Exhibit 99.2

RECAST ITEM 8.        FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

MEMORIAL PRODUCTION PARTNERS LP

INDEX TO FINANCIAL STATEMENTS

 

 

F-1

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Memorial Production Partners GP LLC and

Unitholders of Memorial Production Partners LP

We have audited the accompanying consolidated and predecessor combined balance sheets of Memorial Production Partners LP (the Partnership) as of December 31, 2011 and 2010, and the related consolidated and predecessor combined statements of operations, equity, and cash flows for each of the years in the three-year period ended December 31, 2011. These consolidated and predecessor combined financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States.) Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated and predecessor combined financial statements referred to above present fairly, in all material respects, the financial position of Memorial Production Partners LP as of December 31, 2011 and 2010, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2011, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 1 to the consolidated and predecessor combined financial statements, the balance sheets, and the related statements of operations, equity, and cash flows have been prepared on a combined basis of accounting.

/s/ KPMG LLP

Dallas, Texas

November 19, 2012

 

F-2

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MEMORIAL PRODUCTION PARTNERS LP

CONSOLIDATED AND PREDECESSOR COMBINED BALANCE SHEETS

(In thousands, except outstanding units)

 

		December 31,
		2011				2010
ASSETS							(Predecessor)
Current Assets:
Cash and cash equivalents		$	1,088			$	5,654
Accounts Receivable:
Oil and natural gas sales (Note 1)			--				6,175
Joint interest owners and other (Note 1)			--				3,848
Affiliates			2,955				--
Short-term derivative instruments			23,069				3,791
Prepaid expenses and other current assets			1,831				771
Total current assets			28,943				20,239
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method			560,248				367,378
Other			--				2,553
			560,248				369,931
Accumulated depreciation, depletion and impairment			(111,611)				(102,969)
Oil and natural gas properties, net			448,637				266,962
Long-term derivative instruments			13,654				3,934
Other long-term assets			2,012				1,298
Total assets		$	493,246			$	292,433
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable (Note 1)		$	--			$	8,482
Revenues payable (Note 1)			--				3,564
Accounts payable – affiliates			1,024				--
Accrued liabilities			2,032				3,874
Current portion of long-term debt			--				69
Short-term derivative instruments			346				109
Asset retirement obligations			--				25
Total current liabilities			3,402				16,123
Long-term debt			120,000				115,359
Asset retirement obligations			14,113				11,447
Long-term derivative instruments			1,040				109
Other long-term liabilities			670				281
Total liabilities			139,225				143,319
Commitments and contingencies (Note 12 )
Equity:
Partners’ equity:
Limited partners:
Common units (16,661,294 units outstanding at December 31, 2011)			241,034				--
Subordinated units (5,360,912 units outstanding at December 31, 2011)			61,708				--
General partner (22,044 units outstanding at December 31, 2011)			426				--
Total partners’ equity			303,168				--
Predecessor capital			50,853				149,114
Total equity			354,021				149,114
Total liabilities and equity		$	493,246			$	292,433

See Accompanying Notes to Consolidated and Predecessor Combined Financial Statements.

 

F-3

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MEMORIAL PRODUCTION PARTNERS LP

STATEMENTS OF CONSOLIDATED AND PREDECESSOR COMBINED OPERATIONS

(In thousands, except per unit amounts)

 

		For Year Ended December 31,
		2011				2010				2009
						(Predecessor)
Revenues:
Oil & natural gas sales		$	84,058			$	47,435			$	32,032
Other income			825				1,433				319
Total revenues			84,883				48,868				32,351
Costs and expenses:
Lease operating			24,474				14,878				12,191
Exploration			56				39				2,690
Production taxes			4,790				2,838				2,032
Depreciation, depletion, and amortization			30,052				24,543				19,011
Impairment of proved oil and natural gas properties			15,141				11,800				3,480
General and administrative			10,399				7,102				5,845
Accretion of asset retirement obligations			1,069				672				326
Realized gain on commodity derivative instruments			(7,944)				(7,294)				(17,574)
Unrealized (gain) loss on commodity derivative instruments			(25,381)				(3,919)				6,453
Gain on sale of properties			(63,024)				(1)				(7,851)
Other, net			1,908				1,194				448
Total costs and expenses			(8,460)				51,852				27,051
Operating income (loss)			93,343				(2,984)				5,300
Interest expense			7,268				4,438				2,937
Income (loss) before income taxes			86,075				(7,422)				2,363
Income tax expense			122				225				--
Net income (loss)			85,953				(7,647)				2,363
Net income (loss) attributable to predecessor			79,361				(7,647)				2,363
Net income attributable to partners		$	6,592			$	--			$	--
Allocation of net income attributable to partners:
Limited partners		$	6,585			$	--			$	--
General partner		$	7			$	--			$	--
Earnings per unit: (see Note 9)
Basic and diluted earnings per unit		$	0.30			$	--			$	--
Weighted average limited partner units outstanding:
Basic and diluted			21,756				--				--

See Accompanying Notes to Consolidated and Predecessor Combined Financial Statements.

 

F-4

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MEMORIAL PRODUCTION PARTNERS LP

STATEMENTS OF CONSOLIDATED AND PREDECESSOR COMBINED CASH FLOWS

(In thousands)

 

		For Year Ended December 31,
		2011				2010				2009
						(Predecessor)
Cash flows from operating activities
Net income (loss)		$	85,953			$	(7,647)			$	2,363
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization			30,052				24,543				19,011
Impairment of proved oil and natural gas properties			15,141				11,800				3,480
Unrealized (gain) loss on derivatives			(24,605)				(3,623)				6,143
Premiums paid for derivatives			(2,847)				--				--
Premiums received for derivatives			1,008				--				--
Deferred income tax expense			122				225				--
Amortization of loan origination costs			465				745				109
Accretion of asset retirement obligations			1,069				672				326
Gain on sale of properties			(63,024)				(1)				(7,851)
Exploratory dry hole costs			56				39				2,690
Changes in operating assets and liabilities:
Accounts receivable			(6,400)				(2,637)				6,522
Accounts receivable – affiliates			(2,955)				--				--
Prepaid expenses and other assets			(786)				227				(729)
Accounts payable			2,196				855				(12,597)
Revenue payable			2,763				423				(1,171)
Accrued liabilities			4,491				1,771				(842)
Other			7				104				(21)
Net cash provided by operating activities			42,706				27,496				17,433
Cash flows from investing activities:
Acquisition of oil and natural gas properties			(138,175)				(119,511)				(17,455)
Additions to oil and gas properties			(33,528)				(16,554)				(36,225)
Additions to other property and equipment			(327)				(416)				(210)
Proceeds from the sale of oil and gas properties			2,378				1,400				11,752
Net cash used in investing activities			(169,652)				(135,081)				(42,138)
Cash flows from financing activities:
Advances on revolving credit facility - Predecessor			85,918				115,106				11,948
Advances on revolving credit facility - Partnership			130,000				--				--
Payments on revolving credit facility - Predecessor			(201,346)				(61,600)				(12,749)
Payments on revolving credit facility - Partnership			(10,000)				--				--
Proceeds from borrowings of long-term debt			--				182				--
Repayment of borrowings of long-term debt			--				(44)				(27)
Loan origination fees - Predecessor			(934)				(1,018)				(489)
Loan origination fees – Partnership			(2,544)				--				--
Predecessor capital contributions			52,804				55,316				29,736
Proceeds from general partner contribution			419				--				--
Net cash proceeds from initial public offering (see Note 1)			146,460				--				--
Net cash proceeds from over-allotment option (see Note 1)			10,659				--				--
Distribution to Memorial Resource (see Note 1)			(73,557)				--				--
Cash retained by Predecessor			(15,499)				--				--
Net cash provided by financing activities			122,380				107,942				28,419
Net change in cash and cash equivalents			(4,566)				357				3,714
Cash and cash equivalents, beginning of year			5,654				5,297				1,583
Cash and cash equivalents, end of year		$	1,088			$	5,654				5,297
Supplemental cash flows:
Cash paid for interest		$	5,278			$	4,309				2,677
Noncash investing and financing activities:
Purchase of fixed assets with note payable			--				--				117
Environmental remediation liability – net (see Note 12)			387				1,450				--
Fair value of assets acquired in excess of cash paid and net book value of properties transferred			68,945				--				--
Assumptions of asset retirement obligations relate to properties acquired			2,661				6,371				996

See Accompanying Notes to Consolidated and Predecessor Combined Financial Statements.

 

F-5

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MEMORIAL PRODUCTION PARTNERS LP

STATEMENTS OF CONSOLIDATED AND PREDECESSOR COMBINED EQUITY

(In thousands)

 

		Partner’s Equity
		Limited Partners								General
		Common				Subordinated				Partner				Predecessor				Total
Balance December 31, 2008		$	--			$	--			$	--			$	69,346			$	69,346
Net income			--				--				--				2,363				2,363
Predecessor capital contributions			--				--				--				29,736				29,736
Balance December 31, 2009			--				--				--				101,445				101,445
Net income (loss)			--				--				--				(7,647)				(7,647)
Predecessor capital contributions			--				--				--				55,316				55,316
Balance December 31, 2010			--				--				--				149,114				149,114
Net income			--				--				--				79,361				79,361
Predecessor capital contributions			--				--				--				52,804				52,804
Net assets retained by predecessor			--				--				--				(17,385)				(17,385)
Exchange of predecessor interests for units (Note 1)			121,101				91,940				--				(213,041)				--
Deferred tax liability from initial public offering			(335)				(111)				--				--				(446)
Net cash proceeds from initial public offering			146,460				--				--				--				146,460
Net cash proceeds from over-allotment option			10,659				--				--				--				10,659
Contributions from general partner			--				--				419				--				419
Distribution to Memorial Resource (Note 1)			(41,813)				(31,744)				--				--				(73,557)
Net income – December 14 to December 31			4,962				1,623				7				--				6,592
Balance December 31, 2011		$	241,034			$	61,708			$	426			$	50,853			$	354,021

See Accompanying Notes to Consolidated and Predecessor Combined Financial Statements.

 

F-6

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO 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 Louisiana and Texas and consist of mature, legacy onshore oil and natural gas reservoirs. The Partnership’s properties consist primarily of operated and non-operated working interests in producing and undeveloped leasehold acreage and working interests in identified producing wells (often referred to as wellbore assignments).

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 GLP 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 securing 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. The Partnership acquired the following net assets of our predecessor:

 

F-7

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

 

 

Oil and natural gas properties, net		$	399,967
Short-term derivative instruments, net			15,779
Long-term derivative instruments, net			10,772
Asset retirement obligations			(13,560)
Credit facilities – predecessor (2)			(198,267)
Accrued liabilities			(1,650)
Net assets (1)		$	213,041
(1)       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. (2)       Although the Partnership did not legally assume the debt of its predecessor, for accounting and financial reporting purposes the $198.3 million that was repaid concurrent with the closing of our IPO on behalf of our predecessor has been netted against the net book value of the net assets that were acquired by us and reflected on our consolidated and combined cash flow statement as “Payments on revolving credit facility – predecessor.”

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 of these net proceeds were used to repay indebtedness under our revolving credit facility.

Predecessor

The Partnership did not own any assets prior to December 14, 2011. For accounting and financial reporting purposes, “our predecessor” refers collectively to: (i) BlueStone Natural Resources Holdings, LLC (“Bluestone”) and its wholly-owned subsidiaries in addition to certain carved-out oil and natural gas properties (“Classic Carve-Out”) owned by Classic for all periods prior to the closing of our IPO, (ii) for periods after April 8, 2011 through the closing of our IPO, certain oil and natural gas properties owned by WHT, and (iii) certain oil and natural gas properties the Partnership acquired from Memorial Resource in April and May 2012 for periods after common control commenced through their respective acquisition dates.

BlueStone, a Delaware limited liability company, 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) have been included in these financial statements from that date forward. Prior to April 8, 2011, WHT did not have any oil and natural gas assets.

Acquisitions of oil and gas properties from Memorial Resource subsequent to our IPO are accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the net assets acquired are recorded at historical cost and certain financial and other information are retrospectively revised to give effect to such acquisitions as if the Partnership had owned the assets beginning on the dates Memorial Resource originally acquired them. See Note 11 for information about the Partnership’s acquisitions of oil and gas properties from Memorial Resource in April and May 2012.

 

F-8

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

 

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 consolidated results of operations following the completion of our IPO (i.e., December 14, 2011 through December 31, 2011) are presented together with the combined results of operations pertaining to our predecessor. 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 all periods presented. Our predecessor’s combined financial statements reflect the financial statements of BlueStone and the Classic Carve-Out through the closing of our IPO, the WHT Assets for periods after April 8, 2011 through December 13, 2011, and certain oil and gas properties acquired from Memorial Resource in April and May 2012 for periods after common control commenced through their respective acquisition dates on a combined basis for all periods presented.

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.

All material intercompany transactions and balances have been eliminated in preparation of our consolidated and predecessor combined financial statements. The accompanying consolidated and predecessor combined financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). In the opinion of management, all adjustments necessary for a fair presentation of the financial statements have been made. Certain amounts in the prior year financial statements have been reclassified to conform to the presentation in the current year financial statements.

Note 2.  Summary of Significant Accounting Policies

Use of Estimates

The preparation of 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 consolidated and predecessor 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.

Principles of Consolidation and Combination

The predecessor combined financial statements include the accounts of BlueStone and the Classic Carve-Out through the closing of our IPO, the WHT Assets for periods after April 8, 2011 through December 13, 2011, and certain oil and gas properties acquired from Memorial Resource in April and May 2012 for periods after common control commenced through their respective acquisition dates on a combined basis. All material intercompany balances and transactions have been eliminated. Likewise, effective with the closing of our IPO, our consolidated financial statements include our accounts and those of our majority-owned subsidiaries in which we have a controlling interest, after the elimination of all intercompany accounts and transactions. Our consolidated and predecessor financial statements previously filed with the SEC and reported herein have been recast to include the financial position and results attributable to the oil and gas properties acquired from Memorial Resource in April and May 2012 on a combined basis for all periods where common control existed.

Cash and Cash Equivalents

Cash and cash equivalents represent unrestricted cash on hand and all highly liquid investments with original contractual maturities of three months or less.

 

F-9

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

 

Concentrations of Credit Risk

Cash balances, accounts receivable and derivative financial instruments are financial instruments potentially subject to credit risk. Cash and cash equivalents are maintained in bank deposit accounts which, at times, may exceed the federally insured limits. Management periodically reviews and assesses the financial condition of the banks to mitigate the risk of loss. Derivative financial instruments are generally executed with major financial institutions that expose our predecessor and us to market and credit risks and which may, at times, be concentrated with certain counterparties. The credit worthiness of the counterparties is subject to continual review. We and our predecessor relied upon netting arrangements with counterparties to reduce credit exposure. Neither we nor our predecessor have experienced any losses from such instruments.

Oil and natural gas are sold to a variety of purchasers, including intrastate and interstate pipelines or their marketing affiliates and independent marketing companies. Accounts receivable from joint operations are from a number of oil and natural gas companies, partnerships, individuals, and others who own interests in the properties operated by us and our predecessor. Generally, operators of crude oil and natural gas properties have the right to offset future revenues against unpaid charges related to operated wells, minimizing the credit risk associated with these receivables. Additionally, management believes that any credit risk imposed by a concentration in the oil and natural gas industry is mitigated by the creditworthiness of its customer base. An allowance for doubtful accounts is recorded after all reasonable efforts have been exhausted to collect or settle the amount owed. Any amounts outstanding longer than the contractual terms are considered past due. Management determined that an allowance for uncollectible accounts was unnecessary at both December 31, 2011 and 2010, respectively.

If we were to lose any one of our customers, the loss could temporarily delay production and sale of oil and natural gas in the related producing region. If we were to lose any single customer, we believe that a substitute customer to purchase the impacted production volumes could be identified. However, if one or more of the our larger customers ceased purchasing oil or natural gas altogether, the loss of such customer could have a detrimental effect on production volumes in general and on the ability to find substitute customers to purchase production volumes.

Oil and Natural Gas Properties

Oil and natural gas exploration, development and production activities are accounted in accordance with the successful efforts method of accounting. Under this method, costs of acquiring properties, costs of drilling successful exploration wells, and development costs are capitalized. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if determination is made that proved reserves have been found. If no proved reserves have been found, the costs of each of the related exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. The costs of such exploratory wells are expensed if a determination of proved reserves has not been made within a twelve-month period after drilling is complete. Exploration costs such as geological, geophysical, and seismic costs are expensed as incurred.

As exploration and development work progresses and the reserves on these properties are proven, capitalized costs attributed to the properties are subject to depreciation and depletion. Depletion of capitalized costs is provided using the units-of-production method based on proved oil and gas reserves related to the associated field. The timing of any write downs of unproven properties, if warranted, depends upon the nature, timing, and extent of planned exploration and development activities and their results.

On the sale or retirement of a complete or partial unit of a proved property or pipeline and related facilities, the cost and related accumulated depreciation, depletion, and amortization are removed from the property accounts, and any gain or loss is recognized.

The following table presents the amount of capitalized exploratory drilling costs pending evaluation at December 31 for each of the last three years and changes in those amounts during the years then ended (in thousands):

 

		2011				2010				2009
Balance, January 1		$	2,013			$	821			$	1,468
Additions to capitalized exploratory well costs pending determination of proved reserves			701				2,013				821
Capitalized exploratory well costs asset exchange (1)			(2,714)
Reclassification to proved oil and natural gas properties based on the determination of proved reserves			--				(821)				--
Capitalized exploratory well costs charged to expense			--				--				(1,468)
Balance, December 31		$	--			$	2,013			$	821
(1)       Our predecessor acquired interest in wells located in South Texas from BP America Production Company (“BP”) in exchange for acreage and cash. Capitalized exploratory well costs were part of this exchange transaction. See Note 3 for further information regarding this transaction.

 

F-10

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

 

Oil and Gas Reserves

The estimates of proved oil and natural gas reserves utilized in the preparation of the consolidated and predecessor combined financial statements are estimated in accordance with the rules established by the SEC and the Financial Accounting Standards Board (“FASB”). In January 2010, the FASB updated its oil and gas estimation and disclosure requirements to align its requirements with the requirements of the modernized oil and gas reporting rules released by the SEC on December 31, 2008. These rules, which became effective during 2009, require that reserve estimates be prepared under existing economic and operating conditions using a 12-month average price with no provision for price and cost escalations in future years except by contractual arrangements. Independent reserve engineers prepared approximately 85% of our estimated proved reserves (by volume) at December 31, 2011. Internal reserve engineers employed by Memorial Resource prepared approximately 15% of our estimated proved reserves (by volume) at December 31, 2011.

Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. Oil and gas properties are depleted by field using the units-of-production method. Capitalized drilling and development costs of producing oil and natural gas properties are depleted over proved developed reserves and leasehold costs are depleted over total proved reserves. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties, or any combination of the above may be increased or reduced. Increases in recoverable economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates.

Other Property & Equipment

Other property and equipment is stated at historical costs and is comprised primarily of vehicles, furniture, fixtures, and computer hardware and software. Depreciation of other property and equipment is calculated using the straight-line method based on estimated useful lives of three to five years.

Impairments

Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such properties, such as a downward revision of the reserve estimates, less than expected production, drilling results, or lower commodity prices. The estimated future cash flows expected in connection with the property are compared to the carrying value of the property to determine if the carrying amount is recoverable. If the carrying value of the property exceeds its estimated undiscounted future cash flows, the carrying amount of the property is reduced to its estimated fair value using Level 3 inputs. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. Impairment expense for the years ended December 31, 2011, 2010 and 2009 was approximately $15.1 million, $11.8 million and $3.5 million, respectively.

Nonproducing oil and natural gas properties, which consist of undeveloped leasehold costs and costs associated with the purchase of proved undeveloped reserves, are assessed for impairment on a property-by-property basis. If the assessment indicates an impairment, a loss is recognized by providing a valuation allowance. The impairment assessment is affected by economic factors such as the results of exploration activities, commodity price outlooks, remaining lease terms, and potential shifts in business strategy employed by management.

Asset Retirement Obligations

An asset retirement obligation associated with retiring long-lived assets is recognized as a liability on a discounted basis in the period in which the legal obligation is incurred and becomes determinable, with an equal amount capitalized as an addition to oil and natural gas properties, which is allocated to expense over the useful life of the asset. Generally, oil and gas producing companies incur such a liability upon acquiring or drilling a well. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. Upon settlement of the liability, a gain or loss is recognized to the extent the actual costs differ from the recorded liability. See Note 6 for further discussion of asset retirement obligations.

 

F-11

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

 

Other Long-Term Assets

Other long-term assets consist of deposits and deferred financing costs associated with the credit facilities. Deferred financing costs are stated at cost, net of amortization, and are amortized over the terms of the credit facilities. Amortization expense for the years ended December 31, 2011, 2010, and 2009 was approximately $0.5 million, $0.7 million, and $0.1 million, respectively.

Revenue Recognition

Revenue from the sale of oil and natural gas and oil is recognized when title passes, net of royalties due to third parties. Oil and natural gas revenues are recorded using the sales method. Under this method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers, regardless of whether the sales are proportionate to our ownership in the property. An asset or a liability is recognized to the extent that we have an imbalance in excess of our proportionate share of the remaining recoverable reserves on the underlying properties. No significant imbalances existed at December 31, 2011 or 2010.

The following individual customers each accounted for 10% or more of total reported revenues for the period indicated:

 

		Years Ending December 31,
		2011		2010		2009
Major customers: (1)
Dominion Gas Ventures, LP		20%		35%		45%
Enterprise Texas Pipeline, LLC		17%		24%		28%
ConocoPhillips		11%		(2)		(2)
(1)       Collectively, these major customers purchased production pursuant to existing marketing agreements with terms that are currently on “evergreen” status and renew on a month-to-month basis until either party gives 30-day advance written notice of non-renewal. (2)       This customer accounted for less than 10% of total revenue for the period indicated.

General and Administrative Expense

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 allocates general and administrative costs based on the relative size of our proved and probable reserves in comparison to Memorial Resource’s total 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. See Note 11 for additional information in regards to the omnibus agreement.

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.

Derivative Instruments

Commodity derivative financial instruments (e.g., swaps, floors, collars, and put options) are used to reduce the impact of natural gas and oil price fluctuations. Interest rate swaps are used to manage exposure to interest rate volatility, primarily as a result of variable rate borrowings under the credit facilities. Every derivative instrument (including certain derivative instruments embedded in other contracts) is recorded in the balance sheet as either an asset or liability measured at its fair value. Changes in the derivative’s fair value are recognized in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative’s gains and losses to offset related results on the hedged item in the statements of operations. Companies must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting treatment. There were no derivatives designated as hedges for financial accounting purposes at December 31, 2011 or 2010.

Changes in the fair value of derivative financial instruments that do not qualify for accounting treatment as hedges are recognized currently in the statements of operations.

 

F-12

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

 

Income Tax

We are organized as a pass-through entity for income tax purposes. As a result, our partners are responsible for federal income taxes on their share of our taxable income. Likewise, our predecessor entities were not taxpaying entities for federal income tax purposes and their partners or members were responsible for federal income taxes on their share of our predecessor’s taxable income.

We, along with our predecessor entities, are subject to the Texas margin tax and certain aspects of the tax make it similar to an income tax as the tax is assessed on 1% of taxable margin. Deferred taxes related to Texas margin tax arise due to temporary differences between the financial statement carrying value of existing assets and liabilities and their respective tax basis. Deferred tax liabilities as of December 31, 2011 were approximately $0.4 million and total tax expense for the year was approximately $0.1 million. Deferred tax liabilities and tax expense as of and for the year ended December 31, 2010 was approximately $0.2 million. There were no deferred taxes at December 31, 2009 and no tax expense recorded for the year ended December 31, 2009. There were no uncertain tax positions that required recognition in the financial statements at December 31, 2011 or 2010.

Earnings Per Unit

Our partnership agreement contains incentive distribution rights. Accordingly, the amount of net income or loss used in the determination of earnings per unit (“EPU”) for the period from December 14, 2011 to December 31, 2011 is reduced by the amount of available cash that will be distributed to the limited partners, the general partner and the holders of the incentive distribution rights for that corresponding period. The undistributed earnings, if any, are then allocated to the limited partners, the general partner and the holders of the incentive distribution rights in accordance with the terms of the partnership agreement. Basic and diluted EPU is determined by dividing net income or loss available to the limited partners, after deducting the amount allocated to the general partner and the holders of the incentive distribution rights, by the weighted average number of outstanding limited partner units during the period from December 14, 2011 to December 31, 2011. Basic and diluted EPU are equivalent, as all subordinated units participate in distributions. See Note 9 for additional information.

Equity Compensation

The fair value of equity-classified awards (e.g., restricted common unit awards) is amortized to earnings over the requisite service or vesting period. Compensation expense for liability-classified awards are recognized over the requisite service or vesting period of an award based on the fair value of the award remeasured at each reporting period. Awards subject to performance criteria vest when it is probable that the performance criteria will be met and the requisite service period has been met. Generally, no compensation expense is recognized for equity instruments that do not vest. See Note 10 for further information.

New Accounting Pronouncements

Fair Value Measurements.  In May 2011, the 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. We adopted this guidance on January 1, 2012 prospectively and it did not have a material impact on our financial statements.

Offsetting Disclosure Requirements.  In December 2011, the FASB issued an accounting standard update intended to enhance current disclosure requirements on offsetting financial assets and liabilities. The new disclosure requirements will require the disclosure of both gross and net information about instruments and transactions eligible for offset in the balance sheet as well as instruments and transactions subject to an agreement similar to a master netting arrangement. Disclosure of collateral received and posted in connection with master netting agreements or similar arrangements is also required. The disclosures will be effective or annual and interim periods beginning on or after January 1, 2013, and must be applied retrospectively. We do not believe adoption of this new guidance will have a significant impact on our financial statements.

 

F-13

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

 

Note 3. Acquisitions and Divestitures

The acquisitions discussed below 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 acquisition costs associated with the acquisitions were expensed as incurred. 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.

2011 Acquisitions

Effective January 1, 2011, our predecessor acquired BP’s interests in wells located in Duval, Jim Hogg, McMullen and Webb counties located in Texas in exchange for our predecessor’s interest in approximately 10,700 net acres located in the Nueces Field of the Eagle Ford Shale located in South Texas and $20 million in cash, subject to certain closing adjustments. The transaction closed on May 31, 2011 and our predecessor paid a total of approximately $12.9 million in cash consideration at closing, net of adjustments.

The purchase price allocation resulted in the acquisition date fair value of $82.6 million allocated to proved oil and gas properties, $1.2 million allocated to asset retirement obligations, $0.5 million allocated to accrued liabilities and $0.6 million to deferred tax liabilities. After taking into consideration the net book value of the Nueces Field properties exchanged to BP of $5.2 million and the $12.9 million in cash consideration paid at closing, our predecessor recorded a $62.2 million gain during the year ended December 31, 2011.

On April 8, 2011, our predecessor acquired producing oil and natural gas properties in East Texas (the “Carthage Properties”) from a third party. Our predecessor estimated that as of April 8, 2011, the fair value of the Carthage Properties acquired was approximately $120.8 million, which our predecessor considered to be representative of the price paid by a typical market participant. The following table summarizes the fair value of the assets acquired and liabilities assumed as of April 8, 2011 (in thousands):

 

Recognized amounts of identifiable assets acquired and liabilities assumed:
Oil and gas properties		$					122,874
Other property and equipment							418
Suspense liabilities assumed							(664)
Environmental liabilities assumed							(387)
Asset retirement obligations							(1,461)
Total identifiable net assets		$					120,780

Summarized below are the results of operations for the years ended December 31, 2011 and 2010, on an unaudited pro forma basis, as if the BP and Carthage Properties acquisitions had occurred on January 1, 2010. The unaudited pro forma financial information was derived from the historical combined statements of operations of our predecessor, the statements of revenues and direct operating expenses for the BP and Carthage Properties and the historical accounting records of the sellers. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of expected future results of operations.

 

		2011								2010
		Actual				Pro Forma				Actual				Pro Forma
		(In thousands)								(In thousands)
BP and Carthage Properties:
Revenues		$	84,883			$	97,641			$	48,868			$	92,434
Net income (loss)		$	85,953			$	27,873			$	(7,647)			$	10,554

During the year ended December 31, 2011, approximately $8.3 million and $17.1 million of revenue and $2.3 million and $11.4 million of earnings were recorded in the statement of operations related to the BP and Carthage Properties acquisitions subsequent to their respective closing dates.

 

F-14

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

 

Effective July 1, 2011, our predecessor acquired producing oil and natural gas properties in Webb and Zapata counties located in South Texas. The net purchase price of $2.25 million was allocated to oil and natural gas properties. The acquisition closed on June 30, 2011.

Approximately $1.0 million of acquisition costs related to the 2011 acquisitions is included in other expense in the accompanying statements of operations for the year ended December 31, 2011.

2010 Acquisitions

Effective January 1, 2010, our predecessor acquired producing oil and natural gas properties in East Texas from Petrohawk Properties, LP for approximately $5.8 million. The net purchase price was allocated $5.8 million to proved oil and gas properties. The acquisition closed on May 28, 2010.

Effective March 1, 2010, our predecessor acquired oil and natural gas properties in East Texas from BP for approximately $8.2 million. The net purchase price was allocated to proved oil and gas properties. This acquisition closed on March 29, 2010.

Effective April 1, 2010, our predecessor acquired Forest Oil’s interests in wells located in Webb County, Texas (the “Forest Oil Properties”) for a net purchase price of approximately $65.9 million. The net purchase price was allocated to oil and gas properties. This acquisition of properties closed on June 30, 2010. Summarized below are the results of operations for the years ended December 31, 2010 and 2009, on an unaudited pro forma basis, as if this acquisition had occurred on January 1, 2009. The unaudited pro forma financial information was derived from the historical combined statement of operations of our predecessor and the statements of revenues and direct operating expenses for the Forest Oil Properties, which were derived from the historical accounting records of the seller. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor is such information indicative of expected future results of operations.

 

		2010								2009
		Actual				Pro Forma				Actual				Pro Forma
		(In thousands)								(In thousands)
Forest Oil Properties:
Revenues		$	48,868			$	57,536			$	32,351			$	48,622
Net income (loss)		$	(7,647)			$	(1,836)			$	2,363			$	12,888

Effective May 1, 2010, the Predecessor acquired Merit Energy’s (“Merit”) interest in wells located in South Texas for a net purchase price of approximately $14.1 million. The net purchase price was allocated as follows (in thousands):

 

Oil and gas properties		$					15,397
Prepaid assets							450
Assumed liabilities							(1,728)
Net purchase price		$					14,119

As part of the acquisition process, an environmental review was performed and it was determined that there was environmental damage to one of the acquired properties. As such, the parties agreed to reduce the purchase price by $550 thousand. Additionally, our predecessor and Merit entered into an escrow agreement whereby our predecessor agreed to pay for the initial $1.0 million of the remediation costs, with Merit paying for gross amounts incurred in excess of $1.0 million and up to $1.5 million. Our predecessor’s anticipated cost to remediate this area is $1.5 million. As of December 31, 2010, our predecessor recorded an accrued liability of $1.5 million for the anticipated costs to remediate this area. Merit funded an escrow account with the $0.5 million and that amount is included in the balance sheet as a prepaid asset. This acquisition closed on June 4, 2010. As of December 31, 2011, approximately $0.7 million of costs have been incurred and the approximately $0.8 million of remaining environmental accrued liability is recorded as a current liability in accrued liabilities.

Effective September 1, 2010, our predecessor acquired certain oil and gas properties in various counties in East Texas from a third party. This acquisition closed on December 16, 2010. The purchase price allocation resulted in the acquisition date fair value of $15.4 million allocated to proved oil and gas properties and $0.4 million allocated to asset retirement obligations. The Partnership purchased these properties form Memorial Resource on April 2, 2012. See Note 11 for information about the Partnership’s acquisitions of oil and gas properties from Memorial Resource in April and Note 1 for information regarding basis of presentation.

Effective May 1, 2010, our predecessor acquired Zachry Exploration, LLC’s interest in Laredo area properties for a net purchase price of $6.5 million. The net purchase price was allocated to oil and gas properties. This acquisition closed on August 3, 2010.

 

F-15

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

 

Effective April 1, 2010, our predecessor acquired U.S. Enercorp, LTD’s interest in wells located in McMullen County, Texas for a net purchase price of approximately $2.6 million. The net purchase price was allocated to oil and gas properties. This acquisition closed on May 28, 2010.

Our predecessor also acquired interests in oil and gas properties in a number of individually insignificant acquisitions during 2010 which aggregated to a total of approximately $6.0 million. Approximately $0.9 million of acquisition costs related to the 2010 acquisitions is included in other expense in the accompanying statements of operations for the year ended December 31, 2010.

2009 Acquisitions

Effective February 1, 2009, our predecessor acquired Coronado Energy E&P Company, LLC’s interest in Laredo area properties for a net purchase price of approximately $13.0 million. The net purchase price was allocated to oil and gas properties. This acquisition closed on March 16, 2009.

Our predecessor also acquired interests in oil and gas properties in a number of individually insignificant acquisitions during 2009, which aggregated to a total of approximately $3.8 million. Approximately $0.3 million of acquisition costs related to the 2009 acquisitions is included in other expense in the accompanying statements of operations for the year ended December 31, 2009.

Divestitures

During August 2011, our predecessor sold working interests related to the deep rights under approximately 4,200 acres in Webb County located in South Texas and options related to an additional 9,000 acres of deep rights in Webb County. Total cash consideration received by our predecessor in August 2011 was approximately $2.0 million, and a $0.8 million gain on the sale of properties was recognized for the year ended December 31, 2011 in the statement of operations. In November 2011, one of the options related to a portion of the 9,000 acres of deep rights was exercised for approximately $0.4 million of cash. No significant gain or loss was recognized related to this option exercise. The transactions did not involve the sale of any existing production.

On January 20, 2010, our predecessor sold its interests in the Saner wells for net proceeds of approximately $1.4 million. There was no significant gain or loss associated with this sale. In addition, during 2010, our predecessor received a settlement of approximately $1.2 million related to a property that our predecessor had not been given the opportunity to acquire despite a preferential right to acquire the property held by our predecessor. This settlement amount has been recorded in other income for the year ended December 31, 2010.

Effective January 8, 2009, our predecessor sold a portion of its interests in the Nueces Mineral Company lease (“NMC Lease”) for net proceeds of $2.7 million. Our predecessor sold additional interests in the NMC Lease effective May 1, 2009 for net proceeds of $9.0 million. Our predecessor recorded gains on these sales of approximately $7.8 million.

Subsequent Events

On September 28, 2012, we acquired certain oil and natural gas properties in East Texas from Goodrich Petroleum Corporation (“Goodrich Acquisition”), for a preliminary net purchase price of $93.2 million, subject to customary post-closing adjustments. The effective date of this transaction was July 1, 2012. This transaction was financed with borrowings under our revolving credit facility. These properties are located in the South Henderson Field of Rusk County, Texas.

On May 1, 2012, we acquired non-operating interests in certain oil and natural gas properties located in East Texas and North Louisiana from an undisclosed third party seller (“Undisclosed Seller Acquisition”) for a final net purchase price of approximately $36.5 million after customary post-closing adjustments. The effective date of this transaction was January 1, 2012. This transaction was financed with borrowings under our revolving credit facility. Because this transaction was a joint acquisition with Memorial Resource, 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.

 

F-16

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO 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 December 31, 2011 and 2010, 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 December 31, 2011 and 2010. 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 December 31, 2010 were based on quotes obtained from the counterparties to the agreements, whereas the fair market values of the derivative financial instruments reflected in the balance sheets as of 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 December 31, 2011 and 2010 for each of the fair value hierarchy levels:

 

		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
Assets:		(In thousands)
Commodity derivatives		$	--			$	39,206			$	--			$	39,206
Liabilities :
Commodity derivatives		$	--			$	3,591			$	--			$	3,591
Interest rate derivatives			--				278				--				278
Total liabilities		$	--			$	3,869			$	--			$	3,869

 

F-17

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

 

		Fair Value Measurements at December 31, 2010 Using
		Quoted Prices in     Active Market (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)				Fair Value
Assets:			(In thousands)
Commodity derivatives		$	--			$	8,388			$	--			$	8,388
Liabilities :
Commodity derivatives		$	--			$	478				--				478
Interest rate derivatives			--				403				--				403
Total liabilities		$	--			$	881			$	--			$	881

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: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital.

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. We have also entered into the International Swaps and Derivatives Association Master Agreements (“ISDA Agreements”) with each of our counterparties. The terms of the ISDA Agreements provide us and each of our counterparties with rights of set-off upon the occurrence of defined acts of default by either us or our counterparty to a derivative, whereby the party not in default may set-off all liabilities owed to the defaulting party against all net derivative asset receivables from the defaulting party. As a result, had our counterparties failed completely to perform according to the terms of the existing contracts, we would have the right to offset $35.6 million against amounts outstanding under our revolving credit facility. See Note 7 for additional information in regards to our revolving credit facility.

 

F-18

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

 

Commodity Derivatives

A combination of commodity derivatives (e.g., floating-for-fixed swaps, collars, put options, and basis swaps) is used to manage exposure to commodity price volatility. We enter into natural gas derivative contracts that are indexed to NYMEX Henry Hub and regional indices such as NGPL TXOK, TETCO STX, and Houston Ship Channel in proximity to the Partnership’s areas of production. We also enter into oil derivative contracts indexed to NYMEX WTI and NGL derivative contracts indexed to OPIS Mont Belvieu. At December 31, 2011, we had the following open commodity positions:

 

		2012				2013				2014				2015				2016
Natural Gas Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (MMBtu)			357,498				451,052				772,740				781,578				865,165
Weighted-average fixed price		$	5.09			$	4.67			$	4.44			$	4.44			$	4.70
Collar contracts:
Average Monthly Volume (MMBtu)			664,500				633,000				120,000				80,000				--
Weighted-average floor price		$	4.75			$	4.78			$	5.08			$	5.25			$	--
Weighted-average ceiling price		$	5.85			$	5.82			$	6.31			$	6.75			$	--
Put options:
Average Monthly Volume (MMBtu)			70,000				--				--				--				--
Weighted-average strike price		$	4.80			$	--			$	--			$	--			$	--
Basis swaps:
Average Monthly Volume (MMBtu)			353,633				405,932				--				--				--
Spread		$	(0.14)			$	(0.16)			$	--			$	--			$	--
Crude Oil Derivative Contracts:
Fixed price swap contracts:
Average Monthly Volume (Bbls)			1,790				1,540				2,250				--				--
Weighted-average fixed price		$	92.00			$	92.00			$	87.90			$	--			$	--
Collar contracts:
Average Monthly Volume (Bbls)			4,500				4,750				3,200				--				--
Weighted-average floor price		$	86.67			$	87.16			$	90.00			$	--			$	--
Weighted-average ceiling price		$	115.12			$	116.94			$	117.72			$	--			$	--
NGL Derivative Contracts:
Collar contracts:
Average Monthly Volume (Bbls)			3,800				--				--				--				--
Weighted-average floor price		$	75.16			$	--			$	--			$	--			$	--
Weighted-average ceiling price		$	93.57			$	--			$	--			$	--			$	--

 

F-19

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

 

Interest Rate Swaps

Partnership. 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 December 31, 2011, 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%

Predecessor. Periodically, our predecessor entered into interest rate swaps to mitigate exposure to market rate fluctuations by converting variable interest rates to fixed interest rates. During the year ended December 31, 2011, our predecessor had the following fixed-for floating interest rate swap open positions whereby our predecessor received the floating rate and paid the fixed rate:

 

Period Covered		Notional ($ in thousands)				Floating Rate		Fixed Rate
April 2011 to April 2014 (1)		$	30,000			1 Month LIBOR			1.510%
June 2010 to June 2012 (1)		$	50,000			1 Month LIBOR			1.000%
February 2009 to February 2011		$	8,400			3 Month LIBOR			1.620%
(1)    These interest rate swap agreements were not acquired by the Partnership at its IPO in December 2011.

Balance Sheet Presentation

The following table summarizes 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 the net recorded fair value as reflected on the balance sheet at December 31:

 

				Asset Derivatives								Liability Derivatives
Type		Balance Sheet Location		2011				2010				2011				2010
				(In thousands)
Natural gas contracts		Short-term derivative instruments		$	22,930			$	4,120			$	44			$	79
Oil contracts		Short-term derivative instruments			83				--				250				81
NGL contracts		Short-term derivative instruments			166				--				--				--
Interest rate swaps		Short-term derivative instruments			--				--				162				153
Gross fair value					23,179				4,120				456				313
Netting arrangements		Short-term derivative instruments			(110)				(329)				(110)				(204)
Net recorded fair value		Short-term derivative instruments		$	23,069			$	3,791			$	346			$	109
Natural gas contracts		Long-term derivative instruments		$	15,595			$	4,268			$	3,034			$	209
Oil contracts		Long-term derivative instruments			432				--				263				109
NGL contracts		Long-term derivative instruments			--				--				--				--
Interest rate swaps		Long-term derivative instruments			--				--				116				250
Gross fair value					16,027				4,268				3,413				568
Netting arrangements		Long-term derivative instruments			(2,373)				(334)				(2,373)				(459)
Net recorded fair value		Long-term derivative instruments		$	13,654			$	3,934			$	1,040			$	109

(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 years ending December 31, 2011, 2010 and 2009:

 

F-20

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

 

				Years Ended December 31,
		Statements of Operations Location		2011				2010				2009
				(In thousands)
Commodity derivative contracts		Realized (gain) loss on commodity derivatives		$	(7,944)			$	(7,294)			$	(17,574)
Commodity derivative contracts		Unrealized (gain) loss on commodity derivatives			(25,381)				(3,919)				6,453
Interest rate swaps (1)		Interest expense			(1,261)				(576)				(165)
(1)     Included in the amounts are net cash payments of approximately $0.5, $0.3 and $0.5 million for the years ended December 31, 2011, 2010 and 2009, respectively.

Note 6. Asset Retirement Obligations

The fair value of our asset retirement obligations related to the plugging, abandonment, and remediation of oil and gas producing properties has been recognized. The present value of the estimated asset retirement costs has been capitalized as part of the carrying amount of the related long-lived assets. The liability has been accreted to its present value as of December 31, 2011 and 2010. Our wells have been evaluated and abandonment dates extend through 2061.

The following table represents a reconciliation of the asset retirement obligations for the years ended December 31, 2011, 2010, and 2009:

 

		2011				2010				2009
		(In thousands)
Asset retirement obligations at beginning of year		$	11,472			$	4,023			$	3,427
Liabilities added from acquisitions or drilling			3,061				7,574				1,136
Liabilities removed upon sale of wells			(64)				(19)				(124)
Accretion expense			1,069				672				326
Revision of estimates			(591)				(778)				(742)
Liabilities retained by our predecessor			(834)				--				--
Asset retirement obligations at end of year		$	14,113			$	11,472			$	4,023

Note 7. Long Term Debt

Revolving Credit Facility

Concurrently with the closing of our IPO on December 14, 2011, OLLC entered into a new senior secured revolving credit facility, which facility is guaranteed by us and all of our current and future subsidiaries. This revolving credit facility is a five-year, $1.0 billion revolving credit facility with an initial borrowing base of $300.0 million. The borrowing base is subject to redetermination on at least a semi-annual basis based on an engineering report with respect to our estimated oil, NGL and natural gas reserves, which will take into account the prevailing oil, NGL and natural gas prices at such time, as adjusted for the impact of commodity derivative contracts. Unanimous approval by the lenders is required for any increase to the borrowing base. See Note 7 for additional information regarding our increased borrowing base that became effective September 28, 2012 and the ability to incur second lien indebtedness.

Borrowings under our revolving credit facility are secured by liens on substantially all of our properties, but in any event, not less than 80% of the total value of the our oil and natural gas properties, and all of our equity interests in OLLC and any future guarantor subsidiaries and all of our other assets including personal property. Additionally, borrowings under our revolving credit facility bear interest, at our option, at either (i) the greatest of (x) the prime rate as determined by the administrative agent, (y) the federal funds effective rate plus 0.50%, and (z) the one-month adjusted LIBOR plus 1.0% (adjusted upwards, if necessary, to the next 1/100th of 1%), in each case, plus a margin that varies from 0.75% to 1.75% per annum according to the borrowing base usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect), or (ii) the applicable LIBOR plus a margin that varies from 1.75% to 2.75% per annum according to the borrowing base usage. The unused portion of the borrowing base will be subject to a commitment fee that varies from 0.375% to 0.50% per annum according to the borrowing base usage.

Our revolving credit facility requires us to maintain a ratio of Consolidated EBITDAX to Consolidated Net Interest Expense (as each term is defined under our revolving credit facility), which we refer to as the interest coverage ratio, of not less than 2.5 to 1.0, and a ratio of consolidated current assets to consolidated current liabilities, each as determined under our revolving credit facility, of not less than 1.0 to 1.0.

 

F-21

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

 

Additionally, our revolving credit facility contains various covenants and restrictive provisions that, among other things, limit our ability to incur additional debt, guarantees or liens; consolidate, merge or transfer all or substantially all of our assets; make certain investments, acquisitions or other restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; incur commodity hedges exceeding a certain percentage of production; and prepay certain indebtedness.

Events of default under our revolving credit facility include the failure to make payments when due, breach of any covenants continuing beyond the cure period, default under any other material debt, change in management or change of control, bankruptcy or other insolvency event and certain material adverse effects on the business of OLLC or us.

If we fail to perform our obligations under these or any other covenants, the revolving credit commitments could be terminated and any outstanding indebtedness under our revolving credit facility, together with accrued interest, fees and other obligations under the credit agreement, could be declared immediately due and payable.

At December 31, 2011, we had $120.0 million outstanding under the facility. The effective weighted average interest rate for the period from December 14, 2011 through December 31, 2011 was 2.81%.

Subsequent Event. On September 18, 2012, we entered into a second amendment to our credit agreement, which among other things: (i) increased the borrowing base to $380.0 million upon closing of the Goodrich Acquisition and (ii) provided us with the ability to incur certain second lien indebtedness. The next borrowing base redetermination is scheduled for April 2013; however, we may seek an interim redetermination if the need arises.

Predecessor

Our predecessor had debt outstanding under three separate revolving credit facilities, none of which was assumed by us in connection with our IPO. Although the Partnership did not legally assume the debt of its predecessor, for accounting and financial reporting purposes the $198.3 million that was repaid concurrent with the closing of our IPO on behalf of our predecessor (see Note 1) has been netted against the net book value of the net assets that were acquired by us and reflected on our consolidated and combined cash flow statement as “Payments on revolving credit facility – predecessor.” At December 31, 2010, $80.2 million was outstanding under BlueStone’s $150.0 million revolving credit facility. BlueStone also had $0.4 million in letters of credit outstanding under its credit facility. The weighted average interest rate for the years ended December 31, 2011, 2010 and 2009 was approximately 3.17%, 3.45% and 4.88%, respectively. At December 31, 2010, BlueStone was in compliance with its debt covenants.

The Classic Carve-Out properties were burdened by debt incurred pursuant to a $150.0 million revolving credit facility extended to Classic. Of the $105.0 million outstanding under this facility at December 31, 2010, $35.1 million pertained to the Classic Carve-Out properties. The weighted average interest rate for the years ended December 31, 2011, 2010 and 2009 was 3.40%, 3.11% and 3.60%, respectively. At December 31, 2010 Classic was in compliance under existing debt covenants.

The WHT Assets were burdened by debt incurred pursuant to a $400.0 million revolving credit facility extended to WHT on April 8, 2011, of which $160.0 million pertained to the WHT assets. The borrowing base was $230.0 million, of which $92.0 million pertained to the WHT assets. The weighted average interest rate for the period from April 8, 2011 through the closing of our IPO was 2.79%.

Note 8. Equity and Distributions

Initial Public Offering of Memorial Production Partners LP

On December 14, 2011, we completed our IPO of 9,000,000 common units representing limited partner interests in the Partnership at $19.00 per common unit for total net proceeds of approximately $146.5 million. In connection with our IPO, 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 (see Note 1). The cash portion of this consideration was financed with approximately $130.0 million in borrowings under a new senior securing revolving credit facility (see Note 7) and the net cash proceeds generated from our IPO.

On December 22, 2011, the underwriters exercised their over-allotment option to purchase an additional 600,000 common units issued by the Partnership under the IPO terms. Total net proceeds from the exercise of the underwriters’ over-allotment option, after deducting estimated offering costs, were $10.7 million.

 

F-22

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

 

Equity Outstanding

Upon completion of our IPO and the underwriters’ exercise of their over-allotment option, we had 16,661,294 common units, 5,360,912 subordinated units and 22,044 general partner units outstanding. Following our IPO and the underwriters’ exercise of their over-allotment option, Memorial Resource owned approximately 42.4% of the common units and 100% of the subordinated units. Memorial Resource owns all of the voting interests in our general partner, and the Funds own non-voting membership interests in our general partner that entitle them collectively to 50% of all cash distributions and common units received by our general partner in respect of the Partnership’s incentive distribution rights.

Common & Subordinated Units. The common units and the subordinated units are separate classes of limited partner interest in us and have limited voting rights as set forth in our partnership agreement. The holders of units are entitled to participate in partnership distributions as discussed further below under Cash Distribution Policy and exercise the rights or privileges available to limited partners under our partnership agreement.

Pursuant to our partnership agreement, if at any time our general partner and its affiliates own more than 80% of the outstanding common units, our general partner has the right, but not the obligation, to purchase all of the remaining common units at a purchase price not less than the then-current market price of the common units, as calculated pursuant to the terms of our partnership agreement.

General Partner Interest. Our general partner owns a 0.1% interest in us. This interest entitles our general partner to receive distributions of available cash from operating surplus as discussed further below under “Cash Distributions. Our partnership agreement sets forth the calculation to be used to determine the amount and priority of cash distributions that the common unitholders, subordinated unitholders, and general partner will receive. The general partner has the management rights as set forth in our partnership agreement.

Allocations of Net Income (Loss)

Net income (loss) is allocated between our general partner and the common and subordinated unitholders in proportion to their pro rata ownership during the period after our IPO through December 31, 2011. For periods prior to our IPO, net income (loss) was attributable solely to our predecessor.

Cash Distribution Policy

We intend to make cash distributions to unitholders on a quarterly basis, although there is no assurance as to the future cash distributions since they are dependent upon future earnings, cash flows, capital requirements, financial condition and other factors. Additionally, under our revolving credit facility, we will not be able to pay distributions to unitholders in any such quarter in the event there exists a borrowing base deficiency or an event of default either before or after giving effect to such distribution or we are not in pro forma compliance with our revolving credit facility after giving effect to such distribution.

Available Cash.  Our partnership agreement requires that within 45 days after the end of each quarter, beginning with the quarter ending December 31, 2011, we distribute all of our available cash (as defined in our partnership agreement) to our general partner and unitholders of record on the applicable record date. Generally, available cash refers to all cash on hand at the end of the quarter less cash reserves established by our general partner to: (i) operate our business (e.g., future capital expenditures, working capital and operating expenses); (ii) comply with applicable law, debt, and other agreements; and (iii) provide funds for distribution to our unitholders (including our general partner) for any one or more of the next four quarters. If our general partner so determines, available cash may include borrowings made after the end of the quarter.

General Partner Interest and Incentive Distribution Rights.  Our general partner is entitled to 0.1% of all distributions of available cash that we make prior to our liquidation. Our general partner’s initial 0.1% interest in these distributions may be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its initial 0.1% general partner interest. Our general partner is not obligated to contribute a proportionate amount of capital to us to maintain its current general partner interest. Our general partner also holds the incentive distribution rights, which entitle the holder to additional increasing percentages, up to a maximum of 24.9%, of the cash we distribute in excess of $0.59375 per common unit per quarter.

 

F-23

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

 

Minimum Quarterly Distribution.  During the subordination period, the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $0.4750 per common unit plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions from operating surplus until the common units have received the minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be available cash from operating surplus to be distributed on the common units.

Our partnership agreement requires that we make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:

 

•

first, 99.9% to the common unitholders, pro rata, and 0.1% to our general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;

 

•

second, 99.9% to the common unitholders, pro rata, and 0.1% to our general partner, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;

 

•

third, 99.9% to the subordinated unitholders, pro rata, and 0.1% to our general partner, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and

 

•

thereafter, cash in excess of the minimum quarterly distributions is distributed to the unitholders and the general partner based on the percentages in the table below.

Our general partner is entitled to incentive distributions if the amount we distribute with respect to one quarter exceeds specified target levels shown below:

 

		Total Quarterly Distributions Target Amount		Marginal Percentage Interest in Distributions
				Unitholders				General Partner
Minimum Quarterly Distribution		$0.4750			99.9%				0.1%
First Target Distribution		up to $0.54625			99.9%				0.1%
Second Target Distribution		above $0.54625 up to $0.59375			85.0%				15.0%
Thereafter		above $0.59375			75.0%				25.0%

Our partnership agreement requires that we make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:

 

•

first, 99.9% to all unitholders, pro rata, and 0.1% to our general partner, until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and

 

•

thereafter, cash in excess of the minimum quarterly distributions is distributed to the unitholders and the general partner based on the percentages in the table above.

The subordination period will extend until the first business day after the distribution to unitholders in respect of any quarter ending on or after December 31, 2014 that each of the following tests are met:

 

•

Distributions of available cash from operating surplus on each of the outstanding common units, subordinated units and general partner units and any other partnership interests that are senior or equal in right of distribution to the subordinated units equaled or exceeded, in the aggregate, the sum of the minimum quarterly distributions payable with respect to a period of twelve consecutive quarters immediately preceding such date;

 

F-24

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

 

•

The “adjusted operating surplus” (as defined in our partnership agreement) generated during the period of twelve consecutive quarters immediately preceding that date equaled or exceeded, in the aggregate, the sum of the minimum quarterly distributions on all of the outstanding common units, subordinated units and general partner units and any other partnership interests that are senior or equal in right of distribution to the subordinated units that were outstanding during these periods payable with respect to such period on a fully diluted weighted average basis; and

 

•

there are no arrearages in payment of the minimum quarterly distribution on the common units.

When the subordination period ends, each outstanding subordinated unit will convert into one common unit and will then participate pro rata with the other common units in distributions of available cash.

In addition, if the unitholders remove our general partner other than for cause and units held by our general partner and its affiliates are not voted in favor of such removal:

 

•

the subordination period will end and each subordinated unit will immediately convert into one common unit;

 

•

any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and

 

•

our general partner will have the right to convert its general partner units into common units or to receive cash in exchange for such general partner units at the equivalent common unit fair market value

The subordination period will also automatically terminate, and all of the subordinated units will convert into an equal number of common units, on the first business day after the distribution to unitholders in respect of any quarter ending on or after December 31, 2012, if the following tests are met:

 

•

distributions of available cash from operating surplus on each of the outstanding common units, subordinated units and general partner units and any other partnership interests that are senior or equal in right of distribution to the subordinated units equaled or exceeded $0.59375 (125% of the minimum quarterly distribution) per quarter for the four quarter period immediately preceding that date;

 

•

the “adjusted operating surplus” generated during the four-quarter period immediately preceding that date equaled or exceeded the sum of a distribution of $2.3750 (125% of the annualized minimum quarterly distribution) on all of the outstanding common units, subordinated units and general partner units and any other partnership interests that are senior or equal in right of distribution to the subordinated units, in each case that were outstanding during such four quarter period on a fully diluted weighted average basis, and the corresponding distributions on the incentive distribution rights; and

 

•

there are no arrearages in payment of the minimum quarterly distribution on the common units.

Our general partner has the right (but not the obligation), at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (25%, assuming it has maintained its 0.1% general partner interest) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our cash distribution at the time of the exercise of the reset election.

Cash Distributions to Unitholders

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

 

Quarter		Declaration Date		Record Date		Payable Date		Amount Per Unit (1)				Aggregate Distribution				Distribution Received by Memorial Resource
3rd Quarter 2012		October 19, 2012		November 1, 2012		November 12, 2012		$	0.4950			$	11.1			$	6.2
2nd Quarter 2012		July 19, 2012		August 1, 2012		August 13, 2012		$	0.4800			$	10.7			$	6.0
1st Quarter 2012		April 19, 2012		May 1, 2012		May 14, 2012		$	0.4800			$	10.7			$	6.0
4th Quarter 2011		January 26, 2012		February 6, 2012		February 13, 2012		$	0.0929			$	2.0			$	1.2
(1)     The $0.0929 per unit pro-rated distribution paid on February 13, 2012 was based upon the minimum quarterly distribution of $0.4750 per unit adjusted to take into account the 18-day period of the fourth quarter of 2011 during which the Partnership was a public entity.

 

F-25

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

 

Predecessor Capital

BlueStone. BlueStone is a wholly-owned subsidiary of BlueStone Natural Resources Holdings, LLC (“Holdings”), whose sole purpose is to provide financing for BlueStone. In February 2006, BlueStone, Holdings and Holdings’ members entered into a subscription and contribution agreement whereby all equity contributions made by Holdings’ members in exchange for equity units would be transferred directly to BlueStone. NGP VIII and certain members of BlueStone’s management committed equity contributions of $75.7 million and $9.0 million under this agreement and amendments thereto, respectively, all of which was contributed by December 31, 2009. In 2010, BlueStone received an equity contribution from members of Holdings of an additional $40.0 million, including equity contributions of $4.2 million from management. NGP VIII advanced certain members of management $4.2 million to fund their equity contributions in 2010 in exchange for notes payable issued by management. BlueStone did not receive any capital contributions during 2011.

Classic. In June 2006, NGP VIII and certain members of Classic’s management entered into a partnership agreement. The Classic partners agreed to contribute an aggregate $135.9 million under the partnership agreement and amendments thereto, including $35.7 million allocable to the Classic Carve-Out. NGP VIII and certain members of Classic’s management committed equity contributions of $123.0 million and $12.9 million, respectively, all of which had been contributed as of January 24, 2011. In 2010, Classic received capital contributions of $19.7 million, net of equity financing fees, from its partners, including $4.1 million allocable to Classic Carve-Out. In 2011, Classic received capital contributions of $21.9 million, net of equity financing fees, from its partners, including $4.8 million allocable to Classic Carve-Out.

WHT. In February 2011, WHT was formed by WildHorse and Tanos. NGP IX and NGP IX Offshore collectively funded 100% of the cash used by WildHorse and Tanos to fund their respective capital contributions to WHT. In 2011, WildHorse and Tanos each contributed $64.7 million to WHT, of which an aggregate $51.8 million was allocable to our predecessor.

Note 9. Earnings per Unit

The following sets forth the calculation of earnings per unit, or EPU, for the period from December 14, 2011 to December 31, 2011 (in thousands, except per unit amounts):

 

Net income attributable to partners		$					6,592
Less: General partner’s 0.1% interest in net income							7
Limited partners’ interest in net income		$					6,585
Weighted average limited partner units outstanding:
Common units							16,395
Subordinated units							5,361
Total							21,756
Basic and diluted EPU		$					0.30

Note 10. Equity-based Awards

Long-Term Incentive Plan

In December 2011, the board of directors of our general partner (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 became effective upon filing of a registration statement on Form S-8 with the SEC on December 14, 2011. 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. No awards had been granted as of December 31, 2011.

 

F-26

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

 

Subsequent Event. As indicated in the following table, multiple awards of restricted common units have been granted under the LTIP:

 

Grant Date		Number of Restricted Units				Award Recipient
January 9, 2012			173,949			Executive Officers of our general partner
January 9, 2012			3,421			Independent Director of our general partner
March 7, 2012			3,511			Independent Director of our general partner
May 31, 2012			95,254			Executive Officers of our general partner and other Memorial Resource employees
August 3, 2012			1,535			Independent Director of our general partner
August 31, 2012			10,273			Other Memorial Resource employees

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.

Note 11. Related Party Transactions

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

 

		2011				2010
Accounts Receivable/(Payable) – Affiliates:
Memorial Resource		$	377				--
BlueStone			2,142			$	--
Classic			436				--
WHT			(1,024)				--
Total		$	1,931			$	--
Accounts payable:
Certain directors of our predecessor entities		$	--			$	32

For the years ended December 31, 2011, 2010, and 2009, respectively, there was less than $0.2 million of related party transactions recognized in the accompanying statements of operations.

Partnership

We have entered into agreements with Memorial Resource and our general partner pursuant to which, among other things, we will make payments to Memorial Resource. These agreements include the following:

 

•

an omnibus agreement pursuant to which, among other things, Memorial Resource provides management, administrative and operating services for us and our general partner; and

 

•

a 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). It is possible that Memorial Resource or its applicable affiliate(s) may use its tax attributes to cause its combined or consolidated group, of which we may be a member for this purpose, to owe less or no tax. In such a situation, we would pay Memorial Resource or its applicable affiliate(s) the tax we would have owed had the tax attributes not been available or used for our benefit, even though Memorial Resource or its applicable affiliate(s) had no cash tax expense for that period. Currently, the Texas margin tax (which has a maximum effective tax rate of 0.7% of gross income apportioned to Texas) is the only tax that is included in a combined or consolidated tax return with Memorial Resource or its applicable affiliate(s).

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 reimburse Memorial Resource approximately $0.1 million for the monthly management fees that it pays to its affiliates.

 

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

 

Our Predecessor

The majority partner of our predecessor, NGP VIII, is an affiliate of certain directors of the entities comprising our predecessor. For the periods ended December 31, 2011, 2010 and 2009, our predecessor expensed advisory and directors’ fees of approximately $0.2 million, $0.2 million, and $0.1 million, respectively, to NGP VIII. At December 31, 2010, less than $0.1 million related to these fees was recorded as a related party payable.

The WHT Assets are operated by WildHorse. Under the terms of a management agreement dated April 8, 2011, WildHorse assumed certain responsibilities for the management of WHT, including the day-to-day operations of the company providing executive, administrative, land, financial, and accounting services and operating WHT’s properties. Under the terms of the agreement, WHT paid WildHorse an approximate $0.1 million monthly management fee, of which 40% was allocable to the WHT Assets. Additionally, WHT pays Tanos less than $0.1 million per month, of which 40% was allocable to the WHT Assets, for certain services that it provides WHT, primarily managing its exploration program. These amounts are payable monthly in advance on the first of each month. At the closing of our IPO, there were no outstanding management, operation and administration fees payable.

In addition to the management fees, both WildHorse and Tanos are entitled to recover from WHT certain expenditures made on its behalf that are not covered by the management fees described above. These amounts include certain payments for third-party professional services and other non-routine direct general and administrative expenses, costs incurred in the operation and development of the properties, and amounts paid to the other operators for WHT’s non-operated interests.

As the operator of the properties, WildHorse also markets WHT’s oil, gas and NGL production, collects the proceeds, pays the related production taxes and disburses amounts owed to royalty and other working interest owners. WildHorse also receives sales proceeds from the operators for the sale of non-operated production.

Acquisition of Oil & Gas Producing Properties Subsequent to our IPO

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, subject to customary post-closing adjustments. This transaction was financed with borrowings under our revolving credit facility. The transaction also included the novation to the Partnership of certain commodity positions with effective dates 2012 through 2013. 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.

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, subject to customary post-closing adjustments. This transaction was financed with borrowings under our revolving credit facility. The transaction also included the novation to the Partnership of certain commodity derivative positions with effective dates 2012 through 2014. 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.

Acquisitions of oil and gas properties from Memorial Resource are accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby the net assets acquired are recorded at Memorial Resource’s carrying value and certain financial and other information are retrospectively revised to give effect to such acquisitions as if the Partnership had owned the assets beginning on the dates Memorial Resource originally acquired them. See Note 1 for information about the Partnership’s basis of presentation in regards to its acquisitions of oil and gas properties from Memorial Resource in April and May 2012.

See Note 1 for information regarding basis of presentation.

 

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

 

Entry into Definitive Purchase and Sale Agreement Subsequent to our IPO

On November 19, 2012, we entered into a definitive purchase and sale agreement with Rise Energy Partners, LP (“Rise”) to acquire Rise Energy Operating, LLC, which owns certain operating interests in producing and non-producing oil and gas properties offshore Southern California, for a purchase price of $271.0 million, which includes $3.0 million of working capital and other customary adjustments (the “Beta Acquisition”). We have the ability to finance this transaction through borrowings under our revolving credit facility and promissory notes payable to Rise. The Beta Acquisition is expected to close in December 2012. Terms of the transaction were approved by the Board and by its conflicts committee, which is comprised entirely of independent directors. On November 19, 2012, the Board also approved, subject to the completion of the Beta Acquisition, an increase in our distribution rate attributable to the fourth quarter of 2012 to $0.5075 per unit.

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.

Environmental costs for remediation are accrued based on estimates of known remediation requirements. Such accruals are based on management’s best estimate of the ultimate cost to remediate a site and are adjusted as further information and circumstances develop. Those estimates may change substantially depending on information about the nature and extent of contamination, appropriate remediation technologies and regulatory approvals. Expenditures to mitigate or prevent future environmental Nocontamination are capitalized. Ongoing environmental compliance costs are charged to expense as incurred. In accruing for environmental remediation liabilities, costs of future expenditures for environmental remediation are not discounted to their present value, unless the amount and timing of the expenditures are fixed or reliably determinable. At December 31, 2011, none of our estimated environmental remediation liabilities were discounted to present value since the ultimate amount and timing of cash payments for such liabilities were not readily determinable.

The following table presents the activity of our environmental reserves for the periods presented:

 

		2011				2010				2009
		(In thousands)
Balance at beginning of period		$	1,450			$	--			$	--
Charged to costs and expenses			--				--				--
Acquisition-related additions			387				1,450				--
Payments			(671)				--				--
Balance at end of period		$	1,166			$	1,450			$	--

At December 31, 2011 and 2010, $0.8 million and $1.5 million, respectively, of our environmental reserves were classified as current liabilities in accrued liabilities.

Operating Leases

We lease certain equipment and office space under operating leases. Amounts shown in the following table represent minimum lease payment obligations under our operating leases, the majority of which are compressor lease rentals. We recognized an immaterial amount of rent expense since our IPO, primarily for office space allocated to us from Memorial Resource.

Our predecessor leased equipment and office space under various operating leases. Our predecessor recorded rent expense of approximately $0.3 million, $0.3 million, and $0.2 million for the years ended December 31, 2011, 2010, and 2009, respectively.

 

		Payment or Settlement due by Period
Lease Obligations		Total				2012				2013				2014				2015				2016				Thereafter
		(In thousands)
Operating leases		$	734			$	682			$	48			$	4			$	--			$	--			$	--

 

F-29

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

 

Note 13. Defined Contribution Plan

Memorial Resource sponsors a defined contribution plan to substantially all employees who have attained 18 years of age. The plan allows eligible employees to make tax-deferred contributions up to 100% of their annual compensation, not to exceed annual limits established by the Internal Revenue Service. Memorial Resource makes matching contributions of 100% of employee contributions that does not exceed 6% of compensation. Employees are immediately vested in these matching contributions. This plan became effective on January 1, 2012.

The companies comprising our predecessor also sponsored defined contribution plans as well for the benefit of substantially all their employees who attained 18 years of age. Our predecessor made matching contributions of up to 6% of an employee’s compensation and had the option to make additional discretionary contributions for eligible employees meeting certain plan requirements. Our predecessor made contributions to the plan of approximately $0.2 million, $0.2 million, and $0.2 million in 2011, 2010 and 2009, respectively.

Note 14. Quarterly Financial Information (Unaudited)

The following table presents selected quarterly financial data for the periods indicated:

 

		First Quarter				Second Quarter				Third Quarter				Fourth Quarter
For the Year Ended December 31, 2011:		(In thousands, except per unit amounts)
Revenues		$	14,285			$	23,176			$	25.550			$	21,872
Operating income (loss)			(910)				66,787				17,517				9,949
Net income (loss)			(1,945)				64,459				15,325				8,114
Net income (loss) attributable to predecessor			(1,945)				64,459				15,325				1,522
Net income attributable to partners			n/a				n/a				n/a				6,592
Earnings per unit			n/a				n/a				n/a				0.30
For the Year Ended December 31, 2010:
Revenues		$	10,968			$	10,355			$	13,534			$	14,011
Operating income (loss)			6,210				(2,665)				4,173				(10,702)
Net income (loss)			5,604				(3,887)				2,596				(11,960)
Net income (loss) attributable to predecessor			5,604				(3,887)				2,596				(11,960)
Net income attributable to partners			n/a				n/a				n/a				n/a
Earnings per unit			n/a				n/a				n/a				n/a

As discussed in Note 1, we closed our IPO on December 14, 2011 and we acquired additional oil and gas properties from Memorial Resource subsequent to our IPO in April and May 2012; therefore, the quarterly financial information presented above for periods prior to December 14, 2011 is that of our predecessor. See Note 2 and 9 for additional information regarding earnings per unit.

Note 15. Supplemental Oil and Gas Information (Unaudited)

Capitalized Costs Relating to Oil and Natural Gas Producing Activities

The total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depreciation, depletion and amortization is as follows at the dates indicated.

 

		December 31,
		2011				2010				2009
		(In thousands)
Evaluated oil and natural gas properties		$	560,248			$	351,993			$	215,427
Unevaluated oil and natural gas properties			--				15,385				5,445
Accumulated depletion, depreciation, and amortization			(111,611)				(102,969)				(66,245)
Total		$	448,637			$	264,409			$	154,627

 

F-30

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

 

Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities

Costs incurred in property acquisition, exploration and development activities were as follows for the periods indicated:

 

		Years Ended December 31,
		2011				2010				2009
		(In thousands)
Property acquisition costs, proved		$	138,175			$	119,511			$	17,455
Exploration and extension well costs			16,192				6,287				6,808
Development			17,336				10,267				29,417
Total		$	171,703			$	136,065			$	53,680

Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves

As required by the FASB and SEC, the standardized measure of discounted future net cash flows presented below is computed by applying first-day-of-the-month average prices, year-end costs and legislated tax rates and a discount factor of 10 percent to proved reserves. We do not believe the standardized measure provides a reliable estimate of the Partnership's expected future cash flows to be obtained from the development and production of its oil and gas properties or of the value of its proved oil and gas reserves. The standardized measure is prepared on the basis of certain prescribed assumptions including first-day-of-the-month average prices, which represent discrete points in time and therefore may cause significant variability in cash flows from year to year as prices change.

Oil and Natural Gas Reserves

Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.

Proved reserves are those quantities of oil and natural gas that 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.

Netherland, Sewell & Associates, Inc. (“NSAI”), our independent reserve engineers, were engaged to prepare portions of our reserves estimates comprising approximately 85% of our estimated proved reserves (by volume) at December 31, 2011. Internal reserve engineers employed by Memorial Resource prepared approximately 15% of our estimated proved reserves (by volume) at December 31, 2011. All proved reserves are located in the United States and all prices are held constant in accordance with SEC rules.

The benchmark product prices used for valuing the reserves are based upon the average of the first-day-of-the-month price for each month within the period January through December of each year presented:

 

F-31

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

 

		2011				2010				2009
Oil ($/Bbl):
West Texas Intermediate spot (1)		$	93.21			$	76.34			$	58.02
NGL ($/Bbl):
West Texas Intermediate spot (1)		$	93.77			$	76.95			$	--
Natural Gas ($/MMbtu):
Henry Hub spot (2)		$	4.118			$	4.376			$	3.861

(1)     The weighted average West Texas Intermediate spot price was adjusted by lease for quality, transportation fees, and a regional price differential.   (2)     The weighted average Henry Hub spot price was adjusted by lease for energy content, compression charges, transportation fees, and regional price differentials.

The following tables set forth estimates of the net reserves as of December 31, 2011, 2010 and 2009, respectively:

 

		Year Ended December 31, 2011
		Oil       (MBbls)				Gas       (MMcf)				NGLs       (MBbls)				Equivalent       (Mmcfe)
Proved developed and undeveloped reserves:
Beginning of year			1,142				173,125				627				183,745
Extensions and discoveries			222				25,247				1,360				34,743
Purchase of minerals in place			1,030				136,345				4,146				167,399
Production			(97)				(15,936)				(182)				(17,608)
Reserves retained by our predecessor			(23)				(3,198)				--				(3,335)
Revision of previous estimates			134				12,633				812				18,297
End of year			2,408				328,216				6,763				383,241
Proved developed reserves:
Beginning of year			1,030				145,478				384				153,970
End of year			1,852				250,986				3,975				285,950
Proved undeveloped reserves:
Beginning of year			112				27,647				243				29,775
End of year			556				77,230				2,788				97,291

 

		Year Ended December 31, 2010
		Oil       (MBbls)				Gas       (MMcf)				NGLs       (MBbls)				Equivalent       (Mmcfe)
Proved developed and undeveloped reserves:
Beginning of year			826				71,647				--				76,604
Extensions and discoveries			58				7,602				212				9,225
Purchase of minerals in place			326				88,125				1				90,085
Production			(62)				(9,151)				(69)				(9,940)
Sale of minerals in place			--				--				--				--
Revision of previous estimates			(6)				14,902				483				17,771
End of year			1,142				173,125				627				183,745
Proved developed reserves:
Beginning of year			774				57,804				--				62,449
End of year			1,030				145,478				384				153,970
Proved undeveloped reserves:
Beginning of year			52				13,843				--				14,155
End of year			112				27,647				243				29,775

 

F-32

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MEMORIAL PRODUCTION PARTNERS LP

NOTES TO CONSOLIDATED AND PREDECESSOR COMBINED FINANCIAL STATEMENTS

 

		Year Ended December 31, 2009
		Oil       (MBbls)				Gas       (MMcf)				NGLs       (MBbls)				Equivalent       (Mmcfe)
Proved developed and undeveloped reserves:
Beginning of year			876				63,277				32				68,720
Extensions and discoveries			6				3,533				--				3,571
Purchase of minerals in place			33				8,322				--				8,524
Production			(108)				(7,027)				(11)				(7,738)
Sale of minerals in place			(90)				--				--				(538)
Revision of previous estimates			109				3,542				(21)				4,065
End of year			826				71,647				--				76,604
Proved developed reserves:
Beginning of year			811				48,369				32				53,422
End of year			774				57,804				--				62,449
Proved undeveloped reserves:
Beginning of year			65				14,908				--				15,298
End of year			52				13,843				--				14,155

Noteworthy amounts included in the categories of proved reserve changes for the years 2011, 2010, and 2009 in the above tables include:

 

•

Our predecessor acquired 167.4 Bcfe in multiple acquisitions, the largest being the Carthage Properties, during the year ended December 31, 2011.

•

Our predecessor acquired 90.1 Bcfe in multiple acquisitions, the largest being the Forest Oil properties of 47.0 Bcfe, during the year ended December 31, 2010.

•

Our predecessor acquired 8.5 Bcfe during the year ended December 31, 2009 multiple acquisitions.

See Note 3 Acquisitions and Divestitures for additional information on acquisitions.

A variety of methodologies are used to determine our proved reserve estimates. The principal methodologies employed are reservoir simulation, decline curve analysis, volumetric, material balance, advance production type curve matching, petro-physics/log analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all of our fields.

The standardized measure of discounted future net cash flows is as follows:

 

		Years Ended December 31,
		2011				2010				2009
		(In thousands)
Future cash inflows		$	1,894,818			$	898,407			$	341,057
Future production costs			(648,781)				(332,963)				(138,833)
Future development costs			(156,192)				(68,998)				(31,180)
Future income tax expense (1)			--				(5,463)				(2,070)
Future net cash flows for estimated timing of cash flows			1,089,845				490,983				168,974
10% annual discount for estimated timing of cash flows			(625,946)				(271,648)				(87,433)
Standardized measure of discounted future net cash flows		$	463,899			$	219,335			$	81,541

(1)       We are subject to the Texas franchise tax which has a maximum effective rate of 0.7% of gross income apportioned to Texas. Due to immateriality we have excluded the impact of this tax for the year ended December 31, 2011.

 

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Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves

The following is a summary of the changes in the standardized measure of discounted future net cash flows for the proved oil and natural gas reserves during each of the years in the three year period ended December 31, 2011:

 

		Years Ended December 31,
		2011				2010				2009
		(In thousands)
Beginning of year		$	219,335			$	81,541			$	115,075
Sale of oil and natural gas produced, net of production costs			(53,466)				(29,416)				(17,465)
Purchase of minerals in place			219,113				114,595				6,213
Sale of minerals in place			--				--				(612)
Reserves retain by predecessor			(1,940)				--				--
Extensions and discoveries			44,095				8,526				2,852
Changes in income taxes, net			--				(1,506)				319
Changes in prices and costs			14,509				23,510				(49,009)
Previously estimated development costs incurred			205				2,228				8,215
Net changes in future development costs			(3,271)				(4,947)				1,253
Revisions of previous quantities			30,009				25,136				5,789
Accretion of discount			21,934				8,251				11,636
Change in production rates and other			(26,624)				(8,583)				(2,725)
End of year		$	463,899			$	219,335			$	81,541

 

F-34