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, 2014

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, 2014, the registrant had 193,559,211 shares of common stock, $.01 par value, outstanding

MemORIAL RESOURCE DEVELOPMENT CORP.

Table of Contents

		Page
	Glossary of Oil and Natural Gas Terms	1
	Names of Entities	5
	Cautionary Note Regarding Forward-Looking Statements	6
	PART I—FINANCIAL INFORMATION
Item 1.	Financial Statements
	Unaudited Condensed Consolidated and Combined Balance Sheets as of September 30, 2014 and December 31, 2013	8
	Unaudited Condensed Statements of Consolidated and Combined Operations for the Three and Nine Months Ended September 30, 2014 and 2013	9
	Unaudited Condensed Statements of Consolidated and Combined Cash Flows for the Nine Months Ended September 30, 2014 and 2013	10
	Unaudited Condensed Statements of Consolidated and Combined Equity for the Nine Months Ended September 30, 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	14
	Note 3 – Acquisitions and Divestitures	19
	Note 4 – Fair Value Measurements of Financial Instruments	20
	Note 5 – Risk Management and Derivative Instruments	22
	Note 6 – Asset Retirement Obligations	26
	Note 7 – Restricted Investments	27
	Note 8 – Long Term Debt	27
	Note 9 – Stockholders’ Equity and Noncontrolling Interests	31
	Note 10 – Earnings per Share	33
	Note 11 – Long-Term Incentive Plans	34
	Note 12 – Incentive Units	35
	Note 13 – Related Party Transactions	37
	Note 14 – Business Segment Data	40
	Note 15 – Commitments and Contingencies	47
	Note 16 – Subsequent Events	49
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	50
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	68
Item 4.	Controls and Procedures	70
	PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	71
Item 1A.	Risk Factors	71
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	71
Item 3.	Defaults Upon Senior Securities	71
Item 4.	Mine Safety Disclosures	71
Item 5.	Other Information	71
Item 6.	Exhibits	72
Signatures		74

i

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.

API Gravity: A system of classifying oil based on its specific gravity, whereby the greater the gravity, the lighter the oil.

Basin: A large depression on the earth’s surface in which sediments accumulate.

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

Bbl/d: One Bbl per day.

Bcf: One billion cubic feet of natural gas.

Bcfe: One billion cubic feet of natural gas equivalent.

Boe: One barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil.

Boe/d: One Boe per day.

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.

Deterministic Estimate: The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering or economic data) in the reserves calculation is used in the reserves estimation procedure.

Developed Acreage: The number of acres which are allocated or assignable to producing wells or wells capable of production.

Development Project: A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

Development Well: A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Differential: An adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.

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.

1

Estimated Ultimate Recovery: Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

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.

Exploratory Well: A well drilled to find and produce oil and natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.

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 a working interest.

ICE: Inter-Continental Exchange.

MBbl: One thousand Bbls.

MBbls/d: One thousand Bbls per day.

MBoe: One thousand Boe.

MBoe/d: One thousand Boe per day.

MBtu: One thousand Btu.

MBtu/d: One thousand Btu per day.

Mcf: One thousand cubic feet of natural gas.

Mcf/d: One Mcf per day.

MMBtu: One million British thermal units.

MMcf: One million cubic feet of natural gas.

MMcfe: One million cubic feet of natural gas equivalent.

Net Acres or Net Wells: Gross acres or wells, as the case may be, multiplied by our working interest ownership percentage.

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

Net Revenue Interest: A working interest owner’s gross working interest in production less the royalty, overriding royalty, production payment and net profits interests.

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.

OPIS: Oil Price Information Service.

Play:  A geographic area with hydrocarbon potential.

2

Probabilistic Estimate:  The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrences.

Productive Well: A well that produces commercial quantities of hydrocarbons, exclusive of its capacity to produce at a reasonable rate of return.

Proved Developed Reserves: Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods.

Proved Reserve Additions: The sum of additions to proved reserves from extensions, discoveries, improved recovery, acquisitions and revisions of previous estimates.

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.

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.

Realized Price: The cash market price less all expected quality, transportation and demand adjustments.

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.

3

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.

Spacing: The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres (e.g., 40-acre spacing) and is often established by regulatory agencies.

Spot Price: The cash market price without reduction for expected quality, transportation and demand adjustments.

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.  Standardized measure does not give effect to derivative transactions.

Undeveloped Acreage: Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

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.

Workover: Operations on a producing well to restore or increase production.

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 has historically owned our predecessor’s business and which was merged into MRD Operating LLC, 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 LLC, 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 collectively to:

o certain oil and natural gas properties and related assets primarily in the Permian Basin, East Texas and the Rockies that MEMP acquired through equity transactions on October 1, 2013 from certain affiliates of NGP. On October 1, 2013, MEMP acquired Boaz Energy, LLC (“Boaz”), Crown Energy Partners, LLC (“Crown”), the Crown net profits interest and overriding royalty interest (“Crown NPI/ORRI”), Propel Energy SPV LLC (“Propel SPV”), together with its wholly-owned subsidiary Propel Energy Services, LLC (“Propel Energy Services”), and Stanolind Oil and Gas SPV LLC (“Stanolind SPV”) from: (a) Boaz Energy Partners, LLC (“Boaz Energy Partners”), Crown Energy Partners Holdings, LLC (“Crown Holdings”), Propel Energy, LLC (“Propel Energy”) and Stanolind Oil and Gas LP (“Stanolind”), all of which are primarily owned by two of the Funds; and

o 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; and

· “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.

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, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact included in this quarterly report, are forward-looking statements. When used in this quarterly report, the words “could,” “should,” “will,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “plan,” “potential,” “pursue,” “target,” “project,” “forecast,” the negative of such terms, or other similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.

Forward-looking statements may include statements about:

· our business strategy;

· our estimated reserves and the present value thereof;

· our technology;

· our cash flows and liquidity;

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

· realized commodity prices;

· timing and amount of future production of reserves;

· availability of drilling and production equipment;

· availability of pipeline capacity;

· availability of oilfield labor;

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

· availability and terms of capital;

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

· competition;

· government regulations;

· marketing of production;

· exploitation or property acquisitions;

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

· 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;

6

· taxation of the oil and natural gas industry;

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

· uncertainty regarding future operating results; and

· plans, objectives, expectation and intentions.

These types of statements, other than statements of historical fact included in this quarterly report, are forward-looking statements. These forward-looking statements may be found in “Part II—Item 1A. Risk Factors,” “Part II—Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and other sections of this quarterly report. 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 “Risk Factors” section of our initial public offering prospectus dated June 12, 2014 filed with the SEC on June 16, 2014 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 AND COMBINED BALANCE SHEETS

(In thousands, except outstanding shares)

	September 30,			December 31,
	2014			2013
ASSETS
Current assets:
Cash and cash equivalents	$	10,316		$	77,721
Restricted cash		—			35,000
Accounts receivable:
Oil and natural gas sales		102,578			68,764
Joint interest owners and other		19,116			19,958
Affiliates		—			4,652
Short-term derivative instruments		37,421			9,289
Prepaid expenses and other current assets		20,696			19,513
Total current assets		190,127			234,897
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method		4,544,176			3,037,298
Other		15,477			10,331
Accumulated depreciation, depletion and impairment		(877,843	)		(627,925	)
Oil and natural gas properties, net		3,681,810			2,419,704
Long-term derivative instruments		34,515			48,616
Restricted investments		76,268			73,385
Restricted cash		260			15,506
Other long-term assets		38,687			37,053
Total assets	$	4,021,667		$	2,829,161
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	16,846		$	20,734
Accounts payable - affiliates		810			1,975
Revenues payable		59,512			56,091
Accrued liabilities		179,381			98,130
Short-term derivative instruments		5,109			9,711
Total current liabilities		261,658			186,641
Long-term debt-MRD Segment		628,000			871,150
Long-term debt-MEMP Segment		1,483,800			792,067
Asset retirement obligations		119,510			111,679
Long-term derivative instruments		15,275			6,080
Deferred tax liabilities		50,643			3,106
Other long-term liabilities		3,782			306
Total liabilities		2,562,668			1,971,029
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; 193,559,211 shares issued and outstanding at September 30, 2014; no shares authorized, issued or outstanding at December 31, 2013		1,936			—
Additional paid-in capital		1,386,143			—
Accumulated earnings (deficit)		(951,801	)		—
Total stockholders' equity		436,278			—
Members' equity:
Members		—			237,186
Previous owners (Note 1)		—			40,331
Total members' equity		—			277,517
Noncontrolling interests		1,022,721			580,615
Total equity		1,458,999			858,132
Total liabilities and equity	$	4,021,667		$	2,829,161

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						For the Nine Months
	Ended September 30,						Ended September 30,
	2014			2013			2014			2013
Revenues:
Oil & natural gas sales	$	244,161		$	152,762		$	669,301		$	420,857
Pipeline tariff income and other		1,332			753			3,584			1,884
Total revenues		245,493			153,515			672,885			422,741
Costs and expenses:
Lease operating		46,211			29,395			111,887			81,746
Pipeline operating		431			394			1,596			1,343
Exploration		175			1,292			1,465			2,265
Production and ad valorem taxes		14,040			7,422			33,623			23,478
Depreciation, depletion, and amortization		84,447			45,136			215,906			132,328
Impairment of proved oil and natural gas properties		67,181			21			67,181			21
Incentive unit compensation expense (Note 12)		25,550			19,069			969,390			19,069
General and administrative		21,196			19,646			61,061			55,982
Accretion of asset retirement obligations		1,553			1,354			4,601			4,016
(Gain) loss on commodity derivative instruments		(189,492	)		2,028			11,580			(29,556	)
(Gain) loss on sale of properties		—			(90,063	)		3,057			(86,218	)
Other, net		—			24			(12	)		622
Total costs and expenses		71,292			35,718			1,481,335			205,096
Operating income (loss)		174,201			117,797			(808,450	)		217,645
Other income (expense):
Interest expense, net		(36,345	)		(20,615	)		(104,928	)		(41,994	)
Loss on extinguishment of debt		—			—			(37,248	)		—
Other, net		15			24			102			81
Total other income (expense)		(36,330	)		(20,591	)		(142,074	)		(41,913	)
Income (loss) before income taxes		137,871			97,206			(950,524	)		175,732
Income tax benefit (expense)		(25,834	)		(1,244	)		(14,398	)		(1,432	)
Net income (loss)		112,037			95,962			(964,922	)		174,300
Net income (loss) attributable to noncontrolling interest		102,109			11,235			(34,851	)		42,134
Net income (loss) attributable to Memorial Resource    Development Corp.		9,928			84,727			(930,071	)		132,166
Net (income) loss allocated to members		—			(84,754	)		(20,305	)		(122,639	)
Net (income) loss allocated to previous owners		—			27			(1,425	)		(9,527	)
Net income (loss) available to common stockholders	$	9,928		$	—		$	(951,801	)	$	—
Earnings per common share: (Note 10)
Basic	$	0.05		$	—		$	(4.94	)	$	—
Diluted	$	0.05		$	—		$	(4.94	)	$	—
Weighted average common and common    equivalent shares outstanding:
Basic		192,500			—			192,500			—
Diluted		192,716			—			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)

	For the Nine Months
	Ended September 30,
	2014			2013
Cash flows from operating activities:
Net income (loss)	$	(964,922	)	$	174,300
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization		215,906			132,328
Impairment of proved oil and natural gas properties		67,181			21
(Gain) loss on derivatives		12,737			(29,487	)
Cash settlements (paid) received on derivative instruments		(22,174	)		21,356
Loss on extinguishment of debt		30,248			—
Amortization of deferred financing costs		5,492			6,193
Accretion of senior notes net discount		1,888			161
Accretion of asset retirement obligations		4,601			4,016
Amortization of equity awards		6,874			2,322
(Gain) loss on sale of properties		3,057			(86,218	)
Non-cash compensation expense		941,659			1,057
Exploration costs		868			—
Deferred income tax expense (benefit)		13,916			—
Changes in operating assets and liabilities:
Accounts receivable		(22,117	)		560
Prepaid expenses and other assets		297			(2,562	)
Payables and accrued liabilities		67,324			13,034
Other		2,625			95
Net cash provided by operating activities		365,460			237,176
Cash flows from investing activities:
Acquisitions of oil and natural gas properties		(1,083,167	)		(104,926	)
Additions to oil and gas properties		(457,838	)		(257,513	)
Additions to other property and equipment		(9,134	)		(1,184	)
Additions to restricted investments		(2,883	)		(4,263	)
Deposits for property acquisitions		—			(25,310	)
Decrease (increase) in restricted cash		49,946			653
Proceeds from the sale of oil and natural gas properties		6,700			156,799
Other		(301	)		(139	)
Net cash used in investing activities		(1,496,677	)		(235,883	)
Cash flows from financing activities:
Advances on revolving credit facilities		2,464,800			478,055
Payments on revolving credit facilities		(2,441,900	)		(900,368	)
Borrowings under second lien credit facility		—			325,000
Redemption of second lien credit facility		(328,282	)		—
Proceeds from the issuances of senior notes		1,092,425			397,563
Redemption of senior notes		(351,808	)		—
Deferred financing costs		(30,284	)		(23,839	)
Purchase of additional interests in consolidated subsidiaries		(3,292	)		(1,270	)
Contributions from previous owners		—			1,214
Proceeds from initial public offering		408,500			—
Costs incurred in conjunction with initial public offering		(28,198	)		—
Proceeds from MEMP public offering		553,288			179,371
Costs incurred in conjunction with MEMP public offering		(12,222	)		(7,592	)
Contributions from NGP affiliates related to sale of properties		1,165			2,013
Distributions to the Funds		—			(363,437	)
Distributions to MRD Holdco		(59,803	)		—
Distributions to noncontrolling interests		(101,327	)		(51,319	)
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	)		—
Distributions made by previous owners		—			(3,130	)
Other		213			—
Net cash provided by financing activities		1,063,812			32,261
Net change in cash and cash equivalents		(67,405	)		33,554
Cash and cash equivalents, beginning of period		77,721			49,391
Cash and cash equivalents, end of period	$	10,316		$	82,945
Supplemental cash flows:
Cash paid for interest	$	67,449		$	22,959
Noncash investing and financing activities:
Change in capital expenditures in payables and accrued liabilities		29,137			25,017
Assumptions of asset retirement obligations related to properties acquired or drilled		5,053			3,478
Accounts receivable related to acquisitions and divestitures		4,271			—

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)

	For the Nine Months
	Ended September 30,
	2014			2013
STOCKHOLDERS' EQUITY
Preferred stock
Balance, beginning and end of period	$	—		$	—
Common stock
Balance, beginning of period		—			—
Issuance of shares in connection with restructuring transactions (see Note 1)		1,710			—
Issuance of shares in connection with initial public offering (see Note 1)		215			—
Restricted stock awards		11			—
Balance, end of period		1,936			—
Additional paid-in capital
Balance, beginning of period		—			—
Issuance of shares in connection with restructuring transactions (see Note 1)		913,152			—
Issuance of shares in connection with initial public offering (see Note 1)		379,962			—
Tax related effects in connection with restructuring transactions and initial public offering		(43,251	)		—
Restricted stock awards		(11	)		—
Amortization of restricted stock awards		1,487			—
Contribution related to MRD Holdco incentive unit compensation expense (see Note 12)		137,307			—
Purchase of noncontrolling interests		(2,881	)		—
Other		378			—
Balance, end of period		1,386,143			—
Accumulated earnings (deficit)
Balance, beginning of period		—			—
Net income (loss) allocation		(951,801	)		—
Balance, end of period		(951,801	)		—
Total stockholders' equity		436,278			—
MEMBERS' EQUITY
Members
Balance, beginning of period		237,186			811,614
Net income (loss) allocation		20,305			122,639
Contribution related to sale of assets to NGP affiliate		1,165			—
Net book value of assets sold to NGP affiliate		(621	)		—
Net book value of assets acquired from NGP affiliates		45,059			—
Distribution to NGP affiliates in connection with acquisition of assets		(66,693	)		—
Distribution of net assets to MRD Holdco		(123,078	)		—
Distribution of shares received in connection with restructuring transactions to MRD Holdco		(110,510	)		—
Distributions		—			(363,437	)
Net equity deemed contribution (distribution) related to net assets transferred to MEMP		(2,659	)		2,560
Impact of equity transactions of MEMP		—			24,024
Other		(154	)		(47	)
Balance, end of period		—			597,353
Previous Owners
Balance, beginning of period		40,331			233,433
Net income (loss) allocation		1,425			9,527
Contributions		—			1,214
Distributions		—			(3,130	)
Net book value of assets acquired from NGP affiliates		(41,756	)		—
Other		—			(2,299	)
Balance, end of period		—			238,745
Total members' equity		—			836,098
NONCONTROLLING INTERESTS
Noncontrolling interests
Balance, beginning of period		580,615			231,662
Net income (loss) allocation		(34,851	)		42,134
Net proceeds from MEMP public equity offering		540,987			171,779
Distributions		(101,327	)		(51,319	)
Net equity deemed contribution (distribution) related to net assets transferred to MEMP		2,659			(2,560	)
Purchase of noncontrolling interests		(411	)		(1,270	)
Impact of equity transactions of MEMP		—			(24,024	)
Amortization of MEMP equity awards		5,387			2,321
Distribution of net assets to MRD Holdco		29,994			—
Other		(332	)		—
Balance, end of period		1,022,721			368,723
TOTAL EQUITY
Total equity		1,458,999			1,204,821

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.

The Company was formed by Memorial Resource Development LLC (“MRD LLC”) in January 2014 to exploit, develop and acquire natural gas, NGL and oil properties in North America. MRD LLC was a Delaware limited liability company formed on April 27, 2011 by Natural Gas Partners VIII, L.P. (“NGP VIII”), Natural Gas Partners IX, L.P. (“NGP IX”) and NGP IX Offshore Holdings, L.P. (“NGP IX Offshore”) (collectively, the “Funds”) to exploit, develop and acquire natural gas, NGL and oil properties. The Funds are private equity funds managed by Natural Gas Partners (“NGP”).  MRD LLC’s consolidated and combined financial statements represent our predecessor for accounting and financial reporting purposes prior to our initial public offering.

Initial Public Offering and Restructuring Transactions

On June 18, 2014, the Company completed its initial public offering of 21,500,000 common units at a price of $19.00 per share, which generated net proceeds to the Company of approximately $380.2 million after deducting underwriting discounts and commissions and other offering related fees and expenses. The following restructuring events and transactions occurred in connection with our initial public offering:

· The Funds contributed all of their interests in MRD LLC to MRD Holdco LLC (“MRD Holdco”) and the members of our management who owned incentive units in MRD LLC exchanged those incentive units for substantially identical incentive units in MRD Holdco, after which MRD Holdco owned 100% of MRD LLC;

· WildHorse Resources, LLC  (“WildHorse Resources”) sold its subsidiary, WildHorse Resources Management Company, LLC (“WHR Management Company”), to an affiliate of the Funds for approximately $0.2 million in cash, and WHR Management Company entered into a services agreement with the Company and WildHorse Resources pursuant to which WHR Management Company will provide transition services to WildHorse Resources;

· Classic Hydrocarbons Holdings, L.P. (“Classic”) and Classic Hydrocarbons GP Co., L.L.C. (“Classic GP”) distributed to MRD LLC the ownership interests in Classic Pipeline & Gathering, LLC (“Classic Pipeline”), which owns certain midstream assets in Texas, and Black Diamond Minerals, LLC (“Black Diamond”) distributed to MRD LLC its ownership interests in Golden Energy Partners LLC (“Golden Energy”), which sold all of its assets in May 2014;

· MRD LLC contributed to us substantially all of its assets, comprised of: (i) 100% of the ownership interests in Classic, Classic GP, Black Diamond, Beta Operating Company, LLC (“Beta Operating”), Memorial Resource Finance Corp., MRD Operating LLC (“MRD Operating”), Memorial Production Partners GP LLC (“MEMP GP”) (including MEMP GP’s ownership of 50% of Memorial Production Partners LP’s (“MEMP”) incentive distribution rights) and (ii) 99.9% of the membership interests in WildHorse Resources;

· We issued 128,665,677 shares of our common stock to MRD LLC, which MRD LLC immediately distributed to MRD Holdco;

· We assumed the obligations of MRD LLC under the indenture governing the $350 million in aggregate principal amount of 10.00% / 10.75% Senior PIK Toggle Notes due 2018 (the “PIK notes”) and reimbursed MRD LLC for the June 15, 2014 interest payment made on the PIK notes;

· Certain former management members of WildHorse Resources contributed to us their outstanding incentive units in WildHorse Resources, as well as the remaining 0.1% of the membership interests in WildHorse Resources, and we issued 42,334,323 shares of our common stock and paid cash consideration of $30.0 million to such former management members of WildHorse Resources;

12

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

· We entered into a registration rights agreement and a voting agreement with MRD Holdco and certain former management members of WildHorse Resources;

· We entered into a new $2.0 billion revolving credit facility (see Note 8) and used approximately $614.5 million in borrowings under that facility to repay all amounts outstanding under WildHorse Resources’ credit agreements, to partially fund the cash consideration payable to the former management members of WildHorse Resources and to reimburse MRD LLC for the June 15, 2014 interest payment made on the PIK notes;

· Notice of redemption was given to the PIK notes trustee (see Note 8) specifying a redemption date of July 16, 2014 and indicating that a portion of the net proceeds from our initial public offering, which temporarily reduced amounts outstanding under our new revolving credit facility, would be used to redeem the PIK notes at a redemption price of 102% of the principal amount of the PIK notes plus accrued and unpaid interest thereon to the date of redemption;

· MRD Operating entered into a merger agreement with MRD LLC pursuant to which after the termination or earlier discharge of the PIK notes MRD LLC would merge into MRD Operating;

· MRD LLC distributed to MRD Holdco the following: (i) BlueStone Natural Resources Holdings, LLC (“BlueStone”), which sold substantially all of its assets in July 2013 for $117.9 million, MRD Royalty LLC, which owns certain leasehold interests and overriding royalty interests in Texas and Montana, MRD Midstream LLC, which owns an indirect interest in certain midstream assets in North Louisiana, Golden Energy and Classic Pipeline; (ii) 5,360,912 subordinated units of MEMP; (iii) the right to the remaining cash to be released from the debt service reserve account in connection with the redemption or earlier discharge of the PIK notes plus the cash received from us in reimbursement of the interest paid on June 15, 2014 in respect of the PIK notes; and (iv) approximately $6.7 million of cash received by MRD LLC in connection with the sale of Golden Energy’s assets in May 2014;

· We irrevocably deposited with the PIK notes trustee approximately $360.0 million on June 27, 2014, which was an amount sufficient to fund the redemption of the PIK notes on the redemption date and to satisfy and discharge our obligations under the PIK notes and the related indenture.  The discharge became effective upon the irrevocable deposit of the funds with the PIK notes trustee; and

· MRD LLC merged into MRD Operating.

Previous Owners

References to “the previous owners” for accounting and financial reporting purposes refer collectively to:

· Certain oil and natural gas properties and related assets primarily in the Permian Basin, East Texas and the Rockies that MEMP acquired through equity transactions on October 1, 2013 from certain affiliates of NGP. On October 1, 2013, MEMP acquired Boaz Energy, LLC (“Boaz”), Crown Energy Partners, LLC (“Crown”), the Crown net profits interest and overriding royalty interest (“Crown NPI/ORRI”), Propel Energy SPV LLC (“Propel SPV”), together with its wholly-owned subsidiary Propel Energy Services, LLC (“Propel Energy Services”), and Stanolind Oil and Gas SPV LLC (“Stanolind SPV”) from Boaz Energy Partners, LLC (“Boaz Energy Partners”), Crown Energy Partners Holdings, LLC (“Crown Holdings”), Propel Energy, LLC (“Propel Energy”) and Stanolind Oil and Gas LP (“Stanolind”), all of which are primarily owned by two of the Funds.

· A net profits interest that WildHorse Resources purchased from NGP Income Co-Investment Fund II, L.P. (“NGPCIF”) on February 28, 2014 (“NGPCIF NPI”). NGPCIF is controlled by NGP. Upon the completion of the 2010 Petrohawk and Clayton Williams acquisitions, WildHorse Resources sold a net profits interest in these properties to NGPCIF. Since WildHorse Resources sold the net profits interest, the historical results are accounted for as a working interest for all periods.

Our unaudited financial statements reported herein include the financial position and results attributable to: (i) those certain oil and natural gas properties and related assets that MEMP acquired through equity transactions on October 1, 2013 from Boaz Energy Partners, Crown Holdings, Propel Energy and Stanolind and (ii) NGPCIF NPI.

13

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Basis of Presentation

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

All material intercompany transactions and balances have been eliminated in preparation of our consolidated and combined financial statements.  Our results of operations for the three and nine months ended September 30, 2014 are not necessarily indicative of results expected for the full year.  In our opinion, the accompanying unaudited condensed consolidated and combined financial statements include all adjustments of a normal recurring nature necessary for fair presentation.  Although we believe the disclosures in these financial statements are adequate and make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted pursuant to the rules and regulations of the United States Securities and Exchange Commission (“SEC”).

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

· MRD—reflects the combined operations of the Company, MRD LLC, WildHorse Resources and its previous owners, Classic and Classic GP, Black Diamond, BlueStone, Beta Operating and MEMP GP.

· MEMP—reflects the combined operations of MEMP, its previous owners, and historical dropdown transactions that occurred between MEMP and other MRD LLC consolidating subsidiaries.

Segment financial information has been retrospectively revised for the following common control transactions for comparability purposes:

· acquisition by MEMP of all the outstanding membership interests in Tanos Energy, LLC (“Tanos”) from MRD LLC for a purchase price of approximately $77.4 million on October 1, 2013;

· acquisition by MEMP of all the outstanding membership interests in Prospect Energy, LLC (“Prospect Energy”) from Black Diamond for a purchase price of approximately $16.3 million on October 1, 2013;

· acquisition by MEMP of certain of the oil and natural gas properties in Jackson County, Texas from MRD LLC for a purchase price of approximately $2.6 million on October 1, 2013; and

· acquisition by MEMP of all the outstanding membership interests in WHT Energy Partners LLC (“WHT”) from WildHorse Resources and Tanos for a purchase price of approximately $200.0 million on March 28, 2013.

Note 2.  Summary of Significant Accounting Policies

Use of Estimates

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

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

14

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Principles of Consolidation and Combination

Our consolidated financial statements include our accounts and those of our subsidiaries in which we have a controlling interest.  Likewise, the combined financial statements include those of our predecessor and the previous owners.

Cash and Cash Equivalents

Cash and cash equivalents represent unrestricted cash on hand and all highly liquid investments with original contractual maturities of three months or less.

Concentrations of Credit Risk

Cash balances, accounts receivable, restricted investments and derivative financial instruments are financial instruments potentially subject to credit risk. Cash and cash equivalents are maintained in bank deposit accounts which, at times, may exceed the federally insured limits. Management periodically reviews and assesses the financial condition of the banks to mitigate the risk of loss. Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with MEMP’s offshore Southern California oil and gas properties. These restricted investments may consist of money market deposit accounts, money market mutual funds, commercial paper, and U.S. Government securities, all held with credit-worthy financial institutions. Derivative financial instruments are generally executed with major financial institutions that expose us to market and credit risks and which may, at times, be concentrated with certain counterparties. The creditworthiness of the counterparties is subject to continual review. We rely upon netting arrangements with counterparties to reduce credit exposure. We have not experienced any losses from such instruments.

Oil and natural gas are sold to a variety of purchasers, including intrastate and interstate pipelines or their marketing affiliates and independent marketing companies. Accounts receivable from joint operations are from a number of oil and natural gas companies, partnerships, individuals, and others who own interests in the properties operated by us and our predecessor. Generally, operators of crude oil and natural gas properties have the right to offset future revenues against unpaid charges related to operated wells, minimizing the credit risk associated with these receivables. Additionally, management believes that any credit risk imposed by a concentration in the oil and natural gas industry is mitigated by the creditworthiness of its customer base. An allowance for doubtful accounts is recorded after all reasonable efforts have been exhausted to collect or settle the amount owed. Any amounts outstanding longer than the contractual terms are considered past due. Management determined that an allowance for uncollectible accounts was unnecessary at both September 30, 2014 and December 31, 2013, respectively.

If we were to lose any one of our customers, the loss could temporarily delay production and the sale of oil and natural gas in the related producing region. If we were to lose any single customer, we believe that a substitute customer to purchase the impacted production volumes could be identified.

Oil and Natural Gas Properties

Oil and natural gas exploration, development and production activities are accounted for in accordance with the successful efforts method of accounting. Under this method, costs of acquiring properties, costs of drilling successful exploration wells, and development costs are capitalized. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if determination is made that proved reserves have been found. If no proved reserves have been found, the costs of each of the related exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. The costs of such exploratory wells are expensed if a determination of proved reserves has not been made within a twelve-month period after drilling is complete. Exploration costs such as geological, geophysical, and seismic costs are expensed as incurred.

As exploration and development work progresses and the reserves on these properties are proven, capitalized costs attributed to the properties are subject to depreciation and depletion. Depletion of capitalized costs is provided using the units-of-production method based on proved oil and gas reserves related to the associated field. Capitalized drilling and development costs of producing oil and natural gas properties are depleted over proved developed reserves and leasehold costs are depleted over total proved reserves.

On the sale or retirement of a complete or partial unit of a proved property or pipeline and related facilities, the cost and related accumulated depreciation, depletion, and amortization are removed from the property accounts, and any gain or loss is recognized.

15

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Impairments

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, such as a downward revision of the reserve estimates, less than expected production, drilling results, higher operating and development costs, or lower commodity prices. The estimated undiscounted future cash flows expected in connection with the property are compared to the carrying value of the property to determine if the carrying amount is recoverable. If the carrying value of the property exceeds its estimated undiscounted future cash flows, the carrying amount of the property is reduced to its estimated fair value using Level 3 inputs. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties.

Unproved oil and natural gas properties are assessed for impairment on a property-by-property basis. A loss is recognized by providing a valuation allowance if the assessment indicates an impairment. The impairment assessment is affected by economic factors such as the results of exploration activities, commodity price outlooks, remaining lease terms, and potential shifts in business strategy employed by management.

Asset Retirement Obligations

An asset retirement obligation associated with retiring long-lived assets is recognized as a liability on a discounted basis in the period in which the legal obligation is incurred and becomes determinable, with an equal amount capitalized as an addition to oil and natural gas properties, which is allocated to expense over the useful life of the asset. Generally, oil and gas producing companies incur such a liability upon acquiring or drilling a well. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. Upon settlement of the liability, a gain or loss is recognized as a component of exploration costs to the extent the actual costs differ from the recorded liability. See Note 6 for further discussion of asset retirement obligations.

Oil and Gas Reserves

The estimates of proved oil and natural gas reserves utilized in the preparation of the consolidated and combined financial statements are estimated in accordance with the rules established by the SEC and the Financial Accounting Standards Board (“FASB”). These rules require that reserve estimates be prepared under existing economic and operating conditions using a trailing 12-month average price with no provision for price and cost escalations in future years except by contractual arrangements.

Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties, or any combination of the above may be increased or reduced. Increases in recoverable economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates.

Other Property & Equipment

Other property and equipment is stated at historical costs and is comprised primarily of vehicles, furniture, fixtures, and computer hardware and software. Depreciation of other property and equipment is calculated using the straight-line method generally based on estimated useful lives of three to five years.

Restricted Investments

Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with MEMP’s offshore Southern California oil and gas properties. These investments are classified as held-to-maturity, and such investments are stated at amortized cost. Interest earned on these investments is included in interest expense – net in the statement of operations. The amortized cost of such investments is adjusted for amortization of premiums and accretion of discounts to maturity. At September 30, 2014, these restricted investments consisted of money market deposit accounts, money market mutual funds, commercial paper, and U.S. Government securities. See Note 7 for additional information.

Debt Issuance Costs

These costs are recorded on the balance sheet and amortized over the term of the associated debt using the straight-line method which approximates the effective yield method.

16

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Revenue Recognition

Revenue from the sale of oil and natural gas is recognized when title passes, net of royalties due to third parties. Oil and natural gas revenues are recorded using the sales method. Under this method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers, regardless of whether the sales are proportionate to our ownership in the property. An asset or a liability is recognized to the extent that we have an imbalance in excess of our proportionate share of the remaining recoverable reserves on the underlying properties.

Derivative Instruments

Commodity derivative financial instruments (e.g., swaps, collars, and put options) are used to reduce the impact of natural gas and oil price fluctuations. Interest rate swaps are used to manage exposure to interest rate volatility, primarily as a result of variable rate borrowings under the credit facilities. Every derivative instrument is recorded on the balance sheet as either an asset or liability measured at its fair value. Changes in the derivative’s fair value are recognized in earnings as we have not elected hedge accounting for any of our derivative positions.

Income Tax

Prior to our initial public offering, MRD LLC was organized as a pass-through entity for federal income tax purposes and was not subject to federal income taxes; however, certain of its consolidating subsidiaries were taxed as corporations and subject to federal income taxes.  We are organized as a taxable C corporation and subject to federal and certain state income taxes.  We are also subject to the Texas margin tax and certain aspects of the tax make it similar to an income tax as the tax is assessed on 1% of taxable margin apportioned to operations in Texas.

Deferred federal and state income taxes are provided on temporary differences between the financial statement carrying amounts of assets and liabilities and their respective tax basis. If it is more likely than not that some of the deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. A tax benefit from an uncertain tax position is recognized when it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position. The tax benefit recorded is equal to the largest amount that is greater than 50% likely to be realized through final settlement with a taxing authority. There were no uncertain tax positions that required recognition in the financial statements at both September 30, 2014 and December 31, 2013, respectively.

In June 2014, we recorded a deferred tax liability of approximately $43.3 million in stockholders’ equity in connection with our initial public offering and the related restructuring transactions.  The tax bases of our assets and liabilities changed as a result our initial public offering and the related restructuring transactions, which represented a transaction among stockholders.

Earnings Per Share

Basic earnings per share (“EPS”) is computed based on the average number of shares of common stock outstanding for the period. Diluted EPS includes the effect of the Company’s outstanding restricted stock awards if the inclusion of these awards is dilutive.   See Note 10 for additional information.

Incentive-Based Compensation Arrangements

The fair value of equity-classified awards (e.g., restricted stock awards) is amortized to earnings over the requisite service or vesting period.  Compensation expense for liability-classified awards are recognized over the requisite service or vesting period of an award based on the fair value of the award re-measured at each reporting period. Generally, no compensation expense is recognized for equity instruments that do not vest.

Prior to the restructuring transactions, the governing documents of MRD LLC and certain of its subsidiaries, including WildHorse Resources and BlueStone, provided for the issuance of incentive units. The incentive units were subject to performance conditions that affected their vesting. Compensation cost was recognized only if the performance condition was probable of being satisfied at each reporting date.

17

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

In connection with the restructuring transactions, the MRD LLC incentive units were exchanged for substantially identical units in MRD Holdco, and such incentive units entitle holders thereof to portions of future distributions by MRD Holdco. While any such distributions made by MRD Holdco will not involve any cash payment by us, we will be required to recognize non-cash compensation expense, which may be material, in future periods. The compensation expense recognized by us related to the incentive units will be offset by a deemed capital contribution from MRD Holdco.

See Notes 11 and 12 for further information.

Current Liabilities – Accrued liabilities

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

	September 30,		December 31,
	2014		2013
Accrued capital expenditures	$	77,716	$	48,579
Accrued lease operating expense		18,142		13,240
Accrued general and administrative expenses		11,986		14,485
Accrued ad valorem and production taxes		26,466		3,541
Accrued interest payable		41,857		11,934
Accrued environmental		571		577
Other miscellaneous, including operator advances		2,643		5,774
	$	179,381	$	98,130

New Accounting Pronouncements

Revenue from Contracts with Customers.  In May 2014, the FASB issued a comprehensive new revenue recognition standard for contracts with customers that will supersede most current revenue recognition guidance, including industry-specific guidance. The core principle of this standard is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, the standard provides a five-step analysis of transactions to determine when and how revenue is recognized. Other major provisions include the capitalization and amortization of certain contract costs, ensuring the time value of money is considered in the transaction price, and allowing estimates of variable consideration to be recognized before contingencies are resolved in certain circumstances. This guidance also requires enhanced disclosures regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from an entity’s contracts with customers. The new standard is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016. Early application is prohibited. The standard permits the use of either the retrospective or cumulative effect transition method. This guidance will be applicable to the Company beginning on January 1, 2017. The Company is currently assessing the impact that adopting this new accounting guidance will have on its financial consolidated financial statements and footnote disclosures.

Reporting Discontinued Operations.  In April 2014, the FASB issued an accounting standards update that changes the criteria for determining when disposals can be presented as discontinued operations and modifies discontinued operations disclosures.  The new guidance now defines a “discontinued operation” as (i) a disposal of a component or group of components that is disposed of or is classified as held for sale and “represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results” or (ii) an acquired business or nonprofit activity that is classified as held for sale on the date of acquisition.  We will adopt this guidance and apply the disclosure requirements prospectively beginning on January 1, 2015.

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.

18

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Note 3.  Acquisitions and Divestitures

Acquisition-related costs are included in general and administrative expenses in the accompanying statements of operations for the periods indicated below (in thousands):

For the Three Months				For the Nine Months
Ended September 30,				Ended September 30,
2014		2013		2014		2013
$	1,425	$	2,977	$	5,480	$	5,073

2014 Acquisitions

On July 1, 2014, MEMP consummated a transaction to acquire certain oil and natural gas liquids properties from a third party in Wyoming for an aggregate purchase price of approximately $911.7 million, including estimated post-closing adjustments (the “Wyoming Acquisition”).  Revenues of $41.6 million were recorded in the statement of operations generated earnings of approximately $16.5 million related to the Wyoming Acquisition subsequent to the closing date.

On March 25, 2014, MEMP closed a transaction to acquire certain oil and natural gas producing properties from a third party in the Eagle Ford for approximately $168.1 million, including estimated customary post-closing adjustments (the “Eagle Ford Acquisition”).  In addition, MEMP acquired a 30% interest in the seller’s Eagle Ford leasehold. During the three and nine months ended September 30, 2014, revenues of approximately $11.5 million and $25.9 million, respectively, were recorded in the statement of operations related to the Eagle Ford Acquisition subsequent to the closing date and MEMP generated earnings of approximately $5.3 million and $13.3 million, respectively.

The following table summarizes the preliminary fair value assessment of the assets acquired and liabilities assumed as of the acquisition date (in thousands):

	Eagle Ford			Wyoming
	Acquisition			Acquisition
Oil and gas properties	$	168,606		$	922,686
Asset retirement obligations		(285	)		(3,328	)
Revenue Payable		—			(444	)
Accrued liabilities		(250	)		(7,237	)
Total identifiable net assets	$	168,071		$	911,677

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

	For the Three Months			For the Nine Months
	Ended September 30,			Ended September 30,
	2014	2013		2014			2013
	(In thousands, except per unit amounts)
Revenues	n/a	$	203,461	$	764,084		$	561,359
Net income (loss)	n/a		115,666		(931,903	)		218,870
Basic and diluted earnings per share	n/a	$	—	$	(4.94	)	$	—

2014 Divestitures

On May 9, 2014, Golden Energy sold certain producing and non-producing properties in the Mississippian oil play of Northern Oklahoma to a third party for approximately $7.6 million, including estimated customary post-closing adjustments, and recorded a loss of $3.2 million.

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MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

2013 Acquisitions

On April 30, 2013, WildHorse Resources purchased certain oil and gas properties and leases in Louisiana from a third party for approximately $67.1 million.

MEMP closed two separate transactions during the nine months ended September 30, 2013 to acquire certain oil and natural gas properties from third parties in East Texas (the “East Texas Acquisition”) and the Rockies (the “Rockies Acquisition”) for approximately $29.4 million in aggregate. The East Texas Acquisition closed on September 6, 2013 and the Rockies Acquisition closed on August 30, 2013.

During the nine months ended September 30, 2013, Propel Energy acquired incremental interests in certain oil and gas properties and leases in the Hendrick Field located in Winkler County, Texas from third parties in three separate transactions for an aggregate purchase price of approximately $8.5 million.

2013 Divestitures

On January 1, 2013, Tanos sold a natural gas gathering pipeline located in East Texas, which it had originally acquired in April 2010, to a privately held gas transportation company for a minimum purchase price of $1.5 million.  The maximum allowable additional proceeds are $2.0 million.  The contingent consideration is based on the natural gas pipeline servicing any new wells that Tanos drills in the area over the following three years.  The contingent consideration portion of an arrangement is recorded when the consideration is determined to be realizable. Tanos recorded an aggregate gain of approximately $1.4 million related to this transaction, of which $0.4 million was contingent consideration.  During the nine months ended September 30, 2013, Tanos also sold certain non-operated oil and gas properties for $2.9 million and recorded a gain of $1.4 million.

On May 10, 2013, Black Diamond entered into a purchase and sale agreement with a third party to sell certain of its Wyoming oil and gas properties with an estimated net book value of $39.8 million for $33.0 million, before customary adjustments. As a result, Black Diamond recorded a loss on the sale of $6.8 million. This transaction closed on June 4, 2013.

During the nine months ended September 30, 2013, BlueStone entered into an agreement with a third party to sell its remaining interest in certain properties in the Mossy Grove Prospect in Walker and Madison Counties located in East Texas. Total cash consideration received by BlueStone was approximately $117.9 million, which exceeded the net book value of the properties sold by $90.2 million. The transaction closed on July 31, 2013.

Note 4.  Fair Value Measurements of Financial Instruments

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

The carrying values of accounts receivables, accounts payables (including accrued liabilities) and amounts outstanding under long-term debt agreements with variable rates included in the accompanying balance sheets approximated fair value at September 30, 2014 and December 31, 2013. The fair value estimates are based upon observable market data and are classified within Level 2 of the fair value hierarchy.  These assets and liabilities are not presented in the following tables.  See Note 8 for the estimated fair value of our outstanding fixed-rate debt.

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, 2014 and December 31, 2013 were based on estimated forward commodity prices and forward interest rate yield curves. 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.

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MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

The following table presents the gross derivative assets and liabilities that are measured at fair value on a recurring basis at September 30, 2014 and December 31, 2013 for each of the fair value hierarchy levels:

	Fair Value Measurements at September 30, 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	$	—	$	129,711	$	—	$	129,711
Interest rate derivatives		—		95		—		95
Total assets	$	—	$	129,806	$	—	$	129,806
Liabilities:
Commodity derivatives	$	—	$	74,542	$	—	$	74,542
Interest rate derivatives		—		3,712		—		3,712
Total liabilities	$	—	$	78,254	$	—	$	78,254

	Fair Value Measurements at December 31, 2013 Using
	Quoted Prices in		Significant Other		Significant
	Active		Observable		Unobservable
	Market		Inputs		Inputs
	(Level 1)		(Level 2)		(Level 3)		Fair Value
	(In thousands)
Assets:
Commodity derivatives	$	—	$	105,054	$	—	$	105,054
Interest rate derivatives		—		884		—		884
Total assets	$	—	$	105,938	$	—	$	105,938
Liabilities:
Commodity derivatives	$	—	$	58,234	$	—	$	58,234
Interest rate derivatives		—		5,590		—		5,590
Total liabilities	$	—	$	63,824	$	—	$	63,824

See Note 5 for additional information regarding our derivative instruments.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

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

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

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

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

· During the three and nine months ending September 30, 2014, we recognized $67.2 million of impairments primarily related to certain MEMP properties located in South Texas. The estimated future cash flows expected for these properties were compared to their carrying values and determined to be unrecoverable in part due to a downward revision of estimated

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MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

proved reserves based on declining commodity prices and increased operating costs. We recognized impairment charges of less than $0.1 million on a consolidated basis for the three and nine months ending September 30, 2013, respectively.

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 creditworthy counterparties that are generally large financial institutions.  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, 2014, after taking into effect netting arrangements, MEMP did not have any counterparty exposure related to its derivative instruments. Had certain counterparties failed completely to perform according to the terms of their existing contracts, MEMP would have the right to offset $37.5 million against amounts outstanding under its revolving credit facility at September 30, 2014.  At September 30, 2014, after taking into effect netting arrangements, we did not have any counterparty exposure related to our derivative instruments. Had certain counterparties failed completely to perform according to the terms of their existing contracts, we would have the right to offset $29.0 million against amounts outstanding under our revolving credit facility at September 30, 2014.  See Note 8 for additional information regarding our revolving credit facilities.

Commodity Derivatives

We may use a combination of commodity derivatives (e.g., floating-for-fixed swaps, put options, costless collars, call spreads and basis swaps) to manage exposure to commodity price volatility. We recognize all derivative instruments at fair value; however, certain of our put option derivative instruments have a deferred premium, which reduces the asset. For the deferred premium puts, the Company agrees to pay a premium to the counterparty at the time of settlement. At settlement, if the applicable index price is below the strike price of the put, the Company receives the difference between the strike price and the applicable index price multiplied by the contract volumes less the premium. If the applicable index price settles at or above the strike price of the put, the Company pays only the premium at settlement.

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MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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 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, 2014, the MRD Segment had the following open commodity positions:

	Remaining
	2014			2015			2016			2017			2018
Natural Gas Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (MMBtu)		4,540,000			2,250,000			1,670,000			1,270,000			1,500,000
Weighted-average fixed price	$	4.18		$	4.08		$	4.18		$	4.30		$	4.30
Collar contracts:
Average Monthly Volume (MMBtu)		730,000			1,580,000			1,100,000			1,050,000			—
Weighted-average floor price	$	4.11		$	4.14		$	4.00		$	4.00		$	—
Weighted-average ceiling price	$	5.15		$	4.61		$	4.71		$	5.06		$	—
TGT Z1 basis swaps:
Average Monthly Volume (MMBtu)		2,270,000			1,730,000			220,000			200,000			—
Spread	$	(0.08	)	$	(0.09	)	$	(0.08	)	$	(0.08	)	$	—
Crude Oil Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		56,000			33,500			—			9,500			7,625
Weighted-average fixed price	$	94.43		$	93.86		$	—		$	87.62		$	87.00
Collar contracts:
Average Monthly Volume (Bbls)		12,000			2,000			27,000			—			—
Weighted-average floor price	$	86.67		$	85.00		$	80.00		$	—		$	—
Weighted-average ceiling price	$	112.33		$	101.35		$	99.70		$	—		$	—
Put option contracts:
Average Monthly Volume (Bbls)		—			26,000			—			—			—
Weighted-average fixed price	$	—		$	85.00		$	—		$	—		$	—
Weighted-average deferred premium	$	—		$	(3.80	)	$	—		$	—		$	—
NGL Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		184,000			151,000			148,500			—			—
Weighted-average fixed price	$	44.84		$	41.61		$	39.75		$	—		$	—

23

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

At September 30, 2014, the MEMP Segment had the following open commodity positions:

	Remaining
	2014			2015			2016			2017			2018		2019
Natural Gas Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (MMBtu)		2,580,200			2,605,278			2,692,442			2,450,067			2,160,000		1,914,583
Weighted-average fixed price	$	4.34		$	4.28		$	4.40		$	4.31		$	4.51	$	4.75
Collar contracts:
Average Monthly Volume (MMBtu)		340,000			350,000			—			—			—		—
Weighted-average floor price	$	5.00		$	4.62		$	—		$	—		$	—	$	—
Weighted-average ceiling price	$	6.31		$	5.80		$	—		$	—		$	—	$	—
Call spreads (1):
Average Monthly Volume (MMBtu)		120,000			80,000			—			—			—		—
Weighted-average sold strike price	$	5.17		$	5.25		$	—		$	—		$	—	$	—
Weighted-average bought strike price	$	6.53		$	6.75		$	—		$	—		$	—	$	—
Basis swaps:
Average Monthly Volume (MMBtu)		2,830,000			2,940,000			1,635,000			300,000			—		—
Spread	$	(0.09	)	$	(0.12	)	$	(0.06	)	$	(0.05	)	$	—	$	—
Crude Oil Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		283,452			314,281			332,813			326,600			312,000		160,000
Weighted-average fixed price	$	95.83		$	90.96		$	85.83		$	84.38		$	83.74	$	85.52
Collar contracts:
Average Monthly Volume (Bbls)		23,000			5,000			—			—			—		—
Weighted-average floor price	$	82.83		$	80.00		$	—		$	—		$	—	$	—
Weighted-average ceiling price	$	105.31		$	94.00		$	—		$	—		$	—	$	—
Basis swaps:
Average Monthly Volume (Bbls)		134,000			97,500			—			—			—		—
Spread	$	(4.32	)	$	(7.07	)	$	—		$	—		$	—	$	—
NGL Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		167,500			149,200			55,000			—			—		—
Weighted-average fixed price	$	43.13		$	43.02		$	39.28		$	—		$	—	$	—

(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.

24

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
	2014			2015			2016			2017
Natural Gas Derivative Contracts:
NGPL TexOk basis swaps:
Average Monthly Volume (MMBtu)		2,260,000			2,280,000			1,500,000			300,000
Spread	$	(0.09	)	$	(0.11	)	$	(0.07	)	$	(0.05	)
NGPL STX basis swaps:
Average Monthly Volume (MMBtu)		380,000			—			—			—
Spread	$	(0.11	)	$	—		$	—		$	—
HSC basis swaps:
Average Monthly Volume (MMBtu)		190,000			150,000			135,000			—
Spread	$	(0.07	)	$	(0.08	)	$	0.07		$	—
CIG basis swaps:
Average Monthly Volume (MMBtu)		—			210,000			—			—
Spread	$	—		$	(0.25	)	$	—		$	—
TETCO STX basis swaps:
Average Monthly Volume (MMBtu)		—			300,000			—			—
Spread	$	—		$	(0.09	)	$	—		$	—
Crude Oil Derivative Contracts:
Midway-Sunset basis swaps:
Average Monthly Volume (Bbls)		60,000			57,500			—			—
Spread - Brent	$	(9.25	)	$	(9.73	)	$	—		$	—
Midland basis swaps:
Average Monthly Volume (Bbls)		40,000			40,000			—			—
Spread - WTI	$	(3.68	)	$	(3.25	)	$	—		$	—
LLS Crude basis swaps:
Average Monthly Volume (Bbls)		34,000			—			—			—
Spread - WTI	$	3.61		$	—		$	—		$	—

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 agreement to fixed interest rates. From time to time we enter into offsetting positions to avoid being economically over-hedged. At September 30, 2014, we had the following interest rate swap open positions:

	Remaining
Credit Facility	2014			2015			2016
MEMP:
Average Monthly Notional (in thousands)	$	248,333		$	280,833		$	150,000
Weighted-average fixed rate		1.299	%		1.416	%		1.193	%
Floating rate	1 Month LIBOR			1 Month LIBOR			1 Month LIBOR

On July 1, 2014, we elected to terminate the interest rate swaps associated with the MRD credit facility and in the aggregate paid our counterparties approximately $0.7 million.  WildHorse Resources novated the interest rate swaps to MRD in connection with the closing of our initial public offering.

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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, 2014 and December 31, 2013.  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	2014			2013			2014			2013
		(In thousands)
Commodity contracts	Short-term derivative instruments	$	48,405		$	21,759		$	12,458		$	19,739
Interest rate swaps	Short-term derivative instruments		—			845			3,635			3,287
Gross fair value			48,405			22,604			16,093			23,026
Netting arrangements	Short-term derivative instruments		(10,984	)		(13,315	)		(10,984	)		(13,315	)
Net recorded fair value	Short-term derivative instruments	$	37,421		$	9,289		$	5,109		$	9,711
Commodity contracts	Long-term derivative instruments	$	81,306		$	83,295		$	62,084		$	38,495
Interest rate swaps	Long-term derivative instruments		95			39			77			2,303
Gross fair value			81,401			83,334			62,161			40,798
Netting arrangements	Long-term derivative instruments		(46,886	)		(34,718	)		(46,886	)		(34,718	)
Net recorded fair value	Long-term derivative instruments	$	34,515		$	48,616		$	15,275		$	6,080

(Gains) Losses on Derivatives

All gains and losses, including changes in the derivative instruments’ fair values, have been recorded in the accompanying statements of operations since derivative instruments are not designated as hedging instruments for accounting and financial reporting purposes. The following table details the gains and losses related to derivative instruments for the three and nine months ended September 30, 2014 and 2013 (in thousands):

		For the Three Months					For the Nine Months
	Statements of	Ended September 30,					Ended September 30,
	Operations Location	2014			2013		2014		2013
Commodity derivative contracts	(Gain) loss on commodity derivatives	$	(189,492	)	$	2,028	$	11,580	$	(29,556	)
Interest rate derivatives	Interest expense, net		(175	)		1,926		1,157		69

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, 2014 (in thousands):

Asset retirement obligations at beginning of period	$	111,769
Liabilities added from acquisitions or drilling		5,053
Liabilities removed upon sale of wells to an affiliate		(1,636	)
Liabilities removed upon plugging and abandoning		(344	)
Revisions		67
Accretion expense		4,601
Asset retirement obligations at end of period	$	119,510

26

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,
	2014		2013
	(In thousands)
BOEM platform abandonment (See Note 15)	$	68,970	$	66,373
BOEM lease bonds		794		794
SPBPC Collateral:
Contractual pipeline and surface facilities abandonment		2,592		2,306
California State Lands Commission pipeline right-of-way bond		3,005		3,005
City of Long Beach pipeline facility permit		500		500
Federal pipeline right-of-way bond		307		307
Port of Long Beach pipeline license		100		100
Restricted investments	$	76,268	$	73,385

Note 8.  Long Term Debt

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

	September 30,			December 31,
	2014			2013
	(In thousands)
MRD Segment:
MRD $2.0 billion revolving credit facility, variable-rate, due June 2019	$	28,000		$	—
WildHorse Resources $1.0 billion revolving credit facility, variable-rate, terminated June 2014		—			203,100
WildHorse Resources $325.0 million second lien term facility, variable-rate, terminated June 2014		—			325,000
10.00%/10.75% senior PIK toggle notes redeemed June 2014 (1)		—			350,000
5.875% senior unsecured notes, due July 2022 (2)		600,000			—
10.00%/10.75% senior PIK toggle notes unamortized discounts		—			(6,950	)
Subtotal		628,000			871,150
MEMP Segment:
MEMP $2.0 billion revolving credit facility, variable-rate, due March 2018		301,000			103,000
7.625% senior notes, fixed-rate, due May 2021 (3)		700,000			700,000
6.875% senior unsecurred notes, due August 2022 (4)		500,000			—
Unamortized discounts		(17,200	)		(10,933	)
Subtotal		1,483,800			792,067
Total long-term debt	$	2,111,800		$	1,663,217

(1)The estimated fair value of this fixed-rate debt was $348.3 million at December 31, 2013.  The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.

(2)The estimated fair value of this fixed-rate debt was $582.0 million September 30, 2014.  The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.

(3)The estimated fair value of this fixed-rate debt was $700.0 million and $721.0 million at September 30, 2014 and December 31, 2013, respectively.  The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.

(4)The estimated fair value of this fixed-rate debt was $475.0 million at September 30, 2014.  The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.

27

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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,
	2014
MRD Segment:
MRD $2.0 billion revolving credit facility, variable-rate, due June 2019	$	668,500
MEMP Segment:
MEMP $2.0 billion revolving credit facility, variable-rate, due March 2018		1,315,000

Subsequent events. On October 3, 2014, the borrowing base under the MRD revolving credit facility was increased to $725.0 million, and we entered into an amendment to the credit agreement to, among other things, permit us to hedge a larger portion of our anticipated production from our proved reserves. On October 10, 2014, MEMP’s borrowing base under its revolving credit facility was redetermined and increased to $1.44 billion.

MRD Revolving Credit Facility

On June 18, 2014, we, as borrower, and certain of our subsidiaries, as guarantors, entered into a revolving credit facility, which is a five-year, $2.0 billion revolving credit facility with an initial borrowing base of $725.0 million and aggregate elected commitments of $725.0 million.

We are permitted to borrow under the revolving credit facility in an amount up to the least of (i) the face amount of our revolving credit facility, (ii) the borrowing base and (iii) the aggregate elected commitments. The revolving credit facility is reserve-based, and thus our borrowing base is primarily based on the estimated value of our oil, NGL and natural gas properties and our commodity derivative contracts as determined semi-annually by our lenders in their sole discretion. Our borrowing base is subject to redetermination on a semi-annual basis based on an engineering report with respect to our estimated oil, NGL and natural gas reserves, which will take into account the prevailing oil, NGL and natural gas prices at such time, as adjusted for the impact of our commodity derivative contracts. Unanimous approval by the lenders is required for any increase to the borrowing base. In addition, we may, subject to certain conditions, increase our aggregate elected commitments in an amount not to exceed the then effective borrowing base on or following a scheduled redetermination of our borrowing base once before the next scheduled redetermination date.

Borrowings under the revolving credit facility are secured by liens on substantially all of our properties, but in any event, not less than 80% of the total value of our oil and natural gas properties, and all of our equity interests in any future guarantor subsidiaries and all of our other assets including personal property. Additionally, borrowings bear interest, at our option, at either (i) the greatest of (x) the prime rate as determined by the administrative agent, (y) the federal funds effective rate plus 0.50%, and (z) the one-month adjusted LIBOR plus 1.0% (adjusted upwards, if necessary, to the next 1/100th of 1%), in each case, plus a margin that varies from 0.50% to 1.50% per annum according to the total commitment usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect), or (ii) the applicable LIBOR plus a margin that varies from 1.50% to 2.50% per annum according to the total commitment usage. The unused portion of the total commitments is subject to a commitment fee that varies from 0.375% to 0.50% per annum according to our total commitments usage.

The revolving credit facility requires maintenance of a ratio of Consolidated EBITDAX to Consolidated Net Interest Expense (as each term is determined under the revolving credit facility), which we refer to as the interest coverage ratio, of not less than 2.5 to 1.0, and a ratio of consolidated current assets to consolidated current liabilities, each as determined under the revolving credit facility, which we refer to as the current ratio, of not less than 1.0 to 1.0.

Additionally, the revolving credit facility contains various covenants and restrictive provisions that, among other things, limit our ability to incur additional debt, guarantees or liens; consolidate, merge or transfer all or substantially all of our assets; make certain investments, acquisitions or other restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; incur commodity hedges exceeding a certain percentage of our production and prepay certain indebtedness.

Events of default under the revolving credit facility include, but are not limited to, failure to make payments when due, breach of any covenant continuing beyond the applicable cure period, default under any other material debt, change in management or change of control, bankruptcy or other insolvency event and certain material adverse effects on our business.

28

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

MRD 5.875% Senior Unsecured Notes Offering

On July 10, 2014, the Company completed a private placement of $600.0 million aggregate principal amount of 5.875% senior unsecured notes (the “MRD Senior Notes”) at par. The MRD Senior Notes will mature on July 1, 2022. Interest on the MRD Senior Notes will accrue from July 10, 2014 and will be payable semiannually on January 1 and July 1 of each year, commencing on January 1, 2015. The MRD Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by certain of our existing subsidiaries. The MRD Senior Notes and the guarantees of the MRD Senior Notes will rank equally with our and the guarantors’ existing and future senior indebtedness, will be effectively junior to all of our and the guarantors’ existing and future secured indebtedness (to the extent of the value of the assets securing such indebtedness), and senior in right of payment to all of our and the guarantors’ subordinated indebtedness. The MRD Senior Notes will be structurally subordinated to the indebtedness and other liabilities of our non-guarantor subsidiaries, including MEMP and its subsidiaries and MEMP GP.

The MRD Senior Notes are governed by an indenture dated as of July 10, 2014.  The MRD Senior Notes are subject to optional redemption at prices specified in the indenture plus accrued and unpaid interest, if any, to the date of redemption. The Company may also be required to repurchase the MRD Senior Notes upon a change of control.  The indenture contains customary covenants and restrictive provisions, many of which will terminate if at any time no default exists under the indenture and the MRD Senior Notes receive an investment grade rating from both of two specified ratings agencies.  MEMP and its subsidiaries are not subject to these covenants. The indenture also provides for customary and other events of default. In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to either the Company or the guarantors, all outstanding MRD Senior Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding MRD Senior Notes may declare all the MRD Senior Notes to be due and payable immediately.

PIK notes

On December 18, 2013, MRD LLC and its wholly-owned subsidiary Memorial Resource Finance Corp. (“MRD Finance Corp.” and, together with MRD LLC, the “MRD Issuers”) completed a private placement of $350.0 million in aggregate principal amount of the PIK notes. The PIK notes were issued at 98% of par with a maturity date of December 15, 2018. Net proceeds from the private offering were used: (i) to repay all indebtedness then outstanding under MRD LLC’s then-existing revolving credit facility, (ii) to establish a cash reserve of $50.0 million for the payment of interest on the PIK notes, (iii) to pay a $210.0 million distribution to the Funds, and (iv) for general company purposes.  Interest on the PIK notes was payable semi-annually in arrears on June 15 and December 15 of each year, commencing on June 15, 2014.

A redemption notice was delivered to the PIK notes trustee on June 16, 2014, which specified a redemption date of July 16, 2014 at a redemption price of 102% of the principal amount of the PIK notes plus accrued and unpaid interest thereon to the date of redemption.  In connection with the closing of our initial public offering, we assumed the obligations of MRD LLC under the PIK notes indenture and the related debt security agreement. We irrevocably deposited with the PIK notes trustee approximately $360.0 million on June 27, 2014, which was an amount sufficient to fund the redemption of the PIK notes on the redemption date and to satisfy and discharge our obligations under the PIK notes and the related indenture.  The discharge became effective upon the irrevocable deposit of the funds with the PIK notes trustee.  An extinguishment loss of $23.6 million was recognized related to the redemption of the PIK notes.

WildHorse Resources Revolving Credit Facility and Second Lien Facility

On April 3, 2013, WildHorse Resources entered into an amended and restated credit agreement. This revolving credit facility provided for aggregate maximum credit amounts at any time of $1.0 billion, consisting of borrowings and letters of credit and had an initial borrowing base of $300.0 million. This revolving credit facility was due to mature on April 13, 2018. The borrowing base was subject to redetermination on at least a semi-annual basis. Borrowings under the revolving credit facility were to be secured by liens on substantially all of WildHorse Resources’ properties, but in any event, not less than 80% of the total value of the WildHorse Resources’ oil and natural gas properties.

On June 13, 2013, WildHorse Resources entered into a $325.0 million second lien term loan agreement that was due to mature on December 13, 2018. Borrowings bore interest, at the borrower’s option, at either: (i) the Alternative Base Rate (as defined within each credit facility) plus 5.25% per annum or (ii) the applicable LIBOR plus 6.25% per annum. Borrowings under the second lien term loan agreement were to be secured by second-priority liens on substantially all of WildHorse Resources’ properties, but in any event, not less than 80% of the total value of the WildHorse Resources’ oil and natural gas properties. The priority of the security interests in the collateral and related creditors’ rights was set forth in an intercreditor agreement. The second lien term loan agreement contained customary affirmative and negative covenants, restrictive provisions and events of default.

29

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

On June 13, 2013, WildHorse Resources borrowed $325.0 million under its second lien term loan agreement and used such borrowings to reduce outstanding indebtedness under its revolving credit facility and to pay a onetime special $225.0 million distribution to MRD LLC. This $225.0 million distribution was subsequently distributed to the Funds.

In connection with the closing of our initial public offering, the WildHorse Resources’ revolving credit facility and second lien term loan were repaid in full and terminated. An extinguishment loss of $13.7 million was recognized related to the termination of the revolving credit facility and second lien term loan.

MEMP Revolving Credit Facility & Senior Notes

Memorial Production Operating LLC (“OLLC”), a wholly-owned subsidiary of MEMP, is a party to a $2.0 billion revolving credit facility, which is guaranteed by MEMP and all of its current and future subsidiaries (other than certain immaterial subsidiaries).

Borrowings under the revolving credit facility are secured by liens on substantially all of MEMP’s properties, but in any event, not less than 80% of the total value of MEMP’s oil and natural gas properties, and all of MEMP’s equity interests in OLLC and any future guarantor subsidiaries (other than San Pedro Bay Pipeline Company) and all of MEMP’s other assets including personal property. Additionally, borrowings under the revolving credit facility bear interest, at MEMP’s option, at: (i) the Alternative Base Rate defined as the greatest of (x) the prime rate as determined by the administrative agent, (y) the federal funds effective rate plus 0.50%, and (z) the one-month adjusted LIBOR plus 1.0% (adjusted upwards, if necessary, to the next 1/100th of 1%), in each case, plus a margin that varies from 0.50% to 1.50% per annum according to the borrowing base usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect), (ii) the applicable LIBOR plus a margin that varies from 1.50% to 2.50% per annum according to the borrowing base usage, or (iii) the applicable LIBOR Market Index plus a margin that varies from 1.75% to 2.75% per annum according to the borrowing base usage. The unused portion of the borrowing base (or, if lower, the reduced commitment amount that has been elected) will be subject to a commitment fee that varies from 0.375% to 0.50% per annum according to the borrowing base usage.

On April 17, 2013, May 23, 2013 and October 10, 2013, MEMP and its wholly-owned subsidiary Memorial Production Finance Corporation (“Finance Corp.” and, together with MEMP, the “MEMP Issuers”) completed a private placement of $300.0 million, $100.0 million and $300.0 million, respectively, of their 7.625% senior unsecured notes due 2021 (the “2021 Senior Notes”). The 2021 Senior Notes are fully and unconditionally guaranteed (subject to customary release provisions) on a joint and several basis by all of the MEMP’s subsidiaries (other than Finance Corp., which is co-issuer of the 2021 Senior Notes, and certain immaterial subsidiaries). The 2021 Senior Notes will mature on May 1, 2021 with interest accruing at a rate of 7.625% per annum and payable semi-annually in arrears on May 1 and November 1 of each year. The 2021 Senior Notes are governed by an indenture. The 2021 Senior Notes are subject to optional redemption at prices specified in the indenture plus accrued and unpaid interest, if any. The MEMP Issuers may also be required to repurchase the 2021 Senior Notes upon a change of control. The indenture contains customary covenants and restrictive provisions, many of which will terminate if at any time no default exists under the indenture and the 2021 Senior Notes receive an investment grade rating from both of two specified ratings agencies. The indenture also provides for customary and other events of default. In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to either of the MEMP Issuers, all outstanding 2021 Senior Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding 2021 Senior Notes may declare all the 2021 Senior Notes to be due and payable immediately.

On July 17, 2014, the MEMP Issuers completed a private placement of $500.0 million aggregate principal amount of 6.875% senior unsecured notes (the “2022 Senior Notes”).  The 2022 Senior Notes were issued at 98.485% of par and are fully and unconditionally guaranteed (subject to customary release provisions on a joint and several basis by all of MEMP’s subsidiaries other than Finance Corp., which is co-issuer of the 2022 Senior Notes, and certain immaterial subsidiaries). The 2022 Senior Notes will mature on August 1, 2022 with interest accruing at 6.875% per annum and payable semi-annually in arrears on February 1 and August 1of each year, commencing on February 1, 2015. The indenture governing the 2022 Notes, dated as July 17, 2014, contains customary covenants and restrictive provisions, many of which will terminate if at any time no default exists under the indenture and the 2022 Senior Notes receive an investment grade rating from both of two specified ratings agencies.  The indenture also provides for customary and other events of default. In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to either of the MEMP Issuers, all outstanding 2022 Senior Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding 2022 Senior Notes may declare all the 2022 Senior Notes to be due and payable immediately. The net proceeds from the notes offering of approximately $484.9 million, after deducting the initial purchasers’ discounts and commissions but before estimated offering expenses, were used to repay a portion of the outstanding borrowings under MEMP’s revolving credit facility and for general partnership purposes.  

30

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Weighted-Average Interest Rates

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

	For the Three Months						For the Nine Months
Credit Facility	Ended September 30,						Ended September 30,
	2014			2013			2014			2013
MRD Segment:
MRD revolving credit facility		3.31	%	n/a				2.40	%	n/a
MRD LLC revolver terminated December 2013	n/a				2.34	%	n/a				3.20	%
WildHorse Resources revolver terminated June 2014	n/a				4.51	%		4.04	%		3.44	%
WildHorse Resources second lien terminated June 2014	n/a				6.50	%		6.44	%		6.50	%
Black Diamond terminated November 2013	n/a			n/a			n/a				3.34	%
MEMP Segment:
MEMP revolving credit facility		2.16	%		2.13	%		2.08	%		2.55	%
WHT revolver terminated March 2013	n/a			n/a			n/a				2.29	%
Tanos revolver terminated April 2013	n/a			n/a			n/a				2.12	%
Stanolind revolver paid off by MEMP October 2013	n/a				3.44	%	n/a				3.52	%
Boaz revolver terminated October 2013	n/a				2.65	%	n/a				2.97	%
Crown revolver terminated October 2013	n/a				3.31	%	n/a				3.38	%
Propel Energy revolver paid off by MEMP October 2013	n/a				3.09	%	n/a				3.08	%

Unamortized Deferred Financing Costs

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

	September 30,		December 31,
	2014		2013
	(In thousands)
MRD Segment:
MRD revolving credit facility	$	4,433	$	—
MRD senior notes		12,825		—
WildHorse Resources revolving credit facility		—		2,436
WildHorse Resources second lien term loan		—		9,030
PIK notes		—		8,261
MEMP Segment:
MEMP revolving credit facility		6,882		5,413
2021 Senior Notes		13,836		15,053
2022 Senior Notes		8,222		—
	$	46,198	$	40,193

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, 2014:

Balance January 1, 2014	—
Shares of common stock issued in connection with restructuring transactions      (Note 1)	171,000,000
Shares of common stock issued sold in initial public offering (Note 1)	21,500,000
Restricted common shares issued (Note 11)	1,068,422
Restricted common shares forfeited	(9,211	)
Balance September 30, 2014	193,559,211

See Note 11 for additional information regarding restricted common shares that were granted in connection with our initial public offering.  Restricted shares of common stock are considered issued and outstanding on the grant date of restricted stock award.

31

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Preferred Stock

Our amended and restated certificate of incorporation authorizes our board of directors (“Board”), subject to any limitations prescribed by law, without further stockholder approval, to establish and to issue from time to time one or more classes or series of preferred stock, par value $0.01 per share, covering up to an aggregate of 50,000,000 shares of preferred stock.  There are no shares issued and outstanding as of September 30, 2014.

Dividend Policy

We do not anticipate declaring or providing any cash dividends to holders of our common stock in the foreseeable future. We currently intend to retain all future earnings, if any, for use in the operation of our business and to fund future growth. The decision whether to pay dividends in the future will be made by our Board in light of conditions then existing, including factors such as our financial condition, earnings, available cash, business opportunities, legal requirements, restrictions in our debt agreements, and other contracts and other factors our Board deems relevant.

Noncontrolling Interests

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

Distributions paid to the limited partners of MEMP primarily represent the quarterly cash distributions paid to MEMP’s unitholders, excluding those paid to MRD LLC.

Contributions received from limited partners of MEMP primarily represent net cash proceeds received from common unit offerings.

On March 25, 2013, MEMP sold 9,775,000 of its common units in an underwritten equity offering, which generated net cash proceeds of $171.8 million after deducting underwriting discounts and offering expenses. The net proceeds from this equity offering partially funded MEMP’s acquisition of all of the outstanding equity interests in WHT.

On July 15, 2014, MEMP sold 9,890,000 common units representing limited partner interests in MEMP (including 1,290,000 common units purchased 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 purchased 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 $321.6 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.

On April 1, 2013, Tanos’ management team sold its 1.066% interest in Tanos to MRD LLC and all incentive units held were forfeited. See Note 12 for further information.

In connection with the our initial public offering, certain former management members of WildHorse Resources contributed their 0.1% membership interest in WildHorse Resources as well as their incentive units in exchange for shares of our common stock and cash consideration of $30.0 million. The difference between the carrying amount of the noncontrolling interest of $0.4 million and the fair value of the consideration paid of $3.3 million was recognized directly in stockholders’ equity as additional paid in capital. See Note 12 for further information.

32

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		For the Nine
	Months Ended		Months Ended
	September 30,		September 30,
	2014		2014
Numerator:
Net income (loss) available to common stockholders	$	9,928	$	(951,801	)
Denominator:
Weighted average common shares outstanding		192,500		192,500
Restricted common shares (1)		216		—
Weighted average common and common equivalent shares    outstanding		192,716		192,500
Basic EPS	$	0.05	$	(4.94	)
Diluted EPS	$	0.05	$	(4.94	)

(1)The treasury stock method is applied to determine the dilutive effect of the unvested restricted common shares. The restricted common shares were antidilutive due to net losses and excluded from the diluted EPS calculation for the nine months ending September 30, 2014. There were 206,956 incremental shares excluded from the computation of diluted EPS for the nine months ending September 30, 2014.

Our supplemental basic and diluted EPS includes earnings allocated to both previous owners and MRD LLC members for all periods presented due to common control considerations.  The following sets forth the calculation of our supplemental EPS, for the periods indicated (in thousands, except per share amounts):

	For the Three		For the Nine
	Months Ended		Months Ended
	September 30,		September 30,
	2014		2014
Numerator:
Net income (loss) attributable to Memorial Resource Development Corp.	$	9,928	$	(930,071	)
Denominator:
Weighted average common shares outstanding		192,500		192,500
Restricted common shares (1)		216		—
Weighted average common and common equivalent shares outstanding		192,716		192,500
Basic EPS	$	0.05	$	(4.83	)
Diluted EPS	$	0.05	$	(4.83	)

(1)The treasury stock method is applied to determine the dilutive effect of the unvested restricted common shares. The restricted common shares were antidilutive due to net losses and excluded from the diluted EPS calculation for the nine months ending September 30, 2014. There were 206,956 incremental shares excluded from the computation of diluted EPS for the nine months ending September 30, 2014.

33

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Note 11.  Long-Term Incentive Plans

MRD

In June 2014, our Board adopted the Memorial Resource Development Corp. 2014 Long Term Incentive Plan (“MRD LTIP”) for the employees of the Company and the Board.  The MRD LTIP became effective upon filing of a registration statement on Form S-8 with the SEC on June 18, 2014. The MRD LTIP provides for potential grants of stock options, stock appreciation rights, restricted stock awards, restricted stock units, bonus stock, dividend equivalents, performance awards, annual incentive awards, and other stock-based awards. The MRD LTIP initially limits the number of common shares that may be delivered pursuant to awards under the plan to 19,250,000 common shares. Common shares that are cancelled, forfeited or withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards. The MRD LTIP will be administered by our Board or a committee thereof.

In connection with our initial public offering, our Board approved an aggregate award of 1,052,633 shares of restricted stock under the MRD LTIP to certain of our key employees, including each of our executive officers. These restricted stock awards will vest ratably on a four-year annual vesting schedule from the date of the grant and are subject to restrictions on transferability and customary forfeiture provisions.  An award of 5,263 shares of restricted stock was also granted to each of our independent directors. These restricted stock awards will vest one year from the date of the grant and are also subject to restrictions on transferability and customary forfeiture provisions.

Award recipients are entitled to all the rights of absolute ownership of the restricted common shares, including the right to vote those shares and to receive dividends thereon if, as, and when declared by our Board.  The term “restricted common share” represents a time-vested share.  Such awards are non-vested until the required service period expires.

The following table summarizes information regarding restricted common share awards granted under the MRD LTIP for the periods presented:

	Number of Shares			Weighted-Average Grant Date Fair Value per Share (1)
Restricted common shares outstanding at December 31, 2013		—		$	—
Granted (2)		1,068,422		$	19.00
Forfeited		(9,211	)	$	19.00
Restricted common units outstanding at September 30, 2014		1,059,211		$	19.00

(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 2014 was $20.3 million   based on a grant date market price of $19.00 per share.

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

For the Three Months				For the Nine Months
Ended September 30,				Ended September 30,
2014		2013		2014		2013
$	1,313	$	—	$	1,487	$	—

The unrecognized compensation cost associated with restricted common share awards was $18.6 million at September 30, 2014.  We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 3.68 years.

34

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

MEMP

In December 2011, the Memorial Production Partners GP LLC Long-Term Incentive Plan (“MEMP LTIP”) was adopted for employees, officers, consultants and directors of MEMP GP and any of its affiliates who perform services for MEMP. The MEMP LTIP consists of restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, other unit-based awards and unit awards. The MEMP LTIP initially limits the number of common units that may be delivered pursuant to awards under the plan to 2,142,221 common units. Common units that are cancelled, forfeited or withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards.

The restricted common units awarded are subject to restrictions on transferability, customary forfeiture provisions and graded vesting provisions. One-third of each award generally vests on the first, second, and third anniversaries of the date of grant. Award recipients have all the rights of a unitholder in MEMP with respect to the restricted common units, including the right to receive distributions thereon if and when distributions are made by MEMP to its unitholders (except with respect to the fourth quarter 2011 distribution that was paid in February 2012). The term “restricted common unit” represents a time-vested unit. Such awards are non-vested until the required service period expires.

The following table summarizes information regarding restricted common unit awards granted under the MEMP LTIP for the periods presented:

	Number of Units			Weighted-Average Grant Date Fair Value per Unit (1)
Restricted common units outstanding at December 31, 2013		706,927		$	18.62
Granted (2)		684,954		$	22.39
Forfeited		(36,112	)	$	20.43
Vested		(260,067	)	$	18.56
Restricted common units outstanding at September 30, 2014		1,095,702		$	20.93

(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 2014 was $15.3 million   based on a grant date market price range of $21.99 - $23.40 per unit

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

For the Three Months				For the Nine Months
Ended September 30,				Ended September 30,
2014		2013		2014		2013
$	2,427	$	1,237	$	5,387	$	2,322

The unrecognized compensation cost associated with restricted common unit awards was $19.1 million at September 30, 2014.  We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.3 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

General

Each of the governing documents of BlueStone, Tanos, WildHorse Resources, Classic, Black Diamond and MRD LLC previously provided for the issuance of incentive units. The incentive units were subject to performance conditions that affected their vesting. Compensation cost was recognized only if the performance condition was probable of being satisfied at each reporting date.

BlueStone, Tanos, WildHorse Resources, Classic, Black Diamond and MRD LLC each granted incentive units to certain of its members who were key employees at the time of grant. Holders of incentive units were entitled to distributions ranging from 10% to 31.5% when declared, but only after cumulative distribution thresholds (“payouts”) had been achieved. Payouts were generally triggered after the recovery of specified members’ capital contributions plus a rate of return. In connection with MEMP’s initial public

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MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

offering in December 2011, BlueStone’s Special Tier and Tier I unit holders vested in their respective awards. Tier I unit holders became eligible to participate in 16.5% of any future distributions made by BlueStone.

Vesting of the incentive units was generally dependent upon an explicit service period, a fundamental change as defined in the respective governing document, and achievement of payout. All incentive units not vested were forfeited if an employee was no longer employed. All incentive units were forfeited if a holder resigned whether the incentive units were vested or not. If the payouts had not yet occurred, then all incentive units, whether or not vested, were forfeited automatically (unless extended).

On April 1, 2013, Tanos’ management team sold its 1.066% interest in Tanos to Memorial Resource and all incentive units held were forfeited. Compensation expense of approximately $5.8 million was recorded by Tanos and recognized as a component of general and administrative expense during the nine months ended September 30, 2013.

Compensation expense of approximately $1.0 million and $19.1 million was recorded by BlueStone (see Note 3) and recognized as a component of incentive unit compensation expense during the nine months ended September 30, 2014 and 2013, respectively.

In connection with the our initial public offering, certain former management members of WildHorse Resources contributed their 0.1% membership interest in WildHorse Resources as well as their incentive units in exchange for 42,334,323 shares of our common stock and cash consideration of $30.0 million. The portion of the total consideration related to acquiring the 0.1% membership interest was accounted for as the acquisition of noncontrolling interests. The difference between the carrying amount of the noncontrolling interest of $0.4 million and the fair value of the consideration paid of $3.3 million was recognized directly in stockholders’ equity as additional paid in capital. Compensation expense of approximately $831.1 million was recognized as a component of incentive unit compensation expense during the nine months ended September 30, 2014 related to the incentive units, of which approximately $26.7 million was paid in cash and the remaining $804.4 million related to the issuance of our common stock.

MRD Holdco

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

The holders of the Exchanged Incentive Units are eligible to participate in 9.3% of any future distributions made by MRD Holdco.  The payment likelihood was deemed probable as a result of our initial public offering and the reasonable expectation that MRD Holdco will monetize the shares of our common stock it owns over an estimated three year period as market conditions permit.  We recognized $136.7 million of compensation expense offset by a deemed capital contribution from MRD Holdco and the unrecognized compensation expense of approximately $158.5 million as of September 30, 2014 will be recognized over the remaining expected service period.   The fair value of the Exchanged Incentive Units will be remeasured on a quarterly basis until all payments have been made. The settlement obligation rests with MRD Holdco.  Accordingly, no payments will ever be made by us related to these incentive units; however, non-cash compensation expense will be allocated to us in future periods offset by capital contributions.  As such, these awards are not dilutive to our stockholders.

Subsequent to our initial public offering, MRD Holdco granted the remaining 70 incentive units to certain key employees (the “Subsequent Incentive Units”).  The holders of the Subsequent Incentive Units are eligible to participate in 0.7% of any future distributions made by MRD Holdco once payout associated with these incentive units has been achieved.  The payment likelihood was deemed probable at September 30, 2014 as a result of our initial public offering and the reasonable expectation that MRD Holdco will monetize the shares of our common stock it owns over an estimated three year period as market conditions permit.  We recognized $0.6 million of compensation expense and the unrecognized compensation expense of approximately $5.3 million as of September 30, 2014 will be recognized over the remaining expected service period.  The fair value of the Subsequent Incentive Units will be remeasured on a quarterly basis until all payments have been made. No payments will ever be made by us related to these incentive units; however, non-cash compensation expense will be allocated to us in future periods offset by capital contributions.  As such, these awards are not dilutive to our stockholders.

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MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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	9/30/2014			9/30/2014
Dividend yield		0	%		0	%
Expected volatility		21.47	%		21.47	%
Risk-free rate		0.90	%		0.90	%
Expected life (years)		2.67			2.67

Note 13.  Related Party Transactions

Amounts due to (due from) MRD Holdco and certain affiliates of NGP at September 30, 2014 and December 31, 2013 are presented as “Accounts receivable – affiliates” and “Accounts payable – affiliates” in the accompanying balance sheets.

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.

Common Control Transactions between MEMP and Other MRD LLC Subsidiaries

MEMP acquired all of the outstanding membership interests in WHT from WildHorse Resources and Tanos on March 28, 2013 for a purchase price of approximately $200.0 million.  On April 1, 2014, MEMP acquired certain oil and natural gas producing properties in East Texas from WildHorse Resources for approximately $33.3 million, including estimated customary post-closing adjustments.  

MEMP acquired of all the outstanding membership interests in Tanos for a purchase price of approximately $77.4 million on October 1, 2013.

MEMP acquired of all the outstanding membership interests in Prospect from Black Diamond for a purchase price of approximately $16.3 million on October 1, 2013.

MEMP acquired of certain of the oil and natural gas properties in Jackson County, Texas from MRD LLC for a purchase price of approximately $2.6 million on October 1, 2013.

Other Acquisitions or Dispositions

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

On March 28, 2014, MRD Royalty acquired certain interests in oil and gas properties in Gonzales and Karnes Counties located in South Texas from Propel Energy for $3.3 million. Due to common control considerations, this transaction was recognized in the equity statement.

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MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

On June 18, 2014, in connection with our initial public offering and the related restructuring transactions (see Note 1), WHR Management Company was sold by WildHorse Resources to an affiliate of the Funds for net book value.  The net book value of the assets sold was as follows (in thousands):

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

Related Party Agreements

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

Registration Rights Agreement

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

Voting Agreement

In connection with the closing of our initial public offering, we entered into a voting agreement with MRD Holdco, WHR Incentive LLC, a limited liability company beneficially owned by Messrs. Bahr and Graham, and certain former management members of WildHorse Resources, who contributed their ownership of WildHorse Resources to us in the restructuring transactions. Among other things, the voting agreement provides that those former management members of WildHorse Resources will vote all of their shares of our common stock as directed by MRD Holdco. The voting agreement also prohibits the transfer of any shares of our common stock by the former management members of WildHorse Resources until after the termination of the services agreement described below; provided, however, that the former management members of WildHorse Resources (other than Messrs. Bahr and Graham) may transfer their shares of our common stock after the 180 day lock-up period has expired and these transfer restrictions will not prohibit Messrs. Bahr and Graham from exercising piggyback registration rights under the registration rights agreement described above.

Omnibus Agreement

On December 14, 2011, in connection with the closing of MEMP’s initial public offering, MRD LLC entered into an omnibus agreement with MEMP and its general partner. We succeeded to all of MRD LLC’s duties and obligations under the omnibus agreement.

Pursuant to the omnibus agreement, MEMP is required to reimburse us for all expenses incurred by us (or payments made on MEMP’s behalf) in conjunction with our provision of general and administrative services to MEMP, including, but not limited to, public company expenses and an allocated portion of the salary and benefits of the executive officers of MEMP’s general partner and our other employees who perform services for MEMP or on MEMP’s behalf. MEMP is also obligated to reimburse us for insurance coverage expenses we incur with respect to MEMP’s business and operations and with respect to director and officer liability coverage for the officers and directors of MEMP’s general partner.

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MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Beta Management Agreement

On December 12, 2012, MRD LLC entered into a management agreement with its wholly-owned subsidiary, Beta Operating Company, LLC pursuant to which MRD LLC agreed to provide management and administrative oversight with respect to the services provided by such subsidiary under certain operating agreements with a subsidiary of MEMP, in exchange for an annual management fee. We succeeded to this management agreement and we will receive approximately $0.4 million from MEMP annually under that agreement.

Services Agreement

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

WHR Management Company may only terminate the services agreement by providing 90-days prior written notice to us after the six-month anniversary of the date of the agreement. We may terminate the services agreement at any time by providing written notice to WHR Management Company. The services agreement may only be assigned by either party with the other party’s consent. Upon the closing of our initial public offering, WHR Management Company became a subsidiary of WildHorse Resources II, LLC, an affiliate of the Company. NGP and certain former management members of WildHorse Resources own WildHorse Resources II, LLC.

Gas Processing Agreement

On March 17, 2014, WildHorse Resources entered into a gas processing agreement with PennTex North Louisiana, LLC (“PennTex”). PennTex is a joint venture among certain affiliates of NGP in which MRD Holdco, through its subsidiary MRD Midstream LLC, owns a minority interest. Once PennTex’s processing plant becomes operational, it will process natural gas produced from wells located on certain leases owned by WildHorse Resources in the state of Louisiana. The agreement has a 15-year primary term, subject to one-year extensions at either party’s election. WildHorse Resources will pay PennTex a monthly fee, subject to an annual inflationary escalation, based on volumes of natural gas delivered and processed. Once the plant is declared operational, WildHorse Resources will be obligated to pay a minimum processing fee equal to approximately $18.3 million on an annual basis, subject to certain adjustments and conditions. The gas processing agreement requires that the processing plant be operational no later than November 1, 2015.

Classic Pipeline Gas Gathering Agreement & Water Disposal Agreement

On November 1, 2011, Classic Hydrocarbons Operating, LLC (“Classic Operating”), which became our wholly-owned subsidiary in connection with the restructuring transactions, and Classic Pipeline entered into a gas gathering agreement. Pursuant to the gas gathering agreement, Classic Operating dedicated to Classic Pipeline all of the natural gas produced (up to 50,000 MMBtus per day) on the properties operated by Classic Operating within certain counties in Texas through 2020, subject to one-year extensions at either party’s election. On May 1, 2014, Classic Operating and Classic Pipeline amended the gas gathering agreement with respect to Classic Operating’s remaining assets located in Panola and Shelby Counties, Texas. Under the amended gas gathering agreement, Classic Operating agreed to pay a fee of (i) $0.30 per MMBtu, subject to an annual 3.5% inflationary escalation, based on volumes of natural gas delivered and processed, and (ii) $0.07 per MMBtu per stage of compression plus its allocated share of compressor fuel. The amended gas gathering agreement has a term until December 31, 2023, subject to one-year extensions at either party’s election.

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

39

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Note 14.  Business Segment Data

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

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

· MRD—reflects the combined operations of the Company, MRD LLC, WildHorse Resources and its previous owners, Classic and Classic GP, Black Diamond, BlueStone, Beta Operating and MEMP GP.

· MEMP—reflects the combined operations of MEMP, its previous owners, and historical dropdown transactions that occurred between MEMP and other MRD LLC consolidating subsidiaries.

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

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

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

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

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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, 2014	$	98,342		$	147,243		$	(92	)	$	245,493
Three months ended September 30, 2013		60,294			93,240			(19	)		153,515
Nine months ended September 30, 2014		301,492			371,530			(137	)		672,885
Nine months ended September 30, 2013		171,361			251,516			(136	)		422,741
Adjusted EBITDA: (1)
Three months ended September 30, 2014		83,388			90,045			22			173,455
Three months ended September 30, 2013		56,836			58,623			(18,447	)		97,012
Nine months ended September 30, 2014		247,335			218,842			(18,912	)		447,265
Nine months ended September 30, 2013		153,679			157,160			(19,554	)		291,285
Segment assets: (2)
As of September 30, 2014		1,232,146			2,749,452			40,069			4,021,667
As of December 31, 2013		1,281,134			1,552,307			(4,280	)		2,829,161
Total cash expenditures for additions to long-lived assets:
Nine months ended September 30, 2014		(276,982	)		(1,273,157	)		—			(1,550,139	)
Nine months ended September 30, 2013		(198,220	)		(165,403	)		—			(363,623	)

(1)Adjustments and eliminations for the three and nine months ended September 30, 2014 and 2013 include amounts related to the MRD's Segment equity investments in the MEMP Segment as well as the elimination of less than $0.1 million and $6.1 million of cash distributions that MEMP paid MRD for the three and nine months ended September 30, 2014, respectively, and $6.4 million and $19.1 million of cash distributions that MEMP paid MRD LLC for the three and nine months ended September 30, 2013, respectively, related to MRD LLC's partnership interests in MEMP.

(2)Adjustments and eliminations primarily represent the elimination of the MRD's Segment equity investments in the MEMP Segment.  The adjustment at September 30, 2014 and December 31, 2013 also includes $47.3 million and $49.9 million, respectively related to an impairment recognized by the MEMP Segment during 2013.  This impairment did not exist on a consolidated basis.

Calculation of Reportable Segments’ Adjusted EBITDA

	For the Three Months
	Ended September 30, 2014
							Combined
	MRD			MEMP			Totals
	(In thousands)
Net income (loss)	$	9,866		$	103,226		$	113,092
Interest expense, net		9,886			26,459			36,345
Income tax expense (benefit)		25,834			—			25,834
DD&A		39,550			43,928			83,478
Impairment of proved oil and natural gas properties		—			67,181			67,181
Accretion of AROs		170			1,383			1,553
(Gain) loss on commodity derivative instruments		(33,090	)		(156,402	)		(189,492	)
Cash settlements received (paid) on commodity derivative instruments		3,699			876			4,575
Acquisition 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	$	83,388		$	90,045		$	173,433

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MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

	For the Three Months
	Ended September 30, 2013
							Combined
	MRD			MEMP			Totals
				(In thousands)
Net income (loss)	$	73,874		$	(39,039	)	$	34,835
Interest expense, net		9,041			11,574			20,615
Income tax expense (benefit)		1,147			97			1,244
DD&A		20,476			24,660			45,136
Impairment of proved oil and natural gas properties		—			50,310			50,310
Accretion of AROs		178			1,176			1,354
(Gain) loss on commodity derivative instruments		213			1,815			2,028
Cash settlements received (paid) on commodity derivative instruments		3,368			3,678			7,046
(Gain) loss on sale of properties		(90,083	)		20			(90,063	)
Acquisition related costs		667			2,310			2,977
Incentive-based compensation expense		19,069			1,237			20,306
Non-cash compensation expense		—			(68	)		(68	)
Exploration costs		439			853			1,292
Non-cash equity (income) loss from MEMP		12,058			—			12,058
Cash distributions from MEMP		6,389			—			6,389
Adjusted EBITDA	$	56,836		$	58,623		$	115,459

	For the Nine Months
	Ended September 30, 2014
							Combined
	MRD			MEMP			Totals
				(In thousands)
Net income (loss)	$	(930,149	)	$	(45,037	)	$	(975,186	)
Interest expense, net		44,355			60,573			104,928
Loss on extinguishment of debt		37,248			—			37,248
Income tax expense (benefit)		14,323			75			14,398
DD&A		107,496			105,830			213,326
Impairment of proved oil and natural gas properties		—			67,181			67,181
Accretion of AROs		495			4,106			4,601
(Gain) loss on commodity derivative instruments		(17,130	)		28,710			11,580
Cash settlements received (paid) on commodity derivative instruments		(4,930	)		(14,999	)		(19,929	)
(Gain) loss on sale of properties		3,057			—			3,057
Acquisition 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
Provision for environmental remediation		—			2,852			2,852
Non-cash equity (income) loss from MEMP		12,844			—			12,844
Cash distributions from MEMP		6,068			—			6,068
Adjusted EBITDA	$	247,335		$	218,842		$	466,177

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MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

	For the Nine Months
	Ended September 30, 2013
							Combined
	MRD			MEMP			Totals
				(In thousands)
Net income (loss)	$	114,628		$	9,359		$	123,987
Interest expense, net		15,947			26,047			41,994
Income tax expense (benefit)		1,147			285			1,432
DD&A		62,605			69,723			132,328
Impairment of proved oil and natural gas properties		—			50,310			50,310
Accretion of AROs		547			3,469			4,016
(Gain) loss on commodity derivative instruments		(8,361	)		(21,195	)		(29,556	)
Cash settlements received (paid) on commodity derivative instruments		9,125			14,081			23,206
(Gain) loss on sale of properties		(83,370	)		(2,848	)		(86,218	)
Acquisition related costs		1,651			3,422			5,073
Incentive-based compensation expense		19,069			2,322			21,391
Non-cash compensation expense		—			1,057			1,057
Exploration costs		1,137			1,128			2,265
Non-cash equity (income) loss from MEMP		454			—			454
Cash distributions from MEMP		19,100			—			19,100
Adjusted EBITDA	$	153,679		$	157,160		$	310,839

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						For the Nine Months
	Ended September 30,						Ended September 30,
	2014			2013			2014			2013
Total Reportable Segments' Adjusted EBITDA	$	173,433		$	115,459		$	466,177		$	310,839
Adjustments to reconcile Adjusted EBITDA to net income (loss):
Interest expense, net		(36,345	)		(20,615	)		(104,928	)		(41,994	)
Loss on extinguishment of debt		—			—			(37,248	)		—
Income tax benefit (expense)		(25,834	)		(1,244	)		(14,398	)		(1,432	)
DD&A		(84,447	)		(45,136	)		(215,906	)		(132,328	)
Impairment of proved oil and natural gas properties		(67,181	)		(21	)		(67,181	)		(21	)
Accretion of AROs		(1,553	)		(1,354	)		(4,601	)		(4,016	)
Gains (losses) on commodity derivative instruments		189,492			(2,028	)		(11,580	)		29,556
Cash settlements paid (received) on commodity derivative instruments		(4,575	)		(7,046	)		19,929			(23,206	)
Gain (loss) on sale of properties		—			90,063			(3,057	)		86,218
Acquisition related costs		(1,425	)		(2,977	)		(5,480	)		(5,073	)
Incentive-based compensation expense		(29,289	)		(20,306	)		(976,264	)		(21,391	)
Non-cash compensation expense		—			68			—			(1,057	)
Exploration costs		(175	)		(1,292	)		(1,465	)		(2,265	)
Provision for environmental remediation		—			—			(2,852	)		—
Cash distributions from MEMP		(64	)		(6,389	)		(6,068	)		(19,100	)
Other non-cash equity (income) loss		—			(1,220	)		—			(430	)
Net income (loss)	$	112,037		$	95,962		$	(964,922	)	$	174,300

43

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):

	For the Three Months
	Ended September 30, 2014
	MRD			MEMP			Other, Adjustments & Eliminations			Consolidated & Combined Totals
Revenues:
Oil & natural gas sales	$	98,337		$	145,824		$	—		$	244,161
Other revenues		5			1,419			(92	)		1,332
Total revenues		98,342			147,243			(92	)		245,493
Costs and expenses:
Lease operating		6,991			39,312			(92	)		46,211
Pipeline operating		—			431			—			431
Exploration		133			42			—			175
Production and ad valorem taxes		3,571			10,469			—			14,040
Depreciation, depletion, and amortization		39,550			43,928			969			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		9,982			11,214			—			21,196
Accretion of asset retirement obligations		170			1,383			—			1,553
(Gain) loss on commodity derivative instruments		(33,090	)		(156,402	)		—			(189,492	)
(Gain) loss on sale of properties		—			—			—			—
Total costs and expenses		52,857			17,558			877			71,292
Operating income (loss)		45,485			129,685			(969	)		174,201
Other income (expense):
Interest expense, net		(9,886	)		(26,459	)		—			(36,345	)
Loss on extinguishment of debt		—			—			—			—
Earnings from equity investments		86			—			(86	)		—
Other, net		15			—			—			15
Total other income (expense)		(9,785	)		(26,459	)		(86	)		(36,330	)
Income (loss) before income taxes		35,700			103,226			(1,055	)		137,871
Income tax benefit (expense)		(25,834	)		—			—			(25,834	)
Net income (loss)	$	9,866		$	103,226		$	(1,055	)	$	112,037

44

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

	For the Three Months
	Ended September 30, 2013
	MRD			MEMP			Other, Adjustments & Eliminations			Consolidated & Combined Totals
Revenues:
Oil & natural gas sales	$	60,179		$	92,583		$	—		$	152,762
Other revenues		115			657			(19	)		753
Total revenues		60,294			93,240			(19	)		153,515
Costs and expenses:
Lease operating		6,144			23,334			(83	)		29,395
Pipeline operating		—			394			—			394
Exploration		439			853			—			1,292
Production and ad valorem taxes		1,354			6,068			—			7,422
Depreciation, depletion, and amortization		20,476			24,660			—			45,136
Impairment of proved oil and natural gas properties		—			50,310			(50,289	)		21
Incentive unit compensation expense		19,069			—			—			19,069
General and administrative		7,653			11,928			65			19,646
Accretion of asset retirement obligations		178			1,176			—			1,354
(Gain) loss on commodity derivative instruments		213			1,815			—			2,028
(Gain) loss on sale of properties		(90,083	)		20			—			(90,063	)
Other, net		—			50			(26	)		24
Total costs and expenses		(34,557	)		120,608			(50,333	)		35,718
Operating income (loss)		94,851			(27,368	)		50,314			117,797
Other income (expense):
Interest expense, net		(9,041	)		(11,574	)		—			(20,615	)
Earnings from equity investments		(10,838	)		—			10,838			—
Other, net		49			—			(25	)		24
Total other income (expense)		(19,830	)		(11,574	)		10,813			(20,591	)
Income (loss) before income taxes		75,021			(38,942	)		61,127			97,206
Income tax benefit (expense)		(1,147	)		(97	)		—			(1,244	)
Net income (loss)	$	73,874		$	(39,039	)	$	61,127		$	95,962

45

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

	For the Nine Months
	Ended September 30, 2014
	MRD			MEMP			Other, Adjustments & Eliminations			Consolidated & Combined Totals
Revenues:
Oil & natural gas sales	$	300,931		$	368,370		$	—		$	669,301
Other revenues		561			3,160			(137	)		3,584
Total revenues		301,492			371,530			(137	)		672,885
Costs and expenses:
Lease operating		18,657			93,367			(137	)		111,887
Pipeline operating		—			1,596			—			1,596
Exploration		1,213			252			—			1,465
Production and ad valorem taxes		10,494			23,129			—			33,623
Depreciation, depletion, and amortization		107,496			105,830			2,580			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		29,301			31,760			—			61,061
Accretion of asset retirement obligations		495			4,106			—			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		1,122,973			355,919			2,443			1,481,335
Operating income (loss)		(821,481	)		15,611			(2,580	)		(808,450	)
Other income (expense):
Interest expense, net		(44,355	)		(60,573	)		—			(104,928	)
Loss on extinguishment of 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 (loss) before income taxes		(915,826	)		(44,962	)		10,264			(950,524	)
Income tax benefit (expense)		(14,323	)		(75	)		—			(14,398	)
Net income (loss)	$	(930,149	)	$	(45,037	)	$	10,264		$	(964,922	)

46

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

	For the Nine Months
	Ended September 30, 2013
	MRD			MEMP			Other, Adjustments & Eliminations			Consolidated & Combined Totals
Revenues:
Oil & natural gas sales	$	171,013		$	249,844		$	—		$	420,857
Other revenues		348			1,672			(136	)		1,884
Total revenues		171,361			251,516			(136	)		422,741
Costs and expenses:
Lease operating		17,065			64,922			(241	)		81,746
Pipeline operating		—			1,343			—			1,343
Exploration		1,137			1,128			—			2,265
Production and ad valorem taxes		8,563			14,915			—			23,478
Depreciation, depletion, and amortization		62,605			69,723			—			132,328
Impairment of proved oil and natural gas properties		—			50,310			(50,289	)		21
Incentive unit compensation expense		19,069			—			—			19,069
General and administrative		22,466			33,411			105			55,982
Accretion of asset retirement obligations		547			3,469			—			4,016
(Gain) loss on commodity derivative instruments		(8,361	)		(21,195	)		—			(29,556	)
(Gain) loss on sale of properties		(83,370	)		(2,848	)		—			(86,218	)
Other, net		(25	)		647			—			622
Total costs and expenses		39,696			215,825			(50,425	)		205,096
Operating income (loss)		131,665			35,691			50,289			217,645
Other income (expense):
Interest expense, net		(15,947	)		(26,047	)		—			(41,994	)
Earnings from equity investments		(24	)		—			24			—
Other, net		81			—			—			81
Total other income (expense)		(15,890	)		(26,047	)		24			(41,913	)
Income before income taxes		115,775			9,644			50,313			175,732
Income tax benefit (expense)		(1,147	)		(285	)		—			(1,432	)
Net income (loss)	$	114,628		$	9,359		$	50,313		$	174,300

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, 2014 and December 31, 2013, we had $2.3 million and $0.6 million of environmental reserves recorded on our balance sheets, respectively.  During the nine months ended September 30, 2014, MEMP recorded $2.9 million of estimated environmental remediation expenses associated with its Permian and Wyoming oil and gas properties.  These expenses are reflected as a component of lease operating expenses on our statement of operations.  Environmental costs for remediation are accrued when environmental remediation efforts are probable and the costs can be reasonably estimated.  Such accruals are based on management’s best estimate of the ultimate cost to remediate a site and are adjusted as further information and circumstances develop.  Those estimates may change substantially depending on information about the nature and extent of contamination, appropriate remediation technologies and regulatory approvals.

47

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Supplemental Bond for Decommissioning Liabilities Trust Agreement

The trust account is held by Rise Energy Operating, LLC (“REO”), a wholly-owned subsidiary of MEMP, 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, 2014 (in thousands):

	Amortized
Investment	Cost
U.S. Bank Money Market Cash Equivalent	$	133,275
Less: Outside working interest owners share		(64,305	)
	$	68,970

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

June 30, 2015	$	72,450
June 30, 2016	$	76,590
December 31, 2016	$	78,660

As of September 30, 2014, the maximum remaining obligation net to REO’s interest was approximately $9.7  million.

Purchase Commitment Assumed

At September 30, 2014, MEMP had a CO₂ purchase commitment with a third party that was assumed in its Wyoming Acquisition. The table below outlines MEMP’s purchase commitment under the contract for the remainder of 2014 and annually thereafter (in thousands):

			Payment or Settlement due by Period
Purchase commitment	Total		Remainder 2014		2015		2016		2017		2018		Thereafter
CO2 minimum purchase commitment:
Estimated payment obligation	$	62,103	$	3,203	$	12,222	$	12,101	$	11,624	$	7,872	$	15,081

Processing Plant Expansions by Third Party Gatherer

In 2012, WildHorse Resources contracted with Regency Field Services LLC (the “Gatherer”) to expand their Dubach processing plant by up to 70 MMcf per day among other facility and infrastructure improvements. The expansion project was complete and fully operational by July 2013. WildHorse Resources will pay a payback demand fee until the payback demand fees received by the Gatherer plus any third party fees equal 110% of the new facility cost. For each month from the commencement date through the month in which the payout date occurs, WildHorse Resources will pay a payback demand fee equal to the monthly demand quantity (136,200 MMBtu per day) times $0.26 per MMBtu. In addition, for each MMBtu gathered in excess of the demand quantity, WildHorse Resources will pay a payback demand fee of $0.26 per MMBtu. The contract with the Gatherer for the Dubach processing plant was amended effective February 1, 2014 where the payback demand fee for the Dubach processing plant increased from $0.26 to $0.275 cents per MMbtu.

In 2013, WildHorse Resources contracted with the Gatherer to build a new high pressure pipeline from the dedicated area to the Gatherer’s Dubberly processing plant in Webster Parish, LA amongst other pipeline and infrastructure improvements. The expansion project was complete and fully operational by mid-December 2013. WildHorse Resources will pay a payback demand fee until the payback demand fees received by the Gatherer plus any third party fees equal to 110% of the pipeline and infrastructure improvement costs. For each month from the commencement date through the month in which the payout date occurs, WildHorse Resources will pay a payback demand fee equal to the monthly demand fee times $0.31 per MMBtu. In addition, for each MMBtu gathered in excess of the demand quantity, WildHorse Resources will pay a payback demand fee of $0.31 per MMBtu. The monthly demand quantity is 56,750 MMBtu per day from the Dubberly start-up date through one full year thereafter and then increasing to 113,500 MMBtu per

48

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

day until payout. The contract with the Gatherer for the new high pressure pipeline was amended effective February 1, 2014 where the payback demand fee decreased from $0.31 to $0.275 cents per MMbtu.

WildHorse Resources’ minimum commitments to the Gatherer, before other owner contributions, as of September 30, 2014 were as follows (in thousands):

	Dubach		Dubberly
2014	$	3,446	$	1,436
2015		13,671		11,393
2016		13,709		11,424
2017		13,671		11,393
2018		12,772		10,643
Total	$	57,269	$	46,289

Related Party Agreements

On March 17, 2014, WildHorse Resources entered into a gas processing agreement with PennTex. See Note 13 for additional information.

Classic Operating entered into a gas gathering agreement and water disposal agreement with Classic Pipeline. See Note 13 for additional information.

Note 16.  Subsequent Events

Common Control Transaction

On October 1, 2014, MRD sold certain oil and natural gas properties in Colorado to MEMP for a purchase price of $15 million, subject to customary post-closing adjustments.  The properties are located in Weld County, Colorado in the Wattenberg Field. The properties are 100% non-operated and included interests in 74 gross wells. The transaction had an effective date of October 1, 2014 and was funded with borrowings under MEMP’s revolving credit facility. The transaction was approved by our Board and its audit committee, which is comprised entirely of independent directors.

MRD Revolving Credit Facility

On October 3, 2014, the borrowing base under our credit facility was increased. For additional information regarding MRD’s revolving credit facility, see Note 8.

MEMP Revolving Credit Facility

On October 10, 2014, the borrowing base under the MEMP credit facility was redetermined and increased. For additional information regarding MEMP’s revolving credit facility, see Note 8.

Terryville Mineral & Royalty Partners LP

On November 4, 2014, the Company’s wholly-owned subsidiary, Terryville Mineral & Royalty Partners LP (“TRVL”), filed a registration statement on Form S-1 with the SEC in connection with its proposed initial public offering of common units representing limited partner interests. In connection with the closing of the proposed offering, the Company will contribute to TRVL certain overriding royalty interests in approximately 27,000 gross acres in the Terryville Complex in exchange for limited partner interests in TRVL.  The royalty interests will entitle TRVL to receive 7% of gross revenues from production within such acreage on all of the Company’s existing horizontal producing wells and future wells completed by the Company. TRVL intends to distribute the net proceeds from the proposed offering to the Company.  A registration statement relating to these securities has been filed with the SEC but has not yet become effective. These securities may not be sold nor may any offers to buy be accepted prior to the time the registration statement becomes effective, and this report does not constitute an offer to sell or a solicitation of any offers to buy these securities.

49

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 initial public offering prospectus dated June 12, 2014 filed with the SEC on June 16, 2014 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 a Delaware corporation formed by Memorial Resource Development LLC (“MRD LLC”) in January 2014 engaged in the acquisition, exploitation, and development of natural gas, NGL and oil properties primarily in North Louisiana and East Texas. MRD LLC, our accounting predecessor, was a Delaware limited liability company formed on April 27, 2011 by Natural Gas Partners VIII, L.P. (“NGP VIII”), Natural Gas Partners IX, L.P. (“NGP IX”) and NGP IX Offshore Holdings, L.P. (“NGP IX Offshore”) (collectively, the “Funds”) to own, acquire, exploit and develop oil and natural gas properties. The Funds are private equity funds managed by Natural Gas Partners (“NGP”).

We completed our initial public offering on June 18, 2014. In connection with the closing of our initial public offering, MRD LLC contributed to us substantially all of its assets, comprised of the following, in exchange for shares of our common stock (which were distributed to MRD LLC’s sole member, MRD Holdco LLC (“MRD Holdco”)): (1) 100% of its ownership interests in 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”), MRD Operating LLC (“MRD Operating”) and Memorial Production Partners GP LLC (“MEMP GP”), which owns a 0.1% general partner interest and 50% of the incentive distribution rights in Memorial Production Partners LP (“MEMP”), and (2) its 99.9% membership interest in WildHorse Resources, LLC (“WildHorse Resources”). In addition, certain former management members of WildHorse Resources contributed to us the remaining 0.1% membership interest in WildHorse Resources, and also exchanged their incentive units in WildHorse Resources, for shares of our common stock and cash consideration. As a result, we are majority-owned by the group consisting of MRD Holdco and certain former management members of WildHorse Resources.

Following the completion of our initial public offering, MRD LLC distributed to MRD Holdco (i) its interests in BlueStone Natural Resources Holdings, LLC (“BlueStone”), MRD Royalty LLC (“MRD Royalty”), MRD Midstream LLC (“MRD Midstream”), Golden Energy Partners LLC (“Golden Energy”) and Classic Pipeline & Gathering, LLC (“Classic Pipeline”), (ii) the MEMP subordinated units; (iii) the remaining cash released from its debt service reserve account in connection with the redemption of the 10.00% /10.75% Senior PIK Toggle Notes due 2018 (the “PIK notes”); and (iv) approximately $6.7 million of cash received by MRD LLC in connection with the sale of Golden Energy’s assets in May 2014. We 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.

As part of the restructuring transactions, we merged Black Diamond into MRD Operating in connection with the completion of our initial public offering, and MRD LLC was merged into MRD Operating upon the termination of the PIK notes indenture on June 27, 2014.

We control MEMP through the ownership of MEMP GP. MEMP is a publicly traded limited partnership engaged in the acquisition, production and development of oil and natural gas properties in the United States. Due to our control of MEMP through the ownership of MEMP GP, we are required to consolidate MEMP for accounting and financial reporting purposes. Although consolidated for accounting and financial reporting, we each have independent capital structures.  MRD LLC previously received cash distributions from MEMP as a result of its partner interests and incentive distribution rights in MEMP, when declared and paid by MEMP.  We will continue to receive cash distributions from MEMP as a result of our 0.1% general partner interest and incentive distribution rights in MEMP, when declared and paid by MEMP.

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 of this quarterly report.

50

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

· MRD—reflects the combined operations of the Company, MRD LLC, WildHorse Resources and its previous owners, Classic and Classic GP, Black Diamond, BlueStone, Beta Operating and MEMP GP.

· MEMP—reflects the combined operations of MEMP, its previous owners, and historical dropdown transactions that occurred between MEMP and other MRD LLC consolidating subsidiaries.

Segment financial information has been retrospectively revised for the following material common control transactions between MEMP and MRD LLC for comparability purposes:

· acquisition by MEMP of all the outstanding membership interests in Tanos Energy, LLC (“Tanos”) for a purchase price of approximately $77.4 million on October 1, 2013;

· acquisition by MEMP of all the outstanding membership interests in Prospect Energy, LLC (“Prospect Energy”) from Black Diamond for a purchase price of approximately $16.3 million on October 1, 2013;

· acquisition by MEMP of certain of the oil and natural gas properties in Jackson County, Texas from MRD LLC for a purchase price of approximately $2.6 million on October 1, 2013; and

· acquisition by MEMP of all the outstanding membership interests in WHT Energy Partners LLC(“WHT”) for a purchase price of approximately $200.0 million on March 28, 2013.

The MRD Segment is focused on the exploitation, development, and acquisition of natural gas, NGL and oil properties mainly in the Cotton Valley formation in North Louisiana and East Texas as well as the Rocky Mountains. 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, Classic Pipeline, the MEMP subordinated units and cash held in a  debt service reserve account that had been established when the PIK notes were issued in December 2013.

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 principally located in East Texas/North Louisiana, the Permian Basin, offshore Southern California, the Rockies, and the Eagle Ford/South Texas. 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.

Significant Recent Developments

There were no significant recent developments subsequent to September 30, 2014 through the filing date of this filing, except for the following:

Terryville Mineral & Royalty Partners LP

On November 4, 2014, the Company’s wholly-owned subsidiary, Terryville Mineral & Royalty Partners LP (“TRVL”), filed a registration statement on Form S-1 with the SEC in connection with its proposed initial public offering of common units representing limited partner interests. In connection with the closing of the proposed offering, the Company will contribute to TRVL certain overriding royalty interests in approximately 27,000 gross acres in the Terryville Complex in exchange for limited partner interests in TRVL.  The royalty interests will entitle TRVL to receive 7% of gross revenues from production within such acreage on all of the Company’s existing horizontal producing wells and future wells completed by the Company. TRVL intends to distribute the net proceeds from the proposed offering to the Company.  A registration statement relating to these securities has been filed with the SEC but has not yet become effective. These securities may not be sold nor may any offers to buy be accepted prior to the time the registration statement becomes effective, and this report does not constitute an offer to sell or a solicitation of any offers to buy these securities.

51

Sources of Revenues

Both the MRD and MEMP Segment’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 segments intend to periodically enter into derivative contracts with respect to a significant portion of their estimated natural gas and oil production through various transactions that fix the future prices received. These transactions may include price swaps whereby the applicable segment will receive a fixed price for production and pay a variable market price to the contract counterparty. Additionally, either segment may enter into costless collars, whereby the applicable segment receives the excess, if any, of the fixed floor over the floating rate or pay the excess, if any, of the floating rate over the fixed ceiling price. 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.

· 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 the MRD and MEMP Segments 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 and unsuccessful leasing efforts.

· Impairment of unprovedand proved properties. For unproved properties, these primarily include costs associated with lease expirations. 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, NGLs and oil. 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 the MRD and MEMP Segments finance a portion of their working capital requirements and acquisitions with borrowings under revolving credit facilities and senior note issuances. As a result, both the MRD and MEMP Segments 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. Prior to our initial public offering, MRD LLC was organized as a pass-through entity for federal income tax purposes and was not subject to federal income taxes; however, certain of its consolidating subsidiaries were taxed as corporations and subject to federal income taxes.  We are organized as a taxable C corporation and subject to federal and certain state income taxes.  We are also subject to the Texas margin tax and certain aspects of the tax make it similar to an income tax as the tax is assessed on 1% of taxable margin apportioned to operations in Texas.

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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

Consolidated

Selected consolidated and combined results of operations for the three and nine months ended September 30, 2014 and 2013 are presented below and have been derived from our consolidated and combined financial statements included under Item 1 of this quarterly report

	For Three Months Ended September 30,						For Nine Months Ended September 30,
	2014			2013			2014			2013
	(in thousands)
Oil & natural gas sales	$	244,161		$	152,762		$	669,301		$	420,857
Lease operating		46,211			29,395			111,887			81,746
Exploration		175			1,292			1,465			2,265
Production and ad valorem taxes		14,040			7,422			33,623			23,478
Depreciation, depletion, and amortization		84,447			45,136			215,906			132,328
Impairment of proved oil and natural gas properties		67,181			21			67,181			21
Incentive unit compensation expense		25,550			19,069			969,390			19,069
General and administrative		21,196			19,646			61,061			55,982
(Gain) loss on commodity derivative instruments		(189,492	)		2,028			11,580			(29,556	)
(Gain) loss on sale of properties		—			(90,063	)		3,057			(86,218	)
Interest expense, net		(36,345	)		(20,615	)		(104,928	)		(41,994	)
Loss on extinguishment of debt		—			—			(37,248	)		—
Net income (loss)		112,037			95,962			(964,922	)		174,300

Three Months Ended September 30, 2014 Compared to the Three Months Ended September 30, 2013

Net income of $112.0 million was generated for the three months ended September 30, 2014 compared to net income of $96.0 million for the three months ended September 30, 2013.  

· Oil, natural gas and NGL revenues for 2014 totaled $244.2 million, an increase of $91.4 million compared with 2013. Production increased 13.4 Bcfe (approximately 49%) primarily due to acquisitions and drilling activities in North Louisiana and East Texas. The average realized sales price increased $0.41 per Mcfe primarily due to higher natural gas prices.  The favorable volume and pricing variance contributed to an approximate $74.8 million and $16.6 million increase in revenues, respectively.

· Lease operating expenses were $46.2 million and $29.4 million for 2014 and 2013, respectively, an increase of $16.8 million primarily due to increased production volumes.  On a per Mcfe basis, lease operating expenses increased to $1.14 for 2014 from $1.08 for 2013.

· DD&A expense for 2014 was $84.4 million compared to $45.1 million for 2013, a $39.3 million increase primarily due to both an increase in the depletable cost base and increased production volumes related to acquisitions and drilling activities in North Louisiana and East Texas. Increased production volumes caused DD&A expense to increase by an approximate $22.1 million and the change in the DD&A rate between periods caused DD&A expense to increase by an approximate $17.2 million.

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· Impairments for 2014 totaled $67.2 million primarily related to certain MEMP properties located in South Texas. The estimated future cash flows expected for 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. We recognized impairment charges of less than $0.1 million on a consolidated basis for 2013.

· Incentive unit compensation expense for 2014 was $25.6 million, which related to MRD Holdco incentive units and compensation expense of approximately $19.1 million was recorded by BlueStone in 2013. For more information regarding the recognition of compensation expense 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 expenses for 2014 were $21.2 million compared to $19.6 million for 2013. General and administrative expenses for 2014 included $3.7 million of compensation expense associated with long-term incentive plans and $1.4 million of acquisition-related costs.  General and administrative expenses for 2013 included $1.2 million of compensation expense associated with long-term incentive plans, and $3.0 million of acquisition-related costs. Increased salaries and employee headcount also contributed to increased general and administrative expenses between periods.

For more information regarding the recognition of compensation expense associated with long-term incentive plans and incentive units, see Notes 11 and 12 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under Item 1 of this quarterly report.

· Net gains on commodity derivative instruments of $189.5 million were recognized during 2014, consisting of $4.6 million of cash settlement receipts in addition to a $184.9 million increase in the fair value of open hedge positions. Net losses on commodity derivative instruments of $2.0 million were recognized during 2013, consisting of $7.0 million of cash settlement receipts, offset by a $9.0 million decrease 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.

· Interest expense was $36.3 million during 2014, an increase of $15.7 million from 2013. The increase in interest expense was primarily due to higher levels of indebtedness. The mix of debt was also a contributing factor. The MRD Senior Notes, MEMP’s 2022 Senior Notes and MEMP’s 2021 Senior Notes carry a higher interest rate compared to debt under revolving credit facilities.

· During 2013, BlueStone entered into an agreement with a third party to sell its remaining interest in certain properties and recognized a gain of $90.1 million.

Please see segment discussion below for further information regarding changes in other line items on a segment basis.

Nine Months Ended September 30, 2014 Compared to the Nine Months Ended September 30, 2013

A net loss of $964.9 million was generated for the nine months ended September 30, 2014 compared to net income of $174.3 million for nine months ended September 30, 2013. The net loss recorded during 2014 was primarily due to compensation expense recognized associated with incentive units as discussed below.

· Oil, natural gas and NGL revenues for 2014 totaled $669.3 million, an increase of $248.4 million compared with 2013.  Production increased 33.9 Bcfe (approximately 45%) primarily due to acquisitions and drilling activities in North Louisiana and East Texas. The average realized sales price increased $0.53 per Mcfe primarily due to higher natural gas prices.  The favorable volume and pricing variance contributed to an approximate $190.3 million and $58.2 million increase in revenues, respectively.

· Lease operating expenses were $111.9 million and $81.7 million for 2014 and 2013, respectively, an increase of $30.2 million primarily due to increased production volumes.  On a per Mcfe basis, lease operating expenses decreased to $1.03 for 2014 from $1.09 for 2013. During 2014, MEMP recorded $2.9 million of estimated environmental remediation expenses associated with its Permian and Wyoming oil and gas properties.

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· DD&A expense for 2014 was $215.9 million compared to $132.3 million for 2013, a $83.6 million increase primarily due to both an increase in the depletable cost base and increased production volumes related to acquisitions and drilling activities in North Louisiana and East Texas. Increased production volumes caused DD&A expense to increase by an approximate $59.8 million and the change in the DD&A rate between periods caused DD&A expense to increase by an approximate $23.8 million.

· Impairments for 2014 totaled $67.2 million primarily related to certain MEMP properties located in South Texas. The estimated future cash flows expected for 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. We recognized impairment charges of less than $0.1 million on a consolidated basis for 2013.

· Incentive unit compensation expense for 2014 was $969.4 million, 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. Incentive unit compensation expense of approximately $19.1 million was recorded by BlueStone in 2013. Net proceeds generated from the sale of oil and gas properties were used to pay a distribution to BlueStone incentive unit holders. For more information regarding the recognition of compensation expense associated with incentive units during 2014, 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 expenses for 2014 were $61.1 million compared to $56.0 million for 2013. General and administrative expenses for 2014 included $6.9 million of compensation expense associated with long-term incentive plans and $5.5 million of acquisition-related costs.  General and administrative expenses for 2013 included $5.8 million recorded by Tanos associated with incentive units forfeited, $2.3 million of compensation expense associated with long-term incentive plans and $5.1 million of acquisition-related costs.  Increased salaries and employee headcount also contributed to increased general and administrative expenses between periods. For more information regarding the recognition of compensation expense associated with long-term incentive plans and incentive units, see Notes 11 and 12 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under Item 1 of this quarterly report.

· Net losses on commodity derivative instruments of $11.6 million were recognized during 2014, consisting of $19.9 million of cash settlement payouts, offset by a $8.3 million increase in the fair value of open hedge positions. Net gain on commodity derivative instruments of $29.6 million were recognized during 2013, consisting of $23.2 million of cash settlement receipts in addition to a $6.4 million increase in the fair value of open hedge positions.

· Interest expense was $104.9 million during 2014, an increase of $62.9 million from 2013. The increase in interest expense was primarily due to higher levels of indebtedness. The mix of debt was also a contributing factor. The MRD Senior Notes, MEMP’s 2022 Senior Notes and MEMP’s 2021 Senior Notes carry a higher interest rate compared to debt under revolving credit facilities.

· We irrevocably deposited with the PIK notes trustee approximately $360.0 million on June 27, 2014, which was an amount sufficient to fund the redemption of the PIK notes on the redemption date and to satisfy and discharge our obligations under the PIK notes and the related indenture.  The discharge became effective upon the irrevocable deposit of the funds with the PIK notes trustee.  An extinguishment loss of $23.6 million was recognized related to the redemption of the PIK notes.

In connection with the closing of our initial public offering, the WildHorse Resources’ revolving credit facility and second lien term loan were repaid in full and terminated. An extinguishment loss of $13.7 million was recognized related to the termination of the revolving credit facility and second lien term loan.

· During 2013, BlueStone entered into an agreement with a third party to sell its remaining interest in certain properties and recognized a gain of $90.1 million. This gain was partially offset by a loss of $6.8 million recorded by Black Diamond on the sale of certain oil and gas properties.

Please see segment discussion below for further information regarding changes in other line items on a segment basis.

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MRD Segment

The MRD Segment’s consolidated and combined results of operations for the three and nine months ended September 30, 2014 and 2013 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 significant transactions:

· the sale of assets by BlueStone in East Texas in July 2013 for approximately $117.9 million;

· the acquisition by WildHorse Resources of assets in Louisiana in March 2013 for approximately $67.1 million; and

· the distribution by MRD LLC of the following to MRD Holdco as part of the restructuring transactions entered into in connection with our initial public offering: (i) BlueStone, which sold substantially all of its assets in July 2013 for $117.9 million, MRD Royalty LLC, which owns certain leasehold interests and overriding royalty interests in Texas and Montana, MRD Midstream LLC, which owns an indirect interest in certain midstream assets in North Louisiana, Golden Energy and Classic Pipeline and (ii) 5,360,912 subordinated units of MEMP.

Segment financial information has been retrospectively revised for material common control transactions between MEMP and MRD LLC for comparability purposes, which includes the following transactions:

· acquisition by MEMP of all the outstanding membership interests in Tanos for a purchase price of approximately $77.4 million on October 1, 2013;

· acquisition by MEMP of all the outstanding membership interests in Prospect from Black Diamond for a purchase price of approximately $16.3 million on October 1, 2013;

· acquisition by MEMP of certain of the oil and natural gas properties in Jackson County, Texas from MRD LLC for a purchase price of approximately $2.6 million on October 1, 2013; and

· acquisition by MEMP of all the outstanding membership interests in WHT for a purchase price of approximately $200.0 million on March 28, 2013.

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	For Three Months Ended September 30,						For Nine Months Ended September 30,
	2014			2013			2014			2013
	(in thousands)
Oil & natural gas sales	$	98,337		$	60,179		$	300,931		$	171,013
Lease operating		6,991			6,144			18,657			17,065
Exploration		133			439			1,213			1,137
Production and ad valorem taxes		3,571			1,354			10,494			8,563
Depreciation, depletion, and amortization		39,550			20,476			107,496			62,605
Incentive unit compensation cost		25,550			19,069			969,390			19,069
General and administrative		9,982			7,653			29,301			22,466
(Gain) loss on commodity derivative instruments		(33,090	)		213			(17,130	)		(8,361	)
(Gain) loss on sale of properties		—			(90,083	)		3,057			(83,370	)
Interest expense, net		(9,886	)		(9,041	)		(44,355	)		(15,947	)
Loss on extinguishment of debt		—			—			(37,248	)		—
Income tax benefit (expense)		(25,834	)		(1,147	)		(14,323	)		(1,147	)
Net income (loss)		9,866			73,874			(930,149	)		114,628
Natural gas and oil revenue:
Oil sales	$	20,234		$	16,456		$	66,495		$	50,683
NGL sales		22,082			16,745			67,539			37,311
Natural gas sales		56,021			26,978			166,897			83,019
Total natural gas and oil revenue	$	98,337		$	60,179		$	300,931		$	171,013
Production Volumes:
Oil (MBbls)		209			153			689			498
NGLs (MBbls)		586			437			1,612			990
Natural gas (MMcf)		16,729			8,991			43,075			25,164
Total (MMcfe)		21,503			12,523			56,869			34,075
Average net production (MMcfe/d)		233.7			136.1			208.3			124.8
Average sales price:
Oil (per Bbl)	$	96.65		$	108.44		$	96.60		$	101.77
NGL (per Bbl)		37.66			38.30			41.93			37.69
Natural gas (per Mcf)		3.35			3.00			3.87			3.30
Total (Mcfe)	$	4.57		$	4.81		$	5.29		$	5.02
Average unit costs per Mcfe:
Lease operating expense	$	0.33		$	0.49		$	0.33		$	0.50
Production and ad valorem taxes	$	0.17		$	0.11		$	0.18		$	0.25
General and administrative expenses	$	0.46		$	0.61		$	0.52		$	0.66
Depletion, depreciation, and amortization	$	1.84		$	1.64		$	1.89		$	1.84

Three Months Ended September 30, 2014 Compared to the Three Months Ended September 30, 2013

The MRD Segment recorded net income of $9.9 million during 2014 compared to net income of $73.9 million during 2013.

· Oil, natural gas and NGL revenues for 2014 totaled $98.3 million, an increase of $38.2 million compared with 2013.  Production increased 9.0 Bcfe (approximately 72%) primarily due to drilling activities in North Louisiana and East Texas. The average realized sales price decreased $0.24 per Mcfe primarily due to lower oil and NGL prices.  The volume and pricing variance contributed to an approximate $43.2 million increase and $5.0 million decrease in revenues, respectively.

· Lease operating expenses were $7.0 million and $6.1 million for 2014 and 2013, respectively.  On a per Mcfe basis, lease operating expenses decreased to $0.33 for 2014 from $0.49 for 2013. Certain items, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges.

· DD&A expense for 2014 was $39.6 million compared to $20.5 million for 2013, a $19.1 million increase primarily due to both an increase in the depletable cost base and increased production volumes related to drilling activities in North Louisiana and East Texas. Increased production volumes caused DD&A expense to increase by approximately $14.7 million and the change in the DD&A rate between periods caused DD&A expense to increase by approximately $4.4 million.

· Incentive unit compensation expense for 2014 was $25.6 million, million related to MRD Holdco incentive units as previously discussed above. Incentive unit compensation expense of approximately $19.1 million was recorded by

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BlueStone in 2013. Net proceeds generated from the sale of oil and gas properties were used to pay a distribution to BlueStone incentive unit holders

· General and administrative expenses for 2014 were $10.0 million compared to $7.7 million for 2013. General and administrative expenses for 2014 included $1.3 million of compensation expense associated with the Memorial Resource Development Corp. 2014 Long Term Incentive Plan (“MRD LTIP”) and $0.5 million of acquisition-related costs.  General and administrative expenses for 2013 included $0.7 million of acquisition-related costs, Increased salaries and employee headcount also contributed to increased general and administrative expenses between periods.

· Net gains on commodity derivative instruments of $33.1 million were recognized during 2014, consisting of $3.7 million of cash settlement receipts in addition to a $29.4 million increase in the fair value of open hedge positions. Net losses on commodity derivative instruments of $0.2 million were recognized during 2013, consisting of $3.4 million of cash settlement receipts, offset by a $3.6 million decrease in the fair value of open hedge positions.

· Net interest expense during 2014 was $9.9 million, including amortization of deferred financing fees of approximately $0.7 million. Net interest expense during 2013 was $9.0 million, including amortization of deferred financing fees of approximately $0.7 million. The increase in net interest expense is primarily the result of higher level of indebtedness during 2014 compared to 2013, including the MRD Senior Notes.

· During 2013, BlueStone entered into an agreement with a third party to sell its remaining interest in certain properties and recognized a gain of $90.1 million.

· We are organized as a taxable C corporation and subject to federal and certain state income taxes. We recorded tax expense of $25.8 million in 2014.

Nine Months Ended September 30, 2014 Compared to the Nine Months Ended September 30, 2013

The MRD Segment recorded a net loss of $930.1 million during 2014 compared to net income of $114.6 million during 2013. The net loss recorded during 2014 was primarily due to compensation expense recognized associated with incentive units as discussed below.

· Oil, natural gas and NGL revenues for 2014 totaled $300.9 million, an increase of $129.9 million compared with 2013.  Production increased 22.8 Bcfe (approximately 67%) primarily due to drilling activities in North Louisiana and East Texas. The average realized sales price increased $0.27 per Mcfe primarily due to higher natural gas and NGL prices.  The favorable volume and pricing variance contributed to an approximate $114.4 million and $15.5 million increase in revenues, respectively.

· Lease operating expenses were $18.7 million and $17.1 million for 2014 and 2013, respectively.  On a per Mcfe basis, lease operating expenses decreased to $0.33 for 2014 from $0.50 for 2013. Certain items, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges

· DD&A expense for 2014 was $107.5 million compared to $62.6 million for 2013, a $44.9 million increase primarily due to both an increase in the depletable cost base and increased production volumes related to drilling activities in North Louisiana and East Texas. Increased production volumes caused DD&A expense to increase by an approximate $41.9 million and the change in the DD&A rate between periods caused DD&A expense to decrease by an approximate $3.0 million.

· Incentive unit compensation expense for 2014 was $969.4 million, 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 as previously discussed above. Incentive unit compensation expense of approximately $19.1 million was recorded by BlueStone in 2013. Net proceeds generated from the sale of oil and gas properties were used to pay a distribution to BlueStone incentive unit holders.

· General and administrative expenses for 2014 were $29.3 million compared to $22.5 million for 2013. General and administrative expenses for 2014 included $1.5 million of compensation expense associated with the MRD LTIP and $1.6 million of acquisition-related costs.  General and administrative expenses for 2013 included $1.7 million of acquisition-related costs. Increased salaries and employee headcount also contributed to increased general and administrative expenses between periods.

· Net gains on commodity derivative instruments of $17.1 million were recognized during 2014, consisting of $4.9 million of cash settlement payouts offset by a $22.0 million increase in the fair value of open hedge positions. Net gains on

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commodity derivative instruments of $8.4 million were recognized during 2013, consisting of $9.1 million of cash settlement receipts offset by a $0.7 million decrease in the fair value of open hedge positions.

· Net interest expense during 2014 was $44.4 million, including amortization of deferred financing fees of approximately $2.6 million and accretion of discount associated with the PIK notes of $0.6 million. Net interest expense during 2013 was $15.9 million, including amortization of deferred financing fees of approximately $1.7 million. The increase in net interest expense is primarily the result of higher level of indebtedness during 2014 compared to 2013, including the MRD Senior Notes.

· During 2013, BlueStone entered into an agreement with a third party to sell its remaining interest in certain properties and recognized a gain of $90.1 million. This gain was offset by a loss of $6.8 million recorded by Black Diamond on the sale of certain oil and gas properties.

· We are organized as a taxable C corporation and subject to federal and certain state income taxes. We recorded tax expense of $14.3 million in 2014 subsequent to our initial public offering.

MEMP Segment

The MEMP Segment’s consolidated and combined results of operations for the three and nine months ended September 30, 2014 and 2013 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 transaction:

· the acquisition of certain oil and natural gas properties in the Eagle Ford trend from Alta Mesa Holdings, LP  in March 2014 for an adjusted purchase price of $168.1 million.

· the acquisition of certain oil and natural gas liquids properties from a third party in Wyoming on July 1, 2014 for an aggregate purchase price of approximately $911.7 million, including estimated post-closing adjustments (the “Wyoming Acquisition”).

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	For Three Months Ended September 30,						For Nine Months Ended September 30,
	2014			2013			2014			2013
	(in thousands)
Oil & natural gas sales	$	145,824		$	92,583		$	368,370		$	249,844
Lease operating		39,312			23,334			93,367			64,922
Exploration		42			853			252			1,128
Production and ad valorem taxes		10,469			6,068			23,129			14,915
Depreciation, depletion, and amortization		43,928			24,660			105,830			69,723
Impairment of proved oil and natural gas properties		67,181			50,310			67,181			50,310
General and administrative		11,214			11,928			31,760			33,411
(Gain) loss on commodity derivative instruments		(156,402	)		1,815			28,710			(21,195	)
(Gain) loss on sale of properties		—			20			—			(2,848	)
Interest expense, net		(26,459	)		(11,574	)		(60,573	)		(26,047	)
Net income (loss)		103,226			(39,039	)		(45,037	)		9,359
Natural gas and oil revenue:
Oil sales	$	89,378		$	48,377		$	192,086		$	127,436
NGL sales		19,937			13,053			48,958		$	35,202
Natural gas sales		36,509			31,153			127,326			87,206
Total natural gas and oil revenue	$	145,824		$	92,583		$	368,370		$	249,844
Production Volumes:
Oil (MBbls)		986			464			2,056			1,307
NGLs (MBbls)		554			443			1,498			1,147
Natural gas (MMcf)		9,948			9,361			30,625			26,137
Total (MMcfe)		19,188			14,805			51,946			40,861
Average net production (MMcfe/d)		208.6			160.9			190.3			149.7
Average sales price:
Oil (per Bbl)	$	90.63		$	104.25		$	93.45		$	97.50
NGL(per Bbl)		36.01			29.45			32.69			30.69
Natural gas (per Mcf)		3.67			3.33			4.16			3.34
Total (Mcfe)	$	7.60		$	6.25		$	7.09		$	6.11
Average unit costs per Mcfe:
Lease operating expense	$	2.05		$	1.58		$	1.80		$	1.59
Production and ad valorem taxes	$	0.55		$	0.41		$	0.45		$	0.37
General and administrative expenses	$	0.58		$	0.81		$	0.61		$	0.82
Depletion, depreciation, and amortization	$	2.29		$	1.67		$	2.04		$	1.71

Three Months Ended September 30, 2014 Compared to the Three Months Ended September 30, 2013

Net income of $103.2 million was generated for the three months ended September 30, 2014, primarily due to gains on commodity derivative instruments, which was partially offset by impairment expenses, compared to a net loss of $39.0 generated for three months ended September 30, 2013.

· Oil, natural gas and NGL revenues for 2014 totaled $145.8 million, an increase of $53.2 million compared with 2013.  Production increased 4.4 Bcfe (approximately 30%), primarily from increased drilling activities and increased volumes from third party acquisitions.  The average realized sales price increased $1.35 per Mcfe primarily due to higher natural gas prices and crude oil volumes.  The favorable volume and pricing variance contributed to an approximate $27.3 million and $25.9 million increase in revenues, respectively.

· Lease operating expenses were $39.3 million and $23.3 million for 2014 and 2013, respectively.  On a per Mcfe basis, lease operating expenses increased to $2.05 for 2014 from $1.58 for 2013. This increase was primarily due to the acquisition of crude oil properties, which typically have a higher lease operating rate on a per Mcfe basis than natural gas properties.

· Production and ad valorem taxes for 2014 totaled $10.5 million, an increase of $4.4 million compared with 2013 primarily due to an increase in production volumes. On a per Mcfe basis, production and ad valorem taxes increased to $0.55 for 2014 from $0.41 for 2013 due to higher production tax rates on a per Mcfe basis for MEMP’s Wyoming acquisition.

· DD&A expense for 2014 was $43.9 million compared to $24.7 million for 2013, a $19.2 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 an approximate $7.3 million and the change in the DD&A rate between periods caused DD&A expense to increase by an approximately $11.9 million.

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· MEMP recognized $67.2 million of impairments in 2014 related primarily 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 as a result of a downward revision of estimated proved reserves based on pricing terms specified to these properties and increased operating costs. During the three months ended September 30, 2013, the MEMP Segment recorded impairments of $50.3 million. The impairments related to certain properties located in East Texas. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable as a result of a downward revision of estimated proved reserves based on updated well performance data.

· General and administrative expenses for 2014 were $11.2 million and included $2.4 million of non-cash unit-based compensation expense and $0.9 million of acquisition-related costs.  General and administrative expenses for 2013 totaled $11.9 million and included $1.2 million of non-cash unit-based compensation expense and $2.3 million of acquisition-related costs.  

· Net gains on commodity derivative instruments of $156.4 million were recognized during 2014, consisting of $0.9 million of cash settlement receipts in addition to a $155.5 million increase in the fair value of open hedge positions. Net losses on commodity derivative instruments of $1.8 million were recognized during 2013, consisting of $3.7 million of cash settlement receipts offset by a $5.5 million decrease in the fair value of open hedge positions.

· Net interest expense totaled $26.5 million during 2014, including gains on interest rate swaps of approximately $0.2 million, amortization of deferred financing fees of approximately $1.2 million, and accretion of net discount associated with the senior notes of $0.6 million.  Net interest expense totaled $11.6 million during 2013, including losses on interest rate swaps of $1.5 million and amortization of deferred financing fees of approximately $0.7 million.  The increase in net interest expense is primarily the result of higher level of indebtedness during 2014 compared to 2013, including MEMP’s 2022 Senior Notes.

Nine Months Ended September 30, 2014 Compared to the Nine Months Ended September 30, 2013

A net loss of $45.0 million was generated for the nine months ended September 30, 2014, primarily due to impairment charges, as discussed below, and losses on commodity derivatives.  Net income of $9.4 million was generated for the nine months ended September 30, 2013.

· Oil, natural gas and NGL revenues for 2014 totaled $368.4 million, an increase of $118.5 million compared with 2013.  Production increased 11.1 Bcfe (approximately 27%), primarily from drilling activities and increased volumes from third party acquisitions.  The average realized sales price increased $0.98 per Mcfe primarily due to higher gas prices and an increase in oil volumes relative to other commodities due to MEMP’s acquisitions.  The favorable volume and pricing variance contributed to an approximate $67.7 million and $50.8 million increase in revenues, respectively.

· Lease operating expenses were $93.4 million and $64.9 million for the nine months ended September 30, 2014 and 2013, respectively.  On a per Mcfe basis, lease operating expenses increased to $1.80 for 2014 from $1.59 for 2013. During 2014, MEMP recorded $2.9 million of estimated environmental remediation expenses associated with its Permian and Wyoming oil and gas properties.

· Production and ad valorem taxes for 2014 totaled $23.1 million, an increase of $8.2 million compared with 2013 primarily due to an increase in production volumes. On a per Mcfe basis, production and ad valorem taxes increased to $0.45 for 2014 from $0.36 for 2013 due to higher production tax rates on a per Mcfe basis for MEMP’s Wyoming acquisition.

· DD&A expense for 2014 was $105.8 million compared to $69.7 million for 2013, a $36.1 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 an approximate $18.9 million and the change in the DD&A rate between periods caused DD&A expense to increase by an approximate $17.2 million.

· MEMP recognized $67.2 million of impairments in 2014 related primarily 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 as a result of a downward revision of estimated proved reserves based on pricing terms specified to these properties and increased operating costs. During 2013, the MEMP Segment recorded impairments of $50.3 million. The impairments related to certain properties located in East Texas. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable as a result of a downward revision of estimated proved reserves based on updated well performance data.

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· General and administrative expenses for 2014 were $31.8 million and included $5.4 million of non-cash unit-based compensation expense and $3.9 million of acquisition-related costs.  General and administrative expenses for 2013 totaled $33.4 million and included $2.3 million of non-cash unit-based compensation expense and $3.4 million of acquisition-related costs.  The $1.6 million decrease in general administrative expenses included a $5.8 million buyout of Tanos management during 2013 offset by increased salaries and employee count between periods.

· Net losses on commodity derivative instruments of $28.7 million were recognized during 2014, consisting of $15.0 million of cash settlement payouts in addition to a $13.7 million decline in the fair value of open hedge positions. Net gains on commodity derivative instruments of $21.2 million were recognized during 2013, consisting of $14.1 million of cash settlement receipts, in addition to a $7.1 million increase in the fair value of open hedge positions.

· Net interest expense is comprised of interest on credit facilities, interest on MEMP’s outstanding senior notes, amortization of debt issue costs, accretion of net discount associated with the senior notes, and gains and losses on interest rate swaps. Net interest expense totaled $60.6 million during 2014, including losses on interest rate swaps of approximately $0.9 million, amortization of deferred financing fees of approximately $2.9 million, and accretion of net discount associated with the senior notes of $1.3 million.  Net interest expense totaled $26.0 million during 2013, including gains on interest rate swaps of $0.2 million and amortization of deferred financing fees of approximately $4.5 million.  The increase in net interest expense is primarily the result of higher level of indebtedness during 2014 compared to 2013, including MEMP’s 2022 Senior Notes.

Liquidity and Capital Resources

Although results are consolidated for financial reporting, the MRD and MEMP Segments operate with independent capital structures. The cash needs of each segment have been met independently with a combination of operating cash flows, asset sales, credit facility borrowings, issuances of senior notes and the issuance of equity.

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 exploitation, development and acquisition of natural gas, NGLs 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. The future success in growing proved reserves and production will be highly dependent on the capital resources available. As of December 31, 2013, we had 1,582 identified gross potential horizontal well locations, which will take many years to develop. Additionally, the proved undeveloped reserves will require an estimated $1.3 billion of development capital over the next five years according to our reserve report as of December 31, 2013. A significant portion of this capital requirement will be funded out of operating cash flows. However, we may be required to generate or raise significant capital to conduct drilling activities on these identified potential well locations and to finance the development of proved undeveloped reserves.

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 or 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.

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 pursue our currently planned 2014 development drilling activities. However, future cash flows are subject to a number of variables, including the level of natural gas production and prices, and significant additional capital expenditures will be required to more fully develop our properties and acquire additional properties. We cannot assure you that operations and other needed capital will be available on acceptable terms, or at all.

As of September 30, 2014, our liquidity of $650.2 million consisted of $9.7 million of cash and cash equivalents and $640.5 million of available borrowings under our revolving credit facility. As of September 30, 2014, we had a working capital deficit balance of $17.8 million primarily due to the timing of accruals, which included accrued capital expenditures of $33.8 million offset by a net asset balance of $15.2 million of current derivative instruments.

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Capital Budget

In 2014, a total of $351.0 million is budgeted to drill 47 gross (39 net) operated horizontal wells. The majority of our drilling locations and our 2014 development program are focused on the Terryville Complex, where we plan to invest $304.0 million on drilling 43 gross (37 net) horizontal wells and 3 gross (2.7 net) vertical wells.

For the nine months ended September 30, 2014, our total capital expenditures were $268.7 million and related to drilling, recompletions and capital workovers. We spent approximately 84% in the Terryville Complex, 8% in East Texas, and 8% in the Rockies.

Debt Agreements—MRD Segment

Revolving Credit Facility

On June 18, 2014, we, as borrower, and certain of our subsidiaries, as guarantors, entered into a revolving credit facility, which is a five-year, $2.0 billion revolving credit facility with an initial borrowing base of $725 million and aggregate elected commitments of $725 million. On October 3, 2014, the borrowing base and aggregate elected commitments was increased from $668.5 to $725 million. For additional information regarding our revolving credit facility, see Note 8 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under Item 1 of this quarterly report.

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. A future decline in commodity prices could result in a redetermination that lowers our borrowing base in the future and, in such case, we could be required to repay any indebtedness in excess of the borrowing base, or we could be required to pledge other oil and natural gas properties as additional collateral. If a redetermination of our borrowing base results in our borrowing base being less than our aggregate elected commitments, our aggregate elected commitments will be automatically reduced to the amount of such reduced borrowing base. We do not anticipate having any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under the revolving credit facility.

If we fail to perform our obligations under these and other covenants, the revolving credit commitments could be terminated and any outstanding indebtedness together with accrued interest, fees and other obligations under the revolving credit facility, could be declared immediately due and payable.

Senior Notes

On July 10, 2014, the Company completed a private placement of $600.0 million aggregate principal amount of 5.875% senior unsecured notes (the “MRD Senior Notes”) at par. The MRD Senior Notes will mature on July 1, 2022. Interest on the MRD Senior Notes will accrue from July 10, 2014 and will be payable semiannually on January 1 and July 1 of each year, commencing on January 1, 2015. The MRD Senior Notes are governed by an indenture dated as of July 10, 2014.

For additional information regarding MRD Senior Notes, see Note 8 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under Item 1 of this quarterly report.

Debt Agreements—MEMP Segment

Revolving Credit Facility

Memorial Production Operating LLC (“OLLC”), a wholly-owned subsidiary of MEMP, is a party to a $2.0 billion revolving credit facility that matures in March 2018 and is guaranteed by MEMP and all of its current and future subsidiaries (other than certain immaterial subsidiaries).  A seventh amendment to the credit agreement was entered into on June 13, 2014, which among other things increased the borrowing base to $1.44 billion upon the closing of the Acquisition.  On July 17, 2014, the borrowing base was automatically reduced by $125.0 million in conjunction with the issuance of the 2022 Senior Notes in accordance with the terms of the credit facility. On October 10, 2014, MEMP’s borrowing base was redetermined and increased from $1.315 to $1.44 billion.

For additional information regarding MEMP’s revolving credit facility, see Note 8 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under Item 1 of this quarterly report.

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2021 Senior Notes

On April 17, 2013, May 23, 2013 and October 10, 2013, the MEMP Issuers issued $300.0 million, $100.0 million and $300.0 million, respectively, of its 7.625% senior notes due 2021 (“2021 Senior Notes”). The 2021 Senior Notes are fully and unconditionally guaranteed (subject to customary release provisions) on a joint and several basis by all of the MEMP’s subsidiaries (other than Finance Corp., which is co-issuer of the 2021 Senior Notes, and certain immaterial subsidiaries). The 2021 Senior Notes will mature on May 1, 2021 with interest accruing at a rate of 7.625% per annum and payable semi-annually in arrears on May 1 and November 1 of each year.  The 2021 Senior Notes were issued under and are governed by an indenture dated as of April 17, 2013.

For additional information regarding MEMP’s 2021 Senior Notes, see Note 8 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under Item 1 of this quarterly report.

2022 Senior Notes

On July 17, 2014, the MEMP Issuers completed a private placement of $500 million aggregate principal amount of 6.875% senior unsecured notes (the “2022 Senior Notes”).  The 2022 Senior Notes were issued at 98.485% of par and are fully and unconditionally guaranteed (subject to customary release provisions on a joint and several basis by all of MEMP’s subsidiaries other than Finance Corp., which is the 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 a rate of 6.876% 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.

For additional information regarding the 2022 Senior Notes, see Note 8 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under Item 1 of this quarterly report.

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, 2014, 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, 2014.

On July 1, 2014, we elected to terminate the interest rate swaps associated with our credit facility and in the aggregate paid our counterparties approximately $0.7 million.  WildHorse Resources novated theses interest rate swaps to us in connection with the closing of our initial public offering.

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

	For Nine Months Ended September 30,
	2014			2013
Net cash provided by operating activities	$	181,683		$	90,118
Net cash used in investing activities:
Acquisition of oil and natural gas properties	$	—		$	(67,098	)
Additions to oil and gas properties		(267,848	)		(130,064	)
Additions to other property and equipment		(9,134	)		(1,058	)
Equity investments in MEMP Segment		(570	)		(189	)
Distributions received from MEMP Segment related to partnership interests		6,068			19,100
Decrease (increase) in restricted cash		49,946			—
Proceeds from the sale of oil and gas properties to third parties		6,700			152,274
Other		(301	)		653
Net cash provided by (used in) investing activities	$	(215,139	)	$	(26,382	)
Net cash provided by financing activities
Advances on revolving credit facilities	$	1,139,800		$	161,700
Payments on revolving credit facilities		(1,314,900	)		(200,500	)
Proceeds from issuance of senior notes		600,000			—
Borrowings under second lien credit facility		—			325,000
Redemption of second lien credit facility		(328,282	)		—
Redemption of senior notes		(351,808	)		—
Deferred financing costs		(18,875	)		(12,619	)
Purchase of additional interests in consolidated subsidiaries		(3,292	)		—
Proceeds from initial public offering		408,500			—
Costs incurred in conjunction with initial public offering		(28,198	)		—
Contribution from NGP affiliates related to sale of properties		1,165			—
Contributions from MEMP Segment		33,880			84,020
Distributions to Funds		—			(363,437	)
Distributions to MRD Holdco		(59,803	)		—
Distributions to noncontrolling interest		(325	)		(7,531	)
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	)		—
Distributions made by previous owners		—			(1,715	)
Other		213			(6,296	)
Net cash provided by (used in) financing activities	$	(21,388	)	$	(21,378	)

Nine months Ended September 30, 2014 Compared to the Nine months Ended September 30, 2013

Operating Activities. Net cash flows provided by operating activities were $181.7 million during 2014 compared to $90.1 million during 2013.  Production increased 22.8 Bcfe (approximately 67%) and average realized sales price increased $0.27 per Mcfe as previously discussed under “—Results of Operations—MRD Segment.”  Cash paid for interest during 2014 was $35.5 million compared to $12.8 million during 2013.  During 2014, compensation expense of approximately $26.7 million was paid in cash related to WildHorse Resources’ incentive units compared to $19.1 million in 2013 related to BlueStone incentive units.

Investing Activities. Total cash used in investing activities was $215.1 million during 2014 compared to $26.4 million for the same period in 2013. Cash used for additions to oil and gas properties $267.8 million during 2014 compared to $130.1 million for the same period in 2013, which consisted primarily of drilling and completion activities in the Cotton Valley in North Louisiana and East Texas area. Additions to other property and equipment were $9.1 million which consisted primarily of computer hardware, software, and other leased office space build out during 2014. On April 30, 2013, WildHorse Resources purchased certain oil and gas properties and leases in Louisiana from a third party for approximately $67.1 million.  Distributions of $6.1 million were received from MEMP primarily from the subordinated units owned by MRD LLC during 2014 compared to $19.1 million during 2013 received from MEMP primarily from the common and subordinated units owned by MRD LLC. 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, subject to customary post-closing adjustments. On July 31, 2013, BlueStone entered into an agreement with a third party to sell its remaining interest in certain properties in the Mossy Grove Prospect in Walker and Madison Counties located in East Texas. Total cash consideration received by BlueStone was approximately $117.9 million. On June 4, 2013, Black Diamond sold certain of its Wyoming oil and gas properties to a third party for cash consideration of approximately $32.9 million.  There was a decrease in restricted cash of $49.9 million, 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.  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. Net proceeds from our initial public offering were $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.

Net repayments under revolving credit facilities were $175.1 million during 2014 compared to net repayments of $38.8 million during 2013. Amounts borrowed under our revolving credit facility were primarily incurred to repay the amounts outstanding under WildHorse Resources’ 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. On June 13, 2013, WildHorse Resources borrowed $325.0 million under its second lien term loan agreement and used such borrowings to reduce outstanding indebtedness under its revolving credit facility and to pay a onetime special $225.0 million distribution to MRD LLC, which MRD LLC subsequently distributed to the Funds. In connection with the closing of our initial public offering, WildHorse Resources’ second lien term loan was repaid in full, including a premium of approximately $3.3 million.

Net proceeds of $584.9 million from the issuance of our MRD Senior Notes during the nine months ending September 30, 2014 were used to repay portions of our 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.  WildHorse Resources sold its subsidiary, WHR Management Company, 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.  For additional information regarding this transaction, see Note 13 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under Item 1 of this quarterly report.

MEMP paid $33.9 million to WildHorse Resources in connection with MEMP’s April 1, 2014 acquisition of certain oil and natural gas properties in East Texas.  MEMP paid $55.4 million to WildHorse Resources in connection with MEMP’s March 28, 2013 acquisition of all the outstanding equity interests in WHT. Tanos also distributed approximately $28.6 million to MRD LLC during 2013.

In connection with the our initial public offering, certain former management members of WildHorse Resources contributed their 0.1% membership interest in WildHorse Resources as well as their incentive units in exchange for 42,334,323 shares of our common stock and cash consideration of $30.0 million. The portion of the total consideration related to acquiring the 0.1% membership interest was $3.3 million.

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.

Distributions to the Funds during 2013 were $363.4 million. From time-to-time, MRD LLC made distributions of cash to the Funds. The timing and amount of these cash distributions was within the discretion of the board of managers of MRD LLC and was based, in part, upon available cash, the performance of its business, and other relevant factors. During 2013, substantially all of the cash distributed to the Funds was sourced from long term borrowings or sales of assets. The sources to fund these distributions primarily included $225.0 million from the WildHorse second lien term loan, $75.0 million from the sale of properties to MEMP, and approximately $63.4 million related to the sale of properties by BlueStone.

Deferred financing costs of approximately $18.9 million were incurred during 2014 compared to approximately $12.6 million during 2013.

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MEMP Segment

	For Nine Months Ended September 30,
	2014			2013
Net cash provided by operating activities	$	183,777		$	147,005
Net cash used in investing activities:
Acquisition of oil and natural gas properties	$	(1,083,167	)	$	(37,828	)
Additions to oil and gas properties		(189,990	)		(127,449	)
Additions to other property and equipment		—			(126	)
Additions to restricted investments		(2,883	)		(4,263	)
Proceeds from the sale of oil and gas properties to third parties		—			4,525
Deposits for property acquisitions		—			(25,310	)
Net cash provided by (used in) investing activities	$	(1,276,040	)	$	(190,451	)
Net cash provided by financing activities
Advances on revolving credit facilities	$	1,325,000		$	316,355
Payments on revolving credit facilities		(1,127,000	)		(699,868	)
Proceeds from the issuances of senior notes		492,425			397,563
Deferred financing costs		(11,409	)		(11,218	)
Contributions from previous owners		—			7,233
Contribution from NGP affiliate		—			2,013
Contribution from general partner		570			189
Proceeds from public equity offering		553,288			179,371
Costs incurred in conjunction with issuance of common units		(12,222	)		(7,592	)
Distributions to partners		(107,070	)		(62,888	)
Distributions to MRD Segment		(33,880	)		(84,020	)
Distributions made by previous owners		—			(2,552	)
Other		—			55
Net cash provided by (used in) financing activities	$	1,079,702		$	34,641

Nine months Ended September 30, 2014 Compared to the Nine months Ended September 30, 2013

Operating Activities.  Key drivers of net operating cash flows are commodity prices, production volumes and operating costs. Net income decreased by $54.4 million as further discussed above under “—Results of Operations—MEMP Segment,” and net cash provided by operating activities increased by $36.8 million. Cash paid for interest during 2014 was $32.0 million compared to $10.1 million during 2013.  Net cash provided by operating activities included $11.4 million period-to-period increase in cash flow attributable to the timing of cash receipts and disbursements related to operating activities during 2014 compared to 2013.

Investing Activities. Net cash used in investing activities during 2014 was $1.28 billion, of which $1.08 billion was used to acquire oil and natural gas properties from a third parties and $190.0 million was used for additions to oil and gas properties. Cash used in investing activities during 2013 was $190.4 million, of which $37.8 million was used to acquire oil and natural gas properties from a third parties and $127.4 million was used for additions to oil and gas properties. During the nine months ended September 30, 2013, we paid a deposit of $25.3 million related to the Cinco Acquisition.  During the nine months ended September 30, 2013, Tanos had sales proceeds of $4.5 million related to the sale of 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.    

Financing Activities.  For the nine months ended September 30, 2014, 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.  The net proceeds from these issuances were primarily used to repay borrowings on our revolving credit facility. On March 25, 2013, MEMP issued 9,775,000 common units representing limited partner interests in the Partnership to the public at an offering price of $18.35 per unit generating gross proceeds of approximately $179.4 million, offset by approximately $7.6 million of costs incurred in conjunction with the issuance of common units. The net proceeds from this equity offering, including MEMP GP’s proportionate capital contribution, partially funded the acquisition of all of the outstanding equity interests in WHT.

Distributions to partners during 2014 were $107.1 million compared to $62.9 million during 2013, of which the MRD Segment received $6.1 million during 2014 compared to $19.1 million during 2013. The increase in total distributions is due to both an increase in MEMP’s outstanding units between periods and an increase in the declared cash distribution rate per unit. The decrease in distributions to the MRD Segment is due to MRD LLC selling 7,061,294 common units in November 2013 and distributed 5,360,912 subordinated units to MRD Holdco in June 2014 in connection with our initial public offering.

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MEMP paid $33.9 million to WildHorse Resources in connection with MEMP’s April 1, 2014 acquisition of certain oil and natural gas properties in East Texas.  MEMP paid $55.4 million to WildHorse Resources in connection with its March 28, 2013 acquisition of all of the outstanding equity interests in WHT and repaid $89.3 million of indebtedness under WHT’s credit facility. Tanos also distributed approximately $28.6 million to MRD LLC during 2013.

MEMP’s previous owners received contributions of $7.2 million during 2013, of which Tanos received $5.2 million from MRD LLC.   Distributions made by MEMP’s previous owners totaled $2.6 million in 2013.

MEMP had net payments of $276.0 million under its revolving credit facility during 2013. The Cinco Group had advances of $18.4 million under their credit facilities and repaid $36.6 million of outstanding borrowings during the nine months ending September 30, 2013. MEMP had borrowings of $1.33 billion under its revolving credit facility during 2014 that were used primarily to fund their acquisitions and drilling program. Deferred financing costs of approximately $11.4 million were incurred during 2014 compared to approximately $11.2 million during 2013.

Proceeds of $492.4 million from the issuances of the 2022 Senior Notes during 2014 were used to repay borrowings outstanding under MEMP’s revolving credit facility.

Contractual Obligations

During the nine months ended September 30, 2014, there were no significant changes in our consolidated and combined contractual obligations from those reported in our initial public offering prospectus dated June 12, 2014 filed with the SEC on June 16, 2014 except for the issuance of the MRD Senior Notes and MEMP’s 2022 Senior notes, borrowings and repayments under revolving credit facilities, the redemption of the PIK notes, the repayment and termination of WildHorse Resources’ revolving and second lien credit facilities, and the purchase commitment listed below.

During the nine months ended September 30, 2014, MEMP assumed the following contractual obligation as a result of their Wyoming Acquisition (in thousands):

			Payment or Settlement due by Period
Purchase commitment	Total		Remainder 2014		2015 - 2017		2018 - 2019		Thereafter
CO2 minimum purchase commitment:
Estimated payment obligation (1)	$	62,103	$	3,203	$	35,947	$	15,741	$	7,212

(1)Represents firm agreement to purchase CO₂volumes as of September 30, 2014.

Off–Balance Sheet Arrangements

As of September 30, 2014, 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 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 initial public offering prospectus dated June 12, 2014 filed with the SEC on June 16, 2014.

68

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, 2014, see Note 5 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under Item 1 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 of this quarterly report for interest rate swap arrangements that were outstanding at September 30, 2014.

At September 30, 2014, we had $28 million of Eurodollar borrowings outstanding under our revolving credit facility, with an interest rate of LIBOR plus 1.50%, or 1.66%.  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 $0.1million per year.

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, 2014
	Carrying		Estimated
Description	Amount		Fair Value
MRD Segment:
5.875% senior notes, fixed-rate, due May 1, 2022	$	600,000	$	582,000
MEMP Segment:
7.625% senior notes, fixed rate, due May 1, 2021	$	690,182	$	700,000
6.875% senior notes, fixed-rate, due August 1, 2022	$	492,618	$	475,000

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 of this quarterly report for additional information regarding credit risk associated with our derivative instruments.

69

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, 2014. 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, 2014 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, 2014 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.

70

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 FACTORS.

Our business faces many risks. Any of the risks discussed elsewhere in this Quarterly Report and our other SEC filings could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operations. There have been no material changes with respect to the risk factors since those disclosed in our initial public offering prospectus dated June 12, 2014 filed with the SEC on June 16, 2014.

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

(a) Recent sales of unregistered securities.

There were no sales of unregistered equity securities during the period covered by this Quarterly Report on Form 10-Q  other than as previously included in a Current Report on Form 8-K.

(b) Use of proceeds.

None.

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

None.

ITEM 3.  DEFAULTS UPON SENIOR SECURITIES.

None.

ITEM 4.  MINE SAFETY DISCLOSURES.

Not applicable.

ITEM 5.  OTHER INFORMATION.

None.

71

ITEM 6.  EXHIBITS.

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 between Memorial Resource Development LLC and Memorial Production Operating LLC, dated as of July 15, 2013 (incorporated by reference to Exhibit 2.5 to Memorial Production Partners LP’s Form 8-K (File No. 001-35364), filed with the SEC on July 16, 2013).
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	—	Indenture, dated July 10, 2014, by and among Memorial Resource Development Corp., the subsidiary guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K (File No. 001-36490) filed on July 16, 2014).
4.2	—	Form of 5.875% Senior Note due 2022 (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K (File No. 001-36490) filed on July 16, 2014).
4.3	—	Registration Rights Agreement, dated as of July 10, 2014, by and among Memorial Resource Development Corp., the several guarantors named therein and Citigroup Global Markets Inc., as representative of the initial purchasers named therein (incorporated by reference to Exhibit 4.3 to the Company’s Current Report on Form 8-K (File No. 001-36490) filed on July 16, 2014).
4.4	—	Indenture, dated July 17, 2014, by and among Memorial Production Partners LP, Memorial Production Finance Corporation, the subsidiary guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Memorial Production Partners LP’s Current Report on Form 8-K (File No. 001-35364) filed on July 17, 2014).
4.5	—	Registration Rights Agreement, dated July 17, 2014, by and among Memorial Production Partners LP, Memorial Production Finance Corporation, the subsidiary guarantors named therein, and Barclays Capital Inc., as representative of the initial purchasers named therein (incorporated by reference to Exhibit 4.2 to Memorial Production Partners LP’s Current Report on Form 8-K (File No. 001-35364) filed on July 17, 2014).
4.6#	—	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	—	Memorial Resource Development Corp. 2014 Long Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (File No. 001-36490) filed on June 16, 2014).
10.2	—	Omnibus Agreement dated as of December 14, 2011, by and among Memorial Production Partners LP, Memorial Production Partners GP LLC and Memorial Resource Development LLC (incorporated by reference to Exhibit 10.1 to Memorial Production Partners LP’s Form 8-K (File No. 001-35364) filed on December 15, 2011).
10.3	—	Purchase Agreement, dated as of June 25, 2014, by and among Memorial Resource Development Corp., the subsidiary guarantors named therein and Citigroup Global Markets Inc., as representative of the initial purchasers named therein (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (File No. 001-36490) filed on June 26, 2014).
10.4	—	Purchase Agreement, dated July 14, 2014, by and among Memorial Production Partners LP, Memorial Production Finance Corporation, the subsidiary guarantors named therein, and Barclays Capital Inc., as representative of the several initial purchasers named therein (incorporated by reference to Exhibit 10.1 to Memorial Production Partners LP’s Form 8-K (File No. 001-35364) filed on July 15, 2014).

72

10.5	—	Eighth Amendment to Credit Agreement, dated as of October 10, 2014, by and among Memorial Production Partners LP, Memorial Production Operating LLC, Wells Fargo Bank, National Association, as administrative agent for the lenders party thereto, JPMorgan Chase Bank, N.A., as syndication agent for the lenders party thereto, Royal Bank of Canada, The Royal Bank of Scotland plc, Union Bank, N.A. and Comerica Bank, as co-documentation agents for the lenders party thereto, and the other lenders party thereto (incorporated by reference to Exhibit 10.1 to Memorial Production Partners LP’s Form 8-K (File No. 001-35364) filed on October 14, 2014).
10.6*	—	First 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 August 18, 2014.
10.7*	—	Second 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 October 3, 2014.
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
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.

73

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 5, 2014	By:	/s/ Andrew J. Cozby
	Name:	Andrew J. Cozby
	Title:	Senior Vice President and Chief Financial Officer

74

EX-10.6

Exhibit 10.6

First Amendment to Credit Agreement

dated as of August 18, 2014

among

Memorial Resource Development Corp.,
as Borrower,

Bank of America, N.A.,
as Administrative Agent,

Citibank, N.A.,
as Syndication Agent,

JPMorgan Chase Bank, N.A., BMO Harris Bank, N.A., Comerica Bank,

Credit Agricole Corporate and Investment Bank, Natixis, MUFG Union Bank,

N.A. f/k/a Union Bank, N.A., and Wells Fargo Bank, National Association,

as Co-Documentation Agents

and

the Lenders party hereto

Merrill Lynch, Pierce, Fenner & Smith Incorporated,
Sole Lead Arranger and Sole Bookrunner

First Amendment to Credit Agreement

This First Amendment to Credit Agreement  (this “First Amendment”), dated as of August 18, 2014 (the “First Amendment Effective Date”), is among Memorial Resource Development Corp., a corporation formed under the laws of the State of Delaware (the “Borrower”); each of the undersigned guarantors (together with the Borrower, collectively, the “Loan Parties”); each of the Lenders that is a signatory hereto; and Bank of America, N.A., as administrative agent for the Lenders (in such capacity, together with its successors, the “Administrative Agent”).

Recitals

A.The Borrower, the Administrative Agent and the Lenders are parties to that certain Credit Agreement dated as of June 18, 2014 (the “Credit Agreement”), pursuant to which the Lenders have, subject to the terms and conditions set forth therein, made certain credit available to and on behalf of the Borrower.

B.The parties desire to amend the Credit Agreement in certain respects including, without limitation, to modify the Swap Agreements negative covenant as set forth herein, to be effective as of the First Amendment Effective Date.

NOW, THEREFORE, in consideration of the premises and the mutual covenants herein contained, for good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:

Section 1.Defined Terms.  Each capitalized term which is defined in the Credit Agreement, but which is not defined in this First Amendment, shall have the meaning ascribed such term in the Credit Agreement, as amended hereby.  Unless otherwise indicated, all section references in this First Amendment refer to the Credit Agreement.

Section 2.Amendments.  In reliance on the representations, warranties, covenants and agreements contained in this First Amendment, and subject to the satisfaction of the conditions precedent set forth in Section 3 hereof, the Credit Agreement shall be amended effective as of the First Amendment Effective Date in the manner provided in this Section 2.

2.1Additional Definition.  Section 1.02 of the Credit Agreement is hereby amended to add thereto in alphabetical order the following definition which shall read in full as follows:

“First Amendment” means that certain First Amendment to Credit Agreement dated as of August 18, 2014, among the Borrower, the Guarantors, the Administrative Agent and the Lenders party thereto.

2.2Amended Definition.  The definition of “Loan Documents” contained in Section 1.02 of the Credit Agreement is hereby amended and restated in its entirety to read in full as follows:

“Loan Documents” means this Agreement, the First Amendment, the Notes, the Letter of Credit Agreements, the Letters of Credit, the Agency Fee Letter, and the Security Instruments.

2.3Amendment to Section 9.18 of the Credit Agreement.  Section 9.18 of the Credit Agreement is hereby amended by adding a new clause (e) thereto which shall read in full as follows:

(e)For purposes of Section 9.18(a)(i), the reasonably anticipated projected production from the Loan Parties’ proved Oil and Gas Properties included in the most recent Reserve Report delivered pursuant to the terms of this Agreement shall be deemed to include any increase therein anticipated based on information obtained by the Loan Parties and delivered to the Administrative Agent subsequent to the publication of such Reserve Report, including the Loan Parties’ internal forecasts of (i) additions to anticipated future production from new wells and (ii) completed acquisitions coming on stream; provided that any such supplemental information shall be reasonably satisfactory to the Administrative Agent.

Section 3.Conditions Precedent.  The effectiveness of the amendments to the Credit Agreement contained in Section 2 hereof is subject to the following:

3.1The Administrative Agent shall have received counterparts of this First Amendment from the Loan Parties and each of the Majority Lenders.

3.2The Administrative Agent shall have received all fees and other amounts due and payable on or prior to the First Amendment Effective Date.

3.3No Default, Event of Default, or Borrowing Base Deficiency exists immediately prior to or after giving effect to the amendments to the Credit Agreement contained in Section 2 hereof.

3.4The Administrative Agent shall have received such other documents as the Administrative Agent or counsel to the Administrative Agent may reasonably request.

The Administrative Agent shall notify the Borrower and the Lenders of the effectiveness of this First Amendment, and such notice shall be conclusive and binding.

Section 4.Representations and Warranties; Etc.  Each Loan Party hereby affirms: (a) that as of the date hereof, all of the representations and warranties contained in each Loan Document to which such Loan Party is a party are true and correct in all material respects as though made on and as of the date hereof (unless made as of a specific earlier date, in which case, was true as of such date and except to the extent that any such representation and warranty is qualified by materiality, in which case such representation and warranty shall continue to be true and correct in all respects), (b) no Defaults exist under the Loan Documents or will, after giving effect to this First Amendment, exist under the Loan Documents and (c) no Material Adverse Effect has occurred.

Section 5.Miscellaneous.

5.1Confirmation and Effect.  The provisions of the Credit Agreement (as amended by this First Amendment) shall remain in full force and effect in accordance with its terms following the effectiveness of this First Amendment.  Each reference in the Credit Agreement to “this Agreement”, “hereunder”, “hereof”, “herein”, or words of like import shall mean and be a reference to the Credit Agreement as amended hereby, and each reference to the Credit Agreement in any other document, instrument or agreement executed and/or delivered in connection with the Credit Agreement shall mean and be a reference to the Credit Agreement as amended hereby.

5.2Ratification and Affirmation of Loan Parties.  Each of the Loan Parties hereby expressly (a) acknowledges the terms of this First Amendment, (b) ratifies and affirms its obligations under the Guaranty Agreement and the other Loan Documents to which it is a party, as amended hereby, (c) acknowledges, renews and extends its continued liability under the Guaranty Agreement and the other Loan Documents to which it is a party, as amended hereby, (d) ratifies and affirms all Liens granted by it pursuant to the Loan Documents to secure the Indebtedness (except to the extent that such Liens have been released in accordance with the Loan Documents) and (e) agrees that its guarantee under the Guaranty Agreement and the other Loan Documents to which it is a party remains in full force and effect with respect to the Indebtedness.

5.3Counterparts.  This First Amendment may be executed by one or more of the parties hereto in any number of separate counterparts, and all of such counterparts taken together shall be deemed to constitute one and the same instrument. Delivery of this First Amendment by facsimile or electronic (e.g., pdf) transmission shall be effective as delivery of a manually executed original counterpart hereof.

5.4No Oral Agreement.  This written First Amendment, the Credit Agreement and the other Loan Documents executed in connection herewith and therewith represent the final agreement between the parties and may not be contradicted by evidence of prior, contemporaneous, or unwritten oral agreements of the parties.  There are no subsequent oral agreements between the parties.

5.5Governing Law.  This First Amendment (including, but not limited to, the validity and enforceability hereof) shall be governed by, and construed in accordance with, the laws of the State of New York.

5.6Payment of Expenses.  The Borrower agrees to pay or reimburse the Administrative Agent for all of its out-of-pocket costs and expenses incurred in connection with this First Amendment, any other documents prepared in connection herewith and the transactions contemplated hereby, including, without limitation, the reasonable fees and disbursements of counsel to the Administrative Agent.

5.7Severability.  Any provision of this First Amendment which is prohibited or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such prohibition or unenforceability without invalidating the remaining provisions hereof, and any such prohibition or unenforceability in any jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction.

5.8Successors and Assigns.  This First Amendment shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns.

[Signature pages follow]

IN WITNESS WHEREOF, the parties hereto have caused this First Amendment to be duly executed effective as of the date first written above.

BORROWER:	MEMORIAL RESOURCE DEVELOPMENT CORP.,
	a Delaware corporation
	By:	/s/ John A. Weinzierl
	Name:	John A. Weinzierl
	Title:	Chief Executive Officer
GUARANTORS:	MEMORIAL RESOURCE FINANCE CORP.,
	a Delaware corporation
	By:	/s/ John A. Weinzierl
	Name:	John A. Weinzierl
	Title:	Chief Executive Officer
	MRD Operating LLC
	BETA OPERATING COMPANY, LLC
	WILDHORSE RESOURCES, LLC
		By:	Memorial Resource Development Corp.,
			its sole member
		By:	/s/ John A. Weinzierl
		Name:	John A. Weinzierl
		Title:	Chief Executive Officer
	Classic Hydrocarbons GP Co., L.L.C.
	CLASSIC HYDROCARBONS HOLDINGS, L.P.
		By:	Classic Hydrocarbons GP Co., L.L.C.,
			its general partner
		By:	/s/ John A. Weinzierl
		Name:	John A. Weinzierl
		Title:	President and Chief Executive Officer
	CLASSIC OPERATING CO. LLC
		By:	Classic Hydrocarbons, Inc.,
			its sole member
	CLASSIC HYDROCARBONS OPERATING, LLC
	CLASSIC HYDROCARBONS, INC.
	CRATON ENERGY GP III, LLC
	CRATON ENERGY HOLDINGS III, LP
		By:	Craton Energy GP III, LLC,
			its general partner
	By:	/s/ John A. Weinzierl
	Name:	John A. Weinzierl
	Title:	Chief Executive Officer

[Signature Page to First Amendment to Credit Agreement

Memorial Resource Development Corp.]

ADMINISTRATIVE AGENT	BANK OF AMERICA, N.A., as Administrative Agent
AND LENDER:
	By:	/s/ Christine Trotter
	Name:	Christine Trotter
	Title:	Assistant Vice President
	BANK OF AMERICA, N.A., as a Lender
	By:	/s/ Raza Jafferi
	Name:	Raza Jafferi
	Title:	Vice President

[Signature Page to First Amendment to Credit Agreement

Memorial Resource Development Corp.]

LENDER:	Citibank, N.A., as a Lender
	By:
	Name:
	Title:

[Signature Page to First Amendment to Credit Agreement

Memorial Resource Development Corp.]

LENDER:	JPMorgan Chase Bank, N.A., as a Lender
	By:	/s/ Ryan Aman
	Name:	Ryan Aman
	Title:	Authorized Officer

[Signature Page to First Amendment to Credit Agreement

Memorial Resource Development Corp.]

LENDER:	BMO Harris Bank, N.A., as a Lender
	By:	/s/ Gumaro Tijerina
	Name:	Gumaro Tijerina
	Title:	Managing Director

[Signature Page to First Amendment to Credit Agreement

Memorial Resource Development Corp.]

LENDER:	Comerica Bank, as a Lender
	By:	/s/ Jason Klesel
	Name:	Jason Klesel
	Title:	Commercial Banking Officer

[Signature Page to First Amendment to Credit Agreement

Memorial Resource Development Corp.]

LENDER:	Credit Agricole Corporate and Investment Bank, as a Lender
	By:
	Name:
	Title:
	By:
	Name:
	Title:

[Signature Page to First Amendment to Credit Agreement

Memorial Resource Development Corp.]

LENDER:	Natixis, as a Lender
	By:
	Name:
	Title:
	By:
	Name:
	Title:

[Signature Page to First Amendment to Credit Agreement

Memorial Resource Development Corp.]

LENDER:	MUFG Union Bank, N.A.
	f/k/aUnion Bank, N.A., as a Lender
	By:	/s/ Stacy A. Goldstein
	Name:	Stacy A. Goldstein
	Title:	Vice President

[Signature Page to First Amendment to Credit Agreement

Memorial Resource Development Corp.]

LENDER:	Wells Fargo Bank, National Association, as a Lender
	By:	/s/ Shiloh Davila
	Name:	Shiloh Davila
	Title:	Vice President

[Signature Page to First Amendment to Credit Agreement

Memorial Resource Development Corp.]

LENDER:	Barclays Bank PLC, as a Lender
	By:	/s/ May Huang
	Name:	May Huang
	Title:	Assistant Vice President

[Signature Page to First Amendment to Credit Agreement

Memorial Resource Development Corp.]

LENDER:	ING Capital LLC, as a Lender
	By:	/s/ Juli Bieser
	Name:	Juli Bieser
	Title:	Director
	By:	/s/ Charles Hall
	Name:	Charles Hall
	Title:	Managing Director

[Signature Page to First Amendment to Credit Agreement

Memorial Resource Development Corp.]

LENDER:	Royal Bank of Canada, as a Lender
	By:	/s/ Mark Lumpkin, Jr.
	Name:	Mark Lumpkin, Jr.
	Title:	Authorized Signatory

[Signature Page to First Amendment to Credit Agreement

Memorial Resource Development Corp.]

LENDER:	Commonwealth Bank of Australia, as a Lender
	By:	/s/ Renee Simpson
	Name:	Renee Simpson
	Title:	Senior Associate

[Signature Page to First Amendment to Credit Agreement

Memorial Resource Development Corp.]

LENDER:	Capital One, National Association, as a Lender
	By:
	Name:
	Title:

[Signature Page to First Amendment to Credit Agreement

Memorial Resource Development Corp.]

LENDER:	Associated Bank, N.A., as a Lender
	By:	/s/ Kyle Lewis
	Name:	Kyle Lewis
	Title:	Assistant Vice President

[Signature Page to First Amendment to Credit Agreement

Memorial Resource Development Corp.]

EX-10.7

Exhibit 10.7

Second Amendment to Credit Agreement

dated as of October 3, 2014

among

Memorial Resource Development Corp.,
as Borrower,

Bank of America, N.A.,
as Administrative Agent,

Citibank, N.A.,
as Syndication Agent,

JPMorgan Chase Bank, N.A., BMO Harris Bank, N.A., Comerica Bank,

Credit Agricole Corporate and Investment Bank, Natixis, MUFG Union Bank,

N.A., and Wells Fargo Bank, National Association,

as Co-Documentation Agents

and

the Lenders party hereto

Merrill Lynch, Pierce, Fenner & Smith Incorporated,
Sole Lead Arranger and Sole Bookrunner

Second Amendment to Credit Agreement

This Second Amendment to Credit Agreement  (this “Second Amendment”), dated as of October 3, 2014 (the “Second Amendment Effective Date”), is among Memorial Resource Development Corp., a corporation formed under the laws of the State of Delaware (the “Borrower”); each of the undersigned guarantors (together with the Borrower, collectively, the “Loan Parties”); each of the Lenders that is a signatory hereto; and Bank of America, N.A., as administrative agent for the Lenders (in such capacity, together with its successors, the “Administrative Agent”).

Recitals

A.The Borrower, the Administrative Agent and the Lenders are parties to that certain Credit Agreement dated as of June 18, 2014 (as amended prior to the date hereof, the “Credit Agreement”), pursuant to which the Lenders have, subject to the terms and conditions set forth therein, made certain credit available to and on behalf of the Borrower.

B.The parties hereto desire to enter into this Second Amendment to amend the Credit Agreement in certain respects including, without limitation, to modify the Swap Agreements negative covenant as set forth herein, to be effective as of the Second Amendment Effective Date.

C.Subject to and upon the terms and conditions set forth herein, the Lenders have agreed to enter this Second Amendment.

NOW, THEREFORE, in consideration of the premises and the mutual covenants herein contained and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:

Section 1.Defined Terms.  Each capitalized term which is defined in the Credit Agreement, but which is not defined in this Second Amendment, shall have the meaning ascribed such term in the Credit Agreement, as amended hereby.  Unless otherwise indicated, all section references in this Second Amendment refer to the Credit Agreement.

Section 2.Amendments.  In reliance on the representations, warranties, covenants and agreements contained in this Second Amendment, and subject to the satisfaction of the conditions precedent set forth in Section 3 hereof, the Credit Agreement shall be amended effective as of the Second Amendment Effective Date in the manner provided in this Section 2.

2.1Additional Definition.  Section 1.02 of the Credit Agreement is hereby amended to add thereto in alphabetical order the following definition which shall read in full as follows:

“Second Amendment” means that certain Second Amendment to Credit Agreement dated as of October 3, 2014, among the Borrower, the Guarantors, the Administrative Agent and the Lenders party thereto.

2.2Amended Definitions.  The definitions of “Approved Counterparty” and “Loan Documents” contained in Section 1.02 of the Credit Agreement are hereby amended and restated in their entirety to read in full as follows:

“Approved Counterparty” means (a) any Lender or any Affiliate of a Lender or (b) any other Person that has a long term senior unsecured debt rating of BBB+/Baa1 by S&P or Moody’s (or their equivalent) or higher (including, for the sake of clarity, any other Person the obligations of which under Swap Agreements with Loan Parties are guaranteed by a credit support provider that has a long term senior unsecured debt rating of BBB+/Baa1 by S&P or Moody’s (or their equivalent) or higher at the time such Swap Agreement is entered into).

“Loan Documents” means this Agreement, the First Amendment, the Second Amendment, the Notes, the Letter of Credit Agreements, the Letters of Credit, the Agency Fee Letter, and the Security Instruments.

2.3Amendment to Section 9.18 of the Credit Agreement.  Section 9.18(a)(i) of the Credit Agreement is hereby amended and restated in its entirety to read in full as follows:

(i)Swap Agreements in respect of commodities (A) with an Approved Counterparty and (B) the notional volumes for which (when aggregated with other commodity Swap Agreements then in effect other than basis differential swaps on volumes already hedged pursuant to other Swap Agreements) do not exceed, as of the date such Swap Agreement is executed, (1) for the first 24 months after the date of execution of such Swap Agreement (the “First Measurement Period”), 100% and (2) for the first 36 months immediately following the First Measurement Period, 75%, in each case, of the reasonably anticipated projected production (assuming no curtailment or interruption of transportation for such anticipated

production) from proved Oil and Gas Properties included in the most recent Reserve Report for each month during the period during which such Swap Agreement is in effect for each of crude oil, natural gas and natural gas liquids, (which, in the case of natural gas liquids, may be hedged with Swap Agreements for crude oil), each calculated separately,

Section 3.Conditions Precedent.  The effectiveness of the amendments to the Credit Agreement contained in Section 2 hereof is subject to the following:

3.1The Administrative Agent shall have received counterparts of this Second Amendment from the Loan Parties and the Majority Lenders.

3.2The Administrative Agent shall have received all fees and other amounts due and payable on or prior to the Second Amendment Effective Date.

3.3No Default, Event of Default, or Borrowing Base Deficiency shall exist immediately prior to or after giving effect to the amendments to the Credit Agreement contained in Section 2 hereof.

3.4The Administrative Agent shall have received such other documents as the Administrative Agent or counsel to the Administrative Agent may reasonably request.

The Administrative Agent shall notify the Borrower and the Lenders of the effectiveness of this Second Amendment, and such notice shall be conclusive and binding.

Section 4.Representations and Warranties; Etc.  Each Loan Party hereby affirms: (a) that as of the date hereof, all of the representations and warranties contained in each Loan Document to which such Loan Party is a party are true and correct in all material respects as though made on and as of the date hereof (unless made as of a specific earlier date, in which case, was true as of such date and except to the extent that any such representation and warranty is qualified by materiality, in which case such representation and warranty shall continue to be true and correct in all respects), (b) no Defaults exist under the Loan Documents or will, after giving effect to this Second Amendment, exist under the Loan Documents and (c) no Material Adverse Effect has occurred.

Section 5.Miscellaneous.

5.1Confirmation and Effect.  The provisions of the Credit Agreement (as amended by this Second Amendment) shall remain in full force and effect in accordance with its terms following the effectiveness of this Second Amendment.  Each reference in the Credit Agreement to “this Agreement”, “hereunder”, “hereof”, “herein”, or words of like import shall mean and be a reference to the Credit Agreement as amended hereby, and each reference to the Credit Agreement in any other document, instrument or agreement executed and/or delivered in connection with the Credit Agreement shall mean and be a reference to the Credit Agreement as amended hereby.

5.2Ratification and Affirmation of Loan Parties.  Each of the Loan Parties hereby expressly (a) acknowledges the terms of this Second Amendment, (b) ratifies and affirms its obligations under the Guaranty Agreement and the other Loan Documents to which it is a party, as amended hereby, (c) acknowledges, renews and extends its continued liability under the Guaranty Agreement and the other Loan Documents to which it is a party, as amended hereby, (d) ratifies and affirms all Liens granted by it pursuant to the Loan Documents to secure the Indebtedness (except to the extent that such Liens have been released in accordance with the Loan Documents) and (e) agrees that its guarantee under the Guaranty Agreement and the other Loan Documents to which it is a party remains in full force and effect with respect to the Indebtedness.

5.3Counterparts.  This Second Amendment may be executed by one or more of the parties hereto in any number of separate counterparts, and all of such counterparts taken together shall be deemed to constitute one and the same instrument. Delivery of this Second Amendment by facsimile or electronic (e.g., pdf) transmission shall be effective as delivery of a manually executed original counterpart hereof.

5.4No Oral Agreement.  This written Second Amendment, the Credit Agreement and the other Loan Documents executed in connection herewith and therewith represent the final agreement between the parties and may not be contradicted by evidence of prior, contemporaneous, or unwritten oral agreements of the parties.  There are no unwritten oral agreements between the parties.

5.5Governing Law.  This Second Amendment (including, but not limited to, the validity and enforceability hereof) shall be governed by, and construed in accordance with, the laws of the State of New York.

5.6Payment of Expenses.  The Borrower agrees to pay or reimburse the Administrative Agent for all of its out-of-pocket costs and expenses incurred in connection with this Second Amendment, any other documents prepared in connection herewith and the transactions contemplated hereby, including, without limitation, the reasonable fees and disbursements of counsel to the Administrative Agent.

5.7Severability.  Any provision of this Second Amendment which is prohibited or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such prohibition or unenforceability without invalidating the remaining provisions hereof, and any such prohibition or unenforceability in any jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction.

5.8Successors and Assigns.  This Second Amendment shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns.

[Signature pages follow]

IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be duly executed effective as of the date first written above.

BORROWER:	MEMORIAL RESOURCE DEVELOPMENT CORP.,
	a Delaware corporation
	By:	/s/ John A. Weinzierl
	Name:	John A. Weinzierl
	Title:	Chief Executive Officer
GUARANTORS:	MEMORIAL RESOURCE FINANCE CORP.,
	a Delaware corporation
	By:	/s/ John A. Weinzierl
	Name:	John A. Weinzierl
	Title:	Chief Executive Officer
	MRD Operating LLC
	BETA OPERATING COMPANY, LLC
	WILDHORSE RESOURCES, LLC
		By:	Memorial Resource Development Corp.,
			its sole member
		By:	/s/ John A. Weinzierl
		Name:	John A. Weinzierl
		Title:	Chief Executive Officer
	Classic Hydrocarbons GP Co., L.L.C.
	CLASSIC HYDROCARBONS HOLDINGS, L.P.
		By:	Classic Hydrocarbons GP Co., L.L.C.,
			its general partner
		By:	/s/ John A. Weinzierl
		Name:	John A. Weinzierl
		Title:	President and Chief Executive Officer
	CLASSIC OPERATING CO. LLC
		By:	Classic Hydrocarbons, Inc.,
			its sole member
	CLASSIC HYDROCARBONS OPERATING, LLC
	CLASSIC HYDROCARBONS, INC.
	CRATON ENERGY GP III, LLC
	CRATON ENERGY HOLDINGS III, LP
		By:	Craton Energy GP III, LLC,
			its general partner
	By:	/s/ John A. Weinzierl
	Name:	John A. Weinzierl
	Title:	Chief Executive Officer

[Signature Page to Second Amendment to Credit Agreement

Memorial Resource Development Corp.]

ADMINISTRATIVE AGENT		BANK OF AMERICA, N.A., as Administrative Agent
AND LENDER:
	By:	/s/ Denise Jones
	Name:	Denise Jones
	Title:	Assistant Vice President
		BANK OF AMERICA, N.A., as a Lender
	By:	/s/ Raza Jafferi
	Name:	Raza Jafferi
	Title:	Vice President

[Signature Page to Second Amendment to Credit Agreement

Memorial Resource Development Corp.]

LENDER:	Citibank, N.A., as a Lender
	By:	/s/ Peter Kardos
	Name:	Peter Kardos
	Title:	Vice-President

[Signature Page to Second Amendment to Credit Agreement

Memorial Resource Development Corp.]

LENDER:	JPMorgan Chase Bank, N.A., as a Lender
	By:	/s/ Robert L. Mendoza
	Name:	Robert L. Mendoza
	Title:	Senior Vice President

[Signature Page to Second Amendment to Credit Agreement

Memorial Resource Development Corp.]

LENDER:	BMO Harris Bank, N.A., as a Lender
	By:	/s/ Gumaro Tijerina
	Name:	Gumaro Tijerina
	Title:	Managing Director

[Signature Page to Second Amendment to Credit Agreement

Memorial Resource Development Corp.]

LENDER:	Comerica Bank, as a Lender
	By:	/s/ Jeffery Treadway
	Name:	Jeffery Treadway
	Title:	Senior Vice President

[Signature Page to Second Amendment to Credit Agreement

Memorial Resource Development Corp.]

LENDER:	Credit Agricole Corporate and Investment Bank, as a Lender
	By:	/s/ Sharada Manne
	Name:	Sharada Manne
	Title:	Managing Director
	By:	/s/ Ting Lee
	Name:	Ting Lee
	Title:	Director

[Signature Page to Second Amendment to Credit Agreement

Memorial Resource Development Corp.]

LENDER:	Natixis, as a Lender
	By:	/s/ Stuart Murray
	Name:	Stuart Murray
	Title:	Managing Director
	By:	/s/ Jarrett Price
	Name:	Jarrett Price
	Title:	Vice President

[Signature Page to Second Amendment to Credit Agreement

Memorial Resource Development Corp.]

LENDER:	MUFG Union Bank, N.A. f/k/aUnion Bank, N.A., as a Lender
	By:	/s/ Stacy A. Goldstein
	Name:	Stacy A. Goldstein
	Title:	Vice President

[Signature Page to Second Amendment to Credit Agreement

Memorial Resource Development Corp.]

LENDER:	Wells Fargo Bank, National Association, as a Lender
	By:	/s/ Shiloh Davila
	Name:	Shiloh Davila
	Title:	Vice President

[Signature Page to Second Amendment to Credit Agreement

Memorial Resource Development Corp.]

LENDER:	Barclays Bank PLC, as a Lender
	By:	/s/ Marguerite Sutton
	Name:	Marguerite Sutton
	Title:	Vice President

[Signature Page to Second Amendment to Credit Agreement

Memorial Resource Development Corp.]

LENDER:	ING Capital LLC, as a Lender
	By:	/s/ Juli Bieser
	Name:	Juli Bieser
	Title:	Director
	By:	/s/ Michael Price
	Name:	Michael Price
	Title:	Managing Director

[Signature Page to Second Amendment to Credit Agreement

Memorial Resource Development Corp.]

LENDER:	Royal Bank of Canada, as a Lender
	By:	/s/ Mark Lumpkin, Jr.
	Name:	Mark Lumpkin, Jr.
	Title:	Authorized Signatory

[Signature Page to Second Amendment to Credit Agreement

Memorial Resource Development Corp.]

LENDER:	Commonwealth Bank of Australia, as a Lender
	By:	/s/ Sanjay Remond
	Name:	Sanjay Remond
	Title:	Director

[Signature Page to Second Amendment to Credit Agreement

Memorial Resource Development Corp.]

LENDER:	Capital One, National Association, as a Lender
	By:	/s/ Michael Higgins
	Name:	Michael Higgins
	Title:	Director

[Signature Page to Second Amendment to Credit Agreement

Memorial Resource Development Corp.]

LENDER:	Associated Bank, N.A., as a Lender
	By:	/s/ Farhan Iqbal
	Name:	Farhan Iqbal
	Title:	Senior Vice President

[Signature Page to Second Amendment to Credit Agreement

Memorial Resource Development Corp.]

EX-31.1

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)) 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.	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
	c.	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 5, 2014	/s/ John A. Weinzierl
	John A. Weinzierl
	Chief Executive Officer
	Memorial Resource Development Corp.

EX-31.2

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)) 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.	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
	c.	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 5, 2014	/s/ Andrew J. Cozby
	Andrew J. Cozby
	Senior Vice President & Chief Financial Officer
	Memorial Resource Development Corp.

EX-32.1

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 5, 2014			/s/ John A. Weinzierl
			John A. Weinzierl
			Chief Executive Officer
			Memorial Resource Development Corp.
Date:  November 5, 2014			/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

Summary of Significant Accounting Policies - Additional Information (Detail) (USD $)				9 Months Ended
	Sep. 30, 2014	Jun. 30, 2014	Dec. 31, 2013	Sep. 30, 2014 Texas [Member]	Sep. 30, 2014 Minimum [Member]	Sep. 30, 2014 Maximum [Member]
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives					3 years	5 years
Taxable margin rate				1.00%
Minimum percentage tax benefit to be realized upon final settlement	50.00%
Uncertain tax benefits	$ 0		$ 0
Deferred tax liability recorded in equity in connection with initial public offering and restricting transactions		$ 43,300,000

XML

Long Term Debt - Consolidated and Combined Debt Obligations (Detail) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014		Dec. 31, 2013
Debt Instrument [Line Items]
Total long-term debt	$ 2,111,800		$ 1,663,217
MRD [Member]
Debt Instrument [Line Items]
Long-term debt	628,000		871,150
MRD [Member] | 2.0 billion revolving credit facility [Member]
Debt Instrument [Line Items]
Credit facility	28,000
MRD [Member] | PIK notes [Member]
Debt Instrument [Line Items]
Senior Notes			350,000	[1]
MRD [Member] | 5.875% Senior Unsecured Notes Due July 2022
Debt Instrument [Line Items]
Senior Notes	600,000	[2]
MRD [Member] | Senior Pik Toggle Notes Unamortized Discounts [Member]
Debt Instrument [Line Items]
Unamortized discounts			(6,950)
MRD [Member] | WildHorse Resources, LLC [Member] | 1.0 billion revolving credit facility [Member]
Debt Instrument [Line Items]
Credit facility			203,100
MRD [Member] | WildHorse Resources, LLC [Member] | 325.0 Million Lien Term Facility [Member]
Debt Instrument [Line Items]
Credit facility			325,000
MEMP [Member]
Debt Instrument [Line Items]
Long-term debt	1,483,800		792,067
MEMP [Member] | 2.0 billion revolving credit facility [Member]
Debt Instrument [Line Items]
Credit facility	301,000		103,000
MEMP [Member] | 7.625 % Senior Notes Due May 2021 [Member]
Debt Instrument [Line Items]
Senior Notes	700,000	[3]	700,000	[3]
MEMP [Member] | 6.875% Senior Unsecurred Notes Due August 2022 [Member]
Debt Instrument [Line Items]
Senior Notes	500,000	[4]
MEMP [Member] | Unamortized Discounts [Member]
Debt Instrument [Line Items]
Unamortized discounts	$ (17,200)		$ (10,933)

[1] The estimated fair value of this fixed-rate debt was $348.3 million at December 31, 2013. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.

[2] The estimated fair value of this fixed-rate debt was $582.0 million September 30, 2014. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.

[3] The estimated fair value of this fixed-rate debt was $700.0 million and $721.0 million at September 30, 2014 and December 31, 2013, respectively. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.

[4] The estimated fair value of this fixed-rate debt was $475.0 million at September 30, 2014. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.

XML

Risk Management and Derivative Instruments - Schedule of Open Commodity Positions (Detail)	9 Months Ended
	Sep. 30, 2014 MMBTU
Remaining 2014 [Member] | Natural Gas Derivative Contracts [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	4,540,000
Weighted-average fixed price	4.18
Remaining 2014 [Member] | Natural Gas Derivative Contracts [Member] | Fixed price swap contracts [Member] | MEMP [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	2,580,200
Weighted-average fixed price	4.34
Remaining 2014 [Member] | Natural Gas Derivative Contracts [Member] | Collar contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	730,000
Weighted-average floor price	4.11
Weighted-average ceiling price	5.15
Remaining 2014 [Member] | Natural Gas Derivative Contracts [Member] | Collar contracts [Member] | MEMP [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	340,000
Weighted-average floor price	5.00
Weighted-average ceiling price	6.31
Remaining 2014 [Member] | Natural Gas Derivative Contracts [Member] | TGT Z1 basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	2,270,000
Spread	(0.08)
Remaining 2014 [Member] | Natural Gas Derivative Contracts [Member] | Call Spreads | MEMP [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	120,000
Weighted-average sold strike price	5.17
Weighted-average bought strike price	6.53
Remaining 2014 [Member] | Natural Gas Derivative Contracts [Member] | Basis Swap | MEMP [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	2,830,000
Spread	(0.09)
Remaining 2014 [Member] | Natural Gas Derivative Contracts [Member] | NGPL TexOk basis swaps [Member] | MEMP [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	2,260,000
Spread	(0.09)
Remaining 2014 [Member] | Natural Gas Derivative Contracts [Member] | NGPL STX basis swaps [Member] | MEMP [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	380,000
Spread	(0.11)
Remaining 2014 [Member] | Natural Gas Derivative Contracts [Member] | HSC basis swaps [Member] | MEMP [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	190,000
Spread	(0.07)
Remaining 2014 [Member] | Crude Oil Derivative Contracts [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price	94.43
Average Monthly Volume (Bbls)	56,000
Remaining 2014 [Member] | Crude Oil Derivative Contracts [Member] | Fixed price swap contracts [Member] | MEMP [Member]
Derivative [Line Items]
Weighted-average fixed price	95.83
Average Monthly Volume (Bbls)	283,452
Remaining 2014 [Member] | Crude Oil Derivative Contracts [Member] | Collar contracts [Member]
Derivative [Line Items]
Weighted-average floor price	86.67
Weighted-average ceiling price	112.33
Average Monthly Volume (Bbls)	12,000
Remaining 2014 [Member] | Crude Oil Derivative Contracts [Member] | Collar contracts [Member] | MEMP [Member]
Derivative [Line Items]
Weighted-average floor price	82.83
Weighted-average ceiling price	105.31
Average Monthly Volume (Bbls)	23,000
Remaining 2014 [Member] | Crude Oil Derivative Contracts [Member] | Basis Swap | MEMP [Member]
Derivative [Line Items]
Spread	(4.32)
Average Monthly Volume (Bbls)	134,000
Remaining 2014 [Member] | Crude Oil Derivative Contracts [Member] | Midway-Sunset basis swaps [Member] | MEMP [Member]
Derivative [Line Items]
Average Monthly Volume (Bbls)	60,000
Remaining 2014 [Member] | Crude Oil Derivative Contracts [Member] | Midway-Sunset basis swaps [Member] | MEMP [Member] | Brent
Derivative [Line Items]
Spread	(9.25)
Remaining 2014 [Member] | Crude Oil Derivative Contracts [Member] | Midland Basis Swap [Member] | MEMP [Member]
Derivative [Line Items]
Average Monthly Volume (Bbls)	40,000
Remaining 2014 [Member] | Crude Oil Derivative Contracts [Member] | Midland Basis Swap [Member] | MEMP [Member] | W T I
Derivative [Line Items]
Spread	(3.68)
Remaining 2014 [Member] | Crude Oil Derivative Contracts [Member] | LLS Crude basis swaps [Member] | MEMP [Member]
Derivative [Line Items]
Average Monthly Volume (Bbls)	34,000
Remaining 2014 [Member] | Crude Oil Derivative Contracts [Member] | LLS Crude basis swaps [Member] | MEMP [Member] | W T I
Derivative [Line Items]
Spread	3.61
Remaining 2014 [Member] | NGL Derivative Contracts [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price	44.84
Average Monthly Volume (Bbls)	184,000
Remaining 2014 [Member] | NGL Derivative Contracts [Member] | Fixed price swap contracts [Member] | MEMP [Member]
Derivative [Line Items]
Weighted-average fixed price	43.13
Average Monthly Volume (Bbls)	167,500
2015 [Member] | Put option contracts
Derivative [Line Items]
Average Monthly Volume (Bbls)	26,000
Weighted-average fixed price	85.00
Weighted-average deferred premium	(3.80)
2015 [Member] | Natural Gas Derivative Contracts [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	2,250,000
Weighted-average fixed price	4.08
2015 [Member] | Natural Gas Derivative Contracts [Member] | Fixed price swap contracts [Member] | MEMP [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	2,605,278
Weighted-average fixed price	4.28
2015 [Member] | Natural Gas Derivative Contracts [Member] | Collar contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	1,580,000
Weighted-average floor price	4.14
Weighted-average ceiling price	4.61
2015 [Member] | Natural Gas Derivative Contracts [Member] | Collar contracts [Member] | MEMP [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	350,000
Weighted-average floor price	4.62
Weighted-average ceiling price	5.80
2015 [Member] | Natural Gas Derivative Contracts [Member] | TGT Z1 basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	1,730,000
Spread	(0.09)
2015 [Member] | Natural Gas Derivative Contracts [Member] | Call Spreads | MEMP [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	80,000
Weighted-average sold strike price	5.25
Weighted-average bought strike price	6.75
2015 [Member] | Natural Gas Derivative Contracts [Member] | Basis Swap | MEMP [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	2,940,000
Spread	(0.12)
2015 [Member] | Natural Gas Derivative Contracts [Member] | NGPL TexOk basis swaps [Member] | MEMP [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	2,280,000
Spread	(0.11)
2015 [Member] | Natural Gas Derivative Contracts [Member] | HSC basis swaps [Member] | MEMP [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	150,000
Spread	(0.08)
2015 [Member] | Natural Gas Derivative Contracts [Member] | CIG basis swaps [Member] | MEMP [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	210,000
Spread	(0.25)
2015 [Member] | Natural Gas Derivative Contracts [Member] | TETCO STX basis swaps [Member] | MEMP [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	300,000
Spread	(0.09)
2015 [Member] | Crude Oil Derivative Contracts [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price	93.86
Average Monthly Volume (Bbls)	33,500
2015 [Member] | Crude Oil Derivative Contracts [Member] | Fixed price swap contracts [Member] | MEMP [Member]
Derivative [Line Items]
Weighted-average fixed price	90.96
Average Monthly Volume (Bbls)	314,281
2015 [Member] | Crude Oil Derivative Contracts [Member] | Collar contracts [Member]
Derivative [Line Items]
Weighted-average floor price	85.00
Weighted-average ceiling price	101.35
Average Monthly Volume (Bbls)	2,000
2015 [Member] | Crude Oil Derivative Contracts [Member] | Collar contracts [Member] | MEMP [Member]
Derivative [Line Items]
Weighted-average floor price	80.00
Weighted-average ceiling price	94.00
Average Monthly Volume (Bbls)	5,000
2015 [Member] | Crude Oil Derivative Contracts [Member] | Basis Swap | MEMP [Member]
Derivative [Line Items]
Spread	(7.07)
Average Monthly Volume (Bbls)	97,500
2015 [Member] | Crude Oil Derivative Contracts [Member] | Midway-Sunset basis swaps [Member] | MEMP [Member]
Derivative [Line Items]
Average Monthly Volume (Bbls)	57,500
2015 [Member] | Crude Oil Derivative Contracts [Member] | Midway-Sunset basis swaps [Member] | MEMP [Member] | Brent
Derivative [Line Items]
Spread	(9.73)
2015 [Member] | Crude Oil Derivative Contracts [Member] | Midland Basis Swap [Member] | MEMP [Member]
Derivative [Line Items]
Average Monthly Volume (Bbls)	40,000
2015 [Member] | Crude Oil Derivative Contracts [Member] | Midland Basis Swap [Member] | MEMP [Member] | W T I
Derivative [Line Items]
Spread	(3.25)
2015 [Member] | NGL Derivative Contracts [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price	41.61
Average Monthly Volume (Bbls)	151,000
2015 [Member] | NGL Derivative Contracts [Member] | Fixed price swap contracts [Member] | MEMP [Member]
Derivative [Line Items]
Weighted-average fixed price	43.02
Average Monthly Volume (Bbls)	149,200
2016 [Member] | Natural Gas Derivative Contracts [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	1,670,000
Weighted-average fixed price	4.18
2016 [Member] | Natural Gas Derivative Contracts [Member] | Fixed price swap contracts [Member] | MEMP [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	2,692,442
Weighted-average fixed price	4.40
2016 [Member] | Natural Gas Derivative Contracts [Member] | Collar contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	1,100,000
Weighted-average floor price	4.00
Weighted-average ceiling price	4.71
2016 [Member] | Natural Gas Derivative Contracts [Member] | TGT Z1 basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	220,000
Spread	(0.08)
2016 [Member] | Natural Gas Derivative Contracts [Member] | Basis Swap | MEMP [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	1,635,000
Spread	(0.06)
2016 [Member] | Natural Gas Derivative Contracts [Member] | NGPL TexOk basis swaps [Member] | MEMP [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	1,500,000
Spread	(0.07)
2016 [Member] | Natural Gas Derivative Contracts [Member] | HSC basis swaps [Member] | MEMP [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	135,000
Spread	0.07
2016 [Member] | Crude Oil Derivative Contracts [Member] | Fixed price swap contracts [Member] | MEMP [Member]
Derivative [Line Items]
Weighted-average fixed price	85.83
Average Monthly Volume (Bbls)	332,813
2016 [Member] | Crude Oil Derivative Contracts [Member] | Collar contracts [Member]
Derivative [Line Items]
Weighted-average floor price	80.00
Weighted-average ceiling price	99.70
Average Monthly Volume (Bbls)	27,000
2016 [Member] | NGL Derivative Contracts [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price	39.75
Average Monthly Volume (Bbls)	148,500
2016 [Member] | NGL Derivative Contracts [Member] | Fixed price swap contracts [Member] | MEMP [Member]
Derivative [Line Items]
Weighted-average fixed price	39.28
Average Monthly Volume (Bbls)	55,000
2017 [Member] | Natural Gas Derivative Contracts [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	1,270,000
Weighted-average fixed price	4.30
2017 [Member] | Natural Gas Derivative Contracts [Member] | Fixed price swap contracts [Member] | MEMP [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	2,450,067
Weighted-average fixed price	4.31
2017 [Member] | Natural Gas Derivative Contracts [Member] | Collar contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	1,050,000
Weighted-average floor price	4.00
Weighted-average ceiling price	5.06
2017 [Member] | Natural Gas Derivative Contracts [Member] | TGT Z1 basis swaps [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	200,000
Spread	(0.08)
2017 [Member] | Natural Gas Derivative Contracts [Member] | Basis Swap | MEMP [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	300,000
Spread	(0.05)
2017 [Member] | Natural Gas Derivative Contracts [Member] | NGPL TexOk basis swaps [Member] | MEMP [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	300,000
Spread	(0.05)
2017 [Member] | Crude Oil Derivative Contracts [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price	87.62
Average Monthly Volume (Bbls)	9,500
2017 [Member] | Crude Oil Derivative Contracts [Member] | Fixed price swap contracts [Member] | MEMP [Member]
Derivative [Line Items]
Weighted-average fixed price	84.38
Average Monthly Volume (Bbls)	326,600
2018 [Member] | Natural Gas Derivative Contracts [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	1,500,000
Weighted-average fixed price	4.30
2018 [Member] | Natural Gas Derivative Contracts [Member] | Fixed price swap contracts [Member] | MEMP [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	2,160,000
Weighted-average fixed price	4.51
2018 [Member] | Crude Oil Derivative Contracts [Member] | Fixed price swap contracts [Member]
Derivative [Line Items]
Weighted-average fixed price	87.00
Average Monthly Volume (Bbls)	7,625
2018 [Member] | Crude Oil Derivative Contracts [Member] | Fixed price swap contracts [Member] | MEMP [Member]
Derivative [Line Items]
Weighted-average fixed price	83.74
Average Monthly Volume (Bbls)	312,000
2019 [Member] | Natural Gas Derivative Contracts [Member] | Fixed price swap contracts [Member] | MEMP [Member]
Derivative [Line Items]
Average Monthly Volume (MMBtu)	1,914,583
Weighted-average fixed price	4.75
2019 [Member] | Crude Oil Derivative Contracts [Member] | Fixed price swap contracts [Member] | MEMP [Member]
Derivative [Line Items]
Weighted-average fixed price	85.52
Average Monthly Volume (Bbls)	160,000

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Earnings per Share - Summary of Calculation of Supplemental EPS (Detail) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2014
Numerator:
Net income (loss) available to common stockholders	$ 9,928	$ (951,801)
Denominator:
Weighted average common shares outstanding	192,500	192,500
Restricted common shares	216
Weighted average common and common equivalent shares outstanding	192,716	192,500
Basic EPS	$ 0.05	$ (4.94)
Diluted EPS	$ 0.05	$ (4.94)
Supplemental EPS [Member]
Numerator:
Net income (loss) available to common stockholders	$ 9,928	$ (930,071)
Denominator:
Weighted average common shares outstanding	192,500	192,500
Restricted common shares	216
Weighted average common and common equivalent shares outstanding	192,716	192,500
Basic EPS	$ 0.05	$ (4.83)
Diluted EPS	$ 0.05	$ (4.83)

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Long Term Debt - Consolidated and Combined Debt Obligations (Parenthetical) (Detail) (USD $) In Millions, unless otherwise specified	9 Months Ended			12 Months Ended		9 Months Ended		9 Months Ended		9 Months Ended		9 Months Ended
	Sep. 30, 2014 PIK notes [Member]	Sep. 30, 2014 7.625 % Senior Notes Due May 2021 [Member]	Sep. 30, 2014 MRD [Member] 2.0 billion revolving credit facility [Member]	Dec. 31, 2013 MRD [Member] 1.0 billion revolving credit facility [Member]	Dec. 31, 2013 MRD [Member] PIK notes [Member]	Sep. 30, 2014 MRD [Member] 5.875% Senior Unsecured Notes Due July 2022	Dec. 31, 2013 MRD [Member] WildHorse Resources, LLC [Member] 325.0 Million Lien Term Facility [Member]	Sep. 30, 2014 MEMP [Member] 2.0 billion revolving credit facility [Member]	Dec. 31, 2013 MEMP [Member] 2.0 billion revolving credit facility [Member]	Sep. 30, 2014 MEMP [Member] 7.625 % Senior Notes Due May 2021 [Member]	Dec. 31, 2013 MEMP [Member] 7.625 % Senior Notes Due May 2021 [Member]	Sep. 30, 2014 MEMP [Member] 6.875% Senior Unsecurred Notes Due August 2022 [Member]	Dec. 31, 2013 MEMP [Member] 6.875% Senior Unsecurred Notes Due August 2022 [Member]
Debt Instrument [Line Items]
Credit facilities			$ 2,000.0	$ 1,000.0			$ 325.0	$ 2,000.0	$ 2,000.0
Senior notes maturity date	Dec. 15, 2018	May 01, 2021	Jun. 30, 2019			Jul. 31, 2022		Mar. 31, 2018		May 31, 2021		Aug. 31, 2022
Termination date of revolving credit facility				Jun. 30, 2014
Debt interest rate, minimum	10.00%				10.00%
Senior notes redemption date					Jun. 30, 2014
Debt interest rate, maximum	10.75%				10.75%
Debt interest rate		7.625%				5.875%				7.625%	7.625%	6.875%	6.875%
Estimated fair value of fixed rate debt					$ 348.3	$ 582.0				$ 700.0	$ 721.0	$ 475.0

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Related Party Transactions - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	0 Months Ended					9 Months Ended	0 Months Ended	9 Months Ended			9 Months Ended		9 Months Ended		0 Months Ended
	May 01, 2014	Nov. 01, 2011 MMBTU_day	May 01, 2014 Classic [Member]	Mar. 28, 2014 Propel [Member]	Mar. 17, 2014 WildHorse Resources, LLC [Member]	Sep. 30, 2014 WildHorse Resources, LLC [Member]	Mar. 10, 2014 BlueStone Natural Resources Holdings, LLC [Member]	Sep. 30, 2014 WHR Management Company [Member]	Sep. 30, 2014 NGPCIF [Member]	Feb. 28, 2014 NGPCIF [Member]	Sep. 30, 2014 NGPCIF [Member] WildHorse Resources, LLC [Member]	Mar. 28, 2013 NGPCIF [Member] WildHorse Resources, LLC [Member]	Sep. 30, 2014 NGPCIF [Member] WildHorse Resources, LLC [Member] Estimated Customary Post Closing Adjustments [Member]	Apr. 01, 2014 NGPCIF [Member] WildHorse Resources, LLC [Member] Estimated Customary Post Closing Adjustments [Member]	Oct. 01, 2013 Tanos Energy LLC [Member]	Oct. 01, 2013 Prospect Energy LLC [Member]	Oct. 01, 2013 Jackson County [Member]	Dec. 12, 2012 MEMP [Member]
Related Party Transaction [Line Items]
Business acquisition purchase price										$ 63.4		$ 200.0		$ 33.3
Date of acquisition common control									Feb. 28, 2014		Mar. 28, 2013		Apr. 01, 2014
Oil and gas properties				3.3											77.4	16.3	2.6
Total cash consideration							1.2
Amount of gain over the book value							0.5
Gain recognized as contribution							0.5
Common stock lock-up agreement period						180 days
Amount receivable under management agreement																		0.4
Management fee per month								1.0
Service agreement termination period								90 days
Primary term of gas processing agreement					15 years
Minimum annual processing fee					$ 18.3
Fee per MMBTU	0.30
Natural gas produced per day		50,000
Annual inflationary escalation	3.50%
Price per unit	0.07
Water disposal fee per barrel			1.10
Water disposal agreement period			3 years

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Fair Value Measurements of Financial Instruments - Additional Information (Detail) (MEMP [Member], USD $) In Millions, unless otherwise specified	3 Months Ended	9 Months Ended	3 Months Ended	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2014	Sep. 30, 2013 Maximum [Member]	Sep. 30, 2013 Maximum [Member]
Fair Value Of Assets And Liabilities Measured On Non Recurring Basis [Line Items]
Asset impairments	$ 67.2	$ 67.2	$ 0.1	$ 0.1

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Long-Term Incentive Plans (Tables)

9 Months Ended

Sep. 30, 2014

Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]

Summary of Information Regarding Restricted Common Unit Awards

The following table summarizes information regarding restricted common share awards granted under the MRD LTIP for the periods presented:

	Number of Shares			Weighted-Average Grant Date Fair Value per Share (1)
Restricted common shares outstanding at December 31, 2013		—		$	—
Granted (2)		1,068,422		$	19.00
Forfeited		(9,211	)	$	19.00
Restricted common units outstanding at September 30, 2014		1,059,211		$	19.00

(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 2014 was $20.3 million   based on a grant date market price of $19.00 per share.

The following table summarizes information regarding restricted common unit awards granted under the MEMP LTIP for the periods presented:

	Number of Units			Weighted-Average Grant Date Fair Value per Unit (1)
Restricted common units outstanding at December 31, 2013		706,927		$	18.62
Granted (2)		684,954		$	22.39
Forfeited		(36,112	)	$	20.43
Vested		(260,067	)	$	18.56
Restricted common units outstanding at September 30, 2014		1,095,702		$	20.93

(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 2014 was $15.3 million   based on a grant date market price range of $21.99 - $23.40 per unit

Summary of Amount of Compensation Expense Recognized

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

For the Three Months				For the Nine Months
Ended September 30,				Ended September 30,
2014		2013		2014		2013
$	1,313	$	—	$	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				For the Nine Months
Ended September 30,				Ended September 30,
2014		2013		2014		2013
$	2,427	$	1,237	$	5,387	$	2,322

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Related Party Transactions - Schedule of Net Assets Recorded (Detail) (NGPCIF [Member], USD $) In Thousands, unless otherwise specified	Feb. 28, 2014
NGPCIF [Member]
Related Party Transaction [Line Items]
Accounts receivable	$ 2,274
Oil and natural gas properties, net	40,056
Accrued liabilities	(297)
Asset retirement obligations	(277)
Net assets	$ 41,756

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Long-Term Incentive Plans - Summary of Information Regarding Restricted Common Unit Awards (Detail) (Restricted Stock [Member], USD $)	9 Months Ended
	Sep. 30, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted common shares outstanding, Number of Units, Beginning Balance	0
Granted, Number of Units	1,068,422
Forfeited, Number of Units	(9,211)
Restricted common shares outstanding, Number of Units, Ending Balance	1,059,211
Restricted common shares outstanding, Weighted-Average Grant Date Fair Value Per Unit, Beginning Balance	$ 0
Granted, Weighted-Average Grant Date Fair Value Per Unit	$ 19.00
Forfeited, Weighted-Average Grant Date Fair Value Per Unit	$ 19.00
Restricted common shares outstanding, Weighted-Average Grant Date Fair Value Per Unit, Ending Balance	$ 19.00
MEMP [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted, Number of Units	684,954
Forfeited, Number of Units	(36,112)
Restricted common shares outstanding, Weighted-Average Grant Date Fair Value Per Unit, Beginning Balance	$ 18.62
Granted, Weighted-Average Grant Date Fair Value Per Unit	$ 22.39
Forfeited, Weighted-Average Grant Date Fair Value Per Unit	$ 20.43
Restricted common shares outstanding, Weighted-Average Grant Date Fair Value Per Unit, Ending Balance	$ 20.93
Restricted common shares outstanding, Number of Units, Beginning Balance	706,927
Vest, Number of Units	(260,067)
Restricted common shares outstanding, Number of Units, Ending Balance	1,095,702
Vested, Weighted-Average Grant Date Fair Value Per Unit	$ 18.56

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Commitments and Contingencies - Minimum Balances Attributable to Net Working Interest (Detail) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014
June 30, 2015 [Member]
Asset retirement obligations
Minimum balances attributable to REO's net working interest	$ 72,450
June 30, 2016 [Member]
Asset retirement obligations
Minimum balances attributable to REO's net working interest	76,590
December 31, 2016 [Member]
Asset retirement obligations
Minimum balances attributable to REO's net working interest	$ 78,660

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Long Term Debt - Borrowing Base Credit Facility (Parenthetical) (Detail) (USD $) In Millions, unless otherwise specified	Sep. 30, 2014
MRD [Member] | 2.0 Billion Revolving Credit Facility Due June 2019 [Member]
Credit Facilities [Line Items]
Revolving credit facility	$ 2,000.0
MEMP [Member] | 2.0 Billion Revolving Credit Facility Due March 2018 [Member]
Credit Facilities [Line Items]
Revolving credit facility	$ 2,000.0

XML

Incentive Units - Additional Information (Detail) (USD $)	9 Months Ended			0 Months Ended	9 Months Ended				9 Months Ended		3 Months Ended	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013	Apr. 01, 2013 Tanos Energy LLC [Member]	Sep. 30, 2013 Tanos Energy LLC [Member]	Sep. 30, 2014 BlueStone Natural Resources Holdings, LLC [Member]	Sep. 30, 2013 BlueStone Natural Resources Holdings, LLC [Member]	Sep. 30, 2014 BlueStone Natural Resources Holdings, LLC [Member] Special Tier and Tier I Unit Holders [Member]	Sep. 30, 2014 WildHorse Resources, LLC [Member]	Sep. 30, 2014 MRD Holdco LLC [Member]	Sep. 30, 2014 MRD Holdco LLC [Member] Subsequent Incentive Units [Member]	Sep. 30, 2014 MRD Holdco LLC [Member] Exchanged Incentive Units [Member]	Sep. 30, 2014 MRD Holdco LLC [Member] Exchanged Incentive Units [Member] Subsequent Incentive Units [Member]	Sep. 30, 2014 Minimum [Member]	Sep. 30, 2014 Maximum [Member]
Equity Incentive Plan [Line Items]
Ranging of distributions for incentive units														10.00%	31.50%
Percentage of future distributions incentive unit holders are entitled to after payout has been achieved								16.50%			0.70%	9.30%
Percentage of ownership interest sold to company				1.066%
Compensation expense as component of general and administrative expense					$ 5,800,000
Compensation expense						1,000,000	19,100,000		831,100,000		600,000	136,700,000
Percentage of interest contributed former management members									0.10%
Exchange of incentive units	193,559,211		0						42,334,323
Cash consideration paid to certain former management members									30,000,000
Carrying amount of the noncontrolling interest	1,022,721,000		580,615,000						400,000
Fair value of consideration paid for noncontrolling interests	3,292,000	1,270,000							3,300,000
Cash component of incentive unit compensation expense									26,700,000
Incentive units exchanges for shares of our common stock									804,400,000
The number of incentive units authorized by governing documents										1,000
Incentive units granted in an exchange for cancelled predecessor awards												930
Remaining expected life													3 years
Unrecognized compensation expense											$ 5,300,000	$ 158,500,000
Subsequent incentive units											70

XML

Business Segment Data - Schedule of Consolidated and Combined Statement of Operations Disaggregated by Reportable Segment (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Revenues:
Oil & natural gas sales	$ 244,161	$ 152,762	$ 669,301	$ 420,857
Other revenues	1,332	753	3,584	1,884
Total revenues	245,493	153,515	672,885	422,741
Costs and expenses:
Lease operating	46,211	29,395	111,887	81,746
Pipeline operating	431	394	1,596	1,343
Exploration	175	1,292	1,465	2,265
Production and ad valorem taxes	14,040	7,422	33,623	23,478
Depreciation, depletion, and amortization	84,447	45,136	215,906	132,328
Impairment of proved oil and natural gas properties	67,181	21	67,181	21
Incentive unit compensation expense	25,550	19,069	969,390	19,069
General and administrative	21,196	19,646	61,061	55,982
Accretion expense	1,553	1,354	4,601	4,016
(Gain) loss on commodity derivative instruments	(189,492)	2,028	11,580	(29,556)
(Gain) loss on sale of properties	0	(90,063)	3,057	(86,218)
Other, net		24	(12)	622
Total costs and expenses	71,292	35,718	1,481,335	205,096
Operating income (loss)	174,201	117,797	(808,450)	217,645
Other income (expense):
Interest expense, net	(36,345)	(20,615)	(104,928)	(41,994)
Loss on extinguishment of debt	0		(37,248)
Other, net	15	24	102	81
Total other income (expense)	(36,330)	(20,591)	(142,074)	(41,913)
Income (loss) before income taxes	137,871	97,206	(950,524)	175,732
Income tax benefit (expense)	(25,834)	(1,244)	(14,398)	(1,432)
Net income (loss)	112,037	95,962	(964,922)	174,300
Operating Segments [Member]
Costs and expenses:
Exploration	175	1,292	1,465	2,265
Depreciation, depletion, and amortization	83,478	45,136	213,326	132,328
Impairment of proved oil and natural gas properties	67,181	50,310	67,181	50,310
Accretion expense	1,553	1,354	4,601	4,016
(Gain) loss on commodity derivative instruments	(189,492)	2,028	11,580	(29,556)
(Gain) loss on sale of properties		(90,063)	3,057	(86,218)
Other income (expense):
Interest expense, net	(36,345)	(20,615)	(104,928)	(41,994)
Loss on extinguishment of debt			(37,248)
Income tax benefit (expense)	(25,834)	(1,244)	(14,398)	(1,432)
Net income (loss)	113,092	34,835	(975,186)	123,987
Operating Segments [Member] | MRD [Member]
Revenues:
Oil & natural gas sales	98,337	60,179	300,931	171,013
Other revenues	5	115	561	348
Total revenues	98,342	60,294	301,492	171,361
Costs and expenses:
Lease operating	6,991	6,144	18,657	17,065
Exploration	133	439	1,213	1,137
Production and ad valorem taxes	3,571	1,354	10,494	8,563
Depreciation, depletion, and amortization	39,550	20,476	107,496	62,605
Incentive unit compensation expense	25,550	19,069	969,390	19,069
General and administrative	9,982	7,653	29,301	22,466
Accretion expense	170	178	495	547
(Gain) loss on commodity derivative instruments	(33,090)	213	(17,130)	(8,361)
(Gain) loss on sale of properties	0	(90,083)	3,057	(83,370)
Other, net				(25)
Total costs and expenses	52,857	(34,557)	1,122,973	39,696
Operating income (loss)	45,485	94,851	(821,481)	131,665
Other income (expense):
Interest expense, net	(9,886)	(9,041)	(44,355)	(15,947)
Loss on extinguishment of debt	0		(37,248)
Earnings from equity investments	86	(10,838)	(12,844)	(24)
Other, net	15	49	102	81
Total other income (expense)	(9,785)	(19,830)	(94,345)	(15,890)
Income (loss) before income taxes	35,700	75,021	(915,826)	115,775
Income tax benefit (expense)	(25,834)	(1,147)	(14,323)	(1,147)
Net income (loss)	9,866	73,874	(930,149)	114,628
Operating Segments [Member] | MEMP [Member]
Revenues:
Oil & natural gas sales	145,824	92,583	368,370	249,844
Other revenues	1,419	657	3,160	1,672
Total revenues	147,243	93,240	371,530	251,516
Costs and expenses:
Lease operating	39,312	23,334	93,367	64,922
Pipeline operating	431	394	1,596	1,343
Exploration	42	853	252	1,128
Production and ad valorem taxes	10,469	6,068	23,129	14,915
Depreciation, depletion, and amortization	43,928	24,660	105,830	69,723
Impairment of proved oil and natural gas properties	67,181	50,310	67,181	50,310
General and administrative	11,214	11,928	31,760	33,411
Accretion expense	1,383	1,176	4,106	3,469
(Gain) loss on commodity derivative instruments	(156,402)	1,815	28,710	(21,195)
(Gain) loss on sale of properties	0	20	0	(2,848)
Other, net		50	(12)	647
Total costs and expenses	17,558	120,608	355,919	215,825
Operating income (loss)	129,685	(27,368)	15,611	35,691
Other income (expense):
Interest expense, net	(26,459)	(11,574)	(60,573)	(26,047)
Loss on extinguishment of debt	0		0
Total other income (expense)	(26,459)	(11,574)	(60,573)	(26,047)
Income (loss) before income taxes	103,226	(38,942)	(44,962)	9,644
Income tax benefit (expense)		(97)	(75)	(285)
Net income (loss)	103,226	(39,039)	(45,037)	9,359
Other, Adjustments & Eliminations [Member]
Revenues:
Other revenues	(92)	(19)	(137)	(136)
Total revenues	(92)	(19)	(137)	(136)
Costs and expenses:
Lease operating	(92)	(83)	(137)	(241)
Depreciation, depletion, and amortization	969		2,580
Impairment of proved oil and natural gas properties		(50,289)		(50,289)
General and administrative		65		105
(Gain) loss on sale of properties	0	0	0	0
Other, net		(26)
Total costs and expenses	877	(50,333)	2,443	(50,425)
Operating income (loss)	(969)	50,314	(2,580)	50,289
Other income (expense):
Loss on extinguishment of debt	0		0
Earnings from equity investments	(86)	10,838	12,844	24
Other, net		(25)
Total other income (expense)	(86)	10,813	12,844	24
Income (loss) before income taxes	(1,055)	61,127	10,264	50,313
Net income (loss)	$ (1,055)	$ 61,127	$ 10,264	$ 50,313

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Business Segment Data - Additional Information (Detail)	9 Months Ended
	Sep. 30, 2014 Segment
Segment Reporting [Abstract]
Number of reportable business segments	2

XML

Commitments and Contingencies - Additional Information (Detail) (USD $)			12 Months Ended						9 Months Ended
	Sep. 30, 2014	Dec. 31, 2013	Dec. 31, 2012 Dubach [Member] MMBTU	Dec. 31, 2013 Dubberly [Member] MMBTU	Dec. 31, 2012 Minimum [Member] Dubach [Member]	Dec. 31, 2013 Minimum [Member] Dubberly [Member]	Dec. 31, 2012 Maximum [Member] Dubach [Member]	Dec. 31, 2013 Maximum [Member] Dubberly [Member]	Sep. 30, 2014 MEMP [Member]
Loss Contingencies [Line Items]
Environmental reserves	$ 2,300,000	$ 600,000
Estimated environmental remediation expenses									2,900,000
Maximum remaining obligation	$ 9,700,000
Expansion of processing plant			70
Payback demand fee for third party			110.00%
Payback demand quality per day			136,200
Payback of fee in excess of demand quantity			0.26
Increase in demand fee					0.26		0.275
Payback demand fee received by the third party				110.00%
Payback of demand fee				0.31
Monthly demand quantity				56,750
Increase of demand quantity				113,500
Decrease in demand fee						0.275		0.31

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Incentive Units - Fair Value of Incentive Units Estimated (Detail)	9 Months Ended
	Sep. 30, 2014
Exchanged Incentive Units [Member]
Schedule Of Share Based Compensation Valuation Assumptions [Line Items]
Valuation date	Sep. 30, 2014
Dividend yield	0.00%
Expected volatility	2147.00%
Risk-free rate	90.00%
Expected life (years)	2 years 8 months 1 day
Subsequent Incentive Units [Member]
Schedule Of Share Based Compensation Valuation Assumptions [Line Items]
Valuation date	Sep. 30, 2014
Dividend yield	0.00%
Expected volatility	2147.00%
Risk-free rate	90.00%
Expected life (years)	2 years 8 months 1 day

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Earnings per Share - Summary of Calculation of Supplemental EPS (Parenthetical) (Detail) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2014
Earnings Per Share [Line Items]
Shares excluded from computation of EPS	206,956
Supplemental EPS [Member]
Earnings Per Share [Line Items]
Shares excluded from computation of EPS	206,956

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Acquisitions and Divestitures (Tables)

9 Months Ended

Sep. 30, 2014

Acquisition-Related Costs

Acquisition-related costs are included in general and administrative expenses in the accompanying statements of operations for the periods indicated below (in thousands):

For the Three Months				For the Nine Months
Ended September 30,				Ended September 30,
2014		2013		2014		2013
$	1,425	$	2,977	$	5,480	$	5,073

Unaudited Pro Forma Results of Operations

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

	For the Three Months			For the Nine Months
	Ended September 30,			Ended September 30,
	2014	2013		2014			2013
	(In thousands, except per unit amounts)
Revenues	n/a	$	203,461	$	764,084		$	561,359
Net income (loss)	n/a		115,666		(931,903	)		218,870
Basic and diluted earnings per share	n/a	$	—	$	(4.94	)	$	—

Eagle Ford and Wyoming Acquisition [Member]

Summary of Fair Value Assessment of Assets Acquired and Liabilities Assumed

The following table summarizes the preliminary fair value assessment of the assets acquired and liabilities assumed as of the acquisition date (in thousands):

	Eagle Ford			Wyoming
	Acquisition			Acquisition
Oil and gas properties	$	168,606		$	922,686
Asset retirement obligations		(285	)		(3,328	)
Revenue Payable		—			(444	)
Accrued liabilities		(250	)		(7,237	)
Total identifiable net assets	$	168,071		$	911,677

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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, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Net recorded fair value	$ 37,421	$ 9,289
Asset Derivatives, Net recorded fair value	34,515	48,616
Liability Derivatives, Net recorded fair value	5,109	9,711
Liability Derivatives, Net recorded fair value	15,275	6,080
Short-term derivative instruments [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	48,405	22,604
Asset Derivatives, Netting arrangements	(10,984)	(13,315)
Asset Derivatives, Net recorded fair value	37,421	9,289
Liability Derivatives, Gross fair value	16,093	23,026
Liability Derivatives, Netting arrangements	(10,984)	(13,315)
Liability Derivatives, Net recorded fair value	5,109	9,711
Short-term derivative instruments [Member] | Commodity contracts [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	48,405	21,759
Liability Derivatives, Gross fair value	12,458	19,739
Short-term derivative instruments [Member] | Interest rate swaps [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value		845
Liability Derivatives, Gross fair value	3,635	3,287
Long-term derivative instruments [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	81,401	83,334
Asset Derivatives, Netting arrangements	(46,886)	(34,718)
Asset Derivatives, Net recorded fair value	34,515	48,616
Liability Derivatives, Gross fair value	62,161	40,798
Liability Derivatives, Netting arrangements	(46,886)	(34,718)
Liability Derivatives, Net recorded fair value	15,275	6,080
Long-term derivative instruments [Member] | Commodity contracts [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	81,306	83,295
Liability Derivatives, Gross fair value	62,084	38,495
Long-term derivative instruments [Member] | Interest rate swaps [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	95	39
Liability Derivatives, Gross fair value	$ 77	$ 2,303

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Acquisitions and Divestitures - Additional Information (Detail) (USD $)	9 Months Ended		0 Months Ended	9 Months Ended		3 Months Ended	9 Months Ended	3 Months Ended	9 Months Ended	0 Months Ended	9 Months Ended	0 Months Ended			9 Months Ended		0 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Apr. 30, 2013 WildHorse Resources, LLC [Member]	Sep. 30, 2013 East Texas and Rockies Acquisitions	Sep. 30, 2013 BlueStone Natural Resources Holdings, LLC [Member]	Sep. 30, 2014 Wyoming Acquisition [Member]	Sep. 30, 2014 Wyoming Acquisition [Member]	Sep. 30, 2014 Eagle Ford Acquisition [Member]	Sep. 30, 2014 Eagle Ford Acquisition [Member]	May 09, 2014 Golden Energy [Member]	Sep. 30, 2013 Propel [Member]	Jan. 01, 2013 Tanos [Member] Natural Gas Pipe Lines [Member]	Jan. 01, 2013 Tanos [Member] Natural Gas Pipe Lines [Member] Minimum [Member]	Jan. 01, 2013 Tanos [Member] Natural Gas Pipe Lines [Member] Maximum [Member]	Sep. 30, 2013 Tanos [Member] Oil And Natural Gas Properties [Member]	Sep. 30, 2013 Tanos [Member] Non Operated Oil And Natural Gas Properties [Member]	May 10, 2013 Black Diamond [Member]
Business Acquisition [Line Items]
Oil and gas properties			$ 67,100,000	$ 29,400,000		$ 911,700,000			$ 168,100,000		$ 8,500,000
Business acquisition, revenues							41,600,000	11,500,000	25,900,000
Business acquisition, earnings							16,500,000	5,300,000	13,300,000
Percentage of leasehold interest acquired									30.00%
Proceeds from sale of oil and gas properties										7,600,000			1,500,000	2,000,000	2,900,000		33,000,000
Gain (loss) on sale of natural gas pipeline					90,200,000					(3,200,000)		1,400,000				1,400,000	(6,800,000)
Period for drilling any new wells												3 years
Contingent consideration related to sale of natural gas pipeline												400,000
Net book value of oil and gas properties																	39,800,000
Proceeds from the sale of oil and natural gas properties	$ 6,700,000	$ 156,799,000			$ 117,900,000

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Long-Term Incentive Plans - Summary of Amount of Compensation Expense Recognized (Detail) (MEMP [Member], USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
MEMP [Member]
Compensation Related Costs Disclosure [Line Items]
Amortization of MEMP equity awards	$ 2,427	$ 1,237	$ 5,387	$ 2,322

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Commitments and Contingencies (Tables)

9 Months Ended

Sep. 30, 2014

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, 2014 (in thousands):

	Amortized
Investment	Cost
U.S. Bank Money Market Cash Equivalent	$	133,275
Less: Outside working interest owners share		(64,305	)
	$	68,970

Minimum Balances Attributable to Net Working Interest

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

June 30, 2015	$	72,450
June 30, 2016	$	76,590
December 31, 2016	$	78,660

Minimum Commitments to Gatherer before Other Owner Contributions

WildHorse Resources’ minimum commitments to the Gatherer, before other owner contributions, as of September 30, 2014 were as follows (in thousands):

	Dubach		Dubberly
2014	$	3,446	$	1,436
2015		13,671		11,393
2016		13,709		11,424
2017		13,671		11,393
2018		12,772		10,643
Total	$	57,269	$	46,289

Wyoming Acquisition [Member]

CO2 Minimum Purchase Commitment

At September 30, 2014, MEMP had a CO₂ purchase commitment with a third party that was assumed in its Wyoming Acquisition. The table below outlines MEMP’s purchase commitment under the contract for the remainder of 2014 and annually thereafter (in thousands):

			Payment or Settlement due by Period
Purchase commitment	Total		Remainder 2014		2015		2016		2017		2018		Thereafter
CO2 minimum purchase commitment:
Estimated payment obligation	$	62,103	$	3,203	$	12,222	$	12,101	$	11,624	$	7,872	$	15,081

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Asset Retirement Obligations - Summary of Changes in Asset Retirement Obligations (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations at beginning of period			$ 111,769
Liabilities added from acquisitions or drilling			5,053
Liabilities removed upon sale of wells to an affiliate			(1,636)
Liabilities removed upon plugging and abandoning			(344)
Revisions			67
Accretion expense	1,553	1,354	4,601	4,016
Asset retirement obligations at end of period	$ 119,510		$ 119,510

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Stockholders' Equity and Noncontrolling Interests - Summary of Changes In Common Shares Issued (Detail)	0 Months Ended	9 Months Ended
	Jun. 18, 2014	Sep. 30, 2014
Class of Stock [Line Items]
Balance January 1, 2014		0
Shares of common stock issued sold in initial public offering (Note 1)	21,500,000
Restricted common shares forfeited		(9,211)
Balance September 30, 2014		193,559,211
Common Stock [Member]
Class of Stock [Line Items]
Shares of common stock issued in connection with restructuring transactions (Note 1)		171,000,000
Shares of common stock issued sold in initial public offering (Note 1)		21,500,000
Restricted common shares issued (Note 11)		1,068,422

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Long Term Debt - PIK notes - Additional Information (Detail) (USD $)	3 Months Ended	9 Months Ended		0 Months Ended	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2014	Sep. 30, 2013	Dec. 18, 2013 PIK notes [Member]	Sep. 30, 2014 PIK notes [Member]	Jun. 27, 2014 PIK notes [Member]	Jun. 18, 2014 PIK notes [Member]
Debt Obligations [Line Items]
Aggregate principal amount				$ 350,000,000			$ 350,000,000
Percentage of PIK toggle notes issued at par				98.00%
Cash reserve for payment of interest on notes				50,000,000
Payment of distribution to funds			363,437,000	210,000,000
Debt redemption price percentage					102.00%
Irrevocable deposits						360,000,000
Extinguishment loss	$ 0	$ (37,248,000)			$ 23,600,000

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Risk Management and Derivative Instruments - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	9 Months Ended	0 Months Ended	9 Months Ended
	Sep. 30, 2014	Jul. 02, 2014 Interest rate swaps [Member]	Sep. 30, 2014 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	$ 29.0		$ 37.5
Aggregate termination amount paid to counterparties		$ 0.7

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Acquisitions and Divestitures

9 Months Ended

Sep. 30, 2014

Business Combinations [Abstract]

Acquisitions and Divestitures

Note 3.  Acquisitions and Divestitures

Acquisition-related costs are included in general and administrative expenses in the accompanying statements of operations for the periods indicated below (in thousands):

For the Three Months				For the Nine Months
Ended September 30,				Ended September 30,
2014		2013		2014		2013
$	1,425	$	2,977	$	5,480	$	5,073

2014 Acquisitions

On July 1, 2014, MEMP consummated a transaction to acquire certain oil and natural gas liquids properties from a third party in Wyoming for an aggregate purchase price of approximately $911.7 million, including estimated post-closing adjustments (the “Wyoming Acquisition”).  Revenues of $41.6 million were recorded in the statement of operations generated earnings of approximately $16.5 million related to the Wyoming Acquisition subsequent to the closing date.

On March 25, 2014, MEMP closed a transaction to acquire certain oil and natural gas producing properties from a third party in the Eagle Ford for approximately $168.1 million, including estimated customary post-closing adjustments (the “Eagle Ford Acquisition”).  In addition, MEMP acquired a 30% interest in the seller’s Eagle Ford leasehold. During the three and nine months ended September 30, 2014, revenues of approximately $11.5 million and $25.9 million, respectively, were recorded in the statement of operations related to the Eagle Ford Acquisition subsequent to the closing date and MEMP generated earnings of approximately $5.3 million and $13.3 million, respectively.

The following table summarizes the preliminary fair value assessment of the assets acquired and liabilities assumed as of the acquisition date (in thousands):

	Eagle Ford			Wyoming
	Acquisition			Acquisition
Oil and gas properties	$	168,606		$	922,686
Asset retirement obligations		(285	)		(3,328	)
Revenue Payable		—			(444	)
Accrued liabilities		(250	)		(7,237	)
Total identifiable net assets	$	168,071		$	911,677

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

	For the Three Months			For the Nine Months
	Ended September 30,			Ended September 30,
	2014	2013		2014			2013
	(In thousands, except per unit amounts)
Revenues	n/a	$	203,461	$	764,084		$	561,359
Net income (loss)	n/a		115,666		(931,903	)		218,870
Basic and diluted earnings per share	n/a	$	—	$	(4.94	)	$	—

2014 Divestitures

On May 9, 2014, Golden Energy sold certain producing and non-producing properties in the Mississippian oil play of Northern Oklahoma to a third party for approximately $7.6 million, including estimated customary post-closing adjustments, and recorded a loss of $3.2 million.

2013 Acquisitions

On April 30, 2013, WildHorse Resources purchased certain oil and gas properties and leases in Louisiana from a third party for approximately $67.1 million.

MEMP closed two separate transactions during the nine months ended September 30, 2013 to acquire certain oil and natural gas properties from third parties in East Texas (the “East Texas Acquisition”) and the Rockies (the “Rockies Acquisition”) for approximately $29.4 million in aggregate. The East Texas Acquisition closed on September 6, 2013 and the Rockies Acquisition closed on August 30, 2013.

During the nine months ended September 30, 2013, Propel Energy acquired incremental interests in certain oil and gas properties and leases in the Hendrick Field located in Winkler County, Texas from third parties in three separate transactions for an aggregate purchase price of approximately $8.5 million.

2013 Divestitures

On January 1, 2013, Tanos sold a natural gas gathering pipeline located in East Texas, which it had originally acquired in April 2010, to a privately held gas transportation company for a minimum purchase price of $1.5 million.  The maximum allowable additional proceeds are $2.0 million.  The contingent consideration is based on the natural gas pipeline servicing any new wells that Tanos drills in the area over the following three years.  The contingent consideration portion of an arrangement is recorded when the consideration is determined to be realizable. Tanos recorded an aggregate gain of approximately $1.4 million related to this transaction, of which $0.4 million was contingent consideration.  During the nine months ended September 30, 2013, Tanos also sold certain non-operated oil and gas properties for $2.9 million and recorded a gain of $1.4 million.

On May 10, 2013, Black Diamond entered into a purchase and sale agreement with a third party to sell certain of its Wyoming oil and gas properties with an estimated net book value of $39.8 million for $33.0 million, before customary adjustments. As a result, Black Diamond recorded a loss on the sale of $6.8 million. This transaction closed on June 4, 2013.

During the nine months ended September 30, 2013, BlueStone entered into an agreement with a third party to sell its remaining interest in certain properties in the Mossy Grove Prospect in Walker and Madison Counties located in East Texas. Total cash consideration received by BlueStone was approximately $117.9 million, which exceeded the net book value of the properties sold by $90.2 million. The transaction closed on July 31, 2013.

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Long Term Debt - WildHorse Resources Revolving Credit Facility and Second Lien Facility - Additional Information (Detail) (USD $)	3 Months Ended	9 Months Ended			0 Months Ended		9 Months Ended	0 Months Ended
	Sep. 30, 2014	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014 Revolving Credit Facility [Member]	Apr. 03, 2013 Revolving Credit Facility [Member] WildHorse Resources, LLC [Member]	Jun. 13, 2013 Revolving Credit Facility [Member] WildHorse Resources, LLC [Member] Second Lien Term Loan [Member]	Sep. 30, 2014 Revolving Credit Facility [Member] WildHorse Resources, LLC [Member] Second Lien Term Loan [Member]	Jun. 13, 2013 Revolving Credit Facility [Member] WildHorse Resources, LLC [Member] Second Lien Term Loan [Member] Alternative Base Rate	Jun. 13, 2013 Revolving Credit Facility [Member] WildHorse Resources, LLC [Member] Second Lien Term Loan [Member] London Interbank Offered Rate (LIBOR)
Debt Obligations [Line Items]
Initial borrowing base of second lien term facility				$ 2,000,000,000	$ 1,000,000,000	$ 325,000,000
Line of credit facility, initial borrowing base					300,000,000
Line of credit, minimum collateral percentage					80.00%	80.00%
Debt instrument interest rate								5.25%	6.25%
Cash distribution paid			363,437,000			225,000,000
Loss on extinguishment of debt	$ 0	$ (37,248,000)					$ (13,700,000)

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Acquisitions and Divestitures - Summary of Fair Value Assessment of Assets Acquired and Liabilities Assumed (Detail) (USD $) In Thousands, unless otherwise specified	Mar. 25, 2014 Eagle Ford Acquisition [Member]	Jun. 30, 2014 Wyoming Acquisition [Member]
Business Acquisition [Line Items]
Oil and gas properties	$ 168,606	$ 922,686
Asset retirement obligations	(285)	(3,328)
Revenue Payable		(444)
Accrued liabilities	(250)	(7,237)
Total identifiable net assets	$ 168,071	$ 911,677

XML

Restricted Investments (Tables)

9 Months Ended

Sep. 30, 2014

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,
	2014		2013
	(In thousands)
BOEM platform abandonment (See Note 15)	$	68,970	$	66,373
BOEM lease bonds		794		794
SPBPC Collateral:
Contractual pipeline and surface facilities abandonment		2,592		2,306
California State Lands Commission pipeline right-of-way bond		3,005		3,005
City of Long Beach pipeline facility permit		500		500
Federal pipeline right-of-way bond		307		307
Port of Long Beach pipeline license		100		100
Restricted investments	$	76,268	$	73,385

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Asset Retirement Obligations (Tables)

9 Months Ended

Sep. 30, 2014

Asset Retirement Obligation Disclosure [Abstract]

Summary of Changes in Asset Retirement Obligations

The following table presents the changes in the asset retirement obligations for the nine months ended September 30, 2014 (in thousands):

Asset retirement obligations at beginning of period	$	111,769
Liabilities added from acquisitions or drilling		5,053
Liabilities removed upon sale of wells to an affiliate		(1,636	)
Liabilities removed upon plugging and abandoning		(344	)
Revisions		67
Accretion expense		4,601
Asset retirement obligations at end of period	$	119,510

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Long Term Debt - Borrowing Base Credit Facility (Detail) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014
MRD [Member] | 2.0 Billion Revolving Credit Facility Due June 2019 [Member]
Credit Facilities [Line Items]
Borrowing base	$ 668,500
MEMP [Member] | 2.0 Billion Revolving Credit Facility Due March 2018 [Member]
Credit Facilities [Line Items]
Borrowing base	$ 1,315,000

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Acquisitions and Divestitures - Unaudited Pro Forma Results of Operations (Detail) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Business Combinations [Abstract]
Revenues	$ 203,461	$ 764,084	$ 561,359
Net income (loss)	$ 115,666	$ (931,903)	$ 218,870
Basic and diluted earnings per share		$ (4.94)

XML

Long Term Debt (Tables)

9 Months Ended

Sep. 30, 2014

Debt Disclosure [Abstract]

Consolidated and Combined Debt Obligations

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

	September 30,			December 31,
	2014			2013
	(In thousands)
MRD Segment:
MRD $2.0 billion revolving credit facility, variable-rate, due June 2019	$	28,000		$	—
WildHorse Resources $1.0 billion revolving credit facility, variable-rate, terminated June 2014		—			203,100
WildHorse Resources $325.0 million second lien term facility, variable-rate, terminated June 2014		—			325,000
10.00%/10.75% senior PIK toggle notes redeemed June 2014 (1)		—			350,000
5.875% senior unsecured notes, due July 2022 (2)		600,000			—
10.00%/10.75% senior PIK toggle notes unamortized discounts		—			(6,950	)
Subtotal		628,000			871,150
MEMP Segment:
MEMP $2.0 billion revolving credit facility, variable-rate, due March 2018		301,000			103,000
7.625% senior notes, fixed-rate, due May 2021 (3)		700,000			700,000
6.875% senior unsecurred notes, due August 2022 (4)		500,000			—
Unamortized discounts		(17,200	)		(10,933	)
Subtotal		1,483,800			792,067
Total long-term debt	$	2,111,800		$	1,663,217

(1)The estimated fair value of this fixed-rate debt was $348.3 million at December 31, 2013.  The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.

(2)The estimated fair value of this fixed-rate debt was $582.0 million September 30, 2014.  The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.

(3)The estimated fair value of this fixed-rate debt was $700.0 million and $721.0 million at September 30, 2014 and December 31, 2013, respectively.  The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.

(4)The estimated fair value of this fixed-rate debt was $475.0 million at September 30, 2014.  The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.

Borrowing Base Credit Facility

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

	September 30,
	2014
MRD Segment:
MRD $2.0 billion revolving credit facility, variable-rate, due June 2019	$	668,500
MEMP Segment:
MEMP $2.0 billion revolving credit facility, variable-rate, due March 2018		1,315,000

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

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

	For the Three Months						For the Nine Months
Credit Facility	Ended September 30,						Ended September 30,
	2014			2013			2014			2013
MRD Segment:
MRD revolving credit facility		3.31	%	n/a				2.40	%	n/a
MRD LLC revolver terminated December 2013	n/a				2.34	%	n/a				3.20	%
WildHorse Resources revolver terminated June 2014	n/a				4.51	%		4.04	%		3.44	%
WildHorse Resources second lien terminated June 2014	n/a				6.50	%		6.44	%		6.50	%
Black Diamond terminated November 2013	n/a			n/a			n/a				3.34	%
MEMP Segment:
MEMP revolving credit facility		2.16	%		2.13	%		2.08	%		2.55	%
WHT revolver terminated March 2013	n/a			n/a			n/a				2.29	%
Tanos revolver terminated April 2013	n/a			n/a			n/a				2.12	%
Stanolind revolver paid off by MEMP October 2013	n/a				3.44	%	n/a				3.52	%
Boaz revolver terminated October 2013	n/a				2.65	%	n/a				2.97	%
Crown revolver terminated October 2013	n/a				3.31	%	n/a				3.38	%
Propel Energy revolver paid off by MEMP October 2013	n/a				3.09	%	n/a				3.08	%

Summary of Unamortized Deferred Financing Costs Associated with Consolidated Debt Obligations

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

	September 30,		December 31,
	2014		2013
	(In thousands)
MRD Segment:
MRD revolving credit facility	$	4,433	$	—
MRD senior notes		12,825		—
WildHorse Resources revolving credit facility		—		2,436
WildHorse Resources second lien term loan		—		9,030
PIK notes		—		8,261
MEMP Segment:
MEMP revolving credit facility		6,882		5,413
2021 Senior Notes		13,836		15,053
2022 Senior Notes		8,222		—
	$	46,198	$	40,193

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Stockholders' Equity and Noncontrolling Interests (Tables)

9 Months Ended

Sep. 30, 2014

Equity [Abstract]

Summary of Changes In Common Shares Issued

The following is a summary of the changes in our common shares issued for the nine months ended September 30, 2014:

Balance January 1, 2014	—
Shares of common stock issued in connection with restructuring transactions      (Note 1)	171,000,000
Shares of common stock issued sold in initial public offering (Note 1)	21,500,000
Restricted common shares issued (Note 11)	1,068,422
Restricted common shares forfeited	(9,211	)
Balance September 30, 2014	193,559,211

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Summary of Significant Accounting Policies

9 Months Ended

Sep. 30, 2014

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

Note 2.  Summary of Significant Accounting Policies

Use of Estimates

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

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

Principles of Consolidation and Combination

Our consolidated financial statements include our accounts and those of our subsidiaries in which we have a controlling interest.  Likewise, the combined financial statements include those of our predecessor and the previous owners.

Cash and Cash Equivalents

Cash and cash equivalents represent unrestricted cash on hand and all highly liquid investments with original contractual maturities of three months or less.

Concentrations of Credit Risk

Cash balances, accounts receivable, restricted investments and derivative financial instruments are financial instruments potentially subject to credit risk. Cash and cash equivalents are maintained in bank deposit accounts which, at times, may exceed the federally insured limits. Management periodically reviews and assesses the financial condition of the banks to mitigate the risk of loss. Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with MEMP’s offshore Southern California oil and gas properties. These restricted investments may consist of money market deposit accounts, money market mutual funds, commercial paper, and U.S. Government securities, all held with credit-worthy financial institutions. Derivative financial instruments are generally executed with major financial institutions that expose us to market and credit risks and which may, at times, be concentrated with certain counterparties. The creditworthiness of the counterparties is subject to continual review. We rely upon netting arrangements with counterparties to reduce credit exposure. We have not experienced any losses from such instruments.

Oil and natural gas are sold to a variety of purchasers, including intrastate and interstate pipelines or their marketing affiliates and independent marketing companies. Accounts receivable from joint operations are from a number of oil and natural gas companies, partnerships, individuals, and others who own interests in the properties operated by us and our predecessor. Generally, operators of crude oil and natural gas properties have the right to offset future revenues against unpaid charges related to operated wells, minimizing the credit risk associated with these receivables. Additionally, management believes that any credit risk imposed by a concentration in the oil and natural gas industry is mitigated by the creditworthiness of its customer base. An allowance for doubtful accounts is recorded after all reasonable efforts have been exhausted to collect or settle the amount owed. Any amounts outstanding longer than the contractual terms are considered past due. Management determined that an allowance for uncollectible accounts was unnecessary at both September 30, 2014 and December 31, 2013, respectively.

If we were to lose any one of our customers, the loss could temporarily delay production and the sale of oil and natural gas in the related producing region. If we were to lose any single customer, we believe that a substitute customer to purchase the impacted production volumes could be identified.

Oil and Natural Gas Properties

Oil and natural gas exploration, development and production activities are accounted for in accordance with the successful efforts method of accounting. Under this method, costs of acquiring properties, costs of drilling successful exploration wells, and development costs are capitalized. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if determination is made that proved reserves have been found. If no proved reserves have been found, the costs of each of the related exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. The costs of such exploratory wells are expensed if a determination of proved reserves has not been made within a twelve-month period after drilling is complete. Exploration costs such as geological, geophysical, and seismic costs are expensed as incurred.

As exploration and development work progresses and the reserves on these properties are proven, capitalized costs attributed to the properties are subject to depreciation and depletion. Depletion of capitalized costs is provided using the units-of-production method based on proved oil and gas reserves related to the associated field. Capitalized drilling and development costs of producing oil and natural gas properties are depleted over proved developed reserves and leasehold costs are depleted over total proved reserves.

On the sale or retirement of a complete or partial unit of a proved property or pipeline and related facilities, the cost and related accumulated depreciation, depletion, and amortization are removed from the property accounts, and any gain or loss is recognized.

Impairments

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, such as a downward revision of the reserve estimates, less than expected production, drilling results, higher operating and development costs, or lower commodity prices. The estimated undiscounted future cash flows expected in connection with the property are compared to the carrying value of the property to determine if the carrying amount is recoverable. If the carrying value of the property exceeds its estimated undiscounted future cash flows, the carrying amount of the property is reduced to its estimated fair value using Level 3 inputs. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties.

Unproved oil and natural gas properties are assessed for impairment on a property-by-property basis. A loss is recognized by providing a valuation allowance if the assessment indicates an impairment. The impairment assessment is affected by economic factors such as the results of exploration activities, commodity price outlooks, remaining lease terms, and potential shifts in business strategy employed by management.

Asset Retirement Obligations

An asset retirement obligation associated with retiring long-lived assets is recognized as a liability on a discounted basis in the period in which the legal obligation is incurred and becomes determinable, with an equal amount capitalized as an addition to oil and natural gas properties, which is allocated to expense over the useful life of the asset. Generally, oil and gas producing companies incur such a liability upon acquiring or drilling a well. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. Upon settlement of the liability, a gain or loss is recognized as a component of exploration costs to the extent the actual costs differ from the recorded liability. See Note 6 for further discussion of asset retirement obligations.

Oil and Gas Reserves

The estimates of proved oil and natural gas reserves utilized in the preparation of the consolidated and combined financial statements are estimated in accordance with the rules established by the SEC and the Financial Accounting Standards Board (“FASB”). These rules require that reserve estimates be prepared under existing economic and operating conditions using a trailing 12-month average price with no provision for price and cost escalations in future years except by contractual arrangements.

Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties, or any combination of the above may be increased or reduced. Increases in recoverable economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates.

Other Property & Equipment

Other property and equipment is stated at historical costs and is comprised primarily of vehicles, furniture, fixtures, and computer hardware and software. Depreciation of other property and equipment is calculated using the straight-line method generally based on estimated useful lives of three to five years.

Restricted Investments

Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with MEMP’s offshore Southern California oil and gas properties. These investments are classified as held-to-maturity, and such investments are stated at amortized cost. Interest earned on these investments is included in interest expense – net in the statement of operations. The amortized cost of such investments is adjusted for amortization of premiums and accretion of discounts to maturity. At September 30, 2014, these restricted investments consisted of money market deposit accounts, money market mutual funds, commercial paper, and U.S. Government securities. See Note 7 for additional information.

Debt Issuance Costs

These costs are recorded on the balance sheet and amortized over the term of the associated debt using the straight-line method which approximates the effective yield method.

Revenue Recognition

Revenue from the sale of oil and natural gas is recognized when title passes, net of royalties due to third parties. Oil and natural gas revenues are recorded using the sales method. Under this method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers, regardless of whether the sales are proportionate to our ownership in the property. An asset or a liability is recognized to the extent that we have an imbalance in excess of our proportionate share of the remaining recoverable reserves on the underlying properties.

Derivative Instruments

Commodity derivative financial instruments (e.g., swaps, collars, and put options) are used to reduce the impact of natural gas and oil price fluctuations. Interest rate swaps are used to manage exposure to interest rate volatility, primarily as a result of variable rate borrowings under the credit facilities. Every derivative instrument is recorded on the balance sheet as either an asset or liability measured at its fair value. Changes in the derivative’s fair value are recognized in earnings as we have not elected hedge accounting for any of our derivative positions.

Income Tax

Prior to our initial public offering, MRD LLC was organized as a pass-through entity for federal income tax purposes and was not subject to federal income taxes; however, certain of its consolidating subsidiaries were taxed as corporations and subject to federal income taxes.  We are organized as a taxable C corporation and subject to federal and certain state income taxes.  We are also subject to the Texas margin tax and certain aspects of the tax make it similar to an income tax as the tax is assessed on 1% of taxable margin apportioned to operations in Texas.

Deferred federal and state income taxes are provided on temporary differences between the financial statement carrying amounts of assets and liabilities and their respective tax basis. If it is more likely than not that some of the deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. A tax benefit from an uncertain tax position is recognized when it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position. The tax benefit recorded is equal to the largest amount that is greater than 50% likely to be realized through final settlement with a taxing authority. There were no uncertain tax positions that required recognition in the financial statements at both September 30, 2014 and December 31, 2013, respectively.

In June 2014, we recorded a deferred tax liability of approximately $43.3 million in stockholders’ equity in connection with our initial public offering and the related restructuring transactions.  The tax bases of our assets and liabilities changed as a result our initial public offering and the related restructuring transactions, which represented a transaction among stockholders.

Earnings Per Share

Basic earnings per share (“EPS”) is computed based on the average number of shares of common stock outstanding for the period. Diluted EPS includes the effect of the Company’s outstanding restricted stock awards if the inclusion of these awards is dilutive.   See Note 10 for additional information.

Incentive-Based Compensation Arrangements

The fair value of equity-classified awards (e.g., restricted stock awards) is amortized to earnings over the requisite service or vesting period.  Compensation expense for liability-classified awards are recognized over the requisite service or vesting period of an award based on the fair value of the award re-measured at each reporting period. Generally, no compensation expense is recognized for equity instruments that do not vest.

Prior to the restructuring transactions, the governing documents of MRD LLC and certain of its subsidiaries, including WildHorse Resources and BlueStone, provided for the issuance of incentive units. The incentive units were subject to performance conditions that affected their vesting. Compensation cost was recognized only if the performance condition was probable of being satisfied at each reporting date.

In connection with the restructuring transactions, the MRD LLC incentive units were exchanged for substantially identical units in MRD Holdco, and such incentive units entitle holders thereof to portions of future distributions by MRD Holdco. While any such distributions made by MRD Holdco will not involve any cash payment by us, we will be required to recognize non-cash compensation expense, which may be material, in future periods. The compensation expense recognized by us related to the incentive units will be offset by a deemed capital contribution from MRD Holdco.

See Notes 11 and 12 for further information.

Current Liabilities – Accrued liabilities

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

	September 30,		December 31,
	2014		2013
Accrued capital expenditures	$	77,716	$	48,579
Accrued lease operating expense		18,142		13,240
Accrued general and administrative expenses		11,986		14,485
Accrued ad valorem and production taxes		26,466		3,541
Accrued interest payable		41,857		11,934
Accrued environmental		571		577
Other miscellaneous, including operator advances		2,643		5,774
	$	179,381	$	98,130

New Accounting Pronouncements

Revenue from Contracts with Customers.  In May 2014, the FASB issued a comprehensive new revenue recognition standard for contracts with customers that will supersede most current revenue recognition guidance, including industry-specific guidance. The core principle of this standard is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, the standard provides a five-step analysis of transactions to determine when and how revenue is recognized. Other major provisions include the capitalization and amortization of certain contract costs, ensuring the time value of money is considered in the transaction price, and allowing estimates of variable consideration to be recognized before contingencies are resolved in certain circumstances. This guidance also requires enhanced disclosures regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from an entity’s contracts with customers. The new standard is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016. Early application is prohibited. The standard permits the use of either the retrospective or cumulative effect transition method. This guidance will be applicable to the Company beginning on January 1, 2017. The Company is currently assessing the impact that adopting this new accounting guidance will have on its financial consolidated financial statements and footnote disclosures.

Reporting Discontinued Operations.  In April 2014, the FASB issued an accounting standards update that changes the criteria for determining when disposals can be presented as discontinued operations and modifies discontinued operations disclosures.  The new guidance now defines a “discontinued operation” as (i) a disposal of a component or group of components that is disposed of or is classified as held for sale and “represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results” or (ii) an acquired business or nonprofit activity that is classified as held for sale on the date of acquisition.  We will adopt this guidance and apply the disclosure requirements prospectively beginning on January 1, 2015.

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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Earnings per Share (Tables)

9 Months Ended

Sep. 30, 2014

Summary of Calculation of Earnings (Loss) Per Share, or EPS

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

	For the Three		For the Nine
	Months Ended		Months Ended
	September 30,		September 30,
	2014		2014
Numerator:
Net income (loss) available to common stockholders	$	9,928	$	(951,801	)
Denominator:
Weighted average common shares outstanding		192,500		192,500
Restricted common shares (1)		216		—
Weighted average common and common equivalent shares    outstanding		192,716		192,500
Basic EPS	$	0.05	$	(4.94	)
Diluted EPS	$	0.05	$	(4.94	)

(1)The treasury stock method is applied to determine the dilutive effect of the unvested restricted common shares. The restricted common shares were antidilutive due to net losses and excluded from the diluted EPS calculation for the nine months ending September 30, 2014. There were 206,956 incremental shares excluded from the computation of diluted EPS for the nine months ending September 30, 2014.

Supplemental EPS [Member]

Summary of Calculation of Earnings (Loss) Per Share, or EPS

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

	For the Three		For the Nine
	Months Ended		Months Ended
	September 30,		September 30,
	2014		2014
Numerator:
Net income (loss) attributable to Memorial Resource Development Corp.	$	9,928	$	(930,071	)
Denominator:
Weighted average common shares outstanding		192,500		192,500
Restricted common shares (1)		216		—
Weighted average common and common equivalent shares outstanding		192,716		192,500
Basic EPS	$	0.05	$	(4.83	)
Diluted EPS	$	0.05	$	(4.83	)

(1)The treasury stock method is applied to determine the dilutive effect of the unvested restricted common shares. The restricted common shares were antidilutive due to net losses and excluded from the diluted EPS calculation for the nine months ending September 30, 2014. There were 206,956 incremental shares excluded from the computation of diluted EPS for the nine months ending September 30, 2014.

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Business Segment Data - Summary of Selected Business Segment Information (Parenthetical) (Detail) (USD $)	3 Months Ended	9 Months Ended	3 Months Ended	9 Months Ended		12 Months Ended	3 Months Ended	9 Months Ended		3 Months Ended
	Sep. 30, 2014 MEMP [Member]	Sep. 30, 2014 MEMP [Member]	Sep. 30, 2013 MEMP [Member] Maximum [Member]	Sep. 30, 2013 MEMP [Member] Maximum [Member]	Sep. 30, 2014 Other, Adjustments & Eliminations [Member]	Dec. 31, 2013 Other, Adjustments & Eliminations [Member]	Sep. 30, 2013 Other, Adjustments & Eliminations [Member] MEMP [Member]	Sep. 30, 2014 Other, Adjustments & Eliminations [Member] MEMP [Member]	Sep. 30, 2013 Other, Adjustments & Eliminations [Member] MEMP [Member]	Sep. 30, 2014 Other, Adjustments & Eliminations [Member] MEMP [Member] Maximum [Member]
Segment Reporting Information [Line Items]
Cash distributions paid							$ 6,400,000	$ 6,100,000	$ 19,100,000	$ 100,000
Impairment charges	$ (67,200,000)	$ (67,200,000)	$ (100,000)	$ (100,000)	$ 47,300,000	$ 49,900,000

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Summary of Significant Accounting Policies - Schedule of Current Accrued Liabilities (Detail) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Accounting Policies [Abstract]
Accrued capital expenditures	$ 77,716	$ 48,579
Accrued lease operating expense	18,142	13,240
Accrued general and administrative expenses	11,986	14,485
Accrued ad valorem and production taxes	26,466	3,541
Accrued interest payable	41,857	11,934
Accrued environmental	571	577
Other miscellaneous, including operator advances	2,643	5,774
Accrued liabilities	$ 179,381	$ 98,130

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Restricted Investments - Restricted Investment Balance (Detail) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Schedule Of Investments [Line Items]
Restricted investments	$ 76,268	$ 73,385
BOEM platform abandonment [Member]
Schedule Of Investments [Line Items]
Restricted investments	68,970	66,373
BOEM lease bonds [Member]
Schedule Of Investments [Line Items]
Restricted investments	794	794
SPBPC Collateral Contractual pipeline and surface facilities abandonment [Member]
Schedule Of Investments [Line Items]
Restricted investments	2,592	2,306
SPBPC Collateral California State Lands Commission pipeline right-of-way bond [Member]
Schedule Of Investments [Line Items]
Restricted investments	3,005	3,005
SPBPC Collateral City of Long Beach pipeline facility permit [Member]
Schedule Of Investments [Line Items]
Restricted investments	500	500
SPBPC Collateral Federal pipeline right-of-way bond [Member]
Schedule Of Investments [Line Items]
Restricted investments	307	307
SPBPC Collateral Port of Long Beach pipeline license [Member]
Schedule Of Investments [Line Items]
Restricted investments	$ 100	$ 100

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Long-Term Incentive Plans - Additional Information (Detail) (USD $) In Millions, except Share data, unless otherwise specified			9 Months Ended
	Sep. 30, 2014	Dec. 31, 2011 MEMP [Member]	Sep. 30, 2014 Restricted Stock [Member]	Sep. 30, 2014 Restricted Stock [Member] MEMP [Member]	Sep. 30, 2014 Restricted Stock [Member] Director [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of common shares that may be delivered	19,250,000
Aggregate award of restricted stock issued to employees and each independent director			1,052,633		5,263
Vesting period of award			4 years		1 year
Unrecognized compensation cost			$ 18.6	$ 19.1
Unrecognized compensation cost weighted-average period			3 years 8 months 5 days	2 years 3 months 18 days
Number of common units that may be delivered		2,142,221

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UNAUDITED CONDENSED CONSOLIDATED AND COMBINED BALANCE SHEETS (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Current assets:
Cash and cash equivalents	$ 10,316	$ 77,721
Restricted cash		35,000
Accounts receivable:
Oil and natural gas sales	102,578	68,764
Joint interest owners and other	19,116	19,958
Affiliates		4,652
Short-term derivative instruments	37,421	9,289
Prepaid expenses and other current assets	20,696	19,513
Total current assets	190,127	234,897
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method	4,544,176	3,037,298
Other	15,477	10,331
Accumulated depreciation, depletion and impairment	(877,843)	(627,925)
Oil and natural gas properties, net	3,681,810	2,419,704
Long-term derivative instruments	34,515	48,616
Restricted investments	76,268	73,385
Restricted cash	260	15,506
Other long-term assets	38,687	37,053
Total assets	4,021,667	2,829,161
Current liabilities:
Accounts payable	16,846	20,734
Accounts payable - affiliates	810	1,975
Revenues payable	59,512	56,091
Accrued liabilities	179,381	98,130
Short-term derivative instruments	5,109	9,711
Total current liabilities	261,658	186,641
Noncurrent liabilities:
Asset retirement obligations	119,510	111,679
Long-term derivative instruments	15,275	6,080
Deferred tax liabilities	50,643	3,106
Other long-term liabilities	3,782	306
Total liabilities	2,562,668	1,971,029
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; 193,559,211 shares issued and outstanding at September 30, 2014; no shares authorized, issued or outstanding at December 31, 2013	1,936
Additional paid-in capital	1,386,143
Accumulated earnings (deficit)	(951,801)
Total stockholders' equity	436,278
Members' equity:
Members		237,186
Previous owners (Note 1)		40,331
Total members' equity		277,517
Noncontrolling interests	1,022,721	580,615
Total equity	1,458,999	858,132
Total liabilities and equity	4,021,667	2,829,161
MRD [Member]
Noncurrent liabilities:
Long-term debt	628,000	871,150
MEMP [Member]
Noncurrent liabilities:
Long-term debt	$ 1,483,800	$ 792,067

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Fair Value Measurements of Financial Instruments - Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) (Fair Value, Measurements [Member], USD $) In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Assets:
Commodity derivatives	$ 129,806	$ 105,938
Liabilities:
Commodity derivatives	78,254	63,824
Interest rate derivatives [Member]
Assets:
Commodity derivatives	95	884
Liabilities:
Commodity derivatives	3,712	5,590
Significant Observable Inputs (Level 2) [Member]
Assets:
Commodity derivatives	129,806	105,938
Liabilities:
Commodity derivatives	78,254	63,824
Significant Observable Inputs (Level 2) [Member] | Interest rate derivatives [Member]
Assets:
Commodity derivatives	95	884
Liabilities:
Commodity derivatives	3,712	5,590
Commodity derivatives [Member]
Assets:
Commodity derivatives	129,711	105,054
Liabilities:
Commodity derivatives	74,542	58,234
Commodity derivatives [Member] | Significant Observable Inputs (Level 2) [Member]
Assets:
Commodity derivatives	129,711	105,054
Liabilities:
Commodity derivatives	$ 74,542	$ 58,234

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UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED AND COMBINED EQUITY (USD $) In Thousands	Total	Preferred Stock [Member]	Common Stock [Member]	Additional Paid-in Capital [Member]	Accumulated earnings (deficit) [Member]	Noncontrolling Interest [Member]	Members Equity [Member]	Members Equity [Member] Previous Owners [Member]
Noncontrolling interests, beginning balance at Dec. 31, 2012						$ 231,662
Members' equity, beginning balance at Dec. 31, 2012							811,614	233,433
Stockholders' equity, beginning balance at Dec. 31, 2012		0	0	0	0
Purchase of noncontrolling interests						(1,270)
Other							(47)	(2,299)
Net income (loss) allocation	174,300					42,134	122,639	9,527
Distributions						(51,319)	(363,437)	(3,130)
Net equity deemed contribution (distribution) related to net assets transferred to MEMP						(2,560)	2,560
Impact of equity transactions of MEMP						(24,024)	24,024
Contributions								1,214
Net proceeds from MEMP public equity offering						171,779
Amortization of MEMP equity awards						2,321
Total equity	1,204,821
Noncontrolling interests, ending balance at Sep. 30, 2013						368,723
Members' equity, ending balance at Sep. 30, 2013	836,098						597,353	238,745
Stockholders' equity, ending balance at Sep. 30, 2013	0	0	0	0
Noncontrolling interests, beginning balance at Dec. 31, 2013	580,615					580,615
Members' equity, beginning balance at Dec. 31, 2013	277,517						237,186	40,331
Stockholders' equity, beginning balance at Dec. 31, 2013		0	0	0	0
Issuance of shares in connection with restructuring transactions (see Note 1)			1,710	913,152
Issuance of shares in connection with initial public offering (see Note 1)			215	379,962
Restricted stock awards			11	(11)
Tax related effects in connection with restructuring transactions and initial public offering				(43,251)
Amortization of restricted stock awards				1,487
Contribution related to MRD Holdco incentive unit compensation expense (see Note 12)				137,307
Purchase of noncontrolling interests				(2,881)		(411)
Other				378		(332)	(154)
Net income (loss) allocation	(964,922)				(951,801)	(34,851)	20,305	1,425
Contribution related to sale of assets to NGP affiliate							1,165
Net book value of assets sold to NGP affiliate							(621)
Net book value of assets acquired from NGP affiliates							45,059	(41,756)
Distribution to NGP affiliates in connection with acquisition of assets							(66,693)
Distribution of net assets to MRD Holdco						29,994	(123,078)
Distribution of shares received in connection with restructuring transactions to MRD Holdco							(110,510)
Distributions						(101,327)
Net equity deemed contribution (distribution) related to net assets transferred to MEMP						2,659	(2,659)
Net proceeds from MEMP public equity offering						540,987
Amortization of MEMP equity awards						5,387
Total equity	1,458,999
Noncontrolling interests, ending balance at Sep. 30, 2014	1,022,721					1,022,721
Stockholders' equity, ending balance at Sep. 30, 2014	$ 436,278	$ 0	$ 1,936	$ 1,386,143	$ (951,801)

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Long Term Debt - MRD Revolving Credit Facility - Additional Information (Detail) (Revolving Credit Facility [Member], USD $)		9 Months Ended						0 Months Ended	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2014 Minimum [Member]	Sep. 30, 2014 Minimum [Member] Range 1 [Member] Alternative Base Rate	Sep. 30, 2014 Minimum [Member] Range 2 [Member] London Interbank Offered Rate (LIBOR)	Sep. 30, 2014 Maximum [Member]	Sep. 30, 2014 Maximum [Member] Range 1 [Member] Alternative Base Rate	Sep. 30, 2014 Maximum [Member] Range 2 [Member] London Interbank Offered Rate (LIBOR)	Jun. 18, 2014 MRD [Member]	Sep. 30, 2014 MRD [Member] Optional Base Rate Federal Funds Effective Rate	Sep. 30, 2014 MRD [Member] Optional Base Rate Adjusted London Interbank Offered Rate	Sep. 30, 2014 MRD [Member] Minimum [Member]	Sep. 30, 2014 MRD [Member] Minimum [Member] Range 1 [Member] Alternative Base Rate	Sep. 30, 2014 MRD [Member] Minimum [Member] Range 2 [Member] Alternative Base Rate	Sep. 30, 2014 MRD [Member] Maximum [Member]	Sep. 30, 2014 MRD [Member] Maximum [Member] Range 1 [Member] London Interbank Offered Rate (LIBOR)	Sep. 30, 2014 MRD [Member] Maximum [Member] Range 2 [Member] London Interbank Offered Rate (LIBOR)
Debt Obligations [Line Items]
Revolving credit facility expiration term								5 years
Initial borrowing base of second lien term facility	$ 2,000,000,000							$ 2,000,000,000
Line of credit facility, initial borrowing base								725,000,000
Aggregate elected capacity of revolving credit								$ 725,000,000
Lien percentage of assets for credit facility									80.00%
Line of credit, additional margin rate			0.50%	1.50%		1.50%	2.50%		0.50%	1.00%		0.50%	1.50%		1.50%	2.50%
Line of credit, adjusted description									the one-month adjusted LIBOR plus 1.0% (adjusted upwards, if necessary, to the next 1/100th of 1%)
Percentage of revolving unused commitment fee		0.375%			0.50%				0.375%		0.375%			0.50%
Debt instrument interest coverage ratio											2.5
Debt instrument, current asset to current liabilities ratio											1.0

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Related Party Transactions (Tables)

9 Months Ended

Sep. 30, 2014

Related Party Transactions [Abstract]

Schedule of Net Assets Recorded

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

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

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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Long Term Debt - Summary of Unamortized Deferred Financing Costs Associated with Consolidated Debt Obligations (Detail) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Debt Obligations [Line Items]
Unamortized deferred financing costs	$ 46,198	$ 40,193
Revolving Credit Facility [Member]
Debt Obligations [Line Items]
Unamortized deferred financing costs	4,433
Senior Notes
Debt Obligations [Line Items]
Unamortized deferred financing costs	12,825
PIK notes [Member]
Debt Obligations [Line Items]
Unamortized deferred financing costs		8,261
WildHorse Resources, LLC [Member] | Revolving Credit Facility [Member]
Debt Obligations [Line Items]
Unamortized deferred financing costs		2,436
WildHorse Resources, LLC [Member] | Second Lien Credit Facility [Member]
Debt Obligations [Line Items]
Unamortized deferred financing costs		9,030
MEMP [Member] | 2.0 billion revolving credit facility [Member]
Debt Obligations [Line Items]
Unamortized deferred financing costs	6,882	5,413
MEMP [Member] | 2021 Senior Notes [Member]
Debt Obligations [Line Items]
Unamortized deferred financing costs	13,836	15,053
MEMP [Member] | 2022 Senior Notes [Member]
Debt Obligations [Line Items]
Unamortized deferred financing costs	$ 8,222

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Subsequent Events

9 Months Ended

Sep. 30, 2014

Subsequent Events [Abstract]

Subsequent Events

Note 16.  Subsequent Events

Common Control Transaction

On October 1, 2014, MRD sold certain oil and natural gas properties in Colorado to MEMP for a purchase price of $15 million, subject to customary post-closing adjustments.  The properties are located in Weld County, Colorado in the Wattenberg Field. The properties are 100% non-operated and included interests in 74 gross wells. The transaction had an effective date of October 1, 2014 and was funded with borrowings under MEMP’s revolving credit facility. The transaction was approved by our Board and its audit committee, which is comprised entirely of independent directors.

MRD Revolving Credit Facility

On October 3, 2014, the borrowing base under our credit facility was increased. For additional information regarding MRD’s revolving credit facility, see Note 8.

MEMP Revolving Credit Facility

On October 10, 2014, the borrowing base under the MEMP credit facility was redetermined and increased. For additional information regarding MEMP’s revolving credit facility, see Note 8.

Terryville Mineral & Royalty Partners LP

On November 4, 2014, the Company’s wholly-owned subsidiary, Terryville Mineral & Royalty Partners LP (“TRVL”), filed a registration statement on Form S-1 with the SEC in connection with its proposed initial public offering of common units representing limited partner interests. In connection with the closing of the proposed offering, the Company will contribute to TRVL certain overriding royalty interests in approximately 27,000 gross acres in the Terryville Complex in exchange for limited partner interests in TRVL.  The royalty interests will entitle TRVL to receive 7% of gross revenues from production within such acreage on all of the Company’s existing horizontal producing wells and future wells completed by the Company. TRVL intends to distribute the net proceeds from the proposed offering to the Company.  A registration statement relating to these securities has been filed with the SEC but has not yet become effective. These securities may not be sold nor may any offers to buy be accepted prior to the time the registration statement becomes effective, and this report does not constitute an offer to sell or a solicitation of any offers to buy these securities.

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Business Segment Data (Tables)

9 Months Ended

Sep. 30, 2014

Segment Reporting [Abstract]

Summary of Selected Business Segment Information

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

							Other,			Consolidated
							Adjustments &			& Combined
	MRD			MEMP			Eliminations			Totals
Total revenues:
Three months ended September 30, 2014	$	98,342		$	147,243		$	(92	)	$	245,493
Three months ended September 30, 2013		60,294			93,240			(19	)		153,515
Nine months ended September 30, 2014		301,492			371,530			(137	)		672,885
Nine months ended September 30, 2013		171,361			251,516			(136	)		422,741
Adjusted EBITDA: (1)
Three months ended September 30, 2014		83,388			90,045			22			173,455
Three months ended September 30, 2013		56,836			58,623			(18,447	)		97,012
Nine months ended September 30, 2014		247,335			218,842			(18,912	)		447,265
Nine months ended September 30, 2013		153,679			157,160			(19,554	)		291,285
Segment assets: (2)
As of September 30, 2014		1,232,146			2,749,452			40,069			4,021,667
As of December 31, 2013		1,281,134			1,552,307			(4,280	)		2,829,161
Total cash expenditures for additions to long-lived assets:
Nine months ended September 30, 2014		(276,982	)		(1,273,157	)		—			(1,550,139	)
Nine months ended September 30, 2013		(198,220	)		(165,403	)		—			(363,623	)

(1)Adjustments and eliminations for the three and nine months ended September 30, 2014 and 2013 include amounts related to the MRD's Segment equity investments in the MEMP Segment as well as the elimination of less than $0.1 million and $6.1 million of cash distributions that MEMP paid MRD for the three and nine months ended September 30, 2014, respectively, and $6.4 million and $19.1 million of cash distributions that MEMP paid MRD LLC for the three and nine months ended September 30, 2013, respectively, related to MRD LLC's partnership interests in MEMP.

(2)Adjustments and eliminations primarily represent the elimination of the MRD's Segment equity investments in the MEMP Segment.  The adjustment at September 30, 2014 and December 31, 2013 also includes $47.3 million and $49.9 million, respectively related to an impairment recognized by the MEMP Segment during 2013.  This impairment did not exist on a consolidated basis.

Schedule of Calculation of Reportable Segment's Adjusted EBITDA

Calculation of Reportable Segments’ Adjusted EBITDA

	For the Three Months
	Ended September 30, 2014
							Combined
	MRD			MEMP			Totals
	(In thousands)
Net income (loss)	$	9,866		$	103,226		$	113,092
Interest expense, net		9,886			26,459			36,345
Income tax expense (benefit)		25,834			—			25,834
DD&A		39,550			43,928			83,478
Impairment of proved oil and natural gas properties		—			67,181			67,181
Accretion of AROs		170			1,383			1,553
(Gain) loss on commodity derivative instruments		(33,090	)		(156,402	)		(189,492	)
Cash settlements received (paid) on commodity derivative instruments		3,699			876			4,575
Acquisition 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	$	83,388		$	90,045		$	173,433

	For the Three Months
	Ended September 30, 2013
							Combined
	MRD			MEMP			Totals
				(In thousands)
Net income (loss)	$	73,874		$	(39,039	)	$	34,835
Interest expense, net		9,041			11,574			20,615
Income tax expense (benefit)		1,147			97			1,244
DD&A		20,476			24,660			45,136
Impairment of proved oil and natural gas properties		—			50,310			50,310
Accretion of AROs		178			1,176			1,354
(Gain) loss on commodity derivative instruments		213			1,815			2,028
Cash settlements received (paid) on commodity derivative instruments		3,368			3,678			7,046
(Gain) loss on sale of properties		(90,083	)		20			(90,063	)
Acquisition related costs		667			2,310			2,977
Incentive-based compensation expense		19,069			1,237			20,306
Non-cash compensation expense		—			(68	)		(68	)
Exploration costs		439			853			1,292
Non-cash equity (income) loss from MEMP		12,058			—			12,058
Cash distributions from MEMP		6,389			—			6,389
Adjusted EBITDA	$	56,836		$	58,623		$	115,459

	For the Nine Months
	Ended September 30, 2014
							Combined
	MRD			MEMP			Totals
				(In thousands)
Net income (loss)	$	(930,149	)	$	(45,037	)	$	(975,186	)
Interest expense, net		44,355			60,573			104,928
Loss on extinguishment of debt		37,248			—			37,248
Income tax expense (benefit)		14,323			75			14,398
DD&A		107,496			105,830			213,326
Impairment of proved oil and natural gas properties		—			67,181			67,181
Accretion of AROs		495			4,106			4,601
(Gain) loss on commodity derivative instruments		(17,130	)		28,710			11,580
Cash settlements received (paid) on commodity derivative instruments		(4,930	)		(14,999	)		(19,929	)
(Gain) loss on sale of properties		3,057			—			3,057
Acquisition 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
Provision for environmental remediation		—			2,852			2,852
Non-cash equity (income) loss from MEMP		12,844			—			12,844
Cash distributions from MEMP		6,068			—			6,068
Adjusted EBITDA	$	247,335		$	218,842		$	466,177

	For the Nine Months
	Ended September 30, 2013
							Combined
	MRD			MEMP			Totals
				(In thousands)
Net income (loss)	$	114,628		$	9,359		$	123,987
Interest expense, net		15,947			26,047			41,994
Income tax expense (benefit)		1,147			285			1,432
DD&A		62,605			69,723			132,328
Impairment of proved oil and natural gas properties		—			50,310			50,310
Accretion of AROs		547			3,469			4,016
(Gain) loss on commodity derivative instruments		(8,361	)		(21,195	)		(29,556	)
Cash settlements received (paid) on commodity derivative instruments		9,125			14,081			23,206
(Gain) loss on sale of properties		(83,370	)		(2,848	)		(86,218	)
Acquisition related costs		1,651			3,422			5,073
Incentive-based compensation expense		19,069			2,322			21,391
Non-cash compensation expense		—			1,057			1,057
Exploration costs		1,137			1,128			2,265
Non-cash equity (income) loss from MEMP		454			—			454
Cash distributions from MEMP		19,100			—			19,100
Adjusted EBITDA	$	153,679		$	157,160		$	310,839

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						For the Nine Months
	Ended September 30,						Ended September 30,
	2014			2013			2014			2013
Total Reportable Segments' Adjusted EBITDA	$	173,433		$	115,459		$	466,177		$	310,839
Adjustments to reconcile Adjusted EBITDA to net income (loss):
Interest expense, net		(36,345	)		(20,615	)		(104,928	)		(41,994	)
Loss on extinguishment of debt		—			—			(37,248	)		—
Income tax benefit (expense)		(25,834	)		(1,244	)		(14,398	)		(1,432	)
DD&A		(84,447	)		(45,136	)		(215,906	)		(132,328	)
Impairment of proved oil and natural gas properties		(67,181	)		(21	)		(67,181	)		(21	)
Accretion of AROs		(1,553	)		(1,354	)		(4,601	)		(4,016	)
Gains (losses) on commodity derivative instruments		189,492			(2,028	)		(11,580	)		29,556
Cash settlements paid (received) on commodity derivative instruments		(4,575	)		(7,046	)		19,929			(23,206	)
Gain (loss) on sale of properties		—			90,063			(3,057	)		86,218
Acquisition related costs		(1,425	)		(2,977	)		(5,480	)		(5,073	)
Incentive-based compensation expense		(29,289	)		(20,306	)		(976,264	)		(21,391	)
Non-cash compensation expense		—			68			—			(1,057	)
Exploration costs		(175	)		(1,292	)		(1,465	)		(2,265	)
Provision for environmental remediation		—			—			(2,852	)		—
Cash distributions from MEMP		(64	)		(6,389	)		(6,068	)		(19,100	)
Other non-cash equity (income) loss		—			(1,220	)		—			(430	)
Net income (loss)	$	112,037		$	95,962		$	(964,922	)	$	174,300

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

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

	For the Three Months
	Ended September 30, 2014
	MRD			MEMP			Other, Adjustments & Eliminations			Consolidated & Combined Totals
Revenues:
Oil & natural gas sales	$	98,337		$	145,824		$	—		$	244,161
Other revenues		5			1,419			(92	)		1,332
Total revenues		98,342			147,243			(92	)		245,493
Costs and expenses:
Lease operating		6,991			39,312			(92	)		46,211
Pipeline operating		—			431			—			431
Exploration		133			42			—			175
Production and ad valorem taxes		3,571			10,469			—			14,040
Depreciation, depletion, and amortization		39,550			43,928			969			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		9,982			11,214			—			21,196
Accretion of asset retirement obligations		170			1,383			—			1,553
(Gain) loss on commodity derivative instruments		(33,090	)		(156,402	)		—			(189,492	)
(Gain) loss on sale of properties		—			—			—			—
Total costs and expenses		52,857			17,558			877			71,292
Operating income (loss)		45,485			129,685			(969	)		174,201
Other income (expense):
Interest expense, net		(9,886	)		(26,459	)		—			(36,345	)
Loss on extinguishment of debt		—			—			—			—
Earnings from equity investments		86			—			(86	)		—
Other, net		15			—			—			15
Total other income (expense)		(9,785	)		(26,459	)		(86	)		(36,330	)
Income (loss) before income taxes		35,700			103,226			(1,055	)		137,871
Income tax benefit (expense)		(25,834	)		—			—			(25,834	)
Net income (loss)	$	9,866		$	103,226		$	(1,055	)	$	112,037

	For the Three Months
	Ended September 30, 2013
	MRD			MEMP			Other, Adjustments & Eliminations			Consolidated & Combined Totals
Revenues:
Oil & natural gas sales	$	60,179		$	92,583		$	—		$	152,762
Other revenues		115			657			(19	)		753
Total revenues		60,294			93,240			(19	)		153,515
Costs and expenses:
Lease operating		6,144			23,334			(83	)		29,395
Pipeline operating		—			394			—			394
Exploration		439			853			—			1,292
Production and ad valorem taxes		1,354			6,068			—			7,422
Depreciation, depletion, and amortization		20,476			24,660			—			45,136
Impairment of proved oil and natural gas properties		—			50,310			(50,289	)		21
Incentive unit compensation expense		19,069			—			—			19,069
General and administrative		7,653			11,928			65			19,646
Accretion of asset retirement obligations		178			1,176			—			1,354
(Gain) loss on commodity derivative instruments		213			1,815			—			2,028
(Gain) loss on sale of properties		(90,083	)		20			—			(90,063	)
Other, net		—			50			(26	)		24
Total costs and expenses		(34,557	)		120,608			(50,333	)		35,718
Operating income (loss)		94,851			(27,368	)		50,314			117,797
Other income (expense):
Interest expense, net		(9,041	)		(11,574	)		—			(20,615	)
Earnings from equity investments		(10,838	)		—			10,838			—
Other, net		49			—			(25	)		24
Total other income (expense)		(19,830	)		(11,574	)		10,813			(20,591	)
Income (loss) before income taxes		75,021			(38,942	)		61,127			97,206
Income tax benefit (expense)		(1,147	)		(97	)		—			(1,244	)
Net income (loss)	$	73,874		$	(39,039	)	$	61,127		$	95,962

	For the Nine Months
	Ended September 30, 2014
	MRD			MEMP			Other, Adjustments & Eliminations			Consolidated & Combined Totals
Revenues:
Oil & natural gas sales	$	300,931		$	368,370		$	—		$	669,301
Other revenues		561			3,160			(137	)		3,584
Total revenues		301,492			371,530			(137	)		672,885
Costs and expenses:
Lease operating		18,657			93,367			(137	)		111,887
Pipeline operating		—			1,596			—			1,596
Exploration		1,213			252			—			1,465
Production and ad valorem taxes		10,494			23,129			—			33,623
Depreciation, depletion, and amortization		107,496			105,830			2,580			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		29,301			31,760			—			61,061
Accretion of asset retirement obligations		495			4,106			—			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		1,122,973			355,919			2,443			1,481,335
Operating income (loss)		(821,481	)		15,611			(2,580	)		(808,450	)
Other income (expense):
Interest expense, net		(44,355	)		(60,573	)		—			(104,928	)
Loss on extinguishment of 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 (loss) before income taxes		(915,826	)		(44,962	)		10,264			(950,524	)
Income tax benefit (expense)		(14,323	)		(75	)		—			(14,398	)
Net income (loss)	$	(930,149	)	$	(45,037	)	$	10,264		$	(964,922	)

	For the Nine Months
	Ended September 30, 2013
	MRD			MEMP			Other, Adjustments & Eliminations			Consolidated & Combined Totals
Revenues:
Oil & natural gas sales	$	171,013		$	249,844		$	—		$	420,857
Other revenues		348			1,672			(136	)		1,884
Total revenues		171,361			251,516			(136	)		422,741
Costs and expenses:
Lease operating		17,065			64,922			(241	)		81,746
Pipeline operating		—			1,343			—			1,343
Exploration		1,137			1,128			—			2,265
Production and ad valorem taxes		8,563			14,915			—			23,478
Depreciation, depletion, and amortization		62,605			69,723			—			132,328
Impairment of proved oil and natural gas properties		—			50,310			(50,289	)		21
Incentive unit compensation expense		19,069			—			—			19,069
General and administrative		22,466			33,411			105			55,982
Accretion of asset retirement obligations		547			3,469			—			4,016
(Gain) loss on commodity derivative instruments		(8,361	)		(21,195	)		—			(29,556	)
(Gain) loss on sale of properties		(83,370	)		(2,848	)		—			(86,218	)
Other, net		(25	)		647			—			622
Total costs and expenses		39,696			215,825			(50,425	)		205,096
Operating income (loss)		131,665			35,691			50,289			217,645
Other income (expense):
Interest expense, net		(15,947	)		(26,047	)		—			(41,994	)
Earnings from equity investments		(24	)		—			24			—
Other, net		81			—			—			81
Total other income (expense)		(15,890	)		(26,047	)		24			(41,913	)
Income before income taxes		115,775			9,644			50,313			175,732
Income tax benefit (expense)		(1,147	)		(285	)		—			(1,432	)
Net income (loss)	$	114,628		$	9,359		$	50,313		$	174,300

XML

Summary of Significant Accounting Policies (Tables)

9 Months Ended

Sep. 30, 2014

Accounting Policies [Abstract]

Schedule of Current Accrued Liabilities

ERROR: Could not retrieve Word content for note block

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Earnings per Share - Summary of Calculation of Earnings (Loss) Per Share (Detail) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2014
Numerator:
Net income (loss) available to common stockholders	$ 9,928	$ (951,801)
Denominator:
Weighted average common shares outstanding	192,500	192,500
Restricted common shares	216
Weighted average common and common equivalent shares outstanding	192,716	192,500
Basic EPS	$ 0.05	$ (4.94)
Diluted EPS	$ 0.05	$ (4.94)

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Background, Organization and Basis of Presentation

9 Months Ended

Sep. 30, 2014

Accounting Policies [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.

The Company was formed by Memorial Resource Development LLC (“MRD LLC”) in January 2014 to exploit, develop and acquire natural gas, NGL and oil properties in North America. MRD LLC was a Delaware limited liability company formed on April 27, 2011 by Natural Gas Partners VIII, L.P. (“NGP VIII”), Natural Gas Partners IX, L.P. (“NGP IX”) and NGP IX Offshore Holdings, L.P. (“NGP IX Offshore”) (collectively, the “Funds”) to exploit, develop and acquire natural gas, NGL and oil properties. The Funds are private equity funds managed by Natural Gas Partners (“NGP”).  MRD LLC’s consolidated and combined financial statements represent our predecessor for accounting and financial reporting purposes prior to our initial public offering.

Initial Public Offering and Restructuring Transactions

On June 18, 2014, the Company completed its initial public offering of 21,500,000 common units at a price of $19.00 per share, which generated net proceeds to the Company of approximately $380.2 million after deducting underwriting discounts and commissions and other offering related fees and expenses. The following restructuring events and transactions occurred in connection with our initial public offering:

· The Funds contributed all of their interests in MRD LLC to MRD Holdco LLC (“MRD Holdco”) and the members of our management who owned incentive units in MRD LLC exchanged those incentive units for substantially identical incentive units in MRD Holdco, after which MRD Holdco owned 100% of MRD LLC;

· WildHorse Resources, LLC  (“WildHorse Resources”) sold its subsidiary, WildHorse Resources Management Company, LLC (“WHR Management Company”), to an affiliate of the Funds for approximately $0.2 million in cash, and WHR Management Company entered into a services agreement with the Company and WildHorse Resources pursuant to which WHR Management Company will provide transition services to WildHorse Resources;

· Classic Hydrocarbons Holdings, L.P. (“Classic”) and Classic Hydrocarbons GP Co., L.L.C. (“Classic GP”) distributed to MRD LLC the ownership interests in Classic Pipeline & Gathering, LLC (“Classic Pipeline”), which owns certain midstream assets in Texas, and Black Diamond Minerals, LLC (“Black Diamond”) distributed to MRD LLC its ownership interests in Golden Energy Partners LLC (“Golden Energy”), which sold all of its assets in May 2014;

· MRD LLC contributed to us substantially all of its assets, comprised of: (i) 100% of the ownership interests in Classic, Classic GP, Black Diamond, Beta Operating Company, LLC (“Beta Operating”), Memorial Resource Finance Corp., MRD Operating LLC (“MRD Operating”), Memorial Production Partners GP LLC (“MEMP GP”) (including MEMP GP’s ownership of 50% of Memorial Production Partners LP’s (“MEMP”) incentive distribution rights) and (ii) 99.9% of the membership interests in WildHorse Resources;

· We issued 128,665,677 shares of our common stock to MRD LLC, which MRD LLC immediately distributed to MRD Holdco;

· We assumed the obligations of MRD LLC under the indenture governing the $350 million in aggregate principal amount of 10.00% / 10.75% Senior PIK Toggle Notes due 2018 (the “PIK notes”) and reimbursed MRD LLC for the June 15, 2014 interest payment made on the PIK notes;

· Certain former management members of WildHorse Resources contributed to us their outstanding incentive units in WildHorse Resources, as well as the remaining 0.1% of the membership interests in WildHorse Resources, and we issued 42,334,323 shares of our common stock and paid cash consideration of $30.0 million to such former management members of WildHorse Resources;

· We entered into a registration rights agreement and a voting agreement with MRD Holdco and certain former management members of WildHorse Resources;

· We entered into a new $2.0 billion revolving credit facility (see Note 8) and used approximately $614.5 million in borrowings under that facility to repay all amounts outstanding under WildHorse Resources’ credit agreements, to partially fund the cash consideration payable to the former management members of WildHorse Resources and to reimburse MRD LLC for the June 15, 2014 interest payment made on the PIK notes;

· Notice of redemption was given to the PIK notes trustee (see Note 8) specifying a redemption date of July 16, 2014 and indicating that a portion of the net proceeds from our initial public offering, which temporarily reduced amounts outstanding under our new revolving credit facility, would be used to redeem the PIK notes at a redemption price of 102% of the principal amount of the PIK notes plus accrued and unpaid interest thereon to the date of redemption;

· MRD Operating entered into a merger agreement with MRD LLC pursuant to which after the termination or earlier discharge of the PIK notes MRD LLC would merge into MRD Operating;

· MRD LLC distributed to MRD Holdco the following: (i) BlueStone Natural Resources Holdings, LLC (“BlueStone”), which sold substantially all of its assets in July 2013 for $117.9 million, MRD Royalty LLC, which owns certain leasehold interests and overriding royalty interests in Texas and Montana, MRD Midstream LLC, which owns an indirect interest in certain midstream assets in North Louisiana, Golden Energy and Classic Pipeline; (ii) 5,360,912 subordinated units of MEMP; (iii) the right to the remaining cash to be released from the debt service reserve account in connection with the redemption or earlier discharge of the PIK notes plus the cash received from us in reimbursement of the interest paid on June 15, 2014 in respect of the PIK notes; and (iv) approximately $6.7 million of cash received by MRD LLC in connection with the sale of Golden Energy’s assets in May 2014;

· We irrevocably deposited with the PIK notes trustee approximately $360.0 million on June 27, 2014, which was an amount sufficient to fund the redemption of the PIK notes on the redemption date and to satisfy and discharge our obligations under the PIK notes and the related indenture.  The discharge became effective upon the irrevocable deposit of the funds with the PIK notes trustee; and

· MRD LLC merged into MRD Operating.

Previous Owners

References to “the previous owners” for accounting and financial reporting purposes refer collectively to:

· Certain oil and natural gas properties and related assets primarily in the Permian Basin, East Texas and the Rockies that MEMP acquired through equity transactions on October 1, 2013 from certain affiliates of NGP. On October 1, 2013, MEMP acquired Boaz Energy, LLC (“Boaz”), Crown Energy Partners, LLC (“Crown”), the Crown net profits interest and overriding royalty interest (“Crown NPI/ORRI”), Propel Energy SPV LLC (“Propel SPV”), together with its wholly-owned subsidiary Propel Energy Services, LLC (“Propel Energy Services”), and Stanolind Oil and Gas SPV LLC (“Stanolind SPV”) from Boaz Energy Partners, LLC (“Boaz Energy Partners”), Crown Energy Partners Holdings, LLC (“Crown Holdings”), Propel Energy, LLC (“Propel Energy”) and Stanolind Oil and Gas LP (“Stanolind”), all of which are primarily owned by two of the Funds.

· A net profits interest that WildHorse Resources purchased from NGP Income Co-Investment Fund II, L.P. (“NGPCIF”) on February 28, 2014 (“NGPCIF NPI”). NGPCIF is controlled by NGP. Upon the completion of the 2010 Petrohawk and Clayton Williams acquisitions, WildHorse Resources sold a net profits interest in these properties to NGPCIF. Since WildHorse Resources sold the net profits interest, the historical results are accounted for as a working interest for all periods.

Our unaudited financial statements reported herein include the financial position and results attributable to: (i) those certain oil and natural gas properties and related assets that MEMP acquired through equity transactions on October 1, 2013 from Boaz Energy Partners, Crown Holdings, Propel Energy and Stanolind and (ii) NGPCIF NPI.

Basis of Presentation

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

All material intercompany transactions and balances have been eliminated in preparation of our consolidated and combined financial statements.  Our results of operations for the three and nine months ended September 30, 2014 are not necessarily indicative of results expected for the full year.  In our opinion, the accompanying unaudited condensed consolidated and combined financial statements include all adjustments of a normal recurring nature necessary for fair presentation.  Although we believe the disclosures in these financial statements are adequate and make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted pursuant to the rules and regulations of the United States Securities and Exchange Commission (“SEC”).

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

· MRD—reflects the combined operations of the Company, MRD LLC, WildHorse Resources and its previous owners, Classic and Classic GP, Black Diamond, BlueStone, Beta Operating and MEMP GP.

· MEMP—reflects the combined operations of MEMP, its previous owners, and historical dropdown transactions that occurred between MEMP and other MRD LLC consolidating subsidiaries.

Segment financial information has been retrospectively revised for the following common control transactions for comparability purposes:

· acquisition by MEMP of all the outstanding membership interests in Tanos Energy, LLC (“Tanos”) from MRD LLC for a purchase price of approximately $77.4 million on October 1, 2013;

· acquisition by MEMP of all the outstanding membership interests in Prospect Energy, LLC (“Prospect Energy”) from Black Diamond for a purchase price of approximately $16.3 million on October 1, 2013;

· acquisition by MEMP of certain of the oil and natural gas properties in Jackson County, Texas from MRD LLC for a purchase price of approximately $2.6 million on October 1, 2013; and

· acquisition by MEMP of all the outstanding membership interests in WHT Energy Partners LLC (“WHT”) from WildHorse Resources and Tanos for a purchase price of approximately $200.0 million on March 28, 2013.

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UNAUDITED CONDENSED CONSOLIDATED AND COMBINED BALANCE SHEETS (Parenthetical) (USD $)	Sep. 30, 2014	Dec. 31, 2013
Statement Of Financial Position [Abstract]
Preferred stock, par value	$ 0.01
Preferred stock, shares authorized	50,000,000
Preferred stock, shares issued	0
Preferred stock, shares outstanding	0
Common stock, par value	$ 0.01
Common stock, shares authorized	600,000,000	0
Common stock, shares issued	193,559,211	0
Common stock, shares outstanding	193,559,211	0

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Long-Term Incentive Plans

9 Months Ended

Sep. 30, 2014

Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]

Long-Term Incentive Plans

Note 11.  Long-Term Incentive Plans

MRD

In June 2014, our Board adopted the Memorial Resource Development Corp. 2014 Long Term Incentive Plan (“MRD LTIP”) for the employees of the Company and the Board.  The MRD LTIP became effective upon filing of a registration statement on Form S-8 with the SEC on June 18, 2014. The MRD LTIP provides for potential grants of stock options, stock appreciation rights, restricted stock awards, restricted stock units, bonus stock, dividend equivalents, performance awards, annual incentive awards, and other stock-based awards. The MRD LTIP initially limits the number of common shares that may be delivered pursuant to awards under the plan to 19,250,000 common shares. Common shares that are cancelled, forfeited or withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards. The MRD LTIP will be administered by our Board or a committee thereof.

In connection with our initial public offering, our Board approved an aggregate award of 1,052,633 shares of restricted stock under the MRD LTIP to certain of our key employees, including each of our executive officers. These restricted stock awards will vest ratably on a four-year annual vesting schedule from the date of the grant and are subject to restrictions on transferability and customary forfeiture provisions.  An award of 5,263 shares of restricted stock was also granted to each of our independent directors. These restricted stock awards will vest one year from the date of the grant and are also subject to restrictions on transferability and customary forfeiture provisions.

Award recipients are entitled to all the rights of absolute ownership of the restricted common shares, including the right to vote those shares and to receive dividends thereon if, as, and when declared by our Board.  The term “restricted common share” represents a time-vested share.  Such awards are non-vested until the required service period expires.

The following table summarizes information regarding restricted common share awards granted under the MRD LTIP for the periods presented:

	Number of Shares			Weighted-Average Grant Date Fair Value per Share (1)
Restricted common shares outstanding at December 31, 2013		—		$	—
Granted (2)		1,068,422		$	19.00
Forfeited		(9,211	)	$	19.00
Restricted common units outstanding at September 30, 2014		1,059,211		$	19.00

(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 2014 was $20.3 million   based on a grant date market price of $19.00 per share.

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

For the Three Months				For the Nine Months
Ended September 30,				Ended September 30,
2014		2013		2014		2013
$	1,313	$	—	$	1,487	$	—

The unrecognized compensation cost associated with restricted common share awards was $18.6 million at September 30, 2014.  We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 3.68 years.

MEMP

In December 2011, the Memorial Production Partners GP LLC Long-Term Incentive Plan (“MEMP LTIP”) was adopted for employees, officers, consultants and directors of MEMP GP and any of its affiliates who perform services for MEMP. The MEMP LTIP consists of restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, other unit-based awards and unit awards. The MEMP LTIP initially limits the number of common units that may be delivered pursuant to awards under the plan to 2,142,221 common units. Common units that are cancelled, forfeited or withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards.

The restricted common units awarded are subject to restrictions on transferability, customary forfeiture provisions and graded vesting provisions. One-third of each award generally vests on the first, second, and third anniversaries of the date of grant. Award recipients have all the rights of a unitholder in MEMP with respect to the restricted common units, including the right to receive distributions thereon if and when distributions are made by MEMP to its unitholders (except with respect to the fourth quarter 2011 distribution that was paid in February 2012). The term “restricted common unit” represents a time-vested unit. Such awards are non-vested until the required service period expires.

The following table summarizes information regarding restricted common unit awards granted under the MEMP LTIP for the periods presented:

	Number of Units			Weighted-Average Grant Date Fair Value per Unit (1)
Restricted common units outstanding at December 31, 2013		706,927		$	18.62
Granted (2)		684,954		$	22.39
Forfeited		(36,112	)	$	20.43
Vested		(260,067	)	$	18.56
Restricted common units outstanding at September 30, 2014		1,095,702		$	20.93

(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 2014 was $15.3 million   based on a grant date market price range of $21.99 - $23.40 per unit

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

For the Three Months				For the Nine Months
Ended September 30,				Ended September 30,
2014		2013		2014		2013
$	2,427	$	1,237	$	5,387	$	2,322

The unrecognized compensation cost associated with restricted common unit awards was $19.1 million at September 30, 2014.  We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.3 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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Commitments and Contingencies - Minimum Commitments to Gather before Other Owner Contributions (Detail) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014
Dubach [Member]
Other Commitments [Line Items]
2014	$ 3,446
2015	13,671
2016	13,709
2017	13,671
2018	12,772
Total	57,269
Dubberly [Member]
Other Commitments [Line Items]
2014	1,436
2015	11,393
2016	11,424
2017	11,393
2018	10,643
Total	$ 46,289

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Document and Entity Information	9 Months Ended
	Sep. 30, 2014	Oct. 31, 2014
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2014
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	Q3
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		193,559,211

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Incentive Units

9 Months Ended

Sep. 30, 2014

Compensation Related Costs [Abstract]

Incentive Units

Note 12.  Incentive Units

General

Each of the governing documents of BlueStone, Tanos, WildHorse Resources, Classic, Black Diamond and MRD LLC previously provided for the issuance of incentive units. The incentive units were subject to performance conditions that affected their vesting. Compensation cost was recognized only if the performance condition was probable of being satisfied at each reporting date.

BlueStone, Tanos, WildHorse Resources, Classic, Black Diamond and MRD LLC each granted incentive units to certain of its members who were key employees at the time of grant. Holders of incentive units were entitled to distributions ranging from 10% to 31.5% when declared, but only after cumulative distribution thresholds (“payouts”) had been achieved. Payouts were generally triggered after the recovery of specified members’ capital contributions plus a rate of return. In connection with MEMP’s initial public offering in December 2011, BlueStone’s Special Tier and Tier I unit holders vested in their respective awards. Tier I unit holders became eligible to participate in 16.5% of any future distributions made by BlueStone.

Vesting of the incentive units was generally dependent upon an explicit service period, a fundamental change as defined in the respective governing document, and achievement of payout. All incentive units not vested were forfeited if an employee was no longer employed. All incentive units were forfeited if a holder resigned whether the incentive units were vested or not. If the payouts had not yet occurred, then all incentive units, whether or not vested, were forfeited automatically (unless extended).

On April 1, 2013, Tanos’ management team sold its 1.066% interest in Tanos to Memorial Resource and all incentive units held were forfeited. Compensation expense of approximately $5.8 million was recorded by Tanos and recognized as a component of general and administrative expense during the nine months ended September 30, 2013.

Compensation expense of approximately $1.0 million and $19.1 million was recorded by BlueStone (see Note 3) and recognized as a component of incentive unit compensation expense during the nine months ended September 30, 2014 and 2013, respectively.

In connection with the our initial public offering, certain former management members of WildHorse Resources contributed their 0.1% membership interest in WildHorse Resources as well as their incentive units in exchange for 42,334,323 shares of our common stock and cash consideration of $30.0 million. The portion of the total consideration related to acquiring the 0.1% membership interest was accounted for as the acquisition of noncontrolling interests. The difference between the carrying amount of the noncontrolling interest of $0.4 million and the fair value of the consideration paid of $3.3 million was recognized directly in stockholders’ equity as additional paid in capital. Compensation expense of approximately $831.1 million was recognized as a component of incentive unit compensation expense during the nine months ended September 30, 2014 related to the incentive units, of which approximately $26.7 million was paid in cash and the remaining $804.4 million related to the issuance of our common stock.

MRD Holdco

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

The holders of the Exchanged Incentive Units are eligible to participate in 9.3% of any future distributions made by MRD Holdco.  The payment likelihood was deemed probable as a result of our initial public offering and the reasonable expectation that MRD Holdco will monetize the shares of our common stock it owns over an estimated three year period as market conditions permit.  We recognized $136.7 million of compensation expense offset by a deemed capital contribution from MRD Holdco and the unrecognized compensation expense of approximately $158.5 million as of September 30, 2014 will be recognized over the remaining expected service period.   The fair value of the Exchanged Incentive Units will be remeasured on a quarterly basis until all payments have been made. The settlement obligation rests with MRD Holdco.  Accordingly, no payments will ever be made by us related to these incentive units; however, non-cash compensation expense will be allocated to us in future periods offset by capital contributions.  As such, these awards are not dilutive to our stockholders.

Subsequent to our initial public offering, MRD Holdco granted the remaining 70 incentive units to certain key employees (the “Subsequent Incentive Units”).  The holders of the Subsequent Incentive Units are eligible to participate in 0.7% of any future distributions made by MRD Holdco once payout associated with these incentive units has been achieved.  The payment likelihood was deemed probable at September 30, 2014 as a result of our initial public offering and the reasonable expectation that MRD Holdco will monetize the shares of our common stock it owns over an estimated three year period as market conditions permit.  We recognized $0.6 million of compensation expense and the unrecognized compensation expense of approximately $5.3 million as of September 30, 2014 will be recognized over the remaining expected service period.  The fair value of the Subsequent Incentive Units will be remeasured on a quarterly basis until all payments have been made. No payments will ever be made by us related to these incentive units; however, non-cash compensation expense will be allocated to us in future periods offset by capital contributions.  As such, these awards are not dilutive to our stockholders.

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

	Exchanged Incentive Units			Subsequent Incentive Units
Valuation date	9/30/2014			9/30/2014
Dividend yield		0	%		0	%
Expected volatility		21.47	%		21.47	%
Risk-free rate		0.90	%		0.90	%
Expected life (years)		2.67			2.67

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Related Party Transactions - Book Value of Assets Sold (Detail) (WHR Management Company [Member], USD $) In Thousands, unless otherwise specified	Jun. 18, 2014
WHR Management Company [Member]
Schedule Of Other Related Party Transactions [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

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Commitments and Contingencies - CO2 Minimum Purchase Commitment (Detail) (Wyoming Acquisition [Member], USD $) In Thousands, unless otherwise specified	Sep. 30, 2014
Wyoming Acquisition [Member]
Minimum Purchase Commitment [Line Items]
Estimated payment obligation, Total	$ 62,103
Estimated payment obligation, Remainder 2014	3,203
Estimated payment obligation, 2015	12,222
Estimated payment obligation, 2016	12,101
Estimated payment obligation, 2017	11,624
Estimated payment obligation, 2018	7,872
Estimated payment obligation, Thereafter	$ 15,081

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UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED AND COMBINED OPERATIONS (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Revenues:
Oil & natural gas sales	$ 244,161	$ 152,762	$ 669,301	$ 420,857
Pipeline tariff income and other	1,332	753	3,584	1,884
Total revenues	245,493	153,515	672,885	422,741
Costs and expenses:
Lease operating	46,211	29,395	111,887	81,746
Pipeline operating	431	394	1,596	1,343
Exploration	175	1,292	1,465	2,265
Production and ad valorem taxes	14,040	7,422	33,623	23,478
Depreciation, depletion, and amortization	84,447	45,136	215,906	132,328
Impairment of proved oil and natural gas properties	67,181	21	67,181	21
Incentive unit compensation expense (Note 12)	25,550	19,069	969,390	19,069
General and administrative	21,196	19,646	61,061	55,982
Accretion of asset retirement obligations	1,553	1,354	4,601	4,016
(Gain) loss on commodity derivative instruments	(189,492)	2,028	11,580	(29,556)
(Gain) loss on sale of properties	0	(90,063)	3,057	(86,218)
Other, net		24	(12)	622
Total costs and expenses	71,292	35,718	1,481,335	205,096
Operating income (loss)	174,201	117,797	(808,450)	217,645
Other income (expense):
Interest expense, net	(36,345)	(20,615)	(104,928)	(41,994)
Loss on extinguishment of debt	0		(37,248)
Other, net	15	24	102	81
Total other income (expense)	(36,330)	(20,591)	(142,074)	(41,913)
Income (loss) before income taxes	137,871	97,206	(950,524)	175,732
Income tax benefit (expense)	(25,834)	(1,244)	(14,398)	(1,432)
Net income (loss)	112,037	95,962	(964,922)	174,300
Net income (loss) attributable to noncontrolling interest	102,109	11,235	(34,851)	42,134
Net income (loss) attributable to Memorial Resource Development Corp.	9,928	84,727	(930,071)	132,166
Net (income) loss allocated to members		(84,754)	(20,305)	(122,639)
Net (income) loss allocated to previous owners		27	(1,425)	(9,527)
Net income (loss) available to common stockholders	$ 9,928		$ (951,801)
Earnings per common share: (Note 10)
Basic	$ 0.05		$ (4.94)
Diluted	$ 0.05		$ (4.94)
Weighted average common and common equivalent shares outstanding:
Basic	192,500		192,500
Diluted	192,716		192,500

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Asset Retirement Obligations

9 Months Ended

Sep. 30, 2014

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

Note 6.  Asset Retirement Obligations

Asset retirement obligations primarily relate to our portion of future plugging and abandonment costs for wells and related facilities.

The following table presents the changes in the asset retirement obligations for the nine months ended September 30, 2014 (in thousands):

Asset retirement obligations at beginning of period	$	111,769
Liabilities added from acquisitions or drilling		5,053
Liabilities removed upon sale of wells to an affiliate		(1,636	)
Liabilities removed upon plugging and abandoning		(344	)
Revisions		67
Accretion expense		4,601
Asset retirement obligations at end of period	$	119,510

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Risk Management and Derivative Instruments

9 Months Ended

Sep. 30, 2014

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Risk Management and Derivative Instruments

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 creditworthy counterparties that are generally large financial institutions.  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, 2014, after taking into effect netting arrangements, MEMP did not have any counterparty exposure related to its derivative instruments. Had certain counterparties failed completely to perform according to the terms of their existing contracts, MEMP would have the right to offset $37.5 million against amounts outstanding under its revolving credit facility at September 30, 2014.  At September 30, 2014, after taking into effect netting arrangements, we did not have any counterparty exposure related to our derivative instruments. Had certain counterparties failed completely to perform according to the terms of their existing contracts, we would have the right to offset $29.0 million against amounts outstanding under our revolving credit facility at September 30, 2014.  See Note 8 for additional information regarding our revolving credit facilities.

Commodity Derivatives

We may use a combination of commodity derivatives (e.g., floating-for-fixed swaps, put options, costless collars, call spreads and basis swaps) to manage exposure to commodity price volatility. We recognize all derivative instruments at fair value; however, certain of our put option derivative instruments have a deferred premium, which reduces the asset. For the deferred premium puts, the Company agrees to pay a premium to the counterparty at the time of settlement. At settlement, if the applicable index price is below the strike price of the put, the Company receives the difference between the strike price and the applicable index price multiplied by the contract volumes less the premium. If the applicable index price settles at or above the strike price of the put, the Company pays only the premium at settlement.

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 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, 2014, the MRD Segment had the following open commodity positions:

	Remaining
	2014			2015			2016			2017			2018
Natural Gas Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (MMBtu)		4,540,000			2,250,000			1,670,000			1,270,000			1,500,000
Weighted-average fixed price	$	4.18		$	4.08		$	4.18		$	4.30		$	4.30
Collar contracts:
Average Monthly Volume (MMBtu)		730,000			1,580,000			1,100,000			1,050,000			—
Weighted-average floor price	$	4.11		$	4.14		$	4.00		$	4.00		$	—
Weighted-average ceiling price	$	5.15		$	4.61		$	4.71		$	5.06		$	—
TGT Z1 basis swaps:
Average Monthly Volume (MMBtu)		2,270,000			1,730,000			220,000			200,000			—
Spread	$	(0.08	)	$	(0.09	)	$	(0.08	)	$	(0.08	)	$	—
Crude Oil Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		56,000			33,500			—			9,500			7,625
Weighted-average fixed price	$	94.43		$	93.86		$	—		$	87.62		$	87.00
Collar contracts:
Average Monthly Volume (Bbls)		12,000			2,000			27,000			—			—
Weighted-average floor price	$	86.67		$	85.00		$	80.00		$	—		$	—
Weighted-average ceiling price	$	112.33		$	101.35		$	99.70		$	—		$	—
Put option contracts:
Average Monthly Volume (Bbls)		—			26,000			—			—			—
Weighted-average fixed price	$	—		$	85.00		$	—		$	—		$	—
Weighted-average deferred premium	$	—		$	(3.80	)	$	—		$	—		$	—
NGL Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		184,000			151,000			148,500			—			—
Weighted-average fixed price	$	44.84		$	41.61		$	39.75		$	—		$	—

At September 30, 2014, the MEMP Segment had the following open commodity positions:

	Remaining
	2014			2015			2016			2017			2018		2019
Natural Gas Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (MMBtu)		2,580,200			2,605,278			2,692,442			2,450,067			2,160,000		1,914,583
Weighted-average fixed price	$	4.34		$	4.28		$	4.40		$	4.31		$	4.51	$	4.75
Collar contracts:
Average Monthly Volume (MMBtu)		340,000			350,000			—			—			—		—
Weighted-average floor price	$	5.00		$	4.62		$	—		$	—		$	—	$	—
Weighted-average ceiling price	$	6.31		$	5.80		$	—		$	—		$	—	$	—
Call spreads (1):
Average Monthly Volume (MMBtu)		120,000			80,000			—			—			—		—
Weighted-average sold strike price	$	5.17		$	5.25		$	—		$	—		$	—	$	—
Weighted-average bought strike price	$	6.53		$	6.75		$	—		$	—		$	—	$	—
Basis swaps:
Average Monthly Volume (MMBtu)		2,830,000			2,940,000			1,635,000			300,000			—		—
Spread	$	(0.09	)	$	(0.12	)	$	(0.06	)	$	(0.05	)	$	—	$	—
Crude Oil Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		283,452			314,281			332,813			326,600			312,000		160,000
Weighted-average fixed price	$	95.83		$	90.96		$	85.83		$	84.38		$	83.74	$	85.52
Collar contracts:
Average Monthly Volume (Bbls)		23,000			5,000			—			—			—		—
Weighted-average floor price	$	82.83		$	80.00		$	—		$	—		$	—	$	—
Weighted-average ceiling price	$	105.31		$	94.00		$	—		$	—		$	—	$	—
Basis swaps:
Average Monthly Volume (Bbls)		134,000			97,500			—			—			—		—
Spread	$	(4.32	)	$	(7.07	)	$	—		$	—		$	—	$	—
NGL Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		167,500			149,200			55,000			—			—		—
Weighted-average fixed price	$	43.13		$	43.02		$	39.28		$	—		$	—	$	—

(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
	2014			2015			2016			2017
Natural Gas Derivative Contracts:
NGPL TexOk basis swaps:
Average Monthly Volume (MMBtu)		2,260,000			2,280,000			1,500,000			300,000
Spread	$	(0.09	)	$	(0.11	)	$	(0.07	)	$	(0.05	)
NGPL STX basis swaps:
Average Monthly Volume (MMBtu)		380,000			—			—			—
Spread	$	(0.11	)	$	—		$	—		$	—
HSC basis swaps:
Average Monthly Volume (MMBtu)		190,000			150,000			135,000			—
Spread	$	(0.07	)	$	(0.08	)	$	0.07		$	—
CIG basis swaps:
Average Monthly Volume (MMBtu)		—			210,000			—			—
Spread	$	—		$	(0.25	)	$	—		$	—
TETCO STX basis swaps:
Average Monthly Volume (MMBtu)		—			300,000			—			—
Spread	$	—		$	(0.09	)	$	—		$	—
Crude Oil Derivative Contracts:
Midway-Sunset basis swaps:
Average Monthly Volume (Bbls)		60,000			57,500			—			—
Spread - Brent	$	(9.25	)	$	(9.73	)	$	—		$	—
Midland basis swaps:
Average Monthly Volume (Bbls)		40,000			40,000			—			—
Spread - WTI	$	(3.68	)	$	(3.25	)	$	—		$	—
LLS Crude basis swaps:
Average Monthly Volume (Bbls)		34,000			—			—			—
Spread - WTI	$	3.61		$	—		$	—		$	—

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 agreement to fixed interest rates. From time to time we enter into offsetting positions to avoid being economically over-hedged. At September 30, 2014, we had the following interest rate swap open positions:

	Remaining
Credit Facility	2014			2015			2016
MEMP:
Average Monthly Notional (in thousands)	$	248,333		$	280,833		$	150,000
Weighted-average fixed rate		1.299	%		1.416	%		1.193	%
Floating rate	1 Month LIBOR			1 Month LIBOR			1 Month LIBOR

On July 1, 2014, we elected to terminate the interest rate swaps associated with the MRD credit facility and in the aggregate paid our counterparties approximately $0.7 million.  WildHorse Resources novated the interest rate swaps to MRD in connection with the closing of our initial public offering.

Balance Sheet Presentation

The following table summarizes both: (i) the gross fair value of derivative instruments by the appropriate balance sheet classification even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the balance sheet and (ii) the net recorded fair value as reflected on the balance sheet at September 30, 2014 and December 31, 2013.  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	2014			2013			2014			2013
		(In thousands)
Commodity contracts	Short-term derivative instruments	$	48,405		$	21,759		$	12,458		$	19,739
Interest rate swaps	Short-term derivative instruments		—			845			3,635			3,287
Gross fair value			48,405			22,604			16,093			23,026
Netting arrangements	Short-term derivative instruments		(10,984	)		(13,315	)		(10,984	)		(13,315	)
Net recorded fair value	Short-term derivative instruments	$	37,421		$	9,289		$	5,109		$	9,711
Commodity contracts	Long-term derivative instruments	$	81,306		$	83,295		$	62,084		$	38,495
Interest rate swaps	Long-term derivative instruments		95			39			77			2,303
Gross fair value			81,401			83,334			62,161			40,798
Netting arrangements	Long-term derivative instruments		(46,886	)		(34,718	)		(46,886	)		(34,718	)
Net recorded fair value	Long-term derivative instruments	$	34,515		$	48,616		$	15,275		$	6,080

(Gains) Losses on Derivatives

All gains and losses, including changes in the derivative instruments’ fair values, have been recorded in the accompanying statements of operations since derivative instruments are not designated as hedging instruments for accounting and financial reporting purposes. The following table details the gains and losses related to derivative instruments for the three and nine months ended September 30, 2014 and 2013 (in thousands):

		For the Three Months					For the Nine Months
	Statements of	Ended September 30,					Ended September 30,
	Operations Location	2014			2013		2014		2013
Commodity derivative contracts	(Gain) loss on commodity derivatives	$	(189,492	)	$	2,028	$	11,580	$	(29,556	)
Interest rate derivatives	Interest expense, net		(175	)		1,926		1,157		69

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Background, Organization and Basis of Presentation (Policies)

9 Months Ended

Sep. 30, 2014

Accounting Policies [Abstract]

Overview

Overview

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

The Company was formed by Memorial Resource Development LLC (“MRD LLC”) in January 2014 to exploit, develop and acquire natural gas, NGL and oil properties in North America. MRD LLC was a Delaware limited liability company formed on April 27, 2011 by Natural Gas Partners VIII, L.P. (“NGP VIII”), Natural Gas Partners IX, L.P. (“NGP IX”) and NGP IX Offshore Holdings, L.P. (“NGP IX Offshore”) (collectively, the “Funds”) to exploit, develop and acquire natural gas, NGL and oil properties. The Funds are private equity funds managed by Natural Gas Partners (“NGP”).  MRD LLC’s consolidated and combined financial statements represent our predecessor for accounting and financial reporting purposes prior to our initial public offering.

Initial Public Offering and Restructuring Transactions

Initial Public Offering and Restructuring Transactions

On June 18, 2014, the Company completed its initial public offering of 21,500,000 common units at a price of $19.00 per share, which generated net proceeds to the Company of approximately $380.2 million after deducting underwriting discounts and commissions and other offering related fees and expenses. The following restructuring events and transactions occurred in connection with our initial public offering:

· The Funds contributed all of their interests in MRD LLC to MRD Holdco LLC (“MRD Holdco”) and the members of our management who owned incentive units in MRD LLC exchanged those incentive units for substantially identical incentive units in MRD Holdco, after which MRD Holdco owned 100% of MRD LLC;

· WildHorse Resources, LLC  (“WildHorse Resources”) sold its subsidiary, WildHorse Resources Management Company, LLC (“WHR Management Company”), to an affiliate of the Funds for approximately $0.2 million in cash, and WHR Management Company entered into a services agreement with the Company and WildHorse Resources pursuant to which WHR Management Company will provide transition services to WildHorse Resources;

· Classic Hydrocarbons Holdings, L.P. (“Classic”) and Classic Hydrocarbons GP Co., L.L.C. (“Classic GP”) distributed to MRD LLC the ownership interests in Classic Pipeline & Gathering, LLC (“Classic Pipeline”), which owns certain midstream assets in Texas, and Black Diamond Minerals, LLC (“Black Diamond”) distributed to MRD LLC its ownership interests in Golden Energy Partners LLC (“Golden Energy”), which sold all of its assets in May 2014;

· MRD LLC contributed to us substantially all of its assets, comprised of: (i) 100% of the ownership interests in Classic, Classic GP, Black Diamond, Beta Operating Company, LLC (“Beta Operating”), Memorial Resource Finance Corp., MRD Operating LLC (“MRD Operating”), Memorial Production Partners GP LLC (“MEMP GP”) (including MEMP GP’s ownership of 50% of Memorial Production Partners LP’s (“MEMP”) incentive distribution rights) and (ii) 99.9% of the membership interests in WildHorse Resources;

· We issued 128,665,677 shares of our common stock to MRD LLC, which MRD LLC immediately distributed to MRD Holdco;

· We assumed the obligations of MRD LLC under the indenture governing the $350 million in aggregate principal amount of 10.00% / 10.75% Senior PIK Toggle Notes due 2018 (the “PIK notes”) and reimbursed MRD LLC for the June 15, 2014 interest payment made on the PIK notes;

· Certain former management members of WildHorse Resources contributed to us their outstanding incentive units in WildHorse Resources, as well as the remaining 0.1% of the membership interests in WildHorse Resources, and we issued 42,334,323 shares of our common stock and paid cash consideration of $30.0 million to such former management members of WildHorse Resources;

· We entered into a registration rights agreement and a voting agreement with MRD Holdco and certain former management members of WildHorse Resources;

· We entered into a new $2.0 billion revolving credit facility (see Note 8) and used approximately $614.5 million in borrowings under that facility to repay all amounts outstanding under WildHorse Resources’ credit agreements, to partially fund the cash consideration payable to the former management members of WildHorse Resources and to reimburse MRD LLC for the June 15, 2014 interest payment made on the PIK notes;

· Notice of redemption was given to the PIK notes trustee (see Note 8) specifying a redemption date of July 16, 2014 and indicating that a portion of the net proceeds from our initial public offering, which temporarily reduced amounts outstanding under our new revolving credit facility, would be used to redeem the PIK notes at a redemption price of 102% of the principal amount of the PIK notes plus accrued and unpaid interest thereon to the date of redemption;

· MRD Operating entered into a merger agreement with MRD LLC pursuant to which after the termination or earlier discharge of the PIK notes MRD LLC would merge into MRD Operating;

· MRD LLC distributed to MRD Holdco the following: (i) BlueStone Natural Resources Holdings, LLC (“BlueStone”), which sold substantially all of its assets in July 2013 for $117.9 million, MRD Royalty LLC, which owns certain leasehold interests and overriding royalty interests in Texas and Montana, MRD Midstream LLC, which owns an indirect interest in certain midstream assets in North Louisiana, Golden Energy and Classic Pipeline; (ii) 5,360,912 subordinated units of MEMP; (iii) the right to the remaining cash to be released from the debt service reserve account in connection with the redemption or earlier discharge of the PIK notes plus the cash received from us in reimbursement of the interest paid on June 15, 2014 in respect of the PIK notes; and (iv) approximately $6.7 million of cash received by MRD LLC in connection with the sale of Golden Energy’s assets in May 2014;

· We irrevocably deposited with the PIK notes trustee approximately $360.0 million on June 27, 2014, which was an amount sufficient to fund the redemption of the PIK notes on the redemption date and to satisfy and discharge our obligations under the PIK notes and the related indenture.  The discharge became effective upon the irrevocable deposit of the funds with the PIK notes trustee; and

· MRD LLC merged into MRD Operating.

Previous Owners

Previous Owners

References to “the previous owners” for accounting and financial reporting purposes refer collectively to:

· Certain oil and natural gas properties and related assets primarily in the Permian Basin, East Texas and the Rockies that MEMP acquired through equity transactions on October 1, 2013 from certain affiliates of NGP. On October 1, 2013, MEMP acquired Boaz Energy, LLC (“Boaz”), Crown Energy Partners, LLC (“Crown”), the Crown net profits interest and overriding royalty interest (“Crown NPI/ORRI”), Propel Energy SPV LLC (“Propel SPV”), together with its wholly-owned subsidiary Propel Energy Services, LLC (“Propel Energy Services”), and Stanolind Oil and Gas SPV LLC (“Stanolind SPV”) from Boaz Energy Partners, LLC (“Boaz Energy Partners”), Crown Energy Partners Holdings, LLC (“Crown Holdings”), Propel Energy, LLC (“Propel Energy”) and Stanolind Oil and Gas LP (“Stanolind”), all of which are primarily owned by two of the Funds.

· A net profits interest that WildHorse Resources purchased from NGP Income Co-Investment Fund II, L.P. (“NGPCIF”) on February 28, 2014 (“NGPCIF NPI”). NGPCIF is controlled by NGP. Upon the completion of the 2010 Petrohawk and Clayton Williams acquisitions, WildHorse Resources sold a net profits interest in these properties to NGPCIF. Since WildHorse Resources sold the net profits interest, the historical results are accounted for as a working interest for all periods.

Our unaudited financial statements reported herein include the financial position and results attributable to: (i) those certain oil and natural gas properties and related assets that MEMP acquired through equity transactions on October 1, 2013 from Boaz Energy Partners, Crown Holdings, Propel Energy and Stanolind and (ii) NGPCIF NPI.

Basis of Presentation

Basis of Presentation

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

All material intercompany transactions and balances have been eliminated in preparation of our consolidated and combined financial statements.  Our results of operations for the three and nine months ended September 30, 2014 are not necessarily indicative of results expected for the full year.  In our opinion, the accompanying unaudited condensed consolidated and combined financial statements include all adjustments of a normal recurring nature necessary for fair presentation.  Although we believe the disclosures in these financial statements are adequate and make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted pursuant to the rules and regulations of the United States Securities and Exchange Commission (“SEC”).

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

· MRD—reflects the combined operations of the Company, MRD LLC, WildHorse Resources and its previous owners, Classic and Classic GP, Black Diamond, BlueStone, Beta Operating and MEMP GP.

· MEMP—reflects the combined operations of MEMP, its previous owners, and historical dropdown transactions that occurred between MEMP and other MRD LLC consolidating subsidiaries.

Segment financial information has been retrospectively revised for the following common control transactions for comparability purposes:

· acquisition by MEMP of all the outstanding membership interests in Tanos Energy, LLC (“Tanos”) from MRD LLC for a purchase price of approximately $77.4 million on October 1, 2013;

· acquisition by MEMP of all the outstanding membership interests in Prospect Energy, LLC (“Prospect Energy”) from Black Diamond for a purchase price of approximately $16.3 million on October 1, 2013;

· acquisition by MEMP of certain of the oil and natural gas properties in Jackson County, Texas from MRD LLC for a purchase price of approximately $2.6 million on October 1, 2013; and

· acquisition by MEMP of all the outstanding membership interests in WHT Energy Partners LLC (“WHT”) from WildHorse Resources and Tanos for a purchase price of approximately $200.0 million on March 28, 2013.

Use of Estimates

Use of Estimates

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

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

Principles of Consolidation and Combination

Principles of Consolidation and Combination

Our consolidated financial statements include our accounts and those of our subsidiaries in which we have a controlling interest.  Likewise, the combined financial statements include those of our predecessor and the previous owners.

Cash and Cash Equivalents

Cash and Cash Equivalents

Cash and cash equivalents represent unrestricted cash on hand and all highly liquid investments with original contractual maturities of three months or less.

Concentrations of Credit Risk

Concentrations of Credit Risk

Cash balances, accounts receivable, restricted investments and derivative financial instruments are financial instruments potentially subject to credit risk. Cash and cash equivalents are maintained in bank deposit accounts which, at times, may exceed the federally insured limits. Management periodically reviews and assesses the financial condition of the banks to mitigate the risk of loss. Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with MEMP’s offshore Southern California oil and gas properties. These restricted investments may consist of money market deposit accounts, money market mutual funds, commercial paper, and U.S. Government securities, all held with credit-worthy financial institutions. Derivative financial instruments are generally executed with major financial institutions that expose us to market and credit risks and which may, at times, be concentrated with certain counterparties. The creditworthiness of the counterparties is subject to continual review. We rely upon netting arrangements with counterparties to reduce credit exposure. We have not experienced any losses from such instruments.

Oil and natural gas are sold to a variety of purchasers, including intrastate and interstate pipelines or their marketing affiliates and independent marketing companies. Accounts receivable from joint operations are from a number of oil and natural gas companies, partnerships, individuals, and others who own interests in the properties operated by us and our predecessor. Generally, operators of crude oil and natural gas properties have the right to offset future revenues against unpaid charges related to operated wells, minimizing the credit risk associated with these receivables. Additionally, management believes that any credit risk imposed by a concentration in the oil and natural gas industry is mitigated by the creditworthiness of its customer base. An allowance for doubtful accounts is recorded after all reasonable efforts have been exhausted to collect or settle the amount owed. Any amounts outstanding longer than the contractual terms are considered past due. Management determined that an allowance for uncollectible accounts was unnecessary at both September 30, 2014 and December 31, 2013, respectively.

If we were to lose any one of our customers, the loss could temporarily delay production and the sale of oil and natural gas in the related producing region. If we were to lose any single customer, we believe that a substitute customer to purchase the impacted production volumes could be identified.

Oil and Natural Gas Properties

Oil and Natural Gas Properties

Oil and natural gas exploration, development and production activities are accounted for in accordance with the successful efforts method of accounting. Under this method, costs of acquiring properties, costs of drilling successful exploration wells, and development costs are capitalized. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if determination is made that proved reserves have been found. If no proved reserves have been found, the costs of each of the related exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. The costs of such exploratory wells are expensed if a determination of proved reserves has not been made within a twelve-month period after drilling is complete. Exploration costs such as geological, geophysical, and seismic costs are expensed as incurred.

As exploration and development work progresses and the reserves on these properties are proven, capitalized costs attributed to the properties are subject to depreciation and depletion. Depletion of capitalized costs is provided using the units-of-production method based on proved oil and gas reserves related to the associated field. Capitalized drilling and development costs of producing oil and natural gas properties are depleted over proved developed reserves and leasehold costs are depleted over total proved reserves.

On the sale or retirement of a complete or partial unit of a proved property or pipeline and related facilities, the cost and related accumulated depreciation, depletion, and amortization are removed from the property accounts, and any gain or loss is recognized.

Impairments

Impairments

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, such as a downward revision of the reserve estimates, less than expected production, drilling results, higher operating and development costs, or lower commodity prices. The estimated undiscounted future cash flows expected in connection with the property are compared to the carrying value of the property to determine if the carrying amount is recoverable. If the carrying value of the property exceeds its estimated undiscounted future cash flows, the carrying amount of the property is reduced to its estimated fair value using Level 3 inputs. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties.

Unproved oil and natural gas properties are assessed for impairment on a property-by-property basis. A loss is recognized by providing a valuation allowance if the assessment indicates an impairment. The impairment assessment is affected by economic factors such as the results of exploration activities, commodity price outlooks, remaining lease terms, and potential shifts in business strategy employed by management.

Asset Retirement Obligations

Asset Retirement Obligations

An asset retirement obligation associated with retiring long-lived assets is recognized as a liability on a discounted basis in the period in which the legal obligation is incurred and becomes determinable, with an equal amount capitalized as an addition to oil and natural gas properties, which is allocated to expense over the useful life of the asset. Generally, oil and gas producing companies incur such a liability upon acquiring or drilling a well. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. Upon settlement of the liability, a gain or loss is recognized as a component of exploration costs to the extent the actual costs differ from the recorded liability. See Note 6 for further discussion of asset retirement obligations.

Oil and Gas Reserves

Oil and Gas Reserves

The estimates of proved oil and natural gas reserves utilized in the preparation of the consolidated and combined financial statements are estimated in accordance with the rules established by the SEC and the Financial Accounting Standards Board (“FASB”). These rules require that reserve estimates be prepared under existing economic and operating conditions using a trailing 12-month average price with no provision for price and cost escalations in future years except by contractual arrangements.

Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties, or any combination of the above may be increased or reduced. Increases in recoverable economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates.

Other Property & Equipment

Other Property & Equipment

Other property and equipment is stated at historical costs and is comprised primarily of vehicles, furniture, fixtures, and computer hardware and software. Depreciation of other property and equipment is calculated using the straight-line method generally based on estimated useful lives of three to five years.

Restricted Investments

Restricted Investments

Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with MEMP’s offshore Southern California oil and gas properties. These investments are classified as held-to-maturity, and such investments are stated at amortized cost. Interest earned on these investments is included in interest expense – net in the statement of operations. The amortized cost of such investments is adjusted for amortization of premiums and accretion of discounts to maturity. At September 30, 2014, these restricted investments consisted of money market deposit accounts, money market mutual funds, commercial paper, and U.S. Government securities. See Note 7 for additional information.

Debt Issuance Costs

Debt Issuance Costs

These costs are recorded on the balance sheet and amortized over the term of the associated debt using the straight-line method which approximates the effective yield method.

Revenue Recognition

Revenue Recognition

Revenue from the sale of oil and natural gas is recognized when title passes, net of royalties due to third parties. Oil and natural gas revenues are recorded using the sales method. Under this method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers, regardless of whether the sales are proportionate to our ownership in the property. An asset or a liability is recognized to the extent that we have an imbalance in excess of our proportionate share of the remaining recoverable reserves on the underlying properties.

Derivative Instruments

Derivative Instruments

Commodity derivative financial instruments (e.g., swaps, collars, and put options) are used to reduce the impact of natural gas and oil price fluctuations. Interest rate swaps are used to manage exposure to interest rate volatility, primarily as a result of variable rate borrowings under the credit facilities. Every derivative instrument is recorded on the balance sheet as either an asset or liability measured at its fair value. Changes in the derivative’s fair value are recognized in earnings as we have not elected hedge accounting for any of our derivative positions.

Income Tax

Income Tax

Prior to our initial public offering, MRD LLC was organized as a pass-through entity for federal income tax purposes and was not subject to federal income taxes; however, certain of its consolidating subsidiaries were taxed as corporations and subject to federal income taxes.  We are organized as a taxable C corporation and subject to federal and certain state income taxes.  We are also subject to the Texas margin tax and certain aspects of the tax make it similar to an income tax as the tax is assessed on 1% of taxable margin apportioned to operations in Texas.

Deferred federal and state income taxes are provided on temporary differences between the financial statement carrying amounts of assets and liabilities and their respective tax basis. If it is more likely than not that some of the deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. A tax benefit from an uncertain tax position is recognized when it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position. The tax benefit recorded is equal to the largest amount that is greater than 50% likely to be realized through final settlement with a taxing authority. There were no uncertain tax positions that required recognition in the financial statements at both September 30, 2014 and December 31, 2013, respectively.

In June 2014, we recorded a deferred tax liability of approximately $43.3 million in stockholders’ equity in connection with our initial public offering and the related restructuring transactions.  The tax bases of our assets and liabilities changed as a result our initial public offering and the related restructuring transactions, which represented a transaction among stockholders.

Earnings Per Share

Earnings Per Share

Basic earnings per share (“EPS”) is computed based on the average number of shares of common stock outstanding for the period. Diluted EPS includes the effect of the Company’s outstanding restricted stock awards if the inclusion of these awards is dilutive.   See Note 10 for additional information.

Incentive-Based Compensation Arrangements

Incentive-Based Compensation Arrangements

The fair value of equity-classified awards (e.g., restricted stock awards) is amortized to earnings over the requisite service or vesting period.  Compensation expense for liability-classified awards are recognized over the requisite service or vesting period of an award based on the fair value of the award re-measured at each reporting period. Generally, no compensation expense is recognized for equity instruments that do not vest.

Prior to the restructuring transactions, the governing documents of MRD LLC and certain of its subsidiaries, including WildHorse Resources and BlueStone, provided for the issuance of incentive units. The incentive units were subject to performance conditions that affected their vesting. Compensation cost was recognized only if the performance condition was probable of being satisfied at each reporting date.

In connection with the restructuring transactions, the MRD LLC incentive units were exchanged for substantially identical units in MRD Holdco, and such incentive units entitle holders thereof to portions of future distributions by MRD Holdco. While any such distributions made by MRD Holdco will not involve any cash payment by us, we will be required to recognize non-cash compensation expense, which may be material, in future periods. The compensation expense recognized by us related to the incentive units will be offset by a deemed capital contribution from MRD Holdco.

See Notes 11 and 12 for further information.

New Accounting Pronouncements

New Accounting Pronouncements

Revenue from Contracts with Customers.  In May 2014, the FASB issued a comprehensive new revenue recognition standard for contracts with customers that will supersede most current revenue recognition guidance, including industry-specific guidance. The core principle of this standard is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, the standard provides a five-step analysis of transactions to determine when and how revenue is recognized. Other major provisions include the capitalization and amortization of certain contract costs, ensuring the time value of money is considered in the transaction price, and allowing estimates of variable consideration to be recognized before contingencies are resolved in certain circumstances. This guidance also requires enhanced disclosures regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from an entity’s contracts with customers. The new standard is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016. Early application is prohibited. The standard permits the use of either the retrospective or cumulative effect transition method. This guidance will be applicable to the Company beginning on January 1, 2017. The Company is currently assessing the impact that adopting this new accounting guidance will have on its financial consolidated financial statements and footnote disclosures.

Reporting Discontinued Operations.  In April 2014, the FASB issued an accounting standards update that changes the criteria for determining when disposals can be presented as discontinued operations and modifies discontinued operations disclosures.  The new guidance now defines a “discontinued operation” as (i) a disposal of a component or group of components that is disposed of or is classified as held for sale and “represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results” or (ii) an acquired business or nonprofit activity that is classified as held for sale on the date of acquisition.  We will adopt this guidance and apply the disclosure requirements prospectively beginning on January 1, 2015.

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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Related Party Transactions

9 Months Ended

Sep. 30, 2014

Related Party Transactions [Abstract]

Related Party Transactions

Note 13.  Related Party Transactions

Amounts due to (due from) MRD Holdco and certain affiliates of NGP at September 30, 2014 and December 31, 2013 are presented as “Accounts receivable – affiliates” and “Accounts payable – affiliates” in the accompanying balance sheets.

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.

Common Control Transactions between MEMP and Other MRD LLC Subsidiaries

MEMP acquired all of the outstanding membership interests in WHT from WildHorse Resources and Tanos on March 28, 2013 for a purchase price of approximately $200.0 million.  On April 1, 2014, MEMP acquired certain oil and natural gas producing properties in East Texas from WildHorse Resources for approximately $33.3 million, including estimated customary post-closing adjustments.  

MEMP acquired of all the outstanding membership interests in Tanos for a purchase price of approximately $77.4 million on October 1, 2013.

MEMP acquired of all the outstanding membership interests in Prospect from Black Diamond for a purchase price of approximately $16.3 million on October 1, 2013.

MEMP acquired of certain of the oil and natural gas properties in Jackson County, Texas from MRD LLC for a purchase price of approximately $2.6 million on October 1, 2013.

Other Acquisitions or Dispositions

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

On March 28, 2014, MRD Royalty acquired certain interests in oil and gas properties in Gonzales and Karnes Counties located in South Texas from Propel Energy for $3.3 million. Due to common control considerations, this transaction was recognized in the equity statement.

On June 18, 2014, in connection with our initial public offering and the related restructuring transactions (see Note 1), WHR Management Company was sold by WildHorse Resources to an affiliate of the Funds for net book value.  The net book value of the assets sold was as follows (in thousands):

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

Related Party Agreements

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

Registration Rights Agreement

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

Voting Agreement

In connection with the closing of our initial public offering, we entered into a voting agreement with MRD Holdco, WHR Incentive LLC, a limited liability company beneficially owned by Messrs. Bahr and Graham, and certain former management members of WildHorse Resources, who contributed their ownership of WildHorse Resources to us in the restructuring transactions. Among other things, the voting agreement provides that those former management members of WildHorse Resources will vote all of their shares of our common stock as directed by MRD Holdco. The voting agreement also prohibits the transfer of any shares of our common stock by the former management members of WildHorse Resources until after the termination of the services agreement described below; provided, however, that the former management members of WildHorse Resources (other than Messrs. Bahr and Graham) may transfer their shares of our common stock after the 180 day lock-up period has expired and these transfer restrictions will not prohibit Messrs. Bahr and Graham from exercising piggyback registration rights under the registration rights agreement described above.

Omnibus Agreement

On December 14, 2011, in connection with the closing of MEMP’s initial public offering, MRD LLC entered into an omnibus agreement with MEMP and its general partner. We succeeded to all of MRD LLC’s duties and obligations under the omnibus agreement.

Pursuant to the omnibus agreement, MEMP is required to reimburse us for all expenses incurred by us (or payments made on MEMP’s behalf) in conjunction with our provision of general and administrative services to MEMP, including, but not limited to, public company expenses and an allocated portion of the salary and benefits of the executive officers of MEMP’s general partner and our other employees who perform services for MEMP or on MEMP’s behalf. MEMP is also obligated to reimburse us for insurance coverage expenses we incur with respect to MEMP’s business and operations and with respect to director and officer liability coverage for the officers and directors of MEMP’s general partner.

Beta Management Agreement

On December 12, 2012, MRD LLC entered into a management agreement with its wholly-owned subsidiary, Beta Operating Company, LLC pursuant to which MRD LLC agreed to provide management and administrative oversight with respect to the services provided by such subsidiary under certain operating agreements with a subsidiary of MEMP, in exchange for an annual management fee. We succeeded to this management agreement and we will receive approximately $0.4 million from MEMP annually under that agreement.

Services Agreement

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

WHR Management Company may only terminate the services agreement by providing 90-days prior written notice to us after the six-month anniversary of the date of the agreement. We may terminate the services agreement at any time by providing written notice to WHR Management Company. The services agreement may only be assigned by either party with the other party’s consent. Upon the closing of our initial public offering, WHR Management Company became a subsidiary of WildHorse Resources II, LLC, an affiliate of the Company. NGP and certain former management members of WildHorse Resources own WildHorse Resources II, LLC.

Gas Processing Agreement

On March 17, 2014, WildHorse Resources entered into a gas processing agreement with PennTex North Louisiana, LLC (“PennTex”). PennTex is a joint venture among certain affiliates of NGP in which MRD Holdco, through its subsidiary MRD Midstream LLC, owns a minority interest. Once PennTex’s processing plant becomes operational, it will process natural gas produced from wells located on certain leases owned by WildHorse Resources in the state of Louisiana. The agreement has a 15-year primary term, subject to one-year extensions at either party’s election. WildHorse Resources will pay PennTex a monthly fee, subject to an annual inflationary escalation, based on volumes of natural gas delivered and processed. Once the plant is declared operational, WildHorse Resources will be obligated to pay a minimum processing fee equal to approximately $18.3 million on an annual basis, subject to certain adjustments and conditions. The gas processing agreement requires that the processing plant be operational no later than November 1, 2015.

Classic Pipeline Gas Gathering Agreement & Water Disposal Agreement

On November 1, 2011, Classic Hydrocarbons Operating, LLC (“Classic Operating”), which became our wholly-owned subsidiary in connection with the restructuring transactions, and Classic Pipeline entered into a gas gathering agreement. Pursuant to the gas gathering agreement, Classic Operating dedicated to Classic Pipeline all of the natural gas produced (up to 50,000 MMBtus per day) on the properties operated by Classic Operating within certain counties in Texas through 2020, subject to one-year extensions at either party’s election. On May 1, 2014, Classic Operating and Classic Pipeline amended the gas gathering agreement with respect to Classic Operating’s remaining assets located in Panola and Shelby Counties, Texas. Under the amended gas gathering agreement, Classic Operating agreed to pay a fee of (i) $0.30 per MMBtu, subject to an annual 3.5% inflationary escalation, based on volumes of natural gas delivered and processed, and (ii) $0.07 per MMBtu per stage of compression plus its allocated share of compressor fuel. The amended gas gathering agreement has a term until December 31, 2023, subject to one-year extensions at either party’s election.

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

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Business Segment Data - Schedule of Calculation of Reportable Segment's Adjusted EBITDA (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Segment Reporting Information [Line Items]
Net income (loss)	$ 112,037	$ 95,962	$ (964,922)	$ 174,300
Interest expense, net	36,345	20,615	104,928	41,994
Income tax expense (benefit)	25,834	1,244	14,398	1,432
DD&A	84,447	45,136	215,906	132,328
Impairment of proved oil and natural gas properties	67,181	21	67,181	21
Accretion of AROs	1,553	1,354	4,601	4,016
(Gain) loss on commodity derivative instruments	(189,492)	2,028	11,580	(29,556)
Exploration costs	175	1,292	1,465	2,265
Adjusted EBITDA	173,455	97,012	447,265	291,285
(Gain) loss on sale of properties	0	(90,063)	3,057	(86,218)
Loss on extinguishment of debt	0		37,248
Operating Segments [Member]
Segment Reporting Information [Line Items]
Net income (loss)	113,092	34,835	(975,186)	123,987
Interest expense, net	36,345	20,615	104,928	41,994
Income tax expense (benefit)	25,834	1,244	14,398	1,432
DD&A	83,478	45,136	213,326	132,328
Impairment of proved oil and natural gas properties	67,181	50,310	67,181	50,310
Accretion of AROs	1,553	1,354	4,601	4,016
(Gain) loss on commodity derivative instruments	(189,492)	2,028	11,580	(29,556)
Cash settlements received (paid) on commodity derivative instruments	4,575	7,046	(19,929)	23,206
Acquisition-related costs	1,425	2,977	5,480	5,073
Compensation expense	29,289	20,306	976,264	21,391
Non-cash compensation expense		(68)		1,057
Exploration costs	175	1,292	1,465	2,265
Provision for environmental remediation			2,852
Non-cash equity (income) loss from MEMP	(86)	12,058	12,844	454
Cash distributions from MEMP	64	6,389	6,068	19,100
Adjusted EBITDA	173,433	115,459	466,177	310,839
(Gain) loss on sale of properties		(90,063)	3,057	(86,218)
Loss on extinguishment of debt			37,248
Operating Segments [Member] | MRD [Member]
Segment Reporting Information [Line Items]
Net income (loss)	9,866	73,874	(930,149)	114,628
Interest expense, net	9,886	9,041	44,355	15,947
Income tax expense (benefit)	25,834	1,147	14,323	1,147
DD&A	39,550	20,476	107,496	62,605
Accretion of AROs	170	178	495	547
(Gain) loss on commodity derivative instruments	(33,090)	213	(17,130)	(8,361)
Cash settlements received (paid) on commodity derivative instruments	3,699	3,368	(4,930)	9,125
Acquisition-related costs	500	667	1,568	1,651
Compensation expense	26,862	19,069	970,877	19,069
Exploration costs	133	439	1,213	1,137
Non-cash equity (income) loss from MEMP	(86)	12,058	12,844	454
Cash distributions from MEMP	64	6,389	6,068	19,100
Adjusted EBITDA	83,388	56,836	247,335	153,679
(Gain) loss on sale of properties	0	(90,083)	3,057	(83,370)
Loss on extinguishment of debt	0		37,248
Operating Segments [Member] | MEMP [Member]
Segment Reporting Information [Line Items]
Net income (loss)	103,226	(39,039)	(45,037)	9,359
Interest expense, net	26,459	11,574	60,573	26,047
Income tax expense (benefit)		97	75	285
DD&A	43,928	24,660	105,830	69,723
Impairment of proved oil and natural gas properties	67,181	50,310	67,181	50,310
Accretion of AROs	1,383	1,176	4,106	3,469
(Gain) loss on commodity derivative instruments	(156,402)	1,815	28,710	(21,195)
Cash settlements received (paid) on commodity derivative instruments	876	3,678	(14,999)	14,081
Acquisition-related costs	925	2,310	3,912	3,422
Compensation expense	2,427	1,237	5,387	2,322
Non-cash compensation expense		(68)		1,057
Exploration costs	42	853	252	1,128
Provision for environmental remediation			2,852
Adjusted EBITDA	90,045	58,623	218,842	157,160
(Gain) loss on sale of properties	0	20	0	(2,848)
Loss on extinguishment of debt	$ 0		$ 0

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Stockholders' Equity and Noncontrolling Interests

9 Months Ended

Sep. 30, 2014

Equity [Abstract]

Stockholders' Equity and Noncontrolling Interests

Note 9.  Stockholders’ Equity and Noncontrolling Interests

Common Stock

The Company's authorized capital stock includes 600,000,000 shares of common stock, $0.01 par value per share. The following is a summary of the changes in our common shares issued for the nine months ended September 30, 2014:

Balance January 1, 2014	—
Shares of common stock issued in connection with restructuring transactions      (Note 1)	171,000,000
Shares of common stock issued sold in initial public offering (Note 1)	21,500,000
Restricted common shares issued (Note 11)	1,068,422
Restricted common shares forfeited	(9,211	)
Balance September 30, 2014	193,559,211

See Note 11 for additional information regarding restricted common shares that were granted in connection with our initial public offering.  Restricted shares of common stock are considered issued and outstanding on the grant date of restricted stock award.

Preferred Stock

Our amended and restated certificate of incorporation authorizes our board of directors (“Board”), subject to any limitations prescribed by law, without further stockholder approval, to establish and to issue from time to time one or more classes or series of preferred stock, par value $0.01 per share, covering up to an aggregate of 50,000,000 shares of preferred stock.  There are no shares issued and outstanding as of September 30, 2014.

Dividend Policy

We do not anticipate declaring or providing any cash dividends to holders of our common stock in the foreseeable future. We currently intend to retain all future earnings, if any, for use in the operation of our business and to fund future growth. The decision whether to pay dividends in the future will be made by our Board in light of conditions then existing, including factors such as our financial condition, earnings, available cash, business opportunities, legal requirements, restrictions in our debt agreements, and other contracts and other factors our Board deems relevant.

Noncontrolling Interests

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

Distributions paid to the limited partners of MEMP primarily represent the quarterly cash distributions paid to MEMP’s unitholders, excluding those paid to MRD LLC.

Contributions received from limited partners of MEMP primarily represent net cash proceeds received from common unit offerings.

On March 25, 2013, MEMP sold 9,775,000 of its common units in an underwritten equity offering, which generated net cash proceeds of $171.8 million after deducting underwriting discounts and offering expenses. The net proceeds from this equity offering partially funded MEMP’s acquisition of all of the outstanding equity interests in WHT.

On July 15, 2014, MEMP sold 9,890,000 common units representing limited partner interests in MEMP (including 1,290,000 common units purchased 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 purchased 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 $321.6 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.

On April 1, 2013, Tanos’ management team sold its 1.066% interest in Tanos to MRD LLC and all incentive units held were forfeited. See Note 12 for further information.

In connection with the our initial public offering, certain former management members of WildHorse Resources contributed their 0.1% membership interest in WildHorse Resources as well as their incentive units in exchange for shares of our common stock and cash consideration of $30.0 million. The difference between the carrying amount of the noncontrolling interest of $0.4 million and the fair value of the consideration paid of $3.3 million was recognized directly in stockholders’ equity as additional paid in capital. See Note 12 for further information.

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Long Term Debt - MRD 5.875% Senior Unsecured Notes Offering - Additional Information (Detail) (5.875% Senior Unsecured Notes ("MRD Senior Notes") [Member], USD $) In Millions, unless otherwise specified	0 Months Ended
	Jul. 10, 2014
Debt Obligations [Line Items]
Senior unsecured notes maturity date	Jul. 01, 2022
Other event of default minimum note holder percentage to accelerate	25.00%
Private Placement of Debt [Member]
Debt Obligations [Line Items]
Aggregate principal amount	$ 600.0
Senior unsecured notes interest rate	5.875%

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Restricted Investments

9 Months Ended

Sep. 30, 2014

Schedule Of Investments [Abstract]

Restricted Investments

Note 7.  Restricted Investments

Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with offshore Southern California oil and gas properties owned by MEMP.  

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

	September 30,		December 31,
	2014		2013
	(In thousands)
BOEM platform abandonment (See Note 15)	$	68,970	$	66,373
BOEM lease bonds		794		794
SPBPC Collateral:
Contractual pipeline and surface facilities abandonment		2,592		2,306
California State Lands Commission pipeline right-of-way bond		3,005		3,005
City of Long Beach pipeline facility permit		500		500
Federal pipeline right-of-way bond		307		307
Port of Long Beach pipeline license		100		100
Restricted investments	$	76,268	$	73,385

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Long Term Debt

9 Months Ended

Sep. 30, 2014

Debt Disclosure [Abstract]

Long Term Debt

Note 8.  Long Term Debt

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

	September 30,			December 31,
	2014			2013
	(In thousands)
MRD Segment:
MRD $2.0 billion revolving credit facility, variable-rate, due June 2019	$	28,000		$	—
WildHorse Resources $1.0 billion revolving credit facility, variable-rate, terminated June 2014		—			203,100
WildHorse Resources $325.0 million second lien term facility, variable-rate, terminated June 2014		—			325,000
10.00%/10.75% senior PIK toggle notes redeemed June 2014 (1)		—			350,000
5.875% senior unsecured notes, due July 2022 (2)		600,000			—
10.00%/10.75% senior PIK toggle notes unamortized discounts		—			(6,950	)
Subtotal		628,000			871,150
MEMP Segment:
MEMP $2.0 billion revolving credit facility, variable-rate, due March 2018		301,000			103,000
7.625% senior notes, fixed-rate, due May 2021 (3)		700,000			700,000
6.875% senior unsecurred notes, due August 2022 (4)		500,000			—
Unamortized discounts		(17,200	)		(10,933	)
Subtotal		1,483,800			792,067
Total long-term debt	$	2,111,800		$	1,663,217

(1)The estimated fair value of this fixed-rate debt was $348.3 million at December 31, 2013.  The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.

(2)The estimated fair value of this fixed-rate debt was $582.0 million September 30, 2014.  The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.

(3)The estimated fair value of this fixed-rate debt was $700.0 million and $721.0 million at September 30, 2014 and December 31, 2013, respectively.  The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.

(4)The estimated fair value of this fixed-rate debt was $475.0 million at September 30, 2014.  The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.

Borrowing Base

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

	September 30,
	2014
MRD Segment:
MRD $2.0 billion revolving credit facility, variable-rate, due June 2019	$	668,500
MEMP Segment:
MEMP $2.0 billion revolving credit facility, variable-rate, due March 2018		1,315,000

Subsequent events. On October 3, 2014, the borrowing base under the MRD revolving credit facility was increased to $725.0 million, and we entered into an amendment to the credit agreement to, among other things, permit us to hedge a larger portion of our anticipated production from our proved reserves. On October 10, 2014, MEMP’s borrowing base under its revolving credit facility was redetermined and increased to $1.44 billion.

MRD Revolving Credit Facility

On June 18, 2014, we, as borrower, and certain of our subsidiaries, as guarantors, entered into a revolving credit facility, which is a five-year, $2.0 billion revolving credit facility with an initial borrowing base of $725.0 million and aggregate elected commitments of $725.0 million.

We are permitted to borrow under the revolving credit facility in an amount up to the least of (i) the face amount of our revolving credit facility, (ii) the borrowing base and (iii) the aggregate elected commitments. The revolving credit facility is reserve-based, and thus our borrowing base is primarily based on the estimated value of our oil, NGL and natural gas properties and our commodity derivative contracts as determined semi-annually by our lenders in their sole discretion. Our borrowing base is subject to redetermination on a semi-annual basis based on an engineering report with respect to our estimated oil, NGL and natural gas reserves, which will take into account the prevailing oil, NGL and natural gas prices at such time, as adjusted for the impact of our commodity derivative contracts. Unanimous approval by the lenders is required for any increase to the borrowing base. In addition, we may, subject to certain conditions, increase our aggregate elected commitments in an amount not to exceed the then effective borrowing base on or following a scheduled redetermination of our borrowing base once before the next scheduled redetermination date.

Borrowings under the revolving credit facility are secured by liens on substantially all of our properties, but in any event, not less than 80% of the total value of our oil and natural gas properties, and all of our equity interests in any future guarantor subsidiaries and all of our other assets including personal property. Additionally, borrowings bear interest, at our option, at either (i) the greatest of (x) the prime rate as determined by the administrative agent, (y) the federal funds effective rate plus 0.50%, and (z) the one-month adjusted LIBOR plus 1.0% (adjusted upwards, if necessary, to the next 1/100th of 1%), in each case, plus a margin that varies from 0.50% to 1.50% per annum according to the total commitment usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect), or (ii) the applicable LIBOR plus a margin that varies from 1.50% to 2.50% per annum according to the total commitment usage. The unused portion of the total commitments is subject to a commitment fee that varies from 0.375% to 0.50% per annum according to our total commitments usage.

The revolving credit facility requires maintenance of a ratio of Consolidated EBITDAX to Consolidated Net Interest Expense (as each term is determined under the revolving credit facility), which we refer to as the interest coverage ratio, of not less than 2.5 to 1.0, and a ratio of consolidated current assets to consolidated current liabilities, each as determined under the revolving credit facility, which we refer to as the current ratio, of not less than 1.0 to 1.0.

Additionally, the revolving credit facility contains various covenants and restrictive provisions that, among other things, limit our ability to incur additional debt, guarantees or liens; consolidate, merge or transfer all or substantially all of our assets; make certain investments, acquisitions or other restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; incur commodity hedges exceeding a certain percentage of our production and prepay certain indebtedness.

Events of default under the revolving credit facility include, but are not limited to, failure to make payments when due, breach of any covenant continuing beyond the applicable cure period, default under any other material debt, change in management or change of control, bankruptcy or other insolvency event and certain material adverse effects on our business.

MRD 5.875% Senior Unsecured Notes Offering

On July 10, 2014, the Company completed a private placement of $600.0 million aggregate principal amount of 5.875% senior unsecured notes (the “MRD Senior Notes”) at par. The MRD Senior Notes will mature on July 1, 2022. Interest on the MRD Senior Notes will accrue from July 10, 2014 and will be payable semiannually on January 1 and July 1 of each year, commencing on January 1, 2015. The MRD Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by certain of our existing subsidiaries. The MRD Senior Notes and the guarantees of the MRD Senior Notes will rank equally with our and the guarantors’ existing and future senior indebtedness, will be effectively junior to all of our and the guarantors’ existing and future secured indebtedness (to the extent of the value of the assets securing such indebtedness), and senior in right of payment to all of our and the guarantors’ subordinated indebtedness. The MRD Senior Notes will be structurally subordinated to the indebtedness and other liabilities of our non-guarantor subsidiaries, including MEMP and its subsidiaries and MEMP GP.

The MRD Senior Notes are governed by an indenture dated as of July 10, 2014.  The MRD Senior Notes are subject to optional redemption at prices specified in the indenture plus accrued and unpaid interest, if any, to the date of redemption. The Company may also be required to repurchase the MRD Senior Notes upon a change of control.  The indenture contains customary covenants and restrictive provisions, many of which will terminate if at any time no default exists under the indenture and the MRD Senior Notes receive an investment grade rating from both of two specified ratings agencies.  MEMP and its subsidiaries are not subject to these covenants. The indenture also provides for customary and other events of default. In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to either the Company or the guarantors, all outstanding MRD Senior Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding MRD Senior Notes may declare all the MRD Senior Notes to be due and payable immediately.

PIK notes

On December 18, 2013, MRD LLC and its wholly-owned subsidiary Memorial Resource Finance Corp. (“MRD Finance Corp.” and, together with MRD LLC, the “MRD Issuers”) completed a private placement of $350.0 million in aggregate principal amount of the PIK notes. The PIK notes were issued at 98% of par with a maturity date of December 15, 2018. Net proceeds from the private offering were used: (i) to repay all indebtedness then outstanding under MRD LLC’s then-existing revolving credit facility, (ii) to establish a cash reserve of $50.0 million for the payment of interest on the PIK notes, (iii) to pay a $210.0 million distribution to the Funds, and (iv) for general company purposes.  Interest on the PIK notes was payable semi-annually in arrears on June 15 and December 15 of each year, commencing on June 15, 2014.

A redemption notice was delivered to the PIK notes trustee on June 16, 2014, which specified a redemption date of July 16, 2014 at a redemption price of 102% of the principal amount of the PIK notes plus accrued and unpaid interest thereon to the date of redemption.  In connection with the closing of our initial public offering, we assumed the obligations of MRD LLC under the PIK notes indenture and the related debt security agreement. We irrevocably deposited with the PIK notes trustee approximately $360.0 million on June 27, 2014, which was an amount sufficient to fund the redemption of the PIK notes on the redemption date and to satisfy and discharge our obligations under the PIK notes and the related indenture.  The discharge became effective upon the irrevocable deposit of the funds with the PIK notes trustee.  An extinguishment loss of $23.6 million was recognized related to the redemption of the PIK notes.

WildHorse Resources Revolving Credit Facility and Second Lien Facility

On April 3, 2013, WildHorse Resources entered into an amended and restated credit agreement. This revolving credit facility provided for aggregate maximum credit amounts at any time of $1.0 billion, consisting of borrowings and letters of credit and had an initial borrowing base of $300.0 million. This revolving credit facility was due to mature on April 13, 2018. The borrowing base was subject to redetermination on at least a semi-annual basis. Borrowings under the revolving credit facility were to be secured by liens on substantially all of WildHorse Resources’ properties, but in any event, not less than 80% of the total value of the WildHorse Resources’ oil and natural gas properties.

On June 13, 2013, WildHorse Resources entered into a $325.0 million second lien term loan agreement that was due to mature on December 13, 2018. Borrowings bore interest, at the borrower’s option, at either: (i) the Alternative Base Rate (as defined within each credit facility) plus 5.25% per annum or (ii) the applicable LIBOR plus 6.25% per annum. Borrowings under the second lien term loan agreement were to be secured by second-priority liens on substantially all of WildHorse Resources’ properties, but in any event, not less than 80% of the total value of the WildHorse Resources’ oil and natural gas properties. The priority of the security interests in the collateral and related creditors’ rights was set forth in an intercreditor agreement. The second lien term loan agreement contained customary affirmative and negative covenants, restrictive provisions and events of default.

On June 13, 2013, WildHorse Resources borrowed $325.0 million under its second lien term loan agreement and used such borrowings to reduce outstanding indebtedness under its revolving credit facility and to pay a onetime special $225.0 million distribution to MRD LLC. This $225.0 million distribution was subsequently distributed to the Funds.

In connection with the closing of our initial public offering, the WildHorse Resources’ revolving credit facility and second lien term loan were repaid in full and terminated. An extinguishment loss of $13.7 million was recognized related to the termination of the revolving credit facility and second lien term loan.

MEMP Revolving Credit Facility & Senior Notes

Memorial Production Operating LLC (“OLLC”), a wholly-owned subsidiary of MEMP, is a party to a $2.0 billion revolving credit facility, which is guaranteed by MEMP and all of its current and future subsidiaries (other than certain immaterial subsidiaries).

Borrowings under the revolving credit facility are secured by liens on substantially all of MEMP’s properties, but in any event, not less than 80% of the total value of MEMP’s oil and natural gas properties, and all of MEMP’s equity interests in OLLC and any future guarantor subsidiaries (other than San Pedro Bay Pipeline Company) and all of MEMP’s other assets including personal property. Additionally, borrowings under the revolving credit facility bear interest, at MEMP’s option, at: (i) the Alternative Base Rate defined as the greatest of (x) the prime rate as determined by the administrative agent, (y) the federal funds effective rate plus 0.50%, and (z) the one-month adjusted LIBOR plus 1.0% (adjusted upwards, if necessary, to the next 1/100th of 1%), in each case, plus a margin that varies from 0.50% to 1.50% per annum according to the borrowing base usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect), (ii) the applicable LIBOR plus a margin that varies from 1.50% to 2.50% per annum according to the borrowing base usage, or (iii) the applicable LIBOR Market Index plus a margin that varies from 1.75% to 2.75% per annum according to the borrowing base usage. The unused portion of the borrowing base (or, if lower, the reduced commitment amount that has been elected) will be subject to a commitment fee that varies from 0.375% to 0.50% per annum according to the borrowing base usage.

On April 17, 2013, May 23, 2013 and October 10, 2013, MEMP and its wholly-owned subsidiary Memorial Production Finance Corporation (“Finance Corp.” and, together with MEMP, the “MEMP Issuers”) completed a private placement of $300.0 million, $100.0 million and $300.0 million, respectively, of their 7.625% senior unsecured notes due 2021 (the “2021 Senior Notes”). The 2021 Senior Notes are fully and unconditionally guaranteed (subject to customary release provisions) on a joint and several basis by all of the MEMP’s subsidiaries (other than Finance Corp., which is co-issuer of the 2021 Senior Notes, and certain immaterial subsidiaries). The 2021 Senior Notes will mature on May 1, 2021 with interest accruing at a rate of 7.625% per annum and payable semi-annually in arrears on May 1 and November 1 of each year. The 2021 Senior Notes are governed by an indenture. The 2021 Senior Notes are subject to optional redemption at prices specified in the indenture plus accrued and unpaid interest, if any. The MEMP Issuers may also be required to repurchase the 2021 Senior Notes upon a change of control. The indenture contains customary covenants and restrictive provisions, many of which will terminate if at any time no default exists under the indenture and the 2021 Senior Notes receive an investment grade rating from both of two specified ratings agencies. The indenture also provides for customary and other events of default. In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to either of the MEMP Issuers, all outstanding 2021 Senior Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding 2021 Senior Notes may declare all the 2021 Senior Notes to be due and payable immediately.

On July 17, 2014, the MEMP Issuers completed a private placement of $500.0 million aggregate principal amount of 6.875% senior unsecured notes (the “2022 Senior Notes”).  The 2022 Senior Notes were issued at 98.485% of par and are fully and unconditionally guaranteed (subject to customary release provisions on a joint and several basis by all of MEMP’s subsidiaries other than Finance Corp., which is co-issuer of the 2022 Senior Notes, and certain immaterial subsidiaries). The 2022 Senior Notes will mature on August 1, 2022 with interest accruing at 6.875% per annum and payable semi-annually in arrears on February 1 and August 1of each year, commencing on February 1, 2015. The indenture governing the 2022 Notes, dated as July 17, 2014, contains customary covenants and restrictive provisions, many of which will terminate if at any time no default exists under the indenture and the 2022 Senior Notes receive an investment grade rating from both of two specified ratings agencies.  The indenture also provides for customary and other events of default. In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to either of the MEMP Issuers, all outstanding 2022 Senior Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding 2022 Senior Notes may declare all the 2022 Senior Notes to be due and payable immediately. The net proceeds from the notes offering of approximately $484.9 million, after deducting the initial purchasers’ discounts and commissions but before estimated offering expenses, were used to repay a portion of the outstanding borrowings under MEMP’s revolving credit facility and for general partnership purposes.  

Weighted-Average Interest Rates

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

	For the Three Months						For the Nine Months
Credit Facility	Ended September 30,						Ended September 30,
	2014			2013			2014			2013
MRD Segment:
MRD revolving credit facility		3.31	%	n/a				2.40	%	n/a
MRD LLC revolver terminated December 2013	n/a				2.34	%	n/a				3.20	%
WildHorse Resources revolver terminated June 2014	n/a				4.51	%		4.04	%		3.44	%
WildHorse Resources second lien terminated June 2014	n/a				6.50	%		6.44	%		6.50	%
Black Diamond terminated November 2013	n/a			n/a			n/a				3.34	%
MEMP Segment:
MEMP revolving credit facility		2.16	%		2.13	%		2.08	%		2.55	%
WHT revolver terminated March 2013	n/a			n/a			n/a				2.29	%
Tanos revolver terminated April 2013	n/a			n/a			n/a				2.12	%
Stanolind revolver paid off by MEMP October 2013	n/a				3.44	%	n/a				3.52	%
Boaz revolver terminated October 2013	n/a				2.65	%	n/a				2.97	%
Crown revolver terminated October 2013	n/a				3.31	%	n/a				3.38	%
Propel Energy revolver paid off by MEMP October 2013	n/a				3.09	%	n/a				3.08	%

Unamortized Deferred Financing Costs

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

	September 30,		December 31,
	2014		2013
	(In thousands)
MRD Segment:
MRD revolving credit facility	$	4,433	$	—
MRD senior notes		12,825		—
WildHorse Resources revolving credit facility		—		2,436
WildHorse Resources second lien term loan		—		9,030
PIK notes		—		8,261
MEMP Segment:
MEMP revolving credit facility		6,882		5,413
2021 Senior Notes		13,836		15,053
2022 Senior Notes		8,222		—
	$	46,198	$	40,193

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Earnings per Share

9 Months Ended

Sep. 30, 2014

Earnings Per Share [Abstract]

Earnings per Share

Note 10.  Earnings per Share

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

	For the Three		For the Nine
	Months Ended		Months Ended
	September 30,		September 30,
	2014		2014
Numerator:
Net income (loss) available to common stockholders	$	9,928	$	(951,801	)
Denominator:
Weighted average common shares outstanding		192,500		192,500
Restricted common shares (1)		216		—
Weighted average common and common equivalent shares    outstanding		192,716		192,500
Basic EPS	$	0.05	$	(4.94	)
Diluted EPS	$	0.05	$	(4.94	)

(1)The treasury stock method is applied to determine the dilutive effect of the unvested restricted common shares. The restricted common shares were antidilutive due to net losses and excluded from the diluted EPS calculation for the nine months ending September 30, 2014. There were 206,956 incremental shares excluded from the computation of diluted EPS for the nine months ending September 30, 2014.

Our supplemental basic and diluted EPS includes earnings allocated to both previous owners and MRD LLC members for all periods presented due to common control considerations.  The following sets forth the calculation of our supplemental EPS, for the periods indicated (in thousands, except per share amounts):

	For the Three		For the Nine
	Months Ended		Months Ended
	September 30,		September 30,
	2014		2014
Numerator:
Net income (loss) attributable to Memorial Resource Development Corp.	$	9,928	$	(930,071	)
Denominator:
Weighted average common shares outstanding		192,500		192,500
Restricted common shares (1)		216		—
Weighted average common and common equivalent shares outstanding		192,716		192,500
Basic EPS	$	0.05	$	(4.83	)
Diluted EPS	$	0.05	$	(4.83	)

(1)The treasury stock method is applied to determine the dilutive effect of the unvested restricted common shares. The restricted common shares were antidilutive due to net losses and excluded from the diluted EPS calculation for the nine months ending September 30, 2014. There were 206,956 incremental shares excluded from the computation of diluted EPS for the nine months ending September 30, 2014.

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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, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
MRD LLC [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates		2.34%		3.20%
WildHorse Resources, LLC [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates		4.51%	4.04%	3.44%
WildHorse Resources second lien [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates		6.50%	6.44%	6.50%
Black Diamond [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates				3.34%
MRD [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates	3.31%		2.40%
MEMP [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates	2.16%	2.13%	2.08%	2.55%
MEMP [Member] | Wht [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates				2.29%
MEMP [Member] | Tanos Energy LLC [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates				2.12%
MEMP [Member] | Stanolind [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates		3.44%		3.52%
MEMP [Member] | Boaz [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates		2.65%		2.97%
MEMP [Member] | Crown [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates		3.31%		3.38%
MEMP [Member] | Propel [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates		3.09%		3.08%

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Business Segment Data - Reconciliation of Total Reportable Segment's Adjusted EBITDA to Net Income (Loss) (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Segment Reporting Revenue Reconciling Item [Line Items]
Adjusted EBITDA	$ 173,455	$ 97,012	$ 447,265	$ 291,285
Adjustments to reconcile Adjusted EBITDA to net income (loss):
Interest expense, net	(36,345)	(20,615)	(104,928)	(41,994)
Loss on extinguishment of debt	0		(37,248)
Income tax benefit (expense)	(25,834)	(1,244)	(14,398)	(1,432)
DD&A	(84,447)	(45,136)	(215,906)	(132,328)
Impairment of proved oil and natural gas properties	(67,181)	(21)	(67,181)	(21)
Accretion of AROs	(1,553)	(1,354)	(4,601)	(4,016)
Gains (losses) on commodity derivative instruments	189,492	(2,028)	(11,580)	29,556
Gain (loss) on sale of properties	0	90,063	(3,057)	86,218
Exploration costs	(175)	(1,292)	(1,465)	(2,265)
Net income (loss)	112,037	95,962	(964,922)	174,300
Reportable Segments [Member]
Segment Reporting Revenue Reconciling Item [Line Items]
Adjusted EBITDA	173,433	115,459	466,177	310,839
Adjustments to reconcile Adjusted EBITDA to net income (loss):
Interest expense, net	(36,345)	(20,615)	(104,928)	(41,994)
Loss on extinguishment of debt	0	0	(37,248)	0
Income tax benefit (expense)	(25,834)	(1,244)	(14,398)	(1,432)
DD&A	(84,447)	(45,136)	(215,906)	(132,328)
Impairment of proved oil and natural gas properties	(67,181)	(21)	(67,181)	(21)
Accretion of AROs	(1,553)	(1,354)	(4,601)	(4,016)
Gains (losses) on commodity derivative instruments	189,492	(2,028)	(11,580)	29,556
Cash settlements paid (received) on commodity derivative instruments	(4,575)	(7,046)	19,929	(23,206)
Gain (loss) on sale of properties	0	90,063	(3,057)	86,218
Acquisition related costs	(1,425)	(2,977)	(5,480)	(5,073)
Incentive-based compensation expense	(29,289)	(20,306)	(976,264)	(21,391)
Non-cash compensation expense		68		(1,057)
Exploration costs	(175)	(1,292)	(1,465)	(2,265)
Provision for environmental remediation			(2,852)
Cash distributions from MEMP	(64)	(6,389)	(6,068)	(19,100)
Other non-cash equity (income) loss		(1,220)		(430)
Net income (loss)	$ 112,037	$ 95,962	$ (964,922)	$ 174,300

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Stockholders' Equity and Noncontrolling Interests - Additional Information (Detail) (USD $)	9 Months Ended				0 Months Ended	9 Months Ended		0 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Jun. 18, 2014	Dec. 31, 2013	Apr. 01, 2013 Tanos Energy LLC [Member]	Sep. 30, 2014 WildHorse Resources, LLC [Member]	Jun. 18, 2014 WildHorse Resources, LLC [Member]	Sep. 09, 2014 Common Stock [Member] MEMP [Member]	Jul. 15, 2014 Common Stock [Member] MEMP [Member]	Mar. 25, 2013 Common Stock [Member] MEMP [Member]
Stockholders Equity Note Disclosure [Line Items]
Common stock, shares authorized	600,000,000			0
Common stock, par value	$ 0.01
Preferred stock, par value	$ 0.01
Preferred stock, shares authorized	50,000,000
Preferred stock, shares issued	0
Preferred stock, shares outstanding	0
Number of common units sold by subsidiary								14,950,000	9,890,000	9,775,000
Net proceeds from sale of common units by subsidiary								$ 321,600,000	$ 220,000,000	$ 171,800,000
Number of over-allotment common units issued by Partnership								1,950,000	1,290,000
Public offering price per common unit			$ 19.00					$ 22.29	$ 22.25
Percentage of ownership interest sold to company					1.066%
Percentage of interest contributed former management members							0.10%
Cash consideration paid to certain former management members							30,000,000
Noncontrolling interests	1,022,721,000			580,615,000			400,000
Fair value consideration paid	$ 3,292,000	$ 1,270,000				$ 3,300,000

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Long Term Debt - MEMP Revolving Credit Facility and Senior Notes - Additional Information (Detail) (USD $)	9 Months Ended			0 Months Ended	9 Months Ended				9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014 7.625 % Senior Notes Due May 2021 [Member]	Jul. 17, 2014 MEMP [Member] 6.875% Senior Unsecured Notes ("2022 Senior Notes") [Member]	Sep. 30, 2014 MEMP [Member] 6.875% Senior Unsecured Notes ("2022 Senior Notes") [Member]	Sep. 30, 2014 MEMP [Member] 7.625 % Senior Notes Due May 2021 [Member]	Dec. 31, 2013 MEMP [Member] 7.625 % Senior Notes Due May 2021 [Member]	Sep. 30, 2014 Revolving Credit Facility [Member]	Sep. 30, 2014 Revolving Credit Facility [Member] M E M P Optional Base Rate Federal Funds Effective Rate	Sep. 30, 2014 Revolving Credit Facility [Member] M E M P Optional Base Rate Adjusted London Interbank Offered Rate	Sep. 30, 2014 Revolving Credit Facility [Member] Minimum [Member]	Sep. 30, 2014 Revolving Credit Facility [Member] Minimum [Member] Alternative Base Rate Range 1 [Member]	Sep. 30, 2014 Revolving Credit Facility [Member] Minimum [Member] London Interbank Offered Rate (LIBOR) Range 2 [Member]	Sep. 30, 2014 Revolving Credit Facility [Member] Minimum [Member] LIBOR Market Index Plus [Member] Range 3 [Member]	Sep. 30, 2014 Revolving Credit Facility [Member] Maximum [Member]	Sep. 30, 2014 Revolving Credit Facility [Member] Maximum [Member] Alternative Base Rate Range 1 [Member]	Sep. 30, 2014 Revolving Credit Facility [Member] Maximum [Member] London Interbank Offered Rate (LIBOR) Range 2 [Member]	Sep. 30, 2014 Revolving Credit Facility [Member] Maximum [Member] LIBOR Market Index Plus [Member] Range 3 [Member]	Oct. 10, 2013 Private Placement of Debt [Member] 7.625 % Senior Notes Due May 2021 [Member]	May 23, 2013 Private Placement of Debt [Member] 7.625 % Senior Notes Due May 2021 [Member]	Apr. 17, 2013 Private Placement of Debt [Member] 7.625 % Senior Notes Due May 2021 [Member]	Jul. 17, 2014 Private Placement of Debt [Member] MEMP [Member] 6.875% Senior Unsecured Notes ("2022 Senior Notes") [Member]
Debt Obligations [Line Items]
Initial borrowing base of second lien term facility								$ 2,000,000,000
Lien percentage of assets for credit facility									80.00%
Line of credit, additional margin rate									0.50%	1.00%		0.50%	1.50%	1.75%		1.50%	2.50%	2.75%
Line of credit, adjusted description									The one-month adjusted LIBOR plus 1.0% (adjusted upwards, if necessary, to the next 1/100th of 1%)
Percentage of revolving unused commitment fee											0.375%				0.50%
Aggregate principal amount																			300,000,000	100,000,000	300,000,000	500,000,000
Senior unsecured notes interest rate			7.625%			7.625%	7.625%															6.875%
Other event of default minimum note holder percentage to accelerate			25.00%	25.00%
Senior unsecured notes maturity date			May 01, 2021	Aug. 01, 2022		May 31, 2021
Net proceeds from notes offering	$ 1,092,425,000	$ 397,563,000			$ 484,900,000
Note issued at percentage of par				98.485%

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Subsequent Events - Additional Information (Detail) (Subsequent Event, USD $) In Millions, unless otherwise specified	0 Months Ended
	Oct. 01, 2014 well	Nov. 04, 2014 acre
Subsequent Event [Line Items]
Non operating properties acquired percentage	100.00%
Number of wells, Gross	74
Underlying acreage associated with overriding royalty interests		27,000
Percentage of revenue from royalty interests		7.00%
M E M P
Subsequent Event [Line Items]
Purchase price	$ 15.0

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Incentive Units (Tables)

9 Months Ended

Sep. 30, 2014

Compensation Related Costs [Abstract]

Fair Value of Incentive Units Estimated

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

	Exchanged Incentive Units			Subsequent Incentive Units
Valuation date	9/30/2014			9/30/2014
Dividend yield		0	%		0	%
Expected volatility		21.47	%		21.47	%
Risk-free rate		0.90	%		0.90	%
Expected life (years)		2.67			2.67

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Risk Management and Derivative Instruments - Schedule of Gains and Losses Related to Derivative Instruments (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Gain (Loss) on Derivative Instruments, Net, Pretax [Abstract]
(Gain) loss on commodity derivatives	$ (189,492)	$ 2,028	$ 11,580	$ (29,556)
Interest expense, net	36,345	20,615	104,928	41,994
Commodity contracts [Member]
Gain (Loss) on Derivative Instruments, Net, Pretax [Abstract]
(Gain) loss on commodity derivatives	(189,492)	2,028	11,580	(29,556)
Interest rate derivatives [Member]
Gain (Loss) on Derivative Instruments, Net, Pretax [Abstract]
Interest expense, net	$ (175)	$ 1,926	$ 1,157	$ 69

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Commitments and Contingencies

9 Months Ended

Sep. 30, 2014

Commitments And Contingencies Disclosure [Abstract]

Commitments and Contingencies

Note 15.  Commitments and Contingencies

Litigation & Environmental

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

At September 30, 2014 and December 31, 2013, we had $2.3 million and $0.6 million of environmental reserves recorded on our balance sheets, respectively.  During the nine months ended September 30, 2014, MEMP recorded $2.9 million of estimated environmental remediation expenses associated with its Permian and Wyoming oil and gas properties.  These expenses are reflected as a component of lease operating expenses on our statement of operations.  Environmental costs for remediation are accrued when environmental remediation efforts are probable and the costs can be reasonably estimated.  Such accruals are based on management’s best estimate of the ultimate cost to remediate a site and are adjusted as further information and circumstances develop.  Those estimates may change substantially depending on information about the nature and extent of contamination, appropriate remediation technologies and regulatory approvals.

Supplemental Bond for Decommissioning Liabilities Trust Agreement

The trust account is held by Rise Energy Operating, LLC (“REO”), a wholly-owned subsidiary of MEMP, 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, 2014 (in thousands):

	Amortized
Investment	Cost
U.S. Bank Money Market Cash Equivalent	$	133,275
Less: Outside working interest owners share		(64,305	)
	$	68,970

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

June 30, 2015	$	72,450
June 30, 2016	$	76,590
December 31, 2016	$	78,660

As of September 30, 2014, the maximum remaining obligation net to REO’s interest was approximately $9.7 million.

Purchase Commitment Assumed

At September 30, 2014, MEMP had a CO₂ purchase commitment with a third party that was assumed in its Wyoming Acquisition. The table below outlines MEMP’s purchase commitment under the contract for the remainder of 2014 and annually thereafter (in thousands):

			Payment or Settlement due by Period
Purchase commitment	Total		Remainder 2014		2015		2016		2017		2018		Thereafter
CO2 minimum purchase commitment:
Estimated payment obligation	$	62,103	$	3,203	$	12,222	$	12,101	$	11,624	$	7,872	$	15,081

Processing Plant Expansions by Third Party Gatherer

In 2012, WildHorse Resources contracted with Regency Field Services LLC (the “Gatherer”) to expand their Dubach processing plant by up to 70 MMcf per day among other facility and infrastructure improvements. The expansion project was complete and fully operational by July 2013. WildHorse Resources will pay a payback demand fee until the payback demand fees received by the Gatherer plus any third party fees equal 110% of the new facility cost. For each month from the commencement date through the month in which the payout date occurs, WildHorse Resources will pay a payback demand fee equal to the monthly demand quantity (136,200 MMBtu per day) times $0.26 per MMBtu. In addition, for each MMBtu gathered in excess of the demand quantity, WildHorse Resources will pay a payback demand fee of $0.26 per MMBtu. The contract with the Gatherer for the Dubach processing plant was amended effective February 1, 2014 where the payback demand fee for the Dubach processing plant increased from $0.26 to $0.275 cents per MMbtu.

In 2013, WildHorse Resources contracted with the Gatherer to build a new high pressure pipeline from the dedicated area to the Gatherer’s Dubberly processing plant in Webster Parish, LA amongst other pipeline and infrastructure improvements. The expansion project was complete and fully operational by mid-December 2013. WildHorse Resources will pay a payback demand fee until the payback demand fees received by the Gatherer plus any third party fees equal to 110% of the pipeline and infrastructure improvement costs. For each month from the commencement date through the month in which the payout date occurs, WildHorse Resources will pay a payback demand fee equal to the monthly demand fee times $0.31 per MMBtu. In addition, for each MMBtu gathered in excess of the demand quantity, WildHorse Resources will pay a payback demand fee of $0.31 per MMBtu. The monthly demand quantity is 56,750 MMBtu per day from the Dubberly start-up date through one full year thereafter and then increasing to 113,500 MMBtu per day until payout. The contract with the Gatherer for the new high pressure pipeline was amended effective February 1, 2014 where the payback demand fee decreased from $0.31 to $0.275 cents per MMbtu.

WildHorse Resources’ minimum commitments to the Gatherer, before other owner contributions, as of September 30, 2014 were as follows (in thousands):

	Dubach		Dubberly
2014	$	3,446	$	1,436
2015		13,671		11,393
2016		13,709		11,424
2017		13,671		11,393
2018		12,772		10,643
Total	$	57,269	$	46,289

Related Party Agreements

On March 17, 2014, WildHorse Resources entered into a gas processing agreement with PennTex. See Note 13 for additional information.

Classic Operating entered into a gas gathering agreement and water disposal agreement with Classic Pipeline. See Note 13 for additional information.

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Fair Value Measurements of Financial Instruments (Tables)

9 Months Ended

Sep. 30, 2014

Fair Value Disclosures [Abstract]

Assets and Liabilities Measured at Fair Value on Recurring Basis

The following table presents the gross derivative assets and liabilities that are measured at fair value on a recurring basis at September 30, 2014 and December 31, 2013 for each of the fair value hierarchy levels:

	Fair Value Measurements at September 30, 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	$	—	$	129,711	$	—	$	129,711
Interest rate derivatives		—		95		—		95
Total assets	$	—	$	129,806	$	—	$	129,806
Liabilities:
Commodity derivatives	$	—	$	74,542	$	—	$	74,542
Interest rate derivatives		—		3,712		—		3,712
Total liabilities	$	—	$	78,254	$	—	$	78,254

	Fair Value Measurements at December 31, 2013 Using
	Quoted Prices in		Significant Other		Significant
	Active		Observable		Unobservable
	Market		Inputs		Inputs
	(Level 1)		(Level 2)		(Level 3)		Fair Value
	(In thousands)
Assets:
Commodity derivatives	$	—	$	105,054	$	—	$	105,054
Interest rate derivatives		—		884		—		884
Total assets	$	—	$	105,938	$	—	$	105,938
Liabilities:
Commodity derivatives	$	—	$	58,234	$	—	$	58,234
Interest rate derivatives		—		5,590		—		5,590
Total liabilities	$	—	$	63,824	$	—	$	63,824

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Risk Management and Derivative Instruments - Schedule of Entity's Interest Rate Swap Open Positions (Detail) (Interest rate swaps [Member], MEMP [Member], USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2014
Remaining 2014 [Member]
Derivative [Line Items]
Average Monthly Notional	$ 248,333
Weighted-average fixed rate	1.299%
Floating rate	1 Month LIBOR
2015 [Member]
Derivative [Line Items]
Average Monthly Notional	280,833
Weighted-average fixed rate	1.416%
Floating rate	1 Month LIBOR
2016 [Member]
Derivative [Line Items]
Average Monthly Notional	$ 150,000
Weighted-average fixed rate	1.193%
Floating rate	1 Month LIBOR

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Acquisitions and Divestitures - Acquisition Related Costs (Detail) (General and Administrative Expense [Member], USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
General and Administrative Expense [Member]
Business Acquisition [Line Items]
Acquisition-related costs	$ 1,425	$ 2,977	$ 5,480	$ 5,073

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UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED AND COMBINED CASH FLOWS (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013
Cash flows from operating activities:
Net income (loss)	$ (964,922)	$ 174,300
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization	215,906	132,328
Impairment of proved oil and natural gas properties	67,181	21
(Gain) loss on derivatives	12,737	(29,487)
Cash settlements (paid) received on derivative instruments	(22,174)	21,356
Loss on extinguishment of debt	30,248
Amortization of deferred financing costs	5,492	6,193
Accretion of senior notes net discount	1,888	161
Accretion of asset retirement obligations	4,601	4,016
Amortization of equity awards	6,874	2,322
(Gain) loss on sale of properties	3,057	(86,218)
Non-cash compensation expense	941,659	1,057
Exploration costs	868
Deferred income tax expense (benefit)	13,916
Changes in operating assets and liabilities:
Accounts receivable	(22,117)	560
Prepaid expenses and other assets	297	(2,562)
Payables and accrued liabilities	67,324	13,034
Other	2,625	95
Net cash provided by operating activities	365,460	237,176
Cash flows from investing activities:
Acquisitions of oil and natural gas properties	(1,083,167)	(104,926)
Additions to oil and gas properties	(457,838)	(257,513)
Additions to other property and equipment	(9,134)	(1,184)
Additions to restricted investments	(2,883)	(4,263)
Deposits for property acquisitions		(25,310)
Decrease (increase) in restricted cash	49,946	653
Proceeds from the sale of oil and natural gas properties	6,700	156,799
Other	(301)	(139)
Net cash used in investing activities	(1,496,677)	(235,883)
Cash flows from financing activities:
Advances on revolving credit facilities	2,464,800	478,055
Payments on revolving credit facilities	(2,441,900)	(900,368)
Borrowings under second lien credit facility		325,000
Redemption of second lien credit facility	(328,282)
Proceeds from the issuances of senior notes	1,092,425	397,563
Redemption of senior notes	(351,808)
Deferred financing costs	(30,284)	(23,839)
Purchase of additional interests in consolidated subsidiaries	(3,292)	(1,270)
Contributions from previous owners		1,214
Distributions to the Funds		(363,437)
Distributions to noncontrolling interests	(101,327)	(51,319)
Distributions made by previous owners		(3,130)
Other	213
Net cash provided by financing activities	1,063,812	32,261
Net change in cash and cash equivalents	(67,405)	33,554
Cash and cash equivalents, beginning of period	77,721	49,391
Cash and cash equivalents, end of period	10,316	82,945
Supplemental cash flows:
Cash paid for interest	67,449	22,959
Noncash investing and financing activities:
Change in capital expenditures in payables and accrued liabilities	29,137	25,017
Assumptions of asset retirement obligations related to properties acquired or drilled	5,053	3,478
Accounts receivable related to acquisitions and divestitures	4,271
MRD [Member]
Cash flows from financing activities:
Proceeds from public offering	408,500
Costs incurred in conjunction with public offering	(28,198)
MEMP [Member]
Cash flows from financing activities:
Costs incurred in conjunction with public offering	(12,222)	(7,592)
Proceeds from public offering	553,288	179,371
Natural Gas Partners [Member]
Cash flows from financing activities:
Contributions from NGP affiliates related to sale of properties	1,165	2,013
Distribution to NGP affiliates related to purchase of assets	(66,693)
Distribution to NGP affiliates related to sale of assets, net of cash received	(32,770)
MRD Holdco LLC [Member]
Cash flows from financing activities:
Distributions to MRD Holdco	$ (59,803)

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Commitments and Contingencies - Gross Held-to-Maturity Investments (Detail) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014
Held-to-maturity Securities [Abstract]
Amortized Cost	$ 68,970
Less: Outside working interest owners share	(64,305)
Money Market Funds [Member]
Held-to-maturity Securities [Abstract]
Amortized Cost	$ 133,275

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Fair Value Measurements of Financial Instruments

9 Months Ended

Sep. 30, 2014

Fair Value Disclosures [Abstract]

Fair Value Measurements of Financial Instruments

Note 4.  Fair Value Measurements of Financial Instruments

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

The carrying values of accounts receivables, accounts payables (including accrued liabilities) and amounts outstanding under long-term debt agreements with variable rates included in the accompanying balance sheets approximated fair value at September 30, 2014 and December 31, 2013. The fair value estimates are based upon observable market data and are classified within Level 2 of the fair value hierarchy.  These assets and liabilities are not presented in the following tables.  See Note 8 for the estimated fair value of our outstanding fixed-rate debt.

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, 2014 and December 31, 2013 were based on estimated forward commodity prices and forward interest rate yield curves. 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, 2014 and December 31, 2013 for each of the fair value hierarchy levels:

	Fair Value Measurements at September 30, 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	$	—	$	129,711	$	—	$	129,711
Interest rate derivatives		—		95		—		95
Total assets	$	—	$	129,806	$	—	$	129,806
Liabilities:
Commodity derivatives	$	—	$	74,542	$	—	$	74,542
Interest rate derivatives		—		3,712		—		3,712
Total liabilities	$	—	$	78,254	$	—	$	78,254

	Fair Value Measurements at December 31, 2013 Using
	Quoted Prices in		Significant Other		Significant
	Active		Observable		Unobservable
	Market		Inputs		Inputs
	(Level 1)		(Level 2)		(Level 3)		Fair Value
	(In thousands)
Assets:
Commodity derivatives	$	—	$	105,054	$	—	$	105,054
Interest rate derivatives		—		884		—		884
Total assets	$	—	$	105,938	$	—	$	105,938
Liabilities:
Commodity derivatives	$	—	$	58,234	$	—	$	58,234
Interest rate derivatives		—		5,590		—		5,590
Total liabilities	$	—	$	63,824	$	—	$	63,824

See Note 5 for additional information regarding our derivative instruments.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

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

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

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

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

· During the three and nine months ending September 30, 2014, we recognized $67.2 million of impairments primarily related to certain MEMP properties located in South Texas. The estimated future cash flows expected for 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. We recognized impairment charges of less than $0.1 million on a consolidated basis for the three and nine months ending September 30, 2013, respectively.

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Long Term Debt - Borrowing Base - Additional Information (Detail) (Revolving Credit Facility [Member], USD $) In Thousands, unless otherwise specified	Jun. 18, 2014 MRD [Member]	Oct. 10, 2014 Subsequent Event M E M P	Oct. 03, 2014 Subsequent Event MRD [Member]
Debt Obligations [Line Items]
Borrowing base	$ 725,000	$ 1,440,000	$ 725,000

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Business Segment Data - Summary of Selected Business Segment Information (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013
Segment Reporting Information [Line Items]
Total revenues	$ 245,493	$ 153,515	$ 672,885	$ 422,741
Adjusted EBITDA	173,455	97,012	447,265	291,285
Segment assets	4,021,667		4,021,667		2,829,161
Total cash expenditures for additions to long-lived assets			(1,550,139)	(363,623)
Operating Segments [Member]
Segment Reporting Information [Line Items]
Adjusted EBITDA	173,433	115,459	466,177	310,839
Other, Adjustments & Eliminations [Member]
Segment Reporting Information [Line Items]
Total revenues	(92)	(19)	(137)	(136)
Adjusted EBITDA	22	(18,447)	(18,912)	(19,554)
Segment assets	40,069		40,069		(4,280)
MRD [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	98,342	60,294	301,492	171,361
Adjusted EBITDA	83,388	56,836	247,335	153,679
Segment assets	1,232,146		1,232,146		1,281,134
Total cash expenditures for additions to long-lived assets			(276,982)	(198,220)
MEMP [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total revenues	147,243	93,240	371,530	251,516
Adjusted EBITDA	90,045	58,623	218,842	157,160
Segment assets	2,749,452		2,749,452		1,552,307
Total cash expenditures for additions to long-lived assets			$ (1,273,157)	$ (165,403)

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Earnings per Share - Summary of Calculation of Earnings (Loss) Per Share (Parenthetical) (Detail) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2014
Earnings Per Share [Abstract]
Shares excluded from computation of EPS	206,956

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Risk Management and Derivative Instruments (Tables)

9 Months Ended

Sep. 30, 2014

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Schedule of Open Commodity Positions

At September 30, 2014, the MRD Segment had the following open commodity positions:

	Remaining
	2014			2015			2016			2017			2018
Natural Gas Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (MMBtu)		4,540,000			2,250,000			1,670,000			1,270,000			1,500,000
Weighted-average fixed price	$	4.18		$	4.08		$	4.18		$	4.30		$	4.30
Collar contracts:
Average Monthly Volume (MMBtu)		730,000			1,580,000			1,100,000			1,050,000			—
Weighted-average floor price	$	4.11		$	4.14		$	4.00		$	4.00		$	—
Weighted-average ceiling price	$	5.15		$	4.61		$	4.71		$	5.06		$	—
TGT Z1 basis swaps:
Average Monthly Volume (MMBtu)		2,270,000			1,730,000			220,000			200,000			—
Spread	$	(0.08	)	$	(0.09	)	$	(0.08	)	$	(0.08	)	$	—
Crude Oil Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		56,000			33,500			—			9,500			7,625
Weighted-average fixed price	$	94.43		$	93.86		$	—		$	87.62		$	87.00
Collar contracts:
Average Monthly Volume (Bbls)		12,000			2,000			27,000			—			—
Weighted-average floor price	$	86.67		$	85.00		$	80.00		$	—		$	—
Weighted-average ceiling price	$	112.33		$	101.35		$	99.70		$	—		$	—
Put option contracts:
Average Monthly Volume (Bbls)		—			26,000			—			—			—
Weighted-average fixed price	$	—		$	85.00		$	—		$	—		$	—
Weighted-average deferred premium	$	—		$	(3.80	)	$	—		$	—		$	—
NGL Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		184,000			151,000			148,500			—			—
Weighted-average fixed price	$	44.84		$	41.61		$	39.75		$	—		$	—

At September 30, 2014, the MEMP Segment had the following open commodity positions:

	Remaining
	2014			2015			2016			2017			2018		2019
Natural Gas Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (MMBtu)		2,580,200			2,605,278			2,692,442			2,450,067			2,160,000		1,914,583
Weighted-average fixed price	$	4.34		$	4.28		$	4.40		$	4.31		$	4.51	$	4.75
Collar contracts:
Average Monthly Volume (MMBtu)		340,000			350,000			—			—			—		—
Weighted-average floor price	$	5.00		$	4.62		$	—		$	—		$	—	$	—
Weighted-average ceiling price	$	6.31		$	5.80		$	—		$	—		$	—	$	—
Call spreads (1):
Average Monthly Volume (MMBtu)		120,000			80,000			—			—			—		—
Weighted-average sold strike price	$	5.17		$	5.25		$	—		$	—		$	—	$	—
Weighted-average bought strike price	$	6.53		$	6.75		$	—		$	—		$	—	$	—
Basis swaps:
Average Monthly Volume (MMBtu)		2,830,000			2,940,000			1,635,000			300,000			—		—
Spread	$	(0.09	)	$	(0.12	)	$	(0.06	)	$	(0.05	)	$	—	$	—
Crude Oil Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		283,452			314,281			332,813			326,600			312,000		160,000
Weighted-average fixed price	$	95.83		$	90.96		$	85.83		$	84.38		$	83.74	$	85.52
Collar contracts:
Average Monthly Volume (Bbls)		23,000			5,000			—			—			—		—
Weighted-average floor price	$	82.83		$	80.00		$	—		$	—		$	—	$	—
Weighted-average ceiling price	$	105.31		$	94.00		$	—		$	—		$	—	$	—
Basis swaps:
Average Monthly Volume (Bbls)		134,000			97,500			—			—			—		—
Spread	$	(4.32	)	$	(7.07	)	$	—		$	—		$	—	$	—
NGL Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		167,500			149,200			55,000			—			—		—
Weighted-average fixed price	$	43.13		$	43.02		$	39.28		$	—		$	—	$	—

·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
	2014			2015			2016			2017
Natural Gas Derivative Contracts:
NGPL TexOk basis swaps:
Average Monthly Volume (MMBtu)		2,260,000			2,280,000			1,500,000			300,000
Spread	$	(0.09	)	$	(0.11	)	$	(0.07	)	$	(0.05	)
NGPL STX basis swaps:
Average Monthly Volume (MMBtu)		380,000			—			—			—
Spread	$	(0.11	)	$	—		$	—		$	—
HSC basis swaps:
Average Monthly Volume (MMBtu)		190,000			150,000			135,000			—
Spread	$	(0.07	)	$	(0.08	)	$	0.07		$	—
CIG basis swaps:
Average Monthly Volume (MMBtu)		—			210,000			—			—
Spread	$	—		$	(0.25	)	$	—		$	—
TETCO STX basis swaps:
Average Monthly Volume (MMBtu)		—			300,000			—			—
Spread	$	—		$	(0.09	)	$	—		$	—
Crude Oil Derivative Contracts:
Midway-Sunset basis swaps:
Average Monthly Volume (Bbls)		60,000			57,500			—			—
Spread - Brent	$	(9.25	)	$	(9.73	)	$	—		$	—
Midland basis swaps:
Average Monthly Volume (Bbls)		40,000			40,000			—			—
Spread - WTI	$	(3.68	)	$	(3.25	)	$	—		$	—
LLS Crude basis swaps:
Average Monthly Volume (Bbls)		34,000			—			—			—
Spread - WTI	$	3.61		$	—		$	—		$	—

Schedule of Entity's Interest Rate Swap Open Positions

At September 30, 2014, we had the following interest rate swap open positions:

	Remaining
Credit Facility	2014			2015			2016
MEMP:
Average Monthly Notional (in thousands)	$	248,333		$	280,833		$	150,000
Weighted-average fixed rate		1.299	%		1.416	%		1.193	%
Floating rate	1 Month LIBOR			1 Month LIBOR			1 Month LIBOR

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

The following table summarizes both: (i) the gross fair value of derivative instruments by the appropriate balance sheet classification even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the balance sheet and (ii) the net recorded fair value as reflected on the balance sheet at September 30, 2014 and December 31, 2013.  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	2014			2013			2014			2013
		(In thousands)
Commodity contracts	Short-term derivative instruments	$	48,405		$	21,759		$	12,458		$	19,739
Interest rate swaps	Short-term derivative instruments		—			845			3,635			3,287
Gross fair value			48,405			22,604			16,093			23,026
Netting arrangements	Short-term derivative instruments		(10,984	)		(13,315	)		(10,984	)		(13,315	)
Net recorded fair value	Short-term derivative instruments	$	37,421		$	9,289		$	5,109		$	9,711
Commodity contracts	Long-term derivative instruments	$	81,306		$	83,295		$	62,084		$	38,495
Interest rate swaps	Long-term derivative instruments		95			39			77			2,303
Gross fair value			81,401			83,334			62,161			40,798
Netting arrangements	Long-term derivative instruments		(46,886	)		(34,718	)		(46,886	)		(34,718	)
Net recorded fair value	Long-term derivative instruments	$	34,515		$	48,616		$	15,275		$	6,080

Schedule of Gains and Losses Related to Derivative Instruments

The following table details the gains and losses related to derivative instruments for the three and nine months ended September 30, 2014 and 2013 (in thousands):

		For the Three Months					For the Nine Months
	Statements of	Ended September 30,					Ended September 30,
	Operations Location	2014			2013		2014		2013
Commodity derivative contracts	(Gain) loss on commodity derivatives	$	(189,492	)	$	2,028	$	11,580	$	(29,556	)
Interest rate derivatives	Interest expense, net		(175	)		1,926		1,157		69

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Long-Term Incentive Plans - Summary of Information Regarding Restricted Common Unit Awards (Parenthetical) (Detail) (USD $)	6 Months Ended			9 Months Ended
	Jun. 30, 2014 MEMP [Member]	Jun. 30, 2014 Minimum [Member] MEMP [Member]	Jun. 30, 2014 Maximum [Member] MEMP [Member]	Sep. 30, 2014 Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Aggregate grant date fair value	$ 15,300,000			$ 20,300,000
Aggregate grant date fair value, market price				$ 19.00
Aggregate grant date fair value, market price		$ 21.99	$ 23.40

XML

Background, Organization and Basis of Presentation - Additional Information (Detail) (USD $)	0 Months Ended	9 Months Ended			0 Months Ended							9 Months Ended				0 Months Ended										0 Months Ended	9 Months Ended	1 Months Ended		6 Months Ended
	Jun. 18, 2014	Sep. 30, 2014 Segment	Sep. 30, 2013	Dec. 31, 2013	Oct. 01, 2013 Tanos Energy LLC [Member]	Oct. 01, 2013 Prospect Energy LLC [Member]	Oct. 01, 2013 Jackson County [Member]	Mar. 28, 2013 WHT Energy Partners LLC [Member]	Sep. 30, 2014 Limited Partner [Member]	Sep. 30, 2014 General Partner [Member]	Jun. 27, 2014 PIK notes trustee [Member]	Sep. 30, 2014 PIK notes [Member]	Jun. 27, 2014 PIK notes [Member]	Jun. 18, 2014 PIK notes [Member]	Dec. 18, 2013 PIK notes [Member]	Jun. 18, 2014 WildHorse Resources, LLC [Member]	Jun. 18, 2014 Classic [Member]	Jun. 18, 2014 Classic GP[Member]	Jun. 18, 2014 Black Diamond [Member]	Jun. 18, 2014 Beta Operating [Member]	Jun. 18, 2014 Memorial Resource Finance Corp [Member]	Jun. 18, 2014 MRD Operating [Member]	Jun. 18, 2014 MEMP GP [Member]	Jun. 18, 2014 MEMP GP & MEMP IDRs [Member]	Jun. 18, 2014 MRD Holdco LLC [Member]	Jun. 18, 2014 MRD LLC [Member] MRD Holdco [Member]	Sep. 30, 2014 MRD [Member]	Jul. 31, 2013 BlueStone Natural Resources Holdings, LLC [Member]	May 31, 2014 Golden Energy [Member]	Jun. 30, 2014 Limited Partners Subordinated Units [Member]
Consolidation And Basis Of Presentation [Line Items]
Initial public offering	21,500,000
Common stock price per share	$ 19.00
Proceeds from initial public offering	$ 380,200,000
Initial public offering completion date	Jun. 18, 2014
Ownership percentage in MRD LLC after contribution from Funds and prior to redemption of PIK notes																										100.00%
Proceeds for sale of subsidiary																200,000
Ownership interest percentage																99.90%	100.00%	100.00%	100.00%	100.00%	100.00%	100.00%	100.00%	50.00%
Common stock, shares issued		193,559,211		0												42,334,323									128,665,677
Aggregate principal amount														350,000,000	350,000,000
Senior notes maturity date												Dec. 15, 2018
Debt interest rate, minimum												10.00%
Debt interest rate, maximum												10.75%
Membership interest percentage																0.10%
Cash consideration paid																30,000,000
Revolving credit facility																											2,000,000,000
Credit facility used		2,464,800,000	478,055,000																								614,500,000
Senior PIK Toggle Notes, Redemption price percentage												102.00%
Senior PIK Toggle Notes, Redemption date		Jul. 16, 2014
Sale of assets																												117,900,000	6,700,000
Subordinated units																														5,360,912
Irrevocable deposits											360,000,000		360,000,000
Partnership ownership percentage									99.90%	0.10%
Number of reportable business segments		2
Business acquisition purchase price					$ 77,400,000	$ 16,300,000	$ 2,600,000	$ 200,000,000

XML

Business Segment Data

9 Months Ended

Sep. 30, 2014

Segment Reporting [Abstract]

Business Segment Data

Note 14.  Business Segment Data

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

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

· MRD—reflects the combined operations of the Company, MRD LLC, WildHorse Resources and its previous owners, Classic and Classic GP, Black Diamond, BlueStone, Beta Operating and MEMP GP.

· MEMP—reflects the combined operations of MEMP, its previous owners, and historical dropdown transactions that occurred between MEMP and other MRD LLC consolidating subsidiaries.

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

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

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

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

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

							Other,			Consolidated
							Adjustments &			& Combined
	MRD			MEMP			Eliminations			Totals
Total revenues:
Three months ended September 30, 2014	$	98,342		$	147,243		$	(92	)	$	245,493
Three months ended September 30, 2013		60,294			93,240			(19	)		153,515
Nine months ended September 30, 2014		301,492			371,530			(137	)		672,885
Nine months ended September 30, 2013		171,361			251,516			(136	)		422,741
Adjusted EBITDA: (1)
Three months ended September 30, 2014		83,388			90,045			22			173,455
Three months ended September 30, 2013		56,836			58,623			(18,447	)		97,012
Nine months ended September 30, 2014		247,335			218,842			(18,912	)		447,265
Nine months ended September 30, 2013		153,679			157,160			(19,554	)		291,285
Segment assets: (2)
As of September 30, 2014		1,232,146			2,749,452			40,069			4,021,667
As of December 31, 2013		1,281,134			1,552,307			(4,280	)		2,829,161
Total cash expenditures for additions to long-lived assets:
Nine months ended September 30, 2014		(276,982	)		(1,273,157	)		—			(1,550,139	)
Nine months ended September 30, 2013		(198,220	)		(165,403	)		—			(363,623	)

(1)Adjustments and eliminations for the three and nine months ended September 30, 2014 and 2013 include amounts related to the MRD's Segment equity investments in the MEMP Segment as well as the elimination of less than $0.1 million and $6.1 million of cash distributions that MEMP paid MRD for the three and nine months ended September 30, 2014, respectively, and $6.4 million and $19.1 million of cash distributions that MEMP paid MRD LLC for the three and nine months ended September 30, 2013, respectively, related to MRD LLC's partnership interests in MEMP.

(2)Adjustments and eliminations primarily represent the elimination of the MRD's Segment equity investments in the MEMP Segment.  The adjustment at September 30, 2014 and December 31, 2013 also includes $47.3 million and $49.9 million, respectively related to an impairment recognized by the MEMP Segment during 2013.  This impairment did not exist on a consolidated basis.

Calculation of Reportable Segments’ Adjusted EBITDA

	For the Three Months
	Ended September 30, 2014
							Combined
	MRD			MEMP			Totals
	(In thousands)
Net income (loss)	$	9,866		$	103,226		$	113,092
Interest expense, net		9,886			26,459			36,345
Income tax expense (benefit)		25,834			—			25,834
DD&A		39,550			43,928			83,478
Impairment of proved oil and natural gas properties		—			67,181			67,181
Accretion of AROs		170			1,383			1,553
(Gain) loss on commodity derivative instruments		(33,090	)		(156,402	)		(189,492	)
Cash settlements received (paid) on commodity derivative instruments		3,699			876			4,575
Acquisition 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	$	83,388		$	90,045		$	173,433

	For the Three Months
	Ended September 30, 2013
							Combined
	MRD			MEMP			Totals
				(In thousands)
Net income (loss)	$	73,874		$	(39,039	)	$	34,835
Interest expense, net		9,041			11,574			20,615
Income tax expense (benefit)		1,147			97			1,244
DD&A		20,476			24,660			45,136
Impairment of proved oil and natural gas properties		—			50,310			50,310
Accretion of AROs		178			1,176			1,354
(Gain) loss on commodity derivative instruments		213			1,815			2,028
Cash settlements received (paid) on commodity derivative instruments		3,368			3,678			7,046
(Gain) loss on sale of properties		(90,083	)		20			(90,063	)
Acquisition related costs		667			2,310			2,977
Incentive-based compensation expense		19,069			1,237			20,306
Non-cash compensation expense		—			(68	)		(68	)
Exploration costs		439			853			1,292
Non-cash equity (income) loss from MEMP		12,058			—			12,058
Cash distributions from MEMP		6,389			—			6,389
Adjusted EBITDA	$	56,836		$	58,623		$	115,459

	For the Nine Months
	Ended September 30, 2014
							Combined
	MRD			MEMP			Totals
				(In thousands)
Net income (loss)	$	(930,149	)	$	(45,037	)	$	(975,186	)
Interest expense, net		44,355			60,573			104,928
Loss on extinguishment of debt		37,248			—			37,248
Income tax expense (benefit)		14,323			75			14,398
DD&A		107,496			105,830			213,326
Impairment of proved oil and natural gas properties		—			67,181			67,181
Accretion of AROs		495			4,106			4,601
(Gain) loss on commodity derivative instruments		(17,130	)		28,710			11,580
Cash settlements received (paid) on commodity derivative instruments		(4,930	)		(14,999	)		(19,929	)
(Gain) loss on sale of properties		3,057			—			3,057
Acquisition 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
Provision for environmental remediation		—			2,852			2,852
Non-cash equity (income) loss from MEMP		12,844			—			12,844
Cash distributions from MEMP		6,068			—			6,068
Adjusted EBITDA	$	247,335		$	218,842		$	466,177

	For the Nine Months
	Ended September 30, 2013
							Combined
	MRD			MEMP			Totals
				(In thousands)
Net income (loss)	$	114,628		$	9,359		$	123,987
Interest expense, net		15,947			26,047			41,994
Income tax expense (benefit)		1,147			285			1,432
DD&A		62,605			69,723			132,328
Impairment of proved oil and natural gas properties		—			50,310			50,310
Accretion of AROs		547			3,469			4,016
(Gain) loss on commodity derivative instruments		(8,361	)		(21,195	)		(29,556	)
Cash settlements received (paid) on commodity derivative instruments		9,125			14,081			23,206
(Gain) loss on sale of properties		(83,370	)		(2,848	)		(86,218	)
Acquisition related costs		1,651			3,422			5,073
Incentive-based compensation expense		19,069			2,322			21,391
Non-cash compensation expense		—			1,057			1,057
Exploration costs		1,137			1,128			2,265
Non-cash equity (income) loss from MEMP		454			—			454
Cash distributions from MEMP		19,100			—			19,100
Adjusted EBITDA	$	153,679		$	157,160		$	310,839

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						For the Nine Months
	Ended September 30,						Ended September 30,
	2014			2013			2014			2013
Total Reportable Segments' Adjusted EBITDA	$	173,433		$	115,459		$	466,177		$	310,839
Adjustments to reconcile Adjusted EBITDA to net income (loss):
Interest expense, net		(36,345	)		(20,615	)		(104,928	)		(41,994	)
Loss on extinguishment of debt		—			—			(37,248	)		—
Income tax benefit (expense)		(25,834	)		(1,244	)		(14,398	)		(1,432	)
DD&A		(84,447	)		(45,136	)		(215,906	)		(132,328	)
Impairment of proved oil and natural gas properties		(67,181	)		(21	)		(67,181	)		(21	)
Accretion of AROs		(1,553	)		(1,354	)		(4,601	)		(4,016	)
Gains (losses) on commodity derivative instruments		189,492			(2,028	)		(11,580	)		29,556
Cash settlements paid (received) on commodity derivative instruments		(4,575	)		(7,046	)		19,929			(23,206	)
Gain (loss) on sale of properties		—			90,063			(3,057	)		86,218
Acquisition related costs		(1,425	)		(2,977	)		(5,480	)		(5,073	)
Incentive-based compensation expense		(29,289	)		(20,306	)		(976,264	)		(21,391	)
Non-cash compensation expense		—			68			—			(1,057	)
Exploration costs		(175	)		(1,292	)		(1,465	)		(2,265	)
Provision for environmental remediation		—			—			(2,852	)		—
Cash distributions from MEMP		(64	)		(6,389	)		(6,068	)		(19,100	)
Other non-cash equity (income) loss		—			(1,220	)		—			(430	)
Net income (loss)	$	112,037		$	95,962		$	(964,922	)	$	174,300

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

	For the Three Months
	Ended September 30, 2014
	MRD			MEMP			Other, Adjustments & Eliminations			Consolidated & Combined Totals
Revenues:
Oil & natural gas sales	$	98,337		$	145,824		$	—		$	244,161
Other revenues		5			1,419			(92	)		1,332
Total revenues		98,342			147,243			(92	)		245,493
Costs and expenses:
Lease operating		6,991			39,312			(92	)		46,211
Pipeline operating		—			431			—			431
Exploration		133			42			—			175
Production and ad valorem taxes		3,571			10,469			—			14,040
Depreciation, depletion, and amortization		39,550			43,928			969			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		9,982			11,214			—			21,196
Accretion of asset retirement obligations		170			1,383			—			1,553
(Gain) loss on commodity derivative instruments		(33,090	)		(156,402	)		—			(189,492	)
(Gain) loss on sale of properties		—			—			—			—
Total costs and expenses		52,857			17,558			877			71,292
Operating income (loss)		45,485			129,685			(969	)		174,201
Other income (expense):
Interest expense, net		(9,886	)		(26,459	)		—			(36,345	)
Loss on extinguishment of debt		—			—			—			—
Earnings from equity investments		86			—			(86	)		—
Other, net		15			—			—			15
Total other income (expense)		(9,785	)		(26,459	)		(86	)		(36,330	)
Income (loss) before income taxes		35,700			103,226			(1,055	)		137,871
Income tax benefit (expense)		(25,834	)		—			—			(25,834	)
Net income (loss)	$	9,866		$	103,226		$	(1,055	)	$	112,037

	For the Three Months
	Ended September 30, 2013
	MRD			MEMP			Other, Adjustments & Eliminations			Consolidated & Combined Totals
Revenues:
Oil & natural gas sales	$	60,179		$	92,583		$	—		$	152,762
Other revenues		115			657			(19	)		753
Total revenues		60,294			93,240			(19	)		153,515
Costs and expenses:
Lease operating		6,144			23,334			(83	)		29,395
Pipeline operating		—			394			—			394
Exploration		439			853			—			1,292
Production and ad valorem taxes		1,354			6,068			—			7,422
Depreciation, depletion, and amortization		20,476			24,660			—			45,136
Impairment of proved oil and natural gas properties		—			50,310			(50,289	)		21
Incentive unit compensation expense		19,069			—			—			19,069
General and administrative		7,653			11,928			65			19,646
Accretion of asset retirement obligations		178			1,176			—			1,354
(Gain) loss on commodity derivative instruments		213			1,815			—			2,028
(Gain) loss on sale of properties		(90,083	)		20			—			(90,063	)
Other, net		—			50			(26	)		24
Total costs and expenses		(34,557	)		120,608			(50,333	)		35,718
Operating income (loss)		94,851			(27,368	)		50,314			117,797
Other income (expense):
Interest expense, net		(9,041	)		(11,574	)		—			(20,615	)
Earnings from equity investments		(10,838	)		—			10,838			—
Other, net		49			—			(25	)		24
Total other income (expense)		(19,830	)		(11,574	)		10,813			(20,591	)
Income (loss) before income taxes		75,021			(38,942	)		61,127			97,206
Income tax benefit (expense)		(1,147	)		(97	)		—			(1,244	)
Net income (loss)	$	73,874		$	(39,039	)	$	61,127		$	95,962

	For the Nine Months
	Ended September 30, 2014
	MRD			MEMP			Other, Adjustments & Eliminations			Consolidated & Combined Totals
Revenues:
Oil & natural gas sales	$	300,931		$	368,370		$	—		$	669,301
Other revenues		561			3,160			(137	)		3,584
Total revenues		301,492			371,530			(137	)		672,885
Costs and expenses:
Lease operating		18,657			93,367			(137	)		111,887
Pipeline operating		—			1,596			—			1,596
Exploration		1,213			252			—			1,465
Production and ad valorem taxes		10,494			23,129			—			33,623
Depreciation, depletion, and amortization		107,496			105,830			2,580			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		29,301			31,760			—			61,061
Accretion of asset retirement obligations		495			4,106			—			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		1,122,973			355,919			2,443			1,481,335
Operating income (loss)		(821,481	)		15,611			(2,580	)		(808,450	)
Other income (expense):
Interest expense, net		(44,355	)		(60,573	)		—			(104,928	)
Loss on extinguishment of 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 (loss) before income taxes		(915,826	)		(44,962	)		10,264			(950,524	)
Income tax benefit (expense)		(14,323	)		(75	)		—			(14,398	)
Net income (loss)	$	(930,149	)	$	(45,037	)	$	10,264		$	(964,922	)

	For the Nine Months
	Ended September 30, 2013
	MRD			MEMP			Other, Adjustments & Eliminations			Consolidated & Combined Totals
Revenues:
Oil & natural gas sales	$	171,013		$	249,844		$	—		$	420,857
Other revenues		348			1,672			(136	)		1,884
Total revenues		171,361			251,516			(136	)		422,741
Costs and expenses:
Lease operating		17,065			64,922			(241	)		81,746
Pipeline operating		—			1,343			—			1,343
Exploration		1,137			1,128			—			2,265
Production and ad valorem taxes		8,563			14,915			—			23,478
Depreciation, depletion, and amortization		62,605			69,723			—			132,328
Impairment of proved oil and natural gas properties		—			50,310			(50,289	)		21
Incentive unit compensation expense		19,069			—			—			19,069
General and administrative		22,466			33,411			105			55,982
Accretion of asset retirement obligations		547			3,469			—			4,016
(Gain) loss on commodity derivative instruments		(8,361	)		(21,195	)		—			(29,556	)
(Gain) loss on sale of properties		(83,370	)		(2,848	)		—			(86,218	)
Other, net		(25	)		647			—			622
Total costs and expenses		39,696			215,825			(50,425	)		205,096
Operating income (loss)		131,665			35,691			50,289			217,645
Other income (expense):
Interest expense, net		(15,947	)		(26,047	)		—			(41,994	)
Earnings from equity investments		(24	)		—			24			—
Other, net		81			—			—			81
Total other income (expense)		(15,890	)		(26,047	)		24			(41,913	)
Income before income taxes		115,775			9,644			50,313			175,732
Income tax benefit (expense)		(1,147	)		(285	)		—			(1,432	)
Net income (loss)	$	114,628		$	9,359		$	50,313		$	174,300