Amplify Energy Corp - FORM 10-Q

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10–Q

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

For the quarterly period ended June 30, 2014

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

For the transition period from to .

Commission File Number: 001-35364

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 July 31, 2014, the registrant had 66,384,211 common units, 5,360,912 subordinated units and 71,820 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 June 30, 2014 and December 31, 2013	9
	Unaudited Condensed Statements of Consolidated and Combined Operations for the Three and Six Months Ended June 30, 2014 and 2013	10
	Unaudited Condensed Statements of Consolidated and Combined Cash Flows for the Six Months Ended June 30, 2014 and 2013	11
	Unaudited Condensed Statements of Consolidated and Combined Equity for the Six Months Ended June 30, 2014	12
	Notes to Unaudited Condensed Consolidated and Combined Financial Statements
	Note 1 – Organization and Basis of Presentation	13
	Note 2 – Summary of Significant Accounting Policies	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	21
	Note 9 – Equity & Distributions	23
	Note 10 – Earnings per Unit	25
	Note 11 – Equity-based Awards	26
	Note 12 – Related Party Transactions	26
	Note 13 – Commitments and Contingencies	28
	Note 14 – Subsequent Events	28
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	30
Item 3.	Quantitative and Qualitative Disclosures About Market Risk.	41
Item 4.	Controls and Procedures.	42

PART II—OTHER INFORMATION
Item 1.	Legal Proceedings.	43
Item 1A.	Risk Factors.	43
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds.	43
Item 3.	Defaults Upon Senior Securities.	44
Item 4.	Mine Safety Disclosures.	44
Item 5.	Other Information.	44
Item 6.	Exhibits.	44

Signatures		46

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.

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

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

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

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

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

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

ICE: Inter-Continental Exchange.

MBbl: One thousand Bbls.

MBbls/d: One thousand Bbls per day.

MBoe: One thousand Boe.

MBoe/d: One thousand Boe per day.

MBtu: One thousand Btu.

MBtu/d: One thousand Btu per day.

Mcf: One thousand cubic feet of natural gas.

Mcf/d: One Mcf per day.

MMBtu: One million British thermal units.

MMcf: One million cubic feet of natural gas.

MMcfe: One million cubic feet of natural gas equivalent.

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

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

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

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

NYMEX: New York Mercantile Exchange.

Oil: Oil and condensate.

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

OPIS: Oil Price Information Service.

Play: A geographic area with hydrocarbon potential.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

WTI: West Texas Intermediate.

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;

•

“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;

•

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

•

“MRD LLC” refers to Memorial Resource Development LLC, which is the predecessor of Memorial Resource;

•

“Cinco Group” refers to (i) certain oil and natural gas properties and related assets primarily in the Permian Basin, East Texas and the Rockies owned by: (a) Boaz Energy, LLC (“Boaz”), (b) Crown Energy Partners, LLC (“Crown”), (c) the Crown net profits overriding royalty interest and overriding royalty interest (“Crown NPI/ORRI”), (d) Propel Energy SPV LLC (“Propel SPV”), together with its wholly-owned subsidiary Propel Energy Services, LLC (“Propel Energy Services”), (e) Stanolind Oil and Gas SPV LLC (“Stanolind SPV”), (f) Tanos Energy, LLC (“Tanos”), together with its wholly-owned subsidiaries, and (g) Prospect Energy, LLC (“Prospect”) and (ii) certain oil and natural gas properties in Jackson County, Texas (the “MRD Assets”) owned by MRD LLC. The Partnership acquired substantially all of the Cinco Group on October 1, 2013 from: (x) Boaz Energy Partners, LLC (“Boaz Energy Partners”), Crown Energy Partners Holdings, LLC (“Crown Holdings”), Propel Energy, LLC (“Propel Energy”) and Stanolind Oil and Gas LP (“Stanolind”), all of which are primarily owned by two of the Funds (defined below) and (y) MRD LLC;

•

“the previous owners” for accounting and financial reporting purposes refers collectively to (a) 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 and (b) the Cinco Group;

•

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

•

“MRD Holdco” refers to MRD Holdco LLC, which together with a group controls Memorial Resource; and

•

“NGP” refers to Natural Gas Partners. The Funds, which are three of the private equity funds managed by NGP, collectively control MRD Holdco.

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 or materials;

•

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,” “outlook,” “continue,” the negative of such terms or other comparable terminology. These statements discuss future expectations, contain projections of results of operations or of financial condition or include other “forward-looking” information. These forward-looking statements involve risks and uncertainties. Important factors that could cause our actual results or financial condition to differ materially from our expectations include, but are not limited to, the following risks and uncertainties:

•

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

•

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

•

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

•

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

•

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

•

potential shortages of, or increased costs for, drilling and production equipment and supply materials for production, such as CO₂;

•

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, 2013 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.

PART I—FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS.

MEMORIAL PRODUCTION PARTNERS LP

UNAUDITED CONDENSED CONSOLIDATED AND COMBINED BALANCE SHEETS

(In thousands, except outstanding units)


	June 30,		December 31,
	2014		2013
ASSETS
Current assets:
Cash and cash equivalents	$	349	$	13,139
Accounts receivable:
Oil and natural gas sales		50,264		31,132
Joint interest owners and other		11,943		4,634
Affiliates		--		4,473
Short-term derivative instruments		1,436		7,600
Prepaid expenses and other current assets		9,403		9,146

Total current assets		73,395		70,124
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method		2,107,459		1,764,468
Other		2,917		2,900
Accumulated depreciation, depletion and impairment		(487,409)		(418,688)

Oil and natural gas properties, net		1,622,967		1,348,680
Long-term derivative instruments		1,149		42,657
Restricted investments		75,506		73,385
Other long–term assets		86,332		17,461

Total assets	$	1,859,349	$	1,552,307


LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	18,207	$	8,566
Accounts payable – affiliates		2,409		474
Revenues payable		23,487		16,291
Accrued liabilities		54,455		39,847
Short-term derivative instruments		45,188		7,996

Total current liabilities		143,746		73,174
Long-term debt (Note 8)		1,148,806		792,067
Asset retirement obligations		103,513		99,619
Long-term derivative instruments		90,696		5,875
Other long-term liabilities		3,804		1,956

Total liabilities		1,490,565		972,691
Commitments and contingencies (Note 13)
Equity:
Partners’ equity (deficit):
Common units (56,497,187 units outstanding at June 30, 2014 and 55,877,831 units outstanding at December 31, 2013)		389,906		582,075
Subordinated units (5,360,912 units outstanding at June 30, 2014 and December 31, 2013)		(27,222)		(8,715)
General partner (61,920 units outstanding at June 30, 2014 and 61,300 units outstanding at December 31, 2013)		529		728

Total partners’ equity		363,213		574,088
Noncontrolling interests		5,571		5,528

Total equity		368,784		579,616

Total liabilities and equity	$	1,859,349	$	1,552,307

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

MEMORIAL PRODUCTION PARTNERS LP

UNAUDITED CONDENSED STATEMENTS OF

CONSOLIDATED AND COMBINED OPERATIONS

(In thousands, except per unit amounts)


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

	2014		2013*		2014		2013*

Revenues:
Oil & natural gas sales	$	122,247	$	89,673	$	222,546	$	157,261
Pipeline tariff income and other		1,063		501		1,741		1,015

Total revenues		123,310		90,174		224,287		158,276


Costs and expenses:
Lease operating		26,067		20,217		54,055		41,588
Pipeline operating		676		479		1,165		949
Exploration		204		48		210		275
Production and ad valorem taxes		7,076		4,967		12,660		8,847
Depreciation, depletion, and amortization		35,157		24,672		61,902		45,063
General and administrative		10,588		14,170		20,546		21,483
Accretion of asset retirement obligations		1,366		1,148		2,723		2,293
(Gain) loss on commodity derivative instruments		138,346		(36,079)		185,112		(23,010)
(Gain) loss on sale of properties		--		(885)		--		(2,868)
Other, net		--		623		(12)		597

Total costs and expenses		219,480		29,360		338,361		95,217

Operating income (loss)		(96,170)		60,814		(114,074)		63,059
Other income (expense):
Interest expense, net		(18,036)		(7,931)		(34,114)		(14,473)

Total other income (expense)		(18,036)		(7,931)		(34,114)		(14,473)

Income (loss) before income taxes		(114,206)		52,883		(148,188)		48,586
Income tax benefit (expense)		--		(188)		(75)		(188)

Net income (loss)		(114,206)		52,695		(148,263)		48,398
Net income (loss) attributable to noncontrolling interest		(12)		98		43		94

Net income (loss) attributable to Memorial Production Partners LP	$	(114,194)	$	52,597	$	(148,306)	$	48,304


Limited partners’ interest in net income (loss):
Net income (loss) attributable to Memorial Production Partners LP	$	(114,194)	$	52,597	$	(148,306)	$	48,304
Net (income) loss allocated to previous owners		--		(6,418)		--		(7,147)
Net (income) loss allocated to general partner		94		(46)		108		(41)
Net (income) loss allocated to NGP IDRs		(20)		--		(40)		--

Limited partners’ interest in net income (loss)	$	(114,120)	$	46,133	$	(148,238)	$	41,116


Earnings per unit: (Note 10)
Basic and diluted earnings per unit	$	(1.86)	$	1.04	$	(2.42)	$	1.04

Weighted average limited partner units outstanding:
Basic and diluted		61,464		44,231		61,358		39,668

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.

MEMORIAL PRODUCTION PARTNERS LP

UNAUDITED CONDENSED STATEMENTS OF

CONSOLIDATED AND COMBINED CASH FLOWS

(In thousands)


	For the Six Months Ended June 30,
	2014		2013*

Cash flows from operating activities:
Net income (loss)	$	(148,263)	$	48,398
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization		61,902		45,063
(Gain) loss on derivative instruments		186,203		(24,680)
Cash settlements (paid) received on derivative instruments		(16,518)		9,357
Amortization of deferred financing costs		1,701		3,823
Accretion of senior notes net discount		739		86
Accretion of asset retirement obligations		2,723		2,293
Amortization of equity awards		2,960		1,085
Gain on sale of properties		--		(2,868)
Non-cash compensation expense		--		1,125
Changes in operating assets and liabilities:
Accounts receivable		(17,278)		(8,563)
Prepaid expenses and other assets		(117)		(369)
Payables and accrued liabilities		20,050		7,040
Other		1,950		75

Net cash provided by operating activities		96,052		81,865
Cash flows from investing activities:
Acquisitions of oil and natural gas properties		(173,000)		(6,310)
Additions to oil and gas properties		(117,616)		(88,629)
Additions to restricted investments		(2,121)		(3,080)
Additions to other property and equipment		--		(130)
Deposits for property acquisitions		(70,125)		--
Proceeds from the sale of oil and natural gas properties		--		4,525

Net cash used in investing activities		(362,862)		(93,624)
Cash flows from financing activities:
Advances on revolving credit facilities		418,000		251,250
Payments on revolving credit facilities		(62,000)		(691,702)
Proceeds from borrowings of long-term debt		--		397,563
Deferred financing costs		(590)		(11,224)
Capital contributions from previous owners		--		7,126
Contributions related to sale of assets to NGP affiliate		--		2,013
Proceeds from general partner contribution		14		189
Proceeds from the issuance of common units		--		179,371
Costs incurred in conjunction with issuance of common units		--		(7,592)
Distributions to partners		(67,524)		(40,030)
Distribution to Memorial Resource (see Note 12)		(33,880)		(55,419)
Distributions made by previous owners		--		(23,157)

Net cash provided by financing activities		254,020		8,388
Net change in cash and cash equivalents		(12,790)		(3,371)
Cash and cash equivalents, beginning of period		13,139		24,440

Cash and cash equivalents, end of period	$	349	$	21,069


Supplemental cash flows:
Cash paid for interest	$	31,298	$	8,078
Noncash investing and financing activities:
Change in capital expenditures in payables and accrued liabilities		12,434		16,768
Accounts receivable related to Eagle Ford Acquisition		3,879		--
Accounts receivable related to Double A Acquisition		586		--

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.

MEMORIAL PRODUCTION PARTNERS LP

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED AND COMBINED EQUITY

(In thousands)


	Partner’s Equity (Deficit)
	Limited Partners				General		NGP		Noncontrolling
	Common		Subordinated		Partner		IDRs		Interest		Total

Balance, December 31, 2013	$	582,075	$	(8,715)	$	728	$	--	$	5,528	$	579,616
Net income (loss)		(135,376)		(12,862)		(108)		40		43		(148,263)
Amortization of equity awards		2,960		--		--		--		--		2,960
Contributions		--		--		14		--		--		14
Distributions		(61,479)		(5,897)		(108)		(40)		--		(67,524)
Contributions attributable to net assets acquired (See Note 12)		2,656		255		3		--		--		2,914
Other		(930)		(3)		--		--		--		(933)

Balance, June 30, 2014	$	389,906	$	(27,222)	$	529	$	--	$	5,571	$	368,784

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

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 (“MRD LLC”) to own, acquire and exploit oil and natural gas properties in North America. In January 2014, MRD LLC formed Memorial Resource Development Corp (“MRD”). On June 18, 2014, MRD LLC contributed substantially all of its assets, including its interest in our general partner, to MRD in connection with MRD’s initial public offering. Unless the context requires otherwise, references to “Memorial Resource” refer collectively to MRD 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 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. 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 was formed by MRD LLC in January 2014 to exploit, develop and acquire natural gas, NGL and oil properties in North America. MRD LLC was a Delaware limited liability company formed in April 2011 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. In June 2014, (i) the Funds contributed all of their interests in MRD LLC to MRD Holdco LLC (“MRD Holdco”), after which MRD Holdco owned 100% of MRD LLC, and (ii) MRD LLC distributed certain assets, including all of our subordinated units, to MRD Holdco. On June 27, 2014, MRD LLC merged into MRD Operating LLC, a subsidiary of MRD. 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 indirectly own 50% of our incentive distribution rights (“IDRs”). The remaining IDRs are 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 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, and (ii) certain oil and natural gas properties and related assets primarily in the Permian Basin, East Texas and the Rockies that the Partnership acquired through equity and asset transactions on October 1, 2013, which we refer to collectively as the “Cinco Group acquisition,” from MRD LLC and certain affiliates of NGP.

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.

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 six months ended June 30, 2014 are not necessarily indicative of results expected for the full year. In our opinion, the accompanying unaudited condensed consolidated and combined financial statements include all adjustments of a normal recurring nature necessary for fair presentation. Although we believe the disclosures in these financial statements are adequate and make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted pursuant to the rules and regulations of the United States Securities and Exchange Commission (“SEC”). These unaudited condensed consolidated and combined financial statements and the notes thereto should be read in conjunction with the audited consolidated financial statements and notes thereto included in our annual report on Form 10-K for the year ended December 31, 2013 (the “2013 Form 10-K”).

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

Use of Estimates

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

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

Note 2. Summary of Significant Accounting Policies

A discussion of our critical accounting policies and estimates is included in our 2013 Form 10-K.

Current Liabilities – Accrued liabilities

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


	June 30,		December 31,
	2014		2013

Accrued capital expenditures	$	28,627	$	16,193
Accrued lease operating expense		9,509		10,666
Accrued general and administrative expenses		688		1,547
Accrued ad valorem taxes		4,778		1,531
Accrued interest payable		8,923		8,931
Environmental liability		698		437
Other		1,232		542

	$	54,455	$	39,847

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

New Accounting Pronouncements

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

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

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

Note 3. Acquisitions and Divestitures

Related Party Acquisitions. 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 Acquisition. In March 2014, we closed a transaction to acquire certain oil and natural gas producing properties from a third party in the Eagle Ford for approximately $169.1 million, including estimated customary post-closing adjustments (the “Eagle Ford Acquisition”). In addition, we acquired a 30% interest in the seller’s Eagle Ford leasehold. During the three and six months ended June 30, 2014, revenues of approximately $13.4 million and $14.4 million, respectively, were recorded in the statement of operations related to the Eagle Ford Acquisition subsequent to the closing date and we generated earnings of approximately $7.4 million and $8.0 million for the three and six months ended June 30, 2014, respectively. The following table summarizes the preliminary fair value assessment of the assets acquired and liabilities assumed as of the acquisition date (in thousands):


	Eagle Ford Acquisition

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

Total identifiable net assets	$	169,121

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 June 30,				For the Six Months Ended June 30,
2014		2013		2014		2013


$	1,093	$	897	$	2,987	$	1,112

The following unaudited pro forma combined results of operations are provided for the three and six months ended June 30, 2014 and 2013 as though the Eagle Ford Acquisition had been completed on January 1, 2013. The unaudited pro forma financial information was derived from the historical combined statements of operations of the Partnership and the previous owners and adjusted to include: (i) the revenues and direct operating expenses associated with oil and gas properties acquired, (ii) depletion

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

expense applied to the adjusted basis of the properties acquired and (iii) interest expense on additional borrowings necessary to finance the acquisition. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of expected future results of operations.


	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2014		2013		2014		2013
	(In thousands, except per unit amounts)

Revenues	$	123,310	$	104,050	$	233,553	$	184,911
Net income (loss)		(114,206)		59,775		(144,054)		61,887
Basic and diluted earnings per unit		(1.86)		1.20		(2.35)		1.38

Previous Owners’ Divestitures

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

During the six months ended June 30, 2013, Tanos also sold certain non-operated oil and gas properties for $2.9 million and recorded a gain of $1.4 million.

Previous Owners’ Acquisitions

2013 Acquisitions

During the six months ended June 30, 2013, Propel Energy acquired incremental interests in certain oil and gas properties and leases in the Hendrick Field located in Winkler County, Texas from two third parties in two separate transactions for an aggregate purchase price of approximately $6.3 million.

Note 4. Fair Value Measurements of Financial Instruments

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

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

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The fair market values of the derivative financial instruments reflected on the balance sheets as of June 30, 2014 and December 31, 2013 were based on estimated forward commodity prices and forward interest rate yield curves. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement in its entirety. The significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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


	Fair Value Measurements at June 30, 2014 Using
	Quoted Prices in Active Market (Level 1)			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Fair Value

		(In thousands)
Assets:
Commodity derivatives		$	--	$	47,256	$	--	$	47,256
Interest rate derivatives			--		11		--		11

Total assets			--	$	47,267		--	$	47,267


Liabilities:
Commodity derivatives		$	--	$	176,143	$	--	$	176,143
Interest rate derivatives			--		4,423		--		4,423

Total liabilities		$	--	$	180,566	$	--	$	180,566


	Fair Value Measurements at December 31, 2013 Using
	Quoted Prices in Active Market (Level 1)			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Fair Value

		(In thousands)
Assets:
Commodity derivatives		$	--	$	95,926	$	--	$	95,926
Interest rate derivatives			--		872		--		872

Total assets		$	--	$	96,798	$	--	$	96,798


Liabilities:
Commodity derivatives		$	--	$	55,576	$	--	$	55,576
Interest rate derivatives			--		4,836		--		4,836

Total liabilities		$	--	$	60,412	$	--	$	60,412

See Note 5 for additional information regarding our derivative instruments.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

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

•

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

•

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

•

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

We did not have any impairment charges for the three and six months ended June 30, 2014 and 2013, respectively.

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Note 5. Risk Management and Derivative Instruments

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

Certain inherent business risks are associated with commodity and interest derivative contracts, including market risk and credit risk. Market risk is the risk that the price of natural gas or oil will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the counterparty to a contract. It is our policy to enter into derivative contracts, including interest rate swaps, only with creditworthy counterparties, which generally are financial institutions, deemed by management as competent and competitive market makers. Some of the lenders, or certain of their affiliates, under our credit agreement are counterparties to our derivative contracts. While collateral is generally not required to be posted by counterparties, credit risk associated with derivative instruments is minimized by limiting exposure to any single counterparty and entering into derivative instruments only with creditworthy counterparties that are generally large financial institutions. Additionally, master netting agreements are used to mitigate risk of loss due to default with counterparties on derivative instruments. We have also entered into the International Swaps and Derivatives Association Master Agreements (“ISDA Agreements”) with each of our counterparties. The terms of the ISDA Agreements provide us and each of our counterparties with rights of set-off upon the occurrence of defined acts of default by either us or our counterparty to a derivative, whereby the party not in default may set-off all liabilities owed to the defaulting party against all net derivative asset receivables from the defaulting party. At June 30, 2014, after taking into effect netting arrangements, we do not have any counterparty exposure related to our derivative instruments. As a result, had certain counterparties failed completely to perform according to the terms of their existing contracts, we would have the right to offset $1.7 million against amounts outstanding under our revolving credit facility at June 30, 2014. See Note 8 for additional information regarding our revolving credit facility.

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 Inter-Continental Exchange (“ICE”) Brent and California Midway-Sunset. Our NGL derivative contracts are indexed to OPIS Mont Belvieu. At June 30, 2014, we had the following open commodity positions:


	Remaining 2014		2015		2016		2017		2018		2019
Natural Gas Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (MMBtu)		2,626,033		2,605,278		2,692,442		2,450,067		2,160,000		1,914,583
Weighted-average fixed price	$	4.33	$	4.28	$	4.40	$	4.31	$	4.51	$	4.75

Collar contracts:
Average Monthly Volume (MMBtu)		340,000		350,000		--		--		--		--
Weighted-average floor price	$	5.00	$	4.62	$	--	$	--	$	--	$	--
Weighted-average ceiling price	$	6.31	$	5.80	$	--	$	--	$	--	$	--

Call spreads (1):
Average Monthly Volume (MMBtu)		120,000		80,000		--		--		--		--
Weighted-average sold strike price	$	5.17	$	5.25	$	--	$	--	$	--	$	--
Weighted-average bought strike price	$	6.53	$	6.75	$	--	$	--	$	--	$	--

Basis swaps:
Average Monthly Volume (MMBtu)		2,875,833		2,940,000		600,000		--		--		--
Spread	$	(0.09)	$	(0.12)	$	(0.10)	$	--	$	--	$	--

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

Collar contracts:
Average Monthly Volume (Bbls)		23,000		5,000		--		--		--		--
Weighted-average floor price	$	82.83	$	80.00	$	--	$	--	$	--	$	--
Weighted-average ceiling price	$	105.31	$	94.00	$	--	$	--	$	--	$	--

Basis swaps:
Average Monthly Volume (Bbls)		134,000		97,500		--		--		--		--
Spread	$	(4.32)	$	(7.07)	$	--	$	--	$	--	$	--

NGL Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)		171,000		149,200		--		--		--		--
Weighted-average fixed price	$	42.96	$	43.02	$	--	$	--	$	--	$	--

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

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


	Remaining 2014		2015		2016
Average Monthly Notional (in thousands)		$ 236,667		$ 280,833		$ 150,000
Weighted-average fixed rate		1.320%		1.416%		1.193%
Floating rate		1 Month LIBOR		1 Month LIBOR		1 Month LIBOR

Balance Sheet Presentation

The following table summarizes both: (i) the gross fair value of derivative instruments by the appropriate balance sheet classification even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the balance sheet and (ii) the net recorded fair value as reflected on the balance sheet at June 30, 2014 and December 31, 2013. There was no cash collateral received or pledged associated with our derivative instruments since most of the counterparties, or certain of their affiliates, to our derivative contracts are lenders under our credit agreement.


		Asset Derivatives				Liability Derivatives

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

Type	Balance Sheet Location	2014		2013		2014		2013

		(In thousands)

Commodity contracts	Short-term derivative instruments	$	10,425	$	18,578	$	50,721	$	17,120
Interest rate swaps	Short-term derivative instruments		--		845		3,456		2,699

Gross fair value			10,425		19,423		54,177		19,819
Netting arrangements	Short-term derivative instruments		(8,989)		(11,823)		(8,989)		(11,823)

Net recorded fair value	Short-term derivative instruments	$	1,436	$	7,600	$	45,188	$	7,996


Commodity contracts	Long-term derivative instruments	$	36,831	$	77,348	$	125,422	$	38,456
Interest rate swaps	Long-term derivative instruments		11		27		967		2,137

Gross fair value			36,842		77,375		126,389		40,593
Netting arrangements	Long-term derivative instruments		(35,693)		(34,718)		(35,693)		(34,718)

Net recorded fair value	Long-term derivative instruments	$	1,149	$	42,657	$	90,696	$	5,875

(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 six months ended June 30, 2014 and 2013 (in thousands):


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


Commodity derivative contracts	(Gain) loss on commodity derivatives	$	138,346	$	(36,079)	$	185,112	$	(23,010)
Interest rate derivatives	Interest expense, net		776		(1,677)		1,091		(1,670)

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Note 6. Asset Retirement Obligations

The Partnership’s asset retirement obligations primarily relate to the Partnership’s portion of future plugging and abandonment costs for wells and related facilities. The following table presents the changes in the asset retirement obligations for the six months ended June 30, 2014 (in thousands):



Asset retirement obligations at beginning of period	$	99,619
Liabilities added from acquisitions or drilling		1,448
Revisions		66
Liabilities settled		(343)
Accretion expense		2,723

Asset retirement obligations at end of period	$	103,513

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:


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

BOEM platform abandonment (See Note 13)	$	68,313	$	66,373
BOEM lease bonds		794		794

SPBPC Collateral:
Contractual pipeline and surface facilities abandonment		2,487		2,306
California State Lands Commission pipeline right-of-way bond		3,005		3,005
City of Long Beach pipeline facility permit		500		500
Federal pipeline right-of-way bond		307		307
Port of Long Beach pipeline license		100		100

Restricted investments	$	75,506	$	73,385

Note 8. Long Term Debt

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


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

OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018	$	459,000	$	103,000
2021 Senior Notes, fixed-rate, due May 2021 (1)		700,000		700,000
Unamortized discounts		(10,194)		(10,933)

Total long-term debt	$	1,148,806	$	792,067

(1)

The estimated fair value of our fixed-rate debt was $735.0 million and $721.0 million at June 30, 2014 and December 31, 2013, respectively. The estimated fair value is based on quoted market prices and is classified as Level 2 within the fair value hierarchy.

Subsidiary Guarantors

We are a “Well-Known Seasoned Issuer” under SEC rules, and thus may at any time file, a universal shelf registration statement with the SEC that allows us to issue debt and equity securities. Any debt securities issued will be governed by an indenture. Our outstanding debt securities are, and any debt securities issued in the future will likely 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.

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

Borrowing Base

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


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

OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018	$	870,000	$	845,000

OLLC Revolving Credit Facility

OLLC is a party to a $2.0 billion revolving credit facility, which is guaranteed by us and all of our current and future subsidiaries (other than certain immaterial subsidiaries).

2021 Senior Notes

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

Weighted-Average Interest Rates

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

For the Three Months
Ended June 30,

For the Six Months
Ended June 30,

2014

2013

2014

2013

OLLC revolving credit facility

2.46%

3.31%

2.70%

2.98%

WHT revolving credit facility

n/a

1.11%

Stanolind revolving credit facility

n/a

3.79%

n/a

3.56%

Boaz revolving credit facility

n/a

2.89%

n/a

3.07%

Crown revolving credit facility

n/a

3.50%

n/a

3.41%

Tanos revolving credit facility

n/a

2.12%

Propel Energy revolving credit facility

n/a

2.89%

n/a

3.08%

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 debt obligations were as follows at the dates indicated:


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

OLLC $2.0 billion revolving credit facility, variable-rate, due March 2018	$	5,019	$	5,413
2021 Senior Notes (1)		14,335		15,053


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

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		Previous Owner Revolving Credit Facility		Total


For the Six Months Ended June 30, 2014:
Advances on revolving credit facility		$ 418,000	$	--	$	418,000
Payments on revolving credit facility		(62,000)		--		(62,000)

For the Six Months Ended June 30, 2013:
Advances on revolving credit facility		$ 237,000	$	14,250	$	251,250
Payments on revolving credit facility		(569,000)		(122,702)		(691,702)

Note 9. Equity & Distributions

2013 Public Equity Offering

On March 25, 2013, we issued 9,775,000 common units representing limited partner interests in the Partnership (including 1,275,000 common units purchased pursuant to the full exercise of the underwriters’ option to purchase additional common units) to the public at an offering price of $18.35 per unit generating total net proceeds of approximately $171.8 million after deducting underwriting discounts and offering expenses. The net proceeds from the 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.

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, 2013:



	Common		Subordinated		General Partner
Balance December 31, 2013		55,877,831		5,360,912		61,300
Common units issued		--		--		--
Restricted common units issued		669,898		--		--
Restricted common units forfeited		(8,863)		--		--
Restricted common units repurchased (1)		(41,679)		--		--
General partner units issued		--		--		620

Balance June 30, 2014		56,497,187		5,360,912		61,920


(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 approximately $0.9 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 six months ended June 30, 2014.

As of June 30, 2014, MRD Holdco owned 100% of the subordinated units. Memorial Resource owns 100% of our general partner, which owns 50% of our incentive distribution rights. The Funds collectively indirectly own 50% of our incentive distribution rights.

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 and the Funds. 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		Aggregate Distribution		Distribution Received by Affiliates (2)

2^nd Quarter 2014 (1)	July 24, 2014	August 5, 2014	August 12, 2014	$	0.5500	$	39.5	$	3.0
1^st Quarter 2014	April 24, 2014	May 6, 2014	May 13, 2014	$	0.5500	$	33.8	$	3.0
4^th Quarter 2013	January 27, 2014	February 6, 2014	February 13, 2014	$	0.5500	$	33.8	$	3.0
3^rd Quarter 2013	October 22, 2013	November 1, 2013	November 12, 2013	$	0.5500	$	33.8	$	6.9
2^nd Quarter 2013	July 18, 2013	August 1, 2013	August 12, 2013	$	0.5125	$	22.9	$	6.4
1^st Quarter 2013	April 18, 2013	May 1, 2013	May 13, 2013	$	0.5125	$	22.6	$	6.4
4^th Quarter 2012	January 15, 2013	February 1, 2013	February 13, 2013	$	0.5075	$	17.4	$	6.3

(1)

Distributions paid on August 12, 2014 will include distributions paid on 9,890,000 common units which were issued on July 15, 2014. See Note 14 for more information regarding the equity offering.

(2)	In June 2014, MRD LLC distributed all of our subordinated units to MRD Holdco. See Note 1 for additional information.

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 June 30,				For the Six Months Ended June 30,
	2014		2013		2014		2013

Net income (loss) attributable to Memorial Production Partners LP	$	(114,194)	$	52,597	$	(148,306)	$	48,304
Less: Previous owners interest in net income (loss)		--		6,418		--		7,147
Less: General partner’s 0.1% interest in net income (loss)		(114)		46		(148)		41
Less: IDRs attributable to corresponding period		47		--		87		--

Net income (loss) available to limited partners	$	(114,127)	$	46,133	$	(148,245)	$	41,116


Weighted average limited partner units outstanding:
Common units		56,103		38,870		55,997		34,307
Subordinated units		5,361		5,361		5,361		5,361

Total		61,464		44,231		61,358		39,668


Basic and diluted EPU	$	(1.86)	$	1.04	$	(2.42)	$	1.04

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


	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2014		2013		2014		2013

Net income (loss) attributable to Memorial Production Partners LP	$	(114,194)	$	52,597	$	(148,306)	$	48,304
Less: General partner’s 0.1% interest in net income (loss)		(114)		46		(148)		41
Less: IDRs attributable to corresponding period		47		--		87		--

Net income (loss) available to limited partners	$	(114,127)	$	52,551	$	(148,245)	$	48,263


Weighted average limited partner units outstanding:
Common units		56,103		38,870		55,997		34,307
Subordinated units		5,361		5,361		5,361		5,361

Total		61,464		44,231		61,358		39,668


Supplemental basic and diluted EPU	$	(1.86)	$	1.19	$	(2.42)	$	1.22

Our supplemental basic and diluted EPU includes all the earnings generated by the Partnership’s previous owners for the periods presented due to common control considerations. As discussed under Note 1, transactions between entities under common control are accounted for retrospectively.

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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, 2013		706,927	$	18.62
Granted (2)		669,898	$	22.36
Forfeited		(8,863)	$	18.57
Vested		(256,130)	$	18.57

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

(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 2014 was $15.0 million based on a grant date market price range of $21.99 - $22.37 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 June 30,			For the Six Months Ended June 30,
2014		2013	2014		2013

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

The unrecognized compensation cost associated with restricted common unit awards was $21.7 million at June 30, 2014. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.5 years. Since the restricted common units are participating securities, distributions received by the restricted common unitholders are generally included in distributions to partners as presented on our unaudited condensed statements of consolidated and combined cash flows.

Note 12. Related Party Transactions

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

Common Control Acquisitions

April 2014 Acquisition. In April 2014, we acquired certain oil and natural gas properties in East Texas from WildHorse Resources, LLC (“WildHorse”), a subsidiary of MRD LLC, for approximately $33.3 million, including estimated customary post-closing adjustments (the “Double A Acquisition”). The acquired properties primarily represent additional working interests in wells currently owned by us and located in Polk and Tyler Counties in the Double A Field of East Texas as well as the Sunflower, Segno and Sugar Creek Fields. Terms of the transaction were approved by our general partner’s board of directors and by its conflicts committee. This acquisition was accounted for as a transaction with an entity under common control whereby the acquisition was recorded at historical cost at the acquisition date. The Partnership recorded the following net assets (in thousands):


	Double A Acquisition

Oil and gas properties, net	$	37,838
Asset retirement obligations		(908)
Other current liabilities		(722)

Total identifiable net assets	$	36,208

Due to common control considerations, the difference between the purchase price and the total identifiable assets has been recorded as a contribution on our Unaudited Condensed Statements of Consolidated and Combined Equity.

March 2013 Acquisition. On March 28, 2013, we acquired all of the outstanding equity interests in WHT from operating subsidiaries of MRD LLC 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,

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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):


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

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 provides 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 June 30,				For the Six Months Ended June 30,
2014		2013		2014		2013

$	5,411	$	1,766	$	10,259	$	3,251

Beta Management Agreement

The Partnership acquired Rise Energy Operating, LLC (“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, MRD LLC entered into a management agreement with its wholly-owned subsidiary, Beta Operating Company, LLC. Pursuant to such management agreement, Memorial Resource, as successor to MRD LLC under the agreement, provides 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.

WHT Management Agreement

MRD LLC controlled 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 PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

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 June 30, 2014 and December 31, 2013, we had $2.5 million and $0.4 million of environmental reserves recorded on our balance sheets, respectively. During the six months ended June 30, 2014, we recorded $2.9 million of estimated environmental remediation expenses associated with our Permian and Wyoming oil and gas properties. These expenses are reflected as a component of lease operating expenses on our statement of operations. Environmental costs for remediation are accrued when environmental remediation efforts are probable and the costs can be reasonably estimated. Such accruals are based on management’s best estimate of the ultimate cost to remediate a site and are adjusted as further information and circumstances develop. Those estimates may change substantially depending on information about the nature and extent of contamination, appropriate remediation technologies and regulatory approvals.

Supplemental Bond for Decommissioning Liabilities Trust Agreement

The trust account is held by REO for the benefit of all working interest owners. The following is a summary of the gross held-to-maturity investments held in the trust account less the outside working interest owners share as of June 30, 2014 (in thousands):


Investment	Amortized Cost

U.S. Bank Money Market Cash Equivalent	$	132,003

Less: Outside working interest owners share		(63,690)

	$	68,313

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


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

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

Note 14. Subsequent Events

2022 Senior Notes Offering

On July 17, 2014, the Issuers completed a private placement of $500.0 million aggregate principal amount of 6.875% senior unsecured notes due in 2022 (the “2022 Senior Notes”). The 2022 Senior Notes were issued at 98.485% of par and are fully and unconditionally guaranteed (subject to customary release provisions) on a joint and several basis by the Guarantor Subsidiaries and by certain future subsidiaries of the Partnership. The 2022 Senior Notes will mature on August 1, 2022 with interest accruing at 6.875% per annum and payable semi-annually in arrears on February 1 and August 1 of each year, commencing on February 1, 2015. 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 2022 Senior Notes receive an investment grade rating from both of two specified ratings agencies. The indenture also provides for customary and other events of default. In the case of an event of default arising from certain events of bankruptcy or insolvency with respect to either of the Issuers, all outstanding 2022 Senior Notes will become due and payable

MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding 2022 Senior Notes may declare all the 2022 Senior Notes to be due and payable immediately. The net proceeds from the notes offering of approximately $484.9 million, after deducting the initial purchasers’ discounts and commissions but before estimated offering expenses, were used to repay a portion of the outstanding borrowings under our revolving credit facility and for general partnership purposes. In conjunction with the closing of the offer and sale of the 2022 Senior Notes, the borrowing base under our revolving credit facility was automatically decreased from $1.44 billion to $1.315 billion.

2014 Equity Offering

On July 15, 2014, we issued 9,890,000 common units representing limited partner interests in the Partnership (including 1,290,000 common units purchased pursuant to the full exercise of the underwriters’ option to purchase additional common units) to the public at an offering price of $22.25 per unit generating total net proceeds of approximately $220.3 million after deducting underwriting discounts but before offering expenses. The net proceeds from the equity offering, including our general partner’s proportionate capital contribution, were used to repay a portion of the outstanding borrowings under our revolving credit facility.

Wyoming Acquisition

On May 5, 2014, we announced that we entered into a definitive purchase and sale agreement with Merit Energy Company, LLC and certain of its affiliates to acquire oil and natural gas liquids properties in Wyoming (the “Wyoming Acquisition”). On May 5, 2014, we paid a deposit of $70.1 million, which is recorded as a component of “Other long-term assets” on our Unaudited Condensed Consolidated and Combined Balance Sheets at June 30, 2014. On July 1, 2014, we consummated the Wyoming Acquisition for an aggregate purchase price of approximately $915.1 million, subject to customary post-closing adjustments. The Wyoming Acquisition has an effective date of April 1, 2014. In conjunction with the closing of the Wyoming Acquisition, the borrowing base under our revolving credit facility increased from $870 million to $1.44 billion. The Wyoming Acquisition was funded with borrowings under our revolving credit facility.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS.

Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the unaudited condensed financial statements and accompanying notes in “Item 1. Financial Statements” contained herein and our Annual Report on Form 10-K for the year ended December 31, 2013 (“2013 Form 10-K”). The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. See “Cautionary Note Regarding Forward-Looking Statements” in the front of this report.

Overview

We are a Delaware limited partnership formed in April 2011 by MRD LLC to own, acquire and exploit oil and natural gas properties in North America. The Partnership is owned 99.9% by its limited partners and 0.1% by its general partner, which is a wholly-owned subsidiary of Memorial Resource. Our general partner is responsible for managing all of the Partnership’s operations and activities.

We operate in one reportable segment engaged in the acquisition, exploitation, development and production of oil and natural gas properties. Our business activities are conducted through OLLC, our wholly-owned subsidiary, and its wholly-owned subsidiaries. Our assets consist primarily of producing oil and natural gas properties and are principally located in Texas, Louisiana, 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, 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 2,866 gross (1,663 net) producing wells across our properties, with an average working interest of 58%, and the Partnership or Memorial Resource is the operator of record of the properties containing 94% of our total estimated proved reserves; and

•

Our average net production for the three months ended December 31, 2013 was 167.7 MMcfe/d, implying a reserve-to-production ratio of approximately 17 years.

Significant Recent Developments

2022 Senior Notes Offering

On July 17, 2014, we and Finance Corp. (collectively, the “Issuers”) completed a private placement of $500.0 million aggregate principal amount of 6.875% senior unsecured notes due in 2022 (the “2022 Senior Notes”). The 2022 Senior Notes were issued at 98.485% of par and are fully and unconditionally guaranteed (subject to customary release provisions) on a joint and several basis by all of our subsidiaries (other than Finance Corp., which is co-issuer of the 2022 Senior Notes, and certain immaterial subsidiaries). The 2022 Senior Notes will mature on August 1, 2022 with interest accruing at 6.875% per annum and payable semi-annually in arrears on February 1 and August 1 of each year, commencing on February 1, 2015. The net proceeds of approximately $484.9 million, after deducting the initial purchasers’ discounts and commissions but before estimated offering expenses, were used to repay a portion of the borrowings outstanding under our revolving credit facility and for general partnership purposes. In conjunction with the closing of the offer and sale of the 2022 Senior Notes, the borrowing base under our revolving credit facility was automatically decreased from $1.44 billion to $1.315 billion. For additional information regarding the 2022 Senior Notes, see Note 14 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under Item 1 of this quarterly report.

2014 Equity Offering

Wyoming Acquisition

On May 5, 2014, we announced that we entered into a definitive purchase and sale agreement with Merit Energy Company, LLC and certain of its affiliates to acquire oil and natural gas liquids properties in Wyoming (the “Wyoming Acquisition”). On July 1, 2014, we consummated the Wyoming Acquisition for an aggregate purchase price of approximately $915.1 million, subject to customary post-closing adjustments. The Wyoming Acquisition has an effective date of April 1, 2014. In conjunction with the closing of the Wyoming Acquisition, the borrowing base under our revolving credit facility was increased from $870 million to $1.44 billion. The Wyoming Acquisition was funded with 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.

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 believe 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 primarily with lenders under our credit agreement. Historically, the Partnership has not paid or received premiums for put options; however, from time to time the previous owners did enter into such agreements.

Lease Operating Expenses

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.

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

General & Administrative Expenses

We and our general partner are parties to an omnibus agreement with a wholly-owned subsidiary of 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. Memorial Resource allocates its indirect general and administrative costs based on our relative production in comparison to Memorial Resource’s production, which it believes accurately reflects 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; and

•

Other non-routine items that we deem appropriate.

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 June 30,				For the Six Months Ended June 30,
	2014		2013		2014		2013

Calculation of Adjusted EBITDA:
Net income (loss)	$	(114,206)	$	52,695	$	(148,263)	$	48,398
Interest expense, net		18,036		7,931		34,114		14,473
Income tax expense (benefit)		--		188		75		188
DD&A		35,157		24,672		61,902		45,063
Accretion of AROs		1,366		1,148		2,723		2,293
(Gains) losses on commodity derivative instruments		138,346		(36,079)		185,112		(23,010)
Cash settlements received (paid) on commodity derivative instruments		(7,906)		3,286		(15,875)		10,403
Gain on sale of properties		--		(885)		--		(2,868)
Acquisition related costs		1,093		897		2,987		1,112
Unit-based compensation expense		1,665		663		2,960		1,085
Non-cash compensation expense		--		1,125		--		1,125
Exploration costs		204		48		210		275
Provision for environmental remediation		--		--		2,852		--

Adjusted EBITDA	$	73,755	$	55,689	$	128,797	$	98,537


	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2014		2013		2014		2013

Reconciliation of Net Cash from Operating Activities to Adjusted EBITDA:
Net cash provided by operating activities	$	48,029	$	40,094	$	96,052	$	81,865
Changes in working capital		7,891		6,196		(4,605)		1,817
Interest expense, net		18,036		7,931		34,114		14,473
Gain (loss) on interest rate swaps		(776)		1,677		(1,091)		1,670
Cash settlements paid on interest rate derivative instruments		512		415		643		1,046
Amortization of deferred financing fees		(862)		(1,671)		(1,701)		(3,823)
Accretion of senior notes discount		(372)		(86)		(739)		(86)
Acquisition related expenses		1,093		897		2,987		1,112
Income tax expense (benefit) – current portion		--		188		75		188
Exploration costs		204		48		210		275
Provision for environmental remediation		--		--		2,852		--

Adjusted EBITDA	$	73,755	$	55,689	$	128,797	$	98,537

Critical Accounting Policies and Estimates

A discussion of our critical accounting policies and estimates is included in our 2013 Form 10-K. Significant estimates include, but are not limited to, oil and natural gas reserves; depreciation, depletion, and amortization of proved oil and natural gas

properties; future cash flows from oil and natural gas properties; impairment of long-lived assets; fair value of derivatives; fair value of equity compensation; fair values of assets acquired and liabilities assumed in business combinations and asset retirement obligations. These estimates, in our opinion, are subjective in nature, require the exercise of professional judgment and involve complex analysis.

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

Results of Operations

The results of operations for the three and six months ended June 30, 2014 and 2013 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 (i) the WHT Properties acquired from MRD LLC in March 2013 from February 2, 2011 (inception) through the date of acquisition and (ii) the Cinco Group acquisition. The results of operations for the three and six months ended June 30, 2013 have 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.


	For the Three Months Ended June 30,				For the Six Months Ended June 20,
	2014		2013		2014		2013

Revenues:
Oil & natural gas sales	$	122,247	$	89,673	$	222,546	$	157,261
Pipeline tariff income and other		1,063		501		1,741		1,015

Total revenues		123,310		90,174		224,287		158,276


Costs and expenses:
Lease operating		26,067		20,217		54,055		41,588
Pipeline operating		676		479		1,165		949
Exploration		204		48		210		275
Production and ad valorem taxes		7,076		4,967		12,660		8,847
Depreciation, depletion, and amortization		35,157		24,672		61,902		45,063
General and administrative		10,588		14,170		20,546		21,483
Accretion of asset retirement obligations		1,366		1,148		2,723		2,293
(Gain) loss on commodity derivative instruments		138,346		(36,079)		185,112		(23,010)
(Gain) loss on sale of properties		--		(885)		--		(2,868)
Other, net		--		623		(12)		597

Total costs and expenses		219,480		29,360		338,361		95,217

Operating income (loss)		(96,170)		60,814		(114,074)		63,059
Other income (expense):
Interest expense, net		(18,036)		(7,931)		(34,114)		(14,473)

Total other income (expense)		(18,036)		(7,931)		(34,114)		(14,473)

Income before income taxes		(114,206)		52,883		(148,188)		48,586
Income tax benefit (expense)		--		(188)		(75)		(188)

Net income (loss)		(114,206)		52,695		(148,263)		48,398
Net income (loss) attributable to noncontrolling interest		(12)		98		43		94

Net income (loss) attributable to Memorial Production Partners LP	$	(114,194)	$	52,597	$	(148,306)	$	48,304


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

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


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

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

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


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

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


Average unit costs per Mcfe:
Lease operating expense	$	1.46	$	1.40	$	1.65	$	1.59
Production and ad valorem taxes	$	0.40	$	0.34	$	0.39	$	0.34
General and administrative expenses	$	0.59	$	0.98	$	0.63	$	0.82
Depletion, depreciation, and amortization	$	1.97	$	1.71	$	1.89	$	1.73

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

A net loss of $114.2 million was recorded during the three months ended June 30, 2014, primarily due to losses on commodity derivative instruments and increased DD&A expense, as discussed below, compared to net income of $52.7 million recorded during the three months ended June 30, 2013.

Revenues. Oil, natural gas and NGL revenues for the three months ended June 30, 2014 totaled $122.2 million, an increase of $32.6 million compared with the three months ended June 30, 2013. Production increased 3.4 Bcfe (approximately 23%), primarily from increased drilling activities and increased volumes from third party acquisitions. The average realized sales price increased $0.67 per Mcfe primarily due to higher natural gas and crude oil prices. The favorable volume and pricing variance contributed to an approximate $20.8 million and $11.8 million increase in revenues, respectively.

Lease Operating. Lease operating expenses were $26.1 million and $20.2 million for the three months ended June 30, 2014 and 2013, respectively. On a per Mcfe basis, lease operating expenses increased to $1.46 for the three months ended June 30, 2014 from $1.40 for the three months ended June 30, 2013. This increase was primarily due to the acquisition of new oil and gas properties.

Production and Ad Valorem Taxes. Production and ad valorem taxes for the three months ended June 30, 2014 totaled $7.1 million, an increase of $2.1 million compared with the three months ended June 30, 2013 primarily due to an increase in production volumes. On a per Mcfe basis, production and ad valorem taxes increased to $0.40 for the three months ended June 30, 2014 from $0.34 for the three months ended June 30, 2013.

Depreciation, Depletion and Amortization. DD&A expense for the three months ended June 30, 2014 was $35.2 million compared to $24.7 million for the three months ended June 30, 2013, a $10.5 million increase primarily due to both an increase in the depletable cost base and increased production volumes related to third party acquisitions and the Partnership’s drilling program. Increased production volumes caused DD&A expense to increase by an approximate $5.8 million and the change in the DD&A rate between periods caused DD&A expense to increase by approximately $4.7 million.

General and Administrative. General and administrative expenses include the costs of administrative employees and related benefits, management fees paid to affiliates, professional fees and other costs not directly associated with field operations. General and administrative expenses for the three months ended June 30, 2014 were $10.6 million. General and administrative expenses for the three months ended June 30, 2014 included $1.7 million of non-cash unit-based compensation expense and $1.1 million of acquisition-related costs. General and administrative expenses for the three months ended June 30, 2013 totaled $14.2 million. General and administrative expenses for the three months ended June 30, 2013 included $0.7 million of non-cash unit-based compensation expense and $0.9 million of acquisition-related costs. The $3.6 million decrease in general administrative expenses included $5.8 million of compensation expense related to the Tanos management buyout during the three months ended June 30, 2013 offset by increased salaries and employee count between periods.

Gain/Loss on Commodity Derivative Instruments. Net losses on commodity derivative instruments of $138.3 million were recognized during the three months ended June 30, 2014, consisting of $7.9 million of cash settlement payouts in addition to a $130.4 million decline in the fair value of open positions. Net gains on commodity derivative instruments of $36.1 million were recognized during the three months ended June 30, 2013, consisting of $3.3 million of cash settlement receipts in addition to a $32.8 million increase in the fair value of open positions.

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

Interest Expense, Net. Net interest expense is comprised of interest on credit facilities, interest on our senior notes, amortization of debt issue costs, accretion of net discount associated with our senior notes, and gains and losses on interest rate swaps. Interest expense, net totaled $18.0 million during the three months ended June 30, 2014, including losses on interest rate swaps of approximately $0.8 million, amortization of deferred financing fees of approximately $0.9 million, and accretion of net discount associated with our senior notes of $0.4 million. Interest expense, net totaled $7.9 million during the three months ended June 30, 2013, including gains on interest rate swaps of approximately $1.7 million and amortization of deferred financing fees of

approximately $1.7 million. The $10.1 million increase in interest expense is primarily due to the increase in outstanding borrowings under the Partnership’s revolving credit facility and a higher aggregate principal amount of our senior notes issued and outstanding for the three months ended June 30, 2014 compared to the three months ended June 30, 2013.

Average outstanding borrowings under the Partnership’s revolving credit facility were $431.7 million during the three months ended June 30, 2014 compared to $138.4 million during the three months ended June 30, 2013. Average outstanding borrowings under the previous owners’ revolving credit facilities were $129.9 million during the three months ended June 30, 2013. For the three months ended June 30, 2014, the Partnership had a weighted average of $700.0 million aggregate principal amount of our senior notes issued and outstanding as compared to a weighted average of $290.1 million aggregate principal amount of our senior notes issued and outstanding for the three months ended June 30, 2013.

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

A net loss of $148.3 million was generated for the six months ended June 30, 2014, primarily due to losses on commodity derivative instruments, increased lease operating expenses and increases in DD&A, as discussed below. Net income of $48.4 million was generated for the six months ended June 30, 2013.

Revenues. Oil, natural gas and NGL revenues for the six months ended June 30, 2014 totaled $222.5 million, an increase of $65.3 million compared with the six months ended June 30, 2013. Production increased 6.7 Bcfe (approximately 26%), primarily from drilling activities and increased volumes from third party acquisitions. The average realized sales price increased $0.76 per Mcfe primarily due to higher natural gas prices. The favorable volume and pricing variance contributed to an approximate $40.4 million and $24.9 million increase in revenues, respectively.

Lease Operating. Lease operating expenses were $54.1 million and $41.6 million for the six months ended June 30, 2014 and 2013, respectively. On a per Mcfe basis, lease operating expenses increased to $1.65 for 2014 from $1.60 for 2013. During the six months ended June 30, 2014, we recorded $2.9 million of estimated environmental remediation expenses associated with our Permian and Wyoming oil and gas properties.

Production and Ad Valorem Taxes. Production and ad valorem taxes for the six months ended June 30, 2014 totaled $12.7 million, an increase of $3.8 million compared with the six months ended June 30, 2013 primarily due to an increase in production volumes. On a per Mcfe basis, production and ad valorem taxes increased to $0.39 for the six months ended June 30, 2014 from $0.34 for 2013.

Depreciation, Depletion and Amortization. DD&A expense for the six months ended June 30, 2014 was $61.9 million compared to $45.1 million for the six months ended June 30, 2013, a $16.8 million increase primarily due to both an increase in the depletable cost base and increased production volumes related to third party acquisitions and the Partnership’s drilling program. Increased production volumes caused DD&A expense to increase by an approximate $11.6 million and the change in the DD&A rate between periods caused DD&A expense to increase by approximately $5.2 million.

General and Administrative. General and administrative expenses for the six months ended June 30, 2014 were $20.5 million. General and administrative expenses for the six months ended June 30, 2014 included $3.0 million of non-cash unit-based compensation expense and $3.0 million of acquisition-related costs. General and administrative expenses for the six months ended June 30, 2013 totaled $21.5 million. General and administrative expenses for the six months ended June 30, 2013 included $1.1 million of non-cash unit-based compensation expense and $1.1 million of acquisition-related costs. The $1.0 million decrease in general administrative expenses included $5.8 million of compensation expense related to the Tanos management buyout during the six months ended June 30, 2013 offset by increased salaries and employee count between periods.

Gain/Loss on Commodity Derivative Instruments. Net losses on commodity derivative instruments of $185.1 million were recognized during the six months ended June 30, 2014, consisting of $15.9 million of cash settlement payouts in addition to a $169.2 million decline in the fair value of open positions. Net gains on commodity derivative instruments of $23.0 million were recognized during the six months ended June 30, 2013, consisting of $10.4 million of cash settlement receipts, in addition to a $12.6 million increase in the fair value of open positions.

Interest Expense, Net. Interest expense, net totaled $34.1 million during the six months ended June 30, 2014, including losses on interest rate swaps of approximately $1.1 million, amortization of deferred financing fees of approximately $1.7 million, and accretion of net discount associated with our senior notes of $0.7 million. Interest expense, net totaled $14.5 million during the six months ended June 30, 2013, including gains on interest rate swaps of $1.7 million and amortization of deferred financing fees of approximately $3.8 million. The $19.6 million increase in interest expense is primarily due to a higher aggregate principal amount of our senior notes issued and outstanding for the six months ended June 30, 2014 compared to the six months ended June 30, 2013.

Average outstanding borrowings under the Partnership’s revolving credit facility were $291.0 million during the six months ended June 30, 2014 compared to $253.6 million during the six months ended June 30, 2013. Average outstanding borrowings under the previous owners’ revolving credit facilities were $179.6 million during the six months ended June 30, 2013. For the six months ended June 30, 2014, the Partnership had a weighted average of $700.0 million aggregate principal amount of our senior notes issued and outstanding. For the six months ended June 30, 2013, the Partnership had a weighted average of $145.9 million aggregate principal amount of our senior notes issued and outstanding.

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 June 30, 2014, our liquidity of $411.3 million consisted of $0.3 million of cash and cash equivalents and $411.0 million of available borrowings under our revolving credit facility. At August 1, 2014, there was approximately $695.0 million of available borrowings under our revolving credit facility after giving effect to the Wyoming Acquisition and application of the net proceeds from our July 15, 2014 equity offering and the issuance of the 2022 Senior Notes on July 17, 2014. 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 have filed, and we may in the future file, a universal shelf registration statement with the SEC to register the offer and sale of our equity or debt securities. Our primary cash requirements are for working capital needs, capital expenditures, debt service and distributions to our partners.

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 and/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.

As of June 30, 2014, we had a negative working capital balance of $70.4 million primarily due to the timing of accruals, which included accrued capital expenditures of $28.6 million and a net liability balance of $43.8 million of current derivative instruments. As of June 30, 2014, we had $411.0 million of available borrowings under our revolving credit facility to meet our working capital needs.

Capital Expenditures

For the six months ended June 30, 2014, our total capital expenditures, excluding acquisitions, were approximately $129.0 million. Our capital spending program related to drilling, recompletions and capital workovers was approximately 97% of total capital expenditures. We spent approximately 53% in East Texas / North Louisiana, 30% in the Permian Basin, 10% in California and 7% in South Texas / Eagle Ford.

Revolving Credit Facility

OLLC is a party to a $2.0 billion revolving credit facility that matures in March 2018 and is guaranteed by us and all of our current and future subsidiaries (other than certain immaterial subsidiaries). As of June 30, 2014, we had $459.0 million of outstanding borrowings. On July 1, 2014, in connection with the Wyoming Acquisition, our borrowing base was increased from $870.0 million to $1.44 billion. In conjunction with the closing of the 2022 Senior Notes, the borrowing base under our revolving credit facility was automatically decreased from $1.44 billion to $1.315 billion. 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 June 30, 2014, we were in compliance with all of the financial and other covenants under our revolving credit facility.

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

2021 Senior Notes

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

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

2022 Senior Notes

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

For additional information regarding the 2022 Senior Notes, see Note 14 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under Item 1 of this quarterly report.

Commodity Derivative Contracts

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

For additional information regarding the volumes of our production covered by commodity derivative contracts and the average prices at which production is hedged as of June 30, 2014, see “Item 3. Quantitative and Qualitative Disclosures About Market Risk — Counterparty and Customer Credit Risk.”

Interest Rate Derivative Contracts

Periodically, we 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 June 30, 2014.

Counterparty Exposure

Our derivative contracts are primarily with major financial institutions, certain of which are also lenders under our revolving credit facility. We have rights of offset against the borrowings under our revolving credit facility. See “Item 3. Quantitative and Qualitative Disclosures About Market Risk — Counterparty and Customer Credit Risk” for additional information.

Cash Flows from Operating, Investing and Financing Activities

The following table summarizes our cash flows from operating, investing and financing activities for the periods indicated. The cash flows for the six months ended June 30, 2014 and 2013 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 (i) the WHT Properties acquired from MRD LLC in March 2013 from February 2, 2011 (inception) through the date of acquisition and (ii) the Cinco Group 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 Six months Ended June 30,
	2014		2013

Net cash provided by operating activities	$	96,052	$	81,865
Net cash used in investing activities		362,862		93,624
Net cash provided by financing activities		254,020		8,388

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

Operating Activities. Key drivers of net operating cash flows are commodity prices, production volumes and operating costs. Net income decreased by $196.7 million and net cash provided by operating activities increased by $14.2 million. Production increased 6.7 Bcfe (approximately 26%) and average realized sales price increased $0.76 per Mcfe as previously discussed under “—Results of Operations.” Cash paid for interest during the six months ended June 30, 2014 was $31.3 million compared to $8.1 million during the six months ended June 30, 2013. Net cash provided by operating activities included a $6.4 million period-to-period increase in cash flow attributable to the timing of cash receipts and disbursements related to operating activities during the six months ended June 30, 2014 compared to the six months ended June 30, 2013.

Investing Activities. Net cash used in investing activities during the six months ended June 30, 2014 was $362.9 million, of which $173.0 million was used to acquire oil and natural gas properties from a third party and $117.6 million was used for additions to oil and gas properties. Cash used in investing activities during the six months ended June 30, 2013 was $93.6 million, of which $6.3 million was used to acquire oil and natural gas properties from a third party and $88.6 million was used for additions to oil and gas properties. On May 5, 2014, we paid a deposit of $70.1 million related to our Wyoming Acquisition. During the six months ended June 30, 2013, Tanos had sales proceeds of $4.5 million related to the sale of oil and natural gas properties. Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with our offshore Southern California oil and gas properties.

Financing Activities. On March 25, 2013, we issued 9,775,000 common units representing limited partner interests in the Partnership to the public at an offering price of $18.35 per unit generating gross proceeds of approximately $179.4 million, offset by approximately $7.6 million of costs incurred in conjunction with the issuance of common units. The net proceeds from the equity offering, including our general partner’s proportionate capital contribution, partially funded the acquisition of all of the outstanding equity interests in WHT.

Distributions to partners during the six months ended June 30, 2014 were $67.5 million compared to $40.0 million during 2013. 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 the six months ended June 30, 2013 were $23.2 million.

We paid $55.4 million to MRD LLC in connection with our March 28, 2013 acquisition of all of the outstanding equity interests in WHT and repaid $89.3 million of indebtedness under WHT’s credit facility. The Partnership had net payments of $332.0 million under its revolving credit facility during the six months ended June 30, 2013. The Cinco Group had advances of $13.3 million under their credit facilities and repaid $32.4 million of outstanding borrowings during the six months ended June 30, 2013. The Partnership had net borrowings of $356.0 million under its revolving credit facility during 2014 that were used primarily to fund the Eagle Ford Acquisition and to fund its drilling program and the earnest money deposit for the Wyoming acquisition. Deferred financing costs of approximately $0.6 million were incurred during the six months ended June 30, 2014 compared to approximately $11.2 million during the six months ended June 30, 2013.

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.

Contractual Obligations

During the six months ended June 30, 2014, there were no significant changes in our consolidated contractual obligations from those reported in our 2013 Form 10-K except for revolving credit facility borrowings and advances.

Off–Balance Sheet Arrangements

As of June 30, 2014, we had no off–balance sheet arrangements.

Recently Issued Accounting Pronouncements

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

In the normal course of our business operations, we are exposed to certain risks, including changes in interest rates and commodity prices. We may enter into derivative instruments to manage or reduce market risk, but do not enter into derivative agreements for speculative purposes. We do not designate these or plan to designate future derivative instruments as hedges for accounting purposes. Accordingly, the changes in the fair value of these instruments are recognized currently in earnings. We believe that our exposures to market risk have not changed materially since those reported under Item 7A, “Quantitative and Qualitative Disclosures About Market Risk,” included in our 2013 Form 10-K.

Commodity Price Risk

Our major market risk exposure is in the pricing that we receive for our natural gas, oil and NGL production. To reduce the impact of fluctuations in commodity prices on our revenues, or to protect the economics of property acquisitions, we periodically enter into derivative contracts with respect to a portion of our projected production through various transactions that fix the future prices received. 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 June 30, 2014, see Note 5 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under Item 1 of this quarterly report.

Interest Rate Risk

Our risk management policy provides for the use of interest rate swaps to reduce the exposure to market rate fluctuations by converting variable interest rates to fixed interest rates. Conditions sometimes arise where actual borrowings are less than notional amounts hedged which has and could result in over-hedged amounts from an economic perspective. From time to time we enter into offsetting positions to avoid being economically over-hedged. See Note 5 of the Notes to Unaudited Condensed Consolidated and Combined Financial Statements included under Item 1 of this quarterly report for interest rate swap arrangements that were outstanding at June 30, 2014.

At June 30, 2014, we had $459.0 million of Eurodollar borrowings outstanding under our revolving credit facility, with an interest rate of LIBOR plus 2.00%, or 2.15%. 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 June 30, 2014, would be less than $0.1 million per year.

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


	June 30, 2014
Description	Carrying Amount		Estimated Fair Value


2021 Senior Notes, fixed-rate, due May 1, 2021	$	689,806	$	735,000

Counterparty and Customer Credit Risk

We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. In addition, our derivative contracts may expose us to credit risk in the event of nonperformance by counterparties. Some of the lenders, or certain of their affiliates, under our credit agreement are counterparties to our derivative contracts. While collateral is generally not required to be posted by counterparties, credit risk associated with derivative instruments is minimized by limiting exposure to any single counterparty and entering into derivative instruments only with counterparties that are large financial institutions. Additionally, master netting agreements are used to mitigate risk of loss due to default with counterparties on derivative instruments. These agreements allow us to offset our asset position with our liability position in the event of default by the counterparty. We have also entered into the International Swaps and Derivatives Association Master Agreements (“ISDA Agreements”) with each of our counterparties. The terms of the ISDA Agreements provide us and each of our counterparties with rights of set-off upon the occurrence of defined acts of default by either us or our counterparty to a derivative, whereby the party not in default may set-off all liabilities owed to the defaulting party against all net derivative asset receivables from the defaulting party. At June 30, 2014, after taking into effect netting arrangements, we do not have any counterparty exposure related to our derivative instruments. 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 $1.7 million against amounts outstanding under our revolving credit facility at June 30, 2014.

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 June 30, 2014.

Change in Internal Controls Over Financial Reporting

No changes in our internal control over financial reporting occurred during the quarter ended June 30, 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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

PART II—OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS.

For information regarding legal proceedings, see Part I, Item 1, Financial Statements, Note 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, 2013 filed with the SEC on March 7, 2014 and the revised, clarified and supplemented risk factors disclosed in our Current Report on Form 8-K filed with the SEC on July 1, 2014.

The listing of a species as either “threatened” or “endangered” under the federal Endangered Species Act could result in increased costs, new operating restrictions, or delays in our operations, which could adversely affect our results of operations and financial condition.

The federal Endangered Species Act (“ESA”) and analogous state laws regulate activities that could have an adverse effect on threatened and endangered species. Operations in areas where threatened or endangered species or their habitat are known to exist may require us to incur increased costs to implement mitigation or protective measures and also may restrict or preclude our activities in those areas or during certain seasons, such as breeding and nesting seasons. On March 27, 2014, the U.S. Fish and Wildlife Service (“FWS”) announced the listing of the lesser prairie chicken, whose habitat is over a five-state region, including Texas, New Mexico and Colorado, where we conduct operations, as a threatened species under the ESA. Listing of the lesser prairie chicken as threatened imposes restrictions on disturbances to critical habitat by landowners and drilling companies that would harass, harm or otherwise result in a “taking” of this species. The FWS also announced a final rule that will limit regulatory impacts on landowners and businesses from the listing if those landowners and businesses have entered into certain range-wide conservation planning agreements, such as those developed by the Western Association of Fish and Wildlife Agencies (“WAFWA”), pursuant to which such parties agreed to take steps to protect the lesser prairie chicken’s habitat and to pay a mitigation fee if its actions harm the lesser prairie chicken’s habitat. The listing of the lesser prairie chicken as a threatened species or, alternatively, entry into certain range-wide conservation planning agreements such as WAFWA, could result in increased costs to us from species protection measures, time delays or limitations on our activities, which costs, delays or limitations may be significant and could adversely affect our results of operations and financial position.

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

Our general partner’s 0.1% interest in us was represented by 61,920 general partner units at June 30, 2014. 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 six months ended June 30, 2014, 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 620 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.

The following table summarizes our repurchase activity during the quarterly period ended June 30, 2014:


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

June 1, 2014 to June 30, 2014 (1)		41,202	$	22.80		--		--


(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.

ITEM 6. EXHIBITS.


Exhibit Number		Description
2.1##	—	Purchase and Sale Agreement, dated as of March 25, 2014, between Alta Mesa Eagle, LLC and Memorial Production Operating LLC (incorporated by reference to Exhibit 2.1 to Current Report on Form 8-K (File No. 001-35364) filed on March 25, 2014).

2.2##	—	Purchase and Sale Agreement, dated as of May 2, 2014, among Merit Management Partners I, L.P., Merit Energy Partners III, L.P., Merit Pipeline Company, LLC and Merit Energy Company, LLC and Memorial Production Operating LLC (incorporated by reference to Exhibit 2.1 to Current Report on Form 8-K (File No. 001-35364) filed on May 5, 2014).

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*	—	Third Amended and Restated Limited Liability Company Agreement of Memorial Production Partners GP LLC.

4.1	—	Indenture, dated July 17, 2014, by and among Memorial Production Partners LP, Memorial Production Finance Corporation, the subsidiary guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K (File No. 001-35364) filed on July 17, 2014).


4.2	—	Registration Rights Agreement, dated July 17, 2014, by and among Memorial Production Partners LP, Memorial Production Finance Corporation, the subsidiary guarantors named therein, and Barclays Capital Inc., as representative of the initial purchasers named therein (incorporated by reference to Exhibit 4.2 to Current Report on Form 8-K (File No. 001-35364) filed on July 17, 2014).

4.3#	—	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).

10.1	—	Purchase Agreement, dated July 14, 2014, by and among Memorial Production Partners LP, Memorial Production Finance Corporation, the subsidiary guarantors named therein, and Barclays Capital Inc., as representative of the several initial purchasers named therein (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (File No. 001-35364) filed on July 15, 2014).

10.2	—	Seventh Amendment to Credit Agreement, dated as of June 13, 2014, by and among Memorial Production Partners LP, Memorial Production Operating LLC, Wells Fargo Bank, National Association, as administrative agent for the lenders party thereto, JPMorgan Chase Bank, N.A., as syndication agent for the lenders party thereto, Royal Bank of Canada, The Royal Bank of Scotland plc, Union Bank, N.A. and Comerica Bank, as co-documentation agents for the lenders party thereto, and the other lenders party thereto (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K (File No. 001-35364) filed on June 19, 2014).

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 as an exhibit to this Quarterly Report on Form 10-Q.

** 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.

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: August 6, 2014	By:	/s/ Robert L. Stillwell, Jr.
	Name:	Robert L. Stillwell, Jr.
	Title:	Vice President, Finance of Memorial Production Partners GP LLC

Amplify Energy Corp - FORM 10-Q - August 6, 2014

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