Memorial Resource Development 8-K 28 Jul 16 Other Events Financial data

Document and Entity Information

Document and Entity Information	12 Months Ended
	Dec. 31, 2015
Document And Entity Information [Abstract]
Document Type	8-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2015
Trading Symbol	MRD
Entity Registrant Name	Memorial Resource Development Corp.
Entity Central Index Key	1,599,222

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 0	$ 3,364
Accounts receivable:
Oil and natural gas sales	22,719	27,476
Joint interest owners and other	29,973	5,602
Short-term derivative instruments	227,991	131,471
Other financial instruments (Note 6)	46,106
Prepaid expenses and other current assets	3,374	11,344
Assets of discontinued operation (Note 3)	345,541	321,536
Total current assets	675,704	500,793
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method (Note 2)	2,160,008	1,317,102
Other	22,822	29,658
Accumulated depreciation, depletion and impairment	(438,383)	(280,116)
Property and equipment, net	1,744,447	1,066,644
Long-term derivative instruments	91,292	123,567
Other long-term assets	4,976	3,586
Assets of discontinued operation (Note 3)	2,566,430	2,865,236
Total assets	5,082,849	4,559,826
Current liabilities:
Accounts payable	25,057	959
Accounts payable - affiliates	5,016	160
Revenues payable	34,026	21,807
Accrued liabilities (Note 2)	68,876	51,236
Liabilties of discontinued operation (Note 3)	91,779	159,946
Total current liabilities	224,754	234,108
Long-term debt	1,012,064	770,545
Asset retirement obligations	10,079	9,829
Deferred tax liabilities	193,733	114,599
Other long-term liabilities	7,195	8,585
Liabilities of discontinued operation (Note 3)	2,167,103	1,719,196
Total liabilities	3,614,928	2,856,862
Commitments and contingencies (Note 15)
Stockholders' equity (deficit):
Preferred stock, $.01 par value: 50,000,000 shares authorized; no shares issued and outstanding
Common stock, $.01 par value: 600,000,000 shares authorized; 205,293,743 shares issued and outstanding at December 31, 2015; 193,435,414 shares issued and outstanding at December 31, 2014	2,053	1,935
Additional paid-in capital	1,560,949	1,367,346
Accumulated earnings (deficit)	(740,175)	(786,871)
Total stockholders' equity	822,827	582,410
Noncontrolling interests	645,094	1,120,554
Total equity	1,467,921	1,702,964
Total liabilities and equity	$ 5,082,849	$ 4,559,826

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2015	Dec. 31, 2014
Statement Of Financial Position [Abstract]
Preferred stock, par value	$ 0.01	$ 0.01
Preferred stock, shares authorized	50,000,000	50,000,000
Preferred stock, shares issued	0	0
Preferred stock, shares outstanding	0	0
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	600,000,000	600,000,000
Common stock, shares issued	205,293,743	193,435,414
Common stock, shares outstanding	205,293,743	193,435,414

UNAUDITED CONDENSED STATEMENTS

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS - USD ($) shares in Thousands, $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenues:
Oil & natural gas sales		$ 374,042	$ 409,070	$ 219,552
Other revenues			12
Total revenues		374,042	409,082	219,552
Costs and expenses:
Lease operating		24,903	17,570	17,207
Gathering, processing, and transportation		72,554	45,956	17,666
Gathering, processing, and transportation – affiliate		25,403
Exploration		8,969	13,853	1,034
Taxes other than income		14,896	12,610	8,699
Depreciation, depletion, and amortization		188,742	128,238	70,903
Impairment of proved oil and natural gas properties		0	24,576	2,528
Incentive unit compensation expense		35,142	943,949	34,997
General and administrative		46,288	38,549	35,414
Accretion of asset retirement obligations		417	533	593
(Gain) loss on commodity derivative instruments		(281,249)	(257,734)	(3,161)
(Gain) loss on sale of properties		(47)	3,057	(82,773)
Other, net			(1)	2
Total costs and expenses		136,018	971,156	103,109
Operating income (loss)		238,024	(562,074)	116,443
Other income (expense):
Interest expense, net		(39,396)	(50,283)	(24,948)
Loss on extinguishment of debt			(37,248)
Other, net		(1,022)	320	143
Total other income (expense)		(40,418)	(87,211)	(24,805)
Income (loss) from continuing operations before income taxes		197,606	(649,285)	91,638
Income tax benefit (expense)		(100,005)	(102,392)	(1,311)
Net income (loss) from continuing operations		97,601	(751,677)	90,327
Discontinued Operations: (Note 3)
Income (loss) before income taxes		(397,666)	114,193	61,313
Income tax benefit (expense)		2,175	1,421	(308)
Net income (loss) from discontinued operations		(395,491)	115,614	61,005
Net income (loss)		(297,890)	(636,063)	151,332
Net income (loss) attributable to noncontrolling interest		(393,538)	126,788	49,830
Net income (loss) attributable to Memorial Resource Development Corp.		95,648	(762,851)	101,502
Net (income) loss allocated to members			(20,305)	(90,712)
Net (income) loss allocated to previous owners			(1,425)	$ (10,790)
Net (income) allocated to participating restricted stockholders		(734)
Net (income) loss from discontinued operations		327	(314)
Net income (loss) from continuing operations available to common stockholders		$ 95,241	$ (784,895)
Earnings per common share – basic: (Note 10)
Income (loss) from continuing operations		$ 0.49	$ (4.08)
Income (loss) from discontinued operations		0	0	$ 0
Net income (loss)		0.49	(4.08)
Earnings per common share – diluted: (Note 10)
Income (loss) from continuing operations	[1]	0.49	(4.08)
Income (loss) from discontinued operations		0	0	$ 0
Net income (loss)		$ 0.49	$ (4.08)
Weighted average common and common equivalent shares outstanding:
Basic		193,698	192,498
Diluted		193,698	192,498
[1]	The Company determines the more dilutive of either the two-class method or the treasury stock method for diluted EPS. The two-class method was more dilutive for each period presented.

STATEMENTS OF CONSOLIDATED AND

STATEMENTS OF CONSOLIDATED AND COMBINED CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash flows from operating activities:
Net income (loss)	$ (297,890)	$ (636,063)	$ 151,332
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
(Income) loss from discontinued operations	395,491	(115,614)	(61,005)
Depreciation, depletion, and amortization	188,742	128,238	70,903
Impairment of proved oil and natural gas properties	0	24,576	2,528
(Gain) loss on derivatives	(281,249)	(257,438)	(2,852)
Cash settlements (paid) received on expired derivative instruments	170,899	8,866	7,725
Cash settlements on terminated derivatives	92,258	5,326
Premiums paid for derivatives	(46,152)	(6,065)
Loss on extinguishment of debt		30,248
Amortization of deferred financing costs	2,823	3,209	2,330
Accretion of senior notes net discount		580	50
Accretion of asset retirement obligations	417	533	593
Amortization of equity awards	8,788	2,804
(Gain) loss on sale of properties	(47)	3,057	(82,773)
Non-cash compensation expense	35,142	916,218
Deferred income tax expense (benefit)	89,935	101,778	76
Exploration costs	85	12,993	86
Changes in operating assets and liabilities:
Accounts receivable	(19,614)	(7,419)	(4,113)
Prepaid expenses and other assets	9,529	(4,300)	(4,280)
Payables and accrued liabilities	64,131	8,469	7,872
Other	(546)	5,694
Net cash provided by continuing operations	412,742	225,690	88,472
Net cash provided by discontinued operations	221,169	250,581	189,351
Net cash provided by operating activities	633,911	476,271	277,823
Cash flows from investing activities:
Acquisitions of oil and natural gas properties	(291,536)	(93,909)	(67,098)
Additions to oil and gas properties	(594,901)	(376,122)	(185,194)
Additions to other property and equipment	(3,853)	(16,831)	(2,307)
Other financial instruments	(46,106)
Deposits for property acquisitions		(215)
Decrease (increase) in restricted cash		49,946	(49,347)
Proceeds from the sale of oil and natural gas properties	13,612	6,700	151,187
Other		(301)
Net cash used in continuing operations	(922,784)	(430,732)	(152,759)
Net cash used in discontinued operations	(337,505)	(1,386,247)	(214,684)
Net cash used in investing activities	(1,260,289)	(1,816,979)	(367,443)
Cash flows from financing activities:
Advances on revolving credit facilities	798,000	1,300,800	174,400
Payments on revolving credit facilities	(558,000)	(1,320,900)	(200,500)
Termination of second lien credit facility		(328,282)
Proceeds from the issuance of senior notes		600,000	343,000
Redemption of senior notes		(351,808)
Borrowings under second lien credit facility			325,000
Deferred financing costs	(1,498)	(18,840)	(20,251)
Purchase of additional interests in consolidated subsidiaries		(3,292)	(15,135)
Proceeds from MRD equity offering	242,880	408,500
Costs incurred in conjunction with MRD equity offering	(4,773)	(28,373)
Distributions to the Funds			(732,362)
Distributions to noncontrolling interests		(376)	(7,446)
Distributions made by previous owners			(2,590)
MRD equity repurchases	(51,197)	(161)
Other		320	71
Net cash provided by (used in) continuing operations	425,412	99,487	(801)
Net cash provided by discontinued operations	197,183	1,169,458	118,751
Net cash provided by financing activities	622,595	1,268,945	117,950
Net change in cash and cash equivalents	(3,783)	(71,763)	28,330
Add: cash balance included in assets of discontinued operations at beginning of period	2,594	26,191	32,336
Less: cash balance included in assets of discontinued operations at end of period	2,175	2,594	26,191
Cash and cash equivalents, beginning of period	3,364	51,530	17,055
Cash and cash equivalents, end of period	$ 0	3,364	51,530
Natural Gas Partners [Member]
Cash flows from financing activities:
Contributions from NGP affiliates related to sale of assets		1,165
Distribution to NGP affiliates related to purchase of assets		(66,693)
Distribution to NGP affiliates related to sale of assets, net of cash received		(32,770)
MRD Holdco LLC [Member]
Cash flows from financing activities:
Distribution to MRD Holdco		$ (59,803)
MEMP [Member]
Cash flows from financing activities:
Proceeds from changes in ownership interests in MEMP			$ 135,012

STATEMENTS OF CONSOLIDATED AND6

STATEMENTS OF CONSOLIDATED AND COMBINED EQUITY - USD ($) $ in Thousands	Total	Common Stock [Member]	Additional Paid-in Capital [Member]	Accumulated earnings (deficit) [Member]	Noncontrolling Interest [Member]	MEMP [Member]	MEMP [Member]Noncontrolling Interest [Member]	Member Equity [Member]	Member Equity [Member]Previous Owners [Member]
Total equity, beginning balance at Dec. 31, 2012	$ 1,276,709	$ 0	$ 0	$ 0
Noncontrolling interests, beginning balance at Dec. 31, 2012		0	0	0	$ 231,662			$ 0	$ 0
Members' equity, beginning balance at Dec. 31, 2012	0	0	0	0	0			811,614	233,433
Net income (loss)	151,332	0	0	0	49,830			90,712	10,790
Contributions	1,214	0	0	0	0			0	1,214
Net Proceeds from MEMP public equity offering	490,138	0	0	0	490,138			0	0
Sale of MEMP common units	135,012	0	0	0	74,311			60,701	0
Distributions	(814,450)	0	0	0	(78,083)			(732,362)	(4,005)
Net book value of net assets acquired from affiliates	0	0	0	0	130,805			50,751	(181,556)
Amortization of MEMP equity awards	3,558	0	0	0	3,558			0	0
Distribution to NGP affiliates in connection with acquisition of assets	(351,235)	0	0	0	(253,055)			(98,180)	0
Noncontrolling interest's share of cash consideration received in excess of the net book value sold to MEMP	0	0	0	0	24			(24)	0
Purchase of noncontrolling interests	(15,135)	0	0	0	(14,832)			(303)	0
Impact of equity transactions of MEMP	0	0	0	0	(54,183)			54,183	0
Other	(1,765)	0	0	0	440			94	(2,299)
Net assets retained by previous owners	(17,246)	0	0	0	0			0	(17,246)
Members' equity, ending balance at Dec. 31, 2013								237,186	40,331
Total stockholders equity, ending balance at Dec. 31, 2013		0	0	0
Total equity, ending balance at Dec. 31, 2013	858,132	0	0	0
Noncontrolling interests, ending balance at Dec. 31, 2013		0	0	0	580,615			0	0
Net income (loss)	(636,063)	0	0	(784,581)	126,788			20,305	1,425
Issuance of shares in connection with restructuring transactions (Note 1)	380,177	215	379,962	0	0			0	0
Issuance of shares in connection with initial public offering (see Note 1)	914,862	1,710	913,152	0	0			0	0
Tax related effects in connection with restructuring transactions and initial public offering	(43,251)	0	(43,251)	0	0			0	0
Share repurchase	(2,215)	(1)		(2,214)		$ (12,903)	$ (12,903)
Restricted stock awards	0	11	(11)	0	0			0	0
Amortization of restricted stock awards	2,804	0	2,804	0	0			0	0
Contribution related to MRD Holdco incentive unit compensation expense (Note 12)	111,866	0	111,866	0	0			0	0
Net Proceeds from MEMP public equity offering	540,698	0	0	0	540,698			0	0
Distributions	(149,084)	0	0	0	(149,084)			0	0
Net book value of net assets acquired from affiliates	3,303	0	0	0	0			45,059	(41,756)
Amortization of MEMP equity awards	7,874	0	0	0	7,874			0	0
Contribution related to sale of assets to NGP affiliate	1,165	0	0	0	0			1,165	0
Net book value of assets sold to NGP affiliate	(621)	0	0	0	0			(621)	0
Distribution to NGP affiliates in connection with acquisition of assets	(66,693)	0	0	0	0			(66,693)	0
Purchase of noncontrolling interests	(3,292)	0	(2,881)	0	(411)			0	0
Distribution of net assets to MRD Holdco	(93,084)	0	0	0	29,994			(123,078)	0
Distribution of shares received in connection with restructuring transactions to MRD Holdco	(110,510)	0	0	0	0			(110,510)	0
Net equity deemed contribution (distribution) related to net assets transferred to MEMP	0	0	5,327	0	(2,668)			(2,659)	0
Restricted equity repurchased and returned to plan						(1,012)	(1,012)
Other	811	0	378	(76)	663			$ (154)	$ 0
Total stockholders equity, ending balance at Dec. 31, 2014	582,410	1,935	1,367,346	(786,871)
Total equity, ending balance at Dec. 31, 2014	1,702,964
Noncontrolling interests, ending balance at Dec. 31, 2014	1,120,554				1,120,554
Net income (loss)	(297,890)	0	0	95,648	(393,538)
Contributions	2,962	0	0	0	2,962
Issuance of shares in connection with restructuring transactions (Note 1)	242,880	138	242,742	0	0
Cost incurred in conjunction with equity offering	(4,402)	0	(4,402)	0	0
Share repurchase	(47,785)	(28)	0	(47,757)	0	$ (53,999)	$ (53,999)
Restricted stock awards	0	9	(9)	0	0
Amortization of restricted stock awards	8,788	0	8,788	0	0
Contribution related to MRD Holdco incentive unit compensation expense (Note 12)	35,142	0	35,142	0	0
Deferred tax adjustments (Note 15)	38,778	0	38,778	0	0
Distributions	(163,007)	0	0	0	(163,007)
Amortization of MEMP equity awards	10,809	0	0	0	10,809
Purchase of noncontrolling interests	(5,946)	0	0	0	(5,946)
Net equity deemed contribution (distribution) related to net assets transferred to MEMP	0	0	(127,149)	0	127,149
Restricted equity repurchased and returned to plan	(1,196)	(1)		(1,195)
Other	(177)	0	(287)	0	110
Total stockholders equity, ending balance at Dec. 31, 2015	822,827	$ 2,053	$ 1,560,949	$ (740,175)
Total equity, ending balance at Dec. 31, 2015	1,467,921
Noncontrolling interests, ending balance at Dec. 31, 2015	$ 645,094				$ 645,094

Organization and Basis of Prese

Organization and Basis of Presentation	12 Months Ended
	Dec. 31, 2015
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Organization and Basis of Presentation	Note 1. Organization and Basis of Presentation Overview Memorial Resource Development Corp. (the “Company”) is a publicly traded Delaware corporation, the common shares of which are listed on the NASDAQ Global Market (“NASDAQ”) under the symbol “MRD.” Unless the context requires otherwise, references to “we,” “us,” “our,” “MRD,” or “the Company” are intended to mean the business and operations of Memorial Resource Development Corp. and its consolidated subsidiaries. The Company was formed by Memorial Resource Development LLC (“MRD LLC”) in January 2014 to acquire, explore and develop natural gas and oil properties in North America. MRD LLC was a Delaware limited liability company formed on April 27, 2011 by Natural Gas Partners VIII, L.P. (“NGP VIII”), Natural Gas Partners IX, L.P. (“NGP IX”) and NGP IX Offshore Holdings, L.P. (“NGP IX Offshore”) (collectively, the “Funds”) to explore, develop and acquire natural gas and oil properties. The Funds are private equity funds managed by Natural Gas Partners (“NGP”). MRD LLC’s consolidated and combined financial statements represent our predecessor for accounting and financial reporting purposes prior to our initial public offering. 2014 Initial Public Offering and Restructuring Transactions On June 18, 2014, the Company completed its initial public offering of 21,500,000 common units at a price of $19.00 per share, which generated net proceeds to the Company of approximately $380.2 million after deducting underwriting discounts and commissions and other offering related fees and expenses. The following restructuring events and transactions occurred in connection with our initial public offering: · The Funds contributed all of their interests in MRD LLC to MRD Holdco LLC (“MRD Holdco”) and the members of our management who owned incentive units in MRD LLC exchanged those incentive units for substantially identical incentive units in MRD Holdco, after which MRD Holdco owned 100% of MRD LLC; · WildHorse Resources, LLC (“WildHorse Resources”) sold its subsidiary, WildHorse Resources Management Company, LLC (“WHR Management Company”), to an affiliate of the Funds for approximately $0.2 million in cash, and WHR Management Company entered into a services agreement with the Company and WildHorse Resources pursuant to which WHR Management Company agreed to provide certain management services to WildHorse Resources, which was terminated as of March 1, 2015; · Classic Hydrocarbons Holdings, L.P. (“Classic”) and Classic Hydrocarbons GP Co., L.L.C. (“Classic GP”) distributed to MRD LLC the ownership interests in Classic Pipeline & Gathering, LLC (“Classic Pipeline”), which owns certain midstream assets in Texas, and Black Diamond Minerals, LLC (“Black Diamond”) distributed to MRD LLC its ownership interests in Golden Energy Partners LLC (“Golden Energy”), which sold all of its assets in May 2014; · MRD LLC contributed to us substantially all of its assets, comprised of: (i) 100% of the ownership interests in Classic, Classic GP, Black Diamond, Beta Operating Company, LLC (“Beta Operating”), Memorial Resource Finance Corp., MRD Operating LLC (“MRD Operating”), Memorial Production Partners GP LLC (“MEMP GP”) (including MEMP GP’s ownership of 50% of Memorial Production Partners LP’s (“MEMP”) incentive distribution rights) and (ii) 99.9% of the membership interests in WildHorse Resources; · We issued 128,665,677 shares of our common stock to MRD LLC, which MRD LLC immediately distributed to MRD Holdco; · We assumed the obligations of MRD LLC under the indenture governing the $350 million in aggregate principal amount of 10.00% / 10.75% Senior PIK Toggle Notes due 2018 (the “PIK notes”) and reimbursed MRD LLC for the June 15, 2014 interest payment made on the PIK notes; · Certain former management members of WildHorse Resources, including Jay Graham, our Chief Executive Officer, contributed to us their outstanding incentive units in WildHorse Resources, as well as the remaining 0.1% of the membership interests in WildHorse Resources, and we issued 42,334,323 shares of our common stock and paid cash consideration of $30.0 million to Jay Graham and such other former management members of WildHorse Resources; · We entered into a registration rights agreement and a voting agreement with MRD Holdco, Jay Graham, our Chief Executive Officer, and certain other former management members of WildHorse Resources; · We entered into a new $2.0 billion revolving credit facility (see Note 8) and used approximately $614.5 million in borrowings under that facility to repay all amounts outstanding under WildHorse Resources’ credit agreements, to partially fund the cash consideration payable to the former management members of WildHorse Resources and to reimburse MRD LLC for the June 15, 2014 interest payment made on the PIK notes; · Notice of redemption was given to the PIK notes trustee (see Note 8) specifying a redemption date of July 16, 2014 and indicating that a portion of the net proceeds from our initial public offering, which temporarily reduced amounts outstanding under our new revolving credit facility, would be used to redeem the PIK notes at a redemption price of 102% of the principal amount of the PIK notes plus accrued and unpaid interest thereon to the date of redemption; · MRD Operating entered into a merger agreement with MRD LLC pursuant to which after the termination or earlier discharge of the PIK notes MRD LLC would merge into MRD Operating; · MRD LLC distributed to MRD Holdco the following: (i) BlueStone Natural Resources Holdings, LLC (“BlueStone”), which sold substantially all of its assets in July 2013 for $117.9 million, MRD Royalty LLC, which owned certain leasehold interests and overriding royalty interests in Texas and Montana, MRD Midstream LLC, which owned an indirect interest in certain midstream assets in North Louisiana, Golden Energy and Classic Pipeline; (ii) 5,360,912 subordinated units of MEMP; (iii) the right to the remaining cash to be released from the debt service reserve account in connection with the redemption or earlier discharge of the PIK notes plus the cash received from us in reimbursement of the interest paid on June 15, 2014 in respect of the PIK notes; and (iv) approximately $6.7 million of cash received by MRD LLC in connection with the sale of Golden Energy’s assets in May 2014; · We irrevocably deposited with the PIK notes trustee approximately $360.0 million on June 27, 2014, which was an amount sufficient to fund the redemption of the PIK notes on the redemption date and to satisfy and discharge our obligations under the PIK notes and the related indenture. The discharge became effective upon the irrevocable deposit of the funds with the PIK notes trustee; and · MRD LLC merged into MRD Operating. Previous Owners References to “the previous owners” for accounting and financial reporting purposes refer collectively to: · Certain oil and natural gas properties and related assets primarily in the Permian Basin, East Texas and the Rockies that MEMP acquired through equity transactions in October 2013 from certain affiliates of NGP. In October 2013, MEMP acquired Boaz Energy, LLC (“Boaz”), Crown Energy Partners, LLC (“Crown”), the Crown net profits interest and overriding royalty interest (“Crown NPI/ORRI”), Propel Energy SPV LLC (“Propel SPV”), together with its wholly-owned subsidiary Propel Energy Services, LLC (“Propel Energy Services”), and Stanolind Oil and Gas SPV LLC (“Stanolind SPV”) from Boaz Energy Partners, LLC (“Boaz Energy Partners”), Crown Energy Partners Holdings, LLC (“Crown Holdings”), Propel Energy, LLC (“Propel Energy”) and Stanolind Oil and Gas LP (“Stanolind”), all of which are primarily owned by two of the Funds. · A net profits interest that WildHorse Resources purchased from NGP Income Co-Investment Fund II, L.P. (“NGPCIF”) in February 2014 (“NGPCIF NPI”). NGPCIF is controlled by NGP. Upon the completion of the 2010 Petrohawk and Clayton Williams acquisitions, WildHorse Resources sold a net profits interest in these properties to NGPCIF. Since WildHorse Resources sold the net profits interest, the historical results are accounted for as a working interest for all periods. Our audited financial statements reported herein include the financial position and results attributable to: (i) those certain oil and natural gas properties and related assets that MEMP acquired through equity transactions in October 2013 from Boaz Energy Partners, Crown Holdings, Propel Energy and Stanolind, all of which are components of discontinued operations 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 were required to consolidate MEMP for accounting and financial reporting purposes. MEMP was owned 99.9% by its limited partners and 0.1% by MEMP GP. On June 1, 2016, we completed the sale of MEMP GP, the general partner of MEMP, Beta Operating Company, LLC and MEMP Services LLC (collectively, the “Disposition Entities”) to MEMP for total proceeds of $0.75 million. Our financial statements have been retrospectively revised to reflect the Disposition Entities and its subsidiaries as discontinued operations for all periods presented. Certain amounts in the prior year financial statements have been reclassified to conform to current presentation. Gathering, processing, and transportation costs were previously accounted for as revenue deductions and are now being presented as costs and expenses on our statements of operations on a separate line item. We have elected to early adopt new accounting pronouncements related to the presentation of deferred taxes and debt issuance costs. The retrospective adjustments to the December 31, 2014 balance sheet are shown below. December 31, 2014 Before Adjustment Adjustment Effect December 31, 2014 As Adjusted (In thousands) Prepaid expenses and other current assets 12,999 (1,655 ) 11,344 Other long-term assets 14,126 (10,540 ) 3,586 Accrued liabilities 101,758 (50,522 ) 51,236 Long-term debt 783,000 (12,455 ) 770,545 Deferred tax liabilities 64,077 50,522 114,599 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”). Prior to the sale of the Disposition Entities and its subsidiaries we had two reportable segments, one of which was MEMP and its subsidiaries. Effective June 1, 2016, we now have one reportable business segment, which is engaged in the acquisition, exploration, development and production of oil and natural gas properties. Accordingly, we have retrospectively revised our segment disclosures for all periods presented.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Note 2. Summary of Significant Accounting Policies Use of Estimates The preparation of consolidated and combined financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated and combined financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates include, but are not limited to, oil and natural gas reserves; depreciation, depletion, and amortization of proved oil and natural gas properties; future cash flows from oil and natural gas properties; impairment of long-lived assets; fair value of derivatives; fair value of equity and incentive unit compensation; fair values of assets acquired and liabilities assumed in business combinations and asset retirement obligations. Principles of Consolidation and Combination Our consolidated financial statements include our accounts and those of our subsidiaries in which we have a controlling interest, after the elimination of all intercompany accounts and transactions. Likewise, the combined financial statements include the accounts of our predecessor and the previous owners as discussed above. All material intercompany balances and transactions have been eliminated. Certain prior period balances have been reclassified to better align with financial statement presentation in the current fiscal year. Cash and Cash Equivalents Cash and cash equivalents represent unrestricted cash on hand and all highly liquid investments with original contractual maturities of three months or less. Book Overdrafts Book overdrafts, representing outstanding checks in excess of funds on deposit, are classified as accounts payable and the change in the related balance is reflected in operating activities in the statement of cash flows. Concentrations of Credit Risk Cash balances, accounts receivable, restricted investments and derivative and other financial instruments are financial instruments potentially subject to credit risk. Cash and cash equivalents are maintained in bank deposit accounts which, at times, may exceed the federally insured limits. Management periodically reviews and assesses the financial condition of the banks to mitigate the risk of loss. Derivative financial instruments are generally executed with major financial institutions that expose us to market and credit risks and which may, at times, be concentrated with certain counterparties. The credit worthiness of the counterparties is subject to continual review. We rely upon netting arrangements with counterparties to reduce credit exposure. Neither we nor our predecessor and the previous owners have experienced any losses from such instruments. Oil and natural gas are sold to a variety of purchasers, including intrastate and interstate pipelines or their marketing affiliates and independent marketing companies. Accounts receivable from joint operations are from a number of oil and natural gas companies, partnerships, individuals, and others who own interests in the properties operated by us, our predecessor, and the previous owners. Generally, operators of crude oil and natural gas properties have the right to offset future revenues against unpaid charges related to operated wells, minimizing the credit risk associated with these receivables. Additionally, management believes that any credit risk imposed by a concentration in the oil and natural gas industry is mitigated by the creditworthiness of its customer base. An allowance for doubtful accounts is recorded after all reasonable efforts have been exhausted to collect or settle the amount owed. Any amounts outstanding longer than the contractual terms are considered past due. We did not have any material write-offs related to uncollectible accounts during the years ended December 31, 2015, 2014 and 2013. Management determined that an allowance for uncollectible accounts was unnecessary at both December 31, 2015 and 2014, respectively. If we were to lose any one of our customers, the loss could temporarily delay the production and the sale of oil and natural gas in the related producing region. If we were to lose any single customer, we believe that a substitute customer to purchase the impacted production volumes could be identified. Oil and Natural Gas Properties Oil and natural gas exploration, development and production activities are accounted for in accordance with the successful efforts method of accounting. Under this method, costs of acquiring properties, costs of drilling successful exploration wells, and development costs are capitalized. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if determination is made that proved reserves have been found. If no proved reserves have been found, the costs of each of the related exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. The costs of such exploratory wells are expensed if a determination of proved reserves has not been made within a twelve-month period after drilling is complete. Exploration costs such as geological, geophysical, and seismic costs are expensed as incurred. As exploration and development work progresses and the reserves on these properties are proven, capitalized costs attributed to the properties are subject to depreciation and depletion. Depletion of capitalized costs is provided using the units-of-production method based on proved oil and gas reserves related to the associated field. Capitalized drilling and development costs of producing oil and natural gas properties are depleted over proved developed reserves and leasehold costs are depleted over total proved reserves. On the sale or retirement of a complete or partial unit of a proved property or pipeline and related facilities, the cost and related accumulated depreciation, depletion, and amortization are removed from the property accounts, and any gain or loss is recognized. There were no material capitalized exploratory drilling costs pending evaluation at December 31, 2015, 2014, and 2013. Oil and natural gas properties consisted of the following at the dates indicated: December 31, 2015 2014 (In thousands) Proved oil and natural gas properties $ 1,740,530 $ 1,269,605 Support equipment and facilities 4,719 — Unproved oil and natural gas properties 414,759 47,497 Total oil and natural gas properties $ 2,160,008 $ 1,317,102 At December 31, 2015 and 2014, we had $174.0 million and $100.5 million, respectively, capitalized in proved oil and natural gas properties related to wells in various stages of drilling and completion, which have been excluded from the depletion base. Oil and Gas Reserves The estimates of proved oil and natural gas reserves utilized in the preparation of the consolidated and combined financial statements are estimated in accordance with the rules established by the SEC and the Financial Accounting Standards Board (“FASB”). These rules require that reserve estimates be prepared under existing economic and operating conditions using a trailing 12-month average price with no provision for price and cost escalations in future years except by contractual arrangements. Netherland, Sewell & Associates, Inc. (“NSAI”), our independent reserve engineers, was engaged to audit our internally prepared reserves estimates at December 31, 2015. 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 7 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 and 2013 was approximately $24.6 million and $2.5 million, respectively. We did not record any impairment expense for the year ended December 31, 2015. See Note 5 for further discussion on impairments. Unproved oil and natural gas properties are reviewed for impairment based on time or geologic factors. Information such as drilling results, reservoir performance, seismic interpretation or future plans to develop acreage is also considered. When unproved property investments are deemed to be impaired, the expense is reported in exploration expenses. We did not record any impairments related to unproved properties for the years ended December 31, 2015, 2014 and 2013. Debt Issuance Costs These costs are recorded on the balance sheet and amortized over the term of the associated debt using the straight-line method which generally approximates the effective yield method. Amortization expense, including write-off of debt issuance costs, for the years ended December 31, 2015, 2014, and 2013 was approximately $2.8 million, $3.2 million and $2.3 million, respectively. Revenue Recognition Revenue from the sale of oil and natural gas is recognized when title passes, net of royalties due to third parties. Oil and natural gas revenues are recorded using the sales method. Under this method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers, regardless of whether the sales are proportionate to our ownership in the property. An asset or a liability is recognized to the extent there is an imbalance in excess of the proportionate share of the remaining recoverable reserves on the underlying properties. No significant imbalances existed at December 31, 2015 or 2014. The following individual customers each accounted for 10% or more of total reported revenues for the period indicated: Years Ending December 31, 2015 2014 2013 Energy Transfer Equity, L.P. and subsidiaries 56 % 85 % 86 % Plains Marketing, L.P. 11 % n/a n/a Derivative and Other Financial Instruments Commodity derivative financial instruments (e.g., swaps, collars, and put options) are used to reduce the impact of natural gas, NGL and oil price fluctuations. Interest rate swaps are used to manage exposure to interest rate volatility, primarily as a result of variable rate borrowings under the credit facilities. Every derivative instrument is recorded on the balance sheet as either an asset or liability measured at its fair value. Changes in the derivative’s fair value are recognized in earnings as we have not elected hedge accounting for any of our derivative positions. Embedded derivatives that are required to be bifurcated and accounted for separately are treated in the same manner as freestanding derivatives. Embedded derivatives are recorded at fair value, with the difference between the basis of the hybrid financial instrument and the fair value of the embedded derivative recorded as the carrying value of the host contract. See Note 6 for further information on certain commodity contracts that required bifurcation. Capitalized Interest We capitalize interest costs to oil and gas properties on expenditures made in connection with certain projects such as drilling and completion of new oil and natural gas wells and major facility installations. Interest is capitalized only for the period that such activities are in progress. Interest is capitalized using a weighted average interest rate based on our outstanding borrowings. These capitalized costs are included within intangible drilling costs and amortized using the units of production method. For the year ended December 31, 2015 and 2014, we capitalized $5.4 million and $4.5 million of interest, respectively. Income Tax The Company uses the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the tax basis in assets and liabilities and their reported amounts in the financial statements and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. Deferred tax assets are reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of deferred tax assets will not be realized. The Company recognizes interest and penalties accrued to unrecognized tax benefits in other income (expense) in its consolidated statement of operations. A tax benefit from an uncertain tax position is recognized when it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position. The tax benefit recorded is equal to the largest amount that is greater than 50% likely to be realized through effective settlement with a taxing authority. Earnings Per Share Basic earnings per share (“EPS”) is computed using the two-class method based on net income (loss) available to common stockholders and the average number of shares of common stock outstanding for the period. Diluted EPS includes the impact of the Company’s restricted shares of common stock as they are participating securities. The Company determines the more dilutive of either the two-class method or the treasury stock method for diluted EPS. See Note 10 for additional information. Incentive Based Compensation Arrangements The fair value of equity-classified awards (e.g., restricted stock awards) is amortized to earnings over the requisite service or vesting period. Compensation expense for liability-classified awards (e.g., phantom unit awards) is recognized over the requisite service or vesting period of an award based on the fair value of the award re-measured at each reporting period. Generally, no compensation expense is recognized for equity instruments that do not vest. Prior to the restructuring transactions, the governing documents of MRD LLC and certain of its subsidiaries provided for the issuance of incentive units. The incentive units were subject to performance conditions that affected their vesting. Compensation cost was recognized only if the performance condition was probable of being satisfied at each reporting date. In connection with the restructuring transactions, the MRD LLC incentive units were exchanged for substantially identical units in MRD Holdco, and such incentive units entitle holders thereof to portions of future distributions by MRD Holdco. While any such distributions made by MRD Holdco will not involve any cash payment by us, we will be required to recognize non-cash compensation expense, which may be material, in future periods. The compensation expense recognized by us related to the incentive units will be offset by a deemed capital contribution from MRD Holdco as they are remeasured at the end of each reporting period. See Notes 11 and 12 for further information. Accrued Liabilities Current accrued liabilities consisted of the following at the dates indicated (in thousands): December 31, December 31, 2015 2014 Accrued capital expenditures $ 40,197 $ 44,308 Accrued interest payable 17,657 124 Other accrued liabilities 11,022 6,804 $ 68,876 $ 51,236 Supplemental Cash Flow Information Supplemental cash flow for continuing operations for the periods presented (in thousands): For the Year Ended December 31, 2015 2014 2013 Supplemental cash flows: Cash paid for interest, net of capitalized interest $ 18,815 $ 67,023 $ 18,541 Cash paid for taxes 8,160 687 — Noncash investing and financing activities: Increase (decrease) in capital expenditures in payables and accrued liabilities (4,111 ) 18,012 22,238 (Increase) decrease in accounts receivable related to acquisitions and divestitures 852 (852 ) — Assumptions of asset retirement obligations related to properties acquired or drilled 1,348 786 2,111 Repurchase of equity under repurchase program — 2,053 — New Accounting Pronouncements Balance Sheet Classification of Deferred Taxes . In November 2015, the Financial Accounting Standards Board (“FASB”) issued an accounting standards update that requires entities with a classified balance sheet to present all deferred tax assets and liabilities as noncurrent. The current requirement that deferred tax assets and liabilities of a tax-paying component of an entity be offset and presented as a single amount is not affected by the amendment. The amendments are effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early adoption is permitted for all entities as of the beginning of an interim or annual reporting period. The amendments may be applied either prospectively to all deferred tax assets and liabilities or retrospectively to all periods presented. We have adopted this guidance as of December 31, 2015 and applied the disclosure requirements retrospectively to the consolidated financial statements and footnote disclosure. Simplifying the Accounting for Measurement-Period Adjustments . In September 2015, the FASB issued an accounting standards update that eliminates the requirement that an acquirer in a business combination account for measurement-period adjustments retrospectively. Instead, an acquirer will recognize a measurement-period adjustment during the period in which it determines the amount of the adjustment. Disclosure of the effect on earnings of any amounts an acquirer would have recorded in previous periods if the accounting had been completed at the acquisition date is required. The disclosure is required for each affected income statement line item, and may be presented separately on the face of the income statement or in the notes to the financial statements. The new guidance should be applied prospectively to adjustments to provisional amounts that occur after the effective date and is effective for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Early adoption is permitted for any interim and annual financial statements that have not yet been issued. The Company does not expect the impact of adopting this guidance to be material to the Company’s financial statements and related disclosures. Revenue from Contracts with Customers . In May 2014, the FASB issued a comprehensive new revenue recognition standard for contracts with customers that will supersede most current revenue recognition guidance, including industry-specific guidance. The core principle of this standard is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, the standard provides a five-step analysis of transactions to determine when and how revenue is recognized. In August 2015, the FASB issued an accounting standards update that formally delayed the effective date of its new revenue recognition standard. The new standard is now effective for fiscal years, and interim periods within those years, beginning after December 15, 2017. Early adoption is now permitted for fiscal years, and interim periods within those years, beginning after December 15, 2016. The standard permits the use of either the retrospective or cumulative effect transition method. This guidance will be applicable to the Company beginning on January 1, 2018. The Company has not yet selected a transition method and is currently evaluating the standard and the impact on its consolidated financial statements and footnote disclosures. Presentation of Debt Issuance Cost . In April 2015, the FASB issued an accounting standards update that requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying value of that debt liability, consistent with debt discounts. The guidance is effective retrospectively for fiscal years, and interim periods within those years, beginning after December 15, 2015. Early adoption is permitted for financial statements that have not been previously issued. The Company has chosen to adopt this standard and have applied this guidance in its consolidated financial statements and footnote disclosures. In August 2015, the FASB issued an accounting standards update that incorporates SEC guidance clarifying that debt issuance costs related to line-of-credit arrangements can be deferred and presented as an asset that is subsequently amortized over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The Company has elected this presentation in its consolidated financial statements and footnote disclosures as of December 31, 2015. Amendments to Consolidation Analysis . In February 2015, the FASB issued an accounting standards update to improve consolidation guidance for certain types of legal entities. The guidance modifies the evaluation of whether limited partnerships and similar legal entities are variable interest entities (“VIEs”) or voting interest entities, eliminates the presumption that a general partner should consolidate a limited partnership, affects the consolidation analysis of reporting entities that are involved with VIEs, particularly those that have fee arrangements and related party relationships, and provides a scope exception from consolidation guidance for certain money market funds. These provisions are effective for annual reporting periods beginning after December 15, 2015, and interim periods within those annual periods, with early adoption permitted. These provisions may also be adopted using either a full retrospective or a modified retrospective approach. Although the Company continues to assess the impact that adopting this new accounting guidance will have on its consolidated financial statements and footnote disclosures, we expect that MEMP will become a VIE. We believe we will continue to consolidate MEMP and become subject to the VIE primary beneficiary disclosure requirements. 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.

Discontinued Operations

Discontinued Operations	12 Months Ended
	Dec. 31, 2015
Discontinued Operations And Disposal Groups [Abstract]
Discontinued Operations	Note 3. Discontinued Operations As previously discussed in Note 1, we sold the Disposition Entities and its subsidiaries on June 1, 2016 to MEMP. Below is a reconciliation of carrying amounts of major classes of assets and liabilities included as part of discontinued operations as reflected on the balance sheets associated with this disposal transaction (in thousands): December 31, December 31, 2015 2014 ASSETS Current assets: Cash and cash equivalents $ 2,175 $ 2,594 Accounts receivable 61,403 98,498 Short-term derivative instruments 272,320 208,585 Prepaid expenses and other current assets 9,643 11,859 Total current assets 345,541 321,536 Property and equipment, net 1,946,937 2,471,011 Long-term derivative instruments 461,809 311,802 Restricted investments 152,631 77,361 Other long-term assets 5,053 5,062 Total assets $ 2,911,971 $ 3,186,772 LIABILITIES Current liabilities: Accounts payable $ 8,792 $ 24,813 Accounts payable - affiliates 193 464 Revenues payable 27,021 35,545 Accrued liabilities 52,923 95,835 Short-term derivative instruments 2,850 3,289 Total current liabilities 91,779 159,946 Long-term debt 2,000,579 1,574,147 Asset retirement obligations 162,989 112,702 Long-term derivative instruments 1,441 — Deferred tax liabilities 2,094 32,347 Total liabilities $ 2,258,882 $ 1,879,142 Below is a reconciliation of major line items constituting pretax profit (loss) of discontinued operations to the after tax profit (loss) of discontinued operations that are presented in the statement of operations (in thousands): For Year Ended December 31, 2015 2014 2013 Revenues: Oil & natural gas sales $ 355,422 $ 561,677 $ 391,440 Other revenues 2,725 4,366 3,075 Total revenues 358,147 566,043 394,515 Costs and expenses: Lease operating 168,199 143,733 94,591 Gathering, processing, and transportation 34,939 31,892 25,055 Exploration 2,317 2,750 1,322 Taxes other than income 25,828 33,141 18,447 Depreciation, depletion, and amortization 195,814 185,955 113,814 Impairment of proved oil and natural gas properties 616,784 407,540 4,072 General and administrative (1) 56,671 49,124 54,947 Accretion of asset retirement obligations 7,125 5,773 4,988 (Gain) loss on commodity derivative instruments (462,890 ) (492,254 ) (26,133 ) (Gain) loss on sale of properties (2,998 ) — (2,848 ) Other, net (665 ) (11 ) 647 Total costs and expenses 641,124 367,643 288,902 Operating income (loss) (282,977 ) 198,400 105,613 Other income (expense): Interest expense, net (114,732 ) (83,550 ) (44,302 ) Other, net 43 (657 ) 2 Total other income (expense) (114,689 ) (84,207 ) (44,300 ) Pretax profit (loss) of discontinued operations (397,666 ) 114,193 61,313 Income tax benefit (expense) 2,175 1,421 (308 ) Net income (loss) from discontinued operations $ (395,491 ) $ 115,614 $ 61,005 (1) Includes $32.3 million, $24.4 million and $9.4 million for the years ended December 31, 2015, 2014 and 2013 that was allocated to discontinued operations under an omnibus agreement. This omnibus agreement terminated on June 1, 2016. We entered into a transition services agreement with MEMP to manage post-closing separation costs and activities.

Acquisitions and Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2015
Business Combinations [Abstract]
Acquisitions and Divestitures	Note 4. Acquisitions and Divestitures The third party acquisitions discussed below were accounted for under the acquisition method of accounting. Accordingly, we, our predecessor, and the previous owners conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while acquisition costs associated with the acquisitions were expensed as incurred. The operating revenues and expenses of acquired properties are included in the accompanying financial statements from their respective closing dates forward. The transactions were financed through equity offerings, capital contributions and borrowings under credit facilities. The fair values of proved oil and natural gas properties are measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of proved oil and natural properties include estimates of: (i) economic reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital. Transaction-related costs Transaction-related costs for both related party and third party transactions are included in general and administrative expenses in the accompanying statements of operations for the periods indicated below (in thousands): For the Year Ended December 31, 2015 2014 2013 $ 1,974 $ 2,305 $ 1,584 2015 Acquisitions On June 1, 2015, we entered into an oil and gas lease option agreement with a third party pursuant to which we have the right to obtain one or more oil and gas leases in North Louisiana and is exercisable through February 2017. The purchase price of this option was approximately $4.0 million. The purchase price has been capitalized as part of unproved properties and will be expensed if the option is not exercised. On October 22, 2015, we closed a transaction to acquire certain proved and unproved oil and natural gas properties in North Louisiana from a third party for approximately $284.3 million (the “North Louisiana Acquisition”), of which $281.9 million of the purchase price was allocated to unproved oil and natural gas properties with the remainder allocated to proved oil and natural gas properties. 2015 Divestitures On April 17, 2015, we sold certain oil and natural gas properties in Colorado and Wyoming to a third party for approximately $13.6 million (the “Rockies Divestiture”) and recorded a gain of less than $0.1 million related to the sale. 2014 Acquisitions On December 30, 2014, we acquired certain oil and natural gas producing properties from third parties in the Terryville Complex for approximately $71.9 million, after customary post-closing adjustments (the “Louisiana Acquisition”). The following table summarizes the fair value assessment of the assets acquired and liabilities assumed as of the acquisition date (in thousands): Louisiana Acquisition Oil and gas properties $ 72,141 Asset retirement obligations (271 ) Total identifiable net assets $ 71,870 During the fourth quarter 2014, we 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. 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. The following table summarizes the fair value assessment of the assets acquired and liabilities assumed as of the acquisition date (in thousands): Oil and gas properties $ 68,887 Asset retirement obligations (1,789 ) Total identifiable net assets $ 67,098 2013 Divestitures On May 10, 2013, Black Diamond entered into a purchase and sale agreement with a third party to sell certain of its Wyoming oil and gas properties with an estimated net book value of $39.8 million for $33.0 million, before customary adjustments. As a result, Black Diamond recorded a loss on the sale of $6.8 million. This transaction closed on June 4, 2013. During 2013, BlueStone entered into an agreement with a third party to sell its remaining interest in certain properties in the Mossy Grove Prospect in Walker and Madison Counties located in East Texas. Total cash consideration received by BlueStone was approximately $117.9 million, which exceeded the net book value of the properties sold by $89.5 million. The transaction closed on July 31, 2013.

Fair Value Measurements of Fina

Fair Value Measurements of Financial Instruments	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Fair Value Measurements of Financial Instruments	Note 5. Fair Value Measurements of Financial Instruments Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. Fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk. A three-tier hierarchy has been established that classifies fair value amounts recognized or disclosed in the financial statements. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3). The characteristics of fair value amounts classified within each level of the hierarchy are described as follows: Level 1 — Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. An active market is one in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2 — Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. At December 31, 2015 and 2014, all of the derivative instruments reflected on the accompanying balance sheets were considered Level 2. Level 3 — Measure based on prices or valuation models that require inputs that are both significant to the fair value measurement and are less observable from objective sources (i.e., supported by little or no market activity). Assets and Liabilities Measured at Fair Value on a Recurring Basis The carrying values of cash and cash equivalents, accounts receivables, other financial assets, accounts payables (including accrued liabilities) and amounts outstanding under long-term debt agreements with variable rates included in the accompanying balance sheets approximated fair value at December 31, 2015 and December 31, 2014. The fair value estimates are based upon observable market data and are classified within Level 2 of the fair value hierarchy. These assets and liabilities are not presented in the following tables. See Note 8 for the estimated fair value of our outstanding fixed-rate debt. The fair market values of the derivative financial instruments reflected on the balance sheets as of December 31, 2015 and December 31, 2014 were based on estimated forward commodity prices (including nonperformance risk) and forward interest rate yield curves. Nonperformance risk is the risk that the obligation related to the derivative instrument will not be fulfilled. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement in its entirety. The significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The following table presents the derivative assets and liabilities that are measured at fair value on a recurring basis at December 31, 2015 and December 31, 2014 for each of the fair value hierarchy levels: Fair Value Measurements at December 31, 2015 Using Quoted Prices in Significant Other Significant Active Observable Unobservable Market Inputs Inputs (Level 1) (Level 2) (Level 3) Fair Value (In thousands) Assets: Commodity derivatives $ — $ 319,763 $ — $ 319,763 Liabilities: Commodity derivatives $ — $ 480 $ — $ 480 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 $ — $ 280,846 $ — $ 280,846 Liabilities: Commodity derivatives $ — $ 25,808 $ — $ 25,808 See Note 6 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 7 for a summary of changes in AROs. · If sufficient market data is not available, the determination of the fair values of proved and unproved properties acquired in transactions accounted for as business combinations are prepared by utilizing estimates of discounted cash flow projections. The factors to determine fair value include, but are not limited to, estimates of: (i) economic reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital. To compensate for the inherent risk of estimating and valuing unproved properties, the discounted future net revenues of probable and possible reserves are reduced by additional risk-weighting factors. The fair value of supporting equipment, such as plant assets, acquired in transactions accounted for as business combinations are commonly estimated using the depreciated replacement cost approach. · Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate the carrying value of such properties may not be recoverable. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. · During the year ended December 31, 2014, impairment expense of $24.6 million was recognized. 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, 2013, impairment expense of $2.5 million was recognized. The impairments related to certain properties located in Texas. The estimated future cash flows expected were compared to their carrying values and determined to be unrecoverable as a result of a downward revision of estimated proved reserves based on pricing terms specific to these properties.

Risk Management and Derivative

Risk Management and Derivative and Other Financial Instruments	12 Months Ended
	Dec. 31, 2015
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Risk Management and Derivative and Other Financial Instruments	Note 6. Risk Management and Derivative and Other Financial Instruments Derivative and other financial instruments are utilized to manage exposure to commodity price and interest rate fluctuations and achieve a more predictable cash flow in connection with natural gas and oil sales from production and borrowing related activities. These transactions limit exposure to declines in prices or increases in interest rates, but also limit the benefits that would be realized if prices increase or interest rates decrease. Certain inherent business risks are associated with commodity and interest derivative contracts and other financial instruments, including market risk and credit risk. Market risk is the risk that the price of natural gas or oil will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the counterparty to a contract. It is our policy to enter into derivative contracts, including interest rate swaps, and other financial instruments only with creditworthy counterparties, which generally are financial institutions, deemed by management as competent and competitive market makers. Some of the lenders, or certain of their affiliates, under our credit agreements are counterparties to our derivative contracts. While collateral is generally not required to be posted by counterparties, credit risk associated with derivative and other financial instruments is minimized by limiting exposure to any single counterparty and entering into derivative instruments only with counterparties that are large financial institutions, which management believes present minimal credit risk. Additionally, master netting agreements are used to mitigate risk of loss due to default with counterparties on derivative instruments. We have also entered into the International Swaps and Derivatives Association Master Agreements (“ISDA Agreements”) with each of our counterparties. The terms of the ISDA Agreements provide us and each of our counterparties with rights of set-off upon the occurrence of defined acts of default by either us or our counterparty to a derivative or other financial instrument, whereby the party not in default may set-off all liabilities owed to the defaulting party against all net derivative and other financial asset receivables from the defaulting party. At December 31, 2015, we had derivative and other financial assets of $365.4 million. After taking into effect netting arrangements, we had counterparty exposure of $169.1 million related to derivative and other financial instruments of which $86.8 million was with a single counterparty. Had certain counterparties failed completely to perform according to the terms of their existing contracts, we would have the right to offset $196.3 million against amounts outstanding under our revolving credit facility at December 31, 2015. See Note 8 for additional information regarding our revolving credit facility. Commodity Derivatives and Other Financial Instruments We may use a combination of commodity derivatives and other financial instruments (e.g., floating-for-fixed swaps, put options, costless collars and basis swaps) to manage exposure to commodity price volatility. We recognize all derivative instruments at fair value; however, certain of our put option derivative instruments have a deferred premium, which reduces the asset. For the deferred premium puts, the Company agrees to pay a premium to the counterparty at the time of settlement. At settlement, if the applicable index price is below the strike price of the put, the Company receives the difference between the strike price and the applicable index price multiplied by the contract volumes less the premium. If the applicable index price settles at or above the strike price of the put, the Company pays only the premium at settlement. Cash settlements received on settled derivative positions during 2015 is net of deferred premiums of $8.0 million. During the year ended December 31, 2015, we restructured our existing 2018 crude oil and natural gas hedges for crude oil and NGL swaps that will settle in 2016. Cash settlements of approximately $92.3 million from the terminated 2018 positions were received and applied as premiums for the new crude oil and NGL swaps. Certain contracts are classified as other financial instruments, which require bifurcation, based on the relationship between the fixed swap price and the market price at the restructure dates. Due to bifurcation, $46.1 million of the restructured contracts represents other financial assets at December 31, 2015. During the year ended December 31, 2014, we restructured a portion of our 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 TGT Z1 in proximity to our areas of production. Our oil derivative contracts are primarily indexed to NYMEX-WTI. Our NGL derivative contracts are primarily indexed to OPIS Mont Belvieu. At December 31, 2015, we had the following open commodity positions (excluding embedded derivatives): 2016 2017 Natural Gas Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (MMBtu) 2,570,000 1,770,000 Weighted-average fixed price $ 4.09 $ 4.24 Collar contracts: Average Monthly Volume (MMBtu) 1,100,000 1,050,000 Weighted-average floor price $ 4.00 $ 4.00 Weighted-average ceiling price $ 4.71 $ 5.06 Purchased put option contracts: Average Monthly Volume (MMBtu) 6,000,000 5,350,000 Weighted-average strike price $ 3.51 $ 3.48 Weighted-average deferred premium paid $ (0.34 ) $ (0.32 ) TGT Z1 basis swaps: Average Monthly Volume (MMBtu) 1,120,000 200,000 Spread - Henry Hub $ (0.10 ) $ (0.08 ) Crude Oil Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 35,583 28,000 Weighted-average fixed price $ 83.58 $ 84.70 Collar contracts: Average Monthly Volume (Bbls) 27,000 — Weighted-average floor price $ 80.00 $ — Weighted-average ceiling price $ 99.70 $ — NGL Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 353,399 — Weighted-average fixed price $ 39.68 $ — At December 31, 2015, we had the following open embedded derivative positions: 2016 Oil Hybrid Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 27,080 Weighted-average fixed price $ 46.51 Initial net investment price 62.16 Total contract swap price $ 108.67 NGL Hybrid Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 83,101 Weighted-average fixed price $ 15.84 Initial net investment price 25.98 Total contract swap price $ 41.82 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 revolving credit agreement to fixed interest rates. On July 1, 2014, we elected to terminate the interest rate swaps associated with our 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. We did not have any interest rate swaps at December 31, 2015. Balance Sheet Presentation The following table summarizes both: (i) the gross fair value of derivative instruments by the appropriate balance sheet classification even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the balance sheet and (ii) the net recorded fair value as reflected on the balance sheet at December 31, 2015 and 2014. There was no cash collateral received or pledged associated with our derivative instruments since most of the counterparties, or certain affiliates, to our derivative contracts are lenders under our credit agreement. Asset Derivatives Liability Derivatives Type Balance Sheet Location 2015 2014 2015 2014 (In thousands) Commodity contracts Short-term derivative instruments $ 228,349 $ 153,026 $ 358 $ 21,555 Netting arrangements Short-term derivative instruments (358 ) (21,555 ) (358 ) (21,555 ) Net recorded fair value Short-term derivative instruments $ 227,991 $ 131,471 $ — $ — Commodity contracts Long-term derivative instruments $ 91,414 $ 127,820 $ 122 $ 4,253 Netting arrangements Long-term derivative instruments (122 ) (4,253 ) (122 ) (4,253 ) Net recorded fair value Long-term derivative instruments $ 91,292 $ 123,567 $ — $ — (Gains) & Losses on Derivatives All gains and losses, including changes in the derivative instruments’ fair values, have been recorded in the accompanying statements of operations since derivative instruments are not designated as hedging instruments for accounting and financial reporting purposes. The following table details the gains and losses related to derivative instruments for the years ending December 31, 2015, 2014, and 2013: Statements of For the Year Ended December 31, Operations Location 2015 2014 2013 Commodity derivative contracts (Gain) loss on commodity derivatives $ (281,249 ) $ (257,734 ) $ (3,161 ) Interest rate derivatives Interest expense, net — 296 309

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Note 7. Asset Retirement Obligations Asset retirement obligations primarily relate to our portion of future plugging and abandonment of wells and related facilities. The following table presents the changes in the asset retirement obligations for the years ended December 31, 2015, 2014 and 2013: 2015 2014 2013 (In thousands) Asset retirement obligations at beginning of period $ 9,829 $ 10,333 $ 9,349 Liabilities added from acquisitions or drilling 1,348 786 2,111 Liabilities settled — — (150 ) Revision of estimates 927 (97 ) 195 Liabilities removed upon sale of wells (2,442 ) (1,726 ) (1,765 ) Accretion expense 417 533 593 Asset retirement obligations at end of period 10,079 9,829 10,333 Less: Current portion — — 90 Asset retirement obligations - long-term portion $ 10,079 $ 9,829 $ 10,243

Long Term Debt

Long Term Debt	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Long Term Debt	Note 8. Long Term Debt The following table presents our debt obligations at the dates indicated. December 31, December 31, 2015 2014 (In thousands) $2.0 billion revolving credit facility, variable-rate, due June 2019 $ 423,000 $ 183,000 5.875% senior unsecured notes, due July 2022 ("MRD Senior Notes") (1) (2) 600,000 600,000 Unamortized debt issuance costs (10,936 ) (12,455 ) Total long-term debt $ 1,012,064 $ 770,545 (1) The estimated fair value of this fixed-rate debt was $525.0 million and $534.0 million at December 31, 2015 and 2014, respectively. (2) The estimated fair value 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. Our revolving credit facility borrowing base is subject to redetermination on at least a semi-annual basis primarily based on estimated proved reserves. The borrowing base for our revolving credit facility was the following at the date indicated: December 31, 2015 $2.0 billion revolving credit facility, variable-rate, due June 2019 $ 1,000,000 Revolving Credit Facility On June 18, 2014, we, as borrower, and certain of our subsidiaries, as guarantors, entered into a revolving credit facility, which is a five-year, $2.0 billion revolving credit facility. We are permitted to borrow under the revolving credit facility in an amount up to the lesser of (i) the face amount of our revolving credit facility, (ii) the borrowing base or (iii) the aggregate elected commitments. The revolving credit facility is reserve-based, and thus our borrowing base is primarily based on the estimated value of our oil and natural gas properties and our commodity derivative contracts as determined semi-annually by our lenders in their sole discretion. Our borrowing base is subject to redetermination on a semi-annual basis based on an engineering report with respect to our estimated oil, NGL and natural gas reserves, which will take into account the prevailing oil, NGL and natural gas prices at such time, as adjusted for the impact of our commodity derivative contracts. Unanimous approval by the lenders is required for any increase to the borrowing base. In addition, we may, subject to certain conditions, increase our aggregate elected commitments in an amount not to exceed the then effective borrowing base on or following a scheduled redetermination of our borrowing base once before the next scheduled redetermination date. Borrowings under the revolving credit facility are secured by liens on substantially all of our properties, but in any event, not less than 80% of the total value of our oil and natural gas properties, and all of our equity interests in any future guarantor subsidiaries and all of our other assets including personal property. Additionally, borrowings bear interest, at our option, at either (i) the greatest of (x) the prime rate as determined by the administrative agent, (y) the federal funds effective rate plus 0.50%, and (z) the one-month adjusted LIBOR plus 1.0% (adjusted upwards, if necessary, to the next 1/100th of 1%), in each case, plus a margin that varies from 0.50% to 1.50% per annum according to the total commitment usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect), or (ii) the applicable LIBOR plus a margin that varies from 1.50% to 2.50% per annum according to the total commitment usage. The unused portion of the total commitments is subject to a commitment fee that varies from 0.375% to 0.50% per annum according to our total commitments usage. The revolving credit facility requires maintenance of a ratio of Consolidated EBITDAX to Consolidated Net Interest Expense (as each term is determined under the revolving credit facility), which we refer to as the interest coverage ratio, of not less than 2.5 to 1.0, and a ratio of consolidated current assets to consolidated current liabilities, each as determined under the revolving credit facility, which we refer to as the current ratio, of not less than 1.0 to 1.0. Additionally, the revolving credit facility contains various covenants and restrictive provisions that, among other things, limit our ability to incur additional debt, guarantees or liens; consolidate, merge or transfer all or substantially all of our assets; make certain investments, acquisitions or other restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; incur commodity hedges exceeding a certain percentage of our production and prepay certain indebtedness. Events of default under the revolving credit facility include, but are not limited to, failure to make payments when due, breach of any covenant continuing beyond the applicable cure period, default under any other material debt, change in management or change of control, bankruptcy or other insolvency event and certain material adverse effects on our business. MRD 5.875% Senior Unsecured Notes On July 10, 2014, we 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. Effective June 1, 2016, the guarantor subsidiaries are 100% owned by the Company; the Company has no material assets or operations independent of the guarantor subsidiaries; and there are no significant restrictions upon the ability of the guarantor subsidiaries to distribute funds to the Company. The MRD Senior Notes are governed by an indenture dated as of July 10, 2014. The MRD Senior Notes are subject to optional redemption at prices specified in the indenture plus accrued and unpaid interest, if any, to the date of redemption. The Company may also be required to repurchase the MRD Senior Notes upon a change of control. The indenture contains customary covenants and restrictive provisions, many of which will terminate if at any time no default exists under the indenture and the MRD Senior Notes receive an investment grade rating from both of two specified ratings agencies. MEMP and its subsidiaries are not subject to these covenants. The indenture also provides for customary and other events of default. In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to either the Company or the guarantors, all outstanding MRD Senior Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding MRD Senior Notes may declare all the MRD Senior Notes to be due and payable immediately. PIK Notes On December 18, 2013, MRD LLC and its wholly-owned subsidiary Memorial Resource Finance Corp. (“MRD Finance Corp.” and, together with MRD LLC, the “MRD Issuers”) completed a private placement of $350.0 million in aggregate principal amount of the PIK notes. The PIK notes were issued at 98% of par with a maturity date of December 15, 2018. Net proceeds from the private offering were used: (i) to repay all indebtedness then outstanding under MRD LLC’s then-existing revolving credit facility, (ii) to establish a cash reserve of $50.0 million for the payment of interest on the PIK notes, (iii) to pay a $210.0 million distribution to the Funds, and (iv) for general company purposes. Interest on the PIK notes was payable semi-annually in arrears on June 15 and December 15 of each year, commencing on June 15, 2014. A redemption notice was delivered to the PIK notes trustee on June 16, 2014, which specified a redemption date of July 16, 2014 at a redemption price of 102% of the principal amount of the PIK notes plus accrued and unpaid interest thereon to the date of redemption. In connection with the closing of our initial public offering, we assumed the obligations of MRD LLC under the PIK notes indenture and the related debt security agreement. We irrevocably deposited with the PIK notes trustee approximately $360.0 million on June 27, 2014, which was an amount sufficient to fund the redemption of the PIK notes on the redemption date and to satisfy and discharge our obligations under the PIK notes and the related indenture. The discharge became effective upon the irrevocable deposit of the funds with the PIK notes trustee. An extinguishment loss of $23.6 million was recognized related to the redemption of the PIK notes. WildHorse Resources Revolving Credit Facility and Second Lien Facility On April 3, 2013, WildHorse Resources entered into an amended and restated credit agreement. This revolving credit facility provided for aggregate maximum credit amounts at any time of $1.0 billion, consisting of borrowings and letters of credit. This revolving credit facility was due to mature on April 13, 2018. The borrowing base was subject to redetermination on at least a semi-annual basis. Borrowings under the revolving credit facility were to be secured by liens on substantially all of WildHorse Resources’ properties, but in any event, not less than 80% of the total value of the WildHorse Resources’ oil and natural gas properties. On June 13, 2013, WildHorse Resources entered into a $325.0 million second lien term loan agreement that was due to mature on December 13, 2018. Borrowings bore interest, at the borrower’s option, at either: (i) the Alternative Base Rate (as defined within each credit facility) plus 5.25% per annum or (ii) the applicable LIBOR plus 6.25% per annum. Borrowings under the second lien term loan agreement were to be secured by second-priority liens on substantially all of WildHorse Resources’ properties, but in any event, not less than 80% of the total value of the WildHorse Resources’ oil and natural gas properties. The priority of the security interests in the collateral and related creditors’ rights was set forth in an intercreditor agreement. The second lien term loan agreement contained customary affirmative and negative covenants, restrictive provisions and events of default. On June 13, 2013, WildHorse Resources borrowed $325.0 million under its second lien term loan agreement and used such borrowings to reduce outstanding indebtedness under its revolving credit facility and to pay a onetime special $225.0 million distribution to MRD LLC. This $225.0 million distribution was subsequently distributed to the Funds. In connection with the closing of our initial public offering, the WildHorse Resources’ revolving credit facility and second lien term loan were repaid in full and terminated. An extinguishment loss of $13.7 million was recognized related to the termination of the revolving credit facility and second lien term loan. Weighted-Average Interest Rates The following table presents the weighted-average interest rates paid on our variable-rate debt obligations for the periods presented: Credit Facility For the Year Ended December 31, 2015 2014 2013 Revolving credit facility 1.92 % 1.99 % n/a WildHorse Resources revolver terminated June 2014 n/a 4.04 % 2.30 % WildHorse Resources second lien terminated June 2014 n/a 6.44 % 7.60 % Black Diamond terminated November 2013 n/a n/a 3.97 % Unamortized Deferred Financing Costs Unamortized deferred financing costs associated with our debt obligations were as follows at the dates indicated: December 31, December 31, 2015 2014 (In thousands) Revolving credit facility $ 4,976 $ 4,285 Senior Notes 10,936 12,455 $ 15,912 $ 16,740

Stockholders' Equity and Noncon

Stockholders' Equity and Noncontrolling Interests	12 Months Ended
	Dec. 31, 2015
Equity [Abstract]
Stockholders' Equity and Noncontrolling Interests	Note 9. Stockholders’ Equity and Noncontrolling Interests Common Stock The Company’s authorized capital stock includes 600,000,000 shares of common stock, $0.01 par value per share. The following is a summary of the changes in our common shares since January 1, 2014: Balance January 1, 2014 — Shares of common stock issued 192,500,000 Shares of common stock repurchased (123,797 ) Restricted common shares issued (Note 11) 1,068,422 Restricted common shares forfeited (9,211 ) Balance December 31, 2014 193,435,414 Shares of common stock issued 13,800,000 Shares of common stock repurchased (2,764,887 ) Restricted common shares issued (Note 11) 938,558 Restricted common shares repurchased (1) (60,773 ) Restricted common shares forfeited (54,569 ) Balance December 31, 2015 205,293,743 (1) Restricted common shares are generally net-settled by shareholders to cover the required withholding tax upon vesting. Participants surrendered shares with value equivalent to the employee’s minimum statutory obligation for the applicable income and other employment taxes. Total payments remitted for the employees’ tax obligations to the appropriate taxing authorities were approximately $1.2 million. These net-settlements had the effect of shares repurchased by the Company as they reduced the number of shares that would have otherwise been outstanding as a result of the vesting and did not represent an expense to the Company. See Note 11 for additional information regarding restricted common shares that were granted in connection with our long-term incentive plan. Restricted shares of common stock are participating securities and considered issued and outstanding on the grant date of restricted stock award. On September 25, 2015, the Company issued 13,800,000 shares of common stock (including 1,800,000 shares of common stock sold pursuant to the full exercise of the underwriters’ option to purchase additional shares of common stock) to the public generating total net proceeds of approximately $238.1 million after deducting underwriting discounts and offering expenses. The net proceeds from the equity offering were used to temporarily pay down our revolving credit facility and subsequently re-borrowed to fund a portion of the purchase price of the North Louisiana Acquisition that closed on October 22, 2015. Share Repurchase Program In December 2014, the board of directors (“Board”) of the Company authorized the repurchase of up to $50.0 million of the Company’s outstanding common stock from time to time on the open market, through block trades or otherwise and subject to market conditions, as well as corporate, regulatory, and other considerations. During the year ended December 31, 2014, 123,797 shares of common stock were repurchased and retired for a total cost of approximately $2.2 million. We repurchased 2,764,887 shares of common stock under our repurchase program for an aggregate price of $47.8 million through March 16, 2015, which exhausted the December 2014 repurchase program. We have retired all of the shares of common stock repurchased and the shares of common stock are no longer issued or outstanding. In April 2015, the Board authorized the repurchase of up to $50.0 million of the Company’s outstanding common stock from time to time on the open market, through block trades or otherwise. The Company is not obligated to repurchase any dollar amount or specific number of shares of its common stock under the program, which may be suspended or discontinued at any time. The amount, timing and price of purchases will depend on market conditions and other factors. The Company did not repurchase any shares of common stock under this program through December 31, 2015. Preferred Stock Our amended and restated certificate of incorporation authorizes our Board, subject to any limitations prescribed by law, without further stockholder approval, to establish and to issue from time to time one or more classes or series of preferred stock, par value $0.01 per share, covering up to an aggregate of 50,000,000 shares of preferred stock. There are no shares of preferred stock issued and outstanding as of December 31, 2015. Dividend Policy We do not anticipate declaring or providing any cash dividends to holders of our common stock in the foreseeable future. We currently intend to retain all future earnings, if any, for use in the operation of our business and to fund future growth. The decision whether to pay dividends in the future will be made by our Board in light of conditions then existing, including factors such as our financial condition, earnings, available cash, business opportunities, legal requirements, restrictions in our debt agreements, and other contracts and other factors our Board deems relevant. Noncontrolling Interests Noncontrolling interests is the portion of equity ownership in the Company’s consolidated subsidiaries not attributable to the Company and primarily consists of the equity interests held by the limited partners of MEMP. Prior to our initial public offering, certain current or former key employees of certain of MRD LLC’s subsidiaries also held equity interests in those subsidiaries. Distributions paid to the limited partners of MEMP primarily represent the quarterly cash distributions paid to MEMP’s unitholders, excluding those paid to MRD LLC prior to our initial public offering. Contributions received from limited partners of MEMP primarily represent net cash proceeds received from common unit offerings. These distributions and contributions are a component of net cash provided by discontinued operations from financing activities as presented on our cash flow statement. 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, including Mr. Graham, contributed their 0.1% membership interest in WildHorse Resources as well as their incentive units in exchange for shares of our common stock and cash consideration of $30.0 million. The difference between the carrying amount of the noncontrolling interest of $0.4 million and the fair value of the consideration paid of $3.3 million was recognized directly in stockholders’ equity as additional paid in capital. See Note 12 for further information.

Earnings per share

Earnings per share	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
Earnings per share	Note 10. Earnings per share The following sets forth the calculation of earnings (loss) per share, or EPS, for the period indicated (in thousands, except per share amounts): For the Year Ended December 31, 2015 2014 Numerator: Net income (loss) from continuing operations available to common stockholders $ 95,241 $ (784,895 ) Net income (loss) from discontinued operations available to common stockholders $ (327 ) $ 314 Denominator: Weighted average common shares outstanding 193,698 192,498 Incremental treasury stock method shares (1) 469 203 Basic EPS from continuing operations $ 0.49 $ (4.08 ) Diluted EPS from continuing operations(1) $ 0.49 $ (4.08 ) Basic EPS from discontinued operations $ — $ — Diluted EPS from discontinued operations(1) $ — $ — (1) The Company determines the more dilutive of either the two-class method or the treasury stock method for diluted EPS. The two-class method was more dilutive for each period presented.

Long-Term Incentive Plans

Long-Term Incentive Plans	12 Months Ended
	Dec. 31, 2015
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Long-Term Incentive Plans	Note 11. Long-Term Incentive Plan In June 2014, our Board adopted the Memorial Resource Development Corp. 2014 Long Term Incentive Plan (“MRD LTIP”) for the employees of the Company and the Board. The MRD LTIP became effective upon filing of a registration statement on Form S-8 with the SEC on June 18, 2014. The MRD LTIP provides for potential grants of stock options, stock appreciation rights, restricted stock awards, restricted stock units, bonus stock, dividend equivalents, performance awards, annual incentive awards, and other stock-based awards. The MRD LTIP initially limits the number of common shares that may be delivered pursuant to awards under the plan up to 19,250,000 common shares. Common shares that are cancelled, forfeited or withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards. The MRD LTIP will be administered by our Board or a committee thereof. Restricted stock awards granted to our employees subsequent to our initial public offering generally vest ratably on a three-year annual vesting schedule from the date of the grant. In connection with our initial public offering, our Board approved an aggregate award of 1,052,633 shares of restricted stock under the MRD LTIP to certain of our key employees, including each of our executive officers. These restricted stock awards will vest ratably on a four-year annual vesting schedule from the date of the grant and are subject to restrictions on transferability and customary forfeiture provisions. An award of 5,263 shares of restricted stock was also granted to each of our independent directors. These restricted stock awards will vest one year from the date of the grant and are also subject to restrictions on transferability and customary forfeiture provisions. Award recipients are entitled to all the rights of absolute ownership of the restricted common shares, including the right to vote those shares and to receive dividends thereon if, as, and when declared by our Board. The term “restricted common share” represents a time-vested share. Such awards are non-vested until the required service period expires. The following table summarizes information regarding restricted common share awards granted under the MRD LTIP for the periods presented: Number of Shares Weighted-Average Grant Date Fair Value per Share (1) Restricted common shares outstanding at January 1, 2014 — $ — Granted (2) 1,068,422 $ 19.00 Forfeited (9,211 ) $ 19.00 Restricted common shares outstanding at December 31, 2014 1,059,211 $ 19.00 Granted (3) 938,558 $ 18.80 Forfeited (54,569 ) $ 18.83 Vested (274,355 ) $ 19.00 Restricted common shares outstanding at December 31, 2015 1,668,845 $ 18.89 (1) Determined by dividing the aggregate grant date fair value of awards by the number of awards issued. (2) The aggregate grant date fair value of restricted common share awards issued in 2014 was $20.3 million based on grant date market price of $19.00 per share (3) The aggregate grant date fair value of restricted common share awards issued in 2015 was $17.6 million based on grant date market prices ranging from $17.58 to $18.91 per share. The following table summarizes the amount of recognized compensation expense associated with these awards that are reflected in the accompanying statements of operations for the periods presented (in thousands): For the Year Ended December 31, 2015 2014 $ 8,788 $ 2,804 The unrecognized compensation cost associated with restricted common share awards was an aggregate $25.1 million at December 31, 2015. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.42 years. Subsequent event. An award of 8,023 shares of restricted stock was granted to each of our independent directors on January 8, 2016 and will vest one year from the date of grant.

Incentive Units

Incentive Units	12 Months Ended
	Dec. 31, 2015
Compensation Related Costs [Abstract]
Incentive Units	Note 12. Incentive Units General Each of the governing documents of BlueStone, Tanos, WildHorse Resources, Classic, Black Diamond and MRD LLC previously provided for the issuance of incentive units. The incentive units were subject to performance conditions that affected their vesting. Compensation cost was recognized only if the performance condition was probable of being satisfied at each reporting date. BlueStone, Tanos, WildHorse Resources, Classic, Black Diamond and MRD LLC each granted incentive units to certain of its members who were key employees at the time of grant. Holders of incentive units were entitled to distributions ranging from 10% to 31.5% when declared, but only after cumulative distribution thresholds (“payouts”) had been achieved. Payouts were generally triggered after the recovery of specified members’ capital contributions plus a rate of return. In connection with MEMP’s initial public offering in December 2011, BlueStone’s Special Tier and Tier I unit holders vested in their respective awards. Tier I unit holders became eligible to participate in 16.5% of any future distributions made by BlueStone. Vesting of the incentive units was generally dependent upon an explicit service period, a fundamental change as defined in the respective governing document, and achievement of payout. All incentive units not vested were forfeited if an employee was no longer employed. All incentive units were forfeited if a holder resigned whether the incentive units were vested or not. If the payouts had not yet occurred, then all incentive units, whether or not vested, were forfeited automatically (unless extended). On April 1, 2013, Tanos’ management team sold its 1.066% interest in Tanos to MRD LLC and all incentive units held were forfeited. Compensation expense of approximately $5.8 million was recorded by Tanos and is reflected as a component of discontinued operations 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, of which $8.3 million is reflected as a component of discontinued operations. Compensation expense of approximately $1.0 million and $20.7 million was recorded by BlueStone and recognized as a component of incentive unit compensation expense during the year ended December 31, 2014 and 2013, respectively. In connection with the PIK notes issued in December 2013, a special distribution of $10.0 million to holders of WildHorse’s Tier 1 incentive units was deemed probable of occurring. This amount was recognized as compensation expense in December 2013. In connection with the our initial public offering, certain former management members of WildHorse Resources contributed their 0.1% membership interest in WildHorse Resources as well as their incentive units in exchange for 42,334,323 shares of our common stock and cash consideration of $30.0 million. The portion of the total consideration related to acquiring the 0.1% membership interest was accounted for as the acquisition of noncontrolling interests. The difference between the carrying amount of the noncontrolling interest of $0.4 million and the fair value of the consideration paid of $3.3 million was recognized directly in stockholders’ equity as additional paid in capital. Compensation expense of approximately $831.1 million was recognized as a component of incentive unit compensation expense during the year ended December 31, 2014 related to the incentive units, of which approximately $26.7 million was paid in cash and the remaining $804.4 million related to the issuance of our common stock. MRD Holdco MRD LLC incentive units were originally granted in June 2012 and February 2013. In connection with our initial public offering and the related restructuring transactions, these incentive units were exchanged for substantially identical units in MRD Holdco, and such incentive units entitle holders thereof to portions of future distributions by MRD Holdco. MRD Holdco’s governing documents authorize the issuance of 1,000 incentive units, of which 930 incentive units were granted in an exchange for the cancelled MRD LLC awards (the “Exchanged Incentive Units”). Subsequent to our initial public offering, MRD Holdco granted the remaining 70 incentive units to certain key employees (the “Subsequent Incentive Units”). We recognized $35.2 million and $111.9 million of compensation expense in 2015 and 2014, respectively, offset by a deemed capital contribution from MRD Holdco and the unrecognized compensation expense of approximately $58.8 million as of December 31, 2015 will be recognized over the remaining expected service period of 1.42 years. The fair value of the Exchanged and Subsequent Incentive Units will be remeasured on a quarterly basis until all payments have been made. The settlement obligation rests with MRD Holdco. Accordingly, no payments will ever be made by us related to these incentive units; however, non-cash compensation expense (income) will be allocated to us in future periods offset by capital contributions (distributions). As such, these awards are not dilutive to our stockholders. The fair value of the incentive units was estimated using a Monte Carlo simulation valuation model with the following assumptions: Exchanged Incentive Units Subsequent Incentive Units Valuation date 12/31/2015 12/31/2015 Dividend yield 0 % 0 % Expected volatility 51.30 % 51.30 % Risk-free rate 0.82 % 0.82 % Expected life (years) 1.42 1.42

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2015
Related Party Transactions [Abstract]
Related Party Transactions	Note 13. Related Party Transactions Amounts due to MRD Holdco and certain affiliates of NGP at December 31, 2015 and 2014 are presented as “Accounts payable – affiliates” in the accompanying balance sheets. NGP Affiliated Companies During the year ended December 31, 2015, we paid approximately $8.5 million to Cretic Energy Services, LLC, an NGP affiliated company, for services related to our drilling and completion activities. During the year ended December 31, 2015, we paid approximately $2.3 million to Multi-Shot, LLC, an NGP affiliated company, for services related to our drilling and completion activities, of which $0.3 million was attributable to discontinued operations. Net Profits Interest Sold to NGP Upon the completion of the 2010 Petrohawk and Clayton Williams acquisitions, WildHorse Resources sold a net profits interest in these properties to NGPCIF. Upon the acquisition of the Petrohawk properties WildHorse Resources immediately sold a net profits interest of 6.25% for all producing well bores and the right to participate in a 3.125% net profits interest in non-producing wellbores for the subject area for $19.5 million, or $19.1 million after adjustments. Upon the acquisition of the Clayton Williams properties, WildHorse Resources immediately sold a net profits interest of 23.5% for all producing wellbores and the right to participate in a 10.0% net profits interest in non-producing wellbores for the subject area for $19.8 million, or $19.9 million after adjustments. No gain or loss was recorded from these two transactions. The net profits agreements for these transactions provided for a fixed fee of $20,000 per month for overhead and management in lieu of COPAS (Council of Petroleum Accountants Societies) billings. The net profits agreements did not provide for an overhead adjustment factor for this monthly charge, as suggested by COPAS. Quarterly net payments were made to NGPCIF for its net profits interest in the Petrohawk and Clayton Williams acquisitions. The net payments included credits for revenue receipts which were offset with production costs, capital expenditures and the management fee and were adjusted for any acquisition settlements received or paid and any other miscellaneous adjustments. As required by such agreements, WildHorse Resources could not collect funds owed by NGPCIF to WildHorse Resources, but WildHorse Resources could net amounts due from future quarterly payments. As a result of these transactions, WildHorse Resources paid NGPCIF a total of $2.6 million during 2013. NGPCIF owed WildHorse Resources $0.2 million at December 31, 2013. NGPCIF NPI Acquisition WildHorse Resources repurchased the net profits interests discussed above from NGPCIF on February 28, 2014 for a purchase price of $63.4 million (see Note 1). This acquisition was accounted for as a combination of entities under common control at historical cost in a manner similar to the pooling of interest method. WildHorse Resources recorded the following net assets (in thousands): Accounts receivable $ 2,274 Oil and natural gas properties, net 40,056 Accrued liabilities (297 ) Asset retirement obligations (277 ) Net assets $ 41,756 Due to common control considerations, the difference between the purchase price and the net assets acquired are reflected within equity as a deemed distribution to NGP affiliates. Transactions Between the Previous Owners and NGP Affiliates The previous owners sold certain interests in oil and gas properties offshore Louisiana on October 11, 2012. The remaining proceeds of approximately $2.0 million were released from escrow in April 2013, which is reflected as a component of net cash provided by discontinued operations from financing activities as presented on our cash flow statement. 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 $507.1 million was received by certain affiliates of NGP and included as a component of discontinued operation on the statement of cash flows. We refer to this transaction as the “Cinco Group acquisition.” The Cinco Group acquisition was funded with borrowings under MEMP’s revolving credit facility, which is also included in discontinued operations. The Cinco Group acquisition was accounted for as a combination of entities under common control at historical cost in a manner similar to the pooling of interest method. The net assets acquired were as follows (in thousands): Cash and cash equivalents $ 2,820 Accounts receivable 5,184 Prepaid expenses and other current assets 1,454 Oil and natural gas properties, net 342,759 Long-term derivative instruments, net (826 ) Other long-term assets 344 Accounts payable (2,346 ) Revenue payable (2,910 ) Accrued liabilities (1,799 ) Short-term derivative instruments, net (1,828 ) Asset retirement obligations (9,606 ) Credit facilities (151,690 ) Net assets $ 181,556 Other Acquisitions or Dispositions On November 2, 2015, in connection with an auction process administered by a third-party, MEMP divested certain oil and gas properties in the Permian Basin to an affiliate of NGP for a purchase price of approximately $0.9 million. Due to common control considerations, the proceeds from the sale exceeded the net book value of the properties by $0.7 million and is recognized as a contribution in the equity statement. On March 10, 2014, BlueStone sold certain interests in oil and gas properties in McMullen, Webb, Zapata, and Hidalgo Counties located in South Texas to BlueStone Natural Resources II, LLC, an NGP controlled entity. Total cash consideration received by BlueStone was approximately $1.2 million, which exceeded the net book value of the properties sold by $0.5 million. Due to common control considerations, the $0.5 million was recognized in the equity statement as a contribution. On March 28, 2014, MRD Royalty acquired certain interests in oil and gas properties in Gonzales and Karnes Counties located in South Texas from Propel Energy for $3.3 million. On June 18, 2014, in connection with our initial public offering and the related restructuring transactions (see Note 1), WHR Management Company was sold by WildHorse Resources to an affiliate of the Funds for net book value. The net book value of the assets sold was as follows (in thousands): Cash and cash equivalents $ 33,001 Restricted cash 300 Accounts receivable 5,256 Prepaid expenses and other current assets 379 Property, plant and equipment, net 3,410 Other long-term assets 4 Accounts payable (19,959 ) Accounts payable - affiliates (17,099 ) Accrued liabilities (5,061 ) Net assets $ 231 Related Party Agreements We and certain of our affiliates have entered into various documents and agreements. These agreements have been negotiated among affiliated parties and, consequently, are not the result of arm’s-length negotiations. Registration Rights Agreement In connection with the closing of our initial public offering, we entered into a registration rights agreement with MRD Holdco and former management members of WildHorse Resources, Jay Graham (“Graham”) and Anthony Bahr (“Bahr”). Pursuant to the registration rights agreement, we have agreed to register the sale of shares of our common stock under certain circumstances. Voting Agreement In connection with the closing of our initial public offering, we entered into a voting agreement with MRD Holdco, WHR Incentive LLC, a limited liability company beneficially owned by Messrs. Bahr and Graham, and certain former management members of WildHorse Resources, including Graham, who contributed their ownership of WildHorse Resources to us in the restructuring transactions. Among other things, the voting agreement provides that Graham and those former management members of WildHorse Resources will vote all of their shares of our common stock as directed by MRD Holdco. The voting agreement also provides MRD Holdco with the right to designate up to three nominees to the Board, provided that such number of nominees shall be reduced to two, one and zero if the Funds and their affiliates collectively own less than 35%, 15%, and 5% respectively, of the outstanding shares of our common stock. The voting agreement also requires us and the stockholders party thereto to take all necessary actions, to the fullest extent permitted by applicable law (including with respect to any fiduciary duties under Delaware law), including voting their shares of our common stock, to cause the election of the nominees designated by MRD Holdco. In addition, the voting agreement provides that for so long as MRD Holdco has the right to designate two directors to the Board, we will cause any committee of the Board to include in its membership at least one director designated by MRD Holdco, except to the extent that such membership would violate applicable securities laws or stock exchange rules. Services Agreement In connection with the closing of our initial public offering, we entered into a services agreement with WildHorse Resources and WHR Management Company, pursuant to which WHR Management Company agreed to provide operating and administrative services to us for twelve months relating to the Terryville Complex. In exchange for such services, we paid a monthly management fee to WHR Management Company of approximately $1.0 million excluding third party COPAS income credits. Upon the closing of our initial public offering, WHR Management Company became a subsidiary of WildHorse Resources II, LLC, an affiliate of the Company. NGP, Graham and certain former management members of WildHorse Resources own WHR II. The services agreement was terminated effective March 1, 2015. WildHorse Management Services Agreement WHR II is an independent energy company engaged in the acquisition, exploration, and development of natural gas and crude oil properties. WHR II is a related party and was organized in the State of Delaware on June 3, 2013. A management services agreement was executed on August 8, 2013, where WildHorse Resources provided general, administrative and employee services to WHR II. On August 8, 2013, a management agreement between WildHorse Resources and WHR II was executed where WildHorse was appointed the manager for WHR II with responsibilities included administrative and land services, operator services and financial and accounting services. As operator, WildHorse Resources received operated and non-operated revenues on behalf of WHR II and billed and received joint interest billings. In addition, WildHorse Resources paid for lease operating expenses and drilling costs on behalf of WHR II. On August 8, 2013, an asset and cost sharing agreement between WildHorse Resources and WHR II was executed. As part of the agreement, shared WildHorse Resources costs were allocated between WildHorse Resources and WHR II in accordance with a sharing ratio. The sharing ratio is based on the previous quarter’s capital expenditures and number of operated wells. Company specific costs were billed directly to the appropriate entity. As a result of these agreements, WildHorse Resources received net payments of $4.4 million from WHR II in 2013. WildHorse Resources owed WHR II $2.4 million as of December 31, 2013. These agreements were terminated in connection with our initial public offering. Cinco Group Transition Service Agreements MEMP entered into transition service agreements with Propel Energy, Stanolind, and Boaz Energy Partners to provide operating and administrative services to MEMP with respect to the acquired properties. The term of these agreements were from October 1, 2013 through February 28, 2014. MEMP paid transition service fees of approximately $0.8 million in the aggregate under these agreements. Other Agreements Certain of the Cinco Group entities entered into advisory service, reimbursement, and indemnification agreements with NGP. These agreements generally required that an annual advisory fee be paid to NGP. Fees paid under these agreements for the year ended December 31, 2013 were approximately $0.3 million. Midstream Agreements Prior to our initial public offering, we entered into various midstream service agreements with affiliates of PennTex Midstream Partners, LP (“PennTex”), an affiliate of NGP, for the gathering, processing and transportation of natural gas and NGLs. Additionally, we entered into an area of mutual interest and exclusivity agreement (“AMI”) with PennTex pursuant to which PennTex has the exclusive right to provide midstream services to support our current and future production in North Louisiana on our operated acreage within such area (other than production subject to existing third-party commitments). PennTex is a publicly traded master limited partnership. MRD Midstream LLC (“MRD Midstream”), a wholly-owned subsidiary of MRD Holdco, has ownership interests in both PennTex and its general partner. In addition to a 5.25% membership interest in PennTex’s general partner, MRD Midstream also owns approximately 18.4% of PennTex’s limited partner interests and 5.25% of its incentive distribution rights. The amended and restated gas processing agreement, (“GPA”) has a 15-year primary term, subject to one-year extensions at either party’s election. Processing fees under the GPA are subject to annual inflation escalators. Under the GPA, the Company has agreed to deliver a minimum volume of gas for processing through the term of the agreement measured on a cumulative basis based on specified daily minimum volume thresholds. Any volumes of gas delivered up to the then-applicable daily minimum volume threshold are considered firm reserved gas and are charged the firm fixed-commitment fee, and any volumes delivered in excess of such threshold are considered interruptible volumes and are charged the interruptible-service fixed fee. Pursuant to the GPA, any deficiency payments made by the Company under the GPA will be treated as prepaid processing fees by PennTex (except for the June 2015 deficiency payment). These charges do not expire until the end of the primary term of the GPA. Quarterly deficiency payments are based on the firm-commitment fixed fee. The following table summarizes the minimum volume commitment (“MVC”) and fees associated with the GPA. Period MVC (MMBtu/d) Firm Fee ($/MMBtu) Interruptible Fee ($/MMBtu) June 1, 2015 to September 30, 2015 115,000 0.435 0.470 October 1, 2015 to June 30, 2016 345,000 0.435 0.470 July 1, 2016 to June 30, 2026 (1) 460,000 0.435 0.350 July 1, 2026 to June 1, 2030 345,000 0.435 0.350 June 2, 2030 to October 1, 2030 115,000 0.435 0.350 (1) The firm fee is reduced to $0.35 $/MMBtu for volumes in excess of 345,000 MMBtu/d. The gas gathering agreement, as amended, (“GGA”) has a 15-year primary term, subject to one-year extensions at either party’s election. The Company pays fees for gathering services provided by PennTex, including a firm capacity reservation payment through November 30, 2019 and a usage fee component that is subject to a minimum volume commitment. The GGA also has an annual “use it or lose it” deficiency provision that is based on the usage fee. The minimum volume commitment under the GGA is linked to the minimum volume commitment under the GPA. Period MVC (MMBtu/d) Firm Fee ($/MMBtu) Usage Fee ($/MMBtu) June 1, 2015 to November 30, 2019 460,000 0.03 n/a June 1, 2015 to September 30, 2015 115,000 n/a 0.02 October 1, 2015 to June 30, 2016 345,000 n/a 0.02 July 1, 2016 to November 30, 2019 460,000 n/a 0.02 December 1, 2019 to June 30, 2026 460,000 n/a 0.05 July 1, 2026 to June 1, 2030 345,000 n/a 0.05 The gas transportation agreement, as amended, (“GTA”) has a 15-year primary term, subject to one-year extensions at either party’s election. The GTA provides for the transportation of residue gas through PennTex’s residue gas pipeline from the outlet of their processing plants to delivery points at interconnections with third-party natural gas transportation pipelines. The Company pays a usage fee for all volumes transported under the GTA. The GTA includes a plant tailgate dedication pursuant to which all of the Company’s residue gas produced from the PennTex’s processing plants are delivered for transportation on their residue gas pipeline. The GTA also includes a fixed monthly demand charge to provide priority firm service. The following table summarizes the fees associated with the GTA: Period Demand Fee ($/month) Usage Fee ($/MMBtu) June 1, 2015 to June 1, 2030 n/a 0.04 January 1, 2016 to December 31, 2025 360,000 n/a The transportation services agreement (“TSA”) provides for the transportation of NGLs through PennTex’s NGL pipeline from the outlet of their processing plants to a third party delivery point. The Company pays a usage fee for all volumes transported under the TSA. The TSA includes a plant tailgate dedication pursuant to which all of the Company’s NGLs produced from PennTex’s processing plants are delivered for transportation on the its NGL pipeline. The following table summarizes the fees associated with the TSA: Period Usage Fee ($/gallon) October 1, 2015 to October 1, 2030 0.04 All net costs associated with these agreements are reflected in the statement of operations in the “Gathering processing, and transportation – affiliate” line. Classic Pipeline Gas Gathering Agreement & Water Disposal Agreement On November 1, 2011, Classic Hydrocarbons Operating, LLC (“Classic Operating”), which became our wholly-owned subsidiary in connection with the restructuring transactions, and Classic Pipeline entered into a gas gathering agreement. Pursuant to the gas gathering agreement, Classic Operating dedicated to Classic Pipeline all of the natural gas produced (up to 50,000 MMBtus per day) on the properties operated by Classic Operating within certain counties in Texas through 2020, subject to one-year extensions at either party’s election. On May 1, 2014, Classic Operating and Classic Pipeline amended the gas gathering agreement with respect to Classic Operating’s remaining assets located in Panola and Shelby Counties, Texas. Under the amended gas gathering agreement, Classic Operating agreed to pay a fee of (i) $0.30 per MMBtu, subject to an annual 3.5% inflationary escalation, based on volumes of natural gas delivered and processed, and (ii) $0.07 per MMBtu per stage of compression plus its allocated share of compressor fuel. The amended gas gathering agreement had a term until December 31, 2023, subject to one-year extensions at either party’s election. The amended gas gather agreement was terminated in November 2015 in connection with a third party’s acquisition of Classic Pipeline’s Joaquin gathering system. On May 1, 2014, Classic Operating and Classic Pipeline entered into a water disposal agreement. The water disposal agreement had a three-year term, subject to one-year extensions at either party’s election. Under the water disposal agreement, Classic Operating agreed to pay a fee of $1.10 per barrel for each barrel of water delivered to Classic Pipeline. Effective July, 1 2015, the fee was reduced to $0.40 per barrel for each barrel of water delivered to Classic Pipeline. In February 2015, Classic sold all of the equity interests owned by it in Classic Operating to Memorial Production Operating LLC (“OLLC”), a wholly-owned subsidiary of MEMP, and Classic and Classic GP were merged into MRD Operating in March 2015. Classic Pipeline assigned its saltwater disposal system to OLLC in November 2015. Due to common control considerations, we recorded the receipt of this asset at historical cost and recognized approximately $2.1 million as a contribution in the equity statement. For the years ended December 31, 2015, 2014 and 2013, MEMP incurred gathering and salt water disposal fees of approximately $3.6 million, $1.8 million and $0.6 million, respectively, from Classic Pipeline, an affiliate. These fees are a component of net income (loss) from discontinued operations as presented on our statement of operations.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Income Taxes	Note 14. Income Taxes The components of income tax benefit (expense) from continuing operations are as follows: For the Year Ended December 31, 2015 2014 2013 (In thousands) Current income taxes: Federal $ (9,971 ) $ — $ — State (99 ) 149 (1,311 ) Total current income tax benefit (expense) (10,070 ) 149 (1,311 ) Deferred income taxes: Federal (55,417 ) (91,051 ) — State (34,518 ) (11,490 ) — Total deferred income tax benefit (expense) (89,935 ) (102,541 ) — Total income tax benefit (expense) $ (100,005 ) $ (102,392 ) $ (1,311 ) The actual income tax benefit (expense) from continuing operations differs from the expected amount computed by applying the federal statutory corporate tax rate of 35% as follows: For the Year Ended December 31, 2015 2014 2013 (In thousands) Expected tax benefit (expense) at federal statutory rate $ (69,162 ) $ 227,250 $ (32,073 ) State income tax benefit (expense), net of federal benefit (22,501 ) (7,753 ) (1,311 ) Pass-through entities (1) — 7,989 32,073 Stock compensation (2) (12,300 ) (330,024 ) — Other 3,958 146 — Total income tax benefit (expense) $ (100,005 ) $ (102,392 ) $ (1,311 ) (1) Our predecessor was also a pass-through entity for federal income tax purposes. (2) As discussed in Note 12, the compensation expense associated with the incentive units of WildHorse Resources and MRD Holdco created a nondeductible permanent difference for income tax purposes. The components of net deferred income tax liabilities are as follows: December 31, 2015 2014 (In thousands) Deferred income tax assets: Net operating loss carryforward $ 68,375 $ 24,084 Asset retirement obligation 3,789 3,902 Alternative minimum tax credit carryforward 9,984 — Other 5,546 3,550 Total deferred income tax assets $ 87,694 $ 31,536 Valuation allowance — — Net deferred income tax assets 87,694 31,536 Deferred income tax liabilities: Property, plant and equipment $ 171,627 $ 48,104 Derivatives 109,800 97,760 Other — 271 Total deferred income tax liabilities $ 281,427 $ 146,135 Net deferred income tax liabilities $ 193,733 $ 114,599 In June 2014, we recorded a deferred tax liability of approximately $43.3 million through stockholders’ equity in connection with our initial public offering and the related restructuring transactions. The tax basis of our assets and liabilities were stepped up as a result of our initial public offering and the related restructuring transactions, which is reported as a transaction among stockholders for financial reporting purposes. Consistent with establishing the deferred tax liability through stockholders’ equity in our initial public offering, we reversed a deferred tax liability of approximately $38.8 million through stockholders’ equity in 2015, of which $4.4 million was associated with the estimated deferred tax effects included in equity in connection with our initial public offering in 2014 and $34.4 million was attributable to the deferred tax effects of a common control transaction with MEMP in February 2015. Uncertain Income Tax Position. 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. We had no unrecognized tax benefits as of December 31, 2015 and expect no significant change to the unrecognized tax benefits over the next twelve months ending December 31, 2016. Tax Audits and Settlements. Generally, our income tax years 2011 through 2015 remain open and subject to examination by Federal tax authorities or the tax authorities in Louisiana and Texas and certain other small state taxing jurisdictions where we conduct operations. In certain jurisdictions we operate through more than one legal entity, each of which may have different open years subject to examination. Tax Attribute Carryforwards and Valuation Allowance. As of December 31, 2015, we had federal net operating loss carryforwards of approximately $169.5 million, of which $0.2 million is a component of discontinued operations, which would expire in 2034 and 2035. We also had state tax carryforwards of approximately $173.6 million, which would expire 2034 and 2035. No valuation allowance was established based upon management’s evaluation that loss carryforwards will be fully realized. We had alternative minimum tax credit carryfowards of approximately $10.0 million, which would be carried forward indefinitely.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2015
Commitments And Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 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. 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 years ended December 31, 2014 and 2013: 2014 2013 (In thousands) Balance at beginning of period $ 140 $ 418 Charged to costs and expenses — — Payments (140 ) (278 ) Balance at end of period $ — $ 140 Our environmental reserves were classified as current liabilities in accrued liabilities for the periods presented. Third Party Midstream Service Agreement We have an existing amended and restated midstream service agreement with Regency Field Services LLC (“Regency”) for the gathering and processing of natural gas in in North Louisiana. The agreement’s primary term expires on December 31, 2025, subject to one-year extensions at either party’s election. Pursuant to the agreement, Regency expanded its Dubach processing facility among other facility and infrastructure improvements, built a new high pressure gathering pipeline to tie-in to their Dubberly processing plant amongst other pipeline and infrastructure improvements, and constructed facilities that permit deliveries into PennTex’s system (see Note 13). Regency is entitled to receive a payback demand fee from us and other third parties equal to 110% of the infrastructure improvement costs. The payback demand fee is based upon actual volumes gathered, but not less than a specified monthly demand quantity. Until payout is achieved, there is also a monthly demand quantity associated with gathering and processing fees. The table below summarizes the monthly demand quantity (“MDQ”) and fees associated with the agreement. Based on the MDQ, we project that that payout would be achieved during January 2020. MDQ (MMBtu/d) Payback Demand Fee ($/MMBtu) Gathering Demand Fee ($/MMBtu) Dubberly Cryogenic Processing Fee ($/MMBtu) January 1, 2016 to January 22, 2020 249,700 0.275 0.295 n/a January 1, 2016 to January 22, 2020 113,000 n/a n/a 0.380 Regency has no obligation to process gas gathered and dedicated under the agreement after December 31, 2020. Effective on January 1, 2021 and continuing through the termination or expiration of the agreement, we will deliver all gas from the dedicated area and Regency will gather such gas, but will only process gas upon request. We have the right to request that gas gathered by Regency be delivered to alternative delivery points for processing (e.g., PennTex). Under these circumstances, Regency assesses us a $0.25 per MMBtu gathering only fee to take gas off its system. Related Party Agreements See Note 13 for additional information related to the Classic and PennTex agreements. Operating Leases We also have leases for our corporate headquarters, lease equipment and incur surface rentals related to our business operations. For the years ended December 31, 2015, 2014, and 2013, we recognized $8.5 million, $3.9 million, and $3.0 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 2016 2017 2018 2019 2020 Thereafter (In thousands) Operating leases $ 45,323 $ 10,509 $ 9,344 $ 7,368 $ 6,776 $ 6,203 $ 5,123 Sublease rental income 4,021 1,579 1,197 814 431 — —

Quarterly Financial Information

Quarterly Financial Information (Unaudited)	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Information (Unaudited)	Note 16. 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 12, we recorded incentive unit compensation expense, respectively, during 2014 and 2015, which impacted the comparability of net income (loss) from continuing operations between the periods presented below. First Quarter Second Quarter Third Quarter Fourth Quarter For the Year Ended December 31, 2015 (In thousands, except per share amounts) Revenues $ 87,023 $ 78,605 $ 111,654 $ 96,760 Operating income (loss) 107,872 (41,593 ) 120,415 51,330 Net income (loss) from continuing operations 50,509 (26,614 ) 56,726 16,980 Net income (loss) (112,149 ) (140,473 ) (135,255 ) 89,987 Net income (loss) attributable to noncontrolling interest (158,041 ) (113,771 ) (191,807 ) 70,081 Net income (loss) attributable to Memorial Resource Development Corp. 45,892 (26,702 ) 56,552 19,906 Net income (loss) from continuing operations available to common stockholders 45,615 (26,702 ) 56,051 20,277 Earnings per common share – basic Income (loss) from continuing operations 0.24 (0.14 ) 0.29 0.10 Income (loss) from discontinued operations 0.24 (0.14 ) 0.29 0.10 Earnings per common share – diluted Income (loss) from continuing operations 0.24 (0.14 ) 0.29 0.10 Income (loss) from discontinued operations 0.24 (0.14 ) 0.29 0.10 First Quarter Second Quarter Third Quarter Fourth Quarter For the Year Ended December 31, 2014 (In thousands, except per share amounts) Revenues $ 87,736 $ 110,569 $ 99,035 $ 111,742 Operating income (loss) 27,344 (899,962 ) 47,123 263,421 Net income (loss) from continuing operations 9,376 (941,803 ) 10,730 170,020 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) from continuing operations available to common stockholders n/a (961,707 ) 9,928 166,884 Earnings per common share – basic Income (loss) from continuing operations n/a (5.00 ) 0.05 0.87 Income (loss) from discontinued operations n/a (5.00 ) 0.05 0.87 Earnings per common share – diluted Income (loss) from continuing operations n/a (5.00 ) 0.05 0.87 Income (loss) from discontinued operations n/a (5.00 ) 0.05 0.87

Supplemental Oil and Gas Inform

Supplemental Oil and Gas Information (Unaudited)	12 Months Ended
	Dec. 31, 2015
Extractive Industries [Abstract]
Supplemental Oil and Gas Information (Unaudited)	Note 17. Supplemental Oil and Gas Information (Unaudited) The following supplemental information has been retrospectively revised to exclude amounts for all periods presented related to discontinued operations. Capitalized Costs Relating to Oil and Natural Gas Producing Activities The total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depreciation, depletion and amortization is as follows at the dates indicated. For the Year Ended December 31, 2015 2014 2013 (In thousands) Evaluated oil and natural gas properties $ 1,740,530 $ 1,269,605 $ 897,511 Support equipment and facilities 4,719 — — Unevaluated oil and natural gas properties 414,759 47,497 44,453 Accumulated depletion, depreciation, and amortization (434,735 ) (276,837 ) (160,620 ) Total $ 1,725,273 $ 1,040,265 $ 781,344 Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities Costs incurred in property acquisition, exploration and development activities were as follows for the periods indicated: For the Year Ended December 31, 2015 2014 2013 (In thousands) Property acquisition costs, proved $ 8,347 $ 74,490 $ 56,108 Property acquisition costs, unproved 360,353 24,310 19,975 Exploration and extension well costs 28,068 209,532 13,313 Development 492,191 181,026 191,350 Total $ 888,959 $ 489,358 $ 280,746 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 our 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 to audit our internally prepared reserves estimates for all of our estimated proved reserves (by volume) at December 31, 2015. All proved reserves are located in the United States and all prices are held constant in accordance with SEC rules. The weighted-average benchmark product prices used for valuing the reserves are based upon the average of the first-day-of-the-month price for each month within the period January through December of each year presented: 2015 2014 2013 Oil ($/Bbl) West Texas Intermediate (1) $ 46.79 $ 91.48 $ 93.42 NGL ($/Bbl) West Texas Intermediate (1) $ 46.79 $ 91.48 $ 93.42 Natural Gas ($/Mmbtu) Henry Hub (2) $ 2.59 $ 4.35 $ 3.67 (1) The unweighted average West Texas Intermediate price was adjusted by lease for quality, transportation fees, and a regional price differential. (2) The unweighted average Henry Hub price was adjusted by lease for energy content, compression charges, transportation fees, and regional price differentials. The following tables set forth estimates of the net reserves as of December 31, 2015, 2014, and 2013 respectively: For the Year Ended December 31, 2015 Oil (MBbls) Gas (MMcf) NGLs (MBbls) Equivalent (MMcfe) Proved developed and undeveloped reserves: Beginning of the year 11,915 1,013,340 53,033 1,403,030 Extensions and discoveries 1,111 50,343 2,741 73,456 Purchase of minerals in place 535 17,508 969 26,532 Production (1,331 ) (98,269 ) (3,249 ) (125,749 ) Sales of minerals in place (407 ) (39,272 ) (358 ) (43,861 ) Revision of previous estimates 1,331 30,164 1,024 44,286 End of year 13,154 973,814 54,160 1,377,694 Proved developed reserves: Beginning of year 3,708 355,331 18,203 486,793 End of year 6,101 443,983 24,583 628,081 Proved undeveloped reserves: Beginning of year 8,207 658,009 34,830 916,237 End of year 7,053 529,831 29,577 749,613 For the Year Ended December 31, 2014 Oil (MBbls) Gas (MMcf) NGLs (MBbls) Equivalent (MMcfe) Proved developed and undeveloped reserves: Beginning of the year 10,824 671,485 35,628 950,199 Extensions and discoveries 1,825 183,467 9,876 253,670 Purchase of minerals in place 269 22,186 1,247 31,283 Production (908 ) (56,574 ) (1,863 ) (73,200 ) Sales of minerals in place (623 ) (10,815 ) (950 ) (20,253 ) Revision of previous estimates 528 203,591 9,095 261,331 End of year 11,915 1,013,340 53,033 1,403,030 Proved developed reserves: Beginning of year 3,238 223,362 12,226 316,154 End of year 3,708 355,331 18,203 486,793 Proved undeveloped reserves: Beginning of year 7,586 448,123 23,402 634,045 End of year 8,207 658,009 34,830 916,237 For the Year Ended December 31, 2013 Oil (MBbls) Gas (MMcf) NGLs (MBbls) Equivalent (MMcfe) Proved developed and undeveloped reserves: Beginning of the year 10,220 549,449 31,264 798,357 Extensions and discoveries 1,635 105,289 5,712 149,369 Purchase of minerals in place 211 31,815 1,017 39,183 Production (631 ) (28,729 ) (1,282 ) (40,212 ) Sales of minerals in place (599 ) (14,137 ) (1,573 ) (27,169 ) Revision of previous estimates (12 ) 27,798 490 30,671 End of year (1) 10,824 671,485 35,628 950,199 Proved developed reserves: Beginning of year 2,813 180,523 10,208 258,651 End of year 3,238 223,362 12,226 316,154 Proved undeveloped reserves: Beginning of year 7,407 368,926 21,056 539,706 End of year 7,586 448,123 23,402 634,045 (1) Includes reserves of 41,077 MMcfe attributable to noncontrolling interests and NGPCIF. Noteworthy amounts included in the categories of proved reserve changes in the above tables include: · During 2015, we had upward performance revisions to total proved reserves of 233 Bcfe offset by downward price revisions of 189 Bcfe primarily due to declining commodity prices. Additionally, there was an increase of 74 Bcfe from extensions and discoveries, primarily due to the continued redevelopment program in the Terryville Complex. We also acquired 27 Bcfe in the Terryville Complex and divested 44 Bcfe in other noncore areas. PUDs decreased by 166 Bcfe during 2015 due to reclassifications of 231 Bcfe into proved developed reserves, upward revisions of 286 Bcfe due to well performance and downward revisions of 221 Bcfe due to uneconomic vertical PUDs. · During 2014, we had an increase in reserves of 254 Bcfe, primarily through the category extensions and discoveries. The extensions and discoveries were due to the horizontal development of unproved locations. Additionally, upward revisions of 261 Bcfe were due to positive well performance in the Terryville Complex. We also acquired 31 Bcfe from multiple acquisitions within the Terryville Complex. · During 2013, extensions and discoveries of 149 Bcfe primarily related to the horizontal redevelopment drilling program in the Terryville Complex. See Note 4 for additional information on acquisitions and divestitures. A variety of methodologies are used to determine our proved reserve estimates. The principal methodologies employed are reservoir simulation, decline curve analysis, volumetric, material balance, advance production type curve matching, petro-physics/log analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all of our fields. The standardized measure of discounted future net cash flows is as follows: For the Year Ended December 31, 2015 2014 2013 (In thousands) Future cash inflows $ 4,008,764 $ 7,314,745 $ 4,942,687 Future production costs (1,438,531 ) (1,020,599 ) (1,343,252 ) Future development costs (784,003 ) (1,209,907 ) (1,137,429 ) Future income tax expense (1) (88,723 ) (1,669,356 ) — Future net cash flows for estimated timing of cash flows 1,697,507 3,414,883 2,462,006 10% annual discount for estimated timing of cash flows (877,647 ) (1,604,728 ) (1,103,145 ) Standardized measure of discounted future net cash flows (2) $ 819,860 $ 1,810,155 $ 1,358,861 (1) Our predecessor was a pass through entity and was subject to the Texas margin tax based on the taxable margin apportioned to Texas. However, due to immateriality, we have excluded the impact of this tax for the year ended December 31, 2013. (2) Includes $63,422 attributable to both noncontrolling interests and NGPCIF for the year ended December 31, 2013. Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves The following is a summary of the changes in the standardized measure of discounted future net cash flows for the proved oil and natural gas reserves during each of the years in the three year period ended December 31, 2015: For the Year Ended December 31, 2015 2014 2013 (In thousands) Beginning of year $ 1,810,155 $ 1,358,861 $ 1,138,271 Sale of oil and natural gas produced, net of production costs (240,244 ) (332,785 ) (175,933 ) Purchase of minerals in place 53,597 69,282 51,177 Sale of minerals in place (41,543 ) (47,791 ) (54,091 ) Extensions and discoveries 30,006 653,088 286,796 Changes in income taxes, net 882,942 (995,635 ) — Changes in prices and costs (2,284,279 ) 367,212 (59,083 ) Previously estimated development costs incurred 294,617 205,388 62,012 Net changes in future development costs 190,403 (68,079 ) (1,295 ) Revisions of previous quantities 51,455 713,176 45,183 Accretion of discount 244,123 135,887 110,312 Change in production rates and other (171,372 ) (248,449 ) (44,488 ) End of year $ 819,860 $ 1,810,155 $ 1,358,861

Condensed Consolidating Financi

Condensed Consolidating Financial Information	12 Months Ended
	Dec. 31, 2015
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Condensed Consolidating Financial Information	Note 18. Condensed Consolidating Financial Information We own no operating assets and have no significant operations independent of our subsidiaries. Our obligations under our 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 our financial information on a unconsolidated stand-alone basis and our combined guarantor and combined non-guarantor subsidiaries as of and for the periods indicated. Such financial information may not necessarily be indicative of our results of operations, cash flows or financial position had these subsidiaries operated as independent entities. As of December 31, 2015 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated (In thousands) ASSETS Current assets: Cash and cash equivalents $ 2,986 $ — $ — $ (2,986 ) $ — Accounts receivable - trade 7,850 48,372 — (3,530 ) 52,692 Accounts receivable - affiliates 9,525 — — (9,525 ) — Short-term derivative instruments 227,991 — — — 227,991 Other financial assets 46,106 — — — 46,106 Prepaid expenses and other current assets 2,318 1,056 — — 3,374 Assets of discontinued operations — 3,779 340,186 1,576 345,541 Total current assets 296,776 53,207 340,186 (14,465 ) 675,704 Property and equipment, net 15,825 1,728,622 — — 1,744,447 Long-term derivative instruments 91,292 — — — 91,292 Investments in subsidiaries 1,482,847 — — (1,482,847 ) — Other long-term assets 4,976 — — — 4,976 Assets of discontinued operations — 614 2,565,816 — 2,566,430 Total assets $ 1,891,716 $ 1,782,443 $ 2,906,002 $ (1,497,312 ) $ 5,082,849 LIABILITIES AND EQUITY Current Liabilities: Accounts payable and accrued liabilities $ 26,796 $ 66,133 $ — $ 1,004 $ 93,933 Accounts payable - affiliates — 17,339 — (12,323 ) 5,016 Revenues payable 80 33,946 — — 34,026 Liabilities of discontinued operations — 1,517 93,408 (3,146 ) 91,779 Total current liabilities 26,876 118,935 93,408 (14,465 ) 224,754 Long-term debt 1,012,064 — — — 1,012,064 Asset retirement obligations — 10,079 — — 10,079 Deferred tax liabilities 22,754 170,979 — — 193,733 Other long-term liabilities 7,195 — — — 7,195 Liabilities of discontinued operations — — 2,167,103 — 2,167,103 Total liabilities 1,068,889 299,993 2,260,511 (14,465 ) 3,614,928 Equity: Equity 822,827 1,482,450 645,491 (2,127,941 ) 822,827 Noncontrolling interest — — — 645,094 645,094 Total equity 822,827 1,482,450 645,491 (1,482,847 ) 1,467,921 Total liabilities & equity $ 1,891,716 $ 1,782,443 $ 2,906,002 $ (1,497,312 ) $ 5,082,849 As of December 31, 2014 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated (In thousands) ASSETS Current assets: Cash and cash equivalents $ 2,241 $ 1,123 $ — $ — $ 3,364 Accounts receivable- trade 5,995 29,804 — (2,721 ) 33,078 Accounts receivable - affiliates 10,047 — — (10,047 ) — Short-term derivative instruments 131,471 — — — 131,471 Prepaid expenses and other current assets 4,178 7,166 — — 11,344 Assets of discontinued operations — 18,614 303,961 (1,039 ) 321,536 Total current assets 153,932 56,707 303,961 (13,807 ) 500,793 Property and equipment, net 16,601 1,050,043 — — 1,066,644 Long-term derivative instruments 123,567 — — — 123,567 Investments in subsidiaries 1,139,792 — — (1,139,792 ) — Other long-term assets 3,324 260 — 2 3,586 Assets of discontinued operations — 679 2,864,559 (2 ) 2,865,236 Total assets $ 1,437,216 $ 1,107,689 $ 3,168,520 $ (1,153,599 ) $ 4,559,826 LIABILITIES AND EQUITY Current Liabilities: Accounts payable and accrued expenses $ 6,245 $ 49,075 $ — $ (3,125 ) $ 52,195 Accounts payable - affiliates — 160 — — 160 Revenues payable — 21,807 — — 21,807 Liabilities of discontinued operations — 16,384 152,985 (9,423 ) 159,946 Total current liabilities 6,245 87,426 152,985 (12,548 ) 234,108 Long-term debt 770,545 — — — 770,545 Asset retirement obligations — 9,829 — — 9,829 Deferred tax liabilities 69,431 45,122 — 46 114,599 Other long-term liabilities 8,585 — — — 8,585 Liabilities of discontinued operations — 1 1,719,241 (46 ) 1,719,196 Total liabilities 854,806 142,378 1,872,226 (12,548 ) 2,856,862 Equity: Equity 582,410 965,311 1,290,734 (2,256,045 ) 582,410 Noncontrolling interest — — 5,560 1,114,994 1,120,554 Total equity 582,410 965,311 1,296,294 (1,141,051 ) 1,702,964 Total liabilities & equity $ 1,437,216 $ 1,107,689 $ 3,168,520 $ (1,153,599 ) $ 4,559,826 December 31, 2015 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated (In thousands) Revenues: Oil & natural gas sales $ — $ 374,042 $ — $ — $ 374,042 Total revenues — 374,042 — — 374,042 Costs and expenses: Lease operating — 24,904 — (1 ) 24,903 Gathering, processing and transportation — 72,555 — (1 ) 72,554 Gathering, processing, and transportation - affiliate — 25,403 — — 25,403 Exploration — 8,969 — — 8,969 Taxes other than income 3,833 11,063 — — 14,896 Depreciation, depletion and amortization 4,191 184,551 — — 188,742 Incentive unit compensation expense 35,142 — — — 35,142 General and administrative 43,624 2,664 — — 46,288 Accretion of asset retirement obligations — 418 — (1 ) 417 (Gain) loss on commodity derivatives (281,250 ) — — 1 (281,249 ) (Gain) loss on sale of properties — (47 ) — — (47 ) Total costs and expenses (194,460 ) 330,480 — (2 ) 136,018 Operating income (loss) 194,460 43,562 — 2 238,024 Other income (expense): Interest expense, net (39,308 ) (88 ) — — (39,396 ) Equity earnings from subsidiaries 16,434 — — (16,434 ) — Other, net (100 ) (922 ) — — (1,022 ) Total other income (expense) (22,974 ) (1,010 ) — (16,434 ) (40,418 ) Income before income taxes 171,486 42,552 — (16,432 ) 197,606 Income tax benefit (expense) (75,838 ) (24,167 ) — — (100,005 ) Net income (loss) from continuing operations 95,648 18,385 — (16,432 ) 97,601 Discontinued Operations Income (loss) before income taxes — — (397,664 ) (2 ) (397,666 ) Income tax benefit (expense) — — 2,175 — 2,175 Net income (loss) from discontinued operations — — (395,489 ) (2 ) (395,491 ) Net income (loss) 95,648 18,385 (395,489 ) (16,434 ) (297,890 ) Net income (loss) attributable to noncontrolling interest — — 386 (393,924 ) (393,538 ) Net income (loss) attributable to Memorial Resource Development Corp. $ 95,648 $ 18,385 $ (395,875 ) $ 377,490 $ 95,648 December 31, 2014 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated (In thousands) Revenues: Oil & natural gas sales $ — $ 409,070 $ — $ — $ 409,070 Other income 5 7 — — 12 Total revenues 5 409,077 — — 409,082 Costs and expenses: Lease operating — 17,570 — — 17,570 Gathering, processing and transportation — 45,956 — — 45,956 Exploration — 13,853 — — 13,853 Taxes other than income — 12,610 — — 12,610 Depreciation, depletion and amortization 1,133 127,105 — — 128,238 Impairment of proved oil and natural gas properties — 24,576 — — 24,576 Incentive unit compensation expense 111,866 831,060 1,023 — 943,949 General and administrative 13,232 25,277 16 24 38,549 Accretion of asset retirement obligations — 533 — — 533 (Gain) loss on commodity derivatives (277,129 ) 19,395 — — (257,734 ) (Gain) loss on sale of properties — 3,167 (110 ) — 3,057 Other, net — — — (1 ) (1 ) Total costs and expenses (150,898 ) 1,121,102 929 23 971,156 Operating income (loss) 150,903 (712,025 ) (929 ) (23 ) (562,074 ) Other income (expense): Interest expense, net (19,532 ) (30,751 ) — — (50,283 ) Loss on extinguishment of debt (23,562 ) (13,686 ) — — (37,248 ) Equity earnings from subsidiaries (809,017 ) — — 809,017 — Other, net — 319 — 1 320 Total other income (expense) (852,111 ) (44,118 ) — 809,018 (87,211 ) Income before income taxes (701,208 ) (756,143 ) (929 ) 808,995 (649,285 ) Income tax benefit (expense) (83,373 ) (19,028 ) — 9 (102,392 ) Net income (loss) (784,581 ) (775,171 ) (929 ) 809,004 (751,677 ) Discontinued Operations Income (loss) before income taxes — — 114,171 22 114,193 Income tax benefit (expense) — — 1,430 (9 ) 1,421 Net income (loss) from discontinued operations — — 115,601 13 115,614 Net income (loss) (784,581 ) (775,171 ) 114,672 809,017 (636,063 ) Net income (loss) attributable to noncontrolling interest — — 32 126,756 126,788 Net income (loss) attributable to Memorial Resource Development Corp. $ (784,581 ) $ (775,171 ) $ 114,640 $ 682,261 $ (762,851 ) December 31, 2013 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Combined & Consolidated (In thousands) Revenues: Oil & natural gas sales $ — $ 202,423 $ 17,129 $ — $ 219,552 Total revenues — 202,423 17,129 — 219,552 Costs and expenses: Lease operating — 14,710 2,605 (108 ) 17,207 Gathering, processing and transportation — 17,666 — — 17,666 Exploration — 1,034 — — 1,034 Taxes other than income — 7,869 830 — 8,699 Depreciation, depletion and amortization — 61,990 8,913 — 70,903 Impairment of proved oil and natural gas properties — 128 2,400 — 2,528 Incentive unit compensation expense — 14,353 20,644 — 34,997 General and administrative — 31,674 3,616 124 35,414 Accretion of asset retirement obligations — 516 77 — 593 (Gain) loss on commodity derivatives — (3,179 ) 18 — (3,161 ) (Gain) loss on sale of properties — 6,776 (89,549 ) — (82,773 ) Other, net — — 2 — 2 Total costs and expenses — 153,537 (50,444 ) 16 103,109 Operating income (loss) — 48,886 67,573 (16 ) 116,443 Other income (expense): Interest expense, net — (24,895 ) (53 ) — (24,948 ) Equity earnings from subsidiaries — 71,222 — (71,222 ) — Other, net — 141 2 — 143 Total other income (expense) — 46,468 (51 ) (71,222 ) (24,805 ) Income before income taxes — 95,354 67,522 (71,238 ) 91,638 Income tax benefit (expense) — (164 ) (1,147 ) — (1,311 ) Net income (loss) — 95,190 66,375 (71,238 ) 90,327 Discontinued Operations Income (loss) before income taxes — — 61,297 16 61,313 Income tax benefit (expense) — — (308 ) — (308 ) Net income (loss) from discontinued operations — — 60,989 16 61,005 Net income (loss) — 95,190 127,364 (71,222 ) 151,332 Net income (loss) attributable to noncontrolling interest — — 267 49,563 49,830 Net income (loss) attributable to Memorial Resource Development Corp. $ — $ 95,190 $ 127,097 $ (120,785 ) $ 101,502 December 31, 2015 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated (In thousands) Net cash provided by continuing operations $ 45,528 $ 373,155 $ — $ (5,941 ) $ 412,742 Net cash provided (used in) by discontinued operations — (1,127 ) 216,750 5,546 221,169 Net cash provided by (used in) operating activities 45,528 372,028 216,750 (395 ) 633,911 Cash flows from investing activities: Acquisitions of oil and natural gas properties — (291,536 ) — — (291,536 ) Additions to oil and gas properties — (594,901 ) — — (594,901 ) Additions to other property and equipment (3,401 ) (452 ) — — (3,853 ) Additions to restricted investments — — — — — Other financial hybrid instruments (46,106 ) — — — (46,106 ) Investments in subsidiaries (499,336 ) — — 499,336 — Distributions from subsidiaries 78,648 — — (78,648 ) — Proceeds from the sale of oil and gas properties — 13,612 — — 13,612 Net cash used in continuing operations (470,195 ) (873,277 ) — 420,688 (922,784 ) Net cash used in discontinued operations — 63 (337,568 ) — (337,505 ) Net cash used in investing activities (470,195 ) (873,214 ) (337,568 ) 420,688 (1,260,289 ) Cash flows from financing activities: Advances on revolving credit facility 798,000 — — — 798,000 Payments on revolving credit facility (558,000 ) — — — (558,000 ) Deferred finance costs (1,498 ) — — — (1,498 ) Proceeds from MRD equity offering 242,880 — — — 242,880 Costs incurred in conjunction with MRD equity offering (4,773 ) — — — (4,773 ) Capital contributions — 497,424 — (497,424 ) — Repurchases of equity (51,197 ) — — — (51,197 ) Net cash used in continuing operations 425,412 497,424 — (497,424 ) 425,412 Net cash used in discontinued operations — — 120,447 76,736 197,183 Net cash provided by financing activities 425,412 497,424 120,447 (420,688 ) 622,595 Net change in cash and cash equivalents 745 (3,762 ) (371 ) (395 ) (3,783 ) Add: cash balance included in assets of discontinued operations at beginning of period — 2,639 970 (1,015 ) 2,594 Less: cash balance included in assets of discontinued operations at end of period — — 599 1,576 2,175 Cash and cash equivalents, beginning of period 2,241 1,123 — — 3,364 Cash and cash equivalents, end of period $ 2,986 $ — $ — $ (2,986 ) $ — December 31, 2014 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Combined & Consolidated (In thousands) Net cash provided by (used in) continuing operations $ (72,612 ) $ 299,206 $ (2,879 ) $ 1,975 $ 225,690 Net cash provided by (used in) discontinued operations — (1,716 ) 254,272 (1,975 ) 250,581 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 ) — — (93,909 ) Additions to oil and gas properties — (376,123 ) — 1 (376,122 ) Additions to other property and equipment (15,980 ) (851 ) — — (16,831 ) Investments in subsidiaries (696,489 ) — — 696,489 — Distributions from subsidiaries 15,140 74,424 — (89,564 ) — Change in restricted cash — 49,946 — — 49,946 Deposits for property acquisitions — (215 ) — — (215 ) Proceeds from the sale of oil and gas properties — — 6,700 — 6,700 Other — — (300 ) (1 ) (301 ) Net cash used in continuing operations (697,329 ) (346,728 ) 6,400 606,925 (430,732 ) Net cash used in discontinued operations — (138 ) (1,386,109 ) — (1,386,247 ) Net cash used in investing activities (697,329 ) (346,866 ) (1,379,709 ) 606,925 (1,816,979 ) Cash flows from financing activities: Advances on revolving credit facility 1,174,000 126,800 — — 1,300,800 Payments on revolving credit facility (991,000 ) (329,900 ) — — (1,320,900 ) Termination of second lien credit facility — (328,282 ) — — (328,282 ) Proceeds from the issuances of senior notes 600,000 — — — 600,000 Redemption of senior notes (351,808 ) — — — (351,808 ) Deferred finance costs (18,779 ) (61 ) — — (18,840 ) Proceeds from MRD initial public offering 408,500 — — — 408,500 Costs incurred in conjunction with initial public offering (28,373 ) — — — (28,373 ) MRD equity repurchases (161 ) — — — (161 ) Capital contributions — 686,623 — (686,623 ) — Contributions from NGP affiliates related to sale of properties — — 1,165 — 1,165 Purchase of additional interests in subsidiaries (3,292 ) — — — (3,292 ) Distribution to equity owners — (15,000 ) (2,315 ) 17,315 — Distribution to NGP affiliates related to purchase of assets — (63,389 ) (3,304 ) — (66,693 ) Distribution to noncontrolling interests — — — (376 ) (376 ) Distributions to MRD Holdco (17,207 ) (39,520 ) (3,076 ) — (59,803 ) Distribution to NGP affiliates related to sale of assets, net of cash received — (32,770 ) — — (32,770 ) Other 302 18 — — 320 Net cash used in continuing operations 772,182 4,519 (7,530 ) (669,684 ) 99,487 Net cash used in discontinued operations — — 1,107,714 61,744 1,169,458 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 ) Add: cash balance included in assets of discontinued operations at beginning of period — 4,493 21,698 — 26,191 Less: cash balance included in assets of discontinued operations at end of period — 2,639 970 (1,015 ) 2,594 Cash and cash equivalents, beginning of period — 44,126 7,404 — 51,530 Cash and cash equivalents, end of period $ 2,241 $ 1,123 $ — $ — $ 3,364 December 31, 2013 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Combined & Consolidated (In thousands) Net cash provided by (used in) continuing operations $ — $ 92,997 $ (17,702 ) $ 13,177 $ 88,472 Net cash provided by (used in) discontinued operations — 867 201,661 (13,177 ) 189,351 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 ) — — (67,098 ) Additions to oil and gas properties — (164,850 ) (20,344 ) — (185,194 ) Additions to other property and equipment — (2,307 ) — — (2,307 ) 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 — 33,152 118,035 151,187 Net cash used in continuing operations — (70,189 ) 97,691 (180,261 ) (152,759 ) Net cash used in discontinued operations — (125 ) (214,559 ) — (214,684 ) 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 — — 174,400 Payments on revolving credit facilities — (200,500 ) — — (200,500 ) Proceeds from the issuances of senior notes — 343,000 — — 343,000 Borrowings under second lien credit facility — 325,000 — — 325,000 Deferred financing costs — (20,250 ) — (1 ) (20,251 ) Proceeds from changes in ownership interests in MEMP — 135,012 — — 135,012 Purchase of additional interests in subsidiaries — (15,135 ) — — (15,135 ) Distributions to the Funds — (732,362 ) — — (732,362 ) Distribution to equity owners — — (74,787 ) 74,787 — Distributions to noncontrolling interests — — — (7,446 ) (7,446 ) Distributions made by previous owners — (2,590 ) — — (2,590 ) Other — (129 ) — 200 71 Net cash used in continuing operations — 6,446 (74,787 ) 67,540 (801 ) Net cash used in discontinued operations — — 6,030 112,721 118,751 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 Add: cash balance included in assets of discontinued operations at beginning of period — 3,751 28,585 — 32,336 Less: cash balance included in assets of discontinued operations at end of period — 4,493 21,698 — 26,191 Cash and cash equivalents, beginning of period — 14,872 2,183 — 17,055 Cash and cash equivalents, end of period $ — $ 44,126 $ 7,404 $ — $ 51,530

Summary of Significant Accoun25

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Overview	Overview Memorial Resource Development Corp. (the “Company”) is a publicly traded Delaware corporation, the common shares of which are listed on the NASDAQ Global Market (“NASDAQ”) under the symbol “MRD.” Unless the context requires otherwise, references to “we,” “us,” “our,” “MRD,” or “the Company” are intended to mean the business and operations of Memorial Resource Development Corp. and its consolidated subsidiaries. The Company was formed by Memorial Resource Development LLC (“MRD LLC”) in January 2014 to acquire, explore and develop natural gas and oil properties in North America. MRD LLC was a Delaware limited liability company formed on April 27, 2011 by Natural Gas Partners VIII, L.P. (“NGP VIII”), Natural Gas Partners IX, L.P. (“NGP IX”) and NGP IX Offshore Holdings, L.P. (“NGP IX Offshore”) (collectively, the “Funds”) to explore, develop and acquire natural gas and oil properties. The Funds are private equity funds managed by Natural Gas Partners (“NGP”). MRD LLC’s consolidated and combined financial statements represent our predecessor for accounting and financial reporting purposes prior to our initial public offering.
Initial Public Offering and Restructuring Transactions	2014 Initial Public Offering and Restructuring Transactions On June 18, 2014, the Company completed its initial public offering of 21,500,000 common units at a price of $19.00 per share, which generated net proceeds to the Company of approximately $380.2 million after deducting underwriting discounts and commissions and other offering related fees and expenses. The following restructuring events and transactions occurred in connection with our initial public offering: · The Funds contributed all of their interests in MRD LLC to MRD Holdco LLC (“MRD Holdco”) and the members of our management who owned incentive units in MRD LLC exchanged those incentive units for substantially identical incentive units in MRD Holdco, after which MRD Holdco owned 100% of MRD LLC; · WildHorse Resources, LLC (“WildHorse Resources”) sold its subsidiary, WildHorse Resources Management Company, LLC (“WHR Management Company”), to an affiliate of the Funds for approximately $0.2 million in cash, and WHR Management Company entered into a services agreement with the Company and WildHorse Resources pursuant to which WHR Management Company agreed to provide certain management services to WildHorse Resources, which was terminated as of March 1, 2015; · Classic Hydrocarbons Holdings, L.P. (“Classic”) and Classic Hydrocarbons GP Co., L.L.C. (“Classic GP”) distributed to MRD LLC the ownership interests in Classic Pipeline & Gathering, LLC (“Classic Pipeline”), which owns certain midstream assets in Texas, and Black Diamond Minerals, LLC (“Black Diamond”) distributed to MRD LLC its ownership interests in Golden Energy Partners LLC (“Golden Energy”), which sold all of its assets in May 2014; · MRD LLC contributed to us substantially all of its assets, comprised of: (i) 100% of the ownership interests in Classic, Classic GP, Black Diamond, Beta Operating Company, LLC (“Beta Operating”), Memorial Resource Finance Corp., MRD Operating LLC (“MRD Operating”), Memorial Production Partners GP LLC (“MEMP GP”) (including MEMP GP’s ownership of 50% of Memorial Production Partners LP’s (“MEMP”) incentive distribution rights) and (ii) 99.9% of the membership interests in WildHorse Resources; · We issued 128,665,677 shares of our common stock to MRD LLC, which MRD LLC immediately distributed to MRD Holdco; · We assumed the obligations of MRD LLC under the indenture governing the $350 million in aggregate principal amount of 10.00% / 10.75% Senior PIK Toggle Notes due 2018 (the “PIK notes”) and reimbursed MRD LLC for the June 15, 2014 interest payment made on the PIK notes; · Certain former management members of WildHorse Resources, including Jay Graham, our Chief Executive Officer, contributed to us their outstanding incentive units in WildHorse Resources, as well as the remaining 0.1% of the membership interests in WildHorse Resources, and we issued 42,334,323 shares of our common stock and paid cash consideration of $30.0 million to Jay Graham and such other former management members of WildHorse Resources; · We entered into a registration rights agreement and a voting agreement with MRD Holdco, Jay Graham, our Chief Executive Officer, and certain other former management members of WildHorse Resources; · We entered into a new $2.0 billion revolving credit facility (see Note 8) and used approximately $614.5 million in borrowings under that facility to repay all amounts outstanding under WildHorse Resources’ credit agreements, to partially fund the cash consideration payable to the former management members of WildHorse Resources and to reimburse MRD LLC for the June 15, 2014 interest payment made on the PIK notes; · Notice of redemption was given to the PIK notes trustee (see Note 8) specifying a redemption date of July 16, 2014 and indicating that a portion of the net proceeds from our initial public offering, which temporarily reduced amounts outstanding under our new revolving credit facility, would be used to redeem the PIK notes at a redemption price of 102% of the principal amount of the PIK notes plus accrued and unpaid interest thereon to the date of redemption; · MRD Operating entered into a merger agreement with MRD LLC pursuant to which after the termination or earlier discharge of the PIK notes MRD LLC would merge into MRD Operating; · MRD LLC distributed to MRD Holdco the following: (i) BlueStone Natural Resources Holdings, LLC (“BlueStone”), which sold substantially all of its assets in July 2013 for $117.9 million, MRD Royalty LLC, which owned certain leasehold interests and overriding royalty interests in Texas and Montana, MRD Midstream LLC, which owned an indirect interest in certain midstream assets in North Louisiana, Golden Energy and Classic Pipeline; (ii) 5,360,912 subordinated units of MEMP; (iii) the right to the remaining cash to be released from the debt service reserve account in connection with the redemption or earlier discharge of the PIK notes plus the cash received from us in reimbursement of the interest paid on June 15, 2014 in respect of the PIK notes; and (iv) approximately $6.7 million of cash received by MRD LLC in connection with the sale of Golden Energy’s assets in May 2014; · We irrevocably deposited with the PIK notes trustee approximately $360.0 million on June 27, 2014, which was an amount sufficient to fund the redemption of the PIK notes on the redemption date and to satisfy and discharge our obligations under the PIK notes and the related indenture. The discharge became effective upon the irrevocable deposit of the funds with the PIK notes trustee; and · MRD LLC merged into MRD Operating.
Previous Owners	Previous Owners References to “the previous owners” for accounting and financial reporting purposes refer collectively to: · Certain oil and natural gas properties and related assets primarily in the Permian Basin, East Texas and the Rockies that MEMP acquired through equity transactions in October 2013 from certain affiliates of NGP. In October 2013, MEMP acquired Boaz Energy, LLC (“Boaz”), Crown Energy Partners, LLC (“Crown”), the Crown net profits interest and overriding royalty interest (“Crown NPI/ORRI”), Propel Energy SPV LLC (“Propel SPV”), together with its wholly-owned subsidiary Propel Energy Services, LLC (“Propel Energy Services”), and Stanolind Oil and Gas SPV LLC (“Stanolind SPV”) from Boaz Energy Partners, LLC (“Boaz Energy Partners”), Crown Energy Partners Holdings, LLC (“Crown Holdings”), Propel Energy, LLC (“Propel Energy”) and Stanolind Oil and Gas LP (“Stanolind”), all of which are primarily owned by two of the Funds. · A net profits interest that WildHorse Resources purchased from NGP Income Co-Investment Fund II, L.P. (“NGPCIF”) in February 2014 (“NGPCIF NPI”). NGPCIF is controlled by NGP. Upon the completion of the 2010 Petrohawk and Clayton Williams acquisitions, WildHorse Resources sold a net profits interest in these properties to NGPCIF. Since WildHorse Resources sold the net profits interest, the historical results are accounted for as a working interest for all periods. Our audited financial statements reported herein include the financial position and results attributable to: (i) those certain oil and natural gas properties and related assets that MEMP acquired through equity transactions in October 2013 from Boaz Energy Partners, Crown Holdings, Propel Energy and Stanolind, all of which are components of discontinued operations 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 were required to consolidate MEMP for accounting and financial reporting purposes. MEMP was owned 99.9% by its limited partners and 0.1% by MEMP GP. On June 1, 2016, we completed the sale of MEMP GP, the general partner of MEMP, Beta Operating Company, LLC and MEMP Services LLC (collectively, the “Disposition Entities”) to MEMP for total proceeds of $0.75 million. Our financial statements have been retrospectively revised to reflect the Disposition Entities and its subsidiaries as discontinued operations for all periods presented. Certain amounts in the prior year financial statements have been reclassified to conform to current presentation. Gathering, processing, and transportation costs were previously accounted for as revenue deductions and are now being presented as costs and expenses on our statements of operations on a separate line item. We have elected to early adopt new accounting pronouncements related to the presentation of deferred taxes and debt issuance costs. The retrospective adjustments to the December 31, 2014 balance sheet are shown below. December 31, 2014 Before Adjustment Adjustment Effect December 31, 2014 As Adjusted (In thousands) Prepaid expenses and other current assets 12,999 (1,655 ) 11,344 Other long-term assets 14,126 (10,540 ) 3,586 Accrued liabilities 101,758 (50,522 ) 51,236 Long-term debt 783,000 (12,455 ) 770,545 Deferred tax liabilities 64,077 50,522 114,599 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”). Prior to the sale of the Disposition Entities and its subsidiaries we had two reportable segments, one of which was MEMP and its subsidiaries. Effective June 1, 2016, we now have one reportable business segment, which is engaged in the acquisition, exploration, development and production of oil and natural gas properties. Accordingly, we have retrospectively revised our segment disclosures for all periods presented.
Use of Estimates	Use of Estimates The preparation of consolidated and combined financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated and combined financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates include, but are not limited to, oil and natural gas reserves; depreciation, depletion, and amortization of proved oil and natural gas properties; future cash flows from oil and natural gas properties; impairment of long-lived assets; fair value of derivatives; fair value of equity and incentive unit compensation; fair values of assets acquired and liabilities assumed in business combinations and asset retirement obligations.
Principles of Consolidation and Combination	Principles of Consolidation and Combination Our consolidated financial statements include our accounts and those of our subsidiaries in which we have a controlling interest, after the elimination of all intercompany accounts and transactions. Likewise, the combined financial statements include the accounts of our predecessor and the previous owners as discussed above. All material intercompany balances and transactions have been eliminated. Certain prior period balances have been reclassified to better align with financial statement presentation in the current fiscal year.
Cash and Cash Equivalents	Cash and Cash Equivalents Cash and cash equivalents represent unrestricted cash on hand and all highly liquid investments with original contractual maturities of three months or less.
Book Overdrafts	Book Overdrafts Book overdrafts, representing outstanding checks in excess of funds on deposit, are classified as accounts payable and the change in the related balance is reflected in operating activities in the statement of cash flows.
Concentrations of Credit Risk	Concentrations of Credit Risk Cash balances, accounts receivable, restricted investments and derivative and other financial instruments are financial instruments potentially subject to credit risk. Cash and cash equivalents are maintained in bank deposit accounts which, at times, may exceed the federally insured limits. Management periodically reviews and assesses the financial condition of the banks to mitigate the risk of loss. Derivative financial instruments are generally executed with major financial institutions that expose us to market and credit risks and which may, at times, be concentrated with certain counterparties. The credit worthiness of the counterparties is subject to continual review. We rely upon netting arrangements with counterparties to reduce credit exposure. Neither we nor our predecessor and the previous owners have experienced any losses from such instruments. Oil and natural gas are sold to a variety of purchasers, including intrastate and interstate pipelines or their marketing affiliates and independent marketing companies. Accounts receivable from joint operations are from a number of oil and natural gas companies, partnerships, individuals, and others who own interests in the properties operated by us, our predecessor, and the previous owners. Generally, operators of crude oil and natural gas properties have the right to offset future revenues against unpaid charges related to operated wells, minimizing the credit risk associated with these receivables. Additionally, management believes that any credit risk imposed by a concentration in the oil and natural gas industry is mitigated by the creditworthiness of its customer base. An allowance for doubtful accounts is recorded after all reasonable efforts have been exhausted to collect or settle the amount owed. Any amounts outstanding longer than the contractual terms are considered past due. We did not have any material write-offs related to uncollectible accounts during the years ended December 31, 2015, 2014 and 2013. Management determined that an allowance for uncollectible accounts was unnecessary at both December 31, 2015 and 2014, respectively. If we were to lose any one of our customers, the loss could temporarily delay the production and the sale of oil and natural gas in the related producing region. If we were to lose any single customer, we believe that a substitute customer to purchase the impacted production volumes could be identified.
Oil and Natural Gas Properties	Oil and Natural Gas Properties Oil and natural gas exploration, development and production activities are accounted for in accordance with the successful efforts method of accounting. Under this method, costs of acquiring properties, costs of drilling successful exploration wells, and development costs are capitalized. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if determination is made that proved reserves have been found. If no proved reserves have been found, the costs of each of the related exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. The costs of such exploratory wells are expensed if a determination of proved reserves has not been made within a twelve-month period after drilling is complete. Exploration costs such as geological, geophysical, and seismic costs are expensed as incurred. As exploration and development work progresses and the reserves on these properties are proven, capitalized costs attributed to the properties are subject to depreciation and depletion. Depletion of capitalized costs is provided using the units-of-production method based on proved oil and gas reserves related to the associated field. Capitalized drilling and development costs of producing oil and natural gas properties are depleted over proved developed reserves and leasehold costs are depleted over total proved reserves. On the sale or retirement of a complete or partial unit of a proved property or pipeline and related facilities, the cost and related accumulated depreciation, depletion, and amortization are removed from the property accounts, and any gain or loss is recognized. There were no material capitalized exploratory drilling costs pending evaluation at December 31, 2015, 2014, and 2013. Oil and natural gas properties consisted of the following at the dates indicated: December 31, 2015 2014 (In thousands) Proved oil and natural gas properties $ 1,740,530 $ 1,269,605 Support equipment and facilities 4,719 — Unproved oil and natural gas properties 414,759 47,497 Total oil and natural gas properties $ 2,160,008 $ 1,317,102 At December 31, 2015 and 2014, we had $174.0 million and $100.5 million, respectively, capitalized in proved oil and natural gas properties related to wells in various stages of drilling and completion, which have been excluded from the depletion base.
Oil and Gas Reserves	Oil and Gas Reserves The estimates of proved oil and natural gas reserves utilized in the preparation of the consolidated and combined financial statements are estimated in accordance with the rules established by the SEC and the Financial Accounting Standards Board (“FASB”). These rules require that reserve estimates be prepared under existing economic and operating conditions using a trailing 12-month average price with no provision for price and cost escalations in future years except by contractual arrangements. Netherland, Sewell & Associates, Inc. (“NSAI”), our independent reserve engineers, was engaged to audit our internally prepared reserves estimates at December 31, 2015. 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 7 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 and 2013 was approximately $24.6 million and $2.5 million, respectively. We did not record any impairment expense for the year ended December 31, 2015. See Note 5 for further discussion on impairments. Unproved oil and natural gas properties are reviewed for impairment based on time or geologic factors. Information such as drilling results, reservoir performance, seismic interpretation or future plans to develop acreage is also considered. When unproved property investments are deemed to be impaired, the expense is reported in exploration expenses. We did not record any impairments related to unproved properties for the years ended December 31, 2015, 2014 and 2013.
Debt Issuance Costs	Debt Issuance Costs These costs are recorded on the balance sheet and amortized over the term of the associated debt using the straight-line method which generally approximates the effective yield method. Amortization expense, including write-off of debt issuance costs, for the years ended December 31, 2015, 2014, and 2013 was approximately $2.8 million, $3.2 million and $2.3 million, respectively.
Revenue Recognition	Revenue Recognition Revenue from the sale of oil and natural gas is recognized when title passes, net of royalties due to third parties. Oil and natural gas revenues are recorded using the sales method. Under this method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers, regardless of whether the sales are proportionate to our ownership in the property. An asset or a liability is recognized to the extent there is an imbalance in excess of the proportionate share of the remaining recoverable reserves on the underlying properties. No significant imbalances existed at December 31, 2015 or 2014. The following individual customers each accounted for 10% or more of total reported revenues for the period indicated: Years Ending December 31, 2015 2014 2013 Energy Transfer Equity, L.P. and subsidiaries 56 % 85 % 86 % Plains Marketing, L.P. 11 % n/a n/a
Derivative and Other Financial Instruments	Derivative and Other Financial Instruments Commodity derivative financial instruments (e.g., swaps, collars, and put options) are used to reduce the impact of natural gas, NGL and oil price fluctuations. Interest rate swaps are used to manage exposure to interest rate volatility, primarily as a result of variable rate borrowings under the credit facilities. Every derivative instrument is recorded on the balance sheet as either an asset or liability measured at its fair value. Changes in the derivative’s fair value are recognized in earnings as we have not elected hedge accounting for any of our derivative positions. Embedded derivatives that are required to be bifurcated and accounted for separately are treated in the same manner as freestanding derivatives. Embedded derivatives are recorded at fair value, with the difference between the basis of the hybrid financial instrument and the fair value of the embedded derivative recorded as the carrying value of the host contract. See Note 6 for further information on certain commodity contracts that required bifurcation.
Capitalized Interest	Capitalized Interest We capitalize interest costs to oil and gas properties on expenditures made in connection with certain projects such as drilling and completion of new oil and natural gas wells and major facility installations. Interest is capitalized only for the period that such activities are in progress. Interest is capitalized using a weighted average interest rate based on our outstanding borrowings. These capitalized costs are included within intangible drilling costs and amortized using the units of production method. For the year ended December 31, 2015 and 2014, we capitalized $5.4 million and $4.5 million of interest, respectively.
Income Tax	Income Tax The Company uses the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the tax basis in assets and liabilities and their reported amounts in the financial statements and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. Deferred tax assets are reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of deferred tax assets will not be realized. The Company recognizes interest and penalties accrued to unrecognized tax benefits in other income (expense) in its consolidated statement of operations. A tax benefit from an uncertain tax position is recognized when it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position. The tax benefit recorded is equal to the largest amount that is greater than 50% likely to be realized through effective settlement with a taxing authority.
Earnings Per Share	Earnings Per Share Basic earnings per share (“EPS”) is computed using the two-class method based on net income (loss) available to common stockholders and the average number of shares of common stock outstanding for the period. Diluted EPS includes the impact of the Company’s restricted shares of common stock as they are participating securities. The Company determines the more dilutive of either the two-class method or the treasury stock method for diluted EPS. See Note 10 for additional information.
Incentive Based Compensation Arrangements	Incentive Based Compensation Arrangements The fair value of equity-classified awards (e.g., restricted stock awards) is amortized to earnings over the requisite service or vesting period. Compensation expense for liability-classified awards (e.g., phantom unit awards) is recognized over the requisite service or vesting period of an award based on the fair value of the award re-measured at each reporting period. Generally, no compensation expense is recognized for equity instruments that do not vest. Prior to the restructuring transactions, the governing documents of MRD LLC and certain of its subsidiaries provided for the issuance of incentive units. The incentive units were subject to performance conditions that affected their vesting. Compensation cost was recognized only if the performance condition was probable of being satisfied at each reporting date. In connection with the restructuring transactions, the MRD LLC incentive units were exchanged for substantially identical units in MRD Holdco, and such incentive units entitle holders thereof to portions of future distributions by MRD Holdco. While any such distributions made by MRD Holdco will not involve any cash payment by us, we will be required to recognize non-cash compensation expense, which may be material, in future periods. The compensation expense recognized by us related to the incentive units will be offset by a deemed capital contribution from MRD Holdco as they are remeasured at the end of each reporting period. See Notes 11 and 12 for further information.
Accrued Liabilities	Accrued Liabilities Current accrued liabilities consisted of the following at the dates indicated (in thousands): December 31, December 31, 2015 2014 Accrued capital expenditures $ 40,197 $ 44,308 Accrued interest payable 17,657 124 Other accrued liabilities 11,022 6,804 $ 68,876 $ 51,236
Supplemental Cash Flow Information	Supplemental Cash Flow Information Supplemental cash flow for continuing operations for the periods presented (in thousands): For the Year Ended December 31, 2015 2014 2013 Supplemental cash flows: Cash paid for interest, net of capitalized interest $ 18,815 $ 67,023 $ 18,541 Cash paid for taxes 8,160 687 — Noncash investing and financing activities: Increase (decrease) in capital expenditures in payables and accrued liabilities (4,111 ) 18,012 22,238 (Increase) decrease in accounts receivable related to acquisitions and divestitures 852 (852 ) — Assumptions of asset retirement obligations related to properties acquired or drilled 1,348 786 2,111 Repurchase of equity under repurchase program — 2,053 —
New Accounting Pronouncements	New Accounting Pronouncements Balance Sheet Classification of Deferred Taxes . In November 2015, the Financial Accounting Standards Board (“FASB”) issued an accounting standards update that requires entities with a classified balance sheet to present all deferred tax assets and liabilities as noncurrent. The current requirement that deferred tax assets and liabilities of a tax-paying component of an entity be offset and presented as a single amount is not affected by the amendment. The amendments are effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Early adoption is permitted for all entities as of the beginning of an interim or annual reporting period. The amendments may be applied either prospectively to all deferred tax assets and liabilities or retrospectively to all periods presented. We have adopted this guidance as of December 31, 2015 and applied the disclosure requirements retrospectively to the consolidated financial statements and footnote disclosure. Simplifying the Accounting for Measurement-Period Adjustments . In September 2015, the FASB issued an accounting standards update that eliminates the requirement that an acquirer in a business combination account for measurement-period adjustments retrospectively. Instead, an acquirer will recognize a measurement-period adjustment during the period in which it determines the amount of the adjustment. Disclosure of the effect on earnings of any amounts an acquirer would have recorded in previous periods if the accounting had been completed at the acquisition date is required. The disclosure is required for each affected income statement line item, and may be presented separately on the face of the income statement or in the notes to the financial statements. The new guidance should be applied prospectively to adjustments to provisional amounts that occur after the effective date and is effective for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Early adoption is permitted for any interim and annual financial statements that have not yet been issued. The Company does not expect the impact of adopting this guidance to be material to the Company’s financial statements and related disclosures. Revenue from Contracts with Customers . In May 2014, the FASB issued a comprehensive new revenue recognition standard for contracts with customers that will supersede most current revenue recognition guidance, including industry-specific guidance. The core principle of this standard is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, the standard provides a five-step analysis of transactions to determine when and how revenue is recognized. In August 2015, the FASB issued an accounting standards update that formally delayed the effective date of its new revenue recognition standard. The new standard is now effective for fiscal years, and interim periods within those years, beginning after December 15, 2017. Early adoption is now permitted for fiscal years, and interim periods within those years, beginning after December 15, 2016. The standard permits the use of either the retrospective or cumulative effect transition method. This guidance will be applicable to the Company beginning on January 1, 2018. The Company has not yet selected a transition method and is currently evaluating the standard and the impact on its consolidated financial statements and footnote disclosures. Presentation of Debt Issuance Cost . In April 2015, the FASB issued an accounting standards update that requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying value of that debt liability, consistent with debt discounts. The guidance is effective retrospectively for fiscal years, and interim periods within those years, beginning after December 15, 2015. Early adoption is permitted for financial statements that have not been previously issued. The Company has chosen to adopt this standard and have applied this guidance in its consolidated financial statements and footnote disclosures. In August 2015, the FASB issued an accounting standards update that incorporates SEC guidance clarifying that debt issuance costs related to line-of-credit arrangements can be deferred and presented as an asset that is subsequently amortized over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The Company has elected this presentation in its consolidated financial statements and footnote disclosures as of December 31, 2015. Amendments to Consolidation Analysis . In February 2015, the FASB issued an accounting standards update to improve consolidation guidance for certain types of legal entities. The guidance modifies the evaluation of whether limited partnerships and similar legal entities are variable interest entities (“VIEs”) or voting interest entities, eliminates the presumption that a general partner should consolidate a limited partnership, affects the consolidation analysis of reporting entities that are involved with VIEs, particularly those that have fee arrangements and related party relationships, and provides a scope exception from consolidation guidance for certain money market funds. These provisions are effective for annual reporting periods beginning after December 15, 2015, and interim periods within those annual periods, with early adoption permitted. These provisions may also be adopted using either a full retrospective or a modified retrospective approach. Although the Company continues to assess the impact that adopting this new accounting guidance will have on its consolidated financial statements and footnote disclosures, we expect that MEMP will become a VIE. We believe we will continue to consolidate MEMP and become subject to the VIE primary beneficiary disclosure requirements. Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Company’s financial position, results of operations and cash flows.

Organization and Basis of Pre26

Organization and Basis of Presentation (Tables)	12 Months Ended
	Dec. 31, 2015
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Schedule of Retrospective Adjustments to Balance Sheet	The retrospective adjustments to the December 31, 2014 balance sheet are shown below. December 31, 2014 Before Adjustment Adjustment Effect December 31, 2014 As Adjusted (In thousands) Prepaid expenses and other current assets 12,999 (1,655 ) 11,344 Other long-term assets 14,126 (10,540 ) 3,586 Accrued liabilities 101,758 (50,522 ) 51,236 Long-term debt 783,000 (12,455 ) 770,545 Deferred tax liabilities 64,077 50,522 114,599

Summary of Significant Accoun27

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Schedule of Oil and Natural Gas Properties	Oil and natural gas properties consisted of the following at the dates indicated: December 31, 2015 2014 (In thousands) Proved oil and natural gas properties $ 1,740,530 $ 1,269,605 Support equipment and facilities 4,719 — Unproved oil and natural gas properties 414,759 47,497 Total oil and natural gas properties $ 2,160,008 $ 1,317,102
Individual Customers Each Accounted for 10% or More of Total Reported Revenues	The following individual customers each accounted for 10% or more of total reported revenues for the period indicated: Years Ending December 31, 2015 2014 2013 Energy Transfer Equity, L.P. and subsidiaries 56 % 85 % 86 % Plains Marketing, L.P. 11 % n/a n/a
Schedule of Accrued Liabilities	Current accrued liabilities consisted of the following at the dates indicated (in thousands): December 31, December 31, 2015 2014 Accrued capital expenditures $ 40,197 $ 44,308 Accrued interest payable 17,657 124 Other accrued liabilities 11,022 6,804 $ 68,876 $ 51,236
Schedule of Supplemental Cash Flow	Supplemental cash flow for continuing operations for the periods presented (in thousands): For the Year Ended December 31, 2015 2014 2013 Supplemental cash flows: Cash paid for interest, net of capitalized interest $ 18,815 $ 67,023 $ 18,541 Cash paid for taxes 8,160 687 — Noncash investing and financing activities: Increase (decrease) in capital expenditures in payables and accrued liabilities (4,111 ) 18,012 22,238 (Increase) decrease in accounts receivable related to acquisitions and divestitures 852 (852 ) — Assumptions of asset retirement obligations related to properties acquired or drilled 1,348 786 2,111 Repurchase of equity under repurchase program — 2,053 —

Discontinued Operations (Tables

Discontinued Operations (Tables)	12 Months Ended
	Dec. 31, 2015
Discontinued Operations And Disposal Groups [Abstract]
Schedule of Reconciliation of Carrying Amounts of Major Classes of Assets and Liabilities Included as Part of Discontinued Operations	Below is a reconciliation of carrying amounts of major classes of assets and liabilities included as part of discontinued operations as reflected on the balance sheets associated with this disposal transaction (in thousands): December 31, December 31, 2015 2014 ASSETS Current assets: Cash and cash equivalents $ 2,175 $ 2,594 Accounts receivable 61,403 98,498 Short-term derivative instruments 272,320 208,585 Prepaid expenses and other current assets 9,643 11,859 Total current assets 345,541 321,536 Property and equipment, net 1,946,937 2,471,011 Long-term derivative instruments 461,809 311,802 Restricted investments 152,631 77,361 Other long-term assets 5,053 5,062 Total assets $ 2,911,971 $ 3,186,772 LIABILITIES Current liabilities: Accounts payable $ 8,792 $ 24,813 Accounts payable - affiliates 193 464 Revenues payable 27,021 35,545 Accrued liabilities 52,923 95,835 Short-term derivative instruments 2,850 3,289 Total current liabilities 91,779 159,946 Long-term debt 2,000,579 1,574,147 Asset retirement obligations 162,989 112,702 Long-term derivative instruments 1,441 — Deferred tax liabilities 2,094 32,347 Total liabilities $ 2,258,882 $ 1,879,142
Schedule of Reconciliation of Major Line Items Constituting Pretax Profit (Loss) of Discontinued Operations to After Tax Profit (Loss) of Discontinued Operations	Below is a reconciliation of major line items constituting pretax profit (loss) of discontinued operations to the after tax profit (loss) of discontinued operations that are presented in the statement of operations (in thousands): For Year Ended December 31, 2015 2014 2013 Revenues: Oil & natural gas sales $ 355,422 $ 561,677 $ 391,440 Other revenues 2,725 4,366 3,075 Total revenues 358,147 566,043 394,515 Costs and expenses: Lease operating 168,199 143,733 94,591 Gathering, processing, and transportation 34,939 31,892 25,055 Exploration 2,317 2,750 1,322 Taxes other than income 25,828 33,141 18,447 Depreciation, depletion, and amortization 195,814 185,955 113,814 Impairment of proved oil and natural gas properties 616,784 407,540 4,072 General and administrative (1) 56,671 49,124 54,947 Accretion of asset retirement obligations 7,125 5,773 4,988 (Gain) loss on commodity derivative instruments (462,890 ) (492,254 ) (26,133 ) (Gain) loss on sale of properties (2,998 ) — (2,848 ) Other, net (665 ) (11 ) 647 Total costs and expenses 641,124 367,643 288,902 Operating income (loss) (282,977 ) 198,400 105,613 Other income (expense): Interest expense, net (114,732 ) (83,550 ) (44,302 ) Other, net 43 (657 ) 2 Total other income (expense) (114,689 ) (84,207 ) (44,300 ) Pretax profit (loss) of discontinued operations (397,666 ) 114,193 61,313 Income tax benefit (expense) 2,175 1,421 (308 ) Net income (loss) from discontinued operations $ (395,491 ) $ 115,614 $ 61,005 (1) Includes $32.3 million, $24.4 million and $9.4 million for the years ended December 31, 2015, 2014 and 2013 that was allocated to discontinued operations under an omnibus agreement. This omnibus agreement terminated on June 1, 2016. We entered into a transition services agreement with MEMP to manage post-closing separation costs and activities.

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2015
Transaction-Related Costs	Transaction-related costs for both related party and third party transactions are included in general and administrative expenses in the accompanying statements of operations for the periods indicated below (in thousands): For the Year Ended December 31, 2015 2014 2013 $ 1,974 $ 2,305 $ 1,584
Louisiana [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 date (in thousands): Louisiana Acquisition Oil and gas properties $ 72,141 Asset retirement obligations (271 ) Total identifiable net assets $ 71,870
2013 Acquisitions [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 date (in thousands): Oil and gas properties $ 68,887 Asset retirement obligations (1,789 ) Total identifiable net assets $ 67,098

Fair Value Measurements of Fi30

Fair Value Measurements of Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Assets and Liabilities Measured at Fair Value on Recurring Basis	The following table presents the derivative assets and liabilities that are measured at fair value on a recurring basis at December 31, 2015 and December 31, 2014 for each of the fair value hierarchy levels: Fair Value Measurements at December 31, 2015 Using Quoted Prices in Significant Other Significant Active Observable Unobservable Market Inputs Inputs (Level 1) (Level 2) (Level 3) Fair Value (In thousands) Assets: Commodity derivatives $ — $ 319,763 $ — $ 319,763 Liabilities: Commodity derivatives $ — $ 480 $ — $ 480 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 $ — $ 280,846 $ — $ 280,846 Liabilities: Commodity derivatives $ — $ 25,808 $ — $ 25,808

Risk Management and Derivativ31

Risk Management and Derivative and Other Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2015
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Schedule of Open Commodity Positions	At December 31, 2015, we had the following open commodity positions (excluding embedded derivatives): 2016 2017 Natural Gas Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (MMBtu) 2,570,000 1,770,000 Weighted-average fixed price $ 4.09 $ 4.24 Collar contracts: Average Monthly Volume (MMBtu) 1,100,000 1,050,000 Weighted-average floor price $ 4.00 $ 4.00 Weighted-average ceiling price $ 4.71 $ 5.06 Purchased put option contracts: Average Monthly Volume (MMBtu) 6,000,000 5,350,000 Weighted-average strike price $ 3.51 $ 3.48 Weighted-average deferred premium paid $ (0.34 ) $ (0.32 ) TGT Z1 basis swaps: Average Monthly Volume (MMBtu) 1,120,000 200,000 Spread - Henry Hub $ (0.10 ) $ (0.08 ) Crude Oil Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 35,583 28,000 Weighted-average fixed price $ 83.58 $ 84.70 Collar contracts: Average Monthly Volume (Bbls) 27,000 — Weighted-average floor price $ 80.00 $ — Weighted-average ceiling price $ 99.70 $ — NGL Derivative Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 353,399 — Weighted-average fixed price $ 39.68 $ — At December 31, 2015, we had the following open embedded derivative positions: 2016 Oil Hybrid Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 27,080 Weighted-average fixed price $ 46.51 Initial net investment price 62.16 Total contract swap price $ 108.67 NGL Hybrid Contracts: Fixed price swap contracts: Average Monthly Volume (Bbls) 83,101 Weighted-average fixed price $ 15.84 Initial net investment price 25.98 Total contract swap price $ 41.82
Summary of Gross Fair Value and Net Recorded Fair Value of Derivative Instruments by Appropriate Balance Sheet Classification	The following table summarizes both: (i) the gross fair value of derivative instruments by the appropriate balance sheet classification even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the balance sheet and (ii) the net recorded fair value as reflected on the balance sheet at December 31, 2015 and 2014. There was no cash collateral received or pledged associated with our derivative instruments since most of the counterparties, or certain affiliates, to our derivative contracts are lenders under our credit agreement. Asset Derivatives Liability Derivatives Type Balance Sheet Location 2015 2014 2015 2014 (In thousands) Commodity contracts Short-term derivative instruments $ 228,349 $ 153,026 $ 358 $ 21,555 Netting arrangements Short-term derivative instruments (358 ) (21,555 ) (358 ) (21,555 ) Net recorded fair value Short-term derivative instruments $ 227,991 $ 131,471 $ — $ — Commodity contracts Long-term derivative instruments $ 91,414 $ 127,820 $ 122 $ 4,253 Netting arrangements Long-term derivative instruments (122 ) (4,253 ) (122 ) (4,253 ) Net recorded fair value Long-term derivative instruments $ 91,292 $ 123,567 $ — $ —
Schedule of Gains and Losses Related to Derivative Instruments	The following table details the gains and losses related to derivative instruments for the years ending December 31, 2015, 2014, and 2013: Statements of For the Year Ended December 31, Operations Location 2015 2014 2013 Commodity derivative contracts (Gain) loss on commodity derivatives $ (281,249 ) $ (257,734 ) $ (3,161 ) Interest rate derivatives Interest expense, net — 296 309

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Summary of Changes in Asset Retirement Obligations	The following table presents the changes in the asset retirement obligations for the years ended December 31, 2015, 2014 and 2013: 2015 2014 2013 (In thousands) Asset retirement obligations at beginning of period $ 9,829 $ 10,333 $ 9,349 Liabilities added from acquisitions or drilling 1,348 786 2,111 Liabilities settled — — (150 ) Revision of estimates 927 (97 ) 195 Liabilities removed upon sale of wells (2,442 ) (1,726 ) (1,765 ) Accretion expense 417 533 593 Asset retirement obligations at end of period 10,079 9,829 10,333 Less: Current portion — — 90 Asset retirement obligations - long-term portion $ 10,079 $ 9,829 $ 10,243

Long Term Debt (Tables)

Long Term Debt (Tables)	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Debt Obligations	The following table presents our debt obligations at the dates indicated. December 31, December 31, 2015 2014 (In thousands) $2.0 billion revolving credit facility, variable-rate, due June 2019 $ 423,000 $ 183,000 5.875% senior unsecured notes, due July 2022 ("MRD Senior Notes") (1) (2) 600,000 600,000 Unamortized debt issuance costs (10,936 ) (12,455 ) Total long-term debt $ 1,012,064 $ 770,545 (1) The estimated fair value of this fixed-rate debt was $525.0 million and $534.0 million at December 31, 2015 and 2014, respectively. (2) The estimated fair value 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 our revolving credit facility was the following at the date indicated: December 31, 2015 $2.0 billion revolving credit facility, variable-rate, due June 2019 $ 1,000,000
Summary of Weighted-Average Interest Rates Paid On Variable-Rate Debt Obligations	The following table presents the weighted-average interest rates paid on our variable-rate debt obligations for the periods presented: Credit Facility For the Year Ended December 31, 2015 2014 2013 Revolving credit facility 1.92 % 1.99 % n/a WildHorse Resources revolver terminated June 2014 n/a 4.04 % 2.30 % WildHorse Resources second lien terminated June 2014 n/a 6.44 % 7.60 % Black Diamond terminated November 2013 n/a n/a 3.97 %
Summary of Unamortized Deferred Financing Costs Associated with Debt Obligations	Unamortized deferred financing costs associated with our debt obligations were as follows at the dates indicated: December 31, December 31, 2015 2014 (In thousands) Revolving credit facility $ 4,976 $ 4,285 Senior Notes 10,936 12,455 $ 15,912 $ 16,740

Stockholders' Equity and Nonc34

Stockholders' Equity and Noncontrolling Interests (Tables)	12 Months Ended
	Dec. 31, 2015
Equity [Abstract]
Summary of Changes In Common Shares Issued	The Company’s authorized capital stock includes 600,000,000 shares of common stock, $0.01 par value per share. The following is a summary of the changes in our common shares since January 1, 2014: Balance January 1, 2014 — Shares of common stock issued 192,500,000 Shares of common stock repurchased (123,797 ) Restricted common shares issued (Note 11) 1,068,422 Restricted common shares forfeited (9,211 ) Balance December 31, 2014 193,435,414 Shares of common stock issued 13,800,000 Shares of common stock repurchased (2,764,887 ) Restricted common shares issued (Note 11) 938,558 Restricted common shares repurchased (1) (60,773 ) Restricted common shares forfeited (54,569 ) Balance December 31, 2015 205,293,743 (1) Restricted common shares are generally net-settled by shareholders to cover the required withholding tax upon vesting. Participants surrendered shares with value equivalent to the employee’s minimum statutory obligation for the applicable income and other employment taxes. Total payments remitted for the employees’ tax obligations to the appropriate taxing authorities were approximately $1.2 million. These net-settlements had the effect of shares repurchased by the Company as they reduced the number of shares that would have otherwise been outstanding as a result of the vesting and did not represent an expense to the Company.

Earnings per share (Tables)

Earnings per share (Tables)	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
Summary of Calculation of Earnings (Loss) Per Share, or EPS	The following sets forth the calculation of earnings (loss) per share, or EPS, for the period indicated (in thousands, except per share amounts): For the Year Ended December 31, 2015 2014 Numerator: Net income (loss) from continuing operations available to common stockholders $ 95,241 $ (784,895 ) Net income (loss) from discontinued operations available to common stockholders $ (327 ) $ 314 Denominator: Weighted average common shares outstanding 193,698 192,498 Incremental treasury stock method shares (1) 469 203 Basic EPS from continuing operations $ 0.49 $ (4.08 ) Diluted EPS from continuing operations(1) $ 0.49 $ (4.08 ) Basic EPS from discontinued operations $ — $ — Diluted EPS from discontinued operations(1) $ — $ — (1) The Company determines the more dilutive of either the two-class method or the treasury stock method for diluted EPS. The two-class method was more dilutive for each period presented.

Long-Term Incentive Plans (Tabl

Long-Term Incentive Plans (Tables)	12 Months Ended
	Dec. 31, 2015
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Summary of Information Regarding Restricted Common Unit Awards	The following table summarizes information regarding restricted common share awards granted under the MRD LTIP for the periods presented: Number of Shares Weighted-Average Grant Date Fair Value per Share (1) Restricted common shares outstanding at January 1, 2014 — $ — Granted (2) 1,068,422 $ 19.00 Forfeited (9,211 ) $ 19.00 Restricted common shares outstanding at December 31, 2014 1,059,211 $ 19.00 Granted (3) 938,558 $ 18.80 Forfeited (54,569 ) $ 18.83 Vested (274,355 ) $ 19.00 Restricted common shares outstanding at December 31, 2015 1,668,845 $ 18.89 (1) Determined by dividing the aggregate grant date fair value of awards by the number of awards issued. (2) The aggregate grant date fair value of restricted common share awards issued in 2014 was $20.3 million based on grant date market price of $19.00 per share (3) The aggregate grant date fair value of restricted common share awards issued in 2015 was $17.6 million based on grant date market prices ranging from $17.58 to $18.91 per share.
Summary of Amount of Compensation Expense Recognized	The following table summarizes the amount of recognized compensation expense associated with these awards that are reflected in the accompanying statements of operations for the periods presented (in thousands): For the Year Ended December 31, 2015 2014 $ 8,788 $ 2,804

Incentive Units (Tables)

Incentive Units (Tables)	12 Months Ended
	Dec. 31, 2015
Compensation Related Costs [Abstract]
Fair Value of Incentive Units Estimated	The fair value of the incentive units was estimated using a Monte Carlo simulation valuation model with the following assumptions: Exchanged Incentive Units Subsequent Incentive Units Valuation date 12/31/2015 12/31/2015 Dividend yield 0 % 0 % Expected volatility 51.30 % 51.30 % Risk-free rate 0.82 % 0.82 % Expected life (years) 1.42 1.42

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2015
Schedule of Net Assets Recorded	WildHorse Resources recorded the following net assets (in thousands): Accounts receivable $ 2,274 Oil and natural gas properties, net 40,056 Accrued liabilities (297 ) Asset retirement obligations (277 ) Net assets $ 41,756
Book Value of Net Assets Acquired	The net assets acquired were as follows (in thousands): Cash and cash equivalents $ 2,820 Accounts receivable 5,184 Prepaid expenses and other current assets 1,454 Oil and natural gas properties, net 342,759 Long-term derivative instruments, net (826 ) Other long-term assets 344 Accounts payable (2,346 ) Revenue payable (2,910 ) Accrued liabilities (1,799 ) Short-term derivative instruments, net (1,828 ) Asset retirement obligations (9,606 ) Credit facilities (151,690 ) Net assets $ 181,556
Book Value of Assets Sold	The net book value of the assets sold was as follows (in thousands): Cash and cash equivalents $ 33,001 Restricted cash 300 Accounts receivable 5,256 Prepaid expenses and other current assets 379 Property, plant and equipment, net 3,410 Other long-term assets 4 Accounts payable (19,959 ) Accounts payable - affiliates (17,099 ) Accrued liabilities (5,061 ) Net assets $ 231
Schedule of Minimum Volume Commitment and Fees Associated with the GPA	The amended and restated gas processing agreement, (“GPA”) has a 15-year primary term, subject to one-year extensions at either party’s election. Processing fees under the GPA are subject to annual inflation escalators. Under the GPA, the Company has agreed to deliver a minimum volume of gas for processing through the term of the agreement measured on a cumulative basis based on specified daily minimum volume thresholds. Any volumes of gas delivered up to the then-applicable daily minimum volume threshold are considered firm reserved gas and are charged the firm fixed-commitment fee, and any volumes delivered in excess of such threshold are considered interruptible volumes and are charged the interruptible-service fixed fee. Pursuant to the GPA, any deficiency payments made by the Company under the GPA will be treated as prepaid processing fees by PennTex (except for the June 2015 deficiency payment). These charges do not expire until the end of the primary term of the GPA. Quarterly deficiency payments are based on the firm-commitment fixed fee. The following table summarizes the minimum volume commitment (“MVC”) and fees associated with the GPA. Period MVC (MMBtu/d) Firm Fee ($/MMBtu) Interruptible Fee ($/MMBtu) June 1, 2015 to September 30, 2015 115,000 0.435 0.470 October 1, 2015 to June 30, 2016 345,000 0.435 0.470 July 1, 2016 to June 30, 2026 (1) 460,000 0.435 0.350 July 1, 2026 to June 1, 2030 345,000 0.435 0.350 June 2, 2030 to October 1, 2030 115,000 0.435 0.350 (1) The firm fee is reduced to $0.35 $/MMBtu for volumes in excess of 345,000 MMBtu/d.
Transportation Services Agreement [Member]
Schedule of Fees Associated with Agreement	The transportation services agreement (“TSA”) provides for the transportation of NGLs through PennTex’s NGL pipeline from the outlet of their processing plants to a third party delivery point. The Company pays a usage fee for all volumes transported under the TSA. The TSA includes a plant tailgate dedication pursuant to which all of the Company’s NGLs produced from PennTex’s processing plants are delivered for transportation on the its NGL pipeline. The following table summarizes the fees associated with the TSA: Period Usage Fee ($/gallon) October 1, 2015 to October 1, 2030 0.04
Gas Gathering Agreement [Member]
Schedule of Minimum Volume Commitment and Fees Associated with the GPA	The gas gathering agreement, as amended, (“GGA”) has a 15-year primary term, subject to one-year extensions at either party’s election. The Company pays fees for gathering services provided by PennTex, including a firm capacity reservation payment through November 30, 2019 and a usage fee component that is subject to a minimum volume commitment. The GGA also has an annual “use it or lose it” deficiency provision that is based on the usage fee. The minimum volume commitment under the GGA is linked to the minimum volume commitment under the GPA. Period MVC (MMBtu/d) Firm Fee ($/MMBtu) Usage Fee ($/MMBtu) June 1, 2015 to November 30, 2019 460,000 0.03 n/a June 1, 2015 to September 30, 2015 115,000 n/a 0.02 October 1, 2015 to June 30, 2016 345,000 n/a 0.02 July 1, 2016 to November 30, 2019 460,000 n/a 0.02 December 1, 2019 to June 30, 2026 460,000 n/a 0.05 July 1, 2026 to June 1, 2030 345,000 n/a 0.05
Gas Transportation Agreement [Member]
Schedule of Fees Associated with Agreement	The gas transportation agreement, as amended, (“GTA”) has a 15-year primary term, subject to one-year extensions at either party’s election. The GTA provides for the transportation of residue gas through PennTex’s residue gas pipeline from the outlet of their processing plants to delivery points at interconnections with third-party natural gas transportation pipelines. The Company pays a usage fee for all volumes transported under the GTA. The GTA includes a plant tailgate dedication pursuant to which all of the Company’s residue gas produced from the PennTex’s processing plants are delivered for transportation on their residue gas pipeline. The GTA also includes a fixed monthly demand charge to provide priority firm service. The following table summarizes the fees associated with the GTA: Period Demand Fee ($/month) Usage Fee ($/MMBtu) June 1, 2015 to June 1, 2030 n/a 0.04 January 1, 2016 to December 31, 2025 360,000 n/a

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Components of Income Tax Benefit (Expense) from Continuing Operations	The components of income tax benefit (expense) from continuing operations are as follows: For the Year Ended December 31, 2015 2014 2013 (In thousands) Current income taxes: Federal $ (9,971 ) $ — $ — State (99 ) 149 (1,311 ) Total current income tax benefit (expense) (10,070 ) 149 (1,311 ) Deferred income taxes: Federal (55,417 ) (91,051 ) — State (34,518 ) (11,490 ) — Total deferred income tax benefit (expense) (89,935 ) (102,541 ) — Total income tax benefit (expense) $ (100,005 ) $ (102,392 ) $ (1,311 )
Reconciliation of Income Tax Benefit (Expense) from Continuing Operations	The actual income tax benefit (expense) from continuing operations differs from the expected amount computed by applying the federal statutory corporate tax rate of 35% as follows: For the Year Ended December 31, 2015 2014 2013 (In thousands) Expected tax benefit (expense) at federal statutory rate $ (69,162 ) $ 227,250 $ (32,073 ) State income tax benefit (expense), net of federal benefit (22,501 ) (7,753 ) (1,311 ) Pass-through entities (1) — 7,989 32,073 Stock compensation (2) (12,300 ) (330,024 ) — Other 3,958 146 — Total income tax benefit (expense) $ (100,005 ) $ (102,392 ) $ (1,311 ) (1) 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.
Components of Net Deferred Income Tax Liabilities	The components of net deferred income tax liabilities are as follows: December 31, 2015 2014 (In thousands) Deferred income tax assets: Net operating loss carryforward $ 68,375 $ 24,084 Asset retirement obligation 3,789 3,902 Alternative minimum tax credit carryforward 9,984 — Other 5,546 3,550 Total deferred income tax assets $ 87,694 $ 31,536 Valuation allowance — — Net deferred income tax assets 87,694 31,536 Deferred income tax liabilities: Property, plant and equipment $ 171,627 $ 48,104 Derivatives 109,800 97,760 Other — 271 Total deferred income tax liabilities $ 281,427 $ 146,135 Net deferred income tax liabilities $ 193,733 $ 114,599

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2015
Commitments And Contingencies Disclosure [Abstract]
Environmental Reserves Activity	The following table presents the activity of our environmental reserves for the years ended December 31, 2014 and 2013: 2014 2013 (In thousands) Balance at beginning of period $ 140 $ 418 Charged to costs and expenses — — Payments (140 ) (278 ) Balance at end of period $ — $ 140
Monthly Demand Quantity and Fees	The table below summarizes the monthly demand quantity (“MDQ”) and fees associated with the agreement. Based on the MDQ, we project that that payout would be achieved during January 2020. MDQ (MMBtu/d) Payback Demand Fee ($/MMBtu) Gathering Demand Fee ($/MMBtu) Dubberly Cryogenic Processing Fee ($/MMBtu) January 1, 2016 to January 22, 2020 249,700 0.275 0.295 n/a January 1, 2016 to January 22, 2020 113,000 n/a n/a 0.380
Minimum Lease Payment Obligations and Sublease Rental Income Under Non-Cancelable Operating Leases	Amounts shown in the following table represent minimum lease payment obligations and sublease rental income under non-cancelable operating leases with a remaining term in excess of one year: Payment or Settlement due by Period Total 2016 2017 2018 2019 2020 Thereafter (In thousands) Operating leases $ 45,323 $ 10,509 $ 9,344 $ 7,368 $ 6,776 $ 6,203 $ 5,123 Sublease rental income 4,021 1,579 1,197 814 431 — —

Quarterly Financial Informati41

Quarterly Financial Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Schedule of Quarterly Financial Information	The following tables present selected quarterly financial data for the periods indicated. Earnings per share are computed independently for each of the quarters presented and the sum of the quarterly earnings per share may not necessarily equal the total for the year. As discussed in Note 12, we recorded incentive unit compensation expense, respectively, during 2014 and 2015, which impacted the comparability of net income (loss) from continuing operations between the periods presented below. First Quarter Second Quarter Third Quarter Fourth Quarter For the Year Ended December 31, 2015 (In thousands, except per share amounts) Revenues $ 87,023 $ 78,605 $ 111,654 $ 96,760 Operating income (loss) 107,872 (41,593 ) 120,415 51,330 Net income (loss) from continuing operations 50,509 (26,614 ) 56,726 16,980 Net income (loss) (112,149 ) (140,473 ) (135,255 ) 89,987 Net income (loss) attributable to noncontrolling interest (158,041 ) (113,771 ) (191,807 ) 70,081 Net income (loss) attributable to Memorial Resource Development Corp. 45,892 (26,702 ) 56,552 19,906 Net income (loss) from continuing operations available to common stockholders 45,615 (26,702 ) 56,051 20,277 Earnings per common share – basic Income (loss) from continuing operations 0.24 (0.14 ) 0.29 0.10 Income (loss) from discontinued operations 0.24 (0.14 ) 0.29 0.10 Earnings per common share – diluted Income (loss) from continuing operations 0.24 (0.14 ) 0.29 0.10 Income (loss) from discontinued operations 0.24 (0.14 ) 0.29 0.10 First Quarter Second Quarter Third Quarter Fourth Quarter For the Year Ended December 31, 2014 (In thousands, except per share amounts) Revenues $ 87,736 $ 110,569 $ 99,035 $ 111,742 Operating income (loss) 27,344 (899,962 ) 47,123 263,421 Net income (loss) from continuing operations 9,376 (941,803 ) 10,730 170,020 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) from continuing operations available to common stockholders n/a (961,707 ) 9,928 166,884 Earnings per common share – basic Income (loss) from continuing operations n/a (5.00 ) 0.05 0.87 Income (loss) from discontinued operations n/a (5.00 ) 0.05 0.87 Earnings per common share – diluted Income (loss) from continuing operations n/a (5.00 ) 0.05 0.87 Income (loss) from discontinued operations n/a (5.00 ) 0.05 0.87

Supplemental Oil and Gas Info42

Supplemental Oil and Gas Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2015
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, 2015 2014 2013 (In thousands) Evaluated oil and natural gas properties $ 1,740,530 $ 1,269,605 $ 897,511 Support equipment and facilities 4,719 — — Unevaluated oil and natural gas properties 414,759 47,497 44,453 Accumulated depletion, depreciation, and amortization (434,735 ) (276,837 ) (160,620 ) Total $ 1,725,273 $ 1,040,265 $ 781,344
Costs Incurred for Property Acquisitions, Exploration and Development	Costs incurred in property acquisition, exploration and development activities were as follows for the periods indicated: For the Year Ended December 31, 2015 2014 2013 (In thousands) Property acquisition costs, proved $ 8,347 $ 74,490 $ 56,108 Property acquisition costs, unproved 360,353 24,310 19,975 Exploration and extension well costs 28,068 209,532 13,313 Development 492,191 181,026 191,350 Total $ 888,959 $ 489,358 $ 280,746
Weighted Average Benchmark Product Prices	The weighted-average benchmark product prices used for valuing the reserves are based upon the average of the first-day-of-the-month price for each month within the period January through December of each year presented: 2015 2014 2013 Oil ($/Bbl) West Texas Intermediate (1) $ 46.79 $ 91.48 $ 93.42 NGL ($/Bbl) West Texas Intermediate (1) $ 46.79 $ 91.48 $ 93.42 Natural Gas ($/Mmbtu) Henry Hub (2) $ 2.59 $ 4.35 $ 3.67 (1) The unweighted average West Texas Intermediate price was adjusted by lease for quality, transportation fees, and a regional price differential. (2) The unweighted average Henry Hub price was adjusted by lease for energy content, compression charges, transportation fees, and regional price differentials.
Reserve Quantity Information	The following tables set forth estimates of the net reserves as of December 31, 2015, 2014, and 2013 respectively: For the Year Ended December 31, 2015 Oil (MBbls) Gas (MMcf) NGLs (MBbls) Equivalent (MMcfe) Proved developed and undeveloped reserves: Beginning of the year 11,915 1,013,340 53,033 1,403,030 Extensions and discoveries 1,111 50,343 2,741 73,456 Purchase of minerals in place 535 17,508 969 26,532 Production (1,331 ) (98,269 ) (3,249 ) (125,749 ) Sales of minerals in place (407 ) (39,272 ) (358 ) (43,861 ) Revision of previous estimates 1,331 30,164 1,024 44,286 End of year 13,154 973,814 54,160 1,377,694 Proved developed reserves: Beginning of year 3,708 355,331 18,203 486,793 End of year 6,101 443,983 24,583 628,081 Proved undeveloped reserves: Beginning of year 8,207 658,009 34,830 916,237 End of year 7,053 529,831 29,577 749,613 For the Year Ended December 31, 2014 Oil (MBbls) Gas (MMcf) NGLs (MBbls) Equivalent (MMcfe) Proved developed and undeveloped reserves: Beginning of the year 10,824 671,485 35,628 950,199 Extensions and discoveries 1,825 183,467 9,876 253,670 Purchase of minerals in place 269 22,186 1,247 31,283 Production (908 ) (56,574 ) (1,863 ) (73,200 ) Sales of minerals in place (623 ) (10,815 ) (950 ) (20,253 ) Revision of previous estimates 528 203,591 9,095 261,331 End of year 11,915 1,013,340 53,033 1,403,030 Proved developed reserves: Beginning of year 3,238 223,362 12,226 316,154 End of year 3,708 355,331 18,203 486,793 Proved undeveloped reserves: Beginning of year 7,586 448,123 23,402 634,045 End of year 8,207 658,009 34,830 916,237 For the Year Ended December 31, 2013 Oil (MBbls) Gas (MMcf) NGLs (MBbls) Equivalent (MMcfe) Proved developed and undeveloped reserves: Beginning of the year 10,220 549,449 31,264 798,357 Extensions and discoveries 1,635 105,289 5,712 149,369 Purchase of minerals in place 211 31,815 1,017 39,183 Production (631 ) (28,729 ) (1,282 ) (40,212 ) Sales of minerals in place (599 ) (14,137 ) (1,573 ) (27,169 ) Revision of previous estimates (12 ) 27,798 490 30,671 End of year (1) 10,824 671,485 35,628 950,199 Proved developed reserves: Beginning of year 2,813 180,523 10,208 258,651 End of year 3,238 223,362 12,226 316,154 Proved undeveloped reserves: Beginning of year 7,407 368,926 21,056 539,706 End of year 7,586 448,123 23,402 634,045 (1) Includes reserves of 41,077 MMcfe attributable to noncontrolling interests and NGPCIF.
Discounted Future Net Cash Flows	The standardized measure of discounted future net cash flows is as follows: For the Year Ended December 31, 2015 2014 2013 (In thousands) Future cash inflows $ 4,008,764 $ 7,314,745 $ 4,942,687 Future production costs (1,438,531 ) (1,020,599 ) (1,343,252 ) Future development costs (784,003 ) (1,209,907 ) (1,137,429 ) Future income tax expense (1) (88,723 ) (1,669,356 ) — Future net cash flows for estimated timing of cash flows 1,697,507 3,414,883 2,462,006 10% annual discount for estimated timing of cash flows (877,647 ) (1,604,728 ) (1,103,145 ) Standardized measure of discounted future net cash flows (2) $ 819,860 $ 1,810,155 $ 1,358,861 (1) Our predecessor was a pass through entity and was subject to the Texas margin tax based on the taxable margin apportioned to Texas. However, due to immateriality, we have excluded the impact of this tax for the year ended December 31, 2013. (2) Includes $63,422 attributable to both noncontrolling interests and NGPCIF for the year ended December 31, 2013.
Summary of the Changes in the Standardized Measure of Future Net Cash Flows	The following is a summary of the changes in the standardized measure of discounted future net cash flows for the proved oil and natural gas reserves during each of the years in the three year period ended December 31, 2015: For the Year Ended December 31, 2015 2014 2013 (In thousands) Beginning of year $ 1,810,155 $ 1,358,861 $ 1,138,271 Sale of oil and natural gas produced, net of production costs (240,244 ) (332,785 ) (175,933 ) Purchase of minerals in place 53,597 69,282 51,177 Sale of minerals in place (41,543 ) (47,791 ) (54,091 ) Extensions and discoveries 30,006 653,088 286,796 Changes in income taxes, net 882,942 (995,635 ) — Changes in prices and costs (2,284,279 ) 367,212 (59,083 ) Previously estimated development costs incurred 294,617 205,388 62,012 Net changes in future development costs 190,403 (68,079 ) (1,295 ) Revisions of previous quantities 51,455 713,176 45,183 Accretion of discount 244,123 135,887 110,312 Change in production rates and other (171,372 ) (248,449 ) (44,488 ) End of year $ 819,860 $ 1,810,155 $ 1,358,861

Condensed Consolidating Finan43

Condensed Consolidating Financial Information (Tables)	12 Months Ended
	Dec. 31, 2015
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Condensed Consolidating Balance Sheets	The following condensed consolidating financial information presents our financial information on a unconsolidated stand-alone basis and our combined guarantor and combined non-guarantor subsidiaries as of and for the periods indicated. Such financial information may not necessarily be indicative of our results of operations, cash flows or financial position had these subsidiaries operated as independent entities. As of December 31, 2015 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated (In thousands) ASSETS Current assets: Cash and cash equivalents $ 2,986 $ — $ — $ (2,986 ) $ — Accounts receivable - trade 7,850 48,372 — (3,530 ) 52,692 Accounts receivable - affiliates 9,525 — — (9,525 ) — Short-term derivative instruments 227,991 — — — 227,991 Other financial assets 46,106 — — — 46,106 Prepaid expenses and other current assets 2,318 1,056 — — 3,374 Assets of discontinued operations — 3,779 340,186 1,576 345,541 Total current assets 296,776 53,207 340,186 (14,465 ) 675,704 Property and equipment, net 15,825 1,728,622 — — 1,744,447 Long-term derivative instruments 91,292 — — — 91,292 Investments in subsidiaries 1,482,847 — — (1,482,847 ) — Other long-term assets 4,976 — — — 4,976 Assets of discontinued operations — 614 2,565,816 — 2,566,430 Total assets $ 1,891,716 $ 1,782,443 $ 2,906,002 $ (1,497,312 ) $ 5,082,849 LIABILITIES AND EQUITY Current Liabilities: Accounts payable and accrued liabilities $ 26,796 $ 66,133 $ — $ 1,004 $ 93,933 Accounts payable - affiliates — 17,339 — (12,323 ) 5,016 Revenues payable 80 33,946 — — 34,026 Liabilities of discontinued operations — 1,517 93,408 (3,146 ) 91,779 Total current liabilities 26,876 118,935 93,408 (14,465 ) 224,754 Long-term debt 1,012,064 — — — 1,012,064 Asset retirement obligations — 10,079 — — 10,079 Deferred tax liabilities 22,754 170,979 — — 193,733 Other long-term liabilities 7,195 — — — 7,195 Liabilities of discontinued operations — — 2,167,103 — 2,167,103 Total liabilities 1,068,889 299,993 2,260,511 (14,465 ) 3,614,928 Equity: Equity 822,827 1,482,450 645,491 (2,127,941 ) 822,827 Noncontrolling interest — — — 645,094 645,094 Total equity 822,827 1,482,450 645,491 (1,482,847 ) 1,467,921 Total liabilities & equity $ 1,891,716 $ 1,782,443 $ 2,906,002 $ (1,497,312 ) $ 5,082,849 As of December 31, 2014 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated (In thousands) ASSETS Current assets: Cash and cash equivalents $ 2,241 $ 1,123 $ — $ — $ 3,364 Accounts receivable- trade 5,995 29,804 — (2,721 ) 33,078 Accounts receivable - affiliates 10,047 — — (10,047 ) — Short-term derivative instruments 131,471 — — — 131,471 Prepaid expenses and other current assets 4,178 7,166 — — 11,344 Assets of discontinued operations — 18,614 303,961 (1,039 ) 321,536 Total current assets 153,932 56,707 303,961 (13,807 ) 500,793 Property and equipment, net 16,601 1,050,043 — — 1,066,644 Long-term derivative instruments 123,567 — — — 123,567 Investments in subsidiaries 1,139,792 — — (1,139,792 ) — Other long-term assets 3,324 260 — 2 3,586 Assets of discontinued operations — 679 2,864,559 (2 ) 2,865,236 Total assets $ 1,437,216 $ 1,107,689 $ 3,168,520 $ (1,153,599 ) $ 4,559,826 LIABILITIES AND EQUITY Current Liabilities: Accounts payable and accrued expenses $ 6,245 $ 49,075 $ — $ (3,125 ) $ 52,195 Accounts payable - affiliates — 160 — — 160 Revenues payable — 21,807 — — 21,807 Liabilities of discontinued operations — 16,384 152,985 (9,423 ) 159,946 Total current liabilities 6,245 87,426 152,985 (12,548 ) 234,108 Long-term debt 770,545 — — — 770,545 Asset retirement obligations — 9,829 — — 9,829 Deferred tax liabilities 69,431 45,122 — 46 114,599 Other long-term liabilities 8,585 — — — 8,585 Liabilities of discontinued operations — 1 1,719,241 (46 ) 1,719,196 Total liabilities 854,806 142,378 1,872,226 (12,548 ) 2,856,862 Equity: Equity 582,410 965,311 1,290,734 (2,256,045 ) 582,410 Noncontrolling interest — — 5,560 1,114,994 1,120,554 Total equity 582,410 965,311 1,296,294 (1,141,051 ) 1,702,964 Total liabilities & equity $ 1,437,216 $ 1,107,689 $ 3,168,520 $ (1,153,599 ) $ 4,559,826
Condensed Consolidating Statements of Operations	December 31, 2015 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated (In thousands) Revenues: Oil & natural gas sales $ — $ 374,042 $ — $ — $ 374,042 Total revenues — 374,042 — — 374,042 Costs and expenses: Lease operating — 24,904 — (1 ) 24,903 Gathering, processing and transportation — 72,555 — (1 ) 72,554 Gathering, processing, and transportation - affiliate — 25,403 — — 25,403 Exploration — 8,969 — — 8,969 Taxes other than income 3,833 11,063 — — 14,896 Depreciation, depletion and amortization 4,191 184,551 — — 188,742 Incentive unit compensation expense 35,142 — — — 35,142 General and administrative 43,624 2,664 — — 46,288 Accretion of asset retirement obligations — 418 — (1 ) 417 (Gain) loss on commodity derivatives (281,250 ) — — 1 (281,249 ) (Gain) loss on sale of properties — (47 ) — — (47 ) Total costs and expenses (194,460 ) 330,480 — (2 ) 136,018 Operating income (loss) 194,460 43,562 — 2 238,024 Other income (expense): Interest expense, net (39,308 ) (88 ) — — (39,396 ) Equity earnings from subsidiaries 16,434 — — (16,434 ) — Other, net (100 ) (922 ) — — (1,022 ) Total other income (expense) (22,974 ) (1,010 ) — (16,434 ) (40,418 ) Income before income taxes 171,486 42,552 — (16,432 ) 197,606 Income tax benefit (expense) (75,838 ) (24,167 ) — — (100,005 ) Net income (loss) from continuing operations 95,648 18,385 — (16,432 ) 97,601 Discontinued Operations Income (loss) before income taxes — — (397,664 ) (2 ) (397,666 ) Income tax benefit (expense) — — 2,175 — 2,175 Net income (loss) from discontinued operations — — (395,489 ) (2 ) (395,491 ) Net income (loss) 95,648 18,385 (395,489 ) (16,434 ) (297,890 ) Net income (loss) attributable to noncontrolling interest — — 386 (393,924 ) (393,538 ) Net income (loss) attributable to Memorial Resource Development Corp. $ 95,648 $ 18,385 $ (395,875 ) $ 377,490 $ 95,648 December 31, 2014 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated (In thousands) Revenues: Oil & natural gas sales $ — $ 409,070 $ — $ — $ 409,070 Other income 5 7 — — 12 Total revenues 5 409,077 — — 409,082 Costs and expenses: Lease operating — 17,570 — — 17,570 Gathering, processing and transportation — 45,956 — — 45,956 Exploration — 13,853 — — 13,853 Taxes other than income — 12,610 — — 12,610 Depreciation, depletion and amortization 1,133 127,105 — — 128,238 Impairment of proved oil and natural gas properties — 24,576 — — 24,576 Incentive unit compensation expense 111,866 831,060 1,023 — 943,949 General and administrative 13,232 25,277 16 24 38,549 Accretion of asset retirement obligations — 533 — — 533 (Gain) loss on commodity derivatives (277,129 ) 19,395 — — (257,734 ) (Gain) loss on sale of properties — 3,167 (110 ) — 3,057 Other, net — — — (1 ) (1 ) Total costs and expenses (150,898 ) 1,121,102 929 23 971,156 Operating income (loss) 150,903 (712,025 ) (929 ) (23 ) (562,074 ) Other income (expense): Interest expense, net (19,532 ) (30,751 ) — — (50,283 ) Loss on extinguishment of debt (23,562 ) (13,686 ) — — (37,248 ) Equity earnings from subsidiaries (809,017 ) — — 809,017 — Other, net — 319 — 1 320 Total other income (expense) (852,111 ) (44,118 ) — 809,018 (87,211 ) Income before income taxes (701,208 ) (756,143 ) (929 ) 808,995 (649,285 ) Income tax benefit (expense) (83,373 ) (19,028 ) — 9 (102,392 ) Net income (loss) (784,581 ) (775,171 ) (929 ) 809,004 (751,677 ) Discontinued Operations Income (loss) before income taxes — — 114,171 22 114,193 Income tax benefit (expense) — — 1,430 (9 ) 1,421 Net income (loss) from discontinued operations — — 115,601 13 115,614 Net income (loss) (784,581 ) (775,171 ) 114,672 809,017 (636,063 ) Net income (loss) attributable to noncontrolling interest — — 32 126,756 126,788 Net income (loss) attributable to Memorial Resource Development Corp. $ (784,581 ) $ (775,171 ) $ 114,640 $ 682,261 $ (762,851 ) December 31, 2013 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Combined & Consolidated (In thousands) Revenues: Oil & natural gas sales $ — $ 202,423 $ 17,129 $ — $ 219,552 Total revenues — 202,423 17,129 — 219,552 Costs and expenses: Lease operating — 14,710 2,605 (108 ) 17,207 Gathering, processing and transportation — 17,666 — — 17,666 Exploration — 1,034 — — 1,034 Taxes other than income — 7,869 830 — 8,699 Depreciation, depletion and amortization — 61,990 8,913 — 70,903 Impairment of proved oil and natural gas properties — 128 2,400 — 2,528 Incentive unit compensation expense — 14,353 20,644 — 34,997 General and administrative — 31,674 3,616 124 35,414 Accretion of asset retirement obligations — 516 77 — 593 (Gain) loss on commodity derivatives — (3,179 ) 18 — (3,161 ) (Gain) loss on sale of properties — 6,776 (89,549 ) — (82,773 ) Other, net — — 2 — 2 Total costs and expenses — 153,537 (50,444 ) 16 103,109 Operating income (loss) — 48,886 67,573 (16 ) 116,443 Other income (expense): Interest expense, net — (24,895 ) (53 ) — (24,948 ) Equity earnings from subsidiaries — 71,222 — (71,222 ) — Other, net — 141 2 — 143 Total other income (expense) — 46,468 (51 ) (71,222 ) (24,805 ) Income before income taxes — 95,354 67,522 (71,238 ) 91,638 Income tax benefit (expense) — (164 ) (1,147 ) — (1,311 ) Net income (loss) — 95,190 66,375 (71,238 ) 90,327 Discontinued Operations Income (loss) before income taxes — — 61,297 16 61,313 Income tax benefit (expense) — — (308 ) — (308 ) Net income (loss) from discontinued operations — — 60,989 16 61,005 Net income (loss) — 95,190 127,364 (71,222 ) 151,332 Net income (loss) attributable to noncontrolling interest — — 267 49,563 49,830 Net income (loss) attributable to Memorial Resource Development Corp. $ — $ 95,190 $ 127,097 $ (120,785 ) $ 101,502
Condensed Consolidating Statements of Cash Flows	December 31, 2015 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated (In thousands) Net cash provided by continuing operations $ 45,528 $ 373,155 $ — $ (5,941 ) $ 412,742 Net cash provided (used in) by discontinued operations — (1,127 ) 216,750 5,546 221,169 Net cash provided by (used in) operating activities 45,528 372,028 216,750 (395 ) 633,911 Cash flows from investing activities: Acquisitions of oil and natural gas properties — (291,536 ) — — (291,536 ) Additions to oil and gas properties — (594,901 ) — — (594,901 ) Additions to other property and equipment (3,401 ) (452 ) — — (3,853 ) Additions to restricted investments — — — — — Other financial hybrid instruments (46,106 ) — — — (46,106 ) Investments in subsidiaries (499,336 ) — — 499,336 — Distributions from subsidiaries 78,648 — — (78,648 ) — Proceeds from the sale of oil and gas properties — 13,612 — — 13,612 Net cash used in continuing operations (470,195 ) (873,277 ) — 420,688 (922,784 ) Net cash used in discontinued operations — 63 (337,568 ) — (337,505 ) Net cash used in investing activities (470,195 ) (873,214 ) (337,568 ) 420,688 (1,260,289 ) Cash flows from financing activities: Advances on revolving credit facility 798,000 — — — 798,000 Payments on revolving credit facility (558,000 ) — — — (558,000 ) Deferred finance costs (1,498 ) — — — (1,498 ) Proceeds from MRD equity offering 242,880 — — — 242,880 Costs incurred in conjunction with MRD equity offering (4,773 ) — — — (4,773 ) Capital contributions — 497,424 — (497,424 ) — Repurchases of equity (51,197 ) — — — (51,197 ) Net cash used in continuing operations 425,412 497,424 — (497,424 ) 425,412 Net cash used in discontinued operations — — 120,447 76,736 197,183 Net cash provided by financing activities 425,412 497,424 120,447 (420,688 ) 622,595 Net change in cash and cash equivalents 745 (3,762 ) (371 ) (395 ) (3,783 ) Add: cash balance included in assets of discontinued operations at beginning of period — 2,639 970 (1,015 ) 2,594 Less: cash balance included in assets of discontinued operations at end of period — — 599 1,576 2,175 Cash and cash equivalents, beginning of period 2,241 1,123 — — 3,364 Cash and cash equivalents, end of period $ 2,986 $ — $ — $ (2,986 ) $ — December 31, 2014 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Combined & Consolidated (In thousands) Net cash provided by (used in) continuing operations $ (72,612 ) $ 299,206 $ (2,879 ) $ 1,975 $ 225,690 Net cash provided by (used in) discontinued operations — (1,716 ) 254,272 (1,975 ) 250,581 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 ) — — (93,909 ) Additions to oil and gas properties — (376,123 ) — 1 (376,122 ) Additions to other property and equipment (15,980 ) (851 ) — — (16,831 ) Investments in subsidiaries (696,489 ) — — 696,489 — Distributions from subsidiaries 15,140 74,424 — (89,564 ) — Change in restricted cash — 49,946 — — 49,946 Deposits for property acquisitions — (215 ) — — (215 ) Proceeds from the sale of oil and gas properties — — 6,700 — 6,700 Other — — (300 ) (1 ) (301 ) Net cash used in continuing operations (697,329 ) (346,728 ) 6,400 606,925 (430,732 ) Net cash used in discontinued operations — (138 ) (1,386,109 ) — (1,386,247 ) Net cash used in investing activities (697,329 ) (346,866 ) (1,379,709 ) 606,925 (1,816,979 ) Cash flows from financing activities: Advances on revolving credit facility 1,174,000 126,800 — — 1,300,800 Payments on revolving credit facility (991,000 ) (329,900 ) — — (1,320,900 ) Termination of second lien credit facility — (328,282 ) — — (328,282 ) Proceeds from the issuances of senior notes 600,000 — — — 600,000 Redemption of senior notes (351,808 ) — — — (351,808 ) Deferred finance costs (18,779 ) (61 ) — — (18,840 ) Proceeds from MRD initial public offering 408,500 — — — 408,500 Costs incurred in conjunction with initial public offering (28,373 ) — — — (28,373 ) MRD equity repurchases (161 ) — — — (161 ) Capital contributions — 686,623 — (686,623 ) — Contributions from NGP affiliates related to sale of properties — — 1,165 — 1,165 Purchase of additional interests in subsidiaries (3,292 ) — — — (3,292 ) Distribution to equity owners — (15,000 ) (2,315 ) 17,315 — Distribution to NGP affiliates related to purchase of assets — (63,389 ) (3,304 ) — (66,693 ) Distribution to noncontrolling interests — — — (376 ) (376 ) Distributions to MRD Holdco (17,207 ) (39,520 ) (3,076 ) — (59,803 ) Distribution to NGP affiliates related to sale of assets, net of cash received — (32,770 ) — — (32,770 ) Other 302 18 — — 320 Net cash used in continuing operations 772,182 4,519 (7,530 ) (669,684 ) 99,487 Net cash used in discontinued operations — — 1,107,714 61,744 1,169,458 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 ) Add: cash balance included in assets of discontinued operations at beginning of period — 4,493 21,698 — 26,191 Less: cash balance included in assets of discontinued operations at end of period — 2,639 970 (1,015 ) 2,594 Cash and cash equivalents, beginning of period — 44,126 7,404 — 51,530 Cash and cash equivalents, end of period $ 2,241 $ 1,123 $ — $ — $ 3,364 December 31, 2013 Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Combined & Consolidated (In thousands) Net cash provided by (used in) continuing operations $ — $ 92,997 $ (17,702 ) $ 13,177 $ 88,472 Net cash provided by (used in) discontinued operations — 867 201,661 (13,177 ) 189,351 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 ) — — (67,098 ) Additions to oil and gas properties — (164,850 ) (20,344 ) — (185,194 ) Additions to other property and equipment — (2,307 ) — — (2,307 ) 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 — 33,152 118,035 151,187 Net cash used in continuing operations — (70,189 ) 97,691 (180,261 ) (152,759 ) Net cash used in discontinued operations — (125 ) (214,559 ) — (214,684 ) 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 — — 174,400 Payments on revolving credit facilities — (200,500 ) — — (200,500 ) Proceeds from the issuances of senior notes — 343,000 — — 343,000 Borrowings under second lien credit facility — 325,000 — — 325,000 Deferred financing costs — (20,250 ) — (1 ) (20,251 ) Proceeds from changes in ownership interests in MEMP — 135,012 — — 135,012 Purchase of additional interests in subsidiaries — (15,135 ) — — (15,135 ) Distributions to the Funds — (732,362 ) — — (732,362 ) Distribution to equity owners — — (74,787 ) 74,787 — Distributions to noncontrolling interests — — — (7,446 ) (7,446 ) Distributions made by previous owners — (2,590 ) — — (2,590 ) Other — (129 ) — 200 71 Net cash used in continuing operations — 6,446 (74,787 ) 67,540 (801 ) Net cash used in discontinued operations — — 6,030 112,721 118,751 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 Add: cash balance included in assets of discontinued operations at beginning of period — 3,751 28,585 — 32,336 Less: cash balance included in assets of discontinued operations at end of period — 4,493 21,698 — 26,191 Cash and cash equivalents, beginning of period — 14,872 2,183 — 17,055 Cash and cash equivalents, end of period $ — $ 44,126 $ 7,404 $ — $ 51,530

Organization and Basis of Pre44

Organization and Basis of Presentation - Additional Information (Detail)	Jun. 01, 2016USD ($)Segment	Jul. 16, 2014	Jun. 18, 2014USD ($)$ / sharesshares	May 31, 2014USD ($)	Jul. 31, 2013USD ($)	Dec. 31, 2015USD ($)Segmentshares	Dec. 31, 2014USD ($)shares	Dec. 31, 2013USD ($)shares	Jun. 27, 2014USD ($)	Dec. 18, 2013USD ($)	Apr. 03, 2013USD ($)
Consolidation And Basis Of Presentation [Line Items]
Initial public offering | shares			21,500,000
Common unit price per share | $ / shares			$ 19
Proceeds from initial public offering			$ 380,200,000
Initial public offering completion date			Jun. 18, 2014
Common stock, shares issued | shares						205,293,743	193,435,414	0
Advances on revolving credit facilities						$ 798,000,000	$ 1,300,800,000	$ 174,400,000
Senior PIK Toggle Notes, Redemption date						Jul. 16, 2014
Number of reportable business segments | Segment						2
MEMP [Member]
Consolidation And Basis Of Presentation [Line Items]
Number of reportable business segments | Segment						1
Subsequent Event [Member]
Consolidation And Basis Of Presentation [Line Items]
Number of reportable business segments | Segment	1
Subsequent Event [Member] | MEMP GP, Beta Operating Company, LLC and MEMP Services LLC | MEMP [Member]
Consolidation And Basis Of Presentation [Line Items]
Proceeds from divestiture	$ 750,000
Limited Partner [Member]
Consolidation And Basis Of Presentation [Line Items]
Partnership ownership percentage						99.90%
General Partner [Member]
Consolidation And Basis Of Presentation [Line Items]
Partnership ownership percentage						0.10%
PIK Notes trustee [Member]
Consolidation And Basis Of Presentation [Line Items]
Irrevocable deposits									$ 360,000,000
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
Revolving Credit Facility [Member]
Consolidation And Basis Of Presentation [Line Items]
Revolving credit facility			$ 2,000,000,000
Advances on revolving credit facilities			614,500,000
PIK Notes [Member]
Consolidation And Basis Of Presentation [Line Items]
Aggregate principal amount			$ 350,000,000							$ 350,000,000
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 contributed by our predecessor			99.90%
Common stock, shares issued | shares			42,334,323
Membership interest percentage			0.10%
Cash consideration paid			$ 30,000,000
WildHorse Resources, LLC [Member] | Revolving Credit Facility [Member]
Consolidation And Basis Of Presentation [Line Items]
Revolving credit facility											$ 1,000,000,000
Classic [Member]
Consolidation And Basis Of Presentation [Line Items]
Ownership interest percentage contributed by our predecessor			100.00%
Classic GP[Member]
Consolidation And Basis Of Presentation [Line Items]
Ownership interest percentage contributed by our predecessor			100.00%
Black Diamond [Member]
Consolidation And Basis Of Presentation [Line Items]
Ownership interest percentage contributed by our predecessor			100.00%
Beta Operating [Member]
Consolidation And Basis Of Presentation [Line Items]
Ownership interest percentage contributed by our predecessor			100.00%
Memorial Resource Finance Corp [Member]
Consolidation And Basis Of Presentation [Line Items]
Ownership interest percentage contributed by our predecessor			100.00%
MRD Operating [Member]
Consolidation And Basis Of Presentation [Line Items]
Ownership interest percentage contributed by our predecessor			100.00%
Memorial Production Partners GP LLC [Member]
Consolidation And Basis Of Presentation [Line Items]
Ownership interest percentage contributed by our predecessor			100.00%
MEMP GP & MEMP IDRs [Member]
Consolidation And Basis Of Presentation [Line Items]
Ownership interest percentage contributed by our predecessor			50.00%
BlueStone Natural Resources Holdings, LLC [Member]
Consolidation And Basis Of Presentation [Line Items]
Sale of assets					$ 117,900,000

Organization and Basis of Pre45

Organization and Basis of Presentation - Schedule of Retrospective Adjustments to Balance Sheet (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Consolidation And Basis Of Presentation [Line Items]
Prepaid expenses and other current assets	$ 3,374	$ 11,344
Other long-term assets	4,976	3,586
Accrued liabilities (Note 2)	68,876	51,236
Long-term debt	1,012,064	770,545
Deferred tax liabilities	$ 193,733	114,599
Before Adjustment [Member]
Consolidation And Basis Of Presentation [Line Items]
Prepaid expenses and other current assets		12,999
Other long-term assets		14,126
Accrued liabilities (Note 2)		101,758
Long-term debt		783,000
Deferred tax liabilities		64,077
Adjustment Effect [Member]
Consolidation And Basis Of Presentation [Line Items]
Prepaid expenses and other current assets		(1,655)
Other long-term assets		(10,540)
Accrued liabilities (Note 2)		(50,522)
Long-term debt		(12,455)
Deferred tax liabilities		$ 50,522

Summary of Significant Accoun46

Summary of Significant Accounting Policies - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Summary Of Significant Accounting Policies [Line Items]
Capitalized exploratory drilling costs	$ 0	$ 0	$ 0
Capitalized in proved oil and natural gas properties	174,000,000	100,500,000
Impairment of proved oil and natural gas properties	0	24,576,000	2,528,000
Impairment of unproved properties	0	0	0
Amortization expense, including write-offs of debt issuance costs	2,823,000	3,209,000	$ 2,330,000
Capitalized interest	$ 5,400,000	$ 4,500,000
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 Accoun47

Summary of Significant Accounting Policies - Schedule of Oil and Natural Gas Properties (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Accounting Policies [Abstract]
Proved oil and natural gas properties	$ 1,740,530	$ 1,269,605
Support equipment and facilities	4,719
Unproved oil and natural gas properties	414,759	47,497
Total oil and natural gas properties	$ 2,160,008	$ 1,317,102

Summary of Significant Accoun48

Summary of Significant Accounting Policies - Individual Customers Each Accounted for 10% or More of Total Reported Revenues (Detail) - Sales Revenue, Net [Member] - Customer Concentration Risk [Member]	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Energy Transfer Equity, LP. and subsidiaries [Member]
Entity Wide Revenue Major Customer [Line Items]
Individual customers each accounted for 10% or more of total reported revenues	56.00%	85.00%	86.00%
Plains Marketing, L.P.[Member]
Entity Wide Revenue Major Customer [Line Items]
Individual customers each accounted for 10% or more of total reported revenues	11.00%

Summary of Significant Accoun49

Summary of Significant Accounting Policies - Schedule of Accrued Liabilities (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Accounting Policies [Abstract]
Accrued capital expenditures	$ 40,197	$ 44,308
Accrued interest payable	17,657	124
Other accrued liabilities	11,022	6,804
Accrued liabilities	$ 68,876	$ 51,236

Summary of Significant Accoun50

Summary of Significant Accounting Policies - Schedule of Supplemental Cash Flow (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Supplemental cash flows:
Cash paid for interest, net of capitalized interest	$ 18,815	$ 67,023	$ 18,541
Cash paid for taxes	8,160	687
Noncash investing and financing activities:
Increase (decrease) in capital expenditures in payables and accrued liabilities	(4,111)	18,012	22,238
(Increase) decrease in accounts receivable related to acquisitions and divestitures	852	(852)
Assumptions of asset retirement obligations related to properties acquired or drilled	$ 1,348	786	$ 2,111
Repurchase of equity under repurchase program		$ 2,053

Discontinued Operations - Sched

Discontinued Operations - Schedule of Reconciliation of Carrying Amounts of Major Classes of Assets and Liabilities Included as Part of Discontinued Operations (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Current assets:
Cash and cash equivalents	$ 2,175	$ 2,594	$ 26,191	$ 32,336
Short-term derivative instruments	227,991	131,471
Total current assets	345,541	321,536
Long-term derivative instruments	91,292	123,567
Current liabilities:
Accounts payable - affiliates	5,016	160
Revenues payable	34,026	21,807
Total current liabilities	91,779	159,946
Long-term debt	1,012,064	770,545
Asset retirement obligations	10,079	9,829	$ 10,243
MEMP GP, Beta Operating Company, LLC and MEMP Services LLC | Discontinued Operations [Member]
Current assets:
Cash and cash equivalents	2,175	2,594
Accounts receivable	61,403	98,498
Short-term derivative instruments	272,320	208,585
Prepaid expenses and other current assets	9,643	11,859
Total current assets	345,541	321,536
Property and equipment, net	1,946,937	2,471,011
Long-term derivative instruments	461,809	311,802
Restricted investments	152,631	77,361
Other long-term assets	5,053	5,062
Total assets	2,911,971	3,186,772
Current liabilities:
Accounts payable	8,792	24,813
Accounts payable - affiliates	193	464
Revenues payable	27,021	35,545
Accrued liabilities	52,923	95,835
Short-term derivative instruments	2,850	3,289
Total current liabilities	91,779	159,946
Long-term debt	2,000,579	1,574,147
Asset retirement obligations	162,989	112,702
Long-term derivative instruments	1,441
Deferred tax liabilities	2,094	32,347
Total liabilities	$ 2,258,882	$ 1,879,142

Discontinued Operations - Sch52

Discontinued Operations - Schedule of Reconciliation of Major Line Items Constituting Pretax Profit (Loss) of Discontinued Operations to After Tax Profit (Loss) of Discontinued Operations (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenues:
Oil & natural gas sales		$ 374,042	$ 409,070	$ 219,552
Other revenues			12
Costs and expenses:
Lease operating		24,903	17,570	17,207
Gathering, processing, and transportation		72,554	45,956	17,666
Exploration		8,969	13,853	1,034
Taxes other than income		14,896	12,610	8,699
Impairment of proved oil and natural gas properties		0	24,576	2,528
Accretion of asset retirement obligations		417	533	593
(Gain) loss on commodity derivative instruments		(281,249)	(257,734)	(3,161)
(Gain) loss on sale of properties		(47)	3,057	(82,773)
Other, net			(1)	2
Total costs and expenses		136,018	971,156	103,109
Other income (expense):
Interest expense, net		(39,396)	(50,283)	(24,948)
Other, net		(1,022)	320	143
Total other income (expense)		(40,418)	(87,211)	(24,805)
MEMP GP, Beta Operating Company, LLC and MEMP Services LLC | Discontinued Operations [Member]
Revenues:
Oil & natural gas sales		355,422	561,677	391,440
Other revenues		2,725	4,366	3,075
Total revenues		358,147	566,043	394,515
Costs and expenses:
Lease operating		168,199	143,733	94,591
Gathering, processing, and transportation		34,939	31,892	25,055
Exploration		2,317	2,750	1,322
Taxes other than income		25,828	33,141	18,447
Depreciation, depletion, and amortization		195,814	185,955	113,814
Impairment of proved oil and natural gas properties		616,784	407,540	4,072
General and administrative	[1]	56,671	49,124	54,947
Accretion of asset retirement obligations		7,125	5,773	4,988
(Gain) loss on commodity derivative instruments		(462,890)	(492,254)	(26,133)
(Gain) loss on sale of properties		(2,998)		(2,848)
Other, net		(665)	(11)	647
Total costs and expenses		641,124	367,643	288,902
Operating income (loss)		(282,977)	198,400	105,613
Other income (expense):
Interest expense, net		(114,732)	(83,550)	(44,302)
Other, net		43	(657)	2
Total other income (expense)		(114,689)	(84,207)	(44,300)
Pretax profit (loss) of discontinued operations		(397,666)	114,193	61,313
Income tax benefit (expense)		2,175	1,421	(308)
Net income (loss) from discontinued operations		$ (395,491)	$ 115,614	$ 61,005
[1]	Includes $32.3 million, $24.4 million and $9.4 million for the years ended December 31, 2015, 2014 and 2013 that was allocated to discontinued operations under an omnibus agreement. This omnibus agreement terminated on June 1, 2016. We entered into a transition services agreement with MEMP to manage post-closing separation costs and activities.

Discontinued Operations - Sch53

Discontinued Operations - Schedule of Reconciliation of Major Line Items Constituting Pretax Profit (Loss) of Discontinued Operations to After Tax Profit (Loss) of Discontinued Operations (Parenthetical) (Detail) - Omnibus Agreement [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Statement Balance Sheet And Additional Disclosures By Disposal Groups Including Discontinued Operations [Line Items]
General and administrative	$ 32.3	$ 24.4	$ 9.4
Agreement termination date	Jun. 1, 2016

Acquisitions and Divestitures -

Acquisitions and Divestitures - Transaction Related Costs (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
General and administrative expense [Member]
Business Acquisition [Line Items]
For the Year Ended December 31,	$ 1,974	$ 2,305	$ 1,584

Acquisitions and Divestitures55

Acquisitions and Divestitures - Additional Information (Detail) - USD ($) $ in Thousands	Oct. 22, 2015	Jun. 01, 2015	Apr. 17, 2015	Dec. 30, 2014	May 09, 2014	May 10, 2013	Apr. 30, 2013	Dec. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Business Acquisition And Divestiture [Line Items]
Purchase price to unproved oil and natural gas properties									$ 360,353	$ 24,310	$ 19,975
Proceeds from the sale of oil and natural gas properties									$ 13,612	$ 6,700	151,187
Terryville Acquisition [Member]
Business Acquisition And Divestiture [Line Items]
Payments to acquire oil and gas properties and leases				$ 71,900				$ 24,000
WildHorse Resources, LLC [Member]
Business Acquisition And Divestiture [Line Items]
Payments to acquire oil and gas properties and leases							$ 67,100
Black Diamond [Member]
Business Acquisition And Divestiture [Line Items]
Proceeds from divestitures						$ 33,000
Gain (loss) on sale of oil and gas properties						(6,800)
Net book value of oil and gas properties						$ 39,800
BlueStone Natural Resources Holdings, LLC [Member]
Business Acquisition And Divestiture [Line Items]
Gain (loss) on sale of oil and gas properties											89,500
Proceeds from the sale of oil and natural gas properties											$ 117,900
Rockies Divestiture [Member]
Business Acquisition And Divestiture [Line Items]
Proceeds from divestitures			$ 13,600
Gain (loss) on sale of oil and gas properties			$ 100
North Louisiana [Member]
Business Acquisition And Divestiture [Line Items]
Purchase price to unproved oil and natural gas properties	$ 281,900	$ 4,000
Payments to acquire oil and gas properties and leases	$ 284,300
Northern Oklahoma [Member]
Business Acquisition And Divestiture [Line Items]
Proceeds from divestitures					$ 7,600
Gain (loss) on sale of oil and gas properties					$ (3,200)

Acquisitions and Divestitures56

Acquisitions and Divestitures - Summary of Fair Value Assessment of Assets Acquired and Liabilities Assumed (Detail) - Louisiana [Member] - USD ($) $ in Thousands	Dec. 30, 2014	Apr. 30, 2013
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

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] - Commodity derivatives [Member] - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Assets:
Fair value of derivative asset	$ 319,763	$ 280,846
Liabilities:
Fair value of derivative liability	480	25,808
Quoted Prices in Active Market (Level 1) [Member]
Assets:
Fair value of derivative asset	0	0
Liabilities:
Fair value of derivative liability	0	0
Significant Other Observable Inputs (Level 2) [Member]
Assets:
Fair value of derivative asset	319,763	280,846
Liabilities:
Fair value of derivative liability	480	25,808
Significant Unobservable Inputs (Level 3) [Member]
Assets:
Fair value of derivative asset	0	0
Liabilities:
Fair value of derivative liability	$ 0	$ 0

Fair Value Measurements of Fi58

Fair Value Measurements of Financial Instruments - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Fair Value Disclosures [Abstract]
Impairment of proved oil and natural gas properties	$ 0	$ 24,576	$ 2,528

Risk Management and Derivativ59

Risk Management and Derivative and Other Financial Instruments - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 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	$ 196,300,000
Effect netting arrangements, counterparty exposure	169,100,000
Derivative asset	365,400,000
Deferred premiums	8,000,000
Cash settlement receipt	92,300,000	$ 6,100,000
Other financial assets	46,106,000
Cash collateral received or pledged	0
Interest rate swaps [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Aggregate termination amount paid to counterparties			$ 700,000
Single Counterparty [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Effect netting arrangements, counterparty exposure	$ 86,800,000

Risk Management and Derivativ60

Risk Management and Derivative and Other Financial Instruments - Schedule of Open Commodity Positions Excluding Embedded Derivatives (Detail) MMBTU in Thousands	12 Months Ended
	Dec. 31, 2015MMBTU$ / MMBTUbbl
Natural Gas Derivative Contracts [Member] | 2016 [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	2,570
Weighted-average fixed price	4.09
Natural Gas Derivative Contracts [Member] | 2016 [Member] | Collar contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	1,100
Weighted-average floor price	4
Weighted-average ceiling price	4.71
Natural Gas Derivative Contracts [Member] | 2016 [Member] | Put Option [Member] | Purchased [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	6,000
Weighted-average strike price	3.51
Weighted-average deferred premium paid	(0.34)
Natural Gas Derivative Contracts [Member] | 2016 [Member] | TGT Z1 basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	1,120
Natural Gas Derivative Contracts [Member] | 2016 [Member] | TGT Z1 basis swaps [Member] | Henry Hub [Member]
Derivative [Line Items]
Spread - Henry Hub	(0.10)
Natural Gas Derivative Contracts [Member] | 2017 [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	1,770
Weighted-average fixed price	4.24
Natural Gas Derivative Contracts [Member] | 2017 [Member] | Collar contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	1,050
Weighted-average floor price	4
Weighted-average ceiling price	5.06
Natural Gas Derivative Contracts [Member] | 2017 [Member] | Put Option [Member] | Purchased [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	5,350
Weighted-average strike price	3.48
Weighted-average deferred premium paid	(0.32)
Natural Gas Derivative Contracts [Member] | 2017 [Member] | TGT Z1 basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	200
Natural Gas Derivative Contracts [Member] | 2017 [Member] | TGT Z1 basis swaps [Member] | Henry Hub [Member]
Derivative [Line Items]
Spread - Henry Hub	(0.08)
Crude Oil Derivative Contracts [Member] | 2016 [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price	83.58
Average Monthly Volume (Bbls) | bbl	35,583
Crude Oil Derivative Contracts [Member] | 2016 [Member] | Collar contracts [Member]
Derivative [Line Items]
Weighted-average floor price	80
Weighted-average ceiling price	99.70
Average Monthly Volume (Bbls) | bbl	27,000
Crude Oil Derivative Contracts [Member] | 2017 [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price	84.70
Average Monthly Volume (Bbls) | bbl	28,000
Crude Oil Derivative Contracts [Member] | 2017 [Member] | Collar contracts [Member]
Derivative [Line Items]
Weighted-average floor price	0
Weighted-average ceiling price	0
Average Monthly Volume (Bbls) | bbl	0
NGL Derivative Contracts [Member] | 2016 [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price	39.68
Average Monthly Volume (Bbls) | bbl	353,399
NGL Derivative Contracts [Member] | 2017 [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price	0
Average Monthly Volume (Bbls) | bbl	0

Risk Management and Derivativ61

Risk Management and Derivative and Other Financial Instruments - Schedule of Open Embedded Derivative Positions (Detail) - 2016 [Member] - Fixed price swap contracts [Member]	12 Months Ended
	Dec. 31, 2015$ / bblbbl
Oil Hybrid Contracts [Member]
Derivative [Line Items]
Average Monthly Volume (Bbls) | bbl	27,080
Weighted-average fixed price	46.51
Initial net investment price	62.16
Total contract swap price	108.67
NGL Hybrid Contracts [Member]
Derivative [Line Items]
Average Monthly Volume (Bbls) | bbl	83,101
Weighted-average fixed price	15.84
Initial net investment price	25.98
Total contract swap price	41.82

Risk Management and Derivativ62

Risk Management and Derivative and Other Financial Instruments - Summary of Gross Fair Value and Net Recorded Fair Value of Derivative Instruments by Appropriate Balance Sheet Classification (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Net recorded fair value	$ 227,991	$ 131,471
Asset Derivatives, Net recorded fair value	91,292	123,567
Short-term derivative instruments [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Netting arrangements	(358)	(21,555)
Asset Derivatives, Net recorded fair value	227,991	131,471
Liability Derivatives, Netting arrangements	(358)	(21,555)
Liability Derivatives, Net recorded fair value	0
Short-term derivative instruments [Member] | Commodity derivatives [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	228,349	153,026
Liability Derivatives, Gross fair value	358	21,555
Long-term derivative instruments [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Netting arrangements	(122)	(4,253)
Asset Derivatives, Net recorded fair value	91,292	123,567
Liability Derivatives, Netting arrangements	(122)	(4,253)
Liability Derivatives, Net recorded fair value	0
Long-term derivative instruments [Member] | Commodity derivatives [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	91,414	127,820
Liability Derivatives, Gross fair value	$ 122	$ 4,253

Risk Management and Derivativ63

Risk Management and Derivative and Other Financial Instruments - Schedule of Gains and Losses Related to Derivative Instruments (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Gain (Loss) on Derivative Instruments, Net, Pretax [Abstract]
(Gain) loss on commodity derivative instruments	$ (281,249)	$ (257,734)	$ (3,161)
Interest expense, net	39,396	50,283	24,948
Commodity derivative contracts [Member]
Gain (Loss) on Derivative Instruments, Net, Pretax [Abstract]
(Gain) loss on commodity derivative instruments	(281,249)	(257,734)	(3,161)
Interest rate derivatives [Member]
Gain (Loss) on Derivative Instruments, Net, Pretax [Abstract]
Interest expense, net	$ 0	$ 296	$ 309

Asset Retirement Obligations -

Asset Retirement Obligations - Summary of Changes in Asset Retirement Obligations (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Asset Retirement Obligation Roll Forward Analysis Roll Forward
Asset retirement obligations at beginning of period	$ 9,829	$ 10,333	$ 9,349
Liabilities added from acquisitions or drilling	1,348	786	2,111
Liabilities settled			(150)
Revision of estimates	927	(97)	195
Liabilities removed upon sale of wells	(2,442)	(1,726)	(1,765)
Accretion expense	417	533	593
Asset retirement obligations at end of period	10,079	9,829	10,333
Less: Current portion			90
Asset retirement obligations - long-term portion	$ 10,079	$ 9,829	$ 10,243

Long Term Debt - Debt Obligatio

Long Term Debt - Debt Obligations (Detail) - USD ($) $ in Thousands		Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Unamortized debt issuance costs		$ (15,912)	$ (16,740)
Total long-term debt		1,012,064	770,545
Senior Notes [Member]
Debt Instrument [Line Items]
Unamortized debt issuance costs		(10,936)	(12,455)
2.0 Billion Revolving Credit Facility Due June 2019 [Member]
Debt Instrument [Line Items]
Credit facility		423,000	183,000
Unamortized debt issuance costs		(4,976)	(4,285)
5.875% Senior Unsecured Notes Due July 2022 [Member]
Debt Instrument [Line Items]
Senior Notes	[1],[2]	$ 600,000	$ 600,000
[1]	(1)The estimated fair value of this fixed-rate debt was $525.0 million and $534.0 million at December 31, 2015 and 2014, respectively.
[2]	(2)The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.

Long Term Debt - Debt Obligat66

Long Term Debt - Debt Obligations (Parenthetical) (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
2.0 Billion Revolving Credit Facility Due June 2019 [Member]
Debt Instrument [Line Items]
Revolving credit facility	$ 2,000,000,000
Maturity date	Jun. 18, 2019
5.875% Senior Unsecured Notes Due July 2022 [Member]
Debt Instrument [Line Items]
Maturity date	Jul. 1, 2022
Debt interest rate	5.875%
Estimated fair value of fixed rate debt	$ 525,000,000	$ 534,000,000

Long Term Debt - Borrowing Base

Long Term Debt - Borrowing Base Credit Facility (Detail)	Dec. 31, 2015USD ($)
2.0 Billion Revolving Credit Facility Due June 2019 [Member]
Line Of Credit Facility [Line Items]
Borrowing base	$ 1,000,000

Long Term Debt - Borrowing Ba68

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

Long Term Debt - Revolving Cred

Long Term Debt - Revolving Credit Facility - Additional Information (Detail) - Revolving Credit Facility [Member] - USD ($)	Jun. 18, 2014	Dec. 31, 2015
Debt Obligations [Line Items]
Revolving credit facility expiration term	5 years
Line of credit facility, aggregate maximum borrowing amount	$ 2,000,000,000
Optional Base Rate | Federal Funds Effective Rate [Member]
Debt Obligations [Line Items]
Lien percentage of assets for credit facility		80.00%
Line of credit, additional margin rate		0.50%
Line of credit, adjusted description		The one-month adjusted LIBOR plus 1.0% (adjusted upwards, if necessary, to the next 1/100th of 1%)
Range 1 [Member] | Alternative Base Rate
Debt Obligations [Line Items]
Line of credit, additional margin rate		0.50%
Range 1 [Member] | London Interbank Offered Rate (LIBOR)
Debt Obligations [Line Items]
Line of credit, additional margin rate		1.50%
Range 2 [Member] | Alternative Base Rate
Debt Obligations [Line Items]
Line of credit, additional margin rate		1.50%
Range 2 [Member] | London Interbank Offered Rate (LIBOR)
Debt Obligations [Line Items]
Line of credit, additional margin rate		2.50%
Minimum [Member]
Debt Obligations [Line Items]
Percentage of revolving unused commitment fee		0.375%
Debt instrument interest coverage ratio		2.50%
Debt instrument, current asset to current liabilities ratio		1.00%
Maximum [Member]
Debt Obligations [Line Items]
Percentage of revolving unused commitment fee		0.50%

Long Term Debt - MRD 5.875% Sen

Long Term Debt - MRD 5.875% Senior Unsecured Notes Offering - Additional Information (Detail) - 5.875% Senior Unsecured Notes ("MRD Senior Notes") [Member] - USD ($) $ in Millions	Jun. 01, 2016	Jul. 10, 2014
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%
Subsequent Event [Member]
Debt Obligations [Line Items]
Percentage of ownership in guarantor subsidiaries as of effective date	100.00%

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	Jun. 27, 2014	Jun. 18, 2014
Debt Obligations [Line Items]
Payment of distribution to funds				$ 732,362
Extinguishment loss			$ 37,248
PIK Notes [Member]
Debt Obligations [Line Items]
Aggregate principal amount		$ 350,000				$ 350,000
Percentage of PIK toggle notes issued at par		98.00%
Cash reserve for payment of interest on notes		$ 50,000
Payment of distribution to funds		$ 210,000
Debt redemption price percentage	102.00%
Irrevocable deposits					$ 360,000
Extinguishment loss			$ 23,600

Long Term Debt - WildHorse Reso

Long Term Debt - WildHorse Resources Revolving Credit Facility and Second Lien Facility - Additional Information (Detail) - USD ($)	Jun. 13, 2013	Apr. 03, 2013	Dec. 31, 2014	Dec. 31, 2013	Jun. 18, 2014
Debt Obligations [Line Items]
Cash distribution paid				$ 732,362,000
Loss on extinguishment of debt			$ 37,248,000
Revolving Credit Facility [Member]
Debt Obligations [Line Items]
Line of credit facility, aggregate maximum borrowing amount					$ 2,000,000,000
Revolving Credit Facility [Member] | WildHorse Resources, LLC [Member]
Debt Obligations [Line Items]
Line of credit facility, aggregate maximum borrowing amount		$ 1,000,000,000
Line of credit, minimum collateral percentage		80.00%
Revolving Credit Facility [Member] | WildHorse Resources, LLC [Member] | Second Lien Term Loan [Member]
Debt Obligations [Line Items]
Line of credit facility, aggregate maximum borrowing amount	$ 325,000,000
Line of credit, minimum collateral percentage	80.00%
Cash distribution paid	$ 225,000,000
Loss on extinguishment of debt			$ 13,700,000
Revolving Credit Facility [Member] | WildHorse Resources, LLC [Member] | Second Lien Term Loan [Member] | Alternative Base Rate
Debt Obligations [Line Items]
Debt instrument interest rate	5.25%
Revolving Credit Facility [Member] | WildHorse Resources, LLC [Member] | Second Lien Term Loan [Member] | London Interbank Offered Rate (LIBOR)
Debt Obligations [Line Items]
Debt instrument interest rate	6.25%

Long Term Debt - Summary of Wei

Long Term Debt - Summary of Weighted-Average Interest Rates Paid On Variable-Rate Debt Obligations (Detail)	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
2.0 Billion Revolving Credit Facility Due June 2019 [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates	1.92%	1.99%
WildHorse Resources, LLC [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates		4.04%	2.30%
WildHorse Resources second lien [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates		6.44%	7.60%
Black Diamond [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates			3.97%

Long Term Debt - Summary of Una

Long Term Debt - Summary of Unamortized Deferred Financing Costs Associated with Debt Obligations (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Unamortized deferred financing costs	$ 15,912	$ 16,740
2.0 Billion Revolving Credit Facility Due June 2019 [Member]
Debt Instrument [Line Items]
Unamortized deferred financing costs	4,976	4,285
Senior Notes [Member]
Debt Instrument [Line Items]
Unamortized deferred financing costs	$ 10,936	$ 12,455

Stockholders' Equity and Nonc75

Stockholders' Equity and Noncontrolling Interests - Additional Information (Detail) - USD ($)	Sep. 25, 2015	Jun. 18, 2014	Apr. 01, 2013	Mar. 16, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Apr. 30, 2015	Dec. 31, 2012
Stockholders Equity Note Disclosure [Line Items]
Common stock, shares authorized					600,000,000	600,000,000
Common stock, par value					$ 0.01	$ 0.01
Shares of common stock issued		21,500,000
Net proceeds from issuance of common stock	$ 238,100,000
Stock repurchase program, authorized amount						$ 50,000,000		$ 50,000,000
Stock repurchased and retired during period, shares				2,764,887	0	123,797
Payments for repurchase of common stock				$ 47,800,000	$ 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
Noncontrolling interests					$ 645,094,000	$ 1,120,554,000
Fair value consideration paid						3,292,000	$ 15,135,000
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	$ 3,300,000
Common Stock [Member]
Stockholders Equity Note Disclosure [Line Items]
Shares of common stock issued	13,800,000				13,800,000	192,500,000
Stock repurchased and retired during period, shares					2,764,887	123,797
Payments for repurchase of common stock					$ 28,000	$ 1,000
Noncontrolling interests							$ 0		$ 0
Common Stock [Member] | Over-Allotment [Member]
Stockholders Equity Note Disclosure [Line Items]
Shares of common stock issued	1,800,000

Stockholders' Equity and Nonc76

Stockholders' Equity and Noncontrolling Interests - Summary of Changes In Common Shares Issued (Detail) - shares	Sep. 25, 2015	Jun. 18, 2014	Mar. 16, 2015	Dec. 31, 2015	Dec. 31, 2014
Class of Stock [Line Items]
Beginning Balance			193,435,414	193,435,414	0
Shares of common stock issued		21,500,000
Shares of common stock repurchased			(2,764,887)	0	(123,797)
Ending Balance				205,293,743	193,435,414
Common Stock [Member]
Class of Stock [Line Items]
Shares of common stock issued	13,800,000			13,800,000	192,500,000
Shares of common stock repurchased				(2,764,887)	(123,797)
Restricted common shares issued (Note 11)				938,558	1,068,422
Restricted common shares repurchased				(60,773)
Restricted common shares forfeited				(54,569)	(9,211)

Stockholders' Equity and Nonc77

Stockholders' Equity and Noncontrolling Interests - Summary of Changes In Common Shares Issued (Parenthetical) (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Statement Of Stockholders Equity [Abstract]
Payments remitted for employees tax obligations	$ 1.2

Earnings per share - Summary of

Earnings per share - Summary of Calculation of Earnings (Loss) Per Share (Detail) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands		3 Months Ended							12 Months Ended
		Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
Numerator:
Net income (loss) from continuing operations available to common stockholders		$ 20,277	$ 56,051	$ (26,702)	$ 45,615	$ 166,884	$ 9,928	$ (961,707)	$ 95,241		$ (784,895)
Net income (loss) from discontinued operations available to common stockholders									$ (327)		$ 314
Denominator:
Weighted average common shares outstanding									193,698		192,498
Incremental treasury stock method shares	[1]								469		203
Basic EPS from continuing operations		$ 0.10	$ 0.29	$ (0.14)	$ 0.24	$ 0.87	$ 0.05	$ (5)	$ 0.49		$ (4.08)
Diluted EPS from continuing operations		0.10	0.29	(0.14)	0.24	0.87	0.05	(5)	0.49	[1]	(4.08)	[1]
Basic EPS from discontinued operations		0.10	0.29	(0.14)	0.24	0.87	0.05	(5)	0		0		$ 0
Diluted EPS from discontinued operations		$ 0.10	$ 0.29	$ (0.14)	$ 0.24	$ 0.87	$ 0.05	$ (5)	$ 0	[1]	$ 0	[1]
[1]	The Company determines the more dilutive of either the two-class method or the treasury stock method for diluted EPS. The two-class method was more dilutive for each period presented.

Long-Term Incentive Plans - Add

Long-Term Incentive Plans - Additional Information (Detail) - USD ($) $ in Millions	Jan. 08, 2016	Jun. 18, 2014	Dec. 31, 2015
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of common shares that may be delivered			19,250,000
Vesting period of award			3 years
Unrecognized compensation cost			$ 25.1
Unrecognized compensation cost weighted-average period			2 years 5 months 1 day
Restricted Stock [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period of award		4 years
Aggregate award of restricted stock issued to employees and each independent director		1,052,633
Director [Member] | Restricted Stock [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period of award		1 year
Aggregate award of restricted stock issued to employees and each independent director		5,263
Director [Member] | Restricted Stock [Member] | Subsequent Event [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period of award	1 year
Aggregate award of restricted stock issued to employees and each independent director	8,023

Long-Term Incentive Plans - Sum

Long-Term Incentive Plans - Summary of Information Regarding Restricted Common Unit Awards (Detail) - Restricted Stock [Member] - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Restricted common shares outstanding, Number of Shares, Beginning Balance	1,059,211
Granted, Number of Shares	938,558	1,068,422
Forfeited, Number of Shares	(54,569)	(9,211)
Vested, Number of Shares	(274,355)
Restricted common shares outstanding, Number of Shares, Ending Balance	1,668,845	1,059,211
Restricted common shares outstanding, Weighted-Average Grant Date Fair Value Per Shares, Beginning Balance	$ 19
Granted, Weighted-Average Grant Date Fair Value Per Shares	18.80	$ 19
Forfeited, Weighted-Average Grant Date Fair Value Per Shares	18.83	19
Vested, Weighted-Average Grant Date Fair Value Per Shares	19
Restricted common shares outstanding, Weighted-Average Grant Date Fair Value Per Shares, Ending Balance	$ 18.89	$ 19

Long-Term Incentive Plans - S81

Long-Term Incentive Plans - Summary of Information Regarding Restricted Common Unit Awards (Parenthetical) (Detail) - Restricted Stock [Member] - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Aggregate grant date fair value	$ 17.6	$ 20.3
Granted, Weighted-Average Grant Date Fair Value Per Shares	$ 18.80	$ 19
Minimum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted, Weighted-Average Grant Date Fair Value Per Shares	17.58
Maximum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted, Weighted-Average Grant Date Fair Value Per Shares	$ 18.91

Long-Term Incentive Plans - S82

Long-Term Incentive Plans - Summary of Amount of Compensation Expense Recognized (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)
Restricted Stock [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Amortization of equity awards	$ 8,788

Incentive Units - Additional In

Incentive Units - Additional Information (Detail) - USD ($) $ in Thousands	Apr. 01, 2013	Dec. 31, 2013	Nov. 30, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Jun. 18, 2014
Equity Incentive Plan [Line Items]
Exchange of incentive units		0		205,293,743	193,435,414	0
Carrying amount of the noncontrolling interest				$ 645,094	$ 1,120,554
Fair value of consideration paid for noncontrolling interests					3,292	$ 15,135
Remaining expected life				2 years 5 months 1 day
MRD Holdco LLC [Member]
Equity Incentive Plan [Line Items]
The number of incentive units authorized by governing documents				1,000
MRD Holdco LLC [Member] | Exchanged Incentive Units [Member]
Equity Incentive Plan [Line Items]
Compensation expense				$ 35,200	111,900
Incentive units granted in an exchange for cancelled predecessor awards				930
Unrecognized compensation expense				$ 58,800
Remaining expected life				1 year 5 months 1 day
MRD Holdco LLC [Member] | Subsequent Incentive Units [Member]
Equity Incentive Plan [Line Items]
Subsequent incentive units				70
BlueStone Natural Resources Holdings, LLC [Member]
Equity Incentive Plan [Line Items]
Compensation expense					1,000	20,700
BlueStone Natural Resources Holdings, LLC [Member] | Special Tier and Tier I Unit Holders [Member]
Equity Incentive Plan [Line Items]
Percentage of future distributions incentive unit holders are entitled to after payout has been achieved				16.50%
Tanos Energy LLC [Member]
Equity Incentive Plan [Line Items]
Percentage of ownership interest sold to company	1.066%
Compensation expense as component of discontinued operations						$ 5,800
Black Diamond, Classic GP and Classic [Member]
Equity Incentive Plan [Line Items]
Compensation expense as component of discontinued operations			$ 8,300
Compensation expense			$ 12,600
WildHorse Resources, LLC [Member]
Equity Incentive Plan [Line Items]
Compensation expense		$ 10,000			831,100
Percentage of interest contributed former management members							0.10%
Exchange of incentive units							42,334,323
Cash consideration paid to certain former management members							$ 30,000
Carrying amount of the noncontrolling interest							$ 400
Fair value of consideration paid for noncontrolling interests				$ 3,300	3,300
Cash component of incentive unit compensation expense					26,700
Incentive units exchanges for shares of our common stock					$ 804,400
Minimum [Member]
Equity Incentive Plan [Line Items]
Ranging of distributions for incentive units				10.00%
Maximum [Member]
Equity Incentive Plan [Line Items]
Ranging of distributions for incentive units				31.50%

Incentive Units - Fair Value of

Incentive Units - Fair Value of Incentive Units Estimated (Detail)	12 Months Ended
	Dec. 31, 2015
Exchanged Incentive Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Dividend yield	0.00%
Expected volatility	51.30%
Risk-free rate	0.82%
Expected life (years)	1 year 5 months 1 day
Subsequent Incentive Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Dividend yield	0.00%
Expected volatility	51.30%
Risk-free rate	0.82%
Expected life (years)	1 year 5 months 1 day

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Detail)

Nov. 02, 2015USD ($)

Jul. 01, 2015$ / bbl

May 01, 2014$ / MMBTU$ / bbl

Mar. 28, 2014USD ($)

Mar. 10, 2014USD ($)

Nov. 01, 2011MMBTU / d

Nov. 30, 2015USD ($)

Apr. 30, 2013USD ($)

Dec. 31, 2015USD ($)

Dec. 31, 2014USD ($)

Dec. 31, 2013USD ($)

Dec. 31, 2010USD ($)

Feb. 28, 2014USD ($)

Oct. 01, 2013USD ($)

Related Party Transaction [Line Items]

Cash received

$ 19,800,000

Related party transaction voting agreement description

The voting agreement also provides MRD Holdco with the right to designate up to three nominees to the Board, provided that such number of nominees shall be reduced to two, one and zero if the Funds and their affiliates collectively own less than 35%, 15%, and 5% respectively, of the outstanding shares of our common stock.

NGPCIF [Member]

Related Party Transaction [Line Items]

Net Profits Interest Sold to NGP

3.125%

Cash received

$ 19,500,000

Fixed overhead cost per month

$ 20,000

Business acquisition common control purchase price

$ 63,400,000

Date of acquisition common control

Feb. 28, 2014

Cinco Group [Member]

Related Party Transaction [Line Items]

Business acquisition common control purchase price

$ 603,000,000

Cinco Group [Member] | Advisory Fees [Member]

Related Party Transaction [Line Items]

Expenses incurred with related parties

300,000

Gas Gathering Agreement [Member]

Related Party Transaction [Line Items]

Primary term of gas agreement

15 years

Extension term of gas agreement

1 year

Gas Transportation Agreement [Member]

Related Party Transaction [Line Items]

Primary term of gas agreement

15 years

Extension term of gas agreement

1 year

Adjustments [Member]

Related Party Transaction [Line Items]

Cash received

19,900,000

Adjustments [Member] | NGPCIF [Member]

Related Party Transaction [Line Items]

Cash received

$ 19,100,000

Cretic Energy Services, LLC [Member]

Related Party Transaction [Line Items]

Drilling and completion expenses

$ 8,500,000

Multi-Shot, LLC [Member]

Related Party Transaction [Line Items]

Drilling and completion expenses

2,300,000

Drilling and completion expenses attributable to discontinued operations

300,000

Oil And Gas Production [Member]

Related Party Transaction [Line Items]

Net Profits Interest Sold to NGP

23.50%

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

Related Party Transaction [Line Items]

Net Profits Interest Sold to NGP

6.25%

Non Producing Wellbore [Member] | Net Profits Interest Sold To Affiliate NGPCIF [Member]

Related Party Transaction [Line Items]

Net Profits Interest Sold to NGP

10.00%

WildHorse Resources, LLC [Member]

Related Party Transaction [Line Items]

Cash received from related party

4,400,000

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

Related Party Transaction [Line Items]

Payment to related party

2,600,000

Payable to related party

200,000

NGP Controlled Entity [Member] | Discontinued Operations [Member]

Related Party Transaction [Line Items]

Proceeds from divestitures

$ 2,000,000

Natural Gas Partners [Member]

Related Party Transaction [Line Items]

Proceeds from divestitures

$ 900,000

Gain (loss) on sale of oil and gas properties

$ 700,000

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

Related Party Transaction [Line Items]

Business acquisition common control purchase price

$ 507,100,000

BlueStone Natural Resources Holdings, LLC [Member]

Related Party Transaction [Line Items]

Gain (loss) on sale of oil and gas properties

$ 500,000

Total cash consideration

1,200,000

Gain recognized as contribution

$ 500,000

Propel Energy [Member]

Related Party Transaction [Line Items]

Cash received

$ 3,300,000

WHR Management Company [Member]

Related Party Transaction [Line Items]

Payable to related party

2,400,000

Management fee per month

$ 1,000,000

MEMP [Member]

Related Party Transaction [Line Items]

Payable to related party

800,000

MRD Midstream LLC [Member]

Related Party Transaction [Line Items]

General partner interest percentage

5.25%

Limited partner interest percentage

18.40%

Incentive distribution rights percentage

5.25%

PennTex Operating [Member] | Gas Processing Agreement

Related Party Transaction [Line Items]

Primary term of gas agreement

15 years

Extension term of gas agreement

1 year

Classic Operating And Classic Pipeline [Member] | Gas Gathering Agreement [Member]

Related Party Transaction [Line Items]

Pipeline transportation agreement expiration year

2,020

Pipeline transportation agreement extension

1 year

Amended gas gathering agreement terms disclosure

Classic Operating agreed to pay a fee of (i) $0.30 per MMBtu, subject to an annual 3.5% inflationary escalation, based on volumes of natural gas delivered and processed, and (ii) $0.07 per MMBtu per stage of compression plus its allocated share of compressor fuel

Fee per MMBTU | $ / MMBTU

0.30

MVC (MMBtu/d) | MMBTU / d

50,000

Annual inflationary escalation

3.50%

Price per unit | $ / MMBTU

0.07

Agreement expired, date

Dec. 31, 2023

Classic Operating And Classic Pipeline [Member] | Water Disposal Agreement [Member]

Related Party Transaction [Line Items]

Gain recognized as contribution

$ 2,100,000

Water disposal agreement period

3 years

Pipeline water disposal agreement extension

1 year

Water disposal fee per barrel | $ / bbl

0.40

1.10

Salt water disposal fees

$ 3,600,000

$ 1,800,000

$ 600,000

Related Party Transactions - Sc

Related Party Transactions - Schedule of Net Assets Recorded (Detail) - USD ($) $ in Thousands	Feb. 28, 2014	Oct. 01, 2013
Cinco Group [Member]
Related Party Transaction [Line Items]
Cash and cash equivalents		$ 2,820
Accounts receivable		5,184
Prepaid expenses and other current assets		1,454
Oil and natural gas properties, net		342,759
Long-term derivative instruments, net		(826)
Other long-term assets		344
Accounts payable		(2,346)
Revenue Payable		(2,910)
Accrued liabilities		(1,799)
short-term derivative instruments, net		(1,828)
Asset retirement obligations		(9,606)
Credit facilities		(151,690)
Net assets		$ 181,556
WildHorse Resources, LLC [Member] | NGPCIF [Member]
Related Party Transaction [Line Items]
Accounts receivable	$ 2,274
Oil and natural gas properties, net	40,056
Accrued liabilities	(297)
Asset retirement obligations	(277)
Net assets	$ 41,756

Related Party Transactions - Bo

Related Party Transactions - Book Value of Assets Sold (Detail) - WHR Management Company [Member] - WildHorse Resources, LLC [Member] - Disposition [Member] $ in Thousands	Jun. 18, 2014USD ($)
Related Party Transaction [Line Items]
Cash and cash equivalents	$ 33,001
Restricted cash	300
Accounts receivable	5,256
Prepaid expenses and other current assets	379
Property, plant and equipment, net	3,410
Other long-term assets	4
Accounts payable	(19,959)
Accounts payable - affiliates	(17,099)
Accrued liabilities	(5,061)
Net assets	$ 231

Related Party Transactions - Su

Related Party Transactions - Summary of Minimum Volume Commitment and Fees Associated with GPA (Detail)	12 Months Ended
	Dec. 31, 2015MMBTU / d$ / MMBTU
Gas Processing Agreement, June 1, 2015 to September 30, 2015 [Member]
Related Party Transaction [Line Items]
MVC (MMBtu/d) | MMBTU / d	115,000
Gas Processing Agreement, June 1, 2015 to September 30, 2015 [Member] | Firm Fee [Member]
Related Party Transaction [Line Items]
Fees associated with GPA	0.435
Gas Processing Agreement, June 1, 2015 to September 30, 2015 [Member] | Interruptible Fee [Member]
Related Party Transaction [Line Items]
Fees associated with GPA	0.470
Gas Processing Agreement, October 1, 2015 to June 30, 2016 [Member]
Related Party Transaction [Line Items]
MVC (MMBtu/d) | MMBTU / d	345,000
Gas Processing Agreement, October 1, 2015 to June 30, 2016 [Member] | Firm Fee [Member]
Related Party Transaction [Line Items]
Fees associated with GPA	0.435
Gas Processing Agreement, October 1, 2015 to June 30, 2016 [Member] | Interruptible Fee [Member]
Related Party Transaction [Line Items]
Fees associated with GPA	0.470
Gas Processing Agreement, July 1, 2016 to June 30, 2026 [Member]
Related Party Transaction [Line Items]
MVC (MMBtu/d) | MMBTU / d	460,000	[1]
Gas Processing Agreement, July 1, 2016 to June 30, 2026 [Member] | Firm Fee [Member]
Related Party Transaction [Line Items]
Fees associated with GPA	0.435	[1]
Gas Processing Agreement, July 1, 2016 to June 30, 2026 [Member] | Interruptible Fee [Member]
Related Party Transaction [Line Items]
Fees associated with GPA	0.350	[1]
Gas Processing Agreement, July 1, 2026 to June 30, 2030 [Member]
Related Party Transaction [Line Items]
MVC (MMBtu/d) | MMBTU / d	345,000
Gas Processing Agreement, July 1, 2026 to June 30, 2030 [Member] | Firm Fee [Member]
Related Party Transaction [Line Items]
Fees associated with GPA	0.435
Gas Processing Agreement, July 1, 2026 to June 30, 2030 [Member] | Interruptible Fee [Member]
Related Party Transaction [Line Items]
Fees associated with GPA	0.350
Gas Processing Agreement, June 2, 2030 to October 1, 2030 [Member]
Related Party Transaction [Line Items]
MVC (MMBtu/d) | MMBTU / d	115,000
Gas Processing Agreement, June 2, 2030 to October 1, 2030 [Member] | Firm Fee [Member]
Related Party Transaction [Line Items]
Fees associated with GPA	0.435
Gas Processing Agreement, June 2, 2030 to October 1, 2030 [Member] | Interruptible Fee [Member]
Related Party Transaction [Line Items]
Fees associated with GPA	0.350
[1]	The firm fee is reduced to $0.35 $/MMBtu for volumes in excess of 345,000 MMBtu/d

Related Party Transactions - 89

Related Party Transactions - Summary of Minimum Volume Commitment and Fees Associated with GPA (Parenthetical) (Detail) - Gas Processing Agreement, July 1, 2016 to June 30, 2026 [Member]	12 Months Ended
	Dec. 31, 2015MMBTU / d$ / MMBTU
Related Party Transaction [Line Items]
Decrease in firm fee | $ / MMBTU	0.35
MVC (MMBtu/d)	460,000	[1]
Minimum [Member]
Related Party Transaction [Line Items]
MVC (MMBtu/d)	345,000
[1]	The firm fee is reduced to $0.35 $/MMBtu for volumes in excess of 345,000 MMBtu/d

Related Party Transactions - 90

Related Party Transactions - Summary of Minimum Volume Commitment under GGA (Detail)	12 Months Ended
	Dec. 31, 2015MMBTU / d$ / MMBTU
Gas Gathering Agreement, June 1, 2015 to November 30, 2019 [Member]
Related Party Transaction [Line Items]
MVC (MMBtu/d) | MMBTU / d	460,000
Gas Gathering Agreement, June 1, 2015 to November 30, 2019 [Member] | Firm Fee [Member]
Related Party Transaction [Line Items]
Fees associated with GGA | $ / MMBTU	0.03
Gas Gathering Agreement, June 1, 2015 to September 30, 2015 [Member]
Related Party Transaction [Line Items]
MVC (MMBtu/d) | MMBTU / d	115,000
Gas Gathering Agreement, June 1, 2015 to September 30, 2015 [Member] | Usage Fee [Member]
Related Party Transaction [Line Items]
Fees associated with GGA | $ / MMBTU	0.02
Gas Gathering Agreement, October 1, 2015 to June 30, 2016 [Member]
Related Party Transaction [Line Items]
MVC (MMBtu/d) | MMBTU / d	345,000
Gas Gathering Agreement, October 1, 2015 to June 30, 2016 [Member] | Usage Fee [Member]
Related Party Transaction [Line Items]
Fees associated with GGA | $ / MMBTU	0.02
Gas Gathering Agreement, July 1, 2016 to November 30, 2019 [Member]
Related Party Transaction [Line Items]
MVC (MMBtu/d) | MMBTU / d	460,000
Gas Gathering Agreement, July 1, 2016 to November 30, 2019 [Member] | Usage Fee [Member]
Related Party Transaction [Line Items]
Fees associated with GGA | $ / MMBTU	0.02
Gas Gathering Agreement, December 1, 2019 to June 30, 2026 [Member]
Related Party Transaction [Line Items]
MVC (MMBtu/d) | MMBTU / d	460,000
Gas Gathering Agreement, December 1, 2019 to June 30, 2026 [Member] | Usage Fee [Member]
Related Party Transaction [Line Items]
Fees associated with GGA | $ / MMBTU	0.05
Gas Gathering Agreement, July 1, 2026 to June 1, 2030 [Member]
Related Party Transaction [Line Items]
MVC (MMBtu/d) | MMBTU / d	345,000
Gas Gathering Agreement, July 1, 2026 to June 1, 2030 [Member] | Usage Fee [Member]
Related Party Transaction [Line Items]
Fees associated with GGA | $ / MMBTU	0.05

Related Party Transactions - 91

Related Party Transactions - Summary of Fees Associated with GTA and TSA (Detail)	12 Months Ended
	Dec. 31, 2015USD ($)$ / MMBTU$ / gal
Gas Transportation Agreement, June 1, 2015 to June 1, 2030 [Member] | Usage Fee [Member]
Related Party Transaction [Line Items]
Fees associated with GTA or TSA | $ / MMBTU	0.04
Gas Transportation Agreement , January 1, 2016 to December 31, 2025 [Member]
Related Party Transaction [Line Items]
Gas transportation agreement, demand fee | $	$ 360,000
Transportation Services Agreement, October 1, 2015 to October 1, 2030 [Member] | Usage Fee [Member]
Related Party Transaction [Line Items]
Fees associated with GTA or TSA | $ / gal	0.04

Income Taxes - Components of In

Income Taxes - Components of Income Tax Benefit (Expense) from Continuing Operations (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Current income taxes:
Federal	$ (9,971)	$ 0	$ 0
State	(99)	149	(1,311)
Total current income tax benefit (expense)	(10,070)	149	(1,311)
Deferred income taxes:
Federal	(55,417)	(91,051)	0
State	(34,518)	(11,490)	0
Total deferred income tax benefit (expense)	(89,935)	(102,541)	0
Total income tax benefit (expense)	$ (100,005)	$ (102,392)	$ (1,311)

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Jun. 30, 2014
Operating Loss Carryforwards [Line Items]
Federal statutory corporate tax rate	35.00%
Deferred tax liabilities	$ 281,427,000	$ 146,135,000	$ 43,300,000
Reversed deferred tax liability	38,778,000
Deferred Tax Adjustment Equity Initial Public Offering	4,400,000
Deferred Tax Adjustment Property Exchanges	34,400,000
Unrecognized tax benefits	0
Valuation allowance	0
Tax credit carryforward	9,984,000
United States [Member]
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards	$ 169,500,000
Operating loss carryforwards expiration start year	2,034
Operating loss carryforwards expiration end year	2,035
State [Member]
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards	$ 173,600,000
Operating loss carryforwards expiration start year	2,034
Operating loss carryforwards expiration end year	2,035
Discontinued Operations [Member] | United States [Member]
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards	$ 200,000

Income Taxes - Reconciliation o

Income Taxes - Reconciliation of Income Tax Benefit (Expense) from Continuing Operations (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Expected tax benefit (expense) at federal statutory rate		$ (69,162)	$ 227,250	$ (32,073)
State income tax benefit (expense), net of federal benefit		(22,501)	(7,753)	(1,311)
Pass-through entities	[1]	0	7,989	32,073
Stock compensation	[2]	(12,300)	(330,024)	0
Other		3,958	146	0
Total income tax benefit (expense)		$ (100,005)	$ (102,392)	$ (1,311)
[1]	Our predecessor was also a pass-through entity for federal income tax purposes.
[2]	As discussed in Note 12, the compensation expense associated with the incentive units of WildHorse Resources and MRD Holdco created a nondeductible permanent difference for income tax purposes.

Income Taxes - Components of Ne

Income Taxes - Components of Net Deferred Income Tax Liabilities (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Jun. 30, 2014
Deferred income tax assets:
Net operating loss carryforward	$ 68,375	$ 24,084
Asset retirement obligation	3,789	3,902
Alternative minimum tax credit carryforward	9,984
Other	5,546	3,550
Total deferred income tax assets	87,694	31,536
Valuation allowance	0
Net deferred income tax assets	87,694	31,536
Deferred income tax liabilities:
Property, plant and equipment	171,627	48,104
Derivatives	109,800	97,760
Other		271
Total deferred income tax liabilities	281,427	146,135	$ 43,300
Net deferred income tax liabilities	$ 193,733	$ 114,599

Commitments and Contingencies -

Commitments and Contingencies - Environmental Reserves Activity (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Commitments And Contingencies Disclosure [Abstract]
Balance at beginning of period	$ 140	$ 418
Charged to costs and expenses	0	0
Payments	$ (140)	(278)
Balance at end of period		$ 140

Commitments and Contingencies97

Commitments and Contingencies - Additional Information (Detail) - Regency Field Services LLC [Member]	12 Months Ended
	Dec. 31, 2015$ / MMBTU
Unrecorded Unconditional Purchase Obligation [Line Items]
Agreement expired, date	Dec. 31, 2025
Extension term of gas agreement	1 year
Natural gas assesses per MMBtu	0.25
Dubberly [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Payback demand fee received by the third party	110.00%

Commitments and Contingencies98

Commitments and Contingencies - Monthly Demand Quantity and Fees (Detail) - January 1, 2016 to January 22, 2020 [Member]	12 Months Ended
	Dec. 31, 2015MMBTU / d$ / MMBTU
Other Commitments [Line Items]
MDQ | MMBTU / d	249,700
Payback Demand Fee [Member]
Other Commitments [Line Items]
Fees associated with third party midstream service agreement	0.275
Gathering Demand Fee [Member]
Other Commitments [Line Items]
Fees associated with third party midstream service agreement	0.295
MDQ | MMBTU / d	113,000
Dubberly Cryogenic Processing Fee [Member]
Other Commitments [Line Items]
Fees associated with third party midstream service agreement	0.380

Commitments and Contingencies99

Commitments and Contingencies - Operating Leases - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Commitments And Contingencies Disclosure [Abstract]
Rent expense	$ 8.5	$ 3.9	$ 3

Commitments and Contingencie100

Commitments and Contingencies - Minimum Lease Payment Obligations and Sublease Rental Income Under Non-Cancelable Operating Leases (Detail) $ in Thousands	Dec. 31, 2015USD ($)
Operating leases
Total	$ 45,323
2,016	10,509
2,017	9,344
2,018	7,368
2,019	6,776
2,020	6,203
Thereafter	5,123
Sublease rental income
Sublease rental income, Total	4,021
Sublease rental income, 2016	1,579
Sublease rental income, 2017	1,197
Sublease rental income, 2018	814
Sublease rental income, 2019	431
Sublease rental income, 2020	0
Sublease rental income, Thereafter	$ 0

Quarterly Financial Informat101

Quarterly Financial Information (Unaudited) - Schedule of Quarterly Financial Information (Detail) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
Quarterly Financial Data [Abstract]
Revenues	$ 96,760	$ 111,654	$ 78,605	$ 87,023	$ 111,742	$ 99,035	$ 110,569	$ 87,736	$ 374,042		$ 409,082		$ 219,552
Operating income (loss)	51,330	120,415	(41,593)	107,872	263,421	47,123	(899,962)	27,344	238,024		(562,074)		116,443
Net income (loss) from continuing operations	16,980	56,726	(26,614)	50,509	170,020	10,730	(941,803)	9,376	97,601		(751,677)		90,327
Net income (loss)	89,987	(135,255)	(140,473)	(112,149)	328,859	112,037	(1,053,443)	(23,516)	95,648		(762,851)		101,502
Net income (loss) attributable to noncontrolling interest	70,081	(191,807)	(113,771)	(158,041)	161,661	102,109	(105,094)	(31,888)	(393,538)		126,788		49,830
Net income (loss) attributable to Memorial Resource Development Corp.	19,906	56,552	(26,702)	45,892	167,198	9,928	(948,349)	8,372
Net income (loss) allocated to members							13,358	6,947			20,305		90,712
Net income (loss) allocated to previous owners								$ 1,425			1,425		$ 10,790
Net income (loss) from continuing operations available to common stockholders	$ 20,277	$ 56,051	$ (26,702)	$ 45,615	$ 166,884	$ 9,928	$ (961,707)		$ 95,241		$ (784,895)
Earnings per common share – basic
Income (loss) from continuing operations	$ 0.10	$ 0.29	$ (0.14)	$ 0.24	$ 0.87	$ 0.05	$ (5)		$ 0.49		$ (4.08)
Income (loss) from discontinued operations	0.10	0.29	(0.14)	0.24	0.87	0.05	(5)		0		0		$ 0
Earnings per common share – diluted
Income (loss) from continuing operations	0.10	0.29	(0.14)	0.24	0.87	0.05	(5)		0.49	[1]	(4.08)	[1]
Income (loss) from discontinued operations	$ 0.10	$ 0.29	$ (0.14)	$ 0.24	$ 0.87	$ 0.05	$ (5)		$ 0	[1]	$ 0	[1]
[1]	The Company determines the more dilutive of either the two-class method or the treasury stock method for diluted EPS. The two-class method was more dilutive for each period presented.

Supplemental Oil and Gas Inf102

Supplemental Oil and Gas Information - Capitalized Costs Relating to Oil and Natural Gas Producing Activities (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Extractive Industries [Abstract]
Evaluated oil and natural gas properties	$ 1,740,530	$ 1,269,605	$ 897,511
Support equipment and facilities	4,719	0	0
Unevaluated oil and natural gas properties	414,759	47,497	44,453
Accumulated depletion, depreciation, and amortization	(434,735)	(276,837)	(160,620)
Total	$ 1,725,273	$ 1,040,265	$ 781,344

Supplemental Oil and Gas Inf103

Supplemental Oil and Gas Information - Costs Incurred for Property Acquisition, Exploration and Development (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Extractive Industries [Abstract]
Property acquisition costs, proved	$ 8,347	$ 74,490	$ 56,108
Property acquisition costs, unproved	360,353	24,310	19,975
Exploration and extension well costs	28,068	209,532	13,313
Development	492,191	181,026	191,350
Total	$ 888,959	$ 489,358	$ 280,746

Supplemental Oil and Gas Inf104

Supplemental Oil and Gas Information - Weighted Average Product Price (Detail)		12 Months Ended
		Dec. 31, 2015$ / MMBTU$ / bbl	Dec. 31, 2014$ / MMBTU$ / bbl	Dec. 31, 2013$ / MMBTU$ / bbl
Oil [Member] | West Texas Intermediate [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Price	[1]	46.79	91.48	93.42
Natural Gas Liquids [Member] | West Texas Intermediate [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Price	[1]	46.79	91.48	93.42
Natural Gas [Member] | Henry Hub [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Price | $ / MMBTU	[2]	2.59	4.35	3.67
[1]	The unweighted average West Texas Intermediate price was adjusted by lease for quality, transportation fees, and a regional price differential.
[2]	The unweighted average Henry Hub price was adjusted by lease for energy content, compression charges, transportation fees, and regional price differentials.

Supplemental Oil and Gas Inf105

Supplemental Oil and Gas Information - Reserve Quantity Information (Detail)	12 Months Ended
	Dec. 31, 2015MMcfeBcfeMBblsMMcf	Dec. 31, 2014MMcfeBcfeMBblsMMcf		Dec. 31, 2013MMcfeBcfeMBblsMMcf
Proved developed and undeveloped reserves:
Extensions and discoveries | Bcfe	74	254		149
Oil [Member]
Proved developed and undeveloped reserves:
Beginning of the year	11,915	10,824	[1]	10,220
Extensions and discoveries	1,111	1,825		1,635
Purchase of minerals in place	535	269		211
Production	(1,331)	(908)		(631)
Sales of minerals in place	(407)	(623)		(599)
Revision of previous estimates	1,331	528		(12)
End of year	13,154	11,915		10,824	[1]
Proved developed reserves:
Beginning of year	3,708	3,238		2,813
End of year	6,101	3,708		3,238
Proved undeveloped reserves:
Beginning of year	8,207	7,586		7,407
End of year	7,053	8,207		7,586
Natural Gas [Member]
Proved developed and undeveloped reserves:
Beginning of the year | MMcf	1,013,340	671,485	[1]	549,449
Extensions and discoveries | MMcf	50,343	183,467		105,289
Purchase of minerals in place | MMcf	17,508	22,186		31,815
Production | MMcf	(98,269)	(56,574)		(28,729)
Sales of minerals in place | MMcf	(39,272)	(10,815)		(14,137)
Revision of previous estimates | MMcf	30,164	203,591		27,798
End of year | MMcf	973,814	1,013,340		671,485	[1]
Proved developed reserves:
Beginning of year | MMcf	355,331	223,362		180,523
End of year | MMcf	443,983	355,331		223,362
Proved undeveloped reserves:
Beginning of year | MMcf	658,009	448,123		368,926
End of year | MMcf	529,831	658,009		448,123
Natural Gas Liquids [Member]
Proved developed and undeveloped reserves:
Beginning of the year	53,033	35,628	[1]	31,264
Extensions and discoveries	2,741	9,876		5,712
Purchase of minerals in place	969	1,247		1,017
Production	(3,249)	(1,863)		(1,282)
Sales of minerals in place	(358)	(950)		(1,573)
Revision of previous estimates	1,024	9,095		490
End of year	54,160	53,033		35,628	[1]
Proved developed reserves:
Beginning of year	18,203	12,226		10,208
End of year	24,583	18,203		12,226
Proved undeveloped reserves:
Beginning of year	34,830	23,402		21,056
End of year	29,577	34,830		23,402
Natural Gas Equivalent [Member]
Proved developed and undeveloped reserves:
Beginning of the year | MMcfe	1,403,030	950,199	[1]	798,357
Extensions and discoveries | MMcfe	73,456	253,670		149,369
Purchase of minerals in place | MMcfe	26,532	31,283		39,183
Production | MMcfe	(125,749)	(73,200)		(40,212)
Sales of minerals in place | MMcfe	(43,861)	(20,253)		(27,169)
Revision of previous estimates | MMcfe	44,286	261,331		30,671
End of year | MMcfe	1,377,694	1,403,030		950,199	[1]
Proved developed reserves:
Beginning of year | MMcfe	486,793	316,154		258,651
End of year | MMcfe	628,081	486,793		316,154
Proved undeveloped reserves:
Beginning of year | MMcfe	916,237	634,045		539,706
End of year | MMcfe	749,613	916,237		634,045
[1]	Includes reserves of 41,077 MMcfe attributable to noncontrolling interests and NGPCIF.

Supplemental Oil and Gas Inf106

Supplemental Oil and Gas Information - Reserve Quantity Information (Parenthetical) (Detail) - Natural Gas Equivalent [Member] - MMcfe	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013		Dec. 31, 2012
Reserve Quantities [Line Items]
End of year	1,377,694	1,403,030	950,199	[1]	798,357
Noncontrolling Interest [Member] | NGPCIF [Member]
Reserve Quantities [Line Items]
End of year			41,077
[1]	Includes reserves of 41,077 MMcfe attributable to noncontrolling interests and NGPCIF.

Supplemental Oil And Gas Inf107

Supplemental Oil And Gas Information - Additional Information (Detail) - Bcfe	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Reserve Quantities [Line Items]
Upward revisions in proved reserve	233	261
Downward price revisions in proved reserve	189
Extensions and discoveries	74	254	149
Divestiture of oil and gas properties in other noncore areas	44
Decrease in reserve	166
Reclassification of proved undeveloped resources to proved developed	231
Upward revisions due to updated well performance data	286
Downward revisions due to uneconomic vertical proved undeveloped reserve	221
Terryville Acquisition [Member]
Reserve Quantities [Line Items]
Multiple acquisitions	27	31

Supplemental Oil and Gas Inf108

Supplemental Oil and Gas Information - Discounted Future Net Cash Flows (Detail) - USD ($) $ in Thousands		Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Extractive Industries [Abstract]
Future cash inflows		$ 4,008,764		$ 7,314,745		$ 4,942,687
Future production costs		(1,438,531)		(1,020,599)		(1,343,252)
Future development costs		(784,003)		(1,209,907)		(1,137,429)
Future income tax expense	[1]	(88,723)		(1,669,356)
Future net cash flows for estimated timing of cash flows		1,697,507		3,414,883		2,462,006
10% annual discount for estimated timing of cash flows		(877,647)		(1,604,728)		(1,103,145)
Standardized measure of discounted future net cash flows		$ 819,860	[2]	$ 1,810,155	[2]	$ 1,358,861	[2]	$ 1,138,271
[1]	Our predecessor was a pass through entity and was subject to the Texas margin tax based on the taxable margin apportioned to Texas. However, due to immateriality, we have excluded the impact of this tax for the year ended December 31, 2013.
[2]	Includes $63,422 attributable to both noncontrolling interests and NGPCIF for the year ended December 31, 2013.

Supplemental Oil and Gas Inf109

Supplemental Oil and Gas Information - Discounted Future Net Cash Flows (Parenthetical) (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	[1]	Dec. 31, 2014	[1]	Dec. 31, 2013		Dec. 31, 2012
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items]
Standardized measure of discounted future net cash flows	$ 819,860		$ 1,810,155		$ 1,358,861	[1]	$ 1,138,271
Noncontrolling Interest [Member] | NGPCIF [Member]
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items]
Standardized measure of discounted future net cash flows					$ 63,422
[1]	Includes $63,422 attributable to both noncontrolling interests and NGPCIF for the year ended December 31, 2013.

Supplemental Oil and Gas Inf110

Supplemental Oil and Gas Information - Summary of the Changes in the Standardized Measure of Future Net Cash Flows (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
Extractive Industries [Abstract]
Beginning of year		$ 1,810,155	[1]	$ 1,358,861	[1]	$ 1,138,271
Sale of oil and natural gas produced, net of production costs		(240,244)		(332,785)		(175,933)
Purchase of minerals in place		53,597		69,282		51,177
Sale of minerals in place		(41,543)		(47,791)		(54,091)
Extensions and discoveries		30,006		653,088		286,796
Changes in income taxes, net		882,942		(995,635)
Changes in prices and costs		(2,284,279)		367,212		(59,083)
Previously estimated development costs incurred		294,617		205,388		62,012
Net changes in future development costs		190,403		(68,079)		(1,295)
Revisions of previous quantities		51,455		713,176		45,183
Accretion of discount		244,123		135,887		110,312
Change in production rates and other		(171,372)		(248,449)		(44,488)
End of year	[1]	$ 819,860		$ 1,810,155		$ 1,358,861
[1]	Includes $63,422 attributable to both noncontrolling interests and NGPCIF for the year ended December 31, 2013.

Condensed Consolidating Fina111

Condensed Consolidating Financial Information - Condensed Consolidating Balance Sheets (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Current assets:
Cash and cash equivalents	$ 0	$ 3,364	$ 51,530	$ 17,055
Accounts receivable - trade	52,692	33,078
Accounts receivable - affiliates	0	0
Short-term derivative instruments	227,991	131,471
Other financial assets	46,106
Prepaid expenses and other current assets	3,374	11,344
Assets of discontinued operation (Note 3)	345,541	321,536
Total current assets	675,704	500,793
Property and equipment, net	1,744,447	1,066,644
Long-term derivative instruments	91,292	123,567
Investments in subsidiaries	0	0
Other long-term assets	4,976	3,586
Assets of discontinued operation (Note 3)	2,566,430	2,865,236
Total assets	5,082,849	4,559,826
Current liabilities:
Accounts payable and accrued liabilities	93,933	52,195
Accounts payable - affiliates	5,016	160
Revenues payable	34,026	21,807
Liabilties of discontinued operation (Note 3)	91,779	159,946
Total current liabilities	224,754	234,108
Long-term debt	1,012,064	770,545
Asset retirement obligations	10,079	9,829	10,243
Deferred tax liabilities	193,733	114,599
Other long-term liabilities	7,195	8,585
Liabilities of discontinued operation (Note 3)	2,167,103	1,719,196
Total liabilities	3,614,928	2,856,862
Equity:
Equity	822,827	582,410
Noncontrolling interests	645,094	1,120,554
Total equity	1,467,921	1,702,964	858,132	1,276,709
Total liabilities and equity	5,082,849	4,559,826
Parent [Member]
Current assets:
Cash and cash equivalents	2,986	2,241
Accounts receivable - trade	7,850	5,995
Accounts receivable - affiliates	9,525	10,047
Short-term derivative instruments	227,991	131,471
Other financial assets	46,106
Prepaid expenses and other current assets	2,318	4,178
Assets of discontinued operation (Note 3)	0	0
Total current assets	296,776	153,932
Property and equipment, net	15,825	16,601
Long-term derivative instruments	91,292	123,567
Investments in subsidiaries	1,482,847	1,139,792
Other long-term assets	4,976	3,324
Assets of discontinued operation (Note 3)	0	0
Total assets	1,891,716	1,437,216
Current liabilities:
Accounts payable and accrued liabilities	26,796	6,245
Accounts payable - affiliates	0	0
Revenues payable	80	0
Liabilties of discontinued operation (Note 3)	0	0
Total current liabilities	26,876	6,245
Long-term debt	1,012,064	770,545
Asset retirement obligations	0	0
Deferred tax liabilities	22,754	69,431
Other long-term liabilities	7,195	8,585
Liabilities of discontinued operation (Note 3)	0	0
Total liabilities	1,068,889	854,806
Equity:
Equity	822,827	582,410
Noncontrolling interests	0	0
Total equity	822,827	582,410
Total liabilities and equity	1,891,716	1,437,216
Guarantor Subsidiaries [Member]
Current assets:
Cash and cash equivalents	0	1,123	44,126	14,872
Accounts receivable - trade	48,372	29,804
Accounts receivable - affiliates	0	0
Short-term derivative instruments	0	0
Other financial assets	0
Prepaid expenses and other current assets	1,056	7,166
Assets of discontinued operation (Note 3)	3,779	18,614
Total current assets	53,207	56,707
Property and equipment, net	1,728,622	1,050,043
Long-term derivative instruments	0	0
Investments in subsidiaries	0	0
Other long-term assets	0	260
Assets of discontinued operation (Note 3)	614	679
Total assets	1,782,443	1,107,689
Current liabilities:
Accounts payable and accrued liabilities	66,133	49,075
Accounts payable - affiliates	17,339	160
Revenues payable	33,946	21,807
Liabilties of discontinued operation (Note 3)	1,517	16,384
Total current liabilities	118,935	87,426
Long-term debt	0	0
Asset retirement obligations	10,079	9,829
Deferred tax liabilities	170,979	45,122
Other long-term liabilities	0	0
Liabilities of discontinued operation (Note 3)	0	1
Total liabilities	299,993	142,378
Equity:
Equity	1,482,450	965,311
Noncontrolling interests	0	0
Total equity	1,482,450	965,311
Total liabilities and equity	1,782,443	1,107,689
Non-Guarantor Subsidiaries [Member]
Current assets:
Cash and cash equivalents	0	0	$ 7,404	$ 2,183
Accounts receivable - trade	0	0
Accounts receivable - affiliates	0	0
Short-term derivative instruments	0	0
Other financial assets	0
Prepaid expenses and other current assets	0	0
Assets of discontinued operation (Note 3)	340,186	303,961
Total current assets	340,186	303,961
Property and equipment, net	0	0
Long-term derivative instruments	0	0
Investments in subsidiaries	0	0
Other long-term assets	0	0
Assets of discontinued operation (Note 3)	2,565,816	2,864,559
Total assets	2,906,002	3,168,520
Current liabilities:
Accounts payable and accrued liabilities	0	0
Accounts payable - affiliates	0	0
Revenues payable	0	0
Liabilties of discontinued operation (Note 3)	93,408	152,985
Total current liabilities	93,408	152,985
Long-term debt	0	0
Asset retirement obligations	0	0
Deferred tax liabilities	0	0
Other long-term liabilities	0	0
Liabilities of discontinued operation (Note 3)	2,167,103	1,719,241
Total liabilities	2,260,511	1,872,226
Equity:
Equity	645,491	1,290,734
Noncontrolling interests	0	5,560
Total equity	645,491	1,296,294
Total liabilities and equity	2,906,002	3,168,520
Eliminations [Member]
Current assets:
Cash and cash equivalents	(2,986)	0
Accounts receivable - trade	(3,530)	(2,721)
Accounts receivable - affiliates	(9,525)	(10,047)
Short-term derivative instruments	0	0
Other financial assets	0
Prepaid expenses and other current assets	0	0
Assets of discontinued operation (Note 3)	1,576	(1,039)
Total current assets	(14,465)	(13,807)
Property and equipment, net	0	0
Long-term derivative instruments	0	0
Investments in subsidiaries	(1,482,847)	(1,139,792)
Other long-term assets	0	2
Assets of discontinued operation (Note 3)	0	(2)
Total assets	(1,497,312)	(1,153,599)
Current liabilities:
Accounts payable and accrued liabilities	1,004	(3,125)
Accounts payable - affiliates	(12,323)	0
Revenues payable	0	0
Liabilties of discontinued operation (Note 3)	(3,146)	(9,423)
Total current liabilities	(14,465)	(12,548)
Long-term debt	0	0
Asset retirement obligations	0	0
Deferred tax liabilities	0	46
Other long-term liabilities	0	0
Liabilities of discontinued operation (Note 3)	0	(46)
Total liabilities	(14,465)	(12,548)
Equity:
Equity	(2,127,941)	(2,256,045)
Noncontrolling interests	645,094	1,114,994
Total equity	(1,482,847)	(1,141,051)
Total liabilities and equity	$ (1,497,312)	$ (1,153,599)

Condensed Consolidating Fina112

Condensed Consolidating Financial Information - Condensed Consolidating Statements of Operations (Detail) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenues:
Oil & natural gas sales									$ 374,042	$ 409,070	$ 219,552
Other income										12
Total revenues	$ 96,760	$ 111,654	$ 78,605	$ 87,023	$ 111,742	$ 99,035	$ 110,569	$ 87,736	374,042	409,082	219,552
Costs and expenses:
Lease operating									24,903	17,570	17,207
Gathering, processing, and transportation									72,554	45,956	17,666
Gathering, processing, and transportation – affiliate									25,403
Exploration									8,969	13,853	1,034
Taxes other than income									14,896	12,610	8,699
Depreciation, depletion, and amortization									188,742	128,238	70,903
Impairment of proved oil and natural gas properties									0	24,576	2,528
Incentive unit compensation expense									35,142	943,949	34,997
General and administrative									46,288	38,549	35,414
Accretion of asset retirement obligations									417	533	593
(Gain) loss on commodity derivatives									(281,249)	(257,734)	(3,161)
(Gain) loss on sale of properties									(47)	3,057	(82,773)
Other, net										(1)	2
Total costs and expenses									136,018	971,156	103,109
Operating income (loss)	51,330	120,415	(41,593)	107,872	263,421	47,123	(899,962)	27,344	238,024	(562,074)	116,443
Other income (expense):
Interest expense, net									(39,396)	(50,283)	(24,948)
Loss on extinguishment of debt										(37,248)
Equity earnings from subsidiaries									0	0	0
Other, net									(1,022)	320	143
Total other income (expense)									(40,418)	(87,211)	(24,805)
Income (loss) from continuing operations before income taxes									197,606	(649,285)	91,638
Income tax benefit (expense)									(100,005)	(102,392)	(1,311)
Net income (loss) from continuing operations	16,980	56,726	(26,614)	50,509	170,020	10,730	(941,803)	9,376	97,601	(751,677)	90,327
Discontinued Operations
Income (loss) before income taxes									(397,666)	114,193	61,313
Income tax benefit (expense)									2,175	1,421	(308)
Net income (loss) from discontinued operations									(395,491)	115,614	61,005
Net income (loss)									(297,890)	(636,063)	151,332
Net income (loss) attributable to noncontrolling interest	70,081	(191,807)	(113,771)	(158,041)	161,661	102,109	(105,094)	(31,888)	(393,538)	126,788	49,830
Net income (loss) attributable to Memorial Resource Development Corp.	$ 89,987	$ (135,255)	$ (140,473)	$ (112,149)	$ 328,859	$ 112,037	$ (1,053,443)	$ (23,516)	95,648	(762,851)	101,502
Parent [Member]
Revenues:
Oil & natural gas sales									0	0	0
Other income										5
Total revenues									0	5	0
Costs and expenses:
Lease operating									0	0	0
Gathering, processing, and transportation									0	0	0
Gathering, processing, and transportation – affiliate									0
Exploration									0	0	0
Taxes other than income									3,833	0	0
Depreciation, depletion, and amortization									4,191	1,133	0
Impairment of proved oil and natural gas properties										0	0
Incentive unit compensation expense									35,142	111,866	0
General and administrative									43,624	13,232	0
Accretion of asset retirement obligations									0	0	0
(Gain) loss on commodity derivatives									(281,250)	(277,129)	0
(Gain) loss on sale of properties									0	0	0
Other, net										0	0
Total costs and expenses									(194,460)	(150,898)	0
Operating income (loss)									194,460	150,903	0
Other income (expense):
Interest expense, net									(39,308)	(19,532)	0
Loss on extinguishment of debt										(23,562)
Equity earnings from subsidiaries									16,434	(809,017)	0
Other, net									(100)	0	0
Total other income (expense)									(22,974)	(852,111)	0
Income (loss) from continuing operations before income taxes									171,486	(701,208)	0
Income tax benefit (expense)									(75,838)	(83,373)	0
Net income (loss) from continuing operations									95,648	(784,581)	0
Discontinued Operations
Income (loss) before income taxes									0	0	0
Income tax benefit (expense)									0	0	0
Net income (loss) from discontinued operations									0	0	0
Net income (loss)									95,648	(784,581)	0
Net income (loss) attributable to noncontrolling interest									0	0	0
Net income (loss) attributable to Memorial Resource Development Corp.									95,648	(784,581)	0
Guarantor Subsidiaries [Member]
Revenues:
Oil & natural gas sales									374,042	409,070	202,423
Other income										7
Total revenues									374,042	409,077	202,423
Costs and expenses:
Lease operating									24,904	17,570	14,710
Gathering, processing, and transportation									72,555	45,956	17,666
Gathering, processing, and transportation – affiliate									25,403
Exploration									8,969	13,853	1,034
Taxes other than income									11,063	12,610	7,869
Depreciation, depletion, and amortization									184,551	127,105	61,990
Impairment of proved oil and natural gas properties										24,576	128
Incentive unit compensation expense									0	831,060	14,353
General and administrative									2,664	25,277	31,674
Accretion of asset retirement obligations									418	533	516
(Gain) loss on commodity derivatives									0	19,395	(3,179)
(Gain) loss on sale of properties									(47)	3,167	6,776
Other, net										0	0
Total costs and expenses									330,480	1,121,102	153,537
Operating income (loss)									43,562	(712,025)	48,886
Other income (expense):
Interest expense, net									(88)	(30,751)	(24,895)
Loss on extinguishment of debt										(13,686)
Equity earnings from subsidiaries									0	0	71,222
Other, net									(922)	319	141
Total other income (expense)									(1,010)	(44,118)	46,468
Income (loss) from continuing operations before income taxes									42,552	(756,143)	95,354
Income tax benefit (expense)									(24,167)	(19,028)	(164)
Net income (loss) from continuing operations									18,385	(775,171)	95,190
Discontinued Operations
Income (loss) before income taxes									0	0	0
Income tax benefit (expense)									0	0	0
Net income (loss) from discontinued operations									0	0	0
Net income (loss)									18,385	(775,171)	95,190
Net income (loss) attributable to noncontrolling interest									0	0	0
Net income (loss) attributable to Memorial Resource Development Corp.									18,385	(775,171)	95,190
Non-Guarantor Subsidiaries [Member]
Revenues:
Oil & natural gas sales									0	0	17,129
Other income										0
Total revenues									0	0	17,129
Costs and expenses:
Lease operating									0	0	2,605
Gathering, processing, and transportation									0	0	0
Gathering, processing, and transportation – affiliate									0
Exploration									0	0	0
Taxes other than income									0	0	830
Depreciation, depletion, and amortization									0	0	8,913
Impairment of proved oil and natural gas properties										0	2,400
Incentive unit compensation expense									0	1,023	20,644
General and administrative									0	16	3,616
Accretion of asset retirement obligations									0	0	77
(Gain) loss on commodity derivatives									0	0	18
(Gain) loss on sale of properties									0	(110)	(89,549)
Other, net										0	2
Total costs and expenses									0	929	(50,444)
Operating income (loss)									0	(929)	67,573
Other income (expense):
Interest expense, net									0	0	(53)
Loss on extinguishment of debt										0
Equity earnings from subsidiaries									0	0	0
Other, net									0	0	2
Total other income (expense)									0	0	(51)
Income (loss) from continuing operations before income taxes									0	(929)	67,522
Income tax benefit (expense)									0	0	(1,147)
Net income (loss) from continuing operations									0	(929)	66,375
Discontinued Operations
Income (loss) before income taxes									(397,664)	114,171	61,297
Income tax benefit (expense)									2,175	1,430	(308)
Net income (loss) from discontinued operations									(395,489)	115,601	60,989
Net income (loss)									(395,489)	114,672	127,364
Net income (loss) attributable to noncontrolling interest									386	32	267
Net income (loss) attributable to Memorial Resource Development Corp.									(395,875)	114,640	127,097
Eliminations [Member]
Revenues:
Oil & natural gas sales									0	0	0
Other income										0
Total revenues									0	0	0
Costs and expenses:
Lease operating									(1)	0	(108)
Gathering, processing, and transportation									(1)	0	0
Gathering, processing, and transportation – affiliate									0
Exploration									0	0	0
Taxes other than income									0	0	0
Depreciation, depletion, and amortization									0	0	0
Impairment of proved oil and natural gas properties										0	0
Incentive unit compensation expense									0	0	0
General and administrative									0	24	124
Accretion of asset retirement obligations									(1)	0	0
(Gain) loss on commodity derivatives									1	0	0
(Gain) loss on sale of properties									0	0	0
Other, net										(1)	0
Total costs and expenses									(2)	23	16
Operating income (loss)									2	(23)	(16)
Other income (expense):
Interest expense, net									0	0	0
Loss on extinguishment of debt										0
Equity earnings from subsidiaries									(16,434)	809,017	(71,222)
Other, net									0	1	0
Total other income (expense)									(16,434)	809,018	(71,222)
Income (loss) from continuing operations before income taxes									(16,432)	808,995	(71,238)
Income tax benefit (expense)									0	9	0
Net income (loss) from continuing operations									(16,432)	809,004	(71,238)
Discontinued Operations
Income (loss) before income taxes									(2)	22	16
Income tax benefit (expense)									0	(9)	0
Net income (loss) from discontinued operations									(2)	13	16
Net income (loss)									(16,434)	809,017	(71,222)
Net income (loss) attributable to noncontrolling interest									(393,924)	126,756	49,563
Net income (loss) attributable to Memorial Resource Development Corp.									$ 377,490	$ 682,261	$ (120,785)

Condensed Consolidating Fina113

Condensed Consolidating Financial Information - Condensed Consolidating Statements of Cash Flows (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Condensed Cash Flow Statements Captions [Line Items]
Net cash provided (used in) by continuing operations	$ 412,742	$ 225,690	$ 88,472
Net cash provided (used in) by discontinued operations	221,169	250,581	189,351
Net cash provided by operating activities	633,911	476,271	277,823
Cash flows from investing activities:
Acquisitions of oil and natural gas properties	(291,536)	(93,909)	(67,098)
Additions to oil and gas properties	(594,901)	(376,122)	(185,194)
Additions to other property and equipment	(3,853)	(16,831)	(2,307)
Additions to restricted investments	0
Other financial hybrid instruments	(46,106)
Change in restricted cash		49,946	(49,347)
Deposits for property acquisitions		(215)
Proceeds from the sale of oil and gas properties	13,612	6,700	151,187
Other		(301)
Net cash used in continuing operations	(922,784)	(430,732)	(152,759)
Net cash used in discontinued operations	(337,505)	(1,386,247)	(214,684)
Net cash used in investing activities	(1,260,289)	(1,816,979)	(367,443)
Cash flows from financing activities:
Advances on revolving credit facilities	798,000	1,300,800	174,400
Payments on revolving credit facility	(558,000)	(1,320,900)	(200,500)
Termination of second lien credit facility		(328,282)
Proceeds from the issuances of senior notes		600,000	343,000
Borrowings under second lien credit facility			325,000
Redemption of senior notes		(351,808)
Deferred finance costs	(1,498)	(18,840)	(20,251)
Proceeds from MRD equity offering	242,880	408,500
MRD equity repurchases	(51,197)	(161)
Costs incurred in conjunction with MRD equity offering	(4,773)	(28,373)
Purchase of additional interests in subsidiaries		(3,292)	(15,135)
Distributions to the Funds			(732,362)
Distribution to noncontrolling interests		(376)	(7,446)
Distributions made by previous owners			(2,590)
Other		320	71
Net cash provided by (used in) continuing operations	425,412	99,487	(801)
Net cash used in discontinued operations	197,183	1,169,458	118,751
Net cash provided by financing activities	622,595	1,268,945	117,950
Net change in cash and cash equivalents	(3,783)	(71,763)	28,330
Add: cash balance included in assets of discontinued operations at beginning of period	2,594	26,191	32,336
Less: cash balance included in assets of discontinued operations at end of period	2,175	2,594	26,191
Cash and cash equivalents, beginning of period	3,364	51,530	17,055
Cash and cash equivalents, end of period	0	3,364	51,530
MEMP [Member]
Cash flows from financing activities:
Proceeds from changes in ownership interests in MEMP			135,012
Natural Gas Partners [Member]
Cash flows from financing activities:
Contributions from NGP affiliates related to sale of properties		1,165
Distribution to NGP affiliates related to purchase of assets		(66,693)
Distribution to NGP affiliates related to sale of assets, net of cash received		(32,770)
MRD Holdco LLC [Member]
Cash flows from financing activities:
Distributions to MRD Holdco		(59,803)
Parent [Member]
Condensed Cash Flow Statements Captions [Line Items]
Net cash provided (used in) by continuing operations	45,528	(72,612)
Net cash provided by operating activities	45,528	(72,612)
Cash flows from investing activities:
Additions to other property and equipment	(3,401)	(15,980)
Additions to restricted investments	0
Other financial hybrid instruments	(46,106)
Investments in subsidiaries	(499,336)	(696,489)
Distributions from subsidiaries	78,648	15,140
Net cash used in continuing operations	(470,195)	(697,329)
Net cash used in investing activities	(470,195)	(697,329)
Cash flows from financing activities:
Advances on revolving credit facilities	798,000	1,174,000
Payments on revolving credit facility	(558,000)	(991,000)
Proceeds from the issuances of senior notes		600,000
Redemption of senior notes		(351,808)
Deferred finance costs	(1,498)	(18,779)
Proceeds from MRD equity offering	242,880	408,500
MRD equity repurchases	(51,197)	(161)
Costs incurred in conjunction with MRD equity offering	(4,773)	(28,373)
Purchase of additional interests in subsidiaries		(3,292)
Other		302
Net cash provided by (used in) continuing operations	425,412	772,182
Net cash provided by financing activities	425,412	772,182
Net change in cash and cash equivalents	745	2,241
Cash and cash equivalents, beginning of period	2,241
Cash and cash equivalents, end of period	2,986	2,241
Parent [Member] | MRD Holdco LLC [Member]
Cash flows from financing activities:
Distributions to MRD Holdco		(17,207)
Guarantor Subsidiaries [Member]
Condensed Cash Flow Statements Captions [Line Items]
Net cash provided (used in) by continuing operations	373,155	299,206	92,997
Net cash provided (used in) by discontinued operations	(1,127)	(1,716)	867
Net cash provided by operating activities	372,028	297,490	93,864
Cash flows from investing activities:
Acquisitions of oil and natural gas properties	(291,536)	(93,909)	(67,098)
Additions to oil and gas properties	(594,901)	(376,123)	(164,850)
Additions to other property and equipment	(452)	(851)	(2,307)
Additions to restricted investments	0
Investments in subsidiaries			(93,433)
Distributions from subsidiaries		74,424	273,694
Change in restricted cash		49,946	(49,347)
Deposits for property acquisitions		(215)
Proceeds from the sale of oil and gas properties	13,612		33,152
Net cash used in continuing operations	(873,277)	(346,728)	(70,189)
Net cash used in discontinued operations	63	(138)	(125)
Net cash used in investing activities	(873,214)	(346,866)	(70,314)
Cash flows from financing activities:
Advances on revolving credit facilities		126,800	174,400
Payments on revolving credit facility		(329,900)	(200,500)
Termination of second lien credit facility		(328,282)
Proceeds from the issuances of senior notes			343,000
Borrowings under second lien credit facility			325,000
Deferred finance costs		(61)	(20,250)
Capital contributions	497,424	686,623
Purchase of additional interests in subsidiaries			(15,135)
Distribution to equity owners		(15,000)
Distributions to the Funds			(732,362)
Distributions made by previous owners			(2,590)
Other		18	(129)
Net cash provided by (used in) continuing operations	497,424	4,519	6,446
Net cash provided by financing activities	497,424	4,519	6,446
Net change in cash and cash equivalents	(3,762)	(44,857)	29,996
Add: cash balance included in assets of discontinued operations at beginning of period	2,639	4,493	3,751
Less: cash balance included in assets of discontinued operations at end of period		2,639	4,493
Cash and cash equivalents, beginning of period	1,123	44,126	14,872
Cash and cash equivalents, end of period	0	1,123	44,126
Guarantor Subsidiaries [Member] | MEMP [Member]
Cash flows from financing activities:
Proceeds from changes in ownership interests in MEMP			135,012
Guarantor Subsidiaries [Member] | Natural Gas Partners [Member]
Cash flows from financing activities:
Distribution to NGP affiliates related to purchase of assets		(63,389)
Distribution to NGP affiliates related to sale of assets, net of cash received		(32,770)
Guarantor Subsidiaries [Member] | MRD Holdco LLC [Member]
Cash flows from financing activities:
Distributions to MRD Holdco		(39,520)
Non-Guarantor Subsidiaries [Member]
Condensed Cash Flow Statements Captions [Line Items]
Net cash provided (used in) by continuing operations		(2,879)	(17,702)
Net cash provided (used in) by discontinued operations	216,750	254,272	201,661
Net cash provided by operating activities	216,750	251,393	183,959
Cash flows from investing activities:
Additions to oil and gas properties			(20,344)
Additions to restricted investments	0
Proceeds from the sale of oil and gas properties		6,700	118,035
Other		(300)
Net cash used in continuing operations		6,400	97,691
Net cash used in discontinued operations	(337,568)	(1,386,109)	(214,559)
Net cash used in investing activities	(337,568)	(1,379,709)	(116,868)
Cash flows from financing activities:
Distribution to equity owners		(2,315)	(74,787)
Net cash provided by (used in) continuing operations		(7,530)	(74,787)
Net cash used in discontinued operations	120,447	1,107,714	6,030
Net cash provided by financing activities	120,447	1,100,184	(68,757)
Net change in cash and cash equivalents	(371)	(28,132)	(1,666)
Add: cash balance included in assets of discontinued operations at beginning of period	970	21,698	28,585
Less: cash balance included in assets of discontinued operations at end of period	599	970	21,698
Cash and cash equivalents, beginning of period	0	7,404	2,183
Cash and cash equivalents, end of period	0	0	7,404
Non-Guarantor Subsidiaries [Member] | Natural Gas Partners [Member]
Cash flows from financing activities:
Contributions from NGP affiliates related to sale of properties		1,165
Distribution to NGP affiliates related to purchase of assets		(3,304)
Non-Guarantor Subsidiaries [Member] | MRD Holdco LLC [Member]
Cash flows from financing activities:
Distributions to MRD Holdco		(3,076)
Eliminations [Member]
Condensed Cash Flow Statements Captions [Line Items]
Net cash provided (used in) by continuing operations	(5,941)	1,975	13,177
Net cash provided (used in) by discontinued operations	5,546	(1,975)	(13,177)
Net cash provided by operating activities	(395)
Cash flows from investing activities:
Additions to oil and gas properties		1
Additions to restricted investments	0
Investments in subsidiaries	499,336	696,489	93,433
Distributions from subsidiaries	(78,648)	(89,564)	(273,694)
Other		(1)
Net cash used in continuing operations	420,688	606,925	(180,261)
Net cash used in investing activities	420,688	606,925	(180,261)
Cash flows from financing activities:
Deferred finance costs			(1)
Capital contributions	(497,424)	(686,623)
Distribution to equity owners		17,315	74,787
Distribution to noncontrolling interests		(376)	(7,446)
Other			200
Net cash provided by (used in) continuing operations	(497,424)	(669,684)	67,540
Net cash used in discontinued operations	76,736	61,744	112,721
Net cash provided by financing activities	(420,688)	(607,940)	$ 180,261
Net change in cash and cash equivalents	(395)	(1,015)
Add: cash balance included in assets of discontinued operations at beginning of period	(1,015)
Less: cash balance included in assets of discontinued operations at end of period	1,576	(1,015)
Cash and cash equivalents, beginning of period	0
Cash and cash equivalents, end of period	$ (2,986)	$ 0