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 March 31, 2013

OR

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

For the transition period from        to       .

Commission File Number: 001-35364

MEMORIAL PRODUCTION PARTNERS LP

(Exact name of registrant as specified in its charter)

Delaware	90-0726667
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
1301 McKinney, Suite 2100, Houston, TX	77010
(Address of principal executive offices)	(Zip Code)

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

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

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

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

Large accelerated filer ¨	Accelerated filer þ
Non-accelerated filer ¨ (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 April 30, 2013, the registrant had 38,702,882 common units, 5,360,912 subordinated units and 44,112 general partner units outstanding.

MEMORIAL PRODUCTION PARTNERS LP

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 March 31, 2013 and December 31, 2012	9
Unaudited Condensed Statements of Consolidated and Combined Operations for the Three Months Ended March 31, 2013 and 2012	10
Unaudited Condensed Statements of Consolidated and Combined Cash Flows for the Three Months Ended March 31, 2013 and 2012	11
Unaudited Condensed Statements of Consolidated and Combined Equity for the Three Months Ended March 31, 2013 and 2012	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	14
Note 3 – Acquisitions and Divestitures	15
Note 4 – Fair Value Measurements of Financial Instruments	15
Note 5 – Risk Management and Derivative Instruments	17
Note 6 – Asset Retirement Obligations	20
Note 7 – Restricted Investments	20
Note 8 – Long Term Debt	20
Note 9 – Equity & Distributions	23
Note 10 – Earnings per Unit	24
Note 11 – Equity-based Awards	24
Note 12 – Related Party Transactions	24
Note 13 – Commitments and Contingencies	26
Item 2.          Management’s Discussion and Analysis of Financial Condition and Results of Operations.	28
Item 3.          Quantitative and Qualitative Disclosures About Market Risk.	38
Item 4.         Controls and Procedures.	39
PART II—OTHER INFORMATION
Item 1.         Legal Proceedings.	40
Item 1A.      Risk Factors.	40
Item 2.          Unregistered Sales of Equity Securities and Use of Proceeds.	42
Item 3.          Defaults Upon Senior Securities.	42
Item 4.         Mine Safety Disclosures.	42
Item 5.         Other Information.	42
Item 6.         Exhibits.	43
Signatures	45

i

GLOSSARY OF OIL AND NATURAL GAS TERMS

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

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

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

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

Bbl/d:  One Bbl per day.

Bcf:  One billion cubic feet of natural gas.

Bcfe:  One billion cubic feet of natural gas equivalent.

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

Boe/d:  One Boe per day.

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.

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.

1

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.

2

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.

3

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.

4

Standardized Measure:  The present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules, regulations or standards established by the United States Securities and Exchange Commission (“SEC”) and the Financial Accounting Standards Board (“FASB”) (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. Because we are a limited partnership, we are generally not subject to federal or state income taxes and thus make no provision for federal or state income taxes in the calculation of our standardized measure. 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.

5

NAMES OF ENTITIES

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

• “Memorial Production Partners,” “the Partnership,” “we,” “our,” “us” or like terms refer to Memorial Production Partners LP individually and collectively with its subsidiaries, as the context requires;

• “our general partner” refers to Memorial Production Partners GP LLC, our general partner;

• “Memorial Resource” refers collectively to Memorial Resource Development LLC and its subsidiaries other than the Partnership;

• “the previous owners” for accounting and financial reporting purposes refers collectively to (a) certain oil and natural gas properties the Partnership acquired from Memorial Resource in April and May 2012 for periods after common control commenced through their respective acquisition dates, (b) Rise Energy Operating, LLC and its wholly-owned subsidiaries (except for Rise Energy Operating, Inc.) (“REO”) from February 3, 2009 (inception) through the date of acquisition and (c) certain oil and natural gas properties and related assets in East Texas and North Louisiana (the “WHT properties”) owned by WHT Energy Partners LLC (“WHT”), an indirect wholly-owned subsidiary of Memorial Resource, for periods after April 8, 2011 through the date of acquisition;

• “the Funds” refers collectively to Natural Gas Partners VIII, L.P., Natural Gas Partners IX, L.P. and NGP IX Offshore Holdings, L.P.;

• “OLLC” refers to Memorial Production Operating LLC, our wholly-owned subsidiary through which we operate our properties;

• “Finance Corp.” refers to Memorial Production Finance Corporation, our wholly-owned subsidiary, whose activities are limited to co-issuing our debt securities and engaging in other activities incidental thereto; and

• “NGP” refers to Natural Gas Partners. The Funds, which are three of the private equity funds managed by NGP, collectively own 100% of Memorial Resource.

6

CAUTIONARY NOTE REGARDING FORWARD–LOOKING STATEMENTS

This Quarterly Report on Form 10-Q contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control, which may include statements about our:

• business strategies;

• ability to replace the reserves we produce through drilling and property acquisitions;

• drilling locations;

• oil and natural gas reserves;

• technology;

• realized oil and natural gas prices;

• production volumes;

• lease operating expenses;

• general and administrative expenses;

• future operating results;

• cash flows and liquidity;

• ability to procure drilling and production equipment;

• ability to procure oil field labor;

• planned capital expenditures and the availability of capital resources to fund capital expenditures;

• ability to access capital markets;

• marketing of oil and natural gas;

• expectations regarding general economic conditions;

• competition in the oil and natural gas industry;

• effectiveness of risk management activities;

• environmental liabilities;

• counterparty credit risk;

• expectations regarding governmental regulation and taxation;

• expectations regarding distributions and distribution rates;

• expectations regarding developments in oil-producing and natural-gas producing countries; and

• plans, objectives, expectations and intentions.

7

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

• our ability to generate sufficient cash to pay the minimum quarterly distribution or any other amount on our common units;

• our substantial future capital requirements, which may be subject to limited availability of financing;

• the uncertainty inherent in the development and production of oil and natural gas and in estimating reserves;

• our need to make accretive acquisitions or substantial capital expenditures to maintain our declining asset base;

• our ability to access funds on acceptable terms, if at all, because of the terms and conditions governing our indebtedness;

• potential shortages of drilling and production equipment;

• potential difficulties in the marketing of, and volatility in the prices for, oil and natural gas;

• uncertainties surrounding the success of our secondary and tertiary recovery efforts;

• competition in the oil and natural gas industry;

• general political and economic conditions, globally and in the jurisdictions in which we operate;

• the impact of legislation and governmental regulations, including those related to climate change, hydraulic fracturing and our status as a partnership for federal income tax purposes;

• the risk that our hedging strategy may be ineffective or may reduce our income;

• the cost and availability of insurance as well as operating risks that may not be covered by an effective indemnity or insurance;

• actions of third-party co-owners of interest in properties in which we also own an interest; and

• risks related to potential acquisitions, including our ability to make acquisitions on favorable terms or to integrate acquired properties.

The forward-looking statements contained in this 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 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 “Part I—Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2012 and “Part II—Item 1A. Risk Factors” appearing within this report and elsewhere in this report. All forward-looking statements speak only as of the date of this 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.

8

PART I—FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS.

MEMORIAL PRODUCTION PARTNERS LP

UNAUDITED CONDENSED CONSOLIDATED AND COMBINED BALANCE SHEETS

(In thousands, except outstanding units)

	March 31,		December 31,
	2013*		2012*
ASSETS
Current assets:
Cash and cash equivalents	$	8,347	$	7,990
Accounts receivable:
Oil and natural gas sales		19,770		17,017
Joint interest owners and other		849		1,427
Affiliates		3,712		8,497
Short-term derivative instruments		8,149		23,091
Prepaid expenses and other current assets		2,948		2,111
Total current assets		43,775		60,133
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method		1,061,019		1,038,962
Other		1,611		1,541
Accumulated depreciation, depletion and impairment		(191,290)		(178,135)
Oil and natural gas properties, net		871,340		862,368
Long-term derivative instruments		9,500		11,524
Restricted investments		69,306		68,024
Other long–term assets		3,680		4,141
Total assets	$	997,601	$	1,006,190
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	987	$	1,033
Accounts payable – affiliates		2,081		1,738
Revenues payable		2,851		3,108
Accrued liabilities		18,122		12,448
Short-term derivative instruments		4,499		2,635
Total current liabilities		28,540		20,962
Long-term debt		408,000		460,300
Asset retirement obligations		79,270		78,286
Long-term derivative instruments		6,564		9,577
Other long-term liabilities		2,057		2,101
Total liabilities		524,431		571,226
Commitments and contingencies (Note 13)
Equity:
Limited partners:
Common units (38,706,966 units outstanding at March 31, 2013 and 28,921,903 units outstanding at December 31, 2012)		450,919		301,204
Subordinated units (5,360,912 units outstanding at March 31, 2013 and December 31, 2012)		16,392		20,156
General partner (44,112 units outstanding at March 31, 2013 and 34,317 units outstanding at December 31, 2012)		602		450
Total partners’ equity		467,913		321,810
Noncontrolling interests		5,257		5,261
Previous owners		--		107,893
Total equity		473,170		434,964
Total liabilities and equity	$	997,601	$	1,006,190

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

*See Note 1 for information regarding recast amounts and basis of financial statement presentation.

9

MEMORIAL PRODUCTION PARTNERS LP

UNAUDITED CONDENSED STATEMENTS OF

CONSOLIDATED AND COMBINED OPERATIONS

(In thousands, except per unit amounts)

	For the Three Months Ended March 31,
	2013*		2012*
Revenues:
Oil & natural gas sales	$	44,035	$	43,289
Pipeline tariff income		305		334
Other income		--		110
Total revenues	$	44,340	$	43,733
Costs and expenses:
Lease operating		13,098		13,085
Pipeline operating		470		734
Exploration		95		--
Production and ad valorem taxes		2,287		2,481
Depreciation, depletion, and amortization		13,155		11,130
General and administrative		4,787		4,376
Accretion of asset retirement obligations		998		943
Realized (gain) loss on commodity derivative instruments		(5,694)		(8,628)
Unrealized (gain) loss on commodity derivative instruments		16,356		(14,532)
Other, net		--		125
Total costs and expenses		45,552		9,714
Operating income (loss)		(1,212)		34,019
Other income (expense):
Interest expense, net		(5,033)		(2,509)
Amortization of investment premium		--		(121)
Total other income (expense)		(5,033)		(2,630)
Income (loss) before income taxes		(6,245)		31,389
Income tax benefit (expense)		--		(183)
Net income (loss)		(6,245)		31,206
Net income (loss) attributable to previous owners		(1,219)		10,403
Net income (loss) attributable to noncontrolling interest		(4)		(91)
Net income (loss) attributable to partners	$	(5,022)	$	20,894
Allocation of net income (loss) attributable to partners:
Limited partners	$	(5,017)	$	20,873
General partner	$	(5)	$	21
Earnings per unit: (Note 10)
Basic and diluted earnings per unit	$	(0.14)	$	0.94
Weighted average limited partner units outstanding:
Basic and diluted		35,054		22,185

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

*See Note 1 for information regarding recast amounts and basis of financial statement presentation.

10

MEMORIAL PRODUCTION PARTNERS LP

UNAUDITED CONDENSED STATEMENTS OF

CONSOLIDATED AND COMBINED CASH FLOWS

(In thousands)

	For the Three Months     Ended March 31,
	2013*		2012*
Cash flows from operating activities:
Net income (loss)	$	(6,245)	$	31,206
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization		13,155		11,130
Unrealized (gain) loss on derivatives		15,818		(14,183)
Deferred income tax expense (benefit)		--		183
Amortization of loan origination costs		2,022		277
Amortization of investment premium		--		121
Accretion of asset retirement obligations		998		943
Amortization of equity awards		422		248
Exploration costs		95		--
Changes in operating assets and liabilities:
Accounts receivable		(2,175)		(7,435)
Accounts receivable - affiliates		4,785		5,026
Prepaid expenses and other assets		(700)		1,264
Accounts payable		(47)		(1,339)
Revenues payable		343		898
Accounts payable - affiliates		(256)		372
Accrued liabilities		(28)		3,006
Other		(42)		5
Net cash provided by operating activities		28,145		31,722
Cash flows from investing activities:
Additions to oil and gas properties		(16,845)		(17,955)
Additions to restricted investments		(1,281)		(1,128)
Additions to other property and equipment		(69)		(377)
Net cash used in investing activities		(18,195)		(19,460)
Cash flows from financing activities:
Advances on revolving credit facilities		217,000		7,000
Payments on revolving credit facilities		(269,300)		(3,500)
Loan origination fees		(1,670)		(17)
Proceeds from general partner contribution		180		-
Proceeds from the issuance of common units		179,371		-
Costs incurred in conjunction with issuance of common units		(7,050)		-
Distributions to partners		(17,424)		(2,048)
Distribution to Memorial Resource (see Note 1)		(110,700)		-
Distributions made by previous owners		--		(9,166)
Net cash used in financing activities		(9,593)		(7,731)
Net change in cash and cash equivalents		357		4,531
Cash and cash equivalents, beginning of period		7,990		9,624
Cash and cash equivalents, end of period	$	8,347	$	14,155
Supplemental cash flows:
Cash paid for interest	$	3,868	$	1,876
Additions to oil and gas properties – change in capital accruals		5,323		1,178
Accrued equity offering costs		348		--

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

*See Note 1 for information regarding recast amounts and basis of financial statement presentation.

11

MEMORIAL PRODUCTION PARTNERS LP

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED AND COMBINED EQUITY

(In thousands)

	Partner’s Equity
	Limited Partners				General		Previous		Noncontrolling
	Common		Subordinated		Partner		Owners		Interest		Total
Balance December 31, 2012*	$	301,204	$	20,156	$	450	$	107,893	$	5,261	$	434,964
Net income (loss)		(4,462)		(555)		(5)		(1,219)		(4)		(6,245)
Net proceeds from the issuance of common units		171,973		--		--		--		--		171,973
Contributions		--		--		180		--		--		180
Distribution attributable to net assets acquired (Note 1)		(97,137)		(13,452)		(111)		--		--		(110,700)
Net book value of net assets acquired (Note 12)		93,605		12,964		105		(106,674)		--		--
Amortization of equity awards		422		--		--		--		--		422
Distributions		(14,686)		(2,721)		(17)		--		--		(17,424)
Balance March 31, 2013*	$	450,919	$	16,392	$	602	$	--	$	5,257	$	473,170

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

*See Note 1 for information regarding recast amounts and basis of financial statement presentation.

12

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Note 1.  Organization and Basis of Presentation

General

Memorial Production Partners LP (the “Partnership”) is a publicly traded Delaware limited partnership, the common units of which are listed on the NASDAQ Global Market (“NASDAQ”) under the symbol “MEMP.” Unless the context requires otherwise, references to “we,” “us,” “our,” or “the Partnership” are intended to mean the business and operations of Memorial Production Partners LP and its consolidated subsidiaries.

The Partnership was formed in April 2011 by Memorial Resource Development LLC to own, acquire and exploit oil and natural gas properties in North America. Unless the context requires otherwise, references to “Memorial Resource” refer collectively to Memorial Resource Development LLC and its subsidiaries other than the Partnership. The Partnership is owned 99.9% by its limited partners and 0.1% by its general partner, Memorial Production Partners GP LLC, which is a wholly-owned subsidiary of Memorial Resource. Our general partner is responsible for managing all of the Partnership’s operations and activities.

We operate in one reportable segment engaged in the acquisition, exploitation, development and production of oil and natural gas properties. Our management evaluates performance based on one reportable business segment as there are not different economic environments within the operation of our oil and natural gas properties. Our business activities are conducted through Memorial Production Operating LLC (“OLLC”), our wholly-owned subsidiary, and its wholly-owned subsidiaries. Our assets consist primarily of producing oil and natural gas properties and are principally located in Texas, Louisiana and offshore Southern California. Most of our oil and natural gas properties are located in large, mature oil and natural gas reservoirs. The Partnership’s properties consist primarily of operated and non-operated working interests in producing and undeveloped leasehold acreage and working interests in identified producing wells (often referred to as wellbore assignments).

Memorial Production Finance Corporation (“Finance Corp.”), our wholly-owned subsidiary, has no material assets or any liabilities other than as a co-issuer of our debt securities and as a guarantor of certain of our other indebtedness. Its activities will be limited to co-issuing our debt securities and engaging in other activities incidental thereto.

Memorial Resource is a Delaware limited liability company owned and formed by Natural Gas Partners VIII, L.P., Natural Gas Partners IX, L.P. and NGP IX Offshore Holdings, L.P. (collectively, the “Funds”) to own, acquire, exploit and develop oil and natural gas properties and to own our general partner. Memorial Resource provides management, administrative, and operations personnel to us and our general partner under an omnibus agreement (see Note 12). The Funds are private equity funds managed by Natural Gas Partners (“NGP”). The Funds collectively directly own, through non-voting membership interests in our general partner, 50% of the economic interest in our incentive distribution rights (“IDRs”). The remaining economic interest in our IDRs is owned by our general partner.

References to “the previous owners” for accounting and financial reporting purposes refer collectively to: (i) certain oil and natural gas properties the Partnership acquired from Memorial Resource in April and May 2012 for periods after common control commenced through their respective acquisition dates, (ii) Rise Energy Operating, LLC and its wholly-owned subsidiaries (except for Rise Energy Operating, Inc.) (“REO”) from February 3, 2009 (inception) through the date of acquisition; and (iii) certain oil and natural gas properties and related assets in East Texas and North Louisiana (the “WHT properties”) owned by WHT Energy Partners LLC (“WHT”), an indirect wholly-owned subsidiary of Memorial Resource, for periods after April 8, 2011 through the date of acquisition. Each of these acquisitions was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the net assets acquired was recorded at historical cost and certain financial and other information has been retrospectively revised to give effect to such acquisitions as if the Partnership owned the assets for periods after common control commenced through their respective acquisition dates. The WHT properties represent additional working interests in properties that we originally acquired in December 2011 in conjunction with our initial public offering. See Note 12 for additional information regarding these common control transactions.

13

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Basis of Presentation

Our consolidated results of operations are presented together with the combined results of operations pertaining to the previous owners. The combined financial statements of the previous owners were derived from their historical accounting records and reflect their historical financial position, results of operations and cash flows.

The ownership interest of the noncontrolling shareholder in the San Pedro Bay Pipeline Company (“SPBPC”), an indirect majority-owned subsidiary of the Partnership, is presented as a noncontrolling interest in the financial statements.

Our results of operations for the three months ended March 31, 2013 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”). These unaudited condensed consolidated and combined financial statements and the notes thereto should be read in conjunction with the audited consolidated and combined financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2012 (the “2012 Form 10-K”).

All material intercompany transactions and balances have been eliminated in preparation of our consolidated and combined financial statements.

Use of Estimates

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

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

Note 2.  Summary of Significant Accounting Policies

A discussion of our critical accounting policies and estimates is included in our 2012 Form 10-K.

Current Liabilities

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

	March 31,		December 31,
	2013		2012
Accrued capital expenditures	$	10,064	$	4,741
Accrued lease operating expense		4,380		3,994
Accrued general and administrative costs		1,425		1,349
Accrued production and ad valorem taxes		1,453		702
Accrued environmental		619		623
Accrued interest payable		156		618
Other		25		421
	$	18,122	$	12,448

14

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

New Accounting Pronouncements

Offsetting Disclosure Requirements. In December 2011, the FASB issued an accounting standard update intended to enhance current disclosure requirements on offsetting financial assets and liabilities. In January 2013, the FASB issued an accounting standard update to clarify the scope of offsetting disclosure requirements. The disclosure requirements require the disclosure of both gross and net information about derivatives, repurchase agreements and reverse purchase agreements, and securities borrowing and securities lending transactions eligible for offset on the balance sheet or subject to a master netting arrangement or similar agreement. Disclosure of collateral received and posted in connection with master netting agreements or similar arrangements is also required. We adopted this guidance on January 1, 2013 and applied the disclosure requirements retrospectively. The enhanced offsetting disclosure requirements did not have a significant impact on our financial statements.

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 Partnership’s financial position, results of operations and cash flows.

Note 3.  Acquisitions and Divestitures

There were no third party acquisitions consummated during the three months ended March 31, 2013 and 2012 nor were there any divestitures. See Note 12 for further information regarding related party acquisitions that have been accounted as transactions between entities under common control that impact the basis of presentation for the periods presented.

Acquisition-related costs. Approximately $0.2 million and $0.1 million of acquisition-related costs are included in general and administrative expenses in the accompanying statements of operations for the three months ended March 31, 2013 and 2012, respectively. This amount includes acquisition-related costs for both related party and third party transactions.

Disclosure of Supplementary Pro Forma Information for Business Combinations. In May and September 2012, we closed two third party acquisitions. The following unaudited pro forma combined results of operations are provided for the three months ended March 31, 2012 as though the third-party acquisitions had been completed on January 1, 2011. The unaudited pro forma financial information was derived from the historical combined statements of operations of the Partnership and the previous owners and was adjusted to include: (i) the revenues and direct operating expenses associated with oil and gas properties acquired, (ii) depletion expense applied to the adjusted basis of the properties acquired and (iii) interest expense on additional borrowings necessary to finance the acquisitions. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transactions occurred on the basis assumed above, nor is such information indicative of expected future results of operations.

	For the Three Months     Ended March 31,
	2012
	(In thousands, except per   unit amounts)
Revenues	$	53,913
Net income		35,927
Basic and diluted earnings per unit		1.12

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.

15

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The carrying values of cash and cash equivalents, accounts receivables, accounts payables (including accrued liabilities) and amounts outstanding under long-term debt agreements included in the accompanying balance sheets approximated fair value at March 31, 2013 and December 31, 2012. 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.

The fair market values of the derivative financial instruments reflected on the balance sheets as of March 31, 2013 and December 31, 2012 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 March 31, 2013 and December 31, 2012 for each of the fair value hierarchy levels:

	Fair Value Measurements at March 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	$	--	$	68,769	$	--	$	68,769
Liabilities:
Commodity derivatives	$	--	$	57,634	$	--	$	57,634
Interest rate derivatives		--		4,549		--		4,549
Total liabilities	$	--	$	62,183	$	--	$	62,183

	Fair Value Measurements at December 31, 2012 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	$	--	$	69,304	$	--	$	69,304
Liabilities:
Commodity derivatives	$	--	$	41,814	$	--	$	41,814
Interest rate derivatives		--		5,087		--		5,087
Total liabilities	$	--	$	46,901	$	--	$	46,901

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.

16

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Note 5.  Risk Management and Derivative Instruments

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

Certain inherent business risks are associated with commodity and interest derivative contracts, including market risk and credit risk. Market risk is the risk that the price of natural gas or oil will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the counterparty to a contract. It is our policy to enter into derivative contracts, including interest rate swaps, only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. Each of the counterparties to our derivative contracts is a lender under our credit agreement. While collateral is generally not required to be posted by counterparties, credit risk associated with derivative instruments is minimized by limiting exposure to any single counterparty and entering into derivative instruments only with counterparties that are large financial institutions. Additionally, master netting agreements are used to mitigate risk of loss due to default with counterparties on derivative instruments. We have also entered into the International Swaps and Derivatives Association Master Agreements (“ISDA Agreements”) with each of our counterparties. The terms of the ISDA Agreements provide us and each of our counterparties with rights of set-off upon the occurrence of defined acts of default by either us or our counterparty to a derivative, whereby the party not in default may set-off all liabilities owed to the defaulting party against all net derivative asset receivables from the defaulting party. As a result, had certain counterparties failed completely to perform according to the terms of the existing contracts, we would have the right to offset $10.7 million against amounts outstanding under our revolving credit facility at March 31, 2013. See Note 8 for additional information regarding our revolving credit facility.

17

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Commodity Derivatives

We may use a combination of commodity derivatives (e.g., floating-for-fixed swaps, collars, call spreads and basis swaps) to manage exposure to commodity price volatility. We enter into natural gas derivative contracts that are indexed to NYMEX Henry Hub and regional indices such as NGPL TXOK, TETCO STX, and Houston Ship Channel in proximity to our areas of production. We also enter into oil derivative contracts indexed to NYMEX WTI, Inter-Continental Exchange (“ICE”) Brent and California Midway-Sunset. Our NGL derivative contracts are indexed to OPIS Mont Belvieu. At March 31, 2013, we had the following open commodity positions:

	Remaining         2013		2014		2015		2016		2017		2018
Natural Gas Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (MMBtu)		985,172		1,432,125		1,336,112		1,413,275		1,290,067		1,220,000
Weighted-average fixed price	$	4.32	$	4.35	$	4.30	$	4.51	$	4.33	$	4.67
Collar contracts:
Average Monthly Volume (MMBtu)		850,000		300,000		200,000		--		--		--
Weighted-average floor price	$	4.81	$	5.08	$	5.25	$	--	$	--	$	--
Weighted-average ceiling price	$	5.88	$	6.31	$	6.75	$	--	$	--	$	--
Call spreads (1):
Average Monthly Volume (MMBtu)		430,000		120,000		80,000		--		--		--
Weighted-average sold strike price	$	4.59	$	5.08	$	5.25	$	--	$	--	$	--
Weighted-average bought strike price	$	5.84	$	6.31	$	6.75	$	--	$	--	$	--
Basis swaps:
Average Monthly Volume (MMBtu)		1,220,932		1,728,750		--		--		--		--
Spread	$	(0.10)	$	(0.09)	$	--	$	--	$	--	$	--
Crude Oil Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		51,632		57,810		61,031		56,013		52,000		42,000
Weighted-average fixed price	$	106.05	$	99.21	$	95.65	$	93.31	$	90.99	$	90.66
Collar contracts:
Average Monthly Volume (Bbls)		10,700		8,000		--		--		--		--
Weighted-average floor price	$	88.79	$	90.00	$	--	$	--	$	--	$	--
Weighted-average ceiling price	$	118.42	$	117.72	$	--	$	--	$	--	$	--
Basis swaps:
Average Monthly Volume (Bbls)		40,000		--		--		--		--		--
Spread	$	(10.20)	$	--	$	--	$	--	$	--	$	--
NGL Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		69,303		58,350		--		--		--		--
Weighted-average fixed price	$	41.37	$	42.00	$	--	$	--	$	--	$	--

 (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.

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. At March 31, 2013, we had the following fixed-for-floating interest rate swap open positions whereby we receive the floating rate and pay the fixed rate:

Period Covered	Notional ($ in thousands)		Floating Rate	Fixed Rate
January 2013 to December 2016	$	100,000	1 Month LIBOR	1.305%
January 2013 to December 2016	$	50,000	1 Month LIBOR	0.970%
April 2011 to April 2014 (1)	$	75,000	1 Month LIBOR	1.510%
(1)    These interest rate swaps were novated to the Partnership from the previous owners in March 2013 in connection with the acquisition of the WHT properties.

Subsequent event. In connection with the issuance of senior notes in April 2013 (see Note 8), we entered into offsetting interest rate swap derivative instruments whereby we will receive the fixed rate and will pay the floating rate as follows:

Period Covered	Notional ($ in thousands)		Floating Rate	Fixed Rate
April 2013 to October 2013	$	40,000	1 Month LIBOR	1.305%
April 2013 to October 2013	$	75,000	1 Month LIBOR	1.510%

18

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

We also entered into additional interest rate swap derivative instruments whereby we will receive the floating rate and will pay the fixed rate as follows:

Period Covered	Notional ($ in thousands)		Floating Rate	Fixed Rate
October 2013 to April 2014	$	40,000	1 Month LIBOR	1.370%
April 2014 to October 2014	$	75,000	1 Month LIBOR	1.640%

Balance Sheet Presentation

The following table summarizes both: (i) the gross fair value of derivative instruments by the appropriate balance sheet classification even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the balance sheet and (ii) the net recorded fair value as reflected on the balance sheet at March 31, 2013 and December 31, 2012. There was no cash collateral received or pledged associated with our derivative instruments since each of the counterparties to our derivative contracts is a lender under our credit agreement.

		Asset Derivatives				Liability Derivatives
		March 31,		December 31,		March 31,		December 31,
Type	Balance Sheet Location	2013		2012		2013		2012
		(In thousands)
Natural gas contracts	Short-term derivative instruments	$	10,104	$	22,070	$	2,642	$	961
Oil contracts	Short-term derivative instruments		3,346		6,453		4,191		4,483
NGL contracts	Short-term derivative instruments		1,025		871		1,620		1,124
Interest rate swaps	Short-term derivative instruments		-		-		2,372		2,370
Gross fair value			14,475		29,394		10,825		8,938
Netting arrangements	Short-term derivative instruments		(6,326)		(6,303)		(6,326)		(6,303)
Net recorded fair value	Short-term derivative instruments	$	8,149	$	23,091	$	4,499	$	2,635
Natural gas contracts	Long-term derivative instruments	$	15,402	$	17,435	$	9,564	$	9,353
Oil contracts	Long-term derivative instruments		38,385		22,471		38,837		25,359
NGL contracts	Long-term derivative instruments		507		4		780		534
Interest rate swaps	Long-term derivative instruments		-		-		2,177		2,717
Gross fair value			54,294		39,910		51,358		37,963
Netting arrangements	Long-term derivative instruments		(44,794)		(28,386)		(44,794)		(28,386)
Net recorded fair value	Long-term derivative instruments	$	9,500	$	11,524	$	6,564	$	9,577

(Gains) Losses on Derivatives

We do not designate derivative instruments as hedging instruments for financial reporting purposes and neither did the previous owners. Accordingly, all gains and losses, including unrealized gains and losses from changes in the derivative instruments’ fair values, have been recorded in the accompanying statements of operations. The following table details the unrealized and realized gains and losses related to derivative instruments for the three months ended March 31, 2013 and 2012:

		Three Months Ended March 31,
	Statements of Operations Location	2013		2012
Commodity derivative contracts	Realized (gain) loss on commodity derivatives	$	(5,694)	$	(8,628)
Commodity derivative contracts	Unrealized (gain) loss on commodity derivatives		16,356		(14,532)
Interest rate swaps (1)	Interest expense		5		642

(1) Included in the amounts are net cash payments of approximately $0.5 million and $0.3 million for the three months ended March 31, 2013 and 2012, respectively.

19

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Note 6.  Asset Retirement Obligations

The Partnership’s asset retirement obligations primarily relate to the Partnership’s portion of future plugging and abandonment of wells and related facilities. The following table presents the changes in the asset retirement obligations for the three months ended March 31, 2013 (in thousands):

Asset retirement obligations at beginning of period	$	78,286
Liabilities added from acquisitions or drilling		5
Liabilities removed upon plugging and abandoning		(19)
Accretion expense		998
Asset retirement obligations at end of period	$	79,270

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 our offshore Southern California oil and gas properties. The components of the restricted investment balance consisted of the following at the dates indicated:

	March 31,		December 31,
	2013		2012
	(In thousands)
BOEM platform abandonment (See Note 13)	$	62,601	$	61,389
BOEM lease bonds		776		776
SPBPC Collateral:
Contractual pipeline and surface facilities abandonment (See Note 13)		2,029		1,959
California State Lands Commission pipeline right-of-way bond		3,000		3,000
City of Long Beach pipeline facility permit		500		500
Federal pipeline right-of-way bond		300		300
Port of Long Beach pipeline license		100		100
Restricted investments	$	69,306	$	68,024

Note 8.  Long Term Debt

Partnership

Our consolidated debt obligations consisted of the following at the dates indicated:

	March 31,		December 31,
	2013		2012
	(In thousands)
$1.0 billion revolving credit facility, variable–rate, due March 2018	$	408,000	$	371,000

The revolving credit facility, which OLLC entered into at the closing of our initial public offering, is guaranteed by us and certain of our current and future subsidiaries and had a borrowing base of $580.0 million at March 31, 2013. As of March 31, 2013, available borrowing capacity under this revolving credit facility was $172.0 million. The effective weighted average interest rate for the three months ended March 31, 2013 and 2012 was 2.9% for both periods. The effective weighted average interest rate includes the impact of the commitment fee and excludes the impact of interest rate hedging activity. Upon issuance of the senior notes discussed below, the borrowing base under our revolving credit facility was reduced to $505.0 million and the available borrowing capacity was approximately $387.0 million.

The following table presents borrowings and repayments under our revolving credit facility for the periods presented:

	For the Three Months Ended March 31,
	2013		2012
Advances on revolving credit facility	$	216,000	$	--
Payments on revolving credit facility		(179,000)		--

20

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

During the three months ended March 31, 2013, our revolving credit facility was primarily used to fund the acquisitions of oil and gas properties from Memorial Resource. See Note 13 for additional information regarding this related party acquisition. In conjunction with the closing of this transaction, the borrowing base was increased by $120.0 million. Additional financing costs were incurred associated with this borrowing base redetermination and will be amortized over the remaining life of our revolving credit facility. Unamortized deferred financing costs associated with our revolving credit facility were the following at the dates indicated:

March 31,		December 31,
2013		2012
(In thousands)
	$                    4,516	$	3,359

We filed a universal shelf registration statement with the SEC, which was declared effective on March 15, 2013, that allows us to issue up to $750.0 million in debt and equity securities for general partnership purposes, which may include, among other things, paying or refinancing all or a portion of our indebtedness and funding acquisitions, capital expenditures and working capital. Any debt securities issued will be governed by an indenture. Furthermore, any debt securities issued may be jointly and severally, fully and unconditionally guaranteed by certain of the Partnership’s subsidiaries (collectively, “Guarantor Subsidiaries”). The Guarantor Subsidiaries are 100 percent owned by the Partnership. The Partnership has no assets or operations independent of the Guarantor Subsidiaries and there are no significant restrictions upon the ability of the Subsidiaries to distribute funds to the Partnership.

Subsequent event.  On April 17, 2013, we and Finance Corp. (collectively, the “Issuers”) completed a private placement of $300.0 million in aggregate principal amount of the Issuers’ 7.625% senior notes due 2021 (the “Senior Notes”). The Senior Notes were sold to initial purchasers at 98.521% of par for net proceeds of approximately $289.6 million, after deducting the initial purchasers’ discounts and commissions, but before estimated offering expenses. We used the net proceeds to repay borrowings outstanding under our revolving credit facility.

The Senior Notes were offered and sold to the initial purchasers in a private placement exempt from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”). The Senior Notes were resold by the initial purchasers to qualified institutional buyers in reliance on Rule 144A under the Securities Act and to non-U.S. persons outside the United States in reliance on Regulation S under the Securities Act.

The Senior Notes were issued pursuant to an indenture, dated April 17, 2013 (the “Indenture”), among the Issuers, the Guarantor Subsidiaries and U.S. Bank National Association, as trustee. The Senior Notes will mature on May 1, 2021 and interest is payable on the Senior Notes on May 1 and November 1 of each year, commencing November 1, 2013.

The Senior Notes are the general unsecured senior obligations of the Issuers. The Senior Notes rank equally in right of payment with all of the Issuers’ existing and future senior unsecured indebtedness and senior in right of payment to any of the Issuers’ future subordinated indebtedness. The Senior Notes are effectively junior in right of payment to all of the Issuers’ existing and future secured indebtedness and other secured obligations, including borrowings outstanding under our revolving credit facility, to the extent of the value of the assets securing such indebtedness and obligations. The Senior Notes are fully and unconditionally guaranteed on a senior basis by each of the Guarantor Subsidiaries and by certain future subsidiaries of the Partnership.

The Issuers have the option to redeem all or a portion of the Senior Notes at any time on or after May 1, 2017 at a redemption price of 103.813%, decreasing to 101.906% on May 1, 2018 and 100% on May 1, 2019, plus accrued and unpaid interest, if any. The Issuers may also redeem all or any part of the Senior Notes at a “make-whole” redemption price specified in the Indenture, plus accrued and unpaid interest, at any time before May 1, 2017. In addition, the Issuers may, on any one or more occasions, redeem up to 35% of the aggregate principal amount of the Senior Notes before May 1, 2016 under certain circumstances with the net cash proceeds from certain equity offerings at a redemption price of 107.625% of the principal amount of the notes redeemed, plus accrued and unpaid interest, if any. The Issuers may also be required to repurchase the Senior Notes at a price equal to 101% of the principal amount, plus accrued and unpaid interest, if any, upon a change of control.

21

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

The Indenture restricts the Partnership’s ability, and the ability of the Partnership’s restricted subsidiaries, to: (i) incur, assume or guarantee additional indebtedness or issue certain types of equity securities; (ii) pay distributions on, purchase or redeem units or purchase or redeem subordinated debt; (iii) make certain investments; (iv) enter into certain transactions with affiliates; (v) create or incur liens on their assets; (vi) sell assets; (vii) consolidate, merge or transfer all or substantially all of their assets; (viii) restrict distributions or other payments from the Partnership’s restricted subsidiaries; and (ix) designate subsidiaries as unrestricted subsidiaries. These covenants are subject to a number of important exceptions and qualifications, including that certain of the covenants will be terminated if at any time no default exists under the Indenture and the Senior Notes receive an investment grade rating from both of two specified ratings agencies.

The Indenture also includes customary 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 Issuers, all outstanding 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 Senior Notes may declare all the Senior Notes to be due and payable immediately.

In connection with the issuance and sale of the Senior Notes, the Issuers and the Guarantor Subsidiaries entered into a registration rights agreement (the “Registration Rights Agreement”) pursuant to which the Issuers and the Guarantor Subsidiaries agreed to file and use commercially reasonable efforts to cause to become effective a registration statement with respect to an offer to exchange the Senior Notes for substantially identical notes that are registered under the Securities Act so as to permit the exchange offer to be consummated no later than the 365^th day following the issuance of the Senior Notes. Under specified circumstances, the Issuers and the Guarantor Subsidiaries have also agreed to use commercially reasonable efforts to cause to become effective a shelf registration statement relating to resales of the Senior Notes. The Issuers and the Guarantor Subsidiaries are required to pay additional interest (up to a maximum of 1.0%) if they fail to comply with their obligations to consummate the exchange offer or to cause a shelf registration statement relating to resales of the Senior Notes to become effective within the time periods specified in the Registration Rights Agreement.

Previous Owners

WHT.  On April 8, 2011, WHT entered into a $400.0 million variable-rate revolving credit facility with a maturity date of April 8, 2016. Debt outstanding under this facility was $89.3 million at December 31, 2012. The weighted average interest rate for the three months ended March 31, 2013 and 2012 was approximately 2.3% and 2.8%, respectively.

For accounting and financial reporting purposes, the $89.3 million that was repaid in conjunction with the acquisition of the WHT properties was netted against the net book value of the net assets that we acquired and is reflected on our unaudited consolidated and combined cash flow statement as “Payments on revolving credit facility.” Unamortized deferred financing costs associated with this revolving credit facility were approximately $1.4 million at December 31, 2012. The unamortized deferred financing costs associated with this revolving credit facility were written-off at the time the debt was repaid and the facility was terminated.

The following table presents borrowings and repayments under the WHT revolving credit facility for the periods presented:

	For the Three Months     Ended March 31,
	2013		2012
Advances on revolving credit facility	$	1,000	$	--
Payments on revolving credit facility		(90,300)		(1,500)

REO. On October 26, 2011, REO entered into a $150.0 million variable-rate revolving credit facility with a maturity date of October 26, 2014. This revolving credit facility was terminated on December 12, 2012 and all amounts outstanding at that time were repaid. The weighted average interest rate for the three months ended March 31, 2012 was approximately 3.4%.

The following table presents borrowings and repayments under the REO revolving credit facility for the three months ended March 31, 2012:

Advances on revolving credit facility	$	7,000
Payments on revolving credit facility		(2,000)

22

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Note 9.  Equity & Distributions

2013 Public Equity Offering

On March 25, 2013, we issued 9,775,000 common units representing limited partner interests in the Partnership (including 1,275,000 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 $18.35 per unit generating total net proceeds of approximately $172.0 million after deducting underwriting discounts and offering expenses. The net proceeds from this equity offering, including our general partner’s proportionate capital contribution, partially funded the acquisition of the WHT properties as further discussed under Note 12.

Equity Outstanding

The following table summarizes changes in the number of outstanding units since December 31, 2012:

	Common		Subordinated		General     Partner
Balance December 31, 2012		28,921,903		5,360,912		34,317
Common units issued		9,775,000		--		--
Restricted common units issued		16,627		--		--
Restricted common units forfeited		(6,564)		--		--
General partner units issued		--		--		9,795
Balance March 31, 2013		38,706,966		5,360,912		44,112

Restricted common units are a component of common units as presented on our unaudited condensed consolidated balance sheets. See Note 11 for additional information regarding restricted common units that were granted to our general partner’s executive officers and independent directors during the three months ended March 31, 2013.

As of March 31, 2013, Memorial Resource owned approximately 18.2% of the common units and 100% of the subordinated units. Memorial Resource owns all of the voting interests in our general partner and 50% of the economic interest in our IDRs. The Funds collectively directly own, through non-voting membership interests in our general partner, 50% of the remaining economic interest in our IDRs.

Allocations of Net Income (Loss)

Net income (loss) attributable to the Partnership is allocated between our general partner and the common and subordinated unitholders in proportion to their pro rata ownership. Net income (loss) attributable to acquisitions accounted for as a transaction between entities under common control prior to their acquisition date is allocated to the previous owners.

Cash Distributions to Unitholders

The following table summarizes our declared quarterly cash distribution rates with respect to the quarter indicated (dollars in millions, except per unit amounts):

Quarter	Declaration Date	Record Date	Payable Date	Amount Per Unit (1)	Aggregate Distribution	Distribution Received by Memorial Resource
1st Quarter 2013	April 18, 2013	May 1, 2013	May 13, 2013	$            0.5125	$            22.6	$            6.5
4th Quarter 2012	January 15, 2013	February 1, 2013	February 13, 2013	$            0.5075	$            17.4	$            6.3
3rd Quarter 2012	October 19, 2012	November 1, 2012	November 12, 2012	$            0.4950	$            11.1	$            6.2
2nd Quarter 2012	July 19, 2012	August 1, 2012	August 13, 2012	$            0.4800	$            10.7	$            6.0
1st Quarter 2012	April 19, 2012	May 1, 2012	May 14, 2012	$            0.4800	$            10.7	$            6.0
4th Quarter 2011	January 26, 2012	February 6, 2012	February 13, 2012	$            0.0929	$              2.0	$            1.2

  (1) The $0.0929 per unit pro-rated distribution paid on February 13, 2012 was based upon the minimum quarterly distribution of $0.4750 per unit adjusted to take into account the 18-day period of the fourth quarter of 2011 during which the Partnership was a public entity.

23

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Note 10.  Earnings per Unit

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

	For the Three Months Ended March 31,
	2013		2012
Net income (loss) attributable to partners	$	(5,022)	$	20,894
Less: General partner’s 0.1% interest in net income (loss)		(5)		21
Limited partners’ interest in net income (loss)	$	(5,017)	$	20,873
Weighted average limited partner units outstanding:
Common units		29,693		16,824
Subordinated units		5,361		5,361
Total		35,054		22,185
Basic and diluted EPU	$	(0.14)	$	0.94

Note 11.  Equity-based Awards

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

	Number of Units		Weighted- Average Grant Date Fair Value per Unit (1)
Restricted common units outstanding at December 31, 2012		285,609	$	18.08
Granted (2)		16,627	$	18.33
Forfeited		(6,564)	$	17.14
Vested		(60,296)	$	18.58
Restricted common units outstanding at March 31, 2013		235,376	$	17.99

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

(2) The aggregate grant date fair value of restricted common unit awards issued in 2013 was $0.3 million based on grant date market price of $18.33 unit.

We recognized approximately $0.4 million and $0.2 million of compensation expense associated with these awards during the three months ended March 31, 2013 and 2012, respectively. The unrecognized compensation cost associated with restricted common unit awards was $3.5 million at March 31, 2013. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.24 years. Since the restricted common units are participating securities, any distributions received by the restricted common unitholders are included in distributions to partners as presented on our unaudited condensed statements of consolidated and combined cash flows.

Note 12.  Related Party Transactions

Amounts due to (due from) Memorial Resource and certain of its subsidiaries at March 31, 2013 and December 31, 2012 are presented as “Accounts receivable – affiliates” and “Accounts payable – affiliates” in the accompanying balance sheets.

For the three months ended March 31, 2013 and 2012, approximately $2.3 million and $1.6 million of related party transactions, respectively, are reflected in the accompanying statements of operations. These costs and expenses represent payments under our omnibus agreement (as discussed below) and management fees paid to affiliates for operating our assets.

24

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Common Control Acquisitions

March 2013 Acquisition.  On March 28, 2013, we acquired all of the outstanding equity interests in WHT from operating subsidiaries of Memorial Resource for a purchase price of $200.0 million, which included $4.0 million of working capital and other customary adjustments. This acquisition was funded with borrowings under our revolving credit facility and the net proceeds from our March 25, 2013 public offering of common units (including our general partner’s proportionate capital contribution). The effective date for this transaction was January 1, 2013. Terms of the transaction were approved by our general partner’s board of directors and by its conflicts committee, which is comprised entirely of independent directors. The WHT properties consist of additional working interests in properties that we originally acquired in December 2011 in conjunction with our initial public offering. 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. See Note 1 for additional information regarding basis of presentation. The Partnership recorded the following net assets (in thousands):

Cash and cash equivalents	$	1,354
Accounts receivable		3,866
Short-term derivative instruments, net		1,206
Prepaid expenses and other current assets		98
Oil and natural gas properties, net		192,280
Long-term derivative instruments, net		3,528
Accrued liabilities		(3,494)
Asset retirement obligations		(2,753)
Credit facilities		(89,300)
Other long-term liabilities		(111)
Net assets	$	106,674

2012 Acquisitions.  We acquired oil and gas properties from Memorial Resource in April and May 2012. In December 2012, we acquired our offshore Southern California properties and the associated onshore tankage and metering facility from an affiliate of Memorial Resource.

Certain financial information previously filed with the SEC and reported herein has been retrospectively revised for these common control transactions. For example, the December 31, 2012 balance sheet has been recast to include the financial position attributable to the WHT properties. The results of operations and the cash flows for the three months ended March 31, 2012 has also been recast to include those attributable to the common control acquisitions that were consummated after such date.

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.

Omnibus Agreement

Memorial Resource continues to provide management, administrative and operating services for us and our general partner pursuant to our omnibus agreement. For the three months ended March 31, 2013 and 2012, we recognized $1.5 million and $0.3 million of general and administrative costs and expenses under the omnibus agreement, respectively.

Tax Sharing Agreement

The tax sharing agreement pursuant to which we pay Memorial Resource (or its applicable affiliate(s)) our share of state and local income and other taxes for which our results are included in a combined or consolidated tax return filed by Memorial Resource or its applicable affiliate(s) also remains in effect.

Beta Management Agreements

The Partnership acquired REO, which owns certain operating interests in producing and non-producing oil and gas properties offshore Southern California, in December 2012. We refer to this transaction as the “Beta acquisition” and the acquired properties as the “Beta properties.” In connection with the Beta acquisition, Memorial Resource entered into a management agreement with its wholly-owned subsidiary, Beta Operating Company, LLC, pursuant to which Memorial Resource agreed to provide management and

25

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

administrative oversight with respect to the services provided by such subsidiary under certain operating agreements with our subsidiary, Rise Energy Beta, LLC, related to the Beta properties in exchange for an annual management fee. Pursuant to such management agreement and in connection with such operating agreements, Memorial Resource will receive approximately $0.4 million from Rise Energy Beta, LLC annually.

An affiliate of REO collected a management fee for providing administrative services to REO prior to the Beta acquisition. These administrative services included accounting, business development, finance, legal, information technology, insurance, government regulations, communications, regulatory, environmental and human resources services. REO incurred and paid management fees of $0.7 million for the three months ended March 31, 2012. These management fees are presented as a component of general and administrative costs and expenses in the accompanying statements of operations.

WHT Management Agreement

Memorial Resource controls WildHorse Resources, LLC (“WildHorse”) and Tanos Energy, LLC (“Tanos”), which collectively owned the outstanding equity interests in WHT prior to March 28, 2013. Under the terms of a management agreement dated April 8, 2011, WildHorse provided executive, financial, accounting and land services to WHT. WildHorse also managed day-to-day field operations and drilling activities. Geological, executive and other services were provided by Tanos. To compensate for these services, WHT paid WildHorse and Tanos management fees totaling approximately $0.2 million per month. In connection with the WHT acquisition, the management agreement was terminated as of March 28, 2013.

As the designated operator, WildHorse received both operated and non-operated revenues on behalf of WHT and billed and received joint interest billings. WildHorse also paid for lease operating expenses, drilling cost and general and administrative costs on behalf of WHT. Receivable and payable balances were settled monthly between WHT and WildHorse.

Memorial Resource Revolving Credit Facility

Memorial Resource has a senior secured revolving credit facility, which is guaranteed by our general partner. Memorial Resource has pledged 7,061,294 of our common units and 5,360,912 of our subordinated units as security under the credit facility as well as its oil and gas properties and certain other assets of Memorial Resource.

Note 13.  Commitments and Contingencies

Litigation & Environmental

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

At March 31, 2013 and December 31, 2012, we had $1.0 million and $1.1 million of environmental reserves recorded on our balance sheets, respectively. At both March 31, 2013 and December 31, 2012, $0.6 million of our environmental reserves were classified as current liabilities in accrued liabilities.

Sinking Fund Trust Agreement

As of March 31, 2013, the gross account balance included in restricted investments was approximately $2.0 million. REO’s maximum remaining obligation net to its 51.75% interest under the terms of the current agreement was approximately $1.2 million at March 31, 2013.

26

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Supplemental Bond for Decommissioning Liabilities Trust Agreement

The following is a summary of the gross held-to-maturity investments held in the trust account less the outside working interest owners share as of March 31, 2013 (in thousands):

Investment	Amortized     Cost		Unrealized     Gain (Loss)		Fair Market     Value
U.S. Bank Money Market Cash Equivalent	$	75,833	$	--	$	75,833
U.S. Government Treasury Note, maturity of March 31, 2013, and 2.50% coupon (1)		22,070		--		22,070
U.S. Government Treasury Note, maturity of March 31, 2014, and 1.75% coupon		23,024		410		23,434
Less: Outside working interest owners share		(58,326)		(198)		(58,524)
	$	62,601	$	212	$	62,813

(1) We made an election to roll the principal into our U.S. Bank Money Market cash equivalent account upon maturity. The proceeds were deposited into our account on April 1, 2013.

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

June 30, 2013	$	64,170
June 30, 2014	$	68,310
June 30, 2015	$	72,450
June 30, 2016	$	76,590
December 31, 2016	$	78,660

As of March 31, 2013, the maximum remaining obligation net to REO’s interest was approximately $15.9 million.

27

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 Annual Report on Form 10-K for the year ended December 31, 2012 (the “2012 Form 10-K”). 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 limited partnership formed in April 2011 by Memorial Resource to own, acquire and exploit oil and natural gas properties in North America. The Partnership is owned 99.9% by its limited partners and 0.1% by its general partner, which is a wholly-owned subsidiary of Memorial Resource. Our general partner is responsible for managing all of the Partnership’s operations and activities.

We operate in one reportable segment engaged in the acquisition, exploitation, development and production of oil and natural gas properties. Our business activities are conducted through OLLC, our wholly-owned subsidiary, and its wholly-owned subsidiaries. Our assets consist primarily of producing oil and natural gas properties and are principally located in Texas, Louisiana and offshore Southern California. Most of our oil and natural gas 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. After giving effect to the WHT acquisition retrospectively, as of December 31, 2012:

• Our total estimated proved reserves were approximately 771 Bcfe, of which approximately 63% were natural gas and 60% were classified as proved developed reserves;

• We produced from 1,671 gross (926 net) producing wells across our properties, with an average working interest of 55%, and we or Memorial Resource operated 97% of the properties in which we have interests; and

• Our average net production for the three months ended December 31, 2012 was 92.9 MMcfe/d, implying a reserve-to-production ratio of approximately 23 years.

Significant Current Developments

Private Offering of Senior Notes

On April 17, 2013, we and our wholly-owned subsidiary, Finance Corp., (collectively, the “Issuers”), completed a private placement of $300.0 million aggregate principal amount of 7.625% senior unsecured notes due 2021 (the “Senior Notes”). The Senior Notes were issued at 98.521% of par and are guaranteed by all of the Partnership’s subsidiaries (other than Finance Corp., which is co-issuer of the Senior Notes, and San Pedro Bay Pipeline Company, which is an immaterial majority-owned subsidiary) jointly and severally on a senior unsecured basis. The 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, commencing November 1, 2013. For additional information regarding our Senior Notes, see Note 8 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under Item 1 of this quarterly report.

Amendment to Revolving Credit Facility

On March 19, 2013, we entered into a fifth amendment to our credit agreement, which among other things, increased the borrowing base to $580.0 million upon closing of the acquisition of oil and gas properties from operating subsidiaries of Memorial Resource (discussed below) and extended the maturity date of the credit agreement to March 19, 2018. The borrowing base was reduced to $505.0 million upon issuance of the Senior Notes discussed above. The next borrowing base redetermination is scheduled for October 2013; however, we have the right to seek an interim redetermination if the need arises.

28

Acquisition of Oil & Gas Properties

On March 28, 2013, we acquired all of the outstanding equity interests in WHT Energy Partners LLC (“WHT”), which owns certain oil and natural gas properties and related assets in East Texas and North Louisiana (the “WHT properties”), from operating subsidiaries of Memorial Resource for a purchase price of $200.0 million, which included $4.0 million of working capital and other customary adjustments. This acquisition was funded with borrowings under our revolving credit facility and the net proceeds from our March 25, 2013 public offering of common units (including our general partner’s proportionate capital contribution). The effective date for this transaction was January 1, 2013. Terms of the transaction were approved by our general partner’s board of directors and by its conflicts committee, which is comprised entirely of independent directors. The WHT properties consist of additional working interests in properties that we originally acquired in December 2011 in conjunction with our initial public offering. 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.

Public Equity Offering

On March 25, 2013, we issued 9,775,000 common units representing limited partner interests in the Partnership (including 1,275,000 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 $18.35 per unit generating total net proceeds of approximately $172.0 million after deducting underwriting discounts and offering expenses.

Business Environment and Operational Focus

Our primary business objective is to generate stable cash flows, allowing us to make quarterly cash distributions to our unitholders and, over time, to increase those quarterly cash distributions. We use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including: (i) production volumes; (ii) realized prices on the sale of our production, including the effect of our derivative contracts; (iii) lease operating expenses; (iv) general and administrative expenses; and (v) Adjusted EBITDA (defined below).

Production Volumes

Production volumes directly impact our results of operations. Producing oil and natural gas reservoirs are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. We attempt to overcome this natural decline through a combination of acquisitions and development projects and improving the economics of producing oil and natural gas from our properties. Our ability to add estimated reserves through acquisitions and development projects is dependent on many factors, including our ability to raise capital, obtain regulatory approvals and procure contract drilling rigs and personnel.

Realized Prices on the Sale of our Production

We market our natural gas, NGL and oil production to a variety of purchasers based on regional pricing. The relative prices of natural gas, NGL and oil are determined by the factors impacting global and regional supply and demand dynamics, such as economic conditions, production levels, weather cycles and other events. In addition, relative prices are heavily influenced by product quality and location relative to consuming and refining markets. We expect commodity prices to be volatile in the future. Although we cannot predict the occurrence of events that will affect future commodity prices or the degree to which these prices will be affected, the prices for any oil, natural gas or NGLs that we produce will generally approximate market prices in the geographic region of the production.

Our hedging policy is designed to reduce the impact to our cash flows from commodity price volatility. Under this policy, we intend to maintain a portfolio of commodity derivative contracts covering approximately 65% to 85% of our estimated production from total proved reserves over a three-to-six year period at any given point in time. We may, however, from time to time hedge more or less than this approximate range. Additionally, we intend to individually identify these non-speculative hedges as “designated hedges” for U.S. federal income tax purposes as we enter into them, resulting in ordinary income treatment of our realized hedge activity. By removing a significant portion of this price volatility on our future production through December 2018, we have mitigated, but not eliminated, the potential effects of changing commodity prices on our cash flows from operations for those periods.

29

Lease Operating Expenses

We strive to increase our production levels to maximize our revenue and cash available for distribution. Lease operating expenses are the costs incurred in the operation of producing properties and workover costs. Certain items, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. We monitor our operations to ensure that we are incurring operating costs at the optimal level. Accordingly, we monitor our production expenses and operating costs per well to determine if any wells or properties should be shut in, recompleted or sold.

General & Administrative Expenses

We and our general partner have entered into an omnibus agreement with Memorial Resource pursuant to which, among other things, Memorial Resource performs all operational, management and administrative services on our general partner’s and our behalf. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocated to us, including expenses incurred by our general partner and its affiliates on our behalf. During the year ended December 31, 2012, Memorial Resource allocated its general and administrative costs based on the relative size of our proved and probable reserves in comparison to Memorial Resource’s proved and probable reserves. In January 2013, Memorial Resource began to allocate its general and administrative costs based on our relative production in comparison to Memorial Resource’s production, which it believes will more accurately reflect the cost incurred to provide services to us. Under our partnership agreement and the omnibus agreement, we reimburse Memorial Resource for all direct and indirect costs incurred on our behalf.

Adjusted EBITDA

We include in this report the non-GAAP financial measure Adjusted EBITDA and provide our calculation of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to net cash flow from operating activities, our most directly comparable financial measure calculated and presented in accordance with GAAP. We define Adjusted EBITDA as net income (loss):

Plus:

• Interest expense, including realized and unrealized losses on interest rate derivative contracts;

• Income tax expense;

• Depreciation, depletion and amortization (“DD&A”);

• Impairment of goodwill and long-lived assets (including oil and natural gas properties) (“Impairment”);

• Accretion of asset retirement obligations (“AROs”);

• Unrealized losses on commodity derivative contracts;

• Losses on sale of assets and other, net;

• Unit-based compensation expenses;

• Exploration costs;

• Acquisition related costs;

• Amortization of investment premium;

• Net operating cash flow from acquisitions, effective date through closing date; and

• Other non-routine items that we deem appropriate.

Less:

• Interest income;

• Income tax benefit;

• Unrealized gains on commodity derivative contracts;

• Gains on sale of assets and other, net; and

• Other non-routine items that we deem appropriate.

30

Adjusted EBITDA is used as a supplemental financial measure by our management and by external users of our financial statements, such as investors, research analysts and rating agencies, to assess:

• our operating performance as compared to that of other companies and partnerships in our industry, without regard to financing methods, capital structure or historical cost basis;

• the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness, and make distributions on our units; and

• the viability of projects and the overall rates of return on alternative investment opportunities.

In addition, management uses Adjusted EBITDA to evaluate actual cash flow available to pay distributions to our unitholders, develop existing reserves or acquire additional oil and natural gas properties.

Adjusted EBITDA should not be considered an alternative to net income, operating income, cash flow from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner.

The following tables present our calculation of Adjusted EBITDA as well as a reconciliation of Adjusted EBITDA to cash flows from operating activities, our most directly comparable GAAP financial measure, for each of the periods indicated.

	For the Three Months     Ended March 31,
	2013		2012
Calculation of Adjusted EBITDA:
Net income (loss)	$	(6,245)	$	31,206
Interest expense, net		5,033		2,509
Income tax expense		--		183
DD&A		13,155		11,130
Accretion of AROs		998		943
Unrealized (gains) losses on commodity derivative instruments		16,356		(14,532)
Acquisition related costs		215		113
Unit-based compensation expense		422		248
Exploration costs		95		--
Amortization of investment premium		--		121
Adjusted EBITDA	$	30,029	$	31,921
	For the Three Months     Ended March 31,
	2013		2012
Reconciliation of Net Cash from Operating Activities to Adjusted EBITDA:
Net cash provided by operating activities	$	28,145	$	31,722
Changes in working capital		(1,880)		(1,797)
Interest expense, net		5,033		2,509
Unrealized gain (loss) on interest rate swaps		538		(349)
Acquisition related costs		215		113
Amortization of deferred financing fees		(2,022)		(277)
Adjusted EBITDA	$	30,029	$	31,921

31

Critical Accounting Policies and Estimates

A discussion of our critical accounting policies and estimates is included in our 2012 Form 10-K. 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. 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

The results of operations for the three months ended March 31, 2013 and 2012 have been derived from both our consolidated financial statements and the previous owners’ combined financial statements. The combined financial statements of the previous owners reflect certain oil and gas properties acquired from Memorial Resource in April and May 2012 for periods after common control commenced through their respective acquisition dates, the consolidated financial statements of REO from February 3, 2009 (inception) through the date of acquisition, and the consolidated financial statements of WHT from April 8, 2011 through March 28, 2013. The results of operations attributable to the previous owners may not necessarily be indicative of the actual results of operations that might have occurred if the Partnership operated separately during those periods. The following table summarizes certain of the results of operations and period-to-period comparisons for the periods indicated.

32

	For the Three Months     Ended March 31,
	2013		2012
Revenues:
Oil & natural gas sales	$	44,035	$	43,289
Pipeline tariff income		305		334
Other income		--		110
Total revenues	$	44,340	$	43,733
Costs and expenses:
Lease operating		13,098		13,085
Pipeline operating		470		734
Exploration		95		--
Production and ad valorem taxes		2,287		2,481
Depreciation, depletion, and amortization		13,155		11,130
General and administrative		4,787		4,376
Accretion of asset retirement obligations		998		943
Realized (gain) loss on commodity derivative instruments		(5,694)		(8,628)
Unrealized (gain) loss on commodity derivative instruments		16,356		(14,532)
Other, net		--		125
Total costs and expenses		45,552		9,714
Operating income (loss)		(1,212)		34,019
Other income (expense):
Interest expense, net		(5,033)		(2,509)
Amortization of investment premium		--		(121)
Total other income (expense)		(5,033)		(2,630)
Income before income taxes		(6,245)		31,389
Income tax benefit (expense)		--		(183)
Net income (loss)		(6,245)		31,206
Net income (loss) attributable to previous owners		(1,219)		10,403
Net income (loss) attributable to noncontrolling interest		(4)		(91)
Net income attributable to partners	$	(5,022)	$	20,894
Oil and natural gas revenue:
Oil sales	$	18,424	$	21,121
NGL sales		8,857		6,699
Natural gas sales		16,754		15,469
Total oil and natural gas revenue	$	44,035	$	43,289
Production volumes:
Oil (MBbls)		176		195
NGLs (MBbls)		270		129
Natural gas (MMcf)		5,686		5,555
Total (MMcfe)		8,363		7,500
Average net production (MMcfe/d)		92.9		82.4
Average sales price (excluding commodity derivatives):
Oil (per Bbl)	$	104.94	$	108.17
NGL (per Bbl)	$	32.74	$	51.98
Natural gas (per Mcf)	$	2.95	$	2.78
Total (Mcfe)	$	5.27	$	5.77
Average unit costs per Mcfe:
Lease operating expense	$	1.57	$	1.74
Production and ad valorem taxes	$	0.27	$	0.33
General and administrative expenses	$	0.57	$	0.58
Depletion, depreciation, and amortization	$	1.57	$	1.48

33

Three Months Ended March 31, 2013 Compared to the Three Months Ended March 31, 2012

A net loss of $6.2 million was generated for the three months ended March 31, 2013, of which $1.2 million was attributable to the previous owners. Net income was $31.2 million for the three months ended March 31, 2012, of which $10.4 million was attributable to the previous owners. The decrease in net income was largely attributable to an unrealized loss on commodity derivatives of $16.4 million that was recognized during 2013 compared to an unrealized gain on commodity derivatives of $14.5 million that was recognized during 2012.

Revenues.  Oil, natural gas and NGL revenues for 2013 totaled $44.0 million, an increase of $0.7 million compared with 2012. Production increased 863 MMcfe (approximately 12%) and the average realized sales price (excluding realized gain on derivatives) decreased $0.50 per Mcfe. The favorable volume variance contributed to an approximate $5.0 million increase in revenues, which was partially offset by the unfavorable pricing variance.

In January 2013, the Partnership temporarily shut-in production from one of its offshore Southern California production platforms for 26 days to allow for maintenance and inspection services on segments of the associated platform piping systems. The production impact of the shut-in was approximately 72 MBbls gross (28 MBbls net).

Effective January 1, 2013, we also began presenting NGLs volumes and revenues produced from our South Texas properties separately from gas volumes and revenues for accounting purposes. This change in presentation had no impact on total oil and natural gas revenue reported for the comparable period.

Lease Operating.  Lease operating expenses for both 2013 and 2012 were $13.1 million. Lease operating expenses associated with third party acquisitions that were consummated during 2012 was approximately $0.8 million. Excluding results from these third party acquisitions, lease operating expense decreased by $0.8 million primarily due to less workover expenses and operational efficiencies. On a per Mcfe basis, lease operating expenses decreased to $1.57 for 2013 from $1.74 for 2012.

Production and Ad Valorem Taxes.  Production and ad valorem taxes for 2013 totaled $2.3 million, a decrease of $0.2 million compared with 2012. On a per Mcfe basis, production and ad valorem taxes decreased to $0.27 for 2013 from $0.33 for 2012.

Depreciation, Depletion and Amortization.  DD&A expense for 2013 was $13.2 million compared to $11.1 million for 2012, a $2.1 million period-to-period increase primarily due to both an increase in the depletable cost base and increased production volumes related to third party acquisitions consummated during 2012. DD&A expense per Mcfe was $1.57 for 2013 compared to $1.48 for 2012. Increased production volumes caused DD&A expense to increase by an approximate $1.3 million and the 6% change in the DD&A rate between periods caused DD&A expense to increase by an approximate $0.8 million.

General and Administrative.  General and administrative expenses include the costs of administrative employees and related benefits, management fees paid to affiliates, professional fees and other costs not directly associated with field operations. General and administrative expenses for 2013 were $4.8 million, of which $0.6 million was attributable to the previous owners. General and administrative expenses for 2013 included $0.4 million of non-cash unit-based compensation expense and $0.2 million of acquisition-related costs. General and administrative expenses for 2012 totaled $4.4 million, of which $2.4 million was attributable to the previous owners.

On a per Mcfe basis, general and administrative expenses were $0.57 in 2013 compared to $0.58 in 2012 due to increased production volumes.

Gain/Loss on Derivative Instruments.  Net losses on commodity derivative instruments of $10.7 million were recognized during 2013, of which $5.7 million were realized gains and $16.4 million were unrealized losses. Net gains on commodity derivative instruments of $23.2 million were recognized during 2012, of which $8.6 million were realized gains and $14.5 million were unrealized gains.

Given the volatility of commodity prices, it is not possible to predict future reported unrealized 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.

34

Net Interest Expense.  Net interest expense is comprised of interest on credit facilities, amortization of debt issue costs and realized and unrealized gains and losses on interest rate swaps. Net interest expense totaled $5.0 million during 2013, including unrealized gains on interest rate swaps of approximately $0.5 million and amortization of deferred financing fees of approximately $2.0 million. Unamortized deferred financing costs of $1.4 million associated with the previous owner’s revolving credit facility were written-off at the time their debt was repaid and terminated in March 2013. Net interest expense totaled $2.5 million during 2012, including unrealized losses on interest rate swaps of approximately $0.3 million and amortization of deferred financing fees of approximately $0.3 million. Average outstanding borrowings under the Partnership’s revolving credit facility were $370.1 million during 2013 compared to $120.0 million during 2012. Average outstanding borrowings under the previous owners’ revolving credit facilities were $88.5 million during 2013 compared to $134.7 million during 2012.

Liquidity and Capital Resources

Our ability to finance our operations, including funding capital expenditures and acquisitions, to meet our indebtedness obligations, to refinance our indebtedness or to meet our collateral requirements will depend on our ability to generate cash in the future. Our ability to generate cash is subject to a number of factors, some of which are beyond our control, including weather, commodity prices, particularly for oil and natural gas and our ongoing efforts to manage operating costs and maintenance capital expenditures, as well as general economic, financial, competitive, legislative, regulatory and other factors.

As of March 31, 2013, our liquidity of $180.3 million consisted of $8.3 million of available cash and $172.0 million of available borrowings under our revolving credit facility. Our primary sources of liquidity and capital resources are cash flows generated by operating activities and borrowings under our revolving credit facility. We have the ability to issue additional equity and debt as needed through public or private offerings of such securities. We filed a universal shelf registration statement with the SEC, which was declared effective on March 15, 2013, that allows us to issue up to $750.0 million in debt and equity securities for general partnership purposes. Our primary cash requirements are for distributions to our partners, capital expenditures, debt service and working capital needs. The Partnership used the net proceeds of approximately $289.6 million generated from the issuance of the Senior Notes (discussed above), after deducting the initial purchasers’ discounts and commissions but before estimated offering expenses, to repay a portion of the indebtedness outstanding under its revolving credit facility. Upon issuance of the Senior Notes on April 17, 2013, the borrowing base under our revolving credit facility was reduced to $505.0 million, our indebtedness under our revolving credit facility was $118.0 million, and the available borrowing capacity was approximately $387.0 million. In connection with the issuance of our Senior Notes and repayment of indebtedness under our revolving credit facility, we reduced the notional amount of our interest rate swap derivative instruments by entering into offsetting positions. 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.

We expect to fund cash distributions to partners primarily with operating cash flows. We also plan to reinvest a sufficient amount of our operating cash flow to fund our maintenance capital expenditures. Our growth capital expenditures, which include any acquisitions of oil and natural gas properties and related assets, are expected to be primarily funded with borrowings under our revolving credit facility or proceeds from the issuance of additional equity and debt securities. Our debt service requirements are expected to be funded by operating cash flows and/or refinancing arrangements. We expect to fund our working capital needs primarily with operating cash flows. It is our belief that we will continue to have adequate liquidity and capital resources to fund our primary cash requirements.

As of March 31, 2013, we had a positive working capital balance of $15.2 million.

Capital Expenditures

For the three months ended March 31, 2013, our total capital expenditures were $22.1 million. See “— Significant Current Developments” for additional information regarding our acquisition of oil and gas producing properties in March 2013.

35

Revolving Credit Facility

OLLC entered into a $1.0 billion revolving credit facility at the closing of our initial public offering that matures in March 2018 and is guaranteed by us and certain of our current and future subsidiaries. As of March 31, 2013, the borrowing base under our revolving credit facility was $580.0 million and we had $408.0 million of outstanding borrowings. Upon issuance of the Senior Notes on April 17, 2013, the borrowing base under our revolving credit facility was reduced to $505.0 million and we had $118.0 million of outstanding borrowings. The borrowing base is subject to redetermination on at least 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 commodity derivative contracts. Unanimous approval by the lenders is required for any increase to the borrowing base. The next borrowing base redetermination is scheduled for October 2013; however, we may seek an interim redetermination if the need arises. As of March 31, 2013, we were in compliance with all of the financial and other covenants under our revolving credit facility.

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

Senior Notes due 2021

See “— Significant Current Developments” for additional information regarding the issuance of our Senior Notes in a private offering.

Commodity Derivative Contracts

Our hedging policy is designed to reduce the impact to our cash flows from commodity price volatility. Under this policy, we intend to enter into commodity derivative contracts covering approximately 65% to 85% of our estimated production from total proved reserves over a three-to-six year period at any given point of time. We may, however, from time to time hedge more or less than this approximate range. Our revolving credit facility contains various covenants and restrictive provisions which, among other things, limit our ability to enter into commodity price hedges exceeding a certain percentage of production.

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 March 31, 2013, see “Item 3. Quantitative and Qualitative Disclosures About Market Risk — Counterparty and Customer Credit Risk.”

Interest Rate Derivative Contracts

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.

See “Item 3. Quantitative and Qualitative Disclosure About Market Risk” for a summary of our derivative contracts as of March 31, 2013.

Counterparty Exposure

All of our derivative contracts are with major financial institutions who 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.

36

Cash Flows from Operating, Investing and Financing Activities

The following table summarizes our cash flows from operating, investing and financing activities for the periods indicated. The cash flows for the three months ended March 31, 2013 and 2012 has been derived from both our consolidated financial statements and the previous owners’ combined financial statements. The combined financial statements of the previous owners reflect certain oil and gas properties acquired from Memorial Resource in April and May 2012 for periods after common control commenced through their respective acquisition dates, the consolidated financial statements of REO from February 3, 2009 (inception) through December 11, 2012, and the consolidated financial statements of WHT from April 8, 2011 through March 28, 2013. 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.

	For the Three Months     Ended March 31,
	2013		2012
Net cash provided by operating activities	$	28,145	$	31,722
Net cash used in investing activities		(18,195)		(19,460)
Net cash used in financing activities		(9,593)		(7,731)

Three Months Ended March 31, 2013 Compared to the Three Months Ended March 31, 2012

Operating Activities.  Key drivers of net operating cash flows are commodity prices, production volumes and operating costs. Although net income decreased by $37.1 million as further discussed above under “— Results of Operations,” net cash provided by operating activities only decreased by $3.6 million. Non-cash adjustments to net income (loss) increased by $33.4 million. An unrealized loss on derivatives of $15.8 million was recognized during 2013 compared to an unrealized gain on derivatives of $14.2 million recognized during 2012, an increase of $30.0 million. The net effect of changes in operating accounts increased by $0.1 million due to the timing of cash receipts and disbursements.

Investing Activities.  Net cash used in investing activities during 2013 was $18.2 million, of which $16.8 million was used for additions to oil and gas properties. Cash used in investing activities during 2012 was $19.5 million, of which $18.0 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 our offshore Southern California oil and gas properties. Additions to restricted investments during 2013 were $1.3 million compared to $1.1 million during 2012. The period-to-period decrease in additions to other property and equipment was approximately $0.3 million.

Financing Activities.    On March 25, 2013, we issued 9,775,000 common units representing limited partner interests in the Partnership (including 1,275,000 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 $18.35 per unit generating gross proceeds of approximately $179.4 million, offset by approximately $7.1 million of costs incurred in conjunction with the issuance of common units.

Distributions to partners during 2013 were $17.4 million compared to $2.0 million during 2012. The period-to-period increase is due to both an increase in the outstanding units between periods and an increase in the declared cash distribution rate per unit. A $0.5075 per unit distribution was paid on February 13, 2013. An aggregate 34,333,776 common, subordinated, and general partner units participated in this distribution. The $0.0929 per unit pro-rated distribution paid on February 13, 2012 was based upon the minimum quarterly distribution of $0.4750 per unit adjusted to take into account the 18-day period of the fourth quarter of 2011 during which the Partnership was a public entity. An aggregate 22,044,250 common, subordinated, and general partner units participated in this distribution. Distributions made by the previous owners during 2012 were $9.2 million.

We distributed $110.7 million to Memorial Resource in connection with our 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. The Partnership had net borrowings of $37.0 million under its revolving credit facility during 2013 that were used primarily to fund the WHT acquisition. The previous owners had net borrowings of $3.5 million under their revolving credit facilities during 2012. Loan origination fees of approximately $1.7 million were incurred during 2013 compared to less than $0.1 million during 2012.

37

Contractual Obligations

During the three months ended March 31, 2013, there were no significant changes in our consolidated contractual obligations from those reported in our 2012 Form 10-K except for net borrowings made under our revolving credit facility and the credit facility agreement was amended to extend the maturity from December 2016 to March 2018.

See “— Significant Current Developments” for additional information regarding the issuance of the Senior Notes in a private offering on April 17, 2013.

Off–Balance Sheet Arrangements

As of March 31, 2013, 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 Item 7A, “Quantitative and Qualitative Disclosures About Market Risk,” included in our 2012 Form 10-K.

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 March 31, 2013, see Note 5 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under Item 1 of this quarterly report.

The increase in hedged volumes that occurred during the three months ending March 31, 2013 is primarily due to our related party acquisition consummated in March 2013.

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. 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 March 31, 2013 and entered into during April 2013.

At March 31, 2013, we had $207.0 million of Eurodollar borrowings outstanding under our revolving credit facility, with an interest rate of LIBOR plus 2.25%, or 2.46%. We also had $201.0 million of alternative base rate borrowings outstanding under our revolving credit facility, with an interest rate of Prime plus 1.25%, or 4.50%. 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, after giving effect to our interest rate swaps that were in place at March 31, 2013, would be approximately $0.7 million per year. On April 2, 2013, we converted $201.0 million of the alternative base rate borrowings to Eurodollar borrowings at an interest rate of LIBOR plus 2.00%, or 2.21%.

38

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. Each of the counterparties to our derivative contracts is a lender under our credit agreement. While collateral is generally not required to be posted by counterparties, credit risk associated with derivative instruments is minimized by limiting exposure to any single counterparty and entering into derivative instruments only with counterparties that are large financial institutions. Additionally, master netting agreements are used to mitigate risk of loss due to default with counterparties on derivative instruments. These agreements allow us to offset our asset position with our liability position in the event of default by the counterparty. We have also entered into the International Swaps and Derivatives Association Master Agreements (“ISDA Agreements”) with each of our counterparties. The terms of the ISDA Agreements provide us and each of our counterparties with rights of set-off upon the occurrence of defined acts of default by either us or our counterparty to a derivative, whereby the party not in default may set-off all liabilities owed to the defaulting party against all net derivative asset receivables from the defaulting party. As a result, had certain counterparties failed completely to perform according to the terms of the existing contracts, we would have the right to offset $10.7 million against amounts outstanding under our revolving credit facility at March 31, 2013.

ITEM 4.  CONTROLS AND PROCEDURES.

Evaluation of Disclosure Controls and Procedures

As required by Rules 13a-15(b) and 15d-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including the principal executive officer and principal financial officer of our general partner, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) and under the Exchange Act) as of the end of the period covered by this quarterly report. 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 the principal executive officer and principal financial officer of our general partner, 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 the evaluation, the principal executive officer and principal financial officer of our general partner have concluded that our disclosure controls and procedures were effective at the reasonable assurance level as of March 31, 2013.

Change in Internal Controls Over Financial Reporting

No changes in our internal control over financial reporting occurred during the quarter ended March 31, 2013 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.

39

PART II—OTHER INFORMATION

ITEM 1.  LEGAL PROCEEDINGS.

For information regarding legal proceedings, see Part I, Item 1, Financial Statements, Note 13, “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.

There have been no material changes with respect to the risk factors disclosed in our 2012 Form 10-K, except for updated risk factors set forth below related to the issuance of our senior notes on April 17, 2013 in a private offering.

Our leverage and debt service obligations may adversely affect our financial condition, results of operations and business prospects.

We have a substantial amount of indebtedness. After the issuance of our senior notes on April 17, 2013, our indebtedness was approximately $418 million and we had additional borrowing capacity of approximately $387 million under our revolving credit facility. The terms and conditions governing our indebtedness, including our senior notes and our revolving credit facility:

• require us to dedicate a substantial portion of our cash flow from operations to service our existing debt, thereby reducing the cash available to finance our operations and other business activities and could limit our flexibility in planning for or reacting to changes in our business and the industry in which we operate;

• increase our vulnerability to economic downturns and adverse developments in our business;

• limit our ability to access the capital markets to raise capital on favorable terms or to obtain additional financing for working capital, capital expenditures or acquisitions or to refinance existing indebtedness;

• place restrictions on our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations;

• place us at a competitive disadvantage relative to competitors with lower levels of indebtedness in relation to their overall size or less restrictive terms governing their indebtedness;

• make it more difficult for us to satisfy our obligations under our senior notes or other debt and increase the risk that we may default on our debt obligations; and

• limit management’s discretion in operating our business.

Our ability to meet our expenses and debt obligations will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors. We will not be able to control many of these factors, such as economic conditions and governmental regulation. We cannot be certain that our cash flow will be sufficient to allow us to pay the principal and interest on our debt and meet our other obligations. If we do not have enough money, we may be required to refinance all or part of our existing debt, sell assets, borrow more money or raise equity. We may not be able to refinance our debt, sell assets, borrow more money or raise equity on terms acceptable to us, if at all. Our ability to comply with the financial and other restrictive covenants in our indebtedness will be affected by the levels of cash flow from our operations and future events and circumstances beyond our control. Failure to comply with these covenants would result in an event of default under our indebtedness, and such an event of default could adversely affect our business, financial condition and results of operations.

40

Availability under our revolving credit facility is determined semi-annually, as well as upon the occurrence of certain events, by the lenders in their sole discretion, based primarily on reserve reports that reflect our lenders’ projections of future commodity prices at such time. Significant declines in natural gas, NGL or oil prices may result in a decrease in our borrowing base. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our revolving credit facility. Any increase in the borrowing base requires the consent of all the lenders. Outstanding borrowings in excess of the borrowing base must be repaid immediately, or we must pledge other properties as additional collateral. We do not currently have any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under our senior secured revolving credit facility.

We may not be able to generate enough cash flow to meet our debt obligations.

We expect our earnings and cash flow to vary significantly from year to year due to the cyclical nature of our industry. As a result, the amount of debt that we can service in some periods may not be appropriate for us in other periods. Additionally, our future cash flow may be insufficient to meet our debt obligations and commitments. Any insufficiency could negatively impact our business. A range of economic, competitive, business and industry factors will affect our future financial performance, and, as a result, our ability to generate cash flow from operations and to pay our debt. Many of these factors, such as oil and natural gas prices, economic and financial conditions in our industry and the global economy or competitive initiatives of our competitors, are beyond our control.

If we do not generate enough cash flow from operations to satisfy our debt obligations, we may have to undertake alternative financing plans, such as:

• refinancing or restructuring our debt;

• selling assets;

• reducing or delaying capital investments; or

• seeking to raise additional capital.

However, we cannot assure you that undertaking alternative financing plans, if necessary, would allow us to meet our debt obligations. Our inability to generate sufficient cash flow to satisfy our debt obligations or to obtain alternative financing, could materially and adversely affect our ability to make payments on our senior notes and our business, financial condition and results of operations.

We distribute all of our available cash to our unitholders after reserves established by our general partner, which may limit the cash available to service our senior notes or repay them at maturity.

Subject to the limitations on restricted payments contained in the indenture governing our senior notes and in our revolving credit facility, we will distribute all of our “available cash” each quarter to our unitholders. “Available cash” is defined in our partnership agreement.

As a result, we may not accumulate significant amounts of cash. These distributions could significantly reduce the cash available to us in subsequent periods to make payments on our senior notes.

Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.

Borrowings under our revolving credit facility bear interest at variable rates and expose us to interest rate risk. If interest rates increase and we are unable to effectively hedge our interest rate risk, our debt service obligations on the variable rate indebtedness would increase even if the amount borrowed remained the same, and our net income and cash available for servicing our indebtedness would decrease. See “Item 3. Quantitative and Qualitative Disclosures About Market Risk — Interest Price Risk” included under Part I of this quarterly report for further information regarding interest rate sensitivity.

41

Despite our current level of indebtedness, we may still be able to incur substantially more debt. This could further exacerbate the risks associated with our substantial indebtedness.

We and our subsidiaries may be able to incur substantial additional indebtedness in the future, subject to certain limitations, including under our revolving credit facility and under the indenture for our senior notes. If new debt is added to our current debt levels, the related risks that we now face could increase. Our level of indebtedness could, for instance, prevent us from engaging in transactions that might otherwise be beneficial to us or from making desirable capital expenditures. This could put us at a competitive disadvantage relative to other less leveraged competitors that have more cash flow to devote to their operations. In addition, the incurrence of additional indebtedness could make it more difficult to satisfy our existing financial obligations.

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

Our general partner’s 0.1% interest in us was represented by 44,112 general partner units at March 31, 2013. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us in exchange for additional general partner units to maintain its current general partner interest.

During the three months ended March 31, 2013, awards of restricted common units were granted under the Memorial Production Partners GP LLC Long-Term Incentive Plan (“LTIP”) to executive officers and independent directors of our general partner. In conjunction with the issuance of these restricted common units, we issued 17 general partner units on January 9, 2013 to our general partner to maintain its 0.1% interest in us, for which the capital contribution received from our general partner, was less than $0.1 million. The issuance of these general partner units was exempt from registration under Section 4(a)(2) of the Securities Act.

In connection with our underwritten public offering of common units in March 2013, we issued 9,778 general partner units to our general partner on March 25, 2013 to maintain its 0.1% interest in us, for which we received a capital contribution of approximately $0.2 million from our general partner. The issuance of these general partner units was exempt from registration under Section 4(a)(2) of the Securities Act.

ITEM 3.  DEFAULTS UPON SENIOR SECURITIES.

None.

ITEM 4.  MINE SAFETY DISCLOSURES.

Not applicable.

ITEM 5.  OTHER INFORMATION.

None.

42

ITEM 6.  EXHIBITS.

Exhibit Number		Description
2.1##	—	Purchase and Sale Agreement, dated as of September 18, 2012, by and among Memorial Production Operating LLC, Goodrich Petroleum Company, L.L.C. and Goodrich Petroleum Corporation (incorporated by reference to Exhibit 2.1 to Current Report on Form 8-K (File No. 001-35364) filed on September 19, 2012).
2.2##	—	Purchase and Sale Agreement, dated as of November 19, 2012, by and among Memorial Production Operating LLC and Rise Energy Partners, LP (incorporated by reference to Exhibit 2.1 to Current Report on Form 8-K (File No. 001-35364) filed on November 20, 2012).
2.3##	—	Purchase and Sale Agreement, dated as of March 18, 2013, among Memorial Resource Development LLC, Tanos Energy, LLC, WildHorse Resources, LLC and Memorial Production Operating LLC (incorporated by reference to Exhibit 2.1 to Current Report on Form 8-K (File No. 001-35364) filed on March 19, 2013).
3.1	—	Certificate of Limited Partnership of Memorial Production Partners LP (incorporated by reference to Exhibit 3.1 to Registration Statement on Form S-1 (File No. 333-175090) filed on June 23, 2011).
3.2	—	First Amended and Restated Agreement of Limited Partnership of Memorial Production Partners LP (incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K (File No. 001-35364) filed on December 15, 2011).
3.3	—	Certificate of Formation of Memorial Production Partners GP LLC (incorporated by reference to Exhibit 3.4 to Registration Statement on Form S-1 (File No. 333-175090) filed on June 23, 2011).
3.4	—	Amended and Restated Limited Liability Company Agreement of Memorial Production Partners GP LLC (incorporated by reference to Exhibit 3.2 to Current Report on Form 8-K (File No. 001-35364) filed on December 15, 2011).
4.1#	—	Form of Restricted Unit Agreement under the Memorial Production Partners GP LLC Long-Term Incentive Plan (incorporated by reference to Exhibit 4.6 to Registration Statement on Form S-8 (File No. 333-178493) filed on December 14, 2011).
4.2	—	Indenture, dated April 17, 2013, 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 Current Report on Form 8-K (File No. 001-35364) filed on April 17, 2013).
4.3		Registration Rights Agreement, dated April 17, 2013, by and among Memorial Production Partners LP, Memorial Production Finance Corporation, the subsidiary guarantors named therein, and Wells Fargo Securities, LLC, as representative of the several initial purchasers named therein (incorporated by reference to Exhibit 4.2 to Current Report on Form 8-K (File No. 001-35364) filed on April 17, 2013).
10.1*	—	Fourth Amendment to Credit Agreement and First Amendment to Guaranty Agreement, dated as of March 8, 2013, by and among Memorial Production Partners LP, Memorial Production Operating LLC, the other guarantors party thereto, 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.
10.2	—	Fifth Amendment to Credit Agreement, dated as of March 19, 2013, 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 Current Report on Form 8-K (File No. 001-35364) filed on March 21, 2013).

43

10.3	—	Purchase Agreement, dated April 12, 2013, by and among Memorial Production Partners LP, Memorial Production Finance Corporation, the subsidiary guarantors named therein, and Wells Fargo Securities, LLC, as representative of the several initial purchasers named therein (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (File No. 001-35364) filed on April 17, 2013).
31.1*	—	Certification of Chief Executive Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934
31.2*	—	Certification of Chief Financial Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934
32.1*	—	Certifications of Chief Executive Officer and Chief Financial Officer pursuant to 18. U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.CAL*	—	XBRL Calculation Linkbase Document
101.DEF*	—	XBRL Definition Linkbase Document
101.INS*	—	XBRL Instance Document
101.LAB*	—	XBRL Labels Linkbase Document
101.PRE*	—	XBRL Presentation Linkbase Document
101.SCH*	—	XBRL Schema Document

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

# Management contract or compensatory plan or arrangement.

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

44

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 Production Partners LP (Registrant)
	By:	Memorial Production Partners GP LLC, its general partner
Date:         May 10, 2013	By:	/s/ Andrew J. Cozby
	Name:	Andrew J. Cozby
	Title:	Vice President and Chief Financial Officer of Memorial Production Partners GP LLC

45