiaries [Member] | MRD Holdco LLC [Member]
Cash flows from financing activities:
Distributions to MRD Holdco				(3,076)
MEMP [Member]
Cash flows from financing activities:
Repayment of senior notes		(2,914)
Costs incurred in conjunction with initial public offering				(12,510)	(21,066)	(8,268)
Proceeds from MEMP public offering				553,288	511,204	202,573
Repurchased shares under repurchase program		(28,420)		(11,531)
MEMP [Member] | Non-Guarantor Subsidiaries [Member]
Cash flows from financing activities:
Repayment of senior notes		(2,914)
Costs incurred in conjunction with initial public offering				(12,510)	(21,066)	(8,268)
Proceeds from MEMP public offering				553,288	511,204	202,573
Repurchased shares under repurchase program		(28,420)		(11,531)
MRD [Member]
Cash flows from financing activities:
Proceeds from initial public offering				408,500
Costs incurred in conjunction with initial public offering				(28,373)
Repurchased shares under repurchase program		(50,000)		(161)
MRD [Member] | Parent [Member]
Cash flows from financing activities:
Proceeds from initial public offering				408,500
Costs incurred in conjunction with initial public offering				(28,373)
Repurchased shares under repurchase program		(50,000)		(161)
MRD [Member] | Non-Guarantor Subsidiaries [Member]
Cash flows from financing activities:
Distributions to MRD Holdco		(78,000)
Eliminations [Member]
Cash flows from operating activities:
Net cash provided by (used in) operating activities		1,015
Cash flows from investing activities:
Investment in subsidiaries		5,580	4,146	696,489	93,433	718
Distribution from subsidiaries		(78,076)	(4,993)	(89,564)	(273,694)	(22,979)
Net cash used in investing activities		(72,496)	(847)	606,925	(180,261)	(22,261)
Cash flows from financing activities:
Capital contributions		(5,580)		(696,489)	(93,433)	(718)
Distribution to equity owners		46,315	36,078	237,633	351,777	38,187
Distributions to noncontrolling interests		(46,239)	(31,085)	(149,084)	(78,083)	(15,208)
Net cash provided by financing activities		72,496	$ 847	(607,940)	$ 180,261	$ 22,261
Net change in cash and cash equivalents		1,015		(1,015)
Cash and cash equivalents, beginning of period		(1,015)
Cash and cash equivalents, end of period				$ (1,015)
Eliminations [Member] | MRD [Member]
Cash flows from financing activities:
Distributions to MRD Holdco		$ 78,000

Quarterly Financial Informat113

Quarterly Financial Information (Unaudited) - Schedule of Quarterly Financial Information (Detail) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended									12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Quarterly Financial Data [Line Items]
Revenues	$ 179,841	$ 226,460	$ 245,493	$ 236,564	$ 204,621	$ 152,282	$ 153,515	$ 147,045	$ 122,181	$ 899,345	$ 575,023	$ 396,868
Operating income (loss)	(28,498)	444,776	174,201	(993,256)	10,605	4,411	117,797	90,327	9,521	(363,674)	222,056	60,001
Net income (loss)	(112,149)	328,859	112,037	(1,053,443)	(23,516)	(22,968)	95,962	78,158	180	(636,063)	151,332	26,997
Net income (loss) attributable to noncontrolling interest	(158,041)	161,661	102,109	(105,094)	(31,888)	7,689	11,235	34,975	(4,069)	126,788	49,830	(2,701)
Net income (loss) attributable to Memorial Resource Development Corp.	45,892	167,198	9,928	(948,349)	8,372	(30,657)	84,727	43,183	4,249	(762,851)	101,502	29,698
Net income (loss) allocated to members				13,358	6,947	(31,917)	84,754	35,278	2,597	20,305	90,712	(7,620)
Net income (loss) allocated to previous owners					1,425	$ 1,260	$ (27)	$ 7,905	$ 1,652	1,425	10,790	37,318
Net income (loss) available to common stockholders	$ 45,615	$ 167,198	$ 9,928	$ (961,707)						$ (784,581)	$ 0	$ 0
Basic EPS	$ 0.24	$ 0.87	$ 0.05	$ (5)						$ (4.08)	$ 0	$ 0
Diluted EPS	$ 0.24	$ 0.87	$ 0.05	$ (5)						$ (4.08)	$ 0	$ 0
Scenario Previously Reported [Member]
Quarterly Financial Data [Line Items]
Revenues					$ 190,828

Capitalized Costs Relating to O

Capitalized Costs Relating to Oil and Natural Gas Producing Activities (Detail) - USD ($) $ in Thousands		Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Evaluated oil and natural gas properties	[1]	$ 4,598,211	$ 2,974,855	$ 2,591,861
Support equipment and facilities		185,997	5,910	5,760
Unevaluated oil and natural gas properties		48,229	46,413	31,593
Accumulated depletion, depreciation, and amortization	[1]	(1,334,235)	(623,362)	(468,291)
Subtotal		3,498,202	2,403,816	2,160,923
MRD [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Evaluated oil and natural gas properties		1,268,873	897,511	742,404
Unevaluated oil and natural gas properties		48,229	44,453	24,629
Accumulated depletion, depreciation, and amortization		(276,837)	(160,620)	(122,712)
Subtotal		1,040,265	781,344	644,321
MEMP [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Evaluated oil and natural gas properties	[1]	3,329,338	2,077,344	1,849,457
Support equipment and facilities		185,997	5,910	5,760
Unevaluated oil and natural gas properties			1,960	6,964
Accumulated depletion, depreciation, and amortization	[1]	(1,057,398)	(462,742)	(345,579)
Subtotal		$ 2,457,937	$ 1,622,472	$ 1,516,602
[1]	Amounts do not include costs for SPBPC and related support equipment.

Costs Incurred for Property Acq

Costs Incurred for Property Acquisition, Exploration and Development (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Property acquisition costs, proved		$ 1,058,286	$ 93,894	$ 366,103
Property acquisition costs, unproved		24,310	19,975	5,293
Exploration and extension well costs		209,532	13,313	42,642
Development	[1]	487,777	356,270	198,423
Subtotal		1,779,905	483,452	612,461
MRD [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Property acquisition costs, proved		74,490	56,108	87,857
Property acquisition costs, unproved		24,310	19,975	5,293
Exploration and extension well costs		209,532	13,313	212
Development		181,026	191,350	99,028
Subtotal		489,358	280,746	192,390
MEMP [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Property acquisition costs, proved		983,796	37,786	278,246
Exploration and extension well costs				42,430
Development	[1]	306,751	164,920	99,395
Subtotal		$ 1,290,547	$ 202,706	$ 420,071
[1]	Amounts do not include costs for SPBPC and related support equipment.

Weighted Average Product Price

Weighted Average Product Price (Detail)		12 Months Ended
		Dec. 31, 2014$ / MMBTU$ / bbl	Dec. 31, 2013$ / MMBTU$ / bbl	Dec. 31, 2012$ / MMBTU$ / bbl
Oil [Member] | West Texas Intermediate [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Price	[1]	91.48	93.42	91.33
Natural Gas Liquids [Member] | West Texas Intermediate [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Price	[1]	91.48	93.42	91.75
Natural Gas [Member] | Henry Hub [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Price | $ / MMBTU	[2]	4.35	3.67	2.75
[1]	The unweighted average West Texas Intermediate price was adjusted by lease for quality, transportation fees, and a regional price differential.
[2]	The unweighted average Henry Hub price was adjusted by lease for energy content, compression charges, transportation fees, and regional price differentials.

Reserve Quantity Information (D

Reserve Quantity Information (Detail)	12 Months Ended
	Dec. 31, 2014MMcfeMBblsMMcf		Dec. 31, 2013MMcfeMBblsMMcf		Dec. 31, 2012MMcfeMBblsMMcf
Oil [Member]
Proved developed and undeveloped reserves:
Beginning of the year	50,459	[1]	51,042	[2]	37,984
Extensions and discoveries	2,674		7,449		8,190
Purchase of minerals in place	69,364		330		12,436
Production	(4,042)		(2,429)		(1,888)
Sales of minerals in place	(623)		(599)		(4,218)
Revision of previous estimates	(5,659)		(5,334)		(1,462)
End of year	112,173	[3]	50,459	[1]	51,042	[2]
Proved developed reserves:
Beginning of year	25,667		27,597		21,439
End of year	58,431		25,667		27,597
Proved undeveloped reserves:
Beginning of year	24,792		23,445		16,545
End of year	53,742		24,792		23,445
Natural Gas [Member]
Proved developed and undeveloped reserves:
Beginning of the year | MMcf	1,409,393	[1]	1,343,818	[2]	1,509,086
Extensions and discoveries | MMcf	196,250		190,744		61,888
Purchase of minerals in place | MMcf	35,222		48,109		141,732
Production | MMcf	(105,295)		(70,016)		(53,875)
Sales of minerals in place | MMcf	(10,815)		(14,137)		(4,942)
Revision of previous estimates | MMcf	215,801		(89,125)		(310,071)
End of year | MMcf	1,740,556	[3]	1,409,393	[1]	1,343,818	[2]
Proved developed reserves:
Beginning of year | MMcf	651,345		622,381		604,988
End of year | MMcf	772,578		651,345		622,381
Proved undeveloped reserves:
Beginning of year | MMcf	758,048		721,437		904,098
End of year | MMcf	967,978		758,048		721,437
Natural Gas Liquids [Member]
Proved developed and undeveloped reserves:
Beginning of the year	71,422	[1]	70,818	[2]	68,076
Extensions and discoveries	10,587		10,065		3,831
Purchase of minerals in place	23,598		1,275		8,974
Production	(4,363)		(3,089)		(1,643)
Sales of minerals in place	(950)		(1,573)
Revision of previous estimates	11,773		(6,074)		(8,420)
End of year	112,067	[3]	71,422	[1]	70,818	[2]
Proved developed reserves:
Beginning of year	29,863		28,268		17,659
End of year	55,463		29,863		28,268
Proved undeveloped reserves:
Beginning of year	41,559		42,550		50,417
End of year	56,604		41,559		42,550
Natural Gas Equivalent [Member]
Proved developed and undeveloped reserves:
Beginning of the year | MMcfe	2,140,683	[1]	2,074,982	[2]	2,145,454
Extensions and discoveries | MMcfe	275,815		295,832		134,010
Purchase of minerals in place | MMcfe	592,996		57,737		270,190
Production | MMcfe	(155,718)		(103,122)		(75,056)
Sales of minerals in place | MMcfe	(20,253)		(27,169)		(30,250)
Revision of previous estimates | MMcfe	252,467		(157,577)		(369,366)
End of year | MMcfe	3,085,990	[3]	2,140,683	[1]	2,074,982	[2]
Proved developed reserves:
Beginning of year | MMcfe	984,535		957,573		839,577
End of year | MMcfe	1,455,934		984,535		957,573
Proved undeveloped reserves:
Beginning of year | MMcfe	1,156,148		1,117,409		1,305,877
End of year | MMcfe	1,630,056		1,156,148		1,117,409
[1]	Includes reserves of 966,335 MMcfe attributable to noncontrolling interests and previous owners.
[2]	Includes reserves of 605,680 MMcfe attributable to noncontrolling interests and previous owners.
[3]	Includes reserves of 1,452,457 MMcfe attributable to noncontrolling interests.

Reserve Quantity Information (P

Reserve Quantity Information (Parenthetical) (Detail) - Natural Gas Equivalent [Member] - MMcfe	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Reserve Quantities [Line Items]
End of year	3,085,990	[1]	2,140,683	[2]	2,074,982	[3]	2,145,454
Noncontrolling Interest [Member]
Reserve Quantities [Line Items]
End of year	1,452,457		966,335		605,680
[1]	Includes reserves of 1,452,457 MMcfe attributable to noncontrolling interests.
[2]	Includes reserves of 966,335 MMcfe attributable to noncontrolling interests and previous owners.
[3]	Includes reserves of 605,680 MMcfe attributable to noncontrolling interests and previous owners.

Supplemental Oil And Gas Inf119

Supplemental Oil And Gas Information - Additional Information (Detail) - Bcfe	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Reserve Quantities [Line Items]
Multiple acquisitions	561.7		224.2
MRD [Member]
Reserve Quantities [Line Items]
Upward revisions in proved reserve	261.3
MRD [Member] | WildHorse Resources, LLC [Member]
Reserve Quantities [Line Items]
Extensions and discoveries		148.6
Multiple acquisitions			43.5
Terryville Acquisition [Member] | MRD [Member]
Reserve Quantities [Line Items]
Extensions and discoveries	253.7
Multiple acquisitions	31.3
Wyoming Acquisition [Member]
Reserve Quantities [Line Items]
Multiple acquisitions, largest acquisition	497.2
Eagle Ford Acquisition [Member]
Reserve Quantities [Line Items]
Multiple acquisitions	45
Goodrich [Member]
Reserve Quantities [Line Items]
Multiple acquisitions, largest acquisition			148.9
Stanolind [Member]
Reserve Quantities [Line Items]
Multiple acquisitions			43.6
Menemsha [Member]
Reserve Quantities [Line Items]
Multiple acquisitions, largest acquisition			23.9
Propel [Member]
Reserve Quantities [Line Items]
Divestiture of oil and gas properties			19

Discounted Future Net Cash Flow

Discounted Future Net Cash Flows (Detail) - USD ($) $ in Thousands		Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Extractive Industries [Abstract]
Future cash inflows		$ 21,505,195		$ 12,614,999		$ 11,432,968
Future production costs		(5,841,650)		(4,306,398)		(3,513,843)
Future development costs		(2,665,833)		(2,038,803)		(1,681,721)
Future income tax expense	[1]	(1,789,031)
Future net cash flows for estimated timing of cash flows		11,208,681		6,269,798		6,237,404
10% annual discount for estimated timing of cash flows		(6,486,539)		(3,192,733)		(3,326,893)
Standardized measure of discounted future net cash flows		$ 4,722,142	[2]	$ 3,077,065	[2]	$ 2,910,511	[2]	$ 2,885,485
[1]	Our predecessor was a pass through entity and was subject to the Texas margin tax which has a maximum effective rate of 0.7% of gross income apportioned to Texas. Due to immateriality, we have excluded the impact of this tax for the years ended December 31, 2013 and 2012.
[2]	Includes $2,756,848, $1,529,216 and $1,113,453 attributable to both noncontrolling interests and previous owners for the years ended December 31, 2014, 2013 and 2012, respectively.

Discounted Future Net Cash F121

Discounted Future Net Cash Flows (Parenthetical) (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2014		Dec. 31, 2011
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items]
Standardized measure of discounted future net cash flows	$ 3,077,065	[1]	$ 2,910,511	[1]	$ 4,722,142	[1]	$ 2,885,485
Maximum [Member] | Texas Margin Tax [Member]
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items]
Franchise effective tax rate	0.70%		0.70%
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	$ 1,529,216		$ 1,113,453		$ 2,756,848
[1]	Includes $2,756,848, $1,529,216 and $1,113,453 attributable to both noncontrolling interests and previous owners for the years ended December 31, 2014, 2013 and 2012, respectively.

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, 2014		Dec. 31, 2013		Dec. 31, 2012
Extractive Industries [Abstract]
Beginning of year		$ 3,077,065	[1]	$ 2,910,511	[1]	$ 2,885,485
Sale of oil and natural gas produced, net of production costs		(687,717)		(430,964)		(267,339)
Purchase of minerals in place		1,558,759		74,337		474,337
Sale of minerals in place		(47,791)		(54,091)		(154,963)
Extensions and discoveries		697,931		437,427		393,102
Changes in income taxes, net		(1,058,815)				1,947
Changes in prices and costs		196,530		(85,731)		(733,962)
Previously estimated development costs incurred		480,466		261,787		130,750
Net changes in future development costs		(201,177)		(17,514)		(68,471)
Revisions of previous quantities		665,089		(327,926)		(267,375)
Accretion of discount		307,707		287,535		288,743
Change in production rates and other		(265,905)		21,694		228,257
End of year	[1]	$ 4,722,142		$ 3,077,065		$ 2,910,511
[1]	Includes $2,756,848, $1,529,216 and $1,113,453 attributable to both noncontrolling interests and previous owners for the years ended December 31, 2014, 2013 and 2012, respectively.