UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10–Q

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

For the quarterly period ended September 30, 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 October 31, 2013, the registrant had 55,877,831 common units, 5,360,912 subordinated units and 61,300 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 September 30, 2013 and December 31, 2012	9
	Unaudited Condensed Statements of Consolidated and Combined Operations for the Three and Nine Months Ended September 30, 2013 and 2012	10
	Unaudited Condensed Statements of Consolidated and Combined Cash Flows for the Nine Months Ended September 30, 2013 and 2012	11
	Unaudited Condensed Statements of Consolidated and Combined Equity for the Nine Months Ended September 30, 2013	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	16
	Note 5 – Risk Management and Derivative Instruments	18
	Note 6 – Asset Retirement Obligations	21
	Note 7 – Restricted Investments	21
	Note 8 – Long Term Debt	22
	Note 9 – Equity & Distributions	24
	Note 10 – Earnings per Unit	26
	Note 11 – Equity-based Awards	26
	Note 12 – Related Party Transactions	27
	Note 13 – Commitments and Contingencies	29
	Note 14 – Subsequent Events	30
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	31
Item 3.	Quantitative and Qualitative Disclosures About Market Risk.	43
Item 4.	Controls and Procedures.	44
	PART II—OTHER INFORMATION
Item 1.	Legal Proceedings.	45
Item 1A.	Risk Factors.	45
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds.	46
Item 3.	Defaults Upon Senior Securities.	47
Item 4.	Mine Safety Disclosures.	47
Item 5.	Other Information.	47
Item 6.	Exhibits.	48
Signatures		50

i

GLOSSARY OF OIL AND NATURAL GAS TERMS

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

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

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

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

Bbl/d:  One Bbl per day.

Bcf:  One billion cubic feet of natural gas.

Bcfe:  One billion cubic feet of natural gas equivalent.

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

Boe/d:  One Boe per day.

BOEM:  Bureau of Ocean Energy Management.

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

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.

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.

4

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 that the Partnership acquired in March 2013 (the “WHT Properties”) owned by WHT Energy Partners LLC (“WHT”) from February 2, 2011 (inception) 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.

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;

7

• 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)

	September 30,		December 31,
	2013		2012*
ASSETS
Current assets:
Cash and cash equivalents	$	3,356	$	7,990
Accounts receivable:
Oil and natural gas sales		22,140		17,017
Joint interest owners and other		1,271		1,427
Affiliates		3,134		8,497
Short-term derivative instruments		16,390		23,091
Escrow deposits for acquisitions		25,310		--
Prepaid expenses and other current assets		7,041		2,111
Total current assets		78,642		60,133
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method		1,161,793		1,038,962
Other		1,693		1,541
Accumulated depreciation, depletion and impairment		(273,860)		(178,135)
Oil and natural gas properties, net		889,626		862,368
Long-term derivative instruments		27,890		11,524
Restricted investments		72,288		68,024
Other long–term assets		10,444		4,141
Total assets	$	1,078,890	$	1,006,190
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	4,388	$	1,033
Accounts payable – affiliates		3,049		1,738
Revenues payable		9,050		3,108
Accrued liabilities		43,542		12,448
Short-term derivative instruments		3,184		2,635
Total current liabilities		63,213		20,962
Long-term debt (Note 8)		492,724		460,300
Asset retirement obligations		82,568		78,286
Long-term derivative instruments		5,795		9,578
Other long-term liabilities		2,059		2,100
Total liabilities		646,359		571,226
Commitments and contingencies (Note 13)
Equity:
Limited partners:
Common units (39,194,060 units outstanding at September 30, 2013 and 28,921,903 units outstanding at December 31, 2012)		415,226		301,204
Subordinated units (5,360,912 units outstanding at September 30, 2013 and December 31, 2012)		11,256		20,156
General partner (44,601 units outstanding at September 30, 2013 and 34,317 units outstanding at December 31, 2012)		568		450
Total partners’ equity		427,050		321,810
Noncontrolling interests		5,481		5,261
Previous owners		--		107,893
Total equity		432,531		434,964
Total liabilities and equity	$	1,078,890	$	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 September 30,				For the Nine Months         Ended September 30,
	2013		2012*		2013*		2012*
Revenues:
Oil & natural gas sales	$	59,194	$	42,395	$	160,838	$	124,525
Pipeline tariff income and other		267		421		873		1,239
Total revenues	$	59,461	$	42,816	$	161,711	$	125,764
Costs and expenses:
Lease operating		14,803		14,114		40,262		39,633
Pipeline operating		394		470		1,343		1,628
Exploration		--		2		114		509
Production and ad valorem taxes		3,025		2,030		8,020		6,887
Depreciation, depletion, and amortization		16,094		13,056		45,409		36,011
Impairment of proved oil and natural gas properties		50,291		--		50,291		--
General and administrative		8,335		3,768		18,752		11,972
Accretion of asset retirement obligations		1,025		936		3,022		2,810
(Gain) loss on commodity derivative instruments		(1,443)		28,427		(24,158)		(10,224)
(Gain) loss on sale of properties		--		--		--		(426)
Other, net		--		141		--		465
Total costs and expenses		92,524		62,944		143,055		89,265
Operating income (loss)		(33,063)		(20,128)		18,656		36,499
Other income (expense):
Interest expense, net		(10,007)		(4,163)		(21,506)		(11,399)
Amortization of investment premium		--		(25)		--		(170)
Total other income (expense)		(10,007)		(4,188)		(21,506)		(11,569)
Income (loss) before income taxes		(43,070)		(24,316)		(2,850)		24,930
Income tax benefit (expense)		(97)		171		(285)		(244)
Net income (loss)		(43,167)		(24,145)		(3,135)		24,686
Net income (loss) attributable to previous owners		--		1,095		(1,219)		29,361
Net income (loss) attributable to noncontrolling interest		126		92		220		17
Net income (loss) attributable to partners	$	(43,293)	$	(25,332)	$	(2,136)	$	(4,692)
Allocation of net income (loss) attributable to partners:
Limited partners	$	(43,250)	$	(25,307)	$	(2,134)	$	(4,687)
General partner	$	(43)	$	(25)	$	(2)	$	(5)
Earnings per unit: (Note 10)
Basic and diluted earnings per unit	$	(0.97)	$	(1.13)	$	(0.05)	$	(0.21)
Weighted average limited partner units outstanding:
Basic and diluted		44,556		22,302		41,315		22,241

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 Nine Months         Ended September 30,
	2013*		2012*
Cash flows from operating activities:
Net income (loss)	$	(3,135)	$	24,686
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization		45,409		36,011
Impairment of proved oil and natural gas properties		50,291		--
(Gain) loss on derivatives		(24,581)		(5,593)
Cash settlements on derivative instruments		11,682		29,765
Deferred income tax expense (benefit)		--		26
Amortization of deferred financing costs		3,895		828
Accretion of senior notes net discount		161		--
Amortization of investment premium		--		170
Accretion of asset retirement obligations		3,022		2,810
Amortization of equity awards		2,322		993
Gain on sale of properties		--		(426)
Exploration costs		95		--
Changes in operating assets and liabilities:
Accounts receivable		396		(7,098)
Prepaid expenses and other assets		(3,816)		1,560
Payables and accrued liabilities		25,587		4,059
Net cash provided by operating activities		111,328		87,791
Cash flows from investing activities:
Acquisitions of oil and natural gas properties		(29,359)		(129,637)
Additions to oil and gas properties		(76,329)		(41,717)
Additions to restricted investments		(4,263)		(3,651)
Additions to other property and equipment		(126)		(837)
Escrow deposits for acquisitions		(25,310)		--
Proceeds from the sale of oil and natural gas properties		--		500
Net cash used in investing activities		(135,387)		(175,342)
Cash flows from financing activities:
Advances on revolving credit facilities		299,000		194,000
Payments on revolving credit facilities		(664,300)		(30,900)
Deferred financing costs		(11,218)		(411)
Proceeds from the issuances of senior notes		397,563		--
Proceeds from general partner contribution		189		--
Proceeds from the issuance of common units		179,371		--
Costs incurred in conjunction with issuance of common units		(7,592)		--
Distributions to partners		(62,888)		(23,430)
Distribution to Memorial Resource (see Note 1)		(110,700)		(45,489)
Distributions made by previous owners		--		(8,900)
Net cash provided by financing activities		19,425		84,870
Net change in cash and cash equivalents		(4,634)		(2,681)
Cash and cash equivalents, beginning of period		7,990		9,624
Cash and cash equivalents, end of period	$	3,356	$	6,943
Supplemental cash flows:
Cash paid for interest	$	6,212	$	6,509
Additions to oil and gas properties – change in capital accruals		15,858		6,461

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)		(1,938)		(196)		(2)		(1,219)		220		(3,135)
Net proceeds from the issuance of common units		171,779		--		--		--		--		171,779
Contributions		--		--		189		--		--		189
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		2,322		--		--		--		--		2,322
Distributions		(54,609)		(8,216)		(63)		--		--		(62,888)
Balance September 30, 2013	$	415,226	$	11,256	$	568	$	--	$	5,481	$	432,531

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 that the Partnership acquired in March 2013 (the “WHT Properties”) owned by WHT Energy Partners LLC (“WHT”) from February 2, 2011 (inception) 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 were 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 and nine months ended September 30, 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 recast audited consolidated and combined financial statements and notes thereto included in our Current Report on Form 8-K filed on June 19, 2013 (our “Recast Form 8-K”). On October 1, 2013, we filed a Current Report on Form 8-K, which included audited supplemental financial statements that retrospectively revised certain of our financial and other information to give effect to the Cinco Group acquisition (see Note 12). This Quarterly Report on Form 10-Q has not been recast for the Cinco Group acquisition which closed on October 1, 2013.

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 Recast Form 8-K.

Current Liabilities

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

	September 30,		December 31,
	2013		2012
Accrued capital expenditures	$	20,600	$	4,742
Accrued lease operating expense		4,966		3,944
Accrued interest payable(1)		13,994		618
Accrued ad valorem		3,073		341
Other		909		2,803
	$	43,542	$	12,448
(1)    Increase in accrued interest payable primarily due to issuances of Senior Notes (see Note 8).

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

Related Party. See Note 12 for further information regarding related party acquisitions that have been accounted for as transactions between entities under common control that impact the basis of presentation for the periods presented.

Third Party. We closed two separate transactions during the three and nine months ended September 30, 2013 to acquire certain oil and natural gas properties from third parties in East Texas (the “East Texas Acquisition”) and the Rockies (the “Rockies Acquisition”) for approximately $29.0 million in aggregate, subject to customary post-closing adjustments. The East Texas Acquisition closed on September 6, 2013 and the Rockies Acquisition closed on August 30, 2013. The following table summarizes our preliminary purchase price allocations as of each acquisition date (in thousands):

	East Texas     Acquisition		Rockies     Acquisition
Oil and gas properties	$	9,974	$	20,744
Asset retirement obligations		(78)		(1,163)
Accrued liabilities		--		(118)
Total identifiable net assets	$	9,896	$	19,463

On May 1, 2012, we acquired non-operating interests in certain oil and natural gas properties located in East Texas and North Louisiana from an undisclosed third party seller for a final net purchase price of approximately $36.5 million after customary post-closing adjustments.

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

For the Three Months         Ended September 30,			For the Nine Months Ended September 30,
2013	2012		2013		2012
$                    2,310	$	381	$	3,422	$	780

15

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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 and nine months ended September 30, 2012 as though these 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 September 30,		For the Nine Months     Ended September 30,
	2012		2012
	(In thousands, except per unit amounts)
Revenues	$	47,634	$	146,777
Net income (loss)		(22,455)		33,140
Basic and diluted earnings per unit		(1.06)		0.17

Note 4. Fair Value Measurements of Financial Instruments

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

The carrying values of accounts receivables, accounts payables (including accrued liabilities) and amounts outstanding under long-term debt agreements with variable rates included in the accompanying balance sheets approximated fair value at September 30, 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. See Note 8 for the estimated fair value of our outstanding fixed-rate debt.

16

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 fair market values of the derivative financial instruments reflected on the balance sheets as of September 30, 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 September 30, 2013 and December 31, 2012 for each of the fair value hierarchy levels:

	Fair Value Measurements at September 30, 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	$	--	$	87,487	$	--	$	87,487
Liabilities:
Commodity derivatives	$	--	$	48,450	$	--	$	48,450
Interest rate derivatives		--		3,736		--		3,736
Total liabilities	$	--	$	52,186	$	--	$	52,186
	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	$	--	$	69,303	$	--	$	69,303
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.

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

17

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

During three and nine months ended September 30, 2013, we recognized $50.3 million of impairments. The impairments related to certain properties located in East Texas. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable as a result of a downward revision of estimated proved reserves based on updated well performance data. The carrying value of these properties after impairment was approximately $31.5 million. We did not have any impairment charges for 2012.

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 $25.5 million against amounts outstanding under our revolving credit facility at September 30, 2013, reducing our maximum credit exposure to approximately $18.8 million, of which approximately $11.6 million was with a single counterparty. See Note 8 for additional information regarding our revolving credit facility.

18

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, costless collars, call spreads and basis swaps) to manage exposure to commodity price volatility. Historically, the Partnership has not paid or received premiums for put options. We enter into natural gas derivative contracts that are indexed to NYMEX Henry Hub and regional indices such as NGPL TXOK, TETCO STX, 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 September 30, 2013, we had the following open commodity positions:

	Remaining 2013		2014		2015		2016		2017		2018		2019
Natural Gas Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (MMBtu)		1,345,172		1,860,458		1,785,278		1,842,442		1,690,067		1,660,000		1,514,583
Weighted-average fixed price	$	4.32	$	4.34	$	4.30	$	4.47	$	4.33	$	4.58	$	4.87
Collar contracts:
Average Monthly Volume (MMBtu)		840,000		300,000		200,000		--		--		--		--
Weighted-average floor price	$	4.82	$	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)		1,620,932		2,224,583		--		--		--		--		--
Spread	$	(0.10)	$	(0.09)	$	--	$	--	$	--	$	--	$	--
Crude Oil Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		73,632		78,477		96,281		116,013		105,500		100,000		--
Weighted-average fixed price	$	102.53	$	97.40	$	93.72	$	86.97	$	85.84	$	85.34	$	--
Collar contracts:
Average Monthly Volume (Bbls)		10,600		8,000		--		--		--		--		--
Weighted-average floor price	$	88.87	$	90.00	$	--	$	--	$	--	$	--	$	--
Weighted-average ceiling price	$	118.59	$	117.72	$	--	$	--	$	--	$	--	$	--
Basis swaps:
Average Monthly Volume (Bbls)		40,000		49,958		47,500		--		--		--		--
Spread	$	(10.20)	$	(9.04)	$	(9.60)	$	--	$	--	$	--	$	--
NGL Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		94,871		84,150		85,300		--		--		--		--
Weighted-average fixed price	$	39.49	$	39.76	$	35.12	$	--	$	--	$	--	$	--

(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.

19

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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. In connection with the issuances of senior notes in April and May 2013 (see Note 8), we entered into offsetting interest rate swap derivative instruments to avoid being economically over-hedged. At September 30, 2013, we had the following interest rate swap open positions:

Period Covered	Notional     ($ in thousands)		Floating Rate	Fixed Rate			Fixed Rate Payer
April 2011 to April 2014 (1)	$	75,000	1 Month LIBOR		1.510	%	Partnership
April 2013 to October 2013	$	75,000	1 Month LIBOR		1.510	%	Counterparty
January 2013 to December 2016	$	100,000	1 Month LIBOR		1.305	%	Partnership
April 2013 to October 2013	$	40,000	1 Month LIBOR		1.305	%	Counterparty
January 2013 to December 2016	$	50,000	1 Month LIBOR		0.970	%	Partnership
October 2013 to April 2014	$	40,000	1 Month LIBOR		1.370	%	Partnership
April 2014 to October 2014	$	75,000	1 Month LIBOR		1.640	%	Partnership
June 2013 to October 2013	$	110,000	1 Month LIBOR		1.153	%	Counterparty
October 2014 to February 2015	$	110,000	1 Month LIBOR		1.400	%	Partnership

  (1) These interest rate swaps were novated to the Partnership from the previous owners in connection with the March 2013 acquisition.

Subsequent event. In October 2013, we entered into offsetting interest rate swap derivative instruments to avoid being economically over-hedged. We will receive the fixed rate and will pay the floating rate as follows:

Period Covered	Notional     ($ in thousands)		Floating Rate	Fixed Rate			Fixed Rate Payer
October 2013 to April 2014	$	150,000	1 Month LIBOR		1.193	%	Counterparty
October 2013 to April 2014	$	75,000	1 Month LIBOR		1.510	%	Counterparty
February 2015 to August 2015	$	225,000	1 Month LIBOR		1.715	%	Partnership

Balance Sheet Presentation

The following table summarizes both: (i) the gross fair value of derivative instruments by the appropriate balance sheet classification even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the balance sheet and (ii) the net recorded fair value as reflected on the balance sheet at September 30, 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
			September 30,		December 31,		September 30,		December 31,
Type	Balance Sheet Location		2013		2012		2013		2012
			(In thousands)
Natural gas contracts		Short-term derivative instruments	$	18,714	$	22,069	$	582	$	961
Oil contracts		Short-term derivative instruments		3,469		6,453		6,102		4,483
NGL contracts		Short-term derivative instruments		1,722		871		1,515		1,124
Interest rate swaps		Short-term derivative instruments		--		--		2,500		2,369
Gross fair value				23,905		29,393		10,699		8,937
Netting arrangements		Short-term derivative instruments		(7,515)		(6,302)		(7,515)		(6,302)
Net recorded fair value		Short-term derivative instruments	$	16,390	$	23,091	$	3,184	$	2,635
Natural gas contracts		Long-term derivative instruments	$	30,067	$	17,435	$	6,055	$	9,352
Oil contracts		Long-term derivative instruments		32,663		22,471		32,989		25,360
NGL contracts		Long-term derivative instruments		852		4		1,207		534
Interest rate swaps		Long-term derivative instruments		--		--		1,236		2,718
Gross fair value				63,582		39,910		41,487		37,964
Netting arrangements		Long-term derivative instruments		(35,692)		(28,386)		(35,692)		(28,386)
Net recorded fair value		Long-term derivative instruments	$	27,890	$	11,524	$	5,795	$	9,578

20

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

(Gains) Losses on Derivatives

We do not designate derivative instruments as hedging instruments for accounting and financial reporting purposes and neither did the previous owners. Accordingly, all gains and losses, including changes in the derivative instruments’ fair values, have been recorded in the accompanying statements of operations. The following table details the gains and losses related to derivative instruments for the three and nine months ended September 30, 2013 and 2012 (in thousands):

		For the Three Months Ended September 30,				For the Nine Months Ended September 30,
Statements of                 Operations Location		2013		2012		2013		2012
Commodity derivative contracts	(Gain) loss on commodity derivatives	$	(1,443)	$	28,427	$	(24,158)	$	(10,224)
Interest rate derivatives	Interest expense		1,022		1,604		(423)		4,631

Note 6. Asset Retirement Obligations

The Partnership’s asset retirement obligations primarily relate to the Partnership’s portion of future plugging and abandonment costs for wells and related facilities. The following table presents the changes in the asset retirement obligations for the nine months ended September 30, 2013 (in thousands):

Asset retirement obligations at beginning of period	$	78,286
Liabilities added from acquisitions or drilling		1,278
Liabilities removed upon plugging and abandoning		(18)
Accretion expense		3,022
Asset retirement obligations at end of period	$	82,568

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:

	September 30,		December 31,
	2013		2012
	(In thousands)
BOEM platform abandonment (See Note 13)	$	65,390	$	61,389
BOEM lease bonds		776		776
SPBPC Collateral:
Contractual pipeline and surface facilities abandonment		2,222		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	$	72,288	$	68,024

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Note 8. Long Term Debt

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

	September 30,		December 31,
	2013		2012
	(In thousands)
OLLC $1.0 billion multi-year revolving credit facility, variable-rate, due March 2018	$	95,000	$	371,000
7.625% senior notes, fixed-rate, due May 1, 2021 (1)		400,000		--
WHT $400.0 million revolving credit facility, variable-rate, terminated March 2013		--		89,300
Unamortized discounts		(2,276)		--
Total long-term debt	$	492,724	$	460,300

(1) The estimated fair value of our fixed-rate debt was $386.0 million. The estimated fair value is based on quoted market prices and is classified as Level 1 within the fair value hierarchy.

Subsidiary Guarantors

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. Any debt securities issued will be governed by an indenture. Furthermore, any debt securities issued may be jointly and severally, fully and unconditionally guaranteed (subject to customary release provisions) by certain of the Partnership’s subsidiaries (collectively, the “Guarantor Subsidiaries”). The Guarantor Subsidiaries are 100% owned by the Partnership. The Partnership has no material assets or operations independent of the Guarantor Subsidiaries and there are no significant restrictions upon the ability of the Guarantor Subsidiaries to distribute funds to the Partnership.

Borrowing Base

Credit facilities tied to borrowing bases are common throughout the oil and gas industry. The borrowing base for each credit facility was the following at the dates indicated:

	September 30,		December 31,
	2013		2012
	(In thousands)
OLLC $1.0 billion multi-year revolving credit facility, variable-rate, due March 2018	$	480,000	$	460,000
WHT $400.0 million revolving credit facility, variable-rate, terminated March 2013		--		120,000
Total borrowing base	$	480,000	$	580,000

The borrowing base increased to $580.0 million effective March 28, 2013. The borrowing base was then automatically reduced by $100.0 million in conjunction with the issuances of senior notes in April and May 2013 in accordance with the terms of our credit facility. Effective October 1, 2013, the borrowing base was increased by $440.0 million, as discussed below. On October 10, 2013, the borrowing base was automatically reduced by $75.0 million in conjunction with the issuance of additional senior notes, as discussed below.

OLLC Revolving Credit Facility

OLLC entered into a $1.0 billion revolving credit facility at the closing of our initial public offering, which is guaranteed by us and certain of our current and future subsidiaries. On September 26, 2013, we entered into a sixth amendment to our credit agreement, which among other things: (i) increased the maximum aggregate credit amounts under the revolving facility from $1.0 billion to $2.0 billion and (ii) increased the borrowing base from $480.0 million to $920.0 million upon the closing of the Cinco Group acquisition on October 1, 2013 as further discussed in Note 12.

WHT Revolving Credit Facility

WHT entered into a $400.0 million revolving credit facility on April 8, 2011 with a maturity date of April 8, 2016. On March 28, 2013, the debt balance then outstanding under the revolving credit facility of $89.3 million and all accrued interest was paid off in full and the revolving credit facility was terminated.

22

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

REO Revolving Credit Facility

On October 26, 2011, REO entered into a three-year, $150.0 million revolving credit facility. On December 12, 2012, indebtedness then outstanding under the revolving credit facility of $28.5 million and all accrued interest was paid off in full and the revolving credit facility was terminated.

7.625% Senior Notes

On April 17, 2013, we and 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 fully and unconditionally guaranteed (subject to customary release provisions) on a joint and several basis by the Guarantor Subsidiaries and by certain future subsidiaries of the Partnership. On May 23, 2013, the Issuers issued an additional $100.0 million aggregate principal amount of the Senior Notes at 102.0% of par. On October 10, 2013, the Issuers issued an additional $300.0 million aggregate principal amount of the Senior Notes at 97.0% of par. 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. The Senior Notes are governed by an indenture. The Senior Notes are subject to optional redemption at prices specified in the indenture plus accrued and unpaid interest, if any. The Issuers may also be required to repurchase the Senior Notes upon a change of control. The indenture contains customary covenants and restrictive provisions, many of which will terminate if at any time no default exists under the indenture and the Senior Notes receive an investment grade rating from both of two specified ratings agencies. The indenture also provides for customary and other events of default. In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to either of the 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.

Weighted-Average Interest Rates

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

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2013		2012		2013		2012
OLLC revolving credit facility		2.13%		2.79%		2.55%		2.79%
WHT revolving credit facility		n/a		2.88%		2.29%		2.81%
REO revolving credit facility		n/a		3.19%		n/a		3.31%

23

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Unamortized Deferred Financing Costs

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

	September 30,		December 31,
	2013		2012
	(In thousands)
OLLC $1.0 billion multi-year revolving credit facility, variable-rate, due March 2018 (1)	$	3,542	$	3,359
Senior Notes (2)		8,871		--
WHT $400.0 million revolving credit facility, variable-rate, terminated March 2013 (3)		--		1,419

(1) Additional financing costs were incurred in connection with the borrowing base increase that became effective March 28, 2013. Unamortized deferred financing costs are amortized over the remaining life of our revolving credit facility. As disclosed above, the borrowing base was automatically reduced upon issuance of the Senior Notes. As a result, approximately $0.9 million of deferred financing costs were written-off during the nine months ended September 30, 2013 and are included in interest expense in the accompanying statements of operations.

(2) Unamortized deferred financing costs are amortized using the straight line method which approximates the effective interest method.

(3) The unamortized deferred financing costs were written-off at the time the debt was repaid and the facility was terminated on March 28, 2013.

Advances and Repayments

The following table presents borrowings and repayments under our consolidated and combined revolving credit facilities for the periods presented (in thousands):

	OLLC Revolving Credit Facility		WHT Revolving Credit Facility		REO Revolving Credit Facility		Total
For the Nine Months Ended September 30, 2013:
Advances on revolving credit facility	$	298,000	$	1,000	$	--	$	299,000
Payments on revolving credit facility		(574,000)		(90,300)		--		(664,300)
For the Nine Months Ended September 30, 2012:
Advances on revolving credit facility	$	186,000	$	1,000	$	7,000	$	194,000
Payments on revolving credit facility		(13,000)		(5,900)		(12,000)		(30,900)

Note 9. Equity & Distributions

2013 Public Equity Offerings

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 $171.8 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 all of the outstanding equity interests in WHT as further discussed under Note 12.

See Note 14 for additional information regarding our October 2013 public equity offering.

24

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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		515,947		--		--
Restricted common units forfeited		(11,734)		--		--
Restricted common units repurchased (1)		(7,056)		--		--
General partner units issued		--		--		10,284
Balance September 30, 2013		39,194,060		5,360,912		44,601

(1) Restricted common units are generally net-settled by unitholders to cover the required withholding tax upon vesting. Unitholders surrendered units with value equivalent to the employees’ minimum statutory obligation for the applicable income and other employment taxes. Total payments remitted for the employees’ tax obligations to the appropriate taxing authorities were $0.1 million. These net-settlements had the effect of unit repurchases by the Partnership as they reduced the number of units that would have otherwise been outstanding as a result of the vesting and did not represent an expense to the Partnership.

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 during the nine months ended September 30, 2013.

As of September 30, 2013, Memorial Resource owned approximately 18.0% 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, the remaining 50% 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 after giving effect to priority earnings allocations in an amount equal to incentive cash distributions allocated to our general partner. 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 (2)		Memorial Resource Distribution
3rd Quarter 2013	October 22, 2013	November 1, 2013	November 12, 2013	$	0.5500	$	33.8	$	6.9
2nd Quarter 2013	July 18, 2013	August 1, 2013	August 12, 2013	$	0.5125	$	22.9	$	6.4
1st Quarter 2013	April 18, 2013	May 1, 2013	May 13, 2013	$	0.5125	$	22.6	$	6.4
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.

  (2) The aggregate distribution for the third quarter of 2013 reflects the October 2013 public equity offering (see Note 14).

25

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     September 30,		For the Three Months Ended     September 30,		For the Nine Months Ended     September 30,		For the Nine Months Ended     September 30,
	2013		2012		2013		2012
Net income (loss) attributable to partners	$	(43,293)	$	(25,332)	$	(2,136)	$	(4,692)
Less: General partner’s 0.1% interest in net income (loss)		(43)		(25)		(2)		(5)
Less: IDRs		(40)		--		(40)		--
Net income (loss) available to limited partners	$	(43,210)	$	(25,307)	$	(2,094)	$	(4,687)
Weighted average limited partner units outstanding:
Common units		39,195		16,941		35,954		16,880
Subordinated units		5,361		5,361		5,361		5,361
Total		44,556		22,302		41,315		22,241
Basic and diluted EPU	$	(0.97)	$	(1.13)	$	(0.05)	$	(0.21)

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)		515,947	$	18.81
Forfeited		(11,734)	$	17.24
Vested		(91,154)	$	18.31
Restricted common units outstanding at September 30, 2013		698,668	$	18.60

(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 $9.7 million based on grant date market prices ranging from of $18.33 to $19.88 per unit.

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

For the Three Months Ended September 30,				For the Nine Months Ended September 30,
2013		2012		2013		2012
$	1,237	$	418	$	2,322	$	993

The unrecognized compensation cost associated with restricted common unit awards was $11.3 million at September 30, 2013. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.39 years. Since the restricted common units are participating securities, distributions received by the restricted common unitholders are generally included in distributions to partners as presented on our unaudited condensed statements of consolidated and combined cash flows.

26

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Note 12. Related Party Transactions

Amounts due to (due from) Memorial Resource and certain of its subsidiaries at September 30, 2013 and December 31, 2012 are presented as “Accounts receivable – affiliates” and “Accounts payable – affiliates” in the accompanying balance sheets.

The following table summarizes the amount of related party transactions reflected in the accompanying statements of operations for the periods presented (in thousands):

For the Three Months Ended September 30,				For the Nine Months Ended September 30,
2013		2012		2013		2012
$	3,151	$	1,614	$	7,880	$	4,747

These costs and expenses, the vast majority of which are general and administrative, represent payments under our omnibus agreement (as discussed below) and management fees paid to affiliates for operating our assets.

Common Control Acquisitions

October 2013 Acquisition. On October 1, 2013, we acquired, through equity and asset transactions, oil and natural gas properties primarily in the Permian Basin, East Texas and the Rockies from Memorial Resource and certain affiliates of NGP for an aggregate purchase price of approximately $603 million, subject to customary post-closing adjustments. We refer to this transaction as the “Cinco Group acquisition.” The Cinco Group acquisition was funded with borrowings under our revolving credit facility. 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 Cinco Group acquisition was accounted for as a combination of entities under common control at historical cost in a manner similar to the pooling of interest method.

Concurrent with the closing of the Cinco Group acquisition, our revolving credit facility was amended to increase the maximum borrowing capacity to $2.0 billion from $1.0 billion. The borrowing base was also increased from $480.0 million to $920.0 million. On October 10, 2013, the borrowing base was automatically reduced by $75.0 million in conjunction with the issuance of additional Senior Notes. See Note 8 for additional information regarding our revolving credit facility and Senior Notes.

Our Current Report on Form 8-K filed on October 1, 2013 included audited supplemental consolidated and combined balance sheets as of December 31, 2012 and 2011, and the related supplemental consolidated and combined statements of operations, equity, and cash flows for each of the years in the three-year period ended December 31, 2012 to retrospectively revise certain of our financial and other information to give effect to the Cinco Group acquisition. Such information was previously revised for the WHT acquisition as described in and filed with our Current Report on Form 8-K filed on June 19, 2013. This Quarterly Report on Form 10-Q has not been recast for the Cinco Group acquisition, which closed on October 1, 2013.

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. The acquired 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. The Partnership recorded the following net assets (in thousands):

27

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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.

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. The following table summarizes the amount of general and administrative expenses recognized under the omnibus agreement that are reflected in the accompanying statements of operations for the periods presented (in thousands):

For the Three Months Ended September 30,				For the Nine Months Ended September 30,
2013		2012		2013		2012
$	2,988	$	526	$	6,239	$	1,185

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 Agreement

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 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.

28

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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. The following table summarizes the amount of management fees REO incurred and paid, which are included in general and administrative expenses in the accompanying statements of operations for the periods presented (in thousands):

For the Three Months         Ended September 30,	For the Nine Months         Ended September  30,
2012	2012
$                                     345	$                            1,500

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 Credit Facility

As of November 1, 2013, 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, 5,360,912 of our subordinated units, and its ownership in our general partner as well as its oil and gas properties and certain other assets of Memorial Resource as security under the credit facility.

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 September 30, 2013 and December 31, 2012, we had $0.5 million and $1.1 million of environmental reserves recorded on our balance sheets, respectively.

29

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 September 30, 2013 (in thousands):

Investment	Amortized     Cost		Unrealized     Gain (Loss)		Fair Market     Value
U.S. Bank Money Market Cash Equivalent	$	103,285	$	--	$	103,285
U.S. Government Treasury Note, maturity of March 31, 2014, and 1.75% coupon		23,073		194		23,267
Less: Outside working interest owners share		(60,968)		(93)		(61,061)
	$	65,390	$	101	$	65,491

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

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

As of September 30, 2013, the maximum remaining obligation net to REO’s interest was approximately $13.2 million.

Note 14. Subsequent Events

Common Control Acquisition

The Cinco Group acquisition closed on October 1, 2013. See Note 12 for additional information regarding this acquisition. Additionally, our revolving credit facility was amended concurrent with the closing of the Cinco Group acquisition. See Note 8 for additional information regarding the amendment to our revolving credit facility.

October 2013 Public Equity Offering

On October 8, 2013, we issued 16,675,000 common units representing limited partner interests in the Partnership (including 2,175,000 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 $19.90 per unit. The net proceeds, including our general partner’s proportional capital contributions and after deducting underwriting discounts and commissions but before estimated expenses, was approximately $319.2 million. The net proceeds were used to repay a portion of outstanding borrowings under our revolving credit facility.

October 2013 Senior Notes Offering

On October 10, 2013, the Issuers issued an additional $300.0 million aggregate principal amount of the Senior Notes at 97.0% of par. See Note 8 for more information regarding our Senior Notes.

30

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 Recast Form 8-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. As of October, 1, 2013, our assets consist primarily of producing oil and natural gas properties and are principally located in Texas, Louisiana, Colorado, Wyoming, New Mexico 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. As of December 31, 2012, after giving retrospective effect to the WHT acquisition, which closed on March 28, 2013, and the Cinco Group acquisition (as described below), which closed on October 1, 2013:

• Our total estimated proved reserves were approximately 1,015 Bcfe, of which approximately 60% were natural gas and 61% were classified as proved developed reserves;

• We produced from 2,922 gross (1,649 net) producing wells across our properties, with an average working interest of 57%, and we or Memorial Resource operated 94% of the properties in which we have interests; and

• Our average net production for the three months ended December 31, 2012 was 125.7 MMcfe/d, implying a reserve-to-production ratio of approximately 22 years.

Significant Recent Developments

Acquisitions of Oil & Natural Gas Properties from Affiliates

On October 1, 2013, we acquired, through equity and asset transactions, oil and natural gas properties primarily in the Permian Basin, East Texas and the Rockies from Memorial Resource and certain affiliates of NGP for an aggregate purchase price of approximately $603 million, subject to customary post-closing adjustments. We refer to this transaction as the “Cinco Group acquisition.” The Cinco Group acquisition was funded with borrowings under our revolving credit facility. Terms of the transaction were approved by the Board and by its conflicts committee, which is comprised entirely of independent directors. 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.

On September 26, 2013, we entered into a sixth amendment to our credit agreement, which among other things: (i) increased the maximum aggregate credit amounts under the revolving facility from $1.0 billion to $2.0 billion and (ii) increased the borrowing base from $480.0 million to $920.0 million upon the closing of the Cinco Group acquisition on October 1, 2013. On October 10, 2013, the borrowing base was automatically reduced by $75.0 million in conjunction with the issuance of additional senior notes, as discussed below.

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Our Current Report on Form 8-K filed on October 1, 2013, included audited supplemental consolidated and combined balance sheets as of December 31, 2012 and 2011, and the related supplemental consolidated and combined statements of operations, equity, and cash flows for each of the years in the three-year period ended December 31, 2012 to retrospectively revise our Recast Form 8-K to give effect to the Cinco Group acquisition. Such information was previously revised for the WHT acquisition as described in and filed with our Current Report on Form 8-K filed on June 19, 2013. This Quarterly Report on Form 10-Q has not been recast for the Cinco Group acquisition which closed on October 1, 2013.

7.625% Senior Notes

On April 17, 2013, we and 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 fully and unconditionally guaranteed (subject to customary release provisions) on a joint and several basis by certain of the Partnership’s subsidiaries and by certain future subsidiaries of the Partnership. On May 23, 2013, the Issuers issued an additional $100.0 million aggregate principal amount of the Senior Notes at 102.0% of par. On October 10, 2013, the Issuers issued an additional $300.0 million aggregate principal amount of the Senior Notes at 97.0% of par. As of October 10, 2013, there were $700.0 million of outstanding Senior Notes. 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 the Senior Notes, see Note 8 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under Item 1 of this quarterly report.

October 2013 Public Equity Offering

On October 8, 2013, we issued 16,675,000 common units representing limited partner interests in the Partnership (including 2,175,000 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 $19.90 per unit. The net proceeds, including our general partner’s proportional capital contributions and after deducting underwriting discounts and commissions but before estimated expenses, was approximately $319.2 million. The net proceeds were used to repay a portion of outstanding borrowings under our revolving credit facility.

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) cash settlements on our commodity derivatives; (iv) lease operating expenses; (v) general and administrative expenses; and (vi) 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.

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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 2019, we have mitigated, but not eliminated, the potential effects of changing commodity prices on our cash flows from operations for those periods.

It has been our practice to enter into costless collars and fixed price swaps only with lenders under our credit agreement. Historically, the Partnership has not paid or received premiums for put options; however, from time to time our predecessor and the previous owners did enter into such agreements.

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 gains or 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”);

• Loss on commodity derivative instruments;

• Cash settlements received on commodity derivative instruments;

• Losses on sale of assets and other, net;

• Unit-based compensation expenses;

• Exploration costs;

• Acquisition related costs;

• Amortization of investment premium;

• Other non-routine items that we deem appropriate.

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Less:

• Interest income;

• Income tax benefit;

• Gain on commodity derivative instruments;

• Cash settlements paid on commodity derivative instruments;

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

• Other non-routine items that we deem appropriate.

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 September 30,				For the Nine Months Ended September 30,
	2013		2012		2013		2012
Calculation of Adjusted EBITDA:
Net income (loss)	$	(43,167)	$	(24,145)	$	(3,135)	$	24,686
Interest expense, net		10,007		4,163		21,506		11,399
Income tax expense (benefit)		97		(171)		285		244
DD&A		16,094		13,056		45,409		36,011
Impairment of proved oil and natural gas properties		50,291		--		50,291		--
Accretion of AROs		1,025		936		3,022		2,810
(Gains) losses on commodity derivative instruments		(1,443)		28,427		(24,158)		(10,224)
Cash settlements received on commodity derivative instruments		4,096		9,857		12,610		30,785
Gain on sale of properties		--		--		--		(426)
Acquisition related costs		2,310		381		3,422		780
Unit-based compensation expense		1,237		418		2,322		993
Exploration costs		--		2		114		509
Amortization of investment premium		--		25		--		170
Adjusted EBITDA	$	40,547	$	32,949	$	111,688	$	97,737

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	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2013		2012		2013		2012
Reconciliation of Net Cash from Operating Activities to Adjusted EBITDA:
Net cash provided by operating activities	$	52,358	$	29,351	$	111,328	$	87,791
Changes in working capital		(22,510)		569		(22,167)		1,479
Interest expense, net		10,007		4,163		21,506		11,399
Gain (loss) on interest rate swaps		(1,022)		(1,605)		423		(4,631)
Cash settlements paid on interest rate derivative instruments		--		378		928		1,020
Amortization of deferred financing fees		(618)		(276)		(3,895)		(828)
Accretion of senior notes discount		(75)		--		(161)		--
Acquisition related expenses		2,310		381		3,422		780
Income tax expense (benefit) – current portion		97		(14)		285		218
Exploration costs		--		2		19		509
Adjusted EBITDA	$	40,547	$	32,949	$	111,688	$	97,737

Critical Accounting Policies and Estimates

A discussion of our critical accounting policies and estimates is included in our Recast Form 8-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 and nine months ended September 30, 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 WHT Properties acquired from Memorial Resource in March 2013 from February 2, 2011 (inception) through the date of acquisition. The results of operations for the three and nine months ended September 30, 2013 and 2012 have not been recast for the Cinco Group acquisition which closed on October 1, 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 had operated the applicable assets separately during those periods. The following table summarizes certain of the results of operations and period-to-period comparisons for the periods indicated.

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	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2013		2012		2013		2012
Revenues:
Oil & natural gas sales	$	59,194	$	42,395	$	160,838	$	124,525
Pipeline tariff income and other		267		421		873		1,239
Total revenues	$	59,461	$	42,816	$	161,711	$	125,764
Costs and expenses:
Lease operating		14,803		14,114		40,262		39,633
Pipeline operating		394		470		1,343		1,628
Exploration		--		2		114		509
Production and ad valorem taxes		3,025		2,030		8,020		6,887
Depreciation, depletion, and amortization		16,094		13,056		45,409		36,011
Impairment of proved oil and natural gas properties		50,291		--		50,291		--
General and administrative		8,335		3,768		18,752		11,972
Accretion of asset retirement obligations		1,025		936		3,022		2,810
(Gain) loss on commodity derivative instruments		(1,443)		28,427		(24,158)		(10,224)
(Gain) loss on sale of properties		--		--		--		(426)
Other, net		--		141		--		465
Total costs and expenses		92,524		62,944		143,055		89,265
Operating income (loss)		(33,063)		(20,128)		18,656		36,499
Other income (expense):
Interest expense, net		(10,007)		(4,163)		(21,506)		(11,399)
Amortization of investment premium		--		(25)		--		(170)
Total other income (expense)		(10,007)		(4,188)		(21,506)		(11,569)
Income before income taxes		(43,070)		(24,316)		(2,850)		24,930
Income tax benefit (expense)		(97)		171		(285)		(244)
Net income (loss)		(43,167)		(24,145)		(3,135)		24,686
Net income (loss) attributable to previous owners		--		1,095		(1,219)		29,361
Net income (loss) attributable to noncontrolling interest		126		92		220		17
Net income (loss) attributable to partners	$	(43,293)	$	(25,332)	$	(2,136)	$	(4,692)
Oil and natural gas revenue:
Oil sales	$	25,013	$	20,348	$	66,948	$	61,383
NGL sales		12,385		5,870		32,778		18,385
Natural gas sales		21,796		16,177		61,112		44,757
Total oil and natural gas revenue	$	59,194	$	42,395	$	160,838	$	124,525
Production volumes:
Oil (MBbls)		238		207		658		602
NGLs (MBbls)		419		199		1,074		493
Natural gas (MMcf)		6,981		5,849		19,366		17,169
Total (MMcfe)		10,926		8,284		29,762		23,735
Average net production (MMcfe/d)		118.8		90.0		109.0		86.6
Average sales price:
Oil (per Bbl)	$	104.70	$	98.25	$	101.62	$	101.97
NGL (per Bbl)	$	29.60	$	29.54	$	30.53	$	37.33
Natural gas (per Mcf)	$	3.12	$	2.77	$	3.16	$	2.61
Total (Mcfe)	$	5.42	$	5.12	$	5.40	$	5.25
Average unit costs per Mcfe:
Lease operating expense	$	1.35	$	1.70	$	1.35	$	1.67
Production and ad valorem taxes	$	0.28	$	0.25	$	0.27	$	0.29
General and administrative expenses	$	0.76	$	0.45	$	0.63	$	0.50
Depletion, depreciation, and amortization	$	1.47	$	1.58	$	1.53	$	1.52

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Three Months Ended September 30, 2013 Compared to the Three Months Ended September 30, 2012

A net loss of $43.2 million was generated for 2013, primarily due to impairment charges, as discussed below. A net loss of $25.3 million was generated for 2012, primarily due to losses on commodity derivatives.

Revenues. Oil, natural gas and NGL revenues for 2013 totaled $59.2 million, an increase of $16.8 million compared with 2012. Production increased 2,642 MMcfe (approximately 32%) primarily from new drills in East Texas and increased volumes from third party acquisitions. The average realized sales price increased $0.30 per Mcfe due to higher gas and oil prices. The favorable volume and pricing variance contributed to an approximate $13.5 million and $3.3 million increase in revenues, respectively.

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; however, this change in presentation did have a favorable impact period-to-period on NGL volumes and an unfavorable impact period-to-period on natural gas volumes.

Lease Operating. Lease operating expenses were $14.8 million and $14.1 million for 2013 and 2012, respectively. On a per Mcfe basis, lease operating expenses decreased to $1.35 for 2013 from $1.70 for 2012, primarily due to an increase in production volumes between periods.

Production and Ad Valorem Taxes. Production and ad valorem taxes for 2013 totaled $3.0 million, an increase of $1.0 million compared with 2012. On a per Mcfe basis, production and ad valorem taxes increased to $0.28 for 2013 from $0.25 for 2012.

Depreciation, Depletion and Amortization. DD&A expense for 2013 was $16.1 million compared to $13.1 million for 2012, a $3.0 million increase primarily due to both an increase in the depletable cost base and increased production volumes related to third party acquisitions consummated during 2012 and the Partnership’s drilling program. Increased production volumes caused DD&A expense to increase by an approximate $4.2 million and the change in the DD&A rate between periods caused DD&A expense to decrease by an approximate $1.2 million.

Impairment of proved oil and natural gas properties. We recognized $50.3 million of impairments during 2013. The impairments related to certain properties located in East Texas. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable as a result of a downward revision of estimated proved reserves based on updated well performance data. The carrying value of these properties after impairment was approximately $31.5 million. We did not have any impairment charges for 2012.

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 $8.3 million. General and administrative expenses for 2013 included $1.2 million of non-cash unit-based compensation expense and $2.3 million of acquisition-related costs. General and administrative expenses for 2012 totaled $3.8 million. General and administrative expenses for 2012 included $0.4 million of non-cash unit-based compensation expense and $0.4 million of acquisition-related costs.

In 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. The higher general and administrative split between the Partnership and Memorial Resource as well as increased salaries and employee count in 2013 contributed to increased general and administrative expenses.

Gain/Loss on Derivative Instruments. Net gains on commodity derivative instruments of $1.4 million were recognized during 2013, consisting of $4.1 million of cash settlements received, which were offset by a $2.7 million decline in the fair value of open hedge positions. Net losses on commodity derivative instruments of $28.4 million were recognized during 2012, consisting of $9.9 million consisted of cash settlements received, which were offset by a $38.3 million decline in the fair value of open hedge positions.

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

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hedge positions, the hedges are expected to dampen the otherwise positive effect on earnings of higher oil, natural gas and NGL prices and will, in this context, be viewed as having resulted in an opportunity cost.

Net Interest Expense. Net interest expense is comprised of interest on credit facilities, interest on the Senior Notes, amortization of debt issue costs, accretion of net discount associated with the Senior Notes, and gains and losses on interest rate swaps. Net interest expense totaled $10.0 million during 2013, including losses on interest rate swaps of approximately $1.0 million, amortization of deferred financing fees of approximately $0.6 million, and accretion of net discount associated with the Senior Notes of less than $0.1 million. Net interest expense totaled $4.2 million during 2012, including losses on interest rate swaps of approximately $1.6 million and amortization of deferred financing fees of approximately $0.3 million.

Average outstanding borrowings under the Partnership’s revolving credit facility were $76.7 million during 2013 compared to $206.4 million during 2012. Average outstanding borrowings under the previous owners’ revolving credit facilities were $136.0 million during 2012. The previous owners’ had no outstanding borrowings during 2013. During 2013, the Issuers also issued $400.0 million aggregate principal amount of the Senior Notes. See “— Significant Recent Developments” for additional information regarding the issuances of the Senior Notes.

Nine Months Ended September 30, 2013 Compared to the Nine Months Ended September 30, 2012

Net loss of $3.1 million was generated for the nine months ended September 30, 2013, of which $1.2 million of losses were attributable to the previous owners. Net income was $24.7 million for the nine months ended September 30, 2012, of which $29.4 million was attributable to the previous owners.

Revenues. Oil, natural gas and NGL revenues for 2013 totaled $160.8 million, an increase of $36.3 million compared with 2012. Production increased 6,027 MMcfe (approximately 25%) primarily from new drills in East Texas and increased volumes from third party acquisitions. The average realized sales price increased $0.15 per Mcfe. The favorable volume and pricing variance contributed to an approximate $31.7 million and $4.6 million increase in revenues, respectively.

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; however, this change in presentation did have a favorable impact period-to-period on NGL volumes and an unfavorable impact period-to-period on natural gas volumes.

Lease Operating. Lease operating expenses were $40.3 million and $39.6 million for 2013 and 2012, respectively. On a per Mcfe basis, lease operating expenses decreased to $1.35 for 2013 from $1.67 for 2012, primarily due to an increase in production volumes between periods.

Production and Ad Valorem Taxes. Production and ad valorem taxes for 2013 totaled $8.0 million, an increase of $1.1 million compared with 2012. On a per Mcfe basis, production and ad valorem taxes decreased to $0.27 for 2013 from $0.29 for 2012.

Depreciation, Depletion and Amortization. DD&A expense for 2013 was $45.4 million compared to $36.0 million for 2012, a $9.4 million increase primarily due to both an increase in the depletable cost base and increased production volumes related to both third party acquisitions consummated during 2012 and the Partnership’s drilling program. Increased production volumes caused DD&A expense to increase by an approximate $9.1 million and the change in the DD&A rate between periods caused DD&A expense to increase by an approximate $0.3 million.

Impairment of proved oil and natural gas properties. We recognized $50.3 million of impairments during 2013. The impairments related to certain properties located in East Texas. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable as a result of a downward revision of estimated proved reserves based on updated well performance data. The carrying value of these properties after impairment was approximately $31.5 million. We did not have any impairment charges for 2012.

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General and Administrative. General and administrative expenses for 2013 were $18.8 million, which included $2.3 million of non-cash unit-based compensation expense and $3.4 million of acquisition-related costs. General and administrative expenses for 2012 totaled $12.0 million. General and administrative expenses for 2012 included $1.0 million of non-cash unit-based compensation expense and $0.8 million of acquisition-related costs.

Gain/Loss on Derivative Instruments. Net gains on commodity derivative instruments of $24.2 million were recognized during 2013, consisting of $12.6 million consisted of cash settlements received, which were supplemented with an $11.6 million increase in the fair value of open hedge positions. Net gains on commodity derivative instruments of $10.2 million were recognized during 2012, consisting of $30.8 million consisted of cash settlements received, which were offset by a $20.6 million decline in the fair value of open hedge positions.

Net Interest Expense. Net interest expense totaled $21.5 million during 2013, including gains on interest rate swaps of approximately $0.4 million, amortization of deferred financing fees of approximately $3.9 million, and accretion of net discount associated with the Senior Notes of $0.2 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. Additionally, approximately $0.9 million of deferred financing costs were written-off associated with the Partnership’s revolving credit facility in connection with automatic borrowing base reductions upon the issuances of the Senior Notes. Net interest expense totaled $11.4 million during 2012, including losses on interest rate swaps of approximately $4.6 million and amortization of deferred financing fees of approximately $0.8 million.

Average outstanding borrowings under the Partnership’s revolving credit facility were $194.0 million during 2013 compared to $167.7 million during 2012. Average outstanding borrowings under the previous owners’ revolving credit facilities were $28.2 million during 2013 compared to $133.2 million during 2012. As noted above, the Issuers also issued $400.0 million aggregate principal amount of the Senior Notes during 2013.

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…, NGL, … and natural gas, and our ongoing efforts to manage… production volumes, … operating costs and maintenance capital expenditures, as well as general economic, financial, competitive, legislative, regulatory and other factors.

As of September 30, 2013, our liquidity of $388.4 million consisted of $3.4 million of available cash and $385.0 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. Through October 8, 2013, we have issued approximately $511.2 million of securities under this registration statement. Our primary cash requirements are for working capital needs, capital expenditures, debt service and distributions to our partners.

The Partnership used the net proceeds generated from the issuances of the Senior Notes and our October 2013 equity offering (as discussed in “— Significant Recent Developments”) to repay a portion of the indebtedness outstanding under its revolving credit facility. In connection with the issuances of the 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 our working capital needs 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 cash distributions to partners 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.

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As of September 30, 2013, we had a positive working capital balance of $15.4 million.

As previously discussed under “— Significant Recent Developments,” we acquired certain oil and gas properties from both Memorial Resource and affiliates of NGP for an aggregate purchase price of approximately $603.0 million on October 1, 2013 through borrowings under our revolving credit facility. On September 26, 2013, we entered into a sixth amendment to our credit agreement, which among other things: (i) increased the maximum aggregate credit amounts under the revolving facility from $1.0 billion to $2.0 billion and (ii) increased the borrowing base from $480.0 million to $920.0 million upon the closing of the Cinco Group acquisition on October 1, 2013. On October 10, 2013, the borrowing base was automatically reduced by $75.0 million in conjunction with the issuance of an additional $300.0 million aggregate principal amount of the Senior Notes. As of November 1, 2013, we had $93.0 million of indebtedness outstanding under our revolving credit facility and $752.0 million of available credit under our revolving credit facility.

Capital Expenditures

For the nine months ended September 30, 2013, our total capital expenditures, excluding acquisitions, were $92.3 million (including the change in capital accruals). Our capital spending program related to drilling, recompletions and capital workovers was approximately 89% of total capital expenditures. The remaining expenditures were primarily related to California facility upgrades, including upgrading permanent drilling equipment systems on the Ellen platform and installation of a power supply cable. We spent approximately 81% in East Texas / North Louisiana, 16% in California and 3% in South Texas.

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 September 30, 2013, the borrowing base under our revolving credit facility was $480.0 million and we had $95.0 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. As of September 30, 2013, we were in compliance with all of the financial and other covenants under our revolving credit facility.

On September 26, 2013, we entered into a sixth amendment to our credit agreement, which among other things: (i) increased the maximum aggregate credit amounts under the revolving facility from $1.0 billion to $2.0 billion and (ii) increased the borrowing base from $480.0 million to $920.0 million upon the closing of the Cinco Group acquisition on October 1, 2013. On October 10, 2013, the borrowing base was automatically reduced by $75.0 million in conjunction with the issuance of additional senior notes, as previously discussed.

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 Recent Developments” for additional information regarding the issuances of the Senior Notes.

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. It has been our practice to enter into costless collars and fixed price swaps only with lenders under our credit agreement. Historically, the Partnership has not paid or received premiums for put options.

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For additional information regarding the volumes of our production covered by commodity derivative contracts and the average prices at which production is hedged as of September 30, 2013, see “Item 3. Quantitative and Qualitative Disclosures About Market Risk — Counterparty and Customer Credit Risk.”

Consistent with our hedging policy, we entered into incremental commodity derivative contracts that, together with the commodity derivative contracts that were novated to the Partnership upon the closing of the Cinco Group acquisition previously discussed under “— Significant Recent Developments,” cover up to 85% of projected production volumes related to this acquisition through 2018.

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. Conditions sometimes arise where actual borrowings are less than notional amounts hedged which has and could result in over-hedged amounts from an economic perspective. From time to time we enter into offsetting positions to avoid being economically over-hedged.

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

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 nine months ended September 30, 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 the date of acquisition, and the WHT Properties acquired from Memorial Resource in March 2013 from February 2, 2011 (inception) through the date of acquisition. 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 Nine Months             Ended September 30,
	2013		2012
Net cash provided by operating activities	$	111,328	$	87,791
Net cash used in investing activities		135,387		175,342
Net cash provided by financing activities		19,425		84,870

Nine Months Ended September 30, 2013 Compared to the Nine Months Ended September 30, 2012

Operating Activities. Key drivers of net operating cash flows are commodity prices, production volumes and operating costs. Net income decreased by $27.8 million as further discussed above under “— Results of Operations,” and net cash provided by operating activities increased by $23.5 million.

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Investing Activities. Net cash used in investing activities during 2013 was $135.4 million, of which $29.4 million was used to acquire oil and natural gas properties from a third parties and $76.3 million was used for additions to oil and gas properties. Cash used in investing activities during 2012 was $175.3 million, of which $129.6 million was used to acquire oil and natural gas properties from a third party and $41.7 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 $4.3 million compared to $3.7 million during 2012. The decrease in additions to other property and equipment was approximately $0.7 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 $7.6 million of costs incurred in conjunction with the issuance of common units. The net proceeds were used to repay borrowings outstanding under the Partnership’s revolving credit facility.

Distributions to partners during 2013 were $62.9 million compared to $23.4 million during 2012. The increase is due to both an increase in the outstanding units between periods and an increase in the declared cash distribution rate per unit. Distributions made by the previous owners during 2012 were $8.9 million.

We paid $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. This common control acquisition was funded with borrowings from the Partnership’s revolving credit facility. We paid $45.5 million to Memorial Resource in connection with our acquisitions of oil and gas properties from them in April and May 2012. During 2012, we borrowed $84.0 million to fund the acquisitions of oil and gas properties from Memorial Resource and for other general partnership purposes.

Proceeds of $397.6 million from the issuances of our Senior Notes during 2013 were used to repay borrowings outstanding under the Partnership’s revolving credit facility.

During 2012, the previous owners had advances of $8.0 million under their revolving credit facilities and repaid $17.9 million of borrowings outstanding under their revolving credit facilities. Deferred financing costs of approximately $11.2 million were incurred during 2013 compared to approximately $0.4 million during 2012.

Contractual Obligations

During the nine months ended September 30, 2013, there were no significant changes in our consolidated and combined contractual obligations from those reported in our Recast Form 8-K except for:

• revolving credit facility borrowings and advances;

• amending the credit facility agreement to extend the maturity date from December 2016 to March 2018; and

• the issuance of $400.0 million aggregate principal amount of the Senior Notes.

Off–Balance Sheet Arrangements

As of September 30, 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.

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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 Recast Form 8-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. It has been our practice to enter into costless collars and fixed price swaps only with lenders under our credit agreement. Historically, the Partnership has not paid or received premiums for put options.

For additional information regarding the volumes of our production covered by commodity derivative contracts and the average prices at which production is hedged as of September 30, 2013, see Note 5 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under Item 1 of this quarterly report.

Interest Rate Risk

Our risk management policy provides for the use of interest rate swaps to reduce the exposure to market rate fluctuations by converting variable interest rates to fixed interest rates. Conditions sometimes arise where actual borrowings are less than notional amounts hedged which has and could result in over-hedged amounts from an economic perspective. From time to time we enter into offsetting positions to avoid being economically over-hedged. See Note 5 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under Item 1 of this quarterly report for interest rate swap arrangements that were outstanding at September 30, 2013 and interest rate swap arrangements entered into during October 2013.

At September 30, 2013, we had $95.0 million of Eurodollar borrowings outstanding under our revolving credit facility, with an interest rate of LIBOR plus 1.50%, or 1.69%. Assuming no change in the amount of debt outstanding, the impact on interest expense of a 10% increase or decrease in the in the variable component of the stated interest rates, after giving effect to our interest rate swaps that were in place at September 30, 2013, would be less than $0.1 million per year.

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

	September 30, 2013
	Carrying	Estimated
Description	Amount	Fair Value
7.625% senior notes, fixed-rate, due May 1, 2021	$  397,724		$  386,000

Counterparty and Customer Credit Risk

We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. In addition, our derivative contracts may expose us to credit risk in the event of nonperformance by counterparties. 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

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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 $25.5 million against amounts outstanding under our revolving credit facility at September 30, 2013, reducing our maximum credit exposure to approximately $18.8 million, of which approximately $11.6 million was with a single counterparty.

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 September 30, 2013.

Change in Internal Controls Over Financial Reporting

No changes in our internal control over financial reporting occurred during the quarter ended September 30, 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.

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PART II—OTHER INFORMATION

ITEM 1.   LEGAL PROCEEDINGS.

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

In addition to the risk factor described below, security holders and potential investors in our securities should carefully consider the risk factors disclosed in our Annual Report on Form 10-K for the year ended December 31, 2012 filed with the SEC on March 5, 2013 and the, updated risk factors related to the issuances of the Senior Notes that were disclosed in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2013 filed with the SEC on May 10, 2013.

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations.

Our oil and natural gas development and production operations are subject to complex and stringent laws and regulations administered by governmental authorities vested with broad authority relating to the exploration for, and the development, production and transportation of, oil and natural gas, as well as environmental and safety matters. To conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. Failure to comply with laws and regulations applicable to our operations, including any evolving interpretation and enforcement by governmental authorities, could have a material adverse effect on our business, financial condition, and results of operations.

Our oil and natural gas development and production operations are also subject to stringent and complex federal, state and local laws and regulations governing the discharge of materials into the environment, health and safety aspects of our operations, or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations applicable to our operations including the acquisition of a permit before conducting regulated drilling activities; the restriction of types, quantities and concentration of materials that can be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from our operations. Numerous governmental authorities, such as the U.S. Environmental Protection Agency, or EPA, and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly compliance or corrective actions. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, the imposition of investigatory or remedial obligations, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and, in some instances, the issuance of orders limiting or prohibiting some or all of our operations. In addition, we may experience delays in obtaining or be unable to obtain required permits, which may delay or interrupt our operations and limit our growth and revenue.

Under certain environmental laws that impose strict as well as joint and several liability, we may be required to remediate contaminated properties currently or formerly owned or operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. Moreover, public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stringent environmental legislation and regulations applied to the crude oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business, prospects, financial condition or results of operations could be materially adversely affected.

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Our oil and gas operations associated with our Beta properties are conducted on offshore leases in federal waters. Federal offshore leases are administered by Bureau of Ocean Energy Management, or BOEM. Holders of federal offshore leases are required to comply with detailed BOEM regulations, Bureau of Safety and Environmental Enforcement, or BSEE, regulations and the Outer Continental Shelf Lands Act (OCSLA), which are subject to interpretation and change. Lessees must obtain BOEM approval for exploration, development and production plans prior to the commencement of offshore operations. In addition, approvals and permits are required from other agencies such as the U.S. Coast Guard and the EPA. BSEE has regulations requiring offshore production facilities and pipelines located on the outer continental shelf to meet stringent engineering and construction specifications, and has proposed and/or promulgated additional safety related regulations concerning the design and operating procedures of these facilities and pipelines, including regulations to safeguard against or respond to well blowouts and other catastrophes. BSEE regulations also restrict the flaring or venting of natural gas and prohibit the flaring of liquid hydrocarbons and oil without prior authorization.

BSEE has regulations governing the plugging and abandonment of wells located offshore and the installation and removal of all fixed drilling and production facilities. BSEE generally requires that lessees have substantial net worth, post supplemental bonds or provide other acceptable assurances that the obligations will be met. If we fail to pay royalties or comply with safety and environmental regulations, BOEM and BSEE may require that our operations on the Beta properties be suspended or terminated. The requirements imposed by BOEM and BSEE regulations are frequently changed and subject to new interpretations.

If we conduct operations on federal, state or Indian oil and natural gas leases, these operations must comply with numerous regulatory restrictions, including various non–discrimination statutes, royalty and related valuation requirements, and certain of these operations must be conducted pursuant to certain on-site security regulations and other appropriate permits issued by the Bureau of Land Management, or the BLM, BOEM, BSEE, Bureau of Indian Affairs, tribal or other appropriate federal, state and/or Indian tribal agencies.

The Mineral Leasing Act of 1920, as amended, or the Mineral Act, prohibits ownership of any direct or indirect interest in federal onshore oil and natural gas leases by a foreign citizen or a foreign entity except through equity ownership in a corporation formed under the laws of the United States or of any U.S. State or territory, and only if the laws, customs, or regulations of their country of origin or domicile do not deny similar or like privileges to citizens or entities of the United States. If these restrictions are violated, the oil and natural gas lease can be canceled in a proceeding instituted by the United States Attorney General. We qualify as an entity formed under the laws of the United States or of any U.S. State or territory. Although the regulations promulgated and administered by the BLM pursuant to the Mineral Act provide for agency designations of non-reciprocal countries, there are presently no such designations in effect. It is possible that our unitholders may be citizens of foreign countries who do not own their units in a U.S. corporation, or that even if such units are held through a U.S. corporation, their country of citizenship may be determined to be non-reciprocal countries under the Mineral Act. In such event, any federal onshore oil and natural gas leases held by us could be subject to cancellation based on such determination.

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

Our general partner’s 0.1% interest in us was represented by 44,601 general partner units at September 30, 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 nine months ended September 30, 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 and to other Memorial Resource employees who provide services to the Partnership. In conjunction with the issuance of these restricted common units, we issued 506 general partner units 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 of 1933, as amended (“Securities Act”).

In connection with our 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.

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The following table summarizes our repurchase activity during the quarterly period ended September 30, 2013:

Period	Total Number of Units Purchased	Average Price Paid per Unit	Total Number of Units Purchased as Part of Publicly Announced Plans	Maximum Number of Units That May Yet Be Purchased Under the Plans
July 1, 2013 – July 30, 2013	--	$                        --	--	--
August 1, 2013 – August 31, 2013 (1)	742	$                  20.24	--	--
September 1, 2013 – September 30, 2013	--	$                        --	--	--
Total	742	$                  20.24	--	--
(1)    Represents common units surrendered to satisfy tax liabilities incident to the vesting of restricted common units issued under the LTIP.

ITEM 3.   DEFAULTS UPON SENIOR SECURITIES.

None.

ITEM 4.   MINE SAFETY DISCLOSURES.

Not applicable.

ITEM 5.   OTHER INFORMATION.

None.

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ITEM 6.   EXHIBITS.

Exhibit     Number		Description
2.1##	—	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).
2.2##	—	Purchase and Sale Agreement, dated as of July 15, 2013, between Boaz Energy Partners, 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 July 16, 2013).
2.3##	—	Purchase and Sale Agreement, dated as of July 15, 2013, between Crown Energy Partners Holdings, LLC and Memorial Production Operating LLC (incorporated by reference to Exhibit 2.2 to Current Report on Form 8-K (File No. 001-35364) filed on July 16, 2013).
2.4##	—	Purchase and Sale Agreement, dated as of July 15, 2013, between Propel Energy, LLC and Memorial Production Operating LLC (incorporated by reference to Exhibit 2.3 to Current Report on Form 8-K (File No. 001-35364) filed on July 16, 2013).
2.5##	—	Purchase and Sale Agreement, dated as of July 15, 2013, between Stanolind Oil and Gas LP and Memorial Production Operating LLC (incorporated by reference to Exhibit 2.4 to Current Report on Form 8-K (File No. 001-35364) filed on July 16, 2013).
2.6##	—	Purchase and Sale Agreement, dated as of July 15, 2013, between Memorial Resource Development LLC and Memorial Production Operating LLC (incorporated by reference to Exhibit 2.5 to Current Report on Form 8-K (File No. 001-35364) filed on July 16, 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*	—	First Supplemental Indenture, dated as of October 7, 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.
4.4	—	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).

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4.5	—	Registration Rights Agreement, dated May 23, 2013, by and among Memorial Production Partners LP, Memorial Production Finance Corporation, the subsidiary guarantors named therein, and Wells Fargo Securities, LLC, as initial purchaser (incorporated by reference to Exhibit 4.2 to Current Report on Form 8-K (File No. 001-35364) filed on May 23, 2013).
4.6	—	Registration Rights Agreement, dated October 10, 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 October 10, 2013).
10.1	—	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).
10.2	—	Purchase Agreement, dated May 20, 2013, by and among Memorial Production Partners LP, Memorial Production Finance Corporation, the subsidiary guarantors named therein, and Wells Fargo Securities, LLC, as the initial purchaser (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (File No. 001-35364) filed on May 23, 2013).
10.3	—	Purchase Agreement, dated October 7, 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 October 10, 2013).
10.4	—	Sixth Amendment to Credit Agreement, dated as of September 26, 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 October 1, 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.

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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:         November 7, 2013	By:	/s/ Andrew J. Cozby
	Name:	Andrew J. Cozby
	Title:	Vice President and Chief Financial Officer of Memorial Production Partners GP LLC

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