10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10–Q

þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2015

OR

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to .

Commission File Number: 001-36490

MEMORIAL RESOURCE DEVELOPMENT CORP.

(Exact name of registrant as specified in its charter)

Delaware	46-4710769
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
500 Dallas Street, Suite 1800, Houston, TX	77002
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: (713) 588-8300

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes þ  No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes þ  No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b–2 of the Exchange Act. Check one:

Large accelerated filer	¨	Accelerated filer	¨
Non-accelerated filer	þ (Do not check if a smaller reporting company)	Smaller reporting company	¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b–2 of the Exchange Act).  Yes ¨  No þ

As of October 31, 2015, the registrant had 205,314,453 shares of common stock, $.01 par value, outstanding

MemORIAL RESOURCE DEVELOPMENT CORP.

Table of Contents

		Page
	Glossary of Oil and Natural Gas Terms	2
	Names of Entities	5
	Cautionary Note Regarding Forward-Looking Statements	6
	PART I—FINANCIAL INFORMATION
Item 1.	Financial Statements
	Unaudited Condensed Consolidated Balance Sheets as of September 30, 2015 and December 31, 2014	8
	Unaudited Condensed Statements of Consolidated and Combined Operations for the Three and Nine Months Ended September 30, 2015 and 2014	9
	Unaudited Condensed Statements of Consolidated and Combined Cash Flows for the Nine Months Ended September 30, 2015 and 2014	10
	Unaudited Condensed Statements of Consolidated and Combined Equity for the Nine Months Ended September 30, 2015 and 2014	11
	Notes to Unaudited Condensed Consolidated and Combined Financial Statements
	Note 1 – Background, Organization and Basis of Presentation	12
	Note 2 – Summary of Significant Accounting Policies	13
	Note 3 – Acquisitions and Divestitures	15
	Note 4 – Fair Value Measurements of Financial Instruments	16
	Note 5 – Risk Management and Derivative Instruments	18
	Note 6 – Asset Retirement Obligations	22
	Note 7 – Restricted Investments	23
	Note 8 – Long Term Debt	23
	Note 9 – Stockholders’ Equity and Noncontrolling Interests	24
	Note 10 – Earnings per Share	26
	Note 11 – Long-Term Incentive Plans	26
	Note 12 – Incentive Units	27
	Note 13 – Related Party Transactions	28
	Note 14 – Business Segment Data	30
	Note 15 – Commitments and Contingencies	36
	Note 16 – Condensed Consolidating Financial Information	37
	Note 17 – Subsequent Events	45
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	46
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	61
Item 4.	Controls and Procedures	62
	PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	63
Item 1A.	Risk Factors	63
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	63
Item 3.	Defaults Upon Senior Securities	63
Item 4.	Mine Safety Disclosures	64
Item 5.	Other Information	64
Item 6.	Exhibits	64
Signatures		65

1

GLOSSARY OF OIL AND NATURAL GAS TERMS

Analogous Reservoir: Analogous reservoirs, as used in resource assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, analogous reservoir refers to a reservoir that shares all of the following characteristics with the reservoir of interest: (i) the same geological formation (but not necessarily in pressure communication with the reservoir of interest); (ii) the same environment of deposition; (iii) similar geologic structure; and (iv) the same drive mechanism.

Bbl: One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.

Bcfe: One billion cubic feet of natural gas equivalent.

BOEM: Bureau of Ocean Energy Management.

Btu: One British thermal unit, the quantity of heat required to raise the temperature of a one-pound mass of water by one degree Fahrenheit.

COPAS: Council of Petroleum Accountants Societies.

Dry Hole or Dry Well: A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production expenses and taxes.

Economically Producible: The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. For this determination, the value of the products that generate revenue are determined at the terminal point of oil and natural gas producing activities.

Exploitation: A development or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.

Field: An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

Gross Acres or Gross Wells: The total acres or wells, as the case may be, in which we have working interest.

MBbl: One thousand Bbls.

Mcf: One thousand cubic feet of natural gas.

MMBtu: One million British thermal units.

MMcf: One million cubic feet of natural gas.

MMcfe: One million cubic feet of natural gas equivalent.

Net Production: Production that is owned by us less royalties and production due others.

NGLs: The combination of ethane, propane, butane and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.

NYMEX: New York Mercantile Exchange.

Oil: Oil and condensate.

Operator: The individual or company responsible for the exploration and/or production of an oil or natural gas well or lease.

Play: A geographic area with hydrocarbon potential.

Possible Reserves: Reserves that are less certain to be recovered than probable reserves.

Probable Reserves: Reserves that are less certain to be recovered than proved reserves but that, together with proved reserves, are as likely as not to be recovered.

2

Proved Reserves: Those quantities of oil and natural gas, which, 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. The area of the reservoir considered as proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons, as seen in a well penetration, unless geoscience, engineering or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir, or an analogous reservoir or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price used is the average price during the twelve-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

PUDs: Proved Undeveloped Reserves.

Proved Undeveloped Reserves: Proved oil and natural gas reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

Recompletion: The completion for production of an existing wellbore in another formation from that which the well has been previously completed.

Reliable Technology: Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

Reserve Life: A measure of the productive life of an oil and natural gas property or a group of properties, expressed in years. Reserve life is calculated by dividing proved reserve volumes at year-end by production volumes. In our calculation of reserve life, production volumes are adjusted, if necessary, to reflect property acquisitions and dispositions.

Reserves: Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Reservoir: A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.

Resources: Resources are quantities of oil and natural gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable and another portion may be considered unrecoverable. Resources include both discovered and undiscovered accumulations.

3

Standardized Measure: The present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules, regulations or standards established by the United States Securities and Exchange Commission (“SEC”) and the Financial Accounting Standards Board (“FASB”) (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. Because we are a corporation, we are subject to federal or state income taxes and thus make provisions for federal or state income taxes in the calculation of our standardized measure. Standardized measure does not give effect to derivative transactions.

Wellbore: The hole drilled by the bit that is equipped for oil or natural gas production on a completed well. Also called well or borehole.

Working Interest: An interest in an oil and natural gas lease that gives the owner of the interest the right to drill for and produce oil and natural gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations.

WTI: West Texas Intermediate.

4

NAMES OF ENTITIES

As used in this Form 10-Q, unless we indicate otherwise:

· Unless the context requires otherwise, references to “we,” “us,” “our,” “MRD,” or “the Company” or like terms are intended to mean the business and operations of Memorial Resource Development Corp. and its consolidated subsidiaries;

· “MRD LLC” refers to Memorial Resource Development LLC, which historically owned our predecessor’s business and which was merged into MRD Operating LLC (“MRD Operating”), our subsidiary, subsequent to our initial public offering;

· “Memorial Production Partners,” “MEMP” and “the Partnership” refer to Memorial Production Partners LP individually and collectively with its subsidiaries, as the context requires;

· “MEMP GP” refers to Memorial Production Partners GP LLC, the general partner of the Partnership;

· “our predecessor” refers collectively to: (i) MRD LLC and its former consolidated subsidiaries, consisting of Classic Hydrocarbons Holdings, L.P. (“Classic”), Classic Hydrocarbons GP Co., L.L.C. (“Classic GP”), Black Diamond Minerals, LLC (“Black Diamond”), Beta Operating Company, LLC (“Beta Operating”), MEMP GP, BlueStone Natural Resources Holdings, LLC (“BlueStone”), MRD Operating, WildHorse Resources, LLC (“WildHorse Resources”), Tanos Energy, LLC (“Tanos”), and each of their respective subsidiaries, including MEMP and its subsidiaries and (ii) the previous owners as defined below;

· “the Funds” refers collectively to Natural Gas Partners VIII, L.P., Natural Gas Partners IX, L.P. and NGP IX Offshore Holdings, L.P., which collectively control MRD Holdco;

· “MRD Holdco” refers to MRD Holdco LLC, a holding company controlled by the Funds that, together with a group, owns a majority of our common stock;

· “the previous owners” for accounting and financial reporting purposes refers to the carved-out net profits interest created from working interests in certain oil and natural gas properties that WildHorse Resources originally acquired in 2010 from third parties and immediately sold to NGP Income Co-Investment Fund II, L.P. (“NGPCIF”), a NGP controlled entity, and subsequently reacquired from NGPCIF on February 28, 2014;

· “NGP” refers to Natural Gas Partners, a family of private equity funds organized to make direct equity investments in the energy industry, including the Funds; and

· “Classic Pipeline” refers to Classic Pipeline & Gathering, LLC, a subsidiary of MRD Holdco that owns certain immaterial midstream assets in Texas.

5

CAUTIONARY NOTE REGARDING FORWARD–LOOKING STATEMENTS

This quarterly report contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control, may include statements about our:

· business strategy;

· estimated reserves and the present value thereof;

· technology;

· cash flows and liquidity;

· financial strategy, budget, projections and future operating results;

· realized commodity prices;

· timing and amount of future production of reserves;

· ability to procure drilling and production equipment;

· ability to procure oilfield labor;

· the amount, nature and timing of capital expenditures, including future development costs;

· ability to access, and the terms of, capital;

· drilling of wells, including statements made about future horizontal drilling activities;

· competition;

· expectations regarding government regulations;

· marketing of production and the availability of pipeline capacity;

· exploitation or property acquisitions;

· costs of exploiting and developing our properties and conducting other operations;

· expectations regarding general economic and business conditions;

· competition in the oil and natural gas industry;

· effectiveness of our risk management activities;

· environmental and other liabilities;

· counterparty credit risk;

· expectations regarding taxation of the oil and natural gas industry;

· expectations regarding developments in other countries that produce oil and natural gas;

· future operating results;

· plans and objectives of management; and

· plans, objectives, expectations and intentions contained in this report that are not historical.

6

These types of statements, other than statements of historical fact included in this quarterly report, are forward-looking statements. In some cases, you can identify forward-looking statements by terminology such as “may,” “will,” “could,” “should,” “expect,” “plan,” “project,” “forecast,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “outlook,” “continue,” the negative of such terms or other comparable terminology. These statements discuss future expectations, contain projections of results of operations or of financial condition or include other “forward-looking” information. These forward-looking statements involve risks and uncertainties. Important factors that could cause our actual results or financial condition to differ materially from our expectations include, but are not limited to, the following risks and uncertainties:

· variations in the market demand for, and prices of, oil, natural gas and NGLs;

· uncertainties about our estimated reserves;

· the adequacy of our capital resources and liquidity including, but not limited to, access to additional borrowing capacity under our revolving credit facility;

· general economic and business conditions;

· risks associated with negative developments in the capital markets;

· failure to realize expected value creation from property acquisitions;

· uncertainties about our ability to replace reserves and economically develop our current reserves;

· drilling results;

· potential financial losses or earnings reductions from our commodity price risk management programs;

· adoption or potential adoption of new governmental regulations;

· the availability of capital on economic terms to fund our capital expenditures and acquisitions;

· risks associated with our substantial indebtedness; and

· our ability to satisfy future cash obligations and environmental costs.

The forward-looking statements contained in this quarterly report are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. All readers are cautioned that the forward-looking statements contained in this quarterly report are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or that the events or circumstances described in any forward-looking statement will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to factors described in the “Part I—Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2014 (our “2014 Form 10-K) and “Part II—Item 1A. Risk Factors” appearing within this quarterly report and elsewhere in this quarterly report. All forward-looking statements speak only as of the date of this quarterly report. We do not intend to update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

7

PART I—FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS.

MEMORIAL RESOURCE DEVELOPMENT CORP.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except outstanding shares)

	September 30,			December 31,
	2015			2014
ASSETS
Current assets:
Cash and cash equivalents	$	7,363		$	5,958
Accounts receivable:
Oil and natural gas sales		77,795			82,263
Joint interest owners and other		58,193			49,313
Short-term derivative instruments		383,548			340,056
Prepaid expenses and other current assets		27,856			28,027
Total current assets		554,755			505,617
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method		5,477,217			4,844,529
Other		27,053			33,815
Accumulated depreciation, depletion and impairment		(2,208,722	)		(1,340,688	)
Property and equipment, net		3,295,548			3,537,656
Long-term derivative instruments		630,496			435,369
Restricted investments		81,254			77,361
Other long-term assets		55,215			37,544
Total assets	$	4,617,268		$	4,593,547
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	38,668		$	25,772
Accounts payable - affiliates		9,757			624
Revenues payable		70,380			57,352
Accrued liabilities		176,599			147,123
Deferred income tax liabilities		57,444			51,877
Short-term derivative instruments		3,515			3,289
Total current liabilities		356,363			286,037
Long-term debt—MRD Segment		726,000			783,000
Long-term debt—MEMP Segment		1,878,264			1,595,413
Asset retirement obligations		129,060			122,531
Long-term derivative instruments		3,183			—
Deferred tax liabilities		120,789			95,017
Other long-term liabilities		6,995			8,585
Total liabilities		3,220,654			2,890,583
Commitments and contingencies (Note 15)
Equity:
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; 205,318,103 shares issued and outstanding at September 30, 2015; 193,435,414 shares  issued and outstanding at December 31, 2014		2,053			1,935
Additional paid-in capital		1,554,671			1,367,346
Accumulated earnings (deficit)		(757,229	)		(786,871	)
Total stockholders' equity		799,495			582,410
Noncontrolling interests		597,119			1,120,554
Total equity		1,396,614			1,702,964
Total liabilities and equity	$	4,617,268		$	4,593,547

See Accompanying Notes to Unaudited Condensed Consolidated and Combined Financial Statements.

8

MEMORIAL RESOURCE DEVELOPMENT CORP.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED AND COMBINED OPERATIONS

(In thousands, except per share amounts)

	For the Three Months Ended						For the Nine Months Ended
	September 30,						September 30,
	2015			2014			2015			2014
Revenues:
Oil & natural gas sales	$	199,173		$	263,964		$	553,971		$	721,110
Other revenues		564			1,332			2,350			3,584
Total revenues		199,737			265,296			556,321			724,694
Costs and expenses:
Lease operating		53,365			46,211			147,807			111,887
Gathering, processing, and transportation		30,767			19,803			77,087			51,809
Gathering, processing, and transportation - affiliate (Note 13)		9,215			—			13,028			—
Pipeline operating		461			431			1,407			1,596
Exploration		6,209			175			9,287			1,465
Production and ad valorem taxes		9,647			14,040			28,275			33,623
Depreciation, depletion, and amortization		106,340			84,447			280,251			215,906
Impairment of proved oil and natural gas properties		361,836			67,181			613,183			67,181
Incentive unit compensation expense (Note 12)		4,965			25,550			31,305			969,390
General and administrative		25,605			21,196			77,792			61,061
Accretion of asset retirement obligations		1,811			1,553			5,347			4,601
(Gain) loss on commodity derivative instruments		(370,055	)		(189,492	)		(531,838	)		11,580
(Gain) loss on sale of properties		—			—			50			3,057
Other, net		—			—			(943	)		(12	)
Total costs and expenses		240,166			91,095			752,038			1,533,144
Operating income (loss)		(40,429	)		174,201			(195,717	)		(808,450	)
Other income (expense):
Interest expense, net		(40,431	)		(36,345	)		(116,528	)		(104,928	)
Loss on extinguishment of debt		—			—			—			(37,248	)
Other, net		(71	)		15			112			102
Total other income (expense)		(40,502	)		(36,330	)		(116,416	)		(142,074	)
Income (loss) before income taxes		(80,931	)		137,871			(312,133	)		(950,524	)
Income tax benefit (expense)		(54,324	)		(25,834	)		(75,744	)		(14,398	)
Net income (loss)		(135,255	)		112,037			(387,877	)		(964,922	)
Net income (loss) attributable to noncontrolling interest		(191,807	)		102,109			(466,471	)		(34,851	)
Net income (loss) attributable to Memorial Resource    Development Corp.		56,552			9,928			78,594			(930,071	)
Net (income) loss allocated to members		—			—			—			(20,305	)
Net (income) loss allocated to previous owners		—			—			—			(1,425	)
Net (income) allocated to participating restricted stockholders		(501	)		(55	)		(588	)		—
Net income (loss) available to common stockholders	$	56,051		$	9,873		$	78,006		$	(951,801	)
Earnings per common share: (Note 10)
Basic	$	0.29		$	0.05		$	0.41		$	(4.94	)
Diluted	$	0.29		$	0.05		$	0.41		$	(4.94	)
Weighted average common and common    equivalent shares outstanding:
Basic		190,725			192,500			190,353			192,500
Diluted		190,725			192,500			190,353			192,500

See Accompanying Notes to Unaudited Condensed Consolidated and Combined Financial Statements.

9

MEMORIAL RESOURCE DEVELOPMENT CORP.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED AND COMBINED CASH FLOWS

 (In thousands)

	Nine Months Ended
	September 30,
	2015			2014
Cash flows from operating activities:
Net income (loss)	$	(387,877	)	$	(964,922	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization		280,251			215,906
Impairment of proved oil and natural gas properties		613,183			67,181
(Gain) loss on derivatives		(525,210	)		12,737
Cash settlements (paid) received on expired derivative instruments		290,001			(22,174	)
Cash settlements on terminated derivatives		27,063			—
Premiums paid for derivatives		(27,063	)		—
Loss on extinguishment of debt		—			30,248
Amortization of deferred financing costs		6,426			5,492
Accretion of senior notes net discount		1,818			1,888
Accretion of asset retirement obligations		5,347			4,601
Amortization of equity awards		14,034			6,874
Settlement of asset retirement obligations		(780	)		—
(Gain) loss on sale of properties		50			3,057
Non-cash compensation expense		31,305			941,659
Deferred income tax expense (benefit)		68,798			13,916
Changes in operating assets and liabilities:
Accounts receivable		13,759			(22,117	)
Prepaid expenses and other assets		4,134			297
Payables and accrued liabilities		22,391			67,324
Other		789			3,493
Net cash provided by operating activities		438,419			365,460
Cash flows from investing activities:
Acquisitions of oil and natural gas properties		(13,362	)		(1,083,167	)
Acquisition post-closing adjustment receipts		9,570			—
Additions to oil and gas properties		(634,317	)		(457,838	)
Additions to other property and equipment		(3,768	)		(9,134	)
Additions to restricted investments		(3,893	)		(2,883	)
Deposits for property acquisitions		(21,286	)		—
Decrease (increase) in restricted cash		—			49,946
Proceeds from the sale of oil and natural gas properties		13,612			6,700
Other		—			(301	)
Net cash used in investing activities		(653,444	)		(1,496,677	)
Cash flows from financing activities:
Advances on revolving credit facilities		748,000			2,464,800
Payments on revolving credit facilities		(521,000	)		(2,441,900	)
Termination of second lien credit facility		—			(328,282	)
Proceeds from the issuance of senior notes		—			1,092,425
Redemption of senior notes		(2,914	)		(351,808	)
Deferred financing costs		(1,765	)		(30,284	)
Purchase of additional interests in consolidated subsidiaries		—			(3,292	)
Proceeds from MRD equity offering		242,880			408,500
Costs incurred in conjunction with MRD equity offering		(3,979	)		(28,198	)
Proceeds from MEMP equity offering		—			553,288
Costs incurred in conjunction with MEMP equity offering		—			(12,222	)
Contributions from NGP affiliates related to sale of assets		—			1,165
Distribution to MRD Holdco		—			(59,803	)
Distributions to noncontrolling interests		(138,123	)		(101,327	)
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 equity repurchases		(51,197	)		—
MEMP equity repurchases		(55,472	)		—
Other		—			213
Net cash provided by financing activities		216,430			1,063,812
Net change in cash and cash equivalents		1,405			(67,405	)
Cash and cash equivalents, beginning of period		5,958			77,721
Cash and cash equivalents, end of period	$	7,363		$	10,316

See Accompanying Notes to Unaudited Condensed Consolidated and Combined Financial Statements.

10

MEMORIAL RESOURCE DEVELOPMENT CORP.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED AND COMBINED EQUITY

(In thousands)

	Stockholders' Equity									Members' Equity
	Common stock			Additional paid in capital			Accumulated earnings (deficit)			Members			Previous Owners			Noncontrolling Interest			Total
Balance, January 1, 2014	$	—		$	—		$	—		$	237,186		$	40,331		$	580,615		$	858,132
Net income (loss)		—			—			(951,801	)		20,305			1,425			(34,851	)		(964,922	)
Issuance of shares in connection with restructuring transactions		1,710			913,152			—			—			—			—			914,862
Issuance of shares/units in connection with equity offerings		215			379,962			—			—			—			540,987			921,164
Restricted stock awards		11			(11	)		—			—			—			—			—
Tax related effects in connection with restructuring transactions and initial public offering		—			(43,251	)		—			—			—			—			(43,251	)
Contribution related to MRD Holdco incentive unit compensation expense		—			137,307			—			—			—			—			137,307
Contribution related to sale of assets to NGP affiliate		—			—			—			1,165			—			—			1,165
Net book value of assets sold to NGP affiliate		—			—			—			(621	)		—			—			(621	)
Distributions		—			—			—			—			—			(101,327	)		(101,327	)
Net book value of assets acquired from NGP affiliates		—			—			—			45,059			(41,756	)		—			3,303
Purchase of noncontrolling interest		—			(2,881	)		—			—			—			(411	)		(3,292	)
Distribution of net assets to  MRD Holdco		—			—			—			(123,078	)		—			29,994			(93,084	)
Distribution of shares received in connection with restructuring transactions to MRD Holdco		—			—			—			(110,510	)		—			—			(110,510	)
Distribution to NGP affiliates in connection with acquisition of assets		—			—			—			(66,693	)		—			—			(66,693	)
Net equity deemed contribution (distribution) related to net assets transferred to MEMP		—			—			—			(2,659	)		—			2,659			—
Amortization of equity awards		—			1,487			—			—			—			5,387			6,874
Other		—			378			—			(154	)		—			(332	)		(108	)
Balance, September 30 2014	$	1,936		$	1,386,143		$	(951,801	)	$	—		$	—		$	1,022,721		$	1,458,999
Balance, January 1, 2015	$	1,935		$	1,367,346		$	(786,871	)	$	—		$	—		$	1,120,554		$	1,702,964
Net income (loss)		—			—			78,594			—			—			(466,471	)		(387,877	)
Issuance of shares in connection with equity offering		138			242,742			—			—			—			—			242,880
Cost incurred in conjunction with equity offering		—			(4,351	)		—			—			—			—			(4,351	)
Share repurchase		(28	)		—			(47,757	)		—			—			—			(47,785	)
Restricted stock awards		9			(9	)		—			—			—			—			—
Amortization of restricted stock awards		—			6,135			—			—			—			—			6,135
Contribution related to MRD Holdco incentive unit compensation expense (Note 12)		—			31,305			—			—			—			—			31,305
Net equity deemed contribution (distribution) related to MEMP property exchange (Note 1)		—			(127,149	)		—			—			—			127,149			—
Deferred tax adjustments (Note 2)		—			38,778			—			—			—			—			38,778
Distributions		—			—			—			—			—			(138,123	)		(138,123	)
Amortization of MEMP equity awards		—			—			—			—			—			7,899			7,899
MEMP common units repurchased		—			—			—			—			—			(53,999	)		(53,999	)
MRD restricted shares repurchased		(1	)		—			(1,195	)		—			—			—			(1,196	)
Other		—			(126	)		—			—			—			110			(16	)
Balance, September 30, 2015	$	2,053		$	1,554,671		$	(757,229	)	$	—		$	—		$	597,119		$	1,396,614

See Accompanying Notes to Unaudited Condensed Consolidated and Combined Financial Statements.

11

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Note 1. Background, Organization and Basis of Presentation

Overview

Memorial Resource Development Corp. (the “Company”) is a publicly traded Delaware corporation, the common shares of which are listed on the NASDAQ Global Market (“NASDAQ”) under the symbol “MRD.” Unless the context requires otherwise, references to “we,” “us,” “our,” “MRD,” or “the Company” are intended to mean the business and operations of Memorial Resource Development Corp. and its consolidated subsidiaries.

References to: (i) “Memorial Production Partners,” “MEMP” and “the Partnership” refer to Memorial Production Partners LP individually and collectively with its subsidiaries, as the context requires; (ii) “MEMP GP” refer to Memorial Production Partners GP LLC, the general partner of the Partnership, which we own; (iii) “MRD Holdco” refer to MRD Holdco LLC, a holding company controlled by the Funds (defined below) that, together as part of a group, owns a majority of our common stock; (iv) “MRD LLC” refer to Memorial Resource Development LLC, which historically owned our predecessor’s business and was merged into MRD Operating LLC (“MRD Operating”), our 100% owned subsidiary, subsequent to our initial public offering; (v) “WildHorse Resources” refer to WildHorse Resources, LLC, which owned our interest in the Terryville Complex and merged into MRD Operating in February 2015; (vi) “our predecessor” refer collectively to MRD LLC and its former consolidated subsidiaries, consisting of Classic Hydrocarbons Holdings, L.P., Classic Hydrocarbons GP Co., L.L.C., Black Diamond Minerals, LLC, Beta Operating Company, LLC, MEMP GP, BlueStone Natural Resources Holdings, LLC (“BlueStone”), MRD Operating, WildHorse Resources, Tanos Energy LLC and each of their respective subsidiaries, including MEMP and its subsidiaries; (vii) “the Funds” refer collectively to Natural Gas Partners VIII, L.P., Natural Gas Partners IX, L.P. and NGP IX Offshore Holdings, L.P., which collectively control MRD Holdco; and (viii) “NGP” refer to Natural Gas Partners, a family of private equity investment funds organized to make direct equity investments in the energy industry, including the Funds.

Previous Owners

References to “the previous owners” for accounting and financial reporting purposes refer to the net profits interest that WildHorse Resources purchased from NGP Income Co-Investment Fund II, L.P. (“NGPCIF”) in February 2014 (“NGPCIF NPI”). NGPCIF is controlled by NGP. Upon the completion of certain acquisitions in 2010, WildHorse Resources sold a net profits interest in these properties to NGPCIF. Since WildHorse Resources sold the net profits interest, the historical results are accounted for as a working interest for all periods.

Our unaudited financial statements reported herein include the financial position and results attributable to NGPCIF NPI.

Basis of Presentation

The financial statements reported herein include the financial position and results attributable to both our predecessor and the previous owners on a combined basis for periods prior to our initial public offering. For periods after the completion of our initial public offering, our consolidated financial statements include our accounts and those of our subsidiaries in which we have a controlling interest. Due to our control of MEMP through our ownership of MEMP GP, we are required to consolidate MEMP for accounting and financial reporting purposes. MEMP is owned 99.9% by its limited partners and 0.1% by MEMP GP.

Certain amounts in the prior year financial statements have been reclassified to conform to current presentation. Gathering, processing, and transportation costs were previously accounted for as revenue deductions and are now being presented as costs and expenses on our statements of operations on a separate line item.

All material intercompany transactions and balances have been eliminated in preparation of our consolidated and combined financial statements. Our results of operations for the three and nine months ended September 30, 2015 are not necessarily indicative of results expected for the full year. In our opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments of a normal recurring nature necessary for fair presentation. Although we believe the disclosures in these financial statements are adequate and make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted pursuant to the rules and regulations of the United States Securities and Exchange Commission (“SEC”).

We have two reportable business segments, both of which are engaged in the acquisition, exploration and development of oil and natural gas properties (See Note 14). Our reportable business segments are as follows:

· MRD—reflects the combined operations of the Company and its consolidating subsidiaries except for MEMP and its subsidiaries.

· MEMP—reflects the combined operations of MEMP and its subsidiaries.

12

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Segment financial information has been retrospectively revised for the acquisition by the MEMP Segment of certain assets from the MRD Segment in East Texas in February 2015 in exchange for approximately $78.4 million in cash and certain properties in North Louisiana (the “Property Swap”) for comparability purposes. Our equity statement reflects a $127.1 million equity transfer from stockholders’ equity to noncontrolling interest related to this transaction.

Use of Estimates

The preparation of the accompanying unaudited condensed consolidated and combined financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated and combined financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Significant estimates include, but are not limited to, oil and natural gas reserves; depreciation, depletion, and amortization of proved oil and natural gas properties; future cash flows from oil and natural gas properties; impairment of long-lived assets; fair value of derivatives; fair value of equity compensation; fair values of assets acquired and liabilities assumed in business combinations, income taxes and asset retirement obligations.

Note 2. Summary of Significant Accounting Policies

A discussion of our critical accounting policies and estimates is included in our Current Report on Form 8-K filed on July 8, 2015 (our “Recast Form 8-K”).  Our Recast Form 8-K was filed to retrospectively revise certain historical segment financial information to give effect to the Property Swap for comparability purposes and to include a new note containing condensed consolidating financial information.

Accrued liabilities

Current accrued liabilities consisted of the following at the dates indicated (in thousands):

	September 30,		December 31,
	2015		2014
Accrued capital expenditures	$	84,698	$	80,350
Accrued lease operating expense		18,495		16,403
Accrued general and administrative expenses		14,035		8,516
Accrued ad valorem taxes		15,010		8,870
Accrued interest payable		36,810		24,797
Accrued income tax payable		4,942		52
Accrued environmental		588		2,092
Other miscellaneous, including operator advances		2,021		6,043
	$	176,599	$	147,123

Supplemental Cash Flow Information

Supplemental cash flow for the periods presented (in thousands):

	For the Nine Months Ended
	September 30,
	2015		2014
Supplemental cash flows:
Cash paid for interest, net of capitalized interest	$	93,038	$	67,449
Cash paid for taxes		2,055		550
Noncash investing and financing activities:
Increase (decrease) in capital expenditures in payables and accrued liabilities		4,348		29,137
(Increase) decrease in accounts receivable related to acquisitions and divestitures		9,570		(4,271	)
Accrued expenses related to MRD equity offering		372		—

Income Tax

MRD is a corporation subject to federal and certain state income taxes. The net income (loss) attributable to noncontrolling interest is related to MEMP, which is a pass-through entity for federal income tax purposes. As discussed in Note 12, the compensation expense associated with the incentive units of MRD Holdco creates a nondeductible permanent difference for income tax purposes. MRD’s predecessor was organized as a pass-through entity for federal income tax purposes and was not subject to federal income taxes prior to our initial public offering in June 2014; however, certain of its consolidating subsidiaries were subject to federal and certain state income taxes. 

MRD reported no liability for unrecognized tax benefits as of September 30, 2015 and expects no significant change to the unrecognized tax benefits in the next twelve months. 

13

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

MRD’s effective tax rate for the three and nine months ended September 30, 2015 was negative 67.1% and negative 24.3%, respectively, and the effective tax rate for the three and nine months ended September 30, 2014 was 18.7% and negative 1.5%, respectively. The effective tax rate for the three and nine months ended September 30, 2014 and 2015 differs from the statutory federal income tax rate primarily due to the following recurring items:

· earnings from the MEMP Segment pass-through entities;

· non-deductible incentive unit compensation; and

· state income tax, net of federal benefit.

MRD reported a $38.8 million increase to equity during the nine months ended September 30, 2015, of which $4.4 million was associated with the estimated deferred tax effects included in equity in connection with its initial public offering and $34.4 million was attributable to the deferred tax effects of the property exchanges under common control including certain oil and gas properties in East Texas that MEMP acquired from MRD in February 2015. 

New Accounting Pronouncements

Simplifying the Accounting for Measurement-Period Adjustments. In September 2015, the Financial Accounting Standards Board ("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 does not expect the impact of adopting this guidance to be material to the Company's financial statements and related 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.

14

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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 currently believe we will continue to consolidate MEMP and become subject to the VIE primary beneficiary disclosure requirements. The deconsolidation of MEMP would have a material impact on our consolidated financial statements and related disclosuresin the event there is a reconsideration event that triggers deconsolidation.

Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Company’s financial position, results of operations and cash flows.

Note 3. Acquisitions and Divestitures

Transaction-related costs, which include costs associated with acquisitions and divestitures, are included in general and administrative expenses in the accompanying statements of operations for the periods indicated below (in thousands):

For the Three Months Ended				For the Nine Months Ended
September 30,				September 30,
2015		2014		2015		2014
$	229	$	1,425	$	3,232	$	5,480

2015 Acquisitions

Subsequent event. On October 22, 2015, MRD closed a transaction to acquire certain producing and non-producing oil and natural gas properties in North Louisiana from a third party for approximately $284.0 million, subject to customary post-closing adjustments.

2015 Divestitures

On April 17, 2015, MRD sold certain oil and natural gas properties in Colorado and Wyoming to a third party for approximately $13.6 million (the “Rockies Divestiture”) and recorded a loss of less than $0.1 million related to the sale.

2014 Acquisitions

On March 25, 2014, MEMP closed a transaction to acquire certain oil and natural gas producing properties in the Eagle Ford from a third party for approximately $168.1 million, including customary post-closing adjustments (the “Eagle Ford Acquisition”).

On July 1, 2014, MEMP closed a transaction to acquire certain oil and natural gas liquids properties in Wyoming from a third party for approximately $906.1 million, including customary post-closing adjustments (the “Wyoming Acquisition”).

The following unaudited pro forma combined results of operations are provided for the nine months ended September 30, 2014 as though the Wyoming Acquisition had been completed on January 1, 2013. The unaudited pro forma financial information was derived from the historical combined statements of operations of the Company and the previous owners and adjusted to include: (i) the revenues and direct operating expenses associated with oil and gas properties acquired, (ii) depletion expense applied to the adjusted basis of the properties acquired and (iii) interest expense on additional borrowings necessary to finance the acquisition. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of expected future results of operations.

	For the Nine Months Ended
	September 30,
	2014
MRD Consolidated and Combined	(In thousands)
Revenues	$	815,893
Net income (loss)		(930,903	)
Basic and diluted earnings per share	$	(4.94	)

15

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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.

Note 4. Fair Value Measurements of Financial Instruments

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. Fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk. A three-tier hierarchy has been established that classifies fair value amounts recognized or disclosed in the financial statements. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3). All of the derivative instruments reflected on the accompanying balance sheets were considered Level 2.

The carrying values of accounts receivables, accounts payables (including accrued liabilities), restricted investments and amounts outstanding under long-term debt agreements with variable rates included in the accompanying balance sheets approximated fair value at September 30, 2015 and December 31, 2014. The fair value estimates are based upon observable market data and are classified within Level 2 of the fair value hierarchy. These assets and liabilities are not presented in the following tables. See Note 8 for the estimated fair value of our outstanding fixed-rate debt.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The fair market values of the derivative financial instruments reflected on the balance sheets as of September 30, 2015 and December 31, 2014 were based on estimated forward commodity prices (including nonperformance risk) and forward interest rate yield curves. Nonperformance risk is the risk that the obligation related to the derivative instrument will not be fulfilled. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement in its entirety. The significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

The following table presents the gross derivative assets and liabilities that are measured at fair value on a recurring basis at September 30, 2015 and December 31, 2014 for each of the fair value hierarchy levels:

	Fair Value Measurements at September 30, 2015 Using
	Quoted Prices in		Significant Other		Significant
	Active		Observable		Unobservable
	Market		Inputs		Inputs
	(Level 1)		(Level 2)		(Level 3)		Fair Value
	(In thousands)
Assets:
Commodity derivatives	$	—	$	1,095,235	$	—	$	1,095,235
Interest rate derivatives		—		—		—		—
Total assets	$	—	$	1,095,235	$	—	$	1,095,235
Liabilities:
Commodity derivatives	$	—	$	82,529	$	—	$	82,529
Interest rate derivatives		—		5,360		—		5,360
Total liabilities	$	—	$	87,889	$	—	$	87,889

	Fair Value Measurements at December 31, 2014 Using
	Quoted Prices in		Significant Other		Significant
	Active		Observable		Unobservable
	Market		Inputs		Inputs
	(Level 1)		(Level 2)		(Level 3)		Fair Value
	(In thousands)
Assets:
Commodity derivatives	$	—	$	845,759	$	—	$	845,759
Interest rate derivatives		—		1,305		—		1,305
Total assets	$	—	$	847,064	$	—	$	847,064
Liabilities:
Commodity derivatives	$	—	$	71,639	$	—	$	71,639
Interest rate derivatives		—		3,289		—		3,289
Total liabilities	$	—	$	74,928	$	—	$	74,928

16

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

See Note 5 for additional information regarding our derivative instruments.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Certain assets and liabilities are reported at fair value on a nonrecurring basis as reflected on the balance sheets. The following methods and assumptions are used to estimate the fair values:

· The fair value of asset retirement obligations (“AROs”) is based on discounted cash flow projections using numerous estimates, assumptions, and judgments regarding factors such as the existence of a legal obligation for an ARO; amounts and timing of settlements; the credit-adjusted risk-free rate; and inflation rates. See Note 6 for a summary of changes in AROs.

·  If sufficient market data is not available, the determination of the fair values of proved and unproved properties acquired in transactions accounted for as business combinations are prepared by utilizing estimates of discounted cash flow projections. The factors to determine fair value include, but are not limited to, estimates of: (i) economic reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital.

· Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such properties. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and natural gas properties.

· During the three and nine months ended September 30, 2015, MEMP recognized $361.8 million and $613.2 million, respectively, of impairments related to certain properties located in East Texas, South Texas, the Permian, Wyoming and Colorado. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable primarily as a result of declining commodity prices. As a result of the impairments, the carrying value of these properties was reduced to approximately $407.7 million. MEMP recorded $67.2 million of impairments during the three and nine months ended September 30, 2014 primarily related to certain properties located in South Texas. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable in part due to a downward revision of estimated proved reserves based on declining commodity prices and increased operating costs .

17

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Note 5. Risk Management and Derivative Instruments

Derivative instruments are utilized to manage exposure to commodity price and interest rate fluctuations and achieve a more predictable cash flow in connection with natural gas and oil sales from production and borrowing related activities. These instruments limit exposure to declines in prices or increases in interest rates, but also limit the benefits that would be realized if prices increase or interest rates decrease.

Certain inherent business risks are associated with commodity and interest derivative contracts, including market risk and credit risk. Market risk is the risk that the price of natural gas or oil will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the counterparty to a contract. It is our policy to enter into derivative contracts, including interest rate swaps, only with creditworthy counterparties, which generally are financial institutions, deemed by management as competent and competitive market makers. Some of the lenders, or certain of their affiliates, under our credit agreements are counterparties to our derivative contracts. While collateral is generally not required to be posted by counterparties, credit risk associated with derivative instruments is minimized by limiting exposure to any single counterparty and entering into derivative instruments only with counterparties that are large financial institutions, which management believes present minimal credit risk. Additionally, master netting agreements are used to mitigate risk of loss due to default with counterparties on derivative instruments. We have also entered into the International Swaps and Derivatives Association Master Agreements (“ISDA Agreements”) with each of our counterparties. The terms of the ISDA Agreements provide us and each of our counterparties with rights of set-off upon the occurrence of defined acts of default by either us or our counterparty to a derivative, whereby the party not in default may set-off all liabilities owed to the defaulting party against all net derivative asset receivables from the defaulting party.

At September 30, 2015, MEMP had net derivative assets of $663.9 million. After taking into effect netting arrangements, MEMP had counterparty exposure of $345.9 million related to its derivative instruments of which $115.3 million was with a single counterparty. Had all counterparties failed completely to perform according to the terms of their existing contracts, MEMP would have the right to offset $320.3 million against amounts outstanding under its revolving credit facility at September 30, 2015. At September 30, 2015, MRD had net derivative assets of $343.6 million. After taking into effect netting arrangements, MRD had counterparty exposure of $277.9 million related to derivative instruments of which $91.4 million was with a single counterparty. Had all counterparties failed completely to perform according to the terms of their existing contracts, MRD would have the right to offset $65.7 million against amounts outstanding under its revolving credit facility at September 30, 2015. See Note 8 for additional information regarding our revolving credit facilities.

Commodity Derivatives

We may use a combination of commodity derivatives (e.g., floating-for-fixed swaps, put options, costless collars and basis swaps) to manage exposure to commodity price volatility. We recognize all derivative instruments at fair value; however, certain of our derivative instruments have a deferred premium. The deferred premium is factored into the fair value measurement and the Company agrees to defer the premium paid or received until the time of settlement. Cash settlements received on settled derivative positions during the nine months ended September 30, 2015 is net of deferred premiums of $7.1 million.

In February 2015, MEMP restructured a portion of its commodity derivative portfolio by effectively terminating “in-the-money” crude oil derivatives settling in 2015 through 2017 and entering into NGL derivatives with the same tenor. Cash settlement receipts of approximately $27.1 million from the termination of the crude oil derivatives were applied as premiums for the new NGL derivatives.

We enter into natural gas derivative contracts that are indexed to NYMEX-Henry Hub and regional indices such as NGPL TXOK, TETCO STX, TGT Z1, and Houston Ship Channel in proximity to our areas of production. We also enter into oil derivative contracts indexed to a variety of locations such as NYMEX-WTI, Inter-Continental Exchange (“ICE”) Brent, California Midway-Sunset and other regional locations. Our NGL derivative contracts are primarily indexed to OPIS Mont Belvieu.

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MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

At September 30, 2015, the MRD Segment had the following open commodity positions:

	Remaining
	2015			2016			2017			2018
Natural Gas Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (MMBtu)		3,400,000			2,570,000			1,770,000			4,600,000
Weighted-average fixed price	$	4.15		$	4.09		$	4.24		$	4.06
Collar contracts:
Average Monthly Volume (MMBtu)		130,000			1,100,000			1,050,000			—
Weighted-average floor price	$	4.00		$	4.00		$	4.00		$	—
Weighted-average ceiling price	$	4.64		$	4.71		$	5.06		$	—
Purchased put option contracts:
Average Monthly Volume (MMBtu)		4,100,000			6,000,000			5,350,000			3,450,000
Weighted-average strike price	$	3.75		$	3.51		$	3.48		$	3.62
Weighted-average deferred premium paid	$	(0.33	)	$	(0.34	)	$	(0.32	)	$	(0.34	)
Written call option contracts (1):
Average Monthly Volume (MMBtu)		3,225,000			—			—			—
Weighted-average sold strike price	$	3.75		$	—		$	—		$	—
Weighted-average deferred premium received	$	0.08		$	—		$	—		$	—
TGT Z1 basis swaps:
Average Monthly Volume (MMBtu)		3,380,000			1,120,000			200,000			—
Spread - Henry Hub	$	(0.10	)	$	(0.10	)	$	(0.08	)	$	—
Crude Oil Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		42,000			8,500			28,000			31,625
Weighted-average fixed price	$	91.67		$	84.80		$	84.70		$	84.50
Collar contracts:
Average Monthly Volume (Bbls)		2,000			27,000			—			—
Weighted-average floor price	$	85.00		$	80.00		$	—		$	—
Weighted-average ceiling price	$	101.35		$	99.70		$	—		$	—
Purchased put option contracts:
Average Monthly Volume (Bbls)		39,000			—			—			—
Weighted-average strike price	$	85.00		$	—		$	—		$	—
Weighted-average deferred premium paid	$	(3.80	)	$	—		$	—		$	—
Written call option contracts (1):
Average Monthly Volume (Bbls)		29,250			—			—			—
Weighted-average sold strike price	$	85.00		$	—		$	—		$	—
Weighted-average deferred premium received	$	0.48		$	—		$	—		$	—
NGL Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		163,000			185,658			—			—
Weighted-average fixed price	$	41.52		$	34.06		$	—		$	—

(1) These transactions were entered into for the purpose of creating a ceiling on our put options, which effectively converted the applicable puts into swaps.

19

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

At September 30, 2015, the MEMP Segment had the following open commodity positions:

	Remaining
	2015			2016			2017			2018			2019
Natural Gas Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (MMBtu)		3,359,237			3,592,442			3,350,067			3,060,000			2,814,583
Weighted-average fixed price	$	4.08		$	4.14		$	4.06		$	4.18		$	4.31
Collar contracts:
Average Monthly Volume (MMBtu)		350,000			—			—			—			—
Weighted-average floor price	$	4.62		$	—		$	—		$	—		$	—
Weighted-average ceiling price	$	5.80		$	—		$	—		$	—		$	—
Call spreads (1):
Average Monthly Volume (MMBtu)		80,000			—			—			—			—
Weighted-average sold strike price	$	5.25		$	—		$	—		$	—		$	—
Weighted-average bought strike price	$	6.75		$	—		$	—		$	—		$	—
Basis swaps:
Average Monthly Volume (MMBtu)		3,690,000			3,578,333			2,210,000			1,315,000			900,000
Spread	$	(0.12	)	$	(0.07	)	$	(0.04	)	$	(0.02	)	$	0.01
Crude Oil Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		272,531			279,813			301,600			312,000			160,000
Weighted-average fixed price	$	91.34		$	86.87		$	84.70		$	83.74		$	85.52
Collar contracts:
Average Monthly Volume (Bbls)		5,000			—			—			—			—
Weighted-average floor price	$	80.00		$	—		$	—		$	—		$	—
Weighted-average ceiling price	$	94.00		$	—		$	—		$	—		$	—
Basis swaps:
Average Monthly Volume (Bbls)		97,000			95,000			30,000			—			—
Spread	$	(7.06	)	$	(9.56	)	$	(2.35	)	$	—		$	—
NGL Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		209,200			213,100			43,300			—			—
Weighted-average fixed price	$	42.38		$	35.64		$	37.55		$	—		$	—

(1) These transactions were entered into for the purpose of eliminating the ceiling portion of certain collar arrangements, which effectively converted the applicable collars into swaps.

20

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

The MEMP Segment basis swaps included in the table above is presented on a disaggregated basis below:

	Remaining
	2015			2016			2017			2018			2019
Natural Gas Derivative Contracts:
NGPL TexOk basis swaps:
Average Monthly Volume (MMBtu)		3,030,000			3,003,333			1,800,000			1,200,000			900,000
Spread - Henry Hub	$	(0.11	)	$	(0.07	)	$	(0.07	)	$	(0.03	)	$	0.01
HSC basis swaps:
Average Monthly Volume (MMBtu)		150,000			135,000			115,000			115,000			—
Spread - Henry Hub	$	(0.08	)	$	0.07		$	0.14		$	0.15		$	—
CIG basis swaps:
Average Monthly Volume (MMBtu)		210,000			170,000			—			—			—
Spread - Henry Hub	$	(0.25	)	$	(0.30	)	$	—		$	—		$	—
TETCO STX basis swaps:
Average Monthly Volume (MMBtu)		300,000			270,000			295,000			—			—
Spread - Henry Hub	$	(0.09	)	$	0.06		$	0.03		$	—		$	—
Crude Oil Derivative Contracts:
Midway-Sunset basis swaps:
Average Monthly Volume (Bbls)		57,000			55,000			—			—			—
Spread - Brent	$	(9.73	)	$	(13.35	)	$	—		$	—		$	—
Midland basis swaps:
Average Monthly Volume (Bbls)		40,000			40,000			30,000			—			—
Spread - WTI	$	(3.25	)	$	(4.34	)	$	(2.35	)	$	—		$	—

Interest Rate Swaps

Periodically, we enter into interest rate swaps to mitigate exposure to market rate fluctuations by converting variable interest rates such as those in our credit agreements to fixed interest rates. From time to time we enter into offsetting positions to avoid being economically over-hedged. At September 30, 2015, we had the following interest rate swap open positions:

	Remaining
Credit Facility	2015			2016			2017			2018
MEMP:
Average Monthly Notional (in thousands)	$	400,000		$	400,000		$	400,000		$	100,000
Weighted-average fixed rate		0.943	%		0.943	%		1.612	%		1.946	%
Floating rate	1 Month LIBOR			1 Month LIBOR			1 Month LIBOR			1 Month LIBOR

21

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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 September 30, 2015 and December 31, 2014. There was no cash collateral received or pledged associated with our derivative instruments since most of the counterparties, or certain of their affiliates, to our derivative contracts are lenders under our collective credit agreements.

		Asset Derivatives						Liability Derivatives
		September 30,			December 31,			September 30,			December 31,
Type	Balance Sheet Location	2015			2014			2015			2014
		(In thousands)
Commodity contracts	Short-term derivative instruments	$	428,389		$	378,908		$	46,127		$	38,852
Interest rate swaps	Short-term derivative instruments		—			—			2,229			3,289
Gross fair value			428,389			378,908			48,356			42,141
Netting arrangements	Short-term derivative instruments		(44,841	)		(38,852	)		(44,841	)		(38,852	)
Net recorded fair value	Short-term derivative instruments	$	383,548		$	340,056		$	3,515		$	3,289
Commodity contracts	Long-term derivative instruments	$	666,846		$	466,851		$	36,402		$	32,787
Interest rate swaps	Long-term derivative instruments		—			1,305			3,131			—
Gross fair value			666,846			468,156			39,533			32,787
Netting arrangements	Long-term derivative instruments		(36,350	)		(32,787	)		(36,350	)		(32,787	)
Net recorded fair value	Long-term derivative instruments	$	630,496		$	435,369		$	3,183		$	—

(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 periods indicated (in thousands):

		For the Three Months Ended						For the Nine Months Ended
	Statements of	September 30,						September 30,
	Operations Location	2015			2014			2015			2014
Commodity derivative contracts	(Gain) loss on commodity derivatives	$	(370,055	)	$	(189,492	)	$	(531,838	)	$	11,580
Interest rate derivatives	Interest expense, net		3,543			(175	)		6,628			1,157

Note 6. Asset Retirement Obligations

Asset retirement obligations primarily relate to our portion of future plugging and abandonment costs for wells and related facilities. The following table presents the changes in the asset retirement obligations for the nine months ended September 30, 2015 (in thousands):

Asset retirement obligations at beginning of period	$	122,531
Liabilities added from acquisitions or drilling		1,565
Liabilities settled		(780	)
Revision of estimates		573
Liabilities removed upon sale of wells		(176	)
Accretion expense		5,347
Asset retirement obligations at end of period	$	129,060

22

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Note 7. Restricted Investments

Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with offshore Southern California oil and gas properties owned by MEMP. The components of the restricted investment balance consisted of the following at the dates indicated:

	September 30,		December 31,
	2015		2014
	(In thousands)
BOEM platform abandonment (See Note 15)	$	73,488	$	69,954
BOEM lease bonds		794		794
SPBPC Collateral:
Contractual pipeline and surface facilities abandonment		3,060		2,701
California State Lands Commission pipeline right-of-way bond		3,005		3,005
City of Long Beach pipeline facility permit		500		500
Federal pipeline right-of-way bond		307		307
Port of Long Beach pipeline license		100		100
Restricted investments	$	81,254	$	77,361

Note 8. Long Term Debt

The following table presents our consolidated debt obligations at the dates indicated:

	September 30,			December 31,
	2015			2014
	(In thousands)
MRD Segment:
MRD $2.0 billion revolving credit facility, variable-rate, due June 2019	$	126,000		$	183,000
5.875% senior unsecured notes, due July 2022 ("MRD Senior Notes") (1) (4)		600,000			600,000
Subtotal		726,000			783,000
MEMP Segment:
MEMP $2.0 billion revolving credit facility, variable-rate, due March 2018		696,000			412,000
7.625% senior unsecured notes, due May 2021 ("2021 Senior Notes") (2) (4)		700,000			700,000
6.875% senior unsecured notes, due August 2022 ("2022 Senior Notes") (3) (4)		496,990			500,000
Unamortized discounts		(14,726	)		(16,587	)
Subtotal		1,878,264			1,595,413
Total long-term debt	$	2,604,264		$	2,378,413

(1) The estimated fair value of this fixed-rate debt was $547.5 million and $534.0 million at September 30, 2015 and December 31, 2014, respectively.

(2) The estimated fair value of this fixed-rate debt was $469.0 million and $563.5 million at September 30, 2015 and December 31, 2014, respectively.

(3) The estimated fair value of this fixed-rate debt was $303.2 million and $380.0 million at September 30, 2015 and December 31, 2014, respectively.

(4) The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.

Borrowing Base

Credit facilities tied to borrowing bases are common throughout the oil and gas industry. Each of the revolving credit facilities’ borrowing base is subject to redetermination, on at least a semi-annual basis, primarily based on estimated proved reserves. The borrowing base for each credit facility was the following at the date indicated (in thousands):

	September 30,
	2015
MRD Segment:
MRD $2.0 billion revolving credit facility, variable-rate, due June 2019	$	1,000,000
MEMP Segment:
MEMP $2.0 billion revolving credit facility, variable-rate, due March 2018		1,300,000

On September 18, 2015, the borrowing base under the MRD revolving credit facility was increased to $1.0 billion in connection with the semi-annual borrowing base redetermination by the lenders, and can increase to $1.05 billion, subject to certain conditions, if MRD consummates a certain potential acquisition before December 31, 2015, as acknowledged by the parties in the fifth amendment to the revolving credit agreement.

23

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Subsequent event. On November 4, 2015, MEMP’s borrowing base under its revolving credit facility was redetermined in connection with the semi-annual borrowing base redetermination by the lendersand decreased to approximately $1.18billion.

Weighted-Average Interest Rates

The following table presents the weighted-average interest rates paid on our consolidated variable-rate debt obligations for the periods presented:

	For the Three Months Ended						For the Nine Months Ended
Credit Facility	September 30,						September 30,
	2015			2014			2015			2014
MRD Segment:
MRD revolving credit facility		1.94	%		2.62	%		1.86	%		2.15	%
WildHorse Resources revolver terminated June 2014	n/a			n/a			n/a				4.04	%
WildHorse Resources second lien terminated June 2014	n/a			n/a			n/a				6.44	%
MEMP Segment:
MEMP revolving credit facility		2.14	%		2.16	%		2.06	%		2.08	%

Unamortized Deferred Financing Costs

Unamortized deferred financing costs associated with our consolidated debt obligations were as follows at the dates indicated:

	September 30,		December 31,
	2015		2014
	(In thousands)
MRD Segment:
MRD revolving credit facility	$	5,264	$	4,285
MRD Senior Notes		11,355		12,455
MEMP Segment:
MEMP revolving credit facility		4,534		6,468
2021 Senior Notes		11,722		13,308
2022 Senior Notes		7,375		7,958
	$	40,250	$	44,474

Note 9. Stockholders’ Equity and Noncontrolling Interests

Common Stock

The Company's authorized capital stock includes 600,000,000 shares of common stock, $0.01 par value per share. The following is a summary of the changes in our common shares issued for the nine months ended September 30, 2015:

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	(30,209	)
Balance September 30, 2015	205,318,103

(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. Restricted shares of common stock are considered issued and outstanding on the grant date of the restricted stock award.

On September 25, 2015, MRD 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 $238.4 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 as of September 30, 2015 and subsequently re-borrowed to fund a portion of the purchase price of the North Louisiana Acquisition that closed on October 22, 2015.

24

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Share Repurchase Program

MRD repurchased 2,764,887 shares of common stock under the December 2014 repurchase program for an aggregate price of $47.8 million through March 16, 2015, which exhausted the December 2014 repurchase program. MRD has retired all of the shares of common stock repurchased and the shares of common stock are no longer issued or outstanding.

In April 2015, the board of directors (“Board”) of the Company authorized the repurchase of up to $50.0 million of the Company’s outstanding common stock from time to time on the open market, through block trades or otherwise. The Company is not obligated to repurchase any dollar amount or specific number of shares of its common stock under the program, which may be suspended or discontinued at any time. The amount, timing and price of purchases will depend on market conditions and other factors. The Company did not repurchase any shares of common stock under this program through September 30, 2015.

Noncontrolling Interests

Noncontrolling interests is the portion of equity ownership in the Company’s consolidated subsidiaries not attributable to the Company and primarily consists of the equity interests held by: (i) the limited partners of MEMP and (ii) a third party investor in the San Pedro Bay Pipeline Company. Prior to our initial public offering, certain current or former key employees of certain of MRD LLC’s subsidiaries also held equity interests in those subsidiaries.

Distributions paid to the limited partners of MEMP primarily represent the quarterly cash distributions paid to MEMP’s unitholders, excluding those paid to MRD LLC prior to our initial public offering. Contributions received from limited partners of MEMP primarily represent net cash proceeds received from common unit offerings.

During the nine months ended September 30, 2015, MEMP repurchased 3,547,921 common units under its repurchase program for an aggregate price of $52.8 million. MEMP has retired all common units repurchased and those common units are no longer issued or outstanding.

On July 15, 2014, MEMP sold 9,890,000 common units representing limited partner interests in MEMP (including 1,290,000 common units sold pursuant to the full exercise of the underwriters’ option to purchase additional common units) to the underwriters at a negotiated price of $22.25 per unit generating total net proceeds of approximately $220.0 million after deducting offering expenses. The net proceeds from the equity offering were used to repay a portion of the outstanding borrowings under MEMP’s revolving credit facility.

On September 9, 2014, MEMP issued 14,950,000 common units representing limited partner interests in MEMP (including 1,950,000 common units sold pursuant to the full exercise of the underwriters’ option to purchase additional common units) to the public at an offering price of $22.29 per unit generating total net proceeds of approximately $321.3 million after deducting underwriting discounts and offering expenses. The net proceeds from the equity offering were used to repay a portion of the outstanding borrowings under MEMP’s revolving credit facility.

25

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Note 10. Earnings per Share

The following sets forth the calculation of earnings (loss) per share, or EPS, for the periods indicated (in thousands, except per share amounts):

	For the Three Months Ended				For the Nine Months Ended
	September 30,				September 30,
	2015		2014		2015		2014
Numerator:
Net income (loss) available to common stockholders	$	56,051	$	9,873	$	78,006	$	(951,801	)
Denominator:
Weighted average common shares outstanding		190,725		192,500		190,353		192,500
Incremental treasury stock method shares (1)		86		216		410		207
Basic EPS	$	0.29	$	0.05	$	0.41	$	(4.94	)
Diluted EPS (1)	$	0.29	$	0.05	$	0.41	$	(4.94	)

(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.

Note 11. Long-Term Incentive Plans

MRD

The following table summarizes information regarding restricted common share awards granted under the Memorial Resource Development Corp. 2014 Long-Term Incentive Plan for the periods presented:

	Number of Shares			Weighted-Average Grant Date Fair Value per Share (1)
Restricted common shares outstanding at December 31, 2014		1,059,211		$	19.00
Granted (2)		938,558		$	18.80
Forfeited		(30,209	)	$	18.86
Vested		(274,355	)	$	19.00
Restricted common shares outstanding at September 30, 2015		1,693,205		$	18.89

(1) Determined by dividing the aggregate grant date fair value of awards issued.

(2) The aggregate grant date fair value of restricted common share awards issued in 2015 was $17.6 million based on a grant date market price 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 Three Months Ended				For the Nine Months Ended
September 30,				September 30,
2015		2014		2015		2014
$	2,692	$	1,312	$	6,135	$	1,487

The unrecognized compensation cost associated with restricted common share awards was $28.1 million at September 30, 2015. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.66 years.

26

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

MEMP

The following table summarizes information regarding restricted common unit awards granted under the Memorial Production Partners GP LLC Long-Term Incentive Plan for the periods presented:

	Number of Units			Weighted-Average Grant Date Fair Value per Unit (1)
Restricted common units outstanding at December 31, 2014		1,093,520		$	20.93
Granted (2)		815,607		$	15.04
Forfeited		(32,876	)	$	19.61
Vested		(483,627	)	$	20.37
Restricted common units outstanding at September 30, 2015		1,392,624		$	17.70

(1) Determined by dividing the aggregate grant date fair value of awards issued.

(2) The aggregate grant date fair value of restricted common unit awards issued in 2015 was $12.3 million based on a grant date market price ranging from $14.70 to $15.45 per unit.

The following table summarizes the amount of recognized compensation expense associated with these awards that are reflected in the accompanying statements of operations for the periods presented (in thousands):

For the Three Months Ended				For the Nine Months Ended
September 30,				September 30,
2015		2014		2015		2014
$	2,993	$	2,427	$	7,899	$	5,387

The unrecognized compensation cost associated with restricted common unit awards was $20.0 million at September 30, 2015. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.03 years. Since the restricted common units are participating securities, distributions received by the restricted common unitholders are generally included in distributions to noncontrolling interests as presented on our unaudited condensed statements of consolidated and combined cash flows.

Note 12. Incentive Units

MRD Holdco

MRD LLC incentive units were originally granted in June 2012 and February 2013. In connection with our initial public offering and the related restructuring transactions, these incentive units were exchanged for substantially identical units in MRD Holdco, and such incentive units entitle holders thereof to portions of future distributions by MRD Holdco. MRD Holdco’s governing documents authorize the issuance of 1,000 incentive units, of which 930 incentive units were granted in an exchange for the cancelled MRD LLC awards (the “Exchanged Incentive Units”). Subsequent to our initial public offering, MRD Holdco granted the remaining 70 incentive units to certain key employees (the “Subsequent Incentive Units”).

We recognized $5.0 million and $31.3 million of compensation expense for the three and nine months ending September 30, 2015, respectively, offset by a deemed capital contribution from MRD Holdco and the unrecognized compensation expense of approximately $72.7 million as of September 30, 2015 will be recognized over the remaining expected service period of 1.67 years.

The fair value of the Exchanged and Subsequent Incentive Units will be remeasured on a quarterly basis until all payments have been made. The settlement obligation rests with MRD Holdco. Accordingly, no payments will ever be made by us related to these incentive units; however, non-cash compensation expense will be allocated to us in future periods offset by deemed capital contributions. As such, these awards are not dilutive to our stockholders.

The fair value of the incentive units was estimated using a Monte Carlo simulation valuation model with the following assumptions:

	Exchanged Incentive Units			Subsequent Incentive Units
Valuation date	9/30/2015			9/30/2015
Dividend yield		0	%		0	%
Expected volatility		48.99	%		48.99	%
Risk-free rate		0.54	%		0.54	%
Expected life (years)		1.67			1.67

27

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Note 13. Related Party Transactions

Amounts due to (due from) MRD Holdco and certain affiliates of NGP at September 30, 2015 and December 31, 2014 are presented as “Accounts receivable – affiliates” and “Accounts payable – affiliates” in the accompanying balance sheets.

NGP Affiliated Companies

During the three and nine months ended September 30, 2015, MRD paid approximately $4.8 million and $6.7 million, respectively to Cretic Energy Services, LLC, an NGP affiliated company, for services related to our drilling and completion activities.

During the three and nine months ended September 30, 2015, MRD paid approximately $1.0 million and $1.2 million, respectively to Multi-Shot, LLC, an NGP affiliated company, for services related to our drilling and completion activities.

NGPCIF NPI Acquisition

WildHorse Resources purchased a net profits interest from NGPCIF on February 28, 2014 for a purchase price of $63.4 million (see Note 1). This acquisition was accounted for as a combination of entities under common control at historical cost in a manner similar to the pooling of interest method. WildHorse Resources recorded the following net assets (in thousands):

Accounts receivable	$	2,274
Oil and natural gas properties, net		40,056
Accrued liabilities		(297	)
Asset retirement obligations		(277	)
Net assets	$	41,756

Due to common control considerations, the difference between the purchase price and the net assets acquired are reflected within equity as a deemed distribution to NGP affiliates.

Other Acquisitions or Dispositions

On March 10, 2014, BlueStone sold certain interests in oil and gas properties in McMullen, Webb, Zapata, and Hidalgo Counties located in South Texas to BlueStone Natural Resources II, LLC, an NGP controlled entity. Total cash consideration received by BlueStone was approximately $1.2 million, which exceeded the net book value of the properties sold by $0.5 million. Due to common control considerations, the $0.5 million was recognized in the equity statement as a contribution.

On March 28, 2014, our predecessor acquired certain interests in oil and gas properties in Gonzales and Karnes Counties located in South Texas from an NGP affiliated company for $3.3 million.

On June 18, 2014, in connection with our initial public offering and the related restructuring transactions, 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.

28

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Voting Agreement

In connection with the closing of our initial public offering, we entered into a voting agreement with MRD Holdco, WHR Incentive LLC, a limited liability company beneficially owned by Messrs. Bahr and Graham, and certain former management members of WildHorse Resources, who contributed their ownership of WildHorse Resources to us in the restructuring transactions. Among other things, the voting agreement provides that those former management members of WildHorse Resources will vote all of their shares of our common stock as directed by MRD Holdco.

Services Agreement

In connection with the closing of our initial public offering, we entered into a services agreement with WildHorse Resources and WildHorse Resource Management Company, LLC (“WHR Management Company”), pursuant to which WHR Management Company agreed to provide operating and administrative services to us for twelve months relating to the Terryville Complex. In exchange for such services, we paid a monthly management fee to WHR Management Company of approximately $1.0 million excluding third party COPAS income credits.

Upon the closing of our initial public offering, WHR Management Company became a subsidiary of WildHorse Resources II, LLC, an affiliate of the Company (“WHR II”). NGP and certain former management members of WildHorse Resources own WHR II.

The services agreement was terminated effective March 1, 2015.

WildHorse Management Services Agreement

A discussion of the WildHorse and WHR II management services and related agreements is included in our Recast Form 8-K. These agreements were terminated in connection with our initial public offering.

Midstream Agreements

On April 14, 2015, we, through our wholly-owned subsidiary, MRD Operating, entered into an amended and restated gas processing agreement (“GPA”) with PennTex North Louisiana Operating, LLC (“PennTex Operating”), a wholly-owned subsidiary of PennTex North Louisiana, LLC (“PennTex”). WildHorse Resources, which owned our interest in the Terryville Complex and merged into MRD Operating in February 2015, initially entered into a gas processing agreement with PennTex in March 2014, prior to our initial public offering. PennTex is a joint venture among certain affiliates of NGP in which MRD Midstream LLC, a wholly-owned subsidiary of MRD Holdco, owns a minority interest. Once PennTex Operating’s first processing plant became operational on June 1, 2015, it began to process natural gas produced from wells located on certain leases owned by us in the state of Louisiana. The GPA has a 15-year primary term, subject to one-year extensions at either party’s election. We pay PennTex Operating a monthly volume processing fee, subject to annual inflation escalators, based on volumes of natural gas processed by PennTex Operating. Once the first plant was declared operational, we became obligated to pay a minimum processing fee equal to approximately $18.3 million on an annual basis, subject to certain adjustments and conditions until the second processing plant was declared operational. Once the second plant was declared operational in October 2015, we became obligated to pay a minimum volume processing fee equal to approximately $55.0 million on an annual basis, subject to certain adjustments and conditions.

In addition, on April 14, 2015, we entered into (i) an amended and restated area of mutual interest and midstream exclusivity agreement (“AMI”) with PennTex NLA Holdings, LLC, which owns a majority interest in PennTex, MRD WHR LA Midstream LLC, an affiliate of MRD Holdco, and PennTex, (ii) a gas transportation agreement (“GTA”) with PennTex Operating, (iii) a gas gathering agreement (“GGA”) with PennTex Operating, and (iv) a transportation services agreement (“TSA” and, together with the GPA, AMI, GTA, and GGA, the “Midstream Agreements”) with PennTex Operating to provide gathering, residue gas and natural gas liquids transportation services to us in the state of Louisiana. The Midstream Agreements have a 15-year primary term, subject to one-year extensions at either party’s elections.

Under the GGA, once the first processing plant was declared operational, we began to pay PennTex Operating a commodity usage charge equal to at least the minimum volume commitment (115,000 MMBtu per day) times $0.02 per MMBtu until PennTex Operating’s second processing plant was declared operational. Once the second processing plant was declared operational, we became obligated to pay PennTex Operating a commodity usage charge equal to at least an increased minimum volume commitment (345,000 MMBtu per day) times $0.02 MMBtu through November 30, 2019. The minimum volume commitment will increase to 460,000 MMBtu on July 1, 2016 and may further increase subject to the terms of the GGA. Prior to December 1, 2019, PennTex Operating is also entitled to a payback demand fee from us equal to the monthly demand quantity (460,000 MMBtu per day) times a $0.03 MMBtu through November 30, 2019. Beginning on December 1, 2019, PennTex Operating is not entitled to a monthly demand charge, the commodity usage charge escalates to $0.05 per MMBtu, and PennTex Operating is entitled to receive a commodity usage charge from us equal to the minimum volume commitment (460,000 MMBtu per day through June 30, 2026, and 345,000 MMBtu per day thereafter) times $0.05 MMBtu.

29

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Similarly, under the GTA which commences concurrently with the operational dates of the two processing plants, PennTex Operating will be entitled to a commodity usage charge of $0.04 per MMBtu for all volumes of residue gas produced on our behalf. Under the TSA, which commences concurrently with the operational dates of the two processing plants, PennTex Operating will be entitled to a commodity usage charge of $0.04 per gallon for all volumes of natural gas liquids produced on our behalf.

Under the AMI, we granted PennTex Operating the exclusive right to build all of our midstream infrastructure in northern Louisiana and to provide midstream services to support our current and future production on our operated acreage within such area (other than production subject to existing third-party commitments).

All net costs associated with these gas processing agreements are reflected in the statement of operations in the “Gathering processing, and transportation – affiliate” line.

Classic Pipeline Gas Gathering Agreement & Water Disposal Agreement

In November 2011, Classic Hydrocarbons Operating, LLC (“Classic Operating”), which became our wholly-owned subsidiary in connection with the restructuring transactions, and Classic Pipeline entered into a gas gathering agreement. Pursuant to the gas gathering agreement, Classic Operating dedicated to Classic Pipeline all of the natural gas produced (up to 50,000 MMBtus per day) on the properties operated by Classic Operating within certain counties in Texas through 2020, subject to one-year extensions at either party’s election. In May 2014, Classic Operating and Classic Pipeline amended the gas gathering agreement with respect to Classic Operating’s remaining assets located in Panola and Shelby Counties, Texas. Under the amended gas gathering agreement, Classic Operating agreed to pay a fee of (i) $0.30 per MMBtu, subject to an annual 3.5% inflationary escalation, based on volumes of natural gas delivered and processed, and (ii) $0.07 per MMBtu per stage of compression plus its allocated share of compressor fuel. The amended gas gathering agreement has a term until December 31, 2023, subject to one-year extensions at either party’s election.

In May 2014, Classic Operating and Classic Pipeline entered into a water disposal agreement. The water disposal agreement has a three-year term, subject to one-year extensions at either party’s election. Under the water disposal agreement, Classic Operating agreed to pay a fee of $1.10 per barrel for each barrel of water delivered to Classic Pipeline. Effective July 1, 2015, the fee was reduced to $0.40 per barrel for each barrel of water delivered to Classic Pipeline.

In February 2015, in connection with and as part of the Property Swap, Classic sold all of the equity interests owned by it in Classic Operating to Memorial Production Operating LLC, a wholly-owned subsidiary of MEMP, and Classic and Classic GP were merged into MRD Operating in March 2015.

Note 14. Business Segment Data

Our reportable business segments are organized in a manner that reflects how management manages those business activities.

We have two reportable business segments, both of which are engaged in the acquisition, exploration and development of oil and natural gas properties. Our reportable business segments are as follows:

· MRD—reflects the combined operations of the Company and its consolidating subsidiaries except for MEMP and its subsidiaries.

· MEMP—reflects the combined operations of MEMP and its subsidiaries.

We evaluate segment performance based on Adjusted EBITDA. Adjusted EBITDA is defined as net income (loss), plus interest expense; loss on extinguishment of debt; income tax expense; depreciation, depletion and amortization (“DD&A”); impairment of goodwill and long-lived properties; accretion of asset retirement obligations (“AROs”); losses on commodity derivative contracts and cash settlements received; losses on sale of properties; incentive-based compensation expenses; exploration costs; provision for environmental remediation; equity loss from MEMP (MRD Segment only); cash distributions from MEMP (MRD Segment only); transaction related costs; amortization of investment premium; and other non-routine items, less interest income; income tax benefit; gains on commodity derivative contracts and cash settlements paid on expired positions; equity income from MEMP (MRD Segment only); gains on sale of assets and other non-routine items.

Financial information presented for the MEMP business segment is derived from the underlying consolidated and combined financial statements of MEMP that are publicly available.

Segment revenues and expenses include intersegment transactions. Our consolidated totals reflect the elimination of intersegment transactions.

In the MRD Segment’s individual financial statements, investments in the MEMP Segment that are included in the consolidated and combined financial statements are accounted for by the equity method.

30

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

The following table presents selected business segment information for the periods indicated (in thousands):

					Other,			Consolidated
					Adjustments &			& Combined
	MRD		MEMP		Eliminations			Totals
Total revenues:
Three Months Ended September 30, 2015	$	111,654	$	88,083	$	—		$	199,737
Three Months Ended September 30, 2014		99,035		166,261		—			265,296
Nine Months Ended September 30, 2015		277,282		279,039		—			556,321
Nine Months Ended September 30, 2014		297,340		427,354		—			724,694
Adjusted EBITDA: (1)
Three Months Ended September 30, 2015		104,319		80,766		(75	)		185,010
Three Months Ended September 30, 2014		76,237		97,196		(64	)		173,369
Nine Months Ended September 30, 2015		273,980		250,073		(226	)		523,827
Nine Months Ended September 30, 2014		222,460		243,717		(6,068	)		460,109
Segment assets: (2)
As of September 30, 2015		1,871,270		2,749,376		(3,378	)		4,617,268
As of December 31, 2014		1,413,768		3,189,760		(9,981	)		4,593,547
Total cash expenditures for additions to long-lived assets:
Nine Months Ended September 30, 2015		449,297		202,150		—			651,447
Nine Months Ended September 30, 2014		249,324		1,300,815		—			1,550,139

(1) Adjustments and eliminations for the three and nine months ended September 30, 2015 and 2014 include cash distributions that MEMP paid to MRD during the three and nine months ended September 30, 2015 and 2014, related to the ownership of partnership interests in MEMP. In 2014, MRD LLC owned MEMP subordinated units, which were distributed to MRD Holdco in connection with the Company’s initial public offering in June 2014.

(2) As of September 30, 2015, adjustments and eliminations primarily represent the elimination of accounts receivable and accounts payable balances between the MRD Segment and the MEMP Segment.

Calculation of Reportable Segments’ Adjusted EBITDA

	For the Three Months Ended
	September 30, 2015
							Combined
	MRD			MEMP			Totals
	(In thousands)
Net income (loss)	$	56,551		$	(191,981	)	$	(135,430	)
Interest expense, net		9,176			31,255			40,431
Income tax expense (benefit)		54,431			(107	)		54,324
DD&A		53,035			53,305			106,340
Impairment of proved oil and natural gas properties		—			361,836			361,836
Accretion of AROs		95			1,716			1,811
(Gain) loss on commodity derivative instruments		(125,167	)		(244,888	)		(370,055	)
Cash settlements received (paid) on expired commodity derivative instruments		44,010			64,480			108,490
Transaction related costs		213			16			229
Incentive-based compensation expense		7,657			2,993			10,650
Exploration costs		4,068			2,141			6,209
Non-cash equity (income) loss from MEMP		175			—			175
Cash distributions from MEMP		75			—			75
Adjusted EBITDA	$	104,319		$	80,766		$	185,085

31

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

	For the Three Months Ended
	September 30, 2014
							Combined
	MRD			MEMP			Totals
	(In thousands)
Net income (loss)	$	10,816		$	101,307		$	112,123
Interest expense, net		9,887			26,458			36,345
Income tax expense (benefit)		26,522			(688	)		25,834
DD&A		30,798			53,649			84,447
Impairment of proved oil and natural gas properties		—			67,181			67,181
Accretion of AROs		132			1,421			1,553
(Gain) loss on commodity derivative instruments		(33,090	)		(156,402	)		(189,492	)
Cash settlements received (paid) on expired commodity derivative instruments		3,699			876			4,575
Transaction related costs		500			925			1,425
Incentive-based compensation expense		26,862			2,427			29,289
Exploration costs		133			42			175
Non-cash equity (income) loss from MEMP		(86	)		—			(86	)
Cash distributions from MEMP		64			—			64
Adjusted EBITDA	$	76,237		$	97,196		$	173,433

	For the Nine Months Ended
	September 30, 2015
							Combined
	MRD			MEMP			Totals
	(In thousands)
Net income (loss)	$	80,219		$	(468,498	)	$	(388,279	)
Interest expense, net		28,545			87,983			116,528
Income tax expense (benefit)		77,345			(1,601	)		75,744
DD&A		129,394			150,857			280,251
Impairment of proved oil and natural gas properties		—			613,183			613,183
Accretion of AROs		311			5,036			5,347
(Gain) loss on commodity derivative instruments		(202,894	)		(328,944	)		(531,838	)
Cash settlements received (paid) on expired commodity derivative instruments		114,298			178,955			293,253
(Gain) loss on sale of properties		50			—			50
Transaction related costs		1,620			1,612			3,232
Incentive-based compensation expense		37,440			7,899			45,339
Exploration costs		7,024			2,263			9,287
Loss on settlement of AROs		—			1,328			1,328
Non-cash equity (income) loss from MEMP		402			—			402
Cash distributions from MEMP		226			—			226
Adjusted EBITDA	$	273,980		$	250,073		$	524,053

32

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

	For the Nine Months Ended
	September 30, 2014
							Combined
	MRD			MEMP			Totals
	(In thousands)
Net income (loss)	$	(934,541	)	$	(43,225	)	$	(977,766	)
Interest expense, net		44,355			60,573			104,928
Loss on debt extinguishment		37,248			—			37,248
Income tax expense (benefit)		14,701			(303	)		14,398
DD&A		86,741			129,165			215,906
Impairment of proved oil and natural gas properties		—			67,181			67,181
Accretion of AROs		389			4,212			4,601
(Gain) loss on commodity derivative instruments		(17,130	)		28,710			11,580
Cash settlements received (paid) on expired commodity derivative instruments		(4,930	)		(14,999	)		(19,929	)
(Gain) loss on sale of properties		3,057			—			3,057
Transaction related costs		1,568			3,912			5,480
Incentive-based compensation expense		970,877			5,387			976,264
Exploration costs		1,213			252			1,465
Non-cash equity (income) loss from MEMP		12,844			—			12,844
Provision for environmental remediation		—			2,852			2,852
Cash distributions from MEMP		6,068			—			6,068
Adjusted EBITDA	$	222,460		$	243,717		$	466,177

The following table presents a reconciliation of total reportable segments’ Adjusted EBITDA to net income (loss) for each of the periods indicated (in thousands).

	For the Three Months Ended						For the Nine Months Ended
	September 30,						September 30,
	2015			2014			2015			2014
Total Reportable Segments' Adjusted EBITDA	$	185,085		$	173,433		$	524,053		$	466,177
Adjustments to reconcile Adjusted EBITDA to net income (loss):
Interest expense, net		(40,431	)		(36,345	)		(116,528	)		(104,928	)
Loss on debt extinguishment		—			—			—			(37,248	)
Income tax benefit (expense)		(54,324	)		(25,834	)		(75,744	)		(14,398	)
DD&A		(106,340	)		(84,447	)		(280,251	)		(215,906	)
Impairment of proved oil and natural gas properties		(361,836	)		(67,181	)		(613,183	)		(67,181	)
Accretion of AROs		(1,811	)		(1,553	)		(5,347	)		(4,601	)
Gains (losses) on commodity derivative instruments		370,055			189,492			531,838			(11,580	)
Cash settlements paid (received) on expired commodity derivative instruments		(108,490	)		(4,575	)		(293,253	)		19,929
Gain (loss) on sale of properties		—			—			(50	)		(3,057	)
Transaction related costs		(229	)		(1,425	)		(3,232	)		(5,480	)
Incentive-based compensation expense		(10,650	)		(29,289	)		(45,339	)		(976,264	)
Exploration costs		(6,209	)		(175	)		(9,287	)		(1,465	)
Provision for environmental remediation		—			—			—			(2,852	)
Loss on settlement of AROs		—			—			(1,328	)		—
Cash distributions from MEMP		(75	)		(64	)		(226	)		(6,068	)
Net income (loss)	$	(135,255	)	$	112,037		$	(387,877	)	$	(964,922	)

33

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Included below is our consolidated and combined statement of operations disaggregated by reportable segment for the period indicated (in thousands):

	Three Months Ended September 30, 2015
	MRD			MEMP			Other, Adjustments & Eliminations		Consolidated
Revenues:
Oil & natural gas sales	$	111,654		$	87,519		$	—	$	199,173
Other revenues		—			564			—		564
Total revenues		111,654			88,083			—		199,737
Costs and expenses:
Lease operating		7,949			45,416			—		53,365
Gathering, processing, and transportation		22,633			8,134			—		30,767
Gathering, processing, and transportation - affiliate		9,215			—			—		9,215
Pipeline operating		—			461			—		461
Exploration		4,068			2,141			—		6,209
Production and ad valorem taxes		2,751			6,896			—		9,647
Depreciation, depletion, and amortization		53,035			53,305			—		106,340
Impairment of proved oil and natural gas properties		—			361,836			—		361,836
Incentive unit compensation expense		4,965			—			—		4,965
General and administrative		11,695			13,910			—		25,605
Accretion of asset retirement obligations		95			1,716			—		1,811
(Gain) loss on commodity derivative instruments		(125,167	)		(244,888	)		—		(370,055	)
Total costs and expenses		(8,761	)		248,927			—		240,166
Operating income (loss)		120,415			(160,844	)		—		(40,429	)
Other income (expense):
Interest expense, net		(9,176	)		(31,255	)		—		(40,431	)
Earnings from equity investments		(175	)		—			175		—
Other, net		(82	)		11			—		(71	)
Total other income (expense)		(9,433	)		(31,244	)		175		(40,502	)
Income (loss) before income taxes		110,982			(192,088	)		175		(80,931	)
Income tax benefit (expense)		(54,431	)		107			—		(54,324	)
Net income (loss)	$	56,551		$	(191,981	)	$	175	$	(135,255	)

34

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

	Three Months Ended September 30, 2014
	MRD			MEMP			Other, Adjustments & Eliminations			Consolidated
Revenues:
Oil & natural gas sales	$	99,029		$	164,935		$	—		$	263,964
Other revenues		6			1,326			—			1,332
Total revenues		99,035			166,261			—			265,296
Costs and expenses:
Lease operating		4,333			41,878			—			46,211
Gathering, processing, and transportation		11,941			7,862			—			19,803
Pipeline operating		—			431			—			431
Exploration		133			42			—			175
Production and ad valorem taxes		2,987			11,053			—			14,040
Depreciation, depletion, and amortization		30,798			53,649			—			84,447
Impairment of proved oil and natural gas properties		—			67,181			—			67,181
Incentive unit compensation expense		25,550			—			—			25,550
General and administrative		9,127			12,069			—			21,196
Accretion of asset retirement obligations		132			1,421			—			1,553
(Gain) loss on commodity derivative instruments		(33,090	)		(156,402	)		—			(189,492	)
Total costs and expenses		51,911			39,184			—			91,095
Operating income (loss)		47,124			127,077			—			174,201
Other income (expense):
Interest expense, net		(9,887	)		(26,458	)		—			(36,345	)
Earnings from equity investments		86			—			(86	)		—
Other, net		15			—			—			15
Total other income (expense)		(9,786	)		(26,458	)		(86	)		(36,330	)
Income (loss) before income taxes		37,338			100,619			(86	)		137,871
Income tax benefit (expense)		(26,522	)		688			—			(25,834	)
Net income (loss)	$	10,816		$	101,307		$	(86	)	$	112,037

	Nine Months Ended September 30, 2015
	MRD			MEMP			Other, Adjustments & Eliminations		Consolidated
Revenues:
Oil & natural gas sales	$	277,282		$	276,689		$	—	$	553,971
Other revenues		—			2,350			—		2,350
Total revenues		277,282			279,039			—		556,321
Costs and expenses:
Lease operating		17,025			130,782			—		147,807
Gathering, processing, and transportation		51,685			25,402			—		77,087
Gathering, processing, and transportation - affiliate		13,028			—			—		13,028
Pipeline operating		—			1,407			—		1,407
Exploration		7,024			2,263			—		9,287
Production and ad valorem taxes		8,666			19,609			—		28,275
Depreciation, depletion, and amortization		129,394			150,857			—		280,251
Impairment of proved oil and natural gas properties		—			613,183			—		613,183
Incentive unit compensation expense		31,305			—			—		31,305
General and administrative		34,994			42,798			—		77,792
Accretion of asset retirement obligations		311			5,036			—		5,347
(Gain) loss on commodity derivative instruments		(202,894	)		(328,944	)		—		(531,838	)
(Gain) loss on sale of properties		50			—			—		50
Other, net		—			(943	)		—		(943	)
Total costs and expenses		90,588			661,450			—		752,038
Operating income (loss)		186,694			(382,411	)		—		(195,717	)
Other income (expense):
Interest expense, net		(28,545	)		(87,983	)		—		(116,528	)
Earnings from equity investments		(402	)		—			402		—
Other, net		(183	)		295			—		112
Total other income (expense)		(29,130	)		(87,688	)		402		(116,416	)
Income (loss) before income taxes		157,564			(470,099	)		402		(312,133	)
Income tax benefit (expense)		(77,345	)		1,601			—		(75,744	)
Net income (loss)	$	80,219		$	(468,498	)	$	402	$	(387,877	)

35

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

	Nine Months Ended September 30, 2014
	MRD			MEMP			Other, Adjustments & Eliminations		Consolidated & Combined
Revenues:
Oil & natural gas sales	$	297,328		$	423,782		$	—	$	721,110
Other revenues		12			3,572			—		3,584
Total revenues		297,340			427,354			—		724,694
Costs and expenses:
Lease operating		12,361			99,526			—		111,887
Gathering, processing, and transportation		30,793			21,016			—		51,809
Pipeline operating		—			1,596			—		1,596
Exploration		1,213			252			—		1,465
Production and ad valorem taxes		9,141			24,482			—		33,623
Depreciation, depletion, and amortization		86,741			129,165			—		215,906
Impairment of proved oil and natural gas properties		—			67,181			—		67,181
Incentive unit compensation expense		969,390			—			—		969,390
General and administrative		26,880			34,181			—		61,061
Accretion of asset retirement obligations		389			4,212			—		4,601
(Gain) loss on commodity derivative instruments		(17,130	)		28,710			—		11,580
(Gain) loss on sale of properties		3,057			—			—		3,057
Other, net		—			(12	)		—		(12	)
Total costs and expenses		1,122,835			410,309			—		1,533,144
Operating income (loss)		(825,495	)		17,045			—		(808,450	)
Other income (expense):
Interest expense, net		(44,355	)		(60,573	)		—		(104,928	)
Loss on extinguishment on debt		(37,248	)		—			—		(37,248	)
Earnings from equity investments		(12,844	)		—			12,844		—
Other, net		102			—			—		102
Total other income (expense)		(94,345	)		(60,573	)		12,844		(142,074	)
Income before income taxes		(919,840	)		(43,528	)		12,844		(950,524	)
Income tax benefit (expense)		(14,701	)		303			—		(14,398	)
Net income (loss)	$	(934,541	)	$	(43,225	)	$	12,844	$	(964,922	)

Note 15. Commitments and Contingencies

Litigation & Environmental

As part of our normal business activities, we may be named as defendants in litigation and legal proceedings, including those arising from regulatory and environmental matters. Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to indemnify us against liabilities arising from future legal proceedings. We are not aware of any litigation, pending or threatened, that we believe is reasonably likely to have a significant adverse effect on our financial position, results of operations or cash flows.

At September 30, 2015 and December 31, 2014, we had $0.6 million and $2.1 million of environmental reserves recorded on our balance sheets, respectively.

Midstream Agreements

See Note 13 for additional information.

Supplemental Bond for Decommissioning Liabilities Trust Agreement

In connection with its 2009 acquisition of the Beta properties, Rise Energy Operating, LLC (“REO”), a wholly-owned subsidiary of MEMP, assumed an obligation with the BOEM for the decommissioning of the offshore production facilities. The trust account is held by REO for the benefit of all working interest owners. The following is a summary of the gross held-to-maturity investments held in the trust account less the outside working interest owners share as of September 30, 2015 (in thousands):

	Amortized
Investment	Cost
U.S. Bank Money Market Cash Equivalent	$	142,005
Less: Outside working interest owners share		(68,517	)
	$	73,488

36

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

The trust account must maintain minimum balances attributable to REO’s net working interest as follows (in thousands):

June 30, 2016	$	76,590
December 31, 2016	$	78,660

As of September 30, 2015, the maximum remaining obligation net to REO’s interest was approximately $5.2 million.

Processing Plant Expansions by Third Party Gatherer

A discussion of processing plant expansions by a third party gatherer is included in our Recast Form 8-K.

Related Party Agreements

See Note 13 for additional information.

Note 16. Condensed Consolidating Financial Information  

The Company owns no operating assets and has no significant operations independent of its subsidiaries. Our obligations under the MRD Senior Notes outstanding are fully and unconditionally guaranteed, jointly and severally, by certain of our 100% owned subsidiaries on a senior unsecured basis. Subsidiaries with noncontrolling interests (i.e. MEMP) and certain de minimis subsidiaries are non-guarantors.

The following condensed consolidating financial information presents the financial information of the Company on a unconsolidated stand-alone basis and its combined guarantor and combined non-guarantor subsidiaries as of and for the period indicated. Such financial information may not necessarily be indicative of our results of operations, cash flows or financial position had these subsidiaries operated as independent entities.

	As of September 30, 2015
	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	4,725	$	2,107	$	531	$	—		$	7,363
Accounts receivable - trade		6,890		76,715		55,169		(2,786	)		135,988
Accounts receivable - affiliates		7,438		—		—		(7,438	)		—
Short-term derivative instruments		152,208		—		231,340		—			383,548
Prepaid expenses and other current assets		4,995		8,603		14,258		—			27,856
Total current assets		176,256		87,425		301,298		(10,224	)		554,755
Property and equipment, net		16,814		1,371,384		1,907,350		—			3,295,548
Long-term derivative instruments		191,426		—		439,070		—			630,496
Investments in subsidiaries		1,261,135		—		—		(1,261,135	)		—
Other long-term assets		13,526		21,285		101,658		—			136,469
Total assets	$	1,659,157	$	1,480,094	$	2,749,376	$	(1,271,359	)	$	4,617,268
LIABILITIES AND EQUITY
Current Liabilities:
Accounts payable and accrued liabilities	$	24,574	$	86,766	$	104,488	$	(561	)	$	215,267
Accounts payable - affiliates		—		14,376		5,006		(9,625	)		9,757
Revenues payable		80		37,600		32,700		—			70,380
Deferred tax liabilities		55,985		—		1,459		—			57,444
Short-term derivative instruments		—		—		3,515		—			3,515
Total current liabilities		80,639		138,742		147,168		(10,186	)		356,363
Long-term debt		726,000		—		1,878,264		—			2,604,264
Asset retirement obligations		—		8,316		120,744		—			129,060
Long-term derivative instruments		—		—		3,183		—			3,183
Deferred tax liabilities		46,028		72,372		2,389		—			120,789
Other long-term liabilities		6,995		—		—		—			6,995
Total liabilities		859,662		219,430		2,151,748		(10,186	)		3,220,654
Equity:
Equity		799,495		1,260,664		591,740		(1,852,404	)		799,495
Noncontrolling interest		—		—		5,888		591,231			597,119
Total equity		799,495		1,260,664		597,628		(1,261,173	)		1,396,614
Total liabilities & equity	$	1,659,157	$	1,480,094	$	2,749,376	$	(1,271,359	)	$	4,617,268

37

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

	As of December 30, 2014
	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	2,241	$	3,762	$	970	$	(1,015	)	$	5,958
Accounts receivable- trade		5,995		44,952		83,346		(2,717	)		131,576
Accounts receivable - affiliates		10,047		—		28		(10,075	)		—
Short-term derivative instruments		131,471		—		208,585		—			340,056
Prepaid expenses and other current assets		5,833		7,993		14,201		—			28,027
Total current assets		155,587		56,707		307,130		(13,807	)		505,617
Property and equipment, net		16,601		1,050,722		2,470,333		—			3,537,656
Long-term derivative instruments		123,567		—		311,802		—			435,369
Investments in subsidiaries		1,139,792		—		—		(1,139,792	)		—
Other long-term assets		14,124		5,660		100,521		(5,400	)		114,905
Total assets	$	1,449,671	$	1,113,089	$	3,189,786	$	(1,158,999	)	$	4,593,547
LIABILITIES AND EQUITY
Current Liabilities:
Accounts payable and accrued expenses	$	6,245	$	56,598	$	113,177	$	(3,125	)	$	172,895
Accounts payable - affiliates		—		3,638		6,409		(9,423	)		624
Revenues payable		—		27,242		30,110		—			57,352
Deferred tax liabilities		—		50,470		1,407		—			51,877
Short-term derivative instruments		—		—		3,289		—			3,289
Total current liabilities		6,245		137,948		154,392		(12,548	)		286,037
Long-term debt		783,000		—		1,595,413		—			2,378,413
Asset retirement obligations		—		9,830		112,701		—			122,531
Deferred tax liabilities		69,431		—		30,986		(5,400	)		95,017
Other long-term liabilities		8,585		—		—		—			8,585
Total liabilities		867,261		147,778		1,893,492		(17,948	)		2,890,583
Equity:
Equity		582,410		965,311		1,290,734		(2,256,045	)		582,410
Noncontrolling 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	$	1,449,671	$	1,113,089	$	3,189,786	$	(1,158,999	)	$	4,593,547

38

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

	Three Months Ended September 30, 2015
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues:
Oil & natural gas sales	$	—		$	111,654		$	87,519		$	—		$	199,173
Other income		—			—			564			—			564
Total revenues		—			111,654			88,083			—			199,737
Costs and expenses:
Lease operating		—			7,949			45,416			—			53,365
Gathering, processing and transportation		—			22,633			8,134			—			30,767
Gathering, processing and transportation - affiliate		—			9,215			—			—			9,215
Pipeline operating		—			—			461			—			461
Exploration		—			4,068			2,141			—			6,209
Production and ad valorem taxes		—			2,751			6,896			—			9,647
Depreciation, depletion and amortization		1,087			51,948			53,305			—			106,340
Impairment of proved oil and natural gas properties		—			—			361,836			—			361,836
Incentive unit compensation expense		4,965			—			—			—			4,965
General and administrative		11,327			368			13,910			—			25,605
Accretion of asset retirement obligations		—			95			1,716			—			1,811
(Gain) loss on commodity derivatives		(125,167	)		—			(244,888	)		—			(370,055	)
Total costs and expenses		(107,788	)		99,027			248,927			—			240,166
Operating income (loss)		107,788			12,627			(160,844	)		—			(40,429	)
Other income (expense):
Interest expense, net		(9,174	)		(2	)		(31,255	)		—			(40,431	)
Equity earnings from subsidiaries		10,839			—			—			(10,839	)		—
Other, net		(100	)		18			11			—			(71	)
Total other income (expense)		1,565			16			(31,244	)		(10,839	)		(40,502	)
Income before income taxes		109,353			12,643			(192,088	)		(10,839	)		(80,931	)
Income tax benefit (expense)		(52,801	)		(1,630	)		107			—			(54,324	)
Net income (loss)		56,552			11,013			(191,981	)		(10,839	)		(135,255	)
Net income (loss) attributable to noncontrolling interest		—			—			104			(191,911	)		(191,807	)
Net income (loss) attributable to Memorial Resource Development Corp.	$	56,552		$	11,013		$	(192,085	)	$	181,072		$	56,552

39

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

	Three Months Ended September 30, 2014
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues:
Oil & natural gas sales	$	—		$	99,026		$	164,938		$	—		$	263,964
Other income		6			—			1,326			—			1,332
Total revenues		6			99,026			166,264			—			265,296
Costs and expenses:
Lease operating		—			4,320			41,891			—			46,211
Gathering, processing and transportation		—			11,941			7,862			—			19,803
Pipeline operating		—			—			431			—			431
Exploration		—			133			42			—			175
Production and ad valorem taxes		—			2,987			11,053			—			14,040
Depreciation, depletion and amortization		168			30,630			53,649			—			84,447
Impairment of proved oil and natural gas properties		—			—			67,181			—			67,181
Incentive unit compensation expense		25,550			—			—			—			25,550
General and administrative		7,215			1,889			12,092			—			21,196
Accretion of asset retirement obligations		1			131			1,421			—			1,553
(Gain) loss on commodity derivatives		(33,090	)		—			(156,402	)		—			(189,492	)
Total costs and expenses		(156	)		52,031			39,220			—			91,095
Operating income (loss)		162			46,995			127,044			—			174,201
Other income (expense):
Interest expense, net		(9,868	)		(19	)		(26,458	)		—			(36,345	)
Equity earnings from subsidiaries		25,675			—			—			(25,675	)		—
Other, net		—			5			10			—			15
Total other income (expense)		15,807			(14	)		(26,448	)		(25,675	)		(36,330	)
Income before income taxes		15,969			46,981			100,596			(25,675	)		137,871
Income tax benefit (expense)		(6,041	)		(20,489	)		696			—			(25,834	)
Net income (loss)		9,928			26,492			101,292			(25,675	)		112,037
Net income (loss) attributable to noncontrolling interest		—			—			52			102,057			102,109
Net income (loss) attributable to Memorial Resource Development Corp.	$	9,928		$	26,492		$	101,240		$	(127,732	)	$	9,928

40

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

	Nine Months Ended September 30, 2015
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues:
Oil & natural gas sales	$	—		$	277,282		$	276,689		$	—		$	553,971
Other income		—			—			2,350			—			2,350
Total revenues		—			277,282			279,039			—			556,321
Costs and expenses:
Lease operating		—			17,025			130,782			—			147,807
Gathering, processing and transportation		—			51,685			25,402			—			77,087
Gathering, processing and transportation -affiliate		—			13,028			—			—			13,028
Pipeline operating		—			—			1,407			—			1,407
Exploration		—			7,024			2,263			—			9,287
Production and ad valorem taxes		—			8,666			19,609			—			28,275
Depreciation, depletion and amortization		3,139			126,255			150,857			—			280,251
Impairment of proved oil and natural gas properties		—			—			613,183			—			613,183
Incentive unit compensation expense		31,305			—			—			—			31,305
General and administrative		32,656			2,338			42,798			—			77,792
Accretion of asset retirement obligations		—			311			5,036			—			5,347
(Gain) loss on commodity derivatives		(202,894	)		—			(328,944	)		—			(531,838	)
(Gain) loss on sale of properties		—			50			—			—			50
Other, net		—			—			(943	)		—			(943	)
Total costs and expenses		(135,794	)		226,382			661,450			—			752,038
Operating income (loss)		135,794			50,900			(382,411	)		—			(195,717	)
Other income (expense):
Interest expense, net		(28,456	)		(89	)		(87,983	)		—			(116,528	)
Equity earnings from subsidiaries		28,180			—			—			(28,180	)		—
Other, net		(100	)		(83	)		295			—			112
Total other income (expense)		(376	)		(172	)		(87,688	)		(28,180	)		(116,416	)
Income before income taxes		135,418			50,728			(470,099	)		(28,180	)		(312,133	)
Income tax benefit (expense)		(56,824	)		(20,521	)		1,601			—			(75,744	)
Net income (loss)		78,594			30,207			(468,498	)		(28,180	)		(387,877	)
Net income (loss) attributable to noncontrolling interest		—			—			328			(466,799	)		(466,471	)
Net income (loss) attributable to Memorial Resource Development Corp.	$	78,594		$	30,207		$	(468,826	)	$	438,619		$	78,594

41

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

	Nine Months Ended September 30, 2014
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Combined & Consolidated
	(In thousands)
Revenues:
Oil & natural gas sales	$	—		$	297,325		$	423,785		$	—		$	721,110
Other income		5			7			3,572			—			3,584
Total revenues		5			297,332			427,357			—			724,694
Costs and expenses:
Lease operating		—			12,348			99,539			—			111,887
Gathering, processing and transportation		—			30,793			21,016			—			51,809
Pipeline operating		—			—			1,596			—			1,596
Exploration		—			1,213			252			—			1,465
Production and ad valorem taxes		—			9,141			24,482			—			33,623
Depreciation, depletion and amortization		168			86,573			129,165			—			215,906
Impairment of proved oil and natural gas properties		—			—			67,181			—			67,181
Incentive unit compensation expense		137,307			831,060			1,023			—			969,390
General and administrative		7,390			19,450			34,221			—			61,061
Accretion of asset retirement obligations		1			388			4,212			—			4,601
(Gain) loss on commodity derivatives		(36,525	)		19,395			28,710			—			11,580
(Gain) loss on sale of properties		—			3,167			(110	)		—			3,057
Other, net		—			—			(12	)		—			(12	)
Total costs and expenses		108,341			1,013,528			411,275			—			1,533,144
Operating income (loss)		(108,336	)		(716,196	)		16,082			—			(808,450	)
Other income (expense):
Interest expense, net		(10,843	)		(33,512	)		(60,573	)		—			(104,928	)
Debt extinguishment costs		(23,562	)		(13,686	)		—			—			(37,248	)
Equity earnings from subsidiaries		(811,093	)		—			—			811,093			—
Other, net		—			92			10			—			102
Total other income (expense)		(845,498	)		(47,106	)		(60,563	)		811,093			(142,074	)
Income before income taxes		(953,834	)		(763,302	)		(44,481	)		811,093			(950,524	)
Income tax benefit (expense)		2,033			(16,742	)		311			—			(14,398	)
Net income (loss)		(951,801	)		(780,044	)		(44,170	)		811,093			(964,922	)
Net income (loss) attributable to noncontrolling interest		—			—			95			(34,946	)		(34,851	)
Net income (loss) attributable to Memorial Resource Development Corp.		(951,801	)		(780,044	)		(44,265	)		846,039			(930,071	)

42

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

	Nine Months Ended September 30, 2015
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Net cash provided by (used in) operating activities	$	64,375		$	187,457		$	185,572		$	1,015		$	438,419
Cash flows from investing activities:
Acquisitions of oil and natural gas properties		—			(7,267	)		(6,095	)		—			(13,362	)
Acquisition post-closing adjustment receipts		—			—			9,570			—			9,570
Additions to oil and gas properties		—			(438,262	)		(196,055	)		—			(634,317	)
Additions to other property and equipment		(3,340	)		(428	)		—			—			(3,768	)
Additions to restricted investments		—			—			(3,893	)		—			(3,893	)
Deposit for property acquisition		—			(21,286	)		—			—			(21,286	)
Investments in subsidiaries		(266,431	)		—			—			266,431			—
Distributions from subsidiaries		78,622			—			—			(78,622	)		—
Proceeds from the sale of oil and gas properties		—			13,612			—			—			13,612
Net cash used in investing activities		(191,149	)		(453,631	)		(196,473	)		187,809			(653,444	)
Cash flows from financing activities:
Advances on revolving credit facility		403,000			—			345,000			—			748,000
Payments on revolving credit facility		(460,000	)		—			(61,000	)		—			(521,000	)
Repayment of senior notes		—			—			(2,914	)		—			(2,914	)
Deferred finance costs		(1,446	)		—			(319	)		—			(1,765	)
Proceeds from MRD equity offering		242,880			—			—			—			242,880
Costs incurred in conjunction with MRD equity offering		(3,979	)		—			—			—			(3,979	)
Capital contributions		—			264,519			1,912			(266,431	)		—
Distributions to MRD		—			—			(78,396	)		78,396			—
Distribution to partners		—			—			(138,349	)		138,349			—
Distribution to noncontrolling interests		—			—			—			(138,123	)		(138,123	)
Repurchases of equity		(51,197	)		—			(55,472	)		—			(106,669	)
Net cash provided by financing activities		129,258			264,519			10,462			(187,809	)		216,430
Net change in cash and cash equivalents		2,484			(1,655	)		(439	)		1,015			1,405
Cash and cash equivalents, beginning of period		2,241			3,762			970			(1,015	)		5,958
Cash and cash equivalents, end of period	$	4,725		$	2,107		$	531		$	—		$	7,363

43

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

	Nine Months Ended September 30, 2014
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Combined & Consolidated
	(In thousands)
Net cash provided by (used in) operating activities	$	8,463		$	149,927		$	207,070		$	—		$	365,460
Cash flows from investing activities:
Acquisitions of oil and natural gas properties		—			—			(1,083,167	)		—			(1,083,167	)
Additions to oil and gas properties		—			(240,204	)		(217,634	)		—			(457,838	)
Additions to other property and equipment		(8,936	)		(184	)		(14	)		—			(9,134	)
Additions to restricted investments		—			—			(2,883	)		—			(2,883	)
Investments in subsidiaries		(611,853	)		—			—			611,853			—
Distributions from subsidiaries		—			56,027			—			(56,027	)		—
Change in restricted cash		—			49,946			—			—			49,946
Proceeds from the sale of oil and gas properties		—			—			6,700			—			6,700
Other		—			—			(301	)		—			(301	)
Net cash used in investing activities		(620,789	)		(134,415	)		(1,297,299	)		555,826			(1,496,677	)
Cash flows from financing activities:
Advances on revolving credit facility		1,013,000			126,800			1,325,000			—			2,464,800
Payments on revolving credit facility		(985,000	)		(329,900	)		(1,127,000	)		—			(2,441,900	)
Termination of second lien credit facility		—			(328,282	)		—			—			(328,282	)
Proceeds from the issuances of senior notes		600,000			—			492,425			—			1,092,425
Redemption of senior notes		(351,808	)		—			—			—			(351,808	)
Deferred finance costs		(18,814	)		(61	)		(11,409	)		—			(30,284	)
Proceeds from MRD initial public offering		408,500			—			—			—			408,500
Costs incurred in conjunction with initial public offering		(28,198	)		—			—			—			(28,198	)
Proceeds from MEMP equity offering		—			—			553,288			—			553,288
Costs incurred in conjunction with MEMP equity offering		—			—			(12,222	)		—			(12,222	)
Capital contributions		—			608,466			3,387			(611,853	)		—
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		—			—			(156,549	)		156,549			—
Distribution to NGP affiliates related to purchase of assets		—			(63,389	)		(3,304	)		—			(66,693	)
Distribution to noncontrolling interests		—			—			—			(101,327	)		(101,327	)
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		—			213			—			—			213
Net cash provided by financing activities		617,181			(58,443	)		1,061,705			(556,631	)		1,063,812
Net change in cash and cash equivalents		4,855			(42,931	)		(28,524	)		(805	)		(67,405	)
Cash and cash equivalents, beginning of period		—			48,619			29,102			—			77,721
Cash and cash equivalents, end of period	$	4,855		$	5,688		$	578		$	(805	)	$	10,316

44

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Note 17. Subsequent Events

MRD Purchase of Oil and Natural Gas Properties in Louisiana

For additional information, see Note 3.

MEMP Borrowing Base Redetermination

For additional information, see Note 8.

MEMP November 2015 Beta Acquisition

On November 3, 2015, MEMP completed an acquisition of the remaining interests in its oil and gas properties offshore Southern California (the “Beta properties”) from a third party for approximately $101.0 million, subject to customary post-closing adjustments.  

MEMP first acquired its interests in the Beta properties in December 2012.  The acquired interests primarily consist of the 48.25% remaining working interests in three Pacific Outer Continental Shelf blocks in the Beta Field, which includes 58 gross wells, that are located in federal waters approximately eleven miles offshore the Port of Long Beach, California.  The acquired interests also include the 48.25% remaining interest in associated facilities including (i) two combined production and drilling platforms (ii) one production processing platform, (iii) a 17.5 mile long 16-inch diameter oil pipeline and (iv) an onshore pump station, tankage and metering facility.  

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. 

Management’s Discussion and Analysis of Financial Condition and Results ofOperations should be read in conjunction with the unaudited condensed financial statements and accompanying notes in “Item 1. Financial Statements” contained herein and our 2014 Form 10-K filed with the SEC on March 18, 2015, our Recast Form 8-K filed with the SEC on July 8, 2015 and any supplements thereto. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. See “Cautionary Note Regarding Forward-Looking Statements” in the front of this report.

Overview

We are an independent natural gas and oil company focused on the acquisition, exploration and development of natural gas and oil properties with a majority of our activity in the Terryville Complex of North Louisiana, where we are targeting overpressured, liquids-rich natural gas opportunities in multiple zones in the Cotton Valley formation. We are focused on creating shareholder value primarily through the development of our sizeable horizontal inventory.

We have two reportable segments, both of which are engaged in the acquisition, exploration and development of oil and natural gas properties:

· MRD—reflects the combined operations of the Company and its consolidating subsidiaries except for MEMP and its subsidiaries.

· MEMP—reflects the combined operations of MEMP and its subsidiaries.

Because we control MEMP through our ownership of its general partner, its business and operations are consolidated with ours for financial reporting purposes, even though we do not own any of its common units. As a result, our financial statements and notes thereto included under “Item 1. Financial Statements” consolidate MEMP’s business and assets with ours; however, the MEMP Segment’s debt is nonrecourse to the Company. Except where expressly noted to the contrary, the following discussion of our business, operations and assets and the use of the terms “we”, “our” and “us” excludes MEMP’s business, operations and assets.

As discussed under Note 2 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under “Item 1. Financial Statements,” the FASB issued an accounting standards update in February 2015 to improve consolidation guidance for certain types of legal entities. The guidance, among other things, modifies the evaluation of whether limited partnerships and similar legal entities are variable interest entities (“VIEs”) or voting interest entities and eliminates the presumption that a general partner should consolidate a limited partnership. We currently believe we will continue to consolidate MEMP and become subject to the VIE primary beneficiary disclosure requirements. The deconsolidation of MEMP would have a material impact on our consolidated financial statements and related disclosures in the event there is a reconsideration event that triggers deconsolidation.

Recent Developments

North Louisiana Acquisition

In October 2015, we closed a transaction to acquire producing and non-producing properties in North Louisiana, including approximately 45,807 gross (45,121 net) acres for approximately $284.0 million, subject to customary post-closing adjustments, from a third party (the “North Louisiana Acquisition”). The acquisition has an effective date of August 1, 2015.  We financed the North Louisiana Acquisition with the net proceeds from our September 2015 equity offering (discussed below) and borrowings under our revolving credit facility.

September 2015 Equity Offering

In September 2015, we issued 13,800,000 shares of our common stock in an underwritten public offering (which included 1,800,000 shares sold pursuant to the option to purchase additional shares of our common stock granted by us to, and exercised in full by, the underwriter). The aggregate net proceeds from our September 2015 equity offering were approximately $238.4 million after deducting underwriting discounts and commissions and estimated offering expenses. The net proceeds from the equity offering were used to temporarily pay down our revolving credit facility as of September 30, 2015 and subsequently re-borrowed to fund a portion of the purchase price of the North Louisiana Acquisition that closed on October 22, 2015.

Amendments to MRD Revolving Credit Facility and Borrowing Base Redeterminations

In April 2015, we entered into a fourth amendment to our revolving credit facility to, among other things, add new lenders and permit the repurchase of up to $50.0 million of our common stock. In connection therewith, the lenders under our revolving credit facility reaffirmed the borrowing base under our revolving credit facility at $725.0 million.

46

In September 2015, we entered into a fifth amendment to our revolving credit facilityto, among other things, increase (i) the borrowing base under our revolving credit facility from $725.0 million to $1.0 billion and (ii) the aggregate elected commitment amounts to $1.0 billion. If the Company consummates a potential acquisition (unrelated to the North Louisiana Acquisition) prior to December 31, 2015 and subject to certain conditions, then the fifth amendment would also increase the borrowing base and the aggregate elected commitment amounts to $1.05 billion effective immediately before consummation of such acquisition.

Property Swap

In February 2015, we and MEMP completed a transaction (the “Property Swap”) in which we exchanged certain of our oil and gas properties in East Texas and West Louisiana for MEMP’s North Louisiana oil and gas properties and approximately $78.4 million in cash. Terms of the transaction were approved by our Board and by its conflicts committee, which is comprised entirely of independent directors. The transaction had an effective date of January 1, 2015.

MEMP November 2015 Beta Acquisition

In November 2015, MEMP completed an acquisition of the remaining interests in its oil and gas properties offshore Southern California (the “Beta properties”) from a third party for approximately $101.0 million, subject to customary post-closing adjustments.

MEMP first acquired its interests in the Beta properties in December 2012.  The acquired interests primarily consist of the 48.25% remaining working interests in three Pacific Outer Continental Shelf blocks in the Beta Field, which includes 58 gross wells, that are located in federal waters approximately eleven miles offshore the Port of Long Beach, California.  The acquired interests also include the 48.25% remaining interest in associated facilities including (i) two combined production and drilling platforms (ii) one production processing platform, (iii) a 17.5 mile long 16-inch diameter oil pipeline and (iv) an onshore pump station, tankage and metering facility.  

MEMP Semi-Annual Borrowing Base Redeterminations

In November 2015, in connection with the semi-annual borrowing base redetermination by lenders under MEMP’s revolving credit facility, the borrowing base under its revolving credit facility decreased from $1.30 billion to approximately $1.18 billion. The new borrowing base became effective on November 4, 2015.  In March 2015, the borrowing base under its revolving credit facility decreased from $1.44 billion to $1.3 billion. The borrowing base reductions were primarily the result of the deterioration of commodity prices in the oil and natural gas industry.

MEMP Conversion of Subordinated Units

In February 2015, the subordination period for the 5,360,912 MEMP subordinated units ended. All of the subordinated units, which were owned by MRD Holdco, converted to common units on a one-to-one basis at the end of the subordination period and were then sold by MRD Holdco during the second quarter of 2015.

MEMP Repurchase Program

In December 2014, the board of directors of MEMP’s general partner authorized the repurchase of up to $150.0 million of MEMP’s common units (“MEMP Repurchase Program”).  In 2015, MEMP repurchased $52.8 million of common units through October 31, 2015, which represents a repurchase and retirement of 3,547,921 common units under the MEMP Repurchase Program.

Business Segments

Our reportable business segments are organized in a manner that reflects how management manages those business activities. We evaluate segment performance based on Adjusted EBITDA. For additional information regarding our reportable business segments and Adjusted EBITDA, see Note 14 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under “Item 1. Financial Statements” of this quarterly report.

Segment financial information has been retrospectively revised for the acquisition by the MEMP Segment of certain assets from the MRD Segment in East Texas in February 2015 in exchange for approximately $78.4 million in cash and certain properties in North Louisiana for comparability purposes.

The MRD Segment is focused on the acquisition, exploration, and development of natural gas and oil properties primarily in the Cotton Valley formation in North Louisiana. These properties consist primarily of assets with extensive production histories, high drilling success rates, and significant horizontal redevelopment potential. The MRD Segment is focused on maintaining and growing its production and cash flow primarily through the development of its sizeable inventory. The MRD Segment, prior to our initial public offering, included BlueStone, MRD Royalty, MRD Midstream, Golden Energy Partners LLC (“Golden Energy”), Classic Pipeline, the MEMP subordinated units and cash held in a debt service reserve account that had been established when the 10.00%/10.75% Senior PIK toggle notes due 2018 (the “PIK notes”) were issued by MRD LLC in December 2013.

47

The MEMP Segment is engaged in the acquisition, exploitation, development and production of oil and natural gas properties, with assets consisting primarily of producing oil and natural gas properties that are located in Texas, Louisiana, Colorado, Wyoming, and New Mexico and offshore Southern California. Most of the MEMP Segment’s properties are located in large, mature oil and natural gas reservoirs with well-known geologic characteristics and long-lived, predictable production profiles and modest capital requirements. The MEMP Segment is focused on generating stable cash flows to allow MEMP to make quarterly cash distributions to its unitholders and, over time, to increase those quarterly cash distributions.

Sources of Revenues

Both our and MEMP’s revenues are derived from the sale of natural gas and oil production, as well as the sale of NGLs that are extracted from natural gas during processing. Production revenues are derived entirely from the continental United States. Natural gas, NGL and oil prices are inherently volatile and are influenced by many factors outside our control. In order to reduce the impact of fluctuations in natural gas and oil prices on revenues, or to protect the economics of property acquisitions, both we and MEMP intend to periodically enter into derivative contracts with respect to a significant portion of estimated natural gas and oil production through various transactions that fix the future prices received. At the end of each period the fair value of these commodity derivative instruments are estimated and, because hedge accounting is not elected, the changes in the fair value of unsettled commodity derivative instruments are recognized in earnings at the end of each accounting period.

Principal Components of Cost Structure

· Lease operating expenses. These are the day to day costs incurred to maintain production of our natural gas, NGLs and oil. Such costs include utilities, direct labor, water injection and disposal, materials and supplies, compression, repairs and workover expenses. Cost levels for these expenses can vary based on supply and demand for oilfield services.

· Gathering, processing and transportation. These are costs incurred to deliver production of our natural gas, NGLs and oil to the market. Cost levels of these expenses can vary based on the volume of natural gas, NGLs and oil production as well as the cost of commodity processing.

· Production and ad valorem taxes. These consist of severance and ad valorem taxes. Production taxes are paid on produced natural gas, NGLs and oil based on a percentage of market prices and at fixed per unit rates established by federal, state or local taxing authorities. Both MRD and MEMP take full advantage of all credits and exemptions in the various taxing jurisdictions where they operate. Ad valorem taxes are generally tied to the valuation of the oil and natural properties; however, these valuations are reasonably correlated to revenues, excluding the effects of any commodity derivative contracts.

· Exploration expense. These are geological and geophysical costs and include seismic costs, costs of unsuccessful exploratory dry holes, delay rentals and unsuccessful leasing efforts.

· Impairment of proved properties. Proved properties are impaired whenever the carrying value of the properties exceed their estimated undiscounted future cash flows.

· Depreciation, depletion and amortization. Depreciation, depletion and amortization, or DD&A, includes the systematic expensing of the capitalized costs incurred to acquire, exploit and develop natural gas and oil properties. As a “successful efforts” company, all costs associated with acquisition and development efforts and all successful exploration efforts are capitalized, and these costs are depleted using the units of production method.

· Incentive unit compensation expense. For more information regarding compensation expense recognized associated with incentive units, see Note 12 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under Item 1 of this quarterly report.

· General and administrative expense. These costs include overhead, including payroll and benefits for employees, costs of maintaining headquarters, costs of managing production and development operations, compensation expense associated with certain long-term incentive-based plans, franchise taxes, audit and other professional fees, and legal compliance expenses.

· Interest expense. Both MRD and MEMP finance a portion of their working capital requirements and acquisitions with borrowings under revolving credit facilities and senior note issuances. As a result, both MRD and MEMP incur substantial interest expense that is affected by both fluctuations in interest rates and financing decisions. We expect to continue to incur significant interest expense as we continue to grow.

· Income tax expense. We are a corporation subject to federal and certain state income taxes. Prior to our initial public offering, MRD LLC was organized as a pass-through entity for federal income tax purposes and was not subject to federal income taxes; however, certain of its consolidating subsidiaries were taxed as corporations and subject to federal income taxes.

48

Reserves Sensitivity

Historically, commodity prices have been extremely volatile and we expect this volatility to continue for the foreseeable future. For example, for the five years ended December 31, 2014, the NYMEX-WTI oil future price ranged from a high of $113.93 per Bbl to a low of $53.27 per Bbl, while the NYMEX-Henry Hub natural gas future price ranged from a high of $6.15 per MMBtu to a low of $1.91 per MMBtu. For the nine months ended September 30, 2015, the West Texas Intermediate posted price ranged from a high of $61.43 per Bbl on June 10, 2015 to a low of $38.24 per Bbl on August 24, 2015 and the Henry Hub spot market price ranged from a high of $3.233 per MMBtu on January 15, 2015 to a low of $2.490 per MMBtu on April 27, 2015. NGL prices have also suffered significant recent declines. The continuation of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital.

We are unable to predict future commodity prices with any greater precision than the futures market. To quantify the effect of changes in the current pricing environment on the quantities of our year-end 2014 reported proved reserves, we re-ran our December 31, 2014 reserve report using September 30, 2015 NYMEX forward strip pricing. If we had used NYMEX forward strip pricing as of September 30, 2015 to determine our proved reserves as of December 31, 2014, our estimated proved reserves as of December 31, 2014 would have been 1,595 Bcfe, which is 2% less than the 1,632 Bcfe reported as of December 31, 2014 in our Annual Report on Form 10-K for the year ended December 31, 2014. This calculation strictly isolates the potential impact of commodity prices on our estimated proved reserves. Other than the price adjustment, we did not re-engineer our estimated proved reserves to account for cost reductions or any other factors impacting the estimation of proved reserves. For example, this estimate does not give effect to any production or drilling or completion activity that has occurred since December 31, 2014. This estimate was prepared by our internal reserve engineers and has not been audited or reviewed by our independent reserve engineers.

Critical Accounting Policies and Estimates

Significant estimates include, but are not limited to, oil and natural gas reserves; depreciation, depletion, and amortization of proved oil and natural gas properties; future cash flows from oil and natural gas properties; impairment of long-lived assets; fair value of derivatives; fair value of equity compensation; fair value of incentive unit compensation; fair values of assets acquired and liabilities assumed in business combinations and asset retirement obligations. These estimates, in our opinion, are subjective in nature, require the exercise of professional judgment and involve complex analysis.

When used in the preparation of our consolidated financial statements, such estimates are based on our current knowledge and understanding of the underlying facts and circumstances and may be revised as a result of actions we take in the future. Changes in these estimates will occur as a result of the passage of time and the occurrence of future events. Subsequent changes in these estimates may have a significant impact on our consolidated financial position, results of operations and cash flows.

Results of Operations

MRD Segment

The MRD Segment’s combined results of operations for the three and nine months ended September 30, 2015 and 2014 presented below have been derived from our consolidated and combined financial statements. The comparability of the results of operations among the periods presented is impacted by the distribution by MRD LLC of the following to MRD Holdco prior to our initial public offering: (i) BlueStone, which sold substantially all of its assets in July 2013 for $117.9 million, MRD Royalty LLC, which owned certain immaterial 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 and (ii) 5,360,912 subordinated units of MEMP (which converted to common units on February 13, 2015 and were then sold by MRD Holdco during the second quarter of 2015).

Segment financial information has been retrospectively revised for material common control transactions between the MEMP Segment and the MRD Segment for comparability purposes, which includes the acquisition by the MEMP Segment of certain assets from the MRD Segment in East Texas in February 2015 in exchange for approximately $78.4 million in cash and certain properties in North Louisiana.

49

	Three Months Ended September 30,						Nine months ended September 30,
	2015			2014			2015			2014
	(in thousands)
Oil & natural gas sales	$	111,654		$	99,029		$	277,282		$	297,328
Lease operating		7,949			4,333			17,025			12,361
Gathering, processing, and transportation (including affiliate)		31,848			11,941			64,713			30,793
Exploration		4,068			133			7,024			1,213
Production and ad valorem taxes		2,751			2,987			8,666			9,141
Depreciation, depletion, and amortization		53,035			30,798			129,394			86,741
Incentive unit compensation expense		4,965			25,550			31,305			969,390
General and administrative		11,695			9,127			34,994			26,880
(Gain) loss on commodity derivative instruments		(125,167	)		(33,090	)		(202,894	)		(17,130	)
(Gain) loss on sale of properties		—			—			50			3,057
Interest expense, net		(9,176	)		(9,887	)		(28,545	)		(44,355	)
Loss on extinguishment of debt		—			—			—			(37,248	)
Income tax benefit (expense)		(54,431	)		(26,522	)		(77,345	)		(14,701	)
Net income (loss)		56,551			10,816			80,219			(934,541	)
Natural gas and oil revenue:
Oil sales	$	16,152		$	19,251		$	46,297		$	63,650
NGL sales		17,240			19,474			42,736			61,187
Natural gas sales		78,262			60,304			188,249			172,491
Total natural gas and oil revenue	$	111,654		$	99,029		$	277,282		$	297,328
Production Volumes:
Oil (MBbls)		365			200			963			654
NGLs (MBbls)		1,052			470			2,224			1,330
Natural gas (MMcf)		28,827			14,499			67,490			37,470
Total (MMcfe)		37,329			18,519			86,612			49,375
Average net production (MMcfe/d)		405.8			201.3			317.3			180.9
Average sales price:
Oil (per Bbl)	$	44.25		$	96.26		$	48.08		$	97.32
NGL (per Bbl)		16.39			41.43			19.22			46.01
Natural gas (per Mcf)		2.71			4.16			2.79			4.60
Total (Mcfe)	$	2.99		$	5.35		$	3.20		$	6.02
Average unit costs per Mcfe:
Lease operating expense	$	0.21		$	0.23		$	0.20		$	0.25
Gathering, processing, and transportation  (including affiliate)		0.85			0.64			0.75			0.62
Production and ad valorem taxes		0.07			0.16			0.10			0.19
General and administrative expenses		0.31			0.49			0.40			0.54
Depletion, depreciation, and amortization		1.42			1.66			1.49			1.76

Three Months Ended September 30, 2015 Compared to the Three Months Ended September 30, 2014

The MRD Segment recorded net income of $56.6 million during the three months ended September 30, 2015 compared to net income of $10.8 million during the three months ended September 30, 2014.

· Oil, natural gas and NGL revenues for 2015 totaled $111.7 million, an increase of $12.6 million compared with 2014. Production increased 18.8 Bcfe (approximately 102%) primarily due to drilling activities in North Louisiana. The average realized sales price decreased $2.36 per Mcfe (approximately 44%) due to lower commodity prices. The volume and pricing variance contributed to an approximate $100.6 million increase and offset by a $88.0 million decrease in revenues, respectively.

· Lease operating expenses were $7.9 million and $4.3 million for 2015 and 2014, respectively. On a per Mcfe basis, lease operating expenses decreased to $0.21 for 2015 from $0.23 for 2014 due to increased production volumes. Certain items, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges.

· Gathering, processing and transportation expenses, including affiliates, were $31.8 million and $11.9 million for 2015 and 2014, respectively. The increase of $19.9 million is primarily due to an increase in natural gas and NGL volumes and an increase in the rate due to efficient cryogenic processing associated with the new gas processing agreements. On a per Mcfe basis, gathering, processing and transportation expenses, including affiliates, were $0.85 for 2015 compared to $0.64 for 2014. For more information regarding the new midstream service agreements, see Note 13 of the Notes to the Unaudited Condensed Consolidated and Combined Financial Statements included under “Item 1. Financial Statements” of this quarterly report.

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· DD&A expense for 2015 was $53.0 million compared to $30.8 million for 2014, an increase of $22.2 million.The increase is due to an increase in production volumes and was partially offset by a decrease in the rate as reserves grew faster than costs subject to depletion. Increased production volumes caused DD&A expense to increase by approximately $31.3 million and the change in the DD&A rate between periods caused DD&A expense to decrease by approximately $9.1million. 

· Incentive unit compensation expense for 2015 was $5.0 million related to MRD Holdco incentive units as discussed in Note 12 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under Item 1 of this quarterly report. Incentive unit compensation expense of approximately $25.6 million was recorded in 2014 related to MRD Holdco incentive units.

· General and administrative expenses for 2015 were $11.7 million compared to $9.1 million for 2014. General and administrative expenses for 2015 included $0.2 million of transaction-related costs compared to $0.5 million of transaction-related costs in 2014. Expense associated with our long-term incentive plan (“LTIP”) awards increased $1.4 million between periods. Increased salaries and employee headcount also contributed to increased general and administrative expenses between periods.

· Net gains on commodity derivative instruments of $125.2 million were recognized during 2015, consisting of $44.0 million of cash settlement receipts and a $81.2 million increase in the fair value of open hedge positions. Net gains on commodity derivative instruments of $33.1 million were recognized during 2014, consisting of $3.7 million of cash settlement receipts and a $29.4 million increase in the fair value of open hedge positions.

Given the volatility of commodity prices, it is not possible to predict future reported mark-to-market net gains or losses and the actual net gains or losses that will ultimately be realized upon settlement of the hedge positions in future years. If commodity prices at settlement are lower than the prices of the hedge positions, the hedges are expected to mitigate the otherwise negative effect on earnings of lower oil, natural gas and NGL prices. However, if commodity prices at settlement are higher than the prices of the hedge positions, the hedges are expected to dampen the otherwise positive effect on earnings of higher oil, natural gas and NGL prices and will, in this context, be viewed as having resulted in an opportunity cost.

· Net interest expense during 2015 was $9.2 million, including amortization of deferred financing fees of approximately $0.7 million. Net interest expense during 2014 was $9.9 million, including amortization of deferred financing fees of approximately $0.7 million. The period-to-period increase in capitalized interest was $2.1 million.

Average outstanding borrowings under our revolving credit facility were $245.6 million during 2015. Average outstanding borrowings under our revolving credit facility were $100.3 million during 2014. For both 2015 and 2014, we had an average of $600.0 million aggregate principal amount of the MRD Senior Notes issued and outstanding.

· Income tax expense for 2015 was $54.4 million compared to $26.5 million for 2014. The increase in income tax expense is primarily the result of an increase in the net income subject to income taxes for 2015, as discussed above. The effective tax rate was 49.0% for 2015 compared to 71.0% for 2014. The effective tax rate for both 2015 and 2014 differs from the federal statutory income tax rate primarily due to the non-deductibility of incentive unit compensation and state income tax.

Nine Months Ended September 30, 2015 Compared to the Nine Months Ended September 30, 2014

The MRD Segment recorded net income of $80.2 million during the nine months ended September 30, 2015 compared to net loss of $934.5 million during the nine months ended September 30, 2014.

· Oil, natural gas and NGL revenues for 2015 totaled $277.3 million, a decrease of $20.0 million compared with 2014. Production increased 37.2 Bcfe (approximately 75%) primarily due to drilling activities in North Louisiana. The average realized sales price decreased $2.82 per Mcfe (approximately 47%) primarily due to lower commodity prices. The volume and pricing variance contributed to an approximate $224.2 million increase and $244.2 million decrease in revenues, respectively.

· Lease operating expenses were $17.0 million and $12.4 million for 2015 and 2014, respectively. On a per Mcfe basis, lease operating expenses decreased to $0.20 for 2015 from $0.25 for 2014 due to increased production volumes. Certain items, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges.

· Gathering, processing and transportation expenses, including affiliates, were $64.7 million and $30.8 million for 2015 and 2014, respectively. The increase of $33.9 million is primarily due to an increase in natural gas and NGL volumes and an increase in the rate due to efficient cryogenic processing associated with new gas processing agreements. On a per Mcfe basis, gathering, processing and transportation expenses, including affiliates, were $0.75 for 2015 compared to $0.62 for 2014. For more information regarding the new midstream service agreements, see Note 13 of the Notes to the Unaudited Condensed Consolidated and Combined Financial Statements included under “Item 1. Financial Statements” of this quarterly report.

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· DD&A expense for 2015 was $129.4 million compared to $86.7 million for 2014, an increase of $42.7 million. The increase is due to an increase in production volumes and was partially offset by a decrease in the rate as reserves grew faster than costs subject to depletion. Increased production volumes caused DD&A expense to increase by approximately $65.5 million and the change in the DD&A rate between periods caused DD&A expense to decrease by approximately $22.8million. 

· Incentive unit compensation expense for 2015 was $31.3 million related to MRD Holdco incentive units as discussed in Note 12 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under Item 1 of this quarterly report. Incentive unit compensation expense of approximately $969.4 million was recorded in 2014, of which $831.1 million related to WildHorse Resources’ incentive units, $137.3 million related to MRD Holdco incentive units, and $1.0 million related to BlueStone incentive units.

· General and administrative expenses for 2015 were $35.0 million compared to $26.9 million for 2014. General and administrative expenses included $1.6 million of transaction-related costs in both 2015 and 2014. Expense associated with our LTIP awards for 2015 was $6.1 million compared to $1.5 million in 2014. Increased salaries and employee headcount also contributed to increased general and administrative expenses between periods.

· Net gains on commodity derivative instruments of $202.9 million were recognized during 2015, consisting of $114.3 million of cash settlement receipts in addition to a $88.6 million increase in the fair value of open hedge positions. Net gains on commodity derivative instruments of $17.1 million were recognized during 2014, consisting of $4.9 million of cash settlement payments offset by $22.0 million related to the increase in the fair value of open hedge positions.

· Net interest expense during 2015 was $28.5 million, including amortization of deferred financing fees of approximately $2.1 million. Net interest expense during 2014 was $44.4 million, including amortization of deferred financing fees of approximately $2.6 million. The period-to-period increase in capitalized interest was $4.2 million.

Average outstanding borrowings under our revolving credit facility were $189.8 million during 2015. Average outstanding borrowings under WildHorse Resources’ revolving credit facility and our revolving credit facility were $206.5 million during 2014. For 2015, we had an average of $600.0 million aggregate principal amount of the MRD Senior Notes issued and outstanding. For 2014, we had an average of $214.1 million aggregate principal amount of the PIK notes issued and outstanding, an average of $201.2 million aggregate principal outstanding for the WildHorse Resources’ second lien term facility, and an average of $600.0 million aggregate principal amount of the MRD Senior Notes issued and outstanding.

· Income tax expense for 2015 was $77.3 million compared to $14.7 million for 2014. The income tax expense is primarily the result of net income before income taxes for 2015, compared to net loss before income taxes for 2014, as discussed above. The effective tax rate was 49.1% for 2015 compared to negative 1.6% for 2014. The effective tax rate for 2015 differs from the federal statutory income tax rate primarily due to the non-deductibility of incentive unit compensation and state income tax. The effective tax rate for 2014 differs from the federal statutory income tax rate primarily due to the non-deductibility of incentive unit compensation and MRD’s predecessor being a pass-through entity prior to the initial public offering.

MEMP Segment

The MEMP Segment’s combined results of operations for the three and nine months ended September 30, 2015 and 2014 presented below have been derived from our consolidated and combined financial statements. The comparability of the results of operations among the periods presented is impacted by the following transactions:

· the Eagle Ford acquisition in March 2014 for a net purchase price of $168.1 million; and

· the Wyoming acquisition in July 2014 for a net purchase price of approximately $906.1 million.

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	Three Months Ended September 30,						Nine months ended September 30,
	2015			2014			2015			2014
	(in thousands)
Oil & natural gas sales	$	87,519		$	164,935		$	276,689		$	423,782
Lease operating		45,416			41,878			130,782			99,526
Gathering, processing, and transportation		8,134			7,862			25,402			21,016
Exploration		2,141			42			2,263			252
Production and ad valorem taxes		6,896			11,053			19,609			24,482
Depreciation, depletion, and amortization		53,305			53,649			150,857			129,165
Impairment of proved oil and natural gas properties		361,836			67,181			613,183			67,181
General and administrative		13,910			12,069			42,798			34,181
(Gain) loss on commodity derivative instruments		(244,888	)		(156,402	)		(328,944	)		28,710
Interest expense, net		(31,255	)		(26,458	)		(87,983	)		(60,573	)
Net income (loss)		(191,981	)		101,307			(468,498	)		(43,225	)
Natural gas and oil revenue:
Oil sales	$	40,516		$	90,281		$	137,584		$	195,398
NGL sales		10,089			24,891			33,425			61,684
Natural gas sales		36,914			49,763			105,680			166,700
Total natural gas and oil revenue	$	87,519		$	164,935		$	276,689		$	423,782
Production Volumes:
Oil (MBbls)		967			996			3,002			2,090
NGLs (MBbls)		729			670			2,120			1,779
Natural gas (MMcf)		13,204			12,177			37,907			36,229
Total (MMcfe)		23,394			22,172			68,640			59,444
Average net production (MMcfe/d)		254.3			241.0			251.4			217.7
Average sales price:
Oil (per Bbl)	$	41.90		$	90.64		$	45.83		$	93.47
NGL(per Bbl)		13.84			37.15			15.77			34.68
Natural gas (per Mcf)		2.80			4.09			2.79			4.60
Total (Mcfe)	$	3.74		$	7.44		$	4.03		$	7.13
Average unit costs per Mcfe:
Lease operating expense	$	1.94		$	1.89		$	1.91		$	1.67
Gathering, processing, and transportation		0.35			0.35			0.37			0.35
Production and ad valorem taxes		0.29			0.50			0.29			0.41
General and administrative expenses		0.59			0.54			0.62			0.58
Depletion, depreciation, and amortization		2.28			2.42			2.20			2.17

Three Months Ended September 30, 2015 Compared to the Three Months Ended September 30, 2014

A net loss of $192.0 million was recorded for the three months ended September 30, 2015, primarily due to significant losses related to impairments offset by gains on commodity derivative instruments, compared to a net income of $101.3 million recorded during the three months ended September 30, 2014.

· Oil, natural gas and NGL revenues for 2015 totaled $87.5 million, a decrease of $77.4 million compared with 2014. Production increased 1.2 Bcfe (approximately 6%), primarily from increased drilling activities. The average realized sales price decreased $3.70 per Mcfe primarily due to lower period-to-period commodity prices. The unfavorable price variance contributed to an approximate $86.5 million decrease in revenues that was partially offset by a favorable volume variance, which contributed to an approximate $9.1 million increase in revenues.

· Lease operating expenses were $45.4 million and $41.9 million for 2015 and 2014, respectively. On a per Mcfe basis, lease operating expenses were $1.94 for 2015 which was generally consistent with the $1.89 for 2014.

· Gathering, processing and transportation expenses were $8.1 million and $7.9 million for 2015 and 2014, respectively. On a per Mcfe basis, gathering, processing, and transportation expenses were $0.35 for 2015 and 2014.

· Production and ad valorem taxes for 2015 totaled $6.9 million, a decrease of $4.2 million compared with 2014 primarily due to lower realized commodity prices. On a per Mcfe basis, production and ad valorem taxes decreased to $0.29 for 2015 compared to $0.50 for 2014 due to lower realized commodity prices.

· DD&A expense for 2015 was $53.3 million compared to $53.6 million for 2014, a $0.3 million decrease. Increased production volumes caused DD&A expense to increase by approximately $3.0 million and the change in the DD&A rate between periods caused DD&A expense to decrease by approximately $3.3 million.

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· MEMP recognized $361.8 million of impairments in 2015 related to certain properties in East Texas, South Texas, and the Permian. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverableprimarily due to a downward revision of estimated proved reserves as a result of significant declines in commodity prices. During 2014, MEMP recorded impairments of $67.2 million primarily related to certain properties in South Texas. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable in part due to a downward revision of estimated proved reserves based on pricing terms specific to these properties and increased costs. 

· General and administrative expenses for 2015 were $13.9 million and included $3.0 million of unit-based compensation expense. General and administrative expenses for 2014 totaled $12.1 million and included approximately $2.4 million of unit-based compensation expense and approximately $0.9 million of acquisition-related costs. The $1.8 million period-to-period increase was primarily due to increased head count.

· Net gains on commodity derivative instruments of $244.9 million were recognized during 2015, consisting of $64.5 million of cash settlement receipts and a $180.4 million increase in the fair value of open positions. Net gains on commodity derivative instruments of $156.4 million were recognized during 2014, consisting of $0.9 million of cash settlement receipts and a $155.5 million increase in the fair value of open positions.

· Net interest expense totaled $31.3 million during 2015, including losses on interest rate swaps of approximately $3.5 million, amortization of deferred financing fees of approximately $1.3 million, and accretion of net discount associated with the senior notes of $0.6 million. Net interest expense totaled $26.5 million during 2014, including gains on interest rate swaps of $0.2 million, amortization of deferred financing fees of approximately $1.2 million, and accretion of net discounts associated with the senior notes of $0.6 million. The increase in net interest expense is primarily due to losses on interest rate swaps, an increase in outstanding borrowings under MEMP’s revolving credit facility and a higher aggregate principal amount of MEMP’s senior notes issued and outstanding for 2015 compared to 2014.

Average outstanding borrowings under MEMP’s revolving credit facility were $684.2 million during 2015 compared to $679.2 million during 2014. For 2015, MEMP had an average of $1.2 billion aggregate principal amount of its senior notes issued and outstanding. For 2014, MEMP had an average of $1.1 billion aggregate principal amount of its senior notes issued and outstanding.

Nine Months Ended September 30, 2015 Compared to the Nine Months Ended September 30, 2014

A net loss of $468.5 million was generated for the nine months ended September 30, 2015, primarily due to impairment charges partially offset by significant gains on commodity derivative instruments, compared to a net loss of $43.2 million generated for the nine months ended September 30, 2014.

· Oil, natural gas and NGL revenues for 2015 totaled $276.7 million, a decrease of $147.1 million compared with 2014. Production increased 9.2 Bcfe (approximately 15%), primarily from increased drilling activities and increased volumes from third party acquisitions. The average realized sales price decreased $3.10 per Mcfe primarily due to lower period-to-period commodity prices. Crude oil volumes comprised approximately 26% of total volumes for 2015 compared to approximately 21% of total volumes for 2014. The unfavorable price variance contributed to an approximate $212.7 million decrease in revenues that was partially offset by a favorable volume variance, which contributed to an approximate $65.6 million increase in revenues.

· Lease operating expenses were $130.8 million and $99.5 million for 2015 and 2014, respectively. On a per Mcfe basis, lease operating expenses increased to $1.91 for 2015 from $1.67 for 2014. The increase was primary due to the acquisitions of oil properties with higher lifting costs.

· Gathering, processing and transportation expenses were $25.4 million and $21.0 million for 2015 and 2014, respectively. The increase of $4.4 million is primarily due to an increase in natural gas and NGL volumes. On a per Mcfe basis, gathering, processing, and transportation increased from $0.35 for 2014 to $0.37 for 2015.

· Production and ad valorem taxes for 2015 totaled $19.6 million, a decrease of $4.9 million compared with 2014 primarily due to a decrease in commodity prices. On a per Mcfe basis, production and ad valorem taxes decreased to $0.29 for 2015 from $0.41 for 2014 due to lower realized commodity prices in East Texas, South Texas and the Permian, partially offset by higher production tax rates on a per Mcfe basis for production from MEMP’s July 2014 Wyoming acquisition.

· DD&A expense for 2015 was $150.9 million compared to $129.2 million for 2014, a $21.7 million increase primarily due to both an increase in the depletable cost base and increased production volumes related to third party acquisitions and MEMP’s drilling program. Increased production volumes caused DD&A expense to increase by approximately $20.0 million and the change in the DD&A rate between periods caused DD&A expense to increase by approximately $1.7 million.

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· Impairment expense for 2015 was $613.2 million which related to certain properties in East Texas, South Texas, the Permian, Wyoming and Colorado. 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.  MEMP recorded $67.2 million of impairments during the same period for 2014.The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable in part due to a downward revision of estimated proved reserves based on pricing terms specific to these properties and increased costs. 

· General and administrative expenses for 2015 were $42.8 million and included $7.9 million of unit-based compensation expense and $1.6 million of transaction-related costs. General and administrative expenses for 2014 totaled $34.2 million and included approximately $5.4 million of unit-based compensation expense and approximately $3.9 million of transaction-related costs. The $8.6 million period-to period increase was primarily due to increased salaries and employee headcount.

· Net gains on commodity derivative instruments of $328.9 million were recognized during 2015, consisting of $179.0 million of cash settlement receipts on expired positions and $27.1 million in cash settlements received on terminated derivatives. These gains also included a $122.8 million increase in the fair value of open positions. Net losses on commodity derivative instruments of $28.7 million were recognized during 2014, consisting of $15.0 million of cash settlement payments and $13.7 million decrease in the fair value of open positions.

· Net interest expense totaled $88.0 million during 2015, including losses on interest rate swaps of approximately $6.6 million, amortization of deferred financing fees of approximately $4.4 million, and accretion of net discount associated with the senior notes of $1.8 million. Net interest expense totaled $60.6 million during 2014, including losses on interest rate swaps of $0.9 million and amortization of deferred financing fees of approximately $2.9 million and accretion of net discounts associated with senior notes of $1.3 million. The increase in net interest expense is primarily due to the increase in outstanding borrowings under MEMP’s revolving credit facility and a higher aggregate principal amount of MEMP’s senior notes issued and outstanding for 2015 compared to 2014.

Average outstanding borrowings under MEMP’s revolving credit facility were $607.1 million during 2015 compared to $421.9 million during 2014. For 2015, MEMP had an average of $1.2 billion aggregate principal amount of its senior notes issued and outstanding. For 2014, MEMP had an average of $839.2 million aggregate principal amount of its senior notes issued and outstanding.

Consolidated

For consolidated results of operations, see MRD Segment and MEMP Segment above.

Liquidity and Capital Resources

Although results are consolidated for financial reporting, the MRD and MEMP Segments operate with independent capital structures. The MEMP Segment’s debt is nonrecourse to the Company. With the exception of cash distributions paid to the MRD Segment by the MEMP Segment related to MEMP partnership interests held by the Company, the cash needs of each segment have been met independently with a combination of operating cash flows, asset sales, credit facility borrowings and the issuance of debt and equity. We expect that the cash needs of each of the MRD Segment and the MEMP Segment will continue to be met independently of each other with a combination of these funding sources.

MRD Segment

Historically, the primary sources of liquidity have been through borrowings under credit facilities, capital contributions from NGP and certain members of management, borrowings under a second lien term loan facility, issuance of senior notes, asset sales, including dropdowns to MEMP, and net cash provided by operating activities. The primary use of cash has been for the exploration, development and acquisition of natural gas and oil properties. As we pursue reserve and production growth, we continually monitor what capital resources, including equity and debt financings, are available to meet future financial obligations, planned capital expenditure activities and liquidity requirements. Any future success in growing proved reserves and production will be highly dependent on the capital resources available. Our identified potential horizontal well locations in North Louisiana will take many years to develop.

Currently, the primary sources of liquidity and capital resources are cash flows generated by operating activities and borrowings under our revolving credit facility. We also have the ability to issue additional equity and debt as needed through both private and public offerings. We may from time-to-time refinance our existing indebtedness including by issuing longer-term fixed rate debt to refinance shorter-term floating rate debt.

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We believe our cash flows provided by operating activities and availability under our revolving credit facility will provide us with the financial flexibility and wherewithal to meet our cash requirements, including normal operating needs, and permit us to complete our remaining planned 2015 development drilling activities. However, future cash flows are subject to a number of variables, including the level of our oil and natural gas production and prices we receive for our oil and natural gas production, and significant additional capital expenditures will be required to more fully develop our properties and acquire additional properties. We can provide no assurance that operations and other needed capital will be available on acceptable terms, or at all.

As of September 30, 2015, we had $874.0 million of available borrowing capacity under our revolving credit facility and $6.8 million of cash and cash equivalents. As of September 30, 2015, we had a working capital balance of $44.3 million. We believe the available borrowings under our revolving credit facility provides sufficient liquidity to finance anticipated working capital and capital expenditure requirements. We borrowed $261.0 million in connection with the closing of the North Louisiana acquisition.

Capital Budget

For the nine months ended September 30, 2015, MRD Segment’s total capital expenditures, including unproved leasehold, were $460.5 million related primarily to the development of the Terryville Complex.

Debt Agreements—MRD Segment

Revolving Credit Facility

In June 2014, we, as borrower, and certain of our subsidiaries, as guarantors, entered into a revolving credit facility, which is a five-year, $2.0 billion revolving credit facility with a borrowing base of $1.0 billion as of September 30, 2015. 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. In September 2015, the borrowing base under our revolving credit facility was increased to $1.0 billion. If the Company consummates a potential acquisition (unrelated to the North Louisiana Acquisition) prior to December 31, 2015 and subject to certain conditions, then the fifth amendment would also increase the borrowing base and the aggregate elected commitment amounts to $1.05 billion effective immediately before consummation of such acquisition. In the future, we may be unable to access sufficient capital under the revolving credit facility as a result of (i) a decrease in our borrowing base due to a subsequent borrowing base redetermination or (ii) an unwillingness or inability on the part of our lenders to meet their funding obligations.

We believe we were in compliance with all the financial (interest coverage ratio and current ratio) and other covenants associated with our revolving credit facility as of September 30, 2015.

See Note 8 under “Item 1. Financial Statements” for additional information regarding our revolving credit facility.

MRD Senior Notes

As of September 30, 2015, MRD had $600.0 million aggregate principal amount of 5.875% senior unsecured notes due 2022 (the “MRD Senior Notes”) outstanding. The MRD Senior Notes will mature on July 1, 2022 with interest accruing at a rate of 5.875% per annum and payable semi-annually in arrears on January 1 and July 1 of each year. The MRD Senior Notes are governed by an indenture dated as of July 10, 2014. The MRD Senior Notes are fully and unconditionally guaranteed, subject to customary release provisions, on a senior unsecured basis by certain of our existing subsidiaries. See Note 8 under “Item 1. Financial Statements” for additional information regarding the MRD Senior Notes.

Debt Agreements—MEMP Segment

Revolving Credit Facility

Memorial Production Operating LLC (“OLLC”), a wholly-owned subsidiary of MEMP, is party to a $2.0 billion revolving credit facility, with a borrowing base of $1.3 billion as of September 30, 2015 that matures in March 2018 and is guaranteed by MEMP and all of its current and future subsidiaries (other than certain immaterial subsidiaries). As of November 4, 2015, MEMP’s borrowing base was reduced to approximately $1.18 billion. See Note 8 under “Item 1. Financial Statements” for additional information regarding MEMP’s revolving credit facility.

Senior Notes

As of September 30, 2015, MEMP had $700.0 million aggregate principal of amount of 7.625% senior notes due 2021 (“2021 Senior Notes”) outstanding. The 2021 Senior Notes are fully and unconditionally guaranteed (subject to customary release provisions) on a joint and several basis by all of MEMP’s subsidiaries (other than Finance Corp., which is co-issuer of the 2021 Senior Notes, and certain immaterial subsidiaries). The 2021 Senior Notes will mature on May 1, 2021 with interest accruing at a rate of 7.625% per annum and payable semi-annually in arrears on May 1 and November 1 of each year. The 2021 Senior Notes were issued under and are governed by an indenture dated as of April 17, 2013.

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As of September 30, 2015, MEMP had approximately $497.0 million aggregate principal amount of 6.875% senior notes due 2022 (“2022 Senior Notes”) outstanding. The 2022 Senior Notes were issued at 98.485% of par and are fully and unconditionally guaranteed (subject to customary release provisions) on a joint and several basis by all of MEMP’s subsidiaries (other than Finance Corp., which is co-issuer of the 2022 Senior Notes, and certain immaterial subsidiaries). The 2022 Senior Notes will mature on August 1, 2022 with interest accruing at 6.875% per annum and payable semi-annually in arrears on February 1 and August 1 of each year. The 2022 Senior Notes were issued under and are governed by an indenture dated as of July 17, 2014.

See Note 8 under “Item 1. Financial Statements” for additional information regarding the 2021 Senior Notes and 2022 Senior Notes.

Commodity Derivative Contracts

Our hedging policy is designed to reduce the impact to our cash flows from commodity price volatility.

For additional information regarding the volumes of our production covered by commodity derivative contracts and the average prices at which production is hedged as of September 30, 2015, see “Item 3. Quantitative and Qualitative Disclosures About Market Risk — Counterparty and Customer Credit Risk.”

Interest Rate Derivative Contracts

Periodically, we may enter into interest rate swaps to mitigate exposure to market rate fluctuations by converting variable interest rates such as those in our credit agreement to fixed interest rates. Conditions sometimes arise where actual borrowings are less than notional amounts hedged which has and could result in over-hedged amounts from an economic perspective. From time-to-time we may enter into offsetting positions to avoid being economically over-hedged.

See “Item 3. Quantitative and Qualitative Disclosure About Market Risk” for a summary of our derivative contracts as of September 30, 2015.

Counterparty Exposure

Our hedging policy permits us to enter into derivative contracts with major financial institutions or major energy entities. Our derivative contracts are currently with major financial institutions, certain of which are also lenders under our revolving credit facility. We have rights of offset against the borrowings under our revolving credit facility. See “Item 3. Quantitative and Qualitative Disclosures About Market Risk — Counterparty and Customer Credit Risk” for additional information.

Cash Flows from Operating, Investing and Financing Activities

The following tables summarize segment cash flows from operating, investing and financing activities for the periods indicated. For information regarding the individual components of our cash flow amounts, see the Unaudited Condensed Statements of Consolidated and Combined Cash Flows included under Item 1 of this quarterly report.

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MRD Segment

	Nine months ended September 30,
	2015			2014
Net cash provided by operating activities:	$	251,832		$	155,514
Net cash used in investing activities:
Acquisition of oil and natural gas properties	$	(7,267	)	$	—
Additions to oil and gas properties		(438,262	)		(240,204	)
Additions to other property and equipment		(3,768	)		(9,120	)
Equity investments in MEMP Segment		—			(570	)
Deposits for property acquisitions		(21,286	)		—
Distributions received from MEMP Segment related to partnership interests		226			6,068
Decrease (increase) in restricted cash		—			49,946
Proceeds from the sale of oil and gas properties to third parties		13,612			6,700
Other		—			(301	)
Net cash provided by (used in) investing activities	$	(456,745	)	$	(187,481	)
Net cash provided by financing activities:
Advances on revolving credit facilities	$	403,000		$	1,139,800
Payments on revolving credit facilities		(460,000	)		(1,314,900	)
Proceeds from issuance of senior notes		—			600,000
Termination of second lien credit facility		—			(328,282	)
Redemption of senior notes		—			(351,808	)
Deferred financing costs		(1,446	)		(18,875	)
Purchase of additional interest in consolidated subsidiaries		—			(3,292	)
Proceeds from public offering		242,880			408,500
Costs incurred in conjunctions with public offering		(3,979	)		(28,198	)
Contributions from MEMP Segment		78,396			43,767
Contribution related to sale of assets to NGP affiliates		—			1,165
Distribution to noncontrolling interest		—			(325	)
Distribution to MEMP Segment		(1,912	)		(2,817	)
Distribution to MRD Holdco		—			(59,803	)
Distribution to other NGP affiliates		—			(99,463	)
Repurchases of shares		(51,197	)		—
Other		—			213
Net cash provided by (used in) financing activities	$	205,742		$	(14,318	)

Nine Months Ended September 30, 2015 Compared to the Nine Months Ended September 30, 2014

Operating Activities. Net cash flows provided by operating activities were $251.8 million during 2015 compared to $155.5 million during 2014. Production increased 37.2 Bcfe (approximately 75%) and average realized sales price decreased $2.82 per Mcfe as previously discussed under “Results of Operations—MRD Segment.” Cash paid for interest during 2015 was $17.7 million compared to $35.5 million during 2014 and cash settlements on commodity derivatives were $119.2 million higher in 2015. In 2014, $26.7 million was paid related to the WildHorse Resources incentive units and $30.2 million was paid for debt extinguishment costs.

Investing Activities. Total cash used in investing activities was $456.7 million during 2015 compared to $187.5 million for the same period in 2014. Cash used for additions to oil and gas properties was $438.3 million during 2015 compared to $240.2 million for the same period in 2014, which consisted primarily of drilling and completion activities in North Louisiana. Cash used for acquisition of oil and natural gas properties was $7.3 million during 2015 which was used to acquire oil and natural gas properties from a third party. Additions to other property and equipment were $3.8 million which consisted primarily of computer hardware, software, and other leased office space build out during 2015. The $9.1 million of additions to other property and equipment during 2014 was primarily related to new office space costs. MRD made an earnest money deposit of $21.3 million during 2015 related to its North Louisiana Acquisition. Distributions of $0.2 million and $6.0 million were received from MEMP related to partnership interests owned by the MRD Segment during 2015 and 2014, respectively. MRD LLC owned MEMP subordinated units during 2014.  These MEMP partnership interests were distributed to MRD Holdco in connection with Company’s initial public offering in June 2014.  On April 17, 2015, we sold certain oil and natural gas properties to a third party in Colorado and Wyoming for approximately $13.6 million. On May 9, 2014, Black Diamond sold certain producing and non-producing properties in the Mississippian oil play of Northern Oklahoma to a third party for cash consideration of approximately $6.7 million. There was a decrease in restricted cash of $49.9 million in 2014, which was primarily due to $50.0 million being released from the debt service reserve account associated with the PIK notes.

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Financing Activities.  Net repayments under our revolving credit facility were $57.0 million during 2015.  Amounts borrowed under our revolving credit facility were primarily used for additions to oil and natural gas properties, to fund the earnest money deposit for the North Louisiana Acquisition, and general corporate purposes, including working capital.  Net repayments under revolving credit facilities were $175.1 million during 2014.  Amounts borrowed under our revolving credit facility were primarily incurred to repay the amounts outstanding under WildHorseResources’ credit facilities in connection with the closing of our initial public offering. WildHorse Resources primarily utilized its revolving credit facility during 2014 to repurchase net profits interests from an affiliate of NGP.

Net proceeds of $586.8 million from the issuance of the MRD Senior Notes during 2014 were used to repay portions of our borrowings outstanding under our revolving credit facility.

On June 18, 2014, we completed our initial public offering pursuant to which we sold 21,500,000 shares of our common stock to the public at an offering price of $19.00 per share. After deducting underwriting discounts and commissions of $23.0 million and additional offering expenses of $5.2 million, the net proceeds from our initial public offering were approximately $380.3 million. We used approximately $360.0 million of our initial public offering proceeds to redeem the PIK notes on June 27, 2014, of which $351.8 million was classified as a financing activity and the remaining $8.2 million was classified as an operating activity representing interest expense.

On September 25, 2015, MRD 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 $238.4 million after deducting underwriting discounts and offering expenses. The net proceeds temporarily reduced borrowings outstanding under our revolving credit facility.

Distributions to NGP affiliates related to the purchase of assets were primarily related to WildHorse Resources’ February 2014 acquisition of net profits interests in the Terryville Complex from an affiliate of NGP for $63.4 million. MRD Royalty also acquired certain interests in oil and gas properties in Gonzales and Karnes Counties located in South Texas from an affiliate of NGP for $3.3 million in March 2014.

Distributions to NGP affiliates related to the sale of assets were $32.8 million during 2014. WildHorse Resources sold its subsidiary, WHR Management Company, LLC to an affiliate of the Funds for approximately $0.2 million and $33.0 million of cash was a component of the net book value transferred.

Distributions to MRD Holdco during 2014 were $59.8 million. Approximately $6.7 million of cash received by MRD LLC in connection with the sale of Golden Energy’s assets in May 2014 was distributed to MRD Holdco in connection with our initial public offering. We also reimbursed MRD LLC for the approximately $17.2 million interest payment that it made on the PIK notes on June 15, 2014, which was distributed to MRD Holdco. Remaining cash of $32.8 million released from the debt service reserve account in connection with the redemption and discharge of the PIK notes was also distributed to MRD Holdco. Bluestone distributed $3.1 million to MRD Holdco in connection with our initial public offering and restructuring transactions.

The MRD Segment received $78.4 million from the MEMP Segment in connection with the Property Swap. MRD made deemed distributions of $1.9 million and $2.8 million to MEMP related to the properties MEMP acquired in the Property Swap transaction during 2015 and 2014, respectively. The MRD Segment received $43.8 million from the MEMP Segment, of which $33.9 million was received in connection with MEMP’s acquisition of certain oil and gas properties in East Texas during 2014 and $9.9 million was a deemed contribution related to the properties MEMP acquired in the Property Swap.

Total payments remitted for employees’ tax obligations to the appropriate taxing authorities were approximately $1.2 million during 2015 upon vesting of the restricted common stock.The Company repurchased 2,888,684 shares of its common stock under its December 2014 repurchase program for an aggregate price of $50.0 million during 2015, which exhausted the December 2014 repurchase program. At December 31, 2014, there was $2.2 million accrued for 123,797 shares that were repurchased and retired in 2014. The Company has retired all of the shares of common stock repurchased and those shares of common stock are no longer issued or outstanding.  

Deferred financing costs of approximately $1.5 million and $18.9 million were incurred during 2015 and 2014, respectively.

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MEMP Segment

	Nine months ended September 30,
	2015			2014
Net cash provided by operating activities	$	185,572		$	209,946
Net cash used in investing activities:
Acquisition of oil and natural gas properties	$	(6,095	)	$	(1,083,167	)
Acquisition post-closing adjustment receipts		9,570			—
Additions to oil and gas properties		(196,055	)		(217,634	)
Additions to other property and equipment		—			(14	)
Additions to restricted investments		(3,893	)		(2,883	)
Net cash provided by (used in) investing activities	$	(196,473	)	$	(1,303,698	)
Net cash provided by financing activities
Advances on revolving credit facilities	$	345,000		$	1,325,000
Payments on revolving credit facilities		(61,000	)		(1,127,000	)
Proceeds from the issuance of senior notes		—			492,425
Repurchase of senior notes		(2,914	)		—
Deferred financing costs		(319	)		(11,409	)
Contribution from MRD Segment		1,912			2,817
Contribution from general partner		—			570
Proceeds from public equity offering		—			553,288
Costs incurred in conjunction with issuance of common units		—			(12,222	)
Distributions to partners		(138,349	)		(107,070	)
Distributions to MRD Segment		(78,396	)		(43,767	)
Restricted units returned to plan		(1,288	)		—
Repurchased units under unit repurchase program		(54,184	)		—
Net cash provided by (used in) financing activities	$	10,462		$	1,072,632

Nine Months Ended September 30, 2015 Compared to the Nine Months Ended September 30, 2014

Operating Activities. Key drivers of net operating cash flows are commodity prices, production volumes and operating costs. Net cash provided by operating activities decreased by $24.4 million and net income decreased by $425.3 million. Production increased 9.2 Bcfe (approximately 15%) while average realized sales price decreased $3.10 per Mcfe. Net cash provided by operating activities included a $194.0 million period-to-period increase in cash settlements received on expired commodity derivative instruments. The period-to-period increases in cash settlements received on expired commodity derivatives partially offset decreased revenues and increased operating costs as previously discussed under “—Results of Operations—MEMP Segment.”

Investing Activities. Net cash used in investing activities during 2015 was $196.5 million, of which $6.1 million was used to acquire oil and natural gas properties from a third party and $196.1 million was used for additions to oil and natural gas properties. Cash used in investing activities during 2014 was $1.3 billion, of which $1.1 billion was used to acquire oil and natural gas properties from third parties and $217.6 million was used for additions to oil and natural gas properties. Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with MEMP’s offshore Southern California oil and gas properties. Additions to restricted investments were $3.9 million during 2015 compared to $2.9 million during 2014. MEMP received a post-closing settlement receipt of $9.6 million related to its July 2014 Wyoming acquisition during 2015.

Financing Activities. Distributions to partners during 2015 were $138.3 million compared to $107.1 million during 2014, of which the MRD Segment received $0.2 million during 2015 compared to $6.1 million during 2014. The MEMP Segment distributed $78.4 million to the MRD Segment in connection with the Property Swap acquisition. MEMP received a contribution of $1.9 million and $2.8 million from the MRD Segment related to the properties MEMP acquired in the Property Swap transaction during 2015 and 2014, respectively. The MEMP Segment distributed $43.8 million to the MRD Segment, of which $33.9 million was related to the acquisition of certain oil and gas properties in East Texas during 2014 by MEMP and $9.9 million was a deemed contribution related to the properties MEMP acquired in the Property Swap.

MEMP issued a total of 24,840,000 common units generating gross proceeds of approximately $553.3 million offset by approximately $12.2 million of costs incurred in conjunction with the issuance of common units during 2014. The net proceeds from these issuances were primarily used to repay borrowings under MEMP’s revolving credit facility. Proceeds of $492.4 million from the issuances of the 2022 Senior Notes during 2014 were also used to repay borrowings outstanding under MEMP’s revolving credit facility.

MEMP had net borrowings of $284.0 million under its revolving credit facility during 2015 that were primarily used to fund the Property Swap acquisition, common unit repurchases and to fund MEMP’s drilling program. MEMP had net borrowings of $198.0 million under its revolving credit facility during 2014 that were used primarily to fund its March 2014 Eagle Ford acquisition, the July 2014 Wyoming acquisition and to fund MEMP’s drilling program.

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MEMP repurchased $54.2 million in common units during 2015, which represents a repurchase and retirement of 3,641,721 common units under the MEMP Repurchase Program (including commonunit repurchases of $1.4 million, representing 93,800 common units, accrued at December 31, 2014).MEMP repurchased a principal amount of approximately $3.0 million of the 2022 Senior Notes at a price of 83.000% of the face value of the 2022 Senior Notes in January 2015, of which $2.9 million was classified as a financing outflow representing repayment of the original proceeds and $0.3 million classified as an operating inflow.

Contractual Obligations

During the nine months ended September 30, 2015, there were no significant changes in our consolidated contractual obligations from those reported in our Recast Form 8-K filed with the SEC on July 8, 2015, except for the addition of the midstream service agreements with PennTex. For more information, see Note 13 of the Notes to the Unaudited Condensed Consolidated and Combined Financial Statements included under “Item 1. Financial Statements” of this quarterly report.

Off–Balance Sheet Arrangements

As of September 30, 2015, we had no off–balance sheet arrangements.

Recently Issued Accounting Pronouncements

For a discussion of recent accounting pronouncements that will affect us, see Note 2 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under “Item 1. Financial Statements” of this quarterly report.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

In the normal course of our business operations, we are exposed to certain risks, including changes in interest rates and commodity prices. We may enter into derivative instruments to manage or reduce market risk, but do not enter into derivative agreements for speculative purposes. We do not designate these or plan to designate future derivative instruments as hedges for accounting purposes. Accordingly, the changes in the fair value of these instruments are recognized currently in earnings. We believe that our exposures to market risk have not changed materially since those reported under “Quantitative and Qualitative Disclosures About Market Risk,” included in our 2014 Form 10-K filed with the SEC on March 18, 2015.

Commodity Price Risk

Our major market risk exposure is in the pricing that we receive for our natural gas, oil and NGL production. To reduce the impact of fluctuations in commodity prices on our revenues, or to protect the economics of property acquisitions, we periodically enter into derivative contracts with respect to a portion of our projected production through various transactions that fix the future prices received.

For additional information regarding the volumes of our production covered by commodity derivative contracts and the average prices at which production is hedged as of September 30, 2015, see Note 5 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under “Item 1. Financial Statements” of this quarterly report.

Interest Rate Risk

Our risk management policy provides for the use of interest rate swaps to reduce the exposure to market rate fluctuations by converting variable interest rates to fixed interest rates. Conditions sometimes arise where actual borrowings are less than notional amounts hedged which has and could result in over-hedged amounts from an economic perspective. From time to time we enter into offsetting positions to avoid being economically over-hedged. See Note 5 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under “Item 1. Financial Statements” of this quarterly report for interest rate swap arrangements that were outstanding at September 30, 2015.

At September 30, 2015, we had $126.0 million of Eurodollar borrowings outstanding under our revolving credit facility, with an interest rate of LIBOR plus 1.50%, or 1.69%. Assuming no change in the amount of debt outstanding, the impact on interest expense of a 10% increase or decrease in the in the variable component of the stated interest rates would be less than $0.1 million per year.

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The fair value of MRD Senior Notes, MEMP’s 2022 Senior Notes and MEMP’s 2021 Senior Notes is sensitive to changes in interest rates. We estimate the fair value of MRD Senior Notes, MEMP’s 2022 Senior Notes and MEMP’s 2021 Senior Notes using quoted market prices. The carrying value (net of any discount or premium) is compared to the estimated fair value in the table below (in thousands):

	September 30, 2015
	Carrying		Estimated
Description	Amount		Fair Value
MRD Segment:
5.875% senior notes, fixed-rate, due May 1, 2022	$	600,000	$	547,500
MEMP Segment:
7.625% senior notes, fixed rate, due May 1, 2021	$	691,676	$	469,000
6.875% senior notes, fixed-rate, due August 1, 2022	$	490,589	$	303,164

Counterparty and Customer Credit Risk

We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. In addition, our derivative contracts may expose us to credit risk in the event of nonperformance by counterparties. See Note 5 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under “Item 1. Financial Statements” of this quarterly report for additional information regarding credit risk associated with our derivative instruments.

ITEM 4. CONTROLS AND PROCEDURES.

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) of the Securities Exchange Act of 1934 (the “Exchange Act”), we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of September 30, 2015. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of September 30, 2015 at the reasonable assurance level.

Change in Internal Controls Over Financial Reporting

No changes in our internal control over financial reporting occurred during the quarter ended September 30, 2015 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

The certifications required by Section 302 of the Sarbanes-Oxley Act of 2002 are filed as Exhibits 31.1 and 31.2, respectively, to this quarterly report.

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PART II—OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS.

For information regarding legal proceedings, see Part I, “Item 1. Financial Statements”, Note 15, “Commitments and Contingencies – Litigation & Environmental,” of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included in this quarterly report, which is incorporated herein by reference.

ITEM 1A. RISK FACTOR.

In addition to the risk factor described below, security holders and potential investors in our securities should carefully consider the risk factors disclosed in our 2014 Form 10-K filed with the SEC on March 18, 2015 and our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2015 filed with the SEC on May 11, 2015.

The standardized measure of our estimated proved reserves and our PV-10 as of December 31, 2014 and the estimated proved and possible reserves attributable to certain of our properties in North Louisiana as of July 31, 2015 may be higher than the current market value of our estimated proved oil and natural gas reserves.

The present value of future net cash flows from our proved reserves as of December 31, 2014, or standardized measure, and our PV-10 may not be the current market value of our estimated natural gas and oil reserves. In accordance with rules established by the SEC and the Financial Accounting Standards Board, we base the estimated discounted future net cash flows from our proved reserves on the 12-month average oil and gas index prices, calculated as the unweighted arithmetic average for the first-day-of-the-month price for each month and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties. Our estimated proved reserves as of December 31, 2014 and related PV-10 and Standardized Measure were calculated under SEC rules using twelve-month trailing average benchmark prices of $94.99 per barrel of oil (WTI) and $4.35 per MMBtu (Henry Hub spot). Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than the current estimate. On September 30, 2015, the prompt month NYMEX-WTI futures price for crude oil was $45.71 per Bbl and the prompt month NYMEX-Henry Hub futures price of natural gas was $2.52 per MMBtu. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general. Using more recent prices in estimating our proved reserves, without giving effect to any acquisitions or development activities we have executed during 2015, would likely result in a reduction in proved reserve volumes due to economic limits, which would reduce the PV-10 and standardized measure of our proved reserves.

Similarly, the estimated proved and possible reserves attributable to the approximately 45,807 gross (45,121 net) acres we acquired in the North Louisiana Acquisition and the approximately 6,521 net acres we acquired in 2015 through our organic leasing efforts in and around the properties acquired in the North Louisiana Acquisition (collectively, the “Acquisition Acreage”) and associated net value of future net cash flows may not be the current market value of such estimated reserves. Additionally, the development of possible reserves will require additional capital expenditures compared to proved reserves, and possible reserves are less certain to be recovered than proved reserves. The estimated proved and possible reserves attributable to the Acquisition Acreage as of July 31, 2015 and related possible reserve PV-10 were calculated under SEC rules using twelve-month trailing average benchmark prices of $64.15 per barrel of oil (WTI) and $3.25 per MMBtu (Henry Hub spot).

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.

(a) Recent sales of unregistered securities.

None.

(b) Use of proceeds.

None.

(c) Purchases of equity securities by the issuer and affiliated purchasers.

During the quarterly period ended September 30, 2015, there were no repurchases of our common stock.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES.

None.

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ITEM 4. MINE SAFETY DISCLOSURES. 

Not applicable.

ITEM 5. OTHER INFORMATION.

None.

ITEM 6. EXHIBITS.

The information required by this Item 6. Exhibits is set forth in the Exhibit Index accompanying this quarterly report on Form 10-Q, which is incorporated herein by reference.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	Memorial Resource Development Corp.
	(Registrant)
Date: November 4, 2015	By:	/s/Andrew J. Cozby
	Name:	Andrew J. Cozby
	Title:	Senior Vice President and Chief Financial Officer

65

EXHIBIT INDEX

Exhibit Number		Description
2.1##	—	Purchase and Sale Agreement, dated as of May 2, 2014, among Merit Management Partners I, L.P., Merit Energy Partners III, L.P., Merit Pipeline Company, LLC and Merit Energy Company, LLC and Memorial Production Operating LLC (incorporated by reference to Exhibit 2.1 to Memorial Production Partners LP’s Current Report on Form 8-K (File No. 001-35364) filed on May 5, 2014).
2.2##	—		Purchase and Sale Agreement, dated as of March 25, 2014, between Alta Mesa Eagle, LLC and Memorial Production Operating LLC (incorporated by reference to Exhibit 2.1 to Memorial Production Partners LP’s Current Report on Form 8-K (File No. 001-35364) filed on March 25, 2014).
2.3##	—		Purchase and Sale Agreement, dated as of September 21, 2015, between Rockcliff-QLS Joint Venture LLC and MRD Operating LLC (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K (File No. 001-36490) filed on September 21, 2015).
3.1	—		Amended and Restated Certificate of Incorporation dated June 10, 2014 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K (File No. 001-36490) filed on June 16, 2014).
3.2	—		Amended and Restated Bylaws dated June 10, 2014 (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K (File No. 001-36490) filed on June 16, 2014).
4.1#	—		Form of Restricted Unit Agreement under the Memorial Production Partners GP LLC Long-Term Incentive Plan (incorporated by reference to Exhibit 4.6 to Memorial Production Partners LP’s Registration Statement on Form S-8 (File No. 333-178493) filed on December 14, 2011).
10.1	—		Fifth Amendment to Credit Agreement by and among Memorial Resource Development Corp., as borrower, Bank of America, N.A., as administrative agent, and the other lenders and parties party thereto, dated as of September 18, 2015 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (File No. 001-36490) filed on September 21, 2015).
10.2*	—		Amendment No. 2 to Amended and Restated Gas Processing Agreement by and between PennTex North Louisiana Operating, LLC and MRD Operating LLC, dated as of August 5, 2015.
10.3*	—		Amendment No. 2 to Gas Gathering Agreement by and between PennTex North Louisiana Operating, LLC and MRD Operating LLC, dated as of August 5, 2015.
10.4*	—		Amendment No. 1 to Gas Transportation Agreement by and between PennTex North Louisiana Operating, LLC and MRD Operating LLC, dated as of August 5, 2015.
10.5	—		Amendment to Water Disposal Agreement, dated effective as of July 1, 2015, between Memorial Production Operating LLC and Classic Pipeline & Gathering, LLC (incorporated by reference to Exhibit 10.1 to Memorial Production Partners LP’s Quarterly Report on Form 10-Q (File No. 001-35364) filed on November 4, 2015).
31.1*	—		Certification of Principal Executive Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.
31.2*	—		Certification of Principal Financial Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934
32.1*	—		Certifications of Principal Executive Officer and Principal Financial Officer pursuant to 18. U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.CAL*	—		XBRL Calculation Linkbase Document
101.DEF*	—		XBRL Definition Linkbase Document

66

101.INS*	—	XBRL Instance Document
101.LAB*	—	XBRL Labels Linkbase Document
101.PRE*	—	XBRL Presentation Linkbase Document
101.SCH*	—	XBRL Schema Document

* Filed or furnished as an exhibit to this Quarterly Report on Form 10-Q.

# Management contract or compensatory plan or arrangement.

## Pursuant to Item 601(b)(2) of Regulation S-K, the registrant agrees to furnish supplementally a copy of any omitted exhibit or schedule to the SEC upon request.

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EX-10

Exhibit 10.2

AMENDMENT NO. 2 TO
AMENDED AND RESTATED GAS PROCESSING AGREEMENT

This Amendment No. 2 (this “Amendment”), dated as of August 5, 2015, to that certain Amended and Restated Gas Processing Agreement, dated as of April 14, 2015, as amended by that certain Amendment No. 1 to Amended and Restated Gas Processing Agreement, dated as of May 20, 2015 (as so amended, the “Agreement”), is entered into by and among PennTex North Louisiana, LLC, a Delaware limited liability company (“Processor”), and MRD Operating LLC, a Delaware limited liability company (“Customer”).  Processor and Customer are each referred to herein as a “Party,” and collectively as, the “Parties.”  Defined terms used but not defined herein have the meaning given to them in the Agreement.

WHEREAS, Processor has agreed to provide certain processing services for Customer, and Customer has agreed to deliver Gas and/or make certain payments to Processor, pursuant to the Agreement; and

WHEREAS, the Parties desire to amend the Agreement in accordance with Section 19.20 thereof as set forth herein to facilitate the processing of Customer Gas in the Initial Quarterly Period, Second Quarterly Period and Third Quarterly Period (each as defined below).

NOW THEREFORE, in consideration of the premises of this Amendment and the agreements set forth herein and other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged, and intending to be legally bound hereby, the Parties hereby agree as follows:

1.Definitions. Article I of the Agreement is hereby amended by adding thereto in alphabetical order or amending and restating each of the following definitions, which shall read in full as follows:

“Gross Heating Value” shall mean the number of Btus produced by the complete combustion in air, at constant pressure of one (1) cubic foot of Gas, at a base temperature of sixty degrees Fahrenheit (60°F) and at a reference pressure base equal to 14.73 psia, with air of the temperature and pressure of the Gas, after the products of combustion are cooled to the initial temperature of the Gas, and after the air and water formed by the combustion is condensed to the liquid state.  The gross heating value of the Gas shall be corrected for water vapor under testing conditions to the actual water vapor content of the Gas being delivered; provided, however, if the actual water vapor content is seven (7) pounds per 1,000,000 standard cubic feet of Gas or less, the Gas shall be deemed “dry” and no water vapor correction shall be made.

“Initial Quarter Deficiency Payment” shall have the meaning given to such term in Section 9.4.

“Initial Quarterly Period” shall mean the period commencing at 9:00 a.m., Central Clock Time on June 1, 2015 and ending at 9:00 a.m., Central Clock Time on July 1, 2015.

“MMcf” shall mean one million (1,000,000) cubic feet at a pressure of 14.73 psia and a temperature of sixty degrees Fahrenheit (60°F).

“Second Quarter Forecast Volume” shall mean with respect to the Second Quarterly Period, the quantity of Gas (in MMBtu) equal to the cumulative sum of 161,000 MMBtu per Day for all Days during the Second Quarterly Period.

“Second Quarterly Period” shall mean the period commencing at 9:00 a.m., Central Clock Time on July 1, 2015 and ending at 9:00 a.m., Central Clock Time on October 1, 2015.

“Thermal Content” shall mean (i) with respect to Gas, the product of a volume of Gas and the Gross Heating Value of such Gas, adjusted to a same pressure base of 14.73 psia, as expressed in MMBtus, and (ii) with respect to a given Plant Product, the product of a volume of such Plant Product and the Gross Heating Value of such Plant Product.

“Third Quarterly Period” shall mean the period commencing at 9:00 a.m., Central Clock Time on October 1, 2015 and ending at 9:00 a.m., Central Clock Time on January 1, 2016.

2.Measurement Factors

3..  Section 6.3(a) of the Agreement is hereby amended and restated as follows:

(a)The unit of volume shall be one (1) cubic foot of Gas at a base temperature of sixty degrees Fahrenheit (60°F) and at a base pressure of fourteen and seventy-three hundredths (14.73) pounds per square inch absolute.  The atmospheric pressure shall be assumed to be a constant, determined by elevation and specific site location, regardless of the variations of such atmospheric pressure from time to time.    

3.Calculation of Shrinkage

4..  Section 8.2 of the Agreement is hereby amended and restated as follows:

8.2Calculation of Shrinkage

5..  Customer’s share of Shrinkage shall be calculated by Processor each Month, for each Plant, by multiplying (i) the number of Gallons of each produced component of the mixed stream of Plant Products as determined and allocated to Customer Gas pursuant to the terms of this Agreement, by (ii) the Btu equivalent of each such component as set forth in the GPA Technical Standards Publication No. 2145-03, as revised from time to time, and as adjusted to sixty degrees Fahrenheit (60°F) and 14.73psia pressure base, with the aggregate Btus of all such components constituting Customer’s share of Shrinkage hereunder.

4.Deficiency Payments. Section 9.4 of the Agreement is hereby amended and restated as follows:

9.4Deficiency Payments. If a Quarterly Deficiency Quantity (as defined below) exists as of the end of any Quarterly Period, then Customer shall pay to Processor an amount equal to the product of (i) the Quarterly Deficiency Quantity for such Quarterly Period multiplied by (ii) the Applicable Firm Rate per MMBtu that would have been paid hereunder with respect to such Quarterly Deficiency Quantity had such Quarterly Deficiency Quantity been processed hereunder (such product being the “Deficiency Payment”). “Quarterly Deficiency Quantity” means the amount (in MMBtu), if any, determined as of the end of each Quarterly Period, by which (a) the Aggregate Gas Commitment as of the end of such Quarterly Period exceeds (b) the sum of (x) the total cumulative quantity (in MMBtu) of Customer Gas delivered at the Point of Delivery during the MQ Period as of the end of such Quarterly Period, plus (y) the total cumulative quantity (in MMBtu) of Customer Gas on which Customer has paid to Processor a Deficiency Payment under this Agreement as of the end of the preceding Quarterly Period, plus (z) the total cumulative Plant Interruption Credit Quantity (in MMBtu) as of the end of such Quarterly Period. Except as may otherwise be provided herein, any such Deficiency Payments made by Customer shall be treated by Processor as a prepayment of the Processing Fee for Customer Gas that may be delivered by Customer after the date on which Customer has delivered the Total Gas Commitment and shall be credited by Processor to the payment of the Processing Fee that otherwise would be payable hereunder for such quantities of Customer Gas delivered during the Primary Term until such prepaid fees have been exhausted; provided, however, that if a Deficiency Payment with respect to the Initial Quarterly Period is made by Customer (the “Initial Quarter Deficiency Payment”) and Customer delivers (i) Customer Gas during the Second Quarterly Period that exceeds the Second Quarter Forecast Volume or (ii) Customer Gas during the Third Quarterly Period that exceeds the MDQ in effect for the Third Quarterly Period, then the Quarterly Deficiency Quantity corresponding to such Initial Quarter Deficiency Payment shall be credited by Processor to the quantity of Customer Gas delivered in excess of the Second Quarter Forecast Volume during the last Month in the Second Quarterly Period or to the quantity of Customer Gas delivered in excess of the MDQ in effect for the Third Quarterly Period during the last Month of the Third Quarterly Period, as applicable. Notwithstanding anything in this Agreement to the contrary, (i) if and to the extent that the Quarterly Deficiency Quantity corresponding to such Initial Quarter Deficiency Payment is so credited for deliveries of Customer Gas in the Second Quarterly Period or the Third Quarterly Period, as applicable, then the Initial Quarter Deficiency Payment, and the corresponding Quarterly Deficiency Quantity, shall not be taken into account when determining the amount of prepayment and credit to which Customer is entitled

2

pursuant to the preceding sentence or in the determination of the total cumulative quantity (in MMBtu) of Customer Gas specified in clause (y) above, and (ii)if and to the extent that the Quarterly Deficiency Quantity corresponding to such Initial Quarterly Deficiency Payment is not so credited for deliveries of Customer Gas in the Second Quarterly Period or the Third Quarterly Period, as applicable, such Quarterly Deficiency Quantity shall immediately expire, shall not be available for future use by Customer and shall not be taken into account when determining the amount of prepayment and credit to which Customer is entitled pursuant to the preceding sentence or in the determination of the total cumulative quantity (in MMBtu) of Customer Gas specified in clause (y) above.  Any Deficiency Payments due by Customer hereunder shall be paid by Processor as provided in Article XII. 

5.Governing Law.  This Amendment shall be governed, interpreted and construed in accordance with the laws of the State of Texas without regard to the conflicts of laws provisions thereof.

6.Counterpart Execution.  This Amendment may be executed in any number of counterparts, each of which shall be considered an original, and all of which shall be considered one and the same instrument. Any signature delivered by a Party by facsimile transmission or electronically shall be deemed an original signature.

7.Integration with Agreement.  This Amendment shall be and hereby is incorporated into and forms a part of the Agreement.  Except as expressly provided herein, all terms and conditions of the Agreement shall remain in full force and effect.

[signature page follows]

3

IN WITNESS WHEREOF, each of the Parties has duly executed this Amendment as of the date first written above.

MRD Operating LLC
By:	Memorial Resource Development Corp., its sole member
By:	/s/ Kyle N. Roane
Name:	Kyle N. Roane
Title:	Senior Vice President
PennTex North Louisiana, LLC
By:	/s/ Robert O. Bond
Name:	Robert O. Bond
Title:	Chief Operating Officer

[Signature Page to Amendment No. 2 to Amended and Restated Gas Processing Agreement]

EX-10

Exhibit 10.3

AMENDMENT NO. 2 TO
GAS GATHERING AGREEMENT

This Amendment No. 2 (this “Amendment”), dated as of August 5, 2015, to that certain Gas Gathering Agreement, dated as of April 14, 2015, as amended by that certain Amendment No. 1 to Gas Gathering Agreement, dated as of May 20, 2015 (as so amended, the “Agreement”), is entered into by and between PennTex North Louisiana, LLC, a Delaware limited liability company (“Gatherer”), and MRD Operating LLC, a Delaware limited liability company (“Customer”).  Gatherer and Customer are each referred to herein as a “Party,” and collectively as, the “Parties.”  Defined terms used but not defined herein have the meaning given to them in the Agreement.

WHEREAS, Gatherer agreed to provide certain gathering, compression, dehydration and/or treating services for Customer pursuant to the Agreement; and

WHEREAS, the Parties desire to amend the Agreement in accordance with Article XV thereof as set forth herein.

NOW THEREFORE, in consideration of the premises of this Amendment and the agreements set forth herein and other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged, and intending to be legally bound hereby, the Parties hereby agree as follows:

1.Amendment to Article I.  Article I of the Agreement is hereby amended by amending and restating the following definition, which shall read in full as follows:

“Gross Heating Value” shall mean the number of Btus produced by the complete combustion in air, at constant pressure of one (1) cubic foot of Gas, at a base temperature of sixty degrees Fahrenheit (60°F) and at a reference pressure base equal to 14.73 psia, with air of the temperature and pressure of the Gas, after the products of combustion are cooled to the initial temperature of the Gas, and after the air and water formed by the combustion is condensed to the liquid state.  The gross heating value of the Gas shall be corrected for water vapor under testing conditions to the actual water vapor content of the Gas being delivered; provided, however, if the actual water vapor content is seven (7) pounds per 1,000,000 standard cubic feet of Gas or less, the Gas shall be deemed “dry” and no water vapor correction shall be made.  

2.Amendments to Article VIII.  

(i) The Section titled “Fees” in Article VIII of the Agreement is hereby amended by deleting subsection (b) of the section titled “Plant Delivery Point Gathering Fee” in its entirety and replacing it with the following:   

“(b) Plant Delivery Point Gathering Fee.  For all Customer Gas received by Gatherer at the Points of Receipt and allocated for delivery to either the PTX Lincoln Parish Point of Delivery or the Mt. Olive Point of Delivery each Month, Customer shall pay Gatherer a gathering fee for such Month as follows:

(i)  From the Commencement Date through November 30, 2019, $0.02 per MMBtu; and  

(ii)  Commencing on December 1, 2019, $0.05 per MMBtu.

(ii) The Section titled “Fees” in Article VIII of the Agreement is hereby amended by deleting subsection (c) of the section titled “DCP Harris Road Delivery Point Gathering Fee” in its entirety and replacing it with the following:   

“(c) DCP Harris Road Delivery Point Gathering Fee.  For all Customer Gas received by Gatherer at the Points of Receipt and allocated for delivery to the DCP Harris Road Point

of Delivery each Month, Customer shall pay Gatherer a gathering fee of $0.22 per MMBtu.” 

3.Governing Law.  This Amendment shall be governed, interpreted and construed in accordance with the laws of the State of Texas without regard to the conflicts of laws provisions thereof.

4.Counterpart Execution.  This Amendment may be executed in any number of counterparts, each of which shall be considered an original, and all of which shall be considered one and the same instrument. Any signature delivered by a Party by facsimile transmission or electronically shall be deemed an original signature.

5.Integration with Agreement.  This Amendment shall be and hereby is incorporated into and forms a part of the Agreement.  Except as expressly provided herein, all terms and conditions of the Agreement shall remain in full force and effect.

[signature page follows]

2

IN WITNESS WHEREOF, each of the Parties has duly executed this Amendment as of the date first written above.

MRD Operating LLC
By:	Memorial Resource Development Corp., its sole member
By:	/s/ Kyle N. Roane
Name:	Kyle N. Roane
Title:	Senior Vice President
PennTex North Louisiana, LLC
By:	/s/ Robert O. Bond
Name:	Robert O. Bond
Title:	Chief Operating Officer

[Signature Page to Amendment No. 2 to Gas Gathering Agreement]

EX-10

Exhibit 10.4

AMENDMENT NO. 1 TO
GAS TRANSPORTATION AGREEMENT

This Amendment No. 1 to Gas Transportation Agreement, dated as of August 5, 2015 (this “Amendment”), is entered into by and among PennTex North Louisiana, LLC, a Delaware company and successor in interest to PennTex North Louisiana Operating, LLC (“Transporter”), and MRD Operating LLC, a Delaware limited liability company (“Customer”). Transporter and Customer are each referred to herein as a “Party,” and collectively as, the “Parties.”  Defined terms used but not defined herein have the meaning given to them in the Agreement (as defined below).

WHEREAS, the Parties entered into that certain Gas Transportation Agreement, dated as of April 14, 2015 (the “Agreement”), to provide for the transportation of Customer Gas on Transporter’s Transportation System; and

WHEREAS, the Parties desire to amend the Agreement in accordance with Article XV thereof as set forth herein.

NOW THEREFORE, in consideration of the premises of this Amendment and the agreements set forth herein and other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged, and intending to be legally bound hereby, the Parties hereby agree as follows:

1.Amendment to Article I.  Article I of the Agreement is hereby amended by amending and restating the following definition, which shall read in full as follows:

“Gross Heating Value” shall mean the number of Btus produced by the complete combustion in air, at constant pressure of one (1) cubic foot of Gas, at a base temperature of sixty degrees Fahrenheit (60°F) and at a reference pressure base equal to 14.73 psia, with air of the temperature and pressure of the Gas, after the products of combustion are cooled to the initial temperature of the Gas, and after the air and water formed by the combustion is condensed to the liquid state.  The gross heating value of the Gas shall be corrected for water vapor under testing conditions to the actual water vapor content of the Gas being delivered; provided, however, if the actual water vapor content is seven (7) pounds per 1,000,000 standard cubic feet of Gas or less, the Gas shall be deemed “dry” and no water vapor correction shall be made.  

2.Governing Law.  This Amendment shall be governed, interpreted and construed in accordance with the laws of the State of Texas without regard to the conflicts of laws provisions thereof.

3.Counterpart Execution.  This Amendment may be executed in any number of counterparts, each of which shall be considered an original, and all of which shall be considered one and the same instrument. Any signature delivered by a Party by facsimile transmission or electronically shall be deemed an original signature.

4.Integration with Agreement.  This Amendment shall be and hereby is incorporated into and forms a part of the Agreement.  Except as expressly provided herein, all terms and conditions of the Agreement shall remain in full force and effect.

[signature page follows]

IN WITNESS WHEREOF, each of the Parties has duly executed this Amendment as of the date first written above.

MRD Operating LLC
By:	Memorial Resource Development Corp., its sole member
By:	/s/ Kyle N. Roane
Name:	Kyle N. Roane
Title:	Senior Vice President
PennTex North Louisiana, LLC
By:	/s/ Robert O. Bond
Name:	Robert O. Bond
Title:	Chief Operating Officer

[Signature Page to Amendment No. 1 to Gas Transportation Agreement]

EX-31

Exhibit 31.1

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)

OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, John A. Weinzierl, certify that:

1.	I have reviewed this Quarterly Report on Form 10-Q of Memorial Resource Development Corp. (the “registrant”);
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
	a.	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	b.	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	c.	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	d.	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.	The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
	a.	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
	b.	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  November 4, 2015	/s/ John A. Weinzierl
	John A. Weinzierl
	Chief Executive Officer
	Memorial Resource Development Corp.

EX-31

Exhibit 31.2

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER

PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)

OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, Andrew J. Cozby, certify that:

1.	I have reviewed this Quarterly Report on Form 10-Q of Memorial Resource Development Corp. (the “registrant”);
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
	a.	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
	b.	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
	c.	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
	d.	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.	The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
	a.	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
	b.	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  November 4, 2015	/s/ Andrew J. Cozby
	Andrew J. Cozby
	Senior Vice President & Chief Financial Officer
	Memorial Resource Development Corp.

EX-32

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q of Memorial Resource Development Corp. (the “Company”), as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned, John A. Weinzierl, Chief Executive Officer of Memorial Resource Development Corp. and Andrew J. Cozby, Senior Vice President & Chief Financial Officer of Memorial Resource Development Corp., certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to their knowledge:

	(1)	the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and
	(2)	the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
Date:  November 4, 2015			/s/ John A. Weinzierl
			John A. Weinzierl
			Chief Executive Officer
			Memorial Resource Development Corp.
Date:  November 4, 2015			/s/ Andrew J. Cozby
			Andrew J. Cozby
			Senior Vice President & Chief Financial Officer
			Memorial Resource Development Corp.

The foregoing certifications are being furnished as an exhibit to the Report pursuant to Item 601(b)(32) of Regulation S-K and Section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) and, accordingly, are not being filed as part of the Report for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and are not incorporated by reference into any filing of the Company, whether made before or after the date hereof, regardless of any general incorporation language in such filing.

XML

Condensed Consolidating Financial Information (Tables)

9 Months Ended

Sep. 30, 2015

Organization Consolidation And Presentation Of Financial Statements [Abstract]

Condensed Consolidating Balance Sheets

The following condensed consolidating financial information presents the financial information of the Company on a unconsolidated stand-alone basis and its combined guarantor and combined non-guarantor subsidiaries as of and for the period indicated. Such financial information may not necessarily be indicative of our results of operations, cash flows or financial position had these subsidiaries operated as independent entities.

	As of September 30, 2015
	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	4,725	$	2,107	$	531	$	—		$	7,363
Accounts receivable - trade		6,890		76,715		55,169		(2,786	)		135,988
Accounts receivable - affiliates		7,438		—		—		(7,438	)		—
Short-term derivative instruments		152,208		—		231,340		—			383,548
Prepaid expenses and other current assets		4,995		8,603		14,258		—			27,856
Total current assets		176,256		87,425		301,298		(10,224	)		554,755
Property and equipment, net		16,814		1,371,384		1,907,350		—			3,295,548
Long-term derivative instruments		191,426		—		439,070		—			630,496
Investments in subsidiaries		1,261,135		—		—		(1,261,135	)		—
Other long-term assets		13,526		21,285		101,658		—			136,469
Total assets	$	1,659,157	$	1,480,094	$	2,749,376	$	(1,271,359	)	$	4,617,268
LIABILITIES AND EQUITY
Current Liabilities:
Accounts payable and accrued liabilities	$	24,574	$	86,766	$	104,488	$	(561	)	$	215,267
Accounts payable - affiliates		—		14,376		5,006		(9,625	)		9,757
Revenues payable		80		37,600		32,700		—			70,380
Deferred tax liabilities		55,985		—		1,459		—			57,444
Short-term derivative instruments		—		—		3,515		—			3,515
Total current liabilities		80,639		138,742		147,168		(10,186	)		356,363
Long-term debt		726,000		—		1,878,264		—			2,604,264
Asset retirement obligations		—		8,316		120,744		—			129,060
Long-term derivative  instruments		—		—		3,183		—			3,183
Deferred tax liabilities		46,028		72,372		2,389		—			120,789
Other long-term liabilities		6,995		—		—		—			6,995
Total liabilities		859,662		219,430		2,151,748		(10,186	)		3,220,654
Equity:
Equity		799,495		1,260,664		591,740		(1,852,404	)		799,495
Noncontrolling interest		—		—		5,888		591,231			597,119
Total equity		799,495		1,260,664		597,628		(1,261,173	)		1,396,614
Total liabilities & equity	$	1,659,157	$	1,480,094	$	2,749,376	$	(1,271,359	)	$	4,617,268

	As of December 30, 2014
	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	2,241	$	3,762	$	970	$	(1,015	)	$	5,958
Accounts receivable- trade		5,995		44,952		83,346		(2,717	)		131,576
Accounts receivable - affiliates		10,047		—		28		(10,075	)		—
Short-term derivative instruments		131,471		—		208,585		—			340,056
Prepaid expenses and other current assets		5,833		7,993		14,201		—			28,027
Total current assets		155,587		56,707		307,130		(13,807	)		505,617
Property and equipment, net		16,601		1,050,722		2,470,333		—			3,537,656
Long-term derivative instruments		123,567		—		311,802		—			435,369
Investments in subsidiaries		1,139,792		—		—		(1,139,792	)		—
Other long-term assets		14,124		5,660		100,521		(5,400	)		114,905
Total assets	$	1,449,671	$	1,113,089	$	3,189,786	$	(1,158,999	)	$	4,593,547
LIABILITIES AND EQUITY
Current Liabilities:
Accounts payable and accrued expenses	$	6,245	$	56,598	$	113,177	$	(3,125	)	$	172,895
Accounts payable - affiliates		—		3,638		6,409		(9,423	)		624
Revenues payable		—		27,242		30,110		—			57,352
Deferred tax liabilities		—		50,470		1,407		—			51,877
Short-term derivative instruments		—		—		3,289		—			3,289
Total current liabilities		6,245		137,948		154,392		(12,548	)		286,037
Long-term debt		783,000		—		1,595,413		—			2,378,413
Asset retirement obligations		—		9,830		112,701		—			122,531
Deferred tax liabilities		69,431		—		30,986		(5,400	)		95,017
Other long-term liabilities		8,585		—		—		—			8,585
Total liabilities		867,261		147,778		1,893,492		(17,948	)		2,890,583
Equity:
Equity		582,410		965,311		1,290,734		(2,256,045	)		582,410
Noncontrolling 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	$	1,449,671	$	1,113,089	$	3,189,786	$	(1,158,999	)	$	4,593,547

Condensed Consolidating Statements of Operations

	Three Months Ended September 30, 2015
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues:
Oil & natural gas sales	$	—		$	111,654		$	87,519		$	—		$	199,173
Other income		—			—			564			—			564
Total revenues		—			111,654			88,083			—			199,737
Costs and expenses:
Lease operating		—			7,949			45,416			—			53,365
Gathering, processing and transportation		—			22,633			8,134			—			30,767
Gathering, processing and transportation - affiliate		—			9,215			—			—			9,215
Pipeline operating		—			—			461			—			461
Exploration		—			4,068			2,141			—			6,209
Production and ad valorem taxes		—			2,751			6,896			—			9,647
Depreciation, depletion and amortization		1,087			51,948			53,305			—			106,340
Impairment of proved oil and natural gas properties		—			—			361,836			—			361,836
Incentive unit compensation expense		4,965			—			—			—			4,965
General and administrative		11,327			368			13,910			—			25,605
Accretion of asset retirement obligations		—			95			1,716			—			1,811
(Gain) loss on commodity derivatives		(125,167	)		—			(244,888	)		—			(370,055	)
Total costs and expenses		(107,788	)		99,027			248,927			—			240,166
Operating income (loss)		107,788			12,627			(160,844	)		—			(40,429	)
Other income (expense):
Interest expense, net		(9,174	)		(2	)		(31,255	)		—			(40,431	)
Equity earnings from subsidiaries		10,839			—			—			(10,839	)		—
Other, net		(100	)		18			11			—			(71	)
Total other income (expense)		1,565			16			(31,244	)		(10,839	)		(40,502	)
Income before income taxes		109,353			12,643			(192,088	)		(10,839	)		(80,931	)
Income tax benefit (expense)		(52,801	)		(1,630	)		107			—			(54,324	)
Net income (loss)		56,552			11,013			(191,981	)		(10,839	)		(135,255	)
Net income (loss) attributable to noncontrolling interest		—			—			104			(191,911	)		(191,807	)
Net income (loss) attributable to Memorial Resource Development Corp.	$	56,552		$	11,013		$	(192,085	)	$	181,072		$	56,552

	Three Months Ended September 30, 2014
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues:
Oil & natural gas sales	$	—		$	99,026		$	164,938		$	—		$	263,964
Other income		6			—			1,326			—			1,332
Total revenues		6			99,026			166,264			—			265,296
Costs and expenses:
Lease operating		—			4,320			41,891			—			46,211
Gathering, processing and transportation		—			11,941			7,862			—			19,803
Pipeline operating		—			—			431			—			431
Exploration		—			133			42			—			175
Production and ad valorem taxes		—			2,987			11,053			—			14,040
Depreciation, depletion and amortization		168			30,630			53,649			—			84,447
Impairment of proved oil and natural gas properties		—			—			67,181			—			67,181
Incentive unit compensation expense		25,550			—			—			—			25,550
General and administrative		7,215			1,889			12,092			—			21,196
Accretion of asset retirement obligations		1			131			1,421			—			1,553
(Gain) loss on commodity derivatives		(33,090	)		—			(156,402	)		—			(189,492	)
Total costs and expenses		(156	)		52,031			39,220			—			91,095
Operating income (loss)		162			46,995			127,044			—			174,201
Other income (expense):
Interest expense, net		(9,868	)		(19	)		(26,458	)		—			(36,345	)
Equity earnings from subsidiaries		25,675			—			—			(25,675	)		—
Other, net		—			5			10			—			15
Total other income (expense)		15,807			(14	)		(26,448	)		(25,675	)		(36,330	)
Income before income taxes		15,969			46,981			100,596			(25,675	)		137,871
Income tax benefit (expense)		(6,041	)		(20,489	)		696			—			(25,834	)
Net income (loss)		9,928			26,492			101,292			(25,675	)		112,037
Net income (loss) attributable to noncontrolling interest		—			—			52			102,057			102,109
Net income (loss) attributable to Memorial Resource Development Corp.	$	9,928		$	26,492		$	101,240		$	(127,732	)	$	9,928

	Nine Months Ended September 30, 2015
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues:
Oil & natural gas sales	$	—		$	277,282		$	276,689		$	—		$	553,971
Other income		—			—			2,350			—			2,350
Total revenues		—			277,282			279,039			—			556,321
Costs and expenses:
Lease operating		—			17,025			130,782			—			147,807
Gathering, processing and transportation		—			51,685			25,402			—			77,087
Gathering, processing and transportation -affiliate		—			13,028			—			—			13,028
Pipeline operating		—			—			1,407			—			1,407
Exploration		—			7,024			2,263			—			9,287
Production and ad valorem taxes		—			8,666			19,609			—			28,275
Depreciation, depletion and amortization		3,139			126,255			150,857			—			280,251
Impairment of proved oil and natural gas properties		—			—			613,183			—			613,183
Incentive unit compensation expense		31,305			—			—			—			31,305
General and administrative		32,656			2,338			42,798			—			77,792
Accretion of asset retirement obligations		—			311			5,036			—			5,347
(Gain) loss on commodity derivatives		(202,894	)		—			(328,944	)		—			(531,838	)
(Gain) loss on sale of properties		—			50			—			—			50
Other, net		—			—			(943	)		—			(943	)
Total costs and expenses		(135,794	)		226,382			661,450			—			752,038
Operating income (loss)		135,794			50,900			(382,411	)		—			(195,717	)
Other income (expense):
Interest expense, net		(28,456	)		(89	)		(87,983	)		—			(116,528	)
Equity earnings from subsidiaries		28,180			—			—			(28,180	)		—
Other, net		(100	)		(83	)		295			—			112
Total other income (expense)		(376	)		(172	)		(87,688	)		(28,180	)		(116,416	)
Income before income taxes		135,418			50,728			(470,099	)		(28,180	)		(312,133	)
Income tax benefit (expense)		(56,824	)		(20,521	)		1,601			—			(75,744	)
Net income (loss)		78,594			30,207			(468,498	)		(28,180	)		(387,877	)
Net income (loss) attributable to noncontrolling interest		—			—			328			(466,799	)		(466,471	)
Net income (loss) attributable to Memorial Resource Development Corp.	$	78,594		$	30,207		$	(468,826	)	$	438,619		$	78,594

	Nine Months Ended September 30, 2014
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Combined & Consolidated
	(In thousands)
Revenues:
Oil & natural gas sales	$	—		$	297,325		$	423,785		$	—		$	721,110
Other income		5			7			3,572			—			3,584
Total revenues		5			297,332			427,357			—			724,694
Costs and expenses:
Lease operating		—			12,348			99,539			—			111,887
Gathering, processing and transportation		—			30,793			21,016			—			51,809
Pipeline operating		—			—			1,596			—			1,596
Exploration		—			1,213			252			—			1,465
Production and ad valorem taxes		—			9,141			24,482			—			33,623
Depreciation, depletion and amortization		168			86,573			129,165			—			215,906
Impairment of proved oil and natural gas properties		—			—			67,181			—			67,181
Incentive unit compensation expense		137,307			831,060			1,023			—			969,390
General and administrative		7,390			19,450			34,221			—			61,061
Accretion of asset retirement obligations		1			388			4,212			—			4,601
(Gain) loss on commodity derivatives		(36,525	)		19,395			28,710			—			11,580
(Gain) loss on sale of properties		—			3,167			(110	)		—			3,057
Other, net		—			—			(12	)		—			(12	)
Total costs and expenses		108,341			1,013,528			411,275			—			1,533,144
Operating income (loss)		(108,336	)		(716,196	)		16,082			—			(808,450	)
Other income (expense):
Interest expense, net		(10,843	)		(33,512	)		(60,573	)		—			(104,928	)
Debt extinguishment costs		(23,562	)		(13,686	)		—			—			(37,248	)
Equity earnings from subsidiaries		(811,093	)		—			—			811,093			—
Other, net		—			92			10			—			102
Total other income (expense)		(845,498	)		(47,106	)		(60,563	)		811,093			(142,074	)
Income before income taxes		(953,834	)		(763,302	)		(44,481	)		811,093			(950,524	)
Income tax benefit (expense)		2,033			(16,742	)		311			—			(14,398	)
Net income (loss)		(951,801	)		(780,044	)		(44,170	)		811,093			(964,922	)
Net income (loss) attributable to noncontrolling interest		—			—			95			(34,946	)		(34,851	)
Net income (loss) attributable to Memorial Resource Development Corp.		(951,801	)		(780,044	)		(44,265	)		846,039			(930,071	)

Condensed Consolidating Statements of Cash Flows

	Nine Months Ended September 30, 2015
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Net cash provided by (used in) operating activities	$	64,375		$	187,457		$	185,572		$	1,015		$	438,419
Cash flows from investing activities:
Acquisitions of oil and natural gas properties		—			(7,267	)		(6,095	)		—			(13,362	)
Acquisition post-closing adjustment receipts		—			—			9,570			—			9,570
Additions to oil and gas properties		—			(438,262	)		(196,055	)		—			(634,317	)
Additions to other property and equipment		(3,340	)		(428	)		—			—			(3,768	)
Additions to restricted investments		—			—			(3,893	)		—			(3,893	)
Deposit for property acquisition		—			(21,286	)		—			—			(21,286	)
Investments in subsidiaries		(266,431	)		—			—			266,431			—
Distributions from subsidiaries		78,622			—			—			(78,622	)		—
Proceeds from the sale of oil and gas properties		—			13,612			—			—			13,612
Net cash used in investing activities		(191,149	)		(453,631	)		(196,473	)		187,809			(653,444	)
Cash flows from financing activities:
Advances on revolving credit facility		403,000			—			345,000			—			748,000
Payments on revolving credit facility		(460,000	)		—			(61,000	)		—			(521,000	)
Repayment of senior notes		—			—			(2,914	)		—			(2,914	)
Deferred finance costs		(1,446	)		—			(319	)		—			(1,765	)
Proceeds from MRD equity offering		242,880			—			—			—			242,880
Costs incurred in conjunction with MRD equity offering		(3,979	)		—			—			—			(3,979	)
Capital contributions		—			264,519			1,912			(266,431	)		—
Distributions to MRD		—			—			(78,396	)		78,396			—
Distribution to partners		—			—			(138,349	)		138,349			—
Distribution to noncontrolling interests		—			—			—			(138,123	)		(138,123	)
Repurchases of equity		(51,197	)		—			(55,472	)		—			(106,669	)
Net cash provided by financing activities		129,258			264,519			10,462			(187,809	)		216,430
Net change in cash and cash equivalents		2,484			(1,655	)		(439	)		1,015			1,405
Cash and cash equivalents, beginning of period		2,241			3,762			970			(1,015	)		5,958
Cash and cash equivalents, end of period	$	4,725		$	2,107		$	531		$	—		$	7,363

	Nine Months Ended September 30, 2014
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Combined & Consolidated
	(In thousands)
Net cash provided by (used in) operating activities	$	8,463		$	149,927		$	207,070		$	—		$	365,460
Cash flows from investing activities:
Acquisitions of oil and natural gas properties		—			—			(1,083,167	)		—			(1,083,167	)
Additions to oil and gas properties		—			(240,204	)		(217,634	)		—			(457,838	)
Additions to other property and equipment		(8,936	)		(184	)		(14	)		—			(9,134	)
Additions to restricted investments		—			—			(2,883	)		—			(2,883	)
Investments in subsidiaries		(611,853	)		—			—			611,853			—
Distributions from subsidiaries		—			56,027			—			(56,027	)		—
Change in restricted cash		—			49,946			—			—			49,946
Proceeds from the sale of oil and gas properties		—			—			6,700			—			6,700
Other		—			—			(301	)		—			(301	)
Net cash used in investing activities		(620,789	)		(134,415	)		(1,297,299	)		555,826			(1,496,677	)
Cash flows from financing activities:
Advances on revolving credit facility		1,013,000			126,800			1,325,000			—			2,464,800
Payments on revolving credit facility		(985,000	)		(329,900	)		(1,127,000	)		—			(2,441,900	)
Termination of second lien credit facility		—			(328,282	)		—			—			(328,282	)
Proceeds from the issuances of senior notes		600,000			—			492,425			—			1,092,425
Redemption of senior notes		(351,808	)		—			—			—			(351,808	)
Deferred finance costs		(18,814	)		(61	)		(11,409	)		—			(30,284	)
Proceeds from MRD initial public offering		408,500			—			—			—			408,500
Costs incurred in conjunction with initial public offering		(28,198	)		—			—			—			(28,198	)
Proceeds from MEMP equity offering		—			—			553,288			—			553,288
Costs incurred in conjunction with MEMP equity offering		—			—			(12,222	)		—			(12,222	)
Capital contributions		—			608,466			3,387			(611,853	)		—
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		—			—			(156,549	)		156,549			—
Distribution to NGP affiliates related to purchase of assets		—			(63,389	)		(3,304	)		—			(66,693	)
Distribution to noncontrolling interests		—			—			—			(101,327	)		(101,327	)
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		—			213			—			—			213
Net cash provided by financing activities		617,181			(58,443	)		1,061,705			(556,631	)		1,063,812
Net change in cash and cash equivalents		4,855			(42,931	)		(28,524	)		(805	)		(67,405	)
Cash and cash equivalents, beginning of period		—			48,619			29,102			—			77,721
Cash and cash equivalents, end of period	$	4,855		$	5,688		$	578		$	(805	)	$	10,316

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Asset Retirement Obligations - Summary of Changes in Asset Retirement Obligations (Detail) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations at beginning of period			$ 122,531
Liabilities added from acquisitions or drilling			1,565
Liabilities settled			(780)
Revision of estimates			573
Liabilities removed upon sale of wells			(176)
Accretion expense	$ 1,811	$ 1,553	5,347	$ 4,601
Asset retirement obligations at end of period	$ 129,060		$ 129,060

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Fair Value Measurements of Financial Instruments - Additional Information (Detail) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment of proved oil and natural gas properties	$ 361,836	$ 67,181	$ 613,183	$ 67,181
Carrying value of properties after impairment charges	3,295,548		3,295,548		$ 3,537,656
MEMP [Member] | East Texas, Wyoming and Colorado [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment of proved oil and natural gas properties	361,800	$ 67,200	613,200	$ 67,200
Carrying value of properties after impairment charges	$ 407,700		$ 407,700

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Restricted Investments - Restricted Investment Balance (Detail) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Schedule Of Investments [Line Items]
Restricted investments	$ 81,254	$ 77,361
BOEM platform abandonment [Member]
Schedule Of Investments [Line Items]
Restricted investments	73,488	69,954
BOEM lease bonds [Member]
Schedule Of Investments [Line Items]
Restricted investments	794	794
SPBPC Collateral Contractual pipeline and surface facilities abandonment [Member]
Schedule Of Investments [Line Items]
Restricted investments	3,060	2,701
SPBPC Collateral City of Long Beach pipeline facility permit [Member]
Schedule Of Investments [Line Items]
Restricted investments	500	500
SPBPC Collateral Federal pipeline right-of-way bond [Member]
Schedule Of Investments [Line Items]
Restricted investments	307	307
SPBPC Collateral Port of Long Beach pipeline license [Member]
Schedule Of Investments [Line Items]
Restricted investments	100	100
California State | SPBPC Collateral Lands Commission pipeline right-of-way bond [Member]
Schedule Of Investments [Line Items]
Restricted investments	$ 3,005	$ 3,005

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Business Segment Data - Schedule of Calculation of Reportable Segment's Adjusted EBITDA (Detail) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Segment Reporting Information [Line Items]
Net income (loss)	$ 56,552	$ 9,928	$ 78,594	$ (930,071)
Interest expense, net	40,431	36,345	116,528	104,928
Loss on debt extinguishment				37,248
Income tax expense (benefit)	54,324	25,834	75,744	14,398
DD&A	106,340	84,447	280,251	215,906
Impairment of proved oil and natural gas properties	361,836	67,181	613,183	67,181
Accretion of asset retirement obligations	1,811	1,553	5,347	4,601
(Gain) loss on commodity derivative instruments	(370,055)	(189,492)	(531,838)	11,580
Cash settlements received (paid) on expired commodity derivative instruments	(108,490)	(4,575)	(293,253)	19,929
(Gain) loss on sale of properties			50	3,057
Transaction related costs	229	1,425	3,232	5,480
Compensation expense	10,650	29,289	45,339	976,264
Exploration costs	6,209	175	9,287	1,465
Loss on settlement of AROs			1,328
Provision for environmental remediation				2,852
Cash distributions from MEMP	75	64	226	6,068
Adjusted EBITDA	185,010	173,369	523,827	460,109
Operating Segments [Member]
Segment Reporting Information [Line Items]
Net income (loss)	(135,430)	112,123	(388,279)	(977,766)
Interest expense, net	40,431	36,345	116,528	104,928
Loss on debt extinguishment				37,248
Income tax expense (benefit)	54,324	25,834	75,744	14,398
DD&A	106,340	84,447	280,251	215,906
Impairment of proved oil and natural gas properties	361,836	67,181	613,183	67,181
Accretion of asset retirement obligations	1,811	1,553	5,347	4,601
(Gain) loss on commodity derivative instruments	(370,055)	(189,492)	(531,838)	11,580
Cash settlements received (paid) on expired commodity derivative instruments	108,490	4,575	293,253	(19,929)
(Gain) loss on sale of properties			50	3,057
Transaction related costs	229	1,425	3,232	5,480
Compensation expense	10,650	29,289	45,339	976,264
Exploration costs	6,209	175	9,287	1,465
Loss on settlement of AROs			1,328
Provision for environmental remediation				2,852
Non-cash equity (income) loss from MEMP	175	(86)	402	12,844
Cash distributions from MEMP	75	64	226	6,068
Adjusted EBITDA	185,085	173,433	524,053	466,177
Operating Segments [Member] | MRD Segment [Member]
Segment Reporting Information [Line Items]
Net income (loss)	56,551	10,816	80,219	(934,541)
Interest expense, net	9,176	9,887	28,545	44,355
Loss on debt extinguishment				37,248
Income tax expense (benefit)	54,431	26,522	77,345	14,701
DD&A	53,035	30,798	129,394	86,741
Accretion of asset retirement obligations	95	132	311	389
(Gain) loss on commodity derivative instruments	(125,167)	(33,090)	(202,894)	(17,130)
Cash settlements received (paid) on expired commodity derivative instruments	44,010	3,699	114,298	(4,930)
(Gain) loss on sale of properties			50	3,057
Transaction related costs	213	500	1,620	1,568
Compensation expense	7,657	26,862	37,440	970,877
Exploration costs	4,068	133	7,024	1,213
Non-cash equity (income) loss from MEMP	175	(86)	402	12,844
Cash distributions from MEMP	75	64	226	6,068
Adjusted EBITDA	104,319	76,237	273,980	222,460
Operating Segments [Member] | MEMP [Member]
Segment Reporting Information [Line Items]
Net income (loss)	(191,981)	101,307	(468,498)	(43,225)
Interest expense, net	31,255	26,458	87,983	60,573
Income tax expense (benefit)	(107)	(688)	(1,601)	(303)
DD&A	53,305	53,649	150,857	129,165
Impairment of proved oil and natural gas properties	361,836	67,181	613,183	67,181
Accretion of asset retirement obligations	1,716	1,421	5,036	4,212
(Gain) loss on commodity derivative instruments	(244,888)	(156,402)	(328,944)	28,710
Cash settlements received (paid) on expired commodity derivative instruments	64,480	876	178,955	(14,999)
Transaction related costs	16	925	1,612	3,912
Compensation expense	2,993	2,427	7,899	5,387
Exploration costs	2,141	42	2,263	252
Loss on settlement of AROs			1,328
Provision for environmental remediation				2,852
Adjusted EBITDA	$ 80,766	$ 97,196	$ 250,073	$ 243,717

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Acquisitions and Divestitures - Unaudited Pro Forma Results of Operations (Detail) $ / shares in Units, $ in Thousands	9 Months Ended
	Sep. 30, 2014 USD ($) $ / shares
Business Combinations [Abstract]
Revenues	$ 815,893
Net income (loss)	$ (930,903)
Basic and diluted earnings per share | $ / shares	$ (4.94)

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Earnings per Share (Tables)

9 Months Ended

Sep. 30, 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 periods indicated (in thousands, except per share amounts):

	For the Three Months Ended				For the Nine Months Ended
	September 30,				September 30,
	2015		2014		2015		2014
Numerator:
Net income (loss) available to common stockholders	$	56,051	$	9,873	$	78,006	$	(951,801	)
Denominator:
Weighted average common shares outstanding		190,725		192,500		190,353		192,500
Incremental treasury stock method shares (1)		86		216		410		207
Basic EPS	$	0.29	$	0.05	$	0.41	$	(4.94	)
Diluted EPS (1)	$	0.29	$	0.05	$	0.41	$	(4.94	)

(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.

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Business Segment Data - Reconciliation of Total Reportable Segment's Adjusted EBITDA to Net Income (Loss) (Detail) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Segment Reporting, Revenue Reconciling Item [Line Items]
Total Reportable Segments' Adjusted EBITDA	$ 185,010	$ 173,369	$ 523,827	$ 460,109
Adjustments to reconcile Adjusted EBITDA to net income (loss):
Interest expense, net	(40,431)	(36,345)	(116,528)	(104,928)
Loss on extinguishment of debt				(37,248)
Income tax benefit (expense)	(54,324)	(25,834)	(75,744)	(14,398)
DD&A	(106,340)	(84,447)	(280,251)	(215,906)
Impairment of proved oil and natural gas properties	(361,836)	(67,181)	(613,183)	(67,181)
Accretion of asset retirement obligations	(1,811)	(1,553)	(5,347)	(4,601)
Gains (losses) on commodity derivative instruments	370,055	189,492	531,838	(11,580)
Cash settlements received (paid) on expired commodity derivative instruments	(108,490)	(4,575)	(293,253)	19,929
Gain (loss) on sale of properties			(50)	(3,057)
Transaction related costs	(229)	(1,425)	(3,232)	(5,480)
Incentive-based compensation expense	(10,650)	(29,289)	(45,339)	(976,264)
Exploration costs	(6,209)	(175)	(9,287)	(1,465)
Provision for environmental remediation				(2,852)
Loss on settlement of AROs			(1,328)
Cash distributions from MEMP	(75)	(64)	(226)	(6,068)
Net income (loss)	(135,255)	112,037	(387,877)	(964,922)
Reportable Segments [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Total Reportable Segments' Adjusted EBITDA	$ 185,085	$ 173,433	$ 524,053	$ 466,177

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Related Party Transactions - Additional Information (Detail) $ in Millions					1 Months Ended		3 Months Ended	9 Months Ended
	Jul. 01, 2015 $ / bbl	Apr. 14, 2015 USD ($)	Mar. 28, 2014 USD ($)	Mar. 10, 2014 USD ($)	May. 31, 2014 $ / MMBTU $ / bbl	Nov. 30, 2011 MMBTU / d	Sep. 30, 2015 USD ($) $ / MMBTU $ / gal	Sep. 30, 2015 USD ($) MMBTU / d $ / MMBTU $ / gal	Feb. 28, 2014 USD ($)
Gas Gathering Agreement [Member] | Classic Operating And Classic Pipeline [Member]
Related Party Transaction [Line Items]
Gas volume commitment | MMBTU / d						50,000
Pipeline transportation agreement expiration year						2020
Pipeline transportation agreement extension						1 year
Fee per MMBTU | $ / MMBTU					0.30
Annual inflationary escalation					3.50%
Price per unit | $ / MMBTU					0.07
Agreement expired, date					Dec. 31, 2023
Water Disposal Agreement [Member] | Classic Operating And Classic Pipeline [Member]
Related Party Transaction [Line Items]
Water disposal agreement period					3 years
Pipeline water disposal agreement extension					1 year
Water disposal fee per barrel | $ / bbl	0.40				1.10
NGPCIF [Member]
Related Party Transaction [Line Items]
Business acquisition common control purchase price									$ 63.4
Cretic Energy Services, LLC [Member]
Related Party Transaction [Line Items]
Drilling and completion expenses							$ 4.8	$ 6.7
Multi-Shot, LLC [Member]
Related Party Transaction [Line Items]
Drilling and completion expenses							$ 1.0	1.2
BlueStone Natural Resources Holdings, LLC [Member]
Related Party Transaction [Line Items]
Total cash consideration				$ 1.2
Amount of gain over the book value				0.5
Gain recognized as contribution				$ 0.5
Natural Gas Partners [Member]
Related Party Transaction [Line Items]
Cash received			$ 3.3
WHR Management Company [Member]
Related Party Transaction [Line Items]
Management fee per month								$ 1.0
PennTex Operating [Member] | Gas Processing Agreement [Member]
Related Party Transaction [Line Items]
Primary term of gas processing agreement		15 years
Extension term of gas processing agreement		1 year
PennTex Operating [Member] | Gas Gathering Agreement [Member] | Commodity Usage Charge Commitment [Member] | July 1, 2016 | Minimum [Member]
Related Party Transaction [Line Items]
Gas volume commitment | MMBTU / d								460,000
PennTex Operating [Member] | Gas Gathering Agreement [Member] | Commodity Usage Charge Commitment [Member] | Through June 30, 2026 [Member]
Related Party Transaction [Line Items]
Commodity usage and payback fee | $ / MMBTU							0.05	0.05
PennTex Operating [Member] | Gas Gathering Agreement [Member] | Commodity Usage Charge Commitment [Member] | Through June 30, 2026 [Member] | Minimum [Member]
Related Party Transaction [Line Items]
Gas volume commitment | MMBTU / d								460,000
PennTex Operating [Member] | Gas Gathering Agreement [Member] | Commodity Usage Charge Commitment [Member] | June 30, 2026, and thereafter
Related Party Transaction [Line Items]
Commodity usage and payback fee | $ / MMBTU							0.05	0.05
PennTex Operating [Member] | Gas Gathering Agreement [Member] | Commodity Usage Charge Commitment [Member] | June 30, 2026, and thereafter | Minimum [Member]
Related Party Transaction [Line Items]
Gas volume commitment | MMBTU / d								345,000
PennTex Operating [Member] | Gas Gathering Agreement [Member] | Payback Fee Commitment [Member] | Through November 30, 2019
Related Party Transaction [Line Items]
Gas volume commitment | MMBTU / d								460,000
Commodity usage and payback fee | $ / MMBTU							0.03	0.03
PennTex Operating [Member] | Gas Transportation Agreement [Member] | Commodity Usage Charge Commitment [Member]
Related Party Transaction [Line Items]
Commodity usage and payback fee | $ / MMBTU							0.04	0.04
PennTex Operating [Member] | Transportation Services Agreement [Member] | Commodity Usage Charge Commitment [Member]
Related Party Transaction [Line Items]
Commodity usage and payback fee | $ / gal							0.04	0.04
PennTex Operating [Member] | First Plant [Member] | Gas Processing Agreement [Member]
Related Party Transaction [Line Items]
Minimum annual processing fee		$ 18.3
PennTex Operating [Member] | First Plant [Member] | Gas Gathering Agreement [Member] | Until Second Processing Plant Operational | Commodity Usage Charge Commitment [Member]
Related Party Transaction [Line Items]
Commodity usage and payback fee | $ / MMBTU							0.02	0.02
PennTex Operating [Member] | First Plant [Member] | Gas Gathering Agreement [Member] | Until Second Processing Plant Operational | Commodity Usage Charge Commitment [Member] | Minimum [Member]
Related Party Transaction [Line Items]
Gas volume commitment | MMBTU / d								115,000
PennTex Operating [Member] | Second Plant [Member] | Gas Processing Agreement [Member]
Related Party Transaction [Line Items]
Minimum annual processing fee		$ 55.0
PennTex Operating [Member] | Second Plant [Member] | Gas Gathering Agreement [Member] | Commodity Usage Charge Commitment [Member] | Through November 30, 2019
Related Party Transaction [Line Items]
Commodity usage and payback fee | $ / MMBTU							0.02	0.02
PennTex Operating [Member] | Second Plant [Member] | Gas Gathering Agreement [Member] | Commodity Usage Charge Commitment [Member] | Through November 30, 2019 | Minimum [Member]
Related Party Transaction [Line Items]
Gas volume commitment | MMBTU / d								345,000
PennTex NLA Holdings, LLC | Midstream Agreements
Related Party Transaction [Line Items]
Primary term of gas processing agreement		15 years
Extension term of gas processing agreement		1 year

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Long Term Debt - Consolidated Debt Obligations (Parenthetical) (Detail) - USD ($)	9 Months Ended
	Sep. 30, 2015	Dec. 31, 2014
MRD Segment [Member] | 2.0 Billion Revolving Credit Facility Due June 2019 [Member]
Debt Instrument [Line Items]
Credit facilities	$ 2,000,000,000
Maturity date	Jun. 18, 2019
MRD Segment [Member] | 5.875% Senior Unsecured Notes Due July 2022 [Member]
Debt Instrument [Line Items]
Maturity date	Jul. 01, 2022
Debt interest rate	5.875%
Estimated fair value of fixed rate debt	$ 547,500,000	$ 534,000,000
MEMP [Member] | 2.0 Billion Revolving Credit Facility Due March 2018 [Member]
Debt Instrument [Line Items]
Credit facilities	$ 2,000,000,000
Maturity date	Mar. 19, 2018
MEMP [Member] | 7.625% senior unsecured notes, due May 2021 ("2021 Senior Notes") [Member]
Debt Instrument [Line Items]
Maturity date	May 01, 2021
Debt interest rate	7.625%
Estimated fair value of fixed rate debt	$ 469,000,000	563,500,000
MEMP [Member] | 6.875% Senior Unsecured Notes Due August 2022 ("2022 Senior Notes") [Member]
Debt Instrument [Line Items]
Maturity date	Aug. 01, 2022
Debt interest rate	6.875%
Estimated fair value of fixed rate debt	$ 303,200,000	$ 380,000,000

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Business Segment Data - Additional Information (Detail)	9 Months Ended
	Sep. 30, 2015 Segment
Segment Reporting [Abstract]
Number of reportable business segments	2

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Condensed Consolidating Financial Information - Condensed Consolidating Statements of Cash Flows (Detail) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Cash flows from operating activities:
Net cash provided by (used in) operating activities	$ 438,419	$ 365,460
Cash flows from investing activities:
Acquisitions of oil and natural gas properties	(13,362)	(1,083,167)
Acquisition post-closing adjustment receipts	9,570
Additions to oil and gas properties	(634,317)	(457,838)
Additions to other property and equipment	(3,768)	(9,134)
Additions to restricted investments	(3,893)	(2,883)
Deposits for property acquisitions	(21,286)
Change in restricted cash		49,946
Proceeds from the sale of oil and gas properties	13,612	6,700
Other		(301)
Net cash used in investing activities	(653,444)	(1,496,677)
Cash flows from financing activities:
Advances on revolving credit facilities	748,000	2,464,800
Payments on revolving credit facilities	(521,000)	(2,441,900)
Termination of second lien credit facility		(328,282)
Proceeds from the issuance of senior notes		1,092,425
Repayment of senior notes	(2,914)	(351,808)
Deferred financing costs	(1,765)	(30,284)
Costs incurred in conjunction with equity offering		(28,198)
Purchase of additional interests in consolidated subsidiaries		(3,292)
Distributions to noncontrolling interests	(138,123)	(101,327)
Other		213
Repurchases of equity	(106,669)
Net cash provided by financing activities	216,430	1,063,812
Net change in cash and cash equivalents	1,405	(67,405)
Cash and cash equivalents, beginning of period	5,958	77,721
Cash and cash equivalents, end of period	7,363	10,316
MRD Holdco LLC [Member]
Cash flows from financing activities:
Distributions to affiliates		(59,803)
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)
Parent [Member]
Cash flows from operating activities:
Net cash provided by (used in) operating activities	64,375	8,463
Cash flows from investing activities:
Additions to other property and equipment	(3,340)	(8,936)
Investments in subsidiaries	(266,431)	(611,853)
Distributions from subsidiaries	78,622
Net cash used in investing activities	(191,149)	(620,789)
Cash flows from financing activities:
Advances on revolving credit facilities	403,000	1,013,000
Payments on revolving credit facilities	(460,000)	(985,000)
Proceeds from the issuance of senior notes		600,000
Repayment of senior notes		(351,808)
Deferred financing costs	(1,446)	(18,814)
Costs incurred in conjunction with equity offering		(28,198)
Purchase of additional interests in consolidated subsidiaries		(3,292)
Repurchases of equity	(51,197)
Net cash provided by financing activities	129,258	617,181
Net change in cash and cash equivalents	2,484	4,855
Cash and cash equivalents, beginning of period	2,241
Cash and cash equivalents, end of period	4,725	4,855
Parent [Member] | MRD Holdco LLC [Member]
Cash flows from financing activities:
Distributions to affiliates		(17,207)
Guarantor Subsidiaries [Member]
Cash flows from operating activities:
Net cash provided by (used in) operating activities	187,457	149,927
Cash flows from investing activities:
Acquisitions of oil and natural gas properties	(7,267)
Additions to oil and gas properties	(438,262)	(240,204)
Additions to other property and equipment	(428)	(184)
Deposits for property acquisitions	(21,286)
Distributions from subsidiaries		56,027
Change in restricted cash		49,946
Proceeds from the sale of oil and gas properties	13,612
Net cash used in investing activities	(453,631)	(134,415)
Cash flows from financing activities:
Advances on revolving credit facilities		126,800
Payments on revolving credit facilities		(329,900)
Termination of second lien credit facility		(328,282)
Deferred financing costs		(61)
Capital contributions	264,519	608,466
Other		213
Net cash provided by financing activities	264,519	(58,443)
Net change in cash and cash equivalents	(1,655)	(42,931)
Cash and cash equivalents, beginning of period	3,762	48,619
Cash and cash equivalents, end of period	2,107	5,688
Guarantor Subsidiaries [Member] | MRD Holdco LLC [Member]
Cash flows from financing activities:
Distributions to affiliates		(39,520)
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)
Non-Guarantor Subsidiaries [Member]
Cash flows from operating activities:
Net cash provided by (used in) operating activities	185,572	207,070
Cash flows from investing activities:
Acquisitions of oil and natural gas properties	(6,095)	(1,083,167)
Acquisition post-closing adjustment receipts	9,570
Additions to oil and gas properties	(196,055)	(217,634)
Additions to other property and equipment		(14)
Additions to restricted investments	(3,893)	(2,883)
Proceeds from the sale of oil and gas properties		6,700
Other		(301)
Net cash used in investing activities	(196,473)	(1,297,299)
Cash flows from financing activities:
Advances on revolving credit facilities	345,000	1,325,000
Payments on revolving credit facilities	(61,000)	(1,127,000)
Proceeds from the issuance of senior notes		492,425
Repayment of senior notes	(2,914)
Deferred financing costs	(319)	(11,409)
Capital contributions	1,912	3,387
Distribution to partners	(138,349)
Repurchases of equity	(55,472)
Distribution to equity owners		(156,549)
Net cash provided by financing activities	10,462	1,061,705
Net change in cash and cash equivalents	(439)	(28,524)
Cash and cash equivalents, beginning of period	970	29,102
Cash and cash equivalents, end of period	531	578
Non-Guarantor Subsidiaries [Member] | MRD Corp. [Member]
Cash flows from financing activities:
Distributions to affiliates	(78,396)
Non-Guarantor Subsidiaries [Member] | MRD Holdco LLC [Member]
Cash flows from financing activities:
Distributions to affiliates		(3,076)
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)
Eliminations [Member]
Cash flows from operating activities:
Net cash provided by (used in) operating activities	1,015
Cash flows from investing activities:
Investments in subsidiaries	266,431	611,853
Distributions from subsidiaries	(78,622)	(56,027)
Net cash used in investing activities	187,809	555,826
Cash flows from financing activities:
Capital contributions	(266,431)	(611,853)
Distribution to partners	138,349
Distributions to noncontrolling interests	(138,123)	(101,327)
Distribution to equity owners		156,549
Net cash provided by financing activities	(187,809)	(556,631)
Net change in cash and cash equivalents	1,015	(805)
Cash and cash equivalents, beginning of period	(1,015)
Cash and cash equivalents, end of period		(805)
Eliminations [Member] | MRD Corp. [Member]
Cash flows from financing activities:
Distributions to affiliates	78,396
MRD Segment [Member]
Cash flows from financing activities:
Proceeds from MRD equity offering	242,880	408,500
Costs incurred in conjunction with equity offering	(3,979)	(28,198)
Repurchases of equity	(51,197)
MRD Segment [Member] | Parent [Member]
Cash flows from financing activities:
Proceeds from MRD equity offering	242,880	408,500
Costs incurred in conjunction with equity offering	(3,979)
MEMP [Member]
Cash flows from financing activities:
Costs incurred in conjunction with equity offering		(12,222)
Proceeds from MEMP equity offering		553,288
Repurchases of equity	$ (55,472)
MEMP [Member] | Non-Guarantor Subsidiaries [Member]
Cash flows from financing activities:
Costs incurred in conjunction with equity offering		(12,222)
Proceeds from MEMP equity offering		$ 553,288

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Commitments and Contingencies - Additional Information (Detail) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Commitments And Contingencies Disclosure [Abstract]
Environmental reserves liability	$ 0.6	$ 2.1
Maximum remaining obligation	$ 5.2

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Subsequent Events - Additional Information (Detail) $ in Thousands		9 Months Ended		12 Months Ended
	Nov. 03, 2015 USD ($)	Sep. 30, 2015 USD ($)	Sep. 30, 2014 USD ($)	Dec. 31, 2012 well Platform mi in
Subsequent Event [Line Items]
Acquisitions of oil and natural gas properties | $		$ 13,362	$ 1,083,167
MEMP [Member] | November 2015 Beta Acquisition [Member]
Subsequent Event [Line Items]
Working interest				48.25%
Number of gross wells acquired | well				58
Number of combined production and drilling platforms acquired				2
Number of production processing platforms acquired				1
Length of oil pipeline acquired | mi				17.5
Diameter of oil pipeline acquired | in				16
Business acquisition description		MEMP first acquired its interests in the Beta properties in December 2012. The acquired interests primarily consist of the 48.25% remaining working interests in three Pacific Outer Continental Shelf blocks in the Beta Field, which includes 58 gross wells, that are located in federal waters approximately eleven miles offshore the Port of Long Beach, California. The acquired interests also include the 48.25% remaining interest in associated facilities including (i) two combined production and drilling platforms (ii) one production processing platform, (iii) a 17.5 mile long 16-inch diameter oil pipeline and (iv) an onshore pump station, tankage and metering facility.
Subsequent Event [Member] | MEMP [Member] | November 2015 Beta Acquisition [Member]
Subsequent Event [Line Items]
Acquisitions of oil and natural gas properties | $	$ 101,000

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Business Segment Data - Summary of Selected Business Segment Information (Detail) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Segment Reporting Information [Line Items]
Total revenues	$ 199,737	$ 265,296	$ 556,321	$ 724,694
Adjusted EBITDA	185,010	173,369	523,827	460,109
Segment assets	4,617,268		4,617,268		$ 4,593,547
Total cash expenditures for additions to long-lived assets			651,447	1,550,139
Operating Segments [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA	185,085	173,433	524,053	466,177
Operating Segments [Member] | MRD Segment [Member]
Segment Reporting Information [Line Items]
Total revenues	111,654	99,035	277,282	297,340
Adjusted EBITDA	104,319	76,237	273,980	222,460
Segment assets	1,871,270		1,871,270		1,413,768
Total cash expenditures for additions to long-lived assets			449,297	249,324
Operating Segments [Member] | MEMP [Member]
Segment Reporting Information [Line Items]
Total revenues	88,083	166,261	279,039	427,354
Adjusted EBITDA	80,766	97,196	250,073	243,717
Segment assets	2,749,376		2,749,376		3,189,760
Total cash expenditures for additions to long-lived assets			202,150	1,300,815
Other, Adjustments & Eliminations [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA	(75)	$ (64)	(226)	$ (6,068)
Segment assets	$ (3,378)		$ (3,378)		$ (9,981)

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Incentive Units - Additional Information (Detail) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Equity Incentive Plan [Line Items]
Compensation expense	$ 10,650	$ 29,289	$ 45,339	$ 976,264
MRD Holdco LLC [Member]
Equity Incentive Plan [Line Items]
The number of incentive units authorized by governing documents	1,000		1,000
MRD Holdco LLC [Member] | Exchanged Incentive Units [Member]
Equity Incentive Plan [Line Items]
Incentive units granted in an exchange for cancelled predecessor awards			930
Compensation expense	$ 5,000		$ 31,300
Unrecognized compensation expense	$ 72,700		$ 72,700
Remaining expected life			1 year 8 months 1 day
MRD Holdco LLC [Member] | Subsequent Incentive Units [Member]
Equity Incentive Plan [Line Items]
Subsequent incentive units	70		70

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Summary of Significant Accounting Policies (Tables)

9 Months Ended

Sep. 30, 2015

Accounting Policies [Abstract]

Schedule of Accrued Liabilities

Current accrued liabilities consisted of the following at the dates indicated (in thousands):

	September 30,		December 31,
	2015		2014
Accrued capital expenditures	$	84,698	$	80,350
Accrued lease operating expense		18,495		16,403
Accrued general and administrative expenses		14,035		8,516
Accrued ad valorem taxes		15,010		8,870
Accrued interest payable		36,810		24,797
Accrued income tax payable		4,942		52
Accrued environmental		588		2,092
Other miscellaneous, including operator advances		2,021		6,043
	$	176,599	$	147,123

Schedule of Supplemental Cash Flow

Supplemental cash flow for the periods presented (in thousands):

	For the Nine Months Ended
	September 30,
	2015		2014
Supplemental cash flows:
Cash paid for interest, net of capitalized interest	$	93,038	$	67,449
Cash paid for taxes		2,055		550
Noncash investing and financing activities:
Increase (decrease) in capital expenditures in payables and accrued liabilities		4,348		29,137
(Increase) decrease in accounts receivable related to acquisitions and divestitures		9,570		(4,271	)
Accrued expenses related to MRD equity offering		372		—

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Risk Management and Derivative Instruments - Schedule of Open Commodity Positions (Detail)	9 Months Ended
	Sep. 30, 2015 MMBTU $ / MMBTU $ / bbl bbl
2015 [Member] | Natural Gas Derivative Contracts [Member] | MRD Segment [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	3,400,000
Weighted-average fixed price	4.15
2015 [Member] | Natural Gas Derivative Contracts [Member] | MRD Segment [Member] | Collar contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	130,000
Weighted-average floor price	4.00
Weighted-average ceiling price	4.64
2015 [Member] | Natural Gas Derivative Contracts [Member] | MRD Segment [Member] | Put Option [Member] | Purchased [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	4,100,000
Weighted-average strike price	3.75
Weighted-average deferred premium paid	(0.33)
2015 [Member] | Natural Gas Derivative Contracts [Member] | MRD Segment [Member] | Call Option [Member] | Written [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	3,225,000	[1]
Weighted-average sold strike price	3.75	[1]
Weighted-average deferred premium received	0.08	[1]
2015 [Member] | Natural Gas Derivative Contracts [Member] | MRD Segment [Member] | TGT Z1 basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	3,380,000
2015 [Member] | Natural Gas Derivative Contracts [Member] | MRD Segment [Member] | TGT Z1 basis swaps [Member] | Henry Hub [Member]
Derivative [Line Items]
Spread	(0.10)
2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	3,359,237
Weighted-average fixed price	4.08
2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Collar contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	350,000
Weighted-average floor price	4.62
Weighted-average ceiling price	5.80
2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Call Spreads [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	80,000	[2]
Weighted-average sold strike price	5.25	[2]
Weighted-average bought strike price	6.75	[2]
2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Basis Swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	3,690,000
Spread	(0.12)
2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | NGPL TexOk basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	3,030,000
2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | NGPL TexOk basis swaps [Member] | Henry Hub [Member]
Derivative [Line Items]
Spread	(0.11)
2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | HSC basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	150,000
2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | HSC basis swaps [Member] | Henry Hub [Member]
Derivative [Line Items]
Spread	(0.08)
2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | CIG basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	210,000
2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | CIG basis swaps [Member] | Henry Hub [Member]
Derivative [Line Items]
Spread	(0.25)
2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | TETCO STX basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	300,000
2015 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | TETCO STX basis swaps [Member] | Henry Hub [Member]
Derivative [Line Items]
Spread	(0.09)
2015 [Member] | Crude Oil Derivative Contracts [Member] | MRD Segment [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price | $ / bbl	91.67
Average Monthly Volume (Bbls) | bbl	42,000
2015 [Member] | Crude Oil Derivative Contracts [Member] | MRD Segment [Member] | Collar contracts [Member]
Derivative [Line Items]
Weighted-average floor price | $ / bbl	85.00
Weighted-average ceiling price | $ / bbl	101.35
Average Monthly Volume (Bbls) | bbl	2,000
2015 [Member] | Crude Oil Derivative Contracts [Member] | MRD Segment [Member] | Put Option [Member] | Purchased [Member]
Derivative [Line Items]
Weighted-average strike price | $ / bbl	85.00
Weighted-average deferred premium paid | $ / bbl	(3.80)
Average Monthly Volume (Bbls) | bbl	39,000
2015 [Member] | Crude Oil Derivative Contracts [Member] | MRD Segment [Member] | Call Option [Member] | Written [Member]
Derivative [Line Items]
Weighted-average sold strike price | $ / bbl	85.00
Weighted-average deferred premium received | $ / bbl	0.48
Average Monthly Volume (Bbls) | bbl	29,250
2015 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price | $ / bbl	91.34
Average Monthly Volume (Bbls) | bbl	272,531
2015 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Collar contracts [Member]
Derivative [Line Items]
Weighted-average floor price | $ / bbl	80.00
Weighted-average ceiling price | $ / bbl	94.00
Average Monthly Volume (Bbls) | bbl	5,000
2015 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Basis Swaps [Member]
Derivative [Line Items]
Spread | $ / bbl	(7.06)
Average Monthly Volume (Bbls) | bbl	97,000
2015 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Midway-Sunset basis swaps [Member]
Derivative [Line Items]
Spread | $ / bbl	(9.73)
Average Monthly Volume (Bbls) | bbl	57,000
2015 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Midland Basis Swap [Member]
Derivative [Line Items]
Spread | $ / bbl	(3.25)
Average Monthly Volume (Bbls) | bbl	40,000
2015 [Member] | NGL Derivative Contracts [Member] | MRD Segment [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price | $ / bbl	41.52
Average Monthly Volume (Bbls) | bbl	163,000
2015 [Member] | NGL Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price | $ / bbl	42.38
Average Monthly Volume (Bbls) | bbl	209,200
2016 [Member] | Natural Gas Derivative Contracts [Member] | MRD Segment [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	2,570,000
Weighted-average fixed price	4.09
2016 [Member] | Natural Gas Derivative Contracts [Member] | MRD Segment [Member] | Collar contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	1,100,000
Weighted-average floor price	4.00
Weighted-average ceiling price	4.71
2016 [Member] | Natural Gas Derivative Contracts [Member] | MRD Segment [Member] | Put Option [Member] | Purchased [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	6,000,000
Weighted-average strike price	3.51
Weighted-average deferred premium paid	(0.34)
2016 [Member] | Natural Gas Derivative Contracts [Member] | MRD Segment [Member] | TGT Z1 basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	1,120,000
2016 [Member] | Natural Gas Derivative Contracts [Member] | MRD Segment [Member] | TGT Z1 basis swaps [Member] | Henry Hub [Member]
Derivative [Line Items]
Spread	(0.10)
2016 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	3,592,442
Weighted-average fixed price	4.14
2016 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Basis Swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	3,578,333
Spread	(0.07)
2016 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | NGPL TexOk basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	3,003,333
2016 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | NGPL TexOk basis swaps [Member] | Henry Hub [Member]
Derivative [Line Items]
Spread	(0.07)
2016 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | HSC basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	135,000
2016 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | HSC basis swaps [Member] | Henry Hub [Member]
Derivative [Line Items]
Spread	0.07
2016 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | CIG basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	170,000
2016 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | CIG basis swaps [Member] | Henry Hub [Member]
Derivative [Line Items]
Spread	(0.30)
2016 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | TETCO STX basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	270,000
2016 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | TETCO STX basis swaps [Member] | Henry Hub [Member]
Derivative [Line Items]
Spread	0.06
2016 [Member] | Crude Oil Derivative Contracts [Member] | MRD Segment [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price | $ / bbl	84.80
Average Monthly Volume (Bbls) | bbl	8,500
2016 [Member] | Crude Oil Derivative Contracts [Member] | MRD Segment [Member] | Collar contracts [Member]
Derivative [Line Items]
Weighted-average floor price | $ / bbl	80.00
Weighted-average ceiling price | $ / bbl	99.70
Average Monthly Volume (Bbls) | bbl	27,000
2016 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price | $ / bbl	86.87
Average Monthly Volume (Bbls) | bbl	279,813
2016 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Basis Swaps [Member]
Derivative [Line Items]
Spread | $ / bbl	(9.56)
Average Monthly Volume (Bbls) | bbl	95,000
2016 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Midway-Sunset basis swaps [Member]
Derivative [Line Items]
Spread | $ / bbl	(13.35)
Average Monthly Volume (Bbls) | bbl	55,000
2016 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Midland Basis Swap [Member]
Derivative [Line Items]
Spread | $ / bbl	(4.34)
Average Monthly Volume (Bbls) | bbl	40,000
2016 [Member] | NGL Derivative Contracts [Member] | MRD Segment [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price | $ / bbl	34.06
Average Monthly Volume (Bbls) | bbl	185,658
2016 [Member] | NGL Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price | $ / bbl	35.64
Average Monthly Volume (Bbls) | bbl	213,100
2017 [Member] | Natural Gas Derivative Contracts [Member] | MRD Segment [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	1,770,000
Weighted-average fixed price	4.24
2017 [Member] | Natural Gas Derivative Contracts [Member] | MRD Segment [Member] | Collar contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	1,050,000
Weighted-average floor price	4.00
Weighted-average ceiling price	5.06
2017 [Member] | Natural Gas Derivative Contracts [Member] | MRD Segment [Member] | Put Option [Member] | Purchased [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	5,350,000
Weighted-average strike price	3.48
Weighted-average deferred premium paid	(0.32)
2017 [Member] | Natural Gas Derivative Contracts [Member] | MRD Segment [Member] | TGT Z1 basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	200,000
2017 [Member] | Natural Gas Derivative Contracts [Member] | MRD Segment [Member] | TGT Z1 basis swaps [Member] | Henry Hub [Member]
Derivative [Line Items]
Spread	(0.08)
2017 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	3,350,067
Weighted-average fixed price	4.06
2017 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Basis Swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	2,210,000
Spread	(0.04)
2017 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | NGPL TexOk basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	1,800,000
2017 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | NGPL TexOk basis swaps [Member] | Henry Hub [Member]
Derivative [Line Items]
Spread	(0.07)
2017 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | HSC basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	115,000
2017 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | HSC basis swaps [Member] | Henry Hub [Member]
Derivative [Line Items]
Spread	0.14
2017 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | TETCO STX basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	295,000
2017 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | TETCO STX basis swaps [Member] | Henry Hub [Member]
Derivative [Line Items]
Spread	0.03
2017 [Member] | Crude Oil Derivative Contracts [Member] | MRD Segment [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price | $ / bbl	84.70
Average Monthly Volume (Bbls) | bbl	28,000
2017 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price | $ / bbl	84.70
Average Monthly Volume (Bbls) | bbl	301,600
2017 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Basis Swaps [Member]
Derivative [Line Items]
Spread | $ / bbl	(2.35)
Average Monthly Volume (Bbls) | bbl	30,000
2017 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Midland Basis Swap [Member]
Derivative [Line Items]
Spread | $ / bbl	(2.35)
Average Monthly Volume (Bbls) | bbl	30,000
2017 [Member] | NGL Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price | $ / bbl	37.55
Average Monthly Volume (Bbls) | bbl	43,300
2018 [Member] | Natural Gas Derivative Contracts [Member] | MRD Segment [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	4,600,000
Weighted-average fixed price	4.06
2018 [Member] | Natural Gas Derivative Contracts [Member] | MRD Segment [Member] | Put Option [Member] | Purchased [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	3,450,000
Weighted-average strike price	3.62
Weighted-average deferred premium paid	(0.34)
2018 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	3,060,000
Weighted-average fixed price	4.18
2018 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Basis Swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	1,315,000
Spread	(0.02)
2018 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | NGPL TexOk basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	1,200,000
2018 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | NGPL TexOk basis swaps [Member] | Henry Hub [Member]
Derivative [Line Items]
Spread	(0.03)
2018 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | HSC basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	115,000
2018 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | HSC basis swaps [Member] | Henry Hub [Member]
Derivative [Line Items]
Spread	0.15
2018 [Member] | Crude Oil Derivative Contracts [Member] | MRD Segment [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price | $ / bbl	84.50
Average Monthly Volume (Bbls) | bbl	31,625
2018 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price | $ / bbl	83.74
Average Monthly Volume (Bbls) | bbl	312,000
2019 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	2,814,583
Weighted-average fixed price	4.31
2019 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | Basis Swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	900,000
Spread	0.01
2019 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | NGPL TexOk basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu) | MMBTU	900,000
2019 [Member] | Natural Gas Derivative Contracts [Member] | MEMP [Member] | NGPL TexOk basis swaps [Member] | Henry Hub [Member]
Derivative [Line Items]
Spread	0.01
2019 [Member] | Crude Oil Derivative Contracts [Member] | MEMP [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price | $ / bbl	85.52
Average Monthly Volume (Bbls) | bbl	160,000

[1] These transactions were entered into for the purpose of creating a ceiling on our put options, which effectively converted the applicable puts into swaps

[2] These transactions were entered into for the purpose of eliminating the ceiling portion of certain collar arrangements, which effectively converted the applicable collars into swaps.

XML

Summary of Significant Accounting Policies - Schedule of Supplemental Cash Flow (Detail) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Supplemental cash flows:
Cash paid for interest, net of capitalized interest	$ 93,038	$ 67,449
Cash paid for taxes	2,055	550
Noncash investing and financing activities:
Increase (decrease) in capital expenditures in payables and accrued liabilities	4,348	29,137
(Increase) decrease in accounts receivable related to acquisitions and divestitures	9,570	$ (4,271)
MRD Segment [Member]
Noncash investing and financing activities:
Accrued expenses related to MRD equity offering	$ 372

XML

Related Party Transactions - Book Value of Assets Sold (Detail) - WHR Management Company [Member] - WildHorse Resources, LLC [Member] - Disposition [Member] $ in Thousands	Jun. 18, 2014 USD ($)
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

XML

Business Segment Data (Tables)

9 Months Ended

Sep. 30, 2015

Segment Reporting [Abstract]

Summary of Selected Business Segment Information

The following table presents selected business segment information for the periods indicated (in thousands):

					Other,			Consolidated
					Adjustments &			& Combined
	MRD		MEMP		Eliminations			Totals
Total revenues:
Three Months Ended September 30, 2015	$	111,654	$	88,083	$	—		$	199,737
Three Months Ended September 30, 2014		99,035		166,261		—			265,296
Nine Months Ended September 30, 2015		277,282		279,039		—			556,321
Nine Months Ended September 30, 2014		297,340		427,354		—			724,694
Adjusted EBITDA: (1)
Three Months Ended September 30, 2015		104,319		80,766		(75	)		185,010
Three Months Ended September 30, 2014		76,237		97,196		(64	)		173,369
Nine Months Ended September 30, 2015		273,980		250,073		(226	)		523,827
Nine Months Ended September 30, 2014		222,460		243,717		(6,068	)		460,109
Segment assets: (2)
As of September 30, 2015		1,871,270		2,749,376		(3,378	)		4,617,268
As of December 31, 2014		1,413,768		3,189,760		(9,981	)		4,593,547
Total cash expenditures for additions to long-lived assets:
Nine Months Ended September 30, 2015		449,297		202,150		—			651,447
Nine Months Ended September 30, 2014		249,324		1,300,815		—			1,550,139

(1) Adjustments and eliminations for the three and nine months ended September 30, 2015 and 2014 include cash distributions that MEMP paid to MRD during the three and nine months ended September 30, 2015 and 2014, related to the ownership of partnership interests in MEMP. In 2014, MRD LLC owned MEMP subordinated units, which were distributed to MRD Holdco in connection with the Company’s initial public offering in June 2014.

(2) As of September 30, 2015, adjustments and eliminations primarily represent the elimination of accounts receivable and accounts payable balances between the MRD Segment and the MEMP Segment.

Schedule of Calculation of Reportable Segment's Adjusted EBITDA

Calculation of Reportable Segments’ Adjusted EBITDA

	For the Three Months Ended
	September 30, 2015
							Combined
	MRD			MEMP			Totals
	(In thousands)
Net income (loss)	$	56,551		$	(191,981	)	$	(135,430	)
Interest expense, net		9,176			31,255			40,431
Income tax expense (benefit)		54,431			(107	)		54,324
DD&A		53,035			53,305			106,340
Impairment of proved oil and natural gas properties		—			361,836			361,836
Accretion of AROs		95			1,716			1,811
(Gain) loss on commodity derivative instruments		(125,167	)		(244,888	)		(370,055	)
Cash settlements received (paid) on expired commodity derivative instruments		44,010			64,480			108,490
Transaction related costs		213			16			229
Incentive-based compensation expense		7,657			2,993			10,650
Exploration costs		4,068			2,141			6,209
Non-cash equity (income) loss from MEMP		175			—			175
Cash distributions from MEMP		75			—			75
Adjusted EBITDA	$	104,319		$	80,766		$	185,085

	For the Three Months Ended
	September 30, 2014
							Combined
	MRD			MEMP			Totals
	(In thousands)
Net income (loss)	$	10,816		$	101,307		$	112,123
Interest expense, net		9,887			26,458			36,345
Income tax expense (benefit)		26,522			(688	)		25,834
DD&A		30,798			53,649			84,447
Impairment of proved oil and natural gas properties		—			67,181			67,181
Accretion of AROs		132			1,421			1,553
(Gain) loss on commodity derivative instruments		(33,090	)		(156,402	)		(189,492	)
Cash settlements received (paid) on expired commodity derivative instruments		3,699			876			4,575
Transaction related costs		500			925			1,425
Incentive-based compensation expense		26,862			2,427			29,289
Exploration costs		133			42			175
Non-cash equity (income) loss from MEMP		(86	)		—			(86	)
Cash distributions from MEMP		64			—			64
Adjusted EBITDA	$	76,237		$	97,196		$	173,433

	For the Nine Months Ended
	September 30, 2015
							Combined
	MRD			MEMP			Totals
	(In thousands)
Net income (loss)	$	80,219		$	(468,498	)	$	(388,279	)
Interest expense, net		28,545			87,983			116,528
Income tax expense (benefit)		77,345			(1,601	)		75,744
DD&A		129,394			150,857			280,251
Impairment of proved oil and natural gas properties		—			613,183			613,183
Accretion of AROs		311			5,036			5,347
(Gain) loss on commodity derivative instruments		(202,894	)		(328,944	)		(531,838	)
Cash settlements received (paid) on expired commodity derivative instruments		114,298			178,955			293,253
(Gain) loss on sale of properties		50			—			50
Transaction related costs		1,620			1,612			3,232
Incentive-based compensation expense		37,440			7,899			45,339
Exploration costs		7,024			2,263			9,287
Loss on settlement of AROs		—			1,328			1,328
Non-cash equity (income) loss from MEMP		402			—			402
Cash distributions from MEMP		226			—			226
Adjusted EBITDA	$	273,980		$	250,073		$	524,053

	For the Nine Months Ended
	September 30, 2014
							Combined
	MRD			MEMP			Totals
	(In thousands)
Net income (loss)	$	(934,541	)	$	(43,225	)	$	(977,766	)
Interest expense, net		44,355			60,573			104,928
Loss on debt extinguishment		37,248			—			37,248
Income tax expense (benefit)		14,701			(303	)		14,398
DD&A		86,741			129,165			215,906
Impairment of proved oil and natural gas properties		—			67,181			67,181
Accretion of AROs		389			4,212			4,601
(Gain) loss on commodity derivative instruments		(17,130	)		28,710			11,580
Cash settlements received (paid) on expired commodity derivative instruments		(4,930	)		(14,999	)		(19,929	)
(Gain) loss on sale of properties		3,057			—			3,057
Transaction related costs		1,568			3,912			5,480
Incentive-based compensation expense		970,877			5,387			976,264
Exploration costs		1,213			252			1,465
Non-cash equity (income) loss from MEMP		12,844			—			12,844
Provision for environmental remediation		—			2,852			2,852
Cash distributions from MEMP		6,068			—			6,068
Adjusted EBITDA	$	222,460		$	243,717		$	466,177

Reconciliation of Total Reportable Segment's Adjusted EBITDA to Net Income (Loss)

The following table presents a reconciliation of total reportable segments’ Adjusted EBITDA to net income (loss) for each of the periods indicated (in thousands).

	For the Three Months Ended						For the Nine Months Ended
	September 30,						September 30,
	2015			2014			2015			2014
Total Reportable Segments' Adjusted EBITDA	$	185,085		$	173,433		$	524,053		$	466,177
Adjustments to reconcile Adjusted EBITDA to net income (loss):
Interest expense, net		(40,431	)		(36,345	)		(116,528	)		(104,928	)
Loss on debt extinguishment		—			—			—			(37,248	)
Income tax benefit (expense)		(54,324	)		(25,834	)		(75,744	)		(14,398	)
DD&A		(106,340	)		(84,447	)		(280,251	)		(215,906	)
Impairment of proved oil and natural gas properties		(361,836	)		(67,181	)		(613,183	)		(67,181	)
Accretion of AROs		(1,811	)		(1,553	)		(5,347	)		(4,601	)
Gains (losses) on commodity derivative instruments		370,055			189,492			531,838			(11,580	)
Cash settlements paid (received) on expired commodity derivative instruments		(108,490	)		(4,575	)		(293,253	)		19,929
Gain (loss) on sale of properties		—			—			(50	)		(3,057	)
Transaction related costs		(229	)		(1,425	)		(3,232	)		(5,480	)
Incentive-based compensation expense		(10,650	)		(29,289	)		(45,339	)		(976,264	)
Exploration costs		(6,209	)		(175	)		(9,287	)		(1,465	)
Provision for environmental remediation		—			—			—			(2,852	)
Loss on settlement of AROs		—			—			(1,328	)		—
Cash distributions from MEMP		(75	)		(64	)		(226	)		(6,068	)
Net income (loss)	$	(135,255	)	$	112,037		$	(387,877	)	$	(964,922	)

Schedule of Consolidated and Combined Statement of Operations Disaggregated by Reportable Segment

Included below is our consolidated and combined statement of operations disaggregated by reportable segment for the period indicated (in thousands):

	Three Months Ended September 30, 2015
	MRD			MEMP			Other, Adjustments & Eliminations		Consolidated
Revenues:
Oil & natural gas sales	$	111,654		$	87,519		$	—	$	199,173
Other revenues		—			564			—		564
Total revenues		111,654			88,083			—		199,737
Costs and expenses:
Lease operating		7,949			45,416			—		53,365
Gathering, processing, and transportation		22,633			8,134			—		30,767
Gathering, processing, and transportation - affiliate		9,215			—			—		9,215
Pipeline operating		—			461			—		461
Exploration		4,068			2,141			—		6,209
Production and ad valorem taxes		2,751			6,896			—		9,647
Depreciation, depletion, and amortization		53,035			53,305			—		106,340
Impairment of proved oil and natural gas properties		—			361,836			—		361,836
Incentive unit compensation expense		4,965			—			—		4,965
General and administrative		11,695			13,910			—		25,605
Accretion of asset retirement obligations		95			1,716			—		1,811
(Gain) loss on commodity derivative instruments		(125,167	)		(244,888	)		—		(370,055	)
Total costs and expenses		(8,761	)		248,927			—		240,166
Operating income (loss)		120,415			(160,844	)		—		(40,429	)
Other income (expense):
Interest expense, net		(9,176	)		(31,255	)		—		(40,431	)
Earnings from equity investments		(175	)		—			175		—
Other, net		(82	)		11			—		(71	)
Total other income (expense)		(9,433	)		(31,244	)		175		(40,502	)
Income (loss) before income taxes		110,982			(192,088	)		175		(80,931	)
Income tax benefit (expense)		(54,431	)		107			—		(54,324	)
Net income (loss)	$	56,551		$	(191,981	)	$	175	$	(135,255	)

	Three Months Ended September 30, 2014
	MRD			MEMP			Other, Adjustments & Eliminations			Consolidated
Revenues:
Oil & natural gas sales	$	99,029		$	164,935		$	—		$	263,964
Other revenues		6			1,326			—			1,332
Total revenues		99,035			166,261			—			265,296
Costs and expenses:
Lease operating		4,333			41,878			—			46,211
Gathering, processing, and transportation		11,941			7,862			—			19,803
Pipeline operating		—			431			—			431
Exploration		133			42			—			175
Production and ad valorem taxes		2,987			11,053			—			14,040
Depreciation, depletion, and amortization		30,798			53,649			—			84,447
Impairment of proved oil and natural gas properties		—			67,181			—			67,181
Incentive unit compensation expense		25,550			—			—			25,550
General and administrative		9,127			12,069			—			21,196
Accretion of asset retirement obligations		132			1,421			—			1,553
(Gain) loss on commodity derivative instruments		(33,090	)		(156,402	)		—			(189,492	)
Total costs and expenses		51,911			39,184			—			91,095
Operating income (loss)		47,124			127,077			—			174,201
Other income (expense):
Interest expense, net		(9,887	)		(26,458	)		—			(36,345	)
Earnings from equity investments		86			—			(86	)		—
Other, net		15			—			—			15
Total other income (expense)		(9,786	)		(26,458	)		(86	)		(36,330	)
Income (loss) before income taxes		37,338			100,619			(86	)		137,871
Income tax benefit (expense)		(26,522	)		688			—			(25,834	)
Net income (loss)	$	10,816		$	101,307		$	(86	)	$	112,037

	Nine Months Ended September 30, 2015
	MRD			MEMP			Other, Adjustments & Eliminations		Consolidated
Revenues:
Oil & natural gas sales	$	277,282		$	276,689		$	—	$	553,971
Other revenues		—			2,350			—		2,350
Total revenues		277,282			279,039			—		556,321
Costs and expenses:
Lease operating		17,025			130,782			—		147,807
Gathering, processing, and transportation		51,685			25,402			—		77,087
Gathering, processing, and transportation - affiliate		13,028			—			—		13,028
Pipeline operating		—			1,407			—		1,407
Exploration		7,024			2,263			—		9,287
Production and ad valorem taxes		8,666			19,609			—		28,275
Depreciation, depletion, and amortization		129,394			150,857			—		280,251
Impairment of proved oil and natural gas properties		—			613,183			—		613,183
Incentive unit compensation expense		31,305			—			—		31,305
General and administrative		34,994			42,798			—		77,792
Accretion of asset retirement obligations		311			5,036			—		5,347
(Gain) loss on commodity derivative instruments		(202,894	)		(328,944	)		—		(531,838	)
(Gain) loss on sale of properties		50			—			—		50
Other, net		—			(943	)		—		(943	)
Total costs and expenses		90,588			661,450			—		752,038
Operating income (loss)		186,694			(382,411	)		—		(195,717	)
Other income (expense):
Interest expense, net		(28,545	)		(87,983	)		—		(116,528	)
Earnings from equity investments		(402	)		—			402		—
Other, net		(183	)		295			—		112
Total other income (expense)		(29,130	)		(87,688	)		402		(116,416	)
Income (loss) before income taxes		157,564			(470,099	)		402		(312,133	)
Income tax benefit (expense)		(77,345	)		1,601			—		(75,744	)
Net income (loss)	$	80,219		$	(468,498	)	$	402	$	(387,877	)

	Nine Months Ended September 30, 2014
	MRD			MEMP			Other, Adjustments & Eliminations		Consolidated & Combined
Revenues:
Oil & natural gas sales	$	297,328		$	423,782		$	—	$	721,110
Other revenues		12			3,572			—		3,584
Total revenues		297,340			427,354			—		724,694
Costs and expenses:
Lease operating		12,361			99,526			—		111,887
Gathering, processing, and transportation		30,793			21,016			—		51,809
Pipeline operating		—			1,596			—		1,596
Exploration		1,213			252			—		1,465
Production and ad valorem taxes		9,141			24,482			—		33,623
Depreciation, depletion, and amortization		86,741			129,165			—		215,906
Impairment of proved oil and natural gas properties		—			67,181			—		67,181
Incentive unit compensation expense		969,390			—			—		969,390
General and administrative		26,880			34,181			—		61,061
Accretion of asset retirement obligations		389			4,212			—		4,601
(Gain) loss on commodity derivative instruments		(17,130	)		28,710			—		11,580
(Gain) loss on sale of properties		3,057			—			—		3,057
Other, net		—			(12	)		—		(12	)
Total costs and expenses		1,122,835			410,309			—		1,533,144
Operating income (loss)		(825,495	)		17,045			—		(808,450	)
Other income (expense):
Interest expense, net		(44,355	)		(60,573	)		—		(104,928	)
Loss on extinguishment on debt		(37,248	)		—			—		(37,248	)
Earnings from equity investments		(12,844	)		—			12,844		—
Other, net		102			—			—		102
Total other income (expense)		(94,345	)		(60,573	)		12,844		(142,074	)
Income before income taxes		(919,840	)		(43,528	)		12,844		(950,524	)
Income tax benefit (expense)		(14,701	)		303			—		(14,398	)
Net income (loss)	$	(934,541	)	$	(43,225	)	$	12,844	$	(964,922	)

XML

Risk Management and Derivative Instruments - Summary of Gross Fair Value and Net Recorded Fair Value of Derivative Instruments by Appropriate Balance Sheet Classification (Detail) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Net recorded fair value	$ 383,548	$ 340,056
Asset Derivatives, Net recorded fair value	630,496	435,369
Liability Derivatives, Net recorded fair value	3,515	3,289
Liability Derivatives, Net recorded fair value	3,183
Short-term derivative instruments [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	428,389	378,908
Asset Derivatives, Netting arrangements	(44,841)	(38,852)
Asset Derivatives, Net recorded fair value	383,548	340,056
Liability Derivatives, Gross fair value	48,356	42,141
Liability Derivatives, Netting arrangements	(44,841)	(38,852)
Liability Derivatives, Net recorded fair value	3,515	3,289
Short-term derivative instruments [Member] | Commodity derivatives [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	428,389	378,908
Liability Derivatives, Gross fair value	46,127	38,852
Short-term derivative instruments [Member] | Interest rate swaps [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Liability Derivatives, Gross fair value	2,229	3,289
Long-term derivative instruments [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	666,846	468,156
Asset Derivatives, Netting arrangements	(36,350)	(32,787)
Asset Derivatives, Net recorded fair value	630,496	435,369
Liability Derivatives, Gross fair value	39,533	32,787
Liability Derivatives, Netting arrangements	(36,350)	(32,787)
Liability Derivatives, Net recorded fair value	3,183
Long-term derivative instruments [Member] | Commodity derivatives [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	666,846	466,851
Liability Derivatives, Gross fair value	36,402	32,787
Long-term derivative instruments [Member] | Interest rate swaps [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value		$ 1,305
Liability Derivatives, Gross fair value	$ 3,131

XML

Long-Term Incentive Plans - Summary of Information Regarding Restricted Common Unit Awards (Detail) - Restricted Stock [Member]	9 Months Ended
	Sep. 30, 2015 $ / shares shares
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
Forfeited, Number of Shares	(30,209)
Vested, Number of Shares	(274,355)
Restricted common shares outstanding, Number of Shares, Ending Balance	1,693,205
Restricted common shares outstanding, Weighted-Average Grant Date Fair Value Per Shares, Beginning Balance | $ / shares	$ 19.00
Granted, Weighted-Average Grant Date Fair Value Per Shares | $ / shares	18.80
Forfeited, Weighted-Average Grant Date Fair Value Per Shares | $ / shares	18.86
Vested, Weighted-Average Grant Date Fair Value Per Shares | $ / shares	19.00
Restricted common shares outstanding, Weighted-Average Grant Date Fair Value Per Shares, Ending Balance | $ / shares	$ 18.89
MEMP [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted, Number of Shares	815,607
Forfeited, Number of Shares	(32,876)
Vested, Number of Shares	(483,627)
Restricted common shares outstanding, Weighted-Average Grant Date Fair Value Per Shares, Beginning Balance | $ / shares	$ 20.93
Granted, Weighted-Average Grant Date Fair Value Per Shares | $ / shares	15.04
Forfeited, Weighted-Average Grant Date Fair Value Per Shares | $ / shares	19.61
Vested, Weighted-Average Grant Date Fair Value Per Shares | $ / shares	20.37
Restricted common shares outstanding, Weighted-Average Grant Date Fair Value Per Shares, Ending Balance | $ / shares	$ 17.70
Restricted common shares outstanding, Number of Units, Beginning Balance	1,093,520
Restricted common shares outstanding, Number of Units, Ending Balance	1,392,624

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Long Term Debt - Summary of Weighted-Average Interest Rates Paid On Variable-Rate Debt Obligations (Detail)	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
MRD Segment [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates	1.94%	2.62%	1.86%	2.15%
MRD Segment [Member] | WildHorse Resources, LLC [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates				4.04%
MRD Segment [Member] | WildHorse Resources second lien [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates				6.44%
MEMP [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates	2.14%	2.16%	2.06%	2.08%

XML

Fair Value Measurements of Financial Instruments - Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) - Fair Value, Measurements [Member] - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Assets:
Fair value of derivative asset	$ 1,095,235	$ 847,064
Liabilities:
Fair value of derivative liability	87,889	74,928
Significant Other Observable Inputs (Level 2) [Member]
Assets:
Fair value of derivative asset	1,095,235	847,064
Liabilities:
Fair value of derivative liability	87,889	74,928
Commodity derivatives [Member]
Assets:
Fair value of derivative asset	1,095,235	845,759
Liabilities:
Fair value of derivative liability	82,529	71,639
Commodity derivatives [Member] | Significant Other Observable Inputs (Level 2) [Member]
Assets:
Fair value of derivative asset	1,095,235	845,759
Liabilities:
Fair value of derivative liability	82,529	71,639
Interest rate derivatives [Member]
Assets:
Fair value of derivative asset		1,305
Liabilities:
Fair value of derivative liability	5,360	3,289
Interest rate derivatives [Member] | Significant Other Observable Inputs (Level 2) [Member]
Assets:
Fair value of derivative asset		1,305
Liabilities:
Fair value of derivative liability	$ 5,360	$ 3,289

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Acquisitions and Divestitures

9 Months Ended

Sep. 30, 2015

Business Combinations [Abstract]

Acquisitions and Divestitures

Note 3. Acquisitions and Divestitures

Transaction-related costs, which include costs associated with acquisitions and divestitures, are included in general and administrative expenses in the accompanying statements of operations for the periods indicated below (in thousands):

For the Three Months Ended				For the Nine Months Ended
September 30,				September 30,
2015		2014		2015		2014
$	229	$	1,425	$	3,232	$	5,480

2015 Acquisitions

Subsequent event. On October 22, 2015, MRD closed a transaction to acquire certain producing and non-producing oil and natural gas properties in North Louisiana from a third party for approximately $284.0 million, subject to customary post-closing adjustments.

2015 Divestitures

On April 17, 2015, MRD sold certain oil and natural gas properties in Colorado and Wyoming to a third party for approximately $13.6 million (the “Rockies Divestiture”) and recorded a loss of less than $0.1 million related to the sale.

2014 Acquisitions

On March 25, 2014, MEMP closed a transaction to acquire certain oil and natural gas producing properties in the Eagle Ford from a third party for approximately $168.1 million, including customary post-closing adjustments (the “Eagle Ford Acquisition”).

On July 1, 2014, MEMP closed a transaction to acquire certain oil and natural gas liquids properties in Wyoming from a third party for approximately $906.1 million, including customary post-closing adjustments (the “Wyoming Acquisition”).

The following unaudited pro forma combined results of operations are provided for the nine months ended September 30, 2014 as though the Wyoming Acquisition had been completed on January 1, 2013. The unaudited pro forma financial information was derived from the historical combined statements of operations of the Company and the previous owners and adjusted to include: (i) the revenues and direct operating expenses associated with oil and gas properties acquired, (ii) depletion expense applied to the adjusted basis of the properties acquired and (iii) interest expense on additional borrowings necessary to finance the acquisition. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of expected future results of operations.

	For the Nine Months Ended
	September 30,
	2014
MRD Consolidated and Combined	(In thousands)
Revenues	$	815,893
Net income (loss)		(930,903	)
Basic and diluted earnings per share	$	(4.94	)

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.

XML

Long Term Debt - Summary of Unamortized Deferred Financing Costs Associated with Consolidated Debt Obligations (Detail) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Unamortized deferred financing costs	$ 40,250	$ 44,474
MRD Segment [Member] | 2.0 Billion Revolving Credit Facility Due June 2019 [Member]
Debt Instrument [Line Items]
Unamortized deferred financing costs	5,264	4,285
MRD Segment [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Unamortized deferred financing costs	11,355	12,455
MEMP [Member] | 2.0 Billion Revolving Credit Facility Due March 2018 [Member]
Debt Instrument [Line Items]
Unamortized deferred financing costs	4,534	6,468
MEMP [Member] | 7.625% senior unsecured notes, due May 2021 ("2021 Senior Notes") [Member]
Debt Instrument [Line Items]
Unamortized deferred financing costs	11,722	13,308
MEMP [Member] | 6.875% Senior Unsecured Notes Due August 2022 ("2022 Senior Notes") [Member]
Debt Instrument [Line Items]
Unamortized deferred financing costs	$ 7,375	$ 7,958

XML

Summary of Significant Accounting Policies - Additional Information (Detail) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Summary Of Significant Accounting Policies [Line Items]
Unrecognized tax benefits	$ 0		$ 0
Effective tax rate	(67.10%)	18.70%	(24.30%)	(1.50%)
Deferred tax adjustments			$ 38,778,000
Initial Public Offering [Member]
Summary Of Significant Accounting Policies [Line Items]
Deferred tax adjustments			4,400,000
Property Exchanges Under Common Control [Member]
Summary Of Significant Accounting Policies [Line Items]
Deferred tax adjustments			$ 34,400,000

XML

Asset Retirement Obligations (Tables)

9 Months Ended

Sep. 30, 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 nine months ended September 30, 2015 (in thousands):

Asset retirement obligations at beginning of period	$	122,531
Liabilities added from acquisitions or drilling		1,565
Liabilities settled		(780	)
Revision of estimates		573
Liabilities removed upon sale of wells		(176	)
Accretion expense		5,347
Asset retirement obligations at end of period	$	129,060

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Risk Management and Derivative Instruments (Tables)

9 Months Ended

Sep. 30, 2015

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Schedule of Open Commodity Positions

At September 30, 2015, the MRD Segment had the following open commodity positions:

	Remaining
	2015			2016			2017			2018
Natural Gas Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (MMBtu)		3,400,000			2,570,000			1,770,000			4,600,000
Weighted-average fixed price	$	4.15		$	4.09		$	4.24		$	4.06
Collar contracts:
Average Monthly Volume (MMBtu)		130,000			1,100,000			1,050,000			—
Weighted-average floor price	$	4.00		$	4.00		$	4.00		$	—
Weighted-average ceiling price	$	4.64		$	4.71		$	5.06		$	—
Purchased put option contracts:
Average Monthly Volume (MMBtu)		4,100,000			6,000,000			5,350,000			3,450,000
Weighted-average strike price	$	3.75		$	3.51		$	3.48		$	3.62
Weighted-average deferred premium paid	$	(0.33	)	$	(0.34	)	$	(0.32	)	$	(0.34	)
Written call option contracts (1):
Average Monthly Volume (MMBtu)		3,225,000			—			—			—
Weighted-average sold strike price	$	3.75		$	—		$	—		$	—
Weighted-average deferred premium received	$	0.08		$	—		$	—		$	—
TGT Z1 basis swaps:
Average Monthly Volume (MMBtu)		3,380,000			1,120,000			200,000			—
Spread - Henry Hub	$	(0.10	)	$	(0.10	)	$	(0.08	)	$	—
Crude Oil Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		42,000			8,500			28,000			31,625
Weighted-average fixed price	$	91.67		$	84.80		$	84.70		$	84.50
Collar contracts:
Average Monthly Volume (Bbls)		2,000			27,000			—			—
Weighted-average floor price	$	85.00		$	80.00		$	—		$	—
Weighted-average ceiling price	$	101.35		$	99.70		$	—		$	—
Purchased put option contracts:
Average Monthly Volume (Bbls)		39,000			—			—			—
Weighted-average strike price	$	85.00		$	—		$	—		$	—
Weighted-average deferred premium paid	$	(3.80	)	$	—		$	—		$	—
Written call option contracts (1):
Average Monthly Volume (Bbls)		29,250			—			—			—
Weighted-average sold strike price	$	85.00		$	—		$	—		$	—
Weighted-average deferred premium received	$	0.48		$	—		$	—		$	—
NGL Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		163,000			185,658			—			—
Weighted-average fixed price	$	41.52		$	34.06		$	—		$	—

(1) These transactions were entered into for the purpose of creating a ceiling on our put options, which effectively converted the applicable puts into swaps.

At September 30, 2015, the MEMP Segment had the following open commodity positions:

	Remaining
	2015			2016			2017			2018			2019
Natural Gas Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (MMBtu)		3,359,237			3,592,442			3,350,067			3,060,000			2,814,583
Weighted-average fixed price	$	4.08		$	4.14		$	4.06		$	4.18		$	4.31
Collar contracts:
Average Monthly Volume (MMBtu)		350,000			—			—			—			—
Weighted-average floor price	$	4.62		$	—		$	—		$	—		$	—
Weighted-average ceiling price	$	5.80		$	—		$	—		$	—		$	—
Call spreads (1):
Average Monthly Volume (MMBtu)		80,000			—			—			—			—
Weighted-average sold strike price	$	5.25		$	—		$	—		$	—		$	—
Weighted-average bought strike price	$	6.75		$	—		$	—		$	—		$	—
Basis swaps:
Average Monthly Volume (MMBtu)		3,690,000			3,578,333			2,210,000			1,315,000			900,000
Spread	$	(0.12	)	$	(0.07	)	$	(0.04	)	$	(0.02	)	$	0.01
Crude Oil Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		272,531			279,813			301,600			312,000			160,000
Weighted-average fixed price	$	91.34		$	86.87		$	84.70		$	83.74		$	85.52
Collar contracts:
Average Monthly Volume (Bbls)		5,000			—			—			—			—
Weighted-average floor price	$	80.00		$	—		$	—		$	—		$	—
Weighted-average ceiling price	$	94.00		$	—		$	—		$	—		$	—
Basis swaps:
Average Monthly Volume (Bbls)		97,000			95,000			30,000			—			—
Spread	$	(7.06	)	$	(9.56	)	$	(2.35	)	$	—		$	—
NGL Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		209,200			213,100			43,300			—			—
Weighted-average fixed price	$	42.38		$	35.64		$	37.55		$	—		$	—

(1) These transactions were entered into for the purpose of eliminating the ceiling portion of certain collar arrangements, which effectively converted the applicable collars into swaps.

The MEMP Segment basis swaps included in the table above is presented on a disaggregated basis below:

	Remaining
	2015			2016			2017			2018			2019
Natural Gas Derivative Contracts:
NGPL TexOk basis swaps:
Average Monthly Volume (MMBtu)		3,030,000			3,003,333			1,800,000			1,200,000			900,000
Spread - Henry Hub	$	(0.11	)	$	(0.07	)	$	(0.07	)	$	(0.03	)	$	0.01
HSC basis swaps:
Average Monthly Volume (MMBtu)		150,000			135,000			115,000			115,000			—
Spread - Henry Hub	$	(0.08	)	$	0.07		$	0.14		$	0.15		$	—
CIG basis swaps:
Average Monthly Volume (MMBtu)		210,000			170,000			—			—			—
Spread - Henry Hub	$	(0.25	)	$	(0.30	)	$	—		$	—		$	—
TETCO STX basis swaps:
Average Monthly Volume (MMBtu)		300,000			270,000			295,000			—			—
Spread - Henry Hub	$	(0.09	)	$	0.06		$	0.03		$	—		$	—
Crude Oil Derivative Contracts:
Midway-Sunset basis swaps:
Average Monthly Volume (Bbls)		57,000			55,000			—			—			—
Spread - Brent	$	(9.73	)	$	(13.35	)	$	—		$	—		$	—
Midland basis swaps:
Average Monthly Volume (Bbls)		40,000			40,000			30,000			—			—
Spread - WTI	$	(3.25	)	$	(4.34	)	$	(2.35	)	$	—		$	—

Schedule of Entity's Interest Rate Swap Open Positions

At September 30, 2015, we had the following interest rate swap open positions:

	Remaining
Credit Facility	2015			2016			2017			2018
MEMP:
Average Monthly Notional (in thousands)	$	400,000		$	400,000		$	400,000		$	100,000
Weighted-average fixed rate		0.943	%		0.943	%		1.612	%		1.946	%
Floating rate	1 Month LIBOR			1 Month LIBOR			1 Month LIBOR			1 Month LIBOR

Summary of Gross Fair Value and Net Recorded Fair Value of Derivative Instruments by Appropriate Balance Sheet Classification

The following table summarizes both: (i) the gross fair value of derivative instruments by the appropriate balance sheet classification even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the balance sheet and (ii) the net recorded fair value as reflected on the balance sheet at September 30, 2015 and December 31, 2014. There was no cash collateral received or pledged associated with our derivative instruments since most of the counterparties, or certain of their affiliates, to our derivative contracts are lenders under our collective credit agreements.

		Asset Derivatives						Liability Derivatives
		September 30,			December 31,			September 30,			December 31,
Type	Balance Sheet Location	2015			2014			2015			2014
		(In thousands)
Commodity contracts	Short-term derivative instruments	$	428,389		$	378,908		$	46,127		$	38,852
Interest rate swaps	Short-term derivative instruments		—			—			2,229			3,289
Gross fair value			428,389			378,908			48,356			42,141
Netting arrangements	Short-term derivative instruments		(44,841	)		(38,852	)		(44,841	)		(38,852	)
Net recorded fair value	Short-term derivative instruments	$	383,548		$	340,056		$	3,515		$	3,289
Commodity contracts	Long-term derivative instruments	$	666,846		$	466,851		$	36,402		$	32,787
Interest rate swaps	Long-term derivative instruments		—			1,305			3,131			—
Gross fair value			666,846			468,156			39,533			32,787
Netting arrangements	Long-term derivative instruments		(36,350	)		(32,787	)		(36,350	)		(32,787	)
Net recorded fair value	Long-term derivative instruments	$	630,496		$	435,369		$	3,183		$	—

Schedule of Gains and Losses Related to Derivative Instruments

The following table details the gains and losses related to derivative instruments for the periods indicated (in thousands):

		For the Three Months Ended						For the Nine Months Ended
	Statements of	September 30,						September 30,
	Operations Location	2015			2014			2015			2014
Commodity derivative contracts	(Gain) loss on commodity derivatives	$	(370,055	)	$	(189,492	)	$	(531,838	)	$	11,580
Interest rate derivatives	Interest expense, net		3,543			(175	)		6,628			1,157

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Long Term Debt - Consolidated Debt Obligations (Detail) - USD ($) $ in Thousands		Sep. 30, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Long-term debt		$ 2,604,264	$ 2,378,413
MRD Segment [Member]
Debt Instrument [Line Items]
Long-term debt		726,000	783,000
MRD Segment [Member] | 2.0 Billion Revolving Credit Facility Due June 2019 [Member]
Debt Instrument [Line Items]
Credit facility		126,000	183,000
MRD Segment [Member] | 5.875% Senior Unsecured Notes Due July 2022 [Member]
Debt Instrument [Line Items]
Senior Notes	[1]	600,000	600,000
MEMP [Member]
Debt Instrument [Line Items]
Unamortized discounts		(14,726)	(16,587)
Long-term debt		1,878,264	1,595,413
MEMP [Member] | 2.0 Billion Revolving Credit Facility Due March 2018 [Member]
Debt Instrument [Line Items]
Credit facility		696,000	412,000
MEMP [Member] | 7.625% senior unsecured notes, due May 2021 ("2021 Senior Notes") [Member]
Debt Instrument [Line Items]
Senior Notes	[2]	700,000	700,000
MEMP [Member] | 6.875% Senior Unsecured Notes Due August 2022 ("2022 Senior Notes") [Member]
Debt Instrument [Line Items]
Senior Notes	[3]	$ 496,990	$ 500,000

[1] (1)The estimated fair value of this fixed-rate debt was $547.5 million and $534.0 million at September 30, 2015 and December 31, 2014, respectively.

[2] The estimated fair value of this fixed-rate debt was $469.0 million and $563.5 million at September 30, 2015 and December 31, 2014, respectively.

[3] The estimated fair value of this fixed-rate debt was $303.2 million and $380.0 million at September 30, 2015 and December 31, 2014, respectively.

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Acquisitions and Divestitures - Transaction Related Costs (Detail) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Business Acquisition [Line Items]
Transaction related costs	$ 229	$ 1,425	$ 3,232	$ 5,480
General and administrative expense [Member]
Business Acquisition [Line Items]
Transaction related costs	$ 229	$ 1,425	$ 3,232	$ 5,480

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Restricted Investments (Tables)

9 Months Ended

Sep. 30, 2015

Schedule Of Investments [Abstract]

Restricted Investment Balance

The components of the restricted investment balance consisted of the following at the dates indicated:

	September 30,		December 31,
	2015		2014
	(In thousands)
BOEM platform abandonment (See Note 15)	$	73,488	$	69,954
BOEM lease bonds		794		794
SPBPC Collateral:
Contractual pipeline and surface facilities abandonment		3,060		2,701
California State Lands Commission pipeline right-of-way bond		3,005		3,005
City of Long Beach pipeline facility permit		500		500
Federal pipeline right-of-way bond		307		307
Port of Long Beach pipeline license		100		100
Restricted investments	$	81,254	$	77,361

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Long Term Debt (Tables)

9 Months Ended

Sep. 30, 2015

Debt Disclosure [Abstract]

Consolidated Debt Obligations

The following table presents our consolidated debt obligations at the dates indicated:

	September 30,			December 31,
	2015			2014
	(In thousands)
MRD Segment:
MRD $2.0 billion revolving credit facility, variable-rate, due June 2019	$	126,000		$	183,000
5.875% senior unsecured notes, due July 2022 ("MRD Senior Notes") (1) (4)		600,000			600,000
Subtotal		726,000			783,000
MEMP Segment:
MEMP $2.0 billion revolving credit facility, variable-rate, due March 2018		696,000			412,000
7.625% senior unsecured notes, due May 2021 ("2021 Senior Notes") (2) (4)		700,000			700,000
6.875% senior unsecured notes, due August 2022 ("2022 Senior Notes") (3) (4)		496,990			500,000
Unamortized discounts		(14,726	)		(16,587	)
Subtotal		1,878,264			1,595,413
Total long-term debt	$	2,604,264		$	2,378,413

(1) The estimated fair value of this fixed-rate debt was $547.5 million and $534.0 million at September 30, 2015 and December 31, 2014, respectively.

(2) The estimated fair value of this fixed-rate debt was $469.0 million and $563.5 million at September 30, 2015 and December 31, 2014, respectively.

(3) The estimated fair value of this fixed-rate debt was $303.2 million and $380.0 million at September 30, 2015 and December 31, 2014, respectively.

(4) The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.

Borrowing Base Credit Facility

The borrowing base for each credit facility was the following at the date indicated (in thousands):

	September 30,
	2015
MRD Segment:
MRD $2.0 billion revolving credit facility, variable-rate, due June 2019	$	1,000,000
MEMP Segment:
MEMP $2.0 billion revolving credit facility, variable-rate, due March 2018		1,300,000

Summary of Weighted-Average Interest Rates Paid On Variable-Rate Debt Obligations

The following table presents the weighted-average interest rates paid on our consolidated variable-rate debt obligations for the periods presented:

	For the Three Months Ended						For the Nine Months Ended
Credit Facility	September 30,						September 30,
	2015			2014			2015			2014
MRD Segment:
MRD revolving credit facility		1.94	%		2.62	%		1.86	%		2.15	%
WildHorse Resources revolver terminated June 2014	n/a			n/a			n/a				4.04	%
WildHorse Resources second lien terminated June 2014	n/a			n/a			n/a				6.44	%
MEMP Segment:
MEMP revolving credit facility		2.14	%		2.16	%		2.06	%		2.08	%

Summary of Unamortized Deferred Financing Costs Associated with Consolidated Debt Obligations

Unamortized deferred financing costs associated with our consolidated debt obligations were as follows at the dates indicated:

	September 30,		December 31,
	2015		2014
	(In thousands)
MRD Segment:
MRD revolving credit facility	$	5,264	$	4,285
MRD Senior Notes		11,355		12,455
MEMP Segment:
MEMP revolving credit facility		4,534		6,468
2021 Senior Notes		11,722		13,308
2022 Senior Notes		7,375		7,958
	$	40,250	$	44,474

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Summary of Significant Accounting Policies

9 Months Ended

Sep. 30, 2015

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

Note 2. Summary of Significant Accounting Policies

A discussion of our critical accounting policies and estimates is included in our Current Report on Form 8-K filed on July 8, 2015 (our “Recast Form 8-K”).  Our Recast Form 8-K was filed to retrospectively revise certain historical segment financial information to give effect to the Property Swap for comparability purposes and to include a new note containing condensed consolidating financial information.

Accrued liabilities

Current accrued liabilities consisted of the following at the dates indicated (in thousands):

	September 30,		December 31,
	2015		2014
Accrued capital expenditures	$	84,698	$	80,350
Accrued lease operating expense		18,495		16,403
Accrued general and administrative expenses		14,035		8,516
Accrued ad valorem taxes		15,010		8,870
Accrued interest payable		36,810		24,797
Accrued income tax payable		4,942		52
Accrued environmental		588		2,092
Other miscellaneous, including operator advances		2,021		6,043
	$	176,599	$	147,123

Supplemental Cash Flow Information

Supplemental cash flow for the periods presented (in thousands):

	For the Nine Months Ended
	September 30,
	2015		2014
Supplemental cash flows:
Cash paid for interest, net of capitalized interest	$	93,038	$	67,449
Cash paid for taxes		2,055		550
Noncash investing and financing activities:
Increase (decrease) in capital expenditures in payables and accrued liabilities		4,348		29,137
(Increase) decrease in accounts receivable related to acquisitions and divestitures		9,570		(4,271	)
Accrued expenses related to MRD equity offering		372		—

Income Tax

MRD is a corporation subject to federal and certain state income taxes. The net income (loss) attributable to noncontrolling interest is related to MEMP, which is a pass-through entity for federal income tax purposes. As discussed in Note 12, the compensation expense associated with the incentive units of MRD Holdco creates a nondeductible permanent difference for income tax purposes. MRD’s predecessor was organized as a pass-through entity for federal income tax purposes and was not subject to federal income taxes prior to our initial public offering in June 2014; however, certain of its consolidating subsidiaries were subject to federal and certain state income taxes. 

MRD reported no liability for unrecognized tax benefits as of September 30, 2015 and expects no significant change to the unrecognized tax benefits in the next twelve months. 

MRD’s effective tax rate for the three and nine months ended September 30, 2015 was negative 67.1% and negative 24.3%, respectively, and the effective tax rate for the three and nine months ended September 30, 2014 was 18.7% and negative 1.5%, respectively. The effective tax rate for the three and nine months ended September 30, 2014 and 2015 differs from the statutory federal income tax rate primarily due to the following recurring items:

· earnings from the MEMP Segment pass-through entities;

· non-deductible incentive unit compensation; and

· state income tax, net of federal benefit.

MRD reported a $38.8 million increase to equity during the nine months ended September 30, 2015, of which $4.4 million was associated with the estimated deferred tax effects included in equity in connection with its initial public offering and $34.4 million was attributable to the deferred tax effects of the property exchanges under common control including certain oil and gas properties in East Texas that MEMP acquired from MRD in February 2015. 

New Accounting Pronouncements

Simplifying the Accounting for Measurement-Period Adjustments. In September 2015, the Financial Accounting Standards Board ("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 does not expect the impact of adopting this guidance to be material to the Company's financial statements and related 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.

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 currently believe we will continue to consolidate MEMP and become subject to the VIE primary beneficiary disclosure requirements. The deconsolidation of MEMP would have a material impact on our consolidated financial statements and related disclosures in the event there is a reconsideration event that triggers deconsolidation.

Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Company’s financial position, results of operations and cash flows.

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Stockholders' Equity and Noncontrolling Interests (Tables)

9 Months Ended

Sep. 30, 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 issued for the nine months ended September 30, 2015:

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	(30,209	)
Balance September 30, 2015	205,318,103

(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.

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

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Background, Organization and Basis of Presentation - Additional Information (Detail) $ in Millions	1 Months Ended	9 Months Ended
	Feb. 28, 2015 USD ($)	Sep. 30, 2015 Segment
Consolidation And Basis Of Presentation [Line Items]
Number of reportable business segments | Segment		2
MEMP [Member]
Consolidation And Basis Of Presentation [Line Items]
Net payment made to affiliate for acquisition of oil and natural gas properties	$ 78.4
Net equity deemed contribution (distribution) related to net assets transferred	$ 127.1
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%
MRD Operating [Member]
Consolidation And Basis Of Presentation [Line Items]
Ownership interest percentage		100.00%

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Risk Management and Derivative Instruments - Schedule of Gains and Losses Related to Derivative Instruments (Detail) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Gain (Loss) on Derivative Instruments, Net, Pretax [Abstract]
(Gain) loss on commodity derivative instruments	$ (370,055)	$ (189,492)	$ (531,838)	$ 11,580
Interest expense, net	40,431	36,345	116,528	104,928
Commodity derivative contracts [Member]
Gain (Loss) on Derivative Instruments, Net, Pretax [Abstract]
(Gain) loss on commodity derivative instruments	(370,055)	(189,492)	(531,838)	11,580
Interest rate derivatives [Member]
Gain (Loss) on Derivative Instruments, Net, Pretax [Abstract]
Interest expense, net	$ 3,543	$ (175)	$ 6,628	$ 1,157

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Incentive Units - Fair Value of Incentive Units Estimated (Detail)	9 Months Ended
	Sep. 30, 2015
Exchanged Incentive Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Dividend yield	0.00%
Expected volatility	48.99%
Risk-free rate	0.54%
Expected life (years)	1 year 8 months 1 day
Subsequent Incentive Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Dividend yield	0.00%
Expected volatility	48.99%
Risk-free rate	0.54%
Expected life (years)	1 year 8 months 1 day

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UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 7,363	$ 5,958
Accounts receivable:
Oil and natural gas sales	77,795	82,263
Joint interest owners and other	58,193	49,313
Short-term derivative instruments	383,548	340,056
Prepaid expenses and other current assets	27,856	28,027
Total current assets	554,755	505,617
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method	5,477,217	4,844,529
Other	27,053	33,815
Accumulated depreciation, depletion and impairment	(2,208,722)	(1,340,688)
Property and equipment, net	3,295,548	3,537,656
Long-term derivative instruments	630,496	435,369
Restricted investments	81,254	77,361
Other long-term assets	55,215	37,544
Total assets	4,617,268	4,593,547
Current liabilities:
Accounts payable	38,668	25,772
Accounts payable - affiliates	9,757	624
Revenues payable	70,380	57,352
Accrued liabilities	176,599	147,123
Deferred income tax liabilities	57,444	51,877
Short-term derivative instruments	3,515	3,289
Total current liabilities	356,363	286,037
Noncurrent liabilities:
Long-term debt	2,604,264	2,378,413
Asset retirement obligations	129,060	122,531
Long-term derivative instruments	3,183
Deferred tax liabilities	120,789	95,017
Other long-term liabilities	6,995	8,585
Total liabilities	$ 3,220,654	$ 2,890,583
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; 205,318,103 shares issued and outstanding at September 30, 2015; 193,435,414 shares issued and outstanding at December 31, 2014	$ 2,053	$ 1,935
Additional paid-in capital	1,554,671	1,367,346
Accumulated earnings (deficit)	(757,229)	(786,871)
Total stockholders' equity	799,495	582,410
Noncontrolling interests	597,119	1,120,554
Total equity	1,396,614	1,702,964
Total liabilities and equity	4,617,268	4,593,547
MRD Segment [Member]
Noncurrent liabilities:
Long-term debt	726,000	783,000
MEMP [Member]
Noncurrent liabilities:
Long-term debt	$ 1,878,264	$ 1,595,413

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Acquisitions and Divestitures - Additional Information (Detail) - USD ($) $ in Millions	Oct. 22, 2015	Apr. 17, 2015	Jul. 02, 2014	May. 09, 2014	Mar. 25, 2014
Eagle Ford Acquisition [Member]
Business Acquisition And Divestiture [Line Items]
Payments to acquire oil and gas properties and leases					$ 168.1
Wyoming Acquisition [Member]
Business Acquisition And Divestiture [Line Items]
Payments to acquire oil and gas properties and leases			$ 906.1
Rockies Divestiture [Member]
Business Acquisition And Divestiture [Line Items]
Proceeds from divestitures		$ 13.6
Gain (loss) on sale of oil and gas properties		$ (0.1)
North Louisiana [Member] | Subsequent Event [Member]
Business Acquisition And Divestiture [Line Items]
Payments to acquire oil and gas properties and leases	$ 284.0
Northern Oklahoma [Member]
Business Acquisition And Divestiture [Line Items]
Proceeds from divestitures				$ 7.6
Gain (loss) on sale of oil and gas properties				$ (3.2)

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UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED AND COMBINED EQUITY - USD ($) $ in Thousands	Total	MEMP [Member]	MRD Segment [Member]	Member Equity [Member]	Common Stock [Member]	Common Stock [Member] MRD Segment [Member]	Additional paid in capital [Member]	Accumulated earnings (deficit) [Member]	Accumulated earnings (deficit) [Member] MRD Segment [Member]	Previous Owners [Member] Member Equity [Member]	Noncontrolling Interest [Member]	Noncontrolling Interest [Member] MEMP [Member]
Total equity, beginning balance at Dec. 31, 2013	$ 858,132										$ 580,615
Members' equity, beginning balance at Dec. 31, 2013				$ 237,186						$ 40,331
Net income (loss)	(964,922)			20,305				$ (951,801)		1,425	(34,851)
Issuance of shares in connection with restructuring transactions	914,862				$ 1,710		$ 913,152
Issuance of shares/units in connection with equity offerings	921,164				215		379,962				540,987
Restricted stock awards					11		(11)
Tax related effects in connection with restructuring transactions and initial public offering	(43,251)						(43,251)
Contribution related to MRD Holdco incentive unit compensation expense	137,307						137,307
Contribution related to sale of assets to NGP affiliate	1,165			1,165
Net book value of assets sold to NGP affiliate	(621)			(621)
Distributions	(101,327)										(101,327)
Net book value of assets acquired from NGP affiliates	3,303			45,059						$ (41,756)
Purchase of noncontrolling interest	(3,292)						(2,881)				(411)
Distribution of net assets to MRD Holdco	(93,084)			(123,078)							29,994
Distribution of shares received in connection with restructuring transactions to MRD Holdco	(110,510)			(110,510)
Distribution to NGP affiliates in connection with acquisition of assets	(66,693)			(66,693)
Net equity deemed contribution (distribution) related to net assets transferred to MEMP				(2,659)							2,659
Amortization of MEMP equity awards	6,874						1,487				5,387
Other	(108)			$ (154)			378				(332)
Total equity, ending balance at Sep. 30, 2014	1,458,999										1,022,721
Total stockholders equity, ending balance at Sep. 30, 2014					1,936		1,386,143	(951,801)
Total equity, beginning balance at Dec. 31, 2014	1,702,964										1,120,554
Total stockholders equity, beginning balance at Dec. 31, 2014	582,410				1,935		1,367,346	(786,871)
Net income (loss)	(387,877)							78,594			(466,471)
Share repurchase	(47,785)	$ (53,999)			(28)			(47,757)				$ (53,999)
Issuance of shares/units in connection with equity offerings	242,880				138		242,742
Cost incurred in conjunction with equity offering	(4,351)						(4,351)
Restricted stock awards					9		(9)
Amortization of restricted stock awards	6,135						6,135
Contribution related to MRD Holdco incentive unit compensation expense	31,305						31,305
Deferred tax adjustments (Note 2)	38,778						38,778
Distributions	(138,123)										(138,123)
Amortization of MEMP equity awards	7,899										7,899
MRD restricted shares repurchased			$ (1,196)			$ (1)			$ (1,195)
Other	(16)						(126)				110
Total equity, ending balance at Sep. 30, 2015	1,396,614										597,119
Total stockholders equity, ending balance at Sep. 30, 2015	$ 799,495				$ 2,053		1,554,671	$ (757,229)
Net equity deemed contribution (distribution) related to MEMP property exchange (Note 1)							$ (127,149)				$ 127,149

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Long Term Debt - Borrowing Base Credit Facility (Parenthetical) (Detail)	Sep. 30, 2015 USD ($)
MRD Segment [Member] | 2.0 Billion Revolving Credit Facility Due June 2019 [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility	$ 2,000,000,000
MEMP [Member] | 2.0 Billion Revolving Credit Facility Due March 2018 [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility	$ 2,000,000,000

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Incentive Units (Tables)

9 Months Ended

Sep. 30, 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	9/30/2015			9/30/2015
Dividend yield		0	%		0	%
Expected volatility		48.99	%		48.99	%
Risk-free rate		0.54	%		0.54	%
Expected life (years)		1.67			1.67

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Stockholders' Equity and Noncontrolling Interests - Summary of Changes In Common Shares Issued (Parenthetical) (Detail) $ in Millions	9 Months Ended
	Sep. 30, 2015 USD ($)
Statement Of Stockholders Equity [Abstract]
Payments remitted for employees tax obligations	$ 1.2

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Condensed Consolidating Financial Information

9 Months Ended

Sep. 30, 2015

Organization Consolidation And Presentation Of Financial Statements [Abstract]

Condensed Consolidating Financial Information

Note 16. Condensed Consolidating Financial Information  

The Company owns no operating assets and has no significant operations independent of its subsidiaries. Our obligations under the MRD Senior Notes outstanding are fully and unconditionally guaranteed, jointly and severally, by certain of our 100% owned subsidiaries on a senior unsecured basis. Subsidiaries with noncontrolling interests (i.e. MEMP) and certain de minimis subsidiaries are non-guarantors.

The following condensed consolidating financial information presents the financial information of the Company on a unconsolidated stand-alone basis and its combined guarantor and combined non-guarantor subsidiaries as of and for the period indicated. Such financial information may not necessarily be indicative of our results of operations, cash flows or financial position had these subsidiaries operated as independent entities.

	As of September 30, 2015
	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	4,725	$	2,107	$	531	$	—		$	7,363
Accounts receivable - trade		6,890		76,715		55,169		(2,786	)		135,988
Accounts receivable - affiliates		7,438		—		—		(7,438	)		—
Short-term derivative instruments		152,208		—		231,340		—			383,548
Prepaid expenses and other current assets		4,995		8,603		14,258		—			27,856
Total current assets		176,256		87,425		301,298		(10,224	)		554,755
Property and equipment, net		16,814		1,371,384		1,907,350		—			3,295,548
Long-term derivative instruments		191,426		—		439,070		—			630,496
Investments in subsidiaries		1,261,135		—		—		(1,261,135	)		—
Other long-term assets		13,526		21,285		101,658		—			136,469
Total assets	$	1,659,157	$	1,480,094	$	2,749,376	$	(1,271,359	)	$	4,617,268
LIABILITIES AND EQUITY
Current Liabilities:
Accounts payable and accrued liabilities	$	24,574	$	86,766	$	104,488	$	(561	)	$	215,267
Accounts payable - affiliates		—		14,376		5,006		(9,625	)		9,757
Revenues payable		80		37,600		32,700		—			70,380
Deferred tax liabilities		55,985		—		1,459		—			57,444
Short-term derivative instruments		—		—		3,515		—			3,515
Total current liabilities		80,639		138,742		147,168		(10,186	)		356,363
Long-term debt		726,000		—		1,878,264		—			2,604,264
Asset retirement obligations		—		8,316		120,744		—			129,060
Long-term derivative  instruments		—		—		3,183		—			3,183
Deferred tax liabilities		46,028		72,372		2,389		—			120,789
Other long-term liabilities		6,995		—		—		—			6,995
Total liabilities		859,662		219,430		2,151,748		(10,186	)		3,220,654
Equity:
Equity		799,495		1,260,664		591,740		(1,852,404	)		799,495
Noncontrolling interest		—		—		5,888		591,231			597,119
Total equity		799,495		1,260,664		597,628		(1,261,173	)		1,396,614
Total liabilities & equity	$	1,659,157	$	1,480,094	$	2,749,376	$	(1,271,359	)	$	4,617,268

	As of December 30, 2014
	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	2,241	$	3,762	$	970	$	(1,015	)	$	5,958
Accounts receivable- trade		5,995		44,952		83,346		(2,717	)		131,576
Accounts receivable - affiliates		10,047		—		28		(10,075	)		—
Short-term derivative instruments		131,471		—		208,585		—			340,056
Prepaid expenses and other current assets		5,833		7,993		14,201		—			28,027
Total current assets		155,587		56,707		307,130		(13,807	)		505,617
Property and equipment, net		16,601		1,050,722		2,470,333		—			3,537,656
Long-term derivative instruments		123,567		—		311,802		—			435,369
Investments in subsidiaries		1,139,792		—		—		(1,139,792	)		—
Other long-term assets		14,124		5,660		100,521		(5,400	)		114,905
Total assets	$	1,449,671	$	1,113,089	$	3,189,786	$	(1,158,999	)	$	4,593,547
LIABILITIES AND EQUITY
Current Liabilities:
Accounts payable and accrued expenses	$	6,245	$	56,598	$	113,177	$	(3,125	)	$	172,895
Accounts payable - affiliates		—		3,638		6,409		(9,423	)		624
Revenues payable		—		27,242		30,110		—			57,352
Deferred tax liabilities		—		50,470		1,407		—			51,877
Short-term derivative instruments		—		—		3,289		—			3,289
Total current liabilities		6,245		137,948		154,392		(12,548	)		286,037
Long-term debt		783,000		—		1,595,413		—			2,378,413
Asset retirement obligations		—		9,830		112,701		—			122,531
Deferred tax liabilities		69,431		—		30,986		(5,400	)		95,017
Other long-term liabilities		8,585		—		—		—			8,585
Total liabilities		867,261		147,778		1,893,492		(17,948	)		2,890,583
Equity:
Equity		582,410		965,311		1,290,734		(2,256,045	)		582,410
Noncontrolling 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	$	1,449,671	$	1,113,089	$	3,189,786	$	(1,158,999	)	$	4,593,547

	Three Months Ended September 30, 2015
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues:
Oil & natural gas sales	$	—		$	111,654		$	87,519		$	—		$	199,173
Other income		—			—			564			—			564
Total revenues		—			111,654			88,083			—			199,737
Costs and expenses:
Lease operating		—			7,949			45,416			—			53,365
Gathering, processing and transportation		—			22,633			8,134			—			30,767
Gathering, processing and transportation - affiliate		—			9,215			—			—			9,215
Pipeline operating		—			—			461			—			461
Exploration		—			4,068			2,141			—			6,209
Production and ad valorem taxes		—			2,751			6,896			—			9,647
Depreciation, depletion and amortization		1,087			51,948			53,305			—			106,340
Impairment of proved oil and natural gas properties		—			—			361,836			—			361,836
Incentive unit compensation expense		4,965			—			—			—			4,965
General and administrative		11,327			368			13,910			—			25,605
Accretion of asset retirement obligations		—			95			1,716			—			1,811
(Gain) loss on commodity derivatives		(125,167	)		—			(244,888	)		—			(370,055	)
Total costs and expenses		(107,788	)		99,027			248,927			—			240,166
Operating income (loss)		107,788			12,627			(160,844	)		—			(40,429	)
Other income (expense):
Interest expense, net		(9,174	)		(2	)		(31,255	)		—			(40,431	)
Equity earnings from subsidiaries		10,839			—			—			(10,839	)		—
Other, net		(100	)		18			11			—			(71	)
Total other income (expense)		1,565			16			(31,244	)		(10,839	)		(40,502	)
Income before income taxes		109,353			12,643			(192,088	)		(10,839	)		(80,931	)
Income tax benefit (expense)		(52,801	)		(1,630	)		107			—			(54,324	)
Net income (loss)		56,552			11,013			(191,981	)		(10,839	)		(135,255	)
Net income (loss) attributable to noncontrolling interest		—			—			104			(191,911	)		(191,807	)
Net income (loss) attributable to Memorial Resource Development Corp.	$	56,552		$	11,013		$	(192,085	)	$	181,072		$	56,552

	Three Months Ended September 30, 2014
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues:
Oil & natural gas sales	$	—		$	99,026		$	164,938		$	—		$	263,964
Other income		6			—			1,326			—			1,332
Total revenues		6			99,026			166,264			—			265,296
Costs and expenses:
Lease operating		—			4,320			41,891			—			46,211
Gathering, processing and transportation		—			11,941			7,862			—			19,803
Pipeline operating		—			—			431			—			431
Exploration		—			133			42			—			175
Production and ad valorem taxes		—			2,987			11,053			—			14,040
Depreciation, depletion and amortization		168			30,630			53,649			—			84,447
Impairment of proved oil and natural gas properties		—			—			67,181			—			67,181
Incentive unit compensation expense		25,550			—			—			—			25,550
General and administrative		7,215			1,889			12,092			—			21,196
Accretion of asset retirement obligations		1			131			1,421			—			1,553
(Gain) loss on commodity derivatives		(33,090	)		—			(156,402	)		—			(189,492	)
Total costs and expenses		(156	)		52,031			39,220			—			91,095
Operating income (loss)		162			46,995			127,044			—			174,201
Other income (expense):
Interest expense, net		(9,868	)		(19	)		(26,458	)		—			(36,345	)
Equity earnings from subsidiaries		25,675			—			—			(25,675	)		—
Other, net		—			5			10			—			15
Total other income (expense)		15,807			(14	)		(26,448	)		(25,675	)		(36,330	)
Income before income taxes		15,969			46,981			100,596			(25,675	)		137,871
Income tax benefit (expense)		(6,041	)		(20,489	)		696			—			(25,834	)
Net income (loss)		9,928			26,492			101,292			(25,675	)		112,037
Net income (loss) attributable to noncontrolling interest		—			—			52			102,057			102,109
Net income (loss) attributable to Memorial Resource Development Corp.	$	9,928		$	26,492		$	101,240		$	(127,732	)	$	9,928

	Nine Months Ended September 30, 2015
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Revenues:
Oil & natural gas sales	$	—		$	277,282		$	276,689		$	—		$	553,971
Other income		—			—			2,350			—			2,350
Total revenues		—			277,282			279,039			—			556,321
Costs and expenses:
Lease operating		—			17,025			130,782			—			147,807
Gathering, processing and transportation		—			51,685			25,402			—			77,087
Gathering, processing and transportation -affiliate		—			13,028			—			—			13,028
Pipeline operating		—			—			1,407			—			1,407
Exploration		—			7,024			2,263			—			9,287
Production and ad valorem taxes		—			8,666			19,609			—			28,275
Depreciation, depletion and amortization		3,139			126,255			150,857			—			280,251
Impairment of proved oil and natural gas properties		—			—			613,183			—			613,183
Incentive unit compensation expense		31,305			—			—			—			31,305
General and administrative		32,656			2,338			42,798			—			77,792
Accretion of asset retirement obligations		—			311			5,036			—			5,347
(Gain) loss on commodity derivatives		(202,894	)		—			(328,944	)		—			(531,838	)
(Gain) loss on sale of properties		—			50			—			—			50
Other, net		—			—			(943	)		—			(943	)
Total costs and expenses		(135,794	)		226,382			661,450			—			752,038
Operating income (loss)		135,794			50,900			(382,411	)		—			(195,717	)
Other income (expense):
Interest expense, net		(28,456	)		(89	)		(87,983	)		—			(116,528	)
Equity earnings from subsidiaries		28,180			—			—			(28,180	)		—
Other, net		(100	)		(83	)		295			—			112
Total other income (expense)		(376	)		(172	)		(87,688	)		(28,180	)		(116,416	)
Income before income taxes		135,418			50,728			(470,099	)		(28,180	)		(312,133	)
Income tax benefit (expense)		(56,824	)		(20,521	)		1,601			—			(75,744	)
Net income (loss)		78,594			30,207			(468,498	)		(28,180	)		(387,877	)
Net income (loss) attributable to noncontrolling interest		—			—			328			(466,799	)		(466,471	)
Net income (loss) attributable to Memorial Resource Development Corp.	$	78,594		$	30,207		$	(468,826	)	$	438,619		$	78,594

	Nine Months Ended September 30, 2014
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Combined & Consolidated
	(In thousands)
Revenues:
Oil & natural gas sales	$	—		$	297,325		$	423,785		$	—		$	721,110
Other income		5			7			3,572			—			3,584
Total revenues		5			297,332			427,357			—			724,694
Costs and expenses:
Lease operating		—			12,348			99,539			—			111,887
Gathering, processing and transportation		—			30,793			21,016			—			51,809
Pipeline operating		—			—			1,596			—			1,596
Exploration		—			1,213			252			—			1,465
Production and ad valorem taxes		—			9,141			24,482			—			33,623
Depreciation, depletion and amortization		168			86,573			129,165			—			215,906
Impairment of proved oil and natural gas properties		—			—			67,181			—			67,181
Incentive unit compensation expense		137,307			831,060			1,023			—			969,390
General and administrative		7,390			19,450			34,221			—			61,061
Accretion of asset retirement obligations		1			388			4,212			—			4,601
(Gain) loss on commodity derivatives		(36,525	)		19,395			28,710			—			11,580
(Gain) loss on sale of properties		—			3,167			(110	)		—			3,057
Other, net		—			—			(12	)		—			(12	)
Total costs and expenses		108,341			1,013,528			411,275			—			1,533,144
Operating income (loss)		(108,336	)		(716,196	)		16,082			—			(808,450	)
Other income (expense):
Interest expense, net		(10,843	)		(33,512	)		(60,573	)		—			(104,928	)
Debt extinguishment costs		(23,562	)		(13,686	)		—			—			(37,248	)
Equity earnings from subsidiaries		(811,093	)		—			—			811,093			—
Other, net		—			92			10			—			102
Total other income (expense)		(845,498	)		(47,106	)		(60,563	)		811,093			(142,074	)
Income before income taxes		(953,834	)		(763,302	)		(44,481	)		811,093			(950,524	)
Income tax benefit (expense)		2,033			(16,742	)		311			—			(14,398	)
Net income (loss)		(951,801	)		(780,044	)		(44,170	)		811,093			(964,922	)
Net income (loss) attributable to noncontrolling interest		—			—			95			(34,946	)		(34,851	)
Net income (loss) attributable to Memorial Resource Development Corp.		(951,801	)		(780,044	)		(44,265	)		846,039			(930,071	)

	Nine Months Ended September 30, 2015
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Net cash provided by (used in) operating activities	$	64,375		$	187,457		$	185,572		$	1,015		$	438,419
Cash flows from investing activities:
Acquisitions of oil and natural gas properties		—			(7,267	)		(6,095	)		—			(13,362	)
Acquisition post-closing adjustment receipts		—			—			9,570			—			9,570
Additions to oil and gas properties		—			(438,262	)		(196,055	)		—			(634,317	)
Additions to other property and equipment		(3,340	)		(428	)		—			—			(3,768	)
Additions to restricted investments		—			—			(3,893	)		—			(3,893	)
Deposit for property acquisition		—			(21,286	)		—			—			(21,286	)
Investments in subsidiaries		(266,431	)		—			—			266,431			—
Distributions from subsidiaries		78,622			—			—			(78,622	)		—
Proceeds from the sale of oil and gas properties		—			13,612			—			—			13,612
Net cash used in investing activities		(191,149	)		(453,631	)		(196,473	)		187,809			(653,444	)
Cash flows from financing activities:
Advances on revolving credit facility		403,000			—			345,000			—			748,000
Payments on revolving credit facility		(460,000	)		—			(61,000	)		—			(521,000	)
Repayment of senior notes		—			—			(2,914	)		—			(2,914	)
Deferred finance costs		(1,446	)		—			(319	)		—			(1,765	)
Proceeds from MRD equity offering		242,880			—			—			—			242,880
Costs incurred in conjunction with MRD equity offering		(3,979	)		—			—			—			(3,979	)
Capital contributions		—			264,519			1,912			(266,431	)		—
Distributions to MRD		—			—			(78,396	)		78,396			—
Distribution to partners		—			—			(138,349	)		138,349			—
Distribution to noncontrolling interests		—			—			—			(138,123	)		(138,123	)
Repurchases of equity		(51,197	)		—			(55,472	)		—			(106,669	)
Net cash provided by financing activities		129,258			264,519			10,462			(187,809	)		216,430
Net change in cash and cash equivalents		2,484			(1,655	)		(439	)		1,015			1,405
Cash and cash equivalents, beginning of period		2,241			3,762			970			(1,015	)		5,958
Cash and cash equivalents, end of period	$	4,725		$	2,107		$	531		$	—		$	7,363

	Nine Months Ended September 30, 2014
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Combined & Consolidated
	(In thousands)
Net cash provided by (used in) operating activities	$	8,463		$	149,927		$	207,070		$	—		$	365,460
Cash flows from investing activities:
Acquisitions of oil and natural gas properties		—			—			(1,083,167	)		—			(1,083,167	)
Additions to oil and gas properties		—			(240,204	)		(217,634	)		—			(457,838	)
Additions to other property and equipment		(8,936	)		(184	)		(14	)		—			(9,134	)
Additions to restricted investments		—			—			(2,883	)		—			(2,883	)
Investments in subsidiaries		(611,853	)		—			—			611,853			—
Distributions from subsidiaries		—			56,027			—			(56,027	)		—
Change in restricted cash		—			49,946			—			—			49,946
Proceeds from the sale of oil and gas properties		—			—			6,700			—			6,700
Other		—			—			(301	)		—			(301	)
Net cash used in investing activities		(620,789	)		(134,415	)		(1,297,299	)		555,826			(1,496,677	)
Cash flows from financing activities:
Advances on revolving credit facility		1,013,000			126,800			1,325,000			—			2,464,800
Payments on revolving credit facility		(985,000	)		(329,900	)		(1,127,000	)		—			(2,441,900	)
Termination of second lien credit facility		—			(328,282	)		—			—			(328,282	)
Proceeds from the issuances of senior notes		600,000			—			492,425			—			1,092,425
Redemption of senior notes		(351,808	)		—			—			—			(351,808	)
Deferred finance costs		(18,814	)		(61	)		(11,409	)		—			(30,284	)
Proceeds from MRD initial public offering		408,500			—			—			—			408,500
Costs incurred in conjunction with initial public offering		(28,198	)		—			—			—			(28,198	)
Proceeds from MEMP equity offering		—			—			553,288			—			553,288
Costs incurred in conjunction with MEMP equity offering		—			—			(12,222	)		—			(12,222	)
Capital contributions		—			608,466			3,387			(611,853	)		—
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		—			—			(156,549	)		156,549			—
Distribution to NGP affiliates related to purchase of assets		—			(63,389	)		(3,304	)		—			(66,693	)
Distribution to noncontrolling interests		—			—			—			(101,327	)		(101,327	)
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		—			213			—			—			213
Net cash provided by financing activities		617,181			(58,443	)		1,061,705			(556,631	)		1,063,812
Net change in cash and cash equivalents		4,855			(42,931	)		(28,524	)		(805	)		(67,405	)
Cash and cash equivalents, beginning of period		—			48,619			29,102			—			77,721
Cash and cash equivalents, end of period	$	4,855		$	5,688		$	578		$	(805	)	$	10,316

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Related Party Transactions (Tables)

9 Months Ended

Sep. 30, 2015

Related Party Transactions [Abstract]

Schedule of Net Assets Recorded

WildHorse Resources recorded the following net assets (in thousands):

Accounts receivable	$	2,274
Oil and natural gas properties, net		40,056
Accrued liabilities		(297	)
Asset retirement obligations		(277	)
Net assets	$	41,756

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

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Summary of Significant Accounting Policies (Policies)

9 Months Ended

Sep. 30, 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.

References to: (i) “Memorial Production Partners,” “MEMP” and “the Partnership” refer to Memorial Production Partners LP individually and collectively with its subsidiaries, as the context requires; (ii) “MEMP GP” refer to Memorial Production Partners GP LLC, the general partner of the Partnership, which we own; (iii) “MRD Holdco” refer to MRD Holdco LLC, a holding company controlled by the Funds (defined below) that, together as part of a group, owns a majority of our common stock; (iv) “MRD LLC” refer to Memorial Resource Development LLC, which historically owned our predecessor’s business and was merged into MRD Operating LLC (“MRD Operating”), our 100% owned subsidiary, subsequent to our initial public offering; (v) “WildHorse Resources” refer to WildHorse Resources, LLC, which owned our interest in the Terryville Complex and merged into MRD Operating in February 2015; (vi) “our predecessor” refer collectively to MRD LLC and its former consolidated subsidiaries, consisting of Classic Hydrocarbons Holdings, L.P., Classic Hydrocarbons GP Co., L.L.C., Black Diamond Minerals, LLC, Beta Operating Company, LLC, MEMP GP, BlueStone Natural Resources Holdings, LLC (“BlueStone”), MRD Operating, WildHorse Resources, Tanos Energy LLC and each of their respective subsidiaries, including MEMP and its subsidiaries; (vii) “the Funds” refer collectively to Natural Gas Partners VIII, L.P., Natural Gas Partners IX, L.P. and NGP IX Offshore Holdings, L.P., which collectively control MRD Holdco; and (viii) “NGP” refer to Natural Gas Partners, a family of private equity investment funds organized to make direct equity investments in the energy industry, including the Funds.

Previous Owners

Previous Owners

References to “the previous owners” for accounting and financial reporting purposes refer to the net profits interest that WildHorse Resources purchased from NGP Income Co-Investment Fund II, L.P. (“NGPCIF”) in February 2014 (“NGPCIF NPI”). NGPCIF is controlled by NGP. Upon the completion of certain acquisitions in 2010, WildHorse Resources sold a net profits interest in these properties to NGPCIF. Since WildHorse Resources sold the net profits interest, the historical results are accounted for as a working interest for all periods.

Our unaudited financial statements reported herein include the financial position and results attributable to NGPCIF NPI.

Basis of Presentation

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 initial public offering, our consolidated financial statements include our accounts and those of our subsidiaries in which we have a controlling interest. Due to our control of MEMP through our ownership of MEMP GP, we are required to consolidate MEMP for accounting and financial reporting purposes. MEMP is owned 99.9% by its limited partners and 0.1% by MEMP GP.

Certain amounts in the prior year financial statements have been reclassified to conform to current presentation. Gathering, processing, and transportation costs were previously accounted for as revenue deductions and are now being presented as costs and expenses on our statements of operations on a separate line item.

All material intercompany transactions and balances have been eliminated in preparation of our consolidated and combined financial statements. Our results of operations for the three and nine months ended September 30, 2015 are not necessarily indicative of results expected for the full year. In our opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments of a normal recurring nature necessary for fair presentation. Although we believe the disclosures in these financial statements are adequate and make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted pursuant to the rules and regulations of the United States Securities and Exchange Commission (“SEC”).

We have two reportable business segments, both of which are engaged in the acquisition, exploration and development of oil and natural gas properties (See Note 14). Our reportable business segments are as follows:

· MRD—reflects the combined operations of the Company and its consolidating subsidiaries except for MEMP and its subsidiaries.

· MEMP—reflects the combined operations of MEMP and its subsidiaries.

Segment financial information has been retrospectively revised for the acquisition by the MEMP Segment of certain assets from the MRD Segment in East Texas in February 2015 in exchange for approximately $78.4 million in cash and certain properties in North Louisiana (the “Property Swap”) for comparability purposes. Our equity statement reflects a $127.1 million equity transfer from stockholders’ equity to noncontrolling interest related to this transaction.

Use of Estimates

Use of Estimates

The preparation of the accompanying unaudited condensed consolidated and combined financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated and combined financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Significant estimates include, but are not limited to, oil and natural gas reserves; depreciation, depletion, and amortization of proved oil and natural gas properties; future cash flows from oil and natural gas properties; impairment of long-lived assets; fair value of derivatives; fair value of equity compensation; fair values of assets acquired and liabilities assumed in business combinations, income taxes and asset retirement obligations.

Accrued Liabilities

Accrued liabilities

Current accrued liabilities consisted of the following at the dates indicated (in thousands):

	September 30,		December 31,
	2015		2014
Accrued capital expenditures	$	84,698	$	80,350
Accrued lease operating expense		18,495		16,403
Accrued general and administrative expenses		14,035		8,516
Accrued ad valorem taxes		15,010		8,870
Accrued interest payable		36,810		24,797
Accrued income tax payable		4,942		52
Accrued environmental		588		2,092
Other miscellaneous, including operator advances		2,021		6,043
	$	176,599	$	147,123

Supplemental Cash Flow Information

Supplemental Cash Flow Information

Supplemental cash flow for the periods presented (in thousands):

	For the Nine Months Ended
	September 30,
	2015		2014
Supplemental cash flows:
Cash paid for interest, net of capitalized interest	$	93,038	$	67,449
Cash paid for taxes		2,055		550
Noncash investing and financing activities:
Increase (decrease) in capital expenditures in payables and accrued liabilities		4,348		29,137
(Increase) decrease in accounts receivable related to acquisitions and divestitures		9,570		(4,271	)
Accrued expenses related to MRD equity offering		372		—

Income Tax

Income Tax

MRD is a corporation subject to federal and certain state income taxes. The net income (loss) attributable to noncontrolling interest is related to MEMP, which is a pass-through entity for federal income tax purposes. As discussed in Note 12, the compensation expense associated with the incentive units of MRD Holdco creates a nondeductible permanent difference for income tax purposes. MRD’s predecessor was organized as a pass-through entity for federal income tax purposes and was not subject to federal income taxes prior to our initial public offering in June 2014; however, certain of its consolidating subsidiaries were subject to federal and certain state income taxes. 

MRD reported no liability for unrecognized tax benefits as of September 30, 2015 and expects no significant change to the unrecognized tax benefits in the next twelve months. 

MRD’s effective tax rate for the three and nine months ended September 30, 2015 was negative 67.1% and negative 24.3%, respectively, and the effective tax rate for the three and nine months ended September 30, 2014 was 18.7% and negative 1.5%, respectively. The effective tax rate for the three and nine months ended September 30, 2014 and 2015 differs from the statutory federal income tax rate primarily due to the following recurring items:

· earnings from the MEMP Segment pass-through entities;

· non-deductible incentive unit compensation; and

· state income tax, net of federal benefit.

MRD reported a $38.8 million increase to equity during the nine months ended September 30, 2015, of which $4.4 million was associated with the estimated deferred tax effects included in equity in connection with its initial public offering and $34.4 million was attributable to the deferred tax effects of the property exchanges under common control including certain oil and gas properties in East Texas that MEMP acquired from MRD in February 2015. 

New Accounting Pronouncements

New Accounting Pronouncements

Simplifying the Accounting for Measurement-Period Adjustments. In September 2015, the Financial Accounting Standards Board ("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 does not expect the impact of adopting this guidance to be material to the Company's financial statements and related 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.

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 currently believe we will continue to consolidate MEMP and become subject to the VIE primary beneficiary disclosure requirements. The deconsolidation of MEMP would have a material impact on our consolidated financial statements and related disclosures in the event there is a reconsideration event that triggers deconsolidation.

Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Company’s financial position, results of operations and cash flows.

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Long-Term Incentive Plans - Summary of Information Regarding Restricted Common Unit Awards (Parenthetical) (Detail) - Restricted Stock [Member] $ / shares in Units, $ in Millions	9 Months Ended
	Sep. 30, 2015 USD ($) $ / shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted, Weighted-Average Grant Date Fair Value Per Shares	$ 18.80
MRD Segment [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Aggregate grant date fair value | $	$ 17.6
MEMP [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Aggregate grant date fair value | $	$ 12.3
Granted, Weighted-Average Grant Date Fair Value Per Shares	$ 15.04
Minimum [Member] | MRD Segment [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted, Weighted-Average Grant Date Fair Value Per Shares	17.58
Minimum [Member] | MEMP [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted, Weighted-Average Grant Date Fair Value Per Shares	14.70
Maximum [Member] | MRD Segment [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted, Weighted-Average Grant Date Fair Value Per Shares	18.91
Maximum [Member] | MEMP [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted, Weighted-Average Grant Date Fair Value Per Shares	$ 15.45

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Background, Organization and Basis of Presentation

9 Months Ended

Sep. 30, 2015

Organization Consolidation And Presentation Of Financial Statements [Abstract]

Background, Organization and Basis of Presentation

Note 1. Background, Organization and Basis of Presentation

Overview

Memorial Resource Development Corp. (the “Company”) is a publicly traded Delaware corporation, the common shares of which are listed on the NASDAQ Global Market (“NASDAQ”) under the symbol “MRD.” Unless the context requires otherwise, references to “we,” “us,” “our,” “MRD,” or “the Company” are intended to mean the business and operations of Memorial Resource Development Corp. and its consolidated subsidiaries.

References to: (i) “Memorial Production Partners,” “MEMP” and “the Partnership” refer to Memorial Production Partners LP individually and collectively with its subsidiaries, as the context requires; (ii) “MEMP GP” refer to Memorial Production Partners GP LLC, the general partner of the Partnership, which we own; (iii) “MRD Holdco” refer to MRD Holdco LLC, a holding company controlled by the Funds (defined below) that, together as part of a group, owns a majority of our common stock; (iv) “MRD LLC” refer to Memorial Resource Development LLC, which historically owned our predecessor’s business and was merged into MRD Operating LLC (“MRD Operating”), our 100% owned subsidiary, subsequent to our initial public offering; (v) “WildHorse Resources” refer to WildHorse Resources, LLC, which owned our interest in the Terryville Complex and merged into MRD Operating in February 2015; (vi) “our predecessor” refer collectively to MRD LLC and its former consolidated subsidiaries, consisting of Classic Hydrocarbons Holdings, L.P., Classic Hydrocarbons GP Co., L.L.C., Black Diamond Minerals, LLC, Beta Operating Company, LLC, MEMP GP, BlueStone Natural Resources Holdings, LLC (“BlueStone”), MRD Operating, WildHorse Resources, Tanos Energy LLC and each of their respective subsidiaries, including MEMP and its subsidiaries; (vii) “the Funds” refer collectively to Natural Gas Partners VIII, L.P., Natural Gas Partners IX, L.P. and NGP IX Offshore Holdings, L.P., which collectively control MRD Holdco; and (viii) “NGP” refer to Natural Gas Partners, a family of private equity investment funds organized to make direct equity investments in the energy industry, including the Funds.

Previous Owners

References to “the previous owners” for accounting and financial reporting purposes refer to the net profits interest that WildHorse Resources purchased from NGP Income Co-Investment Fund II, L.P. (“NGPCIF”) in February 2014 (“NGPCIF NPI”). NGPCIF is controlled by NGP. Upon the completion of certain acquisitions in 2010, WildHorse Resources sold a net profits interest in these properties to NGPCIF. Since WildHorse Resources sold the net profits interest, the historical results are accounted for as a working interest for all periods.

Our unaudited financial statements reported herein include the financial position and results attributable to NGPCIF NPI.

Basis of Presentation

The financial statements reported herein include the financial position and results attributable to both our predecessor and the previous owners on a combined basis for periods prior to our initial public offering. For periods after the completion of our initial public offering, our consolidated financial statements include our accounts and those of our subsidiaries in which we have a controlling interest. Due to our control of MEMP through our ownership of MEMP GP, we are required to consolidate MEMP for accounting and financial reporting purposes. MEMP is owned 99.9% by its limited partners and 0.1% by MEMP GP.

Certain amounts in the prior year financial statements have been reclassified to conform to current presentation. Gathering, processing, and transportation costs were previously accounted for as revenue deductions and are now being presented as costs and expenses on our statements of operations on a separate line item.

All material intercompany transactions and balances have been eliminated in preparation of our consolidated and combined financial statements. Our results of operations for the three and nine months ended September 30, 2015 are not necessarily indicative of results expected for the full year. In our opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments of a normal recurring nature necessary for fair presentation. Although we believe the disclosures in these financial statements are adequate and make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted pursuant to the rules and regulations of the United States Securities and Exchange Commission (“SEC”).

We have two reportable business segments, both of which are engaged in the acquisition, exploration and development of oil and natural gas properties (See Note 14). Our reportable business segments are as follows:

· MRD—reflects the combined operations of the Company and its consolidating subsidiaries except for MEMP and its subsidiaries.

· MEMP—reflects the combined operations of MEMP and its subsidiaries.

Segment financial information has been retrospectively revised for the acquisition by the MEMP Segment of certain assets from the MRD Segment in East Texas in February 2015 in exchange for approximately $78.4 million in cash and certain properties in North Louisiana (the “Property Swap”) for comparability purposes. Our equity statement reflects a $127.1 million equity transfer from stockholders’ equity to noncontrolling interest related to this transaction.

Use of Estimates

The preparation of the accompanying unaudited condensed consolidated and combined financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated and combined financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Significant estimates include, but are not limited to, oil and natural gas reserves; depreciation, depletion, and amortization of proved oil and natural gas properties; future cash flows from oil and natural gas properties; impairment of long-lived assets; fair value of derivatives; fair value of equity compensation; fair values of assets acquired and liabilities assumed in business combinations, income taxes and asset retirement obligations.

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UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Sep. 30, 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	205,318,103	193,435,414
Common stock, shares outstanding	205,318,103	193,435,414

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Long-Term Incentive Plans

9 Months Ended

Sep. 30, 2015

Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]

Long-Term Incentive Plans

Note 11. Long-Term Incentive Plans

MRD

The following table summarizes information regarding restricted common share awards granted under the Memorial Resource Development Corp. 2014 Long-Term Incentive Plan for the periods presented:

	Number of Shares			Weighted-Average Grant Date Fair Value per Share (1)
Restricted common shares outstanding at December 31, 2014		1,059,211		$	19.00
Granted (2)		938,558		$	18.80
Forfeited		(30,209	)	$	18.86
Vested		(274,355	)	$	19.00
Restricted common shares outstanding at September 30, 2015		1,693,205		$	18.89

(1) Determined by dividing the aggregate grant date fair value of awards issued.

(2) The aggregate grant date fair value of restricted common share awards issued in 2015 was $17.6 million based on a grant date market price 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 Three Months Ended				For the Nine Months Ended
September 30,				September 30,
2015		2014		2015		2014
$	2,692	$	1,312	$	6,135	$	1,487

The unrecognized compensation cost associated with restricted common share awards was $28.1 million at September 30, 2015. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.66 years.

MEMP

The following table summarizes information regarding restricted common unit awards granted under the Memorial Production Partners GP LLC Long-Term Incentive Plan for the periods presented:

	Number of Units			Weighted-Average Grant Date Fair Value per Unit (1)
Restricted common units outstanding at December 31, 2014		1,093,520		$	20.93
Granted (2)		815,607		$	15.04
Forfeited		(32,876	)	$	19.61
Vested		(483,627	)	$	20.37
Restricted common units outstanding at September 30, 2015		1,392,624		$	17.70

(1) Determined by dividing the aggregate grant date fair value of awards issued.

(2) The aggregate grant date fair value of restricted common unit awards issued in 2015 was $12.3 million based on a grant date market price ranging from $14.70 to $15.45 per unit.

The following table summarizes the amount of recognized compensation expense associated with these awards that are reflected in the accompanying statements of operations for the periods presented (in thousands):

For the Three Months Ended				For the Nine Months Ended
September 30,				September 30,
2015		2014		2015		2014
$	2,993	$	2,427	$	7,899	$	5,387

The unrecognized compensation cost associated with restricted common unit awards was $20.0 million at September 30, 2015. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.03 years. Since the restricted common units are participating securities, distributions received by the restricted common unitholders are generally included in distributions to noncontrolling interests as presented on our unaudited condensed statements of consolidated and combined cash flows.

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Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2015	Oct. 31, 2015
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2015
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q3
Trading Symbol	MRD
Entity Registrant Name	MEMORIAL RESOURCE DEVELOPMENT CORP.
Entity Central Index Key	0001599222
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		205,314,453

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Incentive Units

9 Months Ended

Sep. 30, 2015

Compensation Related Costs [Abstract]

Incentive Units

Note 12. Incentive Units

MRD Holdco

MRD LLC incentive units were originally granted in June 2012 and February 2013. In connection with our initial public offering and the related restructuring transactions, these incentive units were exchanged for substantially identical units in MRD Holdco, and such incentive units entitle holders thereof to portions of future distributions by MRD Holdco. MRD Holdco’s governing documents authorize the issuance of 1,000 incentive units, of which 930 incentive units were granted in an exchange for the cancelled MRD LLC awards (the “Exchanged Incentive Units”). Subsequent to our initial public offering, MRD Holdco granted the remaining 70 incentive units to certain key employees (the “Subsequent Incentive Units”).

We recognized $5.0 million and $31.3 million of compensation expense for the three and nine months ending September 30, 2015, respectively, offset by a deemed capital contribution from MRD Holdco and the unrecognized compensation expense of approximately $72.7 million as of September 30, 2015 will be recognized over the remaining expected service period of 1.67 years.

The fair value of the Exchanged and Subsequent Incentive Units will be remeasured on a quarterly basis until all payments have been made. The settlement obligation rests with MRD Holdco. Accordingly, no payments will ever be made by us related to these incentive units; however, non-cash compensation expense will be allocated to us in future periods offset by deemed capital contributions. As such, these awards are not dilutive to our stockholders.

The fair value of the incentive units was estimated using a Monte Carlo simulation valuation model with the following assumptions:

	Exchanged Incentive Units			Subsequent Incentive Units
Valuation date	9/30/2015			9/30/2015
Dividend yield		0	%		0	%
Expected volatility		48.99	%		48.99	%
Risk-free rate		0.54	%		0.54	%
Expected life (years)		1.67			1.67

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Business Segment Data - Schedule of Consolidated and Combined Statement of Operations Disaggregated by Reportable Segment (Detail) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Revenues:
Oil & natural gas sales	$ 199,173	$ 263,964	$ 553,971	$ 721,110
Other revenues	564	1,332	2,350	3,584
Total revenues	199,737	265,296	556,321	724,694
Costs and expenses:
Lease operating	53,365	46,211	147,807	111,887
Gathering, processing, and transportation	30,767	19,803	77,087	51,809
Gathering, processing, and transportation - affiliate (Note 13)	9,215		13,028
Pipeline operating	461	431	1,407	1,596
Exploration	6,209	175	9,287	1,465
Production and ad valorem taxes	9,647	14,040	28,275	33,623
Depreciation, depletion, and amortization	106,340	84,447	280,251	215,906
Impairment of proved oil and natural gas properties	361,836	67,181	613,183	67,181
Incentive unit compensation expense	4,965	25,550	31,305	969,390
General and administrative	25,605	21,196	77,792	61,061
Accretion of asset retirement obligations	1,811	1,553	5,347	4,601
(Gain) loss on commodity derivative instruments	(370,055)	(189,492)	(531,838)	11,580
Total costs and expenses	240,166	91,095	752,038	1,533,144
Other, net			(943)	(12)
(Gain) loss on sale of properties			50	3,057
Operating income (loss)	(40,429)	174,201	(195,717)	(808,450)
Other income (expense):
Interest expense, net	(40,431)	(36,345)	(116,528)	(104,928)
Other, net	(71)	15	112	102
Total other income (expense)	(40,502)	(36,330)	(116,416)	(142,074)
Loss on extinguishment of debt				(37,248)
Income (loss) before income taxes	(80,931)	137,871	(312,133)	(950,524)
Income tax benefit (expense)	(54,324)	(25,834)	(75,744)	(14,398)
Net income (loss)	(135,255)	112,037	(387,877)	(964,922)
Operating Segments [Member]
Costs and expenses:
Exploration	6,209	175	9,287	1,465
Depreciation, depletion, and amortization	106,340	84,447	280,251	215,906
Impairment of proved oil and natural gas properties	361,836	67,181	613,183	67,181
Accretion of asset retirement obligations	1,811	1,553	5,347	4,601
(Gain) loss on commodity derivative instruments	(370,055)	(189,492)	(531,838)	11,580
(Gain) loss on sale of properties			50	3,057
Other income (expense):
Interest expense, net	(40,431)	(36,345)	(116,528)	(104,928)
Loss on extinguishment of debt				(37,248)
Income tax benefit (expense)	(54,324)	(25,834)	(75,744)	(14,398)
Other, Adjustments & Eliminations [Member]
Other income (expense):
Earnings from equity investments	175	(86)	402	12,844
Total other income (expense)	175	(86)	402	12,844
Income (loss) before income taxes	175	(86)	402	12,844
Net income (loss)	175	(86)	402	12,844
MRD Segment [Member] | Operating Segments [Member]
Revenues:
Oil & natural gas sales	111,654	99,029	277,282	297,328
Other revenues		6		12
Total revenues	111,654	99,035	277,282	297,340
Costs and expenses:
Lease operating	7,949	4,333	17,025	12,361
Gathering, processing, and transportation	22,633	11,941	51,685	30,793
Gathering, processing, and transportation - affiliate (Note 13)	9,215		13,028
Exploration	4,068	133	7,024	1,213
Production and ad valorem taxes	2,751	2,987	8,666	9,141
Depreciation, depletion, and amortization	53,035	30,798	129,394	86,741
Incentive unit compensation expense	4,965	25,550	31,305	969,390
General and administrative	11,695	9,127	34,994	26,880
Accretion of asset retirement obligations	95	132	311	389
(Gain) loss on commodity derivative instruments	(125,167)	(33,090)	(202,894)	(17,130)
Total costs and expenses	(8,761)	51,911	90,588	1,122,835
(Gain) loss on sale of properties			50	3,057
Operating income (loss)	120,415	47,124	186,694	(825,495)
Other income (expense):
Interest expense, net	(9,176)	(9,887)	(28,545)	(44,355)
Earnings from equity investments	(175)	86	(402)	(12,844)
Other, net	(82)	15	(183)	102
Total other income (expense)	(9,433)	(9,786)	(29,130)	(94,345)
Loss on extinguishment of debt				(37,248)
Income (loss) before income taxes	110,982	37,338	157,564	(919,840)
Income tax benefit (expense)	(54,431)	(26,522)	(77,345)	(14,701)
Net income (loss)	56,551	10,816	80,219	(934,541)
MEMP [Member] | Operating Segments [Member]
Revenues:
Oil & natural gas sales	87,519	164,935	276,689	423,782
Other revenues	564	1,326	2,350	3,572
Total revenues	88,083	166,261	279,039	427,354
Costs and expenses:
Lease operating	45,416	41,878	130,782	99,526
Gathering, processing, and transportation	8,134	7,862	25,402	21,016
Pipeline operating	461	431	1,407	1,596
Exploration	2,141	42	2,263	252
Production and ad valorem taxes	6,896	11,053	19,609	24,482
Depreciation, depletion, and amortization	53,305	53,649	150,857	129,165
Impairment of proved oil and natural gas properties	361,836	67,181	613,183	67,181
General and administrative	13,910	12,069	42,798	34,181
Accretion of asset retirement obligations	1,716	1,421	5,036	4,212
(Gain) loss on commodity derivative instruments	(244,888)	(156,402)	(328,944)	28,710
Total costs and expenses	248,927	39,184	661,450	410,309
Other, net			(943)	(12)
Operating income (loss)	(160,844)	127,077	(382,411)	17,045
Other income (expense):
Interest expense, net	(31,255)	(26,458)	(87,983)	(60,573)
Other, net	11		295
Total other income (expense)	(31,244)	(26,458)	(87,688)	(60,573)
Income (loss) before income taxes	(192,088)	100,619	(470,099)	(43,528)
Income tax benefit (expense)	107	688	1,601	303
Net income (loss)	$ (191,981)	$ 101,307	$ (468,498)	$ (43,225)

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UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED AND COMBINED OPERATIONS - USD ($) shares in Thousands, $ in Thousands		3 Months Ended		9 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Revenues:
Oil & natural gas sales		$ 199,173	$ 263,964	$ 553,971	$ 721,110
Other revenues		564	1,332	2,350	3,584
Total revenues		199,737	265,296	556,321	724,694
Costs and expenses:
Lease operating		53,365	46,211	147,807	111,887
Gathering, processing, and transportation		30,767	19,803	77,087	51,809
Gathering, processing, and transportation - affiliate (Note 13)		9,215		13,028
Pipeline operating		461	431	1,407	1,596
Exploration		6,209	175	9,287	1,465
Production and ad valorem taxes		9,647	14,040	28,275	33,623
Depreciation, depletion, and amortization		106,340	84,447	280,251	215,906
Impairment of proved oil and natural gas properties		361,836	67,181	613,183	67,181
Incentive unit compensation expense (Note 12)		4,965	25,550	31,305	969,390
General and administrative		25,605	21,196	77,792	61,061
Accretion of asset retirement obligations		1,811	1,553	5,347	4,601
(Gain) loss on commodity derivative instruments		(370,055)	(189,492)	(531,838)	11,580
(Gain) loss on sale of properties				50	3,057
Other, net				(943)	(12)
Total costs and expenses		240,166	91,095	752,038	1,533,144
Operating income (loss)		(40,429)	174,201	(195,717)	(808,450)
Other income (expense):
Interest expense, net		(40,431)	(36,345)	(116,528)	(104,928)
Loss on extinguishment of debt					(37,248)
Other, net		(71)	15	112	102
Total other income (expense)		(40,502)	(36,330)	(116,416)	(142,074)
Income (loss) before income taxes		(80,931)	137,871	(312,133)	(950,524)
Income tax benefit (expense)		(54,324)	(25,834)	(75,744)	(14,398)
Net income (loss)		(135,255)	112,037	(387,877)	(964,922)
Net income (loss) attributable to noncontrolling interest		(191,807)	102,109	(466,471)	(34,851)
Net income (loss) attributable to Memorial Resource Development Corp.		56,552	9,928	78,594	(930,071)
Net (income) loss allocated to members					(20,305)
Net (income) loss allocated to previous owners					(1,425)
Net (income) allocated to participating restricted stockholders		(501)	(55)	(588)
Net income (loss) available to common stockholders		$ 56,051	$ 9,873	$ 78,006	$ (951,801)
Earnings per common share: (Note 10)
Basic		$ 0.29	$ 0.05	$ 0.41	$ (4.94)
Diluted	[1]	$ 0.29	$ 0.05	$ 0.41	$ (4.94)
Weighted average common and common equivalent shares outstanding:
Basic		190,725	192,500	190,353	192,500
Diluted		190,725	192,500	190,353	192,500

[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.

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Asset Retirement Obligations

9 Months Ended

Sep. 30, 2015

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

Note 6. Asset Retirement Obligations

Asset retirement obligations primarily relate to our portion of future plugging and abandonment costs for wells and related facilities. The following table presents the changes in the asset retirement obligations for the nine months ended September 30, 2015 (in thousands):

Asset retirement obligations at beginning of period	$	122,531
Liabilities added from acquisitions or drilling		1,565
Liabilities settled		(780	)
Revision of estimates		573
Liabilities removed upon sale of wells		(176	)
Accretion expense		5,347
Asset retirement obligations at end of period	$	129,060

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Risk Management and Derivative Instruments

9 Months Ended

Sep. 30, 2015

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Risk Management and Derivative Instruments

Note 5. Risk Management and Derivative Instruments

Derivative instruments are utilized to manage exposure to commodity price and interest rate fluctuations and achieve a more predictable cash flow in connection with natural gas and oil sales from production and borrowing related activities. These instruments limit exposure to declines in prices or increases in interest rates, but also limit the benefits that would be realized if prices increase or interest rates decrease.

Certain inherent business risks are associated with commodity and interest derivative contracts, including market risk and credit risk. Market risk is the risk that the price of natural gas or oil will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the counterparty to a contract. It is our policy to enter into derivative contracts, including interest rate swaps, only with creditworthy counterparties, which generally are financial institutions, deemed by management as competent and competitive market makers. Some of the lenders, or certain of their affiliates, under our credit agreements are counterparties to our derivative contracts. While collateral is generally not required to be posted by counterparties, credit risk associated with derivative instruments is minimized by limiting exposure to any single counterparty and entering into derivative instruments only with counterparties that are large financial institutions, which management believes present minimal credit risk. Additionally, master netting agreements are used to mitigate risk of loss due to default with counterparties on derivative instruments. We have also entered into the International Swaps and Derivatives Association Master Agreements (“ISDA Agreements”) with each of our counterparties. The terms of the ISDA Agreements provide us and each of our counterparties with rights of set-off upon the occurrence of defined acts of default by either us or our counterparty to a derivative, whereby the party not in default may set-off all liabilities owed to the defaulting party against all net derivative asset receivables from the defaulting party.

At September 30, 2015, MEMP had net derivative assets of $663.9 million. After taking into effect netting arrangements, MEMP had counterparty exposure of $345.9 million related to its derivative instruments of which $115.3 million was with a single counterparty. Had all counterparties failed completely to perform according to the terms of their existing contracts, MEMP would have the right to offset $320.3 million against amounts outstanding under its revolving credit facility at September 30, 2015. At September 30, 2015, MRD had net derivative assets of $343.6 million. After taking into effect netting arrangements, MRD had counterparty exposure of $277.9 million related to derivative instruments of which $91.4 million was with a single counterparty. Had all counterparties failed completely to perform according to the terms of their existing contracts, MRD would have the right to offset $65.7 million against amounts outstanding under its revolving credit facility at September 30, 2015. See Note 8 for additional information regarding our revolving credit facilities.

Commodity Derivatives

We may use a combination of commodity derivatives (e.g., floating-for-fixed swaps, put options, costless collars and basis swaps) to manage exposure to commodity price volatility. We recognize all derivative instruments at fair value; however, certain of our derivative instruments have a deferred premium. The deferred premium is factored into the fair value measurement and the Company agrees to defer the premium paid or received until the time of settlement. Cash settlements received on settled derivative positions during the nine months ended September 30, 2015 is net of deferred premiums of $7.1 million.

In February 2015, MEMP restructured a portion of its commodity derivative portfolio by effectively terminating “in-the-money” crude oil derivatives settling in 2015 through 2017 and entering into NGL derivatives with the same tenor. Cash settlement receipts of approximately $27.1 million from the termination of the crude oil derivatives were applied as premiums for the new NGL derivatives.

We enter into natural gas derivative contracts that are indexed to NYMEX-Henry Hub and regional indices such as NGPL TXOK, TETCO STX, TGT Z1, and Houston Ship Channel in proximity to our areas of production. We also enter into oil derivative contracts indexed to a variety of locations such as NYMEX-WTI, Inter-Continental Exchange (“ICE”) Brent, California Midway-Sunset and other regional locations. Our NGL derivative contracts are primarily indexed to OPIS Mont Belvieu.

At September 30, 2015, the MRD Segment had the following open commodity positions:

	Remaining
	2015			2016			2017			2018
Natural Gas Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (MMBtu)		3,400,000			2,570,000			1,770,000			4,600,000
Weighted-average fixed price	$	4.15		$	4.09		$	4.24		$	4.06
Collar contracts:
Average Monthly Volume (MMBtu)		130,000			1,100,000			1,050,000			—
Weighted-average floor price	$	4.00		$	4.00		$	4.00		$	—
Weighted-average ceiling price	$	4.64		$	4.71		$	5.06		$	—
Purchased put option contracts:
Average Monthly Volume (MMBtu)		4,100,000			6,000,000			5,350,000			3,450,000
Weighted-average strike price	$	3.75		$	3.51		$	3.48		$	3.62
Weighted-average deferred premium paid	$	(0.33	)	$	(0.34	)	$	(0.32	)	$	(0.34	)
Written call option contracts (1):
Average Monthly Volume (MMBtu)		3,225,000			—			—			—
Weighted-average sold strike price	$	3.75		$	—		$	—		$	—
Weighted-average deferred premium received	$	0.08		$	—		$	—		$	—
TGT Z1 basis swaps:
Average Monthly Volume (MMBtu)		3,380,000			1,120,000			200,000			—
Spread - Henry Hub	$	(0.10	)	$	(0.10	)	$	(0.08	)	$	—
Crude Oil Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		42,000			8,500			28,000			31,625
Weighted-average fixed price	$	91.67		$	84.80		$	84.70		$	84.50
Collar contracts:
Average Monthly Volume (Bbls)		2,000			27,000			—			—
Weighted-average floor price	$	85.00		$	80.00		$	—		$	—
Weighted-average ceiling price	$	101.35		$	99.70		$	—		$	—
Purchased put option contracts:
Average Monthly Volume (Bbls)		39,000			—			—			—
Weighted-average strike price	$	85.00		$	—		$	—		$	—
Weighted-average deferred premium paid	$	(3.80	)	$	—		$	—		$	—
Written call option contracts (1):
Average Monthly Volume (Bbls)		29,250			—			—			—
Weighted-average sold strike price	$	85.00		$	—		$	—		$	—
Weighted-average deferred premium received	$	0.48		$	—		$	—		$	—
NGL Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		163,000			185,658			—			—
Weighted-average fixed price	$	41.52		$	34.06		$	—		$	—

(1) These transactions were entered into for the purpose of creating a ceiling on our put options, which effectively converted the applicable puts into swaps.

At September 30, 2015, the MEMP Segment had the following open commodity positions:

	Remaining
	2015			2016			2017			2018			2019
Natural Gas Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (MMBtu)		3,359,237			3,592,442			3,350,067			3,060,000			2,814,583
Weighted-average fixed price	$	4.08		$	4.14		$	4.06		$	4.18		$	4.31
Collar contracts:
Average Monthly Volume (MMBtu)		350,000			—			—			—			—
Weighted-average floor price	$	4.62		$	—		$	—		$	—		$	—
Weighted-average ceiling price	$	5.80		$	—		$	—		$	—		$	—
Call spreads (1):
Average Monthly Volume (MMBtu)		80,000			—			—			—			—
Weighted-average sold strike price	$	5.25		$	—		$	—		$	—		$	—
Weighted-average bought strike price	$	6.75		$	—		$	—		$	—		$	—
Basis swaps:
Average Monthly Volume (MMBtu)		3,690,000			3,578,333			2,210,000			1,315,000			900,000
Spread	$	(0.12	)	$	(0.07	)	$	(0.04	)	$	(0.02	)	$	0.01
Crude Oil Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		272,531			279,813			301,600			312,000			160,000
Weighted-average fixed price	$	91.34		$	86.87		$	84.70		$	83.74		$	85.52
Collar contracts:
Average Monthly Volume (Bbls)		5,000			—			—			—			—
Weighted-average floor price	$	80.00		$	—		$	—		$	—		$	—
Weighted-average ceiling price	$	94.00		$	—		$	—		$	—		$	—
Basis swaps:
Average Monthly Volume (Bbls)		97,000			95,000			30,000			—			—
Spread	$	(7.06	)	$	(9.56	)	$	(2.35	)	$	—		$	—
NGL Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		209,200			213,100			43,300			—			—
Weighted-average fixed price	$	42.38		$	35.64		$	37.55		$	—		$	—

(1) These transactions were entered into for the purpose of eliminating the ceiling portion of certain collar arrangements, which effectively converted the applicable collars into swaps.

The MEMP Segment basis swaps included in the table above is presented on a disaggregated basis below:

	Remaining
	2015			2016			2017			2018			2019
Natural Gas Derivative Contracts:
NGPL TexOk basis swaps:
Average Monthly Volume (MMBtu)		3,030,000			3,003,333			1,800,000			1,200,000			900,000
Spread - Henry Hub	$	(0.11	)	$	(0.07	)	$	(0.07	)	$	(0.03	)	$	0.01
HSC basis swaps:
Average Monthly Volume (MMBtu)		150,000			135,000			115,000			115,000			—
Spread - Henry Hub	$	(0.08	)	$	0.07		$	0.14		$	0.15		$	—
CIG basis swaps:
Average Monthly Volume (MMBtu)		210,000			170,000			—			—			—
Spread - Henry Hub	$	(0.25	)	$	(0.30	)	$	—		$	—		$	—
TETCO STX basis swaps:
Average Monthly Volume (MMBtu)		300,000			270,000			295,000			—			—
Spread - Henry Hub	$	(0.09	)	$	0.06		$	0.03		$	—		$	—
Crude Oil Derivative Contracts:
Midway-Sunset basis swaps:
Average Monthly Volume (Bbls)		57,000			55,000			—			—			—
Spread - Brent	$	(9.73	)	$	(13.35	)	$	—		$	—		$	—
Midland basis swaps:
Average Monthly Volume (Bbls)		40,000			40,000			30,000			—			—
Spread - WTI	$	(3.25	)	$	(4.34	)	$	(2.35	)	$	—		$	—

Interest Rate Swaps

Periodically, we enter into interest rate swaps to mitigate exposure to market rate fluctuations by converting variable interest rates such as those in our credit agreements to fixed interest rates. From time to time we enter into offsetting positions to avoid being economically over-hedged. At September 30, 2015, we had the following interest rate swap open positions:

	Remaining
Credit Facility	2015			2016			2017			2018
MEMP:
Average Monthly Notional (in thousands)	$	400,000		$	400,000		$	400,000		$	100,000
Weighted-average fixed rate		0.943	%		0.943	%		1.612	%		1.946	%
Floating rate	1 Month LIBOR			1 Month LIBOR			1 Month LIBOR			1 Month LIBOR

Balance Sheet Presentation

The following table summarizes both: (i) the gross fair value of derivative instruments by the appropriate balance sheet classification even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the balance sheet and (ii) the net recorded fair value as reflected on the balance sheet at September 30, 2015 and December 31, 2014. There was no cash collateral received or pledged associated with our derivative instruments since most of the counterparties, or certain of their affiliates, to our derivative contracts are lenders under our collective credit agreements.

		Asset Derivatives						Liability Derivatives
		September 30,			December 31,			September 30,			December 31,
Type	Balance Sheet Location	2015			2014			2015			2014
		(In thousands)
Commodity contracts	Short-term derivative instruments	$	428,389		$	378,908		$	46,127		$	38,852
Interest rate swaps	Short-term derivative instruments		—			—			2,229			3,289
Gross fair value			428,389			378,908			48,356			42,141
Netting arrangements	Short-term derivative instruments		(44,841	)		(38,852	)		(44,841	)		(38,852	)
Net recorded fair value	Short-term derivative instruments	$	383,548		$	340,056		$	3,515		$	3,289
Commodity contracts	Long-term derivative instruments	$	666,846		$	466,851		$	36,402		$	32,787
Interest rate swaps	Long-term derivative instruments		—			1,305			3,131			—
Gross fair value			666,846			468,156			39,533			32,787
Netting arrangements	Long-term derivative instruments		(36,350	)		(32,787	)		(36,350	)		(32,787	)
Net recorded fair value	Long-term derivative instruments	$	630,496		$	435,369		$	3,183		$	—

(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 periods indicated (in thousands):

		For the Three Months Ended						For the Nine Months Ended
	Statements of	September 30,						September 30,
	Operations Location	2015			2014			2015			2014
Commodity derivative contracts	(Gain) loss on commodity derivatives	$	(370,055	)	$	(189,492	)	$	(531,838	)	$	11,580
Interest rate derivatives	Interest expense, net		3,543			(175	)		6,628			1,157

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Subsequent Events

9 Months Ended

Sep. 30, 2015

Subsequent Events [Abstract]

Subsequent Events

Note 17. Subsequent Events

MRD Purchase of Oil and Natural Gas Properties in Louisiana

For additional information, see Note 3.

MEMP Borrowing Base Redetermination

For additional information, see Note 8.

MEMP November 2015 Beta Acquisition

On November 3, 2015, MEMP completed an acquisition of the remaining interests in its oil and gas properties offshore Southern California (the “Beta properties”) from a third party for approximately $101.0 million, subject to customary post-closing adjustments.  

MEMP first acquired its interests in the Beta properties in December 2012.  The acquired interests primarily consist of the 48.25% remaining working interests in three Pacific Outer Continental Shelf blocks in the Beta Field, which includes 58 gross wells, that are located in federal waters approximately eleven miles offshore the Port of Long Beach, California.  The acquired interests also include the 48.25% remaining interest in associated facilities including (i) two combined production and drilling platforms (ii) one production processing platform, (iii) a 17.5 mile long 16-inch diameter oil pipeline and (iv) an onshore pump station, tankage and metering facility.  

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Related Party Transactions

9 Months Ended

Sep. 30, 2015

Related Party Transactions [Abstract]

Related Party Transactions

Note 13. Related Party Transactions

Amounts due to (due from) MRD Holdco and certain affiliates of NGP at September 30, 2015 and December 31, 2014 are presented as “Accounts receivable – affiliates” and “Accounts payable – affiliates” in the accompanying balance sheets.

NGP Affiliated Companies

During the three and nine months ended September 30, 2015, MRD paid approximately $4.8 million and $6.7 million, respectively to Cretic Energy Services, LLC, an NGP affiliated company, for services related to our drilling and completion activities.

During the three and nine months ended September 30, 2015, MRD paid approximately $1.0 million and $1.2 million, respectively to Multi-Shot, LLC, an NGP affiliated company, for services related to our drilling and completion activities.

NGPCIF NPI Acquisition

WildHorse Resources purchased a net profits interest from NGPCIF on February 28, 2014 for a purchase price of $63.4 million (see Note 1). This acquisition was accounted for as a combination of entities under common control at historical cost in a manner similar to the pooling of interest method. WildHorse Resources recorded the following net assets (in thousands):

Accounts receivable	$	2,274
Oil and natural gas properties, net		40,056
Accrued liabilities		(297	)
Asset retirement obligations		(277	)
Net assets	$	41,756

Due to common control considerations, the difference between the purchase price and the net assets acquired are reflected within equity as a deemed distribution to NGP affiliates.

Other Acquisitions or Dispositions

On March 10, 2014, BlueStone sold certain interests in oil and gas properties in McMullen, Webb, Zapata, and Hidalgo Counties located in South Texas to BlueStone Natural Resources II, LLC, an NGP controlled entity. Total cash consideration received by BlueStone was approximately $1.2 million, which exceeded the net book value of the properties sold by $0.5 million. Due to common control considerations, the $0.5 million was recognized in the equity statement as a contribution.

On March 28, 2014, our predecessor acquired certain interests in oil and gas properties in Gonzales and Karnes Counties located in South Texas from an NGP affiliated company for $3.3 million.

On June 18, 2014, in connection with our initial public offering and the related restructuring transactions, WHR Management Company was sold by WildHorse Resources to an affiliate of the Funds for net book value. The net book value of the assets sold was as follows (in thousands):

Cash and cash equivalents	$	33,001
Restricted cash		300
Accounts receivable		5,256
Prepaid expenses and other current assets		379
Property, plant and equipment, net		3,410
Other long-term assets		4
Accounts payable		(19,959	)
Accounts payable - affiliates		(17,099	)
Accrued liabilities		(5,061	)
Net assets	$	231

Related Party Agreements

We and certain of our affiliates have entered into various documents and agreements. These agreements have been negotiated among affiliated parties and, consequently, are not the result of arm’s-length negotiations.

Registration Rights Agreement

In connection with the closing of our initial public offering, we entered into a registration rights agreement with MRD Holdco and former management members of WildHorse Resources, Jay Graham (“Graham”) and Anthony Bahr (“Bahr”). Pursuant to the registration rights agreement, we have agreed to register the sale of shares of our common stock under certain circumstances.

Voting Agreement

In connection with the closing of our initial public offering, we entered into a voting agreement with MRD Holdco, WHR Incentive LLC, a limited liability company beneficially owned by Messrs. Bahr and Graham, and certain former management members of WildHorse Resources, who contributed their ownership of WildHorse Resources to us in the restructuring transactions. Among other things, the voting agreement provides that those former management members of WildHorse Resources will vote all of their shares of our common stock as directed by MRD Holdco.

Services Agreement

In connection with the closing of our initial public offering, we entered into a services agreement with WildHorse Resources and WildHorse Resource Management Company, LLC (“WHR Management Company”), pursuant to which WHR Management Company agreed to provide operating and administrative services to us for twelve months relating to the Terryville Complex. In exchange for such services, we paid a monthly management fee to WHR Management Company of approximately $1.0 million excluding third party COPAS income credits.

Upon the closing of our initial public offering, WHR Management Company became a subsidiary of WildHorse Resources II, LLC, an affiliate of the Company (“WHR II”). NGP and certain former management members of WildHorse Resources own WHR II.

The services agreement was terminated effective March 1, 2015.

WildHorse Management Services Agreement

A discussion of the WildHorse and WHR II management services and related agreements is included in our Recast Form 8-K. These agreements were terminated in connection with our initial public offering.

Midstream Agreements

On April 14, 2015, we, through our wholly-owned subsidiary, MRD Operating, entered into an amended and restated gas processing agreement (“GPA”) with PennTex North Louisiana Operating, LLC (“PennTex Operating”), a wholly-owned subsidiary of PennTex North Louisiana, LLC (“PennTex”). WildHorse Resources, which owned our interest in the Terryville Complex and merged into MRD Operating in February 2015, initially entered into a gas processing agreement with PennTex in March 2014, prior to our initial public offering. PennTex is a joint venture among certain affiliates of NGP in which MRD Midstream LLC, a wholly-owned subsidiary of MRD Holdco, owns a minority interest. Once PennTex Operating’s first processing plant became operational on June 1, 2015, it began to process natural gas produced from wells located on certain leases owned by us in the state of Louisiana. The GPA has a 15-year primary term, subject to one-year extensions at either party’s election. We pay PennTex Operating a monthly volume processing fee, subject to annual inflation escalators, based on volumes of natural gas processed by PennTex Operating. Once the first plant was declared operational, we became obligated to pay a minimum processing fee equal to approximately $18.3 million on an annual basis, subject to certain adjustments and conditions until the second processing plant was declared operational. Once the second plant was declared operational in October 2015, we became obligated to pay a minimum volume processing fee equal to approximately $55.0 million on an annual basis, subject to certain adjustments and conditions.

In addition, on April 14, 2015, we entered into (i) an amended and restated area of mutual interest and midstream exclusivity agreement (“AMI”) with PennTex NLA Holdings, LLC, which owns a majority interest in PennTex, MRD WHR LA Midstream LLC, an affiliate of MRD Holdco, and PennTex, (ii) a gas transportation agreement (“GTA”) with PennTex Operating, (iii) a gas gathering agreement (“GGA”) with PennTex Operating, and (iv) a transportation services agreement (“TSA” and, together with the GPA, AMI, GTA, and GGA, the “Midstream Agreements”) with PennTex Operating to provide gathering, residue gas and natural gas liquids transportation services to us in the state of Louisiana. The Midstream Agreements have a 15-year primary term, subject to one-year extensions at either party’s elections.

Under the GGA, once the first processing plant was declared operational, we began to pay PennTex Operating a commodity usage charge equal to at least the minimum volume commitment (115,000 MMBtu per day) times $0.02 per MMBtu until PennTex Operating’s second processing plant was declared operational. Once the second processing plant was declared operational, we became obligated to pay PennTex Operating a commodity usage charge equal to at least an increased minimum volume commitment (345,000 MMBtu per day) times $0.02 MMBtu through November 30, 2019. The minimum volume commitment will increase to 460,000 MMBtu on July 1, 2016 and may further increase subject to the terms of the GGA. Prior to December 1, 2019, PennTex Operating is also entitled to a payback demand fee from us equal to the monthly demand quantity (460,000 MMBtu per day) times a $0.03 MMBtu through November 30, 2019. Beginning on December 1, 2019, PennTex Operating is not entitled to a monthly demand charge, the commodity usage charge escalates to $0.05 per MMBtu, and PennTex Operating is entitled to receive a commodity usage charge from us equal to the minimum volume commitment (460,000 MMBtu per day through June 30, 2026, and 345,000 MMBtu per day thereafter) times $0.05 MMBtu.

Similarly, under the GTA which commences concurrently with the operational dates of the two processing plants, PennTex Operating will be entitled to a commodity usage charge of $0.04 per MMBtu for all volumes of residue gas produced on our behalf. Under the TSA, which commences concurrently with the operational dates of the two processing plants, PennTex Operating will be entitled to a commodity usage charge of $0.04 per gallon for all volumes of natural gas liquids produced on our behalf.

Under the AMI, we granted PennTex Operating the exclusive right to build all of our midstream infrastructure in northern Louisiana and to provide midstream services to support our current and future production on our operated acreage within such area (other than production subject to existing third-party commitments).

All net costs associated with these gas processing agreements are reflected in the statement of operations in the “Gathering processing, and transportation – affiliate” line.

Classic Pipeline Gas Gathering Agreement & Water Disposal Agreement

In November 2011, Classic Hydrocarbons Operating, LLC (“Classic Operating”), which became our wholly-owned subsidiary in connection with the restructuring transactions, and Classic Pipeline entered into a gas gathering agreement. Pursuant to the gas gathering agreement, Classic Operating dedicated to Classic Pipeline all of the natural gas produced (up to 50,000 MMBtus per day) on the properties operated by Classic Operating within certain counties in Texas through 2020, subject to one-year extensions at either party’s election. In May 2014, Classic Operating and Classic Pipeline amended the gas gathering agreement with respect to Classic Operating’s remaining assets located in Panola and Shelby Counties, Texas. Under the amended gas gathering agreement, Classic Operating agreed to pay a fee of (i) $0.30 per MMBtu, subject to an annual 3.5% inflationary escalation, based on volumes of natural gas delivered and processed, and (ii) $0.07 per MMBtu per stage of compression plus its allocated share of compressor fuel. The amended gas gathering agreement has a term until December 31, 2023, subject to one-year extensions at either party’s election.

In May 2014, Classic Operating and Classic Pipeline entered into a water disposal agreement. The water disposal agreement has a three-year term, subject to one-year extensions at either party’s election. Under the water disposal agreement, Classic Operating agreed to pay a fee of $1.10 per barrel for each barrel of water delivered to Classic Pipeline. Effective July 1, 2015, the fee was reduced to $0.40 per barrel for each barrel of water delivered to Classic Pipeline.

In February 2015, in connection with and as part of the Property Swap, Classic sold all of the equity interests owned by it in Classic Operating to Memorial Production Operating LLC, a wholly-owned subsidiary of MEMP, and Classic and Classic GP were merged into MRD Operating in March 2015.

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Condensed Consolidating Financial Information - Condensed Consolidating Balance Sheets (Detail) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014	Sep. 30, 2014	Dec. 31, 2013
Current assets:
Cash and cash equivalents	$ 7,363	$ 5,958	$ 10,316	$ 77,721
Accounts receivable - trade	135,988	131,576
Short-term derivative instruments	383,548	340,056
Prepaid expenses and other current assets	27,856	28,027
Total current assets	554,755	505,617
Property and equipment, net	3,295,548	3,537,656
Long-term derivative instruments	630,496	435,369
Other long-term assets	136,469	114,905
Total assets	4,617,268	4,593,547
Current liabilities:
Accounts payable and accrued liabilities	215,267	172,895
Accounts payable - affiliates	9,757	624
Revenues payable	70,380	57,352
Deferred tax liabilities	57,444	51,877
Short-term derivative instruments	3,515	3,289
Total current liabilities	356,363	286,037
Long-term debt	2,604,264	2,378,413
Asset retirement obligations	129,060	122,531
Long-term derivative instruments	3,183
Deferred tax liabilities	120,789	95,017
Other long-term liabilities	6,995	8,585
Total liabilities	3,220,654	2,890,583
Equity:
Equity	799,495	582,410
Noncontrolling interests	597,119	1,120,554
Total equity	1,396,614	1,702,964	1,458,999	858,132
Total liabilities and equity	4,617,268	4,593,547
Parent [Member]
Current assets:
Cash and cash equivalents	4,725	2,241	4,855
Accounts receivable - trade	6,890	5,995
Accounts receivable - affiliates	7,438	10,047
Short-term derivative instruments	152,208	131,471
Prepaid expenses and other current assets	4,995	5,833
Total current assets	176,256	155,587
Property and equipment, net	16,814	16,601
Long-term derivative instruments	191,426	123,567
Investments in subsidiaries	1,261,135	1,139,792
Other long-term assets	13,526	14,124
Total assets	1,659,157	1,449,671
Current liabilities:
Accounts payable and accrued liabilities	24,574	6,245
Revenues payable	80
Deferred tax liabilities	55,985
Total current liabilities	80,639	6,245
Long-term debt	726,000	783,000
Deferred tax liabilities	46,028	69,431
Other long-term liabilities	6,995	8,585
Total liabilities	859,662	867,261
Equity:
Equity	799,495	582,410
Total equity	799,495	582,410
Total liabilities and equity	1,659,157	1,449,671
Guarantor Subsidiaries [Member]
Current assets:
Cash and cash equivalents	2,107	3,762	5,688	48,619
Accounts receivable - trade	76,715	44,952
Prepaid expenses and other current assets	8,603	7,993
Total current assets	87,425	56,707
Property and equipment, net	1,371,384	1,050,722
Other long-term assets	21,285	5,660
Total assets	1,480,094	1,113,089
Current liabilities:
Accounts payable and accrued liabilities	86,766	56,598
Accounts payable - affiliates	14,376	3,638
Revenues payable	37,600	27,242
Deferred tax liabilities		50,470
Total current liabilities	138,742	137,948
Asset retirement obligations	8,316	9,830
Deferred tax liabilities	72,372
Total liabilities	219,430	147,778
Equity:
Equity	1,260,664	965,311
Total equity	1,260,664	965,311
Total liabilities and equity	1,480,094	1,113,089
Non-Guarantor Subsidiaries [Member]
Current assets:
Cash and cash equivalents	531	970	578	$ 29,102
Accounts receivable - trade	55,169	83,346
Accounts receivable - affiliates		28
Short-term derivative instruments	231,340	208,585
Prepaid expenses and other current assets	14,258	14,201
Total current assets	301,298	307,130
Property and equipment, net	1,907,350	2,470,333
Long-term derivative instruments	439,070	311,802
Other long-term assets	101,658	100,521
Total assets	2,749,376	3,189,786
Current liabilities:
Accounts payable and accrued liabilities	104,488	113,177
Accounts payable - affiliates	5,006	6,409
Revenues payable	32,700	30,110
Deferred tax liabilities	1,459	1,407
Short-term derivative instruments	3,515	3,289
Total current liabilities	147,168	154,392
Long-term debt	1,878,264	1,595,413
Asset retirement obligations	120,744	112,701
Long-term derivative instruments	3,183
Deferred tax liabilities	2,389	30,986
Total liabilities	2,151,748	1,893,492
Equity:
Equity	591,740	1,290,734
Noncontrolling interests	5,888	5,560
Total equity	597,628	1,296,294
Total liabilities and equity	2,749,376	3,189,786
Eliminations [Member]
Current assets:
Cash and cash equivalents		(1,015)	$ (805)
Accounts receivable - trade	(2,786)	(2,717)
Accounts receivable - affiliates	(7,438)	(10,075)
Total current assets	(10,224)	(13,807)
Investments in subsidiaries	(1,261,135)	(1,139,792)
Other long-term assets		(5,400)
Total assets	(1,271,359)	(1,158,999)
Current liabilities:
Accounts payable and accrued liabilities	(561)	(3,125)
Accounts payable - affiliates	(9,625)	(9,423)
Total current liabilities	(10,186)	(12,548)
Deferred tax liabilities		(5,400)
Total liabilities	(10,186)	(17,948)
Equity:
Equity	(1,852,404)	(2,256,045)
Noncontrolling interests	591,231	1,114,994
Total equity	(1,261,173)	(1,141,051)
Total liabilities and equity	$ (1,271,359)	$ (1,158,999)

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Stockholders' Equity and Noncontrolling Interests

9 Months Ended

Sep. 30, 2015

Equity [Abstract]

Stockholders' Equity and Noncontrolling Interests

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Note 9. Stockholders’ Equity and Noncontrolling Interests

Common Stock

The Company's authorized capital stock includes 600,000,000 shares of common stock, $0.01 par value per share. The following is a summary of the changes in our common shares issued for the nine months ended September 30, 2015:

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	(30,209	)
Balance September 30, 2015	205,318,103

(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. Restricted shares of common stock are considered issued and outstanding on the grant date of the restricted stock award.

On September 25, 2015, MRD 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 $238.4 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 as of September 30, 2015 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

MRD repurchased 2,764,887 shares of common stock under the December 2014 repurchase program for an aggregate price of $47.8 million through March 16, 2015, which exhausted the December 2014 repurchase program. MRD has retired all of the shares of common stock repurchased and the shares of common stock are no longer issued or outstanding.

In April 2015, the board of directors (“Board”) of the Company authorized the repurchase of up to $50.0 million of the Company’s outstanding common stock from time to time on the open market, through block trades or otherwise. The Company is not obligated to repurchase any dollar amount or specific number of shares of its common stock under the program, which may be suspended or discontinued at any time. The amount, timing and price of purchases will depend on market conditions and other factors. The Company did not repurchase any shares of common stock under this program through September 30, 2015.

Noncontrolling Interests

Noncontrolling interests is the portion of equity ownership in the Company’s consolidated subsidiaries not attributable to the Company and primarily consists of the equity interests held by: (i) the limited partners of MEMP and (ii) a third party investor in the San Pedro Bay Pipeline Company. Prior to our initial public offering, certain current or former key employees of certain of MRD LLC’s subsidiaries also held equity interests in those subsidiaries.

Distributions paid to the limited partners of MEMP primarily represent the quarterly cash distributions paid to MEMP’s unitholders, excluding those paid to MRD LLC prior to our initial public offering. Contributions received from limited partners of MEMP primarily represent net cash proceeds received from common unit offerings.

During the nine months ended September 30, 2015, MEMP repurchased 3,547,921 common units under its repurchase program for an aggregate price of $52.8 million. MEMP has retired all common units repurchased and those common units are no longer issued or outstanding.

On July 15, 2014, MEMP sold 9,890,000 common units representing limited partner interests in MEMP (including 1,290,000 common units sold pursuant to the full exercise of the underwriters’ option to purchase additional common units) to the underwriters at a negotiated price of $22.25 per unit generating total net proceeds of approximately $220.0 million after deducting offering expenses. The net proceeds from the equity offering were used to repay a portion of the outstanding borrowings under MEMP’s revolving credit facility.

On September 9, 2014, MEMP issued 14,950,000 common units representing limited partner interests in MEMP (including 1,950,000 common units sold pursuant to the full exercise of the underwriters’ option to purchase additional common units) to the public at an offering price of $22.29 per unit generating total net proceeds of approximately $321.3 million after deducting underwriting discounts and offering expenses. The net proceeds from the equity offering were used to repay a portion of the outstanding borrowings under MEMP’s revolving credit facility.

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Long Term Debt - Additional Information (Detail) - USD ($)	Sep. 18, 2015	Nov. 04, 2015	Sep. 30, 2015
MRD Segment [Member] | 2.0 Billion Revolving Credit Facility Due June 2019 [Member]
Debt Instrument [Line Items]
Borrowing base	$ 1,000,000,000		$ 1,000,000,000
Increase to Revolving Credit Facility	$ 1,050,000,000
MEMP [Member] | 2.0 Billion Revolving Credit Facility Due March 2018 [Member]
Debt Instrument [Line Items]
Borrowing base			$ 1,300,000,000
MEMP [Member] | 2.0 Billion Revolving Credit Facility Due March 2018 [Member] | Subsequent Event [Member]
Debt Instrument [Line Items]
Borrowing base		$ 1,180,000,000

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Restricted Investments

9 Months Ended

Sep. 30, 2015

Schedule Of Investments [Abstract]

Restricted Investments

Note 7. Restricted Investments

Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with offshore Southern California oil and gas properties owned by MEMP. The components of the restricted investment balance consisted of the following at the dates indicated:

	September 30,		December 31,
	2015		2014
	(In thousands)
BOEM platform abandonment (See Note 15)	$	73,488	$	69,954
BOEM lease bonds		794		794
SPBPC Collateral:
Contractual pipeline and surface facilities abandonment		3,060		2,701
California State Lands Commission pipeline right-of-way bond		3,005		3,005
City of Long Beach pipeline facility permit		500		500
Federal pipeline right-of-way bond		307		307
Port of Long Beach pipeline license		100		100
Restricted investments	$	81,254	$	77,361

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Long Term Debt

9 Months Ended

Sep. 30, 2015

Debt Disclosure [Abstract]

Long Term Debt

Note 8. Long Term Debt

The following table presents our consolidated debt obligations at the dates indicated:

	September 30,			December 31,
	2015			2014
	(In thousands)
MRD Segment:
MRD $2.0 billion revolving credit facility, variable-rate, due June 2019	$	126,000		$	183,000
5.875% senior unsecured notes, due July 2022 ("MRD Senior Notes") (1) (4)		600,000			600,000
Subtotal		726,000			783,000
MEMP Segment:
MEMP $2.0 billion revolving credit facility, variable-rate, due March 2018		696,000			412,000
7.625% senior unsecured notes, due May 2021 ("2021 Senior Notes") (2) (4)		700,000			700,000
6.875% senior unsecured notes, due August 2022 ("2022 Senior Notes") (3) (4)		496,990			500,000
Unamortized discounts		(14,726	)		(16,587	)
Subtotal		1,878,264			1,595,413
Total long-term debt	$	2,604,264		$	2,378,413

(1) The estimated fair value of this fixed-rate debt was $547.5 million and $534.0 million at September 30, 2015 and December 31, 2014, respectively.

(2) The estimated fair value of this fixed-rate debt was $469.0 million and $563.5 million at September 30, 2015 and December 31, 2014, respectively.

(3) The estimated fair value of this fixed-rate debt was $303.2 million and $380.0 million at September 30, 2015 and December 31, 2014, respectively.

(4) The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.

Borrowing Base

Credit facilities tied to borrowing bases are common throughout the oil and gas industry. Each of the revolving credit facilities’ borrowing base is subject to redetermination, on at least a semi-annual basis, primarily based on estimated proved reserves. The borrowing base for each credit facility was the following at the date indicated (in thousands):

	September 30,
	2015
MRD Segment:
MRD $2.0 billion revolving credit facility, variable-rate, due June 2019	$	1,000,000
MEMP Segment:
MEMP $2.0 billion revolving credit facility, variable-rate, due March 2018		1,300,000

On September 18, 2015, the borrowing base under the MRD revolving credit facility was increased to $1.0 billion in connection with the semi-annual borrowing base redetermination by the lenders, and can increase to $1.05 billion, subject to certain conditions, if MRD consummates a certain potential acquisition before December 31, 2015, as acknowledged by the parties in the fifth amendment to the revolving credit agreement.

Subsequent event. On November 4, 2015, MEMP’s borrowing base under its revolving credit facility was redetermined in connection with the semi-annual borrowing base redetermination by the lenders and decreased to approximately $1.18 billion.

Weighted-Average Interest Rates

The following table presents the weighted-average interest rates paid on our consolidated variable-rate debt obligations for the periods presented:

	For the Three Months Ended						For the Nine Months Ended
Credit Facility	September 30,						September 30,
	2015			2014			2015			2014
MRD Segment:
MRD revolving credit facility		1.94	%		2.62	%		1.86	%		2.15	%
WildHorse Resources revolver terminated June 2014	n/a			n/a			n/a				4.04	%
WildHorse Resources second lien terminated June 2014	n/a			n/a			n/a				6.44	%
MEMP Segment:
MEMP revolving credit facility		2.14	%		2.16	%		2.06	%		2.08	%

Unamortized Deferred Financing Costs

Unamortized deferred financing costs associated with our consolidated debt obligations were as follows at the dates indicated:

	September 30,		December 31,
	2015		2014
	(In thousands)
MRD Segment:
MRD revolving credit facility	$	5,264	$	4,285
MRD Senior Notes		11,355		12,455
MEMP Segment:
MEMP revolving credit facility		4,534		6,468
2021 Senior Notes		11,722		13,308
2022 Senior Notes		7,375		7,958
	$	40,250	$	44,474

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Earnings per Share

9 Months Ended

Sep. 30, 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 periods indicated (in thousands, except per share amounts):

	For the Three Months Ended				For the Nine Months Ended
	September 30,				September 30,
	2015		2014		2015		2014
Numerator:
Net income (loss) available to common stockholders	$	56,051	$	9,873	$	78,006	$	(951,801	)
Denominator:
Weighted average common shares outstanding		190,725		192,500		190,353		192,500
Incremental treasury stock method shares (1)		86		216		410		207
Basic EPS	$	0.29	$	0.05	$	0.41	$	(4.94	)
Diluted EPS (1)	$	0.29	$	0.05	$	0.41	$	(4.94	)

(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.

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Stockholders' Equity and Noncontrolling Interests - Summary of Changes In Common Shares Issued (Detail) - shares		9 Months Ended
	Sep. 25, 2015	Sep. 30, 2015
Class of Stock [Line Items]
Beginning Balance		193,435,414
Shares of common stock repurchased		0
Ending Balance		205,318,103
Common Stock [Member]
Class of Stock [Line Items]
Shares of common stock issued	13,800,000	13,800,000
Shares of common stock repurchased		(2,764,887)
Restricted common shares issued (Note 11)		938,558
Restricted common shares repurchased		(60,773)
Restricted common shares forfeited		(30,209)

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Condensed Consolidating Financial Information - Condensed Consolidating Statements of Operations (Detail) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Revenues:
Oil & natural gas sales	$ 199,173	$ 263,964	$ 553,971	$ 721,110
Other income	564	1,332	2,350	3,584
Total revenues	199,737	265,296	556,321	724,694
Costs and expenses:
Lease operating	53,365	46,211	147,807	111,887
Gathering, processing, and transportation	30,767	19,803	77,087	51,809
Gathering, processing and transportation - affiliate	9,215		13,028
Pipeline operating	461	431	1,407	1,596
Exploration	6,209	175	9,287	1,465
Production and ad valorem taxes	9,647	14,040	28,275	33,623
Depreciation, depletion, and amortization	106,340	84,447	280,251	215,906
Impairment of proved oil and natural gas properties	361,836	67,181	613,183	67,181
Incentive unit compensation expense	4,965	25,550	31,305	969,390
General and administrative	25,605	21,196	77,792	61,061
Accretion of asset retirement obligations	1,811	1,553	5,347	4,601
(Gain) loss on commodity derivatives	(370,055)	(189,492)	(531,838)	11,580
(Gain) loss on sale of properties			50	3,057
Other, net			(943)	(12)
Total costs and expenses	240,166	91,095	752,038	1,533,144
Operating income (loss)	(40,429)	174,201	(195,717)	(808,450)
Other income (expense):
Interest expense, net	(40,431)	(36,345)	(116,528)	(104,928)
Debt extinguishment costs				(37,248)
Other, net	(71)	15	112	102
Total other income (expense)	(40,502)	(36,330)	(116,416)	(142,074)
Income (loss) before income taxes	(80,931)	137,871	(312,133)	(950,524)
Income tax benefit (expense)	(54,324)	(25,834)	(75,744)	(14,398)
Net income (loss)	(135,255)	112,037	(387,877)	(964,922)
Net income (loss) attributable to noncontrolling interest	(191,807)	102,109	(466,471)	(34,851)
Net income (loss) attributable to Memorial Resource Development Corp.	56,552	9,928	78,594	(930,071)
Parent [Member]
Revenues:
Other income		6		5
Total revenues		6		5
Costs and expenses:
Depreciation, depletion, and amortization	1,087	168	3,139	168
Incentive unit compensation expense	4,965	25,550	31,305	137,307
General and administrative	11,327	7,215	32,656	7,390
Accretion of asset retirement obligations		1		1
(Gain) loss on commodity derivatives	(125,167)	(33,090)	(202,894)	(36,525)
Total costs and expenses	(107,788)	(156)	(135,794)	108,341
Operating income (loss)	107,788	162	135,794	(108,336)
Other income (expense):
Interest expense, net	(9,174)	(9,868)	(28,456)	(10,843)
Debt extinguishment costs				(23,562)
Equity earnings from subsidiaries	10,839	25,675	28,180	(811,093)
Other, net	(100)		(100)
Total other income (expense)	1,565	15,807	(376)	(845,498)
Income (loss) before income taxes	109,353	15,969	135,418	(953,834)
Income tax benefit (expense)	(52,801)	(6,041)	(56,824)	2,033
Net income (loss)	56,552	9,928	78,594	(951,801)
Net income (loss) attributable to Memorial Resource Development Corp.	56,552	9,928	78,594	(951,801)
Guarantor Subsidiaries [Member]
Revenues:
Oil & natural gas sales	111,654	99,026	277,282	297,325
Other income				7
Total revenues	111,654	99,026	277,282	297,332
Costs and expenses:
Lease operating	7,949	4,320	17,025	12,348
Gathering, processing, and transportation	22,633	11,941	51,685	30,793
Gathering, processing and transportation - affiliate	9,215		13,028
Exploration	4,068	133	7,024	1,213
Production and ad valorem taxes	2,751	2,987	8,666	9,141
Depreciation, depletion, and amortization	51,948	30,630	126,255	86,573
Incentive unit compensation expense				831,060
General and administrative	368	1,889	2,338	19,450
Accretion of asset retirement obligations	95	131	311	388
(Gain) loss on commodity derivatives				19,395
(Gain) loss on sale of properties			50	3,167
Total costs and expenses	99,027	52,031	226,382	1,013,528
Operating income (loss)	12,627	46,995	50,900	(716,196)
Other income (expense):
Interest expense, net	(2)	(19)	(89)	(33,512)
Debt extinguishment costs				(13,686)
Other, net	18	5	(83)	92
Total other income (expense)	16	(14)	(172)	(47,106)
Income (loss) before income taxes	12,643	46,981	50,728	(763,302)
Income tax benefit (expense)	(1,630)	(20,489)	(20,521)	(16,742)
Net income (loss)	11,013	26,492	30,207	(780,044)
Net income (loss) attributable to Memorial Resource Development Corp.	11,013	26,492	30,207	(780,044)
Non-Guarantor Subsidiaries [Member]
Revenues:
Oil & natural gas sales	87,519	164,938	276,689	423,785
Other income	564	1,326	2,350	3,572
Total revenues	88,083	166,264	279,039	427,357
Costs and expenses:
Lease operating	45,416	41,891	130,782	99,539
Gathering, processing, and transportation	8,134	7,862	25,402	21,016
Pipeline operating	461	431	1,407	1,596
Exploration	2,141	42	2,263	252
Production and ad valorem taxes	6,896	11,053	19,609	24,482
Depreciation, depletion, and amortization	53,305	53,649	150,857	129,165
Impairment of proved oil and natural gas properties	361,836	67,181	613,183	67,181
Incentive unit compensation expense				1,023
General and administrative	13,910	12,092	42,798	34,221
Accretion of asset retirement obligations	1,716	1,421	5,036	4,212
(Gain) loss on commodity derivatives	(244,888)	(156,402)	(328,944)	28,710
(Gain) loss on sale of properties				(110)
Other, net			(943)	(12)
Total costs and expenses	248,927	39,220	661,450	411,275
Operating income (loss)	(160,844)	127,044	(382,411)	16,082
Other income (expense):
Interest expense, net	(31,255)	(26,458)	(87,983)	(60,573)
Other, net	11	10	295	10
Total other income (expense)	(31,244)	(26,448)	(87,688)	(60,563)
Income (loss) before income taxes	(192,088)	100,596	(470,099)	(44,481)
Income tax benefit (expense)	107	696	1,601	311
Net income (loss)	(191,981)	101,292	(468,498)	(44,170)
Net income (loss) attributable to noncontrolling interest	104	52	328	95
Net income (loss) attributable to Memorial Resource Development Corp.	(192,085)	101,240	(468,826)	(44,265)
Eliminations [Member]
Other income (expense):
Equity earnings from subsidiaries	(10,839)	(25,675)	(28,180)	811,093
Total other income (expense)	(10,839)	(25,675)	(28,180)	811,093
Income (loss) before income taxes	(10,839)	(25,675)	(28,180)	811,093
Net income (loss)	(10,839)	(25,675)	(28,180)	811,093
Net income (loss) attributable to noncontrolling interest	(191,911)	102,057	(466,799)	(34,946)
Net income (loss) attributable to Memorial Resource Development Corp.	$ 181,072	$ (127,732)	$ 438,619	$ 846,039

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Earnings per Share - Summary of Calculation of Earnings (Loss) Per Share (Detail) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands		3 Months Ended		9 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Numerator:
Net income (loss) available to common stockholders		$ 56,051	$ 9,873	$ 78,006	$ (951,801)
Denominator:
Weighted average common shares outstanding		190,725	192,500	190,353	192,500
Incremental treasury stock method shares	[1]	86	216	410	207
Basic EPS		$ 0.29	$ 0.05	$ 0.41	$ (4.94)
Diluted EPS	[1]	$ 0.29	$ 0.05	$ 0.41	$ (4.94)

[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.

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Stockholders' Equity and Noncontrolling Interests - Additional Information (Detail) - USD ($)					9 Months Ended
	Sep. 25, 2015	Mar. 16, 2015	Sep. 09, 2014	Jul. 15, 2014	Sep. 30, 2015	Apr. 30, 2015	Dec. 31, 2014
Stockholders Equity Note Disclosure [Line Items]
Common stock, shares authorized					600,000,000		600,000,000
Common stock, par value					$ 0.01		$ 0.01
Net proceeds from issuance of common stock	$ 238,400,000
Payments for repurchase of common stock					$ 47,785,000
Stock repurchased and retired during period, shares					0
Stock repurchase program, authorized amount						$ 50,000,000
MEMP [Member]
Stockholders Equity Note Disclosure [Line Items]
Payments for repurchase of common stock					$ 53,999,000
MRD Segment [Member]
Stockholders Equity Note Disclosure [Line Items]
Payments for repurchase of common stock		$ 47,800,000
Stock repurchased and retired during period, shares		2,764,887
Common Stock [Member]
Stockholders Equity Note Disclosure [Line Items]
Shares of common stock issued	13,800,000				13,800,000
Payments for repurchase of common stock					$ 28,000
Stock repurchased and retired during period, shares					2,764,887
Common Stock [Member] | MEMP [Member]
Stockholders Equity Note Disclosure [Line Items]
Number of common units sold by subsidiary			14,950,000	9,890,000
Number of over-allotment common units issued by subsidiary			1,950,000	1,290,000
Public offering price per common unit			$ 22.29	$ 22.25
Net proceeds from sale of common units by subsidiary			$ 321,300,000	$ 220,000,000
Common Stock [Member] | Over-Allotment [Member]
Stockholders Equity Note Disclosure [Line Items]
Shares of common stock issued	1,800,000
Noncontrolling Interest [Member] | MEMP [Member]
Stockholders Equity Note Disclosure [Line Items]
Payments for repurchase of common stock					$ 53,999,000
Stock repurchased and retired during period, shares					3,547,921
Payments for repurchase of common units					$ 52,800,000

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Long-Term Incentive Plans (Tables)

9 Months Ended

Sep. 30, 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 Memorial Resource Development Corp. 2014 Long-Term Incentive Plan for the periods presented:

	Number of Shares			Weighted-Average Grant Date Fair Value per Share (1)
Restricted common shares outstanding at December 31, 2014		1,059,211		$	19.00
Granted (2)		938,558		$	18.80
Forfeited		(30,209	)	$	18.86
Vested		(274,355	)	$	19.00
Restricted common shares outstanding at September 30, 2015		1,693,205		$	18.89

(1) Determined by dividing the aggregate grant date fair value of awards issued.

(2) The aggregate grant date fair value of restricted common share awards issued in 2015 was $17.6 million based on a grant date market price ranging from $17.58 to $18.91 per share.

The following table summarizes information regarding restricted common unit awards granted under the Memorial Production Partners GP LLC Long-Term Incentive Plan for the periods presented:

	Number of Units			Weighted-Average Grant Date Fair Value per Unit (1)
Restricted common units outstanding at December 31, 2014		1,093,520		$	20.93
Granted (2)		815,607		$	15.04
Forfeited		(32,876	)	$	19.61
Vested		(483,627	)	$	20.37
Restricted common units outstanding at September 30, 2015		1,392,624		$	17.70

(1) Determined by dividing the aggregate grant date fair value of awards issued.

(2) The aggregate grant date fair value of restricted common unit awards issued in 2015 was $12.3 million based on a grant date market price ranging from $14.70 to $15.45 per unit.

Summary of Amount of Compensation Expense Recognized

The following table summarizes the amount of recognized compensation expense associated with these awards that are reflected in the accompanying statements of operations for the periods presented (in thousands):

For the Three Months Ended				For the Nine Months Ended
September 30,				September 30,
2015		2014		2015		2014
$	2,692	$	1,312	$	6,135	$	1,487

The following table summarizes the amount of recognized compensation expense associated with these awards that are reflected in the accompanying statements of operations for the periods presented (in thousands):

For the Three Months Ended				For the Nine Months Ended
September 30,				September 30,
2015		2014		2015		2014
$	2,993	$	2,427	$	7,899	$	5,387

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Risk Management and Derivative Instruments - Schedule of Entity's Interest Rate Swap Open Positions (Detail) - MEMP [Member] - Interest rate swaps [Member] $ in Thousands	9 Months Ended
	Sep. 30, 2015 USD ($)
2015 [Member]
Derivative [Line Items]
Average Monthly Notional	$ 400,000
Weighted-average fixed rate	0.943%
Floating rate	1 Month LIBOR
2016 [Member]
Derivative [Line Items]
Average Monthly Notional	$ 400,000
Weighted-average fixed rate	0.943%
Floating rate	1 Month LIBOR
2017 [Member]
Derivative [Line Items]
Average Monthly Notional	$ 400,000
Weighted-average fixed rate	1.612%
Floating rate	1 Month LIBOR
2018 [Member]
Derivative [Line Items]
Average Monthly Notional	$ 100,000
Weighted-average fixed rate	1.946%
Floating rate	1 Month LIBOR

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Commitments and Contingencies

9 Months Ended

Sep. 30, 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.

At September 30, 2015 and December 31, 2014, we had $0.6 million and $2.1 million of environmental reserves recorded on our balance sheets, respectively.

Midstream Agreements

See Note 13 for additional information.

Supplemental Bond for Decommissioning Liabilities Trust Agreement

In connection with its 2009 acquisition of the Beta properties, Rise Energy Operating, LLC (“REO”), a wholly-owned subsidiary of MEMP, assumed an obligation with the BOEM for the decommissioning of the offshore production facilities. The trust account is held by REO for the benefit of all working interest owners. The following is a summary of the gross held-to-maturity investments held in the trust account less the outside working interest owners share as of September 30, 2015 (in thousands):

	Amortized
Investment	Cost
U.S. Bank Money Market Cash Equivalent	$	142,005
Less: Outside working interest owners share		(68,517	)
	$	73,488

The trust account must maintain minimum balances attributable to REO’s net working interest as follows (in thousands):

June 30, 2016	$	76,590
December 31, 2016	$	78,660

As of September 30, 2015, the maximum remaining obligation net to REO’s interest was approximately $5.2 million.

Processing Plant Expansions by Third Party Gatherer

A discussion of processing plant expansions by a third party gatherer is included in our Recast Form 8-K.

Related Party Agreements

See Note 13 for additional information.

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Acquisitions and Divestitures (Tables)

9 Months Ended

Sep. 30, 2015

Business Combinations [Abstract]

Transaction-Related Costs

Transaction-related costs, which include costs associated with acquisitions and divestitures, are included in general and administrative expenses in the accompanying statements of operations for the periods indicated below (in thousands):

For the Three Months Ended				For the Nine Months Ended
September 30,				September 30,
2015		2014		2015		2014
$	229	$	1,425	$	3,232	$	5,480

Unaudited Pro Forma Results of Operations

The following unaudited pro forma combined results of operations are provided for the nine months ended September 30, 2014 as though the Wyoming Acquisition had been completed on January 1, 2013. The unaudited pro forma financial information was derived from the historical combined statements of operations of the Company and the previous owners and adjusted to include: (i) the revenues and direct operating expenses associated with oil and gas properties acquired, (ii) depletion expense applied to the adjusted basis of the properties acquired and (iii) interest expense on additional borrowings necessary to finance the acquisition. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of expected future results of operations.

	For the Nine Months Ended
	September 30,
	2014
MRD Consolidated and Combined	(In thousands)
Revenues	$	815,893
Net income (loss)		(930,903	)
Basic and diluted earnings per share	$	(4.94	)

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Risk Management and Derivative Instruments - Additional Information (Detail) - USD ($)	1 Months Ended	9 Months Ended
	Feb. 28, 2015	Sep. 30, 2015
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		$ 65,700,000
Effect netting arrangements, counterparty exposure		277,900,000
Derivative asset		343,600,000
Deferred premiums		7,100,000
Cash collateral received or pledged		0
MEMP [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Conditional rights of set-off under ISDA Master Agreement reduce the maximum amount of loss due to credit risk		320,300,000
Effect netting arrangements, counterparty exposure		345,900,000
Derivative asset		663,900,000
Cash settlement receipt	$ 27,100,000
MEMP [Member] | Single Counterparty [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Effect netting arrangements, counterparty exposure		115,300,000
MRD [Member] | Single Counterparty [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Effect netting arrangements, counterparty exposure		$ 91,400,000

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Summary of Significant Accounting Policies - Schedule of Accrued Liabilities (Detail) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Accounting Policies [Abstract]
Accrued capital expenditures	$ 84,698	$ 80,350
Accrued lease operating expense	18,495	16,403
Accrued general and administrative expenses	14,035	8,516
Accrued ad valorem taxes	15,010	8,870
Accrued interest payable	36,810	24,797
Accrued income tax payable	4,942	52
Accrued environmental	588	2,092
Other miscellaneous, including operator advances	2,021	6,043
Accrued liabilities	$ 176,599	$ 147,123

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UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED AND COMBINED CASH FLOWS - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Cash flows from operating activities:
Net income (loss)	$ (387,877)	$ (964,922)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization	280,251	215,906
Impairment of proved oil and natural gas properties	613,183	67,181
(Gain) loss on derivatives	(525,210)	12,737
Cash settlements (paid) received on expired derivative instruments	290,001	(22,174)
Cash settlements on terminated derivatives	27,063
Premiums paid for derivatives	(27,063)
Loss on extinguishment of debt		30,248
Amortization of deferred financing costs	6,426	5,492
Accretion of senior notes net discount	1,818	1,888
Accretion of asset retirement obligations	5,347	4,601
Amortization of equity awards	14,034	6,874
Settlement of asset retirement obligations	(780)
(Gain) loss on sale of properties	50	3,057
Non-cash compensation expense	31,305	941,659
Deferred income tax expense (benefit)	68,798	13,916
Changes in operating assets and liabilities:
Accounts receivable	13,759	(22,117)
Prepaid expenses and other assets	4,134	297
Payables and accrued liabilities	22,391	67,324
Other	789	3,493
Net cash provided by operating activities	438,419	365,460
Cash flows from investing activities:
Acquisitions of oil and natural gas properties	(13,362)	(1,083,167)
Acquisition post-closing adjustment receipts	9,570
Additions to oil and gas properties	(634,317)	(457,838)
Additions to other property and equipment	(3,768)	(9,134)
Additions to restricted investments	(3,893)	(2,883)
Deposits for property acquisitions	(21,286)
Decrease (increase) in restricted cash		49,946
Proceeds from the sale of oil and natural gas properties	13,612	6,700
Other		(301)
Net cash used in investing activities	(653,444)	(1,496,677)
Cash flows from financing activities:
Advances on revolving credit facilities	748,000	2,464,800
Payments on revolving credit facilities	(521,000)	(2,441,900)
Termination of second lien credit facility		(328,282)
Proceeds from the issuance of senior notes		1,092,425
Redemption of senior notes	(2,914)	(351,808)
Deferred financing costs	(1,765)	(30,284)
Purchase of additional interests in consolidated subsidiaries		(3,292)
Costs incurred in conjunction with equity offering		(28,198)
Distributions to noncontrolling interests	(138,123)	(101,327)
Repurchased shares under repurchase program	(106,669)
Other		213
Net cash provided by financing activities	216,430	1,063,812
Net change in cash and cash equivalents	1,405	(67,405)
Cash and cash equivalents, beginning of period	5,958	77,721
Cash and cash equivalents, end of period	7,363	10,316
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)
MRD Segment [Member]
Cash flows from financing activities:
Proceeds from MRD equity offering	242,880	408,500
Costs incurred in conjunction with equity offering	(3,979)	(28,198)
Repurchased shares under repurchase program	(51,197)
MEMP [Member]
Cash flows from financing activities:
Costs incurred in conjunction with equity offering		(12,222)
Proceeds from MEMP equity offering		$ 553,288
Repurchased shares under repurchase program	$ (55,472)

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Fair Value Measurements of Financial Instruments

9 Months Ended

Sep. 30, 2015

Fair Value Disclosures [Abstract]

Fair Value Measurements of Financial Instruments

Note 4. Fair Value Measurements of Financial Instruments

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. Fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk. A three-tier hierarchy has been established that classifies fair value amounts recognized or disclosed in the financial statements. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3). All of the derivative instruments reflected on the accompanying balance sheets were considered Level 2.

The carrying values of accounts receivables, accounts payables (including accrued liabilities), restricted investments and amounts outstanding under long-term debt agreements with variable rates included in the accompanying balance sheets approximated fair value at September 30, 2015 and December 31, 2014. The fair value estimates are based upon observable market data and are classified within Level 2 of the fair value hierarchy. These assets and liabilities are not presented in the following tables. See Note 8 for the estimated fair value of our outstanding fixed-rate debt.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The fair market values of the derivative financial instruments reflected on the balance sheets as of September 30, 2015 and December 31, 2014 were based on estimated forward commodity prices (including nonperformance risk) and forward interest rate yield curves. Nonperformance risk is the risk that the obligation related to the derivative instrument will not be fulfilled. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement in its entirety. The significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

The following table presents the gross derivative assets and liabilities that are measured at fair value on a recurring basis at September 30, 2015 and December 31, 2014 for each of the fair value hierarchy levels:

	Fair Value Measurements at September 30, 2015 Using
	Quoted Prices in		Significant Other		Significant
	Active		Observable		Unobservable
	Market		Inputs		Inputs
	(Level 1)		(Level 2)		(Level 3)		Fair Value
	(In thousands)
Assets:
Commodity derivatives	$	—	$	1,095,235	$	—	$	1,095,235
Interest rate derivatives		—		—		—		—
Total assets	$	—	$	1,095,235	$	—	$	1,095,235
Liabilities:
Commodity derivatives	$	—	$	82,529	$	—	$	82,529
Interest rate derivatives		—		5,360		—		5,360
Total liabilities	$	—	$	87,889	$	—	$	87,889

	Fair Value Measurements at December 31, 2014 Using
	Quoted Prices in		Significant Other		Significant
	Active		Observable		Unobservable
	Market		Inputs		Inputs
	(Level 1)		(Level 2)		(Level 3)		Fair Value
	(In thousands)
Assets:
Commodity derivatives	$	—	$	845,759	$	—	$	845,759
Interest rate derivatives		—		1,305		—		1,305
Total assets	$	—	$	847,064	$	—	$	847,064
Liabilities:
Commodity derivatives	$	—	$	71,639	$	—	$	71,639
Interest rate derivatives		—		3,289		—		3,289
Total liabilities	$	—	$	74,928	$	—	$	74,928

See Note 5 for additional information regarding our derivative instruments.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Certain assets and liabilities are reported at fair value on a nonrecurring basis as reflected on the balance sheets. The following methods and assumptions are used to estimate the fair values:

· The fair value of asset retirement obligations (“AROs”) is based on discounted cash flow projections using numerous estimates, assumptions, and judgments regarding factors such as the existence of a legal obligation for an ARO; amounts and timing of settlements; the credit-adjusted risk-free rate; and inflation rates. See Note 6 for a summary of changes in AROs.

·  If sufficient market data is not available, the determination of the fair values of proved and unproved properties acquired in transactions accounted for as business combinations are prepared by utilizing estimates of discounted cash flow projections. The factors to determine fair value include, but are not limited to, estimates of: (i) economic reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital.

· Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such properties. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and natural gas properties.

· During the three and nine months ended September 30, 2015, MEMP recognized $361.8 million and $613.2 million, respectively, of impairments related to certain properties located in East Texas, South Texas, the Permian, Wyoming and Colorado. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable primarily as a result of declining commodity prices. As a result of the impairments, the carrying value of these properties was reduced to approximately $407.7 million. MEMP recorded $67.2 million of impairments during the three and nine months ended September 30, 2014 primarily related to certain properties located in South Texas. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable in part due to a downward revision of estimated proved reserves based on declining commodity prices and increased operating costs .

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Long Term Debt - Borrowing Base Credit Facility (Detail) - USD ($) $ in Thousands	Sep. 30, 2015	Sep. 18, 2015
MRD Segment [Member] | 2.0 Billion Revolving Credit Facility Due June 2019 [Member]
Line Of Credit Facility [Line Items]
Borrowing base	$ 1,000,000	$ 1,000,000
MEMP [Member] | 2.0 Billion Revolving Credit Facility Due March 2018 [Member]
Line Of Credit Facility [Line Items]
Borrowing base	$ 1,300,000

XML

Commitments and Contingencies - Gross Held-to-Maturity Investments (Detail) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Held-to-maturity Securities [Abstract]
Less: Outside working interest owners share, Amortized Cost	$ (68,517)
Restricted investments	81,254	$ 77,361
BOEM platform abandonment [Member]
Held-to-maturity Securities [Abstract]
Restricted investments	73,488	$ 69,954
Money Market Funds [Member]
Held-to-maturity Securities [Abstract]
Amortized Cost	$ 142,005

XML

Long-Term Incentive Plans - Summary of Amount of Compensation Expense Recognized (Detail) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Amortization of equity awards	$ 10,650	$ 29,289	$ 45,339	$ 976,264
MEMP [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Amortization of equity awards	2,993	2,427	7,899	5,387
Restricted Stock [Member] | MRD Segment [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Amortization of equity awards	$ 2,692	$ 1,312	$ 6,135	$ 1,487

XML

Fair Value Measurements of Financial Instruments (Tables)

9 Months Ended

Sep. 30, 2015

Fair Value Disclosures [Abstract]

Assets and Liabilities Measured at Fair Value on Recurring Basis

The following table presents the gross derivative assets and liabilities that are measured at fair value on a recurring basis at September 30, 2015 and December 31, 2014 for each of the fair value hierarchy levels:

	Fair Value Measurements at September 30, 2015 Using
	Quoted Prices in		Significant Other		Significant
	Active		Observable		Unobservable
	Market		Inputs		Inputs
	(Level 1)		(Level 2)		(Level 3)		Fair Value
	(In thousands)
Assets:
Commodity derivatives	$	—	$	1,095,235	$	—	$	1,095,235
Interest rate derivatives		—		—		—		—
Total assets	$	—	$	1,095,235	$	—	$	1,095,235
Liabilities:
Commodity derivatives	$	—	$	82,529	$	—	$	82,529
Interest rate derivatives		—		5,360		—		5,360
Total liabilities	$	—	$	87,889	$	—	$	87,889

	Fair Value Measurements at December 31, 2014 Using
	Quoted Prices in		Significant Other		Significant
	Active		Observable		Unobservable
	Market		Inputs		Inputs
	(Level 1)		(Level 2)		(Level 3)		Fair Value
	(In thousands)
Assets:
Commodity derivatives	$	—	$	845,759	$	—	$	845,759
Interest rate derivatives		—		1,305		—		1,305
Total assets	$	—	$	847,064	$	—	$	847,064
Liabilities:
Commodity derivatives	$	—	$	71,639	$	—	$	71,639
Interest rate derivatives		—		3,289		—		3,289
Total liabilities	$	—	$	74,928	$	—	$	74,928

XML

Related Party Transactions - Schedule of Net Assets Recorded (Detail) - WildHorse Resources, LLC [Member] - NGPCIF [Member] - Acquisitions [Member] $ in Thousands	Feb. 28, 2014 USD ($)
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

XML

Commitments and Contingencies (Tables)

9 Months Ended

Sep. 30, 2015

Commitments And Contingencies Disclosure [Abstract]

Gross Held-to-Maturity Investments

The following is a summary of the gross held-to-maturity investments held in the trust account less the outside working interest owners share as of September 30, 2015 (in thousands):

	Amortized
Investment	Cost
U.S. Bank Money Market Cash Equivalent	$	142,005
Less: Outside working interest owners share		(68,517	)
	$	73,488

Minimum Balances Attributable to Net Working Interest

The trust account must maintain minimum balances attributable to REO’s net working interest as follows (in thousands):

June 30, 2016	$	76,590
December 31, 2016	$	78,660

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Business Segment Data

9 Months Ended

Sep. 30, 2015

Segment Reporting [Abstract]

Business Segment Data

Note 14. Business Segment Data

Our reportable business segments are organized in a manner that reflects how management manages those business activities.

We have two reportable business segments, both of which are engaged in the acquisition, exploration and development of oil and natural gas properties. Our reportable business segments are as follows:

· MRD—reflects the combined operations of the Company and its consolidating subsidiaries except for MEMP and its subsidiaries.

· MEMP—reflects the combined operations of MEMP and its subsidiaries.

We evaluate segment performance based on Adjusted EBITDA. Adjusted EBITDA is defined as net income (loss), plus interest expense; loss on extinguishment of debt; income tax expense; depreciation, depletion and amortization (“DD&A”); impairment of goodwill and long-lived properties; accretion of asset retirement obligations (“AROs”); losses on commodity derivative contracts and cash settlements received; losses on sale of properties; incentive-based compensation expenses; exploration costs; provision for environmental remediation; equity loss from MEMP (MRD Segment only); cash distributions from MEMP (MRD Segment only); transaction related costs; amortization of investment premium; and other non-routine items, less interest income; income tax benefit; gains on commodity derivative contracts and cash settlements paid on expired positions; equity income from MEMP (MRD Segment only); gains on sale of assets and other non-routine items.

Financial information presented for the MEMP business segment is derived from the underlying consolidated and combined financial statements of MEMP that are publicly available.

Segment revenues and expenses include intersegment transactions. Our consolidated totals reflect the elimination of intersegment transactions.

In the MRD Segment’s individual financial statements, investments in the MEMP Segment that are included in the consolidated and combined financial statements are accounted for by the equity method.

The following table presents selected business segment information for the periods indicated (in thousands):

					Other,			Consolidated
					Adjustments &			& Combined
	MRD		MEMP		Eliminations			Totals
Total revenues:
Three Months Ended September 30, 2015	$	111,654	$	88,083	$	—		$	199,737
Three Months Ended September 30, 2014		99,035		166,261		—			265,296
Nine Months Ended September 30, 2015		277,282		279,039		—			556,321
Nine Months Ended September 30, 2014		297,340		427,354		—			724,694
Adjusted EBITDA: (1)
Three Months Ended September 30, 2015		104,319		80,766		(75	)		185,010
Three Months Ended September 30, 2014		76,237		97,196		(64	)		173,369
Nine Months Ended September 30, 2015		273,980		250,073		(226	)		523,827
Nine Months Ended September 30, 2014		222,460		243,717		(6,068	)		460,109
Segment assets: (2)
As of September 30, 2015		1,871,270		2,749,376		(3,378	)		4,617,268
As of December 31, 2014		1,413,768		3,189,760		(9,981	)		4,593,547
Total cash expenditures for additions to long-lived assets:
Nine Months Ended September 30, 2015		449,297		202,150		—			651,447
Nine Months Ended September 30, 2014		249,324		1,300,815		—			1,550,139

(1) Adjustments and eliminations for the three and nine months ended September 30, 2015 and 2014 include cash distributions that MEMP paid to MRD during the three and nine months ended September 30, 2015 and 2014, related to the ownership of partnership interests in MEMP. In 2014, MRD LLC owned MEMP subordinated units, which were distributed to MRD Holdco in connection with the Company’s initial public offering in June 2014.

(2) As of September 30, 2015, adjustments and eliminations primarily represent the elimination of accounts receivable and accounts payable balances between the MRD Segment and the MEMP Segment.

Calculation of Reportable Segments’ Adjusted EBITDA

	For the Three Months Ended
	September 30, 2015
							Combined
	MRD			MEMP			Totals
	(In thousands)
Net income (loss)	$	56,551		$	(191,981	)	$	(135,430	)
Interest expense, net		9,176			31,255			40,431
Income tax expense (benefit)		54,431			(107	)		54,324
DD&A		53,035			53,305			106,340
Impairment of proved oil and natural gas properties		—			361,836			361,836
Accretion of AROs		95			1,716			1,811
(Gain) loss on commodity derivative instruments		(125,167	)		(244,888	)		(370,055	)
Cash settlements received (paid) on expired commodity derivative instruments		44,010			64,480			108,490
Transaction related costs		213			16			229
Incentive-based compensation expense		7,657			2,993			10,650
Exploration costs		4,068			2,141			6,209
Non-cash equity (income) loss from MEMP		175			—			175
Cash distributions from MEMP		75			—			75
Adjusted EBITDA	$	104,319		$	80,766		$	185,085

	For the Three Months Ended
	September 30, 2014
							Combined
	MRD			MEMP			Totals
	(In thousands)
Net income (loss)	$	10,816		$	101,307		$	112,123
Interest expense, net		9,887			26,458			36,345
Income tax expense (benefit)		26,522			(688	)		25,834
DD&A		30,798			53,649			84,447
Impairment of proved oil and natural gas properties		—			67,181			67,181
Accretion of AROs		132			1,421			1,553
(Gain) loss on commodity derivative instruments		(33,090	)		(156,402	)		(189,492	)
Cash settlements received (paid) on expired commodity derivative instruments		3,699			876			4,575
Transaction related costs		500			925			1,425
Incentive-based compensation expense		26,862			2,427			29,289
Exploration costs		133			42			175
Non-cash equity (income) loss from MEMP		(86	)		—			(86	)
Cash distributions from MEMP		64			—			64
Adjusted EBITDA	$	76,237		$	97,196		$	173,433

	For the Nine Months Ended
	September 30, 2015
							Combined
	MRD			MEMP			Totals
	(In thousands)
Net income (loss)	$	80,219		$	(468,498	)	$	(388,279	)
Interest expense, net		28,545			87,983			116,528
Income tax expense (benefit)		77,345			(1,601	)		75,744
DD&A		129,394			150,857			280,251
Impairment of proved oil and natural gas properties		—			613,183			613,183
Accretion of AROs		311			5,036			5,347
(Gain) loss on commodity derivative instruments		(202,894	)		(328,944	)		(531,838	)
Cash settlements received (paid) on expired commodity derivative instruments		114,298			178,955			293,253
(Gain) loss on sale of properties		50			—			50
Transaction related costs		1,620			1,612			3,232
Incentive-based compensation expense		37,440			7,899			45,339
Exploration costs		7,024			2,263			9,287
Loss on settlement of AROs		—			1,328			1,328
Non-cash equity (income) loss from MEMP		402			—			402
Cash distributions from MEMP		226			—			226
Adjusted EBITDA	$	273,980		$	250,073		$	524,053

	For the Nine Months Ended
	September 30, 2014
							Combined
	MRD			MEMP			Totals
	(In thousands)
Net income (loss)	$	(934,541	)	$	(43,225	)	$	(977,766	)
Interest expense, net		44,355			60,573			104,928
Loss on debt extinguishment		37,248			—			37,248
Income tax expense (benefit)		14,701			(303	)		14,398
DD&A		86,741			129,165			215,906
Impairment of proved oil and natural gas properties		—			67,181			67,181
Accretion of AROs		389			4,212			4,601
(Gain) loss on commodity derivative instruments		(17,130	)		28,710			11,580
Cash settlements received (paid) on expired commodity derivative instruments		(4,930	)		(14,999	)		(19,929	)
(Gain) loss on sale of properties		3,057			—			3,057
Transaction related costs		1,568			3,912			5,480
Incentive-based compensation expense		970,877			5,387			976,264
Exploration costs		1,213			252			1,465
Non-cash equity (income) loss from MEMP		12,844			—			12,844
Provision for environmental remediation		—			2,852			2,852
Cash distributions from MEMP		6,068			—			6,068
Adjusted EBITDA	$	222,460		$	243,717		$	466,177

The following table presents a reconciliation of total reportable segments’ Adjusted EBITDA to net income (loss) for each of the periods indicated (in thousands).

	For the Three Months Ended						For the Nine Months Ended
	September 30,						September 30,
	2015			2014			2015			2014
Total Reportable Segments' Adjusted EBITDA	$	185,085		$	173,433		$	524,053		$	466,177
Adjustments to reconcile Adjusted EBITDA to net income (loss):
Interest expense, net		(40,431	)		(36,345	)		(116,528	)		(104,928	)
Loss on debt extinguishment		—			—			—			(37,248	)
Income tax benefit (expense)		(54,324	)		(25,834	)		(75,744	)		(14,398	)
DD&A		(106,340	)		(84,447	)		(280,251	)		(215,906	)
Impairment of proved oil and natural gas properties		(361,836	)		(67,181	)		(613,183	)		(67,181	)
Accretion of AROs		(1,811	)		(1,553	)		(5,347	)		(4,601	)
Gains (losses) on commodity derivative instruments		370,055			189,492			531,838			(11,580	)
Cash settlements paid (received) on expired commodity derivative instruments		(108,490	)		(4,575	)		(293,253	)		19,929
Gain (loss) on sale of properties		—			—			(50	)		(3,057	)
Transaction related costs		(229	)		(1,425	)		(3,232	)		(5,480	)
Incentive-based compensation expense		(10,650	)		(29,289	)		(45,339	)		(976,264	)
Exploration costs		(6,209	)		(175	)		(9,287	)		(1,465	)
Provision for environmental remediation		—			—			—			(2,852	)
Loss on settlement of AROs		—			—			(1,328	)		—
Cash distributions from MEMP		(75	)		(64	)		(226	)		(6,068	)
Net income (loss)	$	(135,255	)	$	112,037		$	(387,877	)	$	(964,922	)

Included below is our consolidated and combined statement of operations disaggregated by reportable segment for the period indicated (in thousands):

	Three Months Ended September 30, 2015
	MRD			MEMP			Other, Adjustments & Eliminations		Consolidated
Revenues:
Oil & natural gas sales	$	111,654		$	87,519		$	—	$	199,173
Other revenues		—			564			—		564
Total revenues		111,654			88,083			—		199,737
Costs and expenses:
Lease operating		7,949			45,416			—		53,365
Gathering, processing, and transportation		22,633			8,134			—		30,767
Gathering, processing, and transportation - affiliate		9,215			—			—		9,215
Pipeline operating		—			461			—		461
Exploration		4,068			2,141			—		6,209
Production and ad valorem taxes		2,751			6,896			—		9,647
Depreciation, depletion, and amortization		53,035			53,305			—		106,340
Impairment of proved oil and natural gas properties		—			361,836			—		361,836
Incentive unit compensation expense		4,965			—			—		4,965
General and administrative		11,695			13,910			—		25,605
Accretion of asset retirement obligations		95			1,716			—		1,811
(Gain) loss on commodity derivative instruments		(125,167	)		(244,888	)		—		(370,055	)
Total costs and expenses		(8,761	)		248,927			—		240,166
Operating income (loss)		120,415			(160,844	)		—		(40,429	)
Other income (expense):
Interest expense, net		(9,176	)		(31,255	)		—		(40,431	)
Earnings from equity investments		(175	)		—			175		—
Other, net		(82	)		11			—		(71	)
Total other income (expense)		(9,433	)		(31,244	)		175		(40,502	)
Income (loss) before income taxes		110,982			(192,088	)		175		(80,931	)
Income tax benefit (expense)		(54,431	)		107			—		(54,324	)
Net income (loss)	$	56,551		$	(191,981	)	$	175	$	(135,255	)

	Three Months Ended September 30, 2014
	MRD			MEMP			Other, Adjustments & Eliminations			Consolidated
Revenues:
Oil & natural gas sales	$	99,029		$	164,935		$	—		$	263,964
Other revenues		6			1,326			—			1,332
Total revenues		99,035			166,261			—			265,296
Costs and expenses:
Lease operating		4,333			41,878			—			46,211
Gathering, processing, and transportation		11,941			7,862			—			19,803
Pipeline operating		—			431			—			431
Exploration		133			42			—			175
Production and ad valorem taxes		2,987			11,053			—			14,040
Depreciation, depletion, and amortization		30,798			53,649			—			84,447
Impairment of proved oil and natural gas properties		—			67,181			—			67,181
Incentive unit compensation expense		25,550			—			—			25,550
General and administrative		9,127			12,069			—			21,196
Accretion of asset retirement obligations		132			1,421			—			1,553
(Gain) loss on commodity derivative instruments		(33,090	)		(156,402	)		—			(189,492	)
Total costs and expenses		51,911			39,184			—			91,095
Operating income (loss)		47,124			127,077			—			174,201
Other income (expense):
Interest expense, net		(9,887	)		(26,458	)		—			(36,345	)
Earnings from equity investments		86			—			(86	)		—
Other, net		15			—			—			15
Total other income (expense)		(9,786	)		(26,458	)		(86	)		(36,330	)
Income (loss) before income taxes		37,338			100,619			(86	)		137,871
Income tax benefit (expense)		(26,522	)		688			—			(25,834	)
Net income (loss)	$	10,816		$	101,307		$	(86	)	$	112,037

	Nine Months Ended September 30, 2015
	MRD			MEMP			Other, Adjustments & Eliminations		Consolidated
Revenues:
Oil & natural gas sales	$	277,282		$	276,689		$	—	$	553,971
Other revenues		—			2,350			—		2,350
Total revenues		277,282			279,039			—		556,321
Costs and expenses:
Lease operating		17,025			130,782			—		147,807
Gathering, processing, and transportation		51,685			25,402			—		77,087
Gathering, processing, and transportation - affiliate		13,028			—			—		13,028
Pipeline operating		—			1,407			—		1,407
Exploration		7,024			2,263			—		9,287
Production and ad valorem taxes		8,666			19,609			—		28,275
Depreciation, depletion, and amortization		129,394			150,857			—		280,251
Impairment of proved oil and natural gas properties		—			613,183			—		613,183
Incentive unit compensation expense		31,305			—			—		31,305
General and administrative		34,994			42,798			—		77,792
Accretion of asset retirement obligations		311			5,036			—		5,347
(Gain) loss on commodity derivative instruments		(202,894	)		(328,944	)		—		(531,838	)
(Gain) loss on sale of properties		50			—			—		50
Other, net		—			(943	)		—		(943	)
Total costs and expenses		90,588			661,450			—		752,038
Operating income (loss)		186,694			(382,411	)		—		(195,717	)
Other income (expense):
Interest expense, net		(28,545	)		(87,983	)		—		(116,528	)
Earnings from equity investments		(402	)		—			402		—
Other, net		(183	)		295			—		112
Total other income (expense)		(29,130	)		(87,688	)		402		(116,416	)
Income (loss) before income taxes		157,564			(470,099	)		402		(312,133	)
Income tax benefit (expense)		(77,345	)		1,601			—		(75,744	)
Net income (loss)	$	80,219		$	(468,498	)	$	402	$	(387,877	)

	Nine Months Ended September 30, 2014
	MRD			MEMP			Other, Adjustments & Eliminations		Consolidated & Combined
Revenues:
Oil & natural gas sales	$	297,328		$	423,782		$	—	$	721,110
Other revenues		12			3,572			—		3,584
Total revenues		297,340			427,354			—		724,694
Costs and expenses:
Lease operating		12,361			99,526			—		111,887
Gathering, processing, and transportation		30,793			21,016			—		51,809
Pipeline operating		—			1,596			—		1,596
Exploration		1,213			252			—		1,465
Production and ad valorem taxes		9,141			24,482			—		33,623
Depreciation, depletion, and amortization		86,741			129,165			—		215,906
Impairment of proved oil and natural gas properties		—			67,181			—		67,181
Incentive unit compensation expense		969,390			—			—		969,390
General and administrative		26,880			34,181			—		61,061
Accretion of asset retirement obligations		389			4,212			—		4,601
(Gain) loss on commodity derivative instruments		(17,130	)		28,710			—		11,580
(Gain) loss on sale of properties		3,057			—			—		3,057
Other, net		—			(12	)		—		(12	)
Total costs and expenses		1,122,835			410,309			—		1,533,144
Operating income (loss)		(825,495	)		17,045			—		(808,450	)
Other income (expense):
Interest expense, net		(44,355	)		(60,573	)		—		(104,928	)
Loss on extinguishment on debt		(37,248	)		—			—		(37,248	)
Earnings from equity investments		(12,844	)		—			12,844		—
Other, net		102			—			—		102
Total other income (expense)		(94,345	)		(60,573	)		12,844		(142,074	)
Income before income taxes		(919,840	)		(43,528	)		12,844		(950,524	)
Income tax benefit (expense)		(14,701	)		303			—		(14,398	)
Net income (loss)	$	(934,541	)	$	(43,225	)	$	12,844	$	(964,922	)