Range Resources - Louisiana, Inc. - FORM 10-Q

Range Resources - Louisiana, Inc. - FORM 10-Q - August 8, 2014

Attached files

Attached files

Range Resources - Louisiana, Inc. Reports

file	filename
EX-32.1 - EX-32.1 - Range Resources - Louisiana, Inc.	d744705dex321.htm
EX-31.1 - EX-31.1 - Range Resources - Louisiana, Inc.	d744705dex311.htm
EX-31.2 - EX-31.2 - Range Resources - Louisiana, Inc.	d744705dex312.htm

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 June 30, 2014

¨ 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)

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 ¨ No þ

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 ¨ 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 July 31, 2014, the registrant had 193,568,422 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	6
	Cautionary Note Regarding Forward-Looking Statements	7

	PART I—FINANCIAL INFORMATION
Item 1.	Financial Statements.
	Unaudited Condensed Consolidated and Combined Balance Sheets as of June 30, 2014 and December 31, 2013	9
	Unaudited Condensed Statements of Consolidated and Combined Operations for the Three and Six Months Ended June 30, 2014 and 2013	10
	Unaudited Condensed Statements of Consolidated and Combined Cash Flows for the Six Months Ended June 30, 2014 and 2013	11
	Unaudited Condensed Statements of Consolidated and Combined Equity for the Six Months Ended June 30, 2014	12
	Notes to Unaudited Condensed Consolidated and Combined Financial Statements
	Note 1 – Organization and Basis of Presentation	13
	Note 2 – Summary of Significant Accounting Policies	15
	Note 3 – Acquisitions and Divestitures	20
	Note 4 – Fair Value Measurements of Financial Instruments	21
	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 & Noncontrolling Interests	31
	Note 10 – Earnings per Share	32
	Note 11 – Long-Term Incentive Plans	32
	Note 12 – Incentive Units	34
	Note 13 – Related Party Transactions	35
	Note 14 – Business Segment Data	38
	Note 15 – Commitments and Contingencies	43
	Note 16 – Subsequent Events	45
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	47
Item 3.	Quantitative and Qualitative Disclosures About Market Risk.	67
Item 4.	Controls and Procedures.	68

	PART II—OTHER INFORMATION
Item 1.	Legal Proceedings.	69
Item 1A.	Risk Factors.	69
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds.	69
Item 3.	Defaults Upon Senior Securities.	69
Item 4.	Mine Safety Disclosures.	69
Item 5.	Other Information.	70
Item 6.	Exhibits.	70

Signatures		72

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.

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 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.

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.

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.

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 and that, together with a group, owns a majority of our common stock;

—

“the previous owners” for accounting and financial reporting purposes refers 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: (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

^¡

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.

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;

—

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.

PART I—FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS.

MEMORIAL RESOURCE DEVELOPMENT CORP.

UNAUDITED CONDENSED CONSOLIDATED AND COMBINED BALANCE SHEETS

(In thousands, except outstanding units)


	June 30,		December 31,
	2014		2013
ASSETS
Current assets:
Cash and cash equivalents	$	15,966	$	77,721
Restricted cash		--		35,000
Accounts receivable:
Oil and natural gas sales		99,552		68,764
Joint interest owners and other		18,967		19,958
Affiliates		3,777		4,652
Short-term derivative instruments		1,998		9,289
Prepaid expenses and other current assets		16,827		19,513

Total current assets		157,087		234,897
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method		3,434,324		3,037,298
Other		7,574		10,331
Accumulated depreciation, depletion and impairment		(726,157)		(627,925)

Oil and natural gas properties, net		2,715,741		2,419,704
Long-term derivative instruments		4,294		48,616
Restricted investments		75,506		73,385
Restricted cash		260		15,506
Other long–term assets		91,032		37,053

Total assets	$	3,043,920	$	2,829,161


LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	22,140	$	20,734
Accounts payable – affiliates		333		1,975
Revenues payable		54,526		56,091
Accrued liabilities		90,047		98,130
Short-term derivative instruments		50,063		9,711

Total current liabilities		217,109		186,641
Long-term debt—MRD Segment		619,000		871,150
Long-term debt—MEMP Segment		1,148,806		792,067
Asset retirement obligations		114,467		111,679
Long-term derivative instruments		91,062		6,080
Deferred tax liabilities		34,810		3,106
Other long-term liabilities		2,014		306

Total liabilities		2,227,268		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; 193,568,422 shares issued and outstanding at June 30, 2014; no shares authorized, issued or outstanding at December 31, 2013		1,936		--
Additional paid-in capital		1,359,777		--
Accumulated earnings (deficit)		(961,707)		--

Total stockholders’ equity		400,006		--

Members’ equity:
Members		--		237,186
Previous owners (Note 1)		--		40,331

Total members’ equity		--		277,517

Noncontrolling interests		416,646		580,615

Total equity		816,652		858,132

Total liabilities and equity	$	3,043,920	$	2,829,161

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

MEMORIAL RESOURCE DEVELOPMENT CORP.

UNAUDITED CONDENSED STATEMENTS OF

CONSOLIDATED AND COMBINED OPERATIONS

(In thousands, except per share amounts)


	For the Three Months Ended June 30,				For the Six Months Ended June 30,

	2014		2013		2014		2013

Revenues:
Oil & natural gas sales	$	235,223	$	146,469	$	425,140	$	268,095
Pipeline tariff income and other		1,341		576		2,252		1,131

Total revenues		236,564		147,045		427,392		269,226


Costs and expenses:
Lease operating		31,994		25,987		65,676		52,351
Pipeline operating		676		479		1,165		949
Exploration		1,144		117		1,290		973
Production and ad valorem taxes		10,999		8,770		19,583		16,056
Depreciation, depletion, and amortization		73,780		43,986		131,459		87,192
Incentive unit compensation expense (Note 12)		942,817		--		943,840		--
General and administrative		22,126		23,750		39,865		36,336
Accretion of asset retirement obligations		1,527		1,332		3,048		2,662
(Gain) loss on commodity derivative instruments		141,590		(54,129)		201,072		(31,584)
(Gain) loss on sale of properties		3,167		5,828		3,057		3,845
Other, net		--		598		(12)		598

Total costs and expenses		1,229,820		56,718		1,410,043		169,378

Operating income (loss)		(993,256)		90,327		(982,651)		99,848
Other income (expense):
Interest expense, net		(34,531)		(12,009)		(68,583)		(21,379)
Loss on extinguishment of debt		(37,248)		--		(37,248)		--
Other, net		56		28		87		57

Total other income (expense)		(71,723)		(11,981)		(105,744)		(21,322)

Income (loss) before income taxes		(1,064,979)		78,346		(1,088,395)		78,526
Income tax benefit (expense)		11,536		(188)		11,436		(188)

Net income (loss)		(1,053,443)		78,158		(1,076,959)		78,338
Net income (loss) attributable to noncontrolling interest		(105,094)		34,975		(136,982)		30,906

Net income (loss) attributable to Memorial Resource Development Corp.		(948,349)		43,183		(939,977)		47,432
Net (income) loss allocated to members		(13,358)		(35,278)		(20,305)		(37,875)
Net (income) loss allocated to previous owners		--		(7,905)		(1,425)		(9,557)

Net income (loss) available to common stockholders	$	(961,707)	$	--	$	(961,707)	$	--


Earnings per common share: (Note 10)
Basic	$	(5.00)		n/a	$	(5.00)		n/a

Diluted	$	(5.00)		n/a	$	(5.00)		n/a

Weighted average common and common equivalent shares outstanding:
Basic		192,500		n/a		192,500		n/a

Diluted		192,500		n/a		192,500		n/a

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

MEMORIAL RESOURCE DEVELOPMENT CORP.

UNAUDITED CONDENSED STATEMENTS OF

CONSOLIDATED AND COMBINED CASH FLOWS

(In thousands)


	For the Six Months Ended June 30,

	2014		2013

Cash flows from operating activities:
Net income (loss)	$	(1,076,959)	$	78,338
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization		131,459		87,192
(Gain) loss on derivatives		202,395		(33,442)
Cash settlements (paid) received on derivative instruments		(25,447)		14,620
Loss on extinguishment of debt		30,248		--
Amortization of deferred financing costs		3,587		4,785
Accretion of senior notes net discount		1,319		86
Accretion of asset retirement obligations		3,048		2,662
Amortization of equity awards		3,134		1,085
(Gain) loss on sale of properties		3,057		3,845
Non-cash compensation expense		916,109		1,125
Exploration costs		920		94
Deferred income tax expense (benefit)		(11,955)		--
Changes in operating assets and liabilities:
Accounts receivable		(26,847)		605
Prepaid expenses and other assets		(119)		(1,448)
Payables and accrued liabilities		21,574		3,714
Other		2,224		(119)

Net cash provided by operating activities		177,747		163,142
Cash flows from investing activities:
Acquisitions of oil and natural gas properties		(173,000)		(73,408)
Additions to oil and gas properties		(293,567)		(162,657)
Additions to other property and equipment		(1,268)		(353)
Additions to restricted investments		(2,121)		(3,080)
Deposits for property acquisitions		(70,125)		--
Decrease (increase) in restricted cash		49,946		907
Proceeds from the sale of oil and natural gas properties		6,700		37,462
Other		(301)		--

Net cash used in investing activities		(483,736)		(201,129)
Cash flows from financing activities:
Advances on revolving credit facilities		1,548,800		395,650
Payments on revolving credit facilities		(776,900)		(879,706)
Borrowings under second lien credit facility		--		325,000
Redemption of second lien credit facility		(328,282)		--
Proceeds from the issuances of senior notes		--		397,563
Redemption of senior notes		(351,808)		--
Deferred financing costs		(6,234)		(23,659)
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		(26,875)		--
Proceeds from MEMP public offering		--		179,371
Costs incurred in conjunction with MEMP public offering		--		(7,592)
Contributions from NGP affiliates related to sale of properties		1,165		2,013
Distributions to the Funds		--		(300,000)
Distributions to MRD Holdco		(59,803)		--
Distributions to noncontrolling interests		(61,844)		(27,319)
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		--		(1,923)
Other		270		345

Net cash provided by financing activities		244,234		59,687
Net change in cash and cash equivalents		(61,755)		21,700
Cash and cash equivalents, beginning of period		77,721		49,391

Cash and cash equivalents, end of period	$	15,966	$	71,091


Supplemental cash flows:
Cash paid for interest	$	65,641	$	12,678
Noncash investing and financing activities:
Accrued initial public offering expenses		957		--
Change in capital expenditures in payables and accrued liabilities		3,526		18,599
Assumptions of asset retirement obligations related to properties acquired or drilled		745		2,068
Accounts receivable related to acquisitions and divestitures		4,732		--

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

MEMORIAL RESOURCE DEVELOPMENT CORP.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED AND COMBINED EQUITY

(In thousands)


	For the Six Months Ended June 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)		380,453		--
Tax related effects in connection with restructuring transactions and initial public offering		(43,251)		--
Restricted stock awards		(11)		--
Amortization of restricted stock awards		174		--
Contribution related to MRD Holdco incentive unit compensation expense (see Note 12)		111,757		--
Purchase of noncontrolling interests		(2,881)		--
Other		384

Balance, end of period		1,359,777		--

Accumulated earnings (deficit)
Balance, beginning of period		--		--
Net income (loss) allocation		(961,707)		--

Balance, end of period		(961,707)		--

Total stockholders’ equity		400,006		--


MEMBERS’ EQUITY
Members
Balance, beginning of period		237,186		811,614
Net income (loss) allocation		20,305		37,875
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		--		(300,000)
Net equity deemed contribution (distribution) related to net assets transferred to MEMP		(2,659)		2,560
Impact of equity transactions of MEMP		--		23,029
Other		(154)		108

Balance, end of period		--		575,186

Previous Owners
Balance, beginning of period		40,331		233,433
Net income (loss) allocation		1,425		9,557
Contributions		--		1,214
Distributions		--		(1,923)
Net book value of assets acquired from NGP affiliates		(41,756)		--
Other		--		(11)

Balance, end of period		--		242,270

Total members’ equity		--		817,456


NONCONTROLLING INTERESTS
Noncontrolling interests
Balance, beginning of period		580,615		231,662
Net income (loss) allocation		(136,982)		30,906
Net proceeds from MEMP public equity offering		--		171,779
Distributions		(61,844)		(27,319)
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		--		(23,029)
Amortization of MEMP equity awards		2,960		1,085
Distribution of net assets to MRD Holdco		29,994		--
Other		(345)		(33)

Balance, end of period		416,646		381,221


TOTAL EQUITY

Total equity	$	816,652	$	1,198,677

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

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.

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 $380.7 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;

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.

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, 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 six months ended June 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.

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 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 June 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.

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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.

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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 June 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 June 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.

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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):


	June 30,		December 31,
	2014		2013

Accrued capital expenditures	$	52,105	$	48,579
Accrued lease operating expense		11,038		13,240
Accrued general and administrative expenses		7,650		14,485
Accrued initial public offering expenses		957		--
Accrued ad valorem and production taxes		7,041		3,541
Accrued interest payable		8,923		11,934
Accrued environmental		797		577
Other miscellaneous, including operator advances		1,536		5,774

	$	90,047	$	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.

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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.

Note 3. Acquisitions and Divestitures

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


For the Three Months Ended June 30,				For the Six Months Ended June 30,

2014		2013		2014		2013


$	1,593	$	1,839	$	4,055	$	2,096

2014 Acquisitions

In March 2014, MEMP closed a transaction to acquire certain oil and natural gas producing properties from a third party in the Eagle Ford for approximately $169.1 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 six months ended June 30, 2014, revenues of approximately $13.4 million and $14.4 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 $7.4 million and $8.0 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 Acquisition

Oil and gas properties	$	169,656
Asset retirement obligations		(285)
Accrued liabilities		(250)

Total identifiable net assets	$	169,121

Unaudited supplemental pro forma financial information is not presented due to immateriality.

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.

During the six months ended June 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 two separate transactions for an aggregate purchase price of approximately $6.3 million.

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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 six months ended June 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.

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 June 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 June 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 June 30, 2014 and December 31, 2013 for each of the fair value hierarchy levels:


		Fair Value Measurements at June 30, 2014 Using

	Quoted Prices in Active Market (Level 1)			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Fair Value

		(In thousands)
Assets:
Commodity derivatives		$	--	$	69,792	$	--	$	69,792
Interest rate derivatives			--		16		--		16

Total assets		$	--	$	69,808	$	--	$	69,808


Liabilities:
Commodity derivatives		$	--	$	199,539	$	--	$	199,539
Interest rate derivatives			--		5,102		--		5,102

Total liabilities		$	--	$	204,641	$	--	$	204,641

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS


		Fair Value Measurements at December 31, 2013 Using

	Quoted Prices in Active Market (Level 1)			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (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. We did not have any impairment charges for the three and six months ended June 30, 2014 and 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

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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 June 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 $1.7 million against amounts outstanding under its revolving credit facility at June 30, 2014. At June 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 $1.6 million against amounts outstanding under our revolving credit facility at June 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, costless collars, call spreads and basis swaps) to manage exposure to commodity price volatility. Historically, we have not paid or received premiums for put options. 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 Inter-Continental Exchange (“ICE”) Brent and California Midway-Sunset. Our NGL derivative contracts are indexed to OPIS Mont Belvieu. At June 30, 2014, the MRD Segment had the following open commodity positions:


	Remaining 2014		2015		2016		2017

Natural Gas Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (MMBtu)		2,505,000		1,000,000		720,000		520,000
Weighted-average fixed price	$	4.35	$	4.20	$	4.32	$	4.45

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)		870,000		180,000		220,000		200,000
Spread	$	(0.07)	$	(0.09)	$	(0.08)	$	(0.08)

Crude Oil Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		34,000		33,500		--		--
Weighted-average fixed price	$	96.08	$	93.86	$	--	$	--

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	$	--

NGL Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		131,000		85,000		--		--
Weighted-average fixed price	$	46.26	$	42.63	$	--	$	--

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

At June 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)		2,626,033		2,605,278		2,692,442		2,450,067		2,160,000		1,914,583
Weighted-average fixed price	$	4.33	$	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)		2,875,833		2,940,000		600,000		--		--		--
Spread	$	(0.09)	$	(0.12)	$	(0.10)	$	--	$	--	$	--

Crude Oil Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		285,285		314,281		300,313		286,600		272,000		60,000
Weighted-average fixed price	$	95.80	$	90.96	$	85.44	$	83.96	$	83.24	$	83.33

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)		171,000		149,200		--		--		--		--
Weighted-average fixed price	$	42.96	$	43.02	$	--	$	--	$	--	$	--

(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.

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

Natural Gas Derivative Contracts:

NGPL TexOk basis swaps:
Average Monthly Volume (MMBtu)		2,305,833		2,280,000		600,000
Spread	$	(0.09)	$	(0.11)	$	(0.10)

NGPL STX basis swaps:
Average Monthly Volume (MMBtu)		190,000		--		--
Spread	$	(0.07)	$	--	$	--

HSC basis swaps:
Average Monthly Volume (MMBtu)		380,000		150,000		--
Spread	$	(0.11)	$	(0.08)	$	--

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	$	(9.25)	$	(9.73)	$	--

Midland basis swaps:
Average Monthly Volume (Bbls)		40,000		40,000		--
Spread	$	(3.68)	$	(3.25)	$	--

LLS Crude basis swaps:
Average Monthly Volume (Bbls)		34,000		--		--
Spread	$	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 June 30, 2014, we had the following interest rate swap open positions:


Credit Facility	Remaining 2014		2015		2016

MEMP:
Average Monthly Notional (in thousands)		$ 236,667		$ 280,833		$ 150,000
Weighted-average fixed rate		1.320%		1.416%		1.193%
Floating rate		1 Month LIBOR		1 Month LIBOR		1 Month LIBOR
MRD:
Average Monthly Notional (in thousands)		$ 112,500		$ 100,000		$ --
Weighted-average fixed rate		0.769%		0.758%		--
Floating rate		1 & 3 Month LIBOR		1 & 3 Month LIBOR		--

Subsequent event. 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.

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 June 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 is a lender under our collective credit agreements.


		Asset Derivatives				Liability Derivatives

		June 30,		December 31,		June 30,		December 31,

Type	Balance Sheet Location	2014		2013		2014		2013

		(In thousands)

Commodity contracts	Short-term derivative instruments	$	16,810	$	21,759	$	60,841	$	19,739
Interest rate swaps	Short-term derivative instruments		--		845		4,034		3,287

Gross fair value			16,810		22,604		64,875		23,026
Netting arrangements	Short-term derivative instruments		(14,812)		(13,315)		(14,812)		(13,315)

Net recorded fair value	Short-term derivative instruments	$	1,998	$	9,289	$	50,063	$	9,711


Commodity contracts	Long-term derivative instruments	$	52,982	$	83,295	$	138,698	$	38,495
Interest rate swaps	Long-term derivative instruments		16		39		1,068		2,303

Gross fair value			52,998		83,334		139,766		40,798
Netting arrangements	Long-term derivative instruments		(48,704)		(34,718)		(48,704)		(34,718)

Net recorded fair value	Long-term derivative instruments	$	4,294	$	48,616	$	91,062	$	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 six months ended June 30, 2014 and 2013 (in thousands):


		For the Three Months Ended June 30,				For the Six Months Ended June 30,
	Statements of Operations Location	2014		2013		2014		2013


Commodity derivative contracts	(Gain) loss on commodity derivatives	$	141,590	$	(54,129)	$	201,072	$	(31,584)
Interest rate derivatives	Interest expense, net		821		(1,913)		1,323		(1,857)

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 six months ended June 30, 2014 (in thousands):



Asset retirement obligations at beginning of period	$	111,769
Liabilities added from acquisitions or drilling		745
Liabilities removed upon sale of wells to an affiliate		(728)
Liabilities removed upon plugging and abandoning		(344)
Revisions		67
Accretion expense		3,048

Asset retirement obligations at end of period		114,557
Less: current portion		90

Asset retirement obligations—long-term portion	$	114,467

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:


	June 30,		December 31,
	2014		2013
	(In thousands)

BOEM platform abandonment (See Note 15)	$	68,313	$	66,373
BOEM lease bonds		794		794

SPBPC Collateral:
Contractual pipeline and surface facilities abandonment		2,487		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	$	75,506	$	73,385

Note 8. Long Term Debt

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


	June 30,		December 31,
	2014		2013
	(In thousands)
MRD Segment:
MRD $2.0 billion revolving credit facility, variable-rate, due June 2019	$	619,000	$	--
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
10.00%/10.75% senior PIK toggle notes unamortized discounts		--		(6,950)

Subtotal		619,000		871,150


MEMP Segment:
MEMP $2.0 billion revolving credit facility, variable-rate, due March 2018		459,000		103,000
7.625% senior notes, fixed-rate, due May 2021 (2)		700,000		700,000
Unamortized discounts		(10,194)		(10,933)

Subtotal		1,148,806		792,067

Total long-term debt	$	1,767,806	$	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 $735.0 million and $721.0 million at June 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.

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):


	June 30,
	2014
MRD Segment:
MRD $2.0 billion revolving credit facility, variable-rate, due June 2019	$	725,000
MEMP Segment:
MEMP $2.0 billion revolving credit facility, variable-rate, due March 2018	$	870,000

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

MRD Revolving Credit Facility

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.

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

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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.

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:


Credit Facility	For the Three Months Ended June 30,				For the Six Months Ended June 30,

	2014		2013		2014		2013

MRD Segment:
MRD revolving credit facility		2.24%		n/a		2.24%		n/a
MRD LLC revolver terminated December 2013		n/a		2.64%		n/a		3.63%
WildHorse Resources revolver terminated June 2014		4.13%		2.80%		4.04%		2.91%
WildHorse Resources second lien terminated June 2014		6.44%		6.44%		6.44%		6.44%
Black Diamond terminated November 2013		n/a		3.96%		n/a		3.34%
MEMP Segment:
MEMP revolving credit facility		2.46%		3.31%		2.70%		2.98%
WHT revolver terminated March 2013		n/a		n/a		n/a		1.11%
Tanos revolver terminated April 2013		n/a		n/a		n/a		2.12%
Stanolind revolver paid off by MEMP October 2013		n/a		3.79%		n/a		3.56%
Boaz revolver terminated October 2013		n/a		2.89%		n/a		3.07%
Crown revolver terminated October 2013		n/a		3.50%		n/a		3.41%
Propel Energy revolver paid off by MEMP October 2013		n/a		2.89%		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:


	June 30,		December 31,
	2014		2013
	(In thousands)
MRD Segment:
MRD revolving credit facility	$	4,679	$	--
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		5,019		5,413
2021 Senior Notes		14,335		15,053

	$	24,033	$	40,193

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Note 9. Stockholders’ Equity and Noncontrolling Interests

Common Stock

The Company’s authorized capital stock includes 600,000,000 shares of common stock, $0.01 par value per share. The following is a summary of the changes in our common shares issued for the six months ended June 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

Balance June 30, 2014			193,568,422

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, 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 June 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 of directors 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 of directors 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 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.

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Note 10. Earnings per Share

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


		For the Three Months Ended June 30,		For the Six Months Ended June 30,

		2014		2014
Numerator:
Net income (loss) available to common stockholders		$	(961,707)	$	(961,707)


Denominator:
Weighted average common shares outstanding			192,500		192,500
Restricted common shares (1)			--		--

Weighted average common and common equivalent shares outstanding			192,500		192,500


Basic EPS		$	(5.00)	$	(5.00)

Diluted EPS		$	(5.00)	$	(5.00)


(1)	Unvested restricted common shares are not included in basic EPS calculations. The treasury stock method is applied to determine the dilutive effect of the unvested restricted common shares. For the periods presented, the restricted common shares were antidilutive due to net losses and excluded from the diluted EPS calculation. There were 149,672 incremental shares excluded from the computation of diluted EPS.

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 Months Ended June 30,		For the Six Months Ended June 30,

		2014		2014
Numerator:
Net income (loss) attributable to Memorial Resource Development Corp.		$	(948,349)	$	(939,977)


Denominator:
Weighted average common shares outstanding			192,500		192,500
Restricted common shares (1)			--		--

Weighted average common and common equivalent shares outstanding			192,500		192,500


Basic EPS		$	(4.93)	$	(4.88)

Diluted EPS		$	(4.93)	$	(4.88)


(1)	Unvested restricted common shares are not included in basic EPS calculations. The treasury stock method is applied to determine the dilutive effect of the unvested restricted common shares. For the periods presented, the restricted common shares were antidilutive due to net losses and excluded from the diluted EPS calculation. There were 149,672 incremental shares excluded from the computation of diluted EPS.

Note 11. Long-Term Incentive Plans

MRD

In June 2014, our board of directors (“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 the Board or a committee thereof.

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

In connection with our initial public offering, the 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 the 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 Units		Weighted- Average Grant Date Fair Value per Unit (1)

Restricted common shares outstanding at December 31, 2013		--	$	--
Granted (2)		1,068,422	$	19.00

Restricted common units outstanding at June 30, 2014		1,068,422	$	19.00

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


For the Three Months Ended June 30,				For the Six Months Ended June 30,

2014		2013		2014		2013


$	174		--	$	174		--

The unrecognized compensation cost associated with restricted common share awards was $20.1 million at June 30, 2014. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 3.9 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.

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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)		669,898	$	22.36
Forfeited		(8,863)	$	18.57
Vested		(256,130)	$	18.57

Restricted common units outstanding at June 30, 2014		1,111,832	$	20.89


For the Three Months Ended June 30,				For the Six Months Ended June 30,

2014		2013		2014		2013


$	1,665	$	663	$	2,960	$	1,085

The unrecognized compensation cost associated with restricted common unit awards was $21.7 million at June 30, 2014. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.5 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 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 three and six months ended June 30, 2013.

Compensation expense of approximately $1.0 million was recorded by BlueStone and recognized as a component of incentive unit compensation expense during the six months ended June 30, 2014.

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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 three and six months ended June 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 $111.8 million of compensation expense offset by a deemed capital contribution from MRD Holdco and the unrecognized compensation expense of approximately $159.3 million as of June 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 June 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. The unrecognized compensation expense of approximately $5.3 million as of June 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	6-30-2014	6-30-2014
Dividend yield	0%	0%
Expected volatility	44.11%	44.11%
Risk-free rate	0.84%	0.84%
Expected life (years)	2.9	2.9

Note 13. Related Party Transactions

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

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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. These intercompany transactions have been eliminated in preparation of our consolidated and combined financial statements.

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.

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Voting Agreement

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

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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.

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; unit-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.

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):


	MRD		MEMP		Other, Adjustments & Eliminations		Consolidated & Combined Totals

Total revenues:
Three months ended June 30, 2014	$	113,284	$	123,310	$	(30)	$	236,564
Three months ended June 30, 2013		56,905		90,174		(34)		147,045
Six months ended June 30, 2014		203,150		224,287		(45)		427,392
Six months ended June 30, 2013		111,067		158,276		(117)		269,226
Adjusted EBITDA: (1)
Three months ended June 30, 2014		92,191		73,755		(12,946)		153,000
Three months ended June 30, 2013		46,084		55,689		7,338		109,111
Six months ended June 30, 2014		163,947		128,797		(18,934)		273,810
Six months ended June 30, 2013		96,843		98,537		(1,107)		194,273
Segment assets: (2)
As of June 30, 2014		1,143,636		1,859,349		40,935		3,043,920
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:
Six months ended June 30, 2014		177,219		290,616		--		467,835
Six months ended June 30, 2013		141,349		95,069		--		236,418

(1) Adjustments and eliminations for the three and six months ended June 30, 2014 and 2013 include amounts related to the MRD’s Segment equity investments in the MEMP Segment as well the elimination of $3.0 million and $6.0 million of cash distributions that MEMP paid MRD LLC for the three and six months ended June 30, 2014, respectively, and $6.4 million and $12.7 million of cash distributions that MEMP paid MRD LLC for the three and six months ended June 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 June 30, 2014 and December 31, 2013 also includes $48.3 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 June 30, 2014

	MRD		MEMP		Combined Totals

	(In thousands)
Net income (loss)	$	(948,377)	$	(114,206)	$ (1,062,583)
Interest expense, net		16,495		18,036	34,531
Loss on extinguishment of debt		37,248		--	37,248
Income tax expense (benefit)		(11,536)		--	(11,536)
DD&A		37,819		35,157	72,976
Accretion of AROs		161		1,366	1,527
(Gain) loss on commodity derivative instruments		3,244		138,346	141,590
Cash settlements received (paid) on commodity derivative instruments		(3,408)		(7,906)	(11,314)
(Gain) loss on sale of properties		3,167		--	3,167
Acquisition related costs		500		1,093	1,593
Incentive-based compensation expense		942,992		1,665	944,657
Exploration costs		940		204	1,144
Non-cash equity (income) loss from MEMP		9,944		--	9,944
Cash distributions from MEMP		3,002		--	3,002

Adjusted EBITDA	$	92,191	$	73,755	$ 165,946

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS


	For the Three Months Ended June 30, 2013

	MRD		MEMP		Combined Totals

	(In thousands)
Net income (loss)	$	38,670	$	52,695	$ 91,365
Interest expense, net		4,078		7,931	12,009
Income tax expense (benefit)		--		188	188
DD&A		19,045		24,672	43,717
Accretion of AROs		184		1,148	1,332
(Gain) loss on commodity derivative instruments		(18,050)		(36,079)	(54,129)
Cash settlements received (paid) on commodity derivative instruments		1,771		3,286	5,057
(Gain) loss on sale of properties		6,713		(885)	5,828
Acquisition related costs		942		897	1,839
Incentive-based compensation expense		--		663	663
Non-cash compensation expense		--		1,125	1,125
Exploration costs		69		48	117
Non-cash equity (income) loss from MEMP		(13,727)		--	(13,727)
Cash distributions from MEMP		6,389		--	6,389

Adjusted EBITDA	$	46,084	$	55,689	$ 101,773


	For the Six Months Ended June 30, 2014

	MRD		MEMP		Combined Totals

	(In thousands)
Net income (loss)	$	(940,015)	$	(148,263)	$ (1,088,278)
Interest expense, net		34,469		34,114	68,583
Loss on extinguishment of debt		37,248		--	37,248
Income tax expense (benefit)		(11,511)		75	(11,436)
DD&A		67,946		61,902	129,848
Accretion of AROs		325		2,723	3,048
(Gain) loss on commodity derivative instruments		15,960		185,112	201,072
Cash settlements received (paid) on commodity derivative instruments		(8,629)		(15,875)	(24,504)
(Gain) loss on sale of properties		3,057		--	3,057
Acquisition related costs		1,068		2,987	4,055
Incentive-based compensation expense		944,015		2,960	946,975
Exploration costs		1,080		210	1,290
Provision for environmental remediation		--		2,852	2,852
Non-cash equity (income) loss from MEMP		12,930		--	12,930
Cash distributions from MEMP		6,004		--	6,004

Adjusted EBITDA	$	163,947	$	128,797	$ 292,744


	For the Six Months Ended June 30, 2013

	MRD		MEMP		Combined Totals

	(In thousands)
Net income (loss)	$	40,754	$	48,398	$ 89,152
Interest expense, net		6,906		14,473	21,379
Income tax expense (benefit)		--		188	188
DD&A		42,129		45,063	87,192
Accretion of AROs		369		2,293	2,662
(Gain) loss on commodity derivative instruments		(8,574)		(23,010)	(31,584)
Cash settlements received (paid) on commodity derivative instruments		5,757		10,403	16,160
(Gain) loss on sale of properties		6,713		(2,868)	3,845
Acquisition related costs		984		1,112	2,096
Incentive-based compensation expense		--		1,085	1,085
Non-cash compensation expense		--		1,125	1,125
Exploration costs		698		275	973
Non-cash equity (income) loss from MEMP		(11,604)		--	(11,604)
Cash distributions from MEMP		12,711		--	12,711

Adjusted EBITDA	$	96,843	$	98,537	$ 195,380

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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


	For the Three Months Ended June 30,				For the Six Months Ended June 30,

	2014		2013		2014		2013

Total Reportable Segments’ Adjusted EBITDA	$	165,946	$	101,773	$	292,744	$	195,380
Adjustments to reconcile Adjusted EBITDA to net income (loss):
Interest expense, net		(34,531)		(12,009)		(68,583)		(21,379)
Loss on extinguishment of debt		(37,248)		--		(37,248)		--
Income tax benefit (expense)		11,536		(188)		11,436		(188)
DD&A		(73,780)		(43,986)		(131,459)		(87,192)
Accretion of AROs		(1,527)		(1,332)		(3,048)		(2,662)
Gains (losses) on commodity derivative instruments		(141,590)		54,129		(201,072)		31,584
Cash settlements paid (received) on commodity derivative instruments		11,314		(5,058)		24,504		(16,160)
Gain (loss) on sale of properties		(3,167)		(5,828)		(3,057)		(3,845)
Acquisition related costs		(1,593)		(1,839)		(4,055)		(2,096)
Incentive-based compensation expense		(944,657)		(663)		(946,975)		(1,085)
Non-cash compensation expense		--		(1,125)		--		(1,125)
Exploration costs		(1,144)		(117)		(1,290)		(973)
Provision for environmental remediation		--		--		(2,852)		--
Cash distributions from MEMP		(3,002)		(6,389)		(6,004)		(12,711)
Other non-cash equity (income) loss		--		790		--		790

Net income (loss)	$	(1,053,443)	$	78,158	$	(1,076,959)	$	78,338

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 June 30, 2014
	MRD		MEMP		Other, Adjustments & Eliminations		Consolidated & Combined Totals


Revenues:
Oil & natural gas sales	$	112,976	$	122,247	$	--	$	235,223
Other revenues		308		1,063		(30)		1,341

Total revenues		113,284		123,310		(30)		236,564


Costs and expenses:
Lease operating		5,957		26,067		(30)		31,994
Pipeline operating		--		676		--		676
Exploration		940		204		--		1,144
Production and ad valorem taxes		3,923		7,076		--		10,999
Depreciation, depletion, and amortization		37,819		35,157		804		73,780
Incentive unit compensation expense		942,817		--		--		942,817
General and administrative		11,538		10,588		--		22,126
Accretion of asset retirement obligations		161		1,366		--		1,527
(Gain) loss on commodity derivative instruments		3,244		138,346		--		141,590
(Gain) loss on sale of properties		3,167		--		--		3,167

Total costs and expenses		1,009,566		219,480		774		1,229,820

Operating income (loss)		(896,282)		(96,170)		(804)		(993,256)
Other income (expense):
Interest expense, net		(16,495)		(18,036)		--		(34,531)
Loss on extinguishment of debt		(37,248)		--		--		(37,248)
Earnings from equity investments		(9,944)		--		9,944		--
Other, net		56		--		--		56

Total other income (expense)		(63,631)		(18,036)		9,944		(71,723)

Income (loss) before income taxes		(959,913)		(114,206)		9,140		(1,064,979)
Income tax benefit (expense)		11,536		--		--		11,536

Net income (loss)	$	(948,377)	$	(114,206)	$	9,140	$	(1,053,443)

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS


	For the Three Months Ended June 30, 2013
	MRD		MEMP		Other, Adjustments & Eliminations		Consolidated & Combined Totals


Revenues:
Oil & natural gas sales	$	56,796	$	89,673	$	--	$	146,469
Other revenues		109		501		(34)		576

Total revenues		56,905		90,174		(34)		147,045


Costs and expenses:
Lease operating		5,844		20,217		(74)		25,987
Pipeline operating		--		479		--		479
Exploration		69		48		--		117
Production and ad valorem taxes		3,803		4,967		--		8,770
Depreciation, depletion, and amortization		19,045		24,672		269		43,986
General and administrative		9,540		14,170		40		23,750
Accretion of asset retirement obligations		184		1,148		--		1,332
(Gain) loss on commodity derivative instruments		(18,050)		(36,079)		--		(54,129)
(Gain) loss on sale of properties		6,713		(885)		--		5,828
Other, net		(25)		623		--		598

Total costs and expenses		27,123		29,360		235		56,718

Operating income (loss)		29,782		60,814		(269)		90,327
Other income (expense):
Interest expense, net		(4,078)		(7,931)		--		(12,009)
Earnings from equity investments		12,937		--		(12,937)		--
Other, net		29		--		(1)		28

Total other income (expense)		8,888		(7,931)		(12,938)		(11,981)

Income (loss) before income taxes		38,670		52,883		(13,207)		78,346
Income tax benefit (expense)		--		(188)		--		(188)

Net income (loss)	$	38,670	$	52,695	$	(13,207)	$	78,158


	For the Six Months Ended June 30, 2014

	MRD		MEMP		Other, Adjustments & Eliminations		Consolidated & Combined Totals


Revenues:
Oil & natural gas sales	$	202,594	$	222,546	$	--	$	425,140
Other revenues		556		1,741		(45)		2,252

Total revenues		203,150		224,287		(45)		427,392


Costs and expenses:
Lease operating		11,666		54,055		(45)		65,676
Pipeline operating		--		1,165		--		1,165
Exploration		1,080		210		--		1,290
Production and ad valorem taxes		6,923		12,660		--		19,583
Depreciation, depletion, and amortization		67,946		61,902		1,611		131,459
Incentive unit compensation expense		943,840		--		--		943,840
General and administrative		19,319		20,546		--		39,865
Accretion of asset retirement obligations		325		2,723		--		3,048
(Gain) loss on commodity derivative instruments		15,960		185,112		--		201,072
(Gain) loss on sale of properties		3,057		--		--		3,057
Other, net		--		(12)		--		(12)

Total costs and expenses		1,070,116		338,361		1,566		1,410,043

Operating income (loss)		(866,966)		(114,074)		(1,611)		(982,651)
Other income (expense):
Interest expense, net		(34,469)		(34,114)		--		(68,583)
Loss on extinguishment of debt		(37,248)		--		--		(37,248)
Earnings from equity investments		(12,930)		--		12,930		--
Other, net		87		--		--		87

Total other income (expense)		(84,560)		(34,114)		12,930		(105,744)

Income (loss) before income taxes		(951,526)		(148,188)		11,319		(1,088,395)
Income tax benefit (expense)		11,511		(75)		--		11,436

Net income (loss)	$	(940,015)	$	(148,263)	$	11,319	$	(1,076,959)

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS


	For the Six Months Ended June 30, 2013

	MRD		MEMP		Other, Adjustments & Eliminations		Consolidated & Combined Totals

Revenues:
Oil & natural gas sales	$	110,834	$	157,261	$	--	$	268,095
Other revenues		233		1,015		(117)		1,131

Total revenues		111,067		158,276		(117)		269,226


Costs and expenses:
Lease operating		10,921		41,588		(158)		52,351
Pipeline operating		--		949		--		949
Exploration		698		275		--		973
Production and ad valorem taxes		7,209		8,847		--		16,056
Depreciation, depletion, and amortization		42,129		45,063		--		87,192
General and administrative		14,813		21,483		40		36,336
Accretion of asset retirement obligations		369		2,293		--		2,662
(Gain) loss on commodity derivative instruments		(8,574)		(23,010)		--		(31,584)
(Gain) loss on sale of properties		6,713		(2,868)		--		3,845
Other, net		(25)		597		26		598

Total costs and expenses		74,253		95,217		(92)		169,378

Operating income (loss)		36,814		63,059		(25)		99,848
Other income (expense):
Interest expense, net		(6,906)		(14,473)		--		(21,379)
Earnings from equity investments		10,814		--		(10,814)		--
Other, net		32		--		25		57

Total other income (expense)		3,940		(14,473)		(10,789)		(21,322)

Income before income taxes		40,754		48,586		(10,814)		78,526
Income tax benefit (expense)		--		(188)		--		(188)

Net income (loss)	$	40,754	$	48,398	$	(10,814)	$	78,338

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 June 30, 2014 and December 31, 2013, we had $2.6 million and $0.6 million of environmental reserves recorded on our balance sheets, respectively. During the six months ended June 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.

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 June 30, 2014 (in thousands):


Investment	Amortized Cost

U.S. Bank Money Market Cash Equivalent	$	132,003
Less: Outside working interest owners share		(63,690)

	$	68,313

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


June 30, 2014	$	68,310
June 30, 2015	$	72,450
June 30, 2016	$	76,590
December 31, 2016	$	78,660

As of June 30, 2014, the maximum remaining obligation net to REO’s interest was approximately $10.3 million.

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 June 30, 2014 were as follows (in thousands):


	Dubach		Dubberly

2014	$	6,892	$	2,872
2015		13,671		11,393
2016		13,709		11,424
2017		13,671		11,393
2018		12,772		10,643

Total	$	60,715	$	47,725

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Related Party Agreements

On March 17, 2014, WildHorse Resources entered into a gas processing agreement with PennTex. 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. 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

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. In conjunction with the closing of the offer and sale of the MRD Senior Notes, the borrowing base under MRD’s revolving credit facility was automatically decreased by $56.5 million.

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.

MEMP July 2014 Third-Party Acquisition

On July 1, 2014, MEMP acquired certain oil and natural gas liquids properties in Wyoming (the “Acquisition”) from Merit Energy Company, LLC and certain of its affiliates for an aggregate adjusted purchase price of approximately $915.1 million, subject to customary post-closing adjustments. The Acquisition had an effective date of April 1, 2014. In conjunction with the closing of the Acquisition, the borrowing base under MEMP’s revolving credit facility was increased from $870 million to $1.44 billion. The Acquisition was funded with borrowings under MEMP’s revolving credit facility.

MEMP 2014 Equity Offering

On July 15, 2014, MEMP issued 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 public at an offering price of $22.25 per unit generating total net proceeds of approximately $220.3 million after deducting underwriting discounts and commissions but before estimated 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.

MEMORIAL RESOURCE DEVELOPMENT CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

MEMP 6.875% Senior Unsecured Notes Offering

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. In conjunction with the closing of the offer and sale of the 2022 Senior Notes, the borrowing base under MEMP’s revolving credit facility was automatically decreased from $1.44 billion to $1.315 billion.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS.

Management’s Discussion and Analysis of Financial Condition and Results of Operations 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.

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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.

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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 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 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

MRD Segment

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. We received net proceeds of approximately $380.7 million, after deducting underwriting discounts and commissions and fees and expenses associated with the offering and the restructuring transactions entered into in connection with the offering. We used approximately $360.0 million of our initial public offering proceeds to redeem the PIK notes on June 27, 2014. In addition, MRD Holdco sold 27,720,000 shares of our common stock in our initial public offering as a selling stockholder. We did not receive any proceeds from the sale of shares by MRD Holdco. For more information regarding the restructuring transactions entered into in connection with our initial public offering, see Note 1 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under Item 1 of this quarterly report.

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 net proceeds of approximately $586.0 million, after deducting the initial purchasers’ discounts and commissions and estimated offering expenses, were used to repay a portion of the borrowings outstanding under our revolving credit facility. The amounts to be repaid under our revolving credit facility were incurred to repay the amounts outstanding under WildHorse Resources’ credit facilities in connection with the closing of our initial public offering. In conjunction with the closing of the offer and sale of the MRD Senior Notes, the borrowing base under MRD’s revolving credit facility was automatically decreased by $56.5 million.

MEMP Segment

On July 1, 2014, MEMP acquired certain oil and natural gas liquids properties in Wyoming (the “Acquisition”) from Merit Energy Company, LLC and certain of its affiliates (“Merit”) for an aggregate adjusted purchase price of approximately $915 million, subject to customary post-closing adjustments. The Acquisition had an effective date of April 1, 2014. In conjunction with the closing of the Acquisition, the borrowing base under MEMP’s revolving credit facility was increased from $870 million to $1.44 billion. The Acquisition was funded with borrowings under MEMP’s revolving credit facility.

On July 15, 2014, MEMP issued 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 public at an offering price of $22.25 per unit generating total net proceeds of approximately $220.3 million after deducting underwriting discounts and commissions but before estimated offering expenses. The net proceeds from this equity offering were used to repay a portion of the outstanding borrowings under MEMP’s revolving credit facility.

On July 17, 2014, MEMP and its wholly-owned subsidiary Memorial Production Finance Corporation (“Finance Corp.” and, together with MEMP, the “MEMP Issuers”) completed a private placement of $500.0 million aggregate principal amount of 6.875% senior unsecured notes due 2022 (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 the 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 net proceeds 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 borrowings outstanding under MEMP’s revolving credit facility and for general partnership purposes. In conjunction with the closing of the offer and sale of the 2022 Senior Notes, the borrowing base under MEMP’s revolving credit facility was automatically decreased from $1.440 billion to $1.315 billion.

Sources of Revenues

Both the MRD Segment’s and the 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

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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.

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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.

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

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Impairment of unproved and 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.

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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.

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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.

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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.

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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.

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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.

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 six months ended June 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 June 30,				For Six Months Ended June 30,
	2014		2013		2014		2013
	(in thousands)

Oil & natural gas sales	$	235,223	$	146,469	$	425,140	$	268,095
Lease operating		31,994		25,987		65,676		52,351
Exploration		1,144		117		1,290		973
Production and ad valorem taxes		10,999		8,770		19,583		16,056
Depreciation, depletion, and amortization		73,780		43,986		131,459		87,192
Incentive unit compensation expense		942,817		--		943,840		--
General and administrative		22,126		23,750		39,865		36,336
(Gain) loss on commodity derivative instruments		141,590		(54,129)		201,072		(31,584)
(Gain) loss on sale of properties		3,167		5,828		3,057		3,845
Interest expense, net		34,531		12,009		68,583		21,379
Loss on extinguishment of debt		37,248		--		37,248		--
Net income (loss)		(1,053,443)		78,158		(1,076,959)		78,338

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

A net loss of $1.1 billion was generated for the three months ended June 30, 2014 compared to net income of $78.2 million for the three months ended June 30, 2013. The net loss recorded during 2014 was primarily due to compensation expense recognized associated with incentive units as discussed below.

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Oil, natural gas and NGL revenues for 2014 totaled $235.2 million, an increase of $88.8 million compared with 2013. Production increased 12,712 MMcfe (approximately 50%) primarily due to acquisitions and drilling activities in North Louisiana and East Texas. The average realized sales price increased $0.40 per Mcfe primarily due to higher natural gas prices. The favorable volume and pricing variance contributed to an approximate $73.6 million and $15.2 million increase in revenues, respectively.

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Lease operating expenses were $32.0 million and $26.0 million for 2014 and 2013, respectively. On a per Mcfe basis, lease operating expenses decreased to $0.84 for 2014 from $1.03 for 2013.

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DD&A expense for 2014 was $73.8 million compared to $44.0 million for 2013, a $29.8 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 $7.7 million.

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Incentive unit compensation expense for 2014 was $942.8 million, of which $831.1 million related to WildHorse Resources incentive units and $111.8 million related to MRD Holdco incentive units. 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.

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General and administrative expenses for 2014 were $22.1 million compared to $23.8 million for 2013. General and administrative expenses for 2014 included $1.8 million of compensation expense associated with long-term incentive plans and $1.6 million of acquisition-related costs. General and administrative expenses for 2013 included $5.8 million recorded by Tanos associated with incentive units forfeited, $0.7 million of compensation expense associated with long-term incentive plans, and $1.8 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.

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Net losses on commodity derivative instruments of $141.6 million were recognized during 2014, consisting of $11.3 million of cash settlement payouts in addition to a $130.3 million decline in the fair value of open hedge positions. Net gain on commodity derivative instruments of $54.1 million were recognized during 2013, consisting of $5.1 million of cash settlement receipts in addition to a $49.0 million increase in the fair value of open hedge positions.

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

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Interest expense was $34.5 million during 2014, an increase of $22.5 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 PIK notes and MEMP’s 2021 Senior Notes carry a higher interest rate compared to debt under revolving credit facilities.

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

Six Months Ended June 30, 2014 Compared to the Six Months Ended June 30, 2013

A net loss of $1.1 billion was generated for the six months ended June 30, 2014 compared to net income of $78.3 million for six months ended June 30, 2013. The net loss recorded during 2014 was primarily due to compensation expense recognized associated with incentive units as discussed below.

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Oil, natural gas and NGL revenues for 2014 totaled $425.1 million, an increase of $157.0 million compared with 2013. Production increased 20,510 MMcfe (approximately 43%) primarily due to acquisitions and drilling activities in North Louisiana and East Texas. The average realized sales price increased $0.61 per Mcfe primarily due to higher natural gas prices. The favorable volume and pricing variance contributed to an approximate $115.4 million and $41.6 million increase in revenues, respectively.

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Lease operating expenses were $65.7 million and $52.4 million for 2014 and 2013, respectively. On a per Mcfe basis, lease operating expenses decreased to $0.96 for 2014 from $1.10 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 $131.5 million compared to $87.2 million for 2013, a $44.3 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 $37.6 million and the change in the DD&A rate between periods caused DD&A expense to increase by an approximate $6.7 million.

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Incentive unit compensation expense for 2014 was $943.8 million, of which $831.1 million related to WildHorse Resources incentive units, $111.8 million related to MRD Holdco incentive units, and $1.0 million related to BlueStone incentive units. 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.

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General and administrative expenses for 2014 were $39.9 million compared to $36.3 million for 2013. General and administrative expenses for 2014 included $3.1 million of compensation expense associated with long-term incentive plans and $4.1 million of acquisition-related costs. General and administrative expenses for 2013 included $5.8 million recorded by Tanos associated with incentive units forfeited, $1.1 million of compensation expense associated with long-term incentive plans and $2.1 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 $201.1 million were recognized during 2014, consisting of $24.5 million of cash settlement payouts in addition to a $176.6 million decline in the fair value of open hedge positions. Net gain on commodity derivative instruments of $31.6 million were recognized during 2013, consisting of $16.2 million of cash settlement receipts in addition to a $15.4 million increase in the fair value of open hedge positions.

—

Interest expense was $68.6 million during 2014, an increase of $47.2 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 PIK notes, the $325.0 million second lien term facility at WildHorse Resources, and MEMP’s 2021 Senior Notes carry a higher interest rate compared to debt under revolving credit facilities.

—

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

MRD Segment

The MRD Segment’s consolidated and combined results of operations for the three and six months ended June 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: (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.


	For Three Months Ended June 30,				For Six Months Ended June 30,

	2014		2013		2014		2013

	(in thousands)

Oil & natural gas sales	$	112,976	$	56,796	$	202,594	$	110,834
Lease operating		5,957		5,844		11,666		10,921
Exploration		940		69		1,080		698
Production and ad valorem taxes		3,923		3,803		6,923		7,209
Depreciation, depletion, and amortization		37,819		19,045		67,946		42,129
Incentive unit compensation cost		942,817		--		943,840		--
General and administrative		11,538		9,540		19,319		14,813
(Gain) loss on commodity derivative instruments		3,244		(18,050)		15,960		(8,574)
(Gain) loss on sale of properties		3,167		6,713		3,057		6,713
Interest expense, net		16,495		4,078		34,469		6,906
Loss on extinguishment of debt		37,248		--		37,248		--
Income tax benefit (expense)		11,536		--		11,511		--
Net income (loss)		(948,377)		38,670		(940,015)		40,754

Natural gas and oil revenue:
Oil sales	$	24,237	$	17,778	$	46,260	$	34,228
NGL sales		24,337		9,938		45,457		20,566
Natural gas sales		64,402		29,080		110,877		56,040

Total natural gas and oil revenue	$	112,976	$	56,796	$	202,594	$	110,834


Production Volumes:
Oil (MBbls)		247		173		479		345
NGLs (MBbls)		509		280		1,024		552
Natural gas (MMcf)		15,672		8,136		26,346		16,173

Total (MMcfe)		20,212		10,857		35,367		21,554

Average net production (MMcfe/d)		222.1		119.3		195.4		119.1


Average sales price:
Oil (per Bbl)	$	98.00	$	102.71	$	96.57	$	99.28
NGL (per Bbl)		47.79		35.44		44.37		37.25
Natural gas (per Mcf)		4.11		3.57		4.21		3.47

Total (Mcfe)	$	5.59	$	5.23	$	5.73	$	5.14


Average unit costs per Mcfe:
Lease operating expense	$	0.29	$	0.54	$	0.33	$	0.51
Production and ad valorem taxes	$	0.19	$	0.35	$	0.20	$	0.33
General and administrative expenses	$	0.57	$	0.88	$	0.55	$	0.69
Depletion, depreciation, and amortization	$	1.87	$	1.75	$	1.92	$	1.95

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

The MRD Segment recorded a net loss of $948.4 million during 2014 compared to net income of $38.7 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 $113.0 million, an increase of $56.2 million compared with 2013. Production increased 9,355 MMcfe (approximately 86%) primarily due to drilling activities in North Louisiana and East Texas. The average realized sales price increased $0.36 per Mcfe primarily due to higher natural gas and NGL prices. The favorable volume and pricing variance contributed to an approximate $48.9 million and $7.3 million increase in revenues, respectively.

—

Lease operating expenses were $6.0 million and $5.8 million for 2014 and 2013, respectively. On a per Mcfe basis, lease operating expenses decreased to $0.29 for 2014 from $0.54 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 $37.8 million compared to $19.0 million for 2013, a $18.8 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 $16.4 million and the change in the DD&A rate between periods caused DD&A expense to increase by approximately $2.4 million.

—

General and administrative expenses for 2014 were $11.5 million compared to $9.5 million for 2013. General and administrative expenses for 2014 included $0.2 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 $0.9 million of acquisition-related costs. Increased salaries and employee headcount also contributed to increased general and administrative expenses between periods.

—

Net losses on commodity derivative instruments of $3.2 million were recognized during 2014, consisting of $3.4 million of cash settlement payouts in addition to a $0.2 million increase in the fair value of open hedge positions. Net gains on commodity derivative instruments of $18.1 million were recognized during 2013, consisting of $1.8 million of cash settlement receipts in addition to a $16.3 million increase in the fair value of open hedge positions.

—

Net interest expense during 2014 was $16.5 million, including amortization of deferred financing fees of approximately $0.8 million and accretion of discount associated with the PIK notes of $0.3 million. Net interest expense during 2013 was $4.1 million, including amortization of deferred financing fees of approximately $0.6 million. The increase in net interest expense is primarily the result of higher level of indebtedness during 2014 compared to 2013, including the PIK notes and the $325.0 million second lien term facility at WildHorse Resources.

—

An extinguishment loss of $23.6 million was recognized related to the redemption of the PIK notes. An extinguishment loss of $13.7 million was recognized related to the termination of WildHorse Resources’ revolving credit facility and second lien term loan. For more information regarding our debt, see Note 8 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under Item 1 of this quarterly report.

—

We are organized as a taxable C corporation and subject to federal and certain state income taxes. We recorded a tax benefit of $11.6 million in June 2014 subsequent to our initial public offering.

Six Months Ended June 30, 2014 Compared to the Six Months Ended June 30, 2013

The MRD Segment recorded a net loss of $940.0 million during 2014 compared to net income of $40.8 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 $202.6 million, an increase of $91.8 million compared with 2013. Production increased 13,813 MMcfe (approximately 64%) primarily due to drilling activities in North Louisiana and East Texas. The average realized sales price increased $0.59 per Mcfe primarily due to higher natural gas and NGL prices. The favorable volume and pricing variance contributed to an approximate $71.0 million and $20.8 million increase in revenues, respectively.

—

Lease operating expenses were $11.7 million and $10.9 million for 2014 and 2013, respectively. On a per Mcfe basis, lease operating expenses decreased to $0.33 for 2014 from $0.51 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 $67.9 million compared to $42.1 million for 2013, a $25.8 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 $27.0 million and the change in the DD&A rate between periods caused DD&A expense to decrease by an approximate $1.2 million.

—

General and administrative expenses for 2014 were $19.3 million compared to $14.8 million for 2013. General and administrative expenses for 2014 included $0.2 million of compensation expense associated with the MRD LTIP and $1.1 million of acquisition-related costs. General and administrative expenses for 2013 included $1.0 million of acquisition-related costs. Increased salaries and employee headcount also contributed to increased general and administrative expenses between periods.

—

Net losses on commodity derivative instruments of $16.0 million were recognized during 2014, consisting of $8.6 million of cash settlement payouts in addition to a $7.4 million decline in the fair value of open hedge positions. Net gains on commodity derivative instruments of $8.6 million were recognized during 2013, consisting of $5.8 million of cash settlement receipts in addition to a $2.8 million increase in the fair value of open hedge positions.

—

Net interest expense during 2014 was $34.5 million, including amortization of deferred financing fees of approximately $1.9 million and accretion of discount associated with the PIK notes of $0.6 million. Net interest expense during 2013 was $6.9 million, including amortization of deferred financing fees of approximately $1.0 million. The increase in net interest expense is primarily the result of higher level of indebtedness during 2014 compared to 2013, including the PIK notes and the $325.0 million second lien term facility at WildHorse Resources.

—

We are organized as a taxable C corporation and subject to federal and certain state income taxes. We recorded a tax benefit of $11.6 million in June 2014 subsequent to our initial public offering.

MEMP Segment

The MEMP Segment’s consolidated and combined results of operations for the three and six months ended June 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 $169.1 million.


	For Three Months Ended June 30,				For Six Months Ended June 30,

	2014		2013		2014		2013

	(in thousands)

Oil & natural gas sales	$	122,247	$	89,673	$	222,546	$	157,261
Lease operating		26,067		20,217		54,055		41,588
Exploration		204		48		210		275
Production and ad valorem taxes		7,076		4,967		12,660		8,847
Depreciation, depletion, and amortization		35,157		24,672		61,902		45,063
General and administrative		10,588		14,170		20,546		21,483
(Gain) loss on commodity derivative instruments		138,346		(36,079)		185,112		(23,010)
(Gain) loss on sale of properties		--		(885)		--		(2,868)
Interest expense, net		18,036		7,931		34,114		14,473
Net income		(114,206)		52,695		(148,263)		48,398

Natural gas and oil revenue:
Oil sales	$	60,913	$	44,822	$	102,708	$	79,059
NGL sales		15,254		12,484		29,021		22,149
Natural gas sales		46,080		32,367		90,817		56,053

Total natural gas and oil revenue	$	122,247	$	89,673	$	222,546	$	157,261


Production Volumes:
Oil (MBbls)		617		470		1,070		843
NGLs (MBbls)		524		416		944		704
Natural gas (MMcf)		10,965		9,129		20,677		16,776

Total (MMcfe)		17,806		14,456		32,758		26,070

Average net production (MMcfe/d)		195.7		158.9		181.0		144.0


Average sales price:
Oil (per Bbl)	$	98.81	$	95.26	$	96.04	$	93.78
NGL(per Bbl)		29.13		29.93		30.74		31.46
Natural gas (per Mcf)		4.20		3.55		4.39		3.34

Total (Mcfe)	$	6.87	$	6.20	$	6.79	$	6.03


Average unit costs per Mcfe:
Lease operating expense	$	1.46	$	1.40	$	1.65	$	1.60
Production and ad valorem taxes	$	0.40	$	0.34	$	0.39	$	0.34
General and administrative expenses	$	0.59	$	0.98	$	0.63	$	0.82
Depletion, depreciation, and amortization	$	1.97	$	1.71	$	1.89	$	1.73

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

A net loss of $114.2 million was generated for the three months ended June 30, 2014, primarily due to losses on commodity derivative instruments, as discussed below. Net income of $52.7 million was generated for three months ended June 30, 2013.

—

Oil, natural gas and NGL revenues for 2014 totaled $122.2 million, an increase of $32.6 million compared with 2013. Production increased 3,350 MMcfe (approximately 23%), primarily from new drills in East Texas and increased volumes from third party acquisitions. The average realized sales price increased $0.67 per Mcfe primarily due to higher natural gas and crude oil prices. The favorable volume and pricing variance contributed to an approximate $20.8 million and $11.8 million increase in revenues, respectively.

—

Lease operating expenses were $26.1 million and $20.2 million for 2014 and 2013, respectively. On a per Mcfe basis, lease operating expenses increased to $1.46 for 2014 from $1.40 for 2013. This increase was primarily due to the acquisition of new assets.

—

Production and ad valorem taxes for 2014 totaled $7.1 million, an increase of $2.1 million compared with 2013 primarily due to an increase in production volumes. On a per Mcfe basis, production and ad valorem taxes increased to $0.40 for 2014 from $0.34 for 2013.

—

DD&A expense for 2014 was $35.2 million compared to $24.7 million for 2013, a $10.5 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 $5.8 million and the change in the DD&A rate between periods caused DD&A expense to increase by an approximately $4.7 million.

—

General and administrative expenses for 2014 were $10.6 million. General and administrative expenses for 2014 included $1.7 million of non-cash unit-based compensation expense and $1.1 million of acquisition-related costs. General and administrative expenses for 2013 totaled $14.2 million. General and administrative expenses for 2013 included $0.7 million of non-cash unit-based compensation expense and $0.9 million of acquisition-related costs. The $3.6 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 $138.3 million were recognized during 2014, consisting of $7.9 million of cash settlement payouts in addition to a $130.4 million decline in the fair value of open hedge positions. Net gains on commodity derivative instruments of $36.1 million were recognized during 2013, consisting of $3.3 million of cash settlement receipts in addition to a $32.8 million increase in the fair value of open hedge positions.

—

Net interest expense totaled $18.0 million during 2014, including losses on interest rate swaps of approximately $0.8 million, amortization of deferred financing fees of approximately $0.9 million, and accretion of net discount associated with the senior notes of $0.4 million. Net interest expense totaled $7.9 million during 2013, including gains on interest rate swaps of $1.7 million and 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 MEMP’s senior notes issued in April, May and October 2013.

Six Months Ended June 30, 2014 Compared to the Six Months Ended June 30, 2013

A net loss of $148.3 million was generated for the six months ended June 30, 2014, primarily due to losses on commodity derivative instruments, as discussed below. Net income of $48.4 million was generated for the six months ended June 30, 2013.

—

Oil, natural gas and NGL revenues for 2014 totaled $222.5 million, an increase of $65.3 million compared with 2013. Production increased 6,688 MMcfe (approximately 26%), primarily from new drilling activities and increased volumes from third party acquisitions. The average realized sales price increased $0.76 per Mcfe primarily due to higher gas prices. The favorable volume and pricing variance contributed to an approximate $40.4 million and $24.9 million increase in revenues, respectively.

—

Lease operating expenses were $54.1 million and $41.6 million for the six months ended June 30, 2014 and 2013, respectively. On a per Mcfe basis, lease operating expenses increased to $1.65 for 2014 from $1.60 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 $12.7 million, an increase of $3.8 million compared with 2013 primarily due to an increase in production volumes. On a per Mcfe basis, production and ad valorem taxes increased to $0.39 for 2014 from $0.34 for 2013.

—

DD&A expense for 2014 was $61.9 million compared to $45.1 million for 2013, a $16.8 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 $11.6 million and the change in the DD&A rate between periods caused DD&A expense to increase by an approximate $5.2 million.

—

General and administrative expenses for 2014 were $20.5 million. General and administrative expenses for 2014 included $3.0 million of non-cash unit-based compensation expense and $3.0 million of acquisition-related costs. General and administrative expenses for 2013 totaled $21.5 million. General and administrative expenses for 2013 included $1.1 million of non-cash unit-based compensation expense and $1.1 million of acquisition-related costs. The $1.0 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 $185.1 million were recognized during 2014, consisting of $15.9 million of cash settlement payouts in addition to a $169.2 million decline in the fair value of open hedge positions. Net gains on commodity derivative instruments of $23.0 million were recognized during 2013, consisting of $10.4 million of cash settlement receipts, in addition to a $12.6 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 $34.1 million during 2014, including losses on interest rate swaps of approximately $1.1 million, amortization of deferred financing fees of approximately $1.7 million, and accretion of net discount associated with the senior notes of $0.7 million. Net interest expense totaled $14.5 million during 2013, including gains on interest rate swaps of $1.7 million and amortization of deferred financing fees of approximately $3.8 million. The increase in net interest expense is primarily the result of higher level of indebtedness during 2014 compared to 2013, including MEMP’s senior notes issued in April, May and October 2013.

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 June 30, 2014, our liquidity of $121.6 million consisted of $15.6 million of cash and cash equivalents and $106.0 million of available borrowings under our revolving credit facility. On July 10, 2014, the net proceeds of approximately $586.0 million from the issuance of the MRD Senior Notes were used to repay a portion of the borrowings outstanding under our revolving credit facility, the borrowing base under MRD’s revolving credit facility was automatically decreased by $56.5 million in connection with the issuance of the MRD Senior Notes, and our liquidity increased by approximately $529.5 million. As of August 1, 2014, our liquidity of $637.2 million consisted of approximately $13.7 million of cash and cash equivalents and $623.5 million of available borrowings under our revolving credit facility. As of June 30, 2014, we had a working capital balance of $13.3 million.

Capital Budget

In 2014, a total of $351 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 million on drilling 43 gross (37 net) horizontal wells and 3 gross (2.7 net) vertical wells.

For the six months ended June 30, 2014, our total capital expenditures were $166.4 million and related to drilling, recompletions and capital workovers. We spent approximately 78% in the Terryville Complex, 12% in East Texas, and 10% 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. In connection with the issuance of the MRD Senior Notes (discussed below), the borrowing base under our revolving credit facility was automatically decreased by approximately $56.5 million.

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

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.

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 (Redeemed)

WildHorse Resources Revolving Credit Facility and Second Lien Facility (Terminated)

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.

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.

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.

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.

2022 Senior Notes

On July 17, 2014, the MEMP Issuers issued the 2022 Senior Notes as previously discussed under “—Significant Recent Developments—MEMP Segment” included within this Item 2.

For additional information regarding the 2022 Senior Notes, see Note 16 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 June 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 June 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 had 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.

MRD Segment


	For Six Months Ended June 30,

	2014		2013

Net cash provided by operating activities	$	81,695	$	81,266

Net cash used in investing activities:
Acquisition of oil and natural gas properties	$	--	$	(67,098)
Additions to oil and gas properties		(175,951)		(74,028)
Additions to other property and equipment		(1,268)		(223)
Equity investments in MEMP Segment		(14)		(189)
Distributions received from MEMP Segment related to partnership interests		6,005		12,711
Decrease (increase) in restricted cash		49,946		907
Proceeds from the sale of oil and gas properties to third parties		6,700		32,937
Other		(301)		--

Net cash provided by (used in) investing activities	$	(114,883)	$	(94,983)


Net cash provided by financing activities
Advances on revolving credit facilities	$	1,130,800	$	144,400
Payments on revolving credit facilities		(714,900)		(188,004)
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		(5,644)		(12,435)
Purchase of additional interests in consolidated subsidiaries		(3,292)		--
Proceeds from initial public offering		408,500		--
Costs incurred in conjunction with initial public offering		(26,875)		--
Contribution from NGP affiliates related to sale of properties		1,165		--
Contributions from MEMP Segment		33,880		76,304
Distributions to Funds		--		(300,000)
Distributions to MRD Holdco		(59,803)		--
Distributions to noncontrolling interest		(325)		--
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		--		(1,169)
Other		270		(5,307)

Net cash provided by (used in) financing activities	$	(15,777)	$	38,789

Six months Ended June 30, 2014 Compared to the Six months Ended June 30, 2013

Operating Activities. Net cash flows provided by operating activities were $81.7 million during 2014 compared to $81.3 million during 2013. Production increased 13,813 MMcfe (approximately 64%) and average realized sales price increased $0.59 per Mcfe as previously discussed under “—Results of Operations—MRD Segment.” Cash paid for interest during 2014 was $34.3 million compared to $4.6 million during 2013. During 2014, compensation expense of approximately $26.7 million was paid in cash related to WildHorse Resources’ incentive units.

Investing Activities. Total cash used in investing activities was $114.9 million during 2014 compared to $95.0 million for the same period in 2013. Cash used for additions to oil and gas properties $175.9 million during 2014 compared to $74.0 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. 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 $6.0 million were received from MEMP primarily from the subordinated units owned by MRD LLC during 2014 compared to $12.7 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 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.

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. After deducting underwriting discounts and commissions of $23.0 million and additional estimated offering expenses of $4.8 million (including $0.9 million of accrued offering expenses), the net proceeds from our initial public offering were approximately $380.7 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 advances under revolving credit facilities were $415.9 million during 2014 compared to net repayments of $43.6 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 as discussed above under “Recent Developments—MRD Segment.” 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.

Distributions to NGP affiliates related to the purchase of assets 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 $20.9 to MRD LLC during 2013.

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 $300.0 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 and $75.0 million from the sale of properties to MEMP.

Deferred financing costs of approximately $5.6 million were incurred during 2014 compared to approximately $12.4 million during 2013.

MEMP Segment


	For Six Months Ended June 30,

	2014		2013

Net cash provided by operating activities	$	96,052	$	81,865

Net cash used in investing activities:
Acquisition of oil and natural gas properties	$	(173,000)	$	(6,310)
Additions to oil and gas properties		(117,616)		(88,629)
Additions to other property and equipment		--		(130)
Additions to restricted investments		(2,121)		(3,080)
Proceeds from the sale of oil and gas properties to third parties		--		4,525
Deposits for property acquisitions		(70,125)		--

Net cash provided by (used in) investing activities	$	(362,862)	$	(93,624)


Net cash provided by financing activities
Advances on revolving credit facilities	$	418,000	$	251,250
Payments on revolving credit facilities		(62,000)		(691,702)
Proceeds from the issuances of senior notes		--		397,563
Deferred financing costs		(590)		(11,224)
Contributions from previous owners		--		7,126
Contribution from NGP affiliate		--		2,013
Contribution from general partner		14		189
Net proceeds from public equity offering		--		171,779
Distributions to partners		(67,524)		(40,030)
Distributions to MRD Segment		(33,880)		(76,304)
Distributions made by previous owners		--		(2,272)

Net cash provided by (used in) financing activities	$	254,020	$	8,388

Operating Activities. Key drivers of net operating cash flows are commodity prices, production volumes and operating costs. Net income decreased by $196.7 million as further discussed above under “—Results of Operations—MEMP Segment,” and net cash provided by operating activities increased by $14.2 million. Cash paid for interest during 2014 was $31.3 million compared to $8.1 million during 2013. Net cash provided by operating activities included $6.4 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 $362.9 million, of which $173.0 million was used to acquire oil and natural gas properties from a third parties and $117.6 million was used for additions to oil and gas properties. Cash used in investing activities during 2013 was $93.6 million, of which $6.3 million was used to acquire oil and natural gas properties from a third party and $88.6 million was used for additions to oil and 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. MEMP made an earnest money deposit of $70.1 million during 2014 related to the Acquisition. Tanos received $4.5 million of proceeds from the sale of oil and gas properties during 2013.

Financing Activities. 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 $67.5 million compared to $40.0 million during 2013, of which the MRD Segment received $6.0 million during 2014 compared to $12.7 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.

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 $20.9 million to MRD LLC during 2013.

MEMP’s previous owners received contributions of $7.1 million during 2013, of which Tanos received $5.2 million from MRD LLC. Distributions made by MEMP’s previous owners totaled $2.3 million in 2013.

MEMP had net payments of $332.0 million under its revolving credit facility during 2013. Proceeds of $397.6 million from the 2021 Senior Notes during 2013 were used to repay borrowings outstanding under MEMP’s revolving credit facility. Tanos and the previous owners had aggregate advances of $13.3 million under their credit facilities and repaid an aggregate of $32.4 million of outstanding borrowings during 2013. MEMP had net borrowings of $356.0 million under its revolving credit facility during 2014 that were used primarily used to fund its Eagle Ford acquisition, its drilling program, and the earnest money deposit for the Acquisition. Deferred financing costs of approximately $0.6 million were incurred during 2014 compared to approximately $11.2 million during 2013.

Contractual Obligations

During the six months ended June 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 borrowings and repayments under revolving credit facilities, the redemption of the PIK notes, and the repayment and termination of WildHorse Resources’ revolving and second lien credit facilities.

Off–Balance Sheet Arrangements

As of June 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.

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 June 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 June 30, 2014 and subsequently terminated on July 1, 2014.

At June 30, 2014, we had $619.0 million of Eurodollar borrowings outstanding under our revolving credit facility, with an interest rate of LIBOR plus 2.25%, or 2.40%. Assuming no change in the amount of debt outstanding, the impact on interest expense of a 10% increase or decrease in the in the variable component of the stated interest rates would be less than $0.1 million per year.

The fair value of MEMP’s 2021 Senior Notes is sensitive to changes in interest rates. We estimate the fair value of the 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):


	June 30, 2014
Description	Carrying Amount		Estimated Fair Value

MEMP Segment:

7.625% senior notes, fixed-rate, due May 1, 2021	$	689,806	$	735,000

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.

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 June 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 June 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 June 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.

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.

On June 12, 2014, the SEC declared effective our Registration Statement on Form S-1 (File No. 333-195062) relating to our initial public offering. On June 18, 2014, we sold 21,500,000 shares of our common stock and MRD Holdco, as selling stockholder, sold 27,720,000 shares of our common stock (including 6,420,000 shares of our common stock in connection with the full exercise of the underwriters’ over-allotment option) at an initial public offering price of $19.00 per share. We received no proceeds from the sale of shares by MRD Holdco. Citigroup Global Markets Inc., Barclays Capital Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, BMO Capital Markets Corp., Goldman, Sachs & Co., Raymond James & Associates, Inc., RBC Capital Markets, LLC and Wells Fargo Securities, LLC acted as joint book-running managers. Simmons & Company International, Credit Suisse Securities (USA) LLC, Morgan Stanley & Co. LLC, Scotia Capital (USA) Inc., Stephens Inc., Stifel, Nicolaus & Company, Incorporated, UBS Securities LLC, Wunderlich Securities, Inc., Comerica Securities, Inc., and Mitsubishi UFJ Securities (USA), Inc. acted as co-managers. After deducting underwriting discounts and commissions of $23.0 million and additional estimated offering expenses of $4.8 million, the net proceeds from our initial public offering were approximately $380.7 million. No offering expenses were paid directly or indirectly to any of our directors or officers (or their associates), persons owning ten percent or more of our common stock, or to any affiliates. The net proceeds from our initial public equity offering were primarily used to redeem the PIK notes. 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 net proceeds from our equity offering were also used to partially fund the $30.0 million received by former management members of WildHorse Resources on June 18, 2014.

(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.

ITEM 6.

EXHIBITS.


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	—	Credit Agreement by and among Memorial Resource Development Corp., as the Borrower, the Lenders party thereto, Bank of America, N.A., as Administrative Agent and Collateral Agent, and the other parties party thereto, dated as of June 18, 2014 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (File No. 001-36490) filed on June 24, 2014).

10.3	—	Voting Agreement among Memorial Resource Development Corp., MRD Holdco LLC and certain former management members of WildHorse Resources, LLC, dated as of June 18, 2014 (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K (File No. 001-36490) filed on June 24, 2014).

10.4	—	Services Agreement among Memorial Resource Development Corp., WildHorse Resources, LLC and WildHorse Resources Management Company, LLC, dated as of June 18, 2014 (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K (File No. 001-36490) filed on June 24, 2014).

10.5	—	Registration Rights Agreement among Memorial Resource Development Corp. and certain stockholders, dated as of June 18, 2014 (incorporated by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K (File No. 001-36490) filed on June 24, 2014).


10.6	—	Contribution Agreement among Memorial Resource Development LLC, MRD Holdco LLC and Memorial Resource Development Corp., dated as of June 18, 2014 (incorporated by reference to Exhibit 10.5 to the Company’s Current Report on Form 8-K (File No. 001-36490) filed on June 24, 2014).

10.7	—	Contribution Agreement among the former management members of WildHorse Resources, LLC party thereto and Memorial Resource Development Corp., dated as of June 18, 2014 (incorporated by reference to Exhibit 10.6 to the Company’s Current Report on Form 8-K (File No. 001-36490) filed on June 24, 2014).

10.8	—	Agreement and Plan of Merger merging Memorial Resource Development LLC with and into MRD Operating LLC, dated as of June 18, 2014 (incorporated by reference to Exhibit 10.7 to the Company’s Current Report on Form 8-K (File No. 001-36490) filed on June 24, 2014).

10.9	—	Purchase Agreement and Assignment between WildHorse Resources, LLC and WildHorse Resources II, LLC, dated as of June 18, 2014 (incorporated by reference to Exhibit 10.8 to the Company’s Current Report on Form 8-K (File No. 001-36490) filed on June 24, 2014).

10.10#	—	Form of Indemnification Agreement between Memorial Resource Development Corp. and each of the officers and directors thereof (incorporated by reference to Exhibit 10.9 to the Company’s Current Report on Form 8-K (File No. 001-36490) filed on June 24, 2014).

10.11#	—	Form of Change in Control Agreement (incorporated by reference to Exhibit 10.10 to the Company’s Current Report on Form 8-K (File No. 001-36490) filed on June 24, 2014).

10.12#	—	Form of Restricted Stock Agreement (incorporated by reference to Exhibit 10.11 to the Company’s Current Report on Form 8-K (File No. 001-36490) filed on June 24, 2014).

10.13	—	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).

10.14	—	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).

10.15	—	Service Agreement, dated as of May 1, 2014 between Classic Hydrocarbons Operating, LLC and Classic Pipeline & Gathering, LLC (incorporated by reference to Exhibit 10.11 to Amendment No. 2 to the Company’s Registration Statement on Form S-1 (File No. 333-195062), filed on May 27, 2014).

10.16	—	Water Disposal Agreement, dated as of May 1, 2014, between Classic Hydrocarbons Operating, LLC and Classic Pipeline & Gathering, LLC (incorporated by reference to Exhibit 10.12 to Amendment No. 2 to the Company’s Registration Statement on Form S-1 (File No. 333-195062), filed on May 27, 2014).

10.17	—	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).

10.18	—	Seventh Amendment to Credit Agreement, dated as of June 13, 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 June 19, 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.

** To be furnished by amendment within the 30-day grace period provided by Rule 405(a)(2) of Regulation S-T.

# 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.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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:	August 8, 2014	By:	/s/ Andrew J. Cozby
		Name:	Andrew J. Cozby
		Title:	Vice President and Chief Financial Officer

Delaware

46-4710769

(State or other jurisdiction of incorporation or organization)

(I.R.S. Employer Identification No.)

1301 McKinney, Suite 2100, Houston, TX

(Address of principal executive offices)

(Zip Code)