Table of Contents

 

 

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10–Q

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

For the quarterly period ended March 31, 2012

OR

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

For the transition period from          to         .

Commission File Number: 001-35364

MEMORIAL PRODUCTION PARTNERS LP

(Exact name of registrant as specified in its charter)

 

Delaware		90-0726667
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
1301 McKinney Street, 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		¨
Non-accelerated filer		þ		(Do not check if a smaller reporting company)		Smaller reporting company		¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b–2 of the Exchange Act). Yes ¨  No þ

As of April 30, 2012, the registrant had 16,842,175 common units, 5,360,912 subordinated units and 22,222 general partner units outstanding.

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Table of Contents

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 Balance Sheets as of March 31, 2012 and December 31, 2011		9
		Unaudited Condensed Statements of Consolidated and Predecessor Combined Operations for the Three Months Ended March 31, 2012 and 2011		10
		Unaudited Condensed Statements of Consolidated and Predecessor Combined Cash Flows for the Three Months Ended March 31, 2012 and 2011		11
		Unaudited Condensed Statements of Consolidated Equity for the Three Months Ended March 31, 2012		12
		Notes to Unaudited Condensed Consolidated and Predecessor Combined Financial Statements
		Note 1 – Organization and Basis of Presentation		13
		Note 2 – New Accounting Pronouncements		15
		Note 3 – Acquisitions and Divestitures		15
		Note 4 – Fair Value Measurements of Financial Instruments		16
		Note 5 – Risk Management and Derivative Instruments		17
		Note 6 – Asset Retirement Obligations		21
		Note 7 – Long Term Debt		22
		Note 8 – Equity & Distributions		22
		Note 9 – Earnings per Unit		23
		Note 10 – Equity-based Awards		23
		Note 11 – Related Party Transactions		24
		Note 12 – Commitments and Contingencies		25
		Note 13 – Subsequent Events		25
Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations.		26
Item 3.		Quantitative and Qualitative Disclosures About Market Risk.		38
Item 4.		Controls and Procedures.		39
		PART II—OTHER INFORMATION
Item 1.		Legal Proceedings.		40
Item 1A.		Risk Factors.		40
Item 2.		Unregistered Sales of Equity Securities and Use of Proceeds.		40
Item 3.		Defaults Upon Senior Securities.		40
Item 4.		Mine Safety Disclosures.		40
Item 5.		Other Information.		40
Item 6.		Exhibits.		41
Signatures				42

 

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GLOSSARY OF OIL AND NATURAL GAS TERMS

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

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

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

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

Bbl/d: One Bbl per day.

Bcf: One billion cubic feet of natural gas.

Bcfe: One billion cubic feet of natural gas equivalent.

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

Boe/d: One Boe per day.

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

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

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

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

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

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

Dry Hole or Dry Well: A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production expenses and taxes.

 

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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.

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 working interest.

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.

 

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NYMEX: New York Mercantile Exchange.

Oil: Oil and condensate and natural gas liquids.

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.

 

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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 based on annualized fourth quarter production and 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.

 

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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.

 

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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 collectively to Memorial Production Partners LP and its subsidiaries;

 

•

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

 

•

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

 

•

“our predecessor” refers collectively to (a) BlueStone Natural Resources Holdings, LLC and its wholly-owned subsidiaries, (b) certain oil and natural gas properties owned by Classic Hydrocarbons Holdings, L.P. (“Classic”), and (c) for periods after April 8, 2011, certain oil and natural gas properties owned by WHT Energy Partners LLC, a subsidiary of Memorial Resource that acquired those properties in April 2011, all of which are collectively our predecessor for accounting purposes and the owners, prior to the formation transactions;

 

•

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

 

•

“formation transactions” refers to (i) the contribution by the Funds of their respective controlling ownership interests in certain of their subsidiaries (including our predecessor) to Memorial Resource prior to the closing of our initial public offering and (ii) the contribution by Memorial Resource to us of our properties (including the contribution to us of Columbus Energy, LLC (“Columbus”), a wholly-owned subsidiary of BlueStone Natural Resources Holdings, LLC, and ETX I LLC (“ETX”), a wholly-owned subsidiary of WHT Energy Partners LLC, each of which owned certain of our properties);

 

•

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

 

•

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

 

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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;

 

•

availability of drilling and production equipment;

 

•

availability of oil field labor;

 

•

capital expenditures;

 

•

availability and terms of capital;

 

•

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 developments in oil-producing and natural-gas producing countries; and

 

•

plans, objectives, expectations and intentions.

These types of statements, other than statements of historical fact included in this report, are forward-looking statements. In some cases, you can identify forward-looking statements by terminology such as “may,” “will,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” the negative of such terms or other comparable terminology. These statements discuss future expectations, contain projections of results of operations or of financial condition or state other “forward-looking” information. These statements also involve risks and uncertainties that could cause our actual results or financial condition to materially differ from our expectations as expressed in this Form 10-Q including, but not limited to:

 

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•

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 estimating our reserves;

 

•

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

 

•

cash flows and liquidity;

 

•

potential shortages of drilling and production equipment;

 

•

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

 

•

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

 

•

competition in the oil and natural gas industry;

 

•

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

 

•

legislation and governmental regulations, including climate change legislation;

 

•

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

 

•

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, 2011 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.

 

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PART I—FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS.

MEMORIAL PRODUCTION PARTNERS LP

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except outstanding units)

 

		March 31,				December 31,
		2012				2011
ASSETS
Current assets:
Cash and cash equivalents		$	8,318			$	1,088
Accounts receivable:
Oil and natural gas sales			8,062				--
Joint interest owners and other			488				--
Affiliates			1,344				2,955
Short-term derivative instruments			27,389				21,140
Prepaid expenses and other current assets			1,564				1,831
Total current assets			47,165				27,014
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method			506,875				496,818
Accumulated depreciation, depletion and impairment			(102,316)				(96,156)
Oil and natural gas properties, net			404,559				400,662
Long-term derivatives			20,388				12,206
Other long –term assets			1,896				2,012
Total assets		$	474,008			$	441,894
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable		$	3,431			$	--
Accounts payable – affiliates			1,327				1,024
Accrued liabilities			11,131				2,032
Short-term derivative instruments			724				346
Total current liabilities			16,613				3,402
Long-term debt			120,000				120,000
Asset retirement obligations			13,892				13,614
Long-term derivative instruments			417				1,040
Other long-term liabilities			824				670
Total liabilities			151,746				138,726
Commitments and contingencies (Note 12)
Partners’ equity:
Limited partners:
Common units (16,842,175 units outstanding at March 31, 2012 and 16,661,294 units outstanding at December 31, 2011)			255,566				241,034
Subordinated units (5,360,912 units outstanding at March 31, 2012 and December 31, 2011)			66,251				61,708
General partner (22,222 units outstanding at March 31, 2012 and 22,044 units outstanding at December 31, 2011)			445				426
Total partners’ equity			322,262				303,168
Total liabilities and partners’ equity		$	474,008			$	441,894

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

 

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MEMORIAL PRODUCTION PARTNERS LP

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED AND PREDECESSOR COMBINED OPERATIONS

UNAUDITED CONDENSED STATEMENTS OF

CONSOLIDATED AND PREDECESSOR COMBINED OPERATIONS

(In thousands, except per unit amounts)

 

		For the Three Months Ended March 31,
		2012				2011
						(Predecessor)
Revenues:
Oil & natural gas sales		$	16,546			$	11,590
Other income			110				103
Total revenues		$	16,656			$	11,693
Costs and expenses:
Lease operating			5,524				4,244
Production and ad valorem taxes			1,688				1,214
Depreciation, depletion, and amortization			6,160				4,450
General and administrative			2,018				1,474
Accretion of asset retirement obligations			278				210
Realized gain on commodity derivative instruments			(6,491)				(1,367)
Unrealized (gain) loss on commodity derivative instruments			(14,980)				2,070
Gain on sale of properties			--				(8)
Other, net			57				354
Total costs and expenses			(5,746)				12,641
Operating income (loss)			22,402				(948)
Interest expense			(1,325)				(1,035)
Income (loss) before income taxes			21,077				(1,983)
Income tax expense			(183)				--
Net income (loss)			20,894				(1,983)
Net loss attributable to predecessor			--				(1,983)
Net income attributable to partners		$	20,894			$	--
Allocation of net income attributable to partners:
Limited partners		$	20,873			$	--
General partner		$	21			$	--
Earnings per unit: (Note 9)
Basic and diluted earnings per unit		$	0.94			$	--
Weighted average limited partner units outstanding:
Basic and diluted			22,185				--

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

 

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MEMORIAL PRODUCTION PARTNERS LP

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED AND PREDECESSOR COMBINED CASH FLOWS

UNAUDITED CONDENSED STATEMENTS OF

CONSOLIDATED AND PREDECESSOR COMBINED CASH FLOWS

(In thousands)

 

		For the Three Months Ended March 31,
		2012				2011
						(Predecessor)
Cash flows from operating activities
Net income (loss)		$	20,894			$	(1,983)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization			6,160				4,450
Unrealized (gain) loss on derivatives			(14,718)				1,898
Deferred income tax expense			183				--
Amortization of loan origination costs			129				85
Accretion of asset retirement obligations			278				210
Amortization of equity awards			248
Gain on sale of properties			--				(8)
Changes in operating assets and liabilities:
Accounts receivable			(8,550)				357
Accounts receivable - affiliates			1,611				--
Prepaid expenses and other assets			272				(100)
Accounts payable			3,431				(1,879)
Accounts payable - affiliates			303				--
Accrued liabilities			3,610				(25)
Other			40				(6)
Net cash provided by operating activities			13,891				2,999
Cash flows from investing activities:
Acquisition of oil and natural gas properties			--				(1,650)
Additions to oil and gas properties			(4,596)				(6,021)
Additions to other property and equipment			--				(227)
Net cash used in investing activities			(4,596)				(7,898)
Cash flows from financing activities:
Advances on revolving credit facility - Predecessor			--				47
Payments on revolving credit facility - Predecessor			--				(2,893)
Loan origination fees – Partnership			(17)				--
Distributions to partners			(2,048)				--
Predecessor capital contributions			--				4,221
Net cash provided by financing activities			(2,065)				1,375
Net change in cash and cash equivalents			7,230				(3,524)
Cash and cash equivalents, beginning of period			1,088				5,654
Cash and cash equivalents, end of period		$	8,318			$	2,130
Supplemental cash flows:
Cash paid for interest		$	957			$	987
Additions to oil and gas properties - capital accruals		$	5,461			$	--

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

 

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MEMORIAL PRODUCTION PARTNERS LP

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED EQUITY

(In thousands)

 

		Limited Partners
		Common				Subordinated				General Partner				Total
Balance December 31, 2011		$	241,034			$	61,708			$	426			$	303,168
Net income			15,832				5,041				21				20,894
Amortization of equity awards			248				--				--				248
Distributions to partners			(1,548)				(498)				(2)				(2,048)
Balance March 31, 2012		$	255,566			$	66,251			$	445			$	322,262

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

 

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

AND PREDECESSOR 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.

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 our wholly owned subsidiary Memorial Production Operating LLC (“OLLC”), and its wholly-owned subsidiaries. Our properties are located in Texas and Louisiana and consist of mature, legacy onshore oil and natural gas reservoirs. The Partnership’s properties consist of operated working interests in producing and undeveloped leasehold acreage and in identified producing wells and non-operated working interests in producing and undeveloped leasehold acreage.

The Partnership was formed in April 2011 to own and acquire 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, Memorial Production Partners GP LLC, which is a wholly owned subsidiary of Memorial Resource Development LLC (“Memorial Resource”). Our general partner is responsible for managing all of the Partnership’s operations and activities.

Memorial Resource is a Delaware limited liability company owned and formed by Natural Gas Partners VIII, L.P. (“NGP VIII”), Natural Gas Partners IX, L.P. (“NGP IX”) and NGP IX Offshore Holdings, L.P. (“NGP IX Offshore”) (collectively, the “Funds”) to own, acquire, exploit and develop oil and natural gas properties and to own our general partner. Memorial Resource provides management, administrative, and operations personnel to us and our general partner under an omnibus agreement (see Note 11). The Funds are private equity funds managed by Natural Gas Partners (“NGP”). The Funds collectively directly own, through non-voting membership interests in our general partner, 50% of the economic interest in our incentive distribution rights (“IDRs”). The remaining economic interest in our IDRs is owned by our general partner.

On December 14, 2011, the Partnership completed its initial public offering (“IPO”) of 9,000,000 common units at a price of $19.00 per unit, which generated net proceeds to the Partnership of approximately $146.5 million after deducting underwriting discounts, structuring fees and other offering and formation-related fees. In connection with the closing of the IPO, the Partnership acquired for a combination of cash, common units, and subordinated units (1) substantially all of the oil and natural gas properties and related assets owned by BlueStone Natural Resources Holdings, LLC, a majority-controlled subsidiary of Memorial Resource, (2) certain oil and natural gas properties and related assets owned by Classic Hydrocarbons Holdings, L.P. (“Classic”), a majority-controlled subsidiary of Memorial Resource, and (3) a 40% undivided interest in certain oil and natural gas properties and related assets (the “WHT Assets”) controlled by WHT Energy Partners LLC (“WHT”), which is 50% owned by WildHorse Resources, LLC (“WildHorse”) and 50% owned by Tanos Energy, LLC (“Tanos”), both of which are majority-controlled subsidiaries of Memorial Resource.

We distributed approximately $73.6 million in cash, 7,061,294 common units, and 5,360,912 subordinated units to Memorial Resource to acquire the net assets of our predecessor and repaid $198.3 million of our predecessor’s credit facilities concurrent with the closing of our IPO. The cash portion of this consideration was financed with approximately $130.0 million in borrowings under a new senior secured revolving credit facility (see Note 7) and the net cash proceeds generated from our IPO. This dropdown transaction was accounted for as a combination of entities under common control; therefore, the Partnership accounted for the acquisition at historical cost in a manner similar to the pooling of interest method. Due to the timing of our IPO and the fact that we did not acquire working capital from our predecessor, our consolidated balance sheet as of December 31, 2011 did not include any trade receivables or payables.

On December 22, 2011, the underwriters exercised a portion of their over-allotment option, purchasing an additional 600,000 common units issued by the Partnership, which generated net proceeds to the Partnership of approximately $10.7 million. Of this amount, $10.0 million was used to repay indebtedness under our revolving credit facility.

 

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

 

Predecessor

The Partnership did not own any assets prior to December 14, 2011. The business and operations of the Partnership prior to December 14, 2011 are referred to as “our predecessor.” The following entities are included in the historical combined financial statements of our predecessor: (i) BlueStone Natural Resources Holdings, LLC (“Bluestone”) and its wholly-owned subsidiaries, (ii) certain carved-out oil and natural gas properties (“Classic Carve-Out”) owned by Classic, and (iii) for periods after April 8, 2011, certain oil and natural gas properties owned by WHT, which are collectively our predecessor for accounting and financial reporting purposes, prior to the closing of our IPO. Our predecessor was determined in accordance with the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”).

BlueStone was formed in January 2006 to engage in the acquisition, development, production and exploration and sale of oil and natural gas. BlueStone’s assets include oil and natural gas producing properties located in Texas. Prior to our IPO, Memorial Resource owned an 89.45% interest in BlueStone and certain members of BlueStone’s management owned a 10.55% interest.

Classic was formed in 2006 to engage in the exploration, development, production, and sale of oil and natural gas primarily in East Texas. Prior to our IPO, Memorial Resource owned a 90.21% limited partner interest in Classic and an 83.33% membership interest in the general partner of Classic. The Classic Carve-Out financial statements include the applicable amounts of Craton Energy Holdings III, LP (“Craton”), which was contributed to Classic by one of the Funds in 2009. This contribution was accounted for as a combination of entities under common control; therefore, Classic accounted for the acquisition in a manner similar to the pooling of interest method. Information included in these financial statements is presented as if Craton had been combined throughout the periods presented in which common control existed.

The WHT Assets were acquired on April 8, 2011 from a third party; therefore, the results of operations (proportionally consolidated) were not included in the financial statements for the three months ended March 31, 2011. Prior to April 8, 2011, WHT did not have any oil and natural gas assets.

Our predecessor operated oil and natural gas properties as one business segment: the exploration, development and production of oil and natural gas. Our predecessor’s management evaluated performance based on one business segment as there were not different economic environments within the operation of the oil and natural gas properties.

Basis of Presentation

Our predecessor combined financial statements were derived from the historical accounting records of our predecessor and reflect the historical financial position, results of operations and cash flows for periods prior to our IPO. As common control existed among our predecessor entities, our predecessor’s combined financial statements for the three months ended March 31, 2011 reflect the financial statements of BlueStone and Classic Carve-Out on a combined basis.

The Classic Carve-Out amounts included in the accompanying financial statements were determined in accordance with SEC regulations and guidance. Certain expenses incurred by Classic are only indirectly attributable to its ownership of Classic Carve-Out as Classic owns interests in numerous other oil and natural gas properties. As a result, certain assumptions and estimates were made in order to allocate a reasonable share of such expenses to our predecessor, so that the amounts included in the predecessor combined financial statements reflect substantially all of the cost of doing business. Such allocations may or may not reflect future costs associated with the operation of the Partnership.

Our results of operations for the three months ended March 31, 2012 are not necessarily indicative of results expected for the full year. In our opinion, the accompanying unaudited condensed consolidated and predecessor 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 SEC. These unaudited condensed consolidated and predecessor combined financial statements and the notes thereto should be read in conjunction with the audited consolidated and predecessor combined financial statements and notes thereto included in our annual report on Form 10-K for the year ended December 31, 2011 (the “2011 Form 10-K”).

 

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

 

All material intercompany transactions and balances have been eliminated in preparation of our consolidated and predecessor combined financial statements. Certain amounts in the prior year financial statements have been reclassified to conform with the presentation in the current year financial statements.

Use of Estimates

The preparation of the accompanying unaudited condensed consolidated and predecessor 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 combined financial statements 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. New Accounting Pronouncements

In May 2011, the Financial Accounting Standards Board (“FASB”) issued an accounting standard update that amended previous fair value measurement and disclosure guidance. These amendments generally involve clarifications on how to measure and disclose fair value amounts recognized in the financial statements. They also expand the disclosure requirements, particularly for Level 3 fair value measurements, to include a description of the valuation processes used and an analysis of the sensitivity of the fair value measurements to changes in unobservable inputs and the interrelationships between those unobservable inputs, if any. The Partnership adopted this amendment on January 1, 2012. The amendment did not have a material impact on our financial position, results of operations, cash flows or notes to the financial statements.

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

Note 3. Acquisitions and Divestitures

There were no acquisitions or divestures during the three months ended March 31, 2012. Our predecessor acquired interests in oil and gas properties, including acreage, in a number of individually insignificant acquisitions during the three months ended March 31, 2011 which aggregated to a total of approximately $1.7 million. These acquisitions were accounted for under the acquisition method of accounting. Accordingly, our predecessor conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while less than $0.1 million of acquisition costs associated with these acquisitions were expensed as incurred and included in other expense in the accompanying statements of operations for the three months ended March 31, 2011. The operating revenues and expenses of acquired properties are included in the accompanying financial statements from their respective closing dates forward. The transactions were financed through capital contributions and borrowings under credit facilities.

The fair values of oil and natural gas properties are measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital.

See Note 13 for further information regarding the acquisitions of oil and gas properties from Memorial Resource in April and May 2012 and from an undisclosed third party seller in May 2012. Approximately $0.1 million of acquisition-related costs is included in general and administrative expense in the accompanying statements of operations for the three months ended March 31, 2012 in connection with the acquisition that closed in April 2012.

 

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

 

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). The characteristics of fair value amounts classified within each level of the hierarchy are described as follows:

Level 1 — Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. An active market is one in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 — Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. Level 2 instruments primarily include non-exchange-traded derivatives, such as over-the-counter commodity price swaps, collars, put options and interest rate swaps. At March 31, 2012 and December 31, 2011, all of the derivative instruments reflected on the accompanying balance sheets were considered Level 2.

Level 3 — Measure based on prices or valuation models that require inputs that are both significant to the fair value measurement and are less observable from objective sources (i.e., supported by little or no market activity).

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The carrying values of cash and cash equivalents, accounts receivables, accounts payables (including accrued liabilities) and amounts outstanding under long-term debt agreements included in the accompanying balance sheets approximated fair value at March 31, 2012 and December 31, 2011. The fair value estimates are based upon observable market data and are classified within Level 2 of the fair value heirarchy. These assets and liabilities are not presented in the following tables.

The fair market values of the derivative financial instruments reflected in the balance sheets as of March 31, 2012 and December 31, 2011 were based on estimated forward commodity prices and forward interest rate yield curves. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement in its entirety. The significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The following table presents the derivative assets and liabilities that are measured at fair value on a recurring basis at March 31, 2012 and December 31, 2011 for each of the fair value hierarchy levels:

 

		Fair Value Measurements at March 31, 2012 Using
		Quoted Prices in     Active Market (Level 1)				Significant Other   Observable Inputs   (Level 2)				Significant Unobservable Inputs (Level 3)				Fair Value
		(In thousands)
Assets:
Commodity derivatives		$	--			$	52,303			$	--			$	52,303
Liabilities :
Commodity derivatives		$	--			$	5,127			$	--			$	5,127
Interest rate derivatives			--				540				--				540
Total liabilities		$	--			$	5,667			$	--			$	5,667

 

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

 

 

		Fair Value Measurements at December 31, 2011 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		$	--			$	35,829			$	--			$	35,829
Liabilities :
Commodity derivatives		$	--			$	3,591			$	--			$	3,591
Interest rate derivatives			--				278				--				278
Total liabilities		$	--			$	3,869			$	--			$	3,869

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 such factors as the existence of a legal obligation for an ARO; amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. See Note 6 for a summary of changes in ARO’s.

 

•

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 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.

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 transactions limit exposure to declines in prices or increases in interest rates, but also limit the benefits that would be realized if prices increase or interest rates decrease.

Certain inherent business risks are associated with commodity and interest derivative contracts, including market risk and credit risk. Market risk is the risk that the price of natural gas or oil will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the counterparty to a contract. It is our policy to enter into derivative contracts, including interest rate swaps, only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. Each of the counterparties to our derivative contracts is a lender in our credit agreement. While collateral is generally not required to be posted by counterparties, credit risk associated with derivative instruments is minimized by limiting exposure to any single counterparty and entering into derivative instruments only with counterparties that are large financial institutions, which management believes present minimal credit risk. 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. Had our counterparties failed to perform under existing commodity derivative contracts, the maximum loss at March 31, 2012 would be approximately $47.2 million, of which $28.8 million was with a single counterparty.

 

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

 

Commodity Derivatives

A combination of commodity derivatives (e.g., floating-for-fixed swaps, collars, put options, call spreads, and basis swaps) is used to manage exposure to commodity price volatility. At March 31, 2012, we had the following open commodity positions:

 

Natural Gas — Swaps
Period Covered				Index		Average Monthly Volume (MMBtu)		Weighted Average       Fixed Price ($)
4/1/2012		12/31/2012		Houston Ship Channel		80,000		4.84
4/1/2012		12/31/2012		NGPL TXOK		32,000		6.34
4/1/2012		12/31/2012		NYMEX (Henry Hub)		280,979		4.13
4/1/2012		12/31/2012		TETCO STX		60,000		5.51
1/1/2013		12/31/2013		Houston Ship Channel		80,000		4.84
1/1/2013		12/31/2013		NGPL TXOK		21,000		6.58
1/1/2013		12/31/2013		NYMEX (Henry Hub)		314,172		4.14
1/1/2013		12/31/2013		TETCO STX		40,000		5.34
1/1/2014		12/31/2014		NYMEX (Henry Hub)		786,000		4.42
1/1/2015		12/31/2015		NYMEX (Henry Hub)		822,778		4.43
1/1/2016		12/31/2016		NYMEX (Henry Hub)		903,275		4.70

 

Natural Gas — Basis Swaps
Period Covered				Floating Index 1		Floating Index 2		Average Monthly Volume (MMBtu)		Spread ($)
4/1/2012		12/31/2012		NYMEX (Henry Hub)		NGPL TXOK		23,899		(0.1050)
4/1/2012		12/31/2012		NYMEX (Henry Hub)		TETCO STX		330,734		(0.1450)
1/1/2013		12/31/2013		NYMEX (Henry Hub)		NGPL TXOK		31,644		(0.1050)
1/1/2013		12/31/2013		NYMEX (Henry Hub)		TETCO STX		337,208		(0.1650)
1/1/2013		12/31/2013		NYMEX (Henry Hub		Houston Ship Channel		37,080		(0.1075)

 

Natural Gas — Collars
Period Covered				Index		Average Monthly Volume (MMBtu)		Weighted Average Floor Price ($)		Weighted Average       Ceiling Price ($)
4/1/2012		12/31/2012		Houston Ship Channel		140,000		4.28		5.65
4/1/2012		12/31/2012		NGPL TXOK		75,000		5.49		6.57
4/1/2012		12/31/2012		NYMEX (Henry Hub)		203,000		4.99		5.75
4/1/2012		12/31/2012		TETCO STX		200,000		4.68		6.03
1/1/2013		12/31/2013		Houston Ship Channel		95,000		4.23		5.68
1/1/2013		12/31/2013		NGPL TXOK		69,000		4.87		6.15
1/1/2013		12/31/2013		NYMEX (Henry Hub		148,000		5.00		6.01
1/1/2013		12/31/2013		TETCO STX		280,000		4.76		5.70
1/1/2014		12/31/2014		NYMEX (Henry Hub)		120,000		5.08		6.31
1/1/2015		12/31/2015		NYMEX (Henry Hub)		80,000		5.25		6.75

 

Natural Gas — Call Spreads (1)
Period Covered				Index		Average Monthly Volume (MMBtu)		Weighted Average Sold Strike Price ($)		Weighted Average       Bought Strike   Price ($)
4/1/2012		12/31/2012		Houston Ship Channel		80,000		4.20		5.70
1/1/2013		12/31/2013		Houston Ship Channel		80,000		4.20		5.70
1/1/2013		12/31/2013		NGPL TXOK		30,000		4.40		5.55
1/1/2013		12/31/2013		NYMEX (Henry Hub)		120,000		5.00		6.09
1/1/2013		12/31/2013		TETCO STX		200,000		4.54		5.78
1/1/2014		12/31/2014		NYMEX (Henry Hub)		120,000		5.08		6.31
1/1/2015		12/31/2015		NYMEX (Henry Hub)		80,000		5.25		6.75
(1)        These transactions were entered into for the purpose of eliminating the ceiling portion of certain collar arrangements, which effectively converted the collars into swaps.

 

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

 

Natural Gas — Put Options
Period Covered				Index		Average Monthly Volume (MMBtu)		Strike Price ($)
4/1/2012		12/31/2012		TETCO STX		70,000		4.80

 

Oil — Collars
Period Covered				Index		Average Monthly Volume (Bbls)		Weighted Average Floor Price ($)		Weighted Average       Ceiling Price ($)
4/1/2012		12/31/2012		NYMEX WTI		4,500		86.67		115.12
1/1/2013		12/31/2013		NYMEX WTI		4,750		87.16		116.94
1/1/2014		12/31/2014		NYMEX WTI		3,200		90.00		117.72

 

Oil — Swaps
Period Covered				Index		Average Monthly Volume (Bbls)		Weighted Average       Fixed Price ($)
4/1/2012		12/31/2012		NYMEX WTI		2,947		95.42
1/1/2013		12/31/2013		NYMEX WTI		1,832		93.39
1/1/2014		12/31/2014		NYMEX WTI		3,352		90.55
1/1/2015		12/31/2015		NYMEX WTI		6,531		91.36
1/1/2016		12/31/2016		NYMEX WTI		6,531		91.36

 

Natural Gas Liquids (“NGL”) — Collars

Period Covered

Product

Index

Average Monthly Volume (Bbls)

Weighted Average Floor Price ($)

Weighted Average       Ceiling Price ($)

4/1/2012

12/31/2012

Propane

OPIS Mt. Belvieu

1,200

52.50

66.78

4/1/2012

12/31/2012

Normal Butane

OPIS Mt. Belvieu

600

71.40

86.10

4/1/2012

12/31/2012

Iso-Butane

OPIS Mt. Belvieu

400

71.40

89.04

4/1/2012

12/31/2012

Pentane

OPIS Mt. Belvieu

1,600

94.50

117.60

 

NGL — Swaps
Period Covered				Product		Index		Average Monthly Volume (Bbls)		Weighted Average       Fixed Price ($)
4/1/2012		12/31/2012		Propane		OPIS Mt. Belvieu		1,195		53.24
4/1/2012		12/31/2012		Normal Butane		OPIS Mt. Belvieu		362		73.48
4/1/2012		12/31/2012		Iso-Butane		OPIS Mt. Belvieu		347		76.03
4/1/2012		12/31/2012		Pentane		OPIS Mt. Belvieu		345		93.97
1/1/2013		12/31/2013		Propane		OPIS Mt. Belvieu		2,189		53.24
1/1/2013		12/31/2013		Normal Butane		OPIS Mt. Belvieu		880		73.48
1/1/2013		12/31/2013		Iso-Butane		OPIS Mt. Belvieu		683		76.03
1/1/2013		12/31/2013		Pentane		OPIS Mt. Belvieu		1,973		93.97

Our acquisition of oil and gas properties from Memorial Resource in April 2012 included the novation of 2012 through 2013 commodity derivative positions to the Partnership. See Note 13 for additional information regarding this acquisition. The following table reflects the notional volumes and the weighted-average hedge prices related to this novation:

 

Natural Gas — Collars
Period Covered				Index		Average Monthly Volume (MMBtu)		Weighted Average Floor Price ($)		Weighted Average       Ceiling Price ($)
4/1/2012		12/31/2012		NYMEX (Henry Hub)		45,000		4.25		4.98
1/1/2013		12/31/2013		NYMEX (Henry Hub)		41,000		4.75		5.78

Our acquisition of oil and gas properties from Memorial Resource in May 2012 included the novation of 2012 through 2014 commodity derivative positions to the Partnership. See Note 13 for additional information regarding this acquisition. The following table reflects the notional volumes and the weighted-average hedge prices related to this novation:

 

Natural Gas — Swaps
Period Covered				Index		Average Monthly Volume (MMBtu)		Weighted Average       Fixed Price ($)
4/1/2012		12/31/2012		NGPL TXOK		30,000		6.97
1/1/2013		12/31/2013		NGPL TXOK		30,000		6.58
1/1/2014		12/31/2014		NYMEX (Henry Hub)		30,000		4.40

 

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

 

Subsequent to March 31, 2012 and consistent with our hedging policy, we executed additional commodity price hedges on a portion of our expected oil and natural gas volumes as follows:

 

Oil — Swaps
Period Covered				Index		Average Monthly Volume (Bbls)		Weighted Average       Fixed Price ($)
6/1/2012		12/31/2012		NYMEX WTI		1,800		103.90
1/1/2013		12/31/2013		NYMEX WTI		2,800		103.54

 

Natural Gas — Swaps
Period Covered				Index		Average Monthly Volume (MMBtu)		Weighted Average       Fixed Price ($)
6/1/2012		12/31/2012		NYMEX (Henry Hub)		90,000		3.69
1/1/2013		12/31/2013		NYMEX (Henry Hub)		165,000		3.69
1/1/2014		12/31/2014		NYMEX (Henry Hub)		257,375		4.22
1/1/2015		12/31/2015		NYMEX (Henry Hub)		175,000		3.69
1/1/2016		12/31/2016		NYMEX (Henry Hub)		90,000		3.69
1/1/2016		5/31/2017		NYMEX (Henry Hub)		757,160		4.27

Interest Rate Swaps

Periodically, we enter into interest rate swaps to mitigate exposure to market rate fluctuations by converting variable interest rates such as those in our credit agreement to fixed interest rates. At March 31, 2012, we had the following fixed-for floating interest rate swap open positions whereby we receive the floating rate and pay the fixed rate:

 

Period Covered

Notional     ($ in thousands)

Floating Rate

Fixed Rate

1/17/2012

1/16/2013

$

100,000

1 Month LIBOR

0.600%

1/17/2013

12/14/2016

$

100,000

1 Month LIBOR

1.305%

In May 2012, we added the following fixed-for floating interest rate swap open positions:

Period Covered

Notional ($ in thousands)

Floating Rate

Fixed Rate

5/17/2012

1/17/2013

$

50,000

1 Month LIBOR

0.600%

1/17/2013

12/14/2016

$

50,000

1 Month LIBOR

0.970%

In June 2010, our predecessor entered into an interest rate swap agreement in order to mitigate its exposure to interest rate fluctuations. Under this swap agreement, our predecessor received the current 1-month LIBOR and paid a fixed rate of 1.00% on a notional amount of $50.0 million. The effective date of the swap was from June 2010 to June 2012 and was not acquired by the partnership at its IPO in December 2011. In 2009, our predecessor entered into two interest rate swap agreements in order to mitigate its exposure to interest rate fluctuations. Under these swap agreements, our predecessor paid 1.62% and received the current 3-month LIBOR rate per month on a notional amount of $6.7 million and $1.7 million, respectively. The effective dates of the swaps were from February 2009 to February 2011.

None of the interest rate swaps are designated as hedges for financial accounting purposes. All gains and losses, including unrealized gains and losses related to the change in the interest rate swaps fair value, have been recorded in interest expense, net in the statements of operations for all periods presented.

 

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

 

Balance Sheet Presentation

The following table summarizes both: (i) the gross fair value of derivative instruments by the appropriate balance sheet classification even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the balance sheet and (ii) the net recorded fair value as reflected on the balance sheet at March 31, 2012 and December 31, 2011:

 

				Asset Derivatives								Liability Derivatives
				March 31,				December 31,				March 31,				December 31,
Type		Balance Sheet Location		2012				2011				2012				2011
				(In thousands)
Natural gas contracts		Short-term derivative instruments		$	27,958			$	21,001			$	261			$	44
Oil contracts		Short-term derivative instruments			85				83				597				250
NGL contracts		Short-term derivative instruments			105				166				198				--
Interest rate swaps		Short-term derivative instruments			--				--				427				162
Gross fair value					28,148				21,250				1,483				456
Netting arrangements		Short-term derivative instruments			(759)				(110)				(759)				(110)
Net recorded fair value		Short-term derivative instruments		$	27,389			$	21,140			$	724			$	346
Natural gas contracts		Long-term derivative instruments		$	23,566			$	14,147			$	2,455			$	3,034
Oil contracts		Long-term derivative instruments			589				432				1,518				263
NGL contracts		Long-term derivative instruments			--				--				98				--
Interest rate swaps		Long-term derivative instruments			--				--				113				116
Gross fair value					24,155				14,579				4,184				3,413
Netting arrangements		Long-term derivative instruments			(3,767)				(2,373)				(3,767)				(2,373)
Net recorded fair value		Long-term derivative instruments		$	20,388			$	12,206			$	417			$	1,040

(Gains) Losses on Derivatives

We do not designate derivative instruments as hedging instruments for financial reporting purposes and neither did our predecessor. Accordingly, all gains and losses, including unrealized gains and losses from changes in the derivative instruments’ fair values, have been recorded in the accompanying statements of operations. The following table details the unrealized and realized gains and losses related to derivative instruments for the three months ended March 31, 2012 and 2011:

 

				Three Months Ended March 31,
		Statements of Operations Location		2012				2011
Commodity derivative contracts		Realized (gain) loss on commodity derivatives		$	(6,491)			$	(1,367)
Commodity derivative contracts		Unrealized (gain) loss on commodity derivatives			(14,980)				2,070
Interest rate swaps (1)		Interest expense			320				53

 

		(1)        Included in the amounts are net cash payments of approximately $0.1 million for both the three months ended March 31, 2012 and 2011.

Note 6. Asset Retirement Obligations

We recognize the fair value of asset retirement obligations related to the plugging, abandonment, and remediation activities of oil and gas producing properties in the period in which it is incurred, with the associated asset retirement cost capitalized as part of the carrying cost of the related long-lived assets. The following table represents information regarding our asset retirement obligations since December 31, 2011 (in thousands):

 

Asset retirement obligations at beginning of period		$	13,614
Accretion expense			278
Asset retirement obligations at end of period		$	13,892

 

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

 

Note 7.  Long Term Debt

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

 

		March 31,				December 31,
		2012				2011
		(In thousands)
$1.0 billion multi-year revolving credit facility, variable –rate, due December 2016		$	120,000			$	120,000

This revolving credit facility is guaranteed by us and all of our current and future subsidiaries with an initial borrowing base of $300.0 million. As of March 31, 2102, available borrowing capacity under this revolving credit facility is $180.0 million. The effective weighted average interest rate for the three months ended March 31, 2012 was 2.9%. We were in compliance with the financial covenants of our consolidated debt agreements at March 31, 2012.

In connection with the April 2012 scheduled borrowing base redetermination under the Partnership’s revolving credit facility, the Partnership’s borrowing base remained at $300.0 million.

In April and May 2012, we borrowed $84.0 million to fund the acquisitions of oil and gas properties as further discussed in Note 13 and for other general partnership purposes. As of May 15, 2012, our outstanding borrowings under our revolving credit facility were $204.0 million.

Note 8. Equity & Distributions

Equity Outstanding

The following table summarizes changes in the number of outstanding units since December 31, 2011:

 

		Common				Subordinated				General        Partner
Balance December 31, 2011			16,661,294				5,360,912				22,044
Restricted common units issued			180,881				--				--
General partner units issued			--				--				178
Balance March 31, 2012			16,842,175				5,360,912				22,222

Restricted common units are a component of common units as presented on our unaudited condensed consolidated balance sheets. See Note 10 for additional information regarding restricted common units that were granted to our general partner’s executive officers and independent directors during the three months ended March 31, 2012.

Cash Distributions to Unitholders

On January 26, 2012, the board of directors of our general partner (the “Board”) declared a quarterly cash distribution for the fourth quarter of 2011 of $0.0929 per unit. The distribution represented a proration of our minimum quarterly distribution of $0.4750 per unit for the period from December 14, 2011 through December 31, 2011. The aggregate distribution of $2.0 million, of which Memorial Resource received $1.2 million, was paid on February 13, 2012 to unitholders of record as of the close of business on February 6, 2012, except for the holders of 177,370 restricted common units that were granted to our general partner’s executive officers and independent director on January 9, 2012 (see Note 10).

On April 19, 2012, the Board declared a quarterly cash distribution for the first quarter of 2012 of $0.48 per unit. The aggregate distribution of $10.7 million, of which Memorial Resource received $6.0 million, was paid on May 14, 2012 to unitholders of record as of the close of business on May 1, 2012.

 

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

 

Note 9.  Earnings per Unit

The following sets forth the calculation of earnings per unit, or EPU, for the three months ended March 31, 2012 (in thousands, except per unit amounts):

 

Net income attributable to partners		$	20,894
Less: General partner’s 0.1% interest in net income			21
Limited partners’ interest in net income		$	20,873
Weighted average limited partner units outstanding:
Common units			16,824
Subordinated units			5,361
Total			22,185
Basic and diluted EPU		$	0.94

Note 10. Equity-based Awards

Long-Term Incentive Plan

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

In January 2012, an aggregate of 177,370 restricted common units were granted under the LTIP to our general partner’s executive officers and an independent director of our general partner. In March 2012, the Board granted an award of 3,511 restricted common units under the LTIP to a newly appointed independent director, Mr. P. Michael Highum. The restricted common units awarded are subject to restrictions on transferability, customary forfeiture provisions and graded vesting provisions in which one-third of each award vests on the first, second, and third anniversaries of the date of grant. Award recipients have all the rights of a unitholder in the partnership with respect to the restricted common units, including the right to receive distributions thereon if and when distributions are made by the Partnership to its unitholders (except with respect to the fourth quarter 2011 distribution that was paid in February 2012). The term “restricted common unit” represents a time-vested unit. Such awards are non-vested until the required service period expires.

The fair value of the restricted common units awarded to our general partner’s executive officers was $3.2 million based on the market price per unit on the date of grant. This amount will be recognized as compensation cost on a straight-line basis over the requisite service period. Our general partner’s executive officers were granted these awards for both services they performed in connection with the completion of our IPO and to provide them with incentive to help drive the Partnership’s future success and to share in the economic benefits of that success. The compensation costs associated with these awards are recorded as direct general and administrative expenses. During the three months ended March 31, 2012, we recognized approximately $0.2 million of compensation expense associated with these awards.

The fair value of the restricted unit awards granted to the independent directors of our general partner is remeasured as of the end of each reporting period and will be recognized as compensation cost on a straight-line basis over the requisite service period. The compensation costs associated with these awards are recorded as direct general and administrative expenses. During the three months ended March 31, 2012, we recognized less than $0.1 million of compensation expense associated with these awards.

 

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

 

The following table summarizes information regarding restricted common unit awards for the periods presented:

 

		Number of Units				Weighted- Average Grant Date Fair Value per Unit (1)
Restricted common units outstanding at December 31, 2011			--			$	--
Granted (2)			180,881			$	18.58
Restricted common units outstanding at March 31, 2012			180,881			$	18.58
(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 2012 was $3.4 million based on grant date market prices of $18.58 and $18.52 per unit.

The unrecognized compensation cost associated with restricted common unit awards was an aggregate $3.1 million at March 31, 2012. We expect to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.9 years.

Since the restricted common units are participating securities, any distributions received by the restricted common unitholders are included in distributions to partners as presented on our unaudited condensed statements of consolidated and predecessor combined cash flows. No cash distributions were paid to the restricted common unitholders during the three months ended March 31, 2012. The restricted common unitholders received a distribution of approximately $0.1 million on May 14, 2012 with respect to the quarterly cash distribution for the first quarter of 2012 that the Board declared in April 2012.

Note 11. Related Party Transactions

The following table summarizes our related party receivable and payable amounts included in the accompanying balance sheets at March 31, 2012 and December 31, 2011 (in thousands):

 

		March 31,				December 31,
		2012				2011
Accounts Receivable/(Payable) – Affiliates:
Memorial Resource		$	(164)			$	377
BlueStone			1,344				2,142
Classic			(208)				436
WHT			(955)				(1,024)
Total		$	17			$	1,931

For the three months ended March 31, 2012, approximately $0.5 million of related party transactions are reflected in the accompanying statements of operations. For the comparable period in 2011, there was less than $0.1 million of related party transactions recognized in the accompanying statements of operations.

Agreements

Memorial Resource continues to provide management, administrative and operating services for us and our general partner pursuant to our omnibus agreement. In December 2011, Memorial Resource entered into agreements with affiliates on our behalf relating to the management, operation and administration of the properties acquired by us on December 14, 2011. We record approximately $0.1 million monthly for the management fees that Memorial Resource pays to its affiliates. The tax sharing agreement pursuant to which we pay Memorial Resource (or its applicable affiliate(s)) our share of state and local income and other taxes for which our results are included in a combined or consolidated tax return filed by Memorial Resource or its applicable affiliate(s) also remains in effect.

Acquisition of Oil & Gas Producing Properties

See Note 13 for information regarding our acquisition of oil and gas properties from Memorial Resource in April and May 2012.

 

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO UNAUDITED CONDENSED CONSOLIDATED

AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

 

Note 12. 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 both March 31, 2012 and December 31, 2011, we had $1.1 million of environmental reserves recorded on our balance sheets. At March 31, 2012 and December 31, 2011, $0.7 million and $0.8 million, respectively, of our environmental reserves were classified as current liabilities in accrued liabilities.

Note 13. Subsequent Events

Acquisition of Oil & Gas Properties – Common Control

On April 2, 2012, we acquired certain oil and natural gas producing properties in East Texas from an operating subsidiary of Memorial Resource with an effective date of April 1, 2012, for a purchase price of $18.5 million. This transaction was partially financed with $15.0 million of borrowings under our revolving credit facility. The transaction also included the novation to the Partnership of 2012 through 2013 commodity derivative positions. The transaction was approved by the Board and by its conflicts committee, which is comprised entirely of independent directors. These properties are located primarily in the Willow Springs field in Gregg County, as well as in Upshur, Rusk, Panola, Smith and Leon counties in East Texas. Memorial Resource will continue to operate 84% of the acquired properties and the remaining 16% will continue to be operated by third parties. Approximately 82% of the current net production of 2.3 MMcfe/d is natural gas and the remaining 18% is oil and NGLs. This acquisition will be accounted for as a combination of entities under common control at historical cost in a manner similar to the pooling of interest method.

On May 14, 2012, we acquired certain oil and natural gas producing properties in East Texas from an operating subsidiary of Memorial Resource with an effective date of April 1, 2012, for a purchase price of $27.0 million. This transaction was fully financed with borrowings under our revolving credit facility. The transaction also included the novation to the Partnership of 2012 through 2014 commodity derivative positions. The transaction was approved by the Board and by its conflicts committee, which is comprised entirely of independent directors. These properties are located primarily in the Cotton Valley and Travis Peak fields in Panola and Shelby counties in East Texas. Memorial Resource will continue to operate 55% of the acquired properties and the remaining 45% will continue to be operated by third parties. Approximately 81% of the current net production of 4.2 MMcfe/d is natural gas and the remaining 19% is oil and NGLs. This acquisition will be accounted for as a combination of entities under common control at historical cost in a manner similar to the pooling of interest method.

Acquisition of Oil & Gas Properties – Third Party

On May 1, 2012, we acquired an undivided 35% non-operating interest in certain oil and natural gas properties located in East Texas and an undivided 15% non-operating interest in certain oil and natural gas properties located in North Louisiana from an undisclosed seller for approximately $37.3 million, subject to customary post-closing adjustments. The effective date of this transaction was January 1, 2012. This transaction was partially financed with $35.0 million of borrowings under our revolving credit facility. The transaction was approved by the Board and by its conflicts committee, which is comprised entirely of independent directors. These properties are located primarily in Polk County, Texas and Lincoln and Claiborne Parishes, Louisiana. Memorial Resource will operate 75% of the acquired properties and the remaining 25% will be operated by third parties. Approximately 61% of the current net production of 3.5 MMcfe/d is natural gas and the remaining 39% is oil and NGLs. This acquisition will be accounted for as a business combination using the acquisition method of accounting. Given the recent nature of this transaction, we have not yet completed the related purchase price allocation.

 

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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, 2011 (the “2011 Form 10-K”). The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. See “Cautionary Note Regarding Forward-Looking Statements” in the front of this report.

Overview

We are a Delaware limited partnership formed in April 2011 by Memorial Resource to own and acquire 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 and our general partner have entered into an omnibus agreement with Memorial Resource pursuant to which Memorial Resource performs services for us and our general partner, including the operation of our properties.

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, Columbus and ETX. Our assets consist of oil and natural gas producing properties that are primarily located in South and East Texas.

Based on proved reserves volumes at December 31, 2011, we or Memorial Resource operate 94% of the properties in which we have interests, and we own an average working interest of 48% across our oil and natural gas properties. As of December 31, 2011, we had interests in 1,274 gross (590 net) producing wells across our properties, with an average working interest of 46%. As of December 31, 2011, we had estimated proved reserves of 324 Bcfe, of which approximately 79% were classified as proved developed reserves including approximately 13% classified as proved developed non-producing, and a standardized measure of $378.3 million.

Significant Current Developments

Acquisition of Oil & Gas Properties – Common Control

On April 2, 2012, we acquired certain oil and natural gas producing properties in East Texas from an operating subsidiary of Memorial Resource with an effective date of April 1, 2012, for a purchase price of $18.5 million. This transaction was partially financed with $15.0 million of borrowings under our revolving credit facility. The transaction also included the novation to the Partnership of 2012 through 2013 commodity derivative positions. The transaction was approved by the Board and by its conflicts committee, which is comprised entirely of independent directors. These properties are located primarily in the Willow Springs field in Gregg County, as well as in Upshur, Rusk, Panola, Smith and Leon counties in East Texas. Memorial Resource will continue to operate 84% of the acquired properties and the remaining 16% will continue to be operated by third parties. Approximately 82% of the current net production of 2.3 MMcfe/d is natural gas and the remaining 18% is oil and NGLs. This acquisition will be accounted for as a combination of entities under common control at historical cost in a manner similar to the pooling of interest method.

On May 14, 2012, we acquired certain oil and natural gas producing properties in East Texas from an operating subsidiary of Memorial Resource with an effective date of April 1, 2012, for a purchase price of $27.0 million. This transaction was fully financed with borrowings under our revolving credit facility. The transaction also included the novation to the Partnership of 2012 through 2014 commodity derivative positions. The transaction was approved by the Board and by its conflicts committee, which is comprised entirely of independent directors. These properties are located primarily in the Cotton Valley and Travis Peak fields in Panola and Shelby counties in East Texas. Memorial Resource will continue to operate 55% of the acquired properties and the remaining 45% will continue to be operated by third parties. Approximately 81% of the current net production of 4.2 MMcfe/d is natural gas and the remaining 19% is oil and NGLs. This acquisition will be accounted for as a combination of entities under common control at historical cost in a manner similar to the pooling of interest method.

 

 

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Acquisition of Oil & Gas Properties – Third Party

On May 1, 2012, we acquired an undivided 35% non-operating interest in certain oil and natural gas properties located in East Texas and an undivided 15% non-operating interest in certain oil and natural gas properties located in North Louisiana from an undisclosed seller for approximately $37.3 million, subject to customary post-closing adjustments. The effective date of this transaction was January 1, 2012. This transaction was partially financed with $35.0 million of borrowings under our revolving credit facility. The transaction was approved by the Board and by its conflicts committee, which is comprised entirely of independent directors. These properties are located primarily in Polk County, Texas and Lincoln and Claiborne Parishes, Louisiana. Memorial Resource will operate 75% of the acquired properties and the remaining 25% will be operated by third parties. Approximately 61% of the current net production of 3.5 MMcfe/d is natural gas and the remaining 39% is oil and NGLs. This acquisition will be accounted for as a business combination using the acquisition method of accounting. Given the recent nature of this transaction, we have not yet completed the related purchase price allocation.

Business Environment and Operational Focus

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

Production Volumes

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

Realized Prices on the Sale of our Production

We market our natural gas, NGL and oil production to a variety of purchasers based on regional pricing. The relative prices of natural gas, NGL and oil are determined by the factors impacting global and regional supply and demand dynamics, such as economic conditions, production levels, weather cycles and other events. In addition, relative prices are heavily influenced by product quality and location relative to consuming and refining markets. We expect commodity prices to be volatile in the future. Recently, natural gas futures traded on the NYMEX fell below $2.00 per MMBtu for the first time in over a decade as a result of supply and demand fundamentals. The decline in gas prices is primarily a result of growing gas production associated with discoveries of significant gas reserves in United States shale plays, combined with the warmer than normal winter of 2011-2012, which has resulted in gas storage levels being at historically high levels. 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 enter into commodity derivative contracts covering approximately 65% to 85% of our targeted average net production over a three-to-five year period at any given point of time. We may, however, from time to time hedge more or less than this approximate range. By removing a significant portion of this price volatility on our future production through May 2017, we have mitigated, but not eliminated, the potential effects of changing commodity prices on our cash flows from operations for those periods.

 

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Lease Operating Expenses

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

General & Administrative Expenses

We and our general partner have entered into an omnibus agreement with Memorial Resource pursuant to which, among other things, Memorial Resource performs all operational, management and administrative services on our general partner’s and our behalf. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocated to us, including expenses incurred by our general partner and its affiliates on our behalf. Memorial Resource currently intends to allocate its expected general and administrative costs proportionately based on the relative size of our proved and probable reserves in comparison to Memorial Resource’s proved and probable reserves. Under our partnership agreement and the omnibus agreement, we reimburse Memorial Resource for all direct and indirect costs incurred on our behalf.

Adjusted EBITDA

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

Plus:

 

•

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

•

Income tax expense;

•

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

•

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

•

Accretion of asset retirement obligations (“AROs”);

•

Unrealized losses on commodity derivative contracts;

•

Losses on sale of assets and other, net;

•

Unit-based compensation expenses;

•

Exploration costs;

•

Acquisition related costs; and

•

Other non-routine items that we deem appropriate.

Less:

 

•

Interest income;

•

Income tax benefit;

•

Unrealized gains on commodity derivative contracts;

•

Gains on sale of assets and other, net; and

•

Other non-routine items that we deem appropriate.

We are required to comply with certain Adjusted EBITDA-related metrics under our revolving credit facility.

 

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Adjusted EBITDA is used as a supplemental financial measure by our management and by external users of our financial statements, such as investors, commercial banks and others, 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; and

•

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

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

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

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

 

		For the Three Months Ended March 31,
		2012				2011
						(Predecessor)
Calculation of Adjusted EBITDA:
Net income (loss)		$	20,894			$	(1,983)
Interest expense			1,325				1,035
Deferred income tax expense			183				--
DD&A			6,160				4,450
Accretion of AROs			278				210
Unrealized (gains) losses on commodity derivative instruments			(14,980)				2,070
Gain on sale of properties			--				(8)
Acquisition related expenses			113				--
Unit-based compensation expense			248				--
Adjusted EBITDA		$	14,221			$	5,774

 

		For the Three Months Ended March 31,
		2012				2011
						(Predecessor)
Reconciliation of Net Cash from Operating Activities to Adjusted EBITDA:
Net cash provided by operating activities		$	13,891			$	2,999
Changes in working capital			(717)				1,653
Interest expense			1,325				1,035
Unrealized (loss) gain on interest rate swaps			(262)				172
Amortization of deferred financing fees			(129)				(85)
Acquisition related expenses			113				--
Adjusted EBITDA		$	14,221			$	5,774

 

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Critical Accounting Policies and Estimates

A discussion of our critical accounting policies and estimates is included in our 2011 Form 10-K. Significant estimates include, but are not limited to, oil and natural gas reserves; depreciation, depletion, and amortization of proved oil and natural gas properties; future cash flows from oil and natural gas properties; impairment of long-lived assets; fair value of derivatives; fair value of equity compensation; fair values of assets acquired and liabilities assumed in business combinations and asset retirement obligations. These estimates, in our opinion, are subjective in nature, require the exercise of professional judgment and involve complex analysis.

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

Results of Operations

The results of operations for the three months ended March 31, 2012 has been derived from our consolidated financial statements. The results of operations for the three months ended March 31, 2011 is presented on a combined basis, consisting of the combined financial information of our predecessor. The historical financial data of our predecessor consists of the combined financial data of BlueStone Natural Resources Holdings, LLC, certain oil and natural gas properties owned by Classic and for periods after April 8, 2011, certain oil and natural gas properties owned by WHT. The results of operations covering periods prior to the closing of our IPO on December 14, 2011 may not necessarily be indicative of the actual results of operations that might have occurred if the Partnership operated separately during those periods. The following table summarizes certain of the results of operations and period-to-period comparisons for the periods indicated.

 

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		For the Three Months Ended March 31,
		2012				2011
						(Predecessor)
Revenues:
Oil & natural gas sales		$	16,546			$	11,590
Other income			110				103
Total revenues		$	16,656			$	11,693
Costs and expenses:
Lease operating			5,524				4,244
Production and ad valorem taxes			1,688				1,214
Depreciation, depletion, and amortization			6,160				4,450
General and administrative			2,018				1,474
Accretion of asset retirement obligations			278				210
Realized gain on commodity derivative instruments			(6,491)				(1,367)
Unrealized (gain) loss on commodity derivative instruments			(14,980)				2,070
Gain on sale of properties			--				(8)
Other, net			57				354
Total costs and expenses			(5,746)				12,641
Operating income (loss)			22,402				(948)
Interest expense			(1,325)				(1,035)
Income (loss) before income taxes			21,077				(1,983)
Income tax expense			(183)				--
Net income (loss)			20,894				(1,983)
Net income (loss) attributable to predecessor			--				(1,983)
Net income attributable to partners		$	20,894			$	--
Oil and natural gas revenue:
Oil sales		$	2,801			$	1,471
NGL sales			2,664				278
Natural gas sales			11,081				9,841
Total oil and natural gas revenue		$	16,546			$	11,590
Production volumes:
Oil (MBbls)			27				16
NGLs (MBbls)			52				5
Natural gas (MMcf)			3,865				2,266
Total (MMcfe)			4,340				2,395
Average net production (MMcfe/d)			47.7				26.6
Average sales price (excluding commodity derivatives):
Oil (per Bbl)		$	102.67			$	91.28
NGL (per Bbl)		$	51.38			$	52.09
Natural gas (per Mcf)		$	2.87			$	4.34
Total (Mcfe)		$	3.81			$	4.84
Average unit costs per Mcfe:
Lease operating expense		$	1.27			$	1.77
Production and ad valorem taxes		$	0.39			$	0.51
General and administrative expenses		$	0.46			$	0.62
Depletion, depreciation, and amortization		$	1.42			$	1.86

 

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Three Months Ended March 31, 2012 Compared to the Three Months Ended March 31, 2011

We recorded net income of $20.9 million for the three months ended March 31, 2012 compared to a net loss of $2.0 million recorded by our predecessor for the three months ended March 31, 2011. The three months ended March 31, 2012 included a $15.0 million unrealized gain on commodity derivative instruments, as compared to a $2.1 million unrealized loss recorded by our predecessor during the same period in 2011.

Revenues. Oil, natural gas and NGL revenues for the three months ended March 31, 2012 were $16.5 million, an increase of $4.9 million compared with same period in 2011. The increase was largely the result of increased production of 1,945 MMcfe, or 81%, primarily related to properties acquired by our predecessor in April and May of 2011. The average realized sales price (excluding realized gain on derivatives) for the three months ended March 31, 2012 was $3.81 per Mcfe compared to $4.84 per Mcfe for the same period in 2011. The quarter-to-quarter decrease is primarily driven by a 34% decrease in the natural gas average realized sales price.

Lease Operating. Lease operating expenses increased by approximately $1.3 million, or 30%, to approximately $5.5 million for the three months ended March 31, 2012, from approximately $4.2 million for the three months ended March 31, 2011. Lease operating expenses increased primarily due to costs associated with properties acquired by our predecessor in April and May of 2011.

Production and Ad Valorem Taxes. Production and ad valorem taxes for the three months ended March 31, 2012 was $1.7 million, an increase of $0.5 million compared with the same period in 2011. The increase in these taxes was mainly due to higher oil, natural gas and NGL revenues during three months ended March 31, 2012 as compared to the same period in 2011 and increased ad valorem taxes related to properties acquired by our predecessor in April and May of 2011.

Depreciation, Depletion and Amortization. DD&A expense increased from approximately $4.5 million for the three months ended March 31, 2011 to approximately $6.2 million for the three months ended March 31, 2012 due to increased production from 2,395 MMcfe to 4,340 MMcfe related to properties acquired in 2011. DD&A per Mcfe decreased from $1.86 per Mcfe for the three months ended March 31, 2011 to $1.42 for the three months ended March 31, 2012 due to an increase in proved reserve volumes between periods relative to the increase in capitalized costs subject to amortization.

General and Administrative. Our general and administrative expenses include the costs of administrative employees and related benefits, management fees paid to Memorial Resource, professional fees and other costs not directly associated with field operations. General and administrative expenses for the three months ended March 31, 2012 was $2.0 million.

Our predecessor’s general and administrative expenses included the costs of administrative employees, related benefits, office rents, professional fees and other costs not directly associated with field operations or production. Our predecessor’s general and administrative expenses for the three months ended March 31, 2011 was $1.5 million.

(Gain) Loss on Commodity Derivative Instruments. We recognized a gain on commodity derivative instruments of approximately $21.5 million during the three months ended March 31, 2012, of which approximately $6.5 million was realized and $15.0 million was unrealized. Our predecessor recognized a loss on commodity derivative instruments of $0.7 million during the three months ended March 31, 2011. The $0.7 million loss was comprised of realized gains of approximately $1.4 million and unrealized losses of approximately $2.1 million.

Interest Expense. Interest expense is comprised of interest on credit facilities, amortization of debt issue costs and realized and unrealized gains and losses on interest rate swaps. Interest expense was $1.3 million for the three months ended March 31, 2012 attributable to the Partnership’s revolving credit facility, which included unrealized losses on interest rate swaps of approximately $0.3 million. Our predecessor’s interest expense was comprised of interest on its credit facilities and amortization of debt issuance costs. Our predecessor’s interest expense was $1.0 million for the three months ended March 31, 2011.

 

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Liquidity and Capital Resources

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

As of March 31, 2012, our liquidity of $188.3 million consisted of $8.3 million of available cash and $180.0 million of available borrowings under our revolving credit facility. Our primary sources of liquidity and capital resources are cash flows generated by operating activities and borrowings under our revolving credit facility. We may also have the ability to issue additional equity and debt as needed. Our primary cash requirements are for distributions to our partners, capital expenditures, debt service and working capital needs. During April and May 2012, we borrowed an additional $77.0 million under our revolving credit facility to complete three acquisitions.

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

As of March 31, 2012, we had a positive working capital balance of $30.6 million.

Capital Expenditures

For the three months ended March 31, 2012, our maintenance and growth capital expenditures were $2.3 million and $7.8 million, respectively. See “— Significant Current Developments” for additional information regarding our acquisition of oil and gas producing properties in April and May of 2012.

Revolving Credit Facility

We have a $1.0 billion revolving credit facility that expires in December 2016. Borrowings under the facility may not exceed a borrowing base determined by the lenders based on our oil and natural gas reserves. As of March 31, 2012, our revolving credit facility had borrowing capacity of $180.0 million ($300.0 million borrowing base less $120.0 million of outstanding borrowings). In connection with the April 2012 scheduled borrowing base redetermination under the Partnership’s revolving credit facility, the Partnership’s borrowing base remained at $300.0 million. Our next scheduled borrowing base redetermination is October 2012. As of March 31, 2012, 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 7 of the Notes to Unaudited Condensed Consolidated and Predecessor Combined Financial Statements included under Item 1 of this quarterly report.

 

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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 targeted average net production over a three-to-five year period at any given point of time. We may, however, from time to time hedge more or less than this approximate range.

As of May 1, 2012, we have open commodity derivative contracts for the years ending:

 

•

December 31, 2012, 2013, 2014, 2015 and 2016 covering approximately 88%, 88%, 82%, 76% and 70%, respectively, of our targeted average net production of natural gas, and we have total hedged volumes for the years ending December 31, 2012, 2013, 2014, 2015 and 2016, respectively, at weighted-average floor hedge prices of $4.64, $4.51, $4.44, $4.37 and $4.58 per MMBtu;

 

•

December 31, 2012, 2013, 2014, 2015 and 2016 covering approximately 84%, 89%, 62%, 62%, and 62% respectively, of our targeted average net production of crude oil, and have total hedged volumes for the years ending December 31, 2012, 2013, 2014, 2015, and 2016, respectively, at weighted-average floor hedge prices of $92.31, $93.26, $90.28, $91.36 and $91.34 per barrel; and

 

•

December 31, 2012 and 2013 covering approximately 26% and 25% respectively, of our targeted average net production of NGLs, and have total hedged volumes for the years ending December 31, 2012 and 2013, respectively, at weighted-average floor hedge prices of $71.85 and $73.11 per barrel.

 

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The following table reflects the volumes of our production covered by commodity derivative contracts and the average prices at which production is hedged as of May 1, 2012 for the following calendar years:

 

			000000000				000000000				000000000				000000000				000000000
		Remaining     2012				2013				2014				2015				2016
Natural Gas Derivative Contracts:
Fixed price swap contracts:
Volume (MMBtu/d)			19,729				34,526				38,248				35,434				32,566
Weighted-average fixed price		$	4.44			$	4.40			$	4.44			$	4.37			$	4.58
Collar contracts:
Volume (MMBtu/d)			19,080				6,674				--				--				--
Weighted-average floor price		$	4.83			$	5.07			$	--			$	--			$	--
Weighted-average ceiling price		$	5.87			$	5.80			$	--			$	--			$	--
Put options:
Volume (MMBtu/d)			2,291				--				--				--				--
Weighted-average floor price		$	4.80			$	--			$	--			$	--			$	--
Total natural gas volumes hedged (MMBtu/d):			41,100				41,200				38,248				35,434				32,566
Crude Oil Derivative Contracts:
Fixed price swap contracts:
Volume (Bbl/d)			142				152				110				215				214
Weighted-average fixed price		$	98.15			$	99.53			$	90.55			$	91.36			$	91.34
Collar contracts:
Volume (Bbl/d)			147				156				105				--				--
Weighted-average floor price		$	86.67			$	87.16			$	90.00			$	--			$	--
Weighted-average ceiling price		$	115.12			$	116.94			$	117.72			$	--			$	--
Total crude oil volumes hedged (Bbl/d):			289				308				215				215				214
NGL Derivative Contracts:
Fixed price swap contracts:
Volume (Bbl/d)			74				188				--				--				--
Weighted-average fixed price		$	66.26			$	73.11			$	--			$	--			$	--
Collar contracts:
Volume (Bbl/d)			124				--				--				--				--
Weighted-average floor price		$	75.16			$	--			$	--			$	--			$	--
Weighted-average ceiling price		$	93.57			$	--			$	--			$	--			$	--
Total NGL volumes hedged (Bbl/d):			198				188				--				--				--

The following table reflects the volumes of our production covered by commodity derivative contracts and the average prices at which production is hedged as of May 1, 2012 for the period indicated:

 

		January 2017     Through May 2017
Natural Gas Derivative Contracts:
Fixed price swap contracts:
Volume (MMBtu/d)			25,072
Weighted-average fixed price		$	4.27

 

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Our acquisition of oil and gas properties from Memorial Resource in April 2012 included the novation of 2012 through 2013 commodity derivative positions to the Partnership. See “— Significant Current Developments” for additional information regarding this acquisition. The following table reflects the notional volumes and the weighted-average hedge prices related to this novation, which are also reflected in the table above:

 

		Remaining     2012				2013
Natural Gas Derivative Contracts:
Collar contracts:
Volume (MMBtu/d)			1,473				1,348
Weighted-average floor price		$	4.25			$	4.75
Weighted-average ceiling price		$	4.98			$	5.78

Our acquisition of oil and gas properties from Memorial Resource in May 2012 included the novation of 2012 through 2014 commodity derivative positions to the Partnership. See “— Significant Current Developments” for additional information regarding this acquisition. The following table reflects the notional volumes and the weighted-average hedge prices related to this novation:

 

		Remaining     2012				2013				2014
Natural Gas Derivative Contracts:
Fixed price swap contracts:
Volume (MMBtu/d)			982				986				986
Weighted-average fixed price		$	6.97			$	6.58			$	4.40

See “Item 3. Quantitative and Qualitative Disclosure About Market Risk” for a summary of our derivative contracts as of March 31, 2012.

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. At May 2, 2012, we had the following fixed-for floating interest rate swap open positions:

 

Period Covered						Notional     ($ in thousands)				Floating Rate		Fixed Rate
1/17/2012			1/16/2013			$	100,000			1 Month LIBOR		0.600%
1/17/2013			12/14/2016			$	100,000			1 Month LIBOR		1.305%
5/17/2012			1/17/2013			$	50,000			1 Month LIBOR		0.600%
1/17/2013			12/14/2016			$	50,000			1 Month LIBOR		0.970%

See “Item 3. Quantitative and Qualitative Disclosure About Market Risk” for a summary of our derivative contracts as of March 31, 2012.

Counterparty Exposure

As of March 31, 2012, our open commodity derivative contracts were in a net receivable position. All of our commodity derivative contracts are with major financial institutions who are also lenders under our revolving credit facility. Should one of these financial counterparties not perform, we may not realize the benefit of some of our derivative instruments under lower commodity prices and we could incur a loss. Although we have entered into netting agreements under our derivative instruments with certain of our counterparties, below we have presented all asset and liability positions without netting. As of March 31, 2012, all of our counterparties have performed pursuant to their commodity derivative contracts.

The following table presents our gross asset and liability positions with our counterparties as of March 31, 2012:

 

		Gross
Assets		$	52,303
Liabilities			(5,667)
Net		$	46,636

 

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Cash Flows from Operating, Investing and Financing Activities

The following table summarizes our cash flows from operating, investing and financing activities for the periods indicated. The cash flows for the three months ended March 31, 2011 is presented on a combined basis, consisting of the combined financial information of our predecessor. For information regarding the individual components of our cash flow amounts, see the Unaudited Condensed Statements of Consolidated and Predecessor Combined Cash Flows included under Item 1 of this quarterly report.

 

		For the Three Months Ended March 31,
		2012				2011
						(Predecessor)
Net cash provided by operating activities		$	13,891			$	2,999
Net cash (used in) investing activities			(4,596)				(7,898)
Net cash (used in) provided by financing activities			(2,065)				1,375

Three Months Ended March 31, 2012 Compared to the Three Months Ended March 31, 2011

Operating Activities. Key drivers of net operating cash flows are commodity prices, production volumes and operating costs. Net cash flows provided by operating activities increased for the three months ended March 31, 2012 primarily due to an increase in production volumes as a result of our predecessor’s acquisition activities in 2011. We primarily used cash flows provided by operating activities primarily to fund distributions to our partners and additions to oil and gas properties. Our predecessor primarily used cash flows provided by operating activities to fund its exploration and development expenditures.

Investing Activities. Cash used in investing activities for the three months ended March 31, 2012 was $4.6 million for additions to oil and gas properties. During the three months ended March 31, 2012, we participated in 4 new drills in East Texas, none of which were dry holes, for a success rate of 100%.

Cash used in investing activities for the three months ended March 31, 2011 was $7.9 million, driven mostly by additions to oil and natural gas properties of $6.0 million. During the three months ended March 31, 2011, our predecessor participated in the drilling of 2 wells, none of which were dry holes, for a success rate of 100%.

Financing Activities. On January 26, 2012, the board of directors of our general partner declared a quarterly cash distribution for the fourth quarter of 2011 of $0.0929 per unit. The distribution represented a proration of our minimum quarterly distribution of $0.4750 per unit for the period from December 14, 2011 through December 31, 2011. The aggregate distribution of $2.0 million, of which Memorial Resource received $1.2 million, was paid on February 13, 2012 to unitholders of record as of the close of business on February 6, 2012, except for the holders of 177,370 restricted common units that were granted to our general partner’s executive officers and independent director on January 9, 2012.

During the three months ended March 31, 2011, our predecessor received capital contributions of $4.2 million and made net repayments of $2.8 million. Our predecessor primarily used cash flows provided by financing activities to fund its development and property acquisition program.

Contractual Obligations

During the three months ended March 31, 2012, there were no significant changes in our consolidated contractual obligations from those reported in our 2011 Form 10-K.

Off–Balance Sheet Arrangements

As of March 31, 2012, 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 Predecessor Financial Statements included under Item 1 of this quarterly report.

 

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ITEM 3.   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

In the normal course of our business operations, we are exposed to certain risks, including changes in interest rates and commodity prices. We may enter into derivative instruments to manage or reduce market risk, but do not enter into derivative agreements for speculative purposes. We do not designate these or plan to designate future derivative instruments as hedges for accounting purposes. Accordingly, the changes in the fair value of these instruments are recognized currently in earnings. We do not 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 2011 Form 10-K.

Commodity Price Risk

Our major market risk exposure is in the pricing that we receive for our natural gas, oil and NGL production. To reduce the impact of fluctuations in commodity prices on our revenues, or to protect the economics of property acquisitions, we periodically enter into derivative contracts with respect to a portion of our projected production through various transactions that fix the future prices received.

For additional information regarding the volumes of our production covered by commodity derivative contracts and the average prices at which production is hedged as of March 31, 2012, see Note 5 of the Notes to Unaudited Condensed Consolidated and Predecessor Combined Financial Statements included under Item 1 of this quarterly report.

See “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources —Commodity Derivative Contract” for a summary of our derivative contracts that were in place as of May 1, 2012.

Interest Rate Risk

At March 31, 2012, we had $120 million of debt outstanding under our revolving credit facility, with a weighted average interest rate of LIBOR plus 2.0%, or 2.32%. 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. The following interest rate swap arrangements were outstanding at March 31, 2012:

 

•

$100,000,000 notional amount fixed-for-floating swap for the period beginning January 17, 2012 and ending January 17, 2013 at a fixed annual rate of 0.60%; and

 

•

$100,000,000 notional amount fixed-for-floating swap for the period beginning January 17, 2013 and ending December 14, 2016 at a fixed annual rate of 1.305%.

Assuming no change in the amount of debt outstanding, the impact on interest expense of a 10% increase or decrease in the weighted average interest rate, after giving effect to our interest rate swaps, would be less than $0.1 million per year.

See “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources —Interest Rate Derivative Contract” for a summary of our derivative contracts that were in place as of May 2, 2012.

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. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. In addition, our commodity derivative contracts expose us to credit risk in the event of nonperformance by counterparties. As of March 31, 2012, our open commodity derivative contracts were in a net receivable position with a fair value of $47.2 million. Should one of the counterparties to our commodity derivative contracts not perform, we may not realize the benefit of some of our derivative instruments under lower commodity prices and we could incur a loss.

 

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ITEM 4.   CONTROLS AND PROCEDURES.

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-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 Rule 13a-15(e) under the Exchange Act) as of the end of the period covered by this quarterly report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including the principal executive officer and principal financial officer of our general partner, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, the principal executive officer and principal financial officer of our general partner have concluded that our disclosure controls and procedures were effective at the reasonable assurance level as of March 31, 2012.

Change in Internal Controls Over Financial Reporting

During the quarterly period ended March 31, 2012, our internal control over financial reporting was enhanced. A number of employees who had been offered and accepted employment in December 2011 were hired by Memorial Resource to support our business activities in January 2012, including a controller, financial reporting manager, financial accounting manager and engineering and land professionals. During the first quarter of 2012, Memorial Resource also hired additional legal, accounting, finance, human resource, information technology, operational and engineering professionals to support our business activities. Documenting and testing our internal control over financial reporting is currently underway.

Except as noted above, there have not been any changes in our internal controls over financial reporting that occurred during the quarterly period ended March 31, 2011 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

 

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PART II—OTHER INFORMATION

ITEM 1.   LEGAL PROCEEDINGS.

For information regarding legal proceedings, see Part I, Item 1, Financial Statements, Note 12, “Commitments and Contingencies – Litigation & Environmental,” of the Notes to Unaudited Condensed Consolidated and Predecessor Combined Financial Statements included in this quarterly report, which is incorporated herein by reference.

ITEM 1A.   RISK FACTORS.

There have been no material changes with respect to the risk factors disclosed in our 2011 Form 10-K.

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

None.

ITEM 3.   DEFAULTS UPON SENIOR SECURITIES.

None.

ITEM 4.   MINE SAFETY DISCLOSURES.

Not applicable.

ITEM 5.   OTHER INFORMATION.

None.

 

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ITEM 6.   EXHIBITS.

 

Exhibit     Number								Description
	3.1				—			Certificate of Limited Partnership of Memorial Production Partners LP (Incorporated by reference to Exhibit 3.1 of the Partnership’s 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 of the Partnership’s 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 of the Partnership’s Registration Statement on Form S-1 (File No. 333-175090) filed on June 23, 2011).
	3.4				—			Amended and Restated Limited Liability Company Agreement of Memorial Production Partners GP LLC (Incorporated by reference to Exhibit 3.2 of the Partnership’s Current Report on Form 8-K (File No. 001-35364) filed on December 15, 2011).
	4.1#				—			Form of Restricted Unit Agreement under the Memorial Production Partners GP LLC Long-Term Incentive Plan (Incorporated by reference to Exhibit 4.6 of the Partnership’s Registration Statement on Form S-8 (File No. 333-178493) filed on December 14, 2011).
	10.1*				—			First Amendment to Credit Agreement, dated as of April 30, 2012, among Memorial Production Operating LLC, as borrower, Memorial Production Partners LP, as parent guarantor, 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, BNP Paribas, Citibank, N.A. and Comerica Bank, as co-documentation agents for the lenders party thereto, and the other lenders party thereto.
	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.

# Management contract or compensatory plan or arrangement.

 

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Table of Contents

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

				Memorial Production Partners LP (Registrant)
				By:		Memorial Production Partners GP LLC, its general partner
Date:        May 15, 2012				By:		/s/ Andrew J. Cozby
				Name:		Andrew J. Cozby
				Title:		Vice President and Chief Financial Officer of Memorial Production Partners GP LLC

 

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